FINAL SUPPLEMENTAL GENERIC
ENVIRONMENTAL IMPACT STATEMENT
ON THE OIL, GAS AND SOLUTION MINING
REGULATORY PROGRAM
Regulatory Program for Horizontal Drilling and High-Volume
Hydraulic Fracturing to Develop the Marcellus Shale and
Other Low-Permeability Gas Reservoirs

Volume 1: Final Supplemental Generic Environmental Impact Statement
Volume 2: Response to Comments

May 2015

VOLUME 1 OF 2
FINAL SUPPLEMENTAL GENERIC ENVIRONMENTAL IMPACT STATEMENT

LEAD AGENCY: NYSDEC

LEAD AGENCY CONTACT: EUGENE J. LEFF
Deputy Commissioner of Remediation & Materials Management
NYSDEC, 625 Broadway, 14th Floor
Albany, NY 12233
P: (518) 402-8044

www.dec.ny.gov

 ACKNOWLEDGEMENTS
NEW YORK STATE ENERGY RESEARCH & DEVELOPMENT AUTHORITY*
NEW YORK STATE DEPARTMENT OF HEALTH
CENTER FOR ENVIRONMENTAL HEALTH

* NYSERDA research assistance for September 2009 draft SGEIS, for 2011 revised draft and
2013 Final SGEIS.

 Table of Contents
VOLUME 1
EXECUTIVE SUMMARY ........................................................................................................................................... 1
CHAPTER 1 INTRODUCTION ................................................................................................................................ 1-1
1.1 HYDRAULIC FRACTURING AND MULTI-WELL PAD DRILLING ...................................................................................... 1-1
1.1.1 Significant Changes in Proposed Operations Since 2009........................................................................... 1-2
1.1.1.1 Use of Reserve Pits or Centralized Impoundments for Flowback Water ........................................ 1-2
1.1.1.2 Flowback Water Recycling .............................................................................................................. 1-2
1.2 REGULATORY JURISDICTION ............................................................................................................................... 1-3
1.3 STATE ENVIRONMENTAL QUALITY REVIEW ACT...................................................................................................... 1-3
1.4 PROJECT CHRONOLOGY .................................................................................................................................... 1-4
1.4.1 February 2009 Final Scope ........................................................................................................................ 1-4
1.4.2 2009 Draft SGEIS ........................................................................................................................................ 1-4
1.4.2.1 April 2010 Announcement Regarding Communities with Filtration Avoidance Determinations ... 1-5
1.4.2.2 Subsequent Exclusion of Communities with Filtration Avoidance Determinations ....................... 1-5
1.4.3 2011 Revised Draft SGEIS .......................................................................................................................... 1-5
1.4.4 Draft Regulations ....................................................................................................................................... 1-5
1.4.5 Health Review by the New York State Department of Health ................................................................... 1-6
1.4.6 Final SGEIS ................................................................................................................................................. 1-6
1.4.7 Next Steps .................................................................................................................................................. 1-6
1.5 METHODOLOGY.............................................................................................................................................. 1-6
1.5.1 Information about the Proposed Operations ............................................................................................ 1-6
1.5.2 Intra-/Inter-agency Coordination .............................................................................................................. 1-7
1.5.3 Comment Review ...................................................................................................................................... 1-7
1.6 LAYOUT AND ORGANIZATION............................................................................................................................. 1-8
1.6.1 Chapters..................................................................................................................................................... 1-8
1.6.2 Revisions .................................................................................................................................................. 1-10
1.6.3 Glossary, Bibliographies and Appendices ................................................................................................ 1-10
1.7 ENHANCED IMPACT ANALYSES AND MITIGATION MEASURES .................................................................................. 1-10
1.7.1 Hydraulic Fracturing Chemical Disclosure ............................................................................................... 1-10
1.7.2 Water Well Testing .................................................................................................................................. 1-11
1.7.3 Water Withdrawal and Consumption ...................................................................................................... 1-11
1.7.3.1 2009 Draft SGEIS ........................................................................................................................... 1-11
1.7.3.2 Revised Draft SGEIS....................................................................................................................... 1-11
1.7.4 Well Control and Emergency Response Planning .................................................................................... 1-11
1.7.5 Local Planning Documents ....................................................................................................................... 1-12
1.7.6 Secondary Containment, Spill Prevention and Stormwater Pollution Prevention .................................. 1-12
1.7.7 Well Construction .................................................................................................................................... 1-12
1.7.7.1 2009 Draft SGEIS ........................................................................................................................... 1-13
1.7.7.2 Revised Draft SGEIS....................................................................................................................... 1-13
1.7.8 Flowback Water Handling On-Site ........................................................................................................... 1-14
1.7.9 Flowback Water Disposal ........................................................................................................................ 1-14
1.7.10 Management of Drill Cuttings ................................................................................................................. 1-14

Final SGEIS 2015, Page i

 1.7.11 Emissions and Air Quality ........................................................................................................................ 1-15
1.7.11.1 2009 Draft SGEIS ........................................................................................................................... 1-15
1.7.11.2 Revised Draft SGEIS....................................................................................................................... 1-16
1.7.12 Greenhouse Gas Mitigation ..................................................................................................................... 1-17
1.7.13 Habitat Fragmentation ............................................................................................................................ 1-17
1.7.14 State Forests, State Wildlife Management Areas and State Parks .......................................................... 1-18
1.7.15 Community and Socioeconomic Impacts ................................................................................................ 1-18
1.8 ADDITIONAL PRECAUTIONARY MEASURES .......................................................................................................... 1-18
CHAPTER 2 DESCRIPTION OF PROPOSED ACTION ............................................................................................... 2-1
2.1 PURPOSE ...................................................................................................................................................... 2-2
2.2 PROJECT LOCATION ......................................................................................................................................... 2-2
2.3 ENVIRONMENTAL SETTING ................................................................................................................................ 2-3
2.3.1 Water Use Classifications .......................................................................................................................... 2-3
2.3.2 Water Quality Standards ........................................................................................................................... 2-7
2.3.3 Drinking Water .......................................................................................................................................... 2-8
2.3.3.1 Federal ............................................................................................................................................ 2-8
2.3.3.2 New York State ............................................................................................................................. 2-13
2.3.4 Public Water Systems .............................................................................................................................. 2-14
2.3.4.1 Primary and Principal Aquifers ..................................................................................................... 2-15
2.3.4.2 Public Water Supply Wells ............................................................................................................ 2-17
2.3.5 Private Water Wells and Domestic-Supply Springs ................................................................................. 2-17
2.3.6 History of Drilling and Hydraulic Fracturing in Water Supply Areas ........................................................ 2-18
2.3.7 Regulated Drainage Basins ...................................................................................................................... 2-20
2.3.7.1 Delaware River Basin .................................................................................................................... 2-21
2.3.7.2 Susquehanna River Basin .............................................................................................................. 2-21
2.3.7.3 Great Lakes-St. Lawrence River Basin ........................................................................................... 2-23
2.3.8 Water Resources Replenishment ............................................................................................................ 2-23
2.3.9 Floodplains............................................................................................................................................... 2-25
2.3.9.1 Analysis of Recent Flood Events ................................................................................................... 2-27
2.3.9.2 Flood Zone Mapping ..................................................................................................................... 2-27
2.3.9.3 Seasonal Analysis .......................................................................................................................... 2-28
2.3.10 Freshwater Wetlands .............................................................................................................................. 2-29
2.3.11 Socioeconomic Conditions....................................................................................................................... 2-30
2.3.11.1 Economy, Employment, and Income ............................................................................................ 2-36
2.3.11.2 Population..................................................................................................................................... 2-70
2.3.11.3 Housing ......................................................................................................................................... 2-76
2.3.11.4 Government Revenues and Expenditures .................................................................................... 2-86
2.3.11.5 Environmental Justice ................................................................................................................... 2-98
2.3.12 Visual Resources .................................................................................................................................... 2-111
2.3.12.1 Historic Properties and Cultural Resources ................................................................................ 2-114
2.3.12.2 Parks and Other Recreation Areas .............................................................................................. 2-121
2.3.12.3 Natural Areas .............................................................................................................................. 2-127
2.3.12.4 Additional Designated Scenic or Other Areas ............................................................................. 2-136
2.3.13 Noise ...................................................................................................................................................... 2-144
2.3.13.1 Noise Fundamentals ................................................................................................................... 2-144
2.3.13.2 Common Noise Effects ................................................................................................................ 2-146
2.3.13.3 Noise Regulations and Guidance ................................................................................................ 2-148
2.3.13.4 Existing Noise Levels ................................................................................................................... 2-151

Final SGEIS 2015, Page ii

 2.3.14 Transportation - Existing Environment .................................................................................................. 2-151
2.3.14.1 Terminology and Definitions....................................................................................................... 2-151
2.3.14.2 Regional Road Systems ............................................................................................................... 2-156
2.3.14.3 Condition of New York State Roads ............................................................................................ 2-162
2.3.14.4 NYSDOT Funding Mechanisms .................................................................................................... 2-163
2.3.14.5 Rail and Air Services .................................................................................................................... 2-166
2.3.15 Community Character............................................................................................................................ 2-167
CHAPTER 3 PROPOSED SEQRA REVIEW PROCESS ................................................................................................ 3-1
3.1 INTRODUCTION – USE OF A GENERIC ENVIRONMENTAL IMPACT STATEMENT ................................................................ 3-1
3.1.1 1992 GEIS and Findings.............................................................................................................................. 3-2
3.1.2 Need for a Supplemental GEIS................................................................................................................... 3-3
3.2 FUTURE SEQRA COMPLIANCE ........................................................................................................................... 3-4
3.2.1 Scenarios for Future SEQRA Compliance under the SGEIS ........................................................................ 3-4
3.2.2 Review Parameters .................................................................................................................................... 3-6
3.2.2.1 SGEIS Applicability - Definition of High-Volume Hydraulic Fracturing ............................................ 3-6
3.2.2.2 Project Scope .................................................................................................................................. 3-7
3.2.2.3 Size of Project ................................................................................................................................. 3-7
3.2.2.4 Lead Agency .................................................................................................................................... 3-8
3.2.3 EAF Addendum and Additional Informational Requirements ................................................................... 3-8
3.2.3.1 Hydraulic Fracturing Information ................................................................................................... 3-9
3.2.3.2 Water Source Information .............................................................................................................. 3-9
3.2.3.3 Distances ....................................................................................................................................... 3-10
3.2.3.4 Water Well Information ................................................................................................................ 3-11
3.2.3.5 Fluid Disposal Plan ........................................................................................................................ 3-12
3.2.3.6 Operational Information ............................................................................................................... 3-12
3.2.3.7 Invasive Species Survey and Map ................................................................................................. 3-13
3.2.3.8 Required Affirmations................................................................................................................... 3-13
3.2.3.9 Local Planning Documents ............................................................................................................ 3-14
3.2.3.10 Habitat Fragmentation ................................................................................................................. 3-14
3.2.4 Prohibited Locations ................................................................................................................................ 3-15
3.2.5 Projects Requiring Site-Specific SEQRA Determinations of Significance ................................................. 3-15
3.3 REGULATIONS .............................................................................................................................................. 3-17
CHAPTER 4 - GEOLOGY ........................................................................................................................................ 4-1
4.1 INTRODUCTION............................................................................................................................................... 4-1
4.2 BLACK SHALES ................................................................................................................................................ 4-2
4.3 UTICA SHALE ................................................................................................................................................. 4-5
4.3.1 Total Organic Carbon ............................................................................................................................... 4-10
4.3.2 Thermal Maturity and Fairways............................................................................................................... 4-13
4.3.3 Potential for Gas Production ................................................................................................................... 4-13
4.4 MARCELLUS FORMATION ................................................................................................................................ 4-14
4.4.1 Total Organic Carbon ............................................................................................................................... 4-16
4.4.2 Thermal Maturity and Fairways............................................................................................................... 4-16
4.4.3 Potential for Gas Production ................................................................................................................... 4-17
4.5 SEISMICITY IN NEW YORK STATE....................................................................................................................... 4-23
4.5.1 Background .............................................................................................................................................. 4-23
4.5.2 Seismic Risk Zones ................................................................................................................................... 4-24

Final SGEIS 2015, Page iii

 4.5.3
4.5.4
4.5.5

Seismic Damage – Modified Mercalli Intensity Scale .............................................................................. 4-27
Seismic Events ......................................................................................................................................... 4-27
Monitoring Systems in New York ............................................................................................................ 4-33

4.6 NATURALLY OCCURRING RADIOACTIVE MATERIALS (NORM) IN MARCELLUS SHALE.................................................... 4-35
4.7 NATURALLY OCCURRING METHANE IN NEW YORK STATE....................................................................................... 4-35
CHAPTER 5 NATURAL GAS DEVELOPMENT ACTIVITIES & HIGH-VOLUME HYDRAULIC FRACTURING ................... 5-1
5.1 LAND DISTURBANCE ........................................................................................................................................ 5-2
5.1.1 Access Roads.............................................................................................................................................. 5-2
5.1.2 Well Pads ................................................................................................................................................... 5-6
5.1.3 Utility Corridors ....................................................................................................................................... 5-10
5.1.4 Well Pad Density ...................................................................................................................................... 5-11
5.1.4.1 Historic Well Density..................................................................................................................... 5-11
5.1.4.2 Anticipated Well Pad Density ....................................................................................................... 5-12
5.2 HORIZONTAL DRILLING ................................................................................................................................... 5-19
5.2.1 Drilling Rigs .............................................................................................................................................. 5-21
5.2.2 Multi-Well Pad Development .................................................................................................................. 5-23
5.2.3 Drilling Mud ............................................................................................................................................. 5-27
5.2.4 Cuttings .................................................................................................................................................... 5-28
5.2.4.1 Cuttings Volume ........................................................................................................................... 5-29
5.2.4.2 NORM in Marcellus Cuttings ......................................................................................................... 5-29
5.2.5 Management of Drilling Fluids and Cuttings ........................................................................................... 5-32
5.2.5.1 Reserve Pits on Multi-Well Pads ................................................................................................... 5-32
5.2.5.2 Closed-Loop Tank Systems............................................................................................................ 5-32
5.3 HYDRAULIC FRACTURING ................................................................................................................................ 5-34
5.4 FRACTURING FLUID ....................................................................................................................................... 5-35
5.4.1 Properties of Fracturing Fluids ................................................................................................................ 5-44
5.4.2 Classes of Additives ................................................................................................................................. 5-44
5.4.3 Composition of Fracturing Fluids ............................................................................................................. 5-46
5.4.3.1 Chemical Categories and Health Information ............................................................................... 5-58
5.5 TRANSPORT OF HYDRAULIC FRACTURING ADDITIVES ............................................................................................. 5-72
5.6 ON-SITE STORAGE AND HANDLING OF HYDRAULIC FRACTURING ADDITIVES ............................................................... 5-73
5.6.1 Summary of Additive Container Types .................................................................................................... 5-74
5.7 SOURCE WATER FOR HIGH-VOLUME HYDRAULIC FRACTURING ................................................................................ 5-76
5.7.1 Delivery of Source Water to the Well Pad ............................................................................................... 5-77
5.7.2 Use of Centralized Impoundments for Fresh Water Storage .................................................................. 5-78
5.8 HYDRAULIC FRACTURING DESIGN ..................................................................................................................... 5-81
5.8.1 Fracture Development ............................................................................................................................. 5-82
5.8.2 Methods for Limiting Fracture Growth.................................................................................................... 5-83
5.8.3 Hydraulic Fracturing Design – Summary.................................................................................................. 5-84
5.9 HYDRAULIC FRACTURING PROCEDURE................................................................................................................ 5-85
5.10 RE-FRACTURING ........................................................................................................................................... 5-89
5.11 FLUID RETURN.............................................................................................................................................. 5-92
5.11.1 Flowback Water Recovery ....................................................................................................................... 5-93
5.11.2 Flowback Water Handling at the Wellsite ............................................................................................... 5-93

Final SGEIS 2015, Page iv

 5.11.3 Flowback Water Characteristics .............................................................................................................. 5-93
5.11.3.1 Temporal Trends in Flowback Water Composition .................................................................... 5-111
5.11.3.2 NORM in Flowback Water .......................................................................................................... 5-112
5.12 FLOWBACK WATER TREATMENT, RECYCLING AND REUSE ..................................................................................... 5-112
5.12.1 Physical and Chemical Separation ......................................................................................................... 5-114
5.12.2 Dilution .................................................................................................................................................. 5-116
5.12.2.1 Reuse .......................................................................................................................................... 5-116
5.12.3 Other On-Site Treatment Technologies ................................................................................................. 5-118
5.12.3.1 Membranes / Reverse Osmosis .................................................................................................. 5-118
5.12.3.2 Thermal Distillation ..................................................................................................................... 5-119
5.12.3.3 Ion Exchange ............................................................................................................................... 5-120
5.12.3.4 Electrodialysis/Electrodialysis Reversal ...................................................................................... 5-120
5.12.3.5 Ozone/Ultrasonic/Ultraviolet ..................................................................................................... 5-121
5.12.3.6 Crystallization/Zero Liquid Discharge ......................................................................................... 5-122
5.12.4 Comparison of Potential On-Site Treatment Technologies ................................................................... 5-122
5.13 WASTE DISPOSAL ....................................................................................................................................... 5-123
5.13.1 Cuttings from Mud Drilling .................................................................................................................... 5-123
5.13.2 Reserve Pit Liner from Mud Drilling ...................................................................................................... 5-124
5.13.3 Flowback Water ..................................................................................................................................... 5-124
5.13.3.1 Injection Wells ............................................................................................................................ 5-125
5.13.3.2 Municipal Sewage Treatment Facilities ...................................................................................... 5-126
5.13.3.3 Out-of-State Treatment Plants ................................................................................................... 5-126
5.13.3.4 Road Spreading ........................................................................................................................... 5-127
5.13.3.5 Private In-State Industrial Treatment Plants .............................................................................. 5-127
5.13.3.6 Enhanced Oil Recovery ............................................................................................................... 5-128
5.13.4 Solid Residuals from Flowback Water Treatment ................................................................................. 5-128
5.14 WELL CLEANUP AND TESTING ........................................................................................................................ 5-128
5.15 SUMMARY OF OPERATIONS PRIOR TO PRODUCTION ........................................................................................... 5-129
5.16 NATURAL GAS PRODUCTION ......................................................................................................................... 5-131
5.16.1 Partial Site Reclamation ......................................................................................................................... 5-131
5.16.2 Gas Composition .................................................................................................................................... 5-131
5.16.2.1 Hydrocarbons.............................................................................................................................. 5-131
5.16.2.2 Hydrogen Sulfide ........................................................................................................................ 5-132
5.16.3 Production Rate ..................................................................................................................................... 5-132
5.16.4 Well Pad Production Equipment ........................................................................................................... 5-133
5.16.5 Brine Storage ......................................................................................................................................... 5-135
5.16.6 Brine Disposal ........................................................................................................................................ 5-135
5.16.7 NORM in Marcellus Production Brine.................................................................................................... 5-135
5.16.8 Gas Gathering and Compression ........................................................................................................... 5-136
5.17 WELL PLUGGING......................................................................................................................................... 5-137
CHAPTER 6 POTENTIAL ENVIRONMENTAL IMPACTS ........................................................................................... 6-1
6.1 WATER RESOURCES ......................................................................................................................................... 6-1
6.1.1 Water Withdrawals.................................................................................................................................... 6-2
6.1.1.1 Reduced Stream Flow ..................................................................................................................... 6-2
6.1.1.2 Degradation of a Stream’s Best Use ............................................................................................... 6-2
6.1.1.3 Impacts to Aquatic Habitat ............................................................................................................. 6-3
6.1.1.4 Impacts to Aquatic Ecosystems ...................................................................................................... 6-3
6.1.1.5 Impacts to Wetlands ....................................................................................................................... 6-5

Final SGEIS 2015, Page v

 6.1.1.6 Aquifer Depletion ........................................................................................................................... 6-5
6.1.1.7 Cumulative Water Withdrawal Impacts ......................................................................................... 6-6
6.1.2 Stormwater Runoff .................................................................................................................................. 6-14
6.1.3 Surface Spills and Releases at the Well Pad ............................................................................................ 6-15
6.1.3.1 Drilling ........................................................................................................................................... 6-16
6.1.3.2 Hydraulic Fracturing Additives ...................................................................................................... 6-16
6.1.3.3 Flowback Water and Production Brine ......................................................................................... 6-17
6.1.3.4 Potential Impacts to Primary and Principal Aquifers .................................................................... 6-37
6.1.4 Groundwater Impacts Associated With Well Drilling and Construction.................................................. 6-41
6.1.4.1 Turbidity ........................................................................................................................................ 6-41
6.1.4.2 Fluids Pumped Into the Well......................................................................................................... 6-42
6.1.4.3 Natural Gas Migration .................................................................................................................. 6-42
6.1.5 Unfiltered Surface Drinking Water Supplies: NYC and Syracuse ............................................................. 6-43
6.1.5.1 Pollutants of Critical Concern in Unfiltered Drinking Water Supplies .......................................... 6-46
6.1.5.2 Regulatory and Programmatic Framework for Filtration Avoidance ............................................ 6-49
6.1.5.3 Adverse Impacts to Unfiltered Drinking Waters from High-Volume Hydraulic Fracturing ........... 6-51
6.1.5.4 Conclusion..................................................................................................................................... 6-52
6.1.6 Hydraulic Fracturing Procedure ............................................................................................................... 6-53
6.1.6.1 Wellbore Failure ........................................................................................................................... 6-54
6.1.6.2 Subsurface Pathways .................................................................................................................... 6-54
6.1.7 Waste Transport ...................................................................................................................................... 6-57
6.1.8 Fluid Discharges ....................................................................................................................................... 6-58
6.1.8.1 POTWs .......................................................................................................................................... 6-58
6.1.8.2 Private Off-site Wastewater Treatment and/or Reuse Facilities .................................................. 6-64
6.1.8.3 Private On-site Wastewater Treatment and/or Reuse Facilities .................................................. 6-64
6.1.8.4 Disposal Wells ............................................................................................................................... 6-65
6.1.8.5 Other Means of Wastewater Disposal .......................................................................................... 6-65
6.1.9 Solids Disposal ......................................................................................................................................... 6-66
6.1.9.1 NORM Considerations - Cuttings .................................................................................................. 6-66
6.1.9.2 Cuttings Volume ........................................................................................................................... 6-66
6.1.9.3 Cuttings and Liner Associated With Mud-Drilling ......................................................................... 6-66
6.2 FLOODPLAINS ............................................................................................................................................... 6-67
6.3 FRESHWATER WETLANDS................................................................................................................................ 6-67
6.4 ECOSYSTEMS AND WILDLIFE ............................................................................................................................ 6-67
6.4.1 Impacts of Fragmentation to Terrestrial Habitats and Wildlife ............................................................... 6-68
6.4.1.1 Impacts of Grassland Fragmentation ............................................................................................ 6-73
6.4.1.2 Impacts of Forest Fragmentation ................................................................................................. 6-75
6.4.2 Invasive Species ....................................................................................................................................... 6-84
6.4.2.1 Terrestrial...................................................................................................................................... 6-85
6.4.2.2 Aquatic .......................................................................................................................................... 6-87
6.4.3 Impacts to Endangered and Threatened Species .................................................................................... 6-89
6.4.4 Impacts to State-Owned Lands ................................................................................................................ 6-91
6.5 AIR QUALITY................................................................................................................................................ 6-94
6.5.1 Regulatory Overview ............................................................................................................................... 6-94
6.5.1.1 Emission Analysis NOx - Internal Combustion Engine Emissions ................................................ 6-100
6.5.1.2 Natural Gas Production Facilities NESHAP 40 CFR Part 63, Subpart HH (Glycol
Dehydrators) ............................................................................................................................... 6-103
6.5.1.3 Flaring Versus Venting of Wellsite Air Emissions ........................................................................ 6-104
6.5.1.4 Number of Wells Per Pad Site ..................................................................................................... 6-105
6.5.1.5 Natural Gas Condensate Tanks ................................................................................................... 6-105

Final SGEIS 2015, Page vi

 6.5.1.6
6.5.1.7
6.5.1.8

Emissions Tables ......................................................................................................................... 6-106
Offsite Gas Gathering Station Engine ......................................................................................... 6-108
Department Determinations on the Air Permitting Process Relative to Marcellus Shale
High-Volume Hydraulic Fracturing Development Activities. ...................................................... 6-109
6.5.2 Air Quality Impact Assessment .............................................................................................................. 6-111
6.5.2.1 Introduction ................................................................................................................................ 6-111
6.5.2.2 Sources of Air Emissions and Operational Scenarios .................................................................. 6-114
6.5.2.3 Modeling Procedures .................................................................................................................. 6-118
6.5.2.4 Results of the Modeling Analysis ................................................................................................ 6-133
6.5.2.5 Supplemental Modeling Assessment for Short Term PM2.5, SO2 and NO2 Impacts and
Mitigation Measures Necessary to Meet NAAQS. ...................................................................... 6-141
6.5.2.6 The Practicality of Mitigation Measures on the Completion Equipment and Drilling
Engines. ....................................................................................................................................... 6-154
6.5.2.7 Conclusions from the Modeling Analysis ................................................................................. 6-158
6.5.3 Regional Emissions of O3 Precursors and Their Effects on Attainment Status in the SIP ...................... 6-170
6.5.4 Air Quality Monitoring Requirements for Marcellus Shale Activities .................................................... 6-183
6.5.5 Permitting Approach to the Well Pad and Compressor Station Operations ......................................... 6-188
6.6 GREENHOUSE GAS EMISSIONS ....................................................................................................................... 6-189
6.6.1 Greenhouse Gases ................................................................................................................................. 6-190
6.6.2 Emissions from Oil and Gas Operations ................................................................................................ 6-190
6.6.2.1 Vented Emissions ........................................................................................................................ 6-191
6.6.2.2 Combustion Emissions ................................................................................................................ 6-191
6.6.2.3 Fugitive Emissions ....................................................................................................................... 6-192
6.6.3 Emissions Source Characterization ........................................................................................................ 6-192
6.6.4 Emission Rates ....................................................................................................................................... 6-196
6.6.5 Drilling Rig Mobilization, Site Preparation and Demobilization ............................................................ 6-197
6.6.6 Completion Rig Mobilization and Demobilization ................................................................................. 6-198
6.6.7 Well Drilling ........................................................................................................................................... 6-198
6.6.8 Well Completion .................................................................................................................................... 6-199
6.6.9 Well Production ..................................................................................................................................... 6-201
6.6.10 Summary of GHG Emissions .................................................................................................................. 6-203
6.7 NATURALLY OCCURRING RADIOACTIVE MATERIALS IN THE MARCELLUS SHALE.......................................................... 6-208
6.8 SOCIOECONOMIC IMPACTS ............................................................................................................................ 6-210
6.8.1 Economy, Employment, and Income ..................................................................................................... 6-214
6.8.1.1 New York State ........................................................................................................................... 6-214
6.8.1.2 Representative Regions .............................................................................................................. 6-220
6.8.2 Population ............................................................................................................................................. 6-234
6.8.2.1 New York State ........................................................................................................................... 6-236
6.8.2.2 Representative Regions .............................................................................................................. 6-241
6.8.3 Housing .................................................................................................................................................. 6-245
6.8.3.1 New York State ........................................................................................................................... 6-245
6.8.3.2 Representative Regions .............................................................................................................. 6-248
6.8.3.3 Cyclical Nature of the Natural Gas Industry................................................................................ 6-253
6.8.3.4 Property Values .......................................................................................................................... 6-253
6.8.4 Government Revenue and Expenditures ............................................................................................... 6-257
6.8.4.1 New York State ........................................................................................................................... 6-257
6.8.4.2 Representative Regions .............................................................................................................. 6-260
6.8.5 Environmental Justice ............................................................................................................................ 6-266

Final SGEIS 2015, Page vii

 6.9 VISUAL IMPACTS ......................................................................................................................................... 6-266
6.9.1 Changes since Publication of the 1992 GEIS that Affect the Assessment of Visual Impacts ................. 6-267
6.9.1.1 Equipment and Drilling Techniques ............................................................................................ 6-267
6.9.1.2 Changes in Well Pad Size and the Number of Water Storage Sites ............................................ 6-268
6.9.1.3 Duration and Nature of Drilling and Hydraulic-Fracturing Activities .......................................... 6-268
6.9.2 New Landscape Features Associated with the Different Phases of Horizontal Drilling and
Hydraulic Fracturing .............................................................................................................................. 6-269
6.9.2.1 New Landscape Features Associated with the Construction of Well Pads ................................. 6-269
6.9.2.2 New Landscape Features Associated with Drilling Activities at Well Pads ................................. 6-273
6.9.2.3 New Landscape Features Associated with Hydraulic Fracturing Activities at Well Pads ............ 6-273
6.9.2.4 New Landscape Features Associated with Production at Viable Well Sites ............................... 6-275
6.9.2.5 New Landscape Features Associated with the Reclamation of Well Sites ................................. 6-275
6.9.3 Visual Impacts Associated with the Different Phases of Horizontal Drilling and Hydraulic
Fracturing............................................................................................................................................... 6-275
6.9.3.1 Visual Impacts Associated with Construction of Well Pads ........................................................ 6-276
6.9.3.2 Visual Impacts Associated with Drilling Activities on Well Pads ................................................. 6-277
6.9.3.3 Visual Impacts Associated with Hydraulic Fracturing Activities at Well Sites ............................. 6-278
6.9.3.4 Visual Impacts Associated with Production at Well Sites ........................................................... 6-278
6.9.3.5 Visual Impacts Associated with the Reclamation of Well Sites .................................................. 6-279
6.9.4 Visual Impacts of Off-site Activities Associated with Horizontal Drilling and Hydraulic Fracturing ...... 6-280
6.9.5 Previous Evaluations of Visual Impacts from Horizontal Drilling and Hydraulic Fracturing .................. 6-282
6.9.6 Assessment of Visual Impacts using NYSDEC Policy and Guidance ....................................................... 6-286
6.9.7 Summary of Visual Impacts ................................................................................................................... 6-287
6.10 NOISE ...................................................................................................................................................... 6-292
6.10.1 Access Road Construction ..................................................................................................................... 6-294
6.10.2 Well Site Preparation ............................................................................................................................. 6-295
6.10.3 High-Volume Hydraulic Fracturing – Drilling ......................................................................................... 6-296
6.10.4 High-Volume Hydraulic Fracturing – Fracturing .................................................................................... 6-299
6.10.5 Transportation ....................................................................................................................................... 6-302
6.10.6 Gas Well Production .............................................................................................................................. 6-303
6.11 TRANSPORTATION IMPACTS .......................................................................................................................... 6-303
6.11.1 Estimated Truck Traffic .......................................................................................................................... 6-304
6.11.1.1 Total Number of Trucks per Well ................................................................................................ 6-304
6.11.1.2 Temporal Distribution of Truck Traffic per Well ......................................................................... 6-307
6.11.1.3 Temporal Distribution of Truck Traffic for Multi-Well Pads ....................................................... 6-307
6.11.2 Increased Traffic on Roadways .............................................................................................................. 6-310
6.11.3 Damage to Local Roads, Bridges, and other Infrastructure ................................................................... 6-313
6.11.4 Damage to State Roads, Bridges, and other Infrastructure ................................................................... 6-315
6.11.5 Operational and Safety Impacts on Road Systems ................................................................................ 6-317
6.11.6 Transportation of Hazardous Materials ................................................................................................. 6-318
6.11.7 Impacts on Rail and Air Travel ............................................................................................................... 6-319
6.12 COMMUNITY CHARACTER IMPACTS ................................................................................................................. 6-319
6.13 SEISMICITY ................................................................................................................................................ 6-322
6.13.1 Hydraulic Fracturing-Induced Seismicity ............................................................................................... 6-322
6.13.1.1 Background ................................................................................................................................. 6-323
6.13.1.2 Recent Investigations and Studies .............................................................................................. 6-326
6.13.1.3 Correlations between New York and Texas ................................................................................ 6-328
6.13.1.4 Affects of Seismicity on Wellbore Integrity ................................................................................ 6-329
6.13.2 Summary of Potential Seismicity Impacts ............................................................................................. 6-330

Final SGEIS 2015, Page viii

 CHAPTER 7 EXISTING AND RECOMMENDED MITIGATION MEASURES ................................................................ 7-1
7.1 PROTECTING WATER RESOURCES ....................................................................................................................... 7-1
7.1.1 Water Withdrawal Regulatory and Oversight Programs ........................................................................... 7-2
7.1.1.1 Department Jurisdictions ................................................................................................................ 7-2
7.1.1.2 Other Jurisdictions - Great Lakes-St. Lawrence River Basin Water Resources Compact ................ 7-5
7.1.1.3 Other Jurisdictions - River Basin Commissions ............................................................................... 7-6
7.1.1.4 Impact Mitigation Measures for Surface Water Withdrawals ...................................................... 7-14
7.1.1.5 Impact Mitigation Measures for Groundwater Withdrawals ....................................................... 7-24
7.1.1.6 Cumulative Water Withdrawal Impacts ....................................................................................... 7-25
7.1.2 Stormwater .............................................................................................................................................. 7-26
7.1.2.1 Construction Activities .................................................................................................................. 7-29
7.1.2.2 Industrial Activities ....................................................................................................................... 7-30
7.1.2.3 Production Activities ..................................................................................................................... 7-31
7.1.3 Surface Spills and Releases at the Well Pad ............................................................................................ 7-31
7.1.3.1 Fueling Tank and Tank Refilling Activities ..................................................................................... 7-33
7.1.3.2 Drilling Fluids ................................................................................................................................ 7-34
7.1.3.3 Hydraulic Fracturing Additives ...................................................................................................... 7-38
7.1.3.4 Flowback Water ............................................................................................................................ 7-39
7.1.3.5 Primary and Principal Aquifers ..................................................................................................... 7-40
7.1.4 Potential Ground Water Impacts Associated With Well Drilling and Construction ................................ 7-41
7.1.4.1 Private Water Well Testing ........................................................................................................... 7-44
7.1.4.2 Sufficiency of As-Built Wellbore Construction .............................................................................. 7-49
7.1.4.3 Annular Pressure Buildup ............................................................................................................. 7-55
7.1.5 Setback from FAD Watersheds ................................................................................................................ 7-55
7.1.6 Hydraulic Fracturing Procedure ............................................................................................................... 7-56
7.1.7 Waste Transport ...................................................................................................................................... 7-59
7.1.7.1 Drilling and Production Waste Tracking Form .............................................................................. 7-59
7.1.7.2 Road Spreading ............................................................................................................................. 7-60
7.1.7.3 Flowback Water Piping ................................................................................................................. 7-61
7.1.7.4 Use of Tanks Instead of Impoundments for Centralized Flowback Water Storage ...................... 7-61
7.1.7.5 Closure Requirements .................................................................................................................. 7-62
7.1.8 SPDES Discharge Permits ......................................................................................................................... 7-62
7.1.8.1 Treatment Facilities ...................................................................................................................... 7-63
7.1.8.2 Disposal Wells ............................................................................................................................... 7-65
7.1.9 Solids Disposal ......................................................................................................................................... 7-67
7.1.10 Protecting NYC’s Subsurface Water Supply Infrastructure...................................................................... 7-68
7.1.11 Setbacks ................................................................................................................................................... 7-69
7.1.11.1 Setbacks from Groundwater Resources ....................................................................................... 7-71
7.1.11.2 Setbacks from Other Surface Water Resources ............................................................................ 7-74
7.2 PROTECTING FLOODPLAINS ............................................................................................................................. 7-77
7.3 PROTECTING FRESHWATER WETLANDS .............................................................................................................. 7-77
7.4 MITIGATING POTENTIAL SIGNIFICANT IMPACTS ON ECOSYSTEMS AND WILDLIFE .......................................................... 7-77
7.4.1 Protecting Terrestrial Habitats and Wildlife ............................................................................................ 7-78
7.4.1.1 BMPs for Reducing Direct Impacts at Individual Well Sites .......................................................... 7-78
7.4.1.2 Reducing Indirect and Cumulative Impacts of Habitat Fragmentation ........................................ 7-79
7.4.1.3 Monitoring Changes in Habitat ..................................................................................................... 7-87
7.4.2 Invasive Species ....................................................................................................................................... 7-87
7.4.2.1 Terrestrial...................................................................................................................................... 7-88
7.4.2.2 Aquatic .......................................................................................................................................... 7-91

Final SGEIS 2015, Page ix

 7.4.3
7.4.4

Protecting Endangered and Threatened Species..................................................................................... 7-97
Protecting State-Owned Land.................................................................................................................. 7-99

7.5 MITIGATING AIR QUALITY IMPACTS ................................................................................................................ 7-100
7.5.1 Mitigation Measures Resulting from Regulatory Analysis (Internal Combustion Engines and Glycol
Dehydrators) .......................................................................................................................................... 7-101
7.5.1.1 Control Measures for Nitrogen Oxides - NOx .............................................................................. 7-101
7.5.1.2 Control Measures for Sulfur Oxides - SOx ................................................................................... 7-104
7.5.1.3 Natural Gas Production Facilities Subject to NESHAP 40 CFR Part 63, Subpart HH (Glycol
Dehydrators) ............................................................................................................................... 7-105
7.5.2 Mitigation Measures Resulting from Air Quality Impact Assessment and Regional Ozone Precursor
Emissions ............................................................................................................................................... 7-106
7.5.3 Summary of Mitigation Measures to Protect Air Quality ...................................................................... 7-107
7.5.3.1 Well Pad Activity Mitigation Measures ....................................................................................... 7-107
7.5.3.2 Mitigation Measures for Off-Site Gas Compressors ................................................................... 7-108
7.6 MITIGATING GHG EMISSIONS ....................................................................................................................... 7-109
7.6.1 General .................................................................................................................................................. 7-109
7.6.2 Site Selection ......................................................................................................................................... 7-110
7.6.3 Transportation ....................................................................................................................................... 7-110
7.6.4 Well Design and Drilling ......................................................................................................................... 7-110
7.6.5 Well Completion .................................................................................................................................... 7-111
7.6.6 Well Production ..................................................................................................................................... 7-112
7.6.7 Leak and Detection Repair Program ...................................................................................................... 7-113
7.6.8 Mitigating GHG Emissions Impacts - Conclusion ................................................................................... 7-115
7.7 MITIGATING NORM IMPACTS ....................................................................................................................... 7-116
7.7.1 State and Federal Responses to Oil and Gas NORM .............................................................................. 7-116
7.7.2 Regulation of NORM in New York State ................................................................................................ 7-116
7.8 SOCIOECONOMIC MITIGATION MEASURES........................................................................................................ 7-118
7.9 VISUAL MITIGATION MEASURES..................................................................................................................... 7-120
7.9.1 Design and Siting Measures ................................................................................................................... 7-121
7.9.2 Maintenance Activities .......................................................................................................................... 7-125
7.9.3 Decommissioning .................................................................................................................................. 7-125
7.9.4 Offsetting Mitigation ............................................................................................................................. 7-126
7.10 NOISE MITIGATION MEASURES ...................................................................................................................... 7-127
7.10.1 Pad Siting Equipment, Layout and Operation ....................................................................................... 7-127
7.10.2 Access Road and Traffic Noise ............................................................................................................... 7-128
7.10.3 Well Drilling and Hydraulic Fracturing ................................................................................................... 7-129
7.10.4 Conclusion ............................................................................................................................................. 7-133
7.11 TRANSPORTATION MITIGATION MEASURES ...................................................................................................... 7-134
7.11.1 Mitigating Damage to Local Road Systems............................................................................................ 7-134
7.11.1.1 Development of Transportation Plans, Baseline Surveys, and Traffic Studies ........................... 7-134
7.11.1.2 Municipal Control over Local Road Systems ............................................................................... 7-136
7.11.1.3 Road Use Agreements ................................................................................................................ 7-137
7.11.1.4 Reimbursement for Costs Associated with Local Road Work ..................................................... 7-139
7.11.2 Mitigating Incremental Damage to the State System of Roads ............................................................. 7-139
7.11.3 Mitigating Operational and Safety Impacts on Road Systems............................................................... 7-140
7.11.4 Other Transportation Mitigation Measures .......................................................................................... 7-141

Final SGEIS 2015, Page x

 7.11.5 Mitigating Impacts from the Transportation of Hazardous Materials................................................... 7-141
7.11.6 Mitigating Impacts on Rail and Air Travel .............................................................................................. 7-142
7.12 COMMUNITY CHARACTER MITIGATION MEASURES............................................................................................. 7-143
7.13 EMERGENCY RESPONSE PLAN ........................................................................................................................ 7-145
CHAPTER 8 PERMIT PROCESS AND REGULATORY COORDINATION ..................................................................... 8-1
8.1 INTERAGENCY COORDINATION ........................................................................................................................... 8-1
8.1.1 Local Governments .................................................................................................................................... 8-1
8.1.1.1 SEQRA Participation ........................................................................................................................ 8-1
8.1.1.2 NYCDEP ........................................................................................................................................... 8-4
8.1.1.3 Local Government Notification ....................................................................................................... 8-4
8.1.1.4 Road-Use Agreements .................................................................................................................... 8-4
8.1.1.5 Local Planning Documents .............................................................................................................. 8-4
8.1.1.6 County Health Departments ........................................................................................................... 8-5
8.1.2 State........................................................................................................................................................... 8-5
8.1.2.1 Public Service Commission ............................................................................................................. 8-6
8.1.2.2 NYS Department of Transportation ............................................................................................. 8-18
8.1.3 Federal ..................................................................................................................................................... 8-19
8.1.3.1 U.S. Department of Transportation .............................................................................................. 8-19
8.1.3.2 Occupational Safety and Health Administration – Material Safety Data Sheets .......................... 8-21
8.1.3.3 EPA’s Mandatory Reporting of Greenhouse Gases ...................................................................... 8-24
8.1.4 River Basin Commissions ......................................................................................................................... 8-28
8.2 INTRA-DEPARTMENT ..................................................................................................................................... 8-29
8.2.1 Well Permit Review Process .................................................................................................................... 8-29
8.2.1.1 Required Hydraulic Fracturing Additive Information .................................................................... 8-29
8.2.2 Other Department Permits and Approvals .............................................................................................. 8-32
8.2.2.1 Bulk Storage .................................................................................................................................. 8-32
8.2.2.2 Impoundment Regulation ............................................................................................................. 8-33
8.2.3 Enforcement ............................................................................................................................................ 8-42
8.2.3.1 Enforcement of Article 23 ............................................................................................................. 8-42
8.2.3.2 Enforcement of Article 17 ............................................................................................................. 8-44
8.3 WELL PERMIT ISSUANCE ................................................................................................................................. 8-48
8.3.1 Use and Summary of Supplementary Permit Conditions for High-Volume Hydraulic Fracturing ........... 8-48
8.3.2 High-Volume Re-Fracturing ..................................................................................................................... 8-48
8.4 OTHER STATES’ REGULATIONS ......................................................................................................................... 8-49
8.4.1 Ground Water Protection Council ........................................................................................................... 8-51
8.4.1.1 GWPC - Hydraulic Fracturing ........................................................................................................ 8-51
8.4.1.2 GWPC - Other Activities ................................................................................................................ 8-52
8.4.2 Alpha’s Regulatory Survey ....................................................................................................................... 8-53
8.4.2.1 Alpha - Hydraulic Fracturing ......................................................................................................... 8-53
8.4.2.2 Alpha - Other Activities ................................................................................................................. 8-54
8.4.3 Colorado’s Final Amended Rules ............................................................................................................. 8-60
8.4.3.1 Colorado - New MSDS Maintenance and Chemical Inventory Rule ............................................. 8-60
8.4.3.2 Colorado - Setbacks from Public Water Supplies.......................................................................... 8-61
8.4.4 Summary of Pennsylvania Environmental Quality Board. Title 25-Environmental Protection,
Chapter 78, Oil and Gas Wells ................................................................................................................. 8-62
8.4.5 Other States’ Regulations - Conclusion ................................................................................................... 8-62

Final SGEIS 2015, Page xi

 CHAPTER 9 ALTERNATIVE ACTIONS ..................................................................................................................... 9-1
9.1 NO-ACTION ALTERNATIVE ................................................................................................................................ 9-1
9.2 PHASED PERMITTING APPROACH ........................................................................................................................ 9-4
9.2.1 Inherent Difficulties in Predicting Gas Well Development Rates and Patterns ......................................... 9-5
9.2.2 Known Tendency for Development to Occur in Phases without Government Intervention ..................... 9-5
9.2.3 Prohibitions and Limits that Function as a Partial Phased Permitting Approach ...................................... 9-6
9.2.3.1 Permanent Prohibitions .................................................................................................................. 9-6
9.2.3.2 Prohibitions in Place for at Least 3 Years ........................................................................................ 9-7
9.2.3.3 Prohibitions in Place for At Least 2 Years ....................................................................................... 9-7
9.2.4 Permit Issuance Matched to Department Resources ................................................................................ 9-8
9.3 “GREEN” OR NON-CHEMICAL FRACTURING TECHNOLOGIES AND ADDITIVES ................................................................. 9-8
9.3.1 Environmentally-Friendly Chemical Alternatives .................................................................................... 9-10
9.3.2 Summary .................................................................................................................................................. 9-11
CHAPTER 10 REVIEW OF SELECTED NON-ROUTINE INCIDENTS IN PENNSYLVANIA ............................................ 10-1
10.1 GAS MIGRATION – SUSQUEHANNA AND BRADFORD COUNTIES ............................................................................... 10-1
10.1.1 Description of Incidents ........................................................................................................................... 10-1
10.1.2 New York Mitigation Measures Designed to Prevent Gas Migration Similar to the Pennsylvania
Incidents .................................................................................................................................................. 10-1
10.2 FRACTURING FLUID RELEASES – SUSQUEHANNA AND BRADFORD COUNTIES ............................................................... 10-2
10.2.1 Description of Incidents ........................................................................................................................... 10-2
10.2.2 New York Mitigation Measures Designed to Prevent Fracturing Fluid Releases..................................... 10-3
10.3 UNCONTROLLED WELLBORE RELEASE OF FLOWBACK WATER AND BRINE – CLEARFIELD COUNTY ..................................... 10-3
10.3.1 Description of Incident ............................................................................................................................ 10-3
10.3.2 New York Mitigation Measures Designed to Prevent Uncontrolled Wellbore Release of Flowback
Water and Brine ...................................................................................................................................... 10-4
10.4 HIGH TOTAL DISSOLVED SOLIDS (TDS) DISCHARGES – MONONGAHELA RIVER ........................................................... 10-4
10.4.1 Description of Incidents ........................................................................................................................... 10-4
10.4.2 New York Mitigation Measures Designed to Prevent High In-Stream TDS ............................................. 10-4
CHAPTER 11 SUMMARY OF POTENTIAL IMPACTS AND MITIGATION MEASURES .............................................. 11-1
GLOSSARY .......................................................................................................................................................... G-1
BIBLIOGRAPHY .................................................................................................................................................... B-1
APPENDIX 1

FEMA FLOOD INSURANCE RATE MAP AVAILABILITY .................................................................A1-1

APPENDIX 2

1992 SEQRA FINDINGS STATEMENT ON THE GEIS ON THE OIL, GAS AND SOLUTION
MINING REGULATORY PROGRAM .............................................................................................A2-1

APPENDIX 3

SUPPLEMENTAL SEQRA FINDINGS STATEMENT ON LEASING OF STATE LANDS FOR
ACTIVITIES REGULATED UNDER THE OIL, GAS AND SOLUTION MINING LAW ............................A3-1

APPENDIX 4

EXISTING APPLICATION FORM FOR PERMIT TO DRILL, DEEPEN, PLUG BACK OR CONVERT
A WELL SUBJECT TO THE OIL, GAS AND SOLUTION MINING REGULATORY PROGRAM ..............A4-1

APPENDIX 5

EXISTING ENVIRONMENTAL ASSESSMENT FORM FOR WELL PERMITTING ................................A5-1

APPENDIX 6

PROPOSED ENVIRONMENTAL ASSESSMENT FORM ADDENDUM ..............................................A6-1

APPENDIX 7

SAMPLE DRILLING RIG SPECIFICATIONS PROVIDED BY CHESAPEAKE ENERGY ...........................A7-1

APPENDIX 8

EXISTING CASING AND CEMENTING PRACTICES REQUIRED FOR ALL WELLS IN NYS ..................A8-1

Final SGEIS 2015, Page xii

 APPENDIX 9

EXISTING FRESH WATER AQUIFER SUPPLEMENTARY PERMIT CONDITIONS REQUIRED
FOR WELLS DRILLED IN PRIMARY AND PRINCIPAL AQUIFERS ...................................................A9-1

APPENDIX 10 PROPOSED SUPPLEMENTARY PERMIT CONDITIONS FOR HIGH-VOLUME HYDRAULIC
FRACTURING ...........................................................................................................................A10-1
APPENDIX 11 ANALYSIS OF SUBSURFACE MOBILITY OF FRACTURING FLUIDS (EXCERPTED FROM ICF
INTERNATIONAL, TASK 1, 2009) .............................................................................................A11-1
APPENDIX 12 BENEFICIAL USE DETERMINATION (BUD) NOTIFICATION REGARDING ROAD SPREADING ......A12-1
APPENDIX 13 RADIOLOGICAL DATA – PRODUCTION BRINE FROM NYS MARCELLUS WELLS .........................A13-1
APPENDIX 14 DEPARTMENT OF PUBLIC SERVICE ENVIRONMENTAL MANAGEMENT AND
CONSTRUCTION STANDARDS AND PRACTICES – PIPELINES ....................................................A14-1
APPENDIX 15 HYDRAULIC FRACTURING – 15 STATEMENTS FROM REGULATORY OFFICIALS ........................A15-1
APPENDIX 16 APPLICABILITY OF NOX RACT REQUIREMENTS FOR NATURAL GAS PRODUCTION
FACILITIES ...............................................................................................................................A16-1
APPENDIX 17 APPLICABILITY OF 40 CFR PART 63 SUBPART ZZZZ (ENGINE MACT) FOR NATURAL GAS
PRODUCTION FACILITIES – FINAL RULE ...................................................................................A17-1
APPENDIX 18 DEFINITION OF STATIONARY SOURCE OR FACILITY FOR THE DETERMINATION OF AIR
PERMIT REQUIREMENTS .........................................................................................................A18-1
APPENDIX 18A EVALUATION OF PARTICULATE MATTER AND NITROGEN OXIDES EMISSIONS FACTORS
AND POTENTIAL AFTERTREATMENT CONTROLS FOR NONROAD ENGINES FOR
MARCELLUS SHALE DRILLING AND HYDRAULIC FRACTURING OPERATIONS ......................... A18A-1
APPENDIX 18B COST ANALYSIS OF MITIGATION OF NO2 EMISSIONS AND AIR IMPACTS BY SELECTED
CATALYTIC REDUCTION (SCR) TREATMENT .......................................................................... A18B-1
APPENDIX 18C REGIONAL ON-ROAD MOBILE SOURCE EMISSION ESTIMATES FROM EPA’S MOVES
MODEL AND SINGLE-PAD PM2.5 ESTIMATES FROM MOBILE 6 MODEL .................................A18C-1
APPENDIX 19 GREENHOUSE GAS (GHG) EMISSIONS .....................................................................................A19-1
APPENDIX 20 PROPOSED PRE-FRAC CHECKLIST AND CERTIFICATION ............................................................A20-1
APPENDIX 21 PUBLICALLY OWNED TREATMENT WORKS (POTWS) WITH APPROVED PRETREATMENT
PROGRAMS .............................................................................................................................A21-1
APPENDIX 22 POTWS PROCEDURES FOR ACCEPTING HIGH-VOLUME HYDRAULIC FRACTURING
WASTEWATER.........................................................................................................................A22-1
APPENDIX 23 USEPA NATURAL GAS STAR PROGRAM ...................................................................................A23-1
APPENDIX 24 KEY FEATURES OF USEPA NATURAL GAS STAR PROGRAM ......................................................A24-1
APPENDIX 25 REDUCED EMISSIONS COMPLETION (REC) EXECUTIVE SUMMARY ..........................................A25-1
APPENDIX 26 INSTRUCTIONS FOR USING THE ON-LINE SEARCHABLE DATABASE TO LOCATE DRILLING
APPLICATIONS ........................................................................................................................A26-1
APPENDIX 27 NYSDOH RADIATION SURVEY GUIDELINES AND SAMPLE RADIOACTIVE MATERIALS
HANDLING LICENSE .................................................................................................................A27-1

Final SGEIS 2015, Page xiii

 FIGURES
Figure 2.1 - Primary and Principal Aquifers in New York State ................................................................................ 2-16
Figure 2.2 - Susquehanna and Delaware River Basins ............................................................................................. 2-22
Figure 2.3 - Representative Regions Within the Marcellus Shale Extent (New August 2011) ................................. 2-31
Figure 2.4 - Representative Regions A, B, and C (New August 2011) ...................................................................... 2-33
Figure 2.5 - Region A: Natural Gas Production, 1994 to 2009 (New August 2011) ................................................. 2-56
Figure 2.6 - Region C: Natural Gas Production, 1994-2009 (New August 2011) ..................................................... 2-68
Figure 2.7 - Potential Environmental Justice Areas for Region A (New August 2011) ........................................... 2-103
Figure 2.8 - Potential Environmental Justice Areas for Region B (New August 2011) ........................................... 2-106
Figure 2.9 - Potential Environmental Justice Areas for Region C (New August 2011) ........................................... 2-109
Figure 2.10 - Area of Interest for Visual Resources (New August 2011)................................................................ 2-112
Figure 2.11 - Visually Sensitive Areas Associated with Historic Properties and Cultural Resources (New
August 2011) .................................................................................................................................... 2-120
Figure 2.12 - Parks and Recreational Resources that May be Visually Sensitive (New August 2011) ................... 2-125
Figure 2.13 - Natural Areas that May be Visually Sensitive (New August 2011) ................................................... 2-128
Figure 2.14 - Additional Designated Scenic or other Areas that May be Visually Sensitive .................................. 2-137
Figure 2.15 - Level of Continuous Noise Causing Speech Interference (New August 2011).................................. 2-147
Figure 2.16 - FHWA Vehicle Classifications (New August 2011) ............................................................................ 2-154
Figure 2.17 - New York State Department of Transportation Regions (New August 2011) .................................. 2-156
Figure 2.18 - Transportation (New August 2011) .................................................................................................. 2-158
Figure 2.19 - Land Cover and Agricultural Districts, Representative Region A (New August 2011) ...................... 2-171
Figure 2.20 - Land Cover and Agricultural Districts, Representative Region B (New August 2011) ...................... 2-179
Figure 2.21 - Land Cover and Agricultural Districts, Representative Region C (New August 2011) ...................... 2-187
Figure 4.1 - Gas Shale Distribution in the Appalachian Basin .................................................................................... 4-4
Figure 4.2 - Stratigraphic Column of Southwestern New York .................................................................................. 4-7
Figure 4.3 - East West Cross-Section of New York State. .......................................................................................... 4-8
Figure 4.4 - Extent of Utica Shale in New York State ................................................................................................. 4-9
Figure 4.5 - Depth to Base of Utica Shale in New York State ................................................................................... 4-11
Figure 4.6 - Thickness of High-Organic Utica Shale in New York State .................................................................... 4-12
Figure 4.7 - Utica Shale Fairway in New York State ................................................................................................. 4-15
Figure 4.8 - Depth and Extent of Marcellus Shale in New York State ...................................................................... 4-18
Figure 4.9 - Marcellus Shale Thickness in New York State....................................................................................... 4-19
Figure 4.10 - Total Organic Carbon of Marcellus Shale in New York State .............................................................. 4-20
Figure 4.11 - Marcellus Shale Thermal Maturity ..................................................................................................... 4-21
Figure 4.12 - Marcellus Shale Fairway in New York State........................................................................................ 4-22
Figure 4.13 - Mapped Geologic Faults in New York State ....................................................................................... 4-25
Figure 4.14 - New York State Seismic Hazard Map .................................................................................................. 4-26
Figure 4.15 - Seismic Events in New York State (1970 to 2009) .............................................................................. 4-34
Figure 5.1 - Well Pad Schematic .............................................................................................................................. 5-10
Figure 5.2 - Possible well spacing unit configurations and wellbore paths ............................................................. 5-26
Figure 5.3 - Sample Fracturing Fluid Composition (12 Additives), by Weight, from Fayetteville Shale .................. 5-47
Figure 5.4 - Sample Fracturing Fluid Composition (9 Additives), by Weight, from Marcellus Shale (New July
2011) .................................................................................................................................................. 5-48
Figure 5.5 - Sample Fracturing Fluid Composition (6 Additives), by Weight, from Marcellus Shale (New July
2011) .................................................................................................................................................. 5-48
Figure 5.6 - Example Fracturing Fluid Composition Including Recycled Flowback Water (New July 2011) .......... 5-117
Figure 5.7 - One configuration of potential on-site treatment technologies. ....................................................... 5-118
Figure 5.8 – Simplified Illustration of Gas Production Process .............................................................................. 5-134
Figure 6.1 - Water Withdrawals in the United States ............................................................................................. 6-11

Final SGEIS 2015, Page xiv

 Figure 6.2 - Fresh Water Use in NY (millions of gallons per day) with Projected Peak Water Use for HighVolume Hydraulic Fracturing (New July 2011) ..................................................................................... 6-12
Figure 6.3 - Daily Water Withdrawals, Exports, and Consumptive Uses in the Delaware River Basin ................... 6-13
Figure 6.4 - NYSDOH Regulated Groundwater Supplies within Mapped Primary and Principal Aquifers in
NY, Where the Marcellus Shale is Greater than 2,000 Feet below Ground Surface ............................ 6-39
Figure 6.5 - Average Spatial Disturbance for Marcellus Shale Well Pads in Forested Context (New July
2011) .................................................................................................................................................... 6-78
Figure 6.6 – Interior Forest Habitat Before & After Development of a Marcellus Gas Well Pad, Elk County
PA (New July 2011) ............................................................................................................................... 6-81
Figure 6.7 - Total Forest Areas Converted (New July 2011) .................................................................................... 6-82
Figure 6.8 - New York's Forest Matrix Blocks and State Connectivity (New July 2011) .......................................... 6-84
Figure 6.9 - Areas of Concern for Endangered and Threatened Animal Species, March 31, 2011 (New July
2011) .................................................................................................................................................... 6-91
Figure 6.10 - Marcellus Shale Extent Meteorological Data Sites ........................................................................... 6-168
Figure 6.11 - Location of Well Pad Sources of Air Pollution Used in Modeling ..................................................... 6-169
Figure 6.12 - Barnett Shale Natural Gas Production Trend, 1998-2007 ................................................................ 6-175
Figure 6.13 – Projected Direct Employment in New York State Resulting from Each Development Scenario
(New August 2011) ........................................................................................................................... 6-217
Figure 6.14 - Projected Total Employment in New York State Resulting from Each Development Scenario
(New August 2011) ........................................................................................................................... 6-218
Figure 6.15 - Projected Direct Employment in Region A Resulting from Each Development Scenario (New
August 2011) .................................................................................................................................... 6-224
Figure 6.16 - Projected Direct Employment in Region B Resulting from Each Development Scenario (New
August 2011) .................................................................................................................................... 6-225
Figure 6.17 - Projected Direct Employment in Region C Resulting from Each Development Scenario (New
August 2011) .................................................................................................................................... 6-226
Figure 6.18 – Projected Total Employment in Region A Under Each Development Scenario (New August
2011) ................................................................................................................................................ 6-228
Figure 6.19 - Projected Total Employment in Region B Under Each Development Scenario (New August
2011) ................................................................................................................................................ 6-229
Figure 6.20 - Projected Total Employment in Region C Under Each Development Scenario (New August
2011) ................................................................................................................................................ 6-230
Figure 6.21 - A-Weighted Noise Emissions: Cruise Throttle, Average Pavement (New August 2011) ................. 6-302
Figure 6.22 - Estimated Round-Trip Daily Heavy and Light Truck Traffic, by Well Type - Single Well (New
August 2011) .................................................................................................................................... 6-307
Figure 6.23 - Estimated Daily Round-Trips of Heavy and Light Truck Traffic - Multi Horizontal Wells (New
August 2011) .................................................................................................................................... 6-309
Figure 6.24 - Estimated Round-Trip Daily Heavy and Light Truck Traffic - Multi Vertical Wells (New August
2011) ................................................................................................................................................ 6-309
Figure 7.1 - Hydrologic Regions of New York (New July 2011) (Taken from Lumia et al, 2006) .............................. 7-21
Figure 7.2 - Key Habitat Areas for Protecting Grassland and Interior Forest Habitats (Updated August 2011)...... 7-80
Figure 7.3 - Scaling Factors for Matrix Forest Systems in the High Allegheny Ecoregion (New July 2011) ............. 7-84
Figure 8.1- Protection of Waters - Dam Safety Permitting Criteria ......................................................................... 8-35

Final SGEIS 2015, Page xv

 TABLES
Table 2.1 - New York Water Use Classifications ........................................................................................................ 2-4
Table 2.2 - Primary Drinking Water Standards ........................................................................................................ 2-10
Table 2.3 - Secondary Drinking Water Standards .................................................................................................... 2-13
Table 2.4 - Public Water System Definition ............................................................................................................. 2-15
Table 2.5 - New York State: Area Employment by Industry, 2009 (New August 2011) ........................................... 2-38
Table 2.6 - New York State: Wages by Industry, 2009 (New August 2011) ............................................................. 2-39
Table 2.7 - New York State: Labor Force Statistics, 2000 and 2010 (New August 2011) ........................................ 2-39
Table 2.8 - New York State: Income Statistics, 1999 and 2009 (New August 2011) ................................................ 2-40
Table 2.9 - New York State: Employment in Travel and Tourism, 2009 (New August 2011) .................................. 2-41
Table 2.10 - New York State: Wages in Travel and Tourism, 2009 (New August 2011) ......................................... 2-41
Table 2.11 - New York State: Agricultural Data, 2007 (New August 2011) .............................................................. 2-42
Table 2.12 - New York: Impact of a $1 Million Dollar Increase in the Final Demand in the Output of the Oil
and Gas Extraction Industry on the Value of the Output of Other Industries (New August
2011) .................................................................................................................................................. 2-43
Table 2.13 - New York State: Employment in the Oil and Gas Extraction Industry, 2000-2010 (New August
2011) .................................................................................................................................................. 2-44
Table 2.14 - Most Common Occupations in the U.S. Oil and Gas Extraction Industry, 2008 (New August
2011) .................................................................................................................................................. 2-45
Table 2.15 - New York State: Wages in the Oil and Gas Industry, 2009 (New August 2011) .................................. 2-46
Table 2.16 - New York State: Natural Gas Production, 1985-2009 (New August 2011) .......................................... 2-47
Table 2.17 - Permits Issued, Wells Completed, and Active Wells, NYS Gas Wells, 1994-2009 (New August
2011) .................................................................................................................................................. 2-48
Table 2.18 - Average Wellhead Price for New York State’s Natural Gas, 1994-2009 (New August 2011) .............. 2-49
Table 2.19 - Market Value of New York State’s Natural Gas Production, 1994-2009 (New August 2011).............. 2-49
Table 2.20 - Region A: Area Employment by Industry, 2009 (New August 2011) ................................................... 2-50
Table 2.21 - Region A: Wages by Industry, 2009 (New August 2011) ..................................................................... 2-51
Table 2.22 - Region A: Labor Force Statistics, 2000 and 2010 (New August 2011) ................................................. 2-52
Table 2.23 - Region A: Income Statistics, 1999 and 2009 (New August 2011) ........................................................ 2-52
Table 2.24 - Region A: Employment in Travel and Tourism, 2009 (New August 2011) ........................................... 2-54
Table 2.25 - Region A: Wages in Travel and Tourism, 2009 (New August 2011) ..................................................... 2-54
Table 2.26 - Region A: Agricultural Data, 2007 (New August 2011) ........................................................................ 2-55
Table 2.27 - Region A: Number of Active Natural Gas Wells, 1994-2009 (New August 2011) ................................ 2-56
Table 2.28 – Natural Gas Production and Active Wells by Town within each County in Region A, 2009 (New
August 2011) ...................................................................................................................................... 2-57
Table 2.29 - Region B: Area Employment, by Industry, 2009 (New August 2011) .................................................. 2-58
Table 2.30 - Region B: Wages, by Industry, 2009 (New August 2011) ..................................................................... 2-58
Table 2.31 - Region B: Labor Force Statistics, 2000 and 2010 ((New August 2011)) ............................................... 2-59
Table 2.32 - Region B: Income Statistics, 1999 and 2009 (New August 2011) ........................................................ 2-60
Table 2.33 - Region B: Travel and Tourism, by Industrial Group, 2009 (New August 2011).................................... 2-61
Table 2.34 - Region B: Wages in Travel and Tourism, 2009 (New August 2011) ..................................................... 2-61
Table 2.35 - Region B: Agricultural Data, 2007 (New August 2011) ........................................................................ 2-62
Table 2.36 - Region C: Area Employment by Industry, 2009 (New August 2011) ................................................... 2-63
Table 2.37 - Region C: Wages, by Industry, 2009 (New August 2011) ..................................................................... 2-63
Table 2.38 - Region C: Labor Force Statistics, 2000 and 2010 (New August 2011) ................................................. 2-64
Table 2.39 - Region C: Income Statistics, 1999 and 2009 (New August 2011) ........................................................ 2-64
Table 2.40 - Region C: Travel and Tourism, by Industrial Group, 2009 (New August 2011).................................... 2-66
Table 2.41 - Region C: Wages in Travel and Tourism, 2009 (New August 2011) ..................................................... 2-66
Table 2.42 - Region C: Agricultural Data, 2007 (New August 2011) ........................................................................ 2-67
Table 2.43 - Number of Active Natural Gas Wells in Region C, 1994-2009 (New August 2011) ............................. 2-68

Final SGEIS 2015, Page xvi

 Table 2.44 - Natural Gas Production and the Number of Active Gas Wells by Town within each County in
Region C, 2009 (New August 2011) .................................................................................................... 2-69
Table 2.45 - New York State: Historical and Current Population, 1990, 2000, 2010 (New August 2011) ............... 2-71
Table 2.46 - New York State: Projected Population, 2015 to 2030 (New August 2011) ......................................... 2-71
Table 2.47 - Region A: Historical and Current Population, 1990, 2000, 2010 (New August 2011) .......................... 2-72
Table 2.48 - Region A: Population Projections, 2015 to 2030 (New August 2011) ................................................. 2-73
Table 2.49 - Region B: Historical and Current Population - 1990, 2000, 2010 (New August 2011) ......................... 2-73
Table 2.50 - Region B: Population Projections, 2015 to 2030 (New August 2011) .................................................. 2-74
Table 2.51 - Region C: Historical and Current Population - 1990, 2000, 2010 (New August 2011) ......................... 2-75
Table 2.52 - Region C: Population Projections, 2015 to 2030 (New August 2011) ................................................. 2-75
Table 2.53 - New York State: Total Housing Units - 1990, 2000, 2010 (New August 2011).................................... 2-76
Table 2.54 - New York State: Type of Housing Units, 2009 (New August 2011)...................................................... 2-76
Table 2.55 - New York State: Number of Sales and Annual Median Sale Price of Single-Family Homes Sold,
2008-2010 (New August 2011) .......................................................................................................... 2-77
Table 2.56 - New York State: Housing Characteristics, 2010 (New August 2011) ................................................... 2-77
Table 2.57 - Region A: Total Housing Units - 1990, 2000, 2010 (New August 2011) ............................................... 2-78
Table 2.58 - Region A: Total Housing Units by Type of Structure, 2009 (New August 2011) .................................. 2-78
Table 2.59 - Region A: Number of Sales and Annual Median Sale Price of Single-Family Homes Sold, 20082010 (New August 2011) .................................................................................................................... 2-79
Table 2.60 - Region A: Housing Characteristics, 2010 (New August 2011) .............................................................. 2-80
Table 2.61 - Region A: Short-Term Accommodations (Hotels/Motels), 2011 (New August 2011) ......................... 2-80
Table 2.62 - Region B: Total Housing Units - 1990, 2000, 2010 (New August 2011) ............................................... 2-81
Table 2.63 - Region B: Total Housing Units by Type of Structure 2009 (New August 2011) ................................... 2-81
Table 2.64- Region B: Number of Sales and Annual Median Sale Price of Single-Family Homes Sold, 20082010 (New August 2011) .................................................................................................................... 2-82
Table 2.65 - Region B: Housing Characteristics, 2010 (New August 2011) .............................................................. 2-83
Table 2.66 - Region B: Short-Term Accommodations (Hotels/Motels) (New August 2011).................................... 2-83
Table 2.67 - Region C: Total Housing Units - 1990, 2000, 2010 (New August 2011) ............................................... 2-84
Table 2.68 - Region C: Total Housing Units by Type of Structure, 2009 (New August 2011) .................................. 2-84
Table 2.69 - Region C: Number of Sales and Annual Median Sale Price of Single-Family Homes Sold, 20082010 (New August 2011) .................................................................................................................... 2-85
Table 2.70 - Region C: Housing Characteristics, 2010 (New August 2011) .............................................................. 2-85
Table 2.71 - Region C: Short-Term Accommodations (Hotels/Motels) (New August 2011).................................... 2-86
Table 2.72 - New York State Revenues Collected for FY Ending March 31, 2010 (New August 2011) .................... 2-87
Table 2.73 - New York State: Number of Leases and Acreage of State Land Leased for Oil and Natural Gas
Development, 2010 (New August 2011) ............................................................................................ 2-88
Table 2.74 - 2000-2010 Leasing Revenue by Payment Type for New York State (New August 2011) .................... 2-88
Table 2.75 - Region A: Total Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011) ............. 2-90
Table 2.76 - Region A: Local Tax Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011) ...... 2-91
Table 2.77 - Gas Economic Profile for Medina Region 3 (New August 2011) .......................................................... 2-91
Table 2.78 - Region A: Expenditures for FY Ending December 31, 2009 ($ millions) (New August 2011) ............... 2-92
Table 2.79 - Region B: Total Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011) ............. 2-93
Table 2.80 - Region B: Local Tax Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011) ...... 2-94
Table 2.81 - Gas Economic Profile for Medina Region 4 and State Equalization Rates and Millage Rates for
Region B (New August 2011) .............................................................................................................. 2-94
Table 2.82 - Region B: Expenditures for FY Ending December 31, 2009 ($ millions) (New August 2011) ............... 2-95
Table 2.83 - Region C: Revenues for FY Ending December 31, 2009 ($ millions) (New August 2011)..................... 2-96
Table 2.84 - Region C: Local Tax Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011) ...... 2-97
Table 2.85 - Gas Economic Profile for Medina Region 2 and State Equalization Rates and Millage Rates for
Region C (New August 2011) .............................................................................................................. 2-97
Table 2.86 - Region C: Expenditures for FY Ending December 31, 2009 (New August 2011) .................................. 2-98

Final SGEIS 2015, Page xvii

 Table 2.87 - Racial and Ethnicity Characteristics for New York State (New August 2011) .................................... 2-101
Table 2.88 - Region A: Racial and Ethnicity Characteristics (New August 2011) ................................................... 2-104
Table 2.89 - Region B: Racial and Ethnicity Characteristics (New August 2011) ................................................... 2-107
Table 2.90 - Region C: Racial and Ethnicity Characteristics (New August 2011) ................................................... 2-110
Table 2.91 - Number of NRHP-Listed Historic Properties within the Area Underlain by the Marcellus and
Utica Shales in New York (New August 2011) .................................................................................. 2-115
Table 2.92 - National Historic Landmarks (NHLs) Located within the Area Underlain by the Marcellus and
Utica Shales in New York (New August 2011) .................................................................................. 2-118
Table 2.93 - State Parks Located within the Area Underlain by the Marcellus and Utica Shales in New York
(New August 2011) ........................................................................................................................... 2-122
Table 2.94 - Select Trails Located within the Area Underlain by the Marcellus and Utica Shales in New York
(New August 2011) ........................................................................................................................... 2-126
Table 2.95 - State Nature and Historic Preserves in Counties Located within the Area Underlain by the
Marcellus and Utica Shales in New York (New August 2011) .......................................................... 2-129
Table 2.96 - National and State Wild, Scenic and Recreational Rivers (designated or potential) Located
within the Area Underlain by the Marcellus and Utica Shales in New York (New August 2011) ..... 2-132
Table 2.97 - State Game Refuges and State Wildlife Management Areas Located within the Area Underlain
by the Marcellus and Utica Shales in New York (New August 2011) ............................................... 2-134
Table 2.98 - National Natural Landmarks Located within the Area Underlain by the Marcellus and Utica
Shales in New York (New August 2011) ........................................................................................... 2-135
Table 2.99 - Designated and Proposed National and State Scenic Byways, Highways, and Roads Located
within the Area Underlain by the Marcellus and Utica Shales in New York (New August 2011) ..... 2-138
Table 2.100 - Recommended Open Space Conservation Projects Located in the Area Underlain by the
Marcellus and Utica Shales in New York (New August 2011) .......................................................... 2-141
Table 2.101 - Effects of Noise on People (New August 2011) ............................................................................... 2-148
Table 2.102 - Summary of Noise Levels Identified as Requisite to Protect Public Health and Welfare with
an Adequate Margin of Safety (New August 2011) .......................................................................... 2-149
Table 2.103 - Common Noise Levels (New August 2011) ...................................................................................... 2-151
Table 2.104 - Guidelines on Extent of Rural Functional Systems (New August 2011) ........................................... 2-153
Table 2.105 - Descriptions of the Thirteen FHWA Vehicle Classification Categories (New August 2011) ............. 2-155
Table 2.106 - Region A: Highway Mileage by County, 2009 (New August 2011) .................................................. 2-159
Table 2.107 - Heavy Vehicles as a Percentage of Total Vehicles in Rural Areas in NYSDOT Regions 6 and 9,
2004-2009 (New August 2011) ........................................................................................................ 2-159
Table 2.108 - Region B: Highway Mileage by County, 2009 (New August 2011)................................................... 2-160
Table 2.109 - Heavy Vehicles as a Percentage of Total Vehicles in Rural Areas in NYSDOT Region 9, 20042009 (New August 2011) .................................................................................................................. 2-161
Table 2.110 - Region C: Highway Mileage by County, 2009 (New August 2011)................................................... 2-161
Table 2.111 - Heavy Vehicles as a Percentage of Total Vehicles in Rural Areas in NYSDOT Region 5, 2009
(New August 2011) ........................................................................................................................... 2-162
Table 2.112 - Ranking System of Pavement Condition in New York State (New August 2011)............................. 2-163
Table 2.113 - NYSDOT Total Receipts, 2009-2012 ($ thousands) (New August 2011) .......................................... 2-165
Table 4.1 - Modified Mercalli Scale ......................................................................................................................... 4-29
Table 4.2 - Summary of Seismic Events in New York State ...................................................................................... 4-30
Table 5.1 - Ten square mile area (i.e., 6,400 acres), completely drilled with horizontal wells in multi-well
units or vertical wells in single-well units (Updated July 2011) ......................................................... 5-19
Table 5.2 - 2009 Marcellus Radiological Data .......................................................................................................... 5-30
Table 5.3 - Gamma Ray Spectroscopy ..................................................................................................................... 5-31
Table 5.4 - Fracturing Additive Products – Complete Composition Disclosure Made to the Department
(Updated July 2011) ........................................................................................................................... 5-37
Table 5.5 - Fracturing Additive Products – Partial Composition Disclosure to the Department (Updated July
2011) .................................................................................................................................................. 5-42

Final SGEIS 2015, Page xviii

 Table 5.6 - Types and Purposes of Additives Proposed for Use in New York State (Updated July 2011) ................ 5-45
Table 5.7 - Chemical Constituents in Additives (Updated July 2011) ...................................................................... 5-49
Table 5.8 - Categories based on chemical structure of potential fracturing fluid constituents. (Updated July
2011) .................................................................................................................................................. 5-58
Table 5.9 - Parameters present in a limited set of flowback analytical results (Updated July 2011) ...................... 5-95
Table 5.10 - Typical concentrations of flowback constituents based on limited samples from PA and WV,
and regulated in NY (Revised July 2011) ............................................................................................ 5-99
Table 5.11 - Typical concentrations of flowback constituents based on limited samples from PA and WV,
not regulated in NY(Revised July 2011)............................................................................................ 5-102
Table 5.12 - Conventional Analytes In MSC Study (New July 2011) ...................................................................... 5-103
Table 5.13 - Total and Dissolved Metals Analyzed In MSC Study (New July 2011)................................................ 5-104
Table 5.14 - Volatile Organic Compounds Analyzed in MSC Study (New July 2011) ............................................. 5-105
Table 5.15 - Semi-Volatile Organics Analyzed in MSC Study (New July 2011) ....................................................... 5-106
Table 5.16 - Organochlorine Pesticides Analyzed in MSC Study (New July 2011) ................................................. 5-107
Table 5.17 - PCBs Analyzed in MSC Study (New July 2011) ................................................................................... 5-107
Table 5.18 - Organophosphorus Pesticides Analyzed in MSC Study (New July 2011) ........................................... 5-107
Table 5.19 - Alcohols Analyzed in MSC Study (New July 2011) ............................................................................. 5-107
Table 5.20 - Glycols Analyzed in MSC Study (New July 2011)................................................................................ 5-107
Table 5.21 - Acids Analyzed in MSC Study (New July 2011) .................................................................................. 5-107
Table 5.22 - Parameter Classes Analyzed for in the MSC Study (New July 2011).................................................. 5-108
Table 5.23 - Parameter Classes Detected in Flowback Analyticals in MSC Study (New July 2011) ....................... 5-109
Table 5.24 - Concentrations of NORM constituents based on limited samples from PA and WV (Revised
July 2011) ......................................................................................................................................... 5-112
Table 5.25 - Maximum allowable water quality requirements for fracturing fluids, based on input from one
expert panel on Barnett Shale (Revised July 2011) .......................................................................... 5-113
Table 5.26 - Treatment capabilities of EDR and RO Systems ................................................................................. 5-121
Table 5.27 - Summary of Characteristics of On-Site Flowback Water Treatment Technologies (Updated July
2011) ................................................................................................................................................ 5-123
Table 5.28 - Out-of-state treatment plants proposed for disposition of NY flowback water................................ 5-127
Table 5.29 - Primary Pre-Production Well Pad Operations (Revised July 2011) .................................................... 5-129
Table 5.30 - Marcellus Gas Composition from Bradford County, PA..................................................................... 5-131
Table 6.1 - Comparison of additives used or proposed for use in NY, parameters detected in analytical
results of flowback from the Marcellus operations in PA and WV and parameters regulated via
primary and secondary drinking water standards, SPDES or TOGS111 (Revised August 2011) ........... 6-19
Table 6.2 - Grassland Bird Population Trends at Three Scales from 1966 to 2005. (New July 2011) ..................... 6-74
Table 6.3 - Terrestrial Invasive Plant Species In New York State (Interim List) ....................................................... 6-85
Table 6.4 - Aquatic, Wetland & Littoral Invasive Plant Species in New York State (Interim List) ............................ 6-88
Table 6.5 - Endangered & Threatened Animal Species within the Area Underlain by the Marcellus Shale
(New July 2011) ..................................................................................................................................... 6-90
Table 6.6 - EPA AP-42 Emissions Factors Tables ................................................................................................... 6-101
Table 6.7 - Estimated Wellsite Emissions (Dry Gas) - Flowback Gas Flaring (Tpy)(Updated July 2011) ................ 6-107
Table 6.8 - Estimated Wellsite Emissions (Dry Gas) - Flowback Gas Venting (Tpy)(Updated July 2011) .............. 6-107
Table 6.9 - Estimated Wellsite Emissions (Wet Gas) - Flowback Gas Flaring (Tpy) (Updated July 2011) .............. 6-107
Table 6.10 - Estimated Wellsite Emissions (Wet Gas) - Flowback Gas Venting (Tpy) (Updated July 2011) .......... 6-107
Table 6.11 - Estimated Off-Site Compressor Station Emissions (Tpy) ................................................................... 6-108
Table 6.12 - Sources and Pollutants Modeled for Short-Term Simultaneous Operations .................................... 6-160
Table 6.13 - National Weather Service Data Sites Used in the Modeling ............................................................. 6-160
Table 6.14 - National Ambient Air Quality Standards (NAAQS), PSD Increments & Significant Impact Levels
3
(SILs) for Criteria Pollutants (µg/m ) ................................................................................................. 6-161
Table 6.15 - Maximum Background Concentration from Department Monitor Sites .......................................... 6-162
Table 6.16 - Maximum Impacts of Criteria Pollutants for Each Meteorological Data Set ..................................... 6-163

Final SGEIS 2015, Page xix

 Table 6.17 - Maximum Project Impacts of Criteria Pollutants and Comparison to SILs, PSD Increments and
Ambient Standards ........................................................................................................................... 6-164
Table 6.18 - Maximum Impacts of Non-Criteria Pollutants and Comparisons to SGC/AGC and New York
State AAQS ........................................................................................................................................ 6-165
Table 6.19 - Modeling Results for Short Term PM10, PM2.5 and NO2 (New July 2011) ...................................... 6-166
Table 6.20 - Engine Tiers and Use in New York with Recommended Mitigation Controls Based on the
Modeling Analysis (New July 2011) .................................................................................................. 6-167
Table 6.21 - Predicted Ozone Precursor Emissions (Tpy) ...................................................................................... 6-176
Table 6.22 - Barnett Shale Annual Average Emissions from All Sources ............................................................... 6-180
Table 6.23 - Near-Field Pollutants of Concern for Inclusion in the Near-Field Monitoring Program (New
July 2011) .......................................................................................................................................... 6-184
Table 6.24 - Department Air Quality Monitoring Requirements for Marcellus Shale Activities (New July
2011) ................................................................................................................................................. 6-187
Table 6.25 - Assumed Drilling & Completion Time Frames for Single Vertical Well (New July 2011) ................... 6-195
Table 6.26 - Assumed Drilling & Completion Time Frames for Single Horizontal Well (Updated July 2011) ........ 6-195
Table 6.27 - Global Warming Potential for Given Time Horizon ........................................................................... 6-204
Table 6.28 - Summary of Estimated Greenhouse Gas Emissions (Revised July 2011) .......................................... 6-205
Table 6.29 - Emission Estimation Approaches – General Considerations ............................................................. 6-207
Table 6.30 - Radionuclide Half-Lives ..................................................................................................................... 6-209
Table 6.31 - Major Development Scenario Assumptions (New August 2011) ...................................................... 6-212
Table 6.32 - Maximum Direct and Indirect Employment Impacts on New York State under Each
Development Scenario (New August 2011) ...................................................................................... 6-216
Table 6.33 - Maximum Direct and Indirect Annual Employee Earnings Impacts on New York State under
Each Development Scenario (New August 2011) ............................................................................. 6-219
Table 6.34 - Major Development Scenario Assumptions for Each Representative Region (New August
2011) ................................................................................................................................................. 6-221
Table 6.35 - Maximum Direct and Indirect Employment Impacts on Each Representative Region under
Each Development Scenario (New August 2011) ............................................................................. 6-223
Table 6.36 - Maximum Direct and Indirect Earnings Impacts on Each Representative Region under Each
Development Scenario (New August 2011) ...................................................................................... 6-231
Table 6.37 - Transient, Permanent and Total Construction Employment Under Each Development Scenario
for Select Years: New York State (New August 2011) ....................................................................... 6-237
Table 6.38 - Estimated Population Associated with Construction and Production Employment for Select
Years: New York State (New August 2011) ....................................................................................... 6-238
Table 6.39 - Maximum Temporary and Permanent Impacts Associated with Well Construction and
Production: New York State (New August 2011) .............................................................................. 6-240
Table 6.40 - Transient, Permanent, and Total Construction Employment Under Each Development
Scenario for Select Years for Representative Region A (New August 2011) ..................................... 6-241
Table 6.41 - Transient, Permanent, and Total Construction Employment Under Each Development
Scenario for Select Years for Representative Region B (New August 2011) ..................................... 6-241
Table 6.42 - Transient, Permanent, and Total Construction Employment Under Each Development
Scenario for Select Years for Representative Region C (New August 2011) ..................................... 6-242
Table 6.43 - Maximum Temporary and Permanent Impacts Associated with Well Construction and
Production ........................................................................................................................................ 6-243
Table 6.44 - Maximum Estimated Employment by Development Scenario for New York State (New August
2011) ................................................................................................................................................. 6-246
Table 6.45 - New York State Rental Housing Stock (2010) (New August 2011) .................................................... 6-247
Table 6.46 - Availability of Owner-Occupied Housing Units (2010) (New August 2011) ...................................... 6-248
Table 6.47 - Maximum Transient and Permanent Employment by Development Scenario and Region (New
August 2011) ..................................................................................................................................... 6-248
Table 6.48 - Availability of Rental Housing Units (New August 2011)................................................................... 6-250
Table 6.49 - Availability of Housing Units (New August 2011) .............................................................................. 6-252

Final SGEIS 2015, Page xx

 Table 6.50 - Example of the Real Property Tax Payments From a Typical Horizontal Well (New August
2011) ................................................................................................................................................. 6-262
Table 6.51 - Example of the Real Property Tax Payments from a Typical Vertical Well (New August 2011)........ 6-264
Table 6.52 - Projected Change in Total Assessed Value and Property Tax Receipts at Peak Production (Year
30), by Region (New August 2011).................................................................................................... 6-264
Table 6.53 - Summary of Generic Visual Impacts Resulting from Horizontal Drilling and Hydraulic
Fracturing in the Marcellus and Utica Shale Area of New York (New August 2011) ........................ 6-288
Table 6.54 - Estimated Construction Noise Levels at Various Distances for Access Road Construction (New
August 2011) ..................................................................................................................................... 6-295
Table 6.55 - Estimated Construction Noise Levels at Various Distances for Well Pad Preparation (New
August 2011) ..................................................................................................................................... 6-296
Table 6.56 - Estimated Construction Noise Levels at Various Distances for Rotary Air Well Drilling (New
August 2011) ..................................................................................................................................... 6-298
Table 6.57 - Estimated Construction Noise Levels at Various Distances for Horizontal Drilling (New August
2011) ................................................................................................................................................. 6-298
Table 6.58 - Estimated Construction Noise Levels at Various Distances for High-Volume Hydraulic
Fracturing (New August 2011) .......................................................................................................... 6-300
Table 6.59 - Assumed Construction and Development Times (New August 2011) .............................................. 6-301
Table 6.60 - Estimated Number of One-Way (Loaded) Trips Per Well: Horizontal Well (New August 2011) ....... 6-305
Table 6.61 - Estimated Number of One-Way (Loaded) Trips Per Well: Vertical Well (New August 2011) ........... 6-306
Table 6.62 - Estimated Truck Volumes for Horizontal Wells Compared to Vertical Wells (New August 2011) .... 6-306
Table 6.63 - Estimated Annual Heavy Truck Trips (in thousands) (New August 2011) ......................................... 6-312
Table 6.64 - Illustrative AADT Range for State Roads (New August 2011) ............................................................ 6-313
Table 7.1 - Regulations Pertaining to Watershed Withdrawal (Revised July 2011) ................................................. 7-8
Table 7.2 - Regional Passby Flow Coefficients (cfs/sq. mi.) (Updated August 2011) .............................................. 7-22
Table 7.3 - NYSDOH Water Well Testing Recommendations ................................................................................. 7-46
Table 7.4 - Principal Species Found in the Four Grassland Focus Areas within the area underlain by the
Marcellus Shale in New York (New July 2011) .......................................................................................7-81
Table 7.5 - Summary of Regulations Pertaining to Transfer of Invasive Species .................................................... 7-93
Table 7.6 - Required Well Pad Stack Heights to Prevent Exceedances................................................................. 7-108
Table 8.1 - Regulatory Jurisdictions Associated with High-Volume Hydraulic Fracturing (Revised July 2011).......... 8-3
Table 8.2 - Intrastate Pipeline Regulation ............................................................................................................... 8-10
Table 8.3 - Water Resources and Private Dwelling Setbacks from Alpha, 2009 ...................................................... 8-59
Table 9.1 - Marcellus Permits Issued in Pennsylvania, 2007 - 2010 .......................................................................... 9-6
Table 11.1 - Summary of Potential Impacts and Proposed Mitigation Measures (New July 2011) ........................ 11-2
PHOTOS
Photo 5.1 - Access Road and Erosion/Sedimentation Controls, Salo 1, Barton, Tioga County NY ............................ 5-4
Photo 5.2 - Access Road, Nornew Smyrna Hillbillies 2H, Smyrna, Madison County NY ............................................ 5-4
Photo 5.3 - In-Service Access Road to Horizontal Marcellus well in Bradford County PA ......................................... 5-5
Photo 5.4 - Access Road and Sedimentation Controls, Moss 1, Corning, Steuben County NY .................................. 5-5
Photo 5.5 - Chesapeake Energy Marcellus Well Drilling, Bradford County, PA ......................................................... 5-8
Photo 5.6 - Hydraulic fracturing operation, Horizontal Marcellus Well, Upshur County, WV .................................. 5-8
Photo 5.7 - Hydraulic Fracturing Operation, Horizontal Marcellus Well, Bradford County, PA ................................ 5-9
Photo 5.8 - Locations of Over 44,000 Natural Gas Wells Targeting the Medina Formation, Chautauqua
County NY........................................................................................................................................... 5-13
Photo 5.9 - Locations of 48 Natural Gas Wells Targeting the Medina Formation, Chautauqua County NY ............ 5-14
Photo 5.10 - Locations of 28 Wells in the Town of Poland, Chautauqua County NY ............................................... 5-15
Photo 5.11 - Locations of 77 Wells in the Town of Sheridan, Chautauqua County NY............................................ 5-16
Photo 5.12 - Double Drilling Rig, Union Drilling Rig 54, Olsen 1B, Town of Fenton, Broome County NY ................ 5-24
Photo 5.13 - Double Drilling Rig, Union Drilling Rig 48, Salo 1, Town of Barton, Tioga County NY ......................... 5-24
Photo 5.14 - Triple Drilling Rig, Precision Drilling Rig 26, Ruger 1, Horseheads, Chemung County NY ................... 5-25

Final SGEIS 2015, Page xxi

 Photo 5.15 - Top Drive Single Drilling Rig, Barber and DeLine Rig, Sheckells 1, Town of Cherry Valley,
Otsego County NY .............................................................................................................................. 5-25
Photo 5.16 - Drilling rig mud system (blue tanks) ................................................................................................... 5-28
Photo 5.17 - Sand used as proppant in hydraulic fracturing operation in Bradford County, PA ............................. 5-47
Photo 5.18 - Transport trucks with totes ................................................................................................................. 5-75
Photo 5.19 - Fortuna SRBC-Approved Chemung River Water Withdrawal Facility, Towanda PA ........................... 5-79
Photo 5.20 - Fresh Water Supply Pond.................................................................................................................... 5-79
Photo 5.21 - Water Pipeline from Fortuna Centralized Freshwater Impoundments, Troy PA ................................ 5-79
Photo 5.22 - Construction of Freshwater Impoundment, Upshur County WV........................................................ 5-80
Photo 5.23 - Personnel monitoring a hydraulic fracturing procedure. Source: Fortuna Energy. ............................ 5-84
Photo 5.24 - Three Fortuna Energy wells being prepared for hydraulic fracturing, with 10,000 psi well head
and goat head attached to lines. Troy PA. Source: New York State Department of
Environmental Conservation 2009 ..................................................................................................... 5-86
Photo 5.25 - Hydraulic Fracturing Operation Equipment at a Fortuna Energy Multi-Well Site, Troy PA ................ 5-90
Photo 5.26 - Fortuna Energy Multi-Well Site in Troy PA After Removal of Most Hydraulic Fracturing
Equipment .......................................................................................................................................... 5-91
Photo 5.27 - Wellhead and Fracturing Equipment .................................................................................................. 5-91
Photo 5.28 - Pipeline Compressor in New York. Source: Fortuna Energy ............................................................. 5-137
Photo 6.1 - A representative view of completion activities at a recently constructed well pad (New August
2011) ................................................................................................................................................ 6-270
Photo 6.2 - A representative view of completion activities at a recently constructed well pad, showing a
newly created access road in foreground (New August 2011) ........................................................ 6-271
Photo 6.3 - A representative view of a newly constructed water impoundment area (New August 2011) ......... 6-272
Photo 6.4 - A representative view of a water procurement site (New August 2011) ........................................... 6-272
Photo 6.5 - A representative view of active high-volume hydraulic fracturing (New August 2011) ..................... 6-274
Photo 6.6 - Electric Generators, Active Drilling Site (New August 2011) ............................................................... 6-299
Photo 6.7 - Truck-mounted Hydraulic Fracturing Pump (New August 2011) ........................................................ 6-300
Photo 6.8 - Hydraulic Fracturing of a Marcellus Shale Well Site (New August 2011) ............................................ 6-301
Photo 6.9 - Map Depicting Trenton-Black River Wells and Historical Wells Targeting Other Formations in
Chemung County ................................................................................................................................ 6-332
Photo 6.10 - Map Depicting the Location of Trenton-Black River Wells in the Eastern-end of Quackenbush
Hill Field ............................................................................................................................................ 6-333
Photo 6.11 - Trenton-Black River Well Site (Rhodes) ............................................................................................ 6-333
Photo 6.12 - Trenton-Black River Well Site (Gregory) ........................................................................................... 6-334
Photo 6.13 - Trenton-Black River Well Site (Schwingel) ........................................................................................ 6-334
Photo 6.14 - Trenton-Black River Well Site (Soderblom) ....................................................................................... 6-335
Photo 6.15 - Map Depicting the Locations of Two Trenton Black River Wells in North-Central Chemung
County .............................................................................................................................................. 6-336
Photo 6.16 - Trenton-Black River Well Site (Little) ................................................................................................ 6-337
Photo 6.17 - Trenton-Black River Well Site (Hulett) .............................................................................................. 6-337
Photo 6.18 - Map Depicting the Location of Trenton-Black River Wells in Western Chemung County and
Eastern Steuben County ................................................................................................................... 6-338
Photo 6.19 - Trenton-Black River Well Site (Lovell) ............................................................................................... 6-339
Photo 6.20 - Trenton Black River Well Site (Henkel) ............................................................................................. 6-339
Photo 7.1 - View of a well site during the fracturing phase of development, with maximum presence of on-site
equipment. (New August 2011) ......................................................................................................... 7-124
Photo 7.2 - Sound Barrier. Source: Ground Water Protection Council, Oklahoma City, OK and ALL Consulting, Tulsa
OK, 2009 (New August 2011) ..............................................................................................................7-131
Photo 7.3 - Sound Barrier Installation (New August 2011) .................................................................................. 7-132
Photo 7.4 - Sound Barrier Installation (New August 2011) .................................................................................. 7-132

Final SGEIS 2015, Page xxii

 VOLUME 2
RESPONSE TO COMMENTS
INTRODUCTION .............................................................................................................................................. RTC-1
1.

SEQRA AND SAPA ................................................................................................................................... RTC-9
GENERAL SEQRA .......................................................................................................................................... RTC-9
FUTURE SEQRA COMPLIANCE........................................................................................................................ RTC-12
ALTERNATIVES ............................................................................................................................................ RTC-14
SAPA ....................................................................................................................................................... RTC-18

2.

PERMIT PROCESS AND REGULATORY COORDINATION ......................................................................... RTC-19
GENERAL – PERMIT PROCESS ......................................................................................................................... RTC-19
INTERAGENCY COORDINATION ........................................................................................................................ RTC-31
LOCAL GOVERNMENT NOTIFICATION AND COORDINATION .................................................................................... RTC-39
HYDRAULIC FRACTURING INFORMATION ........................................................................................................... RTC-45

3.

PROHIBITED LOCATIONS....................................................................................................................... RTC-54
GENERAL PROHIBITIONS................................................................................................................................ RTC-54
NYC AND SYRACUSE WATERSHEDS AND 4,000-FOOT BUFFER .............................................................................. RTC-61
OTHER PUBLIC DRINKING SUPPLIES AND 2,000-FOOT BUFFER .............................................................................. RTC-66
PRIVATE WATER WELLS AND 500-FOOT BUFFER ................................................................................................ RTC-70
PRIMARY AQUIFERS AND 500-FOOT BUFFER ..................................................................................................... RTC-73
STATE-OWNED LANDS .................................................................................................................................. RTC-78
100-YEAR FLOODPLAINS............................................................................................................................... RTC-82

4.

GEOLOGY.............................................................................................................................................. RTC-85
GENERAL GEOLOGY...................................................................................................................................... RTC-85
SEISMICITY ................................................................................................................................................. RTC-87
NATURALLY OCCURRING RADIOACTIVE MATERIALS ............................................................................................. RTC-93

5.

POTENTIAL ENVIRONMENTAL IMPACTS AND MITIGATION ................................................................ RTC-106
WATER RESOURCES ................................................................................................................................... RTC-106
WELL CONSTRUCTION ................................................................................................................................ RTC-126
HYDRAULIC FRACTURING............................................................................................................................. RTC-135
FRACTURING FLUID AND FLOWBACK .............................................................................................................. RTC-143
FLOWBACK WATER AND OTHER IMPOUNDMENTS ............................................................................................. RTC-147
WASTE TRANSPORT AND DISPOSAL ............................................................................................................... RTC-150

Final SGEIS 2015, Page xxiii

 SETBACKS ................................................................................................................................................ RTC-159
FLOODPLAINS ........................................................................................................................................... RTC-167
WETLANDS .............................................................................................................................................. RTC-168
LAND RESOURCES ...................................................................................................................................... RTC-171
ECOSYSTEMS AND WILDLIFE ......................................................................................................................... RTC-175
AIR QUALITY AND GREENHOUSE GAS EMISSIONS.............................................................................................. RTC-186
SOCIOECONOMIC ....................................................................................................................................... RTC-220
VISUAL RESOURCES .................................................................................................................................... RTC-259
NOISE ..................................................................................................................................................... RTC-264
TRANSPORTATION ..................................................................................................................................... RTC-268
COMMUNITY CHARACTER ............................................................................................................................ RTC-274
CULTURAL RESOURCES ................................................................................................................................ RTC-280
6.

CUMULATIVE IMPACTS ....................................................................................................................... RTC-282

7.

HEALTH IMPACTS ............................................................................................................................... RTC-294

8.

ENFORCEMENT ................................................................................................................................... RTC-305

9.

OTHER ................................................................................................................................................ RTC-318
OTHER STATES’ REGULATIONS ...................................................................................................................... RTC-318
INCIDENTS IN NY AND OTHER STATES ............................................................................................................ RTC-322
COMPULSORY INTEGRATION ........................................................................................................................ RTC-327
LEASES .................................................................................................................................................... RTC-331
ALTERNATIVE ENERGY ................................................................................................................................ RTC-333
PIPELINES/COMPRESSOR STATIONS ............................................................................................................... RTC-334

APPENDIX A PUBLIC HEALTH REVIEW OF SHALE GAS DEVELOPMENT ........................................................ RTC A-1
APPENDIX B MODELING OF OZONE IMPACTS FROM WELL PAD ACTIVITIES AND ASSOCIATED TRUCK
TRAFFIC AND COMPRESSOR STATIONS FOR FUTURE PEAK WELL DEVELOPMENT
CONDITIONS IN THE MARCELLUS SHALE AREA OF NEW YORK STATE .................................... RTC B-1
APPENDIX C DISPERSION MODELING INPUT AND OUTPUT DATA, SENSITIVITY ANALYSIS AND
EXPLANATION OF NAAQS AND TOXICS THRESHOLD ESTABLISHMENT PROCESS .................... RTC C-1

Final SGEIS 2015, Page xxiv

 NEW YORK Department of

STATE OF .

OPPORTUNITYW Envuronmental
Conservation

 

Executive Summary

Final

Supplemental Generic Environmental Impact Statement



This page intentionally left blank.

EXECUTIVE SUMMARY
High-volume hydraulic fracturing utilizes a well stimulation technique that has greatly increased
the ability to extract natural gas from very tight rock. High-volume hydraulic fracturing, which
is often used in conjunction with horizontal drilling and multi-well pad development, raises new,
significant, adverse impacts not studied in 1992 in the Department of Environmental
Conservation’s (Department or DEC) previous Generic Environmental Impact Statement (1992
GEIS) on the Oil, Gas and Solution Mining Regulatory Program. 1
Since issuing a draft Scope for public review in October 2008, the Department has conducted an
exhaustive evaluation of high-volume hydraulic fracturing’s potential significant adverse
environmental and public health impacts and possible mitigation measures to eliminate, avoid or
reduce those impacts. The Department received over 260,000 public comments, an
unprecedented number, on the 2009 Draft SGEIS (dSGEIS) and the 2011 Revised Draft SGEIS
(rdSGEIS) and the associated regulatory documents which were considered before issuing this
Final SGEIS (FSGEIS) (the drafts and the final SGEIS are collectively referred to as the
“SGEIS,” unless otherwise distinguished). During this period of time, a broad range of experts
from academia, industry, environmental organizations, municipalities, and the medical and
public health professions commented and/or provided their analyses of high-volume hydraulic
fracturing. The comments referenced an increasing number of ongoing scientific studies across a
wide range of professional disciplines. These studies and expert comments evidence that
significant uncertainty remains regarding the level of risk to public health and the environment
that would result from permitting high-volume hydraulic fracturing in New York, and regarding
the degree of effectiveness of proposed mitigation measures. In fact, the uncertainty regarding
the potential significant adverse environmental and public health impacts has been growing over
time.

1

The Generic Environmental Impact Statement (1992 GEIS) on the Oil, Gas and Solution Mining Regulatory
Program is posted on the Department’s website at http://www.dec.ny.gov/energy/45912.html. The 1992 GEIS
includes an analysis of impacts from vertical gas drilling as well as hydraulic fracturing. Since 1992 the
Department has used the 1992 GEIS as the basis of its State Environmental Quality Review Act (SEQRA)
review for permit applications for gas drilling in New York State.

Final SGEIS 2015, Executive Summary, Page 1

 The Department worked closely with the New York State Department of Health (NYSDOH)
during preparation of the SGEIS. Due to the increasing concern regarding high-volume
hydraulic fracturing’s impacts on public health, the Department on September 20, 2012,
requested NYSDOH to conduct a review of the SGEIS and mitigation measures and advise the
Department whether they were adequate to protect public health. On December 17, 2014,
NYSDOH advised the Department that there are several potential adverse environmental impacts
that can result from high-volume hydraulic fracturing which may be associated with adverse
public health outcomes. These impacts include: 1) air impacts that could affect respiratory
health due to increased levels of particulate matter, diesel exhaust, or volatile organic chemicals;
2) climate change impacts due to methane and other volatile organic chemical releases to the
atmosphere ; 3) drinking water impacts from underground migration of methane and/or
fracturing fluid chemicals associated with faulty well construction or seismic activity; 4) surface
spills potentially resulting in soil, groundwater, and surface water contamination; 5) surface
water contamination resulting from inadequate wastewater treatment; 6) earthquakes and
creation of fissures induced during the hydraulic fracturing stage; and 7) community character
impacts such as increased vehicle traffic, road damage, noise, odor complaints, and increased
local demand for housing and medical care. NYSDOH concluded that “until the science
provides sufficient information to determine the level of risk to public health from HVHF to all
New Yorkers and whether the risks can be adequately managed … HVHF should not proceed in
New York State.”
The Department concurs with NYSDOH, as the uncertainty revolving around potential public
health impacts stems from many of the significant adverse environmental risks identified in the
SGEIS for which the Department proposed and considered extensive mitigation measures. In
response to additional scientific information regarding the magnitude of high-volume hydraulic
fracturing’s potential significant adverse impacts, the Department considered expanding many
of the mitigation measures previously proposed in the rdSGEIS to protect public health and the
environment with a greater margin of safety.
As a result, more and more area within the Marcellus Shale fairway would be off limits to highvolume hydraulic fracturing. For example, the Department considered prohibiting high-volume
hydraulic fracturing on private lands within the Catskill Park, increasing setbacks to residences,

Final SGEIS 2015, Executive Summary, Page 2

 and natural and cultural resources, and expanding the sensitive areas that would be off limits.
The additional restrictions and prohibitions and the necessity for close and coordinated
regulatory oversight by the Department with involved and interested state and local agencies
would substantially increase costs to industry, which would likely negatively impact the potential
economic benefits associated with high-volume hydraulic fracturing..
The Court of Appeals decision in Matter of Wallach v. Town of Dryden and Cooperstown
Holstein Corp. v. Town of Middlefield, which held that local governments could exercise their
zoning and land use jurisdiction to restrict or prohibit high-volume hydraulic fracturing within
their communities, would impact prior economic projections and would likely result in a
decrease in potential economic benefits. This would also create potential land use conflicts with
high-volume hydraulic fracturing’s ancillary infrastructure in communities that reject highvolume hydraulic fracturing within their borders.
General Background
The Department has received applications for permits to drill horizontal wells to evaluate and
develop the Marcellus Shale for natural gas production by high-volume hydraulic fracturing. In
New York, the primary target for shale-gas development is currently the Marcellus Shale, with
the deeper Utica Shale also identified as a potential resource. Additional low-permeability
reservoirs may be considered by project sponsors for development by high-volume hydraulic
fracturing.
Horizontal drilling with high-volume hydraulic fracturing facilitates natural gas extraction from
large areas where conventional natural gas extraction is commercially unprofitable; thus, well
operations would likely be widespread across certain regions within the Marcellus formation.
Distinct from conventional natural gas extraction technologies governed by the Department’s
1992 GEIS and related oil and gas permits, high-volume hydraulic fracturing involves
substantially larger volumes of water and a multitude of potential chemical additives. The use of
high-volume hydraulic fracturing with horizontal well drilling technology enables a number of
wells to be drilled from a single well pad (multi-pad wells). Although horizontal drilling results

Final SGEIS 2015, Executive Summary, Page 3

 in fewer well pads than traditional vertical well drilling, the pads are larger and the industrial
activity taking place on the pads is more intense.
Hydraulic fracturing requires chemical additives, some of which potentially pose hazards to
public health and the environment through exposure. The high volume of water associated with
hydraulic fracturing may also result in significant adverse impacts relating to water supplies,
other water resources, wastewater treatment and disposal, and truck traffic. Horizontal wells also
generate greater volumes of drilling waste (cuttings) than vertical wells. The industry
projections of the level of drilling, as reflected in the intense development activity in neighboring
Pennsylvania, has raised additional concerns relating to community character, including noise,
and visual impacts; adverse impacts on cultural and historic resources, agriculture, tourism, and
scenic resources; and socioeconomics impacts.
The Department has prepared this Final Supplemental Generic Environmental Impact Statement
(Final SGEIS) to satisfy the requirements of the State Environmental Quality Review Act
(SEQRA) by examining high-volume hydraulic fracturing and identifying new potential
significant adverse impacts of these operations.
The Department’s environmental review associated with the Department’s determination
whether to authorize high-volume hydraulic fracturing in New York State required extensive
evaluation of the current and developing science underlying high-volume hydraulic fracturing’s
impacts and the increasingly stringent mitigation measures to protect the environment and public
health.
SEQRA Procedure to Date
The public process to develop the SGEIS began with public scoping sessions in the autumn of
2008. Since then, engineers, geologists and other scientists and specialists in all of the
Department’s natural resources and environmental quality programs have collaborated to
comprehensively analyze a vast amount of information about the proposed operations and the
potential significant adverse impacts of these operations on the environment, identify mitigation
measures that would prevent or minimize any significant adverse impacts, and identify criteria
and conditions for future permit approvals and other regulatory action.

Final SGEIS 2015, Executive Summary, Page 4

 In September 2009, the Department issued an initial dSGEIS (2009 dSGEIS) for public review
and comment. The extensive public comments revealed a significant concern with potential
contamination of groundwater and surface drinking water supplies that could result from this
new stimulation technique. Concerns raised included comments that the 2009 dSGEIS did not
fully study the potential for gas migration from this new technique, or adequately consider
impacts from disposal of solid and liquid wastes. Additionally, commenters stated the 2009
dSGEIS did not contain sufficient consideration of visual, noise, traffic, community character or
socioeconomic impacts. Accordingly, in 2010 Governor Paterson ordered the Department to
issue a revised dSGEIS (rdSGEIS) on or about June 1, 2011. Executive Order 41 also provided
that no permits authorizing high-volume hydraulic fracturing would be issued until the SGEIS
was finalized.
Since the issuance of the 2009 dSGEIS, and the subsequent rdSGEIS, the Department has gained
a more detailed understanding of the potential impacts associated with high-volume hydraulic
fracturing with horizontal drilling from: (i) the extensive public comments from environmental
organizations, municipalities, industry groups, medical and public health professionals, and other
members of the public; (ii) its review of reports and studies of proposed operations prepared by
industry groups; (iii) extensive consultations with scientists in several bureaus within the
NYSDOH; (iv) the use of outside consulting firms to prepare analyses relating to socioeconomic
impacts, as well as impacts on community character, including visual, noise and traffic impacts;
and, (v) its review of information and data from the Pennsylvania Department of Environmental
Protection (PADEP) and the Susquehanna River Basin Commission (SRBC) about events,
regulations, enforcement and other matters associated with ongoing Marcellus Shale
development in Pennsylvania. In June 2011, moreover, Commissioner Joseph Martens and
Department staff visited a well pad in LeRoy, Pennsylvania, where contaminants had discharged
from the well pad into an adjacent stream, and had further conversations with industry
representatives and public officials about that event and high-volume hydraulic fracturing
operations in Pennsylvania generally.
In addition, as discussed above, NYSDOH conducted a comprehensive health review of highvolume hydraulic fracturing and completed its Public Health Review in December 2014.

Final SGEIS 2015, Executive Summary, Page 5

 During preparation of this Final SGEIS, the Department incorporated suggestions made by the
public and, where appropriate, provided additional discussion in either the Final SGEIS or the
Response to Comments to clarify the content of the drafts. Specifically, the Department has
revised Chapter 1 to reflect all of the procedural changes and actions that have occurred
following the time of publication of the rdSGEIS for public comment. In Chapter 2, a subsection
drafted in 2011 relating to the potential public need and benefit of high-volume hydraulic
fracturing was deleted because the subject is now addressed more accurately in the Department’s
Response to Comments, which is based on analysis subsequent to the rdSGEIS and public
comment. The Department also revised Chapter 7 of the Final SGEIS to remove conclusory
language with respect to the mitigation proposed, to better reflect remaining uncertainty as to the
effectiveness or the degree to which the mitigation would reduce impacts and risks associated
with high-volume hydraulic fracturing. The Department also revised Chapter 9 to better
represent both the benefits and negative consequences of the No Action Alternative. This
Executive Summary was also revised to reflect these changes, as well as to reflect some of the
additional mitigation measures that were considered by the Department. These minor changes to
the SGEIS do not reflect that some laws or regulations may have changed from the time of
publication of the 2011 rdSGEIS, notably, amendments to the Water Resources Law and
corresponding regulations.
Pursuant to 6 NYCRR Section 617.9(b)(8), the Final SGEIS consists of the prior drafts of the
SGEIS, including all revisions noted above and the summary of the substantive comments
received and the Department’s responses, which both comprise the Department’s Response to
Comments. Consequently, the findings for this action will consider the relevant environmental
and public health impacts, mitigation measures and facts discussed in the Final SGEIS, prior
drafts of the SGEIS, and the 1992 GEIS, including the Department’s Response to Comments.
The Department’s Response to Comments represents the Department’s most current assessment
of the impacts associated with high-volume hydraulic fracturing and the effectiveness of
proposed or considered mitigation measures to adequately mitigate significant adverse
environmental and public health impacts.
Each chapter of this final SGEIS is summarized below.

Final SGEIS 2015, Executive Summary, Page 6

 Chapter 1 – Introduction
This Chapter contains background information and an introduction to the SGEIS.
Chapter 2 – Description of Proposed Action
This Chapter includes a discussion of the purpose of proposed high-volume hydraulic fracturing
operations, as well as the potential locations, projected activity levels, and environmental setting
for such operations. Information on the environmental setting focuses on topics determined
during scoping to require attention in the SGEIS. The Department determined, based on industry
projections in 2010 that it would potentially receive applications to drill approximately 1,700 2,500 horizontal and vertical wells for development of the Marcellus Shale by high-volume
hydraulic fracturing during a “peak development” year, if high-volume hydraulic fracturing were
authorized. Based on these projections, an average year could see 1,600 or more applications.
Development of the Marcellus Shale in New York could occur over a 30-year period. A
consultant to the Department completed a draft estimate of the potential economic and public
benefits of proposed high-volume hydraulic fracturing development, including an analysis based
on an average development scenario as well as a more conservative low potential development
scenario. That analysis calculates for each scenario the total economic value to the proposed
operations, potential state and local tax revenue, and projected total job creation. However,
given the cost of compliance with New York State’s draft high-volume hydraulic fracturing
program conditions, the Matter of Wallach v. Town of Dryden and Cooperstown Holstein Corp.
v. Town of Middlefield decision, the areas where high-volume hydraulic fracturing would be
prohibited or restricted by the SGEIS, and the economics of oil and gas production, the
Department cannot with any certainty predict how many applications would be submitted if
high-volume hydraulic fracturing were authorized. However even with a reduced economic
outlook, it remains likely that high-volume hydraulic fracturing would be widespread and would
impact areas that previously have not been exposed to oil and gas development. In fact, if highvolume hydraulic fracturing were authorized, the proposed restrictions and prohibitions in certain
areas would likely lead to intensified development in those areas where high-volume hydraulic
volume would be permissible. Moreover, as discussed below, beyond directly impacting those
particular areas where the activity would be allowed, the ancillary activities associated with high-

Final SGEIS 2015, Executive Summary, Page 7

 volume hydraulic fracturing and their corresponding significant adverse impacts would likely
spread to those areas of the State where high-volume hydraulic fracturing is prohibited.
Chapter 3 – Proposed SEQRA Review Process
This Chapter describes how the Department would use the 1992 GEIS and the Final SGEIS in
reviewing applications to conduct high-volume hydraulic fracturing operations in New York
State if high-volume hydraulic fracturing were authorized. It describes the proposed
Environmental Assessment Form (EAF) addendum requirements that would be used in
connection with high-volume hydraulic fracturing applications, and also identifies those potential
activities that would require site-specific SEQRA determinations of significance after the SGEIS
is completed. Specifically, Chapter 3 states that site-specific environmental assessments and
SEQRA determinations of significance would be required for the following types of high-volume
hydraulic fracturing applications, regardless of the target formation, the number of wells drilled
on the pad and whether the wells are vertical or horizontal (the Department considered
expanding some of the distances listed below):
1) Any proposed high-volume hydraulic fracturing where the top of the target fracture zone
is shallower than 2,000 feet along a part of the proposed length of the wellbore;
2) Any proposed high-volume hydraulic fracturing where the top of the target fracture zone
at any point along the entire proposed length of the wellbore is less than 1,000 feet below
the base of a known fresh water supply;
3) Any proposed well pad within the boundaries of a principal aquifer, or outside but within
500 feet of the boundaries of a principal aquifer;
4) Any proposed well pad within 150 feet of a perennial or intermittent stream, storm drain,
lake or pond;
5) A proposed surface water withdrawal that is found not to be consistent with the
Department’s preferred passby flow methodology as described in Chapter 7; and
6) Any proposed well location determined by the New York City Department of
Environmental Protection (NYCDEP) to be within 1,000 feet of its subsurface water
supply infrastructure.
In all of the aforementioned circumstances a site-specific SEQRA assessment would be required
because such application is either beyond the scope of the analyses contained in this draft SGEIS

Final SGEIS 2015, Executive Summary, Page 8

 or the Department has determined that proposed activities in these areas raise additional
environmental issues that necessitate a site-specific review. Many of the issues for which the
Department determined that a site-specific environmental assessment and SEQRA determination
of significance would be required represent areas of heightened environmental concern where
environmental impacts could be expected to be significant. As indicated previously, the
Department continued its evaluation of more stringent conditions to address both the uncertainty
regarding the potential impacts and the impacts that remain unresolved due to the potential
inadequacy of mitigation measures. The Department weighed additional conditions to address
programmatic concerns as the public comment and scientific studies revealed an expanding
bibliography of scientific uncertainty and unresolved and unmitigated environmental impacts.
In addition to those site-specific SEQRA assessments described in Chapter 3, the Department
considered requiring site-specific environmental assessments and SEQRA determinations of
significance for the following additional types of high-volume hydraulic fracturing applications:
1) Any proposed centralized flowback water surface impoundment;
2) Any proposed well location within a contiguous, 30-acre, high- or medium-scoring
grassland patch in a grassland focus area unless the ecological assessment demonstrates
lack of a significant adverse impact on grassland habitat and grassland birds;
3) Any proposed well location within a contiguous, 150-acre forest patch in a forest focus
area unless the ecological assessment demonstrates lack of a significant adverse impact
on forest interior habitat and forest interior birds;
4) Any proposed well location on private lands that are totally surrounded by New York
State Office of Parks, Recreation and Historic Preservation (OPRHP) lands or
Department-administered State-owned lands;
5) Any proposed well location within the Catskill Park outside the New York City
watershed or the Adirondack Park; and
6) Any proposed well location wholly or partially within or substantially contiguous to an
historic district.
The Department also considered expanding the buffers of some of the previously proposed
locations requiring a site-specific review, including expanding the 150-foot buffer from a

Final SGEIS 2015, Executive Summary, Page 9

 perennial or intermittent stream, storm drain, lake or pond to 300 feet and including freshwater
wetlands, and converting some of the requirements for site-specific reviews to prohibitions.
Chapter 3 also identifies the Department’s oil and gas well regulations, located at 6 NYCRR Part
550, and it discusses the existence of other regulations related to high-volume hydraulic
fracturing. The Department proposed revised regulations relating to high-volume hydraulic
fracturing in 2011 but abandoned the rulemaking in 2013.
Chapter 4 - Geology
Chapter 4 supplements the geology discussion in the 1992 GEIS (Chapter 5) with additional
details about the Marcellus and Utica Shales, seismicity in New York State, naturally occurring
radioactive materials (NORM) in the Marcellus Shale and naturally occurring methane in New
York State.
Chapter 5 - Natural Gas Development Activities & High-Volume Hydraulic Fracturing
This Chapter comprehensively describes the activities associated with high-volume hydraulic
fracturing and multi-well pad drilling, including the composition of hydraulic fracturing
additives and flowback water characteristics. It is based on the 2011 description of proposed
activities provided by industry and verified by the Department in addition to being informed by
high-volume hydraulic fracturing operations ongoing in Pennsylvania and elsewhere. In this
Chapter, the average disturbance associated with a multi-well pad, access road and proportionate
infrastructure during the drilling and fracturing stage is estimated at 7.4 acres, compared to the
average disturbance associated with a well pad for a single vertical well during the drilling and
fracturing stage, which is estimated at 4.8 acres. As a result of required partial reclamation, the
average well pad would generally be reduced to averages of about 5.5 acres and 4.5 acres,
respectively, during the production phase.
This Chapter describes the process for constructing access roads, and observes that because most
shale gas development would consist of several wells on a multi-well pad, more than one well
would be serviced by a single access road instead of one well per access road as was typically the
case when the 1992 GEIS was prepared. Therefore, in areas developed by horizontal drilling

Final SGEIS 2015, Executive Summary, Page 10

 using multi-well pads, it is expected that fewer access roads as a function of the number of wells
would be constructed. Industry estimates that 90% of the wells used to develop the Marcellus
Shale would be horizontal wells located on multi-well pads. However, the evolution of the
technology that facilitates extraction of natural gas from deep low-permeability shale formations
where it was previously not feasible would lead to more widespread impacts in certain regions
that could not occur from conventional methods of extraction. Chapter 5 describes the
constituents of drilling mud and the containment of drill cuttings, either in a lined on-site reserve
pit or in a closed-loop tank system. This Chapter also calculates the projected volume of cuttings
and the potential for such cuttings to contain naturally occurring radioactive materials (NORM).
This Chapter also discusses the process of high-volume hydraulic fracturing, the composition of
fracturing fluid, on-site storage and handling, and transport of fracturing additives. The highvolume hydraulic fracturing process involves the controlled use of high volumes of water and
chemical additives, pumped under pressure into a steel-cased and cemented wellbore. To protect
fresh water zones and isolate the target hydrocarbon-bearing zone, high-volume hydraulic
fracturing does not occur until after the well is cased and cemented, and typically after the
drilling rig and its associated equipment are removed from the well pad. Chapter 5 explains that
the Department would generally require at least three strings of cemented casing in the well
during fracturing operations. The outer string (i.e., surface casing) would extend below fresh
ground water and would have been cemented to the surface before the well was drilled deeper.
The intermediate casing string, also called protective string, is installed between the surface and
production strings. The innermost casing string (i.e., production casing) typically extends from
the ground surface to the toe of the horizontal well.
The fluid used for high-volume hydraulic fracturing is typically comprised of more than 98%
fresh water and sand, with chemical additives comprising 2% or less of the fluid. The
Department has collected compositional information on many of the additives proposed for use
in fracturing shale formations in New York directly from chemical suppliers and service
companies and those additives are identified and discussed in detail in Chapter 5. It is estimated
that 2.4 million to 7.8 million gallons of water may be used for a multi-stage hydraulic fracturing
procedure in a typical 4,000-foot lateral wellbore. Water may be delivered by truck or pipeline

Final SGEIS 2015, Executive Summary, Page 11

 directly from the source to the well pad, or may be delivered by trucks or pipeline from
centralized water storage or staging facilities consisting of tanks or engineered impoundments.
After the high-volume hydraulic fracturing procedure is completed and pressure is released, the
direction of fluid flow reverses. The well is “cleaned up” by allowing water and excess proppant
(typically sand) to flow up through the wellbore to the surface. Both the process and the returned
water are commonly referred to as “flowback.” The SGEIS estimates flowback water volume to
range from 216,000 gallons to 2.7 million gallons per well, based on a pumped fluid estimate of
2.4 million to 7.8 million gallons. After completion of drilling operations and while natural gas
production is underway, brine fluids that preexisted naturally in the formation prior to drilling
are returned to the surface from the borehole, which is commonly referred to as “production
brine.” It is estimated that production brine per well may range from 400 gallons per day (gpd) to
3,400 gpd. Chapter 5 discusses the volume, characteristics, recycling and disposal of flowback
water and production brine.
Chapter 6 – Potential Environmental Impacts
This Chapter identifies and evaluates the potential significant adverse impacts associated with
high-volume hydraulic fracturing operations and, like other chapters, should be read as a
supplement to the 1992 GEIS. The Department’s evolving understanding of the potential
significant adverse impacts associated with high-volume hydraulic fracturing is reflected in the
accompanying Response to Comments, which represents the Department’s current assessment of
those impacts and of the effectiveness of proposed or considered mitigation measures. In this
regard, the ever increasing collection of proposed mitigation measures demonstrates three
essential weaknesses of the proposed program: (1) the effectiveness of the mitigation is
uncertain; (2) the potential risk and impact from the proposed Action to the environment and
public health cannot be quantified at this time, and (3) there are some significant adverse impacts
that are simply unavoidable.
Water Resources Impacts
The Department recognizes the importance of protecting New York’s water resources for
drinking water supplies, economic development, agriculture, recreation and tourism. As

Final SGEIS 2015, Executive Summary, Page 12

 memorialized in Environmental Conservation Law (ECL) § 15-0105, the Department must
require the use of all known available and reasonable methods to protect and preserve the purity
and quality of water resources over the long-term in order to serve public health, safety and
welfare and to maintain ecological resources. Potential significant adverse impacts on water
resources exist with regard to potential degradation of drinking water supplies; impacts to
surface and underground water resources due to large water withdrawals for high-volume
hydraulic fracturing; cumulative impacts; stormwater runoff; surface spills, leaks and pit or
surface impoundment failures; groundwater impacts associated with well drilling and
construction and seismic activity; waste disposal; and New York City’s subsurface water supply
infrastructure.
Water for hydraulic fracturing may be obtained by withdrawing it from surface water bodies
away from the well site or through new or existing water-supply wells drilled into aquifers.
Chapter 6 concludes that, without proper controls on the rate, timing and location of such water
withdrawals, the cumulative impacts of such withdrawals could cause modifications to
groundwater levels, surface water levels, and stream flow that could result in significant adverse
impacts, including but not limited to impacts to the aquatic ecosystem, downstream river channel
and riparian resources, wetlands, and aquifer supplies.
Using an industry estimate of a yearly peak activity in New York of 2,462 wells, the SGEIS
estimates that high-volume hydraulic fracturing would result in a calculated peak annual fresh
water usage of 9 billion gallons. Total daily fresh water withdrawal in New York has been
estimated at about 10.3 billion gallons. This equates to an annual total of about 3.8 trillion
gallons. Based on this calculation, at peak activity high-volume hydraulic fracturing would
result in increased demand for fresh water in New York of 0.24%. Thus, water usage for highvolume hydraulic fracturing represents a very small percentage of water usage throughout the
state. Nevertheless, as noted, the cumulative impact of water withdrawals, if such withdrawals
were temporally proximate and from the same water resource, could potentially be significant.
Chapter 6 also describes the potential significant adverse impacts on water resources from
stormwater runoff associated with the construction and operation of high-volume hydraulic
fracturing well pads. All phases of natural gas well development, from initial land clearing for

Final SGEIS 2015, Executive Summary, Page 13

 access roads, equipment staging areas and well pads, to drilling and fracturing operations,
production and final reclamation, have the potential to cause water resource impacts during rain
and snow melt events if stormwater is not properly managed. Proposed mitigation measures to
reduce significant adverse impacts from stormwater runoff are described in Chapter 7.
Nonetheless, the potential for significant cumulative as well as site-specific impacts resulting
from uncontained contaminated runoff remains.
The SGEIS concludes that spills or releases in connection with high-volume hydraulic fracturing
could have significant adverse impacts on water resources. The SGEIS identifies a significant
number of contaminants contained in fracturing additives, or otherwise associated with highvolume hydraulic fracturing operations. Spills or releases can occur as a result of tank ruptures,
equipment or surface impoundment failures, overfills, vandalism, accidents (including vehicle
collisions), ground fires, or improper operations. Spilled, leaked or released fluids could flow to
a surface water body or infiltrate the ground, reaching subsurface soils and aquifers. Proposed
mitigation measures to reduce significant adverse impacts from spills and releases are described
in Chapter 7.
Chapter 6 also assesses the potential significant adverse impacts on groundwater resources from
well drilling and construction associated with high-volume hydraulic fracturing. Those potential
impacts include impacts from turbidity, fluids pumped into or flowing from rock formations
penetrated by the well, and contamination from natural gas present in the rock formations
penetrated by the well. Because of the concentrated nature of the activity on multi-well pads, the
larger fluid volumes and pressures associated with high-volume hydraulic fracturing and likely
cumulative impacts across the area where high-volume hydraulic fracturing would be employed,
an unacceptable level of uncertainty remains as to the degree of protection afforded by the
enhanced procedures and mitigation measures that the Department evaluated and which are
discussed in Chapter 7.
The SGEIS explains that the potential migration of natural gas to a water well, which presents a
safety hazard because of its combustible and asphyxiant nature, especially if the natural gas
builds up in an enclosed space such as a well shed, house or garage, was addressed in the 1992
GEIS. Gas migration most likely would be the result of poor well construction (i.e., casing and

Final SGEIS 2015, Executive Summary, Page 14

 cement problems). As with all gas drilling, well construction practices mandated in New York
are engineered in a manner that would reduce the risk of gas migration.
Subsequent to the publication of the rdSGEIS, the Department considered public comment and
evolving scientific knowledge associated with seismicity and faults and the opportunities for
contamination to migrate to groundwater and potable water supplies. Impacts to water resources
may occur due to underground vertical migration of fracturing fluids through the shale
formations, specifically through preexisting faults or abandoned gas wells. Pathways may exist
for upward migration of fracturing fluids and/or natural gas through the shale formations.
Drilling and fracturing fluids, mud-drilled cuttings, pit liners, flowback water and production
brine, although classified as non-hazardous industrial waste, must be hauled under a New York
State Part 364 waste transporter permit issued by the Department. Furthermore, as discussed in
Chapter 7, environmental risks posed by the improper discharge of liquid wastes would be
addressed through the institution of a waste tracking procedure similar to that which is required
for medical waste. However, the Department recognizes that horizontal wells associated with
high-volume hydraulic fracturing produce significantly more drilling and fracturing fluids,
cuttings, flowback water and production brine, and result in an increase in the duration of use of
pit liners. This increase in the volume of waste consequently creates greater waste disposal
impacts, including the risk of inadequate disposal options and the likelihood of spills from
accidents occurring during the transportation of this waste. Information about traffic
management related to high-volume hydraulic fracturing is discussed in Chapter 7.
The disposal of flowback water and production brine could cause significant adverse impacts.
Residual fracturing chemicals and naturally-occurring constituents from the rock formation could
be present in flowback water and production brine and could result in treatment, sludge disposal,
and receiving-water impacts. Salts and dissolved solids may not be sufficiently treated by
municipal biological treatment and/or other treatment technologies which are not designed to
remove pollutants of this nature. Mitigation measures have been identified that would attempt to
reduce potential significant adverse impact from flowback water and production brine or
treatment of other liquid wastes associated with high-volume hydraulic fracturing.

Final SGEIS 2015, Executive Summary, Page 15

 The potential for significant adverse environmental impacts from any proposal to inject flowback
water and production brine from high-volume hydraulic fracturing into a disposal well would be
reviewed on a site-specific basis with consideration to local geology (including faults and
seismicity), hydrogeology, nearby wellbores or other potential conduits for fluid migration and
other pertinent site-specific factors.
The 1992 GEIS summarized the potential impacts of flood damage relative to mud or reserve
pits, brine and oil tanks, other fluid tanks, brush debris, erosion and topsoil, bulk supplies
(including additives) and accidents. Those potential impacts would also result from high-volume
hydraulic fracturing operations but the potential impacts could be significantly greater. Severe
flooding is described as one of the ways that bulk supplies such as additives “might accidentally
enter the environment in large quantities.” Mitigation measures that attempt to reduce the
significant adverse impacts from floods are identified and recommended in Chapter 7.
Gamma ray logs from deep wells drilled in New York over the past several decades show the
Marcellus Shale to be higher in radioactivity than other bedrock formations including other
potential reservoirs that could be developed by high-volume hydraulic fracturing. However,
based on the analytical results from field-screening and gamma ray spectroscopy performed on
samples of Marcellus Shale, NORM levels in cuttings are similar to those naturally encountered
in the surrounding environment. During production associated with high-volume hydraulic
fracturing, however, radioactivity originating in wastewater may become more concentrated in
pipe scale and liquid waste treatment residuals and may require additional mitigation.
As explained in Chapter 5, the total volume of drill cuttings produced from drilling a horizontal
well may be about 40% greater than that for a conventional, vertical well. For multi-well pads,
cuttings volume would be multiplied by the number of wells on the pad. The potential water
resources impacts associated with the greater volume of drill cuttings from multiple horizontal
well drilling operations would arise from the retention of cuttings during drilling, necessitating a
larger reserve pit that may be present for a longer period of time that could impact integrity of a
liner system, unless the cuttings are directed into tanks as part of a closed-loop tank system.

Final SGEIS 2015, Executive Summary, Page 16

 Impacts on Ecosystems and Wildlife
The SGEIS also analyzes the potential significant adverse impacts on ecosystems and wildlife
from high-volume hydraulic fracturing operations. Four areas of concern related to high-volume
hydraulic fracturing are: (1) fragmentation of habitat; (2) potential transfer of invasive species;
(3) impacts to endangered and threatened species; and (4) use of State-owned lands.
The SGEIS concludes that high-volume hydraulic fracturing operations would have a significant
adverse impact on the environment because such operations have the potential to draw
substantial development into New York, which would result in unavoidable impacts to habitats
(fragmentation, loss of connectivity, degradation, etc.), species distributions and populations, and
overall natural resource biodiversity. Habitat loss, conversion, and fragmentation (both shortterm and long-term) would result from land grading and clearing, and the construction of well
pads, roads, pipelines, and other infrastructure associated with gas drilling. Possible mitigation
measures are identified in Chapter 7.
The number of vehicle trips associated with high-volume hydraulic fracturing, particularly at
multi-well sites, has been identified as an activity which presents the opportunity to transfer
invasive terrestrial species. Surface water withdrawals also have the potential to transfer
invasive aquatic species. The introduction of terrestrial and aquatic invasive species would have
a significant adverse impact on the environment.
State-owned lands play a unique role in New York’s landscape because they are managed under
public ownership to allow for sustainable use of natural resources, provide recreational
opportunities for all New Yorkers, and provide important wildlife habitat and open space. Given
the level of development expected for multi-pad horizontal drilling, the SGEIS anticipates that
there would be additional pressure for surface disturbance on State lands. Surface disturbance
associated with gas extraction within and adjacent to state lands could have an impact on
habitats, and recreational use of the state and private lands, especially large contiguous forest
patches that are valuable because they sustain wide-ranging forest species, and provide more
habitat for forest interior species.

Final SGEIS 2015, Executive Summary, Page 17

 The area underlain by the Marcellus Shale includes both terrestrial and aquatic habitat for 18
animal species listed as endangered or threatened in New York State that are protected under the
State Endangered Species Law (ECL 11-0535) and associated regulations (6 NYCRR Part 182).
Endangered and threatened wildlife may be adversely impacted through project actions such as
clearing, grading and road building that occur within the habitats that they occupy. Certain
species are unable to avoid direct impact due to their inherent poor mobility (e.g., Blanding’s
turtle, club shell mussel). Certain actions, such as clearing of vegetation or alteration of stream
beds, can also result in the loss of nesting and spawning areas.
Mitigation measures for potentially significant adverse impacts from potential transfer of
invasive species or from use of State lands, and mitigation measures for potential impacts to
endangered and threatened species are discussed in Chapter 7.
Impacts on Air Resources
Chapter 6 of the SGEIS provides a comprehensive list of federal and New York State regulations
that apply to potential air emissions and air quality impacts associated with the drilling,
completion (hydraulic fracturing and flowback) and production phases (processing, transmission
and storage). The Chapter includes a regulatory assessment of the various air pollution sources
and the air permitting process.
As part of the Department’s effort to address the potential air quality impacts of horizontal
drilling and hydraulic fracturing activities in the Marcellus Shale and other low-permeability gas
reservoirs, an air quality modeling analysis was undertaken by the Department’s Division of Air
Resources (DAR). The analysis identifies the emission sources involved in well drilling,
completion and production, and the analysis of source operations for purposes of assessing
compliance with applicable air quality standards.
After the September 2009 draft SGEIS was published, industry provided information that: (1)
simultaneous drilling and completion operations at a single pad would not occur; (2) the
maximum number of wells to be drilled at a pad in a year would be four in a 12-month period;
and (3) centralized flowback impoundments, which are large-volume, lined ponds that function
as fluid collection points for multiple wells, are not contemplated. Based on these operational

Final SGEIS 2015, Executive Summary, Page 18

 restrictions, the Department revised the limited modeling of 24 hour PM2.5 impacts and
conducted supplemental air quality modeling to assess standards compliance and air quality
impacts. In addition, the Department conducted supplemental modeling to account for the
promulgation of new 1-hour SO2 and NO2 National Ambient Air Quality Standards (NAAQS)
after September 2009. The results of this supplemental modeling indicate the need for the
imposition of certain control measures to achieve the NO2 and PM2.5 NAAQS. These measures,
along with all other restrictions reflecting industry’s proposed operational restrictions and
recommended mitigation measures based on the modeling results, are detailed in Section 7.5.3 of
the SGEIS and in the Response to Comments as proposed operation conditions to be included in
well permits. As detailed in the Response to Comments, the modeling also demonstrates that
high-volume hydraulic fracturing could contribute significantly to elevated ozone levels in the
New York metropolitan ozone nonattainment area.
The Department also developed an air monitoring program to address potential for adverse air
quality impacts beyond those analyzed in the SGEIS, which are either not fully known at this
time or not verifiable by the assessments to date. The air monitoring plan would help determine
and distinguish both the background and drilling-related concentrations of pertinent pollutants in
the ambient air.
Air quality impact mitigation measures are further discussed in Chapter 7 of the SGEIS,
including a detailed discussion of pollution control techniques, various operational scenarios and
equipment that can be used to achieve regulatory compliance, and mitigation measures for well
pad operations. In addition, measures to reduce benzene emissions from glycol dehydrators and
formaldehyde emissions from off-site compressor stations are provided.
Greenhouse Gas Emission Impacts
All operational phases of proposed well pad activities associated with high-volume hydraulic
fracturing were considered, and resulting greenhouse gas (GHG) emissions determined in the
SGEIS. Emission estimates of carbon dioxide (CO2) and methane (CH4) are included as both
short tons and as carbon dioxide equivalents (CO2e) expressed in short tons for expected
exploration and development of the Marcellus Shale and other low-permeability gas reservoirs

Final SGEIS 2015, Executive Summary, Page 19

 using high-volume hydraulic fracturing. The Department not only quantified potential GHG
emissions from activities, but also identified and characterized major sources of CO2 and CH4
during anticipated operations so that key contributors of GHGs with the most significant Global
Warming Potential (GWP) could be addressed, with particular emphasis placed on mitigating
CH4, with its greater GWP.
Whether the combustion of natural gas results in a net increase of GHG emissions depends on
what energy sources are being displaced by natural gas. Replacing higher-emitting fuels such as
coal and petroleum in the power, industry, building and transportation sectors may reduce GHG
emissions. Recent research demonstrates that low-cost natural gas suppresses investment in and
use of clean energy alternatives (such as renewable solar and wind, or energy efficiency),
because it makes those alternatives less cost-competitive in comparison to fossil fuels. New
York is also implementing a number of policies that promote the continued investment in
renewables and efficiency, which should reduce the potential for gas development to pose an
economic obstacle to development of renewable energy and investment in energy efficiency. In
the long term, New York’s policies are directed towards achieving substantial reductions in GHG
emissions by reducing reliance on all fossil fuels, including natural gas.
Socioeconomic Impacts
To assess the potential socioeconomic impacts of high-volume hydraulic fracturing, including
the potential impacts on population, employment and housing, three representative regions were
selected. The three regions were selected to evaluate how high-volume hydraulic fracturing
might impact areas with different production potential, different land use patterns, and different
levels of experience with natural gas well development. All of the projections identified below
relied on assumptions concerning the number of high-volume hydraulic fracturing wells that
would be drilled in a year without reference to the buffers and prohibitions proposed in the
SGEIS or to the Court of Appeals’ decision in the Matter of Wallach v. Town of Dryden and
Cooperstown Holstein Corp. v. Town of Middlefield and without reference to changes that have
occurred in the energy market since this analysis was completed. The current circumstances
reduce the projections of economic benefits for the regions where high-volume hydraulic
fracturing would likely occur. In fact, the assumptions concerning the number of high-volume

Final SGEIS 2015, Executive Summary, Page 20

 hydraulic fracturing wells that would be drilled, and thus, economic benefits initially projected in
the dSGEIS do not accurately reflect the current energy market, the high cost of adherence to the
conditions that would have been imposed in New York State if high-volume hydraulic fracturing
were authorized and the patchwork of local laws and land use controls that prohibit development.
Therefore, such benefits would be significantly less than projected in this SGEIS, as explained in
the Response to Comments.
Region A consists of Broome, Chemung and Tioga County. Region B consists of Delaware,
Otsego and Sullivan County, and Region C consists of Cattaraugus and Chautauqua County.
Using a low and average rate of development based on industry estimates, high-volume
hydraulic fracturing could potentially have a positive economic effect where the activity takes
place.
There would potentially be positive impacts on income levels in the state as a result of highvolume hydraulic fracturing. Employee earnings from operational employment were expected to
range from $121.2 million under the low-development scenario to $484.8 million under the
average-development scenario in Year 30. Indirect employee earnings were anticipated to range
from $202.3 million under the low-development scenario to $809.2 million under the averagedevelopment scenario in Year 30. However, as discussed above, given the expected cost of
compliance with New York State’s draft high-volume hydraulic fracturing program conditions,
the economics of oil and gas production and the areas where high-volume hydraulic fracturing
would be prohibited or restricted these earnings and employment figures would be significantly
lower. Chapter 6 details how the potential job creation and employee earnings might be
distributed across the three representative regions.
Chapter 6 also assesses the potential temporary and permanent population impacts on each of the
three selected regions, finding that Region A will experience an estimated 1.4% increase in the
region’s total population the first decade after high-volume hydraulic fracturing is introduced.
The population of Region C is projected to be more modestly impacted by high-volume
hydraulic fracturing.

Final SGEIS 2015, Executive Summary, Page 21

 While potentially providing positive impacts in the areas of employment and income, highvolume hydraulic fracturing could cause adverse impacts on the availability of housing,
especially temporary housing such as hotels and motels. In Region A, where the use of highvolume hydraulic fracturing is expected to be initially concentrated, there could be shortages of
rental housing. High-volume hydraulic fracturing would also bring both positive and negative
impacts on state and local government spending. Increased activity could result in increases in
local tax revenues and increases in the receipt of production royalties but would also result in an
increased demand for infrastructure repair and local services, including emergency response
services.
Visual, Noise and Community Character Impacts
The construction of well pads and wells associated with high-volume hydraulic fracturing will
result in adverse impacts relating to noise. In certain areas the construction and development
activities would also result in visual impacts. Potential mitigation measures to address such
impacts if high-volume hydraulic fracturing were authorized are summarized in Chapter 7.
The cumulative impact of well construction activity and related truck traffic would cause impacts
on the character of the rural communities where much of this activity would take place. Despite
the recent New York Court of Appeals in Matter of Wallach v. Town of Dryden and
Cooperstown Holstein Corp. v. Town of Middlefield that found that ECL Section 23-0303(2)
does not preempt communities with adopted zoning laws from prohibiting or restricting the use
of land for high-volume hydraulic fracturing drilling, it is likely that localities still may not be
able to prevent cross boundary cumulative impacts to their respective community character.
Even were a community to prohibit drilling, it is reasonably foreseeable that regional impacts
related to high-volume hydraulic fracturing activities, including truck traffic, visual impacts, and
impacts on cultural, historic, agricultural, tourism, and scenic resources would adversely affect
neighboring municipalities that enact zoning prohibitions.

Final SGEIS 2015, Executive Summary, Page 22

 Transportation Impacts
The introduction of high-volume hydraulic fracturing has the potential to generate significant
truck traffic during the construction and development phases of the well. The cumulative impact
of this truck traffic has the potential to result in significant adverse impacts on local roads and, to
a lesser extent, state roads where truck traffic from this activity is concentrated. It is not feasible
to conduct a detailed traffic assessment given that the precise location of well pads is unknown at
this time. However, such traffic has the potential to damage roads and impact air quality.
Chapter 7 discusses the potential mitigation measures to address such impacts, including the
requirement that the applicant develop a Transportation Plan that sets forth proposed truck
routes, surveys road conditions along those routes and requires local road use agreements to
address any impacts on local roads.
Additional NORM Concerns
Based upon currently available information it is anticipated that flowback water would not
contain levels of NORM of significance, whereas production brine could contain elevated
NORM levels. Although the highest concentrations of NORM are in production brine, it does
not present a risk to workers because the external radiation levels are very low. However, the
build-up of NORM in pipes and equipment (pipe scale and sludge) has the potential to cause a
significant adverse impact because it could expose workers handling (cleaning or maintenance)
the pipe to unsafe radiation levels. Also, wastes from the treatment of production brine may
contain concentrated NORM and, if so, controls would be required to limit radiation exposure to
workers handling this material as well as to ensure that this material is disposed of in accordance
with applicable regulatory requirements.
Seismicity
There is a reasonable base of knowledge and experience related to seismicity induced by
hydraulic fracturing. The information on the potential seismic impacts from high-volume
hydraulic fracturing has increased since the release of the rdSGEIS. A recent study (Skoumal,
2015) ascribed a series of earthquakes in Poland, Ohio to high-volume hydraulic fracturing
operations. Between March 4 and March 12, 2014, 77 earthquakes, ranging between 1.0 and 3.0

Final SGEIS 2015, Executive Summary, Page 23

 in magnitude, were identified and found to be closely related spatially and temporally to
hydraulic fracturing operations at a nearby well. The Department’s review of available
information indicates unanswered questions remain on the seismic impacts associated with highvolume hydraulic fracturing. The Department would need to evaluate the risk to the public,
infrastructure, and natural resources from induced seismicity related to hydraulic fracturing if
this activity were authorized.
Chapter 7 – Mitigation Measures

This Chapter describes the measures the Department identified as of 2011 to address the
potentially significant adverse impacts from high-volume hydraulic fracturing operations if highvolume hydraulic fracturing were authorized. However, there is currently insufficient scientific
information to conclude that this activity can be undertaken without posing unreasonable risk to
public health, and to determine what mitigation measures provide a level of assurance that
potential risks have been satisfactorily minimized.
The Department recognizes the importance of protecting New York’s surface and groundwater
for drinking water supplies, economic development, and agriculture. In recognition of the
potential for spills or releases in connection with high-volume hydraulic fracturing, the
Department considered, as a general matter, requiring that operators develop and implement a
groundwater monitoring program to detect potential spills and releases around the high-volume
hydraulic fracturing well pad and to detect potential contamination in groundwater.
The following describes some of the mitigation measures that were evaluated in the SGEIS, as
well as additional measures that were considered:
No High-Volume Hydraulic Fracturing Operations in the New York City and Syracuse
Watersheds
In April 2010, the Department concluded that due to the issues presented by high-volume
hydraulic fracturing operations within the drinking watersheds for the City of New York and
Syracuse, the SGEIS would not apply to activities in those watersheds. Those areas present
issues that primarily stem from the fact that they are unfiltered water supplies that depend on

Final SGEIS 2015, Executive Summary, Page 24

 strict land use and development controls to ensure that water quality is protected. Then in 2011,
the Department concluded that the proposed high-volume hydraulic fracturing activity is not
consistent with the preservation of these watersheds as unfiltered drinking water supplies.
Notwithstanding the mitigation measures considered for this activity, a risk remains that
significant high-volume hydraulic fracturing activities in these areas could result in a degradation
of drinking water supplies from accidents, surface spills, etc. Moreover, such large-scale
industrial activity in these areas, even without spills, could imperil Filtration Avoidance
Determinations and result in the affected municipalities incurring substantial costs to filter their
drinking water supply. Accordingly, this SGEIS supports a finding that high-volume hydraulic
fracturing well pads not be permitted in the Syracuse and New York City drinking water supply
watersheds or in a protective 4,000-foot buffer area around those watersheds.
In response to concerns raised about infrastructure associated with the Syracuse and New York
City drinking water supply watersheds, the Department considered extending its initial 4,000foot setback from unfiltered drinking water supply watersheds for the siting of high-volume
hydraulic fracturing well pads. The setback would encompass a portion of the water supply
infrastructure, including tunnels that transport water for drinking supplies. Beyond that, the
Department also considered prohibiting the placement of any portion of a wellbore less than
2,000 feet from any water tunnel or underneath a tunnel, and requiring enhanced site-specific
review plus consultation with the municipality for any wellbore located within two miles of any
water supply infrastructure for the Syracuse and NYC drinking water supplies.
No High-Volume Hydraulic Fracturing Operations on Primary Aquifers
Eighteen other aquifers in the State of New York have been identified by NYSDOH as highly
productive aquifers presently utilized as sources of water supply by major municipal water
supply systems and have been designated as “primary aquifers.” Because these aquifers are the
primary source for many public drinking water supplies, the potential significant impacts, similar
to those that would impact the New York City and Syracuse drinking water supply watersheds,
must be reduced to ensure that high-volume hydraulic fracturing would not pose a threat to these
critical resources and the communities that rely on them. While the Department recommended
in the SGEIS that high-volume hydraulic fracturing well pads should not be permitted above a

Final SGEIS 2015, Executive Summary, Page 25

 Primary Aquifer or within a 500-foot buffer area, the impacts may be more widespread and
significant than was previously considered, and consequently broader mitigation measures may
be necessary.
No High-Volume Hydraulic Fracturing Operations on Certain State Lands
This SGEIS supports a finding that site disturbance relating to high-volume hydraulic fracturing
operations should not be permitted on certain State lands because the potential impacts resulting
from high-volume hydraulic fracturing are inconsistent with the purposes for which those lands
have been acquired including public access for a wide range of recreational activities.
Prohibition of high-volume hydraulic fracturing development would prevent the loss of habitat in
the protected State land areas, which represent some of the largest contiguous forest patches
where high-volume hydraulic fracturing activity could occur. Depending on the location of
ancillary infrastructure and activities horizontal extraction of gas resources underneath State
lands from well pads located outside this area may not significantly impact valuable habitat on
forested State lands.
No High-Volume Hydraulic Fracturing Operations on Principal Aquifers Without SiteSpecific Environmental Review
Similar to Primary Aquifers, Principal Aquifers are also highly productive. Because they are
largely contained in unconsolidated material, and due to the high permeability (which allows
rapid movement of groundwater) and shallow depth to the water table, both Primary and
Principal Aquifers are particularly susceptible to contamination. Protection of these aquifers is
critical for existing water supply needs, as well as to fulfill future needs for new or expanded
water supplies. In order to reduce the risk of significant adverse impacts on these important
water resources from potential surface discharges from high-volume hydraulic fracturing well
pads, the SGEIS proposed that for at least two years from issuance of the final SGEIS,
applications for high-volume hydraulic fracturing operations at any surface location within the
boundaries of principal aquifers, or outside but within 500 feet of the boundaries of principal
aquifers, would require (1) site-specific environmental assessments and SEQRA determinations
of significance and (2) individual SPDES permits for storm water discharges. The Department
considered removing the two year re-evaluation period for impacts to Principal Aquifers.

Final SGEIS 2015, Executive Summary, Page 26

 No High-Volume Hydraulic Fracturing Operations within 2,000 feet of Public Drinking
Water Supplies
More than 360,000 people (or roughly 40.9% of the population) in the Marcellus Shale play area
are served by individual private wells or public surface water supplies, or community supplies
outside of Primary and Principal Aquifer areas. The SGEIS seeks to reduce the risk of
significant adverse impacts on water resources from potential surface discharges from highvolume hydraulic fracturing well pads by proposing that high-volume hydraulic fracturing well
pads at any surface location within 2,000 feet of public water supply wells, river or stream
intakes and reservoirs should not be permitted. In an attempt to further reduce the potential risks,
the Department additionally considered requiring a 2,000-foot prohibition around a public
(municipal or otherwise) drinking water supply intake in flowing water with an additional
prohibition of 1,000 feet on each side of the main flowing waterbody and any tributary to that
waterbody, both for a distance of 1 mile upstream from the public drinking water supply intake.
No High-Volume Hydraulic Fracturing Operations in Floodplains or Within 500 Feet of
Private Water Wells
In order to address potential significant adverse impacts due to flooding, the SGEIS evaluated
the significant impacts associated with high-volume hydraulic fracturing development located
wholly or partially within a 100-year floodplain. In further recognition of the increasing
frequency and intensity of recent and potentially future flood events, the Department considered
requiring that, in certain areas, well pads be elevated two feet above the 500-year floodplain
elevation or the known elevation of the flood of record. However, the Department notes that
flood risks change over time and consequently potential impacts could still occur from highvolume hydraulic fracturing as a result of incomplete data.
Since just 2000, 16,000 new private water wells in the Marcellus Shale play area have been
reported to the Department; this averages out to over 1,000 per year. In order to reduce potential
impacts on drinking water supplies from high-volume hydraulic fracturing operations, the SGEIS
evaluated impacts on private water wells and domestic use springs and considered prohibiting
any well pad located within 500 feet of a private water well or domestic supply spring, unless the
Department issued a variance from the requirement, with the consent of the landowner, and any

Final SGEIS 2015, Executive Summary, Page 27

 tenants, if applicable. The final SGEIS reflects the importance of protecting this resource so
critical to residents within the Marcellus Shall play area.
Mandatory Disclosure of Hydraulic Fracturing Additives and Alternatives Analysis
The SGEIS identifies by chemical name and Chemical Abstract Services (CAS) number 322
chemicals proposed for use for high-volume hydraulic fracturing in New York. Chemical usage
was reviewed by NYSDOH, which provided health hazard information that is presented in the
document. In response to public concerns relating to the use of hydraulic fracturing additives
and their potential impact on water resources, this SGEIS contains a requirement that operators
evaluate and use alternative hydraulic fracturing additive products that pose less potential risk to
water resources if high-volume hydraulic fracturing were authorized. In addition, in the EAF
addendum a project sponsor must disclose all additive products it proposes to use, and provide
Material Safety Data Sheets for those products, so that the appropriate remedial measures could
be employed if a spill were to occur. If high-volume hydraulic fracturing were authorized, the
Department would publicly disclose the identities of hydraulic fracturing fluid additive products
and their Material Safety Data Sheets, provided that information which meets the confidential
business information exception to the Department’s records access program will not be subject to
public disclosure. In addition, the Department considered expanding the fracturing fluid
chemical disclosure requirements to ensure that each chemical, and not merely each product,
would be disclosed both before drilling and after completion of each well.
Enhanced Well Casing
In order to mitigate the risk of significant adverse impacts to water resources from the migration
of gas or pollutants in connection with high-volume hydraulic fracturing operations, the SGEIS
added a requirement for a third cemented “string” of well casing around the gas production wells
in most situations. This enhanced casing specification is designed to specifically reduce
potential impacts from migration of gas into aquifers.

Final SGEIS 2015, Executive Summary, Page 28

 Required Secondary Containment and Stormwater Controls
The risk of a significant adverse impact to water resources from spills of chemical additives,
hydraulic fracturing fluid or liquid wastes associated with high-volume hydraulic fracturing,
secondary containment, spill prevention and storm water pollution prevention have been
evaluated in the SGEIS. However, because of the unique aspects of multi-well pad development
associated with high-volume hydraulic fracturing, the existing Department engineering controls
and management practices that would be required are untested for the scale of this activity and,
consequently, it remains uncertain whether they would be adequate to prevent spills and mitigate
adverse impacts if a spill occurs. Compounding this risk is the current uncertainty, as identified
by NYSDOH, regarding the level of risk high-volume hydraulic fracturing activities pose to
public health.
Conditions Related to Disposal of Wastewater and Solid Waste
The Department had proposed to require that before any permit is issued the well operator have
Department-approved plans in place for disposing of flowback water and production brine. In
addition, the Department proposed to require a tracking system, similar to what is in place for
medical waste, for all liquid and solid wastes generated in connection with high-volume
hydraulic fracturing operations.
The SGEIS also contains a requirement for closed-loop drilling to address impacts related to the
disposal of pyrite-rich Marcellus Shale cuttings on-site.
Air Quality Control Measures and Mitigation for Greenhouse Gas Emissions
The SGEIS identifies additional mitigation measures designed to ensure that emissions
associated with high-volume hydraulic fracturing operations would not result in the exceedance
of any NAAQS if high-volume hydraulic fracturing were authorized. In addition, the
Department has committed to implement local and regional level air quality monitoring at well
pads and surrounding areas.

Final SGEIS 2015, Executive Summary, Page 29

 The SGEIS also identifies mitigation measures that could be required through permit conditions
and possibly new regulations to reduce GHG emissions from high-volume hydraulic fracturing
activities. The SGEIS would require a GHG emission impacts mitigation plan (the Plan). The
Plan would include: a list of best management practices for GHG emission sources for
implementation at the permitted well site; a leak detection and repair program; use of the U.S.
Environmental Protection Agency’s (EPA) Natural Gas Star best management practices for any
pertinent equipment; use of reduced emission completions that provide for the recovery of
methane instead of flaring whenever a gas sales line and interconnecting gathering line are
available; and a statement that the operator would provide the Department with a copy of the
report filed with EPA to meet the requirements of the EPA GHG Reporting Program (40 CFR
§98), which mandates the monitoring and reporting of GHG emissions from certain source
categories in the United States.
Mitigation for Loss of Habitat and Impacts on Wildlife
The Department had proposed several mitigation measures to attempt to address the significant
adverse impacts on wildlife habitat caused by fragmentation of forest and grasslands on private
land. Although a site-specific environmental assessment and SEQRA determination of
significance may have assisted the Department in reducing such impacts, the cumulative nature
of the impacts across the area where high-volume hydraulic fracturing would likely occur is such
that the impacts would remain only partially mitigated.
Chapter 8 – Permit Process and Regulatory Coordination
This Chapter explains inter- and intra-agency coordination relative to the well permit process,
including the role of local governments and a revised approach to local government notification
and consideration of potential impacts of high-volume hydraulic fracturing operations on local
land use laws and policies. The Department also considered requiring that every ECL Article 23
well application proposing high-volume hydraulic fracturing on a new well pad be subject to a
fifteen-day public notice period, limited to site-specific issues on the subject application not
addressed in the 1992 GEIS or this SGEIS. As a result of the Matter of Wallach v. Town of
Dryden and Cooperstown Holstein Corp. v. Town of Middlefield decision, some towns could

Final SGEIS 2015, Executive Summary, Page 30

 exercise their zoning authority in such a way that they would be involved agencies under
SEQRA. This means that the Department would be required to coordinate the environmental
review with such government agencies if the permit required discretionary approvals from a
local government agency (e.g., a special use permit or some other type of zoning approval).
Chapter 9 – Alternative Actions
Chapter 9 discusses the alternatives to well permit issuance that were reviewed and considered
by the Department. The SGEIS considers a range of alternatives for authorizing high-volume
hydraulic fracturing operations in New York. As required by SEQRA, the SGEIS considers the
No Action Alternative. The No Action Alternative would not result in any of the significant
adverse impacts identified herein, but would also not result in any of the potential economic and
other benefits identified with natural gas drilling by this method.
The alternatives analysis also considers the use of a phased-permitting approach to developing
the Marcellus Shale and other low-permeability gas reservoirs, including consideration of
limiting and/or restricting resource development in designated areas.
The SGEIS also contains a review and analysis of the development and use of “green” or nonchemical fracturing alternatives. The use of environmentally friendly or “green chemicals”
would depend on both their reduced toxicity and their technical effectiveness in the Marcellus
Shale play and other shale plays. While more research and approval criteria would be necessary
to establish benchmarks for “green chemicals,” this Final SGEIS proposes that if high-volume
hydraulic fracturing were authorized, this alternative approach be adopted by requiring
applicants to review and consider, to the Department’s satisfaction, the use of alternative additive
products that may pose less risk to the environment, including water resources, where feasible,
and to publicly disclose the chemicals that make up these additives. These requirements would
be altered and/or expanded as the use of “green chemicals” begins to provide reasonable
alternatives and the appropriate technology, criteria and processes are put in place to evaluate
and produce “green chemicals.”

Final SGEIS 2015, Executive Summary, Page 31

 Chapter 10 – Review of Selected Non-Routine Incidents in Pennsylvania
Chapter 10 discusses a number of incidents involving high-volume hydraulic fracturing
operations in Pennsylvania that have caused concern about the safety and potential adverse
impacts associated with high-volume hydraulic fracturing operations.

Chapter 11 – Summary of Potential Impacts and Mitigation Measures
Chapter 11 highlights the mitigation measures implemented through the 1992 GEIS and
summarizes the impacts and mitigation that are discussed in Chapters 6 and 7.

Response to Comments
The accompanying Response to Comments includes summaries of the substantive comments
received on both the 2009 dSGEIS and the 2011 rdSGEIS, along with the Department’s
responses to such comments.

Final SGEIS 2015, Executive Summary, Page 32

 NEW YORK Department of

STATE OF .

OPPORTUNITYW EnVIronmental
Conservation

 

Chapter 1
Introduction

Final

Supplemental Generic Environmental Impact Statement



This page intentionally left blank.

Chapter 1 – Introduction
CHAPTER 1 INTRODUCTION ............................................................................................................................. 1-1
1.1 HYDRAULIC FRACTURING AND MULTI-WELL PAD DRILLING ..................................................................................... 1-1
1.1.1 Significant Changes in Proposed Operations Since 2009 .......................................................................... 1-2
1.1.1.1 Use of Reserve Pits or Centralized Impoundments for Flowback Water ........................................ 1-2
1.1.1.2 Flowback Water Recycling .............................................................................................................. 1-2
1.2 REGULATORY JURISDICTION ............................................................................................................................. 1-3
1.3 STATE ENVIRONMENTAL QUALITY REVIEW ACT .................................................................................................... 1-3
1.4 PROJECT CHRONOLOGY .................................................................................................................................. 1-4
1.4.1 February 2009 Final Scope ........................................................................................................................ 1-4
1.4.2 2009 Draft SGEIS ........................................................................................................................................ 1-4
1.4.2.1 April 2010 Announcement Regarding Communities with Filtration Avoidance Determinations ... 1-5
1.4.2.2 Subsequent Exclusion of Communities with Filtration Avoidance Determinations ....................... 1-5
1.4.3 2011 Revised Draft SGEIS .......................................................................................................................... 1-5
1.4.4 Draft Regulations ....................................................................................................................................... 1-5
1.4.5 Health Review by the New York State Department of Health ................................................................... 1-6
1.4.6 Final SGEIS ................................................................................................................................................. 1-6
1.4.7 Next Steps.................................................................................................................................................. 1-6
1.5 METHODOLOGY............................................................................................................................................ 1-6
1.5.1 Information about the Proposed Operations ............................................................................................ 1-6
1.5.2 Intra-/Inter-agency Coordination .............................................................................................................. 1-7
1.5.3 Comment Review ...................................................................................................................................... 1-7
1.6 LAYOUT AND ORGANIZATION ........................................................................................................................... 1-8
1.6.1 Chapters .................................................................................................................................................... 1-8
1.6.2 Revisions .................................................................................................................................................. 1-10
1.6.3 Glossary, Bibliographies and Appendices ................................................................................................ 1-10
1.7 ENHANCED IMPACT ANALYSES AND MITIGATION MEASURES .................................................................................. 1-10
1.7.1 Hydraulic Fracturing Chemical Disclosure ............................................................................................... 1-10
1.7.2 Water Well Testing .................................................................................................................................. 1-11
1.7.3 Water Withdrawal and Consumption...................................................................................................... 1-11
1.7.3.1 2009 Draft SGEIS ........................................................................................................................... 1-11
1.7.3.2 Revised Draft SGEIS....................................................................................................................... 1-11
1.7.4 Well Control and Emergency Response Planning .................................................................................... 1-11
1.7.5 Local Planning Documents....................................................................................................................... 1-12
1.7.6 Secondary Containment, Spill Prevention and Stormwater Pollution Prevention .................................. 1-12
1.7.7 Well Construction .................................................................................................................................... 1-12
1.7.7.1 2009 Draft SGEIS ........................................................................................................................... 1-13
1.7.7.2 Revised Draft SGEIS....................................................................................................................... 1-13
1.7.8 Flowback Water Handling On-Site ........................................................................................................... 1-14
1.7.9 Flowback Water Disposal ........................................................................................................................ 1-14
1.7.10 Management of Drill Cuttings ................................................................................................................. 1-14
1.7.11 Emissions and Air Quality ........................................................................................................................ 1-15
1.7.11.1 2009 Draft SGEIS ........................................................................................................................... 1-15
1.7.11.2 Revised Draft SGEIS....................................................................................................................... 1-16
1.7.12 Greenhouse Gas Mitigation ..................................................................................................................... 1-17
1.7.13 Habitat Fragmentation ............................................................................................................................ 1-17
1.7.14 State Forests, State Wildlife Management Areas and State Parks .......................................................... 1-18

Final SGEIS 2015, Page 1-i

 1.7.15 Community and Socioeconomic Impacts ................................................................................................ 1-18
1.8 ADDITIONAL PRECAUTIONARY MEASURES .......................................................................................................... 1-18

Final SGEIS 2015, Page 1-ii

 Chapter 1

INTRODUCTION

The Department of Environmental Conservation (Department) has received applications for
permits to drill horizontal wells to evaluate and develop the Marcellus and Utica Shales for
natural gas production. To release the gas embedded in the shale formations, wells would
undergo a stimulation process known as high-volume hydraulic fracturing. While the horizontal
well applications received to date are for proposed locations in Broome, Cattaraugus, Chemung,
Chenango, Delaware, and Tioga Counties, the Department expects to receive applications to drill
in other areas, including counties where natural gas production has not previously occurred.
There is also potential for development of the Utica Shale using horizontal drilling and highvolume hydraulic fracturing in Otsego and Schoharie Counties and elsewhere as shown in
Chapter 4. Other shale and low-permeability formations in New York may also be targeted for
future application of horizontal drilling and high-volume hydraulic fracturing. The Department
has prepared this revised draft Supplemental Generic Environmental Impact Statement (SGEIS)
to satisfy the requirements of the State Environmental Quality Review Act (SEQRA) for some of
these anticipated operations. In reviewing and processing permit applications for horizontal
drilling and hydraulic fracturing in these deep, low-permeability formations, the Department
would apply the findings and requirements of the SGEIS, including criteria and conditions for
future approvals, in conjunction with the existing Generic Environmental Impact Statement on
the Oil, Gas and Solution Mining Regulatory Program, issued by the Department in 1992 (1992
GEIS). 1
1.1

Hydraulic Fracturing and Multi-Well Pad Drilling

Hydraulic fracturing is a well stimulation technique which consists of pumping an engineered
fluid system and a propping agent (proppant) such as sand down the wellbore under high
pressure to create fractures in the hydrocarbon-bearing rock. The fractures serve as pathways for
hydrocarbons to move to the wellbore for production. Further information on high-volume
hydraulic fracturing, including the composition of the fluid system, is provided in Chapter 5.

1

The 1992 GEIS is posted on the Department’s website at http://www.dec.ny.gov/energy/45912.html.

Final SGEIS 2015, Page 1-1

 For environmental review purposes pursuant to SEQRA, stimulation including hydraulic
fracturing is considered part of the action of drilling a well. Wells where high-volume hydraulic
fracturing is used may be drilled vertically, directionally or horizontally. Multiple wells may be
drilled from a common location (multi-well pad or multi-well site).
1.1.1

Significant Changes in Proposed Operations Since 2009

The gas drilling industry has informed the Department of the following changes in its planned
operations in New York, based, in part, on experience gained in actively developing the
Marcellus Shale in Pennsylvania. These changes are reflected in the assumptions used in this
revised draft SGEIS to identify and consider potential significant adverse impacts.
1.1.1.1 Use of Reserve Pits or Centralized Impoundments for Flowback Water
The Department was informed in September 2010 that operators would not routinely propose to
store flowback water either in reserve pits on the wellpad or in centralized impoundments. 2
Therefore, these practices are not addressed in this revised draft SGEIS and such impoundments
would not be approved without site-specific environmental review.
1.1.1.2 Flowback Water Recycling
The Department was also informed in September 2010 that operators plan to maximize reuse of
flowback water for subsequent high-volume hydraulic fracturing operations, with some
companies targeting goals of recycling 100% of flowback water. 3 The technologies for
accomplishing this have evolved through ongoing Marcellus Shale development in Pennsylvania.
The Susquehanna River Basin Commission (SRBC) has confirmed that operators are re-using
flowback water. 4 This development has the potential to greatly reduce the volume of flowback
water that requires treatment, hauling and disposal, and the related environmental concerns.
Fresh water consumption and hauling are also somewhat reduced, but in current practice fresh
water still comprises 80-90% of the water used at each well for high-volume hydraulic
fracturing.

2

ALL Consulting, 2010, pp. 18-19.

3

ALL Consulting, 2010, pp. 73-76.

4

Richenderfer, 2010, p. 30.

Final SGEIS 2015, Page 1-2

 1.2

Regulatory Jurisdiction

The State of New York’s official policy, enacted into law, is “to conserve, improve and protect
its natural resources and environment . . . ,” 5 and it is the Department’s responsibility to carry out
this policy. As set forth in Environmental Conservation Law (ECL) §3-0301(1), the
Department’s broad authority includes, among many other things, the power to:
•

manage natural resources to assure their protection and balanced utilization;

•

prevent and abate water, land and air pollution; and

•

regulate storage, handling and transport of solids, liquids and gases to prevent pollution.

The Department regulates the drilling, operation and plugging of oil and natural gas wells to
ensure that activities related to these wells are conducted in accordance with statutory mandates
found in the ECL. In addition to protecting the environment and public health and safety, the
Department is also required by Article 23 of the ECL (ECL 23) to prevent waste of the State’s oil
and gas resources, to provide for greater ultimate recovery of the resources, and to protect
correlative rights. 6
1.3

State Environmental Quality Review Act

As explained in greater detail in Chapter 3, the Department’s SEQRA regulations authorize the
use of generic environmental impact statements to assess the environmental impacts of separate
actions having generic or common impacts. Drilling and production of separate oil and gas
wells, and other wells regulated under the Oil, Gas and Solution Mining Law (ECL 23) have
common impacts. After a comprehensive review of all the potential environmental impacts of
oil and gas drilling and production in New York, the Department finalized a Generic
Environmental Impact Statement and issued SEQRA Findings on the regulatory program in 1992
(1992 GEIS). In 2008, the Department determined that some aspects of the current and
anticipated application of high-volume hydraulic fracturing, which is often used in conjunction
with horizontal drilling and multi-well pad development, warranted further review in the context
of a SGEIS. This revised draft SGEIS discusses high-volume hydraulic fracturing in great detail
5

Environmental Conservation Law (ECL) §1-0101(1).

6

Correlative rights are the rights of mineral owners to receive or recover oil and gas, or the equivalent thereof, from their owned
tracts without drilling unnecessary wells or incurring unnecessary expense.

Final SGEIS 2015, Page 1-3

 and describes the potential significant impacts from this activity as well as measures that would
fully or partially mitigate the identified impacts. Specific mitigation measures would be adopted
as part of the Department’s Findings Statement in the event high-volume hydraulic fracturing is
authorized pursuant to the studies presented herein.
1.4

Project Chronology

1.4.1

February 2009 Final Scope

The Department released a draft Scope for public review in October 2008, and held public
scoping sessions at six venues in the Southern Tier and Catskills in November and December,
2008. A total of 188 verbal comments were received at these sessions. In addition, over 3,770
written comments were received (via e-mail, mail, or written comment card). All of these
comments were read and reviewed by Department staff and the Final Scope was completed in
February 2009, outlining the detailed analysis required for a thorough understanding of the
potentially significant environmental impacts of horizontal drilling and high-volume hydraulic
fracturing in low-permeability shale.
1.4.2

2009 Draft SGEIS

The Department released the 2009 draft SGEIS for public review on September 30, 2009 and
held public hearings at four venues in New York City (NYC), the Catskills and the Southern Tier
in October and November, 2009. Comments were accepted at the hearings verbally and in
writing, by postal mail, by e-mail and through a web-based application developed specifically for
that purpose. More than 2,500 people attended the Department hearings, and more than 200
verbal comments were delivered by individuals, local government officials, representatives of
environmental groups and other organizations and members of the oil and gas industry. The
Department also received over 13,000 comments via e-mail, postal mail and the web-based
comment system. In addition, transcripts from hearings held by the New York State Assembly,
the City of Oneonta, and the Tompkins County Council of Governments on the 2009 draft
SGEIS also provided the Department with numerous comments.

Final SGEIS 2015, Page 1-4

 1.4.2.1 April 2010 Announcement Regarding Communities with Filtration Avoidance
Determinations
On April 23, 2010, then-Commissioner Pete Grannis announced that due to the unique issues
related to the protection of NYC and Syracuse drinking water supplies, these watersheds would
be excluded from the generic environmental review process.
1.4.2.2 Subsequent Exclusion of Communities with Filtration Avoidance Determinations
The analysis of high-volume hydraulic fracturing conducted since the 2009 draft SGEIS supports
a finding that high-volume hydraulic fracturing is not consistent with the preservation of these
watersheds as an unfiltered drinking water supply.
1.4.3

2011 Revised Draft SGEIS

On January 1, 2011, Governor Cuomo continued Executive Order No. 41 (EO 41), which had
been issued by then-Governor Paterson on December 13, 2010. EO 41 directed the Department
to publish a revised draft SGEIS on or about June 1, 2011 and to accept public comment on the
revisions for a period of not less than 30 days.
On July 1, 2011, the Department published the Executive Summary of the Preliminary Revised
Draft SGEIS, prepared after considering the many comments received on the Draft SGEIS, and
on July 8, 2011, the Department published the full Preliminary Revised Draft SGEIS.
On September 7, 2011, the Department published a full Revised Draft SGEIS with a supporting
socioeconomic study for public comment. Hearings were held in four locations throughout the
state in November 2011. Approximately 67,000 comments were received by the close of the
comment period on January 11, 2012.
1.4.4

Draft Regulations

At the same time that the revised draft SGEIS was released in September 2011, the Department
published draft regulations for comment. In December 2012, DEC published revised draft
HVHF regulations. Over 180,000 comments were received on the proposed regulations. These
proposed regulations have lapsed under State law.

Final SGEIS 2015, Page 1-5

 1.4.5

Health Review by the New York State Department of Health

In September 2012, DEC Commissioner Martens requested the New York State Health
Commissioner to assess the health impact analysis in DEC’s revised draft SGEIS. The New
York State Department of Health (NYSDOH) retained three national experts, Drs. Lynn
Goldman (G. Wash. School of Pub. Health), John Adgate (Col. School of Pub. Health) and
Richard Jackson (UCLA School of Pub. Health), to assist in the review of the SGEIS. NYSDOH
also reviewed and evaluated scientific literature, engaged in field visits and discussions with
health and environmental authorities in nearly all states where HVHF activity is taking place,
and communicated with local, state, federal, international, academic, environmental and public
health stakeholders.
On December 17, 2014, Acting NYSDOH Commissioner Dr. Howard Zucker announced that
NYSDOH had completed its public health review of HVHF and recommended that HVHF
should not move forward in New York State. NYSDOH issued a report entitled “A Public
Health Review of High Volume Hydraulic Fracturing for Shale Gas Development.” 7 (See
Appendix A to the accompanying Response to Comments.)
1.4.6

Final SGEIS

By publishing this SGEIS and the accompanying Response to Comments, the Department is
further implementing EO 41.
1.4.7

Next Steps

At least 10 days after filing of the final SGEIS, the Department will issue a written Findings
Statement. Chapter 3 presents detailed information about a proposed future SEQRA compliance
process.
1.5

Methodology

1.5.1

Information about the Proposed Operations

For the 2009 draft SGEIS, the Department primarily relied on two sources of information
regarding the operations proposed for New York: (1) a number of permit applications filed with
the Department; and (2) the Independent Oil & Gas Association of New York (IOGA-NY),
7

The report can also be found at: http://www.health.ny.gov/press/reports/docs/high_volume_hydraulic_fracturing.pdf.

Final SGEIS 2015, Page 1-6

 which provided the Department with information from operators actively developing the
Marcellus Shale in Pennsylvania.
Preliminary review of comments on the 2009 draft SGEIS led Department staff to identify
additional technical and operational details needed from industry in order to evaluate and address
the comments. In April 2010, Department staff sent a “Notice of Information Needs” to IOGANY and to specific exploration/production and service companies that commented on the 2009
draft SGEIS. Again, IOGA-NY coordinated industry’s response, which was received in
September 2010 (ALL Consulting, 2010).
Department staff also communicated with and reviewed information and data made available
from the Pennsylvania Department of Environmental Protection (PADEP) and the SRBC about
events, regulations, enforcement and other matters associated with ongoing Marcellus Shale
development in Pennsylvania.
1.5.2

Intra-/Inter-agency Coordination

Within the Department, preparation of both the 2009 draft SGEIS and the revised draft SGEIS
involved all of the programs listed on the “Acknowledgements” page of each document. 8 Other
State agencies also provided assistance. Department staff consulted extensively with NYSDOH
staff, and staff in the Department of Public Service (Public Service Commission, or PSC)
assisted with the text describing that Department’s jurisdiction and regulation over gas gathering
facilities.
1.5.3

Comment Review

Of the nearly 13,300 comments received on the 2009 draft SGEIS, at least 9,830 were identified
as various campaigns likely generated by on-line form letters, eleven were unique petitions
signed by 31,464 individuals and organizations collectively, and seven were the transcripts of the
hearings described in Subsection 1.4.2. Each of the transcripts includes comments from a large
number of speakers, some of whom also submitted written comments. These transcripts were
treated as official public comments, and all comments received were given equal consideration

8

As a result of organizational changes within the Department, the Division of Solid & Hazardous Materials is now the Division
of Materials Management.

Final SGEIS 2015, Page 1-7

 regardless of the method by which they are received. Department staff read and categorized
every transcript and every piece of correspondence received to ensure that all substantive
comments would be evaluated.
Although the comment period on the 2009 draft SGEIS officially closed on December 31, 2009,
the Department accepted all comments submitted through January 8, 2010 to further ensure that
all substantive comments would be considered. As noted above, approximately 67,000
comments were received by the close of the comment period for the revised draft SGEIS on
January 11, 2012. Following this comment period, Department staff again reviewed and
categorized every comment. Comments on both draft documents were consolidated, and all
programs involved in preparing the revised draft SGEIS also participated in developing
responses to the summarized comments. The accompanying Response to Comments (Vol. 2)
includes summaries of the substantive comments received on both the 2009 draft SGEIS and the
revised dSGEIS, along with the Department’s responses to such comments.
1.6

Layout and Organization

The revised draft SGEIS supplements the existing 1992 GEIS, and does not exhaustively repeat
narrative from the 1992 GEIS that remains applicable to well permit issuance for horizontal
drilling and high-volume hydraulic fracturing.
1.6.1

Chapters

Chapter 1 is an introduction that explains the context, history and contents of the document, and
highlights the enhanced procedures, regulations and mitigation measures incorporated into the
document.
Chapter 2 is a description of the proposed action, and includes sections on purpose, public need
and benefit, project location and environmental setting that are required by SEQRA. The
environmental setting section focuses on topics that arose during the public scoping sessions.
For a comprehensive understanding of the environmental setting where high-volume hydraulic
fracturing might occur, it is necessary to also consult the 1992 GEIS.
Chapter 3 describes the use of a generic environmental impact statement and the resultant
SEQRA review process, identifies those potential projects which would require site-specific

Final SGEIS 2015, Page 1-8

 SEQRA determinations of significance after the SGEIS is completed, and identifies restricted
locations where high-volume hydraulic fracturing would be prohibited.
Chapter 4 supplements the geology discussion in Chapter 5 of the 1992 GEIS with additional
details about the Marcellus and Utica Shales, seismicity in New York State, naturally-occurring
radioactive materials (NORM) in the Marcellus Shale and naturally-occurring methane in New
York State.
Chapter 5 comprehensively describes the activities associated with high-volume hydraulic
fracturing and multi-well pad drilling, including the composition of hydraulic fracturing
additives and flowback water characteristics.
Chapter 6 describes potential impacts associated with the proposed activity and, like other
chapters, should be read as a supplement to the 1992 GEIS.
Chapter 7 describes the enhanced procedures, regulations and proposed mitigation measures that
have been identified to fully and/or partially mitigate potential significant adverse impacts from
high-volume hydraulic fracturing activities to be covered by the SGEIS and 1992 GEIS for
SEQRA purposes.
Chapter 8 explains intra- and interagency coordination involved in the well permitting process,
including the role of local governments and an expanded approach to local government
notification. Descriptions of other regulatory programs that govern some aspects of the potential
activities that were previously distributed among several chapters in the document are also now
included in Chapter 8.
Chapter 9 discusses the alternatives to well permit issuance that were reviewed and considered.
Chapter 10 is new in the revised draft SGEIS and provides information on certain non-routine
incidents in Pennsylvania where development of the Marcellus Shale by high-volume hydraulic
fracturing is currently ongoing.
Chapter 11 is new in the revised draft SGEIS and summarizes the impacts and mitigation
discussed in Chapters 6 and 7.

Final SGEIS 2015, Page 1-9

 The Department’s response to comments (Vol. 2) represents the Department’s most current
assessment of the impacts associated with high-volume hydraulic fracturing and the effectiveness
of proposed or considered mitigation measures to adequately mitigate significant adverse
environmental and public health impacts. To the extent that there is any inconsistency between
the Response to Comments and the text within the chapters and appendices of this Final SGEIS,
the Response to Comments should be relied upon.
1.6.2

Revisions

Revisions to the 2011 revised draft SGEIS text are generally marked by vertical lines in the page
margins, and new text is underlined.
1.6.3

Glossary, Bibliographies and Appendices

The Chapters described above are augmented by 27 Appendices and a lengthy glossary that
includes acronyms and technical or scientific terms that appear in the document. References
cited throughout the document are listed in a bibliography, and separate bibliographies are
included that list the various consultants’ sources.
1.7

Enhanced Impact Analyses and Mitigation Measures

The Department has identified numerous enhanced procedures and proposed mitigation measures
that are available to address the potential significant environmental impacts associated with well
permit issuance for horizontal drilling and high-volume hydraulic fracturing. Only the most
significant are listed below. Chapter 7 of this document and the 1992 GEIS in its entirety would
need to be consulted for the full range of available and required mitigation practices.
The list presented below does not include analyses and mitigation measures proposed in
September 2009 that are superseded by the revised draft SGEIS, or that are no longer relevant
because of changes in proposed operations.
1.7.1

Hydraulic Fracturing Chemical Disclosure

The Department’s hydraulic fracturing chemical disclosure requirements and public disclosure
approach set forth in Chapter 8, combined with the chemical disclosures required from industry
for the SGEIS analysis, make the Department’s disclosure regime among the most stringent in
the country. The Department’s regime exceeds the requirements of 22 of the 27 oil and gas

Final SGEIS 2015, Page 1-10

 producing states reviewed and is on par with the five states currently leading the country on
chemical disclosure. Additionally, the enhanced disclosure requirements are equivalent to the
proposed requirements of the federal Fracturing Awareness and Responsibility (FRAC) Act of
2011.
1.7.2

Water Well Testing

Prior to drilling, operators would be required to test private wells within 1,000 feet of the drill
site to provide baseline information and allow for ongoing monitoring. If there are no wells
within 1,000 feet, the survey area would extend to 2,000 feet. Chapter 7 reflects updated
recommendations from the NYSDOH regarding what analyses should be conducted.
1.7.3

Water Withdrawal and Consumption

1.7.3.1 2009 Draft SGEIS
Applicants would not only have to follow SRBC and Delaware River Basin Commission
(DRBC) protocols for water withdrawal where applicable, but would also be required to adhere
to a more stringent and protective passby flow requirement in regards to water withdrawal plans
- whether inside or outside of the Susquehanna or Delaware river basins. The intended results of
these requirements would be to protect aquatic organisms and their habitats in surface waters.
1.7.3.2 Revised Draft SGEIS
The discussion of passby flow and the required streamflow analysis have been updated based on
research and studies conducted after the release of the 2009 draft SGEIS. Additionally, details
have been added regarding the Department’s methodology for evaluating and determining
approvable groundwater withdrawal rates.
1.7.4

Well Control and Emergency Response Planning

Although current practices and requirements have proven effective at countless wells throughout
New York State, the Department has responded to the public’s heightened concerns regarding
well control and emergency response issues by including three significant revisions in the
revised draft SGEIS:
•

Submission, for review in the permit application, of the operator’s proposed blowout
preventer use and test plan for drilling and completion;

Final SGEIS 2015, Page 1-11

 •

Description of the required elements of an emergency response plan (ERP); and

•

Submission and on-site availability of an ERP consistent with the SGEIS, including a list
of emergency contact numbers for the community surrounding the well pad.

1.7.5

Local Planning Documents

The Department proposes that applicants be required to compare the proposed well pad location
to local land use laws, regulations, plans and policies to determine whether the proposed activity
is consistent with such local land use laws, regulations, plans and policies. If the applicant or the
potentially impacted local government informs the Department that it believes a conflict exists,
the Department would request additional information with regard to this issue so it can consider
whether significant adverse impacts relating to land use and zoning would result from permit
issuance.
1.7.6

Secondary Containment, Spill Prevention and Stormwater Pollution Prevention

The Department proposes to require, via permit condition and/or new regulation, that operators
provide secondary containment around all additive staging areas and fueling tanks, manned
fluid/fuel transfers and visible piping and appropriate use of troughs, drip pads or drip pans. In
addition, drilling and hydraulic fracturing operations would be subject to an activity-specific
general stormwater permit that would address industrial activities as well as the construction
activities that are traditionally the focus of stormwater permitting for oil and gas well sites. The
comprehensive Stormwater Pollution Prevention Plan (SWPPP) would incorporate by reference
a Spill Prevention, Control and Countermeasures Plan.
1.7.7

Well Construction

Existing requirements are designed to ensure that surface casing be set deeply enough to not only
isolate fresh water zones but also to serve as an adequate foundation for well control while
drilling deeper. It is also necessary under existing requirements, to the extent possible, to avoid
extending the surface casing into shallow gas-bearing zones. Existing casing and cementing
requirements that are incorporated into permit conditions establish the required surface casing
setting depth based on the best available site-specific information. Each subsequent installation
of casing and cement serves to further protect the surface casing and hence, the surrounding fresh
water zones.

Final SGEIS 2015, Page 1-12

 1.7.7.1 2009 Draft SGEIS
Proposed well construction enhancements for high-volume hydraulic fracturing included:
•

Requirement for fully cemented production casing or intermediate casing (if used), with
the cement bond evaluated by use of a cement bond logging tool; and

•

Required certification prior to hydraulic fracturing of the sufficiency of as-built wellbore
construction.

1.7.7.2 Revised Draft SGEIS
Additional well construction enhancements for high-volume hydraulic fracturing that the
Department proposes to require pursuant to permit condition and/or regulation are listed below:
•

Specific American Petroleum Institute (API) standards, specifications and practices
would be incorporated into permit conditions related to well construction. Among these
would be requirements to adhere to specifications for centralizer type and for casing and
cement quality;

•

Fully cemented intermediate casing would be required unless supporting site-specific
documentation to waive the requirement is presented. This directly addresses gas
migration concerns by providing additional barriers (i.e., steel casing, cement) between
aquifers and shallow gas-bearing zones;

•

Additional measures to ensure cement strength and sufficiency would be incorporated
into permit conditions, also directly addressing gas migration concerns. Compliance
would continue to be tracked through site inspections and required well completion
reports, and any other documentation the Department deems necessary for the operator to
submit or make available for review; and

•

Minimum compressive strength requirements.
o Minimum waiting times during which no activity is allowed which might disturb
the cement while it sets;
o Enhanced requirements for use of centralizers which serve to ensure the
uniformity and strength of the cement around the well casing; and
o Required use of more advanced cement evaluation tools.

Final SGEIS 2015, Page 1-13

 1.7.8

Flowback Water Handling On-Site

The Department proposes to require that operators storing flowback water on-site would be
required to use watertight tanks located within secondary containment, and remove the fluid
from the wellpad within specified time frames.
1.7.9

Flowback Water Disposal

Under existing regulations, before a permit is issued, the operator must disclose plans for
disposal of flowback water and production brine. Further, in the SGEIS the Department
proposes to use a new "Drilling and Production Waste Tracking" process, similar to the process
applicable to medical waste, to monitor disposal. Under existing regulations, full analysis and
approvals under state water laws and regulations are required before a water treatment facility
can accept flowback from high-volume hydraulic fracturing operations. Appendix 22 includes a
description and flow chart of the required approval process for discharge of flowback water or
production brine from high-volume hydraulic fracturing to a Publicly-Owned Treatment Works
(POTW). An applicant proposing discharge to a POTW would be required to submit a treatment
capacity analysis for the receiving POTW, and, in the event that the POTW is the primary fluid
disposal plan, a contingency plan. Additionally, limits would be established for NORM in
POTW influent.
1.7.10 Management of Drill Cuttings
The Department has determined that drill cuttings are solid wastes, specifically construction and
demolition debris, under the State’s regulatory system. Therefore, the Department would allow
disposal of cuttings from drilling processes which utilize only air and/or water on-site, at
construction and demolition (C&D) debris landfills, or at municipal solid waste (MSW) landfills,
while cuttings from processes which utilize any oil-based or polymer-based products could only
be disposed of at MSW landfills. The revised draft SGEIS proposes to require, pursuant to
permit conditions and/or regulation, that a closed-loop tank system be used instead of a reserve
pit to manage drilling fluids and cuttings for:
•

Horizontal drilling in the Marcellus Shale without an acceptable acid rock drainage
(ARD) mitigation plan for on-site cuttings burial; and

Final SGEIS 2015, Page 1-14

 •

Cuttings that, because of the drilling fluid composition used must be disposed off-site,
including at a landfill.

Only ARD mitigation plans that do not require long-term monitoring would be acceptable.
Examples are provided in Chapter 7.
1.7.11 Emissions and Air Quality
The need to re-evaluate air quality impacts and the applicability of various regulations was raised
during the scoping process, with emphasis on the duration of activities at a multi-well pad and
the number of internal combustion engines used for high-volume hydraulic fracturing.
1.7.11.1

2009 Draft SGEIS

The following conclusions and requirements were set forth:
•

Per United States Environmental Protection Agency (EPA) NESHAPS subpart ZZZZ, the
compressor station would have an oxidation catalyst for formaldehyde. This also reduces
carbon monoxide (CO) by 90% and Volatile Organic Compounds (VOCs) by 70%;

•

Per EPA subpart HH, the glycol dehydrator would have a condenser to achieve a benzene
emission of <1 ton per year (Tpy) (if “wet” gas is detected);

•

Use of Ultra Low Sulfur Fuel (ULSF) of 15 parts per million (ppm) in all engines would
be required;

•

Small stack height increases on compressor, vent and dehydrator would be required (if
“sour” and “wet” gas encountered for the latter two, respectively);

•

All annual and short-term ambient standards (National Ambient Air Quality Standards, or
NAAQS) and the Department’s toxics thresholds (Annual and Short-Term Guideline
Concentrations, or AGCs and SGCs) would be met, except 24-hour PM10/PM2.5
NAAQS due to drilling and hydraulic fracturing engines; and

•

Impacts from a nearby pad modeled and indicated no overlap in the calculated
“cumulative” impacts on local scale.

The facility definition for permitting was based on Clean Air Act (CAA) 112(n)(4) per EPA
guidance at the time, which limits it to “surface area” (i.e., per pad). Annual emissions from all
sources were calculated assuming ten wells per pad and resulted in a classification of the
emissions as “minor” sources. No final determination was made as to whether non-road engines

Final SGEIS 2015, Page 1-15

 would be part of “stationary” facility since it was unclear before September 2009 if these would
be at the pad more than 12 months.
1.7.11.2

Revised Draft SGEIS

The Department performed substantive additional emissions and air quality analyses, which
identified the following mitigation measures that the Department proposes to require through
enhanced procedures, permit conditions and/or regulations:
•

The diesel fuel used in drilling and completion equipment engines would be limited to
ULSF with a maximum sulfur content of 15 ppm;

•

There would not be any simultaneous operations of the drilling and completion
equipment engines at the single well pad;

•

The maximum number of wells to be drilled and completed annually or during any
consecutive 12-month period at a single pad would be limited to four;

•

The emissions of benzene at any glycol dehydrator to be used at the well pad would be
limited to 1 Tpy as determined by calculations with the Gas Research Institute’s (GRI)
GlyCalc program. If wet gas is encountered, then the dehydrator would have a minimum
stack height of 30 feet (9.1 meters) and would be equipped with a control device to limit
the benzene emissions to 1 Tpy;

•

Condensate tanks used at the well pad would be equipped with vapor recovery systems to
minimize fugitive VOC emissions;

•

During the flowback phase, the venting of gas from each well pad would be limited to a
maximum of 5 million standard cubic feet (MMscf) during any consecutive 12 month
period. If “sour” gas is encountered with detected hydrogen sulfide (H2S) emissions, the
height at which the gas would be vented would be a minimum of 30 feet (9.1 meters);

•

During the flowback phase, flaring of gas at each well pad would be limited to a
maximum of 120 MMscf during any consecutive 12-month period;

•

Wellhead compressors would be equipped with Non-Selective Catalytic Reduction
(NSCR) controls;

•

No uncertified (i.e., EPA Tier 0) drilling or completion equipment engines would be used
for any activity at the well sites;

•

The drilling engines and drilling air compressors would be limited to EPA Tier 2 or
newer equipment. If Tier 1 drilling equipment is to be used, these would be equipped
with both particulate traps (Continuously Regenerating Diesel Particulate Filters, or

Final SGEIS 2015, Page 1-16

 CRDPF) and Selective Catalytic Reduction (SCR) controls. During operations, this
equipment would be positioned as close to the center of the well pad as practicable. If
industry deviates from the control requirements or proposes alternate mitigation and/or
control measures to demonstrate ambient standard compliance, site-specific information
would be provided to the Department for review and concurrence; and
•

The completion equipment engines would be limited to EPA Tier 2 or newer equipment.
CRDPFs would be required for all Tier 2 engines. SCR control would be required on all
completion equipment engines regardless of the emission Tier. During operations, this
equipment would be positioned as close to the center of the well pad as practicable. If
industry deviates from this requirement or proposes mitigation and/or alternate control
measures to demonstrate ambient standard compliance, site specific information would
be provided to the Department for review and concurrence.

In addition, the revised draft SGEIS discusses the effect of region-wide emissions on State
Implementation Plan (SIP) for Ozone NAAQS and implementation of local and regional level air
quality monitoring at well pads and surrounding areas.
1.7.12 Greenhouse Gas Mitigation
All operational phases of well pad activities, and all greenhouse gas (GHG) emission sources are
evaluated in both the 2009 draft SGEIS and the current draft. Based on this analysis, the
Department proposes in the current draft to require the following controls and mitigation
measures, pursuant to permit conditions and/or regulation:
•

Implementation by the operator of a Leak Detection and Repair Program;

•

Upon request, the operator would be required to provide a copy of data required under
federal (EPA) GHG reporting rule;

•

Reduced Emissions Completion (REC) would be required whenever a gathering line is
already constructed. In addition, two years after issuance of the first permit for highvolume hydraulic fracturing, the Department would evaluate whether the number of wells
that can be drilled on a pad without REC should be limited; and

•

Implementation of other control technologies when applicable, as described in Chapter 7.

1.7.13 Habitat Fragmentation
The current draft includes a substantially augmented analysis of potential impacts from highvolume hydraulic fracturing on wildlife and habitat. Based on that analysis, two measures that
were not included in the 2009 draft SGEIS are proposed as mitigation in the revised draft SGEIS:

Final SGEIS 2015, Page 1-17

 •

Grassland Focus Areas on private land – Surface disturbance in grassland patches
comprised of 30 acres or more of contiguous grassland within Grassland Focus Areas
would be contingent on the findings of a site-specific ecological assessment conducted by
the permit applicant and implementation of mitigation measures identified as part of such
ecological assessment; and

•

Forest Focus Areas on private land – Surface disturbance in forest patches comprised of
150 acres or more of undisturbed, contiguous forest within Forest Focus Areas would be
contingent on a site-specific ecological assessment conducted by the permit applicant and
implementation of mitigation measures identified as part of such ecological assessment.

1.7.14 State Forests, State Wildlife Management Areas and State Parks
Surface disturbance associated with high-volume hydraulic fracturing would not be allowed on
State-owned lands administered by the Department, including but not limited to State Forests and
State Wildlife Management Areas, because it is inconsistent with the suite of purposes for which
those lands have been acquired. Current Office of Parks, Recreation and Historic Preservation
(OPRHP) policy would impose a similar restriction on State Parks.
1.7.15 Community and Socioeconomic Impacts
Chapter 6 of this revised draft SGEIS includes a significantly expanded discussion of community
and socioeconomic impacts, traffic impacts, and noise and visual impacts, with measures that
will be implemented by the Department to mitigate these impacts described in Chapter 7.
1.8

Additional Precautionary Measures

In order to safeguard the environment from risks associated with spills or other events that could
release contaminants into environmentally sensitive areas, the revised draft SGEIS includes the
following prohibitions and mitigation measures for high-volume hydraulic fracturing:
•

Well pads for high-volume hydraulic fracturing would be prohibited in the NYC and
Syracuse watersheds, and within a 4,000-foot buffer around those watersheds;

•

Well pads for high-volume hydraulic fracturing would be prohibited within 500 feet of
primary aquifers (subject to reconsideration 2 years after issuance of the first permit for
high-volume hydraulic fracturing);

•

Well pads for high-volume hydraulic fracturing would be prohibited within 2,000 feet of
public water supply wells, river or stream intakes and reservoirs (subject to
reconsideration 3 years after issuance of the first permit for high-volume hydraulic
fracturing);

Final SGEIS 2015, Page 1-18

 •

For at least two years from issuance of the first permit for high-volume hydraulic
fracturing, proposals for high-volume hydraulic fracturing at any well pad within 500 feet
of principal aquifers, would require (1) site-specific SEQRA determinations of
significance and (2) individual State Pollutant Discharge Elimination System (SPDES)
permits for stormwater discharges. The Department would re-evaluate the necessity of
this approach after two years of experience issuing permits in areas outside of the 500foot boundary;

•

The Department would not issue permits for proposed high-volume hydraulic fracturing
at any well pad in 100-year floodplains; and

•

The Department would not issue permits for proposed high-volume hydraulic fracturing
at any proposed well pad within 500 feet of a private water well or domestic use spring,
unless waived by the owner.

As reflected in the response to comments, subsequent to the issuance of the 2011 dSGEIS and in
the face of ever-increasing information and scientific studies detailing the risks and uncertainties
regarding the environmental and public health impacts that result from HVHF development, the
Department considered numerous additional mitigation measures to protect and reduce impacts
to drinking and other water resources, air, and other resources, including, for example, banning
any HVHF development in the Catskill Park, extending setbacks from various resources and
eliminating sunset periods for various restrictions.

Final SGEIS 2015, Page 1-19

 This page intentionally left blank.

Chapter 2
Description of Proposed Action
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Chapter 2 – Description of Proposed Action
CHAPTER 2 DESCRIPTION OF PROPOSED ACTION ............................................................................................. 2-1
2.1 PURPOSE................................................................................................................................................... 2-2
2.2 PROJECT LOCATION...................................................................................................................................... 2-2
2.3 ENVIRONMENTAL SETTING ............................................................................................................................. 2-3
2.3.1 Water Use Classifications .......................................................................................................................... 2-3
2.3.2 Water Quality Standards ........................................................................................................................... 2-7
2.3.3 Drinking Water .......................................................................................................................................... 2-8
2.3.3.1 Federal ............................................................................................................................................ 2-8
2.3.3.2 New York State ............................................................................................................................. 2-13
2.3.4 Public Water Systems .............................................................................................................................. 2-14
2.3.4.1 Primary and Principal Aquifers ..................................................................................................... 2-15
2.3.4.2 Public Water Supply Wells ............................................................................................................ 2-17
2.3.5 Private Water Wells and Domestic-Supply Springs ................................................................................. 2-17
2.3.6 History of Drilling and Hydraulic Fracturing in Water Supply Areas ........................................................ 2-18
2.3.7 Regulated Drainage Basins ...................................................................................................................... 2-20
2.3.7.1 Delaware River Basin .................................................................................................................... 2-21
2.3.7.2 Susquehanna River Basin .............................................................................................................. 2-21
2.3.7.3 Great Lakes-St. Lawrence River Basin ........................................................................................... 2-23
2.3.8 Water Resources Replenishment ............................................................................................................ 2-23
2.3.9 Floodplains .............................................................................................................................................. 2-25
2.3.9.1 Analysis of Recent Flood Events ................................................................................................... 2-27
2.3.9.2 Flood Zone Mapping ..................................................................................................................... 2-27
2.3.9.3 Seasonal Analysis .......................................................................................................................... 2-28
2.3.10 Freshwater Wetlands .............................................................................................................................. 2-29
2.3.11 Socioeconomic Conditions ...................................................................................................................... 2-30
2.3.11.1 Economy, Employment, and Income ............................................................................................ 2-36
2.3.11.2 Population..................................................................................................................................... 2-70
2.3.11.3 Housing ......................................................................................................................................... 2-76
2.3.11.4 Government Revenues and Expenditures .................................................................................... 2-86
2.3.11.5 Environmental Justice ................................................................................................................... 2-98
2.3.12 Visual Resources .................................................................................................................................... 2-111
2.3.12.1 Historic Properties and Cultural Resources ................................................................................ 2-114
2.3.12.2 Parks and Other Recreation Areas .............................................................................................. 2-121
2.3.12.3 Natural Areas .............................................................................................................................. 2-127
2.3.12.4 Additional Designated Scenic or Other Areas ............................................................................. 2-136
2.3.13 Noise ...................................................................................................................................................... 2-144
2.3.13.1 Noise Fundamentals ................................................................................................................... 2-144
2.3.13.2 Common Noise Effects ................................................................................................................ 2-146
2.3.13.3 Noise Regulations and Guidance ................................................................................................ 2-148
2.3.13.4 Existing Noise Levels ................................................................................................................... 2-151
2.3.14 Transportation - Existing Environment .................................................................................................. 2-151
2.3.14.1 Terminology and Definitions....................................................................................................... 2-151
2.3.14.2 Regional Road Systems ............................................................................................................... 2-156
2.3.14.3 Condition of New York State Roads ............................................................................................ 2-162
2.3.14.4 NYSDOT Funding Mechanisms .................................................................................................... 2-163
2.3.14.5 Rail and Air Services .................................................................................................................... 2-166
2.3.15 Community Character............................................................................................................................ 2-167

Final SGEIS 2015, Page 2-i

 FIGURES
Figure 2.1 - Primary and Principal Aquifers in New York State ................................................................................ 2-16
Figure 2.2 - Susquehanna and Delaware River Basins ............................................................................................. 2-22
Figure 2.3 - Representative Regions Within the Marcellus Shale Extent (New August 2011) ................................. 2-31
Figure 2.4 - Representative Regions A, B, and C (New August 2011) ...................................................................... 2-33
Figure 2.5 - Region A: Natural Gas Production, 1994 to 2009 (New August 2011) ................................................. 2-56
Figure 2.6 - Region C: Natural Gas Production, 1994-2009 (New August 2011) ..................................................... 2-68
Figure 2.7 - Potential Environmental Justice Areas for Region A (New August 2011) ........................................... 2-103
Figure 2.8 - Potential Environmental Justice Areas for Region B (New August 2011) ........................................... 2-106
Figure 2.9 - Potential Environmental Justice Areas for Region C (New August 2011) ........................................... 2-109
Figure 2.10 - Area of Interest for Visual Resources (New August 2011)................................................................ 2-112
Figure 2.11 - Visually Sensitive Areas Associated with Historic Properties and Cultural Resources (New
August 2011) .................................................................................................................................... 2-120
Figure 2.12 - Parks and Recreational Resources that May be Visually Sensitive (New August 2011) ................... 2-125
Figure 2.13 - Natural Areas that May be Visually Sensitive (New August 2011) ................................................... 2-128
Figure 2.14 - Additional Designated Scenic or other Areas that May be Visually Sensitive .................................. 2-137
Figure 2.15 - Level of Continuous Noise Causing Speech Interference (New August 2011).................................. 2-147
Figure 2.16 - FHWA Vehicle Classifications (New August 2011) ............................................................................ 2-154
Figure 2.17 - New York State Department of Transportation Regions (New August 2011) .................................. 2-156
Figure 2.18 - Transportation (New August 2011) .................................................................................................. 2-158
Figure 2.19 - Land Cover and Agricultural Districts, Representative Region A (New August 2011) ...................... 2-171
Figure 2.20 - Land Cover and Agricultural Districts, Representative Region B (New August 2011) ...................... 2-179
Figure 2.21 - Land Cover and Agricultural Districts, Representative Region C (New August 2011) ...................... 2-187
TABLES
Table 2.1 - New York Water Use Classifications ........................................................................................................ 2-4
Table 2.2 - Primary Drinking Water Standards ........................................................................................................ 2-10
Table 2.3 - Secondary Drinking Water Standards .................................................................................................... 2-13
Table 2.4 - Public Water System Definition ............................................................................................................. 2-15
Table 2.5 - New York State: Area Employment by Industry, 2009 (New August 2011) ........................................... 2-38
Table 2.6 - New York State: Wages by Industry, 2009 (New August 2011) ............................................................. 2-39
Table 2.7 - New York State: Labor Force Statistics, 2000 and 2010 (New August 2011) ........................................ 2-39
Table 2.8 - New York State: Income Statistics, 1999 and 2009 (New August 2011) ................................................ 2-40
Table 2.9 - New York State: Employment in Travel and Tourism, 2009 (New August 2011) .................................. 2-41
Table 2.10 - New York State: Wages in Travel and Tourism, 2009 (New August 2011) ......................................... 2-41
Table 2.11 - New York State: Agricultural Data, 2007 (New August 2011).............................................................. 2-42
Table 2.12 - New York: Impact of a $1 Million Dollar Increase in the Final Demand in the Output of the Oil
and Gas Extraction Industry on the Value of the Output of Other Industries (New August
2011) .................................................................................................................................................. 2-43
Table 2.13 - New York State: Employment in the Oil and Gas Extraction Industry, 2000-2010 (New August
2011) .................................................................................................................................................. 2-44
Table 2.14 - Most Common Occupations in the U.S. Oil and Gas Extraction Industry, 2008 (New August
2011) .................................................................................................................................................. 2-45
Table 2.15 - New York State: Wages in the Oil and Gas Industry, 2009 (New August 2011) .................................. 2-46
Table 2.16 - New York State: Natural Gas Production, 1985-2009 (New August 2011) .......................................... 2-47
Table 2.17 - Permits Issued, Wells Completed, and Active Wells, NYS Gas Wells, 1994-2009 (New August
2011) .................................................................................................................................................. 2-48
Table 2.18 - Average Wellhead Price for New York State’s Natural Gas, 1994-2009 (New August 2011) .............. 2-49
Table 2.19 - Market Value of New York State’s Natural Gas Production, 1994-2009 (New August 2011).............. 2-49
Table 2.20 - Region A: Area Employment by Industry, 2009 (New August 2011) ................................................... 2-50
Table 2.21 - Region A: Wages by Industry, 2009 (New August 2011) ..................................................................... 2-51
Table 2.22 - Region A: Labor Force Statistics, 2000 and 2010 (New August 2011) ................................................. 2-52
Table 2.23 - Region A: Income Statistics, 1999 and 2009 (New August 2011) ........................................................ 2-52

Final SGEIS 2015, Page 2-ii

 Table 2.24 - Region A: Employment in Travel and Tourism, 2009 (New August 2011) ........................................... 2-54
Table 2.25 - Region A: Wages in Travel and Tourism, 2009 (New August 2011) ..................................................... 2-54
Table 2.26 - Region A: Agricultural Data, 2007 (New August 2011) ........................................................................ 2-55
Table 2.27 - Region A: Number of Active Natural Gas Wells, 1994-2009 (New August 2011) ................................ 2-56
Table 2.28 – Natural Gas Production and Active Wells by Town within each County in Region A, 2009 (New
August 2011) ...................................................................................................................................... 2-57
Table 2.29 - Region B: Area Employment, by Industry, 2009 (New August 2011) .................................................. 2-58
Table 2.30 - Region B: Wages, by Industry, 2009 (New August 2011) ..................................................................... 2-58
Table 2.31 - Region B: Labor Force Statistics, 2000 and 2010 ((New August 2011)) ............................................... 2-59
Table 2.32 - Region B: Income Statistics, 1999 and 2009 (New August 2011) ........................................................ 2-60
Table 2.33 - Region B: Travel and Tourism, by Industrial Group, 2009 (New August 2011).................................... 2-61
Table 2.34 - Region B: Wages in Travel and Tourism, 2009 (New August 2011) ..................................................... 2-61
Table 2.35 - Region B: Agricultural Data, 2007 (New August 2011) ........................................................................ 2-62
Table 2.36 - Region C: Area Employment by Industry, 2009 (New August 2011) ................................................... 2-63
Table 2.37 - Region C: Wages, by Industry, 2009 (New August 2011) ..................................................................... 2-63
Table 2.38 - Region C: Labor Force Statistics, 2000 and 2010 (New August 2011) ................................................. 2-64
Table 2.39 - Region C: Income Statistics, 1999 and 2009 (New August 2011) ........................................................ 2-64
Table 2.40 - Region C: Travel and Tourism, by Industrial Group, 2009 (New August 2011) .................................... 2-66
Table 2.41 - Region C: Wages in Travel and Tourism, 2009 (New August 2011) ..................................................... 2-66
Table 2.42 - Region C: Agricultural Data, 2007 (New August 2011) ........................................................................ 2-67
Table 2.43 - Number of Active Natural Gas Wells in Region C, 1994-2009 (New August 2011) ............................. 2-68
Table 2.44 - Natural Gas Production and the Number of Active Gas Wells by Town within each County in
Region C, 2009 (New August 2011) .................................................................................................... 2-69
Table 2.45 - New York State: Historical and Current Population, 1990, 2000, 2010 (New August 2011) ............... 2-71
Table 2.46 - New York State: Projected Population, 2015 to 2030 (New August 2011) ......................................... 2-71
Table 2.47 - Region A: Historical and Current Population, 1990, 2000, 2010 (New August 2011).......................... 2-72
Table 2.48 - Region A: Population Projections, 2015 to 2030 (New August 2011)................................................. 2-73
Table 2.49 - Region B: Historical and Current Population - 1990, 2000, 2010 (New August 2011)......................... 2-73
Table 2.50 - Region B: Population Projections, 2015 to 2030 (New August 2011).................................................. 2-74
Table 2.51 - Region C: Historical and Current Population - 1990, 2000, 2010 (New August 2011) ......................... 2-75
Table 2.52 - Region C: Population Projections, 2015 to 2030 (New August 2011) ................................................. 2-75
Table 2.53 - New York State: Total Housing Units - 1990, 2000, 2010 (New August 2011).................................... 2-76
Table 2.54 - New York State: Type of Housing Units, 2009 (New August 2011)...................................................... 2-76
Table 2.55 - New York State: Number of Sales and Annual Median Sale Price of Single-Family Homes Sold,
2008-2010 (New August 2011) .......................................................................................................... 2-77
Table 2.56 - New York State: Housing Characteristics, 2010 (New August 2011) ................................................... 2-77
Table 2.57 - Region A: Total Housing Units - 1990, 2000, 2010 (New August 2011) ............................................... 2-78
Table 2.58 - Region A: Total Housing Units by Type of Structure, 2009 (New August 2011) .................................. 2-78
Table 2.59 - Region A: Number of Sales and Annual Median Sale Price of Single-Family Homes Sold, 20082010 (New August 2011) .................................................................................................................... 2-79
Table 2.60 - Region A: Housing Characteristics, 2010 (New August 2011) .............................................................. 2-80
Table 2.61 - Region A: Short-Term Accommodations (Hotels/Motels), 2011 (New August 2011) ......................... 2-80
Table 2.62 - Region B: Total Housing Units - 1990, 2000, 2010 (New August 2011) ............................................... 2-81
Table 2.63 - Region B: Total Housing Units by Type of Structure 2009 (New August 2011) ................................... 2-81
Table 2.64- Region B: Number of Sales and Annual Median Sale Price of Single-Family Homes Sold, 20082010 (New August 2011) .................................................................................................................... 2-82
Table 2.65 - Region B: Housing Characteristics, 2010 (New August 2011) .............................................................. 2-83
Table 2.66 - Region B: Short-Term Accommodations (Hotels/Motels) (New August 2011).................................... 2-83
Table 2.67 - Region C: Total Housing Units - 1990, 2000, 2010 (New August 2011) ............................................... 2-84
Table 2.68 - Region C: Total Housing Units by Type of Structure, 2009 (New August 2011) .................................. 2-84
Table 2.69 - Region C: Number of Sales and Annual Median Sale Price of Single-Family Homes Sold, 20082010 (New August 2011) .................................................................................................................... 2-85
Table 2.70 - Region C: Housing Characteristics, 2010 (New August 2011) .............................................................. 2-85

Final SGEIS 2015, Page 2-iii

 Table 2.71 - Region C: Short-Term Accommodations (Hotels/Motels) (New August 2011).................................... 2-86
Table 2.72 - New York State Revenues Collected for FY Ending March 31, 2010 (New August 2011) .................... 2-87
Table 2.73 - New York State: Number of Leases and Acreage of State Land Leased for Oil and Natural Gas
Development, 2010 (New August 2011) ............................................................................................ 2-88
Table 2.74 - 2000-2010 Leasing Revenue by Payment Type for New York State (New August 2011)..................... 2-88
Table 2.75 - Region A: Total Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011) ............. 2-90
Table 2.76 - Region A: Local Tax Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011) ...... 2-91
Table 2.77 - Gas Economic Profile for Medina Region 3 (New August 2011) .......................................................... 2-91
Table 2.78 - Region A: Expenditures for FY Ending December 31, 2009 ($ millions) (New August 2011) ............... 2-92
Table 2.79 - Region B: Total Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011) ............. 2-93
Table 2.80 - Region B: Local Tax Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011) ...... 2-94
Table 2.81 - Gas Economic Profile for Medina Region 4 and State Equalization Rates and Millage Rates for
Region B (New August 2011).............................................................................................................. 2-94
Table 2.82 - Region B: Expenditures for FY Ending December 31, 2009 ($ millions) (New August 2011) ............... 2-95
Table 2.83 - Region C: Revenues for FY Ending December 31, 2009 ($ millions) (New August 2011)..................... 2-96
Table 2.84 - Region C: Local Tax Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011) ...... 2-97
Table 2.85 - Gas Economic Profile for Medina Region 2 and State Equalization Rates and Millage Rates for
Region C (New August 2011) .............................................................................................................. 2-97
Table 2.86 - Region C: Expenditures for FY Ending December 31, 2009 (New August 2011) .................................. 2-98
Table 2.87 - Racial and Ethnicity Characteristics for New York State (New August 2011) .................................... 2-101
Table 2.88 - Region A: Racial and Ethnicity Characteristics (New August 2011) ................................................... 2-104
Table 2.89 - Region B: Racial and Ethnicity Characteristics (New August 2011) ................................................... 2-107
Table 2.90 - Region C: Racial and Ethnicity Characteristics (New August 2011) ................................................... 2-110
Table 2.91 - Number of NRHP-Listed Historic Properties within the Area Underlain by the Marcellus and
Utica Shales in New York (New August 2011) .................................................................................. 2-115
Table 2.92 - National Historic Landmarks (NHLs) Located within the Area Underlain by the Marcellus and
Utica Shales in New York (New August 2011) .................................................................................. 2-118
Table 2.93 - State Parks Located within the Area Underlain by the Marcellus and Utica Shales in New York
(New August 2011) ........................................................................................................................... 2-122
Table 2.94 - Select Trails Located within the Area Underlain by the Marcellus and Utica Shales in New York
(New August 2011) ........................................................................................................................... 2-126
Table 2.95 - State Nature and Historic Preserves in Counties Located within the Area Underlain by the
Marcellus and Utica Shales in New York (New August 2011) .......................................................... 2-129
Table 2.96 - National and State Wild, Scenic and Recreational Rivers (designated or potential) Located
within the Area Underlain by the Marcellus and Utica Shales in New York (New August 2011) ..... 2-132
Table 2.97 - State Game Refuges and State Wildlife Management Areas Located within the Area Underlain
by the Marcellus and Utica Shales in New York (New August 2011) ............................................... 2-134
Table 2.98 - National Natural Landmarks Located within the Area Underlain by the Marcellus and Utica
Shales in New York (New August 2011) ........................................................................................... 2-135
Table 2.99 - Designated and Proposed National and State Scenic Byways, Highways, and Roads Located
within the Area Underlain by the Marcellus and Utica Shales in New York (New August 2011) ..... 2-138
Table 2.100 - Recommended Open Space Conservation Projects Located in the Area Underlain by the
Marcellus and Utica Shales in New York (New August 2011) .......................................................... 2-141
Table 2.101 - Effects of Noise on People (New August 2011) ............................................................................... 2-148
Table 2.102 - Summary of Noise Levels Identified as Requisite to Protect Public Health and Welfare with
an Adequate Margin of Safety (New August 2011).......................................................................... 2-149
Table 2.103 - Common Noise Levels (New August 2011) ...................................................................................... 2-151
Table 2.104 - Guidelines on Extent of Rural Functional Systems (New August 2011) ........................................... 2-153
Table 2.105 - Descriptions of the Thirteen FHWA Vehicle Classification Categories (New August 2011) ............. 2-155
Table 2.106 - Region A: Highway Mileage by County, 2009 (New August 2011) .................................................. 2-159
Table 2.107 - Heavy Vehicles as a Percentage of Total Vehicles in Rural Areas in NYSDOT Regions 6 and 9,
2004-2009 (New August 2011) ........................................................................................................ 2-159
Table 2.108 - Region B: Highway Mileage by County, 2009 (New August 2011)................................................... 2-160

Final SGEIS 2015, Page 2-iv

 Table 2.109 - Heavy Vehicles as a Percentage of Total Vehicles in Rural Areas in NYSDOT Region 9, 20042009 (New August 2011) .................................................................................................................. 2-161
Table 2.110 - Region C: Highway Mileage by County, 2009 (New August 2011)................................................... 2-161
Table 2.111 - Heavy Vehicles as a Percentage of Total Vehicles in Rural Areas in NYSDOT Region 5, 2009
(New August 2011) ........................................................................................................................... 2-162
Table 2.112 - Ranking System of Pavement Condition in New York State (New August 2011)............................. 2-163
Table 2.113 - NYSDOT Total Receipts, 2009-2012 ($ thousands) (New August 2011) .......................................... 2-165

Final SGEIS 2015, Page 2-v

 This page intentionally left blank.

Chapter 2 DESCRIPTION OF PROPOSED ACTION
The proposed action is the Department’s issuance of permits to drill, deepen, plug back or
convert wells for horizontal drilling and high-volume hydraulic fracturing in the Marcellus Shale
and other low-permeability natural gas reservoirs. Wells where high-volume hydraulic
fracturing is used may be drilled vertically, directionally or horizontally. The proposed action,
however, does not include horizontal drilling where high-volume hydraulic fracturing is not
employed. Such drilling is covered under the GEIS.
Hydraulic fracturing is a well stimulation technique which consists of pumping an engineered
fluid system and a proppant such as sand down the wellbore under high pressure to create
fractures in the hydrocarbon-bearing rock. The fractures serve as pathways for hydrocarbons to
move to the wellbore for production. High-volume hydraulic fracturing, using 300,000 gallons
of water or more per well, is also referred to as “slick water fracturing.” An individual well
treatment may consist of multiple stages (multi-stage fracturing). Further information on highvolume hydraulic fracturing, including the composition of the fluid system, is provided in
Chapter 5.
Multiple wells may be drilled from a common location (multi-well pad, or multi-well site). The
Department may receive applications to drill approximately 1,700 – 2,500 horizontal and vertical
wells for development of the Marcellus Shale by high-volume hydraulic fracturing during a
“peak development” year. An average year may see 1,600 or more applications. Development
of the Marcellus Shale in New York may occur over a 30-year period. 9 More information about
these activity estimates and the factors which could affect them is presented in Chapter 5.
This SGEIS is focused on topics not addressed by the 1992 GEIS, with emphasis on potential
impacts associated with the large volumes of water required to hydraulically fracture horizontal
shale wells using the slick water fracturing technique and the disturbance associated with multiwell sites. An additional aspect of this SGEIS is to consider measures that will be incorporated
into revisions or additions to the Department’s regulations concerning high-volume hydraulic
fracturing.
9

ALL Consulting, 2010, pp. 7 - 9.

Final SGEIS 2015, Page 2-1

 2.1

Purpose

As stated in the 1992 GEIS, a generic environmental impact statement is used to evaluate the
environmental effects of a program having wide application and is required for direct
programmatic actions undertaken by a state agency. The SGEIS will address new activities or
new potential impacts not addressed by the 1992 GEIS and will set forth practices and mitigation
designed to reduce environmental impacts to the maximum extent practicable. The SGEIS and
its findings will be used to satisfy SEQR for the issuance of permits to drill, deepen, plug back or
convert wells for horizontal drilling and high-volume hydraulic fracturing. The SGEIS will also
be used to satisfy SEQR for the enactment of revisions or additions to the Department’s
regulations relating to high-volume hydraulic fracturing.
2.2

Project Location

The 1992 GEIS is applicable to onshore oil and gas well drilling statewide. Sedimentary rock
formations which may someday be developed by horizontal drilling and hydraulic fracturing
exist from the Vermont/Massachusetts border up to the St. Lawrence/Lake Champlain region,
west along Lake Ontario to Lake Erie and across the Southern Tier and Finger Lakes regions.
Drilling will not occur on State-owned lands in the Adirondack and Catskill Forest Preserves
because of the State Constitution’s requirement that Forest Preserve lands be kept forever wild
and not be leased or sold. Drilling will not occur on State reforestation areas and wildlife
management areas that are located in the Forest Preserve because the State Constitution prohibits
those areas from being leased or sold. Surface disturbance associated with high-volume
hydraulic fracturing would not be allowed on State-owned lands administered by DEC outside of
the Forest Preserve, including but not limited to State Forests and State Wildlife Management
Areas, because high-volume hydraulic fracturing would be inconsistent with the purposes for
which those lands were acquired. Current OPRHP policy would impose a similar restriction on
State Parks. In addition, the subsurface geology of the Adirondacks, NYC and Long Island and
other factors render drilling for hydrocarbons in those areas unlikely.
The prospective region for the extraction of natural gas from Marcellus and Utica Shales has
been roughly described as an area extending from Chautauqua County eastward to Greene,
Ulster and Sullivan Counties, and from the Pennsylvania border north to the approximate

Final SGEIS 2015, Page 2-2

 location of the east-west portion of the New York State Thruway between Schenectady and
Auburn. The maps in Chapter 4 depict the prospective area.
2.3

Environmental Setting

Environmental resources discussed in the 1992 GEIS with respect to potential impacts from oil
and gas development include: waterways/water bodies; drinking water supplies; public lands;
coastal areas; wetlands; floodplains; soils; agricultural lands; intensive timber production areas;
significant habitats; areas of historical, architectural, archeological and cultural significance;
clean air and visual resources. 10 Further information is provided below regarding specific
aspects of the environmental setting for Marcellus and Utica Shale development and highvolume hydraulic fracturing that were determined during Scoping to require attention in the
SGEIS.
2.3.1

Water Use Classifications 11

Water use classifications are assigned to surface waters and groundwaters throughout New York.
Surface water and groundwater sources are classified by the best use that is or could be made of
the source. The preservation of these uses is a regulatory requirement in New York.
Classifications of surface waters and groundwaters in New York are identified and assigned in 6
NYCRR Part 701.
In general, the discharge of sewage, industrial waste, or other wastes must not cause impairment
of the best usages of the receiving water as specified by the water classifications at the location
of discharge and at other locations that may be affected by such discharge. In addition, for
higher quality waters, the Department may impose discharge restrictions (described below) in
order to protect public health, or the quality of distinguished value or sensitive waters.
A table of water use classifications, usages and restrictions follows.

10

NYSDEC, 1992, GEIS Chapter 6 provides a broad background of these environmental resources, including the then-existing
legislative protections, other than SEQRA, guarding these resources from potential impacts. Chapters 8, 9, 10, 11, 12, 13, 14
and 15 of the GEIS contain more detailed analyses of the specific environmental impacts of development on these resources,
as well as the mitigation measures required to prevent these impacts.

11

URS, 2009, p. 4-2.

Final SGEIS 2015, Page 2-3

 Table 2.1 - New York Water Use Classifications

Water Use Class

Water Type

Best Usages and
Suitability

Notes

N

Fresh Surface

1, 2

AA-Special

Fresh Surface

3, 4, 5, 6

Note a

A-Special

Fresh Surface

3, 4, 5, 6

Note b

AA

Fresh Surface

3, 4, 5, 6

Note c

A

Fresh Surface

3, 4, 5, 6

Note d

B

Fresh Surface

4, 5, 6

C

Fresh Surface

5, 6, 7

D

Fresh Surface

5, 7, 8

SA

Saline Surface

4, 5, 6, 9

SB

Saline Surface

4, 5, 6,

SC

Saline Surface

5, 6, 7

I

Saline Surface

5, 6, 10

SD

Saline Surface

5, 8

GA

Fresh Groundwater

11

GSA

Saline Groundwater

12

Note e

GSB

Saline Groundwater

13

Note f

Other – T/TS

Fresh Surface

Trout/Trout Spawning

Other – Discharge
Restriction Category

All Types

N/A

See descriptions below

Best Usage/Suitability Categories [Column 3 of Table 2.1 above]
1. Best usage for enjoyment of water in its natural condition and, where compatible, as a
source of water for drinking or culinary purposes, bathing, fishing, fish propagation, and
recreation;
2. Suitable for shellfish and wildlife propagation and survival, and fish survival;
3. Best usage as source of water supply for drinking, culinary or food processing purposes;
4. Best usage for primary and secondary contact recreation;
5. Best usage for fishing;
6. Suitable for fish, shellfish, and wildlife propagation and survival;

Final SGEIS 2015, Page 2-4

 7. Suitable for primary and secondary contact recreation, although other factors may limit
the use for these purposes;
8. Suitable for fish, shellfish, and wildlife survival (not propagation);
9. Best usage for shellfishing for market purposes;
10. Best usage for secondary, but not primary, contact recreation;
11. Best usage for potable water supply;
12. Best usage for source of potable mineral waters, or conversion to fresh potable waters, or
as raw material for the manufacture of sodium chloride or its derivatives or similar
products; and
13. Best usage is as receiving water for disposal of wastes (may not be assigned to any
groundwaters of the State, unless the Commissioner finds that adjacent and tributary
groundwaters and the best usages thereof will not be impaired by such classification).
Notes [Column 4 of Table 2.1 above]
a. These waters shall contain no floating solids, settleable solids, oil, sludge deposits, toxic
wastes, deleterious substances, colored or other wastes or heated liquids attributable to
sewage, industrial wastes or other wastes; there shall be no discharge or disposal of
sewage, industrial wastes or other wastes into these waters; these waters shall contain no
phosphorus and nitrogen in amounts that will result in growths of algae, weeds and
slimes that will impair the waters for their best usages; there shall be no alteration to flow
that will impair the waters for their best usages; there shall be no increase in turbidity that
will cause a substantial visible contrast to natural conditions;
b. This classification may be given to those international boundary waters that, if subjected
to approved treatment, equal to coagulation, sedimentation, filtration and disinfection
with additional treatment, if necessary, to reduce naturally present impurities, meet or
will meet NYSDOH drinking water standards and are or will be considered safe and
satisfactory for drinking water purposes;

Final SGEIS 2015, Page 2-5

 c. This classification may be given to those waters that if subjected to pre-approved
disinfection treatment, with additional treatment if necessary to remove naturally present
impurities, meet or will meet NYSDOH drinking water standards and are or will be
considered safe and satisfactory for drinking water purposes;
d. This classification may be given to those waters that, if subjected to approved treatment
equal to coagulation, sedimentation, filtration and disinfection, with additional treatment
if necessary to reduce naturally present impurities, meet or will meet NYSDOH drinking
water standards and are or will be considered safe and satisfactory for drinking water
purposes;
e. Class GSA waters are saline groundwaters. The best usages of these waters are as a
source of potable mineral waters, or conversion to fresh potable waters, or as raw
material for the manufacture of sodium chloride or its derivatives or similar products; and
f.

Class GSB waters are saline groundwaters that have a chloride concentration in excess of
1,000 milligrams per liter (mg/L) or a total dissolved solids (TDS) concentration in
excess of 2,000 mg/L; this classification shall not be assigned to any groundwaters of the
State, unless the Department finds that adjacent and tributary groundwaters and the best
usages thereof will not be impaired by such classification.

Discharge Restriction Categories [Last Row of Table 2.1 above]
Based on a number of relevant factors and local conditions, per 6 NYCRR §701.20, discharge
restriction categories may be assigned to: (1) waters of particular public health concern; (2)
significant recreational or ecological waters where the quality of the water is critical to
maintaining the value for which the waters are distinguished; and (3) other sensitive waters
where the Department has determined that existing standards are not adequate to maintain water
quality.
1. Per 6 NYCRR §701.22, new discharges may be permitted for waters where discharge
restriction categories are assigned when such discharges result from environmental
remediation projects, from projects correcting environmental or public health

Final SGEIS 2015, Page 2-6

 emergencies, or when such discharges result in a reduction of pollutants for the
designated waters. In all cases, best usages and standards will be maintained;
2. Per 6 NYCRR §701.23, except for storm water discharges, no new discharges shall be
permitted and no increase in any existing discharges shall be permitted; and
3. Per 6 NYCRR §701.24, specified substances shall not be permitted in new discharges,
and no increase in the release of specified substances shall be permitted for any existing
discharges. Storm water discharges are an exception to these restrictions. The substance
will be specified at the time the waters are designated.
2.3.2

Water Quality Standards

Generally speaking, groundwater and surface water classifications and quality standards in New
York are established by the United States Environmental Protection Agency (USEPA) and the
Department. The NYC Department of Environmental Protection (NYCDEP) defers to the New
York State Department of Health (NYSDOH) for water classifications and quality standards.
The most recent NYC Drinking Water Quality Report can be found at
http://www.nyc.gov/html/dep/pdf/wsstate10.pdf. The Susquehanna River Basin Commission
(SRBC) has not established independent classifications and quality standards. However, one of
SRBC’s roles is to recommend modifications to state water quality standards to improve
consistency among the states. The Delaware River Basin Commission (DRBC) has established
independent classifications and water quality standards throughout the Delaware River Basin,
including those portions within New York. The relevant and applicable water quality standards
and classifications include the following:
•

6 NYCRR Part 703, Surface Water and Groundwater Quality Standards and Groundwater
Effluent Limitations; 12

•

USEPA Drinking Water Contaminants; 13

•

18 CFR Part 410, DRBC Administrative Manual Part III Water Quality Regulations; 14

12

http://www.dec.ny.gov/regs/4590.html.

13

http://www.epa.gov/safewater/contaminants/index.html.

Final SGEIS 2015, Page 2-7

 •

10 NYCRR Part 5, Subpart 5-1 Public Water Systems; 15 and

•

NYCDEP Drinking Water Supply and Quality Report. 16

2.3.3

Drinking Water 17

The protection of drinking water sources and supplies is extremely important for the
maintenance of public health, and the protection of this water use type is paramount. Chemical
or biological substances that are inadvertently released into surface water or groundwater sources
that are designated for drinking water use can adversely impact or disqualify such usage if there
are constituents that conflict with applicable standards for drinking water. These standards are
discussed below.
2.3.3.1 Federal
The Safe Drinking Water Act (SDWA), passed in 1974 and amended in 1986 and 1996, gives
USEPA the authority to set drinking water standards. There are two categories of drinking water
standards: primary and secondary. Primary standards are legally enforceable and apply to public
water supply systems. The secondary standards are non-enforceable guidelines that are
recommended as standards for drinking water. Public water supply systems are not required to
comply with secondary standards unless a state chooses to adopt them as enforceable standards.
New York has elected to enforce both as Maximum Contaminant Levels (MCLs) and does not
make the distinction.
The primary standards are designed to protect drinking water quality by limiting the levels of
specific contaminants that can adversely affect public health and are known or anticipated to
occur in drinking water. The determinations of which contaminants to regulate are based on
peer-reviewed science research and an evaluation of the following factors:
•

Occurrence in the environment and in public water supply systems at levels of concern;

14

http://www.state.nj.us/drbc/regs/WQRegs_071608.pdf

15

http://www.health.state.ny.us/environmental/water/drinking/part5/subpart5.htm

16

http://www.nyc.gov/html/dep/html/drinking_water/wsstate.shtml.

17

URS, 2009, pp. 4-5:4-16.

Final SGEIS 2015, Page 2-8

 •

Human exposure and risks of adverse health effects in the general population and
sensitive subpopulations;

•

Analytical methods of detection;

•

Technical feasibility; and

•

Impacts of regulation on water systems, the economy and public health.

After reviewing health effects studies and considering the risk to sensitive subpopulations, EPA
sets a non-enforceable Maximum Contaminant Level Goal (MCLG) for each contaminant as a
public health goal. This is the maximum level of a contaminant in drinking water at which no
known or anticipated adverse effect on the health of persons would occur, and which allows an
adequate margin of safety. MCLGs only consider public health and may not be achievable given
the limits of detection and best available treatment technologies. The SDWA prescribes limits in
terms of MCLs or Treatment Techniques (TTs), which are achievable at a reasonable cost, to
serve as the primary drinking water standards. A contaminant generally is classified as microbial
in nature or as a carcinogenic/non-carcinogenic chemical.
Secondary contaminants may cause cosmetic effects (such as skin or tooth discoloration) or
aesthetic effects (such as taste, odor, or color) in drinking water. The numerical secondary
standards are designed to control these effects to a level desirable to consumers.
Table 2.2 and Table 2.3 list contaminants regulated by federal primary and secondary drinking
water standards.

Final SGEIS 2015, Page 2-9

 Table 2.2 - Primary Drinking Water Standards

Microorganisms

Contaminant
Cryptosporidium
Giardia Lamblia
Heterotrophic plate count
Legionella
Total Coliform (including
fecal coliform and E. coli)
Turbidity
Viruses (enteric)

MCLG
(mg/L)
0
0
n/a
0

MCL or TT
(mg/L)
TT
TT
TT
TT

0

5%

n/a
0

TT
TT

MCLG: Maximum contaminant level goal
MCL: Maximum contaminant level
TT: Treatment technology

Disinfection
Byproducts

Contaminant
Bromate
Chlorite
Haloacetic acids (HAA5)
Total Trihalomethanes
(TTHMs)

Disinfectants

Contaminant
Chloramines (as Cl2)
Chlorine (as Cl2)
Chlorine dioxide (as ClO2)

MCLG
(mg/L)
0
0.8
n/a

MCL or TT
(mg/L)
0.01
1
0.06

n/a

0.08

MRDLG
(mg/L)
4.0
4.0
0.8

MRDL
(mg/L)
4.0
4.0
0.8

MRDL: Maximum Residual Disinfectant Level
MRDLG: Maximum Residual Disinfectant Level Goal
Inorganic
Chemicals

Contaminant
Antimony

CAS
number
07440-36-0

MCLG
(mg/L)
0.006

MCL or TT
(mg/L)
0.006

Arsenic

07440-38-2

0

0.01
as of 01/23/06

Asbestos
(fiber >10 micrometers)

01332-21-5

7 million
fibers per liter

7 MFL

Barium
Beryllium
Cadmium
Chromium (total)

07440-39-3
07440-41-7
07440-43-9
07440-47-3

2
0.004
0.005
0.1

Copper

07440-50-8

1.3

Cyanide (as free cyanide)
Fluoride

00057-12-5
16984-48-8

0.2
4

Final SGEIS 2015, Page 2-10

2
0.004
0.005
0.1
TT;
Action
Level=1.3
0.2
4

 Inorganic
Chemicals

Organic
Chemicals

CAS
number

MCLG
(mg/L)

Lead

07439-92-1

0

Mercury (inorganic)

07439-97-6

0.002

0.002

Nitrate (measured as
Nitrogen)

10

10

Nitrite (measured as
Nitrogen)

1

1

Contaminant

MCL or TT
(mg/L)
TT;
Action
Level=0.015

Selenium
Thallium

07782-49-2
07440-28-0

0.05
0.0005

0.05
0.002

Contaminant
Acrylamide
Alachlor
Atrazine
Benzene
Benzo(a)pyrene (PAHs)
Carbofuran
Carbon tetrachloride
Chlordane
Chlorobenzene

CAS
number
00079-06-1
15972-60-8
01912-24-9
00071-43-2
00050-32-8
01563-66-2
00056-23-5
00057-74-9
00108-907

MCLG
(mg/L)
0
0
0.003
0
0
0.04
0
0
0.1

MCL or TT
(mg/L)
TT
0.002
0.003
0.005
0.0002
0.04
0.005
0.002
0.1

2,4-Dichloro-phenoxyacetic
acid (2,4-D)

00094-75-7

0.07

0.07

Dalapon

00075-99-0

0.2

0.2

1,2-Dibromo-3chloropropane (DBCP)

00096-12-8

0

0.0002

00095-50-1
00106-46-7
00107-06-2
00075-35-4
00156-59-2
00156-60-5
00074-87-3
00078-87-5
00103-23-1
00117-81-7
00088-85-7
01746-01-6

0.6
0.075
0
0.007
0.07
0.1
0
0
0.4
0
0.007
0
0.02
0.1
0.002
0
0.7
0
0.7
0

0.6
0.075
0.005
0.007
0.07
0.1
0.005
0.005
0.4
0.006
0.007
0.00000003
0.02
0.1
0.002
TT
0.7
0.00005
0.7
0.0004

o-Dichlorobenzene
p-Dichlorobenzene
1,2-Dichloroethane
1,1-Dichloroethylene
cis-1,2-Dichloroethylene
trans-1,2-Dichloroethylene
Dichloromethane
1,2-Dichloropropane
Di(2-ethylhexyl) adipate
Di(2-ethylhexyl) phthalate
Dinoseb
Dioxin (2,3,7,8-TCDD)
Diquat
Endothall
Endrin
Epichlorohydrin
Ethylbenzene
Ethylene dibromide
Glyphosate
Heptachlor

00145-73-3
00072-20-8
00100-41-4
00106-93-4
01071-83-6
00076-44-8

Final SGEIS 2015, Page 2-11

 Organic
Chemicals

Contaminant
Heptachlor epoxide
Hexachlorobenzene
Hexachlorocyclopentadiene
Lindane
Methoxychlor
Oxamyl (Vydate)

CAS
number
01024-57-3
00118-74-1
00077-47-4
00058-89-9
00072-43-5
23135-22-0

Polychlorinated biphenyls
(PCBs)
Pentachlorophenol
Picloram
Simazine
Styrene
Tetrachloroethylene
Toluene
Toxaphene
2,4,5-TP (Silvex)
1,2,4-Trichlorobenzene
1,1,1-Trichloroethane
1,1,2-Trichloroethane
Trichloroethylene
Vinyl chloride
Xylenes (total)

Radionuclides

00087-86-5
01918-02-1
00122-34-9
00100-42-5
00127-18-4
00108-88-3
08001-35-2
00093-72-1
00120-82-1
00071-55-6
00079-00-5
00079-01-6
00075-01-4

MCLG
(mg/L)
0
0
0.05
0.0002
0.04
0.2

MCL or TT
(mg/L)
0.0002
0.001
0.05
0.0002
0.04
0.2

0

0.0005

0
0.5
0.004
0.1
0
1
0
0.05
0.07
0.2
0.003
0
0
10

0.001
0.5
0.004
0.1
0.005
1
0.003
0.05
0.07
0.2
0.005
0.005
0.002
10

MCLG
(mg/L)

MCL or TT
(mg/L)

Alpha particles

none
------------zero

15 picocuries per Liter (pCi/L)

Beta particles and photon
emitters

none
------------zero

4 millirems per year

Radium 226 and Radium
228 (combined)

none
------------zero

5 pCi/L

zero

30 ug/L

Contaminant

Uranium

Final SGEIS 2015, Page 2-12

 Table 2.3 - Secondary Drinking Water Standards

CAS
number

Contaminant
Aluminum

07439-90-5

Standard
0.05 to 0.2 mg/L
250 mg/L

Chloride

15 (color units)

Color
Copper

07440-50-8

1.0 mg/L
Non-corrosive

Corrosivity
Fluoride

16984-48-8

2.0 mg/L
0.5 mg/L

Foaming Agents (surfactants)
Iron

07439-89-6

0.3 mg/L

Manganese

07439-96-5

0.05 mg/L
3 threshold odor number

Odor

6.5-8.5

pH
Silver

07440-22-4

0.10 mg/L

Sulfate

14808-79-8

250 mg/L
500 mg/L

Total Dissolved Solids
Zinc

07440-66-6

5 mg/L

New York State is a primacy state and has assumed responsibility for the implementation of the
drinking water protection program.
2.3.3.2 New York State
Authorization to use water for a public drinking water system is subject to Article 15, Title 15 of
the ECL administered by the Department, while the design and operation of a public drinking
water system and quality of drinking water is regulated under the State Sanitary Code 10
NYCRR, Subpart 5-1 administered by NYSDOH. 18
Anyone planning to operate or operating a public water supply system must obtain a Water
Supply Permit from the Department before undertaking any of the regulated activities.
Contact with the Department and submission of a Water Supply Permit application will
automatically involve NYSDOH, which has a regulatory role in water quality and other sanitary
aspects of a project relating to human health. Through the State Sanitary Code (Chapter 1 of 10
NYCRR), NYSDOH oversees the suitability of water for human consumption. Section 5-1.30 of

18

6 NYCRR 601 – http://www.dec.ny.gov/regs/4445.html.

Final SGEIS 2015, Page 2-13

 10 NYCRR 19 prescribes the required minimum treatment for public water systems, which
depends on the source water type and quality. To assure the safety of drinking water in New
York, NYSDOH, in cooperation with its partners, the county health departments, regulates the
operation, design and quality of public water supplies; assures water sources are adequately
protected, and sets standards for constructing individual water supplies.
NYSDOH standards, established in regulations found at Section 5-1.51 of 10 NYCRR and
accompanying Tables in Section 1.52, meet or exceed national drinking water standards. These
standards address national primary standards, secondary standards and other contaminants,
including those not listed in federal standards such as principal organic contaminants with
specific chemical compound classification and unspecified organic contaminants.
2.3.4

Public Water Systems

Public water systems in New York range in size from that of NYC, the largest engineered water
system in the nation, serving more than nine million people, to those run by municipal
governments or privately-owned water supply companies serving municipalities of varying size
and type, schools with their own water supply, and small retail outlets in rural areas serving
customers water from their own wells. Privately owned, residential wells supplying water to
individual households do not require a water supply permit. In total, there are nearly 10,000
public water systems in New York State. A majority of the systems (approximately 8,460) rely
on groundwater aquifers, although a majority of the State’s population is served by surface water
sources. Public water systems include community water systems (CWS) and non-community
water systems (NCWS). NCWSs include non-transient non-community (NTNC) and transient
non-community (TNC) water systems. NYSDOH regulations contain the definitions listed in
Table 2.4.

19

10 NYCRR 5-1.30 – http://www.health.state.ny.us/nysdoh/phforum/nycrr10.htm.

Final SGEIS 2015, Page 2-14

 Table 2.4 - Public Water System Definition 20

Public water system means a community, non-community or non-transient non-community water system
which provides water to the public for human consumption through pipes or other constructed
conveyances, if such system has at least five service connections or regularly serves an average of at least
25 individuals daily at least 60 days out of the year. Such term includes:
a.
b.

collection, treatment, storage and distribution facilities under control of the supplier of water
of such system and used with such system; and
collection or pretreatment storage facilities not under such control which are used with such
system.

Community water system (CWS) means a public water system which serves at least five service
connections used by year-round residents or regularly serves at least 25 year-round residents.
Noncommunity water system (NCWS) means a public water system that is not a community water
system.
Non-transient noncommunity water system (NTNC) means a public water system that is not a
community water system but is a subset of a noncommunity water system that regularly serves at least 25
of the same people, four hours or more per day, for four or more days per week, for 26 or more weeks per
year.
Transient noncommunity water system (TNC) means a noncommunity water system that does not
regularly serve at least 25 of the same people over six months per year.

2.3.4.1 Primary and Principal Aquifers
About one quarter of New Yorkers rely on groundwater as a source of potable water. In order to
enhance regulatory protection in areas where groundwater resources are most productive and
most vulnerable, the NYSDOH, in 1981, identified 18 Primary Water Supply Aquifers (also
referred to simply as Primary Aquifers) across the State. These are defined in the Division of
Water (DOW) Technical and Operational Guidance Series (TOGS) 2.1.3 21 as “highly productive
aquifers presently utilized as sources of water supply by major municipal water supply systems.”
Many Principal Aquifers have also been identified and are defined in the DOW TOGS as “highly
productive, but which are not intensively used as sources of water supply by major municipal
systems at the present time.” Principal Aquifers are those known to be highly productive
aquifers or where the geology suggests abundant potential supply, but are not presently being
heavily used for public water supply. The 21 Primary and the many Principal Aquifers greater
than one square mile in area within New York State (excluding Long Island) are shown on
20

10 NYCRR, Part 5, Subpart 5-1 Public Water Systems (Current as of: October 1, 2007); SUBPART 5-1; PUBLIC WATER
SYSTEMS; 5-1.1 Definitions. (Effective Date: May 26, 2004).

21

http://www.dec.ny.gov/docs/water_pdf/togs213.pdf.

Final SGEIS 2015, Page 2-15

 Number of Wells Within Mapped
Aquifer Boundary
Map No.
Aquifer Name
Other
Gas Wells Oil Wells
Wells*
1
Baldwinsville
37
0
3

2

Batavia
0
0
5

3

Corning
5
0
4

4

Cortland-Homer-Preble
0
0
2

5

Elmira-Horseheads-Big Flats
6
0
16

6

Endicott-Johnson City
0
0
3
7
Fulton
4
0
2

8

Jamestown
82
11
14

9

Lower Cohocton
4
0
24

10

Olean
7
310
81

11

Owego
0
0
2

12

Salamanca
14
2
6

13

Upper Cohocton
0
0
3

14

W averly
0
0
1

Principal Aquifer

1,664
749
1,344
Total
1,823
1,072
1,510

q

Notes:

* - Other wells include storage, solution brine, dry hole, injection, stratigraphic, geothermal, and
not listed well types.

7
1

2

4

13
12

8

0

50

Legend

9
3

10

5

Primary Aquifer

14

11

6

100 Miles

FIGURE 2.1
REGULATED OIL, GAS, & OTHER

WELLS IN PRIMARY AND PRINCIPAL
AQUIFERS IN NEW YORK STATE
Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Source:

- "New York State Aquifers" by NYS Department of Health,
Bureau of Public Water Supply Protection (April 2001) on
http://nysgis.state.ny.us/gis9/nyaquifers.zip.

- Well information from (February 2009)

http://www.dec.ny.gov/energy/1603.html


Map Document: (Z:\projects\2009\09100-09120\09104 - Gas Well Permitting GEIS\Figures\GIS\Aquifers.mxd)
8/11/2009 -- 11:31:56 AM

Final SGEIS 2015, Page 2-16

Principal Aquifer
Greater Than 1 Sq. Mi.
Combined Utica and
Marcellus Shales in
New York State

 Figure 2.1. The remaining portion of the State is underlain by smaller aquifers or low-yielding
groundwater sources that typically are suitable only for small community and non-community
public water systems or individual household supplies. 22
2.3.4.2 Public Water Supply Wells
NYSDOH estimates that over two million New Yorkers outside of Long Island are served by
public groundwater supplies. 23 Most public water systems with groundwater sources pump and
treat groundwater from wells. Public groundwater supply wells are governed by Subpart 5-1 of
the State Sanitary Code under 10 NYCRR. 24
2.3.5

Private Water Wells and Domestic-Supply Springs

There are potentially tens to hundreds of thousands of private water supply wells in the State. To
ensure that private water wells provide adequate quantities of water fit for consumption and
intended uses, they need to be located and constructed to maintain long-term water yield and
reduce the risk of contamination. Improperly constructed water wells can allow for easy transport
of contaminants to the well and pose a significant health risk to users. New, replacement or
renovated private wells are required to be in compliance with the New York State Residential
Code, NYSDOH Appendix 5-B “Standards for Water Wells,” 25 installed by a certified
Department-registered water well contractor and have groundwater as the water source.
However, many private water wells installed before these requirements took effect are still in use.
The 1992 GEIS describes how improperly constructed private water wells are susceptible to
pollution from many sources, and proposes a 150-foot setback to protect vulnerable private
wells. 26
NYSDOH includes springs – along with well points, dug wells and shore wells – as susceptible
sources that are vulnerable to contamination from pathogens, spills and the effects of drought. 27

22

Alpha, 2009, p. 3-2.

23

http://www.health.state.ny.us/environmental/water/drinking/facts_figures.htm.

24

http://www.health.state.ny.us/environmental/water/drinking/part5/subpart5.htm.

25

http://www.health.state.ny.us/environmental/water/drinking/part5/appendix5b.htm.

26

NYSDEC, 1992, GEIS, p. 8-22.

27

http://www.health.state.ny.us/environmental/water/drinking/part5/append5b/fs5_susceptible_water_sources.htm.

Final SGEIS 2015, Page 2-17

 Use of these sources for drinking water is discouraged and should be considered only as a last
resort with proper protective measures. With respect to springs, NYSDOH specifically states:
Springs occur where an aquifer discharges naturally at or near the ground surface,
and are broadly classified as either rock or earth springs. It is often difficult to
determine the true source of a spring (that is, whether it truly has the natural
protection against contamination that a groundwater aquifer typically has.) Even if
the source is a good aquifer, it is difficult to develop a collection device (e.g.,
"spring box") that reliably protects against entry of contaminants under all weather
conditions. (The term "spring box" varies, and, depending on its construction,
would be equivalent to, and treated the same, as either a spring, well point or shore
well.) Increased yield and turbidity during rain events are indications of the source
being under the direct influence of surface water. 28
Because of their vulnerability, and because in addition to their use as drinking water supplies they
also supply water to wetlands, streams and ponds, the 1992 GEIS proposes a 150-foot setback. 29
For oil and gas regulatory purposes, potable fresh water is defined as water containing less than
250 ppm of sodium chloride or 1,000 ppm TDS 30 and salt water is defined as containing more
than 250 ppm sodium chloride or 1,000 ppm TDS. 31 Groundwater from sources below
approximately 850 feet in New York typically is too saline for use as a potable water supply;
however, there are isolated wells deeper than 850 feet that produce potable water and wells less
than 850 feet that produce salt water. A depth of 850 feet to the base of potable water is
commonly used as a practical generalization for the maximum depth of potable water; however, a
variety of conditions affect water quality, and the maximum depth of potable water in an area
should be determined based on the best available data. 32
2.3.6

History of Drilling and Hydraulic Fracturing in Water Supply Areas

A tabulated summary of the regulated oil, gas, and other wells located within the boundaries of
the Primary and Principal Aquifers in the State is provided on Figure 2.1. There are 482 oil and
gas wells located within the boundaries of 14 Primary Aquifers and 2,413 oil and gas wells

28

NYSDOH - http://www.health.ny.gov/environmental/water/drinking/part5/append5b/docs/fs5_susceptible_water_sources.pdf.

29

NYSDEC, 1992, GEIS, p. 8-16.

30

6 NYCRR Part 550.3(ai).

31

6 NYCRR Part 550.3(at).

32

Alpha, 2009, p. 3-3.

Final SGEIS 2015, Page 2-18

 located within the boundaries of Principal Aquifers. Another 1,510 storage, solution brine,
injection, stratigraphic, geothermal, and other deep wells are located within the boundaries of the
mapped aquifers. The remaining regulated oil and gas wells likely penetrate a horizon of potable
freshwater that can be used by residents or communities as a drinking water source. These
freshwater horizons include unconsolidated deposits and bedrock units. 33
Chapter 4, on Geology, includes a generalized cross-section (Figure 4.3) across the Southern Tier
of New York State which illustrates the depth and thickness of rock formations including the
prospective shale formations.
No documented instances of groundwater contamination from previous horizontal drilling or
hydraulic fracturing projects in New York are recorded in the Department’s well files or records
of complaint investigations. No documented incidents of groundwater contamination in public
water supply systems could be recalled by the NYSDOH central office and Rochester district
office (NYSDOH, 2009a; NYSDOH, 2009b). References have been made to some reports of
private well contamination in Chautauqua County in the 1980s that may be attributed to oil and
gas drilling (Chautauqua County Department of Health, 2009; NYSDOH, 2009a; NYSDOH,
2009b; Sierra Club, undated). The reported Chautauqua County incidents, the majority of which
occurred in the 1980s and which pre-date the current casing and cementing practices and fresh
water aquifer supplementary permit conditions, could not be substantiated because pre-drilling
water quality testing was not conducted, improper tests were run which yielded inconclusive
results and/or the incidents of alleged well contamination were not officially confirmed. 34
An operator caused turbidity (February 2007) in nearby water wells when it continued to pump
compressed air for many hours through the drill string in an attempt to free a stuck drill bit at a
well in the Town of Brookfield, Madison County. The compressed air migrated through natural
fractures in the shallow bedrock because the well had not yet been drilled to the permitted surface
casing seat depth. This non-routine incident was reported to the Department and staff were
dispatched to investigate the problem. The Department shut down drilling operations and ordered
the well plugged when it became apparent that continued drilling at the wellsite would cause
33

Alpha, 2009, p. 3-3.

34

Alpha, 2009, p. 3-3.

Final SGEIS 2015, Page 2-19

 turbidity to increase above what had already been experienced. The operator immediately
provided drinking water to the affected residents and subsequently installed water treatment
systems in several residences. Over a period of several months the turbidity abated and water
wells returned to normal. Operators that use standard drilling practices and employ good
oversight in compliance with their permits would not typically cause the excessive turbidity event
seen at the Brookfield wells. The Department has no records of similar turbidity caused by well
drilling as occurred at this Madison County well. Geoffrey Snyder, Director Environmental
Health Madison County Health Department, stated in a May 2009 email correspondence
regarding the Brookfield well accident that, “Overall we find things have pretty much been
resolved and the water quality back to normal if not better than pre-incident conditions.”
2.3.7

Regulated Drainage Basins

New York State is divided into 17 watersheds, or drainage basins, which are the basis for various
management, monitoring, and assessment activities. 35 A watershed is an area of land that drains
into a body of water, such as a river, lake, reservoir, estuary, sea or ocean. The watershed
includes the network of rivers, streams and lakes that convey the water and the land surfaces from
which water runs off into those water bodies. Since all of New York State’s land area is
incorporated into watersheds, all oil and gas drilling that has occurred since 1821 has occurred
within watersheds, specifically, in 13 of the State’s 17 watersheds. Watersheds are separated
from adjacent watersheds by high points, such as mountains, hills and ridges. Groundwater flow
within watersheds may not be controlled by the same topographic features as surface water flow.
The river basins described below are subject to additional jurisdiction by existing regulatory
bodies with respect to certain specific activities related to high-volume hydraulic fracturing.
The delineations of the Susquehanna and Delaware River Basins in New York are shown on
Figure 2.2.

35

See map at http://www.dec.ny.gov/lands/26561.html.

Final SGEIS 2015, Page 2-20

 2.3.7.1 Delaware River Basin
Including Delaware Bay, the Delaware River Basin comprises 13,539 square miles in four states
(New York, Pennsylvania, Delaware and New Jersey). Approximately 18.5 % of the surface area
of the basin, or 2,362 square miles, lies within portions of Broome, Chenango, Delaware,
Schoharie, Greene, Ulster, Sullivan and Orange Counties in New York. This acreage overlaps
with NYC’s West of Hudson Watershed; the Basin supplies about half of NYC’s drinking water
and 100% of Philadelphia’s supply.
The DRBC was established by a compact among the federal government, New York, New Jersey,
Pennsylvania and Delaware to coordinate water resource management activities and the review of
projects affecting water resources in the basin. New York is represented on the DRBC by a
designee of New York State’s Governor, and the Department has the opportunity to provide input
on projects requiring DRBC action.
DRBC has identified its areas of concern with respect to natural gas drilling as reduction of flow
in streams or aquifers, discharge or release of pollutants into ground water or surface water, and
treatment and disposal of hydraulic fracturing fluid. DRBC staff will also review drill site
characteristics, fracturing fluid composition and disposal strategy prior to recommending approval
of shale gas development projects in the Delaware River Basin. 36
2.3.7.2 Susquehanna River Basin
The Susquehanna River Basin comprises 27,510 square miles in three states (New York,
Pennsylvania and Maryland) and drains into the Chesapeake Bay. Approximately 24 % of the
basin, or 6,602 square miles, lies within portions of Allegany, Livingston, Steuben, Yates,
Ontario, Schuyler, Chemung, Tompkins, Tioga, Cortland, Onondaga, Madison, Chenango,
Broome, Delaware, Schoharie, Otsego, Herkimer and Oneida Counties in New York.

36

http://www.state.nj.us/drbc/naturalgas.htm

Final SGEIS 2015, Page 2-21

 q

Legend

Delaware River Basin
Susquehanna River Basin
Utica and Marcellus Shales
in New York State

Oswego
Niagara Falls
Batavia

Utica

Syracuse

Extent of
Marcellus Shale

Cortland

ung

Elmira

R.

S

Endicott

e

qu

ehan na R.
usqu

Oneonta
nna
ha

R.

S us

CorningC
hem

Olean

Ch

Jamestown

r

Binghamton
Hancock

st
We

Br

nc

h

la
De

wa

B
st

h De
r an c

R
re

.

R.

ve

a re

Ri

en

go
an

a

Ithaca

Fredonia

la w

Ea

Buffalo

Extent of
Utica Shale

Rochester

De
ve
l aw are R i

50

r

0

100 Miles

FIGURE 2.2
MAJOR TRIBUTARIES IN THE
SUSQUEHANNA & DELAWARE
RIVER BASINS IN NEW YORK STATE
Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Sources:
- Delaware River Basin Commission Geographic
Information System http://www.state.nj.us/drbc/gis.htm.
- Susquehanna River Basin Commision Map and Data Atlas
http://www.srbc.net/atlas/whatgis.asp

Map Document: (Z:\projects\2009\09100-09120\09104 - Gas Well Permitting GEIS\Figures\GIS\SRB_DRB_Flooding.mxd)
8/17/2009 -- 2:28:41 PM

Final SGEIS 2015, Page 2-22

 The SRBC was established by a compact among the federal government, New York,
Pennsylvania and Maryland to coordinate water resource management activities and review of
projects affecting water resources in the Basin. New York is represented on the SRBC by a
designee of the Department’s Commissioner, and the Department has the opportunity to provide
input on projects requiring SRBC action.
The Susquehanna River is the largest tributary to the Chesapeake Bay, with average annual flow
to the Bay of over 20 billion gallons per day (gpd). Based upon existing consumptive use
approvals plus estimates of other uses below the regulatory threshold requiring approval, SRBC
estimates current maximum use potential in the Basin to be 882.5 million gpd. Projected
maximum consumptive use in the Basin for gas drilling, calculated by SRBC based on twice the
drilling rate in the Barnett Shale play in Texas, is about 28 million gpd as an annual average. 37
2.3.7.3 Great Lakes-St. Lawrence River Basin
In New York, the Great Lakes-St. Lawrence River Basin is the watershed of the Great Lakes and
St. Lawrence River, upstream from Trois Rivieres, Quebec, and includes all or parts of 34
counties, including the Lake Champlain and Finger Lakes sub-watersheds. Approximately 80
percent of New York's fresh surface water, over 700 miles of shoreline, and almost 50% of New
York’s lands are contained in the drainage basins of Lake Ontario, Lake Erie, and the St.
Lawrence River. Jurisdictional authorities in the Great Lakes-St. Lawrence River Basin, in
addition to the Department, include the Great Lakes Commission, the Great Lakes Fishery
Commission, the International Joint Commission, the Great Lakes-St. Lawrence River Water
Resources Compact Council, and the Great Lakes-St. Lawrence Sustainable Water Resources
Regional Body.
2.3.8

Water Resources Replenishment 38

The ability of surface water and groundwater systems to support withdrawals for various
purposes, including natural gas development, is based primarily on replenishment (recharge). The
Northeast region typically receives ample precipitation that replenishes surface water (runoff and
groundwater discharge) and groundwater (infiltration).
37

http://www.srbc.net/programs/projreviewmarcellustier3.htm.

38

Alpha, 2009, p. 3-26.

Final SGEIS 2015, Page 2-23

 The amount of water available to replenish groundwater and surface water depends on several
factors and varies seasonally. A “water balance” is a common, accepted method used to describe
when the conditions allow groundwater and surface water replenishment and to evaluate the
amount of withdrawal that can be sustained. The primary factors included in a water balance are
precipitation, temperature, vegetation, evaporation, transpiration, soil type, and slope.
Groundwater recharge (replenishment) occurs when the amount of precipitation exceeds the
losses due to evapotranspiration (evaporation and transpiration by plants) and water retained by
soil moisture. Typically, losses due to evapotranspiration are large in the growing season and
consequently, less groundwater recharge occurs during this time. Groundwater also is recharged
by losses from streams, lakes, and rivers, either naturally (in influent stream conditions) or
induced by pumping. The amount of groundwater available from a well and the associated
aquifer is typically determined by performing a pumping test to determine the safe yield, which is
the amount of groundwater that can be withdrawn for an extended period without depleting the
aquifer. Non-continuous withdrawal provides opportunities for water resources to recover during
periods of non-pumping.
Surface water replenishment occurs directly from precipitation, from surface runoff, and by
groundwater discharge to surface water bodies. Surface runoff occurs when the amount of
precipitation exceeds infiltration and evapotranspiration rates. Surface water runoff typically is
greater during the non-growing season when there is little or no evapotranspiration, or where soil
permeability is relatively low.
Short-term variations in precipitation may result in droughts and floods which affect the amount
of water available for groundwater and surface water replenishment. Droughts of significant
duration reduce the amount of surface water and groundwater available for withdrawal. Periods
of drought may result in reduced stream flow, lowered lake levels, and reduced groundwater
levels until normal precipitation patterns return.
Floods may occur from short or long periods of above-normal precipitation and rapid snow melt.
Flooding results in increased flow in streams and rivers and may increase levels in lakes and
reservoirs. Periods of above-normal precipitation that may cause flooding also may result in

Final SGEIS 2015, Page 2-24

 increased groundwater levels and greater availability of groundwater. The duration of floods
typically is relatively short compared to periods of drought.
The SRBC and DRBC have established evaluation processes and mitigation measures to ensure
adequate replenishment of water resources. The evaluation processes for proposed withdrawals
address recharge potential and low-flow conditions. Examples of the mitigation measures utilized
by the SRBC include:
•

Replacement – release of storage or use of a temporary source;

•

Discontinue – specific to low-flow periods;

•

Conservation releases;

•

Payments; and

•

Alternatives – proposed by applicant.

Operational conditions and mitigation requirements establish passby criteria and withdrawal
limits during low-flow conditions. A passby flow is a prescribed quantity of flow that must be
allowed to pass an intake when withdrawal is occurring. Passby requirements also specify lowflow conditions during which no water can be withdrawn.
2.3.9

Floodplains

Floodplains are low-lying lands next to rivers and streams. When left in a natural state,
floodplain systems store and dissipate floods without adverse impacts on humans, buildings,
roads or other infrastructure. Floodplains can be viewed as a type of natural infrastructure that
can provide a safety zone between people and the damaging waters of a flood. Changes to the
landscape outside of floodplain boundaries, like urbanization and other increases in the area of
impervious surfaces in a watershed, may increase the size of floodplains. Floodplain information
is found on Flood Insurance Rate Maps (FIRMs) produced by the Federal Emergency
Management Agency (FEMA). These maps are organized on either a county, town, city or

Final SGEIS 2015, Page 2-25

 village basis and are available through the FEMA Map Service Center. 39 They may also be
viewed at local government facilities, the Department, and county and regional planning offices.
A floodplain development permit issued by a local government (town, city or village) must be
obtained before commencing any floodplain development activity. This permit must comply with
a local floodplain development law (often named Flood Damage Prevention Laws), designed to
ensure that development will not incur flood damages or cause additional off-site flood damages.
These local laws, which qualify communities for participation in the National Flood Insurance
Program (NFIP), require that any development in mapped, flood hazard areas be built to certain
standards, identified in the NFIP regulations (44 CFR 60.3) and the Building Code of New York
State and the Residential Code of New York State. Floodplain development is defined to mean
any man-made change to improved or unimproved real estate, including but not limited to
buildings or other structures (including gas and liquid storage tanks), mining, dredging, filling,
paving, excavation or drilling operations, or storage of equipment or materials. Virtually all
communities in New York with identified flood hazard areas participate in the NFIP.
The area that would be inundated by a 100-year flood (also thought of as an area that has a one
percent or greater chance of experiencing a flood in any single year) is designated as a Special
Flood Hazard Area. The 100-year flood is also known as the base flood, and the elevation that
the base flood reaches is known as the base flood elevation (BFE). The BFE is the basic standard
for floodplain development, used to determine the required elevation of the lowest floor of any
new or substantially improved structure. For streams where detailed hydraulic studies have
identified the BFE, the 100-year floodplain has been divided into two zones, the floodway and the
floodway fringe. The floodway is that area that must be kept open to convey flood waters
downstream. The floodway fringe is that area that can be developed in accordance with FEMA
standards as adopted in local law. The floodway is shown either on the community's FIRM or on
a separate “Flood Boundary and Floodway” map or maps published before about 1988. Flood
Damage Prevention Laws differentiate between more hazardous floodways and other areas
inundated by flood water. In particular for floodways, no encroachment can be permitted unless

39

http://msc.fema.gov.

Final SGEIS 2015, Page 2-26

 there is an engineering analysis that proves that the proposed development does not increase the
BFE by any measurable amount at any location.
Each participating community in the State has a designated floodplain administrator. This is
usually the building inspector or code enforcement official. If development is being considered
for a flood hazard area, then the local floodplain administrator reviews the development to ensure
that construction standards have been met before issuing a floodplain development permit.
2.3.9.1 Analysis of Recent Flood Events 40
The Susquehanna and Delaware River Basins in New York are vulnerable to frequent, localized
flash floods every year. These flash floods usually affect the small tributaries and can occur with
little advance warning. Larger floods in some of the main stem reaches of these same river-basins
also have been occurring more frequently. For example, the Delaware River in Delaware and
Sullivan Counties experienced major flooding along the main stem and in its tributaries during
more than one event from September 2004 through June 2006 (Schopp and Firda, 2008).
Significant flooding also occurred along the Susquehanna River during this same time period.
The increased frequency and magnitude of flooding has raised a concern for unconventional gas
drilling in the floodplains of these rivers and tributaries, and the recent flooding has identified
concerns regarding the reliability of the existing FEMA FIRMs that depict areas that are prone to
flooding with a defined probability or recurrence interval. The concern focused on the
Susquehanna and Delaware Rivers and associated tributaries in Steuben, Chemung, Tioga,
Broome, Chenango, Otsego, Delaware and Sullivan Counties, New York.
2.3.9.2 Flood Zone Mapping 41
Flood zones are geographic areas that FEMA has defined according to varying levels of flood
risk. These zones are depicted on a community’s FIRM. Each zone reflects the severity or type
of flooding in the area and the level of detailed analysis used to evaluate the flood zone.

40

Alpha, 2009, p. 3-30.

41

Alpha, 2009, p. 3-30.

Final SGEIS 2015, Page 2-27

 Appendix 1 Alpha’s Table 3.4 – FIRM Maps summarizes the availability of FIRMs for New York
State as of July 23, 2009 (FEMA, 2009a). FIRMs are available for all communities in Broome,
Delaware, and Sullivan Counties. The effective date of each FIRM is included in Appendix 1.
As shown, many of the communities in New York use FIRMs with effective dates prior to the
recent flood events. Natural and anthropogenic changes in stream morphology (e.g.,
channelization) and land use/land cover (e.g., deforestation due to fires or development) can affect
the frequency and extent of flooding. For these reasons, FIRMs are updated periodically to reflect
current information. Updating FIRMs and incorporation of recent flood data can take two to three
years (FEMA, 2009b).
While the FIRMs are legal documents that depict flood-prone areas, the most up-to-date
information on extent of recent flooding is most likely found at local or county-wide planning or
emergency response departments (DRBC, 2009). Many of the areas within the Delaware and
Susquehanna River Basins that were affected by the recent flooding of 2004 and 2006 lie outside
the flood zones noted on the FIRMs (SRBC, 2009; DRBC, 2009; Delaware County 2009). Flood
damage that occurs outside the flood zones often is related to inadequate maintenance or sizing of
storm drain systems and is unrelated to streams. Mapping the areas affected by recent flooding in
the Susquehanna River Basin currently is underway and is scheduled to be published in late 2012
(SRBC, 2011). Updated FIRMs are being prepared for communities in Delaware County affected
by recent flooding and are expected to be released in late 2012 (Delaware County, 2011).
According to the DOW, preliminary county-wide FIRMs have been completed and adopted by
Sullivan County. County-wide FIRMs for Broome and Delaware Counties are scheduled to be
completed in late 2012.
2.3.9.3 Seasonal Analysis 42
The historic and recent flooding events do not show a seasonal trend. Flooding in Delaware
County, which resulted in Presidential declarations of disaster and emergency between 1996 and
2006, occurred during the following months: January 1996, November 1996, July 1998, August
2003, October 2004, August 2004 and April 2005 (Tetra Tech, 2005). The Delaware River and
many of its tributaries in Delaware and Sullivan Counties experienced major flooding that caused
42

Alpha, 2009, p. 3-31.

Final SGEIS 2015, Page 2-28

 extensive damage from September 2004 to June 2006 (Schopp and Firda, 2008). These data show
that flooding is not limited to any particular season and may occur at any time during the year.
2.3.10 Freshwater Wetlands
Freshwater wetlands are lands and submerged lands, commonly called marshes, swamps, sloughs,
bogs, and flats, supporting aquatic or semi-aquatic vegetation. These ecological areas are
valuable resources, necessary for flood control, surface and groundwater protection, wildlife
habitat, open space, and water resources. Freshwater wetlands also provide opportunities for
recreation, education and research, and aesthetic appreciation. Adjacent areas may share some of
these values and, in addition, provide a valuable buffer for the wetlands.
The Department has classified regulated freshwater wetlands according to their respective
functions, values and benefits. Wetlands may be Class I, II, III or IV. Class I wetlands are the
most valuable and are subject to the most stringent standards.
The Freshwater Wetlands Act (FWA), Article 24 of the ECL, provides the Department and the
Adirondack Park Agency (APA) with the authority to regulate freshwater wetlands in the State.
The NYS Legislature passed the Freshwater Wetlands Act in 1975 in response to uncontrolled
losses of wetlands and problems resulting from those losses, such as increased flooding. The
FWA protects wetlands larger than 12.4 acres (5 hectares) in size, and certain smaller wetlands of
unusual local importance. In the Adirondack Park, the APA regulates wetlands, including
wetlands above one acre in size, or smaller wetlands if they have free interchange of flow with
any surface water. The law requires the Department and APA to map those wetlands that are
protected by the FWA. In addition, the law requires the Department and APA to classify
wetlands. Inside the Adirondack Park, wetlands are classified according to their vegetation cover
type. Outside the Park, the Department classifies wetlands according to 6 NYCRR Part 664,
Wetlands Mapping and Classification. 43 Around every regulated wetland is a regulated adjacent
area of 100 feet, which serves as a buffer area for the wetland.
FWA’s main provisions seek to regulate those uses that would have an adverse impact on
wetlands, such as filling or draining. Other activities are specifically exempt from regulation,
43

6 NYCRR 664 - http://www.dec.ny.gov/regs/4612.html.

Final SGEIS 2015, Page 2-29

 such as cutting firewood, continuing ongoing activities, certain agricultural activities, and most
recreational activities like hunting and fishing. In order to obtain an FWA permit, a project must
meet the permit standards in 6 NYCRR Part 663, Freshwater Wetlands Permit Requirement
Regulations. 44 Intended to prevent despoliation and destruction of freshwater wetlands, these
regulations were designed to:
•

preserve, protect, and enhance the present and potential values of wetlands;

•

protect the public health and welfare; and

•

be consistent with the reasonable economic and social development of the State.

2.3.11 Socioeconomic Conditions 45
The Marcellus and Utica Shales are the most prominent shale formations in New York State. The
prospective region for the extraction of natural gas from these formations generally extends from
Chautauqua County eastward to Greene, Ulster, and Sullivan Counties, and from the
Pennsylvania border north to the approximate location of the east-west portion of the New York
State Thruway, between Schenectady and Auburn (Figure 2.3). This region covers all or parts of
30 counties. Fourteen counties are entirely within the area underlain by the Marcellus and Utica
Shales, and 16 counties are partially within the area.
Due to the broad extent of the prospective region for the extraction of natural gas from the
Marcellus and Utica Shales, the socioeconomic analysis in the SGEIS focuses on representative
regional and local areas of New York State where natural gas extraction may occur, and also
provides a statewide analysis. The three regions were selected to evaluate differences between
areas with a high, moderate and low production potential; areas that have experienced gas
development in the past and areas that have not experienced gas development in the past; and
differences in land use patterns. The three representative regions and the respective counties
within the region are:

44

6 NYCRR 663 - http://www.dec.ny.gov/regs/4613.html.

45

Subsection 2.4.11, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011 and was adapted
by the Department.

Final SGEIS 2015, Page 2-30

 ME
Clinton

C A N A D A

Franklin

St.
Lawrence

VT

Essex

Jefferson

Watertown

Nia ga ra
Fa lls
North Tonawanda
Buffa lo

Che ek
towaga
CD P


Wyoming

ie
Er

81
Wayne

Monroe

Yates
390

Chautauqua

Cattaraugus

86

Allegany

Ja me st own

90

Ontario

Livingston

L

Rochester

Genesee

290

Erie

e
ak

Orleans

Niagara

Steuben

Auburn

Seneca

Schuyler

Cayuga

Onondaga

Tompki ns

NY

Uti ca

Chenango

It haca

Saratoga

Fulton

Sarat oga
Spr ings

Schenectady

Schenectady
Troy

Montgomery

Madison

Cortland

N H


Warren

Oneida

Rom e

Syracuse

Hamilton

Washington

Oswego

Herkimer

Lewis

Lake Ontario

Otsego

Albany

Schohari e

Albany

Rensselaer

M A


88

Chemung

Tioga

El mira

B ingham ton

Broome

Greene

Delaware

Columbia
Ulster

587
Dutchess

Sullivan

87

Newburgh

PA


Middletown

Spring Valle y

0

12.5

25

50
Miles

Representative Regions
Region A

Region B

Region C

CDP = Census Designated Place

Place with Year 2010
Population Greater than 25,000

Major Water Bodies
County Boundary
State Boundary

Tribal Lands Boundary

White Plains
Port Chester
New Rochelle

Suffolk

Hempstead
Lindenhurst
Valley
Freeport
Stream Long B each

Figure 2.3: Representative Regions within the
Marcellus Shale Extent in New York

Marcellus Shale Extent
in New York State
Utica Shale Extent in New York State
Extent of Marcellus and Utica Shales in NYS

Westchester

Yonkers
Moun t Vernon
New York

RI

Putnam

Orange
Rockland

NJ

CT

Poughkeepsie

Source: ESRI, 2010; USGS, 2002

Final SGEIS 2015, Page 2-31

 •

Region A: Broome County, Chemung County, and Tioga County (Figure 2.4a);

•

Region B: Delaware County, Otsego County, and Sullivan County (Figure 2.4b); and

•

Region C: Cattaraugus County and Chautauqua County (Figure 2.4c);

Region A is defined as a high-potential production area. Wells in Broome, Chemung, and Tioga
Counties are expected to yield some of the highest production of shale gas, based on the geology,
thermal maturity of the organic matter, and other geochemical factors of the Marcellus and Utica
Shale formations. Due to the proximity to active gas drilling in these counties, and neighboring
counties in Pennsylvania, the associated infrastructure (pipelines) has already been developed.
With the associated infrastructure in place, developers are expected to begin development of wells
in this area if development in New York State is approved. Region A encompasses
urban/suburban land uses associated with the larger cities of Binghamton and Elmira, as well as
rural settings. In addition, conventional natural gas development has occurred in this area.
Region B is defined as an average-potential production area. High-volume hydraulic-fracturing is
expected to occur in portions of Delaware, Otsego, and Sullivan Counties, but the production of
shale gas is not anticipated to reach the levels expected in Region A. Region B is largely rural
and encompasses part of the Catskill Mountains. Development in this region would be limited by
the exclusion of drilling from the New York City watershed and state-owned lands (e.g., the
Forest Preserve) in the Catskill Mountains. To date, only exploratory natural gas well
development has occurred in this region.
Region C is defined as a low-potential production area. Although Chautauqua and Cattaraugus
Counties are within the footprints of both the Utica and Marcellus Shales, they are outside of the
fairways for both shales; thus, horizontal wells in this region would not be expected to yield
enough gas to be economically feasible. However, thousands of vertical gas wells exist in
conventional formations, and additional vertical wells would likely be constructed. If the price of
gas increases or drilling technology advances, gas production in the Utica or other formations in
this region may become more feasible. Region C is largely rural, and conventional natural gas
development has been occurring in this area for many years.

Final SGEIS 2015, Page 2-32

 Ludlowv ille

Schuyler

Newark
Valley

Candor

Spencer

96

Elmi
ra
He igh
t s

iv er
Wes t
E lmira

New York


Otsego

g

Unadill
a

Waverly

17C
282 

235

n a Owego

Endi cott

Chenango
Bridge

88

Johnson
Endwell City
Por t D icki nson

Apalachi n

17

Vestal

434

Vestal
Center

Nichols 

Bi ngha m t on

Conklin
7A

7

Af t on

Delaware

7B

ha n
que e r
Riv

Bainbridge

206

Sidney


41
79

86

Windsor

Deposit 10
17

t
We s w
D e la

17

Ch
Greene

369

Broome

Ti oga

Elmi ra

Wells burg

26

38B

Chemung

Southpor t

81

34

s

R

86

ng

Sout
h
Corn ing


13

Su

352

io u

38

Horse hea ds 

Bi g
F la ts
C h e mu

Whit ney
Po i n t

Berkshi re

224

Van
E tten

Moun
t
Upton


r
ve

r

Riv er side

Corn i ng

96B

go
en a n

ve

Paint e d
Post

Lisl e

79

i
aR

Steuben

Alpine

ar

r

B ra n
c
e Ri v h
e

Pennsylvania

0 

2.5

5

10
Miles

Representative Region A

River/Stream

State Boundary

Secondary Road

County Boundary
Urban Area

51

G ilbert svill e

12

11

Tompkins

Sou t h New
Ber li n

io g

Pi ne
Va lle y

Marat hon

Slat erville

Springs


East
It haca

Sou t h
Hi ll

ill a r
e

8

Oxford

hn

Millport

327

Chenango

221

366

13A

Norwich

41

T

414

415

Ithaca

New
Ber lin

23

Cortland

392

Cayuga He ight s Forest H ome

Burdett

Wa tki
ns
Gl
en
Mont our
Falls
Odessa

Dryden

Lansi ng

227

226

ts e
Riv

Cincinnatus

Freeville

122

14A

228

McGraw

13 

89

14 

Cortland

Munsons

Corners


222

Un
ad
R iv

Dundee

Truma nsburg

Gro t on

Ri

Yates

54

34B

l
er ic

Seneca

O

Lodi

Figure 2.4a: Representative Region A

Highway/Major Road

Source: ESRI, 2010; USGS, 2002

Final SGEIS 2015, Page 2-33

 Oneida

M u n n s v ille
O r is k a n y
M o r r is v ille F a lls

C a z e n o v ia

Wa te r v ille

M a d is o n

Madison

Cla y v ille
C a s s v ille

Herkimer

S a n g e r field
B r id g e w a t e r W e s 20
t

Ric h f ield
S p r in g s


Winfield


H a m ilto n

L e o n a r d s v ille

Smy rn a

nd

H a r twic k

Ne w
B e r lin 

Chenango

O x fo r d 

S o u t h N e w
 M o r r is
B e r lin

Gilb e r t s v ille
M o un t
U p to n

La u re n s

West E nd

Win d s o r

C o n k lin

S c h e n e v u s 

Ri ve

r
Ro x bu r y

el a

D D e lhi
ch

t De La n c ey

W e s te r lo
G r e e n v ille

Delaware

P r a tts v ill e

C a i
r o

Ac ra

Greene
H u n te r

An d es

es

W

Ta n n e r s v ille

P a le n v ill e

Fleis c h m a n n s

M a r g a r e tville

E a s t

B r a n c h


Secondary Road

W e s t

H u r le y


H u r l
e y

Livin g s to n
Man o r

C a llic o o n

are R iver
River/Stream

Highway/Major Road

Ze n a

New York

Ro s co e

J e ffe r s o n v ille

Ulster

Lib e r t y
S o u th
F a lls b u r g

Na rr o w sb u rg

R o s e n d a le
209

Wo od b o u rn e
W o o d r id g e

M o n tic e llo

law
De
Urban Area

Albany

Schoharie

w

ar e

Br a n
iv

State Boundary

Alta m o n t

W o o d s to c k

10
M iles

County Boundary

D e la n s o n

P h o e n icia

Pennsylvania

Representative Region B

20

Ho b ar t

Sullivan

5 

Schenectady

Sta m fo r d

Ha n co c k

2.5

Am s te r d a m

Mid d le b u r g h

D e p o s it

h er
an c
st B r e R
Ea e la w a r
D

0

Ha g am an

S c h o h a r ie

Ric h m o n d v ille

Ot e g o

Wa l to n

Broome

C o b le s k ill

Da ve n p or t

O n e o n ta

Aft o n

86

C a r lisle E s p e r a n c e
C e n tr a l
B r id g e

W o r c e s te r 

88

F r a n k li n
q u eha n n a U n a d illa
S us Rive r
B a in b r i d g e
Si d n e y
Sid n e y
C e n te r

Gr e en e

Sh ar o n
S p r in g s

Otsego

Milfo r d
N o r w ic h

Fo r t J oh n s o n
F u lto n v ille
Tr ib e s
90
H ill

Montgomery

C o o p e r s to w n

E d me st on

Sh er b u rn e

Am es

Ch e rr y
Va lle y

S c h u y le r
La k e

E a r lville
S o u th
Ot s e lic 

Fo n d a
F o r t N e llisto n
Plai n
5
P a latin e
B r id g e C a n a jo h a r ie

C e d a r v ille 

Tills o n

Ke rh o n ks o n

Ne w
P a ltz

Na p an o ch
Elle n v ille

44
Pin e
Bu s h

Clinto n d a le

Wa llkill

87
Wu rt s b or o
Wa ld e n
B lo o m in g b u r g
M o n t g o m e r y O rGaanrgden e r t o w n
Eld r e d
L a k e B a lm v ill e
Wa s h i n g to n
84
Ne w bu r g h
S c o tc h t o w n
B a r r y v ill e
s
H
e
ig
h
t
Ot is v ill e
W in d s o r
M a y b r oNVa
oekw
ils G a te
 Fi
rt h clif fe
Orange
P o n d E dd y
M id d l eto w n
S a li s b u r y M ill s
9W C ornwall-on
E a s t Mid d l et o w n
Wa
s h in g to n v ill e
Go s h en
6 C h e s te r
209P o r t J e r v is

Figure 2.4b: Representative Region B
Source: NESRI, 2010; USGS, 2002

Final SGEIS 2015, Page 2-34

 Ed en

A n g o la o n th e L a k e
A n g o la
L a k e E r ie
Be ac h
Fa r nh a m

L A K E 
ERIE

Silv e r
Cr ee k
5

D u n k ir k

No r th
C o lli n s

C o ld e n

H o lla n d

Wyoming

438

S p r in g v ille

Yo r k s h ir e

P e r r y s b u r g 

90

Ca ss ad a g a

83

Riple y

L a ke 
C h a u ta u q u a

76

La k ew o o d
Pan a ma

Ellic o tt ville

Ellin g t o n
Cu b a

241 

R a n d o lp h

474

F r a n k lin v ille

242

Lit tle
Va lle y

Be mu s
P o int

430

Sh er ma n

C a tta r a u g u s

Sin c lair v ille

M a y v ille

243

16
353

Ch e rr y
Cr ee k

Chautauqua

98

219

62

394

39

M a c h ia s

South
Da yto n

C e lo r o n

F a lc o n e r

J a m e s to w n

Eas t

394 R a n d o lp h

Cattaraugus

S a la m a n c a

86

y
A lle g h e n
R ive r

Fr e ws b u rg

New York


Alle g a n y

Sai n t
Bo n av e n tu re
Lim e s to n e 

W e s to n

Ol e a n Mills

P o r tville

305

Allegany

417

Pennsylvania
0 

2.5

5

10
Miles

Representative Region C

River/Stream


County Boundary

Highway/Major Road


Urban Area


Tribal Lands Boundary

State Boundary

Blis s

C e n te r v ille

Lim e
La k e

B r o c to n
60

Ar ca d e

D e le v a n

Go w a n d a

39

20W e s tfield

78

Erie

75

F o r e s tville

F r e d o n ia

No r th
Bo s to n

20

Figure 2.4c: Representative Region C

Secondary Road


Source: NESRI, 2010; USGS, 2002

Final SGEIS 2015, Page 2-35

 While these regions are being analyzed as a way to assess the impacts on representative local
communities, actual development would not be limited to these regions, and impacts similar to
those described in Section 6 could occur anywhere where high-volume hydraulic-fracturing wells
are developed. Therefore, this section also provides the socioeconomic baseline for the state as a
whole.
A description of the baseline socioeconomic conditions includes Economy, Employment and
Income (Subsection 2.3.11.1); Population (Subsection 2.3.11.2); Housing (Subsection 2.3.11.3);
Government Revenues and Expenditures (Subsection 2.3.11.4); and Environmental Justice (EJ)
(Subsection 2.3.11.5). Socioeconomic impacts are discussed in Chapter 6, and socioeconomic
mitigation measures are discussed in Chapter 7.
2.3.11.1

Economy, Employment, and Income

This subsection provides a discussion of the economy, employment and income for New York
State, and the local areas within each of the three representative regions (Region A, B and C),
focusing on the agricultural and tourism industries, as well as existing natural gas development.
Natural gas development is expected to benefit other industries as equipment, material, and
supplies are purchased by the natural gas industry and workers spend their wages in the local
economy. These positive impacts are discussed in more detail in Section 6. However, as
agriculture and tourism relate to uses of the land that may be impacted by natural gas
development, those industries are discussed in more detail herein, and potential impacts from both
a land use and economic perspective are discussed in Chapter 6.
Several data sources were used to describe the baseline economy, employment, and income for
New York State and the local areas, including the U.S. Census Bureau (USCB) and the New York
State Department of Labor (NYSDOL). Data from the 2010 Census of Population and Housing
were used to identify major employment sectors for the state and the representative regions. Data
from the census is self-reported by individuals and is aggregated to provide general information
about the labor force from very small to large geographic areas on a cross-sectional or one-time
basis.

Final SGEIS 2015, Page 2-36

 Detailed data on employment and wages, by industry, was obtained from the NYSDOL’s
quarterly census of employment and wages (QCEW). The NYSDOL collects employment and
wage data for all employers liable for unemployment insurance. These data were used to provide
information on wages and for more detailed information on employment in the travel and tourism
and oil and gas sectors. All of the labor statistics from the NYSDOL and USCB are based on the
North American Industry Classification System, which is the standard system used by
government agencies to classify businesses, although the data may be grouped differently for
reporting purposes. Data on agricultural workers is taken from the U.S. Census of Agriculture,
which is collected every 5 years, and provides information on the value of farm production and
agricultural employment in the state and local areas. Although the data referenced within this
section were collected by government agencies using different methodologies, all data were used
to support an overall portrait of the statewide and local economies.
New York State
Table 2.5 presents total employment by industry within New York State. As shown, New York
State has a large and diverse economy. The largest employment sector in the state is educational,
health, and social services, accounting for approximately 26.2% of the total employed labor force
(USCB 2009a). Other large sectors are professional, scientific, management, administrative, and
waste management services (10.8%); and retail trade (10.5%). Several of the largest private
employers in New York State include NY Presbyterian Healthcare System (29,000 employees);
Walmart (28,000 employees); Citigroup (27,000 employees); IBM Corporation (21,000
employees); and JP Morgan Chase (21,000 employees).

Final SGEIS 2015, Page 2-37

 Table 2.5 - New York State: Area Employment by Industry, 2009 (New August 2011)

Sector
Agriculture, forestry, fishing, hunting, and mining
Construction
Manufacturing
Wholesale trade
Retail trade
Transportation and warehousing, utilities
Information
Finance, insurance, real estate, and renting/leasing
Professional, scientific, management, administrative, and waste
management services
Educational, health, and social services
Arts, entertainment, recreation, accommodation, and food services
Other services (except public administration)
Public administration
Total

Number of
Jobs
54,900
548,018
672,481
266,946
959,414
482,768
299,378
789,372
981,317

% of
Total
0.6
6.0
7.4
2.9
10.5
5.3
3.3
8.7
10.8

2,385,864
764,553
449,940
447,645
9,102,596

26.2
8.4
4.9
4.9

Source: USCB 2009a.

In 2010, New York State had a total gross domestic product (GDP, i.e., the value of the output of
goods and services produced by labor and property located in New York State) of approximately
$1.16 trillion (USDOC 2010).
Each region of the state contributes to the state’s GDP in different ways. New York City is the
leading center of banking, finance, and communications in the United States, and thus has a large
number of workers employed in these industrial sectors. In contrast, the economies of large
portions of western and central New York are based on agriculture. Manufacturing also plays a
significant role in the overall economy of New York State; most manufacturing occurs in the
upstate regions, predominantly in the cities of Albany, Buffalo, Rochester, and Syracuse.
Table 2.6 provides total and average wages, by industry, as reported by NYSDOL for 2009.

Final SGEIS 2015, Page 2-38

 Table 2.6 - New York State: Wages by Industry, 2009 (New August 2011)

Industry
Total, all industries
Agriculture, forestry, fishing, hunting
Mining
Construction
Manufacturing
Wholesale trade
Retail trade
Transportation and warehousing
Utilities
Information
Finance and insurance
Real estate and renting/leasing
Professional and technical services
Management of companies and enterprises
Administrative and waste services
Educational services
Health, and social assistance
Arts, entertainment, and recreation
Accommodation, and food services
Other services (except public administration)
Public administration

Total Wages ($ millions)
$481,690.6
640.4
265.5
19,336.0
27,098.4
22,797.7
25,130.8
9,302.9
3,633.7
22,124.3
86,303.4
9,360.2
48,815.9
15,648.4
16,354.4
13,606.9
55,486.7
6,154.3
12,178.7
10,732.4
75,828.4

Average Wage
$57,794
$28,275
$55,819
$59,834
$57,144
$69,282
$29,202
$42,477
$92,469
$87,970
$173,899
$52,417
$87,136
$119,804
$40,546
$46,772
$44,104
$44,246
$21,369
$33,602
$52,594

Source: NYSDOL 2009a.

The total labor force in New York State in 2010 was approximately 9,630,900 workers. In 2010,
the annual average unemployment rate across New York State was 8.6% (Table 2.7). Between
2000 and 2010, the size of the labor force increased by 5.1%, while the unemployment rate nearly
doubled.
Table 2.7 - New York State: Labor Force Statistics, 2000 and 2010 (New August 2011)

Total labor force
Employed workers
Unemployed workers
Unemployment rate (%)

2000
9,167,000
8,751,400
415,500
4.5

Source: NYSDOL 2010a.

Final SGEIS 2015, Page 2-39

2010
9,630,900
8,806,800
824,100
8.6

 In 2009, the per capita income for New York State was $30,634, and 13.9% of the population
lived below the poverty level (Table 2.8). Over the past decade, per capita income has increased
by 31.0%, and the percentage of individuals living below the poverty level has decreased by
0.7%.
Table 2.8 - New York State: Income Statistics, 1999 and 2009 (New August 2011)

1999
$23,389
14.6

Per capita income
% Below the poverty level1

2009
$30,634
13.9

Source: USCB 2000a, 2009b.
1
If the total income for an individual falls below relevant poverty thresholds, updated annually relative to the Consumer
Price Index for All Urban Consumers, then the individual is classified as being "below the poverty level."

The Empire State Development Corporation has identified 16 industry clusters for New York
State. Industry clusters define a set of interdependent and connected companies and businesses
that help to support a local economy, such as automobile manufacturing in Detroit, Michigan, and
information technology in the Silicon Valley of California. Industry clusters for the state include:
back office and outsourcing; biomedical; communications, software, and media services;
distribution; electronics and imaging; fashion, apparel, and textiles; financial services; food
processing; forest products; front office and producer services; industrial machinery and services;
information technology services; materials processing; miscellaneous manufacturing;
transportation equipment; and travel and tourism.
Travel and tourism is a large industry in New York State, ranking third in employment of the 16
industry clusters in the state. New York State has many notable attractions, including natural
areas (Niagara Falls, the Finger Lakes, and the Adirondack, Catskill, and Allegany Mountains);
cultural attractions (museums, arts, theater), and historic sites, many of which are described in
Section 2.3.12, Visual Resources. The travel and tourism sector draws from several industries, as
shown in Table 2.9 and Table 2.10. Approximately 351,130 persons were employed in the travel
and tourism sector in New York State in 2009, including food service (96,990 jobs); culture,
recreation, and amusements (84,550 jobs); accommodations (81,780 jobs); passenger
transportation (73,180 jobs); and travel retail (14,630) (see Table 2.9). In 2009, wages earned by
persons employed in the travel and tourism sector was approximately $12.9 billion dollars, or
approximately 2.7% of all wages earned in New York State (NYSDOL 2009b) (see Table 2.10).

Final SGEIS 2015, Page 2-40

 In 2009, visitors to New York State spent approximately $4.5 billion in the state (Tourism
Economics 2010).
Table 2.9 - New York State: Employment in Travel and Tourism, 2009 (New August 2011)

Industry Group
Accommodations
Culture, recreation and amusements
Food service
Passenger transportation
Travel retail
Total

Number of Jobs
81,780
84,550
96,990
73,180
14,630
351,130

% of Total
23.3%
24.1%
27.6%
20.8%
4.2%
100%

Source: NYSDOL 2009b.
Table 2.10 - New York State: Wages in Travel and Tourism, 2009 (New August 2011)

Accommodations
Culture, recreation and amusements
Food service
Passenger transportation
Travel retail
Total

Total Wages ($ millions)
$2,928.3
$4,355.5
$1,840.9
$3,478.4
$324.1
$12,927.3

Average Wage
$35,800
$51,500
$18,980
$47,532
$22,153
$36,800

Source: NYSDOL 2009b.

Agriculture is also an important industry for New York State. Table 2.11 provides agricultural
statistics for New York State. Approximately 36,352 farms are located in New York State,
encompassing 7.2 million acres of land, or 23% of the total land area of the state.
The value of agricultural production in 2009 was $4.4 billion dollars. New York State is a
leading producer of milk, fruits (apples, grapes, cherries, pears), and fresh vegetables (sweet corn,
onions, and cabbage). Most of the state’s field crops (corn, soybeans, and wheat) support its dairy
industry (USDA 2007).
Most counties in New York State have placed agricultural land in state-certified agricultural
districts, which are managed by the New York State Department of Agriculture and Markets.
Farmlands within agricultural districts are provided legal protection, and farmers benefit from
preferential real property tax assessment and protection from restrictive local laws, governmentfunded acquisition or construction projects, and private nuisance suits involving agricultural

Final SGEIS 2015, Page 2-41

 practices. Article 25-AA of Agriculture and Markets Law authorizes the creation of local
agricultural districts pursuant to landowner initiative, preliminary county review, state
certification, and county adoption.
The acreage of land in agricultural districts in New York State is provided on Table 2.11.
Table 2.11 - New York State: Agricultural Data, 2007 (New August 2011)

Number of farms
Land in farms
Average size of farm
Market value of products sold
Principal operator by primary occupation
Farming
Other
Hired farm labor
Land in state-designated agricultural districts

36,352
7,174,743 acres
197 acres
$4,418.6 million
19,624
16,728
59,683
8,873,157 acres

Source: USDA 2007; NYSDAM 2011.

The oil and gas extraction industry is a relatively small part of the economy of New York State.
According to data provided by the U.S. Department of Commerce (USDOC), Bureau of
Economic Analysis (BEA), the oil and gas extraction industry accounted for only 0.004% of New
York State’s GDP in 2009. For comparison purposes, at the national level, the oil and gas
extraction industry’s 2009 share of the U.S. GDP was 1.01% (USDOC 2010). Consequently, the
oil and gas extraction industry is currently of less relative economic importance in New York
State than it is at the national level.
The natural gas extraction industry is linked to other industries in New York State through its
purchases of their output of goods and services. As a natural gas extraction company increases
the number of wells it drills, it needs additional supplies and materials (e.g., concrete) from other
industries to complete the wells. The other industries, in turn, need additional goods and services
from their suppliers to meet the additional demand. The interrelations between various industries
are known as linkages in the economy.
To provide a sense of the direction and magnitude of the linkages for the oil and gas extraction
industry, Table 2.12 shows the impact of a $1 million increase in the final demand in the oil and
gas extraction industry on the value of the output of other industries in New York State. The data

Final SGEIS 2015, Page 2-42

 used to construct the table were drawn from the estimates contained in the BEA’s Regional InputOutput Modeling System II (RIMS II). In constructing the table, the initial $1 million increase in
the final demand for the output of the oil and gas extraction industry was deducted from the
change in its output value to leave just the increase in its output value caused by its purchases of
goods and services from other companies in the mining industry, of which it forms a part.
Table 2.12 - New York: Impact of a $1 Million Dollar Increase in the Final Demand in the Output of the Oil and
Gas Extraction Industry on the Value of the Output of Other Industries (New August 2011)

Industry
Real estate and rental and leasing
Professional, scientific, and technical services
Management of companies and enterprises
Construction
Manufacturing
Finance and insurance
Utilities
Wholesale trade
Information
Administrative and waste management services
Transportation and warehousing
Retail trade
Other services
Arts, entertainment, and recreation
Mining
Food services and drinking places
Accommodation
Health care and social assistance
Educational services

Change in the Value
of Output
$47,100
$30,500
$27,600
$24,300
$21,000
$15,700
$12,300
$10,800
$7,700
$5,900
$3,900
$3,100
$2,600
$1,600
$1,500
$700
$600
$300
$200

Source: US Bureau of Economic Analysis 2011.

As shown in the table above, the oil and gas extraction industry is linked through its purchases of
inputs to 18 other major industries (out of a total of 20 industries used by the Regional InputOutput Modeling System II). The largest linkages are to real estate and rental and leasing;
professional, scientific, and technical services; management of companies and enterprises; and
construction. In total, a $1 million increase in the final demand for the output of the mining
industry is estimated to lead to an increase of an additional $217,400 in final output across all
industries.

Final SGEIS 2015, Page 2-43

 The oil and gas extraction industry accounts for a very small proportion of total employment in
New York State. According to the NYSDOL, the oil and gas extraction industry employed 362
people in the state (i.e., less than 0.01% of the state’s total employment) (NYSDOL 2009a).
Although the number of people employed in the oil and gas extraction industry in New York State
is relatively small, the industry has experienced sustained growth in employment during the last
few years. Employment in the oil and gas extraction industry in New York State between 2000
and 2010 is shown on Table 2.13. As shown, employment in the industry more than doubled
from 2003 to 2010, with the addition of 252 employees during that period.
Table 2.13 - New York State: Employment in the Oil and Gas Extraction Industry, 2000-2010 (New August 2011)

Year
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010

Employment
165
188
193
196
137
163
236
281
341
362
448

Source: NYSDOL 2000 -2008, 2009a, 2010b.
Note: 2010 data are provisional.

A general indication of the types of jobs held by those working in the natural gas extraction
industry is provided by looking at the occupational distribution of employment within the oil and
gas extraction industry at the national level. Table 2.14 presents employment data on the 20
occupations that accounted for the largest shares of employment in the oil and gas extraction
industry at the national level in 2008 (BLS 2011).

Final SGEIS 2015, Page 2-44

 Table 2.14 - Most Common Occupations in the U.S. Oil and Gas Extraction Industry, 2008 (New August 2011)

Occupation
Roustabouts, oil and gas
Petroleum pump system operators, refinery operators, and gaugers
Petroleum engineers
Wellhead pumpers
Accountants and auditors
General and operations managers
Geoscientists, except hydrologists and geographers
Geological and petroleum technicians
Office clerks, general
Bookkeeping, accounting, and auditing clerks
Executive secretaries and administrative assistants
Secretaries, except legal, medical, and executive
Service unit operators, oil, gas, and mining
First-line supervisors/managers of construction trades and extraction
workers
All other engineers
Business operation specialists, all others
Financial analysts
Maintenance and repair workers, general
Real estate sales agents
Rotary drill operators, oil and gas

% of Industry
Employment
7.45
6.07
5.43
5.41
4.88
4.18
3.88
3.27
3.03
2.93
2.77
2.49
2.50
2.27
1.74
1.72
1.56
1.43
1.35
1.33

Source: BLS 2011.

The oil and gas extraction industry is a relatively high-wage industry. In 2009, the average
annual wage paid to employees in the industry was $83,606, which is almost 45% above the
average annual wages of $57,794 paid to employees across all industries in the state (NYSDOL
2009a). However, national data show that workers in the mining, quarrying, and oil and gas
extraction industry have the longest work week among all of the nonagricultural industries. The
average work week for all workers aged over 16 in the nonagricultural industries was 38.1 hours
long, while the average work week for those in the mining, quarrying, and oil and gas extraction
industry was 49.4 hours long (i.e., an almost 30% longer average work week) (BLS 2010).

Final SGEIS 2015, Page 2-45

 Table 2.15 presents total and average wages for the oil and gas industry and all industries in New
York State. The oil and gas industry was a marginal contributor to total wages in New York
State, accounting for $30 million in 2009, or less than 1/100th of a percentage point of total wages
across all industries (NYSDOL 2009a).
Table 2.15 - New York State: Wages in the Oil and Gas Industry, 2009 (New August 2011)

Oil and gas industry
Total, all industries

Total Wages
($ million)
$30.3
$481,690.6

Average
Wage
$83,606
$57,794

Source: NYSDOL 2009a.

Compared to other parts of the country, New York State currently is a relatively minor natural gas
producer. Based on data on natural gas gross withdrawals and production published by the
Energy Information Administration (EIA), New York State accounted for 0.2% of the United
States’ total marketed natural gas production in 2009. During the same period, New York ranked
23rd out of 34 gas-producing areas in the U.S., which included states and the federal Offshore
Gulf of Mexico (EIA 2011).
New York State is, however, a major natural gas consumer. Based on data on natural gas
consumption by end-use published by the EIA, New York State accounted for 5% of the United
States’ total consumption of natural gas in 2009. During the same period, New York State was
ranked as the 4th largest natural gas consumer among the nation’s states (EIA 2011).
By combining the EIA’s data on the total consumption and marketed production of natural gas in
2009, there was a difference of approximately 1.1 Tcf between New York State’s total
consumption and marketed production of natural gas. In 2009, New York State’s marketed
production was equal to 3.9% of its total consumption.

Final SGEIS 2015, Page 2-46

 Table 2.16 shows natural gas production in New York State between 1985 and 2009.
Table 2.16 - New York State: Natural Gas Production, 1985-2009 (New August 2011)

Year
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009

Natural Gas Production
(Bcf)
33.1
34.8
29.5
28.1
25.7
25.1
23.4
23.6
22.1
20.5
18.7
18.3
16.2
16.7
16.1
17.7
28.0
36.8
36.0
46.9
55.2
55.3
54.9
50.3
44.9

Source: NYSDEC 1994-2009.

As shown in the table, natural gas production in New York State generally declined between 1986
and 1999, increased steeply until 2005, and then declined toward the end of that decade.
Other indicators of the level of activity in the natural gas extraction industry in New York State
are the number of well permits granted, the number of wells completed, and the number of active
wells in each year. Table 2.17 shows the number of permits granted for gas wells, the number of
gas wells completed, and the number of active gas wells in New York State between 1994 and
2009.

Final SGEIS 2015, Page 2-47

 Table 2.17 - Permits Issued, Wells Completed, and Active Wells, NYS Gas Wells, 1994-2009 (New August 2011)

Year
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009

Permits
for Gas
Wells
58
38
45
53
68
74
78
127
97
81
133
180
353
386
429
246

Gas Wells
Completed
97
31
31
22
41
28
112
103
43
31
70
104
191
271
270
134

Active
Gas Wells
6,019
6,216
5,869
5,741
5,903
5,756
5,775
5,949
5,773
5,906
6,076
5,957
6,213
6,683
6,675
6,628

Source: NYSDEC 1994-2009.

As with natural gas production, well permits and completions experienced a considerable increase
in the 2000s compared to the 1990s, before declining in the late 2000s. This trend most likely
reflects the discovery and development of commercial natural gas reserves in the Black River
formation in the southern Finger Lakes area along with the impact of higher natural gas prices in
the 2000s compared to the 1990s (see Table 2.18). As shown in Table 2.17, active natural gas
wells reached a low point in 1997 when only 5,741 wells were active. By 2007, this figure had
reached a peak of 6,683 wells.
The level of activity in the natural gas extraction industry is related to the price of natural gas.
Table 2.18 shows the average wellhead price for New York State’s natural gas for the years 1994
to 2009 inclusive.

Final SGEIS 2015, Page 2-48

 Table 2.18 - Average Wellhead Price for New York State’s Natural Gas, 1994-2009 (New August 2011)

Year
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009

Price per Mcf
$2.35
$2.30
$2.21
$2.56
$2.46
$2.19
$3.75
$4.85
$3.03
$5.78
$6.98
$7.78
$7.13
$8.85
$8.94
$4.25

Source: NYSDEC 1994-2009.

As shown in the table, the average wellhead price for natural gas remained at relatively low levels
in the 1990s, generally increased thereafter, reaching a peak in 2008, and then fell sharply in 2009.
Table 2.19 shows the market value of New York State’s natural gas production, which is the price
multiplied by the total production.
Table 2.19 - Market Value of New York State’s Natural Gas Production, 1994-2009 (New August 2011)

Year
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009

Millions of Dollars
$48.1
$43.0
$40.6
$41.5
$41.1
$34.7
$66.4
$135.5
$111.7
$207.4
$327.7
$429.5
$394.6
$486.0
$450.0
$188.8

Source: NYSDEC 1994-2009.

Final SGEIS 2015, Page 2-49

 The combination of generally rising natural gas production and increasing average wellhead
prices for much of the 2000s resulted in a substantial increase in the market value of New York
State’s natural gas production in the 2000s compared to the 1990s. The peak value of $486
million in 2007 was approximately 12 times larger than the average value for the years 1994 to
1999 inclusive (i.e., $41.51 million). However, between 2008 and 2009 the combination of a
10.7% decline in natural gas production and a 52.5% decline in the average wellhead price of
natural gas resulted in a 58% decline in the market value of New York State’s natural gas
production.
Region A
Table 2.20 presents employment, by industry, within Tioga, Broome, and Chemung Counties, and
for Region A. The largest employment sector in Region A is the educational, health, and social
services sector, with approximately 28.7% of total employment in Region A (USCB 2009a).
Manufacturing was the next largest employment sector, accounting for approximately 14.6% of
total employment within the region. The economic center for Broome and Tioga Counties is the
tri-city area of Binghamton, Endicott, and Johnson City, within the Binghamton Metropolitan
Statistical Area (MSA). For Chemung County, the economic center is the city of Elmira.
Table 2.20 - Region A: Area Employment by Industry, 2009 (New August 2011)

Sector
Agriculture, forestry, fishing,
hunting, and mining
Construction
Manufacturing
Wholesale trade
Retail trade
Transportation and warehousing,
utilities
Information
Finance, insurance, real estate, and
renting/leasing
Professional, scientific,
management, administrative, and
waste management services
Educational, health, and social
services

Region A
Number % of
of Jobs Total
1,464
1.0

Broome
Chemung
County
County
Tioga County
Number % of Number % of Number % of
of Jobs Total of Jobs Total of Jobs Total
558
0.6
335
0.9
571
2.3

8,572
22,522
4,749
18,358
5,808

5.6
14.6
3.1
11.9
3.8

4,846
11,957
3,123
10,721
3,840

5.3
13.1
3.4
11.8
4.2

2,054
6,030
959
4,599
1,228

5.4
15.8
2.5
12.1
3.2

1,672
4,535
667
3,038
740

6.8
18.5
2.7
12.4
3.0

3,096
7,554

2.0
4.9

2,016
5,022

2.2
5.5

706
1,719

1.9
4.5

374
813

1.5
3.3

11,847

7.7

7,140

7.8

2,575

6.8

2,132

8.7

44,084

28.7

26,764

29.3

10,869

28.5

6,451

26.4

Final SGEIS 2015, Page 2-50

 Region A
Number % of
of Jobs Total
11,723
7.6

Sector
Arts, entertainment, recreation,
accommodation, and food services
Other services (except public
6,620
administration)
Public administration
7,435
Total 153,832

Broome
Chemung
County
County
Tioga County
Number % of Number % of Number % of
of Jobs Total of Jobs Total of Jobs Total
7,198
7.9
2,928 7.7
1,597
6.5

4.3

3,898

4.3

1,786

4.7

936

3.8

4.8

4,154
91,237

4.6

2,348
38,136

6.2

933
24,459

3.8

Source: USCB 2009a.

Table 2.21 presents total and average wages across all industries for Region A. The average
wages for persons employed across all industries in Region A was $37,875 in 2009.
Table 2.21 - Region A: Wages by Industry, 2009 (New August 2011)

2009
Total Wages
Average
($ millions)
Wages
Region A
Total, all industries
Broome County
Total, all industries
Chemung County
Total, all industries
Tioga County
Total, all industries

$5,435.03

$37,875

$3,390.12

$36,802

$1,379.61

$36,979

$665.30

$47,268

Source: NYSDOL 2009a, 2010b.

The total labor force for Region A is approximately 162,000 workers, of which 60% are in
Broome County, 25% are in Chemung County, and 15% are in Tioga County. The annual
average unemployment rate in Region A in 2010 was consistent with the overall state average
unemployment rate of approximately 8.6% (Table 2.22). The rate of unemployment was slightly
higher in Broome County than in Chemung or Tioga Counties. Overall, the size of the labor force
has declined between 2000 and 2010 across the region, while the unemployment rate has
generally doubled.

Final SGEIS 2015, Page 2-51

 Table 2.22 - Region A: Labor Force Statistics, 2000 and 2010 (New August 2011)

Region A
Total labor force
Employed workers
Unemployed workers
Unemployment rate (%)
Broome County
Total labor force
Employed workers
Unemployed workers
Unemployment rate (%)
Chemung County
Total labor force
Employed workers
Unemployed workers
Unemployment rate (%)
Tioga County
Total labor force
Employed workers
Unemployed workers
Unemployment rate (%)

2000

2010

167,700
161,400
6,300
3.8

162,000
148,000
14,000
8.6

98,300
94,800
3,600
3.6

95,700
87,200
8,500
8.9

42,800
41,000
1,800
4.3

40,700
37,300
3,400
8.4

26,600
25,600
900
3.4

25,600
23,500
2,100
8.2

Source: NYSDOL 2010a.

Table 2.23 presents per capita income for Region A. Per capita income rose approximately
26.8% between 1999 and 2009. The percentage of individuals living below the poverty level in
Region A increased from 12.2% in 1999 to 14.4% in 2009. During the same period, individuals
living below the poverty level in New York State as a whole decreased from 14.6% to 13.9%
(USCB 2000a, 2009b).
Table 2.23 - Region A: Income Statistics, 1999 and 2009 (New August 2011)

Region A
Per capita income
% Below the poverty level1
Broome County
Per capita income
% Below the poverty level1
Chemung County
Per capita income
% Below the poverty level1
Tioga County
Per capita income
% Below the poverty level1

1999

2009

$18,854
12.2

$23,912
14.4

$19,168
12.8

$24,432
15.0

$18,264
13.0

$22,691
15.8

$18,673
8.4

$24,034
10.0

Source: USCB 2000a, 2009b.
1 If the total income for an individual falls below relevant poverty thresholds, updated annually relative to the
Consumer Price Index for All Urban Consumers, then the individual is classified as being "below the poverty
level."

Final SGEIS 2015, Page 2-52

 The five largest employers in the Binghamton MSA, which includes Broome and Tioga Counties
are United Health Services, (3,300 employees); Lockheed Martin, (3,000 employees); Broome
County (2,500 employees); the State University of New York Binghamton University (2,300
employees); and Lourdes Hospital (2,300 employees) (BCIDA 2010). The largest employer in
Chemung County is St. Joseph’s Hospital (1,000-1,200 employees) (STC Planning 2009).
The Empire State Development Corporation has identified 16 industry clusters for the Southern
Tier Region of the state, which encompasses Region A (Broome, Chemung, and Tioga Counties)
as well as Chenango, Delaware, Schuyler, Steuben, and Tompkins Counties. The industry
clusters that support the largest number of jobs are industrial machinery and services, travel and
tourism, financial services, front office and producer services, and electronics and imaging.
Travel and tourism is a large industry for the Southern Tier Region (which includes Region A),
ranking second in employment of the 16 industry clusters in the Southern Tier Region. Broome
and Tioga Counties are part of the Susquehanna Heritage Area, and Chemung County considers
itself the gateway to the Finger Lakes Region. Various attractions and natural areas are described
in more detail in Section 2.3.12, Visual Resources, and Section 2.3.15, Community Character.
The travel and tourism industry employs approximately 4,590 persons throughout Region A
(NYSDOL 2009b), primarily in food service (2,000 workers) and accommodations (1,190
workers) (Table 2.24). In 2009, wages earned by persons employed in the travel and tourism
sector were approximately $78.6 million, or about 1.5% of all wages earned in Region A
(NYSDOL 2009b) (Table 2.25).

Final SGEIS 2015, Page 2-53

 Table 2.24 - Region A: Employment in Travel and Tourism, 2009 (New August 2011)

Region A
Number % of
of Jobs Total
1,190
25.9
530
11.5

Industry Group
Accommodations
Culture, recreation, and
amusements
Food service
Passenger transportation
Travel retail
Total

2,000
540
330
4,590

43.6
11.8
7.2

Broome
Chemung
County
County
Tioga County
Number % of Number % of Number % of
of Jobs Total of Jobs Total of Jobs Total
830
27.8
210
18.3
150
33.3
320
10.7
100
8.7
110
24.4
1,340
330
170
2,990

44.8
11.0
5.7

530
210
100
1,150

46.1
18.3
8.7

130
0
60
450

28.9
13.3

Source: NYSDOL 2009b.
Table 2.25 - Region A: Wages in Travel and Tourism, 2009 (New August 2011)

Region A
Broome County
Chemung County
Tioga County

2009
Total Wages
Average
(millions)
Wages
$78.6
$17,100
$50.3
$16,800
$20.9
$18,100
$7.4
$16,100

Source: NYSDOL 2009b.

Agriculture is also an important industry within Region A. Table 2.26 provides agricultural
statistics for Broome, Chemung, and Tioga Counties. Approximately 1,518 farms are located in
Region A, encompassing 258,571 acres of land. The value of agricultural production in 2009 was
$83.2 million dollars (USDA 2007). The principal source of farm income is dairy products,
which account for 70% of the agricultural sales in Broome County, and 75% of the sales in Tioga
County (USDA 2007).

Final SGEIS 2015, Page 2-54

 Table 2.26 - Region A: Agricultural Data, 2007 (New August 2011)

Number of farms
Land in farms (acres)
Average size of farm (acres)
Market value of Products Sold ($
millions)
Principal operator by primary
occupation
Farming
Other
Hired farm labor
Land in state-designated
agricultural districts

Region A
1,518
258,571
170
83.2

Broome
County
580
86,613
149
29.9

Chemung
County
373
65,124
175
16.6

Tioga County
565
106,834
189
36.7

681
837
971
278,935

252
328
340
153,233

183
190
238
41,966

246
319
393
83,736

Source: USDA 2007; NYSDAM 2011.

Approximately 125 persons are employed in the oil and gas industry in Region A, or about 34.5%
of persons working in the oil and gas industry in New York State (NYSDOL 2009a, 2010b).
Workers are primarily employed in Chemung County, as the data on oil and gas industry
employment in Broome and Tioga Counties is so low as to not be reported due to business
confidentiality reasons.
The oil and gas industry was a marginal contributor to total wages in Region A in 2009. Total
wages for persons employed in the oil and gas industry in Chemung County were $12.5 million,
or about 0.2% of total wages across all industries (NYSDOL 2009a, 2010b). The average annual
wage for workers employed in the oil and gas sector in Chemung County was $99,600 in 2009.
In the 1990s, Region A was a minor contributor to New York State’s natural gas production.
However, starting in 2001, Region A experienced a substantial increase in its gas production,
reaching a peak in 2006 before declining in each of the following three years (Figure 2.5).
Table 2.27 shows the number of active natural gas wells operating in Region A from 1994 to
2009. As shown on the table, the number of active wells in Region A has been steadily increasing
since 1995.

Final SGEIS 2015, Page 2-55

 Figure 2.5 - Region A: Natural Gas Production, 1994 to 2009 (New August 2011)

Source: NYSDEC 1994-2009.

Table 2.27 - Region A: Number of Active Natural Gas Wells, 1994-2009 (New August 2011)

Year
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009

No. of Gas Wells
15
12
15
16
17
20
19
25
29
30
36
38
37
40
41
46

Source: NYSDEC 1994-2009.

Final SGEIS 2015, Page 2-56

 In 2009, the average annual output per well in Region A was 317.9 MMcf of natural gas. The
average production per well in Region A was greater (by a factor of 47) than the statewide
average of 6.8 MMcf (NYSDEC 2009).
Table 2.28 shows the production of natural gas and the number of active wells, by town, within
each county in Region A for 2009. As shown in the table, Chemung County accounted for nearly
all of the natural gas production and active wells in Region A. There were no active natural gas
wells in Broome County in 2009.
Table 2.28 – Natural Gas Production and Active Wells by Town within each County in Region A, 2009 (New August 2011)

Location
Region A
Chemung County
Baldwin
Big Flats
Catlin
Elmira
City
Erin
Horseheads
Southport
Van Etten
Veteran
Tioga County
Spencer

Natural Gas
Production
(Mcf)
14,623,232
13,890,161
327,738
2,095,184
1,441,322
2,685

Number of
Active Gas Wells
46
45
1
4
9
1

4,037,072
4,910
1,752,131
3,048,850
1,180,269
733,071
733,071

6
0
5
12
7
1
1

Source: NYSDEC 2009.

Region B
Table 2.29 presents employment, by industry, within Sullivan, Delaware, and Otsego Counties
(Region B). The largest employment sectors are educational, health, and social services (30.1%
of workers); retail trade (11.6%) arts, entertainment, recreation, accommodation, and food
services (10.1%). This region also has a comparatively high number of employment in the
agriculture, forestry, fishing, hunting, and mining sector (2.9%), particularly Delaware County
(5.2%), compared to New York State as a whole (0.6%) (USCB 2009a).

Final SGEIS 2015, Page 2-57

 Table 2.29 - Region B: Area Employment, by Industry, 2009 (New August 2011)

Region B
Number of % of
Industry Sector
Jobs
Total
Agriculture, forestry, fishing,
2,498
2.9
hunting, and mining
Construction
7,276
8.5
Manufacturing
6,442
7.5
Wholesale Trade
2,134
2.5
Retail Trade
9,900
11.6
Transportation and
3,626
4.3
warehousing, utilities
Information
1,493
1.7
Finance, insurance, real
4,373
5.1
estate, and renting/leasing
Professional, scientific,
4,618
5.4
management, administrative,
and waste management
services
Educational, health, and
25,788
30.1
social services
Arts, entertainment,
8,630
10.1
recreation, accommodation,
and food services
Other services (except public
4,248
5.0
administration)
Public administration
4,571
5.3
Total
85,597

Sullivan County
Number % of
of Jobs
Total
591
1.7

Delaware County
Number % of
of Jobs
Total
1,102
5.2

Otsego County
Number % of
of Jobs
Total
805
2.7

3,178
1,504
924
3,740
1,710

9.2
4.4
2.7
10.9
5.0

2,051
2,565
432
2,362
897

9.7
12.2
2.0
11.2
4.2

2,047
2,373
778
3,798
1,019

6.8
7.9
2.6
12.6
3.4

696
2,034

2.0
5.9

323
737

1.5
3.5

474
1,602

1.6
5.3

2,006

5.8

1,113

5.3

1,499

5.0

10,368

30.1

5,564

26.4

9,856

32.8

3,494

10.1

1,845

8.7

3,291

11.0

1,818

5.3

1,069

5.1

1,361

4.5

2,377
34,440

6.9

1,051
21,111

5.0

1,143
30,046

3.8

Source: USCB 2009a.

Table 2.30 presents total and average wages across all industries for Region B. The average
wages for persons employed across all industries in Region B was $35,190 in 2009.
Table 2.30 - Region B: Wages, by Industry, 2009 (New August 2011)

2009
Total Wages
Average
(millions)
Wages
Region B
Total, all industries
Delaware County
Total, all industries
Chemung County
Total, all industries
Tioga County
Total, all industries

$2,266.66

$35,190

$544.78

$34,655

$830.49

$35,310

$891.39

$35,412

Source: NYSDOL 2000ba, 2010b.

Final SGEIS 2015, Page 2-58

 The total labor force for Region B is approximately 88,500 workers, of which 40% are in Sullivan
County, 35% are in Otsego County, and 25% are in Delaware County. As shown in Table 2.31,
the 2010 annual average unemployment rate in Region B was approximately 8.5%, similar to
New York State as a whole. Among the counties that comprise Region B, Sullivan County had
the highest average unemployment rate, approximately 9.2% (NYSDOL 2010a).
Table 2.31 - Region B: Labor Force Statistics, 2000 and 2010 ((New August 2011))

Region B
Total labor force
Employed workers
Unemployed workers
Unemployment rate
Delaware County
Total labor force
Employed workers
Unemployed workers
Unemployment rate (%)
Otsego County
Labor force
Employed workers
Unemployed workers
Unemployment rate (%)
Sullivan County
Labor force
Employed workers
Unemployed workers
Unemployment rate (%)

2000

2010

Percent
Change

85,200
81,500
3,600
4.2

88,500
81,000
7,500
8.5

3.9
-0.6
108.3
102.3

22,200
21,300
900
4.2

22,000
20,100
1,900
8.7

-0.9
-5.6
111.1
107.1

29,800
28,500
1,300
4.2

31,500
29,100
2,400
7.7

5.7
2.1
84.6
83.3

33,200
31,700
1,400
4.3

35,000
31,800
3,200
9.2

5.4
0.3
128.6
114.0

Source: NYSDOL 2010a.

Table 2.32 presents per capita income data for Region B. From 1999 to 2009, per capita income
across the region increased by 27.9%. Individuals living below the poverty level in Region B
increased from 14.9% in 1999 to 15.0% in 2009 (USCB 2000a, 2009b).

Final SGEIS 2015, Page 2-59

 Table 2.32 - Region B: Income Statistics, 1999 and 2009 (New August 2011)

Region B
Per capita income
% Below the poverty level1
Delaware County
Per capita income
% Below the poverty level1
Otsego County
Per capita income
% Below the poverty level1
Sullivan County
Per capita income
% Below the poverty level1

1999

2009

$17,790
14.9

$22,750
15.0

$17,357
12.9

$22,199
15.1

$16,806
14.9

$22,255
15.2

$18,892
16.3

$23,491
14.7

Source: U.S. Census 2000a, 2009b.
1

If the total income for an individual falls below relevant poverty thresholds, updated annually relative to the
Consumer Price Index for All Urban Consumers, then the individual is classified as being "below the poverty
level."

The five largest employers in Delaware and Otsego Counties are: Bassett Healthcare (3,200+
employees), Amphenol Corporation (1,400 employees), State University of New York College
Oneonta (1,181 employees); New York Central Mutual Fire Insurance Company (1,000
employees) and A.O. Fox Hospital (1,000 employees) (Bassett Healthcare 2011; Delaware
County Economic Development 2010; Otsego County 2010).
The counties within Region B are part of three economic development regions, as defined by the
Empire State Development Corporation, including the Southern Tier Region (Delaware County),
Mid-Hudson Region (Sullivan County), and Mohawk Valley Region (Otsego County). Ranked
by employment, travel and tourism is the lead employment industry cluster for the Mid-Hudson
Region, and the second largest employment industry cluster in the Southern Tier and Mohawk
Valley Regions. The tourism industry is an important economic driver in Region B, particularly
in Otsego and Sullivan Counties, with the Catskill Mountains, as well as popular destinations
such as the Baseball Hall of Fame in the village of Cooperstown (Otsego County) and the
Monticello Raceway in the village of Monticello (Sullivan County). Approximately 4,560
persons were employed in the travel and tourism sector in Region B in 2009, including
accommodations (1,820 jobs), and culture, recreation, and amusements (960 jobs), food service
(930 jobs), passenger transportation (250 jobs), and travel retail (600 jobs) (Table 2.33). In 2009

Final SGEIS 2015, Page 2-60

 wages earned by persons employed in the travel and tourism sector was approximately $72.3
million, or about 3.4% of all wages earned in Region B (NYSDOL 2009b) (Table 2.34).
Table 2.33 - Region B: Travel and Tourism, by Industrial Group, 2009 (New August 2011)

Industry Group
Accommodations
Culture, recreation, and
amusements
Food service
Passenger transportation
Travel retail
Total

Delaware
Region B
County
Otsego County Sullivan County
Number % of Number % of Number % of Number % of
of Jobs
Total of Jobs Total of Jobs Total of Jobs Total
1,820
39.9%
150
11.7%
530
35.3%
1,140 64.0%
960

21.1%

100

7.8%

500

33.3%

360

20.2%

930
250
600
4,560

20.4%
5.5%
13.2%

360
150
520
1,280

28.1%
11.7%
40.6%

360
60
50
1,500

24.0%
4.0%
3.3%

210
40
30
1,780

11.8%
2.2%
1.7%

Source: NYSDOL 2009b.

Table 2.34 - Region B: Wages in Travel and Tourism, 2009 (New August 2011)

Region B
Delaware County
Otsego County
Sullivan County

2009
Total Wages
Average
(millions)
Wage
$72.3
$19,500
$6.5
$15,400
$28.6
$19,200
$37.2
$20,900

Source: NYSDOL 2009b.

Agriculture also is an important industry within Region B. Table 2.35 provides agricultural
statistics for Delaware, Otsego, and Sullivan Counties. Approximately 2,050 farms are located in
Region B, encompassing 392,496 acres of land. The value of agricultural production in 2009 was
$148.7 million dollars (USDA 2007). The principal sources of farm income in the region are
dairy products (particularly in Otsego and Delaware Counties, where dairy products accounted for
70% and 62% of the agricultural sales in the county, respectively) and poultry and eggs
(particularly in Sullivan County, where poultry and eggs accounted for 65% of the sales in the
county) (USDA 2007).

Final SGEIS 2015, Page 2-61

 Table 2.35 - Region B: Agricultural Data, 2007 (New August 2011)

Number of farms
Land in farms (acres)
Average size of farm (acres)
Market value of Products Sold ($
millions)
Principal operator by primary
occupation
Farming
Other
Hired farm labor
Land in state designated
agricultural districts

Region B
2,050
392,496
191
$148.7

Delaware
County
747
165,572
222
$55.1

Otsego
County
980
176,481
180
$51.4

Sullivan
County
323
50,443
156
$42.1

1,139
911
1,746
588,443

437
310
760
237,385

538
442
574
189,291

164
159
412
161,767

Source: USDA 2007; NYSDAM 2011.

Currently, there are no producing natural gas wells in Region B, although some exploratory well
activity occurred in 2007 and 2009.
Region C
Table 2.36 presents employment by industry within Chautauqua and Cattaraugus Counties, and
for Region C. The largest employment sectors in Region C are education, health, and social
services sector (26.7% of total employment), manufacturing (16.5% of total employment), and
retail trade (11.6%). The agriculture, forestry, fishing, hunting, and mining sector accounted for
about 2.9% of total employment in the region, which is relatively high compared to New York
State as a whole, which had 0.6% of its workforce employed in this sector (USCB 2009a).

Final SGEIS 2015, Page 2-62

 Table 2.36 - Region C: Area Employment by Industry, 2009 (New August 2011)

Sector
Agriculture, forestry, fishing, hunting, and
mining
Construction
Manufacturing
Wholesale trade
Retail trade
Transportation and warehousing, utilities
Information
Finance, insurance, real estate, and
renting/leasing
Professional, scientific, management,
administrative, and waste management
services
Educational, health, and social services
Arts, entertainment, recreation,
accommodation, and food services
Other services (except public administration)
Public administration

Cattaraugus
Chautauqua
Region C
County
County
Number of % of Number % of Number
% of
Jobs
Total of Jobs Total of Jobs
Total
2,813
2.9
1,136
3.1
1,677
2.8
6,042
16,194
2,620
11,392
4,116
1,578
3,486

6.2
16.6
2.3
11.7
4.2
1.6
3.6

2,825
5,752
879
4,432
1,398
525
1,289

7.6
15.5
2.4
11.9
3.7
1.4
3.5

3,217
10,442
1,741
6,960
2,718
1,053
2,197

5.3
17.2
2.9
11.5
4.4
1.7
3.6

4,816

4.9

1,898

5.1

2,918

4.8

26,161
9,581

26.8
9.8

9,575
3,893

25.7
10.4

16,586
5,688

27.3
9.4

4,225
4,960
97,984

4.3
5.1

1,468
2,150
37220

3.9
5.8

2,757
2,810
60,764

4.5
4.6

Source: USCB 2009a.

Table 2.37 presents total and average wages across all industries for Region C. The average
wages for persons employed across all industries in Region C was $32,971 in 2009.
Table 2.37 - Region C: Wages, by Industry, 2009 (New August 2011)

2009
Total Wages
(millions)
Region C
Total, all industries
Cattaraugus County
Total, all industries
Chautauqua County
Total, all industries

Average
Wages

$2,732.72

$32,971

$1,046.92

$34,428

$1,685.80

$32,127

Source: NYSDOL 2009a, 2010b.

The total labor force for Region C is approximately 105,800 workers, of which 61% are in
Chautauqua County, and 39% are in Cattaraugus County. As shown in Table 2.38, the 2010

Final SGEIS 2015, Page 2-63

 annual average unemployment rate in Region C was approximately 8.9%. The size of the labor
force decreased by 3.1% between 2000 and 2010 across the region, and the unemployment rate
has generally doubled.
Table 2.38 - Region C: Labor Force Statistics, 2000 and 2010 (New August 2011)

Region C
Labor force
Employed workers
Unemployed workers
Unemployment rate (%)
Cattaraugus County
Labor force
Employed workers
Unemployed workers
Unemployment rate (%)
Chautauqua County
Labor force
Employed workers
Unemployed workers
Unemployment rate (%)

2000

2010

109,200
104,700
4,600
4.2

105,800
96,400
9,400
8.9

41,100
39,300
1,900
4.5

41,200
37,400
3,800
9.2

68,100
65,400
2,700
4.0

64,600
59,000
5,600
8.7

Source: NYSDOL 2010a.

Table 2.39 presents per capita income data for Region C. Per capita income in Region C rose
approximately 26.2% between 1999 and 2009. The number of individuals living below the
poverty level in Region C increased from 13.8% in 1999 to 16.1% in 2009.
Table 2.39 - Region C: Income Statistics, 1999 and 2009 (New August 2011)

Region C
Per capita income
% Below the poverty level1
Cattaraugus County
Per capita income
% Below the poverty level1
Chautauqua County
Per capita income
% Below the poverty level1

1999

2009

$16,509
13.8

$20,830
16.1

$15,959
13.7

$20,508
15.7

$16,840
13.8

$21,023
16.3

Source: U.S. Census 2000a, 2009b.
1

If the total income for an individual falls below relevant poverty thresholds, updated annually relative to the
Consumer Price Index for All Urban Consumers, then the individual is classified as being "below the poverty
level."

The five largest employers in Region C are Dresser-Rand Company (3,300 employees); The
Resource Center, Chautauqua County (1,748 employees); Chautauqua County (1,366 employees);

Final SGEIS 2015, Page 2-64

 Cummins Engine, Chautauqua County (1,300 employees); and Cattaraugus County (1,180
employees) (Buffalo Business First 2011).
The Empire State Development Corporation has identified 16 industry clusters for the Western
New York Region of the state, which encompasses Cattaraugus and Chautauqua Counties, as well
as Erie (City of Buffalo), Niagara (City of Niagara Falls), and Allegany Counties. The industry
clusters that support the largest number of jobs are front office and producer services, financial
services, travel and tourism, industrial machinery and services, and distribution. Travel and
tourism is the third largest industry cluster in terms of employment in the Western New York
Region.
Tourism is a significant component of the economy in Region C. Cattaraugus County, known as
the Enchanted Mountains Region, boasts abundant recreational opportunities that primarily
revolve around its natural resources. Popular tourist destinations include Allegany State Park, the
Amish Trail, Holiday Valley Ski Resort, Rock City Park, Griffis Sculpture Park, and the SenecaAllegany Casino. Chautauqua County is also recognized for its natural resources and unique
learning destinations associated with the Chautauqua Institute. Approximately 4,040 persons
were employed in the travel and tourism sector in Region C in 2009, including accommodations
(1,110 jobs); culture, recreation, and amusements (1,220 jobs); food service (1,210 jobs);
passenger transportation (280 jobs); and travel retail (220 jobs) (Table 2.40). In 2009, wages
earned by persons employed in the travel and tourism sector were approximately $77.5 million, or
about 3.0% of all wages earned in Region C (NYSDOL 2009b) (Table 2.41).

Final SGEIS 2015, Page 2-65

 Table 2.40 - Region C: Travel and Tourism, by Industrial Group, 2009 (New August 2011)

Region C
Number of
% of
Jobs
Total
1,110
27.5%

Industry Group
Accommodations
Culture, Recreation and
Amusements
Food Service
Passenger Transportation
Travel Retail
Total

Cattaraugus County Chautauqua County
Number of % of Number of % of
Jobs
Total
Jobs
Total
180
10.5%
930
40.1%

1,220

30.2%

1,050

61.0%

170

7.3%

1,210
280
220
4,040

30.0%
6.9%
5.4%

380
30
80
1,720

22.1%
1.7%
4.7%

830
250
140
2,320

35.8%
10.8%
6.0%

Source: NYSDOL 2009b.
Table 2.41 - Region C: Wages in Travel and Tourism, 2009 (New August 2011)

2009

Region C
Cattaraugus County
Chautauqua County

Total Wages
(millions)
$77.5
$39.7
$37.8

Average Wage
$19,200
$23,300
$16,300

Source: NYSDOL 2009b.

Agriculture is also an important industry within Region C. Table 2.42 provides agricultural
statistics for Cattaraugus and Chautauqua Counties. Approximately 2,770 farms are located in
Region C, encompassing 419,297 acres of land. The value of agricultural production in 2009 was
$213.7 million dollars (USDA 2007). Dairy products account for approximately 68% of
agricultural sales in Cattaraugus County. In Chautauqua County, the principal sources of farm
income are grape and dairy products (USDA 2007). Grapes and grape products account for
approximately 30% of agricultural sales in Chautauqua County, and dairy products account for
approximately 51% of agricultural sales (USDA 2007).

Final SGEIS 2015, Page 2-66

 Table 2.42 - Region C: Agricultural Data, 2007 (New August 2011)

Number of farms
Land in farms (acres)
Average size of farm (acres)
Market value of Products Sold ($
millions)
Principal operator by primary
occupation
Farming
Other
Hired farm labor
Land in state-designated
agricultural districts

Region C
2,770
419,297
151
$213.7

Cattaraugus
County
1,112
183,439
163
$75.2

Chautauqua
County
1,658
235,858
142
$138.6

1,437
1,343
4,341
631,686

550
572
994
239,641

887
771
3,347
392,045

Source: USDA 2007; NYSDAM 2011.

Approximately 157 persons are employed in the oil and gas industry in Region C, or
approximately 43.4% of all persons working in the oil and gas industry in New York State in
2009 (NYSDOL 2009a, 2010b).
The oil and gas industry was a marginal contributor to total wages in Region C in 2009. The total
wages for persons employed in the oil and gas industry in the region were $10.8 million, or about
0.4% of the total wages across all industries (NYSDOL 2009a). The average annual wages for
workers employed in the oil and gas sector varied greatly between the counties in Region C. The
average annual wage for oil and gas workers in Cattaraugus County was $44,978 in 2009,
whereas the average annual wage for oil and gas workers in Chautauqua County was $76,970
during the same time period (NYSDOL 2009a).
Natural gas production in Region C is shown on Figure 2.6. In the mid-1990s, Region C
produced nearly 12 MMcf of natural gas per year. Production has declined from that level over
the last 15 years, and the region is now producing slightly more than 8 MMcf of natural gas per
year.

Final SGEIS 2015, Page 2-67

 Figure 2.6 - Region C: Natural Gas Production, 1994-2009 (New August 2011)

Source: NYSDEC 1994-2009.

The total number of active natural gas wells in Region C over the period 1994 to 2009 is shown
on Table 2.43. As shown in the table, the number of active natural gas wells in Region C has
increased by nearly 400 wells since 1994, to a total of 3,917 wells.
Table 2.43 - Number of Active Natural Gas Wells in Region C, 1994-2009 (New August 2011)

Year
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009

No. of Gas Wells
3,523
3,759
3,512
3,427
3,585
3,590
3,545
3,579
3,350
3,470
3,645
3,629
3,740
3,935
3,984
3,917

Source: NYSDEC 1994-2009.

Final SGEIS 2015, Page 2-68

 In 2009 the average annual output per well in Region C was only 2.1 MMcf of natural gas.
Production per well was significantly less than the average annual output per well in Region A
(317.9 MMcf) or the statewide average per well (6.8 MMcf) (NYSDEC 2009). Because of this
low productivity per well, Region C is currently a minor contributor to New York State’s natural
gas production, even though it accounts for the largest number of active wells in the state
(NYSDEC 2009).
Table 2.44 shows the production of natural gas and the number of active wells, by town, within
each county in Region C in 2009. As shown in the table, in 2009 there were 530 active gas wells
in Cattaraugus County and 3,387 active gas wells in Chautauqua County (NYDEC 2009).
Table 2.44 - Natural Gas Production and the Number of Active Gas Wells by Town
within each County in Region C, 2009 (New August 2011)

Location
Region C
Cattaraugus County
Allegany
Ashford
Carrollton
Conewango
Dayton
East Otto
Ellicottville
Farmersville
Freedom
Leon
Machias
Napoli
New Albion
Olean
Otto
Perrysburg
Persia
Randolph
South Valley
Yorkshire
Chautauqua County
Arkwright
Busti

Natural Gas
Production (Mcf)
14,623,232
1,615,243
255,057
10,416
89,633
154,745
113,159
96,897
737
214
3,845
249,247
100
1,187
7,220
7,163
69,647
343,006
99,100
72,434
892
40,544
6,473,408
106,655
321,152

Final SGEIS 2015, Page 2-69

Number of
Active Gas Wells
46
530
6
11
3
76
59
15
3
2
4
88
1
2
9
5
70
42
43
72
2
17
3,387
122
121

 Location
Carroll
Charlotte
Chautauqua
Cherry Creek
Clymer
Dunkirk
Dunkirk City
Ellery
Ellicott
Ellington
French Creek
Gerry
Hanover
Harmony
Jamestown
Kiantone
Mina
North Harmony
Poland
Pomfret
Portland
Ripley
Sheridan
Sherman
Stockton
Villanova
Westfield

Natural Gas
Production (Mcf)
181,427
230,836
469,915
179,037
159,828
69,003
10,169
180,187
204,129
264,581
26,003
437,202
450,439
231,897
4,183
425,027
53,986
352,930
554,983
189,905
235,705
185,487
142,294
106,236
169,836
141,171
389,205

Number of
Active Gas Wells
70
127
314
123
101
36
6
82
66
180
40
152
152
116
3
84
71
159
159
174
149
182
86
84
118
57
253

Source: NYSDEC 2009.

2.3.11.2

Population

The following subsection discusses the past, current and projected population for New York State,
and the local areas within each of the three regions (Region A, B and C).
New York State
New York State is the third most populous state in the country, with a 2010 population of
approximately 19.38 million (USCB 2010) (see Table 2.45). The population density of the state
is 410 persons per square mile. Nearly half of the population in the state is located within NYC
(8.1 million persons). Subtracting out the population of NYC, the average population density of
the rest of New York State is 237.3 persons per square mile. New York State’s population has

Final SGEIS 2015, Page 2-70

 continually increased during the past 20 years, though the rate of growth was faster from 1990 to
2000 than it was from 2000 to 2010 (see Table 2.45).
Table 2.45 - New York State: Historical and Current Population, 1990, 2000, 2010 (New August 2011)

2010
2000
1990

Total
Population
19,378,102
18,976,457
17,990,455

Percent
Change
2.1%
5.5%
--

Average Annual
Growth Rate
0.2%
0.5%
--

Average
Population Density
410.4
401.9
381.0

Source: USCB 1990a, 2000b, and 2010.

Table 2.46 shows the state’s total 2010 population and presents population projections for 2015 to
2030. As shown, the population in New York State is projected to continue to grow through
2030. The state’s population is projected to grow at an average annual rate of 0.2% between 2015
and 2030. By 2030, New York State’s population is projected to reach 20,415,446 persons.
Table 2.46 - New York State: Projected Population, 2015 to 2030 (New August 2011)

Population
2010a
(actual)
19,378,102

Population
2015b
(projected)
19,876,073

Population
2020b
(projected)
20,112,402

Population Population Average Annual
2025b
2030b
Growth Rate
(projected) (projected)
2015-2030
20,299,512 20,415,446
0.2%

Sources:
USCB 2010.
b
Cornell University 2009.
a

Region A
Table 2.47 provides the 1990, 2000 and 2010 population for Region A and for each of the three
counties within this region. The population of Region A is 342,390 persons (USCB 2010), with
an average population density of 209 persons per square mile. Since 1990, all three counties
within Region A have lost population. Between 1990 and 2000, the region lost population at a
rate of approximately 0.5% per year, and between 2000 and 2010, the region lost population at a
rate of approximately 0.1% per year.

Final SGEIS 2015, Page 2-71

 Table 2.47 - Region A: Historical and Current Population, 1990, 2000, 2010 (New August 2011)

Year
Region A
Total Population
Percent Change
Average Annual Growth Rate
Average Population Density
Broome County
Population
Percent Change
Average Annual Growth Rate
Average Population Density
Chemung County
Population
Percent Change
Average Annual Growth Rate
Average Population Density
Tioga County
Population
Percent Change
Average Annual Growth Rate
Average Population Density

1990

2000

2010

359,692
--220.1

343,390
-4.5%
-0.5%
210.2

340,555
-0.8%
-0.1%
208.5

212,160
--300.2

200,536
-5.5%
-0.6%
283.7

200,600
<0.1%
< 0.1%
283.8

95,195
--233.2

91,070
-4.3%
-0.4%
223.1

88,830
-2.5%
-0.3%
217.6

52,337
--100.9

51,784
-1.1%
-0.1%
99.8

51,125
-1.3%
-0.1%
98.6

Source: USCB 1990a, 2000b, and 2010.

The City of Binghamton has the largest population in the region, with a population in 2010 of
47,376; this is 13.9% of Region A’s population as a whole. Other large population centers in the
region include City of Elmira (29,200 persons), Village of Johnson City (15,174), and Village of
Endicott (13,392 persons).
Region A’s population has continually decreased during the past 20 years, though the rate of
decline was faster from 1990 to 2000 than it was from 2000 to 2010 (see Table 2.47).
Table 2.48 shows Region A’s total 2010 population and presents population projections for 2015
to 2030 (Cornell University 2009). As shown in Table 2.48, the population of Region A is
projected to continue to decrease through 2030. The population of the Region is projected to
decrease at an average annual rate of 0.7% between 2015 and 2030. By 2030, Region A’s
population is projected to be 279,675, which would be a decrease of 19% from the 2010 census
population.

Final SGEIS 2015, Page 2-72

 Table 2.48 - Region A: Population Projections, 2015 to 2030 (New August 2011)

County/
Region
Broome
Chemung
Tioga
Region A Total
Sources:

a

Population Population Population Population Population
2015b
2020b
2025b
2030b
2010a
(actual)
(projected) (projected) (projected) (projected)
200,600
183,115
176,715
169,968
162,750
88,830
83,282
80,643
77,773
74,614
51,125
48,089
46,412
44,481
42,311
340,555
314,486
303,770
292,222
279,675

Average
Annual
Growth
Rate
2015-2030
-0.7%
-0.7%
-0.8%
-0.7%

USCB 2010; b Cornell University 2009.

Region B
Table 2.49 provides the 1990, 2000 and 2010 population for Region B and for each of the three
counties within this region. The population of Region B is 187,786 persons (USCB 2010), with
an average population density of 59.6 persons per square mile. The region has gained population
over the last 20 years, primarily in Sullivan County. Between 1990 and 2000, the population
grew at a rate of approximately 0.4% per year, and between 2000 and 2010, population increased
at a rate of approximately 0.2% per year. Since 1990 the population of Region B has increased by
10,767, which is an increase of approximately 6.1%.
Table 2.49 - Region B: Historical and Current Population - 1990, 2000, 2010 (New August 2011)

Region B
Population
Percent Change
Average Annual Growth Rate
Average Population Density
Delaware County
Population
Percent Change
Average Annual Growth Rate
Average Population Density
Otsego County
Population
Percent Change
Average Annual Growth Rate
Average Population Density
Sullivan County
Population
Percent Change
Average Annual Growth Rate
Average Population Density

1990

2000

2010

177,019
--56.2

183,697
3.8%
0.4%
58.3

187,786
2.2%
0.2%
59.6

47,225
--32.7

48,055
1.8%
0.2%
33.2

47,980
-0.2%
< 0.0%
33.2

60,517
--60.4

61,676
1.9%
0.2%
61.5

62,259
1.0%
0.1%
62.1

69,277
--71.4

73,966
6.8%
0.7%
76.3

77,547
4.8%
.5%
80.0

Source: USCB 1990a, 2000b, and 2010.

Final SGEIS 2015, Page 2-73

 The two largest population centers in Region B are the City of Oneonta (13,901 persons) in
Otsego County and the Village of Monticello (6,726 persons) in Sullivan County.
Region B’s population has continually increased during the past 20 years, though the rate of
growth has declined from the 1990 to 2000 period to the 2000 to 2010 period (see Table 2.49).
Table 2.50 shows Region B’s total 2010 population and presents population projections for 2015
to 2030 (Cornell University 2009). As shown in Table 2.50, the population in Region B overall is
projected to decrease through 2030, although the population in Otsego County will increase
slightly through 2025, then decline in 2030, and the population in Sullivan County will increase
slightly between 2015 and 2030. By 2030, Region B’s population is projected to be 183,031,
which would be a decrease of 2.5% from the 2010 census population.
Table 2.50 - Region B: Population Projections, 2015 to 2030 (New August 2011)

County/
Region
Delaware
Otsego
Sullivan
Region B Total

Population Population Population Population Population
2015b
2020b
2025b
2030b
2010a
(actual)
(projected) (projected) (projected) (projected)
47,980
44,644
42,995
40,980
38,631
62,259
63,820
64,344
64,597
64,508
77,547
78,329
79,322
79,845
79,892
187,786
186,793
186,661
185,422
183,031

Average
Annual
Growth
Rate
2015-2030
-0.9%
0.1%
0.1%
-0.1%

Sources: a USCB 2010; b Cornell University 2009.

Region C
Table 2.51 provides the 1990, 2000 and 2010 population for Region C and for Cattaraugus and
Chautauqua Counties. The population of Region C is 215,222 persons (USCB 2010), with an
average population density of 90.7 persons per square mile. Between 2000 and 2010, the region
lost population at an average annual rate of 0.4%. This rate was higher than the rate at which the
region lost population between 1990 and 2000 (0.1% per year). Since 1990 the population of
Region C has decreased by 10,907, or 4.8%.

Final SGEIS 2015, Page 2-74

 Table 2.51 - Region C: Historical and Current Population - 1990, 2000, 2010 (New August 2011)

Region C
Population
Percent Change
Average Annual Growth Rate
Average Population Density
Cattaraugus County
Population
Percent Change
Average Annual Growth Rate
Average Population Density
Chautauqua County
Population
Percent Change
Average Annual Growth Rate
Average Population Density

1990

2000

2010

226,129
--95.3

223,705
-1.1%
-0.1%
94.3

215,222
-3.8%
-0.4%
90.7

84,234
--64.3

83,955
-0.3%
< 0.0%
64.1

80,317
-4.3%
-0.4
61.3

141,895
--133.6

139,750
-1.5%
-0.2%
131.6

134,905
-3.5%
-0.4%
127.0

Source: USCB 1990a, 2000b, and 2010.

The largest population centers in Region C are the City of Jamestown (31,146 persons), City of
Olean (14,452 persons), City of Dunkirk (12,563 persons), and Village of Fredonia (11,230
persons).
Region C’s population has continually decreased during the past 20 years, though the rate of
decline was faster from 2000 to 2010 than it was from 1990 to 2000. As shown in Table 2.52, the
population of Region C is projected to continue to decrease through 2030. The population of
Region C is projected to decrease at an average annual rate of 0.6% between 2015 and 2030. By
2030, Region C’s population is projected to be 188,752 people, which would be a decrease of
12% from the 2010 census population.
Table 2.52 - Region C: Population Projections, 2015 to 2030 (New August 2011)

County/
Region
Cattaraugus
Chautauqua
Region C Total

Average
Annual
Population Population Population Population Population Growth
Rate
2015b
2020b
2025b
2030b
2010a
(actual)
(projected) (projected) (projected) (projected) 2015-2030
80,317
77,870
75,651
73,048
70,075
-0.7%
134,905
129,596
126,521
122,906
118,677
-0.6%
215,222
207,466
202,172
195,954
188,752
-0.6%

Source:
a
USCB 2010.
b
Cornell University 2009.

Final SGEIS 2015, Page 2-75

 2.3.11.3

Housing
New York State

The total number of housing units in New York State in 2010 was 8.1 million. The total number
of housing units has been growing over the past two decades; however, with the advent of the
recent housing market crisis and recession, the rate of growth has slowed in the past few years.
According to the U.S. Census Bureau, in 1990 there were a total of 7.2 million housing units in
New York State. By 2000, the total number of housing units increased by 6.3% to approximately
7.7 million. Between 2000 and 2010, the total number of housing units increased by 5.6% (see
Table 2.53) (USCB 1990b, 2000c, 2010).
Table 2.53 - New York State: Total Housing Units - 1990, 2000, 2010 (New August 2011)

Year
2010
2000
1990

Total Housing Units
8,108,103
7,679,307
7,226,891

Percent Change
5.6
6.3
--

Source: USCB 1990b, 2000c, and 2010.

Nearly half of all housing units in New York State are single-family units. In 2009 an estimated
3.7 million units, or 47.0% of all housing units in the state, were single-family units. Multifamily units, i.e., structures that have three or more units in them, accounted for 39.5% of the total
housing units (see Table 2.54) (USCB 2009c).
Table 2.54 - New York State: Type of Housing Units, 20091 (New August 2011)

Type of Structure
Single Family
Duplex
Multi-family
Mobile Home
Other
Total

Total Number
of Units
3,735,364
866,157
3,142,770
202,773
2,971
7,905,035

% of Total
47.0
10.9
39.5
2.6
<0.1
100

Source: USCB 2009c.
1
Data from the 2010 Census of Population and Housing on housing units by type of structure
had not been released at the time of this report; therefore, estimated 2009 data from the 20052009 American Community Survey estimates is included herein.

Table 2.55 provides the number of sales and annual median sale price of single family homes sold
in New York State over the past three years. The number of annual sales has declined over the

Final SGEIS 2015, Page 2-76

 past three years, while the median sales price has fluctuated. In 2008 the median sales price for
single-family homes was $210,000. During the height of the housing market crisis in 2009, the
median sales price fell to $195,000. By 2010 prices in the statewide housing market had
recovered, and median sales prices rose to $215,000 (NYS Association of Realtors 2011a, 2011b).
Although the statewide housing market statistics have improved over the last year, housing is
intrinsically a local or regional market; many areas of New York State are still experiencing
downward pressures on house prices.
Table 2.55 - New York State: Number of Sales and Annual Median Sale Price of SingleFamily Homes Sold, 2008-2010 (New August 2011)

2008
80,521
$210,000

Number of Sales
Median Sale Price

2009
78,327
$195,000

2010
74,718
$215,000

Source: NYS Association of Realtors 2011a, 2011b.

In 2010, New York State had approximately 3.9 million owner-occupied housing units and 3.4
million renter-occupied housing units (USCB 2010).
The homeowner vacancy rate was 1.9% and the rental vacancy rate was 5.5% (USCB 2010) (see
Table 2.56).
Table 2.56 - New York State: Housing Characteristics, 2010 (New August 2011)

Occupied
Owner Occupied
Renter Occupied
Vacant
For Rent
Rented, Not Occupied
For Sale Only
Sold, Not Occupied
For Seasonal, Recreational, or
Occasional Use
All Other Vacant
Total
Homeowner Vacancy Rate
Rental Vacancy Rate

Housing Units
7,317,755
3,897,837
3,419,918
790,348
200,039
12,786
77,225
21,027
289,301
189,970
8,108,103
1.9%
5.5%

Source: USCB 2010.

Final SGEIS 2015, Page 2-77

 Region A
According to the U.S. Census Bureau, the housing market in Region A has experienced little
growth over the past two decades. As shown in Table 2.57, the region experienced an increase of
1.7% in the total number of housing units from 1990 to 2000, and a 2.1% increase from 2000 to
2010 (USCB 1990b, 2000c, 2010).
Table 2.57 - Region A: Total Housing Units - 1990, 2000, 2010 (New August 2011)

Region A
Broome County
Chemung County
Tioga County

Total
Housing
Units
(1990)
145,513
87,969
37,290
20,254

Total
Housing
Units
(2000)
147,972
88,817
37,745
21,410

Total
Housing
Units
(2010)
151,135
90,563
38,369
22,203

Percent
Change
(1990-2000)
1.7%
1.0%
1.2%
5.7%

Percent
Change
(20002010)
2.1%
2.0%
1.7%
3.7%

Source: USCB 1990b, 2000c, 2010.

A majority of housing units in Region A are single-family units. In 2009 an estimated 96,956
units, or 65.0% of all housing units in the region, were single-family units. Multi-family units,
i.e., structures that contained three or more housing units, accounted for 17.0% of the total
housing units (see Table 2.58).
Table 2.58 - Region A: Total Housing Units by Type of Structure, 20091 (New August 2011)

Number of Units
Region A
Single Family
Duplex
Multi-family
Mobile Home
Other
Broome County
Single Family
Duplex
Multi-family
Mobile Home
Other

% of Total

96,956
15,901
25,389
10,756
64
149,066

65.0
10.8
17.0
7.2
<0.1
100

56,225
10,436
17,646
4,795
15
89,117

63.1
11.7
19.8
5.4
<0.1
100

Final SGEIS 2015, Page 2-78

 Number of Units
Chemung County
Single Family
Duplex
Multi-family
Mobile Home
Other
Tioga County
Single Family
Duplex
Multi-family
Mobile Home
Other
Total

% of Total

25,739
4,291
5,749
2,325
12
38,116

67.5
11.3
15.1
6.1
<0.1
100

14,992
1,174
1,994
3,636
37
21,833

68.7
5.4
9.1
16.7
0.1
100

Source: USCB 2009c.
1 Data from the 2010 Census of Population and Housing on housing units by type of structure had not
been released at the time of this report; therefore, estimated 2009 data from the 2005-2009 American
Community Survey are provided herein.

Table 2.59 provides the number of sales and annual median sale price of single family homes sold
in Region A over the past three years (New York State Association of Realtors 2011a, 2011b).
Table 2.59 - Region A: Number of Sales and Annual Median Sale Price of Single-Family Homes Sold, 2008-2010
(New August 2011)

Broome County
Chemung County
Tioga County
Region A

2008
Number
Median
of Sales Sale Price
1,412
$109,438
629
$85,000
275
$136,170
2,316
NA

Number
of Sales
1,287
593
304
2,184

2009
Median
Sales Price
$115,000
$86,000
$120,000
NA

Number
of Sales
1,193
638
227
2,058

2010
Median
Sales Price
$106,000
$100,000
$122,500
NA

Source: NYS Association of Realtors 2011a, 2011b.
NA = Not available.

In 2010, Region A had approximately 93,074 owner-occupied housing units and 44,905 renteroccupied housing units. The homeowner vacancy rate was 1.1%, and the rental vacancy rate was
7.8% (see Table 2.60) (USCB 2010).

Final SGEIS 2015, Page 2-79

 Table 2.60 - Region A: Housing Characteristics, 2010 (New August 2011)

Occupied
Owner Occupied
Renter Occupied
Vacant
For Rent
Rented, Not Occupied
For Sale Only
Sold, Not Occupied
For Seasonal, Recreational, or
Occasional Use
All Other Vacant
Total
Homeowner Vacancy Rate
Rental Vacancy Rate

Region A
137,979
93,074
44,905
13,156
3,824
226
1,516
471
2,774
4,345
151,135
1.1%
7.8%

Housing Units
Broome Chemung
County
County
82,167
35,462
53,260
24,011
28,907
11,451
8,396
2,907
2,522
917
143
56
956
377
226
151
1,843
376
2,706
90,563
1.8%
8.0%

Tioga
County
20,350
15,803
4,547
1,853
385
27
183
94
555

1,030
38,369
1.5%
7.4%

609
22,203
1.1%
7.8%

Source: USCB 2010.

The 2010 Census of Population and Housing identified 2,774 housing units in Region A that are
considered seasonal, recreational, or occasional use. In addition to the permanent housing
discussed above, there are also numerous short-term accommodations including hotels, motels,
inns, and campgrounds available in the area. Table 2.61 lists the numbers of hotels/motels
available in Region A that were registered with the I Love New York Tourism Agency. As of
2011 there were 40 hotels/motels with approximately 3,110 rooms in Region A.
Table 2.61 - Region A: Short-Term Accommodations (Hotels/Motels), 2011 (New August 2011)

Broome County
Chemung County
Tioga County
Region A

Total
Hotels/Motels
27
9
4
40

Source: Official New York State Tourism Site (ILOVENY) 2011.

Final SGEIS 2015, Page 2-80

Total Rooms
2,202
676
232
3,110

 Region B
According to the U.S. Census Bureau, the rate of growth of the housing supply in Region B has
increased since 1990. The total number of housing units in the region grew from 95,560 in 1990
to 102,163 in 2000, an increase of 6.9%. Between 2000 and 2010, the total number of housing
units increased to 111,185, an increase of 8.8%. (see Table 2.62) (USCB 1990b, 2000c, 2010).
Table 2.62 - Region B: Total Housing Units - 1990, 2000, 2010 (New August 2011)

Delaware County
Otsego County
Sullivan County
Region B

Total
Housing
Units
(1990)
27,361
26,385
41,814
95,560

Total
Housing
Units
(2000)
28,952
28,481
44,730
102,163

Total
Housing
Units
(2010)
31,222
30,777
49,186
111,185

Percent
Change
(1990-2000)
5.8%
7.9%
7.0%
6.9%

Percent
Change
(20002010)
7.8%
8.1%
10.0%
8.8%

Source: USCB 1990b, 2000c, 2010.

A majority of housing units in Region B are single-family units. In 2009 an estimated 76,883
units, or 70.7% of all housing units in the region, were single-family units. Mobile homes
accounted for 12.7% of the total housing units (see Table 2.63).
Table 2.63 - Region B: Total Housing Units by Type of Structure 20091 (New August 2011)

Number of Units
Region B
Single Family
Duplex
Multi-family
Mobile Home
Other
Total

76,883
6,025
12,097
13,731
6
108,742

70.7
5.5
11.1
12.7
<0.1
100

Total

21,876
1,502
2,400
3,949
0
29,727

73.6
5.0
8.1
13.3
0
100

20,576
1,791
3,868
4,405

67.1
5.9
12.6
14.4

Delaware
Single Family
Duplex
Multi-family
Mobile Home
Other
Otsego
Single Family
Duplex
Multi-family
Mobile Home

% of Total

Final SGEIS 2015, Page 2-81

 Number of Units
Total

6
30,646

% of Total
<0.1
100

Total

34,431
2,732
5,829
5,377
0
48,369

71.2
5.6
12.1
11.1
0
100

Other
Sullivan
Single Family
Duplex
Multi-family
Mobile Home
Other

Source: USCB 2009c.
1
Data from the 2010 Census of Population and Housing on housing units by type of structure had
not been released at the time of this report; therefore, estimated 2009 data from the 2005-2009
American Community Survey are provided herein.

As shown in Table 2.64, the housing market in Region B experienced a general decline in total
sales and price in the single-family home market from 2008 to 2010. In the region as a whole, the
number of single-family homes sold each year from 2008 to 2010 declined by 8.7%, from 785
homes in 2008 to 717 homes in 2010.
Median sale prices in the region experienced similar trends. From 2008 to 2010, the median sale
price of single-family homes in Sullivan and Otsego Counties decreased by 16.4% and 8.8%,
respectively. In contrast, the median sale price of homes in Delaware County remained relatively
constant from 2008 to 2010 (see Table 2.64).
Table 2.64- Region B: Number of Sales and Annual Median Sale Price of Single-Family
Homes Sold, 2008-2010 (New August 2011)

Delaware County
Otsego County
Sullivan County
Region B

2008
2009
2010
Number Median Number Median Number Median
of Sales Sale Price of Sales Sales Price of Sales Sales Price
160 $109,250
171
$110,000
149
$110,000
309 $131,000
304
$126,523
319
$119,500
316 $149,450
269
$125,000
249
$125,000
785
NA
744
NA
717
NA

Source: NYS Association of Realtors 2011a, 2011b.
NA = Not available.

In 2010, Region B had approximately 52,860 owner-occupied housing units and 21,797 renteroccupied housing units. The homeowner vacancy rate was 2.6%, and the rental vacancy rate was
10.6% (USCB 2010).

Final SGEIS 2015, Page 2-82

 There were 2,604 units for rent, 1,989 units for sale, and 27,240 units for seasonal, recreational, or
occasional use in the area (see Table 2.65). The percentage of vacant seasonal, recreational, or
occasional use units was very high, largely due to the region’s proximity to the Catskill
Mountains (USCB 2010).
Table 2.65 - Region B: Housing Characteristics, 2010 (New August 2011)

Occupied
Owner Occupied
Renter Occupied
Vacant
For Rent
Rented, Not Occupied
For Sale Only
Sold, Not Occupied
For Seasonal, Recreational,
or Occasional Use
All Other Vacant
Total
Homeowner Vacancy Rate
Rental Vacancy Rate

Region B
74,657
52,860
21,797
36,528
2,604
157
1,989
461
27,240

Housing Units
Delaware
Otsego
County
County
19,898
24,620
14,768
17,885
5,130
6,735
11,324
6,157
565
615
36
45
446
514
117
127
9,276
3,621

Sullivan
County
30,139
20,207
9,932
19,047
1,424
76
1,029
217
14,343

4,077
111,185

884
31,222

1,235
30,777

1,958
49,186

2.6%
10.6%

2.9%
9.9%

2.8%
8.3%

4.8%
12.5%

Source: USCB 2010.

In addition to the permanent housing discussed above, there are also numerous short-term
accommodations including hotels, motels, inns, and campgrounds available in the area. Table
2.66 lists the number of hotels/motels available in Region B that was registered with the I Love
New York Tourism Agency. As of 2011 there were 78 hotels/motels with approximately 3,705
rooms in Region B (see Table 2.66).
Table 2.66 - Region B: Short-Term Accommodations (Hotels/Motels) (New August 2011)

Delaware County
Otsego County
Sullivan County
Region B

Total
Hotels/Motels
27
34
17
78

Source: Official New York State Tourism Site (ILOVENY) 2011.

Final SGEIS 2015, Page 2-83

Total Rooms
1,123
1,373
1,209
3,705

 Region C
In 2010, Region C had a total of 108,031 housing units. The total number of housing units
increased by 8.1% between 1990 and 2000, and by 3.2% between 2000 and 2010 (see Table 2.67)
(USCB 1990b, 2000c, 2010). Approximately 62% of the housing units are located in Chautauqua
County, and 38% are located in Cattaraugus County.
Table 2.67 - Region C: Total Housing Units - 1990, 2000, 2010 (New August 2011)

Cattaraugus County
Chautauqua County
Region C

Total
Housing
Units
(1990)
36,839
62,682
99,521

Total
Housing
Units
(2000)
39,839
64,900
104,739

Total
Housing
Units
(2010)
41,111
66,920
108,031

Percent
Change
(1990-2000)
8.1%
3.5%
5.2%

Percent
Change
(20002010)
3.2%
3.1%
3.1%

Source: USCB 1990b, 2000c, 2010.

Most of the housing units in Region C are single-family units. In 2009 an estimated 106,519
units, or 68.7% of all housing units in the region, were single-family units (see Table 2.68)
Table 2.68 - Region C: Total Housing Units by Type of Structure, 20091 (New August 2011)

Region C
Single Family
Duplex
Multi-family
Mobile Home
Other
Total
Cattaraugus
Single Family
Duplex
Multi-family
Mobile Home
Other
Total
Chautauqua
Single Family
Duplex
Multi-family
Mobile Home
Other
Total

Number of Units

% of Total

73,183
10,802
12,432
10,090
12
106,519

68.7
10.1
11.7
9.5
<0.1
100

28,451
2,850
3,797
5,502
12
40,612

70.1
7.0
9.3
13.6
<0.1
100

44,732
7,952
8,635
4,588
0
65,907

67.9
12.0
13.1
7.0
0
100

Source: USCB 2009c.
1
Data from the 2010 Census of Population and Housing on housing units by type of structure had
not been released at the time of this report; therefore, estimated 2009 data from the 2005-2009
American Community Survey are provided herein.

Final SGEIS 2015, Page 2-84

 As shown on Table 2.69, the market for single-family homes in Region C declined over the past
three years. In the region as a whole, the number of single-family homes sold each year from
2008 to 2010 declined by 14.1%, from 1,492 homes in 2008 to 1,281 homes in 2010 (NYS
Association of Realtors 2011a, 2011b).
Table 2.69 - Region C: Number of Sales and Annual Median Sale Price of Single-Family
Homes Sold, 2008-2010 (New August 2011)

Number
of Sales
577
915
1,492

Cattaraugus County
Chautauqua County
Region C

2008
Median
Sale Price
$69,000
$75,000
NA

Number
of Sales
501
843
1,344

2009
Median
Sales Price
$70,000
$74,521
NA

Number
of Sales
434
847
1,281

2010
Median
Sales Price
$73,000
$80,000
NA

Source: NYS Association of Realtors 2011a, 2011b.
NA = Not available.

In 2010 Region C had approximately 60,182 owner-occupied housing units and 26,325 renteroccupied housing units. The homeowner vacancy rate was 1.4%, and the rental vacancy rate was
9.0% (see Table 2.70) (USCB 2010).
Table 2.70 - Region C: Housing Characteristics, 2010 (New August 2011)

Occupied
Owner Occupied
Renter Occupied
Vacant
For Rent
Rented, Not Occupied
For Sale Only
Sold, Not Occupied
For Seasonal, Recreational,
or Occasional Use
All Other Vacant
Total
Homeowner Vacancy Rate
Rental Vacancy Rate

Region C
86,507
60,182
26,325
21,524
2,624
178
1,278
426
13,308

Cattaraugus
County
32,263
23,306
8,857
8,848
748
82
483
157
6,035

Chautauqua
County
54,244
36,876
17,368
12,676
1,876
96
795
269
7,573

3,410
108,031

1,343
41,111

2,067
66,920

1.4%
9.0%

2.0%
7.6%

2.1%
9.7%

Source: USCB 2010.

Final SGEIS 2015, Page 2-85

 There were 2,624 units for rent, 1,278 units for sale, and 13,608 units for seasonal, recreational, or
occasional use in the area. The percentage of vacant seasonal, recreational, or occasional use
units was very high, largely due to the cottages around Lake Chautauqua, Chautauqua Institute,
and other natural areas in these counties (USCB 2010).

In addition to the permanent housing discussed above, there are also numerous short-term
accommodations including hotels, motels, inns, and campgrounds available in the area. Table
2.71 lists the number of hotels/motels available in Region C that was registered with the I Love
New York Tourism Agency. As of 2011 there were 41 hotels/motels with approximately 1,987
rooms in Region C (see Table 2.71).

Table 2.71 - Region C: Short-Term Accommodations (Hotels/Motels) (New August 2011)

Cattaraugus County
Chautauqua County
Region C

Total
Hotels/Motels
17
24
41

Total Rooms
634
1,353
1,987

Source: Official New York State Tourism Site (ILOVENY) 2011.

2.3.11.4

Government Revenues and Expenditures
New York State

Table 2.72 lists the main sources of tax revenues for New York State. For fiscal year (FY) ending
March 31, 2010, revenues collected in New York State totaled approximately $55 billion.
Revenue from personal income taxes is the largest source of tax revenue for the state, accounting
for approximately 63% of the total revenue (New York State Department of Taxation and Finance
[NYSDTF] 2010a, 2010b).

Final SGEIS 2015, Page 2-86

 Table 2.72 - New York State Revenues Collected for FY Ending March 31, 2010 (New August 2011)

Total
Revenues
($ billions)
Percent of
Total

Personal
Income
Taxes
$34.8

Corporation
and Business
Taxes
$6.6

Sales and
Excise Taxes
and User
Fees
$12.2

Property
Transfers
$1.4

Other Taxes
and Fees
$0.2

Total
Revenues
$55.2

63.0

12.0

22.1

2.5

0.4

100.0

Source: NYSDTF 2010a, 2010b.
Totals may not equal sum of components due to rounding.

Currently, no specific state tax is levied on the extraction of natural gas in New York State;
however, the state government receives revenues from the natural gas industry and from natural
gas development primarily through income and sales taxes. The state assesses personal income
tax on wages earned by workers in the industry, and income received by individuals as royalty
payments and lease payments from natural gas operators. Further, the state also collects revenue
from sales taxes receipts from the purchase of non-exempt materials and equipment needed to
construct and operate natural gas wells. In some cases, the state may receive revenue from
corporate and business taxes assessed on the corporate income of natural gas operators, though
these taxes are subject to various exemptions and incentives that reduce the amount of revenue
that the state is able to collect from the natural gas industry. In addition, New York State receives
revenues from leases for oil and natural gas development on state lands. Lease revenues are
acquired through delay rentals; bonus bids; royalties; and storage fees. Delay rentals are the
annual fees that oil and natural gas developers pay to hold a leased property before development
occurs. Bonus bids are additional fees above the delay rental fee for a specific tract. All bonus
bids are subject to a sealed competitive bidding process. Once the gas well is developed, the
delay rental payments are waived and the developer is assessed royalty fees of 12.5% of gross
revenues. Storage fees are fees that are levied on the operators of underground natural gas storage
facilities. A summary of the acreage and number of leases on state lands is provided in Table
2.73. Table 2.74 provides a summary of state revenues received between 2000 and 2010 from oil
and gas lease payments.

Final SGEIS 2015, Page 2-87

 Table 2.73 - New York State: Number of Leases and Acreage of State Land Leased for
Oil and Natural Gas Development, 2010 (New August 2011)

County
Allegany
Broome
Cattaraugus
Cayuga
Chautauqua
Chemung
Cortland
Erie
Ontario
Schuyler
Seneca
Steuben
Tioga
Tompkins
Total

Acreage of State Land Leased
Rental
Royalty
Storage
Total
126
126
512
512
62
9,981
10,043
62
62
15,715
15,715
730
667
1,397
7,791
7,791
10
255
265
55
55
2,416
10,019
1
12,436
17
17
685
5,859
1,620
8,164
6,179
6,179
915
915
19,228
32,537
11,912
63,677

Number of Leases
Royalty
Storage
1

Rental
1

3
4

1
1
6
1
17

2
4
29
10

8

2

2
1
1

6
1
8

2

63

14

Total
1
1
10
4
29
13
4
4
1
8
1
11
6
1
94

Source: NYSDEC 2010.

Table 2.74 - 2000-2010 Leasing Revenue by Payment Type for New York State (New August 2011)

Year
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010

Bonus Bids
$4,583,239
$9,001,335
$2,922

Delay
Rentals
$42,280
$118,732
$79,435
$16,486
$130,746
$80,534
$75,305
$166,868
$97,269
$96,136
$96,377

Royalties
$75,327
$150,922
$96,620
$609,821
$525,050
$3,235,206
$3,096,620
$2,466,312
$1,866,519
$637,254
$581,824

Source: NYSDEC 2010.

Final SGEIS 2015, Page 2-88

Storage Fees
$9,781
$178,128
$73,617
$117,381
$109,986
$123,930
$125,007
$133,298
$211,927
$50,960
$65,010

Yearly Total
$127,388
$447,782
$249,672
$5,326,927
$765,782
$3,439,670
$3,296,932
$11,767,813
$2,175,715
$784,350
$746,133

 In New York State, local government entities have taxing authority for real property tax purposes.
However, the New York State Department of Taxation and Finance provides a uniform, statewide
method of valuing natural-gas-producing properties for real property tax purposes. Valuations of
natural-gas-producing properties are based on a “unit of production” value - a dollar amount per
Mcf of gas produced. The total valuation is then equalized across four natural gas producing
regions within the state, and then taxed at the local millage rate, similar to any other real property
within the local jurisdiction.
Spending on community services is generally divided between the state and local governments
(i.e., counties, municipalities, fire districts, and school districts). For public safety, New York
State funds state troopers, counties fund county sheriffs, and municipalities commonly fund local
police services. Emergency services such as fire protection/EMT are largely volunteer efforts in
smaller towns, with some financial support received from smaller cities, suburban and rural
towns, and villages. Major cities generally support their own fire departments, which generally
have their own EMT operation.
Roadways are also supported by various levels of government. New York State provides funding
for state and local highways, the operation of which is the responsibility of the NYSDOT as well
as the New York State Thruway Authority. Counties finance county highways, while
municipalities generally provide the funds to administer and maintain local roadways.
In regards to education, New York State financially supports the State University of New York
(SUNY), a system of higher education institutions. Funding for K-12 education is generally
provided by local school districts, which in turn receive revenues from a variety of sources,
including federal aid, state aid, and real property taxes, among others.
Recreation services, including public parks, are another expenditure in which both state and local
governments contribute. New York State provides funding to OPRHP, which operates
recreational facilities at the state level, including the state park system. County governments
generally provide funds for recreational facilities in towns and villages, while cities and larger
suburban areas generally support their own recreational services.
Health, including Medicaid, is an expenditure that is largely carried by the state. Medicaid is a
joint federal-state program. However, counties and major cities in New York State also

Final SGEIS 2015, Page 2-89

 contribute funds. Counties and local governments also have miscellaneous health care costs,
including public health administration, public health services, mental health services,
environmental services, and public health facilities, among others.
Expenditures for water and waste water treatment are generally made by counties and local
municipalities.
Region A
Table 2.75 lists the main sources of public revenues for Region A. Revenues collected in Region
A totaled approximately $736 million for the fiscal year ending December 31, 2009. The
majority of revenues were derived from local sources. Local revenue, including ad valorem (real
and personal property) tax receipts and services, accounted for approximately 67.5% of total
revenues in Region A (NYS Office of the State Comptroller 2010a).
Table 2.75 - Region A: Total Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011)

Broome
County
Chemung
County
Tioga
County
Region A

Taxes1
(% of
total)
$169.4
(37.0)
$80.6
(42.0)
$39.4
(46.2)
$289.4
(39.4)

Services2
(% of
total)
$139.6
(30.4)
$47.3
(24.7)
$20.6
(24.1)
$207.5
(28.2)

Subtotal
Local
Revenue
(% of
total)
$309.0
(67.4)
$127.9
(66.7)
$60.0
(70.2)
$496.9
(67.5)

State/
Federal
Aid
(% of
total)
$127.5
(27.8)
$54.8
(28.6)
$20.4
(23.9)
$202.7
(27.5)

Subtotal
Local//
(% of
total)
$436.5
(95.2)
$182.7
(95.3)
$80.4
(94.0)
$699.6
(95.1)

Other
Sources3
(% of total)
$22.1
(4.8)
$9.1
(4.7)
$5.1
(6.0)
$36.3
(4.9)

Total
Revenue4
$458.6
$191.8
$85.5
$735.9

Source: NYS Office of the State Comptroller 2010a.
1
Taxes include real property taxes and assessments, other real property tax items, sales and use taxes, and other non-property
taxes.
2
Services include charges for services, charges to other governments, use and sale of property, and other local revenues.
3
Other revenues include proceeds of debt and all other sources of revenue.
4
Totals may not equal sum of components due to rounding.

As shown in Table 2.76, the total local tax revenue collected in Region A during the FY ending
on December 31, 2009, was approximately $289.4 million. Of the total tax collected, 59.8% was
derived from sales tax and distribution. Real property taxes, special assessments, and other real
property tax items accounted for about 39.1% of the total local revenue (NYS Office of the State
Comptroller 2010a).

Final SGEIS 2015, Page 2-90

 Table 2.76 - Region A: Local Tax Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011)

Broome
County
Chemung
County
Tioga
County
Region A

Real
Property
Taxes
(% of
total)
$59.1
(34.9)
$26.8
(33.3)
$19.2
(48.7)
$105.1
(36.3)

Other Real
Property
Sales Tax
Tax Items1
and
Special
Distribution
Assessments
(% of
(% of total)
total)
(% of total)
$0
$4.0
$104.1
(0)
(2.4)
(61.4)
$0
$1.9
$51.2
(0)
(2.4)
(63.5)
$0
$2.2
$17.7
(0)
(5.6)
(44.9)
$0
$8.1
$173.0
(0)
(2.8)
(59.8)

Miscellaneous
Use Taxes
(% of total)
$1.5
(0.9)
$0.6
(0.7)
$0.1
(0.3)
$2.2
(0.7)

Other
NonProperty
Taxes2
(% of
total)
$0.7
(0.4)
$0.1
(0.1)
$0.2
(0.5)
$1.0
(0.4)

Total Tax
Collection3
$169.4
$80.6
$39.4
$289.4

Source: NYS Office of the State Comptroller 2010a.
1
Other real property tax items include STAR payments, payments in lieu of taxes, interest penalties, gain from sale of tax
acquired property, and miscellaneous tax items.
2
Other non-property taxes include franchises, emergency telephone system surcharges, city income taxes, and other
miscellaneous non-property taxes.
3
Totals may not equal sum of components due to rounding.

The production value (e.g., gas economic profile), state equalization rate, and millage rate for gasproducing properties in Region A are shown in Table 2.77. Broome, Chemung, and Tioga
Counties are within the Medina Region 3, natural-gas-producing region designated by New York
State. The final gas unit of production value for gas-producing properties within Medina Region
3 was $11.19 in 2010 (NYSDTF 2011). The overall full-value millage rates for Broome,
Chemung, and Tioga Counties were 35.50, 34.30 and 30.80, respectively. These rates have
already been equalized and include the rates of all taxing districts in the county, including county,
town, village, school district, and other special district rates.
Table 2.77 - Gas Economic Profile for Medina Region 3 (New August 2011)

Broome County
Chemung County
Tioga County

2010 Final Gas Unit
of Production Valuea
$11.19
$11.19
$11.19

Millage
Rateb
(2010)
35.50
34.30
30.80

Sources:
a
b

NYSDTF 2011.
NYS Office of the State Comptroller 2010b. Millage rates represent the “overall full-value tax rate” and
include the rates of all taxing districts in the county, including county, town, village, school district, and
special districts rates.

Final SGEIS 2015, Page 2-91

 Table 2.78 presents local government expenditures for Region A during the FY ending December
31, 2009. Social services combined to create the largest single expenditure in each of the counties
of Region A. Approximately 28.7% of the counties’ collective operating and capital budgets
were spent on social services during the FY ending December 31, 2009. Expenditure categories
within social services include social service administration, financial assistance, Medicaid, nonMedicaid medical assistance, housing assistance, employment services, youth services, public
facilities, and miscellaneous social services. Other major expenditures in Region A included
general government (20.5%), employee benefits (15.3%), and health (9.9%). Public safety
accounted for approximately 7.0% of total expenditures in Region A, including $15,299,556 for
police and $118,376 for fire protection. No county in Region A spent any monies on emergency
response. Broome and Chemung Counties did not financially support any fire protection services
(NYS Office of the State Comptroller 2010a).
Table 2.78 - Region A: Expenditures for FY Ending December 31, 2009 ($ millions) (New August 2011)

General
Government
Education
Public Safety
Health
Transportation
Social Services
Economic
Development
Culture and
Recreation
Community
Services
Utilities
Sanitation
Employee
Benefits
Debt Service
Total
Expenditures

Broome County
% of
Total $
Total
$91,817,010
20.4

Chemung County
Tioga County
Region A
% of
% of
% of
Total $
Total
Total $
Total
Total $
Total
$33,090,334 17.8 $21,682,356 27.0 $146,589,700 20.5

$20,406,276
$30,483,583
$39,151,049
$22,685,968
$122,931,621
$6,005,330

4.5
6.8
8.7
5.1
27.4
1.3

$4,412,651
$12,944,032
$24,028,632
$14,625,859
$61,987,864
$60,000

2.4
7.0
12.9
7.9
33.4
<0.1

$5,191,138
$6,467,954
$7,398,260
$6,181,134
$20,346,458
$636,502

6.5
8.1
9.2
7.7
25.4
0.8

$30,010,065
$49,895,569
$70,577,941
$43,492,961
$205,265,943
$6,701,832

4.2
7.0
9.9
6.1
28.7
0.9

$10,186,350

2.3

$2,349,947

1.3

$232,827

0.3

$12,769,124

1.8

$6,768,148

1.5

$2,978,999

1.6

$569,025

0.7

$10,316,172

1.4

$0
$954,025
$82,228,270

0.0
0.2
18.3

$0
$5,780,216
$17,926,465

0.0
3.1
9.6

$0
$1,176,043
$9,460,820

0.0
1.5
11.8

$0
$7,910,284
$109,615,555

0.0
1.1
15.3

$15,410,760
$449,028,390

3.4
$5,620,336
3.0
$862,138
1.1
$21,893,234
100.0 $185,805,335 100.0 $80,204,655 100.0 $715,038,380

3.1
100.0

Source: NYS Office of the State Comptroller 2010a.

Final SGEIS 2015, Page 2-92

 Region B
Table 2.79 lists the main sources of county government revenues for Region B. Revenues
collected in Region B totaled approximately $429.0 million for the fiscal year ending December
31, 2009. Most of the revenues were derived from local sources. Local revenue, including ad
valorem (real and personal property) tax receipts and services, accounted for approximately
65.6% of total revenues in Region B (NYS Office of the State Comptroller 2010a).
Table 2.79 - Region B: Total Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011)

Delaware
County
Otsego County
Sullivan
County
Region B

Taxes1
(% of
total)
$43.1
(37.6)
$44.7
(41.6)
$84.2
(40.7)
$172.0
(40.1)

Services2
(% of
total)
$21.1
(18.4)
$30.7
(28.5)
$57.5
(27.8)
$109.3
(25.5)

Subtotal
Local
Revenue
(% of
total)
$64.2
(56.0)
$75.4
(70.1)
$141.7
(68.5)
$281.3
(65.6)

State/
Federal
Aid
(% of
total)
$33.0
(28.8)
$25.2
(23.4)
$44.2
(21.4)
$102.4
(23.9)

Subtotal
Local//
(% of
total)
$97.1
(84.8)
$100.6
(93.5)
$186.0
(89.9)
$383.7
(89.4)

Other
Sources3
(% of total)
$17.4
(15.2)
$7.0
(6.5)
$20.9
(10.1)
$45.3
(10.6)

Total
Revenue4
$114.5
$107.6
$206.9
$429.0

Source: NYS Office of the State Comptroller 2010a.
1

2
3
4

Taxes include real property taxes and assessments, other real property tax items, sales and use taxes, and other non-property
taxes.
Services includes charges for services, charges to other governments, use and sale of property, and other local revenues.
Other revenues include proceeds of debt and all other sources of revenue.
Totals may not equal sum of components due to rounding.

As shown in Table 2.80, the total local tax revenue in Region B during the fiscal year ending on
December 31, 2009, was approximately $173.7 million. Of the total tax collected, 49.2% was
derived from taxes levied on real property, special assessments, and other real property tax items.
Sales tax and distribution accounted for approximately 48.4% of the total (NYS Office of the
State Comptroller 2010a).

Final SGEIS 2015, Page 2-93

 Table 2.80 - Region B: Local Tax Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011)

Delaware
County
Otsego
County
Sullivan
County
Region B

Real
Property
Taxes
(% of
total)
$23.4
(54.2)
$9.5
(20.5)
$42.1
(50.1)
$75.0
(43.2)

Other Real
Property
Sales Tax
Tax Items1
and
Special
Distribution
Assessments
(% of
(% of total)
total)
(% of total)
$0
$1.7
$17.9
(0)
(3.9)
(41.4)
$1.1
$1.4
$33.1
(2.4)
(3.0)
(71.3)
$0
$6.3
$33.1
(0)
(7.5)
(39.4)
$1.1
$9.4
$84.1
(0.6)
(5.4)
(48.4)

Miscellaneous
Use Taxes
(% of total)
$0
(0)
$1.1
(2.4)
$1.1
(1.3)
$2.2
(1.3)

Other
NonProperty
Taxes2
(% of
total)
$0.2
(0.5)
$0.2
(0.4)
$1.5
(1.8)
$1.9
(1.1)

Total
Revenue
$43.2
$46.4
$84.1
$173.7

Source: NYS Office of the State Comptroller 2010a.
1
Other real property tax items include STAR payments, payments in lieu of taxes, interest penalties, gain from sale of tax
acquired property, and miscellaneous tax items.
2
Other non-property taxes include franchises, emergency telephone system surcharges, city income taxes, and other
miscellaneous non-property taxes.
3
Totals may not equal sum of components due to rounding.

Delaware, Otsego, and Sullivan Counties are within Medina Region 4, natural-gas-producing
region designated by New York State. The final gas unit of production value for gas-producing
properties within the Medina Region 4 was $11.19 in 2010; the 2011 tentative gas unit of
production value is $11.32 (NYSDTF 2011). The 2010 overall full-value millage rates for
Delaware, Otsego, and Sullivan Counties were 21.20, 19.60 and 26.20, respectively (see Table
2.81). These rates have already been equalized and include the rates of all taxing districts in the
county, including county, town, village, school district, and other special district rates.
Table 2.81 - Gas Economic Profile for Medina Region 4 and State Equalization Rates and
Millage Rates for Region B (New August 2011)

Delaware County
Otsego County
Sullivan County

Final Gas Unit
of Production
Value (2010)a
$11.19
$11.19
$11.19

Millage
Rateb
(2010)
21.20
19.60
26.20

Sources:
a
NYSDTF 2011.
b
NYS Office of the State Comptroller 2010b. Millage rates represent the “overall full-value tax rate” and
include the rates of all taxing districts in the county, including county, town, village, school district, and
special districts rates.

Final SGEIS 2015, Page 2-94

 Table 2.82 presents local government expenditures for Region B during the FY ending December
31, 2009. Social services combined to create the largest single expenditure in each of the counties
in Region B. Approximately 30% of the counties’ collective operating and capital budgets were
spent on social services during the FY ending December 31, 2009. Expenditure categories within
social services include social service administration, financial assistance, Medicaid, non-Medicaid
medical assistance, housing assistance, employment services, youth services, public facilities, and
miscellaneous social services. Other major expenditures in Region B included employee benefits
(14.5%), general government (12.4%), and transportation (12.3%). Public safety accounted for
approximately 7.7% of total expenditures in Region B, including $9,103,208 for police and
$70,719 for fire protection. No county in Region B spent any monies on emergency response.
Delaware and Otsego Counties did not financially support any fire protection services (NYS
Office of the State Comptroller 2010a).
Table 2.82 - Region B: Expenditures for FY Ending December 31, 2009 ($ millions) (New August 2011)

General
Government
Education
Public Safety
Health
Transportation
Social Services
Economic
Development
Culture and
Recreation
Community
Services
Utilities
Sanitation
Employee
Benefits
Debt Service
Total
Expenditures

Delaware County
% of
Total $
Total
$8,960,337
9.7

Otsego County
Sullivan County
% of
% of
Total $
Total
Total $
Total
$18,661,059 17.9 $20,991,003 10.7

Region B
Total $
$48,612,399

% of
Total
12.4

$623,530
$5,541,817
$8,405,703
$18,081,013
$28,776,564
$610,060

0.7
6.0
9.1
19.5
31.1
0.7

$2,546,555
$6,882,871
$5,563,650
$11,588,286
$37,215,496
$1,069,964

2.4
6.6
5.3
11.1
35.6
1.0

$6,342,470
$17,902,819
$29,995,278
$18,465,889
$51,657,658
$2,390,941

3.2
9.1
15.3
9.4
26.4
1.2

$9,512,555
$30,327,507
$43,964,631
$48,135,188
$117,649,718
$4,070,965

2.4
7.7
11.2
12.3
30.0
1.0

$702,837

0.8

$277,033

0.3

$2,802,213

1.4

$3,782,083

1.0

$3,172,734

3.4

$2,047,629

2.0

$1,087,185

0.6

$6,307,548

1.6

$0
$3,906,766
$10,972,513

0.0
4.2
11.9

$0
$1,065,180
$15,976,297

0.0
1.0
15.3

$0
$4,312,952
$30,048,837

0.0
2.2
15.4

$0
$9,284,898
$56,997,647

0.0
2.4
14.5

$2,826,085
3.1
$1,606,314
1.5
$9,742,478
5.0
$14,174,877
3.6
$92,579,959 100.0 $104,500,334 100.0 $195,739,723 100.0 $392,820,016 100.0

Source: NYS Office of the State Comptroller 2010a.

Final SGEIS 2015, Page 2-95

 Region C
Table 2.83 lists the main sources of county government revenues for Region C. Revenues
collected in Region C totaled approximately $501.4 million for the fiscal year ending December
31, 2009. Most of the revenues were derived from local sources. Local revenue, including ad
valorem (real and personal property) tax receipts and services, accounted for approximately
70.8% of total revenues in Region C (NYS Office of the State Comptroller 2010a).
Table 2.83 - Region C: Revenues for FY Ending December 31, 2009 ($ millions) (New August 2011)

Cattaraugus
County
Chautauqua
County
Region C

Taxes1
(% of
total)
$78.1
(36.4)
$114.8
(40.1)
$192.9
(38.5)

Services2
(% of
total)
$73.6
(34.3)
$88.5
(30.9)
$162.1
(32.3)

Subtotal
Local
Revenue
(% of
total)
$151.7
(70.6)
$203.3
(70.9)
$355.0
(70.8)

State/
Federal
Aid
(% of
total)
$42.7
(19.9)
$65.0
(22.7)
$107.7
(21.5)

Subtotal
Local//
(% of total)
$194.4
(90.5)
$268.3
(93.6)
$462.7
(92.3)

Other
Sources3
(% of total)
$20.4
(9.5)
$18.3
(6.4)
$38.7
(7.7)

Total
Revenue4
$214.8
$286.6
$501.4

Source: NYS Office of the State Comptroller 2010a.
1
Taxes include real property taxes and assessments, other real property tax items, sales and use taxes, and other non-property
taxes.
2
Services include charges for services, charges to other governments, use and sale of property, and other local revenues.
3
Other revenues include proceeds of debt and all other sources of revenue.
4
Totals may not equal sum of components due to rounding

As shown in Table 2.84, the total local tax revenue in Region C during the fiscal year ending on
December 31, 2009, was approximately $192.8 million. Of the total receipts, 53.2% was derived
from taxes levied on real property, special assessments, and other real property tax items. Sales
tax and distribution accounted for approximately 45.1% of the total (NYS Office of the State
Comptroller 2010a).

Final SGEIS 2015, Page 2-96

 Table 2.84 - Region C: Local Tax Revenue for FY Ending December 31, 2009 ($ millions) (New August 2011)

Cattaraugus
County
Chautauqua
County
Region C

Real
Property
Taxes
(% of
total)
$42.0
(53.8%)
$54.2
(47.2%)
$96.2
(49.9%)

Other Real
Property
Sales Tax
Tax Items1
and
Special
Distribution
Assessments
(% of
(% of total)
total)
(% of total)
$0
$2.6
$33.1
(0%)
(3.3%)
(42.4%)
$0
$3.7
$53.8
(0%)
(3.2%)
(46.9%)
$0
$6.3
$86.9
(0%)
(3.3%)
(45.1%)

Miscellaneous
Use Taxes
(% of total)
$0
(0%)
$1.2
(1.0%)
$1.2
(0.6%)

Other
NonProperty
Taxes2
(% of
Total Tax
total)
Collection3
$0.3
$78.0
(0.4%)
$1.9
$114.8
(1.7%)
$2.2
$192.8
(1.1%)

Source: NYS Office of the State Comptroller 2010a.
1
Other real property tax items include STAR payments, payments in lieu of taxes, interest penalties, gain from sale of tax
acquired property, and miscellaneous tax items.
2
Other non-property taxes include franchises, emergency telephone system surcharges, city income taxes, and other
miscellaneous non-property taxes.
3
Totals may not equal sum of components due to rounding.

Cattaraugus and Chautauqua Counties are both split between Medina Region 2 and Medina
Region 3, natural-gas-producing regions designated by New York State. The final gas unit of
production value for Medina Region 2 and Medina Region 3 was $11.19 in 2010; the 2011
tentative gas unit of production value is $11.32 (NYSDTF 2011). The 2010 overall full-value
millage rates for Cattaraugus and Chautauqua Counties were 35.50 and 32.10, respectively (see
Table 2.85). These rates have already been equalized and include the rates of all taxing districts
in the county, including county, town, village, school district, and other special district rates.
Table 2.85 - Gas Economic Profile for Medina Region 2 and State Equalization Rates and
Millage Rates for Region C (New August 2011)

Cattaraugus County
Chautauqua County

Final Gas Unit
of
Production
Value (2010)a
$11.19
$11.19

Millage Rateb
(2010)
35.50
32.10

Sources:
a
NYSDTF 2011.
b
NYS Office of the State Comptroller 2010b. Millage rates represent the “overall full-value tax rate” and
include the rates of all taxing districts in the county, including county, town, village, school district, and special
districts rates.

Final SGEIS 2015, Page 2-97

 Table 2.86 presents local government expenditures for Region C during the fiscal year ending
December 31, 2009. Social services combined to create the largest single expenditure in both
Cattaraugus and Chautauqua Counties, and thus in Region C. Approximately 30% of the
counties’ collective operating and capital budgets were spent on social services during the fiscal
year ending December 31, 2009. Expenditure categories within social services include social
service administration, financial assistance, Medicaid, non-Medicaid medical assistance, housing
assistance, employment services, youth services, public facilities, and miscellaneous social
services. Other major expenditures in Region C included general government (19.7%), employee
benefits (13.4%), and transportation (10.2%). Public safety accounted for approximately 7.2% of
total expenditures in Region C, including $12,866,430 for police, $260,959 for fire protection,
and $100,667 for emergency response (NYS Office of the State Comptroller 2010a).
Table 2.86 - Region C: Expenditures for FY Ending December 31, 2009 (New August 2011)

General Government
Education
Public Safety
Health
Transportation
Social Services
Economic Development
Culture and Recreation
Community Services
Utilities
Sanitation
Employee Benefits
Debt Service
Total Expenditures

Cattaraugus County
% of
Total $
Total
$38,547,702
20.2
$6,779,075
3.5
$13,349,284
7.0
$23,233,153
12.2
$20,346,282
10.7
$49,828,802
26.1
$1,278,250
0.7
$1,489,536
0.8
$2,877,290
1.5
$0
0.0
$2,004,345
1.0
$23,122,461
12.1
$8,144,509
4.3
$191,000,689
100.0

Chautauqua County
% of
Total $
Total
$51,753,045
19.4
$10,119,356
3.8
$19,805,376
7.4
$14,164,348
5.3
$26,489,032
9.9
$87,553,524
32.8
$3,395,624
1.3
$694,416
0.3
$3,752,921
1.4
$21,402
<0.1
$7,288,201
2.7
$38,268,359
14.4
$3,368,753
1.3
$266,674,357
100.0

Region B
Total $
$90,300,747
$16,898,431
$33,154,660
$37,397,501
$46,835,314
$137,382,326
$4,673,874
$2,183,952
$6,630,211
$21,402
$9,292,546
$61,390,820
$11,513,262
$457,675,046

% of
Total
19.7
3.7
7.2
8.2
10.2
30.0
1.0
0.5
1.4
<0.1
2.0
13.4
2.5
100.0

Source: NYS Office of the State Comptroller 2010a.

2.3.11.5

Environmental Justice
New York State

Nearly each county in New York State has census block groups that may be considered potential
EJ areas. The term “environmental justice” refers to a Federal policy established by Executive
Order 12898 (59 Federal Register [FR] 7629) under which each Federal agency identifies and
addresses, as appropriate, disproportionately high and adverse human health or environmental

Final SGEIS 2015, Page 2-98

 effects of its programs, policies, and activities on minority or low-income populations. In
response to EO 12898 the U.S. Environmental Protection Agency developed a definition of EJ as
follows:
The fair treatment and meaningful involvement of all people regardless of race,
color, national origin, or income with respect to the development, implementation,
and enforcement of environmental laws, regulations, and policies. Fair treatment
means that no group of people, including a racial, ethnic, or socioeconomic group,
should bear a disproportionate share of the negative environmental consequences
resulting from industrial, municipal, and commercial operations or the execution
of federal, state, local, and tribal programs and policies.
The Department’s Commissioner Policy 29 (the Policy) on Environmental Justice and Permitting
expands upon Executive Order 12898, defining a potential EJ area as a minority or low-income
community that bears a disproportionate share of the negative environmental consequences
resulting from industrial, municipal, and commercial operations or the execution of federal, state,
local, and tribal programs and policies.
The New York State Policy defines a minority population as a group of individuals that are
identified or recognized as African-American, Asian American/Pacific Islander, American Indian,
or Hispanic. A minority community exists where a census block group, or multiple census block
groups, has a minority population equal to or greater than 51.1% in urban areas or 33.8% in rural
areas. Rural and urban area classifications are established by the USCB. Urban area means all
territory, population, and housing units located in urbanized areas and in places of 2,500 or more
inhabitants outside of an urbanized area. An urbanized area is a continuously built-up area with a
population of 50,000 or more. Rural area means territory, population, and housing units that are
not classified as an urban area.
A low-income population is defined by the Policy as a group of individuals having an annual
income that is less than the poverty threshold established by the USCB. A low-income
community is a census block group, or area with multiple census block groups, having a low-

Final SGEIS 2015, Page 2-99

 income population equal to or greater than 23.59% of the total population for whom poverty
status is determined.
The Policy applies to applications for major projects and major modifications for the permits
authorized by the following sections of the Environmental Conservation Law:
•

Titles 7 and 8 of Article 17, SPDES (implemented by 6 NYCRR Part 750 et seq.);

•

Article 19, Air Pollution Control (implemented by 6 NYCRR Part 201 et seq.);

•

Title 7 of Article 27, solid waste management (implemented by 6 NYCRR Part 360):
including minor modifications involving any tonnage increases beyond the approved
design capacity and minor modifications involving an increase in the amount of
putrescible solid waste beyond the amount that has already been approved in the existing
permit;

•

Title 9 of Article 27, industrial hazardous waste management (implemented by 6 NYCRR
Part 373); and

•

Title 11 of Article 27, siting of industrial hazardous waste facilities (implemented by 6
NYCRR Part 361).

A Department permit applicant must conduct a preliminary screen to identify whether the
proposed action is located in a potential EJ area. The applicant also must identify potential
adverse environmental impacts within the area to be affected. The Department provides online
mapping for each New York State county to assist applicants in identifying potential EJ areas.
Census block data is utilized to identify these areas. The mapping referenced in this section was
last updated in 2005.
The following provides a discussion of the minority and low-income populations in the state and
in each of the representative regions for background information.
In 2010, the percent minority population in New York State was 34.25%. The Hispanic
population was 17.6% in 2010; and the percent of persons living below poverty level in 2009 was
13.9%.

Final SGEIS 2015, Page 2-100

 According to the 2010 Census of Population and Housing, approximately 97.0% of residents of
New York State identify themselves as being of a single race: 65.8% of the population of New
York State self-identify as White; 15.9% as Black or African American; 0.6% as American Indian
and Alaska Native; 7.3% as Asian; less than (<) 0.1% as Native Hawaiian and Other Pacific
Island; and 7.4% as some other race (USCB 2010). The remaining 3.0% of the population selfidentifies as two or more races (see Table 2.87).
Persons of Hispanic or Latino origin are defined as individuals who identified themselves as
Hispanic or Latino on the 2010 Census, regardless of race. In New York State, 17.6% of the
population self-identifies as being Hispanic or Latino.
Table 2.87 presents a summary of the total population of New York State by the race/ethnicity
categories defined by the USCB.
Table 2.87 - Racial and Ethnicity Characteristics for New York State (New August 2011)

Population Category
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native
Only
Asian Only
Native Hawaiian and Other Pacific
Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino

Population
19,378,102
12,740,940
3,073,800
106,906

Percentage of Total
2010 Population
100.0%
65.8%
15.9%
0.6%

1,420,244
8,766

7.3%
< 0.1%

1,441,563
18,792,219
585,849
3,416,922

7.4%
97.0%
3.0%
17.6

Source: USCB 2010.
The categories presented in this table are defined by the USCB. A person must have self-identified during the 2010
census to be included within any of these categories in the 2010 Census of Population and Housing.

Region A
In 2010, the combined percent minority for Region A was 10.51%. Chemung and Broome
Counties had similar percentages of minority population, while Tioga County had a relatively low
percentage (3.07% minority). Region A had a combined percent Hispanic population of 1.82%.

Final SGEIS 2015, Page 2-101

 The counties which comprise Region A, both collectively and individually, are not considered
minority communities.
The combined poverty level of Region A in 2009 was 14.4% in 2009, while Tioga County had a
lower percentage (10.0%) than Broome and Chemung Counties. The poverty level for Region A
is lower than the New York State EJ threshold for a low-income community (23.59%).
The Department’s 2005 preliminary screen mapping for each county identifies potential EJ areas
at the census block group level. These maps were combined to illustrate potential EJ areas in
Region A (Figure 2.7). The mapping indicates that some census blocks in Chemung County
(towns of Elmira and Ashland); Tioga County (towns of Barton and Owego); and Broome County
(towns of Vestal and Kirkwood) are potential EJ areas based on their minority and/or low-income
populations.
According to the 2010 Census of Population and Housing, approximately 97.6% of the
individuals in Region A identify themselves as being of a single race: 89.5% of the population of
Region A self-identifies as White; 4.6% as Black or African American; 0.2% as American Indian
and Alaska Native; 2.5% as Asian; less than (<) 0.1% as Native Hawaiian and Other Pacific
Island; and 0.8% as some other race (USCB 2010). The remaining 2.4% self-identifies as two or
more races.
In Region A, 1.8% of the population self-identifies as being Hispanic or Latino. Table 2.88
presents a summary of the total population of Region A by the race/ethnicity categories defined
by the USCB.

Final SGEIS 2015, Page 2-102

 Ludlowv ille

Schuyler

Newark
Valley

Candor

Spencer

96

Elmi
ra
He igh
t s

iv er
Wes t
E lmira

New York


Otsego

g

Unadill
a

Waverly

17C
282 

235

Chenango
Bridge

88

Johnson
Endwell
 City
Por t D icki nson

n a Owego

Apalachi n

Endi
co tt

17

Vestal

Vestal
Center

Nichols 

Bi ngha m t on

434

7

Af t on

Delaware

7B

ha n
que e r
Riv

Bainbridge

206

Sidney


41
79

86

Windsor

Conklin
7A

Deposit 10
17

t
We s w
D e la

17

Ch
Greene

369

Broome

Ti oga

Elmi ra

Wells burg

26

38B

Chemung

Southpor t

81

34

s

R

86

ng

Sout
h
Corn ing


13

Su

352

io u

38

Horse hea ds 

Bi g
F la ts
C h e mu

Whit ney
Po i n t

Berkshi re

224

Van
E tten

Moun
t
Upton


r
ve

r

Riv er side

Corn i ng

96B

go
en a n

ve

Paint e d
Post

Lisl e

79

i
aR

Steuben

Alpine

ar

r

B ra n
c
e Ri v h
e

Pennsylvania
0 

2.5

5

10
Miles

Representative Region A
County Boundary
State Boundary
Urban Area

51

G ilbert svill e

12

11

Tompkins

Sou t h New
Ber li n

io g

Pi ne
Va lle y

Marat hon

Slat erville

Springs


East
It haca

Sou t h
Hi ll

ill a r
e

8

Oxford

hn

Millport

327

Chenango

221

366

13A

Norwich

41

T

414

415

Ithaca

New
Ber lin

23

Cortland

392

Cayuga He ight s Forest H ome

Burdett

Wa tki
ns
Gl
en
Mont our
Falls
Odessa

Dryden

Lansi ng

227

226

ts e
Riv

Cincinnatus

Freeville

122

14A

228

McGraw

13 

89

14 

Cortland

Munsons

Corners


222

Un
ad
R iv

Dundee

Truma nsburg

Gro t on

Ri

Yates

54

34B

l
er ic

Seneca

O

Lodi

Figure 2.7: Potential Environmental
Justice Areas for Region A

River/Stream

Highway/Major Road
Secondary Road

Potential Environmental Justice Area

Source: NY DEC, 2005, http://www.dec.ny.gov/docs/
permits_ej_operations_pdf/broomeco.pdf; USGS, 2002

Final SGEIS 2015, Page 2-103

 Table 2.88 - Region A: Racial and Ethnicity Characteristics (New August 2011)

Population Category
Broome County
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native Only
Asian Only
Native Hawaiian and Other Pacific Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino
Chemung County
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native Only
Asian Only
Native Hawaiian and Other Pacific Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino
Tioga County
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native Only
Asian Only
Native Hawaiian and Other Pacific Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino
Region A Total
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native Only
Asian Only
Native Hawaiian and Other Pacific Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino

Population

Percentage of Total 2010
Population

200,600
176,444
9,614
396
7,065
82
1,912
195,513
5,087
4,334

100.0%
88.0%
4.8%
0.2%
3.5%
<0.1%
1.0%
97.5%
2.5%
2.2%

88,830
78,771
5,828
233
1,057
20
539
86,448
2,372
1,436

100.0%
88.7%
6.6%
0.3%
1.2%
< 0.1%
0.6%
97.4%
2.7%
1.6%

51,125
49,556
375
86
372
15
146
50,550
575
412

100.0%
96.9%
0.7%
0.2%
0.7%
<0.1%
0.3%
98.9%
1.1%
0.8%

340,555
304,771
15,817
715
8,494
117
2,597
332,511
8,034
6,182

100.0%
89.5%
4.6%
0.2%
2.5%
< 0.1%
0.8%
97.6%
2.4%
1.8%

Source: USCB 2010.
The categories presented in this table are defined by the USCB. A person must have self-identified during the 2010 census to be
included within any of these categories in the 2010 Census of Population and Housing.

Final SGEIS 2015, Page 2-104

 Region B
Region B comprises three counties: Sullivan, Delaware, and Otsego Counties. The 2010 combined
percent minority for Region B was 10.45%. Delaware and Otsego Counties had similar percentages
of minority population, while Sullivan County had a relatively higher percentage (18.04% minority).
Region B had a combined percent Hispanic population of 5.02%, with Sullivan County having a
slightly higher percentage of Hispanic persons at approximately 9% of total population. The
counties which comprise Region B are not considered minority communities. The combined poverty
level of Region B was 15.0% in 2009. The poverty level for Region B is lower than the New York
State EJ threshold for a low-income community (23.59%).
The Department’s 2005 preliminary screen mapping for each county identifies potential EJ areas
at the census block group level. These maps were combined to illustrate potential EJ areas in
Region B (Figure 2.8). The mapping indicates that some census blocks in Otsego County (town
of Oneonta) and Sullivan County (towns of Delaware, Rockland, Liberty, Fallsburg, Bethel, and
Thompson) are potential EJ areas based on their minority and/or low-income populations. There
are no mapped potential EJ areas in Delaware County.
According to the 2010 Census of Population and Housing, approximately 97.9% of the
individuals in Region B identify themselves as being of a single race: 89.6% of the population of
Region B self-identifies as White; 4.7% as Black or African American; 0.3% as American Indian
and Alaska Native; 1.1% as Asian; less than (<) 0.01% as Native Hawaiian and Other Pacific
Island; and 2.1% as some other race (USCB 2010). The remaining 2.1% self-identify as being of
two or more races.
Persons of Hispanic or Latino origin are defined as individuals who identified themselves as a
Hispanic or Latino on the 2010 Census, regardless of race. In Region B, 5.0% of the population
self-identifies as being Hispanic or Latino.
Table 2.89 presents a summary of the total population of Region B by the race/ethnicity
categories defined by the USCB.

Final SGEIS 2015, Page 2-105

 Oneida

Munnsv ille
Oriskany
Morr isv ille Falls

Cazenov ia

Waterville

Herki mer

Ri ch f ield
Springs


Winfield


Hamilton

Leonardsville

Smyrna

nd

Hartwick

New
Berlin
Sout h New
 Morris
Ber lin


Mount
Upton

Gilbert sv ille
West End

Ba inbridge Sidney

ar e

Si dney
Cen ter

Windsor

Conklin

Ri ve

r
Roxbury

Br a n

t De Lancey

Delaware

Cai
ro

Acra

Greene

Tannersville

Palenvill e

Woodstock

iv

East

Branch


Hurl
ey

Livingston
Manor

Callicoon

Ulster

Secondary Road

Jeffersonville

Woodbourne
Woodridge

Monticello
Narrowsburg

Rosendale
209

Libert y

South Fallsburg

are R iver
State Boundary

West

Hurley


Roscoe

law
De
River/Stream

Zena

New York


10
Miles

Representative Region B

Urban Area

Prattsvill e

Phoenicia

Pennsylvania

County Boundary

Greenville

Fleischmanns

Margaretville

Sullivan

5

Westerlo

Hunter

Andes

es

W

Hancock

2.5

Albany

Deposit

h er
an c
st B r e R
Ea e la w a r
D

0

Delanson
Altamont

Schoharie

D Delhi
ch

Wal ton

Broome

20

Hobart

Frankli n

Aft on

86

Schenectady

Stamford

Ot ego

q u eha n n a Unadilla
S us Rive r

Greene

Schenevus

Davenport

Oneonta

Amsterdam

Middleburgh

Worcester

88

Hagaman

Schoharie

Richmondville

w

Oxford

Laurens

Carlisle Esperance
Central
Bridge
Cobleskill

el a

Chenango

Sharon
Springs

Otsego

Milford
Norwich

Fort Johnson
Fultonville
Tr ibes
90
H ill

Montgomery

Cooperstown

Edmest on

Sherburne

Ames

Cherry
Valley

Schuyler
Lake

Earlville
South
Ot se lic

Fonda
Fort Nelliston
Plai n
5
Pa la t ine
Br i dge Canajoharie

Cedarville

Sangerfield
Bridgewat er West20

Madison

Madison

Clayville
Cassville

Tillson

Kerhonkson

New
Paltz

Napanoch
Ellenville

44
Pine
Bush

Clintondale

Wallkill

87
Wurt sboro
Walden
B loom ingburg
Gardner t own
Mont gomery Orange
Eldred
Lake Balmvill e
84
Washi ngton
Newburgh
Barryvill e
Scotcht own
s
He
ight
Ot isvill e
New Windsor
Maybrook
Vails Gate Fi rt h clif fe
Orange
Pond E ddy
M iddl etown
Sali sbury Mill s
9W C ornwall-on
Eas t Middl et own
e
Washingtonvill
Goshen
6 Chester
209Port Jervis

Figure 2.8: Potential Environmental
Justice Areas for Region B

Highway/Major Road
Potential Environmental Justice Area

Source: NY DEC, 2005, http://www.dec.ny.gov/docs/
permits_ej_operations_pdf/broomeco.pdf; USGS, 2002

Final SGEIS 2015, Page 2-106

 Table 2.89 - Region B: Racial and Ethnicity Characteristics (New August 2011)

Population Category
Delaware County
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native Only
Asian Only
Native Hawaiian and Other Pacific Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino
Otsego County
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native Only
Asian Only
Native Hawaiian and Other Pacific Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino
Sullivan County
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native Only
Asian Only
Native Hawaiian and Other Pacific Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino
Region B Total
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native Only
Asian Only
Native Hawaiian and Other Pacific Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino

Population

Percentage of Total
2010 Population

47,980
45,675
779
131
367
12
394
47,358
622
1,058

100.0%
95.2%
1.6%
0.3%
0.8%
< 0.1%
0.8%
98.7%
1.3%
2.2%

62,259
58,935
1,066
121
674
18
413
61,227
1,032
1,391

100.0%
94.7%
1.7%
0.2%
1.1%
< 0.1%
0.7%
98.4%
1.7%
2.2%

77,547
63,560
7,039
354
1,075
24
3,229
75,281
2,266
6,986

100.0%
82.0%
9.1%
0.5%
1.4%
< 0.1%
4.2%
97.2%
2.9%
9.0%

187,786
168,170
8,884
606
2,116
54
4,036
183,866
3,920
9,435

100.0%
89.6%
4.7%
0.3%
1.1%
< 0.1%
2.1%
97.9%
2.1%
5.0%

Source: USCB 2010.
The categories presented in this table are defined by the USCB. A person must have self-identified during the 2010
census to be included within any of these categories in the 2010 Census of Population and Housing.

Final SGEIS 2015, Page 2-107

 Region C
Region C comprises Chautauqua and Cattaraugus Counties. The 2010 combined percent minority
for Region C was 7.30%. Region C had a combined percent Hispanic population of 2.68%, with
Chautauqua County having a higher percentage (3.70%) than Cattaraugus County. Region C is
not considered a minority community. The combined poverty level of Region C was 2.3% in
2009. The poverty level for Region C is lower than the New York State EJ threshold for a lowincome community (23.59%).
The Department’s 2005 preliminary screen mapping was combined to illustrate potential EJ areas
in Region C (Figure 2.9). The mapping indicates that some census blocks in Cattaraugus County
are potential EJ areas based on their minority and/or low-income populations. These
municipalities include Perrysburg, Leon, New Albion, Conewango, Albion, South Valley, Cold
Spring, Red House, Salamanca, Carrolton, and Allegany. Some census blocks in Chautauqua
County (Jamestown, Portland, Pomfret, Dunkirk and Hanover) are potential EJ areas.
According to the 2010 Census of Population and Housing, 98.2% of the individuals in Region C
identify themselves as being of a single race: 92.7% of the population of Region C self-identifies
as White; 2.0% as Black or African American; 1.5% as American Indian and Alaska Native; 0.6%
as Asian; less than 0.1% as Native Hawaiian and Other Pacific Island; and 1.4% as some other
race (USCB 2010). The remaining 1.9% self-identify as being of two or more races.
Persons of Hispanic or Latino origin are defined as individuals who identified themselves as
Hispanic or Latino on the 2010 Census, regardless of race. In Region C, 2.7% of the population
self-identifies as being Hispanic or Latino.

Final SGEIS 2015, Page 2-108

 Eden

Angola on the Lake
Angola
Lake Erie
Beach
Farnham

L A K E 
ERIE

Silver
Creek
5

Brocton
60 

Cassadaga

83

20Westfield
Ripley

Holland

Wyoming

Springville

Yorkshire

Perrysburg

Lake 
Chautauqua

Cattaraugus

242

Franklinville

Ellicott ville

Ellingt on
Cuba

241

Lakewood

Cel oron

Panama

243

16
353

Randolph

474

98

219

Lit tle
Valley

Bemus
Point

430

Sherman

39

Machias

Sout h
Day t on

Falconer

Jamest own

East

394 Randolph

Salama nca

86

Cattaraugus
Alle ghe n y
R iv er
Al l egany

Frewsburg

New York


Sai n t
Bonaventure
Limestone 

Weston

Ol e an Mills

Portville

305

Allegany

417

Pennsylvania
0 

2.5

5

10
Miles

Representative Region C

River/Stream

County Boundary

Highway/Major Road

Urban Area


Tribal Lands Boundary

State Boundary

Bliss

Centerville

Lime
Lake

Sinclairv ille

Mayville 

Arcade

Delevan

Gowanda

Cherry
Creek

Chautauqua 

78

Erie

75

62

394

76

Colden

438

39

Fredonia 

90

Nort h
Co lli ns

Forestville

Dunkirk

Nort h
Bos t on

20

Potential Environmental Justice Area

Secondary Road


Figure 2.9: Potential Environmental
Justice Areas for Region C
Source: NY DEC, 2005, http://www.dec.ny.gov/docs/
permits_ej_operations_pdf/broomeco.pdf; USGS, 2002

Final SGEIS 2015, Page 2-109

 Table 2.90 presents a summary of the total population of Region C by the race/ethnicity
categories defined by the USCB.
Table 2.90 - Region C: Racial and Ethnicity Characteristics (New August 2011)

Population Category
Cattaraugus County
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native Only
Asian Only
Native Hawaiian and Other Pacific
Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino
Chautauqua County
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native Only
Asian Only
Native Hawaiian and Other Pacific
Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino
Region C Total
Total 2010 Population
White Only
Black or African American Only
American Indian and Alaska Native Only
Asian Only
Native Hawaiian and Other Pacific
Islander Only
Some Other Race Only
Total Population of One Race
Two or more races
Hispanic or Latino

Population

Percentage of Total
2010 Population

80,317
74,639
1,024
2,443
528
15

100.0%
92.9%
1.3%
3.0%
0.7%
< 0.1%

305
78,954
1,363
786

0.4%
98.3%
1.7%
1.0%

134,905
124,875
3,197
689
688
36

100.0%
92.6%
2.4%
0.5%
0.5%
< 0.1%

2,669
132,154
2,751
4,991

2.0%
98.0%
2.0%
3.7%

215,222
199,514
4,221
3,132
1,216
51

100.0%
92.7%
2.0%
1.5%
0.6%
< 0.1%

2,974
211,108
4,114
5,777

1.4%
98.2%
1.9%
2.7%

Source: USCB 2010.
The categories presented in this table are defined by the USCB. A person must have self-identified during the 2010
census to be included within any of these categories in the 2010 Census of Population and Housing.

Final SGEIS 2015, Page 2-110

 2.3.12 Visual Resources 46
As stated in Section 1.3, oil and gas drilling is expected to occur statewide, with the exceptions of
(1) state-owned lands that constitute the Adirondack and Catskill Forest Preserves (the state
constitution requires that these areas remain forever wild and not be leased or sold), and (2) those
areas of the Adirondacks region, NYC, and Long Island where subsurface geology renders
drilling for hydrocarbons unlikely. No site-specific project locations are being evaluated in the
SGEIS; however, the Marcellus and Utica Shales are the most prominent shale formations in New
York State, and the prospective region for the extraction of natural gas from these formations
generally extends from Chautauqua County eastward to Greene, Ulster, and Sullivan Counties,
and from the Pennsylvania border north to the approximate location of the east-west portion of the
New York State Thruway between Schenectady and Auburn (Figure 2.10). This region covers all
or parts of 30 counties. Fourteen counties are located entirely within this area, and 16 counties
are located partially within the area.
For the purposes of impact analysis, visual resources located within the areas underlain by the
Marcellus and Utica Shales in New York may be considered representative of the types of visual
resources that would be encountered statewide. Therefore, this section describes the existing
federally and state-designated visual resources within the boundaries of this area in New York.
The potential for other visual resources and visually sensitive areas within the areas underlain by
the Marcellus and Utica Shales in New York, which are defined by regional planning entities,
county and town agencies, and local communities and their residents, is also acknowledged in this
section. All of these types of visual resources and visually sensitive areas (federal, state, and
local) also contribute to the ‘sense of place’ that defines the character of a community, which is
discussed in Section 2.3.15.

46

Subsection 2.4.12, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011 and was adapted
by the Department.

Final SGEIS 2015, Page 2-111

 ME
Clinton

C A N A D A

Franklin

St.
Lawrence

VT

Essex

Jefferson

Wat ertown

Niagara
Fa lls
North Tonawanda
Buffalo

Niagara

290

L

e
ak

Rochest er

ie
Er

Wayne

Monroe

Genesee

Wyoming

81

Yates
390

Chautauqua

Cattaraugus

86

Allegany

90

Ontario

Livingston

Erie

Orleans

Steuben

Jamestown

Auburn

Cayuga

Seneca

Schuyler

Onondaga

Tompki ns

Uti ca

Chenango

It haca

Saratoga

Fulton

Sarat oga
Spr ings
Schenectady
Schenectady
Troy

Montgomery

Madison

Cortland

N H


Warren

NY

Oneida

Rome

Syracuse

Hamilton

Washington

Oswego

Herkimer

Lewis

Lake Ontario

Otsego

Albany

Schohari e

Albany

Rensselaer

M A


88

Chemung

Tioga

El mira

B ingham t on

Broome

Greene

Delaware

Columbia
Ulster

587
Dutchess

Sullivan

87

Newburgh

PA


Middletown

Rockland

NJ
0

12.5

25

50
Miles

City with Year 2000
Population Greater than 25,000
County Boundary

Boundary of Area of
Interest for Visual Resources
Marcellus Shale Extent
in New York State
Utica Shale Extent in New York State


State Boundary

Extent of Marcellus and Utica Shales in New York State


Major Water Bodies

Westchester

Yonkers
Moun t Vernon
New York

RI

Putnam

Orange

Spring Valley

CT

Poughkeepsie

White Plains
Port Chester
New Rochelle

Suffolk

Hempst ead
Lindenhurst
Valley
Freeport
Stream Long Beach

Figure 2.10: Area of Interest
for Visual Resources
Final SGEIS 2015, Page 2-112

Source: ESRI, 2010; USGS, 2002

 Criteria for identifying visual resources are defined in the Department’s Program Policy DEP-002, “Assessing and Mitigating Visual Impacts” (NYSDEC 2000). Federally designated visual
resources include, but are not limited to, National Historic Landmarks (NHL); properties listed in
the National Register of Historic Places (NRHP); National Natural Landmarks (NNL); National
Wildlife Refuges; National Parks, Recreation Areas, Seashores and Forests, as applicable;
National Wild and Scenic Rivers and American Heritage Rivers; and National Scenic, Historic
and Recreation Trails.
State-designated visual resources include, but are not limited to, properties listed or eligible for
listing in the State Register of Historic Places; Heritage Areas (formerly Urban Cultural Parks);
State Forest Preserves; State Game Refuges, State Wildlife Management Areas and Multiple Use
Areas; State Parks, Day Use Areas, Nature Preserves and Historic Preserves; State Wild, Scenic
and Recreational Rivers; State Scenic Byways, Parkways and Roads; State Conservation Areas
and other sites, areas, lakes, or reservoirs designated or eligible for designation as scenic in
accordance with ECL Article 49 or the DOT equivalent; Critical Environmental Areas; Scenic
Areas of Statewide Significance; State Trails; and Bond Act Properties purchased under the
Exceptional Scenic Beauty or Open Space Category. The New York Statewide Trails Plan, Open
Space Conservation Plan, and Statewide Comprehensive Outdoor Recreation Plan were also
consulted during the development of the existing environmental setting for visual resources
(OPRHP 2008, 2009, 2010).
Based on NYSDEC Program Policy DEP-00-2, the visual resources analysis for this draft SGEIS
includes the following:
•

The definitions of the specific visual resource or visually sensitive area, including
descriptions of relevant regulations, where appropriate.

•

The number of the specific visual resources or visually sensitive areas within the area
underlain by the Marcellus and Utica Shales in New York organized by county, where
appropriate.

•

Figures showing the locations of specific visual resources or visually sensitive areas
within the area underlain by the Marcellus and Utica Shales in New York.

Final SGEIS 2015, Page 2-113

 •

Where appropriate, a table summarizing information for specific visual resources or
visually sensitive areas, generally focusing on visual, aesthetic, or scenic qualities of the
resource, if known, and organized by county.

2.3.12.1

Historic Properties and Cultural Resources

This section discusses historic properties and other cultural resources that are considered visual
resources per NYSDEC Program Policy DEP-00-2, including properties listed in the National and
State Registers of Historic Places (including National Historic Landmarks), state historic sites,
state historic parks, and state heritage areas (formerly urban cultural parks) (NYSDEC 2000).
Historic properties and cultural resources are often considered significant partly because of their
associated visual or aesthetic qualities. These visual or aesthetic qualities may be related to the
integrity of the appearance of these properties or resources, or to the integrity of their settings.
Viewsheds can also contribute to the significance of historic properties or cultural resources, and
viewsheds that contain historic properties and cultural resources may be considered significant
because of their presence in the landscape.
A property on or eligible for inclusion in the National or State Register of Historic Places (16
U.S.C. §470a et seq., Parks, Recreation and Historic Preservation Law Section 14.07)
Historic properties are defined as those properties that have been listed in, or determined eligible
for listing in, the NRHP (Advisory Council on Historic Preservation 2011). The NRHP, which is
the official list of the nation’s historic places worthy of preservation, was established under the
National Historic Preservation Act of 1966, as amended (NPS 2011a; OPRHP 2011a). In general,
historic properties are 50 years old or older, and they retain much of their original appearance
because of the integrity of their location, design, setting, materials, workmanship, feeling, and
association (OPRHP 2011a).
The National Park Service (NPS) maintains a database of properties listed in the NRHP. (This
database does not include information for other properties determined to be eligible for listing in
the NRHP.) At least 1,050 NRHP-listed properties have been identified within the area underlain
by the Marcellus and Utica Shales in New York (Table 2.91) (NPS 2011b, ESRI 2011). The
significance of properties listed or eligible for listing on the NRHP may be derived in varying
degrees from scenic or aesthetic qualities that may be considered visually sensitive.

Final SGEIS 2015, Page 2-114

 Table 2.91 - Number of NRHP-Listed Historic Properties within the Area Underlain by
the Marcellus and Utica Shales in New York (New August 2011)

County Name
Albany*
Allegany
Broome
Cattaraugus
Cayuga*
Chautauqua
Chemung
Chenango
Cortland
Delaware
Erie*
Genesee*
Greene*
Livingston*
Madison*
Oneida*
Onondaga*
Ontario*
Orange*
Otsego*
Schoharie*
Schuyler
Seneca*
Steuben
Sullivan*
Tioga
Tompkins
Ulster*
Wyoming
Yates
Total

Number of NRHP-listed
Historic Properties within
Entire County
7
27
52
26
44
45
32
39
25
62
28
6
45
74
48
2
18
37
3
53
15
14
10
49
64
53
57
32
18
65
1,050

Sources: NPS 2011b; ESRI 2010.
*
Only a portion of the county is located within the area underlain by the Marcellus and Utica
Shales in New York.

The State Register of Historic Places, which is the official list of New York State’s historic places
worthy of preservation, was established under the New York State Historic Preservation act of
1980. The eligibility criteria for properties listed in the State Register of Historic Places are the
same as the eligibility criteria for the NRHP (OPRHP 2011a). The OPRHP maintains the
database of records for properties listed in, or determined eligible for listing in, the State and
National Registers of Historic Places (OPRHP 2011b). Over 250,000 properties located across

Final SGEIS 2015, Page 2-115

 New York State are included in this database, and the database provides information on whether
the properties have been evaluated for State and/or National Register eligibility, and if evaluated,
the eligibility status of the resource (OPRHP 2011c). The significance of properties listed or
eligible for listing in the State Register of Historic Places may be derived in varying degrees from
scenic or aesthetic qualities that may be considered visually sensitive.
National Heritage Areas
National Heritage Areas (NHAs) are designated by Congress. For an area to be considered for
designation, certain key elements must be present. Of primary importance, the landscape must
have nationally distinctive natural, cultural, historic, and scenic resources that, when linked
together, tell a unique story about the nation. NHAs are not units of the NPS, nor are they owned
or managed by the NPS. Each NHA is governed by separate authorizing legislation and operates
under provisions unique to its resources and desired goals. The heritage area concept offers an
innovative method for citizens, in partnership with local, state, and federal governments and
nonprofit and private sector interests, to shape the long-term future of their communities (NPS
2010d, 2011g).
Two NHAs are located partially within the area underlain by the Marcellus and Utica Shales in
New York (Figure 2.11): portions of the Erie Canalway National Heritage Corridor in Erie,
Ontario, Yates, Seneca, Cayuga, Schuyler, and Tompkins Counties; and portions of the Hudson
River Valley NHA in Albany, Greene, Ulster, and Sullivan Counties (OPRHP 2007; NPS 2010d,
2011e; Erie Canalway National Heritage Corridor 2008; Hudson River Valley National Heritage
Corridor 2011). These NHAs are likely to contain scenic or aesthetic areas that may be
considered visual resources or visually sensitive.
Properties Designated as National Historic Landmarks
National Historic Landmarks (NHLs) are nationally significant historic places designated by the
Secretary of the Interior because they possess exceptional value or quality in illustrating or
interpreting the heritage of the United States (NPS 2011c). There are 19 NHLs located within the
area underlain by the Marcellus and Utica Shales in New York (Table 2.92 and Figure 2.11).
Generally, these NHLs are historic buildings (residences, churches, civic buildings, and
institutional buildings), but other types of historic properties are also represented, including

Final SGEIS 2015, Page 2-116

 battlefields and canals (Table 2.92). The significance of NHL-designated properties may be
derived in varying degrees from scenic or aesthetic qualities that may be considered visual
resources or visually sensitive.
State Historic Sites and Historic Parks
State Historic Sites and State Historic Parks are historic and cultural places that tell the story of
the New York State’s rich heritage. Owned by New York State, these places are preserved and
interpreted for the public’s enjoyment, education, and enrichment (OPRHP 2011d). There are 12
State Historic Sites and two State Historic Parks in the counties located entirely or partially within
the area underlain by the Marcellus and Utica Shales in New York (OPRHP 2008). Of these 14
historic and cultural places, only two are within the area underlain by the Marcellus and Utica
Shales in New York: Genesee Valley Canal State Historic Site in Livingston County and Lorenzo
State Historic Site in Madison County (see Figure 2.11) (OPRHP 2011d). State Historic Sites and
State Historic Parks may contain scenic or aesthetic qualities that may be considered visually
sensitive.
Local Visually Sensitive Resources or Areas
The counties that are entirely or partially located within the area underlain by the Marcellus and
Utica Shales in New York are expected to contain numerous other local visual resources or
visually sensitive areas. These local visual resources or visually sensitive areas would be
identified, defined and/or designated by regional planning entities and local (county and town)
communities and their residents and would be in addition to the visual resources or visually
sensitive areas described above that are defined or designated by federal and state agencies and
guidance.

Final SGEIS 2015, Page 2-117

 Table 2.92 - National Historic Landmarks (NHLs) Located within the Area Underlain by
the Marcellus and Utica Shales in New York (New August 2011)

County Name*
Broome
Cayuga**

Number of NHLs
within County
1
6

Names of NHLs
•
•
•
•
•
•

Chautauqua

2

•
•
•

Chemung
Delaware

1
1

•
•

Erie**

2

Madison**
Orange**
Otsego**
Seneca**
Sullivan**
Tompkins
Ulster**

1
1
1
1
1
1
2

•
•
•
•
•
•
•
•
•
•

Total

19

New York State Inebriate Asylum
William H. Seward House
Harriet Tubman Home for the Aged
Harriet Tubman Residence
Thompson A.M.E. Zion Church
Willard Memorial Chapel-Welch
Memorial Hall
Jethro Wood House
Chautauqua Historic District
Lewis Miller Cottage, Chautauqua
Institute
Newton Battlefield
John Burroughs Memorial (Woodchuck
Lodge)
Millard Fillmore House
Roycroft Campus
Gerrit Smith Estate
Delaware and Hudson Canal***
Hyde Hall
Rose Hill
Delaware and Hudson Canal***
Morrill Hall, Cornell University
John Burroughs Riverby Study
Delaware and Hudson Canal***

Sources: ESRI 2010; NPS 2011d; OPRHP 2008.
*
There are no NHLs within other counties located entirely or partially within the area underlain by the Marcellus and Utica
Shales in New York.
** Only a portion of the county is located within the area underlain by the Marcellus and Utica Shales in New York.
*** The Delaware and Hudson Canal NHL traverses portions of three counties (Orange, Sullivan, and Ulster).

Final SGEIS 2015, Page 2-118

 State Heritage Areas (former Urban Cultural Parks [Parks, Recreation and Historic Preservation
Law Section 35.15])
The State Heritage Area System, formerly known as the Urban Cultural Park System, is a state
and local partnership established to preserve and develop areas that have special significance to
New York State (OPRHP 2011e). New York State Heritage Areas are places where unique
qualities of geography, history, and culture create a distinctive identity that becomes the focus of
four heritage goals: preservation of significant resources; education that interprets lessons from
the past; recreation and leisure activities; and economic revitalization for sustainable communities
(OPRHP 2011f). Four regional or urban heritage areas or corridors are located entirely or
partially within the area underlain by the Marcellus and Utica Shales in New York (Figure 2.11):
the Concord Grape Belt (Lake Erie) Heritage Area in Chautauqua and Cattaraugus Counties;
portion of the Western Erie Canal Heritage Area in southern Erie County; portions of the
Mohawk Valley Heritage Area in Oneida, Schoharie, and Albany Counties; and the Susquehanna
Heritage Area in Broome County (OPRHP 2007, 2011e; 2011f; Concord Grape Belt Heritage
Association 2011; Western Erie Canal Alliance 2010-2011). These State Heritage Areas are
likely to contain scenic or aesthetic areas that may be considered visual resources or visually
sensitive.

Final SGEIS 2015, Page 2-119

 Clinton

C A N A D A 

VT

Franklin

St.
Lawrence

NY

Essex

Jefferson

Sackets
Harbor

Lake Ontario

Buffalo Theatre District

La

ke

Concord Grape Belt 
ie
Er
Chautauqua

Genesee

Erie

Western

Erie Canal


Wyoming

86

Allegany

Hamilton

Ontari o
Seneca Falls
Yates

90

Oneida

Onondaga

Cortland

Tompki ns

Schuyler

Chenango

Saratoga

Fulton

RiverSpark

Schenectady

Otsego

Schoharie

Saratoga
Schenectady

Montgomery

Madison

Cayuga

Seneca

Warren

Mohawk
Valley

Syracuse

390
Cattaraugus

81 

Wayne

Monroe
290

Oswego

Rochester

Orleans

Ni agara

Livingston

Michigan Street

Erie Canalway National
Heritage Corridor

Rensselaer

Albany

Chemung

Tioga

Broome

Greene

Delaware

587
Columbia

Ulster

Hudson River Valley

National Heritage Area


Kingston

Susquehanna

CT

Dutchess

Sullivan

PA 

87
Orange

Westchester

0 

12.5

25

Harbor
Park

RI

Putnam

North
Shore

Rockland

NJ

M A


Albany

88 

Steuben

NH

Whitehall

Washington

Niagara Fall
s
Underground

Railroad

Herkimer

Western

Erie Cana
l

Lewi s

Suffolk

50
Miles

Major Water Bodies

Erie Canalway NHA

State Boundary

State Urban Hertage Area

County Boundary

Boundary of Area of
Interest for Visual Resources

Hudson River Valley NHA

State Regional Heritage Area
Western Erie Canal

National Register of
Historic Places Site

Mohawk Valley

State Historic Site

Concord Grape Belt
North Shore

National Historic Landmark

Final SGEIS 2015, Page 2-120

Figure 2.11: Visually Sensitive Areas Associated
with Historic Properties
and Cultural Resources

Source: ESRI, 2010; USGS, 2002; OPRHP, 2007, 2009, 2011;
NYCSCIC, 2005; NPS, 2007

 2.3.12.2

Parks and Other Recreation Areas

This section discusses parks and other recreation areas that are considered visual resources per
NYSDEC Program Policy DEP-00-2, “Assessing and Mitigating Visual Impacts,” including state
parks; properties included in the National Park System and areas defined as national recreation
areas, seashores and forests; and state or federally designated trails (NYSDEC 2000). These
recreation areas often contain scenic areas and/or are developed partly because of their associated
visual or aesthetic qualities.
State Parks [Parks, Recreation and Historic Preservation Law Section 14.07]
State Parks contain natural, historic, cultural, and/or recreational resources of significance to New
York State. (Note that State Historic Parks are discussed separately in Section 2.3.12.1). Owned
by New York State, these parks are maintained for the public’s use. Thirty-four state parks are
located partially or entirely within the area underlain by the Marcellus and Utica Shales in New
York (Table 2.93 and Figure 2.12) (OPRHP 2008). These parks may contain scenic or aesthetic
areas that may be considered visual resources or visually sensitive.

Final SGEIS 2015, Page 2-121

 Table 2.93 - State Parks Located within the Area Underlain by the Marcellus and Utica Shales in New York (New August 2011)

County
Name*
Albany**
Broome

Number of State
Parks within County
1
2

Cattaraugus
Cayuga**

1
2

Chautauqua

2

Chemung
Chenango

1
2

Delaware
Erie**

1
3

Genesee**
Livingston**
Madison**

1
1
2

Otsego**

3

Schoharie**

2

Schuyler
Seneca**

1
3

Steuben

2

Sullivan**
Tompkins

1
3

Wyoming

2

Yates
Total

1
34***

•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•

Names of State Parks within County
John Boyd Thacher State Park
Chenango Valley State Park
Oquaga Creek State Park
Allegany State Park
Fillmore Glen State Park
Long Point State Park
Lake Erie State Park
Long Point on Lake Chautauqua State Park
Mark Twain State Park
Hunts Pond State Park
Bowman Lake State Park
Oquaga Creek State Park
Evangola State Park
Woodlawn Beach State Park
Knox Farm State Park
Darien Lakes State Park
Letchworth State Park
Chittenango Falls State Park
Helen L McNitt State Park (undeveloped)
Gilbert Lake State Park
Betty and Wilbur Davis State Park
Glimmerglass State Park
Max V. Shaul State Park
Mine Kill State Park
Watkins Glen State Park
Seneca Lake State Park
Sampson State Park
Taughannock Falls State Park
Stony Brook State Park
Pinnacle State Park
Lake Superior State Park
Taughannock Falls State Park
Robert H. Treman State Park
Buttermilk Falls State Park
Letchworth State Park
Silver Lake State Park (undeveloped)
Keuka Lake State Park

Sources: ESRI 2010; OPRHP 2008.
*
No state parks within other counties entirely or partially within the area underlain by the Marcellus and Utica Shales in NYS.
** Only a portion of the county is located within the area underlain by the Marcellus and Utica Shales in New York.
***Letchworth State Park is in two counties (Wyoming and Livingston); Oquaga Creek State Park is in two counties (Broome and
Delaware); Taughannock Falls State Park is in two counties (Seneca and Tompkins).

Final SGEIS 2015, Page 2-122

 The National Park System, Recreation Areas, Seashores, Forests (16 U.S.C. 1c)
Properties included in the National Park System and areas defined as National Recreation Areas,
Seashores and Forests contain natural, historic, cultural, and recreational resources of significance
to the nation. Owned by the U.S. government and operated by various federal agencies, they are
maintained for the public’s use. At least five properties included in the National Park System are
located in counties that are partially or entirely within the area underlain by the Marcellus and
Utica Shales in New York: Women’s Rights National Historic Park in Seneca County; Fort
Stanwix National Monument in Oneida County; the North Country National Scenic Trail, which
traverses New York State; Old Blenheim Covered Bridge in Schoharie County; and the Upper
Delaware Scenic & Recreational River in Orange, Sullivan, and Delaware Counties (OPRHP
2008). One National Forest, the Finger Lakes National Forest in Seneca and Schuyler Counties,
is located within the area underlain by the Marcellus and Utica Shales in New York (Figure 2.12)
(OPRHP 2008). No National Recreation Areas or National Seashores are located within the area
underlain by the Marcellus and Utica Shales in New York (OPRHP 2008). The federally-owned
National Park System properties and the National Forest may contain scenic or aesthetic areas
that may be considered visual resources or visually sensitive.
A state or federally designated trail, or one proposed for designation (16 U.S.C. Chapter 27 or
equivalent)
New York State’s natural and cultural resources provide for a broad range of land and waterbased trails that offer multiple recreational experiences (Table 2.94). Each region of the state
offers a unique setting and different opportunities for trails (OPRHP 2008). New York State
breaks the existing system of trails into three general categories: primary trails that are of
national, statewide, or regional significance and that are considered long-distance trails;
secondary trails, which typically connect to a primary trail system but are generally within parks
or open space areas; and stand-alone trails, which are trails of local significance that do not
connect to a primary trail system. Stand-alone trails are generally loop trails, trails that connect to
points of interest, or trails that provide short connections between parks, open spaces, historic
sites and/or communities, or elements of a community (OPRHP 2008).

Final SGEIS 2015, Page 2-123

 Additional state-designated trails include heritage trails, greenway trails, and/or water trails.
Heritage trails are existing non-linear resources associated with historical movements or themes
(OPRHP 2007, 2010). Greenway trails are existing and proposed multi-use trails located within
linear corridors of open space that connect public places, connect people with nature, and protect
areas for environmentally sustainable purposes that include recreation, conservation, and
transportation (OPRHP 2007, 2010). Water trails, also known as blueways, are existing and
proposed designated recreational water routes suitable for canoes, kayaks, and small motorized
watercraft (OPRHP 2010).
One federally recognized trail, the North Country National Scenic Trail, traverses portions of the
area underlain by the Marcellus and Utica Shales in New York. The North Country National
Scenic Trail, an approximately 3,200-mile-long trail extending from eastern New York State to
North Dakota, is administered by the NPS (NPS 2010a, 2010b). The portion of the trail in New
York is included in the system of trails shown on Figure 2.12. National Scenic Trails are
designated under Section 5 of the National Trails System Act and are defined as extended trails
located to provide for maximum outdoor recreation potential and for the conservation and
enjoyment of the nationally significant scenic, historic, natural, or cultural qualities of the areas
though which they pass (NPS 2010a). A number of these types of trails are shown on Figure
2.12. All of these types of trails are likely to contain scenic or aesthetic areas that may be
considered visual resources or visually sensitive

Final SGEIS 2015, Page 2-124

 Clinton
St.
Lawrence

C A N A D A 

NY

Heritage Trail Sites
French and Indian

Jefferson

Abraham Lincoln

Adir onda ck
Pa r k

Revolutionary War
Theodore Roosevelt

Lewis

Lake Ontario

Underground Railroad

Cattaraugus

390

86

Allegany

Tompkins

Schuyler

Steuben

Chemung

Ti oga

Madison

Montgomery

Schenectady

Otsego

ng o

Yates

Cayuga
Cortland

Ch e n a

Wyoming

Onondaga

Ontario

Broome

Saratoga

Fulton

90

a

Chautauqua

Wayne

Se n e c

ke

81

Genesee

Livingston

La

ie
Er

Erie

Oneida

Washington

290

Orleans

Hamilton

Her kimer

Niagara

Oswego

Essex

Warren

Women
Monroe

VT

Franklin

Schoharie

Rensselaer

Albany

M A


88
Delaware

587

Greene

Cat skill
Pa r k

Columbia

Ulster

Trails

Existing Long Distance Trails

PA 

Orange

Proposed Greenway Trails
Existing Water Trails

12.5

25

Boundary of Area of
Interest for Visual Resources
County Boundary
State Boundary

Rockland

Signed On-road Bicycle Route

50
Miles

Putnam
Westchester

Proposed Water Trails

0 

87

Proposed Long Distance Trails
Existing Greenway Trails

CT

Dutchess

Sullivan

NJ

Suffolk

Figure 2.12: Parks and Recreational Resources
that May be Visually Sensitive

National Park System Properties
National Forest
State Park

Major Water Bodies

Source: ESRI, 2010; USGS, 2002; NYCSCIC, 2005; NPS, 2010;
National Atlas US and USGS, 2010; OPRHP, 2011; NYSDOT, 2011

Final SGEIS 2015, Page 2-125

 Table 2.94 - Select Trails Located within the Area Underlain by the Marcellus and Utica Shales in New York (New August 2011)
Name of Trail
North County National Scenic Trail*

Type of Trail

Abraham Lincoln Heritage Trail

•
•
•
•
•
•
•
•
•
•
•
•
•
•

Women Heritage Trail

•

Underground Railroad Heritage Trail

•

Revolutionary War Heritage Trail

•

Long Path*
Finger Lakes Trail*
Canalway Trail*
Hudson River Valley Greenway Trail System*
Hudson River Greenway Water Trail*
Genesee Valley Greenway*
The statewide Snowmobile Trail System*
Conservation Trail*
Letchworth Trail*
Bristol Hills Trail*
Link Trail*
Shawangunk Ridge Trail

Catherine Valley Trail

•
•

Catskill Scenic Trail

•

Delaware & Hudson Canal Trail

•

French and Indian Heritage Trail

•
•
•

Erie Canalway Trail*
Genesee Valley Greenway*
Ontario Pathways Rail Trail

•
•

Orange Heritage Trail
Pat McGee Trail
Wallkill Valley Rail Trail
Marden Cobb Waterway Trail
Cayuga-Seneca Canal Trail, which is a component
of the larger NYS Canalway Water Trail*
Chemung Basin River Trail*
Headwaters River Trail(s)*
Upper Delaware Scenic and Recreational River*

•
•
•
•
•
•
•

Long-distance trail of national significance
Long-distance trail of statewide significance
Long-distance trail of statewide significance
Long-distance trail of statewide significance
Long-distance trail of statewide significance
Long-distance trail of statewide significance
Long-distance trail of statewide significance
Long-distance trail of statewide significance
Long-distance hiking trail of regional significance
Long-distance hiking trail of regional significance
Long-distance hiking trail of regional significance
Long-distance hiking trail of regional significance
Long-distance hiking trail of regional significance
State-designated Heritage Trail consisting of resources in Chautauqua,
Onondaga, and Albany Counties
State-designated Heritage Trail consisting of resources in Chautauqua,
Wyoming, Ontario, Seneca, and Cayuga Counties
State-designated Heritage Trail consisting of resources in Wyoming,
Chemung, Seneca, Cayuga, Onondaga, and Madison Counties
State-designated Heritage Trail consisting of resources in Chemung, Broome
Madison, Otsego Schoharie, Sullivan and Orange Counties
State-designated Heritage Trail consisting of resources in Sullivan County
Multi-use trail located within linear corridors of open space in Chemung and
Schuyler Counties
Multi-use trail located within linear corridors of open space in Delaware
County
Multi-use trail located within linear corridors of open space in Sullivan and
Ulster Counties
Multi-use trail located within linear corridors of open space
Multi-use trail located within linear corridors of open space
Multi-use trail located within linear corridors of open space in Ontario
County
Multi-use trail located within linear corridors of open space in Orange County
Multi-use trail located within linear corridors of open space in Cattaraugus
County
Multi-use trail located within linear corridors of open space in Ulster County
Recreational water route
Recreational water route
Recreational water route
Recreational water route

Recreational water route
Proposed Triple Divide Water Trail*
Proposed recreational water route
Sources: ESRI 2010; OPRHP 2007, 2010; NPS 2010a, 2010b.
* Trail traverses one or more counties

Final SGEIS 2015, Page 2-126

 2.3.12.3

Natural Areas

This section discusses natural areas that are considered visual resources per NYSDEC Program Policy
DEP-00-2, including state forest preserve areas; state nature and historic preserves; state or national wild,
scenic and recreational rivers (designated and potential); national wildlife refuges, state game refuges, and
state wildlife management areas; and national natural landmarks (NYSDEC 2000). These natural areas
often contain scenic areas and/or are developed partly because of their associated visual or aesthetic
qualities.

The State Forest Preserve (NYS Constitution Article XIV)
The State Forest Preserve consists of lands included in the Adirondack Forest Preserve (approximately 2.6
million acres) and the Catskill Forest Preserve (approximately 290,000 acres). These lands, which
represent the majority of all state-owned property within the Adirondack and Catskill Parks, are protected
as “forever wild” under Article XIV of the New York State Constitution. They are recognized as having
exceptional scenic, recreational, and ecological value (NYSDEC 2011a, 2011b, 2011c).
The Adirondack Forest Preserve, located entirely within the Adirondack Park boundaries, is outside the
area underlain by the Marcellus and Utica Shales in New York. The Catskill Forest Preserve, located
entirely within the Catskill Park boundaries, is located within the eastern part of this area in portions of
Delaware, Greene, Ulster, and Sullivan Counties (Figure 2.12). Lands included in the Catskill Forest
Preserve are likely to contain scenic or aesthetic areas that may be considered visual resources or visually
sensitive.

State Nature and Historic Preserves (Section 4 of Article XIV of State Constitution)
State nature and historic preserves are parcels of land owned by the state that were acquired to protect the
biological diversity of plants, animals, and natural communities, and which may provide a field laboratory
for the observation of and education in these relationships. These areas may also provide for the protection
of places of historical and natural interest, and may be used by the public for passive recreational pursuits
that are compatible with protection of the ecological significance, historic features, and/or natural character
of the areas designated as state nature and historic preserves (NYSDEC 2011d).
Eight state nature and historic preserves are located in the counties within the area underlain by the
Marcellus and Utica Shales in New York (Table 2.95). These state nature and historic preserves may
contain scenic or aesthetic areas that may be considered visual resources or visually sensitive.

Final SGEIS 2015, Page 2-127

 Clinton

C A N A D A

VT

Franklin

St.
Lawrence

NY

Essex

Jefferson

NH

Lake Ontario
Oswego
Niagara

Orleans

290

Genesee

La

ke

Wyoming

ie
Er

Wayne

Yates
390

Chautauqua

Allegany

Cattaraugus

90

Ontario

Livingston

Erie

Oneida

81
Monroe

Cayuga

Seneca

Tompkins

Steuben
Chemung

86

Onondaga

Chenango

Warren

Saratoga

Fulton

Montgomery

Madison

Cortland

Schuyler

Hamilton

Washington

Herkimer

Lewis

Schenectady

Otsego

Schoharie

Rensselaer

Albany

M A


88
Tioga

Broome

Delaware

Greene

587
Columbia

Ulster

PA

CT

Dutchess

Sullivan

87
Orange

RI

Putnam
Westchester

Rockland

NJ
0

12.5

25

50
Miles

Major Water Bodies
County Boundary
State Boundary

Suffolk

Boundary of Area of
Interest for Visual Resources

National Natural Landmark

National Wild and Scenic River

National Wildlife Refuge
State Forest Preserve
State Unique Area

State Wildlife Management Area

Final SGEIS 2015, Page 2-128

Figure 2.13: Natural Areas that May
be Visually Sensitive
Source: ESRI, 2010; USGS, 2002; NYDEC, 2010; NPS, 2011;
National Atlas US and USGS, 2010

 Table 2.95 - State Nature and Historic Preserves in Counties Located within the Area
Underlain by the Marcellus and Utica Shales in New York (New August 2011)

County Name*
Allegany
Cattaraugus
Cortland

Number of State
Nature and
Historic Preserves
within County
1
1
2

Erie**

2

Onondaga**
Ontario**
Yates

1
1
2

Total

•
•
•
•
•
•
•
•
•
•

Names of State Nature
and Historic Preserves
Showy Lady Slipper Parcel (Town of New Hudson)
Zoar Valley Unique Area (Towns of Otto and Persia)
Bog Brook (Towns of Southeast and Patterson)
Labrador Hollow (Town of Truxton)
Reinstein Woods (Town of Cheektowaga)
Zoar Valley Unique Area (Town of Collins)
Labrador Hollow (Town of Fabius)
Squaw Island (Town of Canandaigua)
Parish Gully (Town of Italy)
Clark Gully (Towns of Middlesex and Italy)

8***

Sources: ESRI 2010; OPRHP 2008; NYSDEC 2011d.
*
There are no State Nature and Historic Preserves within other counties located entirely or partially within the area underlain
by the Marcellus and Utica Shales in New York.
** Only a portion of the county is located within the area underlain by the Marcellus and Utica Shales in New York.
*** Labrador Hollow is in two counties (Onondaga and Cortland); Zoar Valley Unique Area is in two counties (Cattaraugus and
Erie).

Rivers designated as National or State Wild, Scenic or Recreational (16 U.S.C. Chapter 28, ECL
15-2701 et seq.)
National Wild, Scenic or Recreational Rivers are those rivers designated by Congress or the
Secretary of the Interior in accordance with the Wild and Scenic Rivers Act of 1968. The purpose
of such designation is to preserve those rivers with outstanding natural, cultural, and recreational
values in a free-flowing condition for the enjoyment of present and future generations. Wild
rivers are those rivers or sections of rivers that are free of impoundments and generally
inaccessible except by trail, with watershed or shorelines essentially primitive and waters
unpolluted. These represent vestiges of primitive America. Scenic rivers are those rivers or
sections of rivers that are free of impoundments, with shorelines or a watershed still largely
primitive and shorelines largely undeveloped, but accessible in places by roads. Recreational
rivers are those rivers or sections of rivers that are readily accessible by road or railroad, that may
have some development along their shorelines, and that may have undergone some impoundment
or diversion in the past (National Wild and Scenic Rivers System 2011a).

Final SGEIS 2015, Page 2-129

 A portion of only one river, the Delaware River (also known as the Upper Delaware Scenic and
Recreational River), has been designated a National Wild and Scenic River in New York State
(National Wild and Scenic Rivers System 2011b, 2011c; NPS 2010c). This portion of the
Delaware River, located in Delaware County along the New York-Pennsylvania border, is within
the area underlain by the Marcellus and Utica Shales in New York (see Table 2.96 and Figure
2.13). Designated in part for its scenic qualities, this portion of the Delaware River contains
scenic areas that may be considered visual resources or visually sensitive.
A portion of one other water body in New York State, the East Branch of Fish Creek, located in
Lewis County, was studied for its potential for inclusion in the National Wild and Scenic Rivers
System (National Wild and Scenic Rivers System 2011d). This portion of Fish Creek is located
in Oneida County, which is partially located within the area underlain by the Marcellus and Utica
Shales in New York (Table 2.96).
Section 5(d) of the National Wild and Scenic Rivers Act of 1968 requires federal agencies to
consider the effects of planned use and development on potential national wild and scenic river
areas. In partial fulfillment of this requirement, the NPS has compiled and maintains a
Nationwide Rivers Inventory (NRI), which is a register of river segments that potentially qualify
as National Wild, Scenic or Recreational River areas (NPS 2008a).
In order to be listed on the NRI, a river must be free-flowing and possess one or more
Outstanding Remarkable Values (ORVs). In order to be assessed as outstandingly remarkable, a
river-related value must be a unique, rare, or exemplary feature that is significant at a comparative
regional or national scale. Such values must be directly river-related: located in the river or on its
immediate shorelands (generally within 0.25 mile on either side of the river); contribute
substantially to the function of the river ecosystem; and/or owe their location or existence to the
presence of the river. ORVs may involve values associated with scenery, recreation, geology,
fish, wildlife, prehistory, history, cultural, or other values (e.g., hydrology, paleontology, or
botany resources) (NPS 2008a).

Final SGEIS 2015, Page 2-130

 Portions of 17 NRI-listed rivers or water bodies are located partially or entirely within the area
underlain by the Marcellus and Utica Shales in New York (Table 2.96). Many of these rivers or
water bodies have been designated in part for their scenic qualities, and all of these rivers or water
bodies may contain scenic areas that may be considered visual resources or visually sensitive.
State-designated Wild, Scenic and Recreational Rivers are those rivers or portions of rivers of the
state of New York protected by the state’s Wild Scenic and Recreational Rivers Act. This act
protects those rivers of the state that possess outstanding scenic, ecological, recreational, historic,
and scientific values. Attributes of these rivers may include value derived from fish and wildlife
and botanical resources, aesthetic quality, archaeological significance, and other cultural and
historic features. State policy is to preserve designated rivers in a free-flowing condition,
protecting them from improvident development and use, and to preserve the enjoyment and
benefits derived from these rivers for present and future generations (NYSDEC 2011e).
Portions of two state-designated Wild, Scenic and Recreational Rivers - the Genesee River and
the Upper Delaware River - flow within counties located partially or entirely within the area
underlain by the Marcellus and Utica Shales in New York (Table 2.96). These rivers have been
designated, in part, for their scenic qualities, and both of these rivers may contain scenic areas that
may be considered visual resources or visually sensitive.

Final SGEIS 2015, Page 2-131

 Table 2.96 - National and State Wild, Scenic and Recreational Rivers (designated or potential) Located
within the Area Underlain by the Marcellus and Utica Shales in New York (New August 2011)
County Name*
Albany**

•

Name of River or Water Body
Portion of Catskill Creek***

•

Allegany

•

Portions of Genesee River***

•
•

Cattaraugus

•
•
•

Portions of Allegheny River
Portions of Cattaraugus Creek***
Portion of Conewango Creek ***

•
•
•

Cayuga**

•

Portion of Fall Creek***

•

Designated a State Wild, Scenic and
Recreational River

Chautauqua

•
•
•

Portion of Cattaraugus Creek***
Portion of Chautauqua Creek
Portion of Conewango Creek***

•
•
•

Listed in NRI in 1982; updated in 1995
Listed in 1982
Listed in NRI in 1982

Chemung

•

Portion of Chemung River

•

Listed in NRI in 1982

Delaware

•
•

Delaware River (Upper)***
Portions of Delaware River, East Branch

•

Erie**

•

Portions of Cattaraugus Creek***

•
•

Designated a National Wild & Scenic
River in 1978
Listed in NRI in 1982 and 1995
Listed in NRI in 1982; updated in 1995

Greene**

•

Portion of Batavia Kill

•

Listed in NRI in 1982

Livingston**

•

Portions of Genesee River***

•
•

Orange**
Steuben

•
•
•

Portion of Basher Kill ***
Portion of Canisteo River
Portion of Cohocton River

•
•
•

Listed in NRI in 1982; updated in 1995
Designated a State Wild, Scenic and
Recreational River
Listed in NRI in 1995
Listed in NRI in 1995
Listed in NRI in 1995

Sullivan**

•
•
•
•

•

•

Delaware River (Upper)***
Portion of Basher Kill***
Portion of Beaver Kill***
Portions of Neversink River, including East
and West Branches
Portion of Mongaup Creek

Tompkins

•

Portion of Fall Creek***

•

Ulster**

•
•
•

Portion of Beaver Kill***
Portion of Esopus Creek
Portions of Neversink River, including East
and West Branches

•
•
•

Wyoming

•

Portions of Genesee River***

•
•

•
•
•
•

Designation Status
Listed in NRI in 1982
Listed in NRI in 1982; updated in 1995
Designated a State Wild, Scenic and
Recreational River
Listed in NRI in 1982, updated in 1995
Listed in NRI in 1982; updated in 1995
Listed in NRI in 1982

Designated a National Wild and Scenic
River in 1978
Listed in NRI in 1995
Listed in NRI in 1992; updated in 1995
Listed in 1982 and 1995
Listed in NRI in 1995
Designated a State Wild, Scenic and
Recreational River
Listed in NRI in 1992; updated in 1995
Listed in NRI in 1995
Listed in 1982 and 1995
Listed in NRI in 1982; updated in 1995
Designated a State Wild, Scenic and
Recreational River

Sources: ESRI 2010; NPS 2008a, 2009a, 2010c; OPRHP 2008; NYSDEC 2011f.
*
There are no national or state Wild, Scenic and Recreational Rivers within other counties located entirely or partially within
the area underlain by the Marcellus and Utica Shales in New York.
** Only a portion of the county is located within the area underlain by the Marcellus and Utica Shales in New York.
*** Portions of the Genesee River are in three counties (Allegany, Wyoming, and Livingston); portions of the Beaver Kill are in
two counties (Ulster and Sullivan); portions of Cattaraugus Creek are in three counties (Erie, Cattaraugus, and Chautauqua);
Conewango Creek is in two counties (Chautauqua and Cattaraugus); Basher Kill is in two counties (Orange and Sullivan); the
Upper Delaware River is in two counties (Delaware and Sullivan); Fall Creek is in two counties (Cayuga and Tompkins).

Final SGEIS 2015, Page 2-132

 National Wildlife Refuges (16 U.S.C. 668dd), State Game Refuges and State Wildlife Management
Areas (ECL 11-2105)
National Wildlife Refuges (NWRs) are a network of lands and waters included in the National
Wildlife Refuge system and managed by the U.S. Fish and Wildlife Service. These lands and
waters are set aside for the conservation, management and, where appropriate, restoration of fish,
wildlife, and plant resources and their habitats. In addition to the task of conserving wildlife,
NWRs may also be managed for six wildlife-dependent recreational uses: hunting, fishing,
wildlife observation, photography, and environmental education and interpretation. There are
three NWRs in counties that are partially within the area underlain by the Marcellus and Utica
Shales of New York: The Iroquois NWR in Genesee and Orleans Counties; the Montezuma
NWR in Seneca and Wayne Counties; and the Shawangunk Grasslands NWR in Ulster County
(USFWS 2011). However, none of the NWRs are located within the area underlain by the
Marcellus and Utica Shales in New York (Figure 2.13).
New York State’s ECL (11-2105) defines state game refuges as lands set aside or established for
the protection of wildlife and fish. Such lands remain game refuges until the state permits the
taking of wildlife or fish within these lands. State Wildlife Management Areas (WMAs) are lands
owned by New York State that have been acquired primarily for the production and use of
wildlife, including research on wildlife species and habitat management. WMAs are under the
control and management of the Department’s DFWMR. While fishing, hunting and trapping are
the most widely practiced recreational activities on many WMAs, most also provide opportunities
for hiking, cross-country skiing, bird watching, or enjoying nature (NYSDEC 2011g).
There are 42 state game refuges or WMAs within the area underlain by the Marcellus and Utica
Shales in New York (Table 2.97 and Figure 2.13). Many of the lands included in state game
refuges or WMAs contain scenic areas that may be considered visual resources or visually
sensitive.

Final SGEIS 2015, Page 2-133

 Table 2.97 - State Game Refuges and State Wildlife Management Areas Located within the Area Underlain
by the Marcellus and Utica Shales in New York (New August 2011)

County Name*
Albany**

Number of State Game
Refuges and WMAs
2

Allegany

4

Cattaraugus

2

Chautauqua

8

Chenango
Delaware

1
2

Erie**
Greene**
Livingston**

1
1
2

Madison**
Ontario**

1
2

Orange**
Otsego**

1
2

Schoharie**
Schuyler

1
2

Seneca**
Steuben

1
4

Sullivan**

2

Tompkins
Wyoming
Yates
Total

1
1
1
42

•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•

Name of State Game Refuges or WMA
Louise E. Keir WMA
Partridge Run WMA
Alma Pond
Genesee Valley WMA
Hanging Bog WMA
Keeney Swamp WMA
Conewango Swamp WMA
Harwood Lake MUA
Alder Bottom WMA
Canadaway Creek WMA
Clay Pond WMA
Hartson Swamp WMA
Jacquins Pond WMA
Kabob WMA
Tom’s Point WMA
Watts Flats WMA
Pharsalia WMA
Bear Spring Mountain WMA
Wolf Hollow WMA
Hampton Brook Woods WMA
Vinegar Hill WMA
Conesus Inlet WMA
Rattlesnake Hill WMA
Tioughnioga WMA
Honeoye Creek WMA
Stid Hill MUA
Cherry Island WMA
Crumhorn Mountain WMA
Hooker Mountain WMA
Franklinton Vlaie WMA
Catharine Creek WMA
Waneta-Lamoka WMA
Willard WMA
Cold Brook WMA
Erwin WMA
Helmer Creek WMA
West Cameron WMA
Bashakill WMA
Mongaup Valley WMA
Connecticut Hill WMA
Silver Lake Outlet WMA
High Tor WMA

Source: ESRI 2010; NYSDEC 2011g, 2011h; USFWS 2011.
*
No other NWRs or state game refuges or wildlife management areas in New York State are located within the area
underlain by the Marcellus and Utica Shales in New York.
** Only a portion of the county is located within the area underlain by the Marcellus and Utica Shales in New York State.

Final SGEIS 2015, Page 2-134

 National Natural Landmarks [36 CFR Part 62]
National Natural Landmarks (NNLs) are sites that contain outstanding biological and/or
geological resources, regardless of land ownership, and are selected for their outstanding
condition, illustrative value, rarity, diversity, and value to science and education. NNL sites are
designated by the Secretary of the Interior, with landowner concurrence (NPS 2008b, 2009b,
2011e). Five NNLs are located within the area underlain by the Marcellus and Utica Shales in
New York (Figure 2.13 and Table 2.98). These NNLs are a combination of unique ecological
settings such as bogs or marshes and geological features (NPS 2011f). They are likely to contain
aesthetic areas that may be considered visual resources or visually sensitive.
Table 2.98 - National Natural Landmarks Located within the Area Underlain by the
Marcellus and Utica Shales in New York (New August 2011)

Name of National
County Name*
Natural Landmark
Albany
• Bear Swamp

Allegany

•

Moss Lake Bog

Cattaraugus

•

Deer Lick Nature
Sanctuary

Livingston

•

Fall Brook Gorge

•
•
•
•
•
•
•
•
•

Tompkins

•

McLean Bogs

•
•
•

Description
Designated in 1973
Low, swampy woodland with relict stands of great
laurel
Designated in 1973
Post-glacial sphagnum bog in a small kettle lake
Designated in 1967
Gorge and mature northern hardwood forest
Designated in 1970
Gorge exposing Upper and Middle Devonian Age
geological strata with fossil remains and a waterfall
Series of ecological communities developed in
response to sharply contrasting microclimates
Designated in 1973
Two spring-fed bogs, one acidic and one alkaline
Rare plant species and one of the best examples of
a northern deciduous forest in New York

Sources: ESRI 2010; NPS 2011f.
*
None of the other NNLs in New York State, including those in Genesee, Onondaga, Seneca, and Ulster Counties, are
located within the area underlain by the Marcellus and Utica Shales in New York

Final SGEIS 2015, Page 2-135

 2.3.12.4

Additional Designated Scenic or Other Areas

This section discusses additional designated scenic or other areas that are considered visual
resources or visually sensitive per NYSDEC Program Policy DEP-00-2, including sites, areas,
lakes, reservoirs, or highways designated or eligible for designation as scenic; scenic areas of
statewide significance; Adirondack Park scenic vistas; Palisades Park system components; and
national heritage areas (NYSDEC 2000). These areas often contain scenic areas and/or are
developed partly because of their associated visual or aesthetic qualities.
A site, area, lake, reservoir, or highway designated or eligible for designation as scenic (ECL
Article 49 or DOT equivalent and APA), Designated State Highway Roadside (Article 49 Scenic
Road)
Resources designated or eligible for designation as scenic can include sites, areas, lakes,
reservoirs, or highways. Many of these types of resources are discussed in other areas of the
Visual Resources section. This subsection focuses on designated scenic roads.
New York State Scenic Byways are transportation corridors that are of particular statewide
interest. They are representative of a region’s scenic, recreational, cultural, natural, historic, or
archaeological significance (NYSDOT 1999-2011). There are nine state-designated and three
proposed scenic byways within the area underlain by the Marcellus and Utica Shales in New York
(see Table 2.99). The locations of many of these are shown on Figure 2.14. There are also a
number of state-designated scenic roads in New York (NYSDOT 1999-2011). While there are 28
roads in portions of Orange and Greene Counties, these are all located outside the area underlain
by the Marcellus and Utica Shales in New York.
The Great Lakes Seaway Trail, one of the state-designated scenic byways, is also a designated
National Scenic Byway (Table 2.99 and Figure 2.14). The National Scenic Byways Program is
managed by the U.S. Department of Transportation, Federal Highway Administration. National
Scenic Byways are roads that are recognized based on one or more archaeological, cultural,
historic, natural, recreational, and scenic qualities (USDOT 2011). State and national scenic
byways and roads are resources designated specifically for scenic or aesthetic areas or qualities
and which would be considered visual resources or visually sensitive.

Final SGEIS 2015, Page 2-136

 Clinton

C A N A D A

VT

Franklin

St.
Lawrence

NY

Essex

Jefferson

NH

Lake Ontario
Oswego
Niagara

Orleans

290

Genesee

La

ke

Wyoming

ie
Er

Wayne

Yates
390

Chautauqua

Cattaraugus

Allegany

90

Ontario

Livingston

Erie

Oneida

81
Monroe

Seneca

Cayuga

Tompkins

Steuben
Chemung

86

Onondaga

Chenango

Warren

Saratoga

Fulton

Montgomery

Madison

Cortland

Schuyler

Hamilton

Washington

Herkimer

Lewis

Schenectady

Otsego

Schoharie

Rensselaer

Albany

M A


88
Tioga

Broome

Delaware

Greene

587
Columbia

Ulster

PA

CT

Dutchess

Sullivan

87
Orange

RI

Putnam
Westchester

Rockland

NJ
0

12.5

25

Major Water Bodies
County Boundary
State Boundary

Suffolk

50
Miles

Boundary of Area of
Interest for Visual Resources
State Scenic Byway

Figure 2.14: Additional Designated Scenic
or other Areas that May be
Visually Sensitive

National Scenic Byway

Scenic Areas of
Statewide Significance

Source: ESRI, 2010; USGS, 2002; NYDEC, 2010; NPS, 2011;
National Atlas US and USGS, 2010

Final SGEIS 2015, Page 2-137

 Table 2.99 - Designated and Proposed National and State Scenic Byways, Highways, and Roads Located
within the Area Underlain by the Marcellus and Utica Shales in New York (New August 2011)

Name
Great Lakes Seaway Trail

Western New York Southtowns Scenic
Byway
Cayuga Lake Scenic Byway

Scenic Route 90

Route 417/36 Scenic Byway

Seneca Lake, Hector and Lodi Scenic
Byway
Route Twenty Scenic Byway (U.S. Route
20)
Shawangunk Mountains Scenic Byway*

Route 28 Central Catskills Scenic Byway
Mountain Cloves Scenic Byway
Durham Valley Scenic Byway
Upper Delaware Scenic Byway

•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•

Description
National Scenic Byway
State-designated scenic byway
Great Lakes/Canadian border
Scenic, recreational, historic, and natural themes
State-designated scenic byway
Lake Erie
Scenic, historical, natural, recreational themes
State-designated scenic byway
Finger Lakes region of New York State
Scenic and recreational themes
State-designated scenic byway
Finger Lakes region of New York State
Scenic, recreational, natural, and historic themes
State-designated scenic byway
Finger Lakes region of New York State
Scenic, recreational, natural, and historical themes
State-designated scenic byway
Finger Lakes region of New York State
Scenic, historical, recreational, and natural themes
State-designated scenic byway
Central New York State
Scenic, natural and historic themes
State-designated scenic byway
Shawangunk Mountains
Scenic and natural themes
Proposed scenic byway
Catskill Mountains
Proposed scenic byway
Catskill Mountains
Proposed scenic byway
Catskill Mountains
State-designated scenic byway
Delaware River Valley
Scenic, natural, historic, and recreational themes

Sources: NYSDOT 1999-2011; USDOT 2011; Catskill Center for Conservation and Development 2011; Durham Valley Scenic
Byway Corridor Coordinating Committee (undated); Mountain Cloves Scenic Byway Steering Committee 2011.
*
Shawangunk Mountains Scenic Byway is adjacent to and immediately outside of the western edge of the area underlain by
the Marcellus and Utica Shales in New York.

Final SGEIS 2015, Page 2-138

 Scenic Areas of Statewide Significance (Article 42 of Executive Law)
Scenic Areas of Statewide Significance (SASS) are areas designated by the Department of State
based on a scenic assessment program developed by the Division of Coastal Resources. This
program identifies the scenic qualities of coastal landscapes, evaluates them against criteria for
determining aesthetic significance, and recommends areas for designation. An SASS designation
protects scenic landscapes through the review of projects requiring state or federal actions,
including direct actions, permits, or funding (NYSDOS 2004).
Six areas within the Hudson River Valley coastal regions in Columbia, Greene, Dutchess, and
Ulster Counties were designated as SASSs in 1993. All six of these areas are outside the area
underlain by the Marcellus and Utica Shales in New York (Figure 2.14).
Adirondack Park Scenic Vistas (Adirondack Park Land Use and Development Map)
The Adirondack Park was created in 1892 by the State of New York and is the largest publicly
protected area in the contiguous United States. The boundary of the Park encompasses
approximately 6 million acres in northern New York State, including portions of Saint Lawrence,
Franklin, Clinton, Lewis, Herkimer, Hamilton, Essex, Oneida, Fulton, Warren, Saratoga, and
Washington Counties. Nearly half of the Adirondack Park is publicly-owned and belongs to the
people of New York State; this public land is constitutionally protected to remain “forever wild”
forest preserve (Adirondack Park Agency 2003). No Adirondack Park Scenic Vistas are located
within the boundary of the area underlain by the Marcellus and Utica Shales in New York (State
of New York 2001).
Palisades Park (Palisades Interstate Park Commission)
The Palisades are a unique geological feature consisting of cliffs extending from southeastern
New York State to northwestern New Jersey. While there is no Palisades Park in New York
State, there are a number of state, county, and town parks in Orange and Rockland Counties, New
York, that are located along the Palisades, many of which are operated in conjunction with the
Palisades Interstate Park Commission. These parks include: Bear Mountain Park, Blauvelt State
Park, Bristol Beach Park, Buttermilk Falls County Park, Clausland Mountain County Park,
Franny Reese State Park, Goosepond Mountain Park, Harriman Park, Haverstraw Park, High Tor
State Park, Highland Lakes Park, Hook Mountain State Park, Lake Superior Park, Minnewaska

Final SGEIS 2015, Page 2-139

 Preserve, Mountain View Nature County Park, Nyack Beach State Park, Rockland Lake State
Park, Schunnemunk Ridge Park, Sean Hunter Ryan Memorial County Park, Sterling Forest Park,
Storm King Mountain Park, Tackamack Town Park (North and South), and Tallman State Park
(New York-New Jersey Trails Conference 1999-2011, Palisades Parks Conservancy 2003-2007).
None of these parks are located within the area underlain by the Marcellus and Utica Shales in
New York.
Bond Act Properties purchased under Exceptional Scenic Beauty or Open Space category
Bond Act Properties are properties purchased under the “Exceptional Scenic Beauty” or “Open
Space” categories of the Environmental Bond Act of 1986. Properties included in the
“Exceptional Scenic Beauty” category are defined as land forms, water bodies, geologic
formations, and vegetation that possess significant scenic qualities or significantly contribute to
scenic value. Properties included in the “Open Space” category are defined as open or natural
land in or near urban or suburban areas necessary to serve the scenic or recreational needs thereof.
Such properties are purchased by individual municipalities using grants from New York State;
grants consist of moneys raised through the sale of environmental bonds. Municipalities can
include cities; counties, towns, villages, and public benefit corporations; school districts or
improvement districts within a city, county, town or village; or Indian tribes residing within New
York state; or any combination thereof (FindLaw 2011).
The OPRHP’s Open Space Conservation Plan identifies 38 regional priority conservation projects
within the area underlain by the Marcellus and Utica Shales in New York (Table 2.100). These
projects represent the unique and irreplaceable open-space resources that encompass exceptional
ecological, wildlife, recreational, scenic, and historical values. They were identified as a result of
extensive analysis of New York State’s open-space conservation needs by nine Regional
Advisory Committees, in consultation with NYSDEC and OPRHP (OPRHP 2009). If acquired,
these projects would be considered Bond Act properties purchased under the Open Space
category. Additional previous Bond Act Properties may be located throughout the counties
located entirely or partially within the area underlain by the Marcellus and Utica Shales in New
York. Bond Act Properties purchased under the “Exceptional Scenic Beauty” or “Open Space”
categories contain, or may contain, scenic or aesthetic qualities that may be considered visual
resources or visually sensitive.

Final SGEIS 2015, Page 2-140

 Table 2.100 - Recommended Open Space Conservation Projects Located in the Area
Underlain by the Marcellus and Utica Shales in New York (New August 2011)

County Name*
Albany**

Number of
Recommended
Conservation
Projects in County
3

Name of Recommended Conservation Project

•
•

Allegany

1

•
•

Cattaraugus

3

•
•
•

Cayuga**

2

•
•

Chautauqua

5

•
•
•
•
•

Chemung

2

•
•

Chenango

1

Cortland

1

•
•

Black Creek Marsh/Vly Swamp (Project 44) – expand protection of wetland complex
Five Rivers Environmental Education Center (Project 46) – protect Phillipinkill stream
corridor to north and east of education center
Helderberg Escarpment (Project 48) – protect southern extent of this natural feature
Inland Lakes (Project 124)*** – protect undeveloped shoreline associated with
wetlands and critical tributary habitat; protect water quality and important fish and
wildlife habitat; and secure adequate public access for recreational opportunities
Allegheny River Watershed (Project 117) – protect areas for conservation,
recreational, educational, and public access purposes
Cattaraugus Creek and Tributaries (Project 119)*** – protect fisheries, recreational
access, and unique geological areas
Significant wetlands (Project 127)*** – protect significant natural wetland
communities and provide recreational, educational, and ecological enhancement
opportunities (e.g., Keeney Swamp, Bird Swamp, and Hartland Swamp)
Carpenter Falls/Bear Swamp Corridor (Project 91)*** – protect water quality,
preserve scenic resources, and expand the trail system in Bear Swamp State Forest
Summerhill Fen and Forest Complex (Project 102) – secure upland forests, wetlands,
and adjacent upland buffers along Fall Creek that are recognized for biological and
recreational significance
Cattaraugus Creek and Tributaries (Project 119)*** – protect fisheries, recreational
access, and unique geological areas
Chautauqua Lake Access, Vistas, Shore Lands and Tributaries (Project 120) – secure
public access for recreational fishing and boating, preserve undeveloped shoreline, and
protect water quality
Lake Erie Tributary Gorges (Project 125)*** – acquire public access to various gorges
along tributaries to Lake Erie
Trails and Trailways (Project 126) – protect existing trail corridors and acquire new
corridor for trails
Inland Lakes (Project 124)*** – protect undeveloped shoreline associated with
wetlands and critical tributary habitat; protect water quality and important fish and
wildlife habitat; and secure adequate public access for recreational opportunities
Catharine Valley Complex (Project 108) – preserve unique geological and ecological
areas and acquire land for recreational use of historic Chemung Canal towpath
Chemung River Greenbelt (Project 109)*** – expand and enhance significant
recreational resources in a unique scenic landscape and protect important wildlife
habitat
Genny Green Trail/Link Trail (Project 94) – acquire land for major trail connections
Develop a State Park in Cortland County (Project 92) – develop a state park

Final SGEIS 2015, Page 2-141

 County Name*
Delaware

Number of
Recommended
Conservation
Projects in County
3

Name of Recommended Conservation Project

•

•
•
Erie**

2

•
•

Livingston**

2

•
•

Madison**

2

•
•

Oneida**

1

•

Onondaga**

2

•
•

Ontario**

2

•
•

Orange**

1

•
•

Otsego**

2

•

Catskill River and Road Corridors (Project 36)*** – protect lands that serve as
riparian buffers, preserve or restore floodplain areas, protect scenic areas and vistas
along principal road corridors and on visible ridgelines, protect flood-prone areas, and
enhance public access and recreational opportunities in the following areas:
Beaverkill/Willowemoc/Route 17 (future Interstate 86) Corridor; Delaware River
Branches and Main Stem Corridors; Mongaup Valley WMA; and Route 28 Corridor
(Blue Stone Wild Forest, Ticeteneyck Mt./Tonshi Mt./Kenozia Lake, Catskill
Interpretive Center area, and Meade Hill/Fleischmann Mountain)
Upper Delaware Highlands (Project 42)*** – provide contiguous natural resource
protection for one of key remaining ecological regions in the continental U.S through
easements for forestland and farmlands and along the Upper Delaware Scenic Byway.
Susquehanna River Valley Corridor (Project 53)*** - protect areas within the
Chesapeake Bay drainage basin for water quality, fisheries, public recreation, public
access, birding, and agricultural conservation
Buffalo River Watershed (Project 118)*** – protect the Buffalo River corridor and
three of its tributaries and improve access for recreational users
Lake Erie Tributary Gorges (Project 125)***– acquire public access to various gorges
along tributaries to Lake Erie
Genesee River Corridor (Project 107)*** – protect various habitats and landscapes
along the Genesee River
Western Finger Lakes: Conesus, Hemlock, Canadice and Honeoye (Project 113)*** protect Finger Lakes shorelines that are wholly or largely undeveloped
Nelson Swamp (Project 95) – reduce ownership fragmentation of swamp, protect
biologically significant swamp, further management objective of perpetual protection,
and enhance compatible public use opportunities
Central Leatherstocking – Mohawk Grasslands Area (Project 87)*** – multi-regional
project for conservation of habitat for grassland birds (grasslands occur in portions of
Schoharie, Otsego, Oneida, Madison, and Onondaga Counties)
Central Leatherstocking – Mohawk Grasslands Area (Project 87)*** – multi-regional
project for conservation of habitat for grassland birds (grasslands occur in portions of
Schoharie, Otsego, Oneida, Madison and Onondaga Counties)
Camillus Valley/Nine Mile Creek (Project 90) – buffer important attributes of the
Nine Mile Creek Valley from development and provide public waterway access
Carpenter Falls/Bear Swamp Corridor (Project 91)*** – protect water quality,
preserve scenic resources, and expand the trail system in Bear Swamp State Forest
Hi Tor/Bristol Hills (Project 110)*** – ensure that key tracts of land remain as open
space in this area
Western Finger Lakes: Conesus, Hemlock, Canadice and Honeoye (Project 113)*** protect Finger Lakes shorelines that are wholly or largely undeveloped
Wolf Gully (Project 114) – protect for its exceptional biological diversity
Catskill River and Road Corridors (Project 36)*** – protect lands that serve as
riparian buffers, preserve or restore floodplain areas, protect scenic areas and vistas
along principal road corridors and on visible ridgelines, protect flood-prone areas, and
enhance public access and recreational opportunities in the following areas:
Beaverkill/Willowemoc/Route 17 (future Interstate 86) Corridor; Delaware River
Branches and Main-stem Corridors; Mongaup Valley WMA; and Route 28 Corridor
(Blue Stone Wild Forest, Ticeteneyck Mt./Tonshi Mt./Kenozia Lake, Catskill
Interpretive Center area and Meade Hill/Fleischmann Mountain)
Susquehanna River Valley Corridor (Project 53)*** - protect areas within the
Chesapeake Bay drainage basin for water quality, fisheries, public recreation, public
access, birding and agricultural conservation

Final SGEIS 2015, Page 2-142

 County Name*

Number of
Recommended
Conservation
Projects in County

Name of Recommended Conservation Project

•
Schoharie**

1

•

Seneca**

1

•

Steuben

1

•

Sullivan**

4

•

•

•

•
Tioga

Tompkins

2

2

•
•
•
•

Ulster**

3

•
•

Central Leatherstocking – Mohawk Grasslands Area (Project 87)*** – multi-regional
project for conservation of habitat for grassland birds (grasslands occur in portions of
Schoharie, Otsego, Oneida, Madison, and Onondaga Counties)
Central Leatherstocking – Mohawk Grasslands Area (Project 87)*** – multi-regional
project for conservation of habitat for grassland birds (grasslands occur in portions of
Schoharie, Otsego, Oneida, Madison, and Onondaga Counties)
Seneca Army Depot Conservation Area (Project 111) – protect a unique population of
white deer
Chemung River Greenbelt (Project 109)*** – expand and enhance significant
recreation resources in a unique scenic landscape and protect important wildlife
habitat
Neversink Highlands (Project 28) – protect significant natural attractions and
resources, hunting and fishing opportunities, and wildlife habitat in the following
areas: Tomsco Falls, Neversink Gorge vicinity, Basha Kill vicinity and Harlen Swamp
Wetland Complex
Catskill River and Road Corridors (Project 36)*** – protect lands that serve as
riparian buffers, preserve or restore floodplain areas, protect scenic areas and vistas
along principal road corridors and on visible ridgelines, protect flood-prone areas, and
enhance public access and recreational opportunities in the following areas:
Beaverkill/Willowemoc/Route 17 (future Interstate 86) Corridor; Delaware River
Branches and Main-stem Corridors; Mongaup Valley WMA; and Route 28 Corridor
(Blue Stone Wild Forest, Ticeteneyck Mt./Tonshi Mt./Kenozia Lake, Catskill
Interpretive Center area and Meade Hill/Fleischmann Mountain)
New York City Watershed Lands (Project 39) – identify and protect high-priority sites
on land that have potential for development, for forestry, or for fisheries and relatively
large and/or link area already protected by private or public entities and/or allow for
improved long-term management of land and water resources
Upper Delaware Highlands (Project 42)*** – provide contiguous natural resource
projection for one of key remaining ecological regions in the continental U.S through
easements for forestland and farmlands and along the Upper Delaware Scenic Byway
Two Rivers State Park (Project 103) – develop a state park
Emerald Necklace (Project 104) – consolidate existing state holdings while ensuring
linkage between public land in the vicinity of Ithaca, conserve lands, and enhance
recreational opportunities
State Parks Greenbelt/Tompkins County (Project 101) – protect valuable open-space
recreational resources between four state park facilities connected by the Black
Diamond Trail Corridor
Finger Lakes Shorelines (Project 105) – preserve portions of the shoreline of the
Finger Lakes for public access or wildlife in the following areas or projects: Finger
Lakes Water Trails, Owasco Flats, Camp Barton, On Cayuga Lake, B&H Railroad
property at the south end of Keuka Lake in Hammondsport, extending the eastern
terminus of the Outlet Trail to the Seneca Lake shoreline at Dresden, and undeveloped
shoreline on Seneca Lake
Great Rondout Wetlands (Project 24) – protect several large wetlands in the following
areas: Great Pacama Vly, Cedar Swamp and Beer Kill Wetlands/Cape Pond
Catskill River and Road Corridors (Project 36)*** – protect lands that serve as
riparian buffers, preserve or restore floodplain areas, protect scenic areas and vistas
along principal road corridors and on visible ridgelines, protect flood-prone areas, and
enhance public access and recreational opportunities in the following areas:
Beaverkill/Willowemoc/Route 17 (future Interstate 86) Corridor; Delaware River
Branches and Main-stem Corridors; Mongaup Valley WMA; and Route 28 Corridor
(Blue Stone Wild Forest, Ticeteneyck Mt./Tonshi Mt./Kenozia Lake, Catskill
Interpretive Center area, and Meade Hill/Fleischmann Mountain)

Final SGEIS 2015, Page 2-143

 County Name*

Number of
Recommended
Conservation
Projects in County

Name of Recommended Conservation Project

•

Wyoming

3

•
•
•

Yates

1

•

Catskills Unfragmented Forest (Project 37) – securing additional large unfragmented
areas of forestlands in the Catskill High Peaks areas, including the following sites :
Overlook Mountain; Guardian Mountain; Indian Head Wilderness Consolidation;
Balsam, Graham and Doubletop Mountains/Dry Brook Valley; Peekamoose Gorge;
Frost Valley; Fir Brook/Round Pond/Black Bear Road Vicinity; West
Shokan/Sampsonville Area Lands; Bearpen/Vly/Roundtop Mountains; Catskill
Escarpment North and Windham High Peak; Rusk Mountain Wild Forest; Hunter
West Kill Wilderness; and Catskill Mountain Heritage Trail
Buffalo River Watershed (Project 118)*** – protect the Buffalo River corridor and
three of its tributaries and improve access for recreational users
Inland Lakes (Project 124)*** – protect undeveloped shoreline associated with
wetlands and critical tributary habitat; protect water quality and important fish and
wildlife habitat; and secure adequate public access for recreational opportunities
Inland Lakes (Project 124)*** – protect undeveloped shoreline associated with
wetlands and critical tributary habitat; protect water quality and important fish and
wildlife habitat; and secure adequate public access for recreational opportunities
Hi Tor/Bristol Hills (Project 110)*** – ensure that key tracts of land remain as open
space in this area

Total
38***
Source: OPRHP 2009.
*
No other recommended conservation projects are located within the area underlain by the Marcellus and Utica Shales in New
York.
** Only a portion of the county is located within the area underlain by the Marcellus and Utica Shales.
*** Susquehanna River Valley Corridor (Project 53) is in two counties (Otsego and Delaware); Cattaraugus Creek and Tributaries
(Project 119) is in two counties (Cattaraugus and Chautauqua); Carpenter Falls/Bear Swamp Corridor (Project 91) may be in
two counties (Cayuga and Onondaga); Lake Erie Tributary Gorges (Project 125) may be in two counties (Chautauqua and
Erie); Central Leatherstocking – Mohawk Grasslands Area (Project 87) may occur in multiple counties (Schoharie, Otsego,
Oneida, Madison and Onondaga); Catskill River and Road Corridors (Project 36) may occur in multiple counties (Delaware,
Sullivan, Orange and Ulster); Catskill River and Road Corridors (Project 36) may occur in two counties (Delaware and
Sullivan); Buffalo River Watershed (Project 118) will occur in two counties (Erie and Wyoming); Genesee River Corridor
(Project 107) may occur in multiple counties from the New York/Pennsylvania state line to Lake Ontario; Western Finger
Lakes: Conesus, Hemlock, Canadice and Honeoye (Project 113) will occur in two counties (Livingston and Ontario);
Chemung River Greenbelt (Project 109) will occur in two counties (Chemung and Steuben); Inland Lakes (Project 124) is in
three counties (Allegany, Chautauqua, and Wyoming); Hi Tor/Bristol Hills (Project 110) is in two counties (Yates and
Ontario); Significant wetlands (Project 127) may occur in numerous counties.

2.3.13 Noise 47
2.3.13.1

Noise Fundamentals

Noise is defined as any unwanted sound. Sound is defined as any pressure variation that the
human ear can detect. Humans can detect a wide range of sound pressures, but only the pressure
variations occurring within a particular set of frequencies are experienced as sound. However, the
acuity of human hearing is not the same at all frequencies. Humans are less sensitive to low
frequencies than to mid-frequencies, and so noise measurements are often adjusted (or weighted)
to account for human perception and sensitivities. The unit of noise measurement is a decibel
47

Subsection 2.4.13, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011 and was adapted
by the Department.

Final SGEIS 2015, Page 2-144

 (dB). The most common weighting scale used is the A-weighted scale, which was developed to
allow sound-level meters to simulate the frequency sensitivity of human hearing. Sound levels
measured using this weighting are noted as dBA (A-weighted decibels). (“A” indicates that the
sound has been filtered to reduce the strength of very low and very high frequency sounds, much
as the human ear does.) The A-weighted scale is logarithmic, so an increase of 10 dB actually
represents a sound that is 10 times louder. However, humans do not perceive a 10-dBA increase
as 10 times louder but as only twice as loud.
The following is typical of human responses to changes in noise level:
•

A 3-dBA change is the threshold of change detectable by the human ear;

•

A 5-dBA change is readily noticeable; and

•

A 10-dBA change is perceived as a doubling (or halving) of noise level.

The decrease in sound level from any single noise source normally follows the “inverse square
law.” That is, sound pressure level (SPL) changes in inverse proportion to the square of the
distance from the sound source. At distances greater than 50 feet from a sound source, every
doubling of the distance produces a 6-dB reduction in the sound level. Therefore, a sound level of
70 dB at 50 feet would have a sound level of approximately 64 dB at 100 feet. At 200 feet, sound
from the same source would be perceived at a level of approximately 58 dB.
The total sound pressure created by multiple sound sources does not create a mathematical
additive effect. For example, two proximal noise sources that are 70 dBA each do not have a
combined noise level of 140 dBA. In this case the combined noise level is 73 dBA. As the
difference between the two sound levels is 0 dB, 3 dB are added to the sound level to compensate
for the additive effects of the sound.
To characterize the average ambient noise (“noise”) environment in a given area, noise level
descriptors are commonly used. The Leq (sound level equivalent) is generally used to
characterize the average sound energy that occurs during a relatively short period, such as an
hour. The Ldn (day-night level) would be used for an entire 24-hour period. To account for
peoples’ greater sensitivity to sound during nighttime hours, the Ldn noise metric descriptor

Final SGEIS 2015, Page 2-145

 places a stronger emphasis on noise that occurs during nighttime hours (10 p.m. to 7 a.m.) by
applying a 10-dB “penalty” to those hours. The Lmax refers to the maximum A-weighted noise
level recorded for a single noise event during a given period.
Although both the sound power and sound pressure characteristic of sound share the same unit of
measure, the decibel (dB), and the term “sound level” is commonly substituted for each, they
have different properties. Sound power is the acoustical energy emitted by the sound source, and
is an absolute value; it is not affected by the environment. The SPL is the varying difference, at a
fixed point, between the pressure caused by a sound wave and atmospheric pressure. Sound
pressure is what our ears hear and what sound level meters measure. The sound power level is
always considerably higher than the sound pressure level near a source because it takes into
account the effective radiating surface area of the source.
2.3.13.2

Common Noise Effects

Common noise effects include speech interference, sleep disturbance, and annoyance.
Speech Interference
The interference with speech comprehension is a masking process in which environmental noise
curtails or prevents speech perception. The United States Environmental Protection Agency
(USEPA) established the relationship between percent speech intelligibility and continuous noise
level (USEPA 1974). This relationship is presented in Figure 2.15

Final SGEIS 2015, Page 2-146

 Figure 2.15 - Level of Continuous Noise Causing Speech Interference (New August 2011)

100

Percentage Sentence Interference

90
80
70
60
50
40
30
20
10
0
50

55

60

63 65 67 68 69 70.5 72 71.5 74
Ldn Level of Continuous Noise (dB)

75

Source: USEPA 1974.

Sleep Disturbance
Exposure to noise can produce disturbances of sleep in terms of difficulty to fall asleep,
alterations of sleep pattern and depth, and awakening. It should be noted that the adverse effect of
noise on sleep partly depends on the nature of the noise source, and there are considerable
differences in individual reactions to the same noise. To avoid sleep disturbance, the World
Health Organization (WHO) recommends an indoor level in bedrooms of 30 dBA for continuous
noise and an Lmax of 45 dBA for single sound events (WHO 2000).
Annoyance
The capacity of noise to induce annoyance depends upon many of its physical characteristics,
including its SPL and spectral characteristics, as well as the variations of these properties over
time. Numerous studies have been conducted to assess community annoyance in response to
transportation noise sources. A summary of community annoyance is presented in Table 2.101.

Final SGEIS 2015, Page 2-147

 Table 2.101 - Effects of Noise on People (New August 2011)

Ldn (dBA)
> 75

Percent
Annoyance
37

Average
Community
Reaction
Very Severe

70

22

Severe

65

12

Significant

60

7

Moderate

< 55

3

Slight

General Community Attitude Towards Area
Noise is likely to be the most important of all
adverse aspects of the community environment.
Noise is one of the most important adverse
aspects of the community environment.
Noise is one of the important adverse aspects of
the community environment.
Noise may be considered an adverse aspect of
the community environment.
Noise is considered no more important than
various other environmental factors.

Source: Cowan 1994.

2.3.13.3

Noise Regulations and Guidance
Federal

In 1974 the USEPA published Information on Levels of Environmental Noise Requisite to Protect
Public Health and Welfare with an Adequate Margin of Safety (USEPA 1974). This publication
evaluates the effects of environmental noise with respect to health and safety. The document
provides information for state and local governments to use in developing their own ambient
noise standards. The USEPA has determined that in order to protect the public from activity
interference and annoyance outdoors in residential areas, noise levels should not exceed an Ldn of
55 dBA (Table 2.102). The USEPA considers an Ldn of 55 dBA to be the maximum sound level
that will not adversely affect public health and welfare by interfering with speech or other
activities in outdoor areas.

Final SGEIS 2015, Page 2-148

 Table 2.102 - Summary of Noise Levels Identified as Requisite to Protect Public Health
and Welfare with an Adequate Margin of Safety (New August 2011)

Effect
Hearing Loss
Outdoor activity interference
and annoyance

Level
Leq(24) =< 70 dB
Ldn =< 55 dB

Leq(24) =< 55 dB

Indoor activity interference and
annoyance

Ldn =< 45 dB
Leq(24) =< 45 dB

Area
All areas
Outdoors in residential areas
and farms and other outdoor
areas where people spend
widely varying amounts of time
and other places in which quiet
is a basis for use
Outdoor areas where people
spend limited amounts of time,
such as school yards,
playgrounds, etc.
Indoor residential areas
Other indoor areas with human
activities such as schools, etc.

Source: USEPA 1974.

New York State
The Department has issued Program Policy DEP-00-1, Assessing and Mitigating Noise Impacts,
which is intended to provide direction to Department staff for the evaluation of sound levels and
characteristics generated from proposed or existing facilities. Under this policy, in the review of
an application for a permit, the Department is to evaluate the potential for adverse impacts of
sound generated and emanating to receptors outside of the facility or property. When a sound
level evaluation indicates that receptors may experience sound levels or characteristics that
produce significant noise impacts or impairment of property use, the Department is to require the
permittee or applicant to employ reasonable and necessary measures to either eliminate or
mitigate adverse noise effects.
In the Department policy, noise is defined as any loud, discordant, or disagreeable sound or
sounds. More commonly, in an environmental context, noise is defined simply as unwanted
sound. The environmental effects of sound and human perceptions of sound can be described in
terms of the following four characteristics:
1. SPL, or perceived loudness, as expressed in decibels (dB) or A-weighted decibel scale
dBA, which is weighted towards those portions of the frequency spectrum, between 20
and 20,000 Hertz, to which the human ear is most sensitive. Both measure sound pressure
in the atmosphere.

Final SGEIS 2015, Page 2-149

 2. Frequency (perceived as pitch), the rate at which a sound source vibrates or makes the air
vibrate.
3. Duration, i.e., recurring fluctuation in sound pressure or tone at an interval; sharp or
startling noise at recurring interval; the temporal nature (continuous vs. intermittent) of
sound.
4. Pure tone, which is comprised of a single frequency. Pure tones are relatively rare in
nature but, if they do occur, they can be extremely annoying.
The initial evaluation for most facilities should determine the maximum amount of sound created
at a single point in time by multiple activities for the proposed project. All facets of the
construction and operation that produce noise should be included, such as land-clearing activities
(chain saw and equipment operation), drilling, equipment operation for excavating, hauling or
conveying materials, pile driving, steel work, material processing, and product storage and
removal. Land clearing and construction may be only temporary noise at the site, whereas the
ongoing operation of a facility would be considered permanent noise.
The Department Noise Guidelines state that increases ranging from 0 to 3 dB will have no
appreciable effect on receptors, and that increases from 3 to 6 dB have potential for adverse noise
impact only in cases where the most sensitive receptors are present. Sound pressure increases of
more than 6 dB may require additional analysis of impact potential, depending on existing sound
pressure levels and the character of surrounding land uses and receptors, and an increase of 6
dB(A) may cause complaints. Therefore, a cumulative increase in the total ambient sound level
of 6 dBA or less is unlikely to constitute an adverse community impact.
To aid staff in its review of a potential noise impact, Program Policy DEP-00-1 identifies three
major categories of noise sources:
•

Fixed equipment or process operations,

•

Mobile equipment or process operations, and

•

Transport movements of products, raw material or waste.

Final SGEIS 2015, Page 2-150

 2.3.13.4

Existing Noise Levels

The ambient sound level of a region is defined by the total noise generated, including sounds from
natural and man-made sources. The magnitude and frequency of environmental noise may vary
considerably over a day and throughout the week because of changing weather conditions and the
effects of seasonal vegetative cover. Table 2.103 presents SPLs that are characteristic for the land
use described. Most of the high-volume hydraulic fracturing would occur in quiet rural areas
where the noise levels are typically as low as 30 dBA, depending on weather conditions and
natural noise sources.
Table 2.103 - Common Noise Levels (New August 2011)

Description
Rural area at night
Quiet suburban area at night
Typical suburban area
Typical urban area

SPL
(dBA)
30
40
50
60

Source: Cowan 1994.
SPL = sound pressure level.

2.3.14 Transportation - Existing Environment 48
This section presents a general overview of the vehicle and road classification system, major
roadways and roadway use in the regional areas, and the primary funding sources for the roadway
improvements. Although roadways would be the primary transportation system used to access
well sites, railroads and airports may also be used to transport equipment and supplies. These
other transportation modes are also briefly discussed.
2.3.14.1

Terminology and Definitions

The following terms are defined at the federal level to describe roadway classifications and
vehicle classes and are used by transportation planners and engineers at the state and local levels.

48

Subsection 2.4.14, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011 and was adapted
by the Department.

Final SGEIS 2015, Page 2-151

 Federal Functional Classification Codes
The federal functional classification (FC) codes group streets, roads, and highways into several
classes based on the construction type and the type of service the roads provide. This discussion
focuses on the roads prevalent in rural areas, where most of the horizontal drilling and highvolume hydraulic fracturing is assumed to occur.
Rural areas have five basic classifications of roads:
•

FC01/FC02 - Principal Arterial (Interstate or Other);

•

FC06 - Minor Arterial;

•

FC07 – Major Collector;

•

FC08 – Minor Collector; and

•

FC09 – Local.

Typically, the higher the road classification, the higher the level of service a road can supply to
vehicles, whether measured by vehicle class/weight or number of vehicle trips.
The arterial system of roadways provides the highest level of mobility at the highest speed, for
long, uninterrupted travel. The construction of roads in the arterial system follows stringent
guidelines, and high-grade materials are used. These roads can support more of the heavy vehicle
truck traffic than smaller, local roads. The minor collectors (FC08) and, to a larger extent, the
local roads (FC09) show signs of deterioration with an increase in heavy-truck traffic.
•

Principal Arterial. The Principal Arterial categories are often divided into Principal
Arterial - Interstate, and Principal Arterial - Other. Arterials generally are constructed
according to higher design standards than other roads, often have multiple lanes traveling
in the same direction, and have some degree of access control, such as on ramps.

The rural principal arterial highway network is an interstate and inter-county roadway that
connects developed areas with an urban population typically greater than 50,000 people.
•

Minor Arterial. A rural minor arterial highway is a roadway that is considered serving an
urban area if it comes within 2 miles of the urban boundary.

Final SGEIS 2015, Page 2-152

 Collector roadways provide a lower degree of mobility than arterials and are not designed for
long-distance or high-speed travel. They typically consist of two-lane roads that collect and
distribute traffic from the arterial system. They are divided into two categories in the rural
setting - Major Collectors and Minor Collectors.
•

Major Collector. Major Collectors provide service to any county seat not on an arterial
route and can also connect or serve larger towns that are not provided services by their
arterial roads.

•

Minor Collector. Minor Collectors are roadways that are spaced consistently and
proportional to population densities present in the rural community. They collect traffic
from local roads and provide access to higher-level roads.

Local roads are the largest category of roads in terms of mileage in the road network. In rural
areas, they include all public roads below the collector system, including basic residential and
commercial roads.
There is an inverse relationship between the speeds and distances traveled on roads versus the
actual existing mileage of the various road systems. The arterial systems account for higher
average vehicle miles per trip (VMT), while local road systems account for the vast majority of
actual roads (Table 2.104).
Table 2.104 - Guidelines on Extent of Rural Functional Systems (New August 2011)

System
Principal Arterial System
Principal Arterial plus Minor
Arterial Road System
Collector Road System
Local Road System

Range
(Average Vehicle
Miles per Trip [VMT])
30-55
45-75

Miles of Road
(percent)
2-4
6-121

20-35
5-20

20-25
65-75

Source: FHWA 2011.
1
Most states fall in the 7-10% range.

The FC codes have recently been updated; however, the codes presented in this section
correspond to the codes used in data compilations that are currently available.

Final SGEIS 2015, Page 2-153

 FHWA Vehicle Classes with Definitions
Figure 2.16 presents the Federal Highway Administration’s (FHWA) vehicle class definitions
(FHWA 2011). Table 2.105 provides descriptions of the 13 vehicle classes designated by the
FHWA.
Figure 2.16 - FHWA Vehicle Classifications (New August 2011)

Source: Diamond Traffic Products 2011.

Final SGEIS 2015, Page 2-154

 Table 2.105 - Descriptions of the Thirteen FHWA Vehicle Classification Categories (New August 2011)

Vehicle
Class
1

2

3

4

5

6
7
8
9
10
11
12
13

Description
Motorcycles. All two- or three-wheeled motorized vehicles. Typical vehicles in this
category have saddle-type seats and are steered by handlebars rather than steering wheels.
This category includes motorcycles, motor scooters, mopeds, motor-powered bicycles,
and three-wheel motorcycles. This vehicle type may be reported at the option of the
state.
Passenger Cars. All sedans, coupes, and station wagons manufactured primarily for the
purpose of carrying passengers and including those passenger cars pulling recreational or
other light trailers.
Other Two-Axle, Four-Tire Single Unit Vehicles. All two-axle, four-tire vehicles other
than passenger cars. Included in this classification are pickup and panel trucks, vans, and
other vehicles such as campers, motor homes, ambulances, hearses, carryalls, and
minibuses. Other two-axle, four-tire single-unit vehicles pulling recreational or other
light trailers are included in this classification. (Note: Because automatic vehicle
classifiers have difficulty distinguishing class 3 from class 2, these two classes may be
combined into class 2).
Buses. All vehicles manufactured as traditional passenger-carrying buses with two axles
and six tires or three or more axles. This category includes only traditional buses
(including school buses) functioning as passenger-carrying vehicles. Modified buses
should be considered to be a truck and should be appropriately classified.
Two-Axle, Six-Tire, Single-Unit Trucks. All vehicles on a single frame, including
trucks, camping and recreational vehicles, motor homes, etc., with two axles and dual rear
wheels.
Three-Axle, Single-Unit Trucks. All vehicles on a single frame, including trucks,
camping and recreational vehicles, motor homes, etc., with three axles.
Four or More Axle, Single-Unit Trucks. All trucks on a single frame with four or more
axles.
Four or Fewer Axle, Single-Trailer Trucks. All vehicles with four or fewer axles,
consisting of two units, one of which is a tractor or straight truck power unit.
Five-Axle, Single-Trailer Trucks. All five-axle vehicles consisting of two units, one of
which is a tractor or straight truck power unit.
Six or More Axle, Single-Trailer Trucks. All vehicles with six or more axles,
consisting of two units, one of which is a tractor or straight truck power unit.
Five or Fewer Axle, Multi-Trailer Trucks. All vehicles with five or fewer axles,
consisting of three or more units, one of which is a tractor or straight truck power unit.
Six-Axle, Multi-Trailer Trucks. All six-axle vehicles consisting of three or more units,
one of which is a tractor or straight truck power unit.
Seven or More Axle, Multi-Trailer Trucks. All vehicles with seven or more axles,
consisting of three or more units, one of which is a tractor or straight truck power unit.

Source: FHWA 2001.
Notes: In reporting information on trucks, the following criteria should be used:
Truck tractor units traveling without a trailer will be considered single-unit trucks.
A truck tractor unit pulling other such units in a “saddle mount” configuration will be considered one single-unit
truck and will be defined only by the axles on the pulling unit.
Vehicles are defined by the number of axles in contact with the road. Therefore, “floating” axles are counted only
when in the down position.
The term “trailer” includes both semi- and full trailers.

Final SGEIS 2015, Page 2-155

 Not included in the FHWA Vehicle Classification Categories are farm and agricultural
equipment, which are common in the rural areas. Many of the rural roads are shared by passenger
traffic, truck traffic, and farm and agricultural equipment.
2.3.14.2

Regional Road Systems
New York State

The NYSDOT, acting through the Commissioner of Transportation, has general supervision of
roads, highways, and bridges in the State of New York. The functions, powers and duties of the
Commissioner of Transportation and the NYSDOT, respectively, are more fully described in
Article II of the Highway Law and Article 2 of the Transportation Law. It is the mission of the
NYSDOT to ensure that those who live, work, and travel in New York State have a safe, efficient,
balanced, and environmentally sound transportation system.
The NYSDOT is divided into 11 regions to better manage the roadways, duties, and users (Figure
2.17).
Figure 2.17 - New York State Department of Transportation Regions (New August 2011)

Source: NYSDOT 2011a

The network of roads within New York State consists of federal, state, county, local, and private
roads. Overall, there are an estimated 114,546 miles of highway roads in the state. This includes
32 interstate highways (principal arterials) totaling 1,705 miles, which are primarily maintained
by the NYSDOT.

Final SGEIS 2015, Page 2-156

 Figure 2.18 depicts the main interstate highways in New York State. The New York State
Thruway, also known as the Governor Thomas E. Dewey Thruway (Interstate (I-) 90) is the main
east-west route that crosses the midsection of the state, linking Buffalo, Rochester, Syracuse, and
Albany. The New York State Thruway is a system of limited-access highways in New York State
operated by the New York State Thruway Authority (NYSTA). It includes a total of
approximately 570 miles (that is comprised of portions of I-87, I-90, I-95, I-190, and I-287). The
Southern Tier Expressway, I-86, also is a major east-west route that services that southern portion
of the state, connecting Jamestown, Olean, Elmira, and Binghamton. From Binghamton, I-86
runs southeast, providing access to New York City, and I-88 runs northeast providing access to
Albany. Major north-south routes include I-81, which extends from Pennsylvania north through
Binghamton and Syracuse to the border crossing with Canada, and I-87, which extends from New
York City north to Montreal.
The state’s transportation and road network also includes over 15,000 miles of state routes and
97,000 miles of county and local roads (NYSDOT 2009a). Each region examined as part of this
analysis is discussed individually below.
The NYSDOT has specific, statutory authority to regulate work within the state highway rightsof-way (ROWs) (see Highway Law Section 52). This authority extends to granting, conditioning,
or denying permits for, among many other things, curb cuts or breaks in access to state highways,
utility work within the state ROWs that would be necessary for the operation of hydraulic
fracturing facilities, and design approval for any new culverts, bridges, access roads, etc., on state
ROWs that may become necessary for the construction or operation of hydraulic fracturing
facilities.
Region A
Region A comprises Chemung, Tioga, and Broome Counties, which are within NYSDOT
Regions 6 (Chemung) and 9 (Tioga and Broome). Table 2.106 presents a summary of the
mileage of highways within each county. The Highway Mileage Report developed by NYSDOT
provides current information on the public highway mileage in New York State by county
(NYSDOT 2009a).

Final SGEIS 2015, Page 2-157

 ME
Clinton

CSXT

C A N A D A

Franklin

St.
Lawrence

CPRS

Jefferson

VT

Essex

Watertown

Niagara

Niagara
Falls
North Tonawanda

Genesee

290

Buffal o

ke

E

Roches ter
Monroe

Wyoming

NS
Chautauqua

Cattaraugus

81

CSXT

Wayne
90

Ontari o

Livingston

La

CSXT

rie

Erie

Oswego

Yates

Syracuse
Onondaga

Auburn
Cayuga

Rome

CSXT

Cortland

Uti ca

Sarat oga
Spr ings
Montgomery
Schenectady
Schenectady
Troy
Rensse laer
Albany
CPRS

Otsego

Schoharie

390

86

Allegany

Steuben

Schuyler It haca
Chemung

Elmira Tioga
NS Bingham ton

James town

Saratoga

Fulton

Madison

Chenango

N H


Warren

NY

Oneida

Seneca

Tompkins

Hamilton

Was hing ton

Orleans

Her kim er

Lewis

Lake Ontario

Albany

M A


88

Broome

Greene

Delaware

Columbia
Ulster

587

CSXT

Dutchess

87

PA

Newburgh

Sullivan

NS
Middletown

Orange
Rockland

0

12.5

25

Westchester

City with Year 2000
Population Greater than 25,000

Commercial Airports
Railroad


Yonkers
Moun t Vernon
New York
Valley
Stream

50
Miles

Interstate


RI

Putnam

Spring Valley

NJ

CT

Poughkeepsie

White Plains
Port Chester
New Rochelle

Suffolk

Hempstead
Lindenhurst
Freeport
Long Beach

Figure 2.18: Transportation

County Boundary
State Boundary


Source: ESRI, 2010; USGS, 2002


Final SGEIS 2015, Page 2-158

 Table 2.106 - Region A: Highway Mileage by County, 2009 (New August 2011)

Chemung
Tioga
Broome
Total Region A

Town or
Village
766.7
823.7
1,340.1
2,930.5

County
243.7
141.7
339.1
724.5

NYSDOT
Owned
118.4
155.2
297.3
570.9

Other
3.6
0.0
19.6
23.2

Total
1,132.4
1,120.6
1,996.1
4,249.1

Source: NYSDOT 2009a.

The principal arterial in Region A is the Southern Tier Expressway (I-86/NY-17), which runs
east-west through the three counties that constitute Region A. This highway connects Elmira and
areas west of the region with Binghamton and areas east of the region. Another major highway, I81, intersects I-86 in Binghamton and runs north to Syracuse and south to Scranton, Pennsylvania.
In addition, I-88 originates in Binghamton and runs northeast to Albany (Figure 2.18)
Numerous other arterials, collectors, and local roadways cover this region and connect smaller
towns and villages. Heavy vehicles (i.e., Vehicle Classifications 04 through 13) primarily use
major roadways. NYSDOT conducted a study of the road use by heavy vehicle traffic, based on
2004 to 2009 data (NYSDOT 2010a). The data for rural areas in NYSDOT Regions 6 and 9 are
presented in Table 2.107.
Table 2.107 - Heavy Vehicles as a Percentage of Total Vehicles in Rural Areas in
NYSDOT Regions 6 and 9, 2004-2009 (New August 2011)

Functional
Classification (FC)
Code
01
02
06
07
08
09

NYSDOT
Region 6
36.0%
15.5%
10.2%
10.9%
5.7%*
-*

NYSDOT
Region 9
25.1%
13.6%
10.2%
8.7%
6.8%
6.4%

Source: NYSDOT 2010a.
* No data or insufficient data (i.e., data from <10 highway segments).

Final SGEIS 2015, Page 2-159

Statewide
25.2%
12.5%
9.5%
8.9%
6.8%
7.1%

 Heavy-vehicle traffic is concentrated on major roadways, with FC road classifications 01 and 02
handling 51.5% and 38.7%, respectively, of heavy-vehicle traffic in NYSDOT Regions 6 and 9.
Compared to the statewide percentage (37.7%), in both Regions 6 and 9, heavy-vehicle traffic is
concentrated more on principal arterial roadways and less on other roads. Since FC01 and FC02
are arterials used primarily for long-distance, high-speed travel, the majority of this traffic is
assumed to pass through the counties.
Region B
Region B comprises Otsego, Delaware, and Sullivan Counties, all of which are in NYSDOT
Region 9. Table 2.108 presents a summary of the mileage of highways within each county. The
Highway Mileage Report developed by NYSDOT provides current information on the public
highway mileage in New York State by county (NYSDOT 2009a).
Table 2.108 - Region B: Highway Mileage by County, 2009 (New August 2011)

Otsego
Delaware
Sullivan
Total Region B

Town or
Village
1,326.2
1,608.4
1,462.1
4,396.7

County
476.6
262.0
385.3
1,123.9

NYSDOT
Owned
290.4
341.1
201.9
833.4

Other
4.2
37.5
10.6
52.3

Total
2,097.4
2,248.9
2,059.9
6,406.2

Source: NYSDOT 2009a.

The road network in Region B has two main roadway corridors running through different sections
of the three counties. One is I-88, which runs in a southwest-northeast direction along the border
of Otsego and Delaware Counties. In addition, NY-17 runs from the western portion of Delaware
County to the east and southeast, along the Catskill Forest Preserve, into Sullivan County and
towards New York City (Figure 2.18).
Numerous other arterials, collectors, and local roadways cover this region and connect smaller
towns and villages. Heavy vehicles primarily use major roadways. A NYSDOT study used
vehicle classification data from 2004 to 2009 to estimate the percentage of heavy vehicles on
various road classifications in rural and urban settings (NYSDOT 2010a). The data for rural areas
in NYSDOT Region 9 are presented in Table 2.109.

Final SGEIS 2015, Page 2-160

 Table 2.109 - Heavy Vehicles as a Percentage of Total Vehicles in Rural Areas in
NYSDOT Region 9, 2004-2009 (New August 2011)

Functional
Classification (FC)
Code
01
02
06
07
08
09

NYSDOT
Region 9
25.1%
13.6%
10.2%
8.7%
6.8%
6.4%

Statewide
25.2%
12.5%
9.5%
8.9%
6.8%
7.1%

Source: NYSDOT 2010a.

Heavy-vehicle traffic is concentrated on major roadways, with FC road classifications 01 and 02
handling 38.7% of heavy-vehicle traffic in NYSDOT Region 9. Compared to the statewide
percentage (37.7%), in Region 9, heavy-truck traffic is concentrated more on principal arterials
and a less on other roads.
Region C
Region C comprises Chautauqua and Cattaraugus Counties, both of which are in NYSDOT
Region 5. Table 2.110 presents a summary of the mileage of highways in each county. The
Highway Mileage Report developed by NYSDOT provides current information on the public
highway mileage in New York State, by county (NYSDOT 2009a).
Table 2.110 - Region C: Highway Mileage by County, 2009 (New August 2011)

Cattaraugus
Chautauqua
Total Region C

Town or
Village
1,379.8
1,531.5
2,911.3

County
397.7
551.5
949.2

NYSDOT
Owned
315.2
353.1
668.3

Other

Total

54.1
47.1
101.2

2,146.8
2,483.2
4,630.0

Source: NYSDOT 2009a.

The two main roadway corridors in Region C run through different sections of the two counties.
One is I-90, which runs northeast from the Pennsylvania border in Chautauqua County and along
Lake Erie towards Buffalo, New York. The other corridor, I-86/NY-17, runs east-west through
both Chautauqua and Cattaraugus Counties, crossing into Pennsylvania in western Chautauqua
County. I-86/NY-17 crosses over Chautauqua Lake and runs north of the major population center

Final SGEIS 2015, Page 2-161

 of Jamestown. It also connects other cities such as Randolph, Salamanca, and Olean (Figure
2.18).
Numerous other arterials, collectors, and local roadways cover this region and connect smaller
towns and villages; these include Route 16, Route 19, Route 60, and Route 219. Heavy vehicles
primarily use major roadways. A NYSDOT study used vehicle classification data from 2004 to
2009 to estimate the percentage of heavy vehicles on various road classifications in rural and
urban settings (NYSDOT 2010a). The data for rural areas in NYSDOT Region 5 are presented in
Table 2.111.
Table 2.111 - Heavy Vehicles as a Percentage of Total Vehicles in Rural Areas in NYSDOT Region 5, 2009 (New August 2011)

Functional
Classification (FC)
Code
01
02
06
07
08
09

NYSDOT
Region 5
23.5%
10.9%
11.3%
8.8%
6.3%
7.1%

Statewide
25.2%
12.5%
9.5%
8.9%
6.8%
7.1%

Source: NYSDOT 2010a.

Heavy-vehicle traffic is concentrated on major roadways, with FC classifications 01 and 02
handling 34.4% of heavy-vehicle traffic in NYSDOT Region 5. However, the percentages are
less than the corresponding statewide percentage. This may be a result of the city of Buffalo
being located in NYSDOT Region 5, where heavy-vehicle traffic may use smaller roads in
industrial/manufacturing areas for pickups and deliveries.
2.3.14.3

Condition of New York State Roads

New York State reports annually on the condition of bridges and pavements. Based on data
submitted to the FHWA in April 2010, about 12% of the highway bridges in New York State are
classified, under the broad federal standards, as structurally deficient, and about 25% are
classified as functionally obsolete. Those classifications do not mean the bridges are unsafe,
rather that they would require repairs or modifications to restore their condition or improve their
functionality (NYSDOT 2011b).

Final SGEIS 2015, Page 2-162

 The condition of pavements is scored on a 10-point scale, as shown in Table 2.112. New York
State road conditions are ranked 42nd in the nation (NYSDOT 2009b). This makes any impacts
on road conditions an important consideration.
Table 2.112 - Ranking System of Pavement Condition in New York State (New August 2011)

9-10
7-8
6
1-5
U

Excellent
Good Surface
Fair
Poor
Under Construction

No significant surface distress
Distress beginning to show
Surface distress is clearly visible
Distress is frequent and severe
Not rated due to ongoing work

Source: NYSDOT 2010b.

2.3.14.4

NYSDOT Funding Mechanisms

The construction, reconstruction, or maintenance (including repair, rehabilitation, and
replacement) of transportation infrastructure under the State’s jurisdiction are performed by the
NYSDOT. The state has statutorily established a number of funds that collect dedicated taxes and
fees to fund NYSDOT’s capital and operating activities. Most of the tax and fee sources for these
funds are related to transportation and collected from transportation users. They include:
•

Petroleum business tax;

•

Highway use tax;

•

Motor fuel tax;

•

Motor vehicle fees;

•

Auto rental tax; and

•

Miscellaneous special revenues.

The Petroleum Business Tax (PBT) is a tax imposed on petroleum businesses operating in New
York State. The tax is paid by registered distributors and is imposed at a cents-per-gallon rate on
petroleum products sold or used in the State. The tax imposition occurs at different points in the
distribution chain, depending on the type of petroleum product: For motor fuel, the PBT is
imposed upon importation into the State; for diesel motor fuel, the PBT is imposed on the first
sale or use in the State; for non-automotive diesel fuel and residual oil, the PBT is imposed on

Final SGEIS 2015, Page 2-163

 final sale or use; for kero-jet fuel, the PBT is imposed on fuel consumed on take-off from points
in the State. The tax is jointly administered and collected with the State's motor fuel tax
(NYSDTF 2011a).
The Highway Use Tax (HUT) is a tax on motor carriers operating certain motor vehicles on New
York State public highways (excluding toll-paid portions of the New York State Thruway). The
tax is based on mileage traveled on NYS public highways and is computed at a rate determined by
the weight of the motor vehicle and the reporting method. A HUT certificate of registration is
required for any truck, tractor, or other self-propelled vehicle with a gross weight over 18,000
pounds or for any truck with an unloaded weight over 8,000 pounds and any tractor with an
unloaded weight over 4,000 pounds. An automotive fuel carrier (AFC) certificate of registration
is required for any truck, trailer, or semi-trailer transporting automotive fuel (NYSDTF 2011b).
New York State has a motor fuel tax on motor fuel and diesel motor fuel sold in the State. The tax
is imposed when motor fuel is produced in or imported into New York State and when diesel
motor fuel is first sold or used in the State. It is jointly administered and collected with the
petroleum business tax. The tax is paid by registered motor fuel and diesel motor fuel distributors
(NYSDTF Finance 2011c).
Motor vehicle fees, which are collected by the New York State Department of Motor Vehicles,
are another large source of income for the NYSDOT. Other taxes collected for the NYSDOT
include the auto rental tax, corporation and utility tax, and other miscellaneous receipts, although
the PBT, HUT, motor fuel tax, and motor vehicle fees are the main sources of revenue.
Table 2.113 shows the actual total receipts for years 2009-2010 and 2010-2011 for the NYSDOT,
as well as the estimated receipts for year 2011-2012. Total receipts allotted to the NYSDOT
increased from 2009 to 2011 and are expected to continue to increase through 2012.

Final SGEIS 2015, Page 2-164

 Table 2.113 - NYSDOT Total Receipts, 2009-2012 ($ thousands) (New August 2011)

Petroleum Business Tax
Highway Use Tax
Motor Fuel Tax
Motor Vehicle Fees
Auto Rental Tax
Corporation and Utility Tax
Other Miscellaneous Receipts
Total Tax Receipts
Total Receipts

2009-2010
Actual
612,502
137,247
401,099
626,589
51,726
19,641
635,045
1,848,804
2,483,849

2010-2011
Actual
605,945
129,162
407,725
813,264
60,032
16,400
467,876
2,032,528
2,500,404

2011-2012
Estimated
614,000
144,000
404,000
827,000
65,000
15,000
578,902
2,069,000
2,647,902

Source: Zerrillo 2011.

The actual amount of total receipts in the year 2010-2011 was $2.5 billion. Approximately $1.4
billion, or 45.7%, came from business taxes, including the motor fuel, petroleum, and highway
use taxes. Approximately $813 million, or 32.5%, came from motor vehicle fees, and $544
million, or 21.8% came from auto rental and corporation and utility uses taxes and other
miscellaneous receipts. In the estimated receipts for next year (2011-2012), all income related to
taxes is estimated to remain relatively constant, whereas there is expected to be a $200 million
increase in motor vehicle fees due to increases in fees (Table 2.113).
Collectively, revenues from these taxes flow into the state’s Dedicated Highway and Bridge Trust
Fund (DHBTF), which is the primary funding source for the NYSDOT highway and bridge
capital program, engineering and program administration, DMV administration, as well as capital
programs for transit, rail and aviation. In addition to these tax revenues, state general fund
support is required to sustain the DHBTF and provide for new project commitments.
NYSDOT is implementing the final year of a two-year capital program for which approximately
$1.8 billion is annually dedicated to capital rehabilitation and replacement of the state and local
road and bridge system. Despite past investment, the condition of the state’s highway pavements
and bridges is declining. Given the age of the state’s highway system, the capital program, by
necessity, invests largely in safety and asset preservation projects to meet the urgent needs of the
transportation system.

Final SGEIS 2015, Page 2-165

 In addition to state investment in roads and bridges, local governments invest in local roads and
bridge infrastructure maintenance and improvement, largely through local property and other
local taxes.
2.3.14.5

Rail and Air Services

New York State is served by an extensive system of rail lines for passengers and freight. Amtrak,
operating primarily over rail lines owned by freight railroads, is the solitary provider of intercity
rail passenger service in New York State. Over approximately 782 route miles, Amtrak links
downstate with upstate cities that include Albany, Utica, Syracuse, Rochester, Buffalo, and many
other intermediate points. CSX Transportation, Canadian Pacific Railway, and Norfolk Southern
Railway are the primary owners and operators of freight corridors in New York State. CSX
Transportation is the largest among these railroads, operating 1,292 of the total 4,208 miles of
freight rail in the state. Fifty-nine of New York State’s 62 counties are served by one of New
York’s freight railroads, which connect to all adjacent states and Canadian provinces (NYSDOT
2009). The principal rail lines in New York State are shown on Figure 2.18.
Freight carried by railroad is off-loaded at rail yards and transported to specific locations from the
railroads by truck. The rail network in New York State is capable of carrying much of the drill
equipment that might be required, although it would still have to be moved by truck from the rail
yards to the well heads.
Many of the communities in and near the gas development areas are serviced by commercial
airliners, including those associated with airports in smaller cities such as Jamestown,
Binghamton, and Elmira, and in larger cities such as Buffalo, Rochester, and Syracuse. Figure
2.18 shows the location of Commercial - Primary airports, which are publicly-owned airports that
receive scheduled passenger service and have more than 10,000 enplaned passengers per year. A
list of Commercial - Primary airports in New York State is provided below. Some airports that
are not categorized as Primary airports, because they fall below the 10,000 passenger per year
passenger count, also are serviced by scheduled air carriers. The Jamestown airport is one such
facility that lies within the area of potential shale gas development.

Final SGEIS 2015, Page 2-166

 •

Albany International Airport;

•

Greater Binghamton Airport;

•

Buffalo Niagara International Airport;

•

Elmira/Corning Regional Airport;

•

Long Island MacArthur Airport;

•

Ithaca Tompkins Regional Airport;

•

John F. Kennedy International Airport;

•

LaGuardia Airport;

•

Stewart International Airport;

•

Plattsburgh International Airport;

•

Greater Rochester International Airport;

•

Syracuse Hancock International Airport; and

•

Westchester County Airport.

In addition to Commercial - Primary airports, there are many other public use airports that can be
utilized by charter operations. None of these airports are at or near capacity and can be available
to service an influx of temporary workers.
2.3.15 Community Character 49
A community’s character is defined by a combination of natural physical features, history,
demographics and socioeconomics, and culture (Robinson 2005). Key attributes or features used
to define community character generally include local natural features and land uses; local history
and oral traditions; social practices and festivals; unique local restaurants and cuisine; and local
arts. In addition, New York State’s Environmental Quality Review Act acknowledges
community character as a component of the environment, including existing patterns of

49

Subsection 2.4.15, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011 and was adapted
by the Department.

Final SGEIS 2015, Page 2-167

 population concentration, distribution or growth, and existing community or neighborhood
character.
Local and regional planning are important in defining a community’s character and long-term
goals. In New York State, planning, zoning, and local law are implemented and enforced at the
local level, through county and municipal boards or councils. The local entities set forth the
community’s goals and objectives through planning or zoning documents, which provide the most
tangible and formal expression of a community’s character. Notably, a 2007 New York State
Court of Appeals decision (Village of Chestnut Ridge vs. Town of Ramapo) observed that “[t]he
power to define the community character is a unique prerogative of a municipality acting in its
governmental capacity” and, that, generally, through the exercise of their zoning and planning
powers, municipalities are given the job of defining their own character (NYSDEC 2007).
A sense of place also is central to community character or identity. “Sense of place” can be
described as those tangible and intangible characteristics which, over a period of time, have given
a place its distinctiveness, identity, and authenticity (Robinson 2005). Distinctiveness can be
globally, nationally, or regionally important, as well as locally or personally important. The
various elements that comprise sense of place include, but are not limited to, regional and local
planning, population density, transportation and access, and services and amenities.
To be a defined “place” a bounded area must be recognized by those within and without it as
being a distinctive community and having a distinctive character. A sense of place and
community character cannot be described for New York State as a whole due to the vast area it
covers and the range of differences in communities across the state. Residents of a single place
share their history, resources, and common concerns and have a similar way of life. Regions A,
B, and C (Figure 2.3) were developed for the purposes of the SGEIS to generally describe
representative areas of impact within the area underlain by the Marcellus Shale in New York
State. Because they encompass numerous counties and municipalities with diverse land uses,
planning goals, and identities, it is difficult to fully describe community character at the regional
level. Each community within these regions has its own set of distinctiveness, authenticity, and
identity. For the purposes of this analysis, the sense of place for a county or region was described
utilizing regional, county, and local comprehensive plans, economic development plans, and Web

Final SGEIS 2015, Page 2-168

 sites. These resources were used to piece together the sense of place for the representative
regions.
Region A
Region A comprises Broome, Tioga, and Chemung Counties (Figure 2.4a). It is located in the
eastern portion of the Southern Tier of New York, along the New York/Pennsylvania border. The
Southern Tier Expressway (Interstate 86) crosses the southern portion of Region A, providing
east/west access, and connecting the cities of Elmira in Chemung County, Waverly and Oswego
in Tioga County, and Binghamton, Endicott and Johnson City in Broome County. Most of the
urban development occurs along this corridor. The remainder of the region is rural; the rural
landscape is dominated by the hills and valleys along the Susquehanna and Chemung Rivers.
Collectively, the counties within Region A comprise 38 towns/cities, 18 villages, and many
unincorporated areas. There are 21 combined school districts in the Region.
Generally, Region A can be described as having relatively small urban centers and quaint villages
surrounded by small, scattered, and picturesque rural communities, largely set within the hills and
valleys along the Susquehanna and Chemung Rivers. The Susquehanna and Chemung River
valleys are a large part of the natural landscape and create vistas important to local communities.
The natural landscape is home to a variety of wildlife, which is enjoyed by residents and visitors
both passively (e.g., hiking and bird watching) and actively (e.g., fishing and hunting). Rural
elements include scenic drives/routes, farmland, woodlands, forests, waterways, and natural areas.
Villages and towns in Region A are quaint and historic and are also home to many musicians and
artisans. In Region A, officials and residents describe their communities as being friendly and
having a small-town feel and their residents as hard-working and ethical. Many note their country
fairs, unique shops, and overall rural characteristics as contributing to their community’s
character.
Within the counties that comprise Region A, agriculture is an important part of community
character. There are over 1,500 farms within Region A, and approximately 279,000 acres of land
within the Region are located within 11 state-designated agricultural districts (NYSDAM 2011).
Figure 2.19 provides an overview of the agricultural districts within Region A.

Final SGEIS 2015, Page 2-169

 Region A is rich in history and historic preservation opportunities. Chemung County and the city
of Elmira are considered to be “Mark Twain Country,” because it is the area where Mark Twain
lived a large portion of his life and where he died. The character of Region A is influenced by
numerous sites and events associated with Native American history, the Revolutionary War and
Civil War, and the Underground Railroad, as well as historic villages, towns, and farms
(Chemung County Chamber of Commerce 2011). The town of Owego, in Tioga County, has 151
homes that are located in historic districts (Visit Tioga 2011), and numerous Victorian homes
throughout the region contribute to the historical aspect of its region’s character.
The region aims to maintain a “Main Street” and small local business attitude by promoting
economic growth and maintaining a rural character.
Agri-tourism in the form of petting zoos, U-pick farms, and farmers markets is a large part of the
community character of the region. An abundance of outdoor recreational activities, including
hiking, biking, fishing, boating, hunting, cross-country skiing, and bird-watching, contributes to
the high quality of life these communities all strive for. These activities are counterbalanced by
many opportunities to enjoy art, music, and other cultural amenities provided by the region’s
cities and towns.
Drilling for natural gas has been performed to a limited extent in Region A; in 2009 there were
only 46 gas wells in the region (NYSDEC 2009). Of these, 45 active gas wells are located in
Chemung County and one is in Tioga County. In addition, there are 13 underground gas storage
wells in operation in Tioga County (NYSDEC 2011).

Final SGEIS 2015, Page 2-170

 Path: L:\Buffalo\Marcellus_NY\Maps\MXD\Report\DEIS\Agriculture\Region_A_Agriculture.mxd

Seneca

Yates

New York
Cortland

Tompkins

Chenango

Schuyler

teuben

Tioga

Chemung

Broome

Pennsylvania
0

2.5

5

Representative Region A
County Boundary

Agricultural Districts

10
Miles

USGS NLCD
Developed

Open Space
Agriculture

Forest
Herbaceuous/Shrub/Scrub
Open Water
Wetlands

NOTE: Agricultural district boundaries are overlaid on the land cover data. The land cover within agricultural district boundaries
includes land cover other than agriculture; however, land cover within the agricultural district boundaries is predominately agriculture.

Final SGEIS 2015, Page 2-171

Figure 2.19:
Land Cover and Agricultural Districts
Representative Region A
Source: ESRI, 2010; NYSDAM, 2011

 Broome County. Broome County is the furthest east in the region. The county has a total area of
715 square miles, including 707 square miles of land and 8 square miles of surface water (lakes,
ponds, rivers, and streams). Broome County is more densely populated than the other counties in
Region A, with a population density of 284 persons per square mile.
Within Broome County are 17 towns/cities and seven villages, and 12 school districts (Broome
County 2011; New York Schools 2011a). The Binghamton-Johnson City-Endicott Tri-City Area
is the predominant urban area of the county, which is surrounded by suburban development
(Greater Binghamton Chamber of Commerce 2011). Major manufacturers located in Binghamton
include Lockheed Martin (systems integration), BAE Systems (mission systems) and IBM
Corporation (technology). Large healthcare facilities are also located in Binghamton, including
United Health Services and Lourdes Hospital. The State University of New York at Binghamton
is also a large employer within the region.
The Southern Tier Expressway (Interstate 86/NYS Route 17) crosses the southern portion of
Broome County in an east-west direction, and Interstate 81 provides northern access to the cities
of Cortland and Syracuse and the New York State Thruway.
The remaining land area in Broome County is largely rural. As reported by the Census of
Agriculture, in 2007 there were 580 farms in Broome County, covering approximately 98,000
acres of land (22% of the total land area of the county). The average size of a farm in Broome
County in 2007 was 150 acres. Principal sources of farm income include milk, cattle/calves,
other crops/hay and nursery, greenhouse, floriculture, and sod. Dairy products account for
approximately 70% of agricultural sales in the county (USDA 2007). As of 2011, there were
approximately 153,000 acres of land within three state-designated agricultural districts in Broome
County (NYSDAM 2011). Agri-tourism in Broome County focuses on farmers markets, U-pick
farms, alpaca farms, apples, botanical gardens, and maple syrup (Visit Binghamton 2011).
Broome County and Tioga County are a part of the Susquehanna Heritage Area, which seeks to
use the historic, cultural, and natural resources of the counties to strengthen the region’s identity,
enhance the local quality of life, support the local economy, and promote stewardship
(Susquehanna Heritage Area 2009).

Final SGEIS 2015, Page 2-172

 Broome County’s Department of Planning and Economic Development “serves to promote the
sound and orderly economic and physical growth of Broome County and its constituent
municipalities…it implements projects and programs designed to improve the economy,
environment and physical infrastructure of the county” (Broome County 2009). Development of
comprehensive plans is generally left to the discretion of city and town zoning and planning
boards, which originally adopted traditional forms of regulation in an effort to protect land use
and natural resources. Local and regional development is guided by a number of open space
plans, local comprehensive plans, and strategic plans. These documents broadly reflect a
community’s history, values, future goals, and character.
Broome County does not have a comprehensive or master plan, but many of its larger
municipalities have a comprehensive/master plan, land use regulations/laws, and zoning maps. A
brief review of representative local planning documents indicated that several communities in the
county are concerned with protecting and maintain agricultural activities in order to preserve open
space, promote historic preservation, and preserve and enhance the sense of community identities.
As an example, the Town of Union’s Unified Comprehensive Plan outlines the following goals
and objectives: “protect and maintain agricultural activities as a land use option in order to
preserve open space . . . promote a balance between the need to use and the need to preserve
resources . . . [and] . . . promote historic preservation” (Town of Union 2009).
Tioga County. Tioga County is located in the Southern Tier of New York State, west of Broome
County. This county has a total area of 523 square miles, including 519 square miles of land and
4 square miles of surface waters (lakes, ponds, rivers, and streams). Tioga County has the lowest
population density in Region A, with 98.6 persons per square mile.
Within Tioga County are nine towns and six villages, as well as six school districts (Tioga County
2011a; New York Schools 2011b). The largest urban developments are Owego (19,883 persons
in the town and 3,896 persons in the village) and Waverly (4,444 persons). The BinghamtonJohnson City-Endicott Tri-City Area also extends from Broome County into the eastern edge of
Tioga County. The existing land use pattern in Tioga County has been influenced by the historic
pattern of highway-oriented transportation and employment provided by IBM Corporation and
later Lockheed Martin (Tioga County 2005). The presence of technologically advanced industries

Final SGEIS 2015, Page 2-173

 in the southern portion of the county, along the Southern Tier Expressway and near Owego, led to
that portion of the county being more densely populated than the northern portion. There are no
major roadways running east-west in the northern portion of the county.
The remaining land area in Tioga County is largely rural. As reported by the Census of
Agriculture, in 2007 there were 565 farms in this county, covering approximately 106,800 acres
of land (32% of the land area of the county). The average size of a farm in Tioga County in 2007
was 189 acres (USDA 2007). The principal source of farm income is dairy products, which
accounted for approximately 75% of agricultural products sold in 2007. Other farming in the
county includes beef cows, horses, sheep, and poultry. Hay is the largest crop grown in Tioga
County, followed by oats and vegetables. Farming operations in Tioga County also produce over
800 gallons of maple syrup (Tioga County 2011a). In recent years, Tioga County has seen
decreases in the number of farms, the productivity of farms, and farmed acreage (Tioga County
2005). As of 2011, there were approximately 84,000 acres of land within three state-designated
agricultural districts in the county (NYSDAM 2011). Tioga County continues to encourage farm
owners to enroll in and work with the NYSDAM to establish agricultural districts to preserve the
agricultural character of the county (Tioga County 2005).
Tioga County’s physical environment ranges from farming communities to historic town centers
with charming “Main Streets” (Visit Tioga County 2011; Tioga County 2005). The county is
defined as rural and suburban, but not urban (Tioga County 2011b). The portion of the
Susquehanna River basin in Tioga County provides recreational and visual benefits to the county.
Tioga County prides itself in its unspoiled beauty, human resources, and central geographic
location (Tioga County 2011c).
Tioga County encourages local municipalities to develop their own planning documents (Tioga
County 2005). Development of comprehensive plans is generally left to the discretion of village
and town zoning and planning boards, which originally adopted traditional forms of regulation in
an effort to protect land use and natural resources. Local and regional development is guided by a
number of open space plans, local comprehensive plans, and strategic plans. These documents
broadly reflect a community’s history, values, future goals, and character.

Final SGEIS 2015, Page 2-174

 Tioga County does not have a comprehensive or master plan, but many of its municipalities have
a comprehensive/master plan, land use regulations/laws, and/or zoning maps. A brief review of
representative local planning documents indicated that several communities in the county are
concerned with promoting economic development while preserving and maintaining their small
town/hometown atmosphere and rural character. The towns also emphasize the importance of
conservation and preservation of natural areas and open space, including both agriculture land use
and future expansion of recreational community areas. For example, the first goal of the Town of
Candor Comprehensive Plan is to “attract and recruit desirable small business and light industry
in order to help create a stable tax base and maintain the small town/hometown atmosphere”
(Town of Candor 1999).
Chemung County. Chemung County is located west of Tioga County. The county has a total
area of 411 square miles, including 408 square miles of land and 3 square miles of surface water.
Chemung County has a population density of 218 persons per square mile.
Within Chemung County are 12 towns/cities and five villages, as well as three school districts
(Chemung County 2011a; New York Schools 2011c). The existing land use pattern in Chemung
County has been significantly influenced by the topography of the region, including the Chemung
River Valley. The region’s climate, topography, and soils support productive agricultural,
forestry, and wood product industries (Susquehanna – Chemung 2011). The region is rural, with
rolling hills, scenic farmlands, rural vistas, and outdoor recreation opportunities, which are all
major contributors to the region’s appeal.
The city of Elmira is the largest population center in Chemung County. Located along the
Southern Tier Expressway (Interstate 86/17), the city is the historical and cultural center of the
county and has numerous historical markers, museums, and tours. The city has the “largest
concentration of Victorian-era homes in the State of New York” (Chemung County Chamber of
Commerce 2011). Chemung County has many manufacturing industries, which make products
such as subway cars, electronic equipment, structural steel products, helicopters, automotiverelated products, and paper products (Chemung County 2008).

Final SGEIS 2015, Page 2-175

 As reported by the Census of Agriculture, in 2007 there were 373 farms in the county, covering
approximately 65,000 acres of land (approximately 25% of the land area of the county). The
average size of a farm in Chemung County in 2007 was 175 acres (USDA 2007). Agricultural
activities include the production of corn, wheat, hay silage, vegetables, poultry, eggs, beef, milk,
milk products, and pork (Chemung County 2008). Approximately 42,000 acres of farmland in
Chemung County are located in five agricultural districts (NYSDAM 2011). Farming operations
in Chemung County have also decreased over the years, but agriculture is still a major industry in
this county.
Chemung County’s topography consists of hills and valleys, with the principal valley being the
Chemung River valley (Chemung County 2008). The majority of the county is naturally forested
and classified as woodland, but up to 18% of the land area is active agricultural land (Chemung
County 2008). Described as the “Gateway to the Finger Lakes,” Chemung County itself has
sufficient waterways, rolling hills, scenic farmlands, and outdoor recreational resources to provide
a high quality of life for residents and tourists (Susquehanna-Chemung 2011).
Chemung County’s Planning Department assists local communities with comprehensive planning,
land use and zoning, floodplains and watersheds, and grant proposals (Chemung County 2011b).
Chemung County empowers the local municipalities to develop their own planning documents
and periodically presents specialized training workshops for local planning and zoning officials
(Chemung County 2011b, 2011c). Development of comprehensive plans is generally left to the
discretion of village and town zoning and planning boards, which originally adopted traditional
forms of regulation in an effort to protect land use and natural resources. Local and regional
development is guided by a number of open-space plans, comprehensive plans, and strategic
plans. These documents broadly reflect a community’s history, values, future goals, and
character. The Chemung County Planning Department participates actively in the Rural
Leadership program of the Southern Tier Regional Planning and Development Board (Chemung
County 2011b).
Chemung County does not have a comprehensive or master plan, but many of its municipalities
have a comprehensive/master plan, land use regulations/laws, and/or zoning maps. A brief
review of representative local planning documents indicated that several communities in the

Final SGEIS 2015, Page 2-176

 county are concerned with protecting their small town feel, maintaining a similar population size,
enhancing recreational amenities, and protecting environmentally significant and/or sensitive
areas while minimizing anthropogenic adverse impacts on the land and, consequently, the quality
of life of the residents. For example, the Village of Horseheads Comprehensive Plan states their
village “... is an inviting place where diverse residents choose to live, work, and play; it is a blend
of residential neighborhoods, commercial and manufacturing businesses, parks, and open spaces.
Residents and Village officials take pride in the surroundings by assuring the maintenance and
beauty of homes, land, and property” (Village of Horseheads 2010).
Region B
Region B comprises Delaware, Sullivan, and Otsego Counties (Figure 2.4b). Region B is located
in the Catskill Mountains and the Leatherstocking region of New York and has a rich natural and
human history. The National Baseball Hall of Fame is located in Cooperstown, in Otsego
County, and is a destination for thousands of people annually. Glass museums, history museums,
and other tourist attractions exist throughout the region. The Catskills are an attraction for
outdoor enthusiasts. Various manufacturing companies are located across the region, mainly
occurring in the larger towns. The region is known for manufacturing communications
equipment, integrated circuits, pharmaceuticals, transportation equipment, plastic and rubber
products, and food and beverages. Other large employers include insurance companies, colleges,
health care facilities, and retailers. NYSEG, Verizon, and other electronics companies are located
in the city of Oneonta (City of Oneonta 2011). Having manufacturing and cultural hubs
surrounded by natural areas contributes to the community character of the region.
Within the region there are 60 towns, 26 villages, and over 75 hamlets; 42 combined school
districts. Gas drilling is relatively new to these counties and is not an integral part of the
industrial or rural landscape of the region. In 2009 there were no natural gas wells in production
in Region B (NYSDEC 2009). Several exploratory wells were developed in 2007 and 2009, but
no production has been reported.
Generally, Region B can be described as having relatively small urban centers and villages
surrounded by numerous small, scattered, and picturesque rural hamlets within a setting of
sparsely populated hills, mountains, and valleys. Some communities boast about their clean

Final SGEIS 2015, Page 2-177

 water, land, and air and panoramic views of natural beauty, while others are particularly proud of
their proximity to larger metropolitan areas. Local Web sites and planning documents describe
the less densely populated segments of each community as having a rural character, with few
buildings, structures, or development (Catskills Region 2011). Rural elements include
meandering, tree-lined streets, farmland, woodlands and forests, and natural areas. With the
exception of communities immediately along state or county transportation corridors, the hamlets,
villages, and towns in Region B generally are pedestrian-friendly or are in the process of
revitalizing their neighborhoods to be more walkable (Sullivan County Chamber of Commerce
2011a). Within Region B, views and vistas are dominated by undeveloped open space (Town of
Otsego 2005). In Delaware County, this was reinforced by the 1997 Watershed Memorandum of
Agreement with NYC.
There are over 1,900 farms within the three counties that comprise Region B; consequently,
agriculture is an important part of community character within the Region. Approximately
588,000 acres of land within Region B are located within 15 state-designated agricultural districts
(NYSDAM 2011). Figure 2.20 provides an overview of the agricultural districts within Region
B.
In Region B, many of the inhabited places are small and the pace of life is slow. Some local
officials and residents describe their communities as being friendly and having a small-town feel.
Many note their country fairs, specialty shops, and team sports as contributing to their
community’s character. Delaware and Sullivan Counties are described as rural retreats for urban
tourists from NYC. The City of Oneonta, in Otsego County, describes itself as a religious
community, known for its many places and worship. All of the counties in Region B describe
active and passive recreational activities as being essential to their community character.
Available outdoor recreational activities include hiking, fishing, boating, biking, bird-watching,
hunting, skiing, and snowmobiling.

Final SGEIS 2015, Page 2-178

 Oneida

Herkimer

Madison

Montgomery

Schenectady

Otsego
Albany

Schoharie

Chenango

Greene

Broome

Delaware

New York
Ulster

Pennsylvania

Sullivan
Orange
0

2.5

5

10
Miles

Representative Region B USGS NLCD

Agriculture

Agricultural Districts

Herbaceuous/Shrub/Scrub

County Boundary

Developed

Open Space

Forest

Open Water
Wetlands

NOTE: Agricultural district boundaries are overlaid on the land cover data. The land cover
within agricultural district boundaries includes land cover other than agriculture; however,
land cover within the agricultural district boundaries is predominately agriculture.

Figure 2.20:
Land Cover and Agricultural Districts
Representative Region B
Source: ESRI, 2010; NYSDAM, 2010, 2011

Final SGEIS 2015, Page 2-179

 Region B, while rural and slow-paced in some areas, also has several centers of commerce, highquality health care facilities, institutions of higher education, and noteworthy cultural activities,
including art galleries, theatre groups, and music events. These assets significantly contribute to
their “sense of place.” For centuries the Catskills Mountains in Delaware County have been a
place where art colonies flourished. In Cooperstown, in Otsego County, the Baseball Hall of
Fame, Glimmerglass Opera, art galleries, and specialty shops draw throngs of visitors each year.
Sullivan County describes itself as offering value and convenience for visitors seeking an escape
closer to home, with museums, antiques, boutiques and theater, as well as outdoor recreational
activities. It is best known as the home of the Woodstock music festival and the Monticello
Raceway. Agri-tourism also is important to Sullivan County.
Delaware County. Geographically, Delaware County is the largest county in Region B and is one
of the larger counties in New York State (Delaware County Chamber of Commerce 2011a).
Delaware County is located in the southeastern part of the state and is bordered to the south by the
Delaware River. The Catskill Mountains are partially located in Delaware County. The county
has a total area of 1,468 square miles, including 1,446 square miles of land and 22 square miles of
surface water (lakes, ponds, rivers, and streams). Delaware County is one of the least populated
counties in New York State, with 33 persons per square mile. The county has 19 cities/towns, 10
villages, two hamlets, and 13 school districts (Delaware County 2011; Delaware County Chamber
of Commerce 2011b; New York Schools 2011d). The largest population centers are the villages
of Sidney (3,900 persons), Walton (3,088 persons), and Delhi (3,087 persons). Interstate
86/Route 17 crosses the southern boundary of Delaware County.
The remaining areas in Delaware County are rural. As reported by the Census of Agriculture, in
2007, there were 747 farms in the county, covering approximately 200,000 acres (22% of the land
area in the county). The average size of a farm in Delaware County in 2007 was 222 acres. The
principal sources of farm income include milk, vegetables, other crops/hay and nursery,
greenhouse, floriculture, and sod (USDA 2007). According to more recent data from the
Delaware County Chamber of Commerce, dairy products account for approximately 80% of
agricultural sales in the county, and Delaware County represents 80% of the dairy farms in the
NYC watershed area (Delaware County Chamber of Commerce 2011b). As of 2011, there were

Final SGEIS 2015, Page 2-180

 approximately 237,000 acres of land within eight state-designated agricultural districts in
Delaware County (NYSDAM 2011).
The existing land use pattern in Delaware County has been influenced by the historic pattern of
hamlet development, highway-oriented transportation, and state land ownership. In addition, a
major land-acquisition program is underway in Delaware County and other Catskills/Delaware
Watershed communities that help to provide an unfiltered drinking water supply to NYC. The
acquisition of this land will preclude future development in designated areas (NYC Watershed
2009).
Delaware County does not have a comprehensive plan, but it empowers its municipalities to
develop their own planning documents. Development is generally left to the discretion of village
and town zoning and planning boards, which originally adopted traditional forms of regulation in
an effort to protect land use and natural resources. Local and regional development is guided by a
number of open-space plans, comprehensive plans, and strategic plans. These documents broadly
reflect a community’s history, values, future goals, and character.
Delaware County does not have a comprehensive or master plan, but many of its municipalities
have a comprehensive/master plan, land use regulations/laws, and zoning maps. A brief review of
representative local planning documents indicated that several communities in the county are
concerned with protecting and preserving agricultural land, including niche farming, forestry, and
other sensitive areas; maintaining a rural character and the historical context of the communities;
preserving existing development patterns and the appearance of residential development;
maintaining the natural environment; and minimizing impacts on scenic transportation routes and
vistas. For example, the Town of Stamford states in its Final Draft Comprehensive Plan that the
town “will be a place that continues to maintain and celebrate its small town, rural character and
natural beauty . . . maintain our open spaces and the pristine nature of the environment . . . [and] .
. . our quality of life will be enhanced because of the Towns’ strong sense of community through
its caring, friendly people and the dedicated organizations and volunteers that serve us well”
(Town of Stamford 2011).

Final SGEIS 2015, Page 2-181

 Sullivan County. Sullivan County is located south of Delaware County. The county has a total
area of 1,038 square miles, including 1,011 square miles of land and 27 square miles of surface
water (lakes, ponds, rivers, and streams). The county’s physical environment ranges from historic
urban centers to farming communities nestled within an open-space network that includes the
Upper Delaware Scenic and Recreation River (to the west), Catskill Park (to the north) Basherkill
Watershed, and Shawangunk Ridge (Sullivan County Catskills 2011a).
Sullivan County has a population density of 76 persons per square mile. Within the county are 15
cities/towns, six villages, and over 30 hamlets; and eight school districts (Sullivan County
Catskills 2011b; Sullivan County Chamber of Commerce 2011b). The largest population centers
are the Village of Monticello (6,726 persons), and the Village of Liberty (4,392 persons).
Interstate 86/Route 17 crosses through the middle of Sullivan County, providing access to New
York City, which is approximately 60 miles southeast of Sullivan County.
The remaining portions of Sullivan County are rural and open space. According to the Census of
Agriculture, in 2007 there were 323 farms in Sullivan County, covering approximately 63,600
acres (approximately 10% of the land area of the county). The average size of a farm in 2007 was
156 acres (USDA 2007). In 2007, the principal sources of farm income included poultry and
eggs, milk and other dairy products from cows (USDA 2007). Poultry and eggs accounted for
approximately 65% of agricultural sales in the county in 2007. In recent years, however, Sullivan
County has seen a decrease in traditional dairy and livestock farms (it now has only two major
egg producers and 28 dairy farms) and an increase in smaller niche and diversified vegetable and
livestock farms. As of 2011, there were approximately 162,000 acres of land within two statedesignated agricultural districts in Sullivan County (NYSDAM 2011).
In its Comprehensive Plan, the county describes itself as being on the verge of becoming urban,
with rapid growth and development that will change its character and have an impact on its
resources (Sullivan County Catskills 2005). The county’s vision and community land use goals
include avoiding heavy traffic, strip malls, and loss of open space and ensuring the availability of
affordable housing. While development decisions are made at the local level, the county
encourages collective support of a unified vision in its Comprehensive Plan (Sullivan County
Catskills 2005). As stated in the Comprehensive Plan, current development patterns often

Final SGEIS 2015, Page 2-182

 mandate a separation of land uses; however, revitalization efforts are focused on mixed-used infill development (i.e., development within vacant or under-utilized spaces within the built
environment), walkable communities, and streetscape improvements (Sullivan County Catskills
2005). The county also is committed to preserving viewsheds, natural resources, and
environmentally sensitive areas through zoning. Lastly, the county encourages coordinated
zoning among its municipalities and intends to provide resources to municipalities to upgrade
local zoning and land use regulations every 10 years.
Otsego County. Otsego County is located in central New York State, north of Delaware County.
It is situated in the foothills of the Catskill Mountains, at the headwaters of the Susquehanna
River (Otsego County 2011). The County has a total area of 1,015 square miles, including 1,003
square miles of land and 12 square miles of surface water (lakes, ponds, rivers, and streams). The
county has a population density of 62 persons per square mile.
Within the county are 25 cities/towns, nine villages, and 47 hamlets; and 21 school districts The
city of Oneonta, the county seat, has a population of 13,901 persons, and is surrounded by
suburbs, and villages, hamlets, and farm communities that stretch across the remainder of the
county. Interstate 88 crosses the southern portion of Otsego County, connecting the City of
Oneonta to Binghamton to the south, and the Albany area to the north.
Farming operations in Otsego County have decreased over the years, but agriculture is still a
major industry in the county. Active farmland is concentrated in the mid- to northern portions of
the county (Otsego County 1999). According to the Census of Agriculture, in 2007 there were
908 farms in Otsego County, covering approximately 206,000 acres (approximately 30% of the
land area of the county). The average size of a farm in Otsego County in 2007 was 201 acres
(USDA 2007). The principal sources of farm income include milk, cattle/calves, other crops and
hay and nursery, greenhouse, floriculture, and sod. Dairy products account for approximately
70% of agricultural sales in the county (USDA 2007). As of 2011, there were approximately
189,000 acres of land within five state-designated agricultural districts in Otsego County
(NYSDAM 2011).

Final SGEIS 2015, Page 2-183

 Otsego County does not have a comprehensive or master plan, but most of its 34 municipalities
have a comprehensive/master plan, land use regulations/laws, and zoning maps. A brief review of
representative comprehensive plans indicated that several communities in the county are
concerned with protecting sensitive areas, maintaining a low residential density, preserving
existing patterns of land use in hamlets and rural areas, maintaining the natural environment, and
minimizing visual blight. For example, the Town of Otsego Comprehensive Plan’s vision
statement states the following: “We foresee the future Town of Otsego as continuing to have a
clean environment, beautiful landscape, and rural character. We foresee carefully managed
growth and development, maintaining access to our natural areas. We foresee a place of safety
for us and our families.” (Town of Otsego 2008). According to the Otsego County Department of
Planning, affordable housing and real estate is also important to the county (Otsego County
2009).
Region C
Region C comprises Chautauqua and Cattaraugus Counties (Figure 2.4c). Generally, Region C
can be described as largely rural in character, with commercial/industrial hubs located along the
Southern Tier Expressway and agri-tourism spread across the region. Some communities boast
about their access to water bodies and the recreational opportunities they provide, while others are
particularly proud of their proximity to lively cities. Local Web sites and planning documents
describe the less densely populated portions of each community as having a rural character and
charm. Rural elements include scenic drives/routes, farmlands, woodlands and forests,
waterways, and natural areas. Hamlets, villages, and towns in the region are quaint and historic
and many are home to museums and historical sites. The unique geological history of the region
has endowed it with numerous natural attractions, including the deeply incised valleys of
Allegany State Park, the deep gorges of Zoar Valley, and numerous lakes and rivers, all of which
contribute to the region’s character.
Distinct features in each county contribute to the type of agriculture they support, which in turn
influences the character of each county. The floodplains of large streams such as Cattaraugus
Creek support dairy farms in Cattaraugus County, whereas the climatic influences of nearby Lake
Erie support grape production in Chautauqua County.

Final SGEIS 2015, Page 2-184

 The city of Salamanca in Cattaraugus County is the only U.S. city east of the Mississippi River
that is located within a Native American tribal land (Seneca Nation of Indians). The proximity to
Native American tribal lands and the Native American history of the area are important to this
community’s character. The residents of Region C are proud of their history and work diligently
to preserve and promote it. The promotion of this history is evidenced by historical sites and
museums found throughout the region, including the Chautauqua Institution in Chautauqua, New
York. This renowned institution opened in the late 1800s and serves as a community center and
resource “where the human spirit is renewed, minds are stimulated, faith is restored, and art is
valued” (Chautauqua County Chamber of Commerce 2011a). This is another example of heritage
forming an important part of community character in Region C.
Region C has a vibrant and diverse agricultural industry, which can be found throughout the
rolling hills, rural countryside, and woodlands. The agricultural heritage of the region includes
Amish communities in both Cattaraugus and Chautauqua Counties. There are over 2,700 farms in
Region C. Approximately 632,000 acres of land within Region C are located within 17 statedesignated agricultural districts (NYSDAM 2011). Figure 2.21 provides an overview of the
agricultural districts within Region C.
Although agriculture is an important aspect of Region C, there is a balance between rural
preservation and urban development. There are numerous small villages and communities within
Region C, many of which are rich in historic sites and museums. For example, Jamestown in
Chautauqua County is home to the Roger Tory Peterson Institute of Natural History, the Fenton
History Center, the Lucy-Desi Museum, and the Desilu Playhouse and Theater. Jamestown’s
unique character and Victorian heritage are echoed throughout the region.
Tourism is also a large part of the community character of the region. Recreational activities that
draw tourists to the region include bicycling, boating, fishing, gaming (on Native American tribal
land), geo-caching (a treasure-hunting game using GPS technology), golfing, hiking, horseback
riding, motor sports, scenic driving, hunting, mountain biking, downhill skiing, cross-country
skiing, snowmobiling, snowshoeing, and white water rafting. This abundance of the recreational
activities is a significant aspect of the community character in Region C. Within the region are 63
cities/towns, 28 villages, and other unincorporated areas, as well as 30 combined school districts.

Final SGEIS 2015, Page 2-185

 Gas drilling is not new to Region C; in 2009 approximately 3,917 gas wells were in production in
this region (NYSDEC 2009).
Chautauqua County. Located in the southwestern corner of the state, Chautauqua County is
considered the western gateway to New York State (Chautauqua County 2011a). The county is
bordered by Lake Erie to the northwest, Pennsylvania to the south and west, the Seneca Nation of
Indians and Erie County to the northeast, and Cattaraugus County to the east (Chautauqua County
2011b). The center of the county is Chautauqua Lake; five smaller lakes are located throughout
the county. The Southern Tier Expressway crosses the mid-section of the county, and the New
York State Thruway crosses the county along its northern border near Lake Erie. Chautauqua
County has a total area of 1,500 square miles, including 1,062 square miles of land and 438
square miles of surface water (lakes, ponds, rivers, and streams).
There are two cities within the county, Jamestown to the south and Dunkirk along Lake Erie,
which are surrounded by rural areas and lakes. Due to the presence of the two cities, Chautauqua
County has an average population density of 127 persons per square mile. Within the county are
29 cities/towns and15 villages, as well as 18 school districts (Chautauqua County 2011a; New
York Schools 2011e).
According to the Census of Agriculture, in 2007 there were 1,658 farms in Chautauqua County,
which cover approximately 235,858 acres (35% of the land area of the county) (USDA 2007). In
2007 the average size of a farm in this county was 142 acres (USDA 2007). In Chautauqua
County, the principal sources of farm income are grape and dairy products (USDA 2007). Grapes
and grape products account for approximately 30% of agricultural sales in the county, and dairy
products account for approximately 50.5% of agricultural sales (USDA 2007). Grape growers in
Chautauqua County produce approximately 65% of New York State’s total annual grape harvest
(Tour Chautauqua 2011a). As of 2011, there were approximately 392,000 acres of land within 11
state-designated agricultural districts in Chautauqua County (NYSDAM 2011).

Final SGEIS 2015, Page 2-186

 LAKE
ERIE

Erie

Wyoming

L a ke

C h a u ta u q u a


Chautauqua

Cattaraugus

New York

Allegany

Pennsylvania
0 

2.5

5

Representative Region C

County Boundary

Agricultural Districts


10

Miles


USGS NLCD

Developed
Open Space
Agriculture


Forest
Herbaceous/Shrub/Scrub
Open Water
Wetlands

NOTE: Agricultural district boundaries are overlaid on the land cover data. The land cover within agricultural district boundaries
includes land cover other than agriculture; however, land cover within the agricultural district boundaries is predominately agriculture.

Final SGEIS 2015, Page 2-187

Figure 2.21:
Land Cover and Agricultural Districts
Representative Region C
Source: ESRI, 2010; NYSDAM, 2010, 2011

 Agri-tourism in Chautauqua County focuses on wineries in the northern portion of the county and
scenic drives and farmers markets in the southern and eastern portions of the county. Another
large part of agri-tourism here centers on the county’s Amish Country (Tour Chautauqua 2011b).
Other industries also play important roles in the community character of Region C. In
Chautauqua County, tourism based on recreational opportunities and historical and cultural sites
and events is important throughout the county. Dunkirk, which is strategically located along Lake
Erie, is described by the Chautauqua County Chamber of Commerce as having financial and
technological support networks that provide businesses with competitive opportunities for growth
(Chautauqua County Chamber of Commerce 2011b). The village of Fredonia is home to the State
University of New York (SUNY) Fredonia campus, and the educational industry forms a large
part of the community’s character (Chautauqua County Chamber of Commerce 2011c).
Jamestown serves as an industrial, commercial, financial, and recreational hub for southwestern
New York, and the city is home to several museums and historical resources (Chautauqua County
Chamber of Commerce 2011d). The city of Salamanca is located along the Allegheny River and
describes itself as filled with country charm. It is the only city in the U.S. that lies almost
completely within the borders of an Indian Reservation (Seneca Nation) (City of Salamanca
2011). The city is located on the northern border of Allegany State Park and serves as a yearround access point to the park. Salamanca is a center for the forestry and wood products industry
and has plentiful supplies of maple, oak, and cherry (City of Salamanca 2011).
Chautauqua County has a comprehensive plan called Chautauqua County 20/20 Comprehensive
Plan (Chautauqua County 2011b), which is designed to assist the county government in making
decisions that affect the county’s future (Chautauqua County 2011b). The plan identifies strategic
issues and goals and is intended to ensure that there is cooperation between municipalities to
achieve these goals (Chautauqua County 2011b). The plan states that Chautauqua County has an
unusually high number of natural resource assets and unique attractions, including but not limited
to farms (dairy and grape), lakes, historic towns, and the Chautauqua Institution (Chautauqua
County 2011b). The county considers its traditional agricultural base to have preserved its open
space and rural charm, which is a significant aspect of the county’s community character
(Chautauqua County 2011b).

Final SGEIS 2015, Page 2-188

 Cattaraugus County. Cattaraugus County is located directly east of Chautauqua County and is
also located within the Southern Tier of New York. The county has a total area of 1,322 square
miles, including 1,310 square miles of land and 12 square miles of surface water (lakes, ponds,
rivers, and streams). Cattaraugus County has a much lower population density than Chautauqua
County, at 61 persons per square mile. Within the county are 34 cities/towns and 13 villages, as
well as 12 school districts (Cattaraugus County 2011; New York Schools 2011f).
Cattaraugus County is much more rural than Chautauqua County, with small towns and rural
characteristics. There are three Native American reservations wholly or partially within
Cattaraugus County. The county’s geology was sculpted by glaciers during the last glacial
period, and the county is drained by two significant waterways, the Allegheny River in the south
and Cattaraugus Creek in the north (Enchanted Mountains 2011a).
The existing land use pattern in Cattaraugus County has been significantly influenced by the
topography of the region. Glaciers and rivers have sculpted the county into a mountainous region
ideal for a wide variety of outdoor recreational activities, including skiing, hiking, hunting, and
camping, and the fertile valleys support productive agricultural communities.
According to the Census of Agriculture, in 2007 there were 1,122 farms in Cattaraugus County,
which cover approximately 183,000 acres (USDA 2007). In 2007 the average size of a farm in
the county was 163 acres (USDA 2007). The principal sources of farm income are dairy
products; nursery, greenhouse, floriculture, and sod; and cattle/calves (USDA 2007). Dairy
products account for approximately 68% of agricultural sales in the county (USDA 2007).
However, in recent years, dairy farming has declined in Cattaraugus County, especially in areas
around towns/cities where the majority of commerce is not based on agriculture, such as around
Ellicottville, where tourism is the main source livelihood (Cattaraugus County 2007). As of 2011,
there were approximately 240,000 acres of land within six state-designated agricultural districts in
Chautauqua County (NYSDAM 2011).
Agri-tourism is an important industry in Cattaraugus County. Agri-tourism in this county centers
on maple syrup production and the Amish Trail, which is located in the western portion of
Cattaraugus County (Enchanted Mountains 2011b; GOACC 2011).

Final SGEIS 2015, Page 2-189

 The city of Olean is the commercial and industrial hub of Cattaraugus County (GOACC 2011). The
city has a rich commercial and industrial history and is currently home to several large corporations,
including manufacturers such as Dresser-Rand and Cutco-Alcas. This regional industrial and
commercial center is necessary to maintain the rural character of the rest of Cattaraugus County.
The role of the Cattaraugus County Planning Department is to assist local communities with
comprehensive planning, land use and zoning, floodplains and watersheds, census data and
demographics, planning for agriculture, and any downtown revitalization projects (Cattaraugus
County 2011). Cattaraugus County empowers the local municipalities to develop their own planning
documents (Cattaraugus County 2011). Development of comprehensive plans is generally left to the
discretion of county and town zoning and planning boards, which originally adopted traditional forms
of regulation in an effort to protect land use and natural resources. Local and regional development is
guided by a number of open-space plans, comprehensive plans, and strategic plans. These documents
broadly reflect a community’s history, values, future goals, and character.
Cattaraugus County does not have a comprehensive or master plan, but many of its municipalities
have a comprehensive/master plan, land use regulations/laws, and zoning maps. A brief review of
representative local planning documents indicated that several communities in the county are
concerned with protecting sensitive areas, promoting tourism through recreation activities,
maintaining a small town/rural feel, maintaining the natural environment, and creating a balance of
the rural character and protection of the environment with appropriate economic development.
Affordable housing and real estate also is important to the communities. For example, the Town of
Portville Comprehensive Plan outlines the following goals: “… maintain the rural character of the
Town, and at the same time provide for anticipated growth and development … [and] … maintain the
predominantly rural character by preserving natural woodlands and floodplains, conserving the
productive farms as much as possible, encouraging open space areas as a integral part to any new
residential development, and concentrating intensive residential and commercial uses into selected
centers of activity” (Town of Portville 2003).
In Cattaraugus County, Allegany State Park and the Enchanted Mountains provide recreational
opportunities and associated jobs. The village of Ellicottville flourishes on the tourism industry,
which centers on two major ski resorts. In the city of Olean, commerce is centered on industry
(GOACC 2011).

Final SGEIS 2015, Page 2-190

 Chapter 3
Proposed SEQR Review Process
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Chapter 3 - Proposed SEQRA Review Process
CHAPTER 3 PROPOSED SEQRA REVIEW PROCESS ............................................................................................. 3-1
3.1 INTRODUCTION – USE OF A GENERIC ENVIRONMENTAL IMPACT STATEMENT .............................................................. 3-1
3.1.1 1992 GEIS and Findings.............................................................................................................................. 3-2
3.1.2 Need for a Supplemental GEIS................................................................................................................... 3-3
3.2 FUTURE SEQRA COMPLIANCE ........................................................................................................................ 3-4
3.2.1 Scenarios for Future SEQRA Compliance under the SGEIS ........................................................................ 3-4
3.2.2 Review Parameters .................................................................................................................................... 3-6
3.2.2.1 SGEIS Applicability - Definition of High-Volume Hydraulic Fracturing ............................................ 3-6
3.2.2.2 Project Scope .................................................................................................................................. 3-7
3.2.2.3 Size of Project ................................................................................................................................. 3-7
3.2.2.4 Lead Agency .................................................................................................................................... 3-8
3.2.3 EAF Addendum and Additional Informational Requirements ................................................................... 3-8
3.2.3.1 Hydraulic Fracturing Information ................................................................................................... 3-9
3.2.3.2 Water Source Information .............................................................................................................. 3-9
3.2.3.3 Distances ....................................................................................................................................... 3-10
3.2.3.4 Water Well Information ................................................................................................................ 3-11
3.2.3.5 Fluid Disposal Plan ........................................................................................................................ 3-12
3.2.3.6 Operational Information ............................................................................................................... 3-12
3.2.3.7 Invasive Species Survey and Map ................................................................................................. 3-13
3.2.3.8 Required Affirmations................................................................................................................... 3-13
3.2.3.9 Local Planning Documents ............................................................................................................ 3-14
3.2.3.10 Habitat Fragmentation ................................................................................................................. 3-14
3.2.4 Prohibited Locations ................................................................................................................................ 3-15
3.2.5 Projects Requiring Site-Specific SEQRA Determinations of Significance ................................................. 3-15
3.3 REGULATIONS ........................................................................................................................................... 3-17

Final SGEIS 2015, Page 3-i

 This page intentionally left blank.

Chapter 3 PROPOSED SEQRA REVIEW PROCESS
3.1

Introduction – Use of a Generic Environmental Impact Statement

The Department’s regulations to implement SEQRA 50 authorize the use of a generic
environmental impact statement (EIS) to assess the environmental impacts of separate actions
having similar types of impacts. 51 Additionally, a generic EIS and its findings “should set forth
specific conditions or criteria under which future actions will be undertaken or approved,
including requirements for any subsequent SEQRA compliance” 52 such as the need for a
supplemental environmental impact statement (SEIS). The course of action following a final
generic EIS depends on the level of detail within the generic EIS, as well as the specific followup actions being considered. In considering a subsequent action such as permitting horizontal
drilling and high-volume hydraulic fracturing in the Marcellus Shale and other low-permeability
reservoirs, the Department must evaluate the generic EIS to determine whether the impacts from
the subsequently proposed action (i.e., approval of the permit application) are not addressed, or
are inadequately addressed, in the generic EIS, and, in either case, whether the subsequent action
is likely to have one or more significant adverse environmental impacts. If significant adverse
impacts of the subsequent action are identified, and they are not adequately addressed in the
generic EIS, then a site- or project-specific SEIS must be prepared. Under the regulations,
generic EISs and their findings should identify the environmental issues or thresholds that would
trigger the need for a SEIS. However, if the Department determines that the final generic EIS
adequately addresses all potential significant adverse impacts of the subsequently proposed
action, then no SEIS is necessary. The SEQRA regulations pertaining to generic EISs (6
NYCRR §617.10[d][1]) provide that when a final generic EIS has been filed, “no further
SEQRA compliance is required if a subsequent proposed action will be carried out in

50

SEQR regulations are available at available at http://www.dec.ny.gov/regs/4490.html.

51

6 NYCRR §617.10(a). The regulations define the uses and functions of generic EISs. Frequently asked questions on the use of
generic environmental impact statements are posted on the Department’s website at
http://www.dec.ny.gov/permits/56701.html.

52

6 NYCRR §617.10(c).

Final SGEIS 2015, Page 3-1

 conformance with the conditions and thresholds established for such actions” in the generic
EIS. 53
3.1.1

1992 GEIS and Findings

Drilling and production of separate oil and gas wells, and other wells regulated under ECL 23
have common types of impacts. Therefore, the Department issued the 1992 GEIS and Findings
Statement to cover oil, gas and solution mining activities regulated under ECL 23. The 1992
GEIS is incorporated by reference into this document. 54 Based on the 1992 GEIS, the
Department found that issuance of a standard, individual oil or gas well drilling permit anywhere
in the state, when no other permits are involved, would not have a significant environmental
impact. 55 See Appendix 2.
Also, in the 1992 Findings Statement, the Department found that issuance of a drilling permit for
a location in a State Parkland, in an Agricultural District, or within 2,000 feet of a municipal
water supply well, or for a location which requires other Department permits, may be significant
and required a site-specific SEQRA determination. Under the 1992 GEIS, the only instance
where issuance of an individual permit to drill an oil or gas well is always deemed significant
and therefore always requires an SEIS is when the proposed location is within 1,000 feet of a
municipal water supply well.
As part of the 1992 GEIS, the Department also evaluated the action of leasing of state land for
oil and gas development and found no significant environmental impacts associated with that
action. 56 Specifically, the Department concluded that lease clauses and the permitting process
with its attendant environmental review would result in mitigation of any potential impacts that
could result from a proposal to drill. See Appendix 3.

53

6 NYCRR §617.10(d)(1).

54

http://www.dec.ny.gov/energy/45912.html.

55

http://www.dec.ny.gov/docs/materials_minerals_pdf/geisfindorig.pdf.

56

Sovas GH, April 19, 2003 (http://www.dec.ny.gov/docs/materials_minerals_pdf/geisfindsup.pdf).

Final SGEIS 2015, Page 3-2

 3.1.2

Need for a Supplemental GEIS

As mentioned above, the SEQRA regulations require preparation of a supplement to a final
generic EIS if a subsequent proposed action may have one or more significant adverse
environmental impacts that were not addressed in the 1992 GEIS. 57 In 2008, the Department
determined that some aspects of the current and anticipated application of horizontal drilling and
high-volume hydraulic fracturing warranted further review in the context of a SGEIS, or
Supplement. This determination was based primarily upon three concerns, as follows: (1) highvolume hydraulic fracturing would require water volumes far in excess of generic EIS
descriptions (in the 1992 GEIS), (2) the possibility of drilling taking place in the NYC
Watershed, in or near the Catskill Park, and near the federally-designated Upper Delaware
Scenic and Recreational River, and (3) the longer duration of disturbance likely to take place at
multi-well drilling sites.
1) Water Volumes: Multi-stage hydraulic fracturing of horizontal shale wells may require
the use and management of millions of gallons of water for each well. This raised
concerns about the volume of chemical additives present on a site, withdrawal of large
amounts of water from surface water bodies, and the management and disposal of
flowback water;
2) Anticipated Drilling Locations: While the 1992 GEIS does address drilling in watersheds
that are major sources of drinking water supply, areas of rugged topography, unique
habitats and other sensitive areas, oil and gas activity in the eastern third of the State was
rare to non-existent at the time of publication. Although the 1992 Findings have
statewide applicability, the revised draft SGEIS examines whether additional regulatory
controls are needed in any of the new geographic areas of interest given the attributes and
characteristics of those areas. For example, the 1992 GEIS did not address the possibility
of drilling in the vicinity of the NYC watershed area which lies in the prospective area for
Marcellus Shale drilling; and
3) Multi-well pads: Well operators previously suggested that as many as 16 horizontal
wells could be drilled at a single well site, or pad. As stated in the following chapters,
current information suggests that 6 to 10 wells per pad is the likely distribution. While
this method will result in fewer well pads and thus fewer disturbed surface locations, it
will also result in a longer duration of disturbance at each drilling pad than if only one
well were to be drilled there, and a greater intensity of activity at those sites. ECL §2357

6 NYCRR §617.10(d)(4).

Final SGEIS 2015, Page 3-3

 0501(1)(b)(1)(vi) requires that all horizontal infill wells in a multi-well shale unit be
drilled within three years of the date the first well in the unit commences drilling. The
potential impacts of this type of multi-well project were not analyzed in the 1992 GEIS.
3.2

Future SEQRA Compliance

The 1992 Findings Statement describes the well permit and attendant environmental review
processes for individual oil and gas wells. Under the 1992 Findings Statement, each application
to drill a well is deemed by the Department an individual project, meaning each application
requires individual review. In terms of SEQRA compliance, the Department considers itself the
appropriate lead agency for purposes of SEQRA review involving such applications inasmuch as
the Department is the agency principally responsible under ECL §23-0303(2) for regulating oil
and gas development activities with local government jurisdiction being limited to local roads
and the rights of local governments under the Real Property Tax Law. The Department does not
propose to change these aspects of its review.
3.2.1


Scenarios for Future SEQRA Compliance under the SGEIS
FIRST SCENARIO: Applications that conform with the 1992 GEIS and the SGEIS.

Generally, when application documents 58 demonstrate conformance with the thresholds and
conditions for such actions to proceed under the 1992 GEIS and the SGEIS, SEQRA would be
deemed satisfied, and no further SEQRA process would be required. Upon receipt of an
application for a well permit, which will be accompanied by the detailed project-specific
information described in Appendix 6, Department staff will determine based on detailed projectspecific information whether the application conforms to the conditions and thresholds described
in the 1992 GEIS and the SGEIS that entitle the application to be covered by the 1992 GEIS and
the SGEIS. If the application conforms to the 1992 GEIS and the SGEIS, Department staff will
file a record of consistency statement and no further review under SEQRA will occur in
connection with the processing of the well permit application. Permit conditions will be added
on a site-specific basis to ensure compliance with the requirements of the 1992 GEIS, the
SGEIS, and ECL 23.
58

See Appendix 4 for a copy of the Application for Permit to Drill, Deepen, Plug Back or Convert a Well Subject to the Oil, Gas
and Solution Mining Regulatory Program.

Final SGEIS 2015, Page 3-4

 

SECOND SCENARIO: Proposed action is adequately addressed in the 1992 GEIS or
the SGEIS but not in respective Findings Statement.

A supplemental findings statement must be prepared if the proposed action and impacts are
adequately addressed in the 1992 GEIS and the SGEIS but are not addressed in the previously
adopted 1992 GEIS Findings Statement or the SGEIS Findings Statement.


THIRD SCENARIO: Permit applications that are not addressed, or not adequately
addressed, in the 1992 GEIS or the SGEIS.

If the proposed action and its impacts are not addressed in the 1992 GEIS or SGEIS, then
additional information would be required to determine whether the project may result in one or
more additional significant adverse environmental impacts not assessed in the 1992 GEIS or the
SGEIS. The projects that categorically fall into this category are listed in Section 3.2.3.
Depending on the nature of the action, the additional information would include an
environmental assessment form or EAF; topographic, geologic or hydrogeologic information; air
impact analysis; chemical information or other information deemed necessary by the Department
to determine the potential for a significant adverse environmental impact. A project-specific
SEQRA determination will either result in 1) a negative declaration (determination of no
potentially significant impact), or 2) a positive declaration (requiring the preparation of a sitespecific SEIS for the drilling application).
Examples since 1992 where such site-specific determinations have been made include the
following actions: i) underground gas storage projects, ii) well sites where special noise
mitigation measures are required, iii) well sites that disturb more than two and a half acres in
designated Agricultural Districts, and iv) geothermal wells drilled in proximity to NYC water
tunnels. As stated above, under the 1992 GEIS wells closer than 2,000 feet to a municipal water
supply well would also require further site-specific review. None have been permitted since
1992. The following sections explain how this Supplement will be used, together with the
previous 1992 GEIS, to satisfy SEQRA in certain instances when high-volume hydraulic
fracturing is proposed.

Final SGEIS 2015, Page 3-5

 3.2.2

Review Parameters

In conducting SEQRA reviews, the Department will handle the topics of i) SGEIS applicability,
ii) individual project scope, iii) project size and iv) lead agency as follows.
3.2.2.1 SGEIS Applicability - Definition of High-Volume Hydraulic Fracturing
High-volume hydraulic fracturing is done in multiple stages, typically using 300,000-600,000
gallons of water per stage (Chapter 5). High-volume hydraulic fracturing in a vertical well
would be comparable to a single stage. Wells hydraulically fractured with less water are
generally associated with smaller well pads and many fewer truck trips, and do not trigger the
same potential water sourcing and disposal impacts as high-volume hydraulically fractured wells.
Therefore, for purposes of the SGEIS and application of the mitigation requirements described
herein, high-volume hydraulic fracturing is defined as hydraulic fracturing that uses 300,000 or
more gallons of water, regardless of whether the well is vertical, directional or horizontal. Wells
requiring 299,999 or fewer gallons of water to fracture low-permeability reservoirs are not
considered high-volume, and will be reviewed and permitted pursuant to the 1992 GEIS and
Findings Statement.
Potential impacts directly related to water volume are associated with i) water withdrawals, ii)
the volume of materials present on the well pad for fracturing, iii) the handling and disposition of
flowback water, and iv) road use by trucks to haul both fresh water and flowback water. The
Department proposes the following methodology, applicable to both vertical and horizontal wells
that will be subjected to hydraulic fracturing:
≤ 299,999 gallons of water: Not considered high-volume; 1992 GEIS mitigation is sufficient;
and
≥ 300,000 gallons of water: Always considered high-volume. The applicant must complete the
EAF Addendum. All relevant procedures and mitigation measures
set forth in this Supplement are required to satisfy SEQRA without
a site-specific determination.

Final SGEIS 2015, Page 3-6

 3.2.2.2 Project Scope
As was the case under the 1992 GEIS, each application to drill a well will continue to be
considered as an individual project with respect to well drilling, construction, hydraulic
fracturing (including additive use), and any aspects of water and materials management (source,
containment and disposal) that vary between wells on a pad. Well permits will be individually
issued and conditioned based on review of well-specific application materials. However,
location screening for well pad setbacks and other required permits, review of access road
location and construction, and the required stormwater permit coverage will be for the well pad
based on submission of the first well permit application for the pad.
The only case where the project scope extends beyond the well pad and its access road is when
the application documents propose surface water withdrawals that have not been previously
approved by the Department. Such proposed withdrawals will be considered part of the project
scope for the first well permit application that indicates their use, and all well permit applications
that propose their use will be considered incomplete until the Department has approved the
withdrawal.
Gathering lines and pipelines are not within the scope of project review as the PSC has exclusive
jurisdiction to review these activities under Public Service Law Article VII. Compressor stations
associated with gathering lines and pipelines are also under the PSC’s Public Service Law
Article VII review authority except that the Department has jurisdiction under ECL Article 19
(Air Pollution Control) to review air emissions and ECL Article 17 for the SPDES program. The
foregoing is discussed in greater detail in Chapter 3 of the GEIS and Section 1.5 of the Final
Scope. Chapter 5 of this Supplement describes the facilities likely to be associated with a multiwell shale gas production site, and Chapter 8 provides details on the PSC’s environmental review
process for these facilities.
3.2.2.3 Size of Project
The size of the project will continue to be defined as the surface acreage affected by
development, including the well pad, the access roads, and any other physical alteration
necessary. The Department’s well drilling and construction requirements, including the
supplementary permit conditions proposed herein, preclude any subsurface impacts other than

Final SGEIS 2015, Page 3-7

 the permitted action to recover hydrocarbons. Most wells will be drilled on multi-well pads,
described in Chapter 5 as likely an average of 3.5 acres in size, with larger pads possible, during
the drilling and hydraulic fracturing stages of operations. Average production pad size, after
reclamation, is likely to be 1.5 acres for a multi-well pad. Pads for vertical wells would be
smaller. Access road acreage depends on the location, the length of the road and other factors.
In general, each 150 feet of access road adds 1/10th of an acre to the total surface acreage
disturbance.
Surface water withdrawal sites will generally consist of hydrants, meters, power facilities, a
gravel pad for water truck access, and possibly one or more storage tanks. These sites would
generally be expected to be rather small, less than an acre or two in size.
3.2.2.4 Lead Agency
For the reasons set out in section 3.2 above, the Department would in most, if not all, instances
continue to assert the lead agency role under SEQRA. If the proposed action falls under the
jurisdiction of more than one agency, based, for example, on the need for a local floodplain
development permit, the lead agency must in the first instance be determined by agreement
among the involved agencies. Disputes are decided by the Department’s Commissioner pursuant
to 6 NYCRR §617.6(b)(5). Where there is an involved agency or agencies other than the
Department (meaning another agency with jurisdiction to fund, approve, or undertake the
action), to the extent practicable, the Department will seek lead agency designation, which is
consistent with the criteria for such designation under SEQRA.
3.2.3

EAF Addendum and Additional Informational Requirements

The 1992 Findings authorized use of a shortened, program-specific environmental assessment
form (EAF), which is required with every well drilling permit application. 59 (See Appendices 2
and 5). The EAF and well drilling application form 60 do not stand alone, but are supported by
the four-volume 1992 GEIS, the applicant’s well location plat, proposed site-specific drilling and
well construction plans, Department staff's site visit, and geographic information system (GIS) 59

http://www.dec.ny.gov/docs/materials_minerals_pdf/eaf_dril.pdf . Under 6 NYCRR §617.2(m) of the SEQRA regulations, the
model full and short EAFs may be modified by an agency to better serve it in implementing SEQR, provided the scope of the
modified form is as comprehensive as the model.

60

http://www.dec.ny.gov/docs/materials_minerals_pdf/dril_req.pdf.

Final SGEIS 2015, Page 3-8

 based location screening, using the most current data available. Oil and gas staff within the
Department consults and coordinates with staff in other Department programs administered by
the Department when site review and the application documents indicate an environmental
concern or potential need for another Department permit.
The Department has developed an EAF Addendum for gathering and compiling the information
needed to evaluate high-volume hydraulic fracturing projects (≥300,000 gallons) in the context
of this SGEIS and its Findings Statement, and to identify the required site-specific mitigation
measures. The EAF Addendum will be required as follows:
1) With the application to drill the first well on a pad constructed for high-volume
hydraulic fracturing, regardless of whether the well is vertical or horizontal;
2) With the applications to drill subsequent wells for high-volume hydraulic
fracturing on the pad if any of the information changes; and
3) Prior to high-volume re-fracturing of an existing well.
Categories of information required with the EAF addendum are summarized below, and
Appendix 6 provides a full listing of the proposed EAF Addendum requirements.
3.2.3.1 Hydraulic Fracturing Information
Required information will include the minimum depth and elevation of the top of the fracture
zone, estimated maximum depth and elevation of the bottom of potential fresh water,
identification of the proposed fracturing service company and additive products, the proposed
volume of fracturing fluid and percent by weight of water, proppants and each additive.
Documentation of the operator’s evaluation of alternatives to the proposed additive products will
also be required.
3.2.3.2 Water Source Information
The operator will be required to identify the source of water to be used for hydraulic fracturing,
and provide information about any newly proposed surface water source that has not been
previously approved by the Department as part of a well permit application. The proposed
withdrawal location and type of source (e.g., stream, lake, pond, groundwater, etc.) and other

Final SGEIS 2015, Page 3-9

 detailed information will be required to allow the Department to analyze potential impacts and,
in the case of stream withdrawals, to ensure the operator’s compliance relative to passby flow
and the narrative flow standard in 6 NYCRR §703.2.
3.2.3.3 Distances
Distances to the following resources or cultural features will be required, along with a
topographic map of the area showing the well pad, well location, and scaled distances from the
proposed surface location of the well and the closest edge of the well pad to the relevant
resources and features.
•

Any known public water supply reservoir, river or stream intake, public or private water
well or domestic supply spring within 2,640 feet;

•

Any primary or principal aquifer boundary, perennial or intermittent stream, wetland,
storm drain, lake or pond within 660 feet;

•

Any residences, occupied structures or places of assembly within 1,320 feet.

•

Capacity of rig fueling tank(s) and distance to:
o Any public or private water well, domestic-supply spring, reservoir, river or
stream intake, perennial or intermittent stream, storm drain, wetland, lake or pond
within 500 feet of the planned location(s) of the fueling tank(s); and

•

Distance from the surface location of the proposed well to the surface location of any
existing well that is listed in the Department’s Oil & Gas Database 61 or any other
abandoned well identified by property owners or tenants within a) the spacing unit of the
proposed well and/or b) within 1 mile (5,280 feet) of the proposed well location,
whichever results in the greatest number of wells. For each well identified, the following
information would be required, if available:
o Well name and API Number;
o Well type;
o Well status;

61

The Department’s Oil & Gas Database contains information on more than 35,000 oil, gas, storage, solution salt, stratigraphic,
and geothermal wells categorized under Article 23 of the ECL as Regulated Wells. The Oil & Gas database can be accessed on
the Department’s website at http://www.dec.ny.gov/cfmx/extapps/GasOil/.

Final SGEIS 2015, Page 3-10

 o Well orientation; and
o Quantity and type of any freshwater, brine, oil or gas encountered during drilling,
as recorded on the Department’s Well Drilling and Completion Report.
3.2.3.4 Water Well Information
The EAF addendum for high-volume hydraulic fracturing will require evidence of diligent
efforts by the well operator to determine the existence of public or private water wells and
domestic-supply springs within half a mile (2,640 feet) of any proposed drilling location. The
operator will be required to identify the wells and provide available information about their
depth, and completed interval, along with a description of their use. Use information will
include whether the well is public or private, community or non-community and the type of
facility or establishment if it is not a private residence. Information sources available to the
operator include:
•

direct contact with municipal officials;

•

direct communication with property owners and tenants;

•

communication with adjacent lessees;

•

EPA’s Safe Drinking Water Act Information System database, available at
http://oaspub.epa.gov/enviro/sdw_form_v2.create_page?state_abbr=NY; and

•

The Department’s Water Well Information search wizard, available at
http://www.dec.ny.gov/cfmx/extapps/WaterWell/index.cfm?view=searchByCounty.

Additionally, geodata on water wells in New York State is available from the Department in
KML (Keyhole Markup Language) and shape file formats. To access and download water well
information, go to: http://www.dec.ny.gov/geodata/ptk.
Upon receipt of a well permit application, Department staff will compare the operator’s well list
to internally available information and notify the operator of any discrepancies or additional
wells that are indicated within half a mile of the proposed well pad. The operator will be
required to amend its EAF Addendum accordingly.

Final SGEIS 2015, Page 3-11

 3.2.3.5 Fluid Disposal Plan
The Department’s oil and gas regulations, specifically 6 NYCRR §554.1(c)(1), require a fluid
disposal plan to be approved by the Department prior to well permit issuance for “any operation
in which the probability exists that brine, salt water or other polluting fluids will be produced or
obtained during drilling operations in sufficient quantities to be deleterious to the surrounding
environment . . .” To fulfill this obligation, the EAF Addendum will require information about
flowback water and production brine disposition, including:
•

Planned transport off of well pad (truck or piping), and information about any proposed
piping;

•

Planned disposition (e.g., treatment facility, disposal well, reuse, or centralized tank
facility); and

•

Identification and permit numbers for any proposed treatment facility or disposal well
located in New York.

3.2.3.6 Operational Information
Other required information about well pad operations will include:
1. Information about the planned construction and capacity of the reserve pit;
2. Information about the number and individual and total capacity of receiving tanks on the
well pad for flowback water;
3. Indication of the timing of the use of a closed-loop tank system (e.g., surface,
intermediate and/or production hole);
4. Information about any off-site cuttings disposal plan;
5. If proposed flowback vent/flare stack height is less than 30 feet, then documentation that
previous drilling at the pad did not encounter H2S is required;
6. Description of planned public access restrictions, including physical barriers and distance
to edge of well pad;
7. Identification of the EPA Tiers of the drilling and hydraulic fracturing engines used, if
these use gasoline or diesel fuel. If particulate traps or SCR are not used, a description of

Final SGEIS 2015, Page 3-12

 other control measures planned to reduce particulate matter and nitrogen oxide emissions
during the drilling and hydraulic fracturing processes;
8. If condensate tanks are to be used, their capacity and the vapor recovery system to be
used;
9. If a wellhead compressor is used, its size in horsepower and description the control
equipment used for nitrogen oxides (NOx); and
10. If a glycol dehydrator is to be used at the well pad, its stack height and the capacity of
glycol to be used on an annual basis.
3.2.3.7 Invasive Species Survey and Map
The Department will require that well operators submit, with the EAF Addendum, a
comprehensive survey of the entire project site, documenting the presence and identity of any
invasive plant species. As described in Chapter 7, this survey will establish a baseline measure
of percent aerial coverage and, at a minimum, must include the plant species identified on the
Interim List of Invasive Plant Species in New York State. A map (1:24,000) showing all
occurrences of invasive species within the project site must be produced and included with the
survey as part of the EAF Addendum.
3.2.3.8 Required Affirmations
The EAF Addendum will require operator affirmations to address the following:
•

passby flow for surface water withdrawals;

•

review of local floodplain maps;

•

residential water well sampling and monitoring;

•

access road location;

•

stormwater permit coverage;

•

use of ultra-low sulfur fuel;

•

preparation of site plans to address visual and noise impacts, invasive species mitigation
and greenhouse gas emissions;

Final SGEIS 2015, Page 3-13

 •

adherence to all well permit conditions; and

•

adherence to best management practices for reducing direct impacts to terrestrial habitats
and wildlife.

3.2.3.9 Local Planning Documents
The EAF Addendum will require the applicant to identify whether the location of the well pad,
or any other activity under the jurisdiction of the Department, conflicts with local land use laws,
regulations, plans or policies. The applicant will also be required to identify whether the well
pad is located in an area where the affected community has adopted a comprehensive plan or
other local land use plan and whether the proposed action is inconsistent with such plan(s).
3.2.3.10

Habitat Fragmentation

Applicants proposing well pads in Forest or Grassland Focus Areas that involve a disturbance in
a contiguous forest patch of 150 acres or more in size or a contiguous grassland patch of 30 acres
or more in size should not submit the EAF or a well permit application prior to conducting a sitespecific ecological assessment in accordance with a detailed study plan that has been approved
by the Department. The need and plan for an ecological assessment should be determined in
consultation with the Department and will consider information such as existing site conditions,
existing vegetative cover and ongoing and historical land management activities. The completed
ecological assessment must be attached to the EAF and must include, at a minimum:
•

A compilation of historical information about use of the area by forest interior birds or
grassland birds;

•

Results of pre-disturbance biological studies, including a minimum of one year of field
surveys at the site to determine the current extent, if any, of use of the site by forest
interior birds or grassland birds;

•

An evaluation of potential impacts on forest interior or grassland birds from the project;

•

Additional mitigation measures proposed by applicant; and

•

Protocols for monitoring of forest interior or grassland birds during the construction
phase of the project and for a minimum of two years following well completion.

Final SGEIS 2015, Page 3-14

 3.2.4

Prohibited Locations

The Department will not issue well permits for high-volume hydraulic fracturing at the following
locations:
1) Any proposed well pad within the NYC and Syracuse watersheds;
2) Any proposed well pad within a 4,000-foot buffer around the NYC and Syracuse
watersheds;
3) Any proposed well pad within a primary aquifer (subject to reconsideration 2 years after
issuance of the first permit for high-volume hydraulic fracturing);
4) Any proposed well pad within a 500-foot buffer around primary aquifers (subject to
reconsideration 2 years after issuance of the first permit for high-volume hydraulic
fracturing);
5) Any proposed well pad within 2,000 feet of public water supply wells, river or stream
intakes and reservoirs (subject to reconsideration 3 years after issuance of the first permit
for high-volume hydraulic fracturing);
6) Any proposed well pad within 500 feet of private drinking water wells or domestic use
springs, unless waived by the owner; and
7) Any proposed well pad within a 100-year floodplain.
3.2.5

Projects Requiring Site-Specific SEQRA Determinations of Significance

The Department proposes that site-specific environmental assessments and SEQRA
determinations of significance be required for the high-volume hydraulic fracturing projects
listed below, regardless of the target formation, the number of wells drilled on the pad and
whether the wells are vertical, directional or horizontal.
1) Any proposed high-volume hydraulic fracturing where the top of the target fracture
zone is shallower than 2,000 feet along any part of the proposed length of the
wellbore;
2) Any proposed high-volume hydraulic fracturing where the top of the target fracture
zone at any point along any part of the proposed length of the wellbore is less than
1,000 feet below the base of a known fresh water supply;

Final SGEIS 2015, Page 3-15

 3) Any proposed well pad within 500 feet of a principal aquifer;
4) Any proposed well pad within 150 feet of a perennial or intermittent stream, storm
drain, lake or pond;
5) A proposed surface water withdrawal that is found not to be consistent with the
Department’s preferred passby flow methodology as described in Chapter 7;
6) Any proposed water withdrawal from a pond or lake;
7) Any proposed ground water withdrawal within 500 feet of a private well;
8) Any proposed ground water withdrawal within 500 feet of a wetland that pump test
data shows would have an influence on the wetland;
9) Any proposed well location determined by NYCDEP to be within 1,000 feet of its
subsurface water supply infrastructure; and
10) Any proposed centralized flowback water surface impoundment.
The Department will re-evaluate the need for site-specific SEQRA determinations within 500
feet of principal aquifers two years after issuance of the first permit for high-volume hydraulic
fracturing.
The Department is not proposing to alter its 1992 Findings that proposed disposal wells require
individual site-specific review or that proposed disturbances larger than 2.5 acres in designated
Agricultural Districts require a site-specific SEQRA determination. According to the
information received to date, the drilling of all high-volume hydraulically fractured wells will
create surface disturbances in excess of 2.5 acres. The Department will consult with the
Department of Agriculture and Markets to develop permit conditions, best management practices
(BMP) requirements and reclamation guidelines to be followed when the proposed disturbance is
larger than 2.5 acres on a farm in an Agricultural District. Staff will perform the SEQRA review
and publish the results in the Environmental Notice Bulletin (ENB). A large number of
agricultural districts are currently located in areas where high-volume hydraulic fracturing
drilling is expected to occur but many of these districts have reverted to forestlands and are no
longer in agricultural production. Mineral Resources will provide guidance to gas well operators

Final SGEIS 2015, Page 3-16

 to achieve the goal of reducing or minimizing the surface disturbance to agricultural farmlands.
Examples of the proposed Agricultural District requirements include but are not limited to:
•

decompaction and deep ripping of disturbed areas prior to topsoil replacement;

•

removal of construction debris from the site;

•

no mixing of cuttings with topsoil;

•

removal of spent drilling muds from active agricultural fields;

•

location of well pads/access roads along field edges and in nonagricultural areas (where
possible);

•

removal of excess subsoil and rock from the site; and

•

fencing of the site when drilling is located in active pasture areas to prevent livestock
access.

Proposed projects that require other Department permits will continue to require site-specific
SEQRA determinations regarding the activities covered by those permits, with one exception.
Required coverage under a general stormwater permit does not result in the need for a sitespecific SEQRA determination, as the Department issues its general permits pursuant to a
separate process.
3.3

Regulations

The Department’s oil and gas well regulations, located at 6 NYCRR Parts 550 - 559, contain
permitting, recordkeeping, and operating requirements for oil and gas wells. More detailed
requirements applicable to drilling operations are routinely attached as conditions to well drilling
permits issued pursuant to the ECL. Additionally, the Department’s regulations concerning
water withdrawals, stormwater control, and the use of state lands, among others, would apply to
various aspects of high-volume hydraulic fracturing operations considered in this revised draft
SGEIS. Appendix 10 of this revised draft SGEIS contains proposed supplementary permit
conditions for high-volume hydraulic fracturing that will be attached to well drilling permits.
Although conditions incorporated into well drilling are enforceable pursuant to ECL Article 71, a
number of the application requirements specific to high-volume hydraulic fracturing as well as

Final SGEIS 2015, Page 3-17

 many of the mitigation measures discussed in this revised draft SGEIS will be set forth in
regulations. Accordingly, draft revisions and additions to the Department’s regulations will be
considered as part of the SGEIS process, pursuant to the State Administrative Procedures Act
(SAPA) for agency rulemaking.
The enactment of revisions or additions to the Department’s regulations relating to high-volume
hydraulic fracturing would have a positive effect on the environment by mitigating or otherwise
addressing potential environmental impacts from this activity. However, because these
regulations would be enacted as part of an action that would authorize high-volume hydraulic
fracturing the enactment of such regulatory revisions or additions will be considered in
conjunction with the Department’s consideration of the significant environmental impacts under
SEQRA.
SAPA contains other potential impact areas for state agencies to consider, such as the impact of
proposed rules on jobs, rural areas and the regulated community. Some of these types of impacts
are discussed in this revised draft SGEIS, but a complete examination of those types of impacts
will be evaluated within the rulemaking process. The Department will consider all information
generated by the SGEIS and SAPA processes to make determinations on how high-volume
hydraulic fracturing operations would be regulated.

Final SGEIS 2015, Page 3-18

 NEW YORK Department of

STATE OF .

OPPORTUNITYW EnVIronmental
Conservation

 

Chapter 4
Geology

Final

Supplemental Generic Environmental Impact Statement



This page intentionally left blank.

Chapter 4 - Geology
CHAPTER 4 - GEOLOGY .................................................................................................................................... 4-1
4.1 INTRODUCTION ........................................................................................................................................... 4-1
4.2 BLACK SHALES ............................................................................................................................................ 4-2
4.3 UTICA SHALE .............................................................................................................................................. 4-5
4.3.1 Total Organic Carbon ............................................................................................................................... 4-10
4.3.2 Thermal Maturity and Fairways............................................................................................................... 4-13
4.3.3 Potential for Gas Production ................................................................................................................... 4-13
4.4 MARCELLUS FORMATION ............................................................................................................................. 4-14
4.4.1 Total Organic Carbon ............................................................................................................................... 4-16
4.4.2 Thermal Maturity and Fairways............................................................................................................... 4-16
4.4.3 Potential for Gas Production ................................................................................................................... 4-17
4.5 SEISMICITY IN NEW YORK STATE .................................................................................................................... 4-23
4.5.1 Background .............................................................................................................................................. 4-23
4.5.2 Seismic Risk Zones ................................................................................................................................... 4-24
4.5.3 Seismic Damage – Modified Mercalli Intensity Scale .............................................................................. 4-27
4.5.4 Seismic Events ......................................................................................................................................... 4-27
4.5.5 Monitoring Systems in New York ............................................................................................................ 4-33
4.6 NATURALLY OCCURRING RADIOACTIVE MATERIALS (NORM) IN MARCELLUS SHALE ................................................... 4-35
4.7 NATURALLY OCCURRING METHANE IN NEW YORK STATE ..................................................................................... 4-35
FIGURES
Figure 4.1 - Gas Shale Distribution in the Appalachian Basin .................................................................................... 4-4
Figure 4.2 - Stratigraphic Column of Southwestern New York .................................................................................. 4-7
Figure 4.3 - East West Cross-Section of New York State. .......................................................................................... 4-8
Figure 4.4 - Extent of Utica Shale in New York State ................................................................................................. 4-9
Figure 4.5 - Depth to Base of Utica Shale in New York State ................................................................................... 4-11
Figure 4.6 - Thickness of High-Organic Utica Shale in New York State .................................................................... 4-12
Figure 4.7 - Utica Shale Fairway in New York State ................................................................................................. 4-15
Figure 4.8 - Depth and Extent of Marcellus Shale in New York State ...................................................................... 4-18
Figure 4.9 - Marcellus Shale Thickness in New York State....................................................................................... 4-19
Figure 4.10 - Total Organic Carbon of Marcellus Shale in New York State .............................................................. 4-20
Figure 4.11 - Marcellus Shale Thermal Maturity ..................................................................................................... 4-21
Figure 4.12 - Marcellus Shale Fairway in New York State........................................................................................ 4-22
Figure 4.13 - Mapped Geologic Faults in New York State ....................................................................................... 4-25
Figure 4.14 - New York State Seismic Hazard Map .................................................................................................. 4-26
Figure 4.15 - Seismic Events in New York State (1970 to 2009) .............................................................................. 4-34
TABLES
Table 4.1 - Modified Mercalli Scale ......................................................................................................................... 4-29
Table 4.2 - Summary of Seismic Events in New York State ...................................................................................... 4-30

Final SGEIS 2015, Page 4-i

 This page intentionally left blank.

Chapter 4 - GEOLOGY
This Chapter supplements and expands upon Chapter 5 of the 1992 GEIS. Sections 4.1 through
4.5 and the accompanying figures and tables were provided in essentially the form presented
here by Alpha Environmental, Inc., under contract to NYSERDA to assist the Department with
research related to this SGEIS. 62 Alpha’s citations are retained for informational purposes, and
are listed in the “consultants’ references” section of the Bibliography. Section 4.6 discusses how
NORM in the Marcellus Shale is addressed in the SGEIS.
The influence of natural geologic factors with respect to hydraulic fracture design and subsurface
fluid mobility is discussed Chapter 5, specifically in Section 5.8 (Hydraulic Fracturing Design),
and Appendix 11 (Analysis of Subsurface Fracturing Fluid Mobility).
4.1

Introduction

The natural gas industry in the US began in 1821 with a well completed by William Aaron Hart
in the upper Devonian Dunkirk Shale in Chautauqua County. The “Hart” well supplied
businesses and residents in Fredonia, New York with natural gas for 37 years. Hundreds of
shallow wells were drilled in the following years into the shale along Lake Erie and then
southeastward into western New York. Shale gas fields development spread into Pennsylvania,
Ohio, Indiana, and Kentucky. Gas has been produced from the Marcellus since 1880 when the
first well was completed in the Naples field in Ontario County. Eventually, as other formations
were explored, the more productive conventional oil and natural gas fields were developed and
shale gas (unconventional natural gas) exploration diminished.
The terms “conventional” and “unconventional" are related more to prevailing technology and
economics surrounding the development of a given play than to the reservoir rock type from
which the oil or natural gas resources are derived. Gas shales (also called “gas-containing
shales”) are one of a number of reservoir types that are explored for unconventional natural gas,
and this group includes such terms as: deep gas; tight gas; coal-bed methane; geopressurized
zones; and Arctic and sub-sea hydrates.
The US Energy Research and Development Administration (ERDA) began to evaluate gas
resources in the US in the late 1960s. The Eastern Gas Shales Project was initiated in 1976 by

62

Alpha, 2009.

Final SGEIS 2015, Page 4-1

 the ERDA (later the US Department of Energy) to assess Devonian and Mississippian black
shales. The studies concluded that significant natural gas resources were present in these tight
formations.
The interest in development of shale gas resources increased in the late 20th and early 21st
century as the result of an increase in energy demand and technological advances in drilling and
well stimulation. The total unconventional natural gas production in the US increased by 65%
and the proportion of unconventional gas production to total gas production increased from 28%
in 1998 to 46% in 2007. 63
A description of New York State geology and its relationship to oil, gas, and salt production is
included in the 1992 GEIS. The geologic discussion provided herein supplements the
information as it pertains to gas potential from unconventional gas resources. Emphasis is
placed on the Utica and Marcellus Shales because of the widespread distribution of these units in
New York.
4.2

Black Shales

Black shales, such as the Marcellus Shale, are fine-grained sedimentary rocks that contain high
levels of organic carbon. The fine-grained material and organic matter accumulate in deep,
warm, quiescent marine basins. The warm climate favors the proliferation of plant and animal
life. The deep basins allow for an upper aerobic (oxygenated) zone that supports life and a
deeper anaerobic (oxygen-depleted) zone that inhibits decay of accumulated organic matter. The
organic matter is incorporated into the accumulating sediments and is buried. Pressure and
temperature increase and the organic matter are transformed by slow chemical reactions into
liquid and gaseous petroleum compounds as the sediments are buried deeper. The degree to
which the organic matter is converted is dependent on the maximum temperature, pressure, and
burial depth. The extent that these processes have transformed the carbon in the shale is
represented by the thermal maturity and transformation ratio of the carbon. The more favorable
gas producing shales occur where the total organic carbon (TOC) content is at least 2% and

63

Alpha, 2009, p. 121.

Final SGEIS 2015, Page 4-2

 where there is evidence that a significant amount of gas has formed and been preserved from the
TOC during thermal maturation. 64
Oil and gas are stored in isolated pore spaces or fractures and adsorbed on the mineral grains. 65
Porosity (a measure of the void spaces in a material) is low in shales and is typically in the range
of 0 to 10 percent. 66 Porosity values of 1 to 3 percent are reported for Devonian shales in the
Appalachian Basin. 67 Permeability (a measure of a material’s ability to transmit fluids) is also
low in shales and is typically between 0.1 to 0.00001 millidarcy (md). 68 Hill et al. (2002)
summarized the findings of studies sponsored by NYSERDA that evaluated the properties of the
Marcellus Shale. The porosity of core samples from the Marcellus in one well in New York
ranged from 0 to 18%. The permeability of Marcellus Shale ranged from 0.0041 md to 0.216 md
in three wells in New York State.
Black shale typically contains trace levels of uranium that is associated with organic matter in
the shale. 69 The presence of naturally occurring radioactive materials (NORM) induces a
response on gamma-ray geophysical logs and is used to identify, map, and determine thickness
of gas shales.
The Appalachian Basin was a tropical inland sea that extended from New York to Alabama
(Figure 4.1). The tropical climate of the ancient Appalachian Basin provided favorable
conditions for generating the organic matter, and the erosion of the mountains and highlands
bordering the basin provided clastic material (i.e., fragments of rock) for deposition. The
sedimentary rocks that fill the basin include shales, siltstones, sandstones, evaporites, and
limestones that were deposited as distinct layers that represent several sequences of sea level rise
and fall. Several black shale formations, which may produce natural gas, are included in these
layers. 70

64

Alpha, 2009, p. 122.

65

Alpha, 2009, p. 122.

66

Alpha, 2009, p.122.

67

Alpha, 2009, p.122.

68

Alpha, 2009, p.122.

69

Alpha, 2009, p. 122.

70

Alpha, 2009, p. 123.

Final SGEIS 2015, Page 4-3

 Minnesota
Maine
Michigan
Iowa

New York

New Ham
p sh

Ve rmo
n

t

ire

Wisconsin

Massa

chu sett
s

Conn

Pennsylvania

Ohio

Indiana

ut

Ma
ryla

Missouri
West Virginia
Kentucky

nd

Virginia

q

New J
ersey

Illinois

ectic

Legend

Marcellus & Utica shales
Marcellus shale
Utica shale

Tennessee

Arkansas

Appalachian Basin Province

North Carolina

0

Lou isian

a

Mississippi

200 Miles

FIGURE 4.1

South Carolina
Alabama

100

GAS SHALE DISTRIBUTION IN
THE APPALACHIAN BASIN
OF THE EASTERN UNITED STATES

Georgia

Source:
- National Assessment of Oil and Gas Project - Appalachian Basin
Province. U. S. Geological Survey, Central Energy Resources
Team
Lo
uis (2002).

ian a

Map Document: (Z:\projects\2009\09100-09120\09104 - Gas Well Permitting GEIS\Figures\GIS\Appalachian_Basin.mxd)
6/4/2009 -- 1:21:45 PM

DRAFT

Final SGEIS 2015, Page 4-4

Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

 The stratigraphic column for southwestern New York State is shown in Figure 4.2 and includes oil
and gas producing horizons. This figure was initially developed by Van Tyne and Copley, 71 from
the analysis of drilling data in southwestern New York State, and it has been modified several
times since then as various authors have cited it in different studies. The version presented as
Figure 4.2 can also be found on the Department’s website at
http://www.dec.ny.gov/energy/33893.html. Figure 4.3 is a generalized cross-section from west to
east across the southern tier of New York State and shows the variation in thickness and depth of
the different stratigraphic units. This figure was initially developed by the Reservoir
Characterization Group of the New York State Museum. It is important to note that the geographic
areas represented in Figure 4.2 and Figure 4.3 are not precisely the same, and the figures were
originally developed by different authors. For example, the Marcellus Shale is shown in Figure
4.2 as the basal unit of the Hamilton Group, but it appears as a discrete unit below the Hamilton
Group in Figure 4.3 to highlight its gas-bearing potential. Similarly, the “Devonian Sandstone and
Shale” of Figure 4.3 correlates to the Conewango, Conneaut, Canadaway, West Falls, Sonyea, and
Genesee Groups of Upper Devonian age shown in Figure 4.2.
The Ordovician-aged Utica Shale and the Devonian-aged Marcellus Shale are of particular
interest because of recent estimates of natural gas resources and because these units extend
throughout the Appalachian Basin from New York to Tennessee. There are other black shale
formations (Figure 4.2 and Figure 4.3) in New York that may produce natural gas on a localized
basis. 72 The following sections describe the Utica and Marcellus Shales in greater detail.
4.3

Utica Shale

The Utica Shale is an upper Ordovician-aged black shale that extends across the Appalachian
Plateau from New York and Quebec, Canada, south to Tennessee. It covers approximately
28,500 square miles in New York and extends from the Adirondack Mountains to the southern
tier and east to the Catskill front (Figure 4.4). The Utica Shale is exposed in outcrops along the
southern and western Adirondack Mountains, and it dips gently south to depths of more than
9,000 feet in the southern tier of New York.

71

Van Tyne and Copley, 1983.

72

Alpha, 2009, p. 123.

Final SGEIS 2015, Page 4-5

 The Utica Shale is a massive, fossiliferous, organic-rich, thermally-mature, black to gray shale.
The sediment comprising the Utica Shale was derived from the erosion of the Taconic Mountains
at the end of the Ordovician, approximately 440 to 460 million years ago. The shale is bounded
below by Trenton Group strata and above by the Lorraine Formation and consists of three
members in New York State that include: Flat Creek Member (oldest), Dolgeville Member, and
the Indian Castle Member (youngest). 73 The Canajoharie Shale and Snake Hill Shale are found
in the eastern part of the state and are lithologically equivalent, but older than the western
portions of the Utica. 74
There is some disagreement over the division of the Utica Shale members. Smith & Leone
(2009) divide the Indian Castle Member into an upper low-organic carbon regional shale and a
high-organic carbon lower Indian Castle. Nyahay et al. (2007) combines the lower Indian Castle
Member with the Dolgeville Member. Fisher (1977) includes the Dolgeville as a member of the
Trenton Group. The stratigraphic convention of Smith and Leone is used in this document.
Units of the Utica Shale have abundant pyrite, which indicates deposition under anoxic
conditions. Geophysical logs and cutting analyses indicate that the Utica Shale has a low bulk
density and high total organic carbon content. 75
The Flat Creek and Dolgeville Members are found south and east of a line extending
approximately from Steuben County to Oneida County (Figure 4.4). The Dolgeville is an
interbedded limestone and shale. The Flat Creek is a dark, calcareous shale in its western extent
and grades to an argillaceous calcareous mudstone to the east. These two members are timeequivalent and grade laterally toward the west into Trenton limestones. 76 The lower Indian
Castle Member is a fissile, black shale and is exposed in road cuts, particularly at the New York
State Thruway (I-90) exit 29A in Little Falls. Figure 4.5 shows the depth to the base of the Utica
Shale. 77 This depth corresponds approximately with the base of the organic-rich section of the
Utica Shale.

73

Alpha, 2009, p. 124.

74

Alpha, 2009, p. 124.

75

Alpha, 2009, p. 124.

76

Alpha, 2009, p. 124.

77

Alpha, 2009, p. 124.

Final SGEIS 2015, Page 4-6

 Figure 4.2- Stratigr aphic Section of Southwestern New York State
Period

Unit

Group

Penn.

Pottsville

Olean

Miss.

Pocono

Knapp

Lithology
Quartz pebble conglomerate

& sandstone. quartz pebble.
conglomerate. sandstone & mtnor shale
Shale & sandstone,
scattered conglomerates

Conewango
Conneaut

Shale & siltstone,
scattered conglomerates

Chadakoin

0
Undifferentiated

1

G Shale & siltstone
0 Minor sandstone
G

Canadaway

0

Upper

2

G Shale & s iltstone
0 Minor ~andstone
G

Java
N unda
Rhine s treet

Shale & siltstone
G Argillaceous limestone

Middlesex

G Shale & s il tstone

Perrysburg

West Falls
Dev.

Sonyea

Shale with mi nor 

siltstone & limestone 


Genesee
T ully

Mtddle

Hami lton

Moscow
ludlowville
Skaneateles
Marcellus
Onondaga

Tristates

Oriskany

Helderberg

Manli us
Rondout

Lower

Akron

Salina
Upper
Lockport
Sil.
Clinton
Lower
Medina

Ord.

Limestone with minor
siltstone & sandstone
Shale with mi nor
sandstone & conglomerate

G

0 limestone

G

G Sandstone
l tmestone & dol ostone

0 Dolostone

G

Camillus
Syracuse
Vernon

s
s

Lockport

G Limestone & dolostone

Shale. siltstone.
anhydrite & hahte

Rochester
Iro ndequoit

Shale & sandstone

Sodus
Reynales
T horold

Limestone & dolost one

Grimsby
Whirlpool
Queenston
Oswego
Lorraine
Utica

Upper

G

Middle

Trenton ­
Black River

Trenton
Black River

lower

Beekmantown

Tribes Hill
Chuctanunda

G Sandstone & shale
G Quartz sandstone
G Shale & siltstone
G with mi nor sandstone
G Limestone and mtnor dolostone
Limestone & dolostone

Cam b. Upper

Quartz sandstone & dolostone;
little Falls
G sandstone &
Galway {Theresa)
sandy dolomite:
Potsdam
G conglomerate base

PreCamb.

Gneiss, Marble ,
Quartzite, etc ...

Metamorphic & 

igneous rocks 


1 - Incl udes: Glade. Bradford 1", C hipmunk. Bradford 2"", Harnsburg Run , Sclo. Penny and Richburg .
2- Incl udes: Bradford 3'd, Humphrey, C larksville, Waugh & Porter, and Fulmer Valley.
0 : Oil produci ng
G: Gas producing
S: Salt producing

Final SGEIS 2015, Page 4-7

 Otsego County

04055-00-00

10834-00-00

Chenango
County

E

Cortland
County

Tioga County

Tompkins

County

03973-00-00

Schuyler County

Chemung
County

Steuben
County

03924-00-00

Allegany
County

09235-00-00

Cattaraugus
County

Chautauqua
County

2000

22531-00-00

W


2000

Devonian Sandstone and Shale
0

e
ese
Ge n
Tully

-2000

Salina
port
Lock
n
Clinto

-4000

-4000

Medina

-6000

Queenston

Lor

e
ra i n

a
Utic
ton
Tren ver
i
c k R ill
a
l
B
H
bes ls
Tri tle Fal

-8000

Lit

Precambrian Basement

Ga

lw a

Shale

Limestone

Sand

Dolomite

Sand
and Shale

Evaporites

SSTVD (ft)

SSTVD (ft)

rg
Helderbe

Hamilton

-2000

-10000

0

Marcellusondaga
On

-6000

Precambrian
Basement

-8000

y

-10000

C-Sand
Potsdam

-11600
-12000

FIGURE 4.3

-12000

EAST WEST CROSS-SECTION
OF NEW YORK STATE

Alpha Project No. 09104

025

5

0

MILES

A. Stolorow, NYSM

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Final SGEIS 2015, Page 4-8

 Source:
- New York State Museum - Reservoir Characterization
Group (2009).
- Nyahay et al. (2007).
- U. S. Geological Survey, Central Energy Resources Team (2002).
- Fisher et al. (1970).

Legend

Utica Shale Outcrop*

Extent of the Utica Shale in New York

Approx. western
extent of Dolgeville
& Flat Creek Members
Approx. western extent
of Organic-Rich Lower
Indian Castle Member

0

50

100 Miles

FIGURE 4.4
EXTENT OF UTICA SHALE
IN NEW YORK STATE

Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Final SGEIS 2015, Page 4-9

q

 4.3.1

Total Organic Carbon

Measurements of TOC in the Utica Shale are sparse. Where reported, TOC has been measured
at over 3% by weight. 78 Nyahay et al. (2007) compiled measurements of TOC for core and
outcrop samples. TOC in the lower Indian Castle, Flat Creek, and Dolgeville Members generally
ranges from 0.5 to 3%. TOC in the upper Indian Castle Member is generally below 0.5%. TOC
values as high as 3.0% in eastern New York and 15% in Ontario and Quebec were also
reported. 79
The New York State Museum Reservoir Characterization Group evaluated cuttings from the
Utica Shale wells in New York State and reported up to 3% TOC. 80 Jarvie et al. (2007) showed
that analyses from cutting samples may underestimate TOC by approximately half; therefore, it
may be as high as 6%. Figure 4.6 shows the combined total thickness of the organic-rich
(greater than 1%, based on cuttings analysis) members of the Utica Shale. As shown on Figure
4.6, the organic-rich Utica Shale ranges from less than 50 feet thick in north-central New York
and increases eastward to more than 700 feet thick.

78

Alpha, 2009, p. 124.

79

Alpha, 2009, p. 125.

80

Alpha, 2009, p. 125.

Final SGEIS 2015, Page 4-10

 q

Legend

Depth to Base of Utica Shale*
Utica Shale Outcrop

Extent of the Utica Shale in New York

1,000
2,000
3,000

0
5,00

6,000

0

0
4,00

5,0
00

7,000

8,000

0
7,00

50

2,00
0

10,000

3,00
0
6,00
0

0
4,00

9,000

0
8,00
0
7,00 00
6,0 00
5,0

100 Miles

FIGURE 4.5
DEPTH TO BASE OF UTICA SHALE
IN NEW YORK STATE

Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Notes:
- Top of the Trenton limestone approximates the base of the Utica
shale (New York State Museum - Reservoir Characterization Group, 2009).
- U. S. Geological Survey, Central Energy Resources Team (2002).

Final SGEIS 2015, Page 4-11

 Legend

q

Utica Shale Thickness Contour (in feet)
Utica Shale Outcrop

500

300

600
650
700

100

40
0

5
10 0
15 0
0

50

0
25

250

0
25

0

0
20

200
150

300

0
15

350
45
0
55
65 0
0

0
25
35
0

400

50
1
1500
0

Extent of the Utica Shale in New York

100 Miles

FIGURE 4.6
THICKNESS OF HIGH-ORGANIC
UTICA SHALE
IN NEW YORK STATE
Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Note:
- Contours show the combined thickness of the high
organic carbon interval (>1% TOC) lower Indian Castle,
Dolgeville, Flat Creek members (New York State Museum Reservoir Characterization Group, 2009).

Final SGEIS 2015, Page 4-12

 4.3.2

Thermal Maturity and Fairways

Nyahay, et. al. (2007) presented an assessment of gas potential in the Marcellus and Utica
Shales. The assessment was based on an evaluation of geochemical data from core and outcrop
samples using methods applied to other shale gas plays, such as the Barnett Shale in Texas. A
gas production “fairway”, which is a portion of the shale most likely to produce gas based on the
evaluation, was presented. Based on the available, limited data, Nyahay et al. (2007) concluded
that most of the Utica Shale is supermature and that the Utica Shale fairway is best outlined by
the Flat Creek Member where the TOC and thickness are greatest. This area extends eastward
from a northeast-southwest line connecting Montgomery to Steuben Counties (Figure 4.7). The
fairway shown on Figure 4.7 correlates approximately with the area where the organic-rich
portion of the Utica Shale is greater than 100 feet thick shown on Figure 4.6. 81 The fairway is
that portion of the formation that has the potential to produce gas based on specific geologic and
geochemical criteria; however, other factors, such as formation depth, make only portions of the
fairway favorable for drilling. Operators consider a variety of these factors, besides the extent of
the fairway, when making a decision on where to drill for natural gas.
The results of the 2007 evaluation are consistent with an earlier report by Weary et al. (2000)
that presented an evaluation of thermal maturity based on patterns of thermal alteration of
conodont microfossils across New York State. The data presented show that the thermal
maturity of much of the Utica Shale in New York is within the dry natural gas generation and
preservation range and generally increases from northwest to southeast.
4.3.3

Potential for Gas Production

The Utica Shale historically has been considered the source rock for the more permeable
conventional gas resources. Fresh samples containing residual kerogen and other petroleum
residuals reportedly have been ignited and can produce an oily sheen when placed in water. 82
Significant gas shows have been reported while drilling through the Utica Shale in eastern and
central New York. 83

81

Alpha, 2009, p. 125.

82

Alpha, 2009, p. 126.

83

Alpha, 2009, p. 126.

Final SGEIS 2015, Page 4-13

 No Utica Shale gas production was reported to the Department in 2009. Vertical test wells
completed in the Utica in the St. Lawrence Lowlands of Quebec have produced up to one million
cubic feet per day (MMcf/d) of natural gas.
4.4

Marcellus Formation

The Marcellus Formation is a Middle Devonian-aged member of the Hamilton Group that
extends across most of the Appalachian Plateau from New York south to Tennessee. The
Marcellus Formation consists of black and dark gray shales, siltstones, and limestones. The
Marcellus Formation lies between the Onondaga limestone and the overlying Stafford-Mottville
limestones of the Skaneateles Formation 84 and ranges in thickness from less than 25 feet in
Cattaraugus County to over 1,800 feet along the Catskill front. 85 The informal name “Marcellus
Shale” is used interchangeably with the formal name “Marcellus Formation.” The discussion
contained herein uses the name Marcellus Shale to refer to the black shale in the lower part of the
Hamilton Group.
The Marcellus Shale underlies an area of approximately 18,700 square miles in New York
(Figure 4.8). The Marcellus is exposed in outcrops to the north and east and reaches depths of
more than 5,000 feet in the southern tier (Figure 4.8).
The Marcellus Shale in New York State consists of three primary members. 86 The oldest (lowermost) member of the Marcellus is the Union Springs Shale which is laterally continuous with the
Bakoven Shale in the eastern part of the state. The Union Springs and Bakoven Shales are
bounded below by the Onondaga and above by the Cherry Valley Limestone in the west and the
correlative Stony Hollow Member in the East. The upper-most member of the Marcellus Shale
is the Oatka Creek Shale (west) and the correlative Cardiff-Chittenango Shales (east). The
members of primary interest with respect to gas production are the Union Springs and

84

Alpha, 2009, p. 126.

85

Alpha, 2009, p. 126.

86

Alpha, 2009, p. 127.

Final SGEIS 2015, Page 4-14

 q

Legend

Utica Shale Outcrop

Source:
- modified from Nyahay et al. (2007)

Utica Shale Fairway

Extent of the Utica Shale in New York

Clinton
Franklin

St. Lawrence

Essex

Jefferson

Lewis
Hamilton

Warren

Oswego
Niagara

Orleans
Monroe

Oneida

Wayne

Genesee
Erie

Chautauqua

Cattaraugus

Cayuga

Ontario
Wyoming

Livingston

Yates

Cortland
Tompkins

Madison

Montgomery
Schenectady
Otsego

Chenango

Steuben
Chemung

Tioga

Saratoga

Fulton

Seneca

Schuyler
Allegany

Onondaga

Washington

Herkimer

Broome

Schoharie

Greene

Delaware

Rensselaer

Albany

Columbia

Ulster
Sullivan

0

50

100 Miles

Orange

Putnam

RocklandWestchester

FIGURE 4.7
UTICA SHALE FAIRWAY
IN NEW YORK STATE

Alpha Project No. 09104

Dutchess

Suffolk
Nassau

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Final SGEIS 2015, Page 4-15

 lower-most portions of the Oatka Creek Shale. 87 The cumulative thickness of the organic-rich
layers ranges from less than 25 feet in western New York to over 300 feet in the east (Figure
4.9). Gamma ray logs indicate that the Marcellus Shale has a slightly radioactive signature on
gamma ray geophysical logs, consistent with typical black shales. Concentrations of uranium
ranging from 5 to 100 parts per million have been reported in Devonian gas shales. 88
4.4.1

Total Organic Carbon

Figure 4.10 shows the aerial distribution of TOC in the Marcellus Shale based on the analysis of
drill cuttings sample data. 89 TOC generally ranges between 2.5 and 5.5 percent and is greatest in
the central portion of the state. Ranges of TOC values in the Marcellus were reported between 3
to 12% 90 and 1 to 10.1%. 91
4.4.2 Thermal Maturity and Fairways
Vitrinite reflectance is a measure of the maturity of organic matter in rock with respect to
whether it has produced hydrocarbons and is reported in percent reflection (% Ro). Values of
1.5 to 3.0 % Ro are considered to correspond to the “gas window,” though the upper value of the
window can vary depending on formation and kerogen type characteristics.
VanTyne (1993) presented vitrinite reflection data from nine wells in the Marcellus Shale in
Western New York. The values ranged from 1.18 % Ro to 1.65 % Ro, with an average of 1.39
% Ro. The vitrinite reflectance values generally increase eastward. Nyahay et al (2007) and
Smith & Leone (2009) presented vitrinite reflectance data for the Marcellus Shale in New York
(Figure 4.11) based on samples compiled by the New York State Museum Reservoir
Characterization Group. The values ranged from less than 1.5 % Ro in western New York to
over 3 % Ro in eastern New York.
Nyahay et al. (2007) presented an assessment of gas potential in the Marcellus Shale that was
based on an evaluation of geochemical data from rock core and outcrop samples using methods

87

Alpha, 2009, p. 127.

88

Alpha, 2009, p. 127.

89

Alpha, 2009, p. 127.

90

Alpha, 2009, p. 127.

91

Alpha, 2009, p. 127.

Final SGEIS 2015, Page 4-16

 applied to other shale gas plays, such as the Barnett Shale in Texas. The gas productive fairway
was identified based on the evaluation and represents the portion of the Marcellus Shale most
likely to produce gas. The Marcellus fairway is similar to the Utica Shale fairway and is shown
on Figure 4.12. The fairway is that portion of the formation that has the potential to produce gas
based on specific geologic and geochemical criteria; however, other factors, such as formation
depth, make only portions of the fairway favorable for drilling. Operators consider a variety of
these factors, besides the extent of the fairway, when making a decision on where to drill for
natural gas. Variation in the actual production is evidenced by Marcellus Shale wells outside the
fairway that have produced gas and wells within the fairway that have been reported dry.
4.4.3

Potential for Gas Production

Gas has been produced from the Marcellus since 1880 when the first well was completed in the
Naples field in Ontario County. The Naples field produced 32 MMcf during its productive life
and nearly all shale gas discoveries in New York since then have been in the Marcellus Shale. 92
All gas wells completed in New York’s Marcellus Shale as of the publication date of this
document are vertical wells. 93
The Department’s summary production database includes reported natural gas production for the
years 1967 through 1999. Approximately 544 MMcf of gas was produced from wells completed
in the Marcellus Shale during this period. 94 In 2010, the most recent reporting year available, a
total of 34 MMcf of gas was produced from 15 Marcellus Shale wells in Livingston, Steuben,
Schuyler, Chemung, Chautauqua, Wyoming and Allegany Counties.
Volumes of in-place natural gas resources have been estimated for the entire Appalachian Basin.
Charpentier et al. (1982) estimated a total in-place resource of 844.2 Tcf in all Devonian shales
within the basin, including the Marcellus Shale. Approximately 164.1 Tcf, or 19%, of that
estimated total, was attributed to the Devonian shales in New York State. NYSERDA estimates
that approximately 15% of the total Devonian shale gas resource of the Appalachian Basin lies
beneath New York State.
92

Alpha, 2009, p. 129.

93

Alpha, 2009, p. 129.

94

Alpha, 2009, p. 129.

Final SGEIS 2015, Page 4-17

 q

Legend

Depth to the Top of the Marcellus Shale
Marcellus Shale and Hamilton Group Outcrop
Extent of the Marcellus Shale in New York

1,000
2,000

3,000
0
4,00

0

50

5,000

3,000

4,00
0

5,000
6,000

100 Miles

FIGURE 4.8
DEPTH AND EXTENT OF
MARCELLUS SHALE
IN NEW YORK STATE
Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Source:
- New York State Museum - Reservoir Characterization Group (Leone, 2009).

Final SGEIS 2015, Page 4-18

 q

Legend

Thickness Organic-Rich Marcellus Shale (in feet)
Marcellus Shale and Hamilton Group Outcrop
Extent of the Marcellus Shale in New York

100

12
5

25

50

25

75

50

50

5
12

22
5

200
22
5
25
0

0
10

15
0

25

250

25

0

125

275

300

100 Miles

FIGURE 4.9
MARCELLUS SHALE THICKNESS
IN NEW YORK STATE

Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Notes:
- Source: New York State Museum - Reservoir Characterization Group (Leone, 2009)
- Organic-rich Marcellus includes Union Springs and Oatka Creek Members and lateral equivalents.

Final SGEIS 2015, Page 4-19

 q

Legend

Total Organic Carbon (weight percent) in
Organic-Rich Marcellus Shale
Marcellus Shale and Hamilton Group Outcrop
Extent of the Marcellus Shale in New York

3.5

5
4.
1.

2. 5

3.5

5
2.

5.5

3.

2.5

4.5

4.5

1.5

4.5

4.5

5

3.5

2.

5

2.5

5

0

50

100 Miles

FIGURE 4.10
TOTAL ORGANIC CARBON
OF MARCELLUS SHALE
IN NEW YORK STATE
Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Source:
- M odified from New York S tate M useum - Reservoir Characterization
Group (Leone, 2009).

Final SGEIS 2015, Page 4-20

 q

Legend

Extent of the Marcellus Shale in New York
Vitrinite Reflection (%Ro)
Less than 0.6
0.6 to 1.5
1.5 to 3.0
Greater than 3.0

0

50

100 Miles

FIGURE 4.11
MARCELLUS SHALE
THERMAL MATURITY

Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Source:
- Modified from Smith & Leone (2009).

Final SGEIS 2015, Page 4-21

 q

Legend
Marcellus Shale and Hamilton Group Outcrop
Marcellus Shale Fairway

Clinton

Extent of the Marcellus Shale in New York

St. Lawrence

Franklin

Essex

Jefferson

Lewis
Hamilton

Warren

Oswego
Orleans

Niagara

Monroe

Genesee

Chautauqua

Wayne

Ontario

Erie

Wyoming

Cattaraugus

Oneida

Livingston

Cortland

Schuyler
Allegany

Montgomery
Schenectady

Madison
Cayuga

Yates
Tompkins

Otsego
Chenango

Steuben
Chemung

Tioga

Saratoga

Fulton

Onondaga

Seneca

Washington

Herkimer

Broome

Delaware

Rensselaer

Schoharie Albany

Greene

Columbia

Ulster
Dutchess

Sullivan

0

50

100 Miles

Orange

FIGURE 4.12

RocklandWestchester

MARCELLUS SHALE FAIRWAY
IN NEW YORK STATE

Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Putnam

Suffolk
Nassau

Source:
- US Geological Survey, Central Energy Resources Team (2002)
- New York State Museum - Reservoir Characterization Group
- Nyahay et al. (2007)

Map Document: (Z:\projects\2009\09100-09120\09104 - Gas Well Permitting GEIS\Figures\GIS\Marcellus_Fairway.mxd)
8/10/2009 -- 3:10:00 PM

Final SGEIS 2015, Page 4-22

 In 2011, the USGS estimated a mean of 84.2 Tcf of technically recoverable undiscovered
natural gas reserves in the Marcellus Shale in the Appalachian Basin, more than a 40-fold
increase from its 2002 estimate of 1.9 Tcf. Engelder had previously estimated a 50% probability
that 489 Tcf of gas would be produced basin-wide from the Marcellus after a 50-year decline,
and assigned 71.9 Tcf of that total to 17 counties in New York.95 Engelder’s basin-wide
estimate appears to include both proven and undiscovered reserves. While Engelder’s
methodology is based on both geology and published information about initial production rates
and production decline from actual wells in Pennsylvania, the USGS describes its approach as
based on recognized geologic characteristics of the formation. There is insufficient information
available to determine the validity of comparing these projections, but it is common for
projections of these types to vary, as a function of the prevailing technologies and knowledge
base associated with a given resource.
4.5

Seismicity in New York State

4.5.1

Background

The term “earthquake” is used to describe any event that is the result of a sudden release of
energy in the earth's crust that generates seismic waves. Many earthquakes are too minor to be
detected without sensitive equipment. Large earthquakes result in ground shaking and
sometimes displacing the ground surface. Earthquakes are caused mainly by movement along
geological faults, but also may result from volcanic activity and landslides. An earthquake's
point of origin is called its focus or hypocenter. The term epicenter refers to the point at the
ground surface directly above the hypocenter.
Geologic faults are fractures along which rocks on opposing sides have been displaced relative to
each other. The amount of displacement may be small (centimeters) or large (kilometers).
Geologic faults are prevalent and typically are active along tectonic plate boundaries. One of the
most well known plate boundary faults is the San Andreas fault zone in California. Faults also
occur across the rest of the U.S., including mid-continent and non-plate boundary areas, such as
the New Madrid fault zone in the Mississippi Valley, or the Ramapo fault system in southeastern
New York and eastern Pennsylvania.

95

Engelder, 2009.

Final SGEIS 2015, Page 4-23

 Figure 4.13 shows the locations of faults and other structures that may indicate the presence of
buried faults in New York State. 96 There is a high concentration of structures in eastern New
York along the Taconic Mountains and the Champlain Valley that resulted from the intense
thrusting and continental collisions during the Taconic and Allegheny orogenies that occurred
350 to 500 million years ago. 97 There is also a high concentration of faults along the Hudson
River Valley. More recent faults in northern New York were formed as a result of the uplift of
the Adirondack Mountains approximately 5 to 50 million years ago.
4.5.2

Seismic Risk Zones

The USGS Earthquake Hazard Program has produced the National Hazard Maps showing the
distribution of earthquake shaking levels that have a certain probability of occurring in the
United States. The maps were created by incorporating geologic, geodetic and historic seismic
data, and information on earthquake rates and associated ground shaking. These maps are used
by others to develop and update building codes and to establish construction requirements for
public safety.
New York State is not associated with a major fault along a tectonic boundary like the San
Andreas, but seismic events are common in New York. Figure 4.14 shows the seismic hazard
map for New York State. 98 The map shows levels of horizontal shaking, in terms of percent of
the gravitational acceleration constant (%g) that is associated with a 2 in 100 (2%) probability of
occurring during a 50-year period. 99 Much of the Marcellus and Utica Shales underlie portions
of the state with the lowest seismic hazard class rating in New York (2% probability of
exceeding 4 to 8 %g in a 50-year period). The areas around New York City, Buffalo, and
northern-most New York have a moderate to high seismic hazard class ratings (2% probability of
exceeding 12 to 40 %g in a 50-year period).

96

Alpha, 2009, p. 138.

97

Alpha, 2009, p. 138.

98

Alpha, 2009, p. 139.

99

Alpha, 2009, p. 139.

Final SGEIS 2015, Page 4-24

 q

Legend

Geologic Fault

Combined Utica and Marcellus Shales

in New York State

Clinton
St. Lawrence
Franklin
Essex
Jefferson

Lewis
Hamilton
Warren

Oswego

Niagara

Erie


Monroe

Cattaraugus

Wayne

Genesee

Onondaga

Ontario

Wyoming

Chautauqua

Extent of
Utica shale

Orleans

Livingston

Seneca Cayuga

Yates

Allegany

Tompkins

Madison

Chemung

Saratoga

Montgomery
Schenectady

Broome

Rensselaer

Otsego

Chenango

Steuben
Tioga

Washington

Herkimer
Fulton

Extent of
Marcellus shale
Cortland

Schuyler

Oneida

Albany

Schoharie

Delaware

Greene

Columbia

Ulster

0

50

100 Miles

DRAFT

Orange

FIGURE 4.13

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Putnam

RocklandWestchester

MAPPED GEOLOGIC FAULTS
IN NEW YORK STATE

Alpha Project No. 09104

Dutchess

Sullivan

Suffolk

Bronx

Note:
- Geologic fault features shown were complied by Isachsen
and McKendree (1977) and exclude brittle structures identified
as drillholes, topographic, and tonal linear features.

Map Document: (Z:\projects\2009\09100-09120\09104 - Gas Well Permitting GEIS\Figures\GIS\Brittle_Structure.mxd)
8/21/2009 -- 9:08:57 AM

Final SGEIS 2015, Page 4-25

Queens

Kings
Richmond

Nassau

 q
Extent of
Utica shale

Extent of
Marcellus shale

Bronx
New York

DRAFT

FIGURE 4.14
NEW YORK STATE
SEISMIC HAZARD MAP

Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Approximate Scale
0

Notes:
- Map shows peak acceleration (%g) with 2% probability
of exceedence in 50 years.
- Source - USGS National Seismic Hazard Maps (2008).

Map Document: (Z:\projects\2009\09100-09120\09104 - Gas Well Permitting GEIS\Figures\GIS\Seismic_Hazard.mxd)
8/21/2009 -- 9:11:20 AM

Final SGEIS 2015, Page 4-26

50

100 Miles

 4.5.3

Seismic Damage – Modified Mercalli Intensity Scale

There are several scales by which the magnitude and the intensity of a seismic event are
reported. The Richter magnitude scale was developed in 1935 to measure of the amount of
energy released during an earthquake. The moment magnitude scale (MMS) was developed in
the 1970s to address shortcomings of the Richter scale, which does not accurately calculate the
magnitude of earthquakes that are large (greater than 7) or distant (measured at a distance greater
than 250 miles away). Both scales report approximately the same magnitude for earthquakes
with a magnitude less than 7 and both scales are logarithmic; an increase of two units of
magnitude on the Richter scale corresponds to a 1,000-fold increase in the amount of energy
released.
The MMS measures the size of a seismic event based on the amount of energy released.
Moment is a representative measure of seismic strength for all sizes of events and is independent
of recording instrumentation or location. Unlike the Richter scale, the MMS has no limits to the
possible measurable magnitudes, and the MMS relates the moments to the Richter scale for
continuity. The MMS also can represent microseisms (very small seismicity) with negative
numbers.
The Modified Mercalli (MM) Intensity Scale was developed in 1931 to report the intensity of an
earthquake. The Mercalli scale is an arbitrary ranking based on observed effects and not on a
mathematical formula. This scale uses a series of 12 increasing levels of intensity that range
from imperceptible shaking to catastrophic destruction, as summarized in Table 4.1. Table 4.1
compares the MM intensity scale to magnitudes of the MMS, based on typical events as
measured near the epicenter of a seismic event. There is no direct conversion between the
intensity and magnitude scales because earthquakes of similar magnitudes can cause varying
levels of observed intensities depending on factors such location, rock type, and depth.
4.5.4

Seismic Events

Table 4.2 summarizes the recorded seismic events in New York State by county between
December 1970 and July 2009. 100 There were a total of 813 seismic events recorded in New
York State during that period. The magnitudes of 24 of the 813 events were equal to or greater
100

Alpha, 2009, p. 140.

Final SGEIS 2015, Page 4-27

 than 3.0. Magnitude 3 or lower earthquakes are mostly imperceptible and are usually detectable
only with sensitive equipment. The largest seismic event during the period 1970 through 2009 is
a 5.3 magnitude earthquake that occurred on April 20, 2002, near Plattsburgh, Clinton County. 101
Damaging earthquakes have been recorded since Europeans settled New York in the 1600s. The
largest earthquake ever measured and recorded in New York State was a magnitude 5.8 event
that occurred on September 5, 1944, near Massena, New York. 102
Figure 4.15 shows the distribution of recorded seismic events in New York State. The majority
of the events occur in the Adirondack Mountains and along the New York-Quebec border. A
total of 180 of the 813 seismic events shown on Table 4.2 and Figure 4.15 during a period of 39
years (1970–2009) occurred in the area of New York that is underlain by the Marcellus and/or
the Utica Shales. The magnitude of 171 of the 180 events was less than 3.0. The distribution of
seismic events on Figure 4.15 is consistent with the distribution of fault structures (Figure 4.13)
and the seismic hazard risk map (Figure 4.14).
Induced seismicity refers to seismic events triggered by human activity such as mine blasts,
nuclear experiments, and fluid injection, including hydraulic fracturing. 103 Induced seismic
waves (seismic refraction and seismic reflection) also are a common tool used in geophysical
surveys for geologic exploration. The surveys are used to investigate the subsurface for a wide
range of purposes including landfill siting; foundations for roads, bridges, dams and buildings;
oil and gas exploration; mineral prospecting; and building foundations. Methods of inducing
seismic waves range from manually striking the ground with weight to setting off controlled
blasts.

101

Alpha, 2009, p. 140.

102

Alpha, 2009, p. 140.

103

Alpha, 2009, p. 138.

Final SGEIS 2015, Page 4-28

 Table 4.1

Modified Mercalli Intensity Scale


Modified
Mercalli
Intensity

Description

I

Instrumental

II

Feeble

Felt only by a few persons at rest, especially on upper floors of
buildings.

Slight

Felt quite noticeably by persons indoors, especially on upper floors of
buildings. Many people do not recognize it as an earthquake.
Standing motor cars may rock slightly. Vibrations similar to the
passing of a truck. Duration estimated.

Moderate

Felt indoors by many, outdoors by few during the day. At night, some
awakened. Dishes, windows, doors disturbed; walls make cracking
sound. Sensation like heavy truck striking building. Standing motor
cars rocked noticeably.

III

IV

V

Rather Strong

VI

Strong

VII

VIII

Effects

Not felt except by a very few under especially favorable conditions.

Destructive

Damage slight in specially designed structures; considerable damage
in ordinary substantial buildings with partial collapse. Damage great in
poorly built structures. Fall of chimneys, factory stacks, columns,
monuments, walls. Heavy furniture overturned.

X

Disastrous

XI

Very Disastrous

XII

Catastrophic

3.0 to 3.9

4.0 to 4.9

Felt by all, many frightened. Some heavy furniture moved; a few
instances of fallen plaster. Damage slight.

Very Strong

Ruinous

1.0 to 3.0

Felt by nearly everyone; many awakened. Some dishes, windows
broken. Unstable objects overturned. Pendulum clocks may stop.

Damage negligible in buildings of good design and construction;
slight to moderate in well-built ordinary structures; considerable
damage in poorly built or badly designed structures; some chimneys
broken.

IX

Typical
Maximum
Moment
Magnitude

5.0 to 5.9

6.0 to 6.9

Damage considerable in specially designed structures; well-designed
frame structures thrown out of plumb. Damage great in substantial
buildings, with partial collapse. Buildings shifted off foundations.
Some well-built wooden structures destroyed; most masonry and
frame structures destroyed with foundations. Rails bent.
Few, if any (masonry) structures remain standing. Bridges destroyed.
Rails bent greatly.

7.0 and higher

Damage total. Lines of sight and level are distorted. Objects thrown
into the air.

The above table compares the Modified Mercalli intensity scale and moment magnitude scales that typically observed near the epicenter of a
seismic event.
Source: USGS Earthquake Hazard Program (http://earthquake.usgs.gov/learning/topics/mag_vs_int.php)

Z:\projects\2009\09100-09120\09104 - Gas Well Permitting GEIS\Earthquakes\Mercalli.xls

Final SGEIS 2015, Page 4-29

 Table 4.2

Summary of Seismic Events in New York State

December 1970 through July 2009

County

Albany
Allegany
Broome
Cattaraugus
Cayuga
Chautauqua
Chemung
Chenango
Cortland
Delaware
Erie
Genesee
Greene
Livingston
Madison
Montgomery
Niagara
Onondaga
Ontario
Otsego
Schoharie
Schuyler
Seneca
Steuben
Sullivan
Tioga
Tompkins
Wyoming
Yates

Magnitude
< 2.0

2.0 to 2.9 3.0 to 3.9 4.0 to 4.9 5.0 to 5.3

Counties Overlying Utica and Marcellus Shales
27
20
3
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
2
0
0
7
5
0
0
3
5
0
0
2
1
0
0
1
5
1
0
0
0
0
0
1
2
0
0
7
3
0
0
0
0
0
0
1
1
0
0
0
0
0
0
2
4
0
1
0
0
0
0
0
0
0
0
2
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
8
5
0
0
1
0
0
0
53

5

Total

0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0

50
0
0
0
0
0
0
0
0
3
12
8
3
7
0
3
10
0
2
0
7
0
0
3
0
0
0
13
1

Subtotal

63

1

0

122

Fulton
Herkimer
Jefferson
Lewis
Monroe
Oneida
Orange
Orleans
Oswego
Saratoga
Schenectady
Wayne
Subtotal

Counties Overlying Utica Shale
1
2
1
0
4
3
0
0
5
3
0
0
3
0
2
0
1
0
0
0
3
4
0
0
14
5
0
0
0
0
0
0
2
0
0
0
1
2
0
0
1
1
0
0
0
0
0
0
35
20
3
0

0
0
0
0
0
0
0
0
0
0
0
0
0

4
7
8
5
1
7
19
0
2
3
2
0
58

Z:\projects\2009\09100-09120\09104 - Gas Well Permitting GEIS\Earthquakes\Summary of NY Events.xls

Final SGEIS 2015, Page 4-30

Page 1 of 2

 Table 4.2

Summary of Seismic Events in New York State

December 1970 through July 2009

Magnitude

County

Bronx
Clinton
Columbia
Dutchess
Essex
Franklin
Hamilton
Kings
Nassau
New York
Putnam
Queens
Rensselaer
Richmond
Rockland
St. Lawrence
Suffolk
Ulster
Warren
Washington
Westchester
Subtotal

< 2.0

2.0 to 2.9 3.0 to 3.9 4.0 to 4.9 5.0 to 5.3

Counties Not Overlying Utica or Marcellus Shales
0
0
0
0
60
30
5
0
0
0
0
0
6
4
2
0
88
64
4
1
40
19
3
0
53
10
0
0
0
0
0
0
1
0
0
0
3
2
0
0
4
2
0
0
0
0
0
0
1
0
0
0
0
0
0
0
15
3
0
0
84
29
0
0
0
0
0
0
3
0
0
0
11
5
1
0
1
3
0
0
61
11
1
1
431
182
16
2

New York State Total

529

255

24

3

Total

0
1
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
2

0
96
0
12
158
62
63
0
1
5
6
0
1
0
18
113
0
3
17
4
74
633

2

813

Notes:
- Seismic events recorded December 13, 1970 through July 28, 2009.
- Lamont-Doherty Cooperative Seismographic Network, 2009

Z:\projects\2009\09100-09120\09104 - Gas Well Permitting GEIS\Earthquakes\Summary of NY Events.xls

Final SGEIS 2015, Page 4-31

Page 2 of 2

 Hydraulic fracturing releases energy during the fracturing process at a level substantially below
that of small, naturally occurring, earthquakes. However, some of the seismic events shown on
Figure 4.15 are known or suspected to be triggered by other types of human activity. The 3.5
magnitude event recorded on March 12, 1994, in Livingston County is suspected to be the result
of the collapse associated with the Retsof salt mine failure in Cuylerville, New York. 104 The 3.2
magnitude event recorded on February 3, 2001, was coincident with, and is suspected to have
been triggered by, test injections for brine disposal at the New Avoca Natural Gas Storage
(NANGS) facility in Steuben County. The cause of the event likely was the result of an
extended period of fluid injection near an existing fault 105 for the purposes of siting a deep
injection well. The injection for the NANGS project occurred numerous times with injection
periods lasting 6 to 28 days and is substantially different than the short-duration, controlled
injection used for hydraulic fracturing.
One additional incident suspected to be related to human activity occurred in late 1971 at Texas
Brine Corporation’s system of wells used for solution mining of brine near Dale, Wyoming
County, New York (i.e., the Dale Brine Field). The well system consisted of a central, high
pressure injection well (No. 11) and four peripheral brine recovery wells. The central injection
well was hydraulically fractured in July 1971 without incident.
The well system was located in the immediate vicinity of the known, mapped, Clarendon-Linden
fault zone which is oriented north-south, and extends south of Lake Ontario in Orleans, Genesee,
Wyoming, and the northern end of Allegany Counties, New York. The Clarendon-Linden fault
zone is not of the same magnitude, scale, or character as the plate boundary fault systems, but
nonetheless has been the source of relatively small to moderate quakes in western New York
(MCEER, 2009; and Fletcher and Sykes, 1977).
Fluids were injected at well No. 11 from August 3 through October 8, and from October 16
through November 9, 1971. Injections were ceased on November 9, 1971 due to an increase in
seismic activity in the area of the injection wells. A decrease in seismic activity occurred when

104

Alpha, 2009, p. 141.

105

Alpha, 2009, p. 141.

Final SGEIS 2015, Page 4-32

 the injections ceased. The tremors attributed to the injections reportedly were felt by residents in
the immediate area.
Evaluation of the seismic activity associated with the Dale Brine Field was performed and
published by researchers from the Lamont-Doherty Geological Observatory (Fletcher and Sykes,
1977). The evaluation concluded that fluids injected during solution mining activity were able to
reach the Clarendon-Linden fault and that the increase of pore fluid pressure along the fault
caused an increase in seismic activity. The research states that “the largest earthquake … that
appears to be associated with the brine field…” was 1.4 in magnitude. In comparison, the
magnitude of the largest natural quake along the Clarendon-Linden fault system through 1977
was magnitude 2.7, measured in 1973. Similar solution mining well operations in later years
located further from the fault system than the Dale Brine Field wells did not create an increase in
seismic activity.
4.5.5

Monitoring Systems in New York

Seismicity in New York is monitored by both the US Geological Survey (USGS) and the
Lamont-Doherty Cooperative Seismographic Network (LCSN). The LCSN is part of the
USGS’s Advanced National Seismic System (ANSS) which provides current information on
seismic events across the country. Other ANSS stations are located in Binghamton and Lake
Ozonia, New York. The New York State Museum also operates a seismic monitoring station in
the Cultural Education Center in Albany, New York.
As part of the ANSS, the LCSN monitors earthquakes that occur primarily in the northeastern
United States and coordinates and manages data from 40 seismographic stations in seven states,
including Connecticut, Delaware, Maryland, New Jersey, New York, Pennsylvania, and
Vermont. 106 Member organizations that operate LCSN stations include two secondary schools,
two environmental research and education centers, three state geological surveys, a museum
dedicated to Earth system history, two public places (Central Park, NYC, and Howe Caverns,
Cobleskill), three two-year colleges, and 15 four-year universities. 107

106

Alpha, 2009, p. 142.

107

Alpha, 2009, p. 143.

Final SGEIS 2015, Page 4-33

 q

Legend

Recorded Seismic Events

Magnitude (Richter Scale)

Less than 3.0
Minor - not felt
3.0 to 3.9
Minor - often felt, no damage
4.0 to 4.9
Minor - shaking observed

Clinton

St. Lawrence

5.0 to 5.3
Moderate - Some damage

Franklin

Jefferson

Essex

Combined Utica and Marcellus Shales
in New York State

Lewis
Hamilton
Warren

Oswego

Niagara

Erie

Monroe

Cattaraugus

Wayne

Genesee
Cayuga

Ontario
Wyoming

Chautauqua

Extent of
Utica shale

Orleans

Livingston

Seneca

Yates

Tompkins

Madison

Chemung

Saratoga

Montgomery
Schenectady
Otsego

Chenango

Steuben
Tioga

Washington

Herkimer
Fulton

Extent of
Marcellus shale
Cortland

Schuyler
Allegany

Onondaga

Oneida

Broome

Albany

Schoharie

Delaware

Rensselaer

Greene

Columbia

Ulster

0

50

DRAFT

100 Miles

Orange

FIGURE 4.15
SEISMIC EVENTS IN
NEW YORK STATE
(1970 to 2009)
Alpha Project No. 09104

Technical Support Document to the
Final Supplemental Generic
Environmental Impact Statement

Dutchess

Sullivan

Putnam

RocklandWestchester

Bronx
New York
QueensNassau
Kings

Notes:
- Seismic events recorded December 13, 1970 through July 28, 2009. Richmond
- Lamont-Doherty Cooperative Seismographic Network, 2009
(http://almaty.ldeo.columbia.edu:8080/data.search.html)

Map Document: (Z:\projects\2009\09100-09120\09104 - Gas Well Permitting GEIS\Figures\GIS\Seismic.mxd)
8/21/2009 -- 9:17:24 AM

Final SGEIS 2015, Page 4-34

Suffolk

 4.6

Naturally Occurring Radioactive Materials (NORM) in Marcellus Shale

NORM is present to varying degrees in virtually all environmental media, including rocks and
soils. As mentioned above, black shale typically contains trace levels of uranium and gamma ray
logs indicate that this is true of the Marcellus Shale. The Marcellus is known to contain
concentrations of NORM such as uranium-238 and radium-226 at higher levels than surrounding
rock formations. Normal disturbance of NORM-bearing rock formations by activities such as
mining or drilling do not generally pose a threat to workers, the general public or the
environment. However, activities having the potential to concentrate NORM need to come
under regulatory oversight to ensure adequate protection of workers, the general public and the
environment.
Chapter 5 includes radiological information (sampling results) from environmental media at
various locations in the Appalachian Basin. Radiological data for the Marcellus in New York
were derived from: a) drill cuttings and core samples from wells drilled through or completed in
the Marcellus; and b) production brine from vertical wells completed in the Marcellus.
Radiological data for the Marcellus in Pennsylvania and West Virginia were derived from: a)
drill cuttings from wells completed in the Marcellus in Pennsylvania; and b) flowback water
analyses provided by operators of wells in Pennsylvania and West Virginia. Chapter 6 includes a
discussion of potential impacts associated with radioactivity in the Marcellus Shale. Chapter 7
details mitigation measures, including existing regulatory programs, proposed well permit
conditions, and proposed future data collection and analysis.
4.7

Naturally Occurring Methane in New York State

The presence of naturally occurring methane in ground seeps and water wells is well documented
throughout New York State. Naturally-occurring methane can be attributed to swampy areas or
where bedrock and unconsolidated aquifers overlie Devonian-age shales or other gas-bearing
formations. The highly fractured Devonian shale formations found throughout western New
York are particularly well known for shallow methane accumulations. In his 1966 report on the
Jamestown Aquifer, Crain explained that natural gas could occur in any water well in the area
"which ends in bedrock or in unconsolidated deposits overlain by fine-grained confining
material. Depth is not of primary importance because pockets of gas may occur in the bedrock at

Final SGEIS 2015, Page 4-35

 nearly any depth." 108 Upper Devonian gas bearing rocks at or near the surface extend across the
southern tier of New York from Chautauqua and Erie Counties, east to Delaware and Sullivan
counties (Figure 4.3).
As noted below, early explorers and water well drillers in New York reported naturally occurring
methane in regions not then associated with natural gas well drilling activity. “Methane can
occur naturally in water wells and when it does, it presents unique problems for water well
drilling contractors. The major concern relates to flammable and explosive hazards associated
with methane.” 109 Gas that occurs naturally in shallow bedrock and unconsolidated sediments
has been known to seep to the surface and/or contaminate water supplies including water wells.
Often landowners are not aware of the presence of methane in their well. Methane is a colorless,
odorless gas, and is generally considered non-toxic but there could be an explosive hazard if gas
is present in significant volumes and the water well is not properly vented.
The existence of naturally occurring methane seeps in New York has been known since the mid
1600s. In August 1669 Rene Robert Cavelier de la Salle and Rene de Brehant de Galinee, while
on their way to explore the Mississippi Valley, arrived in the Bristol Hills area of Ontario
County, New York. It was here where the explorers observed natural gas flowing from joint
planes in the Penn Yan Shale (Upper Devonian) at the foot of a falls over the Genundewa
Limestone. 110 More recent studies and investigations have provided other evidence of naturally
occurring methane in eastern New York. A private well in Schenectady County was gaged at
158 MMcf/d of natural gas by the Department in 1965. The well provided natural gas for the
owner’s domestic use for 30 years. 111 In 1987 the Times Union reported that contaminants,
including methane, were found in well water in the Orchard Park subdivision near New Scotland,
Albany County. Engineers from the Department reported the methane as “natural occurrences
found in shale bedrock deposits beneath the development.” 112 Ten years later, in 1997, a
Saratoga Lake couple disclosed to a news reporter the presence of methane gas in their water
108

NYSDEC, 1992, GEIS, p. 10-6.

109

Keech, D. et al, 1982, pp. 33-36.

110

Wells, J. 1963.

111

Kucewicz, J. 1997.

112

Thurman, K. 1987.

Final SGEIS 2015, Page 4-36

 well. The concentration of gas in the well water was concentrated enough for the owners to
ignite the gas from the bathtub faucet. 113 According to a September 22, 2010 article in the Daily
Gazette, water wells in the Brown Road subdivision, Saratoga County became contaminated with
methane gas when water wells were “blasted” (fractured) to reach a greater supply of water. 114
Methane contamination of groundwater is often mistakenly attributed to or blamed on natural gas
well drilling and hydraulic fracturing. There are a number of other, more common, reasons that
well water can display sudden changes in quality and quantity. Seasonal variations in recharge,
stress on the aquifer from usage demand, and mechanical failures are some factors that could
lead to degradation of well water.
Recently, as part of two separate complaint investigations in the towns of Elmira and Collins,
New York, the Department documented that methane gas existed in the shallow aquifers at the
two sites long before and prior to the exploration and development for natural gas 115, 116. The
comprehensive investigations included the following:
•

Analysis of drilling and completion records of natural gas wells drilled near the water
wells;

•

Evaluation of well logs to ascertain cement integrity;

•

Collection of gas samples for compositional analysis;

•

Inspections of the water and natural gas wells; and

•

Interviews with landowners and water well drillers.

Both investigations provided clear evidence that methane contamination was present in the area’s
water wells prior to the commencement of natural gas drilling operations.
Drilling and construction activities may have an adverse impact on groundwater resources. The
migration of methane can contaminate well water supplies if well construction practices designed
113

Kruse, M. 1997.

114

Bowen, K. 2010.

115

NYSDEC, 2011.

116

NYSDEC, 2011.

Final SGEIS 2015, Page 4-37

 to prevent gas migration are not adhered to. Chapter 6 discusses these potential impacts with
mitigation measures addressed in Chapter 7.
In April 2011 researchers from Duke University (Duke) released a report on the occurrence of
methane contamination of drinking water associated with Marcellus and Utica Shale gas
development. 117 As part of their study, the authors analyzed groundwater from nine drinking
water wells completed in the Genesee Group in Otsego County, New York for the presence of
methane. Of the nine wells, Duke classified one well as being in an active gas extraction area
(i.e., a gas well within 1 kilometer (km) of the water well), and the remaining eight in a nonactive gas extraction area. The analysis showed minimal amounts of methane in this sample
group, with concentrations significantly below the minimum methane action level (10 mg/L) to
maintain the safety of structures and the public, as recommended by the U.S. Department of the
Interior, Office of Surface Mining. 118 The water well located in the active gas extraction area had
5 to 10 times less methane than the wells located in the inactive areas.
The Department monitors groundwater conditions in New York as part of an ongoing
cooperative project between the USGS and the Department’s Division of Water (DOW). 119 The
objectives of this program are to assess and report on the ambient ground-water quality of
bedrock and glacial-drift aquifers throughout New York State. In 2010 water samples were
collected from 46 drinking water wells in the Delaware, Genesee, and St. Lawrence River
Basins. All samples were analyzed for dissolved methane gas using standard USGS protocols.
The highest methane concentration from all samples analyzed was 22.4 mg/L from a well in
Schoharie County; the average detected value was 0.79 mg/L. 120 These groundwater results
confirm that methane migration to shallow aquifers is a natural phenomenon and can be expected
to occur in active and non-active natural gas drilling areas.

117

Osborne, S. et al, 2011.

118

Eltschlager, K. et al, 2001.

119

http://www.dec.ny.gov/lands/36117.html.

120

NYSDEC, 2011.

Final SGEIS 2015, Page 4-38

 Chapter 5
Natural Gas Development
Activities & High-Volume
Hydraulic Fracturing
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Chapter 5 - Natural Gas Development Activities & High-Volume Hydraulic Fracturing
CHAPTER 5 NATURAL GAS DEVELOPMENT ACTIVITIES & HIGH-VOLUME HYDRAULIC FRACTURING .................. 5-1
5.1 LAND DISTURBANCE ..................................................................................................................................... 5-2
5.1.1 Access Roads.............................................................................................................................................. 5-2
5.1.2 Well Pads ................................................................................................................................................... 5-6
5.1.3 Utility Corridors ....................................................................................................................................... 5-10
5.1.4 Well Pad Density ...................................................................................................................................... 5-11
5.1.4.1 Historic Well Density..................................................................................................................... 5-11
5.1.4.2 Anticipated Well Pad Density ....................................................................................................... 5-12
5.2 HORIZONTAL DRILLING ................................................................................................................................ 5-19
5.2.1 Drilling Rigs .............................................................................................................................................. 5-21
5.2.2 Multi-Well Pad Development .................................................................................................................. 5-23
5.2.3 Drilling Mud ............................................................................................................................................. 5-27
5.2.4 Cuttings .................................................................................................................................................... 5-28
5.2.4.1 Cuttings Volume............................................................................................................................ 5-29
5.2.4.2 NORM in Marcellus Cuttings ......................................................................................................... 5-29
5.2.5 Management of Drilling Fluids and Cuttings ........................................................................................... 5-32
5.2.5.1 Reserve Pits on Multi-Well Pads ................................................................................................... 5-32
5.2.5.2 Closed-Loop Tank Systems............................................................................................................ 5-32
5.3 HYDRAULIC FRACTURING .............................................................................................................................. 5-34
5.4 FRACTURING FLUID ..................................................................................................................................... 5-35
5.4.1 Properties of Fracturing Fluids ................................................................................................................ 5-44
5.4.2 Classes of Additives ................................................................................................................................. 5-44
5.4.3 Composition of Fracturing Fluids ............................................................................................................. 5-46
5.4.3.1 Chemical Categories and Health Information ............................................................................... 5-58
5.5 TRANSPORT OF HYDRAULIC FRACTURING ADDITIVES ........................................................................................... 5-72
5.6 ON-SITE STORAGE AND HANDLING OF HYDRAULIC FRACTURING ADDITIVES .............................................................. 5-73
5.6.1 Summary of Additive Container Types .................................................................................................... 5-74
5.7 SOURCE WATER FOR HIGH-VOLUME HYDRAULIC FRACTURING .............................................................................. 5-76
5.7.1 Delivery of Source Water to the Well Pad ............................................................................................... 5-77
5.7.2 Use of Centralized Impoundments for Fresh Water Storage .................................................................. 5-78
5.8 HYDRAULIC FRACTURING DESIGN ................................................................................................................... 5-81
5.8.1 Fracture Development ............................................................................................................................. 5-82
5.8.2 Methods for Limiting Fracture Growth.................................................................................................... 5-83
5.8.3 Hydraulic Fracturing Design – Summary.................................................................................................. 5-84
5.9 HYDRAULIC FRACTURING PROCEDURE ............................................................................................................. 5-85
5.10 RE-FRACTURING ......................................................................................................................................... 5-89
5.11 FLUID RETURN ........................................................................................................................................... 5-92
5.11.1 Flowback Water Recovery ....................................................................................................................... 5-93
5.11.2 Flowback Water Handling at the Wellsite ............................................................................................... 5-93
5.11.3 Flowback Water Characteristics .............................................................................................................. 5-93
5.11.3.1 Temporal Trends in Flowback Water Composition..................................................................... 5-111
5.11.3.2 NORM in Flowback Water .......................................................................................................... 5-112

Final SGEIS 2015, Page 5-i

 5.12 FLOWBACK WATER TREATMENT, RECYCLING AND REUSE.................................................................................... 5-112
5.12.1 Physical and Chemical Separation ......................................................................................................... 5-114
5.12.2 Dilution .................................................................................................................................................. 5-116
5.12.2.1 Reuse .......................................................................................................................................... 5-116
5.12.3 Other On-Site Treatment Technologies................................................................................................. 5-118
5.12.3.1 Membranes / Reverse Osmosis .................................................................................................. 5-118
5.12.3.2 Thermal Distillation..................................................................................................................... 5-119
5.12.3.3 Ion Exchange ............................................................................................................................... 5-120
5.12.3.4 Electrodialysis/Electrodialysis Reversal ...................................................................................... 5-120
5.12.3.5 Ozone/Ultrasonic/Ultraviolet ..................................................................................................... 5-121
5.12.3.6 Crystallization/Zero Liquid Discharge ......................................................................................... 5-122
5.12.4 Comparison of Potential On-Site Treatment Technologies ................................................................... 5-122
5.13 WASTE DISPOSAL ..................................................................................................................................... 5-123
5.13.1 Cuttings from Mud Drilling .................................................................................................................... 5-123
5.13.2 Reserve Pit Liner from Mud Drilling....................................................................................................... 5-124
5.13.3 Flowback Water ..................................................................................................................................... 5-124
5.13.3.1 Injection Wells ............................................................................................................................ 5-125
5.13.3.2 Municipal Sewage Treatment Facilities ...................................................................................... 5-126
5.13.3.3 Out-of-State Treatment Plants ................................................................................................... 5-126
5.13.3.4 Road Spreading ........................................................................................................................... 5-127
5.13.3.5 Private In-State Industrial Treatment Plants .............................................................................. 5-127
5.13.3.6 Enhanced Oil Recovery ............................................................................................................... 5-128
5.13.4 Solid Residuals from Flowback Water Treatment ................................................................................. 5-128
5.14 WELL CLEANUP AND TESTING ...................................................................................................................... 5-128
5.15 SUMMARY OF OPERATIONS PRIOR TO PRODUCTION.......................................................................................... 5-129
5.16 NATURAL GAS PRODUCTION ....................................................................................................................... 5-131
5.16.1 Partial Site Reclamation ......................................................................................................................... 5-131
5.16.2 Gas Composition .................................................................................................................................... 5-131
5.16.2.1 Hydrocarbons.............................................................................................................................. 5-131
5.16.2.2 Hydrogen Sulfide......................................................................................................................... 5-132
5.16.3 Production Rate ..................................................................................................................................... 5-132
5.16.4 Well Pad Production Equipment ........................................................................................................... 5-133
5.16.5 Brine Storage ......................................................................................................................................... 5-135
5.16.6 Brine Disposal ........................................................................................................................................ 5-135
5.16.7 NORM in Marcellus Production Brine.................................................................................................... 5-135
5.16.8 Gas Gathering and Compression ........................................................................................................... 5-136
5.17 WELL PLUGGING ...................................................................................................................................... 5-137

Final SGEIS 2015, Page 5-ii

 FIGURES
Figure 5.1 - Well Pad Schematic .............................................................................................................................. 5-10
Figure 5.2 - Possible well spacing unit configurations and wellbore paths ............................................................. 5-26
Figure 5.3 - Sample Fracturing Fluid Composition (12 Additives), by Weight, from Fayetteville Shale .................. 5-47
Figure 5.4 - Sample Fracturing Fluid Composition (9 Additives), by Weight, from Marcellus Shale (New July
2011) .................................................................................................................................................. 5-48
Figure 5.5 - Sample Fracturing Fluid Composition (6 Additives), by Weight, from Marcellus Shale (New July
2011) .................................................................................................................................................. 5-48
Figure 5.6 - Example Fracturing Fluid Composition Including Recycled Flowback Water (New July 2011).......... 5-117
Figure 5.7 - One configuration of potential on-site treatment technologies. ....................................................... 5-118
Figure 5.8 – Simplified Illustration of Gas Production Process .............................................................................. 5-134
TABLES
Table 5.1 - Ten square mile area (i.e., 6,400 acres), completely drilled with horizontal wells in multi-well
units or vertical wells in single-well units (Updated July 2011) ......................................................... 5-19
Table 5.2 - 2009 Marcellus Radiological Data .......................................................................................................... 5-30
Table 5.3 - Gamma Ray Spectroscopy ..................................................................................................................... 5-31
Table 5.4 - Fracturing Additive Products – Complete Composition Disclosure Made to the Department
(Updated July 2011) ........................................................................................................................... 5-37
Table 5.5 - Fracturing Additive Products – Partial Composition Disclosure to the Department (Updated July
2011) .................................................................................................................................................. 5-42
Table 5.6 - Types and Purposes of Additives Proposed for Use in New York State (Updated July 2011) ................ 5-45
Table 5.7 - Chemical Constituents in Additives (Updated July 2011) ...................................................................... 5-49
Table 5.8 - Categories based on chemical structure of potential fracturing fluid constituents. (Updated July
2011) .................................................................................................................................................. 5-58
Table 5.9 - Parameters present in a limited set of flowback analytical results (Updated July 2011) ...................... 5-95
Table 5.10 - Typical concentrations of flowback constituents based on limited samples from PA and WV,
and regulated in NY (Revised July 2011) ............................................................................................ 5-99
Table 5.11 - Typical concentrations of flowback constituents based on limited samples from PA and WV,
not regulated in NY(Revised July 2011)............................................................................................ 5-102
Table 5.12 - Conventional Analytes In MSC Study (New July 2011) ...................................................................... 5-103
Table 5.13 - Total and Dissolved Metals Analyzed In MSC Study (New July 2011)................................................ 5-104
Table 5.14 - Volatile Organic Compounds Analyzed in MSC Study (New July 2011) ............................................. 5-105
Table 5.15 - Semi-Volatile Organics Analyzed in MSC Study (New July 2011) ....................................................... 5-106
Table 5.16 - Organochlorine Pesticides Analyzed in MSC Study (New July 2011) ................................................. 5-107
Table 5.17 - PCBs Analyzed in MSC Study (New July 2011) ................................................................................... 5-107
Table 5.18 - Organophosphorus Pesticides Analyzed in MSC Study (New July 2011) ........................................... 5-107
Table 5.19 - Alcohols Analyzed in MSC Study (New July 2011) ............................................................................. 5-107
Table 5.20 - Glycols Analyzed in MSC Study (New July 2011)................................................................................ 5-107
Table 5.21 - Acids Analyzed in MSC Study (New July 2011) .................................................................................. 5-107
Table 5.22 - Parameter Classes Analyzed for in the MSC Study (New July 2011).................................................. 5-108
Table 5.23 - Parameter Classes Detected in Flowback Analyticals in MSC Study (New July 2011) ....................... 5-109
Table 5.24 - Concentrations of NORM constituents based on limited samples from PA and WV (Revised
July 2011) ......................................................................................................................................... 5-112
Table 5.25 - Maximum allowable water quality requirements for fracturing fluids, based on input from one
expert panel on Barnett Shale (Revised July 2011) .......................................................................... 5-113
Table 5.26 - Treatment capabilities of EDR and RO Systems ................................................................................. 5-121
Table 5.27 - Summary of Characteristics of On-Site Flowback Water Treatment Technologies (Updated July
2011) ................................................................................................................................................ 5-123
Table 5.28 - Out-of-state treatment plants proposed for disposition of NY flowback water................................ 5-127
Table 5.29 - Primary Pre-Production Well Pad Operations (Revised July 2011) .................................................... 5-129
Table 5.30 - Marcellus Gas Composition from Bradford County, PA ..................................................................... 5-131

Final SGEIS 2015, Page 5-iii

 PHOTOS
Photo 5.1 - Access Road and Erosion/Sedimentation Controls, Salo 1, Barton, Tioga County NY ............................ 5-4
Photo 5.2 - Access Road, Nornew Smyrna Hillbillies 2H, Smyrna, Madison County NY ............................................ 5-4
Photo 5.3 - In-Service Access Road to Horizontal Marcellus well in Bradford County PA ......................................... 5-5
Photo 5.4 - Access Road and Sedimentation Controls, Moss 1, Corning, Steuben County NY .................................. 5-5
Photo 5.5 - Chesapeake Energy Marcellus Well Drilling, Bradford County, PA ......................................................... 5-8
Photo 5.6 - Hydraulic fracturing operation, Horizontal Marcellus Well, Upshur County, WV .................................. 5-8
Photo 5.7 - Hydraulic Fracturing Operation, Horizontal Marcellus Well, Bradford County, PA ................................ 5-9
Photo 5.8 - Locations of Over 44,000 Natural Gas Wells Targeting the Medina Formation, Chautauqua
County NY........................................................................................................................................... 5-13
Photo 5.9 - Locations of 48 Natural Gas Wells Targeting the Medina Formation, Chautauqua County NY ............ 5-14
Photo 5.10 - Locations of 28 Wells in the Town of Poland, Chautauqua County NY............................................... 5-15
Photo 5.11 - Locations of 77 Wells in the Town of Sheridan, Chautauqua County NY............................................ 5-16
Photo 5.12 - Double Drilling Rig, Union Drilling Rig 54, Olsen 1B, Town of Fenton, Broome County NY ................ 5-24
Photo 5.13 - Double Drilling Rig, Union Drilling Rig 48, Salo 1, Town of Barton, Tioga County NY ......................... 5-24
Photo 5.14 - Triple Drilling Rig, Precision Drilling Rig 26, Ruger 1, Horseheads, Chemung County NY ................... 5-25
Photo 5.15 - Top Drive Single Drilling Rig, Barber and DeLine Rig, Sheckells 1, Town of Cherry Valley,
Otsego County NY .............................................................................................................................. 5-25
Photo 5.16 - Drilling rig mud system (blue tanks) ................................................................................................... 5-28
Photo 5.17 - Sand used as proppant in hydraulic fracturing operation in Bradford County, PA ............................. 5-47
Photo 5.18 - Transport trucks with totes ................................................................................................................. 5-75
Photo 5.19 - Fortuna SRBC-Approved Chemung River Water Withdrawal Facility, Towanda PA ........................... 5-79
Photo 5.20 - Fresh Water Supply Pond.................................................................................................................... 5-79
Photo 5.21 - Water Pipeline from Fortuna Centralized Freshwater Impoundments, Troy PA ................................ 5-79
Photo 5.22 - Construction of Freshwater Impoundment, Upshur County WV........................................................ 5-80
Photo 5.23 - Personnel monitoring a hydraulic fracturing procedure. Source: Fortuna Energy. ............................ 5-84
Photo 5.24 - Three Fortuna Energy wells being prepared for hydraulic fracturing, with 10,000 psi well head
and goat head attached to lines. Troy PA. Source: New York State Department of
Environmental Conservation 2009 ..................................................................................................... 5-86
Photo 5.25 - Hydraulic Fracturing Operation Equipment at a Fortuna Energy Multi-Well Site, Troy PA ................ 5-90
Photo 5.26 - Fortuna Energy Multi-Well Site in Troy PA After Removal of Most Hydraulic Fracturing
Equipment .......................................................................................................................................... 5-91
Photo 5.27 - Wellhead and Fracturing Equipment .................................................................................................. 5-91
Photo 5.28 - Pipeline Compressor in New York. Source: Fortuna Energy ............................................................. 5-137

Final SGEIS 2015, Page 5-iv

 Chapter 5 NATURAL GAS DEVELOPMENT ACTIVITIES & HIGH-VOLUME
HYDRAULIC FRACTURING
As noted in the 1992 GEIS, New York has a long history of natural gas production. The first gas
well was drilled in 1821 in Fredonia, and the 40 Bcf of gas produced in 1938 remained the
production peak until 2004 when 46.90 Bcf were produced. Annual production exceeded 50 Bcf
from 2005 through 2008, dropping to 44.86 Bcf in 2009 and 35.67 Bcf in 2010. Chapters 9 and
10 of the 1992 GEIS comprehensively discuss well drilling, completion and production
operations, including potential environmental impacts and mitigation measures. The history of
hydrocarbon development in New York through 1988 is also covered in the 1992 GEIS.
New York counties with actively producing gas wells reported in 2010 were: Allegany,
Cattaraugus, Cayuga, Chautauqua, Chemung, Chenango, Erie, Genesee, Livingston, Madison,
Niagara, Ontario, Oswego, Schuyler, Seneca, Steuben, Tioga, Wayne, Wyoming and Yates.
Hydraulic fracturing is a well stimulation technique which consists of pumping a fluid and a
proppant such as sand down the wellbore under high pressure to create fractures in the
hydrocarbon-bearing rock. No blast or explosion is created by the hydraulic fracturing process.
The proppant holds the fractures open, allowing hydrocarbons to flow into the wellbore after
injected fluids are recovered. Hydraulic fracturing technology was first developed in the late 1940s
and, accordingly, it was addressed in the 1992 GEIS. It is estimated that as many as 90% of wells
drilled in New York are hydraulically fractured. ICF International provides the following
history: 121

Early 1900s
1983
1980-1990s
1991
1991
1996
1996
1998
2002
2003
2005
2007

Hydraulic Fracturing Technological Milestones 122
Natural gas extracted from shale wells. Vertical wells fractured with foam.
First gas well drilled in Barnett Shale in Texas
Cross-linked gel fracturing fluids developed and used in vertical wells
First horizontal well drilled in Barnett Shale
Orientation of induced fractures identified
Slickwater fracturing fluids introduced
Microseismic post-fracturing mapping developed
Slickwater refracturing of originally gel-fractured wells
Multi-stage slickwater fracturing of horizontal wells
First hydraulic fracturing of Marcellus Shale 123
Increased emphasis on improving the recovery factor
Use of multi-well pads and cluster drilling

121

ICF Task 1, 2009, p. 3.

122

Matthews, 2008, as cited by ICF Task 1, 2009, p. 3.

123

Harper, 2008, as cited by ICF Task 1, 2009, p. 3.

Final SGEIS 2015, Page 5-1

 5.1

Land Disturbance

Land disturbance directly associated with high-volume hydraulic fracturing will consist primarily
of constructed gravel access roads, well pads and utility corridors. According to the most recent
industry estimates, the average total disturbance associated with a multi-well pad, including
incremental portions of access roads and utility corridors, during the drilling and fracturing stage
is estimated at 7.4 acres and the average total disturbance associated with a well pad for a single
vertical well during the drilling and fracturing stage is estimated at 4.8 acres. As a result of
required partial reclamation, this would generally be reduced to averages of about 5.5 acres and
4.5 acres, respectively, during the production phase. These estimates include access roads to the
well pads and incremental portions of utility corridors including gathering lines and compressor
facilities, and the access roads associated with compressor facilities. These associated roads and
facilities are projected to account for, on average, about 3.95 acres of the land area associated
with each pad for the life of the wells. During the long-term production phase, a multi-well pad
itself would occupy about 1.5 acres, while a well pad for a single vertical well would occupy
about 0.5 acre. 124,125
5.1.1

Access Roads

The first step in developing a natural gas well site is to construct the access road and well pad.
For environmental review and permitting purposes, the acreage and disturbance associated with
the access road is considered part of the project as described by Topical Response #4 in the 1992
GEIS. However, instead of one well per access road as was typically the case when the GEIS
was prepared, most shale gas development will consist of several wells on a multi-well pad
serviced by a single access road. Therefore, in areas developed by horizontal drilling using
multi-well pads, fewer access roads as a function of the number of wells will be needed.
Industry estimates that 90% of the wells used to develop the Marcellus Shale will be horizontal
wells located on multi-well pads. 126
Access road construction involves clearing the route and preparing the surface for movement of
heavy equipment, or reconstruction or improvement of existing roads if present on the property
124

ALL Consulting, 2010, pp. 14 – 15.

125

Cornue, 2011.

126

ALL Consulting, 2010, pp. 7 – 15.

Final SGEIS 2015, Page 5-2

 being developed. Ground surface preparation for new roads typically involves staking, grading,
stripping and stockpiling of topsoil reserves, then placing a layer of crushed stone, gravel, or
cobbles over geotextile fabric. Sedimentation and erosion control features are also constructed
as needed along the access roads and culverts may be placed across ditches at the entrance from
the main highway or in low spots along the road.
The size of the access road is dictated by the size of equipment to be transported to the well site,
distance of the well pad from an existing road and the route dictated by property access rights
and environmental concerns. The route selected may not be the shortest distance to the nearest
main road. Routes for access roads may be selected to make use of existing roads on a property
and to avoid disturbing environmentally sensitive areas such as protected streams, wetlands, or
steep slopes. Property access rights and agreements and traffic restrictions on local roads may
also limit the location of access routes.
Access road widths would generally range from 20 to 40 feet during the drilling and fracturing
phase and from 10 to 20 feet during the production phase. During the construction and drilling
phase, additional access road width is necessary to accommodate stockpiled topsoil and
excavated material along the roadway and to construct sedimentation and erosion control
features such as berms, ditches, sediment traps or sumps, or silt fencing along the length of the
access road.
Each 150 feet of a 30-foot wide access road adds about one-tenth of an acre to the total surface
acreage disturbance attributed to the well site. Industry estimates an average access road size of
0.27 acre, 127 which would imply an average length of about 400 feet for a 30-foot wide road.
Permit applications for horizontal Marcellus wells received by the Department prior to
publication of the 2009 draft SGEIS indicated road lengths ranging from 130 feet to
approximately 3,000 feet.
Photo 5.1, Photo 5.2, Photo 5.3, and Photo 5.4 depict typical wellsite access roads.

127

Cornue, 2011.

Final SGEIS 2015, Page 5-3

 Photo 5.1 Access road and erosion/sedimentation controls, Salo 1, Barton, Tioga
County NY. Photo taken during drilling phase. This access road is approximately
1,400 feet long. Road width averages 22 feet wide, 28 feet wide at creek crossing
(foreground). Width including drainage ditches is approximately 27 feet.
Source: NYS DEC 2007.

Photo 5.2 Nornew, Smyrna Hillbillies #2H, access road, Smyrna, Madison County
NY. Photo taken during drilling phase of improved existing private dirt road
(approximately 0.8 miles long). Not visible in photo is an additional 0.6 mile of new
access road construction. Operator added ditches, drainage, gravel & silt fence to existing dirt road.
The traveled part of the road surface in the picture is 12.5' wide; width including
drainage ditches is approximately 27 feet. Portion of the road crossing a protected
stream is approximately 20 feet wide. Source: NYS DEC 2008.

Final SGEIS 2015, Page 5-4

 Photo 5.3 In-service access road to horizontal Marcellus well in Bradford County,
PA. Source: Chesapeake Energy

Photo 5.4 Access road and sedimentation controls, Moss 1, Corning, Steuben
County NY. Photo taken during post-drilling phase. Access road at the curb is
approximately 50 feet wide, narrowing to 33 feet wide between curb and access gate. The traveled part of the access road ranges between 13 and 19 feet
wide. Access road length is approximately 1,100 feet long.
Source: NYS DEC 2004.

Final SGEIS 2015, Page 5-5

 5.1.2

Well Pads

Pad size is determined by site topography, number of wells and pattern layout, with
consideration given to the ability to stage, move and locate needed drilling and hydraulic
fracturing equipment. Location and design of pits, impoundments, tanks, hydraulic fracturing
equipment, reduced emission completion equipment, dehydrators and production equipment such
as separators, brine tanks and associated control monitoring, as well as office and vehicle parking
requirements, can increase square footage. Mandated surface restrictions and setbacks may also
impose additional acreage requirements. On the other hand, availability and access to offsite,
centralized dehydrators, compressor stations and centralized water storage or handling facilities
may reduce acreage requirements for individual well pads. 128
The activities associated with the preparation of a well pad are similar for both vertical wells and
multi-well pads where horizontal drilling and high volume hydraulic fracturing will be used. 129
Site preparation activities consist primarily of clearing and leveling an area of adequate size and
preparing the surface to support movement of heavy equipment. As with access road
construction, ground surface preparation typically involves staking, grading, stripping and
stockpiling of topsoil reserves, then placing a layer of crushed stone, gravel, or cobbles over
geotextile fabric. Site preparation also includes establishing erosion and sediment control
structures around the site, and constructing pits for retention of drilling fluid and, possibly, fresh
water.
Depending on site topography, part of a slope may be excavated and the excavated material may
be used as fill (cut and fill) to extend the well pad, providing for a level working area and more
room for equipment and onsite storage. The fill banks must be stabilized using appropriate
sedimentation and control measures.
The primary difference in well pad preparation for a well where high-volume hydraulic
fracturing will be employed versus a well described by the 1992 GEIS is that more land is
disturbed on a per-pad basis, though fewer pads should be needed overall. 130 A larger well pad
128

ICF Task 2, 2009, pp. 4-5.

129

Alpha, 2009, p. 6-6.

130

Alpha, 2009, p. 6-2.

Final SGEIS 2015, Page 5-6

 is required to accommodate fluid storage and equipment needs associated with the high-volume
fracturing operations. In addition, some of the equipment associated with horizontal drilling has
a larger surface footprint than the equipment described by the 1992 GEIS.
Industry estimates the average size of a multi-well pad for the drilling and fracturing phase of
operations at 3.5 acres. 131 Average production pad size, after partial reclamation, is estimated at
1.5 acres for a multi-well pad. 132 Permit applications for horizontal wells received by the
Department prior to publication of the 2009 draft SGEIS indicated multi-well pads ranging in
size from 2.2 acres to 5.5 acres during the drilling and fracturing phase of operations, and from
0.5 to 2 acres after partial reclamation during the production phase.
The well pad sizes discussed above are consistent with published information regarding drilling
operations in other shale formations, as researched by ICF International for NYSERDA. 133 For
example, in an Environmental Assessment published for the Hornbuckle Field Horizontal
Drilling Program (Wyoming), the well pad size required for drilling and completion operations is
estimated at approximately 460 feet by 340 feet, or about 3.6 acres. This estimate does not
include areas disturbed due to access road construction. A study of horizontal gas well sites
constructed by SEECO, Inc. in the Fayetteville Shale reports that the operator generally clears
300 feet by 250 feet, or 1.72 acres, for its pad and reserve pits. Fayetteville Shale sites may be as
large as 500 feet by 500 feet, or 5.7 acres.
Photo 5.5, Photo 5.6, and Photo 5.7 depict typical Marcellus well pads, and Figure 5.1 is a
schematic representation of a typical drilling site.

131

Cornue, 2011.

132

ALL Consulting, 2010, p. 15.

133

ICF Task 2, 2009, p. 4.

Final SGEIS 2015, Page 5-7

 Photo 5.5 Chesapeake Energy Marcellus well drilling, Bradford County, PA
Source: Chesapeake Energy

Photo 5.6 Hydraulic fracturing operation, horizontal Marcellus well, Upshur County, WV
Source: Chesapeake Energy, 2008

Final SGEIS 2015, Page 5-8

 Photo 5.7 Hydraulic fracturing operation, horizontal Marcellus well, Bradford County, PA
Source: Chesapeake Energy, 2008

Final SGEIS 2015, Page 5-9

 Figure 5.1 - Well Pad Schematic

Finished Well Heads
Access Road
Separator
Mobile Water Tanks
Fracturing
Fluid Mixer

Dehydrator
Drilling Rig

Mud Tanks &
Pumps

Compressor
Flare

Temp.
Separator

Office/
Outbuilding

Lined Pit

Not to scale (As reported to NYSERDA by ICF International, derived from
Argonne National Laboratory: EVS-Trip Report for Field Visit to Fayetteville
Shale Gas Wells, plus expert judgment)

5.1.3

Utility Corridors

Utility corridors associated with high-volume hydraulic fracturing will include acreage used for
potential water lines, above ground or underground electrical lines, gas gathering lines and
compressor facilities, with average per-well pad acreage estimates as follows:
•

1.35 acres for water and electrical lines;

•

1.66 acres for gas gathering lines; and

Final SGEIS 2015, Page 5-10

 •

0.67 acre for compression (because a compressor facility will service more than one well
pad, this estimate is for an incremental portion assigned to a single well pad of a
compressor facility and its associated sales line and access roads). 134

Gathering lines may follow the access road associated with the well pad, so clearing and
disturbance for the gathering line may be conducted during the initial site construction phase,
thereby adding to the access road width. For example, some proposals include a 20-foot access
road to the well pad with an additional 10-foot right-of-way for the gathering line.
Activities associated with constructing compressor facility pads are similar to those described
above for well pads.
5.1.4

Well Pad Density

5.1.4.1 Historic Well Density
Well operators reported 6,732 producing natural gas wells in New York in 2010, approximately
half of which (3,358) are in Chautauqua County. With 1,056 square miles of land in Chautauqua
County, 3,358 reported producing wells equates to at least three producing wells per square mile.
For the most part, these wells are at separate surface locations. Actual drilled density where the
resource has been developed is somewhat greater than that, because not every well drilled is
currently producing and some areas are not drilled. The Department issued 5,490 permits to drill
in Chautauqua County between 1962 and June 30, 2011, or five permits per square mile. Of
those permits, 62% (3,396) were issued during a 10-year period between 1975 and 1984, for an
average rate of 340 permits per year in a single county. Again, most of these wells were drilled
at separate surface locations, each with its own access road and attendant disturbance. Although
the number of wells is lower, parts of Seneca and Cayuga County have also been densely
drilled. Many areas in all three counties – Chautauqua, Seneca and Cayuga – have been
developed with “conventional” gas wells on 40-acre spacing (i.e., 16 wells per square mile, at
separate surface locations). Therefore, while recognizing that some aspects of shale development
activity will be different from what is described in the 1992 GEIS, it is worthwhile to note that
this pre-1992 drilling rate and site density were part of the experience upon which the 1992 GEIS
and its findings are based.
134

Cornue, 2011.

Final SGEIS 2015, Page 5-11

 Photo 5.8, Photo 5.9, Photo 5.10, and Photo 5.11 are photos and aerial views of existing well
sites in Chautauqua County, provided for informational purposes. As discussed above, well pads
where high-volume hydraulic fracturing will be employed will necessarily be larger in order to
accommodate the associated equipment. In areas developed by horizontal drilling, well pads will
be less densely spaced, reducing the number of access roads and gathering lines needed.
5.1.4.2 Anticipated Well Pad Density
The number of wells and well sites that may exist per square mile is dictated by gas reservoir
geology and productivity, mineral rights distribution, and statutory well spacing requirements set
forth in ECL Article 23, Title 5, as amended in 2008. The statute provides three statewide
spacing options for shale wells, which are described below. Although the options include
vertical drilling and single-well pad horizontal drilling, the Department anticipates that multiwell pad horizontal drilling (which results in the lowest density and least land disturbance) will
be the predominant approach, for the following reasons:
•

Industry estimates that 90% of the wells drilled to develop the Marcellus Shale will be
horizontal wells on multi-well pads; 135

•

The addition to the ECL of provisions to address multi-well pad drilling was one of the
primary objectives of the 2008 amendments, and was supported by the Department
because of the reduced environmental impact;

•

Multi-well pad drilling reduces operators’ costs, by reducing the number of access roads
and gathering lines that must be constructed as well as potentially reducing the number of
equipment mobilizations; and

•

Multi-well pad drilling reduces the number of regulatory hurdles for operators, because
each well pad location would only need to be reviewed once for environmental concerns,
stormwater permitting purposes and to determine conformance to SEQRA requirements,
including the 1992 GEIS and the Final SGEIS.

135

ALL Consulting, 2010, p. 7.

Final SGEIS 2015, Page 5-12

 Natural Gas Wells in Chautauqua County

Photo 5.8 This map shows the locations of over 4,400 Medina
formation natural gas wells in Chautauqua County from the
Mineral Resources database. The wells were typically drilled on
40 to 80 acre well spacing, making the distance between wells at
least 1/4 mile.
Readers can re-create this map by using the DEC on-line searchable database using County = Chautauqua and exporting the results to a Google Earth KML file.

Year Permit Issued
Pre-1962 (before permit program)

Total
315

1962-1979

1,440

1980-1989

1,989

1990-1999

233

2000-2009

426

Grand Total

Final SGEIS 2015, Page 5-13

4,403

 1

Photo 5.9 a & b The above map shows a
portion of the Chautauqua County map,
near Gerry. Well #1 (API Hole number
25468) shown in the photo to the right
was drilled and completed for production in 2008 to a total depth of 4,095
feet. Of the other 47 Medina gas wells
shown above, the nearest is approximately 1,600 feet to the north.

1

These Medina wells use single well
pads. Marcellus multi-well pads will be
larger and will have more wellheads and
tanks.

Final SGEIS 2015, Page 5-14

 2

Photo 5.10 a & b This map shows 28 wells in the Town of Poland, Chautauqua County. Well #2 (API Hole number
24422) was drilled in 2006 to a depth of 4,250 feet and completed for production in 2007. The nearest other well
is 1,700 feet away.
2

Final SGEIS 2015, Page 5-15

 3

Photo 5.11 a & b The map above shows 77 wells. Well #3 (API Hole number 16427) identified in the map above,
and shown in the photo below, was completed in the Town of Sheridan, Chautauqua County in 1981 and was drilled
to a depth of 2,012 feet. The map indicates that the nearest producing well to Well #3 is 1/4 mile away.

3

Final SGEIS 2015, Page 5-16

 Vertical Wells
Statewide spacing for vertical shale wells provides for one well per 40-acre spacing
unit. 136 This is the spacing requirement that has historically governed most gas well drilling in
the State, and as mentioned above, many square miles of Chautauqua, Seneca and Cayuga
counties have been developed on this spacing. One well per 40 acres equates to a density of 16
wells per square mile (i.e., 640 acres). Infill wells, resulting in more than one well per 40 acres,
may be drilled upon justification to the Department that they are necessary to efficiently recover
gas reserves. Gas well development on 40-acre spacing, with the possibility of infill wells, has
been the prevalent gas well development method in New York for many decades. However, as
reported by the Ground Water Protection Council, 137 economic and technological considerations
favor the use of horizontal drilling for shale gas development. As explained below, horizontal
drilling necessarily results in larger spacing units and reduced well pad density. Industry
estimates that 10% of the wells drilled to develop shale resources by high-volume hydraulic
fracturing will be vertical. 138
Horizontal Wells in Single-Well Spacing Units
Statewide spacing for horizontal wells where only one well will be drilled at the surface site
provides for one well per 40 acres plus the necessary and sufficient acreage so that there will be
330 feet between the wellbore in the target formation and the spacing unit boundary. This means
that the width of the spacing unit will be at least 660 feet and the distance within the target
formation between wellbores will also always be at least 660 feet. Surface locations may be
somewhat closer together because of the need to begin building angle in the wellbore about 500
feet above the target formation. However, unless the horizontal length of the wellbores within
the target formation is limited to 1,980 feet, the spacing units will exceed 40 acres in size.
Although it is possible to drill horizontal wellbores of this length, all information provided to
date indicates that, in actual practice, lateral distance drilled will normally exceed 2,000 feet and
as an example would most likely be 4,000 feet or more, requiring substantially more than 40

136

A spacing unit is the geographic area assigned to the well for the purposes of sharing costs and production. ECL §23-0501(2)
requires that the applicant control the oil and gas rights for 60% of the acreage in a spacing unit for a permit to be
issued. Uncontrolled acreage is addressed through the compulsory integration process set forth in ECL §23-0901(3).

137

GWPC, April 2009, pp. 46-47.

138

ALL Consulting, 2010, p. 7.

Final SGEIS 2015, Page 5-17

 acres. Therefore, the overall density of surface locations would be less than 16 wells per square
mile. For example, with 4,000 feet as the length of a horizontal wellbore in the target shale
formation, a spacing unit would be 4,660 feet long by 660 feet wide, or about 71 acres in size.
Nine, instead of 16, spacing units would fit within a square mile, necessitating nine instead of 16
access roads and nine instead of 16 gas gathering lines. Longer laterals would further reduce the
number of well pads per square mile. The Department anticipates that the vast majority of
horizontal wells will be drilled from common pads (i.e., multi-well pads), reducing surface
disturbance even more.
Horizontal Wells with Multiple Wells Drilled from Common Pads
The third statewide spacing option for shale wells provides, initially, for spacing units of up to
640 acres with all the horizontal wells in the unit drilled from a common well pad. Industry
estimates that 90% of the wells drilled to develop shale resources by high-volume hydraulic
fracturing will be horizontal; 139 as stated above, the Department anticipates that the vast majority
of them will be drilled from multi-well pads. This method provides the most flexibility to avoid
environmentally sensitive locations within the acreage to be developed and significantly reduces
the number of needed well pads and associated roads.
With respect to overall land disturbance, the larger surface area of an individual multi-well pad
will be more than offset by the fewer total number of well pads within a given area and the need
for only a single access road and gas gathering system to service multiple wells on a single
pad. Overall, there clearly is a smaller total area of land disturbance associated with horizontal
wells for shale gas development than that for vertical wells. 140 For example, a spacing of 40
acres per well for vertical shale gas wells would result in, on average, of 70 – 80 acres of
disturbance for the well pads, access roads and utility corridors (4.8 acres per well 141) to develop
an area of 640 acres. By contrast, a single well pad with 6 to 8 horizontal shale gas wells could
access all 640 acres with an average of 7.4 acres of total land disturbance. Table 5.1 below
provides another comparison between the well pad acreage disturbed within a 10-square mile

139

ALL Consulting, 2010, p. 7.

140

Alpha, 2009, p. 6-2.

141

ALL Consulting, 2010, p. 14.

Final SGEIS 2015, Page 5-18

 area completely developed by multi-well pad horizontal drilling versus single-well pad vertical
drilling. 142
Table 5.1 - Ten square mile area (i.e., 6,400 acres), completely drilled with horizontal wells in
multi-well units or vertical wells in single-well units (Updated July 2011)

Spacing Option
Number of Pads
Total Disturbance - Drilling Phase
% Disturbance - Drilling Phase
Total Disturbance - Production Phase
% Disturbance - Production Phase

Multi-Well 640 Acre
10
74 Acres
(7.4 acres per pad)
1.2%
15 Acres
(1.5 ac. per pad)
0.23%

Single-Well 40 Acre
160
768 Acres
(4.8 ac. per pad)
12%
80 Acres
(0.5 ac. per pad)
1.25%

It is possible that a single well-pad could be positioned to site wells to reach adjacent units,
thereby developing 1,280 acres or more without increasing the land disturbance described above
for multi-well pads. Use of longer lateral wellbores is another potential method for developing
larger areas with less land disturbance. 143
Variances or Non-Conforming Spacing Units
The ECL has always provided for variances from statewide spacing or non-conforming spacing
units, with justification, which could result in a greater well density for any of the above
options. A variance from statewide spacing or a non-conforming spacing unit requires the
Department to issue a well-specific spacing order following public comment and, if necessary,
an adjudicatory hearing. Environmental impacts associated with any well to be drilled under a
particular spacing order will continue to be reviewed separately from the spacing variance upon
receipt of a specific well permit application.
5.2

Horizontal Drilling

The first horizontal well in New York was drilled in 1989, and in 2008 approximately 10% of the
well permit applications received by the Department were for directional or horizontal wells.
The predominant use of horizontal drilling associated with natural gas development in New York
142

NTC, 2009, p. 29, updated with information from ALL Consulting, 2010.

143

ALL Consulting, 2010, p. 87.

Final SGEIS 2015, Page 5-19

 has been for production from the Black River and Herkimer Formations during the past several
years. The combination of horizontal drilling and hydraulic fracturing is widely used in other
areas of the United States as a means of recovering gas from tight shale formations.
Except for the use of specialized downhole tools, horizontal drilling is performed using similar
equipment and technology as vertical drilling, with the same protocols in place for aquifer
protection, fluid containment and waste handling. As described below, there are four primary
differences between horizontal drilling for shale gas development and the drilling described in
the 1992 GEIS. One is that larger rigs may be used for all or part of the drilling, with longer perwell drilling times than were described in the 1992 GEIS. The second is that multiple wells are
likely to be drilled from each well site (or well pad). The third is that drilling mud rather than air
may be used while drilling the horizontal portion of the wellbore to lubricate and cool the drill
bit and to clean the wellbore. Fourth and finally, the volume of rock cuttings returned to the
surface from the target formation will be greater for a horizontal well than for a vertical well.
Vertical drilling depth will vary based on target formation and location within the state. Chapter
5 of the 1992 GEIS discusses New York State’s geology with respect to oil and gas production.
Chapter 4 of this SGEIS expands upon that discussion, with emphasis on the Marcellus and Utica
Shales. Chapter 4 includes maps which show depths and thicknesses related to these two shales.
In general, wells will be drilled vertically to a depth of about 500 feet above the top of a target
interval, such as the Union Springs Member of the Marcellus Shale. Drilling may continue with
the same rig, or a larger drill rig may be brought onto the location to build angle and drill the
horizontal portion of the wellbore. A downhole motor behind the drill bit at the end of the drill
pipe is used to accomplish the angled or directional drilling deep within the earth. The drill pipe
is also equipped with inclination and azimuth sensors located about 60 feet behind the drill bit to
continuously record and report the drill bit’s location.
Current drilling technology for onshore consolidated strata results in maximum lateral lengths
that do not greatly exceed the depth of the well. For example, a 5,000-foot deep well would
generally not have a lateral length of significantly greater than 5,000 feet. 144 This may change,
144

ALL Consulting, 2010, pp. 87-88.

Final SGEIS 2015, Page 5-20

 however, as drilling technology continues to evolve. The length of the horizontal wellbore can
also be affected by the operator’s lease position or compulsory integration status within the
spacing unit, the configuration of the approved spacing unit and wellbore paths, and other factors
which influence well design.
5.2.1

Drilling Rigs

Wells for shale gas development using high-volume hydraulic fracturing will be drilled with
rotary rigs. Rotary rigs are described in the 1992 GEIS, with the typical rotary rigs used in New
York at the time characterized as either 40 to 45-foot high “singles” or 70 to 80-foot high
“doubles.” These rigs can, respectively, hold upright one joint of drill pipe or two connected
joints. “Triples,” which hold three connected joints of drill pipe upright and are over 100 feet
high, were not commonly used in New York State when the 1992 GEIS was prepared. However,
triples have been more common in New York since 1992 for natural gas storage field drilling and
to drill some Trenton-Black River wells, and may be used for drilling wells in the Marcellus
Shale and other low-permeability reservoirs.
Operators may use one large rig to drill an entire wellbore from the surface to toe of the
horizontal bore, or may use two or three different rigs in sequence. For each well, only one rig is
over the hole at a time. At a multi-well site, two rigs may be present on the pad at once, but
more than two are unlikely because of logistical and space considerations as described below.
When two rigs are used (in sequence) to drill a well, a smaller rig of similar dimensions to the
typical rotary rigs described in the 1992 GEIS would first drill the vertical portion of the well.
Only the rig used to drill the horizontal portion of the well is likely to be significantly larger than
what is described in the 1992 GEIS. This rig may be a triple, with a substructure height of about
20 feet, a mast height of about 150 feet, and a surface footprint with its auxiliary equipment of
about 14,000 square feet. Auxiliary equipment includes various tanks (for water, fuel and
drilling mud), generators, compressors, solids control equipment (shale shaker, de-silter, desander), choke manifold, accumulator, pipe racks and the crew’s office space (dog house). Initial
work with the smaller rig would typically take up to two weeks, followed by another up to two
weeks of work with the larger rig. These estimates include time for casing and cementing the

Final SGEIS 2015, Page 5-21

 well, and may be extended if drilling is slower than anticipated because of properties of the rock,
or if other problems or unexpected delays occur.
When three rigs are used to drill a well, the first rig is used to drill, case, and cement the surface
hole. This event generally takes about 8 to12 hours. The dimensions of this rig would be
consistent with what is described in the 1992 GEIS. The second rig for drilling the remainder of
the vertical hole would also be consistent with 1992 GEIS descriptions and would again typically
be working for up to 14 days, or longer if drilling is slow or problems occur. The third rig,
equipped to drill horizontally, would, as noted above, be the only one that might exceed 1992
GEIS dimensions, with a substructure height of about 20 feet, a mast height of about 150 feet,
and a surface footprint with its auxiliary equipment of about 14,000 square feet. Work with this
rig would take up to 14 days, or longer if drilling is slow or other problems or delays occur.
An important component of the drilling rig is the blow-out prevention (BOP) system. This
system is discussed in the 1992 GEIS. In summary, BOP system on a rotary drilling rig is a
pressure control system designed specifically to contain and control a “kick” (i.e., unexpected
pressure resulting in the flow of formation fluids into the wellbore during drilling operations).
Other than the well itself, the BOP system basically consists of four parts: 1) the blow-out
preventer stack, 2) the accumulator unit, 3) the choke manifold, and 4) the kill line. Blow-out
preventers are manually or hydraulically operated devices installed at the top of the surface
casing. Within the blow-out preventer there may be a combination of different types of devices
to seal off the well. Pipe rams contain two metal blocks with semi-circular notches that fit
together around the outside of the drill pipe when it is in the hole to block movement of fluids
around the pipe. Blind rams contain two rubber faced metal blocks that can completely seal off
the hole when there is no drill pipe in it. Annular or "bag" type blowout preventers contain a
resilient packing element which expands inward to seal off the hole with or without drill pipe. In
accordance with 6 NYCRR §554.4, the BOP system must be maintained and in proper working
order during operations. A BOP test program is employed to ensure the BOP system is
functioning properly if and when needed.

Final SGEIS 2015, Page 5-22

 Appendix 7 includes sample rig specifications provided by Chesapeake Energy. As noted on the
specs, fuel storage tanks associated with the larger rigs would hold volumes of 10,000 to 12,000
gallons.
In summary, the rig work for a single horizontal well – including drilling, casing and cementing
– would generally last about four to five weeks, subject to extension for slow drilling or other
unexpected problems or delays. A 150-foot tall, large-footprint rotary rig may be used for the
entire duration or only for the actual horizontal drilling. In the latter case, smaller, 1992 GEISconsistent rigs would be used to drill the vertical portion of the wellbore. The rig and its
associated auxiliary equipment would typically move off the well before fracturing operations
commence.
Photo 5.12, Photo 5.13, Photo 5.14, and Photo 5.15 are photographs of drilling rigs.
5.2.2

Multi-Well Pad Development

Horizontal drilling from multi-well pads is the common development method employed to
develop Marcellus Shale reserves in the northern tier of Pennsylvania and is expected to be
common in New York as well. In New York, ECL 23 requires that all horizontal wells in a
multi-well shale unit be drilled within three years of the date the first well in the unit commences
drilling, to prevent operators from holding acreage within large spacing units without fully
developing the acreage. 145
As described above, the space required for hydraulic fracturing operations for a multi-well pad is
dictated by a number of factors but is expected to most commonly be about 3.5 acres. 146 The
well pad is often centered in the spacing unit.

145

ECL §23-0501.

146

Cornue, 2011.

Final SGEIS 2015, Page 5-23

 Photo 5.12 Double. Union Drilling Rig 54, Olsen 1B, Town of Fenton, Broome
County NY. Credit: NYS DEC 2005.

Photo 5.13 Double. Union Drilling Rig 48. Trenton-Black River well, Salo 1, Town of Barton,
Tioga County NY. Source: NYS DEC 2008.

Final SGEIS 2015, Page 5-24

 Photo 5.14 Triple. Precision Drilling Rig 26. Ruger 1 well,
Horseheads, Chemung County. Credit: NYS DEC 2009.

Photo 5.15 Top Drive Single. Barber and DeLine rig, Sheckells 1, Town of Cherry Valley, Otsego County.
Credit: NYS DEC 2007.

Final SGEIS 2015, Page 5-25

 Several factors determine the optimal drilling pattern within the target formation. These include
geologic controls such as formation depth and thickness, mechanical and physical factors
associated with the well construction program, production experience in the area, lease position
and topography or surface restrictions that affect the size or placement of pads. 147 Often, evenly
spaced parallel horizontal bores are drilled in opposite directions from surface locations arranged
in two parallel rows. When fully developed, the resultant horizontal well pattern underground
could resemble two back-to-back pitchforks [Figure 5.2]. Other, more complex patterns may
also be proposed.
Figure 5.2 - Possible well spacing unit configurations and wellbore paths

Because of the close well spacing at the surface, most operators have indicated that only one
drilling rig at a time would be operating on any given well pad. One operator has stated that on a
well pad where six or more wells are needed, it is possible that two triple-style rigs may operate
concurrently. Efficiency and the economics of mobilizing equipment and crews would dictate
that all wells on a pad be drilled sequentially, during a single mobilization. However, this may
147

ALL Consulting, 2010, p. 88.

Final SGEIS 2015, Page 5-26

 be affected by the timing of compulsory integration proceedings if wellbores are proposed to
intersect unleased acreage. 148 Other considerations may result in gaps between well drilling
episodes at a well pad. For instance, early development in a given area may consist of initially
drilling and stimulating one to three wells on a pad to test productivity, followed by additional
wells later, but within the required 3-year time frame. As development in a given area matures
and the results become more predictable, the frequency of drilling and completing all the wells
on each pad with continuous activity in a single mobilization would be expected to increase.
5.2.3

Drilling Mud

The vertical portion of each well, including the portion that is drilled through any fresh water
aquifers, will typically be drilled using either compressed air or freshwater mud as the drilling
fluid. Operators who provided responses to the Department’s information requests stated that the
horizontal portion, drilled after any fresh water aquifers have been sealed behind cemented
surface casing, and typically cemented intermediate casing, may be drilled with a mud that may
be (i) water-based, (ii) potassium chloride/polymer-based with a mineral oil lubricant, or (iii)
synthetic oil-based. Synthetic oil-based muds are described as “food-grade” or “environmentally
friendly.” When drilling horizontally, mud is needed for (1) powering and cooling the downhole
motor and bit used for directional drilling, (2) using navigational tools which require mud to
transmit sensor readings, (3) providing stability to the horizontal borehole while drilling and (4)
efficiently removing cuttings from the horizontal hole. Other operators may drill the horizontal
bore “on air,” (i.e., with compressed air) using special equipment to control fluids and gases that
enter the wellbore. Historically, most wells in New York are drilled on air and air drilling is
addressed by the 1992 GEIS.
Drilling mud is contained and managed on-site through the rig’s mud system which is comprised
of a series of piping, separation equipment, and tanks. Photo 5.16 depicts some typical mudsystem components. During drilling or circulating mud is pumped from the mud holding tanks at
the surface down hole through the drill string and out the drill bit, and returns to the surface
through the annular space between the drill string and the walls of the bore hole, where it enters
the flowline and is directed to the separation equipment. Typical separation equipment includes

148

ECL §23-0501 2.b. prohibits the wellbore from crossing unleased acreage prior to issuance of a compulsory integration order.

Final SGEIS 2015, Page 5-27

 shale shakers, desanders, desilters and centrifuges which separate the mud from the rock
cuttings. The mud is then re-circulated back into the mud tanks where it is withdrawn by the
mud pump for continued use in the well. As described in the 1992 GEIS, used drilling mud is
typically reconditioned for use at a subsequent well. The subsequent well may be located on the
same well pad or at another location.

Photo 5.16 - Drilling rig mud system (blue tanks)

5.2.4

Cuttings

The rock chips and very fine-grained rock fragments removed by the drilling process and
returned to the surface in the drilling fluid are known as “cuttings” and are contained and
managed either in a lined on-site reserve pit or in a closed-loop tank system. 149 As described in
Section 5.13.1, the proper disposal method for cuttings is determined by the composition of the
fluid or fluids used during drilling. The proper disposal method will also dictate how the
cuttings must be contained on-site prior to disposal, as described by Section 7.1.9.
149

Adapted from Alpha, 2009, p. 133.

Final SGEIS 2015, Page 5-28

 5.2.4.1 Cuttings Volume
Horizontal drilling penetrates a greater linear distance of rock and therefore produces a larger
volume of drill cuttings than does a well drilled vertically to the same depth below the ground
surface. For example, a vertical well with surface, intermediate and production casing drilled to
a total depth of 7,000 feet produces approximately 154 cubic yards of cuttings, while a
horizontally drilled well with the same casing program to the same target depth with an example
4,000-foot lateral section produces a total volume of approximately 217 cubic yards of cuttings
(i.e., about 40% more). A multi-well site would produce approximately that volume of cuttings
from each well.
5.2.4.2 NORM in Marcellus Cuttings
To determine NORM concentrations and the potential for exposure to NORM contamination in
Marcellus rock cuttings and cores (i.e., continuous rock samples, typically cylindrical, recovered
during specialized drilling operations), the Department conducted field and sample surveys using
portable Geiger counter and gamma ray spectroscopy methods. Gamma ray spectroscopy
analyses were performed on composited Marcellus samples collected from two vertical wells
drilled through the Marcellus, one in Lebanon (Madison County), and one in Bath (Steuben
County). The results of these analyses are presented in Table 5.2a. Department staff also used a
Geiger counter to screen three types of Marcellus samples: cores from the New York State
Museum’s collection in Albany; regional outcrops of the unit; and various Marcellus well sites
from the west-central part of the state, where most of the vertical Marcellus wells in NYS are
currently located. These screening data are presented in Table 5.2b. Additional radiological
analytical data for Marcellus Shale drill cuttings has been reported from Marcellus wells in
Pennsylvania. Samples were collected from loads of drill cuttings being transported for disposal,
as well as directly from the drilling rigs during drilling of the horizontal legs of the wells. The
materials sampled were screened in-situ with a micro R meter, and analyzed by gamma ray
spectroscopy. These data are provided in Table 5.3. As discussed further in Chapter 6, the
results, which indicate levels of radioactivity that are essentially equal to background values, do
not indicate an exposure concern for workers or the general public associated with Marcellus
cuttings.

Final SGEIS 2015, Page 5-29

 Table 5.2 - 2009 Marcellus Radiological Data

Table 5.2a Marcellus Radiological Data from Gamma Ray Spectroscopy Analyses
Well
Date
API #
Town (County)
Parameter
(Depth)
Collected
K-40
Tl-208
Pb-210
Bi-212
Crouch C 4H
Bi-214
(1040 feet 31-053-26305-00-00
3/17/09
Lebanon (Madison)
Pb-214
1115 feet)
Ra-226
Ac-228
Th-234
U-235
K-40
Tl-208
Pb-210
Bi-212
Blair 2A
Bi-214
(2550’ 31-101-02698-01-00
3/26/09
Bath (Steuben)
Pb-214
2610’)
Ra-226
Ac-228
Th-234
U-235

Result +/Uncertainty
14.438 +/- 1.727 pCi/g
0.197 +/- 0.069 pCi/g
2.358 +/- 1.062 pCi/g
0.853 +/- 0.114 pCi/g
1.743 +/- 0.208 pCi/g
1.879 +/- 0.170 pCi/g
1.843 +/- 0.573 pCi/g
0.850 +/- 0.169 pCi/g
1.021 +/- 0.412 pCi/g
0.185 +/- 0.083 pCi/g
22.845 +/- 2.248 pCi/g
0.381 +/- 0.065 pCi/g
0.535 +/- 0.712 pCi/g
1.174 +/- 0.130 pCi/g
0.779 +/- 0.120 pCi/g
0.868 +/- 0.114 pCi/g
0.872 +/- 0.330 pCi/g
1.087 +/- 0.161 pCi/g
0.567 +/- 0.316 pCi/g
0.079 +/- 0.058 pCi/g

Table 5.2b Marcellus Radiological Data from Geiger Counter Screening

Media
Screened
Cores

Well

Date

Location (County)

Results

Beaver Meadow 1
Oxford 1
75 NY-14
EGSP #4
Jim Tiede
75 NY-18
75 NY-12
75 NY-21
75 NY-15
Matejka

3/12/09
3/12/09
3/12/09
3/12/09
3/12/09
3/12/09
3/12/09
3/12/09
3/12/09
3/12/09

NYS Museum (Albany)
NYS Museum (Albany)
NYS Museum (Albany)
NYS Museum (Albany)
NYS Museum (Albany)
NYS Museum (Albany)
NYS Museum (Albany)
NYS Museum (Albany)
NYS Museum (Albany)
NYS Museum (Albany)

0.005 - 0.080 mR/hr
0.005 - 0.065 mR/hr
0.015 - 0.065 mR/hr
0.005 - 0.045 mR/hr
0.005 - 0.025 mR/hr
0.005 - 0.045 mR/hr
0.015 - 0.045 mR/hr
0.005 - 0.040 mR/hr
0.005 - 0.045 mR/hr
0.005 - 0.090 mR/hr

Outcrops

N/A
N/A
N/A
N/A
N/A
N/A

3/24/2009
3/24/2009
3/24/2009
3/24/2009
3/24/2009
3/24/2009

Onesquethaw Creek (Albany)
DOT Garage, CR 2 (Albany)
SR 20, near SR 166 (Otsego)
Richfield Springs (Otsego)
SR 20 (Otsego)
Gulf Rd (Herkimer)

0.02 - 0.04 mR/hr
0.01 - 0.04 mR/hr
0.01 - 0.04 mR/hr
0.01 - 0.06 mR/hr
0.01 - 0.03 mR/hr
0.01 - 0.04 mR/hr

Well Sites

Beagell 2B
Hulsebosch 1
Bush S1

4/7/2009
4/2/2009
4/2/2009

Kirkwood (Broome)
Elmira City (Chemung)
Elmira (Chemung)

0.04 mR/hr *
0.03 mR/hr *
0.03 mR/hr *

Final SGEIS 2015, Page 5-30

 Parker 1
Donovan Farms 2
Fee 1
Meter 1
Schiavone 2
WGI 10
WGI 11
Calabro T1
Calabro T2
Frost 2A
Webster T1
Haines 1
Haines 2
McDaniels 1A
Drumm G2
Hemley G2
Lancaster M1
Maxwell 1C
Scudder 1
Blair 2A
Retherford 1
Carpenter 1
Cook 1
Zinck 1
Tiffany 1
*maximum values detected

Well Sites

4/7/2009
3/30/2009
3/30/2009
3/30/2009
4/6/2009
4/6/2009
4/6/2009
3/26/2009
3/26/2009
3/26/2009
3/26/2009
4/1/2009
4/1/2009
4/1/2009
4/1/2009
3/26/2009
3/26/2009
4/2/2009
3/26/2009
3/26/2009
4/1/2009
4/1/2009
4/1/2009
4/1/2009
4/7/2009

Oxford (Chenango)
West Sparta (Livingston)
Sparta (Livingston)
West Sparta (Livingston)
Reading (Schuyler)
Dix (Schuyler)
Dix (Schuyler)
Orange (Schuyler)
Orange (Schuyler)
Orange (Schuyler)
Orange (Schuyler)
Avoca (Steuben)
Avoca (Steuben)
Urbana (Steuben)
Bradford (Steuben)
Hornby (Steuben)
Hornby (Steuben)
Caton (Steuben)
Bath (Steuben)
Bath (Steuben)
Troupsburg (Steuben)
Troupsburg (Steuben)
Troupsburg (Steuben)
Woodhull (Steuben)
Owego (Tioga)

Table 5.3 - Gamma Ray Spectroscopy

Final SGEIS 2015, Page 5-31

0.05 mR/hr *
0.03 mR/hr *
0.02 mR/hr *
0.03 mR/hr *
0.05 mR/hr *
0.07 mR/hr *
0.07 mR/hr *
0.03 mR/hr *
0.05 mR/hr *
0.05 mR/hr *
0.05 mR/hr *
0.03 mR/hr *
0.03 mR/hr *
0.03 mR/hr *
0.07 mR/hr *
0.03 mR/hr *
0.03 mR/hr *
0.07 mR/hr *
0.03 mR/hr *
0.03 mR/hr *
0.05 mR/hr *
0.05 mR/hr *
0.05 mR/hr *
0.07 mR/hr *
0.03 mR/hr *

 5.2.5

Management of Drilling Fluids and Cuttings

The 1992 GEIS discusses the use of reserve pits and tanks, either alone or in conjunction with
one another, to contain the cuttings and fluids associated with the drilling process. Both systems
result in complete capture of the fluids and cuttings; however the use of tanks in closed-loop tank
systems facilitates off-site disposal of wastes while more efficiently utilizing drilling fluid and
providing additional insurance against environmental releases.
5.2.5.1 Reserve Pits on Multi-Well Pads
The 1992 GEIS describes the construction, use and reclamation of lined reserve pits, (also called
“drilling pits” or “mud pits”) to contain cuttings and fluids associated with the drilling process.
Rather than using a separate pit for each well on a multi-well pad, operators may propose to
maintain a single pit on the well pad until all wells are drilled and completed. The pit would
need to be adequately sized to hold cuttings from all the wells, unless the cuttings are removed
intermittently as needed to ensure adequate room for drilling-associated fluids and precipitation.
Under existing regulations, fluid associated with each well would have to be removed within 45
days of the cessation of drilling operations, unless the operator has submitted a plan to use the
fluids in subsequent operations and the Department has inspected and approved the pit. 150
Chapter 7 discusses restrictions related to the use of reserve pits for managing drilling fluids and
cuttings for high-volume hydraulic fracturing.
5.2.5.2

Closed-Loop Tank Systems

The design and configuration of closed-loop tank systems will vary from operator to operator,
but all such systems contain drilling fluids and cuttings in a series of containers, thereby
eliminating the need for a reserve pit. The containers may include tanks or bins that may have
closed tops, open tops or open tops in combination with open sides. They may be stationary or
truck-, trailer-, or skid-mounted. Regardless of the specific design of the containers, the
objective is to fully contain the cuttings and fluids in such a manner as to prevent direct contact
with the ground surface or the need to construct a lined reserve pit.
Depending on the drilling fluid utilized, a variety of types of separation equipment may be
employed within a closed-loop tank system to separate the liquids from the cuttings prior to
150

6 NYCRR §554.1(c)(3).

Final SGEIS 2015, Page 5-32

 capture within the system’s containers. For air drilling employing a closed-loop tank system,
shale shakers or other gravity-based equipment would likely be utilized to separate any
formation fluids from the cuttings whereas mud drilling would employ equipment which is
virtually identical to that of the drilling mud systems described previously in Section 5.2.3.
In addition to the equipment typically employed in a drilling mud system, operators may elect to
utilize additional solids control equipment within the closed-loop system when drilling on mud,
in an effort to further separate liquids from the cuttings. Such equipment could include but is not
limited to drying shakers, vertical or horizontal rotary cuttings dryers, squeeze presses, or
centrifuges 151 and when oil-based drilling muds are utilized the separation process may also
include treatment to reduce surface tension between the mud and the cuttings. 152,153 The
additional separation results in greater recovery of the drilling mud for re-circulation and
produces dryer cuttings for off-site disposal.
Depending on the moisture-content of the cuttings, operators may drain or vacuum free-liquids
from the cuttings container, or they may mix absorbent agents such as lime, saw dust or wood
chips into the cuttings in order to absorb any free-liquids prior to hauling off-site for disposal.
This mixing may take place in the primary capture container where the cuttings are initially
collected following separation or in a secondary container located on the well pad.
Operators may simply employ primary capture containers which are suitable for capturing and
transporting cuttings from the well site, or they may transfer cuttings from the primary capture
container to a secondary capture container for transport purposes. If cuttings will be transferred
between containers, front end loaders, vacuum trucks or other equipment would be utilized and
all transfers will be required to occur in a designated transfer area on the well pad, which will be
required to be lined.

151

ANL, 2011(a).

152

The American Oil & Gas Reporter, August 2010, p. 92-93.

153

Dugan, April 2008.

Final SGEIS 2015, Page 5-33

 Depending on the configuration and design of a closed-loop tank system use of such a system
can offer the following advantages:

5.3

•

Eliminates the time and expense associated with reserve pit construction and reclamation;

•

Reduces the surface disturbance associated with the well pad;

•

Reduces the amount of water and mud additives required as a result of re-circulation of
drilling mud;

•

Lowers mud replacement costs by capturing and re-circulating drilling mud;

•

Reduces the wastes associated with drilling by separating additional drilling mud from
the cuttings; and

•

Reduces expenses and truck traffic associated with transporting drilling waste due to the
reduced volume of the waste.
Hydraulic Fracturing

The 1992 GEIS discusses, in Chapter 9, hydraulic fracturing operations using water-based gel
and foam, and describes the use of water, hydrochloric acid and additives including surfactants,
bactericides, 154 clay and iron inhibitors and nitrogen. The fracturing fluid is an engineered
product; service providers vary the design of the fluid based on the characteristics of the
reservoir formation and the well operator’s objectives. In the late 1990s, operators and service
companies in other states developed a technology known as “slickwater fracturing” to develop
shale formations, primarily by increasing the amount and proportion of water used, reducing the
use of gelling agents and adding friction reducers. Any fracturing fluid may also contain scale
and corrosion inhibitors.
ICF International, which reviewed the current state of practice of hydraulic fracturing under
contract with NYSERDA, states that the development of water fracturing technologies has
reduced the quantity of chemicals required to hydraulically fracture target reservoirs and that

154

Bactericides must be registered for use in New York in accordance with ECL §33-0701. Well operators, service companies,
and chemical supply companies were reminded of this requirement in an October 28, 2008 letter from the Division of Mineral
Resources formulated in consultation with the former Division of Solid and Hazardous Materials, now Materials
Management. This correspondence also reminded industry of the corresponding requirement that all bactericides be properly
labeled and that the labels for such products be kept on-site during application and storage.

Final SGEIS 2015, Page 5-34

 slickwater treatments have yielded better results than gel treatments in the Barnett Shale. 155 Poor
proppant suspension and transport characteristics of water versus gel are overcome by the low
permeability of shale formations which allow the use of finer-grained proppants and lower
proppant concentrations. 156 The use of friction reducers in slickwater fracturing procedures
reduce the required pumping pressure at the surface, thereby reducing the number and power of
pumping trucks needed. 157 In addition, according to ICF, slickwater fracturing causes less
formation damage than other techniques such as gel fracturing. 158
Both slickwater fracturing and foam fracturing have been proposed for Marcellus Shale
development. As foam fracturing is already addressed by the 1992 GEIS, this document focuses
on slickwater fracturing. This type of hydraulic fracturing is referred to herein as “high-volume
hydraulic fracturing” because of the large water volumes required.
5.4

Fracturing Fluid

The fluid used for slickwater fracturing is typically comprised of more than 98% fresh water and
sand, with chemical additives comprising 2% or less of the fluid. 159 The Department has
collected compositional information on many of the additives proposed for use in fracturing
shale formations in New York directly from chemical suppliers and service companies. This
information has been evaluated by the Department’s Division of Air Resources (DAR) and
DOW as well as the NYSDOH’s Bureaus of Water Supply Protection and Toxic Substances
Assessment. It has also been reviewed by technical consultants contracted by NYSERDA 160 to
conduct research related to the preparation of this document. Discussion of potential
environmental impacts and mitigation measures in Chapters 6 and 7 of this SGEIS reflect
analysis and input by all of the foregoing entities.

155

ICF Task 1, 2009. pp. 10, 19.

156

ICF Task 1, 2009. pp. 10, 19.

157

ICF Task 1, 2009. P. 12.

158

ICF Task 1, 2009. P. 19.

159

GWPC, April 2009, pp. 61-62.

160

Alpha Environmental Consultants, Inc., ICF International, URS Corporation.

Final SGEIS 2015, Page 5-35

 Six service companies 161 and 15 chemical suppliers 162 have provided additive product
compositional information to the Department in the form of product Material Safety Data Sheets
(MSDSs) 163 and product composition disclosures consisting of chemical constituent names and
their associated Chemical Abstract Service (CAS) Numbers, 164 as well as chemical constituent
percent by weight information. Altogether, some compositional information is on file with the
Department for 235 products, with complete 165 product composition disclosures and MSDSs on
file for 167 of those products. Within these products are 322 unique chemicals whose CAS
Numbers have been disclosed to the Department and at least 21 additional compounds whose
CAS Numbers have not been disclosed due to the fact that many are mixtures. Table 5.4 is an
alphabetical list of all products for which complete chemical information, including complete
product composition disclosures and MSDSs, has been provided to the Department. Table 5.5 is
an alphabetical list of products for which only partial chemical composition information has been
provided to the Department, either in the form of product MSDSs or product composition
disclosures which appear to be lacking information. Any product whose name does not appear
within Table 5.4 or Table 5.5 was not evaluated in this SGEIS either because no chemical
information was submitted to the Department or because the product has not been proposed for
use in high-volume hydraulic fracturing operations in New York to date. These tables are
included for informational purposes only and are not intended to restrict the proposal of
additional additive products. See Chapter 8, Section 8.2.1.1 for a description of the permitting
requirements related to fracturing additive information.

161

BJ Services, Frac Tech Services, Halliburton, Superior Well Services, Universal Well Services, Schlumberger.

162

Baker Petrolite, CESI/Floteck, Champion Technologies/Special Products, Chem EOR, Cortec, Fleurin Fragrances, Industrial
Compounding, Kemira, Nalco, PfP Technologies, SNF Inc., Stepan Company, TBC-Brinadd/Texas United Chemical,
Weatherford/Clearwater, and WSP Chemicals & Technology.

163

MSDSs are regulated by the Occupational Safety and Health Administration (OSHA)’s Hazard Communication Standard, 29
CFR 1910.1200(g) and are described in Chapter 8.

164

Chemical Abstracts Service (CAS) is a division of the American Chemical Society. CAS assigns unique numerical identifiers
to every chemical described in the literature. The intention is to make database searches more convenient, as chemicals often
have many names.

165

The Department defines a complete product composition disclosure to include the chemical names and associated CAS
Numbers of every constituent within a product, as well as the percent by weight information associated with each constituent
of a product.

Final SGEIS 2015, Page 5-36

 Table 5.4 - Fracturing Additive Products – Complete Composition
Disclosure Made to the Department (Updated July 2011)

Product Name
ABF
Acetic Acid 0.1-10%
Acid Pensurf / Pensurf
Activator W
AGA 150 / Super Acid Gell 150
AI-2
Aldacide G
Alpha 125
Ammonium Persulfate/OB Breaker
APB-1, Ammonium Persulfate Breaker
AQF-2
ASP-820
B315 / Friction Reducer B315
B317 / Scale Inhibitor B317
B859 / EZEFLO Surfactant B859 / EZEFLO F103 Surfactant
B867 / Breaker B867 / Breaker J218
B868 / EB-CLEAN B868 LT Encapsulated Breaker / EB-Clean J479 LT Encapsulated
Breaker
B875 / Borate Crosslinker B875 / Borate Crosslinker J532
B880 / EB-CLEAN B880 Breaker / EB-CLEAN J475 Breaker
B890 / EZEFLO Surfactant B890 / EZEFLO F100 Surfactant
B900 / EZEFLO Surfactant B900/ EZEFLO F108 Surfactant
B910 / Corrosion Inhibitor B910 / Corrosion Inhibitor A264
B916 / Gelling Agent ClearFRAC XT B916 / Gelling Agent ClearFRAC XT J590
BA-2
BA-20
BA-40L
BA-40LM
BC-140
BC-140 X2
BE-3S
BE-6
BE-7
BE-9
BF-1
BF-7 / BF-7L
BioClear 1000 / Unicide 1000
Bio-Clear 200 / Unicide 2000

Final SGEIS 2015, Page 5-37

 Product Name
Breaker FR
BXL-2, Crosslinker/ Buffer
BXL-STD / XL-300MB
Carbon Dioxide
CC-302T
CI-14
CL-31
CLA-CHEK LP
Claproteck CF
CLA-STA XP
Clay Treat PP
Clay Treat TS
Clay Treat-3C
Clayfix II
Clayfix II plus
CPF-X Plus
Cronox 245 ES
CS-250 SI
CS-650 OS, Oxygen Scavenger
CS-Polybreak 210
CS-Polybreak 210 Winterized
CT-ARMOR
EB-4L
Enzyme G-NE
FAC-1W / Petrostep FAC-1W
FAC-3W / Petrostop FAC-3W
FE-1A
FE-2
FE-2A
FE-5A
Ferchek
Ferchek A
Ferrotrol 300L
Flomax 50
Flomax 70 / VX9173
FLOPAM DR-6000 / DR-6000
FLOPAM DR-7000 / DR-7000
Formic Acid
FR-46
FR-48W

Final SGEIS 2015, Page 5-38

 Product Name
FR-56
FRP-121
FRW-14
GasPerm 1000
GBL-8X / LEB-10X / GB-L / En-breaker
GBW-30 Breaker
Green-Cide 25G / B244 / B244A
H015 / Hydrochloric Acid 15% H15
HAI-OS Acid Inhibitor
HC-2
High Perm SW-LB
HPH Breaker
HPH foamer
Hydrochloric Acid
Hydrochloric Acid (HCl)
Hydrochloric Acid 10.1-15%
HYG-3
IC 100L
ICA-720 / IC-250
ICA-8 / IC-200
ICI-3240
Inflo-250
InFlo-250W / InFlo-250 Winterized
Iron Check / Iron Chek
Iron Sta IIC / Iron Sta II
Isopropyl Alcohol
J313 / Water Friction-Reducing Agent J313
J534 / Urea Ammonium Nitrate Solution J534
J580 / Water GellingAgent J580
K-34
K-35
KCI
L058 / Iron Stabilizer L58
L064 / Temporary Clay Stabilizer L64
LGC-35 CBM
LGC-36 UC
LGC-VI UC
Losurf 300M
M003 / Soda Ash M3
MA-844W

Final SGEIS 2015, Page 5-39

 Product Name
Methanol
MO-67
Morflo III
MSA-II
Muriatic Acid 36%
Musol A
N002 / Nitrogen N2
NCL-100
Nitrogen
Nitrogen, Liquid N2
OptiKleen-WF
Para Clear D290 / ParaClean II
Paragon 100 E+
Parasperse
Parasperse Cleaner
PSI-720
PSI-7208
Salt
SAS-2
Scalechek LP-55
Scalechek LP-65
Scalechek SCP-2 / SCP-2
Scalehib 100 / Super Scale Inhibitor / Scale Clear SI-112
SGA II
Shale Surf 1000
Shale Surf 1000 Winterized
SI 103
Sodium Citrate
SP Breaker
STIM-50 / LT-32
Super OW 3
Super Pen 2000
SuperGel 15
U042 / Chelating Agent U42
U066 / Mutual Solvent U66
Unicide 100 / EC6116A
Unifoam
Unigel 5F
UniHibA / SP-43X
UnihibG / S-11

Final SGEIS 2015, Page 5-40

 Product Name
Unislik ST 50 / Stim Lube
Vicon NF
WG-11
WG-17
WG-18
WG-35
WG-36
WLC-6
XL-1
XL-8
XLW-32
Xylene

Final SGEIS 2015, Page 5-41

 Table 5.5 - Fracturing Additive Products – Partial Composition Disclosure
to the Department (Updated July 2011)

Product Name
20 Degree Baume Muriatic Acid
AcTivator / 78-ACTW
AMB-100
B869 / Corrosion Inhibitor B869 / Corrosion Inhibitor A262
B885 / ClearFRAC LT B885 / ClearFRAC LT J551A
B892 / EZEFLO B892 / EZEFLO F110 Surfactant
CL-22UC
CL-28M
Clay Master 5C
Corrosion Inhibitor A261
FAW- 5
FDP-S798-05
FDP-S819-05
FE ACID
FR-48
FRW-16
FRW-18
Fracsal FR-143
Fracsal III
Fracsal NE-137
Fracsal Ultra
Fracsal Ultra-FM1
Fracsal Ultra-FM2
Fracsal Ultra-FM3
Fracsal Waterbase
Fracsal Waterbase-M1
FRW-25M
GA 8713
GBW-15L
GW-3LDF
HVG-1, Fast Hydrating Guar Slurry
ICA 400
ICP-1000
Inflo-102
Inhibisal Ultra CS-135
Inhibisal Ultra SI-141
J134L / Enzyme Breaker J134L
KCLS-2, KCL Substitute

Final SGEIS 2015, Page 5-42

 Product Name
L065 / Scale Inhibitor L065
LP-65
Magnacide 575 Microbiocide
MSA ACID
Multifunctional Surfactant F105
Nitrogen, Refrigerated Liquid
Product 239
PS 550
S-150
SandWedge WF
SilkWater FR-A
Super TSC / Super Scale Control TSC
Super Sol 10/20/30
Ultra Breake-C
Ultra Breake-CG
Ultra Breake-M
Ultra-Breake-MG
Unislick 30 / Cyanaflo 105L
WC-5584
WCS 5177 Corrosion Scale Inhibitor
WCW219 Combination Inhibitor
WF-12B Foamer
WF-12B Salt Inhibitor Stix
WF-12B SI Foamer/Salt Inhibitor
WF12BH Foamer
WRR-5
WFR-C
XLBHT-1
XLBHT-2

Final SGEIS 2015, Page 5-43

 Information in sections 5.4.1-3 below was compiled primarily by URS Corporation, 166 under
contract to NYSERDA.
5.4.1

Properties of Fracturing Fluids

Additives are used in hydraulic fracturing operations to elicit certain properties and
characteristics that would aide and enhance the operation. The desired properties and
characteristics include:
•

Non-reactive;

•

Non-flammable;

•

Minimal residuals;

•

Minimal potential for scale or corrosion;

•

Low entrained solids;

•

Neutral pH (pH 6.5 – 7.5) for maximum polymer hydration;

•

Limited formation damage;

•

Appropriately modify properties of water to carry proppant deep into the shale;

•

Economical to modify fluid properties; and

•

Minimal environmental effects.

5.4.2

Classes of Additives

Table 5.6 lists the types, purposes and examples of additives that have been proposed to date for
use in hydraulic fracturing of gas wells in New York State.

166

URS, 2011, p. 2-1 & 2009, p. 2-1.

Final SGEIS 2015, Page 5-44

 Table 5.6 - Types and Purposes of Additives Proposed for Use in New York State (Updated July 2011)

Additive Type
Proppant

Description of Purpose
“Props” open fractures and allows gas / fluids to flow
more freely to the well bore.

Acid

Removes cement and drilling mud from casing
perforations prior to fracturing fluid injection, and
provides accessible path to formation.
Reduces the viscosity of the fluid in order to release
proppant into fractures and enhance the recovery of the
fracturing fluid.
Inhibits growth of organisms that could produce gases
(particularly hydrogen sulfide) that could contaminate
methane gas. Also prevents the growth of bacteria which
can reduce the ability of the fluid to carry proppant into
the fractures.
Adjusts and controls the pH of the fluid in order to
maximize the effectiveness of other additives such as
crosslinkers
Prevents swelling and migration of formation clays
which could block pore spaces thereby reducing
permeability.
Reduces rust formation on steel tubing, well casings,
tools, and tanks (used only in fracturing fluids that
contain acid).
Increases fluid viscosity using phosphate esters
combined with metals. The metals are referred to as
crosslinking agents. The increased fracturing fluid
viscosity allows the fluid to carry more proppant into the
fractures.
Allows fracture fluids to be injected at optimum rates
and pressures by minimizing friction.

Breaker

Bactericide / Biocide
/ Antibacterial Agent

Buffer / pH
Adjusting Agent
Clay Stabilizer /
Control /KCl
Corrosion Inhibitor
(including Oxygen
Scavengers)
Crosslinker

Friction Reducer

Gelling Agent
Iron Control
Scale Inhibitor

Solvent

Surfactant

167

Increases fracturing fluid viscosity, allowing the fluid to
carry more proppant into the fractures.
Prevents the precipitation of metal oxides which could
plug off the formation.
Prevents the precipitation of carbonates and sulfates
(calcium carbonate, calcium sulfate, barium sulfate)
which could plug off the formation.
Additive which is soluble in oil, water & acid-based
treatment fluids which is used to control the wettability
of contact surfaces or to prevent or break emulsions
Reduces fracturing fluid surface tension thereby aiding
fluid recovery.

Examples of Chemicals 167
Sand
[Sintered bauxite; zirconium
oxide; ceramic beads]
Hydrochloric acid (HCl, 3%
to 28%) or muriatic acid
Peroxydisulfates

Gluteraldehyde; 2,2-dibromo3-nitrilopropionamide

Sodium or potassium
carbonate; acetic acid
Salts (e.g., tetramethyl
ammonium chloride
Potassium chloride (KCl)
Methanol; ammonium
bisulfate for Oxygen
Scavengers
Potassium hydroxide; borate
salts

Sodium acrylate-acrylamide
copolymer; polyacrylamide
(PAM); petroleum distillates
Guar gum; petroleum
distillates
Citric acid;
Ammonium chloride;
ethylene glycol;
Various aromatic
hydrocarbons
Methanol; isopropanol;
ethoxylated alcohol

Chemicals in brackets [ ] have not been proposed for use in the State of New York to date, but are known to be used in other
states or shale formations.

Final SGEIS 2015, Page 5-45

 5.4.3

Composition of Fracturing Fluids

The composition of the fracturing fluid used may vary from one geologic basin or formation to
another or from one area to another in order to meet the specific needs of each operation; but the
range of additive types available for potential use remains the same. There are a number of
different products for each additive type; however, only one product of each type is typically
utilized in any given hydraulic fracturing job. The selection may be driven by the formation and
potential interactions between additives. Additionally not all additive types will be utilized in
every fracturing job.
Sample compositions, by weight, of fracturing fluid are provided in Figure 5.3, Figure 5.4 and
Figure 5.5. The composition depicted in Figure 5.3 is based on data from the Fayetteville
Shale 168while those depicted in Figure 5.4 and Figure 5.5 are based on data from Marcellus
Shale development in Pennsylvania. Based on this data, between approximately 84 and 90
percent of the fracturing fluid is water; between approximately 8 and 15 % is proppant (Photo
5.17); the remainder, typically less than 1 % consists of chemical additives listed above.
Barnett Shale is considered to be the first instance of extensive high-volume hydraulic fracturing
technology use; the technology has since been applied in other areas such as the Fayetteville
Shale and the Haynesville Shale. URS notes that data collected from applications to drill
Marcellus Shale wells in New York indicate that the typical fracture fluid composition for
operations in the Marcellus Shale is similar to the provided composition in the Fayetteville
Shale. Even though no horizontal wells have been drilled in the Marcellus Shale in New York,
applications filed to date as well as information provided by the industry 169 indicate that it is
realistic to expect that the composition of fracture fluids used in the Marcellus Shale in New
York would be similar to the fluids used in the Fayetteville Shale and the Marcellus Shale in
Pennsylvania.

168

Similar to the Marcellus Shale, the Fayetteville Shale is a marine shale rich in unoxidized carbon (i.e. a black shale). The two
shales are at similar depths, and vertical and horizontal wells have been drilled/fractured at both shales.

169

ALL Consulting, 2010, p. 80.

Final SGEIS 2015, Page 5-46

 Photo 5.17 - Sand used as proppant in hydraulic fracturing operation in Bradford County, PA

Figure 5.3 - Sample Fracturing Fluid Composition (12 Additives), by Weight, from Fayetteville Shale 170

Acid, 0.11%
Breaker, 0.01%
Bactericide/Biocide, 0.001%
Clay Stabilizer/Controler,
0.05%
Corrosion Inhibitor, 0.001%
Water, 90.60%

Crosslinker, 0.01%
Other, 0.44%

Friction Reducer, 0.08%
Gelling Agent, 0.05%
Iron Control, 0.004%

Proppant, 8.96%

Scale Inhibitor, 0.04%
Surfactant, 0.08%
pH Adjusting Agent, 0.01%

170

URS, 2009, p. 2-4.

Final SGEIS 2015, Page 5-47

 Figure 5.4 - Sample Fracturing Fluid Composition (9 Additives), by Weight, from Marcellus Shale 171 (New July 2011)

Figure 5.5 - Sample Fracturing Fluid Composition (6 Additives), by Weight, from Marcellus Shale 172 (New July 2011)

171

URS, 2011, p. 2-4, adapted from ALL Consulting, 2010, p.81.

172

URS, 2011, p.2-5, adapted from ALL Consulting, 2010, p. 81.

Final SGEIS 2015, Page 5-48

 Each product within the 13 classes of additives may be made up of one or more chemical
constituents. Table 5.7 is a list of chemical constituents and their CAS numbers, that have been
extracted from product composition disclosures and MSDSs submitted to the Department for 235
products used or proposed for use in hydraulic fracturing operations in the Marcellus Shale in
New York. It is important to note that several manufacturers/suppliers provide similar products
(i.e., chemicals that would serve the same purpose) for any class of additive, and that not all
types of additives are used in a single well.
Data provided to the Department to date indicates similar fracturing fluid compositions for
vertically and horizontally drilled wells.
Table 5.7 - Chemical Constituents in Additives 173,174,175 (Updated July
2011)
176

CAS Number
106-24-1
67701-10-4
2634-33-5
95-63-6
93858-78-7
123-91-1
3452-07-1
629-73-2
104-46-1
124-28-7
112-03-8
112-88-9
40623-73-2
1120-36-1
95077-68-2

Chemical Constituent
(2E)-3,7-dimethylocta-2,6-dien-1-ol
(C8-C18) and (C18) Unsaturated Alkylcarboxylic Acid Sodium Salt
1,2 Benzisothiazolin-2-one / 1,2-benzisothiazolin-3-one
1,2,4 trimethylbenzene
1,2,4-Butanetricarboxylicacid, 2-phosphono-, potassium salt
1,4 Dioxane
1-eicosene
1-hexadecene
1-Methoxy-4-propenylbenzene
1-Octadecanamine, N, N-dimethyl- / N,N-Dimthyloctadecylamine
1-Octadecanaminium, N,N,N-Trimethyl-, Chloride
/Trimethyloctadecylammonium chloride
1-octadecene
1-Propanesulfonic acid
1-tetradecene
2- Propenoic acid, homopolymer sodium salt

173

Table 5.7, is a list of chemical constituents and their CAS numbers that have been extracted from product composition
disclosures and MSDSs submitted to the Department. It was compiled by URS Corporation (2011) and was adapted by the
Department to ensure that it accurately reflects the data submitted.

174

These are the chemical constituents of all chemical additives proposed to be used in New York for hydraulic fracturing
operations at shale wells. Only a few chemicals would be used in a single well; the list of chemical constituents used in an
individual well would be correspondingly smaller.

175

This list does not include chemicals that are exclusively used for drilling.

176

Chemical Abstracts Service (CAS) is a division of the American Chemical Society. CAS assigns unique numerical identifiers
to every chemical described in the literature. The intention is to make database searches more convenient, as chemicals often
have many names. Almost all molecule databases today allow searching by CAS number.

Final SGEIS 2015, Page 5-49

 176

CAS Number
98-55-5
10222-01-2
27776-21-2
73003-80-2
15214-89-8
46830-22-2
52-51-7
111-76-2
1113-55-9
104-76-7
67-63-0
26062-79-3
9003-03-6
25987-30-8
71050-62-9
66019-18-9
107-19-7
51229-78-8
106-22-9
5392-40-5
115-19-5
104-55-2
127-41-3
121-33-5
127087-87-0
64-19-7
68442-62-6
108-24-7
67-64-1
79-06-1
38193-60-1
25085-02-3
69418-26-4

68891-29-2
68526-86-3
68551-12-2
64742-47-8
64743-02-8

Chemical Constituent
2-(4-methyl-1-cyclohex-3-enyl)propan-2-ol
2,2 Dibromo-3-nitrilopropionamide
2,2'-azobis-{2-(imidazlin-2-yl)propane}-dihydrochloride
2,2-Dobromomalonamide
2-Acrylamido-2-methylpropanesulphonic acid sodium salt polymer
2-acryloyloxyethyl(benzyl)dimethylammonium chloride
2-Bromo-2-nitro-1,3-propanediol
2-Butoxy ethanol / Ethylene glycol monobutyl ether / Butyl Cellusolve
2-Dibromo-3-Nitriloprionamide /2-Monobromo-3-nitriilopropionamide
2-Ethyl Hexanol
2-Propanol / Isopropyl Alcohol / Isopropanol / Propan-2-ol
2-Propen-1-aminium, N,N-dimethyl-N-2-propenyl-chloride, homopolymer
2-propenoic acid, homopolymer, ammonium salt
2-Propenoic acid, polymer with 2 p-propenamide, sodium salt / Copolymer of
acrylamide and sodium acrylate
2-Propenoic acid, polymer with sodium phosphinate (1:1)
2-propenoic acid, telomer with sodium hydrogen sulfite
2-Propyn-1-ol / Progargyl Alcohol
3,5,7-Triaza-1-azoniatricyclo[3.3.1.13,7]decane, 1-(3-chloro-2-propenyl)chloride,
3,7 - dimethyl-6-octen-1-ol
3,7- dimethyl-2,6-octadienal
3-methyl-1-butyn-3-ol
3-phenyl-2-propenal
4-(2,6,6-trimethyl-1-cyclohex-2-enyl)-3-buten-2-one
4-hydroxy-3-methoxybenzaldehyde
4-Nonylphenol Polyethylene Glycol Ether Branched / Nonylphenol
ethoxylated / Oxyalkylated Phenol
Acetic acid
Acetic acid, hydroxy-, reaction products with triethanolamine
Acetic Anhydride
Acetone
Acrylamide
Acrylamide - sodium 2-acrylamido-2-methylpropane sulfonate copolymer
Acrylamide - Sodium Acrylate Copolymer / Anionic Polyacrylamide / 2Propanoic Acid
Acrylamide polymer with N,N,N-trimethyl-2[1-oxo-2-propenyl]oxy
Ethanaminium chloride / Ethanaminium, N, N, N-trimethyl-2-[(1-oxo-2propenyl)oxy]-, chloride, polymer with 2-propenamide (9Cl)
Alcohols C8-10, ethoxylated, monoether with sulfuric acid, ammonium salt
Alcohols, C11-14-iso, C13-rich
Alcohols, C12-C16, Ethoxylated / Ethoxylated alcohol
Aliphatic Hydrocarbon / Hydrotreated light distillate / Petroleum Distillates /
Isoparaffinic Solvent / Paraffin Solvent / Napthenic Solvent
Alkenes

Final SGEIS 2015, Page 5-50

 176

CAS Number
68439-57-6
9016-45-9
1327-41-9
68155-07-7
73138-27-9
71011-04-6
68551-33-7
1336-21-6
631-61-8
68037-05-8
7783-20-2
10192-30-0
12125-02-9
7632-50-0
37475-88-0
1341-49-7
6484-52-2
7727-54-0
1762-95-4
12174-11-7
121888-68-4
71-43-2
119345-04-9
74153-51-8
122-91-8
1300-72-7
140-11-4
76-22-2
68153-72-0
68876-82-4
1319-33-1
10043-35-3
1303-86-2
71-36-3
68002-97-1
68131-39-5
1317-65-3
10043-52-4
1305-62-0
1305-79-9
124-38-9
68130-15-4

Chemical Constituent
Alkyl (C14-C16) olefin sulfonate, sodium salt
Alkylphenol ethoxylate surfactants
Aluminum chloride
Amides, C8-18 and C19-Unsatd., N,N-Bis(hydroxyethyl)
Amines, C12-14-tert-alkyl, ethoxylated
Amines, Ditallow alkyl, ethoxylated
Amines, tallow alkyl, ethoxylated, acetates
Ammonia
Ammonium acetate
Ammonium Alcohol Ether Sulfate
Ammonium bisulfate
Ammonium Bisulphite
Ammonium Chloride
Ammonium citrate
Ammonium Cumene Sulfonate
Ammonium hydrogen-difluoride
Ammonium nitrate
Ammonium Persulfate / Diammonium peroxidisulphate
Ammonium Thiocyanate
Attapulgite Clay
Bentonite, benzyl(hydrogenated tallow alkyl) dimethylammonium stearate
complex / organophilic clay
Benzene
Benzene, 1,1'-oxybis, tetratpropylene derivatives, sulfonated, sodium salts
Benzenemethanaminium, N,N-dimethyl-N-[2-[(1-oxo-2-propenyl)oxy]ethyl], chloride, polymer with 2-propenamide
Benzenemethanol,4-methoxy-, 1-formate
Benzenesulfonic acid, Dimethyl-, Sodium salt /Sodium xylene sulfonate
Benzyl acetate
Bicyclo (2.2.1) heptan-2-one, 1,7,7-trimethylBlown lard oil amine
Blown rapeseed amine
Borate Salt
Boric acid
Boric oxide / Boric Anhydride
Butan-1-ol
C10 - C16 Ethoxylated Alcohol
C12-15 Alcohol, Ethoxylated
Calcium Carbonate
Calcium chloride
Calcium Hydroxide
Calcium Peroxide
Carbon Dioxide
Carboxymethylhydroxypropyl guar

Final SGEIS 2015, Page 5-51

 176

CAS Number
9012-54-8
9004-34-6
10049-04-4
78-73-9
67-48-1
91-64-5
77-92-9
94266-47-4
61789-40-0
68155-09-9
68424-94-2
7758-98-7
14808-60-7
7447-39-4
1490-04-6
8007-02-1
8000-29-1
1120-24-7
2605-79-0
3252-43-5
25340-17-4
111-46-6
22042-96-2
28757-00-8
68607-28-3
7398-69-8
25265-71-8
34590-94-8
139-33-3
64741-77-1
5989-27-5
123-01-3
27176-87-0
42504-46-1
50-70-4
37288-54-3
149879-98-1
89-65-6
54076-97-0
107-21-1
111-42-2
26027-38-3
9002-93-1

Chemical Constituent
Cellulase / Hemicellulase Enzyme
Cellulose
Chlorine Dioxide
Choline Bicarbonate
Choline Chloride
Chromen-2-one
Citric Acid
Citrus Terpenes
Cocamidopropyl Betaine
Cocamidopropylamine Oxide
Coco-betaine
Copper (II) Sulfate
Crystalline Silica (Quartz)
Cupric chloride dihydrate
Cyclohexanol,5-methyl-2-(1-methylethyl)
Cymbopogon citratus leaf oil
Cymbopogon winterianus jowitt oil
Decyldimethyl Amine
Decyl-dimethyl Amine Oxide
Dibromoacetonitrile
Diethylbenzene
Diethylene Glycol
Diethylenetriamine penta (methylenephonic acid) sodium salt
Diisopropyl naphthalenesulfonic acid
Dimethylcocoamine, bis(chloroethyl) ether, diquaternary ammonium salt
Dimethyldiallylammonium chloride
Dipropylene glycol
Dipropylene Glycol Methyl Ether
Disodium Ethylene Diamine Tetra Acetate
Distillates, petroleum, light hydrocracked
D-Limonene
Dodecylbenzene
Dodecylbenzene sulfonic acid
Dodecylbenzenesulfonate isopropanolamine
D-Sorbitol / Sorbitol
Endo-1,4-beta-mannanase, or Hemicellulase
Erucic Amidopropyl Dimethyl Betaine
Erythorbic acid, anhydrous
Ethanaminium, N,N,N-trimethyl-2-[(1-oxo-2-propenyl)oxy]-, chloride,
homopolymer
Ethane-1,2-diol / Ethylene Glycol
Ethanol, 2,2-iminobisEthoxylated 4-nonylphenol
Ethoxylated 4-tert-octylphenol

Final SGEIS 2015, Page 5-52

 176

CAS Number
68439-50-9
126950-60-5
67254-71-1
68951-67-7
68439-46-3
66455-15-0
84133-50-6
68439-51-0
78330-21-9
34398-01-1
78330-21-8
61791-12-6
61791-29-5
61791-08-0
68439-45-2
9036-19-5
9005-67-8
9005-70-3
64-17-5
100-41-4
93-89-0
97-64-3
9003-11-6
75-21-8
5877-42-9
8000-48-4
61790-12-3
68604-35-3
68188-40-9
9043-30-5
7705-08-0
7782-63-0
50-00-0
29316-47-0
153795-76-7
75-12-7
64-18-6
110-17-8
111-30-8
56-81-5
9000-30-0

Chemical Constituent
Ethoxylated alcohol
Ethoxylated alcohol
Ethoxylated alcohol (C10-12)
Ethoxylated alcohol (C14-15)
Ethoxylated alcohol (C9-11)
Ethoxylated Alcohols
Ethoxylated Alcohols (C12-14 Secondary)
Ethoxylated Alcohols (C12-14)
Ethoxylated branch alcohol
Ethoxylated C11 alcohol
Ethoxylated C11-14-iso, C13-rich alcohols
Ethoxylated Castor Oil
Ethoxylated fatty acid, coco
Ethoxylated fatty acid, coco, reaction product with ethanolamine
Ethoxylated hexanol
Ethoxylated octylphenol
Ethoxylated Sorbitan Monostearate
Ethoxylated Sorbitan Trioleate
Ethyl alcohol / ethanol
Ethyl Benzene
Ethyl benzoate
Ethyl Lactate
Ethylene Glycol-Propylene Glycol Copolymer (Oxirane, methyl-, polymer
with oxirane)
Ethylene oxide
Ethyloctynol
Eucalyptus globulus leaf oil
Fatty Acids
Fatty acids, C 8-18 and C18-unsaturated compounds with diethanolamine
Fatty acids, tall oil reaction products w/ acetophenone, formaldehyde &
thiourea
Fatty alcohol polyglycol ether surfactant
Ferric chloride
Ferrous sulfate, heptahydrate
Formaldehyde
Formaldehyde polymer with 4,1,1-dimethylethyl phenolmethyl oxirane
Formaldehyde, polymers with branched 4-nonylphenol, ethylene oxide and
propylene oxide
Formamide
Formic acid
Fumaric acid
Glutaraldehyde
Glycerol / glycerine
Guar Gum

Final SGEIS 2015, Page 5-53

 176

CAS Number
64742-94-5
9025-56-3
7647-01-0
7722-84-1
64742-52-5
79-14-1
35249-89-9
9004-62-0
5470-11-1
39421-75-5
35674-56-7
64742-88-7
64-63-0
98-82-8
68909-80-8
8008-20-6
64742-81-0
63-42-3
8022-15-9
64742-95-6
1120-21-4
546-93-0
1309-48-4
1335-26-8
14807-96-6
1184-78-7
67-56-1
119-36-8
68891-11-2
8052-41-3
64742-46-7
141-43-5
44992-01-0
64742-48-9
91-20-3
38640-62-9
93-18-5
68909-18-2
68139-30-0
68424-94-2
7727-37-9
68412-54-4
8000-27-9

Chemical Constituent
Heavy aromatic petroleum naphtha
Hemicellulase
Hydrochloric Acid / Hydrogen Chloride / muriatic acid
Hydrogen Peroxide
Hydrotreated heavy napthenic (petroleum) distillate
Hydroxy acetic acid
Hydroxyacetic acid ammonium salt
Hydroxyethyl cellulose
Hydroxylamine hydrochloride
Hydroxypropyl guar
Isomeric Aromatic Ammonium Salt
Isoparaffinic Petroleum Hydrocarbons, Synthetic
Isopropanol
Isopropylbenzene (cumene)
Isoquinoline, reaction products with benzyl chloride and quinoline
Kerosene
Kerosine, hydrodesulfurized
Lactose
Lavandula hybrida abrial herb oil
Light aromatic solvent naphtha
Light Paraffin Oil
Magnesium Carbonate
Magnesium Oxide
Magnesium Peroxide
Magnesium Silicate Hydrate (Talc)
methanamine, N,N-dimethyl-, N-oxide
Methanol
Methyl 2-hydroxybenzoate
Methyloxirane polymer with oxirane, mono (nonylphenol) ether, branched
Mineral spirits / Stoddard Solvent
Mixture of severely hydrotreated and hydrocracked base oil
Monoethanolamine
N,N,N-trimethyl-2[1-oxo-2-propenyl]oxy Ethanaminium chloride
Naphtha (petroleum), hydrotreated heavy
Naphthalene
Naphthalene bis(1-methylethyl)
Naphthalene, 2-ethoxyN-benzyl-alkyl-pyridinium chloride
N-Cocoamidopropyl-N,N-dimethyl-N-2-hydroxypropylsulfobetaine
N-Cocoamidopropyl-N,N-dimethyl-N-2-hydroxypropylsulfobetaine
Nitrogen, Liquid form
Nonylphenol Polyethoxylate
Oils, cedarwood

Final SGEIS 2015, Page 5-54

 176

CAS Number
121888-66-2
628-63-7
540-18-1
8009-03-8
64742-65-0
64741-68-0
101-84-8
70714-66-8
8000-41-7
8002-09-3
60828-78-6
25322-68-3
31726-34-8
24938-91-8
9004-32-4
51838-31-4
56449-46-8
9046-01-9
63428-86-4
62649-23-4
9005-65-6
61791-26-2
65997-18-4
127-08-2
12712-38-8
1332-77-0
20786-60-1
584-08-7
7447-40-7
590-29-4
1310-58-3
13709-94-9
24634-61-5
112926-00-8
57-55-6
107-98-2
68953-58-2
62763-89-7
62763-89-7
15619-48-4
8000-25-7
7631-86-9

Chemical Constituent
Organophilic Clays
Pentyl acetate
Pentyl butanoate
Petrolatum
Petroleum Base Oil
Petroleum naphtha
Phenoxybenzene
Phosphonic acid, [[(phosphonomethyl)imino]bis[2,1ethanediylnitrilobis(methylene)]]tetrakis-, ammonium salt
Pine Oil
Pine Oils
Poly(oxy-1,2-ethanediyl), a-[3,5-dimethyl-1-(2-methylpropyl)hexyl]-whydroxyPoly(oxy-1,2-ethanediyl), a-hydro-w-hydroxy / Polyethylene Glycol
Poly(oxy-1,2-ethanediyl), alpha-hexyl-omega-hydroxy
Poly(oxy-1,2-ethanediyl), α-tridecyl-ω-hydroxyPolyanionic Cellulose
Polyepichlorohydrin, trimethylamine quaternized
Polyethlene glycol oleate ester
Polyethoxylated tridecyl ether phosphate
Polyethylene glycol hexyl ether sulfate, ammonium salt
Polymer with 2-propenoic acid and sodium 2-propenoate
Polyoxyethylene Sorbitan Monooleate
Polyoxylated fatty amine salt
Polyphosphate
Potassium acetate
Potassium borate
Potassium borate
Potassium Borate
Potassium carbonate
Potassium chloride
Potassium formate
Potassium Hydroxide
Potassium metaborate
Potassium Sorbate
Precipitated silica / silica gel
Propane-1,2-diol, /Propylene glycol
Propylene glycol monomethyl ether
Quaternary Ammonium Compounds
Quinoline,2-methyl-, hydrochloride
Quinoline,2-methyl-, hydrochloride
Quinolinium, 1-(phenylmethl),chloride
Rosmarinus officinalis l. leaf oil
Silica, Dissolved

Final SGEIS 2015, Page 5-55

 176

CAS Number
5324-84-5
127-09-3
95371-16-7
532-32-1
144-55-8
7631-90-5
7647-15-6
497-19-8
7647-14-5
7758-19-2
3926-62-3
68-04-2
6381-77-7
2836-32-0
1310-73-2
7681-52-9
7775-19-1
10486-00-7
7775-27-1
68608-26-4
9003-04-7
7757-82-6
1303-96-4
7772-98-7
1338-43-8
57-50-1
5329-14-6
68442-77-3
112945-52-5
68155-20-4
8052-48-0
72480-70-7
68647-72-3
68956-56-9
533-74-4
55566-30-8
75-57-0
64-02-8
68-11-1
62-56-6
68527-49-1
68917-35-1
108-88-3

Chemical Constituent
Sodium 1-octanesulfonate
Sodium acetate
Sodium Alpha-olefin Sulfonate
Sodium Benzoate
Sodium bicarbonate
Sodium bisulfate
Sodium Bromide
Sodium carbonate
Sodium Chloride
Sodium chlorite
Sodium Chloroacetate
Sodium citrate
Sodium erythorbate / isoascorbic acid, sodium salt
Sodium Glycolate
Sodium Hydroxide
Sodium hypochlorite
Sodium Metaborate .8H2O
Sodium perborate tetrahydrate
Sodium persulphate
Sodium petroleum sulfonate
Sodium polyacrylate
Sodium sulfate
Sodium tetraborate decahydrate
Sodium Thiosulfate
Sorbitan Monooleate
Sucrose
Sulfamic acid
Surfactant: Modified Amine
Syntthetic Amorphous / Pyrogenic Silica / Amorphous Silica
Tall Oil Fatty Acid Diethanolamine
Tallow fatty acids sodium salt
Tar bases, quinoline derivs., benzyl chloride-quaternized
Terpene and terpenoids
Terpene hydrocarbon byproducts
Tetrahydro-3,5-dimethyl-2H-1,3,5-thiadiazine-2-thione (a.k.a. Dazomet)
Tetrakis(hydroxymethyl)phosphonium sulfate (THPS)
Tetramethyl ammonium chloride
Tetrasodium Ethylenediaminetetraacetate
Thioglycolic acid
Thiourea
Thiourea, polymer with formaldehyde and 1-phenylethanone
Thuja plicata donn ex. D. don leaf oil
Toluene

Final SGEIS 2015, Page 5-56

 176

CAS Number
81741-28-8
68299-02-5
68442-62-6
112-27-6
52624-57-4
150-38-9
5064-31-3
7601-54-9
57-13-6
25038-72-6
7732-18-5
8042-47-5
11138-66-2
1330-20-7
13601-19-9

Chemical Constituent
Tributyl tetradecyl phosphonium chloride
Triethanolamine hydroxyacetate
Triethanolamine hydroxyacetate
Triethylene Glycol
Trimethylolpropane, Ethoxylated, Propoxylated
Trisodium Ethylenediaminetetraacetate
Trisodium Nitrilotriacetate
Trisodium ortho phosphate
Urea
Vinylidene Chloride/Methylacrylate Copolymer
Water
White Mineral Oil
Xanthan gum
Xylene
Yellow Sodium of Prussiate
Chemical Constituent
Aliphatic acids
Aliphatic alcohol glycol ether
Alkyl Aryl Polyethoxy Ethanol
Alkylaryl Sulfonate
Anionic copolymer
Aromatic hydrocarbons
Aromatic ketones
Citric acid base formula
Ethoxylated alcohol blend/mixture
Hydroxy acetic acid
Oxyalkylated alkylphenol
Petroleum distillate blend
Polyethoxylated alkanol
Polymeric Hydrocarbons
Quaternary amine
Quaternary ammonium compound
Salt of amine-carbonyl condensate
Salt of fatty acid/polyamine reaction product
Sugar
Surfactant blend
Triethanolamine

The chemical constituents listed in Table 5.7 are not linked to the product names listed in Table
5.4 and Table 5.5 because a significant number of product compositions have been properly
justified as trade secrets within the coverage of disclosure exceptions of the Freedom of

Final SGEIS 2015, Page 5-57

 Information Law [Public Officers Law §87.2(d)] and the Department’s implementing regulation,
6 NYCRR § 616.7. The Department however, considers MSDSs to be public information
ineligible for exception from disclosure as trade secrets or confidential business information.
5.4.3.1 Chemical Categories and Health Information
The Department requested assistance from NYSDOH in identifying potential exposure pathways
and constituents of concern associated with high-volume hydraulic fracturing for lowpermeability gas reservoir development. The Department provided DOH with fracturing
additive product constituents based on MSDSs and product-composition disclosures for
hydraulic fracturing additive products that were provided by well-service companies and the
chemical supply companies that manufacture the products.
Compound-specific toxicity data are very limited for many chemical additives to fracturing
fluids, so chemicals potentially present in fracturing fluids were grouped together into categories
according to their chemical structure (or function in the case of microbiocides) in Table 5.8,
compiled by NYSDOH. As explained above, any given individual fracturing job will only
involve a handful of chemicals and may not include every category of chemicals.

Table 5.8 - Categories based on chemical structure of potential fracturing fluid constituents. 177 (Updated July 2011)

Chemical
Amides
Formamide
acrylamide
Amides, C8-18 and C19-Unsatd., N,N-Bis(hydroxyethyl)
Amines
urea
thiourea
Choline chloride
tetramethyl ammonium chloride
Choline Bicarbonate
Ethanol, 2,2-Iminobis1-Octadecanaminium, N,N,N, Trimethyl-, Chloride (aka Trimethyloctadecylammonium
choride)
1-Octadecanamine, N,N-Dimethyl- (aka N,N-Dimethyloctadecylamine)
monoethanolamine
177

The chemicals listed in this table are organized in order of ascending CAS Number by category.

Final SGEIS 2015, Page 5-58

CAS Number
75-12-7
79-06-1
68155-07-7
57-13-6
62-56-6
67-48-1
75-57-0
78-73-9
111-42-2
112-03-8
124-28-7
141-43-5

 Chemical
Decyldimethyl Amine
methanamine, N,N-dimethyl-, N-oxide
Decyl-dimethyl Amine Oxide
dimethyldiallylammonium chloride
polydimethyl dially ammonium chloride
dodecylbenzenesulfonate isopropanolamine
N,N,N-trimethyl-2[1-oxo-2-propenyl]oxy ethanaminium chloride
2-acryloyloxyethyl(benzyl)dimethylammonium chloride
ethanaminium, N,N,N-trimethyl-2-[(1-oxo-2-propenyl)oxy]-, chloride, homopolymer
Cocamidopropyl Betaine
Quaternary Ammonium Chloride
polyoxylated fatty amine salt
quinoline, 2-methyl, hydrochloride
N-cocoamidopropyl-N,N-dimethyl-N-2-hydroxypropylsulfobetaine
tall oil fatty acid diethanolamine
N-cocoamidopropyl-N,N-dimethyl-N-2-hydroxypropylsulfobetaine
amines, tallow alkyl, ethoxylated, acetates
quaternary ammonium compounds, bis(hydrogenated tallow alkyl) dimethyl, salts with
bentonite
amines, ditallow alkyl, ethoxylated
amines, C-12-14-tert-alkyl, ethoxylated
benzenemethanaminium, N,N-dimethyl-N-[2-[(1-oxo-2-propenyl)oxy]ethyl]-, chloride,
polymer with 2-propenamide
Erucic Amidopropyl Dimethyl Betaine
Petroleum Distillates
light paraffin oil
kerosene
Petrolatum
White Mineral Oil
stoddard solvent
Distillates, petroleum, light hydrocracked
petroleum naphtha
Mixture of severely hydrotreated and hydrocracked base oil
Multiple names listed under same CAS#:
LVP aliphatic hydrocarbon,
hydrotreated light distillate,
low odor paraffin solvent,
paraffin solvent,
paraffinic napthenic solvent,
isoparaffinic solvent,
distillates (petroleum) hydrotreated light,
petroleum light distillate,
aliphatic hydrocarbon,
petroleum distillates,
mixture of severely hydrotreated and hydrocracked base oil
naphtha, hydrotreated heavy

Final SGEIS 2015, Page 5-59

CAS Number
1120-24-7
1184-78-7
2605-79-0
7398-69-8
26062-79-3
42504-46-1
44992-01-0
46830-22-2
54076-97-0
61789-40-0
61789-71-7
61791-26-2
62763-89-7
68139-30-0
68155-20-4
68424-94-2
68551-33-7
68953-58-2
71011-04-6
73138-27-9
74153-51-8
149879-98-1
1120-21-4
8008-20-6
8009-03-8
8042-47-5
8052-41-3
64741-77-1
64741-68-0
64742-46-7

64742-47-8

64742-48-9

 Chemical
Multiple names listed under same CAS#:
hydrotreated heavy napthenic distillate,
Petroleum distillates
petroleum base oil
kerosine (petroleum, hydrodesulfurized)
kerosine (petroleum, hydrodesulfurized)
Multiple names listed under same CAS#:
heavy aromatic petroleum naphtha,
light aromatic solvent naphtha
light aromatic solvent naphtha
alkenes, C> 10 αAromatic Hydrocarbons
benzene
naphthalene
naphthalene, 2-ethoxy
1,2,4-trimethylbenzene
cumene
ethyl benzene
toluene
dodecylbenzene
xylene
diethylbenzene
naphthalene bis(1-methylethyl)
Alcohols & Aldehydes
formaldehyde
sorbitol (or) D-sorbitol
Glycerol
propylene glycol
ethanol
isopropyl alcohol
methanol
isopropyl alcohol
butanol
2-(4-methyl-1-cyclohex-3-enyl)propan-2-ol
3-phenylprop-2-enal
2-ethyl-1-hexanol
3,7 - dimethyloct-6-en-1-ol
(2E)-3,7-dimethylocta-2,6-dien-1-ol
propargyl alcohol
ethylene glycol
Diethylene Glycol
3-methyl-1-butyn-3-ol
4-hydroxy-3-methyoxybenzaldehyde
5-methyl-2-propan-2-ylcyclohexan-1-ol
3,7-dimethylocta-2,6-dienal
Ethyloctynol

Final SGEIS 2015, Page 5-60

CAS Number
64742-52-5
64742-65-0
64742-81-0
64742-88-7
64742-94-5
64742-95-6
64743-02-8
71-43-2
91-20-3
93-18-5
95-63-6
98-82-8
100-41-4
108-88-3
123-01-3
1330-20-7
25340-17-4
38640-62-9
50-00-0
50-70-4
56-81-5
57-55-6
64-17-5
67-63-0
67-56-1
67-63-0
71-36-3
98-55-5
104-55-2
104-76-7
106-22-9
106-24-1
107-19-7
107-21-1
111-46-6
115-19-5
121-33-5
1490-04-6
5392-40-5
5877-42-9

 Chemical
Glycol Ethers, Ethoxylated Alcohols & Other Ethers
phenoxybenzene
1-methyoxy-4-prop-1-enylbenzene
propylene glycol monomethyl ether
ethylene glycol monobutyl ether
triethylene glycol
ethoxylated 4-tert-octylphenol
ethoxylated sorbitan trioleate
Polysorbate 80
ethoxylated sorbitan monostearate
Polyethylene glycol-(phenol) ethers
Polyethylene glycol-(phenol) ethers
fatty alcohol polyglycol ether surfactant
Poly(oxy-1,2-ethanediyl), α-tridecyl-ω-hydroxyDipropylene glycol
Nonylphenol Ethoxylate
crissanol A-55
Polyethylene glycol-(alcohol) ethers
dipropylene glycol methyl ether
Trimethylolpropane, Ethoxylated, Propoxylated
Polyethylene glycol-(alcohol) ethers
Ethoxylated castor oil [PEG-10 Castor oil]
ethoxylated alcohols
ethoxylated alcohol
Ethoxylated alcohols
(9 – 16 carbon atoms)
ammonium alcohol ether sulfate
Polyethylene glycol-(alcohol) ethers
Polyethylene glycol-(phenol) ethers
ethoxylated hexanol
Polyethylene glycol-(alcohol) ethers
Ethoxylated alcohols
(9 – 16 carbon atoms)
C12-C14 ethoxylated alcohols
Exxal 13
Ethoxylated alcohols
(9 – 16 carbon atoms)
alcohols, C-14-15, ethoxylated
Ethoxylated C11-14-iso, C13-rich alcohols
Ethoxylated Branched C11-14, C-13-rich Alcohols
Ethoxylated alcohols
(9 – 16 carbon atoms)
alcohol ethoxylated
Polyethylene glycol-(phenol) ethers
Microbiocides
bronopol
glutaraldehyde
2-monobromo-3-nitrilopropionamide
1,2-benzisothiazolin-3-one
dibromoacetonitrile
dazomet

Final SGEIS 2015, Page 5-61

CAS Number
101-84-8
104-46-1
107-98-2
111-76-2
112-27-6
9002-93-1
9005-70-3
9005-65-6
9005-67-8
9016-45-9
9036-19-5
9043-30-5
24938-91-8
25265-71-8
26027-38-3
31726-34-8
34398-01-1
34590-94-8
52624-57-4
60828-78-6
61791-12-6
66455-15-0
67254-71-1
68002-97-1
68037-05-8
68131-39-5
68412-54-4
68439-45-2
68439-46-3
68439-50-9
68439-51-0
68526-86-3
68551-12-2
68951-67-7
78330-21-8
78330-21-9
84133-5-6
126950-60-5
127087-87-0
52-51-7
111-30-8
1113-55-9
2634-33-5
3252-43-5
533-74-4

 Chemical
Hydrogen Peroxide
2,2-dibromo-3-nitrilopropionamide
tetrakis
2,2-dibromo-malonamide
Organic Acids, Salts, Esters and Related Chemicals
tetrasodium EDTA
formic acid
acetic acid
sodium citrate
thioglycolic acid
hydroxyacetic acid
erythorbic acid, anhydrous
ethyl benzoate
ethyl lactate
acetic anhydride
fumaric acid
ethyl 2-hydroxybenzoate
methyl 2-hydroxybenzoate
(4-methoxyphenyl) methyl formate
potassium acetate
sodium acetate
Disodium Ethylene Diamine Tetra Acetate
benzyl acetate
Trisodium Ethylenediamine tetraacetate
sodium benzoate
pentyl butanoate
potassium formate
pentyl acetate
ammonium acetate
Benzenesulfonic acid, Dimethyl-, Sodium salt (aka Sodium xylene sulfonate)
Sodium Glycolate
Sodium Chloroacetate
trisodium nitrilotriacetate
sodium 1-octanesulfonate
Sodium Erythorbate
ammonium citrate
tallow fatty acids sodium salt
Polyethoxylated tridecyl ether phosphate
quinolinium, 1-(phenylmethyl), chloride
diethylenetriamine penta (methylenephonic acid) sodium salt
potassium sorbate
dodecylbenzene sulfonic acid
diisopropyl naphthalenesulfonic acid
hydroxyacetic acid ammonium salt
isomeric aromatic ammonium salt
ammonium cumene sulfonate
Fatty Acids

Final SGEIS 2015, Page 5-62

CAS Number
7722-84-1
10222-01-2
55566-30-8
73003-80-2
64-02-8
64-18-6
64-19-7
68-04-2
68-11-1
79-14-1
89-65-6
93-89-0
97-64-3
108-24-7
110-17-8
118-61-6
119-36-8
122-91-8
127-08-2
127-09-3
139-33-3
140-11-4
150-38-9
532-32-1
540-18-1
590-29-4
628-63-7
631-61-8
1300-72-7
2836-32-0
3926-62-3
5064-31-3
5324-84-5
6381-77-7
7632-50-0
8052-48-0
9046-01-9
15619-48-4
22042-96-2
24634-61-5
27176-87-0
28757-00-8
35249-89-9
35674-56-7
37475-88-0
61790-12-3

 Chemical
Fatty acids, coco, reaction products with ethanolamine, ethoxylated
fatty acid, coco, ethoxylated
2-propenoic acid, telomer with sodium hydrogen sulfite
fatty acides, c8-18 and c18-unsatd., sodium salts
carboxymethylhydroxypropyl guar
Blown lard oil amine
Tall oil Fatty Acid Diethanolamine
fatty acids, tall oil reaction products w/ acetophenone, formaldehyde & thiourea
triethanolamine hydroxyacetate
alkyl (C14-C16) olefin sulfonate, sodium salt
triethanolamine hydroxyacetate
Modified Amine
fatty acids, c-18-18 and c18-unsatd., compds with diethanolamine
Sodium petroleum sulfonate
Blown rapeseed amine
Poly(oxy-1,2-ethanediyl), α-sulfo-ω-hydroxy-, c8-10-alkyl ethers, ammonium salts
N-benzyl-alkyl-pyridinium chloride
phosphonic acid, [[(phosphonomethyl)imino]bis[2,1-ethanediylnitrilobis
(methylene)]]tetrakis-ammonium salt
tributyl tetradecyl phosphonium chloride
2-Phosphonobutane-1,2,4-tricarboxylic acid, potassium salt
sodium alpha-olefin sulfonate
benzene, 1,1'-oxybis, tetratpropylene derivatives, sulfonated, sodium salts
Polymers
guar gum
guar gum
2-propenoic acid, homopolymer, ammonium salt
low mol wt polyacrylate
Low Mol. Wt. Polyacrylate
Multiple names listed under same CAS#:
oxirane, methyl-, polymer with oxirane,
Ethylene Glycol-Propylene Glycol Copolymer
Polyanionic Cellulose
cellulose
hydroxyethyl cellulose
cellulase/hemicellulase enzyme
hemicellulase
xanthan gum
acrylamide-sodium acrylate copolymer
Vinylidene Chloride/Methylacrylate Copolymer
polyethylene glycol
copolymer of acrylamide and sodium acrylate
formaldehyde polymer with 4,1,1-dimethylethyl phenolmethyl oxirane
hemicellulase
acrylamide - sodium 2-acrylamido-2-methylpropane sulfonate copolymer
TerPoly (Acrylamide-AMPS Acrylic Acid)

Final SGEIS 2015, Page 5-63

CAS Number
61791-08-0
61791-29-5
66019-18-9
67701-10-4
68130-15-4
68153-72-0
68155-20-8
68188-40-9
68299-02-5
68439-57-6
68442-62-6
68442-77-3
68604-35-3
68608-26-4
68876-82-4
68891-29-2
68909-18-2
70714-66-8
81741-28-8
93858-78-7
95371-16-7
119345-04-9
9000-30-0
9000-30-01
9003-03-6
9003-04-7
9003-04-7
9003-11-6
9004-32-4
9004-34-6
9004-62-0
9012-54-8
9025-56-3
11138-66-2
25085-02-3
25038-72-6
25322-68-3
25987-30-8
29316-47-0
37288-54-3
38193-60-1
40623-73-2

 Chemical
oxiranemthanaminium, N,N,N-trimethyl-, chloride, homopolymer (aka:
polyepichlorohydrin, trimethylamine quaternized)
polyethlene glycol oleate ester
polymer with 2-propenoic acid and sodium 2-propenoate
modified thiourea polymer
methyloxirane polymer with oxirane, mono (nonylphenol) ether, branched
acrylamide polymer with N,N,N-trimethyl-2[1-oxo-2-propenyl]oxy ethanaminium
chloride
2-propenoic acid, polymer with sodium phosphinate (1:1)
2- Propenoic acid, homopolymer sodium salt
formaldehyde, polymers with branched 4-nonylphenol, ethylene oxide and propylene
oxide
Minerals, Metals and other Inorganics
carbon dioxide
sodium bicarbonate
Sodium Carbonate
Magnesium Carbonate
Potassium Carbonate
Boric Anhydride (a.k.a. Boric Oxide)
sodium tetraborate decahydrate
Calcium Hydroxide
Calcium Peroxide
Magnesium Oxide
Potassium Hydroxide
sodium hydroxide
Calcium Carbonate
Borate Salt
aluminum chloride, basic
Magnesium Peroxide
sodium tetraborate decahydrate
aqua ammonia 29.4%
ammonium hydrogen-difluoride
ammonium thiocyanate
sulfamic acid
hydroxylamine hydrochloride
ammonium nitrate
cupric chloride dihydrate
potassium chloride
Trisodium ortho phosphate
Non-Crystaline Silica
sodium bisulfate
hydrochloric acid
sodium chloride
sodium bromide
aqueous ammonia
sodium hypochlorite
ferric chloride

Final SGEIS 2015, Page 5-64

CAS Number
51838-31-4
56449-46-8
62649-23-4
68527-49-1
68891-11-2
69418-26-4
71050-62-9
95077-68-2
153795-76-7

124-38-9
144-55-8
497-19-8
546-93-0
584-08-7
1303-86-2
1303-96-4
1305-62-0
1305-79-9
1309-48-4
1310-58-3
1310-73-2
1317-65-3
1319-33-1
1327-41-9
1335-26-8
1332-77-0
1336-21-6
1341-49-7
1762-95-4
5329-14-6
5470-11-1
6484-52-2
7447-39-4
7447-40-7
7601-54-9
7631-86-9
7631-90-5
7647-01-0
7647-14-5
7647-15-6
7664-41-7
7681-52-9
7705-08-0

 Chemical
nitrogen
ammonium persulfate
water
sodium sulfate
sodium chlorite
sodium thiosulfate
Sodium Metaborate.8H2O
Sodium Persulphate
ferrous sulfate, heptahydrate
ammonium bisulfate
boric acid
Calcium Chloride
Chlorine Dioxide
ammonium bisulphite
sodium perborate tetrahydrate
ammonium chloride
Attapulgite Clay
potassium borate
Yellow Sodium of Prussiate
potassium metaborate
Magnesium Silicate Hydrate (Talc)
crystalline silica (quartz)
glassy calcium magnesium phosphate
Polyphosphate
silica gel
synthetic amorphous, pyrogenic silica
synthetic amorphous, pyrogenic silica
Miscellaneous
Sucrose
lactose
acetone
ethylene oxide
1,7,7-trimethylbicyclo[2.2.1]heptan-2one
chromen-2-one
1-octadecene
1,4-dioxane
(E)-4-(2,6,6-trimethyl-1-cyclohex-2-enyl)but-3-en-2-one
1-hexadecene
1-tetradecene
sorbitan monooleate
1-eicosene
D-Limonene
rosmarinus officinalis l. leaf oil
oils, cedarwood
cymbopogan winterianus jowitt oil
Pine Oil
eucalyptus globulus leaf oil

Final SGEIS 2015, Page 5-65

CAS Number
7727-37-9
7727-54-0
7732-18-5
7757-82-6
7758-19-2
7772-98-7
7775-19-01
7775-27-1
7782-63-0
7783-20-2
10043-35-3
10043-52-4
10049-04-4
10192-30-0
10486-00-7
12125-02-9
12174-11-7
12714-38-8
13601-19-9
13709-94-9
14807-96-6
14808-60-7
65997-17-3
65997-18-4
112926-00-8
112945-52-5
121888-66-2
57-50-1
63-42-3
67-64-1
75-21-8
76-22-2
91-64-5
112-88-9
123-91-1
127-41-3
629-73-2
1120-36-1
1338-43-8
3452-07-1
5989-27-5
8000-25-7
8000-27-9
8000-29-1
8000-41-7
8000-48-4

 Chemical
oils, pine
cymbopogon citratus leaf oil
lavandula hydrida abrial herb oil
2,2'-azobis-{2-(imidazlin-2-yl)propane}-dihydrochloride
3,5,7-triaza-1-azoniatricyclo[3.3.1.13,7]decane, 1-(3-chloro-2-propenyl)-chloride
alkenes
Cocamidopropyl Oxide
terpene and terpenoids
thuja plicata donn ex. D. don leaf oil
terpene hydrocarbon byproducts
tar bases, quinoline derivs., benzyl chloride-quaternized
citrus terpenes
organophilic clays
Listed without CAS Number 178
belongs with amines
proprietary quaternary ammonium compounds
quaternary ammonium compound
triethanolamine (tea) 85%, drum
Quaternary amine
Fatty amidoalkyl betaine
belongs with petroleum distillates
petroleum distillate blend
belongs with aromatic hydrocarbons
aromatic hydrocarbon
aromatic ketones
belongs with glycol ethers, ethoxylated alcohols & other ethers
Acetylenic Alcohol
Aliphatic Alcohols, ethoxylated
Aliphatic Alcohol glycol ether
Ethoxylated alcohol linear
Ethoxylated alcohols
aliphatic alcohol polyglycol ether
alkyl aryl polyethoxy ethanol
mixture of ethoxylated alcohols
nonylphenol ethoxylate
oxyalkylated alkylphenol
polyethoxylated alkanol
Oxyalkylated alcohol
belongs with organic acids, salts, esters and related chemicals
Aliphatic acids derivative
Aliphatic Acids
178

CAS Number
8002-09-3
8007-02-1
8022-15-9
27776-21-2
51229-78-8
64743-02-8
68155-09-9
68647-72-3
68917-35-1
68956-56-9
72780-70-7
94266-47-4
121888-68-4

NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA

Constituents listed without CAS #’s were tentatively placed in chemical categories based on the name listed on the MSDS or
within confidential product composition disclosures. Many of the constituents reported without CAS #s, are mixtures which
require further disclosure to the Department.

Final SGEIS 2015, Page 5-66

 Chemical
hydroxy acetic acid
citric acid 50%, base formula
Alkylaryl Sulfonate
belongs with polymers
hydroxypropyl guar
2-acrylamido-2-methylpropanesulphonic acid sodium salt polymer
Anionic copolymer
Anionic polymer
belongs with minerals, metals and other inorganics
precipitated silica
sodium hydroxide
belongs with miscellaneous
epa inert ingredient
non-hazardous ingredients
proprietary surfactant
salt of fatty acid/polyamine reaction product
salt of amine-carbonyl condensate
surfactant blend
sugar
polymeric hydrocarbon mixture
water and inert ingredients

CAS Number
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA
NA

Although exposure to fracturing additives would not occur absent a failure of operational
controls such as an accident, a spill or other non-routine incident, the health concerns noted by
NYSDOH for each chemical category are discussed below. The discussion is based on available
qualitative hazard information for chemicals from each category. Qualitative descriptions of
potential health concerns discussed below generally apply to all exposure routes (i.e., ingestion,
inhalation or skin contact) unless a specific exposure route is mentioned. For most chemical
categories, health information is available for only some of the chemicals in the category.
Toxicity testing data is quite limited for some chemicals, and less is known about their potential
adverse effects. In particular, there is little meaningful information one way or the other about
the potential impact on human health of chronic low level exposures to many of these chemicals,
as could occur if an aquifer were to be contaminated as the result of a spill or release that is
undetected and/or unremediated.
The overall risk of human health impacts occurring from hydraulic fracturing would depend on
whether any human exposure occurs, such as, for example, in the event of a spill. If an actual
contamination event such as a spill were to occur, more specific assessment of health risks would

Final SGEIS 2015, Page 5-67

 require obtaining detailed information specific to the event such as the specific additives being
used and site-specific information about exposure pathways and environmental contaminant
levels. Potential human health risks of a specific event would be assessed by comparison of
case-specific data with existing drinking water standards or ambient air guidelines. 179 If needed,
other chemical-specific health comparison values would be developed, based on a case-specific
review of toxicity literature for the chemicals involved. A case-specific assessment would
include information on how potential health effects might differ (both qualitatively and
quantitatively) depending on the route of exposure.
Petroleum Distillate Products
Petroleum-based constituents are included in some fracturing fluid additive products. They are
listed in MSDSs as various petroleum distillate fractions including kerosene, petroleum naphtha,
aliphatic hydrocarbon, petroleum base oil, heavy aromatic petroleum naphtha, mineral spirits,
hydrotreated light petroleum distillates, stoddard solvent or aromatic hydrocarbon. These can be
found in a variety of additive products including corrosion inhibitors, friction reducers and
solvents. Petroleum distillate products are mixtures that vary in their composition, but they have
similar adverse health effects. Accidental ingestion that results in exposure to large amounts of
petroleum distillates is associated with adverse effects on the gastrointestinal system and central
nervous system. Skin contact with kerosene for short periods can cause skin irritation, blistering
or peeling. Breathing petroleum distillate vapors can adversely affect the central nervous system.
Aromatic Hydrocarbons
Some fracturing additive products contain specific aromatic hydrocarbon compounds that can
also occur in petroleum distillates (benzene, toluene, ethylbenzene and xylenes or BTEX;
naphthalene and related derivatives, trimethylbenzene, diethylbenzene, dodecylbenzene,
cumene). BTEX compounds are associated with adverse effects on the nervous system, liver,
kidneys and blood-cell-forming tissues. Benzene has been associated with an increased risk of
leukemia in industrial workers who breathed elevated levels of the chemical over long periods of
time in workplace air. Exposure to high levels of xylene has damaged the unborn offspring of
laboratory animals exposed during pregnancy. Naphthalene is associated with adverse effects on
179

10 NYCRR Part 5: Drinking Water Supplies; Subpart 5-1: Public Water Systems, Maximum Contaminant Levels;
Department Policy DAR-1: Guidelines for the Control of Toxic Ambient Air Contaminants.

Final SGEIS 2015, Page 5-68

 red blood cells when people consumed naphthalene mothballs or when infants wore cloth diapers
stored in mothballs. Laboratory animals breathing naphthalene vapors for their lifetimes had
damage to their respiratory tracts and increased risk of nasal and lung tumors.
Glycols
Glycols occur in several fracturing fluid additives including crosslinkers, breakers, clay and iron
controllers, friction reducers and scale inhibitors. Propylene glycol has low inherent toxicity and
is used as an additive in food, cosmetic and drug products. However, high exposure levels of
ethylene glycol adversely affect the kidneys and reproduction in laboratory animals.
Glycol Ethers
Glycol ethers and related ethoxylated alcohols and phenols are present in fracturing fluid
additives, including corrosion inhibitors, surfactants and friction reducers. Some glycol ethers
[e.g., monomethoxyethanol, monoethoxyethanol, propylene glycol monomethyl ether, ethylene
glycol monobutyl ether (also known as 2-butoxyethanol)] can affect the male reproductive
system and red blood cell formation in laboratory animals at high exposure levels.
Alcohols and Aldehydes
Alcohols are present in some fracturing fluid additive products, including corrosion inhibitors,
foaming agents, iron and scale inhibitors and surfactants. Exposure to high levels of some
alcohols (e.g., ethanol, methanol) affects the central nervous system.
Aldehydes are present in some fracturing fluid additive products, including corrosion inhibitors,
scale inhibitors, surfactants and foaming agents. Aldehydes can be irritating to tissues when
coming into direct contact with them. The most common symptoms include irritation of the
skin, eyes, nose and throat, along with increased tearing. Formaldehyde is present in several
additive products, although in most cases the concentration listed in the product is relatively low
(< 1%) and is listed alongside a formaldehyde-based polymer constituent. Severe pain,
vomiting, coma and possibly death can occur after drinking large amounts of formaldehyde.
Several studies of laboratory rats exposed for life to high amounts of formaldehyde in air found
that the rats developed nose cancer. Some studies of humans exposed to lower amounts of
formaldehyde in workplace air found more cases of cancer of the nose and throat

Final SGEIS 2015, Page 5-69

 (nasopharyngeal cancer) than expected, but other studies have not found nasopharyngeal cancer
in other groups of workers exposed to formaldehyde in air.
Amides
Acrylamide is used in some fracturing fluid additives to create polymers during the stimulation
process. These polymers are part of some friction reducers and scale inhibitors. Although the
reacted polymers that form during fracturing are of low inherent toxicity, unreacted acrylamide
may be present in the fracturing fluid, or breakdown of the polymers could release acrylamide
back into the flowback water. High levels of acrylamide damage the nervous system and
reproductive system in laboratory animals and also cause cancer in laboratory animals.
Formamide may be used in some corrosion inhibitors products. Ingesting high levels of
formamide adversely affects the female reproductive system in laboratory animals.
Amines
Amines are constituents of fracturing fluid products including corrosion inhibitors, cross-linkers,
friction reducers, iron and clay controllers and surfactants. Chronic ingestion of mono-, di- or
tri-ethanolamine adversely affects the liver and kidneys of laboratory animals.
Some quaternary ammonium compounds, such as dimethyldiallyl ammonium chloride, can react
with chemicals used in some systems for drinking water disinfection to form nitrosamines.
Nitrosamines cause genetic damage and cancer when ingested by laboratory animals.
Organic Acids, Salts, Esters and Related Chemicals
Organic acids and related chemicals are constituents of fracturing fluid products including acids,
buffers, corrosion and scale inhibitors, friction reducers, iron and clay controllers, solvents and
surfactants. Some short-chain organic acids such as formic, acetic and citric acids can be
corrosive or irritating to skin and mucous membranes at high concentrations. However, acetic
and citric acids are regularly consumed in foods (such as vinegar and citrus fruits) where they
occur naturally at lower levels that are not harmful.

Final SGEIS 2015, Page 5-70

 Some foaming agents and surfactant products contain organic chemicals included in this
category that contain a sulfonic acid group (sulfonates). Exposure to elevated levels of
sulfonates is irritating to the skin and mucous membranes.
Microbiocides
Microbiocides are antimicrobial pesticide products intended to inhibit the growth of various
types of bacteria in the well. A variety of different chemicals are used in different microbiocide
products that are proposed for Marcellus wells. Toxicity information is limited for several of the
microbiocide chemicals. However, for some, high exposure has caused effects in the respiratory
and gastrointestinal tracts, the kidneys, the liver and the nervous system in laboratory animals.
Other Constituents
The remaining chemicals listed in MSDSs and confidential product composition disclosures
provided to the Department are included in Table 5.8 under the following categories: polymers,
miscellaneous chemicals that did not fit another chemical category and product constituents that
were not identified by a CAS number. Readily available health effects information is lacking for
many of these constituents, but one that is relatively well studied is discussed here. In the event
of environmental contamination involving chemicals lacking readily available health effects
information, the toxicology literature would have to be researched for chemical-specific toxicity
data or toxicity data for closely- related chemicals.
1,4-dioxane may be used in some surfactant products. 1,4-Dioxane is irritating to the eyes and
nose when vapors are breathed. Exposure to very high levels may cause severe kidney and liver
effects and possibly death. Studies in animals have shown that breathing vapors of 1,4-dioxane,
swallowing liquid 1,4-dioxane or contaminated drinking water, or having skin contact with liquid
1,4-dioxane affects mainly the liver and kidneys. Laboratory rats and mice that drank water
containing 1,4-dioxane during most of their lives developed liver cancer; the rats also developed
cancer inside the nose.
Conclusions
The hydraulic fracturing product additives proposed for use in NYS and used for fracturing
horizontal Marcellus Shale wells in other states contain similar types of chemical constituents as

Final SGEIS 2015, Page 5-71

 the products that have been used for many years for hydraulic fracturing of traditional vertical
wells in NYS. Some of the same products are used in both well types. Chemicals in products
proposed for use in high-volume hydraulic fracturing include some that, based mainly on
occupational studies or high-level exposures in laboratory animals, have been shown to cause
effects such as carcinogenicity, mutagenicity, reproductive toxicity, neurotoxicity or organ
damage. This information only indicates the types of toxic effects these chemicals can cause
under certain circumstances but does not mean that use of these chemicals would cause exposure
in every case or that exposure would cause those effects in every case. Whether or not people
actually experience a toxic effect from a chemical depends on whether or not they experience
any exposure to the chemical along with many other factors including, among others, the
amount, timing, duration and route of exposure and individual characteristics that can contribute
to differences in susceptibility.
The total amount of fracturing additives and water used in hydraulic fracturing of horizontal
wells is considerably larger than for traditional vertical wells. This suggests the potential
environmental consequences of an upset condition could be proportionally larger for horizontal
well drilling and fracturing operations. As mentioned earlier, the 1992 GEIS addressed hydraulic
fracturing in Chapter 9, and NYSDOH’s review did not identify any potential exposure scenarios
associated with horizontal drilling and high-volume hydraulic fracturing that are qualitatively
different from those addressed in the 1992 GEIS.
5.5

Transport of Hydraulic Fracturing Additives

Fracturing additives are transported in “DOT-approved” trucks or containers. The trucks are
typically flat-bed trucks that carry a number of strapped-on plastic totes which contain the liquid
additive products. (Totes are further described in Section 5.6.). Liquid products used in smaller
quantities are transported in one-gallon sealed jugs carried in the side boxes of the flat-bed.
Some liquid constituents, such as hydrochloric acid, are transferred in tank trucks.
Dry additives are transported on flat-beds in 50- or 55-pound bags which are set on pallets
containing 40 bags each and shrink-wrapped, or in five-gallon sealed plastic buckets. When
smaller quantities of some dry products such as powdered biocides are used, they are contained

Final SGEIS 2015, Page 5-72

 in a double-bag system and may be transported in the side boxes of the truck that constitutes the
blender unit.
Regulations that reference “DOT-approved” trucks or containers that are applicable to the
transportation and storage of hazardous fracturing additives refer to federal (USDOT) regulations
for registering and permitting commercial motor carriers and drivers, and established standards
for hazardous containers. The United Nations (UN) also has established standards and criteria
for containers. New York is one of many states where the state agency (NYSDOT) has adopted
the federal regulations for transporting hazardous materials interstate. The NYSDOT has its own
requirements for intrastate transportation. 180 For informational purposes, Chapter 8 contains
descriptions of applicable NYSDOT and USDOT regulations.
Transporting fracturing additives that are hazardous is comprehensively regulated under existing
regulations. The regulated materials include the hazardous additives and mixtures containing
threshold levels of hazardous materials. These transported materials are maintained in the
USDOT or UN-approved storage containers until the materials are consumed at the drill sites. 181
5.6

On-Site Storage and Handling of Hydraulic Fracturing Additives

Prior to use, additives remain at the wellsite in the containers and on the trucks in which they are
transported and delivered. Storage time is generally less than a week for economic and logistical
reasons, materials are not delivered until fracturing operations are set to commence, and only the
amount needed for scheduled continuous fracturing operations is delivered at any one time.
As detailed in Section 5.4.3, there are 13 classes of additives, based on their purpose or use; not
all classes would be used at every well; and only one product in each class would typically be
used per job. Therefore, although the chemical lists in Table 5.7 and Table 5.8 reflect the
constituents of 235 products, typically no more than 12 products consisting of far fewer
chemicals than listed would be present at one time at any given site.

180

Alpha 2009, p. 31.

181

Alpha 2009, p. 31.

Final SGEIS 2015, Page 5-73

 When the hydraulic fracturing procedure commences, hoses are used to transfer liquid additives
from storage containers to a truck-mounted blending unit. The flat-bed trucks that deliver liquid
totes to the site may be equipped with their own pumping systems for transferring the liquid
additive to the blending unit when fracturing operations are in progress. Flat-beds that do not
have their own pumps rely on pumps attached to the blending unit. Additives delivered in tank
trucks are pumped to the blending unit or the well directly from the tank truck. Dry additives are
poured by hand into a feeder system on the blending unit. The blended fracturing solution is not
stored, but is immediately mixed with proppant and pumped into the cased and cemented
wellbore. This process is conducted and monitored by qualified personnel, and devices such as
manual valves provide additional controls when liquids are transferred. Common observed
practices during visits to drill sites in the northern tier of Pennsylvania included lined
containments and protective barriers where chemicals were stored and blending took place. 182
5.6.1

Summary of Additive Container Types

The most common containers are 220-gallon to 375-gallon high-density polyethylene (HDPE)
totes, which are generally cube-shaped and encased in a metal cage. These totes have a bottom
release port to transfer the chemicals, which is closed and capped during transport, and a top fill
port with a screw-on cap and temporary lock mechanism. Photo 5.18 depicts a transport truck
with totes.

182

Alpha, 2009, p. 35.

Final SGEIS 2015, Page 5-74

 Photo 5.18 - Transport trucks with totes

To summarize, the storage containers at any given site during the short period of time between
delivery and completion of continuous fracturing operations will consist of all or some of the
following:
•

Plastic totes encased in metal cages, ranging in volume from 220 gallons to 375 gallons,
which are strapped on to flat bed trucks pursuant to USDOT and NYSDOT regulations;

•

Tank trucks;

•

Palletized 50-55 gallon bags, made of coated paper or plastic (40 bags per pallet, shrinkwrapped as a unit and then wrapped again in plastic);

•

One-gallon jugs with perforated sealed twist lids stored inside boxes on the flat-bed; and

•

Smaller double-bag systems stored inside boxes on the blending unit.

Final SGEIS 2015, Page 5-75

 5.7

Source Water for High-Volume Hydraulic Fracturing

As discussed in Chapter 6, it is estimated, based on water withdrawals in the Susquehanna River
Basin in Pennsylvania, that average water use per well in New York could be 3.6 million gallons.
Operators could withdraw water from surface or ground water sources themselves or may
purchase it from suppliers. The suppliers may include, among others, municipalities with excess
capacity in their public supply systems, or industrial entities with wastewater effluent streams
that meet usability criteria for hydraulic fracturing. Potential environmental impacts of water
sourcing are discussed in Chapter 6, and mitigation measures to address potential environmental
impacts are discussed in Chapter 7. Photo 5.19a and b depict a water withdrawal facility along
the Chemung River in the northern tier of Pennsylvania.
Factors affecting usability of a given source include: 183
Availability – The “owner” of the source needs to be identified, contact made, and agreements
negotiated.
Distance/route from the source to the point of use – The costs of trucking large quantities of
water increases and water supply efficiency decreases when longer distances and travel times are
involved. Also, the selected routes need to consider roadway wear, bridge weight limits, local
zoning limits, impacts on residents, and related traffic concerns.
Available quantity – Use of fewer, larger water sources avoids the need to utilize multiple
smaller sources.
Reliability – A source that is less prone to supply fluctuations or periods of unavailability would
be more highly valued than an intermittent and less steady source.
Accessibility –Water from deep mines and saline aquifers may be more difficult to access than a
surface water source unless adequate infrastructure is in place. Access to a municipal or
industrial plant or reservoir may be inconvenient due to security or other concerns. Access to a
stream may be difficult due to terrain, competing land uses, or other issues.

183

URS, 2009, p. 7-1.

Final SGEIS 2015, Page 5-76

 Quality of water – The fracturing fluid serves a very specific purpose at different stages of the
fracturing process. The composition of the water could affect the efficacy of the additives and
equipment used. The water may require pre-treatment or additional additives may be needed to
overcome problematic characteristics.
Potential concerns with water quality include scaling from precipitation of barium sulfate and
calcium sulfate; high concentrations of chlorides, which could increase the need for friction
reducers; very high or low pH (e.g., water from mines); high concentrations of iron (water from
quarries or mines) which could potentially plug fractures; microbes that can accelerate corrosion,
scaling or other gas production; and high concentrations of sulfur (e.g. water from flue gas
desulfurization impoundments), which could contaminate natural gas. In addition, water sources
of variable quality could present difficulties.
Permittability – Applicable permits and approvals would need to be identified and assessed as to
feasibility and schedule for obtaining approvals, conditions and limitations on approval that
could impact the activity or require mitigation, and initial and ongoing fees and charges.
Preliminary discussions with regulating authorities would be prudent to identify fatal flaws or
obstacles.
Disposal – Proper disposal of flowback from hydraulic fracturing will be necessary, or
appropriate treatment for re-use provided. Utilizing an alternate source with sub-standard quality
water could add to treatment and disposal costs.
Cost – Sources that have a higher associated cost to acquire, treat, transport, permit, access or
dispose, typically will be less desirable.
5.7.1

Delivery of Source Water to the Well Pad

Water could be delivered by truck or pipeline directly from the source to the well pad, or could
be delivered by trucks or pipeline from centralized water storage or staging facilities consisting
of tanks or engineered impoundments. Photo 5.21 shows a fresh water pipeline in Bradford
County, Pennsylvania, to move fresh water from an impoundment to a well pad.

Final SGEIS 2015, Page 5-77

 At the well pad, water is typically stored in 500-barrel steel tanks. These mobile storage tanks
provide temporary storage of fresh water, and preclude the need for installation of centralized
impoundments. They are double-walled, wheeled tanks with sealed entry and fill ports on top
and heavy-duty drain valves with locking mechanisms at the base. These tanks are similar in
construction to the ones used to temporarily store flowback water; see Photo 5.7.
Potential environmental impacts related to water transportation, including the number and
duration of truck trips for moving both fluid and temporary storage tanks, will be addressed in
Chapter 6. Mitigation measures are described in Chapter 7.
5.7.2

Use of Centralized Impoundments for Fresh Water Storage

Operators have indicated that centralized water storage impoundments will likely be utilized as
part of a water management plan. Such facilities would allow the operators to withdraw water
from surface water bodies during periods of high flow and store the water for use in future
hydraulic fracturing activities, thus avoiding or reducing the need to withdraw water during
lower-flow periods when the potential for negative impacts to aquatic environments and
municipal drinking water suppliers is greater.
The proposed engineered impoundments would likely be constructed from compacted earth
excavated from the impoundment site and then compressed to form embankments around the
excavated area. Typically, such impoundments would then be lined to minimize the loss of
water due to infiltration. See Section 8.2.2.2 for a description of the Department’s existing
regulatory program related to construction, operation and maintenance of such impoundments.

Final SGEIS 2015, Page 5-78

 Photos 5.19 a & b Fortuna SRBC-approved Chemung

River water withdrawal facility, Towanda PA. Source: 


Photo 5.20 Fresh water supply pond. Black pipe in pond is a float to keep suction away from pond bottom liner.
Ponds are completely enclosed by wire fence. Source: NYS DEC 2009.

Photo 5.21 Water pipeline from Fortuna central freshwater impoundments, Troy PA. Source: NYS DEC 2009.

Final SGEIS 2015, Page 5-79

 Photo 5.22 Construction of freshwater impoundment in Upshur Co. WV. Source: Chesapeake Energy

Final SGEIS 2015, Page 5-80

 It is likely that an impoundment would service well pads within a radius of up to four miles, and
that impoundment volume could be several million gallons with surface acreage of up to five
acres. The siting and sizing of such impoundments would be affected by factors such as terrain,
environmental conditions, natural barriers, surrounding land use and proximity to nearby
development, particularly residential development, as well as by the operators’ lease positions. It
is not anticipated that a single centralized impoundment would service wells from more than one
well operator.
Photo 5.22 depicts a centralized freshwater impoundment and its construction.
5.8

Hydraulic Fracturing Design

Service companies design hydraulic fracturing procedures based on the rock properties of the
prospective hydrocarbon reservoir. For any given area and formation, hydraulic fracturing
design is an iterative process, i.e., it is continually improved and refined as development
progresses and more data is collected. In a new area, it may begin with computer modeling to
simulate various fracturing designs and their effect on the height, length and orientation of the
induced fractures. 184 After the procedure is actually performed, the data gathered can be used to
optimize future treatments. 185 Data to define the extent and orientation of fracturing may be
gathered during fracturing treatments by use of microseismic fracture mapping, tilt
measurements, tracers, or proppant tagging. 186,187 ICF International, under contract to
NYSERDA to provide research assistance for this document, observed that fracture monitoring
by these methods is not regularly used because of cost, but is commonly reserved for evaluating
new techniques, determining the effectiveness of fracturing in newly developed areas, or
calibrating hydraulic fracturing models. 188 Comparison of production pressure and flow-rate

184

GWPC, April 2009, p. 57.

185

GWPC, April 2009, p. 57.

186

GWPC, April 2009, p. 57.

187

ICF, 2009, pp. 5-6.

188

ICF, 2009, p.6.

Final SGEIS 2015, Page 5-81

 analysis to pre-fracture modeling is a more common method for evaluating the results of a
hydraulic fracturing procedure. 189
The objective in any hydraulic fracturing procedure is to limit fractures to the target formation.
Excessive fracturing is undesirable from a cost standpoint because of the expense associated with
unnecessary use of time and materials. 190 Economics would also dictate limiting the use of
water, additives and proppants, as well as the need for fluid storage and handling equipment, to
what is needed to treat the target formation. 191 In addition, if adjacent rock formations contain
water, then fracturing into them would bring water into the reservoir formation and the well.
This could result in added costs to handle production brine, or could result in loss of economic
hydrocarbon production from the well. 192
5.8.1

Fracture Development

ICF reviewed how hydraulic fracturing is affected by the rock’s natural compressive stresses. 193
The dimensions of a solid material are controlled by major, intermediate and minor principal
stresses within the material. In rock layers in their natural setting, these stresses are vertical and
horizontal. Vertical stress increases with the thickness of overlying rock and exerts pressure on a
rock formation to compress it vertically and expand it laterally. However, because rock layers
are nearly infinite in horizontal extent relative to their thickness, lateral expansion is constrained
by the pressure of the horizontally adjacent rock mass. 194
Rock stresses may decrease over geologic time as a result of erosion acting to decrease vertical
rock thickness. Horizontal stress decreases due to erosion more slowly than vertical stress, so
rock layers that are closer to the surface have a higher ratio of horizontal stress to vertical
stress. 195

189

ICF, 2009, pp. 6-8.

190

GWPC, April 2009, p. 58.

191

ICF, 2009, p. 14.

192

GWPC, April 2009, p. 58.

193

ICF, 2009, pp. 14-15.

194

ICF, 2009, pp. 14-15.

195

ICF, 2009, pp. 14-15.

Final SGEIS 2015, Page 5-82

 Fractures form perpendicular to the direction of least stress. If the minor principal stress is
horizontal, fractures will be vertical. The vertical fractures would then propagate horizontally in
the direction of the major and intermediate principal stresses. 196
ICF notes that the initial stress field created during deposition and uniform erosion may become
more complex as a result of geologic processes such as non-uniform erosion, folding and uplift.
These processes result in topographic features that create differential stresses, which tend to die
out at depths approximating the scale of the topographic features. 197 ICF – citing PTTC, 2006 –
concludes that: “In the Appalachian Basin, the stress state would be expected to lead to
predominantly vertical fractures below about 2500 feet, with a tendency towards horizontal
fractures at shallower depths.” 198
5.8.2

Methods for Limiting Fracture Growth

ICF reports that, despite ongoing laboratory and field experimentation, the mechanisms that limit
vertical fracture growth are not completely understood. 199 Pre-treatment modeling, as discussed
above, is one tool for designing fracture treatments based on projected fracture behavior. Other
control techniques identified by ICF include: 200
•

Use of a friction reducer, which helps to limit fracture height by reducing pumping loss
within fractures, thereby maintaining higher fluid pressure at the fracture tip;

•

Measuring fracture growth in real time by microseismic analysis, allowing the fracturing
process to be stopped upon achieving the desired fracturing extent; and

•

Reducing the length of wellbore fractured in each stage of the procedure, thereby
focusing the applied pressure and proppant placement, and allowing for modifications to
the procedure in subsequent stages based on monitoring the results of each stage.

196

ICF, 2009, pp. 14-15.

197

ICF, 2009, pp. 14-15.

198

ICF, 2009, pp. 14-15.

199

ICF, 2009, p. 16.

200

ICF, 2009, p. 17.

Final SGEIS 2015, Page 5-83

 5.8.3

Hydraulic Fracturing Design – Summary

ICF provided the following summary of the current state of hydraulic fracturing design to
contain induced fractures in the target formation:
Hydraulic fracturing analysis, design, and field practices have advanced
dramatically in the last quarter century. Materials and techniques are constantly
evolving to increase the efficiency of the fracturing process and increase reservoir
production. Analytical techniques to predict fracture development, although still
imperfect, provide better estimates of the fracturing results. Perhaps most
significantly, fracture monitoring techniques are now available that provide
confirmation of the extent of fracturing, allowing refinement of the procedures for
subsequent stimulation activities to confine the fractures to the desired production
zone. 201
Photo 5.23 shows personnel monitoring a hydraulic fracturing procedure.

Photo 5.23 - Personnel monitoring a hydraulic fracturing procedure. Source: Fortuna Energy.

201

ICF, 2009, p. 19.

Final SGEIS 2015, Page 5-84

 5.9

Hydraulic Fracturing Procedure

The fracturing procedure involves the controlled use of water and chemical additives, pumped
under pressure into the cased and cemented wellbore. Composition, purpose, transportation,
storage and handling of additives are addressed in previous sections of this document. Water and
fluid management, including source, transportation, storage and disposition, are also discussed
elsewhere in this document. Potential impacts, mitigation measures and the permit process are
addressed in Chapters 6, 7, and 8. The discussion in this section describes only the specific
physical procedure of high-volume hydraulic fracturing. Except where other references are
specifically noted, operational details are derived from permit applications on file with the
Department’s Division of Mineral Resources (DMN) and responses to the Department’s
information requests provided by several operators and service companies about their planned
operations in New York.
Hydraulic fracturing occurs after the well is cased and cemented to protect fresh water zones and
isolate the target hydrocarbon-bearing zone, and after the drilling rig and its associated
equipment have been removed. There will typically be at least three strings of cemented casing
in the well during fracturing operations. The outer string (i.e., surface casing) extends below
fresh ground water and would have been cemented to the surface before the well was drilled
deeper. The intermediate casing string, also called protective string, is installed between the
surface and production strings. The inner string (i.e., production casing) typically extends from
the ground surface to the toe of the horizontal well. Depending on the depth of the well and local
geologic conditions, there may be one or more intermediate casing strings. The inner production
casing is the only casing string that will experience the high pressures associated with the
fracturing treatment. 202 Anticipated Marcellus Shale fracturing pressures range from 5,000
pounds per square inch (psi) to 10,000 psi, so production casing with a greater internal yield
pressure than the anticipated fracturing pressure must be installed.
The last steps prior to fracturing are installation of a wellhead (referred to as a “frac tree”) that is
designed and pressure-rated specifically for the fracturing operation, and pressure testing of the
202

For more details on wellbore casing and cement: see Appendix 8 for current casing and cementing practices required for all
wells in New York, Appendix 9 for additional permit conditions for wells drilled within the mapped areas of primary and
principal aquifers, and Chapter 7 and Appendix 10 for proposed new permit conditions to address high-volume hydraulic
fracturing.

Final SGEIS 2015, Page 5-85

 hydraulic fracturing system. Photo 5.24 depicts a frac tree that is pressure-rated for 10,000 psi.
Before perforating the casing and pumping fracturing fluid into the well, the operator pumps
fresh water, brine or drilling mud to pressure test the production casing, frac tree and associated
lines. Test pumping is performed to at least the maximum anticipated treatment pressure, which
is maintained for a period of time while the operator monitors pressure gauges. The purpose of
this test is to verify, prior to pumping fracturing fluid, that the casing, frac tree and associated
lines will successfully hold pressure and contain the treatment. The test pressure may exceed the
maximum anticipated treatment pressure, but must remain below the working pressure of the
lowest rated component of the hydraulic fracturing system, including the production casing.
Flowback equipment, including pipes, manifolds, a gas-water separator and tanks are connected
to the frac tree and this portion of the flowback system is pressure tested prior to flowing the
well.

Photo 5.24- Three Fortuna Energy wells being prepared for hydraulic
fracturing, with 10,000 psi well head and goat head attached to lines. Troy
PA. Source: New York State Department of Environmental Conservation
2009

Final SGEIS 2015, Page 5-86

 The hydraulic fracturing process itself is conducted in stages by successively isolating,
perforating and fracturing portions of the horizontal wellbore starting with the far end, or toe.
Reasons for conducting the operation in stages are to maintain sufficient pressure to fracture the
entire length of the wellbore, 203 to achieve better control of fracture placement and to allow
changes from stage to stage to accommodate varying geological conditions along the wellbore if
necessary. 204 The length of wellbore treated in each stage will vary based on site-specific
geology and the characteristics of the well itself, but may typically be 300 to 500 feet. In that
case, the multi-stage fracturing operation for a 4,000-foot lateral would consist of eight to 13
fracturing stages. Each stage may require 300,000 to 600,000 gallons of water, so that the entire
multi-stage fracturing operation for a single well would require 2.4 million to 7.8 million gallons
of water. 205 More or less water may be used depending on local conditions, evolution in
fracturing technology, or other factors which influence the operator’s and service company’s
decisions.
The entire multi-stage fracturing operation for a single horizontal well typically takes two to five
days, but may take longer for longer lateral wellbores, for many-stage jobs or if unexpected
delays occur. Not all of this time is spent actually pumping fluid under pressure, as intervals are
required between stages for preparing the hole and equipment for the next stage. Pumping rate
may be as high as 1,260 to 3,000 gallons per minute (gpm). 206,207 At these rates, all the stages in
the largest volume fracturing job described in the previous paragraph would require between
approximately 40 and 100 hours of intermittent pumping during a 2- to 5-day period. Pumping
rates may vary from job-to-job and some operators have reported pump rates in excess of 3,000
gpm and hydraulic fracturing at these higher rates could shorten the overall time spent pumping.

203

GWPC, April 2009, p. 58.

204

GWPC, April 2009, p. 58.

205

Applications on file with the Department propose volumes on the lower end of this range. The higher end of the range is
based on GWPC (April 2009), pp. 58-59, where an example of a single-stage Marcellus fracturing treatment using 578,000
gallons of fluid is presented. Stage lengths used in the above calculation (300 – 500 feet) were provided by Fortuna Energy
and Chesapeake Energy in presentations to Department staff during field tours of operations in the northern tier of
Pennsylvania.

206

ICF Task 1, 2009, p. 3.

207

GWPC, April 2009, p. 59.

Final SGEIS 2015, Page 5-87

 The time spent pumping is the only time, except for when the well is shut-in, that wellbore
pressure exceeds pressure in the surrounding formation. Therefore, the hours spent pumping are
the only time that fluid in fractures and in the rocks surrounding the fractures would move away
from the wellbore instead of towards it. ICF International, under contract to NYSERDA,
estimated the maximum rate of seepage in strata lying above the target Marcellus zone, assuming
hypothetically that the entire bedrock column between the Marcellus and a fresh groundwater
aquifer is hydraulically connected. Under most conditions evaluated by ICF, the seepage rate
would be substantially less than 10 feet per day, or 5 inches per hour of pumping time. 208 More
information about ICF’s analysis is in Chapter 6 and in Appendix 11.
Within each fracturing stage is a series of sub-stages, or steps. 209, 210 The first step is typically an
acid treatment, which may also involve corrosion inhibitors and iron controls. Acid cleans the
near-wellbore area accessed through the perforated casing and cement, while the other additives
that may be used in this phase reduce rust formation and prevent precipitation of metal oxides
that could plug the shale. The acid treatment is followed by the “slickwater pad,” comprised
primarily of water and a friction-reducing agent which helps optimize the pumping rate.
Fractures form during this stage when the fluid pressure exceeds the minimum normal stress in
the rock mass plus whatever minimal tensile stress exists. 211 The fractures are filled with fluid,
and as the fracture width grows, more fluid must be pumped at the same or greater pressure
exerted to maintain and propagate the fractures. 212 As proppant is added, other additives such as
a gelling agent and crosslinker may be used to increase viscosity and improve the fluid’s
capacity to carry proppant. Fine-grained proppant is added first, and carried deepest into the
newly induced fractures, followed by coarser-grained proppant. Breakers may be used to reduce
the fluid viscosity and help release the proppant into the fractures. Biocides may also be added
to inhibit the growth of bacteria that could interfere with the process and produce hydrogen
sulfide. Clay stabilizers may be used to prevent swelling and migration of formation clays. The
final step in the hydraulic fracturing process is a freshwater or brine flush to clean out the
208

ICF Task 1, 2009, pp. 27-28.

209

URS, 2009, pp. 2-12.

210

GWPC, April 2009, pp. 58-60.

211

ICF Task 1, 2009. p. 16.

212

ICF Task 1, 2009. p. 16.

Final SGEIS 2015, Page 5-88

 wellbore and equipment. After hydraulic fracturing is complete, the stage plugs are removed
through a milling process routinely accomplished by a relatively small workover rig, snubbing
unit and/or coiled tubing unit. A snubbing unit or coiled tubing unit may be required if the well
is not dead or if pressure is anticipated after milling through the plugs. Stage plugs may be
removed before or after initial flowback depending upon the type of plug used.
Photo 5.25 and Photo 5.26 depict the same wellsite during and after hydraulic fracturing
operations, with Photo 5.25 labeled to identify the equipment that is present onsite. Photo 5.27 is
a labeled close-up of a wellhead and equipment at the site during hydraulic fracturing operations.
5.10

Re-fracturing

Developers may decide to re-fracture a well to extend its economic life whenever the production
rate declines significantly below past production rates or below the estimated reservoir
potential. 213 According to ICF International, fractured Barnett Shale wells generally would
benefit from re-fracturing within five years of completion, but the time between fracture
stimulations can be less than one year or greater than ten years. 214 However, Marcellus operators
with whom the Department has discussed this question have stated their expectation that refracturing will be a rare event.
It is too early in the development of shale reservoirs in New York to predict the frequency with
which re-fracturing of horizontal wells, using the slickwater method, may occur. ICF provided
some general information on the topic of re-fracturing.
Wells may be re-fractured multiple times, may be fractured along sections of the wellbore that
were not previously fractured, and may be subject to variations from the original fracturing
technique. 215 The Department notes that while one stated reason to re-fracture may be to treat
sections of the wellbore that were not previously fractured, this scenario does not seem applicable
to Marcellus Shale development. Current practice in the Marcellus Shale in the northern tier of
Pennsylvania is to treat the entire lateral wellbore, in stages, during the initial procedure.

213

ICF Task 1, 2009, p. 18.

214

ICF Task 1, 2009, p. 18.

215

ICF Task 1, 2009, p. 17.

Final SGEIS 2015, Page 5-89

  

Final SGEIS 2015, Page 5-90

Photo 5.25 (Above) Hydraulic Fracturing Operation
These photos show a hydraulic fracturing operation at a Fortuna Energy multiwell site in Troy PA. At the time the photos were taken, preparations for fracturing were underway but fracturing had not yet occurred for any of the wells.
11.  Frac additive trucks
12.  Blender
13.  Frac control and monitoring center
1.  Well head and frac tree with ‘Goat 14.  Fresh water impoundment
Head’ (See Figure 5.27 for more
15.  Fresh water supply pipeline
detail)
16. Extra tanks
2.  Flow line (for flowback & testing)
3.  Sand separator for flowback
Production equipment
4.  Flowback tanks
5.  Line heaters
17.  Line heaters
6. F
  lare stack
18. S
  eparator-meter skid
7.  Pump trucks
19. P
  roduction manifold
8.  Sand hogs
9.  Sand trucks
10.  Acid trucks
Hydraulic Fracturing Operation
Equipment

C

E

F

D
B

Photo 5.26 Fortuna multiwell pad after hydraulic
fracturing of three wells
and removal of most
hydraulic fracturing
equipment. Production
equipment for wells on
right side of photo.
Source: Fortuna Energy,
July, 2009.

Final SGEIS 2015, Page 5-91

A

G

H

Photo 5.27. Wellhead and Frac Equipment
A. Well head and frac tree (valves)
B. Goat Head (for frac flow connections)
C. Wireline (used to convey equipment into wellbore)
D. Wireline Blow Out Preventer
E. Wireline lubricator
F. Crane to support wireline equipment
G. Additional wells
H. Flow line (for flowback & testing)

 Several other reasons may develop to repeat the fracturing procedure at a given well. Fracture
conductivity may decline due to proppant embedment into the fracture walls, proppant crushing,
closure of fractures under increased effective stress as the pore pressure declines, clogging from
fines migration, and capillary entrapment of liquid at the fracture and formation boundary. 216
Re-fracturing can restore the original fracture height and length, and can often extend the
fracture length beyond the original fracture dimensions. 217 Changes in formation stresses due to
the reduction in pressure from production can sometimes cause new fractures to propagate at a
different orientation than the original fractures, further extending the fracture zone. 218
Factors that influence the decision to re-fracture include past well production rates, experience
with other wells in the same formation, the costs of re-fracturing, and the current price for gas. 219
Factors in addition to the costs of re-fracturing and the market price for gas that determine costeffectiveness include the characteristics of the geologic formation and the time value of
money. 220
Regardless of how often it occurs, if the high-volume hydraulic fracturing procedure is repeated
it will entail the same type and duration of surface activity at the well pad as the initial
procedure. The rate of subsurface fluid movement during pumping operations would be the
same as discussed above. It is important to note, however, that between fracturing operations,
while the well is producing, flow direction is towards the fracture zone and the wellbore.
Therefore, total fluid movement away from the wellbore as a result of repeated fracture
treatments would be less than the sum of the distance moved during each fracture treatment.
5.11

Fluid Return

After the hydraulic fracturing procedure is completed and pressure is released, the direction of
fluid flow reverses. The well is "cleaned up" by allowing water and excess proppant to flow up

216

ICF Task 1, 2009, p. 17.

217

ICF Task 1, 2009, p. 17.

218

ICF Task 1, 2009, pp. 17-18.

219

ICF Task 1, 2009, p. 18.

220

ICF Task 1, 2009, p. 18.

Final SGEIS 2015, Page 5-92

 through the wellbore to the surface. Both the process and the returned water are commonly
referred to as “flowback.”
5.11.1 Flowback Water Recovery
Flowback water recoveries reported from horizontal Marcellus wells in the northern tier of
Pennsylvania range between 9 and 35 percent of the fracturing fluid pumped. Flowback water
volume, then, could be 216,000 gallons to 2.7 million gallons per well, based on a pumped fluid
estimate of 2.4 million to 7.8 million gallons, as presented in Section 5.9. This volume is
generally recovered within two to eight weeks, then the well’s water production rate sharply
declines and levels off at a few barrels per day for the remainder of its producing life. URS
Corporation reported that limited time-series data indicates that approximately 60 percent of the
total flowback occurs in the first four days after fracturing. 221
5.11.2 Flowback Water Handling at the Wellsite
As discussed throughout this document, the Department will require water-tight tanks for on-site
(i.e., well pad) handling of flowback water for wells covered by the SGEIS.
5.11.3 Flowback Water Characteristics
The 1992 GEIS identified high TDS, chlorides, surfactants, gelling agents and metals as the
components of greatest concern in spent gel and foam fracturing fluids (i.e., flowback).
Slickwater fracturing fluids proposed for Marcellus well stimulation may contain other additives
such as corrosion inhibitors, friction reducers and microbiocides, in addition to the contaminants
of concern identified in the GEIS. Most fracturing fluid additives used in a well can be expected
in the flowback water, although some are expected to be consumed in the well (e.g., strong acids)
or react during the fracturing process to form different products (e.g., polymer precursors).
The following description of flowback water characteristics was provided by URS
Corporation, 222 under contract to NYSERDA. This discussion is based on a limited number of
analyses from out-of-state operations, without corresponding complete compositional
information on the fracturing additives that were used at the source wells. The Department did
221

URS, 2009, p. 3-2.

222

URS, 2009, p. 3-2 & 2011, p. 3-2.

Final SGEIS 2015, Page 5-93

 not direct or oversee sample collection or analysis efforts. Most fracturing fluid components are
not included as analytes in standard chemical scans of flowback samples that were provided to
the Department, so little information is available to document whether and at what
concentrations most fracturing chemicals occur in flowback water. Because of the limited
availability at this time of flowback water quality data, conservative and strict mitigation
measures regarding flowback water handling are proposed in Chapter 7, and additional data will
be required for alternative proposals.
Flowback fluids include the fracturing fluids pumped into the well, which consists of water and
additives discussed in Section 5.4; any new compounds that may have formed due to reactions
between additives; and substances mobilized from within the shale formation due to the
fracturing operation. Some portion of the proppant may return to the surface with flowback, but
operators strive to minimize proppant return: the ultimate goal of hydraulic fracturing is to
convey and deposit the proppant within fractures in the shale to maximize gas flow.
Marcellus Shale is of marine origin and, therefore, contains high levels of salt. This is further
evidenced by analytical results of flowback provided to the Department by well operators and
service companies from operations based in Pennsylvania. The results vary in level of detail.
Some companies provided analytical results for one day for several wells, while other companies
provided several analytical results for different days of the same well (i.e. time-series).
Typical classes of parameters present in flowback fluid are:
•

Dissolved solids (chlorides, sulfates, and calcium);

•

Metals (calcium, magnesium, barium, strontium);

•

Suspended solids;

•

Mineral scales (calcium carbonate and barium sulfate);

•

Bacteria - acid producing bacteria and sulfate reducing bacteria;

•

Friction reducers;

•

Iron solids (iron oxide and iron sulfide);

Final SGEIS 2015, Page 5-94

 •

Dispersed clay fines, colloids & silts; and

•

Acid gases (carbon dioxide, hydrogen sulfide).

A list of parameters detected in a limited set of analytical results is provided in Table 5.9.
Typical concentrations of parameters other than radionuclides, based on limited data from
Pennsylvania and West Virginia, are provided in Table 5.10 and Table 5.11. Flowback
parameters were organized by CAS number, whenever available. Radionuclides are separately
discussed and tabulated in Section 5.11.3.2.
Table 5.9 - Parameters present in a limited set of flowback analytical results 223 (Updated July 2011)

CAS Number
00087-61-6
00095-63-6
00108-67-8
00105-67-9
00087-65-0
00078-93-3
00091-57-6
00095-48-7
109-06-8
00067-63-0
00108-39-4
00106-44-5
00072-55-9
00057-97-6
00064-19-7
00067-64-1
00098-86-2
00107-13-1
00309-00-2
07439-90-5
07440-36-0
07664-41-7
12672-29-6
07440-38-2
07440-39-3
00071-43-2

223

Parameters Detected in Flowback from PA and WV Operations
1,2,3-Trichlorobenzene
1,2,4-Trimethylbenzene
1,3,5-Trimethylbenzene
2,4-Dimethylphenol
2,6-Dichlorophenol
2-Butanone / Methyl ethyl ketone
2-Methylnaphthalene
2-Methylphenol
2-Picoline (2-methyl pyridine)
2-Propanol / Isopropyl Alcohol / Isopropanol / Propan-2-ol
3-Methylphenol
4-Methylphenol
4,4 DDE
7,12-Dimethylbenz(a)anthracene
Acetic acid
Acetone
Acetophenone
Acrylonitrile
Aldrin
Aluminum
Antimony
Aqueous ammonia
Aroclor 1248
Arsenic
Barium
Benzene

This table contains information compiled from flowback analyses submitted to the Department by well operators as well as
flowback information from the Marcellus Shale Coalition Study.

Final SGEIS 2015, Page 5-95

 CAS Number
00050-32-8
00205-99-2
191-24-2
00207-08-9
00100-51-6
07440-41-7
00111-44-4
00117-81-7
07440-42-8
24959-67-9
00075-25-2
07440-43-9
07440-70-2
00124-38-9
00075-15-0
00124-48-1
00067-66-3
07440-47-3
07440-48-4
07440-50-8
00057-12-5
00319-85-7
00058-89-9
00055-70-3
00075-27-4
00084-74-2
00122-39-4
00959-98-8
33213-65-9
07421-93-4
00107-21-1
00100-41-4
00206-44-0
00086-73-7
16984-48-8
00076-44-8
01024-57-3
00193-39-5
07439-89-6
00098-82-8
07439-92-1
07439-93-2
07439-95-4

Parameters Detected in Flowback from PA and WV Operations
Benzo(a)pyrene
Benzo(b)fluoranthene
Benzo(ghi)perylene
Benzo(k)fluoranthene
Benzyl alcohol
Beryllium
Bis(2-Chloroethyl) ether
Bis(2-ethylhexyl)phthalate / Di (2-ethylhexyl) phthalate
Boron
Bromide
Bromoform
Cadmium
Calcium
Carbon Dioxide
Carbondisulfide
Chlorodibromomethane
Chloroform
Chromium
Cobalt
Copper
Cyanide
Cyclohexane (beta BHC)
Cyclohexane (gamma BHC)
Dibenz(a,h)anthracene
Dichlorobromomethane
Di-n-butyl phthalate
Diphenylamine
Endosulfan I
Endosulfan II
Endrin aldehyde
Ethane-1,2-diol / Ethylene Glycol
Ethyl Benzene
Fluoranthene
Fluorene
Fluoride
Heptachlor
Heptachlor epoxide
Indeno(1,2,3-cd)pyrene
Iron
Isopropylbenzene (cumene)
Lead
Lithium
Magnesium

Final SGEIS 2015, Page 5-96

 CAS Number
07439-96-5
07439-97-6
00067-56-1
00074-83-9
00074-87-3
07439-98-7
00091-20-3
07440-02-0
00086-30-6
00085-01-8
00108-95-2
57723-14-0
07440-09-7
00057-55-6
00110-86-1
00094-59-7
07782-49-2
07440-22-4
07440-23-5
07440-24-6
14808-79-8
14265-45-3
00127-18-4
07440-28-0
07440-32-6
00108-88-3
07440-62-2
07440-66-6

Parameters Detected in Flowback from PA and WV Operations
Manganese
Mercury
Methanol
Methyl Bromide
Methyl Chloride
Molybdenum
Naphthalene
Nickel
N-Nitrosodiphenylamine
Phenanthrene
Phenol
Phosphorus
Potassium
Propylene glycol
Pyridine
Safrole
Selenium
Silver
Sodium
Strontium
Sulfate
Sulfite
Tetrachloroethylene
Thallium
Titanium
Toluene
Vanadium
Zinc
2-Picoline
Alkalinity
Alkalinity, Carbonate, as CaCO3
Alpha radiation
Aluminum, Dissolved
Barium Strontium P.S.
Barium, Dissolved
Beta radiation
Bicarbonates
Biochemical Oxygen Demand
Cadmium, Dissolved
Calcium, Dissolved
Cesium 137
Chemical Oxygen Demand
Chloride

Final SGEIS 2015, Page 5-97

 CAS Number

Parameters Detected in Flowback from PA and WV Operations
Chromium (VI)
Chromium (VI), dissolved
Chromium, (III)
Chromium, Dissolved
Cobalt, dissolved
Coliform
Color
Conductivity
Hardness
Heterotrophic plate count
Iron, Dissolved
Lithium, Dissolved
Magnesium, Dissolved
Manganese, Dissolved
Nickel, Dissolved
Nitrate, as N
Nitrogen, Total as N
Oil and Grease
Petroleum hydrocarbons
pH
Phenols
Potassium, Dissolved
Radium
Radium 226
Radium 228
Salt
Scale Inhibitor
Selenium, Dissolved
Silver, Dissolved
Sodium, Dissolved
Strontium, Dissolved
Sulfide
Surfactants
Total Alkalinity
Total Dissolved Solids
Total Kjeldahl Nitrogen
Total Organic Carbon
Total Suspended Solids
Volatile Acids
Xylenes
Zinc, Dissolved
Zirconium

Final SGEIS 2015, Page 5-98

 Parameters listed in Table 5.9, Table 5.10 and Table 5.11 are based on analytical results of
flowback from operations in Pennsylvania or West Virginia. All information is for operations in
the Marcellus Shale, however it is not from a single comprehensive study. The data are based on
analyses performed by different laboratories; most operators provided only one sample/analysis
per well, a few operators provided time-series samples for a single well; the different samples
were analyzed for various parameters with some overlap of parameters. Even though the data
are not strictly comparable, they provide valuable insight on the likely composition of flowback
at New York operations.
Table 5.10 - Typical concentrations of flowback constituents based on limited samples
from PA and WV, and regulated in NY 224,225 (Revised July 2011)

CAS #
00067-64-1

07439-90-5
07440-36-0
07664-41-7
07440-38-2
07440-39-3
00071-43-2
07440-41-7

Parameter Name
Acetone
Acidity, Total
Alkalinity 226
Alkalinity, Carbonate, as
CaCO3
Total Alkalinity
Aluminum
Aluminum, Dissolved
Antimony
Aqueous ammonia
Arsenic
Barium
Barium, Dissolved
Benzene
Beryllium

Total
Number of
Number of
Detects
Samples
3
1
4
4
155
155
164
5
43
22
34
48
43
48
22
35
43

163
5
12
1
1
45
7
47
22
14
1

Min

Median

Max

Units

681
101
0

681
240
153

681
874
384

µg/L
mg/L
mg/L

0
28
0.02
1.37
0.26
11.3
0.015
0.553
0.313
15.7
422

9485
91
0.07
1.37
0.26
44.8
0.09
1450
212
479.5
422

48336
94
1.2
1.37
0.26
382
0.123
15700
19200
1950
422

mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
µg/L
mg/L

224

Table 5.9 was provided by URS Corporation (based on data submitted to the Department) with the following note:
Information presented is based on limited data from Pennsylvania and West Virginia. Characteristics of flowback from the
Marcellus Shale in New York are expected to be similar to flowback from Pennsylvania and West Virginia, but not identical.
In addition, the raw data for these tables came from several sources, with likely varying degrees of reliability. Also, the
analytical methods used were not all the same for given parameters. Sometimes laboratories need to use different analytical
methods depending on the consistency and quality of the sample; sometimes the laboratories are only required to provide a
certain level of accuracy. Therefore, the method detection limits may be different. The quality and composition of flowback
from a single well can also change within a few days soon after the well is fractured. This data does not control for any of
these variables. Additionally, it should be noted that several of these compounds could be traced back to potential laboratory
contamination. Further comparisons of analytical results with those results from associated laboratory method blanks may be
required to further assess the extent of actual concentrations found in field samples versus elevated concentrations found in
field samples due to blank contamination.

225

This table does not include results from the Marcellus Shale Coalition Study.

226

Different data sources reported alkalinity in different and valid forms. Total alkalinity reported here is smaller than carbonate
alkalinity because the data came from different sources.

Final SGEIS 2015, Page 5-99

 CAS #

00117-81-7
07440-42-8
24959-67-9
00075-25-2
07440-43-9
07440-70-2

Bicarbonates
Biochemical Oxygen Demand
Bis(2-ethylhexyl)phthalate
Boron
Bromide
Bromoform
Cadmium
Cadmium, Dissolved
Calcium
Calcium, Dissolved
227

00124-48-1
07440-47-3

07440-48-4

07440-50-8
00057-12-5
00075-27-4
00100-41-4
16984-48-8
07439-89-6
07439-92-1

07439-95-4

07439-96-5
07439-97-6
00074-83-9
00074-87-3
07439-98-7
00091-20-3
07440-02-0

00108-95-2

227

Total
Number of
Number of
Detects
Samples

Parameter Name

Cesium 137
Chemical Oxygen Demand
Chloride
Chlorodibromomethane
Chromium
Chromium (VI), dissolved
Chromium, Dissolved
Cobalt
Cobalt, dissolved
Coliform, Total
Color
Copper
Cyanide
Dichlorobromomethane
Ethyl Benzene
Fluoride
Heterotrophic plate count
Iron
Iron, Dissolved
Lead
Lithium
Lithium, Dissolved
Magnesium
Magnesium, Dissolved
Mg as CaCO3
Manganese
Manganese, Dissolved
Mercury
Methyl Bromide
Methyl Chloride
Molybdenum
Naphthalene
Nickel
Nickel, Dissolved
Nitrate, as N
Nitrogen, Total as N
Oil and Grease
Petroleum hydrocarbons
pH
Phenol

Min

Median

Max

Units
mg/L
mg/L
µg/L
mg/L
mg/L
µg/L
mg/L

150
38
20
23
15
26
43
22
187
3

150
37
2
9
15
2
6
2
186
3

0
3
10.3
0.539
11.3
34.8
0.007
0.017
29.9
2360

183
200
15.9
2.06
607
36.65
0.025
0.026
4241
22300

1708
4450
21.5
26.8
3070
38.5
1.2
0.035
123000
31500

16
38
193
26
43
19
22
30
19
5
3
43
7
29
38
4
5
193
34
43
13
4
193
3
145
43
22
30
26
26
34
23
43
22
1
1
39
1
191
20

2
38
193
2
9
10
2
6
1
2
3
8
2
1
14
2
3
168
26
6
13
4
180
3
145
29
12
2
1
1
12
1
15
2
1
1
9
1
191
1

9.9
223
287
3.28
0.009
0.0126
0.058
0.03
0.489
1
200
0.01
0.006
2.24
3.3
5.23
25
0
6.75
0.008
34.4
24.5
9
218
36
0.15
0.401
0.0006
2.04
15.6
0.16
11.3
0.01
0.03
0.025
13.4
5
0.21
0
459

10.2
5645
56900
3.67
0.082
0.539
0.075
0.3975
0.489
42
1000
0.0245
0.0125
2.24
53.6
392.615
50
29.2
63.25
0.035
90.4
61.35
177
2170
547
1.89
2.975
0.295
2.04
15.6
0.44
11.3
0.03
0.0715
0.025
13.4
17
0.21
6.6
459

10.5
33300
228000
4.06
760
7.81
0.092
0.62
0.489
83
1250
0.157
0.019
2.24
164
780
565
810
196
27.4
297
144
3190
3160
8208
97.6
18
0.59
2.04
15.6
1.08
11.3
0.137
0.113
0.025
13.4
1470
0.21
8.58
459

Regulated under beta particles [19].

Final SGEIS 2015, Page 5-100

mg/L

mg/L
mg/L
pCi/L
mg/L
mg/L
µg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Col/100mL
PCU
mg/L
mg/L
µg/L
µg/L
mg/L
CFU/mL
mg/L
mg/L

mg/L
mg/L
mg/L

mg/L
mg/L
mg/L

mg/L
mg/L

mg/L
µg/L
µg/L
mg/L
µg/L
mg/L
mg/L

mg/L
mg/L
mg/L
mg/L
S.U.
µg/L

 CAS #

57723-14-0
07440-09-7

07782-49-2
07440-22-4
07440-23-5
07440-24-6
14808-79-8
14265-45-3

Parameter Name
Phenols
Phosphorus, as P
Potassium
Potassium, Dissolved
Scale Inhibitor
Selenium
Selenium, Dissolved
Silver
Silver, Dissolved
Sodium
Sodium, Dissolved
Strontium
Strontium, Dissolved
Sulfate (as SO4)
Sulfide (as S)
Sulfite (as SO3)
228

00127-18-4
07440-28-0
07440-32-6
00108-88-3
07440-62-2

Surfactants
Tetrachloroethylene
Thallium
Titanium
Toluene
Total Dissolved Solids
Vanadium
Total Kjeldahl Nitrogen
229

07440-66-6

228
229

Total Organic Carbon
Total Suspended Solids
Xylenes
Zinc
Zinc, Dissolved
Fluid Density
Hardness by Calculation
Salt %
Specific Conductivity
Specific Gravity
Temperature
Temperature

Total
Number of
Number of
Detects
Samples

Min

Median

Max

Units

35
3
33
3
145
34
22
43
22
42
3
36
22
193
8
3

5
3
17
3
145
1
1
3
2
41
3
36
21
169
1
3

0.05
0.89
15.5
84.2
315
0.058
1.06
0.129
0.056
83.1
9290
0.501
8.47
0
29.5
2.56

0.191
1.85
125
327
744
0.058
1.06
0.204
0.0825
23500
54800
1115
629
1
29.5
64

0.44
4.46
7810
7080
1346
0.058
1.06
6.3
0.109
96700
77400
5841
7290
1270
29.5
64

mg/L
mg/L
mg/L

12
26
34
25
38
193
24
25

12
1
2
1
15
193
1
25

0.1
5.01
0.1
0.06
2.3
1530
40.4
37.5

0.21
5.01
0.18
0.06
833
63800
40.4
122

0.61
5.01
0.26
0.06
3190
337000
40.4
585

mg/L
µg/L
mg/L
mg/L
µg/L
mg/L
mg/L
mg/L

28
43
38
43
22
145
170
145
15
150
31
145

23
43
15
18
1
145
170
145
15
154
31
145

69.2
16
15.3
0.011
0.07
8.39004
203
0.9
1030
0
0
24.9

449
129
444
0.036
0.07
8.7
11354
5.8
110000
1.04
15.3
68

1080
2080
2670
8570
0.07
9.2
98000
13.9
165000
1.201
32
76.1

mg/L
mg/L
µg/L
mg/L
mg/L
lb/gal
mg CaCO3/L
%
pmhos/cm

Regulated under foaming agents.
Regulated via BOD, COD and the different classes/compounds of organic carbon.

Final SGEIS 2015, Page 5-101

mg/L

mg/L
mg/L
mg/L

mg/L
mg/L

mg/L
mg/L

mg/L
mg/L

mg/L
mg/L
mg/L

°C
°F

 Table 5.11 - Typical concentrations of flowback constituents based on limited samples
from PA and WV, not regulated in NY 230(Revised July 2011)

Parameter Name
Barium Strontium P.S.
Carbon Dioxide
Zirconium

Total
Number of
Samples
145
5
19

Detects
145
5
1

Min
17
193
0.054

Median
1320
232
0.054

Max
6400
294
0.054

Units
mg/L
mg/L
mg/L

Recognizing the dearth of comparable flowback information that existed at that time within the
Marcellus Shale, the Marcellus Shale Coalition (MSC) facilitated a more rigorous study in 2009.
The study:
•

Gathered and analyzed flowback samples from 19 gas well sites (names A through S) in
Pennsylvania or West Virginia;

•

Took samples at different points in time, typically of the influent water stream, and
flowback water streams 1, 5, 14, and 90 days after stimulating the well. In addition, the
water supply and the fracturing fluid (referred to as Day 0) were also sampled at a few
locations;

•

Included both vertical and horizontal wells;

•

All samples were collected by a single contractor;

•

All analyses were performed by a single laboratory;

•

Sought input from regulatory agencies in Pennsylvania and West Virginia; and

•

Most samples were analyzed for conventional parameters, Metals, VOCs, Semi-Volatile
Organic Compounds (SVOCs), Organochlorine Pesticides, Polychlorinated Biphenyls
(PCBs), an Organophosphorus Pesticide, Alcohols, Glycols, and Acids. The specific
parameters analyzed in the MSC report are listed by class as follows:
o 29 conventional parameters (presented in Table 5.12);

230

Table 5-10.

Final SGEIS 2015, Page 5-102

 o 59 total or dissolved metals (presented in Table 5.13);
o 70 VOCs (presented in Table 5.14);
o 107 SVOCs ( presented in Table 5.15);
o 20 Organochlorine Pesticides (presented in Table 5.16);
o 7 PCB Arochlors (presented in Table 5.17);
o 1 Organophosphorus Pesticide (presented in Table 5.18);
o 5 Alcohols (presented in Table 5.19);
o 2 Glycols (presented in Table 5.20); and
o 4 Acids (presented in Table 5.21).

Table 5.12 - Conventional Analytes In MSC Study (New July 2011)

Acidity
Amenable cyanide
Ammonia nitrogen
Biochemical oxygen demand
Bromide
Chemical oxygen demand
(COD)
Chloride
Dissolved organic carbon
Fluoride
Hardness, as CaCO3

Nitrate as N
Nitrate-nitrite
Nitrite as N
Oil & grease (HEM)
Specific conductance
Sulfate

Total phosphorus
Total suspended solids
Turbidity
Total cyanide
Total sulfide
pH

TOC
Total alkalinity
Total dissolved solids
Total Kjeldahl nitrogen

Total recoverable phenolics
Sulfite
MBAS (mol.wt 320)

Final SGEIS 2015, Page 5-103

 Table 5.13 - Total and Dissolved Metals Analyzed In MSC Study (New July 2011)

Aluminum-dissolved
Antimony
Antimony-dissolved
Arsenic
Arsenic-dissolved
Barium
Barium-dissolved
Beryllium
Beryllium-dissolved
Boron
Boron-dissolved
Cadmium
Cadmium-dissolved
Calcium
Calcium-dissolved

Copper
Copper-dissolved
Iron
Iron-dissolved
Lead
Lead-dissolved
Lithium
Lithium-dissolved
Magnesium
Magnesium-dissolved
Manganese
Manganese-dissolved
Molybdenum
Molybdenum-dissolved
Nickel
Nickel-dissolved

Chromium
Chromium-dissolved
Cobalt
Cobalt-dissolved

Potassium
Potassium-dissolved
Selenium
Selenium-dissolved

Final SGEIS 2015, Page 5-104

Silver
Silver-dissolved
Sodium
Sodium-dissolved
Strontium
Strontium-dissolved
Thallium
Thallium-dissolved
Tin
Tin-dissolved
Titanium
Titanium-dissolved
Trivalent chromium
Zinc
Zinc-dissolved
Hexavalent chromiumdissolved
Hexavalent chromium
Mercury
Mercury-dissolved

 Table 5.14 - Volatile Organic Compounds Analyzed in MSC Study (New July 2011)

1,1,1-Trichloroethane
1,1,2,2-Tetrachloroethane
1,1,2-Trichloroethane
1,1-Dichloroethane
1,1-Dichloroethene
1,1-Dichloropropene
1,2,3-Trichlorobenzene
1,2,3-Trichloropropane
1,2,4-Trichlorobenzene
1,2,4-Trimethylbenzene
1,2-Dibromo-3-chloropropane
1,2-Dibromoethane (EDB)
1,2-Dichlorobenzene
1,2-Dichloroethane
1,2-Dichloropropane
1,3,5-Trimethylbenzene
1,3-Dichlorobenzene
1,3-Dichloropropane
1,4-Dichlorobenzene
1,4-Dioxane
1-chloro-4trifluoromethylbenzene
2,2-Dichloropropane
2-Butanone

2-Chloroethyl vinyl ether
2-Hexanone
4-Chlorotoluene
4-Methyl-2-pentanone (MIBK)
Acetone
Acrolein
Acrylonitrile
Benzene
Benzyl chloride
Bromobenzene
Bromodichloromethane
Bromoform
Bromomethane
Carbon disulfide
Carbon tetrachloride
Chlorobenzene
Chloroethane
Chloroform
Chloromethane
cis-1,2-Dichloroethene
cis-1,3-Dichloropropene
Dibromochloromethane
Dibromomethane
Dichlorodifluoromethane

Final SGEIS 2015, Page 5-105

Ethylbenzene
Isopropylbenzene
Methyl tert-butyl ether
(MTBE)
Methylene chloride
Naphthalene
n-Butylbenzene
n-Propylbenzene
p-Isopropyltoluene
sec-Butylbenzene
Styrene
tert-butyl acetate
tert-Butylbenzene
Tetrachloroethene
tetrahydrofuran
Toluene
trans-1,2-Dichloroethene
trans-1,3-Dichloropropene
Trichloroethene
Trichlorofluoromethane
Vinyl acetate
Vinyl chloride
Xylenes (total)

 Table 5.15 - Semi-Volatile Organics Analyzed in MSC Study (New July 2011)

1,2,4,5-Tetrachlorobenzene
1,2-Diphenylhydrazine
1,3-Dinitrobenzene
1,4-Naphthoquinone
1-Naphthylamine
2,3,4,6-Tetrachlorophenol
2,3,7,8-TCDD
2,4,5-Trichlorophenol
2,4,6-Trichlorophenol
2,4-Dimethylphenol
2,4-Dinitrophenol
2,4-Dinitrotoluene
2,6-Dichlorophenol
2,6-Dinitrotoluene
2-Acetylaminofluorene
2-Chloronaphthalene
2-Chlorophenol
2-Methylnaphthalene
2-Methylphenol

7,12-Dimethylbenz(a)anthracene
Acenaphthene
Acenaphthylene
Acetophenone
Aniline
Aramite
Benzidine
Benzo(a)anthracene
Benzo(a)pyrene
Benzo(b)fluoranthene
Benzo(ghi)perylene
Benzo(k)fluoranthene
Benzyl alcohol
bis(2-Chloroethoxy)methane
bis(2-Chloroethyl) ether
bis(2-Chloroisopropyl) ether
bis(2-Ethylhexyl) phthalate
Butyl benzyl phthalate
Chlorobenzilate

2-Naphthylamine
2-Nitroaniline
2-Nitrophenol
2-Picoline
3,3'-Dichlorobenzidine
3-Methylcholanthrene
3-Methylphenol & 4Methylphenol
3-Nitroaniline
4,6-Dinitro-2-methylphenol
4-Aminobiphenyl
4-Bromophenyl phenyl ether
4-Chloro-3-methylphenol
4-Chloroaniline
4-Chlorophenyl phenyl ether
4-Nitroaniline
4-Nitrophenol
5-Nitro-o-toluidine

Chrysene
Diallate
Dibenz(a,h)anthracene
Dibenzofuran
Diethyl phthalate
Dimethoate
Dimethyl phthalate
Di-n-butyl phthalate
Di-n-octyl phthalate
Dinoseb
Diphenylamine
Disulfoton
Ethyl methanesulfonate
Fluoranthene
Fluorene
Hexachlorobenzene
Hexachlorobutadiene

Final SGEIS 2015, Page 5-106

Hexachlorocyclopentadiene
Hexachloroethane
Hexachloropropene
Indeno(1,2,3-cd)pyrene
Isodrin
Isophorone
Isosafrole
Methyl methanesulfonate
Nitrobenzene
N-Nitrosodiethylamine
N-Nitrosodimethylamine
N-Nitrosodi-n-butylamine
N-Nitrosodi-n-propylamine
N-Nitrosodiphenylamine
N-Nitrosomethylethylamine
N-Nitrosomorpholine
N-Nitrosopiperidine
N-Nitrosopyrrolidine
O,O,O-Triethyl
phosphorothioate
o-Toluidine
Parathion
p-Dimethylaminoazobenzene
Pentachlorobenzene
Pentachloroethane
Pentachloronitrobenzene
Pentachlorophenol
Phenanthrene
Phenol
Phorate
Pronamide
Pyrene
Pyridine
Safrole
Thionazin
Tetraethyldithiopyrophosphate

 Table 5.16 - Organochlorine Pesticides Analyzed in MSC Study (New July 2011)

4,4'-DDD
4,4'-DDE
4,4'-DDT
Aldrin
alpha-BHC
beta-BHC
Chlordane

delta-BHC
Dieldrin
Endosulfan I
Endosulfan II
Endosulfan sulfate
Endrin
Endrin aldehyde

Endrin ketone
gamma-BHC (Lindane)
Heptachlor
Heptachlor epoxide
Methoxychlor
Toxaphene

Table 5.17 - PCBs Analyzed in MSC Study (New July 2011)

Aroclor 1016
Aroclor 1221
Aroclor 1232

Aroclor 1242
Aroclor 1248
Aroclor 1254

Aroclor 1260

Table 5.18 - Organophosphorus Pesticides Analyzed in MSC Study (New July 2011)

Ethyl parathion

Table 5.19 - Alcohols Analyzed in MSC Study (New July 2011)

2-Propanol
Butyl alcohol

Ethanol
Methanol

n-Propanol

Table 5.20 - Glycols Analyzed in MSC Study (New July 2011)

Ethylene glycol
Propylene glycol

Table 5.21 - Acids Analyzed in MSC Study (New July 2011)

Acetic acid
Butyric acid

Propionic acid
Volatile acids

Final SGEIS 2015, Page 5-107

 Table 5.22 is a summary of parameter classes analyzed for (shown with a “•”) at each well site.
Table 5.23 is a summary of parameters detected at quantifiable levels. The check mark (√)
indicates that several samples detected many parameters within a class. The MSC Study Report
lists the following qualifiers associated with analytical results:
The sample was diluted (from 1X, which means no dilution, to up to 1000X) due to
concentrations of analytes exceeding calibration ranges of the instrumentation or due to potential
matrix effect. Laboratories use best judgment when analyzing samples at the lowest dilution
factors allowable without causing potential damage to the instrumentation;
The analyte was detected in the associated lab method blank for the sample. Sample results
would be flagged with a laboratory-generated single letter qualifier (i.e., “B”);
The estimated concentration of the analyte was detected between the method detection limit and
the reporting limit. Sample results would be flagged with a laboratory-generated single letter
qualifier (i.e., “J”). These results should be considered as estimated concentrations; and
The observed value was less than the method detection limit. These results will be flagged with
a “U.”

Table 5.22 - Parameter Classes Analyzed for in the MSC Study (New July 2011)

Final SGEIS 2015, Page 5-108

 Table 5.23 - Parameter Classes Detected in Flowback Analyticals in MSC Study (New July 2011)

Metals and conventional parameters were detected and quantified in many of the samples and
these observations are consistent with parameters listed in Table 5.9. However, the frequency of
occurrence of other parameter classes was much lower: Table 5.23 summarizes the number of
VOCs, SVOCs, PCBs, Pesticides, Alcohols, Glycols, and Acids observed in samples taken from
each well. For the purposes of Table 5.23, if a particular parameter was detected in any sample
from a single well, whether detected in one or all five (Day 0, 1, 5, 14 or 90) samples, it was
considered to be one parameter.
•

Between 1 and 7 of the 70 VOCs were detected in samples from well sites A through S.
VOCs detected include:
1,2,3-Trichlorobenzene
1,2,4-Trimethylbenzene
1,3,5-Trimethylbenzene
2-Butanone
Acetone
Acrylonitrile

Benzene
Bromoform
Carbondisulfide
Chloroform
Chloromethane
Ethylbenzene

Isopropylbenzene
Naphthalene
Toluene
Xylenes

Final SGEIS 2015, Page 5-109

 •

Between 1 and 9 of the 107 SVOCs were detected in samples from well sites A through
S. SVOCs detected include:
2,4-Dimethylphenol
2,6-Dichlorophenol
2-Methylnaphthalene
2-Methylphenol
2-Picoline
3-Methylphenol & 4Methylphenol
7,12Dimethylbenz(a)anthracene
Acetophenone
Benzo(a)pyrene

•

Benzo(b)fluoranthene
Benzo(ghi)perylene
Benzo(k)fluoranthene
Benzyl alcohol
bis(2-Chloroethyl) ether
bis(2-Ethylhexyl) phthalate

Fluoranthene
Fluorene
Indeno(1,2,3-cd)pyrene
N-Nitrosodiphenylamine
Phenanthrene
Phenol

Dibenz(a,h)anthracene

Pyridine

Di-n-butyl phthalate
Diphenylamine

Safrole

At most, 3 of the 20 Organochlorine Pesticides were detected. Organochlorine Pesticides
detected include:
4,4 DDE
Aldrin
cyclohexane (beta BHC)

cyclohexane (gamma
BHC)
endosulfan I
endosulfan II

endrin aldehyde
Heptachlor
heptachlor epoxide

•

Only 1 (Aroclor 1248) of the 7 PCBs was detected, and that was only from one well site;

•

Only 1 Organophosphorus Pesticide was analyzed for, but it was not detected in any
sample;

•

Of the 5 Alcohols analyzed for, 2 were detected at one well site and 1 each was detected
at two well sites. Alcohols that were detected include 2-propanol and methanol;

•

Of the 2 Glycols (Ethylene glycol and Propylene glycol) analyzed for, 1 each was
detected at three well sites; and

•

Of the 4 Acids analyzed for, 1 or 2 Acids (Acetic acid and Volatile Acids) were detected
at several well sites.

Some parameters found in analytical results may be due to additives or supply water used in
fracturing or drilling; some may be due to reactions between different additives; while others
may have been mobilized from within the formation; still other parameters may have been

Final SGEIS 2015, Page 5-110

 contributed from multiple sources. Some of the volatile and semi-volatile analytical results may
be traced back to potential laboratory contamination due to improper ventilation; due to
chromatography column breakdown; or due to chemical breakdown of compounds during
injection onto the instrumentation. Further study would be required to identify the specific
origin of each parameter.
Nine pesticides and one PCB were identified by the MSC Study that were not identified by the
flowback analytical results previously received from industry; all other parameters identified in
the MSC study were already identified in the additives and/or flowback information received
from industry.
Pesticides and PCBs do not originate within the shale play. If pesticides or PCBs were present in
limited flowback samples in Pennsylvania or West Virginia, pesticides or PCBs would likely
have been introduced to the shale or water during drilling or fracturing operations. Whether the
pesticides or PCBs were introduced via additives or source water could not be evaluated with
available information.
5.11.3.1

Temporal Trends in Flowback Water Composition

The composition of flowback water changes with time over the course of the flowback process,
depending on a variety of factors. Limited time-series field data from Marcellus Shale flowback
water, including data from the MSC Study Report, indicate that:
•

The concentrations of total dissolved solids (TDS), chloride, and barium increase;

•

The levels of radioactivity increase, 231 and sometimes exceed MCLs;

•

Calcium and magnesium hardness increases;

•

Iron concentrations increase, unless iron-controlling additives are used;

•

Sulfate levels decrease;

•

Alkalinity levels decrease, likely due to use of acid; and

231

Limited data from vertical well operations in NY have reported the following ranges of radioactivity: alpha 22.41 – 18950
pCi/L; beta 9.68 – 7445 pCi/L; Radium226 2.58 - 33 pCi/L.

Final SGEIS 2015, Page 5-111

 •

Concentrations of metals increase. 232

Available literature cited by URS corroborates the above summary regarding the changes in
composition with time for TDS, chlorides, and barium. Fracturing fluids pumped into the well,
and mobilization of materials within the shale may be contributing to the changes seen in
hardness, sulfate, and metals. The specific changes would likely depend on the shale formation,
fracturing fluids used and fracture operations control.
5.11.3.2

NORM in Flowback Water

Several radiological parameters were detected in flowback samples, as shown in Table 5.24.
Table 5.24 - Concentrations of NORM constituents based on limited
samples from PA and WV (Revised July 2011)

CAS #

Parameter Name

--7440-14-4
7440-14-4
7440-14-4

Gross Alpha
Gross Beta
Total Alpha Radium
Radium-226
Radium-228

5.12

Total
Number of
Samples
15
15
6
3
3

Number
of
Detects
15
15
6
3
3

Min

Median

Max

Units

22.41
62
3.8
2.58
1.15

------

18,950
7,445
1,810
33
18.41

pCi/L
pCi/L
pCi/L
pCi/L
pCi/L

Flowback Water Treatment, Recycling and Reuse

Operators have expressed the objective of maximizing their re-use of flowback water for
subsequent fracturing operations at the same well pad or other well pads; this practice is
increasing and continuing to evolve in the Marcellus Shale. 233 Reuse involves either straight
dilution of the flowback water with fresh water or the introduction on-site of more sophisticated
treatment options prior to flowback reuse. Originally operators focused on treating flowback
water using polymers and flocculants to precipitate out and remove metals, but more recently
operators have begun using filtration technologies to achieve the same goal. 234 As stated above,

232

Metals such as aluminum, antimony, arsenic, barium, boron, cadmium, calcium, cobalt, copper, iron, lead, lithium,
magnesium, manganese, molybdenum, nickel, potassium, radium, selenium, silver, sodium, strontium, thallium, titanium, and
zinc have been reported in flowback analyses. It is important to note that each well did not report the presence of all these
metals.

233

ALL Consulting, 2010, p. 73.

234

ALL Consulting, 2010, p. 73.

Final SGEIS 2015, Page 5-112

 various on-site treatment technologies may be employed prior to reuse of flowback water.
Regardless of the treatment objective, whether for reuse or direct discharge, the three basic issues
that need consideration when developing water treatment technologies are: 235
1. Influent (i.e., flowback water) parameters and their concentrations;
2. Parameters and their concentrations allowable in the effluent (i.e., in the reuse water); and
3. Disposal of residuals.
Untreated flowback water composition is discussed in Section 5.11.3. Table 5.25 summarizes
allowable concentrations after treatment (and prior to potential additional dilution with fresh
water). 236
Table 5.25 - Maximum allowable water quality requirements for fracturing fluids, based
on input from one expert panel on Barnett Shale (Revised July 2011)

Constituent
Chlorides

Concentration
3,000 - 90,000 mg/L

Calcium

350 - 1,000 mg/L

Suspended Solids

< 50 mg/L

Entrained oil and soluble organics

< 25 mg/L

Bacteria

< 100 cells/100 ml

Barium

Low levels

The following factors influence the decision to utilize on-site treatment and the selection of
specific treatment options: 237
Operational
•

Flowback fluid characteristics, including scaling and fouling tendencies;

•

On-site space availability;

235

URS, 2009, p. 5-2.

236

URS, 2009, p. 5-3.

237

URS, 2009, p. 5-3.

Final SGEIS 2015, Page 5-113

 •

Processing capacity needed;

•

Solids concentration in flowback fluid, and solids reduction required;

•

Concentrations of hydrocarbons in flowback fluid, and targeted reduction in
hydrocarbons; 238

•

Species and levels of radioactivity in flowback;

•

Access to freshwater sources;

•

Targeted recovery rate;

•

Impact of treated water on efficacy of additives; and

•

Availability of residuals disposal options.

Cost
•

Capital costs associated with treatment system;

•

Transportation costs associated with freshwater; and

•

Increase or decrease in fluid additives from using treated flowback fluid.

Environmental
•

On-site topography;

•

Density of neighboring population;

•

Proximity to freshwater sources;

•

Other demands on freshwater in the vicinity; and

•

Regulatory environment.

5.12.1 Physical and Chemical Separation 239
Some form of physical and/or chemical separation will be required as a part of on-site treatment.
Physical and chemical separation technologies typically focus on the removal of oil and grease 240
238

Liquid hydrocarbons have not been detected in all Marcellus Shale gas analyses.

239

URS, 2009, p. 5-6.

Final SGEIS 2015, Page 5-114

 and suspended matter from flowback. Modular physical and chemical separation units have been
used in the Barnett Shale and Powder River Basin plays.
Physical separation technologies include hydrocyclones, filters, and centrifuges; however,
filtration appears to be the preferred physical separation technology. The efficiency of filtration
technologies is controlled by the size and quantity of constituents within the flowback fluid as
well as the pore size and total contact area of the membrane. To increase filtration efficiency,
one vendor provides a vibrating filtration unit (several different pore sizes are available) for
approximately $300,000; this unit can filter 25,000 gpd.
Microfiltration has been shown to be effective in lab-scale research, nanofiltration has been used
to treat production brine from off-shore oil rigs, and modular filtration units have been used in
the Barnett Shale and Powder River Basin. 241 Nanofiltration has also been used in Marcellus
development in Pennsylvania, though early experience there indicates that the fouling of filter
packs has been a limiting constraint on its use. 242
Chemical separation utilizes coagulants and flocculants to break emulsions (dissolved oil) and to
remove suspended particles. The companion process of precipitation is accomplished by
manipulating flowback chemistry such that constituents within the flowback (in particular,
metals) will precipitate out of solution. This can also be performed sequentially, so that several
chemicals will precipitate, resulting in cleaner flowback.
Separation and precipitation are used as pre-treatment steps within multi-step on-site treatment
processes. Chemical separation units have been used in the Barnett Shale and Powder River
Basin plays, and some vendors have proprietary designs for sequential precipitation of metals for
potential use in the Marcellus Shale play. 243
If flowback is to be treated solely for blending and re-use as fracturing fluid, chemical
precipitation may be one of the only steps needed. By precipitation of scale-forming metals
240

Oil and grease are not expected in the Marcellus.

241

URS 2011, p 5-6.

242

Yoxtheimer, 2011 (personal communication).

243

URS 2011, p 5-7.

Final SGEIS 2015, Page 5-115

 (e.g., barium, strontium, calcium, magnesium), minimal excess treatment may be required.
Prices for chemical precipitation systems are dependent upon the cost of the treatment chemicals;
one vendor quoted a 15 gpm system for $450,000 or a 500 gpm system for approximately $1
million, with costs ranging from $0.50 to $3.00 per barrel.
5.12.2 Dilution
The dilution option involves blending flowback water with freshwater to make it usable for
future fracturing operations. Because high concentrations of different parameters in flowback
water may adversely affect the desired fracturing fluid properties, 100% recycling is not always
possible without employing some form of treatment. 244,245 Concentrations of chlorides, calcium,
magnesium, barium, carbonates, sulfates, solids and microbes in flowback water may be too high
to use as-is, meaning that some form of physical and/or chemical separation is typically needed
prior to recycling flowback. 246 In addition, the practice of blending flowback with freshwater
involves balancing the additional freshwater water needs with the additional additive needs. 247
For example, the demand for friction reducers increases when the chloride concentration
increases; the demand for scale inhibitors increases when concentrations of calcium, magnesium,
barium, carbonates, or sulfates increase; biocide requirements increase when the concentration of
microbes increases. These considerations do not constrain reuse because both the dilution ratio
and the additive concentrations can be adjusted to achieve the desired properties of the fracturing
fluid. 248 In addition, service companies and chemical suppliers may develop additive products
that are more compatible with the aforementioned flowback water parameters.
5.12.2.1

Reuse

The SRBC’s reporting system for water usage within the Susquehanna River Basin (SRB) has
provided a partial snapshot of flowback water reuse specific to Marcellus development. For the
period June 1, 2008 to June 1, 2011, operators in the SRB in Pennsylvania reused approximately
311 million gallons of the approximately 2.14 billion gallons withdrawn and delivered to
244

URS, 2009, p. 5-1.

245

ALL Consulting, 2010, p. 73.

246

URS, 2009, p. 5-2.

247

URS, 2009, p. 5-2.

248

ALL Consulting, 2010, p. 74.

Final SGEIS 2015, Page 5-116

 Marcellus well pads. The SRBC data indicate that an average of 4.27 million gallons of water
were used per well; this figure reflects an average of 3.84 million gallons of fresh water and 0.43
million gallons of reused flowback water per well. 249 The current limiting factors on flowback
water reuse are the volume of flowback water recovered and the timing of upcoming fracture
treatments. 250 Treatment and reuse of flowback water on the same well pad reduces the number
of truck trips needed to haul flowback water to another destination.
Operators may propose to store flowback water prior to or after dilution in on-site tanks, which
are discussed in Section 5.11.2. The tanks may be set up to segregate flowback based on
estimated water quality. Water that is suitable for reuse with little or no treatment can be stored
separately from water that requires some degree of treatment, and any water deemed unsuitable
for reuse can then be separated for appropriate disposal. 251 An example of the composition of a
fracturing solution that includes recycled flowback water is shown in Figure 5.6.
Figure 5.6 - Example Fracturing Fluid Composition Including Recycled
Flowback Water (New July 2011)

249

SRBC, 2011.

250

ALL Consulting, 2010, p. 74.

251

ALL Consulting, 2010, p. 74.

Final SGEIS 2015, Page 5-117

 5.12.3 Other On-Site Treatment Technologies 252
One example of an on-site treatment technology configuration is illustrated in Figure 5.7. The
parameters treated are listed at the bottom of the figure. The next few sections present several
on-site treatment technologies that have been used to some extent in other U.S. gas-shale plays.

Figure 5.7 - One configuration of potential on-site treatment technologies.

5.12.3.1

Membranes / Reverse Osmosis

Membranes are an advanced form of filtration, and may be used to treat TDS in flowback. The
technology allows water - the permeate - to pass through the membrane, but the membrane
blocks passage of suspended or dissolved particles larger than the membrane pore size. This
method may be able to treat TDS concentrations up to approximately 45,000 mg/L, and produce
an effluent with TDS concentrations between 200 and 500 mg/L. This technology generates a
252

URS, 2009, p. 5-4.

Final SGEIS 2015, Page 5-118

 residual - the concentrate - that would need proper disposal. The flowback water recovery rate
for most membrane technologies is typically between 50-75 percent. Membrane performance
may be impacted by scaling and/or microbiological fouling; therefore, flowback water would
likely require extensive pre-treatment before it is sent through a membrane.
Reverse osmosis (RO) is a membrane technology that uses osmotic pressure on the membrane to
provide passage of high-quality water, producing a concentrated brine effluent that will require
further treatment and disposal. Reverse osmosis is a well-proven technology and is frequently
used in desalination projects, in both modular and permanent configurations, though it is less
efficient under high TDS concentrations. High TDS concentrations, such as in Marcellus
flowback, 253 will likely result in large quantities of concentrated brine (also referred to as
“reject”) that will require further treatment or disposal. When designing treatment processes,
several vendors use RO as a primary treatment (with appropriate pre-treatment prior to RO); and
then use a secondary treatment method for the concentrated brine. The secondary treatment can
be completed on-site, or the concentrated brine can be trucked to a centralized brine treatment
facility.
Modular membrane technology units have been used in different regions for many different
projects, including the Barnett Shale. Some firms have developed modular RO treatment units,
which could potentially be used in the Marcellus. 254
5.12.3.2

Thermal Distillation

Thermal distillation utilizes evaporation and crystallization techniques that integrate a multieffect distillation column, and this technology may be used to treat flowback water with a large
range of parameter concentrations. For example, thermal distillation may be able to treat TDS
concentrations from 5,000 to over 150,000 mg/L, and produce water with TDS concentrations
between 50 and 150 mg/L. The resulting residual salt would need appropriate disposal. This
technology is resilient to fouling and scaling, but is energy intensive and has a large footprint.
Modular thermal distillation units have been used in the Barnett Shale, and have begun to be
253

URS, 2011, p. 4-37.

254

URS, 2011, p. 5-7.

Final SGEIS 2015, Page 5-119

 used in the Marcellus Shale in Pennsylvania. In addition to the units that are already in use,
several vendors have designs ready for testing, potentially further decreasing costs in the near
future. 255
5.12.3.3

Ion Exchange

Ion exchange units utilize different resins to preferentially remove certain ions. When treating
flowback, the resin would be selected to preferentially remove sodium ions. The required resin
volume and size of the ion exchange vessel would depend on the salt concentration and flowback
volume treated.
The Higgins Loop is one version of ion exchange that has been successfully used in Midwest
coal bed methane applications. The Higgins Loop uses a continuous countercurrent flow of
flowback fluid and ion exchange resin. High sodium flowback fluid can be fed into the
absorption chamber to exchange for hydrogen ions. The strong acid-cation resin is advanced to
the absorption chamber through a unique resin pulsing system.
Modular ion exchange units have been used in the Barnett Shale.
5.12.3.4

Electrodialysis/Electrodialysis Reversal

These treatment units are configured with alternating stacks of cation and anion membranes that
allow passage of flowback fluid. Electric current applied to the stacks forces anions and cations
to migrate in different directions.
Electrodialysis Reversal (EDR) is similar to electrodialysis, but its electric current polarity may
be reversed as needed. This current reversal acts as a backwash cycle for the stacks which
reduces scaling on membranes. EDR offers lower electricity usage than standard reverse
osmosis systems and can potentially reduce salt concentrations in the treated water to less than
200 mg/L. Modular electrodialysis units have been used in the Barnett Shale and Powder River
Basin plays. Table 5.26 compares EDR and RO by outlining key characteristics of both
technologies.

255

URS, 2011 p. 5-8.

Final SGEIS 2015, Page 5-120

 Table 5.26 - Treatment capabilities of EDR and RO Systems

Criteria

EDR

RO

400-3,000

100-15,000

Salt removal capacity

50-95%

90-99%

Water recovery rate

85-94%

50-75%

Silt Density Index (SDI) < 12

SDI < 5

Operating Pressure

<50 psi

> 100 psi

Power Consumption

Lower for <2,500 mg/L TDS

Lower for >2,500 mg/L TDS

7-10 years

3-5 years

Acceptable influent TDS
(mg/L)

Allowable Influent Turbidity

Typical Membrane Life

5.12.3.5

Ozone/Ultrasonic/Ultraviolet

These technologies are designed to oxidize and separate hydrocarbons and heavy metals, and to
oxidize biological films and bacteria from flowback water. The microscopic air bubbles in
supersaturated ozonated water and/or ultrasonic transducers cause oils and suspended solids to
float. Some vendors have field-tested the companion process of hydrodynamic cavitation, in
which microscopic ozone bubbles implode, resulting in very high temperatures and pressures at
the liquid-gas interface, converting the ozone to hydroxyl radicals and oxygen gas. The high
temperatures and the newly-formed hydroxyl radicals quickly oxidize organic compounds. 256
Hydrodynamic cavitation has been used in field tests in the Fayetteville and Woodford Shale
plays, but its use has not gained traction in the Marcellus play. 257
Some vendors include ozone treatment technologies as one step in their flowback treatment
process, including treatment for blending and re-use of water in drilling new wells. Systems
incorporating ozone technology have been successfully used and analyzed in the Barnett
Shale. 258

256

NETL, 2010.

257

Yoxtheimer, 2011.

258

URS, 2011 p. 5-9.

Final SGEIS 2015, Page 5-121

 5.12.3.6

Crystallization/Zero Liquid Discharge

Zero liquid discharge (ZLD) follows the same principles as physical and chemical separation
(precipitation, centrifuges, etc.) and evaporation, however a ZLD process ensures that all liquid
effluent is of reusable or dischargeable quality. Additionally, any concentrate from the treatment
process will be crystallized and will either be used in some capacity on site, will be offered for
sale as a secondary product, or will be treated in such a way that it will meet regulations for
disposal within a landfill. ZLD treatment is a relatively rare, expensive treatment process, and
while some vendors suggest that the unit can be setup on the well pad, a more cost-effective use
of ZLD treatment will be at a centralized treatment plant located near users of the systems’
byproducts. In addition to the crystallized salts produced by ZLD, treated effluent water and/or
steam will also be a product that can be used by a third party in some industrial or agricultural
setting.
ZLD treatment systems are in use in a variety of industries, but none have been implemented in a
natural gas production setting yet. Numerous technology vendors have advertised ZLD as a
treatment option in the Marcellus, but the economical feasibility of such a system has not yet
been demonstrated. 259
5.12.4 Comparison of Potential On-Site Treatment Technologies
A comparison of performance characteristics associated with on-site treatment technologies is
provided in Table 5.27 260

259

URS, 2011 p. 5-9.

260

URS, 2009, p. 5-8.

Final SGEIS 2015, Page 5-122

 Table 5.27 - Summary of Characteristics of On-Site Flowback Water
Treatment Technologies (Updated July 2011) 261

Filtration

Ion
Exchange

Reverse
Osmosis

EDR

Thermal
Distillation

Ozone /
Ultrasonic /
Ultraviolet

Energy Cost

Low

Low

Moderate

High

High

Low

Energy Usage
vs. TDS

N/A

Low

Increase

High
Increase

Independent

Increase

Applicable to

All Water
types

All Water
types

Moderate
TDS

High TDS

High TDS

All Water
types

Plant / Unit size

Small /
Modular

Small /
Modular

Modular

Modular

Large

Small /
Modular

Microbiological
Fouling

Possible

Possible

Possible

Low

N/A

Possible

Complexity of
Technology

Low

Low

Moderate /
High
Maintenance

Regular
Maintenance

Complex

Low

Scaling
Potential

Low

Low

High

Low

Low

Low

Theoretical
TDS Feed Limit
(mg/L)

N/A

N/A

32,000

40,000

100,000+

Depends on
turbidity

Pretreatment
Requirement

N/A

Filtration

Extensive

Filtration

Minimal

Filtration

Final Water
TDS

No impact

200-500 ppm

200-500 ppm

200-1000
ppm

< 10 mg/L

Variable

N/A

N/A

30-50%

60-80%

75-85%

Variable

Characteristic

Recovery Rate
(Feed TDS
>20,000 mg/L)

5.13

Waste Disposal

5.13.1 Cuttings from Mud Drilling
The 1992 GEIS discusses on-site burial of cuttings generated during compressed air drilling.
This option is also viable for cuttings generated during drilling with fresh water as the drilling
fluid. However, cuttings that are generated during drilling with polymer- or oil-based muds are
considered industrial non-hazardous waste and therefore must be removed from the site by a
permitted Part 364 Waste Transporter and properly disposed in a solid waste landfill. In New
York State the NORM in cuttings is not precluded by regulation from disposal in a solid waste
261

URS, 2011, p. 5-9

Final SGEIS 2015, Page 5-123

 landfill, though well operators should consult with the operators of any landfills they are
considering using for disposal regarding the acceptance of Marcellus Shale drill cuttings by that
facility.
5.13.2 Reserve Pit Liner from Mud Drilling
The 1992 GEIS discusses on-site burial, with the landowner’s permission, of the plastic liner
used for the reserve pit for air-drilled wells. This option is also viable for wells where freshwater is the drilling fluid. However, pit liners for reserve pits where polymer- or oil-based
drilling muds are used must be removed from the site by a permitted Part 364 Waste Transporter
and properly disposed in a solid waste landfill.
5.13.3 Flowback Water
As discussed in Section 5.12, options exist or are being developed for treatment, recycling and
reuse of flowback water. Nevertheless, proper disposal is required for flowback water that is not
reused. Factors which could result in a need for disposal instead of reuse include lack of reuse
opportunity (i.e., no other wells being fractured within reasonable time frames or a reasonable
distance), prohibitively high contaminant concentrations which render the water untreatable to
usable quality, or unavailability or infeasibility of treatment options for other reasons.
Flowback water requiring disposal is considered industrial wastewater, like many other wateruse byproducts. The Department has an EPA-approved program for the control of wastewater
discharges. Under New York State law, the program is called the State Pollutant Discharge
Elimination System (SPDES). The program controls point source discharges to ground waters
and surface waters. SPDES permits are issued to wastewater dischargers, including POTWs, and
include specific discharge limitations and monitoring requirements. The effluent limitations are
the maximum allowable concentrations or ranges for various physical, chemical, and/or
biological parameters to ensure that there are no impacts to the receiving water body.

Final SGEIS 2015, Page 5-124

 Potential flowback water disposal options discussed in the 1992 GEIS include:
•

injection wells, which are regulated under both the Department’s SPDES program and
the federal Underground Injection Control (UIC) program;

•

municipal sewage treatment facilities (POTWs); and

•

out-of-state industrial treatment plants.

Road spreading for dust control and de-icing (by a Part 364 Transporter with local government
approval) is also discussed in the 1992 GEIS as a general disposition method used in New York
for well-related fluids, primarily production brine (not an option for flowback water). Use of
existing or new private in-state waste water treatment plants and injection for enhanced resource
recovery in oil fields have also been suggested. More information about each of these options is
presented below and a more detailed discussion of the potential environmental impacts and how
they are mitigated is presented in Chapters 6 and 7.
5.13.3.1

Injection Wells

Discussed in Chapter 15 of the 1992 GEIS, injection wells for disposal of brine associated with
oil and gas operations are classified as Class IID in EPA’s UIC program and require federal
permits. Under the Department’s SPDES program, the use of these wells has been categorized
and regulated as industrial discharge. The primary objective of both programs is protection of
underground sources of drinking water, and neither the EPA nor the Department issues a permit
without a demonstration that injected fluids will remain confined in the disposal zone and
isolated from fresh water aquifers. As noted in the 1992 Findings Statement, the permitting
process for brine disposal wells “require[s] an extensive surface and subsurface evaluation which
is in effect a SEIS addressing technical issues. An additional site-specific environmental
assessment and SEQRA determination are required.”
UIC permit requirements will be included by reference in the SPDES permit, and the Department
may propose additional monitoring requirements and/or discharge limits for inclusion in the
SPDES permit. A well permit issued by DMN is also required to drill or convert a well deeper
than 500 feet for brine disposal. This permit is not issued until the required UIC and SPDES
permits have been approved. More information about the required analysis and mitigation

Final SGEIS 2015, Page 5-125

 measures considered during this review is provided in Chapter 7. Because of the 1992 finding
that brine disposal wells require site-specific SEQRA review, mitigation measures are discussed
in Chapter 7 for informational purposes only and are not being proposed on a generic basis.
5.13.3.2

Municipal Sewage Treatment Facilities

Municipal sewage treatment facilities (also called POTWs) are regulated by the Department’s
DOW. POTWs typically discharge treated wastewater to surface water bodies, and operate
under SPDES permits which include specific discharge limitations and monitoring requirements.
In general, POTWs must have a Department-approved pretreatment program for accepting any
industrial waste. POTWs must also notify the Department of any new industrial waste they plan
to receive at their facility. POTWs are required to perform certain analyses to ensure they can
handle the waste without upsetting their system or causing a problem in the receiving water.
Ultimately, the Department needs to approve such analysis and modify SPDES permits as
needed to insure water quality standards in receiving waters are maintained at all times. More
detailed discussion of the potential environmental impacts and how they are mitigated is
presented in Chapters 6 and 7.
5.13.3.3

Out-of-State Treatment Plants

The only regulatory role the Department has over disposal of flowback water (or production
brine) at out-of-state municipal or industrial treatment plants is that transport of these fluids,
which are considered industrial waste, must be by a licensed Part 364 Transporter.
For informational purposes, Table 5.28 lists out-of-state plants that were proposed in actual well
permit applications for disposition of flowback water recovered in New York. The regulatory
regimes in other states for treatment of this waste stream are evolving, and it is unknown whether
disposal at the listed plants remains feasible.

Final SGEIS 2015, Page 5-126

 Table 5.28 - Out-of-state treatment plants proposed for disposition of NY flowback water

Treatment Facility
Advanced Waste Services
Eureka Resources
Lehigh County Authority Pretreatment Plant
Liquid Assets Disposal
Municipal Authority of the City of McKeesport
PA Brine Treatment, Inc.
Sunbury Generation
Tri-County Waste Water Management
Tunnelton Liquids Co.
Valley Joint Sewer Authority
Waste Treatment Corporation

5.13.3.4

Location
New Castle, PA
Williamsport, PA
Fogelsville, PA
Wheeling, WV
McKeesport, PA
Franklin, PA
Shamokin Dam, PA
Waynesburg, PA
Saltsburg, PA
Athens, PA
Washington, PA

County
Lawrence
Lycoming
Lehigh
Ohio
Allegheny
Venango
Snyder
Greene
Indiana
Bradford
Washington

Road Spreading

Consistent with past practice regarding flowback water disposal, in January 2009, the
Department’s Division of Solid and Hazardous Materials (DSHM), which was then responsible
for oversight of the Part 364 program, released a notification to haulers applying for, modifying,
or renewing their Part 364 permit that flowback water from any formation including the
Marcellus may not be spread on roads and must be disposed of at facilities authorized by the
Department or transported for use or re-use at other gas or oil wells where acceptable to DMN.
This notification also addressed production brine and is included as Appendix 12. (Because of
organizational changes within the Department since 2009, the Part 364 program is now overseen
by the Division of Environmental Remediation (DER). As discussed in Chapter 7, BUDs for
reuse of production brine from Marcellus Shale will not be issued until additional data on
NORM content is available and evaluated.)
5.13.3.5

Private In-State Industrial Treatment Plants

Industrial facilities could be constructed or converted in New York to treat flowback water (and
production brine). Such facilities would require a SPDES permit for any discharge. Again, the
SPDES permit for a dedicated treatment facility would include specific discharge limitations and
monitoring requirements. The effluent limitations are the maximum allowable concentrations or
ranges for various physical, chemical, and/or biological parameters to ensure that there are no
impacts to the receiving water body.

Final SGEIS 2015, Page 5-127

 5.13.3.6

Enhanced Oil Recovery

Waterflooding is an enhanced oil recovery technique whereby water is injected into partially
depleted oil reservoirs to displace additional oil and increase recovery. Waterflood operations in
New York are regulated under Part 557 of the Department’s regulations and under the EPA’s
Underground Injection Control Program.
EPA reviews proposed waterflood injectate to determine the threat of endangerment to
underground sources of drinking water. Operations that are authorized by rule are required to
submit an analysis of the injectate anytime it changes, and operations under permit are required
to modify their permits to inject water from a new source. At this time, no waterflood operations
in New York have EPA approval to inject flowback water.
5.13.4 Solid Residuals from Flowback Water Treatment
URS Corporation reports that residuals disposal from the limited on-site treatment currently
occurring generally consists of injection into disposal wells. 262 Other options would be
dependent upon the nature and composition of the residuals and would require site-specific
consultation with the Department’s Division of Materials Management (DMM). Transportation
would require a Part 364 Waste Transporters’ Permit.
5.14

Well Cleanup and Testing

Wells are typically tested after drilling and stimulation to determine their productivity, economic
viability, and design criteria for a pipeline gathering system if one needs to be constructed. If no
gathering line exists, well testing necessitates that produced gas be flared. However, operators
have reported that for Marcellus Shale development in the northern tier of Pennsylvania, flaring
is minimized by construction of the gathering system ahead of well completion. Flaring is
necessary during the initial 12 to 24 hours of flowback operations while the well is producing a
high ratio of flowback water to gas, but no flow testing that requires an extended period of
flaring is conducted. Operators report that without a gathering line in place, initial cleanup or

262

URS, 2009, p. 5-3.

Final SGEIS 2015, Page 5-128

 testing that require flaring could last for 3 days per well. 263 Under the SGEIS, permit conditions
would prohibit flaring during completion operations if a gathering line is in place.
5.15

Summary of Operations Prior to Production

Table 5.29 summarizes the primary operations that may take place at a multi-well pad prior to
the production phase, and their typical durations. This tabulation assumes that a smaller rig is
used to drill the vertical wellbore and a larger rig is used for the horizontal wellbore. Rig
availability and other parameters outside the operators’ control may affect the listed time frames.
As explained in Section 5.2, no more than two rigs would operate on the well pad concurrently.
Note that the early production phase at a pad may overlap with the activities summarized in
Table 5.29, as some wells may be placed into production prior to drilling and completion of all
the wells on a pad. All pre-production operations for an entire pad must be concluded within
three years or less, in accordance with ECL §23-0501. Estimated duration of each operation may
be shorter or longer depending on site specific circumstances.
Table 5.29 - Primary Pre-Production Well Pad Operations (Revised July 2011)

Operation
Access Road and
Well Pad
Construction

Vertical Drilling
with Smaller Rig

Materials and
Equipment
Backhoes, bulldozers and
other types of earthmoving equipment.
Drilling rig, fuel tank,
pipe racks, well control
equipment, personnel
vehicles, associated
outbuildings, delivery
trucks.

Preparation for
Horizontal Drilling
with Larger Rig

Activities
Clearing, grading, pit construction,
placement of road materials such as
geotextile and gravel.
Drilling, running and cementing surface
casing, truck trips for delivery of
equipment and cement. Delivery of
equipment for horizontal drilling may
commence during late stages of vertical
drilling.
Transport, assembly and setup, or
repositioning on site of large rig and
ancillary equipment.

Duration
Up to 4 weeks per
well pad

Up to 2 weeks per
well; one to two
wells at a time

5 – 30 days per
well 264

263

ALL Consulting, 2010, pp. 10-11.

264

The shorter end of the time frame for drilling preparations applies if the rig is already at the well pad and only needs to be
repositioned. The longer end applies if the rig would be brought from off-site and is proportional to the distance which the
rig would be moved. This time frame would occur prior to vertical drilling if the same rig is used for the vertical and
horizontal portions of the wellbore.

Final SGEIS 2015, Page 5-129

 Operation

Horizontal Drilling

Materials and
Equipment
Drilling rig, mud system
(pumps, tanks, solids
control, gas separator),
fuel tank, well control
equipment, personnel
vehicles, associated
outbuildings, delivery
trucks.

Preparation for
Hydraulic Fracturing

Hydraulic Fracturing
Procedure

Fluid Return
(Flowback) and
Treatment

Temporary water tanks,
generators, pumps, sand
trucks, additive delivery
trucks and containers (see
Section 5.6.1), blending
unit, personnel vehicles,
associated outbuildings,
including computerized
monitoring equipment.
Gas/water separator, flare
stack, temporary water
tanks, mobile water
treatment units, trucks for
fluid removal if
necessary, personnel
vehicles.

Waste Disposal

Earth-moving equipment,
pump trucks, waste
transport trucks.

Well Cleanup and
Testing

Well head, flare stack,
brine tanks. Earthmoving equipment.

Activities

Duration

Drilling, running and cementing
production casing, truck trips for delivery
of equipment and cement. Deliveries
associated with hydraulic fracturing may
commence during late stages of
horizontal drilling.

Up to 2 weeks per
well; one to two
wells at a time

Rig down and removal or repositioning of
drilling equipment including possible
changeover to workover rig to clean out
well and run tubing-conveyed perforating
equipment. Wireline truck on site to run
cement bond log (CBL). Truck trips for
delivery of temporary tanks, water, sand,
additives and other fracturing equipment.
Deliveries may commence during late
stages of horizontal drilling.

30 – 60 days per
well, or per well
pad if all wells
treated during one
mobilization

Fluid pumping, and use of wireline
equipment between pumping stages to
raise and lower tools used for downhole
well preparation and measurements.
Computerized monitoring. Continued
water and additive delivery.

2 – 5 days per
well, including
approximately 40
to 100 hours of
actual pumping

Rig down and removal or repositioning of
fracturing equipment; controlled fluid
flow into treating equipment, tanks, lined
pits, impoundments or pipelines; truck
trips to remove fluid if not stored on site
or removed by pipeline.

2 – 8 weeks per
well, may occur
concurrently for
several wells

Pumping and excavation to
empty/reclaim reserve pit(s). Truck trips
to transfer waste to disposal facility.
Truck trips to remove temporary water
storage tanks.
Well flaring and monitoring. Truck trips
to empty brine tanks. Gathering line
construction may commence if not done
in advance.

Final SGEIS 2015, Page 5-130

Up to 6 weeks per
well pad

½ - 30 days per
well

 5.16

Natural Gas Production

5.16.1 Partial Site Reclamation
Subsequent to drilling and fracturing operations, associated equipment is removed. Any pits
used for those operations must be reclaimed and the site must be re-graded and seeded to the
extent feasible to match it to the adjacent terrain. Department inspectors visit the site to confirm
full restoration of areas not needed for production.
Well pad size during the production phase will be influenced on a site-specific basis by
topography and generally by the space needed to support production activities and well
servicing. According to operators, multi-well pads will average 1.5 acres in size during the longterm production phase, after partial reclamation.
5.16.2 Gas Composition
5.16.2.1

Hydrocarbons

As discussed in Chapter 4 and shown on the maps accompanying the discussion in that section,
most of the Utica Shale and most of the Marcellus Shale “fairway” are in the dry gas window as
defined by thermal maturity and vitrinite reflectance. In other words, the shales would not be
expected to produce liquid hydrocarbons such as oil or condensate. This is corroborated by gas
composition analyses provided by one operator for wells in the northern tier of Pennsylvania and
shown in Table 5.30.
Table 5.30 - Marcellus Gas Composition from Bradford County, PA

Mole percent samples from Bradford Co., PA
Sample
Number
1

0.297

Carbon
Dioxide
0.063

96.977

2.546

0.107

2

0.6

0.001

96.884

2.399

0.097

0.004

0.008

3

0.405

0.085

96.943

2.449

0.106

0.003

0.009

100

4

0.368

0.046

96.942

2.522

0.111

0.002

0.009

100

5

0.356

0.067

96.959

2.496

0.108

0.004

0.01

6

1.5366

0.1536

97.6134

0.612

0.0469

7

2.5178

0.218

96.8193

0.4097

0.0352

8

1.2533

0.1498

97.7513

0.7956

0.0195

Nitrogen

Methane

Ethane

Propane

iButane

nButane
0.01

iPentane

nPentane

0.003

0.004

Hexanes
+

Oxygen

sum
100
100

100
0.0375

100

0.0294

100

100
0.0011

9

0.2632

0.0299

98.0834

1.5883

0.0269

0.0000

0.0000

0.0000

0.0000

0.0000

0.0083

100

10

0.4996

0.0551

96.9444

2.3334

0.0780

0.0157

0.0167

0.0000

0.0000

0.0000

0.0571

100

11

0.1910

0.0597

97.4895

2.1574

0.0690

0.0208

0.0126

0.0000

0.0000

0.0000

0.0000

100

12

0.2278

0.0233

97.3201

2.3448

0.0731

0.0000

0.0032

0.0000

0.0000

0.0000

0.0077

100

Final SGEIS 2015, Page 5-131

 ICF International, reviewing the above data under contract to NYSERDA, notes that samples 1,
3, 4 had no detectable hydrocarbons greater than n-butane. Sample 2 had no detectable
hydrocarbons greater than n-pentane. Based on the low VOC content of these compositions,
pollutants such as BTEX are not expected. 265 BTEX would normally be trapped in liquid phase
with other components like natural gas liquids, oil or water. Fortuna Energy reports that it has
sampled for benzene, toluene, and xylene and has not detected it in its gas samples or water
analyses.
5.16.2.2

Hydrogen Sulfide

As further reported by ICF, sample number 1 in Table 5.30 included a sulfur analysis and found
less than 0.032 grams sulfur per 100 cubic feet. The other samples did not include sulfur
analysis. Chesapeake Energy reported in 2009 that no hydrogen sulfide had been detected at any
of its active interconnects in Pennsylvania. Also in 2009, Fortuna Energy (now Talisman
Energy) reported testing for hydrogen sulfide regularly with readings of 2 to 4 ppm during a brief
period on one occasion in its vertical Marcellus wells, and that its presence had not recurred
since. More recently, it has been reported to the Department that, beyond minor detections with
mudlogging equipment, there is no substantiated occurrence of H2S in Marcellus wells in the
northern tier of Pennsylvania. 266
5.16.3 Production Rate
Long-term production rates are difficult to predict accurately for a play that has not yet been
developed or is in the very early stages of development. One operator has indicated that its
Marcellus production facility design will have a maximum capacity of either 6 MMcf/d or 10
MMcf/d, whichever is appropriate. IOGA-NY provided production estimates based on current
information regarding production experience in Pennsylvania, but also noted the following
caveats:
•

The production estimates are based on 640-acre pad development with horizontal wells
in the Marcellus fairway. Vertical wells and off-fairway development will vary.

265

ICF Task 2, 2009, pp. 29-30.

266

ALL Consulting, 2010, p. 49.

Final SGEIS 2015, Page 5-132

 •

The Marcellus fairway in New York is expected to have less formation thickness, and
because there has not been horizontal Marcellus drilling to date in New York the
reservoir characteristics and production performance are unknown. IOGA-NY expects
lower average production rates in New York than in Pennsylvania.

The per-well production estimates provided by IOGA-NY are as follows:
High Estimate
•
•
•
•
•

Year 1 – initial rate of 8.72 MMcf/d declining to 3.49 MMcf/d.
Years 2 to 4 – 3.49 MMcf/d declining to 1.25 MMcf/d.
Years 5 to 10 – 1.25 MMcf/d declining to 0.55 MMcf/d.
Years 11 and after – 0.55 MMcf/d declining at 5% per annum.
The associated estimated ultimate recovery (EUR) is approximately 9.86 Bcf.

Low Estimate
•
•
•
•
•

Year 1 – initial rate of 3.26 MMcf/d declining to 1.14 MMcf/d.
Years 2 to 4 – 1.14 MMcf/d declining to 0.49 MMcf/d.
Years 5 to 10 – 0.49 MMcf/d declining to 0.29 MMcf/d.
Years 11 and after – 0.29 MMcf/d declining at 5% per annum.
The associated EUR is approximately 2.28 Bcf. 267

5.16.4 Well Pad Production Equipment
In addition to the assembly of pressure-control devices and valves at the top of the well known as
the “wellhead,” “production tree” or “Christmas tree,” equipment at the well pad during the
production phase will likely include:

267

•

A small inline heater that is in use for the first 6 to 8 months of production and during
winter months to ensure freezing does not occur in the flow line due to Joule-Thompson
effect (each well or shared);

•

A two-phase gas/water separator;

•

Gas metering devices (each well or shared);

•

Water metering devices (each well or shared); and

•

Brine storage tanks (shared by all wells).

ALL Consulting, 2011, p. 2.

Final SGEIS 2015, Page 5-133

 In addition:
•

A well head compressor may be added during later years after gas production has
declined; and

•

A triethylene glycol (TEG) dehydrator may be located at some well sites, although
typically the gas is sent to a gathering system for compression and dehydration at a
compressor station.

Produced gas flows from the wellhead to the separator through a two- to three-inch diameter pipe
(flow line). The operating pressure in the separator will typically be in the 100 to 200 psi range
depending on the stage of the wells’ life. At the separator, water will be removed from the gas
stream via a dump valve and sent by pipe (water line) to the brine storage tanks. The gas
continues through a meter and to the departing gathering line, which carries the gas to a
centralized compression facility (see Figure 5.8).
Figure 5.8 – Simplified Illustration of Gas Production Process

Final SGEIS 2015, Page 5-134

 5.16.5 Brine Storage
Based on experience to date in the northern tier of Pennsylvania, one operator reports that brine
production has typically been less than 10 barrels per day after the initial flowback operation and
once the well is producing gas. Another operator reports that the rate of brine production during
the production phase is about to 5 - 20 barrels per MMcf of gas produced.
One or more brine tanks will be installed on-site, along with truck loading facilities. At least one
operator has indicated the possibility of constructing pipelines to move brine from the site, in
which case truck loading facilities would not be necessary. Operators monitor brine levels in
the tanks at least daily, with some sites monitored remotely by telemetric devices capable of
sending alarms or shutting wells in if the storage limit is approached.
The storage of production brine in on-site pits has been prohibited in New York since 1984.
5.16.6 Brine Disposal
Production brine disposal options discussed in the 1992 GEIS include injection wells, treatment
plants and road spreading for dust control and de-icing, which are all discussed in the GEIS. If
production brine is trucked off-site, it must be hauled by approved Part 364 Waste Transporters.
With respect to road spreading, in January 2009 the Department released a notification to haulers
applying for, modifying, or renewing their Part 364 Waste Transporter Permits that any entity
applying for a Part 364 permit or permit modification to use production brine for road spreading
must submit a petition for a beneficial use determination (BUD) to the Department. The BUD
and Part 364 permit must be issued by the Department prior to any production brine being
removed from a well site for road spreading. See Appendix 12 for the notification. As discussed
in Chapter 7, BUDs for reuse of production brine from Marcellus Shale will not be issued until
additional data on NORM content is available and evaluated.
5.16.7 NORM in Marcellus Production Brine
Results of the Department’s initial NORM analysis of Marcellus brine produced in New York
are shown in Appendix 13. These samples were collected in late 2008 and 2009 from vertical
gas wells in the Marcellus formation. The data indicate the need to collect additional samples of
production brine to assess the need for mitigation and to require appropriate handling and

Final SGEIS 2015, Page 5-135

 treatment options, including possible radioactive materials licensing. The NYSDOH will require
the well operator to obtain a radioactive materials license for the facility when exposure rate
measurements associated with scale accumulation in or on piping, drilling and brine storage
equipment exceed 50 microR/hr (µR/hr). A license may be required for facilities that will
concentrate NORM during pre-treatment or treatment of brine. Potential impacts and proposed
mitigation measures related to NORM are discussed in Chapters 6 and 7.
5.16.8 Gas Gathering and Compression
Operators report a 0.55 psi/foot to 0.60 psi/foot pressure gradient for the Marcellus Shale in the
northern tier of Pennsylvania. Bottom-hole pressure equals the true vertical depth of the well
times the pressure gradient. Therefore, the bottom-hole pressure on a 6,000-foot deep well will
be approximately between 3,300 and 3,600 psi. Wellhead pressures would be lower, depending
on the makeup of the gas. One operator reported flowing tubing pressures in Bradford County,
Pennsylvania, of 1,100 to 2,000 psi. Gas flowing at these pressures would not initially require
compression to flow into a transmission line. Pressure decreases over time, however, and one
operator stated an advantage of flowing the wells at as low a pressure as economically practical
from the outset, to take advantage of the shale’s gas desorption properties. In either case, the
necessary compression to allow gas to flow into a large transmission line for sale would typically
occur at a centralized site. Dehydration units, to remove water vapor from the gas before it flows
into the sales line, would also be located at the centralized compression facilities.
Based on experience in the northern tier of Pennsylvania, operators estimate that a centralized
facility will service well pads within a four to six mile radius. The gathering system from the
well to a centralized compression facility consists of buried polyvinyl chloride (PVC) or steel
pipe, and the buried lines leaving the compression facility consists of coated steel.
Siting of gas gathering and pipeline systems, including the centralized compressor stations
described above, is not subject to SEQRA review. See 6 NYCRR 617.5(c)(35). Therefore, the
above description of these facilities, and the description in Section 8.1.2.1 of the PSC’s
environmental review process, is presented for informational purposes only. This SGEIS will
not result in SEQRA findings or new SEQRA procedures regarding the siting and approval of
gas gathering and pipeline systems or centralized compression facilities. Environmental factors

Final SGEIS 2015, Page 5-136

 associated with gas-gathering and pipeline systems will be considered as part of the PSC’s
permitting process.
Photo 5.28 shows an aerial view of a compression facility.

Photo 5.28 - Pipeline Compressor in New York. Source: Fortuna Energy

5.17

Well Plugging

As described in the 1992 GEIS, any unsuccessful well or well whose productive life is over must
be properly plugged and abandoned, in accordance with Department-issued plugging permits and
under the oversight of Department field inspectors. Proper plugging is critical for the continued
protection of groundwater, surface water bodies and soil. Financial security to ensure funds for
well plugging is required before the permit to drill is issued, and must be maintained for the life
of the well.

Final SGEIS 2015, Page 5-137

 When a well is plugged, downhole equipment is removed from the wellbore, uncemented casing
in critical areas must be either pulled or perforated, and cement must be placed across or
squeezed at these intervals to ensure seals between hydrocarbon and water-bearing zones. These
downhole cement plugs supplement the cement seal that already exists at least behind the surface
(i.e., fresh-water protection) casing and above the completion zone behind production casing.
Intervals between plugs must be filled with a heavy mud or other approved fluid. For gas wells,
in addition to the downhole cement plugs, a minimum of 50 feet of cement must be placed in the
top of the wellbore to prevent any release or escape of hydrocarbons or brine from the wellbore.
This plug also serves to prevent wellbore access from the surface, eliminating it as a safety
hazard or disposal site.
Removal of all surface equipment and full site restoration are required after the well is plugged.
Proper disposal of surface equipment includes testing for NORM to determine the appropriate
disposal site.
The plugging requirements summarized above are described in detail in Chapter 11 of the 1992
GEIS and are enforced as conditions on plugging permits. Issuance of plugging permits is
classified as a Type II action under SEQRA. Proper well plugging is a beneficial action with the
sole purpose of environmental protection, and constitutes a routine agency action. Horizontal
drilling and high-volume hydraulic fracturing do not necessitate any new or different methods
for well plugging that require further SEQRA review.

Final SGEIS 2015, Page 5-138

 Chapter 6
Potential Environmental Impact
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Chapter 6 – Potential Environmental Impacts
CHAPTER 6 POTENTIAL ENVIRONMENTAL IMPACTS......................................................................................... 6-1
6.1 WATER RESOURCES ..................................................................................................................................... 6-1
6.1.1 Water Withdrawals.................................................................................................................................... 6-2
6.1.1.1 Reduced Stream Flow ..................................................................................................................... 6-2
6.1.1.2 Degradation of a Stream’s Best Use ............................................................................................... 6-2
6.1.1.3 Impacts to Aquatic Habitat ............................................................................................................. 6-3
6.1.1.4 Impacts to Aquatic Ecosystems ...................................................................................................... 6-3
6.1.1.5 Impacts to Wetlands ....................................................................................................................... 6-5
6.1.1.6 Aquifer Depletion............................................................................................................................ 6-5
6.1.1.7 Cumulative Water Withdrawal Impacts ......................................................................................... 6-6
6.1.2 Stormwater Runoff .................................................................................................................................. 6-14
6.1.3 Surface Spills and Releases at the Well Pad ............................................................................................ 6-15
6.1.3.1 Drilling ........................................................................................................................................... 6-16
6.1.3.2 Hydraulic Fracturing Additives ...................................................................................................... 6-16
6.1.3.3 Flowback Water and Production Brine ......................................................................................... 6-17
6.1.3.4 Potential Impacts to Primary and Principal Aquifers .................................................................... 6-37
6.1.4 Groundwater Impacts Associated With Well Drilling and Construction.................................................. 6-41
6.1.4.1 Turbidity........................................................................................................................................ 6-41
6.1.4.2 Fluids Pumped Into the Well......................................................................................................... 6-42
6.1.4.3 Natural Gas Migration .................................................................................................................. 6-42
6.1.5 Unfiltered Surface Drinking Water Supplies: NYC and Syracuse ............................................................. 6-43
6.1.5.1 Pollutants of Critical Concern in Unfiltered Drinking Water Supplies .......................................... 6-46
6.1.5.2 Regulatory and Programmatic Framework for Filtration Avoidance ............................................ 6-49
6.1.5.3 Adverse Impacts to Unfiltered Drinking Waters from High-Volume Hydraulic Fracturing ........... 6-51
6.1.5.4 Conclusion..................................................................................................................................... 6-52
6.1.6 Hydraulic Fracturing Procedure ............................................................................................................... 6-53
6.1.6.1 Wellbore Failure ........................................................................................................................... 6-54
6.1.6.2 Subsurface Pathways .................................................................................................................... 6-54
6.1.7 Waste Transport ...................................................................................................................................... 6-57
6.1.8 Fluid Discharges ....................................................................................................................................... 6-58
6.1.8.1 POTWs .......................................................................................................................................... 6-58
6.1.8.2 Private Off-site Wastewater Treatment and/or Reuse Facilities .................................................. 6-64
6.1.8.3 Private On-site Wastewater Treatment and/or Reuse Facilities .................................................. 6-64
6.1.8.4 Disposal Wells ............................................................................................................................... 6-65
6.1.8.5 Other Means of Wastewater Disposal .......................................................................................... 6-65
6.1.9 Solids Disposal ......................................................................................................................................... 6-66
6.1.9.1 NORM Considerations - Cuttings .................................................................................................. 6-66
6.1.9.2 Cuttings Volume............................................................................................................................ 6-66
6.1.9.3 Cuttings and Liner Associated With Mud-Drilling ......................................................................... 6-66
6.2 FLOODPLAINS ............................................................................................................................................ 6-67
6.3 FRESHWATER WETLANDS ............................................................................................................................. 6-67
6.4 ECOSYSTEMS AND WILDLIFE .......................................................................................................................... 6-67
6.4.1 Impacts of Fragmentation to Terrestrial Habitats and Wildlife ............................................................... 6-68
6.4.1.1 Impacts of Grassland Fragmentation ............................................................................................ 6-73
6.4.1.2 Impacts of Forest Fragmentation ................................................................................................. 6-75
6.4.2 Invasive Species ....................................................................................................................................... 6-84

Final SGEIS 2015, Page 6-i

 6.4.2.1 Terrestrial...................................................................................................................................... 6-85
6.4.2.2 Aquatic .......................................................................................................................................... 6-87
6.4.3 Impacts to Endangered and Threatened Species .................................................................................... 6-89
6.4.4 Impacts to State-Owned Lands ................................................................................................................ 6-91
6.5 AIR QUALITY ............................................................................................................................................. 6-94
6.5.1 Regulatory Overview ............................................................................................................................... 6-94
6.5.1.1 Emission Analysis NOx - Internal Combustion Engine Emissions ................................................ 6-100
6.5.1.2 Natural Gas Production Facilities NESHAP 40 CFR Part 63, Subpart HH (Glycol
Dehydrators) ............................................................................................................................... 6-103
6.5.1.3 Flaring Versus Venting of Wellsite Air Emissions ........................................................................ 6-104
6.5.1.4 Number of Wells Per Pad Site ..................................................................................................... 6-105
6.5.1.5 Natural Gas Condensate Tanks ................................................................................................... 6-105
6.5.1.6 Emissions Tables ......................................................................................................................... 6-106
6.5.1.7 Offsite Gas Gathering Station Engine ......................................................................................... 6-108
6.5.1.8 Department Determinations on the Air Permitting Process Relative to Marcellus Shale
High-Volume Hydraulic Fracturing Development Activities. ...................................................... 6-109
6.5.2 Air Quality Impact Assessment .............................................................................................................. 6-111
6.5.2.1 Introduction ................................................................................................................................ 6-111
6.5.2.2 Sources of Air Emissions and Operational Scenarios .................................................................. 6-114
6.5.2.3 Modeling Procedures .................................................................................................................. 6-118
6.5.2.4 Results of the Modeling Analysis ................................................................................................ 6-133
6.5.2.5 Supplemental Modeling Assessment for Short Term PM2.5, SO2 and NO2 Impacts and
Mitigation Measures Necessary to Meet NAAQS. ...................................................................... 6-141
6.5.2.6 The Practicality of Mitigation Measures on the Completion Equipment and Drilling
Engines. ....................................................................................................................................... 6-154
6.5.2.7 Conclusions from the Modeling Analysis ................................................................................. 6-158
6.5.3 Regional Emissions of O3 Precursors and Their Effects on Attainment Status in the SIP ...................... 6-170
6.5.4 Air Quality Monitoring Requirements for Marcellus Shale Activities .................................................... 6-183
6.5.5 Permitting Approach to the Well Pad and Compressor Station Operations ......................................... 6-188
6.6 GREENHOUSE GAS EMISSIONS ..................................................................................................................... 6-189
6.6.1 Greenhouse Gases ................................................................................................................................. 6-190
6.6.2 Emissions from Oil and Gas Operations ................................................................................................ 6-190
6.6.2.1 Vented Emissions ........................................................................................................................ 6-191
6.6.2.2 Combustion Emissions ................................................................................................................ 6-191
6.6.2.3 Fugitive Emissions ....................................................................................................................... 6-192
6.6.3 Emissions Source Characterization ........................................................................................................ 6-192
6.6.4 Emission Rates ....................................................................................................................................... 6-196
6.6.5 Drilling Rig Mobilization, Site Preparation and Demobilization ............................................................ 6-197
6.6.6 Completion Rig Mobilization and Demobilization ................................................................................. 6-198
6.6.7 Well Drilling ........................................................................................................................................... 6-198
6.6.8 Well Completion .................................................................................................................................... 6-199
6.6.9 Well Production ..................................................................................................................................... 6-201
6.6.10 Summary of GHG Emissions .................................................................................................................. 6-203
6.7 NATURALLY OCCURRING RADIOACTIVE MATERIALS IN THE MARCELLUS SHALE ......................................................... 6-208
6.8 SOCIOECONOMIC IMPACTS ......................................................................................................................... 6-210
6.8.1 Economy, Employment, and Income ..................................................................................................... 6-214
6.8.1.1 New York State ........................................................................................................................... 6-214
6.8.1.2 Representative Regions .............................................................................................................. 6-220
6.8.2 Population ............................................................................................................................................. 6-234
6.8.2.1 New York State ........................................................................................................................... 6-236

Final SGEIS 2015, Page 6-ii

 6.8.2.2 Representative Regions .............................................................................................................. 6-241
6.8.3 Housing .................................................................................................................................................. 6-245
6.8.3.1 New York State ........................................................................................................................... 6-245
6.8.3.2 Representative Regions .............................................................................................................. 6-248
6.8.3.3 Cyclical Nature of the Natural Gas Industry................................................................................ 6-253
6.8.3.4 Property Values .......................................................................................................................... 6-253
6.8.4 Government Revenue and Expenditures............................................................................................... 6-257
6.8.4.1 New York State ........................................................................................................................... 6-257
6.8.4.2 Representative Regions .............................................................................................................. 6-260
6.8.5 Environmental Justice............................................................................................................................ 6-266
6.9 VISUAL IMPACTS ...................................................................................................................................... 6-266
6.9.1 Changes since Publication of the 1992 GEIS that Affect the Assessment of Visual Impacts ................. 6-267
6.9.1.1 Equipment and Drilling Techniques ............................................................................................ 6-267
6.9.1.2 Changes in Well Pad Size and the Number of Water Storage Sites ............................................ 6-268
6.9.1.3 Duration and Nature of Drilling and Hydraulic-Fracturing Activities .......................................... 6-268
6.9.2 New Landscape Features Associated with the Different Phases of Horizontal Drilling and
Hydraulic Fracturing .............................................................................................................................. 6-269
6.9.2.1 New Landscape Features Associated with the Construction of Well Pads ................................. 6-269
6.9.2.2 New Landscape Features Associated with Drilling Activities at Well Pads ................................. 6-273
6.9.2.3 New Landscape Features Associated with Hydraulic Fracturing Activities at Well Pads ............ 6-273
6.9.2.4 New Landscape Features Associated with Production at Viable Well Sites ............................... 6-275
6.9.2.5 New Landscape Features Associated with the Reclamation of Well Sites.................................. 6-275
6.9.3 Visual Impacts Associated with the Different Phases of Horizontal Drilling and Hydraulic
Fracturing .............................................................................................................................................. 6-275
6.9.3.1 Visual Impacts Associated with Construction of Well Pads ........................................................ 6-276
6.9.3.2 Visual Impacts Associated with Drilling Activities on Well Pads ................................................. 6-277
6.9.3.3 Visual Impacts Associated with Hydraulic Fracturing Activities at Well Sites ............................. 6-278
6.9.3.4 Visual Impacts Associated with Production at Well Sites ........................................................... 6-278
6.9.3.5 Visual Impacts Associated with the Reclamation of Well Sites .................................................. 6-279
6.9.4 Visual Impacts of Off-site Activities Associated with Horizontal Drilling and Hydraulic Fracturing ...... 6-280
6.9.5 Previous Evaluations of Visual Impacts from Horizontal Drilling and Hydraulic Fracturing .................. 6-282
6.9.6 Assessment of Visual Impacts using NYSDEC Policy and Guidance ....................................................... 6-286
6.9.7 Summary of Visual Impacts ................................................................................................................... 6-287
6.10 NOISE ................................................................................................................................................... 6-292
6.10.1 Access Road Construction ..................................................................................................................... 6-294
6.10.2 Well Site Preparation ............................................................................................................................. 6-295
6.10.3 High-Volume Hydraulic Fracturing – Drilling ......................................................................................... 6-296
6.10.4 High-Volume Hydraulic Fracturing – Fracturing .................................................................................... 6-299
6.10.5 Transportation ....................................................................................................................................... 6-302
6.10.6 Gas Well Production .............................................................................................................................. 6-303
6.11 TRANSPORTATION IMPACTS ........................................................................................................................ 6-303
6.11.1 Estimated Truck Traffic .......................................................................................................................... 6-304
6.11.1.1 Total Number of Trucks per Well ................................................................................................ 6-304
6.11.1.2 Temporal Distribution of Truck Traffic per Well ......................................................................... 6-307
6.11.1.3 Temporal Distribution of Truck Traffic for Multi-Well Pads ....................................................... 6-307
6.11.2 Increased Traffic on Roadways .............................................................................................................. 6-310
6.11.3 Damage to Local Roads, Bridges, and other Infrastructure ................................................................... 6-313
6.11.4 Damage to State Roads, Bridges, and other Infrastructure................................................................... 6-315
6.11.5 Operational and Safety Impacts on Road Systems ................................................................................ 6-317
6.11.6 Transportation of Hazardous Materials................................................................................................. 6-318
6.11.7 Impacts on Rail and Air Travel ............................................................................................................... 6-319

Final SGEIS 2015, Page 6-iii

 6.12 COMMUNITY CHARACTER IMPACTS ............................................................................................................... 6-319
6.13 SEISMICITY ............................................................................................................................................. 6-322
6.13.1 Hydraulic Fracturing-Induced Seismicity ............................................................................................... 6-322
6.13.1.1 Background ................................................................................................................................. 6-323
6.13.1.2 Recent Investigations and Studies .............................................................................................. 6-326
6.13.1.3 Correlations between New York and Texas ................................................................................ 6-328
6.13.1.4 Affects of Seismicity on Wellbore Integrity ................................................................................ 6-329
6.13.2 Summary of Potential Seismicity Impacts ............................................................................................. 6-330

FIGURES
Figure 6.1 - Water Withdrawals in the United States ............................................................................................. 6-11
Figure 6.2 - Fresh Water Use in NY (millions of gallons per day) with Projected Peak Water Use for HighVolume Hydraulic Fracturing (New July 2011) ..................................................................................... 6-12
Figure 6.3 - Daily Water Withdrawals, Exports, and Consumptive Uses in the Delaware River Basin.................... 6-13
Figure 6.4 - NYSDOH Regulated Groundwater Supplies within Mapped Primary and Principal Aquifers in
NY, Where the Marcellus Shale is Greater than 2,000 Feet below Ground Surface ............................ 6-39
Figure 6.5 - Average Spatial Disturbance for Marcellus Shale Well Pads in Forested Context (New July
2011) .................................................................................................................................................... 6-78
Figure 6.6 – Interior Forest Habitat Before & After Development of a Marcellus Gas Well Pad, Elk County
PA (New July 2011) ............................................................................................................................... 6-81
Figure 6.7 - Total Forest Areas Converted (New July 2011) .................................................................................... 6-82
Figure 6.8 - New York's Forest Matrix Blocks and State Connectivity (New July 2011) .......................................... 6-84
Figure 6.9 - Areas of Concern for Endangered and Threatened Animal Species, March 31, 2011 (New July
2011) .................................................................................................................................................... 6-91
Figure 6.10 - Marcellus Shale Extent Meteorological Data Sites ........................................................................... 6-168
Figure 6.11 - Location of Well Pad Sources of Air Pollution Used in Modeling ..................................................... 6-169
Figure 6.12 - Barnett Shale Natural Gas Production Trend, 1998-2007 ................................................................ 6-175
Figure 6.13 – Projected Direct Employment in New York State Resulting from Each Development Scenario
(New August 2011) ........................................................................................................................... 6-217
Figure 6.14 - Projected Total Employment in New York State Resulting from Each Development Scenario
(New August 2011) ........................................................................................................................... 6-218
Figure 6.15 - Projected Direct Employment in Region A Resulting from Each Development Scenario (New
August 2011) .................................................................................................................................... 6-224
Figure 6.16 - Projected Direct Employment in Region B Resulting from Each Development Scenario (New
August 2011) .................................................................................................................................... 6-225
Figure 6.17 - Projected Direct Employment in Region C Resulting from Each Development Scenario (New
August 2011) .................................................................................................................................... 6-226
Figure 6.18 – Projected Total Employment in Region A Under Each Development Scenario (New August
2011) ................................................................................................................................................ 6-228
Figure 6.19 - Projected Total Employment in Region B Under Each Development Scenario (New August
2011) ................................................................................................................................................ 6-229
Figure 6.20 - Projected Total Employment in Region C Under Each Development Scenario (New August
2011) ................................................................................................................................................ 6-230
Figure 6.21 - A-Weighted Noise Emissions: Cruise Throttle, Average Pavement (New August 2011) ................. 6-302
Figure 6.22 - Estimated Round-Trip Daily Heavy and Light Truck Traffic, by Well Type - Single Well (New
August 2011) .................................................................................................................................... 6-307
Figure 6.23 - Estimated Daily Round-Trips of Heavy and Light Truck Traffic - Multi Horizontal Wells (New
August 2011) .................................................................................................................................... 6-309
Figure 6.24 - Estimated Round-Trip Daily Heavy and Light Truck Traffic - Multi Vertical Wells (New August
2011) ................................................................................................................................................ 6-309

Final SGEIS 2015, Page 6-iv

 TABLES
Table 6.1 - Comparison of additives used or proposed for use in NY, parameters detected in analytical
results of flowback from the Marcellus operations in PA and WV and parameters regulated via
primary and secondary drinking water standards, SPDES or TOGS111 (Revised August 2011) ........... 6-19
Table 6.2 - Grassland Bird Population Trends at Three Scales from 1966 to 2005. (New July 2011) ..................... 6-74
Table 6.3 - Terrestrial Invasive Plant Species In New York State (Interim List) ....................................................... 6-85
Table 6.4 - Aquatic, Wetland & Littoral Invasive Plant Species in New York State (Interim List) ............................ 6-88
Table 6.5 - Endangered & Threatened Animal Species within the Area Underlain by the Marcellus Shale
(New July 2011) ..................................................................................................................................... 6-90
Table 6.6 - EPA AP-42 Emissions Factors Tables ................................................................................................... 6-101
Table 6.7 - Estimated Wellsite Emissions (Dry Gas) - Flowback Gas Flaring (Tpy)(Updated July 2011) ................ 6-107
Table 6.8 - Estimated Wellsite Emissions (Dry Gas) - Flowback Gas Venting (Tpy)(Updated July 2011) .............. 6-107
Table 6.9 - Estimated Wellsite Emissions (Wet Gas) - Flowback Gas Flaring (Tpy) (Updated July 2011) .............. 6-107
Table 6.10 - Estimated Wellsite Emissions (Wet Gas) - Flowback Gas Venting (Tpy) (Updated July 2011) .......... 6-107
Table 6.11 - Estimated Off-Site Compressor Station Emissions (Tpy) ................................................................... 6-108
Table 6.12 - Sources and Pollutants Modeled for Short-Term Simultaneous Operations .................................... 6-160
Table 6.13 - National Weather Service Data Sites Used in the Modeling ............................................................. 6-160
Table 6.14 - National Ambient Air Quality Standards (NAAQS), PSD Increments & Significant Impact Levels
(SILs) for Criteria Pollutants (µg/m3) ................................................................................................. 6-161
Table 6.15 - Maximum Background Concentration from Department Monitor Sites .......................................... 6-162
Table 6.16 - Maximum Impacts of Criteria Pollutants for Each Meteorological Data Set..................................... 6-163
Table 6.17 - Maximum Project Impacts of Criteria Pollutants and Comparison to SILs, PSD Increments and
Ambient Standards ........................................................................................................................... 6-164
Table 6.18 - Maximum Impacts of Non-Criteria Pollutants and Comparisons to SGC/AGC and New York
State AAQS ........................................................................................................................................ 6-165
Table 6.19 - Modeling Results for Short Term PM10, PM2.5 and NO2 (New July 2011) ...................................... 6-166
Table 6.20 - Engine Tiers and Use in New York with Recommended Mitigation Controls Based on the
Modeling Analysis (New July 2011) .................................................................................................. 6-167
Table 6.21 - Predicted Ozone Precursor Emissions (Tpy) ...................................................................................... 6-176
Table 6.22 - Barnett Shale Annual Average Emissions from All Sources............................................................... 6-180
Table 6.23 - Near-Field Pollutants of Concern for Inclusion in the Near-Field Monitoring Program (New
July 2011) .......................................................................................................................................... 6-184
Table 6.24 - Department Air Quality Monitoring Requirements for Marcellus Shale Activities (New July
2011) ................................................................................................................................................. 6-187
Table 6.25 - Assumed Drilling & Completion Time Frames for Single Vertical Well (New July 2011) ................... 6-195
Table 6.26 - Assumed Drilling & Completion Time Frames for Single Horizontal Well (Updated July 2011) ........ 6-195
Table 6.27 - Global Warming Potential for Given Time Horizon ........................................................................... 6-204
Table 6.28 - Summary of Estimated Greenhouse Gas Emissions (Revised July 2011) .......................................... 6-205
Table 6.29 - Emission Estimation Approaches – General Considerations ............................................................. 6-207
Table 6.30 - Radionuclide Half-Lives ..................................................................................................................... 6-209
Table 6.31 - Major Development Scenario Assumptions (New August 2011) ...................................................... 6-212
Table 6.32 - Maximum Direct and Indirect Employment Impacts on New York State under Each
Development Scenario (New August 2011) ...................................................................................... 6-216
Table 6.33 - Maximum Direct and Indirect Annual Employee Earnings Impacts on New York State under
Each Development Scenario (New August 2011) ............................................................................. 6-219
Table 6.34 - Major Development Scenario Assumptions for Each Representative Region (New August
2011) ................................................................................................................................................. 6-221
Table 6.35 - Maximum Direct and Indirect Employment Impacts on Each Representative Region under
Each Development Scenario (New August 2011) ............................................................................. 6-223
Table 6.36 - Maximum Direct and Indirect Earnings Impacts on Each Representative Region under Each
Development Scenario (New August 2011) ...................................................................................... 6-231

Final SGEIS 2015, Page 6-v

 Table 6.37 - Transient, Permanent and Total Construction Employment Under Each Development Scenario
for Select Years: New York State (New August 2011) ....................................................................... 6-237
Table 6.38 - Estimated Population Associated with Construction and Production Employment for Select
Years: New York State (New August 2011) ....................................................................................... 6-238
Table 6.39 - Maximum Temporary and Permanent Impacts Associated with Well Construction and
Production: New York State (New August 2011) .............................................................................. 6-240
Table 6.40 - Transient, Permanent, and Total Construction Employment Under Each Development
Scenario for Select Years for Representative Region A (New August 2011) ..................................... 6-241
Table 6.41 - Transient, Permanent, and Total Construction Employment Under Each Development
Scenario for Select Years for Representative Region B (New August 2011) ..................................... 6-241
Table 6.42 - Transient, Permanent, and Total Construction Employment Under Each Development
Scenario for Select Years for Representative Region C (New August 2011) ..................................... 6-242
Table 6.43 - Maximum Temporary and Permanent Impacts Associated with Well Construction and
Production ........................................................................................................................................ 6-243
Table 6.44 - Maximum Estimated Employment by Development Scenario for New York State (New August
2011) ................................................................................................................................................. 6-246
Table 6.45 - New York State Rental Housing Stock (2010) (New August 2011) .................................................... 6-247
Table 6.46 - Availability of Owner-Occupied Housing Units (2010) (New August 2011) ...................................... 6-248
Table 6.47 - Maximum Transient and Permanent Employment by Development Scenario and Region (New
August 2011) ..................................................................................................................................... 6-248
Table 6.48 - Availability of Rental Housing Units (New August 2011)................................................................... 6-250
Table 6.49 - Availability of Housing Units (New August 2011) .............................................................................. 6-252
Table 6.50 - Example of the Real Property Tax Payments From a Typical Horizontal Well (New August
2011) ................................................................................................................................................. 6-262
Table 6.51 - Example of the Real Property Tax Payments from a Typical Vertical Well (New August 2011)........ 6-264
Table 6.52 - Projected Change in Total Assessed Value and Property Tax Receipts at Peak Production (Year
30), by Region (New August 2011).................................................................................................... 6-264
Table 6.53 - Summary of Generic Visual Impacts Resulting from Horizontal Drilling and Hydraulic
Fracturing in the Marcellus and Utica Shale Area of New York (New August 2011) ........................ 6-288
Table 6.54 - Estimated Construction Noise Levels at Various Distances for Access Road Construction (New
August 2011) ..................................................................................................................................... 6-295
Table 6.55 - Estimated Construction Noise Levels at Various Distances for Well Pad Preparation (New
August 2011) ..................................................................................................................................... 6-296
Table 6.56 - Estimated Construction Noise Levels at Various Distances for Rotary Air Well Drilling (New
August 2011) ..................................................................................................................................... 6-298
Table 6.57 - Estimated Construction Noise Levels at Various Distances for Horizontal Drilling (New August
2011) ................................................................................................................................................. 6-298
Table 6.58 - Estimated Construction Noise Levels at Various Distances for High-Volume Hydraulic
Fracturing (New August 2011) .......................................................................................................... 6-300
Table 6.59 - Assumed Construction and Development Times (New August 2011) .............................................. 6-301
Table 6.60 - Estimated Number of One-Way (Loaded) Trips Per Well: Horizontal Well (New August 2011) ....... 6-305
Table 6.61 - Estimated Number of One-Way (Loaded) Trips Per Well: Vertical Well (New August 2011) ........... 6-306
Table 6.62 - Estimated Truck Volumes for Horizontal Wells Compared to Vertical Wells (New August 2011) .... 6-306
Table 6.63 - Estimated Annual Heavy Truck Trips (in thousands) (New August 2011) ......................................... 6-312
Table 6.64 - Illustrative AADT Range for State Roads (New August 2011) ............................................................ 6-313
PHOTOS
Photo 6.1 - A representative view of completion activities at a recently constructed well pad (New August
2011) ................................................................................................................................................ 6-270
Photo 6.2 - A representative view of completion activities at a recently constructed well pad, showing a
newly created access road in foreground (New August 2011) ........................................................ 6-271
Photo 6.3 - A representative view of a newly constructed water impoundment area (New August 2011) ......... 6-272

Final SGEIS 2015, Page 6-vi

 Photo 6.4 - A representative view of a water procurement site (New August 2011) ........................................... 6-272
Photo 6.5 - A representative view of active high-volume hydraulic fracturing (New August 2011) ..................... 6-274
Photo 6.6 - Electric Generators, Active Drilling Site (New August 2011) ............................................................... 6-299
Photo 6.7 - Truck-mounted Hydraulic Fracturing Pump (New August 2011) ........................................................ 6-300
Photo 6.8 - Hydraulic Fracturing of a Marcellus Shale Well Site (New August 2011)............................................ 6-301
Photo 6.9 - Map Depicting Trenton-Black River Wells and Historical Wells Targeting Other Formations in
Chemung County ................................................................................................................................ 6-332
Photo 6.10 - Map Depicting the Location of Trenton-Black River Wells in the Eastern-end of Quackenbush
Hill Field ............................................................................................................................................ 6-333
Photo 6.11 - Trenton-Black River Well Site (Rhodes) ............................................................................................ 6-333
Photo 6.12 - Trenton-Black River Well Site (Gregory) ........................................................................................... 6-334
Photo 6.13 - Trenton-Black River Well Site (Schwingel) ........................................................................................ 6-334
Photo 6.14 - Trenton-Black River Well Site (Soderblom)....................................................................................... 6-335
Photo 6.15 - Map Depicting the Locations of Two Trenton Black River Wells in North-Central Chemung
County .............................................................................................................................................. 6-336
Photo 6.16 - Trenton-Black River Well Site (Little) ................................................................................................ 6-337
Photo 6.17 - Trenton-Black River Well Site (Hulett) .............................................................................................. 6-337
Photo 6.18 - Map Depicting the Location of Trenton-Black River Wells in Western Chemung County and
Eastern Steuben County ................................................................................................................... 6-338
Photo 6.19 - Trenton-Black River Well Site (Lovell) ............................................................................................... 6-339
Photo 6.20 - Trenton Black River Well Site (Henkel) ............................................................................................. 6-339

Final SGEIS 2015, Page 6-vii

 This page intentionally left blank.

Chapter 6 POTENTIAL ENVIRONMENTAL IMPACTS
This revised Draft SGEIS incorporates by reference the 1992 Generic Environmental Impact
Statement on the Oil, Gas and Solution Mining Regulatory Program - including the draft
volumes released in 1988, the final volume released in 1992 - and the 1992 Findings Statement.
Therefore, the text in this Supplement is not exhaustive with respect to potential environmental
impacts, but instead focuses on new, different or additional information relating to potential
impacts of horizontal drilling and high-volume hydraulic fracturing.
6.1

Water Resources

Protection of water resources is a primary emphasis of the Department. Water resource matters
that may be impacted by activities associated with high-volume hydraulic fracturing are
identified and discussed in Chapter 2.
Adverse impacts to water resources might reasonably be anticipated in the context of
unmitigated high-volume hydraulic fracturing due to: 1) water withdrawals affecting surface or
groundwater, including wetlands; 2) polluted stormwater runoff; 3) surface chemical or
petroleum spills; 4) pit or surface impoundment failures or leaks; 5) groundwater contamination
associated with improper well drilling and construction; and 6) improper waste disposal. NYC’s
subsurface water supply infrastructure that is located in areas outside the boundary of the NYC
Watershed could also be impacted by unmitigated high-volume hydraulic fracturing. Potential
surface water impacts discussed herein are applicable to all areas that might be developed for
natural gas resources through high-volume hydraulic fracturing.
Three water resources issues were the subject of extensive comment during the public scoping
process:
1) Potential degradation of NYC’s surface drinking water supply;
2) Potential groundwater contamination from the hydraulic fracturing procedure itself; and
3) Adverse impacts to the Upper Delaware Scenic and Recreational River.

Final SGEIS 2015, Page 6-1

 Geological factors as well as standard permit requirements that the Department proposes to
impose that would limit or avoid the potential for groundwater contamination from high-volume
hydraulic fracturing are discussed in Chapters 5, 7 and 8.
6.1.1

Water Withdrawals

Water for hydraulic fracturing may be obtained by withdrawing it from surface water bodies or
new or existing water-supply wells drilled into aquifers. Without proper controls on the rate,
timing and location of such withdrawals, modifications to groundwater levels, surface water
levels, and stream flow could result in adverse impacts to aquatic ecosystems, downstream flow
levels, drinking water assured yields, wetlands, and aquifer recharge. While surface-water
bodies are still the primary source of water supplies for the drilling of Marcellus wells in
Pennsylvania, municipal and public water-supply wells have been used there as well.
6.1.1.1 Reduced Stream Flow
Potential effects of reduced stream flow caused by withdrawals could include:
•

insufficient supplies for downstream uses such as public water supply;

•

adverse impacts to quantity and quality of aquatic, wetland, and terrestrial habitats and
the biota that they support; and

•

exacerbation of drought effects.

Unmitigated withdrawals could adversely impact fish and wildlife health due to exposure to
unsuitable water temperature and dissolved oxygen concentrations, particularly in low-flow or
drought conditions. It could also affect downstream dischargers whose effluent limits are linked
to the stream’s flow rate. Water quality could be degraded and adverse impacts on natural
aquatic habitat increased if existing pollutants from point sources (e.g., discharge pipes) and/or
non-point sources (e.g., runoff from farms and paved surfaces) become concentrated.
6.1.1.2 Degradation of a Stream’s Best Use
New York State water use classifications are provided in Section 2.3.1. All of the uses are
dependent upon sufficient water in the stream to support the specified use. As noted,
uncontrolled withdrawals of water from streams in connection with high-volume hydraulic

Final SGEIS 2015, Page 6-2

 fracturing has the potential to adversely impact stream water supply and thus stream water use
classifications.
6.1.1.3 Impacts to Aquatic Habitat
Habitat for stream organisms is provided by the shape of the stream channel and the water that
flows through it. It is important to recognize that the physical habitat (e.g., pools, riffles, instream cover, runs, glides, bank cover, etc.) essential for maintaining the aquatic ecosystem is
formed by periodic disturbances that exist in the natural hydrograph; the seasonal variability in
stream flow resulting from annual precipitation and associated runoff. Maintaining this habitat
diversity within a stream channel is essential in providing suitable conditions for all the life stage
of the aquatic organisms. Stream fish distribution, community structure, and population
dynamics are related to channel morphology. Streamflow alterations that modify channel
morphology and habitat would result in changes in aquatic populations and community shifts
that alter natural ecosystems. Creating and maintaining high quality habitat is a function of
seasonally high flows because scour of fines from pools and deposition of bedload in riffles is
most predominant at high flow associated with spring snowmelt or high rain runoff. Periodic
resetting of the aquatic system is an essential process for maintaining stream habitat that would
continuously provide suitable habitat for all aquatic biota. Clearly, alteration of flow regimes,
sediment loads and riparian vegetation would cause changes in the morphology of stream
channels. Any streamflow management decision would not impair flows necessary to maintain
the dynamic nature of a river channel that is in a constant state of change as substrates are
scoured, moved downstream and re-deposited.
6.1.1.4 Impacts to Aquatic Ecosystems
Aquatic ecosystems could be adversely impacted by:
•

changes to water quality or quantity;

•

insufficient stream flow for aquatic biota stream habitat; or

•

the actual water withdrawal infrastructure.

Native aquatic species possess life history traits that enable individuals to survive and reproduce
within a certain range of environmental variation. Flow depth and velocity, water temperature,

Final SGEIS 2015, Page 6-3

 substrate size distribution and oxygen content are among the myriad of environmental attributes
known to shape the habitat that control aquatic and riparian species distributions. Streamflow
alterations can impact aquatic ecosystems due to community shifts made in response to the
corresponding shifts in these environmental attributes. The perpetuation of native aquatic
biodiversity and ecosystem integrity depends on maintaining some semblance of natural flow
patterns that minimize aquatic community shifts. The natural flow paradigm states that the full
range of natural intra- and inter-annual variation of hydrologic regimes, and associated
characteristics of timing, duration, frequency and rate of change, are critical in sustaining the full
native biodiversity and integrity of aquatic ecosystems.
Improperly installed water withdrawal structures can result in the entrainment of aquatic
organisms, which can remove any/all life stages of fish and macroinvertebrates from their natural
habitats as they are withdrawn with water. While most of the water bodies supplying water for
high-volume hydraulic fracturing contain species of fish whose early life stages are not likely to
be entrained because of their life history and behavioral characteristics, fish in their older life
stages could be entrained without measures to avoid or reduce adverse impacts. To avoid
adverse impacts to aquatic biota from entrainment, intake pipes can be screened to prevent entry
into the pipe. Additionally, the loss of biota that becomes trapped on intake screens, referred to
as impingement, can be minimized by properly sizing the intake to reduce the flow velocity
through the screens. Depending on the water body from which water is being withdrawn, the
location of the withdrawal structure on the water body and the site-specific aquatic organisms
requiring protection, project-specific technologies may be required to minimize the entrainment
and impingement of aquatic organisms. Technologies and operational measures that are proven
effective in reducing these impacts include but are not limited to narrow-slot width wedge-wire
screens (0.5 mm-2.0 mm), fine mesh screening, low intake velocities (0.5 feet per second (fps) or
less), and seasonal restrictions on intake operation. Transporting water from the water
withdrawal location for use off-site, as discussed in Section 6.4.2.2, can transfer invasive species
from one water body to another via trucks, hoses, pipelines, and other equipment. Screening of
the intakes can minimize this transfer; however, additional site-specific mitigation considerations
may be necessary.

Final SGEIS 2015, Page 6-4

 6.1.1.5 Impacts to Wetlands
The existence and sustainability of wetland habitats directly depend on the presence of water at
or near the surface of the soil. The functioning of a wetland is driven by the inflow and outflow
of surface water and/or groundwater. As a result, withdrawal of surface water or groundwater
for high-volume hydraulic fracturing could impact wetland resources. These potential impacts
depend on the amount of water within the wetland, the amount of water withdrawn from the
catchment area of the wetland, and the dynamics of water flowing into and out of the wetland.
Even small changes in the hydrology of the wetland can have significant impacts on the wetland
plant community and on the animals that depend on the wetland. It is important to preserve the
hydrologic conditions and to understand the surface water and groundwater interaction to protect
wetland areas.
6.1.1.6 Aquifer Depletion
The primary concern regarding groundwater withdrawal is aquifer depletion that could affect
other uses, including nearby public and private water supply wells. This includes cumulative
impacts from numerous groundwater withdrawals and potential aquifer depletion from the
incremental increase in withdrawals if groundwater supplies are used for hydraulic fracturing.
Aquifer depletion may also result in aquifer compaction which can result in localized ground
subsidence. Aquifer depletion can occur in both confined and unconfined aquifers.
The depletion of an aquifer and a corresponding decline in the groundwater level can occur when
a well, or wells in an aquifer are pumped at a rate in excess of the recharge rate to the aquifer.
Essentially, surface water and groundwater are one continuous resource; therefore, it also is
possible that aquifer depletion can occur if an excessive volume of water is removed from a
surface water body that recharges an aquifer. Such an action would result in a reduction of
recharge which could potentially deplete an aquifer. This “influent” condition of surface water
recharging groundwater occurs mainly in arid and semi-arid climates, and is not common in New
York, except under conditions such as induced infiltration of surface water by aquifer withdrawal
(e.g., pumping of water wells). 268

268

Alpha, 2009, p. 3-19, with updates from DEC.

Final SGEIS 2015, Page 6-5

 Aquifer depletion can lead to reduced discharge of groundwater to streams and lakes, reduced
water availability in wetland areas, and corresponding impacts to aquatic organisms that depend
on these habitats. Flowing rivers and streams are merely a surface manifestation of what is
flowing through the shallow soils and rocks. Groundwater wells impact surface water flows by
intercepting groundwater that otherwise would enter a stream. In fact, many New York
headwater streams rely entirely on groundwater to provide flows in the hot summer months. It is
therefore important to understand the hydrologic relationship between surface water,
groundwater, and wetlands within a watershed to appropriately manage rates and quantities of
water withdrawal. 269
Depletion of both groundwater and surface water can occur when significant water withdrawals
are transported out of the basin from which they originated. These transfers break the natural
hydrologic cycle, since the transported water never makes it downstream nor returns to the
original watershed to help recharge the aquifer. Without the natural flow regime, including
seasonal high flows, stream channel and riparian habitats critical for maintaining the aquatic
biota of the stream may be adversely impacted.
6.1.1.7 Cumulative Water Withdrawal Impacts 270
As noted in later in this chapter, it is estimated that within 30 years there could be up to 40,000
wells developed with the high-volume hydraulic fracturing technology. This could result in
substantial water usage in the study area. There are several potential types of impacts, when
considered cumulatively, that could result from these estimated new withdrawals associated with
natural gas development. Those are:
•

Stream flow, surface water and groundwater depletion;

•

Loss of aquifer storage capacity due to compaction;

•

Water quality degradation;

•

Wetland hydrology and habitat;

269

Alpha, 2009, p. 81.

270

Alpha, 2009 pp. 3-28.

Final SGEIS 2015, Page 6-6

 •

Fish and aquatic organism impacts;

•

Significant habitats, endangered, rare or threatened species impacts; and

•

Existing water users and reliability of their supplies.

Evaluation of the overall impact of multiple water withdrawals based on the projection of
maximum activity consider the existing water usage, the non-continuous nature of withdrawals
for natural gas development, and the natural replenishment of water resources. Natural
replenishment is described in Section 2.3.8.
The DRBC and SRBC have developed regulations, policies, and procedures to characterize
existing water use and track approved withdrawals. Changes to these systems also require
Commission review. Review of the requirements of the DRBC and SRBC indicates that the
operators and the reviewing authority would perform evaluations to assess the potential impacts
of water withdrawal for well drilling, and consider the following issues and information.
•

Comprehensive project description that includes a description of the proposed water
withdrawal (location, volume, and rate) and its intended use;

•

Existing water use in the withdrawal area;

•

Potential impacts, both ecological and to existing users, from the new withdrawal;

•

Availability of water resources (surface water and/or groundwater) to support the
proposed withdrawals;

•

Availability of other water sources (e.g., treated waste water) and conservation plans to
meet some or all of the water demand;

•

Contingencies for low flow conditions that include passby flow criteria;

•

Public notification requirements;

•

Monitoring and reporting;

•

Inspections;

•

Mitigation measures;

•

Supplemental investigations, including but not limited to, aquatic surveys;

Final SGEIS 2015, Page 6-7

 •

Potential impact to significant habitat and endangered rare or threatened species; and

•

Protection of subsurface infrastructure.
Existing Regulatory Scheme for Water Usage and Withdrawals

The DRBC and SRBC use a permit system and approval process to regulate existing water usage
in their respective basins. The DRBC and SRBC require applications in which operators provide
a comprehensive project description that includes the description of the proposed withdrawals.
The project information required includes site location, water source(s), withdrawal location(s),
proposed timing and rate of water withdrawal and the anticipated project duration. The operators
identify the amount of consumptive use (water not returned to the basin) and any import or
export of water to or from the basin. The method of conveyance from the point(s) of withdrawal
to the point(s) of use is also defined.
There are monitoring and reporting requirements once the withdrawal and consumptive use for a
project has been approved. These requirements include metering withdrawals and consumptive
use, and submitting quarterly reports to the Commission. Monitoring requirements can include
stream flow and stage measurements for surface water withdrawals and monitoring groundwater
levels for groundwater withdrawals.
The recently enacted Water Resources Law extends the Department’s authority to regulate all
water withdrawals over 100,000 gpd throughout all of New York State. This law applies to all
such withdrawals where water would be used for high-volume hydraulic fracturing. Withdrawal
permits issued in the future by the Department, pursuant to the regulations implementing this
law, would include conditions to allow the Department to monitor and enforce water quality and
quantity standards, and requirements. The Department is beginning the process for enacting
regulations on this new law. These standards and requirements may include: passby flow; fish
impingement and entrainment protections; protections for aquatic life; reasonable use; water
conservation practices; and evaluation of cumulative impacts on other water withdrawals. The
Department intends to seek consistency in water resource management within New York
between the DRBC, SRBC and the Department.

Final SGEIS 2015, Page 6-8

 Surface water and groundwater are withdrawn daily for a wide range of uses. New York ranks
as one of the top states with respect to the total amount of water withdrawals. Figure 6.1
presents a graph indicating the total water withdrawal for New York is approximately 9 to 10
billion gpd, based on data from 2000. Figure 6.2 presents fresh water use in New York,
including the projected peak water use for high-volume hydraulic fracturing.
The DRBC reports on the withdrawal of water for various purposes. The daily water
withdrawals, exports, and consumptive uses in the Delaware River Basin are shown in Figure
6.3. The total water withdrawal from the Delaware River Basin was 8,736 MGD, based on 2003
water use records. The highest water use was for thermoelectric power generation at 5,682
million gpd (65%), followed by 875 million gpd (10%) for public water supply, 650 million gpd
(7.4%) for the NYC public water supply, 617 million gpd (7%) for hydroelectric, and 501
million gpd (5.7%) for industrial purposes. The amount of water used for mining is 70 million
gpd (0.8%). The “mining” category typically includes withdrawals for oil and gas drilling;
however, DRBC has not yet approved water withdrawal for Marcellus Shale drilling operations.
The information in Figure 6.3 shows that 4.3% (14 million gpd) of the water withdrawn for
consumptive use is for mining and 88% (650 million gpd) of water exported from the Delaware
River Basin is diverted to NYC.
Whereas certain withdrawals, like many public water supplies are returned to the basin’s
hydrologic cycle, out-of-basin transfers, like the NYC water-supply diversion, some evaporative
losses, and withdrawals for hydraulic fracturing, are considered as 100% consumptive losses
because this water is essentially lost to the basin’s hydrologic cycle.
Withdrawals for High-Volume Hydraulic Fracturing
Current water withdrawal volumes when compared to withdrawal volumes associated with
current natural gas drilling indicates that the historical percentage of withdrawn water that goes
to natural gas drilling is very low. The amount of water withdrawn specifically for high-volume
hydraulic fracturing also is projected to be relatively low when compared to existing overall
levels of water use. The total volume of water withdrawn for high-volume hydraulic fracturing
in New York would not be known with precision until applications are received, reviewed, and
potentially approved or rejected by the appropriate regulatory agency or agencies, but can be

Final SGEIS 2015, Page 6-9

 estimated based on activity in Pennsylvania and projections of potential levels of well drilling
activity in New York.
Between July 2008 and February 2011, average water usage for high-volume hydraulic
fracturing within the Susquehanna River Basin in Pennsylvania was 4.2 million gallons per well,
based on data for 553 wells. 271 Current practice is to use 80% - 90% fresh water and 10% - 20%
recycled flowback water for high-volume hydraulic fracturing. 272 Average fresh water use as
85% of the total used per well is consistent with statistics reported by the SRBC. 273 This would
equate to average fresh water use of 3.6 million gallons per well (85% of 4.2 million gallons).
Industry projects a potential peak annual drilling rate in New York of 2,462 wells, a level of
drilling that is projected to be at the very high end of activity. Although some of these wells may
be vertical wells which require less water than horizontal wells where high-volume hydraulic
fracturing is planned, all of the wells reflected in the peak drilling rate will be conservatively
considered to be horizontal wells for the purpose of this analysis. Multiplying the peak projected
annual wells by current average use per well results in calculated peak annual fresh water usage
for high-volume hydraulic fracturing of 9 billion gallons. Total daily fresh water withdrawal in
New York has been estimated at approximately 10.3 billion gallons. 274 This equates to an annual
total of about 3.8 trillion gallons. Based on this calculation, at peak activity high-volume
hydraulic fracturing would result in increased demand for fresh water in New York of 0.24%.
The potential relationship between water use for high-volume hydraulic fracturing and other
purposes is shown in Figure 6.2.
While projected water withdrawals and consumptive use of water are modest relative to overall
water withdrawals in New York, there remains the potential for adverse impacts particularly
when withdrawals take place during low-flow or drought conditions. Adverse impacts
previously discussed may also occur when high or unsustainable withdrawals take place in
localized ground or surface water that lack adequate hydrologic capacity.

271

SRBC 2011.

272

ALL Consulting, 2010, p. 74.

273

Richenderfer, 2010, p. 30.

274

Kenny et al, 2009, p.7.

Final SGEIS 2015, Page 6-10

 Total withdrawals

E:XPlANATION
w.iter wruutrawals,
in llillioo gal oas

porday

Do

Hm'laii

D

Greatrirthan Oto 2,000

D 2.000 to 4,ooo

U.S. Virgin Islands

...

CJ~-

D 4,ooo to s,ooo
-

6,000 to 9,000
9,000to 13,500

Puerto Rico

FIGURE 6 ..1

Source: USGS

(;J
LPH

GEOSCIENCE
Alpha Project No. 09104
Map Document: (Z:lprojects\2009\09100-09120109104 . Gas Well Pe1mitting GEIS\Figures\Ganvas\Fig3-2-NY_Water_Usage.cvx)

Final SGEIS 2015, Page 6-11

WATER WITHDRAWALS IN THE
UNITED STATES

Technical Support Document to the


Final Supplemental Generic


Environmental Impact Statement



 Figure 6.2 - Fresh Water Use in NY (millions of gallons per day) with Projected Peak
Water Use for High-Volume Hydraulic Fracturing (New July 2011 275)

aquaculture*
63.1
public supply*
2,530

thermoelectric
power*
7,140

domestic*
140

mining*
32.9
livestock*
29.8

other
industrial*
301
*Kenny
*Kenny
et al,et2009.
al. 2009

275

irrigation*
51.1

projected
peak HVHF
24.7

This figure is a replacement for Figure 6.2 in the 2009 draft SGEIS which was a bar graph prepared by SRBC showing projected water use in the Susquehanna River Basin.

Final SGEIS 2015, Page 6-12

 617

Total Water Withdrawals
(ground and surface) from the
Delaware River Basin: 8,736
mgd

• Agriculture

o Domestic
• Industrial
OMining

0 Non-agricultural Irrigation
70

0 Public Water Supply

35

• Thermoelectric

o Hydroelectric
•All Other
DNYC

o NJ (D&R Canal)
Major Exports from the Delaware River Basin: 736 mgd

Consu"l>tive Use in the the Delaware River Basin: 324 mgd

89

Pie chart values in mgd
(million gallons per day)

FIGURE 6. 3

Source: DRBC

(;J
LPH
GEOSCIENCE
Alpha Project No. 09104
Map Document: (Z:\projects\2009109100.09120109104. Gas Well Permitting GEIS\Figures\Ganvas\Fig3·3·DRBC.cvx)

Final SGEIS 2015, Page 6-13

DAILY WATER WITHDRAWALS,
EXPORTS, AND CONSUMPTIVE USES
IN THE DELAWARE RIVER BASIN
Technical Support Document to the

Final Supplemental Generic

Environmental Impact Statement


 6.1.2

Stormwater Runoff

Stormwater, whether as a result of rainfall or snowmelt, is a valuable resource. It is the source of
water for lakes and streams, as well as aquifers. However, stormwater runoff, particularly when
it interacts with the human environment, is a pathway for contaminants to be conveyed from the
land surface to streams and lakes and groundwater. This is especially true for stormwater runoff
from asphalt, concrete, gravel/dirt roads, other impervious surfaces, outdoor industrial activity,
and earthen construction sites, where any material collected on the ground is washed into a
nearby surface water body. Stormwater runoff may also contribute to heightened peak flows and
flooding.
On an undisturbed landscape, precipitation is held by vegetation and pervious soil, allowing it to
slowly filter into the ground. This benefits water resources by using natural filtering properties,
replenishing groundwater aquifers and feeding lakes and streams through base flow during dry
periods. On a disturbed or developed landscape, it is common for the ground surface to be
compacted or otherwise made less pervious and for runoff to be shunted away quickly with
greater force and significantly higher volumes. Such hydrological modifications result in less
groundwater recharge and more rapid runoff to streams, which may cause increased stream
erosion and result in water quality degradation, habitat loss and flooding.
All phases of natural gas well development, from initial land clearing for access roads,
equipment staging areas and well pads, to drilling and fracturing operations, production and final
reclamation, have the potential to cause water resource impacts during rain and snow melt events
if stormwater is not properly managed.
Excess sediment can fill or bury the rock cobble of streams that serve as spawning habitat for
fish and the macro-invertebrate insects that serve as their food source. Stormwater runoff and
heightened sediment loads carry excess levels of nutrient phosphorus and nitrogen that is a major
cause of algae bloom, low dissolved oxygen and other water-quality impairments.
Initial land clearing exposes soil to erosion and more rapid runoff. Construction equipment is a
potential source of contamination from such things as hydraulic, fuel and lubricating fluids.
Equipment and any materials that are spilled, including additive chemicals and fuel, are exposed

Final SGEIS 2015, Page 6-14

 to rainfall, so that contaminants may be conveyed off-site during rain events if they are not
properly contained. Steep access roads, well pads on hill slopes, and well pads constructed by
cut-and-fill operations pose particular challenges, especially if an on-site drilling pit is proposed.
A production site, including access roads, is also a potential source of stormwater runoff impacts
discussed above because its hydrologic characteristics, sediment, nutrient, contaminant, and
water volumes may be substantially different from the pre-developed condition.
6.1.3

Surface Spills and Releases at the Well Pad

Spills or releases can occur as a result of tank ruptures, piping failures, equipment or surface
impoundment failures, overfills, vandalism, accidents (including vehicle collisions), ground fires,
drilling and production equipment defects, or improper operations. Spilled, leaked or released
fluids could flow to a surface water body or infiltrate the ground, reaching subsurface soils and
aquifers.
To evaluate potential health impacts from spills or releases of additives, fracturing fluid
containing diluted additives or residual diluted additive chemicals in flowback water, the
NYSDOH reviewed the composition of additives proposed for high-volume hydraulic fracturing
in New York. The NYSDOH concluded that the proposed additives contain similar types of
chemical constituents as the products that have been used for many years for hydraulic fracturing
of traditional vertical wells in NYS. Some of the same products are used in both well types. The
total amount of fracturing additives and water used in hydraulic fracturing of horizontal wells is
considerably larger than for traditional vertical wells. This suggests the potential environmental
consequences of an upset condition could be proportionally larger for horizontal well drilling and
fracturing operations. As mentioned earlier, the 1992 GEIS addressed hydraulic fracturing in
Chapter 9, and NYSDOH’s review did not identify any potential exposure situations associated
with horizontal drilling and high-volume hydraulic fracturing that are qualitatively different from
those addressed in the 1992 GEIS.

Final SGEIS 2015, Page 6-15

 6.1.3.1 Drilling
Contamination of surface water bodies and groundwater resources during well drilling could
occur as a result of failure to maintain stormwater controls, ineffective site management and
inadequate surface and subsurface fluid containment practices, poor casing construction, or
accidental spills and releases including well blow-outs during drilling or well component failures
during completion operations. A release could also occur during a blow-out event if there are
not trained personnel on site that are educated in the proper use of the BOP system. Surface
spills would involve materials and fluids present at the site during the drilling phase. Pit leakage
or failure could also involve well fluids. These issues are discussed in Chapters 8 and 9 of the
1992 GEIS, but are acknowledged here with respect to unique aspects of the proposed multi-well
development method. The conclusions regarding pit construction standards and liner
specifications presented in the 1992 GEIS were largely based upon the short duration of a pit’s
use. The greater intensity and duration of surface activities associated with well pads with
multiple wells increases the potential for an accidental spill, pit leak or pit failure if engineering
controls and other mitigation measures are not sufficient. Concerns are heightened if on-site pits
for handling drilling fluids are located in primary and principal aquifer areas, or are constructed
on the filled portion of a cut-and-filled well pad.
6.1.3.2 Hydraulic Fracturing Additives
As with the drilling phase, contamination of surface water bodies and groundwater resources
during well stimulation could occur as a result of failure to maintain stormwater controls,
ineffective site management and surface and subsurface fluid containment practices, poor well
construction and grouting, or accidental spills and releases including failure of wellhead
components during hydraulic fracturing. These issues are discussed in Chapters 8 and 9 of the
1992 GEIS, but are acknowledged here because of the larger volumes of fluids and materials to
be managed for high-volume hydraulic fracturing. The potential contaminants are listed in Table
5.7 and grouped into categories recommended by NYSDOH in Table 5.8. URS compared the
list of additive chemicals to the parameters regulated via federal and state primary or secondary
drinking water standards, SPDES discharge limits (see Section 7.1.8), and DOW Technical and
Operational Guidance Series 1.1.1 (TOGS111), Ambient Water Quality Standards and Guidance

Final SGEIS 2015, Page 6-16

 Values and Groundwater Effluent Limitations. 276,277 In NYS, the state drinking water standards
(10 NYCRR 5) apply to all public water supplies and set maximum contaminant levels (MCLs)
for essentially all organic chemicals in public drinking water. See Table 6.1.
6.1.3.3 Flowback Water and Production Brine
Gelling agents, surfactants and chlorides are identified in the 1992 GEIS as the flowback water
components of greatest environmental concern. 278 Other flowback components can include other
dissolved solids, metals, biocides, lubricants, organics and radionuclides. Opportunities for
spills, leaks, and operational errors during the flowback water recovery stage are the same as
they are during the prior stages with additional potential releases from:
•

hoses or pipes used to convey flowback water to tanks or a tanker truck for transportation
to a treatment or disposal site; and

•

tank leakage.

In general, flowback water is water and associated chemical constituents returning from the
borehole during or proximate in time to hydraulic fracturing activities. Production brine, on the
other hand, is fluid that returns from the borehole after completion of drilling operations while
natural gas production is underway. The chemical characteristics and volumes of flowback
water and production brine are expected to differ in significant respects.
Flowback water composition based on a limited number of out-of-state samples from Marcellus
wells is presented in Table 5.9. A comparison of detected flowback parameters, except
radionuclides, to regulated parameters is presented in Table 6.1. 279
Table 5.10 lists parameters found in the flowback analyses, except radionuclides, that are
regulated in New York. The number of samples that were analyzed for the particular parameter
is shown in Column 3, and the number of samples in which parameters were detected is shown in
Column 4. The minimum, median and maximum concentrations detected are indicated in
276

URS, 2009, p. 4-18, et seq.

277

http://www.dec.ny.gov/regulations/2652.html.

278

NYSDEC, 1992, GEIS, p. 9-37.

279

URS, 2009, p. 4-18, et seq.

Final SGEIS 2015, Page 6-17

 Columns 5, 6 and 7. 280 Radionuclides data is presented in Chapter 5, and potential impacts and
regulation are discussed in Section 6.7.
Table 5.11 lists parameters found in the flowback analyses that are not regulated in New York.
Column 2 shows the number of samples that were analyzed for the particular parameter; column
3 indicates the number of samples in which the parameter was detected. 281
Information presented in Tables 5.10 and 5.11 are based on limited data from Pennsylvania and
West Virginia. Samples were not collected specifically for this type of analysis or under the
Department’s oversight. Characteristics of flowback from the Marcellus Shale in New York are
expected to be similar to flowback from Pennsylvania and West Virginia, but not identical. The
raw data for these tables came from several sources, with likely varying degrees of reliability,
and the analytical methods used were not all the same for given parameters. Sometimes,
laboratories need to use different analytical methods depending on the consistency and quality of
the sample; sometimes the laboratories are only required to provide a certain level of accuracy.
Therefore, the method detection limits may be different. The quality and composition of
flowback from a single well can also change within a few days after the well is fractured. This
data does not control for any of these variables. 282

280

URS, 2009, pp. 4-10, 4-31 et seq.

281

URS, 2009, pp. 4-10, p. 4-35.

282

URS, 2009, p. 4-31.

Final SGEIS 2015, Page 6-18

 Table 6.1 - Comparison of additives used or proposed for use in NY, parameters detected in analytical results of flowback
from the Marcellus operations in PA and WV and parameters regulated via primary and secondary drinking water standards,
SPDES or TOGS111 (Revised August 2011) 283, 284

CAS
Number
106-24-1

Parameter Name

Used in
285
Additives ,
286

(2E)-3,7-dimethylocta-2,6-dien-1-ol

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

Yes

TOGS111
Tables

NYS MCL,
291
(mg/L)
0.05

283

Table 6.1 was compiled by URS Corporation, 2011 and revised by the Department in coordination with NYSDOH.

284

This table includes parameters detected in the MSC Study.

285

Information in the “Used in Additives” column is based on the composition of additives used or proposed for use in New York.

286

Parameters marked with ¥ indicates that the compound dissociates, and its components are separately regulated. Not all dissociating compounds are marked.

287

Information in the “Found in Flowback” column is based on analytical results of flowback from operations in Pennsylvania or West Virginia. There are/may be products used
in fracturing operations in Pennsylvania that have not yet been proposed for use in New York for which, therefore, the Department does not have chemical composition data.
Blank entries in the “Found in Flowback” column indicate that the parameter was either not sampled for or not detected in the flowback.

288

USEPA Maximum Contaminant Level (MCL) - The highest level of a contaminant that is allowed in drinking water. MCLs are set as close to MCLGs as feasible using the
best available treatment technology and taking cost into consideration. MCLs are enforceable standards. From USEPA Title 40, Part 141--National Primary Drinking Water
Regulations.

289

USEPA Treatment Technique (TT) – A required process intended to reduce the level of a contaminant in drinking water. From USEPA Title 40, Part 141 – National Primary
Drinking Water Regulations.

290

SPDES or TOGS typically regulates or provides guidance for the total substance, (e.g., iron) and rarely regulates or provides guidance for only its dissolved portion (e.g.,
dissolved iron). The dissolved component is implicitly covered in the total substance. Therefore, the dissolved component is not included in this table. Flowback analyses
provided information for the total and dissolved components of metals. Understanding the dissolved vs. suspended portions of a substance is valuable when determining
potential treatment techniques.

291

10 NYCRR Part 5-1.50 through 5-1.52. Under 10 NYCRR Part 5, organic contaminants (with very few exceptions) have either a Specific MCL (28 compounds plus 1
chemical mixture) or a General MCL of 0.05 mg/L for Unspecified Organic Contaminants (UOC) or 0.005 mg/L for Principal Organic Contaminants (POC). A total UOC +
POC MCL of 0.1 mg/L also applies to all organic contaminants in drinking water. 10 NYCRR Part 5 also contains 23 MCLs for inorganic contaminants. A section sign (§)
indicates that, for organic salts, the free compound (the expected form in drinking water) would be a UOC, but that salts themselves would not be UOC. A double section sign
(§§) indicates that, for parameters listed as a group or mixture of related chemicals (e.g., Ethoxylated alcohol (C14-15), petroleum distillates, essential oils) a state MCL does
not apply to the group as a whole, but would apply to each individual component of the group if detected in drinking water. A triple section sign (§§§) indicates that, for
parameters listed as a polymer, the UOC MCL would apply to the polymer itself, but either the UOC or POC MCL would apply to the individual monomer components. An
asterisk (*) indicates that the total trihalomethane (THM) MCL of 0.08 mg/L also applies.

Final SGEIS 2015, Page 6-19

 CAS
Number

67701-10-4
02634-33-5
00087-61-6
00095-63-6
93858-78-7
00108-67-8
00123-91-1
03452-07-1
00629-73-2
104-46-1
124-28-7

112-03-8
00112-88-9
40623-73-2
01120-36-1
98-55-5
10222-01-2
27776-21-2
73003-80-2
00105-67-9
00087-65-0
15214-89-8
46830-22-2
00052-51-7
00111-76-2

Parameter Name

Used in
285
Additives ,
286

(C8-C18) And (C18) Unsaturated
Alkylcarboxylic Acid Sodium Salt
1,2 Benzisothiazolin-2-one / 1,2benzisothiazolin-3-one
1,2,3-Trichlorobenzene
1,2,4-Trimethylbenzene
1,2,4-Butanetricarboxylicacid, 2-phosphono-,
potassium salt
1,3,5-Trimethylbenzene
1,4 Dioxane
1-eicosene
1-hexadecene
1-Methoxy-4-propenylbenzene
1-Octadecanamine, N, N-dimethyl- / N,NTimethyloctadecylamine
1-Octadecanaminium, N,N,N-Trimethyl-,
Chloride /Trimethyloctadecylammonium
chloride
1-octadecene
1-Propanesulfonic acid
1-tetradecene
2-(4-methyl-1-cyclohex-3-enyl)propan-2-ol
2,2 Dibromo-3-nitrilopropionamide
2,2'-azobis-{2-(imidazlin-2-yl)propane}dihydrochloride
2,2-Dibromomalonamide
2,4-Dimethylphenol
2,6-Dichlorophenol
2-Acrylamido-2-methylpropanesulphonic acid
sodium salt polymer
2-acryloyloxyethyl(benzyl)dimethylammonium
chloride
2-Bromo-2-nitro-1,3-propanediol
2-Butoxy ethanol /Ethylene glycol monobutyl
ether / Butyl Cellusolve

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

NYS MCL,
291
(mg/L)

Yes

§,§§

Yes

0.05

Yes

Yes
Yes

Table 9
Table 9

Tables 1,5
Tables 1,5

Yes

0.005
0.005
0.05

Yes
Yes
Yes
Yes
Yes

Tables 9,10
Table 8

Tables 1,5

0.005
0.05
0.05
0.05
0.05

Yes

0.05

Yes

0.05

Yes
Yes
Yes
Yes
Yes

0.05
0.05
0.05
0.05
Table 9

Tables 1,5

Yes

0.05

Yes

0.05
0.05
0.005

Yes
Yes

Table 6
Table 8

Tables 1,5

Yes

0.05

Yes

0.05

Yes
Yes

Final SGEIS 2015, Page 6-20

Table 10
0.05

 CAS
Number
01113-55-9
00104-76-7
00091-57-6
00095-48-7
109-06-8
00067-63-0
26062-79-3
95077-68-2
09003-03-6
25987-30-8
71050-62-9
66019-18-9
00107-19-7
51229-78-8
106-22-9
5392-40-5
00115-19-5
00108-39-4
104-55-2
127-41-3
00072-55-9
121-33-5
00106-44-5
127087-87-0

Parameter Name

Used in
285
Additives ,
286

2-Dibromo-3-Nitriloprionamide / 2Monobromo-3-nitrilopropionamide
2-Ethyl Hexanol
2-Methylnaphthalene
2-Methylphenol
2-Picoline (2-methyl pyridine)
2-Propanol / Isopropyl Alcohol / Isopropanol /
Propan-2-ol
2-Propen-1-aminium, N,N-dimethyl-N-2propenyl-chloride, homopolymer
2-Propenoic acid, homopolymer sodium salt
2-propenoic acid, homopolymer, ammonium
salt
2-Propenoic acid, polymer with 2 ppropenamide, sodium salt / Copolymer of
acrylamide and sodium acrylate
2-Propenoic acid, polymer with sodium
phosphinate (1:1)
2-propenoic acid, telomer with sodium
hydrogen sulfite
2-Propyn-1-ol / Progargyl Alcohol
3,5,7-Triaza-1azoniatricyclo[3.3.1.13,7]decane, 1-(3-chloro2-propenyl)-chloride,
3,7 - dimethyl-6-octen-1-ol
3,7-dimethyl-2,6-octadienal
3-methyl-1-butyn-3-ol
3-Methylphenol
3-phenyl-2-propenal
4-(2,6,6-trimethyl-1-cyclohex-2-enyl)-3-buten2-one
4,4 DDE
4-hydroxy-3-methoxybenzaldehyde
4-Methylphenol
4-Nonylphenol Polyethylene Glycol Ether
Branched / Nonylphenol ethoxylated /
Oxyalkylated Phenol

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

Yes

0.05

Yes

Yes

NYS MCL,
291
(mg/L)

Yes
Yes
Yes

Table 8
Table 8
Table 8

Yes

Table 10

Tables 1,3
Table 3

0.05
0.05
0.05
0.05
0.05

Yes

0.05

Yes

0.05

Yes

0.05

Yes

0.05

Yes

0.05

Yes

0.05

Yes

0.05

Yes

0.05

Yes
Yes
Yes
Yes

0.05
0.005
0.05
0.05
0.005

Yes

0.05

Yes

Table 8

Yes

Table 6

Yes

Table 8

Yes

Yes

Final SGEIS 2015, Page 6-21

Tables 1,5

0.005
0.05
0.05
0.05

 CAS
Number
00057-97-6
00064-19-7
68442-62-6
00108-24-7
00067-64-1
00098-86-2
00079-06-1
38193-60-1
25085-02-3
69418-26-4
15085-02-3
00107-13-1
68891-29-2
68526-86-3
68551-12-2
00309-00-2

64742-47-8

64743-02-8
68439-57-6

09016-45-9
07439-90-5
01327-41-9

Parameter Name
7,12-Dimethylbenz(a)anthracene
Acetic acid
Acetic acid, hydroxy-, reaction products with
triethanolamine
Acetic Anhydride
Acetone
Acetophenone
Acrylamide
Acrylamide - sodium 2-acrylamido-2methylpropane sulfonate copolymer
Acrylamide - Sodium Acrylate Copolymer or
Anionic Polyacrylamide
Acrylamide polymer with N,N,N-trimethyl2[1-oxo-2-propenyl]oxy Ethanaminium
chloride
Acrylamide-sodium acrylate copolymer
Acrylonitrile
Alcohols C8-10, ethoxylated, monoether with
sulfuric acid, ammonium salt
Alcohols, C11-14-iso-, C13-rich
Alcohols, C12-C16, Ethoxylated (a.k.a.
Ethoxylated alcohol)
Aldrin
Aliphatic acids
Aliphatic alcohol glycol ether
Aliphatic Hydrocarbon / Hydrotreated light
distillate / Petroleum Distillates / Isoparaffinic
Solvent / Paraffin Solvent / Napthenic Solvent
Alkalinity, Carbonate, as CaCO3
Alkenes
Alkyl (C14-C16) olefin sulfonate, sodium salt
Alkyl Aryl Polyethoxy Ethanol
Alkylaryl Sulfonate
Alkylphenol ethoxylate surfactants
Aluminum
Aluminum chloride

Used in
285
Additives ,

Found in
Flowback

286

287

Yes

Yes
Yes

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

NYS MCL,
291
(mg/L)

Table 8
Table 10

Table 3

0.05
0.05

Yes
Yes
Yes

0.05
Table 10
Table 7

Yes
Yes

Yes

TT

Table 9

Tables 1,5
Table 3
Tables 1,5

0.05
0.05
0.05
0.005

Yes

0.05

Yes

0.05

Yes

0.05

Yes

0.05
Yes

Table 6

Tables 1,5

Yes

§,§§

Yes

§§

Yes

§§
Yes

Tables 1,5

Yes
Yes

§§
0.05

Yes

§§
Yes

Table 10

Yes
Yes
Yes
Yes
Yes

§§
0.05
0.05
0.05
§§
Yes

Yes (¥)

Final SGEIS 2015, Page 6-22

Table 7

Tables 1,5

 CAS
Number

Parameter Name

286

68155-07-7
73138-27-9

Amides, C8-18 and C19-Unsatd., N,NBis(hydroxyethyl)
Amines, C12-14-tert-alkyl, ethoxylated

71011-04-6

Amines, Ditallow alkyl, ethoxylated

68551-33-7
01336-21-6
00631-61-8
68037-05-8
07783-20-2
10192-30-0
12125-02-9
07632-50-0
37475-88-0
01341-49-7
06484-52-2

Amines, tallow alkyl, ethoxylated, acetates
Ammonia
Ammonium acetate
Ammonium Alcohol Ether Sulfate
Ammonium bisulfate
Ammonium Bisulphite
Ammonium Chloride
Ammonium citrate
Ammonium Cumene Sulfonate
Ammonium hydrogen-difluoride
Ammonium nitrate
Ammonium Persulfate / Diammonium
peroxidisulphate
Ammonium Thiocyanate
Anionic copolymer
Antimony
Aqueous ammonia
Aroclor 1248
Aromatic hydrocarbons
Aromatic ketones
Arsenic
Attapulgite Clay
Barium
Barium Strontium P.S. (mg/L)
Bentonite, benzyl(hydrogenated tallow alkyl)
dimethylammonium stearate complex /
organophilic clay
Benzene
Benzene, 1,1'-oxybis, tetratpropylene
derivatives, sulfonated, sodium salts

07727-54-0
01762-95-4
07440-36-0
07664-41-7
12672-29-6

07440-38-2
12174-11-7
07440-39-3

121888-68-4
00071-43-2
119345-04-9

Used in
285
Additives ,

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

NYS MCL,
291
(mg/L)

Yes

§§

Yes

§§
§§
§§

Yes
Yes
Yes
Yes
Yes (¥)
Yes (¥)
Yes (¥)
Yes (¥)
Yes (¥)
Yes (¥)
Yes (¥)
Yes (¥)

Yes
Table 10

§
0.05

Table 10
§
§

Yes (¥)
Yes
Yes
Yes

Table 10
Yes
Yes
Yes

0.006

Table 6
Table 7
Table 6

Tables 1,5
Tables 1,5

0.01

Table 6

Tables 1,5

0.0005
§§
§§
0.01

Yes
Yes
Yes

2

Table 7

Tables 1,5

2

Yes

0.005

Table 6

Tables 1,5

0.005

Yes
Yes

0.006

Yes

Yes
Yes
Yes

Final SGEIS 2015, Page 6-23

0.05

 CAS
Number

74153-51-8
122-91-8
1300-72-7
00050-32-8
00205-99-2
00191-24-2
00207-08-9
140-11-4
00100-51-6
07440-41-7
76-22-2
00111-44-4
00117-81-7
68153-72-0
68876-82-4
1319-33-1
10043-35-3
01303-86-2
07440-42-8
24959-67-9
00075-25-2
00071-36-3
68002-97-1
68131-39-5
07440-43-9
07440-70-2
1317-65-3
10043-52-4

Parameter Name

Used in
285
Additives ,
286

Benzenemethanaminium, N,N-dimethyl-N-[2[(1-oxo-2-propenyl)oxy]ethyl]-, chloride,
polymer with 2-propenamide
Benzenemethanol,4-methoxy-, 1-formate
Benzenesulfonic acid, Dimethyl-, Sodium salt
(aka Sodium xylene sulfonate)
Benzo(a)pyrene
Benzo(b)fluoranthene
Benzo(ghi)perylene
Benzo(k)fluoranthene
Benzyl acetate
Benzyl alcohol
Beryllium
Bicarbonates (mg/L)
Bicyclo (2.2.1) heptan-2-one, 1,7,7-trimethylBiochemical Oxygen Demand
Bis(2-Chloroethyl) ether
Bis(2-ethylhexyl)phthalate / Di(2ethylhexyl)phthalate
Blown lard oil amine
Blown rapeseed amine
Borate Salt
Boric acid
Boric oxide / Boric Anhydride
Boron
Bromide
Bromoform
Butan-1-ol
C10 - C16 Ethoxylated Alcohol
C12-15 Alcohol, Ethoxylated
Cadmium
Calcium
Calcium Carbonate
Calcium chloride

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

NYS MCL,
291
(mg/L)

Yes

0.05

Yes

0.05

Yes

0.05
Yes
Yes
Yes
Yes

Table 6

Yes
Yes
Yes

Table 8
Table 6
Table 10

Table 6
Table 6

Tables 1,5
Table 3
Tables 1,5

Yes
0.004

Table 3
Tables 1,5

Yes

0.0002
0.05
0.05
0.05
0.05
0.05
0.004
0.05

Yes
Yes
Yes

0.006

Yes
Table 6

Tables 1,5

0.005

Table 6

Tables 1,5

0.006

Yes
Yes
Yes
Yes
Yes

§§
§§

Yes
Yes
Yes

Table 7
Table 7
Table 6
Table 10

Yes
Yes
Yes
Yes
Yes

0.005

Yes
Yes (¥)

Final SGEIS 2015, Page 6-24

Table 6
Table 8
Table 10

Tables 1,5
Tables 1,5
Tables 1,5
Tables 1,5

Tables 1,5

0.005*
§§
§§
0.005

 CAS
Number
1305-62-0
1305-79-9
00124-38-9
00075-15-0
68130-15-4
09012-54-8
09004-34-6

10049-04-4
00124-48-1
00067-66-3
78-73-9
67-48-1
91-64-5
07440-47-3
00077-92-9
94266-47-4
07440-48-4
61789-40-0
68155-09-9
68424-94-2

Parameter Name

Used in
285
Additives ,
286

Calcium Hydroxide
Calcium Peroxide
Carbon Dioxide
Carbondisulfide
Carboxymethylhydroxypropyl guar
Cellulase / Hemicellulase Enzyme
Cellulose

Yes
Yes
Yes

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

Yes
Yes

SPDES
290
Tables

TOGS111
Tables

Table 8

Tables 1,5

Yes
Yes
Yes

Cesium 137

Yes

Chemical Oxygen Demand
Chloride
Chlorine Dioxide
Chlorodibromomethane
Chloroform
Choline Bicarbonate
Choline Chloride
Chromen-2-one
Chromium
Citric Acid
Citrus Terpenes
Cobalt
Cocamidopropyl Betaine
Cocamidopropylamine Oxide
Coco-betaine
Coliform, Total
Color

Yes
Yes
Yes

§§§
§§§
§§§
Via beta
radiation

Via beta
radiation

MRDL=0.8
Yes
Yes

Yes
Table 7
Table 10
Table 6
Table 6

Tables 1,5
Tables 1,5
Tables 1,5

Yes
Yes
Yes
Yes

0.1

Table 6

Tables 1,5

Table 7

Table 1

Yes
Yes
Yes
Yes
Yes
Yes

Copper

07758-98-7

Copper (II) Sulfate

14808-60-7

Crystalline Silica (Quartz)

Yes

07447-39-4
00057-12-5

Cupric chloride dihydrate
Cyanide

Yes (¥)

250
MRDL=0.8
0.005*
0.005*
§
§
0.05
0.1
0.05
§§
0.05
0.05
0.05

Yes
Yes

07440-50-8

NYS MCL,
291
(mg/L)

Yes

0.05
TT;
Action
Level=1.3

Table 7
Table 7
Table 6

Tables 1,5

Action Level
= 1.3

Table 6

Tables 1,5

0.2

Yes (¥)
Via solids
and TSS
Yes

0.2

Final SGEIS 2015, Page 6-25

 CAS
Number
00319-85-7
00058-89-9
1490-04-6
8007-02-1
8000-29-1
01120-24-7
02605-79-0
00055-70-3
03252-43-5
00075-27-4
25340-17-4
00111-46-6
22042-96-2
28757-00-8
68607-28-3
07398-69-8
00084-74-2
00122-39-4
25265-71-8
34590-94-8
00139-33-3
64741-77-1
05989-27-5
00123-01-3
27176-87-0
42504-46-1
00050-70-4
37288-54-3
00959-98-8
33213-65-9
07421-93-4
149879-98-1

Parameter Name

Used in
285
Additives ,
286

Cyclohexane (beta BHC)
Cyclohexane (gamma BHC)
Cyclohexanol,5-methyl-2-(1-methylethyl)
Cymbopogon citratus leaf oil
Cymbopogon winterianus jowitt oil
Decyldimethyl Amine
Decyl-dimethyl Amine Oxide
Dibenz(a,h)anthracene
Dibromoacetonitrile
Dichlorobromomethane
Diethylbenzene
Diethylene Glycol
Diethylenetriamine penta (methylenephonic
acid) sodium salt
Diisopropyl naphthalenesulfonic acid
Dimethylcocoamine, bis(chloroethyl) ether,
diquaternary ammonium salt
Dimethyldiallylammonium chloride
Di-n-butyl phthalate
Diphenylamine
Dipropylene glycol
Dipropylene glycol methyl ether
Disodium Ethylene Diamine Tetra Acetate
Distillates, petroleum, light hydrocracked
D-Limonene
Dodecylbenzene
Dodecylbenzene sulfonic acid
Dodecylbenzenesulfonate isopropanolamine
D-Sorbitol / Sorbitol
Endo-1,4-beta-mannanase, or Hemicellulase
Endosulfan I
Endosulfan II
Endrin aldehyde
Erucic Amidopropyl Dimethyl Betaine

Found in
Flowback
287

Yes
Yes

USEPA
MCL or TT
288,
(mg/L)
289

0.0002

SPDES
290
Tables

TOGS111
Tables

NYS MCL,
291
(mg/L)

Table 6
Table 6

Tables 1,5
Tables 1,5

Table 9
Table 6

Table 3
Tables 1
Tables 1,5

0.005
0.0002
0.05
§§
§§
0.05
0.05
0.05
0.05
0.005*
0.05
0.05

Yes
Yes
Yes
Yes (¥)
Yes (¥)
Yes
Yes
Yes
Yes
Yes

Table 10

Yes

0.05

Yes

0.05

Yes

0.05

Yes
Yes
Yes

Table 6
Table 7

Tables 1,5
Tables 1,5

Yes
Yes
Yes

Table 6
Table 6
Table 6

Table 3
Table 3
Tables 1,5

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Yes

Final SGEIS 2015, Page 6-26

0.05
0.05
0.005
0.05
0.05
0.05
§§
0.05
0.05
0.05
0.05
0.05
0.05
0.05
0.05
0.005
0.05

 CAS
Number
00089-65-6
54076-97-0
00107-21-1
111-42-2
26027-38-3
09002-93-1
68439-50-9
126950-60-5
68951-67-7
68439-46-3
66455-15-0
67254-71-1
84133-50-6
68439-51-0
78330-21-9
34398-01-1
78330-21-8
61791-12-6
61791-29-5

Parameter Name

Used in
285
Additives ,
286

Erythorbic acid, anhydrous
Ethanaminium, N,N,N-trimethyl-2-[(1-oxo-2propenyl)oxy]-, chloride, homopolymer
Ethane-1,2-diol / Ethylene Glycol

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

NYS MCL,
291
(mg/L)

Yes

0.05

Yes

0.05

Yes

Yes

Table 7

Tables 1,5

0.05

Yes

0.05

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

0.05
0.05
§§
§§
§§
§§
§§
§§
§§
§§
§§
§§
§§
§§
§§

Yes

§§

Yes

§§

68439-45-2

Ethanol, 2,2-iminobisEthoxylated 4-nonylphenol
Ethoxylated 4-tert-octylphenol
Ethoxylated alcohol
Ethoxylated alcohol
Ethoxylated alcohol (C14-15)
Ethoxylated alcohol (C9-11)
Ethoxylated Alcohols
Ethoxylated Alcohols (C10-12)
Ethoxylated Alcohols (C12-14 Secondary)
Ethoxylated Alcohols (C12-14)
Ethoxylated branch alcohol
Ethoxylated C11 alcohol
Ethoxylated C11-14-iso, C13-rich alcohols
Ethoxylated Castor Oil
Ethoxylated fatty acid, coco
Ethoxylated fatty acid, coco, reaction product
with ethanolamine
Ethoxylated hexanol

09036-19-5

Ethoxylated octylphenol

Yes

0.05

09005-67-8
09005-70-3
118-61-6
00064-17-5
00100-41-4
93-89-0
00097-64-3

Ethoxylated Sorbitan Monostearate
Ethoxylated Sorbitan Trioleate
Ethyl 2-hydroxybenzoate
Ethyl alcohol / ethanol
Ethyl Benzene
Ethyl benzoate
Ethyl Lactate

Yes
Yes
Yes
Yes
Yes
Yes
Yes

0.05
0.05
0.05
0.05
0.005
0.05
0.05

61791-08-0

Yes

0.7

Final SGEIS 2015, Page 6-27

Table 6

Tables 1,5

 CAS
Number
09003-11-6
00075-21-8
05877-42-9
8000-48-4
61790-12-3

Parameter Name

286

Ethylene Glycol-Propylene Glycol Copolymer
(Oxirane, methyl-, polymer with oxirane)
Ethylene oxide
Ethyloctynol

00075-12-7
00064-18-6
00110-17-8
65997-17-3
00111-30-8
00056-81-5
09000-30-0
64742-94-5
09025-56-3

Eucalyptus globulus leaf oil
Fatty Acids
Fatty acids, C 8-18 and C18-unsaturated
compounds with diethanolamine
Fatty acids, tall oil reaction products w/
acetophenone, formaldehyde & thiourea
Fatty alcohol polyglycol ether surfactant
Ferric chloride
Ferrous sulfate, heptahydrate
Fluoranthene
Fluorene
Fluoride
Formaldehyde
Formaldehyde polymer with 4,1,1dimethylethyl phenolmethyl oxirane
Formaldehyde, polymers with branched 4nonylphenol, ethylene oxide and propylene
oxide
Formamide
Formic acid
Fumaric acid
Glassy calcium magnesium phosphate
Glutaraldehyde
Glycerol / glycerine
Guar Gum
Heavy aromatic petroleum naphtha
Hemicellulase

00076-44-8
01024-57-3

Heptachlor
Heptachlor epoxide

68604-35-3
68188-40-9
09043-30-5
07705-08-0
07782-63-0
00206-44-0
00086-73-7
16984-48-8
00050-00-0
29316-47-0
153795-76-7

Used in
285
Additives ,

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

Yes

NYS MCL,
291
(mg/L)
0.05

Yes
Yes
Yes
Yes

Table 9

Tables 1,5

0.05
0.05
§§
§§

Yes

§§

Yes

§§

Yes
Yes
Yes

§§
Table 10
Yes
Yes
Yes

4

Yes

Table 6
Table 6
Table 7
Table 8

Tables 1,5
Tables 1,5
Tables 1,5
Tables 1,5

0.05
0.05
2.2

Yes

0.05

Yes

0.05

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

0.05
0.05
0.05

Table 10
Table 10

Yes
Yes

0.0002
0.0002

Final SGEIS 2015, Page 6-28

Tables 1,5
Tables 1,5

0.05
0.05
0.05
0.05
0.05
0.0004
0.0002

 CAS
Number

07647-01-0
07722-84-1
64742-52-5
00079-14-1
35249-89-9
09004-62-0
05470-11-1
39421-75-5
00193-39-5
07439-89-6
35674-56-7

Parameter Name

Used in
285
Additives ,
286

Heterotrophic plate count
Hydrochloric Acid / Hydrogen Chloride /
muriatic acid
Hydrogen Peroxide
Hydrotreated heavy napthenic distillate
Hydroxy acetic acid
Hydroxyacetic acid ammonium salt
Hydroxyethyl cellulose
Hydroxylamine hydrochloride
Hydroxypropyl guar

§§

Yes
Yes

64742-95-6
01120-21-4

Light aromatic solvent naphtha
Light Paraffin Oil
Lithium
Magnesium
Magnesium Carbonate
Magnesium Oxide

07439-95-4
546-93-0
1309-48-4

292

Table 10

Yes

Yes

Lead

NYS MCL,
291
(mg/L)

Yes

Lactose

07439-92-1

TOGS111
Tables

292

Yes
Yes

Kerosine, hydrodesulfurized
Lavandula hybrida abrial herb oil

TT

SPDES
290
Tables

§§
0.05
0.05
0.05
0.05
0.05
0.05
0.3
0.05

00063-42-3
8022-15-9

289

Yes
Yes
Yes
Yes
Yes
Yes
Yes

64742-81-0

68909-80-8

USEPA
MCL or TT
288,
(mg/L)

Yes

08008-20-6

00064-63-0
00098-82-8

287

Yes

Indeno(1,2,3-cd)pyrene
Iron
Isomeric Aromatic Ammonium Salt
Isoparaffinic Petroleum Hydrocarbons,
Synthetic
Isopropanol
Isopropylbenzene (cumene)
Isoquinoline, reaction products with benzyl
chloride and quinoline
Kerosene

64742-88-7

Found in
Flowback

Yes
Yes

Table 6
Table 7

Table 10
Table 9

Yes

Tables 1,5
Tables 1,5

Tables 1,5

0.05
0.005

Yes

0.05

Yes

§§
§§
§§
Yes

TT;
Action Level
0.015

Table 6

Tables 1,5

Yes
Yes

Action level
= 0.015
§§
§§

Yes
Yes
Yes
Yes

Treatment Technology specified.

Final SGEIS 2015, Page 6-29

Table 10
Table 7

Tables 1,5

 CAS
Number

Parameter Name

Used in
285
Additives ,
286

287

USEPA
MCL or TT
288,
(mg/L)

Yes
Yes

0.002

Found in
Flowback

289

SPDES
290
Tables

TOGS111
Tables

NYS MCL,
291
(mg/L)

Table 7
Table 6

Tables 1,5
Tables 1,5

0.3
0.002
0.05
0.05
0.05
0.005
0.005
0.05

1335-26-8
14807-96-6
07439-96-5
07439-97-6
01184-78-7
00067-56-1

Magnesium Peroxide
Magnesium Silicate Hydrate (Talc)
Manganese
Mercury
Methanamine, N,N-dimethyl-, N-oxide
Methanol

119-36-8
00074-83-9
00074-87-3

Methyl 2-hydroxybenzoate
Methyl Bromide
Methyl Chloride / chloromethane

00078-93-3

64742-48-9

Methyl ethyl ketone / 2-Butanone
Methyloxirane polymer with oxirane, mono
(nonylphenol) ether, branched
Mineral spirits / Stoddard Solvent
Mixture of severely hydrotreated and
hydrocracked base oil
Molybdenum
Monoethanolamine
N,N,N-trimethyl-2[1-oxo-2-propenyl]oxy
Ethanaminium chloride
Naphtha (petroleum), hydrotreated heavy

00091-20-3

Naphthalene

Yes

38640-62-9
00093-18-5
68909-18-2

Naphthalene bis(1-methylethyl)
Naphthalene, 2-ethoxyN-benzyl-alkyl-pyridinium chloride
N-Cocoamidopropyl-N,N-dimethyl-N-2hydroxypropylsulfobetaine
Nickel

Yes
Yes
Yes

0.05
0.05
0.05

Yes

0.05

68891-11-2
08052-41-3
64742-46-7
07439-98-7
00141-43-5
44992-01-0

68139-30-0
07440-02-0

Yes
Yes

Yes
Yes
Yes

Yes
Yes
Yes

00086-30-6
26027-38-3

Nitrogen, Liquid form
Nitrogen, Total as N
N-Nitrosodiphenylamine
Nonylphenol Ethoxylate

Table 10

0.005

Table 6
Table 6
Table 7

Tables 1,5
Tables 1,5
Tables 1,5

Yes

0.05

Yes

§§

Yes

§§
Yes

Table 7

Yes

0.05

Yes

0.05

Yes

§§
Yes

Table 6

Yes

Nitrate, as N
07727-37-9

Yes

Yes

10

Tables 1,5

Table 6

Tables 1,5

Table 7

Tables 1,5

Table 6

Table 5
Tables 1,5

0.05

10

Yes
Yes
Yes
Yes

Final SGEIS 2015, Page 6-30

0.05
0.05

 CAS
Number
68412-54-4
8000-27-9
121888-66-2
628-63-7
540-18-1
8009-03-8
64742-65-0
64742-52-5
64741-68-0
00085-01-8
00108-95-2

Parameter Name

Used in
285
Additives ,
286

Nonylphenol Polyethoxylate
Oil and Grease

Yes

Oils, cedarwood
Organophilic Clays
Oxyalkylated alkylphenol

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Pentyl acetate
Pentyl butanoate
Petrolatum
Petroleum Base Oil
Petroleum distillate blend
Petroleum Distillates
Petroleum hydrocarbons
Petroleum naphtha
pH

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

NYS MCL,
291
(mg/L)
0.05

Yes

Table 5
§§
0.05
0.05
0.05
§§
§§
§§

Yes
Yes

0.05
Yes
Yes
Yes
Yes

Phenanthrene
Phenol
Phenols

Table 6
Table 6
Table 6

Table 5
Tables 1,5
Tables 1,5
Tables 1,5

0.05
0.05

Yes

0.05

Yes

§

57723-14-0

Phenoxybenzene
Phosphonic acid,
[[(phosphonomethyl)imino]bis[2,1ethanediylnitrilobis(methylene)]]tetrakis-,
ammonium salt
Phosphorus

08000-41-7

Pine Oil

Yes

§§

Pine oils
Poly(oxy-1,2-ethanediyl), a-[3,5-dimethyl-1(2-methylpropyl)hexyl]-w-hydroxyPoly(oxy-1,2-ethanediyl), a-hydro-w-hydroxy /
Polyethylene Glycol
Poly(oxy-1,2-ethanediyl), α-tridecyl- ωhydroxy

Yes

§§

Yes

§§§

Yes

§§§

Yes

§§§

Yes

§§§

101-84-8
70714-66-8

8002-09-3
60828-78-6
25322-68-3
24938-91-8
31726-34-8

Poly(oxy-1,2-ethanediyl),alpha-hexyl-omegahydroxy

Yes

Final SGEIS 2015, Page 6-31

Table 7

Table 1

 CAS
Number
9004-32-4
51838-31-4
56449-46-8
9046-01-9
63428-86-4
62649-23-4
09005-65-6
61791-26-2
65997-18-4
07440-09-7
00127-08-2
1332-77-0
12712-38-8
20786-60-1
00584-08-7
07447-40-7
00590-29-4
01310-58-3
13709-94-9
24634-61-5
112926-00-8
00057-55-6
00057-55-6
00107-98-2
00110-86-1
68953-58-2

293

Parameter Name

Used in
285
Additives ,
286

Polyanionic Cellulose
Polyepichlorohydrin, trimethylamine
quaternized
polyethlene glycol oleate ester
Polyethoxylated alkanol
Polyethoxylated tridecyl ether phosphate
Polyethylene glycol hexyl ether sulfate,
ammonium salt
Polymer with 2-propenoic acid and sodium 2propenoate
Polymeric Hydrocarbons
Polyoxyethylene Sorbitan Monooleate
Polyoxylated fatty amine salt
Polyphosphate
Potassium
Potassium acetate
Potassium borate
Potassium borate
Potassium borate
Potassium carbonate
Potassium chloride
Potassium formate
Potassium Hydroxide
Potassium metaborate
Potassium Sorbate
Precipitated silica / silica gel
Propane-1,2-diol, or Propylene glycol
Propylene glycol
Propylene glycol monomethyl ether
Pyridine
Quaternary Ammonium Compounds

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

NYS MCL,
291
(mg/L)

Yes

§§§

Yes

§§§

Yes
Yes
Yes

§§§

Yes

§

Yes

§§§

Yes
Yes
Yes
Yes

§§
0.05
0.05

§§

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Table 8
§

§
Table 10
§
Yes

Table 10

Yes

Table 10
Table 7
Table 9

Yes
Yes

TOGS lists this parameter as CAS 58-55-6.

Final SGEIS 2015, Page 6-32

Table 3

293

Tables 1,5
Tables 1

1.0
1.0
0.05
0.05
§§

 CAS
Number

Parameter Name

286

62763-89-7
15619-48-4

Quinoline,2-methyl-, hydrochloride
Quinolinium, 1-(phenylmethl),chloride

8000-25-7
00094-59-7

02836-32-0

Rosmarinus officinalis l. leaf oil
Safrole
Salt of amine-carbonyl condensate
Salt of fatty acid/polyamine reaction product
Scale Inhibitor (mg/L)
Selenium
Silica, Dissolved
Silver
Sodium
Sodium 1-octanesulfonate
Sodium acetate
Sodium Alpha-olefin Sulfonate
Sodium Benzoate
Sodium bicarbonate
Sodium bisulfate
Sodium Bromide
Sodium carbonate
Sodium Chloride
Sodium chlorite
Sodium Chloroacetate
Sodium citrate
Sodium erythorbate / isoascorbic acid, sodium
salt
Sodium Glycolate

1301-73-2
01310-73-2
07681-52-9
07775-19-1
10486-00-7
07775-27-1
68608-26-4

Sodium hydroxide
Sodium Hydroxide
Sodium hypochlorite
Sodium Metaborate .8H2O
Sodium perborate tetrahydrate
Sodium persulphate
Sodium petroleum sulfonate

07782-49-2
07631-86-9
07440-22-4
07440-23-5
05324-84-5
00127-09-3
95371-16-7
00532-32-1
00144-55-8
07631-90-5
07647-15-6
00497-19-8
07647-14-5
07758-19-2
03926-62-3
00068-04-2
06381-77-7

Used in
285
Additives ,

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

TOGS111
Tables

NYS MCL,
291
(mg/L)

Table 8

Table 3

0.05
0.05
§§
0.05

Table 6
Table 8
Table 6
Table 7

Tables 1,5

0.05

Tables 1,5
Tables 1,5

0.1

SPDES
290
Tables

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

0.05

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

1.0 (chlorite)
§
§

Yes

§

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

§

Final SGEIS 2015, Page 6-33

§
§
§
§

Table 10
Table 10

 CAS
Number
09003-04-7
07757-82-6
01303-96-4
07772-98-7
01338-43-8
07440-24-6
00057-50-1
05329-14-6
14808-79-8
14265-45-3
68442-77-3
112945-52-5
68155-20-4
08052-48-0
72480-70-7
68647-72-3
68956-56-9
00127-18-4
00533-74-4
55566-30-8
00075-57-0
00064-02-8
07440-28-0
00068-11-1
00062-56-6

Parameter Name

Used in
285
Additives ,
286

Sodium polyacrylate
Sodium sulfate
Sodium tetraborate decahydrate
Sodium Thiosulfate
Sorbitan Monooleate
Specific Conductivity
Strontium
Sucrose
Sugar
Sulfamic acid
Sulfate
Sulfide
Sulfite
Surfactant blend
Surfactant: Modified Amine
Surfactants MBAS
Syntthetic Amorphous / Pyrogenic Silica /
Amorphous Silica
Tall Oil Fatty Acid Diethanolamine

Yes
Yes
Yes
Yes
Yes

Tallow fatty acids sodium salt
Tar bases, quinoline derivs., benzyl chloridequaternized
Terpene and terpenoids

Yes

Terpene hydrocarbon byproducts
Tetrachloroethylene
Tetrahydro-3,5-dimethyl-2H-1,3,5-thiadiazine2-thione / Dazomet
Tetrakis(hydroxymethyl)phosphonium sulfate
(THPS)
Tetramethyl ammonium chloride
Tetrasodium Ethylenediaminetetraacetate
Thallium
Thioglycolic acid
Thiourea

Yes

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

NYS MCL,
291
(mg/L)
§

Table 10

0.05
Yes
Yes

Table 9

Table 1

Yes
Yes
Yes

Table 7
Table 7
Table 7

Tables 1,5
Tables 1,5
Table 1

Yes
Yes
Yes

Yes
Yes

250

§§
Yes

Yes

§§
§,§§
§§
§§
§§

Yes

Yes
Yes
Yes

0.005

Table 6

Tables 1,5

0.005

Yes

0.05

Yes

0.05

Yes
Yes

§
§
0.002
0.05
0.05

Yes

0.002

Yes
Yes

Final SGEIS 2015, Page 6-34

Table 6
Table 10

Tables 1,5

 CAS
Number
68527-49-1
68917-35-1
07440-32-6
00108-88-3

81741-28-8
68299-02-5
00112-27-6
52624-57-4
00150-38-9
05064-31-3
07601-54-9
00057-13-6
07440-62-2
25038-72-6

Parameter Name

Used in
285
Additives ,
286

Thiourea, polymer with formaldehyde and 1phenylethanone
Thuja plicata donn ex. D. don leaf oil
Titanium
Toluene
Total Dissolved Solids
Total Kjeldahl Nitrogen
Total Organic Carbon
Total Suspended Solids
Tributyl tetradecyl phosphonium chloride
Triethanolamine
Triethanolamine hydroxyacetate
Triethylene Glycol
Trimethylolpropane, Ethoxylated,
Propoxylated
Trisodium Ethylenediaminetetraacetate
Trisodium Nitrilotriacetate
Trisodium ortho phosphate
Urea
Vanadium
Vinylidene Chloride/Methylacrylate
Copolymer

13601-19-9
07440-66-6

294

Water
White Mineral Oil
Xanthan gum
Xylenes
Yellow Sodium of Prussiate
Zinc
Zirconium

287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

Yes

Yes

NYS MCL,
291
(mg/L)
§§§

Yes

§§
Yes
Yes
Yes
Yes
Yes
Yes

1

Table 7
Table 6

Tables 1,5
Table 5

0.005

Yes
Yes
Yes

Yes
Yes
Yes
Yes

§
0.05
0.05
0.05

Yes

§§

Yes
Yes
Yes
Yes

§
§0.05
0.05
Yes

Table 7

Table 1

Yes

Volatile Acids
7732-18-5
8042-47-5
11138-66-2

Found in
Flowback

§§§
294

Yes
Yes
Yes
Yes
Yes
Yes

§§
Yes

10

Yes
Yes

Several volatile compounds regulated via SPDES Table 6. Need to evaluate constituents.

Final SGEIS 2015, Page 6-35

Table 1,5
Table 6

Tables 1,5

§§§
0.005
5.0
0.05

 CAS
Number

Parameter Name

Used in
285
Additives ,
286

Found in
Flowback
287

USEPA
MCL or TT
288,
(mg/L)
289

SPDES
290
Tables

TOGS111
Tables

NYS MCL,
291
(mg/L)
§,§§

Final SGEIS 2015, Page 6-36

 6.1.3.4 Potential Impacts to Primary and Principal Aquifers
An uncontained and unmitigated surface spill could result in rapid contamination of a portion of
a Primary or Principal aquifer.
Aside from the NYC Watershed and water supply system, about one half of New Yorkers rely on
groundwater as a source of potable water. To enhance regulatory protection in areas where
groundwater resources are most highly productive and vulnerable, NYSDOH identified
categories of areas for use in geographic targeting. In order of priority, these areas are
designated as follows: public water supply wellhead areas; primary water supply aquifer areas;
principal aquifer areas; and other areas. The Department’s Division of Water Technical &
Operational Guidance Series (TOGS) 2.1.3 clarifies the meaning of Primary Water Supply
Aquifer (also referred to as a Primary Aquifer) and Principal Aquifer. TOGS 2.1.3 further
defines “highly vulnerable” areas as “aquifers which are highly susceptible to contamination
from human activities at the land surface over the identified aquifer.” This TOGS also further
defines “highly productive” aquifers as those "with capability to provide water for public water
supply of a quantity and natural background quality which is of regional significance.”
NYSDOH identified eighteen Primary Aquifers across New York State, defined in TOGS 2.1.3
as "highly productive aquifers presently utilized as sources of water supply by major municipal
water supply systems.” Primary Aquifers are generally capable of providing more than 100 gallons
of drinking water per minute from an individual well.

NYSDOH has also identified Principal Aquifers, which are defined in the TOGS as “highly
productive but which are not intensively used as sources of water supply by major municipal
systems at the present time.” The TOGS further states that these areas need special protections,
but awards Principal Aquifers a slightly lower priority than that afforded Primary Aquifers.
Principal Aquifers are used by individual households, as well as smaller public water supply
systems, such as schools or restaurants. However, Principal Aquifers are generally capable of
providing 10 to 100 or more gpm of drinking water. Principal Aquifers could become Primary
Aquifers depending on future public water supply use.
The groundwater table in the Primary and Principal Aquifers generally ranges from 0 to 20 feet
in depth, and is overlain with sands and gravels. Because Primary and Principal Aquifers are

Final SGEIS 2015, Page 6-37

 largely located and contained in unconsolidated material (i.e., sand and gravel), the high
permeability of soils that overlie these aquifers and the shallow depth to the water table make
these aquifers particularly susceptible to contamination from surface activity. TOGS 2.1.3 notes
that the aquifer designations provide a rationale for enhancing regulatory protections beyond
those provided by existing programs including the SPDES, Chemical Bulk Storage, and Solid
and Hazardous Wastes.
The Department has issued regulations prohibiting installation of certain facilities that threaten
these aquifers. For example, 6 NYCRR Part 360 "Solid Waste Facilities" provides that landfills
are generally not permitted to be constructed above, or within, Primary or Principal Aquifer
areas. Likewise, the Department has, since 1982, inserted special conditions into permits for
drilling oil, gas and other ECL 23 wells within the boundaries of these aquifers.
As an example of the number and distribution of public supply systems that rely on Primary and
Principal Aquifers within areas that could be developed by high-volume hydraulic fracturing,
Figure 6.4 depicts public water supply systems that draw from Primary and Principal Aquifers
within the area underlain by the Marcellus Shale where the shale occurs at a depth of at least
2,000 feet below the ground surface. The Primary Aquifer areas in this area follow the major
river valleys, and serve hundreds of public water supplies, including a number of significantly
sized municipalities, such as Binghamton and Endicott, as well as their surrounding areas. There
are approximately 1,074 public supply systems that rely on Primary and Principal Aquifers in
this area, and the total population served by these combined water supplies is at least 544,740.
The total population within the area is approximately 906,000. Therefore, roughly 60.1% of the
population in this prospective area is served by community groundwater supplies that draw from
Primary and Principal Aquifer areas. The remainder of the population in this area is served by
individual private wells or public surface water supplies or community supplies outside of
Primary and Principal Aquifer areas.

Final SGEIS 2015, Page 6-38

 FIGURE 6.4
DOH Regulated Groundwater Supplies 

Within Mapped Primary and Principal 

Aquifers in NYS, Where the Marcellus 

Shale is Greater Than 2000 Feet Below
Ground Surface.
107 4 S stems, 1486 Wells, 30 S rin s

• 

s

Spring
Water well
Area Underlain by the Marcellus Shale Where
Greater Than 2000 Feet Below Ground Surface

-

0
I

25

50
I

100 Miles
I
NYSDEC 20110817

Final SGEIS 2015, Page 6-39

 The Department is chiefly concerned with surface contamination in Primary and Principal
Aquifer areas because of the risk that uncontained and unmitigated surface spills could reach the
aquifer in a short amount of time, due to the permeable character of the soils above the aquifers,
and the shallow depth to the aquifers (generally 0-20 feet below the ground). Water quality
management programs for such aquifers focus on preventing contaminants from reaching the
waters in the first instance, because once they become contaminated, it is difficult and expensive
to reclaim an aquifer as a source of drinking water.
As discussed elsewhere, detailed well pad containment requirements and setbacks proposed for
high-volume hydraulic fracturing are likely to effectively contain most surface spills at and in the
vicinity of well pads. Nevertheless, despite the best controls, there is a risk of releases to
Primary or Principal Aquifers of chemicals, petroleum products and drilling fluids from the well
pad.
Therefore, the Department concludes that high-volume hydraulic fracturing operations have the
potential to cause a significant adverse impact to the quality of the drinking water resources
provided by Primary and Principal Aquifers, even if the risk of such events is relatively small.
Conclusion
The Department finds that the proposed high-volume hydraulic fracturing operations, although
temporary in nature, may pose risks to Primary and Principal Aquifers that are not fully
mitigated by the measures identified in this SGEIS.
The proposed activity could result in a degradation of drinking water supplies from accidents,
construction activity, runoff and surface spills. Accordingly, the Department concludes that
high-volume hydraulic fracturing operations within Primary and Principal Aquifers pose the risk
of causing significant adverse impacts to water resources. As discussed in Chapter 7, standard
mitigation measures may only partially mitigate such impacts. Such partial mitigation would be
unacceptable due to the potential consequences posed by such impacts.

Final SGEIS 2015, Page 6-40

 6.1.4

Groundwater Impacts Associated With Well Drilling and Construction

The wellbore being drilled, completed or produced, or a nearby wellbore that is ineffectively
sealed, has the potential to provide subsurface pathways for groundwater pollution from well
drilling, flowback or production operations. Pollutants could include:
•

turbidity;

•

fluids pumped into or flowing from rock formations penetrated by the well; and

•

natural gas present in the rock formations penetrated by the well.

These potential impacts are not unique to horizontal wells and are described by the 1992 GEIS.
The unique aspect of the proposed multi-well development method is that continuous or
intermittent activities would occur over a longer period of time at any given well pad. This does
not alter the per-well likelihood of impacts from the identified subsurface pathways because
existing mitigation measures apply on an individual well basis regardless of how many wells are
drilled at the same site. Nevertheless, the potential impacts are acknowledged here and enhanced
procedures and mitigation measures are proposed in Chapter 7 because of the concentrated
nature of the activity on multi-well pads and the larger fluid volumes and pressures associated
with high-volume hydraulic fracturing. As mentioned earlier, the 1992 GEIS addressed
hydraulic fracturing in Chapter 9, and NYSDOH’s review did not identify any potential exposure
situations associated with horizontal drilling and high-volume hydraulic fracturing that are
qualitatively different from those addressed in the 1992 GEIS.
6.1.4.1 Turbidity
The 1992 GEIS stated that “review of Department complaint records revealed that the most
commonly validated impact from oil and gas drilling activity on private water supplies was a
short-term turbidity problem.” 295 This remains the case today. Turbidity, or suspension of solids
in the water supply, can result from any aquifer penetration (including monitoring wells, water
wells, oil and gas wells, mine shafts and construction pilings) if sufficient porosity and
permeability or a natural subsurface fracture is present to transmit the disturbance. The majority
of these situations correct themselves in a short time.

295

NYSDEC 1992, GEIS, p. 47.

Final SGEIS 2015, Page 6-41

 6.1.4.2 Fluids Pumped Into the Well
Fluids for hydraulic fracturing are pumped into the wellbore for a short period of time per
fracturing stage, until the rock fractures and the proppant has been placed. For each horizontal
well the total pumping time is generally between 40 and 100 hours. ICF International, under its
contract with NYSERDA to conduct research in support of SGEIS preparation, provided the
following discussion and analysis with respect to the likelihood of groundwater contamination by
fluids pumped into a wellbore for hydraulic fracturing (emphasis added): 296
In the 1980s, the American Petroleum Institute (API) analyzed the risk of
contamination from properly constructed Class II injection wells to an
Underground Source of Drinking Water (USDW) due to corrosion of the casing
and failure of the casing cement seal. Although the API did not address the risks
for production wells, production wells would be expected to have a lower risk of
groundwater contamination due to casing leakage. Unlike Class II injection wells
which operate under sustained or frequent positive pressure, a hydraulically
fractured production well experiences pressures below the formation pressure
except for the short time when fracturing occurs. During production, the wellbore
pressure would be less than the formation pressure in order for formation fluids or
gas to flow to the well. Using the API analysis as an upper bound for the risk
associated with the injection of hydraulic fracturing fluids, the probability of
fracture fluids reaching a USDW due to failures in the casing or casing cement is
estimated at less than 2 x 10-8 (fewer than 1 in 50 million wells).
More recently, regulatory officials from 15 states have testified that groundwater contamination
as a result of hydraulic fracturing, which includes this pumping process, has not occurred
(Appendix 15).
6.1.4.3 Natural Gas Migration
As discussed above, turbidity is typically a short-term problem which corrects itself as suspended
particles settle. The probability of groundwater contamination from fluids pumped into a
properly-constructed well is very low. Natural gas migration is a more reasonably anticipated
risk posed by high-volume hydraulic fracturing. The 1992 GEIS, in Chapters 9, 10 and 16,
describes the following scenarios related to oil and gas well construction where natural gas could
migrate into potable groundwater supplies:

296

ICF Task 1, 2009, p. 21.

Final SGEIS 2015, Page 6-42

 •

Inadequate depth and integrity of surface casing to isolate potable fresh water supplies
from deeper gas-bearing formations;

•

Inadequate cement in the annular space around the surface casing, which may be caused
by gas channeling or insufficient cement setting time; gas channeling may occur as a
result of naturally occurring shallow gas or from installing a long string of surface casing
that puts potable water supplies and shallow gas behind the same pipe; and

•

Excessive pressure in the annulus between the surface casing and intermediate or
production casing. Such pressure could break down the formation at the shoe of the
surface casing and result in the potential creation of subsurface pathways outside the
surface casing. Excessive pressure could occur if gas infiltrates the annulus because of
insufficient production casing cement and the annulus is not vented in accordance with
required casing and cementing practices.

As explained in the 1992 GEIS, potential migration of natural gas to a water well presents a
safety hazard because of its combustible and asphyxiant nature, especially if the natural gas
builds up in an enclosed space such as a well shed, house or garage. Well construction practices
designed to prevent gas migration would also form a barrier to other formation fluids such as oil
or brine. Although gas migration may not manifest itself until the production phase, its
occurrence would result from well construction (i.e., casing and cement) problems.
The 1992 GEIS acknowledges that migration of naturally-occurring methane from wetlands,
landfills and shallow bedrock can also contaminate water supplies independently or in the
absence of any nearby oil and gas activities. Section 4.7 of this document explains how the
natural occurrence of shallow methane in New York can affect water wells, which needs to be
considered when evaluating complaints of methane migration that are perceived to be related to
natural gas development.
6.1.5

Unfiltered Surface Drinking Water Supplies: NYC and Syracuse

There are two major surface drinking water sources and systems located within New York that
have been granted permission by EPA and NYSDOH to operate as unfiltered drinking water
supplies pursuant to regulations promulgated under the federal SDWA, known as the Surface
Water Treatment Rule (SWTR). These unfiltered systems are the NYC and City of Syracuse
water supplies and associated watersheds. For a drinking water system to qualify for filtration
avoidance under the SWTR, the system cannot be the source of a waterborne disease outbreak,
must meet source water quality limits for coliform and turbidity and meet coliform and total

Final SGEIS 2015, Page 6-43

 trihalomethane MCLs in finished water. Disinfectant residual levels and redundant disinfection
capability also must be maintained. Filtration avoidance further requires that a watershed
control program be implemented to minimize microbial contamination of the source water. This
program must characterize the watershed’s hydrology, physical features, land use, source water
quality and operational capabilities. It must also identify, monitor and control manmade and
naturally occurring activities that are detrimental to water quality. The watershed control
program must also be able to control activities through land ownership or written agreements.
Heightened public health sensitivities are associated with unfiltered surface water systems
because the only treatment that these drinking waters receive before human consumption is basic
disinfection through such methods as chlorine addition or ultraviolet light irradiation. In
unfiltered systems, there is no application of widely employed treatment measures such as
chemical coagulation/flocculation or physical filtration to remove pathogens, sediments, organic
matter or other contaminants from the drinking water.
The NYC drinking water supply watershed (NYC Watershed) is located in portions of Delaware,
Dutchess, Greene, Putnam, Schoharie, Sullivan, Ulster and Westchester Counties.
Approximately 9.4 million residents rely on the NYC water supply: 8.4 million in NYC and 1
million in portions of Orange, Putnam, Ulster and Westchester Counties. The NYC Watershed
contains 19 reservoirs and 3 controlled lakes that supply, on average, 1.1 to 1.3 billion gallons of
potable water daily. Historically, 90% of this system's drinking water has been supplied by the
"Catskill" and "Delaware" portions of the NYC Watershed, which are located west of the
Hudson River (an area that may be described as the "Catskill/Delaware Watershed"). On
average, the remaining 10% of the water supply flows from the "Croton" portion of the NYC
Watershed that is located in the counties to the east of the Hudson River. An extensive system of
aqueducts and tunnels transmit waters by gravity throughout the NYC Watershed and water
supply system. The NYC Watershed covers 2,000 square miles, an area that comprises 4.2% of
the total land area of New York State.
Eight of the reservoirs located in the Croton portion of the NYC Watershed have been formally
determined by the Department, pursuant to Clean Water Act sec. 303(d), to be impaired due to
excess nutrient phosphorus (Amawalk, Croton Falls, Diverting, East Branch, Middle Branch,
Muscoot, New Croton and Titicus Reservoirs). Designation as "impaired" means that these

Final SGEIS 2015, Page 6-44

 reservoirs are in a condition that violates state water quality standards due to a specified
pollutant. The Cannonsville Reservoir in Delaware County previously had been declared to be
impaired due to excess nutrient phosphorus; however, its status was improved by active water
quality remedial management efforts, including wastewater treatment plant upgrades, septic
system repairs and replacements, construction of stormwater retrofits, and installation of best
management practices on several hundred farms located throughout the Catskill and Delaware
Watershed, most notably in Delaware County. As a result of this comprehensive and aggressive
watershed protection program, the Department has determined that the Cannonsville Reservoir
has been returned to regulatory compliance. The two reservoirs located in the Catskill portion of
the NYC Watershed have been determined by the Department to be impaired due to excessive
levels of suspended sediment (Ashokan and Schoharie Reservoirs).
The most recent EPA Filtration Avoidance Determination (FAD) was granted to NYC by EPA,
in consultation with NYSDOH, in 2007 for the unfiltered use of the Catskill and Delaware
systems and interconnected reservoir basins located in watershed communities to the east of the
Hudson River. Waters flowing from the Croton portion of the NYC Watershed have been
required to be filtered by EPA (at a cost of approximately $3 billion for construction of the
filtration plant). Systems of aqueducts and interchanges, however, allow for Croton waters to be
transferred and intermixed with waters from the Catskill and Delaware systems to assure an
adequate water supply in stressed or emergency situations, such as significant drought or major
infrastructure failure.
The City of Syracuse, with a population of approximately 145,000, has also been granted
permission by EPA and NYSDOH to operate an unfiltered drinking water supply. The most
recent filtration avoidance determination was issued by NYSDOH to Syracuse in 2004. The
unfiltered source water is Skaneateles Lake, a Finger Lake that is located approximately 20 miles
to the south and west of Syracuse. The Skaneateles Lake watershed comprises a total area of 59
square miles that includes the lake - which is approximately 14 miles long and 1 mile wide.
Reports issued by the Syracuse Department of Water state that Skaneateles Lake generally
provides between 32 and 34 million gallons of potable water daily. The most recent NYSDOH
source water assessment found that Skaneateles Lake had a moderate susceptibility to
contamination, including a level of farm pasture land that results in a high potential for protozoan

Final SGEIS 2015, Page 6-45

 contamination. Copper sulfate treatments are at times administered to Skaneateles Lake to
control phosphorus-induced algae growth and associated adverse impacts such as poor taste and
odor.
6.1.5.1 Pollutants of Critical Concern in Unfiltered Drinking Water Supplies
One of the fundamental concepts framing the effective protection of unfiltered drinking water is
"source water protection." Management programs in such watershed necessarily focus on
systematically preventing contaminants from reaching the waters in the first instance, as there is
no mechanism in place (such as a filtration plant) to remove contaminants once they have
entered the water. Once polluted, it very difficult and very expensive to return these water
supplies back to their original condition. In both the NYC and City of Syracuse watersheds,
extensive efforts have been undertaken to stringently treat sewage discharges. Within the
Skaneateles Lake watershed, any discharge, whether treated sewage effluent or otherwise, to any
surface water is prohibited. Within the NYC Watershed, all sewage treatment plants must
achieve an extraordinarily stringent level of treatment consistent with "tertiary treatment, microfiltration and biological phosphorus removal." These are the most technologically advanced
sewage treatment plants in New York State. Therefore, the critical remaining potential for
impairment of these two unfiltered water supplies stems from human activities that place
contaminants on the ground that can then be washed into reservoirs and tributaries via storm
water runoff, or flow into them from contaminated groundwater.
The National Research Council of the National Academies of Sciences undertook a detailed
assessment of the risks and sensitivities associated with the NYC Watershed and water supply
system. This peer-reviewed report provides useful background on the distinctive nature of risks
resulting from potential surface pollution in unfiltered drinking water watersheds and supplies. 297
The concerns and management methods discussed in this report are also relevant and applicable
to the City of Syracuse drinking water supply.
In general, the pollutants of key concern when managing an unfiltered drinking water system are:
(i) nutrient phosphorus; (ii) microbial pathogens; (iii) suspended sediment (or "turbidity"); and

297

National Research Council, 2000.

Final SGEIS 2015, Page 6-46

 (iv) toxic compounds. As explained below, the adverse impacts of these contaminants are
substantially heightened in unfiltered drinking water systems.
Phosphorus: Excess phosphorus leads to algae blooms, including increased growth of toxin
emitting blue-green algae. Algae blooms lead to high bacteria growth (due to bacterial
consumption of algae) that, in turn, deplete the reservoir bottom waters of dissolved oxygen.
Low dissolved oxygen suffocates or drives off fish. Low oxygen levels cause a change in the
biology of reservoir waters (to anaerobic conditions) that result in impaired water taste, odor, and
color. For example, iron, manganese and H2S are brought into the water column under these low
oxygen conditions. The higher levels of dead algae, bacteria and other chemicals in the water
constitute an increase in organic matter that can react with chlorine during the drinking water
disinfection process - causing elevated levels of "disinfection by-products"; many of these
chlorinated organic compounds are suspected by the EPA of being carcinogens and have been
identified in a number of medical studies as a factor linked to early term miscarriage. Finally,
the increased material suspended in water, which results from phosphorus-induced algae blooms,
can interfere with the effectiveness of chlorination and ultraviolet light irradiation on pathogens,
and thereby foster the transport waterborne pathogens to water consumers.
Phosphorus is a naturally-occurring element that is found in human and animal wastes, animal
and plant materials, fertilizers and eroded soil particles. While essential for life, excess
phosphorus at very low levels can cause the adverse environmental and public health impacts
discussed above during the warm weather growing season. Guidance value concentrations, set
by the Department to limit adverse impacts from phosphorus in NYC Watershed reservoirs,
range between 15 and 20 parts per billion (ppb).
Microbial Pathogens: A surface drinking water source may be adversely impacted by a range
of disease-causing microorganisms such as bacteria, viruses and protozoa. Such organisms can
result from a variety of sources but to a significant extent result from human and animal wastes
or possible re-growth in bio-slimes that may form within a drinking water supply system. Both
the NYC and Syracuse drinking water supplies are required by EPA and NYSDOH regulations
to employ two forms of disinfection in series that, when combined with effective source water
protection programs, are highly effective in destroying or de-activating bacteria, viruses and
protozoa.

Final SGEIS 2015, Page 6-47

 However, there are two disinfection-resistant protozoa that have emerged in recent decades that
can cause significant intestinal illness in otherwise healthy humans, and result in severe illness
and even death in individuals with compromised immune systems. These protozoa, Giardia
lamblia and Cryptosporidium parvum, both have life stages where they form cysts (or oocysts)
that can survive standard disinfection treatments and infect human hosts. The basic public health
management response to such organisms is to limit specific human and animal waste
transmission pathways to waters on the landscape and to require controls that limit such
occurrences as algae blooms and suspended sediments, which can assist in the transmittal of
pathogens. As discussed below, inadequately effective controls will likely result in the
imposition of a costly filtration requirement by EPA or NYSDOH in accordance with the SDWA
and the underlying SWTR.
Sediment or Turbidity: Sediment laden, or turbid, water can increase the effective
transportation of pathogens, serve as food for pathogens, promote the re-growth of pathogens in
the water distribution system, and shelter pathogens from exposure to attack by disinfectants
such as chlorine or ultraviolet light. The organic particles that are a cause of turbidity can
combine with chlorine to create problematic disinfection by-products that are possible
carcinogens and suspected by medical studies of increasing the risk of miscarriage.
EPA, in its SWTR, prohibits raw water turbidity measurements in unfiltered drinking water at
the intake to the distribution system in excess of 5 nephelometric turbidity units (essentially, very
clear water). 298 More than one violation per year is grounds for EPA or NYSDOH to require
construction of a water filtration plant. Such a plant for the Catskill and Delaware portions of the
NYC water supply has been estimated to cost between $8 to $10 billion with an additional $200
(plus) million a year in operational and maintenance expenses. An overview of the public health
concerns raised by turbidity in drinking water are discussed in greater detail at: U.S. EPA,
Guidance Manual for Compliance with the Interim Enhanced Surface Water Treatment Rule:
Turbidity Provisions, Office of Water, EPA 815-R-99-010, April 1999, Chapter 7 (and numerous
cited references); see also Kistemann, T., et al., Microbial Load of Drinking Water Reservoir
Tributaries During Extreme Rainfall and Runoff, Applied Environmental Microbiology, Vol. 68,
No. 5, pp. 2188-2197 (May 2002); Naumova, E., et al., The Elderly and Waterborne
298

40 CFR §141.71(a)(2).

Final SGEIS 2015, Page 6-48

 Cryptosporidium Infection: Gastroenteritis Hospitalizations Before and During the 1993
Milwaukee Outbreak, Emerging Infectious Diseases, Vol. 9 No. 4, pp. 418-425 (2003).
Toxic Compounds: Unfiltered drinking water supplies have a heightened sensitivity to
chemical discharges as there is no immediately available method to remove contaminants from
the drinking water source waters. Well pad containment practices and setbacks are likely to
effectively contain most spills at those locations. There is a continuing risk, however, of releases
from chemicals, petroleum products and drilling fluids from the well pad as a result of tank
ruptures, equipment or surface impoundment failures, overfills, vandalism, accidents (including
vehicle collisions), ground fires, or improper operations. Spilled, leaked or released fluids could
flow to a surface water body. The intensive level of trucking activity associated with highvolume hydraulic fracturing, including the transport of chemical and petroleum products,
presents an additional risk of surface water contamination due to truck accidents and associated
releases. Given the topography of much of the NYC and Skaneateles Lake watersheds, many of
the roadways are in immediate proximity to tributaries. Such proximity increases the risk that
chemical and petroleum spills would not, or could not, be effectively intercepted before entering
the drinking water supply.
6.1.5.2 Regulatory and Programmatic Framework for Filtration Avoidance
The basic statutory and regulatory framework applicable to unfiltered drinking water supplies is
provided by the federal Safe Drinking Water Act (SDWA), 42 U.S.C. sec. 300f, et al. The
SDWA directed EPA to adopt regulations requiring public water supplies using surface waters to
apply filtration systems to treat their water unless protective "criteria" or "standards" could be
met. Pursuant to this grant of authority, EPA issued the SWTR, 40 CFR sec. 141.71, et al.
Subject to continuing oversight, EPA has delegated authority to administer the SDWA within
New York to the NYSDOH pursuant to State statutory and regulatory authority that is consistent
with the federal protocol.
There are numerous "filtration avoidance criteria" specified in the SWTR. These criteria must be
met for a drinking water supply system to maintain its unfiltered status. The first two criteria
address fecal coliform and turbidity limits in raw water before disinfection. The next four
criteria address assuring the effectiveness of disinfection and the maintenance of sufficient levels
of disinfection agents in the water distribution system. The next five criteria variously address

Final SGEIS 2015, Page 6-49

 landscape control programs for Giardia lamblia, water supply system inspections, prohibition on
waterborne disease outbreaks, and maximum contaminant level compliance for total coliform
and disinfection by-products in drinking water after disinfection.
Another key provision operates to drive overarching watershed planning and protection
programs, along with cooperative agreements with individuals and municipalities situated within
the unfiltered watershed: "The public water system must demonstrate through ownership and/or
written agreements with landowners within the watershed that it can control all human activities
which may have an adverse impact on the microbiological quality of the source water." 40 CFR
sec. 141.71(b)(2)(iii) (emphasis added). High-volume hydraulic fracturing and associated
activities are within the scope of "human activities" covered by this regulatory provision. As
discussed above, human activities that increase levels of phosphorus and sediment, or heighten
storm water flows that could transmit microbial pathogens into waters, would all have an "impact
on the microbiological quality of the source water."
Major efforts have been undertaken to cooperatively assure equitable implementation of
programs to protect the NYC Watershed and water supply. In 1997, essentially all stakeholders
associated with the NYC Watershed entered into the "1997 New York City Watershed
Memorandum of Agreement." This binding three volume agreement specified extensive
programs with respect to land acquisition, extra-territorial regulations promulgated by NYC, the
establishment of a Watershed Protection and Partnership Council, and an array of specific
programs to limit pollution from septic systems, construction excavations, salt storage facilities,
runoff from impervious surfaces, timber harvesting, waste water treatment plants, unstable
streams and farms. An extensive and updated source water protection program also is detailed in
the FAD that was issued to NYC (covering environmental infrastructure, protection and remedial
water quality efforts, watershed monitoring and regulatory implementation). Protection
programs, as well as programs to equitably address the concerns of local residents, were also
detailed in a Department Water Supply Permit that was finalized and issued to NYC in January
2011. It is estimated that at least $1.6 billion has been invested in NYC Watershed protection
programs since 1997.
Syracuse has developed similar programs to prevent contamination of Skaneateles Lake and its
watershed. Specific regulations have been developed to address a range of human activities that

Final SGEIS 2015, Page 6-50

 could adversely impact water quality – including sewage treatment plants, septic systems, and
erosion and sediment controls at construction sites. Syracuse implements a "Watershed
Agricultural Program" to cooperatively limit pollution that could result from crop land and
animal agricultural activities. A program of conservation easements in certain sensitive lands
has also been developed to limit human activity that might harm water quality.
6.1.5.3 Adverse Impacts to Unfiltered Drinking Waters from High-Volume Hydraulic Fracturing
Activities associated with high-volume hydraulic fracturing involve a significant amount of land
clearing and excavation. New roads, sufficient to reach the well pad and of a design capable of
handling a high volume of fully loaded truck traffic, would need to be cleared and cut. The often
steep terrain of the NYC and Skaneateles Lake watersheds would necessitate a significant level
of cut and fill roadway excavations, as well as soil stockpiles, that would expose soils to erosive
activities. The excavation and grading of level well pads (generally ranging from 3 to 5 acres in
size) to support drilling activities would create significant additional amounts of exposed soils
and cut and fill excavations. Gas transmission pipelines of various sizes would necessarily be
cut through the watersheds, often in straight lines and down hills in a manner that can accelerate
and channelize water during precipitation events. Both the NYC Watershed and Skaneateles
Lake watershed regularly receive high precipitation events that operate to mobilize exposed soil
particles.
The clearing of vegetation, and the excavation and compaction of soils, associated with new
roads, pipelines and drilling well pads in the NYC and Skaneateles Lake watersheds also will
increase the volume and intensity of stormwater runoff, even if subject to stormwater control.
While not fully "impervious" this less pervious landscape will increase runoff. Moreover, to
support high volumes of truck traffic, narrow existing dirt roads may need to be paved and
widened, as has been the experience in Pennsylvania. One acre of impervious surface is
estimated to create the same amount of runoff as 16 acres of naturally vegetated meadow or
forest. 299 Therefore, new impervious surfaces (as well as the substantially less-pervious surfaces
created by the removal of vegetation and compaction of soils associated with construction
excavations) can transmit very high volumes of stormwater relative to natural conditions that
then operate to destabilize road-side ditches and streams, and cause additional erosion. As
299

Schuler, 1994, p. 100.

Final SGEIS 2015, Page 6-51

 discussed, elevated turbidity or suspended sediment levels present particular public health
concerns in an unfiltered drinking water supply, a problem that already significantly affects the
Catskill portion of the NYC Watershed, including the Schoharie and Ashokan Reservoirs.
As in other areas of the state, erosion and sediment control measures would significantly limit
the adverse impacts of stormwater flow from construction excavations, erosion, soils compaction
and increased imperviousness associated with high-volume hydraulic fracturing. However, even
with such stormwater controls, the heightened sensitivity of these unfiltered watersheds make the
potential for adverse impacts to water quality from sedimentation due to construction
excavations significant during levels of projected peak activity. Even with state-of-the art
stormwater controls a risk of increased stormwater runoff from accidents or other unplanned
events cannot be entirely eliminated. The potential consequences of such events – loss of the
FAD – is significant even if the risk of such events occurring is relatively small. Similarly, the
risks associated with high volumes of truck traffic transporting chemical and petroleum products
associated with high-volume hydraulic fracturing is inconsistent with effective protection of an
unfiltered drinking water supply. This is especially so, as a number of factors, discussed above,
are already operating to stress the NYC and Syracuse source waters. This concern is exemplified
by an extensive study by researchers from SUNY ESF and Yale published in 2008. This peerreviewed report concluded that the current rate of excavations and associated increases in
impervious and less pervious surfaces within the NYC Watershed would likely result in the
phosphorus impairment of all reservoirs over an approximate 20 year time frame. Hall, M., R.
Germain, M. Tyrell, and N. Sampson, Predicting Future Water Quality from Land Use Change
Projections in the Catskill-Delaware Watersheds, pp. 217-268 (2008) (available at
http://www.esf.edu/es/faculty/hall.asp). This report does not take into consideration the
accelerated development associated with high-volume hydraulic fracturing.
6.1.5.4 Conclusion
The Department finds that high-volume hydraulic fracturing activity is not consistent with the
preservation of the NYC and Syracuse watersheds as unfiltered drinking water supplies. Even
with all of the criteria and conditions identified in the revised draft SGEIS, a risk remains that
significant high-volume hydraulic fracturing activities in these areas could result in a degradation
of drinking water supplies from accidents, surface spills, etc. Moreover, such large scale

Final SGEIS 2015, Page 6-52

 industrial activity in these areas, even without spills, could imperil EPA’s FADs and result in the
affected municipalities incurring substantial costs to filter their drinking water supply.
Accordingly, and for all of the aforementioned reasons, the Department concludes that highvolume hydraulic fracturing operations within the NYC and Syracuse watersheds pose the risk of
causing significant adverse impacts to water resources. As discussed in Chapter 7, standard
mitigation measures such as stormwater controls would only partially mitigate such impacts.
Such partial mitigation is unacceptable due to the potential consequences – adverse impacts to
human health and loss of filtration avoidance – posed by such impacts.
6.1.6

Hydraulic Fracturing Procedure

Concern has been expressed that potential impacts to groundwater from the high-volume
hydraulic fracturing procedure itself could result from:
•

wellbore failure as a result of an improperly constructed well; or

•

movement of unrecovered fracturing fluid out of the target fracture formation through
subsurface pathways such as:
o a nearby poorly constructed or improperly plugged wellbore;
o fractures created by the hydraulic fracturing process;
o natural faults and fractures; and
o movement of fracturing fluids through the interconnected pore spaces in the rocks
from the fracture zone to a water well or aquifer.

As summarized in Section 8.4.5, regulatory officials from 15 states have recently testified that
groundwater contamination from the hydraulic fracturing procedure is not known to have
occurred despite the procedure’s widespread use in many wells over several decades.
Nevertheless, NYSERDA contracted ICF International to evaluate factors which affect the
likelihood of groundwater contamination from high-volume hydraulic fracturing. 300

300

ICF Task 1, 2009,

Final SGEIS 2015, Page 6-53

 6.1.6.1 Wellbore Failure
As described in Section 6.1.4.2, the probability of fracture fluids reaching an underground source
of drinking water (USDW) from properly constructed wells due to subsequent failures in the
casing or casing cement due to corrosion is estimated at less than 2 x 10-8 (fewer than 1 in 50
million wells). Hydraulic fracturing is not known to cause wellbore failure in properly
constructed wells.
6.1.6.2 Subsurface Pathways
Reference is made in Section 5.9 to ICF International’s calculations of the rate at which
fracturing fluids could move away from the wellbore through fractures and the rock matrix
during pumping operations under hypothetical assumptions of a hydraulic connection. Appendix
11 provides ICF’s full discussion of the principles governing potential fracture fluid flow under
this hypothetical condition. ICF’s conclusion is that “hydraulic fracturing does not present a
reasonably foreseeable risk of significant adverse environmental impacts to potential freshwater
aquifers.” 301 Specific conditions or analytical results supporting this conclusion include:

301

•

The developable shale formations are vertically separated from potential freshwater
aquifers by at least 1,000 feet of sandstones and shales of moderate to low permeability;

•

The amount of time that fluids are pumped under pressure into the target formation is
orders of magnitude less than the time that would be required for fluids to travel through
1,000 feet of low-permeability rock;

•

The volume of fluid used to fracture a well could only fill a small percentage of the void
space between the shale and the aquifer;

•

Some of the chemicals in the additives used in hydraulic fracturing fluids would be
adsorbed by and bound to the organic-rich shales;

•

Diffusion of the chemicals throughout the pore volume between the shale and an aquifer
would dilute the concentrations of the chemicals by several orders of magnitude; and

•

Any flow of fracturing fluid toward an aquifer through open fractures or an unplugged
wellbore would be reversed during flowback, with any residual fluid further flushed by
flow from the aquifer to the production zone as pressures decline in the reservoir during
production.

ICF Task 1, 2009, p. 34

Final SGEIS 2015, Page 6-54

 As noted in Section 2.3.6, a depth of 850 feet to the base of potable water is a commonly used
and practical generalization for the maximum depth of potable water in New York. Alpha
Environmental, under its contract with NYSERDA, provided the following additional
information regarding the Marcellus and Utica Shales: 302
The Marcellus and Utica Shales dip southward from the respective outcrops of
each member, and most of the extents of both shales are found at depths greater
than 1,000 feet in New York. There are multiple alternating layers of shale,
siltstone, limestone, and other sedimentary rocks overlying the Marcellus and
Utica Shales. Shale is a natural, low permeability barrier to vertical movement of
fluids and typically is considered a cap rock in petroleum reservoirs (Selley,
1998) and an aquitard to groundwater aquifers (Freeze & Cherry, 1979). The
varying layers of rocks of different physical characteristics provide a barrier to the
propagation of induced hydraulic fractures from targeted zones to overlying rock
units (Arthur et al, 2008). The vertical separation and low permeability provide a
physical barrier between the gas producing zones and overlying aquifers.
Natural Controls on Underground Fluid Migration
As noted by ICF (Subpart 5.11.1.1 and Appendix 11) and Alpha (as cited above) , the
developable shale formations are vertically separated from potential freshwater aquifers by at
least 1,000 feet of sandstones and shales of moderate to low permeability. Figure 4.2 shows that
most of the bedrock formations above the Marcellus Shale are other shales. That shales must be
hydraulically fractured to produce fluids is evidence that these rocks do not readily transmit
fluids. The high salinity of native water in the Marcellus and other Devonian shales is evidence
that fluid has been trapped in the pore spaces for a significant length of time, implying that there
is no mechanism for discharge.
As previously discussed, hydraulic fracturing is engineered to target the prospective
hydrocarbon-producing zone. The induced fractures create a pathway to the intended wellbore,
but do not create a discharge mechanism or pathway beyond the fractured zone where none
existed before. The pressure differential that pushes fracturing fluid into the formation is
diminished once the rock has fractured, and is reversed toward the wellbore during the flowback
and production phases.

302

Alpha, 2009, p. 3-3.

Final SGEIS 2015, Page 6-55

 Darcy's Law is a universally accepted scientific principle of hydrogeology. It states the
relationship that explains fluid flow in porous media. Flow rate, Q, is calculated by
Q=KA(Phigh-Plow)/μL
where K= permeability, A= cross sectional area, P=pressure, μ=fluid viscosity and L=length of
flow. The factor “Phigh-Plow” describes a pressure differential, and Darcy’s Law explains the
relationship between pressure and fluid flow. During hydraulic fracturing operations, the
pressure in the well is greater than the pressure in the formation and drives the fluid and sand
into the rock creating the induced fractures. If induced fractures do intersect an open fault or
wellbore that diverts fluid from the target formation during pumping, this would be detected by
required pressure monitoring during the fracturing process. Permit conditions will require
pumping operations to cease if this occurs, until the anomalous condition is evaluated and
addressed. Cessation of pumping will remove the pressure differential and stop further flow
away from the target formation. Additionally, the force exerted by lithostatic pressure (i.e., the
weight of overlying rocks) tends to close natural fissures at depth, so even when such fissures
exist they are not necessarily transmissive. This is the reason that hydraulic fracturing requires
the use of proppant to keep induced fractures open to transmit natural gas to the wellbore. Also,
even if it is assumed that fractures in overlying strata are transmissive, there is no reason to
believe that the fractures of different strata are aligned in a manner that would make hydraulic
connections possible.
Once pumping ceases and hydraulic fracturing is accomplished, the well is turned into the
production system at the surface which is at a much lower pressure than the formation.
Therefore gas flows to the well and the surface. At this point there is no pressure differential that
would cause fluid to move in any direction other than towards the gas well.
All of the above factors that inhibit vertical fracturing fluid migration would also inhibit
horizontal migration beyond the fracture zone for the distances required to impact potable water
wells in the Marcellus and other shales from high-volume hydraulic fracturing under the
conditions specified by ICF. Because of regional dip, the geographic location of any target
reservoir where it is more than 1,000 feet below the presumed base of fresh water would be at

Final SGEIS 2015, Page 6-56

 least several miles south of any location where water wells are completed in the same rock
formation.
Mapped Marcellus Hydraulic Fracturing Stages
Four hundred Marcellus hydraulic fracturing stages in Pennsylvania, West Virginia and Ohio
have been mapped with respect to vertical growth and distance to the deepest water wells in the
corresponding areas. 303 Although many of the hydraulic fracturing stages occurred at depths
greater than the depths at which the Marcellus occurs in New York, the results across all depth
ranges showed that induced fractures did not approach the depth of drinking water aquifers. In
addition, as previously discussed, at the shallow end of the target depth range in New York,
fracture growth orientation would change from vertical to horizontal.
6.1.7

Waste Transport

Drilling and fracturing fluids, mud-drilled cuttings, pit liners, flowback water and production
brine are classified as non-hazardous industrial-commercial waste which would be hauled under
a New York State Part 364 waste transporter permit issued by the Department. All Part 364
transporters would identify the general category of wastes transported and obtain written
authorization from each destination facility, which must be maintained at the place of business
and made available to the Department upon request.
Manifesting is not required for non-hazardous industrial-commercial waste, so there is no
tracking and verification of disposal destination on an individual load basis. Although the
Department’s regulations do not classify drilling and production wastes as hazardous, like all
wastes they must be handled and disposed of in accordance with all applicable regulatory
requirements. One concern is that wastes will not be properly identified or may not be taken to
appropriate, permitted facilities. Chapter 7 provides mitigation for this concern in the form of a
waste tracking procedure similar to that which is required for medical waste even though the
hazards are not equivalent. Another concern relates to potential spills as a result of trucking
accidents. It should be noted that the developing practice of treating and reusing flowback water
on the same well pad would reduce the number of truck trips for hauling flowback water to other

303

Fisher, 2010, pp. 30-33.

Final SGEIS 2015, Page 6-57

 destinations. Information about traffic management related to high-volume hydraulic fracturing
is presented in Section 7.8.
6.1.8

Fluid Discharges

Direct discharge of fluids onto the ground or into surface water bodies from the well pad are
prohibited. Discharges would be managed at treatment facilities, appropriately recycled, or in
permitted disposal wells.
6.1.8.1 POTWs
Surface water discharges from water treatment facilities are regulated under the Department’s
SPDES program. Acceptance by a POTW of a waste stream that upsets its system or exceeds its
capacity may result in a SPDES permit effluent violation or a violation of water quality standards
within the receiving water. Water pollution degrades surface waters, potentially making them
unsafe for drinking, fishing, swimming, and other activities or unsuitable for their classified best
uses.
Flowback water may be sent to POTWs. However, treatability of flowback water presents a
potential environmental concern because residual fracturing chemicals and naturally-occurring
constituents from the rock formation could be present in flowback water and have treatment,
sludge disposal, and receiving-water impacts. Salts and dissolved solids may not be sufficiently
treated by municipal biological treatment and/or other treatment technologies which are not
designed to remove pollutants of this nature. Table 6.1 provides information on flowback water
composition based on a limited number of samples from Pennsylvania and West Virginia.
Appendix 21 is a list of POTWs with approved pretreatment and mini-pretreatment programs.
Note that this is not a list of facilities approved to accept wastewater from high-volume hydraulic
fracturing. Rather, it is a list of facilities that have SPDES permit conditions and requirements
allowing them to accept wastewater from hauled or other significant industrial sources in
accordance with 40CFR Part 403. To accept a source of wastewater, the facility must first
evaluate the pollutants present in that source of wastewater against an analysis of the capabilities
of the individual treatment units and the treatment system as a whole to treat these pollutants;
that analysis is known as a Maximum Allowable Headworks Loading analysis (MAHW, or
headworks analysis). In addition, any industrial wastewater source, including this source of

Final SGEIS 2015, Page 6-58

 wastewater, may only be discharged utilizing all treatment processes within the POTW.
Admixture of untreated flowback water or other well development water to the treated effluent of
the POTW is not allowed. Improper handling could result in noncompliance with terms of the
permit or the ECL and result in formal enforcement actions.
The large volumes of return water from high-volume hydraulic fracturing combined with the
diverse mixture of chemicals and high concentrations of TDS that exist in both flowback water
and production brine, requires that the permittee submit a headworks analysis specific to the
parameters expected present in high-volume hydraulic fracturing wastewater, including TDS and
NORM, to both the Department and EPA Region 2 for review in accordance with DOW’s
Technical and Operational Guidance Series (TOGS ) 1.3.8, New Discharges to Publicly Owned
Treatment Works. TOGS 1.3.8., was developed to assist Department permit writers in evaluating
the potential effect of a new, substantially increased, or changed non-domestic discharge to a
POTW on that facility’s SPDES permit and pretreatment program. The DOW and EPA must
determine whether the POTW has adequately evaluated the effects of the proposed discharge on
POTW operation, sludge disposal, effluent quality, and POTW health and safety; whether the
discharge will result in the discharge of a substance that will be subject to effluent limits, action
levels, or other monitoring requirements in the facility’s SPDES permit; and whether the
proposed discharge contains any Bioaccumulative Chemicals of Concern or persistent toxic
substances that may be subject to SPDES effluent limits or other Departmental permit
requirements or controls. Appendix C of TOGS 1.3.8, Guidance for Acceptance of New
Discharges, describes the analyses and submittals necessary for a POTW to accept a new source
of wastewater. Note that if a facility has a currently approved headworks analysis in place for
the parameters and concentrations of those parameters typically found in flowback water and
production brine, the permittee may assess the impacts of the proposed discharge against the
existing headworks analysis.
The Department proposes to require, as a permit condition, that the permittee demonstrate that it
has a source to treat or otherwise legally dispose of wastewater associated with flowback and
production brine prior to the issuance of the drilling permit. Disposal and treatment options
include publicly owned treatment works, privately owned high volume hydraulic fracturing
wastewater treatment and/or reuse facilities, deep-well injection, and out of state disposal.

Final SGEIS 2015, Page 6-59

 Flowback water and production brine must be fully characterized prior to acceptance by a POTW
for treatment. Note in particular Appendix C. IV of TOGS 1.3.8, Maximum Allowable
Headworks Loading. The POTW must perform a MAHW analysis to assure that the flowback
water and production brine will not cause a violation of the POTW’s effluent limits or sludge
disposal criteria, allow pass through of unpermitted substances or inhibit the POTW’s treatment
processes. As a result, the SPDES permits for POTWs that accept this source of wastewater will
be modified to include influent and effluent limits for Radium and TDS, if not already included
in the existing SPDES permit, as well as for other parameters as necessary to ensure that the
permit correctly and completely characterizes the discharge. In the case of NORM, anyone
proposing to discharge flowback water or production brine to a POTW must first determine the
concentration of NORM present in those waste streams to determine appropriate treatment and
disposal options. POTW operators who accept these waste streams are advised to limit the
concentrations of NORM in the influent to their systems to prevent its inadvertent concentration
in their sludge. For example, due to the potentially large volumes of these waste waters that
could be processed through any given POTW, as well as the current lack of data on the level of
NORM concentration that may take place, it will be proposed that POTW influent concentrations
of radium-226 (as measured prior to admixture with POTW influent) be limited to 15 pCi/L, or
25% of the 60 pCi/L concentration value listed in 6 NYCRR Part 380-11.7. As more data
become available on concentrations in influent vs. sludge it is possible that this concentration
limit may be revisited.
Specific information regarding high volume hydraulic fracturing additives, such as chemical
makeup and aquatic toxicity, will be required for this analysis. A complete listing of all
ingredients in each chemical additive to be used shall be included as part of a headworks
analysis, along with aquatic toxicity data for each of the additives. If any confidentiality is
allowed under State law based upon the existence of proprietary material, that fact may be noted
in the submission. However, in no circumstance shall a fracturing additive be approved or
evaluated in a headworks analysis without aquatic toxicity data. Department approval of the
headworks analysis, and the modification of the POTW's SPDES permit if necessary, must be
received prior to the acceptance of flowback water or production brine from wells permitted
pursuant to this Supplement.

Final SGEIS 2015, Page 6-60

 In conducting the headworks analysis, the parameters that must be analyzed include, at a
minimum:
•

pH, range, SU;

•

Oil and Grease;

•

Solids, Total Suspended;

•

Solids, Total Dissolved;

•

Chloride;

•

Sulfate;

•

Alkalinity, Total (CaCO3);

•

BOD, 5 day;

•

Chemical Oxygen Demand (COD);

•

Total Kjeldahl Nitrogen (TKN);

•

Ammonia, as N;

•

Total Organic Carbon;

•

Phenols, Total;

•

the following scans:
o Priority Pollutants Metals;
o Priority Pollutants VOC;
o Priority Pollutants SVOC Base/Neutral; and
o Priority Pollutants SVOC Acid Extractable;

•

Radiological analysis including:
o Gross Alpha - EPA Method 900.0, Standard Methods 7110-B;
o Gross Beta - EPA Method 900.0, Standard Methods 7110-B;

Final SGEIS 2015, Page 6-61

 o Radium - EPA Method 903.0, Standard Methods 7500-Ra B;
o Uranium - EPA Method 908, Standard Methods 7500-U;and
o Thorium - EPA Method 910, Standard Methods 7500-Th;
•

constituents that were present in the hydraulic fracturing additives.

The high concentrations of TDS present in this source of wastewater may prove to be inhibitory
to biological wastewater treatment systems. It has been noted that the concentrations of TDS in
the return and process water increase as a higher percentage of native water is produced and then
stabilize over the life of the well. The expected concentrations of TDS for both the initial
flowback water as well as for the ongoing well operation must therefore be considered in the
development of the headworks analysis. It is incumbent upon the POTW to determine whether
the volumes and concentrations of chemicals present in the flowback water or production brine
would result in adverse impacts to the facility's treatment processes as part of the above
headworks analysis.
The Department has performed a very basic analysis to determine the potential available capacity
for POTWs to accept high-volume hydraulic fracturing wastewater. The Department estimates
that the POTWs within the approximate area of shale development in New York have an
aggregate available flow capacity of approximately 300 MGD, which is the difference between
existing flow and permitted flow. Based on this capacity, an estimate was developed to
determine the existing total treatment capacity based on the actual flows, existing TDS levels and
allowable TDS discharge limits. This estimate was based on a conservative assumption of
influent TDS from production brine. This estimate assumes that all of these POTWs would be
willing to accept this wastewater to their maximum available capacity, and that no other
increased discharges or other growth in the service area are expected. A TDS level of 350,000
mg/L will be used, as this is on the upper end of expected concentrations. Discharge levels from
POTWs would be limited to 1,000 mg/L. Typical influent levels of TDS at a POTW are
approximately 300 mg/L. Therefore, a typical POTW can be expected to have a disposal
capacity of approximately 700 mg/L (1,000 – 300mg/L) of TDS. Again assuming an influent
level of 350,000 mg/L of TDS and a disposal capacity of 700 mg/L at an existing POTW, the
dilution ratio of existing POTW flow to allowable high-volume hydraulic fracturing wastewater
influent flow is 500:1 (350,000 divided by 700). Based on this analysis, the maximum total

Final SGEIS 2015, Page 6-62

 capacity for disposal of high-volume hydraulic fracturing wastewater is estimated to be less than
1 MGD. The estimated production brine per well may range from 400 gpd to 3,400 gpd
depending on the life of the well.
The above analysis is subject to a number of assumptions which, when actual conditions are
factored in, will limit the available capacity to much less than 1 MGD. The analysis assumes
that the treatment facilities are willing to accept this source of wastewater; following its
December 2008 letter to POTWs outlining the requirements to accept high-volume hydraulic
fracturing wastewater, the Division of Water has yet to receive any requests from any POTW in
the State to accept this source of wastewater. The analysis assumes that POTWs are equipped to
take this source of wastewater and that haulers are willing to pump the waste into the POTW at
the rate that will be required to protect the POTW; no POTWs in New York State currently have
TDS-specific treatment technologies, so the ability to accept this wastewater is limited by
influent concentration and flow rates. The analysis assumes that the receiving water has
assimilative capacity to accept additional TDS loadings from POTWs and that the background
TDS in the receiving water is less than the in-stream water quality standard of 500 mg/L; there
are several streams in New York State which cannot accept additional TDS loads. Based on the
above, there is questionable available capacity for POTWs in New York State to accept highvolume hydraulic fracturing wastewater.
Case Study: One wellpad is expected to have 8 wells. Each well is expected to produce 3,000
gallons of production brine. Assuming 3,000 gpd x 8 wells = 24,000 gpd. With a 500:1 ratio
needed for disposal, a POTW with an existing flow of 12 mgd would be needed to dispose of the
production brine from this single wellpad.
Further, because of the inability of biological treatment systems to remove certain high-volume
hydraulic fracturing additives in flowback water, as previously described, POTWs are not
usually equipped to accept influent containing these contaminants. The potential for inhibition of
biological activity and sludge settling and the potential for radionuclide concentration in the
sludge impacts sludge disposal options.
As noted previously, acceptance of wastewater from high-volume hydraulic fracturing operations
must consider the impacts to POTW operation, sludge disposal, effluent quality, and POTW

Final SGEIS 2015, Page 6-63

 health and safety. Concentrations of NORM, specifically radium, in natural gas drilling
wastewater have the potential to impact POTW sludge disposal. At this time there is a lack of
detailed information on levels of NORM in POTW sludge and to what extent NORM that is
introduced to a POTW is concentrated in the sludge. Therefore, to ensure that POTW sludge
disposal is not affected, an influent radium-226 limit of 15 pCi/L for high-volume hydraulic
fracturing wastewater, to be determined prior to admixture with other POTW influents, would be
required in SPDES permits for any POTW that proposes to accept high-volume hydraulic
fracturing wastewater. It is noted that there are a number of water bodies in NY where the
ambient levels of TDS already exceed the water quality standard or where TDS has already been
fully allocated in existing SPDES permits. This may further limit the ability of POTWs to accept
these discharges.
6.1.8.2 Private Off-site Wastewater Treatment and/or Reuse Facilities
Privately owned facilities built specifically for the reuse and/or treatment and disposal of
industrial wastewater from high-volume hydraulic fracturing operate in other states, including
Pennsylvania. Similar facilities that might be constructed in New York would require a SPDES
permit if the operator of the facility intends to discharge treated effluent to surface or
groundwater. The treatment methods that would be applicable to these facilities are discussed in
Chapter 5. A number of adverse impacts are possible resulting from improper maintenance or
overloading of these systems, resulting in either surface or water discharges that do not comply
with applicable standards. However, properly maintained and regulated systems, along with
waste tracking and SPDES permitting control measures as described in Chapter 7 would mitigate
the potential for these impacts. The same limitations and impacts noted regarding the effects of
discharges from POTWs to the waters of the State, including the ability of the receiving water to
accept additional TDS loads, as described in Section 6.1.8.1 above, also apply to privatelyowned off-site treatment works.
6.1.8.3 Private On-site Wastewater Treatment and/or Reuse Facilities
As noted in Chapter 5 of this Draft SGEIS, on-site treatment of flowback water for purposes of
reuse is currently being used in Pennsylvania and other states. The treated water is blended with
fresh water at the well site and reused for hydraulic fracturing, with the treatment system residue
hauled off-site. A number of adverse impacts are possible resulting from improper maintenance

Final SGEIS 2015, Page 6-64

 or overloading of these systems, resulting in either surface or water discharges that do not
comply with applicable standards. However, properly maintained and operated treatment and/or
reuse systems, along with the waste tracking measures described in Chapter 7, would mitigate
the potential for these impacts. Because all applicable technology-based requirements must be
applied in NPDES/SPDES permits under the Clean Water Act section 402(a) and implementing
regulations at 40 CFR 125.3, an NPDES/SPDES permit issued for drilling activity would need to
be consistent with 40 CFR Part 435, Subpart C, which states that “there shall be no discharge of
wastewater pollutants into navigable waters from any source associated with production, field
exploration, drilling, well completion, or well treatment (i.e. production brine, drilling muds,
drill cuttings, and produced sand.”
6.1.8.4 Disposal Wells
As stated in the 1992 GEIS, the primary environmental consideration with respect to disposal
wells is the potential for movement of injected fluids into or between potential underground
sources of drinking water. The Department is not proposing to alter its 1992 Finding that
proposed disposal wells require individual site-specific review. Therefore, the potential for
significant adverse environmental impacts from any proposal to inject flowback water from highvolume hydraulic fracturing into a disposal well would be reviewed on a site-specific basis with
consideration to local geology (including faults and seismicity), hydrogeology, nearby wellbores
or other potential conduits for fluid migration and other pertinent site-specific factors.
6.1.8.5 Other Means of Wastewater Disposal
Wastewater generated by high-volume hydraulic fracturing would be able to be treated and
disposed of to the extent that available capacity exists using the disposal options referenced in
Section 6.1.8.4 above. Should wastewater be generated in volumes exceeding available capacity
within the State, the wastewater would require transport and disposal at facilities not located in
New York State, or additional treatment facilities to be constructed. Potential impacts that may
result from insufficient wastewater treatment capacity would include either storage of
wastewater and associated potential for leaks or spillage, illegal discharge of wastewater to the
ground surface or directly to waters of the State, and increased truck traffic resulting from
transport of wastewater to out of state treatment and disposal facilities.

Final SGEIS 2015, Page 6-65

 6.1.9

Solids Disposal

Most waste generated at a well site is in liquid form. Rock cuttings and the reserve pit liner are
the significant exception. The 1992 GEIS describes potential adverse impacts to agricultural
operations if materials are buried at too shallow a depth or work their way back up to the surface.
Concerns unique to Marcellus development and multi-well pad drilling are discussed below.
6.1.9.1 NORM Considerations - Cuttings
Gamma ray logs from deep wells drilled in New York over the past several decades show the
Marcellus Shale to be higher in radioactivity than other bedrock formations including other
potential reservoirs that could be developed by high-volume hydraulic fracturing. However,
based on the analytical results from field-screening and gamma ray spectroscopy performed on
samples of Marcellus Shale, NORM levels in cuttings are not likely to pose a problem because –
as set forth in Section 5.2.4.2 – the levels are similar to those naturally encountered in the
surrounding environment.
6.1.9.2 Cuttings Volume
As explained in Chapter 5, the total volume of drill cuttings produced from drilling a horizontal
well may be about 40% greater than that for a conventional, vertical well to the same target
depth. For multi-well pads, cuttings volume would be multiplied by the number of wells on the
pad. The potential water resources impact associated with the greater volume of drill cuttings
from multiple horizontal well drilling operations would arise from the retention of cuttings
during drilling, necessitating a larger reserve pit that may be present for a longer period of time,
unless the cuttings are directed into tanks as part of a closed-loop tank system. The geotechnical
stability and bearing capacity of buried cuttings, if left in a common pit, may need to be
reviewed prior to pit closure. 304
6.1.9.3 Cuttings and Liner Associated With Mud-Drilling
Operators have not proposed on-site burial of mud-drilled cuttings, which would be equivalent to
burial or direct ground discharge of the drilling mud itself. Contaminants in the mud or in
contact with the liner if buried on-site could adversely impact soil or leach into shallow
groundwater.

304

Alpha, 2009, p. 6-7.

Final SGEIS 2015, Page 6-66

 6.2

Floodplains

Flooding is hazardous to life, property and structures. Chapter 2 describes Flood Damage
Prevention Laws implemented by local communities to govern development in floodplains and
floodways and also provides information about recent flooding events in the Susquehanna and
Delaware River Basins. The GEIS summarizes the potential impacts of flood damage relative to
mud or reserve pits, production brine and oil tanks, other fluid tanks, brush debris, erosion and
topsoil, bulk supplies (including additives) and accidents. Severe flooding is described as “one
of the few ways” that bulk supplies such as additives “might accidentally enter the environment
in large quantities.” 305 Accordingly, construction of drill pads within flood plains raises serious
and significant environmental issues and risks.
6.3

Freshwater Wetlands

State regulation of wetlands is described in Chapter 2. The 1992 GEIS summarizes the potential
impacts to wetlands associated with interruption of natural drainage, flooding, erosion and
sedimentation, brush disposal, increased access and pit location, and those potential impacts are
applicable to high-volume hydraulic fracturing. Potential impacts to downstream wetlands as a
result of surface water withdrawal are discussed in Section 6.1.1.4 of this Supplement. Other
concerns described herein relative to stormwater runoff and surface spills and releases, also
extend to wetlands.
6.4

Ecosystems and Wildlife

The 1992 GEIS discusses the significant habitats known to exist at the time in or near thenexisting oil and gas fields (heronries, deer wintering areas, and uncommon, rare and endangered
plants). Significant habitats are defined as areas that provide one or more of the key factors
required for survival, variety, or abundance of wildlife, and/or for human recreation associated
with such wildlife. This section considers the potential impact of high-volume hydraulic
fracturing on all terrestrial habitat types, including forests, grasslands (including old fields
managed for grasslands, and pasture and hay fields) and shrublands. Four areas of concern
related to high-volume hydraulic fracturing are:
1) fragmentation of habitat;

305

NYSDEC, 1992, GEIS, p. 8-44

Final SGEIS 2015, Page 6-67

 2) potential transfer of invasive species;
3) potential impacts on endangered and threatened species; and
4) use of certain State-owned lands.
When the 1992 GEIS was developed, the scale and scope of the anticipated impact of oil and gas
drilling in New York State was much different than it is today. Development of low-permeability
reservoirs by high-volume hydraulic fracturing have the potential to draw substantial
development into New York, which is reasonably anticipated to result in potential impacts to
habitats (fragmentation, loss of connectivity, degradation, etc.), species distributions and
populations, and overall natural resource biodiversity.
The development of Marcellus Shale gas will have a large footprint. 306 In addition to direct loss
of habitat, constant activity on each well pad from construction, drilling, and waste removal can
be expected for 4 to 10 months, further affecting species. If a pad has multiple wells, it might be
active for several years. More land is disturbed for multi-well pads, but fewer access roads,
infrastructure, and total pads would be needed. Well pad sites are partially restored after drilling,
but 1-3 acres is typically left open for the life of the well (as are access roads and pipelines),
which is expected to be 20 to 40 years.
6.4.1

Impacts of Fragmentation to Terrestrial Habitats and Wildlife

Fragmentation is an alteration of habitats resulting in changes in area, configuration, or spatial
patterns from a previous state of greater continuity, and usually includes the following:

306

Environmental Law Clinic, 2010.

Final SGEIS 2015, Page 6-68

 •

Reduction in the total area of the habitat;

•

Decrease of the interior to edge ratio;

•

Isolation of one habitat fragment from other areas of habitat;

•

Breaking up of one patch of habitat into several smaller patches; and

•

Decrease in the average size of each patch of habitat.
General Direct, Indirect, and Cumulative Impacts:

Habitat loss, conversion, and fragmentation (both short-term and long-term) would result from
land grading and clearing, and the construction of well pads, roads, pipelines, and other
infrastructure associated with gas drilling. 307
Habitat loss is the direct conversion of surface area to uses not compatible with the needs of
wildlife, and can be measured by calculating the physical dimensions of well pads, roads, and
other infrastructure. In addition to loss of habitat, other potential direct impacts on wildlife from
drilling in the Marcellus Shale include increased mortality, increase of edge habitats, altered
microclimates, and increased traffic, noise, lighting, and well flares. Existing regulation of
wellhead and compressor station noise levels is designed to protect human noise receptors. Little
definitive work has been done on the effects of noise on wildlife. 308
Habitat degradation is the diminishment of habitat value or functionality; its indirect and
cumulative effects on wildlife are often assessed through analysis of landscape metrics. Indirect
and cumulative impacts may include a loss of genetic diversity, species isolation, population
declines in species that are sensitive to human noise and activity or dependent on large blocks of
habitat, increased predation, and an increase of invasive species. Certain life-history
characteristics, including typically long life spans, slow reproductive rates, and specific habitat
requirements for nesting and foraging, make raptor (birds of prey) populations especially
vulnerable to disturbances. Direct habitat loss has less impact than habitat degradation through

307

Environmental Law Clinic, 2010.

308

New Mexico Dept. Game & Fish, 2007.

Final SGEIS 2015, Page 6-69

 fragmentation and loss of connectivity due to widespread activities like oil and gas
development. 309
Biological systems are exceedingly complex, and there can be serious cascading ecological
consequences when these systems are disturbed. Little baseline data are available with which
comparisons can later be made in the attempt to document changes, or lack thereof, due to oil
and gas development. In cases where serious adverse consequences may reasonably be
expected, it is prudent to err on the side of caution. 310
Habitat fragmentation from human infrastructure has been identified as one of the greatest
threats to biological diversity. Research on habitat fragmentation impacts from oil and gas
development specific to New York is lacking. However, the two following studies from the
western United States are presented here to illustrate qualitatively the potential impacts to
terrestrial habitats that could occur in New York. A quantitative comparison between these
studies and potential impacts in New York is not possible because these studies were conducted
under a regulatory structure that resulted in well spacing that differs from those anticipated for
high-volume hydraulic fracturing in New York. Additional research would be necessary to
determine the precise impacts to species and wildlife expected from such drilling in New York’s
Marcellus Shale.
While fragmentation of all habitats is of conservation concern, the fragmentation of grasslands
and interior forest habitats are of utmost concern in New York. Some of the bird species that
depend on these habitat types are declining. This decline is particularly dramatic for grasslands
where 68% of the grassland-dependent birds in New York are declining. 311
Projected Direct Impacts
Study 1, General Discussion: The Wilderness Society conducted a study in 2008 312 that
provided both an analytical framework for examining habitat fragmentation and results from a
hypothetical GIS analysis simulating the incremental development of an oil and gas field to
309

New Mexico Dept. Game & Fish, 2007.

310

New Mexico Dept. Game & Fish, 2007.

311

Post 2006.

312

Wilbert et al., 2008.

Final SGEIS 2015, Page 6-70

 progressively higher well pad numbers over time. Results of the sample analysis gave a
preliminary estimate of the minimum potential fragmentation impacts of oil and gas development
on wildlife and their habitats; the results were not intended to be a substitute for site-specific
analyses.
The study identified a method to measure fragmentation (landscape metrics), and a way to tie
various degrees of fragmentation to their impacts on wildlife (from literature). Two
fragmentation indicator values (road density and distance-to-nearest-road or well pad) were
analyzed for impacts to a few important wildlife species present in oil and gas development areas
across the western U.S.
Study 1, Findings: The total area of direct disturbance from well pads and roads used in oil and
gas development was identified for a hypothetical undeveloped 120-acre site, with seven
separate well-pad densities - one pad per 640 acres, 320 acres, 160 acres, 80 acres, 40 acres, 20
acres, and 10 acres:
1. Well pads: the disturbance area increased approximately linearly as pad density
increased;
2. Total road length: the disturbance area increased more rapidly in the early stages of
development;
3. Mean road density: the rate of increase was higher at earlier stages of development. The
size of the pre-development road system had an effect on the magnitude of change
between subsequent development stages, but the effect decreased as development density
increased;
4. Distance-to-nearest-road (or well pad): the rate of decrease was higher at earlier stages of
development than at later stages; and
5. Significant negative effects on wildlife were predicted to occur over a substantial portion
of a landscape, even at the lower well pad densities characteristic of the early stages of
development in gas or oil fields.
This suggests that landscape-level planning for infrastructure development and analysis of
wildlife impacts need to be done prior to initial development of a field. Where development has
already occurred, the study authors recommend that existing impacts on local wildlife species be
measured and acknowledged, and the cumulative impacts from additional development be
assessed.
Final SGEIS 2015, Page 6-71

 Study 1, Implications for New York: The study results emphasize the importance of
maintaining undeveloped areas. Note that the degree of habitat fragmentation and the associated
impacts on wildlife from such development in real landscapes would be even greater than those
found in the study, which used conservative estimates of road networks (no closed loops, shorter
roads, and few roads pre-development) and did not include pipelines and other infrastructure.
Projected Indirect and Cumulative Impacts
Study 2, General Discussion: The Wilderness Society conducted a study in 2002 313 that analyzed
the landscape of an existing gas and oil field in Wyoming to identify habitat fragmentation
impacts. As fragmentation of the habitat occurred over a wide area, cumulative and indirect
impacts could not be adequately addressed at the individual well pad site level. Rather, analyzing
the overall ecological impacts of fragmentation on the composition, structure, and function of the
landscape required a GIS spatial analysis. A variety of metrics were developed to measure the
condition of the landscape and its level of fragmentation, including: density of roads and linear
features; acreage of habitat in close proximity to infrastructure; and acreage of continuous
uniform blocks of habitat or core areas.
Study 2, Findings: The study area covered 166 square miles, and contained 1864 wells,
equaling a density of 11 wells per square mile. 314 The direct physical footprint of oil and gas
infrastructure was only 4% of the study area; however, the ecological impact of that
infrastructure was much greater. The entire study area was within one-half mile of a road,
pipeline corridor, well head, or other infrastructure, while 97% fell within one-quarter mile.
Study results also showed the total number, total acreage, and the percent of study area
remaining in core areas decreased as the width of the infrastructure impact increased. No core
areas remained within one-half mile of infrastructure, and only 27% remained within 500 feet of
infrastructure. These results, combined with a review of the scientific literature for
fragmentation impacts to western focal species, indicated there was little to no place in the study
area where wildlife would not be impacted.

313

Weller et al. 2002.

314

Note that this density is between that of single horizontal wells (9 per square mile) and vertical wells (16 per square mile)
expected in New York (section 5.1.3.2).

Final SGEIS 2015, Page 6-72

 Study 2, Implications for New York: This study demonstrated that impacts to wildlife extended
beyond the direct effects from the land physically altered by oil and gas fields. Note that the
overall impacts predicted in the study were likely conservative as the data were only assessed at
the individual gas field scale, not the broader landscape. While well densities from multiple
horizontal wells from a common pad (a minimum of 1 well pad per square mile) would be less
than in this study, all three drilling scenarios might result in negative impacts to wildlife in New
York, as the impacts predicted to the complement of species in Wyoming were so extreme.
6.4.1.1 Impacts of Grassland Fragmentation
Grassland birds have been declining faster than any other habitat-species suite in the northeastern
United States. 315 The primary cause of these declines is the fragmentation of habitat caused by
the abandonment of agricultural lands, causing habitat loss due to reversion to later successional
stages or due to sprawl development. Remaining potential habitat is also being lost or severely
degraded by intensification of agricultural practices (e.g., conversion to row crops or early and
frequent mowing of hayfields).
Stabilizing the declines of populations of grassland birds has been identified as a conservation
priority by virtually all of the bird conservation initiatives, groups, and agencies in the
northeastern US, as well as across the continent, due to concern over how precipitous their
population declines have been across portions of their ranges (for the list of species of concern
and their population trends, see Table 6.2). In New York, grassland bird population declines are
linked strongly to the loss of agricultural grasslands, primarily hayfields and pastures; it is
therefore critical to conserve priority grasslands in order to stabilize or reverse these declining
trends.

315

Morgan and Burger 2008.

Final SGEIS 2015, Page 6-73

 Table 6.2 - Grassland Bird Population Trends at Three Scales from 1966 to 2005. 316 (New July 2011)

Some of New York’s grassland birds have experienced steeper declines than others, or have a
smaller population size and/or distribution across the state or region, and are therefore included
in the highest priority tier in Table 6.2: northern harrier (Circus cyaneus), upland sandpiper
(Bartramia longicauda), short-eared owl (Asio flammeus), sedge wren (Cistothorus platensis),
Henslow's sparrow (Ammodramus henslowii), grasshopper sparrow (Ammodramus savannarum),
bobolink (Dolichonyx oryzivorus), and loggerhead shrike (Lanius ludovicianus). Species
included in the high priority tier are those that have been given relatively lower priority, but
whose populations are also declining and are in need of conservation. The high priority tier in

316

Morgan and Burger, 2008.

Final SGEIS 2015, Page 6-74

 Table 6.2 includes: horned lark (Eremophila alpestris), vesper sparrow (Pooecetes gramineus),
eastern meadowlark (Sturnella magna), and savannah sparrow (Passerculus sandwichensis).
While these birds rely on grasslands in New York as breeding habitat (in general), two of these
species (northern harrier and short-eared owl) and several other raptor species also rely on
grasslands for wintering habitat. For this reason, a third target group of birds are those species
that rely on grassland habitats while they over-winter (or are year-round residents) in New York,
and include: snowy owl (Bubo scandiacus), rough-legged hawk (Buteo lagopus), red-tailed hawk
(Buteo jamaicensis), American kestrel (Falco sparverius), and northern shrike (Lanius
excubitor).
The specific effects of drilling for natural gas on nesting grassland birds are not well studied.
However, the level of development expected for multi-pad horizontal drilling and minimum
patch sizes of habitat necessary for bird reproduction, unless mitigated, will result in substantial
impacts from the fragmentation of existing grassland habitats. Minimum patch sizes would vary
by species and by surrounding land uses, but studies have shown that a minimum patch size of
between 30-100 acres is necessary to protect a wide assemblage of grassland-dependent
species. 317
6.4.1.2 Impacts of Forest Fragmentation
Forest fragmentation issues were the subject of two assessments referenced below which are
specific to the East and address multiple horizontal well drilling from common pads. These
studies, therefore, are more directly applicable to New York than previously mentioned western
studies of vertical drilling. The Multi-Resolution Land Characteristic Dataset (“MRLC”) (2004)
indicates the following ratios of habitat types in the area underlain by the Marcellus shale in New
York: 57% forested; 28% grassland/agricultural lands; and 3% scrub/shrub. The other 12% is
divided evenly between developed land and open water/wetlands. As forests are the most
common cover type, it is reasonable to assume that development of the Marcellus Shale would
have a substantial impact on forest habitats and species.

317

USFWS n.d., Sample and Mossman 1997, Mitchell et al, 2000.

Final SGEIS 2015, Page 6-75

 Today, New York is 63% (18.95 million acres) forested 318 and is unlikely to substantially
increase. Current forest parcelization and fragmentation trends will likely result in future losses
of large, contiguous forested areas. 319 Therefore, protecting these remaining areas is very
important for maintaining the diversity of wildlife in New York.
The forest complex provides key ecosystem services that provide substantial ecological,
economic, and social benefits (water quality protection, clean air, flood protection, pollination,
pest predation, wildlife habitat and diversity, recreational opportunities, etc.) that extend far
beyond the boundaries of any individual forested area.
Large contiguous forest patches are especially valuable because they sustain wide-ranging forest
species, and provide more habitat for forest interior species. They are also more resistant to the
spread of invasive species, suffer less tree damage from wind and ice storms, and provide more
ecosystem services – from carbon storage to water filtration – than small patches, 320
Lands adjacent to well pads and infrastructure can also be affected, even if they are not directly
cleared. This is most notable in forest settings where clearings fragment contiguous forest
patches, create new edges, and change habitat conditions for sensitive wildlife and plant species
that depend on interior forest conditions.
Forest ecologists call this the edge effect. While the effect is somewhat different for each
species, research has shown measurable impacts often extend at least 330 feet (100 meters) into
forest adjacent to an edge. 321 Interior forest species avoid edges for different reasons. Blackthroated blue warblers and other interior forest birds, for example, avoid areas near edges during
nesting season because of the increased risk of predation. Tree frogs, flying squirrels and certain
woodland flowers are sensitive to forest fragmentation because of changes in canopy cover,
humidity and light levels. Some species, such as white-tailed deer and cowbirds, are attracted to
forest edges – often resulting in increased competition, predation, parasitism, and herbivory.
Invasive plant species, such as tree of heaven, stilt grass, and Japanese barberry, often thrive on
318

NYSDEC, Forest Resource Assessment and Strategy, 2010.

319

NYSDEC, Forest Resource Assessment and Strategy, 2010.

320

Johnson, 2010, p. 19.

321

Johnson, 2010, p. 11.

Final SGEIS 2015, Page 6-76

 forest edges and can displace native forest species. As large forest patches become progressively
cut into smaller patches, populations of forest interior species decline.
Lessons Learned from Pennsylvania
Assessment 1, General Discussion: The Nature Conservancy (TNC) conducted an assessment in
2010 322 to develop credible energy development projections for horizontal hydraulic fracturing
in Pennsylvania’s Marcellus Shale by 2030, and how those projections might affect high priority
conservation areas, including forests. The projections were informed scenarios, not predictions,
for how much energy development might take place and where it was more and less probable.
Project impacts, however, were based on measurements of actual spatial footprints for hundreds
of well pads.
Potential Direct Impacts, Methodology and Assessment Findings: Projections of future
Marcellus gas development impacts depended on robust spatial measurements for existing
Marcellus well pads and infrastructure. This assessment compared aerial photos of Pennsylvania
Department of Environmental Protection (PADEP) Marcellus well permit locations taken before
and after development and precisely documented the spatial foot print of 242 Marcellus well
pads (totaling 435 drilling permits) in Pennsylvania.
Well pads in Pennsylvania occupy 3.1 acres on average while the associated infrastructure
(roads, water impoundments, pipelines) takes up an additional 5.7 acres, or a total of nearly 9
acres per well pad (Figure 6.5). 323

322

Johnson, 2010.

323

This is larger than the 7.4 acres predicted by IOGA to be disturbed in New York (section 6.4b).

Final SGEIS 2015, Page 6-77

 Figure 6.5 - Average Spatial Disturbance for Marcellus Shale Well Pads in Forested Context 324 (New July 2011)

Another key variable for determining land-use and habitat impacts in this assessment was the
number of wells on each pad; more wells per pad translated to less disturbance and infrastructure
on the landscape. It is technically possible to put a dozen or more Marcellus wells on one pad.
For the 242 well pads assessed in this study, the average in Pennsylvania has been 2 wells per
pad to date (IOGA estimates the same for New York) as companies quickly moved on to drill
other leases to test productivity and to secure as many potentially productive leases as possible
(leases typically expire after 5 years if there is no drilling activity). TNC assumed that in many
cases, the gas company would return to these pads later and drill additional wells. This
assumption may not be valid in New York where there is a three-year limit on well development
(ECL 23-0501).
The TNC assessment developed low, medium, and high scenarios for the amount of energy
development that might take place in Pennsylvania. The projections included a conservative
estimate of 250 horizontal drilling rigs, each of which could drill one well per month, resulting in

324

Taken from Johnson, 2010, p. 10.

Final SGEIS 2015, Page 6-78

 an estimated 3,000 wells drilled annually. Estimates in New York predict less activity than this,
but activity could result in approximately 40,000 wells by 2040.
The low scenario (6,000 well pads) assumed that each pad on average would have 10 wells, or 1
well pad per 620 acres. Because many leases are irregularly shaped, in mixed ownership, or
their topography and geology impose constraints, TNC concluded that it is unlikely this scenario
would develop in Pennsylvania. It would take relatively consolidated leaseholds and few
logistical constraints for this scenario to occur. 325
The medium scenario for well pads assumed 6 wells on average would be drilled from each pad
(10,000 well pads), or 1 pad per 386 acres. Industry generally agreed that 6 is the most likely
number of wells they would be developing per pad for most of their leaseholds in
Pennsylvania. 326
The high scenario assumed each pad would have 4 wells drilled on average (15,000 well pads),
or 1 pad per 258 acres. This scenario is more likely if there is relatively little consolidation of
lease holds between companies in the next several years. While this scenario would result in a
loss of less than 1% of Pennsylvania’s total forest acreage, areas with intensive Marcellus gas
development could see a loss of 2-3% of local forest habitats.
In summary, 60,000 wells could be drilled by 2030 in the area underlain by the Marcellus Shale
in Pennsylvania on between 6,000 and 15,000 new well pads (there are currently about 1,000),
depending on how many wells are placed on each pad.
A majority (64%) of projected well locations were found in a forest setting for all three
scenarios. By 2030, a range of between 34,000 and 82,000 acres of forest cover could be cleared
by new Marcellus gas development in Pennsylvania. Some part of the cleared forest area would
become reforested after drilling is completed, but there has not been enough time to establish a
trend since the Marcellus development started.

325

Note that while no definitive number is provided in section 5.1.3.2, this is expected to be the most common spacing for
horizontal drilling in New York’s Marcellus Shale.

326

Note that IOGA assumes that 6 horizontal wells would be drilled per pad in New York.

Final SGEIS 2015, Page 6-79

 Potential Direct Impacts, Implications for New York: Direct land disturbance from horizontal
hydraulic fracturing of Marcellus Shale in New York is expected to result in 7.4 acres of direct
impacts from each well pad and associated infrastructure. This is different from the experiences
in Pennsylvania where nearly 9 acres of habitat was removed for each well pad and its associated
infrastructure. Under either scenario, the direct impacts are substantial.
The most likely drilling scenario in Pennsylvania would result in a density of 1 pad per 386
acres. However, given New York’s regulatory structure, a spacing of 1 pad per 640 acres is
anticipated. If spacing units are less than 640 acres, or if there are less than 6-8 horizontal wells
per pad, the percentage of land disturbance could be greater. Again, using the set of currently
pending applications as an example, the 47 proposed horizontal wells would be drilled on eleven
separate well pads, with between 2 and 6 wells for each pad. Therefore, greater than 1.2% land
disturbance per pad estimated by industry can be expected in New York.
Potential Indirect Impacts, Methodology and Assessment Findings: To assess the potential
interior forest habitat impact, a 100-meter buffer was created into forest patches from new edges
created by well pad and associated infrastructure development (Figure 6.6). For those well sites
developed in forest areas or along forest edges (about half of the assessed sites), TNC calculated
an average of 21 acres of interior forest habitat was lost. Thus, the total combined loss of habitat
was 30 acres per well pad due to direct and indirect impacts. Figure 6.5 summarizes these data.
In addition to the direct clearing of between 34,000 to 82,000 acres of forest cover in
Pennsylvania, forest interior species could be negatively impacted within an additional 85,000 to
190,000 forest acres adjacent to Marcellus development. Forest impacts would be concentrated
where many of Pennsylvania’s largest and most intact forest patches occur, resulting in
fragmentation into smaller patches by well pads, roads, and other infrastructure. In contrast to
overall forest loss, projected Marcellus gas development scenarios in Pennsylvania indicate a
more pronounced impact on large forest patches. Impacts to forest interior species would vary
depending on their geographic distribution and density. Some species, such as the black-throated
blue warbler, could see widespread impacts to their relatively restricted breeding habitats in the
state, while widely distributed species such as the scarlet tanager, would be relatively less
affected.

Final SGEIS 2015, Page 6-80

 Figure 6.6 – Interior Forest Habitat Before & After Development of a
Marcellus Gas Well Pad, Elk County PA 327 (New July 2011)

This study went on to find that locating energy infrastructure in open areas or toward the outer
edges of large patches can significantly reduce impacts to important forest areas. To address this
finding and explore potential ways in which conservation impacts could be minimized, TNC
examined how projected Marcellus gas pads could be relocated to avoid forest patches in a
specific region of Pennsylvania. To reduce the impacts to forest habitats, the wells were
hypothetically relocated, where practicable, to nearby existing openings maintained by human
activity (e.g., old fields, agricultural fields). If nearby open areas did not exist, the locations of
the well pads were moved toward the edges of forest patches to minimize impacts to forest
interior habitats. This exercise did not eliminate forest impacts in this heavily forested
Pennsylvania landscape, but there was a significant reduction in impacts. Total forest loss
declined almost 40% while impacts to interior forest habitats adjacent to new clearings declined
by one-third (Figure 6.7). The study authors recommend that information about Pennsylvania’s
important natural habitats be an important part of the calculus about trade-offs and optimization
as energy development proceeds.

327

Taken from Johnson, 2010, p. 11.

Final SGEIS 2015, Page 6-81

 Figure 6.7 - Total Forest Areas Converted 328 (New July 2011)

Potential Indirect Impacts, Implications for New York: For each acre of forest directly
cleared for well pads and infrastructure in New York, an additional 2.5 acres can be expected to
be indirectly impacted. Interior forest bird species with restricted breeding habitats, such as the
black-throated blue and cerulean warblers, might be highly impacted.
Additional assessment work conducted for New York based on estimates and locations of well
pad densities across the Marcellus landscape could better quantify expected impacts to forest
interior habitats and wildlife.
New York Forest Matrix and Landscape Connectivity
Forest matrix blocks contain mature forests with old trees, understories, and soils that guarantee
increased structural diversity and habitat important to many species. They include important
stabilizing features such as large, decaying trunks on the forest floor and big, standing snags. Set
within these matrix forests are smaller ecosystems offering a wide range of habitat (wetlands,

328

Taken from Johnson, 2010, p. 27

Final SGEIS 2015, Page 6-82

 streams, and riparian areas) that depend on the surrounding forested landscape for their longterm persistence and health. These large, contiguous areas are viable examples of the dominant
forest types that, if protected, and in some cases allowed to regain their natural condition, serve
as critical source areas for all species requiring interior forest conditions. Few remnants of such
matrix blocks remain in the Northeast; it is therefore critical to conserve these priority areas to
ensure long-term conservation of biodiversity. 329
Assessment 2, General Discussion: The New York Natural Heritage program in 2010 330
identified New York’s forest matrix blocks and predicted corresponding forest connectivity
areas. Securing connections between major forested landscapes and their imbedded matrix forest
blocks is important for the maintenance of viable populations of species, especially those that are
wide-ranging and highly mobile, and ecological processes such as dispersal and pollination over
the long term. Identifying, maintaining, and enhancing these connections represents a critical
adaptation strategy if species are to shift their ranges in response to climate change and other
landscape changes.
Assessment 2, Findings. Figure 6.8 depicts the large forested landscapes within New York and
predicts the linkages between them, called least-cost path (LCP). A least-cost path corridor
represents the most favorable dispersal path for forest species based on a combination of percent
natural forest cover in a defined area, barriers to movement, and distance traveled. Thus, as
many species that live in forests generally prefer to travel through a landscape with less human
development (i.e., fewer impediments to transit) as well as in a relatively direct line, the
predicted routes depict a balance of these sometimes opposing needs.
Assessment 2, Implications for New York: The area underlain by the Marcellus Shale in New
York is 57% forested with about 7% of that forest cover occurring on State-owned lands. It is
reasonable to assume high-volume horizontal hydraulic fracturing would have negative impacts
to forest habitats similar to those predicted in Pennsylvania (Section 6.4.1.2).
In order to minimize habitat fragmentation and resulting restrictions to species movement in the
area underlain by the Marcellus, it is recommended that forest matrix blocks be managed to
329

TNC 2004.

330

NYSDEC, Strategic Plan for State Forest Management, 2010.

Final SGEIS 2015, Page 6-83

 create, maintain, and enhance the forest cover characteristics that are most beneficial to the
priority species that may use them.
Figure 6.8 - New York's Forest Matrix Blocks and State Connectivity 331 (New July 2011)

HAL = High Allegheny Plateau; LNE = Lower New England/Northern Piedmont; NAP= Northern Appalachian/ Acadian;
STL= St. Lawrence-Champlain Valley

6.4.2

Invasive Species

An invasive species, as defined by ECL §9-1703, is a species that is nonnative to the ecosystem
under consideration and whose introduction causes or is likely to cause economic or
environmental harm or harm to human health. Invasive species can be plants, animals, and other
organisms such as microbes, and can impact both terrestrial and aquatic ecosystems.

331

Taken from NYSDEC, Strategic Plan for State Forest Management, 2010.

Final SGEIS 2015, Page 6-84

 While natural means such as water currents, weather patterns and migratory animals can
transport invasive species, human actions - both intentional and accidental - are the primary
means of invasive species introductions to new ecosystems. Once introduced, invasive species
usually spread profusely because they often have no native predators or diseases to limit their
reproduction and control their population size. As a result, invasive species out-compete native
species that have these controls in place, thus diminishing biological diversity, altering natural
community structure and, in some cases, changing ecosystem processes. These environmental
impacts can further impose economic impacts as well, particularly in the water supply,
agricultural and recreational sectors. 332
The number of vehicle trips associated with high-volume hydraulic fracturing, particularly at
multi-well sites, has been identified as an activity which presents the opportunity to transfer
invasive terrestrial species. Surface water withdrawals also have the potential to transfer
invasive aquatic species.
6.4.2.1 Terrestrial
Terrestrial plant species which are widely recognized as invasive 333 or potentially-invasive in
New York State, and are therefore of concern, are listed in Table 6.3 below.
Table 6.3 - Terrestrial Invasive Plant Species In New York State (Interim List) 334,335

Terrestrial – Herbaceous
Common Name
Garlic Mustard
Mugwort
Brown Knapweed
Black Knapweed
Spotted Knapweed
Canada Thistle
Bull Thistle

Scientific Name
Alliaria petiolata
Artemisia vulgaris
Centaurea jacea
Centaurea nigra
Centaurea stoebe ssp. micranthos
Cirsium arvense
Cirsium vulgare

332

ECL §9-1701.

333

As per ECL §9-1703.

334

NYSDEC, DFWMR March 13, 2009. Interim List of Invasive Plant Species in New York State

335

This list was prepared pursuant to ECL §9-1705(5)(b) and ECL §9-1709(2)(d), but is not the so-called “four-Tier lists”
referenced in ECL §9-1705(5)(h). As such the interim list is expected to be supplanted by the “four-Tier list” at such time that
it becomes available.

Final SGEIS 2015, Page 6-85

 Terrestrial – Herbaceous
Common Name
Crown vetch
Black swallow-wort
European Swallow-wort
Fuller’s Teasel
Cutleaf Teasel
Giant Hogweed
Japanese Stilt Grass

Scientific Name
Coronilla varia
Cynanchum louiseae (nigrum)
Cynanchum rossicum
Dipsacus fullonum
Dipsacus laciniatus
Heracleum mantegazzianum
Microstegium vimineum
Terrestrial - Vines

Common Name

Scientific Name

Porcelain Berry
Oriental Bittersweet
Japanese Honeysuckle
Mile-a-minute Weed
Kudzu

Ampelopsis brevipedunculata
Celastrus orbiculatus
Lonicera japonica
Persicaria perfoliata
Pueraria montana var. lobata

Terrestrial – Shrubs & Trees
Common Name

Scientific Name

Norway Maple
Tree of Heaven
Japanese Barberry
Russian Olive
Autumn Olive
Glossy Buckthorn
Border Privet
Amur Honeysuckle
Shrub Honeysuckles
Bradford Pear
Common Buckthorn
Black Locust
Multiflora Rose

Acer platanoides
Ailanthus altissima
Berberis thunbergii
Elaeagnus angustifolia
Elaeagnus umbellata
Frangula alnus
Ligustrum obtusifolium
Lonicera maackii
Lonicera morrowii/tatarica/x bella
Pyrus calleryana
Rhamnus cathartica
Robinia pseudoacacia
Rosa multiflora

Final SGEIS 2015, Page 6-86

 Operations involving land disturbance such as the construction of well pads, access roads, and
engineered surface impoundments for fresh water storage have the potential to both introduce
and transfer invasive species populations. Machinery and equipment used to remove vegetation
and soil may come in contact with invasive plant species that exist at the site and may
inadvertently transfer those species’ seeds, roots, or other viable plant parts via tires,
treads/tracks, buckets, etc. to another location on site, to a separate project site, or to any location
in between.
The top soil that is stripped from the surface of the site during construction and set aside for reuse during reclamation also presents an opportunity for the establishment of an invasive species
population if it is left exposed. Additionally, fill sources (e.g., gravel, crushed stone) brought to
the well site for construction purposes also have the potential to act as a pathway for invasive
species transfer if the fill source itself contains viable plant parts, seeds, or roots.
6.4.2.2 Aquatic
The presence of non-indigenous aquatic invasive species in New York State waters is
recognized, and, therefore, operations associated with the withdrawal, transport, and use of water
for horizontal well drilling and high volume hydraulic fracturing operations have the potential to
transfer invasive species. Species of concern include, but are not necessarily limited to; zebra
mussels, eurasian watermilfoil, alewife, water chestnut, fanwort, curly-leaf pondweed, round
goby, white perch, didymo, and the spiny water flea. Other aquatic, wetland and littoral plant
species that are of concern due to their status as invasive 336 or potentially-invasive in New York
State are listed in Table 6.4.

336

As per ECL §9-1703.

Final SGEIS 2015, Page 6-87

 Table 6.4 - Aquatic, Wetland & Littoral Invasive Plant Species in New York State (Interim List) 337,338

Floating & Submerged Aquatic
Common Name
Carolina Fanwort
Rock Snot (didymo)
Brazilian Elodea
Water thyme
European Frog's Bit
Floating Water Primrose
Parrot-feather
Variable Watermilfoil
Eurasian Watermilfoil
Brittle Naiad
Starry Stonewort (green alga)
Yellow Floating Heart
Water-lettuce
Curly-leaf Pondweed
Water Chestnut

Scientific Name
Cabomba caroliniana
Didymosphenia geminata
Egeria densa
Hydrilla verticillata
Hydrocharis morus-ranae
Ludwigia peploides
Myriophyllum aquaticum
Myriophyllum heterophyllum
Myriophyllum spicatum
Najas minor
Nitellopsis obtusa
Nymphoides peltata
Pistia stratiotes
Potamogeton crispus
Trapa natans

Emergent Wetland & Littoral
Common Name

Scientific Name

Flowering Rush
Japanese Knotweed
Giant Knotweed
Yellow Iris
Purple Loosestrife
Reed Canarygrass
Common Reed- nonnative variety

Butomus umbellatus
Fallopia japonica
Fallopia sachalinensis
Iris pseudacorus
Lythrum salicaria
Phalaris arundinacea
Phragmites australis var. australis

337

NYSDEC, DRWMR March 13, 2009 Interim List of Invasive Plant Species in New York State

338

This list was prepared pursuant to ECL §9-1705(5)(b) and ECL §9-1709(2)(d) ), but is not the so-called “four-Tier lists”
referenced in ECL §9-1705(5)(h). As such the interim list is expected to be supplanted by the “four-Tier list” at such time that
it becomes available.

Final SGEIS 2015, Page 6-88

 Invasive species may be transported with the fresh water withdrawn for, but not used for drilling
or hydraulic fracturing. Invasive species may potentially be transferred to a new area or
watershed if unused water containing such species is later discharged at another location. Other
potential mechanisms for the possible transfer of invasive aquatic species may include trucks,
hoses, pipelines and other equipment used for water withdrawal and transport.
6.4.3

Impacts to Endangered and Threatened Species

The area underlain by the Marcellus Shale includes both terrestrial and aquatic habitat for 18
animal species listed as endangered or threatened in New York State (Table 6.5 and Figure 6.9)
protected under the State Endangered Species Law (ECL 11-0535) and associated regulations (6
NYCRR Part 182). Some species, such as the northern harrier and upland sandpiper, are
dependent upon grassland habitat for breeding and foraging and can be found in many counties
within the project area. Species such as the rayed bean mussel and mooneye fish are aquatic
species limited to only two counties on the western edge of the project area. Other species are
associated with woodlands, with bald eagles nesting in woodlands adjacent to lakes, rivers and
ponds throughout many counties within the project area. The area also includes habitat for
cerulean warblers and eastern hellbenders, two species currently under consideration for listing
by both the State and the federal government.
Endangered and threatened wildlife may be adversely impacted through project actions such as
clearing, grading and road building that occur within the habitats that they occupy. Certain
species are unable to avoid direct impact due to their inherent poor mobility (e.g., Blanding’s
turtle, club shell mussel). Certain actions, such as clearing of vegetation or alteration of stream
beds, can also result in the loss of nesting and spawning areas. If these actions occur during the
time of year that species are breeding, there can be a direct loss of eggs and/or young. For
species that are limited to specific habitat types for breeding, the loss of the breeding area can
result in a loss of productivity in future years as adults are forced into less suitable habitat. Any
road construction through streams or wetlands within habitats occupied by these species can
result in the creation of impermeable barriers to movement for aquatic species and reduce
dispersal for some terrestrial species. Other impacts from the project, such as increased vehicle
traffic, can result in direct mortality of adult animals. In general, the loss of habitat in areas

Final SGEIS 2015, Page 6-89

 occupied by listed species can result in reduced numbers of breeding pairs and lowered
productivity.
Table 6.5 - Endangered & Threatened Animal Species within the Area Underlain by the Marcellus Shale

339

November 3, 2010

Final SGEIS 2015, Page 6-90

339

(New July 2011)

 Figure 6.9 - Areas of Concern for Endangered and Threatened Animal Species, March 31, 2011 (New July
2011)

6.4.4

Impacts to State-Owned Lands

State-owned lands play a unique role in New York’s landscape because they are managed under
public ownership to allow for sustainable use of natural resources, provide recreational
opportunities for all New Yorkers, and provide important wildlife habitat and open space. They
represent the most significant portions of large contiguous forest patch in the study area.
Industrial development on these lands is, for the most part, prohibited, and any type of clearing
and development on these lands is limited and managed. Given the level of development
expected for multi-pad horizontal drilling, it is anticipated that there would be additional pressure
for surface disturbance on state-owned lands. Surface disturbance associated with gas extraction
could have a significant adverse impact on habitats contained on the state-owned lands, and
recreational use of those lands.

Final SGEIS 2015, Page 6-91

 Forest Habitat Fragmentation
As described earlier, large contiguous forest patches are especially valuable because they sustain
wide-ranging forest species, and provide more habitat for forest interior species. State-owned
lands, by their very nature, consist of large contiguous forest patches. While some fragmentation
has occurred, the level of activity associated with multi-well horizontal drilling (e.g., well pad
construction, access roads, pipelines, etc.) would negatively impact the state’s ability to maintain
the existing large contiguous patches of forest.
The Department has stated that protecting these areas from further fragmentation is a high
priority. One of the objectives stated in the Strategic Plan for State Forest Management is to
“emphasize closed canopy and interior forest conditions to maintain and enhance” forest matrix
blocks. It is critical therefore, that any additional road, pipeline and well pad construction be
carefully assessed in order to avoid further reducing this habitat (see also Section 6.4.1). Given
the State’s responsibility to protect these lands as steward of the public trust, the State has a
heightened responsibility, as compared to its role with respect to private lands, to ensure that any
State permitted action does not adversely impact the ecosystems and habitat on these public
lands so that they may be enjoyed by future generations.
Public Recreation
State-owned lands have been acquired over the past century to provide compatible public
recreation opportunities, protect watersheds, and provide sustainable timber harvesting. Drilling
and trucking activities disturb the tranquility found on these lands and can cause significant
visual impacts. Also, many State Forest roads serve as recreational trails for bicyclists,
horseback riders, snowmobilers and others. The level of truck traffic associated with horizontal
drilling and high-volume hydraulic fracturing presents safety issues, and would significantly
degrade the experience for users of these roads, if not altogether during the drilling and
construction phases of development.
Legal Considerations
State Forests have an identity that is distinct from private lands, prescribed by the NYS
Constitution, the ECL and the Environmental Quality Bond Acts of 1972 and 1986, under the

Final SGEIS 2015, Page 6-92

 provisions of which they were acquired. New York State Constitution Article XIV, Section 3(1)
states:
“Forest and wild life conservation are hereby declared to be policies of the state.
For the purposes of carrying out such policies the legislature may appropriate
moneys for the acquisition by the state of land, outside of the Adirondack and
Catskill parks as now fixed by law, for the practice of forest or wild life
conservation.”
ECL Section 9-0501(1), in keeping with the above constitutional provision, authorizes the state
to acquire reforestation areas, “which are adapted for reforestation and the establishment and
maintenance thereon of forests for watershed protection, the production of timber and other
forests products, and for recreation and kindred purposes,. . .which shall be forever devoted to
the planting, growth and harvesting of such trees...”
Similarly, ECL Section 11-2103(1) authorizes the state to acquire “lands, waters or lands and
waters…for the purpose of establishing and maintaining public hunting, trapping and fishing
grounds.”
ECL Section 9-0507 provides the Department discretionary authority to lease oil and gas rights
on reforestation areas, provided that “such leasehold rights shall not interfere with the operation
of such reforestation areas for the purposes for which they were acquired and as defined in
Section 3 of Article XIV of the Constitution.” The expected volume of truck traffic, the
expected acreage that would be converted to non-forest use in the form of well pads, roads and
pipelines, and noise and other impacts, raise serious questions as to how the surface activities
anticipated with horizontal drilling and high-volume hydraulic fracturing could be viewed as
consistent with this provision of the ECL.
For Wildlife Management Areas (WMAs) there are additional legal considerations stemming
from the use of federal funds. Many WMAs were purchased using Federal Aid in Wildlife
Restoration (Pittman-Robertson) funds and all are managed/maintained using Pittman-Robertson
funds. Under these provisions, any surface use of the land must not be in conflict with the
intended use as a WMA. These areas are managed for natural habitats to benefit wildlife, and
disturbance associated with multi-pad wells raises questions about compatibility with essential

Final SGEIS 2015, Page 6-93

 wildlife behaviors such as breeding, raising young, and preparation for migration. Also, selling
or leasing of minerals rights must be approved by the U.S. Fish and Wildlife Service, and may
require reimbursement of the federal government for revenue generated. In addition, siting well
pads on WMAs purchased with Conservation Fund monies may require additional mitigation
under federal statutes and/or compensation.
6.5

Air Quality

6.5.1

Regulatory Overview

This section provides a comprehensive list of federal and New York State regulations which
could potentially be applicable to air emissions and air quality impacts associated with the
drilling, completion (hydraulic fracturing and flowback) and production phases (processing,
transmission and storage). At each of these phases, there are a number of air emission sources
that may be subject to regulation. These general regulatory requirements are then followed by
specific information regarding emission sources that have potential regulatory implications, as
presented below in Sections 6.5.1.1 to 6.5.1.8. Certain discussions reflect new industry
information provided in response to Department requests, as well as finalization, clarification,
and revision to EPA regulations and policy. For example, the definition of what constitutes a
stationary source or “facility” has been refined for criteria pollutants. These discussions are then
followed with Department rule-applicability determinations on in instances where such decisions
can be made as part of the SGEIS, as well as how the Department envisions the permitting of
specific operations should proceed (Section 6.5.1.8).
Applicable Federal Regulations
Prevention of Significant Deterioration of Air Quality (PSD): Under the PSD program, a
federally-enforceable permit is required in order to restrict emissions from new major or major
modification to existing sources (e.g., power plants and manufacturing facilities which emit
criteria air pollutants in quantities above 100 tons per year) located in areas classified as
attainment or unclassifiable with respect to the http://www.epa.gov/ttn/naaqs/. That is, PSD
requirements apply to all pollutants that do not exceed the NAAQS in the source location area.
The NAAQS are numerical maximum pollution levels set to protect public health and welfare
which have been established for ozone (O3), nitrogen dioxide (NO2), sulfur dioxide (SO2), fine
particulate matter (PM10 and PM2.5), carbon monoxide (CO) and lead. The federal PSD

Final SGEIS 2015, Page 6-94

 program is contained in 40 CFR Section 52.21 and the federally approved State program is found
at 6 NYCRR Part 231.
Nonattainment New Source Review (NNSR): This federal program applies to new major or
modified existing major sources in areas where the NAAQS are exceeded. The requirements for
source emissions and potential impacts are more restrictive than through the PSD program. The
federal program is found at 40 CFR Section 51.165 and the federally approved State program is
found at 6 NYCRR Part 231. In New York State, nonattainment requirements are currently
applicable to major sources of O3 precursors (NOx and VOC) and direct PM2.5 and its precursor
emissions (SO2 and NOx). EPA has approved 6 NYCRR Part 231 into the State Implementation
Plan. The regulation is described further under “Applicable State Regulations” below.
New Source Performance Standards (NSPS): Section 111 of the Clean Air Act (CAA) requires
EPA to adopt emissions standards that are applicable to new, modified, and reconstructed
sources. The requirements are meant to force new facilities to perform as well as or better than
the best existing facilities (commonly known as “best demonstrated technology”). As new
technology advances are made, EPA is required to revise and update NSPS applicable to
designated sources. The following federal NSPS may apply:
•

40 CFR Part 60, Subpart JJJJ, Standards of Performance for Stationary Spark Ignition
(SI) Internal Combustion Engines (ICE). Subpart JJJJ applies to manufacturers, owners
and operators of SI ICE which affects new, modified, and reconstructed stationary SI ICE
(i.e., generators, pumps and compressors), combusting any fuel (i.e., gasoline, natural
gas, LPG, landfill gas, digester gas etc.), except combustion turbines. The applicable
emissions standards are based on engine type, fuel type, and manufacturing date. The
regulated pollutants are NOx, CO and VOC and there is a sulfur limit on gasoline.
Subpart JJJJ would apply to facilities operating spark ignition engines at compressor
stations;

•

40 CFR Part 60, Subpart IIII - Standards of Performance for Stationary Compression
Ignition (CI) ICEs. Subpart IIII applies to manufacturers, owners and operators of CI
ICE (diesel) which affects new, modified, and reconstructed (commencing after July 11,
2005) stationary CI ICE (i.e., generators, pumps and compressors), except combustion
turbines. The applicable emissions standards (phased in Tiers with increasing levels of
stringency) are based on engine type and model year. The regulated pollutants are NOx,
PM, CO, non-methane hydrocarbons (NMHC), while the emissions of sulfur oxides

Final SGEIS 2015, Page 6-95

 (SOx) are reduced through the use of low sulfur fuel. Particulate emissions are also
reduced by standards. Subpart IIII would apply to facilities operating compression
ignition engines at compressor stations;
•

40 CFR Part 60, Subpart KKK - Standards of Performance for Equipment Leaks of VOC
from Onshore Natural Gas Processing Plants. Subpart KKK applies to gas processing
plants that are engaged in the extraction of natural gas liquids from field gas and contains
provisions for VOC leak detection and repair (LDAR);

•

40 CFR Part 60, Subpart LLL - Standards of Performance for Onshore Natural Gas
Processing: SO2 Emissions. Subpart LLL governs emissions of SO2 from gas processing
plants, specifically gas sweetening units (remove H2S and CO2 from sour gas) and sulfur
recovery units (recover elemental sulfur); and

•

40 CFR Part 60 Subpart Kb - Standards of Performance for Volatile Organic Liquid
Storage Vessels (Including Petroleum Liquid Storage Vessels) for which Construction,
Reconstruction, or Modification Commenced after July 23, 1984.

National Emission Standards for Hazardous Air Pollutants (NESHAPs): Section 112 of the
CAA requires EPA to adopt standards to control emissions of hazardous air pollutants (HAPs).
NESHAPs are applicable to both new and existing sources of HAPs, and there are NESHAPs for
both “major” sources of HAPs and “area” sources of HAPs. A major source of HAPs is one with
the potential to emit in excess of 10 Tpy of any single HAP or 25 Tpy of all HAPs, combined.
An area source of HAPs is a stationary source of HAPs that is not major. The aim is to develop
technology-based standards which require levels met by the best existing facilities. The
pollutants of concern in the oil and gas sector primarily are the following: BTEX, formaldehyde,
and n-hexane. The following federal NESHAPs may apply:
•

40 CFR Part 63, Subpart ZZZZ - National Emission Standards for Hazardous Air
Pollutants for Reciprocating Internal Combustion Engines (RICE). Appendix 17 has
been revised from the initial analysis to reflect the requirements in the final EPA rule;

•

40 CFR Part 63, Subpart H - National Emission Standards for Organic Hazardous Air
Pollutants for Equipment Leaks. Subpart H applies to equipment that contacts fluids with
a HAP concentration of 5%;

•

40 CFR Part 63, Subpart HH - NESHAPs from Oil and Natural Gas Production Facilities.
Subpart HH controls air toxics from oil and natural gas production operations and

Final SGEIS 2015, Page 6-96

 contains provisions for both major sources and area sources of HAPs. Emission sources
affected by this regulation are tanks with flash emissions (major sources only), equipment
leaks (major sources only), and glycol dehydrators (major and area sources). Further
details on this subpart are presented in section 6.5.1.2;
•

40 CFR Part 63, Subpart HHH - NESHAPs from Natural Gas Transmission and Storage
Facilities. Subpart HHH controls air toxics from natural gas transmission and storage
operations. It affects glycol dehydrators located at major sources of HAPs; and

•

40 CFR Part 61, Subpart V - National Emission Standard for Equipment Leaks (Fugitive
Emission Sources). Subpart V applies to equipment that contacts fluids with a volatile
HAP concentration of 10%.
Applicable New York State Regulations

New York State Air Regulations are codified at 6 NYCRR Part 200 et seq, and can be obtained
from the Department’s web site at http://www.dec.ny.gov/regs/2492.html. Some of the
applicable regulations are briefly described below.
•

Part 200 - General Provisions;
○ Section 200.1 Definitions (relevant subsections);
(cd) Stationary source. Any building, structure, facility or installation, excluding
nonroad engines, that emits or may emit any air pollutant;
(aw) Nonroad engine. (1) Except as specified in paragraph (2) of this subdivision,
a nonroad engine is an internal combustion engine:
(iii) that, by itself or in or on a piece of equipment, is portable or transportable,
meaning designed to be and capable of being carried or moved from one location
to another. Indicators of transportability include, but are not limited to, wheels,
skids, carrying handles, dolly, trailer, or platform.
(2) An internal combustion engine is not a nonroad engine if:
(iii) the engine otherwise included in subparagraph (1)(iii) of this subdivision
remains or would remain at a location for more than 12 consecutive months or a
shorter period of time for an engine located at a seasonal source. A location is
any single site at a building, structure, facility, or installation. Any engine (or
engines) that replaces an engine at a location and that is intended to perform the

Final SGEIS 2015, Page 6-97

 same or similar function as the engine replaced would be included in calculating
the consecutive time period. An engine located at a seasonal source is an engine
that remains at a seasonal source during the full annual operating period of the
seasonal source. A seasonal source is a stationary source that remains in a single
location on a permanent basis (i.e. at least two years) and that operates at that
single location approximately three months (or more) each year. This paragraph
does not apply to an engine after the engine is removed from the location;
o Section 200.6 - Acceptable Ambient Air Quality. Section 200.6 states,
“notwithstanding the provisions of this Subchapter, no person shall allow or
permit any air contamination source to emit air contaminants in quantities which
alone or in combination with emissions from other air contamination sources
would contravene any applicable ambient air quality standard and/or cause air
pollution. In such cases where contravention occurs or may occur, the
commissioner shall specify the degree and/or method of emission control
required”. This regulation prohibiting air pollution, allowing the Department to
evaluate ambient impacts from emission sources; and
o Section 200.7 - Maintenance of Equipment. Section 200.7 states, “any person
who owns or operates an air contamination source which is equipped with an
emission control device shall operate such device and keep it in a satisfactory
state of maintenance and repair in accordance with ordinary and necessary
practices, standards and procedures, inclusive of manufacturer's specifications,
required to operate such device effectively.
•

Part 201 - Permits and Registrations;
○ 201-2.1 Definitions.
(21) Major stationary source or major source or major facility (see further details
and discussions below);
o 201-5 - State Facility Permits. Subpart 201-5 contains the criteria to issue “state
facility permits” to facilities that are not considered to be major. These are
generally facilities with the following characteristics: (1) Their actual emissions
exceed 50% of the level that would make them major, but their potential to emit
as defined in 6 NYCRR Part 200 does not place them in the major category, (2)
They require the use of permit conditions to limit emissions below thresholds that
would make them subject to certain state or federal requirements, or (3) They
have been granted variances under the Department's air regulations;

Final SGEIS 2015, Page 6-98

 o 201-6 - Title V Facility Permits. Subpart 201-6 contains the requirements and
procedures for CAA “Title V Permits”. These include facilities that are judged to
be major under the Department's regulations, or that are subject to NSPSs, to a
standard or other requirements regulating HAPs or to federal acid rain program
requirements; and
o 201-7 - Federally Enforceable Emission Caps. Subpart 201-7 provides the ability
to accept federally enforceable permit terms and conditions which restrict or cap
emissions from a stationary source or emission unit in order to avoid being
subject to one or more applicable requirements.
•

Part 212 - General Process Emission Sources. In general, Part 212 regulates emissions of
particulate, opacity, VOCs (from major sources), NOx (from major sources) and is mainly
used to control air toxics from industries not regulated in other specific 6 NYCRR Parts;

•

Part 227- Stationary Combustion Installations (see Appendix 16 for more details):
o

227-1- Stationary Combustion Installations. Subpart 227-1 regulates emissions
from stationary combustion installations.

o

227-2 - Reasonably Available Control Technology (RACT) For Major Facilities
of Oxides Of Nitrogen (NOx). Subpart 227-2 imposes NOx limits on major
sources (with a potential to emit 100 tons of NOx per year) located in the
attainment areas of the northeast ozone transport region;

•

Part 229 - Petroleum and Volatile Organic Liquid Storage and Transfer. Part 229
regulates petroleum and volatile organic liquid storage and transfer (i.e., gasoline bulk
plants, gasoline loading terminals, marine loading vessels, petroleum liquid storage tanks
or volatile organic liquid storage tanks); and

•

Part 231- New Source Review (NSR) for New and Modified Facilities. Part 231
addresses both the federal NSR and PSD requirements for sources located in
nonattainment or attainment areas and the relevant program requirements. For new major
facilities or modification of existing major facilities, Part 231 applies to those NSR
pollutants with proposed emissions increases greater than the major facility or significant
project threshold, as applicable. The applicable PSD major facility threshold (100 or 250
tons per year) is determined by whether the facility belongs to one of the source
categories listed in 6 NYCRR §201-2.1(b)(21)(iii). Reciprocating internal combustion
engines are not on the list, making the major source threshold 250 tons per year (instead
of 100 tons/year) for PSD applicable pollutants. For the nonattainment pollutants, the
threshold levels are lower, and depend on the location of the proposed new facility or

Final SGEIS 2015, Page 6-99

 modification. For the Marcellus Shale area, which is located within the Ozone Transport
Region (OTR), for regulatory purposes, the area is treated as moderate ozone
nonattainment. The major facility thresholds are 50 tons per year for VOC and 100 tons
per year for NOx.
The following sections discuss what regulatory determinations the Department has made with
respect to operations associated with drilling and completion activities and how the regulatory
process would be used for further permitting determinations related to the offsite compressor
stations and its association with the well pad operations.
6.5.1.1 Emission Analysis NOx - Internal Combustion Engine Emissions
Compressor Engine Exhausts
Internal combustion engines provide the power to run compressors that assist in the production
of natural gas from wells and pressurize natural gas from wells to the pressure of lateral lines that
move natural gas in large pipelines to and from processing plants and through the interstate
pipeline network. The engines are often fired with raw or processed natural gas, and the
combustion of the natural gas in these engines results in air emissions.
Well Drilling and Hydraulic Fracturing Operations
Oil and gas drilling rigs require substantial power to drill and case wellbores to their target
formations. For the development of the Marcellus Shale, this power would typically be provided
by transportable diesel engines, which generate exhaust from the burning of diesel fuel. After
the wellbore is drilled to the target formation, additional power is needed to operate the pumps
that move large quantities of water, sand, or chemicals into the target formation at high pressure
to hydraulically fracture the shale.
The preferred method for calculating engine emissions is to use emission factors provided by the
engine manufacturer. If these cannot be obtained, a preliminary emissions estimate can be made
using EPA AP-42 emission factors. The most commonly used tables appear as Table 6.6 below.

Final SGEIS 2015, Page 6-100

 Table 6.6 - EPA AP-42 Emissions Factors Tables

EPA AP-42 Table 3.2-1: Emission Factors for Uncontrolled Natural Gas-Fired Engines
2-cycle lean burn

4-cycle lean burn

4-cycle rich burn

Pollutant
g/Hp-hr
(power input)

lb/MMBtu
(fuel input)

g/Hp-hr
(power input)

lb/MMBtu
(fuel input)

g/Hp-hr
(power input)

lb/MMBtu
(fuel input)

10.9
1.5
5.9

2.7
0.38
1.5

11.8
1.6
5.0

3.2
0.42
1.3

10.0
8.6
1.2

2.3
1.6
0.27

NOX
CO
TOC

1

TOC is total organic compounds (sometimes referred to as THC). To determine VOC emissions calculate TOC emissions and multiply the value
by the VOC weight fraction of the fuel gas.

EPA AP-42 Table 3.3-1: Emission Factors for Uncontrolled Gasoline and Diesel Industrial Engines
Gasoline Fuel
Pollutant
NOX
CO
Exhaust (TOC)
Evaporative (TOC)
Crankcase (TOC)
Refueling (TOC)

g/Hp-hr
(power output)
5.0
3.16
6.8
0.30
2.2
0.5

Diesel Fuel
lb/MMBtu
(fuel input)
1.63
0.99
2.10
0.09
0.69
0.15

g/Hp-hr
(power output)
14.1
3.03
1.12
0.00
0.02
0.00

lb/MMBtu
(fuel input)
4.41
0.95
0.35
0.00
0.01
0.00

Engine Emissions Example Calculations
A characterization of the significant NOx emission sources during the three operational phases of
horizontally drilled, hydraulically fractured natural gas wells is as follows:
1. Horizontally Drilled/ High-Volume Hydraulically Fractured Wells - Drilling Phase
For a diesel engine drive total of 5400 Hp drilling rig power, 340 using NOx emission factor data
from engine specification data received from natural gas production companies currently
operating in the Marcellus Shale formation outside New York State, a representative NOx
emission factor of 6.4 g/Hp-hr is used in this example. For purposes of estimating the Potential

340

Engine information provided by Chesapeake Energy

Final SGEIS 2015, Page 6-101

 to Emit (PTE) for the engines, continuous year-round operation is assumed. The estimated NOx
emission would be:
NOX emissions = (6.4 g/Hp-hr) × (5400 Hp) × (8760 hr/yr) × (ton/2000 lb) × (1 lb/453.6 g) = 333.7 Tpy

The actual emissions from the engines would be much lower than the above PTE estimate,
depending on the number of wells drilled and the time it takes to drill the wells at a well site in a
given year.
2. Horizontally Drilled/ High-Volume Hydraulically Fractured Wells - Completion Phase
For diesel-drive 2333 Hp fracturing pump engine(s), 341 using NOx emission factor data from
engine specification data received from natural gas production companies currently operating in
the Marcellus Shale formation outside New York State, a representative NOx emission factor of
6.4 g/Hp-hr is used in this example. For purposes of estimating the Potential to Emit (PTE) for
the engines, continuous year-round operation is assumed. The estimated NOx emission would
be:
NOX emissions = (6.4 g/Hp-hr) × (2333 Hp) × (8760 hr/yr) × (ton/2000 lb) × (1 lb/453.6 g) = 144.1 Tpy

The actual emissions from the engines would be lower than the above PTE estimate, depending
on the time it takes to hydraulically fracture each well and the number of wells hydraulically
fractured at a well site in a given year.
3. Horizontally Drilled/High-Volume Hydraulically Fractured Wells - Production Phase
Using recent permit application information from a natural gas compressor station in the
Department’s Region 8, a NOx emission factor 2.0 g/Hp-hr was chosen as more reasonable (yet
still conservative) than AP-42 emission data. The maximum site-rated horsepower is 2500
Hp. 342 The engine(s) is expected to run year round (8760 hr/yr).
NOX emissions = (2.0 g/Hp-hr) × (2500 Hp) × (8760 hr/yr) × (ton/2000 lb) × (1 lb/453.6 g) = 48.3 TPY
341

Engine information provided by Chesapeake Energy.

342

Engine information provided by Chesapeake Energy.

Final SGEIS 2015, Page 6-102

 Since the engines in the example comply with the NOx RACT emission limits, non-applicability
of the rule implies merely avoiding the monitoring requirements that were designed for
permanently located engines. In addition to NOx RACT requirements, Title V permitting
requirements could also apply to other air pollutants such as CO, SO2, particulate matter (PM),
ozone (as VOCs), and elemental lead, with the same emission thresholds as for NOx. An initial
review of other emission information for these engines, such as CO and PM emission factor data,
reveals an unlikely possibility of reaching major source thresholds triggering Title V permitting
requirements for these facilities as discussed further in Section 6.5.1.8.
6.5.1.2 Natural Gas Production Facilities NESHAP 40 CFR Part 63, Subpart HH (Glycol
Dehydrators)
Natural gas produced from wells is a mixture of a large number of gases and vapors. Wellhead
natural gas is often delivered to processing plants where higher molecular weight hydrocarbons,
water, nitrogen, and other compounds are largely removed if they are present. Processing results
in a gas stream that is enriched in methane at concentrations of usually more than 80%. Not all
natural gas requires processing, and gas that is already low in higher hydrocarbons, water, and
other compounds can bypass processing.
Processing plants typically include one or more glycol dehydrators, process units that dry the
natural gas. Glycol, usually TEG, is used in dehydration units to absorb water from wet
produced gas. “Lean” TEG contacts the wet gas and absorbs water. The TEG is then considered
“rich.” As the rich TEG is passed through a flash separator and/or reboiler for regeneration,
steam containing hydrocarbon vapors is released from it. The vapors are then vented from the
dehydration unit flash separator and/or reboiler still vent.
Dehydration units with a natural gas throughput below 3 MMscf per day or benzene emissions
below 1 Tpy are exempted from the control, monitoring and recordkeeping requirements of
Subpart HH. Although the natural gas throughput of some Marcellus horizontal shale wells in
New York State could conceivably be above 3 MMscf, preliminary analysis of gas produced at
Marcellus horizontal shale gas well sites in Pennsylvania indicates a benzene-content below the
exemption threshold of 1 Tpy, for the anticipated range of annual gas production for wells in the
Marcellus. However, the affected natural gas production facilities would still likely be required

Final SGEIS 2015, Page 6-103

 to maintain records of the exemption determination as outlined in 40 CFR §63.774(d) (1) (ii).
Sources with a throughput of 3 MMscf/day or greater and benzene emissions of 1.0 Tpy or
greater are subject to the rule’s emission reduction requirements. This does not necessarily mean
control, depending on the location of the affected emission sources relative to “urbanized areas
(UA) plus offset” or to “urban clusters (UC) with a population of 10,000 or greater” as defined in
the rule.
6.5.1.3 Flaring Versus Venting of Wellsite Air Emissions
Well completion activities include hydraulic fracturing of the well and a flowback period to
clean the well of flowback water and any excess sand (fracturing proppant) that may return out
of the well. Flowback water is routed through separation equipment to separate water, gas, and
sand. Initially, only a small amount of gas is vented for a period of time. Once the flow rate of
gas is sufficient to sustain combustion in a flare, the gas is flared for a short period of time for
testing purposes. Recovering the gas to a sales gas line is called a reduced emissions completion
(REC). See Section 6.6.8 for further discussion of RECs.
Normally the flowback gas is flared when there is insufficient pressure to enter a sales line, or if
a sales line is not available. There is no current requirement for REC, and the Public Service
Commission (PSC) has not historically authorized construction of sales lines before the first well
is drilled on a pad (see Section 8.1.2.1 for a discussion of the PSC’s role and a presentation of
reasons why pre-authorization of gathering lines have been suggested under certain
circumstances), therefore, estimates of emissions from both flaring and venting of flowback gas
are included in the emissions tables in Section 6.5.1.6. Unless PSC revisits this policy in the
future in order to allow for REC, the well pad activities would be required to minimize these
emissions due to the potential for relatively high short-term VOC and CO emissions, as
estimated by the Industry Information Report. The modeling and regional emission assessments,
as well as regulatory applicability discussions, have incorporated industry’s quantifications of the
short term operations associated with flaring and venting. Thus, the well permitting process
would be constrained by the assumed amount of gas to be vented or flared (or the corresponding
average maximum hours of operations).

Final SGEIS 2015, Page 6-104

 Also, during drilling, gaseous zones can sometimes be encountered such that some gas is
returned with the drilling fluid, which is referred to as a gas “kick.” For safety reasons, the
drilling fluid is circulated through a “mud-gas separator” as the gas kick is circulated out of the
wellbore. Circulating the kick through the mud-gas separator diverts the gas away from the rig
personnel. Any gas from such a kick is vented to the main vent line or a separate line normally
run adjacent to the main vent line.
Drilling in a shale formation does not result in significant gas adsorption into the drilling fluid as
the shale has not yet been fractured. Experience in the Marcellus thus far has shown few, if any,
encounters with gas kicks during drilling. However, to account for the potential of a gas kick
where a “wet” gas from another formation might result in some gas being emitted from the mudgas separator, an assumed wet-gas composition was used to estimate emissions.
Gas from the Marcellus Shale in New York is expected to be “dry”, i.e., have little or no VOC
content, and “sweet”, i.e., have little or no H2S. Except for drilling emissions, two sets of
emissions estimates are made to enable comparison of emissions of VOC and HAP from both
dry gas production and wet gas production.
6.5.1.4 Number of Wells Per Pad Site
Drilling as many wells as possible from a single well pad provides for substantial environmental
benefits from less road construction, surface disturbance, etc. Also, experience shows that
average drilling time can be improved as more experience is gained in a shale play. Based on
industry information submitted in response to Department requests, it is expected that no more
than four wells could be drilled, completed, and hooked up to production in any 12-month
period. Therefore, the annual emission estimates presented in Section 6.5.1.7 are based on an
assumed maximum of four wells per site per year.
6.5.1.5 Natural Gas Condensate Tanks
Fluids that are brought to the surface during production at natural gas wells are a mixture of
natural gas, other gases, water, and hydrocarbon liquids (known as condensate). Some gas wells
produce little or no condensate, while others produce large quantities. The mixture typically is
sent first to a separator unit, which reduces the pressure of the fluids and separates the natural gas

Final SGEIS 2015, Page 6-105

 and other gases from any entrained water and hydrocarbon liquids. The gases are collected off
the top of the separator, while the water and hydrocarbon liquids fall to the bottom and are then
stored on-site in storage tanks. Hydrocarbons vapors from the condensate tanks can be emitted
to the atmosphere through vents on the tanks. Condensate liquid is periodically collected by
truck and transported to refineries for incorporation into liquid fuels, or to other processors.
Initial analysis of natural gas produced at Marcellus Shale horizontal gas well sites in
Pennsylvania’s Marcellus Shale area indicates insufficient BTEX and other liquid hydrocarbon
content to justify installation of collection and storage equipment for natural gas liquids.
However, in the instances where “wet” gas is encountered and there is a need to store the
condensate in tanks either at the well pad or at the compressor station, potential VOC and HAP
(e.g., benzene) emissions should be minimized to the maximum extent practicable and controlled
where necessary. The ALL report notes that it is difficult to properly quantify the loss of vapors
from these tanks, but notes that in states where substantial quantities of condensate are
recovered, either a vapor recovery system or flaring is used to control emissions. If such
condensate tanks are to be used in New York, a vapor recovery system would be required to be
installed instead of flaring the emissions since the latter creates additional combustion emissions
and other potential issues.
6.5.1.6 Emissions Tables
Estimated annual emissions from drilling, completion and production activities are based on
industry’s response to the Department’s information requests 343 (hereafter Industry Information
Report) that a maximum number of four wells would be drilled at a given pad in any year (see
further discussion in the modeling section). These estimates are presented in Table 6.7, Table
6.8, Table 6.9, and Table 6.10 below.

343

ALL Consultant Information Request Report on behalf of IOGANY, dated September 16, 2010.

Final SGEIS 2015, Page 6-106

 Table 6.7 - Estimated Wellsite Emissions (Dry Gas) - Flowback Gas Flaring (Tpy)(Updated July 2011)

PM
NOx
CO
VOC
SO2

Drilling
0.5
15.1
8.3
0.8
0.02

Completion
0.2
5.8
3.2
0.2
0.01

Production
0.2
3.8
9.2
2.4
0.07

Subtotal
0.9
24.7
20.7
3.4
0.1

Flowback Gas
1.4
4.9
24.5
0.7
0.0

Total
2.3
29.6
45.2
4.1
0.1

Total HAPs

0.09

0.02

0.03

0.14

0.08

0.22

Table 6.8 - Estimated Wellsite Emissions (Dry Gas) - Flowback Gas Venting (Tpy)(Updated July 2011)

PM
NOx
CO
VOC
SO2

Drilling
0.5
15.1
8.3
0.8
0.02

Completion
0.2
5.8
3.2
0.2
0.01

Production
0.2
3.8
9.2
2.4
0.07

Subtotal
0.9
24.7
20.7
3.4
0.1

Flowback Gas
0.0
0.0
0.0
0.6
0.0

Total
0.9
24.7
20.7
4.0
0.1

Total HAPs

0.09

0.02

0.03

0.14

0.0

0.14

Table 6.9 - Estimated Wellsite Emissions (Wet Gas) - Flowback Gas Flaring (Tpy) (Updated July 2011)

PM
NOx
CO
VOC
SO2
Total HAPs

Drilling
0.5
15.1
8.3
0.8
0.02
0.09

Completion
0.2
5.8
3.2
0.2
0.01
0.02

Production
0.2
3.8
9.2
2.4
0.07
0.31

Subtotal
0.9
24.7
20.7
3.4
0.1
0.42

Flowback Gas
1.4
4.9
24.5
0.7
0.22
0.69

Total
2.3
29.6
45.2
4.1
0.31
1.11

Table 6.10 - Estimated Wellsite Emissions (Wet Gas) - Flowback Gas Venting (Tpy) (Updated July 2011)

PM
NOx
CO
VOC
SO2
Total HAPs

Drilling
0.5
15.1
8.3
0.8
0.02
0.09

Completion
0.2
5.8
3.2
0.2
0.01
0.02

Production
0.2
3.8
9.2
2.4
0.07
0.31

Subtotal
0.9
24.7
20.7
3.4
0.1
0.42

Final SGEIS 2015, Page 6-107

Flowback Gas
0.0
0.0
0.0
21.9
0.0
0.002

Total
0.9
24.7
20.7
25.3
0.1
0.422

 It is important to understand that the “totals” columns in these tables are not meant to be
compared to the major source thresholds discussed in section 6.5.1.2 for the purpose of
determining source applicability to the various regulations. This is because these estimates
include emissions from activities which are not considered stationary sources, as detailed in the
discussions in Section 6.5.1.8. These estimates should be looked upon merely as giving a
relative sense of the expected well pad emissions and what the relation is to major source
thresholds.
6.5.1.7 Offsite Gas Gathering Station Engine
For gas gathering compression, it is anticipated that most operators would select a large 4-stroke
lean-burn engine because of its fuel efficiency. A typical compressor engine is the 1,775-hp
Caterpillar G3606, which is the engine model used for the analysis.
The final revision to NESHAPs Subpart ZZZZ has placed very strict limits on formaldehyde
emissions from reciprocating internal combustion engines (see Appendix 17). Future, 4-stroke
lean-burn engines would be required to have an oxidation catalyst that would reduce
formaldehyde emissions by approximately 90%.
The annual emissions data for a typical gas gathering compressor engine is given in Table 6.11
below. 344
Table 6.11 - Estimated Off-Site Compressor Station Emissions (Tpy)

Component
PM
NOx
CO
SO2
Total VOC
Total HAP

344

Controlled 4-Stroke Lean Burn Engine
0.5
33.3
6.6
0.0
5.0
2.7

ALL Consulting August 26, 2009.

Final SGEIS 2015, Page 6-108

 6.5.1.8 Department Determinations on the Air Permitting Process Relative to Marcellus Shale
High-Volume Hydraulic Fracturing Development Activities.
A determination would first be made as to whether these internal combustion engines (ICEs)
would qualify for the definition of non-road or stationary sources. This, in turn, determines
whether the engines are subject to requirements such as NSPS or NESHAPs.
When considering applicability of these rules, engines can fall into three general classes:
stationary, mobile, or nonroad. The applicable NSPS regulations (40 CFR Part 60, Subpart IIII
and Subpart JJJJ) and NESHAP (40 CFR Part 63 Subpart ZZZZ) define stationary internal
combustion engines as excluding mobile engines and nonroad engines. The New York State
definition of stationary sources given in 6.5.1 also notes the non-road engine exclusion. The
latter engines are defined at 40 CFR Part 1068 (General Compliance Provisions for Nonroad
Program), which is virtually the same as it appears in 40 CFR Part 89 (Control of Emissions
from New and In-Use Nonroad Compression-Ignition Engines) as well as in New York’s
regulations at NYCRR Part 200.1, as given in Section 6.5.1. Paragraph (1)(iii) of the definition
describes a nonroad engine that would be portable or would be part of equipment that would be
considered portable, with the exception given in paragraph 2(iii) if the engines are to remain at
the same location for more than 12 months.
It is clear from the Industry Information Report that the engines used to power the drilling and
well development equipment would be used at a given well pad for maximum of less than half a
year (see discussions in ALL, 8/26/09 and the modeling section on the timeframes of engine
use), even if the maximum of four wells per pad were to be completed in a year. Thus, these
engines are considered as nonroad engines and are not subject to the NSPS, NESHAP or
permitting requirements.
However, as detailed in the following section, the environmental consequences of these engines
are fully analyzed and mitigated where necessary in keeping with SEQRA. For example, the use
of ULSF with a 15 ppm sulfur content would be required for use in all drilling and well
development equipment engines. This limit is required for stationary engines in the final
NESHAPS Subpart ZZZZ rule as discussed in Appendix 17. In addition, a set of control
measures would be required on most of these engines in order to meet NAAQS, as fully

Final SGEIS 2015, Page 6-109

 addressed in the modeling analysis section. The permitting of the various activities associated
with drilling and development activities in the Marcellus Shale would be consistent with
regulatory scheme in 6 NYCRR Part 200, et. seq. for regulating emissions of air pollutants.
Thus, the Department would not subject the nonroad engines to the regulatory requirements
applicable to stationary source, such as the determination of what constitutes a major source per
Part 201. In instances throughout the country reviewed by the Department in terms of permitting
gas drilling and production activities, the determination of a stationary source or facility has
relied on the association of the compressor stations and nearby well emissions, but in none of
these were the nonroad engine emissions included in the permitting emission calculations. This
approach would also be followed in New York as the appropriate regulatory scheme.
Thus, in accounting for the well site operation emissions in the permitting process, the emissions
from Tables 1 to 4 above would only include the remaining activities at the site which are
essentially a small line heater (1 million Btu) a small compressor (150 horsepower), and possibly
a flare. Tables 1 to 4 indicate that for the three higher emission pollutants, NOx, CO and VOCs,
these sources would add up to a maximum of 8.7, 33.7, and 3.1 Tpy, respectively, under the
normal dry gas scenario for each pad. In the unlikely event of encountering “wet” gas, the VOC
emissions could be 24.3 Tpy. However, these CO and VOC emissions are associated with the
transient sources, the flare and gas venting, respectively, which are to be minimized, as would be
apparent in the discussions to follow. In addition, in the unlikely event that a glycol dehydration
would be located at a well site instead of the compressor station, the strict regulatory requirement
noted in Section 6.5.1 would limit the VOC (benzene) emissions to below 1 Tpy. Thus, total
HAPs emissions from a well pad would be much less than even the major source threshold of 10
Tpy for a single HAP.
Therefore, the process which the Department would follow in permitting the air emissions from
Marcellus Shale activities would start with the compressor station permit application review. As
noted in Section 8.1.2.1, this SGEIS for drilling wells is not meant to address the full extent of
the compressor station permitting and the environmental consequences, which falls under the
purview of the PSC and would be dealt with on a case by case basis. The applicable Public
Service Law, Article VII, would be followed in which PSC would be the lead agency for the
environmental review, however the Department would remain the agency responsible for

Final SGEIS 2015, Page 6-110

 reviewing and acting on the air permit application. In this review, the Department would
incorporate all of the applicable regulations, including the determination of what constitutes a
source or facility. The air quality analysis has considered the impacts of a potential compressor
station which is hypothetically placed next to the well pad in the modeling assessment of
standards and other compliance thresholds.
Section 112(n) of the CAA (Section 112) applies specifically to HAPs. The EPA, on September
22, 2009, clarified that for the purposes of New Source Review (NSR) and Title V applicability
review, the process of facility determination should include a detailed consideration of the
traditional set of three criteria used by EPA in past actions. In this determination, a set of related
and adjacent activities could be “aggregated” if they meet the requirements of the criteria.
The Department would follow EPA’s process for the determination of a stationary source or
facility for criteria pollutants, as also guided by recent applicability determinations by EPA and
other states. Details of the Department’s approach are presented in Appendix 18. The process
would involve requesting information during the compressor station permit application phase
using a set of questions framed from previous EPA determinations. A sentinel aspect of EPA’s
regulation and policy, which New York’s approach is adapting, is the use of case-by-case
information to make an informed decision. That process would also consider information
requested on drilling wells which could be associated with the compressor stations.
6.5.2

Air Quality Impact Assessment

6.5.2.1 Introduction
As part of the Department’s effort to address the potential air quality impacts of horizontal
drilling and hydraulic fracturing activities in the Marcellus Shale and other low-permeability gas
reservoirs, an air quality modeling analysis was undertaken by the Department’s Division of Air
Resources (DAR). The original modeling analysis was carried out to determine whether the
various expected operations at a “typical” multi-well site would have the potential for any
adverse air quality impacts, and it addressed a number of issues raised in public comments
during the SGEIS scoping process. The analysis also incorporated subsequently-developed
information on operational scenarios specific to multi-well horizontal drilling and hydraulic
fracturing, to help determine possible air permitting requirements.

Final SGEIS 2015, Page 6-111

 The initial modeling analysis has been updated based on information from both the Industry
Information Report and related public information which has become available since September
2009. In particular, industry has indicated that: 1) simultaneous drilling and completion
operations at a single pad would not occur; 2) the maximum number of wells to be drilled at a
pad would be four in any 12-month period; and 3) flowback impoundments are not
contemplated. The effects of these operational changes are discussed where appropriate. It is to
be noted that the revision from maximum of ten wells down to four wells per pad per year affects
only the annual emissions and the modeled annual impacts and not the short term impacts.
Therefore, the annual impacts were revisited to determine if the reduced emissions had an effect
on the previous conclusions reached on standards compliance. In instances where previous
impacts due to emissions using ten wells did not pose an exceedance, the annual impacts have
not been recalculated since these represent conservative concentrations versus the revised
maximum of four well operations. Instances where this approach is used are noted in the
subsequent discussions.
Due to remaining issues with exceedances of the 24-hour PM2.5 ambient standard and the
adoption of new 1-hour SO2 and NO2 standards by EPA since the initial modeling analysis, a
supplemental modeling analysis was performed. The approach to this assessment and the
consequent results are presented in a separate section which follows this section. That
assessment has incorporated the discussions from an industry modeling exercise for PM2.5 and
PM10, as well as more recent EPA guidance documents on modeling for these pollutants.
This section presents the initial air quality analysis undertaken by DAR staff based on
operational and emissions information supplied mainly by industry and its consultant in a
submission hereafter referred to as the Industry Information Report. 345 To a limited extent,
certain supplemental information from ICF International’s report to NYSERDA 346 was also
used. The applicability determinations of the Department’s air permitting regulations and the
verification approach to the emission calculations are contained in Section 6.5.2.

345

ALL Consulting, 2009,

346

ICF Task 2, 2009,

Final SGEIS 2015, Page 6-112

 To the extent that the information being used was for the modeling of a generic multi-well site
and its operations, it was necessary to reconcile and define a “worst case” scenario for the
various activities in terms of expected impacts. Certain assumptions were made on the type and
sizes of equipment to be used, the potential for simultaneous operation of the equipment on a
short-term basis (i.e., hourly and daily), and the duration of these activities over a period of a
year in order to be able to compare impacts to the corresponding ambient thresholds. The
supplemental modeling analysis indicates that, although the operational time frame for certain
equipment (e.g., engines) over a given year would be reduced according to the Industry
Information Report, 347 the consequences of these reduced annual emissions are only qualitatively
addressed in the following sections since these do not affect any of the initial conclusions
reached on annual impacts. That is, the reduced annual emissions from certain operations which
were initially demonstrated to meet the corresponding standards and thresholds would only be
lowered by this new information.
The air quality analysis relied upon recommended EPA and the Department’s air dispersion
modeling procedures to determine “worst case” impacts of the various operations and activities
identified for the horizontal multi-well sites. Dispersion modeling is an acceptable tool, and at
times the only option, to determine the impacts of many source types in permitting activities and
environmental impact statements. Where necessary, the analysis approach relied on assumed
worst case emissions and operations scenarios due to not only the nature of this generic
assessment, but also because detailed model input data for the sources and their relative locations
on a typical well pad cannot be simply identified or analyzed. Modeling was performed for
various criteria pollutants (those with NAAQS) and a set of non-criteria pollutants (including
toxics) for which New York has established a standard or other ambient threshold levels. Some
of these toxic pollutants were identified in public comments during the SGEIS scoping process
and were quantified to the extent possible for both the modeling and applicability determinations.
The following sections describe the basic source categories and operations at a typical multi-well
site with hydraulic fracturing, the modeling procedures and necessary input data, the resultant
impacts, and a set of conclusions drawn from these results. These conclusions are meant to

347

ALL Consulting, 2010.

Final SGEIS 2015, Page 6-113

 guide the set of conditions under which a site specific assessment might or might not be
necessary. Based on information in the Industry Information Report and an update to EPA’s
dispersion model, the initial PM10/PM2.5 modeling approach and conclusions have been
updated.
6.5.2.2 Sources of Air Emissions and Operational Scenarios
In order to properly estimate the air quality impacts of the set of sources at a single pad with
multiple horizontal wells, the operating scenarios and associated air emission sources would be
correctly represented. Since these operations have a number of interdependent as well as
independent components, the Department has defined both the short-term and long term
emission scenarios from the various source types in order to predict conservative, yet realistic
impacts. The information used to determine the emission sources and their operating scenarios
and constraints, as well as the associated emission rates and parameters, were provided by the
Industry Information Report, while certain operational scenario restrictions were presented in the
ICF report, which reflects information obtained from industry with drilling activities in other
states. Where necessary, further data supplied by industry or determined appropriate by DMN
was used to fill in data gaps or to make assumptions. In some of these instances, the lack of
specific information necessitated a worst-case assumption be made for the purposes of the
modeling exercise. Examples of the latter include defining “ambient air” based on the proximity
of public access to the well pad and the likely structure dimensions to calculate their influence on
the stack plumes.
The Industry and ICF Reports indicate three distinct operation stages and four distinct source
types of air emissions for developing a representative horizontally-drilled multi-well pad. The
phases are drilling, completion, and gas production, each of which has either similar or distinct
sources of air emissions. These phases and the potential air pollution sources are presented in
the Industry Information Report, Section 2.1.5 and Exhibit 2.2.1 of the ICF report, and in
Chapter 5 of the SGEIS, and would only be briefly noted herein. Of the various potential
sources of air emissions, a number have distinct quantifiable and continuous emissions which
lend themselves to modeling. On the other hand, the ICF report also identifies other generic
sources of minor fugitive emissions (e.g., mud return lines) or of emergency release type (e.g.,
BOP stack), or of a pollutant which is quantified only as of “generic” nature (total VOCs for

Final SGEIS 2015, Page 6-114

 tanks) which cannot be modeled to any reliable extent without a well-defined source. The best
approach to address these sources is to apply best minimization techniques, as recommended in
Section 6.5.1.5 for condensate tanks. However, in instances where speciated VOCs or HAPs are
available and provided by industry, such as for the glycol dehydrator and flowback venting of
gas, the modeling was used to predict impacts which were then compared to available ambient
thresholds.
The total operations associated with well drilling can be assigned to three “types” of potential
sources: 1) combustion from engines, compressors, line heaters, and flares; 2) short-term venting
of gas constituents which are not flared; and 3) emissions from truck activities near the well pad.
Each of these source categories have limitations in terms of the size and number of the needed
equipment, their possible simultaneous operations over a short-term period (e.g., 24-hour), and
the time frames over which these equipment or activities could occur over a period of one year,
which effects the corresponding annual impacts. Some of these limitations are described in the
Industry Information Report. These limitations and further assumptions were taken into account
in the modeling analysis, as further discussed in Section 6.5.2.3.
Many of the sources for which the Industry Information Report tabulates the drilling, completion
and production activities are depicted in the typical site layout represented schematically in
Exhibit 2.1.3 of the ICF report. The single pad for multi-horizontal wells is confined to an area
of about 150 meters (m) by 150 m as a worst case size of the operations. From this single pad,
wells are drilled in horizontal direction to develop an area of about one square mile. The initial
industry report noted the possibility of up to ten horizontal wells being eventually drilled and
completed per pad over a year’s time, while the ICF report notes that simultaneous drilling and
completion on the same pad would be limited to a single operation for each. This limitation was
determined appropriate by DMN for analysis of short-term impacts. Thus, the simultaneous
operations on a pad for the assessment of impacts of 24 hours or less is limited to the equipment
necessary to drill one well and complete another. In addition, according to DMN, there is a
potential that a third well’s emissions could be flared at the same time as these latter operations.
Thus, this source was also included in the simultaneous operation scenario for criteria pollutants.
The Industry Information Report indicates that the number of wells drilled in a year at a given
well pad would be four and asserts that there would not be any simultaneous operations of the

Final SGEIS 2015, Page 6-115

 well drilling and completion equipment engines. These revisions are incorporated in the
supplemental modeling analysis section. Their influence on the results in this section is
addressed in places where deemed of consequence.
It should be noted that no emissions of criteria pollutants resulting from uncontrolled venting of
the gas are expected. The other sources which could emit criteria pollutants are associated with
the production phase operations; that is, the off-site compressors and line heaters could be
operating simultaneously with the single pad drilling, completion and flaring operations. The
Industry Information Report provides data for a possible “on-site” line heater instead of at the
compressor station and this source was placed on the pad area and provides for a more
conservative impact.
The Industry Information Report also provides emission data for the non-criteria pollutants as
species of VOCs or HAPs associated with both combustion and gas venting. Review of this
information indicates two essentially different sets of sources which can be treated independently
in the modeling analysis. The first set is the gas venting sources: the mud-gas separator, the
flowback gas venting, and the glycol dehydrator. These sources emit a distinct set of pollutants
associated with the “wet” gas scenario, defined in the Industry Information Report as containing
“heavier” hydrocarbons such as benzene. The industry and ICF reports note that gas samples in
the Marcellus Shale have detected neither these heavier species of VOCs, nor H2S. However, the
Industry Information Report also notes the possibility of gas pockets with “wet” gas and provides
associated emissions. To be comprehensive, the modeling analysis has calculated the impacts of
these species which could be realized in the westernmost part of New York according to DMN.
The Industry Information Report also notes that gas venting is a relatively short-term
phenomenon, especially during the flowback period where the vented gas is preferentially flared
after a few hours of venting. Since there are essentially no simultaneous short-term emissions
expected of the same pollutants at the pad from processes other than flowback venting, coupled
with the clear dominance of the flowback venting emissions of these pollutants, the modeling
was simplified for this scenario and only the short-term impacts were determined, as described in
more detail in Section 6.5.1.3. The second set of non-criteria pollutant emissions presented in
the Industry Information Report is associated mainly with combustion sources. These non-

Final SGEIS 2015, Page 6-116

 criteria pollutants could be emitted over much longer time periods, considering these sources are
operated over these longer periods, both per-well drilling activity and potential multi-well
operations over a given year. Thus, for these pollutants, both short-term and annual impacts
were calculated. It should be noted that, since the glycol dehydrator could operate for a full year
also, its emissions of the same pollutants as those due to combustion were also included in this
assessment of both short-term and annual toxic impacts. Furthermore, the flare emissions are
included in the combustion scenario (and not in the venting), as the flaring of flowback gas
results in over 95% destruction of these pollutants.
In addition, due to the conversion of H2S to SO2 during flaring, the flare was included in the
criteria pollutant simultaneous operations scenario modeling. Table 6.12 summarizes the set of
sources and the pollutants which have been modeled for the various simultaneous operations for
short-term impacts. The specific modeling configuration and emissions data of the various
sources are discussed in Section 6.5.2.3.
The last type of emission source associated with the multi-well operations is truck traffic. An
estimate of the number of trucks needed for the various activities at a single well pad, including
movement of ancillary equipment, delivery of fresh water and proppant/additives, and the
hauling of flowback is presented in Section 6.11. It should be first noted that direct emissions
from mobile sources are controlled under Title II of the CAA and are specifically exempt from
permitting activities. Thus, these emissions are also not addressed in general in a modeling
analysis, with two exceptions. At times, the indirect emissions of fugitive particulate matter are
modeled when estimates of emissions are large. The latter occurs mainly due to poor dust
control measures and the best approach to mitigate these emissions is to have a dust control plan.
In addition, emissions of PM2.5 from mobile sources associated with a project and which occur
on-site are to be addressed by the Department’s Commissioner’s Policy CP-33. 348 Again, if
these emissions are large enough, a modeling analysis is performed for an EIS. For the
assessment of PM2.5 per CP-33, the emission calculations are not to include those associated
with incidental roadway traffic away from the onsite operations.

348

http://www.dec.ny.gov/chemical/8912.html.

Final SGEIS 2015, Page 6-117

 Emissions of both PM10 and PM2.5 due to truck operations at the well pad were initially
calculated by DAR’s Mobile Source Panning Section based on the movement of total number of
trucks on-site for the drilling of one well. These emissions were then multiplied by the 10
potential wells which might be drilled over a year, and resulted in relatively minor quantities of
0.2 Tpy maximum PM2.5 emissions. This is consistent with the limited use of trucks at the well
pad. These emissions are well below the CP-33 threshold of 15 Tpy. Thus, no modeling was
performed for these pollutants and any necessary mitigation scheme for these would be the
application of an appropriate dust control methods and similar limitations on truck usage, such as
inordinate idling.
In order to address on-road truck traffic movement and emissions in the area underlain by the
Marcellus Shale, estimates of regional emissions have been calculated based on information
provided in the Industry Information Report. These regional emissions and their consequence
are discussed in the section to follow. In addition, at the well pad, EPA’s updated emission
model MOVES (Motor Vehicle Emission Simulator) was used instead of the MOBILE 6e model
used in the initial analysis. The MOVES model was also applied to generate regional emissions
of on-road mobile sources associated with Marcellus Shale well development and included
PM2.5 emissions. These estimates have been incorporated in the discussions of regional annual
emissions. Results from the MOVES model indicate that the very low PM2.5 emissions initially
estimated for a single pad are unchanged.
6.5.2.3 Modeling Procedures
EPA 349 and Department 350 guidelines on air dispersion modeling recommend a set of models and
associated procedures for assessing impacts for a given application. For stationary sources with
“non-reactive” pollutants and near-field impacts, the refined AERMOD model (latest version,
07026) and its meteorological and terrain preprocessors is best suited to simulate the impacts of
the sources and pollutants identified in the Marcellus Shale and other gas reservoir operations.
This model is capable of providing impacts for various averaging times using point, volume or
area source characteristics, using hourly meteorological data and a set of receptor locations in the

349

Appendix W to 40 CFR Part 51. http://www.epa.gov/ttn/scram/guidance_permit.htm.

350

http://www.dec.ny.gov/chemical/8923.html.

Final SGEIS 2015, Page 6-118

 surrounding area as inputs. The model simulates the impact of “inert” pollutants such as SO2,
NO2, CO, and particulates without taking into account any removal or chemical conversions in
air, which provides for conservative ambient impacts. However, these effects are of minor
consequences within the context of plume travel time and downwind distances associated with
the maximum ambient impact of pollutants discussed in this section.
AERMOD also does not treat secondary formation of pollutants such as O3 from NOx and VOCs,
but it can model the non-criteria and toxic pollutant components of gas or VOC emissions in
relation to established ambient thresholds. There does not exist a recommended EPA or
Department “single” source modeling scheme to simulate O3 formation from its precursors. This
would involve not only complex chemical reactions in the plumes, but also the interaction of the
regional mix of sources and background levels. Such an assessment is limited to regional scale
emissions and modeling and is outside the scope of the modeling analysis undertaken for this
section. However, the potential consequences of regional emissions of VOCs and NOx are
presented in Section 6.5.3.
Thus, the AERMOD model was used with a set of emission rates and source parameters, in
conjunction with other model input data discussed in the following subsections, to estimate
maximum ambient impacts, which were then compared to established Federal and New York
State ambient air quality standards (AAQS) and other ambient thresholds. The latter are
essentially levels established by the Department’s Division of Air Resources (DAR) program
policy document DAR-1. 351 These levels are the 1-hour SGCs and annual AGCs (short-term and
annual guideline concentration, respectively). Where certain data on the chemicals modeled and
the corresponding ambient thresholds were missing, New York State Department of Health
(NYSDOH) staff provided the requested information. For the thresholds, the Department’s
Toxics Assessment section then calculated the applicable SGCs and AGCs. The modeling
procedures also invoke a number of “default” settings recommended in the AERMOD user’s
guide and EPA’s AERMOD Implementation Guide. For example, the settings of potential wells
are not expected to be in “urban” locations, as defined for modeling purposes and, thus, the rural
option was used. Other model input data are described next.

351

http://www.dec.ny.gov/chemical/30560.html.

Final SGEIS 2015, Page 6-119

 Meteorological Data
The AERMOD model requires the use of representative hourly meteorological data, which
includes parameters such as wind speed, wind direction, temperature and cloud cover for the
calculation of transport and dispersion of the plumes. A complete set of all the parameters
needed for modeling is generally only available from National Weather Service (NWS) sites.
The “raw” data from NWS sites are first pre-processed by the AERMET program and the
AERSURFACE software using land use data at the NWS sites, which then create the necessary
parameters to be input to AERMOD. There is a discrete set of NWS sites in New York which
serves as a source of representative meteorological data sites for a given project. However, for
this analysis, the large spatial extent of the Marcellus Shale necessitated the use of a number of
the NWS site data in order to cover the meteorological conditions associated with possible well
drilling sites throughout the State.
Figure 6.10 presents the spatial extent of the Marcellus Shale and the six NWS sites chosen
within this area and deemed adequate for representing meteorological conditions for the purpose
of dispersion modeling of potential well sites. It was judged that these sites would adequately
envelope the set of conditions which would result in the maximum impacts from the relatively
low-elevation or ground-level sources identified as sources of air pollutants. In addition, EPA
and Department modeling guidance recommends the use of five years of meteorological data
from a site in order to account for year to year variability. For the current analysis, however, the
Department has chosen two years of data per site to gage the sensitivity of the maxima to these
data and to limit the number of model calculations to a manageable set. It was determined that
impacts from the relatively low-elevation sources would be well represented by the total of 12
years of data used in the analysis.
This analysis is conservative from the standpoint of the number of data years used. Certain
public comments 352 recommended that the Department should use the EPA-recommended five
years of data for its analysis. However, these comments do not fully recognize the conservative
nature of using 12 years of meteorological data to determine the worst case impact for any
potential site in the Marcellus Shale play. While the EPA and the Department guidance to use

352

AKRF Consultants, memo dated 12/3/2009, p. 2.

Final SGEIS 2015, Page 6-120

 five years of data applies to individual meteorological site analysis to account for possible
climatological variability at the particular site, the use of 12 years of data from six different sites
has a similar conservatism built into it by the end use of the overall maxima for any well pads or
compressor stations. That is, the overall maxima for any specific pollutant and averaging time
could be controlled by meteorological data from different NWS sites, but these maxima are
being used for all potential sites in the Marcellus Shale play regardless of whether they might
experience these meteorological conditions. A review of the results discussed in the next section
and in Table 6.16 confirms this conclusion. Thus, it is deemed that the use of two years of data
from six NWS sites to assess the maximum potential impacts is conservative.
The NWS sites and the two years of surface meteorological data which were readily available
from each site are presented in Table 6.13, along with latitude and longitude coordinates. In
addition to these surface sites, upper air data is required as input to the AERMOD model in order
to estimate certain meteorological parameters. Upper air data is only available at Buffalo and
Albany for the sites chosen for this analysis, and were included in the data base. It should be
noted that upper air data is not the driving force relative to the surface data in modeling lowelevation source impacts within close proximity of the sources, as analyzed in this exercise. The
meteorological data for each year was used to calculate the maximum impacts per year of data
and then the overall maxima were identified from these per the regulatory definitions of the
specific AAQS and SGCs/AGCs, as detailed in the subsequent subsection.
Receptor and Terrain Input Data
Ground level impacts are calculated by AERMOD at user defined receptor locations in the area
surrounding the source. These receptors are confined to “ambient air” locations to which the
public has access. Current DMN regulations define a set of “set back” distances from the well
sites to roadways and residences. However, these set back distances (e.g., 25m) are defined from
the wellhead for smaller “footprint” vertical wells relative to the size of the multi-pad horizontal
wells. Furthermore, EPA’s strict definition of ambient air only excludes areas to which the
public is explicitly excluded by enforceable measures such as fences, which might not be
normally used by the industry. Thus, in order to determine the potential closest location of
receptors to the well site, the modeling has considered receptors at distances as close as the
boundary of a 150m by 150m well pad. On the other hand, it is clear from diagrams and pictures

Final SGEIS 2015, Page 6-121

 of sample sites that the public would have no access to within the well pad area. However, the
closest receptor to any of the sources was limited to 10m to allow for a minimum practical
“buffer” zone between the equipment on the pad and its edge.
The location of the set of modeled receptors is an iterative process for each application in that an
initial set is used to identify the distance to the maximum and other relatively high impacts, and
then the grid spacing may need to be refined to assure that the overall maxima are properly
identified. For the type of low-elevation and ground level sources which dominate the modeled
set in this analysis, it is clear that maximum impacts would occur in close proximity to the
sources. Thus, a dense grid of 10m spacing was placed along the “fencelines”, and extended on
a Cartesian grid at 10 m grid spacing out to 100 m from the sources in all directions. In a few
cases, the modeling grid was extended to a distance of 1000 m at a grid spacing of 25 m from the
100 m grid’s edge in order to determine the concentration gradients. For the combustion and
venting sources, an initial grid at 10m increment was placed from the edge of the 150 m by 150
m pad area out to 1000 m, but this grid was reduced to a Cartesian grid of 20 m from spacing the
“fenceline” to 500 m in order to reduce computation time. The revised receptor grid resolution
was found to adequately resolve the maxima as well for the purpose of demonstrating the
anticipated drop off of concentrations beyond these maxima.
The AERMOD model is also capable of accounting for ground level terrain variations in the area
of the source by using U.S. Geological Survey Digital Elevation Model (DEM) or more recent
National Elevation Data (NED) sets. However, for sources with low emission release heights,
the current modeling exercise was performed assuming a horizontally invariant plane (flat
terrain) as a better representation of the impacts for two reasons. First, given the large variety of
terrain configurations where wells may be drilled, it was impractical to include a “worst case” or
“typical” configuration. More importantly, the maximum impacts from the low-elevation
sources are expected to occur close-in to the facility site, and any variations in topography in that
area was determined to be best simulated by AERMOD using the concept of “terrain following”
plumes.
It should be clarified that this discussion of terrain data use in AERMOD is distinct from the
issue of whether a site might be located in a complex terrain setting which might create distinct

Final SGEIS 2015, Page 6-122

 flow patterns due to terrain channeling or similar conditions. These latter mainly influence the
location and magnitude of the longer term impacts and are addressed in this analysis to the extent
that the set of meteorological data from six sites included these effects to a large extent. In
addition, the air emission scenarios addressed in the modeling for the three operational phases
and associated activities are deemed to be more constrained by short-term impacts due to the
nature and duration of these operations, as discussed further below. For example, the emissions
from any venting or well fracturing are intermittent and are limited to a few hours and days
before gas production is initiated.
Emissions Input Data
EPA and Department guidance require that modeling of short-term and annual impacts be based
on corresponding maximum potential and, when available, annual emissions, respectively.
However, guidance also requires that certain conservative assumptions be made to assure the
identification of maximum expected impacts. For example, the short-term emission rates have to
represent the maximum allowable or potential emissions which could be associated with the
operations during any given set of hours of the meteorological data set and the corresponding
averaging times of the standards. This is to assure that conditions conducive to maximum
impacts are properly accounted for in the varying meteorological conditions and complex
dependence of the source’s plume dispersion on the latter. Thus, for modeling of all short-term
impacts (up to 24 hours); the maximum hourly emission rate is used to assure that the
meteorological data hours which determine the maximum impacts over a given period of
averaging time were properly assessed.
Based on the information and determinations presented in Section 6.5.1.2 on the set of sources
and pollutants which need to be modeled, the necessary model input data was generated. This
data includes the maximum and annual emission rates for the associated stack parameters for all
of the pollutants for each of the activities. In response to the Department’s request, industry
provided the necessary model input data for all of the activities at the multi-well pad site, as well
as at a potential offsite compressor. These data were independently checked and verified by
DAR staff and the final set of source data information was supplied in the Industry Information
Report noted previously. Although limited source data were also contained in the ICF report, the

Final SGEIS 2015, Page 6-123

 data provided by industry were deemed more complete and could be substantiated for use in the
modeling.
The sources of emissions specific to Marcellus Shale operations are treated by AERMOD as
either point or area sources. Point sources are those with distinct stacks which can also have a
plume rise, simulated by the model using the stack temperatures and velocities. An example of a
point source is the flare used for short term periods. Area sources are generally low or ground
level sources of distinct spatial dimensions which emit pollutants relatively uniformly over the
whole of the area. The previously proposed flowback water impoundments are a good example
of area sources. In addition to the emission rates and parameters supplied by industry, available
photographs and diagrams indicated that many of the stacks could experience building
downwash effects due to the low stack heights relative to the adjacent structure heights. In these
instances, downwash effects were included in a simplified scheme in the AERMOD modeling by
using the height and “projected width” of the structure. These effects were modeled to assure
that worst case impacts for the compressors and engines were properly identified. The specific
model input data used is described next, with criteria and non-criteria source configurations
presented separately for convenience.
Criteria Pollutant Sources - The emission parameters and rates for the combustion source
category at a multi-horizontal well pad were taken from data tables provided in the Industry
Information Report. In some instances, additional information was gathered and assumptions
made for the modeling. The report provides “average” and maximum hourly emission rates,
respectively, of the criteria pollutants in Tables 7 and 8 for the drilling operations, Tables 14, 15,
20 and 21 for the completion phase operations, Table 18 for the production phase sources, and
Table 24 for the offsite compressor. It should be noted that the criteria pollutant source
emissions in these tables are not affected by the dry versus wet gas discussions, with the
exception of SO2 emissions from flaring of H2S in wet gas. For this particular pollutant, the flare
emission rate from Table 21 was used. Furthermore, the modeling has included the off-site
compressor in lieu of the smaller onsite compressor at the wellhead and an onsite line heater
instead of an offsite one in order to determine expected worst case operations impacts.

Final SGEIS 2015, Page 6-124

 As discussed previously, initial modeling of both short-term and annual impacts were based on
the maximum hourly emissions rates, with further analysis of annual impacts performed using
more representative long term emissions only when necessary to demonstrate compliance with
corresponding annual ambient thresholds. For the short-term impacts (less than 24-hour), it was
assumed that there could be simultaneous operations of the set of equipment at an on-site pad
area for one well drilling, one well completion, and one well flaring, along with operations of the
onsite line heater and off site compressor for the gas production phase for previously-completed
wells. For the modeling of the 24-hour PM2.5 impacts for the Supplemental Modeling section,
the simultaneous operation scenario was not used based on the Industry Information Report. It
should be clarified that although AERMOD currently does not include the flare source option in
the SCREEN3 model, the heat release rate provided in Table 15 of the Industry Information
Report was used to calculate the minimum flare “flame height” as the stack height for input to
AERMOD.
The placement of the various pieces of equipment in Table 6.12 on a well pad site was chosen
such as not to underestimate maximum offsite as well as combined impacts. For example, the
schematic diagram in the ICF report represents a typical set up of the various equipment, but for
the modeling of the sources which could be configured in a variety of ways on a given pad, the
locations of the specific equipment were configured on a well pad without limiting their potential
location being close to the property edge. That is, receptors were placed at distances from the
sources as if these were near the edge of the property, with the “buffer zone” restriction noted
previously. This was necessary since many of these low level sources could have maximum
impacts within the potential 150m distance to the facility property and receptors could not be
eliminated in this area.
At the same time, however, it would be unrealistic to locate all of the equipment or a set of the
same multi-set equipment at an identical location. That is, certain sources such as the flare are
not expected to be located next to the rig and the associated engines due to safety reasons. In
addition, there are limits to the size of the “portable” engines which are truck-mounted, thus
requiring a set of up to 15 engines placed adjacent to each other rather than treating these as a
single emission point. Since there were some variations in the number and type of the multisource engines and compressors specifically used for drilling and completion, a balance was

Final SGEIS 2015, Page 6-125

 reached between using a single representative source, with the corresponding stack parameters
and total emissions, versus using distinct individual source in the multi-source set. This
determination was also dictated by the relative emissions of each source.
The modeling used a single source representation for the drilling engines and compressors from
Table 8, while for the fracturing pump engines, five sources were placed next to each other to
represent three-each of the potential fifteen noted in Table 15 of the Industry Information Report.
The total emission rates for the latter sources were divided over the five representative sources in
proper quantities. This scenario was revised for the Supplemental Modeling section by modeling
each of the 15 completion equipment engines as individual point sources. The rest of the sources
are expected to either be a single equipment or are in sets such that representation as a single
source was deemed adequate. The one exception was the modeling of the NO2 1-hour standard
as describe in the next section. Using sample photographs from existing operations in other
states, estimates of both the location as well as the separation between sources were determined.
For example, the size of the trucks with mounted fracturing engines was used to determine the
separation between a row of the five representative sources. These photographs were also used
to estimate the dimension of the “structures” which could influence the stack plumes by building
downwash effects. All of the sources were deemed to have a potential for downwash effects,
except for the flare/vent stack. The height and “effective” horizontal width of the structure
associated with each piece of equipment were used in the modeling for downwash calculations.
It was also noted from the photographs that distinct types of rig engines and air compressors are
used for the drilling operations, with one of the types having “rain-capped” stacks. This
configuration could further retard the momentum plume rise out of the stack. Thus, for
conservatism, this particular source was modeled using the “capped” stack option in AERMOD
with the recommended low value for exit velocity. Revised industry information indicates that
these “rain caps” open during engine operations and the supplemental modeling has incorporated
this information. Furthermore, since the off-site “centralized” compressor could conceivably be
located adjacent to one of the multi-well pads, this source was located adjacent to, but on the
other side of the edge of the 150m by 150m pad site.

Final SGEIS 2015, Page 6-126

 The placement of the various sources of criteria pollutants in the modeling is represented in
Figure 6.11. The figure shows individual completion equipment engines as modeled in the
supplemental analysis. This configuration was deemed adequate for the determination of
expected worst-case impacts from a ‘typical” multi-well pad site. Although the figure outlines
the boundary of the 150m by 150m typical well pad area, it is again clarified that receptors were
placed such that each source would have close-in receptors beyond the 10m “buffer” distance
determined necessary from a practical standpoint. That is, receptors were placed in the pad area
to assure simulation of any configuration of these sources on the pad at a given site.
Annual impacts were initially calculated using the maximum hourly emission rates, and the
results reviewed to determine if any thresholds were exceeded. If impacts exceeded the annual
threshold for a given pollutant, the “average” emission rates specifically for the drilling engines
and air compressors in Table 7 and for the hydraulic fracturing and flaring operations from Table
20 of the Industry Information Report were used. For the other sources, such as the line-heater
and offsite compressor, the average and maximum rates are the same as presented in Tables 18
and 24, respectively, and were not modified for the refined annual impacts. As these average
rates account only for the variability of “source demand” for the specific duration of the
individual operations, an additional adjustment needed to be made for the number of days in a
year during which up to 10 such well operations would occur. Thus, from Tables 7 and 14, it is
seen that there would be a maximum of 250 days of operations for the drilling engines,
maximum of 20 days for hydraulic fracturing engines, and maximum of 30 days of flaring in a
given year. Thus, for these sources, the annual average rate was adjusted accordingly. Although
initial modeling included 10 wells per pad per year as an assumption, the resultant impacts were
reviewed and relevant conclusions adjusted in the sections to follow where it was deemed of
consequence to NAAQS or threshold compliance. That is, if the standards compliance was
already demonstrated with the worst-case assumption of 10 wells, no revisions were necessary.
On the other hand, the modeling has not included any operational limits on the use of the line
heater and off-site compressor for the production phase and the annual emissions were
represented by the maximum rates. Some of these considerations are further discussed in
Section 6.5.2.4.

Final SGEIS 2015, Page 6-127

 Lastly, in order to account for the possibility of well operations at nearby pads at the same time
as operations at the modeled well pad configuration, a sensitivity analysis was performed to
determine the potential contribution of an adjacent pad to the modeled impacts. This assessment
addressed, in a simplified manner, the issue of the potential for cumulative effects from a nearby
pad on the total concentrations of the modeled pad such that larger “background levels” for the
determination of compliance with ambient threshold needed to be determined. The nearby pad
with identical equipment and emissions as the pad modeled was located at a distance of one
kilometer (km) from the 150m by 150m area of the modeled pad. This separation distance is the
minimum expected for horizontal wells drilled from a single pad, which extends out to a
rectangular area of 2500m by 1000m (one square mile).
Non-Criteria Pollutant Sources - There are a set of pollutants from two “distinct” sources in the
Marcellus Shale operations for which there are no national ambient standards, but for which New
York State has established either a state standard (H2S) or toxic guideline concentrations. These
are VOC species and HAPs which are emitted from: a) sources associated with venting of gas
prior to the production phase; or b) as by-products of combustion of gas or fuel oil. A review of
the data on these pollutants and their sources indicated that the two distinct source types can be
modeled independently, as described below.
First, of the sources which vent the constituents of the “wet” gas (if it is encountered), the
flowback venting has by far the most dominant emissions of the toxic constituents. The other
two sources of gas venting are the mud-gas separator and the dehydrator, and a comparison of
the relative emissions of the five pollutants identified in the Industry Information Report
(benzene, hexane, toluene, xylene, and H2S) from these three sources in Tables 8, 21 and 22
shows that the flowback venting has about two orders of magnitude higher emissions than the
other two sources. As noted in the Industry Information Report, this venting is limited to a few
hours before the flare is used, which reduces these emissions by over 90%. Thus, modeling was
used to determine the short-term impacts of the venting emissions. Annual impacts were not
modeled, due to the very limited time frame for gas venting, even if ten wells are to be drilled at
a pad.

Final SGEIS 2015, Page 6-128

 It was determined that during these venting events, essentially no other emissions of the same
five toxics would occur from other sources. That is, even though a subset of these pollutants are
also tabulated in the Industry Information Report at relatively low emissions for the engines,
compressors and the flares, it is either not possible or highly unlikely that the latter sources
would be operating simultaneously with the venting sources (e.g. gas is either vented or flared
from the same stack). Thus, for the short-term venting scenario, only the impacts from the three
sources need to be considered. It was also determined that rather than modeling each of the five
pollutant for the set of the venting sources for each of the 12 meteorological years, the flowback
venting source parameters of Table 15 were used with a unitized emission rate of 1 g/s as
representative of all three sources. The actual pollutant specific impacts were then scaled with
the total emissions from all three sources. This is an appropriate approximation, not only due to
the dominance of the flowback vent emissions, but also since the stack height and the calculated
plume heights for these sources are very similar. This simplification significantly reduced the
number of model runs which would otherwise be necessary, without any real consequence to the
identification of the maximum short-term impacts.
The next set of non-criteria pollutants modeled included those resulting from the combustion
sources. It should be clarified that pollutants emitted from the glycol dehydrator (e.g. benzene),
which are associated with combustion sources were also included in these model calculations for
both the short-term and annual impacts. A review of the emissions in Tables 8, 18, 21, and 24
indicates seven toxic pollutants with no clear dominance of a particular source category.
Furthermore, the sources associated with these pollutants have much more variability in the
source heights than for the venting scenario. For example, the flare emissions of the three
pollutants in Table 21 are higher than for the corresponding hydraulic fracturing pump engines,
but the plume from the flame is calculated to be at a much higher elevation than those for the
engines or compressors such that a “representative” source could not be simply determined in
order to be able to model a unitized emission rate and limit the number of model runs.
However, it was still possible to reduce the number of model calculations from another
standpoint. The seven pollutants associated with these sources were ranked according to the
ratios of their emissions to the corresponding 1-hour SGCs and AGCs (SGCs for hexane and
propylene were determined by Toxics Assessment section since these are not in DAR-1 tables).

Final SGEIS 2015, Page 6-129

 These ratios allowed the use of any clearly dominant pollutants which could be used as
surrogates to identify either a potential issue or compliance for the whole set of toxics. These
calculations indicated that benzene and formaldehyde are clearly the two pollutants which would
provide the desired level of scrutiny of all of the rest of the pollutants in the set. To demonstrate
the appropriateness of this step, limited additional modeling for the annual impacts for
acetaldehyde was also performed due to the relatively low AGC for this pollutant. These steps
further reduced the number of model runs by a significant number.
The emission parameters, downwash structure dimension and the location of the sources were
the same as for the criteria pollutant modeling. Similar to the case of the criteria pollutants, any
necessary adjustments to the annual emission rates to provide more realistic annual impacts were
made after the results of the initial modeling were reviewed to determine the potential for
adverse impacts. These considerations are further discussed in the resultant impact section.
Pollutant Averaging Times, Ambient Thresholds and Background Levels
The AERMOD model calculates impacts for each of the hours in the meteorological data base at
each receptor and then averages these values for each averaging time associated with the ambient
standards and thresholds for the pollutants. For example, particulate matter (PM10 and PM2.5)
has both 24-hour and annual standards, so the model would present the maximum impact at each
receptor for these averaging times. As the form of the standards cannot be exceeded at any
receptor around the source, the model also calculates and identifies the overall maximum impacts
over the whole set of receptors.
For the set of pollutants initially modeled, the averaging times of the standards are: for SO2- 3hour, 24-hour, and annual; for PM10/PM2.5 - 24-hour and annual; for NO2 - annual; for CO - 1hour and 8-hour; and for the set of toxic pollutants – 1-hour SGCs and annual AGCs. For most
criteria pollutants, the annual standards are defined as the maxima not to be exceeded at any
receptor, while the short-term standards are defined at the highest-second-highest (HSH) level
wherein one exceedance is allowed per receptor. The exception is PM2.5 where the standards
are defined as the 3 year averages, with the 24-hour calculated at the 98th percentile level. The
toxic pollutant SGCs and AGCs are defined at a level not be exceeded. In the Department’s
assessments, the maximum impacts for all averaging times were used for all pollutants, except

Final SGEIS 2015, Page 6-130

 for PM2.5, in keeping with modeling guidance for cases where less than five years of
meteorological data per site is used.
In addition to the standards, EPA has defined levels which new sources or modifications after a
certain time frame cannot exceed and cause significant deterioration in air quality in areas where
the observations indicate that the standards are being met (known as attainment areas). The area
depicted in Figure 6.4 for the Marcellus Shale has been classified as attainment for all of the
pollutants modeled in the Department’s analysis. Details on area designations and the state’s
obligation to bring a nonattainment area into compliance are available at the Department’s public
webpage as well as from EPA’s webpage. 353 For the attainment areas, EPA’s Prevention of
Significant Deterioration (PSD) regulations define increments for SO2, NO2 and PM10. More
recently, EPA finalized the PSD increments for PM2.5; these are discussed below. Although, in
the main, the PSD regulations apply only to major sources, the increments are consumed by both
major and minor sources and would be modeled to assure compliance. However, the PSD
regulations also exempt “temporary” sources from having to analyze for these increments. It is
judged that essentially all of the emissions at the well pad can be qualified as temporary sources
since the expectation is that the maximum number of wells at a pad can be drilled and completed
well within a year. Even if a partial set of the wells is drilled in a year and these operations
cease, the increment would be “expanded” as allowed by the regulations.
The only exception to the temporary designation would be the offsite compressor and the line
heater which can operate for years. Thus, only these two sources were considered in the
increment consumption analysis. The applicable standards and PSD increments are presented in
Table 6.14 for the various averaging times. Table 6.14 reflects incorporation of the 1-hour SO2
and NO2 NAAQS which are addressed in the supplemental modeling section. Furthermore, the
final PSD increments for PM2.5, which become effective on December 20, 2011, are added to
the Table. 354 In addition to these standards and increments, the table provides EPA’s defined set
of Significant Impact Levels (SILs) which exist for most of the criteria pollutants. These SILs
are at about 2 to 4% of the corresponding standards and are used to determine if a project would

353
354

http://www.dec.ny.gov/chemical/8403.html and http://www.epa.gov/ttn/naaqs/.
Prevention of Significant Deterioration for PM2.5, final rule, Federal Register, Vol. 75, No. 202, October 20, 2010.

Final SGEIS 2015, Page 6-131

 have a “significant contribution” to either an existing adverse condition or would cause a
standards violation. Table 6.14 -also reflects the SILs for PM2.5 as contained in EPA’s final
PSD rule.
These SILs are also used to determine whether the consideration of background levels, which
include the contribution of regional levels and local sources, need to be explicitly addressed or
modeled. When the SILs are exceeded, it is necessary to explicitly model nearby major sources
in order to establish potential “hot spots” of exceedances to which the project might contribute
significantly. For the present analysis, if the SILs are exceeded for the single multi-well pad, the
Department has considered the potential for the contribution of nearby pads to the impacts of the
former on a simplified level. The approach used was noted previously and involves the
modeling of a nearby pad placed at 1000m distance from the pad for which detailed impacts
were calculated, in order to determine the relative contribution of the nearby pad sources. If
these results indicate the potential for significant cumulative effects, then further analysis would
need to be performed.
On the other hand, in order to determine existing criteria pollutant regional background levels,
which would be explicitly included in the calculation of total concentrations for comparison to
the standards, the Department has conservatively used the maximum observations from a set of
Department monitoring sites in the Marcellus Shale region depicted in Figure 6.4. The location
of these sites and the corresponding data is available in the Department’s public webpage. 355
The Department has reviewed the data from these sites to determine representative, but worst
case background levels for each pollutant. The Department has used maximum values over a
three year period from the latest readily available tabulated information from 2005 through 2007
from at least two sites per pollutant within the Marcellus Shale area, with two exceptions. First,
in choosing these sites, the Department did not use “urban” locations, which could be overly
conservative of the general areas of well drilling. This meant that for NO2 and CO, data from
Amherst and Loudonville, respectively, were used as representative of rural areas since the rest
of the Department’s monitor sites were all in urban areas for these two pollutants. Second, data
for PM10 for the period chosen was not available from any of the appropriate sites due to

355

http://www.dec.ny.gov/chemical/8406.html.

Final SGEIS 2015, Page 6-132

 switching of these sites to PM2.5 monitoring per EPA requirements. Thus, the Department
relied on data from 2002-04 from Newburgh and Belleayre monitors. The final set of data used
for background purposes are presented in Table 6.14. These data represent worst case estimates
of existing conditions to which the multi-well pad impacts would be added in order to determine
total concentrations for comparison to the AAQS. In instances where the use of these maxima
causes an exceedance of the AAQS, EPA and Department guidance identify procedures to define
more case specific background levels. Per the Department’s Air Guide-1, since there are no
monitoredbackground levels for the non-criteria pollutants modeled, the impacts of H2S and rest
of the toxic chemicals are treated as incremental source impacts relative to the corresponding
standard and SGCs/AGCs, respectively. Determinations on the acceptability of these
incremental impacts are then made in accord with the procedures in Air Guide-1.
The background levels for criteria pollutants relied upon in the initial modeling analysis are still
deemed conservative based on a review of observed monitoring levels in more recent years for
pollutants such as PM2.5. Thus, most do not need to be updated. On the other hand, for PM2.5
24-hour averages and the new 1-hour NO2 and SO2 standards, more refined background levels
were determined as discussed in the supplemental modeling section.
6.5.2.4 Results of the Modeling Analysis
Using the various model input data described previously, a number of model calculations were
performed for the criteria and toxic pollutants resulting from the distinct operations of the onsite
and offsite sources. Each of the meteorological data years were used in these assessments and
the receptors grids were defined such as to identify the maxima from the different sources. In
some instances, it was possible to limit the number of years of data used in the modeling, as
results from a subset indicated impacts well below any thresholds. In other cases, it was
necessary to expand the receptor grid such that the decrease in concentration with downwind
distance could be determined. These two aspects are described below in the specific cases in
which they were used.
As described in the previous section, initial modeling of annual impacts was performed in the
same model runs as for the short-term impacts, using the maximum emission rates. However, in
a number of cases, this approach lead to exceedances of annual thresholds and, thus, more

Final SGEIS 2015, Page 6-133

 appropriate annual emissions were determined in accord with the procedures described in
Section 6.5.2.3, and the annual impacts were remodeled for all of the data years. These instances
are also described below in the specific cases in which the annual emissions were used. The
results from these model runs were then summarized in terms of maxima and compared to the
corresponding SILs, PSD increments, ambient standards, and Air Guide-1 AGCs/SGCs.
This comparison indicated that, using the emissions and stack parameter information provided in
the Industry Information Report, a few of the ambient thresholds could be exceeded. Certain of
these exceedances were associated with conditions (such as very low stacks and downwash
effects) which could be rectified relatively easily. Thus, some additional model runs were
performed to determine conditions under which the ambient thresholds would be met. These
results are presented below with the understanding that industry could implement these or
propose their own measures in order to mitigate the exceedances. Results for the criteria
pollutants are discussed first, followed by the results for the toxic/non-criteria pollutants.
Criteria Pollutant Impacts
The set of sources identified in Table 6.12 for short-term simultaneous operations of the various
combustion sources with criteria pollutant emissions were initially modeled with the maximum
hourly emission rate and one year of meteorological data. It was clear from these results that the
annual impacts for PM and NO2 had to be recalculated using the more appropriate annual
emissions procedures discussed in Section 6.5.2.3. That is, for these pollutants, the “average”
rates in the Industry Information Report were scaled by the number of days/hours of operations
per year for the drilling engine/compressor, the hydraulic fracturing engines and the flare, and
then these results were multiplied by ten to account for the potential of ten wells being drilled at
a pad for a year. The rest of the sources were modeled assuming full year operations at the
maximum rates. In addition, based in part on the initial modeling, two further adjustments were
made to the annual NO2 impacts. First, the model resultant impacts were multiplied by the 0.75
default factor of the Tier 2 screening approach in EPA’s modeling guidelines. This factor
accounts for the fact that a large part of emissions of NOx from combustion sources are not in the
NO2 form of the standard. The second adjustment related to the stack height of the off-site
compressor, which was raised to 7.6m (25ft) based on the results for the non-criteria pollutants

Final SGEIS 2015, Page 6-134

 discussed below; that is, this height was deemed necessary in order to meet the formaldehyde
AGC.
Each of the meteorological data years was used to determine the maximum impacts for all of the
criteria pollutants and the corresponding averaging times of the standards. However, in the case
of 24-hour particulate impacts, modeling was limited to the initial year (Albany, 2007) for
reasons discussed below. The results for each year modeled are presented in Table 6.15. It
should be noted that the SO2 annual impacts in this table are based on the maximum hourly rates
and are very conservative. In addition, the tabulated values for the 24-hour PM2.5 impacts are
the eight highest in a year, which is used as a surrogate for the three year average of the eight
highest value (i.e., 99th percentile form of the standard). It is seen that the short-term impacts do
not show any significant variability over the twelve years modeled.
The overall maxima for each pollutant and averaging time from Table 6.15 are then transferred
to Table 6.17 for comparison to the set of ambient thresholds. These maximum impacts are to be
added to the worst case background levels from Table 6.14 (repeated in Table 6.16), with the
sum presented in the total concentration column. The impacts of only the compressor and the
line heater are also presented separately in Table 6.16 for comparison to the corresponding PSD
increments. It should be noted that, due to the low impacts for many of the pollutants from all of
the sources relative to the increments, only the 24-hour PM10 and PM2.5 and the annual NO2
were re-calculated for the compressor and line heater, as noted in Table 6.16. In addition, due to
the promulgated PSD increments for PM2.5 in the 10/20/10 final rule, the increments are
reflected in Table 6.16, along with the corresponding PM2.5 impacts (conservatively assuming
to equal PM10 impacts). The rest of the impacts are the same as those in the maximum overall
impact column.
The results indicate that all of the ambient standards and PSD increments would be met by the
multiple well drilling activities at a single pad, with the exception of the 24-hour PM10 and
PM2.5 impacts. In fact, the 3-hour (and very likely the annual) SO2 impacts are below the
corresponding significant impact levels. This is a direct result of the use of the ultra low sulfur
fuel assumed for the engines, which would have to be implemented in these operations. In
addition, the level of compliance with standards for the maximum annual impacts for NO2 and

Final SGEIS 2015, Page 6-135

 PM2.5 are such as to require the implementation of the minimum 7.6 m (30feet) stack height for
the compressor and general adherence to the annual operational restrictions identified in the
Industry Information Report.
Table 6.16 results for 24-hour PM10 and PM2.5 impacts were limited to one year of
meteorological data since these were found to be significantly above the corresponding
standards, as indicated in Table 6.16. Unlike other cases, a simple adjustment to the stack height
did not resolve these exceedances and it was determined that specific mitigation measures would
need to be identified by industry. However, the Department determined one simple set of
modeling conditions under which impacts can be resolved. It was noted that the relatively large
PM10/PM2.5 impacts occurred very close to the hydraulic fracturing engines (and at lower levels
near the rig engines) at a distance of 20 m, but there was also a very sharp drop-off of these
concentration with distance away from these sources. Specifically, to meet the standards minus
the background levels in Table 6.16, it was determined that the receptor distance had to be
beyond 80 m for PM10, and 500 m for PM2.5. In an attempt to determine if a stack height
adjustment in combination with a distance limitation for public access approach can also
alleviate the exceedances, the rig engine and fracturing engine stacks heights were both
extended by 3.1m (10ft). From the photographs of the truck-mounted engines, it was not clear if
any extensions would be practical and, thus, only this minimal increase was considered. This
scenario was modeled again with the Albany 2007 meteorological data. The resultant maximum
impacts were reduced to 171 and 104 µg/m3 for PM10 and PM2.5, respectively. For this case, in
order to achieve the standards using Table 6.16 background levels, the receptors would be
beyond 40 m and 500 m for PM10 and PM2.5, respectively. Thus, the stack height extension did
not significantly affect the concentrations at the farther distances, as would be expected from the
fact that building downwash effects are largest near the source. However, the background level
for PM2.5 can be adjusted from the standpoint that the expected averages associated with these
operations at relatively remote areas are better represented by the regional component due to
transport. If the contribution of the latter to the observed maxima is conservatively assumed to
be half of the value in Table 6.17 (i.e., 15 µg/m3), then the receptor distance at which a
demonstration of compliance can be made is approximately 150 m.

Final SGEIS 2015, Page 6-136

 Thus, one practical measure to alleviate the PM10 and PM2.5 standard exceedances is to raise
the stacks on the rig and hydraulic fracturing engines and/or erect a fence at a distance
surrounding the pad area in order to preclude public access. Without further modifications to the
industry stack heights, a fence out to 500 m would be required, but this distance could be
reduced to 150 m with the taller stacks and a redefinition of the background levels. Alternately,
there is likely control equipment which could significantly reduce particulate emissions. The set
of specific control or mitigation measures would need to be addressed by industry.
Based on recent industry and public information, supplemental modeling analysis and detailed
review of potential control measures and their practical use was undertaken. The preliminary
results clearly indicate that certain levels of emission reductions are likely necessary for at least
the completion equipment engines. The results of the supplemental modeling and the consequent
recommended mitigation measure are presented in the two sections which follow.
An additional issue addressed in a simplified manner was the possibility of simultaneous
operations at a nearby pad, which could be located at a minimum distance of one km from the
one modeled, as described previously. It is highly unlikely than more than one additional pad
would be operating as modeled simultaneously with other pads within this distance; it is more
likely that drill rigs and other heavy equipment would be moved from one pad to another within
a given vicinity, with sequenced operations. Regardless, the impacts of all the pollutants and
averaging times were determined at a distance of 500 m from the modeled well pad for the years
corresponding to the maximum impacts. This is half the distance to the nearest possible pad and
allows the determination of potential “overlap” in impacts from the two pads. The
concentrations at 500m drop off sharply from the maxima to below significance levels for almost
all cases such that nearby pad emissions would not significantly contribute to the impacts from
the modeled source. These impacts at 500m are presented in the last row of Table 6.16 and their
comparisons to the corresponding SILs in Table 6.16 show only the 24-hour PM2.5 and annual
NO2 impacts are still significant at this distance.
Thus, there is a potential that for these two cases the nearby pad operations could contribute to
another well operation’s impacts. This scenario was assessed by placing an identical set of
sources at another pad at a distance of 1km from the one modeled in the general upwind

Final SGEIS 2015, Page 6-137

 direction from the latter. Impacts were then recalculated on the same receptor grid using the
years of modeled worst case impacts for these two pollutants and averaging times. The results
indicated that the maximum impacts presented in Table 6.16 for annual NO2 and 24-hour PM2.5
were essentially the same; in fact the 24-hour PM2.5 impacts are identical to the previous
maxima while the NO2 annual impact of 63.2 increased by only 1.2 µg/m3. Annual impacts from
any other pad not in the predominant wind direction would be lower. These results are judged
not to effect the compliance demonstrations discussed above. Thus, it is concluded that minimal
interactions from nearby pad well drilling operations would result, even if there were to be such
simultaneous operations.
In addition to these results, the modeled impacts discussed in the supplemental modeling section
and the remediation measures recommended to resolve modeled exceedances of both the 24-hour
PM2.5 and 1-hour NO2 NAAQS would substantially reduce both the PM2.5 and NO2 impacts
from the levels in Table 6.15 at the 500 m distance. Therefore, compliance with standards and
increments can be said to be adequately demonstrated on the basis of individual pad results.
Non-Criteria Pollutant Impacts
As discussed in Section 6.5.2.3, three “distinct” source types were independently modeled for a
corresponding set of toxic pollutants: i) short-term venting of gas constituents, ii) combustion byproducts, plus the emissions of the same pollutants from the glycol dehydrator, and iii) a set of
representative chemicals from the flowback impoundments. These impacts were determined for
comparison to both the short-term 1-hour SGC and annual AGC, with the exception of the
venting scenario which was limited to the short-term impacts due to the very short time frame of
the practice. The gas venting emissions out of three sources (mud-gas separator, flowback
venting, and the dehydrator) are essentially determined by the flowback phase. It was thus
possible to model only this source with a unitized emission rate (1g/s) and then actual 1-hour
impacts were scaled using the total maximum emission rates.
Each year of meteorological data was modeled with the flowback vent parameters to
determine the maximum 1-hour impacts for 1 g/s emission rate. These results were then
reviewed and the maximum overall normalized impact of 641 µg/m3 (for Albany, 2008 data) was
calculated as the worst case hourly impact. Using the total emissions from all three sources for

Final SGEIS 2015, Page 6-138

 each of the vented toxic pollutants, as presented in Table 6.17, along with this maximum
normalized impact, results in the maximum 1-hour pollutant specific values in the third column
of Table 6.17. The pollutants “shaded out” in the table are not vented from these sources. All of
the worst case 1-hour impacts are well below the corresponding SGCs, but the maximum 1-hour
impact of 61.5 µg/m3 for H2S (underlined top entry in the box) is above the New York standard
of 14 µg/m3.
Thus, if any “sour” gas is encountered in the Marcellus Shale, there would be a potential of
exceedance of the H2S standard. The maximum 1-hour impact occurred relatively close to the
stack, and, in order to alleviate the exceedance, ambient air receptors would be excluded in all
areas within at least 100 m of the stack. Alternately, it is possible to also reduce this impact by
using a stack height which is higher than the conservative 3.7 m (12 ft) height provided in the
Industry Information Report. Iterative calculations for the year with the maximum normalized
impact indicated that a minimum stack height of 9.1 m (3 0 ft) would be necessary to reduce the
impact to the 12.1 µg/m3 value for H2S reported in the “Max 1-hour” column of Table 6.18.
With this requirement, all venting source impacts would be below the corresponding SGCs and
standard.
For the set of seven pollutants resulting from the combustion sources and the dehydrator, it was
previously discussed that it was only necessary to explicitly model benzene and formaldehyde,
along with the annual acetaldehyde impacts, in order to demonstrate compliance with all SGCs
and AGCs for the rest of the pollutants. The relative levels of the SGCs and AGCs presented in
Table 6.18 for these pollutants and the corresponding emissions in the Industry Information
Report tables clearly show the adequacy of this assertion. For the modeling of these pollutants,
the maximum short-term emissions were used for the 1-hour impacts, but the annual emissions
were used for the AGCs comparisons. The annual emissions were determined using the same
procedures as discussed above for the criteria pollutants.
An initial year of meteorological data which corresponded to the worst case conditions for the
criteria pollutants was used to determine the level of these impacts relative to the SGCs and
AGCs before additional calculations were made. The results of this initial model run are
presented in right-hand set of columns of Table 6.18. These indicate that, while the 1-hour

Final SGEIS 2015, Page 6-139

 impacts are an order of magnitude below the benzene and formaldehyde SGCs and the
acetaldehyde AGC, there were exceedances of the AGCs for the former two pollutants (the top
underlined entries for each pollutant in the maximum annual column). It was determined that
these exceedances were each associated with a particular source: the glycol dehydrator for
benzene and the offsite compressor for formaldehyde. It should be noted that these exceedances
occur even when the emissions from dehydrator are controlled to be below the National
Emissions Standard for Hazardous Air Pollutants (NESHAP) imposed emission rate provided in
Table 22 of the Industry Information Report and with 90% reduction in formaldehyde emissions
accounted for by the installation of an oxidation catalyst, by NESHAP Subpart JJJJ requirement
for the compressor. To assure the large margin of safety in meeting the benzene and
formaldehyde SGCs and the acetaldehyde AGC, another meteorological data base was used to
calculate these impacts. The results in Table 6.17 did not change from these calculations. Thus,
it was determined that no further modeling was necessary for these. On the other hand, for the
benzene and formaldehyde AGC exceedances, a few additional model runs were performed to
test potential mitigating measures. It is clear that, similar to the criteria pollutant impacts, these
high annual impacts are partially due to the low stacks and the associated downwash effects for
both the dehydrator and the compressor sources. Given that these two sources already need to
include NESHAP control measures, the necessary additional reduction in impacts can be
practically achieved by either limiting public access to about 150m from these sources, or by
raising their stacks.
An iterative modeling of increased stack heights for both the dehydrator and the compressor
demonstrated that in order to achieve the corresponding AGCs, the stack of the dehydrator
should be a minimum of 9.1m (30ft), in which case it would also avoid building downwash
effects, while the compressor stack would be raised to 7.6m (25ft). These higher stacks were
then modeled using each of the 12 years of meteorological data and the resultant overall maxima,
tabulated in the bottom half of the “Max annual” column in Table 6.18. It should be noted that
these modifications to stack height would also reduce the corresponding 1-hour maxima leading
to a larger margin of compliance with SGCs. With these stack modifications and the required
NESHAP control measures, all of the SGCs and AGCs are projected to be met by the various
combustion operations and the dehydrator. It should be noted that appropriate stack height for

Final SGEIS 2015, Page 6-140

 both the compressors and any associated dehydrators can be better determined by case-specific
modeling during the compressor station permitting process if the dehydrator is to be located at
the compressor station.
6.5.2.5 Supplemental Modeling Assessment for Short Term PM2.5, SO2 and NO2 Impacts and
Mitigation Measures Necessary to Meet NAAQS.
As a supplement to the initial modeling, a number of additional model runs had to be made in
order to address certain outstanding issues with PM10 and PM2.5 short term impacts from the
original analysis, as well as to incorporate new information provided by industry. In addition,
the re-assessment also addresses EPA’s promulgated 1-hour NAAQS for SO2 and NO2 which
became effective since September 2009. The modeling performed previously for PM10/PM2.5
was limited to a simplified set-up of the drilling and completion equipment engines and
conservative set of assumptions which lead to substantial exceedances of the 24-hour NAAQS
for both PM10 and PM2.5. Based on this preliminary result, it was deemed that further
modeling would not resolve the exceedances without some level of emission mitigation.
Thus, industry was asked to provide a set of potential mitigation measures to alleviate these
exceedances. In addition, the 2009 draft SGEIS identified a simple stack height and/or “fencingin” of impacts option to be considered. This latter was not meant as the Department’s suggested
preferred mitigation option. Instead, the purpose behind the modeling with increased stack
height was to provide a quantification of the level of simple physical adjustments to the
operations in order for industry to incorporate the results in their assessment of mitigation and
control measures. Based on both industry and public input, additional modeling analysis has
been undertaken to address the PM10 and PM2.5 exceedances and the associated mitigation
measures necessary to assume NAAQS compliance.
In addition to the PM10/PM2.5 issue, EPA promulgated new 1-hour standards for SO2 and NO2.
These standards are 100 ppb (or 188 µg/m3) for NO2 , as the 3 year average of the 98th percentile
of the daily maximum 1-hour values and 75 ppb (or 196 µg/m3) for SO2, as the 3 year average of
the 99th percentile of the daily maximum 1-hour values, which became effective on April 12,
2010 and August 23, 2010, respectively 356. These standards would be considered within the
356

Federal Register: Vol 75, No. 26, pp 6474+ (2/9/10) and Vol. 75, No. 119, pp35520+ (6/22/10).

Final SGEIS 2015, Page 6-141

 context of this SGEIS and in accordance with Subpart 200.6 requirement defined in Section 6.5.1
to assure all potential adverse impacts are identified and rectified. The additional assessments
performed for these short term impacts are addressed separately to distinguish certain
information for PM10/PM2.5 gathered from industry since the initial modeling analysis in the
SGEIS.
A) PM 10 and PM2.5 24-hour Impact Modeling and Potential Mitigation Measures.
As part of the Industry’s Responses (dated September 16, 2009) to Information Requests, IOGA
referenced a modeling assessment performed by consultants for Chesapeake Energy which
incorporated a number of revisions to and recommendations on the Department’s modeling
analysis 357. The analysis was based on one year of Binghamton meteorological data which
indicated compliance with the PM10 NAAQS and much lower PM2.5 impacts than the
Department’s results, but still exceedances of the PM2.5 NAAQS. Mitigation measures were
listed for resolving the latter exceedances. The analysis incorporated a set of assumptions which
are summarized below with the Department’s position on each of these:
The PM emissions provided by ALL consultants in the Industry Information Report were not
speciated with respect to PM10 and PM2.5. Based on factors in EPA’s AP-42 for large
uncontrolled diesel engines, the PM10 and PM2.5 emissions represent 82% and 69%,
respectively, of the total PM emissions. The Department has reviewed the information and
agrees that the corresponding emissions should be adjusted accordingly;
The set of 15 completion equipment engines were represented in the Department’s modeling as
three sets of 5 units stationed next to each other. Industry noted that since these units contributed
significantly to the modeled exceedances, each of the engines should be model as a separate
point source. The Department had noted this conservative step and has remodeled the units are
15 separate sources. However, unlike Chesapeake’s approach of separating the 15 units in two
sets at the extreme ends of the pads, the Department has no reason to believe the engines would
not be placed next to each other. Thus, the engines are re-modeled as depicted in revised Figure
6.11;

357

June 21, 2010 letter from Brad Gill of IOGA-NY to Kathleen Sanford and associated modeling files.

Final SGEIS 2015, Page 6-142

 It is claimed that the use of ULSF would result in an additional 10% reduction in PM emissions.
The Department could not readily verify the level of reduction specifically for all diesel fuel
sulfur contents, but it has been considered in our discussion of resultant impacts;
It was notes that the maximum emissions provided for the completion equipment engines are
only representative of two hours in the operation cycle of these units. Thus, the hourly emission
rate in the modeling was “prorated” to better characterize the likely 24-hour emission rate. The
Department does not agree with this approach. As noted in our previous analysis, the ALL
report noted a typical hydraulic fracturing operation can require up to 10 stages of total 5 hour
periods. Thus, it is likely that a relevant portion of a day could experience the maximum hourly
emission rate associated with worst case impacts, as we had previously assumed. Since there is
no justified or simplified approach to account for this possibility, we believe it prudent to use the
maximum hourly emission rate for the revised analysis; and
It was noted that for drilling engines, the use of the EPA “capping” stack option is not
appropriate since the cap is “open” when the engines are in operation. This assumption has been
revised in the reassessment by using the actual stack velocities and temperatures.
Finally, the Chesapeake modeling report noted that the background levels used were the maxima
observed at representative monitors and are unreasonably high. The SGEIS recognizes the
conservative nature of the background levels chosen as worst case observations, but notes that
more representative values can be determined in instances where such refinement is necessary.
For PM2.5, the reassessment has taken a less conservative approach in accord with the
Department’s and EPA’s modeling guidance by reviewing the monitoring data and the expected
associated average values in the Marcellus Shale area. In its March 23, 2010 guidance memo 358
on PM2.5, EPA provided a screening first Tier conservative approach to addressing NAAQS
compliance which was to be followed by further guidance with more refined methods.
Lacking the follow-up guidance, most states, including New York, have allowed methods more
in line with Section 8.2 of EPA’s Modeling Guidelines. One such approach recognized by the
March 23, 2010 memo is to allow for seasonal average observed concentrations. In reviewing
358

Modeling Procedures for Demonstrating Compliance with PM2.5 NAAQS, Stephen Page, 3/23/10.

Final SGEIS 2015, Page 6-143

 the data at monitors in the Marcellus Shale area, especially for the latest three years, we have
identified a value of 15 µg/m3 as appropriate for the purpose of determining representative 24hour “regional” background level. The data also indicates that more recent observations than the
2005-7 levels in the SGEIS have in general shown a downward trend. It is also noted that the
modeled impacts would dominate the total impacts which are to be compared to the NAAQS.
For this reason, it is deemed appropriate to use the 8th highest concentration, as the form of the
NAAQS, instead of the maximum 24-hour value recommended as a first screening Tier. A
conservative step was to use the 8th highest maximum from each year of meteorological data
modeled since these were limited to only two years per site.
In addition to these modifications to the original PM10 and PM2.5 modeling in the SGEIS, we
have incorporated industry’s assertion that there would not be simultaneous drilling and
hydraulic fracturing operations at a single well pad. In order to better characterize the
contribution of the completion equipment engines, the drilling rig engine and the air
compressors, in addition to calculating the maximum overall impacts, the modeling results were
also separated for each operation to determine the need for mitigation associated with each
engine type. The modeling approach was otherwise identical to the previous analysis, except the
version of AERMOD was updated to the version (09292) available at the time of the analysis.
The first step in the modeling exercise was to determine the maximum 24-hour PM10 and PM2.5
impact for each of the modeled years. These results are presented in Table 6.19. It is seen that
the refined impacts which incorporate the above considerations are much lower than the values
in Table 6.15. This reduction is due mainly to the speciated emission rates and the modeling of
completion equipment engines as individual point sources. However, the impacts are still
projected to be above the PM10 and PM2.5 NAAQS, except for the PM10 impacts associated
with the drilling engines. As was noted previously, these maximum impacts occur next to the
well pad and concentrations drop-off relatively sharply with downwind distance. The modeled
impacts were reviewed and indicate that impacts above the NAAQS-minus-background levels
value occurred at distances up to a maximum of 60m for completion equipment engines and
PM10, while for PM2.5 the corresponding maximum distances were 120 and 150m for the
drilling and completion equipment engines, respectively. The levels of the maximum impacts

Final SGEIS 2015, Page 6-144

 also indicate that the different sets of engines could be dealt with using different mitigation
measures.
As required by Part 617.11(5) (see next section for more details), the Department would pursue
mitigation measures which eliminate potential adverse impacts to the maximum extent
practicable. The August 26, 2009 industry report, the Industry Information Report and technical
information from the public 359 identified a set of such potential measures which have been
reviewed with this SEQRA requirement in mind. Certain of these suggestions would unlikely be
practically implemented to any extent; for example, the use of electric engines could be very
limited due to the remote nature of the drilling sites, while cleaner fuel engines are currently
being investigated by engine manufacturers for future use. To the extent these alternative
cleaner engines are available, the Department recommends their use. On the other hand, PM
control equipment or the use of newer and cleaner engines are two measures recognized by both
industry and the public as viable and the Department’s review has concluded that these measures
are practical. Appendix 18A provides the Department’s review of the emission factors for
various tiers of engines and potential after-treatment methods. Its conclusions are incorporated
in the following discussions.
The discussions are limited to PM2.5 since these are the controlling impacts; that is, any
measures to eliminate the PM2.5 exceedances would also assure compliance with the PM10
NAAQS. For the drilling rig and air compressor engines, the results in Table 6.19 were further
analyzed to determine the impacts from each. The contribution to the overall maximum impact
(Buffalo, 2007) for drilling operations was associated with the rig engines. Furthermore,
industry has suggested and operational diagrams confirm that these engines are used close to the
center of the well pad where the drilling actually occurs. The modeling results in Table 6.19
indicate that at a distance of 75m (from the center to the edge of the well pad) the drilling engine
impacts are 30 µg/m3 , essentially due to the rig engine, which would still require mitigation
when a background level of 15 µg/m3 is used. Even if the 10% reduction in PM emissions due to
the use of ULSF is achieved, as argued by industry, the resultant impact would still exceed the
NAAQS. The rig engine impacts, however, are associated with ALL report’s assumed Tier 1
359

For example, comments by AKRF consultants on behalf of NRDC, Memorandum from Hillel Hammer, dated December 3,
2009, page 5.

Final SGEIS 2015, Page 6-145

 engine emission factor. If the rig engines class was restricted to the use of Tier 2 and higher,
then the PM2.5 impacts would be reduced by at least a factor of 2.7 (see Table Two of Appendix
18A, 0.4/0.15) which would result in compliance with the NAAQS regardless of where these
engines are located on the well pad.
Industry data in the IOGA-NY information responses indicate that a majority (71%) of engines
currently in use are Tier 2 and Tier 3 engines. In addition, a small fraction (3.5%) are uncertified
(Tier 0), with “unknown” emissions. It is the Department’s conclusion that these latter engines
cannot be used for drilling in New York’s Marcellus Shale since it has not been demonstrated
that these would result in NAAQS compliance. Furthermore, since 25% of the current drilling
engines are Tier 1, their use in New York should only take place with certain control measures.
The discussions in Appendix 18A conclude that of the two exhaust after-treatment measures,
Diesel Oxidation Catalyst (DOC) and Continuously Regenerating Diesel Particulate Filter
(CRDPF) or particulate “traps”, the latter is by far the more effective method in that it achieves
almost three times the emission reduction (i.e., 85% vs 30%). The level of control achieved by
the traps is necessary to alleviate all PM2.5 NAAQS exceedances from any Tier 1 drilling
engines. Thus, the CRDPF traps should be the after-treatment for Tier 1 drilling engines if these
are to be used in New York. This conclusion also applies to the air compressors for which the
maximum PM2.5 impact is calculated to be 65ug/m3 for Tier 1 emissions. On the other hand,
Tier 2 and above drilling rig engines and air compressors demonstrate NAAQS compliance
without these controls.
The Department also considered the “mitigation” of the NAAQS exceedances by stack height
and distance restriction measures identified previously in the SGEIS. Although the IOGA-NY
response also lists the stack height increase on the drilling engines as a potential measure, there
is no indication from industry if such measures are practical given the stack configuration of
these engines and the height to which these would be extended. In addition, this measure is not
in strict accord with the need to mitigate the adverse impacts to the maximum extent practicable.
The combination of operating these engines closer to the drilling rig, but more importantly the
use of CRDPF traps on Tier 1 engines are deemed the necessary mitigation measures.

Final SGEIS 2015, Page 6-146

 Turning next to the completion equipment engines, it seems even less practical to apply the
distance and stack height increase restrictions to this class of engines. In fact, industry has
previously indicated that stack height increase on these mobile units cannot be practically
accomplished. A modeling run indicates that in order to meet the PM2.5 standard under the
revised set of assumptions, the stack height would need to be at least doubled. Furthermore, the
distance at which impacts are projected to be below the NAAQS-minus-background level was
noted previously to be 150m. This is based on the Tier 2 emission factor modeled for these
engines as provided by the ALL report. Consequently, the required practical approach to these
engines would also require the use of the CRDPF traps as after-treatment on Tier 2 engines. For
the maximum 24-hour PM2.5 case of Table 6.19 (Buffalo, 2006), the 202 µg/m3 impact reduces
to 44 µg/m3 at a distance of 75m from the engines. Again, a 10% reduction in PM emissions due
the use of ULSF does not alleviate these exceedances. Furthermore, unlike the smaller drilling
engines, the ability of placing the 15 completion equipment engines (typically 14 used in
Pennsylvania) near the center of the well pad is questionable. Based on industry’s depiction, it is
possible to separate these into two sets at either side of the hydraulic fracturing operations to
further reduce impacts. In sum, however, the number of Tier 2 completion equipment engines
which would require the installation of the particulate traps ranges from at least two thirds to all
of the 15 engines per hydraulic fracturing job. For practical purposes, it is recommended that all
Tier 2 engines be equipped with the CRDPF traps. Otherwise, each well operation might need to
undergo more site specific analysis to demonstrate that a certain configuration or PM trap
installation alternative would assure compliance with the 24-hour PM2.5 and PM10 NAAQS.
Further details on the practicality of requiring these traps and other after-treatment control
measures are discussed in the section following the SO2 and NO2 modeling results.
With respect to the Tier 0 and Tier 1 completion equipment engines, these emissions have not
been analyzed or modeled, but for the same reasons as for the drilling engines, Tier 0 completion
equipment engines should not be used in New York. In addition, based on the scaling of the
maximum impact in Table 6.19 by the ratio of Tier 1 to Tier 2 emission factors (2.7), it is
determined that Tier 1 engines have the potential to cause a modeled exceedance even if
equipped with a particulate trap (maximum impact of 82 µg/m3 with 85% control). Industry can
suggest impact mitigation in addition to the use of PM traps in order to show compliance with

Final SGEIS 2015, Page 6-147

 the NAAQS, but lacking such a demonstration, it is the Department’s interim conclusion that
Tier 1 completion equipment engines should not be used in New York. On the other hand, and
as also suggested by industry and the public, newer Tier 4 engines, which would likely be
equipped with traps in order to achieve the required emission factors for those engines, can be
used as an alternative to the Tier 2 engines with a PM trap.
B) SO2 and NO2 1-hour Impacts and Potential Mitigation Measures.
The 1-hour SO2 and NO2 NAAQS were promulgated since September 2009. Permitting and
SEQRA actions after the effective date of an NAAQS are addressed by the Department to assure
compliance with the NAAQS in accord with standard Department and EPA policy and
requirements. EPA Region 2 recommended that the Department consider the new NAAQS in
the SGEIS. In accord with the SEQRA process and the Department’s Subpart 200.6 requirement,
the Department has modeled the 1-hour SO2 and NO2 impacts to assure that all NAAQS are met.
With respect to the 1-hour SO2 standard of 196 µg/m3, no detailed modeling was determined
necessary. Instead, the results of the previous SO2 3-hour modeling in Table 6.15 indicated that
the use of the ULSF would likely result in 1-hour impacts being below the NAAQS. Thus, the 1hour maximum CO impact in Table 6.15 was used to scale the corresponding 1-hour maximum
SO2 impacts using the ratio of the fracturing engine SO2 and CO emissions since these engines
were responsible for the overall maxima. The resultant maximum impact is calculated to be 24
µg/m3. Using a representative, yet conservative, maximum 1-hour SO2 level of 126 µg/m3 from
the Elmira monitor for 2009 gives a total impact of 150 µg/m3 which is below the corresponding
NAAQS of 196 µg/m3. Thus, no further modeling was necessary to demonstrate compliance with
the 1-hour SO2 standard.
Simple scaling to demonstrate compliance was not possible for the NO2 1-hour impacts due to
the very large concentrations projected using the same method. Instead, it was necessary to
account for a number of refinements in the modeling based on EPA and Department guidelines.
There are at least two main aspects to the NO2 modeling which need to be addressed in such
refinements. These issues have been raised by EPA, industry and regulatory agencies as needing

Final SGEIS 2015, Page 6-148

 further guidance. Similar to the PM2.5 guidance, EPA released a memorandum 360 on June 29,
2010 which provides guidance on how to perform a first Tier assessment for the NO2 NAAQS.
More recently, EPA has provided further guidance 361on particulars in the modeling approach for
NO2 1-hour NAAQS compliance determinations.
The two main issues which have been raised deal with: 1) the form of the standard, as the 3 year
average of the 98% of the daily maximum 1-hour value, which the AERMOD model used for the
original modeling and the revised PM2.5 modeling are not set to calculate, and 2) the ratio of
NO2 to NOx emissions assumed for stacks from various source types. Of these, the latter is more
critical since NO2 is a small fraction of the NOx emissions in essentially all source types and
assuming all of the NOx emissions are NO2 is unrealistic. These issues, however, are not
insurmountable. For example, there are model post processors offered by consultants which can
readily resolve the first issue. At the time of our re-analysis, EPA provided the Department with
a “beta” version of AERMOD which performs the correct averages for NO2. Some limited
preliminary supplemental modeling used that model version, but the Department has recalculated
these impacts using the final version of AERMOD (11059) released on 4/8/11 to assure proper
calculation of the 8th highest 1-hour maximum per day of meteorological data. The results
discussed below reflect the use of this version of AERMOD. It should be noted that the revised
version of AERMOD does not contain any changes significant enough to affect the PM2.5
analysis.
With respect to the second issue, a number of entities, including EPA and the Department, have
gathered information on the NO2 to NOx ratios from various source types which can be
incorporated in the modeling. For the specific drilling and completion equipment engines,
Department staff has undertaken a review of available information and has made
recommendations on this issue. The details of the recommendations are provided in Appendix
18A which are used in the analysis to be discussed shortly. In addition to this ratio, EPA and
Department guidance allows the use of two methods to refine NO2 modeled impacts; the Ozone

360

Guidance Concerning the Implementation of the 1-hour NO2 NAAQS for the Prevention of Significant Deterioration
Program. Memo from Stephen Page, EPA OAQPS, dated June 29, 2010.

361

Additional Clarifications Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2 NAAQS. Memo
from Tyler Fox, EPA OAQPS, dated March 1, 2011.

Final SGEIS 2015, Page 6-149

 Limiting Method (OLM) and the Plume Volume Molar Ratio Method (PVMRM). There is no
preference indicated in EPA guidance as to which method might provide more refinement.
However, based on limited model evaluation results presented in the March 1, 2011 EPA
guidance memorandum, the current analysis has relied upon the OLM method with the
appropriate “source group” option (OLMGROUP ALL) noted in the EPA memo.
In addition to the NO2/NOx ratio, hourly O3 data is necessary for the use of the method. These
were taken from available Department observations at monitor sites representative of the
meteorological data bases discussed in the original analysis section. Furthermore, for the
determination of background 1-hour NO2 values, we have refined EPA’s first Tier screening
approach of using the highest observed levels by calculating the average of the readily available
3rd-highest observations from the Department’s Amherst and Pinnacle State Park monitors for the
year 2009. This calculated value is 50 µg/m3 and is still conservative relative to the form of the
NO2 standard, as well as relative to further refinements allowed by EPA and Department
guidance.
Appendix 18A recommends that, for engines for which emissions were calculated by the
Industry Information Report and used in the Department’s modeling, the NO2 fraction of NOx is
11% without after-treatment. Thus, an initial set of model runs were performed for the
completion equipment engines using the two years of Albany data and this ratio of 0.11 in
AERMOD. The results indicate that the maximum impacts from the hydraulic fracturing
operations with the 0.11 factor (without the OLM approach) were approximately 3500 µg/m3
which, although lower than those from the simple scaling of the CO impacts, are still an order of
magnitude above the 1-hour standard of 188 µg/m3 for the hydraulic fracturing operations. The
impact was noted to be above the NAAQS out to a distance of 300 m from the pad. Thus, further
refinements were necessary by the AERMOD-OLM approach.
First to consider, however, is that a confounding issue which this initial modeling did not include
was the discovery that the NO2 to NOx ratio is increased by the particulate trap from 0.11 to 0.35
due to the generation of NO2 in order to oxidize and remove the particulates (see Appendix
18A). This would lead to even higher NO2 impacts. These results clearly indicate that some
form of after-treatment exhaust control method is necessary for the completion equipment

Final SGEIS 2015, Page 6-150

 engines. The after-treatment methods to reduce NOx emissions are discussed in Appendix 18A
which indicates that at present the recommended exhaust treatment method in practical use for
on-road engines or engines in general is the SCR system. As noted in Appendix 18A, this
preferred after-treatment method for NOx control would reduce the NO2 to NOx ratio (with the
CRDPF traps in place) down to essentially the same value as without the traps (i.e. 0.10). Of
course, the SCR system would also substantially reduces the NOx emissions by 90%. Therefore,
the last step in the modeling of the completion equipment engines was to use the 90% reduction
in emissions and the NO2/ NOx ratio of 0.10 with the OLM option. The analysis relied on the
Tier 2 emissions provided by the Industry Information Report as the base emissions which were
then reduced by 90% by the SCR controls. This level of modeling was deemed the most
refinement allowed currently by Department and EPA guidance.
For the drilling engines, an initial modeling was performed first without the SCR controls and
the 0.11 NO2/NOx ratio and the drilling rig Tier 1 emissions provided in the Industry Information
Report as representative of the maximum emission case. For the compressors, Tier 2 was
provided as the worst case emissions for the modeling of short term impacts. Based on two years
of Albany meteorological data, it was found that the rig engines would exceed the NO2 1-hour
standard by about a factor of two and impacts would be above the NAAQS-minus-background
level out to a distance of 150 m. From the modeling for PM2.5, it was found that the Tier 1 rig
engines would need to be equipped with a PM trap in order to project compliance with the 24hour PM2.5 standard. Since the traps were found to increase the NO2/ NOx ratio by three fold, it
is clear that the Tier 1 rig engine impacts would be substantially above the 1-hour NO2 NAAQS
without reductions in the NO2 emissions. Thus, it is concluded that any Tier 1 rig engines (and
compressors by analogy) would need to be equipped with both a PM trap and SCR for use in
New York drilling activities.
Thus, the final set of modeling analysis used the SCR controlled Tier 2 completion equipment
engine emissions with a NO2/NOx ratio of 0.10 and Tier 2 drilling rig engines and air compressor
engines (both of which do not require PM traps) with the NO2/ NOx ratio set to 0.11 as noted
previously. As for the completion equipment engines, the NO2 modeling for the rig engines and
compressors was based on more realistic representation of the units as individual units of five
separate, but contiguous point sources as a further refinement to represent their configuration.

Final SGEIS 2015, Page 6-151

 The emissions for each were scaled from the totals in Table 8 of the 8/26/09 Industry Report and
these were placed in a north-south orientation at the same location as in Figure 6.11.
The set of NO2 modeling with all of the meteorological data sites considered all potential sources
as in previous analysis, but also provided the maximum impact for each of the three types of
engines in order to determine specific potential necessary mitigation measures. However, initial
modeling of the combined “drilling” scenario using two years of Albany data indicated an
inconsistence in the total projected impacts in comparison to the results from the rig engines and
compressors separately. This raised a potential issue with the “combined” impacts from these
two operations which was related to the specifics of the OLM Ozone “distribution” approach.
The resolution of this issue for the purposes of determining impacts from the rig engines and
compressors and the need for potential mitigation measure was to recommend to place these two
types of engines near the rig in the center of the well pad (as in the case of the PM results) and,
furthermore, to separate these on either side of the drill rig to minimize combined impacts. A
single year model run indicated this minimized combined impacts. From information and
diagrams available, it is clear that these engines are in fact placed near the center of the pad when
in actual operation.
The results of the 1-hour NO2 impacts are presented in Table 6.19. As noted in the table, all
engine are based on Tier 2 emissions, with the completion equipment engines assume to use SCR
controls. The results for each of the meteorological data years, the overall maxima, the impacts
at a 75-m distance (from center of pad to boundary), and the distance at which the impacts fall
off to the NAAQS-background value of 138 µg/m3 are presented for the completion equipment
engines, the rig engines and the compressors. It is seen that the overall maxima are above the
NAAQS. However, these need to be qualified relative to the other information tabulated in
terms of potential mitigation measures necessary. It should be noted that a number of
conservative assumptions are related to these impacts. First, it is noted that if the sources are
placed in the center of the pad, as recommended, the impacts are much lower and essentially
below the 1-hour NAAQS. Furthermore, these impacts should be adjusted downward by 10%
since the tiered emission “limits” for Tier 2 and above are at most 90% NOx as described in
Appendix 18A. In addition, the background level used is conservative in that it represents the
average of the third highest observations in the shale area and can be adjusted downwards.

Final SGEIS 2015, Page 6-152

 Lastly, the distance to achieve the NAAQS minus background level is seen in the Table to be
very close to the edge of the well pad. Using concentration maps for the three engine types
indicate a sharp drop off of impacts such that the NAAQS minus background level is reached
essentially at the well pad edge with only the 10% downward adjustment to impacts. In total,
these considerations result in the NO2 impacts being below the 1-hour NAAQS with the proper
placement of the engines near the center of the well pad and the use of SCR control on the
fracturing engines, coupled with Tier 2 or higher engines.
As discussed in Appendix 18A, SCR control is the only currently available NOx reduction
system for these size engines which has demonstrated the ability to practically achieve the level
of reduction necessary (i.e., minimum 90%) to meet the NAAQS. Since the results of the PM2.5
modeling concluded that Tier 0 (uncertified) and Tier 1 completion equipment engines are not
recommended for use in New York if CRDPF (particulate traps) are retrofitted to these, the
application of SCR to Tier 2 and newer engines were considered. It is the Department’s
understanding from the manufacturers of these engines that the Tier 4 engines would have to be
equipped with PM traps and SCR in order to meet the more stringent emission limits. It should
be recalled that without the SCR control, the particulate traps increase the NO2 to NOx ratio by
three fold and the corresponding impacts by a similar magnitude. Thus, the SCR system should
be installed on all engines in which PM traps are being required for PM2.5 NAAQS compliance
purposes. Any alternate system proposed by industry which has a demonstrated ability to
achieve the same level of PM and NOx reduction and, concurrently, resolve the NO2 increase by
the particulate traps in order to meet the NAAQS would be considered by the Department. At
the present time, the Department is not aware of such an alternative system which has a proven
record. For the purposes of the SGEIS, the Department has determined that the SCR system is
necessary and adequate for this purpose. The next section discusses the practicality of using both
the particulate traps and SCRs on completion equipment engines.
A summary of the Department’s determination on the EPA Tier engines and the necessary
mitigations to achieve the 24-hour PM2.5 and 1-hour NO2 NAAQS is presented in tabular form
in Table 6.20. The first column provides the various EPA tiers for the drilling and completion
equipment engines and their time lines as presented in Appendix 18A. The next column presents
sample percent of each Tier engines currently in use as provided by industry in the Information

Final SGEIS 2015, Page 6-153

 Report. Note that based on the previous discussions, the uncertified (Tier 0) engines would not
be allowed to be used in NY for Marcellus Shale activities. The third column provides the ratio
of the Tier 1 emission rates for PM and NOx to the other tiers, based on the information in
Appendix 18A. The last column summarizes the determinations made by the Department on the
control requirements necessary to meet the 24-hour PM2.5 (and PM10) and the 1-hour NO2
ambient standards. As seen from the table, Tier 1 drilling engines and air compressors would
require a PM trap and SCR controls, with the same controls being required on most of the
completion equipment engine tiers.
Another purpose of this table is to provide an important demonstration that the Department’s
recommendations on control measure for these engines would result in substantial emission
reduction over the current levels allowed in any other operations in other states. That is, in terms
of air quality impacts, the emission reduction factor column of Table 6.20 indicates at least a
factor of 3 and 2 reductions in PM2.5 and NO2 emissions, respectively, from the Tier 1 engines.
Thus, although Tier 2 and 3 drilling engines make up a majority of the engines in current use
(71%), their relative emissions are much lower than the Tier 1 engines, which are recommended
not to be used in NY (or have PM traps and SCR controls with about 90% reductions in
emissions). Therefore, in terms of emissions reductions, the Department’s requirements on the
drilling engines would reduce emissions by at least half. Furthermore, since the completion
equipment engines are about four times larger than the drilling engines, the imposition of PM
traps and SCR on most completion equipment engines means a substantial reduction in overall
PM and NOx emissions from the set of engines to be used in New York. Any alternative
emission reduction schemes which industry might further pursue would be judged against these
reductions. It is clear however, that the Department would assure that any such control or
mitigation measure would explicitly demonstrate compliance with the ambient air quality
standards.
6.5.2.6 The Practicality of Mitigation Measures on the Completion Equipment and Drilling
Engines.
The supplemental modeling assessment has concluded that in order to meet the ambient
standards for the 24-hr PM2.5 and the 1-hour NO2 NAAQS, it is necessary that the completion
equipment engines tiers allowed to be used in New York to be equipped with particulate filter

Final SGEIS 2015, Page 6-154

 traps (CRDPF) and SCR control for NOx. These are Tier 2 and newer completion equipment
engines. Similarly, the Tier 1 rig engines and air compressors would be required to be equipped
with both control devices if these are used in New York. The determination on the specific aftertreatment controls was based on the review of available control methods used in practice (see
Appendix 18A). Currently available alternative control measures considered were deemed
inadequate for the purpose of achieving the level of PM2.5 and NOx emission reductions
necessary to demonstrate NAAQS compliance and/or having a proven record of use in practice.
Although industry can attempt to perform an independent assessment of alternatives to the
recommended exhaust after-treatment controls, it is highly likely that a certain level of control
equipment recommended would be necessary on these engines. If industry identifies viable
alternative control measure which can be demonstrated to achieve the same level of emission
reduction for NAAQS standard compliance, these alternative schemes would need to be
submitted for Department review and concurrence prior to their use in New York. Furthermore,
in recommending the use of particulate traps and the SCR technology, Department staff has
considered the requirements of subsection 617.11.5 and the practicality of the chosen measures.
Taking the diesel particulate traps and the SCR controls separately, it is fair to say that since the
former have a longer established history of actual use than the latter on types of engines of size
in the rig engine class, the demonstration of practicality for the traps might be less onerous. For
example, industry itself has identified these diesel particulate traps on Tier 2 and 3 engines in
their list of mitigation measure. 362 In addition, public information (see footnote 17) also has
identified the ongoing use of diesel traps as a required mitigation measure by Metropolitan
Transportation Authority (MTA) for non-road engines in major construction projects in NYC.
These latter engines, however, are in the size range of the smaller rig engines and not in the
completion equipment engine range. Information on the ongoing practical use of particulate
traps in these and similar activities have been further confirmed by Department staff through
publically available information. Thus, while it can be concluded that the requirement to use
particulate traps on certain EPA tiered engines is in accord with Subsection 200.6 and 617.11 of
the Department’s requirements, it is nonetheless necessary for industry to further assess the

362

ALL Consulting 2010. page 43 of the ALL/IOGA September 16, 2010 Information Request Report.

Final SGEIS 2015, Page 6-155

 practicality of their use for the completion equipment engine size range. Based on limited
conversations with two of the engine manufacturers indicated that the main issue still to be
resolved is the details of the engineering necessary to use PM traps as after-treatment equipment.
The concern relates to the need for “stand alone” equipment for each of the completion
equipment engines which differs from the built-in or add on components being currently used for
the smaller on-road or off-road engines. To the Department’s knowledge, currently neither PM
and NO2 control measures are being used by the gas drilling industry for other shale activities to
any extent. However, it is the Department’s assumption that the PM traps can be feasibly used
on the Tier 1 drilling engines and compressors and the Tier 1 and 2 completion equipment
engines.
For the use of SCR as the Department’s preferred control measure to reduce NOx emissions
from all of the completion equipment engines allowed to be used in New York, there is less
information on similar size engines. As Appendix 18A notes, however, these units are widely
used in a package with particulate traps on heavy duty vehicles and there is no operational reason
that the same cannot be achieved with the larger completion equipment engines. One way to
judge the practicality of using SCR control on these engines is to consider the costs involved.
The Department has undertaken a simple approach to this issue by using the analogy to reducing
exhaust stream NOx emission and its “cost effectiveness” as a means for major stationary
sources to get a “waiver” from the emission control limits set forth in Subpart 227-2
(Reasonably Available Control Technology (RACT) for Oxides of Nitrogen (NOx)). That is, if a
source can demonstrate that the costs associated with the imposed emission limits are
unreasonable, the Department and EPA would consider granting a waiver from meeting these
limits.
Details of an analysis of the “cost effectiveness” of the SCR controls for completion equipment
engines and the comparable value currently used by the Department for stationary sources is
provided in Appendix 18B. It is important to note that the “cost effectiveness” is based on
acceptable “engine size scaling-up” method for the completion equipment engines with certain
assumptions which might not be representative of the actual cost of installation of SCR after
treatment. The calculations in Appendix 18B indicate that the cost of requiring SCR on the
completion equipment engines is within the value used by the Department for stationary sources

Final SGEIS 2015, Page 6-156

 and is deemed reasonable. The cost effectiveness for the smaller drilling engines should be
lower. It is recognized that the applicability of 227.2 RACT requirements are meant for major
individual stationary sources, but it is also to be noted that the potential annual NOx emissions
from the sum total of engine use throughout the Marcellus Shale are rather large, as discussed in
the next section. Based on the conversations with the engine manufacturers, the main concern
with the installation of SCR as an after-treatment control relates again to the need for a “standalone” system on the completion equipment engines, with the added complexity that these
systems would require “continuous” maintenance to achieve the level of reduction assumed in
the Department’s analysis. In addition, these discussions indicate that the cost associated with
the installation of the PM traps and SCR are likely above those assumed by the Department. A
calculation using the approach in Appendix 18C for PM after-treatment indicates that the “cost
effectiveness” value is well above the value used for NOx RACT waiver determinations. Thus, it
is recommended that industry undertake a detailed assessment of the PM traps and SCR controls
in addressing the Department’s recommendations of these controls as the required mitigation
measures on certain Tier drilling and completion equipment engines in order to demonstrate
compliance with the 24-hour PM2.5 and 1-hour NO2 NAAQS.
Based on the above discussions, the Department believes that the use of particulate traps and
SCR controls are reasonable and practical in achieving the mitigation of potential adverse 24hour PM2.5 and 1-hour NO2 impacts, respectively. As noted previously, industry can present
equivalent control measures and background information for further Department considerations.
Regardless of the specific measure, however, it should be made clear that the Department is
required to assure compliance with ambient standards with respect to any other control measures
which could put forth by industry or the public. One of the mitigation “measures” noted by
industry in their Information Report, at least for NOx emissions, is to allow for the “natural” fleet
turnover of the EPA tiers as these requirements would “kick-in” over time. This suggestion is
not an acceptable scheme, given that none of the engines currently in use or contemplated are the
interim Tier 4 engines, which become effective in 2011, based on the Department’s knowledge
and industry data. If industry is to advance such a mitigation scheme, it would submit an
acceptable timeline which clearly sets out an aggressive schedule to implement the Tier 4
engines. Based on engine manufacturer’s information, there is ongoing efforts to achieve the

Final SGEIS 2015, Page 6-157

 Tier 4 emission standards before the 2014/15 timelines noted in Table 6.20. Such an
implementation schedule can be tied to the specific tiered engine after-treatment controls
required by the Department.
6.5.2.7 Conclusions from the Modeling Analysis
An air quality impact analysis was undertaken of various sources of air pollution emissions from
a multi-horizontal well pad and an example compressor station located next to a typical site in
the area underlain by the Marcellus Shale. The analysis relied on recommended EPA and
Department modeling procedures and input data assumptions. Due to the extensive area
underlain by the Marcellus Shale and other low-permeability gas reservoirs in New York, certain
assumptions and simplifications had to be made in order to properly simulate the impacts from a
“typical” site such that the results would be generally applicable. At the same time, an adequate
meteorological data base from a number of locations was used to assure proper representation of
the potential well sites in the area underlain by the Marcellus Shale in New York.
Information pertaining to onsite and offsite combustion and gas venting sources and the
corresponding emissions and stack parameters were initially provided by industry and
independently verified by Department staff. The emission information was provided for the gas
drilling, completion and production phases of expected operations. On the other hand, emissions
of potential additive chemicals from the flowback water impoundments, which were proposed by
industry as one means for reuse of water, were not provided by industry or an ICF report to
NYSERDA. Thus, worst-case emission rates were developed by the Department using an EPA
emission model for a set of representative chemicals which were determined to likely control the
potential worst case impacts, using information provided by the hydraulic fracturing completion
operators. The information included the compounds used for various purposes in the hydraulic
fracturing process and the relative content of the various chemicals by percent weight. The
resultant calculated emission rates were shared with industry for their input and comment prior to
the modeling.
The modeling analysis of all sources was carried out for the short-term and annual averages of
the ambient air quality standards for criteria pollutants and for Department defined threshold
levels for non-criteria pollutants. The initial modeling used limitations on simultaneous

Final SGEIS 2015, Page 6-158

 operations of the various equipment at both onsite and offsite operations for a multi-well pad in
the analysis for the short-term averages, while the annual impacts accounted for the potential use
of equipment at the well pad over one year period for the purpose of drilling up to a maximum of
ten wells. For the modeling of chemicals in the flowback water, two impoundments of expected
worst case size were used based on information from industry: a smaller on-site and a larger offsite (or centralized) impoundment.
Initial modeling results indicated compliance with the majority of ambient thresholds, but also
identified certain pollutants which were projected to be exceeded due to specific sources
emission rates and stack parameters provided in the Industry Information Report. It was noted
that many of these exceedances related to the very short stacks and associated structure
downwash effects for the engines and compressors used in the various phases of operations.
Thus, limited additional modeling was undertaken to determine whether simple adjustments to
the stack height might alleviate the exceedances as one mitigation measure which could be
implemented. An estimate of the distances at which the impacts would reduce to below all
applicable SGCs and SGCs were provided as part of the original analysis.
Based on recent information provided by industry on the operational restrictions at the well pad,
the elimination of the flowback impoundments, and a limited modeling of 24-hour PM2.5
impacts, the initial Department assessment was revisited. In addition, due to the promulgation of
new 1-hour SO2 and NO2 NAAQS after September 2009, further modeling was performed. The
significant consequences of the revised restrictions on simultaneous operations of the drilling and
completion equipment engines, the number of wells to be drilled per year, and the elimination of
the impoundments are incorporated in the initial modeling assessment. Further modeling details
for the short term PM2.5, NO2 and SO2 impacts are presented in a supplemental modeling
section. These results indicate the need for the imposition of certain control measures to achieve
the NO2 and PM2.5 NAAQS. These measures, along with all other restrictions reflecting
industry’s proposals and based on the modeling results, are detailed in Section 6.5.5 as well
permit operation conditions.

Final SGEIS 2015, Page 6-159

 Table 6.12 - Sources and Pollutants Modeled for Short-Term Simultaneous Operations

Pollutant
SO2

NO2

Source

PM10 &
PM2.5

Non-criteria
CO

combustion

H2S and other
gas constituents

emissions

Engines for drilling

✔

✔

✔

✔

Compressors for drilling

✔

✔

✔

✔

✔

Engines for hydraulic fracturing

✔

✔

✔

✔

✔

Line heaters

✔

✔

✔

✔

✔

Off-site compressors

✔

✔

✔

✔

✔

Flowback gas flaring

✔

✔

✔

✔

✔
✔

Gas venting

✔

Mud-gas separator
✔

Glycol dehydrator

Table 6.13 - National Weather Service Data Sites Used in the Modeling

NWS Data Site

Meteorology Data Years

Latitude/Longitude Coordinates

Albany

2007-08

42.747/73.799

Syracuse

2007-08

43.111/76.104

Binghamton

2007-08

42.207/75.980

Jamestown

2001-02

42.153/79.254

Buffalo

2006-07

42.940/78.736

Montgomery

2005-06

41.509/74.266

Final SGEIS 2015, Page 6-160

✔

 Table 6.14 - National Ambient Air Quality Standards (NAAQS), PSD Increments & Significant
Impact Levels (SILs) for Criteria Pollutants (µg/m3)

Pollutant

1-hour

3-hour

SO2 NAAQS

196

24-hour

Annual

1300

365

80

PSD Increment

512

91

20

SILs

25

5

1

PM10 NAAQS

150

50

PSD Increment

30

17

SILs

5

1

PM2.5 NAAQS

35

15

PSD Increment

9

4

SILs 363

1.2

0.3

NO2 NAAQS

363

8-hour

188

100

PSD Increment

25

SILs

1.0

CO NAAQS

40,000

10,000

SILs

2000

500

The PM2.5 standards reflect the 3 year averages with the 24 hour standard being calculated as the 98th percentile value.

Final SGEIS 2015, Page 6-161

 Table 6.15 - Maximum Background Concentration from Department Monitor Sites

Maximum Observed Values
Pollutant

Monitor Sites

for 2005-2007 (µg/m3)
3 hour - 125

24-hour - 37

SO2

Elmira* and Belleayre

NO2

Amherst

Annual - 26

PM10**

Newburgh* and Belleayre

24-hour - 49

Annual - 13

24-hour - 30

Annual - 11

PM2.5

Annual - 8

Newburgh* and Pinnacle State Park (3 year averages per NAAQS)

CO

Loudonville

1-hour - 1714

* Denotes the site with the higher numbers.
** For PM10, data from years 2002-4 was used.

Final SGEIS 2015, Page 6-162

8 hour - 1112

 Table 6.16 - Maximum Impacts of Criteria Pollutants for Each Meteorological Data Set

SO2

Meteorological Data Year
3-hour

& Location

PM10

24-hour

Annual

24-hour

Annual

24-hour

1-hour

8-hour

2.7

9270

8209

57.9

Annual

13.3

3.1

2008

15.3

13.2

2.9

2.4

2.4

9262

8298

51.0

2007

15.9

12.6

2.8

2.7

2.7

8631

7849

57.1

2008

15.8

14.3

2.7

2.7

2.7

8626

7774

55.4

2007

18.5

13.4

2.3

2.1

2.1

10122

8751

45.5

2008

18.6

15.4

1.9

1.8

1.8

9970

8758

37.6

2001

16.7

14.0

2.4

2.1

2.1

8874

8193

46.4

2002

16.8

14.4

2.7

2.3

2.3

8765

8199

50.9

2006

16.6

15.7

3.2

2.9

2.9

9023

8067

63.2

2007

16.9

14.4

3.1

2.8

2.8

8910

8270

60.8

2005

17.4

11.6

1.9

1.8

1.8

9362

8226

38.4

2006

14.4

14.0

2.2

2.0

2.0

9529

8301

41.9

Maximum

18.6

15.7

3.2

2.9

2.9

10122

8758

63.2

Impact at 500m

0.3

0.3

0.05

480

253

2.5

Binghamton

Jamestown

Buffalo

Montgomery

7.1

.11

Note: 24-hour PM2.5 values are the 8th highest impact per the standard.

Final SGEIS 2015, Page 6-163

355

Annual

15.4

Syracuse

2.7

NO2

2007

Albany

459

CO

PM2.5*

5.0

.11

 Table 6.17 - Maximum Project Impacts of Criteria Pollutants and Comparison to SILs, PSD Increments and Ambient Standards

Pollutant and
Averaging Time

Maximum
Impact

Worst Case
SIL*

3

Background Level
3

(µg/m )

(µg/m )

Total

NAAQS

(µg/m3)

(µg/m3)

Increment

PSD*

Impact**

Increment

3

(µg/m )

(µg/m3)

SO2 - 3 hour

18.6

25

125

143.6

1300

18.6

512

SO2 - 24-hour

15.7

5

37

52.7

365

15.7

91

SO2 - Annual

3.2

1

8

11.2

80

3.2

20

PM10 - 24-hour

459***

5

49

508***

150

PM10 - Annual

2.9

1

13

15.9

50

2.9

PM2.5 - 24-hour

355***

1.2

30***

385***

35

6.5**

9

PM2.5 - Annual

2.9

0.3

11

13.9

15

2.9

4

NO2 - Annual

63.2

1.0

26

89.2

100

CO - 1-hour

10,122

2000

1714

11,836

40,000

NA

None

CO - 8 hour

8758

500

1112

9870

10,000

NA

None

6.5**

30

5.6**

17

25

*

SILs and increments for PM2.5 included in revised Table from EPA’s final PSD rule for PM2.5

**

Impacts from the off-site compressor plus the line heater only for PSD increment comparisons were recalculated for annual NO2 and PM10 and PM2.5 24-hour cases. NA means not applicable

*** See Supplemental Modeling Section for revised analysis

Final SGEIS 2015, Page 6-164

 Table 6.18 - Maximum Impacts of Non-Criteria Pollutants and Comparisons to SGC/AGC
and New York State AAQS

Total
Venting
Pollutant

Emission

Impacts from all
Venting Sources
(µg/m3)

Rate
(g/s)

*

All Combustion Sources and
Dehydrator Impacts (µg/m3)
Max 1-hr

Max 1-hr

SGC
AGC

SGC

Annual

0.90
0.10

0.13

NA** 4,300

NA

100

NA

37,000

NA

5,000

Formaldehyde*
*

4.4

30

0.20
0.04

0.06

Acetaldehyde

NA

4,500

0.06

0.45

Naphthalene

NA

7,900

NA

3.0

Propylene

NA

21,000

NA

3,000

Benzene***

0.218

140

1,300

Xylene

0.60

365

4,300

Toluene

0.78

500

37,000

Hexane

9.18

5,888

43,000

H2S***

0.096

61.5
12.1

14*

13.2

1,300

Denotes the New York State 1-hour standard for H2S

** Denotes not analyzed by modeling, but the SGCs and AGCs would be met (see text)
*** AGC exceedance for benzene is eliminated by raising the dehydrator stack to 9.1m
The standard exceedance for H2S is eliminated by using a minimum stack height of 9.1m for gas venting
The AGC exceedance for formaldehyde is eliminated by using a compressor stack height of 7.6m

Final SGEIS 2015, Page 6-165

 Table 6.19 - Modeling Results for Short Term PM10, PM2.5 and NO2 (New July 2011)

Met Data
Location

Met
Data
Year

2007
2008
2007
Syracuse
2008
2007
Binghamton
2008
2001
Jamestown
2002
2006
Buffalo
2007
2005
Montgomery
2006
Maximum (µg/m3)
Max @ 75m (µg/m3)
Max Dist to NAAQS Background (m)
Albany

PM10, 24-hr (µg/m3)
Hydraulic
Fracturing
313
268
224
327
281
327
339
229
338
318
255
301
339
92
60

Drilling
76
84
95
81
87
89
74
83
106
102
77
66
106
75
60

PM2.5, 24-hr
(µg/m3)
Hydraulic
Drilling
Fracturing
152
36
129
40
144
34
120
27
154
34
121
35
151
29
155
33
202
55
189
59
104
28
108
21
202
59
44
30
150

120

NO2, 1-hour impact
(µg/m3) (see NOTE)
Hydraulic
Fracturing
198
198
156
161
194
213
180
181
147
148
169
155
213
100-140
<90

Rig Engine

Compressor

256
259
196
180
239
231
237
248
269
272
198
211
272
140-170

216
230
198
208
208
220
221
217
231
231
202
200
231
120-150

<100

<100

NOTE: NO2 results reflect SCR controls on the completion equipment engines, with Tier 2 emissions used for all completion equipment, rig engines and compressors.
Results are from the OLM option in AERMOD. See text for details.

Final SGEIS 2015, Page 6-166

 Table 6.20 - Engine Tiers and Use in New York with Recommended Mitigation Controls Based on the Modeling Analysis (New July 2011)

Engine Type
(year in place)

Control measures considered and
determined “practical” based on availability, use practice
and cost.

Sample Percent
in Use

Reduction factors
in Emissions

Drilling: Tier 1 - 1996
(five @ 500hp)

25

Others relative to
Tier 1

Drilling: Tier 2 - 2002

49

2.7

1.6

No PM controls nor SCR necessary for NAAQS.

Drilling: Tier 3 - 2006

22

2.7

2.6

No PM controls nor SCR necessary for NAAQS.

Drilling: Tier 4 - Interim
(not mandated) - 2011

0

40

5.1

Would likely have PM traps built in.
No SCR necessary.

Drilling: Tier 4 - 2014

0

40

23.

Would have PM traps and SCR built in.

Completion: Tier 1 - 2000
(15 @ 2250 Hp)

Assumed same
as for drilling

Others relative to
Tier 1

Would need PM traps and SCR.

Based on modeling, propose not to allow Tier 1 engines.
Alternative is traps/SCR, plus more mitigation.

Completion: Tier 2 - 2006

2.7

1.6

Would need PM trap and SCR.

Completion: Tier 4
Interim - 2011

5.3

3.5

Would likely have PM traps and SCR built in or would use incylinder control for PM.

Completion: Tier 4 - 2015

13

3.5

Would have PM traps and SCR built in.

Note: 3.5% of engines in use are Uncertified or Tier “0”. These will not be allowed to be used in NY

Final SGEIS 2015, Page 6-167

 Figure 6.10 - Marcellus Shale Extent Meteorological Data Sites

 


a .
SYR
BUF 
,4  -?MGJ
Legend 1?

A NW3 Meteorological Sites

Marcellus extent

 

Final SGEIS 2015, Page 6-168

Offsite Compressor
(
!

(
!

(
!

(
!

L in
ea
ter

gC

p
om

es
gin
En

illin

eH

R ig

Dr

!
(
(
!
(
!
(
!
(
!
(
!
(
!

!
(
(
!
(
!
(
!
(
!
(
!
(
!
(
!

r
so
res

Frac Engines

(
!

Flare/Vent

Figure 6.11- Location of Well Pad Sources
of Air Pollution Used in Modeling
Buildings
Drilling Compressor

Frac Engines1

Frac Engines2

Line Heater


Offsite Compressor


Rig Engines

0 5 10

Final SGEIS 2015, Page 6-169

20

30

40

50
Meters

 6.5.3

Regional Emissions of O3 Precursors and Their Effects on Attainment Status in the SIP

This section addresses a remaining issue, as stressed by EPA Region 2 364 that the initial analysis
did not provide a quantitative discussion of the potential regional emissions of the O3 precursors,
as contemplated in the Final Scoping for the 2009 draft SGEIS. The specific items relate to the
impact of these drilling operations on the SIP for O3 nonattainment purposes, as well as the
impact of cumulative emissions from both stationary and mobile sources.
The initial analysis lacked information on the regional emissions of the cumulative well drilling
activities in the whole of Marcellus Shale due to the lack of detail from industry on the likely
number of wells to be drilled annually and associated emissions. It was determined that
information and available data from similar shale development areas would not be suitable for a
calculation of these emissions due to a variety of factors. Thus, the Department requested this
emission information from industry and received the necessary data in the ALL/IOGA-NY
Information Report referenced previously and in a follow-up request for mileage data for on-road
truck traffic, as discussed below. The following narrative is intended to address concerns with
the regional emissions as these relate to ozone attainment and similar SIP issues.
Attainment Status and Current Air Quality
The most recent nonattainment areas that have been designated by EPA are those for the 1997 8hour ozone of 0.08 ppm (effectively 84 ppb), 1-hour ozone (0.12 ppm), annual and the 24-hour
PM2.5 national ambient air quality standards (NAAQS) of 15 and 35 µg/m3, respectively. In
March 2008, EPA promulgated a revision of the 8-hour ozone NAAQS by setting the standard as
0.075 ppm. Nonattainment areas for the new standard have not as yet been established due to
current efforts by EPA to reconsider a more restrictive NAAQS. EPA proposed its
reconsideration of the 2008 ozone NAAQS in January 2010 taking comment on lowering the
NAAQS to between 0.060 ppm and 0.070 ppm. EPA is expected to complete its reconsideration
in July 2011.
Ozone and particulate matter are two of six pollutants regulated under the CAA as “criteria
pollutants.” Data from Department monitors through 2010 indicate that monitored air
concentrations in the established nonattainment areas for O3 and PM2.5, as well as in the area
364

Comments of EPA Region 2 in letter from John Filippelli dated (12/30/09), pages 2-3.

Final SGEIS 2015, Page 6-170

 underlain by the Marcellus Shale, do not exceed the currently applicable NAAQS. In addition,
there are no areas in New York State that are classified as nonattainment for the remaining four
criteria pollutants: CO, lead, NO2 and SO2. EPA has recently promulgated revisions to the lead,
SO2 and NO2 NAAQS and has established new monitoring requirements for the lead and NO2
NAAQS, as well as new modeling requirements for the SO2 NAAQS. As a result of these new
requirements, the Department cannot yet determine whether ambient air quality complies with
these NAAQS values. However, the Department has proposed to EPA to classify the whole state
as “unclassifiable” with respect to the NO2 1-hour NAAQS and would have to submit a
recommendation to EPA on SO2 1-hour NAAQS. As data becomes available in the next few
years, the Department would assess the data and recommend to EPA designation of all areas in
the State as either attainment or nonattainment.
For O3, the Department has a wealth of information to compare against the current, but delayed,
2008 NAAQS and the range of the reconsidered NAAQS. Under the 2008 Ozone NAAQS,
current air quality in the Poughkeepsie-Newburgh, NYC and Jamestown metropolitan areas
would make these areas nonattainment. If the O3 NAAQS is set at the lower values proposed by
EPA, more areas of the state, including those in the Marcellus Shale play, would also be
nonattainment.
State Implementation Plans
The process by which states meet their obligations to improve air quality under the CAA, (for
example, the applicable NAAQS for criteria pollutants) is established in SIPs. A major
component of SIPs is the establishment of emission reduction requirements through the
promulgation of new regulatory requirements that work to achieve those reductions. The
combined effect of both state and federal requirements is to reduce the level of pollutants in the
air and bring each nonattainment area into attainment. These requirements, which apply to both
stationary and mobile sources, apply to both new and existing sources and are intended to limit
emissions to a level that would not result in an exceedance of a NAAQS, thus preserving the
attainment status of that area. In order to judge the potential effects of the projected O3 and
PM2.5 precursors in the Marcellus Shale on the SIP process, the Department has looked at the
level of these emissions relative to the baseline emissions and has come to certain conclusions on
the approach necessary to assure the goal of NAAQS compliance.

Final SGEIS 2015, Page 6-171

 Projected Emissions and Current/Potential Control Measures
The primary contributors (emission sources) to ozone pollution include those that emit
compounds known as “precursors” that result in the formation of ozone. The two most important
precursors are NOx and VOCs. PM2.5, another pollutant, is also directly emitted or formed from
precursors, such as ammonia, sulfur oxides and NOx. New York State and the federal
government have promulgated emission rules that apply to the sources of these pollutants in
order to protect air quality and prevent exceedances of the ambient air standards. In the case of
Marcellus Shale gas resource development, most emissions resulting from natural gas well
production activities are expected to come from the operation of internal combustion non-road
engines used in drilling and hydraulic fracturing, as well as engines that provide the power for
gas compression. Additional associated emissions occur with on road truck traffic used for
transportation of equipment and hydraulic fracturing fluid components.
Engine emissions have long been known to be a significant source of air pollution. As a result,
control requirements for these sources have been in place for many years, and have been updated
as engine technology and control methods have improved. Regulations and limits exist on both
the federal and state level, and effectively mitigate the effect of cumulative emissions on air
quality and the SIP. In New York, these measures include:
Particulate Matter
Locomotive Engines and Marine Compression-Ignition Engines Final Rule
Heavy Duty Diesel (2007) Engine Standard
Part 227: Stationary Combustion Installations

Sulfur
Federal Nonroad Diesel Rule
6 NYCRR Part 225: Fuel Composition and Use

NOx & VOCs
Part 217: Motor Vehicle Emissions
Part 218: Emission Standards for Motor Vehicles and Motor Vehicle Engines

Final SGEIS 2015, Page 6-172

 Part 248: New York State Diesel Emissions Reduction Act (DERA)
Small Spark-Ignition Engines
Federal On-board Vapor Recovery
In addition, to address mobile sources emissions which might occur due to diesel trucks idling
during the drilling operations, Subpart 217-3 of the New York State ECL specifically addresses
this issue by limiting heavy duty vehicle idling to less than five consecutive minutes when the
heavy duty vehicle is not in motion, except as otherwise permitted. Enforcement of this
regulation is performed by Department Conservation Officers and violation can result in a
substantial fine.
The above requirements for stationary sources apply statewide and not just in nonattainment
areas due to New York's status as part of an Ozone Transport Region state. This differs from
other areas such as the Barnett Shale project in which different standards apply inside and
outside of the Dallas/Fort Worth nonattainment area. Furthermore, additional requirements and
potential controls specific to the operations for the Marcellus Shale gas development were
addressed in Section 6.5.1 with respect to the well pad and the compressor station (e.g., NSPS
and NESHAPs requirements per 40 CFR 60, subpart ZZZZ and Part 63, subpart HH). Certain of
these measures restrict the emissions of O3 precursors to the maximum extent possible with
current control measure. In addition to the mandatory requirements that are in place as a result
of the above rules that directly affect the types of emissions that are expected with the
development of Marcellus Shale gas resources, there are a number of other recommended
measures that have been incorporated in previous sections to further reduce the emissions
associated with these operations and mitigate the cumulative impacts:
1. NOx emission controls (i.e., SCRs) and particulate traps on all diesel completion
equipment engines and on older tier drilling engines (see section 6.5.2);
2. Condensate and oil storage tanks should be equipped with vapor recovery units (see
section 6.5.1.5); and
3. The institution of a fugitive control program to prevent leaks from valves, tanks, lines and
other pressurized production operations and equipment (see section on greenhouse gas
remediation).

Final SGEIS 2015, Page 6-173

 Use of controls for excess gas releases, such as flares by REC should be implemented wherever
practicable (see section 6.5.2). In addition, other measures such as the use of more modern
equipment and electric motors instead of diesel engines, where available, are recommended.
Regional NOx and VOC Emission Estimates and Comparison to Estimates from another GasProducing Region
In order to assist the Department to develop a full understanding of the cumulative and regional
emissions and impacts of developing the gas resources of the Marcellus Shale, available
information from similar activities in other areas of the country has been reviewed. Notably,
certain information from the Barnett Shale formation of north Texas, which has undergone
extensive development of its oil and gas resources, was reviewed. The examination of the
development of the Barnett Shale could be instructive in developing an approach to emissions
control and mitigation efforts for the Marcellus Shale. As a result, the Department has examined
one commonly referenced study and source of information on the regulation and control of air
pollution from the development of the Barnett Shale.
First, the development of the gas resources of the Marcellus Shale, as with the Barnett Shale, not
be spatially distributed evenly across the geographic extent of the region, but would likely
concentrate in different areas at different times, depending on many factors and limitations,
including the price of natural gas at any given moment, the ease of drilling one area versus
another, and other legal/environmental constraints such as potential drilling in watersheds. As
such, industry cannot project at this time as to where impacts may concentrate regionally within
the Marcellus Shale region. Furthermore, well development would occur over time, wherein
initially there would be a “ramping-up” period, followed by a nominal “peak” drilling period,
and then a leveling off or dropping off period. Some of these factors and caveats are discussed
in the ALL/IOGA-NY Information Report.
Thus, the cumulative impacts of gas well drilling within the Marcellus Shale would also vary
depending on what point in time those impacts are measured as the development of the gas
resource expands over time. As an example of how well development proceeded in the Barnett
Shale, the Figure 6.12 indicates that gas production rose dramatically from 1998-2007. This
chart is being used by the Department for illustration purposes only to indicate the timeframes

Final SGEIS 2015, Page 6-174

 which might be involved in the Marcellus development and not as an actual indication of
expected development. Preliminary information from Pennsylvania indicates a more rapid
increase in gas well drilling and production.
Figure 6.12 - Barnett Shale Natural Gas Production Trend, 1998-2007 365

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

As drilling activities “ramp up,” the potential for greater environmental impacts likewise
increase. In estimating the air emissions of drilling in the Marcellus Shale, a worst case
(conservative) scenario of drilling and development was developed by IOGA-NY in response to
an information request from the Department. The estimates are provided in the ALL/IOGA-NY
Information Report. There are a number of caveats associated with these estimates so the
absolute magnitudes of emissions should be interpreted accordingly. However, an estimate of
worst case emissions are projected for the maximum likely number of wells (2216) to be drilled
in the Marcellus Shale for the “peak” year of operations and the emission factors and duration of
operations provided in the previous industry report (8/26/09) used in the modeling assessment.

365

Taken from Armendariz (SMU), 2009, p. 2.

Final SGEIS 2015, Page 6-175

 Some of the factors which were included in the estimates noted in the ALL/IOGA-NY
Information Report include:
•

Average emission rates for dry gas are used for every well for every phase of
development;

•

Maximum number of wells (both horizontal and vertical) in any year;

•

No credit is taken for any mitigation measures, permit emissions controls, or state and
federal regulatory requirements that are expected to reduce these estimates;

•

Drilling emissions are conservatively estimated at 25 days for the horizontal wells;

•

Heater emissions are included year-round in the production estimates; however, they
would be seasonal and would take place during the non-ozone season;

•

Off-pad compressor emissions are included in the production estimates; however, it is
anticipated that most well pads would not include a compressor;

•

No credit is taken for the rolling nature of development; i.e., that all wells would not be
drilled or completed at the same time, on the same pad;

•

No credit is taken for improved nonroad engine performance and resultant reduced NOx
emissions from the higher tier engines that would be phased in over time; and

•

No credit is taken for reduced emission completions which would significantly reduce
flaring and hence related NOx and VOC emissions.

The ALL/IOGA-NY Industry Information Report predicted the ozone precursor emissions
depicted in Table 6.21.
Table 6.21 - Predicted Ozone Precursor Emissions (Tpy)

Drilling

Completion Production

Totals

Horizontal - NOx

8,376

5,903

8,347

22,626

Vertical - NOx
Total NOx
Horizontal - VOC

409
8,785
352

345
6,248
846

927
9,274
5,377

1,681
24,307
6,575

Vertical - VOC

17

81

597

695

Total VOC

369

927

5,974

7,270

Final SGEIS 2015, Page 6-176

 It is seen that the total for NOx emissions for the horizontal wells is made up of 37% each from
drilling and production and 26% from completion. It is to be noted that for the latter emissions,
about half is associated with potential flaring operations. For VOC emissions for the horizontal
wells, the production sources dominate (82% of total). This is related to the dehydrator
emissions assumed to operate for a full year. It is also noted that the completion VOC emissions
are due to venting and flaring. Based on the above numbers, IOGA-NY concluded the impact
from the development of the Marcellus at a worst-case peak development rate would add 3.7% to
existing NOx emissions on a statewide basis. This was based on the 2002 baseline emission
inventory (EI) year used in New York’s 2007 SIP demonstration for the 8-hr ozone standard 366.
A more germane comparison would be to the “upstate” area emissions where Marcellus Shale
area is located. This comparative increase would be 10.4% for the same EI year. These upstate
area emissions exclude the nine-county New York ozone nonattainment area, as well as the
counties north and east of the area underlain by the Marcellus Shale.
The total NOx emissions increase from this example is deemed significant, but does not account
for the number of mitigation measures imposed and recommended in the revised SGEIS. For
example, the use of SCR control to reduce NOx emissions by 90% from the completion
equipment engines would reduce the completion emission by about half, while the minimization
of flaring operations by the use of REC would reduce the rest of these completion emissions
down to a very small value which would significantly reduced the relative percentage. In
addition, as noted by the IOGA-NY Information Report, the production sources used in the
estimates of NOx emissions are not likely to be used the full year and might not be even needed
at many wells. Furthermore, the estimated drilling emissions assume the maximum number of
days would be needed for each well and the associated use of older tier engines throughout the
area and over the long-term. Thus, the relative percent of Marcellus well drilling emissions to
the existing baseline is highly likely to be substantially less than the value above using the worst
case estimates.
The IOGA-NY also concluded that the total VOC emissions of 7,270 Tpy from the development
of the Marcellus Shale would add 0.54% to existing VOC emissions on a statewide basis. Using
366

Ozone Attainment Demonstration for NY Metro Area - Final Proposed Revision, Appendix B, pp. 10-11
http://www.dec.ny.gov/chemical/37012.html.

Final SGEIS 2015, Page 6-177

 the same baseline EI year as for NOx, the relative increase for VOCs would be 1.3%. This
increase is deemed small and also does not account for recommended mitigation measures such
as the minimization of gas venting by REC.
The above NOx and VOC relative emission comparisons do not include the contribution from the
on road truck traffic associated with Marcellus Shale operations and which had to be estimated
by the Department. The ALL/IOGA-NY Information Report included the light and heavy truck
trips, but not the associated average mileage which is necessary to calculate emissions. Thus, the
Department requested an average Vehicle Miles Traveled (VMT) for the two truck types and
ALL Consulting provided the data in a response letter. 367 Based on this information, the
Department projected the NOx and VOC emissions from on road truck as discussed in the next
subsection.
Effects of Increased Truck Traffic on Emissions
The initial modeling analysis did not address on-road mobile source emissions resulting from the
drilling operations, specifically, diesel truck emissions, except at the well pad. The Department
has analyzed the impact of increased emissions from truck traffic in the Marcellus Shale affected
counties. As part of this analysis, the Department utilized estimates of VMT provided by ALL
Consulting/IOGA-NY in response to the Department’s information request to determine the
environmental impacts of project related truck emissions. Industry estimated that the weighted
average one way VMT for both light and heavy duty trucks to be approximately 20 to 25 miles
for both horizontal and vertical wells.
The Department used these estimated average VMT for heavy-duty and light-duty trucks and the
number of truck trips contained in the ALL/IOGANY Information Report to calculate the total
additional VMT associated with drilling activities. These VMT, along with other existing New
York-specific data were input to the EPA’s Motor Vehicle Emission Simulator (MOVES) model
to estimate NOx and VOC emissions for the various truck activities. EPA Region 2 commented
on the SGEIS and requested the use of the MOVES model. As EPA’s approved mobile source
model, MOVES incorporates revised EPA emission factors for various on-road mobile source
activities and associated pollutants. The resulting emissions support a comparison of how traffic
367

All Consulting letter of March 16, 2011 from Daniel Arthur to Brad Gill of IOGANY.

Final SGEIS 2015, Page 6-178

 directly related to the drilling operations impacts the overall mobile emissions that normally
would occur throughout the Marcellus Shale drilling area.
The estimated emissions of NOx and VOCs (and well as other pollutants) that result from the
additional light and heavy duty truck traffic expected with Marcellus well drilling are detailed in
Appendix 18C. The emissions for the counties in the area underlain by the Marcellus Shale are
presented for both the existing baseline activities as well as those associated with the drilling
activities. In addition, the absolute and percent differences which represent the additional truck
emissions are shown.
The results show that the total NOx and VOC emissions are estimated to be 687 and 70 Tpy,
respectively, and are expected to increase the existing baseline emissions by 0.66% and 0.17%.
The maximum increase for any pollutant is 0.8%. These increases are deemed very small. In
addition, the traffic related NOx and VOC emissions are noted to be small fractions of the
corresponding increased emissions due to other activities associated with gas drilling, as
summarized in the last subsection. For example, the traffic related NOx emissions are about 3%
of the total NOx emissions given in the above mentioned summary table. A simple estimate of
traffic related emissions of PM2.5 per pad, using the total emissions and the number of
maximum wells is shown in Appendix 18C to be 0.01 Tpy which is comparable to the previously
estimated pad specific PM2.5 emissions noted in the modeling section which was estimated with
the EPA MOBILE6 model.
Based on these results, the Department concluded that the estimated truck related emissions
would be captured during the standard development of the mobile inventories for the SIP. These
estimates are also noted to be within the variability associated with the MOVES model inputs.
Comparison to Barnett Shale Emission
A referenced report 368 on the Barnett Shale oil and gas production prepared by Southern
Methodist University (SMU) for the Environmental Defense Fund (EDF) has been noted as a
source of emission calculation schemes and resultant regional emissions for that region of Texas.
In terms of the projected emissions of NOx and VOCs, while caution should be exercised in
368

Armendariz (SMU), 2009.

Final SGEIS 2015, Page 6-179

 making comparisons between the two areas, a picture of emissions from the Barnett Shale may
be a useful point of departure for understanding the magnitude and types of emissions to be
expected with the development of the Marcellus Shale. The Department has not undertaken a
review of the rationale or the methodologies used in the SMU report and is also aware of the
Texas Commission on Environmental Quality (TCEQ)’s critique of the report. 369 Since the
report, TCEQ has undertaken a detailed emission inventory development program to better
characterize the sources and to quantify the corresponding emissions.
For the present purposes, it is necessary to provide a brief outline of the potential differences
between the gas development activities and associated sources between the Barnett report and
the industry projections for the Marcellus Shale. For example, the SMU report provided the
relative amount of emissions from different source categories and corresponding NOx and VOC
emissions, as presented in Table 6.22 below. For comparison, the industry-provided emissions
summarized above are 66.7 and 20 tons per day (Tpd) for NOx and VOCs, respectively.
However, the latter do not include some of the sources tabulated in the SMU report such that a
straightforward comparison is not possible. Nonetheless, the SMU report notes that the largest
group of VOC sources was condensate tank vents. Table 6.22 also indicates that fugitive
emissions from production operations have a significant contribution to the VOC totals.

Table 6.22 - Barnett Shale Annual Average Emissions from All Sources 370

Source
Compressor Engine Exhausts
Condensate And Oil Tanks
Production Fugitives
Well Drilling and Completion
Gas Processing
Transmission Fugitives
Total Daily Emissions (Tpd)

370

2007 Pollutants,
Tons per day(Tpd)
NOx
VOC
51
15
0
19
0
17
5.5
21
0
10
0
18
56
100

Adapted from Armendariz (SMU), 2009 p. 24.

Final SGEIS 2015, Page 6-180

2009 Pollutants,
Tons per day (Tpd)
NOx
VOC
46
19
0
30
0
26
5.5
21
0
15
0
28
51
139

 These might explain the differences in VOC emissions in that industry does not expect to use
condensate tanks in New York due to the dry gas encountered in the Marcellus Shale. In
addition, these tank emissions, if used, would be controlled by vapor recovery systems as noted
in Section 6.5.2. In addition, all efforts would need to be made by industry to minimize fugitive
emissions as recommended in the greenhouse gas emission mitigations section which would
reduce concomitant VOC emissions.
The SMU report also provides charts which compare the total NOx plus VOC emissions from the
Barnett oil and gas sources to totals from on-road source categories in the Dallas-Fort Worth
area, concluding that the former are larger than the on road emissions in some respects.
However, these comparisons are not transferrable to the Marcellus Shale situation in New York
not only because VOC emissions dominate these totals, but also since the comparisons are to a
specific regional mix of sources not representative of the situation to be encountered in New
York. On face value, the absolute magnitude of these total emissions is much larger than even a
“worst-case” scenario for the Marcellus Shale.
Again, no firm predictions or projections can be made at this time as to where or when gas
drilling impacts may concentrate regionally within the Marcellus Shale, but the Department
would continue to avail itself of the knowledge and lessons learned from similar regional shale
gas development projects in other parts of the country.
Further Discussions and Conclusions
There are stringent regulatory controls already in place for controlling emissions from stationary
and mobile sources in New York. With additional required emission controls recommended in
the revised SGEIS for the operations associated with drilling activities, coupled with potential
deployment of further emission controls arising from upcoming O3 SIP implementation actions,
the Department is confident that the effect of cumulative impacts from the development of gas
resources in the multi-county area underlain by the Marcellus Shale would be adequately
mitigated. Thus, the Department would be able to continue to meet attainment goals that it has
set forth in cooperation with EPA. In addition to eliminating the use of uncertified and certain

Final SGEIS 2015, Page 6-181

 older tier engines and requiring specific mitigation measures to substantially reduce PM and NOx
emissions in order to meet NAAQS, the Department would review the need for certain additional
mitigation prior to finalizing the SGEIS. As part of the information, the Department is seeking
from industry an implementation timeline to expedite the use of higher tier drilling and
completion equipment engines in New York. Furthermore, as the Department readies for the
soon to be announced revised O3 NAAQS and potential revisions to the PM2.5 NAAQS, the
need for imposing further controls on drilling engines not being currently required to be
equipped with PM traps and SCR would be revisited. If it is determined that further mitigation is
necessary, further controls would be required. The review would consider the relatively high
contribution to regional emissions of NOx from the drilling engines and result from regional
modeling of O3 precursors which would be performed in preparation of the Ozone SIP.
Regional photochemical air quality modeling is a standard tool used to project the consequences
of regional emission strategies for the SIP. The application of these models is very time and
resource intensive. For example, these require detailed information on the spatial distribution of
the emissions of various species of pollutants from not only New York sources, but from those in
neighboring states in order to properly determine impacts of NOx and VOC precursor emissions
on regional O3 levels. At present, detailed necessary information for the proper applications of
this modeling exercise is lacking. However, as part of its commitment to the EPA, and in
cooperation with the Ozone Transport Commission to consider future year emission strategies
for the Ozone SIP, the Department would include the emissions from Marcellus Shale operations
in subsequent SIP modeling scenarios. As such, properly quantified emissions specifically
resulting from Marcellus Shale operations would be included in future SIP inventories to the
extent that the information becomes available. Interim to this detailed modeling, the Department
would perform a screening level regional modeling exercise by adding the projected emissions
associated with New York’s portion of the Marcellus Shale drilling to the baseline inventory
which is currently being finalized. This modeling would guide the Department’s finalization of
the SGEIS. In addition to the availability of the regional modeling results, the Department has
recommended that a monitoring program be undertaken by industry to address both regional and
local air quality concerns as discussed in the next section.

Final SGEIS 2015, Page 6-182

 6.5.4

Air Quality Monitoring Requirements for Marcellus Shale Activities

In order to fully address potential for adverse air quality impacts beyond those analyzed in the
SGEIS relate to associated activities which are either not fully known at this time or verifiable by
the assessments to date, it has been determined that a monitoring program would be undertaken.
For example, the consequences of the increased regional NOx and VOC emissions on the
resultant levels of ozone and PM2.5 cannot be fully addressed by only modeling at this stage due
to the lack of detail on the distribution of the wells and compressor stations. In addition, any
potential emissions of certain VOCs at the well sites due to fugitive emissions, including
possible endogenous level, and from the drilling and gas processing equipment at the compressor
station (e.g. glycol dehydrators) are not fully quantifiable. Thus, it has been determined that an
air monitoring plan is necessary to address these regional concerns as well as to verify the localscale impact of emissions from the three phases of gas field development: drilling, completion
and production. The monitoring plan discussed herein is determined to be the level of effort
necessary to assure that the overall activities of the gas drilling in the Marcellus Shale would not
cause adverse regional or local air quality impacts. The monitoring is an integral component of
the requirements for industry to undertake to satisfy the SEQRA findings of acceptable air
quality levels.
Based on the results from the Department’s assessments of gas production emissions, and in
consideration of the well permitting approach and the modeling analysis, an air monitoring plan
has been developed to address the level of effort necessary to determine and distinguish both
background and drilling related concentrations of pertinent pollutants. In addition, a review of
previous monitoring activities for shale drilling conducted by the TCEQ 371 and the PADEP 372
was undertaken to better characterize the monitoring needs and instrumentation. The approach
selected as best suited for monitoring for New York Marcellus Shale activities combines a
regional and local scale monitoring effort aimed at different aspects of emission impact
characterization. These two efforts are as follows:

371

See: http://www.bseec.org/content/tceq-full-review-armendariz-study-barnett-shale-pollution.

372

See: http://www.dep.state.pa.us/dep/deputate/airwaste/aq/toxics/toxics.htm.

Final SGEIS 2015, Page 6-183

 1) Regional level monitoring: In order to assess the impact of regional emissions of
precursors including VOCs and NOx, monitoring for O3 and PM2.5 would need to be
conducted at two locations. One would be a “background” site and another would need
to be placed at a downwind location sited to reflect the likely impact area from the
atmospheric transport and conversion of the precursors into secondary pollutants. These
would enhance the current Department O3 monitoring in the area. These sites would also
need to be equipped with air toxics monitors so that pollutant levels can be compared to
each other and to other existing sites; and
2) Near-field/local scale monitoring at various locations in the Marcellus Shale: This
monitoring can be intermittent but would be carried out in areas expected to be directly
impacted by one or more wells and compressor stations. The data from this monitoring
effort would be used to assess the significance of the various known drilling related
activities and to identify specific pollutants that may pose a concern. In addition,
possible fugitive emissions of certain VOCs should be monitored to locate and mitigate
emissions, beyond those necessary for worker safety purposes. The Department has
identified specific well drilling activities and pollutants which have been found to be
related to these activities and recommends that these are included in the near-field
monitoring program See Table 6.23.
Table 6.23 - Near-Field Pollutants of Concern for Inclusion in the
Near-Field Monitoring Program (New July 2011)

Well Pad and Related Activity
Drilling and Completing (completion equipment)

Pollutants of Concern
1-Hour NO2 and 24-hour PM2.5

Engines
Gas venting (could be potentially mitigated by

BTEX, formaldehyde, H2S or another odorant.

REC)
Glycol dehydrator and condensate tanks at either
the well pad or at the compressor station (if wet
gas is present)
Leaks and fugitives

BTEX, benzene, and formaldehyde.
Methane and VOC emissions

The near-field local scale monitoring is expected to be performed periodically with field
campaigns typically lasting a few days when activities are occurring at the well pad and when the
compressor station is operational and operating near maximum gas flow conditions. Since the
scope of gas related emissions from one area of operation to another is limited, it is anticipated
that after a few intensive near-field monitoring campaigns, adequate and representative data
would be gathered to understand the potential impacts of the various phases of gas drilling and
production. At that point, the level of effort and the further need for the short term monitoring

Final SGEIS 2015, Page 6-184

 would be evaluated. In addition to the near-field monitoring, it is anticipated that a similar level
of short term monitoring would be conducted on a limited basis at a nearby residential location
or in a representative community setting to determine the actual exposure to the public.
However, based on the results from the TCEQ and PADEP monitoring, the potential for finding
relatively higher concentrations would likely be in close proximity to the well pad and
compressor station.
It is expected that the cost and implementation of this monitoring would be the responsibility of
industry. To carry out this monitoring plan, a specific set of monitoring equipment and
procedures would be necessary. Some of these deviate from the “traditional” compliance
oriented monitoring plans; for example, due to the relatively short term and intensive monitoring
required at various locations of activities, the suggested approach would be to operate a mobile
equipped unit. Department monitoring staff has longstanding expertise in conducting this type of
monitoring over the last two decades. The most recent local-scale monitoring project carried out
by the Department was the Tonawanda Community Air Quality Monitoring project.
As an alternative to industry implementing this monitoring plan in a repetitive company by
company stepwise fashion as gas development progresses, it is the Department ’s preference that
the monitoring be undertaken by the Department’s Division of Air Resources monitoring staff.
However, this alternative cannot be carried out with current Department staff or equipment and
would only be possible with additional staff and equipment resources. This alternative is
preferred from a number of standpoints, including:
1) Overall program cost would be reduced because each operator would not be responsible
for their own monitoring program. Even if the operators are able to hire a common
consultant, there would be complexities in allocation the work to various locations;
2) The Department would not have to “oversee” contractor work hired either by industry or
by the Department;
3) The timing and production of data analysis would be simplified and reports would be
under the Department’s control;
4) The Department can utilize certain existing monitor sites for the regional monitoring
program;

Final SGEIS 2015, Page 6-185

 5) The central coordination would minimize the overall costs of the monitoring; and
6) The Department would have the ability to monitor near the compressor stations which
might not be within the control of the drilling operators.
If the Department was to receive the necessary funding and staff to conduct the monitoring, the
following table identifies some of the specifics associated with the expected level of monitoring.

Final SGEIS 2015, Page 6-186

 Table 6.24 - Department Air Quality Monitoring Requirements for Marcellus Shale Activities (New July 2011)

Monitoring Parameters

Purpose of Monitoring

Proposed Scheme and Instrumentation Needs.

To assess the impact of regional
VOC and NOx emissions on
Ozone and PM2.5 levels.

Add a Department monitoring trailer to a new site in
Binghamton, plus add toxics at existing Pinnacle site and the
new site.

Local/near field
monitoring for BTEX, methane,
formaldehyde, sulfur (plus O3,
PM2.5 and NO2)

To assess impacts close-by to
well pads, compressor stations
and associated equipment (e.g.
glycol dehydrator, condensate
tanks). Also, limited follow- up
in nearby communities.

Purpose-built vehicle with generators as a mobile laboratory. A
less desirable alternative is a “stationary” trailer which would
need days for initialization.

Intermittent methane and VOC
leaks from sources (e.g. fugitive)

To detect and initiate company
mitigation of fugitive leaks.

Forward Looking Infrared (FLIR) cameras- one for routine
inspections, second to respond to complaints.

“Saturated” BTEX and other VOC
species monitoring

To verify the spatial extent of
the mobile monitoring results.

Manually operated canister samplers which can be analyzed for
1 to 24-hour concentrations of various toxics.

Regional scale
O3, PM2.5, NO2
and add toxics.

Final SGEIS 2015, Page 6-187

 This monitoring would be the minimum level of effort necessary to properly characterize the air
quality in the affected areas for the pollutants which have been identified as possibly requiring
mitigation measures or having an effect due to regional emissions. In developing the monitoring
approach, Department staff has reviewed the results of the monitoring conducted by TCEQ and
PADEP to learn from their experiences, as well as from our own toxics monitoring experiences.
To that end, it was determined that a mobile unit with the necessary equipment which would best
perform the monitoring for both near-field and representative community based areas. The use
of an open path Fourier-transform Infrared (FTIR) spectroscopy used in the PADEP study was
evaluated, but deemed unnecessary due to the fact that the mobile unit would be detecting the
same pollutants at lower more health relevant detection levels. To overcome the potential
concern with spatial representativeness of the near-field monitoring program, the Department
recommends augmenting the mobile vehicle with manually placed canisters which could be used
on a limited basis to provide a wider areal coverage during the various activities and as a
secondary confirmation of the mobile unit results.
The monitoring plan outlined above would be used to address public concerns with the actual
pollutant levels in the areas undergoing drilling activities. In addition, it could assist in the
identification of the level of conservatism used in the emission estimates for the well pads, the
Marcellus area region, and modeling analysis which have been noted as concerns.
6.5.5

Permitting Approach to the Well Pad and Compressor Station Operations

The discussions in subsection 6.5.1.8 of the regulatory applicability section outline the approach
which the Department has determined is in line with regulatory permitting requirements and
which best address the issues surrounding the air permitting of the three phases of gas drilling,
completion and production. The use of the compressor station air permit application process to
determine the regulatory disposition and necessary control measures on a case-by-case basis is in
keeping with the approach taken throughout the country, as affirmed by EPA in a number of
instances. This review process would allow the proper determination of the applicable
regulations to both the compressor station and all associated well operations in defining the
facility to which the requirements should apply. In concert with the strict operational restrictions
determined in the modeling section necessary for the drilling and completion equipment engines,
the self-imposed operational and emission limits put forth by industry would assure compliance

Final SGEIS 2015, Page 6-188

 with all applicable standards. To further assure that these restrictions are adhered to for all well
operations, a set of necessary conditions identified in Section 7.5.3 and Appendix 10 will be
included in DMN well permits.
DMN Well Drilling Permit Process Requirements
Based on industry’s self-imposed limitations on operations and the Department’s determination
of conditions necessary to avoid or mitigate adverse air quality impacts from the well drilling,
completion and production operations, mitigation noted in Chapter 7 would be imposed in the
well permitting process.
6.6

Greenhouse Gas Emissions

On July 15, 2009, the Department’s Office of Air, Energy and Climate issued its Guide for
Assessing Energy Use and Greenhouse Gas Emissions in an Environmental Impact Statement. 373
The policy reflected in the guide is used by Department staff in reviewing an environmental
impact statement (EIS) when the Department is the lead agency under SEQRA and energy use or
GHG emissions have been identified as significant in a positive declaration, or as a result of
scoping, and, therefore, are required to be discussed in an EIS. Following is an assessment of
potential GHG emissions for the exploration and development of the Marcellus Shale and other
low-permeability gas reservoirs using high-volume hydraulic fracturing.
SEQRA requires that lead agencies identify and assess adverse environmental impacts, and then
mitigate or reduce such impacts to the extent they are found to be significant. Consistent with
this requirement, SEQRA can be used to identify and assess climate change impacts, as well as
the steps to minimize the emissions of GHGs that cause climate change. Many measures that
would minimize emissions of GHGs would also advance other long-established State policy
goals, such as energy efficiency and conservation; the use of renewable energy technologies;
waste reduction and recycling; and smart and sustainable economic growth. The Guide for
Assessing Energy Use and Greenhouse Gas Emissions in an Environmental Impact Statement is

373

http://www.dec.ny.gov/docs/administration_pdf/eisghgpolicy.pdf.

Final SGEIS 2015, Page 6-189

 not the only State policy or initiative to promote these goals; instead, it furthers these goals by
providing for consideration of energy conservation and GHG emissions within EIS reviews. 374
The goal of this analysis is to characterize and present an estimate of GHG emissions for the
siting, drilling and completion of 1) single vertical well, 2) single horizontal well, 3) four-well
pad (i.e., four horizontal wells at the same site), and respective first-year and post first-year
emissions of CO2, and other relative GHGs, as both short tons and as carbon dioxide equivalents
(CO2e) expressed in short tons, for exploration and development of the Marcellus Shale and
other low-permeability gas reservoirs using high volume hydraulic fracturing. In addition, the
major contributors of GHGs are to be identified and potential mitigation measures offered.
6.6.1

Greenhouse Gases

The two most abundant gases in the atmosphere, nitrogen (comprising 78% of the dry
atmosphere) and oxygen (comprising 21%), exert almost no greenhouse effect. Instead, the
greenhouse effect comes from molecules that are more complex and much less common. Water
vapor is the most important greenhouse gas, and CO2 is the second-most important one. 375
Human activities result in emissions of four principal GHGs: CO2, methane (CH4), nitrous oxide
(N2O) and the halocarbons (a group of gases containing fluorine, chlorine and bromine). These
gases accumulate in the atmosphere, causing concentrations to increase with time. Many human
activities contribute GHGs to the atmosphere. 376 Whenever fossil fuel (coal, oil or gas) burns,
CO2 is released to the air. Other processes generate CH4, N2O and halocarbons and other GHGs
that are less abundant than CO2, but even better at retaining heat. 377
6.6.2

Emissions from Oil and Gas Operations

GHG emissions from oil and gas operations are typically categorized into 1) vented emissions, 2)
combustion emissions and 3) fugitive emissions. Below is a description of each type of
emission. For the noted emission types, no distinction is made between direct and indirect
emissions in this analysis. Further, this GHG discussion is focused on CO2 and CH4 emissions
374

http://www.dec.ny.gov/docs/administration_pdf/eisghgpolicy.pdf.

375

http://ipcc-wg1.ucar.edu/wg1/Report/AR4WG1_Print_FAQs.pdf.

376

http://ipcc-wg1.ucar.edu/wg1/Report/AR4WG1_Print_FAQs.pdf.

377

http://www.dec.ny.gov/energy/44992.html.

Final SGEIS 2015, Page 6-190

 as these are the most prevalent GHGs emitted from oil and gas industry operations, including
expected exploration and development of the Marcellus Shale and other low-permeability gas
reservoirs using high volume hydraulic fracturing. Virtually all companies within the industry
would be expected to have emissions of CO2 - and, to a lesser extent, CH4 and N2O - since these
gases are produced through combustion. Both CH4 and CO2 are also part of the materials
processed by the industry as they are produced in varying quantities, from oil and gas wells.
Because the quantities of N2O produced through combustion are quite small compared to the
amount of CO2 produced, CO2 and CH4 are the predominant oil and gas industry GHGs. 378
6.6.2.1 Vented Emissions
Vented sources are defined as releases resulting from normal operations. Vented emissions of
CH4 can result from the venting of natural gas encountered during drilling operations, flow from
the flare stack during the initial stage of flowback, pneumatic device vents, dehydrator operation,
and compressor start-ups and blowdowns. Oil and natural gas operations are the largest humanmade source of CH4 emissions in the United States and the second largest human-made source of
CH4 emissions globally. Given methane’s role as both a potent greenhouse gas and clean energy
source, reducing these emissions can have significant environmental and economic benefits.
Efforts to reduce CH4 emissions not only conserve natural gas resources but also generate
additional revenues, increase operational efficiency, and make positive contributions to the
global environment. 379
6.6.2.2 Combustion Emissions
Combustion emissions can result from stationary sources (e.g., engines for drilling, hydraulic
fracturing and natural gas compression), mobile sources and flares. Carbon dioxide, CH4, and
N2O are produced and/or emitted as a result of hydrocarbon combustion. Carbon dioxide
emissions result from the oxidation of the hydrocarbons during combustion. Nearly all of the
fuel carbon is converted to CO2 during the combustion process, and this conversion is relatively
independent of the fuel or firing configuration. Methane emissions may result due to incomplete

378

IPIECA and API, December 2003, p. 5-2.

379

http://www.epa.gov/gasstar/documents/ngstar_mktg-factsheet.pdf.

Final SGEIS 2015, Page 6-191

 combustion of the fuel gas, which is emitted as unburned CH4. Overall, CH4 and N2O emissions
from combustion sources are significantly less than CO2 emissions. 380
6.6.2.3 Fugitive Emissions
Fugitive emissions are defined as unintentional gas leaks to the atmosphere and pose several
challenges for quantification since they are typically invisible, odorless and not audible, and
often go unnoticed. Examples of fugitive emissions include CH4 leaks from flanges, tube
fittings, valve stem packing, open-ended lines, compressor seals, and pressure relief valve seats.
Three typical ways to quantify fugitive emissions at a natural gas industry site are 1) facility
level emission factors, 2) component level emission factors paired with component counts, and
3) measurement studies. 381 In the context of GHG emissions, fugitive sources within the
upstream segment of the oil and gas industry are of concern mainly due to the high concentration
of CH4 in many gaseous streams, as well as the presence of CO2 in some streams. However,
relative to combustion and process emissions, fugitive CH4 and CO2 contributions are
insignificant. 382
6.6.3

Emissions Source Characterization

Emissions of CO2 and CH4 occur at many stages of the drilling, completion and production
phases, and can be dependent upon technologies applied and practices employed. Considerable
research – sponsored by the API, the Gas Research Institute (GRI) and the EPA – has been
directed towards developing relatively robust emissions estimates at the national level. 383 The
analytical techniques and emissions factors, and mitigation measures, developed by the these
agencies were used to evaluate GHG emissions from activities necessary for the exploration and
development of the Marcellus Shale and other low-permeability gas reservoirs using highvolume hydraulic fracturing.
In 2009, NYSERDA contracted ICF International (ICF) to assist with supporting studies for the
development of the SGEIS. ICF’s work included preparation of a technical analysis of potential
impacts to air in the form of a report finalized in August 2009. 384 The report, which includes a
380

API 2004; amended 2005. p 4-1.
ICF Task 2, 2009, p. 21.
382
IPIECA and API, December 2003., p. 5-6.
383
New Mexico Climate Change Advisory Group, November 2006, , pp. D-35.
384
ICF Task 2, 2009.
381

Final SGEIS 2015, Page 6-192

 discussion on GHGs, provided the basis for the following in-depth analysis of potential GHGs
from the subject activity. ICF’s referenced study identifies drilling, completion and production
operations and equipment that contribute to GHG emission and provides corresponding emission
rates, and this information facilitated the following analysis by identifying system components
on an operational basis. As such, wellsite operations considered in the SGEIS were divided into
the following phases for this GHG analysis:
•

Drilling Rig Mobilization, Site Preparation and Demobilization;

•

Completion Rig Mobilization and Demobilization;

•

Well Drilling;

•

Well Completion (includes hydraulic fracturing and flowback); and

•

Well Production.

Transport of materials and equipment is an integral component of the oil and gas industry.
Simply stated, a well cannot be drilled, completed or produced without GHGs being emitted
from mobile sources. The estimated required truck trips per well and corresponding fuel usage
for the below noted phases requiring transportation, except well production, were provided by
industry. 385
Drilling Rig Mobilization, Site Preparation and Demobilization
Drill Pad and Road Construction Equipment
Drilling Rig
Drilling Fluid and Materials
Drilling Equipment (casing, drill pipe, etc.)
Completion Rig Mobilization and Demobilization
Completion Rig

385

ALL Consulting, 2011, Exhibits 19B, 20B.

Final SGEIS 2015, Page 6-193

 Well Completion
Completion Fluid and Materials
Completion Equipment (pipe, wellhead)
Hydraulic Fracturing Equipment (pump trucks, tanks)
Hydraulic Fracturing Water
Hydraulic Fracturing Sand
Flow Back Water Removal
Well Production 386
Production Equipment (5 – 10 Truckloads)
Mileage estimates for both light duty and heavy duty trucks were used to determine total fuel
usage associated with site preparation and rig mobilizations, well completion and well
production activities. As further discussed below, when actual or estimated fuel use data was not
available, VMT formed the basis for estimating CO2 emissions.
Three distinct types of well projects were evaluated for GHG emissions as follows:
•

Single-Well Vertical Project;

•

Single-Well Horizontal Project; and

•

Four -Well Pad (i.e., four horizontal wells at the same site).

For rig and equipment mobilizations for each of the project types noted above, it was assumed
that all work involving the same activity would be finished before commencing a different
activity. In other words, the site would be prepared and the drilling rig mobilized, then all wells
(i.e., one or four) would be drilled, followed by the completion of all wells (i.e., one or four) and
subsequent production of all wells (i.e., one or four). A number of operators have indicated to
the Department that activities on multi-well pads would be conducted sequentially, whenever
possible, to realize the greatest efficiency but the actual order of work events and number of
wells on a given pad may vary. Nevertheless, four wells was the number of wells selected for

386

NTC Consultants. Impacts on Community Character of Horizontal Drilling and High Volume Hydraulic Fracturing in the
Marcellus Shale and Other Low-Permeability Gas Reservoirs, September 2009.

Final SGEIS 2015, Page 6-194

 the multi-well pad GHG analysis because industry indicated that number would be the maximum
number of wells drilled at the same site in any 12 consecutive months.
Stationary engines and equipment emit CO2 and/or CH4 during drilling and completion
operations. However, most are not typically operating at their full load every hour of each day
while on location. For example, certain engines may be shut down completely or operating at a
very low load during bit trips, geophysical logging or the running of casing strings.
Consequently, for the purpose of this analysis and as noted in Table 6.25 and Table 6.26 below,
it was assumed that engines and equipment for drilling and completion operations generally
operate at full load for 50% of their time on location. Exceptions to this included engines and
equipment used for hydraulic fracturing and flaring operations. Instead of relying on an assumed
time frame for operation for the many engines that drive the high-pressure high-volume pumps
used for hydraulic fracturing, an average of the fuel usage from eight Marcellus Shale hydraulic
fracturing jobs performed on horizontally drilled wells in neighboring Pennsylvania and West
Virginia was used. 387 In addition, flaring operations and associated equipment were assumed to
be operating at 100% for the entire estimated flaring period.

Table 6.25 - Assumed Drilling & Completion Time Frames for Single Vertical Well (New July 2011)

Estimated Duration
(days / hrs.)

Operation
Well Drilling
Completion
Flaring

13 / 312
¼ / 6 (hydraulic fracturing)
1 / 24 (rig)
3 / 72

Assumed Full Load Operational
Duration for Related Equipment
(days / hrs.)
6½ / 156
¼ / 6 (hydraulic fracturing)
½ / 12 (rig)
3 / 72

Table 6.26 - Assumed Drilling & Completion Time Frames for Single Horizontal Well (Updated July 2011)

Estimated Duration
(days / hrs.)

Operation
Well Drilling
Completion
Flaring

387

25 / 600
2 / 48 (hydraulic fracturing)
2 / 48 (rig)
3 / 72

Assumed Full Load Operational
Duration for Related Equipment
(days / hrs.)
12½ / 300
2 / 48 (hydraulic fracturing)
1 / 24 (rig)
3 / 72

ALL Consulting, 2009, Table 11, p. 10.

Final SGEIS 2015, Page 6-195

 Stationary engines and equipment also emit CO2 and/or CH4 during production operations. In
contrast to drilling and completion operations, production equipment generally operates around
the clock (i.e., 8,760 hours per year) except for scheduled or intermittent shutdowns.
6.6.4

Emission Rates

The primary reference for emission rates for stationary production equipment considered in this
analysis is the GRI’s Methane Emissions from the Natural Gas Industry. Table GHG-1
“Emission Rates for Well Pad” in Appendix 19, Part A shows greenhouse gas (GHG) emission
rates for associated equipment used during natural gas well production operations. Table GHG-1
was adapted from an analysis of potential impacts to air performed in 2009 by ICF International
under contract to NYSERDA. GHG emission rates for flaring during the completion phase were
also obtained from the ICF International study. The emission factors in the table are typically
listed in units of pounds emitted per hour for each piece of equipment or are based on gas
throughput. The emissions rates specified in the table were used to determine the annual
emissions in tons for each stationary source, except for engines used for rig and hydraulic
fracturing engines, using the below equation. The Activity Factor represents the number of
pieces of equipment or occurrences.
Emissions (tons/yr.) = Emissions Factor (lbs./hr) × Duration (yr.) ×(8,760 hrs/yr.) × (1 US short ton/2,000 lbs) × Activity Factor

A material balance approach based on fuel usage and fuel carbon analysis, assuming complete
combustion (i.e., 100% of the fuel carbon combusts to form CO2), is the preferred technique for
estimating CO2 emissions from stationary combustion engines. 388 This approach was used for
the engines required for conducting drilling and hydraulic fracturing operations. Actual fuel
usage, such as the volume of fuel needed to perform hydraulic fracturing, was used where
available to determine CO2 emissions. For emission sources where actual fuel usage data was
not available, estimates were made based on the type and use of the engines needed to perform
the work. For GHG emission from mobile sources, such as trucks used to transport equipment
and materials, where fuel use data was not available VMT was used to estimate fuel usage. The
calculated fuel used was then used to determine estimated CO2 emissions from the mobile

388

API, 2004; amended 2005., p. 4-3.

Final SGEIS 2015, Page 6-196

 sources. A sample calculation showing this methodology for determining combustion emissions
(CO2) from mobile sources is included as Appendix 19, Part B.
Carbon dioxide and CH4 emissions, the focus of this analysis, are produced from the flaring of
natural gas during the well completion phase. Emission rates and calculations from the flaring of
natural gas are presented in the previously mentioned 2009 ICF International report. In that
report, it was determined that approximately 576 tons of CO2 and 4.1 tons of CH4 are emitted
each day for a well being flared at a rate of 10 MMcf/d. ICF International’s calculations
assumed that 2% of the gas by volume goes uncombusted. ICF International relied on an
average composition of Marcellus Shale gas to perform its emissions calculations.
6.6.5

Drilling Rig Mobilization, Site Preparation and Demobilization

Transportation combustion sources are the engines that provide motive power for vehicles used
as part of wellsite operations. Transportation sources may include vehicles such as cars and
trucks used for work-related personnel transport, as well as tanker trucks and flatbed trucks used
to haul equipment and supplies. Light-duty and heavy-duty vehicles use is accounted for and
differentiated in this analysis. 389 The fossil fuel-fired internal combustion engines used in
transportation are a significant source of CO2 emissions. Small quantities of CH4 and N2O are
also emitted based on fuel composition, combustion conditions, and post-combustion control
technology. Estimating emissions from mobile sources is complex, requiring detailed
information on the types of mobile sources, fuel types, vehicle fleet age, maintenance
procedures, operating conditions and frequency, emissions controls, and fuel consumption. The
EPA has developed a software model, MOBILE Vehicle Emissions Modeling Software, that
accounts for these factors in calculating exhaust emissions (CO2, HC, CO, NOx, particulate
matter, and toxics) for gasoline and diesel fueled vehicles. The preferred approach for estimating
CH4 and N2O emissions from mobile sources is to assume that these emissions are negligible
compared to CO2. 390
An alternative to using modeling software for determining CO2 emissions for general
characterization is to estimate GHG emissions using VMT, which includes a determination of
389

ALL Consulting, 2011, Exhibits 19B, 20B.

390

API, 2004; amended 2005, pp. 4-32, 4-33.

Final SGEIS 2015, Page 6-197

 estimated fuel usage, or use a fuel usage estimate if available. These methodologies were used to
calculate the tons of CO2 emissions from mobile sources related to the subject activity. A
sample CO2 emissions calculation using fuel consumption is shown in Appendix 19, Part B.
Table GHG-2 in Appendix 19, Part A includes CO2 emission estimates for transporting the
equipment necessary for constructing the access road and well pad, and moving the drilling rig to
and from the well site. For horizontal wells, Table GHG-2 assumes that the same rig stays on
location and drills both the vertical and lateral portions of a well.
As previously mentioned, because all activities are assumed to be performed sequentially
requiring a single rig move, the GHG emissions presented in Table GHG-2 are representative of
either a one-well project or four-well pad. As shown in the table, approximately 15 tons of CO2
emissions are expected from a mobilization of the drilling rig, including site preparation. Site
preparation for a single vertical well would be less due to a smaller pad size but for
simplification site preparation is assumed the same for all well scenarios considered. The
calculated CO2 emissions shown in this table and all other tables included in this analysis have
been rounded up to the next whole number.
6.6.6

Completion Rig Mobilization and Demobilization

Table GHG-3 in Appendix 19, Part A includes CO2 emission estimates for transporting the
completion rig to and from the wellsite. As shown in the table, approximately 4 tons of CO2
emissions may be generated from a mobilization of the completion rig. For simplification,
transportation associated with rig mobilization for the completion rig was assumed to be the
same as that for the drilling rig. It is acknowledged that this assumption is conservative.
6.6.7

Well Drilling

Vertical wells may be drilled entirely using compressed air as the drilling fluid or possibly with
air for a portion of the well and mud in the target interval. For horizontal wells, drilling activities
would typically include the drilling of the vertical and lateral portions of a well using
compressed air and mud (or other fluid) respectively. Regardless of the type of well, drilling
activities are dependent on the internal combustion engines needed to supply electrical or
hydraulic power to: 1) the rotary table or topdrive that turns the drillstring, 2) the drawworks, 3)
air compressors, and 4) mud pumps. Carbon dioxide emissions occur from the engines needed to

Final SGEIS 2015, Page 6-198

 perform the work required to spud the well and reach its total depth. Table GHG-4 in Appendix
19, Part A includes estimates for CO2 emissions generated by these stationary sources. As
shown in the table, approximately 83 tons of CO2 emissions per single vertical well would be
generated as a result of drilling operations. Tables GHG-5 and GHG-6 show CO2 emissions of
194 tons and 776 tons for the drilling of a single horizontal well and four-well pad, respectively.
6.6.8

Well Completion

Well completion activities include 1) transport of required equipment and materials to and from
the site, 2) hydraulic fracturing of the well, 3) a flowback period, including flaring, to clean the
well of fracturing fluid and excess sand used as the hydraulic fracturing proppant, 4) drilling out
of hydraulic fracturing stage plugs and the running of production tubing by the completion rig
and 5) site reclamation. Mobile and stationary engines, and equipment used during the
aforementioned completion activities emit CO2 and/or CH4. Tables GHG-7, GHG-8 and GHG-9
in Appendix 19, Part A include estimates of individual and total emissions of CO2 and CH4
generated during the completion phase for a single vertical well, single horizontal well and a
four-well pad, respectively.
Similar to the above discussion regarding mobilization and demobilization of rigs, transport of
equipment and materials, which results in CO2 emissions, is necessary for completion of wells.
The results of this evaluation are shown in Tables GHG-7, GHG-8 and GHG-9 of Appendix 19,
Part A. GHG emissions of CO2 from transportation provided in the tables rely on estimated fuel
usage for both light and heavy trucks. A sample calculation for determining CO2 emissions
based on fuel usage is shown in Appendix 19, Part B. As shown in Table GHG-7, transportation
related completion-phase emissions of CO2 for a single vertical well is estimated at 12 tons. For
the single horizontal well and the four-well pad (see Table GHG-8 and GHG-9), transportation
related completion-phase CO2 emissions are estimated at 31 to 115 tons, respectively.
Hydraulic fracturing operations require the use of many engines needed to drive the highpressure high-volume pumps used for hydraulic fracturing (see multiple “Pump trucks” in the
Photos Section of Chapter 6). As previously discussed and shown in Table GHG-5 in Appendix
19, Part A, an average (i.e., 29,000 gallons of diesel) of the fuel usage from eight Marcellus
Shale hydraulic fracturing jobs performed on horizontally drilled wells in neighboring

Final SGEIS 2015, Page 6-199

 Pennsylvania and West Virginia was used to calculate the estimated amount of CO2 emitted
during hydraulic fracturing. Fuel usage for the single vertical well was prorated to account for
less time pumping (i.e., one-eighth). Tables GHG-7, GHG-8 and GHG-9 show that
approximately 54 tons and 325 tons of CO2 emissions per well would be generated as a result of
single vertical well and single horizontal well hydraulic fracturing operations, respectively.
Subsequent to hydraulic fracturing in which fluids are pumped into the well, the direction of flow
is reversed and flowback waters, including reservoir gas, are routed through separation
equipment to remove excess sand, then through a line heater and finally through a separator to
separate water and gas on route to the flare stack. Generally speaking, flares in the oil and gas
industry are used to manage the disposal of hydrocarbons from routine operations, upsets, or
emergencies via combustion. 391 However, only controlled combustion events would be flared
through stacks used during the completion phase for the Marcellus Shale and other lowpermeability gas reservoirs. A flaring period of 3 days was considered for this analysis for the
vertical and horizontal wells respectively although the actual period could be either shorter or
longer.
Initially, only a small amount of gas recovered from the well is vented for a relatively short
period of time. If a sales line is available, once the flow rate of gas is sufficient to sustain
combustion in a flare, the gas is flared until there is sufficient flowing pressure to flow the gas
into the sales line. 392 Otherwise, the gas is flared and combusted at the flare stack. As shown in
Tables GHG-7 and GHG-8 in Appendix 19, Part A, approximately 1,728 tons of CO2 and 12
tons of CH4 emissions are generated per well during a three-day flaring operation for a 10
Mmcf/d flowrate. As mentioned above, the actual duration of flaring may be more or less. The
CH4 emissions during flaring result from 2% of the gas flow remaining uncombusted. ICF
computed the primary CO2 and CH4 emissions rates using an average Marcellus gas
composition. 393 The duration of flaring operations may be shortened by using specialized gas
recovery equipment, provided a gas sales line is in place at the time of commencing flowback
from the well. Recovering the gas to a sales line, instead of flaring it, is called a REC and is
391

API, 2004; amended 2005. p. 4-27.

392

ALL Consulting, 2009. p. 14.

393

ICF Task 2, 2009, p. 28.

Final SGEIS 2015, Page 6-200

 further discussed in Chapter 7 as a possible mitigation measure, and in Appendix 25 (REC
Executive Summary included by ICF for its work in support of preparation of the SGEIS).
The final work conducted during the completion phase consists of using a completion rig,
possibly a coiled-tubing unit, to drill out the hydraulic fracturing stage plugs and run the
production tubing in the well. Assuming a fuel consumption rate of 25 gallons per hour and an
operating period of 24 hours, the rig engines needed to perform this work emit CO2 at a rate of
approximately 4 tons per single vertical well and 7 tons per single horizontal well. No stage plug
milling is normally required and less tubing is run for a single vertical well as compared to a
horizontal well, and less completion time results in less GHG emissions. After the completion
rig is removed from the site, earth moving equipment would be transported to the site and the
area would be reworked and graded, which adds another 9 tons of CO2 emissions for either a
one-well project or four-well pad. Tables GHG-7, GHG-8 and GHG-9 in Appendix 19, Part A
show CO2 emissions from these final stages of work during the well completion phase for a
single vertical well, single horizontal well and a four-well pad, respectively. Site work for a
single vertical well would be less due to a smaller pad size but for simplification, site work is
assumed the same for all well scenarios considered.
6.6.9

Well Production

GHGs from the well production phase include emissions from transporting the production
equipment to the site and then operating the equipment necessary to process and flow the natural
gas from the well into the sales line. Carbon dioxide emissions are generated from the trucks
needed to haul the production equipment to the wellsite. As previously stated, GHG emissions
of CO2 from transportation rely on estimated fuel usage where available or VMT, which
ultimately requires a determination of fuel usage. Such emissions associated with well
production activities, include those from transportation related to the removal of production
brine, as discussed below. The estimated VMT for each case was then used to determine
approximate fuel use and resultant CO2 emissions. As shown in Tables GHG-10, GHG-11 and
GHG-12 in Appendix 19, Part A, transportation needed to haul production equipment to a
wellsite for a one-well project and a four-well pad results in first-year CO2emissions of
approximately 3 tons and 11 tons, respectively.

Final SGEIS 2015, Page 6-201

 Well production may require the removal of production brine from the site which, if present, is
stored temporarily in plastic, fiberglass or steel brine production tanks, and then transported offsite for proper disposal or reuse. The trucks used to haul the production brine off-site generate
CO2 emissions. Transportation estimates were used to determine CO2 emissions from each well
development scenario, and emission estimates are presented in Tables GHG-10, GHG-11 and
GHG-12 in Appendix 19, Part A. Table GHG-10 presents CO2 and CH4 emissions for a onewell project for the period of production remaining in the first year after the single vertical well
is drilled and completed. For the purpose of this analysis, the duration of production for a single
vertical well in its first year was estimated at 349 days (i.e., 365 days minus 16 days to drill &
complete) and for a single horizontal well in its first year 331 days (i.e., 365 days minus 34 days
to drill & complete). Table GHG-13 shows estimated annual emissions for a single vertical well
or single horizontal well commencing in year two, and producing for a full year. Table GHG-12
presents CO2 and CH4 emissions for a four-well pad for the period of production remaining in
the first year after all ten wells are drilled and completed. For the purpose of this analysis, the
duration of production for the ten-well pad in its first year was estimated at 229 days (i.e., 365
days minus 136 days to drill & complete). Instead of work phases occurring sequentially, actual
operations may include concurrent well drilling and producing activities on the same well pad.
Table GHG-14 shows estimated annual emissions for a four-well project commencing in year
two, and producing for a full year.
GHGs in the form of CO2 and CH4 are emitted during the well production phase from process
equipment and compressor engines. Glycol dehydrators, specifically their vents, which are used
to remove moisture from the natural gas in order to meet pipeline specifications and dehydrator
pumps, generate vented CH4 emissions, as do pneumatic device vents which operate by using gas
pressure. Compressors used to increase the pressure of the natural gas so that the gas can be put
into the sales line typically are driven by engines which combust natural gas. The compressor
engine’s internal combustion cycle results in CO2 emissions while compression of the natural gas
generates CH4 fugitive emissions from leaking packing systems. All packing systems leak under
normal conditions, the amount of which depends on cylinder pressure, fitting and alignment of
the packing parts, and the amount of wear on the rings and rod shaft. 394 The emission rates
394

http://www.epa.gov/gasstar/documents/ll_rodpack.pdf.

Final SGEIS 2015, Page 6-202

 presented in Table GHG-1, Appendix 19, Part A “Emission Rates for Well Pad” were used to
calculate estimated emissions of CO2 and CH4 for each stationary source for a single vertical
well, single horizontal well and four-well pad using the equation noted in Section 6.6.4 and the
corresponding Activity Factors shown in Tables GHG-10, GHG-11, GHG-12, GHG-13 and
GHG-14 in Appendix 19, Part A. Based on the specified emissions rates for each piece of
production equipment, the calculated annual GHG emissions presented in the Tables show that
the compressors, glycol dehydrator pumps and vents contribute the greatest amount of CH4
emissions during the this phase, while operation of pneumatic device vents also generates vented
CH4 emissions. The amount of CH4 vented in the compressor exhaust was not quantified in this
analysis but, according to Volume II: Compressor Driver Exhaust, of the 1996 Final Report on
Methane Emissions from the Natural Gas Industry, compressor exhaust accounts for “about 7.9%
of methane emissions from the natural gas industry.”
6.6.10 Summary of GHG Emissions
As previously discussed, wellsite operations were divided into the following five phases to
facilitate GHG analysis: 1) Drilling Rig Mobilization, Site Preparation and Demobilization, 2)
Completion Rig Mobilization and Demobilization, 3) Well Drilling, 4) Well Completion
(includes hydraulic fracturing and flowback) and 5) Well Production. Each of these phases was
analyzed for potential GHG emissions, with a focus on CO2 and CH4 emissions. The results of
these phase-specific analyses for a single vertical well, single horizontal well and four-well pad
are detailed in Tables GHG-15, GHG-16, GHG-17, GHG-18 and GHG-19 in Appendix 19, Part
A. In addition, the tables include estimates of GHG emissions occurring in the first year and
each producing year thereafter for each project type.
The goal of this review is to characterize and present an estimate of total annual emissions of
CO2, and other relative GHGs, as both short tons and CO2e expressed in short tons for
exploration and development of the Marcellus Shale and other low-permeability gas reservoirs
using high volume hydraulic fracturing. To determine CO2e, each greenhouse gas has been
assigned a number or factor that reflects its global warming potential (GWP). The GWP is a
measure of a compound’s ability to trap heat over a certain lifetime in the atmosphere, relative to
the effects of the same mass of CO2 released over the same time period. Emissions expressed in
equivalent terms highlight the contribution of the various gases to the overall inventory.

Final SGEIS 2015, Page 6-203

 Therefore, GWP is a useful statistical weighting tool for comparing the heat trapping potential of
various gases. 395 For example, Chesapeake Energy Corporation’s July 2009 Fact Sheet on
greenhouse gas emissions states that CO2 has a GWP of 1 and CH4 has a GWP of 23, and that
this comparison allows emissions of greenhouse gases to be estimated and reported on an equal
basis as CO2e. 396 However, GWP factors are continually being updated, and for the purpose of
this analysis as required by the Department’s 2009 Guide for Assessing Energy Use and
Greenhouse Gas Emissions in an Environmental Impact Statement, the 100-Year GWP factors
provided in below Table 6.27 were used to determine total GHGs as CO2e. Tables GHG-15,
GHG-16, GHG-17, GHG-18 and GHG-19 in Appendix 19, Part A include a summary of
estimated CO2 and CH4 emissions from the various operational phases as both short tons and as
CO2e expressed in short tons.
Table 6.27 - Global Warming Potential for Given Time Horizon 397

Common Name
Carbon dioxide
Methane

Chemical
Formula
CO2
CH4

20-Year
GWP
1
72

100-Year
GWP
1
25

500-Year
GWP
1
7.6

Table 6.28 is a summary of total estimated CO2 and CH4 emissions for exploration and
development of the Marcellus Shale and other low-permeability gas reservoirs using high
volume hydraulic fracturing, as both short tons and as CO2e expressed in short tons. The below
table includes emission estimates for the first full year in which drilling is commenced and
subsequent producing years for each project type (i.e., single vertical well, single horizontal well
and four-well pad), sourcing of equipment and materials.
The noted CH4 emissions occurring during the production process and compression cycle
represent ongoing annual GHG emissions. As noted above, for the purpose of assessing GHG
impacts, each ton of CH4 emitted is equivalent to 25 tons of CO2. Thus, because of its recurring
nature, the importance of limiting CH4 emissions throughout the production phase cannot be
overstated.

395

API, August 2009. http://www.api.org/ehs/climate/new/upload/2009_GHG_COMPENDIUM.pdf.

396

Chesapeake Energy Corp., July 2009. Greenhouse Gas Emissions and Reductions Fact Sheet.

397

Adapted from Forster, et al. 2007, Table 2.14. Chapter 2, p. 212. http://ipcc-wg1.ucar.edu/wg1/Report/AR4WG1_Print_Ch02.pdf.

Final SGEIS 2015, Page 6-204

 Table 6.28 - Summary of Estimated Greenhouse Gas Emissions (Revised July 2011)

Estimated First-Year
Green House Gas
Emissions from Single
Vertical Well
Estimated First-Year
Green House Gas
Emissions from Single
Horizontal Well
Estimated First-Year
Green House Gas
Emissions from FourWell Pad
Estimated Post FirstYear Annual Green
House Gas Emissions
from Single Vertical or
Single Horizontal Well
Estimated Post FirstYear Annual Green
House Gas Emissions
from Four-Well Project

398

CO2 (tons)

CH4
(tons)

CH4
Expressed
as CO2e
(tons) 398

Total Emissions from
Proposed Activity CO2e
(tons)

8,660

246

6,150

14,810

8,761

240

6,000

14,761

13,901

402

10,050

23,951

6,164

244

6,100

12,264

6,183

565

14,125

20,300

Equals CH4 (tons) multiplied by 25 (100-Year GWP).

Final SGEIS 2015, Page 6-205

 Some uncertainties remain with respect to quantifying GHG emissions for the subject activity.
For the potential associated GHG emission sources, there are multiple options for determining
the emissions, often with different accuracies. Table 6.29, which was prepared by the API,
illustrates the range of available options for estimating GHG emissions and associated
considerations. The two types of approaches used in this analysis were the “Published emission
factors” and “Engineering calculations” options. These approaches, as performed, rely heavily
on a generic set of assumptions with respect to duration and sequencing of activities, and size,
number and type of equipment for operations that would be conducted by many different
companies under varying conditions. Uncertainties associated with GHG emission
determinations can be the result of three main processes noted below. 399
•

Incomplete, unclear or faulty definitions of emission sources;

•

Natural variability of the process that produces the emissions; and

•

Models, or equations, used to quantify emissions for the process or quantity under
consideration.

Nevertheless, while the results of potential GHG emissions presented in above Table 6.28 may
not be precise for each and every well drilled, the real benefit of the emission estimates comes
from the identification of likely major sources of CO2 and CH4 emissions relative to the activities
associated with gas exploration and development. It is through this identification and
understanding of key contributors of GHGs that possible mitigation measures and future efforts
can be focused in New York. Following, in Chapter 7, is a discussion of possible mitigation
measures geared toward reducing GHGs that would be required, with emphasis on CH4.

399

API, August 2009, p. 3-30. http://www.api.org/ehs/climate/new/upload/2009_GHG_COMPENDIUM.pdf.

Final SGEIS 2015, Page 6-206

 Table 6.29 - Emission Estimation Approaches – General Considerations 400

Types of Approaches

Published emission
factors

Equipment manufacturer
emission factors

Engineering calculations

Process simulation or
other computer modeling

Monitoring over a range
of conditions and
deriving emission factors

Periodic or continuousa
monitoring of emissions
or parametersb for
calculating emissions

General Considerations
• Accounts for average operations or conditions
• Simple to apply
• Requires understanding and proper application of measurement units and underlying
standard conditions
• Accuracy depends on the representativeness of the factor relative to the actual
emission source
• Accuracy can vary by GHG constituents (i.e., CO2, CH4, and N2O)
• Tailored to equipment-specific parameters
• Accuracy depends on the representativeness of testing conditions relative to actual
operating practices and conditions
• Accuracy depends on adhering to manufacturers inspection, maintenance and
calibration procedures
• Accuracy depends on adjustment to actual fuel composition used on-site
• Addition of after-market equipment/controls will alter manufacturer emission factors
• Accuracy depends on simplifying assumptions that may be contained within the
calculation methods
• May require detailed data
• Accuracy depends on simplifying assumptions that may be contained within the
computer model methods
• May require detailed input data to properly characterize process conditions
• May not be representative of emissions that are due to operations outside the range of
simulated conditions
• Accuracy depends on representativeness of operating and ambient conditions
monitored relative to actual emission sources
• Care should be taken when correcting to represent the applicable standard conditions
• Equipment, operating, and maintenance costs must be considered for monitoring
equipment
• Accounts for operational and source specific conditions
• Can provide high reliability if monitoring frequency is compatible with the temporal
variation of the activity parameters
• Instrumentation not available for all GHGs or applicable to all sources
• Equipment, operating, and maintenance costs must be considered for monitoring
equipment

Footnotes and Sources:
a
Continuous emissions monitoring applies broadly to most types of air emissions, but may not be directly applicable
nor highly reliable for GHG emissions.
b
Parameter monitoring may be conducted in lieu of emissions monitoring to indicate whether a source is operating
properly. Examples of parameters that may be monitored include temperature, pressure and load.

400

API August 2009, p. 3-9, http://www.api.org/ehs/climate/new/upload/2009_GHG_COMPENDIUM.pdf.

Final SGEIS 2015, Page 6-207

 6.7

Naturally Occurring Radioactive Materials in the Marcellus Shale

Chapter 4 explains that the Marcellus Shale is known to contain NORM concentrations at higher
levels than surrounding rock formations, and Chapter 5 provides some sample data from
Marcellus Shale cuttings. Activities that have the potential to concentrate these constituents
through surface handling and disposal may need regulatory oversight to ensure adequate
protection of workers, the general public, and the environment. Gas wells can bring NORM to
the surface in the cuttings, flowback fluid and production brine, and NORM can accumulate in
pipes and tanks (pipe scale and sludge.) Based upon currently available information it is
anticipated that flowback water will not contain levels of NORM of significance, whereas
production brine is known to contain elevated NORM levels. Radium-226 is the primary
radionuclide of concern from the Marcellus.
Elevated levels of NORM in production brine (measured in picocuries/liter or pCi/L) may result
in the buildup of pipe scale containing elevated levels of radium (measured in pCi/g). The
amount and concentration of radium in the pipe scale would depend on many conditions,
including pressures and temperatures of operation, amount of available radium in the formation,
chemical properties, etc. Because the concentration of radium in the pipe scale cannot be
measured without removing or disconnecting the pipe, a surrogate method is employed,
conducting a radiation survey of the pipe exterior. A high concentration of radium in the scale
would result in an elevated radiation exposure level at the pipe’s exterior surface (measured in
mR/hr) and can be detected with a commonly used survey instrument. The Department of
Health would require a radioactive materials license when the radiation exposure levels of
accessible piping and equipment are greater than 50 microR/hr (µR/hr). Equipment that exhibits
dose rates in excess of this level will be considered to contain processed and concentrated
NORM for the purpose of waste determinations.
Oil and gas NORM occurs in both liquid (production brine), solid (pipe scale, cuttings, tank and
pit sludges), and gaseous states (produced gas). Although the highest concentrations of NORM
are in production brine, it does not present a risk to workers because the external radiation levels
are very low. However, the build-up of NORM in pipes and equipment (pipe scale and sludge)
has the potential to expose workers handling (cleaning or maintenance) the pipe to increased
radiation levels. Also wastes from the treatment of production brines may contain concentrated

Final SGEIS 2015, Page 6-208

 NORM and therefore may require controls to limit radiation exposure to workers handling this
material as well as to ensure that this material is disposed of in accordance with 6 NYCRR §
380.4.
Radium is the most significant radionuclide contributing to oil and gas NORM. It is fairly
soluble in saline water and has a long radioactive half life - about 1,600 years (Table 6.30).
Radon gas, which under most circumstances is the main human health concern from NORM, is
produced by the decay of radium-226, which occurs in the uranium-238 decay chain. Uranium
and thorium, which are naturally occurring parent materials for radium, are contained in mineral
phases in the reservoir rock cuttings, but have very low solubility. The very low concentrations
and poor water solubility are such that uranium and thorium pose little potential health threat.
Table 6.30 - Radionuclide Half-Lives

Radionuclide

Half-life

Mode of Decay

Ra-226

1,600 years

alpha

Rn-222

3.824 days

alpha

Pb-210

22.30 years

beta

Po-210

138.40 days

alpha

Ra-228

5.75 years

beta

Th-228

1.92 years

alpha

Ra-224

3.66 days

alpha

In addition to exploration and production (E&P) worker protection from NORM exposure, the
disposal of NORM-contaminated E&P wastes is a major component of the oil and gas NORM
issue. This has attracted considerable attention because of the large volumes of production brine
(>109 billion bbl/yr; API estimate) and the high costs and regulatory burden of the main disposal
options, which are underground injection in Class II UIC wells and offsite treatment. The
Environmental Sciences Division of Argonne National Laboratory has addressed E&P NORM
disposal options in detail and maintains a Drilling Waste Management Information System
website that links to regulatory agencies in all oil and gas producing states, as well as providing
detailed technical information.

Final SGEIS 2015, Page 6-209

 In NYS the disposal of processed and concentrated NORM in the form of pipe scale or water
treatment waste is subject to regulation under Part 380. Because disposal of Part 380 regulated
waste is prohibited in Part 360 regulated solid waste landfills, this waste would require disposal
in out-of-state facilities approved to accept NORM wastes. Disposal facilities that can accept
this type of waste include select RCRA C facilities and low-level radioactive waste disposal
sites.
6.8

Socioeconomic Impacts 401

This section provides a discussion of the potential socioeconomic impacts on the Economy,
Employment, and Income (Section 6.8.1); Population (Section 6.8.2); Housing (Section 6.8.3);
Government Revenues and Expenditures (Section 6.8.4); and Environmental Justice (Section
6.8.5). A more detailed discussion of the potential impacts, as well as the assumptions used to
estimate the impacts, is provided in the Economic Assessment Report, which is available as an
addendum to this SGEIS.
To estimate the socioeconomic impacts associated with the use of high-volume hydraulic
fracturing techniques for extracting natural gas, several assumptions must be made about the
amount of natural gas development that would occur, the expected rate of development, the
length of time over which that development would occur, and the distribution of this
development throughout the state.
For the purposes of this SGEIS, the expected rate of development is measured by the number of
wells constructed annually. Two different levels of development are analyzed – a low
development scenario, and an average development scenario. These development scenarios were
developed by the Department based on information the Department had requested from the
Independent Oil & Gas Association of New York (IOGA-NY). IOGA-NY started with an
estimated average rate of development based on the following assumptions:

401

Section 6.8, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011, and was adapted by
the Department.

Final SGEIS 2015, Page 6-210

 •

Approximately 67% of the area covered by the Marcellus and Utica shale is developable;

•

Approximately 90% of wells would be horizontal wells, with an average of 160
acres/well; and

•

Approximately 10% of wells would be vertical wells, with an average of 40 acres/well.

For the low rate of development, DEC assumed a rate of 25% of IOGA-NY’s estimated average
rate of development.
Table 6.31 provides a highlight of the major assumptions for each of these scenarios. In both
scenarios, the maximum build-out of new wells is assumed to be completed in Year 30. Under
the low development scenario, a total of 9,461 horizontal wells and 1,071 vertical wells are
assumed to be constructed at maximum build-out (e.g., Year 30). Under the average
development scenario a total of 37,842 horizontal wells and 4,284 vertical wells are assumed to
be constructed at maximum build-out (e.g., Year 30). The high development scenario, which is
analyzed in the Economic Assessment Report, assumes a total of 56,508 horizontal and 6,273
vertical wells are constructed at maximum build-out (e.g., Year 30).
Analysis of the high development scenario is not included in this socioeconomic section of the
SGEIS in order to be conservative in assessing the positive potential economic benefits of highvolume hydraulic fracturing in New York State. The high development scenario was used as the
conservative assumption of activity for all other sections of this SGEIS.
Economic realities, including diminishing marginal returns associated with drilling wells further
from the fairway in less than ideal locations, and the exclusion of high-volume hydraulic
fracturing wells from certain sensitive locations, would make it highly unlikely that the
maximum build-out under the high development scenario would occur. Therefore, only the low
and average development scenarios are discussed throughout this section.
These development scenarios are designed to provide order-of-magnitude estimates for the
following socioeconomic analysis and are in no way meant to forecast actual well development
levels in the Marcellus and Utica Shale reserves in New York State. These scenarios should be

Final SGEIS 2015, Page 6-211

 viewed as a “best estimate” of the range of possible amounts of development that could occur in
New York State.
Table 6.31 - Major Development Scenario Assumptions (New August 2011)

Scenarios
Low
Total Wells Constructed (Year 1 to Year 30)
Horizontal
9,461
Vertical
1,071
Total
10,532
Maximum Number of New Wells Developed per Year (Year 10 to Year 30)
Horizontal
371
Vertical
42
Total
413

Average
37,842
4,284
42,126
1,484
168
1,652

Both development scenarios assume a consistent timeline for development and production.
Development is assumed to occur for a period of 30 years, starting with a 10-year “ramp-up”
period. The number of new wells constructed each year is assumed to reach the maximum in
Year 10 and to continue at this level until Year 30, when all new well construction is assumed to
end. This assumption, which does not significantly affect the socioeconomic impact analysis,
was used to remain consistent with other sections of the SGEIS. In actuality, well development
would more likely gradually ramp up, reach a peak, and then gradually ramp down as fewer and
fewer wells were completed. However, this curve would not necessarily be smooth.
It is unlikely that new well construction would occur under a steady, constant rate. Economic
factors such as the price of natural gas, input costs, the price of other energy sources, changes in
technology, and the general economic conditions of the state and nation would all affect the
yearly rate of well construction and the overall level of development of the gas reserves. The
actual track of well construction would likely be much more cyclical in nature than as described
in the following sections.
The average development scenario should be viewed as the upper boundary of possible
development, while the low development scenario should be viewed as the likely lower boundary
of possible development. As shown in Table 6.31, the maximum number of new wells

Final SGEIS 2015, Page 6-212

 developed in a year under the low development scenario is 371 horizontal and 42 vertical wells,
and the maximum number of new wells developed in a year under the average development
scenario is 1,484 horizontal and 168 vertical wells.
Each newly constructed well is assumed to have an average productive life of 30 years. For
example, wells constructed in Year 1 are assumed to still be producing in Year 30, and wells
constructed in Year 10 are assumed to produce until Year 40. Because of the assumption of a
30-year development period, wells constructed in Year 30 are assumed to be productive until
Year 60. Assuming a 30-year development period and a 30-year production life for each well,
the number of productive wells in New York State would be expected to grow until Year 30, at
which point, the number of productive wells would peak. After Year 30, with no new wells
being constructed, the number of wells in production would begin to decline. Because the
number of annual wells approved and developed each year is different for the two development
scenarios, the peak number of operating wells at Year 30 also differs for each scenario.
Under both development scenarios, natural gas production in New York State would occur from
Year 1 until Year 60, with Year 30 having the maximum number of wells in production. After
Year 30, producing wells would gradually decline until Year 60, at which time it is assumed that
production stops.
As discussed in Section 1, no site-specific project locations are being evaluated in the SGEIS.
Therefore, for purposes of analysis, three distinct regions were identified within the area where
potential drilling may occur in order to take a closer look at the potential impacts at the regional
and local levels. The three regions were selected to evaluate differences between areas with a
high, moderate, and low production potential; areas that have experienced gas development in
the past and areas that have not experienced gas development in the past; and differences in land
use patterns. The three representative regions and the respective counties within the region are:
•

Region A: Broome County, Chemung County, and Tioga County;

•

Region B: Delaware County, Otsego County; and Sullivan County; and

•

Region C: Cattaraugus County and Chautauqua County

Final SGEIS 2015, Page 6-213

 This analysis is not intended to imply that impacts would occur only in these three regions.
Impacts would occur at the local and regional levels wherever high-volume hydraulic fracturing
wells are constructed. The actual locations of these wells have not yet been determined, and they
could be constructed wherever there is low-permeable shale. Similar to the development
scenarios described above, the representative regions are designed to give a range of possible
socioeconomic impacts. Therefore, the results of the local and regional analysis should also be
seen as order-of-magnitude estimates for the range of possible impacts. Further descriptions of
the regions are provided in Section 2.3.11.
6.8.1

Economy, Employment, and Income

The following discusses the potential impacts on the economy, employment and income for New
York State, and the local areas within each of the three regions (Regions A, B and C).
6.8.1.1 New York State
Economy and Employment
Development of low-permeability natural gas reservoirs in the Marcellus and Utica shale by
high-volume hydraulic fracturing would be expected to have a significant, positive impact on the
economy of New York State. Construction and operation of the new natural gas wells are
expected to increase employment, earnings, and economic output throughout the state.
According to statistics collected and calculations made by the Marcellus Shale Education and
Training Center (the Center), in Pennsylvania, an average natural gas well using the high-volume
hydraulic fracturing technique requires 410 individuals working in 150 different occupations.
The manpower requirements to drill a single well were calculated to be 11.53 full-time
equivalent (FTE) construction workers (Marcellus Shale Education and Training Center 2009).
A full-time equivalent worker is defined as one worker working eight hours a day for 260 days a
year, or several workers working a total of 2,080 hours in a year. While the Center found that up
to 410 individuals are required to build one well, only 11.53 FTE workers were needed.
Typically, a high-volume hydraulic fracturing well is constructed over a 3- to 4-month period,
and many of the individuals and occupations are needed for only a very short duration.
Therefore, to accurately assess the economic impacts of constructing a high-volume hydraulic
fracturing well, the FTE workforce was considered.

Final SGEIS 2015, Page 6-214

 The Center also calculated the work force requirements for operating a well as 0.17 FTE
workers, or approximately 354 person hours per year. In other words, approximately 1 FTE
worker is required to operate and maintain every 6 wells in production (Marcellus Shale
Employment and Training Center 2009). Unlike the construction workforce that drills the well
within a few months and is finished, the operational workforce is required for the productive life
of the well. For the purposes of this analysis, a 30-year productive life has been assumed for
each well drilled. Therefore, for every new well drilled, 0.17 FTE workers are employed for 30
years.
In its study, the Marcellus Shale Employment and Training Center did not differentiate between
the labor requirements needed to drill a horizontal versus a vertical well. Typically, it is much
more costly and labor-intensive to drill a high-volume hydraulic fracturing horizontal well than it
is to drill a high-volume hydraulic fracturing vertical well. Therefore, in an effort to be
conservative and not overstate the positive economic impacts, a factor was applied to the 11.53
FTE figure for vertical wells in the estimates used for this analysis. This factor was calculated
using the average depth of a vertical well compared to the average depth of a high-volume
hydraulic-fracturing horizontal well. The resulting ratio of 0.2777 was applied to the 11.53 FTE
labor requirement to estimate the overall labor requirements of a vertical well.
Using the workforce requirement figures developed by the Marcellus Shale Employment and
Training Center and the two development scenarios described above, the expected impacts on
employment and earnings from high-volume hydraulic fracturing were projected for New York
State as a whole.
As shown in Table 6.32, annual direct construction employment is directly related to the number
of wells drilled in a given year. At the maximum well construction rate assumed for each
development scenario, total annual direct construction employment is predicted to range from
4,408 FTE workers under the low development scenario to 17,634 FTE workers under the
average development scenario. These employment figures correspond to the annual construction
of 413 horizontal and vertical wells under the low development scenario and 1,652 horizontal
and vertical wells under the average development scenario. In order to reach the full build-out

Final SGEIS 2015, Page 6-215

 potential used in the scenarios, it is assumed that construction employment and new well
construction would remain at these levels for 20 years, starting in Year 10 (see Table 6.32).
The maximum direct production employment under each development scenario is also shown in
Table 6.32. These figures represent the peak production year (Year 30), when the maximum
build-out potential has been reached before any of the wells have stopped producing. The
preceding and the following years all would have fewer production workers. At the peak,
production employment would be expected to range from 1,790 FTE workers under the low
development scenario to 7,161 FTE workers under the average development scenario (Table
6.32).
Table 6.32 - Maximum Direct and Indirect Employment Impacts on New
York State under Each Development Scenario (New August 2011)

Scenario
Direct Employment Impacts
Construction Employment1
Production Employment2
Indirect Employment 3
Total Employment Impacts
Total Employment as a Percent of New York State
2010 Labor Force

Total Employment
(in number of FTE jobs)
Low
Average
4,408
1,790
7,293
13,491
0.2%

17,634
7,161
29,174
53,969
0.7%

Source: U.S. Bureau of Economic Analysis 2011a; NYSDOL 2010.
1

These figures represent the maximum annual construction employment under each scenario and correspond to construction
employment in Years 10 – 30. See Ecology and Environment Engineering, P.C., 2011, Economic Assessment Report for
expected construction employment for all other years.

2

These figures represent the maximum annual production employment under each scenario. These figures correspond to
production employment in Year 30. See Ecology and Environment Engineering, P.C., 2011, Economic Assessment Report
for expected production employment for all other years.

3

Type I direct employment multipliers for the oil and gas extraction industry from the U.S. Bureau of Economic Analysis,
Regional Input-Output Modeling System (RIMS II) were used to estimate the indirect employment impacts.

Figure 6.13 illustrates the projected direct employment in New York State that would result from
implementation of each development scenario over the 60-year time frame. The figure shows
how construction and production employment levels are expected to vary, with peak direct
employment occurring in Year 30.

Final SGEIS 2015, Page 6-216

 Figure 6.13 – Projected Direct Employment in New York State Resulting
from Each Development Scenario (New August 2011)

In addition to the direct employment impacts described above, the proposed drilling would also
indirectly generate additional employment in other sectors of the economy. As the new
construction and operations workers spend a portion of their payroll in the local area, and as the
natural gas companies purchase materials from suppliers in New York State, the overall demand
for goods and services in the state would expand. Revenues at the wholesale and retail outlets
and service providers within the state would increase. As these merchants respond to this
increase in demand, they may, in turn, increase employment at their operations and/or purchase
more goods and services from their providers. These providers may then increase employment
in their establishments and/or spend a portion of their income in the state, thus “multiplying” the
positive economic impacts of the original increase in construction/production spending. These
“multiplier” effects would continue on until all of the original funds have left New York State’s
economy through either taxes or savings, or through purchases from outside the state.

Final SGEIS 2015, Page 6-217

 Indirect employment impacts are expected to range from an additional 7,293 FTE workers under
the low development scenario to an additional 29,174 FTE workers under the average
development scenario. These annual figures represent the year with the maximum employment
(Year 30). The years before and after this date would have less direct and indirect employment.
In total, at peak employment years, state approval of drilling in the Marcellus and Utica Shales is
expected to generate between 13,491 and 53,969 direct and indirect jobs, which equates to 0.2%
and 0.6%, respectively, of New York State’s 2010 total labor force, depending on the level and
intensity of development that occurs (see Table 6.32). Figure 6.14 graphically illustrates the
projected total employment in New York State that would result from each development
scenario. As shown on the figure, total employment levels would be highest in Year 10 through
Year 30. Once new well construction ends in Year 31, the direct and indirect employment would
be greatly reduced.
Figure 6.14 - Projected Total Employment in New York State Resulting
from Each Development Scenario (New August 2011)

Final SGEIS 2015, Page 6-218

 The majority of these indirect jobs would be concentrated in the construction, professional,
scientific, and technical services; real estate and rental/leasing; administrative and waste
management services; management of companies and enterprises; and manufacturing industries.
Income
The increase in direct and indirect employment would have a positive impact on income levels in
New York State. Table 6.33 provides estimates of the maximum direct and indirect employee
earnings that would be generated under each development scenario. When well construction
reaches its maximum levels (Year 10 through Year 30), total annual construction earnings are
projected to range from $298.4 million under the low development scenario to nearly $1.2 billion
under the average development scenario. Employee earnings from operational employment are
expected to range from $121.2 million under the low development scenario to $484.8 million
under the average development scenario in Year 30, the year that the maximum number of
operational workers are assumed to be employed.
Table 6.33 - Maximum Direct and Indirect Annual Employee Earnings Impacts on New
York State under Each Development Scenario (New August 2011)

Scenario
Direct Earnings Impacts
Construction Earnings1
Production Earnings2
Indirect Employee Earnings Impacts2,3
Total Employee Earnings Impacts
Total Employee Earnings as a Percent of New York
State’s 2009 Total Wages

Total Employee Earnings
($ millions)
Low
Average
$298.4
$121.2
$202.3
$621.9
0.1%

$1,193.8
$484.8
$809.2
$2,487.8
0.5%

Source: U.S. Bureau of Economic Analysis 2011a; NYDOL 2009.
1

These figures represent the maximum annual change in construction earnings under each scenario and correspond to
construction earnings in Years 10 - 30. See Ecology and Environment Engineering, P.C., 2011, Economic Assessment
Report for expected construction earnings for all other years.

2

These figures represent the maximum annual production earnings and indirect employee earnings under each development
scenario. These figures correspond to operations earnings in Year 30. See Ecology and Environment Engineering, P.C.,
2011, Economic Assessment Report for expected operation earnings for all other years.

3

Type I direct earnings multipliers for the oil and gas extraction industry from the U.S. Bureau of Economic Analysis,
Regional Input-Output Modeling System (RIMS II) were used to estimate the indirect employment impacts.

Final SGEIS 2015, Page 6-219

 As described above, the construction and production activities would also generate significant
indirect economic impacts. Indirect employee earnings are anticipated to range from $202.3
million under the low development scenario to $809.2 million under the average development
scenario in Year 30. The total direct and indirect impacts on employee earnings are projected to
range from $621.9 million to $2.5 billion per year at peak production and construction levels in
Year 30. These figures equate to increases of between 0.1% and 0.5% of the total wages and
salaries earned in New York State during 2009 (see Table 6.33).
Owners of the subsurface mineral rights where wells are drilled will also experience a significant
increase in income and wealth. Royalty payments to property owners typically amount to 12.5%
or more of the annual value of production of the well (NYSDEC 2007a). These royalty
payments, particularly in the initial stages of well production when natural gas production is at
its peak, can result in significant increases in income. Signing bonuses/bonus bids also can
provide significant additional income to property owners.
6.8.1.2 Representative Regions
As noted above, three representative regions were selected to show the range of possible
socioeconomic impacts that could occur at the local and regional levels. This analysis in no way
is meant to imply that impacts will occur only in these three regions.
For purposes of this analysis, it is assumed that 50% of all new well construction would occur in
Region A (Chemung, Tioga, and Broome counties); 23% would occur in Region B (Otsego,
Delaware, and Sullivan counties); 5% would occur in Region C (Chautauqua and Cattaraugus
counties); and the remaining 22% of new well construction would occur in the rest of New York
State. Geological data on the extent and thickness of the low-permeability shale in New York
State, including the Marcellus Shale and Utica Shale fairways, were the basis for these
assumptions.
Table 6.34 details the major assumptions for each development scenario for each representative
region. In all cases, total development is assumed to be reached at Year 30. As shown in the
table, Region A is anticipated to receive the majority of the new well construction. The analysis
of Region A is designed to show the upper bound of potential regional economic impacts. Under

Final SGEIS 2015, Page 6-220

 the low development scenario, a total of 5,281 new wells would be constructed in the counties of
Tioga, Chemung, and Broome. Under the average development scenario, a total of 21,067 new
wells would be constructed in Region A. The projected maximum number of new wells
developed per year in Region A would range from 207 to 826 wells, depending on the
development scenario considered. The projected maximum number of new wells developed per
year in Region B would range from 2,425 to 9,690 wells, depending on the development scenario
(see Table 6.34).
In contrast, Region C is assumed to experience a much smaller level of well development than
Region A or Region B. The analysis of Region C is designed to show the lower bound of
potential regional economic impacts. Under the low development scenario, a total of 534 new
wells would be constructed in Region C. Under the average development scenario, a total of
2,095 new wells would be constructed in Region C. The maximum number of new wells
constructed each year in Region C is assumed to be 21 wells under the low development scenario
and 82 wells under the average development scenario. The remaining 22% of the development
would occur in the rest of the state (see Table 6.34).
Table 6.34 - Major Development Scenario Assumptions for Each
Representative Region (New August 2011)

Low

Scenarios
Average

Region A
Total Wells Constructed (Year 1 to Year 30)
Horizontal
4,743
Vertical
538
Total
5,281
Maximum Number of New Wells Developed per Year (Year 10 to Year 30)
Horizontal
186
Vertical
21
Total
207
Region B
Total Wells Constructed (Year 1 to Year 30)
Horizontal
2,170
Vertical
255
Total
2,425
Maximum Number of New Wells Developed per Year (Year 10 to Year 30)
Horizontal
85
Vertical
10

Final SGEIS 2015, Page 6-221

18,923
2,144
21,067
742
84
826

8,697
993
9,690
341
39

 Low
95

Scenarios
Average
380

Total
Region C
Total Wells Constructed (Year 1 to Year 30)
Horizontal
483
Vertical
51
Total
534
Maximum Number of New Wells Developed per Year (Year 10 to Year 30)
Horizontal
19
Vertical
2
Total
21
Rest of State
Total Wells Constructed (Year 1 to Year 30)
Horizontal
2,065
Vertical
227
Total
2,292
Maximum Number of New Wells Developed per Year (Year 10 to Year 30)
Horizontal
81
Vertical
9
Total
90

1,888
207
2,095
74
8
82

8,334
940
9,274
327
37
364

Economy and Employment
The proposed approval of the use of high-volume hydraulic fracturing technique would have a
significant positive economic impact at the regional and local levels. Using the same
methodology described above for the statewide analysis, the FTE labor requirements needed to
construct and operate these wells were estimated for each region. Table 6.35 provides the
maximum direct and indirect employment impacts that are predicted to occur under each
development scenario for each region.
In Region A, which is used to define an upper boundary of the regional socioeconomic impacts,
it is projected that direct construction employment would range from 2,204 FTE construction
workers at the maximum employment levels under the low development scenario to 8,818 FTE
construction workers at the maximum employment levels under the average development
scenario. The new production employment in the region is expected to range from 895 to 3,581
FTE production workers per year.
In contrast, employment impacts are not anticipated to be as large in Region C, which is used to
define a lower boundary for the regional socioeconomic impacts. At the maximum employment
levels under the low development scenario, an estimated 221 new FTE constructions workers

Final SGEIS 2015, Page 6-222

 and 90 new FTE production workers would be needed for drilling and maintaining the new
natural gas wells. These figures would increase to 882 new FTE construction workers and 358
new FTE production workers under the average development scenario (see Table 6.35).
Table 6.35 - Maximum Direct and Indirect Employment Impacts on Each
Representative Region under Each Development Scenario (New August 2011)

Total Employment
(in number of FTE jobs)
Low
Average

Scenario
Region A
Direct Employment Impacts
Construction Employment1
Production Employment2
Indirect Employment Impacts3
Total Employment Impacts
Total Employment as a Percentage of Region A’s
2010 Total Labor Force
Region B
Direct Employment Impacts
Construction Employment1
Production Employment2
Indirect Employment Impacts3
Total Employment Impacts
Total Employment as a Percentage of Region B’s
2010 Total Labor Force
Region C
Direct Employment Impacts
Construction Employment1
Production Employment2
Indirect Employment Impacts3
Total Employment Impacts
Total Employment as a Percentage of Region C’s
2010 Total Labor Force

2,204
895
650
3,749
2.3%

8,818
3,581
2,600
14,999
9.3%

1,014
412
191
1,617
1.8%

4,056
1,647
762
6,465
7.3%

221
90
66
377
0.4%

882
358
263
1,503
1.4%

Source: U.S. Bureau of Economic Analysis 2011a; NYSDOL 2010.
1

These figures represent the maximum annual construction employment under each scenario and correspond to construction
employment in Years 10 – 30. See Ecology and Environment Engineering, P.C., 2011, Economic Assessment Report for
expected construction employment for all other years.

2

These figures represent the maximum annual production employment under each scenario. These figures correspond to
production employment in Year 30. See Ecology and Environment Engineering, P.C., 2011, Economic Assessment Report
for expected operation employment for all other years.

3

Separate Type I direct employment multipliers for the oil and gas extraction industry from the U.S. Bureau of Economic
Analysis, Regional Input-Output Modeling System (RIMS II), were used for each region to estimate the indirect
employment impacts.

Final SGEIS 2015, Page 6-223

 Figure 6.15, Figure 6.16, and Figure 6.17 illustrate the projected direct employment in each
representative region that would result from implementation of each development scenario over
the 60-year time frame. The figures show how construction and production employment levels
are expected to vary, with the peak direct employment occurring in Year 30.
Figure 6.15 - Projected Direct Employment in Region A Resulting from
Each Development Scenario (New August 2011)

Final SGEIS 2015, Page 6-224

 Figure 6.16 - Projected Direct Employment in Region B Resulting from
Each Development Scenario (New August 2011)

Final SGEIS 2015, Page 6-225

 Figure 6.17 - Projected Direct Employment in Region C Resulting from
Each Development Scenario (New August 2011)

As described previously for the statewide impacts, in addition to the direct employment impacts,
the proposed drilling would also indirectly generate additional employment in other sectors of
the economy. As the new construction and operations workers spend a portion of their payroll in
the local area, and as the natural gas companies purchase materials from regional suppliers, the
overall demand for goods and services in the region would expand. Revenues at the region’s
wholesale and retail outlets and service providers would increase. As these merchants respond to
this increase in demand, they may, in turn, increase employment at their operations and/or
purchase more goods and services from their providers. These providers may then increase
employment in their establishments and/or spend a portion of their income in the region, thus
“multiplying” the positive economic impacts of the original increase in construction/operation
spending. These “multiplier” effects would continue on until all of the original funds have left
the region’s economy through either taxes or savings, or through purchases from outside the
region.

Final SGEIS 2015, Page 6-226

 Indirect employment impacts are expected to range from a high of 650 to 2,600 indirect workers
in Region A to a low of 66 to 263 indirect workers in Region C, depending on the development
scenario. Direct employment multipliers of 1.4977 for Region A, 1.3272 for Region B, and
1.4657 for Region C for the oil and gas extraction industry were used in this analysis (U.S.
Bureau of Economic Analysis 2011b; 2011c; 2011d). In contrast, New York State as a whole
had a direct employment multiplier of 2.1766 for the oil and gas extraction industry (U.S. Bureau
of Economic Analysis 2011a).
The employment and earnings multipliers in these regions are much smaller than in New York
State as a whole, underscoring the fact that portions of these study areas do not have as welldeveloped, self-sufficient, and diverse economies as the state as a whole. In particular, the low
multipliers reflect the fact that much of the goods and services that would be needed to construct
and operate the new wells would be purchased outside the regions.
However, it can be expected that as the natural gas industry matures in these regions, more local
suppliers and service providers would enter the markets and be able to respond to the natural gas
industry’s needs. As time goes by, a larger portion of the indirect economic impacts would
remain in the region, further stimulating the local economies.
Figure 6.18, Figure 6.19, and Figure 6.20 graphically illustrate the projected total employment in
Region A, Region B, and Region C, respectively, that would result from each development
scenario. As shown on the figures, total employment levels would be greatest in Year 10
through Year 30. Once new well construction ends in Year 30, the projected direct and indirect
employment would be greatly reduced.

Final SGEIS 2015, Page 6-227

 Figure 6.18 – Projected Total Employment in Region A Under Each Development Scenario (New August 2011)

Final SGEIS 2015, Page 6-228

 Figure 6.19 - Projected Total Employment in Region B Under Each Development Scenario (New August 2011)

Final SGEIS 2015, Page 6-229

 Figure 6.20 - Projected Total Employment in Region C Under Each Development Scenario (New August 2011)

The proposed use of high-volume hydraulic fracturing would have a significant, positive impact
on employment in New York State as a whole and in the affected communities. However, the
distribution of these positive employment impacts would not be evenly distributed throughout
the state or even throughout the areas where low-permeable shale is located. Many geological
and economic factors would interact to determine the exact location that wells would be drilled.
The location of productive wells would determine the distribution of impacts.
In some regions in the state where drilling is most likely to occur, the increases in employment
may be so large that these regions may experience some short-term labor shortages. The
increase in direct and indirect employment related to the natural gas extraction industry could
drive wage rates up in the areas in the short term and make it more difficult for existing
industries to recruit and retain qualified workers. In addition, the increase in wage rates could
have a short-term, negative impact on existing industries as it would increase their labor costs.
These potential short-term labor impacts would be less severe because specialized labor from

Final SGEIS 2015, Page 6-230

 outside the region would likely be required for certain jobs, and the existence of employment
opportunities would cause the migration of workers into the region. In addition, the positive
employment impacts from well construction and development—and the related economic
impacts derived from that employment—would generate more in-migration to the region. In
time, the additional new residents to the areas would expand the regional labor force and reduce
the pressure on labor costs.
Income
The increase in direct and indirect employment would have a positive impact on income levels in
regions where natural gas development occurs. Table 6.36 provides estimates of the maximum
direct and indirect employee earnings that would be generated under each development scenario.
When well construction reaches its maximum levels (Year 10 to Year 30), total annual
construction earnings in a region could range from a low of $15.0 million in Region C under the
low development scenario to nearly $597.0 million under the average development scenario in
Region A. In Year 30, the year that the maximum number of production workers are assumed to
be employed, regional employee earnings from production employment could range from a low
of $6.1 million in Region C under the low development scenario to a high of $242.4 million in
Region A under the average development scenario.
Table 6.36 - Maximum Direct and Indirect Earnings Impacts on Each Representative
Region under Each Development Scenario (New August 2011)

Scenario
Region A
Direct Employment Impacts
Construction Earnings1
Production Earnings2
Indirect Earnings Impacts3
Total Earnings Impacts
Total Earnings as a Percentage of Region A’s 2009
Total Wages
Region B
Direct Earnings Impacts
Construction Earnings1
Production Earnings2
Indirect Earnings Impacts3

Employee Earnings
($ millions)
Low
Average

$149.2
$60.6
$44.0
$253.8
4.7%

$176.0
$1,015.4
18.7%

$68.6
$27.9
$12.9

$274.6
$111.5
$51.6

Final SGEIS 2015, Page 6-231

$597.0

 Scenario
Total Earnings Impacts
Total Earnings as a Percentage of Region B’s 2009
Total Wages
Region C
Direct Earnings Impacts
Construction Earnings1
Production Earnings2
Indirect Earnings Impacts3
Total Earnings Impacts
Total Earnings as a Percent of Region C’s 2009
Total Wages

Employee Earnings
($ millions)
Low
Average
$109.4
$437.7
4.8%
19.3%

$15.0
$6.1
$4.5
$25.6
0.9%

$59.7
$24.2
$17.8
$101.7
3.7%

Source: U.S. Bureau of Economic Analysis 2011b, 2011c, 2011d; NYSDOL 2009.
1

These figures represent the maximum annual construction earnings under each scenario and correspond to construction
earnings in Years 10 – 30. See Ecology and Environment Engineering, P.C., 2011, Economic Assessment Report for
expected construction earnings for all other years.

2

These figures represent the maximum annual production earnings under each development scenario. These figures
correspond to production employee earnings in Year 30. See Ecology and Environment Engineering, P.C., 2011, Economic
Assessment Report for expected production and indirect employee earnings for all other years.

3

Separate Type I direct earnings multipliers for the oil and gas extraction industry from the US Bureau of Economic
Analysis, Regional Input- Output Modeling System (RIMS II) for each region were used to estimate the indirect
employment impacts.

Total employee earnings in all of the regions are expected to increase significantly. Region A
would experience annual increases in employee earnings of approximately $254 million to $1.0
billion, or 4.7% to 18.7% of the 2009 total wages and salaries for the region. Similarly, Region
B would experience annual increases in employee earnings of approximately $109 million to
$438 million, or 4.8% to 19.3% of 2009 total wages and salaries for the region. Region C would
also experience a significant impact in its annual employee earnings. Employee earnings in this
region would increase from approximately $26 million to $102 million, or 0.9% to 3.7% of the
2009 total wages and salaries for the region (see Table 6.36).
Owners of the subsurface mineral rights where wells are drilled would also experience a
significant increase in income and wealth. Royalty payments to property owners typically
amount to 12.5% or greater of the annual value of production of the well (NYSDEC 2007a).
These royalty payments, particularly in the initial stages of well production when natural gas

Final SGEIS 2015, Page 6-232

 production is at its peak, could result in significant increases in income. In addition, mineral
rights owners often receive large signing bonuses/bonus bids as part of the lease agreements.
Impacts on Other Industries
The proposed high-volume hydraulic-fracturing operations would affect not only the size of the
regional economies as described above, but would also have an impact on other industries in the
economy.
As previously described, suppliers of the natural gas extraction industry would experience
significant increases in demand for their goods and services. Over time, these industries would
expand and their importance in the regional economies would likewise increase. As shown in
Section 2.3.11, Economy, Employment, and Income, the industries expected to experience the
greatest indirect, or secondary, growth due to expansion of the natural gas extraction industry
would be real estate; the professional, scientific, and technical industries; the management of
companies and enterprises; construction; and manufacturing industries. For every $1 million
change in the final demand generated in the natural gas extraction industry, a corresponding
significant level of output would be generated in these industries. Typically, a change in final
demand in an industry is defined as the change in output of that industry multiplied by the value
or price of its output. In this case, a $1 million increase in the value of output from the natural
gas extraction industry would generate $47,100 in the real estate and rental and leasing industry;
$30,500 in the professional, scientific, and technical services industry; and $27,600 in the
management of companies and enterprises industry. See Section 2.3.15 for a discussion of
indirect impacts on other industries in New York State.
Each of these secondary industries would experience increases in their output, employment,
income and value added. As a result, industries that supply these secondary industries would
also experience a positive economic impact, and they would expand as demand for their goods
and services increases. Secondary, and eventually even tertiary, suppliers would start to tailor
their products to meet the needs of the natural gas extraction industry.
Conversely, some industries in the regional economies may contract as a result of the proposed
natural gas development. Negative externalities associated with the natural gas drilling and

Final SGEIS 2015, Page 6-233

 production could have a negative impact on some industries such as tourism and agriculture.
Negative changes to the amenities and aesthetics in an area could have some effect on the
number of tourists that visit a region, and thereby impact the tourism industry. However, as
shown by the tourism statistics provided for Region C, Cattaraugus and Chautauqua Counties
still have healthy tourism sectors despite having more than 3,900 active natural gas wells in the
region.
Similarly, agricultural production in the heavily developed regions may experience some decline
as productive agricultural land is taken out of use and is developed by the natural gas industry.
Property values also may experience some increase as a result of the natural gas development
and the resulting increase in economic activity. The potential increase in land prices, which is
one of the main factors of production for agriculture, could impact the industry’s input costs in
areas experiencing the most intense development.
6.8.2

Population

This section presents a summary of the population and demographic findings of the Economic
Assessment Report (2011) written by Ecology and Environment Engineering, P.C.
As described previously, three representative regions were selected to assess the range of
potential socioeconomic impacts that could occur at the local and regional levels. The
designation of these areas as representative regions does not mean that the impacts would
necessarily be limited to those areas. Until the production potential of low-permeability
reservoirs is proven, it is not possible to predict where every potential high-volume hydraulically
fractured well may be sited; wells could be developed anywhere there is low-permeability shale.
The local and regional impacts presented here are intended only to provide order-of-magnitude
estimates for the range of potential impacts. See the Economic Assessment Report for a more
detailed discussion on the selection of these representative regions.
To assess the maximum potential population impacts, the discussion below is based on a
hypothetical situation in which all workers hired for the construction and production phases of
the natural gas wells either migrate into the regions from other areas, or workers migrate into the
regions from other areas to fill positions which local construction and production workers vacate

Final SGEIS 2015, Page 6-234

 to work on the natural gas wells. Although this hypothetical situation is used to examine the
maximum potential population impacts, it is more likely that the actual outcome would be less
than described. Not all workers employed during the construction and production phases would
necessarily live in New York State or one of the representative regions. Particularly in the case
of well development and production in the Southern Tier, existing natural gas workers currently
residing in Pennsylvania, for example, may simply choose to maintain their residency in
Pennsylvania and commute to work in New York.
In addition, actual population impacts may also be less than what is described in the following
section because some currently unemployed or underemployed local workers could be hired to
fill some of the construction and production positions, thereby, reducing the total in-migration to
the region.
The hiring of currently employed local workers (i.e., those workers that leave existing jobs to
work in the natural gas industry) is not expected to reduce total in-migration to the regions as it is
assumed that the jobs these local workers are leaving would need to be filled. Given the finite
number of workers in the regional labor force, any growth in the total number of jobs available in
regional economies not filled by currently unemployed or underemployed persons would lead to
in-migration to the areas.
The following additional assumptions were used to project population impacts:
•

The majority of construction jobs and related population migration to the regions would
be temporary and transient in nature in the beginning of the well development phase. As
well construction continues, these jobs would gradually be filled by permanent residents.

•

Transient construction workers are assumed to temporarily relocate to the region for a
short-duration and are assumed to not be accompanied by their households. Permanent
construction workers are assumed to relocate to the region for the duration of the well
development phase and would be accompanied by their entire households.

•

Production jobs and related population migration to the regions would be permanent and
entire households would relocate to the regions.

•

Natural gas development and production would not “crowd out” employment in other
unrelated industrial sectors, and employment in these sectors would remain unchanged.

Final SGEIS 2015, Page 6-235

 •

Job vacancies created when local employees leave existing industries to take jobs in the
natural gas extraction industry would be filled.

•

The 2010 average household sizes in New York State (2.64 persons per household),
Region A (2.47 persons per household), Region B (2.52 persons per household), and
Region C (2.49 persons per household) were used in estimating the population impacts
associated with permanent construction and production jobs (USCB 2010).

•

There would be no involuntary displacement of persons due to construction of the natural
gas wells, as no buildings would be demolished to make way for wells and wells need to
be drilled at least 500 feet away from private wells and 100 feet from inhabited
dwellings.

6.8.2.1 New York State
Both transient and permanent population impacts are expected to occur as a result of natural gas
well construction. Given the highly specialized nature of natural gas construction, workers with
the skills required to complete a high-volume hydraulic fracturing operation would not be
currently available in New York State or in the representative regions. If high-volume hydraulic
fracturing operations were to begin in New York State, most of the skilled workers would
initially need to be recruited from outside the state and would be both temporary and transient in
nature.
As the industry matures and as more natural gas development occurs in the state and
representative regions, more local persons would acquire the requisite skills needed for these
jobs, and recruitment from within the existing labor force would therefore increase. Also, as the
industry expands and development becomes more assured, the incentive for previously transient
workers to become permanent residents within the state or representative regions would increase.
Therefore, it would be expected that eventually there would be a decline in the number of
transient construction workers and an increase in the number of permanent construction workers.
In an effort to estimate the mix of transient and permanent construction workers, data collected
by the Marcellus Shale Education and Training Center on the occupational composition of the
natural gas workforce and data from the U.S. Bureau of Economic Analysis’ 2008 National
Employment Matrix were used to help forecast the amount of local labor that would be
employed in natural gas well development (Marcellus Shale Education and Training Center
2009; U.S. Bureau of Economic Analysis 2011e). Initially no more than 23% of the construction

Final SGEIS 2015, Page 6-236

 workforce is expected to be hired locally. Due to New York State’s small existing natural gas
industry, the remaining 77% of the workforce would have specialized skills that would most
likely be unavailable among New York’s labor force in Year 1. Given the newness of the
industry, it is assumed that, in Year 1, 77% of the total workforce would be transient workers
from outside the state.
As the natural gas industry matures the number of qualified workers in the state and
representative regions would increase. This pool of qualified workers would expand as existing
local residents gain the requisite skills and/or formerly transient workers permanently relocate to
the state or representative regions. The total number of transient construction workers would
gradually increase as the rate of well development increased until Year 10 when the maximum
number of transient construction workers under both development scenarios is reached. From
Years 11 to 30 the transient population would gradually decrease as a proportion of the total
construction workforce. By Year 30 it is assumed that the natural gas industry would be
sufficiently mature that 90% of all workers could be hired locally. Table 6.37 shows the
transient, permanent, and total construction employment for select years. See the Economic
Assessment Report for a more detailed discussion of how these figures were derived.
Table 6.37 - Transient, Permanent and Total Construction Employment Under Each
Development Scenario for Select Years: New York State (New August 2011)

Low Scenario

Year
1
5
10
15
20
25
30

Transient
342
1,517
2,409
1,759
1,181
740
441

Permanent
97
693
1,999
2,649
3,227
3,668
3,967

Average Scenario
Total
Construction
Employment
439
2,210
4,408
4,408
4,408
4,408
4,408

Transient
1,370
6,051
9,639
7,038
4,725
2,959
1,763

Permanent
389
2,766
7,995
10,596
12,909
14,675
15,871

Total
Construction
Employment
1,759
8,817
17,634
17,634
17,634
17,634
17,634

Since the natural gas wells are expected to stay in operation for 30 years, production workers are
assumed to be permanent workers who reside close to where the wells are located. Thus, these
workers would live in or relocate their families to the area. Wells drilled in Year 1 are expected

Final SGEIS 2015, Page 6-237

 to remain in operation until Year 30; wells drilled in Year 30 would remain in operation until
Year 60.
It is assumed that the households of permanent construction workers and production workers
would, on average, be the same size as existing New York households (i.e., 2.64 persons,
including the single worker). Therefore, in projecting population impacts, it is anticipated that
transient construction workers would be temporary residents unaccompanied by family
members, whereas permanent construction workers and all production workers would be
permanent residents accompanied by an average of 1.64 family members.
Based on the above assumptions, Table 6.38 displays, for New York State as a whole and for
each development scenario, the estimated transient and permanent populations resulting from
construction and production activities for Years 1, 10, 20, 30, 40, 50, and 59.
Table 6.38 - Estimated Population Associated with Construction and Production
Employment for Select Years: New York State (New August 2011)

Production
Year
1
10
20
30
40
50
591

Development
Scenario
Low
Average
Low
Average
Low
Average
Low
Average
Low
Average
Low
Average
Low
Average

Transient
Population
Construction
342
1,370
2,409
9,639
1,181
4,725
441
1,763
0
0
0
0
0
0

Permanent Population
Construction
256
1,026
5,277
21,107
8,519
34,080
10,473
41,898
0
0
0
0
0
0

Production
18
74
1,019
4,079
2,872
11,492
4,726
18,905
3,707
14,829
1,853
7,413
185
742

Total
275
1,100
6,296
25,186
11,392
45,572
15,198
60,803
3,707
14,829
1,853
7,413
185
742

Note:
1

Year 59 is used instead of Year 60 since it is assumed that all operational wells would cease production at the beginning of
Year 60.

Final SGEIS 2015, Page 6-238

 Under the low development scenario, between Years 10 and 30, it is projected that a maximum
of 4,408 construction workers would temporarily or permanently migrate into the areas. The
maximum transient construction workforce would occur in Year 10, with an estimated 2,409
transient workers. (During this same year, there would be 1,999 permanent workers relocating to
the area.) Under the average development scenario, between Years 10 and 30, it is projected that
a maximum of 17,634 construction workers would temporarily or permanently migrate to the
well construction areas. The maximum transient workforce would occur in Year 10, with an
estimated 9,639 transient workers. (During this same time period, there would be 7,995
permanent workers relocating to the area.) The population impact of the maximum number of
transient workers, 9,639 transient workers for the average development scenario, represents less
than 0.1% of the total present population of New York State, indicating that transient workers
would have only a minor short-term population impact at the state level.
Under the low development scenario, the number of persons permanently migrating to the
impacted areas to construct and operate the wells is projected to reach its maximum of 15,198
persons during Year 30 (see Table 6.39). Under the average development scenario during Year
30, it is projected that 60,803 persons would permanently migrate to the impacted areas. Since it
is assumed that permanent construction and production workers would relocate with their
households, these population estimates include the permanent construction and production
workers and members of their households. The maximum impact on the permanent population
under the average development scenario is 60,803 persons in Year 30. This figure represents
approximately 0.3% of the total present population of New York State, indicating that some
long-term population impact could occur at the state level as a result of the operation of the new
natural gas wells.

Final SGEIS 2015, Page 6-239

 Table 6.39 - Maximum Temporary and Permanent Impacts Associated with
Well Construction and Production: New York State (New August 2011)

Region

Total 2010
Existing
Population1

Development
Scenario

Maximum
Transient
Impacts2

New York
State

19,378,102

Low
Average

2,409
9,639

% Increase
Maximum
from Total
Permanent
Existing 2010
Impacts 3
Population
>0.1%
>0.1%

15,198
60,803

% Increase
from Total
Existing
2010
Population
>0.1%
0.3%

Notes:
1

Existing population from U.S. Census Bureau’s 2010 Census of Population (USCB 2010).

2

Maximum transient impacts occur during Year 10. For details on the population impacts for all other years, see Ecology and
Environment Engineering, P.C., 2011, Economic Assessment Report.

3

Maximum operational impacts occur during production year 30, when the number of producing wells is at a maximum. For
details on population impacts for all other years, see Ecology and Environment Engineering, P.C., 2011, Economic
Assessment Report.

According to the population projections developed by Jan K. Vink of the Cornell University
Program on Applied Demographics, the population of New York State is expected to increase by
1,037,344 persons over the next 20 years (i.e., by an average of approximately 52,000 persons
per year) (Cornell University 2009). Consequently, the maximum cumulative population impact
of 60,803 persons, which occurs during production year 30, is slightly more than one year’s
projected incremental population growth for New York State.
Although the maximum population impacts would be relatively minor at the level of the whole
state, natural gas wells would not be spread evenly across the state; they would be concentrated
in particular areas where the influx of construction workers and production workers and their
families may have more significant population impacts. Similarly, because new wells would not
be developed evenly over time due to swings in well development activity, the population
impacts would be greater in some years than in others.
In addition to direct employment (employment impacts from construction and production), there
are projected indirect employment impacts from the development of hydraulic fracturing
operations in the area underlain by the Marcellus and Utica Shales (see Section 6.8.1.1). Given
the relatively high unemployment rates currently being experienced in these regions, it is likely
that some of these new, indirectly created jobs (e.g., gas station clerks, hotel lobby personnel,

Final SGEIS 2015, Page 6-240

 etc.) would be filled by local, previously unemployed or underemployed persons. These indirect
employment impacts would reduce local unemployment and help stimulate the local economies.
The impacts associated with the influx of construction workers, both transient and permanent,
would last as long as wells are being developed in an area, whereas the impacts associated with
the production phase could last up to 60 years.
6.8.2.2 Representative Regions
Table 6.40, Table 6.41, and Table 6.42 show the estimated transient, permanent, and total
construction employment for Regions A, B, and C under the low and average development
scenario.
Table 6.40 - Transient, Permanent, and Total Construction Employment Under Each
Development Scenario for Select Years for Representative Region A (New August 2011)

Low Scenario

Year
1
5
10
15
20
25
30

Transient
171
758
1,205
880
591
370
220

Permanent
48
347
999
1,324
1,613
1,834
1,984

Average Scenario
Total
Construction
Employment
219
1,105
2,204
2,204
2,204
2,204
2,204

Transient
686
3,026
4,820
3,520
2,363
1,480
882

Permanent
194
1,383
3,998
5,298
6,455
7,338
7,936

Total
Construction
Employment
880
4,409
8,818
8,818
8,818
8,818
8,818

Table 6.41 - Transient, Permanent, and Total Construction Employment Under Each
Development Scenario for Select Years for Representative Region B (New August 2011)

Low Scenario

Year
1
5
10
15
20
25
30

Transient
79
349
554
405
272
170
101

Permanent
22
159
460
609
742
844
913

Average Scenario
Total
Construction
Employment
101
508
1,014
1,014
1,014
1,014
1,014

Transient
315
1,392
2,217
1,619
1,087
681
406

Final SGEIS 2015, Page 6-241

Permanent
89
636
1,839
2,437
2,969
3,375
3,650

Total
Construction
Employment
404
2,028
4,056
4,056
4,056
4,056
4,056

 Table 6.42 - Transient, Permanent, and Total Construction Employment Under Each
Development Scenario for Select Years for Representative Region C (New August 2011)

Low Scenario

Year
1
5
10
15
20
25
30

Transient
17
75
121
88
59
37
22

Permanent
5
35
100
133
162
184
199

Average Scenario
Total
Construction
Employment
22
110
221
221
221
221
221

Transient
69
303
482
352
236
148
88

Permanent
19
138
400
530
646
734
794

Total
Construction
Employment
88
441
882
882
882
882
882

Table 6.43 shows the maximum population impacts associated with transient and permanent
construction workers and permanent production workers for the three representative regions. As
noted above, the three representative regions were selected to assess the range of potential
socioeconomic impacts that could occur at the local and regional levels, and the projected local
and regional impacts presented here are intended to provide order-of-magnitude estimates for the
range of potential impacts. In constructing Table 6.43 it was assumed, as discussed above, that a
portion of the construction workers would be temporary, transient residents in an area and would
not be accompanied by members of their households. The remainder of the construction workers
would be permanent residents. The proportion of permanent workers to transient workers would
gradually increase over time. All production workers are assumed to be permanent residents and
would relocate their families to the area. Since the households of permanent construction and
production workers are assumed to be the same size as average households in their respective
regions, permanent workers are assumed to be accompanied by an average of 1.47 family
members in Region A, 1.52 family members in Region B, and 1.49 family workers in Region C.

Final SGEIS 2015, Page 6-242

 Table 6.43 - Maximum Temporary and Permanent Impacts Associated with
Well Construction and Production

Region
A

Total 2010
Existing
Population1
340,555

B

187,786

C

215,222

Development
Scenario
Low
Average
Low
Average
Low
Average

Maximum
Transient
Impacts2
1,205
4,820
554
2,217
121
482

% Increase
from Total
Existing
2010
Population
0.4%
1.4%
0.3%
1.2%
<0.1%
0.2%

Maximum
Permanent
Impacts 3
7,111
28,447
3,339
13,348
720
2,868

% Increase
from Total
Existing
2010
Population
2.1%
8.4%
1.8%
7.1%
0.3%
1.3%

Notes:
1

Existing population from US Census Bureau’s 2010 Census of Population (USCB 2010).

2

Maximum transient impacts occur during Year 10. For details on the population impacts for all other years, see Ecology and
Environment Engineering, P.C., 2011, Economic Assessment Report.

3

Maximum permanent impacts occur during production Year 30, when the number of producing wells is at a maximum. For
details on population impacts for all other years, see Ecology and Environment Engineering, P.C., 2011, Economic
Assessment Report.

The upper bound of the potential impacts is found in Region A under the average development
scenario, when in Year 10 there are projected to be 4,820 unaccompanied transient workers,
representing 1.4% of the region’s total population. The upper bound of the potential impacts
from permanent population changes can be found in Region A under the average development
scenario in Year 30, when 28,447 permanent construction and production workers and their
household members would be residing in the region. This figure represents 8.4% of the existing
population in Region A. According to the population projections presented in Section 2.3.11, in
the absence of gas well development, Region A is expected to experience a future population
decrease and to have a 2030 population of 279,675 persons, a decrease of 60,880 persons, equal
to 17.9% of the total existing population. The influx of workers and their family members
associated with gas well development, which totals 28,447persons in Year 30 under the average
development scenario, would offset approximately 47% of the projected population decline in
Region A and would, therefore, have a beneficial impact.
Under the average development scenario, Region B is projected to have a maximum of 2,217
unaccompanied, transient construction workers and 13,348 permanent construction and

Final SGEIS 2015, Page 6-243

 production workers and their family members residing in the region. Note that maximum
transient population impacts occur in Year 10, while the maximum permanent population
impacts occur in Year 30. The maximum transient population would account for 1.2% of the
existing population in Region B, and the maximum permanent population would account for
7.1% of the existing population, respectively. According to population projection figures
presented in Section 2.34.11, in the absence of gas well development, Region B is expected to
experience a future population decrease and to have a 2030 population of 183,031 persons, a
decrease of 4,755 persons, equal to 2.5% of the total existing population. The influx of workers
and their family members associated with gas well development, which totals 13,348 persons in
Year 30 under the average development scenario, would more than offset the projected
population decline in Region B but would not add significantly to the existing population.
The lowest maximum potential population impact is found in Region C under the low
development scenario, when in Year 10 only 121 unaccompanied, transient construction workers
are expected to reside in the region. Under the same development scenario 720 permanent
construction and production workers and their families would reside in Region C in Year 30,
representing a total of approximately 1.3% of the existing population. Note that maximum
transient population impacts occur in Year 10, while the maximum permanent population
impacts occur in Year 30. In contrast, under the average development scenario in Year 30,
Region C is projected to have a maximum of 482 unaccompanied, transient construction workers
and a maximum of 2,868 permanent construction and production workers and household
members in the region. The maximum transient population represents 0.2% of the existing
population, and the maximum permanent population represents 1.3% of the existing population.
According to population projection figures presented in Section 2.3.11, in the absence of gas
well development, Region C is expected to experience a future population decrease and to have a
2030 population of 188,752 persons, a decrease of 26,470 persons, equal to 12.3% of the total
existing population. The influx of permanent workers and their family members associated with
gas well development, totaling 2,868 persons in Year 30 under the average development
scenario, would offset more than 10% of the projected population decline in Region C and would
have a small-scale beneficial impact.

Final SGEIS 2015, Page 6-244

 Because natural gas wells would not be evenly distributed across the regions, there may be more
significant localized population impacts. Depending on the distribution of the wells and the
phasing of well development, which depends partly on the price of natural gas, shale gas
production may create localized growth in individual small towns. Also, because the
development of new wells would not be distributed evenly over time due to swings in well
development activity, downswings may cause periods of smaller-than-projected population
impacts, while upswings may cause larger-than-projected population impacts.
6.8.3

Housing

This section describes the potential impacts on housing resources and property values that could
result from the development of natural gas reserves in low-permeability shale in New York State.
Statewide and regional impacts are discussed separately in the following section. For the
purposes of this analysis, three representative regions were selected to examine the range of
potential regional impacts. This analysis in no way is meant to imply that impacts would occur
only in these three regions. Local- and regional-level impacts would occur wherever highvolume hydraulic fracturing wells are constructed. Currently, the actual locations of these wells
have not yet been determined, and wells could be sited anywhere there is low-permeability shale.
As described in previous sections, two development scenarios were analyzed for a 60-year
period. Only the impacts that would occur during maximum build-out conditions (Year 10 for
the transient workers and Year 30 for the permanent workers) are presented in this SGEIS.
Impacts for all other years are presented in the Economic Assessment Report.
6.8.3.1 New York State
As previously described in Section 6.8.1 (Economy, Employment, and Income), total
construction employment in New York State that would result from the development of lowpermeability natural gas reserves is projected to range from 4,408 new workers under the low
development scenario to 17,634 new workers under the average development scenario. Initially,
the majority of the construction workers are assumed to be temporary, transient workers. As the
natural gas fields are developed over time, it is assumed that an increasing number of these
workers would become permanent residents. Production employment is projected to range from
1,790 workers under the low development scenario to 7,161 workers under the average
development scenario.

Final SGEIS 2015, Page 6-245

 Table 6.44 presents estimates of the maximum temporary, transient employment that would
occur in Year 10 and the maximum permanent employment that would occur in Year 30.
Transient employment includes those construction workers who would only temporarily relocate
to the area during well construction. Permanent employment includes permanent construction
workers and permanent production workers, as discussed more fully in Section 6.8.2, Population.
Table 6.44 - Maximum1 Estimated Employment by Development Scenario
for New York State (New August 2011)

Development Scenario
Low
Average

Transient Employment (FTE)
2,409
9,639

Permanent2 Employment
(FTE)
5,757
23,032

1

Maximum transient employment occurs in Year 10, while maximum permanent employment occurs in Year 30.

2

Permanent employment includes both permanent construction and production employment.

Note: Maximum transient employment and maximum permanent employment are reached in two different years. Therefore, the
figures for transient employment and permanent employment in this table cannot be added to equal total employment. See
Ecology and Environment Engineering, P.C., 2011, Economic Assessment Report for year-by-year employment details.

Temporary Housing
The construction phase is expected to have a short-term impact on temporary housing resources
in New York State. New York State is currently not a major oil or gas producing state and,
therefore, does not have a large work force skilled in oil and natural gas extraction. Thus, it is
anticipated that workers specialized in gas exploration and drilling would travel into New York
from other states where gas exploration and drilling is more significant. In the beginning, much
of the workforce would need to be imported from other states. Over time, an experienced
workforce would be created within New York, and the need for out-of-state workers would
decline.
Typically, construction of a high-volume hydraulic fracturing well is completed in 3 to 4 months.
Therefore, the transient workers needed to drill these wells would likely only temporarily
relocate to a specific area, and once that well was completed they would move on to another site.
The influx of workers who would move from one well development site to another would
increase the demand for transient housing, such as rental properties and hotel/motel rooms,
thereby decreasing the rental and hotel/motel vacancy rates within the state. Decreased rental

Final SGEIS 2015, Page 6-246

 and hotel/motel vacancy rates would provide short-term economic benefits to some owners of
rental housing and hotels/motels within the state and in certain areas may increase prices charged
for these temporary housing units.
Table 6.45 identifies the total stock of rental housing units, the existing supply of vacant housing
units for rent, and the rental vacancy rate in New York State as a whole. Assuming a worst-case
scenario where each projected transient construction worker would require one rental-housing
unit, New York State as a whole could easily supply rental housing to construction workers
under all development scenarios with existing vacant units at maximum build-out. Therefore,
the impact on the supply of rental housing resources during the construction phase would be
negligible at the statewide level. Impacts at a the regional and local levels are discussed below.
Table 6.45 - New York State Rental Housing Stock (2010) (New August 2011)

Total Rental Inventory
3,632,743

For Rent
200,039

Rental Vacancy Rate (%)
5.5

Source: USCB 2010.

Permanent Housing
Some migration of workers into New York State would be expected to occur as a result of the
construction and production phase of the high-volume hydraulic fracturing operations. Initially,
there would not be enough workers specialized in gas production to meet the demand.
Therefore, it would be expected that these workers would move into New York State from states
where the natural gas extraction industry is more developed. However, over time, an
experienced workforce would be created within the state, and the need for out-of-state workers
would decline.
Table 6.46 identifies the existing supply of vacant housing units for sale or rent in New York
State. Seasonal, recreational, and occasional-use units and units rented or sold but not occupied
were not included in these totals. Assuming a worst-case scenario at maximum build-out, it is
anticipated that each projected permanent construction and production worker would require one
permanent housing unit. Given that assumption, New York State has more than enough houses

Final SGEIS 2015, Page 6-247

 for sale to provide permanent housing units to the new permanent workers. Therefore, the
impact on the supply of permanent housing units would be negligible at the statewide level.
Table 6.46 - Availability of Owner-Occupied Housing Units (2010) (New August 2011)

Total Number of Housing Units
8,108,103

For Sale
77,225

For Rent
200,039

Source: USCB 2010.

Based on the above discussion, it can be concluded that at the statewide level, New York State as
a whole has a more than sufficient supply of rental properties and housing units to cope with the
additional workers employed under each of the development scenarios at maximum build-out in
Year 30. Regional and local impacts are discussed below.
6.8.3.2 Representative Regions
Table 6.47 identifies the maximum transient and permanent employment in Regions A, B, and C.
See Section 6.8.1 and 6.8.2 for a detailed discussion of the derivation of these numbers.
Table 6.47 - Maximum Transient and Permanent Employment by
Development Scenario and Region (New August 2011)

Region
Region A
Low
Average
Region B
Low
Average
Region C
Low
Average

Maximum Transient Employment (in
FTE)1

Maximum Permanent
Employment2

1,205
4,820

2,879
11,517

554
2,217

1,325
5,297

121
482

289
1,152

1

Maximum transient employment occurs in Year 10.

2

Maximum permanent employment occurs in Year 30 and includes both permanent construction and production employment.

Note: Maximum transient employment and maximum permanent employment are reached in two different years. Therefore, the
figures for transient employment and permanent employment in this table cannot be added to equal total employment. See
Ecology and Environment Engineering, P.C., 2011, Economic Assessment Report, for year-by-year employment details.

Final SGEIS 2015, Page 6-248

 Temporary Housing
The construction phase would be expected to have a short-term, mixed impact on the rental
housing stock in the representative regions. As described above, given the short-term nature of
well construction, it is unlikely that many of the construction workers would initially
permanently relocate to the region. However, as the natural gas development industry developed
in the region and long-term employment became more likely, more construction workers would
choose to permanently relocate to the regions.
In most cases, transient construction workers would temporarily reside in nearby population
centers and commute to the development sites. Once the well is completed, they would move on
to another area. The influx of a large number of transient construction workers into these regions
would be expected to increase the demand for temporary housing, such as rental properties,
hotel/motel rooms, and RV camp sites, thereby decreasing rental and hotel/motel vacancy rates
throughout the region. Decreased rental and hotel/motel vacancy rates are expected to provide
short-term economic benefits to some owners of rental housing and hotels/motels in these
regions, but it could also cause a shortage of temporary housing in the most affected areas. The
increase in demand may also increase the price charged for these units.
In areas of Pennsylvania where Marcellus shale drilling activity is occurring, it has been difficult
at times to accommodate the influx of new workers (Kelsey 2011). There have been reports of
large increases in rent in Bradford County, Pennsylvania, as a result of the influx of out-of-area
workers (Lowenstein 2010). There have also been “frequent reports” of landlords not renewing
leases with existing tenants in anticipation of leasing at higher rates to incoming workers, and
reports of an increased demand for motel and hotel rooms, increased demand at RV campsites
and increases in home sales (Kelsey 2011). Such localized increases in the demand for housing
have raised concerns about the difficulties caused for existing local, low-income residents to
afford housing (Kelsey 2011).
The impacts on temporary housing described above for Bradford County, while acute in the
short-term, may decline in the long-term as more workers establish permanent residences in the
area and as the market has time to respond to the shortage in temporary housing. As more

Final SGEIS 2015, Page 6-249

 hotel/motel rooms are constructed, and more rental properties become available, the shortages of
existing units would decline and subsequently rental prices would also decline.
As with the situation in areas in Pennsylvania undergoing early Marcellus shale development, it
is likely that most of the workers employed during the construction phase would relocate from
outside of Regions A, B, and C, as natural gas well exploration and drilling require specialized
skilled workers (Marcellus Shale Education and Training Center 2009).
Table 6.48 identifies the total rental inventory, the existing supply of vacant housing units for
rent, the rental vacancy rate, and the number of hotel/motel rooms in Regions A, B, and C.
Assuming a worst-case scenario, where each incoming temporary worker would require one
rental housing unit or hotel/motel room at maximum transient employment levels (Year 10),
Regions B and C have more vacant rental units than incoming workers under both scenarios.
Region A also has more hotel/motel rooms and vacant rental units than the number of incoming
workers under both development scenarios. However, the average development scenario would
utilize the majority (69.5%) of the rental properties and hotel/motel rooms in Region A, thereby,
causing shortages for the existing renters/ hotel users.
Table 6.48 - Availability of Rental Housing Units (New August 2011)

Region
Region A
Region B
Region C

Total Rental
Inventory
48,955
24,558
29,127

For Rent
3,824
2,604
2,624

Rental Vacancy Rate
(%)
7.8
10.6
9.0

Hotel/Motel
Rooms
3,110
3,705
1,987

Source: USCB 2009.

In Regions B and C under both development scenarios and in Regions A under the low
development scenario, the existing stock of rental housing is sufficient to meet the needs of
incoming workers; thus, no additional rental housing would need to be constructed. However,
rent increases caused by the increased demand for rental housing could make such housing
unaffordable for existing low-income tenants, and increased demand for hotel/motel rooms
would be likely to cause price increases in these sectors.

Final SGEIS 2015, Page 6-250

 Under the average development scenario, shortages of rental housing would likely occur in
Region A. The use of seasonal, recreational, or occasional use housing units as rental properties
could potentially reduce the impact of increased demand on rental housing in these regions.
However, it is likely that rents and hotel/motel room rates would remain elevated until additional
rental housing and motels/hotels were constructed to meet the higher level of demand. The
higher rents would negatively impact existing low-income residents, who may not be able to find
affordable rental housing within the regions. The higher motel/hotel rates and/or the fewer
available rooms may discourage some visitors from coming to these regions and thereby have the
potential to reduce tourism in those areas.
The above analysis was completed on a regional level and included all rental units in a two- or
three-county area. However, temporary housing impacts may occur and be more severe at an
even more local level. If several well pads were developed at the same the time in the same area,
there would be an even larger concentration of workers and a greater demand for temporary
housing in that immediate area and in the population centers located near the general vicinity of
the development. Although data on commuting patterns by occupation show that temporary
construction workers typically are willing to commute farther than other workers, there still
could be a significant increase in local housing demand. Therefore, the localized impacts in
areas where there is a high concentration of natural gas wells may be greater than those described
above.
Permanent Housing
The permanent construction and production workers are expected to have a long-term, mixed
impact on the permanent housing stock in the representative regions. Given the need to have
natural gas operators with specialized skills, many of the production workers would relocate
from areas outside the representative regions. New production workers recruited from outside
the region would typically be offered permanent employment and would likely require
permanent housing. In addition, as the natural gas industry expands in the representative regions
and the long-term construction employment becomes more permanent in the region, more
construction workers would choose to live permanently in the regions and simply commute
between well sites. These additional construction and production workers would increase the
demand for permanent housing. In addition, the increased economic activity that would take

Final SGEIS 2015, Page 6-251

 place in these regions as a result of natural gas development would further increase the demand
for permanent housing and reduce homeowner and rental vacancy rates in the region.
Table 6.49 identifies the number of vacant permanent housing units for sale or rent in Regions A,
B, and C. Seasonal, recreational, and occasional-use units and units rented or sold but not
occupied were not included in this table. The following analysis assumes a worst-case scenario
where all new permanent construction workers and all production workers would relocate to the
region and require one permanent housing unit each at maximum build-out (Year 30) to purchase
or rent. However, in actuality this may overstate the regional impacts. Many of the permanent
worker positions could be filled by currently unemployed or underemployed workers from the
local areas, thus reducing the overall demand for permanent housing.
Given this worse-case assumption, Regions A, B, and C would be able to absorb the additional
demand for permanent housing units under the low development scenario. Regions A, B, and C
would not be able to meet the increased demand for permanent housing units under the average
development scenario.
Table 6.49 - Availability of Housing Units (New August 2011)

Region
Region A
Region B
Region C

Total Number of
Housing Units
151,135
111,185
108,031

For Sale
1,516
1,989
1,278

For Rent
3,824
2,604
2,624

Source: USCB 2010.

No additions to the permanent housing stock would be required under the low development
scenarios in which regions could absorb additional demand for permanent housing. However, it
is expected that house prices would rise initially in response to the increased demand for
permanent housing, resulting in difficulties for low-income residents seeking to buy a home and
capital gains for owners of existing homes. In the long-term, additional housing construction
would take place and prices would level off as the supply of housing units caught up with the
demand for these units.

Final SGEIS 2015, Page 6-252

 Under the average development scenario in which regions do not have enough homes for sale or
rent to meet the potential demand from incoming permanent workers, the incoming workers and
existing residents would compete for the existing stock of permanent housing units, resulting in
an increase in housing prices. Over time, builders and landowners would respond to the higher
prices by constructing more permanent housing units. However, before such homes are
constructed, a period of particularly high prices would be expected. Low-income residents that
do not already own property or currently rent might face difficulties in finding affordable homes
to buy, and owners of existing homes would experience capital gains.
The above analysis was completed on a regional level and included all permanent housing units
in a two- or three-county area. Permanent housing impacts may occur and be more severe on a
more local level. If, for example, production workers are expected to report to only a few
centralized facilities, the demand for permanent housing near these facilities would be greater
than for the region as a whole. This may place a strain on the permanent housing stock in such
areas, and the impacts may be even greater than those described above.
6.8.3.3 Cyclical Nature of the Natural Gas Industry
The demand for housing, both temporary and permanent, would be expected to change over
time. The demand for housing would be the greatest in the period during which the wells in an
area are being developed, and demand would decline thereafter. This would create the
possibility of an excess supply of such housing after the well development period (Kelsey 2011).
If well development in a region occurs in some areas earlier than in others, then housing
shortages and surpluses may occur at the same time in different areas within the same region.
The natural gas market can be volatile, with large swings in well development activity.
Downswings may cause periods of temporary housing surplus, while upswings may exacerbate
housing shortages within the regions.
6.8.3.4 Property Values
At this level of analysis, it is impossible to predict the actual impacts of developing the
Marcellus and Utica shale natural gas reserves on individual property values. However, some

Final SGEIS 2015, Page 6-253

 predictions can be made with regard to the general impact of mineral rights on property values
and the impact of well development on adjacent properties.
Significant increases in property value are expected where the subsurface mineral rights and land
are held jointly with land ownership and the exploitation of the subsurface resources is not
limited in some way. Because the owners of subsurface mineral rights typically receive royalty
payments equal to or greater than 12.5% of the total value of production, the development of
natural gas reserves would be expected to substantially increase the value of their property.
Properties where the mineral rights are not held jointly with land ownership, or where there is
some restriction on drilling, would not experience this increase in value.
Property values could also be affected by the impacts associated with developing natural gas
resources. Gas well development could impact local environmental resources and cause noise
and vibration impacts, and trucks servicing the well development could also impact the
surrounding areas. Once wells are in place, the local impacts would be less and there would be
much less traffic moving to and from the wells. Pipelines would be constructed to carry the
natural gas from the wells. Construction of the pipelines would have an impact on the landscape
and would result in the maintenance of cleared rights-of-way once the pipeline is in place. Gas
compressor stations would also be constructed to maintain the pressure of the gas in the
pipelines, and there would be noise and air emissions associated with their operation.
It is possible that these various impacts, particularly those associated with the construction phase,
could reduce the value of properties close to the wells relative to similar properties not located
close to wells. In order to assess the potential impact these negative externalities would have on
property values in the affected regions, a review of economic literature was undertaken. A
number of studies have been conducted to provide quantitative estimates of the impact of wells
on property values. These studies are discussed and reviewed below. As with much economic
and econometric literature, the following studies are based on data gathered for specific
geographical locations at specific times. While the findings of these studies are analogous to the
current situation discussed in this SGEIS, the findings should only be used as an indication of
direction and the magnitude of possible impacts on property values. Characteristics of individual
housing markets and the nature of the gas development activities would vary dramatically from

Final SGEIS 2015, Page 6-254

 site to site, thus the findings in the following reports should not be viewed as an actual estimate
of impacts. BBC Research and Consulting (2001) examined the impact of coal bed methane
wells on property values in La Plata County, Colorado, between 1989 and the first half of 2000.
The authors used a hedonic approach (i.e., an approach that links property values to their
attributes and the attributes of surrounding areas) to estimate the impact of having a well on a
property and having a well near to, but not on, a property. The authors found that having a well
on a property was associated with a 22% reduction in the value of the property; that having a
well within 550 feet of a property increased its value; and that having a well located between 551
feet and 2,600 feet from a property had a negative impact on a property’s value. The authors
attributed the positive impact on property values of having a well located within 550 feet of a
property to the prevention of further gas well development in that area due to a spacing order and
setback conditions that prevented well drilling close to existing wells (BBC Research and
Consulting 2001).
Boxall, Chan, and McMillan (2005) examined the impact of small to medium size oil and gas
production facilities on rural residential property values using data from central Alberta, Canada.
In this study, the authors found a statistically significant negative relationship between property
values and the presence of oil and gas facilities within approximately of 2.5 miles of rural
residential properties. The presence of oil and gas facilities within 2.5 miles of rural residential
properties was estimated to reduce property values between 4% and 8%, with the potential to
double the impact, depending on the level and composition of the nearby industry activities
(Boxall et al. 2005).
Integra Realty Resources (2011) conducted a study of the impact of natural gas wells on property
values in and around Flower Mound, a community approximately 28 miles northwest of
downtown Dallas, Texas, where gas drilling is a recent development. The authors used four
methods to estimate the impact of wells on property values: (1) examining the relationship
between distance to a well site and property values; (2) comparing the sales prices of properties
close to a well and comparable properties not close to a well; (3) a statistical analysis of the
relationship between property attributes, including proximity to a well and values; and (4)
surveying market participants (principally realty agents). With regard to the relationship
between the distance between properties and well sites, they found that within Flower Mound

Final SGEIS 2015, Page 6-255

 itself there was a negative impact on property values when houses are immediately adjacent to
well sites; however, this negative impact diminishes quickly with increasing distance from the
well. The impact was found to be between -2% and -7% of property values. The results of the
comparable sales analysis indicated that, in most cases, there was little correlation between
proximity to a well site and property values. However, within Flower Mound itself and for
properties in excess of $250,000 in selling price, proximity to a well had a negative impact of
between -3% and -14% on property values. The statistical analysis found no statistically
significant relationship between property values and proximity to a well site. Finally, market
participants reported that proximity to a well site had an impact on the time required to sell a
property; however, this impact was most pronounced during the actual process of well
development and diminished thereafter (Integra Realty Resources 2011).
Fruits (2005) studied the impact of the South Mist Pipeline Extension on residential property
values in Clackamas and Washington counties, Oregon. In his analysis, Fruits performed three
statistical tests using the hedonic housing price approach and found no statistically significant
impact from natural gas pipeline development on residential property values (Fruits 2005).
Palmer (2008) also looked at the impact of the South Mist Pipeline Extension on residential
property values in Clackamas and Washington counties, Oregon. Palmer, working on behalf of
Palomar Gas Transmission LLC, conducted a market study using data from 2004 to 2008 that
compared sales of properties along pipeline corridors with comparable sales of non-affected
properties. Palmer found no measurable impact on property values resulting from the
construction and operation of natural gas pipelines (Palmer 2008).
In conclusion, the above literature review suggests that being in proximity to a well could reduce
the value of a property, but that proximity to a gas pipeline might not reduce the value of a
property. The proposed natural gas development would have an overall regional effect of
increasing property values due to the expected in-migration of construction and operations
workers and the increased economic activity that would occur in the area. Likewise, properties
that still included unexploited sub-surface mineral rights would increase in value due to the
potential of receiving royalty payments. However, not all properties in the region would increase
in value, as residential properties located in close proximity to the new gas wells would likely

Final SGEIS 2015, Page 6-256

 see some downward pressure on price. This downward pressure would be particularly acute for
residential properties that do not own the subsurface mineral rights.
6.8.4

Government Revenue and Expenditures

This section discusses the potential fiscal impacts on state and local government entities that
would occur as a result of the proposed development of low-permeability shale natural gas
reserves. Impacts on major revenue sources for the state and local governments are discussed, as
are expected changes in state and local government expenditures that could occur as a result of
the use of the high-volume hydraulic-fracturing technique.
Given the uncertainty associated with the actual level of future development of these reserves,
the rate of extraction that would occur, and the actual geographic location where development
would take place, it is impossible to definitively quantify the fiscal impacts of this action.
However, some estimates have been made. These estimates should be viewed only as order-ofmagnitude estimates and not as actual revenue or cost projections.
6.8.4.1 New York State
The proposed high-volume hydraulic fracturing operations would have a significant positive
impact on revenues collected by New York State. Revenues in the state would increase directly
as a result of lease payments for natural gas development that would occur under state-owned
land and indirectly from an increase in tax revenues generated by the natural gas development
and the resulting increase in economic activity throughout the state. No surface access would be
granted for high-volume hydraulic fracturing operations on most state-owned lands. However,
the subsurface natural gas deposits under state-owned lands could be accessed by surface
operations located on privately owned lands. If the subsurface natural gas deposits under stateowned lands were extracted, New York State would receive lease payments and royalties for the
mineral rights.
Currently, New York State receives lease payments for any existing or planned natural gas
development on state-owned lands that are leased. These payments would also be received for
any new subsurface mineral rights that are leased and/or any new wells drilled in the lowpermeability shale that would access subsurface natural gas reserves under state-owned lands.

Final SGEIS 2015, Page 6-257

 Delay rentals (i.e., rental payments that are provided to the owner of the mineral rights before
drilling and production occurs) and bonus bid payments would accrue to the state when
developers first purchase the right to exploit the subsurface minerals under state-owned lands.
Royalty payments of 12.5% or more of gross revenues would also be provided to the state for
any natural gas reserves extracted from under state-owned lands.
At this point in the planning processes it is impossible to accurately assess the exact location
where these wells would be drilled and whether or not these wells would be located on private
lands that could access underground reserves under state-owned lands. Therefore, it is
impossible to estimate the total royalty and lease payments that would accrue to the state.
However, these payments are not expected to be large relative to the total New York State
budget. Currently, New York State receives approximately $746,000 in lease payments per year
for all oil and natural gas developments on state-owned lands.
The state would indirectly receive a significant increase in its revenue streams as a result of the
proposed drilling in low-permeability shale. As described in Section 6.8.1 (Economy,
Employment, and Income), high-volume hydraulic fracturing operations would increase
employment and income throughout the state. Up to $621.9 million to $2.5 billion in employee
earnings would be directly and indirectly generated per year at maximum build-out, depending
on the development scenario.
As a result, New York State would experience a large increase in its personal income tax
receipts. In 2008 the effective personal income tax rate for all taxpayers in New York State was
5.0%. If this tax rate were used for estimation purposes, at maximum build-out the state could
receive between $31 million and $125 million a year in personal income tax receipts, depending
on the level of development assumed.
In addition to the personal income tax, the state would also experience some increase in its
corporate tax receipts. Corporate income in the state would increase both directly, as the natural
gas developers profit from the extraction of the gas in the low-permeability shale, and indirectly
due to the resulting increase in economic activity in the state. However, given the many benefits
in the New York State tax code for energy companies, such as expensing, depletion and

Final SGEIS 2015, Page 6-258

 depreciation deductions, the taxable income from the natural gas industry would be greatly
reduced. In addition, New York State offers an investment tax credit (ITC) that could
substantially reduce most, if not, all of the net income generated by these energy development
companies. Also the sale of the natural gas generated by these companies may not take place in
New York and, therefore, may not be subject to New York State corporate tax (NYSDTF 2011a).
Other tax receipts would also increase. Revenues generated from sales and use tax would also
register an increase as industry purchased the materials needed to develop these natural gas
reserves that are not exempt from state and local sales tax. However, many of the materials
needed to construct these wells would be tax-exempt, including such things as piping, drill rigs,
service rigs, vehicles, tools and supplies, pollution control equipment, and services to real
property (NYSDTF 2011a).
The direct, indirect, and induced economic activity associated with the high-volume hydraulic
fracturing would further expand sales tax receipts as the new workers spend a portion of the
increased earnings in the state.
High-volume hydraulic fracturing operations would also result in some significant negative fiscal
impacts on the state. The increased truck traffic required to deliver equipment, supplies, and
water and sand to the well sites would increase the rate of deterioration of the state’s road
system. Additional capital outlays would be required to maintain the same level of service on
these roads for their projected useful life. Depending on the exact location of well pads, the state
may also be required to upgrade roads and interchanges under its jurisdiction in order to handle
the additional truck traffic. The potential increase in accidents and possible additional hazardous
materials spills resulting from the increased truck traffic also would require additional
expenditures. Finally, approval of transportation plans/permits would place additional
administrative costs on the New York State Department of Transportation.
Additional environmental monitoring, oversight, and permitting costs would also accrue to the
state. In order to protect human health and the environment, New York State would be required
to spend substantial funds to review permit applications, to ensure that permit requirements were
met, safe drilling techniques were used, and best available management plans were followed, and

Final SGEIS 2015, Page 6-259

 to enforce against violations. In addition, the state would experience administrative costs
associated with the review of well permit applications and leasing requirements, and
enforcement of regulations and permit restrictions. All of these factors could result in significant
added costs for New York State’s government.
6.8.4.2 Representative Regions
Development of the natural gas reserves would have a significant fiscal impact on local
governments wherever drilling would take place. These impacts would be both positive and
negative in nature. As described above, local government entities who take part in sales tax
revenue sharing schemes would experience a substantial increase in sales tax receipts as a result
of the additional economic activity that would occur within their jurisdictions. Local
government entities that receive proceeds from ad valorem property taxes would see significant
increases to their tax rolls and property tax receipts.
As described previously in Section 2.3.11.4, Government Revenues and Expenditures, producing
natural gas wells are taxable for ad valorem real property tax purposes in New York State.
Therefore, every new natural gas well operating in a local government’s jurisdiction would
increase that government’s tax base and the total assessed value of property.
In New York State, producing natural gas wells are taxed based on the value of their production
for ad valorem property tax purposes. Each year the New York State Office of Real Property
Tax Service determines the “unit of production value” for a region. This unit value is then
multiplied by the total amount of natural gas produced, and the state equalization rate is then
applied to determine the total assessed value of the natural gas well. Applicable property tax
rates are then applied to this assessed value to determine the ad valorem property tax levy. See
Section 2.3.11.4, Government Revenues and Expenditures, for more details.
Using the above-mentioned formula, an estimate of local property tax revenues can be generated
and extrapolated for each development scenario. Using industry estimates for the productivity of
horizontal and vertical high-volume hydraulic fracturing wells, the following property tax
analysis has been completed for Year 30, the year of maximum impact. See the Economic

Final SGEIS 2015, Page 6-260

 Assessment Report for a more detailed discussion of the methodology used to estimate property
tax impacts and to see data for other years.
In order to predict the change in property tax revenues that would result from the proposed
development of the low-permeability shale natural gas reserves, annual production of the wells
was forecasted. Many factors affect the annual production of a natural gas well. Typically,
production initially starts out at a maximum level and then declines quickly until it reaches a
slower rate of decline. Production then continues at this lower level for approximately 30 years.
Horizontal high-volume hydraulic-fracturing wells produce more natural gas than vertical highvolume hydraulic-fracturing wells. This discrepancy has been accounted for in the analysis. For
a more detailed description of projected production levels, see the Economic Assessment Report.
For the purposes of this analysis, the 2010 unit of production value for the Medina formation was
used to estimate the real property tax payments of a representative horizontal high-volume
hydraulic fracturing well in Broome County. When the Marcellus Shale and Utica Shale
reserves are developed in New York State, specific unit of production values would be
developed for that specific formation and the specific drilling techniques used in that formation.
Depending on the results of that analysis, the unit of production value could vary substantially
from the Medina values utilized in this report. Table 6.50 shows the estimated annual real
property tax payments for a typical high-volume hydraulic-fracturing horizontal well in Broome
County in each year of its operational life using the Medina formation unit of production value.
See the Economic Assessment Report for additional examples.

Final SGEIS 2015, Page 6-261

 Table 6.50 - Example of the Real Property Tax Payments From a Typical
Horizontal Well (New August 2011)

County:
2010 Final Gas Unit of Production Value
2010 Overall Full-Value Tax Rate1

Broome
$11.19
35.5

Annual
Production
Production (millions of cubic
Assessed Value of
Year
feet)
Production2
Property Tax Payment3
1
803.00
$8,985,570
$318,988
2
354.05
$3,961,820
$140,645
3
258.00
$2,887,020
$102,489
4
201.43
$2,253,946
$80,015
5
165.93
$1,856,701
$65,913
6
144.50
$1,616,955
$57,402
7
130.00
$1,454,700
$51,642
8
119.00
$1,331,610
$47,272
9
109.93
$1,230,061
$43,667
10
103.20
$1,154,850
$40,997
11
98.04
$1,097,107
$38,947
12
93.14
$1,042,252
$37,000
13
88.48
$990,139
$35,150
14
84.06
$940,633
$33,392
15
79.86
$893,601
$31,723
16
75.86
$848,921
$30,137
17
72.07
$806,475
$28,630
18
68.47
$766,151
$27,198
19
65.04
$727,844
$25,838
20
61.79
$691,451
$24,547
21
58.70
$656,879
$23,319
22
55.77
$624,035
$22,153
23
52.98
$592,833
$21,046
24
50.33
$563,191
$19,993
25
47.81
$535,032
$18,994
26
45.42
$508,280
$18,044
27
43.15
$482,866
$17,142
28
40.99
$458,723
$16,285
29
38.94
$435,787
$15,470
30
37.00
$413,997
$14,697
Total Property Tax Payments for the Productive Life of the Well
$1,448,735
Sources: NYSDTF 2011b, 2011c, 2011d, 2011e; All Consulting 2011.
Notes:
1

Full-value tax rates are tax rates that have been already been equalized. Therefore, these numbers should not be multiplied
by the state equalization rate.

2

Calculated as Annual Production multiplied by 1,000 (to calculate the number of 1,000s of cubic feet) multiplied by the
2010 Final Gas Unit of Production Value (applied to each 1,000 cubic feet).

3

Calculated as Assessed Value multiplied by the Overall Full-Value Tax Rate divided by 1,000.

Final SGEIS 2015, Page 6-262

 In estimating real property tax payments for vertical high-volume hydraulic fracturing wells it
was initially assumed that each well would produce at the same average level of production as
existing wells (in 2009) in the region. However, average annual production for existing wells in
Region A was approximately 317.9 million cubic feet per year. This figure was deemed to be
too optimistic, so a figure of 90 million cubic feet per year was used instead for Region A
production. The 90 million cubic feet per year corresponds to production levels of vertical wells
currently operating in the Marcellus formation in Pennsylvania (NYSDEC 2011). Region B
currently has no producing natural gas wells, and its Marcellus and Utica Shale formations are
similar to those found in Region A (NYSDEC 2011). Therefore, a production level of 90 million
cubic feet per year was also used for Region B. In contrast, due to the geological characteristics
of Region C, high-volume hydraulic fracturing vertical wells are not anticipated to have the same
level of production as in Region A or Region B. High-volume, hydraulic fracturing vertical
wells in Region C are anticipated to have production levels similar to other vertical wells
currently operating in the region (NYSDEC 2011). Therefore, in Region C it is assumed that
each well would produce at the same average level of production as existing wells (in 2009) in
the region.
Table 6.51 shows the estimated annual real property tax payment from a typical vertical well.
The example uses the overall full-value tax rate, which averages the property tax levies in
Broome County from all taxing jurisdictions, including county, town, village, school district, and
other taxing districts, and the 2010 Medina formation unit of production value. As described
previously, once Marcellus Shale or Utica Shale formations become developed in New York
State, specific unit of production values would be developed for that specific formation and the
specific drilling techniques used in that formation. Depending on the results of that analysis, the
unit of production value could vary substantially from the Medina values utilized in this report.

Final SGEIS 2015, Page 6-263

 Table 6.51 - Example of the Real Property Tax Payments from a Typical Vertical Well (New August 2011)

Broome
$11.19
35.5
90
$1,007,100
$35,752

County:
2010 Final Gas Unit of Production Value
2010 Overall Full-Value Tax Rate
Annual Production (millions of cubic feet)
Assessed Value of Production of Well1
Annual Property Tax Payment2
Source: NYSDTF 2011b, 2011c, 2011d, 2011e; NYSDEC 1994-2006, 2007b, 2008, 2009.
Notes:
1

Calculated as Annual Production multiplied by 1,000 (to calculate the number of 1,000s of cubic feet) multiplied by the
Final Gas Unit of Production Value (applied to each 1,000 cubic feet).

2

Calculated as Assessed Value of Production of Well multiplied by the Overall Full-Value Tax Rate divided by 1,000.

As shown on Table 6.52, the projected change in total assessed value and property tax receipts
that would result under any of the development scenarios would be significant. Annual property
tax receipts at the peak production year (Year 30) would range from $9.1 million in Chautauqua
County to $77.5 million in Broome County under the low development scenario. For Year 30,
annual property tax receipts under the average development scenario would range from $35.4
million in Chautauqua County to $309.3 million in Broome County, and annual property tax
receipts under the high development scenario would range from $53.1 million in Chautauqua
County to $460.0 million in Broome County (see Table 6.52).
Table 6.52 - Projected Change in Total Assessed Value and Property Tax
Receipts1 at Peak Production (Year 30), by Region (New August 2011)

Low Development Scenario
Change in
Total Property
Assessed Value
Tax Receipts
($ million)
($ million)
Region A
Broome County
Chemung County
Tioga County
Total Region A
Region B
Delaware County
Otsego County
Sullivan County
Total Region B

Average Development Scenario
Change in
Total Property
Assessed Value
Tax Receipts
($ million)
($ million)

$3,345
$1,930
$2,458
$7,732

$119
$66
$76
$261

$13,342
$7,700
$9,803
$30,845

$474
$264
$302
$1,040

$1,498
$1,040
$1,006
$3,544

$32
$20
$26
$78

$5,996
$4,164
$4,024
$14,184

$127
$82
$105
$314

Final SGEIS 2015, Page 6-264

 Low Development Scenario
Change in
Total Property
Assessed Value
Tax Receipts
($ million)
($ million)
Region C
Cattaraugus County
Chautauqua County
Total Region C
Total Regions A, B,
and C

$406
$329
$735
$42,856

Average Development Scenario
Change in
Total Property
Assessed Value
Tax Receipts
($ million)
($ million)

$14
$11
$25
$364

$1,583
$1,283
$2,866
$47,895

$56
$41
$97
$1,451

Source: NYSDTF 2011b, 2011c, 2011d, 2011e.
1

Property tax receipts are calculated using the overall full-value tax rate for each county. Therefore, the property tax receipts
figure estimates property taxes collected from all levels of government, including county, town, village, school district, and
other special taxing districts.

Note: Totals may not sum due to rounding.

The increase in ad valorem property taxes would have a significant positive impact on the
finances of local government entities. While these figures are not directly comparable to the
current county revenues and expenditures data presented in Section 2.3.11.4, Government
Revenue and Expenditures, the figures can be used to show the order of magnitude of these
impacts. The total property tax receipts shown above were calculated using the overall full-value
tax rate, meaning the impact figures presented above include town, village, school district, and
other special taxing districts revenue as well county property tax receipts.
In addition to the positive fiscal impacts discussed above, local governments would also
experience some significant negative fiscal impacts resulting from the development of natural
gas reserves in the low-permeability shale. As described in previous sections, the use of highvolume hydraulic-fracturing drilling techniques would increase the demand for governmental
services and thus increase the total expenditures of local government entities. Additional road
construction, improvement, and repair expenditures would be required as a result of the
increased truck traffic that would occur. Additional expenditures on emergency services such as
fire, police, and first aid would be expected as a result of the increased traffic and construction
and production activities. Also additional expenditures on public water supply systems may also
be required. Finally, if substantial in-migration occurs in the region as a result of drilling and
production, local governments would be required to increase expenditures on other services, such

Final SGEIS 2015, Page 6-265

 as education, health and welfare, recreation, housing, and solid waste management to serve the
additional population.
6.8.5

Environmental Justice

As described in previous sections, there is potential for some localized negative impacts to occur
as a result of allowing high-volume hydraulic fracturing. Therefore, implementation of such
projects could have localized negative impacts on environmental justice populations if the
projects are sited in identified environmental justice areas. However, specific project site
locations have not been selected at this time.
Currently, natural gas well permit applications are exempt from requirements in NYSDEC
Commissioner Policy 29, Environmental Justice and Permitting (CP-29); therefore, additional
environmental justice screening would not be required for individual well permit applications.
However, some of the auxiliary permits/approvals that would be needed prior to well
construction may require environmental justice screening.
When necessary, project applicants would determine whether the proposed project area is urban
or rural and would perform a geographic information system (GIS)-based analysis at the census
tract or block group level to identify potential environmental justice areas. If a potential
environmental justice area is identified by the preliminary screening, additional community
outreach activities would be required.
6.9

Visual Impacts 402

The visual impacts associated with vertical drilling in the Marcellus and Utica Shales would be
similar to those discussed in the 1992 GEIS (NYSDEC 1992). Horizontal drilling and highvolume hydraulic fracturing are, in general, similar to those discussed in the 1992 GEIS
(NYSDEC 1992), although changes that have occurred in the industry over the last 19 years may
affect visual impacts. These visual impacts would typically result from the introduction of new
landscape features into the existing settings surrounding well pad locations that are inconsistent
with (i.e., different from) existing landscape features in material, form, and function. The

402

Section 6.9, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011, and was adapted by
the Department.

Final SGEIS 2015, Page 6-266

 introduction of these new landscape features would result in changes to visual resources or
visually sensitive areas and would be perceived as negative or detrimental by regulating agencies
and/or the viewing public.
The visual impacts of horizontal drilling and high-volume hydraulic fracturing would result from
four general on-site processes associated with the development of viable well locations:
construction, well development (drilling and fracturing), operation or production, and postproduction reclamation. The greatest visual impacts would be associated with the construction
of well pads and associated facilities, which would create new long-term features within
surrounding landscapes, and well drilling and completion activities at viable well locations,
which would be temporary and short-term in nature. Additional off-site activities could also
result in visual impacts, including the presence of increased workforce personnel and vehicular
traffic, and the use of existing or development of new off-site staging areas or contractor/storage
yards.
The visual impacts of horizontal drilling and hydraulic fracturing would vary depending on
topographic conditions, vegetation characteristics, the time of year, the time of day, and the
distance of one or more well sites from visual resources, visually sensitive areas, or other visual
receptors.
6.9.1

Changes since Publication of the 1992 GEIS that Affect the Assessment of Visual Impacts

A number of changes to equipment and drilling procedures since the 1992 GEIS have the
potential to result in visual impacts over a larger surrounding area and/or visual impacts over a
longer period of time. These changes can generally be separated into three categories: changes
in equipment and drilling techniques; changes in the size of well pads; and changes in the nature
and duration of drilling and hydraulic-fracturing activities.
6.9.1.1 Equipment and Drilling Techniques
The 1992 GEIS stated that drill rigs ranged in height from 30 feet for a small cable tool rig to
100 feet or greater for a large rotary rig. By comparison, the rigs currently used by the industry
for horizontal drilling can be 140 feet or greater in height and have more supporting equipment.
While a substantial amount of on-site equipment, including stationary tanks, compressors, and

Final SGEIS 2015, Page 6-267

 trucks, would be periodically present at each site during specific times of well development
(drilling and fracturing), the amount of necessary on-site equipment during these times is similar
to that addressed in the 1992 GEIS.
6.9.1.2 Changes in Well Pad Size and the Number of Water Storage Sites
The typical area that would undergo site clearing for an individual well pad has increased since
1992, from approximately 2 acres per site to an average of approximately 3.5 acres per site. The
pad size was increased to accommodate the necessary on-site equipment for drilling and
hydraulic-fracturing activities and to accommodate drill sites with multiple well pads. Since
multiple wells can be drilled from the same pad, this change has resulted in fewer, but larger
pads.
In addition, separate large areas for water storage are often developed in the vicinity of well pad
sites. These areas look somewhat similar to well pads because of their overall size and because
of the presence of specific types of equipment (primarily tanks and trucks). However, they may
contain specific landscape features associated with water procurement or storage features,
including large graveled areas for truck traffic, water impoundment areas, and water storage
tanks that are positioned on-site as needed.
6.9.1.3 Duration and Nature of Drilling and Hydraulic-Fracturing Activities
Since 1992 there have been a number of changes in the duration of drilling and hydraulic
fracturing. In the 1992 GEIS, drilling time was described as an approximately one- to two-week
or longer period, and there was no mention of the time required for hydraulic fracturing (NTC
2011). Currently, to complete a horizontal well takes 4 to 5 weeks of drilling, including
hydraulic fracturing.
Since 1992 the industry has been trending, where possible, toward the development of multi-well
pads rather than single-well pads. Multi-well pads are slightly larger, but the equipment used is
often the same. Based on current industry practice, a taller rig (170 feet in total height) with a
larger footprint and substructure may be used to drill multiple wells from a single pad. In some
instances, smaller rigs may be used to drill the initial hole and conductor casing to just above the
kick-off point, the depth at which a vertical borehole begins to turn into a horizontal borehole.

Final SGEIS 2015, Page 6-268

 The larger rig is then used for the final horizontal portion of the hole. Typically, one or two
wells are drilled and the rig is then removed.
If the well(s) are productive, the rig is brought back and the remaining wells are drilled and
stimulated by the injection of hydraulic fracturing additives. There is the possibility that all
wells on a pad would be drilled, stimulated, and completed consecutively, reducing the duration
of visual impacts that would occur during drilling and hydraulic-fracturing activities. However,
state law requires that all wells on a multi-well pad be drilled within three years of starting the
first well (NTC 2011).
6.9.2

New Landscape Features Associated with the Different Phases of Horizontal Drilling and

Hydraulic Fracturing
This section discusses the various visual impacts that may be associated with on-site horizontal
drilling and high-volume hydraulic fracturing activities during the construction, development
(drilling and fracturing), production, and reclamation phases. Visual impacts would occur in the
vicinity of the different sites associated with horizontal drilling and hydraulic fracturing, such as
at well pads, water impoundment and extraction sites, and the large equipment that may be
present on these sites (e.g., drilling rigs), as well as at the locations of off-site areas such as
contractor/equipment storage yards and staging areas, pipeline and compressor station locations,
gravel pits, and disposal areas (Rumbach 2011). Additional off-site activities that may result in
impacts on visual resources or visually sensitive areas during one or more of these phases are
discussed in Section 6.9.3.
6.9.2.1 New Landscape Features Associated with the Construction of Well Pads
New landscape features that would be associated with the construction of well sites include open,
level areas averaging approximately 3.5 acres in size that would serve as the well pad;
construction equipment, including bulldozers, graders, backhoes, and other large equipment to
construct level areas using clearing, cutting, filling and grading techniques; trucks for hauling
equipment and materials; and worker vehicles. Newly created sites would appear as open, level
areas with newly exposed earthen areas, albeit mulched or otherwise protected for erosion
control, similar to the appearance of the construction activities for a water impoundment area as
shown in Photo 5.22 in Section 5.7.2.

Final SGEIS 2015, Page 6-269

 Photo 6.1 below shows a well site where wells have already been drilled and completion
operations are underway. The photograph shows evidence of grading, cutting, and filling
activities; the use of gravel for site preparation; and mulching along an earthen embankment to
prevent erosion—all activities implemented during construction activities. A portion of a newly
created linear right-of-way for a connecting pipeline is shown on the hillside in the background
of the photo. The red and blue tanks shown in Photo 6.1 are discussed in greater detail in
Section 6.9.2.2.
Photo 6.1 - A representative view of completion activities at a recently
constructed well pad (New August 2011)

Photo 6.2 below shows the same recently constructed well pad that is currently under
development, but from a different angle. In the foreground of the photograph below, the newly
created access road leading to the well pad is shown. Erosion control measures and materials are
also shown in the photograph, including channeling, gravel fill and hay bales in the channel, and
mulching on topsoil or spoil piles to the left of the access road to minimize erosion. Additional

Final SGEIS 2015, Page 6-270

 views of access roads are presented in Photos 5.1 through 5.4 in Section 5.1.1 and in Photo 6.2.
Tanks, vehicles, and other equipment are discussed in greater detail in Section 6.9.2.2.
Photo 6.2 - A representative view of completion activities at a recently constructed well
pad, showing a newly created access road in foreground (New August 2011)

If water impoundment sites are necessary, they would be located in the same general area as well
sites, approximately the same size as a well site, and also be generally level. However, they
would also contain one or more large earthen embankments encircling plastic-lined ponds. See
Photo 6.3 below. Photos 5.20 and 5.22 in Section 5.7.2 contain additional representative views
of water impoundment sites.

Final SGEIS 2015, Page 6-271

 Photo 6.3 - A representative view of a newly constructed water impoundment area (New August 2011)

If water procurement sites are necessary, such sites would be located near water withdrawal
locations (typically rivers or other large sources of water) and would consist of large, newly
created graveled areas sufficiently sized for tanker truck use and equipped with on-site water
pumps and metering equipment, as shown in Photo 6.4. Photos 5.19a and 5.19b in Section 5.7.2
contain additional representative views of water procurement sites.
Photo 6.4 - A representative view of a water procurement site (New August 2011)

Final SGEIS 2015, Page 6-272

 Additional areas associated with the construction of well sites would include newly created
access roads and pipeline rights-of-way for connector pipelines (see Photo 6.1 and Photo 6.2).
These sites would typically be narrow, linear features, as opposed to the large open areas needed
for well pads and water impoundment or procurement sites.
6.9.2.2 New Landscape Features Associated with Drilling Activities at Well Pads
New landscape features that would be associated with drilling activities include drill rigs of
various heights and dimensions, including the rotary rigs as described in the 1992 GEIS, with
heights ranging from 40 to 45 feet for single rigs and 70 to 80 feet for double rigs. Currently, the
industry also uses triple rigs that can be more than 100 feet in height. As discussed in Section
5.2.1, only the rig used to drill the horizontal portion of the well is likely to be significantly
larger than what is described in the 1992 GEIS. This rig may be a triple, with a substructure
height of about 20 feet, a mast height of about 150 feet, and a surface footprint of about 14,000
square feet, which would include auxiliary equipment. Auxiliary equipment would include onsite tanks for holding water, fuel, and drilling mud; generators; compressors; solids control
equipment (shale shaker, de-silter, desander); a choke manifold; an accumulator; pipe racks; and
the crew’s office space.
Photo 6.16, Photo 6.17, and Photo 6.20 show what a typical well pad may look like during the
drilling of wells at a well pad. These photos show the industrial appearance of the well pad
during the drilling phase, which would appear dramatically different from the pad’s surrounding
setting for the approximately 4- to 5-week duration of drilling activities.
6.9.2.3 New Landscape Features Associated with Hydraulic Fracturing Activities at Well Pads
New landscape features that would be associated with fracturing activities include an extensive
array of equipment, which would cover almost the entire well pad. Photo 6.5 shows what a
typical well site may look like during the hydraulic fracturing of wells at a well pad. This view
is upslope of a well site that is under development. The photo shows the industrial appearance of
the well site during the hydraulic fracturing phase, which would appear dramatically different
from the site’s surrounding setting for the 3- to 5-day duration of hydraulic fracturing activities.
This view includes a water impoundment site (visible in the right background of the photo) and a

Final SGEIS 2015, Page 6-273

 portion of new right-of-way for a connector pipeline (visible on another hillside in the left
background of the photo).
Photo 6.5 - A representative view of active high-volume hydraulic fracturing (New August 2011)

The equipment typically present during hydraulic fracturing includes the following:
•

storage tanks that contain the water and additives used for hydraulic fracturing
(rectangular red tanks on well site shown in Photo 6.5);

•

tanks containing chemicals used in the fracturing process or for storage of liquefied
natural gas produced during hydraulic fracturing (blue rectangular tanks on well site
shown in Photo 6.5);

•

compressors (large cylindrical blue equipment and smaller dark green equipment with
stacks or vents shown in Photo 6.5) used for pumping product through various hoses and
pipelines;

•

miscellaneous trucks, including tractor trailers and other large trucks for hauling sand and
hydraulic fracturing additives , pipe-hauling trucks, welding and other mechanical
support trucks, and a crane; and

•

miscellaneous worker vehicles (almost all of the white or silver vehicles shown in Photo
6.5).

Final SGEIS 2015, Page 6-274

 6.9.2.4 New Landscape Features Associated with Production at Viable Well Sites
New landscape features associated with production at productive well sites would be relatively
minimal. Following the establishment of viable wells, all of the fracturing equipment and
vehicles shown in Photo 6.5 above would be removed from the site, and the site would be
landscaped with either gravel or low-lying grassy vegetation. Some aboveground structures
would be installed and remain on-site for the duration of production, including one or more
wellheads, small storage tanks, and a metering system for the pipeline connections; however,
these new aboveground structures would be small, less prominent landscape features, which over
time would become part of the existing setting of the well site and its surrounding area. Photo
6.12, Photo 6.13, Photo 6.17, and Photo 6.20 at the end of Chapter 6 show the appearance of well
sites during the production phase and the appearance of the same well sites during the earlier
fracturing phase.
6.9.2.5 New Landscape Features Associated with the Reclamation of Well Sites
If well sites are restored to their original topographic configuration and vegetative cover, on-site
aboveground structures associated with well production are removed and new landscape features
are introduced. The new landscape features would temporarily include bare areas, which would
be created by the large-scale earthmoving activity necessary to re-create the pre-existing terrain
conditions, and newly placed erosion control materials and vegetation to prevent erosion and
facilitate the successful reestablishment of vegetation covers, which would, over time, revert to
pre-existing vegetation patterns and species.
6.9.3

Visual Impacts Associated with the Different Phases of Horizontal Drilling and

Hydraulic Fracturing
Impacts on visual resources or visually sensitive areas such as those identified in Section 2.3.12
would result at or in the vicinity of individual well locations. The following five general
categories of visual impacts result from horizontal drilling and high-volume hydraulic-fracturing
activities:
•

construction-related impacts associated with the preparation of drill sites, including the
construction of access roads, connecting pipelines, and other ancillary facilities; work
during this phase progresses in a linear fashion, with impacts at any one location
occurring for up to several weeks;

Final SGEIS 2015, Page 6-275

 •

development-related impacts associated with the drilling of wells, including the presence
of drill rigs and equipment during the drilling phase; work during this phase progresses
over an approximately 2- to 3-week period;

•

development-related impacts associated with the fracturing of wells, including the
presence of storage tanks, compressors, trucks, and other equipment that supports
fracturing activities; work during this phase progresses over an approximately 2- to 3week period;

•

operational impacts associated with active well sites, which include the presence of
production equipment if the well site is viable; this low-impact phase involves small
pieces of equipment and pipeline connections for up to 30 years; and

•

reclamation impacts associated with the removal of production equipment and the
restoration of well site locations when operations are complete.

6.9.3.1 Visual Impacts Associated with Construction of Well Pads
Construction-related impacts on visual resources or visually sensitive areas such as those
identified in Section 2.3.12 would result from clearing and site preparation activities associated
with access roads, well pads, connecting gas pipelines, retaining structures, and other support
facilities such as water impoundments and water procurement sites. They would also include the
impacts of site-specific construction-related traffic on both new and existing road systems. The
end product of construction-related activities would be the creation of well sites and support
facilities that are new landscape features within the surrounding existing setting, which may be
incompatible with existing visual settings and land uses.
These construction-related visual impacts may be direct (i.e., impact the existing visual setting of
a well location) or indirect (i.e., impact the existing visual setting of areas in the vicinity of a
well location, including views that contain a well location). These visual impacts would be
temporary or of short-term duration (i.e., a matter of months while construction is underway),
and may generally be perceived as negative throughout their duration. These impacts on visual
resources or visually sensitive areas would be both site-specific (i.e., within views that contain
individual well locations) and cumulative (i.e., within views of areas or regions that contain
concentrations of well locations).

Final SGEIS 2015, Page 6-276

 6.9.3.2 Visual Impacts Associated with Drilling Activities on Well Pads
Development-related impacts on visual resources or visually sensitive areas such as those
identified in Section 2.3.12 would result from the introduction of new and visible landscape
features and activities into the existing settings that surround well locations. During drilling
activities, such landscape features would include the newly created well pad sites, including
associated access roads, pipeline rights-of-way, and other aboveground site facilities or
structures such as water impoundment areas; the tall drill rigs; and on-site equipment to support
drilling activities, such as on-site tanks for holding water, fuel, and drilling mud; generators;
compressors; solids control equipment; a choke manifold; an accumulator; pipe racks; and the
crew’s office space.
Drilling rigs, which can reach heights of 150 feet or more, would be the most visible sign of
drilling activity and when viewed from relatively short distances, such as from 1,000 feet to 0.5
miles, are relatively prominent landscape features. Because drilling may operate 24 hours a day,
additional nighttime visual impacts may occur from rig lighting and open flaring (Rumbach
2011, Upadhyay and Bu 2010). Additional new and visible landscape features would include
traffic related to the drilling of wells, including worker vehicles and heavy equipment used to
drill wells at each well site.
Drilling-related visual impacts may be direct (i.e., impact the existing visual setting of a well
location) or indirect (i.e., impact the existing visual settings of areas surrounding a well location,
including views that include a well location). These visual impacts would be temporary or of
short-term duration (i.e., a matter of weeks while drilling is underway), and would generally be
perceived as negative throughout their duration, primarily because of the high visibility of
drilling activities from surrounding vantage points. While drilling activities are generally
considered temporary or of short-duration, they may occur a number of times at well locations
over a three-year period following the date that the initial drilling on a well site commences.
These impacts on visual resources or visually sensitive areas would be both site-specific (i.e.,
within views that contain individual well locations) and cumulative (i.e., within views of areas or
regions that contain concentrations of well locations).

Final SGEIS 2015, Page 6-277

 6.9.3.3 Visual Impacts Associated with Hydraulic Fracturing Activities at Well Sites
Fracturing-related impacts on visual resources or visually sensitive areas such as those identified
in Section 2.3.12 would result from the introduction of new and visible landscape features and
activities into the existing settings that surround well locations. During fracturing activities, such
landscape features would include the newly created well pad sites, including: associated access
roads, pipeline rights-of-way, and other aboveground site facilities or structures such as water
impoundment areas; on-site equipment such storage vessels, trucks, and other equipment within
containment areas; and buildings or other aboveground structures. On-site equipment would be
the most visible sign of fracturing activity and, when viewed from relatively short distances (i.e.,
from 1,000 feet to 0.5 miles) are relatively prominent landscape features. Additional new and
visible landscape features would include traffic related to the development of wells, including
worker vehicles and heavy equipment used at each well site.
Fracturing-related visual impacts may be direct (i.e., impact the existing visual setting of a well
location) or indirect (i.e., impact the existing visual settings of areas surrounding a well location,
including views that include a well location). These visual impacts would be temporary or of
short-term duration (i.e., a matter of weeks while hydraulic fracturing is underway) and would
generally be perceived as negative throughout their duration, primarily because of the high
visibility of fracturing activities from surrounding vantage points. While fracturing activities are
generally considered temporary and of short duration, they would occur a number of times
during the three-year period during which all wells at a well location would have to be drilled
and fractured, and then episodically at well locations over the lifetime of the well, if hydraulic
fracturing activities are repeated at wells to keep them viable (in production). These impacts on
visual resources or visually sensitive areas would be both site-specific (i.e., within views that
contain individual well locations) and cumulative (i.e., within views of areas or regions that
contain concentrations of well locations).
6.9.3.4 Visual Impacts Associated with Production at Well Sites
Operations-related impacts on visual resources or visually sensitive areas such as those identified
in Section 2.3.12 would result from extraction activities at viable well sites. The visual impacts
of production would be less intrusive in surrounding landscapes, primarily because minimal onsite equipment is necessary during productions. Well site locations would consist of large, level

Final SGEIS 2015, Page 6-278

 grassy or graveled areas, with wellhead locations and small aboveground facilities for extraction
and transfer of product into gas lines. Thousands of similar wellhead installations are already
present in the area underlain by the Marcellus and Utica Shales in New York and may be
considered relatively unobtrusive landscape features (see Photo 6.11 through Photo 6.20 at the
end of Chapter 6). Although there would be some traffic associated with operations, including
worker vehicles and equipment needed for operation and maintenance activities, the presence of
such traffic would be substantially less than the traffic generated during construction and
development (drilling and fracturing) of the wells.
Production-related visual impacts would be direct (i.e., directly impact the existing visual setting
of a well location) and indirect (i.e., indirectly impact the existing settings within viewsheds that
would contain a well location, including views of and from visual resources or visually sensitive
areas that would also contain a well location) and would be of long-term duration (i.e., a number
of years while active well sites remain viable). Operations-related visual impacts may initially
be considered as having the potential for high visibility from surrounding vantage points,
particularly when well locations are developed. However, over the lifetime of wells at a well
location, which could be as long as 30 years from the commencement of drilling, operationrelated activities at viable well pad locations would become integral features within their
surrounding landscapes. These impacts on visual resources or visually sensitive areas would be
both site-specific (i.e., within views that contain individual well locations) and cumulative (i.e.,
within views of areas or regions that contain concentrations of well locations).
6.9.3.5 Visual Impacts Associated with the Reclamation of Well Sites
Reclamation-related impacts on visual resources or visually sensitive areas such as those
identified in Section 2.3.12 would result from the removal of on-site well equipment and
structures and from site restoration activities. Site restoration activities would include
recontouring the terrain at well sites to reestablish pre-existing topographic conditions and
planting appropriate vegetative cover to reestablish appropriate site-specific vegetation species
and growth patterns. Subsequent periodic reclamation-related visual impacts may also result
from post-restoration inspection or monitoring and measures needed to ensure the successful
reestablishment and succession of vegetation.

Final SGEIS 2015, Page 6-279

 Reclamation-related visual impacts would be direct (i.e., directly impact the existing visual
setting of a well location) and indirect (i.e., indirectly impact the existing settings within
viewsheds that would contain a well location, including views of and from visual resources or
visually sensitive areas that would also contain a well location). The duration of these temporary
impacts would range from short term to long term. For example, removing well equipment and
structures, recontouring the terrain, and replanting appropriate vegetation to reestablish preexisting conditions would be of short-term duration (a matter of weeks or months). However,
reclamation of forested areas may be of long-term duration.
Additional post-reclamation restoration activities may be necessary to ensure successful
reestablishment of vegetation, consisting of periodic inspection or monitoring and
implementation of any corrective actions to facilitate successful revegetation (such as corrective
erosion control measures or vegetative replanting efforts). These activities would be episodic
and may range from short-term to long term duration (from several months to as long as 1 to 3
years) to ensure successful revegetation. The potential impacts of short- to long-term inspection
and monitoring activities on visual resources or visually sensitive areas during restoration are
expected to be episodic and generally range from neutral to beneficial as vegetation succession
proceeds.
All of the reclamation-related impacts on visual resources or visually sensitive areas would be
both site specific (e.g., within views that contain individual well locations) and cumulative (e.g.,
within views of areas or regions containing concentrations of well locations).
6.9.4

Visual Impacts of Off-site Activities Associated with Horizontal Drilling and Hydraulic

Fracturing
Section 6.9.3 discusses the nature of impacts on visual resources or visually sensitive areas that
may be associated with on-site horizontal drilling and hydraulic-fracturing activities. However,
off-site activities that could occur during one or more of the construction, development (drilling
and fracturing), production, and reclamation phases also may result in additional indirect impacts
on visual resources or visually sensitive areas, particularly during the periodic influx of
specialized workforces during various phases of development. Such off-site activities may
include changes in traffic volumes and patterns, depending on the phase of development

Final SGEIS 2015, Page 6-280

 occurring at one or more well sites in an area; and the development and/or use of existing or new
contractor yards or equipment storage areas or other staging areas that may be necessary at
various times (Upadhyay and Bu 2010).
The periodic and temporary influx of specialized workforces at various phases of development
may also result in increased use of recreational vehicle or other camping areas (areas with cabins
or designated for tent camping) for temporary or seasonal housing. While such camping areas
may experience a congested appearance during such an influx, these areas are specifically
designed for recreational vehicle or other camping activities, and the use of such areas in
accordance with facility-specific occupancy rates may not be considered a negative impact on
visual resources or visually sensitive areas.
The appearance and movement of specialized and large equipment and vehicles would result in
temporary increases in traffic volumes and changes to traffic patterns, which would occur at
various times during the construction, development (drilling and fracturing), and reclamation
phases. This additional specialized traffic would occur on existing interstates, highways, and
secondary roads and could result in increased congestion at intersections and bottlenecks (e.g.,
curves or bridges) or during particular hours (such as in the mornings and afternoons during the
school year). This traffic would generally result in the increased visibility of construction- or
production-related vehicles in the surrounding landscape. The new or increased presence of such
specialized traffic may be considered a negative impact, particularly on highways and secondary
roads that typically do not experience such construction-related traffic.
Additional cumulative visual impacts from traffic during the construction and development
(drilling and fracturing) phase may occur where a number of wells are developed near each other
at the same time, resulting in increased amounts of traffic. For areas with multiple well sites, this
potential increase in traffic during the construction and development (drilling and fracturing)
phase could increase the extent and duration of cumulative visual impacts. This potential
cumulative visual impact from traffic used to construct and develop multiple well sites in an area
might be reduced if the same operator develops multiple pads, because the same equipment may
be used in phases to reduce the overall need and cost for the movement of equipment and
materials.

Final SGEIS 2015, Page 6-281

 The development of new and/or use of existing contractor yards or equipment storage areas or
other staging areas may be necessary at various times during the construction, development
(drilling and fracturing), and reclamation phases. Such areas may have a congested appearance
during their use. If existing, previously developed contractor/storage yards or staging areas are
used for such activities, their temporary and periodic use would be consistent with their existing
setting and would have no new impact on visual resources or visually sensitive areas. However,
if new yards or staging areas have to be created, the temporary and periodic use of such areas
may represent a new impact on visual resources or visually sensitive areas.
6.9.5

Previous Evaluations of Visual Impacts from Horizontal Drilling and Hydraulic

Fracturing
In 2010, students associated with the Department of City and Regional Planning at Cornell
University, in Ithaca, New York, conducted a visual impact assessment of the hydraulic drilling
process currently utilized in the Marcellus Shale region in Pennsylvania (specifically in Bradford
County) (Upadhyay and Bu 2010). The purpose of this visual impact assessment was to describe
the various activities and landscape features associated with horizontal drilling and hydraulic
fracturing at individual well sites and across regions, and to examine the impacts or prominence
of new landscape features at well sites in views from surrounding areas at specific distances
and/or during different times of the day and year. 403
The study also included evaluations of the potential for impacts on visual resources or visually
sensitive areas at three existing well sites in Bradford County, Pennsylvania, using criteria
presented in the New York State Environmental Quality Review (SEQR) Visual EAF
Addendum. The evaluations were conducted to determine the way visual impacts from such
sites would be considered in accordance with New York State guidelines for assessing visual
impacts under the SEQR process. In addition, the visual impact study included predictive
modeling for the appearance of one or more new well sites within views from State Route 13
403

The visual impact assessment considered the visual impacts of only two well sites. Visual impact analysis was conducted
primarily during the day; while some photodocumentation of the appearance of well sites was included in the visual impact
assessment, the distances of nighttime views of the well sites were not specified. The assessment did not conduct analyses
for the well sites during all phases of development (i.e., construction, development, production, and reclamation). The
assessment also did not conduct similar analyses for off-site activities that might result in visual impacts (i.e., at areas used
for temporary worker housing, areas experiencing high levels of construction or production-related traffic, or at
contractor/storage yards or staging areas).

Final SGEIS 2015, Page 6-282

 near Cayuga Heights and from Cornell University’s Libe Slope, which are considered locally
significant visually sensitive areas by the City of Ithaca, and recommended potential mitigation
measures to minimize or mitigate negative impacts on visual resources or visually sensitive
areas.
In the 2010 visual impact assessment, the descriptions and photographs of the various phases of
horizontal drilling and hydraulic-fracturing activities that resulted in new landscape features in
Bradford County, Pennsylvania, are generally consistent with the descriptions and photographs
of the same processes presented in Section 6.9.2 and appear to correspond to the same phases of
well development (construction, well development (drilling and fracturing), production, and
reclamation) that are discussed above in Section 6.9.3.
Upadhyay and Bu’s evaluation of existing visual impacts consisted of examining the daytime
visibility of two different well locations in Bradford County, Pennsylvania, from various
distances ranging from 1,000 feet to 3.5 miles from the sites. 404 The results of this study cannot
be considered definitive because the visibility of only two well sites was examined and the
examination was conducted primarily during daylight hours. However, the visibility of the two
well sites appeared to be relatively limited at distances ranging from 0.5 to 3.5 miles away
(Upadhyay and Bu 2010). The relatively restricted daytime visibility appears to be the result of
perspective (i.e., landscape features associated with well sites do not appear as prominent
features within the landscape at distances of a mile or more) and/or effective screening by
sloping terrain and vegetative cover.
The 2010 visual impact assessment also included four nighttime photographs of well sites in
Bradford County, Pennsylvania. Lighting for nighttime on-site operations or production

404

Regions within the area underlain by the Marcellus and Utica Shales in New York have settings similar to that of Bradford
County, Pennsylvania; thus, similar visual impacts from well sites may be expected. However, a number of different, if not
unique, geographic conditions or settings are present in the Marcellus and Utica Shale area in New York, including: a large
number of lakes and rivers and other natural areas used for recreational purposes and possessing scenic qualities; a number
of regions that are primarily rolling agricultural land rather than sloping forestland (resulting in potentially increased
visibility of landscape features from greater distances); and a number of cities connected by interstate and state highways
(resulting in the potential for an increase in the number of views of and from visual resources or visually sensitive areas that
would contain well sites, and in the potential for an increase in size of the viewing public). These different or unique
geographic conditions and settings contain associated visual resources and visually sensitive areas, including those described
above in Section 2.4, that may be affected by new landscape features associated with well sites (including off-site areas and
activities) and that would be noticeable to the viewing public.

Final SGEIS 2015, Page 6-283

 activities and lighting on equipment are visible in these views; a nighttime view of flaring from
at least one well site is also presented in the visual impact assessment (Upadhyay and Bu 2010).
Similar documentation of the nighttime appearance of well sites during the drilling phase was
also provided in the Southern Tier Central Regional Planning and Development Boards (STC)
approved Marcellus Tourism Study (Rumbach 2011).
While these photographs present the potential impacts of horizontal drilling and hydraulicfracturing activities on visual resources and visually sensitive areas at night, a number of factors
should be reflected in the analysis of nighttime impacts on visual resources or visually sensitive
areas. First, the nighttime impacts of lighting or flaring would be temporary and limited
primarily to the well development phase of horizontal drilling and hydraulic fracturing. Flaring
would only occur during initial flowback at some wells, and the potential for flaring would be
limited to the extent practicable by permit conditions, such that the duration of nighttime impacts
from flaring typically would not occur for longer than three days. Second, the aesthetic qualities
of visual resources or visually sensitive areas are typically not accessible (i.e., visible) at night.
Third, the majority of the viewing public would typically not be present at the locations of most
types of visual resources or visually sensitive areas during nighttime hours, with the exception of
campgrounds, lakes, rivers, or other potentially scenic areas where recreational activities may
extend into evening and nighttime hours for part of the year, or with the exception of nighttime
drivers, whose view of flaring would be transient. Therefore, it is likely that the temporary
negative impacts of any nighttime lighting and flaring would be either visible to only a small
segment of the viewing public, or visible by a larger segment of the viewing public but only on a
seasonal short-term basis.
The 2010 visual impact assessment (Upadhyay and Bu 2010) also included an evaluation of three
well sites in Bradford County, Pennsylvania, using the criteria listed in NYSDEC’s Visual
Environmental Assessment Form (NYSDEC 2011a). These three sites are in settings that are
similar to areas within the area underlain by the Marcellus and Utica Shales in New York.
Two of the three well sites were in the production phase; the third site contained an active drill
rig, suggesting that it was in the drilling phase. All of the sites were in rural areas where there
were no visual resources or visually sensitive areas as described in Section 2.3.12. All of the

Final SGEIS 2015, Page 6-284

 sites were in close proximity to other similar well sites and were visible from local nearby
roadways and from a distance of 0.5 to 3 miles away. At two sites, agricultural and forest
vegetation would provide seasonal screening; the third site was on or near the top of a hill and
was visible from a larger surrounding area, despite the presence of forest vegetation (Upadhyay
and Bu 2010).
Although no conclusions about the significance of potential visual impacts were made based on
the criteria listed in NYSDEC’s Visual Environmental Assessment Form (NYSDEC 2011a), it is
likely that none of these well sites would be considered to have any significant visual impacts,
primarily because no visual resources or visually sensitive areas as described in Section 2.3.12
are present, and it is likely that no further assessment or mitigation of visual impacts as described
in NYSDEC Program Policy DEP-00-2 would be recommended or determined to be necessary.
Upadhyay and Bu’s visual impact assessment also conducted limited three-dimensional
modeling to examine the potential visual impacts of well sites during the drilling phase, when
drill rigs are on-site, in two landscapes in the Ithaca area in Tompkins County, New York.
Tompkins County, including the Ithaca area, is within the area underlain by the Marcellus and
Utica Shales in New York. The two landscapes used for modeling consisted of (1) a view facing
west of slopes on the western side of Cayuga Lake, from southbound Route 13 near Cayuga
Heights (Cayuga Heights is a neighboring town along Cayuga Lake, just north of Ithaca on
Route 13); and (2) a view facing west of upland well sites on the western side of Cayuga Inlet
from Libe Slope on the Cornell University campus in Ithaca. The vantage points of both photos
are estimated to be approximately 2.5 miles from the modeled well site locations. None of the
modeled well sites appear to be prominent new landscape features within these locally
designated scenic views. These results support similar conclusions made above, which were
based on the daytime photographs of the existing wells in Bradford County, Pennsylvania, from
various vantage points along surrounding local roads, i.e., that the visibility of new landscape
features associated with well sites tends to be minimal from distances beyond 1 mile.
The potential for visual impacts from other new landscape features associated with the horizontal
drilling and hydraulic fracturing process, such as interconnections with natural gas pipelines, was
also considered in the STC’s Marcellus Tourism Study (Rumbach 2011). This study suggested

Final SGEIS 2015, Page 6-285

 that potential impacts from the creation of new pipeline-rights-of-way might result in changes in
vegetation patterns, primarily through the creation of new and visible corridors, particularly
where forest would be removed. In addition, the study considered the potential for cumulative
visual impacts of multiple well sites and associated off-site facilities across a relatively large area
such as the STC region (which is comprised of Steuben, Schuyler, and Chemung counties). The
overall conclusion of the STC’s Marcellus Tourism Study was that cumulative visual impacts of
multiple well sites and their associated off-site facilities may result from the creation of an
industrial landscape that is not compatible with the current scenic qualities that are recognized
for the STC region (Rumbach 2011).
The evaluation of existing and potential visual impacts of multiple well sites and their associated
offsite facilities by Upadhyay and Bu (2010) and Rumbach (2011) generated information and
conclusions that were considered when developing the visual impacts presented in Section 6.9.3
for the different phases of well site development in the area underlain by the Marcellus and Utica
Shales in New York.
6.9.6

Assessment of Visual Impacts using NYSDEC Policy and Guidance

An assessment of a project’s potential for visual impacts is generally part of the SEQR process
and is triggered for Type I or unlisted projects, particularly when a Full Environmental
Assessment Form (EAF) is required (NYSDEC 2011b). An addendum to the Full EAF, the
Visual EAF Form, evaluates the potential for visual impacts and is required for those projects
that may have an effect on aesthetic resources (NYSDEC 2011c).
The Visual EAF Form provides additional information on a project’s potential visual impacts
and their magnitude, including: information on the visibility of the project from visual resources
and visually sensitive areas such as those described in Section 2.3.12; whether the visibility of
the project is seasonal and whether the public uses any of the identified visual resources or
visually sensitive areas during seasons when the project may be visible; a description of the
surrounding visual environment; whether there are any similar projects within a 3-mile radius;
the annual number of viewers likely to observe the proposed project; and the situation or activity
in which the viewers are engaged while viewing the proposed project (NYSDEC 2011a).

Final SGEIS 2015, Page 6-286

 In the event that significant resources such as those described in Section 2.3.12 are present and
have viewsheds that contain proposed well sites, a formal visual assessment consistent with the
procedures outlined in NYSDEC DEP-00-2 would be conducted. This formal visual assessment
would consist of developing, “at a minimum, a line-of-sight profile, or depending upon the scope
and potential significance of the activity, a digital viewshed” (such as computer-generated
models or visual simulations) to determine whether a significant visual resource or visually
sensitive area is within potential viewsheds of the proposed project (NYSDEC 2000).
Procedures for formal visual assessments would use control points established by NYSDEC staff
and would include a worst-case scenario. A worst-case scenario for visual assessments is
established using control points that reveal any project visibility at a visually significant
resource. Generally, control points for the worst-case scenario are located in an attempt to reveal
the tallest facility or project component. In addition, the impact area that would be evaluated in
the formal visual assessment would be determined by NYSDEC staff and may be as large as a 5mile-radius area around a project’s various components (NYSDEC 2000).
NYSDEC staff would verify the potential significance of impacts on visual resources or visually
sensitive areas using the qualities of the specific resource(s) and the juxtaposition of the project’s
components (using viewshed and/or line-of-sight profiles) as the guide for determining
significance. If determined significant, visual impacts may require mitigation in accordance with
NYSDEC DEP-000-2 guidelines (NYSDEC 2000). Procedures for mitigation are discussed in
greater detail in Section 7.9.
6.9.7

Summary of Visual Impacts

The potential impacts of well development on visual resource and visually sensitive areas such as
those identified in Section 2.3.12 are summarized below in Table 6.53.These potential impacts
may result from on-site activities associated with construction, drilling, fracturing, production
and reclamation; off-site activities associated with increased traffic; and the use of off-site areas
for construction, staging, and housing. Given the generic nature of this analysis and the lack of
specific well pad locations to evaluate for potential visual impacts, the impacts presented in this
section are not resource-specific. Generic mitigation measures for these potential generic
impacts are presented in Section 7.9.

Final SGEIS 2015, Page 6-287

 Table 6.53 - Summary of Generic Visual Impacts Resulting from Horizontal Drilling and Hydraulic
Fracturing in the Marcellus and Utica Shale Area of New York (New August 2011)

Description of Activity
On-site Well Pad Construction

•
•
•
•
•
•

On-site Well Drilling

•
•

•
•

Description of Typical New Landscape Features
Newly created well pads - open, level areas
averaging approximately 3.5 acres in size
Newly created linear features such as access roads
and connecting pipelines
Newly created water impoundment areas (if
necessary)
Construction equipment, including bulldozers,
graders, backhoes, and other large equipment for
clearing, cutting, filling and grading activities
Trucks for hauling equipment and materials
Worker vehicles

Drill rigs of varying heights and dimensions
Auxiliary on-site equipment such as storage tanks
for water, fuel, and drilling mud; generators;
compressors; solids control equipment; a choke
manifold; an accumulator; pipe racks; and the
crew’s office space
Trucks for hauling equipment and materials
Worker vehicles

•
•
•
•
•
•

•
•
•
•
•
•
•

Final SGEIS 2015, Page 6-288

Description of Potential Visual Impacts
Direct impacts - on the existing visual setting of a
well location
Indirect impacts - on the existing visual setting of
areas in the vicinity of a well location, including
views that contain a well location
Temporary or short-term duration - during the
weeks or months while construction is underway
Negative - because of the introduction of new
features into the landscape
Site-specific - within views that contain individual
well locations
Cumulative - within views of areas or regions that
contain concentrations of well locations
Direct impacts - on the existing visual setting of a
well location
Indirect impacts - on the existing visual settings of
areas surrounding a well location, including views
that include a well location
Temporary - during the weeks while drilling is
underway
Periodic - during the times when drilling may
occur over a three-year period following the date
that the initial drilling on a well site commences
Negative - throughout the duration of drilling,
primarily because of the high visibility of drilling
activities from surrounding vantage points
Site-specific - within views that contain individual
well locations
Cumulative – within views of areas or regions that
contain concentrations of well locations

 Description of Activity
On-site Well Fracturing

Description of Typical New Landscape Features
• On-site equipment such as storage tanks for water,
fuel, and fracturing additives; compressors; cranes;
pipe racks; and the crew’s office space
• Trucks, including tractor trailers and other large
trucks for hauling sand and fracturing additives,
pipe-hauling trucks, welding and other mechanical
support trucks
• Worker vehicles

•
•
•
•
•
•
•

Well Production

•
•
•
•

Operating well pads - open, level areas averaging
approximately 0.5 to 1.0 acre in size, maintained in
grassy or graveled conditions
Wellhead locations and small aboveground
facilities for the pumping and transfer of product
into gas lines.
Access road maintained in graveled condition
Connecting pipeline right-of-way maintained with
grassy vegetation

•
•
•
•
•
•
•

Final SGEIS 2015, Page 6-289

Description of Potential Visual Impacts
Direct impacts – on the existing visual setting of a
well location
Indirect impacts - on the existing visual settings of
areas surrounding a well location, including views
that include a well location
Temporary or short-term duration – during the
weeks while hydraulic fracturing is underway
Periodic - during the times when fracturing may
occur over the lifetime of the well(s)
Negative - throughout their duration, primarily
because of the high visibility of fracturing
activities from surrounding vantage points.
Site-specific - within views that contain individual
well locations
Cumulative – within views of areas or regions that
contain concentration of well locations
Direct impacts - on the existing visual setting of a
well location
Indirect impacts - on the existing settings within
viewsheds that contain a well location
Long-term duration - during the years while active
well sites remain viable
Negative - during short-term period of initial
development
Neutral - during long-term period of production
over a potential 30-year period
Site specific - within views that contain individual
well locations
Cumulative – within views of areas or regions that
contain concentrations of well locations

 Description of Activity
On-site Well Site Reclamation

Description of Typical New Landscape Features
• Initial bare areas resulting from the removal of
wellheads and small aboveground facilities used
during production; recontouring to pre-existing
terrain conditions; and revegetation efforts
• Subsequent vegetated areas reverting to preexisting vegetation patterns and species

•
•
•
•

•
•
•

Off-site changes in traffic
volumes and patterns

•
•
•

Increased traffic during the construction, drilling
and fracturing, and reclamation phases of well
development
Increased traffic would be local (at one or more
well sites in close proximity)
Increased traffic may be regional (in areas where
numerous multi-well sites are under development)

•
•
•
•
•
•

Final SGEIS 2015, Page 6-290

Description of Potential Visual Impacts
Direct impacts - on the existing visual setting of a
well location
Indirect impacts - on the existing settings within
viewsheds that would contain a well location
Temporary to short term - during removal of well
equipment and structures, recontouring terrain,
and replanting of vegetation
Periodic and long-term - during periodic
inspection or monitoring and implementation of
any corrective actions to facilitate successful
revegetation for several months to as long as one
to three years
Neutral to beneficial - as vegetation succession
proceeds
Site specific - within views that contain individual
well locations
Cumulative – within views of areas or regions
containing concentrations of well locations
Direct impacts - on the existing visual setting of a
well location
Indirect impacts - on the existing settings within
viewsheds that contain a well location
Temporary and periodic - during specific phases
of well development (construction, drilling,
fracturing, and reclamation)
Negative - due to the appearance and movement
of high numbers of specialized and large
equipment and vehicles
Site specific - at specific well locations
Cumulative – within views of areas or regions
containing concentrations of well locations under
development at the same time

 Description of Activity
Off-site periodic and
temporary influx of specialized
workforces at various phases
of development

Description of Typical New Landscape Features
• Increased use of local recreational vehicle or other
camping areas (areas with cabins or designated for
tent camping) for temporary or seasonal housing.
• Increased local worker traffic during and after
working hours

•
•
•
•

•

Off-site contractor yards or
equipment storage areas or
other staging areas

•
•

Increased traffic and activity associated with
construction and use of new contractor yards,
equipment storage areas or other staging areas
Increased traffic and activity associated with use of
existing contractor yards, equipment storage areas,
or other staging areas

•
•
•
•
•

Final SGEIS 2015, Page 6-291

Description of Potential Visual Impacts
Direct impacts - on the existing visual setting of
off-site housing locations and on local roads
Indirect impacts - on the existing settings within
viewsheds that would contain off-site housing and
local roads
Temporary and periodic - during specific phases
of well development (construction, drilling,
fracturing, and reclamation)
Neutral to negative - occupancy of existing offsite housing locations would be consistent with
capacity, but local traffic may result in congestion
during and after work hours
Site-specific – at specific housing locations and
along local roads
Direct impacts - on the existing visual setting of
an off-site yard, storage area, or staging area
Indirect impacts - on the existing settings within
viewsheds that contain an off-site yard, storage
area, or staging area
Temporary and periodic - during specific phases
of well development (construction, drilling,
fracturing, and reclamation)
Negative - due to the appearance and movement
of high numbers of specialized and large
equipment and vehicles
Site specific – at specific off-site yard, storage
area, or staging area locations

 6.10

Noise 405

The noise impacts associated with horizontal drilling and high volume hydraulic fracturing are,
in general, similar to those addressed in the 1992 GEIS. The rigs and supporting equipment are
somewhat larger than the commonly used equipment described in 1992, but with the exception
of specialized downhole tools, horizontal drilling is performed using the same equipment,
technology, and procedures as used for many wells that have been drilled in New York.
Production-phase well site equipment is very quiet and has negligible impacts.
The greatest difference with respect to noise impacts, however, is in the duration of drilling. A
horizontal well takes four to five weeks of drilling at 24 hours per day to complete. The 1992
GEIS anticipated that most wells drilled in New York with rotary rigs would be completed in
less than one week, though drilling could extend two weeks or longer.
High-volume hydraulic fracturing is also of a larger scale than the water-gel fracs addressed in
1992. These were described as requiring 20,000 to 80,000 gallons of water pumped into the well
at pressures of 2,000 to 3,500 pounds per square inch (psi). High-volume hydraulic fracturing of
a typical horizontal well could require, on average, 3.6 million gallons of water and a maximum
pumping pressure that may be as high as 10,000 to 11,000 psi. This volume and pressure would
result in more pump and fluid handling noise than anticipated in 1992. The proposed process
requires three to five days to complete. There was no mention of the time required for hydraulic
fracturing in 1992.
There would also be significantly more trucking and associated noise involved with high-volume
hydraulic fracturing than was addressed in the 1992 GEIS.
Site preparation, drilling, and hydraulic fracturing activities could result in temporary noise
impacts, depending on the distance from the site to the nearest noise-sensitive receptors.
Typically, the following factors are considered when evaluating a construction noise impact:

405

Section 6.10, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011, and was adapted by
the Department.

Final SGEIS 2015, Page 6-292

 •

Difference between existing noise levels prior to construction startup and expected noise
levels during construction;

•

Absolute level of expected construction noise;

•

Adjacent land uses; and

•

The duration of construction activity.

In order to evaluate the potential noise impacts related to the drilling operation phases, a
construction noise model was used to estimate noise levels at various distances from the
construction site during a typical hour for each phase of construction. The algorithm in the
model considered construction equipment noise specification data, usage factors, and distance.
The following logarithmic equation was used to compute projected noise levels:
Lp1 = Lp2 + 10log(U.F./10) – 20log(d2/d1):
where:
Lp1 = the average noise level (dBA) at a distance (d2) due to the operation of a unit of
equipment throughout the day;
Lp2 = the equipment noise level (dBA) at a reference distance (d1);
U.F. = a usage factor that accounts for a fraction of time an equipment unit is in use
throughout the day;
d2 = the distance from the unit of equipment in feet; and
d1 = the distance at which equipment noise level data is known.
Noise levels and usage factor data for construction equipment were obtained from industry
sources and government publications. Usage factors were used to account for the fact that
construction equipment use is intermittent throughout the course of a normal workday.
Once the average noise level for the individual equipment unit was calculated, the contribution
of all major noise-producing equipment on-site was combined to provide a composite noise level
at various distances using the following formula:

Final SGEIS 2015, Page 6-293

 Leqtotal

Leq2
Leq3
1

 Leq
10
10

= 10 log10 + 10 + 10 10 ...etc.



Using this approach, the estimated noise levels are conservative in that they do not take into
consideration any noise reduction due to ground attenuation, atmospheric absorption,
topography, or vegetation.
6.10.1 Access Road Construction
Newly constructed access roads are typically unpaved and are generally 20 to 40 feet wide
during the construction phase and 10 to 20 feet wide during the production phase. They are
constructed to efficiently provide access to the well pad while minimizing potential
environmental impacts.
The estimated sound pressure levels (SPLs) produced by construction equipment that would be
used to build or improve access roads are presented in Table 6.54 for various distances. The
composite result is derived by assuming that all of the construction equipment listed in the table
is operating at the percent utilization time listed and by combining their SPLs logarithmically.
These SPLs might temporarily occur over the course of access road construction. Such levels
would not generally be considered acceptable on a permanent basis, but as a temporary, daytime
occurrence, construction noise of this magnitude and duration is not likely to result in many
complaints in the project area.

Final SGEIS 2015, Page 6-294

 Table 6.54 - Estimated Construction Noise Levels at Various Distances for
Access Road Construction (New August 2011)

Construction
Equipment
Quantity
Excavator
2
Grader
2
Bulldozer
2
Compactor
2
Water truck
2
Dump truck
8
Loader
2
Composite Noise Level

Usage
Factor
%
40
40
40
20
40
40
40

Lmax
SPL @
50 Feet
(dBA)
81
85
82
83
76
76
79

Distance in Feet/SPL (dBA)
50
(adj.)
80
84
81
79
75
81
78
89

250
66
70
67
65
61
67
64
75

500
60
64
61
59
55
61
58
69

1,000
54
58
55
53
49
55
52
63

1,500
50
54
51
49
45
52
48
59

2,000
48
52
49
47
43
49
46
57

Source: FHWA 2006.
Key:
adj

= adjusted.

dBA = A-weighted decibels.
Lmax

= maximum noise level.

SPL

= Sound Pressure Level.

6.10.2 Well Site Preparation
Prior to the installation of a well, the site must be cleared and graded to make room for the
placement of the necessary equipment and materials to be used in drilling and developing the
well. The site preparation would generate noise that is associated with a construction site,
including noise from bulldozers, backhoes, and other types of construction equipment. The Aweighted SPLs for the construction equipment that typically would be utilized during well pad
preparation are presented in Table 6.55 along with the estimated SPLs at various distances from
the site. Such levels would not generally be considered acceptable on a permanent basis, but as a
temporary, daytime occurrence, construction noise of this magnitude and duration is not likely to
result in many complaints in the project area.

Final SGEIS 2015, Page 6-295

 Table 6.55 - Estimated Construction Noise Levels at Various Distances for
Well Pad Preparation (New August 2011)

Construction
Equipment
Excavator
Bulldozer
Water truck
Dump truck
Pickup truck
Chain saw

Lmax
Usage
SPL @
Factor
50 Feet
Quantity
%
(dBA)
1
40
81
1
40
82
1
40
76
2
40
76
2
40
75
2
20
84
Composite Noise Level

Distance in Feet/SPL (dBA)
50
(adj.)
77
78
72
75
74
80
84

250
63
64
58
61
60
66
70

500
57
58
52
55
54
60
64

1,000
51
52
46
49
48
54
58

1,500
47
48
42
45
44
50
55

2,000
45
46
40
43
42
48
52

Source: FHWA 2006.
Key:
adj

= adjusted.

dBA = A-weighted decibels.
Lmax

= maximum noise level.

SPL

= Sound Pressure Level.

6.10.3 High-Volume Hydraulic Fracturing – Drilling
High-volume hydraulic fracturing involves various sources of noise. The primary sources of
noise were determined to be as follows:
•

Drill Rigs. Drill rigs are typically powered by diesel engines, which generate noise
emissions primarily from the air intake, crankcase, and exhaust. These levels fluctuate
depending on the engine speed and load.

•

Air Compressors. Air compressors are typically powered by diesel engines and generate the
highest level of noise over the course of drilling operations. Air compressors would be in
operation virtually throughout the drilling of a well, but the actual number of operating
compressors would vary. However, more compressed air capacity is required as the drilling
advances.

•

Tubular Preparation and Cleaning. Tubular preparation and cleaning is an operation that is
conducted as drill pipe is placed into the wellbore. As tubulars are raised onto the drill floor,
workers physically hammer the outside of the pipe to displace internal debris. This process,
when conducted during the evening hours, seems to generate the most concern from adjacent
landowners. While the decibel level is comparatively low, the acute nature of the noise is
noticeable.

Final SGEIS 2015, Page 6-296

 •

Elevator Operation. Elevators are used to move drill pipe and casing into and/or out of the
wellbore. During drilling, elevators are used to add additional pipe to the drill string as the
depth increases. Elevators are used when the operator is removing multiple sections of pipe
from the well or placing drill pipe or casing into the wellbore. Elevator operation is not a
constant activity and its duration is dependent on the depth of the well bore. The decibel
level is low.

•

Drill Pipe Connections. As the depth of the well increases, the operator must connect
additional pipe to the drill string. Most operators in the Appalachian Basins use a method
known as “air-drilling.” As the drill bit penetrates the rock the cuttings must be removed
from the wellbore. Cuttings are removed by displacing pressurized air (from the air
compressors discussed above) into the well bore. As the air is circulated back to the surface,
it carries with it the rock cuttings. To connect additional pipe to the drill string, the operator
will release the air pressure. It is the release of pressure that creates a higher frequency noise
impact.

Once initiated, the drilling operation often continues 24 hours a day until completion and would
therefore generate noise during nighttime hours, when people are generally involved in activities
that require lower ambient noise levels. Certain noise-producing equipment is typically operated
on a fairly continuous basis during the drilling process. The types and quantities of this
equipment are presented in Table 6.56 for rotary air drilling and in Table 6.57 for horizontal
drilling (see Photo 6.6), along with the estimated A-weighted individual and composite SPLs that
would be experienced at various distances from the operation. An analysis of both types of
drilling is included since according to industry sources, in accessing the natural gas formation,
rotary air drilling is often used for the vertical section of the well and then horizontal drilling is
used for making the turn and completing the horizontal section.

Final SGEIS 2015, Page 6-297

 Table 6.56 - Estimated Construction Noise Levels at Various Distances for
Rotary Air Well Drilling (New August 2011)

Construction Equipment
Drill rig drive engine
Compressors
Hurricane booster
Compressor exhaust

Sound
Power
Level
Quantity
(dBA)
1
105
4
105
3
81
1
85
Composite Noise Level

Distance in Feet/SPL1 (dBA)
50
(adj.)
71
77
51
51
79

250
57
63
37
37
64

500
51
57
31
31
58

1,000
45
51
25
25
52

1,500
41
47
22
21
48

2,000
38
45
19
18
45

Source: Confidential Industry Source.
1

SPL = Sound Pressure Level

Key:
adj = adjusted to quantity.

Table 6.57 - Estimated Construction Noise Levels at Various Distances for
Horizontal Drilling (New August 2011)

Distance in Feet/SPL (dBA)
Construction Equipment
Rig drive motor
Generator
Top drive
Draw works
Triple shaker

Sound
Quantity
Level
Distance
1
1052
0
3
812
0
1
851
5
1
1
74
10
1
851
15
Composite Noise Level

50
(adj.)
71
51
65
60
75
76

Source: Confidential Industry Source.
1

SPL = Sound Pressure Level

Key:
adj = adjusted to quantity.

Final SGEIS 2015, Page 6-298

250
57
37
51
46
61
62

500
51
31
45
40
55
56

1000
45
25
39
34
49
50

1500
41
22
35
30
45
47

2000
38
19
33
28
43
44

 Photo 6.6 - Electric Generators, Active Drilling Site (New August 2011)

Intermittent operations that occur during drilling include tubular preparation and cleaning,
elevator operation, and drill pipe connection blowdown. These shorter-duration events may
occur at intervals as short as every 20 to 30 minutes during drilling. Noise associated with the
drilling activities would be temporary and would end once drilling operations cease. 406
6.10.4 High-Volume Hydraulic Fracturing – Fracturing
During the hydraulic fracturing process, water, sand, and other additives are pumped under high
pressure into the formation to create fractures. To inject the required water volume and achieve
the necessary pressure, up to 20 diesel-pumper trucks operating simultaneously are necessary
(see Photo 6.7 and Photo 6.8). Typically the operation takes place over two to five days for a
single well. Normally, hydraulic fracturing is only performed once in the life of a well. The
sound level measured for a diesel- pumper truck under load ranges from 110 to 115 dBA at a
distance of 3 feet. Noise from the diesel engine varies according to load and speed, but the main
component of the sound spectrum is the fundamental engine rotation speed. The diesel engine

406

Page 4, - Notice of Determination of Non-Significance – API# 31-015-22960-00, Permit 08828 (February 13, 2002)

Final SGEIS 2015, Page 6-299

 sound spectrum, which peaks in the range of 50 Hz to 250 Hz, contains higher emissions in the
lower frequencies.
Table 6.58 presents the estimated noise levels that may be experienced at various distances from
a hydraulic fracturing operation, based on 20 pumper trucks operating at a sound power level of
110 dBA and 20 pumper trucks operating at a sound power level of 115 dBA.

Table 6.58 - Estimated Construction Noise Levels at Various Distances for
High-Volume Hydraulic Fracturing (New August 2011)

Construction
Equipment
Pumper truck
Pumper truck

Quantity
20
20

SPL1
(dBA)
110
115

Distance
(feet)
3
3

Quantity
Adjusted
Sound
Level
123
128

Distance in Feet/SPL1 (dBA)

50
99
104

250 500
85 79
90 84

Source: Confidential Industry Source.
1

SPL = Sound Pressure Level

Photo 6.7 - Truck-mounted Hydraulic Fracturing Pump (New August 2011)

Final SGEIS 2015, Page 6-300

1000
73
78

1500
69
74

2000
67
72

 Photo 6.8 - Hydraulic Fracturing of a Marcellus Shale Well Site (New August 2011)

The existing sound level in a quiet rural area at night may be as low as 30 dBA at times. Since
the drilling and hydraulic fracturing operations are often conducted on a 24-hour basis, these
operations, without additional noise mitigations, may result in an increase in noise of 37 to 42 dB
over the quietest background at a distance of 2,000 feet. As indicated previously, according to
NYSDEC guidance, sound pressure increases of more than 6 dB may require a closer analysis of
impact potential, depending on existing SPLs and the character of surrounding land use and
receptors, and an increase of 6 dB(A) may cause complaints. Therefore, mitigation measures
would be required if increases of this nature would be experienced at a receptor location.
Table 6.59 presents the estimated duration of the various phases of activity involved in the
completion of a typical installation. Multiple well pad installations would increase the drilling
and hydraulic fracturing duration in a given area.
Table 6.59 - Assumed Construction and Development Times (New August 2011)

Operation
Access roads
Site preparation/well pad
Well drilling
Hydraulic fracturing single well

Estimated Duration
(days)
3-7
7 - 14
28 - 35
2-5

Final SGEIS 2015, Page 6-301

 6.10.5 Transportation
Similar to any construction operation, drill sites require the use of support equipment and
vehicles. Specialized cement equipment and vehicles, water trucks, flatbed tractor trailers, and
delivery and employee vehicles are the most common forms of support machinery and vehicles.
Cement equipment would generate additional noise during operations, but this impact is typically
short lived and is at levels below that of the compressors described above.
The noise levels generated by vehicles depend on a number of variable conditions, including
vehicle type, load and speed, nature of the roadway surface, road grade, distance from the road to
the receptor, topography, ground condition, and atmospheric conditions. Figure 6.21 depicts
measured noise emission levels for various vehicles and cruise speeds at a distance of 50 feet on
average pavement. As shown in the figure, a heavy truck passing by at 50 miles per hour would
contribute a noise level of approximately 83 dBA at 50 feet from the road in comparison to a
passing automobile, which would contribute approximately 73 dBA at 50 feet. Although a truck
passing by would constitute a short duration noise event, multiple truck trips along a given road
could result in higher hourly Leq noise levels and impacts on noise receptors close to main truck
travel routes. The noise impact of truck traffic would be greater for travel along roads that do
not normally have a large volume of traffic, especially truck traffic.
Figure 6.21 - A-Weighted Noise Emissions: Cruise Throttle, Average Pavement (New August 2011)

FHWA 1998.

Final SGEIS 2015, Page 6-302

 In addition to the trucks required to deliver the drill rig and its associated equipment, trucks are
used to bring in water for drilling and hydraulic fracturing, sand for hydraulic fracturing additive,
and frac tanks. Trucks are also used for the removal of flowback for the site. Estimates of truck
trips per well and truck trips over time during the early development phase of a horizontal and a
vertical well installation are presented in Section 6.11, Transportation.
Development of multiple wells on a single pad would add substantial additional truck traffic
volume in an area, which would be at least partially offset by a reduction in the number of well
pads overall.
This level of truck traffic could have negative noise impacts on those living in proximity to the
well site and access road. Like other noise associated with drilling, this would be temporary.
Current regulations require that all wells on a multi-well pad be drilled within three years of
starting the first well. Thus, it is possible that someone living in proximity to the pad would
experience adverse noise impacts intermittently for up to three years.
6.10.6 Gas Well Production
Once the well has been completed and the equipment has been demobilized, the pad is partially
reclaimed. The remaining wellhead production does not generate a significant level of noise.
Operation and maintenance activities could include a truck visit to empty the condensate
collection tanks on an approximately weekly basis, but condensate production from the
Marcellus Shale in New York is not typically expected. Mowing of the well pad area occurs
approximately two times per year. These activities would result in infrequent, short-term noise
events.
6.11

Transportation Impacts 407

While the trucking for site preparation, rig, equipment, materials, and supplies is similar for
horizontal drilling to what was anticipated in 1992, the water requirement of high–volume
hydraulic fracturing could lead to significantly more truck traffic than was discussed in the GEIS
in the regions where natural gas development would occur. This section presents (1) industry
407

Section 6.11, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011, and was adapted by
the Department.

Final SGEIS 2015, Page 6-303

 estimates on the number of heavy- and light-duty trucks needed for horizontal well drilling as
compared to vertical drilling that already takes place, (2) comparisons and reasonable scenarios
with which to gauge potential impacts on the existing road system and transportation network,
(3) potential impacts on roadways and the transportation network, and (4) potential impacts on
rail and air service.
6.11.1 Estimated Truck Traffic
The Department requested information from the Independent Oil & Gas Association of New
York (IOGA-NY) to estimate the number of truck trips associated with well construction.
6.11.1.1

Total Number of Trucks per Well

Table 6.60 presents the total estimated number of one-way (i.e., loaded) truck trips per horizontal
well during construction, and Table 6.61 presents the total estimated number of one-way truck
trips per vertical well during construction. Information is further provided on the distribution of
light- and heavy-duty trucks for each activity associated with well construction. Table 6.62
summarizes the total overall light- and heavy-duty truck trips per well for both vertical and
horizontal wells. The Department assumed that all truck trips provided in the industry estimates
were one-way trips; thus, to obtain the total vehicle trips, the numbers were doubled to obtain the
round-trips across the road network (Dutton and Blankenship 2010).
As discussed in 1992 regarding conventional vertical wells, trucking during the long-term
production life of a horizontally drilled single or multi-well pad would be insignificant.
IOGA-NY provided estimates of truck trips for two periods of development, as shown in Table
6.60 and Table 6.61: (1) a new well location completed early on in the development life of the
field, and (2) a well location completed during the peak development year. During the early well
pad development, all water is assumed to be transported to the site by truck. During the peak
well pad development, a portion of the wells are assumed to be accessible by pipelines for
transport of the water used in the hydraulic fracturing.
As shown in comparing the number of truck trips per well in Table 6.60 and Table 6.61, the
truck traffic associated with drilling a horizontal well with high-volume hydraulic fracturing is 2
to 3 times higher than the truck traffic associated with drilling a vertical well.

Final SGEIS 2015, Page 6-304

 Table 6.60 - Estimated Number of One-Way (Loaded) Trips Per Well:
Horizontal Well1 (New August 2011)

Well Pad Activity
Drill pad construction
Rig mobilization2
Drilling fluids
Non-rig drilling
equipment
Drilling (rig crew, etc.)
Completion chemicals
Completion equipment
Hydraulic fracturing
equipment (trucks and
tanks)
Hydraulic fracturing
water hauling3
Hydraulic fracturing
sand
Produced water disposal
Final pad prep
Miscellaneous
Total One-Way,
Loaded Trips Per Well

Early Well Pad Development
(all water transported by truck)
Heavy Truck
Light Truck
45
90
95
140
45
45
50
20
5
175

Peak Well Pad Development
(pipelines may be used for some
water transport)
Heavy Truck
Light Truck
45
90
95
140
45
45

140
326

50
20
5
175

500

60

23

23

100
45
1,148

17
45
625

50
85
831

140
326

50
85
795

Source: All Consulting 2010.
1.

Estimates are based on the assumption that a new well pad would be developed for each single horizontal well. However,
industry expects to initially drill two wells on each well pad, which would reduce the number of truck trips. The well pad
would, over time, be developed into a multi-well pad.

2.

Each well would require two rigs, a vertical rig and a directional rig.

3.

It was conservatively assumed that each well would use approximately 5 million gallons of water total and that all water
would be trucked to the site. This is substantially greater than the likely volume of water that would be trucked to the site.

Final SGEIS 2015, Page 6-305

 Table 6.61 - Estimated Number of One-Way (Loaded) Trips Per Well: Vertical Well (New August 2011)

Well Pad Activity

Early Well Pad Development
(all water transported by truck)

Drill pad construction
Rig mobilization
Drilling fluids
Non-rig drilling
equipment
Drilling (rig crew, etc.)
Completion chemicals
Completion equipment
Hydraulic fracturing
equipment (trucks and
tanks)
Hydraulic fracturing
water hauling
Hydraulic fracturing
sand
Produced water disposal
Final pad prep
Miscellaneous
Total One-Way,
Loaded Trips Per Well

Heavy Truck
32
50
15
10

Light Truck
90
140

30
10
5
75

70
72

Peak Well Pad Development
(pipelines may be used for some
water transport)
Heavy Truck
Light Truck
25
90
50
140
15
10
30
10
5
75

90

25

5

5

42
34
0
398

50
85
507

26
34
0
310

70
72

50
85
507

Source: All Consulting 2010.

Table 6.62 - Estimated Truck Volumes for Horizontal Wells Compared to Vertical Wells (New August 2011)

Light-duty trips
Heavy-duty trips
Combined Total
Total Vehicle Trips

Horizontal Well with High-Volume
Hydraulic Fracturing
Heavy Truck
Light Truck
831
795
1,148
625
1,975
1,420
3,950
2,840

Source: Dutton and Blankenship 2010
Note: The first three rows in this table are round trips; total vehicle trips are one-way trips.

Final SGEIS 2015, Page 6-306

Vertical Well
Heavy
Light
Truck
Truck
507
507
389
310
905
817
1,810
1,634

 6.11.1.2

Temporal Distribution of Truck Traffic per Well

Figure 6.22 shows the daily distribution of the truck traffic over the 50-day period of early well
pad development of a horizontal well and a vertical well (Dutton and Blankenship 2010). As
seen in the figure, certain phases of well development require heavier truck traffic (peaks in the
graph). Initial mobilization and drilling is comparable between horizontal and vertical wells;
however, from Day 20 to Day 35, the horizontal well requires significantly more truck transport
than the vertical well.
Figure 6.22 - Estimated Round-Trip Daily Heavy and Light Truck Traffic,
by Well Type - Single Well (New August 2011)

300

Horizontal

Vehicle Trips / Day

250

Vertical

200
150
100
50
0
1

7

13

19

25

31

37

43

49

Day

Source: Dutton and Blankenship 2010.

6.11.1.3

Temporal Distribution of Truck Traffic for Multi-Well Pads

The initial exploratory development using horizontal wells and high-volume hydraulic fracturing
would likely involve a single well on a pad. However, commercial demand would likely expand
development, resulting in multiple wells being drilled on a single pad, with each horizontal well
extending into a different sector of shale. Thus, horizontal wells would be able to access a larger
sector of the shale from a single pad site than would be possible for traditional development with
vertical wells. This means there would be less truck traffic for the development of the pad itself.

Final SGEIS 2015, Page 6-307

 There is a tradeoff, however, as each horizontal well utilizing the high-volume hydraulic
fracturing method of extraction would require more truck trips per well than vertical wells
(Dutton and Blankenship 2010).
Two development scenarios were proposed to estimate the truck traffic for horizontal and
vertical well development for multi-well pads (Dutton and Blankenship 2010). The key
parameters and assumptions are as follows:
Multi-pad Development Scenario 1: Horizontal Wells with High-Volume Hydraulic Fracturing:
•

Three rigs operated over a 120-day period.

•

Each rig drills four wells in succession, then moves off to allow for completion.

•

All water needed to complete the fracturing is hauled in via truck.

•

Fracturing and completion of the four wells occurs sequentially and tanks are brought in
once for all four wells.

•

At an average of 160 acres per well, the three rigs develop a total of 1,920 acres of land.

Multi-pad Development Scenario 2: Vertical Wells
•

Four rigs operated over a 120-day period

•

Each rig drills four wells, moving to a new location after drilling of a well is completed.

•

All water needed to complete the fracturing is hauled in via truck.

•

Fracturing and completion of each well occurs after the rig relocates to a new location.

•

At an average of 40 acres per well, the four rigs develop a total of 640 acres of land.

The extra yield of horizontal wells was compensated for by assuming that four vertical rigs were
utilized during the same time span as three horizontal rigs. The results of these two development
scenarios on a day-by-day basis are depicted in Figure 6.23 and Figure 6.24. As shown, the
number of vehicle trips varies depending on the number of wells per pad. Horizontal wells have
the highest volume of truck traffic in the last five weeks of well development, when fluid is
utilized in high volumes. This is in contrast to the more conventional vertical wells (see Figure
6.24), where the volume of truck traffic is more consistent throughout the period of development.

Final SGEIS 2015, Page 6-308

 Figure 6.23 - Estimated Daily Round-Trips of Heavy and Light Truck Traffic - Multi Horizontal Wells (New August 2011)

Total Truck Vehicle Trips - 3 Rigs Drilling 12 Horizontal Wells
900
Pad #3

800

Pad #2

Vehicle Trips / Day

700

Pad #1

600
500
400
300
200
100

120

113

106

99

92

85

78

71

64

57

50

43

36

29

22

15

8

1

0

Source: Dutton and Blankenship 2010.
Figure 6.24 - Estimated Round-Trip Daily Heavy and Light Truck Traffic - Multi Vertical Wells (New August 2011)

One-Way Truck Trips - 4 Rigs Drilling 16 Vertical Wells
900
800

Vehicle Trips / Day

700
600
500
400
300
200
100
0
1

9

17 25 33

41 49 57

65 73 81

Source: Dutton and Blankenship 2010.

Final SGEIS 2015, Page 6-309

89 97 105 113 121

 The major conclusions to be drawn from this comparison of the truck traffic resulting from the
use of horizontal and vertical wells are as follows (Dutton and Blankenship 2010):
•

Peak-day traffic volumes given sequential completions with multiple rigs drilling
horizontal wells along the same access road could be substantially higher than those for
multiple rigs drilling vertical wells.

•

The larger the area drained per horizontal well and the drilling of multiple wells from a
pad without moving a rig offsets some of the increase in truck traffic associated with the
high-volume fracturing.

•

Based on industry data and other assumptions applied for these scenarios, the total
number of vehicle trips generated by the three rigs drilling 12 horizontal wells is roughly
equivalent to the number of vehicle trips associated with four rigs drilling 16 vertical
wells. However, the horizontal wells require three-times the amount of land (1,920 acres
for horizontal wells versus 640 acres for vertical wells). Thus, developing the same
amount of land using vertical wells would either require three times longer, or would
require deployment of 12 rigs during the same period, effectively tripling the total
number of trips and result in peak daily traffic volumes above the levels associated with
horizontal wells.

Based upon the information presented in these two development scenarios, utilizing horizontal
wells and high-volume hydraulic fracturing rather than vertical wells to access a section of land
would reduce the total amount of truck traffic. However, because vertical well hydraulic
fracturing is not as efficient in its extraction of natural gas, it is not always economically feasible
for operators to pursue. Currently, it is estimated that 10% of the wells drilled to develop lowpermeability reservoirs with high-volume hydraulic fracturing will be vertical. Thus, the number
of permits requested by applicants and issued by NYSDEC has not been fully reached.
Horizontal drilling with high-volume hydraulic fracturing would be expected to result in a
substantial increase in permits, well construction, and truck traffic over what is present in the
current environment.
6.11.2 Increased Traffic on Roadways
As described in Section 6.8, Socioeconomics, three possible development scenarios are being
assessed in this SGEIS to reflect the uncertainties associated with the future development of
natural gas reserves in the Marcellus and Utica Shales – a high, medium and low development
scenario. Each development scenario is defined by the number of vertical and horizontal wells
drilled annually. (A summary of the development scenarios is provided in Section 6.8). Based
on the number of wells estimated in each development scenario and the estimated number of

Final SGEIS 2015, Page 6-310

 truck trips per well as discussed above in Section 6.1.1, the total estimated truck trips for all
wells developed annually is provided in Table 6.63. Annual trips are projected for Years 1
through 30 in 5-year increments. Estimated truck trips are provided for the three representative
regions (Regions A, B, and C), New York State outside of the three regions, and statewide.
The proposed action would also have an impact on traffic on federal, state, county, regional
local roadways. Given the generic nature of this analysis, and the lack of specific well pad
locations to permit the identification of specific road-segment impacts, the projected increase in
average annual daily traffic (AADT) and the associated impact on the level of service on specific
roadway segments, interchanges, and intersections cannot be determined. The AADT on
roadways can vary significantly, depending largely on functional class, and particularly whether
the count was taken in heavily populated communities or in proximity to heavily traveled
intersections/interchanges. Trucks traveling on higher level roadways along arterials and major
collectors are not anticipated to have a significant impact on traffic patterns and traffic flow, as
these roads are designed for a high level of vehicle traffic, and the anticipated increase in the
level of traffic associated with this action would only represent a small, incremental change in
existing conditions. However, certain local roads and minor collectors would likely experience
congestion during certain times of the day or during certain periods of well development.
Table 6.64 illustrates this variation by providing the highest and lowest AADT on three
functional class roads in three counties, one in each of the representative regions. The counts
presented are the lowest and highest counts on the identified road in the designated functional
class in the county.
On some roads, truck traffic generated by high-volume hydraulic fracturing operations may be
small compared to total AADT, as would be the case on I-17 in Binghamton, where AADT was
approximately 77,000 vehicles. In other cases, and particularly on collectors and minor arterials,
traffic from high-volume hydraulic fracturing could be a large share of AADT. Truck traffic
from high-volume hydraulic fracturing operations could also be a large share of total daily truck
traffic on specific stretches of certain interstates and be much larger than existing truck volumes
on lower functional class roads that serve natural gas wells or link the wells to major truck heads
such as water supply, rail trans-loading, and staging areas.

Final SGEIS 2015, Page 6-311

 Table 6.63 - Estimated Annual Heavy Truck Trips (in thousands) (New August 2011)

Region A
Region B
Region C
Counties Broome, Chemung, Tioga,
Delaware, Otsego, Sullivan
Cattaraugus, Chautauqua
Rest of New York State
State-Wide Totals
Low Development Scenario
Year Horizontal Vertical Total Horizontal Vertical Total Horizontal Vertical Total Horizontal Vertical Total Horizontal Vertical Total
1
4,334
226
4,561
2,053
113
2,166
456
0
456
1,597
113
1,710
8,441
453
8,893
5
21,216
1,245 22,460
9,809
566 10,375
2,053
113
2,166
9,353
453
9,806
42,431
2,376 44,807
10
42,431
2,376 44,807
19,391
1,132 20,522
4,334
226
4,561
18,478
1,018 19,496
84,634
4,752 89,387
15
42,431
2,376 44,807
19,391
1,132 20,522
4,334
226
4,561
18,478
1,018 19,496
84,634
4,752 89,387
20
42,431
2,376 44,807
19,391
1,132 20,522
4,334
226
4,561
18,478
1,018 19,496
84,634
4,752 89,387
25
42,431
2,376 44,807
19,391
1,132 20,522
4,334
226
4,561
18,478
1,018 19,496
84,634
4,752 89,387
30
42,431
2,376 44,807
19,391
1,132 20,522
4,334
226
4,561
18,478
1,018 19,496
84,634
4,752 89,387
Average Development Scenario
Year Horizontal Vertical Total Horizontal Vertical Total Horizontal Vertical Total Horizontal Vertical Total Horizontal Vertical Total
1
16,881
1,018 17,900
7,756
453
8,209
1,597
113
1,710
7,528
339
7,868
33,763
1,924 35,686
5
84,634
4,752 89,387
39,009
2,150 41,159
8,441
453
8,893
37,184
2,150 39,334
169,269
9,505 178,773
10
169,269
9,505 178,773
77,791
4,413 82,203
16,881
905 17,786
74,597
4,187 78,783
338,538 19,009 357,547
15
169,269
9,505 178,773
77,791
4,413 82,203
16,881
905 17,786
74,597
4,187 78,783
338,538 19,009 357,547
20
169,269
9,505 178,773
77,791
4,413 82,203
16,881
905 17,786
74,597
4,187 78,783
338,538 19,009 357,547
25
169,269
9,505 178,773
77,791
4,413 82,203
16,881
905 17,786
74,597
4,187 78,783
338,538 19,009 357,547
30
169,269
9,505 178,773
77,791
4,413 82,203
16,881
905 17,786
74,597
4,187 78,783
338,538 19,009 357,547
High Development Scenario
Year Horizontal Vertical Total Horizontal Vertical Total Horizontal Vertical Total Horizontal Vertical Total Horizontal Vertical Total
1
25,322
1,471 26,793
11,634
679 12,313
2,509
113
2,623
11,178
566 11,744
50,644
2,829 53,473
5
126,381
7,015 133,397
58,172
3,168 61,340
12,547
679 13,226
55,663
3,055 58,718
252,763 13,917 266,680
10
252,763 13,917 266,680
116,344
6,450 122,793
25,322
1,358 26,680
111,097
6,110 117,207
505,525 27,835 533,360
15
252,763 13,917 266,680
116,344
6,450 122,793
25,322
1,358 26,680
111,097
6,110 117,207
505,525 27,835 533,360
20
252,763 13,917 266,680
116,344
6,450 122,793
25,322
1,358 26,680
111,097
6,110 117,207
505,525 27,835 533,360
25
252,763 13,917 266,680
116,344
6,450 122,793
25,322
1,358 26,680
111,097
6,110 117,207
505,525 27,835 533,360
30
252,763 13,917 266,680
116,344
6,450 122,793
25,322
1,358 26,680
111,097
6,110 117,207
505,525 27,835 533,360

Final SGEIS 2015, Page 6-312

 Table 6.64 - Illustrative AADT Range for State Roads (New August 2011)

Functional
Class

County

Route

Interstate
Arterial
Collector
Interstate
Arterial
Collector
Interstate
Arterial
Collector

Delaware
Delaware
Delaware
Broome
Broome
Broome
Cattaraugus
Cattaraugus
Cattaraugus

88
28
357
17
26
41
86
219
353

AADT
Range,
(1,000s)
11 - 12
1-6
2-4
7 - 77
2 - 33
1
8 - 13
6 - 11
1-6

Estimated Average
Truck Volume
(1,000s)
2.40
0.30
0.02
7.00
1.00
0.01
2.00
1.00
0.20

AADT and Trucks rounded to the nearest 1,000.
Source: NYSDOT 2011

Although truck traffic is expected to significantly increase in certain locations, most of the
projected trips would be short. The largest component of the truck traffic for horizontal drilling
would be for water deliveries, and these would involve very short trips between the water
procurement area and the well pad. Since the largest category of truck trips involve water trucks
(600 of 1,148 heavy truck trips; see Table 6.60), it is anticipated that the largest impacts from
truck traffic would be near the wells under construction or on local roadways.
Development of the high-volume hydraulic fracturing gas resource would also result in direct
and indirect employment and population impacts, which would increase traffic on area roadways.
The Department, in consultation with NYSDOT, will undertake traffic monitoring in the regions
where well permit applications are most concentrated. These traffic studies and monitoring
efforts will be conducted and reviewed by NYSDOT and used to inform the development of road
use agreements by local governments, road repairs supported by development taxes, and other
mitigation strategies described in Chapter 7.13.
6.11.3 Damage to Local Roads, Bridges, and other Infrastructure
As a result of the anticipated increase in heavy- and light-duty truck traffic, local roads in the
vicinity of the well pads are expected to be damaged. Road damage could range from minor
fatigue cracking (i.e., alligator cracking) to significant potholes, rutting, and complete failure of

Final SGEIS 2015, Page 6-313

 the road structure. Extra truck traffic would also result in extra required maintenance for other
local road structures, such as bridges, traffic devices, and storm water runoff structures. Damage
could occur as normal wear and tear, particularly from heavy trucks, as well as from trucks that
may be on the margin of the road and directly running over culverts and other infrastructure that
is not intended to handle such loads.
As discussed in Section 2.3.14, the different classifications of roads are constructed to
accommodate different levels of service, defined by vehicle trips or vehicle class. Typically, the
higher the road classification, the more stringent the design standards and the higher the grade of
materials used to construct the road. The design of roads and bridges is based on the weight of
vehicles that use the infrastructure. Local roads are not typically designed to sustain a high level
of vehicle trips or loads and thus oftentimes have weight restrictions.
Maintenance and repair of the road infrastructure in New York currently strains the limited
budgets of the New York State Department of Transportation (NYSDOT) as well as the county
and local agencies responsible for local roads. Heavy trucks generally cause more damage to
roads and bridges than cars or light trucks due to the weight of the vehicle. A general “rule of
thumb” is that a single large truck is equivalent to the passing of 9,000 automobiles (Alaska
Department of Transportation and Public Facilities 2004). The higher functional classes of
roads, such as the interstate highways, generally receive better and more frequent maintenance
than the local roads that are likely to receive the bulk of the heavy truck traffic from the
development of shale gas.
Some wells would be located in rural areas where the existing roads are not capable of
accommodating the type of truck or number of truck trips that would occur during well
development. In addition, intersections, bridge capacities, bridge clearances, or other roadway
features may prohibit access to a well development site under current conditions. Applicants
would need to improve the roadway to accommodate the anticipated type and amount of truck
traffic, which would be implemented through a road use agreement with the local municipality.
This road use agreement may include an excess maintenance agreement to provide compensation
for impacts. These criteria are discussed further in Section 7.13, Mitigating Transportation and

Final SGEIS 2015, Page 6-314

 Road Use Impacts. Section 7.13 also discusses additional ways that compensatory mitigation
may be applied to pay for damages.
Actual costs associated with local roads and bridges cannot be determined because these costs
are a factor of (1) the number, location, and density of wells; (2) the actual truck routes and truck
volumes; (3) the existing condition of the roadway; (4) the specific characteristics of the road or
bridge (e.g., the number of lanes, width, pavement type, drainage type, appurtenances, etc.); and
(5) the type of treatment warranted. However, based on a sample of 147 local bridges with a
condition rating of 6 (i.e., Fair to Poor) in Broome, Chemung, and Tioga counties, estimates of
replacement costs could range from $100,000 to $24 million per bridge, and averaged $1.5
million per bridge. The NYSDOT estimates that bridges with a condition rating of 6 or below
would be impacted by the projected increase in truck traffic, resulting in accelerated
deterioration, and warrant replacement. Because these routes were often built to lower standards,
heavy trucks would have a much greater impact than other types of traffic.
According to the NYSDOT, the costs of repair to damaged pavement on local roads also varies
widely depending on the type of work necessary and the characteristics of the road. Low-level
maintenance treatments such as a single course overlay, would range from $70,000 to $150,000
per lane mile. Higher-level maintenance such as rubberizing and crack and seat rehabilitation
would range from $400,000 to $530,000 per lane mile. Full-depth reconstruction can range from
$490,000 to $1.9 million per lane mile.
6.11.4 Damage to State Roads, Bridges, and other Infrastructure
For roads of higher classification in the arterial or major collector categories, the general
construction of the roads would be adequate to sustain the projected travel of heavy- and lighttrucks associated with horizontal drilling and high-volume hydraulic fracturing. However, there
would be an incremental deterioration of the expected life of these roads due to the estimated
thousands of vehicle trips that would occur because of the increase in drilling activity. These
larger roads are part of the public road network and have been built to service the areas of the
state for passenger, commercial, and industrial traffic; however, the loads and numbers of heavy
trucks proposed by this action could effectively reduce the lifespan of several roads, requiring

Final SGEIS 2015, Page 6-315

 unanticipated and early repairs or reconstruction, which would burden of the State and its
taxpayers.
When the cumulative and induced impacts of the total high-volume hydraulic fracturing gas
development are considered, the resulting traffic impacts can be considerable. The principal
cumulative traffic impacts would occur during drilling and well development. Impacts on the
road, bridge, and other infrastructure would be primarily from the cumulative impact of heavy
trucking.
Actual costs to roads of higher functional classification cannot be determined because these costs
are a factor of (1) the number, location and density of wells; (2) the actual truck routes and truck
volumes; (3) the existing condition of the roadway; (4) the specific characteristics of the road or
bridge (e.g., the number of lanes, width, pavement type, drainage type, appurtenances, etc.); and
(5) the type of treatment warranted, similar to the local roads discussed above.
However, based on a sample of 166 state bridges with a condition rating of 6 (i.e., Fair to Poor)
in Broome, Chemung, and Tioga counties, estimates of replacement costs could range from
$100,000 to $31 million per bridge, and averaged $3.3 million per bridge. The NYSDOT
estimates that bridges with a condition rating of 6 or below would be impacted by the projected
increase in truck traffic, resulting in accelerated deterioration, and warrant replacement.
According to the NYSDOT, the costs of repair to damaged pavement on state roads also varies
widely depending on the type of work necessary and the characteristics of the road. Low-level
maintenance treatments such as a single-course overlay, would range from $90,000 to $180,000
per lane mile. Higher-level maintenance such as rubberizing and crack and seat rehabilitation
would range from $540,000 to $790,000 per lane mile. Full depth reconstruction can range from
$910,000 to $2.1 million per lane mile.
Depending on the volume and location of high-volume hydraulic fracturing, there is a possibility
that a number of bridges and certain segments of state roads would require higher levels of
maintenance and possibly replacement. The extent of such road work that would be attributable
to high-volume hydraulic fracturing cannot be calculated because the proportion of truck and
vehicular traffic attributable to such operations compared to truck and vehicular traffic

Final SGEIS 2015, Page 6-316

 attributable to other industries on any particular road would vary significantly. On collectors and
minor arterials, there is a potential for greater impacts from this activity because these routes
were often built to lower standards, and thus, heavy trucks would have a much greater impact
than other types of traffic. As a result, actual contribution of heavy trucks to road and bridge
deterioration would be greater than suggested by their proportion to total traffic. Conversely,
any additional traffic on higher functional class roads, and especially interstates and major
arterials, would result in little impact because these roads were built to higher construction and
pavement standards.
6.11.5 Operational and Safety Impacts on Road Systems
An increase in the amount of truck traffic, and vehicular traffic in general, traveling on both
higher and lower level local roads would most likely increase the number of accidents and
breakdowns in areas experiencing well development. These potential breakdowns and accidents
would require the response of public safety and other transportation-related services (e.g., tow
trucks). Local road commissions and the NYSDOT would also likely incur costs associated with
operational and safety improvements.
The costs of implementing operational and safety improvements on local roads would vary
widely depending on the type of treatment required. Improvements on turn lanes could cost from
$17,000 to $34,000, and the provision of signals and intersection could cost from approximately
$35,000 for the installation of flashing red/yellow signals and from $100,000 to $150,000 for the
installation of three-color signals.
The costs of addressing operational and safety impacts on state roads also would vary widely
depending on the type of treatment required. The most common treatments include constructing
turn lanes, with costs ranging from $20,000 to $40,000 on state roads, and installing signals and
intersections, where costs range from approximately $35,000 for the installation of flashing
red/yellow signals and from $100,000 to $150,000 for the installation of three-color signals.
The cost of addressing capacity and flow constraints stemming from high levels of truck traffic
or direct and indirect employment and population traffic volumes are much greater, however,

Final SGEIS 2015, Page 6-317

 and might approach $1 million per lane per mile (roughly the cost of full reconstruction), not
including the costs of acquiring rights-of-way.
6.11.6 Transportation of Hazardous Materials
Vertical wells do not require the volumes of chemicals that would require consideration of
hazardous chemicals beyond the use of diesel fuel for the equipment on the surface. The truck
traffic supporting the development of the horizontal wells involving high-volume hydraulic
fracturing would be transporting a variety of equipment, supplies, and potentially hazardous
materials.
As described in Section 5.4 of the SGEIS, fracturing fluid is 98% freshwater and sand and 2% or
less chemical additives. There are 12 classes of chemical additives that could be in the
hazardous waste water being trucked to or from a location. Additive classes include: proppant,
acid, breaker, bactericide/biocide, clay stabilizer/control, corrosion inhibitor, cross linker,
friction reducer, gelling agent, iron control, scale inhibitor, and surfactant. These classes are
described in full detail in Section 5.4, Table 5.6. Although the composition of fracturing fluid
varies from one geologic basin or formation to another, the range of additive types available for
potential use remains the same. The selection may be driven by the formation and potential
interactions between additives, and not all additive types would be utilized in every fracturing
job (see Section 5.4). Table 5.7 (Section 5.4) shows the constituents of all hydraulic fracturingrelated chemicals submitted to NYSDEC to date for potential use at shale wells within New
York. Only a handful of these chemicals would be utilized at a single well. Data provided to
NYSDEC to date indicates that similar fracturing fluids are needed for vertical and horizontal
drilling methods.
Trucks transporting hazardous materials to the various well locations would be governed by
USDOT regulations, as discussed in Section 5.5 and Chapter 8. Transportation of any hazardous
materials always carries some risks from spills or accidents. Hazardous materials are moved
daily across the state without incident, but the additional transport resulting from horizontal
drilling poses an additional risk, which could be an adverse impact if spills occur.

Final SGEIS 2015, Page 6-318

 6.11.7 Impacts on Rail and Air Travel
The development of high-volume hydraulic fracturing natural gas would require the movement
of large quantities of pipe, drilling equipment, and other large items from other locations and
from manufacturing sites that are likely far away from the well sites. Rail provides an
inexpensive and efficient means of moving such material. The final movement, from rail depots
to the well sites, would be accomplished with large trucks. The extent of rail and the choice of
unloading locations depends on the well sites and cannot be predicted at this time. However, the
use of rail to transport materials would have several predictable results:
•

Total truck traffic would decrease;

•

Truck traffic near the rail terminals would increase,

•

Truck traffic on the arterials between the terminals and well fields would increase.

These positive and negative impacts would likely alleviate some impacts but might exacerbate
impacts in neighborhoods along the routes to and from the rail centers. These impacts would
require examination as part of road use agreements.
The heavy, bulky, equipment utilized for horizontal drilling would not likely be transported by
air. However, the large numbers of temporary workers that the industry would employ would
likely utilize the network of small airports and commuter airlines that service New York State.
This would increase the traffic to and from these airports. None of the regional airports in New
York State are at capacity, so the air travel is not expected to be a significant impact. In fact, the
extra economic activity would be positive. However, residents that are along approach and
departure corridors would experience more noise from increased service by airplanes.
6.12

Community Character Impacts 408

High-volume hydraulic fracturing operations could potentially have a significant impact on the
character of communities where drilling and production activities would occur. Both short-term
and long-term, impacts could result if this potentially large-scale industry were to start
operations. Experiences in Pennsylvania and West Virginia show that wholesale development of
408

Section 6.12, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011, and was adapted by
the Department.

Final SGEIS 2015, Page 6-319

 the low-permeable shale reserves could lead to changes in the economic, demographic, and
social characteristics of the affected communities.
While some of these impacts are expected to be significant, the determination of whether these
impacts are positive or negative cannot be made. Change would occur in the affected
communities, but how this change is viewed is subjective and would vary from individual to
individual. This section, therefore, seeks to identify expected changes that could occur to the
economic and social makeup of the impacted communities, but it does not attempt to make a
judgment on whether such change is beneficial or harmful to the local community character.
The amount of the change in community character that is expected to occur would be impacted
by several factors. However, the most important factors would be the speed at which highvolume hydraulic fracturing activities would occur and the overall level of the natural gas
activities. Slow, moderate growth of the industry, if it were spread over several years, would
generate much less acute impacts than rapid expansion over a limited time. Community
character is constantly in a state of flux; a community’s sense of place is constantly revised and
adapts as social, demographic, and economic conditions change. When these changes are
gradual, residents are given time to adapt and accommodate to the new conditions and typically
do not view them as negative. When these changes are abrupt and dramatic, residents typically
find them more adverse.
If the high-volume hydraulic fracturing operations reach some of the more optimistic
development levels described in previous sections, the size and structure of the regional
economies could be influenced by this new industry. Local communities that have experienced
declining employment and population levels for decades could quickly become some of the
fastest growing communities in the state. Traditional employment sectors could decline in
importance while new employment sectors, such as the natural gas extraction industry and its
suppliers, could expand in importance. Employment opportunities would increase in the
communities and the types of jobs offered would change.
Total population would increase in the communities and the demographic makeup of these
populations would change. In-migration resulting from the high-volume hydraulic fracturing

Final SGEIS 2015, Page 6-320

 operations would bring a racially and ethnically diverse workforce into the area. Most of the
new population would be working age or their dependents. In addition, most of the employment
opportunities created would be for skilled blue collar jobs.
In addition to employment and demographic impacts, the proposed high-volume hydraulic
fracturing would greatly increase income and earnings throughout affected communities.
Royalty payments to local landowners, increased payroll earnings from the natural gas industry,
added profits to firms that supply the natural gas industry, and added earnings from all of the
induced economic activity that would occur in the communities would all add to the affluence of
the region. While total income in the communities would increase, this added income and
wealth would not be evenly distributed. Landowners that lease out their subsurface mineral
rights would benefit financially from the high-volume hydraulic fracturing operations; however,
those residents that do not own the subsurface mineral rights or chose not to exploit these rights
would not see the same financial benefits. Some entrepreneurs and property owners would see
large financial gains from the increase in economic activity, other residents may experience a
rise in living expenses without enjoying any corresponding financial gains.
In some areas, the housing market would experience an increase in value and price if there is not
sufficient outstanding supply to meet the increased demand. Existing property owners would
most likely benefit; residents not already property owners could experience price rises and
difficulties entering the market. Additional housing would most likely be constructed in response
to increased demand, and in certain instances such development could occur on currently
undeveloped land. Activities that achieve lower financial returns on property, such as
agriculture, may be considered less desirable compared to housing developments. While at the
same time, farmers who own large tracts of land could also benefit greatly from the royalty
payments on the new natural gas wells.
Local governments would see a rapid expansion in the amount of sales tax and property tax
generated by gas drilling and would now have the funding to complete a wide range of
community projects. At the same time, the large influx of population would demand additional
community services and facilities. Existing facilities would likely become overcrowded, and
additional new facilities would have to be built to accommodate this new population.

Final SGEIS 2015, Page 6-321

 Commuting patterns in the affected communities would also change. An increase in traffic both
from the added truck transportation and from the additional population would likely increase
traffic on certain areas roadways and, as further explained in the Transportation subchapter,
would likely lead to the need for road improvements, reconstruction and repairs.
Ambient noise levels in the communities would likely increase as a direct result of drilling and
additional traffic at the well pads, and as a result of increased development in the region (see
Section 2.3.13). Aesthetic resources and viewsheds could be at least temporarily impacted and
changed during well pad construction and development (see Section 2.3.12).
6.13

Seismicity 409

Economic development of natural gas from low permeability formations requires the target
formation to be hydraulically fractured to increase the rock permeability and expose more rock
surface to release the gas trapped within the rock. The hydraulic fracturing process fractures the
rock by controlled application of hydraulic pressure in the wellbore. The direction and length of
the fractures are managed by carefully controlling the applied pressure during the hydraulic
fracturing process.
The release of energy during hydraulic fracturing produces seismic pressure waves in the
subsurface. Microseismic monitoring commonly is performed to evaluate the progress of
hydraulic fracturing and adjust the process, if necessary, to limit the direction and length of the
induced fractures. Chapter 4 of this SGEIS presents background seismic information for New
York. Concerns associated with the seismic events produced during hydraulic fracturing are
discussed below.
6.13.1 Hydraulic Fracturing-Induced Seismicity
Seismic events that occur as a result of injecting fluids into the ground are termed “induced.”
There are two types of induced seismic events that may be triggered as a result of hydraulic
fracturing. The first is energy released by the physical process of fracturing the rock which
creates microseismic events that are detectable only with very sensitive monitoring equipment.

409

Alpha, 2009, Section 7; discussion was provided for NYSERDA by Alpha Environmental, Inc., and Alpha’s references are
included for informational purposes.

Final SGEIS 2015, Page 6-322

 Information collected during the microseismic events is used to evaluate the extent of fracturing
and to guide the hydraulic fracturing process. This type of microseismic event is a normal part
of the hydraulic fracturing process used in the development of both horizontal and vertical oil
and gas wells, and by the water well industry.
The second type of induced seismicity is fluid injection of any kind, including hydraulic
fracturing, which can trigger seismic events ranging from imperceptible microseismic, to smallscale, “felt” events, if the injected fluid reaches an existing geologic fault. A “felt” seismic event
is when earth movement associated with the event is discernable by humans at the ground
surface. Hydraulic fracturing produces microseismic events, but different injection processes,
such as waste disposal injection or long term injection for enhanced geothermal, may induce
events that can be felt, as discussed in the following section. Induced seismic events can be
reduced by engineering design and by avoiding existing fault zones.
6.13.1.1

Background

Hydraulic fracturing consists of injecting fluid into a wellbore at a pressure sufficient to fracture
the rock within a designed distance from the wellbore. Other processes where fluid is injected
into the ground include deep well fluid disposal, fracturing for enhanced geothermal wells,
solution mining and hydraulic fracturing to improve the yield of a water supply well. The
similar aspect of these methods is that fluid is injected into the ground to fracture the rock;
however, each method also has distinct and important differences.
There are ongoing and past studies that have investigated small, felt, seismic events that may
have been induced by injection of fluids in deep disposal wells. These small seismic events are
not the same as the microseismic events triggered by hydraulic fracturing that can only be
detected with the most sensitive monitoring equipment. The processes that induce seismicity in
both cases are very different.
Deep well injection is a disposal technology which involves liquid waste being pumped under
moderate to high pressure, several thousand feet into the subsurface, into highly saline,
permeable injection zones that are confined by more shallow, impermeable strata (FRTR, August

Final SGEIS 2015, Page 6-323

 12, 2009). The goal of deep well injection is to store the liquids in the confined formation(s)
permanently.
Carbon sequestration is also a type of deep well injection, but the carbon dioxide emissions from
a large source are compressed to a near liquid state. Both carbon sequestration and liquid waste
injection can induce seismic activity. Induced seismic events caused by deep well fluid injection
are typically less than a magnitude 3.0 and are too small to be felt or to cause damage. Rarely,
fluid injection induces seismic events with moderate magnitudes, between 3.5 and 5.5, that can
be felt and may cause damage. Most of these events have been investigated in detail and have
been shown to be connected to circumstances that can be avoided through proper site selection
(avoiding fault zones) and injection design (Foxall and Friedmann, 2008).
Hydraulic fracturing also has been used in association with enhanced geothermal wells to
increase the permeability of the host rock. Enhanced geothermal wells are drilled to depths of
many thousands of feet where water is injected and heated naturally by the earth. The rock at the
target depth is fractured to allow a greater volume of water to be re-circulated and heated.
Recent geothermal drilling for commercial energy-producing geothermal projects have focused
on hot, dry, rocks as the source of geothermal energy (Duffield, 2003). The geologic conditions
and rock types for these geothermal projects are in contrast to the shallower sedimentary rocks
targeted for natural gas development. The methods used to fracture the igneous rock for
geothermal projects involve high pressure applied over a period of many days or weeks
(Florentin 2007 and Geoscience Australia, 2009). These methods differ substantially from the
lower pressures and short durations used for natural gas well hydraulic fracturing.
Hydraulic fracturing is a different process that involves injecting fluid under higher pressure for
shorter periods than the pressure level maintained in a fluid disposal well. A horizontal well is
fractured in stages so that the pressure is repeatedly increased and released over a short period of
time necessary to fracture the rock. The subsurface pressures for hydraulic fracturing are
sustained typically for one or two days to stimulate a single well, or for approximately two
weeks at a multi-well pad. The seismic activity induced by hydraulic fracturing is only
detectable at the surface by very sensitive equipment.

Final SGEIS 2015, Page 6-324

 Avoiding pre-existing fault zones minimizes the possibility of triggering movement along a fault
through hydraulic fracturing. It is important to avoid injecting fluids into known, significant,
mapped faults when hydraulic fracturing. Generally, operators would avoid faults because they
disrupt the pressure and stress field and the hydraulic fracturing process. The presence of faults
also potentially reduces the optimal recovery of gas and the economic viability of a well or wells.
Injecting fluid into the subsurface can trigger shear slip on bedding planes or natural fractures
resulting in microseismic events. Fluid injection can temporarily increase the stress and pore
pressure within a geologic formation. Tensile stresses are formed at each fracture tip, creating
shear stress (Pinnacle; “FracSeis;” August 11, 2009). The increases in pressure and stress reduce
the normal effective stress acting on existing fault, bedding, or fracture planes. Shear stress then
overcomes frictional resistance along the planes, causing the slippage (Bou-Rabee and Nur,
2002). The way in which these microseismic events are generated is different than the way in
which microseisms occur from the energy release when rock is fractured during hydraulic
fracturing.
The amount of displacement along a plane that is caused by hydraulic fracturing determines the
resultant microseism’s amplitude. The energy of one of these events is several orders of
magnitude less than that of the smallest earthquake that a human can feel (Pinnacle;
“Microseismic;” August 11, 2009). The smallest measurable seismic events are typically
between 1.0 and 2.0 magnitude. In contrast, seismic events with magnitude 3.0 are typically
large enough to be felt by people. Many induced microseisms have a negative value on the
MMS. Pinnacle Technologies, Inc. has determined that the characteristic frequencies of
microseisms are between 200 and 2,000 Hertz; these are high-frequency events relative to typical
seismic data. These small magnitude events are monitored using extremely sensitive instruments
that are positioned at the fracture depth in an offset wellbore or in the treatment well (Pinnacle;
“Microseismic;” August 11, 2009). The microseisms from hydraulic fracturing can barely be
measured at ground surface by the most sensitive instruments (Sharma, personal communication,
August 7, 2009).
There are no seismic monitoring protocols or criteria established by regulatory agencies that are
specific to high volume hydraulic fracturing. Nonetheless, operators monitor the hydraulic

Final SGEIS 2015, Page 6-325

 fracturing process to optimize the results for successful gas recovery. It is in the operator’s best
interest to closely control the hydraulic fracturing process to ensure that fractures are propagated
in the desired direction and distance and to minimize the materials and costs associated with the
process.
The routine microseismic monitoring that is performed during hydraulic fracturing serves to
evaluate, guide, and control the process and is important in optimizing well treatments. Multiple
receivers on a wireline array are placed in one or more offset borings (new, unperforated well(s)
or older well(s) with production isolated) or in the treatment well to detect microseisms and to
monitor the hydraulic fracturing process. The microseism locations are triangulated using the
arrival times of the various p- and s-waves with the receivers in several wells, and using the
formation velocities to determine the location of the microseisms. A multi-level vertical array of
receivers is used if only one offset observation well is available. The induced fracture is
interpreted to lie within the envelope of mapped microseisms (Pinnacle; “FracSeis;” August 11,
2009).
Data requirements for seismic monitoring of a hydraulic fracturing treatment include formation
velocities (from a dipole sonic log or cross-well tomogram), well surface and deviation surveys,
and a source shot in the treatment well to check receiver orientations, formation velocities and
test capabilities. Receiver spacing is selected so that the total aperture of the array is about half
the distance between the two wells. At least one receiver should be in the treatment zone, with
another located above and one below this zone. Maximum observation distances for
microseisms should be within approximately 2,500 feet of the treatment well; the distance is
dependent upon formation properties and background noise level (Pinnacle; “FracSeis;” August
11, 2009).
6.13.1.2

Recent Investigations and Studies

Hydraulic fracturing has been used by oil and gas companies to stimulate production of vertical
wells in New York State since the 1950s. Despite this long history, there are no records of
induced seismicity caused by hydraulic fracturing in New York State. The only induced
seismicity studies that have taken place in New York State are related to seismicity suspected to
have been caused by waste fluid disposal by injection and a mine collapse, as identified in

Final SGEIS 2015, Page 6-326

 Section 4.5.4. The seismic events induced at the Dale Brine Field (Section 4.5.4) were the result
of the injection of fluids for extended periods of time at high pressure for the purpose of salt
solution mining. This process is significantly different from the hydraulic fracturing process that
would be undertaken for developing the Marcellus and other low-permeability shales in New
York.
Gas producers in Texas have been using horizontal drilling and high-volume hydraulic fracturing
to stimulate gas production in the Barnett Shale for the last decade. The Barnett is geologically
similar to the Marcellus, but is found at a greater depth; it is a deep shale with gas stored in
unconnected pore spaces and adsorbed to the shale matrix. High-volume hydraulic fracturing
allows recovery of the gas from the Barnett to be economically feasible. The horizontal drilling
and high-volume hydraulic fracturing methods used for the Barnett Shale play are similar to
those that would be used in New York State to develop the Marcellus, Utica, and other gas
bearing shales.
Alpha contacted several researchers and geologists who are knowledgeable about seismic
activity in New York and Texas, including:
•

Mr. John Armbruster, Staff Associate, Lamont-Doherty Earth Observatory, Columbia
University;

•

Dr. Cliff Frohlich, Associate Director of the Texas Institute for Geophysics, The
University of Texas at Austin;

•

Dr. Won-Young Kim, Doherty Senior Research Scientist, Lamont-Doherty Earth
Observatory, Columbia University;

•

Mr. Eric Potter, Associate Director of the Texas Bureau of Economic Geology, The
University of Texas at Austin;

•

Mr. Leonardo Seeber, Doherty Senior Research Scientist, Lamont-Doherty Earth
Observatory, Columbia University;

•

Dr. Mukul Sharma, Professor of Petroleum and Geosystems Engineering, The University
of Texas at Austin; and

•

Dr. Brian Stump, Albritton Professor, Southern Methodist University.

Final SGEIS 2015, Page 6-327

 None of these researchers have knowledge of any seismic events that could be explicitly related
to hydraulic fracturing in a shale gas well. Mr. Eric Potter stated that approximately 12,500
wells in the Barnett play and several thousand wells in the East Texas Basin (which target tight
gas sands) have been stimulated using hydraulic fracturing in the last decade, and there have
been no documented connections between wells being fractured hydraulically and felt quakes
(personal communication, August 9, 2009). Dr. Mukul Sharma confirmed that microseismic
events associated with hydraulic fracturing can only be detected using very sensitive instruments
(personal communication, August 7, 2009).
The Bureau of Geology, the University of Texas’ Institute of Geophysics, and Southern
Methodist University (SMU) are planning to study earthquakes measured in the vicinity of the
Dallas - Fort Worth (DFW) area, and Cleburne, Texas, that appear to be associated with salt
water disposal wells, and oil and gas wells. The largest quakes in both areas were magnitudes of
3.3, and more than 100 earthquakes with magnitudes greater than 1.5 have been recorded in the
DFW area in 2008 and 2009. There is considerable oil and gas drilling and deep brine disposal
wells in the area and a small fault extends beneath the DFW area. Dr. Frohlich recently stated
that “[i]t’s always hard to attribute a cause to an earthquake with absolute certainty.” Dr.
Frohlich has two manuscripts in preparation with SMU describing the analysis of the DFW
activity and the relationship with gas production activities (personal communication, August 4
and 10, 2009). Neither of these manuscripts was available before this document was completed.
Nonetheless, information posted online by SMU (2009) states that the research suggests that the
earthquakes seem to have been caused by injections associated with a deep production brine
disposal well, and not with hydraulic fracturing operations.
6.13.1.3

Correlations between New York and Texas

The gas plays of interest, the Marcellus and Utica Shales in New York and the Barnett Shale in
Texas, are relatively deep, low-permeability, gas shales deposited during the Paleozoic Era.
Horizontal drilling and high-volume hydraulic fracturing methods are required for successful,
economical gas production. The Marcellus Shale was deposited during the early Devonian, and
the slightly younger Barnett was deposited during the late Mississippian. The depth of the
Marcellus in New York ranges from exposure at the ground surface in some locations in the
northern Finger Lakes area to 7,000 feet or more below the ground surface at the Pennsylvania

Final SGEIS 2015, Page 6-328

 border in the Delaware River valley. The depth of the Utica Shale in New York ranges from
exposure at the ground surface along the southern Adirondacks to more than 10,000 feet along
the New York Pennsylvania border.
Conditions for economic gas recovery likely are present only in portions of the Marcellus and
Utica members, as described in Chapter 4. The thickness of the Marcellus and Utica in New
York ranges from less than 50 feet in the southwestern portion of the state to approximately 250
feet at the south-central border. The Barnett Shale is 5,000 to 8,000 feet below the ground
surface and 100 to 500 feet thick (Halliburton; August 12, 2009). It has been estimated that the
entire Marcellus Shale may hold between 168 and 516 trillion cubic feet of gas; in contrast, the
Barnett has in-place gas reserves of approximately 26.2 trillion cubic feet (USGS, 2009A) and
covers approximately 4 million acres.
The only known induced seismicity associated with the stimulation of the Barnett wells are
microseisms that are monitored with downhole transducers. These small-magnitude events
triggered by the fluid pressure provide data to the operators to monitor and improve the
fracturing operation and maximize gas production. The hydraulic fracturing and monitoring
operations in the Barnett have provided operators with considerable experience with conditions
similar to those that would be encountered in New York State. Based on the similarity of
conditions, similar results are anticipated for New York State; that is, the microseismic events
would be unfelt at the surface and no damage would result from the induced microseisms.
Operators are likely to monitor the seismic activity in New York, as in Texas, to optimize the
hydraulic fracturing methods and results.
6.13.1.4

Affects of Seismicity on Wellbore Integrity

Wells are designed to withstand deformation from seismic activity. The steel casings used in
modern wells are flexible and are designed to deform to prevent rupture. The casings can
withstand distortions much larger than those caused by earthquakes, except for those very close
to an earthquake epicenter. The magnitude 6.8 earthquake event in 1983 that occurred in
Coalinga, California, damaged only 14 of the 1,725 nearby active oilfield wells, and the energy
released by this event was thousands of times greater than the microseismic events resulting from
hydraulic fracturing. Earthquake-damaged wells can often be re-completed. Wells that cannot

Final SGEIS 2015, Page 6-329

 be repaired are plugged and abandoned (Foxall and Friedmann, 2008). Induced seismicity from
hydraulic fracturing is of such small magnitude that it is not expected to have any effect on
wellbore integrity.
6.13.2 Summary of Potential Seismicity Impacts
The issues associated with seismicity related to hydraulic fracturing addressed herein include
seismic events generated from the physical fracturing of the rock, and possible seismic events
produced when fluids are injected into existing faults.
The possibility of fluids injected during hydraulic fracturing the Marcellus or Utica Shales
reaching a nearby fault and triggering a seismic event are remote for several reasons. The
locations of major faults in New York have been mapped (Figure 4.13) and few major or
seismically active faults exist within the fairways for the Marcellus and Utica Shales. Similarly,
the paucity of historic seismic events and the low seismic risk level in the fairways for these
shales indicates that geologic conditions generally are stable in these areas. By definition, faults
are planes or zones of broken or fractured rock in the subsurface. The geologic conditions
associated with a fault generally are unfavorable for hydraulic fracturing and economical
production of natural gas. As a result, operators typically endeavor to avoid faults for both
practical and economic considerations. It is prudent for an applicant for a drilling permit to
evaluate and identify known, significant, mapped, faults within the area of effect of hydraulic
fracturing and to present such information in the drilling permit application. It is Alpha’s
opinion that an independent pre-drilling seismic survey probably is unnecessary in most cases
because of the relatively low level of seismic risk in the fairways of the Marcellus and Utica
Shales. Additional evaluation or monitoring may be necessary if hydraulic fracturing fluids
might reach a known, significant, mapped fault, such as the Clarendon-Linden fault system.
Recent research has been performed to investigate induced seismicity in an area of active
hydraulic fracturing for natural gas development near Fort Worth, Texas. Studies also were
performed to evaluate the cause of the earthquakes associated with the solution mining activity
near the Clarendon-Linden fault system near Dale, NY in 1971. The studies indicated that the
likely cause of the earthquakes was the injection of fluid for production brine disposal for the
incidents in Texas, and the injection of fluid for solution mining for the incidents in Dale, NY

Final SGEIS 2015, Page 6-330

 The studies in Texas also indicate that hydraulic fracturing is not likely the source of the
earthquakes.
The hydraulic fracturing methods used for enhanced geothermal energy projects are appreciably
different than those used for natural gas hydraulic fracturing. Induced seismicity associated with
geothermal energy projects occurs because the hydraulic fracturing is performed at greater
depths, within different geologic conditions, at higher pressures, and for substantially longer
durations compared with the methods used for natural gas hydraulic fracturing.
There is a reasonable base of knowledge and experience related to seismicity induced by
hydraulic fracturing. Information reviewed in preparing this discussion indicates that there is
essentially no increased risk to the public, infrastructure, or natural resources from induced
seismicity related to hydraulic fracturing. The microseisms created by hydraulic fracturing are
too small to be felt, or to cause damage at the ground surface or to nearby wells.
Seismic monitoring by the operators is performed to evaluate, adjust, and optimize the hydraulic
fracturing process. Monitoring beyond that which is typical for hydraulic fracturing does not
appear to be warranted, based on the negligible risk posed by the process and very low seismic
magnitude. The existing and well-established seismic monitoring network in New York is
sufficient to document the locations of larger-scale seismic events and would continue to provide
additional data to monitor and evaluate the likely sources of seismic events that are felt.

Final SGEIS 2015, Page 6-331

 Photo 6.9 The following series of photos shows Trenton-Black River wells in Chemung County. These wells are
substantially deeper than Medina wells, and are typically drilled on 640 acre units. Although the units and well
pads typically contain one well, the size of the well units and pads is closer to that expected for multi-well Marcellus pads. Unlike expected Marcellus wells, Trenton-Black River wells target geologic features that are typically
narrow and long. Nevertheless, photos of sections of Trenton-Black River fields provide an idea of the area of well
pads within producing units.
The above photo of Chemung County shows Trenton-Black River wells and also historical wells that targeted other
formations. Most of the clearings visible in this photo are agricultural fields.

Final SGEIS 2015, Page 6-332

 Photo 6.10 The Quackenbush Hill Field is a Trenton-Black River field that runs from eastern Steuben County to
north-west Chemung County. The discovery well for the field was drilled in 2000. The map below shows wells
in the eastern end of the field. Note the relative proportion of well pads to area of entire well units. The unit
sizes shown are approximately 640 acres, similar to expected Marcellus Shale multi-well pad units.

6

5

4

7

Photos 6.11 Well #4 (Hole number 22853) was a vertical completed in February 2001 at a true vertical depth of
9,682 feet. The drill site disturbed area was approximately 3.5 acres. The site was subsequently reclaimed to a
fenced area of approximately 0.35 acres for production equipment. Because this is a single-well unit, it contains
fewer tanks and other equipment than a Marcellus multi-well pad. The surface within a Trenton-Black River well
fenced area is typically covered with gravel.

4
Rhodes 1322 11/13/2001

4
Rhodes 1322 5/6/2009

Final SGEIS 2015, Page 6-333

 Photos 6.12 Well #5 (Hole number 22916) was completed as a directional well in 2002. Unit size is 636 acres. Total
drill pad disturbed area was approximately 3 acres, which has been reclaimed to a fenced area of approximately 0.4
acres.

5

5
Gregory #1446A 12/27/2001

Gregory #1446A 5/6/2009

Photo 6.13 Well #6 (Hole number 23820) was drilled as a horizontal infill well in 2006 in the same unit as Well #6.
Total drill pad disturbed area was approximately 3.1 acres, which has been reclaimed to a fenced area of approximately 0.4 acres.

6
Schwingel #2 5/6/2009

Final SGEIS 2015, Page 6-334

 Photos 6.14 Well #7 (Hole number 23134) was completed as a horizontal well in 2004 to a true vertical depth of 9,695
and a true measured depth of 12,050 feet Well unit size is 624 acres. The drill pad disturbed area was approximately
4.2 acres which has been reclaimed to a gravel pad of approximately 1.3 acres of which approximately 0.5 acres is
fenced for equipment.

7

7

Soderblom #1 8/19/2004

Soderblom #1 8/19/2004

7
Soderblom #1 5/6/2009

7
Soderblom #1 5/6/2009

7
Soderblom #1 5/6/2009

Final SGEIS 2015, Page 6-335

 Photo 6.15 This photo shows two Trenton-Black River wells in north-central Chemung County. The two units were
established as separate natural gas fields, the Veteran Hill Field and the Brick House Field.

10
9

Final SGEIS 2015, Page 6-336

 Photos 6.16 Well #9 (Hole number 23228) was drilled as a horizontal Trenton-Black River well and completed in
2006. The well was drilled to a true vertical depth of 9,461 and a true measured depth of 12,550 feet. The well unit is
approximately 622 acres.

9
Little 1 10/6/2005
9

Little 1 11/3/2005

Photos 6.17 Well #10 (Hole number 23827) was drilled as a horizontal Trenton-Black River well and completed
in 2006. The well was drilled to a true vertical depth of 9,062 and a true measured depth of 13,360 feet. The production unit is approximately 650 acres.

10

10
Hulett #1 10/5/2006

Hulett #1 5/6/2009

Final SGEIS 2015, Page 6-337

 Photo 6.18 This photo shows another portion of the Quackenbush Hill Field in western Chemung County and eastern Steuben County. As with other portions of Quackenbush Hill Field, production unit sizes are approximately
640 acres each.

4

11

12

Final SGEIS 2015, Page 6-338

 Photos 6.19 Well #11 (Hole number 22831) was completed in 2000 as a directional well to a total vertical depth of
9,824 feet. The drill site disturbed area was approximately 3.6 acres which has been reclaimed to a fenced area of
0.5 acres.

11

11
Lovell 11/13/2001

Lovell 5/6/2009

Photos 6.20 Well #12 (Hole number 22871) was completed in 2002 as a horizontal well to a true vertical depth of
9,955 feet and a true measured depth of 12,325 feet. The drill site disturbed area was approximately 3.2 acres which
has been reclaimed to a fenced area of 0.45 acres.

12

12
Henkel 10/22/2002

Henkel 5/6/2009

Final SGEIS 2015, Page 6-339

 This page intentionally left blank.

Chapter 7
Mitigation Measures
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Chapter 7 – Mitigation Measures
CHAPTER 7 EXISTING AND RECOMMENDED MITIGATION MEASURES ................................................................ 7-1
7.1 PROTECTING WATER RESOURCES ....................................................................................................................... 7-1
7.1.1 Water Withdrawal Regulatory and Oversight Programs ........................................................................... 7-2
7.1.1.1 Department Jurisdictions ................................................................................................................ 7-2
7.1.1.2 Other Jurisdictions - Great Lakes-St. Lawrence River Basin Water Resources Compact ................ 7-5
7.1.1.3 Other Jurisdictions - River Basin Commissions ............................................................................... 7-6
7.1.1.4 Impact Mitigation Measures for Surface Water Withdrawals ...................................................... 7-14
7.1.1.5 Impact Mitigation Measures for Groundwater Withdrawals ....................................................... 7-24
7.1.1.6 Cumulative Water Withdrawal Impacts ....................................................................................... 7-25
7.1.2 Stormwater .............................................................................................................................................. 7-26
7.1.2.1 Construction Activities .................................................................................................................. 7-29
7.1.2.2 Industrial Activities ....................................................................................................................... 7-30
7.1.2.3 Production Activities ..................................................................................................................... 7-31
7.1.3 Surface Spills and Releases at the Well Pad ............................................................................................ 7-31
7.1.3.1 Fueling Tank and Tank Refilling Activities ..................................................................................... 7-33
7.1.3.2 Drilling Fluids ................................................................................................................................ 7-34
7.1.3.3 Hydraulic Fracturing Additives ...................................................................................................... 7-38
7.1.3.4 Flowback Water ............................................................................................................................ 7-39
7.1.3.5 Primary and Principal Aquifers ..................................................................................................... 7-40
7.1.4 Potential Ground Water Impacts Associated With Well Drilling and Construction ................................ 7-41
7.1.4.1 Private Water Well Testing ........................................................................................................... 7-44
7.1.4.2 Sufficiency of As-Built Wellbore Construction .............................................................................. 7-49
7.1.4.3 Annular Pressure Buildup ............................................................................................................. 7-55
7.1.5 Setback from FAD Watersheds ................................................................................................................ 7-55
7.1.6 Hydraulic Fracturing Procedure ............................................................................................................... 7-56
7.1.7 Waste Transport ...................................................................................................................................... 7-59
7.1.7.1 Drilling and Production Waste Tracking Form .............................................................................. 7-59
7.1.7.2 Road Spreading ............................................................................................................................. 7-60
7.1.7.3 Flowback Water Piping ................................................................................................................. 7-61
7.1.7.4 Use of Tanks Instead of Impoundments for Centralized Flowback Water Storage ...................... 7-61
7.1.7.5 Closure Requirements .................................................................................................................. 7-62
7.1.8 SPDES Discharge Permits ......................................................................................................................... 7-62
7.1.8.1 Treatment Facilities ...................................................................................................................... 7-63
7.1.8.2 Disposal Wells ............................................................................................................................... 7-65
7.1.9 Solids Disposal ......................................................................................................................................... 7-67
7.1.10 Protecting NYC’s Subsurface Water Supply Infrastructure ..................................................................... 7-68
7.1.11 Setbacks ................................................................................................................................................... 7-69
7.1.11.1 Setbacks from Groundwater Resources ....................................................................................... 7-71
7.1.11.2 Setbacks from Other Surface Water Resources ............................................................................ 7-74
7.2 PROTECTING FLOODPLAINS ............................................................................................................................. 7-77
7.3 PROTECTING FRESHWATER WETLANDS .............................................................................................................. 7-77
7.4 MITIGATING POTENTIAL SIGNIFICANT IMPACTS ON ECOSYSTEMS AND WILDLIFE .......................................................... 7-77
7.4.1 Protecting Terrestrial Habitats and Wildlife ............................................................................................ 7-78
7.4.1.1 BMPs for Reducing Direct Impacts at Individual Well Sites .......................................................... 7-78
7.4.1.2 Reducing Indirect and Cumulative Impacts of Habitat Fragmentation ........................................ 7-79
7.4.1.3 Monitoring Changes in Habitat ..................................................................................................... 7-87
7.4.2 Invasive Species ....................................................................................................................................... 7-87
7.4.2.1 Terrestrial...................................................................................................................................... 7-88

Final SGEIS 2015, Page 7-i

 7.4.2.2 Aquatic .......................................................................................................................................... 7-91
7.4.3 Protecting Endangered and Threatened Species .................................................................................... 7-97
7.4.4 Protecting State-Owned Land ................................................................................................................. 7-99
7.5 MITIGATING AIR QUALITY IMPACTS ................................................................................................................ 7-100
7.5.1 Mitigation Measures Resulting from Regulatory Analysis (Internal Combustion Engines and Glycol
Dehydrators) .......................................................................................................................................... 7-101
7.5.1.1 Control Measures for Nitrogen Oxides - NOx .............................................................................. 7-101
7.5.1.2 Control Measures for Sulfur Oxides - SOx ................................................................................... 7-104
7.5.1.3 Natural Gas Production Facilities Subject to NESHAP 40 CFR Part 63, Subpart HH (Glycol
Dehydrators) ............................................................................................................................... 7-105
7.5.2 Mitigation Measures Resulting from Air Quality Impact Assessment and Regional Ozone Precursor
Emissions ............................................................................................................................................... 7-106
7.5.3 Summary of Mitigation Measures to Protect Air Quality ...................................................................... 7-107
7.5.3.1 Well Pad Activity Mitigation Measures ....................................................................................... 7-107
7.5.3.2 Mitigation Measures for Off-Site Gas Compressors ................................................................... 7-108
7.6 MITIGATING GHG EMISSIONS ....................................................................................................................... 7-109
7.6.1 General .................................................................................................................................................. 7-109
7.6.2 Site Selection ......................................................................................................................................... 7-110
7.6.3 Transportation ....................................................................................................................................... 7-110
7.6.4 Well Design and Drilling......................................................................................................................... 7-110
7.6.5 Well Completion .................................................................................................................................... 7-111
7.6.6 Well Production ..................................................................................................................................... 7-112
7.6.7 Leak and Detection Repair Program ...................................................................................................... 7-113
7.6.8 Mitigating GHG Emissions Impacts - Conclusion ................................................................................... 7-115
7.7 MITIGATING NORM IMPACTS ....................................................................................................................... 7-116
7.7.1 State and Federal Responses to Oil and Gas NORM.............................................................................. 7-116
7.7.2 Regulation of NORM in New York State ................................................................................................ 7-116
7.8 SOCIOECONOMIC MITIGATION MEASURES........................................................................................................ 7-118
7.9 VISUAL MITIGATION MEASURES..................................................................................................................... 7-120
7.9.1 Design and Siting Measures................................................................................................................... 7-121
7.9.2 Maintenance Activities .......................................................................................................................... 7-125
7.9.3 Decommissioning .................................................................................................................................. 7-125
7.9.4 Offsetting Mitigation ............................................................................................................................. 7-126
7.10 NOISE MITIGATION MEASURES ...................................................................................................................... 7-127
7.10.1 Pad Siting Equipment, Layout and Operation ....................................................................................... 7-127
7.10.2 Access Road and Traffic Noise ............................................................................................................... 7-128
7.10.3 Well Drilling and Hydraulic Fracturing ................................................................................................... 7-129
7.10.4 Conclusion ............................................................................................................................................. 7-133
7.11 TRANSPORTATION MITIGATION MEASURES ...................................................................................................... 7-134
7.11.1 Mitigating Damage to Local Road Systems ........................................................................................... 7-134
7.11.1.1 Development of Transportation Plans, Baseline Surveys, and Traffic Studies ........................... 7-134
7.11.1.2 Municipal Control over Local Road Systems ............................................................................... 7-136
7.11.1.3 Road Use Agreements ................................................................................................................ 7-137
7.11.1.4 Reimbursement for Costs Associated with Local Road Work ..................................................... 7-139
7.11.2 Mitigating Incremental Damage to the State System of Roads............................................................. 7-139
7.11.3 Mitigating Operational and Safety Impacts on Road Systems .............................................................. 7-140
7.11.4 Other Transportation Mitigation Measures .......................................................................................... 7-141
7.11.5 Mitigating Impacts from the Transportation of Hazardous Materials .................................................. 7-141

Final SGEIS 2015, Page 7-ii

 7.11.6 Mitigating Impacts on Rail and Air Travel .............................................................................................. 7-142
7.12 COMMUNITY CHARACTER MITIGATION MEASURES............................................................................................. 7-143
7.13 EMERGENCY RESPONSE PLAN ........................................................................................................................ 7-145
FIGURES
Figure 7.1 - Hydrologic Regions of New York (New July 2011) (Taken from Lumia et al, 2006) .............................. 7-21
Figure 7.2 - Key Habitat Areas for Protecting Grassland and Interior Forest Habitats (Updated August 2011)...... 7-80
Figure 7.3 - Scaling Factors for Matrix Forest Systems in the High Allegheny Ecoregion (New July 2011) ............. 7-84
TABLES
Table 7.1 Table 7.2 Table 7.3 Table 7.4 -

Regulations Pertaining to Watershed Withdrawal (Revised July 2011) ................................................. 7-8
Regional Passby Flow Coefficients (cfs/sq. mi.) (Updated August 2011) .............................................. 7-22
NYSDOH Water Well Testing Recommendations ................................................................................. 7-46
Principal Species Found in the Four Grassland Focus Areas within the area underlain by the
Marcellus Shale in New York (New July 2011) .......................................................................................7-81
Table 7.5 - Summary of Regulations Pertaining to Transfer of Invasive Species .................................................... 7-93
Table 7.6 - Required Well Pad Stack Heights to Prevent Exceedances................................................................. 7-108

PHOTOS
Photo 7.1 - View of a well site during the fracturing phase of development, with maximum presence of on-site
equipment. (New August 2011) ......................................................................................................... 7-124
Photo 7.2 - Sound Barrier. Source: Ground Water Protection Council, Oklahoma City, OK and ALL
Consulting, Tulsa OK, 2009 (New August 2011) ..................................................................................7-131
Photo 7.3 - Sound Barrier Installation (New August 2011) .................................................................................. 7-132
Photo 7.4 - Sound Barrier Installation (New August 2011) .................................................................................. 7-132

Final SGEIS 2015, Page 7-iii

 This page intentionally left blank.

Chapter 7 EXISTING AND RECOMMENDED MITIGATION MEASURES
Many of the potential impacts identified in Chapter 6 are addressed by existing regulatory
programs, both within and outside of the Department. These are identified and described in this
chapter, along with recommendations for additional mitigation measures to address additional
potential significant adverse environmental impacts from high-volume hydraulic fracturing,
which is often associated with horizontal drilling and multi-well pad development. These
additional recommended mitigation measures, if adopted, can be imposed as enhanced
procedures, permit conditions and/or new regulations. In addition, the proposed EAF Addendum
in Appendix 6 contains a series of informational requirements, such as the disclosure of
additives, the proposed volume of fluids used for fracturing, the percentage weight of water,
proppants and each additive, and mandatory pre-drilling plans, that in some instances may also
serve as mitigation measures. As with Chapter 6, this Supplement text is not exhaustive with
respect to mitigation measures because it incorporates by reference the entire 1992 GEIS and
Findings Statement and the mitigation measures identified therein. This chapter identifies and
discusses:
1) mitigation of impacts not addressed by the 1992 GEIS (e.g., water withdrawal); and
2) enhancements to GEIS mitigation measures to target potential impacts associated with
horizontal drilling, multi-well pad development and high-volume hydraulic fracturing.
Although every single mitigation measure provided by the 1992 GEIS is not reiterated herein,
such measures remain available and applicable as warranted.
7.1

Protecting Water Resources

The Department is authorized by statute to require the drilling, casing, operation, plugging and
replugging of oil and gas wells and reclamation of surrounding land to, among other things,
prevent or remedy "the escape of oil, gas, brine or water out of one stratum into another" and
"the pollution of fresh water supplies by oil, gas, salt water or other contaminants." 410

410

ECL §23-0305(8)(d).

Final SGEIS 2015, Page 7-1

 In addition to its specific authority to regulate well operations to protect the environment, the
Department also has broad authority to "[p]romote and coordinate management of water
resources to assure their protection, enhancement, provision, allocation and balanced utilization .
. . and take into account the cumulative impact upon all of such resources in making any
determination in connection with any . . . permit . . ." 411
7.1.1

Water Withdrawal Regulatory and Oversight Programs

Existing jurisdictions and regulatory programs address some concerns regarding the impacts
related to water withdrawal that are described in Chapter 6. These programs are summarized
below, followed by a discussion of three methodologies for mitigating impacts from surface
water withdrawals. These are DRBC’s method, SRBC’s method and the Natural Flow Regime
Method (NFRM), which is preferred by the Department for purposes of the development of gas
reserves as described in this document and are proposed to be enforced as permit conditions until
further regulatory guidance or regulations are formally adopted. Mitigation of cumulative
impacts is also addressed.
7.1.1.1 Department Jurisdictions
Degradation of Water Use
Currently, the Department’s regulatory authority to regulate water withdrawals outside the Great
Lakes Basin and Long Island is limited to withdrawals for public water supply purposes.
However, the Department proposes to require as a permit condition that applicants identify the
source of the water it intends to use in high-volume hydraulic fracturing operations and report
annually on the aggregate amount of water it has withdrawn or purchased. Furthermore, the
Department also intends to require that permittees employ the NFRM, as described below, as a
mitigation measure to avoid degradation of water quality due to water withdrawals from highvolume hydraulic fracturing.
The Water Resources bill, which was recently passed by both houses of the legislature and
awaits the Governor’s signature to become law, would extend the Department’s authority to
regulate all water withdrawals over 100,000 gpd throughout all of New York State. This bill
411

ECL §3-0301(1)(b).

Final SGEIS 2015, Page 7-2

 applies to all such withdrawals where water would be used for high-volume hydraulic fracturing.
Withdrawal permits issued in the future by the Department, pursuant to the regulations
implementing this law, would include conditions to allow the Department to monitor and enforce
water quality and quantity standards and requirements. These standards and requirements may
include: passby flow; fish impingement and entrainment protections; protections for aquatic life;
reasonable use; water conservation practices; and evaluation of cumulative impacts on other
water withdrawals.
Public Water Supply - New York State currently regulates public drinking water supply ground
and surface water withdrawals through the public water supply permit program. 412 These limited
water supply permit programs help to protect and conserve available water supplies.
Other Water Withdrawals - The Department also regulates non-public water supply withdrawals
in Long Island counties from wells with pumping capacities in excess of 45 gpm. (ECL 151527). All water withdrawals within New York’s portion of the Great Lakes Basin of 100,000
gpd or more (30-day average) must register with the Department (ECL 15-1605). Also, all
withdrawals within New York’s portion of the Delaware and Susquehanna River basins greater
than 100,000 gpd must have the approval of the respective basin commission. Although they
may be subject to the reporting and registration requirements described below, surface and
ground water withdrawals that are not on Long Island and not for drinking water supply
currently are unregulated unless the withdrawals occur within the lands regulated by the DRBC
and the SRBC. Surface water withdrawals are subject to the recently enacted narrative water
quality standard for flow promulgated at 6 NYCRR § 703.2. This water quality standard
generally prohibits any alteration in flow that would impair a fresh surface water body’s
designated best use. Determination of an appropriate passby flow needs to be done on a case by
case basis. However, guidance to clarify the application of the narrative water quality standard
for flow has not yet been issued. For the purpose of this revised draft SGEIS only, the
Department proposes to employ the NFRM via permit condition as a protection measure pending
completion of guidance.

412

ECL Article 15, Title 15.

Final SGEIS 2015, Page 7-3

 Water Withdrawal Reporting - Pursuant to Title 33 of Article 15 of the ECL, any entity that
withdraws, or that has the capacity to withdraw, groundwater or surface water in quantities
greater than 100,000 gpd must file an annual report with the Department. Inter-basin diversions
must be reported on the same form.
Water Withdrawal Regulations
The Department primarily addresses the withdrawal of water and its potential impacts in the
following regulations:
•

6 NYCRR Part 601: Water Supply;

•

6 NYCRR Part 602: Long Island Wells; and

•

6 NYCRR Part 675: Great Lakes Withdrawal Registration Regulations.

The requirements of 6 NYCRR Part 601 pertain to public water supply withdrawals and include
an application that describes the project (map, engineer’s report and project justification) and the
proposed water withdrawal. The applicant is required to identify the source of water, projected
withdrawal amounts and detailed information on rainfall and streamflow.
The purpose of 6 NYCRR Part 675 is to establish requirements for the registration of water
withdrawals and reporting of water losses in the Great Lakes Basin. Part 675 is applicable
because a portion of the shale formations being considered for potential high-volume hydraulic
fracturing is located within the Great Lakes Basin. Registration is required for non-agricultural
purposes in excess of 100,000 gpd (30-day consecutive period). An application for registration
of a withdrawal in the Great Lakes basin is required and addresses location and source of
withdrawal, return flow, water usage description, annual and monthly volumes of withdrawal,
water loss and a list of other regulatory (federal, state and local) requirements. There are also
additional requirements for inter-basin surface water diversions.
Protection of Aquatic Ecosystems
In addition to provisions in the Water Resources Law regarding protection of aquatic
ecosystems, the Environmental Conservation Law includes other programs that protect aquatic
habitat. With respect to disturbances of surface water bodies such as rivers and streams,

Final SGEIS 2015, Page 7-4

 equipment or structures such as standpipes may require permits under Article 15 of the ECL.
The Department has authority to control the use and protection of the waters of New York State
through 6 NYCRR Part 608, Use and Protection of Waters. This regulation enables the agency
to control any change, modification or disturbance to a “protected stream,” which includes all
navigable streams and any stream or portion of a stream with a classification or standard of AA,
AA(t), A, A(t), B, B(t) or C(t), and “navigable waters.” 6 NYCRR Part 608 regulates the use and
protection of waters in the state, and has subparts that address the protection of fish and wildlife
species. Under Part 608.2, “No person or local public corporation may change, modify or
disturb any protected stream, its bed or banks, nor remove from its bed or banks sand, gravel or
other material, without a permit issued pursuant to this Part.” The Department reviews permits
for changes, modifications, or disturbances to streams with respect to potential environmental
impacts on aquatic, wetland and terrestrial habitats; unique and significant habitats; rare,
threatened and endangered species habitats; water quality; hydrology; and water course and
water body integrity. Part 608 does not regulate disturbances of the many streams classified as
“C” or below.
7.1.1.2 Other Jurisdictions - Great Lakes-St. Lawrence River Basin Water Resources Compact
The Great Lakes-St. Lawrence River Basin Water Resources Compact (Compact) was signed
into law on October 3, 2008 through Public Law 110-342. The Great Lakes-St. Lawrence River
Basin Water Resources Council (Council), whose membership includes eight Great Lakes States,
was established by the Compact on December 8, 2008. The Compact prohibits the bulk transport
of water from that basin in containers larger than 5.7 gallons. In addition, effective December 8,
2008, the Compact 413 prohibits any new or increased diversion of any amount of water out of the
Great Lakes Basin with certain limited exceptions. Also, any proposed new or increased
withdrawal of surface or groundwater that will result in a consumptive use of 5 million gpd or
greater averaged over a 90-day period requires prior notice and consultation with the Council and
the Canadian Provinces of Ontario and Quebec.
Within five years of the effective date of the Compact, New York State must implement a
program that ensures that, all new and increased water withdrawals must comply with the
413

ECL Article 21, Title 10.

Final SGEIS 2015, Page 7-5

 Compact’s Decision-Making Standard, Section 4.11, which establishes five criteria all water
withdrawal proposals must meet, including:
1)

The return of all water not otherwise consumed to the source watershed;

2)

No significant adverse individual or cumulative impacts to the quantity of the waters and
water-dependent natural resources;

3)

Implementation of environmentally sound and economically feasible water conservation
measures;

4)

Compliance with all other applicable federal, state, and local laws as well as international
agreements and treaties; and

5)

Reasonable proposed use of water.

The Great Lakes Council does not have regulatory authority similar to that held by SRBC and
DRBC to review water withdrawals and uses and require mitigation of environmental impacts.
However, the Council has specific authority for the review and/or approval of certain new and
increased water withdrawals. Review by the Council will require compliance with the
Compact’s Decision-Making Standard and Standard for Exceptions.
7.1.1.3 Other Jurisdictions - River Basin Commissions
The SRBC and the DRBC are interstate compact entities with authority over certain water uses
within discrete portions of the State. New York is a member of the Board of these river basin
commissions. Those commissions with regulatory programs which address water withdrawals
are described below, and mitigation measures provided by those programs are incorporated into
subsequent sections.
Table 7.1 is a summary of relevant regulations for each of the governmental bodies with
jurisdiction over issues related to water withdrawals. Any amount of surface water withdrawn to
develop shale formations requires the approval of the SRBC and DRBC within their respective
river basins. In response to increased gas drilling in Pennsylvania, SRBC has recently amended
its regulations to further address gas drilling withdrawals and consumptive use. In addition to
surface water withdrawals, SRBC and DRBC control diversions of water into and out of their
respective basins. While ECL 15-1505 prohibits transport of water out of New York State via

Final SGEIS 2015, Page 7-6

 pipes, canals or streams without a permit from the Department, it does not specifically prohibit
such transport by tanker truck. Neither SRBC nor DRBC control transfers of water from stateto-state within their basins.
Delaware River Basin Commission Jurisdictions
Degradation of a Stream’s Use - Section 3.8 of the DRBC’s Compact states “No project having
a substantial effect on the water resources of the basin shall hereafter be undertaken by any
person, corporation or governmental authority unless it shall have been first submitted to and
approved by the Commission, subject to the provisions of Sections 3.3 and 3.5. The
Commission shall approve a project whenever it finds and determines that such project would
not substantially impair or conflict with the Comprehensive Plan and may modify and approve as
modified, or may disapprove any such project whenever it finds and determines that the project
would substantially impair or conflict with such Plan.” DRBC regulations work collectively to
protect Delaware River Basin streams from sources of degradation that would affect the best
usage. The DRBC Water Code 414 provides the regulations, requirements, and programs enacted
into law that serve to facilitate the protection of these water resources in the Basin.
Reduced Stream Flow - Potential impacts of reduced stream flow associated with shale gas
development by high-volume hydraulic fracturing in the Delaware River Basin are under the
purview of the DRBC. The DRBC has the authority to regulate and manage surface and ground
water quantity-related issues throughout the Delaware River Basin. The DRBC requires that all
gas well development operators complete an application for water use that will be subject to
Commission review. The DRBC primarily uses the following regulations, procedures and
programs to address potential impacts of reduced stream flow associated with a water taking:

414

18 CFR Part 410.

Final SGEIS 2015, Page 7-7

 Table 7.1 - Regulations Pertaining to Watershed Withdrawal (Revised July 2011) 415

Agency

Potential Impacts of
Reduced Stream Flow

Denigration of Stream’s
Designated Best Use

Potential Impacts to
Downstream Wetlands

DRBC

Water Code §2.50.2.A
Water Code §2.1.1
Water Code §2.5

Water Code, 18 CFR 410
DRBC Compact

Water Code §2.350

NYSDEC

6 NYCRR §665
6 NYCRR §670
6 NYCRR §671
6 NYCRR §672
6 NYCRR §701

6 NYCRR §608
6 NYCRR §666
6 NYCRR §701

6 NYCRR §663
6 NYCRR §664
6 NYCRR §665

6 NYCRR §595
6 NYCRR §608
6 NYCRR §666

6 NYCRR §601
6 NYCRR §602

SRBC

Reg. of Projects §806.30
Reg. of Projects §801.3
Reg. of Projects §802.23

Reg. of Projects, 18 CFR
§801, §806, §807, §808

Reg. of Projects §801.8
Reg. of Projects §806.14

Reg. of Projects §806.23.b.2
Policy 2003_1
Reg. of Projects §801.9
Reg. of Projects §806.14.b.1.v.C

Reg. of Projects §806.23.b.2
Reg. of Projects §806.12
Reg. of Projects §806.22

415

Adapted from Alpha, 2009.

Final SGEIS 2015, Page 7-8

Potential Impacts to Fish and
Wildlife
Water Code §2.1.1
Water Code §2.200.1
Water Code §3.10.2.B
Water Code §3.10.3.A.2
Water Code §3.10.3.A.2.e
Water Code §3.30.4.A.1
Water Code §2.1.2
Water Code §3.10.3.A.2.b
Water Code §3.20
Water Code §3.30
Water Code §3.40
Water Code §3.30.4.A.1

Potential Aquifer
Depletion

Water Code §2.50.2.A
Water Code §2.20

 •

Allocation of water resources, including three major reservoirs for the NYC Water
supply;

•

Reservoir release targets to maintain minimum flows of surface water;

•

Drought management including water restrictions on use, and prioritizing water use;

•

Water conservation program;

•

Passby flow requirements;

•

Monitoring and reporting requirements; and

•

Aquifer testing protocol.

Impacts to Aquatic Ecosystems - DRBC regulations concerning the protection of fish and
wildlife are located in the Delaware River Basin Water Code. 416 In general, DRBC regulations
require that the quality of waters in the Delaware basin be maintained “in a safe and satisfactory
condition…for wildlife, fish, and other aquatic life” (DRBC Water Code, Article 2.200.1).
One of the primary goals of the DRBC is basin-wide water conservation, which is important for
the sustainability of aquatic species and wildlife. Article 2.1.1 of the Water Code provides the
basis for water conservation throughout the basin. Under Section A of this Article, water
conservation methods will be applied to, “reduce the likelihood of severe low stream flows that
can adversely affect fish and wildlife resources.” Article 2.1.2 outlines general requirements for
achieving this goal, such as increased efficiency and use of improved technologies or practices.
All surface waters in the Delaware River Basin are subject to the water quality standards outlined
in the Water Code. The quality of Basin waters, except intermittent streams, is required by
Article 3.10.2B to be maintained in a safe and satisfactory condition for wildlife, fish and other
aquatic life. Certain bodies of water in the Basin are classified as Special Protection Waters
(also referred to as Outstanding Basin Waters and Significant Resource Waters) and are subject
to more stringent water quality regulations. Article 3.10.3.A.2 defines Special Protection Waters
as having especially high scenic, recreational, ecological, and/or water supply values. Per

416

18 CFR Part 410.

Final SGEIS 2015, Page 7-9

 Article 3.10.3.A.2.b, no measureable change to existing water quality is permitted at these
locations. Under certain circumstances wastewater may be discharged to Special Protection
Areas within the watershed; however, it is discouraged and subject to review and approval by the
Commission. These discharges are required to have a National Pollutant Discharge Elimination
System (NPDES) permit. Non-point source pollution within the Basin that discharges into
Special Protection Areas must submit for approval a Non-Point Source Pollution Control Plan.417
Interstate streams (tidal and non-tidal) and groundwater (basin wide) water quality parameters
are specifically regulated under the DRBC Water Code Articles 3.20, 3.30, and 3.40,
respectively. Interstate non-tidal streams are required to be maintained in a safe and satisfactory
condition for the maintenance and propagation of resident game fish and other aquatic life,
maintenance and propagation of trout, spawning and nursery habitat for anadromous fish, and
wildlife. Interstate tidal streams are required to be maintained in a safe and satisfactory
condition for the maintenance and propagation of resident fish and other aquatic life, passage of
anadromous fish, and wildlife. Groundwater is required to be maintained in a safe and
satisfactory condition for use as a source of surface water suitable for wildlife, fish and other
aquatic life. It shall be “free from substances or properties in concentrations or combinations
which are toxic or harmful to human, animal, plant, or aquatic life, or that produce color, taste, or
odor of the waters.” 418
Impacts to Wetlands - DRBC regulations concerning potential impacts to downstream wetlands
are located in the Delaware River Basin Water Code 419 addressed under Article 2.350, Wetlands
Protection. It is the policy of the DRBC to support the preservation and protection of wetlands
by:
1) Minimizing adverse alterations in the quantity and quality of the underlying soils and
natural flow of waters that nourish wetlands;
2) Safeguarding against adverse draining, dredging or filling practices, liquid or solid waste
management practices, and siltation;
417

DRBC Water Code, Article 3.10.3.A.2.e.

418

DRBC Water Code, Article 3.40.4.A.1.

419

18 CFR 410.

Final SGEIS 2015, Page 7-10

 3) Preventing the excessive addition of pesticides, salts or toxic materials arising from nonpoint source wastes; and
4) Preventing destructive construction activities generally.
Item 1 directly addresses wetlands downstream of a proposed water withdrawal.
The DRBC reviews projects affecting 25 acres or more of wetlands. 420 Projects affecting less
than 25 acres are reviewed by the DRBC only if no state or federal review and permit system is
in place, and the project is determined to be of major significance by the DRBC. Additionally,
the DRBC will review state or federal actions that may not adequately reflect the Commission’s
policy for wetlands in the basin.
Aquifer Depletion - DRBC regulations concerning the mitigation of potential aquifer depletion
are located in the Delaware River Basin Water Code (18 CFR Part 410). The protection of
underground water is covered under Section 2.20 of the DRBC Water Code. Under Section
2.20.2, “The underground water-bearing formations of the Basin, their waters, storage capacity,
recharge areas, and ability to convey water shall be preserved and protected.” Projects that
withdraw underground waters must be planned and operated in a manner which will reasonably
safeguard the present and future groundwater resources of the Basin. Groundwater withdrawals
from the Basin must not exceed sustainable limits. No groundwater withdrawals may cause an
aquifer system’s supplies to become unreliable, or cause a progressive lowering of groundwater
levels, water quality degradation, permanent loss of storage capacity, or substantial impact on
low flows or perennial streams (DRBC Water Code, Article 2.20.4). Additionally, “The
principal natural recharge areas through which the underground waters of the Basin are
replenished shall be protected from unreasonable interference with their recharge function”
(DRBC Water Code, Article 2.20.5).
The interference, impairment, penetration, or artificial recharge of groundwater resources in the
basin are subject to review and evaluation by the DRBC. All operators of individual wells or
groups of wells that withdraw an average of 10,000 gpd or more during any 30-day period from
the underground waters of the Basin must register their wells with the designated agency of the
420

DRBC Water Code, Article 2.350.4.

Final SGEIS 2015, Page 7-11

 state where the well is located. Registration may be filed by the agents of operators, including
well drillers. Any well that is replaced or re-drilled, or is modified to increase the withdrawal
capacity of the well, must be registered with the designated state agency (Delaware Department
of Natural Resources and Environmental Control; New Jersey Department of Environmental
Protection; the Department; or the PADEP (DRBC Water Code, Article 2.20.7).
Groundwater withdrawals from aquifers in the Basin that exceed 100,000 gpd during any 30-day
period are required be metered, recorded, and reported to the designated state agencies.
Withdrawals are to be measured by means of an automatic continuous recording device, flow
meter, or other method, and must be measured to within 5 % of actual flow. Withdrawals must
be recorded on a biweekly basis and reported as monthly totals annually. More frequent
recording or reporting may be required by the designated agency or the DRBC (DRBC Water
Code, 2.50.2.A).
SRBC Jurisdictions
Degradation of a Stream’s Use - The SRBC has been granted statutory authority to regulate the
conservation, utilization, development, management, and control of water and related natural
resources of the Susquehanna River Basin and the activities within the basin that potentially
affect those resources. The SRBC controls allocations, diversions, withdrawals, and releases of
water in the basin to maintain the appropriate quantity of water. The SRBC Regulation of
Projects 421 provides the details of the programs and requirements that are in effect to achieve the
goals of the commission.
Reduced Stream Flow - The SRBC has the authority to regulate and manage surface and ground
water withdrawals and consumptive use in the Susquehanna River Basin. The SRBC requires
that all gas well development operators complete an application for water use that will be subject
to its review. The SRBC primarily uses the following regulations, procedures and programs to
address potential impacts of reduced stream flow associated with a water taking:
•

421

Consumptive use regulations;

18 CFR, Parts 801, 806, 807, and 808.

Final SGEIS 2015, Page 7-12

 •

Mitigation measures;

•

Conservation measures and water use alternatives;

•

Conservation releases;

•

Evaluation of safe yield (7-day, 10-year low flow);

•

Passby requirements;

•

Monitoring and reporting requirements; and

•

Aquifer testing protocol.

Impacts to Aquatic Ecosystems - SRBC regulations concerning the protection of fish and wildlife
are located in the SRBC Regulation of Projects. 422 In general, the Commission promotes sound
practices of watershed management for the purposes of improving fish and wildlife habitat
(SRBC Regulation of Projects, Article 801.9).
Projects requiring review and approval of the SRBC under §§ 806.4, 806.5, or 806.6 are required
to submit to the Commission a water withdrawal application. Applications are required to
contain the anticipated impact of the proposed project on fish and wildlife (SRBC Regulation of
Projects, Article 806.14.b.1.v.C). “The Commission may deny an application, limit or condition
an approval to ensure that the withdrawal will not cause significant adverse impacts to the water
resources of the basin.” 423 The SRBC considers water quality degradation affecting fish, wildlife
or other living resources or their habitat to be grounds for application denial.
Water withdrawal from the Susquehanna River Basin is governed by passby flow requirements
that can be found in the SRBC Policy Document 2003-1, “Guidelines for Using and Determining
Passby Flows and Conservation Releases for Surface-water and Ground-water Withdrawal
Approvals.” A passby flow is a prescribed quantity of flow that must be allowed to pass a
prescribed point downstream from a water supply intake at any time during which a withdrawal

422

18 CFR Parts 801, 806, 807, and 808.

423

SRBC Regulation of Projects, Article 806.23.b.2.

Final SGEIS 2015, Page 7-13

 is occurring. The methods by which passby flows are determined for use as impact mitigation
are described below.
Impacts to Wetlands - Sponsors of projects requiring review and approval of the SRBC under §§
806.4, 806.5, or 806.6 are required to submit to the Commission a water withdrawal application.
Applications are required to contain the anticipated impact of the proposed project on surface
water characteristics, and on threatened or endangered species and their habitats. 424
Aquifer Depletion - Evaluation of ground water resources includes an aquifer testing protocol to
evaluate whether well(s) can provide the desired yield and assess the impacts of pumping. The
protocol includes step drawdown testing and a constant rate pumping test. Monitoring
requirements of ground water and surface water are described in the protocol and analysis of the
test data is required. This analysis typically includes long term yield and drawdown projection
and assessment of pumping impacts.
7.1.1.4 Impact Mitigation Measures for Surface Water Withdrawals
Protecting Stream Flows –DRBC Method
DRBC has the charge of conserving water throughout the Delaware basin by reducing the
likelihood of severe low stream flows that can adversely affect fish and wildlife resources and
recreational enjoyment (18 CFR Part 410, section 2.2.1). The DRBC currently has no specific
passby regulation or policy. Prescribed reservoir releases play an important role in Delaware
River flow. The DRBC uses a Q7-10 flow for water resource evaluation purposes. The Q7-10
flow is the drought flow equal to the lowest mean flow for seven consecutive days, that has a
10-year recurrence interval.
The Q7-10 is a flow statistic developed by sanitary engineers to simulate drought conditions in
water quality modeling when evaluating waste load assimilative capacity (e.g., for point sources
from waste water treatment plants). Q7-10 is not meant to establish a direct relation between
Q7-10 and aquatic life protection. 425 For most streams, the Q7-10 flow is less than 10% of the

424

SRBC Regulation of Projects, Article 806.14.

425

Camp, Dresser and McKee, 1986.

Final SGEIS 2015, Page 7-14

 average annual flow and may result in degradation of aquatic communities if it becomes
established as the only flow protected in a stream. 426
Protecting Stream Flows – SRBC Method
The SRBC requires that passby flows, i.e., prescribed quantities of flow that must be allowed to
pass a prescribed downstream point, be provided as mitigation for water withdrawals. This
requirement is prescribed in part to conserve fish and wildlife habitats. “Approved surface-water
withdrawals from small impoundments, intake dams, continuously flowing springs, or other
intake structures in applicable streams will include conditions that require minimum passby
flows. Approved groundwater withdrawals from wells that, based on an analysis of the 120-day
drawdown without recharge, impact streamflow, or for which a reversal of the hydraulic gradient
adjacent to a stream (within the course of a 48-hour pumping test) is indicated, also will include
conditions that require minimum passby flows.” 427 There are three exceptions to the required
passby flow rules stated above:
1) If the surface-water withdrawal or groundwater withdrawal impact is minimal in
comparison to the natural or continuously augmented flows of a stream or river, no
passby flow will be required. Minimal is defined by SRBC as 10 % or less of the natural
or continuously augmented 7-day, 10-year low flow (Q7-10) of the stream or river;
2) For projects requiring Commission review and approval for an existing surface-water
withdrawal where a passby flow is required, but where a passby flow has historically not
been maintained, withdrawals exceeding 10 % of the Q7-10 low flow will be permitted
whenever flows naturally exceed the passby flow requirement plus the taking. Whenever
stream flows naturally drop below the passby flow requirement plus the taking, both the
quantity and the rate of the withdrawal will be reduced to less than 10 % of the Q7-10
low flow; and
3) If a surface-water withdrawal is made from one or more impoundments (in series) fed by
a stream, or if a ground-water withdrawal impacts one or more impoundments fed by a
stream, a passby flow, as determined by the criteria discussed below or the natural flow,
whichever is less, will be maintained from the most downstream impoundment at all
times during which there is inflow into the impoundment or series of impoundments.

426

Tennant 1976a,b.

427

SRBC, Policy 2003-01.

Final SGEIS 2015, Page 7-15

 In cases where passby flow is required, the following criteria are to be used to determine the
appropriate passby flow for SRBC-Classified Exceptional Value (EV) Waters, High Quality
(HQ) Waters, and Cold-Water Fishery (CWF) Waters; For EV Waters, withdrawals may not
cause greater than 5 % loss of habitat. For HQ Waters, withdrawals may not cause greater than 5
% loss of habitat as well; however, a habitat loss of 7.5 % may be allowed if:
1) The project is in compliance with the Commission’s water conservation regulations of
Section 804.20;
2) No feasible alternative source is available; and
3) Available project sources are used in a program of conjunctive use approved by the
Commission, and combined alternative project source yields are inadequate.
For Class B, 428 CWF Waters, withdrawals may not cause greater than a 10 % loss of habitat. For
Classes C and D, CWF Waters, withdrawals may not cause greater than a 15 % loss of habitat.
For areas of the Susquehanna River Basin not covered by the above regulations, the following
shall apply:
1) On all EV and HQ streams, and those streams with naturally reproducing trout
populations, a passby flow of 25 % of average daily flow will be maintained downstream
from the point of withdrawal whenever withdrawals are made;
2) On all streams not covered in Item 1 above and which are not degraded by acid mine
drainage, a passby flow of 20 % of average daily flow will be maintained downstream
from the point of withdrawal whenever withdrawals are made. These streams generally
include both trout stocking and warm-water fishery uses;
3) On all streams partially impaired by acid mine drainage, but in which some aquatic life
exists, a passby flow of 15 % of ADF will be maintained downstream from the point of
withdrawal whenever withdrawals are made;
4) Under no conditions shall the passby flow be less than the Q7-10 flow; and
5) The SRBC is currently reevaluating the passby requirements described above and draft
changes will likely be proposed sometime in 2011.

428

Water classifications referenced in this section are those established by State of PA which are not equivalent to NYS stream
classifications.

Final SGEIS 2015, Page 7-16

 Protecting Stream Flows - NFRM
The NFRM is an alternative to the current DRBC and SRBC methods and establishes a passby
flow designed to avoid significant adverse environmental impacts from withdrawals for highvolume hydraulic fracturing; specifically impacts associated with: degradation of a stream’s best
use and reduced stream flow including impacts to aquatic habitat and aquatic ecosystems. The
Department proposes to require the NFRM as a permit condition and mitigation measure to
ensure that water withdrawals, including those from the Delaware and Susquehanna River
basins, in connection with high-volume hydraulic fracturing do not result in any significant
adverse environmental impacts.
To assure adequate surface water flow when water withdrawals are made, provisions would be
required to be made to provide for a passby flow in the stream, as defined above. In general,
when streamflow data exist for the proposed withdrawal location, the passby flow is calculated
for each month of the year using monthly flow exceedance values. Monthly flow exceedance
value describes the percentage probability that the calculated streamflow statistic will be
exceeded at any time during the month. For example, the Q60 monthly flow exceedance value is
the calculated instantaneous flow that will be exceeded 60% of the time during a specific month.
As described below, appropriate flow exceedance values will vary by month and will depend on
the watershed size upstream from the water withdrawal.
The purpose of the NFRM is to provide seasonally adjusted instream flows that maintain the
natural formative processes of the stream while requiring only minimal to moderate effort to
calculate. Once adequate streamflow records are obtained, flow exceedance values are easily
calculated. The foundation of the NFRM is based on the New England Aquatic Baseflow
Standard. 429 Commonly referred to as the ABF, or New England Flow Policy, this method is a
component of the broader U.S. Fish and Wildlife Service's New England Flow Policy. The basic
assumption of the method is that varying flows based on monthly flow exceedance values are
appropriate for maintaining differing levels of habitat quality within the stream and that the time
periods for providing different levels of flow are appropriate based on life stage needs of the
aquatic biota. Natural hydrologic variability is used as a surrogate for biological, habitat, and use
429

Larsen, 1981.

Final SGEIS 2015, Page 7-17

 parameters including: depth, width, velocity, substrate, side channels, bars and islands, cover,
migration, temperature, invertebrates, fishing and floating, and aesthetics.
The objective of the NFRM is to retain naturalized annual stream flow patterns (hydrographs)
and otherwise, avoid non-naturalized flows that may degrade stream conditions and result in
adverse impacts. 430 Native aquatic species possess life history traits that enable individuals to
survive and reproduce within a certain range of environmental variation. Changes in channel
morphology and aquatic habitat that exceed this range of variation will result in community
shifts that are detrimental to the native aquatic ecosystem. Flow depth and velocity, water
temperature, substrate size distribution and oxygen content are among the myriad of
environmental attributes known to shape the habitat that control aquatic and riparian species
distributions. Fluvial processes maintain a dynamic mosaic of aquatic habitat structures which
create environmental factors that sustain diverse biotic assemblage; therefore, maintaining a
natural flow regime is recognized as a primary driving force within riverine ecosystems. The
survival of native species and natural communities is reduced if environment flows are pushed
outside the range of their natural variability due to the resultant shifts in community structure.
The NFRM manages our natural aquatic resources within their range of natural variability that
maintains diverse, resilient, productive, and healthy ecosystems. The result is that passby flows
calculated under this method emulate the natural hydrograph, including flushing flows that
define and maintain the stream habitat suitable for aquatic biota. Research by Estes 431 and
Reiser et al. 432 supports the need for these channel-maintaining flows.
There are limitations associated with the NFRM that must be considered, as it assumes a
relationship to the stream biology. Data on historic stream flows must be of a sufficient duration
and quality to represent the natural flow regimes of the stream 433 as prescriptions for passby
flows are only as good as the hydrologic records on which they are based. Beyond concerns over
the quality of available hydrologic data, data that are not based on natural flow conditions (e.g.,
430

IFC, 2004.

431

Estes, 1984.

432

Reiser, et al., 1988.

433

Estes, 1998.

Final SGEIS 2015, Page 7-18

 releases from dams) will influence the calculation of passby flows and may not support fishery
management objectives.
A.

PASSBY FLOW METHODOLOGY: GENERAL CASE

Watersheds and associated waterways each have distinctive natural flow patterns with variable
magnitude, duration, timing, and rate of change of flow rates and water levels. The NFRM
preserves the inherent intra-annual variability associated with a natural flow pattern through the
use of Q75 and/or Q60 monthly exceedance values for establishing passby flows as described
below. The specific flow exceedance values of Q75 and Q60 were selected by Department staff
using best professional judgment, based on research conducted by the State of Michigan (Zorn et
al. 2008). The scientific framework for the Michigan work is the relationship between
streamflow reductions and projected impact on resident fish populations. Regulatory decisions
in Michigan regarding surface or groundwater withdrawals are designed to avoid an adverse
resource impact to local stream ecosystems. Although Michigan methods vary from those
described here, Michigan’s requirements equate to flow exceedance values of approximately
Q75 and Q60.
Waterways with substantial artificial alteration of stream flow by dams, weirs, bypasses,
diversions, and water withdrawals or augmentation are different from waterways without
manmade modifications to flow. As such, methods for determining appropriate passby flows are
different for water bodies with “altered flow” and for water bodies with “natural flow.” The
instream flow requirements would be calculated in accordance with the methods described in the
following sections depending on whether the flow is natural or altered, and gaged or ungaged.
1. Waterways with “Natural Flow”
Waterways that are not subject to substantial artificial modification of stream flow by dams,
weirs, bypasses, diversions, and water withdrawals or augmentation would be considered to have
“natural flow”. The method for computing the passby flows at a specific project site depends on
whether the project is located on a gaged or an ungaged waterway, as described below.
Gaged Waterways - If the proposed water withdrawal project location is on a waterway with a
USGS streamflow gage, and if the project site’s drainage area is between 50 and 200% of the

Final SGEIS 2015, Page 7-19

 drainage area of the stream at the reference gage, a weighted flow exceedance estimate for the
project site can be computed by using the drainage area ratio method. Streamflow statistics for a
given month are estimated by:
Qp = (Ap/Ag) × Qg

where Qp is the flow exceedance value at the project site, Qg is the flow exceedance value at the
reference stream gage, Ap is the drainage area above the project site, and Ag is the drainage area
above the reference stream gage. This equation assumes that the streamflow per unit area at the
project site and reference gage are equal for any given month. Watershed drainage areas can be
determined using the USGS StreamStats tool accessible at
http://water.usgs.gov/osw/streamstats/ssonline.html.
Passby flows in gaged waterways with natural flow would be maintained such that:
a. when the watershed drainage area upstream from the water withdrawal location is greater
than 50 square miles, the monthly passby flows would equal the monthly Q75 flow for
the months of October through June and Q60 for the months of July through September;
or
b. when the watershed drainage area upstream from the water withdrawal location is less
than 50 square miles, the monthly passby flows would equal the monthly Q60 flow.
If the proposed water withdrawal project site is on a gaged stream but the site’s drainage area is
not between 50 and 200% of the drainage area of the stream at the gage, the passby flow should
use the higher of the exceedance value estimates determined from either the reference gage in the
watershed or the regional regression equation for ungaged waterways described below.
Ungaged Waterways - If the proposed water withdrawal project site is on a waterway that does
not have an acceptable USGS streamflow gage as described above, passby flows can be
determined using a regression analysis described in Department guidance documents. 434,435
Regression equations for estimating monthly flow exceedance values based on watershed areas

434

DFWMR 2010.

435

DFWMR 2010.

Final SGEIS 2015, Page 7-20

 have been established for six hydrologic regions across New York State (Figure 7.1). 436
Monthly passby flows, in cubic feet per second (cfs), can be calculated for project sites on
ungaged waterways by multiplying the upstream drainage area by the appropriate regional
coefficient from Table 7.2, below. These coefficients reflect the same principles described in
paragraphs 1.a and b, directly above. If the upstream drainage area lies entirely within a single
hydrologic region, the calculation is straightforward. If, however, the drainage area extends into
multiple hydrologic regions, flows would be calculated based on the percentage that lies within
each hydrologic region. The resulting passby flow is the weighted sum of the values derived
from each hydrologic region within the entire upstream drainage area.
Figure 7.1 - Hydrologic Regions of New York (New July 2011) (Taken from Lumia et al,
2006)

436

Lumia et al. 2006.

Final SGEIS 2015, Page 7-21

 Table 7.2 - Regional Passby Flow Coefficients (cfs/sq. mi.) (Updated August 2011)

REGION

Drainage
Area (mi²)

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

< 50 mi²

1.17

1.02

1.54

3.19

1.75

0.99

0.64

0.48

0.47

0.83

1.36

1.32

> 50 mi²

0.97

0.86

1.19

2.57

1.39

0.76

0.64

0.48

0.47

0.64

1.07

1.09

< 50 mi²

1.30

1.27

1.97

1.99

1.21

0.62

0.36

0.24

0.20

0.41

0.89

1.48

> 50 mi²

0.97

0.90

1.57

1.58

0.94

0.47

0.36

0.24

0.20

0.25

0.64

1.09

1.23

1.07

1.93

2.57

1.48

0.77

0.44

0.28

0.32

0.61

1.51

1.63

> 50 mi²

0.93

0.81

1.37

2.04

1.15

0.56

0.44

0.28

0.32

0.40

0.94

1.21

< 50 mi²

1.23

1.11

1.94

2.28

1.09

0.55

0.35

0.23

0.22

0.39

1.00

1.49

> 50 mi²

0.94

0.84

1.49

1.85

0.81

0.42

0.35

0.23

0.22

0.27

0.64

1.15

< 50 mi²

1.02

0.92

1.77

2.07

0.85

0.42

0.29

0.21

0.20

0.40

0.85

1.33

> 50 mi²

0.66

0.50

1.34

1.49

0.67

0.32

0.29

0.21

0.20

0.28

0.44

0.99

< 50 mi²

0.93

1.00

1.66

1.46

0.69

0.34

0.22

0.17

0.17

0.25

0.52

1.01

> 50 mi²

0.68

0.75

1.20

1.13

0.55

0.28

0.22

0.17

0.17

0.18

0.31

0.69

Adirondack
Lower
Hudson

< 50 mi²
Catskill

Susquehanna
Southern
Tier
Lake Plains

The passby flow requirement described above, if imposed via permit condition and/or regulation,
would fully mitigate any potential significant adverse impact from water withdrawals associated
with high-volume hydraulic fracturing in “Natural Flow” waterways.
2. Waterways with “Altered Flow”
Waterways would be considered to have “altered flow” if more than 25 % of the drainage area
above a proposed project is upstream of a dam, weir, bypass, diversion, or other controlled
artificial flow modification.3 Watershed drainage areas can be determined using the USGS
StreamStats tool accessible at http://water.usgs.gov/osw/streamstats/ssonline.html. Passby flows
within altered waterways would be determined on a case-by-case basis using Department staff’s
best professional judgment. Wherever possible, passby flows in altered waterways will provide
flow patterns that emulate the annual flow hydrograph that would occur in the absence of all
artificial flow alterations. The passby flow requirement, if imposed via permit condition and/or
regulation, would mitigate any potential significant adverse impact from water withdrawals
associated with high-volume hydraulic fracturing in “Altered Flow” waterways.

Final SGEIS 2015, Page 7-22

 B.

ALTERNATIVE PASSBY FLOWS

Alternative passby flows for water withdrawals associated with high-volume hydraulic fracturing
that differ from those determined using the methodology described above may be approved on a
case-by-case basis to protect endangered or threatened species in accordance with 6 NYCRR
Part 182.
Protecting Other Surface Waters
As previously discussed in Chapter 6, water withdrawals from surface water bodies can have a
direct impact upon aquatic habitats and other water users by the reduction of water volumes and
levels. Smaller water bodies will see the greatest visible impact but even small level changes to
large water bodies can sometimes be detrimental. A "safe or dependable" yield analysis is
typically conducted for public water supplies to ensure the availability of water during extended
drought conditions while also considering potential environmental impacts. Parameters such as
stream inflow, usable storage volume, existing withdrawals, evaporation and precipitation
amounts during prolonged drought periods arc used to calculate the amount of water that can be
expected to be available for additional withdrawals. This same methodology can be applied to
all types of withdrawals, including those to be used for hydraulic fracturing purposes. The key
difference between public water supply and withdrawals for hydraulic fracturing is timing.
Public water supplies typically require that a source be available at all times while other uses
such as hydraulic fracturing may have the flexibility to limit their water withdrawals to times
when surplus water is available.
Evaluation of Withdrawals from Surface Water Bodies
All withdrawals from surface water bodies will be evaluated to determine the impacts upon water
quantity and level changes during extended drought conditions. The Department intends to
require permittees to evaluate surface water bodies using the following equation:
ΔV = I + P - W - E - R
Where Δ V = maximum change in storage, I = inflow into water body, P = precipitation onto
water surface, W = existing and proposed water withdrawals, E = evaporation from water

Final SGEIS 2015, Page 7-23

 surface, and R = releases from water body. In some cases such as ponds, factors such as R may
equal zero. The resulting maximum change in storage value (ΔV) shall be used to compute
corresponding maximum water-level drawdowns. Site-specific SEQRA reviews should be
conducted for withdrawals from ponds and lakes. Acceptable drawdown levels will be
determined by Department on a case by case basis.
In accordance with the Department’s Pump Test Recommendations, wetlands located within 500
feet of a proposed water withdrawal require monitoring during the pump test. Lowering of
groundwater levels at or below a wetland is considered to be a significant impact.
7.1.1.5 Impact Mitigation Measures for Groundwater Withdrawals
The Department's DOW Recommended Pump Test Procedures for Water Supply Applications
(http://www.dcc.ny.gov/lands/5003.html) will be used to evaluate proposed groundwater
withdrawals for high-volume hydraulic fracturing.
As stated in the testing guidance, test results will be analyzed to evaluate:
•

Impacts on neighboring water supplies
Neighboring water supplies could be impacted if pumping of wells for Marcellus drilling
requirements results in significant drawdown at offsite supplies. Site specific SEQRA
reviews should be conducted for withdrawals from groundwater within 500 feet of
private wells.

•

Affects to the local groundwater basin
The local groundwater basin can be similarly impacted resulting in lowering of
groundwater levels. The range of impacts could vary from a lowering of water levels to a
lowering of water levels to below pump intakes or to complete dewatering of wells.

•

Impact on wetlands
Impacts to water levels in wetlands could result in degradation of habitat. Site-specific
SEQRA reviews should be conducted for withdrawals within 500 feet of wetlands if
pump test results show the withdrawal could have an influence on the wetland.

•

Well Capability
Test results will establish the maximum pumping rate of the well independent of impacts.

Final SGEIS 2015, Page 7-24

 •

Surface water impacts (passby flows)
Passby flows are required to:
o protect aquatic resources,
o protect competing users,
o protect instream flow uses,
o limit adverse lowering of streamflow levels downstream of the point of
withdrawal.

The Department proposes to impose requirements regarding passby flows as stated in this
document. With those mitigation measures in place there would be no significant adverse
impacts from water withdrawals made in connection with high-volume hydraulic fracturing and
associated horizontal drilling.
7.1.1.6 Cumulative Water Withdrawal Impacts
The SRBC (February, 2009) stated that “the cumulative impact of consumptive use by this new
activity (natural gas development), while significant, appears to be manageable with the
mitigation standards currently in place.” The extent of the gas-producing shales in New York
extends beyond the jurisdictional boundaries of the SRBC and the DRBC. New York State
regulations do not currently address water quantity issues in a manner consistent with those
applicable within the Susquehanna and Delaware River Basins with respect to controlling,
evaluating, and monitoring surface water and ground water withdrawals for shale gas
development. The application of the NFRM to all water withdrawals to support the subject
hydraulic fracturing operations would comprehensively address cumulative impacts on stream
flows because it will ensure a specified minimum passby flow, regardless of the number of water
withdrawals taking place at one time. Accordingly, significant adverse cumulative impacts
would be addressed by the NFRM described above because each operator of a permitted surface
water withdrawal would be required, via permit condition and/or regulation, to estimate or report
the maximum withdrawal rate and measure the actual passby flow for any period of withdrawal.

Final SGEIS 2015, Page 7-25

 7.1.2

Stormwater

The principal control mechanism to mitigate potential significant adverse impacts from
stormwater runoff is to require the development, implementation and maintenance of
Comprehensive SWPPPs. SWPPPs address the often significant impacts of erosion,
sedimentation, peak flow increase, contaminated discharge and nutrient pollution that is
associated with industrial activity, including construction of well pads that would be required for
high-volume hydraulic fracturing. This is commonly required through the administration of the
Department’s SPDES permits (individual or general) for stormwater runoff, which require
operators to develop, implement and maintain up-to-date SWPPPs. To assist this effort, the
Department has produced technical criteria for the planning, construction, operation and
maintenance of stormwater control practices and procedures, including temporary, permanent,
structural and non-structural measures. A successful Comprehensive SWPPP employs
engineering concepts aimed at preventing erosion and maintaining post-development runoff
characteristics in roughly the same manner as the pre-development condition. Many adverse
impacts can be avoided by planning a development to fit site characteristics, like avoiding steep
slopes and maintaining sufficient separation from environmentally sensitive features, such as
streams and wetlands. Another basic principle is to divert uncontaminated water away from
excavated or disturbed areas. In addition, limiting the amount of soil exposed at any one time,
stabilizing disturbed areas as soon as possible, and following equipment maintenance, rapid spill
cleanup and other basic good housekeeping measures will act to minimize potential impacts.
Lastly, measures to treat stormwater and control runoff rates are described in the SWPPP.
A Comprehensive SWPPP that is well developed, implemented, maintained and adapted to
changing circumstances in strict compliance with the Department’s permit conditions and
associated technical standards should act to heighten the beneficial aspects of stormwater runoff
while minimizing its potential deleterious impacts.
The Department has determined that natural gas well development using high-volume hydraulic
fracturing would require a SPDES permit to address stormwater runoff, erosion and
sedimentation. The SPDES permit will address both the construction of well pads and access
roads and any associated soil disturbance, as well as provisions to address surface activities
associated with high-volume hydraulic fracturing for natural gas development. Additionally,

Final SGEIS 2015, Page 7-26

 during the production of natural gas, the Department will require coverage under the SPDES
permit to remain in effect and/or compliance with regulations. The Department proposes to
require SPDES permit conditions, a Comprehensive SWPPP, and both structural and nonstructural Best Management Practices (BMPs) to minimize or eliminate pollutants in stormwater.
The Department is proposing the use of a SPDES general permit for high-volume hydraulic
fracturing (HVHF GP), but the Department proposes to use the same requirements in other
SPDES permits should the HVHF GP not be issued. The Department proposes to publish the
proposed HVHF GP for public review and comment simultaneously with the formal public
comment period on this document. A summary of the SPDES permit conditions follows.
Activities which are exposed to stormwater which will potentially take place during the
development of a well pad may include:
•

Well Drilling and Hydraulic Fracturing;

•

Vehicle and Equipment Storage/Maintenance;

•

Vehicle and Equipment Cleaning;

•

Fueling;

•

Material and Chemical Storage;

•

Chemical Mixing, Material Handling, Loading/Unloading;

•

Fuel/Chemical Storage Areas;

•

Lumber Storage or Processing; and

•

Cement Mixing.

Proposed required BMPs include, but not limited to, a combination of some or all of the
following, or other equally protective practices:
•

Identification of a spill response team and employee training on proper spill prevention
and response techniques;

•

Inspection and preventive maintenance protocols for the tank(s) and fueling area;

Final SGEIS 2015, Page 7-27

 •

Procedures for notifying appropriate authorities in the event of a spill or significant pit
failure;

•

Procedures for immediately stopping the source of the spill and containing the liquid until
cleanup is complete;

•

Ready availability of appropriate spill containment and clean-up materials and
equipment, including oil-containment booms and absorbent material;

•

Disposal of cleanup materials in the same manner as the spilled material;

•

Use of dry cleanup methods and non-use of emulsifiers or dispersants;

•

Protocols for checking/testing stormwater in containment area prior to discharge;

•

Conducting tank filling operations under a roof or canopy where possible, with the
covering extending beyond the spill containment pad to prevent rain from entering;

•

Use of drip pans where leaks or spills could occur during tank filling operations and
where making and breaking hose connections;

•

Use of fueling hoses with check valves to prevent hose drainage after spilling;

•

Use of spill and overflow protection devices;

•

Use of diversion dikes, berms, curbing, grading or other equivalent measures to minimize
or eliminate run-on into tank filling areas;

•

Use of curbing or posts around the fuel tank to prevent collisions during vehicle ingress
and egress;

•

Availability of a manual shutoff valve on the fueling vehicle;

•

Inspection and preventive maintenance protocols for the pit walls and liner;

•

Procedures for immediately repairing the pit or liner and containing any released liquid
until cleanup is complete;

•

Location of additive containers and transport, mixing and pumping equipment as follows:
o within secondary containment;
o away from high traffic areas;
o as far as is practical from surface waters;

Final SGEIS 2015, Page 7-28

 o not in contact with soil or standing water; and
o product and hazard labels not exposed to weathering.
•

Inspection and preventative maintenance protocols for containers, pumping systems and
piping systems, including manned monitoring points during additive transfer, mixing and
pumping activities;

•

Protocols for ensuring that incompatible materials such as acids and bases are not held
within the same containment area;

•

Maintenance of a running inventory of additive products present and used on-site;

•

Use of drip pads or pans where additives and fracturing fluid are transferred from
containers to the blending unit, from the blending unit to the pumping equipment and
from the pumping equipment to the well;

•

Location of tanks within secondary containment, away from high traffic areas and as far
as is practical from surface waters; and

•

Maintenance of a running inventory of flowback water and production brine recovered,
present on site, and removed from the site.

As discussed below, the Department is proposing a method to terminate the application of the
SPDES permit upon Partial Site Reclamation in the manner presented in the HVHF GP or
otherwise by the Department. With the proposed SPDES permit conditions in place for
construction activities and high-volume hydraulic fracturing, as well as permit conditions and/or
regulations for gas production, any potential significant adverse impacts from stormwater
discharges associated with high-volume hydraulic fracturing would be reduced for most
locations.
7.1.2.1 Construction Activities
In order to facilitate the SPDES permitting process for activities addressed by this Supplement,
the Department proposes to utilize the requirements in the SPDES General Permit for
Stormwater Discharges from Construction Activities, GP-0-10-001 (Construction General
Permit), effective January 29, 2010. A Construction SWPPP, meeting or exceeding the
requirements of the Construction General Permit, would be required to be developed as a standalone document, but will also constitute part of the Comprehensive SWPPP. The Construction
SWPPP would address all phases and elements of the construction activity, including all land

Final SGEIS 2015, Page 7-29

 clearing and access road and well pad construction. The Construction SWPPP would be required
to be prepared in accordance with good engineering practices and Department’s Construction
General Permit.
A copy of the Construction SWPPP would be required to be kept on site and available to
Department inspectors while SPDES permit coverage is in effect. Particular monitoring,
inspections and recordkeeping requirements associated with the construction activity will be
initiated upon commencement of construction activities and continue until completion of the
construction project.
7.1.2.2 Industrial Activities
The SPDES permit will require development of a high-volume hydraulic fracturing SWPPP that
will be a stand-alone document, but will also constitute part of the Comprehensive SWPPP. The
high-volume hydraulic fracturing SWPPP would address potential sources of pollution which
may reasonably be expected to affect the quality of stormwater discharges associated with highvolume hydraulic fracturing operations. The Department will require implementation of BMPs
that are to be used to reduce the pollutants in stormwater discharges associated with high-volume
hydraulic fracturing and to ensure compliance with the terms and conditions of the SPDES
permit. Structural, non-structural and other BMPs would have to be considered in the highvolume hydraulic fracturing SWPPP. Structural BMPs include features such as dikes, swales,
diversions, drains, traps, silt fences and vegetative buffers. Non-structural BMPs include good
housekeeping, sheltering activities to minimize exposure to precipitation to the extent
practicable, preventative maintenance, spill prevention and response procedures, routine facility
inspections, employee training and use of designated vehicle and equipment storage or
maintenance areas with adequate stormwater controls. Particular monitoring, inspections and
recordkeeping associated with high-volume hydraulic fracturing would be initiated upon
completion of the construction project and continue until coverage under the SPDES permit has
been appropriately terminated. Monitoring, inspections and reporting for high-volume hydraulic
fracturing will address visual monitoring, dry weather flow inspections, and benchmark
monitoring and analysis. Sites active for less than one year would be required to satisfy all
annual reporting requirements within the period of activity.

Final SGEIS 2015, Page 7-30

 The proposed high-volume hydraulic fracturing SWPPP will apply during all hydraulic
fracturing and flowback operations at a well pad and until such time as coverage under the
HVHF GP is appropriately terminated. A copy of the high-volume hydraulic fracturing SWPPP
must be kept on site and available to Department inspectors while SPDES permit coverage is in
effect. SPDES permit coverage may be terminated upon completion of all drilling and hydraulic
fracturing operations, fracturing flowback operations and partial site reclamation in a manner
specified by the Department. Partial site reclamation has occurred when a Department inspector
determines that drilling and fracturing equipment have been removed, the pit or pits used for
those operations have been reclaimed, and surface disturbances or surface parking or storage
structures not necessary for production activities have been re-graded and seeded, vegetation
cover re-established, and post-construction management practices are fully operational.
Operators may, however, elect to maintain coverage under the SPDES permit after partial site
reclamation if they so choose.
7.1.2.3 Production Activities
As part of a permit and/or in regulation, the Department proposes to require the owner/operator
of the high-volume hydraulic fracturing operation to address potential sources of pollution which
may reasonably be expected to affect the quality of stormwater discharges associated with the
production phase. The Department will require implementation of BMPs that are to be used to
reduce the pollutants in stormwater discharges associated with the production of gas resulting
from high-volume hydraulic fracturing and to ensure compliance with the terms and conditions
of the appropriate permit and/or regulation. Structural, nonstructural and other BMPs will be
incorporated into a permit and/or regulation.
Particular monitoring, inspections and recordkeeping associated with the high-volume hydraulic
fracturing will be include in the permit and/or regulation and initiated once coverage under the
SPDES permit has been appropriately terminated.
7.1.3

Surface Spills and Releases at the Well Pad

A combination of existing Department engineering controls and management practices,
enhanced as necessary to address unique aspects of multi-well pad development and highvolume hydraulic fracturing, would be required in appropriate permits to prevent spills and

Final SGEIS 2015, Page 7-31

 mitigate adverse impacts from any that do occur. This would include disclosure to the
Department of fracturing fluid constituents, so that the appropriate remediation measures can be
taken if a spill occurs. Activities and materials on the well pad of concern with respect to
potential surface and groundwater impacts from unmitigated spills and releases include the
following:
•

Fueling tank and tank refilling activities;

•

Drilling fluids;

•

Hydraulic fracturing additives and flowback water;

•

Production brine;

•

Materials and chemical storage;

•

Chemical mixing, material handling, loading/unloading areas;

•

Bulk chemical/fluid storage tanks;

•

Equipment cleaning;

•

On-site waste storage or disposal;

•

Vehicle and equipment storage/maintenance areas;

•

Piping/conveyances;

•

Lumber storage and/or processing areas; and

•

Cement mixing/concrete products manufacturing.

The proposed spill prevention and mitigation measures advanced herein reflect consideration of
the following information reviewed by Department staff:
•

The 1992 GEIS and its Findings;

•

GWPC, 2009b;

•

Alpha, 2009, regarding:

Final SGEIS 2015, Page 7-32

 o a survey of regulations related to natural gas development activities in
Pennsylvania, Colorado, New Mexico, Wyoming , Texas (including the City of
Fort Worth), West Virginia, Louisiana, Ohio and Arkansas;
o materials handling and transport requirements, including USDOT and NYSDOT
regulations, the Department’s Bulk Storage Programs and EPA reporting
requirements; and
o specific recommendations for minimizing potential liquid chemical spills.
•

Guidance documents relative to the Department’s Petroleum Bulk Storage Program,
including:
o Spill Prevention Operations Technology Series (SPOTS) 10, Secondary
Containment Systems for Aboveground Storage Tanks; 437 and
o Draft Department Program Policy DER-17. 438

•

SWPPP guidance compiled by the Department’s Division of Water; The comprehensive
Stormwater Pollution Prevent Plan (SWPPP) that would be required by the Department’s
proposed HVHF GP will include permit requirements for Good Housekeeping
Procedures, Spill Reduction Measures and Structural Best Management Practices to
minimize or eliminate pollutants in stormwater for all of the activities listed above;

•

US Department of the Interior and US Department of Agriculture, 2007; and

•

An industry BMP manual provided to the Department.

7.1.3.1 Fueling Tank and Tank Refilling Activities
The diesel tank fueling storage associated with the larger rigs described in Chapter 5 may be
larger than 10,000 gallons in capacity and may be in one location on a multi-well pad for the
length of time required to drill all of the wells on the pad. However, the tank would be removed
along with the rig during any drilling hiatus between wells or after all the wells have been
drilled. There are no long-term or permanent operations at a drill pad which require an on-site
fueling tank. Therefore, the tank is considered non-stationary and is exempt from the
Department’s petroleum bulk storage regulations and tank registration requirements. The
following measures are proposed to be required, via permit condition and/or regulation, to

437

http://www.dec.ny.gov/docs/remediation_hudson_pdf/spots10.pdf.

438

http://www.dec.ny.gov/docs/remediation_hudson_pdf/der17.pdf.

Final SGEIS 2015, Page 7-33

 minimize or prevent spills. For all wells subject to the SGEIS, supplementary permit conditions
for high-volume hydraulic fracturing would include the following requirements with respect to
fueling tanks and refilling activities:
a. Secondary containment consistent with the objectives of SPOTS 10 for all fueling tanks.
The secondary containment system could include one or a combination of the following:
dikes, liners, pads, holding ponds, curbs, ditches, sumps, receiving tanks or other
equipment capable of containing spilled fuel. Soil that is used for secondary containment
would be of such character that a spill into the soil will be readily recoverable and would
result in a minimal amount of soil contamination and infiltration. Draft Department
Program Policy DER-17 439 may be consulted for permeability criteria for dikes and dike
construction standards, including capacity of at least 110% of the tank’s volume.
Implementation of secondary containment and permeability criteria is consistent with
GWPC’s recommendations;
b. Fueling tanks would not be positioned within 500 feet of a perennial or intermittent
stream, storm drain, wetland, lake or pond;
c. Fueling tank filling operations would be manned at the fueling truck and at the tank if the
tank is not visible to the fueling operator from the truck; and
d. Troughs, drip pads or drip pans would be required beneath the fill port of the fueling tank
during filling operations if the fill port is not within the secondary containment.
7.1.3.2 Drilling Fluids
The 1992 GEIS describes reserve pits excavated at the well which may contain drill cuttings,
drilling fluid, formation water, and flowback water from a single well. As stated in the 1992
GEIS:
Although the existing regulations do mention clay and hardpan as options in pit
construction, the Department has consistently required that all earthen temporary
drilling pits be lined with sheets of plastic before they can be used. Clay and
hardpan are both low in permeability, but they are not watertight. They are also
subject to chemical reaction with some drilling and completion fluids. In
addition, the time constraints on drilling operations do not allow adequate time for
the percolation tests which should be performed to check the permeability of a
clay lined pit. Liners for large pits are usually made from several sheets of plastic

439

http://www.dec.ny.gov/docs/remediation_hudson_pdf/der17.pdf.

Final SGEIS 2015, Page 7-34

 which should be factory seamed. Careful attention to sealing the seams is
extremely important in preventing groundwater contamination; 440and:
Pits for fluids used in the drilling, completion, and re-completion of wells should
be constructed, maintained and lined to prevent pollution of surface and
subsurface waters and to prevent pit fluids from contacting surface soils or ground
water zones. Department field inspectors are of the opinion that adequate
maintenance after pit liner installation is more critical to halting pollution than the
initial pit liner specifications. Damaged liners must be repaired or replaced
promptly. Instead of very detailed requirements in the regulations, the regulatory
and enforcement emphasis will be on a general performance standard for initial
review of liner-type and on proper liner maintenance.
The type and specifications of the liner proposed by the well drilling applicant
will require approval by the DEC Regional Minerals Manager. The acceptability
of each proposed pit construction and location should be determined during the
pre-site inspection. Any pit site or pit orientation found unacceptable to the
Department must be changed as directed by the regional site inspector. 441
Existing regulations require that pit fluids must be removed within 45 days of cessation of
drilling operations (includes stimulation), “unless the department approves an extension based on
circumstances beyond the operator’s control. The department may also approve an extension if
the fluid is to be used in subsequent operations according to the submitted plan, and the
department has inspected and approved the storage facilities.” 442
Within primary and principal aquifers, existing permit conditions require that if operations are
suspended and the site is left unattended, pit fluids must be removed from the site
immediately. 443 After the cessation of drilling and/or stimulation operations, pit fluids must be
removed within seven days.
Recommended 1992 GEIS specifications, and the ultimate decision to use a site and
performance-based standard rather than detailed specifications, were largely based upon the short
duration of a pit’s use. Pits used for more than one well, as would be the case for high-volume

440

NYSDEC 1992, GEIS, p. 9-32.

441

NYSDEC, 1992, GEIS p. FGEIS48.

442

6 NYCRR §554.(1)(c)(3).

443

Freshwater Aquifer Supplementary Permit Conditions, www.dec.ny.gov/energy/42714.html.

Final SGEIS 2015, Page 7-35

 hydraulic fracturing, would be used for a longer period of time. “The containment of fluids
within a pit is the most critical element in the prevention of shallow ground water
contamination.” 444 Specifications more stringent than those proposed in the 1992 GEIS which
relate to durability and longer duration of use are appropriate, and are consistent with GWPC’s
recommendations (Section 5.18.1.2). Additional protection would be provided by the
requirement for a SWPPP and by measuring proposed setbacks from the edge of the well pad
instead of from the well.
The following measures are proposed to be required to mitigate the potential for releases
associated with any on-site reserve pit:
1) The EAF Addendum would require information about the planned location, construction
and capacity of the reserve pit. The Department would not approve reserve pits on the
filled portion of cut-and-fill sites; and
2) Supplementary permit conditions for multi-well pad high-volume hydraulic fracturing
would include the following requirements:
a. Diversion of surface water and stormwater runoff away from the pit;
b. Flowback water would be prohibited from being directed to or stored in any onsite pit;
c. Pit volume limit of 250,000 gallons, or 500,000 gallons for multiple pits on one
tract or related tracts of land;
d. Beveled walls (45 degrees or less) for pits constructed in unconsolidated
materials;
e. Sidewalls and bottoms free of objects capable of puncturing and ripping the liner;
f. Sufficient slack in liner to accommodate stretching;
g. Minimum 30-mil liner thickness;
h. Liners installed and seamed in accordance with the manufacturer’s specifications,
and constructed, coated, or lined with materials that are chemically compatible
with the substance (s) stored and the environment;
444

GWPC, 2009 April, p. 29.

Final SGEIS 2015, Page 7-36

 i. Freeboard monitoring and maintenance of 2 feet of freeboard at all times (except
freshwater);
j. Fluids removed and pit inspected by a Department inspector prior to additional
use if longer than a 45-day gap in use; and
k. Fluids removed and pit reclaimed within 45 days of completing drilling and
stimulation operations at last well on pad.
As discussed in Section 7.1.9, the Department proposes, via permit condition and/or regulation,
that, reserve pits would not be utilized for on-site management of drilling fluids and the cuttings
entrained with the fluids when the cuttings are required to be disposed of at an off-site facility.
Under circumstances which require the off-site disposal of cuttings, both the cuttings and all
associated drilling fluids would be required to be managed on-site within a closed-loop tank
system.
Chapter 5 discusses the required use of the blow-out prevention (BOP) system and Chapter 6
includes potential impacts that could occur as a result of a component failure of the BOP system
or if the system is improperly operated. The Department proposes to require, via permit
condition and/or regulation, the following requirements:
1. Individual crew member’s responsibilities for blowout control would be posted in the
doghouse or other appropriate location and each crew member would be made aware of
such responsibilities prior to spud of any well being drilled or when another rig is moved
on a previously spudded well and/or prior to the commencement of any rig, snubbing unit
or coiled tubing unit performing completion work. During all drilling and/or completion
operations when a BOP is installed, tested or in use, the operator or operator’s designated
representative would be present at the wellsite and such person or personnel would have a
current well control certification from an accredited training program that is acceptable to
the Department (e.g., International Association of Drilling Contractors). Such
certification would be available at the wellsite and provided to the Department upon
request;
2. Appropriate pressure control procedures and equipment in proper working order would
be employed while conducting drilling and/or completion operations including tripping,
logging, running casing into the well, and drilling out solid-core stage plugs. Unless
otherwise approved by the Department, a snubbing unit and/or coiled tubing unit with a
BOP would be used to enter any well with pressure and/or to drill out one or more solidcore stage plugs; and

Final SGEIS 2015, Page 7-37

 3. Pressure testing of the blow-out preventer (BOP) and related equipment for any drilling
and/or completion operation would be performed in accordance with the approved BOP
use and test plan, and any deviation from the approved plan would be approved by the
Department. Testing would be conducted in accordance with American Petroleum
Institute (API) Recommended Practice (RP) 53, RP for Blowout Prevention Systems for
Drilling Wells, or other procedures approved by the Department.
The aforementioned measures would reduce any significant adverse environmental impacts
posed by drilling fluids associated with high-volume hydraulic fracturing.
7.1.3.3 Hydraulic Fracturing Additives
Chapter 5 describes the USDOT- or UN-approved containers in which hydraulic fracturing
additives are delivered and held until they are mixed with water and proppant and pumped into
the well, and also describes the length of time that additives are present on the site. Well pad
setbacks from water resources described in Section 7.1.11 apply to all locations. Additional
protection would be provided by the requirement to measure proposed setbacks from the edge of
the well pad instead of from the wellbore. Additional mitigation measures would be
implemented as follows to fully mitigate any potential significant adverse impacts from
hydraulic fracturing additives:
1) Secondary containment would be required for all fracturing additive containers and
additive staging areas. These requirements would be included in supplementary well
permit conditions for high-volume hydraulic fracturing.
Secondary containment measures may include one or a combination of the following;
dikes, liners, pads, curbs, sumps, or other structures or equipment capable of containing
the substance. Any such secondary containment would be required to be sufficient to
contain 110% of the total capacity of the single largest container or tank within a
common containment area.
The Department proposes to require, via permit condition and/or regulation, 1) removal
of hydraulic fracturing additives from the site if the site will be unattended and 2) at least
two vacuum trucks would be on standby at the wellsite during the pumping of hydraulic
fracturing fluid;
2) As described in Part 8.2.1.2, the operator’s permit application materials would document
its evaluation of alternative additive products that may pose less risk to the environment,
including water resources; and

Final SGEIS 2015, Page 7-38

 3) Required disclosure to the Department of fracturing fluid additives would ensure that the
appropriate steps could be taken if a spill or release did occur. (See Chapter 8 for a
discussion of the specific additive information which would be required.)
7.1.3.4 Flowback Water
The 1992 GEIS addresses use of the on-site reserve pit for flowback water associated with a
single well. However, even in the single-well case, potential flowback water volumes associated
with high-volume hydraulic fracturing exceed 1992 GEIS descriptions. Estimates provided in
Section 5.11.1 are for 216,000 gallons to 2.7 million gallons of flowback water recovered within
two to eight weeks of hydraulic fracturing a single well. The volume of flowback water that
would require handling and containment on the site is variable and difficult to predict, and data
regarding its likely composition are incomplete. Therefore, the Department proposes to require,
via permit condition and/or regulation, that flowback water handled at the well pad be directed to
and contained in covered watertight steel tanks or covered watertight tanks constructed of
another material approved by the Department. Even without this requirement, the pit volume
limitation proposed above would necessitate that tank storage be available on site. The
Department will also continue to encourage exploration of technologies that promote reuse of
flowback water when practical. Additional mitigation measures would be implemented as
follows:
1) The EAF Addendum would require information about the number, individual and total
capacity and location on the well pad of receiving tanks for flowback water;
2) Permit conditions for high-volume hydraulic fracturing would include the following
requirements:
a. Fluids would be removed if there will be a hiatus in site activity longer than 45
days;
b. Fluids would be removed within 45 days of completing drilling and stimulation
operations at last well on pad;
c. Fluid transfer operations from tanks to tanker trucks would be manned at the truck
and at the tank if the tank is not visible to the truck operator from the truck;
d. Secondary containment for flowback tanks is required; and
e. At least two vacuum trucks would be on standby at the wellsite during the
flowback phase.

Final SGEIS 2015, Page 7-39

 7.1.3.5 Primary and Principal Aquifers
Based on the analysis contained in Section 6.1.3.4, the Department has determined that the
activities associated with high-volume hydraulic fracturing pose a risk of causing significant
adverse impacts to Primary Aquifers and, therefore, such operations may not be consistent with
the long-term protection of Primary Aquifers. The Department finds that standard stormwater
control and other mitigation measures may not fully mitigate the risk of potential significant
adverse impacts on these water resources from spills or other releases that could occur in
connection with high-volume hydraulic fracturing operations.
Therefore, the Department proposes to bar placement of high-volume hydraulic fracturing well
pads over Primary Aquifers and an associated 500-foot buffer to provide an adequate margin of
safety from the full range of high-volume hydraulic fracturing activities. As defined in TOGS
2.1.3, Primary Aquifers are currently extensively used by major municipalities as a source of
drinking water. Contamination of a Primary Aquifer could render a large, concentrated
population without drinking water. Replacing a drinking water source of this magnitude would
be prohibitive because of exorbitant costs, difficulty in locating alternative water supply sources,
and the extensive time needed to implement any alternatives. However, because the mitigation
measures that would be imposed through permit conditions and/or regulations may prove
effective for preventing uncontained, unmitigated releases that could contaminate Primary
Aquifers, this bar will be re-evaluated two years after the commencement of issuance of well
permits associated with high-volume hydraulic fracturing operations.
The Department further proposes to require a site-specific SEQRA review for placement of highvolume hydraulic fracturing well pads that are proposed to be located over Principal Aquifers or
within a 500-foot buffer, as well as an individualized SPDES stormwater permit. As defined in
TOGS 2.1.3 and explained in Chapters 2 and 6, Principal Aquifers are currently not intensively
used by major municipalities as a source of drinking water, as compared to Primary Aquifers.
However, contamination of a Principal Aquifer could still render a large population without
water. Because mitigation measures that would be imposed through permit conditions and/or
regulations may prove effective for preventing uncontained, unmitigated releases that could
contaminate Principal Aquifers, this proposed requirement will be re-evaluated in two years after
the commencement of issuance of well permits for high-volume hydraulic fracturing operations.

Final SGEIS 2015, Page 7-40

 It is important to note that although the percentage of land in New York designated as a Primary
and Principal Aquifer appears significant, due to the fact that wells can be drilled horizontally,
well pads placed outside the boundary of a Primary and Principal Aquifer area may still allow for
access to natural gas reserves underlying the significant majority of the area beneath Primary and
Principal Aquifers. For example, assuming both a 500-foot buffer from the edge of a Primary
and Principal Aquifer and the capacity to drill a 3,500-foot horizontal leg, and also assuming
lease rights, surface access rights and lack of other siting restrictions, less than 1% of the area
where the Marcellus Shale is deeper than 2,000 feet below ground surface and also beneath
Primary or Principal Aquifers would be made at least potentially inaccessible for the extraction
of natural gas by high-volume hydraulic fracturing.
Summary
The Department committed to evaluate the mitigation measures to determine whether they are
sufficient to protect primary and principal aquifers, which are described in Chapters 2 and 6 of
this Supplement and in the 1992 GEIS, the Department would implement the following
restrictions until at least two years after issuance of the first permit for high-volume hydraulic
fracturing:
1) No well pads would be approved within 500 feet of primary aquifers; and
2) A site-specific SEQRA review and determination of significance, and a site-specific
SPDES permit, would be required for any proposed well pad within 500 feet of a
principal aquifer.
Two years after issuance of the first permit for high-volume hydraulic fracturing, the Department
would re-evaluate the need for these restrictions based on experience with high-volume hydraulic
fracturing outside of these restricted areas.
7.1.4

Potential Ground Water Impacts Associated With Well Drilling and
Construction

Existing construction and cementing practices and permit conditions to ensure the protection and
isolation of fresh water would remain in use, and would be enhanced by Permit Conditions for

Final SGEIS 2015, Page 7-41

 high-volume hydraulic fracturing. See Appendices 8, 9 and 10. Based on discussion in Chapters
2 and 6 of this Supplement, along with GWPC’s regulatory review, 445 the Department proposes
to require the following measures associated with well drilling and construction in order to
prevent potential groundwater impacts from these activities:
•

Baseline water quality testing of private wells within a specified distance of the proposed
well;

•

Sufficiency of as-built wellbore construction prior to high-volume hydraulic fracturing,
including:
o Adequacy of surface casing to protect fresh water and to isolate potable fresh
water supplies from deeper gas-bearing zones;
o Adequacy of cement in the annular space around the surface casing;
o Adequacy of cement in the annular space around the intermediate casing;
o Adequacy of cement on production casing to prevent upward migration of fluids;
including gas, during hydraulic fracturing and production conditions;
o Use of centralizers to ensure that the cement sheath surrounds the casing strings,
including the first joint of surface and intermediate casings; and
o The opportunity for state regulators to witness cementing operations; and

•

Prevention of pressure build-up at the surface casing seat and in the annular space
between the surface casing and intermediate casing.

The proposed well construction-related requirements advanced herein reflect consideration of the
following information and sources:

445

•

The 1992 GEIS and its Findings;

•

The Department’s existing required casing and cementing practices (Appendix 8);

•

The Department’s existing supplementary freshwater aquifer permit conditions
(Appendix 9);

GWPC, 2009 May.

Final SGEIS 2015, Page 7-42

 •

Harrison, 1984, with respect to the importance of maintaining the surface-production
casing annulus in a non-pressurized condition (a preventative measure which has been
implemented as part of the Department’s required casing and cementing practices since at
least 1985);

•

Commissioner’s Decision, 1985, regarding well casing cement and the requirement to
maintain an open annulus to prevent gas migration into aquifers;

•

API, regarding:
o Specification 5CT, Specifications for Casing and Tubing (April 2002);
o Recommended Practice (RP) 5A3, RP on Thread Compounds for Casing, Tubing,
Line Pipe, and Drill Stem Elements (November 2009);
o RP 10D-2, RP for Centralizer Placement and Stop Collar Testing (August 2004);
o Specification 10A, Specifications for Cement and Material for Well Cementing
(April 2002 and January 2005 Addendum);
o Guidance Document, HF1, Hydraulic Fracturing Operations - Well Construction
and Integrity Guidelines (October 2009); and
o RP 65 – Part 2, Isolating Potential Flow Zones During Well Construction (May
2010).

446

•

Pennsylvania Environmental Quality Board, Title 25-Environmental Protection, Chapter
78, Oil and Gas Wells, Pennsylvania Bulletin, Vol. 41, No. 6 (February 5, 2011);

•

Ohio Department of Natural Resources, 2008, regarding permit conditions developed to
prevent over-pressurized conditions in the surface-production casing annulus;

•

GWPC, 2009b, well construction recommendations;

•

NYSDOH Recommended Residential Water Quality Testing, Individual Water Supply
Wells Fact Sheet #3, relative to recommended water quality testing for all wells and
recommended additional parameters to test if gas drilling nearby is the reason for water
testing; 446

•

NYSDOH recommendations relative to private water well testing dated July 21, 2009,
based on review of fracturing fluid constituents and flowback characteristics;

http://www.health.state.ny.us/environmental/water/drinking/part5/append5b/fs3_water_quality.htm, accessed 9/16/09.

Final SGEIS 2015, Page 7-43

 •

URS, 2009, water well testing recommendations based on review of fracturing fluid
constituents and flowback characteristics;

•

Alpha, 2009, regarding:
o water well testing requirements in other states identified through a survey of
regulations in 10 other jurisdictions; and
o previous drilling in aquifers, watersheds and aquifer recharge areas; and

•

ICF, 2009a, regarding:
o water well testing recommendations; and
o review of hydraulic fracturing design and subsurface fluid mobility.

7.1.4.1 Private Water Well Testing
The Department proposes to require, via permit condition, that the operator, at its own expense,
sample and test all residential water wells within 1,000 feet of the well pad, subject to the
property owner’s permission, or within 2,000 feet of the well pad if no wells are available for
sampling within 1,000 feet either because there are none of record or because the property owner
denies permission. The Department would require that results of each test be provided to the
property owner within 30 days of the operator’s receipt of laboratory results. The Department
would further require that the data be available to the Department and local health department
upon request for complaint investigation purposes.
Schedule
Testing before drilling is recommended as a mitigation measure related to the potential for
groundwater contamination because it provides a baseline for comparison in the event that water
contamination is suspected. Testing prior to drilling each well at a multi-well pad provides
ongoing monitoring between drilling operations, so the requirement would be attached to every
well permit that authorizes high-volume hydraulic fracturing. Testing at established intervals
after drilling or hydraulic fracturing operations provides opportunities to detect contamination or
confirm its absence. If no contamination is detected a year after the last hydraulic fracturing
event on the pad, then further routine monitoring should not be necessary. The Department
proposes to require, via permit condition the following ongoing monitoring schedule:

Final SGEIS 2015, Page 7-44

 •

Initial sampling and analysis prior to site disturbance at the first well on the pad, and
prior to drilling commencement at additional wells on multi-well pads;

•

Sampling and analysis three months after reaching total measured depth (TMD) at any
well on the pad if there is a hiatus of longer than three months between reaching TMD
and any other milestone on the well pad that would require sampling and analysis; and

•

Sampling and analysis three months, six months and one year after hydraulic fracturing
operations at each well on the pad.

For multi-well pads where drilling and hydraulic fracturing activity is continuous, to the extent
that water well sampling and analysis according to the above schedule would occur more often
than every three months, the Department proposes to simplify the protocol so that sampling and
analysis occurs at three month intervals until six months after the last well on the pad is
hydraulically fractured, with a final round of sampling and analysis one year after the last well
on the pad is hydraulically fractured.
More frequent sampling and analysis, or sampling and analysis beyond one year after last
hydraulic fracturing operations, may be warranted in response to complaints as described below
or for other reasonable cause.
Parameters
The NYSDOH recommends testing for the analytes listed in Table 7.3 to aid with determining
whether gas drilling may have had an impact on the quality or quantity of a well. This analysis is
not intended to constitute a comprehensive evaluation. In the event that a potential impact is
determined, additional investigation (e.g., isotopic analysis of methane to determine source or
site-specific chemical analysis) may be necessary.

Final SGEIS 2015, Page 7-45

 Table 7.3 - NYSDOH Water Well Testing Recommendations
(Revised July 2011 to reflect more recent recommendations from NYSDOH)

Parameter
Barium

Chloride

Conductivity

Gross
alpha/beta
Iron
Manganese
Dissolved
methane &
ethane
pH
Sodium
Total
dissolved
solids (TDS)

Static water
level
Volatile
organic
compounds
(VOCs),
specifically
BTEX

Notes
Barium (barite) is a principal component of many drilling muds. In the event that barite is not
used in the drilling mud, a substitution should be made for a component that is present in the
drilling mud.
A measure of chloride anions in water. Chlorides and other salts are naturally occurring and
can be found in many different geologic zones, but deep groundwater typically contains high
levels of chloride. Flowback water contains high levels of chlorides. Therefore, an increase in
chlorides may be an indication that drilling has allowed communication between geologic
zones and/or flowback water has contaminated an aquifer.
A measure of the ability of water to pass an electrical current. Conductivity in water is
affected by the presence of inorganic dissolved solids such as chloride, nitrate, sulfate, and
phosphate anions (ions that carry a negative charge) or sodium, magnesium, calcium, iron and
aluminum cations (ions that carry a positive charge). Organic compounds like oil, phenol,
alcohol and sugar do not conduct electrical current very well and therefore have a low
conductivity when in water. A change in water quality as a result of drilling is expected to
affect the conductivity.
Radioactivity is typically elevated in shale relative to other rock types and the Marcellus Shale
is especially enriched. Drilling and production of shale may have the ability to mobilize
radioactivity towards the surface where it could either concentrate or infiltrate aquifers. These
Gross analyses are screening values for defining when to perform more detailed analyses.
Iron is commonly found in many aquifers and may be mobilized during initial drilling
activities.
Manganese is commonly found in many deep and shallow aquifers and may be mobilized
during initial drilling activities.
Occurs naturally in many aquifers but may also migrate into aquifers as a product of drilling
and production. Additional analysis may be necessary to determine the source and/or
percentages of dissolved gasses.
A measure of how acidic or basic water is. pH is sensitive to small changes in water chemistry
such as those that may result from natural gas drilling.
Sodium is naturally occurring and commonly found in most water. However, sodium is found
in high concentrations in deep shale production brines and gas wells.
A measure of all dissolved organic and inorganic species in water. TDS is useful as an
indicator of aesthetic characteristics of drinking water and as an aggregate indicator of the
presence of a broad array of chemical contaminants. An increase in TDS may be indicative of
drilling operations having introduced contaminants into the water supply.
Static water level is the level of the water in the well during normal conditions prior to any
pumping. This is a measure of the amount of water in the aquifer. Analysis of changes in
static water level should carefully consider the well’s construction, maintenance and
operational history, recent precipitation and use patterns, the season and the effects of
competing wells.
VOCs encompass a number of compounds that are expected to be used extensively during
surface operations and would account for water supplies potentially being affected by spills,
leaking pits, or other unforeseen incidents. Additionally, certain VOCs are known to exist in
shale and are expected to be a contaminant of concern in the event that flowback waters or
production brines migrate into an aquifer.

Final SGEIS 2015, Page 7-46

 Sampling Protocol
The Department proposes to require that water samples to be collected by a qualified
professional and analyzed utilizing a NYSDOH ELAP approved laboratory, 447 including the use
of proper sampling and laboratory protocol, in addition to the use of proper sample containers,
preservation methods, holding times, chain of custody, analytical methods, and laboratory
QA/QC.
The water samples would be representative of the aquifer being produced by the well.
Therefore, the well pump should be allowed to run for at least 5 minutes prior to sample
collection. The sample should be collected prior to any in home water treatment that may be
present. If this is not feasible, the type of treatment that is present on the well survey should be
noted. The samples should be collected in appropriate containers, refrigerated, and transported
to the laboratory for analysis.
Recommended Sampling Procedure for Water Supply Wells

447

•

Select an indoor, leak-free, cold water faucet from which to collect the sample. If
treatment (softener, filter, RO, etc.) exists the sample should be collected from an
untreated location or the treatment should be bypassed;

•

Remove the faucet’s aerator or strainer, if one is present;

•

Disinfect the faucet by cleaning and flaming the inside of the faucet;

•

Let cold water run for 5 minutes;

•

Reduce water flow to a stream of water the size of a pencil or smaller;

•

Fill sample bottles per method specifications, making sure not the touch the inside of the
bottle or cap; and

•

Cap bottles, refrigerate, and transport to the laboratory for analysis.

http://www.wadsworth.org/labcert/elap/elap.html, accessed 9/16/09.

Final SGEIS 2015, Page 7-47

 Complaints
As noted in the 1992 GEIS:
The diversity of jurisdictions having authority over local water supplies
complicates the response to complaints about water supplies, including those
complaints that complainants believe are related to oil and gas activity. Water
supply complaints occur statewide and take many forms, including taste and
turbidity problems, water quantity problems, contamination by salt, gasoline and
other chemicals and problems with natural gas in water wells. All of these
problems, including natural gas in water supplies, occur statewide and are not
restricted to areas with oil and gas development. 448 and:
The initial response to water supply complaints is best handled by the appropriate
local health office, which has expertise in dealing with water supply problems. 449
The Department has MOUs in place with several county health departments in western NY
whereby the county health department initially investigates a complaint and then refers it to the
Department when a problem has been verified and other potential causes have been ruled out.
For complaints that occur more than a year after the last hydraulic fracturing operations on a well
pad within the radius where baseline sampling occurred (1,000 feet or 2,000 feet), or for
complaints regarding water wells that are more than 2,000 feet away from any well pad, the
Department proposes to continue following the aforementioned procedure statewide.
Complaints would be referred to the county health department, who would refer them back to the
Department for investigation when a problem has been verified and other potential causes have
been ruled out. Sampling and analysis to verify and evaluate the problem would be according to
protocols that are satisfactory to the county health department, with advice from NYSDOH as
necessary.
Complaints that occur during active operations at a well pad within 2,000 feet or the radius
where baseline sampling occurred, or within a year of last hydraulic fracturing at such a site,
should be jointly investigated by the Department and the county health department. Mineral
Resources staff would conduct a site inspection, and if a complaint coincides with any of the
following documented potentially polluting non-routine well pad incidents, then the Department
448

NYSDEC, 1992, GEIS, pp. 15-4 et seq.

449

NYSDEC, 1992, GEIS, p. 15-5.

Final SGEIS 2015, Page 7-48

 would consider the need to require immediate cessation of operations, immediate corrective
action and/or revisions to subsequent plans and procedures on the same well pad, in addition to
any applicable formal enforcement measures:
•

Surface chemical spill;

•

Fracturing equipment failure;

•

Observed leaks in surface equipment onto the ground, into stormwater runoff or into a
surface water body;

•

Observed pit liner failure;

•

Significant lost circulation or fresh water flow below surface casing;

•

The presence of brine, gas or oil zones not anticipated in the pre-drilling prognosis;

•

Evidence of a gas-cut cement job;

•

Anomalous flow or pressure profile during fracturing operations;

•

Any non-routine incident listed in ECL §23-0305(8)(h) (i.e., casing and drill pipe
failures, casing cement failures, fishing jobs, fires, seepages, blowouts); or

•

Any violation of the ECL, its implementing rules and regulations, or any permit
condition, including the requirement that the annulus between the surface casing and the
next casing string be maintained in a non-pressurized condition; and

The Department and the county health department would share information. All data on file with
the county health department relative to the subject water well, including pre-existing conditions
and any available information about the well’s history of use and maintenance, would be
considered in determining the proper course of action with respect to well pad activities. Subsection 8.2.3 describes the Department’s enforcement authority and the enforcement mechanisms
available to the Department.
7.1.4.2 Sufficiency of As-Built Wellbore Construction
Wellbore construction is addressed by the existing 1992 GEIS. While the same concepts apply
to wells used for high-volume hydraulic fracturing, some enhancements are proposed because of
the high pressures that will be exerted, the large fluid volumes that will be pumped and potential

Final SGEIS 2015, Page 7-49

 concentration of the activity in areas without much subsurface well control. Further, recent
Marcellus Shale well drilling and completion experience and associated problems in other states
were analyzed and considered.
Surface Casing
As defined in regulations, the purpose of surface casing is to protect potable fresh water. 450 For
oil and gas regulatory purposes, potable fresh water is defined as water containing less than 250
ppm of sodium chloride or 1,000 ppm of total dissolved solids. 451 As stated in Chapter 2,
maximum depth of potable water in an area should be determined based on the best available
data. This would include water wells and other oil and gas wells in the area, any available local
or regional geologic or hydrogeologic reports, and information from the sources listed in Section
7.1.11.1. When information is not available, a depth of 850 feet to the base of potable
groundwater is a commonly-used and practical generalization.
Current casing and cementing practices attached as conditions to all oil and gas permits require
that:
•

Surface casing shall extend at least 75 feet beyond the deepest fresh water zone
encountered or 75 feet into bedrock, whichever is deeper, and deeply enough to allow the
blow-out preventer stack to contain any formation pressures that may be encountered
before the next casing is run;

•

Surface casing shall not extend into zones known to contain measurable quantities of
shallow gas, and, in the event such a zone is encountered before the fresh water is cased
off, the operator shall notify the Department and take Department-approved actions to
protect the fresh water zone(s); and

•

Surface casing shall consist of new pipe with a mill test of at least 1,000 psi, or used
casing that is pressure tested before drilling ahead after cementing; welded pipe must also
be pressure tested.

The Department proposes to require, via permit condition and/or regulation, the submission of a
Pre-Frac Checklist and Certification Form (pre-frac form) to the Department at least 3 days

450

6 NYCRR §550.3(au).

451

6 NYCRR §550.3(ai).

Final SGEIS 2015, Page 7-50

 prior to commencement of high-volume hydraulic fracturing operations. Regarding the surface
casing hole, the pre-frac form would:
a. Attest to well construction having been performed in accordance with the well permit or
approved revisions,
b. List the depth and estimated flow rates where fresh water, brine, oil and/or gas were
encountered or circulation was lost during drilling operations, and
c. Include information about how any lost circulation zones were addressed.
Hydraulic fracturing would not be authorized to proceed without the above information and
certification.
Surface Casing Cement
Current casing and cementing practices attached as conditions to all oil and gas permits require:
•

Cementing by the pump and plug method and circulation to surface;

•

Minimum of 25% excess cement pumped, with appropriate lost circulation materials;

•

Testing of the mixing water for pH and temperature prior to mixing;

•

Cement slurry preparation to the manufacturer’s or contractor’s specifications to
minimize free water in the cement; and

•

No casing disturbance after cementing until the cement achieves a calculated
compressive strength of 500 psi (e.g., performance chart).

All of the above requirements would remain in effect, and the Department would require the
following additional requirements via permit condition and/or regulation:
1) The pre-frac form would be required as described above;
2) Cement would be required to conform to API Specification 10A, Specifications for
Cement and Material for Well Cementing (April 2002 and January 2005 Addendum).
Further, the cement slurry would be required to be prepared to minimize its free water
content in accordance with the same API specification and it would be required to contain
a gas-block additive; and
3) A minimum WOC (wait on cement) time of 8 hours before the casing is disturbed in any
way, including installation of a blow-out preventer (BOP). The operator may request a

Final SGEIS 2015, Page 7-51

 waiver from the Department from the required WOC time if the operator has bench tested
the actual cement batch and blend using mix water from the actual source for the job, and
determined that 8 hours is not required to reach a compressive strength of 500 psig.
Intermediate Casing
Intermediate casing is run in a well after the surface casing but before production hole is drilled.
Fully cemented intermediate casing can be necessary in some wells to prevent possible
pressurization of the surface casing seat, and to effectively seal the hole below the surface casing
to prevent communication between separate hydrocarbon-bearing strata and between
hydrocarbon and water-bearing strata. The primary uses of intermediate casing are to 1) provide
a means of controlling formation pressures and fluids below the surface casing, 2) seal off
problematic zones prior to drilling the production hole and 3) ensure a casing seat of sufficient
fracture strength for well control purposes. The intermediate casing’s design and setting depth is
typically based on various factors including anticipated or encountered geologic characteristics,
wellbore conditions and the anticipated formation pressure at total depth of the well. Factors can
also include the setting depth of the surface casing, occurrence of shallow gas or flows in the
open hole, mud weights used to drill below intermediate casing, and well-control and safety
considerations.
Current casing and cementing practices attached as conditions to all oil and gas well drilling
permits state that intermediate casing string(s) and cementing requirements will be reviewed and
approved by the Department on an individual well basis. The Department proposes to require,
via permit condition and/or regulation, that for high-volume hydraulic fracturing the installation
of intermediate casing in all wells covered under the SGEIS would be required. However, the
Department may grant an exception to the intermediate casing requirement when technically
justified. A request to waive the intermediate casing requirement would need to be made in
writing with supporting documentation showing that environmental protection and public safety
would not be compromised by omission of the intermediate string. An example of circumstances
that may warrant consideration of the omission of the intermediate string and granting of the
waiver could include: 1) deep set surface casing, 2) relatively shallow total depth of well and 3)
absence of fluid and gas in the section between the surface casing and target interval. Such
intermediate casing waiver request may also be supported by the inclusion of information on the
subsurface and geologic conditions from offsetting wells, if available.

Final SGEIS 2015, Page 7-52

 Intermediate and Production Casing Cement
Current casing and cementing practices set requirements for production casing cement and state
that intermediate casing cement requirements would be reviewed and approved on an individual
well basis. The requirements for production casing cement are as follows:
•

Cement must extend at least 500 feet above the casing shoe or tie into the previous casing
string, whichever is less;

•

If any oil or gas shows are encountered or known to be present in the area, as determined
by the Department at the time of permit application, or subsequently encountered during
drilling, the production casing cement shall extend at least 100 feet above any such
shows;

•

Weighted fluid may be used in the annulus to prevent gas migration in specific instances
when the weight of the cement column could be a problem;

•

Cementing shall be by the pump and plug method for all jobs deeper than 1,500 feet, with
a minimum of 25% excess cement unless caliper logs are run, in which case 10% excess
will suffice;

•

The mixing water shall be tested for pH and temperature prior to mixing; and

•

Following cementing and removal of cementing equipment, the operator shall wait until a
calculated (e.g., performance chart) compressive strength of 500 psi is achieved before
the casing is disturbed in any way.

The above requirements will remain in effect. In addition, the Department proposes to require,
via permit condition and/or regulation, the following additional requirements for high-volume
hydraulic fracturing:
1) The pre-frac form would be required as described above;
2) The setting depth of the intermediate casing would consider the cementing requirements
for the intermediate casing and the production casing as noted below;
3) Intermediate casing would be cemented to the surface and cementing would be by the
pump and plug method with a minimum of 25% excess cement unless caliper logs are
run, in which case 10% excess would suffice;
4) Production casing cement would be tied into the intermediate casing string with at least
300 feet of cement measured using True Vertical Depth (TVD). If intermediate casing

Final SGEIS 2015, Page 7-53

 installation is waived by the Department, the production casing would be cemented to the
surface;
5) Cement would conform to API Specification 10A, Specifications for Cement and
Material for Well Cementing (April 2002 and January 2005 Addendum). Further, the
cement slurry would be prepared to minimize its free water content in accordance with
the same API specification and it would contain a gas-block additive;
6) A minimum WOC time of 8 hours before the casing is disturbed in any way, including
installation of a blow-out preventer (BOP). The operator may request a waiver from the
Department from the required WOC time if the operator has bench tested the actual
cement batch and blend using mix water from the actual source for the job, and
determined that 8 hours is not required to reach a compressive strength of 500 psig;
7) The operator would run a radial cement bond evaluation log or other evaluation approved
by the Department to verify the cement bond on the intermediate casing and the
production casing. The quality and effectiveness of the cement job would be evaluated
using the above required evaluation in conjunction with appropriate supporting data per
Section 6.4 “Other Testing and Information” under the heading of “Well Logging and
Other Testing” of API Guidance Document HF1 (First Edition, October 2009). Remedial
cementing would be required if the cement bond is not adequate to drill ahead and isolate
hydraulic fracturing operations, respectively; and
8) The internal pressure test of the production string, prior to hydraulic fracturing, may not
commence for at least 7 days after the primary cementing operations are completed on
this casing string to help prevent the formation of a micro-annulus.
Centralizers
The use and purpose of centralizers, as recommended by GWPC, is to keep the casing centered
in the wellbore so that cement adequately fills the space around it. Current casing and cementing
practices attached as conditions to all oil and gas drilling permits require use of centralizers on
all casing strings and specify adequate hole diameters and spacing for their use. Centralizers are
required every 120 feet on surface casing, but no fewer than two may be run. These
requirements will continue to apply to wells drilled for high-volume hydraulic fracturing.
The above requirements will remain in effect. In addition, the Department proposes to require,
via permit condition and/or regulation, additional requirements for high-volume hydraulic
fracturing:
1) At least two centralizers, one in the middle and top of the first joint of casing, would be
installed on the surface and intermediate casing strings, and all bow-spring style

Final SGEIS 2015, Page 7-54

 centralizers used on all strings would conform to API Specification 10D for Bow-Spring
Casing Centralizers (March 2002).
Inspections to Witness Casing and Cementing Operations
Current casing and cementing practices attached as conditions to all oil and gas well drilling
permits require notification to the Department prior to any surface casing pressure test when
welded connections or used casing is run. In primary and principal aquifer areas, the Department
must be notified prior to surface casing cementing operations and cementing cannot commence
until a state inspector is present. Supplementary Permit Conditions for high-volume hydraulic
fracturing require notification prior to surface, intermediate and production casing cementing for
all wells, so that Department staff has the opportunity to witness the operations.
7.1.4.3 Annular Pressure Buildup
Current casing and cementing practices require that the annular space between the surface casing
and the next string be vented at all times to prevent pressure build-up in the annulus. If the
annular gas is to be produced, a pressure relieve valve would be installed in an appropriate
manner and set at a pressure approved by the Department. Proposed Supplementary Permit
Conditions for high-volume hydraulic fracturing state that “under no circumstances should the
annulus between the surface casing and the next casing string be shut-in, except during a
pressure test.”
7.1.5

Setback from FAD Watersheds

Based on the analysis set forth in Section 6.1.5, the Department concludes that high-volume
hydraulic fracturing within the NYC and Syracuse watersheds poses the risk of causing
significant adverse impacts to these irreplaceable water supplies. The potential economic
consequence of such impacts – loss of Filtration Avoidance – are substantial. The Department
finds that standard stormwater control and other mitigation measures would not fully mitigate the
risk of potential significant adverse impacts on water resources from high-volume hydraulic
fracturing. Even with such controls in place, the risk of spills and other unplanned events
resulting in the discharge of pollutants associated with high-volume hydraulic fracturing
operations, even if relatively remote, would have significant consequences in these unfiltered
water supplies. In addition, the increased industrial activity associated with well pad
development, road construction and other activities associated with high-volume hydraulic

Final SGEIS 2015, Page 7-55

 fracturing is not consistent with the long-term protection of the NYC and Syracuse unfiltered
surface drinking water supplies. Accordingly, the Department recommends that regulations be
adopted to prohibit high-volume hydraulic fracturing in both the NYC and Skaneateles Lake
watersheds, as well as in a 4,000-foot buffer area surrounding these watersheds, to provide an
adequate margin of safety from the full range of operations related to high-volume hydraulic
fracturing that extend away from the well pad. The Department also is presenting this proposal
based on its consistency with the principles of source water protection and the "multi-barrier"
approach to systematically assuring drinking water quality. See, e.g., National Research Council
Watershed Management for Potable Water Supply: Assessing the NYC Strategy at 97-98 (2000);
American Water Works Association, State Source Water Protection Statement of Principles,
AWWA Mainstream (1997).
7.1.6

Hydraulic Fracturing Procedure

As detailed in this document, potential impacts to ground water from the high-volume hydraulic
fracturing procedure itself are, in most cases, not anticipated. To the extent that any impacts may
occur, the risks have been reduced by all of the proposed mitigation measures outlined above that
the Department proposes to require as permit conditions and/or regulations for high-volume
hydraulic fracturing. These include:
•

Requirement for private water well testing;

•

Pit construction and liner specifications for well pad reserve pits;

•

Requirement that covered watertight tanks be used to contain flowback water on site;

•

Appropriate secondary containment measures;

•

Removal of fluids within specified time frames;

•

Requirement that a Department-approved BOP Use and Test Plan be followed during
well drilling and/or completion operations;

•

Requirement that a snubbing unit and/or coiled tubing unit with a BOP be used to enter
any well with pressure and/or to drill out one or more solid-core stage plugs;

Final SGEIS 2015, Page 7-56

 •

Requirement that appropriate pressure-control procedures and equipment be used, and
fracturing equipment that is pressure tested with fresh water, mud or brine ahead of
pumping the hydraulic fracturing fluid;

•

Requirement for notification to the Department prior to cementing surface, intermediate,
and production casing;

•

Requirements for cement to surface on the surface and intermediate casing strings and
production casing cement tied into the intermediate casing, and a radial cement bond
evaluation log or other evaluation approved by the Department on the intermediate and
production casing strings;

•

Requirement for the submittal of a fracturing treatment plan (as part of the pre-frac form)
which includes a profile of the anticipated pressures and water volume for pumping the
first stage, a description of the planned treatment interval (i.e., top and bottom of
perforations expressed in both True Vertical Depth (TVD) and True Measured Depth
(TMD)), the total number of stages and total volume of water for hydraulic fracturing
operations;

•

Use of the pre-frac form to certify wellbore integrity prior to fracturing;

•

Pre-fracturing pressure testing of casing (if a fracturing string is not used) from surface to
top of treatment interval;

•

Requirement that, prior to spudding the first well on a well pad, a non-routine incident
plan is in place to address potential threats to public health and the environment. The
plan would include detailed descriptions of notification, reporting, and remedial measures
to ensure that any non-routine incident is addressed as quickly and as completely as
possible; and

•

Disclosure to the Department of fracturing fluid additives so that appropriate remedial
actions can be taken in response to any spill or release.

The Department proposes to require as standard permit conditions non-routine incident handling
requirements to ensure that any potential environmental or public health issues are identified,
reported, and remedied as expeditiously as possible. Non-routine incidents would be identified
as soon as possible, and verbal notification to the department would be made within two hours of
its discovery or known occurrence. Non-routine incidents may include, but are not limited to:
casing, drill pipe or hydraulic fracturing equipment failures; cement failures; fishing jobs; fires;
seepages; blowouts; surface chemical spills; observed leaks in surface equipment; observed pit
liner failures; surface effects at previously plugged or other wells; observed effects at water wells
or at the surface; complaints of water well contamination; anomalous pressure and/or flow

Final SGEIS 2015, Page 7-57

 conditions indicated or occurring during hydraulic fracturing operations; or other potentially
polluting non-routine incidents or incidents that may affect the health, safety, welfare, or
property of any person. If hydraulic fracturing activities are suspended pending the satisfactory
completion of non-routine incident reporting and remediation, the operator would be required to
receive Department approval prior to recommencing hydraulic fracturing activities in the same
well.
To help reduce the risk that abandoned wells do not provide a conduit for contamination of fresh
water aquifers, the Department proposes to require that the operator consult the Department’s Oil
and Gas database as well as property owners and tenants in the proposed spacing unit to
determine whether any abandoned wells are present. If (1) the operator has property access
rights, (2) the well is accessible, and (3) it is reasonable to believe based on available records and
history of drilling in the area that the well’s total depth may be as deep or deeper than the target
formation for high-volume hydraulic fracturing, then the Department would require the operator
to enter and evaluate the well, and properly plug it prior to high-volume hydraulic fracturing if
the evaluation shows the well is open to the target formation or is otherwise an immediate threat
to the environment. If any abandoned well is under the operator’s control as owner or lessee of
the pertinent mineral rights, then the operator is required to comply with the Department’s
existing regulations regarding shut-in or temporary abandonment if good cause exists to leave
the well unplugged. This would require a demonstration that the well is in satisfactory condition
to not pose a threat to the environment, including during nearby high-volume hydraulic
fracturing, and a demonstrated intent to complete and/or produce the well within the time frames
provided by existing regulations.
The proposed permit conditions would also include a requirement to monitor flowback rates in
addition to daily and total flowback volumes. These flowback data would be required to be
documented on the Well Drilling and Completion Report. Though flowback rates (and volumes)
will likely vary based on differing well-specific conditions, an analysis of flowback rates may
provide an indication of future flowback rates.
As explained in Section 6.1.5.2, the conclusion that harm from fracturing fluid migration up from
the horizontal wellbore is not reasonably anticipated is contingent upon the presence of certain

Final SGEIS 2015, Page 7-58

 natural conditions, including 1,000 feet of vertical separation between the bottom of a potential
aquifer and the top of the target fracture zone. The presence of 1,000 feet of low-permeability
rocks between the fracture zone and a drinking water source serves as a natural or inherent
mitigation measure that protects against groundwater contamination from hydraulic fracturing.
As stated in Section 8.4.1.1, GWPC recommended a higher level of scrutiny and protection for
shallow hydraulic fracturing or when the target formation is in close proximity to underground
sources of drinking water. Therefore, the Department proposes that site-specific SEQRA review
be required for the following projects:
1) Any proposed high-volume hydraulic fracturing where the top of the target fracture zone
at any point along any part of the proposed length of the wellbore is shallower than 2,000
feet below the ground surface; and
2) Any proposed high-volume hydraulic fracturing where the top of the target fracture zone
at any point along any part of the proposed length of the wellbore is less than 1,000 feet
below the base of a known freshwater supply.
Review would focus on local topographic, geologic, and hydrogeologic conditions, along with
proposed fracturing procedures to determine the potential for a significant adverse impact to
fresh groundwater. The need for a site-specific SEIS would be determined based upon the
outcome of the review.
7.1.7

Waste Transport

7.1.7.1 Drilling and Production Waste Tracking Form
Prior to well permit issuance, the applicant would be required to provide a fluid disposal plan as
required by 6 NYCRR § 554.1(c)(1). Waste transport is an integral part of that plan and
transportation tracking helps to ensure that fluid wastes are disposed of properly. Because of the
number of wells that may be drilled and the current limited disposal options, as well the
anticipated volume of flowback water, the paucity of reliable data regarding flowback water and
production brine composition from New York operations, and NORM concerns, the Department
proposes to require via permit condition and/or regulation that a Drilling and Production Waste
Tracking Form be completed and maintained by generators, haulers and receivers of all flowback
water associated with activities addressed by this Supplement. The record-keeping requirements

Final SGEIS 2015, Page 7-59

 and level of detail would be similar to what is presently required for medical waste. 452 The form
would be required regardless of whether waste is taken to a treatment facility, disposal well,
another well pad, a landfill, or elsewhere. Flowback water transport may be reduced by
treatment and reuse on the same pad for hydraulic fracturing. The Drilling and Production
Waste Tracking Form would also be used to track the transport of production brine from wells
covered under the SGEIS.
7.1.7.2 Road Spreading
Flowback Water
As explained in Chapter 5 and presented in Appendix 12, consistent with past practice, the
Department began in January 2009 notifying Part 364 haulers applying for, modifying or
renewing their Part 364 permit that flowback water may not be spread on roads and must be
disposed of at facilities authorized by the Department or transported for use or re-use at other gas
or oil wells where acceptable to the Division of Mineral Resources.
Production Brine
The notification described above informed Part 364 haulers that any entity applying for a Part
364 permit or permit modification to use production brine for road spreading must submit a
petition for a BUD to the Department. However, the data available to date associated with
NORM concentrations in Marcellus Shale production brine is insufficient to allow road
spreading under a BUD. As more data becomes available, it is anticipated that petitions for such
use will be evaluated by the Department.
For production brines that are intended for use on roads, the BUD and Part 364 permit would be
issued by the Department prior to the removal of any production brine from the well site. As set
forth in the notification, a BUD petition would include analytical results from an ELAPapproved laboratory of a representative sample for the following parameters: NORM, calcium,
sodium, chloride, magnesium, TDS, pH, iron, barium, lead, sulfate, oil & grease, benzene,
ethylbenzene, toluene, and xylene. Dependent upon the analytical results, the Department may
require additional analyses. Evaluations of BUD petitions would include case-by-case
452

http://www.dec.ny.gov/docs/materials_minerals_pdf/medwste.pdf.

Final SGEIS 2015, Page 7-60

 assessments of potential impacts, and would establish limits on volume and frequency of
application.
7.1.7.3 Flowback Water Piping
Flowback water piping and conveyances between well pads and flowback water storage tanks
would be described in the fluid disposal plan required by 6 NYCRR §554.1(c)(1) and the
proposed GP. The fluid disposal plan would demonstrate that pipelines and conveyances would
be constructed of suitable materials, maintained in a leak-free condition, regularly inspected, and
operated using all appropriate spill control and stormwater pollution prevention practices.
Upon review of the existing regulatory framework for liquid containment, the Department has
determined that the existing regulatory structure established for solid waste management
facilities, 6 NYCRR Part 360 (Part 360), is most applicable for the containment, operational,
monitoring and closure requirements for centralized flowback water management facilities. 453
The specific provisions of Subpart 360-6 Liquid Storage would provide the overall requirements
for tanks, describing the minimum operational, monitoring and closure requirements. These
provisions would cross-reference other applicable provisions of Part 360 which more specifically
address system design, materials, quality assurance and certification requirements that likewise
would be applicable to the flowback water containment systems discussed in the SGEIS.
7.1.7.4 Use of Tanks Instead of Impoundments for Centralized Flowback Water Storage
As previously noted, centralized flowback water surface impoundments are not covered under
the SGEIS and the Department proposes that such require a site-specific environmental
assessment and SEQRA determination of significance. Nevertheless, above ground storage
tanks have advantages over surface impoundments. The Department’s experience is that landfill
owners prefer above ground storage tanks over surface impoundments for storage of landfill
leachate. Tanks, while initially more expensive, experience fewer operational issues associated
with liner system leakage. In addition, tanks can be easily covered to control odors and air
emissions from the liquids being stored. Precipitation loading in a surface impoundment with a

453

6 NYCRR Part 360 regulations: http://www.dec.ny.gov/regs/2491.html.

Final SGEIS 2015, Page 7-61

 large surface area can, over time, increase the volumes of liquid needing treatment. Lastly,
above ground tanks also can be dismantled and reused. The provisions of Section 360-6.3
address the minimum regulatory requirements applicable to above ground storage tanks.
7.1.7.5 Closure Requirements
The closure requirements for liquid storage facilities under Subpart 360-6 are specified in section
360-6.6 Closure of Liquid Storage Facilities. These provisions detail the specific closure
requirements for these containment structures and require any post-operation residues to be
properly handled and disposed of as part of the process.
7.1.8

SPDES Discharge Permits

SPDES Discharge Permits - The federal Clean Water Act authorized the development of the
National Pollutant Discharge Elimination System (NPDES) for implementing the requirements
for all discharges to surface waters of the United States. The Department was subsequently
charged, pursuant to the ECL, to develop and administer the state’s program for meeting the
requirements of NPDES. This program, which is authorized by the EPA, is referred to as the
State Pollutant Discharge Elimination System (SPDES).
Regulation of discharges of pollutants to waters of the state, both surface and groundwaters, is
authorized by Article 17 of the ECL. Specific controls on point source discharges are authorized
by Article 17, Title 8 of the ECL. New York’s SPDES program is more stringent than the
federal NPDES program in that the SPDES program also regulates discharges to groundwater.
The minimum threshold for applicability of SPDES to groundwater discharges is 1,000 gpd for
sanitary wastewater, while discharges which include any industrial wastewater have no minimum
threshold. The NYSDOH regulates discharges of less than 1,000 gpd consisting of only sanitary
wastewater. The Department is authorized to issue SPDES permits for groundwater discharges
for a maximum period of 10 years; permits for discharges to surface waters are issued for a
maximum of 5 years.
Administration of the SPDES program is accomplished through the issuance of wastewater
discharge permits, including both individual permits and general permits. Individual SPDES
permits are issued to cover a single facility in one location possessing unique discharge

Final SGEIS 2015, Page 7-62

 characteristics and other factors. General SPDES permits are issued to cover a category of
discharges involving the same or similar types of operations; discharge the same types of
pollutants; require the same effluent limitations or operating conditions; require the same or
similar monitoring; and do not have a significant impact on the environment, either individually
or cumulatively, when carried out in conformance with permit provisions.
The Department is vested with the authority pursuant to state and federal law to enforce the
SPDES permit requirements. The primary objective of the SPDES compliance and enforcement
program is to protect water quality by ensuring that all point sources of pollution obtain a SPDES
permit and comply with all terms and conditions of the permit.
The Department would employ any available compliance mechanisms that may be necessary,
including formal enforcement, to attain the goal of SPDES permit compliance.
Flowback water and production brine are considered industrial wastewater. Wastewater is
generated by many water users and industries. The SPDES program controls point source
discharges to ground waters and surface waters. The Department proposes to require, through
the well permitting process, that the permittee demonstrate prior to issuance of the drilling permit
that any wastewater treatment facility proposed for disposal flowback water and production brine
has the necessary treatment capacity. Furthermore, the Department proposes to continue
requiring that once high-volume hydraulic fracturing operations have ceased and the gas well(s)
are in the production phase, that the permittee properly collect and dispose of all production
fluids generated at the site.
7.1.8.1 Treatment Facilities
SPDES permits are issued to wastewater dischargers, including treatment facilities such as
POTWs operated by municipalities. SPDES permits include specific discharge limitations and
monitoring requirements. The effluent limitations are typically the maximum allowable
concentrations and/or mass loadings for various physical, chemical, and/or biological parameters
to ensure that there are no impacts to the receiving water body.

Final SGEIS 2015, Page 7-63

 POTWs
A POTW must have an approved pretreatment program, or mini-pretreatment program,
developed in accordance with the above requirements in order to accept industrial wastewater
from non-domestic sources covered by Pretreatment Standards which are indirectly discharged
into or transported by truck or rail or otherwise introduced into POTWs.
The Department’s DOW shares pretreatment program oversight (approval authority)
responsibility with the EPA. Indirect discharges to POTWs are regulated by 6 NYCRR §7502.9(b), National Pretreatment Standards, which incorporates by reference the requirements set
forth under 40 CFR Part 403, “General Pretreatment Regulations for Existing and New Sources
of Pollution.” In accordance with DOW’s TOGS 1.3.8, 6 NYCRR §750-2.9, 40 CFR Part 403,
and 40 CFR 122.42, New York State POTW permittees with industrial pretreatment or minipretreatment programs are required to notify the Department of new discharges or substantial
changes in the volume or character of pollutants discharged to the permitted POTW. The
Department must then determine if the SPDES permit needs to be modified to account for the
proposed discharge, change or increase.
Flowback water and production brine from wells permitted pursuant to this Supplement may
only be accepted by POTWs or any other wastewater treatment plant with approved pretreatment
or mini-pretreatment programs, as noted above, and an approved headworks analysis for this
wastewater source in accordance with 40 CFR Part 403 and DOW’s TOGS 1.3.8 and as required
by the POTW’s SPDES permit that includes appropriate monitoring and effluent limits for this
wastewater source. The SPDES permit for the POTW would include specific discharge
limitations and monitoring requirements, including routine reporting of monitoring results,
tracking of these results by the Department, and a well established compliance program to deal
with permit violations.
The Department’s procedures for POTW acceptance of high-volume hydraulic fracturing
wastewater discharges are detailed in Appendix 22 of this Supplement. Discharges that follow
these procedures would provide effective mitigation of significant adverse impacts.

Final SGEIS 2015, Page 7-64

 Private Wastewater Treatment Facilities
Privately owned facilities for the treatment and disposal of industrial wastewater from highvolume hydraulic fracturing operate in other states, including Pennsylvania. Similar facilities
that might be constructed in New York would require a SPDES permit. The permittee would
apply for SPDES permit coverage for a dedicated treatment facility would include specific
discharge limitations and monitoring requirements. The effluent limitations are the maximum
allowable concentrations or ranges for various physical, chemical, and/or biological parameters
to ensure that there are no impacts to the receiving water body.
Private treatment systems, which are designed, constructed, and approved to treat the parameters
specific to high-volume hydraulic fracturing wastewater, including processes as discussed in
Section 5.12 (Flowback Water Treatment, Recycling and Reuse), may be more effective than
POTWs for the treatment, disposal, and potential reuse of this source of wastewater because they
can be designed and optimized to remove the parameters specific to this source of wastewater.
As noted in Chapter 5 of this revised draft SGEIS, onsite treatment of flowback water for
purposes of reuse is currently being used in Pennsylvania and other states. The treated water is
blended with fresh water at the well, generally, and reused for hydraulic fracturing with the
treatment residue hauled off-site. These types of facilities do not require a SPDES permit unless
the discharge of wastewater is planned. The use of on-site treatment and reuse facilities reduces
the demand for fresh water and provides effective mitigation of potential adverse impacts.
7.1.8.2 Disposal Wells
Because of the 1992 GEIS Finding that brine disposal wells require site-specific SEQRA review,
mitigation measures are discussed here for informational purposes only and are not being
proposed on a generic basis.
Flowback and disposal strata water quality must be fully characterized prior to permitting and
injecting into a disposal well. Additional geotechnical information regarding the disposal
strata’s ability to accept and retain the injected fluid is also necessary. The permittee would
apply for and receive coverage under the EPA UIC program prior to applying for a SPDES
permit for discharge using Form NY-2C, available on the Department’s website. The

Final SGEIS 2015, Page 7-65

 characterization and SPDES permit application process for disposal wells is similar to that for
private treatment facilities.
The Department may propose monitoring requirements and/or discharge limits in the SPDES
permit in addition to any requirements included in the required EPA UIC permit. These would
be determined during the site-specific permitting process required by the Uniform Procedures
Act and the 1992 Findings Statement. To be protective of the overlying potable water aquifers,
the site-specific permitting process would consider the following topics:
•

Distance to drinking water supplies or sources, surface water bodies and wetlands;

•

Topography, geology, and hydrogeology;

•

The proposed well construction and operation program;

•

Water quality analysis of the receiving stratum for TDS, chloride, sulfate and metals;

•

Effluent limits for injectate constituents, and potential applicability of 6 NYCRR §703.6
groundwater effluent limits or the groundwater effluent guidance values listed in DOW
TOGS 1.1.1; and

•

Potential requirement for upgradient and downgradient monitoring wells installed in the
deepest identified GA or GSA potable water aquifer.

New York State currently has six permitted underground disposal wells, three of which are used
to dispose of brine produced with oil and /or gas. However, these wells are privately owned and
currently are approved to inject only their own brine. Use of an existing permitted underground
disposal well would require a modification of the existing UIC and SPDES permits for the
existing wells to accept flowback.
The Department notes that potential impacts as described in Chapter 6 of this revised draft
SGEIS have occurred in other states, and remain a concern. With the above mitigation measures
in place, combined with permit monitoring and oversight, significant impacts from waste
transport and disposal in connection with high-volume hydraulic fracturing wastewater would be
reduced.

Final SGEIS 2015, Page 7-66

 7.1.9

Solids Disposal

Cuttings may be managed within a closed-loop tank system or within the lined reserve pit. If
cuttings are contained within the reserve pit and a common reserve pit is used for multiple wells
on the pad, cuttings may have to be removed several times to maintain the required two feet of
freeboard set forth in Section 7.1.3.2. Care must be taken during this operation not to damage
the liner.
Cuttings contaminated with oil-based or polymer-based mud could not be buried on site; they
would be managed in a closed-loop tank system and removed from the site for disposal in a Part
360 solid waste facility. Supplementary permit conditions pertaining to the management of drill
cuttings from high-volume hydraulic fracturing require consultation with the Department’s
Division of Materials Management for the disposal of any cuttings associated with water-based
mud-drilling and any pit liner associated with water-based or brine-based mud-drilling where the
water-based or brine-based mud contains chemical additives. Supplemental permit conditions
also dictate that any cuttings required to be disposed of off-site, including at a landfill, be
managed on-site within a closed-loop tank system rather than a reserve pit.
As the basal portion of the Marcellus has been reported to contain abundant pyrite (an iron
sulfide mineral), 454 there exists the potential that cuttings derived from this interval and placed in
reserve pits may oxidize and leach, resulting in an acidic discharge to groundwater, commonly
referred to as acid rock drainage (ARD). A site-specific ARD-mitigation plan would be required
to be prepared and followed by the operator for on-site burial of Marcellus Shale cuttings from
horizontal drilling in the Marcellus Shale if the operator elects to bury these cuttings. The ARDmitigation plan would be designed to neutralize acid drainage through the emplacement of basic
carbonate materials (e.g., waste lime or limestone cuttings) prior to on-site burial. The pyritic
drill cuttings and the carbonate materials would be mixed thoroughly and compacted prior to
reclamation of the pit area. This method was demonstrated to be effective in an ARD-abatement

454

Engelder and Lash, 2008.

Final SGEIS 2015, Page 7-67

 project jointly conducted by Penn DOT and PADEP during construction of U.S. Route 22 near
Lewiston PA in 2004. 455
Alternatively, if the operator elects or is required (for reasons related to drilling fluid
composition, as previously discussed) to utilize an off-site disposal facility for disposal of
cuttings from horizontal drilling in the Marcellus Shale, then no ARD-mitigation plan is
required. In such instances however, supplementary permit conditions require that these cuttings
be managed and contained on-site within a closed-loop tank system rather than within a reserve
pit, prior to removal for off-site disposal.
Annular disposal of drill cuttings has also been proposed; however, this is not an acceptable
practice in New York and is prohibited by the high-volume hydraulic fracturing Supplementary
Permit Conditions.
Although not directly related to a water resources impact, consideration also should be given to
monitoring and mitigating subsidence by adding fill as any uncontaminated drill cuttings that are
buried on site dewater and consolidate.
7.1.10 Protecting NYC’s Subsurface Water Supply Infrastructure
The advent, in the late 1990s and early 2000s, of geothermal well drilling – also regulated under
ECL 23 if the wells are deeper than 500 feet – led to mutually agreed upon protocols between the
Department and the NYCDEP for processing permits to drill in NYC and Delaware, Dutchess,
Greene, Orange, Putnam, Rockland, Schoharie, Sullivan, Ulster and Westchester Counties. The
Department agreed to notify NYCDEP of any proposed well in the counties outside of NYC, so
that NYCDEP could determine if the proposed surface location is within a 1,000-foot wide
corridor surrounding a water tunnel or aqueduct. For any well that NYCDEP confirms is outside
the corridor, the Department processes the permit application following its normal procedures
without any further NYCDEP involvement to address subsurface infrastructure.
For any well within the 1,000-foot corridor, the Department notifies the applicant that the
proposed drilling is an unlisted action and may pose a significant threat to a municipal water
455

Smith et al. 2006.

Final SGEIS 2015, Page 7-68

 supply, necessitating a site-specific SEQRA finding. A negative declaration is only filed upon a
demonstration to NYCDEP’s satisfaction, through proposed drilling and deviation surveying
protocols, that it is feasible to drill at the proposed location with confidence that there would be
no impact to tunnels or aqueducts. NYCDEP is provided with a copy of each application for a
permit to drill, and any permit issued requires notification to NYCDEP prior to drilling
commencement. 456
Prior to reaching the above-described agreement with NYCDEP, Department staff had
considered applying the 660-foot protective buffer for underground mining operations that is
provided by the oil and gas regulations to NYC’s underground water tunnels and aqueducts. 457
However, those regulations require the underground mine operator (or, in this case, the tunnel
operator) to provide detailed location information regarding its underground property rights to
the Department. NYCDEP has not provided such maps for the subject counties, and the 1,000foot protective corridor suggested by NYCDEP was agreeable to Department staff because it is
more protective and is consistent with the 1992 GEIS criteria for requiring supplemental
environmental review for proposed well locations within 1,000 feet of municipal water supply
wells.
To mitigate impacts to NYC’s subsurface water supply infrastructure, Department staff would
continue to follow the above protocol for any proposed ECL 23 well, including any proposed gas
well, in the NYC Watershed. Except for the horizontal drilling and hydraulic fracturing that may
occur thousands of feet below the depth of any tunnel or aqueduct, the methods and technologies
for geothermal wells are the same as for natural gas wells.
7.1.11 Setbacks
Setbacks provide a margin of safety should the operational mitigation measures fail, and are
therefore a useful risk management tool. The NYSDOH recognizes separation distances, or
setbacks, as a crucial element of protecting water resources against contamination. 458 While the

456

Sanford, K.F., 2007.

457

6 NYCRR Part 552.4 Regulations: http://www.dec.ny.gov/regs/4465.html

458

http://www.health.state.ny.us/environmental/water/drinking/part5/append5b/fs1_additional_measures.htm, viewed 8/26/09.

Final SGEIS 2015, Page 7-69

 cited reference pertains specifically to drinking water wells, setbacks also mitigate potential
impacts to other water resources. As established in the 1992 GEIS with respect to municipal
water supply wells, setback distances can be used to help define the level of environmental
review and mitigation required for a specific proposed activity.
The proposed setback distances advanced herein reflect consideration of the following
information reviewed by Department staff in DMN and DOW:
•

The 1992 GEIS and its Findings;

•

NYSDOH’s required water well separation distances, set forth in Appendix 5-B of the
State Sanitary Code. 459 Although sites specifically related to natural gas development
and production are not explicitly listed among the potential contaminant sources
addressed by Appendix 5-B, NYSDOH staff assisted Department staff in identifying
listed sources which are analogous to activities related to high-volume hydraulic
fracturing;

•

Results and discussion provided by Alpha Environmental Consultants, Inc. (Alpha), to
NYSERDA regarding Alpha’s survey of regulations related to natural gas development
activities in Pennsylvania, Colorado, New Mexico, Wyoming , Texas (including the City
of Fort Worth), West Virginia, Louisiana, Ohio and Arkansas; 460

•

Results and discussion provided by Alpha to NYSERDA regarding Alpha’s review of the
rules and regulations pertaining to protection of water supplies in NYC’s Watershed. 461
Again, although natural gas development activities are not specifically addressed, and
this SGEIS does not cover high-volume hydraulic fracturing in the NYC or Syracuse
watersheds, Alpha identified activities which could be considered analogous to aspects of
high-volume hydraulic fracturing, including:
o Hazardous materials storage;
o Radioactive waste disposal;
o Storage of petroleum products;
o Impervious surfaces;

459

http://www.health.state.ny.us/environmental/water/drinking/part5/appendix5b.htm#table1, viewed 8/26/09.

460

Alpha, 2009, Tables 2.1 - 2.10.

461

Alpha, 2009, p. 94.

Final SGEIS 2015, Page 7-70

 o Stormwater pollution prevention plans;
o Miscellaneous point sources; and
o Solid waste disposal;
•

Local watershed rules and regulations for various jurisdictions within the Marcellus and
Utica Shale fairways. The counties searched included Broome, Chemung, Chenango,
Cortland, Delaware, Madison, Otsego, Steuben, Sullivan, Tioga and Tompkins. Local
watershed rules and regulations include setbacks from water supplies related to the
following activities which are potentially analogous to aspects of high-volume hydraulic
fracturing:
o Chlorides/salt storage;
o Burial of storage containers containing toxic chemicals or substances;
o Disposal of radioactive waste by burial in soil; and
o Direct discharge of polluted liquid to the ground or a water body.

7.1.11.1 Setbacks from Groundwater Resources
The following discussion pertains to the lateral distance, measured at the surface, to a water
supply or spring from the closest edge of the well pad.
The proposed well and well pad setbacks apply to well permit applications where the target
fracturing zone is either at least 2,000 feet deep or 1,000 feet below the underground water
supply. These wells would be drilled vertically through the aquifer, so that the location of the
aquifer penetration at each well corresponds to the well’s location on the ground surface. Well
permit applications where the target fracturing zone is less than either 2,000 feet deep or 1,000
feet below a known underground water supply are addressed in Section 7.1.5.
The EAF addendum for high-volume hydraulic fracturing would require evidence of diligent
efforts by the well operator to determine the existence of public or private water wells and
domestic-supply springs within half a mile (2,640 feet) of any proposed drilling location. The
Department proposes that this distance is adequate to ensure the 2,000-foot setback discussed
herein threshold for public water supply wells is properly applied. The operator would be
required to identify the wells and springs, and provide available information about their depth,
completed interval and use. Use information would include whether the well is public or private,

Final SGEIS 2015, Page 7-71

 community or non-community and of what type in terms of the facility or establishment it serves
if it is not a residential well. Information sources available to the operator include:
•

Direct contact with municipal officials;

•

Direct communication with property owners and tenants;

•

Communication with adjacent lessees;

•

EPA’s Safe Drinking Water Act Information System database, available at
http://oaspub.epa.gov/enviro/sdw_form_v2.create_page?state_abbr=NY; and

•

Department’s Water Well Information search wizard, available at
http://www.dec.ny.gov/cfmx/extapps/WaterWell/index.cfm?view=searchByCounty.

Upon receipt of a well permit application, Department staff would compare the operator’s well
list to internally available information and notify the operator of any discrepancies or additional
wells that are indicated within half a mile of the proposed well pad. The operator would be
required to amend its EAF Addendum accordingly.
The EAF Addendum for high-volume hydraulic fracturing would also require well operators to
identify any wells listed within the Department’s Oil & Gas Database 462 within a) the spacing
unit of the proposed well and b) within 1 mile (5,280 feet) of the proposed well location. For
each well identified, operators would be required to provide information regarding the distance
from the surface location of the existing well to the surface location of the proposed well, as well
as information regarding the quantity and type of any freshwater, brine, oil or gas encountered
during the drilling of the well, as recorded on the Department’s Well Drilling and Completion
Report.
This requirement would help to ensure that available information on nearby wells is considered
by the operator while designing the proposed wellbore. Additionally, this information can be

462

The Department’s Oil & Gas Database contains information on more than 35,000 oil, gas, storage, solution salt, stratigraphic,
and geothermal wells categorized under ECL 23 as Regulated Wells. The Oil & Gas database can be accessed on the
Department’s website at http://www.dec.ny.gov/cfmx/extapps/GasOil/.

Final SGEIS 2015, Page 7-72

 used by Department staff to review any necessary Department well files to ensure that the
operator’s proposed wellbore design is sufficient to protect ground water resources.
Public Water Supplies and Primary and Principal Aquifers
The Department’s 1992 GEIS concluded that issuance of a permit to drill less than 1,000 feet
from a municipal water supply well is considered "always significant" and requires a site-specific
SEIS to analyze groundwater hydrology, potential impacts and propose mitigation measures.
The 1992 GEIS also found that any proposed well location between 1,000 and 2,000 feet from a
municipal water supply well requires a site-specific assessment and SEQRA determination, and
may require a site-specific SEIS. The 1992 GEIS provides the discretion to apply the same
process to other public water supply wells.
For multi-well pads and high-volume hydraulic fracturing, the Department proposes that site
disturbance associated with such operations be prohibited within 2,000 feet of any public
(municipal or otherwise) water supply well, reservoirs, natural lake or man-made impoundments
(except engineered impoundments constructed for fresh water storage associated with fracturing
operations), and river or stream intake, in order to safeguard against significant adverse impacts
due to surface spills and leaks on the well pad that could impact the groundwater supply. As
noted, these setbacks would be measured from the closest edge of the well pad. The Department
will re-evaluate the necessity of this approach after three years of experience issuing permits in
areas outside of the 2,000-foot boundary.
In addition, as stated in sub-section 7.1.3, the Department proposes that for at least two years the
surface disturbance associated with high-volume hydraulic fracturing, including well pad and
associated road construction and operation, be prohibited within 500 feet of primary aquifers.
The Department further proposes that a site-specific SEQRA review be required for high-volume
hydraulic fracturing projects at any proposed well pad within or within 500 feet of a Principal
Aquifer. As noted, these setbacks would be measured from the closest edge of the well pad. The
Department will re-evaluate the necessity of this approach after two years of experience issuing
permits in areas outside of these restricted areas.

Final SGEIS 2015, Page 7-73

 Private Water Wells and Domestic Supply Springs
Chapter 6 describes potential impacts related to high-volume hydraulic fracturing that may
require enhanced protections for private water wells and domestic-supply springs. These
concerns stem more from handling greater fluid volumes on the surface than from downhole
activities. Fluid and chemicals could be present and handled anywhere on the well pad.
Setbacks, therefore, would be measured from the edge of the well pad.
As stated above, uncovered pits or open surface impoundments that could contain flowback
water are analogous to “chemical storage site(s) not protected from the elements,” which are
subject to a 300-foot separation distance from water wells under Appendix 5-B of the State
Sanitary Code. 463 Flowback water tanks and additive containers could be compared to “chemical
storage site(s) protected from the elements,” which require a 100-foot setback from water
wells. 464 Handling and mixing of hydraulic fracturing additives onsite is comparable to
“fertilizer and/or pesticide mixing and/or clean up areas,” which require a 150-foot distance from
water wells. 465
The Department proposes that it will not issue well permits for high-volume hydraulic fracturing
within 500 feet of a private water well or domestic-supply spring, unless waived by the
landowner.
7.1.11.2 Setbacks from Other Surface Water Resources
Application of setbacks from surface water resources prevents direct flow of the full, undiluted
volume of a spilled contaminant into a surface water body. Some amount of evaporation or soil
adsorption would occur in the event of a spill. Existing regulations prohibit the surface location
of an oil or gas well within 50 feet of any “public stream, river or other body of water.” 466 The
1992 GEIS proposed that this distance be increased to 150 feet and apply to the entire well site
instead of just the well itself.

463

http://www.health.state.ny.us/environmental/water/drinking/part5/appendix5b.htm#table1, viewed 8/26/09.

464

http://www.health.state.ny.us/environmental/water/drinking/part5/appendix5b.htm#table1, viewed 8/26/09.

465

http://www.health.state.ny.us/environmental/water/drinking/part5/appendix5b.htm#table1, viewed 8/26/09.

466

6 NYCRR §553.2.

Final SGEIS 2015, Page 7-74

 Significant surface spills at well pads which could contaminate surface water bodies, including
municipal supplies, are most likely to occur during activities which are closely observed and
controlled by personnel at the site. More people are present to monitor operations at the site
during high-volume hydraulic fracturing and flowback operations than at any other time period
in the life of the well pad. Therefore, any surface spills during these operations are likely to be
quickly detected and addressed rather than continue undetected for a lengthy time period. Other
factors which reduce the risk of surface water contamination resulting from well pad operations
include the following:
•

Required stormwater permit coverage, including a SWPPP;

•

Supplementary Permit Conditions for High-Volume Hydraulic Fracturing (see Appendix
10), which are proposed to include:
o Pit construction and liner specifications for well pad reserve pits;
o Requirement that closed-loop tank systems be used instead of reserve pits for any
horizontal drilling in the Marcellus Shale without an ARD- mitigation plan for
on-site burial of cuttings and for any drilling requiring cuttings to be disposed of
off-site;
o Requirement that tanks be used to contain flowback water on site;
o Appropriate secondary containment measures;
o Use of appropriate pressure-control procedures and equipment, including blowout prevention equipment that is tested on-site prior to drilling ahead and
fracturing equipment that is pressure tested with fresh water, mud or brine ahead
of pumping fracturing fluid; and
o Pre-fracturing pressure testing of casing from surface to top of treatment interval;

•

SGEIS setbacks related to potential surface activities measured from the edge of the well
pad instead of from the well. Municipal ownership of land surrounding municipal
surface water supplies may provide additional protection if the municipal-owned buffer
exceeds the setback distance. Other waterfront owners may decline to lease or offer only
non-surface entry leases [e.g., Otsego Lake owners around the lake include NYS
(Glimmerglass State Park), Clark Foundation, etc.]; and

•

The Department’s existing requirement for a Freshwater Wetlands Permit in wetland or
100-foot buffer zone.

Final SGEIS 2015, Page 7-75

 With respect to surface municipal supplies, the 1992 GEIS found that a 150-foot distance
between the wellsite and a surface water supply would provide adequate protection in the event
of an accidental spill. Required erosion and sedimentation control plans would address potential
impacts to nearby water bodies from ground disturbance. As discussed elsewhere in this
document, the Department has since determined that stormwater permit coverage is required for
disturbance greater than one acre.
Reservoir setbacks for comparable activities addressed in some local Watershed Rules and
Regulations establish various setbacks between 20 and 1,000 feet, but they generally pertain
either to actual burial of materials for disposal purposes or direct discharges to the ground or to
surface-water bodies. Burial or direct discharges to the ground of fracturing fluid, additive
chemicals or flowback water are not proposed and would not be approved. The only on-site
burial discussed in Chapter 5 of this document pertains to uncontaminated cuttings and pit-liners
associated with air or fresh-water drilling, as allowed under the 1992 GEIS. Direct discharges to
surface water bodies are regulated by the Department’s SPDES permitting program.
The required setbacks from surface water supplies in other states reviewed by Alpha vary
between 100 and 350 feet. 467 Colorado’s new Public Water System Protection rule requires a
variance for surface activity, including drilling, completion, production and storage, within 300
feet of a surface public water supply. 468
Many local Watershed Rules and Regulations require smaller setbacks from watercourses, as
specifically defined within the watershed, than from reservoirs.
Based on the above information and mitigating factors, the Department proposes that sitespecific SEQRA review be required for projects involving any proposed well pad where the
closest edge is located within 150 feet of a perennial or intermittent stream, storm drain, lake or
pond.

467

Alpha, 2009, pp. 41-45.

468

http://cogcc.state.co.us/RR_Docs_new/rules/300series.pdf, viewed 8/26/09.

Final SGEIS 2015, Page 7-76

 7.2

Protecting Floodplains

The Department proposes to require, through permit condition and/or regulation, that highvolume hydraulic fracturing not be permitted within 100-year floodplains in order to mitigate
significant adverse impacts from such operations if located within 100-year floodplains.
7.3

Protecting Freshwater Wetlands

Section 2.3.10 summarizes the State’s Freshwater Wetlands regulatory program, which addresses
activities within 100 feet of regulated wetlands. In addition, the federal government regulates
development activities in wetlands under Section 404 of the Clean Water Act.
The Department found in 1992 that issuance of a well permit when another Department permit is
necessary requires a site-specific SEQRA determination relative to the activities or resources
addressed by the other permit. In such instances, which include Freshwater Wetlands Permits,
the well permit is not issued until the SEQRA process is complete and the other permit is issued.
Mitigation measures for avoiding wetland impacts from well development activities are
described in Chapter 8 of the 1992 GEIS, which provides that well permits are issued for
locations in wetlands only when alternate locations are not available. Potential mitigation
measures are not limited to those discussed in the 1992 GEIS, but may include other alternatives
recommended by Fish, Wildlife and Marine Resources staff based on current techniques and
practices. Additional measures proposed in this Supplement include the following:

7.4

•

Requirement that, to the extent practical, fueling tanks not be placed within 500 feet of a
wetland (Section 7.1.3.1); and

•

Requirement for secondary containment consistent with the Department’s SPOTS 10 for
any fueling tank, regardless of size (Section 7.1.3.1).
Mitigating Potential Significant Impacts on Ecosystems and Wildlife

Fragmentation of habitat, potential transfer of invasive species, and potential impacts to
endangered and threatened species are identified in Chapter 6 as potential significant adverse
ecosystem and wildlife impacts specifically related to high-volume hydraulic fracturing that are
not addressed by the 1992 GEIS. The following text identifies mitigation measures to address

Final SGEIS 2015, Page 7-77

 significant impacts of fragmentation of habitat, potential transfer of invasive species, and
endangered and threatened species, as well as the use of certain State-owned land.
7.4.1

Protecting Terrestrial Habitats and Wildlife

Significant adverse impacts to habitats, wildlife, and biodiversity from site disturbance
associated with high-volume hydraulic fracturing in the area underlain by the Marcellus Shale in
New York will be unavoidable. In particular, the most significant potential wildlife impact
associated with high-volume hydraulic fracturing is fragmentation of rare interior forest and
grassland habitats and the resulting impacts to the species that depend on those habitats.
However, the following specific mitigation measures would prevent some impacts, minimize
others, and provide valuable information for better understanding the impacts of habitat
fragmentation on New York’s wildlife from multi-pad horizontal gas wells.
7.4.1.1 BMPs for Reducing Direct Impacts at Individual Well Sites
The Department proposes that the BMPs listed below be required mitigation measures to reduce
impacts associated with development of individual wellpads and appurtenances located in natural
habitats. During the permit review process, site-specific conditions would be considered to
determine applicability of each BMP and permit conditions included as appropriate.

469

•

Require multiple wells on single pads wherever possible;

•

Design well pads to fit the available landscape and minimize tree removal; 469

•

Require “soft” edges around forest clearings by either maintaining existing shrub areas,
planting shrubs, or allowing shrub areas to grow;

•

Limit mowing to one cutting per year or less after the construction phase of well pads is
completed. Mowing would not occur during the nesting season for grassland birds (April
23 – August 15);

•

When well pads are placed in large patches of grassland habitat (greater than 30 acres)
located within Grassland Focus Areas (as described in Section 7.4.1.2), construction and
drilling activities are prohibited during grassland bird nesting season (April 23 – August
15);

Environmental Law Clinic 2010.

Final SGEIS 2015, Page 7-78

 •

When well pads are placed in large patches of grassland habitat (greater than 30 acres)
located within Grassland Focus Areas, minimize impacts from dust during the grassland
bird nesting season (April 23 – August 15) by using dust palliatives and other appropriate
measures to reduce dust;

•

Require lighting used at wellpads to shine downward during bird migration periods (April
1 – June 1 and August 15 – October 15);

•

Limit the total area of disturbed ground, number of well pads, and especially, the linear
distance of roads, where practicable; 470

•

Design roads to lessen impacts (including two-track roads and oak mats in low-volume
areas 471) and limit canopy gaps; 472

•

Require roads, water lines, and well pads to follow existing road networks and be located
as close as possible to existing road networks to minimize disturbance;

•

Gate single-purpose roads to limit human disturbance; and 473

•

Require reclamation of non-productive, plugged, and abandoned wells, well pads, roads
and other infrastructure areas. Reclamation would be conducted as soon as practicable
and would include interim steps to establish appropriate vegetation during substantial
periods of inactivity. Native tree, shrub, and grass species should be used in appropriate
habitats.

7.4.1.2 Reducing Indirect and Cumulative Impacts of Habitat Fragmentation
The best opportunity for reducing indirect and cumulative impacts is to preserve existing blocks
of the critically important grassland and interior forest habitats identified in Grassland and Forest
Focus Areas (Figure 7.2) by avoiding site disturbance (wellpad construction) in those areas.
Grassland Focus Areas represent those areas within the State that are most important for
grassland nesting birds. Forest Focus Areas represent those areas in the State that contain large
blocks of forest interior habitats. Development in these areas would be conditioned as outlined
below to mitigate impacts on wildlife from habitat fragmentation. The following measures are

470

New Mexico Dept Game & Fish, 2007.

471

Weller et al., 2002.

472

NYSDEC, Strategic Plan for State Forest Management, 2010.

473

New Mexico Dept Game & Fish, 2007.

Final SGEIS 2015, Page 7-79

 considered necessary to mitigate the cumulative impacts of habitat fragmentation for these
critically important habitat types while not strictly prohibiting development.
Figure 7.2 - Key Habitat Areas for Protecting Grassland and Interior Forest Habitats
(Updated August 2011)

Grassland Focus Areas
Grassland Focus Areas depicted in Figure 7.2 were determined by a group of grassland bird
experts, including Department staff with input from outside experts representing federal agencies
and academia. 474 The focus areas were derived from Breeding Bird Atlas (BBA) data from
2002-2004; 475 they were further modified by expert knowledge, and then followed up with a 2year field verification study before being finalized. They represent areas of New York State that
contain the most important grassland habitat mosaics.
474

See Morgan and Burger 2008.

475

McGowan and Corwin 2008 or visit DEC’s website (http://www/dec/ny.gov/animals/7312.html).

Final SGEIS 2015, Page 7-80

 The 2006 BBA provided the core dataset for delineating Grassland Focus Areas. All atlas blocks
with a high richness of breeding grassland birds, as well as contiguous blocks also supporting
grassland species, were included in the focus areas. The target for the focus areas was to
“capture” or include at least 50% of the BBA blocks where each of the grassland species was
found to be breeding across the state. The focus areas were able to reach that target for all but
the most widespread species. Although the BBA does not provide estimates of abundance or
densities, one of the criteria for inclusion in a focus area was contiguity with adjacent blocks
containing grassland birds; analyses indicate that such blocks contain significantly higher
abundances of the target species than isolated blocks.
Extensive field surveys were conducted in 2005 and 2006 throughout the focus areas. These
surveys collected distribution and abundance data to confirm that the analysis of the breedingbird data reflected actual conditions in the field (Table 7.4). A total of 487 different habitat
patches were surveyed statewide. In some cases, focus area boundaries were adjusted based on
field survey data. The overall process resulted in the identification of 8 focus areas that support
New York’s grassland breeding birds, 4 of which occur in the area underlain by the Marcellus
Shale.
Table 7.4 - Principal Species Found in the Four Grassland Focus Areas within the area
underlain by the Marcellus Shale in New York (New July 2011)

Grassland Focus Area
Western Area
Southern Area
Middle Northern Area
Eastern Area
*Wintering only

Species
Upland sandpiper, vesper sparrow, horned leak, savannah sparrow, shorteared owl*
Northern Harrier, grasshopper sparrow, Eastern meadowlark, savannah
sparrow
Vesper sparrow, grasshopper sparrow, horned lark, savannah sparrow,
short-eared owl*
Northern harrier, short-eared owl*

Specific Mitigation Measures to Reduce Impacts to Grasslands
In order to mitigate impacts from fragmentation of grassland habitats, the Department proposes
to require, through the permit process and/or by regulation, that surface disturbance associated
with high-volume hydraulic fracturing activities in contiguous grassland habitat patches of 30
acres or more within Grassland Focus Areas would be based on the findings of a site-specific

Final SGEIS 2015, Page 7-81

 ecological assessment and implementation of mitigation measures identified as part of such
ecological assessment, in addition to the BMPs required for all disturbances in grassland areas
that are identified in Section 7.4.1.1. This ecological assessment would include pre-disturbance
biological studies and an evaluation of potential impacts on grassland birds from the project.
Pre-disturbance studies would be required to be conducted by qualified biologists and would be
required to include a compilation of historical information on grassland bird use of the area and a
minimum of one year of field surveys at the site to determine the current extent, if any, of
grassland bird use of the site. Should the Department decide to issue a permit after reviewing the
ecological assessment, the applicant would be required to implement supplemental mitigation
measures by locating the site disturbance as close to the edge of the grassland patch as feasible
and proposing additional mitigation measures (e.g., conservation easements, habitat
enhancement). In addition, enhanced monitoring of grassland birds during the construction
phase of the project and for a minimum period of two years following active high-volume
hydraulic fracturing activities (i.e., following well completion) would be required.
Explanation for 30 Acre Threshold: Many of New York’s rarest bird species that rely on
grasslands are affected by the size of a grassland patch. Several species of conservation concern
rely on larger-sized grassland patches and show strong correlation to a minimum patch size if
they are to be present and to successfully breed. Minimum patch sizes will vary by species, and
by surrounding land uses, but a minimum patch size of 30-100 acres is warranted to protect a
wide assemblage of grassland-dependent species. 476 Although a larger patch size is necessary
for raptor species, a minimum 30 acres of grassland is needed to provide enough suitable habitat
for a diversity of grassland species. Grasslands less than 30 acres in size are of less importance
since they do not provide habitat for many of the rarer grassland bird species. 477 The Grassland
Focus Areas cover about 22% of the area underlain by the Marcellus Shale. However, the actual
impacts on Marcellus development would affect less area for two reasons. First, only those
portions of the Grassland Focus Areas meeting the minimum patch size requirement would be
subject to the aforementioned additional restrictions on surface disturbance. Second, even in

476

USFWS n.d., Sample and Mossman 1997, Mitchell et al. 2000.

477

USFWS n.d., Sample and Mossman 1997, Mitchell et al. 2000.

Final SGEIS 2015, Page 7-82

 areas where surface disturbance should be avoided, gas deposits could be accessed horizontally
from adjacent areas where the restriction does not apply.
Forest Focus Areas
Forest Focus Areas depicted in Figure 7.2 were based on Forest Matrix Blocks developed by The
Nature Conservancy (TNC). 478 TNC’s goal in developing Forest Matrix Blocks was to estimate
viability and resilience of forests and determine those areas where forest structure, biological
processes, and biological composition are most intact. Resilient forest ecosystems can absorb,
buffer, and recover from the full range of natural disturbances. TNC used three characteristics in
developing their Forest Matrix Blocks: size, condition, and landscape context. Size was based
on the key factors of the area necessary to absorb natural disturbance and species area
requirements (see Figure 7.3).
•

Natural disturbances and minimum dynamic area: Eastern forests are subject to
hurricanes, tornadoes, fires, ice storms, downbursts, and outbreaks of insects or disease.
While most of these disturbances are small and recovery is fast, damage from larger
catastrophic events may last for decades. Resilient forest ecosystems can absorb, buffer,
and recover from the full range of natural disturbances. The effects of catastrophic
events are typically spread across a landscape in an uneven way. Patches of severe
damage are embedded in larger areas of moderate or light disturbance. Using historical
records, vegetation studies, air photo analysis, and expert interviews, TNC scientists
determined the size and extent of patches of severe damage for each disturbance type
expected over one century. Historic patterns in the Northeast suggest that an area of
approximately four times the size of the largest severe damage patch is necessary for a
particular matrix block to remain adequately resilient.
o Breeding territories and area sensitive species: Forest ecosystems must also be
big enough to support characteristic interior species, including birds, mammals,
herptiles, and insects. Many species establish and defend territories during
breeding season, from which they obtain resources to raise their young. Twentyfive times the average size of a territory, together with information on other
minimum area restrictions for that species, may be used as an estimate of the
space needed for a small population. This reflects a rule of thumb developed for
zoo populations on the number of breeding individuals required to conserve
genetic diversity over generations (Figure 7.3); 479

478

TNC, 2003.

479

TNC, 2003.

Final SGEIS 2015, Page 7-83

 Figure 7.3 - Scaling Factors for Matrix Forest Systems in the
High Allegheny Ecoregion 480 (New July 2011)

480

•

Condition was based on the key factors of structural legacies, fragmenting features, and
biotic composition. TNC’s criteria for viable forest condition were: low road density
with few or no bisecting roads; large regions of core interior habitat with no obvious
fragmenting feature; evidence of the presence of forest breeding species; regions of old
growth forest; mixed age forests with large amounts of structure or forests with no
agricultural history; no obvious loss of native dominants; mid-sized or wide-ranging
carnivores; composition not dominated by weedy or exotic species; no disproportional
amount of damage by pathogens; and minimal spraying or salvage cutting by current
owners. Matrix blocks are bounded by fragmenting features such as roads, railroads,
major utility lines, and major shorelines. The bounding block features were chosen due
to their ecological impact on biodiversity in terms of fragmentation, dispersion, edgeeffects, and invasive species; and

•

Landscape context was based on the key factors of edge-effect buffers, wide-ranging
species, gradients, and structural retention. In evaluating landscape context, TNC
evaluated and recorded information on the surrounding landscape context for all matrix
communities. TNC generally considered areas embedded in much larger areas of forest

From TNC, 2004.

Final SGEIS 2015, Page 7-84

 to be more viable than those embedded in a sea of residential development and
agriculture. However, no area was rejected solely on the basis of its landscape context
because the matrix forests in many of the poorer landscape contexts currently serve as
critical habitat for forest interior species and may be the best example of the forest
ecosystem type. Thus, this criterion was used to reject or accept some examples that
were initially of questionable size and condition.
TNC applied the territory size and disturbance factors to all of the ecoregions in the Northeast,
and tailored minimum size thresholds for matrix blocks to each ecoregion’s forested extent,
ecology, and natural disturbance history. The area underlain by the Marcellus Shale in New
York is located in the High Allegheny Plateau (HAL) ecoregion (minimum block size of 15,000
acres), and contains 26 forest matrix blocks ranging in size from 17,000 acres to 176,000 acres,
totaling 1.3 million acres. These matrix blocks are comprised of several dominant forest
community types, including Northern hardwoods, maple-birch-beech forest, oak hickory forest
and Allegheny oak forests. 481
Specific Mitigation Measures to Reduce Impacts to Forests
In order to mitigate impacts from fragmentation of forest interior habitats, the Department
proposes to require, through the permit process and/or by regulation, that surface disturbance
associated with high-volume hydraulic fracturing activities in contiguous forest patches of 150
acres or more within Forest Focus Areas would be based on the findings of a site-specific
ecological assessment and implementation of mitigation measures identified as part of such
ecological assessment, in addition to the BMPs required for all disturbances in forested areas that
are identified in Section 7.4.1.1. The ecological assessment would include pre-disturbance
biological studies and an evaluation of potential impacts on forest interior birds from the project.
Pre-disturbance studies would be required to be conducted by qualified biologists and would be
required to include a compilation of historical information on forest interior bird use of the area
and a minimum of one year of field surveys at the site to determine the current extent, if any, of
forest interior bird use of the site. Should the Department decide to issue a permit after
reviewing the ecological assessment, the applicant would be required to implement supplemental
mitigation measures by locating the site disturbance as close to the edge of the forest patch as
feasible and proposing additional mitigation measures (e.g., conservation easements, habitat
481

TNC, 2002.

Final SGEIS 2015, Page 7-85

 enhancement). In addition, enhanced monitoring of forest interior birds during the construction
phase of the project and for a minimum period of two years following the end of high-volume
hydraulic fracturing activities (i.e., following date of well completion) would be required.
Explanation for 150-Acre Threshold: Fragmentation of large forest blocks can negatively
affect breeding birds that require interior forest habitat for successful reproduction.
Fragmentation due to human development of forest openings and structures that are relatively
permanent will fragment habitats, create more edge, and reduce breeding success. Humaninduced openings can influence breeding bird productivity several hundred feet from the edge of
the forest through increased predation and increased nest parasitism. There is a wide diversity of
bird species that rely on forest interior habitats to breed. As such, patch size requirements can
vary widely by species, and can be influenced by surrounding land cover as well as the amount
of forest cover on the landscape. Previous research on forest interior birds suggests that the
minimum forest patch size needed to support forest breeding species ranges between 100 and
500 acres. 482 A 100-acre patch size is the minimum that would probably support a relatively
diverse assemblage of forest breeding birds. Additional research indicates that the negative
impacts along a forest edge extend between 200-500 feet into the forest. 483 If we assume a 100acre forest patch with a 300-foot forested buffer, the minimum patch size for forest interior birds
is approximately 150 acres of contiguous forest. Patches less than 150 acres are not of optimum
value to forest interior birds. The Forest Focus Areas outside the Catskill Forest Preserve cover
about 6% of the area underlain by the Marcellus Shale. However, the actual impacts on
Marcellus development would affect less area for two reasons. First, only those portions of the
Forest Focus Areas meeting the minimum patch size requirement would be subject to the
aforementioned restrictions on surface disturbance. Second, even in areas where surface
disturbance should be avoided, gas deposits could be accessed horizontally from adjacent areas.
Given the horizontal reach of the wells, only about 2% of the subsurface areas would not be
accessible.

482

Roberts and Norment 1999, Hoover et al. 1995, Robbins 1979.

483

Rosenburg et al. 1999, Robinson et al. 1995.

Final SGEIS 2015, Page 7-86

 7.4.1.3 Monitoring Changes in Habitat
The following mitigation measures are necessary to better understand and evaluate the impacts
of habitat fragmentation on New York’s wildlife from multi-pad horizontal gas wells and would
be required as permit conditions for any applications seeking site disturbance in 150-acre
portions of Forest Focus Areas and 30-acre portions of Grassland Focus Areas:
•

Conduct pre-development surveys of plants and animals to establish baseline reference
data for future comparison; 484

•

Monitor the effects of disturbance as active development proceeds and for a minimum of
two years following well completion. Practice adaptive management as previously
unknown effects are documented; and 485

•

Conduct test plot studies to develop more effective revegetation practices. Variables
might include slope, aspect, soil preparation, soil amendments, irrigation, and seed mix
composition. 486

With the aforementioned measures in place, the significant adverse impacts on habitat from highvolume hydraulic fracturing would be partially addressed.
7.4.2

Invasive Species

Chapter 26 of the Laws of New York, 2008, amended the ECL to create the New York Invasive
Species Council 487,488 and define the Department’s authority regarding control of invasive
species in New York. The Council, co-lead by the Department and the Department of
Agriculture and Markets (DAM), comprises the Department of Transportation (DOT), the Office
of Parks, Recreation and Historic Preservation (OPRHP), the State Education Department (SED),
the Department of State (DOS), the Thruway Authority, the New York State Canal Corporation,
and the Adirondack Park Agency (APA).

484

New Mexico Dept Game & Fish, 2007.

485

New Mexico Dept Game & Fish, 2007.

486

New Mexico Dept Game & Fish, 2007.

487

ECL § 9-1707.

488

The New York Invasive Species Council supplanted the Invasive Species Task Force that was established in 2003 to explore
the invasive species issue and provide recommendations to the Governor and Legislature by November 2005. The task
force’s findings and recommendations are summarized in the “Final Report of the New York State Invasive Species Task
Force,” which is available at http://www.dec.ny.gov/docs/wildlife_pdf/istfreport1105.pdf.

Final SGEIS 2015, Page 7-87

 The role of the Council includes identifying actions to prevent the introduction of invasive
species, detect and respond rapidly to control populations of invasive species, monitor invasive
species populations, provide for the restoration of native species and habitats that have been
invaded, and promote public education on invasive species. 489
Additionally, a comprehensive management plan is being developed which will address all taxa
of invasive species in New York, with an emphasis on prevention, early detection and rapid
response, and opportunities for control and restoration to prevent future damage. In accordance
with ECL §9-1705(5)(c), the plan will incorporate the approved New York State Aquatic
Nuisance Species Management Plan, the Lake Champlain Basin Aquatic Nuisance Species
Management Plan, and the Adirondack Park Aquatic Nuisance Species Management Plan.
The Council also prepared a report that described a regulatory system for non-native species 490
and included a four-tier system for preventing the importation and/or release of non-native
animal and plant species. The system contains proposed lists of prohibited, regulated and
unregulated species, and a procedure for the review of any non-native species that is not on the
aforementioned lists before the use, distribution or release of such non-native species.
ECL §9-1709(2)(d) authorizes the Department to prohibit and actively eliminate invasive species
at project sites regulated by the State. This responsibility falls within the purview of the
Department’s Division of Fish, Wildlife and Marine Resources.
7.4.2.1 Terrestrial
In order to mitigate the potential transfer of terrestrial invasive species from project locations
associated with high-volume hydraulic fracturing, including well pads, access roads, and
engineered impoundments for fresh water, the Department proposes that well operators be
required to conduct all activities in accordance with the best management practices below. This
would be reflected by a permit condition (see Appendix 10) requiring the preparation and

489

ECL §9-1705(5)(b).

490

Final report – A regulatory system for non-native species. New York Invasive Species Council. 10 June 2010.
http://www.dec.ny.gov/docs/lands_forests_pdf/invasive062910.pdf.

Final SGEIS 2015, Page 7-88

 implementation of an invasive species mitigation plan that would be included on all well permits
where high-volume hydraulic fracturing is proposed.
Survey for the Presence of Invasive Species
Invasive species control is two-fold in that it involves both limiting the spread of existing
invasive species and limiting the introduction of new invasive species. In order to accomplish
these objectives, it is necessary to identify the types of invasive species which are present at a
project site as well as map the locations and extent of any established population.
Therefore, the Department proposes to require that well operators submit, with the EAF
Addendum for a single well or the first well proposed on a multi-well pad, a comprehensive
survey of the entire project site, documenting the presence and identity of any invasive plant
species. The survey should be conducted by an environmental consultant familiar with the
invasive species in New York. This survey would establish a baseline measure of percent aerial
coverage and, at a minimum, would be required to include the plant species identified on the
Interim List of Invasive Plant Species in New York State. 491 A map (1:24,000) showing all
occurrences of invasive species within the project site would also be required to be included with
the survey as part of the EAF Addendum.
Field notes, photographs and GPS handheld equipment should be utilized in documenting any
occurrences of invasive species and all such occurrences would be required to be clearly
identified in the field with signs, flagging, and/or stakes prior to any ground disturbance. If the
invasive species survey submitted with the EAF Addendum shows the presence of specific
invasive species, consultation with the Department may be required prior to any ground
disturbance.
Preventing the Spread of Invasive Species
•

491

Prior to any ground disturbance, any invasive plant species encountered at the site should
be stripped and removed. Cut plant materials, including roots and rhizomes, should be
placed in heavy duty, 3-mil or thicker, black, contractor-quality plastic cleanup bags.
The bags should then be securely tied and transported from the site to a proper disposal

This list appears in Tables 6.3 and 6.4.

Final SGEIS 2015, Page 7-89

 facility in a truck with a topper or cap, in order to prevent the spread or loss of the plant
material during transport;
•

Cut invasive plant species materials should not be disposed of into native cover areas;

•

Machinery and equipment, including hand tools, used in invasive species affected areas
would be required to be pressure-washed and cleaned with water (no soaps or chemicals)
prior to leaving the invasive species affected area to prevent the spread of seeds, roots or
other viable plant parts. This includes all machinery, equipment and tools used in the
stripping, removal, and disposal of invasive plant species;

•

Equipment or machinery should not be washed in any waterbody or wetland, and run-off
resulting from washing operations should not be allowed to directly enter any water
bodies or wetlands. Appropriate erosion control measures would be required be
employed;

•

Loose plant and soil material that has been removed from clothing, boots and equipment,
or generated from cleaning operations would either be a) rendered incapable of any
growth or reproduction or b) appropriately disposed of off-site. If disposed of off-site,
the plant and soil material would be required to be transported in a secure manner;
Preventing New Invasive Species Introductions

•

All machinery and equipment to be used in the construction of the proposed project
location, including but not limited to trucks, tractors, excavators, and any hand tools,
would be required to be washed with high pressure hoses and hot water prior to delivery
to the project site to insure that they are free of invasive species;

•

All fill and/or construction material (e.g. gravel, crushed stone, top soil, etc.) from offsite
locations should be inspected for invasive species and should only be utilized if no
invasive species are found growing in or adjacent to the fill/material source; and

•

Only certified weed-free straw should be utilized for erosion control.
Restoration and Preservation of Native Vegetation

•

Native vegetation should be reestablished and weed-free mulch should be used on bare
surfaces to minimize weed germination;

•

Only native (non-invasive) seeds or plant material should be used for re-vegetation
during site reclamation. An appropriate native seed mixture should be selected based on
pre-disturbance surveys;

•

All seed should be from local sources to the extent possible and should be applied at the
recommended rates to ensure adequate vegetative cover to prevent the colonization of
invasive species;

Final SGEIS 2015, Page 7-90

 •

As part of site reclamation, re-vegetation should occur as quickly as possible at each
project site;

•

Any top soil brought to the site for reclamation activities should be obtained from a
source known to be free of invasive species; and

•

The site should be monitored for new occurrences of invasive plant species following
partial reclamation. If new occurrences are observed, they should be treated with
appropriate physical or chemical controls.
General

•

Implementation of the above practices would be required to be in accordance with a sitespecific and species-specific invasive species mitigation plan that includes seasonally
appropriate specific physical and chemical control methods (e.g., digging to remove all
roots, cutting to the ground, applying herbicides to specific plant parts such as stems or
foliage, etc.). The invasive species mitigation plan would be required to be available to
the Department upon request and available on-site for a Department inspector’s review at
any time that related activities are occurring;

•

The well operator should assign an environmental monitor to check that all trucks,
machinery and equipment have been washed prior to entry and exit of the project site and
that there is no dirt or plant material clinging to the wheels, tracks, or undercarriage of the
vehicles or equipment; and

•

Any new invasive species occurrences found at the project location should be removed
and disposed of appropriately.

7.4.2.2 Aquatic 492
It is beneficial to the operators to implement water conservation and recycling practices because
of the potential difficulties obtaining the large volumes of water needed for hydraulic fracturing.
Most or all operators will recycle or reuse flowback water to reduce the need for fresh water.
It is possible that some unused fresh water may remain in a surface impoundment after drilling
and hydraulic fracturing is completed. This is likely in circumstances where operators build
large centralized surface impoundments to hold water for all drilling and hydraulic fracturing
operations within a several mile radius. Unused water may be transported by truck or pipeline
and discharged into tanks or surface impoundments for use at another drilling location. It also is
possible that unused water could be transported and discharged at its point of origin with proper
492

Alpha, 2009, p. 3-6 et seq., and supplemented by DEC.

Final SGEIS 2015, Page 7-91

 approval. Either of these options avoids the transfer of invasive species into a new habitat or
watershed. Precautions would be required to be implemented, especially when water is stored in
surface impoundments, to preclude the transfer of invasive species into new habitats or
watersheds.
Unused fresh water also could be transported to a wastewater treatment facility for processing,
although this is considered unlikely given the anticipated demand for water in the drilling and
hydraulic fracturing process. As detailed in Section 7.1.8.1, flowback water cannot be taken to a
publicly owned treatment works without the Department’s approval. Standard treatment
processes at waste water treatment plants, such as dissolved air flotation, have been shown to
successfully remove biological particles and sediments that might harbor invasive species;
however, the safest method to avoid transfer of invasive species is to not transfer water from one
water body to another.
Regulatory protections exist to reduce the potential for the transfer of aquatic invasive species.
Regulations and policies of SRBC and DRBC both address the transfer, reuse and discharge of
water and SRBC requires appropriate treatment to prevent the spread of aquatic invasive species.
Table 7.5 is a matrix of SRBC and DRBC regulations pertaining to transfer of invasive species.
The regulations are identified that specifically address the transport of invasive or nuisance
aquatic species. Other regulations in Table 7.5 do not specifically relate to invasive species, but
the required actions and policies nonetheless may have the effect of reducing or eliminating their
transport.
The SRBC’s policy is to discourage the diversion or transfer of water from the basin with the
objective of conserving and protecting water resources. Additionally, the SRBC specifically
requires that “any unused (surplus) water shall not be discharged back to the waters of the basin
without appropriate controls and treatment to prevent the spread of aquatic nuisance species.”

Final SGEIS 2015, Page 7-92

 TABLE 7.5

Summary of Regulations Pertaining to Transfer of Invasive Species


Agency

Document

Article

Regulation Summary

SRBC


18 CFR Part 806.22,f,8

All flowback and produced fluids, including brines, must be treated and disposed of in accordance with applicable state and federal law.

SRBC


Federal Register, Vol 73, No. 247, Rules
and Regulations
Regulation of Projects

SRBC


Regulation of Projects

18 CFR Part 801.3,b

The SRBC will require evidence that proposed interbasin transfers of water will not jeopardize, impair or limit the efficient development and management of the SRBC’s water 

resources, or any aspects of these resources for in-basin use, or have a significant unfavorable impact on the resources of the basin and the receiving waters of the 

Chesapeake Bay.


SRBC


Regulation of Projects

18 CFR Part 801.3,c,1

Allocations, diversions, or withdrawals of water must be based on (1) the rights of landholders in any watershed to use the stream water in reasonable amounts and to have 

the stream flow not unreasonably diminished in quality or quantity by upstream use or diversion of water; and (2) on the maintenance of the historic seasional variations of the 

flows into Chesapeake Bay.


SRBC

Regulation of Projects

18 CFR Part 806.23,2

The SRBC may deny or limit an approval if a withdrawal may cause significant adverse impacts to SRB water, including: lowering of groundwater or stream flow levels; 

rendering competing supplies unreliable; affecting other water uses; causing water quality degradation that may be injurious to any existing or potential water use; affecting 

any living resources or their habitat; causing permanent loss of aquifer storage capacity; or affecting low flow of perennial or intermittent streams.


SRBC

Federal Register, Vol 73, No. 247, Rules
and Regulations
Standard Docket Conditions Contained In
Gas Well Consumptive Water Use
Regulation of Projects

18 CFR Part 806.22,f,6

Flowback fluids or produced brines used for hydrofracturing must be separately accounted for, but will not be included in the daily use volume or be subject to the mitigation 

requirements of § 806.22 [b].

Unused water shall not be discharged back to the SRB waters without appropriate controls and treatment to prevent the spread of aquatic nuisance species.


SRBC
SRBC

18 CFR Part 806.24,b,3,c For diversions into the SRB, must provide: (1) the source, amount, and location of the diverted water,and (2) the water quality classification, if any, of the SRBC discharge 

stream and the discharge location(s). (3) All applicable withdrawal or discharge permits or approvals must have been applied for or received, and must prove that the diversion

will not result in water quality degradation that may be injurious to any existing or potential ground or surface water use.


* Item 10.

18 CFR Part 806.25,b, 4 Industrial water users must evaluate and utilize applicable recirculation and reuse practices.


SRBC

Standard Docket Conditions Contained In
Gas Well Surface Water Dockets

Item 4. (Not contained in Within ninety (90) days of this approval, the project sponsor shall submit a plan of study and a schedule for completion to conduct a survey and evaluate the potential impacts 

all approvals)
on the rare and protected freshwater mussels located in the Susquehanna River within the area of the withdrawal.


SRBC

Standard Docket Conditions Contained In
Gas Well Surface Water Dockets

Item 5. (Not contained in This approval does not become effective until the SRBC is satisfied that the withdrawal has no adverse impacts to the rare and protected freshwater mussel species of 

all approvals)
concern.


SRBC

Standard Docket Conditions Contained In
Gas Well Surface Water Dockets

DRBC

Water Code 18 CFR Part 410

2.20.2

The underground water-bearing formations of the DRB, their waters, storage capacity, recharge areas, and ability to convey water shall be preserved and protected.


DRBC

Water Code 18 CFR Part 410

2.20.3

Projects that withdraw underground waters must reasonably safeguard the present and future public interest in the affected water resources.


DRBC

Water Code 18 CFR Part 410

2.20.4

Withdrawals from DRB ground water are limited to the maximum draft of all withdrawals from a ground water basin, aquifer, or aquifer system that can be sustained without 

rendering supplies unreliable, causing long-term progressive lowering of ground water levels, water quality degradation, permanent loss of storage capacity, or substantial 

impact on low flows of perennial streams, unless the DRBC decides a withdrawal is in the public interest. In confined coastal plain aquifers, the DRBC may apply aquifer 

management levels, if any, established by a signatory state in determining compliance with criteria relating to "longterm progressive lowering of ground water levels."


DRBC

Water Code 18 CFR Part 410

2.20.5

The principal natural recharge areas of the DRB shall be protected from unreasonable interference. No recharge sources (ground or surface water) shall be polluted based on 

water quality standards promulgated by the DRBC or any of the signatory parties.


DRBC

Water Code 18 CFR Part 410

2.20.6

DRBC

Water Code 18 CFR Part 410

2.10.1

The DRB ground water resources shall be used, conserved, developed, managed, and controlled for the needs of present and future generations, so interference, impairment, 

penetration, or artificial recharge shall be subject to review and evaluation under the Compact.

The DRBC may acquire, operate and control projects and facilities for the storage and release of waters, for the regulation of flows and DRB surface and ground water 

supplies, for the protection of public health, stream quality control, economic development, improvement of fisheries, recreation, pollution dilution and abatement, the 

prevention of undue salinity and other purposes. No signatory party may permit any augmentation of flow to be diminished by the diversion of any DRB water during any 

period in which waters are being released from storage by the DRBC for the purpose of augmenting such flow, except in cases where such diversion is authorized by this 

compact, or by the DRBC pursuant to, or by the order of a court of competent jurisdiction.


Page 1 of 3

* Item 10.

Must report the method of water transport (tanker truck or pipeline) and show that all water withdrawn from surface water sources is transported, stored, injected into a well, or 

discharged with appropriate controls and treatment to prevent the spread of aquatic nuisance species.


Final SGEIS 2015, Page
7-93
Z:\projects\2009\09100-09120\09104
- Gas Well Permitting GEIS\Alpha Project Report\Tables\Table 3.1 Invasive Species\Invasive Species Prevention Reg

 DRAFT
Agency
DRBC

Document
Water Code 18 CFR Part 410

Article 
2.30.2 

Regulation Summary
The waters of the DRB are limited in quantity and to drought. The exportation of DRB water is discouraged. The DRB waters have limited assimilative capacity to accept
substances without significant impacts. Wastewater import that would significantly reduce the assimilative capacity of the receiving DRB stream is discouraged and should be
reserved for users within the DRB.

DRBC

Water Code 18 CFR Part 410

2.30.3 

Consideration of the importation or exportation of water will be conducted pursuant to this policy and include assessments of the water resource and economic impacts of the
project and of all alternatives to any water exportation or wastewater importation project.

DRBC

Water Code 18 CFR Part 410

2.30.4 

The DRBC has jurisdiction over exportations and importations of water (Section 3.8 of the Compact, and inclusion within the Comprehensive Plan) as specified in the
Administrative Manual - Rules of Practice and Procedure. The applicant shall address those of the items listed below as directed by the DRBC: A. efforts to develop or use
and conserve outside resources; B. water resource, economic, and social impacts of each alternative, including the "no project" alternative; D. amount, timing and duration of
the proposed transfer and its relationship to DRB hydrologic conditions, and impact on instream uses and downstream waste assimilation capacity; E. benefits to the DRB as a
result of the proposed transfer; F. volume of the transfer and its relationship to other specified actions or Resolutions by the DRBC; G. the relationship of the transfer volume
to all other diversions; H. other significant benefits or impairments to the DRB as a result of the proposed transfer.

DRBC

Water Code 18 CFR Part 410

2.30.6 

The DRBC gives no credit toward meeting wastewater treatment requirements for wastewater imported into the Delaware Basin. Wasteload allocations assigned to
dischargers will not include loadings attributable to wastewater importation.

DRBC

Water Code 18 CFR Part 410

2.200.1 

DRB water quality will be maintained in a safe and satisfactory condition for...wildlife, fish and other aquatic life.

DRBC

Water Code 18 CFR Part 410

2.350.2 

The DRBC will preserve and protect wetlands by: A. minimizing adverse alterations in the quantity and quality of the underlying soils and natural flow of waters that nourish
wetlands; B. safeguarding against adverse draining, dredging or filling practices, liquid or solid waste management practices, and siltation; C. preventing the excessive
addition of pesticides, salts or toxic materials arising from non-point source wastes; and D. preventing destructive construction activities.

DRBC

Water Code 18 CFR Part 410

2.400.2 

DRBC

Water Code 18 CFR Part 410

3.10.3,A,1 

The drought of record, which occurred in the period 1961-1967, shall be the basis for planning and development of facilities and programs for control of salinity in the
Delaware Estuary.
The DRBC maintains the quality of interstate waters, where existing quality is better than the established stream quality objectives, unless such change is justifiable as a result
of necessary economic or social development or to improve significantly another body of water. The DRBC will require the highest degree of waste treatment practicable. No
change will be considered which would be injurious to any designated present or future use.

DRBC

Water Code 18 CFR Part 410

3.10.3,A,2,b 

There will be no measurable change in water quality except towards natural conditions in water that has high scenic, recreational, ecological, and/or water supply values.
Waters with exceptional values may be classified as either Outstanding Basin Waters (OBW) or Significant Resource Waters (SRW). OBW shall be maintained at their
existing water quality. 2) SRW must not be degraded below existing water quality, although localized degradation of water quality may be allowed for initial dilution if the
DRBC, after consultation with the state NPDES permitting agency, finds that the public interest warrants these changes, unless a mixing zone is allowed and then to the exten
of the mixing zone designated as set forth in this section. If degradation of water quality is allowed for initial dilution purposes, the DRBC, will designate mixing zones for each
point source and require the highest possible point source treatment levels necessary to limit the size and extent of the mixing zones. The dimensions of the mixing zone will
be based upon an evaluation of (a) site specific conditions, including channel characteristics; (b) the cost and feasibility of treatment technologies; and (c) the design of the dis

DRBC

Water Code 18 CFR Part 410

3.10.3,A,2,c 

1) Direct discharges of wastewater to Special Protection Waters (SPW) are discouraged. New wastewater treatment facilities and substantial alterations to existing facilities
that discharge directly to SPW may be approved after the applicant has evaluated all nondischarge/ load reduction alternatives and is unable to implement these alternatives
because of technical and/or financial infeasibility. 2) New wastewater treatment facilities and substantial alterations to existing facilities within the drainage area of SPW may
be approved after the applicant fully evaluated all natural treatment alternatives and is unable to implement them because of technical and/or financial infeasibility.For both 1)
and 2) above, the applicant will consider alternatives to all loadings – both existing and proposed – in excess of actual loadings at the time of SPW designation. 3) New
wastewater treatment facilities and substantial alterations to existing facilities discharging directly to SRW may be approved only following a determination that the project is in
the public interest as that term is defined in Section 3.10.3.A.2.a.5 4) The general number, location and size of future wastewater treatment facilities discharging to OBW (if an

DRBC

Water Code 18 CFR Part 410

3.10.3,A,2,d 

Addresses emergency systems (standby power facilities, alarms, emergency management plans) for wastewater treatment facilities discharging to SPW. Emergency
management plans shall include an emergency notification procedure covering all affected downstream users. The minimum level of wastewater treatment for new wastewate
treatment facilities and substantial alterations to existing wastewater treatment facilities that discharge directly to OBW or SRW will be Best Demonstrable Technology
(BDT) (See rule for chemical analyses results that define BDT.) BDT may be superseded by applicable federal, state or DRBC criteria that are more stringent. BDT for
disinfection - ultraviolet light disinfection or an equivalent disinfection process that results in no harm to aquatic life, does not produce toxic chemical residuals, and results in
effective bacterial and viral destruction. DRBC may approve effluent trading on a voluntary basis between point sources within the same watershed or between the same
Interstate or Boundary Control Points to achieve no measurable change to existing water quality. Regulation discusses facilities within drainage areas of SPW and discharges
to OBW and SRW and lists water quality control points and the analyses parameters.

DRBC

Water Code 18 CFR Part 410

3.10.3,A,2,e 

1) Projects subject to review under Section 3.8 of the Compact that are located in the drainage area of SPW must submit for approval a Non-Point Source Pollution Control
Plan that controls the new or increased non-point source loads generated within the portion of the project's service area which is also located within the drainage area of SPW
The plan will state which BMPs must be used to control the non-point source loads. RULE DISCUSSES trade-off plans in detail. It discusses: projects located above major

Page 2 of 3

Final SGEIS 2015, Page
7-94
Z:\projects\2009\09100-09120\09104
- Gas Well Permitting GEIS\Alpha Project Report\Tables\Table 3.1 Invasive Species\Invasive Species Prevention Reg

 Agency

Document

Article

Regulation
Summary
p
p
p
p j
j
surface water impoundments; projects located in municipalities that have adopted and are actively implementing non-point source/stormwater control ordinances, projects
located in watersheds where the applicable state environmental agency, county government, and local municipalities are participating in the development of a watershed plan.
2) Approval of a new or expanded water withdrawal and/or wastewater discharge project will be subject to the condition that any new connection to the project system only
serve an area(s) regulated by a non-point source pollution control plan which has been approved by the DRBC. 3) Future plans for SPWs non-point source control regulations

DRBC

Water Code 18 CFR Part 410

3.10.3B

DRB waters will not contain substances attributable to municipal, industrial, or other discharges in concentrations or amounts sufficient to preclude the protection of specified
water uses. a. The waters shall be substantially free from unsightly or malodorous nuisances due to floating solids, sludge deposits, debris, oil, scum, substances in
concentrations or combinations which are toxic or harmful to human, animal, plant, or aquatic life, or that produce color, taste, odor of the water, or taint fish or shellfish flesh.
b. The concentration of total dissolved solids, except intermittent streams, shall not exceed 133 percent of background. In no case shall concentrations of substances exceed
those values given for rejection of water supplies in the United States Public Health Service Drinking Water Standards.


DRBC

Water Code 18 CFR Part 410

3.10.3C

DRBC

Water Code 18 CFR Part 410

3.10.3D

The DRBC designates numerical stream quality objectives for the protection of aquatic life for the Delaware River Estuary (Zones 2 through 5) which correspond to the designated uses of each 

zone. Aquatic life objectives for the protection from both acute and chronic effects are herein established on a pollutant-specific basis. (See RULE) 

The DRBC designates numerical stream quality objectives for the protection of human health for the Delaware River Estuary (Zones 2 through 5) which correspond to the designated uses of 

each zone. Stream quality objectives for protection from both carcinogenic and systemic effects are herein established on a pollutant-specific basis. (See RULE) 


DRBC

Water Code 18 CFR Part 410

3.10.4,A

All wastes shall receive a minimum of secondary treatment, regardless of the stated stream quality objective.


DRBC

Water Code 18 CFR Part 410

3.10.4,B

Wastes (exclusive of stormwater bypass) containing human excreta or disease producing organisms shall be effectively disinfected before being discharged into surface 

bodies of water as needed to meet applicable DRBC or State water quality standards.


DRBC

Water Code 18 CFR Part 410

3.10.4,C

Effluents shall not create a menace to public health or safety at the point of discharge.


DRBC

Water Code 18 CFR Part 410

3.10.4,D

Lists discharge contaminant limits.


DRBC

Water Code 18 CFR Part 410

3.10.4,E

Where necessary to meet the stream quality objectives, the waste assimilative capacity of the receiving waters shall be allocated in accordance with the doctrine of equitable 

apportionment.


DRBC

Water Code 18 CFR Part 410

3.10.4,F

1. Discharges to intermittent streams may be permitted by the DRBC only if the applicant can demonstrate that there is no reasonable economical alternative, the project is
environmentally acceptable, and would not violate the stream quality objectives set forth in Section 3.10.3B.1.a. 2. Discharges to intermittent streams shall be adequately
treated to protect stream uses, public health and ground water quality, and prevent nuisance conditions.

DRBC

Water Code 18 CFR Part 410

3.10.5,E

The DRBC will consider requests to modify the stream quality objectives for toxic pollutants based upon site-specific factors. Such requests shall provide a demonstration of
the site-specific differences in the physical, chemical or biological characteristics of the area in question, through the submission of substantial scientific data and analysis. The
demonstration shall also include the proposed alternate stream quality objectives. The methodology and form of the demonstration shall be approved by the DRBC.

NYSDEC

6 NYCRR Part 608

608.9

(a) Water quality certifications required by Section 401 of the Federal Water Pollution Control Act, Title 33 United States Code 1341(see subdivision (c)of this Section). Any
applicant for a federal license or permit to conduct any activity, including but not limited to the construction or operation of facilities that may result in any discharge into
navigable waters as defined in Section 502 of the Federal Water Pollution Control Act (33 USC 1362), must apply for and obtain a water quality certification from the
department.The applicant must demonstrate compliance with Sections 301-303, 306 and 307 of the Federal Water Pollution Control Act (See RULE.)

the indicated regulation pertains directly to invasive or nuisance species.
* Connotes
nonetheless may indirectly address the issue.

All other regulations reference practices, methods, and actions that are not specifically targeted at reducing or eliminating the transport of invasive species, but

Final SGEIS 2015, Page 7-95

 The DRBC controls both exportation and importation of water from the Delaware River Basin.
The DRBC’s Rules of Practice and Procedure state that a project sponsor (e.g., operator) may not
discharge to surface waters of the basin or otherwise undertake the project (gas well) until the
sponsor has applied for, and received, approval from the commission. Flow-back water cannot
be taken to a publicly owned treatment works within the Delaware River Basin without the
approval of the DRBC. DRBC also prohibits discharge to the waters of the basin without prior
approval. These actions and policies effectively control the use, withdrawal, discharge, and
transfer to water from and into the basin and reduce the potential for transfer of invasive aquatic
species.
The measures and protocols adopted by the SRBC and DRBC help to address the potential for
transfer of invasive species associated with water use for high-volume hydraulic fracturing.
These protocols, however, are not explicit nor do they apply to the entire area subject to natural
gas activities covered by this SGEIS. Thus, in addition to the requirements of SRBC and DRBC,
the Department recommends that the following best management practices be instituted and
incorporated into the required invasive species mitigation plan to reduce the risk of transferring
invasive species from both the exportation and importation of fresh water. These best
management practices target two specific pathways for the transfer of invasive species, namely
the vehicles and equipment used to transfer the fresh water and the fresh water being moved
between sites and/or discharged.
Best Management Practices for vehicles and equipment:
1. Inspect all vehicles and equipment including trucks, trailers, pumps, hoses, screens, gates,
etc. prior to deployment to new site;
2. Drain all hoses and equipment at collection site after use;
3. Clean all mud, vegetation, organisms and debris and dispose on site if the contaminants
originated at site; dispose in 3 mil trash bags and dispose in trash if contaminants were
transported from another site;
4. When withdrawing water from waters at multiple surface water locations on a single
water body, begin at furthest upstream collection point;

Final SGEIS 2015, Page 7-96

 5. Before moving to another water body, decontaminate equipment that has come in contact
with surface water using appropriate protocols outlined below:
•

Pressure wash with 140º F water at contact point for 3 minutes or disinfect with
200 ppm (0.5 oz/gallon) chlorine for 10 minute contact time; keep disinfection
solution from entering surface waters; and

•

Dry (regardless of treatment);

6. Well operators should provide truck and equipment drivers and operators with clear
instructions, inspection checklists identifying areas on the vehicles or equipment most
likely to harbor invasive species, and specifications and protocols for cleaning and
disinfection; and
7. Document all inspections, cleaning and disinfection activities in a log that would be
required to be maintained by the well operator and made available to the Department
upon request. At a minimum this log would be required to include:
•

Dates and times of all inspection and cleaning/disinfection activities;

•

Identification of the vehicles and equipment inspected and cleaned/disinfected;
and

•

Information regarding the method of cleaning/disinfection.

Best Management Practices for fresh water:
1. Transport unused fresh water via truck or pipeline to other drilling locations where it can
be discharged into tanks or for subsequent use; and
2. If fresh water cannot be used at another drilling location, dispose of unused fresh water
over land (not in surface water or in manner that drains directly to surface water),
preferably in same drainage area as collected, and using appropriate erosion control
measures.
7.4.3

Protecting Endangered and Threatened Species

Prospective project sites should be screened against the Department’s Natural Heritage Database
to determine if endangered or threatened species are known to occur within the vicinity. The
best method for reducing impacts to these species is to avoid siting projects in locations and
habitats known to be utilized by endangered and threatened wildlife.

Final SGEIS 2015, Page 7-97

 Whenever possible, impacts to endangered and threatened animal species should be avoided.
The process for accomplishing this is laid out below:
•

As part of the EAF, the project proponent should do at least one of the following to
screen the project site for potential endangered and threatened animal species:

•

Request a screening from the New York Natural Heritage Program;

•

Self-screen utilizing the Nature Explorer and Environmental Resource Mapper web tools
on the Department’s website; or

•

Conduct site-specific surveys to determine if endangered and threatened animal species
are present at the project site;

•

If any endangered and threatened animal species are found to occur in the vicinity of the
project site, the project proponent should consult with the Regional Department Natural
Resources Office;

•

Regional Department staff can work with project proponent to identify how species may
be affected;

•

Project proponent changes the location of the proposed project or otherwise modifies the
project to avoid any potential “take” of a protected species identified by Department
staff; and

•

If the “take” of an endangered and threatened species is deemed to be unavoidable, the
project proponent would be required to apply for an Incidental Take Permit.

The specific procedure for applying for the Incidental Take Permit is set forth in the
Department’s regulations at 6 NYCRR Part 182 and is summarized below:
•

The applicant develops an endangered or threatened species mitigation plan;

•

The applicant develops an implementation agreement that affirms how the mitigation
plan will be accomplished;

•

The Department reviews the mitigation plan and implementation agreement to determine
if it meets applicable regulatory criteria; and

•

If the Department approves the mitigation plan and implementation agreement and all
other regulatory criteria are met, then an Incidental Take Permit can be issued, subject to
the requisite SEQRA review.

Final SGEIS 2015, Page 7-98

 The Department finds that with the implementation of the above measures, impacts on protected
endangered and threatened species would be reduced.
7.4.4

Protecting State-Owned Land

As discussed in Section 6.4.4, the following issues are of significant concern as they relate to
State-owned forests, wildlife management areas and parklands, and the potential impacts upon
them (See also Sections 6.4.1 and 7.4.1):
•

Forest fragmentation: Because of their size and long-term ownership, the specified stateowned public lands are integral to providing continuous interior forest habitat conditions
and are protected from industrial development. The road systems needed to conduct
drilling and fracturing operations represent significant potential impacts to this important
habitat type;

•

Grassland fragmentation: Because of their size and long-term ownership, the specified
state-owned lands are integral to providing grassland habitat conditions and are protected
from industrial development. The road systems needed to conduct drilling and fracturing
operations represent significant potential impacts to this important habitat type;

•

Public recreation: The level of truck traffic associated with horizontal drilling and high
volume hydraulic fracturing, the presence of drilling rigs and compressor complexes, and
the need to light well pads during drilling and fracturing operations would be likely to
create significant impacts on public recreation opportunities during the construction,
drilling and fracturing phases of development; and

•

Wildlife impacts: Increased light and noise levels would be likely to have significant
impacts on local wildlife populations, including impacts on breeding, feeding and
migration. The activities creating these impacts could take place for up to three years at
any one site, depending on how many wells are drilled from a particular well pad. The
local wildlife populations could take years or even decades to recover.

As an example for one natural gas reservoir that could be developed by high-volume hydraulic
fracturing, State Forests, Wildlife Management Areas and State Parks comprise less than 6% of
the area underlain by the Marcellus Shale in New York State. (As stated in Chapter2, drilling
will not occur on Forest Preserve lands because the State Constitution prevents their being leased
or sold.) Acknowledging that there will likely be physical, technological, ownership and leasing
impediments to reaching all areas under State-owned forests, wildlife management areas and
parklands, it is still likely that less than 3% of the Marcellus Shale formation would be rendered

Final SGEIS 2015, Page 7-99

 unavailable by prohibiting horizontal drilling and high-volume hydraulic fracturing surface
disturbance on these lands.
In order to ensure that the State fulfills the purposes for which State Forests and State Wildlife
Management Areas were created, no surface disturbance associated with horizontal drilling and
high-volume hydraulic fracturing would be permitted on State Forests or Wildlife Management
Areas. This prohibition does not include accessing subsurface resources located within these
areas from adjacent private lands. With the surface disturbance restriction in place, the
Department concludes that impacts to the specified state-owned lands from high-volume
hydraulic fracturing would be reduced. Current OPRHP policy would impose a similar
restriction on State Parks.
7.5

Mitigating Air Quality Impacts

This section identifies mitigation measures which are necessary, or may be necessary, to achieve
compliance with Federal and State air quality standards, State air quality guidelines and State
and Federal regulations. A detailed discussion of the Department’s air quality impact assessment
and analysis of applicable State and Federal regulatory requirements and regional air quality
considerations which give rise to these mitigation measures is presented in Section 6.5. This
section focuses on the following four points. First, the section identifies pollution control
measures required to ensure compliance with ambient air quality standards for criteria air
pollutants and State ambient air thresholds for toxic pollutants. This information is discussed in
detail in Section 6.5.2 and, therefore, is included here in summary form. Second, this section
includes a more detailed discussion of pollution control techniques required pursuant to State and
Federal regulations for specific pollutants, such as NOx, where emissions would be affected by
the type of equipment and fuel to be used. The Department will address the different
approaches, including various operational scenarios and equipment which can be used to achieve
compliance. Third, this section summarizes the total suite of mitigation measures for well pad
operations. Fourth, this section outlines an approach to mitigate formaldehyde emissions from
the compressor station.

Final SGEIS 2015, Page 7-100

 7.5.1

Mitigation Measures Resulting from Regulatory Analysis (Internal Combustion
Engines and Glycol Dehydrators)

This section outlines the potential mitigation measures which would be best suited for given
types of engine and fuel combinations to control NOx; the use of ULSF fuel in diesel engines to
control sulfur oxide emissions; and mitigation measures for glycol dehydrators. Section 7.5.2
identifies SCR as the NOx control measure recommended for diesel engines as a result of the
review of manufacturer’s information and current use based on the detailed dispersion modeling
assessment in Section 6.5.2. In addition, based on the modeling analysis, particulate traps are
deemed the control technology of choice for certain tier diesel engines. Section 7.5.3 outlines all
mitigation measures deemed necessary to assure compliance with Federal and State air quality
standards. State air quality guidelines and Federal and State regulations are detailed in Section
6.5.
7.5.1.1 Control Measures for Nitrogen Oxides - NOx
Control Techniques for Natural Gas Engines
Three generic control techniques have been developed for reciprocating engines: 1) parametric
controls (timing and operating at a leaner air-to-fuel ratio); 2) combustion modifications such as
advanced engine design for new sources or major modification to existing sources (clean-burn
cylinder head designs and pre-stratified charge combustion for rich-burn engines); and 3) postcombustion catalytic controls installed on the engine exhaust system. Post-combustion catalytic
technologies include SCR for lean-burn engines, NSCR for rich-burn engines, and CO oxidation
catalysts for lean-burn engines. For example, the off-site compressors will be required to use an
oxidation catalyst.
Control Techniques for 4-Cycle Rich-Burn Engines
Nonselective Catalytic Reduction (NSCR) - This technique uses the residual hydrocarbons and
CO in the rich-burn engine exhaust as a reducing agent for NOx. In NSCR, hydrocarbons and
CO are oxidized by O2 and NOx. The excess hydrocarbons, CO and NOx pass over a catalyst
(usually a noble metal such as platinum, rhodium, or palladium) that oxidizes the excess
hydrocarbons and CO to H2O and CO2, while reducing NOx to N2. NOx reduction efficiencies are
usually greater than 90 %, while CO reduction efficiencies are approximately 90 %.

Final SGEIS 2015, Page 7-101

 The NSCR technique is effectively limited to engines with normal exhaust oxygen levels of 4 %
or less. This includes 4-stroke rich-burn, naturally aspirated engines and some 4-stroke richburn, turbocharged engines. Engines operating with NSCR require tight air-to-fuel control to
maintain high reduction effectiveness without high hydrocarbon emissions. To achieve effective
NOx reduction performance, the engine may need to be run with a richer fuel adjustment than
normal. This exhaust excess oxygen level would probably be closer to 1 %. Lean-burn engines
could not be retrofitted with NSCR control because of the reduced exhaust temperatures.
Pre-Stratified Charge - Pre-stratified charge combustion is a retrofit system that is limited to 4stroke carbureted natural gas engines. In this system, controlled amounts of air are introduced
into the intake manifold in a specified sequence and quantity to create a fuel-rich and fuel-lean
zone. This stratification provides both a fuel-rich ignition zone and rapid flame cooling in the
fuel-lean zone, resulting in reduced formation of NOx. A pre-stratified charge kit generally
contains new intake manifolds, air hoses, filters, control valves, and a control system.
Control Techniques for Lean-Burn Reciprocating Engines
Selective Catalytic Reduction (SCR) - SCR is a post-combustion technology that has been shown
to effectively reduce NOx in exhaust from lean-burn engines. An SCR system consists of an
ammonia storage, feed, and injection system, and a catalyst and catalyst housing. SCR systems
selectively reduce NOx emissions by injecting ammonia (either in the form of liquid anhydrous
ammonia or aqueous ammonium hydroxide) into the exhaust gas stream upstream of the catalyst.
NOx, NH3, and O2 react on the surface of the catalyst to form N2 and H2O. For the SCR system
to operate properly, the exhaust gas would be within a particular temperature range (typically
between 450° F and 850° F). The temperature range is dictated by the catalyst (typically made
from noble metals, base metal oxides such as vanadium and titanium, and zeolite-based
material). Exhaust gas temperatures greater than the upper limit (850º F) will pass the NOx and
ammonia unreacted through the catalyst. Ammonia emissions, called NH3 slip, are a key
consideration when specifying a SCR system. SCR is most suitable for lean-burn engines
operated at constant loads, and can achieve efficiencies as high as 90 %. For engines which
typically operate at variable loads, such as engines on gas transmission pipelines, an SCR system
may not function effectively, causing either periods of ammonia slip or insufficient ammonia to
gain the reductions needed.

Final SGEIS 2015, Page 7-102

 Catalytic Oxidation - Catalytic oxidation is a post-combustion technology that has been applied,
in limited cases, to oxidize CO in engine exhaust, typically from lean-burn engines. As
previously mentioned, lean-burn technologies may cause increased CO emissions. The
application of catalytic oxidation has been shown to effectively reduce CO emissions from leanburn engines. In a catalytic oxidation system, CO passes over a catalyst, usually a noble metal,
which oxidizes the CO to CO2 at efficiencies of approximately 70 % for two-stroke lean-burn
engines and 90 % for 4-stroke lean-burn engines.
Control Techniques for Diesel and Dual-Fuel Engines
The most common NOx control technique for diesel and dual-fuel engines focuses on modifying
the combustion process. However, post-combustion techniques, such as SCR and NSCR, are
currently also available. Controls for CO have been partly adapted from mobile sources.
Combustion modifications include injection timing retard (ITR), pre-ignition chamber
combustion (PCC), air-to-fuel ratio adjustments, and de-rating. Injection of fuel into the cylinder
of a CI engine initiates the combustion process. Retarding the timing of the diesel fuel injection
causes the combustion process to occur later in the power stroke when the piston is in the
downward motion and combustion chamber volume is increasing. Increasing the volume lowers
the combustion temperature and pressure, thereby lowering NOx formation. ITR reduces NOx
from all diesel engines; however, the effectiveness is specific to each engine model. The amount
of NOx reduction with ITR diminishes with increasing levels of retard.
Improved swirl patterns promote thorough air and fuel mixing and may include a pre-combustion
chamber (PCC). A PCC is an antechamber that ignites a fuel-rich mixture that propagates to the
main combustion chamber. The high exit velocity from the PCC results in improved mixing and
complete combustion of the lean air/fuel mixture, which lowers combustion temperature, thereby
reducing NOx emissions. The air-to-fuel ratio for each cylinder can be adjusted by controlling
the amount of fuel that enters each cylinder. At air-to-fuel ratios less than stoichiometric (fuelrich), combustion occurs under conditions of insufficient oxygen which causes NOx to decrease
because of lower oxygen and lower temperatures. Derating involves restricting the engine
operation to lower than normal levels of power production for the given application. Derating
reduces cylinder pressures and temperatures, thereby lowering NOx formation rates.

Final SGEIS 2015, Page 7-103

 SCR is an add-on NOx control placed in the exhaust stream following the engine and involves
injecting ammonia (NH3) into the flue gas. The NH3 reacts with NOx in the presence of a catalyst
to form water and nitrogen. The effectiveness of SCR depends on fuel quality and engine duty
cycle (load fluctuations). Contaminants in the fuel may poison or mask the catalyst surface
causing a reduction or termination in catalyst activity. Load fluctuations can cause variations in
exhaust temperature and NOx concentration which can create problems with the effectiveness of
the SCR system.
NSCR is often referred to as a three-way conversion catalyst system because the catalyst reactor
simultaneously reduces NOx, CO, and HC and the system involves placing a catalyst in the
exhaust stream of the engine. The reaction requires that the O2 levels be kept low and that the
engine be operated at fuel-rich air-to-fuel ratios.
7.5.1.2 Control Measures for Sulfur Oxides - SOx
Sulfur oxide emissions are a function of only the sulfur content in the fuel rather than any
combustion variables. During the combustion process, essentially all the sulfur in the fuel is
oxidized to SO2. The oxidation of SO2 creates sulfur trioxide (SO3), which reacts with water to
create sulfuric acid (H2SO4), a contributor to acid precipitation. Sulfuric acid reacts with basic
substances to create sulfates, which are fine particulates that contribute to PM-10 and visibility
reduction. Sulfur oxide emissions also contribute to corrosion of the engine parts.
Past communications with representatives of natural gas producer Chesapeake Energy indicated
contractors that provide approximately 80% of the diesel rigs to the industry are using ultra low
sulfur fuel (ULSF, 15ppm) because of the reduced availability of the alternative low sulfur fuel.
Industry has identified the use of ULSF for all engines as a mitigation measure in their
Information Report in response to Department requests.
The final EPA regulation at 40 CFR Part 63 Subpart ZZZZ (Engine MACT rule) described in
Appendix 17 will mandate the use of ultra low sulfur fuel (ULSF). Accordingly, ULSF is being
required for all engines to be used in New York Marcellus Shale activities.

Final SGEIS 2015, Page 7-104

 7.5.1.3 Natural Gas Production Facilities Subject to NESHAP 40 CFR Part 63, Subpart HH
(Glycol Dehydrators)
40 CFR Part 63, Subpart HH imposes specific control requirements on TEG dehydrator units.
Area source TEG dehydration units with natural gas throughput and benzene emission rates
above the cutoff levels described in Section 6.5.1.2, must be connected, through a closed vent
system, to one or more emission control devices. The control devices must: 1) reduce HAP
emissions by 95 % or more (generally by a condenser with a flash tank); or 2) reduce HAP
emissions to an outlet concentration of 20 ppm by volume (ppmv) or less (for combustion
devices); or 3) reduce benzene emissions to a level less than 1.0 Tpy. As an alternative to
complying with these control requirements, pollution prevention measures, such as process
modifications or combinations of process modifications and one or more control devices that
reduce the amount of HAP generated, are allowed provided that they achieve the same required
emission reductions.
Area source TEG dehydration units with natural gas throughput and benzene emission rates
above the cutoff levels described in Section 6.5.1.2, must reduce emissions by lowering the
glycol circulation rate to less than or equal to an optimum rate. The optimum rate is determined
by the following equation:
LOPT = 1.15*3.0 gal TEG *{F*(I – O)}
lb H2O {24hr/day}
Where:
LOPT = Optimal circulation rate, gal/hr.
F = Gas flowrate (MMSCF/D).
I = Inlet water content (lb/MMscf).
O = Outlet water content (lb/MMscf).
The constant 3.0 gal TEG/lb H2O is the industry accepted rule of thumb for a TEG-to-water
ratio. The constant 1.15 is an adjustment factor included for a margin of safety.
All glycol dehydrator units used at the well pad will be required to assure compliance with the 1
Tpy benzene emission limit using the above equation and necessary data and, in the event of wet
gas, apply a condenser to assure such compliance.

Final SGEIS 2015, Page 7-105

 7.5.2

Mitigation Measures Resulting from Air Quality Impact Assessment and
Regional Ozone Precursor Emissions

The modeling analysis conducted and described in Section 6.5.2 concluded that most of the air
quality standards and ambient thresholds will be met under the operations scenarios described by
industry, including certain self-imposed restrictions on these operations. For example, industry
has committed to: 1) limiting the number of wells to be drilled and completed per pad and per
year to a maximum of four; 2) not operate drilling and hydraulic fracturing engines
simultaneously at a single well pad; and 3) limit the amount of gas to be vented and flared per
well. Even with these restrictions, however, certain air quality standards and ambient thresholds
are projected to be exceeded for certain pollutants and, therefore, further mitigation measures are
necessary. Section 6.5.2 details the specific pollutants of concern and the associated additional
mitigation measures necessary to achieve standards compliance. For the mitigation measures
necessary for the drilling and hydraulic fracturing engines, the review process and analysis
conducted to support the specific control techniques recommended by the Department is also
detailed.
In summary, the Department has determined that the modeling results support the following
conclusions for the necessary mitigations which would be necessary for ambient standards
compliance:
1) In order to meet the annual benzene ambient guideline concentration (AGC) due to the
glycol dehydrator emission, the stack height needs to be a minimum of 30 feet even with
the benzene emission limit of 1 Tpy;
2) The gas venting has to use a minimum stack height of 30 feet if “sour” gas is encountered
in order to meet the 1-hour standard for H2S;
3) The off-site compressor must have a minimum stack height of 25 feet, in addition to the
oxidation catalyst required by regulation, in order to meet the formaldehyde annual
threshold; and
4) Certain EPA “Tier” drilling and hydraulic fracturing engines will not be allowed for use
in New York Marcellus activities, while others must be equipped with particulate traps
and SCR controls.
Section 6.5.2.6 details measures required for specific tiers of engines. With respect to these
specific measures for engines, industry is allowed to provide alternative measures which can

Final SGEIS 2015, Page 7-106

 demonstrate the equivalent emission reductions and standards compliance. In addition to these
measures, based on the modeling results, additional controls to reduce NOx emissions might be
necessary in the future to address the Ozone NAAQS SIP requirements. The full set of control
measures resulting from the regulatory and modeling assessments are provided in Section 6.5.5
and are repeated in the next section for convenience.
7.5.3

Summary of Mitigation Measures to Protect Air Quality

7.5.3.1 Well Pad Activity Mitigation Measures
The necessary control measures resulting from the air quality assessments will be imposed on the
well pad activities through the well permitting process, as described in Section 6.5.5. Based on
industry’s self-imposed limitations on operations and Department’s determination of conditions
necessary to reduce or mitigate adverse air quality impacts from the well drilling, completion and
production operations, the following restrictions must be imposed in the well permitting process:
•

The diesel fuel used in drilling and hydraulic fracturing engines will be limited to ULSF
with a maximum sulfur content of 15 ppm;

•

Drilling and fracturing engines will not be operated simultaneously at the single well pad;

•

The maximum number of wells to be drilled and completed annually or during any
consecutive 12-month period at a single pad will be limited to four;

•

The emissions of benzene at any glycol dehydrator to be used at the well pad will be
limited to one ton/year as determined by calculations with the GRI-GlyCalc program. If
wet gas is encountered, the dehydrator will have a minimum stack height of 30 feet
(9.1m) and will be equipped with a control devise to limit the benzene emissions to one
ton/year;

•

Condensate tanks used at the well pad shall be equipped with vapor recovery systems to
minimize fugitive VOC emissions;

•

During the flowback phase, the venting of gas from each well pad will be limited to a
maximum of 5 MMscf during any consecutive 12-month period. If “sour” gas is
encountered with detected hydrogen sulfide emissions, the height at which the gas will be
vented will be a minimum of 30 feet (9.1m);

•

During the flowback phase, flaring of gas at each well pad will be limited to a maximum
of 120 MMscf during any consecutive 12-month period;

•

Wellhead compressors will be equipped with NSCR controls;

Final SGEIS 2015, Page 7-107

 •

No uncertified (i.e., EPA Tier 0) drilling or hydraulic fracturing engines will be used for
any activity at the well sites;

•

The drilling engines and drilling air compressors will be limited to EPA Tier 2 or newer
equipment. If Tier 1 drilling equipment is to be used, these will be equipped with both
particulate traps (CRDPF) and SCR controls. During operations, this equipment will be
positioned as close to the center of the well pad as practicable. If industry deviates from
the control requirements or proposes alternate mitigation and/or control measures to
demonstrate ambient standard compliance, site specific information will be provided to
the Department for review and concurrence; and

•

The completion equipment engines will be limited to EPA Tier 2 or newer equipment.
Particulate traps will be required for all Tier 2 engines. SCR control will be required on
all completion equipment engines regardless of the emission Tier. During operations,
this equipment will be positioned as close to the center of the well pad as practicable. If
industry deviates from this requirement or proposes mitigation and/or alternate control
measures to demonstrate ambient standard compliance, site specific information will be
provided to the Department for review and concurrence.

The EAF Addendum will require information regarding stack heights. If stack heights shorter
than those specified in Table 7.6 are proposed, then information must be attached to the EAF
Addendum which demonstrates that other control measures will effectively prevent exceedances
for the listed pollutants.

Table 7.6 - Required Well Pad Stack Heights to Prevent Exceedances

Equipment

Pollutant

Flowback vent

H2S

Glycol dehydrator

Benzene

Stack Height
30 feet
NOTE: not required if previous drilling at
the same pad has demonstrated that H2S is
not present
30 feet
NOTE: Subpart HH compliance as
described in Section 7.5.1.3 is also required.

7.5.3.2 Mitigation Measures for Off-Site Gas Compressors
As concluded in Sections 6.5.1.8 and 6.5.5, any off-site compressor “stations” will require a case
by case air permit review pursuant to the Department’s air permitting regulations. Thus, all
necessary control measures, such as the stack height necessary to avoid exceedances of the
annual formaldehyde, will be determined for each compressor during the application review

Final SGEIS 2015, Page 7-108

 process. From the regulatory requirements described in Section 6.5.1, an oxidation catalyst will
be required to reduce the emissions of CO, VOCs and formaldehyde in all instances.
7.6

Mitigating GHG Emissions

Potential GHG emissions are discussed in Section 6.6 for the siting, drilling and completion of 1)
single vertical well, 2) single horizontal well, 3) four-well pad (i.e., four horizontal wells at the
same site), and respective first-year and post first-year emissions of carbon dioxide (CO2) and
methane (CH4) as both short tons and as carbon dioxide equivalents (CO2e) expressed in short
tons for expected exploration and development of the Marcellus Shale and other lowpermeability gas reservoirs using high volume hydraulic fracturing. The real benefit of the
emission estimates comes not with quantifying possible emissions but from the identification and
characterization of likely major sources of CO2 and CH4 during the anticipated operations.
Identification and understanding of the key contributors of GHGs allows mitigation measures
and future efforts to be efficiently focused. The following sections discuss possible mitigation
measures for limiting GHGs, with particular emphasis on CH4 because of its Global Warming
Potential (GWP).
7.6.1

General

EPA’s Natural Gas STAR Program is a flexible, voluntary partnership that encourages oil and
natural gas companies – both domestically and abroad – to adopt cost-effective technologies and
practices that improve operational efficiency and reduce emissions of CH4, a potent greenhouse
gas and clean energy source. 493 Natural Gas STAR partners can implement a number of
voluntary activities to reduce GHG emissions from both exploration and production activities.
The Department strongly encourages active participation in the program. Therefore, an example
of a measure that could be included in a greenhouse gas emissions impacts mitigation plan
includes:
•

Proof of participation in the EPA’s Natural Gas STAR Program to reduce methane
emissions (see Appendices 24 and 25). 494

493

http://www.epa.gov/gasstar/.

494

http://www.epa.gov/gasstar/join/index.html.

Final SGEIS 2015, Page 7-109

 7.6.2

Site Selection

Site selection directly impacts the number of rig and equipment mobilizations needed to develop
a well pad or area. Well operators can limit the generation of CO2 by limiting vehicle miles
traveled (VMT) and fuel consumption. Examples of measures that could be included in a
greenhouse gas emissions impacts mitigation plan include:
•

Drilling as many wells as possible on a pad with one rig move;

•

Spacing wells for efficient recovery of natural gas;

•

Hydraulic fracturing as many wells as possible on a pad with one equipment move; and

•

Planning for efficient rig and fracturing equipment moves from one pad to another.

7.6.3

Transportation

Transportation related to sourcing of equipment and materials, including disposal, was identified
as a potential contributor of CO2 emissions. Well operators can limit the generation of CO2 by
limiting VMT and fuel consumption. Examples of measures that could be included in a
greenhouse gas emissions impacts mitigation plan include:
•

Sourcing personnel and equipment from locations within the State or region to minimize
the travel distance;

•

Using materials that are extracted and/or manufactured within the State or region to
minimize the shipping distance;

•

Recycling fluids at in-state facilities;

•

Disposal or processing wastes at in-state facilities including disposal wells; and

•

Using efficient transportation engines.

7.6.4

Well Design and Drilling

Well operators can limit GHG emissions during well drilling operations by effectively designing
drilling programs. Examples of measures that could be included in a greenhouse gas emissions
impacts mitigation plan include:
•

Extending each lateral wellbore as far as technically and legally possible to reduce the
total number of wells required within a spacing unit;

Final SGEIS 2015, Page 7-110

 •

Spacing the lateral wellbores for efficient recovery of natural gas;

•

Re-using drilling fluids;

•

Drilling overbalanced to limit/prevent venting and/or flaring of CH4;

•

Using materials with recycled content (e.g., well casing, drilling fluids);

•

Using efficient rig engines;

•

Using efficient air compressor engines for drilling;

•

Using efficient exterior lighting;

•

Ensuring all flow connections are tight and sealed;

•

Flaring methane instead of venting; and

•

Performing leak detection surveys and taking corrective actions.

7.6.5

Well Completion

Well completion activities primarily contribute to GHG emissions from the internal combustion
engines required for hydraulic fracturing and flaring operations during the flowback period.
Examples of measures that could be included in a greenhouse gas emissions impacts mitigation
plan include:
•

Re-using flowback water;

•

Using materials with recycled content (e.g., hydraulic fracturing fluids);

•

Using efficient hydraulic fracturing pump engines;

•

Using efficient exterior lighting;

•

Limiting flaring during the flowback phase by using REC equipment (see Appendix 25);

•

If allowed by the PSC, constructing gathering lines so that the first well on a pad can
initially be flowed into a sales line;

•

Ensuring all flow connections are tight and sealed;

•

Flaring methane instead of venting; and

Final SGEIS 2015, Page 7-111

 •

Performing leak detection surveys and taking corrective actions.

Two years after the completion date of the first well drilled and completed under the SGEIS, the
Department would analyze the actual usage of RECs in New York, and examine existing
conditions relative to industry’s development of the Marcellus Shale and other low-permeability
gas reservoirs, and PSC’s position on the timing of pipeline installation as discussed in Chapter
8. At the same time, the Department would evaluate a possible additional REC requirement
under certain circumstances through a new supplementary permit condition for high-volume
hydraulic fracturing.
7.6.6

Well Production

As mentioned above, compared to any of the aforementioned operational phases, the ongoing
production phase of any given well is the most significant period and contributor of GHGs,
especially CH4. Natural gas compressors which run virtually around-the-clock, produce both
CO2 and CH4 emissions. Equipment required to process produced natural gas, specifically the
glycol dehydrators (i.e., vents & pumps) and pneumatic devices, generate CH4 emissions during
normal production operations. Examples of measures that could be included in a greenhouse gas
emissions impacts mitigation plan include:
•

Implementing EPA’s Natural Gas STAR BMPs including below; 495

•

Reducing Methane Emissions From Pneumatic Devices in the Natural Gas Industry; 496

•

Reducing Methane Emissions from compressor rod packing systems; 497

•

Reducing emissions when taking compressors off-line; 498

•

Replacing Glycol Dehydrators with Desiccant Dehydrators; 499

495

http://www.epa.gov/gasstar/tools/recommended.html.

496

http://www.epa.gov/gasstar/documents/ll_pneumatics.pdf.

497

http://www.epa.gov/gasstar/documents/ll_rodpack.pdf.

498

http://www.epa.gov/gasstar/documents/ll_compressorsoffline.pdf.

499

http://www.epa.gov/gasstar/documents/ll_desde.pdf.

Final SGEIS 2015, Page 7-112

 •

Replacing gas-assisted glycol pumps with electric pumps; 500

•

Optimizing glycol circulation and installing flash tank separators in glycol
dehydrators; 501

•

Using efficient compressor engines;

•

Using efficient line heaters;

•

Using efficient glycol dehydrators;

•

Re-using production brines;

•

Ensuring all flow connections are tight and sealed;

•

Performing leak detection surveys and taking corrective actions;

•

Using efficient exterior lighting; and

•

Using solar-powered telemetry devices.

7.6.7

Leak and Detection Repair Program

Because the production phase is the greatest contributor of GHGs and in an effort to mitigate
VOC and methane leaks during this phase, the Department proposes to require, via permit
condition and/or regulation, a Leak Detection and Repair Program would include as part of the
operator’s greenhouse gas emissions impacts mitigation plan which is required for any well
subject to permit issuance under the SGEIS. In accordance with the corresponding plan
developed by the operator to meet the Leak Detection and Repair Program’s below minimum
requirements, an annual report for the calendar year would be completed by March 31 of each
following year. Each annual report would be retained by the site owner for a minimum period of
5 years and would be made available to the Department upon request. The report would include
the inspection results of the inspections and repairs completed and an explanation for any repairs
that were not completed. The report would be accompanied by the certification of a company
official that all repairs completed were in accordance with company policies and the requisite
plan, and include a schedule for completion of repairs for any remaining leaks identified in the
500

http://www.epa.gov/gasstar/documents/ll_glycol_pumps3.pdf.

501

http://www.epa.gov/gasstar/documents/ll_flashtanks3.pdf.

Final SGEIS 2015, Page 7-113

 report. In addition, based on the leak history of a site, the report would include an evaluation and
determination of the adequacy of the existing inspection procedures and schedule or a plan to
modify existing procedures and/or increase the number of inspections in the current and future
years. The Leak Detection and Repair Program may be modified at the operator’s discretion
provided it continues to meet the minimum requirements of the SGEIS.
The Leak Detection and Repair Program within the greenhouse gas emissions impacts mitigation
plan would contain the following minimum requirements.
•

There would be an ongoing site inspection for readily detected leaks by sight and sound
whenever company personnel or other personnel under the direction of the company are
on site. Anytime a leak is detected by sight or sound, an attempt at repair should be
made. If the leak is associated with mandated worker safety concerns, it should be so
noted in follow-up reports;

•

Within 30 days of a well being placed into production and at least annually thereafter, all
wellhead and production equipment, surface lines and metering devices at each well
and/or well pad including and from the wellhead leading up to the onsite separator’s
outlet would be inspected for VOC, methane and other gaseous or liquid leaks. Leak
detection would be conducted by visible and audible inspection and through the use of at
least one of the following: 1) electronic instrument such as a forward looking infrared
camera, 2) toxic vapor analyzer, 3) organic vapor analyzer, or 4) other instrument
approved by the department;

•

All components noted above that are possible sources of leaks would be included in the
inspection and repair program. These components include but are not limited to: line
heaters, separators, dehydrators, meters, instruments, pressure relief valves, vents,
connectors, flanges, open-ended lines, pumps and valves from and including the wellhead
up to the onsite separator’s outlet;

•

For each detected leak, if practical and safe an initial attempt at repair would be made at
the time of the inspection, however, any leak that is not able to be repaired during the
inspection may be repaired at any time up to 15 days from the date of detection provided
it does not pose a threat to on-site personnel or public safety. All leaking components
which cannot be repaired at detection would be identified for such repair by tagging. All
repaired components would be re-inspected within 15 days from the date of the initial
repair and/or re-repair to confirm, using one of the approved leak detection instruments,
the adequacy of the repair and to check for leaks. The department may extend the period
allowed for the repair(s) based on site-specific circumstances or it may require early well
or well pad shutdown to make the repair(s) or other appropriate action based on the
number and severity of tagged leaks awaiting repair; and

Final SGEIS 2015, Page 7-114

 •

7.6.8

Site inspection records would be maintained for a minimum period of 5 years. These
records would include the date and location of the inspection, identification of each
leaking component, the date of the initial attempt at repair, the date(s) and result(s) of any
re-inspection and the date of the successful repair if different from initial attempt.
Mitigating GHG Emissions Impacts - Conclusion

Well operators can reduce their GHG emissions through active participation in the EPA’s
Natural Gas STAR Program, leak detection and repair, and through effective planning and
implementation of necessary activities. The Department proposes to require, as a permit
condition for high-volume hydraulic fracturing that the operator construct and operate the site in
accordance with a greenhouse gas emissions impacts mitigation plan that may incorporate the
above practices and considers, to the extent practicable, any applicable Department policy
documents. However, the impacts mitigation plan would, at a minimum, include:
•

A list of GHG-related BMPs planned for implementation at the permitted well site;

•

A Leak Detection and Repair Program consistent with the SGEIS;

•

Required use and a description of EPA’s Natural Gas STAR Best Management Practices
for any equipment (e.g., low bleed gas-driven pneumatic valves and pumps) located from
the wellhead to the onsite separator’s outlet (Department’s regulatory authority cutoff as
described in Chapter 8);

•

A description of planned use of reduced emissions completions, if any, including an
estimate of the amount of methane that would be recovered instead of flared by the use of
such; and

•

A statement that upon request the operator would provide the Department with a copy of
its report(s) for New York State as required under the EPA’s GHG reporting rule
discussed in Chapter 8. The operator would provide such to the Department upon request
at any time during the period up to and including five years after the well is permanently
plugged and abandoned under a Department permit. If the well is located on a multi-well
pad, records would be maintained and made available during the period up to and
including five years after the last well on the pad is permanently plugged and abandoned
under a Department permit.

Further, partners in EPA's Natural Gas STAR Program should include proof of their participation
and starting date. The operator’s greenhouse gas emissions impacts mitigation plan would be
available to the Department upon request.

Final SGEIS 2015, Page 7-115

 The Department proposes to require, via permit condition, the following additional requirements:
•

Gas vented through the flare stack would be ignited whenever possible. The stack would
be equipped with a self-ignition device; and

•

A reduced emissions completion, with minimal flaring (if any), would be performed
whenever a sales line is available during completion at any individual well or the multiwell pad.

7.7

Mitigating NORM Impacts

7.7.1

State and Federal Responses to Oil and Gas NORM 502

Discovery of elevated concentrations of NORM levels in other areas outside of New York in the
1980s led to a series of state and private investigations of the issue. State responses to the
potential of elevated oil and gas NORM range from no action (barring self-reported problems) to
decisions for further study, to implementation of new formal regulations and guidance
documents. NORM is not subject to direct federal regulation (except its transport) under either
the AEA or LLRWPA, and exploration and production (E&P) wastes are specifically exempt
from regulation under Subtitles D and C of RCRA (LA Office of Conservation, 2009); however,
NORM is regulated indirectly at the federal level through potential environmental impacts to
drinking water (SDWA) and cleanup of abandoned hazardous waste sites (CERCLA and NCP).
7.7.2

Regulation of NORM in New York State

In New York State, the handling of radioactive material and waste is regulated. Requirements
for radioactive materials licensing, excluding medical and educational uses in New York City
and entities under exclusive federal jurisdiction, are in the State Sanitary Code, Chapter 1, Part
16 (10 NYCRR 16) and Industrial Code Rule 38 (12 NYCRR 38). The NYSDOH is the
licensing agency, and it enforces both Part 16 and Code Rule 38. Requirements for
environmental discharges, waste shipment and disposal, or environmental cleanup are regulated
by the Department under its 6 NYCRR Part 380 series of regulations. Additionally, the
Department’s solid waste disposal regulations, Part 360, precludes disposal of wastes regulated
under Part 380 in a Part 360 solid waste landfill.

502

Alpha, 2009, p. 2-44 et seq.

Final SGEIS 2015, Page 7-116

 Disposal of flowback waster or brine through a POTW is addressed in section 7.1.8.1.
The overall licensing requirement for radioactive material, §16.100 of the State Sanitary code
states, in part, that “no person shall transfer, receive, possess or use any radioactive material
except pursuant to a specific or general license issued under this Part.” Exemptions to the
overall requirement are listed in Part 16, Appendix 16-A. In summary, any person is exempt
from the requirements to the extent that such person transfers, receives, possesses or uses
products or materials containing radioactive material in concentrations and quantities not in
excess of those listed in the accompanying tables. Where multiple radionuclides are present, the
sum of the ratios shall not exceed unity (one).
The discharge of licensed radioactive material and processed and concentrated NORM (such as
waste filters, sludges, or backwash from the treatment of flowback water or production brine)
into the environment is regulated by the Department. NORM contained in flowback water or
production brine may be subject to applicable SPDES permit conditions.
Analytical results from initial sampling of production brine from vertical gas production wells in
the Marcellus formation have been reviewed and suggest that the potential for NORM scale
buildup in pipes and equipment may require licensing of a facility. The results also indicate that
production brine may be subject to discharge limitations to ensure compliance with Part 380.
Existing data from drilling in the Marcellus Formation in other States, and from within New
York for wells that were not hydraulically fractured, shows significant variability in NORM
content. This variability appears to occur both between wells in different portions of the
formation and at a given well over time. This makes it important that samples from wells in
different locations within New York State are used to assess the extent of this variability. During
the initial Marcellus development efforts, sampling and analysis would be undertaken in order to
assess this variability. These data would be used to determine whether additional mitigation is
necessary to adequately protect workers, the general public, and environment of the State of New
York.
In order to determine which gas production facilities may be subject to the licensing and
environmental discharge requirements, radiological surveys and measurements are necessary

Final SGEIS 2015, Page 7-117

 including radiation exposure rate measurements of areas of potential NORM contamination,
accessible piping, tanks or other equipment that could contain NORM pipe scale buildup.
Facilities that possess NORM wastes or piping, tanks or other equipment with elevated radiation
levels may need a radioactive materials license. Further, any discharge of effluents into the
environment would need to be tested for NORM concentrations in order to ensure compliance
with regulatory requirements.
The Department proposes to require, via permit condition and/or regulation, that radiation
surveys be conducted at specified time intervals for Marcellus wells developed by high-volume
hydraulic fracturing completion methods on all accessible well piping, tanks, or other equipment
that could contain NORM scale buildup. The surveys would be required to be conducted for as
long as the facility remains in active use. Once taken out of use no increases in dose rate are to
be expected. Therefore, surveys may stop until either the site again becomes active or equipment
is planned to be removed from the site. If equipment is to be removed, radiation surveys would
be performed to ensure appropriate disposal of the pipes and equipment. All surveys would be
conducted in accordance with NYSDOH protocols. The NYSDOH’s Radiation Survey
Guidelines and a sample Radioactive Materials Handling License are presented in Appendix 27.
The Department finds that existing regulations, in conjunction with the proposed requirements
for radiation surveys, would reduce any potential significant impacts from NORM.
7.8

Socioeconomic Mitigation Measures 503

High-volume hydraulic fracturing operations would have many positive socioeconomic results in
the local areas where development is expected to occur. These operations would likely result in
a substantial increase in economic activity in the affected areas, as well as a substantial increase
in tax revenues to the state and localities. However, as described in previous sections, this
increased economic activity would also have the potential to result in adverse impacts in regions
with high drilling activity, particularly acute in the short term, including localized impacts on the
housing market caused by the in-migration of construction and production workforces and an

503

Section 7.8, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011 and was adapted by
the Department.

Final SGEIS 2015, Page 7-118

 increase in demand for certain state and local government services, resulting in increased
government expenditures.
As discussed in Section 6.8, potentially significant adverse impacts on local communities
associated with an increase in population and increased demand for housing and community
services are tied to the rate of development. Impacts that were potentially significant under the
average development scenario were not as significant under the low development scenario.
Similarly, impacts on population, housing, and community services are more significant when
concentrated in smaller geographic areas than when incurred across broader geographic areas or
statewide. The rate and concentration of development also affects the significance of impacts on
visual resources, the ambient noise environment, and transportation networks.
The rate and concentration of development is related to many factors that cannot necessarily be
controlled, such as the price of natural gas, input costs, the price of other energy sources, changes
in technology, and the general economic conditions of state and nation, which will all affect the
overall rate of development, as well as the uncertainty in the development potential of the
Marcellus and Utica Shales.
Through its permitting process, the Department will monitor the pace and concentration of
development throughout the state to mitigate adverse impacts at the local and regional levels.
The Department will consult with local jurisdictions, as well as applicants, to reconcile the
timing of development with the needs of the communities. Where appropriate the Department
would impose specific construction windows within well construction permits in order to ensure
that drilling activity and its cumulative adverse socioeconomic effects are not unduly
concentrated in a specific geographic area.
Another way to mitigate the potential adverse impacts associated with in-migration to the region
would be to actively encourage the hiring of local labor. Because natural gas exploration,
drilling, and production activities typically require specialized skills, a jobs training program or
apprentice program should be developed through the SUNY system (e.g., community colleges
and agricultural and technical colleges) to increase the number of local residents with the
requisite job skills for the natural gas industry, thereby reducing the number of workers that

Final SGEIS 2015, Page 7-119

 would need to be hired from outside the region. Such a program would also have the benefit of
reducing unemployment in these regions. A jobs training program would not eliminate the need
for in-migration of skilled labor, but the program could partially offset the in-migration of
workers and thus partially offset the potential housing impact from such in-migration.
7.9

Visual Mitigation Measures 504

As noted, in most cases high-volume hydraulic fracturing operations would not result in
significant adverse impacts on visual resources as set forth in NYSDEC DEP-00-2, “Assessing
and Mitigating Visual Impacts” (NYSDEC 2000). The most significant visual impacts would
result from construction of the well pad and well, and those impacts would be of short duration.
Nevertheless, this section describes generic measures to address temporary adverse impacts of
well site construction, development, production, and reclamation on visual resources. These
measures could be undertaken in cases where well construction takes place near visually
sensitive areas identified within the area underlain by the Marcellus and Utica Shales in New
York State. Measures to mitigate impacts on visual resources would be generally similar,
regardless of the type of visual resource or its location, and despite the need for compliance with
rules, regulations, and permits promulgated by other federal, state, and/or local (town, county or
regional) agencies.
The development of measures to reduce impacts on visual resources or visually sensitive areas
would follow the procedures identified in NYSDEC DEP-00-2, “Assessing and Mitigating
Visual Impacts” (NYSDEC 2000). These measures can generally be divided into: design and
siting measures that could be incorporated during the construction, development, and production
phases; maintenance measures that could be incorporated into the development and production
phases; and decommissioning measures that could be incorporated into the reclamation phase.
Offsetting mitigation, as opposed to avoidance and direct mitigation measures, would typically
be used only as a last resort for the resolution of significant impacts on visual resources or
visually sensitive areas, as determined by Department staff. These measures are discussed in
greater detail in the following subsections.
504

Section 7.9, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011 and was adapted by
the Department.

Final SGEIS 2015, Page 7-120

 Generally, mitigation measures would be developed in consultation between Department staff
and well operators and would be site-specific, or project-specific where multiple sites are a part
of the project design. Depending on the location of the well pad and the resource potentially
impacted, it may also be necessary to consult with additional state and federal regulatory
agencies to develop measures to mitigate visual impacts on specific types of visual resources or
visually sensitive areas, including but not limited to the New York State Historic Preservation
Officer for NRHP-listed or -eligible historic properties; consultation with the National Park
Service for National Historic Landmarks (NHLs) and National Natural Landmarks (NNLs);
consultation with the U.S. Fish and Wildlife Service for National Wildlife Management Areas;
consultation with the NYSDOT for state-designated Scenic Byways, etc.; and consultation with
local (town, county, or regional) agencies for locally designated visual resources or visually
sensitive areas that were identified on the EAF.
7.9.1

Design and Siting Measures

Design and siting measures, as described in NYSDEC DEP-00-2, would typically consist of
screening, relocation, camouflage or disguise, maintaining low facility profiles, downsizing the
scale of a project, using alternative technologies, using non-reflective materials, and controlling
off-site migration of lighting (NYSDEC 2000). These various design and siting techniques are
summarized below.
•

Screening. Screening uses natural or man-made objects to conceal other objects from
view; these objects may be constructed of any material that is opaque.

•

Relocation. Relocation consists of moving facilities or equipment within a site to take
advantage of the mitigating effects of topography and/or vegetation.

•

Camouflage or disguise. Camouflage or disguise consists of using forms, colors,
materials, and patterns to minimize or mitigate visual impacts.

•

Low profiles. The use of low profiles consists of reducing the height of on-site objects
to minimize their visibility from surrounding viewsheds.

•

Downsizing. Downsizing consists of reducing the number, areas, or density of objects on
a site to minimize their visibility from surrounding viewsheds.

•

Alternative technologies. The use of alternative technologies consists of substituting
one technology for another to reduce impacts.

Final SGEIS 2015, Page 7-121

 •

Non-reflective materials. The use of non-reflective, materials consists of using
materials that do not shine or reflect light into surrounding viewsheds.

•

Lighting. Lighting should be the minimum necessary for safe working conditions and
for public safety, and should be sited to minimize off-site light migration, glare, and ‘sky
glow’ light pollution.

Design and siting measures are the simplest and most effective methods for avoiding,
minimizing, or mitigating direct and indirect impacts on visual resources or visually sensitive
areas. For example, the state has determined that surface drilling would be prohibited on stateowned land, including reforestation areas and wildlife management areas, which would include
many of the types of visual resources or visually sensitive areas discussed in Section 2.3.
Implementing this siting measure would result in the exclusion from surface drilling of many
resources and areas that may be designated or used, in part or in whole, for their scenic qualities,
thereby decreasing the potential for direct visual impacts of surface drilling on such resources or
areas. The implementation of design and siting measures would also minimize indirect impacts
on visual resources or visually-sensitive areas that are outside of, but in close proximity to, areas
where drilling is proposed.
Additional use of design and siting measures to avoid, reduce, or mitigate visual impacts would
typically be implemented during the construction, development, and production phases of a well
site. These measures could be used individually or in combination as determined appropriate
and feasible by Department staff and well operators.
For example, the use of multi-well pads for horizontal drilling and hydraulic fracturing is a
design and siting measure that incorporates both relocation and downsizing techniques by
installing more than one well in one location. The benefit of the multi-well pad is that it
decreases the overall number of pads in the surrounding landscapes, which would result in the
decreased potential for impacts on visual resources or visually sensitive areas during the
construction, development, production, and reclamation phases.
The use of horizontal drilling and high-volume hydraulic fracturing is a design and siting
measure that incorporates the use of alternative technology to extract natural gas from the
prospective Marcellus and Utica Shale region. The benefit of horizontal drilling and high-

Final SGEIS 2015, Page 7-122

 volume hydraulic fracturing is that it provides flexibility in pad location, such that well pads can
be sited to avoid or minimize the potential for temporary, short-term, and long-term impacts on
visual resources or visually sensitive areas during the construction, development, production, and
reclamation phases (NTC 2011). Such considerations should be reflected in Department
consideration of well pad applications.
The potential benefit of using camouflage or disguise as a design measure to minimize impacts
on visual resources or visually sensitive areas is shown in Photo 7.1 below. This photo shows
fracturing activities on a well site, a phase when well sites are almost entirely filled with on-site
equipment, which represents new landscape features and results in an area that appears visually
prominent in views from nearby vantage points. Although the fracturing phase of development
is considered temporary and periodic (as described in Table 6.53), it would be possible to
minimize visual impacts during fracturing activities that might occur in the spring, summer, or
fall by requiring on-site water storage tanks (the red tanks in Photo 7.1) to be a green color to
mimic surrounding conditions. This would reduce the prominence of the tanks in the
surrounding landscape during seasons when visual resources or visually sensitive areas are
typically visible to the greatest numbers of the viewing public.
The 2010 visual impact assessment (Upadhyay and Bu 2010) evaluated the effectiveness of
implementing certain design and siting techniques as measures to mitigate visual impacts. Using
aerial photograph interpretation, the authors suggested that reducing the size of the well pad
(downsizing) after drilling (the development phase) was complete could result in reduced sitespecific visual impacts from surrounding vantage points and that reducing the density of multiple
well pads in an area could result in reduced visual impacts within a larger area or region (e.g.,
within a county). Their study further suggested that the following design and siting measures
would avoid or minimize visual impacts from surrounding vantage points: relocating well sites to
avoid ridgelines or other areas where aboveground equipment and facilities breaks the skyline;
and minimizing off-site light migration by using night lighting only when necessary and using
the minimum amount of nighttime lighting necessary, directing lighting downward instead of
horizontally, and using light fixtures that control light to minimize glare, light trespass (off-site
light migration), and light pollution (sky glow) (Upadhyay and Bu 2010).

Final SGEIS 2015, Page 7-123

 Photo 7.1 - View of a well site during the fracturing phase of development,
with maximum presence of on-site equipment. (New August 2011)

A tourism study (Rumbach 2011) prepared for the Southern Tier Central (STC) Regional
Planning and Development Board suggests that visual impacts from horizontal drilling and
hydraulic fracturing could be most effectively addressed during the siting and design phases by
ensuring that well pads are designed and located in ways that minimize potential impacts on
visual resources or visually sensitive areas to the extent practicable. The study also encourages
the inclusion of visual impact mitigation conditions, developed in accordance with NYSDEC
DEP-00-2, in permits when visual resources may be impacted. The study also recommends the
development of a best practices manual for Department staff and the industry, which would
provide information on what is expected by the Department in terms of well siting and visual
mitigation, and the identification of instances where visual mitigation may be necessary.
Additional recommendations included encouraging local agencies (towns, counties, and regions)
to identify areas of high visual sensitivity, which may require additional visual mitigation, and to
develop a feedback mechanism in the project review process to confirm the success of measures

Final SGEIS 2015, Page 7-124

 to avoid, minimize, or mitigate visual impacts, based on the analysis of results for prior projects
(Rumbach 2011).
7.9.2

Maintenance Activities

The maintenance activities described in NYSDEC DEP-00-2 should be implemented to prevent
project facilities from becoming “eyesores.” Such measures would typically consist of
appropriate mowing or other measures to control undesirable vegetation growth; erosion control
measures to prevent migration of dust and/or water runoff from a site; measures to control the
off-site migration of refuse; and measures to maintain facilities in good repair and as organized
and clean as possible according to the type of project (NYSDEC 2000).
Maintenance activities to avoid, reduce, or mitigate visual impacts would typically be
implemented during the development and production phases for well sites. Facilities should be
maintained in good repair and as organized and clean as possible.
Upadhyay and Bu’s visual impact assessment evaluated the effectiveness of site restoration to
minimize visual impacts on surrounding landscapes. Their definition of site restoration as a
mitigation measure, defined as restoring drilling pads to their original condition after drilling and
hydraulic fracturing activities (i.e., the development phase) are completed, is similar in concept
to the NYSDEC DEP-00-2 definition of maintenance activities as a mitigation measure. Their
conclusion was that site restoration following drilling and hydraulic fracturing activities was an
effective way to reduce adverse visual impacts of producing well sites within the existing
landscape. With appropriate site restoration, well sites in the production phase, when activity is
minimal and there are only a few relatively unobtrusive aboveground structures on site, are not
prominent features within the surrounding landscape (Upadhyay and Bu 2010).
7.9.3

Decommissioning

The decommissioning activities described in NYSDEC DEP-00-2 should be implemented when
the useful life of the project facilities is over; these activities would typically occur during the

Final SGEIS 2015, Page 7-125

 reclamation phase for well sites. 505 Such activities would typically consist of, at a minimum, the
removal of aboveground structures at well sites. Additional decommissioning activities that may
also be required include: the total removal of all facility components at a well site (aboveground
and underground) and restoration of a well site to an acceptable condition, usually with attendant
vegetation and possibly including recontouring to reestablish the original topographic contours;
the partial removal of facility components, such as the removal or other elimination of structures
or features that produce visual impacts (such as the restoration of water impoundment sites to
original conditions); and the implementation of actions to maintain an abandoned facility and site
in acceptable condition to prevent the well site from developing into an eyesore, or prevent site
and structural deterioration (NYSDEC 2000).
The tourism study prepared for the STC (Rumbach 2011) discusses additional measures that
could be implemented during the reclamation phase to mitigate visual impacts. These measures,
which would be applied to all well pads, include the application of specific procedures identified
in the 1992 GEIS for topsoil conservation and redistribution in agricultural districts. These
procedures include stripping off and stockpiling topsoil during construction; protecting
stockpiled topsoil from erosion and contamination; cutting well casings to a safe buffer depth of
4 feet below the ground surface; preparing areas before topsoil redistribution if compaction has
occurred on-site; and redistributing the topsoil over the disturbed area of the former well pads
during reclamation (Rumbach 2011).
7.9.4

Offsetting Mitigation

The offsetting mitigation described in NYSDEC DEP-00-2 should be implemented when the
impacts of well sites on visual resources or visually sensitive areas are significant and when such
impacts cannot be avoided by locating the well pad in an alternate location. Per guidance in
NYSDEC DEP-00-2, offsetting mitigation would consist of the correction of an existing
aesthetic problem identified within the viewshed of a proposed well project. Thus, a decline in
the landscape quality that would result from development of a proposed well site could, at least
partially, be ‘offset’ by the correction. An example of offsetting mitigation might be the removal
505

Although substantial equipment and activity would be present at well sites during the construction and development phases,
such equipment and activities are temporary. Once construction and well development is completed, some activities would
cease and some equipment would be removed, and these are not considered to be decommissioning activities.

Final SGEIS 2015, Page 7-126

 of an existing abandoned structure that is in disrepair (i.e., an ‘eyesore’) to offset impacts from
the development of a well site within visual proximity to the same sensitive visual resource
(NYSDEC 2000). Offsetting mitigation should be employed only when significant
improvements in visually sensitive locations can be expected at a reasonable cost (NYSDEC
2000).
7.10

Noise Mitigation Measures 506

Noise is best mitigated by increasing distance between the source and the receiver; the greater
the distance the lower the noise impact. The second level of noise mitigation is direction.
Directing noise-generating equipment away from receptors greatly reduces associated impacts.
Timing also plays a key role in mitigating noise impacts. Scheduling the more significant noisegenerating operations during daylight hours provides for tolerance that may not be achievable
during the evening hours.
7.10.1 Pad Siting Equipment, Layout and Operation
Many of the potential negative impacts of gas development depend on the location chosen for the
well pad and the techniques used in constructing the access road and well site. Before a drilling
permit can be issued, Department staff must ensure that the proposed location of the well and
access road complies with the Department’s spacing regulations and siting restrictions. To assist
in this process, Department staff will rely on Policy Guidance Document DEP-00-1, “Assessing
and Mitigating Noise Impacts.”
The benefits of a multi-well pad are the reduced number of sites generating noise and, with the
horizontal drilling technology, the flexibility to site the pad in the best location to mitigate the
impacts. As described above and in more detail in Subsection 5.1.4.2, current regulations allow
for a single well pad per 40-acre spacing unit, one multi-well pad per 640-acre spacing unit, or
various other combinations. This provides the potential for one multi-well pad to recover the
resource in the same area that could contain up to 16 single well pads.

506

Section 7.10, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011 and was adapted by
the Department.

Final SGEIS 2015, Page 7-127

 With proper pad location and design, the adverse noise impacts could be significantly reduced.
A multi-well pad provides a platform to extract gas over a wider area than the area exploited by a
single vertical well. This provides an opportunity to locate the multi-well pad away from a noise
receptor and in a location where there is intervening topography and vegetation, which can
reduce the noise level at the receptor location to a level below that which might result from
several single-well pads in close proximity to the receptor location.
Multi-well pads also have the potential to greatly reduce the amount of trucking and associated
noise in an area. Rigs and equipment may only need to be delivered and removed one time for
the drilling and stimulation of all of the wells on the pad. Reducing the number of truck trips
required for fracturing water is also possible by reusing water for multiple fracturing jobs. In
certain instances, it also may be economically viable to transport water via pipeline to a multiwell pad.
7.10.2 Access Road and Traffic Noise
As noted, high-volume hydraulic fracturing results in a greater number of heavy truck trips to the
well pad compared to conventional drilling. Given the extensive trucking and associated noise
involved with water transportation for high-volume hydraulic fracturing, attention should be
given to the location of access road(s). Where appropriate, roads should be located as far as
practicable from occupied structures and places of assembly. This would serve to protect noise
receptors from noise impacts associated with trucking and road construction that could conflict
with their property use.
Traffic noise mitigation measures may include modification of speed limits and restricting or
prohibiting truck traffic on certain roads. Restricting truck use on a given roadway would reduce
noise levels at nearby receptors, since trucks are louder than cars. However, displacing truck
traffic from one roadway to another would shift noise impacts from one area to another. While
reducing speeds may reduce noise levels, a reduction of at least 10 mph is needed to achieve a
noticeable difference in noise level.

Final SGEIS 2015, Page 7-128

 7.10.3 Well Drilling and Hydraulic Fracturing
As discussed in the 1992 GEIS (NYSDEC 1992), moderate to significant noise impacts may be
experienced within 1,000 feet of a well site during the drilling phase. With the extended duration
of drilling and other activities involved with multi-well pads, the Department will review the
location of multi-well pads closer than 1,000 feet to occupied structures and places of assembly
and determine what mitigation is necessary to minimize impacts.
Once the location and layout of a drilling site have been established and prior to the execution of
the drilling project, noise modeling should be required using commercially available noise
modeling software for any site located within 1,000 feet of a noise receptor. The software should
be capable of simulating the three-dimensional outdoor propagation of sound from each noise
source and account for sound wave divergence, atmospheric and ground sound absorption, and
sound attenuation due to interceding barriers and topography. The effect of topography on noise
propagation would be an important factor in the areas where drilling to access the Marcellus and
Utica Shales would likely occur. The results of the modeling should be used by the applicant to
evaluate noise levels that would be experienced at the nearest noise receptors and to develop
mitigation measures for use in controlling noise levels generated during drilling and hydraulic
fracturing of the well(s).
Examples of noise mitigation techniques that can be implemented as site-specific permit
conditions include the following, as practicable:
•

Requiring the measurement of ambient noise levels prior to beginning operations;

•

Specifying daytime and nighttime noise level limits as a permit condition and periodic
monitoring thereof;

•

Placing tanks, trailers, topsoil stockpiles, or hay bales between the noise sources and
receptors;

•

Using noise-reduction equipment such as hospital-grade mufflers, exhaust manifolds, or
other high-grade baffling;

•

Limiting drill pipe cleaning (“hammering”) to certain hours;

•

Running of casing during certain hours to minimize noise from elevator operation;

Final SGEIS 2015, Page 7-129

 •

Placing air relief lines and installing baffles or mufflers on lines;

•

Limiting cementing operations to certain hours (i.e., perform noisier activities, when
practicable, after 7 A.M. and before 7 P.M.);

•

Using higher or larger-diameter stacks for flare testing operations;

•

Placing redundant permanent ignition devices at the terminus of the flow line to minimize
noise events of flare re-ignition;

•

Providing advance notification of the drilling schedule to nearby receptors;

•

Placing conditions on air rotary drilling discharge pipe noise, including:
o Orienting high-pressure discharge pipes away from noise receptors;
o Having the air connection blowdown manifolded into the flow line. This would
provide the air with a larger-diameter aperture at the discharge point;
o Having a 2-inch connection air blowdown line connected to a larger-diameter line
near the discharge point or manifolded into multiple 2-inch discharges;
o Shrouding the discharge point by sliding open-ended pieces of larger-diameter
pipe over them; or
o Rerouting piping so that unusually large compressed air releases (such as
connection blowdown on air drilling) would be routed into the larger-diameter pit
flow line to muffle the noise of any release;

•

Using rubber hammer covers on the sledges when clearing drill pipe;

•

Laying down pipe during daylight hours;

•

Scheduling drilling operations to avoid simultaneous effects of multiple rigs on common
receptors;

•

Limiting hydraulic fracturing operations to a single well at a time;

•

Employing electric pumps; and

Final SGEIS 2015, Page 7-130

 •

Installing temporary sound barriers (see Photo 7.2, Photo 7.3, and Photo 7.4) of
appropriate heights, based on noise modeling, around the edge of the drilling location
between a noise generating source and any sensitive surroundings. Sound control
barriers should be tested by a third-party accredited laboratory to rate Sound
Transmission Coefficient (STC) values for comparison to the lower-frequency drilling
noise signature.

Many of these mitigation techniques have been successfully applied at wells drilled in New York
Photo 7.2 - Sound Barrier. Source: Ground Water Protection Council, Oklahoma City,
OK and ALL Consulting, Tulsa OK, 2009 (New August 2011)

Source: Penn State Cooperative Extension

Final SGEIS 2015, Page 7-131

 Photo 7.3 - Sound Barrier Installation (New August 2011)

Photo 7.4 - Sound Barrier Installation (New August 2011)

Final SGEIS 2015, Page 7-132

 7.10.4 Conclusion
As discussed in the 1992 GEIS (NYSDEC 1992), temporary, short-term noise impacts may vary,
based on the presence of topographic barriers (e.g., hills) or vegetative barriers (e.g., hills, trees,
tall grass, shrubs). Drilling and hydraulic fracturing operations are the noisiest phase of
development and usually continue 24 hours a day. Noise sources during the drilling phase
include various drilling rig operations, pipe handling, compressors, and the operation of trucks,
backhoes, tractors, and cement mixers. During hydraulic fracturing, the primary source of noise
is the multiple fracturing fluid pumps operating simultaneously. In most instances, the closest
receptor is the residence of the owner of the property where the well is located, and the owner
will have agreed to the disturbance by entering into a voluntary lease agreement with the well
operator. However, this may not always be the case, due to compulsory integration and other
circumstances. Noise impacts can be reduced, when necessary, at nearby receptors (regardless of
lease status) by a combination of setbacks, site layout to take advantage of existing topography,
implementation of noise barriers, and special permit conditions.
The 1992 GEIS (NYSDEC 1992) indicated that there were unavoidable adverse noise impacts
for those living in proximity to a drill site. These were determined to be short term and could be
mitigated with siting restrictions and setback requirements. Given that the types of noise impacts
associated with horizontal drilling with high-volume hydraulic fracturing have been found to be
similar to those for vertical drilling, these findings are also applicable to horizontal drilling and
high-volume hydraulic fracturing. The extended time period for horizontal drilling with highvolume hydraulic fracturing, while still temporary, makes the control of noise impacts essential.
Since noise control is most effectively addressed during the siting and design phase, it is
important that the pad be properly located and planned, and horizontal drilling provides the
flexibility to accommodate this need. The Department’s guidance document DEP-00-01,
“Assessing and Mitigating Noise Impacts,” should be utilized along with a site plan and noise
modeling (when the well pad is to be located within 1,000 feet of occupied structures or places of
assembly) for this purpose. In addition, the applicant is encouraged to review any applicable
local land use policy documents with the understanding that NYSDEC retains authority to
regulate gas development (NTC 2011).

Final SGEIS 2015, Page 7-133

 Supplementary permit conditions for high-volume hydraulic fracturing would include the
following requirements to mitigate potential noise impacts:
•

Unless otherwise required by private lease agreement, the access road must be located as
far as practicable from occupied structures, places of assembly, and occupied but
unleased property; and

•

The well operator must operate the site in accordance with a noise impacts mitigation
plan consistent with the SGEIS.

The operator’s noise impacts mitigation plan shall be provided to the Department along with the
permit application. Additional site-specific noise mitigation measures will be added to
individual permits if a well pad is located within 1,000 feet of occupied structures or places of
assembly.
7.11

Transportation Mitigation Measures 507

The transportation of water, hydraulic fracturing materials, and liquid wastes appears to account
for well over 90% of all heavy truck traffic from a gas well over its productive life. Mitigating
measures can help prevent, reduce or compensate for the potentially significant adverse impacts
resulting from the increased transportation and road use related to vehicular traffic necessary for
horizontal drilling and high-volume hydraulic fracturing. These are summarized by potential
impact category as described in Section 6.11.
7.11.1 Mitigating Damage to Local Road Systems
As discussed in Section 6.11, the majority of impacts on roads would occur on local roads near
the wells. The following measures would address impacts of increased transportation,
particularly by heavy trucks, on local road systems.
7.11.1.1 Development of Transportation Plans, Baseline Surveys, and Traffic Studies
The Department would require, as part of any permit application, that the applicant submit a
transportation plan. The transportation plan would identify the number of anticipated truck trips
to be generated by the proposed activity; the times of day when trucks are proposed to be
507

Section 7.11, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011 and was adapted by
the Department.

Final SGEIS 2015, Page 7-134

 operating; the proposed routes for such truck trips; the locations of, and access to and from,
appropriate parking/staging areas; and the ability of the roadways located on such routes to
accommodate such truck traffic. The transportation plan would also identify whether the
operator has entered into a road use agreement or agreements with local governments and the
condition of roads and bridges that are expected to be used by trucks directly and indirectly
associated with the drilling operation. No permit should be issued until the Department and the
NYSDOT are satisfied that the Transportation Plan is adequate to ensure that the traffic
associated with the activity can be conducted safely and would reduce the impacts from truck
traffic on local road systems to the maximum extent feasible.
It is important that the Transportation Plan evaluate pre-impact conditions so that any potential
damages to roads and infrastructure can be fairly assessed. Establishing an accurate assessment
of current conditions by conducting a baseline survey can be beneficial to both the local
municipality and the operator; such baseline surveys should include information for local, state
and interstate roads. State and interstate highways are surveyed annually and state secondary
roads are surveyed every two years (NYSDOT 2010). However, local municipalities may not
have the funds, equipment, or staff to survey local roads on a regular basis. Therefore, it would
be the responsibility of the operator to conduct a baseline survey of local roads in accordance
with methods described in the NYS traffic survey methods manual (NYSDOT 2010).
The results of a baseline survey of local road conditions should be combined with an assessment
of the existing heavy truck traffic on the local roads and the relative amount of project-related
traffic to develop a road condition study. This road condition study would be used to assess the
proportion of the cost of road repairs that would be the responsibility of the operator. For
example, if the road condition study concludes that the well operator would double the existing
heavy truck traffic, and the road condition study indicates that a deterioration of pavement
condition during the heavy traffic period of the project would occur, then the operator would be
required to have an agreement in place to pay for the work required to repair or prevent the road
deterioration.

Final SGEIS 2015, Page 7-135

 7.11.1.2 Municipal Control over Local Road Systems
Under NYS highway vehicle traffic laws, local municipalities retain control over their roads, and
as such, can implement measures to prevent or minimize transportation impacts. For example,
NYS Vehicle and Traffic Law § 1640(a)(5) provides that, “The legislative body of any city or
village, with respect to highways … in such city or village … may by local law, ordinance,
order, rule or regulation … exclude trucks, commercial vehicles, tractors, tractor-trailer
combinations, [and] tractor-semitrailer combinations from highways specified by such legislative
body.” Part 10 of this same section allows legislative bodies of a city or village to “establish a
system of truck routes upon which all trucks, tractors and tractor-trailer combinations, having a
gross weight in excess of ten thousand pounds are permitted to travel and operate and excluding
such vehicles and combinations from all highways except those which constitute such truck route
system.” Part 20 of this same section allows for the establishment of weight, height, length, and
width criteria, for which vehicles in excess of such standards may be excluded from highways or
the setting of limits on hours of operation of such vehicles on particular city or village highways
or segments of such highways. Essentially, NYS Vehicle and Traffic Law §1640(a) (5), (10),
and (20) allow local governments to establish regulations pertaining to the use of city or town
highways by trucks, tractor trailers, etc., and to exclude such vehicles from use of city or town
highways as may be delineated by the local legislative body.
In addition to city and village ordinances or rules that may govern the use of highways within a
city or village, NYS Vehicle and Traffic Law § 1650(4)(a) provides that “the county
superintendent of highways of a county with respect to county roads in such county, may by
order, rule or regulation: … exclude trucks, commercial vehicles, tractors, etc. in excess of
designated weight, length, height and width from county highways, or set limits of hours of
operation for such vehicles.” This is essentially the same legislative authority given to cities and
villages in Vehicle and Traffic Law §1640, except this pertains to counties. The same is true of
Vehicle and Traffic Law § 1660(a) (10), (11), (17), and (28), which allow for the same exclusion
of trucks, tractors, tractor-trailers, etc., as provided in the previous Articles, except that this
section pertains to the authority of a town’s legislative body. In addition, Town Law § 130 (7)
allows for a town board, after a public hearing, to enact, amend, or repeal ordinances, rules, and

Final SGEIS 2015, Page 7-136

 regulations pertaining to the use of streets, highways, sidewalks, and public places by
pedestrians, motor and other vehicles, and restrict parking of all vehicles therein.
As noted above, municipalities would be notified of applications that indicate that high-volume
hydraulic fracturing is planned. In addition, municipalities should monitor the Department’s
Web site for additional information regarding gas development in their areas. In light of their
substantial authority over access to local roads, local governments (county, town, and village)
would likely be proactive in exercising their authority under NYS highway vehicle traffic laws.
This would include requiring a local road use agreement (discussed below), taking into account
the required road condition study, which would provide the basis for potentially assessing fees
for maintenance and improvements to local roads.
7.11.1.3 Road Use Agreements
As stated above in Section 7.11.1.2, local governments have the authority to enter into road use
agreements with well operators, which identify where an operator may or may not drive trucks,
weight limits, times of day, etc. Therefore, the owner or operator should attempt to obtain a road
use agreement with the appropriate local municipality; if such an agreement cannot be reached,
the reason(s) for not obtaining one must be documented in the Transportation Plan. The owner
or operator would also have to demonstrate that, despite the absence of such agreement, the
traffic associated with the activity can be conducted safely and that the owner or operator would
reduce the impacts from truck traffic on local road systems to the maximum extent feasible.
The road use agreement would be the primary mechanism by which local governments can hold
well operators accountable for damages and repairs to roads, bridges, and drainage structures that
may be impacted by their excess use. When utilized appropriately, this mechanism has proven
effective with wind developers in New York State.
Measures that should be part of a road use agreement or trucking plan, as appropriate, include:
•

Route selection to maximize efficient driving and public safety, pursuant to city or town
laws or ordinances as may have been enacted under Vehicle and Traffic Law
§1640(a)(10);

Final SGEIS 2015, Page 7-137

 •

Avoidance of peak traffic hours, school bus hours, community events, and overnight
quiet periods, as established by Vehicle and Traffic Law §1640(a)(20);

•

Coordination with local emergency management agencies and highway departments;

•

Upgrades and improvements to roads that will be traveled frequently for water transport
to and from many different well sites, as may be reimbursable pursuant to ECL
§23-0303(3);

•

Advance public notice of any necessary detours or road/lane closures;

•

Adequate off-road parking and delivery areas at the site to avoid lane/road blockage; and

•

Use of rail or temporary pipelines where feasible to move water to and from well sites.

Supplementary permit conditions for high-volume hydraulic fracturing would re-emphasize that
issuance of a well permit does not provide relief from any local requirements authorized by or
enacted pursuant to the Vehicle and Traffic Law. Such permit conditions would also require the
following:
1. Prior to site disturbance, the operator shall submit to the Department and provide a copy
to the NYSDOT of any road use agreement between the operator and local municipality;
and
2. The operator shall file a transportation plan, which shall be incorporated by reference into
the permit; the plan will be developed by a NYS-licensed Professional Engineer in
consultation with the Department and will verify the existing condition and adequacy of
roads, culverts, and bridges to be used locally.
When there is no agreement, the applicant should nevertheless be guided by Environmental
Conservation Law (ECL) § 23-0303(2), which provides that “this article shall supersede all local
laws or ordinances relating to the regulation of the oil, gas and solution mining industries; but
shall not supersede local government jurisdiction over local roads or the rights of local
governments under the real property tax law.” This gives local municipalities the authority to
designate and enforce vehicle and traffic laws pertaining to the use of local roads by motor
vehicles, including trucks engaged in activities connected to gas drilling.

Final SGEIS 2015, Page 7-138

 7.11.1.4 Reimbursement for Costs Associated with Local Road Work
Under Highway Law § 136 (2), “a county superintendent shall establish regulations governing
the issuance of highway work permits, including the fees to be charged therefor, a system of
deposits of money or bonds guaranteeing the performance of the work and requirements of
insurance to protect the interests of the county during performance of the work pursuant to a
highway work permit.” It is through this legislation that a county is able to financially mitigate
impacts on roads and highways caused by roadwork associated with well development, but this
law would not provide for payments for damages to roads from excess use.
7.11.2 Mitigating Incremental Damage to the State System of Roads
Truck traffic on the interstate highway system and other regional roads would also suffer wear
and tear due to the added traffic associated with horizontal drilling and high-volume hydraulic
fracturing. Given the potentially dramatic increase in the number of large trucks and their
distribution in the high-volume hydraulic fracturing region, a significant expansion in truck
inspection requirements would be expected. This would require close coordination with other
organizations, including local municipalities and the State Police. There is likely to be a
substantial increase in oversize/overweight permitting requests, which may require additional
permit staff at NYSDOT to handle these requests.
In addition, the installation of associated infrastructure, such as gas and water pipeline
expansions and extensions, would require highway work permits, resulting in additional
management, oversight, and inspection services by NYSDOT staff. Local municipalities would
also likely see a sharp increase in their transportation-related staffing needs and budgets. These
additional needs would include staff to carry out or oversee road condition surveys, traffic counts
(or studies), local road and detour postings, execution of Road Use or Excess Maintenance
agreements, and other activities. Personnel and resources would be necessary to monitor road
conditions, manage and enforce agreements, and provide regulatory and emergency services.
State permit regulations could be developed that assess mitigation fees as a permit condition to
defray some of these new costs. Other state revenue sources and mechanisms for collecting fees
to address damages and wear to the state system of roads would include contributions to the

Final SGEIS 2015, Page 7-139

 Highway and Bridge Conservation Fund, the collection of heavy vehicle registration fees, tolls
and other highway use taxes, petroleum business taxes, and motor fuel taxes.
However, the revenue that is currently collected to compensate the state for damages to the state
system of roads is deemed by NYSDOT to be insufficient for addressing required roadway
maintenance. Thus, the added burden of the potential adverse impacts on the state system of
roads associated with the proposed development of natural gas reserves using high-volume
hydraulic fracturing may pose an additional financial burden on the state, which would be
considered an adverse impact that may not be fully mitigated.
7.11.3 Mitigating Operational and Safety Impacts on Road Systems
Where appropriate, site-specific mitigation of safety impacts would be applied to each
applicant’s permit. These would include, but are not limited to, the following:
•

Limiting truck weight, axle loading, and weight during seasons when roads are most
sensitive to damage from trucking (e.g., during periods of frost heaving and high runoff);

•

Requiring the operator to pay for the addition of traffic control devices or trained traffic
control agents at peak times at identified problem intersections or road segments;

•

Providing industry-specific training to first responders to prepare for potential accidents;

•

Road use agreements limiting heavy truck traffic to off-hour periods, to the extent
feasible, to minimize congestion;

•

Providing a safety and operational review of the proposed routes, which may include
commitments to providing changes to geometry, signage, and signaling to mitigate safety
risks or operational delays; and

•

Avoiding hours and routes used by school buses.

Due to the generic nature of this analysis and the unknown road segments where these heavyand light-duty trucks would travel, it is not possible at this time to identify specific operational
and safety impacts, nor is it possible to identify operational or safety mitigation strategies for
specific locations.
As noted in Section 7.8 (Socioeconomic Mitigation Measures), through its permitting process,
the Department will monitor the pace and concentration of development throughout the state to

Final SGEIS 2015, Page 7-140

 mitigate adverse impacts at the local and regional levels. The Department will consult with local
jurisdictions, as well as applicants, to reconcile the timing of development with the needs of the
communities. Where appropriate the Department would impose specific construction windows
within well construction permits in order to ensure that drilling activity and its cumulative
adverse socioeconomic effects are not unduly concentrated in a specific geographic area. Those
measures, designed to mitigate socioeconomic impacts and impacts on community character, can
also be employed to minimize operational and safety impacts where such impacts are identified.
7.11.4 Other Transportation Mitigation Measures
High-volume hydraulic fracturing is a relatively new and evolving technology, and the industry
is exploring a variety of alternatives that could substantially reduce the need for and impacts of
heavy trucks. Potential future alternatives include innovative methods of hydraulic fracturing
such as the use of natural gas gels, which might entirely eliminate the need for trucking water to
well sites; and innovative water supply systems such as the construction of water wells serving
multiple well pads via a piping system, which would reduce the need for trucking water to well
sites. On-site treatment and disposition of wastes is another potential alternative that could
reduce the need for trucking. For example, Chesapeake Energy has eliminated the trucking of
wastes from well sites through on-site treatment and disposition in the Marcellus Shale area in
Pennsylvania. If this practice were extended to other gas development companies operating in
other areas with gas-producing shales, such as the Marcellus and Utica Shales in New York, it
would result in similar substantial reductions in the need for trucking.
7.11.5 Mitigating Impacts from the Transportation of Hazardous Materials
Preliminary data has been provided to the Department outlining the typical components of the
fracturing fluids to be used in the state. The operator will provide specific information on the
types and quantities of hazardous materials expected to be transported through the jurisdictions
that they will be operating in and brought on site as part of the permitting process.
Specific information on the transportation of these materials is presented in Section 5.5. In
summary, all fracturing fluids and additives are transported in “DOT-approved” trucks or
containers. The federal Hazardous Material Transportation Act (HMTA) and Hazardous
Materials Transportation Uniform Safety Act (HMTUSA) are the basis for federal hazardous

Final SGEIS 2015, Page 7-141

 materials transportation law and give regulatory authority to the Secretary of the USDOT to
enforce the regulations. These extensive regulations address the potential concerns involved in
transporting hazardous fracturing additives, including loading, unloading, shipping, and
packaging. These regulations are enforced by the USDOT agencies and, when followed and
enforced, can mitigate risks.
The NYSDOT requires all registrants of commercial motor vehicles to obtain a USDOT number
and has adopted many USDOT regulations that apply to interstate highway transportation. There
are minor exceptions to these federal regulations; however, the exemptions do not directly relate
to the objectives of this review. New York State regulations include motor vehicle carriers that
operate solely on an intrastate basis. These carriers must comply with 17 NYCRR Part 820 (as
described in Section 8.1.2.2) in addition to the applicable requirements and regulations of the
Vehicle and Traffic Law and the NYS Department of Motor Vehicles. This includes regulations
requiring carriers to obtain authorization to transport hazardous materials from the USDOT or
NYSDOT Commissioner.
Municipalities may require trucks transporting hazardous materials to travel on designated
routes, in accordance with a road use agreement; however, this would not eliminate entirely the
potential for an accidental release. Depending on its size and location, a spill could have a
significant adverse impact on the local community. First responders and emergency personnel
would need to be aware of hazardous materials being transported in their jurisdiction and also be
properly trained in case of an emergency involving these materials. Permit conditions may
require the operator to provide first responder emergency response training specific to the
hazardous materials to be used in the drilling process if a review of existing resources indicates
such a need, and transportation plans may provide that sensitive locations be avoided for trucks
carrying hazardous materials.
7.11.6 Mitigating Impacts on Rail and Air Travel
The potential impacts on the rail industry would be positive. Growth in haulage, and
consequently in revenues and employment, would likely occur. However, as evidenced in
Pennsylvania, infrastructure would need to be improved (e.g., tracks extended, rail yards
expanded, new sidings/offloading facilities provided at appropriate locations, etc.). The potential

Final SGEIS 2015, Page 7-142

 adverse impacts of increased traffic on the existing rail facilities could be mitigated by the
construction of new facilities. The majority of financing for improvements is provided by the
rail companies or through partnerships and investment partnerships with major users. At the
same time, there can be a significant demand for public investment as well. The variety of
financing and investment instruments can be drawn from Pennsylvania’s experience, for example
SEDA-COG Joint Railway Authority, which financed roughly $16 million of projects in six
counties through a combination of USDOT grants ($10 million), a $3.8 million PennDOT grant,
and a $2.2 million public-private partnership.
7.12

Community Character Mitigation Measures 508

Local and regional planning documents are important in defining a community’s character and
are the principal way of managing change within a community. These plans are used to guide
development and provide direction for land development regulations (e.g., zoning, noise control,
and subdivision ordinances) and designation of special districts for economic development,
historic preservation, and other reasons.
As discussed in Chapter 3, the Department would require the applicant to prepare an EAF
Addendum for gathering and compiling the information needed to evaluate high-volume
hydraulic fracturing projects (≥300,000 gallons) in the context of this SGEIS and its Findings
Statement, and to identify the required site-specific mitigation measures.
The EAF Addendum would be required as follows:

508

•

With the application to drill the first well on a pad constructed for high-volume hydraulic
fracturing, regardless of whether the well is vertical or horizontal;

•

With the applications to drill subsequent wells for high-volume hydraulic fracturing on
the pad if any of the information changes; and

•

Prior to high-volume re-fracturing of an existing well.

Section 7.12, in its entirety, was provided by Ecology and Environment Engineering, P.C., August 2011 and was adapted by
the Department.

Final SGEIS 2015, Page 7-143

 The EAF Addendum would require the applicant to identify whether the location of the well pad,
or any other activity under the jurisdiction of the Department, conflicts with local land use laws,
regulations, plans, or policies. The applicant would also be required to identify whether the well
pad is located in an area where the affected community has adopted a comprehensive plan or
other local land use plan and whether the proposed action is inconsistent with such plan(s).
Where the project sponsor indicates that the location of the well pad, or any other activity under
the jurisdiction of the Department, is either consistent with local land use laws, regulations,
plans, or policies, or is not covered by such local land use laws, regulations, plans, or policies, no
further review of local land use laws and policies would be required.
In cases where a project sponsor indicates that all or part of their proposed application is
inconsistent with local land use laws, regulations, plans, or policies, or where the potentially
impacted local government advises the Department that it believes the application is inconsistent
with such laws, regulations, plans, or policies, the Department intends to request additional
information in the permit application to determine whether this inconsistency raises significant
adverse environmental impacts that have not been addressed in the SGEIS.
The Department notes, that recently the New York Court of Appeals in Matter of Wallach v.
Town of Dryden et al., 23 N.Y.3d 728 (2014), found that ECL Section 23-0303(2) does not
preempt communities with adopted zoning laws from entirely prohibiting the use of land for
high-volume hydraulic fracturing. In that decision, the Court noted that: “Manifestly, Dryden
and Middlefield engaged in a reasonable exercise of their zoning authority … when they adopted
local laws clarifying that oil and gas extraction and production were not permissible uses in any
zoning districts. The Towns both studied the issue and acted within their home rule powers in
determining that gas drilling would permanently alter and adversely affect the deliberately
cultivated, small-town character of their communities.”
In addition, a supplemental site-specific review is required when an applicant proposes to
construct a well pad on a farm within an Agricultural District when the proposed disturbance is
larger than 2.5 acres. In such cases, the Department would consult with the DAM to develop

Final SGEIS 2015, Page 7-144

 additional permit conditions, best management practice requirements, and reclamation guidelines
to be followed.
Examples of the proposed Agricultural District requirements include but are not limited to the
following:
•

Decompaction and deep ripping of disturbed areas prior to topsoil replacement;

•

Removal of construction debris from the site;

•

No mixing of cuttings with topsoil;

•

Removal of spent drilling muds from active agricultural fields;

•

Location of well pads/access roads along field edges and in nonagricultural areas (where
practicable);

•

Removal of excess subsoil and rock from the site; and

•

Fencing of the site when drilling is located in active pasture areas to prevent livestock
access.

Implementation of these measures would lead to successful reestablishment of agricultural lands
when well pads are no longer productive.
The socioeconomic, visual, noise, and transportation impacts discussed in Sections 6.8, 6.9, 6.10,
and 6.11, respectively, also impact community character. To the extent that these impacts are
mitigated as discussed in Sections 7.8 (Socioeconomic), 7.9 (Visual), 7.10 (Noise), and 7.11
(Transportation), impacts on community character would also be reduced to the extent that the
impacts are related to community character.
7.13

Emergency Response Plan

There is always a risk that despite all precautions, non-routine incidents may occur during oil and
gas exploration and development activities. An Emergency Response Plan (ERP) describes how
the operator of the site will respond in emergency situations which may occur at the site. The
procedures outlined in the ERP are intended to provide for the protection of lives, property, and
natural resources through appropriate advance planning and the use of company and community

Final SGEIS 2015, Page 7-145

 assets. The Department proposes to require supplementary permit conditions for high-volume
hydraulic fracturing that would include a requirement that the operator provide the Department
with an ERP consistent with the SGEIS at least 3 days prior to well spud. The ERP would also
indicate that the operator or operator’s designated representative will be on site during drilling
and/or completion operations including hydraulic fracturing, and such person or personnel would
have a current well control certification from an accredited training program that is acceptable to
the Department.
The ERP, at a minimum, would also include the following elements:
•

Identity of a knowledgeable and qualified individual with the authority to respond to
emergency situations and implement the ERP;

•

Site name, type, location (include copy of 7 ½ minute USGS map), and operator
information;

•

Emergency notification and reporting (including a list of emergency contact numbers for
the area in which the well site is located; and appropriate Regional Minerals’ Office),
equipment, key personnel, first responders, hospitals, and evacuation plan;

•

Identification and evaluation of potential release, fire and explosion hazards;

•

Description of release, fire, and explosion prevention procedures and equipment;

•

Implementation plans for shut down, containment and disposal;

•

Site training, exercises, drills, and meeting logs; and

•

Security measures, including signage, lighting, fencing and supervision.

Final SGEIS 2015, Page 7-146

 Chapter 8
Permit Process and
Regulatory Coordination
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Chapter 8 – Permit Process and Regulatory Coordination
CHAPTER 8 PERMIT PROCESS AND REGULATORY COORDINATION ..................................................................... 8-1
8.1 INTERAGENCY COORDINATION ........................................................................................................................... 8-1
8.1.1 Local Governments .................................................................................................................................... 8-1
8.1.1.1 SEQRA Participation ........................................................................................................................ 8-1
8.1.1.2 NYCDEP ........................................................................................................................................... 8-4
8.1.1.3 Local Government Notification ....................................................................................................... 8-4
8.1.1.4 Road-Use Agreements .................................................................................................................... 8-4
8.1.1.5 Local Planning Documents .............................................................................................................. 8-4
8.1.1.6 County Health Departments ........................................................................................................... 8-5
8.1.2 State........................................................................................................................................................... 8-5
8.1.2.1 Public Service Commission ............................................................................................................. 8-6
8.1.2.2 NYS Department of Transportation ............................................................................................. 8-18
8.1.3 Federal ..................................................................................................................................................... 8-19
8.1.3.1 U.S. Department of Transportation .............................................................................................. 8-19
8.1.3.2 Occupational Safety and Health Administration – Material Safety Data Sheets .......................... 8-21
8.1.3.3 EPA’s Mandatory Reporting of Greenhouse Gases ...................................................................... 8-24
8.1.4 River Basin Commissions ......................................................................................................................... 8-28
8.2 INTRA-DEPARTMENT ..................................................................................................................................... 8-29
8.2.1 Well Permit Review Process .................................................................................................................... 8-29
8.2.1.1 Required Hydraulic Fracturing Additive Information .................................................................... 8-29
8.2.2 Other Department Permits and Approvals .............................................................................................. 8-32
8.2.2.1 Bulk Storage .................................................................................................................................. 8-32
8.2.2.2 Impoundment Regulation ............................................................................................................. 8-33
8.2.3 Enforcement ............................................................................................................................................ 8-42
8.2.3.1 Enforcement of Article 23 ............................................................................................................. 8-42
8.2.3.2 Enforcement of Article 17 ............................................................................................................. 8-44
8.3 WELL PERMIT ISSUANCE ................................................................................................................................. 8-48
8.3.1 Use and Summary of Supplementary Permit Conditions for High-Volume Hydraulic Fracturing ........... 8-48
8.3.2 High-Volume Re-Fracturing ..................................................................................................................... 8-48
8.4 OTHER STATES’ REGULATIONS ......................................................................................................................... 8-49
8.4.1 Ground Water Protection Council ........................................................................................................... 8-51
8.4.1.1 GWPC - Hydraulic Fracturing ........................................................................................................ 8-51
8.4.1.2 GWPC - Other Activities ................................................................................................................ 8-52
8.4.2 Alpha’s Regulatory Survey ....................................................................................................................... 8-53
8.4.2.1 Alpha - Hydraulic Fracturing ......................................................................................................... 8-53
8.4.2.2 Alpha - Other Activities ................................................................................................................. 8-54
8.4.3 Colorado’s Final Amended Rules ............................................................................................................. 8-60
8.4.3.1 Colorado - New MSDS Maintenance and Chemical Inventory Rule ............................................. 8-60
8.4.3.2 Colorado - Setbacks from Public Water Supplies.......................................................................... 8-61
8.4.4 Summary of Pennsylvania Environmental Quality Board. Title 25-Environmental Protection,
Chapter 78, Oil and Gas Wells ................................................................................................................. 8-62
8.4.5 Other States’ Regulations - Conclusion ................................................................................................... 8-62
FIGURES
Figure 8.1- Protection of Waters - Dam Safety Permitting Criteria ......................................................................... 8-35
TABLES
Table 8.1 - Regulatory Jurisdictions Associated with High-Volume Hydraulic Fracturing (Revised July 2011).......... 8-3
Table 8.2 - Intrastate Pipeline Regulation ............................................................................................................... 8-10
Table 8.3 - Water Resources and Private Dwelling Setbacks from Alpha, 2009 ...................................................... 8-59

Final SGEIS 2015, Page 8-i

 This page intentionally left blank.

Chapter 8 PERMIT PROCESS AND REGULATORY COORDINATION
8.1

Interagency Coordination

Table 8.1, together with Table 15.1 of the 1992 GEIS, shows the spectrum of government
authorities that oversee various aspects of well drilling and hydraulic fracturing. The 1992 GEIS
should be consulted for complete information on the overall role of each agency listed on Table
15.1. Review of existing regulatory jurisdictions and concerns addressed in this revised draft
SGEIS identified the following additional agencies that were not previously listed and have been
added to Table 8.1:
•

NYSDOH;

•

USDOT and NYSDOT;

•

Office of Parks, Recreation and Historic Preservation (OPRHP);

•

NYCDEP; and

•

SRBC and DRBC.

Following is a discussion on specific, direct involvement of other agencies in the well permit
process relative to high-volume hydraulic fracturing.
8.1.1

Local Governments

ECL §23-0303(2) provides that the Department’s Oil, Gas and Solution Mining Law supersedes
all local laws relating to the regulation of oil and gas development except for local government
jurisdiction over local roads or the right to collect real property taxes. Likewise, ECL §231901(2) provides for supersedure of all other laws enacted by local governments or agencies
concerning the imposition of a fee on activities regulated by ECL 23.
8.1.1.1 SEQRA Participation
For the following actions which were found in 1992 to be significant or potentially significant
under SEQRA, the process will continue to include all opportunities for public input normally
provided under SEQRA:

Final SGEIS 2015, Page 8-1

 •

Issuance of a permit to drill in State Parklands;

•

Issuance of a permit to drill within 2,000 feet of a municipal water supply well; and

•

Issuance of a permit to drill that will result in disturbance of more than 2.5 acres in an
Agricultural District.

Based on the recommendations in this revised draft SGEIS, the Department proposes that the
following additional actions will also include all opportunities for public input normally provided
under SEQRA:
•

Issuance of a permit to drill when high-volume hydraulic fracturing is proposed shallower
than 2,000 feet anywhere along the entire proposed length of the wellbore;

•

Issuance of a permit to drill when high-volume hydraulic fracturing is proposed where
the top of the target fracture zone at any point along the entire proposed length of the
wellbore is less than 1,000 feet below the base of a known fresh water supply;

•

Issuance of a permit to drill when high-volume hydraulic fracturing is proposed at a well
pad within 500 feet of a principal aquifer (to be re-evaluated two years after issuance of
the first permit for high-volume hydraulic fracturing);

•

Issuance of a permit to drill when high-volume hydraulic fracturing is proposed on a well
pad within 150 feet of a perennial or intermittent stream, storm drain, lake or pond;

•

Issuance of a permit to drill when high-volume hydraulic fracturing is proposed and the
source water involves a surface water withdrawal not previously approved by the
Department that is not based on the NFRM as described in Chapter 7;

•

Any proposed water withdrawal from a pond or lake;

•

Any proposed ground water withdrawal within 500 feet of a private well;

•

Any proposed ground water withdrawal within 500 feet of a wetland that pump test data
shows would have an influence on the wetland; and

•

Issuance of a permit to drill any well subject to ECL 23 whose location is determined by
NYCDEP to be within 1,000 feet of its subsurface water supply infrastructure.

Final SGEIS 2015, Page 8-2

 Table 8.1

Regulatory Jurisdictions Associated With High-Volume Hydraulic Fracturing

(Updated August 2011)

Regulated Activity or
Impact

DEC Divisions & Offices

NYS Agencies

Federal Agencies

DMM DFWMR DAR DOH DOT PSC OPRHP EPA USDOT Corps

Local Agencies
Local
Local
Health
Govt.

Other
NYC
DEP RBCs

DMN DEP DOW

DER

P
-

-

-

-

-

-

-

-

-

-

*

-

-

-

-

-

*

*

-

-

-

-

-

-

-

A

-

-

-

-

-

-

P

-

-

S

*

P*

-

-

P

-

-

-

-

-

-

-

-

-

-

-

P*

General
Well siting
Road use
Surface water withdrawals
Stormwater runoff

S

-

P

-

-

-

-

-

-

-

-

-

-

-

-

-

*

*

Wetlands permitting
Transportation of
fracturing chemicals
Well drilling and
construction

-

P

-

-

-

S

-

-

-

-

-

-

-

P

-

-

*

*

-

-

-

S

-

-

-

-

P

-

-

-

P

-

-

-

-

P

-

-

-

-

-

-

-

-

-

-

-

-

-

-

*

-

*

P

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

P

-

*

-

-

-

-

*

-

-

-

-

-

-

-

-

-

*

P

-

-

A

A

-

-

*

-

-

-

-

-

-

-

-

-

-

Wellsite fluid containment
Hydraulic fracturing/
refracturing
Cuttings and reserve pit
liner disposal
Site restoration

P

-

-

-

-

S

-

-

-

-

-

-

-

-

-

-

-

-

Production operations
Gathering lines and
compressor stations
Air emissions from all site
operations

P

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

S

S

-

-

-

-

S

-

-

P

-

-

-

-

-

-

-

-

S

-

-

-

-

-

P*/A*

*

-

-

-

-

-

-

-

-

-

-

Well plugging

P

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

Invasive species control

S

-

-

-

-

P

-

-

-

-

-

-

-

-

-

-

-

-

-

Fluid Disposal Plan
6NYCRR 554.1(c)(1)
Waste transport

-

-

-

P

-

-

-

-

-

-

-

-

-

-

*

-

-

POTW disposal
New in-state industrial
treatment plants

-

*

P

-

-

-

-

-

-

-

-

-

-

-

-

-

*

*

-

P

S

-

-

-

-

-

-

-

*

-

-

-

-

-

*

*

S

P

S

-

-

-

-

-

-

-

-

P

-

-

-

-

-

*

-

-

-

-

-

*

-

-

-

-

-

-

-

P

-

-

P

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

S

-

-

-

-

-

-

*

-

-

-

-

-

-

P

-

-

-

P

-

-

-

-

-

-

-

-

-

-

-

-

-

S

-

-

-

Injection well disposal
Road spreading

-

P

Private Water Wells
Baseline testing and
ongoing monitoring
Initial complaint response
Complaint follow-up

Key: 
P = Primary role
S = Secondary role
A = Advisory role
* = Role pertains in certain circumstances 

DEC Divisions
DMN = Division of Mineral Resources

DEP = Division of Environmental Permits (DRA in GEIS Table 15.1)

DOW = Division of Water (DW in GEIS Table 15.1)

DER = Division of Environmental Remediation (DSHW in GEIS Table 15.1)
DMM = Division of Materials Management
DFWMR = Division of Fish, Wildlife and Marine Resources
DAR = Division of Air Resources

Final SGEIS 2015, Page 8-3

 8.1.1.2 NYCDEP
The Department will continue to notify NYCDEP of proposed drilling locations in counties with
subsurface water supply infrastructure to enable NYCDEP to identify locations in proximity to
infrastructure that might require site-specific SEQRA determinations.
8.1.1.3 Local Government Notification
ECL §23-0305(13) requires that the permittee notify any affected local government and surface
owner prior to commencing operations. Many local governments have requested notification
earlier in the process, although it is not required by law or regulation. The Department would
notify local governments of all applications for high-volume hydraulic fracturing in the locality,
using a continuously updated database of local government officials and an electronic
notification system that would both be developed for this purpose.
8.1.1.4 Road-Use Agreements
The Department strongly encourages operators to reach road use agreements with governing
local authorities. The issuance of a permit to drill does not relieve the operator of the
responsibility to comply with any local requirements authorized by or enacted pursuant to the
New York State Vehicle and Traffic Law. Additional information about road infrastructure and
traffic impacts is provided in Sections 6.11 and 7.13.
8.1.1.5 Local Planning Documents
The Department’s exclusive authority to issue well permits supersedes local government
authority relative to well siting. However, in order to consider potential significant adverse
impacts on land use and zoning as required by SEQRA, the EAF Addendum would require the
applicant to identify whether the proposed location of the well pad, or any other activity under
the jurisdiction of the Department, conflicts with local land use laws or regulations, plans or
policies. The applicant would also be required to identify whether the well pad is located in an
area where the affected community has adopted a comprehensive plan or other local land use
plan and whether the proposed action is inconsistent with such plan(s). For actions where the
applicant indicates to the Department that the location of the well pad, or any other activity under
the jurisdiction of the Department, is either consistent with local land use laws, regulations, plans
or policies, or is not covered by such local land use laws, regulations, plans or policies, the

Final SGEIS 2015, Page 8-4

 Department would proceed to permit issuance unless it receives notice of an asserted conflict by
the potentially impacted local government.
Applicants for permits to drill are already required to identify whether any additional state, local
or federal permits or approvals are required for their projects. Therefore, in cases where an
applicant indicates that all or part of their proposed project is inconsistent with local land use
laws, regulations, plans or policies, or where the potentially impacted local government advises
the Department that it believes the application is inconsistent with such laws, regulations, plans
or policies, the Department would, at the time of permit application, request additional
information so that it can consider whether significant adverse environmental impacts would
result from the proposed project that have not been addressed in the SGEIS and whether
additional mitigation or other action should be taken in light of such significant adverse impacts.
8.1.1.6 County Health Departments
As explained in Chapter 15 of the GEIS and Chapter 7 of this document, county health
departments are the most appropriate entity to undertake initial investigation of water well
complaints. The Department proposes that county health departments retain responsibility for
initial response to most water well complaints, referring them to the Department when causes
other than those related to drilling have been ruled out. The exception to this is when a
complaint is received while active operations are underway within a specified distance; in these
cases, the Department will conduct a site inspection and will jointly perform the initial
investigation along with the county health department.
8.1.2

State

Except for the Public Service Commission relative to its role regarding pipelines and associated
facilities (which will continue; see Section 8.1.2.1), no State agencies other than the Department
are listed in GEIS Table 15.1. The NYSDOH, NYSDOT, along with the Office of Parks,
Recreation and Historic Preservation, are listed in Table 8.1 and will be involved as follows:
•

NYSDOH: Potential future and ongoing involvement in review of NORM issues and
assistance to county health departments regarding water well investigations and
complaints;

Final SGEIS 2015, Page 8-5

 •

NYSDOT: Not directly involved in well permit reviews, but has regulations regarding
intrastate transportation of hazardous chemicals found in hydraulic fracturing
additives and may advise the Department regarding the required transportation plans
and road condition assessments; and

•

OPRHP: In addition to continued review of well and access road locations in areas of
potential historic and archeological significance, OPRHP will also review locations of
related facilities such as surface impoundments and treatment plants.

8.1.2.1 Public Service Commission
Article VII, “Siting of Major Utility Transmission Facilities,” is the section of the New York
Public Service Law (PSL) that requires a full environmental impact review of the siting, design,
construction, and operation of major intrastate electric and natural gas transmission facilities in
New York State. The Public Service Commission (Commission or PSC) has approval authority
over actions involving intrastate electric power transmission lines and high pressure natural fuel
gas pipelines, and actions related to such projects. An example of an action related to a highpressure natural fuel gas pipeline is the siting and construction of an associated compressor
station. While the Department and other agencies can have input into the review of an Article
VII application or Notice of Intent (NOI) for an action, and can process ancillary permits for
federally delegated programs, the ultimate decision on a given project application is made by the
Commission. The review and permitting process for natural fuel gas pipelines is separate and
distinct from that used by the Department to review and permit well drilling applications under
ECL Article 23, and is traditionally conducted after a well is drilled, tested and found productive.
For development and environmental reasons, along with early reported anticipated success rates
of one hundred percent in 2009, it had been suggested that wells targeting the Marcellus Shale
and other low-permeability gas reservoirs using horizontal drilling and high-volume hydraulic
fracturing may deserve consideration of pipeline certification by the PSC in advance of drilling
to allow pipelines to be in place and operational at the time of the completion of the wells.
However, as reported in late 2010 and described below, not all Marcellus Shale wells drilled in
neighboring Pennsylvania have proved to be economical when drilled beyond what some have
termed the “line of death.” 509

509

Citizens Voice, Wilkes-Barre, PA., Drillers Take Another Chance in Columbia County, May 9, 2011
http://energy.wilkes.edu/pages/106.asp?item=341.

Final SGEIS 2015, Page 8-6

 The PSC's statutory authority has its own "SEQR-like" review, record, and decision standards
that apply to major gas and electric transmission lines. As mentioned above, PSC makes the
final decision on Article VII applications. Article VII supersedes other State and local permits
except for federally authorized permits; 510 however, Article VII establishes the forum in which
community residents can participate with members of State and local agencies in the review
process to ensure that the application comports with the substance of State and local laws.
Throughout the Article VII review process, applicants are strongly encouraged to follow a public
information process designed to involve the public in a project’s review. Article VII includes
major utility transmission facilities involving both electricity and fuel gas (natural gas), but the
following discussion, which is largely derived from PSC’s guide entitled “The Certification
Review Process for Major Electric and Fuel Gas Transmission Facilities,” 511 is focused on the
latter. While the focus of PSC’s guide with respect to natural gas is the regulation and permitting
of transmission lines at least ten miles long and operated at a pressure of 125 psig or greater, the
certification process explained in the guide and outlined below provides the basis for the
permitting of transmission lines less than ten miles long that would typically serve Marcellus
Shale and other low-permeability gas reservoir wells.
Public Service Commission
PSC is the five-member decision-making body established by PSL § 4 that regulates investorowned electric, natural gas, steam, telecommunications, and water utilities in New York State.
The Commission, made up of a Chairman and four Commissioners, decides any application filed
under Article VII. The Chairman of the Commission, designated by the Governor, is also the
chief executive officer of the Department of Public Service (DPS). Employees of the DPS serve
as staff to the PSC.
DPS is the State agency that serves to carry out the PSC’s legal mandates. One of DPS’s
responsibilities is to participate in all Article VII proceedings to represent the public interest.
510

Article VII does not however supplant the need to obtain property rights from the State for a transmission line project that
proposes to cross State-owned land. PSC has no authority, express or implied, to grant land easements, licenses, franchises,
revocable consents, or permits to use State land. The Department, therefore, retains the authority to grant or deny access to
State lands under its jurisdiction.

511

http://www.dps.state.ny.us/Article_VII_Process_Guide.pdf.

Final SGEIS 2015, Page 8-7

 DPS employs a wide range of experts, including planners, landscape architects, foresters, aquatic
and terrestrial ecologists, engineers, and economists, who analyze environmental, engineering,
and safety issues, as well as the public need for a facility proposed under Article VII. These
professionals take a broad, objective view of any proposal, and consider the project’s effects on
local residents, as well as the needs of the general public of New York State. Public
participation specialists monitor public involvement in Article VII cases and are available for
consultation with both applicants and stakeholders.
Article VII
The New York State Legislature enacted Article VII of the PSL in 1970 to establish a single
forum for reviewing the public need for, and environmental impact of, certain major electric and
gas transmission facilities. The PSL requires that an applicant must apply for a Certificate of
Environmental Compatibility and Public Need (Certificate) and meet the Article VII
requirements before constructing any such intrastate facility. Article VII sets forth a review
process for the consideration of any application to construct and operate a major utility
transmission facility. Natural gas transmission lines originating at wells are commonly referred
to as “gathering lines” because the lines may collect or gather gas from a single or number of
wells which feed a centralized compression facility or other transmission line. The drilling of
multiple Marcellus Shale or other low-permeability gas reservoir wells from a single well pad
and subsequent production of the wells into one large diameter gathering line eliminates the need
for construction and associated cumulative impacts from individual gathering lines if
traditionally drilled as one well per location. The PSL defines major natural gas transmission
facilities, which statutorily includes many gathering lines, as pipelines extending a distance of at
least 1,000 feet and operated at a pressure of 125 psig or more, except where such natural gas
pipelines:
•

are located wholly underground in a city;

•

are located wholly within the right-of-way of a State, county or town highway or village
street; or

•

replace an existing transmission facility, and are less than one mile long.

Final SGEIS 2015, Page 8-8

 Under 6 NYCRR § 617.5(c)(35), actions requiring a Certificate of Environmental Compatibility
and Public Need under article VII of the PSL and the consideration of, granting or denial of any
such Certificate are classified as "Type II" actions for the purpose of SEQR. Type II actions are
those actions, or classes of actions, which have been found categorically to not have significant
adverse impacts on the environment, or actions that have been statutorily exempted from SEQR
review. Type II actions do not require preparation of an EAF, a negative or positive declaration,
or an environmental impact statement (EIS) under SEQR. Despite the legal exemption from
processing under SEQR, as previously noted, Article VII contains its own process to evaluate
environmental and public safety issues and potential impacts, and impose mitigation measures as
appropriate.
As explained in the GEIS, and shown in Table 8.2, PSC has siting jurisdiction over all lines
operating at a pressure of 125 psig or more and at least 1,000 feet in length, and siting
jurisdiction of lines below these thresholds if such lines are part of a larger project under PSC’s
purview. In addition, PSC’s safety jurisdiction covers all natural gas gathering lines and
pipelines regardless of operating pressure and line length. PSC’s authority, at the well site,
physically begins at the well’s separator outlet. The Department’s permitting authority over
gathering lines operating at pressures less than 125 psig primarily focuses on the permitting of
disturbances in environmentally sensitive areas, such as streams and wetlands, and the
Department is responsible for administering federally delegated permitting programs involving
air and water resources. For all other pipelines regulated by the PSC, the Department’s
jurisdiction is limited to the permitting of certain federally delegated programs involving air and
water resources. Nevertheless, in all instances, the Department either directly imposes
mitigation measures through its permits or provides comments to the PSC which, in turn,
routinely requires mitigation measures to protect environmentally sensitive areas.
Pre-Application Process
Early in the planning phase of a project, the prospective Article VII applicant is encouraged to
consult informally with stakeholders. Before an application is filed, stakeholders may obtain
information about a specific project by contacting the applicant directly and asking the applicant
to put their names and addresses on the applicant’s mailing list to receive notices of public
information meetings, along with project updates. After an application is filed, stakeholders may

Final SGEIS 2015, Page 8-9

 request their names and addresses be included on a project “service list” which is maintained by
the PSC. Sending a written request to the Secretary to the PSC to be placed on the service list
for a case will allow stakeholders to receive copies of orders, notices and rulings in the case.
Such requests should reference the Article VII case number assigned to the application.
Table 8.2 - Intrastate Pipeline Regulation 512
Department

PSC

Gathering
<125 psig

Pipeline Type

Siting jurisdiction only in environmentally
sensitive areas where Department permits,
other than the well permit, are required.
Permitting authority for federally delegated
programs such as Title V of the Clean Air Act
(i.e., major stationary sources) and Clean
Water Act National Pollutant Discharge
Elimination System program (i.e., SPDES
General Permit for Stormwater Discharges).

Safety jurisdiction. Public Service Law § 66,
16 NYCRR § 255.9 and Appendix 7-G(a)**.

Gathering
≥125 psig, <1,000 ft.

Permitting authority for certain federally
delegated programs such as Title V of the
Clean Air Act (i.e., major stationary sources)
and Clean Water Act National Pollutant
Discharge Elimination System program
(i.e., SPDES General Permit for Stormwater
Discharges).

Safety jurisdiction. Public Service Law § 66,
16 NYCRR § 255.9 and Appendix 7-G(a)**.
Siting jurisdiction also applies if part of larger
system subject to siting review. Public
Service Law § 66, 16 NYCRR Subpart 85-1.4.

Fuel Gas Transmission*
≥125 psig, ≤1,000 ft., <5 mi.,
≤6 in. diameter

Permitting authority for certain federally
delegated programs such as Title V of the
Clean Air Act (i.e., major stationary sources)
and Clean Water Act National Pollutant
Discharge Elimination System program
(i.e., SPDES General Permit for Stormwater
Discharges).

Siting and safety jurisdiction. Public Service
Law Sub-Article VII § 121a-2, 16 NYCRR §
255.9 and Appendices 7-D, 7-G and 7-G(a)**.
16 NYCRR Subpart 85-1. EM&CS&P***
checklist must be filed. Service of NOI or
application to other agencies required.

Fuel Gas Transmission*
≥125 psig, ≥5 mi., <10 mi.

Permitting authority for certain federally
delegated programs such as Title V of the
Clean Air Act (i.e., major stationary sources)
and Clean Water Act National Pollutant
Discharge Elimination System program
(i.e., SPDES General Permit for Stormwater
Discharges).

Siting and safety jurisdiction. Public Service
Law Sub-Article VII § 121a-2, 16 NYCRR §
255.9 and Appendices 7-D, 7-G and 7-G(a)**.
16 NYCRR Subpart 85-1. EM&CS&P***
checklist must be filed. Service of NOI or
application to other agencies required.

Permitting authority for certain federally
delegated programs such as Title V of the
Clean Air Act (i.e., major stationary sources)
and Clean Water Act National Pollutant
Discharge Elimination System program
(i.e., SPDES General Permit for Stormwater
Discharges).

Siting and safety jurisdiction. Public Service
Law Article VII § 120, 16 NYCRR § 255.9,
16 NYCRR Subpart 85-2. Environmental
assessment must be filed. Service of
application to other agencies required.

Note: The pipelines associated with wells
being considered in this document typically
fall into this category, or possibly the one
above.
Fuel Gas Transmission*
≥125 psig, ≥10 mi.

* Federal Minimum Pipeline Safety Standards 49 CFR Part 192 supersedes PSC if line is closer than 150 ft. to a residence or in an urban area.
** Appendix 7-G(a) is required in all active farm lands.
*** EM&CS&P means Environmental Management and Construction Standards and Practices.

512

Adapted from the NYSDEC GEIS 1992.

Final SGEIS 2015, Page 8-10

 Application
An Article VII application must contain the following information:
•

location of the line and right-of-way;

•

description of the transmission facility being proposed;

•

summary of any studies made of the environmental impact of the facility, and a
description of such studies;

•

statement explaining the need for the facility;

•

description of any reasonable alternate route(s), including a description of the merits and
detriments of each route submitted, and the reasons why the primary proposed route is
best suited for the facility; and

•

such information as the applicant may consider relevant or the Commission may require.

In an application, the applicant is also encouraged to detail its public involvement activities and
its plans to encourage public participation. DPS staff takes about 30 days after an application is
filed to determine if the application is in compliance with Article VII filing requirements. If an
application lacks required information, the applicant is informed of the deficiencies. The
applicant can then file supplemental information. If the applicant chooses to file the
supplemental information, the application is again reviewed by the DPS for a compliance
determination. Once an application for a Certificate is filed with the PSC, no local municipality
or other State agency may require any hearings or permits concerning the proposed facility.
Timing of Application & Pipeline Construction
The extraction of projected economically recoverable reserves from the Marcellus Shale, and
other low-permeability gas reservoirs, presents a unique challenge and opportunity with respect
to the timing of an application and ultimate construction of the pipeline facilities necessary to tie
this gas source into the transportation system and bring the produced gas to market. In the
course of developing other gas formations, the typical sequence of events begins with the
operator first drilling a well to determine its productivity and, if successful, then submitting an
Article VII application for PSC approval to construct the associated pipeline. This reflects the
risk associated with conventional oil and gas exploration where finding natural gas in paying
quantities is not guaranteed and the same appears to be true for potential drilling under the
SGEIS as not all wells drilled will be productive. More than one or two wells on the same pad

Final SGEIS 2015, Page 8-11

 may need to be drilled to prove economical production prior to an operator making a
commitment to invest in and build a pipeline. Actual drilling at any given location is the only
way to know if a given area will be productive, especially in the fringe of any predetermined
productive fairways. In 2010, it was reported that Encana Oil & Gas USA Inc. drilled several
unsuccessful Marcellus Shale wells in Luzerne County, Pennsylvania and that “there wasn’t
enough gas in either to be marketable.” 513
Consequently, the typical procedure of drilling wells, testing wells by flaring and then
constructing gathering lines may or may not be suited for the development of the Marcellus
Shale and other low permeability reservoirs depending upon the location of proposed wells and
the establishment of productive fairways through drilling experience. In 2009, the success rate
of horizontally drilled and hydraulically fractured Marcellus Shale wells in neighboring
Pennsylvania and West Virginia, as reported by three companies, was one hundred percent for 44
wells drilled. 514 This early rate of success was apparently due primarily to the fact that the
Marcellus Shale reservoir in location-specific fairways appears to contain natural gas in
sufficient quantities which can be produced economically using horizontal drilling and highvolume hydraulic fracturing technology. However, as noted above, some Marcellus Shale wells
subsequently drilled in Pennsylvania apparently using the same technology did not prove
successful. It is highly unlikely that an operator in New York would make a substantial
investment in a pipeline ahead of completing a well unless drilling is conducted in a known
productive fairway and there is a near guarantee of finding gas in suitable quantities and at viable
flow rates.
In addition, the Marcellus Shale formation in some areas is known to have a high concentration
of clay that is sensitive to fresh water contact which makes the formation susceptible to reclosing if the flowback fluid and natural gas do not flow immediately after hydraulic fracturing
operations. The horizontal drilling and hydraulic fracturing technique used to tap into the
Marcellus in these areas could require that the well be flowed back and gas produced
immediately after the well has been fractured and completed, otherwise the formation may be
513

Citizens Voice, Despite Encana’s Exit, Other Companies Stay Put, November 20, 2010
http://citizensvoice.com/news/despite-encana-s-exit-other-companies-stay-put-1.1066540#axzz1NZF239wB.

514

Chesapeake Energy Corp., Fortuna Energy Inc., Seneca Resources Corp.

Final SGEIS 2015, Page 8-12

 damaged and the well may cease to be economically productive. However, clay stabilizer
additives are available for injection during hydraulic fracturing operations which help inhibit the
swelling of clays present in the target formation. In addition to possibly enhancing the
completion by preventing formation damage, having a pipeline in place when a well is initially
flowed would reduce the amount of gas flared to the atmosphere during initial recovery
operations. This type of completion with limited or no flaring is referred to as a reduced
emissions completion (REC). To combat formation damage during hydraulic fracturing with
conventional fluids, a new and alternative hydraulic fracturing technology recently entered the
Canadian market and has also been used in Pennsylvania on a limited basis. It uses liquefied
petroleum gas (LPG), consisting mostly of propane in place of water-based hydraulic fracturing
fluids. Using propane not only minimizes formation damage, but also eliminates the need to
source water for hydraulic fracturing, recover flowback fluids to the surface and dispose of the
flowback fluids. 515 While it is not known if or when LPG hydraulic fracturing will be proposed
in New York, having gathering infrastructure in place may be an important factor in realizing the
advantages of this technology. Instead of LPG/natural gas separation equipment being required
at individual well pads during flowback, an in-place gas production pipeline would allow and
facilitate the siting of centralized separation equipment that could service a number of well pads
thereby providing for a more efficient LPG hydraulic fracturing operation.
Also, if installed prior to well drilling, an in-place gas production pipeline could serve a second
purpose and be used initially to transport fresh water or recycled hydraulic fracturing fluids to
the well site for use in hydraulic fracturing the first well on the pad. This in itself would reduce
or eliminate other fluid transportation options, such as trucking and construction of a separate
fluid pipeline, and associated impacts. Because of the many potential benefits noted above,
which have been demonstrated in other states, it has been suggested that New York should have
the option, after drilling experience is gained, to certify and build pipelines in advance of well
drilling targeting the Marcellus Shale and other low-permeability gas reservoirs in known
productive fairways.

515

Smith M, 2008, p. 4.

Final SGEIS 2015, Page 8-13

 Filing and Notice Requirements
Article VII requires that a copy of an application for a transmission line ten miles or longer in
length be provided by the applicant to the Department, the Department of Economic
Development, the Secretary of State, the Department of Agriculture and Markets and the Office
of Parks, Recreation and Historic Preservation, and each municipality in which any portion of the
facility is proposed to be located. This is done for both the primary route proposed and any
alternative locations listed. A copy of the application must also be provided to the State
legislators whose districts the proposed primary facility or any alternative locations listed would
pass through. Service requirements for transmission lines less than 10 miles in length are
slightly different but nevertheless comprehensive.
An Article VII application for a transmission line ten miles or longer in length must be
accompanied by proof that notice was published in a newspaper(s) of general circulation in all
areas through which the facility is proposed to pass, for both its primary and alternate routes.
The notice must contain a brief description of the proposed facility and its proposed location,
along with a discussion of reasonable alternative locations. An applicant is not required to
provide copies of the application or notice of the filing of the application to individual property
owners of land on which a portion of either the primary or alternative route is proposed.
However, to help foster public involvement, an applicant is encouraged to do so.
Party Status in the Certification Proceeding
Article VII specifies that the applicant and certain State and municipal agencies are parties in any
case. The Department and the Department of Agriculture & Markets are among the statutorily
named parties and usually actively participate. Any municipality through which a portion of the
proposed facility will pass, or any resident of such municipality, may also become a formal party
to the proceeding. Obtaining party status enables a person or group to submit testimony, crossexamine witnesses of other parties and file briefs in the case. Being a party also entails the
responsibility to send copies of all materials filed in the case to all other parties. DPS staff
participates in all Article VII cases as a party, in the same way as any other person who takes an
active part in the proceedings.

Final SGEIS 2015, Page 8-14

 The Certification Process
Once all of the information needed to complete an application is submitted and the application is
determined to be in compliance, review of the application begins. In a case where a hearing is
held, the Commission’s Office of Hearings and Alternative Dispute Resolution provides an
Administrative Law Judge (ALJ) to preside in the case. The ALJ is independent of DPS staff
and other parties and conducts public statement and evidentiary hearings and rules on procedural
matters. Hearings help the Commission decide whether the construction and operation of new
transmission facilities will fulfill the public need, be compatible with environmental values and
the public health and safety, and comply with legal requirements. After considering all the
evidence presented in a case, the ALJ usually makes a recommendation for the Commission’s
consideration.
Commission Decision
The Commission reviews the ALJ’s recommendation, if there is one, and considers the views of
the applicant, DPS staff, other governmental agencies, organizations, and the general public,
received in writing, orally at hearings or at any time in the case. To grant a Certificate, either as
proposed or modified, the Commission must determine all of the following:
•

the need for the facility;

•

the nature of the probable environmental impact;

•

the extent to which the facility minimizes adverse environmental impact, given
environmental and other pertinent considerations;

•

that the facility location will not pose undue hazard to persons or property along the line;

•

that the location conforms with applicable State and local laws; and

•

that the construction and operation of the facility is in the public interest.

Following Article VII certification, the Commission typically requires the certificate holder to
submit various additional documents to verify its compliance with the certification order. One of
the more notable compliance documents, an Environmental Management and Construction Plan
(EM&CP), must be approved by the Commission before construction can begin. The EM&CP
details the precise field location of the facilities and the special precautions that will be taken

Final SGEIS 2015, Page 8-15

 during construction to ensure environmental compatibility. The EM&CP must also indicate the
practices to be followed to ensure that the facility is constructed in compliance with applicable
safety codes and the measures to be employed in maintaining and operating the facility once it is
constructed. Once the Commission is satisfied that the detailed plans are consistent with its
decision and are appropriate to the circumstances, it will authorize commencement of
construction. DPS staff is then responsible for checking the applicant’s practices in the field.
Amended Certification Process
In 1981, the Legislature amended Article VII to streamline procedures and application
requirements for the certification of fuel gas transmission facilities operating at 125 psig or more,
and that extend at least 1,000 feet, but less than ten miles. The pipelines or gathering lines
associated with wells being considered in this document typically fall into this category, and,
consequently, a relatively expedited certification process occurs that is intended to be no less
protective. The updated requirements mimic those described above with notable differences
being: 1) a NOI may be filed instead of an application, 2) there is no mandatory hearing with
testimony or required notice in newspaper, and 3) the PSC is required to act within thirty or sixty
days depending upon the size and length of the pipeline.
The updated requirements applicable to such fuel gas transmission facilities are set forth in PSL
Section 121-a and 16 NYCRR Sub-part 85-1. All proposed pipeline locations are verified and
walked in the field by DPS staff as part of the review process, and staff from the Department and
Department of Agriculture & Markets may participate in field visits as necessary. As mentioned
above, these departments normally become active parties in the NOI or application review
process and usually provide comments to DPS staff for consideration. Typical comments from
the Department and Agriculture and Markets relate to the protection of agricultural lands,
streams, wetlands, rare or state-listed animals and plants, and significant natural communities
and habitats.
Instead of an applicant preparing its own environmental management and construction standards
and practices (EM&CS&P), it may choose to rely on a PSC-approved set of standards and
practices, the most comprehensive of which was prepared by DPS staff in February 2006. 516 The
516

NYSDPS, 2006

Final SGEIS 2015, Page 8-16

 DPS-authored EM&CS&P was written primarily to address construction of smaller-scale fuel
gas transmission projects envisioned by PSL Section 121-a that will be used to transport gas
from the wells being considered in this document. Comprehensive planning and construction
management are key to minimizing adverse environmental impacts of pipelines and their
construction. The EM&CS&P is a tool for minimizing such impacts of fuel gas transmission
pipelines reviewed under the PSL. The standards and practices contained in the 2006
EM&CS&P handbook are intended to cover the range of construction conditions typically
encountered in constructing pipelines in New York.
The pre-approved nature of the 2006 EM&CS&P supports a more efficient submittal and review
process, and aids with the processing of an application or NOI within mandated time frames.
The measures from the EM&CS&P that will be used in a particular project must be identified on
a checklist and included in the NOI or application. A sample checklist is included as Appendix
14, which details the extensive list of standards and practices considered in DPS’s EM&CS&P
and readily available to the applicant. Additionally, the applicant must indicate and include any
measures or techniques it intends to modify or substitute for those included in the PSC-approved
EM&CS&P.
An important measure specified in the EM&CS&P checklist is a requirement for supervision and
inspection during various phases of the project. Page four of the 2006 EM&CS&P states “At
least one Environmental Inspector (EI) is required for each construction spread during
construction and restoration. The number and experience of EIs should be appropriate for the
length of the construction spread and number/significance or resources affected.” The 2006
EM&CS&P also requires that the name(s) of qualified Environmental Inspector(s) and a
statement(s) of the individual’s relative project experience be provided to the DPS prior to the
start of construction for DPS staff’s review and acceptance. Another important aspect of the
PSC-approved EM&CS&P is that Environmental Inspectors have stop-work authority entitling
the EI to stop activities that violate Certificate conditions or other federal, State, local or
landowner requirements, and to order appropriate corrective action.

Final SGEIS 2015, Page 8-17

 Conclusion
Whether an applicant submits an Article VII application or Notice of Intent as allowed by the
Public Service Law, the end result is that all Public Service Commission-issued Certificates of
Environmental Compatibility and Public Need for fuel gas transmission lines contain ordering
clauses, stipulations and other conditions that the Certificate holder must comply with as a
condition of acceptance of the Certificate. Many of the Certificate’s terms and conditions relate
to environmental protection. The Certificate holder is fully expected to comply with all of the
terms and conditions or it may face an enforcement action. DPS staff monitor construction
activities to help ensure compliance with the Commission’s orders. After installation and
pressure testing of a pipeline, its operation, monitoring, maintenance and eventual abandonment
must also be conducted in accordance with and adhere to the provisions of the Certificate and
New York State law and regulations.
8.1.2.2 NYS Department of Transportation
New York State requires all registrants of commercial motor vehicles to obtain a USDOT
number. New York has adopted the FMCSA regulations CFR 49, Parts 390, 391, 392, 393, 395,
and 396, and the Hazardous Materials Transportation Regulations, Parts 100 through 199, as
those regulations apply to interstate highway transportation (NYSDOT, 6/2/09). There are minor
exemptions to these federal regulations in NYCRR Title17 Part 820, “New York State Motor
Carrier Safety Regulations”; however, the exemptions do not directly relate to the objectives of
this review.
The NYS regulations include motor vehicle carriers that operate solely on an intrastate basis.
Those carriers and drivers operating in intrastate commerce must comply with 17 NYCRR Part
820, in addition to the applicable requirements and regulations of the NYS Vehicle and Traffic
Law and the NYS Department of Motor Vehicles (DMV), including the regulations requiring
registration or operating authority for transporting hazardous materials from the USDOT or the
NYSDOT Commissioner.
Part 820.8 (Transportation of hazardous materials) states “Every person … engaged in the
transportation of hazardous materials within this State shall be subject to the rules and
regulations contained in this Part.” The regulations require that the material be “properly

Final SGEIS 2015, Page 8-18

 classed, described, packaged, clearly marked, clearly labeled, and in the condition for
shipment…” [820.8(b)]; that the material “is handled and transported in accordance with this
Part” [(820.8(c)]; “require a shipper of hazardous materials to have someone available at all
times, 24 hours a day, to answer questions with respect to the material being carried and the
hazards involved” [(820.8.(f)]; and provides for immediately reporting to “the fire or police
department of the local municipality or to the Division of State Police any incident that occurs
during the course of transportation (including loading, unloading and temporary storage) as a
direct result of hazardous materials” [820.8 (h)].
Part 820 specifies that “In addition to the requirements of this Part, the Commissioner of
Transportation adopts the following sections and parts of Title 49 of the Code of Federal
Regulations with the same force and effect… for classification, description, packaging, marking,
labeling, preparing, handling and transporting all hazardous materials, and procedures for
obtaining relief from the requirements, all of the standards, requirements and procedures
contained in sections 107.101, 107.105, 107.107, 107.109, 107.111, 107.113, 107.117, 107.121,
107.123, Part 171, except section 171.1, Parts 172 through 199, including appendices, inclusive
and Part 397.
NYSDOT would also have an advisory role with respect to the transportation plans and road
condition assessments that operators will be required to submit.
8.1.3

Federal

The United States Department of Transportation is the only newly listed federal agency in Table
8.1. As explained in Chapter 5, the US DOT regulates transportation of hazardous chemicals
found in fracturing additives and has also established standards for containers. Roles of the other
federal agencies shown on Table 15.1 will not change.
8.1.3.1 U.S. Department of Transportation
The federal Hazardous Material Transportation Act (HMTA, 1975) and the Hazardous Materials
Transportation Uniform Safety Act (HMTUSA, 1990) are the basis for federal hazardous
materials transportation law (49 U.S.C.) and give regulatory authority to the Secretary of the
USDOT to:

Final SGEIS 2015, Page 8-19

 •

“Designate material (including an explosive, radioactive, infectious substance, flammable
or combustible liquid, solid or gas, toxic, oxidizing, or corrosive material, and
compressed gas) or a group or class of material as hazardous when the Secretary
determines that transporting the material in commerce in a particular amount and form
may pose an unreasonable risk to health and safety or property; and

•

“Issue regulations for the safe transportation, including security, of hazardous material in
intrastate, interstate, and foreign commerce” (PHMSA, 2009).

The Code of Federal Regulations (CFR), Title 49, includes the Hazardous Materials
Transportation Regulations, Parts 100 through 199. Federal hazardous materials regulations
include:
•

Hazardous materials classification (Parts 171 and 173);

•

Hazard communication (Part 172);

•

Packaging requirements (Parts 173, 178, 179, 180);

•

Operational rules (Parts 171, 172, 173, 174, 175, 176, 177);

•

Training and security (part 172); and

•

Registration (Part 171).

The extensive regulations address the potential concerns involved in transporting hazardous
fracturing additives, such as Loading and Unloading (Part 177), General Requirements for
Shipments and Packaging (Part 173), Specifications for Packaging (Part 178), and Continuing
Qualification and Maintenance of Packaging (Part 180).
Regulatory functions are carried out by the following USDOT agencies:
•

Pipeline and Hazardous Materials Safety Administration (PHMSA);

•

Federal Motor Carrier Safety Administration (FMCSA);

•

Federal Aviation Administration (FAA); and

•

United States Coast Guard (USCG).

Final SGEIS 2015, Page 8-20

 Each of these agencies shares in promulgating regulations and enforcing the federal hazmat
regulations. State, local, or tribal requirements may only preempt federal hazmat regulations if
one of the federal enforcing agencies issues a waiver of preemption based on accepting a
regulation that offers an equal or greater level of protection to the public and does not
unreasonably burden commerce.
The interstate transportation of hazardous materials for motor carriers is regulated by FMCSA
and PHMSA. FMCSA establishes standards for commercial motor vehicles, drivers, and
companies, and enforces 49 CFR Parts 350-399. FMCSA’s responsibilities include monitoring
and enforcing regulatory compliance, with focus on safety and financial responsibility.
PHMSA’s enforcement activities relate to “the shipment of hazardous materials, fabrication,
marking, maintenance, reconditioning, repair or testing of multi-modal containers that are
represented, marked, certified, or sold for use in the transportation of hazardous materials.”
PHMSA’s regulatory functions include issuing Hazardous Materials Safety Permits; issuing rules
and regulations for safe transportation; issuing, renewing, modifying, and terminating special
permits and approvals for specific activities; and receiving, reviewing, and maintaining records,
among other duties.
8.1.3.2 Occupational Safety and Health Administration – Material Safety Data Sheets
The Occupational Safety and Health Administration (OSHA) is part of the United States
Department of Labor, and was created by Congress under the Occupational Safety and Health
Act of 1970 to ensure safe and healthful working conditions by setting and enforcing standards
and by providing training, outreach, education and assistance. 517
In order to ensure chemical safety in the workplace, information must be available about the
identities and hazards of chemicals. OSHA’s Hazard Communication Standard, 29 CFR
§1910.1200, 518 requires the development and dissemination of such information and requires that
chemical manufacturers and importers evaluate the hazards of the chemicals they produce or
import, prepare labels and Material Safety Data Sheets (MSDSs) to convey the hazard

517

OSHA, http://www.osha.gov/about.html.

518

Available at http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STANDARDS&p_id=10099.

Final SGEIS 2015, Page 8-21

 information, and train workers to handle chemicals appropriately. This standard also requires all
employers to have MSDSs in their workplaces for each hazardous chemical they use.
The requirements pertaining to MSDSs are described in 29 CFR §1910.1200(g), and include the
following information:
•

The identity used on the label;

•

The chemical 519 and common name(s) 520 of the hazardous chemical 521 ingredients, except
as provided for in §1910.1200(i) regarding trade secrets;

•

Physical and chemical characteristics of the hazardous chemical(s);

•

Physical hazards of the hazardous chemical(s), including the potential for fire, explosion
and reactivity;

•

Health hazards of the hazardous chemical(s);

•

Primary route(s) of entry;

•

The OSHA permissible exposure limit, ACGIH Threshold Limit Value, and any other
exposure limit used or recommended by the chemical manufacturer, importer or
employer preparing the MSDS;

•

Whether the hazardous chemical(s) is listed in the National Toxicology Program (NTP)
Annual Report on Carcinogens (latest edition) or has been found to be a potential
carcinogen in the International Agency for Research on Cancer (IARC) Monographs
(latest editions), or by OSHA;

519

29 CFR §1910.1200(c) defines “chemical name” as “the scientific designation of a chemical in accordance with the
nomenclature system developed by the International Union or Pure and Applied Chemistry (IUPAC) or the Chemical
Abstracts Service (CAS) rules of nomenclature, or a name which will clearly identify the chemical for the purpose of
conducting a hazard evaluation.”

520

29 CFR §1910.1200(c) defines “common name” as “any designation or identification such as code name, code number, trade
name, brand name or generic name used to identify a chemical other than by its chemical name.”

521

29 CFR §1910.1200(c) defines “hazardous chemical” as “any chemical which is a physical hazard or a health hazard,” and
further defines “physical hazard” and “health hazard” respectively as follows: “Physical hazard means a chemical for which
there is scientifically valid evidence that it is a combustible liquid, a compressed gas, explosive, flammable, an organic
peroxide, an oxidizer, pyrophoric, unstable (reactive) or water-reactive”; “Health hazard means a chemical for which there is
statistically significant evidence based on at least one study conducted in accordance with established scientific principles
that acute or chronic health effects may occur in exposed employees. The term ‘health hazard’ includes chemicals which are
carcinogens, toxic or highly toxic agents, reproductive toxins, irritants, corrosives, sensitizers, hepatoxins, nephrotoxins,
neurotoxins, agents which act on the hematopoietic system, and agents which damage the lungs, skin, eyes, or mucous
membranes.”

Final SGEIS 2015, Page 8-22

 •

Any generally applicable precautions for safe handling and use including appropriate
hygienic practices, measures during repair and maintenance of contaminated equipment,
and procedures for clean-up of spills and leaks;

•

Any generally applicable control measures such as appropriate engineering controls,
work practices, or personal protective equipment;

•

Emergency and first aid procedures;

•

Date of preparation of the MSDS or the last change to it; and

•

Name, address and telephone number of the chemical manufacturer, importer, employer
or other responsible party preparing or distributing the MSDS, who can provide
additional information on the hazardous chemical and appropriate emergency procedures,
if necessary.
MSDSs and Trade Secrets

29 CFR §1910.1200(i) sets forth an exception from disclosure in the MSDS of the specific
chemical identity, including the chemical name and other specific identification of a hazardous
chemical, if such information is considered to be trade secret. This exception however is
conditioned on the following:
•

that the claim of trade secrecy can be supported;

•

that the MSDS discloses information regarding the properties and effects of the
hazardous chemical;

•

that the MSDS indicates the specific chemical identity is being withheld as a trade secret;
and

•

that the specific chemical identity is made available to health professionals, employees,
and designated representatives in accordance with the provisions of 29 CFR
§1910.1200(i)(3) and (4) which discuss emergency and non-emergency situations.

Final SGEIS 2015, Page 8-23

 8.1.3.3 EPA’s Mandatory Reporting of Greenhouse Gases
In October 2009, the United States EPA published 40 CFR §98, referred to as the Greenhouse
Gas (GHG) Reporting Program, which mandates the monitoring and reporting of GHG
emissions from certain source categories in the United States. The nationwide emission data
collected under the program will provide a better understanding of the relative GHG emissions of
specific industries and of individual facilities within those industries, as well as better
understanding of the factors that influence GHG emissions rates and actions facilities could take
to reduce emissions. 522
The GHG reporting requirements for facilities that contain petroleum and natural gas systems
were finalized in November 2010 as Subpart W of 40 CFR §98. Under Subpart W, facilities that
emit 25,000 metric tons or more of CO2 equivalent 523 per year in aggregated emissions from all
sources are required to report annual GHG emission to EPA. More specifically, petroleum and
natural gas facilities that meet or exceed the reporting threshold are required to report annual
methane (CH4) and carbon dioxide (CO2) emissions from equipment leaks and venting, and
emissions of CO2, CH4, and nitrous oxide (N2O) from flaring, onshore production stationary and
portable combustion emission, and combustion emissions from stationary equipment involved in
natural gas distribution. 524
The rule requires data collection to begin on January 1, 2011 and that reports be submitted
annually by March 31st, for the GHG emissions from the previous calendar year.
Onshore Petroleum and Natural Gas Production Sector
For monitoring and reporting purposes, Subpart W divides the petroleum and natural gas systems
source category into seven segments including: onshore petroleum and natural gas production,
offshore petroleum and natural gas production, onshore natural gas processing, onshore natural
gas transmission compression, underground natural gas storage, liquefied natural gas (LNG)

522

USEPA, August 2010.

523

CO2 equivalent is defined by EPA as a metric measure used to compare the emissions from various GHGs based upon their
global warming potential (GWP), which is the cumulative radiative forcing effects of a gas over a specified time horizon
resulting from the emission of a unit mass of gas relative to a reference gas.

524

USEPA, Fact Sheet for Subpart W, November 2010.

Final SGEIS 2015, Page 8-24

 storage and LNG import and export, and natural gas distribution. 40 CFR §98.230(a)(2) defines
onshore petroleum and natural gas production to mean:
“all equipment on a well pad or associated with a well pad (including compressors,
generators, or storage facilities), and portable non-self-propelled equipment on a well pad
or associated with a well pad (including well drilling and completion equipment,
workover equipment, gravity separation equipment, auxiliary non-transportation-related
equipment, and leased, rented or contracted equipment) used in the production,
extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or
natural gas (including condensate).”
Facility Definition for Onshore Petroleum and Natural Gas Production
Reporting under 40 CFR §98 is at the facility level, however due to the unique characteristics of
onshore petroleum and natural gas production, the definition of “facility” for this industry
segment under Subpart W is distinct from that used for other segments throughout the GHG
Reporting Program. 40 CFR §98.238 defines an onshore petroleum and natural gas production
facility as:
“all petroleum or natural gas equipment on a well pad or associated with a well pad
and CO2 enhanced oil recovery (EOR) operations that are under common ownership or
common control included leased, rented, and contracted activities by an onshore
petroleum and natural gas production operator and that are located in a single
hydrocarbon basin as defined in §98.238.[525 ] Where a person or entity owns or operators
more than one well in a basin, then all onshore petroleum and natural gas production
equipment associated with all wells that the person or entity owns or operates in the basin
would be considered one facility.”

525

40 CFR §98.238 defines “basin” as “geologic provinces as defined by the American Association of Petroleum Geologists
(AAPG) Geologic Note: AAPG-DSD Geologic Provinces code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure
G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991) and the Alaska Geological Province Boundary
Map, Compiled by the American association of Petroleum Geologists committee on Statistics of Drilling in Cooperation with
the USGS, 1978.”

Final SGEIS 2015, Page 8-25

 GHGs to Report
Facilities assessing their applicability in the onshore petroleum and natural gas production
segment must only include emissions from equipment, as specified in 40 CFR 98.232(c) and
discussed below, to determine if they exceed the 25,000 metric ton CO2 equivalent threshold
and thus are required to report their GHG emissions to EPA. 526
§98.232(c) specifies that onshore petroleum and natural gas production facilities report CO2,
CH4, and N2O emissions from only the following source types:

526

•

Natural gas pneumatic device venting;

•

Natural gas driven pneumatic pump venting;

•

Well venting for liquids unloading;

•

Gas well venting during well completions without hydraulic fracturing;

•

Gas well venting during well completions with hydraulic fracturing;

•

Gas well venting during well workovers without hydraulic fracturing;

•

Gas well venting during well workovers with hydraulic fracturing;

•

Flare stack emissions;

•

Storage tanks vented emissions from producted hydrocarbons;

•

Reciprocating compressor rod packing venting;

•

Well testing venting and flaring;

•

Associated gas venting and flaring from produced hydrocarbons;

•

Dehydrator vents;

•

EOR injection pump blowdown;

•

Acid gas removal vents;

Federal Register, November 30, 2010, p. 77462.

Final SGEIS 2015, Page 8-26

 •

EOR hydrocarbon liquids dissolved CO2;

•

Centrifugal compressor venting;

•

Equipment leaks from valves, connectors, open ended lines, pressure relief valves,
pumps, flanges, and other equipment leak sources (such as instruments, loading arms,
stuffing boxes, compressor seals, dump lever arms, and breather caps); and

•

Stationary and portable fuel combustion equipment that cannot move on roadways under
its own power and drive train, and that are located at on onshore production well pad.
The following equipment is listed within the rule as integral to the extraction, processing,
or movement of oil or natural gas: well drilling and completion equipment; workover
equipment; natural gas dehydrators; natural gas compressors; electrical generators; steam
boilers; and process heaters.
GHG Emissions Calculations, Monitoring and Quality Assurance

40 CFR §98.233 prescribes the use of specific equations and methodologies for calculating GHG
emissions from each of the source types listed above. The GHG calculation methodologies used
in the rule generally include the use of engineering estimates, emissions modeling software, and
emission factors, or when other methods are not feasible, direct measurement of emissions. 527 In
some cases, the rule allows reporters the flexibility to choose from more than one method for
calculating emissions from a specific source type; however, reporters must keep record in their
monitoring plans as outlined in 40 CFR 98.3(g). 528
Also, for specified time periods during the 2011 data collection year, reporters may use best
available monitoring methods (BAMM) for certain emission sources in lieu of the monitoring
methods prescribed in §98.233. This is intended to give reporters flexibility as they revise
procedures and contractual agreements during early implementation of the rule. 529
40 CFR §98.234 mandates that the GHG emissions data be quality assured as applicable and
prescribes the use of specific methods to conduct leak detection of equipment leaks, procedures
to operate and calibrate flow meters, composition analyzers and pressure gages used to measure
quantities, and conditions and procedures related to the use of calibrated bags, and high volume

527

USEPA Fact Sheet for Subpart W, November 2010.

528

Federal Register. November 30, 2010, p. 74462.

529

Federal Register. November 30, 2010, p. 74462.

Final SGEIS 2015, Page 8-27

 samplers to measure emissions. Section 98.235 prescribes procedures for estimating missing
data.
Data Recordkeeping and Reporting Requirements
Title 40 CFR §98.3(c) specifies general recordkeeping and reporting requirements that all
facilities required to report under the rule must follow. For example, all reporters must:
•

Retain all required records for at least 5 years;

•

Keep records in an electronic or hard-copy format that is suitable for expeditious
inspection and review;

•

Make required records available to the EPA Administrator upon request;

•

List all units, operations, processes and activities for which GHG emissions were
calculated;

•

Provide the data used to calculate the GHG emissions for each unit, operation, process
and activity, categorized by fuel or material type;

•

Document the process used to collect the necessary data for GHG calculations;

•

Document the GHG emissions factors, calculations and methods used;

•

Document any procedural changes to the GHG accounting methods and any changes in
the instrumentation critical to GHG emissions calculations; and

•

Provide a written quality assurance performance plan which includes the maintenance
and repair of all continuous monitoring systems, flowmeters and other instrumentation.

40 CFR §98.236 specifies additional reporting requirements that are specific to the Petroleum
and Natural Gas Systems covered under Subpart W.
8.1.4

River Basin Commissions

SRBC and DRBC are not directly involved in the well permitting process, and the Department
will gather information related to proposed surface water withdrawals that are identified in well
permit applications. However, the Department will continue to participate on each Commission
to provide input and information regarding projects of mutual interest.

Final SGEIS 2015, Page 8-28

 On May 6, 2010 the DRBC announced that it would draft regulations necessary to protect the
water resources of the DRB during natural gas development. The drilling pad, accompanying
facilities, and locations of water withdrawals were identified as part of the natural gas extraction
project and subject to regulation by the DRBC. A draft rule was published in December 2010
and comments were accepted until April 15, 2011. There is no projected date or deadline for the
adoption of rule changes.
8.2

Intra-Department

8.2.1

Well Permit Review Process

The Division of Mineral Resources (DMN) would maintain its lead role in the review of Article
23 well permit applications, including review of the fluid disposal plan that is required by 6
NYCRR §554.1(c)(1). The Division of Water would assist in this review if the applicant
proposes to discharge either flowback water or production brine to a POTW. The Division of
Fish, Wildlife and Marine Resources (DFWMR) would have an advisory role regarding invasive
species control, and would assist in the review of site disturbance in Forest and Grassland Focus
Areas. The Division of Air Resources would have an advisory role with respect to applicability
of various air quality regulations and effectiveness of proposed emission control measures.
When a site-specific SEQRA review is required, DMN would be assisted by other appropriate
Department programs, depending on the reason that site-specific review is required and the
subject matter of the review. The Division of Materials Management (DMM) would review
applications for beneficial use of production brine in road-spreading projects.
8.2.1.1 Required Hydraulic Fracturing Additive Information
As set forth in Chapter 5, NYSDOH reviewed information on 322 unique chemicals present in
235 products proposed for hydraulic fracturing of shale formations in New York, categorized
them into chemical classes, and did not identify any potential exposure situations that are
qualitatively different from those addressed in the 1992 GEIS. The regulatory discussion in
Section 8.4 concludes that adequate well design prevents contact between fracturing fluids and
fresh ground water sources, and text in Chapter 6 along with Appendix 11 on subsurface fluid
mobility explains why ground water contamination by migration of fracturing fluid is not a
reasonably foreseeable impact. Chapters 6 and 7 include discussion of how setbacks, inherent
mitigating factors, and a myriad of regulatory controls protect surface waters. Chapter 7 also

Final SGEIS 2015, Page 8-29

 sets forth a water well testing protocol using indicators that are independent of specific additive
chemistry.
For every well permit application the Department would require, as part of the EAF Addendum,
identification of additive products, by product name and purpose/type, and proposed percent by
weight of water, proppants and each additive. This would allow the Department to determine
whether the proposed fracturing fluid is water-based and generally similar to the fluid
represented by Figures 5.3, 5.4, and 5.5. Additionally, the anticipated volume of each additive
product proposed for use would be required as part of the EAF Addendum. Beyond providing
information about the quantity of each additive product to be utilized, this requirement informs
the Department of the approximate quantity of each additive product that would be on-site for
each high-volume hydraulic fracturing operation.
The Department would also require the submittal of an MSDS for every additive product
proposed for use, unless the MSDS for a particular product is already on file as a result of the
disclosure provided during the preparation process of this SGEIS (as discussed in Chapter 5) or
during the application process for a previous well permit. Submittal of product MSDSs would
provide the Department with the identities, properties and effects of the hazardous chemical
constituents within each additive proposed for use.
Finally, the Department proposes to require that the application materials (i) document the
applicant’s evaluation of available alternatives for the proposed additive products that are
efficacious but which exhibit reduced aquatic toxicity and pose less risk to water resources and
the environment and (ii) contain a statement that the applicant will utilize such alternatives,
unless it demonstrates to DMN's satisfaction that they are not equally effective or feasible. The
evaluation criteria should include (1) impact to the environment caused by the additive product if
it remains in the environment, (2) the toxicity and mobility of the available alternatives, (3)
persistence in the environment, (4) effectiveness of the available alternative to achieve desired
results in the engineered fluid system and (5) feasibility of implementing the alternative.
In addition to the above requirements for well permit applications, the Department would
continue its practice of requiring hydraulic fracturing information, including identification of

Final SGEIS 2015, Page 8-30

 materials and volumes of materials utilized, on the well completion report 530 which is required,
in accordance with 6 NYCRR §554.7, to be submitted to the Department within 30 days after
the completion of any well. This requirement can be utilized by Department staff to verify that
only those additive products proposed at the time of application, or subsequently proposed and
approved prior to use, were utilized in a given high-volume hydraulic fracturing operation.
The Department has the authority to require, at any time, the disclosure of any additional
additive product composition information it deems necessary to ensure that environmental
protection and public health and safe drinking water objectives are met, or to respond to an
environmental or public health and safety concern. This authority includes the ability to require
the disclosure of information considered to be trade secret, so long as such information is
handled in accordance with the New York State Public Officer’s Law, POL§89(5), and the
Department’s Records Access Regulations, 6 NYCRR §616.7.
In accordance with the discussion in Chapter 7 regarding Publicly Owned Treatment Works
(POTWs), the Department proposes to require the disclosure of additional additive composition
information as part of any headworks analysis used to determine whether a particular treatment
facility can accept flowback or production brine from wells permitted pursuant to this
Supplement, or whether a modification to the POTW’s SPDES permit is necessary prior to any
acceptance of such fluids. This disclosure however, would be handled separately from the
application for permit to drill, as the evaluation of headworks analyses and any necessary SPDES
permit modifications would be handled through existing Department processes.
Public Disclosure of Additive Information
Although the Department must handle information which is sufficiently justified as trade secret
in accordance with existing law and regulation as previously discussed, the Department
considers MSDSs to be public information ineligible for exception from disclosure as trade
secrets. Therefore, the Department proposes to provide a listing of high-volume hydraulic
fracturing additive product names and links to the associated product MSDSs on an individual
well basis on its website. This would provide the public with a resource, beyond the Freedom of
530

The Well Drilling and Completion Report Form is available on the Department’s website at
http://www.dec.ny.gov/docs/materials_minerals_pdf/comp_rpt.pdf .

Final SGEIS 2015, Page 8-31

 Information Law, for obtaining information about the additives utilized in high-volume hydraulic
fracturing operations in New York, and it would provide the natural gas industry with a resource
for determining if a particular product MSDS is already on file with the Department or if an
MSDS needs to be submitted at the time a product is proposed for use.
The New York State Public Officer’s Law and the Department’s Records Access Regulations
would continue to govern the handling of any other records submitted to the Department as part
of the well permit application process, or in response to any Department request for additional
additive product composition information.
8.2.2

Other Department Permits and Approvals

The Division of Environmental Permits (DEP) manages most other permitting programs in the
Department and is therefore shown in Table 8.1 as having primary responsibility for wetlands
permitting, review of new in-state industrial treatment plants, and injection well disposal. The
Department’s technical experts on wetlands permitting reside in DFWMR. Technical review of
SPDES permits, including for industrial treatment plants, POTWs and injection wells is typically
conducted by DOW. Other programs where DOW bears primary responsibility include
stormwater permitting, dam safety permitting for freshwater impoundments, and review of
headworks analysis to determine acceptability of a POTW’s receiving flowback water. Waste
haulers who transport wellsite fluids come under the purview of DER’s Part 364 program, and
must obtain a Beneficial Use Determination for road-spreading from DMM. DFWMR would
review new proposed surface withdrawals to assist DMN in its determination of whether a sitespecific SEQRA determination is required. DAR would have a primary permitting role if
emissions at centralized flowback water surface impoundments or well pads trigger regulatory
thresholds.
8.2.2.1 Bulk Storage
The Department regulates bulk storage of petroleum and hazardous chemicals under 6 NYCRR
Parts 612-614 for Petroleum Bulk Storage (PBS) and Parts 595-597 for Chemical Bulk Storage
(CBS). The PBS regulations do not apply to non-stationary tanks; however, all petroleum spills,
leaks, and discharges must be reported to the Department (613.8).

Final SGEIS 2015, Page 8-32

 The CBS regulations that potentially may apply to fracturing fluids include non-stationary tanks,
barrels, drums or other vessels that store 1000 kg or greater for a period of 90 consecutive days.
Liquid fracturing chemicals are stored in non-stationary containers but most likely would not be
stored on-site for 90 consecutive days; therefore, those chemicals are exempt from Part 596,
“Registration of Hazardous Substance Bulk Storage Tanks” unless the storage period criteria are
exceeded. These liquids typically are trucked to the drill site in volumes required for
consumptive use and only days before the fracturing process. Dry chemical additives, even if
stored on site for 90 days, would be exempt from 6 NYCRR because the dry materials are stored
in 55-lb bags secured on plastic-wrapped pallets.
The facility must maintain inventory records for all applicable non-stationary tanks including
those that do not exceed the 90-day storage threshold. The CBS spill regulations and reporting
requirements also apply regardless of the storage thresholds or exemptions. Any spill of a
“reportable quantity” listed in Part 597.2(b), must be reported within 2 hours unless the spill is
contained by secondary containment within 24 hours and the volume is completely recovered.
Spills of any volume must be reported within two (2) hours if the release could cause a fire,
explosion, contravention of air or water quality standards, illness, or injury. Forty-two of the
chemicals listed in Table 5.7 are listed in Part 597.2(b).
8.2.2.2 Impoundment Regulation
Water stored within an impoundment represents potential energy which, if released, could cause
personal injury, property damage and natural resource damage. In order for an impoundment to
safely fulfill its intended function, the impoundment must be properly designed, constructed,
operated and maintained.
As defined by ECL Section 15-0503, a dam is any artificial barrier, including any earthen barrier
or other structure, together with its appurtenant works, which impounds or will impound waters.
As such, any engineered impoundment designed to store water for use in hydraulic fracturing
operations is considered to be a dam and is therefore subject to regulation in accordance with the
ECL, the Department’s Dam Safety Regulations and the associated Protection of Waters
permitting program.

Final SGEIS 2015, Page 8-33

 Statutory Authority
Chapter 364, Laws of 1999 amended ECL Sections 15-0503, 15-0507 and 15-0511 to revise the
applicability criteria for the dam permit requirement and provide the Department the authority to
regulate dam operation and maintenance for safety purposes. Additionally the amendments
established the dam owners’ responsibility to operate and maintain dams in a safe condition.
Although the revised permit criteria, which are discussed below, became effective in 1999,
implementing the regulation of dam operation and maintenance for all dams (regardless of the
applicability of the permit requirement) necessitated the promulgation of regulations. As such,
the Department issued proposed dam safety regulations in February 2008, followed by revised
draft regulations in May 2009 and adopted the amended regulations in August 2009. These
adopted regulations contain amendments to Part 673 and to portions of Parts 608 and 621 of Title
6 of the Official Compilation of Codes, Rules and Regulations of the State of New York. 531
Permit Applicability
In accordance with ECL §15-0503 (1)(a), a Protection of Waters Permit is required for the
construction, reconstruction, repair, breach or removal of an impoundment provided the
impoundment has:
•

a height equal to or greater than fifteen feet; 532 or

•

a maximum impoundment capacity equal to or greater than three million gallons. 533

If, however, either of the following exemption criteria apply, no permit is required:
•

a height equal to or less than six feet regardless of the structure’s impoundment
capacity; or

•

an impoundment capacity not exceeding one million gallons regardless of the
structure’s height.

531

NYSDEC Notice of Adoption of Amendments to Dam Safety Regulations.

532

Maximum height is measured as the height from the downstream [outside] toe of the dam at its lowest point to the highest
point at the top of the dam.

533

Maximum impounding capacity is measured as the volume of water impounded when the water level is at the top of the dam.

Final SGEIS 2015, Page 8-34

 Figure 8.1 depicts the aforementioned permitting criteria and demonstrates that a permit is
required for any impoundment whose height and storage capacity plot above or to the right of the
solid line, while those impoundments whose height and storage capacity plot below or to the left
of the solid line, do not require a permit.
Figure 8.1- Protection of Waters - Dam Safety Permitting Criteria

Protection of Waters - Dam Safety Permitting Process
If a proposed impoundment meets or exceeds the permitting thresholds discussed above, the well
operator proposing use of the impoundment is required to apply for a Protection of Waters
Permit though the Department’s Division of Environmental Permits.
A pre-application conference is recommended and encouraged for permit applicants, especially
those who are first-time applicants. Such a conference allows the applicant to explain the

Final SGEIS 2015, Page 8-35

 proposed project and to get preliminary answers to any questions concerning project plans,
application procedures, standards for permit issuance and information on any other applicable
permits pertaining to the proposed impoundment. It is also recommended that this conference
occur early in the planning phase, prior to detailed design and engineering work, so that
Department staff can review the proposal and comment on its conformance with permit issuance
standards, which may help to avoid delays later in the process.
Application forms, along with detailed application instructions are available on the Department’s
website 534 and from the Regional Permit Administrator 535 for the county where the impoundment
project is proposed. A complete application package 536 must include the following items:
•

A completed Joint Application for Permit;

•

A completed Application Supplement D-1, which is specific to the construction,
reconstruction or repair of a dam or other impoundment structure;

•

A location map showing the precise location of the project;

•

A plan of the proposed project;

•

Hydrological, hydraulic, and soils information, as required on the application form
prescribed by the Department;

•

An Engineering Design Report sufficiently detailed for Department evaluation of the
safety aspects of the proposed impoundment that shall include:
o A narrative description of the proposed project;
o The proposed Hazard Classification of the impoundment as a result of the
proposed activities or project;
o A hydrologic investigation of the watershed and an assessment of the hydraulic
adequacy of the impoundment;

534

Downloadable permit application forms are available at http://www.dec.ny.gov/permits/6338.html.

535

Contact information for the Department’s Regional Permit Administrators is available on the Department’s website at
http://www.dec.ny.gov/about/558.html.

536

Further details regarding the permit application requirement are available on the instructions which accompany the
Supplement D-1 application form which is available at
http://www.dec.ny.gov/docs/permits_ej_operations_pdf/spplmntd1.pdf.

Final SGEIS 2015, Page 8-36

 o An evaluation of the foundation and surrounding conditions, and materials
involved in the structure of the dam, in sufficient detail to accurately define the
design of the dam and assess its safety, including its structural stability;
o Structural and hydraulic design studies, calculation and procedures, which shall,
at a minimum, be consistent with generally accepted sound engineering practice
in the field of dam design and safety; and
o A description of any proposed permanent instrument installations in the
impoundment; and
•

Construction plans and specifications that are sufficiently detailed for Department
evaluation of the safety aspects of the dam.

Additionally the following information may also be required as part of the permit application:
•

Recent clear photographs of the project site mounted on a separate sheet labeled with the
view shown and the date of the photographs;

•

Information necessary to satisfy the requirements of SEQRA, including: a completed
Environmental Assessment Form (EAF) and, in certain cases, a Draft Environmental
Impact Statement (DEIS);

•

Information necessary to satisfy the requirements of the State Historic Preservation Act
(SHPA) including a completed structural and archaeological assessment form and, in
certain cases, an archaeological study as described by SHPA;

•

Written permission from the landowner for the filing of the project application and
undertaking of the proposed activity; and

•

Other information which Department staff may determine is necessary to adequately
review and evaluate the application.

In order to ensure that an impoundment is properly designed and constructed, the design,
preparation of plans, estimates and specifications, and the supervision of the erection,
reconstruction, or repair of an impoundment must be conducted by a licensed professional
engineer. This individual should utilize the Department’s technical guidance document

Final SGEIS 2015, Page 8-37

 “Guidelines for Design of Dams,” 537 which conveys sound engineering practices and outlines
hydrologic and other criteria that should be utilized in designing and constructing an engineered
impoundment.
All application materials should be submitted to the appropriate Regional Permit Administrator
for the county in which the project is proposed. Once the application is declared complete, the
Department will review the applications, plans and other supporting information submitted and,
in accordance with 6 NYCRR §608.7, may (1) grant the permit; (2) grant the permit with
conditions as necessary to protect the health, safety, or welfare of the people of the state, and its
natural resources; or (3) deny the permit.
The Department’s review will determine whether the proposed impoundment is consistent with
the standards contained within 6 NYCRR §608.8, considering such issues as:
•

the environmental impacts of the proposal, including effects on aquatic, wetland and
terrestrial habitats; unique and significant habitats; rare, threatened and endangered
species habitats; water quality538; hydrology539; water course and waterbody integrity;

•

the adequacy of design and construction techniques for the structure;

•

operation and maintenance characteristics;

•

the safe commercial and recreational use of water resources;

•

the water dependent nature of a use;

•

the safeguarding of life and property; and

•

natural resource management objectives and values.

Additionally, the Department’s review of the proposed impoundment will include the assignment
of a Hazard Classification in accordance with 6 NYCRR§673.5. Hazard Classifications are
assigned to dams and impoundments according to the potential impacts of a dam failure, the
537

“Guidelines for Design of Dams” is available on the Department’s website at
http://www.dec.ny.gov/docs/water_pdf/damguideli.pdf or upon request from the DEC Regional Permit Administrator.

538

Water Quality may include criteria such as temperature, dissolved oxygen, and suspended solids.

539

Hydrology may include such criteria as water velocity, depth, discharge volume, and flooding potential.

Final SGEIS 2015, Page 8-38

 particular physical characteristics of the impoundment and its location, and may be irrespective
of the size of the impoundment, as appropriate. The four potential Hazard Classifications, as
defined by subdivision (b) of Section 673.5, are as follows:
•

Class “A” or “Low Hazard”: A failure is unlikely to result in damage to anything
more than isolated or unoccupied buildings, undeveloped lands, minor roads such as
town or country roads; is unlikely to result in the interruption of important utilities,
including water supply, sewage treatment, fuel, power, cable or telephone
infrastructure; and/or is otherwise unlikely to pose the threat of personal injury,
substantial economic loss or substantial environmental damage;

•

Class “B” or “Intermediate Hazard”: A failure may result in damage to isolate homes,
main highways, and minor railroads; may result in the interruption of important
utilities, including water supply, sewage treatment, fuel, power, cable or telephone
infrastructure; and/or is otherwise likely to pose the threat of personal injury and/or
substantial economic loss or substantial environmental damage. Loss of human life is
not expected;

•

Class “C” or “High Hazard”: A failure may result in widespread or serious damage to
home(s); damage to main highways, industrial or commercial buildings, railroads,
and/or important utilities, including water supply, sewage treatment, fuel, power,
cable or telephone infrastructure; or substantial environmental damage; such that the
loss of human life or widespread substantial economic loss is likely; and

•

Class “D” or “Negligible or No Hazard”: A dam or impoundment that has been
breached or removed, or has failed or otherwise no longer materially impounds
waters, or a dam that was planned but never constructed. Class “D” dams are
considered to be defunct dams posing negligible or no hazard. The Department may
retain pertinent records regarding such dams.

The basis for the issuance of a permit will be a determination that the proposal is in the public
interest in that the proposal is reasonable and necessary, will not endanger the health, safety or
welfare of the people of the State of New York, and will not cause unreasonable, uncontrolled or
unnecessary damage to the natural resources of the state.
Timing of Permit Issuance
Application submission, time frames and processing procedures for the Protection of Waters
Permit are all governed by the provisions of Article 70 of the ECL – the Uniform Procedures Act

Final SGEIS 2015, Page 8-39

 (UPA) – and its implementing regulations, 6 NYCRR § 621. In accordance with subdivision
(a)(2)(iii) of Section 621 as recently amended, only repairs of existing dams inventoried by the
Department are considered minor projects under the UPA and therefore the construction,
reconstruction or removal of an impoundment is considered to be a major project and is thus
subject to the associated UPA timeframes.
Failure to obtain the required permit before commencing work subjects the well operator and any
contractors engaged in the work to Department enforcement action which may include civil or
criminal court action, fines, an order to remove structures or materials or perform other remedial
action, or both a fine and an order.
Operation and Maintenance of Any Impoundment
The Department’s document “An Owners Guidance Manual for the Inspection and Maintenance
of Dams in New York State” should be utilized by all impoundment owners, as it provides
important, direct and indirect steps they can take to reduce the consequences of an impoundment
failure.
The Dam Safety Regulations, as set forth in 6 NYCRR § 673 and amended August 2009, apply
to any owner of any impoundment, regardless of whether the impoundment meets the permit
applicability criteria previously discussed (unless otherwise specified). In accordance with the
general provisions of Section 673.3, any owner of any impoundment must operate and maintain
the impoundment and all appurtenant works in a safe condition. The owner of any impoundment
found to be in violation of this requirement is subject to the provisions of ECL 15-0507 and 150511.
In order to ensure the safe operation and maintenance of an impoundment, a written Inspection
and Maintenance Plan is required under 6 NYCRR §673.6 for any impoundment that (1) requires
a Protection of Waters Permit due to its height and storage capacity as previously discussed, (2)
has been assigned a Hazard Classification of Class “B” or “C”, or (3) impounds waters which
pose a threat of personal injury, substantial property damage or substantial natural resources
damage in the event of a failure, as determined by the Department. Such a plan shall be retained

Final SGEIS 2015, Page 8-40

 by the impoundment owner and updated as necessary, must be made available to the Department
upon request, and must include:
•

detailed descriptions of all procedures governing: the operation, monitoring, and
inspection of the dam, including those governing the reading of instruments and the
recording of instrument readings; the maintenance of the dam; and the preparation
and circulation of notifications of deficiencies and potential deficiencies;

•

a schedule for monitoring, inspections, and maintenance; and

•

any other elements as determined by the Department based on its consideration of
public safety and the specific characteristics of the dam and its location.

Additionally, the owner of any impoundment assigned a Hazard Classification of Class “B” or
“C” must, in accordance with 6 NYCRRR §673, prepare an Emergency Action Plan and annual
updates thereof , provide a signed Annual Certification to the Department’s Dam Safety Section,
conduct and report on Safety Inspections on a regular basis, and provide regular Engineering
Assessments. Furthermore, all impoundment structures are subject to the Recordkeeping and
Response to Request for Records provision of 6 NYCRR.
All impoundment structures, regardless of assigned Hazard Classification or permitting
requirements, are subject to field inspections by the Department at its discretion and without
prior notice. During such an inspection, the Department may document existing conditions
through the use of photographs or videos without limitation. Based on the field inspection, the
Department may create a Field Inspection Report and, if such a report is created for an
impoundment with a Class “B” or “C” Hazard Classification, the Department will provide a copy
of the report to the chief executive officer of the municipality or municipalities in which the
impoundment is located.
To further ensure the safe operation and maintenance of all impoundments, 6 NYCRR §673.17
allows the Department to direct an impoundment owner to conduct studies, investigations and
analyses necessary to evaluate the safety of the impoundment, or to remove, reconstruct or repair
the impoundment within a reasonable time and in a manner specified by the Department.

Final SGEIS 2015, Page 8-41

 8.2.3

Enforcement

Although DMN would retain a lead role in the review of Article 23 well permit applications and
DOW would be responsible for implementing the HVHF GP and approving the discharge from
POTWs who may accept waste from drilling operations, enforcement of violations of the ECL
will require a multi-divisional approach. The SGEIS addresses a broad range of topics and
requires mitigation for all aspects of a well drilling operation beginning with the source of fresh
water for hydraulic fracturing and proceeding long after production wells are drilled. Some of
the proposed mitigation measures identified in Chapter 7 would take the form of permit
conditions attached, as appropriate, to the permit to drill issued pursuant to ECL Article 23.
However, most of the proposed mitigation measures will be set forth as revisions or additions to
the Department’s regulations. Appendix 10 contains proposed supplementary permit conditions
for high-volume hydraulic fracturing, most of which will become revisions or additions to the
Department’s regulations. Failure of a well operator to adhere to conditions of the permit would
be considered a violation of ECL Article 23 and the failure of a well operator to comply with the
HVHF GP would be considered a violation of ECL Article 17. Failure of an operator to follow
the regulations of the Department would be considered a violation of the ECL Article 71.
While there are several different types of approvals needed from the Department in order to site
wells for high-volume hydraulic fracturing in New York, there are two permits that would be
specifically issued by the Department: the Article 23 permit to drill and the HVHF GP. For
informational purposes, a more detailed description of how those permits would be enforced is
provided below. This description is not intended to be exhaustive, since the type of enforcement
response depends entirely on the nature of the violation. For more detailed descriptions of the
Department’s regulations and enforcement policies, the Department’s website should be
consulted.
8.2.3.1 Enforcement of Article 23
The Oil, Gas & Solution Mining Law vests the Department with the authority to regulate the
development, production and utilization of the state’s natural energy resources. There are three
essential policy objectives embodied in ECL 23. Those objectives are to: 1) to prevent waste of
the oil and gas resource as “waste” is defined in the statute; 2) to provide for the operation and
development of oil and gas properties to provide for greater ultimate recovery of the resource,

Final SGEIS 2015, Page 8-42

 and; 3) to protect the correlative rights of all owners and the general public. To carry out these
objectives, ECL 23 specifically provides the Department with the authority to, among other
things:
“Require the drilling, casing, operation, plugging and replugging of wells and reclamation
of surrounding land in accordance with rules and regulations of the department in such
manner as to prevent or remedy the following, including but not limited to: the escape of
oil, gas, brine or water out of one stratum into another; the intrusion of water into oil or
gas strata other than during enhanced recovery operations; the pollution of fresh water
supplies by oil, gas salt water or other contaminants; and blowouts, cavings, seepages and
fires.” ECL 23-0305(8)(d).
Along with other powers enumerated in ECL 23, this broad grant of authority is implemented
through the Department’s oil and gas well regulations, found at 6 NYCRR Part 550, and through
the imposition of conditions attached to a permit to drill issued by the Division of Mineral
Resources. ECL Article 71 makes it unlawful for any person to fail to perform a duty imposed
by ECL 23 or to violate any order or permit condition issued by the Department. Therefore, a
failure of an operator to comply with a permit to drill exposes the well operator to an
enforcement action. Enforcement actions may be pursued through administrative, civil or
criminal means, depending on the nature of the violation. The Department may also call upon
the Attorney General to obtain injunctive relief against any person violating or threatening to
violate ECL 23.
Violations which are pursued administratively may result in an Order on Consent, which is a
settlement agreement signed by the Department and the well operator. There are two
Department policy documents which describe penalty calculations and the necessary components
of an Order and Consent: DEE-1, Civil Penalty Policy, and: DEE-2, Order on Consent
Enforcement Policy. Both policies can be found on the Department’s website at:
http://www.dec.ny.gov/regulations/2379.html. In cases where a settlement is not reached, a
hearing may be held pursuant to the Department’s Uniform Enforcement Hearing Procedures.

Final SGEIS 2015, Page 8-43

 The Oil, Gas & Solution Mining Law also provides the Department with the administrative
power to shut-in drilling or production operations whenever those operations fail to comply with
ECL 23, the Department’s regulations or any order issued by the Department. This power, found
in ECL 23-0305(8)(g), is injunctive in nature and allows the Department to immediately address
a violation without the need for a court order. This is an effective enforcement tool, particularly
in the case of producing wells since the Department, through 6 NYCRR Part 558, may serve the
shut-in order on a pipeline company or carrier, preventing them from transporting product from
an operator found in violation of Article 23.
8.2.3.2 Enforcement of Article 17
The Department will take appropriate action to ensure all regulated point source and non-point
source dischargers comply with applicable laws and regulations to protect public health and the
intended best use of the waters of the state in accordance with “Technical and Operational
guidance Series (TOGS) 1.4.2 – Compliance and Enforcement of State Pollutant Discharge
Elimination System (SPDES) Permits.” This guidance applies to all SPDES permits, including
individual and general permits.
TOGS 1.4.2 supplements existing Department policy regarding civil enforcement actions for
dischargers subject to individual and general permits and provides the minimum enforcement
response and penalty (if applicable). When appropriate, more stringent enforcement responses
may be utilized.
The focus of compliance and enforcement activities is based on resolving priority violations.
Any point source or non-point source discharge to an identified current year CWA Section
303(d) List of Impaired Waters segment; water bodies with a TMDL strategy or other restoration
measure; or a sole-source and/or primary aquifer is also a priority. Discharges from nonsignificant class facilities and unregulated non-point source discharges remain subject to
compliance and enforcement activities as necessary for the protection of public health and the
intended best use of the waters of the state.
Protection of the state’s water resources is required regardless of the Department’s compliance
and enforcement priorities. Any discharge that causes or contributes to a contravention of the

Final SGEIS 2015, Page 8-44

 water quality standards contained in 6 NYCRR Part 700 et seq. (or guidance values adopted
pursuant thereto), or impairs the quality of waters, or otherwise creates a nuisance or menace to
health, is a violation of ECL Article 17 and is subject to enforcement.
Discharging without the appropriate permit is a violation of ECL Article 17 and 6 NYCRR Part
750. A facility discharging without a permit is subject to enforcement prior to issuance of a
permit. Therefore, processing and review of a permit application may be suspended if an
enforcement action is commenced.
SPDES Compliance Evaluation
SPDES permits are issued to wastewater and stormwater dischargers for the protection of the
waters of the State. Operation and maintenance of SPDES-permitted facilities must comply with
applicable regulations pursuant to 6 NYCRR Part 750 and additional facility specific and general
permit conditions. When conditions of a permit, enforcement order or court decree are not met
or not implemented according to a schedule, water quality may be negatively impacted. Permit
compliance leads to protection of the public health and the intended best use of the waters of the
state.
The Department’s SPDES permit compliance program is directly supported by the following
elements which allow the Department to evaluate the compliance status of any regulated facility
and determine whether violations have or may occur:
Periodic Self-Reporting - The Department controls discharges of pollutants from some
SPDES permitted facilities by establishing pollutant specific effluent limits and operating
conditions in the permit and/or Order on Consent. Compliance with these limitations and
conditions via self-reporting is critical to the protection of water quality.
Some SPDES permits and Orders on Consent require reporting of pollutants that are discharged
on a Discharge Monitoring Report (DMR). The DMR is used by the Department to evaluate a
facility’s compliance with permit limitations. The information reported on DMRs is entered into
a database system for compliance assessment, tracking and reporting purposes. Timely and
accurate filing of DMRs is vital to ensuring compliance with the permit.

Final SGEIS 2015, Page 8-45

 The Division of Water (DOW) also relies on other reports (e.g., monthly operating, annual,
toxicity testing and status reports) and notifications (e.g., completion of permit or Order on
Consent compliance schedules), to determine the compliance status of a facility. These
documents may supplement or be submitted in lieu of a DMR, as specified in each permit or
enforcement order.
Inspections - The Department conducts site inspections and effluent sampling to monitor
facility performance, and to detect, identify and assess the magnitude of violations by a
discharger. The primary focus for inspections of individually permitted facilities is on major and
significant minor point source discharges and facilities that pose the highest risk to public health
and safety. The number and type of inspections to be performed at permitted facilities are
determined during DOW’s annual work planning process. The primary focus for inspections of
general permitted facilities is established annually through the same work planning process.
Standardized inspection forms have been developed to assist Department inspectors in assessing
the compliance status of dischargers in relation to the permit conditions, regulatory and record
keeping requirements. Additional inspection forms may be developed to comprehensively
evaluate compliance with permits issued for this activity.
Inspection information is entered into a database system for compliance evaluation, tracking and
reporting purposes. Inspection findings can be rated “satisfactory,” “marginal” or
“unsatisfactory.” An unsatisfactory rating is considered a priority and may be subject to
informal and/or formal enforcement.
The Department may use inspection information provided by federal, state and local
governmental entities to supplement compliance evaluations.
Citizen Complaints - Citizen complaints and observations of possible violations may
assist the Department's compliance and enforcement efforts for SPDES permits. The
Department will evaluate the authenticity of alleged violations and impacts to the environment
and/or public health and safety to determine an appropriate response. This response may include
enforcement. A “Notice of Intent to Sue” is a formal legal letter of intent to commence a federal
“citizens suit” that is served by private parties alleging violations of federal environmental laws,

Final SGEIS 2015, Page 8-46

 specifically the federal Clean Water Act (CWA). The Department has established a systematic
approach in reviewing and responding to such Notices.
SPDES Enforcement
The Department detects, investigates and resolves violations which are likely to impact the
public health or the water quality of the state. Staff will respond to each water priority violation
using the appropriate tools, including formal enforcement actions if necessary, to expedite a
return to compliance. To promote statewide consistency in the handling of water priority
violations in all SPDES programs, TOGS 1.4.2 contains a SPDES compliance and enforcement
response guide allowing staff to determine when enforcement is necessary to bring the facility
back to compliance. TOGS 1.4.2 describes the range of options available to the Department for
enforcement, ranging from warning letters and compliance conferences through more formal
proceedings involving hearings, summary abatement orders and referral to the Attorney
General’s Office. For a more detailed description of all the avenues available to the Department
for SPDES enforcement, TOGS 1.4.2 can be viewed at on the Department’s website at:
http://www.dec.ny.gov/docs/water_pdf/togs142.pdf.
SPDES Enforcement Coordination with EPA
The Department’s obligations with respect to compliance and enforcement of SPDES permits are
specified in the 1987 Enforcement Agreement between Region II of the USEPA and the
Department. This agreement outlines the elements essential to ensure compliance by the
regulated community. Some of these important elements are: monitoring permit compliance;
maintaining and sharing compliance information with EPA; identifying criteria for significant
non-compliance; listing facilities that require action by the Department to require non-complying
facilities to return to compliance; and timely and appropriate enforcement for priority violations.
The Department meets with EPA on a quarterly basis to cooperatively address priority violations
at major facilities and agree on enforcement responses to these violations and other significant
issues such as treatment plant bypasses, manure spills and citizen complaints.
Goals for the Department’s water compliance assurance activities are defined in the Division of
Water annual work planning process. The work plan identifies goals for activities such as for the

Final SGEIS 2015, Page 8-47

 numbers of inspections of facilities, management of data and number of enforcement actions.
The work plan also sets priorities to meet the compliance goals set by the Department and EPA.
Region II EPA also enters into an annual inspection work plan agreement with the Department’s
Division of Water. The EPA inspection work plan identifies roles and responsibilities for EPA,
communication and coordination protocols with Department. Enforcement response to
violations detected by EPA inspections may be conducted by EPA and/or the Department
depending on the situations. The Division of Water work plan and the EPA inspection work plan
may be modified to account for permits required by this activity.
8.3

Well Permit Issuance

8.3.1

Use and Summary of Supplementary Permit Conditions for High-Volume Hydraulic

Fracturing
A generic environmental impact statement addresses common impacts and identifies common
mitigation measures. The proposed Supplementary Permit Conditions for high-volume hydraulic
fracturing capture the mitigation measures identified as necessary by this review (see Appendix
10). These proposed conditions, some or all of which may be promulgated in revised
regulations, address all aspects of well pad activities, including:
•

Planning and local coordination;

•

Site preparation;

•

Site maintenance;

•

Drilling, stimulation (i.e., hydraulic fracturing) and flowback operations;

•

Reclamation; and

•

Other general aspects of the activity.

8.3.2

High-Volume Re-Fracturing

Because of the potential associated disturbance and impacts, the Department proposes that highvolume re-fracturing require submission of the EAF Addendum and the Department’s approval
after:

Final SGEIS 2015, Page 8-48

 8.4

•

review of the planned fracturing procedures and products, water source, proposed site
disturbance and layout, and fluid disposal plans;

•

a site inspection by Department staff; and

•

a determination of whether any other Department permits are required.
Other States’ Regulations

The Department committed in Section 2.1.2 of the Final Scope for this SGEIS to evaluate the
effectiveness of other states’ regulations with respect to hydraulic fracturing and to consider the
advisability of adopting additional protective measures based on those that have proven
successful in other states for similar activities. Department staff consulted the following sources
to conduct this evaluation:
1) Ground Water Protection Council, 2009b. The Ground Water Protection Council (GWPC) is
an association of ground water and underground injection control regulators. In May 2009,
GWPC reported on its review of the regulations of 27 oil and gas producing states. The
stated purpose of the review was to evaluate how the regulations relate to direct protection of
water resources;
2) ICF International, 2009a. NYSERDA contracted ICF International to conduct a regulatory
analysis of New York and up to four other shale gas states regarding notification, application,
review and approval of hydraulic fracturing and re-fracturing operations. ICF’s review
included Arkansas (Fayetteville Shale), Louisiana (Haynesville Shale), Pennsylvania
(Marcellus Shale) and Texas (Barnett Shale);
3) Alpha Environmental Consultants, Inc., 2009. NYSERDA contracted Alpha Environmental
Consultants, Inc., to survey policies, procedures, regulations and recent regulatory changes
related to hydraulic fracturing in Pennsylvania, Colorado, New Mexico, Wyoming, Texas
(including the City of Fort Worth), West Virginia, Louisiana, Ohio and Arkansas. Based on
its review, Alpha summarized potential permit application requirements to evaluate well pad
impacts and also provided recommendations for minimizing the likelihood and impact of
liquid chemical spills that are reflected elsewhere in this SGEIS;

Final SGEIS 2015, Page 8-49

 4) Colorado Oil & Gas Conservation Commission, Final Amended Rules. In the spring of
2009, the Colorado Oil & Gas Conservation Commission adopted new regulations regarding,
among other things, the chemicals that are used at wellsites and public water supply
protection. Colorado’s program was included in Alpha’s regulatory survey, but the amended
rules’ emphasis on topics pertinent to this SGEIS led staff to do a separate review of the
regulations related to chemical use and public water supply buffer zones;
5) June 2009 Statements on Hydraulic Fracturing from State Regulatory Officials. On June 4,
2009, GWPC’s president testified before Congress (i.e., the House Committee on Natural
Resources’ Subcommittee on Energy and Mineral Resources) regarding hydraulic fracturing.
Attached to his written testimony were letters from regulatory officials in Ohio,
Pennsylvania, New Mexico, Alabama and Texas. These officials unanimously stated that no
instances of ground water contamination directly attributable to the hydraulic fracturing
process had been documented in their states. Also in June 2009, the Interstate Oil and Gas
Compact Commission compiled and posted on its website statements from oil and gas
regulators in 12 of its member states: Alabama, Alaska, Colorado, Indiana, Kentucky,
Louisiana, Michigan, Oklahoma, Tennessee, Texas, South Dakota and Wyoming. 540 These
officials also unanimously stated that no verified instances of harm to drinking water
attributable to hydraulic fracturing had occurred in their states despite use of the process in
thousands of wells over several decades. All 15 statements are included in Appendix 15;
6) Pennsylvania Environmental Quality Board. Title 25-Environmental Protection, Chapter 78,
Oil and Gas Wells, Pennsylvania Bulletin, Col. 41. No. 6 ( February 5, 2011); and
7) Statement by Lisa Jackson, EPA Administrator on May 24, 2011 at a House Committee on
Oversight and Government Reform that she is “not aware of any proven case where the
fracturing process itself has affected water.”
Additional information is provided below regarding the findings and conclusions expressed by
GWPC, ICF and Alpha that are most relevant to the mitigation approach presented in this

540

http://www.iogcc.state.ok.us/hydraulic-fracturing.

Final SGEIS 2015, Page 8-50

 SGEIS. Pertinent sections of Colorado’s final amended rules are also summarized, and a brief
discussion of Pennsylvania’s recent revisions to its Chapter 78 Rules is presented.
8.4.1

Ground Water Protection Council

GWPC’s overall conclusion, based on its review of 27 states’ regulations, including New York’s,
is that state oil and gas regulations are adequately designed to directly protect water resources.
Hydraulic fracturing is one of eight topics reviewed. The other seven topics were permitting,
well construction, temporary abandonment, well plugging, tanks, pits and waste handling/spills.
Emphasis on proper well casing and cementing procedures is identified by GWPC and state
regulators as the primary safeguard against groundwater contamination during the hydraulic
fracturing procedure. This approach has been effective, based on the regulatory statements
summarized above and included in the Appendices. Improvements to casing and cementing
requirements, along with enhanced requirements regarding other activities such as pit
construction and maintenance, are appropriate responses to problems and concerns that arise as
technologies advance. Chapters 7 and 8 of this SGEIS, on mitigation measures and the permit
process, reflect consideration of requirements regarding either hydraulic fracturing or ancillary
activities in other states that address potential impacts associated with horizontal drilling and
high-volume hydraulic fracturing that are not covered by the 1992 GEIS.
8.4.1.1 GWPC - Hydraulic Fracturing
With respect to the specific topic of hydraulic fracturing, GWPC found that states generally
focus on well construction (i.e., casing and cement) and noted the importance of proper handling
and disposal of materials. GWPC recommends identification of fracturing fluid additives and
concentrations, as well as a higher level of scrutiny and protection for shallow hydraulic
fracturing or when the target formation is in close proximity to underground sources of drinking
water. GWPC did not provide thresholds for defining when hydraulic fracturing should be
considered “shallow” or “in close proximity” to underground sources of drinking water. GWPC
did not recommend additional controls on the actual conduct of the hydraulic fracturing
procedure itself for deep non-coalbed methane wells that are not in close proximity to drinking
water sources, nor did GWPC suggest any restrictions on fracture fluid composition for such
wells.

Final SGEIS 2015, Page 8-51

 GWPC urges caution against developing and implementing regulations based on anecdotal
evidence alone, but does recommend continued investigation of complaints of ground water
contamination to determine if a causal relationship to hydraulic fracturing can be established.
8.4.1.2 GWPC - Other Activities
Of the other seven topic areas reviewed by GWPC, permitting, well construction, tanks, pits and
waste handling and spills are addressed by this SGEIS. GWPC’s recommendations regarding
each of these are summarized below.
Permitting
Unlike New York, in many states the oil and gas regulatory authority is a separate agency from
other state-level environmental programs. GWPC recommends closer, more formalized
cooperation in such instances. Another suggested action related to permitting is that states
continue to expand use of electronic data management to track compliance, facilitate field
inspections and otherwise acquire, store, share, extract and use environmental data.
Well Construction
GWPC recommends adequate surface casing and cement to protect ground water resources,
adequate cement on production casing to prevent upward migration of fluids during all reservoir
conditions, use of centralizers and the opportunity for state regulators to witness casing and
cementing operations.
Tanks
Tanks, according to GWPC, should be constructed of materials suitable for their usage.
Containment dikes should meet a permeability standard and the areas within containment dikes
should be kept free of fluids except for a specified length of time after a tank release or a rainfall
event.
Pits
GWPC’s recommendations target “long-term storage pits.” Permeability and construction
standards for pit liners are recommended to prevent downward migration of fluids into ground
water. Excavation should not be below the seasonal high water table. GPWC recommends
against use of long-term storage pits where underlying bedrock contains seepage routes, solution

Final SGEIS 2015, Page 8-52

 features or springs. Construction requirements to prevent ingress and egress of fluids during a
flood should be implemented within designated 100-year flood boundaries. Pit closure
specifications should address disposition of fluids, solids and the pit liner. Finally, GWPC
suggests prohibiting the use of long-term storage pits within the boundaries of public water
supply and wellhead protection areas.
Waste Handling and Spills
In the area of waste handling, GWPC’s suggests actions focused on surface discharge because
“approximately 98% of all material generated . . . is produced water,” 541 and injection via
disposal wells is highly regulated. Surface discharge should not occur without the issuance of an
appropriate permit or authorization based on whether the discharge could enter water. As
reflected in Colorado’s recently amended rules, soil remediation in response to spills should be
in accordance with a specific cleanup standard such as a Sodium Absorption Ratio (SAR) for
salt-affected soil.
8.4.2

Alpha’s Regulatory Survey

Topics reviewed by Alpha include: pit rules and specifications, reclamation and waste disposal,
water well testing, fracturing fluid reporting requirements, hydraulic fracturing operations, fluid
use and recycling, materials handling and transport, minimization of potential noise and lighting
impacts, setbacks, multi-well pad reclamation practices, naturally occurring radioactive materials
and stormwater runoff. Alpha supplemented its regulatory survey with discussion of practices
directly observed during field visits to active Marcellus sites in the northern tier of Pennsylvania
(Bradford County).
8.4.2.1 Alpha - Hydraulic Fracturing
Alpha’s review with respect to the specific hydraulic fracturing procedure focused on regulatory
processes, i.e., notification, approval and reporting. Among the states Alpha surveyed,
Wyoming appears to require the most information.

541

GWPC, May 2009, p. 30.

Final SGEIS 2015, Page 8-53

 Pre-Fracturing Notification and Approval
Of the nine states Alpha surveyed, West Virginia, Wyoming, Colorado and Louisiana require
notification or approval prior to conducting hydraulic fracturing operations. Pre-approval for
hydraulic fracturing is required in Wyoming, and the operator would provide information in
advance regarding the depth to perforations or the open hole interval, the water source, the
proppants and estimated pump pressure. Consistent with GWPC’s recommendation, information
required by Wyoming Oil and Gas Commission Rules also includes the trade name of fluids.
Post-Fracturing Reports
Wyoming requires that the operator notify the state regulatory agency of the specific details of a
completed fracturing job. Wyoming requires a report of any fracturing and any associated
activities such as shooting the casing, acidizing and gun perforating. The report is required to
contain a detailed account of the work done; the manner undertaken; the daily volume of oil or
gas and water produced, prior to, and after the action; the size and depth of perforation; the
quantity of sand, chemicals and other material utilized in the activity and any other pertinent
information.
8.4.2.2 Alpha - Other Activities
The Department’s development of the overall mitigation approach proposed in this SGEIS also
considered Alpha’s discussion of other topics included in the regulatory survey. Key points are
summarized below.
Pit Rules and Specifications
Alpha’s review focused on reserve pits at the well pad. Several states have some general
specifications in common. These include:
•

Freeboard monitoring and maintenance of minimum freeboard;

•

Minimum vertical separation between the seasonal high ground water table and the pit
bottom, commonly 20 inches;

•

Minimum liner thickness of 20 – 30 mil, and maximum liner permeability of 1 x 10-7
cm/sec;

Final SGEIS 2015, Page 8-54

 •

Compatibility of liner material with the chemistry of the contained fluid, placement of the
liner with sufficient slack to accommodate stretching, installation and seaming in
accordance with the manufacturer’s specifications;

•

Construction to prevent surface water from entering the pit;

•

Sidewalls and bottoms free of objects capable of puncturing and ripping the liner; and

•

Pit sidewall slopes from 2:1 to 3:1.

Alpha recommends that engineering judgment be applied on a case-by-case basis to determine
the extent of vertical separation that should be required between the pit bottom and the seasonal
high water table. Consideration should be given to the nature of the unconsolidated material and
the water table; concern may be greater, for example, in a lowland area with high rates of inflow
from medium- to high-permeability soils than in upland till-covered areas.
Reclamation and Waste Disposal
In addition to its regulatory survey, Alpha also reviewed and discussed best management
practices directly observed in the northern tier of Pennsylvania and noted that “[t]he reclamation
approach and regulations being applied in PA may be an effective analogue going forward in
New York.” 542 The best management practices referenced by Alpha include:

542

•

Use of steel tanks to contain flowback water at the well pad;

•

On-site or offsite flowback water treatment for re-use, with residual solids disposed or
further treated for beneficial use or disposal in accordance with Pennsylvania’s
regulations;

•

Offsite treatment and disposal of production brine;

•

On-site encapsulation and burial of drill cuttings if they do not contain constituents at
levels that exceed Pennsylvania’s environmental standards;

•

Containerization of sewage and putrescible waste and transport off-site to a regulated
sewage treatment plant or landfill;

Alpha, 2009, p. 2-15.

Final SGEIS 2015, Page 8-55

 •

Secondary containment structures around petroleum storage tanks and lined trenches to
direct fluids to lined sumps where spills can be recovered without environmental
contamination; and

•

Partial reclamation of well pad areas not necessary to support gas production.

Alpha noted that perforating or ripping the pit liner prior to on-site burial could prevent the
formation of an impermeable barrier or the formation of a localized area of poor soil drainage.
Addition of fill may be advisable to mitigate subsidence as drill cuttings dewater and
consolidate. 543
Water Well Testing
Of the jurisdictions surveyed, Colorado and the City of Fort Worth have water well testing
requirements specifically directed at unconventional gas development within targeted regions.
Colorado’s requirements are specific to two particular situations: drilling through the Laramie
Fox Hills Aquifer and drilling coal-bed methane wells. Fort Worth’s regulations pertain to
Barnett Shale development, where horizontal drilling and high-volume hydraulic fracturing are
performed, and address all fresh water wells within 500 feet of the surface location of the gas
well. Ohio requires sampling of wells within 300 feet prior to drilling within urbanized areas.
West Virginia also has testing requirements for wells and springs within 1,000 feet of the
proposed oil or gas well. Louisiana, while it does not require testing, mandates that the results of
voluntary sampling be provided to the landowner and the regulatory agency.
Pennsylvania regulations presume the operator to be the cause of adverse water quality impacts
unless demonstrated otherwise by pre-drilling baseline testing, assuming permission was given
by the landowner. Alpha suggests that the following guidance provided by Pennsylvania and
voluntarily implemented by operators in the northern tier of Pennsylvania and southern tier of
New York should be effective:
•

543

With the landowner’s permission, monitor the quality of any water supply within 1,000
feet of a proposed drilling operation (at least one operator expands the radius to 2,000
feet if there are no wells within 1,000 feet);

Alpha, 2009, p. 2-15.

Final SGEIS 2015, Page 8-56

 •

Analyze the water samples using an independent, state certified, water testing laboratory;
and

•

Analyze the water for sodium, chlorides, iron, manganese, barium and arsenic (Alpha
recommends analysis for methane types, total dissolved solids, chlorides and pH).
Fluid Use and Recycling

Regarding surface water withdrawals, Alpha found that the most stringent rules in the states
surveyed are those implemented in Pennsylvania by the Delaware and Susquehanna River Basin
Commissions.
None of the states surveyed have any requirements, rules or guidance relating to the use of
treated municipal waste water.
Ohio allows the re-use of drilling and flowback water for dust and ice control with an approval
resolution, and will consider other options depending on technology. West Virginia recommends
that operators consider recycling flowback water.
Practices observed in the northern tier of Pennsylvania include treatment at the well pad to
reduce TDS levels below 30,000 ppm. The treated fluids are diluted by mixing with fresh
makeup water and used for the next fracturing project.
Materials Handling and Transport
Alpha provided the review of pertinent federal and state transportation and container
requirements that is included in Section 5.5, and concluded that motor transport of all hazardous
fracturing additives or mixtures to drill sites is adequately covered by existing federal and
NYSDOT regulations. 544 Best management practices such as the following were identified by
Alpha for implementation on the well pad:

544

•

Monitoring and recording inventories;

•

Manual inspections;

•

Berms or dikes;

Alpha, 2009, p. 2-31

Final SGEIS 2015, Page 8-57

 •

Secondary containment;

•

Monitored transfers;

•

Stormwater runoff controls;

•

Mechanical shut-off devices;

•

Setbacks;

•

Physical barriers; and

•

Materials for rapid spill cleanup and recovery.
Minimization of Potential Noise and Lighting Impacts

Colorado, Louisiana, and the City of Fort Worth address noise and lighting issues. Ohio
specifies that operations be conducted in a manner that mitigates noise. With respect to noise
mitigation, sample requirements include:
•

Ambient noise level determination prior to operations;

•

Daytime and nighttime noise level limits for specified zones (in Colorado, e.g.,
residential/agricultural/rural, commercial, light industrial and industrial) or for distances
from the wellsite, and periodic monitoring thereof;

•

Site inspection and possibly sound level measurements in response to complaints;

•

Direction of all exhaust sources away from building units; and

•

Quiet design mufflers or equivalent equipment within 400 feet of building units.

The City of Fort Worth has much more detailed noise level requirements and also sets general
work hour and day of the week guidelines for minimizing noise impacts, in consideration of the
population density and urban nature of the location where the activity occurs.
Alpha found that lighting regulations, where they exist, generally require that site lighting be
directed downward and internally to the extent practicable. Glare minimization on public roads
and adjacent buildings is a common objective, with a target distance of 300 feet from the well in

Final SGEIS 2015, Page 8-58

 Louisiana and Fort Worth and 700 feet from the well in Colorado. Lighting impact
considerations would be balanced against the safety of well site workers.
Setbacks
Alpha’s setback discussion focused on water resources and private dwellings. The setback
ranges in Table 8.3 were reported regarding the surveyed jurisdictions.
Table 8.3 - Water Resources and Private Dwelling Setbacks from Alpha, 2009

Water Resources
Arkansas

Colorado

Louisiana

New Mexico

Ohio
Pennsylvania

Private
Measured From
Dwellings
200 feet from surface waterbody or wetland, or
200 feet, or
Storage tanks
300 feet for streams or rivers designated as
100 feet with
Extraordinary Resource Water, Natural and Scenic owner’s
Waterway, or Ecologically Sensitive Water Body waiver
300 feet (“internal buffer;” applies only to
Not reported Surface operation,
classified water supply segments – see discussion
including drilling,
below)
completion, production
and storage
Not reported
500 feet, or
Wellbore
200 feet with
owner’s
consent
300 feet from continuously flowing water course; 300 feet
Any pit, including fluid
200 feet from other significant water course, lake
storage, drilling
bed, sinkhole or playa lake; 500 feet from private,
circulation and waste
disposal pits
domestic, fresh water wells or springs used by less
than 5 households; 1000 feet from other fresh
water wells or springs; 500 feet from wetland; pits
prohibited within defined municipal fresh water
well field or 100-year floodplain
200 feet from private water supply wells
100 feet
Wellhead
200 feet from water supply springs and wells; 100 200 feet
Well pad limits and
feet from surface water bodies and wetlands
access roads

City of Fort
Worth

200 feet from fresh water well

Wyoming

350 feet from water supplies

Final SGEIS 2015, Page 8-59

600 feet, or
Wellbore surface
300 feet with location for single-well
waiver
pads; closest point on
well pad perimeter for
multi-well sites
350 feet
Pits, wellheads,
pumping units, tanks
and treatment systems

 Multi-Well Pad Reclamation Practices
Except for Pennsylvania, Alpha found that the surveyed jurisdictions treat multi-well pad
reclamation similarly to single well pads. Pennsylvania implements requirements for best
management practices to address erosion and sediment control.
As with single well pads, partial reclamation after drilling and fracturing are done would include
closure of pits and revegetation of areas that are no longer needed.
Stormwater Runoff
Most of the reviewed states have stormwater runoff regulations or best management practices for
oil and gas well drilling and development. Alpha suggests that Pennsylvania’s approach of
reducing high runoff rates and associated sediment control by inducing infiltration may be a
suitable model for New York. Perimeter berms and filter fabric beneath the well pad allow
infiltration of precipitation. Placement of a temporary berm across the access road entrance
during a storm prevents rapid discharge down erodible access roads that slope downhill from the
site.
8.4.3

Colorado’s Final Amended Rules

Significant changes were made to Colorado’s oil and gas rules in 2008 that became effective in
spring 2009. While many topics were addressed, the new rules related to chemical inventorying
and public water supply protection are most relevant to the topics addressed by this SGEIS.
8.4.3.1 Colorado - New MSDS Maintenance and Chemical Inventory Rule
The following information is from a training presentation posted on COGCC’s website. 545 The
new rule’s objective is to assist COGCC in investigation of spills, releases, complaints and
exposure incidents. The rule requires the operators to maintain a chemical inventory of chemical
products brought to a well site for downhole use, if more than 500 pounds is used or stored at the
site for downhole use or if more than 500 pounds of fuel is stored at the well site during a
quarterly reporting period. The chemical inventory, which is not submitted to the COGCC
unless requested, includes:

545

http://cogcc.state.co.us; “Final Amended Rules” and “Training Presentations” links, 7/8/2009.

Final SGEIS 2015, Page 8-60

 •

MSDS for each chemical product;

•

How much of the chemical product was used, how it was used, and when it was used;

•

Identity of trade secret chemical products, but not the specific chemical constituents; and

•

Maximum amount of fuel stored.

The operator must maintain the chemical inventory and make it available for inspection in a
readily retrievable format at the operator’s local field office for the life of the wellsite and for
five years after plugging and abandonment.
MSDSs for proprietary products may not contain complete chemical compositional information.
Therefore, in the case of a spill or complaint to which COGCC must respond, the vendor or
service provider must provide COGCC a list of chemical constituents in any trade secret
chemical product involved in the spill or complaint. COGCC may, in turn, provide the
information to the Colorado Department of Public Health and Environment (CDPHE). The
vendor or service provider must also disclose this list to a health professional in response to a
medical emergency or when needed to diagnose and treat a patient that may have been exposed
to the product. Health professionals’ access to the more detailed information which is not on
MSDSs is subject to a confidentiality agreement. Such information regarding trade secret
products provided to the COGCC or to health professionals does not become part of the chemical
inventory and is not considered public information.
8.4.3.2 Colorado - Setbacks from Public Water Supplies
The following information was provided by Alpha and supplemented from a training
presentation posted on COGCC’s website. 546
Colorado’s new rules require buffer zones along surface water bodies in surface water supply
areas. Buffer zones extend five miles upstream from the water supply intake and are measured
from the ordinary high water line of each bank to the near edge of the disturbed area at the well
location. The buffer applies to surface operations only and does not apply to areas that do not

546

http://cogcc.state.co.us; “Final Amended Rules” and “Training Presentations” links, 7/8/2009.

Final SGEIS 2015, Page 8-61

 drain to classified water supply systems. The buffers are designated as internal (0-300 feet),
intermediate (301-500 feet) and external (501-2,640 feet).
Activity within the internal buffer zone requires a variance and consultation with the CDPHE.
Within the intermediate zone, pitless (i.e., closed-loop) drilling systems are required, flowback
water must be contained in tanks on the well pad or in an area with down gradient perimeter
berming, and berms or other containment devices are required around production-related tanks.
Pitless drilling or specified pit liner standards are required in the external buffer zone. Water
quality sampling and notification requirements apply within the intermediate and external buffer
zones.
8.4.4

Summary of Pennsylvania Environmental Quality Board. Title 25-Environmental

Protection, Chapter 78, Oil and Gas Wells
A number of Pennsylvania’s recent Chapter 78 revisions relate to enhancements to well control
and construction requirements as a result of extensive drilling and completion operations in the
Marcellus Shale in that state. 547 Specific casing and cementing procedures designed to protect
drinking water supplies are now codified as a result of these revisions.
8.4.5

Other States’ Regulations - Conclusion

Experience in other states is similar to that of New York as a regulator of gas drilling operations.
Well control and construction, and materials handling regulations, including those pertaining to
pit construction, when properly implemented and complied with, prevent environmental
contamination from drilling and hydraulic fracturing activities. The reviews and surveys
summarized above are informative with respect to developing enhanced mitigation measures
relative to multi-well pad drilling and high-volume hydraulic fracturing. Consideration of the
information presented above is reflected in Chapters 7 and 8 of this SGEIS.

547

http://www.pacode.com/secure/data/025/chapter78/chap78toc.html “Chapter 78. Oil and Gas Wells.

Final SGEIS 2015, Page 8-62

 Chapter 9
Alternative Actions
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Chapter 9 – Alternative Actions
CHAPTER 9 ALTERNATIVE ACTIONS ..................................................................................................................... 9-1
9.1 NO-ACTION ALTERNATIVE .................................................................................................................................. 9-1
9.2 PHASED PERMITTING APPROACH ......................................................................................................................... 9-4
9.2.1 Inherent Difficulties in Predicting Gas Well Development Rates and Patterns........................................... 9-5
9.2.2 Known Tendency for Development to Occur in Phases without Government Intervention ...................... 9-5
9.2.3 Prohibitions and Limits that Function as a Partial Phased Permitting Approach ........................................ 9-6
9.2.3.1 Permanent Prohibitions ................................................................................................................... 9-6
9.2.3.2 Prohibitions in Place for at Least 3 Years ......................................................................................... 9-7
9.2.3.3 Prohibitions in Place for At Least 2 Years ......................................................................................... 9-7
9.2.4 Permit Issuance Matched to Department Resources.................................................................................. 9-8
9.3 “GREEN” OR NON-CHEMICAL FRACTURING TECHNOLOGIES AND ADDITIVES................................................................... 9-8
9.3.1 Environmentally-Friendly Chemical Alternatives ...................................................................................... 9-10
9.3.2 Summary ................................................................................................................................................... 9-11

TABLES
Table 9.1 - Marcellus Permits Issued in Pennsylvania, 2007 - 2010 .......................................................................... 9-6

Final SGEIS 2015, Page 9-i

 This page intentionally left blank.

Chapter 9 ALTERNATIVE ACTIONS
Chapter 21 of the 1992 GEIS and the 1992 Findings Statement discussed a range of alternatives
concerning oil and gas resource development in New York State that included both its
prohibition and the removal of oil and gas industry regulation. Regulation as described by the
1992 GEIS was found to be the best alternative. Regulatory revisions recommended by the 1992
GEIS have been incorporated into permit conditions, which have been continuously improved
since 1992.
The following alternatives to issuance of permits for high-volume hydraulic fracturing to develop
the Marcellus Shale and other low-permeability gas reservoirs have been reviewed for the
purpose of this SGEIS:

9.1

•

The denial of permits to develop the Marcellus Shale and other low-permeability gas
reservoirs by horizontal drilling and high-volume hydraulic fracturing (No-action
alternative);

•

The use of a phased-permitting approach to developing the Marcellus Shale and other
low-permeability gas reservoirs, including consideration of limiting and/or restricting
resource development in designated areas; and

•

The required use of “green” or non-chemical fracturing technologies and additives.
No-Action Alternative

The no-action alternative to the proposed action would be denial of permits to drill where highvolume hydraulic fracturing is proposed and a prohibition on development of the Marcellus
Shale and other low-permeability reservoirs using this method. If the no-action alternative were
selected, none of the potential significant adverse impacts identified in this SGEIS would occur.
Unlike any other activity regulated by the Department, the potential for significant adverse
impacts is wide-ranging and widespread, including impacts to water resources, forests,
ecosystems and wildlife, air resources, and greenhouse gas emissions across a substantial portion
of the State. There are also potential significant community impacts, including increased truck
traffic, wear and tear on roads and bridges, increased noise and light pollution and
industrialization of rural landscapes.

Final SGEIS 2015, Page 9-1

 The impacts to water resources that would be avoided by the no-action alternative merit special
attention. Even with mitigation measures in place, the risk of spills and other unplanned events
resulting in the discharge of toxic pollutants over a wide area would not be eliminated.
Moreover, the level of risk such spills pose to public health is highly uncertain.
At the same time, if the no-action alternative is selected, none of the economic benefits identified
in Chapters 2 and 6 would occur through the extraction of this energy resource. However, the
no-action alternative would also eliminate the anticipated costs associated with properly
regulating high-volume hydraulic fracturing. These costs include repairing and replacing local
infrastructure, responding to increased demands on emergency services and health care providers
and conducting oversight of permit applications and operations under the permits and the
investigation and remediation of any spills or discharges which will inevitably occur during
high-volume hydraulic fracturing development and transportation. These impacts and response
costs have the potential to overwhelm local, county and State governments and their capacity to
deal effectively with the multi-dimensional nature of the impacts of high-volume hydraulic
fracturing. Indeed, the Department estimates that the cost of administering this program under
the average development scenario would grow from $14 million in the first year to nearly $25
million in the fifth year. These costs do not consider the other substantial costs that would be
incurred by other state agencies, which would nearly double the total State costs associated with
regulating high-volume hydraulic fracturing, or the costs imposed on local agencies.
As more fully described in Chapter 2, the Marcellus Shale, which extends from Ohio through
West Virginia and into Pennsylvania and New York, is attracting attention as a significant new
source of natural gas production. In New York, the Marcellus Shale is located in much of the
Southern Tier, stretching from Chautauqua and Erie counties in the west to the counties of
Sullivan, Ulster, Greene and Albany in the east. According to Penn State University, the
Marcellus Shale is the largest known shale deposit in the world. Engelder and Lash (2008) first
estimated gas-in-place to be between 168 and 500 Tcf with a recoverable estimate of 50 Tcf. 549
While it is very early in the productive life of Marcellus Shale wells, more recent estimates by

549

Considine et al., 2009, p. 2.

Final SGEIS 2015, Page 9-2

 Engelder (2009) using well production decline rates indicate a 50% probability that recoverable
reserves could be as high as 489 Tcf. 550
The 2009 New York State Energy Plan recognized the potential benefit to New York from the
strategic development of in-state energy resources, including renewable resources and natural
gas:
Production and use of in-state energy resources – renewable resources and natural
gas – can increase the reliability and security of our energy systems, reduce
energy costs, and contribute to meeting climate change and environmental
objectives. To the extent that renewable resources and natural gas are able to
displace the use of higher emitting fossil fuels, relying more heavily on these instate resources will also reduce public health and environmental risks posed by all
sectors that produce and use energy. Additionally, by focusing energy
investments on in-state opportunities, New York can reduce the amount of dollars
“exported” out of the State to pay for energy resources. 551
The 2009 Energy Plan further included a recommendation to encourage development of the
Marcellus Shale natural gas formation with environmental safeguards that are protective of water
supplies and natural resources. 552 This recommendation, however, is premised on the
assumption that the development of the Marcellus Shale can be done in an environmentally
sound manner. If, on the other hand that development cannot be done safely, or if there remain
substantial public health and environmental impacts and increasing uncertainty as to those
potential impacts or, correspondingly, the effectiveness of proposed safeguards, permitting
development of the resource would be inconsistent with the caution expressed in the
recommendation. Indeed, the most recent draft State Energy Plan (2014) excludes any mention
of support for development of high-volume hydraulic fracturing.
Furthermore, the 2009 Energy Plan and the draft 2014 Energy Plan recognize that in order to
achieve its overall greenhouse gas (GHG) emission reduction goals, the State must continue to
transition from fossil fuels to non-emitting clean energy sources. Increased availability of lowcost natural gas has the potential to reduce the cost-effectiveness of investment in various types

550

Considine et al., 2009, p. 2.

551

NYS Energy Planning Board, August 2009.

552

NYS Energy Planning Board, August 2009.

Final SGEIS 2015, Page 9-3

 of renewable energy and energy efficiency, thereby suppressing investment in and use of these
clean energy technologies. While natural gas may serve as a “bridge” or “transitional fuel”
towards greater utilization of non-emitting clean energy sources, increased natural gas
development could extend the use of fossil fuels, or delay the necessary deployment of clean
energy.
The New York State Commission on Asset Maximization recommends that “Taking into account
the significant environmental considerations, the State should study the potential for new private
investment in extracting natural gas in the Marcellus Shale on State-owned lands, in addition to
development on private lands.” The Final report concluded that an increase in natural gas
supplies would place downward pressure on natural gas prices, improve system reliability and
result in lower energy costs for New Yorkers. In addition, natural gas extraction would create
jobs, provide income to upstate landowners, and increase State revenue from taxes and
landowner leases and royalties. Development of State‐owned lands could provide much needed
revenue relief to the State and spur economic development and job creation in economically
depressed regions of the State. 553 However, as noted above, this recommendation fails to
consider the environmental and public health impacts of high-volume hydraulic fracturing and
the costs associated with allowing and/or properly regulating high-volume hydraulic fracturing.
9.2

Phased Permitting Approach

The use of a phased-permitting approach to developing the Marcellus Shale and other lowpermeability gas reservoirs, including consideration of limiting and restricting resource
development in designated areas, was evaluated. Phased permitting would potentially place a
temporal and/or geographic limit on impacts from high-volume hydraulic fracturing operations
to the extent such limits were less than the annual demand for well permits. The proposed
mitigation considered in Chapter 7 would partially adopt this alternative by restricting resource
development in the NYC and Syracuse watersheds (plus buffer), public water supplies, primary
aquifers and certain state lands. In addition, restrictions and setbacks relating to development in
other areas near public water supplies, principal aquifers and other resources as outlined within
this SGEIS, would further limit the areas with site disturbances.

553

NYS Commission on Asset Maximization, June 2009.

Final SGEIS 2015, Page 9-4

 A formal phasing plan is not practical because of the inherent difficulties in predicting gas well
development rates and patterns for a particular region or part of the State. In addition, the
Department’s prior experience with well drilling in the State and its review of the development
of high-volume hydraulic fracturing in other states suggests that well development tends to occur
in phases and increase over time without a formal government mandate.
9.2.1

Inherent Difficulties in Predicting Gas Well Development Rates and Patterns

The level of impact on a regional basis would be determined by the amount of development and
the rate at which it occurs. Accurately estimating this is inherently difficult due to the wide and
variable range of the resource; rig, equipment and crew availability; permitting and oversight
capacity; leasing, and most importantly economic factors. This holds true regardless of the type
of drilling and stimulation utilized.
9.2.2

Known Tendency for Development to Occur in Phases without Government Intervention

Upon completion of this Supplement, permit issuance and drilling would start slowly as services
and equipment are mobilized to the area and the Department gains experience in implementing
the enhanced application review procedures. The drilling rate would ramp up over a number of
years until it reaches a peak, and would then ramp down over several years until full-field
development is reached. 554
In Pennsylvania, where the Marcellus play covers a larger area and development has already
occurred, the number of permits issued has increased in recent years as indicated in Table 9.1.
(The source data provides information on the number of permits issued and is not indicative of
the number of wells drilled.) 555

554

ALL Consulting, 2010, p. 6

555

NTC Consultants, 2011, p. 36

Final SGEIS 2015, Page 9-5

 Table 9.1 - Marcellus Permits Issued in Pennsylvania, 2007 - 2010

Marcellus Permits Issued
(Pennsylvania)
99
529
1,991
3,446

Year
2007
2008
2009
2010

It is unknown whether the peak development rate has been reached in Pennsylvania, or how long
it will take to reach full-field development in either Pennsylvania or New York. In general,
however, the stages of development of a natural gas play can be grouped into five general
categories: Exploration/Early Development, Moderate Development, Large-Scale Development,
Post-Development Production and Closure and Reclamation. These stages are not discrete, but
overlap and may occur concurrently in different areas. For example, initial production may
begin during early development and well pads may be closed and reclaimed in one area as
production continues elsewhere. In addition, development levels wax and wane as prices vary
and technological advances occur. 556
9.2.3

Prohibitions and Limits that Function as a Partial Phased Permitting Approach

As set forth below, the proposed mitigation considered in Chapter 7 would partially adopt a
phased approach because it would restrict resource development in certain areas. In addition,
restrictions and setbacks relating to development in other areas near public water supplies,
principal aquifers and other resources as outlined within this SGEIS, would further limit the
areas where site disturbances would be allowed for a certain period of time.
9.2.3.1 Permanent Prohibitions
The Department would not approve well pads for high-volume hydraulic fracturing:

556

•

Within the NYC and Syracuse watersheds, or within a 4,000-foot buffer around those
watersheds;

•

Within 500 feet of private drinking water wells or domestic use springs, unless waived by
the owner;

Dutton and Blankenship 2010, p. 7.

Final SGEIS 2015, Page 9-6

 •

Within 100-year floodplains; and

•

On certain state-owned land.

These limits would function as a partial “phased” permitting approach because they would
prohibit activities in areas deemed to be especially sensitive. As reflected in the response to
comments, subsequent to the issuance of the 2011 dSGEIS, the Department considered
additional mitigation measures, such as banning any high-volume hydraulic fracturing
development in the Catskill Park and eliminating sunset periods for various restrictions, in the
face of ever increasing information detailing the actual environmental and public health impacts
that result from high-volume hydraulic fracturing development.
9.2.3.2 Prohibitions in Place for at Least 3 Years
The Department would not approve well pads for high-volume hydraulic fracturing within 2,000
feet of public water supply wells, river or stream intakes or reservoirs until at least 3 years after
issuance of the first permit for high-volume hydraulic fracturing. Reconsideration of this
prohibition at that time would be based on actual experience and impacts associated with permit
issuance outside these buffer zones. This approach functions as a partial “phased” permitting
approach because it prohibits and limits activities in areas deemed to be especially sensitive
where a phased and cautious approach is merited.
9.2.3.3 Prohibitions in Place for At Least 2 Years
The Department would not approve well pads for high-volume hydraulic fracturing within 500
feet of primary aquifers until at least 2 years after issuance of the first permit for high-volume
hydraulic fracturing. Furthermore, during this time, the Department also would require sitespecific SEQRA determinations of significance for proposed well pads within 500 feet of
principal aquifers. Reconsideration of these restrictions after two years would be based on actual
experience and impacts associated with permit issuance outside these buffer zones. These limits
would function as a partial “phased” permitting approach because they would prohibit and limit
activities in areas deemed to be especially sensitive where a phased and cautious approach is
merited.

Final SGEIS 2015, Page 9-7

 9.2.4

Permit Issuance Matched to Department Resources

The Department believes that any specific annual limit on the number of well permits to be
issued would have to be tied to specific environmental, public health or community impacts to
avoid a claim that the Department acted without a reasonable basis. The Department recognizes
that the risk of significant adverse impacts has the potential to increase if permits were issued in
excess of the Department’s capacity to adequately police such development and enforce permit
conditions. Accordingly, if permitting were allowed to proceed, the Department would consider
a limitation on the number of permits it issues to match the Department resources that are made
available to review and approve permit applications and to adequately inspect well pads and
enforce permit conditions and regulations.
9.3

“Green” or Non-Chemical Fracturing Technologies and Additives

Hydraulic fracturing operations involve the use of significant quantities of additives/products,
albeit in low concentrations, which potentially could have an adverse impact on the environment
if not properly controlled. The recognition of potential hazards has motivated investigation into
environmentally-friendly alternatives for hydraulic fracturing technologies and chemical
additives. 557
It is important to note that use of ‘environmentally friendly’ or “green” alternatives may reduce,
but not entirely eliminate, adverse environmental impacts. Therefore, further research into each
alternative is warranted to fully understand the potential environmental impacts and benefits of
using any of the alternatives. In addition, the claimed benefits of such alternatives would need to
be evaluated in a holistic manner, considering the full lifecycle impact of the technology or
chemical. 558
URS reports that the following environmentally-friendly technology alternatives have been
identified as being in use in the Marcellus Shale, with other fracturing/stimulation applications or
under investigation for possible use in Marcellus Shale operations:

557

URS, 2009, pp. 6-1 - 6-7.

558

URS, 2009, pp. 6-1 - 6-7.

Final SGEIS 2015, Page 9-8

 Liquid CO2 alternative – The use of a liquid CO2 and proppant mixture reduces the use of
other additives [19]. CO2 vaporizes, leaving only the proppant in the fractures. The use
of this technique in the United States has been limited to demonstrations or pilots [20].
The appropriate level of environmental review for this alternative, if proposed in New
York, would be determined at the time of application;
Nitrogen-based foam alternative – Nitrogen-based foam fracturing was used in vertical
shale wells in the Appalachian Basin until recently [21]. Nitrogen gas is unable to carry
appreciable amounts of proppant and the nitrogen foam was found to introduce liquid
components that can cause formation damage [22]. Nitrogen-based foam fracturing is
discussed starting on page 9-27 of the 1992 GEIS (Volume 1); and
Liquefied Petroleum Gas (LPG) alternative – The use of LPG, consisting primarily of
propane, has the advantages of carbon dioxide and nitrogen cited above; additionally,
LPG is known to be a good carrier of proppant due to the higher viscosity of propane gel
[55]. Further, mixing LPG with natural gas does not ‘contaminate’ natural gas; and the
mixture may be flowed directly into a gas pipeline and separated at the gas plant and
recycled [55]. LPG’s high volatility, low weight, and high recovery potential make it a
good fracturing agent. Use of LPG as a hydraulic fracturing fluid also inhibits formation
damage which can occur during hydraulic fracturing with conventional fluids. Using
propane not only minimizes formation damage, but also eliminates the need to source
water for hydraulic fracturing, recover flowback fluids to the surface and dispose of the
flowback fluids. 559 As a result of the elimination of hydraulic fracturing source water,
truck traffic to and from the wellsite would be greatly reduced. In addition, since LPG is
less reactive with the formation matrix, it is therefore less likely to mobilize constituents
which could increase NORM levels in the flowback fluid. LPG is discussed and
addressed in the 1992 GEIS in the context of the permitting of underground gas storage
wells and facilities in the State. Currently, there are three operating underground LPG
storage facilities and associated wells for the injection and withdrawal of LPG, with a
total storage capacity of approximately 150 million gallons of LPG. It is quite possible

559

Smith, 2008, p. 3.

Final SGEIS 2015, Page 9-9

 that these storage facilities which are located in Cortland, Schuyler and Steuben Counties
could supply the LPG needed to conduct hydraulic fracturing operations at wells
targeting the Marcellus Shale and other low-permeability gas reservoirs should a well
operator make such a proposal for the Department’s approval.
Well applications that specify and propose the use of LPG as the primary carrier fluid
will be reviewed and permitted pursuant to the 1992 GEIS and Findings Statement.
Horizontal and directional wells, which are part of the main subject of this SGEIS, are
already in use in the Marcellus Shale. While these drilling techniques require larger
quantities of water and additives per well because of the relatively longer target interval,
horizontal and directional wells are considered to be more environmentally-friendly
because these types of wells provide access to a larger volume of gas/oil than a typical
vertical well [20, 23]. 560
9.3.1 Environmentally-Friendly Chemical Alternatives
The use of alternative chemical additives in hydraulic fracturing is another facet to the
“environmentally- friendly” development in recent years.
There are several US-based chemical suppliers who advertise “green” hydraulic fracturing
additives. Examples include: Earth-friendly GreenSlurry system from Schlumberger used in
both the U.K. North Sea and the Gulf of Mexico [29]; Ecosurf EH surfactants by Dow
Chemicals; CleanStim by Halliburton; and “Green” Chemicals for the North Sea from BASF.
The EPA has published the twelve principles of “green” chemistry and a sustainable chemistry
hierarchy [30], yet these do not provide a common measure of environmental benefits to assess
“green” hydraulic fracturing additives. 561
Although several US-based chemicals suppliers advertise “green” chemicals, there does not seem
to be a US-based metric to evaluate the environmental benefits of these chemicals. 562 The most
significant environmentally conscious hydraulic fracturing operations and regulations to date are

560

URS, 2009, pp. 6-1 - 6-7.

561

URS, 2009, pp. 6-1 - 6-7.

562

URS, 2009, pp. 6-1 - 6-7.

Final SGEIS 2015, Page 9-10

 likely in the North Sea. Several countries have established criteria that define environmentally
beneficial chemicals and utilize models and databases to track chemicals’ overall hazardousness
against those criteria. Similar to the Department, the regulatory authorities in Europe request
proprietary information from chemicals suppliers, and do not release any proprietary information
into the public domain. The proprietary recipes for chemical additives are used to assess their
potential hazard to the environment, and regulate their use as necessary. 563 In addition, the
manufacturers of these “green” alternatives point out that they are not effective under some
conditions. For example, where high clay content is found in the shale formation, a petroleum
distillate may be needed to carry compounds designed to address the difficulties created by the
clay. It is, therefore, not evident that the ability of operators to choose the most effective fluids
to perform hydraulic fracturing can be reasonably circumscribed by government restrictions at
this time.
9.3.2

Summary

As the Marcellus Shale and other shale plays across the United States are developed, the
development and use of “green chemicals” will proceed based on the characteristics of each play
and the potential environmental impacts of the development. While more research and approval
criteria would be necessary to establish benchmarks for “green chemicals”, this SGEIS considers
thresholds, permit conditions and review criteria to reduce or mitigate potential environmental
impacts for development of the Marcellus Shale and other low-permeability gas reservoirs using
high volume hydraulic fracturing. It also considers requiring that applicants evaluate and, where
feasible, use alternative additive products that may pose less risk to the environment, including
water resources. It also considers public disclosure of the additives, including additive MSDSs,
used at each well. These requirements could be altered and/or expanded as clearer evidence
emerges that the use of “green chemicals” can provide reasonable alternatives as the appropriate
technology, criteria, and processes are developed to evaluate and produce “green chemicals.”

563

URS, 2009, pp. 6-1 - 6-7.

Final SGEIS 2015, Page 9-11

 This page intentionally left blank.

Chapter 10
Review of Selected Non-Routine
Incidents in Pennsylvania
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Chapter 10 – Review of Selected Non-Routine Incidents in Pennsylvania
CHAPTER 10 REVIEW OF SELECTED NON-ROUTINE INCIDENTS IN PENNSYLVANIA ............................................ 10-1
10.1 GAS MIGRATION – SUSQUEHANNA AND BRADFORD COUNTIES ............................................................................... 10-1
10.1.1 Description of Incidents ........................................................................................................................... 10-1
10.1.2 New York Mitigation Measures Designed to Prevent Gas Migration Similar to the Pennsylvania
Incidents .................................................................................................................................................. 10-1
10.2 FRACTURING FLUID RELEASES – SUSQUEHANNA AND BRADFORD COUNTIES ............................................................... 10-2
10.2.1 Description of Incidents ........................................................................................................................... 10-2
10.2.2 New York Mitigation Measures Designed to Prevent Fracturing Fluid Releases..................................... 10-3
10.3 UNCONTROLLED WELLBORE RELEASE OF FLOWBACK WATER AND BRINE – CLEARFIELD COUNTY ..................................... 10-3
10.3.1 Description of Incident ............................................................................................................................ 10-3
10.3.2 New York Mitigation Measures Designed to Prevent Uncontrolled Wellbore Release of Flowback
Water and Brine ...................................................................................................................................... 10-4
10.4 HIGH TOTAL DISSOLVED SOLIDS (TDS) DISCHARGES – MONONGAHELA RIVER ........................................................... 10-4
10.4.1 Description of Incidents ........................................................................................................................... 10-4
10.4.2 New York Mitigation Measures Designed to Prevent High In-Stream TDS ............................................. 10-4

Final SGEIS 2015, Page 10-i

 This page intentionally left blank.

Chapter 10 REVIEW OF SELECTED NON-ROUTINE INCIDENTS IN
PENNSYLVANIA
More than 3,000 Marcellus wells have been drilled in Pennsylvania since 2005, most of which
have been or will be developed by high-volume hydraulic fracturing. A number of regulatory
violations, non-routine incidents and enforcement cases have been widely publicized. Some of
them are briefly described below, with information about the measures currently required in New
York or those that the Department proposes to require that are designed to prevent similar
problems if high-volume hydraulic fracturing is permitted in the Empire State.
10.1

Gas Migration – Susquehanna and Bradford Counties

10.1.1 Description of Incidents
In 2009, the appearance of methane in water wells in an area in Dimock Township, Susquehanna
County, was attributed to excessive pressures and improperly or insufficiently cemented casings
at nearby Marcellus wells. 564 Numerous occurrences of methane migration into residential water
wells during 2010 in Tuscarora, Terry, Monroe, Towanda and Wilmot Townships, Bradford
County were attributed to the failure to properly case and cement wells. 565
10.1.2 New York Mitigation Measures Designed to Prevent Gas Migration Similar to the
Pennsylvania Incidents
The potential for water wells to be impacted by methane migration associated with gas well
construction was a high-profile concern in Chautauqua County, New York, in the 1980s. ThenCommissioner Henry Williams addressed the situation in a decision issued after a public hearing
held in Jamestown. That decision, which among other things directed staff to (1) require wells in
primary and principal aquifers to be cemented to surface and (2) prohibit excessive annular
pressure, is the foundation of New York’s current well construction requirements. The 1992
GEIS adopted minimum casing and cement practices, which are augmented as necessary to
address site-specific conditions and incorporated as conditions of every well permit the
Department issues. Additionally, the Department does not issue a permit to drill any well until
the proposed wellbore design for that specific well and location has been reviewed by

564
565

PADEP, 2009, p. 3.
PADEP, 2011, p. 9.

Final SGEIS 2015, Page 10-1

 Department staff and deemed satisfactory. Permits are not issued for improperly designed wells,
and for high-volume hydraulic fracturing, as-built wellbore construction would be verified as
described in Chapter 7. Additionally, intermediate casing would be required, unless clearly
justified otherwise, with the setting depths of both surface and intermediate casing determined by
site-specific conditions.
The effectiveness of the Department’s well construction approach with respect to gas migration
is demonstrated by the rarity of gas migration incidents in New York. The most recent incident
occurred 15 years prior to the date of this document, in 1996, and resulted not from well
construction but from the operator reacting improperly to a problem encountered while drilling.
More than 3,000 wells have been drilled under ECL Article 23 permits since 1996 without
another occurrence.
As noted in the 1992 GEIS and in Section 4.7 of this document, methane is naturally present in
water wells in many locations in New York, for many reasons unrelated to gas well drilling.
This is a fact which must be evaluated and considered when a gas drilling impact is suspected as
a source of methane in water wells.
10.2

Fracturing Fluid Releases – Susquehanna and Bradford Counties

10.2.1 Description of Incidents
In 2009, three fracturing fluid releases occurred at a single well pad in Dimock Township,
Susquehanna County. The releases resulted from equipment failures when the pressure rating of
some piping components on the well pad were exceeded while the operator was mixing and
pumping fluid for hydraulic fracturing. This resulted from a combination of pressure
fluctuations while pumping and a significant elevation difference between the fresh water tanks
and the well pad. The fresh water tanks were located 240 feet above the well pad and the mixing
area was 190 feet above and over 2,000 feet away from the well pad. 566
On April 19, 2011, an uncontrolled flow of hydraulic fracturing fluid occurred during fracture
stimulation of Chesapeake Energy’s Atlas 2H well in LeRoy Township, Bradford County. The
Department’s Commissioner visited this site on June 16, 2011, and was briefed by officials from
566

Cabot Oil & Gas Corporation, 2009.

Final SGEIS 2015, Page 10-2

 the Pennsylvania Department of Environmental Protection, Chesapeake Energy, and the
Bradford County Soil and Water Conservation District. At the briefing and tour of the well pad,
it was learned that a failure occurred at a valve flange connection to the wellhead, causing fluid
to be discharged from the wellhead at high pressure. Approximately 60,000 gallons of fluid
were discharged to the well pad, of which 10,000 gallons flowed over the top of the containment
berms. A portion of this fluid made its way into an unnamed tributary of Towanda Creek. The
wellhead failure is under investigation to determine the precise cause of the breach. The
wellhead was pressure-tested after installation and after each hydraulic fracturing stage prior to
the breach. According to Chesapeake officials, it passed all tests. The discharge of fluid from
the well pad was caused by the failure of stormwater controls on the well pad due to
extraordinary precipitation and other factors. 567
10.2.2 New York Mitigation Measures Designed to Prevent Fracturing Fluid Releases
The site layout in Dimock was unusual and, if proposed in New York, would be flagged during
the Department’s review of the application materials, which always include maps and a prepermitting site inspection. Such a layout would not be approved by the Department without sitespecific permit conditions designed to address the risks associated with hillside locations. Steep
slopes above surface water bodies reduce the time available to respond to a release or spill, and
in New York locations on steep slopes above potential drinking water supplies are not eligible
for authorization under a general stormwater permit.
It is important to note that in both cases it was mixed fracturing fluid that was released, not
undiluted additives. Supplementary permit conditions for high-volume hydraulic fracturing in
New York will require pressure testing of fracturing equipment components with fresh water
prior to introducing additives.
10.3

Uncontrolled Wellbore Release of Flowback Water and Brine – Clearfield County

10.3.1 Description of Incident
In 2010 an operator in Lawrence Township, Clearfield County, lost control of a wellbore during
post-fracturing cleanout activities, releasing natural gas, flowback water and brine into the
567

Although described in press accounts as a “blowout,” such terminology is not technically correct because the
source of pressure was the fracturing operations on the surface. A blowout is an uncontrolled intrusion of fluid
under high pressure into the wellbore, from the rock formation.

Final SGEIS 2015, Page 10-3

 environment. It was determined that blowout prevention equipment was inadequate and that
certified well-control personnel were not on-site. 568
10.3.2 New York Mitigation Measures Designed to Prevent Uncontrolled Wellbore Release of
Flowback Water and Brine
Proposed supplementary permit conditions for high-volume hydraulic fracturing would require
pressure testing of blowout prevention equipment, the use of at least two mechanical barriers that
can be tested, the use of specialized equipment designed for entering the wellbore when pressure
is anticipated and the on-site presence of a certified well control specialist.
10.4

High Total Dissolved Solids (TDS) Discharges – Monongahela River

10.4.1 Description of Incidents
During seasonal low-flow conditions in the Monongahela River in 2008, an increase in gasdrilling wastewater discharges may have provided the TDS “tipping point” for the Monongahela
River. At the time, many rivers in that state were unable to assimilate new high-TDS waste
streams because they were already impaired by pre-existing elevated TDS levels from various
historic practices, and Pennsylvania’s regulations did not include a surface water quality standard
for TDS. In the three years since these events occurred, Pennsylvania has enacted new
regulations that restrict discharge of high-TDS wastewater associated with Marcellus Shale
development. The PADEP has also requested that Marcellus operators discontinue discharging
flowback water to facilities that are “grandfathered” from the new requirements. Additionally,
as discussed in Section 1.1.1, operators in Pennsylvania are now reusing flowback water for
subsequent fracturing operations.
10.4.2 New York Mitigation Measures Designed to Prevent High In-Stream TDS
New York’s water quality standards include an in-stream limit for TDS and SPDES permits
include effluent limitations based on a stream’s assimilative capacity. As described in Chapters
7 and 8, and in Appendix 22, the Department has a robust permitting and approval process in
place to address any proposals to discharge flowback water or production brine to wastewater
treatment plants. Additionally, the Department anticipates that operators will favor reusing
flowback water for subsequent fracturing operations as they are now doing in Pennsylvania.
568

PADEP, 2010.

Final SGEIS 2015, Page 10-4

 Chapter 11
Summary of Potential Impacts
and Mitigation Measures
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Chapter 11 – Summary of Potential Impacts and Mitigation Measures
CHAPTER 11 SUMMARY OF POTENTIAL IMPACTS AND MITIGATION MEASURES .............................................. 11-1
TABLES
Table 11.1 - Summary of Potential Impacts and Proposed Mitigation Measures (New July 2011) ........................ 11-2

Final SGEIS 2015, Page 11-i

 This page intentionally left blank.

Chapter 11 SUMMARY OF POTENTIAL IMPACTS AND MITIGATION MEASURES
A complete description of the potential impacts associated with horizontal drilling and highvolume hydraulic fracturing is presented in Chapter 6. The mitigation measures proposed to
minimize those impacts are discussed in Chapter 7, while the associated Supplementary permit
conditions are provided in Appendix 10. Additionally, Chapter 8 includes descriptions of other
applicable state and federal regulatory programs which have authority over activities associated
with natural gas well development. Table 11.1 below provides a summary of the potential
impacts and proposed mitigation measures.

Final SGEIS 2015, Page 11-1

 6.1.1-2

Same as above.

6.1.1.3-6

6-26-5

6.1.1.3-6

Same as above.

Loss or impairment of aquatic habitat, aquatic
ecosystems, or aquifer recharge ability in
surface waters.

7.1.1.4

7-14

7.1.1.4

Long-term damage to groundwater resources

6.1.1.6

6-5

6.1.1.5

Requires pump testing and site-specific SEQRA for
groundwater withdrawal near wetlands and water wells

7.1.1.5

7-24

7.1.1.5

Cumulative surface water withdrawal impacts.

6.1.1.7

6-6

6.1.1.7

Addressed by individual passby flow determinations as
above.

7.1.1.6

7-25

7.1.1.6

6.1.2

6-14

6.1.2

Requires erosion prevention and sediment control through
development of and adherence to a SWPPP through a
SPDES permit. 


7.1.2

7-26

7.1.2

Requires application for and coverage under the General
Permit before commencement of operations.

7.1.2

7-26

7.1.2

Contamination of surface and/or subsurface
waters from stormwater runoff.

16.B.3.a,b

16-12..15

.

p.

Requires site-specific SEQRA review from any lake or pond.

pp
.

6-2

7.1.1.4

GE
IS

6.1.1-2

7-14

se
c

Reduced stream flow and degradation of a
stream's best use.

7.1.1.4

GE
IS

Requires determination of and adherence to passby flow
for each surface water proposed for withdrawals using the
Natural Flow Regime method.

MITIGATING MEASURE

IS
p

6.1.1.1

dS
GE

6-2

dS
GE
se IS
ct
io
n

p.

6.1.1.1

GE
IS

Depletion of water supply in streams.

GE
IS

IMPACT

Water resources

dS
GE

RESOURCE

SG
EI
se S
ct
io
n
SG
EI
Sp

pp
.

.
se
c

IS
p

dS
GE
se IS
ct
io
n

SG
EI
se S
ct
io
n
SG
EI
Sp

p.

p.

Table 11.1 Summary of Potential Impacts and Proposed Mitigation Measures

Authorizes permit conditions on a case-by-case basis
regarding erosion and sediment control in watersheds of
drinking water reservoirs.

17.B.1.j

17-6

Specifies a reclamation timetable of 45 days following
cessation of drilling.

17.B.2.c

17-7

Requires a Stream Disturbance Permit when project is
w/in 50' of a protected stream. Authorizes permit
conditions on a case-by-case bais regarding stream
crossings, access roads, EPSC measures, and reclamation.

17.B.1.d

17-4..5

Well pads for high-volume hydraulic fracturing prohibited
within 2000' of public drinking water wells, river or stream
intakes and reservoirs.

7.1.11

7-29

7.1.12.1

17.B.1.c

17-4

Specifies setback distances from structures, surface
waters, public/private water wells, and water supply
springs.

7.1.11

7-29

7.1.12.1

17.B.2.a

17-6..7

Final SGEIS 2015, Page 11-2

 Water resources
(cont.)

Contamination of surface waters,
groundwater, or drinking water aquifers from
chemical, fuel, or lubricant spills (including
drilling and fracturing fluids). (cont.)

6.1.3

7.1.3.1

7-33

7.1.3.1

No well pads within 500' of a private water well, unless
waived by the landowner.

7.1.3.1

7-33

7.1.3.1

Specifies continuous monitoring of refueling operations.

7.1.3.1

7-33

7.1.3.1

Requires spill response and cleanup to be addressed in the
SWPPP by inclusion of Best Management Practices to
control, remediate, and clean up spills.

7.1.3.1

7-33

7.1.3.1

Individual crew member responsibilites must be posted
for well-control. Blowout Preventers (BOPs) must be
adequately sized and tested.

7.1.3.2

7-34

7.1.3.2

Affords DEC option to implement location-specific HVHF
fluid management restrictions and permit conditions.

7.1.3.3

7-38

7.1.3.3

Hydraulic fracturing fluid additives should be required by
permit condition to be placed in lined containment areas.

7.1.3.3

7-38

7.1.3.3

Identification of a spill response team and employee
training on proper spill prevention and response
techniques.

7.1.3.3

7-38

7.1.3.3

Requires a closed-tank system for flowback water handled
at the wellpad.

7.1.3.4

7-39

7.1.3.4

Requires reporting EAF addendum on quantity,
worthiness, volume, and location of tanks to accept
flowback water.

7.1.3.4

7-39

7.1.3.4

Promote reuse of flowback water

7.1.3.4

7-39

7.1.3.4

Requires operators to consider less toxic alternative
hydraulic fracturing fluid additives.

8.2.1.1

8-29

8.2.1.2

Limits duration of fluid impoundment after
permanent/temporary suspension of drilling/hydraulic
fracturing.

7.1.3.4

7-39

7.1.3.4

Specifies continuous supervision of fluid transfer activities.

7.1.3.4

7-39

7.1.3.4

Final SGEIS 2015, Page 11-3

pp
.
GE
IS

GE
IS

se
c

.

p.

Requires reporting in EAF addendum of location of fuel
tanks relative to surface waters, wetlands, drinking water
wells, and aquifer boundaries.

IS
p

p.

MITIGATING MEASURE

dS
GE

16-16..19

dS
GE
se IS
ct
io
n

16.B.4.a,c

SG
EI
se S
ct
io
n
SG
EI
Sp

pp
.

.
se
c

GE
IS

6-15

GE
IS

6.1.3

IS
p

Contamination of surface waters,
groundwater, or drinking water aquifers from
chemical, fuel, or lubricant spills (including
drilling and fracturing fluids).

dS
GE

IMPACT

Water resources
(cont.)

dS
GE
se IS
ct
io
n

RESOURCE

SG
EI
se S
ct
io
n
SG
EI
Sp

p.

p.

Table 11.1 Summary of Potential Impacts and Proposed Mitigation Measures

 Specifies spill prevention and response BMPs to be
addressed in SWPPP. At least two vacuum trucks must be
on standby at the wellsite during the flowback phase.

Water resources
(cont.)

Contamination of groundwater/aquifers from
natural gas, drilling fluids, or HVHF fluids in
the wellbore.

6.1.4

6-41

6.1.4

7.1.3.4

7-39

GE
IS

GE
IS

se
c

pp
.

.

p.
IS
p
dS
GE

dS
GE
se IS
ct
io
n

p.

MITIGATING MEASURE

SG
EI
se S
ct
io
n
SG
EI
Sp

pp
.
GE
IS

.
se
c
GE
IS

IS
p
dS
GE

IMPACT

dS
GE
se IS
ct
io
n

RESOURCE

SG
EI
se S
ct
io
n
SG
EI
Sp

p.

p.

Table 11.1 Summary of Potential Impacts and Proposed Mitigation Measures

7.1.3.4

Requires dikes around oil storage tanks.

17.B.2.f

17-7

References requirement for BOPs on wells in NY state.

17.C.1.l

17-12

Subjects operators to enforcement actions and penalties
upon release of flowback fluids onto the ground.

17.C.1.m

17-12

Affords right to the department to require fluid-level
monitors on tanks where repeated overflows have
occurred.

17.D.2.c

17-16

17.C.1.q

17-12..13

Specifies frequency and character of sampling, testing, and
reporting of nearby private water wells before, during, and
after drilling and HVHF activity.

7.1.4.1

7-44

7.1.4.1

Affords DEC the right to curtail or modify operations when
a well complaint and a non-routine wellpad incident
coincide.

7.1.4.1

7-44

7.1.4.1

No well pads for high-volume hydraulic fracturing within
the boundaries of a primary aquifer.

7.1.3.5

7-40

7.1.3.5

No well pads for high-volume hydraulic fracturing
permitted within 500' of a primary aquifer

7.1.3.5

7-40

7.1.3.5

No well pads for high-volume hydraulic fracturing within
500' of a principal aquifer without site-specific SEQRA
review and an individual SPDES permit

7.1.3.5

7-40

7.1.3.5

Requires operator to test private water wells

7.1.4.1

7-44

7.1.4.1

Specifies permit conditions for more stringent casing
construction and cementing, reporting of well information,
and testing of cement job for HVHF wells.

7.1.4.2

7-49

7.1.4.2

Requires departmental notification prior to surface casing
cementing.

7.1.4.2

7-49

7.1.4.2

Specifies constant venting of annulus to prevent pressure
buildup, unless the annular gas is to be produced, in which
case the equipment and production pressure must receive
departmental approval.

7.1.4.3

7-55

7.1.4.3

Final SGEIS 2015, Page 11-4

 Water resources
(cont.)

Contamination of aquifers/ groundwater from
hydraulic fracturing

6.1.5

6-43

6.1.5

Contamination of surface or subsurface water
with HVHF or drilling fluids from container
leakage, structural failure, or improper
transportation.

6.1.6

6-53

6.1.6

16.B.3.b,c

16-14..15

GE
IS

pp
.

GE
IS

se
c

.

p.
IS
p

17.C.1.g-j

17-8..11

State Inspector must be present during surface and
production string cement jobs. State may order remedial
cement work.

17.C.1.q

17-12

Requires continuous venting of annulus.

17.C.1.q

17-13

Requires properly plugging and abandoning well by
isolating hydrocarbon bearing formations with cement
plugs, heavy mud, and casing withdrawal.

17.E.1.c-d

17-17..18

Further specifies plugging materials and methods to
ensure vertical isolation across the well depth.

17.E.2.cd,f,h-m

17-19..22

Limits duration of temporary abandonment of wells.

17.E.1.e-f

17-18

Extends limits on duration of temporary abandonment to
all wells (see 17.E.1.e-f).

17.E.2.o

17-23

Affords the department the right to take temporary
possession of and plug any well in case of operator neglect
or unpermitted abandonment, and requires financial
security prior to application to fund said operation.

17.E.1.a,j

17-17..18

Operators must identify and characterize any existing
wells within the spacing unit and within one mile of
proposed well and plug any abandoned well which is open
to the target formation or is otherwise an immediate
threat to the environment.

Contamination of groundwater/aquifers from
natural gas, drilling fluids, or HVHF fluids in
the wellbore. (cont.)

dS
GE

Specifies methods and materials for the installation and
cementing of the various casings, including the dimensions
of cementing to isolate the producing and other gasbearing formations from overlying, potentially, watersupplying formations.

Requires diligence of operator in researching, locating,
characterizing, and reporting public and private water
wells within 2640 feet (1/2 mile) of proposed well.

Water resources
(cont.)

dS
GE
se IS
ct
io
n

p.

MITIGATING MEASURE

SG
EI
se S
ct
io
n
SG
EI
Sp

pp
.
GE
IS

.
se
c
GE
IS

IS
p
dS
GE

IMPACT

dS
GE
se IS
ct
io
n

RESOURCE

SG
EI
se S
ct
io
n
SG
EI
Sp

p.

p.

Table 11.1 Summary of Potential Impacts and Proposed Mitigation Measures

7.1.11.1

7-71

7.1.12.1

7.1.6

7-56

7.1.6

Requires site-specific SEQRA review of HVHF permit
applications to produce from a formation with < 1000' of
vertical separation from potential or known subsurface
water supplies. (see 6.1.5.2)

7.1.5

7-55

7.1.5

Closed-tank systems must be used for flow-back of wells.

7.1.3.4

7-39

7.3.1.2

Final SGEIS 2015, Page 11-5

 Water resources
(cont.)

Water resources
(cont.)

Contamination of soil or water from improper
disposal, transportation, or release of waste
solids or fluids (including HVHF flowback).

Contamination of soil or water from improper
disposal/release of waste solids or fluids
(including HVHF flowback) into the
environment.
(cont.)

6.1.6-9

6-536-66

6.1.6-9

GE
IS

GE
IS

se
c

pp
.

.

p.
IS
p
dS
GE

dS
GE
se IS
ct
io
n

p.

MITIGATING MEASURE

SG
EI
se S
ct
io
n
SG
EI
Sp

pp
.
GE
IS

.
se
c
GE
IS

IS
p
dS
GE

IMPACT

dS
GE
se IS
ct
io
n

RESOURCE

SG
EI
se S
ct
io
n
SG
EI
Sp

p.

p.

Table 11.1 Summary of Potential Impacts and Proposed Mitigation Measures

Requires impermeable liner in drilling reserve pits.

17.C.1.o

17-12

Limits duration on impoundment of waste fluids to 45
days after drilling operations.

17.C.1.p

17-12

Specifies methods and materials for pit liners.

17.C.2.k-l

17-15

Requires landowner permission to bury trash or pit liners
onsite.

17.B.2.e

17-7

Specifies safe disposal of waste oil and flammables.

17.C.1.d

17-8

Requires a department-approved brine disposal plan.

17.D.2.b

17-16

Requires proper handling of well construction waste fluids
and holding tanks for produced fluids.

17.C.1.q

17-12..13

Sets timetable for waste fluid disposal to 45 days after
cessation of drilling.

17.D.2.a

17-16

Flowback water may not be spread on roads. Requires
coverage under a Part 364 permit and submission of BUD
application for road-spreading of produced brine (includes
independent analysis of brine composition). BUDs for
Marcellus brine will not be issued until additional data on
NORM content is available and evaluated.

7.1.7.2

7-60

7.1.7.2

Cuttings must be disposed of in MSW landfills if well
drilled on oil-based or polymer-based mud. Cuttings may
be disposed of on location only if well drilled on air or
water.

7.1.9

7-67

7.1.9

Prohibits annular disposal of drill cuttings.

7.1.9

7-67

7.1.9

Specifies and requires record-keeping of generation,
transfer/hauling, and receipt of flowback wastewater.

7.1.7.1

7-59

7.1.6.1

Prohibits spreading of HVHF flowback water on roads.

7.1.7.2

7-60

7.1.6.2

Requires submission of a fluid disposal plan for flowback
water which specifies quality, maintenance, and
monitoring of piping and conveyances.

7.1.7.1

7-59

7.1.6.3

Final SGEIS 2015, Page 11-6

 Water resources
(cont.)

Degradation/contamination of the
NYC/unfiltered water supplies.

Floodplains

Contamination of surface waters from the
release into the environment of chemical
pollutants in a flood event.

Freshwater Wetlands Contamination of freshwater wetlands from

6.2

6-67

6.2

6.3

6-67

6.3

accidental release of drilling or HF fluids,
chemicals, or fuel.

16.B.2.d

16-7..8

7.1.8.1

7-63

7.1.8.1

Requires SPDES coverage of any private wastewater
treatment facility proposed to accept waste fluid.

7.1.8.1

7-63

7.1.8.1

Restates governance of EPA UIC permit over proposed
injection well disposal. Notes site-specific SEQRA review
for each injection well.

7.1.8.2

7-65

7.1.8.2

No well pads for high-volume hydraulic fracturing in the
New York City or Syracuse watersheds or within a 4000'
buffer of the watersheds.

7.1.10

7-68

7.1.10

No well pads or access roads for high-volume hydraulic
fracturing permitted within 100-year floodplains.

7.2

7-77

7.2

For Department-regulated wetlands, makes permit
approval dependent on site-specific SEQRA review and
coverage under any necessary wetlands permits.

7.3

7-77

7.3

Specifies setbacks between fuel tanks and wetlands at a
mandatory 500 feet.

7.3

7-77

7.3

Requires SPOTS 10 secondary containment for any fuel
tank.

7.3

7-77

7.3

Degradation of local ecosystem from
fragmentation of habitat

6.4.1

6-68

6.4.1

Requires operator to develop and employ Best
Management Practices for surface disturbance to reduce
habitat impacts.

7.4.1

7-78

7.4.1

Restricts operations during mating and migration seasons
in certain habitats

7.4.1

7-78

7.4.1

Requires pre-drilling and post-completion animal and plant
surveys when well pads are located in 150-acre or larger
forest patches within Forest Focus Areas or 30-acre or
larger grassland patches within Grassland Focus Areas.

7.4.1

7-78

7.4.1

Final SGEIS 2015, Page 11-7

pp
.

.

GE
IS

se
c
GE
IS

17.B.1.f

Requires a Wetlands Permit when project is w/in 100' of a
freshwater wetland > 12.4 ac. in size or of unique local
significance. Authorizes permit conditions on a case-bycase basis regarding location and timing of
activities/facilities and replacement of lost wetland
acreage.

Ecosystems and
Wildlife

IS
p

p.

Requires application and pre-approval of POTWs
proposing to dispose of flowback and production waters.
Specifies application contents (e.g. headworks analysis,
waste fluid characterization, regulatory limits) and
demonstration that final discharges will fall within
regulatory limits.

dS
GE

dS
GE
se IS
ct
io
n

p.

MITIGATING MEASURE

SG
EI
se S
ct
io
n
SG
EI
Sp

pp
.
GE
IS

.
se
c
GE
IS

IS
p
dS
GE

IMPACT

dS
GE
se IS
ct
io
n

RESOURCE

SG
EI
se S
ct
io
n
SG
EI
Sp

p.

p.

Table 11.1 Summary of Potential Impacts and Proposed Mitigation Measures

17-5

 Degradation of local ecosystem functions and
native biological communities from the
introduction of invasive species.

Ecosystems and
Wildlife (cont.)

Air Quality

6.4.1

6-68

6.4.3

6-89

6.4.3

Impacts to State-Owned Lands

6.4.4

6-91

6.4.4

6.5

6-94

6.5

16.B.2.b

16.B.2.f

16-9..10

7.4.2.1

7-88

7.4.2.1

Requires baseline surveying and reporting of project site
for existence of invasive species. 


7.4.2.1

7-88

7.4.2.1

Affords DEC the right to apply permit conditions for
invasive species management when outside of the DRB
and SRB.

7.4.2.2

7-91

7.4.2.2

Relies upon DRBC and SRBC protocols for aquatic invasive
species management in their respective jurisdictions.

7.4.2.2

7-91

7.4.2.2

Requires partial and final well pad reclamation.

7.4.1

7-78

7.4.1

No surface drilling allowed on specified State-owned lands.

7.4.4

7-99

7.4.4

Specifies minimum exhaust-stack heights, restrictions on
public access, and sulfur content of fuel-oil.

7.5.3.1

7-107

7.5.3.1

Prohibits use of the BTEX class of compounds as additives
in HVHF fluid surface impoundments.

7.5.3.2

7-108

7.5.3.2

Requires reporting of fracturing additives and public
access restrictions.

7.5.3.2

7-108

7.5.3.2

Requires catalytic technology for production equipment.

7.5.1.1

7-101

7.5.3.3

Greenhouse Gas
Emissions

Emission of gases with Global Warming
Potential due to natural gas well drilling and
production.

6.6

6-189

6.6

Requires development of a GHG emissions impacts
mitigation plan, requires development of a leak detection
and repair program, and encourages participation in the
USEPA's Natural Gas STAR program. Requires reduced
emission completions where a pipeline is available.

7.6.8

7-115

7.6.8

Naturally Occuring
Radioactive Material
(NORM)

Exposure of workers, the public, and the
environment to harmful levels of radiation.

6.8

6-210

6.8

Outlines necessary monitoring work.

7.7.2

7-116

7.8.2

Requires NORM testing of discharged waste fluids and
material in production tanks.

7.7.2

7-116

7.8.2

7.9

7-120

7.9

Visual Impacts

Temporary new landscape features at well
pads, new offsite facilities, congested
appearance of campsites and staging areas,
increase in specialized traffic.

6.9

6-266

6.9

16.B.2.e

16-8

Permit conditions would require operation consistent with
a visual impacts mitigation plan. Site-specifc assessment
could result in additional design and siting requirements.

Final SGEIS 2015, Page 11-8

pp
.
GE
IS

.
se
c
GE
IS

IS
p

p.

Requires operator diligence in exploiting accepted BMPs
for removal and preventing introduction of invasive
species.

dS
GE

p.
dS
GE
se IS
ct
io
n

GE
IS

16-6..7

MITIGATING MEASURE

SG
EI
se S
ct
io
n
SG
EI
Sp

pp
.

.
se
c
GE
IS

IS
p

6.4.1

Harm to local wildlife populations from the
loss of habitat

Degradation of Air Quality

dS
GE

IMPACT

dS
GE
se IS
ct
io
n

RESOURCE

SG
EI
se S
ct
io
n
SG
EI
Sp

p.

p.

Table 11.1 Summary of Potential Impacts and Proposed Mitigation Measures

 6.8 & 6.12

16-10..11

7.11

7-134

7.11

7.8 & 7.12

7-118 &
7-143

7.8 & 7.12

This section will be updated after July 31, 2011.

housing shortages; positive and negative
impacts on state and government spending;
increased tax revenues and production
royalties; increased demand for local services;
potential changes in the economic,
demographic and social characteristics of
affected communities that could be viewed as
negative by some and positive by others.

Final SGEIS 2015, Page 11-9

.

p.

p.

.

16.B.2.h

Potential for road use agreements between operators and
municipalities. Requirement to file a transportation plan
that includes prposed routes and a road condition
assessment. Site-specific assessment could result in
additional traffic safety requirements, first responder
emergency response training or avoidance of sensitive
locations for trucks carrying hazardous materials.

pp
.

6-210 &
6-319

7.10

17.B.1.b

GE
IS

6.8 & 6.12

Positive impacts on employment and income;
Socioeconomic &
Community Character increased economic activity; potential localized

7-127

se
c

6.11

7.10

GE
IS

6-303

Operator must submit and adhere to a noise impacts
mitigation plan. Site-specific assessment could result in
specific mitigating permit conditions.

IS
p

6.11

MITIGATING MEASURE

dS
GE

Increased traffic on roadways; damage to local
roads, bridges and other infrastructure;
damage to state roads, bridges and other
infrastructure; increased number of
breakdowns and other accidents; risk of
potentially hazardous spills; traffic impacts
near rail centers.

16-2

dS
GE
se IS
ct
io
n

Transportation

16.B

SG
EI
se S
ct
io
n
SG
EI
Sp

6.10

pp
.

6-292

GE
IS

6.10

se
c

Temporary impacts but could occur on 24-hour
basis. Potential 37-42 dB increase over
quietest background at 2,000 feet during
drilling and hydraulic fracturing. Increased
traffic noise near well pad. Noise along
approach and departure corridors from
increased airplan service.

GE
IS

IMPACT

Noise

IS
p

RESOURCE

dS
GE

dS
GE
se IS
ct
io
n

SG
EI
se S
ct
io
n
SG
EI
Sp

p.

p.

Table 11.1 Summary of Potential Impacts and Proposed Mitigation Measures

17-4

 This page intentionally left blank.

NEW YORK Department of

STATE OF .
Envuronmental

Conservation

 

Glossary

Final

Supplemental Generic Environmental Impact Statement



This page intentionally left blank.

Terms and Definitions

Term

Definition

Access Road:

A road constructed to the wellsite that provides access during the
drilling and operation of the well.

Accumulator:

The storage device for nitrogen pressurized hydraulic fluid, which
is used in operating the blowout preventers.

AERMOD:

American Meteorological Society's and USEPA's Regulatory
Model recommended by EPA for regulatory dispersion modeling.

AGC/SGC:

Annual Guideline Concentrations and Short-term Guideline
Concentration defined in DAR-1 (Air Guide 1) procedures.

ALJ:

Administrative Law Judge.

Anaerobic:

Living or active in the absence of free oxygen.

Annular Space or Annulus:

Space between casing and the wellbore, or between the tubing
and casing or wellbore, or between two strings of casing.

ANSS:

USGS’s Advanced National Seismic System.

Anticline:

A fold with strata sloping downward on both sides from a
common crest.

API:

American Petroleum Institute.

API Number:

A number referencing system designed by the American
Petroleum Institute to identify wells; each state and county has a
specific number code.

Aquifer:

A zone of permeable, water saturated rock material below the
surface of the earth capable of producing significant quantities of
water.

ARD (Acid Rock
Drainage):

Refers to the outflow of acidic water from (usually abandoned)
metal mines or coal mines. Acid rock drainage occurs naturally
within some environments as part of the rock weathering process,
usually within rocks containing an abundance of sulfide minerals.

AST:

Above-ground storage tank.

Final SGEIS 2015, Glossary, Page G-1

 Term

Definition

Bactericides:

Also known as a "Biocide." An additive that kills bacteria.

Barrel:

A volumetric unit of measurement equivalent to 42 U.S. gallons.

bbl:

Barrel.

bbl/yr:

Barrels per year.

Bcf:

Billion cubic feet. A unit of measurement for large volumes of
gas.

Bentonite:

A natural clay, used as a cement or mud additive for its expansive
characteristics and/or its tendency to not separate from water.

Berm:

A mound or wall of earth or sand.

Biocides:

See definition for "Bactericides".

Blending Unit or Blender:

The equipment used to prepare the slurries and gels commonly
used in stimulation treatments.

Blooie Line:

Pipe that diverts fluids from the wellbore to a reserve pit.

Blowout:

An uncontrolled flow of gas, oil or water from a well, during
drilling when high formation pressure is encountered.

BMP:

Best Management Practices.

BOD:

Biochemical (or biological) oxygen demand.

BOP:

Blowout Preventer. A device attached immediately above the
casing which can be closed and shut off the hole should a
blowout occur.

Borehole:

See wellbore.

Breaker:

A chemical used to reduce the viscosity of a fluid (break it down)
after the thickened fluid has finished the job it was designed for.

Brine Disposal Well:

A well (Class IID) for subsurface injection of associated
produced brines from oil, gas and underground gas storage
operations, or a well (Class V) for disposal of spent brine from
geothermal and solution mining operations.

Final SGEIS 2015, Glossary, Page G-2

 Term

Definition

Brine:

A solution containing appreciable amounts of NaCl and/or other
salts. Synonymous with salt water.

BTEX:

Benzene, Toluene, Ethylbenzene, and Xylene. These are all
aromatic hydrocarbons.

BUD:

Beneficial Use Determination issued by NYSDEC's Division of
Materials Management.

Buffer Zone:

An area designed to protect and separate an activity from things
around it.

C&D:

Construction and demolition.

CAA:

Clean Air Act.

Cable Tool:

Equipment (rig) for cable-tool drilling consisting of a heavy metal
bar sharpened to a chisel-like point and attached to a cable. The
gravity impact of the heavy metal bar (bit) pulverizes the rock
which is removed with a bailer.

Caliper Log:

A log that is used to check for any wellbore irregularities. It is run
prior to primary cementing as a means of calculating the amount
of cement needed. Also run in conjunction with other open-hole
logs for log corrections.

Carbonate:

A salt of carbonic acid, CO3-2.

Carcinogen:

Cancer causing substance.

CAS Number:

Chemicals Abstract Service number, assigned by Chemical
Abstracts Service, which is part of the American Chemical
Society. The CAS registry is the most authoritative collection of
disclosed chemical substance information, containing more than
48 million organic and inorganic substances and 61 million
sequences.

Casing:

Steel pipe placed in a well.

Casing Shoe:

Reinforcing collar screwed onto the bottom of surface casing that
guides the casing through the hole while absorbing the brunt of
the shock.

Final SGEIS 2015, Glossary, Page G-3

 Term

Definition

Cation:

A positively charged ion.

CBS:

Chemical Bulk Storage.

CEA:

Critical Environmental Area.

Cement Bond Log:

A log used to evaluate the effectiveness of a primary cement job
based on the different responses of sound waves in metal pipe and
cement. It can also be used to locate channels in the cement.

Cement Sheath:

A protective covering around the casing, segregates the producing
formation and prevents undesirable migration of fluid.

CFR:

Code of Federal Regulations.

cfs:

Cubic feet per second.

CH4:

Methane.

Chemical Additive:

A product composed of one or more chemical constituents that is
added to a primary carrier fluid to modify its properties in order
to form hydraulic fracturing fluid.

Chemical Constituent:

A discrete chemical with its own specific name or identity, such
as a CAS Number, which is contained within an additive product.

Choke:

A device with an orifice installed in a line to restrict the flow of
fluids.

Choke Manifold:

The arrangement of piping and special valves, called chokes,
through which drilling mud is circulated when the blowout
preventers are closed to control the pressures encountered during
a kick.

Circulation:

The round trip made by the well fluids from the surface down the
tubing, wellbore or casing, and then back to the surface.

Class GSB Water:

The best usage of Class GSB waters is as a receiving water for
disposal of wastes. Class GSB waters are saline groundwaters
that have a chloride concentration in excess of 1,000 milligrams
per liter or a total dissolved solids concentration in excess of
2,000 milligrams per liter.

Final SGEIS 2015, Glossary, Page G-4

 Term

Definition

Clastic:

Rock consisting of fragments of rocks that have been transported
from other places.

Clay Stabilizer/Clay
Inhibitor:

A chemical additive used in stimulation treatments to prevent the
migration and/or swelling of clay particles.

Closed Loop Drilling
System:

A pitless drilling system where all drilling fluids and cuttings are
contained at the surface within piping, separation equipment and
tanks.

CO:

Carbon monoxide.

CO2:

Carbon Dioxide.

CO2e:

Carbon Dioxide equivalents.

COGCC:

Colorado Oil and Gas Conservation Commission.

Completion:

Preparation of a well for production after it has been drilled to the
objective formation and in the case of a dry hole, preparation of a
well for plugging and abandonment.

Compressive Strength:

Measure of the ability of a substance to withstand compression.

Compressor Stations:

Facilities which increase the pressure on natural gas to move it in
pipelines or into storage.

Compulsory Integration:

New York’s Environmental Conservation Law (Article 23, Titles
5 and 9 as amended by Chapter 386 of the Laws of 2005) gives
all property owners the opportunity to recover or receive the gas
beneath their property. To protect these “correlative rights,” the
Department of Environmental Conservation may establish
spacing units whenever necessary. Compulsory integration is
required when any owner in a spacing unit does not voluntarily
integrate their interests with those of the unit operator.
Compensation to the compulsory integrated interests will be
established by a DEC Commissioner’s Order after a public
hearing.

Condensate:

Liquid hydrocarbons that were originally in the reservoir gas and
are recovered by surface separation.

Conductor Hole:

The hole for conductor pipe or casing.

Final SGEIS 2015, Glossary, Page G-5

 Term

Definition

Conductor Pipe or Casing:

Large diameter casing that is usually the first string of casing in a
well. Set or driven into the unconsolidated material where the
well will be drilled to keep loose material from caving in. Usually
relatively short in length.

Correlative Rights:

Rights of any mineral owner to recover resources that underlay
their property.

Corrosion Inhibitor:

A chemical substance that minimizes or prevents corrosion in
metal equipment.

CRDPF:

Continuously Regenerating Diesel Particulate Filter.

Crosslinkers:

A compound, typically a metallic salt, mixed with a base-gel
fluid, such as a guar-gel system, to create a viscous gel used in
some stimulation or pipeline cleaning treatments. The crosslinker
reacts with the multiple-strand polymer to couple the molecules,
creating a fluid of high viscosity.

CT:

coiled tubing.

Cubic Foot:

Unit of measurement of the volume of gas contained in one cubic
foot of space at a standard pressure (14.73 psi) and standard
temperature (60° F).

Cuttings or Samples:

Chips of rock cut by the drill bit and brought to the surface by the
drilling fluid. They indicate to the wellsite workers what kind of
rocks are being penetrated and can also indicate the presence of
oil or gas.

CWA:

Clean Water Act.

CWF:

Cold-Water Fishery (waters).

CWS:

Community water systems.

CZM:

Coastal Zone Management.

DAR:

Division of Air Resources in the NYS Department of
Environmental Conservation.

DAR-1 (Air Guide-1):

Division of Air Resources program policy guidelines for the
control of toxic air contaminants.

Final SGEIS 2015, Glossary, Page G-6

 Term

Definition

Dehydrator:

A device used to remove water and water vapors from gas.

Department:

New York State Department of Environmental Conservation.

De-sander:

A centrifugal device for removing sand from drilling fluid to
prevent abrasion of the pumps. It may be operated mechanically
or by a fast-moving stream of fluid inside a special cone-shaped
vessel, in which case it is sometimes called a hydrocyclone.

De-silter:

A centrifugal device used to remove very fine particles, or silt,
from drilling fluid.

Devonian Period:

Period of geologic time from 415 to 360 million years ago.

Diesel-Based Hydraulic
Fracturing:

Hydraulic fracturing using diesel as the primary carrier.

Dip:

Angle of inclination from the horizontal.

Dipole Sonic Log:

A type of acoustic log that displays travel time of P-waves versus
depth.

Disconformity:

A surface of erosion between parallel rock strata or a contact
between two discordant structures (e.g., a dike emplaced within a
layered sedimentary rock unit).

Disposal Well:

A well into which waste fluids can be injected deep underground
for safe disposal.

DMM:

Division of Materials Management in the NYS Department of
Environmental Conservation.

DMN:

Division of Mineral Resources in the NYS Department of
Environmental Conservation.

DMR:

Division of Marine Resources in the NYS Department of
Environmental Conservation.

Doghouse:

A small enclosure on the rig floor used as an office and/or as a
storehouse for small objects. Also, any small building used as an
office or for storage.

DOH:

(New York State) Department of Health.

Final SGEIS 2015, Glossary, Page G-7

 Term

Definition

DOW:

Division of Water in the NYS Department of Environmental
Conservation.

DMV:

(New York State) Department of Motor Vehicles.

DPS:

(New York State) Department of Public Service.

DRA:

Division of Regulatory Affairs in the NYS Department of
Environmental Conservation.

DRBC:

Delaware River Basin Commission.

Drilling Fluid:

Mud, water, or air pumped down the drill string which acts as a
lubricant for the bit and is used to carry rock cuttings back up the
wellbore. It is also used for pressure control in the wellbore.

Drive Pipe:

See definition for "Conductor Casing".

Dry Hole:

Any well that does not produce oil or gas in commercial
quantities.

DSHM:

Division of Solid and Hazardous Materials in the NYS
Department of Environmental Conservation.

E&P:

Exploration and Production.

EAF:

Environmental Assessment Form.

ECL:

Environmental Conservation Law.

Ecosystem:

The system composed of interacting organisms and their
environments.

EDR:

Electrodialysis Reversal.

Effluent:

Something that flows out, in particular a waste material such as
an industrial discharge.

EIS:

Environmental Impact Statement.

EM&CP:

Environmental Management and Construction Plan.

Final SGEIS 2015, Glossary, Page G-8

 Term

Definition

EM&CS&P:

Environmental Management and Construction Standards and
Practices.

Entrainment:

The condition of being drawn into something and transported
with it, for example, gas bubbles in cement.

EO 41:

Executive Order 41.

EPA:

(U.S.) Environmental Protection Agency.

EPCRA:

Emergency Planning and Community Right to Know Act of
1986.

ERP:

Emergency Response Plan.

EUR:

Estimated ultimate recovery.

EV:

Exceptional Value (waters).

Evaporite:

Sedimentary rock or mineral deposits formed from the extensive
or total evaporation of seawater.

FAA:

(U.S.) Federal Aviation Administration.

FAD:

Filtration Avoidance Determination.

Fault:

A fracture or fracture zone along which there has been
displacement of the sides relative to each other.

Field:

The general area underlain by one or more pools.

Flare:

The burning of unwanted gas through a pipe.

Flocculant:

A chemical added to a fluid to cause unwanted particles, such as
clay, to clump together for easier removal.

Floodplain:

Level land built up by stream deposition (past floods) that may be
subject to future flooding.

Flowback Fluids:

Liquids produced following drilling and initial completion and
clean-up of the well.

Flowmeter:

An instrument that measures fluid flow rates.

Final SGEIS 2015, Glossary, Page G-9

 Term

Definition

Flue Gas:

An exhaust gas coming out of a pipe or stack.

FMCSA:

Federal Motor Carrier Safety Administration.

Foaming Agents:

An additive used to make foam in a drilling fluid.

Fold:

A bend in rock strata.

Footwall:

The mass of rock beneath a fault plane.

Formation:

A rock body distinguishable from other rock bodies and useful
for mapping or description. Formations may be combined into
groups or subdivided into members.

Fossil:

A record of ancient life.

Fracing (pronounced
“fracking”):

See definition for "Hydraulic Fracturing".

Freeboard:

The height above the recorded high-water mark of a structure
associated with the water. In the case of pits, the extra depth left
unused to prevent any chance of overflow.

Friction Reducers/Friction
Reducing Agent:

Chemical additives which alter the hydraulic fracturing fluid
allowing it to be pumped into the target formation at a higher rate
& reduced pressure.

FTIR:

Fourier-transform Infrared.

Gamma Ray Log:

Log that records natural gamma radiation of the formations.
Shales can be identified because of their high natural gamma
radiation content.

Gas Gathering:

The collection and movement of raw gas from the wellhead to an
acceptance point of a transportation pipeline.

Gas Meter:

An instrument for measuring and indicating, or recording, the
volume of natural gas that has passed through it.

Gas-Water Separator:

A device used to separate undesirable water from gas produced
from a well.

GEIS:

Generic Environmental Impact Statement.

Final SGEIS 2015, Glossary, Page G-10

 Term

Definition

Gelling Agents:

Polymers used to thicken fluid so that it can carry a significant
amount of proppants into the formation.

Geomembrane:

Man-made polymeric membrane (flexible membrane) that is
manufactured to be essentially impermeable and is used to build
containment pits.

Geothermal Well:

A well drilled to explore for or produce heat from the subsurface.

GHG:

Greenhouse gas.

gpd:

Gallons per day.

gpm:

Gallons per minute.

GRI:

Gas Research Institute.

Groundwater:

Water in the subsurface below the water table. Groundwater is
held in the pores of rocks, and can be connate, from meteoric
sources, or associated with igneous intrusions.

Groundwater Hydrology:

The science of the occurrence, distribution, and movement of
water below the surface of the earth.

Grout:

A concrete mixture placed into a well annulus from the surface;
also, the process of emplacing such mixture.

GWP:

Global warming potential.

GWPC:

Ground Water Protection Council.

H2SO4:

Sulfuric acid.

HAPS:

Hazardous Air Pollutants as defined under the Clean Air Act.

Hardpan:

A hard impervious layer of soil composed chiefly of clay
cemented by relatively insoluble materials.

HDPE:

High-density polyethylene. This plastic is resistant to most
chemicals, insoluble in organic solvents, and has high impact and
tensile strength.

Final SGEIS 2015, Glossary, Page G-11

 Term

Definition

High-Volume Hydraulic
Fracturing:

The stimulation of a well using 300,000 gallons or more of water
as the base fluid in fracturing fluid.

HMTA:

Hazardous Material Transportation Act.

HMTUSA:

Hazardous Materials Transportation Uniform Safety Act.

Horizontal Drilling:

Deviation of the borehole from vertical so that the borehole
penetrates a productive formation in a manner parallel to the
formation.

Horizontal Leg:

The part of the wellbore that deviates significantly from the
vertical; it may or may not be perfectly parallel with formational
layering.

HQ:

High Quality (waters).

Hydraulic Conductivity:

A property of a soil or rock, that describes the ease with which
water can move through pore spaces or fractures. It is dependent
upon the intrinsic permeability of the material and on the degree
of saturation.

Hydraulic Fracturing:

The act of pumping hydraulic fracturing fluid into a formation to
increase its permeability.

Hydraulic Fracturing Fluid: Fluid used to perform hydraulic fracturing; includes the primary
carrier fluid and all applicable additives.
Hydrocarbons:

Organic compounds of hydrogen and carbon whose densities,
boiling points, and freezing points increase as their molecular
weights increase. Although composed of only two elements,
hydrocarbons exist in a variety of compounds, because of the
strong affinity of the carbon atom for other atoms and for itself.
The smallest molecules of hydrocarbons are gaseous; the largest
are solids. Petroleum is a mixture of many different
hydrocarbons.

Hydrocyclone:

A device to classify, separate or sort particles in a liquid
suspension based on the densities of the particles. A
hydrocyclone may be used to separate solids from liquids or to
separate liquids from different density.

Final SGEIS 2015, Glossary, Page G-12

 Term

Definition

Hydrogen Sulfide or H2S:

A malodorous, toxic gas with the characteristic odor of rotten
eggs.

ICE:

Internal Combustion Engines.

ICF:

ICF International, a consulting firm.

Igneous Rock:

Rock formed by solidification from a molten or partially molten
state (magma).

Infill Wells:

Wells drilled between known producing wells to better exploit the
reservoir.

Infrastructure:

The system of public works of a country, state, or region. It can
also refer to the resources (as personnel, buildings, or equipment)
required for an activity.

Injectate:

Injectate is any substance injected down a well.

Injection Well:

A well through which fluids are injected into an underground
stratum to increase reservoir pressure and to displace oil. Also
called an input well.

Injection Zone:

A geological formation, group of formations, or part of a
formation that receives fluids through a well.

Intermediate Casing or
String:

Casing set below the surface casing in deep holes where added
support or control of the wellbore is needed. It goes between the
surface casing and the conductor casing. In very deep wells, more
than one string of intermediate casing may be used.

IOGA-NY:

Independent Oil and Gas Association of New York.

IOGCC:

Interstate Oil and Gas Compact Commission.

Iron Inhibitors:

Chemicals used to bind the metal ions and prevent a number of
different types of problems that the metal can cause (for example,
scaling problems in pipe).

ITR:

Injection Timing Retard.

Final SGEIS 2015, Glossary, Page G-13

 Term

Definition

Joule-Thompson Effect:

Referring to the change in temperature observed when a gas
expands while flowing through a restriction without any heat
entering or leaving the system. The change may be positive or
negative. The Joule-Thomson effect often causes a temperature
decrease as gas flows through pores of a reservoir to the wellbore.

km:

Kilometer.

KML:

Keyhole Markup Language.

LCSN:

Lamont-Doherty Cooperative Seismographic Network.

LDAR:

Leak detection and repair.

LDCs:

Local Distribution Companies.

Limestone:

A sedimentary rock consisting chiefly of calcium carbonate
(CaCO3).

Lithologic:

Referring to the physical characteristics of rocks or sediment that
can be determined with the human eye.

Log:

A systematic recording of data, such as a driller’s log, mud log,
electrical well log, or radioactivity log. Many different logs are
run in wells to discern various characteristics of rock formations
that the wellbore passes through.

Lost Circulation:

The quantities of drilling fluid lost to a formation, usually in
cavernous, pressured, or coarsely permeable beds, evidenced by
complete or partial failure of the mud to return to the surface as it
is being circulated in the hole.

Lost Circulation Material:

Material put into fluids to block off the permeability of a lost
circulation zone.

Lost Circulation Zone:

Formation that is so permeable or soluble that it diverts the flow
of fluids from the well.

Low-Permeability Gas
Reservoirs:

Gas bearing rocks (which may or may not contain natural
fractures) which exhibit in-situ gas permeability of less than 0.10
milidarcies.

LPG:

Liquefied Petroleum Gas.

Final SGEIS 2015, Glossary, Page G-14

 Term

Definition

LWRP:

Local Waterfront Revitalization Program.

Manifold:

An arrangement of piping or valves designed to control, distribute
and often monitor fluid flow.

Marcellus Well:

A well for which the operator designates the Marcellus Shale as
the objective formation.

Mcf:

Thousand cubic feet.

MCL, MCLG:

Maximum Contaminant Level, Maximum Contaminant Level
Goal.

md:

Millidarcy.

Methane:

Methane (CH4) is a greenhouse gas that remains in the
atmosphere for approximately 9-15 years. Methane is also a
primary constituent of natural gas and an important energy
source.

Microseisms (or
microseismic events):

Small bursts of seismic energy generated by shear slippages along
planes of weakness in the reservoir and surrounding layers which
are induced by changes in stress and pore pressure around the
hydraulic fracture. These microseisms are extremely small, and
sensitive receiver systems are required.

Micro-annulus (plural is
micro-annuli):

A small gap that can form between the casing or liner and the
surrounding cement sheath, most commonly formed by variations
in temperature or pressure during or after the cementing process.

mg/L:

milligrams per liter.

Mineral Rights:

The ownership of the minerals under a given surface, with the
right to enter and remove them. It may be separated from the
surface ownership.

MMcf:

Million cubic feet.

MMcf/d:

Million cubic feet per day.

Final SGEIS 2015, Glossary, Page G-15

 Term

Definition

MOVES:

Motor Vehicle Emission Simulator.

mR/hr:

Milliroentgens per hour.

MSC:

Marcellus Shale Coalition.

MSDS:

Material Safety Data Sheet. A written or printed document which
is prepared in accordance with 29 CFR 1910.1200(g).

MSGP:

Multi-Sector General Permit.

MSW:

Municipal solid waste.

Mudlogging (Unit):

Trailer located at the wellsite housing equipment and personnel to
progressively analyze wellbore cuttings washed up from the
borehole. A portion of the mud is diverted through a gasdetecting device.

NAAQS and AAQS:

National or State Ambient Air Quality Standards for criteria
pollutants.

Native Gas:

Gas originally in place in an underground formation. Term is
usually associated with gas storage.

NCWS:

Non-community water systems.

NESHAPs:

National Emission Standards for Hazardous Air Pollutants.

NFRM:

Natural Flow Regime Method.

NGPA:

Natural Gas Policy Act of 1978.

NH3:

Ammonia.

NMHC:

Non-methane hydrocarbons.

NNSR:

Nonattainment New Source Review.

NOI:

Notice of Intent.

Noise Log:

A record of the sound vibrations in the wellbore caused by
flowing liquid or gas. Used to determine fluid entry points or
flow behind casing.

Final SGEIS 2015, Glossary, Page G-16

 Term

Definition

Non-Darcy Flow:

Fluid flow that deviates from Darcy's law, which assumes laminar
flow in the formation. Non-Darcy flow is typically observed in
high-rate gas wells when the flow converging to the wellbore
reaches flow velocities exceeding the Reynolds number for
laminar or Darcy flow, and results in turbulent flow.

Nonwetting Phase:

The pore space fluid which is not attached to the reservoir rock
and thus has the greatest mobility.

N2O:

Nitrous Oxide.

NO2:

Nitrogen Dioxide.

NORM - Naturally
Occurring Radioactive
Materials:

Low-level radioactivity that can exist naturally in native
materials, like some shales and may be present in drill cuttings
and other wastes from a well.

Non-Indigenous:

Not having originated in and being produced, growing, living, or
occurring naturally in a particular region or environment.
Another type of Decline or Type Curve Analysis (see).

Normalized Pressure
Integral Curve Analysis:
NPDES:

National Pollutant Discharge Elimination System.

NSCR:

Non-Selective Catalytic Reduction.

NSPS:

New Source Performance Standards.

NTNC:

Non- transient non-community.

NWS:

National Weather Service.

NYCDEP:

New York City Department of Environmental Protection.

NYCRR:

New York Codes of Rules and Regulations.

NYSDAM:

New York State Department of Agriculture and Markets.

NYSDOH:

New York State Department of Health.

NYSDOT:

New York State Department of Transportation.

Final SGEIS 2015, Glossary, Page G-17

 Term

Definition

NYSERDA:

New York State Energy Research and Development Authority.

O3:

Ozone.

Operator:

Any person or organization in charge of the development of a
lease or drilling and operation of a producing well.

OPRHP:

(NY State) Office of Parks, Recreation and Historic Preservation.

Ordovician Period:

Period of geologic time from 520 to 465 million years ago.

PADEP:

Pennsylvania Department of Environmental Protection.

Paleozoic Era:

Large block of geologic time from 570 to 225 million years ago;
beginning marked by the appearance of abundant fossils. Most of
the bedrock in New York State was formed (deposited) during the
Paleozoic.

Parameter:

A characteristic of a model of a reservoir that may or may not
vary with respect to position or with time. (e.g., porosity is a
petrophysical parameter (or characteristic) that varies with
position).

Partial Reclamation:

The reclamation of a well site following completion of a well and
in the case of multi-well pad, completion of the last well on the
multi-well pad. This includes the reclamation of pits, regarding of
lands and the revegetation of lands outside the well pad.

Passby Flow Requirement:

A prescribed quantity of flow that must be allowed to pass an
intake when withdrawal is occurring. Passby requirements also
specify low- flow conditions during which no water can be
withdrawn.

Pathogens:

A specific causative agent (as a virus or bacterium).

PBS:

Petroleum Bulk Storage.

PCC:

Pre-ignition Chamber Combustion.

Pennsylvanian Period:

Period of geologic time from 310 to 280 million years ago.

Percolation Test:

Test to determine at what rate fluids will pass through soil.

Final SGEIS 2015, Glossary, Page G-18

 Term

Definition

Perennial Stream:

A stream channel that has continuous flow in parts of its bed all
year round during years of normal rainfall.

Perforate:

To make holes through the casing to allow the oil or gas to flow
into the well or to squeeze cement behind the casing.

Perforation:

A hole created in the casing to achieve efficient communication
between the reservoir and the wellbore.

Permeability:

A measure of a material’s ability to allow passage of gas or liquid
through pores, fractures, or other openings. The unit of
measurement is the millidarcy.

Permeable:

Able to transmit gas or liquid through interconnected pores,
fractures, or other openings.

Petroleum:

In the broadest sense the term embraces the full spectrum of
hydrocarbons (gaseous, liquid, and solid).

PHMSA:

Pipeline and Hazardous Materials Safety Administration.

PID:

Perforation Inflow Diagnostic.

Pipe Racks:

Horizontal supports for storing tubular goods.

Plat:

A map of land parcels; a drafted map of a site’s location showing
boundaries of adjoining parcels.

Plug Back:

To place cement in or near the bottom of a well to exclude bottom
water, to sidetrack, or to produce from a formation higher in the
well. Plugging back can also be accomplished with a mechanical
plug set by wireline, tubing, or drill pipe.

Plugged and Abandoned:

(plug and abandon) To prepare a well to be closed permanently
with cement plugs, usually after either logs determine there is
insufficient hydrocarbon potential to complete the well, or after
production operations have drained the reservoir.

PM10 and PM2.5:

Particulate matter with sizes of less than 10 and 2.5 microns,
respectively.

Pneumatic:

Run by or using compressed air.

Final SGEIS 2015, Glossary, Page G-19

 Term

Definition

POC:

Principal Organic Contaminant.

Poisson’s ratio:

An elastic constant that is a measure of the compressibility of
material perpendicular to applied stress, or the ratio of latitudinal
to longitudinal strain. Named for French mathematician Simeon
Poisson (1781 to 1840).

Polymer:

Chemical compound of unusually high molecular weight
composed of numerous repeated, linked molecular units.

Pool:

An underground reservoir containing a common accumulation of
oil and/or gas. Each zone of a structure which is completely
separated from any other zone in the same structure is a pool.

Porosity:

Volume of pore space expressed as a percent of the total bulk
volume of the rock.

Potable Fresh Water:

Suitable for drinking by humans and containing less than 250
ppm of sodium chloride or 1,000 ppm TDS.

POTW:

Publicly Owned Treatment Works.

ppb:

Parts per billion.

ppm:

Parts per million.

Precambrian Era:

Very large block of geologic time spanning from Earth’s
formation to the 4,500 to 570 million years ago.

Pressure Buildup Test:

An analysis of data obtained from measurements of the
bottomhole pressure in a well that is shut-in after a flow period.
The profile created on a plot of pressure against time is used with
mathematical reservoir models to assess the extent and
characteristics of the reservoir and the near-wellbore area.

Primary Aquifer:

A highly productive aquifer presently being utilized as a source
of water supply by a major municipal supply system.

Primary Carrier Fluid:

The base fluid, such as water, into which additives are mixed to
form the hydraulic fracturing fluid which transports proppant.

Primary Production:

Production of a reservoir by natural energy in the reservoir.

Final SGEIS 2015, Glossary, Page G-20

 Term

Definition

Principal Aquifer:

An aquifer known to be highly productive or whose geology
suggests abundant potential water supply, but which is not
intensively used as a source of water supply by a major municipal
system.

Principal Stresses:

Forces per unit area acting on the external surface of a solid body.

Product:

A hydraulic fracturing fluid additive that is manufactured using
precise amounts of specific chemical constituents and is assigned
a commercial name under which the substance is sold or utilized.

Production Casing:

Casing set above or through the producing zone through which
the well produces.

Production Brine:

Liquids co-produced during oil and gas wells production.

Proppant or Propping
Agent:

A granular substance (sand grains, aluminum pellets, or other
material) that is carried in suspension by the fracturing fluid and
that serves to keep the cracks open when fracturing fluid is
withdrawn after a fracture treatment.

PSC:

Public Service Commission.

PSD:

Prevention of Significant Deterioration defined in the Clean Air
Act.

PSI:

Pounds per square inch.

PSIG:

Pounds per Square Inch Gauge.

PSL:

Public Service Law.

Public Water Supply:

Either a community or non-community well system which
provides piped water to the public for human consumption if the
system has a minimum of five (5) service connections, or
regularly serves a minimum average of 25 individuals per day at
least 60 days per year.

PTE:

Potential to Emit.

Pump and Plug Method:

A technique for placing cement plugs at appropriate intervals.

PVC:

Polyvinylchloride; a durable petroleum derived plastic.

Final SGEIS 2015, Glossary, Page G-21

 Term

Definition

RACT:

Reasonably Available Control Technology.

Radial Cement Bond Log:

A record of sonic amplitudes derived from acoustic signals
passing along the well casing. Used to evaluate cement-to-pipe
and cement-to-formation bonding.

RCRA:

Resource Conservation and Recovery Act.

Real Property:

Includes mineral claims, surface and water rights.

REC:

Reduced Emissions Completion.

Reclaimed:

(Reclamation) Rehabilitation of a disturbed area to make it
acceptable for designated uses. This normally involves regrading,
replacement of topsoil, re-vegetation, and other work necessary to
restore it.

Remediation:

The removal of pollution or contaminants from the environmental
media such as soil, groundwater, or surface water.

Reserve pit:

A mud pit in which a supply of drilling fluid has been stored.
Also, a waste pit, usually an excavated, earthen-walled pit. In NY
it is required to be lined with plastic to prevent soil
contamination.

Reservoir (oil or gas):

A subsurface, porous, permeable or naturally fractured rock body
in which oil or gas has accumulated. A gas and production is only
gas plus fresh water that condenses from the flow stream
reservoir. In a gas condensate reservoir, the hydrocarbons may
exist as a gas, but, when brought to the surface, some of the
heavier hydrocarbons condense and become a liquid.

Reservoir (water):

Any man-made structure used to supply fresh water to the public.

Reservoir Rock:

A rock that may contain oil or gas in appreciable quantity and
through which petroleum may migrate.

RO:

Reverse Osmosis.

Rotary Rig:

A derrick equipped with rotary equipment where a well is drilled
using rotational movement.

Royalty:

The landowner’s share of the value of oil and gas produced.

Final SGEIS 2015, Glossary, Page G-22

 Term

Definition

Run-Off:

The portion of precipitation on land that ultimately reaches
streams sometimes with dissolved or suspended material.

Sandstone:

A variously colored sedimentary rock composed chiefly of
sandlike quartz grains cemented by lime, silica or other materials.

SAPA:

State Administrative Procedures Act.

Scale Inhibitor:

A chemical substance which prevents the accumulation of a
mineral deposit (for example, calcium carbonate) that precipitates
out of water and adheres to the inside of pipes, heaters, and other
equipment.

SCR:

Selective Catalytic Reduction.

SDWA:

Safe Drinking Water Act.

SDWIS:

Safe Drinking Water Information System.

Sedimentary:

Rocks formed from sediment transported from their source and
deposited in water or by precipitation from solution or from
secretions of organisms.

Sedimentation Control:

(sedimentation) The process of separation of the components of a
cement slurry during which the solids settle. Sedimentation is
one of the characterizations used to define slurry stability.

Seep:

Natural leakage of gas or oil at the earth’s surface.

SEIS:

Supplemental Environmental Impact Statement.

Seismic:

Related to earth vibrations produced naturally or artificially.

Separator:

Tank used to physically separate the oil, gas, and water produced
simultaneously from a well.

SEQR:

Reference to the regulatory program or type of review done under
SEQRA.

SEQRA:

State Environmental Quality Review Act.

Final SGEIS 2015, Glossary, Page G-23

 Term

Definition

Setback:

Minimum distance required between a well operation and other
zones, boundaries, or objects such as highways, wetlands,
streams, or houses.

SGC/AGC:

Short-term Guideline Concentration and Annual Guideline
Concentrations defined in DAR-1 (Air Guide 1) procedures.

SGEIS:

Supplemental Generic Environmental Impact Statement.

Shale:

A thinly laminated claystone, siltstone or mud stone.

Shale Shaker:

A series of trays with sieves or screens that vibrate to remove
cuttings from circulating fluid in rotary drilling operations. The
size of the openings in the sieve is selected to match the size of
the solids in the drilling fluid and the anticipated size of cuttings.
Also called a shaker.

Shear Wave (S-wave):

Elastic body wave in which particles oscillate perpendicular to
the direction in which the wave propagates. S-waves, or shear
waves, travel more slowly than P-waves and cannot travel
through fluids. Interpretation of S-waves can help determine rock
properties.

Short Ton:

20 short hundred weight, 2,000 pounds.

Show:

Small quantity of oil or gas, not enough for commercial
production.

Shut In (Verb):

To close the valves at the wellhead to keep the well from flowing
or to stop producing a well.

Shut-In (Adjective):

The state of a well which has been shut-in.

SI:

Spark Ignition.

Significant Habitats:

Areas which provide one or more of the key factors required for
survival, variety or abundance of wildlife, and/or for human
recreation associated with such wildlife.

SILs:

Significant Impact Levels for criteria pollutants.

Siltation:

The build-up of silt in a stream or lake as a result of activity that
disturbs the streambed, bank, or surrounding land.

Final SGEIS 2015, Glossary, Page G-24

 Term

Definition

Siltstone:

Rock in which the constituent particles are predominantly silt
size.

Silurian Period:

Period of geologic time from 405 to 415 million years ago.

SIP

State Implementation Plan

Slickwater Fracturing (or
slick-water):

A type of hydraulic fracturing which utilizes water-based
fracturing fluid mixed with a friction reducing agent & other
chemical additives. The fluid is typically 98% fresh water & sand
(proppant) & 2% or less chemical additives.

Slippage:

The phenomenon in multiphase flow when one phase flows faster
than another phase, in other words slips past it. Because of this
phenomenon, there is a difference between the holdups and cuts
of the phases.

SO2:

Sulfur dioxide.

SO3

Sulfur trioxide.

Sonic Log:

See “Dipole Sonic Log”.

Spacing Unit:

A surface area allotted to a well by regulations or field rules
issued by a governmental authority having jurisdiction for the
drilling and production of a well.

Spacing:

Distance separating wells in a field to optimize recovery of oil
and gas.

SPDES:

State Pollutant Discharge Elimination System.

Spring:

A place where groundwater naturally flows from underground
onto land or into a body of surface water.

Spudding:

The breaking of the earth’s surface in the initial stage of drilling a
well.

Squeeze:

Technique where cement is forced under pressure into the annular
space between casing and the wellbore, between two strings of
pipe, or into the casing-hole annulus.

SRBC:

Susquehanna River Basin Commission.

Final SGEIS 2015, Glossary, Page G-25

 Term

Definition

Stage:

Isolation of a specific interval of the wellbore and the associated
interval of the formation for the purpose of maintaining sufficient
fracturing pressure.

Stage Plug:

A device used to mechanically isolate a specific interval of the
wellbore and the formation for the purpose of maintaining
sufficient fracturing pressure.

Standpipe:

A vertical pipe rising along the side of the derrick or mast. It joins
the discharge line leading from the mud pump to the rotary hose
and through which mud is pumped going into the hole.

Stimulation:

The act of increasing a well’s productivity by artificial means
such as hydraulic fracturing, acidizing, and shooting.

Stratigraphic Test Well:

A hole drilled to gather engineering, geologic or hydrological
information including but not limited to lithology, structural,
porosity, permeability and geophysical data.

Stratigraphy:

The study of rock layering, including the history, composition,
relative ages and distribution of different rock units.

Stratum (plural strata):

Sedimentary rock layer, typically referred to as a formation,
member, or bed.

Stream’s Designated Best
Use:

Each waterbody in NYS has been assigned a classification, which
reflects the designated “best uses” of the waterbody. These best
uses typically include the ability to support fish and aquatic
wildlife, recreational uses (fishing, boating) and, for some waters,
public bathing, drinking water use or shellfishing. Water quality
is considered to be good if the waters support their best uses.

Substructure:

The foundation on which the derrick and drawworks sit. It
contains space for storage and well-control equipment.

Surface Casing:

Casing extending from the surface through the potable fresh
water zone.

Surface Impoundment:

A liquid containment facility that can be installed in a natural
topographical depression, excavation, or bermed area formed
primarily of earthen materials, then lined with a geomembrane or
a combination of other geosynthetic materials.

Final SGEIS 2015, Glossary, Page G-26

 Term

Definition

Surfactants:

Chemical additives that reduce surface tension; or a surface active
substance. Detergent is a surfactant.

SWPPP:

Stormwater Pollution Prevention Plan.

SWTR:

Surface Water Treatment Rule.

Target Formation:

The reservoir that the driller is trying to reach when drilling the
well.

TCEQ:

Texas Commission on Environmental Quality.

Tcf:

Trillion cubic feet.

TD:

Total depth.

TDS:

Total Dissolved Solids. The dry weight of dissolved material,
organic and inorganic, contained in water and usually expressed
in mg/L or ppm.

TEG:

Triethylene Glycol.

Tensile Strength:

The force per unit cross-sectional area required to pull a
substance apart.

Tight Formation:

Formation with very low permeability.

TMD:

Total measured depth.

TNC:

Transient non-community (in the context of water systems) or
The Nature Conservancy.

TOC:
Total Organic Carbon.
Total Kjeldahl Nitrogen:
The sum of organic nitrogen; ammonium NH3 and ammonia
NH4+ in water and soil analyses.
Tote:

A container used in the storage of various solid powder or liquid
bulk products.

Trap:

Any geological barrier which restricts the migration of oil & gas.

TVD:

True vertical depth.

Final SGEIS 2015, Glossary, Page G-27

 Term

Definition

Turbidity:

Amount of suspended solids in a liquid.

UA:

Urbanized areas.

UC:

Urban clusters.

UIC – Underground
Injection Control:

A program administered by the Environmental Protection
Agency, primacy state, or Indian tribe under the Safe Drinking
Water Act to ensure that subsurface emplacement of fluids does
not endanger underground sources of drinking water.

ULSF:

Ultra-Low Sulfur (Diesel) Fuel.

UN:

United Nations.

Unfiltered Surface Water
Supplies:

Those that the U.S. EPA and NYSDOH have determined meet
the requirements of the “Interim Enhanced Surface Water
Treatment Rule” (IESWT Rule) for unfiltered water supply
systems. The IESWT Rule is a December 16, 1998 amendment to
the Surface Water Treatment Rule that was originally
promulgated by EPA on June 29, 1989. In New York State, this
includes the NYC Drinking Water Supply Watershed and the
Skaneateles Drinking Water Supply Watershed.

UOC:

Unspecified Organic Contaminant.

USCG:

United States Coast Guard.

USDOT:

United States Department of Transportation.

USDW - Underground
Source of Drinking Water:

An aquifer or portion of an aquifer that supplies any public water
system or that contains a sufficient quantity of ground water to
supply a public water system, and currently supplies drinking
water for human consumption, or that contains fewer than 10,000
mg/L total dissolved solids and is not an exempted aquifer.

Water Well:

Any residential well used to supply potable water.

USEPA:

United States Environmental Protection Agency.

Final SGEIS 2015, Glossary, Page G-28

 Term

Definition

USGS:

United States Geological Survey.

Viscosity:

A measure of the degree to which a fluid resists flow under an
applied force.

Vitrinite Reflectance:

A measurement of the maturity of organic matter with respect to
whether it has generated hydrocarbons or could be an effective
source rock.

VMT:

Vehicle Miles per Trip.

VOC:

Volatile Organic Compound.

Watershed:

The region drained by, or contributing water to, a stream, lake, or
other body of water.

Well Location Plat:

A map of parcels of land with the proposed well and other
features, particularly adjoining parcel boundaries.

Well Pad:

The area directly disturbed during drilling and operation of a gas
well.

Wellbore:

A borehole; the hole drilled by the bit. A wellbore may have
casing in it or it may be open (uncased); or part of it may be
cased, and part of it may be open.

Wellhead:

The equipment installed at the surface of the wellbore. A
wellhead includes such equipment as the casinghead and tubing
head.

Well site:

Includes the well pad and access roads, equipment storage and
staging areas, vehicle turnarounds, and any other areas directly or
indirectly impacted by activities involving a well.

Wetland:

Any area regulated pursuant to Part 663.

Wildcat:

Well drilled to discover a previously unknown oil or gas pool or a
well drilled one mile or more from a producing well.

Final SGEIS 2015, Glossary, Page G-29

 Term

Definition

Wireline:

A general term used to describe well-intervention operations
conducted using single-strand or multistrand wire or cable for
intervention in oil or gas wells. Although applied inconsistently,
the term commonly is used in association with electric logging
and cables incorporating electrical conductors.

WMA:

Wildlife Management Area.

WOC Time:

"Waiting on cement" time. Pertaining to the time when drilling or
completion operations are suspended so that the cement in a well
can harden sufficiently.

Workover:

Repair operations on a producing well to restore or increase
production.

ZLD:

Zero liquid discharge.

Zonal Isolation:

The state of keeping fluids in one zone separate from the fluids in
another zone. In the case of a well, isolation is maintained by
appropriate use of casing, cement, plugs and packers.

Zone:

A rock stratum of different character or fluid content from other
strata.

Final SGEIS 2015, Glossary, Page G-30

 NEW YORK Department of

STATE OF .
OPPORTUNITYW Envuronmental

Conservation

 

SGEIS Bibliography

Final

Supplemental Generic Environmental Impact Statement



This page intentionally left blank.

[AKRF] AKRF Consultants 2009 December 3. Memo from Hillel Hammer at AKRF
Consultants to “file” regarding “Marcellus Shale DSGEIS: Summary of Comments on Air
Quality and Greenhouse Gas Analysis.” Memo was submitted as an attachment to the
December 30, 2009, Joint Comment submission from NRDC, Earthjustice, Riverkeeper, and
Catskill Mountainkeeper regarding the 2009 dSGEIS.
[Alpha] Alpha Environmental Consultants Inc. 2011 February 4. Review of USGS Comment on
dSGEIS. Letter from Thomas Johnson to Kathleen Sanford.
[Alpha] Alpha Environmental Consultants Inc. 2011 January 26. Review and Response to
“Human Health Risk Evaluation for Hydraulic Fracturing Fluid Additives – Marcellus Shale
Formation, New York. Prepared for NYSERDA, Albany, NY.
[Alpha] Alpha Environmental Consultants Inc. 2011 January 26. Review and Response to
“Impact Assessment of Natural Gas Production in the New York City Watershed.” Prepared
for NYSERDA, Albany, NY.
[Alpha] Alpha Environmental Consultants Inc. 2011 January 20. Review of dSGEIS and
Identification of Best Technology and Best Practices Recommendations. Prepared for
NYSERDA, Albany, NY.
[Alpha] Alpha Environmental Consultants Inc. 2011 January 19. Review of dSGEIS Concerning
Natural Gas Development of the Marcellus Shale within the New York City Watershed.
Prepared for NYSERDA, Albany, NY.
[Alpha] Alpha Environmental Consultants Inc. 2010 January 14. Review of dSGEIS and
Identification of Best Technology and Best Practices Recommendations. Prepared for
NYSERDA, Albany, NY.
[Alpha] Alpha Environmental Consultants Inc. 2010 January 14. Review of HESI Chemistry
Scoring Index. Letter from Thomas Johnson to Kathleen Sanford.
[Alpha] Alpha Environmental Consultants Inc. 2009 September 23. Issues Related to Developing
the Marcellus Shale and Other Low-Permeability Gas Reservoirs. Prepared for NYSERDA,
Albany, NY.
ALL Consulting. 2011 March 16. Letter from Daniel Arthur to Brad Gill, Executive Director of
the Independent Oil and Gas Association of New York, regarding average vehicle miles
traveled (VMT) for light and heavy truck types.
ALL Consulting. 2011 June 30. SGEIS Supplementary Information – Production Rates. Letter to
Brad Gill, Executive Director, Independent Oil & Gas Association of New York.
ALL Consulting. 2010 September 16. NYDEC Information Requests. Project No. 1284.
Prepared for the Independent Oil & Gas Association of New York.

Final SGEIS 2015, Bibliography, Page B-1

 ALL Consulting. 2009 August 26. Horizontally Drilled/High-Volume Hydraulically Fractured
Wells Air Emission Data.
ALL Consulting. 2008 November. Evaluating the Environmental Implications of Hydraulic
Fracturing in Shale Gas Reservoirs.
[ANL] Argonne National Laboratory. 2011. Fact Sheet – The First Step: Separation of Mud from
Cuttings. Drilling Waste Management Information System. Available at
http://web.ead.anl.gov/dwm.techdesc/sep/index.cfm (accessed May 5, 2011).
[ANL] Argonne National Laboratory. 2011. Fact Sheet – Solidification and Stabilization.
Drilling Waste Management Information System. Available at
http://web.ead.anl.gov/dwm/techdesc/solid/index.cfm (accessed May 6, 2011).
[API] American Petroleum Institute. December 2010. Specification for Cements and Materials
for Well Cementing. ANSI, API Specification 10A. Twenty-Fourth Edition.
[API] American Petroleum Institute. June 2010. Water Management Associated with Hydraulic
Fracturing. API Guidance Document HF2. First Edition.
[API] American Petroleum Institute, ANSI. November 2009. Recommended Practice on Thread
Compounds for Casing, Tubing, Line Pipe, and Drill Stem Elements. ANSI, API
Recommended Practice 5A3. Third Edition.
[API] American Petroleum Institute. August 2009. Compendium of Greenhouse Gas Emissions
Estimation Methodologies for the Oil and Natural Gas Industry. Available at
http://www.api.org/ehs/climate/new/upload/2009_GHG_COMPENDIUM.pdf (accessed
September 21, 2009).
[API] American Petroleum Institute. March 2009. Coiled Tubing Well Control Equipment
Systems. API Recommended Practice 16ST. First Edition.
[API] American Petroleum Institute. April 2008. Specification for Threading, Gauging and
Thread Inspection of Casing, Tubing, and Line Pipe Threads. API Specification 5B. Fifteenth
Edition.
[API] American Petroleum Institute. May 2006. Recommended Practice for Well Control
Operations. API Recommended Practice 59.
[API] American Petroleum Institute. July 2005. Specification for Casing and Tubing. API
Specification 5C7. Eighth Edition.
[API] American Petroleum Institute, ANSI. June 2005. Field Inspection of New Casing, Tubing,
and Plain-end Drill Pipe. ANSI, API Recommended Practice 5A5. Seventh Edition.

Final SGEIS 2015, Bibliography, Page B-2

 [API] American Petroleum Institute. 2004, amended 2005. Compendium of Greenhouse Gas
Emissions Methodologies for the Oil and Gas Industry. Washington DC.
[API] American Petroleum Institute, ISO, ANSI. August 2004. Recommended Practice for
Centralizer Placement and Stop Collar Testing. ANSI,API Recommended Practice 10D-2.
First Edition.
[API] American Petroleum Institute and International Petroleum Industry Environmental
Conservation Association. 2003 December. Petroleum Industry Guidelines for Reporting
Greenhouse Gas Emissions.
[API] American Petroleum Institute. ANSI, ISO. March 2002. Specification for Bow-Spring
Casing Centralizers. API Specification 10D. Sixth Edition.
[API] American Petroleum Institute. November 2001. Recommended Practice for Diverter
Systems Equipment and Operations. API Recommended Practice 64(RP 64). Second Edition.
[API] American Petroleum Institute. May 1999. Recommended Practice for Care and Use of
Casing and Tubing. API Recommended Practice 5C1. Eighteenth Edition.
[API] American Petroleum Institute. March 1997. Recommended Practices for Blowout
Prevention Equipment Systems for Drilling Wells. API Recommended Practice 53. Third
Edition.
[API] American Petroleum Institute. 1996. December. Recommended Practice for Coiled Tubing
Operations in Oil and Gas Well Services. API Recommended Practice 5C7. First Edition.
Armendariz, A. 2009 January 26. Emissions from Natural Gas Production in the Barnett Shale
Area and Opportunities for Cost-Effective Improvements. Department of Environmental and
Civil Engineering. Southern Methodist University. Dallas, Texas. Available from:
http://www.edf.org/documents/9235_Barnett_Shale_Report.pdf.
Bowen, K. 2010 September. Developer’s Blasting Sparks Water Complaints. The Daily Gazette,
Schenectady, NY.
Cabot Oil & Gas Corporation, 2009 October 16. Final Engineering Study in Response to Order
Dated September 24, 2009.
Camp, Dresser and McKee. 1986. Minimum Instream Flow Study. Final Report to the
Commonwealth of Virginia State Water Control Board, Annandale, Virginia.
Chesapeake Energy Corporation. 2009 July. Greenhouse Gas Emissions and Reductions Fact
Sheet. Available from:
http://www.chk.com/Media/CorpMediaKits/Greenhouse_Gas_Emissions_and_Reduction.pdf
(accessed December 10, 2009).

Final SGEIS 2015, Bibliography, Page B-3

 Colorado Oil and Gas Conservation Commission. 2009. Final Amended Rules; Training
Presentations. Available from: http://cogcc.state.co.us (accessed July 8, 2009).
Colorado Oil and Gas Conservation Commission. 2009 March 30. Series Drilling, Development,
Production and Abandonment. Available from:
http://cogcc.state.co.us/RR_Docs_new/rules/300series.pdf (accessed August 26, 2009).
Considine, T., Watson, R., Entler, R., and Sparks, J. 2009 August 5. An Emerging Giant:
Prospects and Economic Impacts of Developing the Marcellus Shale Natural Gas Play.
Prepared for the Marcellus Shale Gas Committee by the Department of Energy and Mineral
Engineering, The Pennsylvania State University, p. 2.
Cornue, D. 2011 May 5. NYSDEC. SGEIS Question Concerning Surface Disturbance. Email to
P. Briggs (NYSDEC).
[DFWMR] Division of Fish, Wildlife and Marine Resources. 2010. Technical Methods for
Passby Flow Determinations for Ungaged Waterways. Technical Report. New York State
Department of Environmental Conservation. 27 pages.
[DRBC] Delaware River Basin Commission. 2008 September 12. Administrative Manual Part
III--Water Quality Regulations (with amendments through July 16, 2008) 18 CFR Part 410.
Available from: http://www.state.nj.us/drbc/regs/WQRegs_071608.pdf (accessed August 27,
2009).
[DRBC] Delaware River Basin Commission. 2007 August 14. Water Code. 18 CFR Part 410.
Available from: http://www.state.nj.us/drbc/regs/watercode_092706.pdf (accessed September
29, 2009).
Dutton, R. and Blankenship, G. 2010 August. Socioeconomic Effects of Natural Gas
Development. Prepared to support NTC Consultants, under contract with The New York
State Energy Research & Development Authority. Appendix B in NTC, 2011.
Dugan, G.M. 2008 April 1. Drilling Fluids: Tackling HDD Spoil Disposal Issues. Trenchless
Technology. Available at http://www.trenchlessonline.com/index/webapp-storiesaction?id=510 (accessed May 5, 2011).
[ECL] Environmental Conservation Law. (With 2009 Cumulative Pocket Part). c2007 and 2009.
Ed. McKinney's Consolidated Laws of New York Annotated--Book 17½. Eagan MN: West.
Available from: http://public.leginfo.state.ny.us/menugetf.cgi?COMMONQUERY=LAWS
(accessed September 21, 2009).
Ecology and Environment Engineering, P.C. 2011 August. Assessing and Mitigating the
Socioeconomic, Visual, Noise, Transportation, and Community Character Impacts Associated
With High-Volume Hydraulic Fracturing.

Final SGEIS 2015, Bibliography, Page B-4

 Eltschlager, K., Hawkins, J., Ehler, W., Baldassare, F. 2001 September. Technical Measures for
the Investigation and Mitigation of Fugitive Methane Hazards in Areas of Coal Mining. U.S.
Department of the Interior, Office of Surface Mining Reclamation and Enforcement,
Pittsburgh.
Engelder, T. 2009 August. Marcellus 2008: Report Card on the Breakout Year for Gas
Production in the Appalachian Basin. Fort Worth Basin Oil & Gas Magazine.
Engelder, T., Lash, G. 2008. Marcellus Shale Play’s Vast Resource Potential Creating Stir in
Appalachia. American Oil & Gas Reporter. May 2008.
Environmental Law Clinic. 2010 October 28. Comment letter on NYSDEC’s Draft Strategic
Plan for Forest Management, from the Environmental Law Clinic.
Estes, C.C. 1998. Annual Summary of Instream Flow Reservations and Protection in Alaska.
Fisheries Data Series No. 98-40. Anchorage: Alaska Department of Fish and Game.
Estes, C.C. 1984. Evaluation of Methods for Recommending Instream Flows to Support
Spawning by Salmon. Master’s thesis, Washington State University, Pullman.
Federal Register. 2010 November 30. Mandatory Reporting of Greenhouse Gases: Petroleum
and Natural Gas Systems; Final Rule. Vol. 35. No. 229. P. 74458-74515. Available at
http://edocket.access.gpo.gov/2010/pdf/2010-28655.pdf (accessed December 8, 2010).
[FEMA] United States Department of Homeland Security. FEMA Map Service Center.
Available from: http://msc.fema.gov (accessed August 27, 2009).
Fisher, K. 2010 July. Data Confirm Safety of Well Fracturing. American Oil & Gas Reporter,
July 2010, pp. 30-33.
Forster, P., Ramaswamy, V., Artaxo, P., Berntsen, T., Betts, R., Fahey, D.W., Haywood, J.,
Lean, J., Lowe, D.C., Myhre, G., Nganga, J., Prinn, R., Raga, G., Schulz, M., and Van
Dorland, R. 2007: Changes in Atmospheric Constituents and in Radiative Forcing. In: Climate
Change 2007: The Physical Science Basis. Contribution of Working Group I to the Fourth
Assessment Report of the Intergovernmental Panel on Climate Change [Solomon, S., D. Qin,
M. Manning, Z. Chen, M. Marquis, K.B. Averyt, M.Tignor and H.L. Miller (eds.)].
Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA.
Available from:. http://ipcc-wg1.ucar.edu/wg1/Report/AR4WG1_Print_Ch02.pdf (accessed
December 10, 2009).
Gas Research Institute. 1996. Methane Emissions from Natural Gas Industry. Available at:
epa.gov/gasstar/tools/related.html (accessed September 22, 2009).

Final SGEIS 2015, Bibliography, Page B-5

 [GWPC] Ground Water Protection Council. 2009 May. State Oil and Natural Gas Regulations
Designed to Protect Water Resources. Prepared for the United States Department of Energy
(USDOE). Available at: http://www.gwpc.org/elibrary/documents/general/State%20Oil%20and%20Gas%20Regulations%20Designed%20to
%20Protect%20Water%20Resources.pdf (accessed September 3, 2009).
[GWPC] Ground Water Protection Council and ALL Consulting. 2009 April. Modern Shale Gas
Development in the United States: A Primer. Prepared for United States Department of
Energy (USDOE). Available from:
http://fossil.energy.gov/programs/oilgas/publications/naturalgas_general/Shale_Gas_Primer_2
009.pdf (accessed August 28, 2009).
Harrison, S.S. 1983 November. Evaluating System for Groundwater Contamination Hazards Due
to Gas Well Drilling on the Glaciated Appalachia Plateau. Groundwater 21:6 pp. 689-700.
Hill, D.G., Lombardi, T.E., Martin, J.P. 2003. Fractured Shale Gas Potential in New York.
Available at http://www.pe.tamu.edu/wattenbarger/public_html/Selected_papers/-Shale%20Gas/fractured%20shale%20gas%20potential%20in%20new%20york.pdf (accessed
September 22, 2009).
Hoover, J.P., M.C. Brittingham, and L.J. Goodrich. 1995. Effects of Forest Patch Size on
Nesting Success of Wood Thrushes. The Auk 112 (1):146-155.
[ICF Task 1] ICF Incorporated, LLC. 2009 August 7. Technical Assistance for the Draft
Supplemental Generic EIS: Oil, Gas and Solution Mining Regulatory Program, Task 1.
Prepared for NYSERDA, Albany, NY.
[ICF Task 2] ICF Incorporated, LLC. 2009 August 5. Technical Assistance for the Draft
Supplemental Generic EIS: Oil, Gas and Solution Mining Regulatory Program, Task 2.
Prepared for NYSERDA, Albany, NY.
[IFC] Instream Flow Council. 2004. Instream Flows for Riverine Resource Stewardship.
[IOCGG] Interstate Oil & Gas Compact Commission. 2009. Issues. Available from:
http://www.iogcc.state.ok.us/hydraulic-fracturing (accessed August 31, 2009).
[IPCC] International Panel on Climate Change. 2007. Climate Change 2007: The Physical
Science Basis. Contribution of Working Group I to the Fourth Assessment Report of the
Intergovernmental Panel on Climate Change. Solomon S, Qin D, Manning M, Chen Z,
Marquis M, Avery KB, Tignor M, and Miller HL, eds. Cambridge University Press,
Cambridge, United Kingdom and New York, NY, USA. Available from: http://ipccwg1.ucar.edu/wg1/Report/AR4WG1_Print_FAQs.pdf (accessed September 22, 2009).
[IPIECA] International Petroleum Industry Environmental Conservation Association and [API]
American Petroleum Institute. Petroleum Industry Guidelines for Reporting Greenhouse Gas
Emissions, December 2003., p. 5-2.

Final SGEIS 2015, Bibliography, Page B-6

 Johnson, N. 2010. Pennsylvania Energy Impacts Assessment Report 1: Marcellus Shale, Natural
Gas and Wind. The Nature Conservancy, Harrisburg, PA.
http://www.nature.org/media/pa/tnc_energy_analysis.pdf
Keech, D. and Gaber, M.1982 February. Methane in Water Wells. National Ground Water
Association. Consultants Collection.
Kenny, J.F., Barber, N.L., Hutson, S.S., Linsey, K.S., Lovelace, J.K. and Maupin, M.A. 2009.
Estimated Use of Water in the United States in 2005: U.S. Geological Survey Circular 1344,
52 p.
Kruse, M. 1997 July. Gaseous Gold. The Daily Gazette, Schenectady, NY.
Kucewicz, J. 1997 July. Potential Plays in Eastern New York; A New Evaluation to Identify
Exploration Fairways.
Larsen, H.N. 1981. Internal Regional Policy for New England Streamflow Recommendations.
Newton Corners, MA: U.S. Fish and Wildlife Service, Region 5.
Lloyd, E. 2008 July 18. Letter to Commissioner Alexander B. Grannis, NYSDEC.
Lumia, R., Freehafer, D.A., and Smith, M.J. 2006. Magnitude and Frequency of Floods in New
York: U.S. Geological Survey Scientific Investigations Report 2006-5112, 152 pages.
Available at http://pubs.usgs.gov/sir/2006/5112/SIR2006-5112.pdf
McGowan, K.J., and Corwin, K. 2008. The Second Atlas of Breeding Birds in New York State.
Cornell University Press, Ithaca, NY. 688pp. Also see
http://www/dec/ny.gov/animals/7312.html.
Mitchell, L.R., Smith, C.R., and Malecki, R.A. 2000. Ecology of Grassland Breeding Birds in
the Northeastern United States - A Literature Review with Recommendations for
Management. U.S. Geological Survey, Biological Resources Division, New York Cooperative
Fish and Wildlife Research Unit, Department of Natural Resources, Cornell University,
Ithaca, NY.
Morgan, M. and Burger, M. 2008. A Plan for Conserving Grassland Birds in New York: Final
Report to the New York State Department of Environmental Conservation under contract #
C005137.
National Reasearch Council. 2000. Watershed Management for Potable Water Supply:
Assessing New York City’s Approach.
[NETL] National Energy Technology Laboratory. 2010. Fact Sheet – Oxidation.
http://www.netl.doe.gov/research/coal/crosscutting/pwmis/tech-desc/oxidation.

Final SGEIS 2015, Bibliography, Page B-7

 New Mexico Climate Change Advisory Group. November 2006. Appendix D New Mexico
Greenhouse Gas Inventory and Reference Case Projections, 1990-2020., pp. D-35. Available
from: http://www.nmclimatechange.us/ewebeditpro/items/O117F10152.pdf (accessed
December 10, 2009).
New Mexico Department of Game and Fish. 2007. Oil and Gas Development Guidelines:
Conserving New Mexico’s Wildlife Habitat and Wildlife.
http://www.wildlife.state.nm.us/documents/oilandgasguidelines.pdf
New Mexico Environment Department. December 2007. Oil and Gas Greenhouse Gas Emissions
Reductions.
New York State Commission on State Asset Maximization. 2009 June. The Final Report of the
New York State Commission on Asset Maximization.
New York State Energy Planning Board. 2009 August. Draft New York State Energy Plan.
New York State Invasive Species Task Force. 2005 Fall. Final Report. Available from:
http://www.dec.ny.gov/docs/wildlife_pdf/istfreport1105.pdf (accessed September 29, 2009).
New York State Public Service Commission. 2004 August. The Certification Review Process for
Major Electric and Fuel Gas Transmission Facilities--Under Article VII of the New York
State Public Service Law. Available from:
http://www.dps.state.ny.us/Article_VII_Process_Guide.pdf (accessed September 29, 2009).
[NTC] NTC Consultants. 2011 February 18. Impacts on Community Character of Horizontal
Drilling and High Volume Hydraulic Fracturing in Marcellus Shale and Other LowPermeability Gas Reservoirs. Prepared for NYSERDA, Albany, NY.
[NTC] NTC Consultants. 2009 September 16. Impacts on Community Character of Horizontal
Drilling and High Volume Hydraulic Fracturing in Marcellus Shale and Other LowPermeability Gas Reservoirs. Prepared for NYSERDA, Albany, NY.
[NYCDEP] New York City Department of Environmental Protection. c2009. Drinking Water
Supply and Quality Report. Available from:
http://www.nyc.gov/html/dep/html/drinking_water/wsstate.shtml (accessed August 27, 2009).
[NYCDEP] New York City Department of Environmental Protection. c2009. New York City
Water Supply Watersheds. Available from:
http://www.nyc.gov/html/dep/html/watershed_protection/html/regcontext.html (accessed
September 3, 2009).
[NYCDEP] New York State Department of Environmental Protection. March 2009. Title 15
Rules of the City of New York. Section 18-16. Definitions. Available from:
http://24.97.137.100/nyc/rcny/entered.htm.

Final SGEIS 2015, Bibliography, Page B-8

 [NYCDEP] New York City Department of Environmental Protection. c2009. Watershed Rules
and Regulations. Available from:
http://www.nyc.gov/html/dep/html/watershed_protection/html/regulations.html# (accessed
August 31, 2009).
[6 NYCRR] New York Department of State--Division of Administrative Rules. 2009. New York
State Compilation of Codes, Rules and Regulations. Thomson Reuters\West. Unofficial
version available from: http://www.dos.state.ny.us/info/nycrr.htm (accessed September 8,
2009).
[6 NYCRR] Part 617.20. [undated]. Appendix A--State Environmental Quality Review: Full
Environmental Assessment Form. Available from:
http://www.dec.ny.gov/docs/permits_ej_operations_pdf/longeaf.pdf (accessed September 3,
2009).
[6 NYCRR] Part 617.20. [undated]. Appendix B--State Environmental Quality Review: Visual
EAF Addendum. Available from:
http://www.dec.ny.gov/docs/permits_ej_operations_pdf/visualeaf.pdf (accessed September 2,
2009).
[10 NYCRR] New York Department of State--Division of Administrative Rules. 2009. New
York State Compilation of Codes, Rules and Regulations. Thomson Reuters\West. Unofficial
version available from: http://www.dos.state.ny.us/info/nycrr.htm (accessed September 8,
2009).
[12 NYCRR] New York Department of State--Division of Administrative Rules. 2009. New
York State Compilation of Codes, Rules and Regulations. Thomson Reuters\West. Unofficial
version available from: http://www.dos.state.ny.us/info/nycrr.htm (accessed September 8,
2009).
[NYSDEC] New York State Department of Environmental Conservation. 2010. Final Report:
A Regulatory System for Non-Native Species. Prepared by the New York Invasive Species
Council, 10 June 2010. Available from:
http://www.dec.ny.gov/docs/lands_forests_pdf/invasive062910.pdf.
[NYSDEC] New York State Department of Environmental Conservation. 2010. Forest Resource
Assessment and Strategy: 2010-2015.
http://www.dec.ny.gov/docs/lands_forests_pdf/fras070110.pdf.
New York State Department of Environmental Conservation. 2010. Strategic Plan for State
Forest Management. http://www.dec.ny.gov/docs/lands_forests_pdf/spsfmfinal.pdf.
[NYSDEC] New York State Department of Environmental Conservation. 2009 July 15.
Assessing Energy Use and Greenhouse Gas Emissions in Environmental Impact Statements.
Available from: http://www.dec.ny.gov/docs/administration_pdf/eisghgpolicy.pdf (accessed
September 30, 2009).

Final SGEIS 2015, Bibliography, Page B-9

 [NYSDEC] New York State Department of Environmental Conservation. 2009 February 6. Final
Scope for Draft Supplemental Generic Environmental Impact Statement [pdSGEIS) on the
Oil, Gas and Solution Mining Regulatory Program-Well Permit Issuance for Horizontal
Drilling and High-Volume Hydraulic Fracturing to Develop the Marcellus Shale and Other
Low-Permeability Gas Reservoirs. Albany, NY.
[NYSDEC] New York State Department of Environmental Conservation. c2009. Part 601: Water
Supply Applications (Exclusive of Long Island Wells). Available from:
http://www.dec.ny.gov/regs/4445.html (accessed September 4, 2009).
[NYSDEC] New York State Department of Environmental Conservation. c2009. Part 663:
Freshwater Wetlands Permit Requirements. Available from:
http://www.dec.ny.gov/regs/4613.html (accessed September 4, 2009).
[NYSDEC] New York State Department of Environmental Conservation. c2009. Part 664:
Freshwater Wetlands Maps and Classification. Available from:
http://www.dec.ny.gov/regs/4612.html (accessed September 4, 2009).
[NYSDEC] New York State Department of Environmental Conservation. 1992. [GEIS] Generic
Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program.
Available from: http://www.dec.ny.gov/energy/45912.html (accessed August 27, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Bureau of Hazardous
Waste Management. c2009. An Investigation of Naturally Occurring Radioactive Materials
(NORM) in Oil and Gas Wells in New York State, Executive Summary. Available from:
http://www.dec.ny.gov/chemical/23473.html (accessed September 3, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Bureau of Source
Control. 1994 September 28. Spill Prevention Operations Technology Series (SPOTS) Memo
#10: Secondary Containment Systems for Aboveground Storage Tanks. Available from:
http://www.dec.ny.gov/docs/remediation_hudson_pdf/spots10.pdf (accessed September 4,
2009).
[NYSDEC] New York State Department of Environmental Conservation, Bureau of Water
Resource Management. c2009. New York City Watershed Program. Available from:
http://www.dec.ny.gov/lands/25599.html (accessed September 3, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Air. c2009.
Ambient Air Quality Monitoring. Available from: http://www.dec.ny.gov/chemical/8406.html
(accessed September 30, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Air. c2009.
Policy CP-33: Assessing and Mitigating Impacts of Fine Particulate Matter Emissions.
Available from: http://www.dec.ny.gov/chemical/8912.html (accessed September 30, 2009).

Final SGEIS 2015, Bibliography, Page B-10

 [NYSDEC] New York State Department of Environmental Conservation, Division of Air. c2009.
Policy DAR-1: Guidelines for Control of Toxic Ambient Air Contaminants. Available from:
http://www.dec.ny.gov/chemical/30681.html (accessed August 31, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Air. c2009.
DAR-1--AGC/SGC Tables and Software Support Files. Available from:
http://www.dec.ny.gov/chemical/30560.html (accessed September 30, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Air. c2009.
Policy DAR-10: Impact Analysis Modeling. Available from:
http://www.dec.ny.gov/chemical/8923.html (accessed September 30, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Air. c2009.
State Implementation Plan. Available from: http://www.dec.ny.gov/chemical/8403.html
(accessed September 30, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of
Environmental Permits. c2009. Division of Environmental Permits Policy Documents.
Available from: html://www.dec.ny.gov/permits/6224.html (accessed September 2, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of
Environmental Remediation. 2010 May 3. Policy DER-10: Technical Guidance for Site
Investigation and Remediation. Available from:
http://www.dec.ny.gov/regulations/67386.html (accessed June 15, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Mineral
Resources. c2009. Casing and Cementing Practices. Available from:
http://www.dec.ny.gov/energy/1757.html (accessed September 2, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Mineral
Resources. c2009. Fresh Water Aquifer Supplementary Drilling Conditions. Available from:
http://www.dec.ny.gov/energy/42714.html (accessed September 2, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Mineral
Resources. c2009. Marcellus Shale. Available from:
http://www.dec.ny.gov/energy/46288.html (accessed September 3, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Minerals.
2007 October. Application to Drill, Deepen, Plug Back or Convert a Well Subject to the Oil,
Gas and Solution Mining Law. Available from:
http://www.dec.ny.gov/docs/materials_minerals_pdf/eaf_dril.pdf (accessed September 3,
2009).

Final SGEIS 2015, Bibliography, Page B-11

 [NYSDEC] New York State Department of Environmental Conservation, Division of Minerals.
2007 January. Environmental Assessment Form. Available from:
http://www.dec.ny.gov/docs/materials_minerals_pdf/eaf_dril.pdf (accessed September 3,
2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Solid and
Hazardous Materials. [undated]. Medical Waste Disposal Form. Available from:
http://www.dec.ny.gov/docs/materials_minerals_pdf/medwste.pdf (accessed September 29,
2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Water.
c2009. Multi-Sector General SW Permit and Forms. Available from:
http://www.dec.ny.gov/chemical/9009.html (accessed September 29, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Water.
c2009. Technical & Operational Guidance Series. Available from:
http://www.dec.ny.gov/regulations/2652.html (accessed September 30, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Water.
c2009. Water Proposed & Recently Adopted Regulations. Available from:
http://www.dec.ny.gov/regulations/39559.html (accessed September 17, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Water.
c2009. Watersheds, Lakes, Rivers. Available from: http://www.dec.ny.gov/lands/26561.html
(accessed September 3, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Division of Water.
1989 January. Guidelines for Design of Dams. Available from:
http://www.dec.ny.gov/docs/water_pdf/damguideli.pdf (accessed September 17, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Office of Air, Energy,
& Climate. 2009 July 15. Guide for Assessing Energy Use & Greenhouse Gas Emissions in an
Environmental Impact Statement. Available at
http://www.dec.ny.gov/docs/administration_pdf/eisghgpolicy.pdf (accessed September 22,
2009).
[NYSDEC] New York State Department of Environmental Conservation, Office of Climate
Change. c2009. Climate Change--New Yorkers are Working on Many Fronts. Available at
http://www.dec.ny.gov/energy/44992.html (accessed September 22, 2009).
[NYSDEC] New York State Department of Environmental Conservation, Office of Remediation
and Materials Management. 2008 September 23. DER-17: Guidelines for Inspecting and
Certifying Secondary Containment Systems of Aboveground Petroleum Storage Tanks at
Major Oil Storage Facilities. Available from:
http://www.dec.ny.gov/docs/remediation_hudson_pdf/der17.pdf (accessed September 4,
2009).

Final SGEIS 2015, Bibliography, Page B-12

 [NYSDEC] New York State Department of Environmental Conservation. 1984 December 19.
Public Information Meeting Pursuant to SEQR--Commissioner's Decision.
[NYSDEC] New York State Department of Environmental Conservation, Division of Water.
Ambient Groundwater Monitoring Program. Available from:
http://www.dec.ny.gov/lands/36117.html (accessed June 14, 2011).
[NYSDEC] New York State Department of Environmental Conservation, Division of Mineral
Resources. 2011 January. Investigation of Anschutz’s Dow 1 & 2 Gas Wells Methane in
Water Well Complaints. Memorandum from Linda Collart to Bradley Field/Jack Dahl.
[NYSDEC] New York State Department of Environmental Conservation, Division of Mineral
Resources. 2011 February. Summary of Natalie Brant Complaint. Memorandum from Chris
Miller to Brad Field/JackDahl.
[NYSDEC] New York State Department of Environmental Conservation, Division of Water.
2011 February. Memorandum from Daniel Kendal to Kathleen Sanford.
[NYSDEC] New York State Department of Environmental Conservation. n.d. New York’s Oil
& Gas Database. Available from:
http://www.dec.ny.gov/docs/remediation_hudson_pdf/spots10.pdf.
[NYSDOH] New York State Department of Health. [undated]. New York State Laws and
Regulations--NYCRR Title 10. Available from:
http://www.health.state.ny.us/nysdoh/phforum/nycrr10.htm (accessed September 4, 2009).
[NYSDOH] New York State Department of Health, 2014. A Public Health Review of High
Volume Hydraulic Fracturing for Shale Gas Development. Available from:
http://www.health.ny.gov/press/reports/docs/high_volume_hydraulic_fracturing.pdf.
[NYSDOH] New York State Department of Health. 2009 July. Drinking Water Program: Facts
and Figures. Available from:
http://www.health.state.ny.us/environmental/water/drinking/facts_figures.htm (accessed
August 27, 2009).
[NYSDOH] New York State Department of Health. 2008 September. Individual Water Supply
Wells--Fact Sheet #1. Available from:
http://www.health.state.ny.us/environmental/water/drinking/part5/append5b/fs1_additional_m
easures.htm (accessed August 26, 2009).
[NYSDOH] New York State Department of Health. 2008 September. Individual Water Supply
Wells--Fact Sheet #3. Available from:
http://www.health.state.ny.us/environmental/water/drinking/part5/append5b/fs3_water_qualit
y.htm (accessed September 16, 2009).

Final SGEIS 2015, Bibliography, Page B-13

 [NYSDOH] New York State Department of Health. 2008 September. Individual Water Supply
Wells--Fact Sheet #5. Available from:
http://www.health.state.ny.us/environmental/water/drinking/part5/append5b/fs5_susceptible_
water_sources.htm (accessed August 27, 2009).
[NYSDOH] New York State Department of Health. 2007 September. Appendix 5-B: Standards
for Water Wells. Available from:
http://www.health.state.ny.us/environmental/water/drinking/part5/appendix5b.htm (accessed
August 27, 2009).
[NYSDOH] New York State Department of Health. 2007 September. Appendix 5-B: Standards
for Water Wells; Table 1--Required Minimum Separation Distances to Protect Water Wells
From Contamination. Available from:
http://www.health.state.ny.us/environmental/water/drinking/part5/appendix5b.htm#table1
(accessed August 26, 2009).
[NYSDOH] New York State Department of Health, Wadsworth Center. [undated].
Environmental Laboratory Approval Program. Available from:
http://www.wadsworth.org/labcert/elap/elap.html (accessed September 29, 2009).
[NYSDPS] New York State Department of Public Service. 2006. Environmental Management
and Construction Standards and Practices for Underground Transmission and Distribution
Facilities in New York State, Office of Electricity & Environment, Albany, NY.
Osborne, S., Vengosh, A., Warner, N., and Jackson, R. 2011 April. Methane Contamination of
Drinking Water Accompanying Gas-Well Drilling and Hydraulic Fracturing. Duke University,
Durham, NC.
[OSHA] Occupational Safety and Health Administration. About OSHA. United States
Department of Labor. http://www.osha.gov/about.html (accessed June 15, 2011).
[OSHA] Occupational Safety and Health Administration. Regulations. Part 1910, Occupational
Safety and Health Standards. Subpart Z, Toxic and Hazardous Substances. Standard
1910.1200 Hazard Communication. Available at
http://www.osha.gov/pls/oshaweb/owadisp.show_document?p_table=STANDARDS&p_id=1
0099 (accessed June 15, 2011).
Ohio Department of Natural Resources, Division of Mineral Resources Management. 2008.
Report on the Investigation of the Natural Gas Invasion of Aquifers in Bainbridge Township
of Geauga County, Ohio. 64 pp.
Pagano, S. 1990 October 23. Memorandum to Regional Water Engineers, Bureau Directors,
Section Chiefs. Available from: http://www.dec.ny.gov/docs/water_pdf/togs213.pdf (accessed
August 27, 2009).

Final SGEIS 2015, Bibliography, Page B-14

 Pennsylvania Environmental Quality Board. Title 25-Environmental Protection, Chapter 78, Oil
and Gas Wells, Pennsylvania Bulletin, Col. 41. No. 6 ( February 5, 2011).
[PADEP] Pennsylvania Department of Environmental Protection. 2009 November 4. Consent
Order and Agreement in the Matter of Cabot Oil and Gas Corporation, Dimock and
Springville Townships, Susquehanna County. 23p.
[PADEP] Pennsylvania Department of Environmental Protection. 2010 July 13. Investigative
Report on Punxsutawney Hunting Club 36H Well.
[PADEP] Pennsylvania Department of Environmental Protection. 2011 May 16. Consent Order
and Agreement in the Matter of Chesapeake Appalachia, LLC. Tuscarora, Terry, Monroe,
Towanda and Wilmot Townships, Bradford County. 40p.
Post, T. 2006. Analysis of Breeding Bird Survey Trends for Landbirds by Species Suite (Habitat)
and Nesting Location. NYSDEC.
Reiser, D.W., Ramey, M.P., and Lambert, T.R. 1988. Review of Flushing Flow Requirements in
Regulated Streams. In Nelson WR, Dwyer JR, Greenberg WE, eds. Flushing and Scouring
Flows for Habitat Maintenance in Regulated Streams. Washington, D.C.: U.S. Environmental
Protection Agency.
Richenderfer, J. 2010. Water Use Profile of Natural Gas Industry in Susquehanna River Basin.
IN Clear Waters Winter 2010, vol. 40, no. 4. New York Water Environment Association, Inc.
Robbins, C.R. 1979. Effects of Forest Fragmentation on Bird Populations. Pgs. 198-212 in
Northcentral and Northeastern forests for nongame birds. USDA Forest Service Techpub.
NC-51.
Roberts, C. and Norment, C.J. 1999. Effects of plot size and habitat characteristics on breeding
success of scarlet tanagers. The Auk 116 (1):73-82.
Robinson, S.K., Thompson III, F.R., Donovan, T.M., Whitehead, D.R., and Faaborg, J. 1995.
Regional forest fragmentation and nesting success of migratory birds. Science. 267(5206):
1987-1990.
Rosenberg, K.V., Rohrbaugh Jr., R.W., Barker, S.E., Lowe, J.D., Hames, R.S., and Dhondt, A.A.
1999. A Land Managers Guide to Improving Habitat for Scarlet Tanagers and Other ForestInterior Birds. The Cornell Lab of Ornithology. web site.
http://www.birds.cornell.edu/conservation/tanager/edge.html.
Sample, D.W. and Mossman, M.J. 1997. Managing Habitat for Grassland Birds: A Guide for
Wisconsin. Dept. of Natural Resources, Madison. 154pp.
Sanford, K.F. 2007 April 18. Letter to Kenneth E. Moriarty, NYCDEP.

Final SGEIS 2015, Bibliography, Page B-15

 Schlumberger. 2010. Coiled Tubing, Nitrogen, and Pumping Services. Available from
http://www.slb.com/resources/other_resources/brochures/coiled_tubing/usland_ct_br.aspx
(accessed June 28, 2011).
Schuler, T. 1994. The Importance of Imperviousness Watershed Protection Techniques. Vol. 1.
Issue 3.
Skrapits, E. 2011 May. Drillers Take Another Chance in Columbia County. Citizens Voice.
Available from http://energy.wilkes.edu/pages/106.asp?item=341 (accessed June 10, 2011.
Skrapits, E. 2010 November. Despite Encana’s Exit, Other Companies Stay Put. Citizens Voice.
Available from http://citizensvoice.com/news/despite-encana-s-exit-other-companies-stayput-1.1066540#axzz1NZF23wB (accessed June 10, 2011).
Smith, M. 2008 September 1. FRACforward, Startup Cracks Propane Fracture Puzzle, Provides
‘Green’ Solution, Nickle’s New Technology Magazine, www.ntm.nickles.com.
Smith, M.W., J.P. Varner, J.P. Mital, D.J. Sokoloski. 2006. Remediation of Acid Rock Drainage
from Highway Construction in the Marcellus Shale, Mifflin County, Pennsylvania.
Abstract available from:
http://gsa.confex.com/gsa/2006NE/finalprogram/abstract_100515.htm).
Sovas, G.H. 2003 April 19. Supplemental Findings Statement. SEQR File No. P0-009900-00046.
Available from: http://www.dec.ny.gov/docs/materials_minerals_pdf/geisfindsup.pdf
(accessed September 3, 2009).
Sovas, G.H. 1992 September 1. Findings Statement. Available from:
http://www.dec.ny.gov/docs/materials_minerals_pdf/geisfindorig.pdf (accessed September 3,
2009).
[SRBC] Susquehanna River Basin Commission. 2011 March 4. Email from Paula Ballaron
(SRBC) to K. Sanford (NYSDEC).
[SRBC] Susquehanna River Basin Commission. 2009 January 15. Regulation of Projects. 18
CFR Parts 801, 806, 807 and 808. Available from:
http://www.srbc.net/policies/docs/srbc_regulation_of_projects.PDF (accessed September 29,
2009).
[SRBC] Susquehanna River Basin Commission. 2002 November 8. Policy No. 2003-01.
Guidelines for Using and Determining Passby Flows and Conservation Releases for SurfaceWater and Ground-Water Withdrawal Approvals. Available from:
http://www.srbc.net/policies/docs/Policy%202003_01.pdf (accessed September 29, 2009).
[SRBC] Susquehanna River Basin Commission. [undated]. Marcellus/Utica Shale and Natural
Gas Well Development. Available from:
http://www.srbc.net/programs/projreviewmarcellustier3.htm (accessed August 27, 2009).

Final SGEIS 2015, Bibliography, Page B-16

 Tennant, D.L. 1976a. Instream Flow Regimes for Fish, Wildlife, Recreation and Related
Environmental Resources. In Osborn JF and Allman CH, eds. Proceedings of Symposium and
Specialty Conference on Instream Flow Needs, Vol. II, American Fisheries Society, Bethesda,
Maryland: 359-373.
Tennant, D.L. 1976b. Instream Flow Regimes for Fish, Wildlife Recreation and Related
Environmental Resources. Fisheries. July-August 1(4):6-10.
Tennant, D.L. 1975. Instream Flow Regimes for Fish, Wildlife Recreation, and Related
Environmental Resources. United States Fish & Wildlife Service. Billings, Montana.
Tennant, D.L. 1972. A Method for Determining Instream Flow Requirements for Fish, Wildlife
and Aquatic Environment. In Pacific Northwest River Basin Commission pp. 3-11.
Tessmann, S.A. 1980. Environmental Assessment, Technical Appendix E in Environmental Use
Sector Reconnaissance Elements of the Western Dakotas Region South Dakota Study.
Brookings, SD: South Dakota State University, Water Resources Research Institute.
The American Oil & Gas Reporter. 2010 August. Technologies Treat OBM Drill Cuttings.
Special Report: Drilling Fluids. pp. 92-93.
Thurman, K. 1987. Water System Urged for Subdivision. Times Union, Albany, NY.
[TNC] The Nature Conservancy. 2004. Determining the Size of Eastern Forest Reserves.
http://www.sweetwatertrust.org/ezstatic/data/sweetwatertrust/forestreserves/Eastern_Forest_R
eserves.pdf.
[TNC] The Nature Conservancy. 2003. Planning Methods for Ecoregional Targets: MatrixForming Ecosystems. http://conserveonline.org/library/HAL_070130.pdf/view.html.
[TNC] The Nature Conservancy. 2002. Results for Matrix-Forming Ecosystems. This is where
the table above is from ; had some trouble with formatting and I deleted a lot of rows and
some columns. Good info though.
http://conserveonline.org/workspaces/ecs/hal/hal_extras/docs/matrix_results/view.html.
United States Department of the Interior and United States Department of Agriculture. 2007.
Surface Operating Standards and Guidelines for Oil and Gas Exploration and Development.
BLM/WO/ST-06/021+3071/Rev 07. Bureau of Land Management. Denver, Colorado. 84 pp.
United State Fish and Wildlife Service. n.d. Conserving Grassland Bird Series. USFWS.
[URS] URS Corporation. 2011 March 25. Water-Related Issues Associated with Gas Production
in the Marcellus Shale. Prepared for NYSERDA, Albany, NY.

Final SGEIS 2015, Bibliography, Page B-17

 [URS] URS Corporation. 2010 May 21. Water-Related Issues Associated with Gas Production in
the Marcellus Shale. Prepared for NYSERDA, Albany, NY.[URS] URS Corporation. 2009
August 5. Water-Related Issues Associated with Gas Production in the Marcellus Shale.
Prepared for NYSERDA, Albany, NY.
[URS] URS Corporation. 2009. Water-Related Issues Associated with Gas Production in the
Marcellus Shale. Prepared for NYSERDA, Albany, NY. August 5, 2009.
[USEPA] United States Environmental Protection Agency. 2011. Additional Clarifications
Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2 NAAQS.
Memo from Tyler Fox, EPA OAQPS, dated March 1, 2011. Available at:
http://www.epa.gov/region7/air/nsr/nsrmemos/appwno2_2.pdf.
[USEPA] United States Environmental Protection Agency. 2010 August. Fact Sheet Mandatory
Reporting of Greenhouse Gases. 40 CFR Part 98. Available at
http://www.epa.gov/climatechange/emissions/downloads09/FactSheet.pdf (accessed June 13,
2011).
[USEPA] United States Environmental Protection Agency 2010. March 23, Modeling
Procedures for Demonstrating Compliance with PM2.5 NAAQS, Stephen Page. Available at:
http://www.epa.gov/region7/air/nsr/nsrmemos/pm25memo.pdf.
[USEPA] United States Environmental Protection Agency. 2010 November. Fact Sheet for
Subpart W Petroleum and Natural Gas Systems. Final Rule. Mandatory Reporting of
Greenhouse Gases. 40 CFR Part 98. Available at
http://www.epa.gov/climatechange/emissions/downloads10/Subpart-W_factsheet.pdf
(accessed June 13, 2011).
[USEPA] United States Environmental Protection Agency. 2009 September 24. Natural Gas
STAR Program. Available at: http://www.epa.gov/gasstar/ (accessed September 22, 2009).
[USEPA] United States Environmental Protection Agency. 2009 September 11. Drinking Water
Contaminants. Available from: http://www.epa.gov/safewater/contaminants/index.html
(accessed September 29, 2009).
[USEPA] United States Environmental Protection Agency. 2009 August 28. Filtration
Avoidance. Available from: http://www.epa.gov/Region2/water/nycshed/filtad.htm (accessed
September 3, 2009).
[USEPA] United States Environmental Protection Agency. 2009 August 28. Natural Gas STAR
Program--Recommended Technologies and Practices. Available at:
http://www.epa.gov/gasstar/tools/recommended.html (accessed September 22, 2009).
[USEPA] United States Environmental Protection Agency. 2009 August 27. Drinking Water
Contaminants. Available from: http://www.epa.gov/safewater/contaminants/index.html
(accessed August 27, 2009).

Final SGEIS 2015, Bibliography, Page B-18

 [USEPA] United States Environmental Protection Agency. 2009 May 21. Technology Transfer
Network--National Ambient Air Quality Standards (NAAQS). Available from:
http://www.epa.gov/ttn/naaqs/ (accessed September 30, 2009).
[USEPA] United States Environmental Protection Agency. 2009 February 16. Natural Gas
STAR Program--Join the Program. Available from:
http://www.epa.gov/gasstar/join/index.html (accessed September 22, 2009).
[USEPA] United States Environmental Protection Agency. 2008 October. Your Partner in
Improving Operational Efficiency, Saving Money, and Reducing Emissions. Available at
http://www.epa.gov/gasstar/documents/ngstar_mktg-factsheet.pdf (accessed September 22,
2009).
[USEPA] United States Environmental Protection Agency. 2007 January 3. Federal Register.
Rules and Regulations. Vol. 72, No. 1. Available from:
http://www.epa.gov/ttn/atw/oilgas/fr03ja07.pdf (accessed September 2, 2009).
[USEPA] United States Environmental Protection Agency. 2006. Lessons Learned From Natural
Gas STAR Partners--Optimize Glycol Circulation and Install Flash Tank Separators In Glycol
Dehydrators. Available at: http://www.epa.gov/gasstar/documents/ll_flashtanks3.pdf
(accessed September 22, 2009).
[USEPA] United States Environmental Protection Agency. 2006. Lessons Learned From Natural
Gas STAR Partners--Options for Reducing Methane Emissions from Pneumatic Devices in
the Natural Gas Industry. Available at:
http://www.epa.gov/gasstar/documents/ll_pneumatics.pdf (accessed September 22, 2009).
[USEPA] United States Environmental Protection Agency. 2006. Lessons Learned From Natural
Gas STAR Partners--Reducing Emissions When Taking Compressors Offline. Available at:
http://www.epa.gov/gasstar/documents/ll_compressorsoffline.pdf (accessed September 22,
2009).
[USEPA] United States Environmental Protection Agency. 2006. Lessons Learned From Natural
Gas STAR Partners--Reducing Methane Emissions from Compressor Rod Packing Systems.
Available at: http://www.epa.gov/gasstar/documents/ll_rodpack.pdf (accessed September 22,
2009).
[USEPA] United States Environmental Protection Agency. 2006. Lessons Learned From Natural
Gas STAR Partners--Replacing Gas-Assisted Glycol Pumps with Electric Pumps. Available
at: http://www.epa.gov/gasstar/documents/ll_glycol_pumps3.pdf (accessed September 22,
2009).
[USEPA] United States Environmental Protection Agency. 2006. Lessons Learned From Natural
Gas STAR Partners--Replacing Glycol Dehydrators with Desiccant Dehydrators. Available at:
http://www.epa.gov/gasstar/documents/ll_desde.pdf (accessed September 22, 2009).

Final SGEIS 2015, Bibliography, Page B-19

 [USEPA] United States Environmental Protection Agency. 2005 November 9. Guideline on Air
Dispersion Models, Appendix W of 40 CFR, Part 51. pp. 68218-68261.
Van Tyne, A.M. and Copley, D.L. 1983. New York State Natural Gas Reserve Study. Prepared
for Independent Oil and Gas Association of New York, Inc.
Weinstein, B.L. and Clower, T.L. 2009 July 28. Draft Potential Economic and Fiscal Impacts
from Natural Gas Production in Broome County, New York. Prepared for Broome County
Legislators. Available from: http://www.energyindepth.org/wp-content/uploads/
2009/03/broome-county-potential-economic.pdf (accessed September 30, 2009).
Weller, W., Thomson, J., Morton, P., and Aplet, G. 2002. Fragmenting our Lands: The
Ecological Footprint from Oil and Gas Development. A Spatial Analysis of a Wyoming Gas
Field. The Wilderness Society, Seattle, WA. http://wilderness.org/files/fragmenting-ourlands.pdf.
Wells, J. 1963. Early Investigations of the Devonian System in New York 1656-1836. Special
GSA Papers Number 74. Cornell University.
Wilbert, M., Thomson, J., and Culver, N.W. 2008. Analysis of Habitat Fragmentation from Oil
and Gas Development and its Impact on Wildlife: A Framework for Public Land Management
Planning. The Wilderness Society. http://wilderness.org/files/Oil-Gas-FragmentationScoping-Brief.pdf.
Yoxtheimer, D. 2011 May. Personal Communication with Theodore Loukides, Division of
Mineral Resources.

Final SGEIS 2015, Bibliography, Page B-20

 Appendices
FINAL
Supplemental Generic Environmental Impact
Statement on the Oil, Gas and Solution Mining
Regulatory Program

Regulatory Program for Horizontal Drilling and
High-Volume Hydraulic Fracturing to Develop
the Marcellus Shale and Other LowPermeability Gas Reservoirs

www.dec.ny.gov

 This page intentionally left blank.

Table of Appendices
Final Supplemental Generic Environmental Impact Statement
NO.
1
2

3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
18A
18B
18C
19
20
21
22
23
24
25

1

TITLE
FEMA Flood Insurance Rate Map Availability
1992 SEQRA Findings Statement on the GEIS on the Oil, Gas and Solution
Mining Regulatory Program
Supplemental SEQRA Findings Statement on Leasing of State Lands for Activities
Regulated Under the Oil, Gas and Solution Mining Law
EXISTING Application Form for Permit to Drill, Deepen, Plug Back or Convert a
Well Subject to the Oil, Gas and Solution Mining Regulatory Program
EXISTING Environmental Assessment Form for Well Permitting
PROPOSED Environmental Assessment Form Addendum
Sample Drilling Rig Specifications Provided by Chesapeake Energy
EXISTING Casing and Cementing Practices Required for All Wells in NYS
EXISTING Fresh Water Aquifer Supplementary Permit Conditions Required for
Wells Drilled in Primary and Principal Aquifers
PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic
Fracturing
Analysis of Subsurface Mobility of Fracturing Fluids (Excerpted from ICF
International, Task 1, 2009)
Beneficial Use Determination (BUD) Notification Regarding Road Spreading
Radiological Data – Production Brine from NYS Marcellus Wells
Department of Public Service Environmental Management and Construction
Standards and Practices – Pipelines
Hydraulic Fracturing – 15 Statements from Regulatory Officials
Applicability of NOx RACT Requirements for Natural Gas Production Facilities
Applicability of 40 CFR Part 63 Subpart ZZZZ (Engine MACT) for Natural Gas
Production Facilities – Final Rule
Definition of Stationary Source or Facility for the Determination of Air Permit
Requirements
Evaluation of Particulate Matter and Nitrogen Oxides Emissions Factors and
Potential Aftertreatment Controls for Nonroad Engines for Marcellus Shale
Drilling and Hydraulic Fracturing Operations 1
Cost Analysis of Mitigation of NO2 Emissions and Air Impacts by Selected
Catalytic Reduction (SCR) Treatment1
Regional On-Road Mobile Source Emission Estimates from EPA’s MOVES Model
and Single-Pad PM2.5 Estimates from MOBILE 6 Model
Greenhouse Gas (GHG) Emissions
PROPOSED Pre-Frac Checklist and Certification
Publically Owned Treatment Works (POTWs) with Approved Pretreatment
Programs
POTWs Procedures for Accepting High-Volume Hydraulic Fracturing Wastewater
USEPA Natural Gas STAR Program
Key Features of USEPA Natural Gas STAR Program
Reduced Emissions Completion (REC) Executive Summary

Updated/revised 2015

Final SGEIS 2015, Page A-i

 Table of Appendices
Final Supplemental Generic Environmental Impact Statement
NO.
26

27

TITLE
Instructions for Using the On-Line Searchable Database to Locate Drilling
Applications
NYSDOH Radiation Survey Guidelines and Sample Radioactive Materials
Handling License

Final SGEIS 2015, Page A-ii

 Appendix 1
FEMA
Flood Insurance Rate Map
Availability
Excerpted from Alpha Environmental, 2009
Updated by NYSDEC
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALBANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY

Community Name
ALBANY, CITY OF
ALTAMONT, VILLAGE OF
BERNE,TOWN OF
BETHLEHEM, TOWN OF
COEYMANS, TOWN OF
COHOES, CITY OF
COLONIE, TOWN OF
GREEN ISLAND, VILLAGE OF
GUILDERLAND, TOWN OF
KNOX, TOWNSHIP OF
MENANDS, VILLAGE OF
NEW SCOTLAND, TOWN OF
RAVENA, VILLAGE OF
RENSSELAERVILLE, TOWN OF
VOORHEESVILLE, VILLAGE OF
WATERVLIET, CITY OF
WESTERLO, TOWN OF
ALFRED, TOWN OF
ALFRED, VILLAGE OF
ALLEN, TOWN OF
ALMA, TOWN OF
ALMOND, VILLAGE OF
AMITY  TOWN OF
AMITY,
ANDOVER, TOWN OF
ANDOVER, VILLAGE OF
ANGELICA, TOWN OF
ANGELICA, VILLAGE OF
BELFAST, TOWN OF
BELMONT, VILLAGE OF
BIRDSALL, TOWN OF
BOLIVAR, TOWN OF
BOLIVAR, VILLAGE OF
BURNS, TOWN OF
CANASERAGA, VILLAGE OF
CANEADEA, TOWN OF
CLARKSVILLE, TOWN OF
CUBA, TOWN OF
CUBA, VILLAGE OF
FRIENDSHIP, TOWN OF
GENESEE, TOWN OF
GRANGER, TOWN OF
GROVE, TOWN OF
HUME, TOWN OF
INDEPENDENCE, TOWN OF
NEW HUDSON, TOWN OF
RICHBURG, VILLAGE OF
RUSHFORD, TOWN OF
SCIO, TOWN OF

Final SGEIS 2015, Page A1-1

Current FIRM Effective 
Date
04/15/1980
08/15/1983
08/01/1987 (L)
04/17/1984
08/03/1989
12/4/1979
09/05/1979
06/04/1980
01/06/1983
08/13/1982 (M)
03/18/1980
12/1/1982
04/02/1982 (M)
08/27/1982 (M)
12/1/1982
01/02/1980
08/03/1989
10/07/1983 (M)
02/15/1980
07/16/1982 (M)
10/07/1983 (M)
02/15/1980
12/18/1984
03/02/1998
04/02/1979
12/31/1982 (M)
02/01/1984
08/06/1982 (M)
12/18/1984
07/16/1982 (M)
07/30/1982 (M)
01/19/1996
07/16/1982 (M)
12/02/1983 (M)
08/20/1982 (M)
11/12/1982 (M)
07/30/1982 (M)
04/17/1978
12/18/1984
07/30/1982 (M)
10/07/1983 (M)
11/6/1991
10/2/1997
07/09/1982 (M)
08/20/1982 (M)
01/05/1978
12/23/1983 (M)
03/18/1985

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
ALLEGANY COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
BROOME COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY

Community Name
WARD,TOWN OF
WELLSVILLE, TOWN OF
WELLSVILLE, VILLAGE OF
WEST ALMOND, TOWN OF
WILLING, TOWN OF
WIRT, TOWN OF
BARKER, TOWN OF
BINGHAMTON, CITY OF
BINGHAMTON, TOWN OF
CHENANGO, TOWN OF
COLESVILLE, TOWN OF
CONKLIN, TOWN OF
DICKINSON, TOWN OF
ENDICOTT, VILLAGE OF
FENTON, TOWN OF
JOHNSON CITY, VILLAGE OF
KIRKWOOD, TOWN OF
LISLE, TOWN OF
LISLE, VILLAGE OF
MAINE, TOWN OF
NANTICOKE, TOWN OF
PORT DICKINSON, VILLAGE OF
SANFORD
SANFORD, TOWN OF
TRIANGLE, TOWN OF
UNION, TOWN OF
VESTAL, TOWN OF
WHITNEY POINT, VILLAGE OF
WINDSOR, TOWN OF
WINDSOR, VILLAGE OF
ALLEGANY, TOWN OF
ALLEGANY, VILLAGE OF
ASHFORD, TOWNSHIP OF
CARROLLTON, TOWN OF
CATTARAUGUS, VILLAGE OF
COLD SPRING, TOWN OF
CONEWANGO, TOWN OF
DAYTON, TOWN OF
DELEVAN, VILLAGE OF
EAST OTTO, TOWN OF
EAST RANDOLPH, VILLAGE OF
ELLICOTTVILLE, TOWN OF
ELLICOTTVILLE, VILLAGE OF
FARMERSVILLE, TOWN OF
FRANKLINVILLE, TOWN OF
FRANKLINVILLE, VILLAGE OF
FREEDOM, TOWN OF
GREAT VALLEY, TOWN OF
HINSDALE, TOWN OF

Final SGEIS 2015, Page A1-2

Current FIRM Effective 
Date
(NSFHA)
03/18/1985
07/17/1978
(NSFHA)
12/24/1982 (M)
06/25/1982 (M)
02/05/1992
06/01/1977
01/06/1984 (M)
08/17/1981
01/20/1993
07/17/1981
04/15/1977
09/07/1998
08/03/1981
09/30/1977
06/01/1977
08/20/2002
01/06/1984 (M)
02/05/1992
12/18/1985
05/02/1977
06/04/1980
07/20/1984 (M)
09/30/1988
03/02/1998
01/06/1984 (M)
09/30/1992
05/18/1992
11/15/1978
12/17/1991
05/25/1984
03/18/1983 (M)
04/20/1984 (M)
03/01/1978
07/30/1982 (M)
05/25/1984 (M)
01/20/1984 (M)
04/20/1984 (M)
02/01/1978
01/19/2000
05/02/1994
07/23/1982 (M)
07/17/1978
07/03/1978
08/19/1991
07/17/1978
01/17/1979

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY
CATTARAUGUS COUNTY/ERIE 
COUNTY/CHAUTAUQUA 
COUNTY/ALLEGANY COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY

HUMPHREY, TOWN OF
ISCHUA, TOWN OF
LEON, TOWN OF
LIMESTONE, VILLAGE OF
LITTLE VALLEY, TOWN OF
LITTLE VALLEY, VILLAGE OF
LYNDON, TOWN OF
MACHIAS, TOWN OF
MANSFIELD, TOWN OF
NAPOLI, TOWN OF
NEW ALBION, TOWN OF
OLEAN, CITY OF
OLEAN, TOWN OF
OTTO, TOWN OF
PERRYSBURG, TOWN OF
PERSIA, TOWN OF
PORTVILLE, TOWN OF
PORTVILLE, VILLAGE OF
RANDOLPH, TOWN OF
RANDOLPH, VILLAGE OF
SALAMANCA, CITY OF
SALAMANCA, TOWN OF
SOUTH DAYTON
DAYTON, VILLAGE OF
SOUTH VALLEY, TOWN OF
YORKSHIRE, TOWN OF

Current FIRM Effective 
Date
08/13/1982 (M)
08/15/1978
08/13/1982 (M)
04/17/1978
06/22/1984 (M)
02/01/1978
07/16/1982 (M)
08/20/1982 (M)
05/25/1984 (M)
07/02/1982 (M)
12/03/1982 (M)
05/09/1980
02/01/1979
04/20/1984 (M)
04/20/1984 (M)
04/20/1984 (M)
07/18/1983
04/17/1978
11/05/1982 (M)
08/01/1978
04/17/1978
11/1/1979
01/05/1978
12/02/1983 (M)
05/25/1984 (M)

SENECA NATION OF INDIANS

09/30/1988

AUBURN, CITY OF
AURELIUS, TOWN OF
AURORA, VILLAGE OF
BRUTUS, TOWN OF
CATO, TOWN OF
CATO, VILLAGE OF
CAYUGA, VILLAGE OF
CONQUEST, TOWN OF
FAIR HAVEN, VILLAGE OF
FLEMING, TOWN OF
GENOA,TOWN OF
IRA, TOWN OF
LEDYARD, TOWN OF
LOCKE, TOWN OF
MENTZ, TOWN OF
MERIDIAN, VILLAGE OF
MONTEZUMA, TOWN OF
MORAVIA, TOWN OF
MORAVIA, VILLAGE OF
NILES, TOWN OF

08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007

Community Name

Final SGEIS 2015, Page A1-3

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CAYUGA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY

Community Name
OWASCO, TOWN OF
PORT BYRON, VILLAGE OF
SCIPIO, TOWN OF
SEMPRONIUS, TOWN OF
SENNETT, TOWN OF
SPRINGPORT, TOWN OF
STERLING, TOWN OF
SUMMER HILL, TOWN OF
THROOP, TOWN OF
UNION SPRINGS, VILLAGE OF
VENICE, TOWN OF
VICTORY, TOWN OF
WEEDSPORT, VILLAGE OF
ARKWRIGHT, TOWN OF
BEMUS POINT, VILLAGE OF
BROCTON, VILLAGE OF
BUSTI, TOWN OF
CARROLL, TOWN OF
CASSADAGA, VILLAGE OF
CELORON, VILLAGE OF
CHARLOTTE, TOWN OF
CHAUTAUQUA, TOWN OF
CHERRY CREEK
CREEK, TOWN OF
CHERRY CREEK, VILLAGE OF
CLYMER, TOWN OF
DUNKIRK, CITY OF
DUNKIRK, TOWN OF
ELLERY, TOWN OF
ELLICOTT, TOWN OF
ELLINGTON, TOWN OF
FALCONER, VILLAGE OF
FORESTVILLE, VILLAGE OF
FREDONIA, VILLAGE OF
FRENCH CREEK, TOWN OF
GERRY, TOWN OF
HANOVER, TOWN OF
HARMONY, TOWNSHIP OF
JAMESTOWN, CITY OF
KIANTONE, TOWN OF
LAKEWOOD, VILLAGE OF
MAYVILLE, VILLAGE OF
MINA, TOWN OF
NORTH HARMONY, TOWN OF
PANAMA, VILLAGE OF
POLAND, TOWN OF
POMFRET, TOWN OF
PORTLAND, TOWN OF
RIPLEY,TOWN OF

Final SGEIS 2015, Page A1-4

Current FIRM Effective 
Date
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
08/02/2007
04/08/1983 (M)
11/2/1977
(NSFHA)
01/20/1993
10/29/1982 (M)
12/1/1977
03/18/1980
03/23/1984 (M)
06/15/1984
07/02/1982 (M)
02/15/1978
10/07/1983 (M)
02/04/1981
08/06/1982 (M)
03/18/1980
08/01/1984
10/07/1983(M)
01/05/1978
03/18/1983(M)
11/15/1989
06/08/1984 (M)
01/06/1984 (M)
12/18/1984
12/01/1986 (L)
06/01/1978
02/02/1996
11/2/1977
01/05/1978
01/02/2003
02/15/1980
03/01/1978
03/11/1983 (M)
12/18/1984
10/07/1983 (M)
(NSFHA)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHAUTAUQUA COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHEMUNG COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY

Community Name
SHERIDAN, TOWN OF
SHERMAN, VILLAGE OF
SHERMAN,TOWN OF
SILVER CREEK, VILLAGE OF
SINCLAIRVILLE, VILLAGE OF
STOCKTON, TOWN OF
VILLENOVA, TOWN OF
WESTFIELD, TOWN OF
WESTFIELD, VILLAGE OF
ASHLAND, TOWN OF
BALDWIN, TOWN OF
BIG FLATS, TOWN OF
CATLIN, TOWN OF
CHEMUNG, TOWN OF
ELMIRA HEIGHTS, VILLAGE OF
ELMIRA, CITY OF
ELMIRA, TOWN OF
ERIN, TOWN OF
HORSEHEADS, TOWN OF
HORSEHEADS, VILLAGE OF
MILLPORT, VILLAGE OF
SOUTHPORT, TOWN OF
VAN ETTEN
ETTEN, TOWN OF
VAN ETTEN, VILLAGE OF
VETERAN, TOWN OF
WELLSBURG, VILLAGE OF
AFTON, TOWN OF
AFTON, VILLAGE OF
BAINBRIDGE, TOWN OF
BAINBRIDGE, VILLAGE OF
COLUMBUS, TOWN OF
COVENTRY, TOWN OF
EARLVILLE, VILLAGE OF
GERMAN, TOWN OF
GREENE, TOWN OF
GREENE, VILLAGE OF
GUILFORD, TOWN OF
LINCKLAEN, TOWN OF
MC DONOUGH, TOWN OF
NEW BERLIN, TOWN OF
NEW BERLIN, VILLAGE OF
NORTH NORWICH, TOWN OF
NORWICH, CITY OF
NORWICH, TOWN OF
OTSELIC, TOWN OF
OXFORD, TOWN OF
OXFORD, VILLAGE OF
PHARSALIA, TOWN OF

Final SGEIS 2015, Page A1-5

Current FIRM Effective 
Date
10/07/1983 (M)
03/01/1978
01/06/1984 (M)
08/01/1983
12/1/1977
10/21/1983 (M)
05/21/1982 (M)
06/08/1984 (M)
10/07/1983 (M)
01/16/1980
07/23/1982 (M)
08/18/1992
06/22/1984 (M)
09/03/1980
09/29/1996
04/02/1997
09/29/1996
08/13/1982 (M)
09/29/1996
09/29/1996
06/15/1988 (M)
08/05/1991
09/28/1979 (M)
07/01/1988 (L)
02/18/1983 (M)
06/15/1981
11/26/2010
11/26/2010
11/26/2010
11/26/2010
11/26/2010 (M)
11/26/2010 (M)
11/26/2010 (M)
11/26/2010 (M)
11/26/2010
11/26/2010
11/26/2010
11/26/2010 (M)
11/26/2010 (M)
11/26/2010
11/26/2010
11/26/2010
11/26/2010
11/26/2010
11/26/2010 (M)
11/26/2010
11/26/2010
11/26/2010 (M)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CHENANGO COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
CLINTON COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
COLUMBIA COUNTY
CORTLAND COUNTY
CORTLAND COUNTY

Community Name
PITCHER, TOWN OF
PLYMOUTH, TOWN OF
PRESTON, TOWN OF
SHERBURNE, TOWN OF
SHERBURNE, VILLAGE OF
SMITHVILLE, TOWN OF
SMYRNA, TOWN OF
SMYRNA, VILLAGE OF
ALTONA, TOWN OF
AUSABLE, TOWN OF
BEEKMANTOWN, TOWN OF
BLACK BROOK, TOWN OF
CHAMPLAIN, TOWN OF
CHAMPLAIN, VILLAGE OF
CHAZY, TOWN OF
CLINTON, TOWN OF
ELLENBURG, TOWN OF
MOOERS, TOWN OF
PERU,TOWN OF
PLATTSBURGH, CITY OF
PLATTSBURGH, TOWN OF
ROUSES POINT, VILLAGE OF
SARANAC
SARANAC, TOWN OF
SCHUYLER FALLS, TOWN OF
ANCRAM, TOWN OF
AUSTERLITZ, TOWN OF
CANAAN, TOWN OF
CHATHAM, TOWN OF
CHATHAM, VILLAGE OF
CLAVERACK, TOWN OF
CLERMONT, TOWNSHIP OF
COPAKE, TOWN OF
GALLATIN, TOWN OF
GERMANTOWN, TOWN OF
GHENT, TOWN OF
GREENPORT, TOWN OF
HILLSDALE, TOWN OF
HUDSON, CITY OF
KINDERHOOK, TOWN OF
KINDERHOOK, VILLAGE OF
LIVINGSTON, TOWN OF
NEW LEBANON, TOWN OF
STOCKPORT, TOWN OF
STUYVESANT, TOWN OF
TAGHKANIC, TOWN OF
VALATIE, VILLAGE OF
CINCINNATUS, TOWN OF
CORTLAND, CITY OF

Final SGEIS 2015, Page A1-6

Current FIRM Effective 
Date
11/26/2010 (M)
11/26/2010 (M)
11/26/2010
11/26/2010
11/26/2010
11/26/2010 (M)
11/26/2010
11/26/2010 (M)
09/28/2007 (M)
09/28/2007 (M)
09/28/2007
09/28/2007
09/28/2007
09/28/2007
09/28/2007
09/28/2007 (M)
09/28/2007 (M)
09/28/2007 (M)
09/28/2007
09/28/2007
09/28/2007
09/28/2007
09/28/2007
09/28/2007
06/05/1985 (M)
06/05/1985 (M)
07/03/1985 (M)
09/15/1993
12/15/1982
09/06/1989
09/05/1984
06/19/1985 (M)
10/16/1984
05/11/1979 (M)
01/01/1988 (L)
11/15/1989
05/15/1985 (M)
09/29/1989
12/1/1982
12/1/1982
05/11/1979 (M)
06/05/1985 (M)
01/19/1983
09/14/1979 (M)
01/03/1986 (M)
12/1/1982
03/02/2010
03/02/2010

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County

Community Name

CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
CORTLAND COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY
DELAWARE COUNTY/BROOME COUNTY
DUTCHESS COUNTY

CORTLANDVILLE, TOWN OF
CUYLER, TOWN OF
FREETOWN, TOWN OF
HARFORD, TOWN OF
HOMER, TOWN OF
HOMER, VILLAGE OF
LAPEER, TOWN OF
MARATHON, TOWN OF
MARATHON, VILLAGE OF
MCGRAW, VILLAGE OF
PREBLE, TOWN OF
SCOTT, TOWN OF
SOLON, TOWN OF
TAYLOR, TOWN OF
TRUXTON, TOWN OF
VIRGIL, TOWN OF
WILLET, TOWN OF
ANDES, TOWN OF
ANDES, VILLAGE OF
BOVINA, TOWN OF
COLCHESTER,TOWN OF
DAVENPORT, TOWN OF
DELHI  TOWN OF
DELHI,
DELHI, VILLAGE OF
DEPOSIT, TOWN OF
FLEISCHMANNS, VILLAGE OF
FRANKLIN, TOWN OF
FRANKLIN, VILLAGE OF
HAMDEN,TOWN OF
HANCOCK, TOWN OF
HANCOCK, VILLAGE OF
HARPERSFIELD, TOWN OF
HOBART, VILLAGE OF
KORTRIGHT, TOWN OF
MARGARETVILLE, VILLAGE OF
MASONVILLE, TOWN OF
MEREDITH, TOWN OF
MIDDLETOWN, TOWN OF
ROXBURY, TOWN OF
SIDNEY, TOWN OF
SIDNEY, VILLAGE OF
STAMFORD, TOWN OF
STAMFORD, VILLAGE OF
TOMPKINS, TOWN OF
WALTON, TOWN OF
WALTON, VILLAGE OF
DEPOSIT, VILLAGE OF
AMENIA, TOWN OF

Final SGEIS 2015, Page A1-7

Current FIRM Effective 
Date
03/02/2010
03/02/2010 (M)
03/02/2010 (M)
03/02/2010 (M)
03/02/2010
03/02/2010
03/02/2010 (M)
03/02/2010
03/02/2010
03/02/2010
03/02/2010
03/02/2010
03/02/2010
03/02/2010 (M)
03/02/2010 (M)
03/02/2010
03/02/2010 (M)
05/01/1985 (M)
04/01/1986 (L)
05/01/1985 (M)
02/04/1987
02/02/2002
07/18/1985
07/18/1985
03/18/1986 (M)
01/17/1986 (M)
04/01/1988 (L)
08/01/1987 (L)
03/04/1986 (M)
09/28/1990
09/28/1990
06/05/1985 (M)
05/15/1985 (M)
05/15/1985 (M)
06/04/1990
11/01/1985 (M)
05/15/1985 (M)
08/02/1993
05/15/1985 (M)
09/30/1987
09/30/1987
10/01/1986 (L)
08/01/1987 (L)
11/15/1985 (M)
09/02/1988
04/02/1991
02/01/1979
11/15/1989

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
DUTCHESS COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY

Community Name
BEACON, CITY OF
BEEKMAN, TOWN OF
CLINTON, TOWN OF
DOVER, TOWN OF
EAST FISHKILL, TOWN OF
FISHKILL, TOWN OF
FISHKILL, VILLAGE OF
HYDE PARK, TOWN OF
LAGRANGE, TOWN OF
MILAN, TOWN OF
MILLBROOK, VILLAGE OF
MILLERTON, VILLAGE OF
NORTH EAST, TOWN OF
PAWLING, TOWN OF
PAWLING, VILLAGE OF
PINE PLAINS, TOWN OF
PLEASANT VALLEY, TOWN OF
POUGHKEEPSIE, CITY OF
POUGHKEEPSIE, TOWN OF
RED HOOK, TOWN OF
RED HOOK, VILLAGE OF
RHINEBECK, TOWN OF
RHINEBECK
RHINEBECK, VILLAGE OF
STANFORD, TOWN OF
TIVOLI, VILLAGE OF
UNION VALE, TOWN OF
WAPPINGER, TOWN OF
WAPPINGERS FALLS, VILLAGE OF
WASHINGTON, TOWN OF
AKRON, VILLAGE OF
ALDEN, TOWN OF
ALDEN, VILLAGE OF
AMHERST, TOWN OF
ANGOLA, VILLAGE OF
AURORA, TOWN OF
BLASDELL, VILLAGE OF
BOSTON, TOWN OF
BRANT, TOWN OF
BUFFALO, CITY OF
CHEEKTOWAGA, TOWN OF
CLARENCE, TOWN OF
COLDEN, TOWN OF
COLLINS,TOWN OF
CONCORD, TOWN OF
DEPEW, VILLAGE OF
EAST AURORA, VILLAGE OF
EDEN, TOWN OF
ELMA,TOWN OF

Final SGEIS 2015, Page A1-8

Current FIRM Effective 
Date
03/01/1984
09/05/1984
07/05/1984
07/04/1988
06/15/1984
06/01/1984
03/15/1984
06/15/1984
09/08/1999
08/10/1979 (M)
02/27/1984 (M)
01/03/1985
09/05/1984
01/03/1985
08/01/1984
10/05/1984 (M)
01/16/1980
01/05/1984
09/08/1999
10/16/1984
(NSFHA)
09/05/1984
02/01/1985
12/17/1991
08/01/1984
09/02/1988
09/22/1999
09/22/1999
08/17/1979 (M)
11/19/1980
02/06/1991
01/06/1984 (M)
10/16/1992
08/06/2002
04/16/1979
06/25/1976 (M)
09/30/1981
01/06/1984 (M)
09/26/2008
03/15/1984
03/05/1996
07/02/1979
09/26/2008
09/04/1986
08/03/1981
08/06/2002
08/24/1979 (M)
06/22/1998

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County

Community Name

ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY
ERIE COUNTY/CATTARAUGUS COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
ESSEX COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY

EVANS, TOWN OF
FARNHAM, VILLAGE OF
GRAND ISLAND, TOWN OF
HAMBURG, TOWN OF
HAMBURG, VILLAGE OF
HOLLAND, TOWN OF
KENMORE,VILLAGE OF
LACKAWANNA, CITY OF
LANCASTER, TOWN OF
LANCASTER, VILLAGE OF
MARILLA, TOWN OF
NEWSTEAD, TOWN OF
ORCHARD PARK, TOWN OF
ORCHARD PARK, VILLAGE OF
SARDINIA, TOWN OF
SLOAN, VILLAGE OF
SPRINGVILLE, VILLAGE OF
TONAWANDA, CITY OF
TONAWANDA, TOWN OF
WALES, TOWN OF
WEST SENECA, TOWN OF
WILLIAMSVILLE, VILLAGE OF
GOWANDA
GOWANDA, VILLAGE OF
CHESTERFIELD, TOWN OF
CROWN POINT,TOWN OF
ELIZABETHTOWN, TOWN OF
ESSEX, TOWN OF
JAY, TOWN OF
KEENE, TOWN OF
KEESEVILLE, VILLAGE OF
LAKE PLACID, VILLAGE OF
LEWIS, TOWN OF
MINERVA, TOWN OF
MORIAH, TOWN OF
NEWCOMB, TOWN OF
NORTH ELBA, TOWN OF
NORTH HUDSON, TOWN OF
PORT HENRY, VILLAGE OF
SCHROON, TOWN OF
ST. ARMAND, TOWN OF
TICONDEROGA, TOWN OF
WESTPORT, TOWN OF
WILLSBORO, TOWN OF
WILMINGTON, TOWN OF
BANGOR, TOWN OF
BELLMONT, TOWN OF
BOMBAY, TOWN OF
BRANDON, TOWN OF

Final SGEIS 2015, Page A1-9

Current FIRM Effective 
Date
02/02/2002
(NSFHA)
09/26/2008
12/20/2001
01/20/1982
09/26/2008
(NSFHA)
07/02/1980
02/23/2001
07/02/1979
09/29/1978
05/04/1992
03/16/1983
(NSFHA)
01/16/2003
(NSFHA)
07/17/1986
09/26/2008
11/12/1982
09/26/2008
09/30/1992
09/26/2008
09/26/2008
05/04/1987
07/16/1987
01/20/1993
04/03/1987
06/17/2002
06/05/1985 (M)
09/28/2007 (M)
(NSFHA)
05/15/1985 (M)
10/05/1984 (M)
09/24/1984 (M)
06/05/1985 (M)
08/23/2001
05/15/1985 (M)
07/16/1987
11/16/1995
02/05/1986
09/06/1996
09/04/1987
05/18/1992
11/16/1995
(NSFHA)
08/05/1985 (M)
02/15/1985 (M)
(NSFHA)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FRANKLIN COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
FULTON COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY

Community Name
BRIGHTON, TOWN OF
BRUSHTON, VILLAGE OF
BURKE, TOWN OF
BURKE, VILLAGE OF
CHATEAUGAY, VILLAGE OF
CONSTABLE, TOWN OF
DICKINSON, TOWN OF
DUANE, TOWN OF
FORT COVINGTON, TOWN OF
FRANKLIN, TOWN OF
HARRIETSTOWN, TOWN OF
MALONE, TOWN OF
MALONE, VILLAGE OF
MOIRA, TOWN OF
SANTA CLARA, TOWN OF
SARANAC LAKE, VILLAGE OF
TUPPER LAKE, TOWN OF
TUPPER LAKE,VILLAGE OF
WAVERLY, TOWN OF
WESTVILLE, TOWN OF
BLEECKER,TOWN OF
BROADALBIN, TOWN OF
BROADALBIN
BROADALBIN, VILLAGE OF
CAROGA, TOWN OF
EPHRATAH, TOWN OF
GLOVERSVILLE, CITY OF
JOHNSTOWN, CITY OF
JOHNSTOWN, TOWN OF
MAYFIELD, TOWN OF
NORTHAMPTON, TOWN OF
NORTHVILLE, VILLAGE OF
OPPENHEIM, TOWN OF
PERTH, TOWN OF
STRATFORD, TOWN OF
ALABAMA, TOWN OF
ALEXANDER, VILLAGE OF
ALEXANDER,TOWN OF
BATAVIA, CITY OF
BATAVIA, TOWN OF
BERGEN, TOWN OF
BERGEN, VILLAGE OF
BETHANY, TOWN OF
BYRON, TOWN OF
CORFU, VILLAGE OF
DARIEN, TOWN OF
ELBA, TOWN OF
ELBA, VILLAGE OF
LE ROY, TOWN OF

Final SGEIS 2015, Page A1-10

Current FIRM Effective 
Date
(NSFHA)
02/19/1986 (M)
02/19/1986 (M)
(NSFHA)
(NSFHA)
(NSFHA)
03/18/1986 (M)
(NSFHA)
12/23/1983 (M)
09/24/1984 (M)
01/03/1985
09/04/1985 (M)
04/03/1978
04/15/1986 (M)
(NSFHA)
01/02/1992
(NSFHA)
03/01/1987 (L)
(NSFHA)
02/15/1985 (M)
07/18/1985 (M)
01/03/1985 (M)
04/15/1986 (M)
07/18/1985 (M)
07/03/1985 (M)
09/30/1983
07/18/1983
07/03/1985 (M)
08/05/1985 (M)
08/19/1985 (M)
(NSFHA)
06/18/1976
02/15/1985 (M)
01/03/1985 (M)
11/18/1983 (M)
05/04/1987
05/04/1987
09/16/1982
01/17/1985
07/06/1984 (M)
06/08/1979 (M)
09/24/1984 (M)
02/01/1988 (L)
10/15/1985 (M)
07/06/1984 (M)
10/05/1984 (M)
01/20/1984 (M)
09/14/1979 (M)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County

Community Name

GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY
GENESEE COUNTY/WYOMING COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
GREENE COUNTY
HAMILTON COUNTY
HAMILTON COUNTY
HAMILTON COUNTY
HAMILTON COUNTY
HAMILTON COUNTY
HAMILTON COUNTY
HAMILTON COUNTY
HAMILTON COUNTY
HAMILTON COUNTY
HAMILTON COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY

LE ROY, VILLAGE OF
OAKFIELD, TOWN OF
OAKFIELD, VILLAGE OF
PAVILION, TOWN OF
PEMBROKE, TOWN OF
STAFFORD,TOWN OF
ATTICA, VILLAGE OF
ASHLAND, TOWN OF
ATHENS, TOWN OF
ATHENS, VILLAGE OF
CAIRO, TOWN OF
CATSKILL, TOWN OF
CATSKILL, VILLAGE OF
COXSACKIE, TOWN OF
COXSACKIE, VILLAGE OF
DURHAM, TOWN OF
GREENVILLE, TOWN OF
HALCOTT, TOWN OF
HUNTER, TOWN OF
HUNTER, VILLAGE OF
JEWETT, TOWN OF
LEXINGTON, TOWN OF
NEW BALTIMORE,
BALTIMORE  TOWN OF
PRATTSVILLE, TOWN OF
TANNERSVILLE, VILLAGE OF
WINDHAM, TOWN OF
ARIETTA, TOWN OF
BENSON, TOWN OF
HOPE, TOWN OF
INDIAN LAKE, TOWN OF
INLET, TOWN OF
LAKE PLEASANT, TOWN OF
LONG LAKE, TOWN OF
MOREHOUSE, TOWN OF
SPECULATOR, VILLAGE OF
WELLS, TOWN OF
COLD BROOK, VILLAGE OF
COLUMBIA, TOWN OF
DANUBE, TOWN OF
DOLGEVILLE, VILLAGE OF
FAIRFIELD, TOWN OF
FRANKFORT, TOWN OF
FRANKFORT, VILLAGE OF
GERMAN FLATTS, TOWN OF
HERKIMER, TOWN OF
HERKIMER, VILLAGE OF
ILION, VILLAGE OF
LITCHFIELD, TOWN OF

Final SGEIS 2015, Page A1-11

Current FIRM Effective 
Date
08/03/1981
05/25/1984 (M)
03/23/1984 (M)
02/27/1984 (M)
01/20/1984 (M)
07/16/1982
07/03/1986
05/16/2008
05/16/2008
05/16/2008
05/16/2008
05/16/2008
05/16/2008
05/16/2008
05/16/2008
05/16/2008 (M)
05/16/2008 (M)
05/16/2008 (M)
05/16/2008
05/16/2008
05/16/2008
05/16/2008
05/16/2008 (M)
05/16/2008
05/16/2008
05/16/2008
(NSFHA)
(NSFHA)
04/30/86(M)
12/04/85(M)
(NSFHA)
(NSFHA)
09/24/1984 (M)
(NSFHA)
02/06/1984 (M)
06/03/1986 (M)
12/20/2000
07/16/1982 (M)
05/12/1999 (M)
03/16/1983
10/18/1988
12/20/2000
03/07/2001
05/15/1985 (M)
04/17/1985 (M)
06/17/2002
09/08/1999
05/07/2001

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
HERKIMER COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY

Community Name
LITTLE FALLS, CITY OF
LITTLE FALLS, TOWN OF
MANHEIM, TOWN OF
MIDDLEVILLE, VILLAGE OF
MOHAWK, VILLAGE OF
NEWPORT, TOWN OF
NEWPORT, VILLAGE OF
NORWAY, TOWN OF
OHIO, TOWN OF
POLAND, VILLAGE OF
RUSSIA, TOWN OF
SALISBURY, TOWN OF
SCHUYLER, TOWN OF
STARK, TOWN OF
WARREN, TOWN OF
WEBB, TOWN OF
WEST WINFIELD, VILLAGE OF
WINFIELD, TOWN OF
ADAMS, TOWN OF
ADAMS, VILLAGE OF
ALEXANDRIA BAY, VILLAGE OF
ALEXANDRIA, TOWN OF
ANTWERP
ANTWERP, TOWN OF
ANTWERP, VILLAGE OF
BLACK RIVER, VILLAGE OF
BROWNVILLE, TOWN OF
BROWNVILLE, VILLAGE OF
CAPE VINCENT, TOWN OF
CAPE VINCENT, VILLAGE OF
CARTHAGE, VILLAGE OF
CHAMPION, TOWN OF
CHAUMONT, VILLAGE OF
CLAYTON, TOWN OF
CLAYTON, VILLAGE OF
DEFERIET, VILLAGE OF
DEXTER, VILLAGE OF
ELLISBURG, TOWN OF
ELLISBURG, VILLAGE OF
EVANS MILLS, VILLAGE OF
GLEN PARK, VILLAGE OF
HENDERSON, TOWN OF
HERRINGS, VILLAGE OF
HOUNSFIELD, TOWN OF
LERAY, TOWN OF
LYME, TOWN OF
ORLEANS, TOWN OF
PAMELIA, TOWN OF
PHILADELPHIA, TOWN OF

Final SGEIS 2015, Page A1-12

Current FIRM Effective 
Date
04/04/1983
03/28/1980 (M)
05/01/1985 (M)
07/03/1985 (M)
09/08/1999
06/02/1999
04/02/1991
07/03/1985 (M)
09/24/1984 (M)
06/02/1999 (M)
06/02/1999
07/03/1985 (M)
06/20/2001
05/15/1985 (M)
(NSFHA)
07/30/1982 (M)
07/30/1982 (M)
07/30/1982 (M)
06/05/1985 (M)
06/19/1985 (M)
04/03/1978
10/15/1985 (M)
04/15/1986 (M)
(NSFHA)
06/05/1989 (M)
06/02/1992
03/18/1986 (M)
06/02/1992
04/17/1985 (M)
06/17/1991
06/02/1993
09/08/1999
04/02/1986
12/1/1977
(NSFHA)
06/15/1994
05/18/1992
06/19/1985 (M)
01/02/1992
(NSFHA)
05/18/1992
12/18/1985
05/18/1992
02/02/1902
09/02/1993
03/01/1978
01/02/1992
06/05/89(M)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
JEFFERSON COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LEWIS COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY

Community Name
PHILADELPHIA, VILLAGE OF
RODMAN, TOWN OF
RUTLAND, TOWN OF
SACKETS HARBOR, VILLAGE OF
THERESA, TOWN OF
THERESA, VILLAGE OF
WATERTOWN, CITY OF
WATERTOWN, TOWN OF
WEST CARTHAGE, VILLAGE OF
WILNA, TOWN OF
WORTH, TOWN OF
CASTORLAND, VILLAGE OF
CONSTABLEVILLE, VILLAGE OF
COPENHAGEN, VILLAGE OF
CROGHAM, VILLAGE OF
CROGHAN, TOWN OF
DENMARK, TOWN OF
DIANA, TOWN OF
GREIG, TOWN OF
HARRISBURG, TOWN OF
HARRISVILLE, VILLAGE OF
LEWIS, TOWN OF
LEYDEN
LEYDEN, TOWN OF
LOWVILLE, TOWN OF
LOWVILLE, VILLAGE OF
LYONS FALLS, VILLAGE OF
LYONSDALE, TOWN OF
MARTINSBURG, TOWN OF
NEW BREMEN, TOWN OF
OSCEOLA, TOWN OF
PINCKNEY, TOWN OF
PORT LEYDEN, VILLAGE OF
TURIN, TOWN OF
TURIN, VILLAGE OF
WATSON, TOWN OF
WEST TURIN, TOWN OF
AVON, TOWN OF
AVON, VILLAGE OF
CALEDONIA, TOWN OF
CALEDONIA, VILLAGE OF
CONESUS, TOWN OF
DANSVILLE, VILLAGE OF
GENESEO, TOWN OF
GENESEO, VILLAGE OF
GROVELAND, TOWN OF
LEICESTER, TOWN OF
LEICESTER, VILLAGE OF
LIMA, TOWN OF

Final SGEIS 2015, Page A1-13

Current FIRM Effective 
Date
09/15/1993
07/03/1985 (M)
08/18/1992
05/02/1994
10/15/1985 (M)
10/15/1985 (M)
08/02/1993
08/02/1993
09/28/1990
01/16/1992
(NSFHA)
(NSFHA)
07/16/1982 (M)
(NSFHA)
05/15/1985 (M)
05/15/1985 (M)
05/15/1985 (M)
09/24/1984 (M)
05/15/1985 (M)
(NSFHA)
09/24/1984 (M)
09/29/1996
06/19/1985 (M)
06/20/2000
06/20/2000
06/19/1985 (M)
06/19/1985 (M)
06/19/1985 (M)
05/04/2000
06/30/1976 (M)
(NSFHA)
06/19/1985 (M)
08/02/1994
07/01/1977 (M)
07/19/2000
(NSFHA)
08/15/1978
08/01/1978
06/01/1981
06/01/1981
02/15/1991
04/05/2010
09/29/1996
09/29/1996
02/15/1991
01/20/1982
08/27/1982 (M)
12/23/1983 (M)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
LIVINGSTON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MADISON COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY

Community Name
LIMA, VILLAGE OF
LIVONIA, TOWN OF
LIVONIA, VILLAGE OF
MOUNT MORRIS, TOWN OF
MOUNT MORRIS, VILLAGE OF
NORTH DANSVILLE, TOWN OF
NUNDA, TOWN OF
NUNDA, VILLAGE OF
OSSIAN, TOWN OF
PORTAGE,TOWN OF
SPARTA, TOWN OF
SPRINGWATER, TOWN OF
WEST SPARTA, TOWN OF
YORK, TOWN OF
BROOKFIELD, TOWN OF
CANASTOTA , VILLAGE OF
CAZENOVIA, TOWN OF
CAZENOVIA, VILLAGE OF
CHITTENANGO, VILLAGE OF
DE RUYTER, TOWN OF
DE RUYTER, VILLAGE OF
EATON, TOWN OF
FENNER
FENNER, TOWNSHIP  OF
GEORGETOWN, TOWN OF
HAMILTON, TOWN OF
HAMILTON,VILLAGE
LEBANON, TOWN OF
LENOX, TOWN OF
LINCOLN, TOWN OF
MADISON, TOWN OF
MORRISVILLE, VILLAGE OF
MUNNSVILLE, VILLAGE OF
NELSON, TOWN OF
ONEIDA, CITY OF
SMITHFIELD, TOWN OF
STOCKBRIDGE, TOWN OF
SULLIVAN, TOWN OF
WAMPSVILLE, VILLAGE OF
BRIGHTON, TOWN OF
BROCKPORT, VILLAGE OF
CHILI, TOWN OF
CHURCHVILLE, VILLAGE OF
CLARKSON, TOWN OF
EAST ROCHESTER, VILLAGE OF
FAIRPORT, VILLAGE OF
GATES, TOWN OF
GREECE, TOWN OF
HAMLIN, TOWN OF

Final SGEIS 2015, Page A1-14

Current FIRM Effective 
Date
07/23/1982 (M)
02/19/1992
06/01/1988 (L)
(NSFHA)
08/01/1978
04/05/2010
07/03/1985 (M)
03/23/1984 (M)
06/08/1984 (M)
12/18/1984
04/05/2010
08/24/1984 (M)
04/05/2010
01/20/1982
04/17/1985 (M)
04/15/1988
06/19/1985
06/19/1985
02/01/1985 (M)
06/08/1984
08/24/1984 (M)
09/10/1984 (M)
02/05/1986
11/02/1984 (M)
09/27/2002
09/27/2002
04/17/1985 (M)
06/03/1988
09/04/1985 (M)
01/19/1983
04/15/1982
09/15/1983
10/05/1984 (M)
02/23/2001
04/17/1985 (M)
(NSFHA)
05/15/1986
(NSFHA)
08/28/2008
08/28/2008 (M)
08/28/2008
08/28/2008
08/28/2008
08/28/2008 (M)
08/28/2008
08/28/2008
08/28/2008
08/28/2008

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONROE COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
MONTGOMERY COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY

Community Name
HENRIETTA, TOWN OF
HILTON, VILLAGE OF
HONEOYE FALLS, VILLAGE OF
IRONDEQUOIT, TOWN OF
MENDON, TOWN OF
OGDEN, TOWN OF
PARMA, TOWN OF
PENFIELD, TOWN OF
PERINTON, TOWN OF
PITTSFORD, TOWN OF
PITTSFORD, VILLAGE OF
RIGA, TOWN OF
ROCHESTER, CITY OF
RUSH, TOWN OF
SCOTTSVILLE, VILLAGE OF
SPENCERPORT, VILLAGE OF
SWEDEN, TOWN OF
WEBSTER, TOWN OF
WEBSTER, VILLAGE OF
WHEATLAND, TOWN OF
AMES, VILLAGE OF
AMSTERDAM, CITY OF
AMSTERDAM
AMSTERDAM, TOWN OF
CANAJOHARIE, TOWN OF
CANAJOHARIE, VILLAGE OF
CHARLESTON, TOWN OF
FLORIDA, TOWN OF
FONDA, VILLAGE OF
FORT JOHNSON, VILLAGE OF
FORT PLAIN, VILLAGE OF
FULTONVILLE, VILLAGE OF
GLEN, TOWN OF
HAGAMAN, VILLAGE OF
MINDEN, TOWN OF
MOHAWK, TOWN OF
NELLISTON, VILLAGE OF
PALATINE BRIDGE, VILLAGE OF
PALATINE, TOWN OF
ROOT, TOWN OF
ST. JOHNSVILLE, TOWN OF
ST. JOHNSVILLE, VILLAGE OF
ATLANTIC BEACH, VILLAGE OF
BAXTER ESTATES, VILLAGE OF
BAYVILLE, VILLAGE OF
CEDARHURST, VILLAGE OF
CENTRE ISLAND, VILLAGE OF
COVE NECK, VILLAGE OF
EAST HILLS, VILLAGE OF

Final SGEIS 2015, Page A1-15

Current FIRM Effective 
Date
08/28/2008
08/28/2008
08/28/2008
08/28/2008
08/28/2008
08/28/2008
08/28/2008
08/28/2008
08/28/2008
08/28/2008
08/28/2008 (M)
08/28/2008
08/28/2008
08/28/2008
08/28/2008
08/28/2008
08/28/2008 (M)
08/28/2008
08/28/2008
08/28/2008
12/4/1985
06/19/1985
12/01/1987 (L)
01/06/1983
11/3/1982
10/15/1985 (M)
12/01/1987 (L)
07/06/1983
01/19/1983
06/17/2002
10/15/1982
02/19/1986 (M)
03/18/1986 (M)
01/19/1983
08/05/1985 (M)
11/3/1982
11/17/1982
05/04/1987
04/01/1988 (L)
03/16/1983
09/29/1989
09/11/2009
09/11/2009
09/11/2009
09/11/2009
09/11/2009
09/11/2009
(NSFHA)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY

Current FIRM Effective 
Date
EAST ROCKAWAY, VILLAGE OF
09/11/2009
EAST WILLISTON, VILLAGE OF
(NSFHA)
FLORAL PARK, VILLAGE OF
(NSFHA)
FLOWER HILL, VILLAGE OF
09/11/2009
FREEPORT, VILLAGE OF
09/11/2009
GARDEN CITY, VILLAGE OF
(NSFHA)
GLEN COVE, CITY OF
09/11/2009
GREAT NECK ESTATES, VILLAGE OF
09/11/2009
GREAT NECK PLAZA, VILLAGE OF
09/11/2009
GREAT NECK, VILLAGE OF
09/11/2009
HEMPSTEAD, TOWN OF
09/11/2009
(NSFHA)
HEMPSTEAD, VILLAGE OF
HEWLETT BAY PARK, VILLAGE OF
09/11/2009
HEWLETT HARBOR, VILLAGE OF
09/11/2009
HEWLETT NECK, VILLAGE OF
09/11/2009
ISLAND PARK, VILLAGE OF
09/11/2009
KENSINGTON, VILLAGE OF
09/11/2009
KINGS POINT, VILLAGE OF
09/11/2009
LAKE SUCCESS, VILLAGE OF
(NSFHA)
LATTINGTOWN, VILLAGE OF
09/11/2009
LAUREL HOLLOW, VILLAGE OF
09/11/2009
LAWRENCE, VILLAGE OF
09/11/2009
LONG BEACH
BEACH, CITY OF
09/11/2009
LYNBROOK, VILLAGE OF
09/11/2009
MALVERNE, VILLAGE OF
09/11/2009
MANORHAVEN, VILLAGE OF
09/11/2009
MASSAPEQUA PARK, VILLAGE OF
09/11/2009
MILL NECK, VILLAGE OF
09/11/2009
MINEOLA, VILLAGE OF
(NSFHA)
MUNSEY PARK, VILLAGE OF
(NSFHA)
NEW HYDE PARK, VILLAGE OF
(NSFHA)
NORTH HEMPSTEAD, TOWN OF
09/11/2009
NORTH HILLS, VILLAGE OF
(NSFHA)
09/11/2009
OYSTER BAY COVE, VILLAGE OF
OYSTER BAY, TOWN OF
09/11/2009
PLANDOME HEIGHTS, VILLAGE OF
09/11/2009
PLANDOME MANOR, VILLAGE OF
09/11/2009
PLANDOME, VILLAGE OF
09/11/2009
09/11/2009
PORT WASHINGTON NORTH, VILLAG
ROCKVILLE CENTRE, VILLAGE OF
09/11/2009
ROSLYN ESTATES, VILLAGE OF
(NSFHA)
ROSLYN HARBOR, VILLAGE OF
09/11/2009
ROSLYN, VILLAGE OF
09/11/2009
RUSSELL GARDENS, VILLAGE OF
09/11/2009
SADDLE ROCK, VILLAGE OF
09/11/2009
SANDS POINT, VILLAGE OF
09/11/2009
SEA CLIFF, VILLAGE OF
09/11/2009
STEWART MANOR, VILLAGE OF
(NSFHA)
Community Name

Final SGEIS 2015, Page A1-16

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NASSAU COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
NIAGARA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY

Community Name
THOMASTON, VILLAGE OF
VALLEY STREAM, VILLAGE OF
WESTBURY, VILLAGE OF
WOODSBURGH, VILLAGE OF
BARKER, VILLAGE OF
CAMBRIA, TOWN OF
HARTLAND, TOWN OF
LEWISTON, TOWN OF
LEWISTON, VILLAGE OF
LOCKPORT, CITY OF
LOCKPORT, TOWN OF
MIDDLEPORT, VILLAGE OF
NEWFANE, TOWN OF
NIAGARA FALLS, CITY OF
NIAGARA, TOWN OF
NORTH TONAWANDA, CITY OF
PENDLETON, TOWN OF
PORTER, TOWN OF
ROYALTON, TOWN OF
SOMERSET, TOWN OF
WHEATFIELD, TOWN OF
WILSON, TOWN OF
WILSON
WILSON, VILLAGE OF
YOUNGSTOWN, VILLAGE OF
ANNSVILLE, TOWN OF
AUGUSTA, TOWN OF
AVA, TOWN OF
BARNEVELD, VILLAGE OF
BOONVILLE, TOWN OF
BOONVILLE, VILLAGE OF
BRIDGEWATER, TOWN OF
BRIDGEWATER, VILLAGE OF
CAMDEN, TOWN OF
CAMDEN, VILLAGE OF
CLAYVILLE, VILLAGE OF
CLINTON, VILLAGE OF
DEERFIELD, TOWN OF
FLORENCE, TOWN OF
FLOYD, TOWN OF
FORESTPORT, TOWN OF
HOLLAND PATENT, VILLAGE OF
KIRKLAND, TOWN OF
LEE, TOWN OF
MARCY, TOWN OF
MARSHALL, TOWN OF
NEW HARTFORD, TOWN OF
NEW HARTFORD, VILLAGE OF
NEW YORK MILLS, VILLAGE OF

Final SGEIS 2015, Page A1-17

Current FIRM Effective 
Date
09/11/2009
09/11/2009
(NSFHA)
09/11/2009
09/17/2010
09/17/2010
09/17/2010 (M)
09/17/2010
(NSFHA)
09/17/2010
09/17/2010
09/17/2010
09/17/2010
09/17/2010
09/17/2010
09/17/2010
09/17/2010
09/17/2010
09/17/2010
09/17/2010
09/17/2010
09/17/2010
09/17/2010
09/17/2010
04/05/1988
05/01/1985 (M)
02/01/1985 (M)
03/23/1999
07/03/1985 (M)
04/17/1985 (M)
(NSFHA)
04/15/1982
09/07/1998
08/16/1988
07/05/1983
05/01/1985
06/02/1999
04/17/1985 (M)
03/15/1984
04/17/1985 (M)
05/21/2001
04/03/1985
08/03/1998
06/01/1984
09/30/1982
04/18/1983
07/05/1983
05/04/2000

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONEIDA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY

Community Name
ONEIDA CASTLE, VILLAGE OF
ORISKANY FALLS, VILLAGE OF
ORISKANY, VILLAGE OF
PARIS, TOWN OF
PROSPECT, VILLAGE OF
REMSEN, TOWN OF
REMSEN, VILLAGE OF
ROME, CITY OF
SANGERFIELD, TOWN OF
SHERRILL, CITY OF
STEUBEN, TOWN OF
SYLVAN BEACH, VILLAGE OF
TRENTON, TOWN OF
UTICA, CITY OF
VERNON, TOWN OF
VERNON, VILLAGE OF
VERONA, TOWN OF
VIENNA, TOWN OF
WATERVILLE, VILLAGE OF
WESTERN, TOWN OF
WESTMORELAND, TOWN OF
WHITESBORO, VILLAGE OF
WHITESTOWN
WHITESTOWN, TOWN OF
YORKVILLE, VILLAGE OF
BALDWINSVILLE, VILLAGE OF
CAMILLUS, TOWN OF
CAMILLUS, VILLAGE OF
CICERO, TOWN OF
CLAY, TOWN OF
DEWITT, TOWN OF
EAST SYRACUSE, VILLAGE OF
ELBRIDGE, TOWN OF
ELBRIDGE, VILLAGE OF
FABIUS, TOWN OF
FAYETTEVILLE, VILLAGE OF
GEDDES, TOWN OF
JORDAN, VILLAGE OF
LAFAYETTE, TOWN OF
LIVERPOOL, VILLAGE OF
LYSANDER, TOWN OF
MANLIUS, TOWN OF
MANLIUS, VILLAGE OF
MARCELLUS, TOWN OF
MARCELLUS, VILLAGE OF
MINOA, VILLAGE OF
NORTH SYRACUSE, VILLAGE OF
ONONDAGA, TOWN OF
OTISCO, TOWN OF

Final SGEIS 2015, Page A1-18

Current FIRM Effective 
Date
07/04/1989
01/19/1983
09/15/1983
09/15/1983
11/20/2000
05/01/1985 (M)
09/24/1984 (M)
09/21/1998
06/05/1985
09/15/1983
09/24/1984 (M)
06/02/1999
09/07/1998
02/01/1984
08/16/1988
04/15/1988
10/20/1999
10/20/1999
08/02/1982
05/04/1989
03/02/1983
05/04/2000
05/04/2000
05/04/2000
03/01/1984
05/18/1999
05/18/1999
09/15/1994
03/16/1992
03/01/1979
08/03/1981
08/16/1982
08/16/1982
04/30/1986 (M)
04/17/1985
02/17/1982
08/16/1982
04/03/1985
02/04/1981
02/04/1983
09/17/1992
08/01/1984
08/16/1982
06/01/1982
09/02/1982
(NSFHA)
06/17/1991
06/03/1986 (M)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONONDAGA COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ONTARIO COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY

Current FIRM Effective 
Date
POMPEY, TOWN OF
10/8/1982
SALINA, TOWN OF
08/16/1982
SKANEATELES, TOWN OF
06/01/1982
SKANEATELES, VILLAGE OF
02/17/1982
SOLVAY, VILLAGE OF
(NSFHA)
SPAFFORD, TOWN OF
04/30/1986 (M)
SYRACUSE, CITY OF
05/15/1986
TULLY, TOWN OF
04/30/1986 (M)
TULLY, VILLAGE OF
01/19/1983
VAN BUREN, TOWN OF
03/01/1984
BLOOMFIELD, VILLAGE OF
8/15/1983
BRISTOL, TOWN OF
01/20/1984 (M)
CANADICE, TOWN OF
05/15/1984
09/24/1982
CANANDAIGUA, CITY OF
CANANDAIGUA, TOWN OF
03/03/1997
CLIFTON SPRINGS, VILLAGE OF
07/23/1982 (M)
EAST BLOOMFIELD, TOWN OF
08/15/1983
FARMINGTON, TOWN OF
09/30/1983
GENEVA, CITY OF
04/15/1982
GENEVA, TOWN OF
02/15/1978
GORHAM, TOWN OF
12/5/1996
HOPEWELL, TOWN OF
02/27/1984 (M)
MANCHESTER
MANCHESTER, TOWN OF
03/09/1984 (M)
MANCHESTER, VILLAGE OF
01/20/1984 (M)
NAPLES, TOWN OF
06/08/1984 (M)
NAPLES, VILLAGE OF
09/30/1977
PHELPS, TOWN OF
12/03/1982 (M)
PHELPS, VILLAGE OF
01/20/1984 (M)
RICHMOND, TOWN OF
12/18/1984
SENECA, TOWN OF
06/22/1984(M)
SHORTSVILLE, VILLAGE OF
09/24/1984 (M)
SOUTH BRISTOL, TOWN OF
05/18/1998
VICTOR, TOWN OF
09/30/1983
VICTOR, VILLAGE OF
05/17/2004
06/01/1978
WEST BLOOMFIELD, TOWN OF
BLOOMING GROVE, TOWN OF
08/03/2009
CHESTER, TOWN OF
08/03/2009
CHESTER, VILLAGE OF
08/03/2009
08/03/2009
CORNWALL ON THE HUDSON, VILLA
CORNWALL, TOWN OF
08/03/2009
CRAWFORD, TOWN OF
08/03/2009
DEER PARK, TOWN OF
08/03/2009
FLORIDA, VILLAGE OF
08/03/2009
GOSHEN, TOWN OF
08/03/2009
GOSHEN, VILLAGE OF
08/03/2009
GREENVILLE, TOWN OF
08/03/2009
GREENWOOD LAKE, VILLAGE OF
08/03/2009
HAMPTONBURGH, TOWN OF
08/03/2009
Community Name

Final SGEIS 2015, Page A1-19

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORANGE COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
ORLEANS COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY

Current FIRM Effective 
Date
HARRIMAN, VILLAGE OF
08/03/2009
HIGHLAND FALLS, VILLAGE OF
08/03/2009
HIGHLANDS, TOWNSHIP OF
08/03/2009
KIRYAS JOEL, VILLAGE OF
08/03/2009
MAYBROOK, VILLAGE OF 
08/03/2009 (M)
MIDDLETOWN, CITY OF
08/03/2009
MINISINK, TOWN OF
08/03/2009
MONROE, TOWN OF
08/03/2009
MONROE, VILLAGE OF
08/03/2009
MONTGOMERY, TOWN OF
08/03/2009
MONTGOMERY, VILLAGE OF
08/03/2009
MOUNT HOPE, TOWN OF
08/03/2009 (M)
08/03/2009
NEW WINDSOR, TOWN OF
NEWBURGH, CITY OF
08/03/2009
NEWBURGH, TOWN OF
08/03/2009
PORT JERVIS, CITY OF
08/03/2009
08/03/2009
SOUTH BLOOMING GROVE, VILLAGE
TUXEDO PARK, VILLAGE OF
08/03/2009
TUXEDO, TOWN OF
08/03/2009
UNIONVILLE, VILLAGE OF
08/03/2009 (M)
WALDEN, VILLAGE OF
08/03/2009
WALLKILL, TOWN OF
08/03/2009
WARWICK
WARWICK, TOWN OF
08/03/2009
WARWICK, VILLAGE OF
08/03/2009
WASHINGTONVILLE, VILLAGE OF
08/03/2009
WAWAYANDA, TOWN OF
08/03/2009
WOODBURY, VILLAGE OF
08/03/2009
ALBION, TOWN OF
08/08/1980 (M)
ALBION, VILLAGE OF
11/30/1979 (M)
BARRE, TOWN OF
10/15/1981 (M)
CARLTON, TOWN OF
11/1/1978
CLARENDON,TOWN OF
(NSFHA)
GAINES, TOWN OF
06/08/1984 (M)
HOLLEY, VILLAGE OF
11/30/1979 (M)
KENDALL, TOWN OF
05/01/1978
09/16/1981
LYNDONVILLE, VILLAGE OF
MEDINA, VILLAGE OF
03/28/1980 (M)
MURRAY, TOWN OF
03/21/1980 (M)
RIDGEWAY,TOWN OF
09/14/1979 (M)
SHELBY,TOWN OF
12/23/1983 (M)
YATES, TOWN OF
09/29/1978
ALBION, TOWN OF
04/15/1986 (M)
ALTMAR, VILLAGE OF
02/05/1986 (M)
AMBOY, TOWN OF
03/01/1988 (L)
BOYLSTON, TOWN OF
(NSFHA)
CENTRAL SQUARE,VILLAGE OF
(NSFHA)
CLEVELAND, VILLAGE OF
06/01/1982
CONSTANTIA, TOWN OF
11/3/1982
Community Name

Final SGEIS 2015, Page A1-20

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OSWEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY

Community Name
FULTON, CITY OF
GRANBY, TOWN OF
HANNIBAL, TOWN OF
HANNIBAL, VILLAGE OF
HASTINGS, TOWN OF
LACONA, VILLAGE OF
MEXICO, TOWN OF
MEXICO, VILLAGE OF
MINETTO, TOWN OF
NEW HAVEN, TOWN OF
ORWELL, TOWN OF
OSWEGO, CITY OF
OSWEGO, TOWN OF
PALERMO, TOWN OF
PARISH, TOWN OF
PARISH, VILLAGE OF
PHOENIX, VILLAGE OF
PULASKI, VILLAGE OF
REDFIELD, TOWN OF
RICHLAND, TOWN OF
SANDY CREEK, TOWN OF
SANDY CREEK, VILLAGE OF
SCHROEPPEL
SCHROEPPEL, TOWN OF
SCRIBA, TOWN OF
VOLNEY, TOWN OF
WEST MONROE, TOWN OF
WILLIAMSTOWN, TOWN OF
BURLINGTON, TOWN OF
BUTTERNUTS, TOWN OF
CHERRY VALLEY, TOWN OF
CHERRY VALLEY, VILLAGE OF
COOPERSTOWN, VILLAGE OF
DECATUR, TOWN OF
EDMESTON, TOWN OF
EXETER, TOWN OF
GILBERTSVILLE, VILLAGE OF
HARTWICK, TOWN OF
LAURENS, TOWN OF
LAURENS, VILLAGE OF
MARYLAND, TOWN OF
MIDDLEFIELD, TOWN OF
MILFORD, TOWN OF
MILFORD, VILLAGE OF
MORRIS, TOWN OF
MORRIS, VILLAGE OF
NEW LISBON, TOWN OF
ONEONTA, CITY OF
ONEONTA, TOWN OF

Final SGEIS 2015, Page A1-21

Current FIRM Effective 
Date
04/15/1982
09/16/1982
02/01/1988 (L)
04/01/1987 (L)
01/19/1983
05/11/1979 (M)
10/15/1981
10/15/1981
09/30/1981
11/2/1995
02/19/1986
11/22/1999
06/20/2001
03/01/1988
04/15/1986 (M)
02/19/1986 (M)
02/17/1982
09/02/1982
04/01/1991 (L)
07/17/1995
07/17/1995
05/11/1979 (M)
08/02/1982
06/06/2001
04/15/1982
01/20/1982
03/01/1988
10/21/1983 (M)
12/23/1983 (M)
02/01/1988 (L)
01/03/1986 (M)
05/04/2000
06/18/1987
06/01/1987 (L)
11/18/1983 (M)
11/01/1985 (M)
11/04/1983 (M)
05/15/1985 (M)
04/17/1987 (M)
06/03/1986 (M)
06/01/1988 (L)
05/19/1987 (M)
11/18/1983
01/03/1986 (M)
12/04/1985 (M)
11/18/1983 (M)
09/29/1978
10/17/1986

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County

Current FIRM Effective 
Date
OTEGO, TOWN OF
02/04/1987
OTEGO, VILLAGE OF
11/5/1986
OTSEGO, TOWN OF
06/01/1987 (L)
PITTSFIELD, TOWN OF
11/04/1983 (M)
PLAINFIELD, TOWN OF
11/04/1983 (M)
RICHFIELD SPRINGS, VILLAGE OF
01/03/1986 (M)
RICHFIELD, TOWN OF
04/15/1986 (M)
ROSEBOOM, TOWN OF
06/01/1988
SPRINGFIELD, TOWN OF
06/01/1987 (L)
UNADILLA, TOWN OF
09/30/1987
UNADILLA, VILLAGE OF
09/30/1987
WESTFORD, TOWN OF
06/01/1987 (L)
WORCESTER, TOWN OF
06/01/1987 (L)
BREWSTER, VILLAGE OF
09/18/1986
CARMEL,TOWN OF
10/19/2001
COLD SPRING, VILLAGE OF
03/15/1984
KENT, TOWN OF
09/04/1986
NELSONVILLE, VILLAGE OF
09/10/1984 (M)
PATTERSON, TOWN OF
07/03/1986
PHILIPSTOWN,TOWN OF
06/18/1987
PUTNAM VALLEY, TOWN OF
06/20/2001
SOUTHEAST, TOWN OF
09/04/1986
BERLIN
BERLIN, TOWN OF
08/17/1979 (M)
BRUNSWICK, TOWN OF
12/6/2000
CASTLETON‐ON‐HUDSON, VILLAGE O
11/15/1984
EAST GREENBUSH, TOWN OF
03/18/1980
EAST NASSAU, VILLAGE OF
09/05/1984
GRAFTON, TOWN OF
10/13/1978 (M)
HOOSICK FALLS, VILLAGE OF
02/04/2005
HOOSICK, TOWN OF
08/01/1987 (L)
NASSAU, TOWN OF
09/05/1984
NASSAU, VILLAGE OF
05/18/1979 (M)
NORTH GREENBUSH,TOWN OF
06/18/1980
PETERSBURG, TOWN OF
09/01/1978 (M)
PITTSTOWN, TOWN OF
09/05/1990
POESTENKILL, TOWN OF
09/02/1981
RENSSELAER, CITY OF
03/18/1980
05/15/1980
SAND LAKE, TOWN OF
SCHAGHTICOKE, TOWN OF
07/16/1984
SCHAGHTICOKE, VILLAGE OF
06/05/1985
SCHODACK, TOWN OF
08/15/1984
STEPHENTOWN, TOWN OF
08/03/1981
TROY, CITY OF
03/18/1980
VALLEY FALLS, VILLAGE OF
06/05/1985
Community Name

OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
OTSEGO COUNTY
PUTNAM COUNTY
PUTNAM COUNTY
PUTNAM COUNTY
PUTNAM COUNTY
PUTNAM COUNTY
PUTNAM COUNTY
PUTNAM COUNTY
PUTNAM COUNTY
PUTNAM COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RENSSELAER COUNTY
RICHMOND COUNTY/QUEENS 
COUNTY/NEW YORK COUNTY/KINGS 
COUNTY/BRONX COUNTY
ROCKLAND COUNTY

NEW YORK, CITY OF

09/05/2007

CHESTNUT RIDGE, VILLAGE OF

09/16/1988

Final SGEIS 2015, Page A1-22

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
ROCKLAND COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY
SARATOGA COUNTY

Current FIRM Effective 
Date
CLARKSTOWN, TOWN OF
05/21/2001
GRAND VIEW‐ON‐HUDSON, VILLAGE
10/15/1981
HAVERSTRAW, TOWN OF
01/06/1982
HAVERSTRAW, VILLAGE OF
09/02/1981
HILLBURN, VILLAGE OF
09/20/1996
KASER, VILLAGE OF
01/01/2050
MONTEBELLO, VILLAGE OF
01/18/1989
NEW HEMPSTEAD, VILLAGE OF
12/16/1988
NEW SQUARE, VILLAGE OF
(NSFHA)
NYACK, VILLAGE OF
12/4/1985
ORANGETOWN, TOWN OF
08/02/1982
PIERMONT, VILLAGE OF
11/17/1982
POMONA, VILLAGE OF
04/15/1982
RAMAPO, TOWN OF
02/02/1989
SLOATSBURG, VILLAGE OF
01/06/1982
11/4/1981
SOUTH NYACK, VILLAGE OF
SPRING VALLEY, VILLAGE OF
08/16/1988
STONY POINT, TOWN OF
09/30/1981
SUFFERN, VILLAGE OF
03/28/1980
UPPER NYACK, VILLAGE OF
(NSFHA)
WESLEY HILLS, VILLAGE OF
09/16/1988
WEST HAVERSTRAW, VILLAGE OF
09/30/1981
BALLSTON SPA,
SPA  VILLAGE OF
08/16/1995
BALLSTON, TOWN OF
08/16/1995
CHARLTON, TOWN OF
08/16/1995
CLIFTON PARK, TOWN OF
08/16/1995
CORINTH, TOWN OF
08/16/1995
CORINTH, VILLAGE OF
08/16/1995
DAY, TOWN OF
(NSFHA)
GALWAY, TOWN OF
08/16/1995
GREENFIELD, TOWN OF
08/16/1995
HADLEY, TOWN OF
08/16/1995
HALFMOON, TOWN OF
08/16/1995
MALTA, TOWN OF
08/16/1995
MECHANICVILLE, CITY OF
08/16/1995
MILTON, TOWN OF
08/16/1995
MOREAU, TOWN OF
08/16/1995
NORTHUMBERLAND, TOWN OF
08/16/1995
PROVIDENCE, TOWN OF
08/16/1995
ROUND LAKE, VILLAGE OF
08/16/1995
SARATOGA SPRINGS, CITY OF
08/16/1995
SARATOGA, TOWN OF
08/16/1995
SCHUYLERVILLE, VILLAGE OF
08/16/1995
SOUTH GLENS FALLS, VILLAGE OF
08/16/1995
STILLWATER, TOWN OF
08/16/1995
STILLWATER, VILLAGE OF
08/16/1995
VICTORY, VILLAGE OF
08/16/1995
WATERFORD, TOWN OF
08/16/1995
Community Name

Final SGEIS 2015, Page A1-23

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
SARATOGA COUNTY
SARATOGA COUNTY
SCHENECTADY COUNTY
SCHENECTADY COUNTY
SCHENECTADY COUNTY
SCHENECTADY COUNTY
SCHENECTADY COUNTY
SCHENECTADY COUNTY
SCHENECTADY COUNTY
SCHENECTADY COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHOHARIE COUNTY
SCHUYLER COUNTY
SCHUYLER COUNTY
SCHUYLER COUNTY
SCHUYLER COUNTY
SCHUYLER COUNTY
SCHUYLER COUNTY
SCHUYLER COUNTY
SCHUYLER COUNTY
SCHUYLER COUNTY
SCHUYLER COUNTY
SCHUYLER COUNTY
SCHUYLER COUNTY
SENECA COUNTY
SENECA COUNTY
SENECA COUNTY
SENECA COUNTY

Community Name
WATERFORD, VILLAGE OF
WILTON,TOWN OF
DELANSON, VILLAGE OF
DUANESBURG, TOWN OF
GLENVILLE,TOWN OF
NISKAYUNA, TOWN OF
PRINCETOWN, TOWN OF
ROTTERDAM, TOWN OF
SCHENECTADY, CITY OF
SCOTIA, VILLAGE OF
BLENHEIM, TOWN OF
BROOME, TOWN OF
CARLISLE, TOWN OF
COBLESKILL, TOWN OF
COBLESKILL, VILLAGE OF
CONESVILLE, TOWN OF
ESPERANCE, TOWN OF
ESPERANCE, VILLAGE OF
FULTON, TOWN OF
GILBOA, TOWN OF
JEFFERSON, TOWN OF
MIDDLEBURGH, TOWN OF
MIDDLEBURGH  VILLAGE OF
MIDDLEBURGH,
RICHMONDVILLE, TOWN OF
RICHMONDVILLE, VILLAGE OF
SCHOHARIE, TOWN OF
SCHOHARIE, VILLAGE OF
SEWARD, TOWN OF
SHARON SPRING, VILLAGE OF
SHARON, TOWN OF
SUMMIT, TOWN OF
WRIGHT, TOWN OF
BURDETT, VILLAGE OF
CATHARINE, TOWN OF
CAYUTA, TOWN OF
DIX, TOWN OF
HECTOR, TOWN OF
MONTOUR FALLS, VILLAGE OF
MONTOUR, TOWN OF
ODESSA, VILLAGE OF
ORANGE, TOWN OF
READING, TOWN OF
TYRONE, TOWN OF
WATKINS GLEN, VILLAGE OF
COVERT, TOWN OF
FAYETTE, TOWN OF
LODI, TOWN OF
LODI, VILLAGE OF

Final SGEIS 2015, Page A1-24

Current FIRM Effective 
Date
08/16/1995
(NSFHA)
05/25/1984 (M)
02/17/1989
05/04/1987
03/01/1978
07/01/1988 (L)
06/15/1984
09/30/1983
06/01/1984
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004
04/02/2004 (M)
04/02/2004
04/02/2004
04/02/2004
06/01/1988 (L)
04/20/1984 (M)
09/24/1984 (M)
10/29/1982 (M)
07/20/1984 (M)
09/15/1983
03/01/1988 (L)
04/20/1984 (M)
04/20/1984 (M)
(NSFHA)
07/06/1984 (M)
07/17/1978
06/08/1984 (M)
01/15/1988
01/15/1988
(NSFHA)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
SENECA COUNTY
SENECA COUNTY
SENECA COUNTY
SENECA COUNTY
SENECA COUNTY
SENECA COUNTY
SENECA COUNTY
SENECA COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST  LAWRENCE COUNTY
ST.
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY

Community Name
OVID, TOWN OF
ROMULUS, TOWN OF
SENECA FALLS, TOWN OF
SENECA FALLS, VILLAGE OF
TYRE, TOWN OF
VARICK, TOWN OF
WATERLOO, TOWN OF
WATERLOO, VILLAGE OF
BRASHER, TOWN OF
CANTON, TOWN OF
CANTON, VILLAGE OF
CLARE, TOWN OF
CLIFTON, CITY OF
COLTON, TOWN OF
DE KALB, TOWN OF
DE PEYSTER, TOWN OF
EDWARDS, TOWN OF
EDWARDS, VILLAGE OF
FINE, TOWN OF
FOWLER, TOWN OF
GOUVERNEUR, TOWN OF
GOUVERNEUR, VILLAGE OF
HAMMOND
HAMMOND, TOWN OF
HERMON, TOWN OF
HERMON, VILLAGE OF
HEUVELTON, VILLAGE OF
HOPKINTON, TOWN OF
LAWRENCE, TOWN OF
LISBON, TOWN OF
LOUISVILLE, TOWN OF
MACOMB, TOWN OF
MADRID, TOWN OF
MASSENA, TOWN OF
MASSENA, VILLAGE OF
MORRISTOWN, TOWN OF
MORRISTOWN, VILLAGE OF
NORFOLK, TOWN OF
NORWOOD, VILLAGE OF
OGDENSBURG, CITY OF
OSWEGATCHIE, TOWN OF
PARISHVILLE, TOWN OF
PIERCEFIELD, TOWN OF
PIERREPONT, TOWN OF
PITCAIRN, TOWN OF
POTSDAM, VILLAGE OF
POTSDAM,TOWN OF
RENSSELAER FALLS, VILLAGE OF
RICHVILLE, VILLAGE OF

Final SGEIS 2015, Page A1-25

Current FIRM Effective 
Date
01/15/1988
06/05/1985 (M)
08/03/1981
08/03/1981
08/31/1979 (M)
12/17/1987
09/16/1981
08/03/1981
01/03/1986 (M)
08/17/1998
05/02/1994
07/16/1982 (M)
05/15/1986 (M)
05/01/1985 (M)
(NSFHA)
07/23/1982 (M)
07/30/1982 (M)
07/23/1982 (M)
05/01/1985 (M)
06/05/1989 (M)
08/06/1982 (M)
03/03/1997
(NSFHA)
(NSFHA)
08/03/1998
04/30/1986 (M)
11/12/1982 (M)
(NSFHA)
(NSFHA)
(NSFHA)
(NSFHA)
(NSFHA)
06/17/1986 (M)
11/5/1980
08/06/1982 (M)
12/02/1980 (M)
04/15/1986 (M)
04/30/1986 (M)
11/5/1980
05/01/1985 (M)
07/30/1982 (M)
01/06/1984 (M)
(NSFHA)
08/13/1982 (M)
01/05/1996
03/04/1986 (M)
01/06/1984 (M)
01/06/1984 (M)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
ST. LAWRENCE COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY

Community Name
ROSSIE, TOWN OF
RUSSELL, TOWN OF
STOCKHOLM, TOWN OF
WADDINGTON, TOWN OF
WADDINGTON, VILLAGE OF
ADDISON, TOWN OF
ADDISON, VILLAGE OF
ARKPORT, VILLAGE OF
AVOCA, TOWN OF
AVOCA, VILLAGE OF
BATH, TOWN OF
BATH, VILLAGE OF
BRADFORD, TOWN OF
CAMERON, TOWN OF
CAMPBELL, TOWN OF
CANISTEO, TOWN OF
CANISTEO, VILLAGE OF
CATON, TOWN OF
COHOCTON, TOWN OF
COHOCTON, VILLAGE OF
CORNING, CITY OF
CORNING, TOWN OF
DANSVILLE
DANSVILLE, TOWN OF
ERWIN, TOWN OF
FREMONT, TOWN OF
GREENWOOD, TOWN OF
HAMMONDSPORT, VILLAGE OF
HARTSVILLE, TOWN OF
HORNBY, TOWN OF
HORNELL, CITY OF
HORNELLSVILLE, TOWN OF
HOWARD, TOWN OF
JASPER, TOWN OF
LINDLEY, TOWN OF
NORTH HORNELL, VILLAGE OF
PAINTED POST, VILLAGE OF
PRATTSBURG, TOWN OF
PULTENEY, TOWN OF
RATHBONE, TOWN OF
RIVERSIDE, VILLAGE OF
SAVONA, VILLAGE OF
SOUTH CORNING, VILLAGE OF
THURSTON, TOWN OF
TROUPSBURG, TOWN OF
TUSCARORA, TOWN OF
URBANA, TOWN OF
WAYLAND, TOWN OF
WAYLAND, VILLAGE OF

Final SGEIS 2015, Page A1-26

Current FIRM Effective 
Date
07/30/1982 (M)
(NSFHA)
04/15/1986 (M)
04/15/1986 (M)
05/11/1979 (M)
12/18/1984
06/15/1981
03/04/1980
02/05/1992
05/16/1983
05/02/1983
03/16/1983
09/24/1984 (M)
05/15/1991
06/11/1982
12/18/1984
05/18/1979 (M)
03/23/1984 (M)
05/16/1983
05/16/1983
09/27/2002
09/27/2002
03/09/84(M)
07/02/1980
10/29/1982 (M)
09/03/1982 (M)
04/17/1978
09/17/1982 (M)
04/15/1986
03/18/1980
07/16/1980
09/03/1982 (M)
07/23/1982 (M)
08/01/1980
01/17/1986
05/18/2000
01/20/1984 (M)
09/30/1977
12/03/1982 (M)
05/15/1980
08/15/1980
10/15/1981
02/11/1983 (M)
09/24/1982 (M)
03/01/1988 (L)
01/19/1978
06/08/1984 (M)
08/01/1988 (L)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County

Current FIRM Effective 
Date
WAYNE, TOWN OF
11/2/1977
WEST UNION, TOWN OF
07/01/1988 (L)
WHEELER, TOWN OF
07/25/1980 (M)
WOODHULL, TOWN OF
04/02/1991
ALMOND, TOWN OF
03/04/1980
AMITYVILLE, VILLAGE OF
09/25/2009
ASHAROKEN, VILLAGE OF
09/25/2009
BABYLON, VILLAGE OF
09/25/2009
BABYLON,TOWN OF
09/25/2009
BELLE TERRE, VILLAGE OF
09/25/2009
BELLPORT, VILLAGE OF
09/25/2009
BRIGHTWATERS, VILLAGE OF
09/25/2009
BROOKHAVEN,TOWN OF
09/25/2009
09/25/2009
DERING HARBOR, VILLAGE OF
EAST HAMPTON,TOWN OF
09/25/2009
EAST HAMPTON,VILLAGE OF
09/25/2009
GREENPORT, VILLAGE OF
09/25/2009
HEAD OF THE HARBOR, VILLAGE OF
09/25/2009
HUNTINGTON BAY, VILLAGE OF
09/25/2009
HUNTINGTON, TOWN OF
09/25/2009
ISLANDIA, VILLAGE OF
09/25/2009 (M)
ISLIP,TOWN OF
09/25/2009
LAKE GROVE
GROVE, VILLAGE OF
(NSFHA)
LINDENHURST, VILLAGE OF
09/25/2009
LLOYD HARBOR, VILLAGE OF
09/25/2009
NISSEQUOGUE, VILLAGE OF
09/25/2009
NORTH HAVEN, VILLAGE OF
09/25/2009
NORTHPORT, VILLAGE OF
09/25/2009
OCEAN BEACH, VILLAGE OF
09/25/2009
OLD FIELD, VILLAGE OF
09/25/2009
PATCHOGUE, VILLAGE OF
09/25/2009
POQUOTT, VILLAGE OF
09/25/2009
PORT JEFFERSON, VILLAGE OF
09/25/2009
QUOGUE, VILLAGE OF
09/25/2009
09/25/2009
RIVERHEAD, TOWN OF
SAG HARBOR, VILLAGE OF
09/25/2009
SAGAPONACK, VILLAGE OF
09/25/2009
SALTAIRE,VILLAGE OF
09/25/2009
SHELTER ISLAND, TOWN OF
09/25/2009
SHOREHAM, VILLAGE OF
09/25/2009
SMITHTOWN, TOWN OF
09/25/2009
SOUTHAMPTON, TOWN OF
09/25/2009
SOUTHAMPTON, VILLAGE OF
09/25/2009
SOUTHOLD,TOWN OF
09/25/2009
THE BRANCH, VILLAGE OF
09/25/2009
09/25/2009
WEST HAMPTON DUNES, VILLAGE O
WESTHAMPTON BEACH, VILLAGE OF
09/25/2009
BETHEL, TOWN OF
02/18/2011
Community Name

STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY
STEUBEN COUNTY/ALLEGANY COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SUFFOLK COUNTY
SULLIVAN COUNTY

Final SGEIS 2015, Page A1-27

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
SULLIVAN COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TIOGA COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY
TOMPKINS COUNTY

Community Name
BLOOMINGBURG, VILLAGE OF
CALLICOON, TOWN OF
COCHECTON, TOWN OF
DELAWARE, TOWN OF
FALLSBURG, TOWN OF
FORESTBURGH, TOWN OF
FREMONT, TOWN OF
HIGHLAND, TOWN OF
JEFFERSONVILLE, VILLAGE OF
LIBERTY, TOWN OF
LIBERTY, VILLAGE OF
LUMBERLAND, TOWN OF
MAMAKATING, TOWN OF
MONTICELLO, VILLAGE OF
NEVERSINK, TOWN OF
ROCKLAND, TOWN OF
THOMPSON, TOWN OF
TUSTEN, TOWN OF
WOODRIDGE, VILLAGE OF
WURTSBORO, VILLAGE OF
BARTON, TOWN OF
BERKSHIRE, TOWN OF
CANDOR
CANDOR, TOWN OF
CANDOR, VILLAGE OF
NEWARK VALLEY, TOWN OF
NEWARK VALLEY, VILLAGE OF
NICHOLS, TOWN OF
NICHOLS, VILLAGE OF
OWEGO, TOWN OF
OWEGO, VILLAGE OF
RICHFORD, TOWN OF
SPENCER, TOWN OF
SPENCER, VILLAGE OF
TIOGA, TOWN OF
WAVERLY, VILLAGE OF
CAROLINE, TOWN OF
CAYUGA HEIGHTS, VILLAGE OF
DANBY, TOWN OF
DRYDEN, TOWN OF
DRYDEN, VILLAGE OF
FREEVILLE, VILLAGE OF
GROTON, TOWN OF
GROTON, VILLAGE OF
ITHACA, CITY OF
ITHACA, TOWN OF
LANSING, TOWN OF
LANSING, VILLAGE OF
NEWFIELD, TOWN OF

Final SGEIS 2015, Page A1-28

Current FIRM Effective 
Date
02/18/2011
02/18/2011
02/18/2011
02/18/2011
02/18/2011
02/18/2011
02/18/2011
02/18/2011
02/18/2011
02/18/2011
02/18/2011
02/18/2011
02/18/2011
02/18/2011
02/18/2011 (M)
02/18/2011
02/18/2011
02/18/2011
02/18/2011 (M)
02/18/2011
05/15/1991
05/15/1985 (M)
08/19/1986
10/01/1991 (L)
02/03/1982
02/03/1982
02/17/1982
09/29/1986
01/17/1997
04/02/1982
05/15/1985 (M)
05/15/1985 (M)
05/15/1985 (M)
05/17/1982
03/16/1983
06/19/1985 (M)
(NSFHA)
05/15/1985 (M)
05/15/1985 (M)
01/03/1979
05/01/88(L)
10/05/1984 (M)
11/5/1986
09/30/1981
06/19/1985
10/15/1985
11/19/1987
10/15/1985 (M)

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
TOMPKINS COUNTY
TOMPKINS COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
ULSTER COUNTY
WARREN COUNTY
WARREN COUNTY
WARREN COUNTY
WARREN COUNTY
WARREN COUNTY
WARREN COUNTY
WARREN COUNTY
WARREN COUNTY
WARREN COUNTY
WARREN COUNTY
WARREN COUNTY
WARREN COUNTY
WARREN COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY

Community Name
TRUMANSBURG, VILLAGE OF
ULYSSES, TOWN OF
DENNING, TOWN OF
ELLENVILLE, VILLAGE OF
ESOPUS, TOWN OF
GARDINER, TOWN OF
HARDENBURGH, TOWN OF
HURLEY, TOWN OF
KINGSTON, CITY OF
KINGSTON,TOWN OF
LLOYD, TOWN OF
MARBLETOWN, TOWN OF
MARLBOROUGH, TOWN OF
NEW PALTZ, TOWN OF
NEW PALTZ, VILLAGE OF
OLIVE, TOWN OF
PLATTEKILL, TOWN OF
ROCHESTER, TOWN OF
ROSENDALE, TOWN OF
SAUGERTIES, TOWN OF
SAUGERTIES, VILLAGE OF
SHANDAKEN, TOWN OF
SHAWANGUNK
SHAWANGUNK, TOWN OF
ULSTER, TOWN OF
WAWARSING, TOWN OF
WOODSTOCK, TOWN OF
BOLTON, TOWN OF
CHESTER, TOWN OF
GLENS FALLS, CITY OF
HAGUE, TOWN OF
HORICON, TOWN OF
JOHNSBURG, TOWN OF
LAKE GEORGE, TOWN OF
LAKE GEORGE, VILLAGE OF
LAKE LUZERNE, TOWN OF
QUEENSBURY, TOWN OF
STONY CREEK, TOWN OF
THURMAN, TOWN OF
WARRENSBURG, TOWN OF
ARGYLE, TOWN OF
ARGYLE, VILLAGE OF
CAMBRIDGE, TOWN OF
CAMBRIDGE, VILLAGE OF
DRESDEN, TOWN OF
EASTON, TOWN OF
FORT ANN, TOWN OF
FORT ANN, VILLAGE OF
FORT EDWARD, TOWN OF

Final SGEIS 2015, Page A1-29

Current FIRM Effective 
Date
04/01/1988 (L)
02/19/1987
05/25/1984 (M)
09/25/2009
09/25/2009
09/25/2009
03/16/2089
08/18/2092
09/25/2009
09/25/2009
09/25/2009
09/25/2009
09/25/2009
09/25/2009
09/25/2009
11/1/1984
(NSFHA)
09/25/2009
09/25/2009
09/25/2009
09/25/2009 (M)
02/17/1989
09/25/2009
09/25/2009
09/15/1983
09/27/1991
08/16/1996
06/05/1985 (M)
06/05/1985
09/29/1996
02/15/1985 (M)
05/01/1985 (M)
08/16/1996
09/29/1996
05/01/1984
08/16/1996
08/24/1984 (M)
08/19/1986
03/01/1984
08/24/1984 (M)
05/18/1979 (M)
09/04/1985 (M)
01/02/2008
09/20/1996
11/20/1991
11/5/1997
(NSFHA)
12/15/1982

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WASHINGTON COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WAYNE COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY

Current FIRM Effective 
Date
FORT EDWARD, VILLAGE OF
02/15/1984
GRANVILLE, TOWN OF
08/05/1985 (M)
GRANVILLE, VILLAGE OF
04/17/1985 (M)
GREENWICH, VILLAGE OF
05/04/2000
GREENWICH,TOWN OF
03/16/1992
HAMPTON, TOWN OF
04/17/1985 (M)
HARTFORD, TOWN OF
11/01/1985 (M)
HEBRON, TOWN OF
06/15/1994
HUDSON FALLS, VILLAGE OF
(NSFHA)
JACKSON, TOWN OF
03/16/1992
KINGSBURY, TOWN OF
09/07/1979 (M)
PUTNAM, TOWN OF
11/20/1996
04/17/1985 (M)
SALEM, VILLAGE OF
SALEM,TOWN OF
04/17/1985 (M)
WHITE CREEK, TOWN OF
04/17/1985 (M)
WHITEHALL, TOWN OF
07/03/1986
WHITEHALL, VILLAGE OF
06/03/1985 (M)
ARCADIA, TOWN OF
11/2/1977
BUTLER, TOWN OF
07/09/1982 (M)
CLYDE, VILLAGE OF
12/18/1984
GALEN, TOWN OF
05/16/1983
HURON, TOWN OF
01/19/1996
LYONS
LYONS, TOWN OF
09/07/1979 (M)
LYONS, VILLAGE OF
03/16/1983
MACEDON, TOWN OF
01/05/1984
MACEDON, VILLAGE OF
09/30/1983
MARION, TOWN OF
07/01/1988 (L)
NEWARK, VILLAGE OF
07/15/1988
ONTARIO, TOWN OF
06/01/1978
PALMYRA, TOWN OF
03/01/1978
PALMYRA, VILLAGE OF
07/15/1988
RED CREEK, VILLAGE OF
04/08/1983 (M)
ROSE, TOWN OF
03/09/1984 (M)
SAVANNAH, TOWN OF
08/06/1982 (M)
11/2/1977
SODUS POINT, VILLAGE OF
SODUS, TOWN OF
06/02/1992
WALWORTH, TOWN OF
03/16/1983
WILLIAMSON TOWN
10/17/1978
WOLCOTT, TOWN OF
06/02/1992
WOLCOTT, VILLAGE OF
07/06/1984 (M)
ARDSLEY, VILLAGE OF
09/28/2007
BEDFORD, TOWN OF
09/28/2007
BRIARCLIFF MANOR, VILLAGE OF
09/28/2007
BRONXVILLE, VILLAGE OF
09/28/2007
BUCHANAN, VILLAGE OF
09/28/2007 (M)
CORTLANDT, TOWN OF
09/28/2007
CROTON‐ON‐HUDSON, VILLAGE OF
09/28/2007
09/28/2007
DOBBS FERRY, VILLAGE OF
Community Name

Final SGEIS 2015, Page A1-30

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WESTCHESTER COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY

Current FIRM Effective 
Date
EASTCHESTER, TOWN OF
09/28/2007
ELMSFORD, VILLAGE OF
09/28/2007
GREENBURGH,TOWN OF
09/28/2007
HARRISON, TOWN OF
09/28/2007
09/28/2007
HASTINGS‐ON‐HUDSON, VILLAGE OF
IRVINGTON, VILLAGE OF
09/28/2007
LARCHMONT, VILLAGE OF
09/28/2007
LEWISBORO, TOWN OF
09/28/2007 (M)
MAMARONECK, TOWN OF
09/28/2007
MAMARONECK, VILLAGE OF
09/28/2007
MOUNT KISCO, VILLAGE OF
09/28/2007
MOUNT PLEASANT, TOWN OF
09/28/2007
MOUNT VERNON, CITY OF
09/28/2007
NEW CASTLE, TOWN OF
09/28/2007
NEW ROCHELLE, CITY OF
09/28/2007
NORTH CASTLE, TOWN OF
09/28/2007
NORTH SALEM, TOWN OF
09/28/2007
OSSINING, TOWN OF
09/28/2007
OSSINING, VILLAGE OF
09/28/2007
PEEKSKILL, CITY OF
09/28/2007
PELHAM MANOR, VILLAGE OF
09/28/2007
PELHAM, VILLAGE OF
09/28/2007
PLEASANTVILLE
PLEASANTVILLE, VILLAGE OF
09/28/2007
PORT CHESTER, VILLAGE OF
09/28/2007
POUND RIDGE, TOWN OF
09/28/2007
RYE BROOK, VILLAGE OF
09/28/2007
RYE, CITY OF
09/28/2007
SCARSDALE, VILLAGE OF
09/28/2007
SLEEPY HOLLOW, VILLAGE OF
09/28/2007
SOMERS, TOWN OF
09/28/2007
TARRYTOWN, VILLAGE OF
09/28/2007
TUCKAHOE, VILLAGE OF
09/28/2007
WHITE PLAINS, CITY OF
09/28/2007
YONKERS, CITY OF
09/28/2007
YORKTOWN, TOWN OF
09/28/2007
ARCADE, TOWN OF
03/03/1992
ARCADE, VILLAGE OF
03/03/1992
ATTICA, TOWN OF
04/30/1986
BENNINGTON, TOWN OF
12/23/1983 (M)
CASTILE, TOWN OF
12/23/1983 (M)
CASTILE, VILLAGE OF
05/28/1982 (M)
COVINGTON, TOWN OF
12/23/1983 (M)
EAGLE, TOWN OF
12/23/1983 (M)
GAINESVILLE, TOWN OF
12/23/1983 (M)
GAINESVILLE, VILLAGE OF
02/15/1985 (M)
GENESEE FALLS, TOWN OF
05/01/1984
JAVA, TOWN OF
12/23/1983 (M)
ORANGEVILLE, TOWN OF
12/23/1983 (M)
Community Name

Final SGEIS 2015, Page A1-31

 TABLE 3.4

Summary of FEMA Flood Insurance Rate Map (FIRM) Availability

County
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
WYOMING COUNTY
YATES COUNTY
YATES COUNTY
YATES COUNTY
YATES COUNTY
YATES COUNTY
YATES COUNTY
YATES COUNTY
YATES COUNTY
YATES COUNTY
YATES COUNTY
YATES COUNTY
YATES COUNTY
YATES COUNTY

Community Name
PERRY, TOWN OF
PERRY, VILLAGE OF
PIKE, TOWN OF
PIKE, VILLAGE OF
SHELDON, TOWN OF
SILVER SPRINGS, VILLAGE OF
WARSAW, TOWN OF
WARSAW, VILLAGE OF
WETHERSFIELD, TOWN OF
WYOMING, VILLAGE OF
BARRINGTON, TOWN OF
BENTON, TOWN OF
DRESDEN, VILLAGE OF
DUNDEE, VILLAGE OF
ITALY, TOWN OF
JERUSALEM, TOWN OF
MIDDLESEX, TOWN OF
MILO, TOWN OF
PENN YAN, VILLAGE OF
POTTER, TOWN OF
RUSHVILLE, VILLAGE OF
STARKEY, TOWN OF
TORREY
TORREY, TOWN OF

Notes:
(NSFHA) ‐ No special flood hazard area ‐ All Zone "C"
(M) No elevation determined ‐ All Zone "A", "C", and "X"

(L) Original FIRM by letter ‐ All Zone "A", "C", and "X"

(S) Suspended community, not in the National Flood Program.

(X) Community not in National Flood Program

(>) Date of current effective map is after the date of this report.

Source: FEMA "Community Status Book Report – June 29, 2011.”

(http://www.fema.gov/fema/csb.shtm)


Final SGEIS 2015, Page A1-32

Current FIRM Effective 
Date
12/23/1983 (M)
07/29/1977 (M)
12/23/1983 (M)
06/18/1982 (M)
12/23/1983 (M)
01/20/1984 (M)
12/23/1983 (M)
11/18/1981
07/16/1982
08/03/1981
03/09/1984 (M)
01/20/1984 (M)
06/15/1981
03/01/1988 (L)
03/07/2001
01/20/1984 (M)
09/29/1989
07/18/1985 (M)
06/15/1981
03/23/1984 (M)
06/05/1985 (M)
12/3/1987
12/3/1987

 Appendix 2
1992 SEQRA Findings Statement on
the GEIS on the Oil, Gas and Solution
Mining Regulatory Program
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

September 1, 1992
Findings Statement
Pursuant to the State Environmental Quality Renew Act (SEQR) of the Environmental
Conservation Law (ECL) and the SEQR Regulations 6NYCRR Part 617, the New York State
Department of Environmental Conservation makes the following findings.
Name of Action
Adoption of the Final Generic Environmental Impact Statement (GEIS) on the Oil, Gas
and Solution Mining Regulatory Program.
Description and Backround
In early 1988, the Department of Environmental Conservation released the Draft GEIS
on the Oil, Gas and Solution Mining Regulatory Program. The Draft GEIS comprehensively
reviewed the environmental impacts of the Department's program for regulating the siting,
drilling, production and plugging and abandonment of oil, gas, underground gas storage, solution
mining, brine disposa1, geothermal and stratigraphic test wells. Six public hearings were held on
the Draft GEIS in June 1988.
The Final GEIS was released in July 1992. It contains individual responses to the
hundreds of comments received on the Draft GEIS. The Final GEIS also includes more detailed
topical responses addressing several controversial issues that frequently appeared in the comments
on the draft document.
Together, the Draft and Final GEIS and this Findings Statement will provide the
groundwork for revisions to the Oil, Gas and Solution Mining Regulations (6NYCRR Parts 550-

559). These regulations are being updated to more accurately reflect and effectively implement
the current Oil, Gas and Solution Mining Law (ECL Article 23).
The Draft GEIS included suggested changes to the regulations in bold print throughout
the document. In the interests of environmental protection and public safety, a significant

Final SGEIS 2015, Page A2-1

 number of the suggested regulatory changes are already put in effect as standard conditions
routinely applied to permits. All formal regulation changes, however, must be promulgated in
accordance with the State Administrative Procedure Act (SAPA) requiring separate review, public
hearings and approval. Further public input during the rulemaking process may cause some of
the new regulations, when they are eventually adopted, to differ from those discussed in the
GEIS. Any regulations adopted that differ significantly from those discussed in the GEIS will
undergo an additional SEQR Review and Determination.
Location
Statewide.
DEC Jurisdiction
Jurisdiction is provided by the Oil, Gas and Solution Mining Law (ECL Article 23).
Date Final GEIS Filed
The Final GEIS was filed June 25, 1992/#PO-009900-00046. The Notice of Completion
was published in the Environmental Notice Bulletin July 8, 1992.
Facts and Conclusions Relied Upon to Support the SEOR Findings
The record of facts established in the Draft and Final GEIS upholds the following
conclusions:
1. 

The unregulated siting, drilling, production, and plugging and abandonment of oil,
gas, solution mining, underground gas storage, brine disposal, geothermal and
stratigraphic test wells could have potential negative impacts on every aspect of the
environment. The potential negative impacts range from very minor to significant.
Potential impacts of unregulated activities on ground and surface waters are a
particularly serious concern. The potential negative impacts on all environmental
resources are described in detail in Chapters 8 through 14 and summarized in
Chapter 16 of the Draft GEIS.

Final SGEIS 2015, Page A2-2

 2.  

Under existing regulntions and permit conditions, the potential environmental
impacts of the above wells are greatly reduced and most are reduced to nonsignificant levels. The extensive mitigation measures required under the existing
regulatory program are described in detail in Chapters 8 through 14 and
summarized in Chapter 17 of the Draft

3.  

GEIS.

The potential environmental impacts associated with the activities covered by the
Oil, Gas and Solution Mining Regulato~yProgram also have economic and social
implications. For example, it is less expensive to prevent pollution than pay for
remediation of environmental problems, health care costs, and lawsuit expenses.
The State also receives significant economic benefits from the activities covered by
the regulatory program. The regulated industries provide jobs and economic
stimulus through the purchase of goods and services, and the payment of taxes,
royalties and leasing bonuses. Additional information on the potential economic
impacts associated with the activities covered by the regulatory program is provided
in Chapter 18of the Draft GEIS.

4.  

The Department's routine requirement of: 1) a program-specific Environmental
Assessment Form (EAF) with every well drilling permit application, 2) a plat
(map) showing the proposed well location, and 3) a pre-drilling site inspection,
allows the Department to:
reliably determine potential environmental problems, and
select appropriate permit conditions for mitigating potential environmental
impacts.
The E A F is printed in its entirety and discussed in detail on pages FGEIS 30-34 of
the Final GEIS. Information on the permit application review process is
summarized in Chapter 7 of the Draft GEIS.

Final SGEIS 2015, Page A2-3

 5.  

The majority of the industry's activity centers on drilling individual oil and gas wells
for primary production. For purposes of this Findings Statement, standard oil and
gas operations are defined as:
any procedure relevant to rotary or cable tool drilling procedures, and

- 

production operations which do

utilize any type of artificial means to

facilitate the recovery of hydrocarbons.
The basic features of standard oil and gas operations are described in detail in
Chapters 9 through 11 of the Draft GEIS.
6.  

The diverse types of wells covered by the regulatory program have enough design
and operational characteristics in common to group them according to their
potential environmental impacts. Design and operational aspects of these wells are
described in detail in Chapters 9 through 14 of the Draft GEIS.

7.  

The magnitude of potential environmental impacts associated with any proposed
well covered by the regulatory program is strongly influenced by the types of
natural and cultural resources in the well's vicinity. New York State's
environmental resources are described in Chapter 6 of the Draft GEIS. Most of
the information on the potential environmental impacts of the regulated activities
on these enviro~irnentalresources can be found in Chapter 8 of the Draft GEIS,
which deals with siting issues. Additional information on potential impacts related
to specific stages (drilling, completion, production, plugging and abandonment) of
well operation can be found in Chapters 9 through 11 of the Draft GEIS.
Additional information on potential environmental impacts related specifically to
enhanced oil recovery, solution salt mining, underground gas storage and waste
brine disposal can be found in Chapters 12 through 15 of the Draft GEIS.

Final SGEIS 2015, Page A2-4

 8.  

The range of future alternatives concerning the activities covered by the Oil, Gas
and Solution Mining Regulatory Program can be divided into three basic
categories: 1) prohibition on regulated activities, 2) removal of regulation, and 3)
maintenance of status quo versus revision of existing regulations. A prohibition on
these regulated activities would deprive the State of substantial economic and
natural resource benefits. Complete removal of regulation would lead to severe
environmental problems. While the existing regulations and permit conditions
provide significant environmental protection, there is still room to improve the
efficiency and effectiveness of the program. Revision of the existing regulations is
the best alternative. Chapter 21 of the Draft GEIS contains a more detailed
assessment of the environmental, economic, and social aspects of each alternative.

SEOR Determinations of Significance
The SEQR determinations on the significance of the environmental impacts associated
with the activities covered by this regulatory program are presented in the following table. The
determinations are supported by the conclusions listed above, which in turn are supported by the
referenced sections of the Draft and Final GEIS.

Final SGEIS 2015, Page A2-5

 SEQR DETERMINATIONS 

-

Agency Action
a.  

b.  

c. 

d.  

Standard individual oil, gas, solution
mining, stratigraphic, geothermal, or gas
storage well drilling permits (no other
permits involved).
Oil and gas drilling permits in State
Parklands.  

Oil and gas drilling permits in Agricultural
Districts.  

Oil and gas drilling permits in the "Bass
Island" fields.  

Environmental Impact  
not significant

may be significant

may be significant

not significant

Explanation
Rules and regulations and conditions are adequate
to protect the environment. The Draft and Final
GEIS satisfy SEQR for these actions. A sitespecific EAF is required with the permit
application.
Site-specific conditions of State Parklands are not
discussed in the Draft and Final GEIS. Further
determination of significant environmental impacts
is needed for State Parklands. A site-specific EAF
is required with the permit application.
Rules and regulations and conditions are adequate
to protect the environment. For most oil and gas
operations in Agricultural Districts which utilize
less than 2% acres the GEIS satisfies SEQR. If
more than 2% acres are disturbed, this is a Type I
action under 6NYCRR Part 617 and an additional
determination of significance is required. A sitespecific EAF is required with the permit
application.
Special conditions and regulations under Part 559
are adequate to protect the environment. The
Draft and Final GEIS satisfy SEQR for these
actions. A site-specific EAF is required with the
permit application.

Final SGEIS 2015, Page A2-6

 e.

f.

g.

h.

i.

Oil and gas drilling permits for locations
above aquifers.

not significant

Oil and gas drilling permits in close
proximity (less than 1,000 feet) to
municipal water supply wells.

always significant

Oil and gas drilling permits in proximity
(between 1,000and 2,000 feet) to
municipal water supply wells.

may be significant

Oil and gas drilling permits when other
DEC permits required.

Plugging permits for oil, gas, solution
mining, stratigraphic, geothermal, gas
storage and brine disposal wells.

Rules and regulations and special aquifer
conditions employed by DEC have been developed
specifically to protect the groundwater resources of
the State. The Draft and Final GEIS satisfy
SEQR for these actions. A site-specific EAF is
required with the permit application.

A supplemental EIS is required dealing with the
groundwater hydrology, potential impacts and
mitigation measures. A site-specific EAF is
required with the permit application.

A supplemental EIS may b e required dealing with

may be significant

Type I1 *

the groundwater hydrology, potential impacts and
mitigation measures. A site-specific assessment
and SEQR determination are required. A sitespecific EAF is required with the permit
application.
A site-specific SEQR assessment and
determination are needed based on the
environmental conditions requiring additional DEC
permits. A site-specific EAF is required with the
permit application.

By law all wells drilled must be plugged before
abandonment. Proper well plugging is a beneficial
action with the sole purpose of environmental
protection, and constitutes a routine agency action.

* Under 6NYCRR 617.13, a Type I1 action is one which has been determined not to have a significant effect o n the environment
and does not require any other SEQR determination or procedure.

-

Final SGEIS 2015, Page A2-7

 .

j.

New waterflood or tertiary recovery
projects.

may be significant

k.

New underground gas storage projects or
major modifications.

may be significant

1.

New solution mining projects or major
modifications.

may be significant

m.

Spacing hearing.
not significant

n.

Variance hearing.

not significant

For major new waterfloods and new tertiary
recovery projects, a site specific environmental
assessment and SEQR determination are required.
A supplemental EIS may be required for new
waterfloods to ensure integrity of the flood. Also,
a supplemental EIS may be required for new
tertiary recovery projects depending on the scope
of operations and methods used. A site-specific
EAF is required with the permit application.
A site-specific environmental assessment and
SEQR determination are required. May require a
supplemental EIS depending on the scope of the
project. A site-specific EAF is required with the
permit application.
A site-specific environmental assessment and
SEQR determination are required. May require a
supplemental EIS depending on the scope of the
project. A site-specific EAF is required with the
permit application.
Action to hold hearing is non-significant. A review
and SEQR determination with respect to all other
issues must be made before the hearing. Any
permit issued subsequently will be reviewed on
issues raised at hearing. A site-specific EAF is
required with the permit application.
Action to hold hearing is non-significant. A review
and SEQR determination with respect to all other
issues must be made before the hearing. Any
permit issued subsequently will be reviewed on
issues raised at hearing. A site-specific EAF is
required with the permit application.

Final SGEIS 2015, Page A2-8

 r

o.  

Compulsory unitization hearing.

p.  

Natural Gas Policy Act pricing 

recommendations.

not significant

none 


q.  

Brine disposal well drilling or conversion
permit.

may be significant

Action to hold hearing is nonsignificant. A review
and SEQR determination with respect to all other
issues must be made before the hearing. Any
permit issued subsequently will be reviewed on
issues raised at hearing. A site-specific EAF is
required with the permit application.
Action only results in recommendations to Federal
Energy Regulatory Commission; therefore, action
is not subject to SEQR.
The brine disposal well permitting guidelines
require an extensive surface and subsurface
evaluation which is in effect a supplemental EIS
addressing technical issues. An additional site
specific environmental assessment and SEQR
determination are required. A site-specific EAF is
required with the permit application.

Final SGEIS 2015, Page A2-9

 SEOR Review Procedures
Upon filing of this Findings Statement, the following SEQR Review procedures will be
adopted for the Oil, Gas and Solution Mining Regulatory Program:
1.  

A shortened program-specific Environmental Assessment Form (EAF) will
continue to be required with every well drilling permit application, regardless of
the SEQR determination listed in the previous table. Information required by the
EAF is considered to be an essential part of the permit application. It contains
vital site-specific information necessary to evaluate the need for individual permit
conditions.

2. 

In the following cases where the GEIS satisfies SEQR, Department staff will no
longer make Determinations of Significance and a Negative or Positive Declaration
under SEQR will no longer be required so long as projects conform to the
descriptions in the Draft and Final GEIS:
Standard individual oil, gas, solution mining, stratigraphic test, geothermal
or gas storage well drilling permits,
Oil and gas drilling permits in the "Bass Islands" field, and

- 
3.  

Oil and gas drilling permits for locations above aquifers.

In addition to the short program-specific EAF, permits for the following projects
will also require detailed site-specific environmental assessments using the LongForm EAF published in Appendix A of 6NYCRR Part 617. A site or projectspecific EIS may also be required for the following projects depending upon the
information revealed in the permit application and accompanying EAF's:
Oil and gas drilling permits in Agricultural Districts if more than two and 

one-half acres will be altered by construction of the well site and access 

road. 

Oil and gas drilling permits in State Parklands. 

Oil and gas drilling permits when other DEC permits are required.

Final SGEIS 2015, Page A2-10

 Oil and gas drilling permits less than 2,000 feet from a municipal water
supply well.
New major waterflood or tertiary recovery projects.

-

New underground gas storage projects or major modifications.
New solution mining projects or major modifications.

-

Brine disposal well drilling or conversion permits.
Any other project not conforming to the standards, criteria o r thresholds
required by the Draft and Final GEIS.

Other SEOR Considerations

I n conducting SEQR reviews, the Department will handle the topics of individual project
scope, project size, lead agency, and coastal resources as described below.
1.  

Proiect scoue - Each application to drill a well will continue to be considered as an
individual project. An applicant applying for five wells will continue to be treated.
the same as five applicants applying to the Department individually, since the wells
may not be drilled at the same time o r in the same area. Planned future wells
might. not be drilled at all depending on the results of the first well drilled.
The exceptions to this are proposed new or major expansions of solution
mining, enhanced recovery or underground gas storage operations which require
that several wells be drilled and operated for an extended period oftime within a
limited area.

2.  

Size of Proiect - The size of the project will continue to b e defined as the surface
acreage affected by development.

3.  

Lead Aeency - In 1981, the Legislature gave exclusive authority t o the Department
to regulate the oil, gas and solution mining industries under E C L Section 230303(2). Thus, only the Department has jurisdiction to grant drilling permits for

wells subject to Article 23, except within State parklands. To the extent
practicable, the Department will actively seek lead agency designation consistent

Final SGEIS 2015, Page A2-11

 with the general intent of Chapter 846 of the Laws of 1981.
4.  

Coastal Resources - On the program specific EAF that must accompany every
drilling permit application, the applicant must indicate whether the proposed well
is in a legally designated New York State Coastal Zone Management (CZM) Area.
Neither the policies in the New York State CZM Plan, nor the provisions of
individual d c a l Waterfront Revitalization Plans (LWRP1s) are covered in the
GEIS. Once an LWRP is adopted by a community, it is a legally binding part of
the New York State CZM Plan. The Department cannot issue any drilling permit
unless it is consistent with the New York State CZM Plan to the "maximum extent
practicable."

Final SGEIS 2015, Page A2-12

 CERTIFICATION OF FINDINGS TO ADOPT THE FINAL GENERIC ENVIRONMENTAL
IMPACT STATEMENT ON THE OIL, GAS AND SOLUTION MINING REGULATORY
PROGRAM
Having considered the Draft and Final GEIS, and having considered the preceding written
facts and conclusions relied upon to meet the requirements of 6NYCRR Part 617.9, this
Statement of Findings certifies that:
1.  

The requirements of 6NYCRR Part 617 have been met;

2.  

Consistent with the social, economic and other essential considerations from
among the reasonable alternatives thereto, the action approved is one which
minimizes or avoids adverse environmental effects to the maximum extent
practicable; including the effects disclosed in the environmental impact statement,
and

3.  

Consistent with social, economic and other essential considerations, to the
maximum extent practicable, adverse environmental effects revealed in the
environmental impact statement process will be minimized or avoided by
incorporating as conditions to the decision those mitigative measures which were
identified as practicable.

4.  

Consistent with the applicable policies of Article 42 of the Executive Law, as
implemented by 19 NYCRR 600.5, this action will achieve a balance between the
protection of the environment and the need to accommodate social and economic
considerations.

,"/

f

Dikctor 4
Division of Mineral Resources

Final SGEIS 2015, Page A2-13

Date

 This page intentionally left blank.

Appendix 3
Supplemental SEQRA Findings Statement
on Leasing of State Lands for Activities
Regulated Under the Oil, Gas and Solution
Mining Law
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

SEQR File No.
P0-009900-00046
Supplemental 

Findings Statement 

Pursuant to the State Environmental Quality Review Act (SEQR) of the Environmental
Conservation Law (ECL) and the SEQR Regulations 6NYCRR Part 617, the New York State
Department of Environmental Conservation makes the following supplemental findings on the
Final Generic Environmental Impact Statement (GEIS) on the Oil, Gas and Solution Mining
Regulatory Program.
Name of Action
Adoption of supplemental findings on leasing of state lands for activities regulated under the
Oil, Gas and Solution Mining Law (ECL Article 23).
Description and Background
In early 1988, the Department of Environmental Conservation released the Draft GEIS on the
Oil, Gas and Solution Mining Regulatory Program. The Draft GEIS comprehensively reviewed the
environmental impacts of the Department's program for regulating the siting, drilling, production
and plugging and abandonment of oil, gas, underground gas storage, solution mining, brine disposal,
geothermal and stratigraphic test wells. The findings statement issued on the Draft and Final GEIS
in September, 1992 neglected to specifically mention DEC's program for leasing of State lands for
these resource development activities.
Prior to adoption of the GEIS, proposed lease sales underwent a segmented review. Segmented
reviews are permitted under certain circumstances if they are no less protective of the environment.
This is true given the highly speculative nature of oil and gas leasing practices:
- 

It is impractical to review the potential environmental impacts of 

development activities at the leasing stage. Information on the 

placement of well sites is not generally known, even by the lessee. 

Not until a company successfully obtains a lease does it invest 

time and money in preparing the exploration and development 

plans that will be submitted to the Department for approval if the 

lessee wishes to commence operations. 


- 

Most of the land leased will never be directly affected by

development activities. Based on a 15 year record of the State's 

leasing program, less than one percent of all the State land 

leased has been subject to any direct impact. 


- 

When the lessee does decide on a proposed well site on a State 

lease, the lessee must obtain a site-specific drilling permit from 

the Department. With eve well drilling permit application the 

Department requires: 1) a program-specific Environmental 

Assessment Form, 2) a plat (map) showing the proposed well 

location and support facilities, and 3) a pre-drilling site

inspection that allows the Department to : 

- 
reliably determine potential environmental

problems; and

Final SGEIS 2015, Page A3-1

 - 

- 

select appropriate permit conditions for mitigating
potential environmental impacts.

Possession of a lease does not a priori grant the right to drill on a lease.
Nor is the lessee in any way guaranteed approval for their first-choice
drilling location. Clauses included in the lease inform the lessee that
any surface disturbing activities must receive Department review and
approval prior. to their commencement. Leases also contain clauses
recommended by other State agency staff that are necessary for
protection of fish, wildlife, plant, land, air, wetlands, water and
cultural resources on the leased parcels.

SEOR Determination of Significance
The Department has determined that the act of leasing State lands for activities regulated under
ECL Article 23 does not have a significant environmental impact. This determination is supported
by the facts listed above.
SEOR Review Procedures
Department staff will no longer make Determinations of Significance and Negative or Positive
Declarations under SEQR for leases on State lands for activities regulated under ECL Article 23 at the
time that the lease is granted; SEQR reviews will continue to be done as needed for site-specific
development.

Final SGEIS 2015, Page A3-2

 CERTIFICATION OF SUPPLEMENTAL FINDINGS ON THE FINAL GENERIC
ENVIRONMENTAL IMPACT STATEMENT ON THE OIL, GAS AND SOLUTION
MINING REGULATORY PROGRAM
Having considered the Draft and Final GEIS, and having considered the preceding written facts
and conclusions relied upon to meet the requirements of 6NYCRR Part 617.9, this Supplemental
Statement of Findings certifies that:
1. 

The requirements of 6NYCRR Part 617 have been met.

2.

Consistent with the social, economic, and other essential
considerations from among the reasonable alternatives thereto, the
action approved is one which minimizes or avoids adverse
environmental effects to the maximum extent practicable; including
the effects disclosed in the environmental impact statement.

3.

Consistent with the social, economic, and other essential
considerations, to the maximum extent practicable, adverse
environmental effects revealed in the environmental impact
statement process will be minimized or avoided by incorporating as
conditions to the decision those mitigative measures which were
identified as practicable.

4. 

Consistent with the applicable policies of Article 42 of the
Executive Law, as implemented by 19 NYCRR 600.5, this action
will achieve a balance between the protection of the environment
and the need to accommodate social and economic considerations.

/S/
Gregory H. Sovas, Director
Division of Mineral Resources

Final SGEIS 2015, Page A3-3

April 19, 1993

 This page intentionally left blank.

Appendix 4
EXISTING

Application Form for Permit to Drill, Deepen, Plug
Back or Convert A Well Subject to the Oil, Gas
and Solution Mining Regulatory Program
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Print Form
85-12-5 (01/13)

PAGE 1 OF 2

NEW YORK STATE DEPARTMENT OF ENVIRONMENTAL CONSERVATION
DIVISION OF MINERAL RESOURCES

PRINT OR TYPE IN BLACK INK

APPLICATION FOR PERMIT TO DRILL, DEEPEN, PLUG BACK OR CONVERT
A WELL SUBJECT TO THE OIL, GAS AND SOLUTION MINING LAW
THIS APPLICATION IS A LEGAL DOCUMENT. READ THE APPLICABLE AFFIRMATION AND ACKNOWLEDGMENT CAREFULLY BEFORE SIGNING.

For instructions on completing this form, visit the Division’s website at www.dec.ny.gov/energy/205.html or contact your local Regional office.
PLANNED OPERATION: (Check one)
Drill

Deepen

Plug Back

TYPE OF WELL: (Check one)
New

Convert

Sidetrack

Existing API Well Identification Number
Existing

31-

-

-

-

TYPE OF WELL BORE: (Check one)
Vertical

Directional

Horizontal

NAME OF OWNER (Full Name of Organization or Individual as registered with the Division)

TELEPHONE NUMBER (include area code)

ADDRESS (P.O. Box or Street Address, City, State, Zip Code)
NAME AND TITLE OF LOCAL REPRESENTATIVE WHO CAN BE CONTACTED WHILE OPERATIONS ARE IN PROGRESS
ADDRESS–Business (P.O. Box or Street Address, City, State, Zip Code)

TELEPHONE NUMBER (include area code)

ADDRESS–Night, Weekend and Holiday (P.O. Box or Street Address, City, State, Zip Code)

TELEPHONE NUMBER (include area code)

WELL LOCATION DATA (attach plat)
COUNTY

TOWN

FIELD/POOL NAME (or “Wildcat”)

WELL NAME

WELL NUMBER

71/2 MINUTE QUAD NAME

QUAD SECTION

LOCATION DESCRIPTION

Decimal Latitude (NAD83)

Decimal Longitude (NAD83)

.
.
.
.
.

Surface
Kickoff
Top of Target Interval
Bottom of Target Interval
Bottom Hole
TVD

.
.
.
.
.

TMD
PROPOSED WELL DATA
PLANNED DATE OF COMMENCEMENT OF OPERATIONS

WELL TYPE

TYPE OF TOOLS

SURFACE ELEVATION (check how obtained)
ft.

PROPOSED TARGET FORMATION

Surveyed

Topo Map

Other

NAME OF PLANNED DRILLING CONTRACTOR (as registered with the Division)

WELL SPACING TYPE (subject to Article 23, Title 5)
Title 5

Non-Title 5

ACREAGE CONTROLLED IN UNIT
100%

TELEPHONE NUMBER (include area code)

PROPOSED SPACING DATA
TYPE OF UNIT (conforms to spacing under either Title 5 or Part 553)

NUMBER OF ACRES IN UNIT

Conforming
Non-Conforming
ACREAGE CONTROLLED IN BORE HOLE (throughout entire hole)

STATE LANDS (leased or unitized)

Yes

≥ 60% AND <100%

No

DEPARTMENT USE ONLY
APD NUMBER

BOND NUMBER

RECEIPT NUMBER

PERMIT FEE

API WELL IDENTIFICATION NUMBER

DATE ISSUED

31-

Final SGEIS 2015, Page A4-1

 85-12-5 (01/13)

APPLICATION FOR PERMIT TO DRILL, DEEPEN, PLUG BACK OR CONVERT

WELL NAME

WELL NUMBER

PAGE 2 OF 2

NAME OF OWNER

PROPOSED CASING AND CEMENTING DATA

Feature

Size
(in.)

Top
(ft.)

Bottom
(ft.)

Feature

Top
(ft.)

Bottom
(ft.)

Volume
(ft.3)

Weight
(lbs.)

New Pipe

Comments

C
A
S
I
N
G
D
A
T
A

Cement Class
(include excess)*

No. of
Sacks*

Weight
(PPG)

Yield
(ft.3/sx)

Vol.
(ft.3)*

Comments

C
E
M
E
N
T
D
A
T
A

AFFIRMATION AND ACKNOWLEDGMENT

A.

For use by individual:

By the act of signing this application:
(1) I affirm under penalty that the information provided in this application is true to the best of my knowledge and belief; and that I possess the right to access
property, and drill and/or extract oil, gas, or salt, by deed or lease, from the lands and site described in the well location data section of this application. I am aware that
any false statement made in this application is punishable as a Class A Misdemeanor under Section 210.45 of the Penal Law.
(2) I acknowledge that if the permit requested to be issued in consideration of the information and affirmations contained in this application is issued, as a condition to the
issuance of that permit, I accept full legal responsibility for all damage, direct or indirect, of whatever nature and by whomever suffered, arising out of the activity
conducted under authority of that permit; and agree to indemnify and hold harmless the State, its representatives, empl oyees, agents, and assigns for all claims, suits,
actions, damages, and costs of every name and description, arising out of or resulting from the permittee's undertaking of activities or operation and maintenance of the
facility or facilities authorized by the permit in compliance or non-compliance with the terms and conditions of the permit.

Printed or Typed Name of Individual

Signature of Individual
B.

Date

For use by organizations other than an individual:

By the act of signing this application:
(1) I affirm under penalty of perjury that I am
(title) of
(organization); that I am authorized by that organization to make this application; that this application was prepared by me or under my supervision and direction, is
true to the best of my knowledge and belief; and that the aforenamed organization possesses the right to access property, and drill and/or extract oil, gas, or salt by
deed or lease, from the lands and site described in the well location data section of this application. I am aware that any false statement made in this application is
punishable as a Class A Misdemeanor under Section 210.45 of the Penal Law.
(2)
(organization); acknowledges that if the permit requested to be issued in
consideration of the information and affirmations contained in this application is issued, as a condition to the issuance of that permit, it accepts full legal responsibility for all
damage, direct or indirect, of whatever nature and by whomever suffered, arising out of the activity conducted under authorit y of that permit; and agrees to indemnify
and hold harmless the State, its representatives, employees, agents, and assigns for all claims, from suits, actions, damages, and costs of every name and description,
arising out of or resulting from the permittee's undertaking of activities or operation and maintenance of the facility or facilities authorized by the permit in compliance or
noncompliance with the terms and conditions of the permit.

Printed or Typed Name of Authorized Representative

Signature of Authorized Representative

Final SGEIS 2015, Page A4-2

Date

 Appendix 5
EXISTING

Environmental Assessment Form
For Well Permitting
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

85-16-5 (8/14)--10b
NEW YORK STATE DEPARTMENT OF ENVIRONMENTAL CONSERVATION
DIVISION OF MINERAL RESOURCES

ENVIRONMENTAL ASSESSMENT FORM
Attachment to Drilling Permit Application
WELL NAME AND NUMBER
NAME OF APPLICANT

BUSINESS TELEPHONE NUMBER
(
)

ADDRESS OF APPLICANT
CITY/P.O.

STATE

ZIP CODE

DESCRIPTION OF PROJECT (Briefly describe type of project or action)

PROJECT SITE IS THE WELL SITE AND SURROUNDING AREA WHICH WILL BE DISTURBED DURING CONSTRUCTION OF SITE,
ACCESS ROAD, and PIT AND ACTIVITIES DURING DRILLING AND COMPLETION AT WELLHEAD.
(PLEASE COMPLETE EACH QUESTION--Indicate N.A., if not applicable)
LAND USE AND PROJECT SITE
1. Project Dimensions. Total Area of Project Site
sq. ft.
Approximate square footage for items below:
During Construction (sq. ft.)
After Construction (sq. ft.)
a. Access Road

(length x width)

b. Well Site

(length x width)

2. Characterize Project Site Vegetation and Estimate Percentage of Each Type Before Construction:
% Agricultural (cropland, hayland, pasture, vineyard, etc.)

% Forested

% Wetlands

% Meadow or Brushland (non agricultural)

% Non vegetated (rock, soil, fill)

3. Present Land Use(s) Within ¼ Mile of Project (Check all that apply)
Rural

Suburban

Industrial

Other

Forest

Urban

Agricultural

Commercial

Park/Recreation

4. How close is the nearest residence, building, or outdoor facility of any type routinely occupied by people at least part of the day?

ft.

Describe

ENVIRONMENTAL RESOURCES ON/NEAR PROJECT SITE
5. The presence of certain environmental resources on or near the project site may require additional permits, approvals or mitigation measures--Is any part
of the well site or access road located:
a. Over a primary or principal aquifer?
Yes
No

Not Known

b. Within 2,640 feet of a public water supply well?

Yes

No

c. Within 150 feet of a surface municipal water supply?

Yes

No

Not Known
Not Known

d. Within 150 feet of a lake, stream, or other public surface water body?

Yes

No

Not Known

e. Within an Agricultural District?

Yes

No

Not Known

f. Within a land parcel having a Soil and Water Conservation Plan?

Yes

No

Not Known

g. In a 100 year flood plain?

Yes

No

Not Known

h. In a regulated wetland or its 100 foot buffer zone?

Yes

No

Not Known

i. In a coastal zone management area?

Yes

No

Not Known

j. In a Critical Environmental Area?
k. Does the project site contain any species of animal life that are listed as threatened
or endangered?

Yes

No

Not Known

Yes

No

Not Known

Yes

No

Not Known

If yes, identify the species and source of information
l. Will proposed project significantly impact visual resources of statewide significance?
If yes, identify the visual resource and source of information

Final SGEIS 2015, Page A5-1

 CULTURAL RESOURCES
6. Are there any known archeological and/or historical resources which will be affected by
drilling operations?
7. Has the land within the project area been previously disturbed or altered (excavated,
landscaped, filled, utilities installed)?

Yes

No

Not Known

Yes

No

Not Known

If answer to Number 6 or 7 is yes, briefly describe

EROSION AND RECLAMATION PLANS
8. Indicate percentage of project site within: 0-10% slope

%

10-15% slope

9. Are erosion control measures needed during construction of the access road and well site?

%

greater than 15% slope
Yes

No

%
Not Known

If yes, describe and/or sketch on attached photocopy of plat

10. Will the topsoil which is disturbed be stockpiled for reclamation use?

Yes

No

11. Does the reclamation plan include revegetation?

Yes

No

Yes

No

Yes

No

Yes

No

Yes

No

If yes, what plant materials will be used?

12. Does the reclamation plan include restoration or installation of surface or subsurface
drainage features to prevent erosion or conform to a Soil and Water Conservation Plan?
If yes, describe

ACCESS ROAD SITING AND CONSTRUCTION
13. Are you going to use existing or common corridors when building the access road?
Locate access road on attached photocopy of plat.
DRILLING
14. Anticipated length of drilling operations?
days
WASTE STORAGE AND DISPOSAL
15. How will drilling fluids and stimulation fluids:
a. Be contained?
b. Be disposed of?
16. Will production brine be stored on site?
If yes:
How will it be stored?
How will it be disposed of?
17. Will the drill cuttings and pit liner be disposed of on site?
If yes, expected burial depth?

feet

ADDITIONAL PERMITS
18. Are any additional State, Local or Federal permits or approvals required for this project?

Yes
Date Application
Submitted

No
Date Application
Received

Stream Disturbance Permit (DEC)
Wetlands Permit (DEC or Local)
Floodplain Permit (DEC or Local)
Other

Printed or Typed Name and Affiliation of Preparer

Printed or Typed Name of Authorized Representative (See below note)

Signature of Authorized Representative (See below note)

Date

Note: The Authorized Representative must be listed in Box 7 of the Organizational Report on file with the Division of Mineral Resources

Final SGEIS 2015, Page A5-2

 Suggested Sources of Information for Division of Mineral Resources
Environmental Assessment Form
3.

LAND USE
Sources:

Local Planning Office
Town Supervisor’s Office
Town Clerk’s Office

5a.

PRIMARY OR PRINCIPAL AQUIFER
Sources:
Local unit of government
NYS Department of Health
NYSDEC, Division of Water--Regional Office
Availability of Water from Aquifers in New York State--United States Geological Survey
Availability of Water from Unconsolidated Deposits in Upstate New York--United States
Geological Survey

5b.

PUBLIC WATER SUPPLY
Sources:
Local unit of government
NYS Department of Health
NYS Atlas of Community Water Systems Sources, NYS Department of Health, 1982
Atlas of Eleven Selected Aquifers in New York State, United States Geological Survey, 1982

5c.

AGRICULTURAL DISTRICT INFORMATION
Sources:
Cooperative Extension
DEC, Division of Lands and Forests
NYS Department of Agriculture and Markets
DEC, Division of Environmental Permits--Regional Office
DEC, Division of Mineral Resources--Regional Office

5f.

SOIL AND WATER CONSERVATION PLAN
Sources:
Landowner
County Soil and Water Conservation District Office

5g.

100 YEAR FLOOD PLAIN
Sources:
DEC Division of Water
DEC, Division of Environmental Permits--Regional Office
DEC, Division of Mineral Resources--Regional Office

5h.

WETLANDS
Sources:

DEC, Division of Fish and Wildlife--Regional Office
DEC, Division of Mineral Resources--Regional Office

5i.

COASTAL ZONE MANAGEMENT AREAS
Sources:
Local unit of government
NYS Department of State, Coastal Management Program
DEC, Division of Water (maps)
DEC, Division of Environmental Permits--Regional Office

5k.

THREATENED OR ENDANGERED SPECIES
Sources:
DEC, Natural Heritage Program--Albany
DEC, Division of Environmental Permits--Regional Office

6.

ARCHEOLOGICAL OR HISTORIC RESOURCES
Sources:
NYS Office of Parks, Recreation and Historic Preservation circles and squares map
DEC, Division of Environmental Permits--Regional Office

18.

ADDITIONAL PERMITS NEEDED
Sources:
DEC, Division of Environmental Permits--Regional Office
DEC, Division of Mineral Resources--Regional Office
NYS Office of Business Permits

Final SGEIS 2015, Page A5-3

 This page intentionally left blank.

Appendix 6
PROPOSED
Environmental Assessment Form
Addendum
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

PROPOSED EAF ADDENDUM REQUIREMENTS
FOR HIGH-VOLUME HYDRAULIC FRACTURING
REQUIRED INFORMATION
• Minimum depth and elevation of top of objective formation or zone for entire length of
wellbore
•

Estimated maximum depth and elevation of bottom of potential fresh water, and basis for
estimate (water well information, other well information, previous drilling at pad, published
or private reports, etc.)

•

Identification of proposed fracturing service company and additive products, by product
name and purpose/type
o Documentation of the applicant’s evaluation of available alternatives for the proposed
additive products that are efficacious but which exhibit reduced aquatic toxicity and
pose less risk to water resources and the environment

•

Proposed volume of water and each additive product to be used in hydraulic fracturing

•

Proposed % by weight of water, proppants and each additive

•

Water source for hydraulic fracturing
o If a newly proposed surface water source (not previously approved by the Department
as part of a well permit application):
 Type of withdrawal (stream, lake, pond, groundwater, etc.)
 Location of water withdrawal point, status of RBC approval if applicable
 List and location of all private water wells within 500 feet of the proposed
water withdrawal point
 For proposed withdrawals from lakes and ponds:
• Estimates of the maximum change in storage resulting from the
proposed withdrawals, including estimates of inflow into the water
body, precipitation onto water surface, existing and proposed water
withdrawals, evaporation from water surface, and releases from water
body
 For proposed groundwater withdrawals:
• Identification of and shortest distance to any wetland within 500 feet
of the proposed withdrawal point
• Results of pump testing as referenced in the SGEIS, including
evaluation of any potential influence on wetland(s) within 500 feet
 Indicate if an Article 15 permit is required and status
 Size of drainage area above withdrawal point (in mi2)
 Indicate whether there is a USGS gage on the stream; if yes:
• Distance to stream gage
• Upstream or downstream of stream gage
• Changes in stream flow (e.g., other withdrawals, diversions, tributary
input) between gage and withdrawal point
• Years of stream gage data available and period of record

Final SGEIS 2015, Page A6-1

 PROPOSED EAF ADDENDUM REQUIREMENTS
FOR HIGH-VOLUME HYDRAULIC FRACTURING
o If a previously proposed or Department-approved surface water source:
 API # of well permit application associated with previous proposal or
approval
•

Scaled distance from surface location of well and closest edge of well pad to:
o Any known water supply reservoir, river or stream intake, water well or domesticsupply spring within 2,640 feet, including public or private wells, community or noncommunity systems
o Any primary or principal aquifer boundary, perennial or intermittent stream, wetland,
storm drain, lake or pond within 660 feet
o All residences, occupied structures or places of assembly within 1,320 feet

•

Capacity of rig fueling tank(s) and distance to:
o Any public or private water well, domestic-supply spring, reservoir, perennial or
intermittent stream, storm drain, wetland, lake or pond within 500 feet of the planned
location(s) of the fueling tank(s)

•

Available information about water wells and domestic-supply springs within 2,640 feet
o Well name and location
o Distance from proposed surface location of well
o Shortest distance from proposed well pad
o Shortest distance from proposed centralized flowback water impoundment
o Well depth
o Well’s completed interval
o Public or private supply
o Community or non-community system (see NYSDOH definitions)
o Type of facility or establishment if not a residence

•

Identification of any well listed in Department’s Oil & Gas Database, or any other abandoned
well identified by property owners or tenants, within the spacing unit of the proposed well
and/or within 1 mile (5,280 feet) of the proposed well location. For each well identified,
provide the following information:
o Well name and API Number
o Distance from proposed surface location of well to surface location of existing well
o Well Type
o Well Status
o Well Orientation
o Quantity and type of any freshwater, brine, oil or gas encountered during drilling, as
recorded on the Department’s Well Drilling and Completion Report

•

Information about the planned construction and capacity of the reserve pit, if any, and an
indication of the timing of the use of a closed-loop tank system (e.g., surface, intermediate
and/or production hole)

•

Information about the number and individual and total capacity of receiving tanks for
flowback water
Final SGEIS 2015, Page A6-2

 PROPOSED EAF ADDENDUM REQUIREMENTS
FOR HIGH-VOLUME HYDRAULIC FRACTURING
•

If proposed flowback vent/flare stack height is less than 30 feet, then documentation that
previous drilling at the pad did not encounter H2S is required

•

Description of planned public access restrictions, including physical barriers and distance to
edge of well pad

•

Identify the EPA Tiers of the drilling and hydraulic fracturing engines used, if these use
gasoline or diesel fuel. If particulate traps or Selective Catalytic Reduction (SCR) are not
used, provide a description of other control measures planned to reduce particulate matter
and NOx emissions during the drilling and hydraulic fracturing processes

•

If condensate tanks are to be used, provide their capacity and the vapor recovery system to be
used

•

If a wellhead compressor is used, provide its size in horsepower. Describe the control
equipment used for NOx

•

If a glycol dehydrator is to be used at the well pad, provide its stack height and the capacity
of glycol to be used on an annual basis

•

Information on the status of a sales line and interconnecting gathering line to the well or
multi-well pad (i.e., is there currently a line in place or is one expected to be in place prior to
conducting hydraulic fracturing operations to facilitate a Reduced Emissions Completion
[REC])
o If REC will not be used, the following must be provided
 an estimate of how much total gas (MMcf) will be vented and flared during
flowback
 an estimate of how much total gas (MMcf) was previously vented and flared
during flowback on the same well pad in the previous 12 months

•

Well information with respect to local planning documents
o Identify whether the location of the well pad, or any other activity under the
jurisdiction of the Department, conflicts with local land use laws or regulations, plans
or policies
o Identify whether the well pad is located in an area where the affected community has
adopted a comprehensive plan or other local land use plan and whether the proposed
action is inconsistent with such plan(s)

REQUIRED ATTACHMENTS
• Scaled, stamped well plat showing the following:
o Plan view of wellbore including surface and bottom-hole locations
o Well pad close-up showing placement of fueling tank(s), reserve pit and receiving
tanks for flowback water

Final SGEIS 2015, Page A6-3

 PROPOSED EAF ADDENDUM REQUIREMENTS
FOR HIGH-VOLUME HYDRAULIC FRACTURING
o Vertical section of wellbore showing the land surface elevation and wellbore
elevation with an indication of the minimum depth of the wellbore within the
objective formation or zone as required above
•

A Material Safety Data Sheet (MSDS) for each additive product proposed for use in
hydraulic fracturing, if not already on file with the Department

•

Topographic map of area within at least 2,640 feet of surface location showing:
o above features and scaled distances
o location and orientation of well pad
o location of access road
o location of any flowback water pipelines or conveyances

•

Evidence of diligent efforts by the well operator to determine the existence of public or
private water wells and domestic-supply springs within one half-mile (2,640 feet) of any
proposed drilling location or centralized flowback water impoundment if proposed
o List of municipal officials contacted for water well information and printed copies of
responses
o List of property owners and tenants contacted for water well information
o List of adjacent lessees contacted for water well information
o Printed results of EPA SDWIS search
(http://oaspub.epa.gov/enviro/sdw_form_v2.create_page?state_abbr=NY)
o Printed results of Department Water Well search
(http://www.dec.ny.gov/cfmx/extapps/WaterWell/index.cfm?view=searchByCounty)

•

Evidence of diligent efforts by the well operator to determine the existence and condition of
abandoned wells within the proposed spacing unit and/or within one mile of the proposed
well location
o Printed results of Department Oil & Gas database search
o List of property owners and tenants contacted for abandoned well information

•

For a newly proposed water withdrawal, topographic map showing:
o The location of the proposed withdrawal
o All private water wells within 500 feet of the proposed water withdrawal point
o For proposed surface water withdrawals:
 Drainage area above the withdrawal point
o For proposed groundwater withdrawals:
 Identification of and shortest distance to any Department-regulated wetland
within 500 feet of the proposed withdrawal point

•

Invasive Species Management Plan that includes:
o Survey of the entire well site, documenting the presence, location, and identity of any
invasive plant species;
o Specific protocols or best management practices for preventing the spread or introduction
of invasive species at the site;
o Specific protocols for the restoration of native plant cover on the site; and
Final SGEIS 2015, Page A6-4

 PROPOSED EAF ADDENDUM REQUIREMENTS
FOR HIGH-VOLUME HYDRAULIC FRACTURING
o Identification of any Certified Pesticide Applicator, if applicable.
•

A Partial Site Reclamation Plan that describes the methods for partially reclaiming the site
after well completion. Partial reclamation shall be compatible with sound environmental
management practices and minimize negative environmental impacts.

•

A description of methods for final reclamation of the well site following plugging of all the
wells on the well pad. Reclamation methods shall be compatible with sound environmental
management practices and minimize negative environmental impacts from the well pad.

•

Proposed fluid disposal plan, pursuant to 6 NYCRR 554.1(c)(1)
o Planned transport of flowback water and production brine off of well pad – trucking
or piping
 If piping, describe construction including size, materials, leak prevention and
spill control measures
o Planned disposition of flowback water and production brine – treatment facility,
disposal well, reuse on same well pad, reuse on another well pad, centralized
flowback surface water impoundment, centralized tank facility, or other (describe)
 If a treatment facility in NY:
• Name, owner/operator, location
• SPDES permit # and date if applicable
• If a POTW, date of Department approval to receive flowback water
(attach a copy of approval notification)
• Brief description of facility and treatment if not a POTW
 If a disposal well in NY:
• SPDES permit # and date
• EPA UIC permit # and date
 If a centralized tank facility in New York:
• Location, affirmation of ownership or permission
• Certification of compliance with 360-6.3

•

Proposed cuttings disposal plan for any drilling requiring cuttings to be disposed of off-site
including at a landfill.
o Planned disposition of cuttings – landfill or other (describe)
 If a landfill in NY:
• Name, owner/operator, location
• Part 360 permit # and date if applicable

•

Proposed blow-out preventer (BOP) use and test plan for all drilling and completion
operations including:
o Pressure rating of any:
 Annular preventer
 Rams including a description of type and number of rams
 Choke manifold and connecting line (from BOP to choke manifold)

Final SGEIS 2015, Page A6-5

 PROPOSED EAF ADDENDUM REQUIREMENTS
FOR HIGH-VOLUME HYDRAULIC FRACTURING
o Timing and frequency of testing and/or visual inspection of BOP and related
equipment including any scheduled retesting of equipment. Test pressure(s) and
duration of test(s) including an explanation as to how the test pressure was
determined
o Test pressure(s) and timing for any internal pressure testing of surface, intermediate
and production casing strings, and duration of test including an explanation as to how
the test pressure was determined
o Test pressure (psi/ft) and anticipated depth (TVD-ft) of any surface and/or
intermediate casing seat integrity tests
 If a casing seat integrity test will not be conducted on a casing string with a
BOP installed on it, an explanation must be provided why such a test is not
required and how any flow will be managed
o System for recording, documenting and retaining the results of all pressure tests and
inspections, and making such available to the Department
o Copy of the operator’s well control barrier policythat identifies acceptable barriers to
be used during identified operations
o Minimum distance from well for remote actuator (powered by a source other than rig
hydraulics)
•

Transportation plan developed by a NYS-licensed Professional Engineer, that specifies
proposed routes and includes a road condition assessment.

•

Noise mitigation plan, including any proposed mitigation measures for any occupied
structure within 1,000 feet.

•

If a new well pad is proposed in a Forest or Grassland Focus Area and involves disturbance
in a contiguous forest patch of 150 acres or more in size or a contiguous grassland patch of
30 acres or more in size, then the Applicant should not submit this EAF or a well permit
application prior to conducting a site-specific ecological assessment in accordance with a
detailed study plan that has been approved by the Department. The need and plan for an
ecological assessment should be determined in consultation with the Department and will
consider information such as existing site conditions, existing covertype and ongoing and
historical land management activities. The completed ecological assessment must be
attached to this EAF and must include, at a minimum:
o a compilation of historical information on use of the area by forest interior birds or
grassland birds;
o results of pre-disturbance biological studies, including a minimum of one year of field
surveys at the site to determine the current extent, if any, of use of the site by forest
interior birds or grassland birds;
o an evaluation of potential impacts on forest interior or grassland birds from the
project;
o additional mitigation measures proposed by the applicant; and
o protocols for monitoring of forest interior or grassland birds during the construction
phase of the project and for a minimum of two years following well completion.

Final SGEIS 2015, Page A6-6

 PROPOSED EAF ADDENDUM REQUIREMENTS
FOR HIGH-VOLUME HYDRAULIC FRACTURING
REQUIRED AFFIRMATIONS
• Any surface water withdrawal associated with this well pad will only occur when flow is
above the appropriate threshold as described in the SGEIS
•

Applicable FIRM and Flood Boundary and Floodway maps consulted, and proposed well pad
and access road are not within a mapped100-year floodplain

•

Baseline residential well sampling, analysis and ongoing monitoring will be conducted and
results shared with property owner as described in SGEIS and permit conditions

•

Unless otherwise required by private lease agreement, the access road will be located as far
as practical from occupied structures, places of assembly and unleased property

•

HVHF GP authorization for stormwater discharges will be obtained prior to site disturbance

•

Operator will prepare and adhere to the following site plans, which will be available to the
Department upon request and available on-site to Department inspector while activities
addressed by the plan are occurring:
• a visual impacts mitigation plan consistent with the SGEIS
• a noise impacts mitigation plan consistent with the SGEIS
• a greenhouse gas impacts mitigation plan consistent with the SGEIS
• an invasive species mitigation plan which includes:
 the best management practices listed in the SGEIS and
 seasonally appropriate site-specific and species-specific physical and
chemical control methods (e.g., digging to remove all roots, cutting to the
ground, applying herbicides to specific plant parts such as stems or
foliage, etc.) based on the invasive species survey submitted with the EAF
Addendum
• an acid rock drainage (ARD) mitigation plan consistent with the SGEIS for on-site
burial of Marcellus Shale cuttings from horizontal drilling in the Marcellus Shale if
the operator elects to bury these cuttings

•

Operator will utilize alternative hydraulic fracturing additive products that exhibit reduced
aquatic toxicity and pose less risk to water resources and the environment, unless
demonstrated to DMN’s satisfaction that they are not equally effective or feasible

•

Operator will prepare and adhere to an emergency response plan (ERP) consistent with the
SGEIS that will be available on-site during any operation from well spud (i.e., first instance
of driving pipe or drilling) through well completion. A list of emergency contact numbers
for the area in which the well site is located must be included in the ERP and the list must be
prominently displayed at the well site during operations conducted under this permit

•

Operator will adhere to all well permit conditions and approved plans, including requirement
for Department approval prior to making any change

Final SGEIS 2015, Page A6-7

 PROPOSED EAF ADDENDUM REQUIREMENTS
FOR HIGH-VOLUME HYDRAULIC FRACTURING
•

Operator will adhere to best management practices for reducing direct impacts to terrestrial
habitats and wildlife consistent with the SGEIS (see Section 7.4.1.1)

ADDITIONAL SUBMISSION REQUIRED PRIOR TO SITE DISTURBANCE
• Copy of any road use agreement between the operator and local municipality
ADDITIONAL SUBMISSION REQUIRED AT LEAST 48 HOURS PRIOR TO WELL
SPUD
• Copy of the ERP in electronic form

Final SGEIS 2015, Page A6-8

 Appendix 7
Sample Drilling Rig Specifications
Provided by Chesapeake Energy
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

ATTACHMENT A
Rig Specifications
Example #1
National Cabot 900
Working Depth: 12,000’
DRAWWORKS:

National Model 2346 – Mechanical – Grooved for 1 1/8’’ drilling line.
Air operated, water cooled Eaton Assist Brake

ENGINES:

2 - Cat C-15 (475HP ea.) with Allison Transmissions

MAST:

NOV - 117’ - 350,000 SHL on 8 lines

SUBSTRUCTURE:

NOV - 18’ Floor Height /15’ Working Height

TRAVELING
EQUIPMENT:

IDECO UTB – 265 Ton Block and Hook

ROTARY TABLE:

27 ½’’ with 440,000# capacity

TUBULARS:

12,000’ - S-135 - 4 1/2’’x 16.60# per foot w/ XH connections
18 - 6 ½’’ collars with NC46 connections

MUD PUMPS:

2 – National 9-P-100 with Cat 3508 Mechanicals (935HP ea.)

MUD SYSTEM:

3 - Tank, 900 BBL total

SOLIDS CONTROL
EQUIPMENT:

Shakers:
Desander:
Desilter:
Agitators:

BOP EQUIPMENT:

1 - Shaffer LXT - 11” 5M - Double Ram
1 – Shaffer Spherical - 11” 5M - Annular

CLOSING UNIT:

Koomey - 6 Station - 160 Gallon; 3000 psi

CHOKE MANIFOLD:

3’’ x 4’’ - 5M, 1 Hydraulic Choke and 1 Manual Choke

GENERATORS:

2 - Caterpillar 545 kW, Powered by 2 Cat C-18’s

AUXILARY
EQUIPMENT:

Water Tank: 400 BBL
Fuel Tank: 10,000 Gallons

SPECIAL TOOLS:

2 - Braden PD12C Hydraulic Hoist
Hydraulic Pipe Spinner
Oil Works OWI-1000 Wire line with 12,000’ of wire

2 – NOV D285P-LP
Brandt - 2 - 10” Cones
Brandt - 12 - 4” Cones
6 – Brandt with 36’’ Impellers

Final SGEIS 2015, Page A7-1

 Rig Specifications
Example #2
610 Mechanical 750 HP
Working Depth: 14,000’
DRAWWORKS:

National 610 Mechanical
Wichita 325 Air Brake

ENGINES:

2 – Caterpillar C-18’s, 600 HP Each

MAST:

Dreco 142’ 550,000 SHL on 10 Lines

SUBSTRUCTURE:

Dreco 20’ Box on Box

TRAVELING
EQUIPMENT:

Block-Hook: Ideco UTB-265-5-36

ROTARY TABLE:

National C-275

COMPOUND:

National 2 Engines

TORQUE CONVERTERS:

2 – National C195

MUD PUMPS:
HP

2 – National 9-P-100, Independent Drive Cummins QSK38, 920

MUD SYSTEM:

2 – Tank, 750 BBL total w/100 BBL Premix

SOLIDS CONTROL
EQUIPMENT:

Shakers:
Desander:
Desilter:

BOP EQUIPMENT:

1 – Shaffer LWS Type 11” 5M
1 – Shaffer Spherical Type 11: 5M

CLOSING UNIT:

Koomey 6 Station 180 Gallon; 1 Air and 1 Electrical Pump

CHOKE MANIFOLD:

4’’ x 3’’ 5M, 2 Adjustable Chokes

GENERATORS:

2 – Cat 545 kW, Powered by 2 Cat C-18’s

AUXILARY
EQUIPMENT:

Water Tank: 500 BBL
Fuel Tank: 12,000 Gallons

SPECIAL TOOLS:

ST-80 Iron Roughneck
Pipe Spinner: Hydraulic
Auto Driller: Satellite
Totco EDR (Rental)
Separator/Trip Tank Combo (Rental)
Hoists: 1 – Thern 2.5A Air Hoist
1 - Braden PD12C Hydraulic Hoist

2 – National Model DLMS-285P
National with 2 - 10” Cones
National with 16 - 4” Cones

Final SGEIS 2015, Page A7-2

 Rig Specifications
Example #3
SpeedStar 185K -- 515 HP
Working Depth: 8,000’
ENGINE:

1 – Caterpillar C-15 with Allison Transmission

MAST:

SpeedStar – 61’ – 185,000 LB SHL
Setback Capacity of 7,000’ – 3.5” Drill Pipe

SUBSTRUCTURE:
MUD PUMP:

Box Type – 7’6” Working Height

1 – MP5

MUD SYSTEM: 2 – Tank, 600 BBL
BOP EQUIPMENT:

11” x 3M Annular

CLOSING UNIT:

Townsend 4 Station, 80 Gallon

CHOKE MANIFOLD:

3’’ x 3’’ 5K with 1 Hydraulic Choke

GENERATORS:

2 – Onan 320 kW with Cummins Engines

DRILL PIPE:

7,500’ OF 3.5” 13.30 LB/FT with IF Connections

DRILL COLLARS:

12 – 6 ½”

AIR SYSTEM:

3 – Ingersoll Rand 1170/350 Air Compressors
2 – Single Stage Boosters

AUXILARY
EQUIPMENT:

Water Tank: 250 BBL
Fuel Tank: 3,500 Gallons

SPECIAL TOOLS:

2 – Braden PD12C Hydraulic Tub Winches
Myers 35GPM Soap Pump
Martin Decker Geolograph
Wireline Unit with 10,000’ of Line

Final SGEIS 2015, Page A7-3

 This page intentionally left blank.

Appendix 8
EXISTING

Casing and Cementing Practices
Required for All Wells in NY
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

New York State Department of Environmental Conservation
Casing and Cementing Practices
SURFACE CASING
1.  

The diameter of the drilled surface casing hole shall be large enough to allow the running of centralizers
in recommended hole sizes.
RECOMMENDED CENTRALIZER-HOLE SIZE COMBINATIONS
Centralizer Size
Inches

Minimum Hole Sizes
Inches

Minimum Clearance
Inches

4-1/2

6-1/8

1-5/8

5-1/2

7-3/8

1-7/8

6-5/8

8-1/2

1-7/8

7

8-3/4

1-3/4

8-5/8

10-5/8

2

9-5/8

12-1/4

2-5/8

13-3/8

17-1/2

4-1/8

NOTE: (1)  If a manufacturer's specifications call for a larger hole size than indicated in the above table, then the
manufacturer's specs take precedence.
(2) Check with the appropriate regional office for sizes not listed above.

2.  

Surface casing shall extend at least 75 feet beyond the deepest fresh water zone encountered or 75 feet into
competent rock (bedrock), whichever is deeper, unless otherwise approved by the Department. However, the
surface pipe must be set deeply enough to allow the BOP stack to contain any formation pressures that may be
encountered before the next casing is run.

3.  

Surface casing shall not extend into zones known to contain measurable quantities of shallow gas. In the event
that such a zone is encountered before the fresh water is cased off, the operator shall notify the Department and,
with the Department's approval, take whatever actions are necessary to protect the fresh water zone(s).

4.  

All surface casing shall be a string of new pipe with a mill test of at least 1,100 pounds per square inch (psi),
unless otherwise approved. Used casing may be approved for use, but must be pressure tested before drilling out
the casing shoe or, if there is no casing shoe, before drilling out the cement in the bottom joint of casing. If plain
end pipe is welded together for use, it too must be pressure tested. The minimum pressure for testing used casing
or casing joined together by welding, shall be determined by the Department at the time of permit application. The
appropriate Regional Mineral Resources office staff will be notified six hours prior to making the test. The results
will be entered on the drilling log.

5.  

Centralizers shall be spaced at least one per every 120 feet; a minimum of two centralizers shall be run on surface
casing. Cement baskets shall be installed appropriately above major lost circulation zones.

6.  

Prior to cementing any casing strings, all gas flows shall be killed and the operator shall attempt to establish
circulation by pumping the calculated volume necessary to circulate. If the hole is dry, the calculated volume
would include the pipe volume and 125% of the annular volume. Circulation is deemed to have been
established once fluid reaches the surface. A flush, spacer or extra cement shall be used to separate the
cement from the bore hole spacer or extra cement shall be used to separate the cement from the bore hole
fluids to prevent dilution. If cement returns are not present at the surface, the operator may be required to run a
log to determine the top of the cement.

Final SGEIS 2015, Page A8-1

 7.

The pump and plug method shall be used to cement surface casing, unless approved otherwise by the
Department. The amount of cement will be determined on a site-specific basis and a minimum of 25% excess
cement shall be used, with appropriate lost circulation materials, unless other amounts of excesses are approved
or specified by the Department.

8.

The operator shall test or require the cementing contractor to test the mixing water for pH and temperature prior
to mixing the cement and to record the results on the cementing ticket.

9.

The cement slurry shall be prepared according to the manufacturer's or contractor's specifications to minimize
free water content in the cement.

10.

After the cement is placed and the cementing equipment is disconnected, the operator shall wait until the
cement achieves a calculated compressive strength of 500 psi before the casing is disturbed in any way. The
waiting-on-cement (WOC) time shall be recorded on the drilling log.

11.

When drive pipe (conductor casing) is left in the ground, a pad of cement shall be placed around the well bore to
block the downward migration of surface pollutants. The pad shall be three feet square or, if circular, three feet
in diameter and shall be crowned up to the drive pipe (conductor casing), unless otherwise approved by the
Department.
WHEN REQUESTED BY THE DEPARTMENT IN WRITING, EACH OPERATOR MUST SUBMIT CEMENT
TICKETS AND/OR OTHER DOCUMENTS THAT INDICATE THE ABOVE SPECIFICATIONS HAVE BEEN
FOLLOWED.
THE CASING AND CEMENTING PRACTICES ABOVE ARE DESIGNED FOR TYPICAL SURFACE CASING
CEMENTING. THE DEPARTMENT WILL REQUIRE ADDITIONAL MEASURES FOR WELLS DRILLED IN
ENVIRONMENTALLY OR TECHNICALLY SENSITIVE AREAS (i.e., PRIMARY OR PRINCIPAL AQUIFERS).
THE DEPARTMENT RECOGNIZES THAT VARIATIONS TO THE ABOVE PROCEDURES MAY BE
INDICATED IN SITE SPECIFIC INSTANCES. SUCH VARIATIONS WILL REQUIRE THE PRIOR APPROVAL
OF THE REGIONAL MINERAL RESOURCES OFFICE STAFF.

INTERMEDIATE CASING
Intermediate casing string(s) and the cementing requirements for that casing string(s) will be reviewed and
approved by Regional Mineral Resources office staff on an individual well basis.

PRODUCTION CASING
12.

The production casing cement shall extend at least 500 feet above the casing shoe or tie into the previous
casing string, whichever is less. If any oil or gas shows are encountered or known to be present in the area, as
determined by the Department at the time of permit application, or subsequently encountered during drilling,
the production casing cement shall extend at least 100 feet above any such shows. The Department may allow
the use of a weighted fluid in the annulus to prevent gas migration in specific instances when the weight of the
cement column could be a problem.

13.

Centralizers shall be placed at the base and at the top of the production interval if casing is run and extends
through that interval, with one additional centralizer every 300 feet of the cemented interval. A minimum of 25%
excess cement shall be used. When caliper logs are run, a 10% excess will suffice. Additional excesses
may be required by the Department in certain areas.

14.

The pump and plug method shall be used for all production casing cement jobs deeper than 1500 feet. If the
pump and plug technique is not used (less than 1500 feet), the operator shall not displace the cement closer
than 35 feet above the bottom of the casing. If plugs are used, the plug catcher shall be placed at the top of the

Final SGEIS 2015, Page A8-2

 lowest (deepest) full joint of casing.
15.  

The casing shall be of sufficient strength to contain any expected formation or stimulation pressures.

16.  

Following cementing and removal of cementing equipment, the operator shall wait until a compressive strength
of 500 psi is achieved before the casing is disturbed in any way. The operator shall test or require the cementing
contractor to test the mixing water for pH and temperature prior to mixing the cement and to record the results on
the cementing tickets and/or the drilling log. WOC time shall be adjusted based on the results of the test.

17.  

The annular space between the surface casing and the production string shall be vented at all times. If the
annular gas is to be produced, a pressure relief valve shall be installed in an appropriate manner and set at a
pressure approved by the Regional Mineral Resources office.
WHEN REQUESTED BY THE DEPARTMENT IN WRITING, EACH OPERATOR MUST SUBMIT CEMENT TICKETS
AND/OR OTHER DOCUMENTS THAT INDICATE THE ABOVE SPECIFICATIONS HAVE BEEN FOLLOWED.
THE CASING AND CEMENTING PRACTICES ABOVE ARE DESIGNED FOR TYPICAL PRODUCTION CASING/
CEMENTING. THE DEPARTMENT WILL REQUIRE ADDITIONAL MEASURES FOR WELLS DRILLED IN
ENVIRONMENTALLY OR TECHNICALLY SENSITIVE AREAS (i.e., PRIMARY OR PRINCIPAL AQUIFERS).
THE DEPARTMENT RECOGNIZES THAT VARIATIONS TO THE ABOVE PROCEDURES MAY BE INDICATED IN SITE
SPECIFIC INSTANCES. SUCH VARIATIONS WILL REQUIRE THE PRIOR APPROVAL OF THE REGIONAL MINERAL
RESOURCES OFFICE.

Final SGEIS 2015, Page A8-3

 This page intentionally left blank.

Appendix 9
EXISTING
Fresh Water Aquifer Supplementary
Permit Conditions Required for Wells Drilled in
Primary and Principal Aquifers
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

FRESH WATER AQUIFER SUPPLEMENTARY PERMIT CONDITIONS

Operator:
API Number:

Well Name:

1. 

All pits must be lined and sized to fully contain all drilling, cementing and stimulation fluids plus any
fluids as a result of natural precipitation. Use of these pits for any other purpose is prohibited.

2. 

All fluids must be contained on the site and properly disposed. If operations are suspended and the
site is left unattended at any time, pit fluids must be removed from the site immediately. After the
cessation of drilling and/or stimulation operations, pit fluids must be removed within 7 days. Disposal
of fluids must be undertaken by a waste transporter with an approved 6 NYCRR Part 364 permit.

3. 

Any hole drilled for conductor or surface casing (i.e., “water string”) must be drilled on air, fresh
water, or fresh water mud. For any holes drilled with mud, techniques for removal of filter cake (e.g.,
spacers, additional cement, appropriate flow regimes) must be considered when designing any primary
cement job on conductor and surface casing.

4. 

If conductor pipe is used, it must be run in a drilled hole and it must be cemented back to surface by
circulation down the inside of the pipe and up the annulus, or installed by another procedure approved
by this office. Lost circulation materials must be added to the cement to ensure satisfactory results.
Additionally, at least two centralizers must be run with one each at the shoe and at the middle of the
string. In the event that cement circulation is not achieved, cement must be grouted (or squeezed)
down from the surface to ensure a complete cement bond. In lieu of or in combination with such
grouting or squeezing from the surface, this office may require perforation of the conductor casing and
squeeze cementing of perforations. This office must be notified _______ hours prior to cementing
operations and cementing cannot commence until a state inspector is present.

5. 

A surface casing string must be set at least 100' below the deepest fresh water zone and at least 100'
into bedrock. If shallow gas is known to exist or is anticipated in this bedrock interval, the casing
setting depth may be adjusted based on site-specific conditions provided it is approved by this office.
There must be at least a 2½" difference between the diameters of the hole and the casing (excluding
couplings) or the clearance specified in the Department’s Casing and Cementing Practices, whichever
is greater. Cement must be circulated back to the surface with a minimum calculated 50% excess.
Lost circulation materials must be added to the cement to ensure satisfactory results. Additionally,
cement baskets and centralizers must be run at appropriate intervals with centralizers run at least every
120'. Pipe must be either new API graded pipe with a minimum internal yield pressure of 1,800 psi
or reconditioned pipe that has been tested internally to a minimum of 2,700 psi. If reconditioned pipe
is used, an affidavit that the pipe has been tested must be submitted to this office before the pipe is run.
This office must be notified _______ hours prior to cementing operations and cementing cannot
commence until a state inspector is present.

Final SGEIS 2015, Page A9-1

 6. 

If multiple fresh water zones are known to exist or are found or if shallow gas is present, this office
may require multiple strings of surface casing to prevent gas intrusion and/or preserve the hydraulic
characteristics and water quality of each fresh water zone. The permittee must immediately inform
this office of the occurrence of any fresh water or shallow gas zones not noted on the permittee’s
drilling application and prognosis. This office may require changes to the casing and cementing plan
in response to unexpected occurrences of fresh water or shallow gas, and may also require the
immediate, temporary cessation of operations while such alterations are developed by the permittee
and evaluated by the Department for approval.

7. 

In the event that cement circulation is not achieved on any surface casing cement job, cement must be
grouted (or squeezed) down from the surface to ensure a complete cement bond. This office must be
notified _______ hours prior to cementing operations and cementing cannot commence until a state
inspector is present. In lieu of or in combination with such grouting or squeezing from the surface, this
office may require perforation of the surface casing and squeeze cementing of perforations. This office
may also require that a cement bond log and/or other logs be run for evaluation purposes. In addition,
drilling out of and below surface casing cannot commence if there is any evidence or indication of flow
behind the surface casing until remedial action has occurred. Alternative remedial actions from those
described above may be approved by this office on a case-by-case basis provided site-specific
conditions form the basis for such proposals.

8. 

This office must be notified _______ hours prior to any stimulation operation. Stimulation may
commence without the state inspector if the inspector is not on location at the time specified during
the notification.

9. 

The operator must complete the “Record of Formations Penetrated” on the Well Drilling and
Completion Report providing a log of formations, both unconsolidated and consolidated, and all water
and gas producing zones.

10. 

If the well is a producer, holding tanks with water-tight diking capable of retaining 1½ times the
capacity of the tank must be installed for the containment of oil, brine and other production fluids.
Disposal of fluids must only be undertaken by a waste transporter with an approved 6 NYCRR Part
364 permit.

11. 

Any deviation from the above conditions must be approved by the Department prior to making
a change.

Final SGEIS 2015, Page A9-2

 Appendix 10
PROPOSED
Supplementary Permit Conditions
For High-Volume Hydraulic Fracturing
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing

Note: The operator must comply with all provisions of Attachment A and Attachment B as noted at
the end of this document, along with Attachment C when applicable.
Planning and Local Coordination
1) All operations authorized by this permit must be conducted in accordance with the following
site-specific plans prepared by the operator, available to the Department upon request, and
available on-site to a Department inspector while activities addressed by the plan are taking
place:
a) a visual impacts mitigation plan consistent with the SGEIS; and
b) a greenhouse gas emissions impacts mitigation plan consistent with the SGEIS.
2) An emergency response plan (ERP) consistent with the SGEIS must be prepared by the well
operator and be available on-site during any operation from well spud (i.e., first instance of
driving pipe or drilling) through well completion. A list of emergency contact numbers for
the area in which the well site is located must be included in the ERP and the list must be
prominently displayed at the well site during operations conducted under this permit.
Further, a copy of the ERP in electronic form must be provided to this office at least 3 days
prior to well spud.
3) The county emergency management office (EMO) must be notified of the well’s location
including latitude and longitude (NAD 83) as follows:
a) prior to spudding the well;
b) first occurrence of flaring while drilling;
c) prior to high-volume hydraulic fracturing, and;
d)

prior to flaring for well clean-up, treatment or testing. A flare permit from the
Department is required prior to any flaring operation for well clean-up, treatment or
testing.

A record of the type, date and time of any notification provided to the EMO must be
maintained by the operator and made available to the Department upon request. In counties
without an EMO, the local fire department must be notified as described above.
4) The operator shall adhere to the Department-approved transportation plan which shall be
incorporated by reference into this permit. In addition, issuance of this permit does not
provide relief from any local requirements authorized by or enacted pursuant to the New
York State Vehicle and Traffic Law. Prior to site disturbance, the operator shall submit to the
Department a copy of any road use agreement between the operator and municipality.
5) Prior to site disturbance (for a new well pad) or spud (for an existing pad), the operator must
sample and test residential water wells within 1,000 feet of the well pad as described by the
SGEIS, and provide results to the property owner within 30 days of the operator’s receipt of
laboratory results. If no residential water wells are available for sampling within 1,000 feet,

Final SGEIS 2015, Page A10-1

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
either because there are none of record or because the property owner denies permission, then
wells within 2,000 feet must be sampled and tested with the property owner’s permission.
6) Ongoing water well monitoring and testing must continue as described by the SGEIS until
one year after hydraulic fracturing at the last well on the pad. More frequent or additional
monitoring and testing may be required by the Department in response to complaints or for
other reasonable cause.
7) Water well analysis must be performed by an ELAP-certified laboratory. Analyses and
documentation that all test results were provided to the property owner must be maintained
by the operator. The results of the analyses (data) and delivery documentation must be made
available to the Department and local health department upon Department request at any time
during the period up to and including five years after the permitted hydrocarbon well is
permanently plugged and abandoned under a Department permit. If the permitted
hydrocarbon well is located on a multi-well pad, all residential water well data and delivery
documentation must be maintained and made available during the period up to and including
five years after the last permitted hydrocarbon well on the pad is permanently plugged and
abandoned under a Department permit.
Site Preparation
8) Unless otherwise required by private lease agreement and in consideration of avoiding
bisection of agricultural fields, to the extent practical the access road must be located as far
away as possible from occupied structures, places of assembly and unleased property.
9) Unless otherwise approved or directed by the Department, all of the topsoil in the project area
stripped to facilitate the construction of well pads and access roads must be stockpiled,
stabilized and remain on site for use in final reclamation.
10) Authorization under the Department’s General Permit for Stormwater Discharges Associated
with High-Volume Hydraulic Fracturing (HVHF GP) must be obtained prior to any
disturbance at the site.
11) Piping, conveyances, valves and tanks in contact with flowback water must be constructed of
materials compatible with flowback water composition, and in accordance with the fluid
disposal plan approved by the Department pursuant to 6 NYCRR 554.1(c)(1).
12) Any reserve pit, drilling pit or mud pit on the well pad which will be used for more than one
well must be constructed as follows:
a) Surface water and stormwater runoff must be diverted away from the pit;
b) Pit volume may not exceed 250,000 gallons, or 500,000 gallons for multiple pits on one
tract or related tracts of land;
c) Pit sidewalls and bottoms must adequately cushioned and free of objects capable of
puncturing and ripping the liner;
d) Pits constructed in unconsolidated sediments must have beveled walls (45 degrees or
less);

Final SGEIS 2015, Page A10-2

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
e) The pit liner must be sized and placed with sufficient slack to accommodate stretching;
f) Liner thickness must be at least 30 mils, and;
g) Seams must be factory installed or field seamed in accordance with the manufacturer’s
recommendations.
Site Maintenance
13) Secondary containment consistent with the Department’s Spill Prevention Operations
Technology Series 10, Secondary Containment Systems for Aboveground Storage Tanks,
(SPOTS 10) is required for all fueling tanks;
14) To the extent practical, fueling tanks must not be placed within 500 feet of a public or private
waterwell, a domestic-supply spring, a reservoir, a perennial or intermittent stream, a storm
drain, a wetland, a lake or a pond;
15) Fueling tank filling operations must be manned at the fueling truck and at the tank if the tank
is not visible to the fueling operator from the truck, and;
16) Troughs, drip pads or drip pans are required beneath the fill port of a fueling tank during
filling operations if the fill port is not within the secondary containment.
17) A copy of the SWPPP must be available on-site and available to Department inspectors while
HVHF GP coverage is in effect. HVHF GP coverage may be terminated upon the plugging
and abandonment of all wells on the well pad in accordance with Department-issued permits.
18) Two feet of freeboard must be maintained at all times for any on-site pit.
19) Except for freshwater storage pits, fluids must be removed from an on-site pit prior to any 45day gap in use (i.e., from the completion date of the well) and the pit must be inspected by a
Department inspector prior to resumed use.
Drilling, Stimulation and Flowback
NOTE: Wildcat Supplementary Conditions may be separately imposed in addition to these.
Unless superseded by more stringent conditions below, the Department’s Casing and
Cementing Practices also remain in effect.
20) Lighting and noise mitigation measures as deemed necessary by the Department may be
required at any time.
21) The operator must provide the drilling company with a well prognosis indicating anticipated
formation top depths with appropriate warning comments prior to spud. The prognosis must
be reviewed by all crew members and posted in a prominent location in the doghouse. The
operator must revise the prognosis and inform the drilling company in a timely manner if
drilling reveals significant variation between the anticipated and actual geology and/or
formation pressures.
22) Individual crew member’s responsibilities for blowout control must be posted in the
doghouse or other appropriate location and each crew member must be made aware of such

Final SGEIS 2015, Page A10-3

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
responsibilities prior to spud of any well being drilled or when another rig is moved on a
previously spudded well and/or prior to the commencement of any rig, snubbing unit or
coiled tubing unit performing completion work. During all drilling and/or completion
operations when a BOP is installed, tested or in use, the operator or operator’s designated
representative must be present at the wellsite and such person or personnel must have a
current well control certification from an accredited training program that is acceptable to the
Department (e.g., International Association of Drilling Contractors). Such certification must
be available at the wellsite and provided to the Department upon request.
23) Appropriate pressure control procedures and equipment in proper working order must be
properly installed and employed while conducting drilling and/or completion operations
including tripping, logging, running casing into the well, and drilling out solid-core stage
plugs. Unless otherwise approved by the Department, a snubbing unit and/or coiled tubing
unit with a BOP must be used to enter any well with pressure and/or to drill out one or more
solid-core stage plugs.
24) Pressure testing of the blow-out preventer (BOP) and related equipment for any drilling
and/or completion operation must be performed in accordance with the approved BOP use
and test plan, and any deviation from the approved plan must be approved by the Department.
Testing must be conducted in accordance with American Petroleum Institute (API)
Recommended Practice (RP) 53, RP for Blowout Prevention Systems for Drilling Wells, or
other procedures approved by the Department. Unless otherwise approved by the
Department, the BOP use and test plan must include the following provisions:
a) A system for recording, documenting and retaining the results of all pressure tests and
inspections conducted during drilling and/or completion operations. The results must be
available to the Department at the wellsite during the corresponding operation, and to the
Department upon request at any time during the period up to and including five years
after the well is permanently plugged and abandoned under a Department permit. If the
well is located on a multi-well pad, all pressure testing records must be maintained and
made available during the period up to and including five years after the last well on the
pad is permanently plugged and abandoned under a Department permit. The record for
each pressure test, at a minimum, must identify the equipment or casing being tested, the
date of the test, the minimum and maximum test pressures in psig, the test medium (e.g.,
water, brine, mud, air, nitrogen) including its density, test duration, and the results of the
test including any pressure drop;
b) A well control barrier policy developed by the operator that identifies acceptable barriers
to be used during identified operations. Such policy must employ, at a minimum, two
mechanical barriers capable of being tested when conducting any drilling and/or
completion operation below the surface casing. In no event shall a stripper rubber or a
stripper head be considered an acceptable barrier;
c) BOP testing prior to being put into service. Such testing must include testing after the
BOP is installed on the well but prior to use. Pressure control equipment, including the
BOP, that fails any pressure test must not be used until it is repaired and passes the
pressure test, and;
d) A remote BOP actuator which is powered by a source other than rig hydraulics that is
located at least 50 feet from the wellhead. All lines, valves and fittings between the BOP

Final SGEIS 2015, Page A10-4

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
and the remote actuator and any other actuator must be flame resistant and have an
appropriate rated working pressure.
25) The operator must detect, if practical, and document all naturally occurring methane in the
conductor hole, if drilled, and the surface hole. Further, in accordance with 6 NYCRR
554.7(b), all freshwater, brine, oil and gas shows must be documented on the Department’s
Well Drilling and Completion Report. In the event H2S is encountered in any portion of the
well, all regulated activities must be conducted by the operator in conformance with
American Petroleum Institute Publication API RP49, “Recommended Practices For Safe
Drilling of Wells Containing Hydrogen Sulfide.”
26) Annular disposal of drill cuttings or fluid is prohibited.
27) All fluids must be contained on the site until properly removed in compliance with the fluid
disposal plan approved in accordance with 6 NYCRR 554.1(c)(1) and applicable conditions
of this permit.
28) A closed-loop tank system must be used instead of a reserve pit to manage and contain

drilling fluids and cuttings for any of the following:
a) horizontal drilling in the Marcellus Shale without an acid rock drainage mitigation plan
for on-site burial of such cuttings, and;
b) any drilling requiring cuttings to be disposed of off-site including at a landfill.
29) With respect to the closed-loop tank system, cuttings may be removed from the site in the
primary capture container (e.g., tank or bin) or transferred onsite via a transfer area to a
secondary container or truck for offsite disposal. If a cuttings transfer area is employed, it
must be lined with a material acceptable to the department. Transfer of cuttings to an onsite
stock pile is prohibited, regardless of any liner under the stock pile. Offsite transport of all
cuttings must be undertaken by a waste transporter with an approved 6 NYCRR Part 364
permit. The Drilling and Production Waste Tracking Form must be completed and retained
for three years by the generator, transporter and destination facility, and made available to the
Department upon request during this period. If requested, the generator is responsible for
producing its originating copy of the Drilling and Production Waste Tracking Form and the
completed form with the original signatures of the generator, transporter and destination
facility.
30) Only biocides with current registration for use in New York may be used for any operation at
the wellsite. Products must be properly labeled, and the label must be kept on-site during
application and storage.
31) With respect to all surface, intermediate and production casing run in the well, and in addition
to the requirements of the Department’s “Casing and Cementing Practices” and any approved
centralizer plan for intermediate casing, the following shall apply:
a) Casing must be new and conform to American Petroleum Institute (API) Specification
5CT, Specifications for Casing and Tubing (April 2002), and welded connections are
prohibited;

Final SGEIS 2015, Page A10-5

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
b) casing thread compound and its use must conform to API Recommended Practice (RP)
5A3, RP on Thread Compounds for Casing, Tubing, Line Pipe, and Drill Stem Elements
(November 2009);
c) at least two centralizers (one in the middle and one at the top) must be installed on the
first joint of casing (except production casing) and all bow-spring style centralizers must
conform to API Specification 10D for Bow-Spring Casing Centralizers (March 2002);
d) cement must conform to API Specification 10A, Specifications for Cement and Material
for Well Cementing (April 2002 and January 2005 Addendum). Further, the cement
slurry must be prepared to minimize its free water content in accordance with the same
API specification and it must contain a gas-block additive;
e) prior to cementing any casing string, the borehole must be circulated and conditioned to
ensure an adequate cement bond;
f) a spacer of adequate volume, makeup and consistency must be pumped ahead of the
cement;
g) the cement must be pumped at a rate and in a flow regime that inhibits channeling of the
cement in the annulus;
h) after the cement is pumped, the operator must wait on cement (WOC):
(1) until the cement achieves a calculated (e.g., performance chart) compressive
strength of at least 500 psig, and
(2) a minimum WOC time of 8 hours before the casing is disturbed in any way,
including installation of a blow-out preventer (BOP). The operator may request a
waiver from the Department from the required WOC time if the operator has
bench tested the actual cement batch and blend using mix water from the actual
source for the job, and determined that 8 hours is not required to reach a
compressive strength of 500 psig, and;
i)

A copy of the cement job log for any cemented casing in the well must be available to the
Department at the wellsite during drilling operations, and thereafter available to the
Department upon request. The operator must provide such to the Department upon
request at any time during the period up to and including five years after the well is
permanently plugged and abandoned under a Department permit. If the well is located on
a multi-well pad, all cementing records must be maintained and made available during
the period up to and including five years after the last well on the pad is permanently
plugged and abandoned under a Department permit.

32) The surface casing must be run and cemented immediately after the hole has been adequately
circulated and conditioned. This office must be notified _______ hours prior to surface
casing cementing operations. (Blank to be filled in based on well’s location and Regional
Minerals Manager’s direction.)
33) Intermediate casing must be installed in the well. The setting depth and design of the casing
must consider all applicable drilling, geologic and well control factors. Additionally, the
setting depth must consider the cementing requirements for the intermediate casing and the
production casing as noted below. Any request to waive the intermediate casing requirement
must be made in writing with supporting documentation and is subject to the Department’s

Final SGEIS 2015, Page A10-6

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
approval. Information gathered from operations conducted on any single well or the first well
drilled on a multi-well pad may serve to form the basis for the Department waiving the
intermediate casing requirement on subsequent wells in the vicinity of the single well or
subsequent wells on the same multi-well pad.
34) This office must be notified ______ hours prior to intermediate casing cementing operations.
Intermediate casing must be fully cemented to surface with excess cement. Cementing must
be by the pump and plug method with a minimum of 25% excess cement unless caliper logs
are run, in which case 10% excess will suffice. (Blank to be filled in based on well’s location
and Regional Minerals Manager’s direction.)
35) The operator must run a radial cement bond evaluation log or other evaluation approved by
the Department to verify the cement bond on the intermediate casing. The quality and
effectiveness of the cement job shall be evaluated by the operator using the above required
evaluation in conjunction with appropriate supporting data per Section 6.4 “Other Testing and
Information” under the heading of “Well Logging and Other Testing” of American Petroleum
Institute (API) Guidance Document HF1 (First Edition, October 2009). Remedial cementing
is required if the cement bond is not adequate for drilling ahead (i.e., diversion or shut-in for
well control).
36) Production casing must be run to the surface. This office must be notified _______ hours
prior to production casing cementing operations. If installation of the intermediate casing is
waived by the Department, then production casing must be fully cemented to surface. If
intermediate casing is installed, the production casing cement must be tied into the
intermediate casing string with at least 500 feet of cement measured using True Vertical
Depth (TVD). Any request to waive any of the preceding cementing requirements must be
made in writing with supporting documentation and is subject to the Department’s approval.
The Department will only consider a request for a waiver if the open-hole wireline logs
including a narrative analysis of such and all other information collected during drilling from
the same well pad or offsetting wells verify that migration of oil, gas or other fluids from one
pool or stratum to another will be prevented. (Blank to be filled in based on well’s location
and Regional Minerals Manager’s direction.)
37) The operator must run a radial cement bond evaluation log or other evaluation approved by
the Department to verify the cement bond on the production casing. The quality and
effectiveness of the cement job shall be evaluated by the operator using the above required
evaluation in conjunction with appropriate supporting data per Section 6.4 “Other Testing and
Information” under the heading of “Well Logging and Other Testing” of American Petroleum
Institute (API) Guidance Document HF1 (First Edition, October 2009). Remedial cementing
is required if the cement bond is not adequate to effectively isolate hydraulic fracturing
operations.
38) The installation of an additional cemented casing string or strings in the well as deemed
necessary by the Department for environmental and/or public safety reasons may be required
at any time.
39) Under no circumstances should the annulus between the surface casing and the next casing
string be shut-in, except during a pressure test.
40) If hydraulic fracturing operations are performed down casing, prior to introducing hydraulic
fracturing fluid into the well the casing extending from the surface of the well to the top of

Final SGEIS 2015, Page A10-7

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
the treatment interval must be tested with fresh water, mud or brine to at least the maximum
anticipated treatment pressure for at least 30 minutes with less than a 5% pressure loss. This
pressure test may not commence for at least 7 days after the primary cementing operations are
completed on this casing string. A record of the pressure test must be maintained by the
operator and made available to the Department upon request. The actual hydraulic fracturing
treatment pressure must not exceed the test pressure at any time during hydraulic fracturing
operations.
41) Prior to commencing hydraulic fracturing and pumping of hydraulic fracturing fluid, the
injection lines and manifold, associated valves, frac head or tree and any other wellhead
component or connection not previously tested must be tested with fresh water, mud or brine
to at least the maximum anticipated treatment pressure for at least 30 minutes with less than a
5% pressure loss. A record of the pressure test must be maintained by the operator and made
available to the Department upon request. The actual hydraulic fracturing treatment pressure
must not exceed the test pressure at any time during hydraulic fracturing operations.
42) The operator must record the depths and estimated flow rates where fresh water, brine, oil
and/or gas were encountered or circulation was lost during drilling operations. This
information and the Department’s Pre-Frac Checklist and Certification form including a
treatment plan, must be submitted to and received by the regional office at least 3 days prior
to commencement of high-volume hydraulic fracturing operations. The treatment plan must
include a profile showing anticipated pressures and volumes of fluid for pumping the first
stage. It must also include a description of the planned treatment interval for the well [i.e.,
top and bottom of perforations expressed in both True Vertical Depth (TVD) and True
Measured Depth (TMD)].
43) Fracturing products other than those identified in the well permit application materials may
not be used without specific approval from this office.
44) This permit does not authorize the use of diesel as the primary carrier fluid (i.e., diesel-based
hydraulic fracturing).
45) The operator may conduct hydraulic fracturing operations provided 1) all items on the
checklist are affirmed by a response of “Yes,” 2) the Pre-Frac Checklist And Certification
and treatment plan are received by the Department at least 3 days prior to hydraulic
fracturing, and 3) all other pre-frac notification requirements are met as specified elsewhere.
The operator is prohibited from conducting hydraulic fracturing operations on the well
without additional Department review and approval if a response of “No” is provided to any
of the items in the Pre-Frac Checklist and Certification.
46) Hydraulic fracturing operations must be conducted as follows:
a) Secondary containment for fracturing additive containers and additive staging areas, and
flowback tanks is required. Secondary containment measures may include, as deemed
appropriate by the Department, one or a combination of the following; dikes, liners, pads,
impoundments, curbs, sumps or other structures or equipment capable of containing the
substance. Any such secondary containment must be sufficient to contain 110% of the
total capacity of the single largest container or tank within a common containment area.
No more than one hour before initiating any hydraulic fracturing stage, all secondary
containment must be visually inspected to ensure all structures and equipment are in

Final SGEIS 2015, Page A10-8

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
place and in proper working order. The results of this inspection must be recorded and
documented by the operator, and available to the Department upon request;
b) At least two vacuum trucks must be on standby at the wellsite during the pumping of
hydraulic fracturing fluid and during any subsequent flowback phases;
c) Hydraulic fracturing additives must be removed from the site if the site will be
unattended;
d) Any hydraulic fracturing string, if used, must be either stung into a production liner or
run with a packer set at least 100 feet below the deepest cement top. An adequately
sized, function tested relief valve and an adequately sized diversion line must be installed
and used to divert flow from the hydraulic fracturing string-casing annulus to a covered
watertight steel tank or covered watertight tank made of another material approved by
the Department in case of hydraulic fracturing string failure. The relief valve must be set
to limit the annular pressure to no more than 95% of the working pressure rating of the
casings forming the annulus. The annulus between the hydraulic fracturing string and
casing must be pressurized to at least 250 psig and monitored;
e) The pressure exerted on treating equipment including valves, lines, manifolds, hydraulic
fracturing head or tree, casing and hydraulic fracturing string, if used, must not exceed
95% of the working pressure rating of the weakest component;
f) The hydraulic fracturing treatment pressure must not exceed the test pressure of any
given component at any time during hydraulic fracturing operations;
g) All annuli available at the surface must be continuously observed or monitored in order to
detect pressure or flow, and the records of such maintained by the operator and made
available to the Department upon request, and;
h) Hydraulic fracturing pumping operations must be immediately suspended if any
anomalous pressure and/or flow condition is indicated or occurring including a
significant deviation from the treatment plan (i.e., profile showing anticipated pressures
and volume of fluid for pumping the first stage) provided to the Department with the PreFrac Checklist and Certification or any other anticipated pressure and/or flow condition.
Suspension of operations due to an anomalous pressure and/or flow condition is
considered a non-routine incident which must be reported in accordance with the General
Provisions of these supplementary permit conditions. In the case of suspended hydraulic
fracturing pumping operations and non-routine incident reporting of such, the operator
must receive Department approval prior to recommencing hydraulic fracturing activities
in the same well.
47) The operator must make and maintain a complete record of its hydraulic fracturing operation
including the flowback phase, and provide such to the Department upon request at any time
during the period up to and including five years after the well is permanently plugged and
abandoned under a Department permit. If the well is located on a multi-well pad, all
hydraulic fracturing records must be maintained and made available during the period up to
and including five years after the last well on the pad is permanently plugged and abandoned
under a Department permit. The record for each well must include all types and volumes of
materials, including additives, pumped into the well, flowback rates, and the daily and total
volumes of fluid recovered during the first 30 days of flow from well. The record must also

Final SGEIS 2015, Page A10-9

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
include a complete description of pressures exhibited throughout the hydraulic fracturing
operation and must include pressure recordings, charts and/or a pressure profile. A synopsis
of the hydraulic fracturing operation must be provided in the appropriate section of the
Department’s Well Drilling and Completion Report which must be provided to the
Department within 30 days after completing the well in accordance with 6 NYCRR 554.7.
48) Flowback water is prohibited from being directed to or stored in any on-site pit. Covered
watertight steel tanks or covered watertight tanks constructed of another material approved by
the Department are required for flowback handling and containment on the well pad.
Flowback water tanks, piping and conveyances, including valves, must be constructed of
suitable materials, be of sufficient pressure rating and be maintained in a leak-free condition.
Fluid transfer operations from tanks to tanker trucks must be manned at the truck and at the
tank if the tank is not visible to the truck operator from the truck. Additionally, during
transfer operations, all interconnecting piping must be manned if not visible to transfer
personnel at the truck and tank.
49) The venting of any gas originating from the target formation during the flowback phase must
be through a flare stack at least 30 feet in height, unless the absence of H2S has been
demonstrated at a previous well on the same pad. Gas vented through the flare stack must be
ignited whenever possible. The stack must be equipped with a self-ignition device.
50) A reduced emissions completion, with minimal flaring (if any), must be performed whenever
a sales line and interconnecting gathering line are available during completion at any
individual well or a multi-well pad.
51) This permit authorizes a one-time single-stage or multi-stage high-volume hydraulic
fracturing operation as described in the well permit application materials, subject to the PreFrac Checklist and Certification and any modifications required by the Department. Any
subsequent high-volume re-fracturing operations are subject to the Department’s approval
after:
a) review of the planned fracturing procedures and products, water source, proposed site
disturbance and layout, and fluid disposal plans;
b) a site inspection by Department staff, and;
c) a determination of whether any other Department permits are required.
Reclamation
52) Fluids must be removed from any on-site pit and the pit reclaimed no later than 45 days after
completion of drilling and stimulation operations at the last well on the pad, unless the
Department grants an extension pursuant to 6 NYCRR 554.1(c)(3). Flowback water must be
removed from on-site tanks within the same time frame.
53) Removed pit fluids must be disposed, recycled or reused as described in the approved fluid
disposal plan submitted pursuant to 6 NYCRR 554.1(c)(1). Transport of all waste fluids by
vehicle must be undertaken by a waste transporter with an approved 6 NYCRR Part 364
permit. The Drilling and Production Waste Tracking Form must be completed and retained
for three years by the generator, transporter and destination facility, and made available to the
Department upon request during this period. If requested, the generator is responsible for

Final SGEIS 2015, Page A10-10

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
producing its originating copy of the Drilling and Production Waste Tracking Form and the
completed form with the original signatures of the generator, transporter and destination
facility.
54) If any fluid or other waste material is moved off site by pipeline or other piping, the operator
must maintain a record of the date and time the fluid or other material left the site, the
quantity of fluid or other material, and its intended disposition and use at that destination or
receiving facility.
55) Cuttings contaminated with oil-based mud and polymer-based muds must be contained and
managed in a closed-loop tank system and not be buried on site, and must be removed from
the site for disposal in a 6 NYCRR Part 360 solid waste facility. Consultation with the
Department’s Division of Materials Management (DMM) is required prior to disposal of any
cuttings associated with water-based mud-drilling and pit liner associated with water-based
mud-drilling where the water-based mud contains chemical additives. Any sampling and
analysis directed by DMM must be by an ELAP-certified laboratory. Disposal must conform
to all applicable Department regulations. The pit liner must be ripped and perforated prior to
any permitted burial on-site and to the extent practical, excess pit liner material must be
removed and disposed of properly. Permission of the surface owner is required for any onsite burial of cuttings and pit liner, regardless of type of drilling and fluids used. Burial of
any other trash on-site is specifically prohibited and all such trash must be removed from the
site and properly disposed. Transport of all cuttings and pit liner off-site, if required by the
Department or otherwise performed, must be undertaken by a waste transporter with an
approved 6 NYCRR Part 364 permit. The Drilling and Production Waste Tracking Form
must be completed and retained for three years by the generator, transporter and destination
facility, and made available to the Department upon request during this period. If requested,
the generator is responsible for producing its originating copy of the Drilling and Production
Waste Tracking Form and the completed form with the original signatures of the generator,
transporter and destination facility.
56) A site-specific acid rock drainage (ARD) mitigation plan consistent with the SGEIS must be
prepared by the operator and followed for on-site burial of Marcellus Shale cuttings from
horizontal drilling in the Marcellus Shale if the operator elects to bury these cuttings. The
plan must be available to the Department upon request, and available on-site to a Department
inspector while activities addressed by the plan are taking place.
57) The operator must fully implement the Partial Site Reclamation Plan described in the
approved application materials.
58) Final reclamation of the wellsite must be approved by the Department. Unless otherwise
approved by this office, well pads and access roads constructed for drilling and production
operations must be scarified or ripped to alleviate compaction prior to replacement of topsoil.
Reclaimed areas must be seeded and mulched after topsoil replacement. Any proposal by the
operator to waive these reclamation requirements must be accompanied by documentation of
the landowner’s written request to keep the access road and/or well pad.
General
59) The operator must follow applicable best management practices (BMPs) for reducing direct
impacts at individual well pads described in Section 7.4.1.1 of the SGEIS.

Final SGEIS 2015, Page A10-11

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
60) The operator must fully implement the Invasive Species Management Plan described in the
approved application materials.
61) The operator must follow applicable best management practices (BMPs) for reducing the
potential for transfer and introduction of invasive species described in Section 7.4.2.2 of the
SGEIS.
62) The operator must complete the “Record of Formations Penetrated” on the Well Drilling and
Completion Report providing a log of formations, both unconsolidated and consolidated, and
depths and estimated flow rates of any fresh water, brine, oil and/or gas. In accordance with
6 NYCRR 554.7, the well operator must provide the Department with the Well Drilling and
Completion Report within 30 days after completing the well.
63) Any non-routine incident of potential environmental and/or public safety significance must be
verbally reported to the Department within two hours of the incident’s known occurrence or
discovery, with a written report detailing the non-routine incident to follow within twentyfour hours of the incident’s known occurrence or discovery. Non-routine incidents may
include, but are not limited to: casing, drill pipe or hydraulic fracturing equipment failures,
cement failures, fishing jobs, fires, seepages, blowouts, surface chemical spills, observed
leaks in surface equipment, observed pit liner failure, surface effects at previously plugged or
other wells, observed effects at water wells or at the surface, complaints of water well
contamination, anomalous pressure and/or flow conditions indicated or occurring during
hydraulic fracturing operations, or other potentially polluting non-routine incident or incident
that may affect the health, safety, welfare, or property of any person. Provided the
environment and public safety would not be further endangered, any action and/or condition
known or suspected of causing and/or contributing to a non-routine incident must cease
immediately upon known occurrence or discovery of the incident, and appropriate initial
remedial actions commenced. The required written non-routine incident report noted above
must provide details of the incident and include, as necessary, a proposed remedial plan for
Department review and approval. In the case of suspended hydraulic fracturing pumping
operations and non-routine incident reporting of such, the operator must receive Department
approval prior to recommencing hydraulic fracturing activities in the same well.
64) Flowback water recovered after high-volume hydraulic fracturing operations must be tested
for NORM prior to removal from the site. Fluids recovered during the production phase (i.e.,
production brine) must be tested for NORM prior to removal.
65) Periodic radiation surveys must be conducted at specified time intervals during the production phase
for Marcellus wells developed by high-volume hydraulic fracturing completion methods. Such
surveys must be performed on all accessible well piping, tanks, or equipment that could contain
NORM scale buildup. The surveys must be conducted for as long as the facility remains in active use.
If piping, tanks, or equipment is to be removed, radiation surveys must be performed to ensure their
appropriate disposal. All surveys must be conducted in accordance with NYSDOH protocols.

66) Production brine is prohibited from being directed to or stored in any on-site pit. Covered
watertight steel, fiberglass or plastic tanks, or covered watertight tanks constructed of another
material approved by the Department, are required for production brine handling and
containment on the well pad. Production brine tanks, piping and conveyances, including
valves, must be constructed of suitable materials, be of sufficient pressure rating and be
maintained in a leak-free condition.

Final SGEIS 2015, Page A10-12

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
67) Production brine which is removed from the site must be disposed, recycled or reused as
described by the well permit application materials. Transport of all waste fluids must be
undertaken by a waste transporter with an approved 6 NYCRR Part 364 permit. The Drilling
and Production Waste Tracking Form must be completed and retained for three years by the
generator, transporter and destination facility, and made available to the Department upon
request during this period. If requested, the generator is responsible for producing its
originating copy of the Drilling and Production Waste Tracking Form and the completed
form with the original signatures of the generator, transporter and destination facility.
Any deviation from the above conditions must be approved by the Department prior to
making a change.

Final SGEIS 2015, Page A10-13

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
ATTACHMENT A
To avoid or mitigate adverse air quality impacts from the well drilling, completion and production
operations, the following restrictions are imposed:
1. The diesel fuel used in drilling and completion equipment engines will be limited to Ultra
Low Sulfur Fuel (ULSF) with a maximum sulfur content of 15 ppm.
2. There will not be any simultaneous operations of the drilling and completion equipment
engines at the single well pad.
3. The maximum number of wells to be drilled and completed annually or during any
consecutive 12-month period at a single pad will be limited to four.
4. The emissions of benzene at any glycol dehydrator to be used at the well pad will be limited
to one ton/year as determined by calculations with the GRI-GlyCalc program. If wet gas is
encountered, then the dehydrator will have a minimum stack height of 30 feet (9.1m) and will
be equipped with a control devise to limit the benzene emissions to 1 Tpy.
5. Condensate tanks used at the well pad shall be equipped with vapor recovery systems to
minimize fugitive VOC emissions.
6. During the flowback phase, the venting of gas from each well pad will be limited to a
maximum of 5 MMscf during any consecutive 12-month period. If “sour” gas is encountered
with detected H2S emissions, the height at which the gas will be vented will be a minimum of
30 feet (9.1m).
7. During the flowback phase, flaring of gas at each well pad will be limited to a maximum of
120 MMscf during any consecutive 12-month period.
8. Wellhead compressor will be equipped with NSCR controls.
9. No uncertified (i.e., EPA Tier 0) drilling or completion equipment engines will be used for
any activity at the well sites.
10. The drilling engines and drilling air compressors will be limited to EPA Tier 2 or newer
equipment. If Tier 1 drilling equipment is to be used, these will be equipped with both
particulate traps (CRDPF) and SCR controls. During operations, this equipment will be
positioned as close to the center of the well pad as practicable. If industry deviates from the
control requirements or proposes alternate mitigation and/or control measures to demonstrate
ambient standard compliance, site specific information will be provided to the Department for
review and concurrence.
11. The completion equipment engines will be limited to EPA Tier 2 or newer equipment.
Particulate traps will be required for all Tier 2 engines. SCR control will be required on all
completion equipment engines regardless of the emission Tier. During operations, this
equipment will be positioned as close to the center of the well pad as practicable. If industry
deviates from this requirement or proposes mitigation and/or alternate control measures to
demonstrate ambient standard compliance, site specific information will be provided to the
Department for review and concurrence.

Final SGEIS 2015, Page A10-14

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
ATTACHMENT B
PASSBY FLOW IMPLEMENTATION AND ENFORCEMENT

1. Monitoring and Reporting. Passby flows must be maintained instantaneously.
Determinations of allowable removal rates will be made based on comparisons with
instantaneous flow data.
2. Description of Gage Types
Tier I- Gage data in this category is collected by the permitee immediately downstream of the
water withdrawal location using streamflow gage equipment capable of accurately measuring
instantaneous flow rates as approved at the discretion of the Department.
Tier II- Gage data in this category is obtained from acceptable USGS gages that must be located
at a point in the same watershed where the drainage area at the gage is from 0.5x to 2.0x the size
of the drainage area as measured at the withdrawal point. The catchment area must not have
altered flows unless the instantaneous flow measurements can take into account the alterations.
Tier III- Gage data in this category is obtained from USGS gages that are either outside the
acceptable distance within the same watershed or are in adjacent watersheds that possess similar
basin characteristics. The use of these “surrogate” watersheds are the most inaccurate account of
stream flow and should be used only as approved at the discretion of the Department.
3. All streamflow records used in determining the instantaneous passby flow rates should be
measured to the nearest 0.1 cfs at 15-minute increments. Water withdrawal rates must be
reported as instantaneous measurements to the nearest 0.1 cfs at 5-minute increments.
Reporting is required annually to Department in Microsoft Excel or similar electronic
spreadsheet/database formats.
4. Violations and Suspension of Operations. Water withdrawal operations will be suspended
immediately upon determination that the required passby flow has not been maintained. The
Department has the right to modify passby flow requirements if water quality standards are
not being met within a watercourse as the result of a water withdrawal. Failure to submit
annual reports, filing of inaccurate reports on water withdrawals, and continuing to withdraw
water after a determination that the required passby flow has not been maintained, are all
considered separate violations of this permit and the Environmental Conservation Law
Article 71-1305(2).

Final SGEIS 2015, Page A10-15

 PROPOSED Supplementary Permit Conditions for High-Volume Hydraulic Fracturing
ATTACHMENT C
FOREST AND GRASSLAND FOCUS AREAS

Operators developing well sites in Forest and Grassland Focus Areas that involve disturbance in a
contiguous forest patch of 150 acres or more in size or in a contiguous grassland patch of 30 acres or
more in size must:
1) Implement mitigation measures identified as part of the Department-approved ecological
assessment;
2) Monitor the effects of disturbance as active development proceeds and for a minimum of two
years following well completion; and
3) Practice adaptive management as previously unknown effects are documented.

Final SGEIS 2015, Page A10-16

 Appendix 11
Analysis of Subsurface Mobility
of Fracturing Fluids
(Excerpted from ICF International, Task 1, 2009)
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

NYSERDA
Agreement No. 9679

1.2.4 Principles governing fracturing fluid flow
The mobility of hydraulic fracturing fluid depends on the same physical and chemical principles
that dictate all fluid transport phenomena. Frac fluid will flow through the well, the fractures, and
the porous media based on pressure differentials and hydraulic conductivities. In addition to the
overall flow of the frac fluids, additives may experience greater or lesser movement due to
diffusion and adsorption. The concentrations of the fluids and additives may change due to
dilution in formation waters and possibly by biological or chemical degradation.
1.2.4.1 Limiting conditions
The analyses below present flow calculations for a range of parameters, with the intent to define
reasonable bounds for the conditions likely to be encountered in New York State. Although one
or more conditions at some future well sites may lie outside of the ranges analyzed, it is
considered unlikely that the combination of conditions at any site would produce environmental
impacts that are significantly more adverse than the worst case scenarios analyzed. The
equations used in the analyses are presented below to facilitate the assessment of additional
scenarios.
The analyses consider potentially useful aquifers with lower limits at depths up to 1,000 feet,
somewhat deeper than the maximum aquifer depth reported in Table 3 for the Marcellus Shale.
Similarly, the minimum depth to the top of the shale is taken as 2,000 ft, well above the
minimum depth reported in Table 3 for the Marcellus Shale. The 2,000 ft. depth has been
postulated as the probable upper limit for economic development of the New York shales.
The analyses include an additional conservative assumption. Even for deep aquifers, the
analyses consider the pore pressure at the bottom of the aquifer to be zero as if a deep well or
well field was operating at maximum drawdown. This assumption maximizes the potential for
upward flow of fracturing fluid or its components from the fracture zone to the aquifer.
134

U.S. EPA, 2004. Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic Fracturing of
Coalbed Methane Reservoirs, Report number: EPA 816-R-04-003.

August 2009

Final SGEIS 2015, Page A11-1

23

 NYSERDA
Agreement No. 9679

1.2.4.2 Gradient
For a fracturing fluid or its additives to have a negative impact on a groundwater aquifer, some
deleterious component of the fracturing fluid would need to travel from the target fracture zone
to the aquifer. In order for fluid to flow from the fracture zone to an aquifer, the total head135
must be greater in the fracture zone than at the well. We can estimate the gradient136 that might
exist between a fracture zone in the shale and a potable water aquifer as follows:

i = 
where

 i
htn
L

ht1 − ht 2
L

(1)

= gradient
= total head at Point n
= length of flow path from Point 1 to Point 2

Since the total head is the sum of the elevation head and the pressure head,

ht = he + h p
The gradient can be restated as

i = 
where

  hen
hpn

(h

e1

(2)

+ h p1 ) − (he2 + h p2 )

(3)

L

= elevation head at Point n 

= pressure head at Point n 


If the ground surface is taken as the elevation datum, we can express the elevation head in
terms of depth.

d n = −hen 

(4)

Restating the gradient yields

i=

(h

where

e1

+ h p1 ) − (he2 + h p 2 )
L 
  dn

=

(− d

1

+ h p1 ) − (− d 2 + h p2 )
L

= 

(d 2 − d1 ) + (h p1 − h p 2 )
L

(5)

= depth at Point n

We can estimate the maximum likely gradient by considering the combination of parameters
which would be most favorable to flow from the hydraulically fractured zone to a potential
groundwater aquifer. These include assuming the minimum possible pressure head in the
aquifer and the shortest possible flow path, i.e. setting hp2 to zero to simulate a well pumped to
the maximum aquifer drawdown and setting L to the vertical distance between the fracture zone
and the aquifer, d1 – d2.
135

Total head at a point is the sum of the elevation at the point plus the pore pressure expressed as the height of a 

vertical column of water. 

136
The groundwater gradient is the difference in total head between two points divided by the distance between the 

points. 


August 2009

Final SGEIS 2015, Page A11-2

24

 NYSERDA
Agreement No. 9679

The gradient now becomes

i=

(d 2 − d1 ) + h p1
d1 − d 2

(6)

The total vertical stress in the fracture zone equals

σ v = d1 × γ R 
where

  σv
d1

γR

(7)

= total vertical stress 

= depth at Point 1, in the fracture zone 

= average total unit weight of the overlying rock 


The effective vertical stress, or the stress transmitted through the mineral matrix, equals the
total unit weight minus the pore pressure. For the purposes of this analysis, the pore pressure is
taken to be equivalent to that of a vertical water column from the fracture zone to the surface.
The effective vertical stress is given by

σ v′ = σ v − (d1 × γ W ) 
where

  σ'v

γW

(8)

= effective vertical stress 

= unit weight of water 


The effective horizontal stress and the total horizontal stress therefore equal

where

  σ'h
K

σh

σ h′ = K × σ v′ 

(9)

σ h = σ h′ + (d1 × γ W ) 

(10)

= effective horizontal stress 

= ratio of horizontal to vertical stress 

= total horizontal stress 


The hydraulic fracturing pressure needs to exceed the minimum total horizontal stress. Allowing
for some loss of pressure from the wellbore to the fracture tip, the pressure head in the fracture
zone equals

h p1 = c × σ h =
where

hp1
c

c × d1 × [K (γ R − γ W ) + γ W ]

γW

(11)

= pressure head at Point 1, in the fracture zone
= coefficient to allow for some loss of pressure from the wellbore
to the fracture tip

Since the horizontal stress is typically in the range of 0.5 to 1.0 times the vertical stress, the
fracturing pressure will equal the depth to the fracture zone times, say, 0.75 times the density of

August 2009

Final SGEIS 2015, Page A11-3

25

 NYSERDA
Agreement No. 9679

the geologic materials (estimated at 150 pcf average), times the depth.137 To allow for some loss
of pressure from the wellbore to the fracture tip, the calculations assume a fracturing pressure
10% higher than the horizontal stress, yielding

h p1 =

110% × d1 × [0.75(150 pcf − 62.4 pcf ) + 62.4 pcf ]
= 2.26d1
62.4 pcf

(12)

Equation (6) thus becomes

i=

(d 2 − d1 ) + 2.26d1
d1 − d 2

=

d 2 + 1.26d1
d1 − d 2

(13)

Figure 1 shows the variation in the average hydraulic gradient between the fracture zone and an
overlying aquifer during hydraulic fracturing for a variety of aquifer and shale depths. The
gradient has a maximum of about 3.5, and is less than 2.0 for most depth combinations.
4.00
Pore pressure at bottom of aquifer = 0
Pore pressure in fracture zone = 110% of the horizontal stress at he top of the
h l

DEPTH TO BOTTOM
OF AQUIFER (ft)

0

3.50

200
400
600
800

HYDRAULIC GRADIENT

3.00

1000

2.50

2.00

1.50

1.00
2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

DEPTH TO TOP OF SHALE in feet

Figure 1: Average hydraulic gradient during fracturing

In an actual fracturing situation, non-steady state conditions will prevail during the limited time of
application of the fracturing pressures, and the gradients will be higher than the average closer

137

Zhang, Lianyang, 2005. Engineering Properties of Rocks, Elsevier Geo-Engineering Book Series, Volume 4,
Amsterdam.

August 2009

Final SGEIS 2015, Page A11-4

26

 NYSERDA
Agreement No. 9679

to the fracture zone and lower than the average closer to the aquifer. It is important to note that
these gradients only apply while fracturing pressures are being applied.
Once fracturing pressures are removed, the total head in the reservoir will fall to near its original
value, which may be higher or lower than the total head in the aquifer. Evidence suggests that
the permeabilities of the Devonian shales are too low for any meaningful hydrological
connection with the post-Devonian formations. The high dissolved solid content near 300,000
ppm in pre-Late Devonian formations supports the concept that these formations are
hydrologically discontinuous, i.e. not well-connected to other formations.138 During production,
the pressure in the shale would decrease as gas is extracted, further reducing any potential for
upward flow.
1.2.4.3 Seepage velocity
The second aspect to consider with regards to flow is the time required for a particle of fluid to
flow from the fracture zone to the well. Using Darcy’s law, the seepage velocity would equal

v=
where

v
k
n

ki
n

(10)

= seepage velocity
= hydraulic conductivity
= porosity

The average hydraulic conductivity between a fracture zone and an aquifer would depend on
the hydraulic conductivity of each intervening stratum, which in turn would depend on the type of
material and whether it was intact or fractured. The rock types overlying the Marcellus Shale are
primarily sandstones and other shales.139 Table 4 lists the range of hydraulic conductivities for
sandstone and shale rock masses. The hydraulic conductivity of rock masses tends to decrease
with depth as higher stress levels close or prevent fractures. Vertical flow across a horizontally
layered system of geologic strata is controlled primarily by the less permeable strata, so the
average vertical hydraulic conductivity of all the strata lying above the target shale would be
expected to be no greater than 1E-5 cm/sec and could be substantially lower.
Table 4: Hydraulic conductivity of rock masses140
Material
Minimum k
Maximum k
Intact Sandstone
1E-8 cm/sec 1E-5 cm/sec
Sandstone rock mass 1E-9 cm/sec 1E-1 cm/sec
Intact Shale
1E-11 cm/sec 1E-9 cm/sec
Shale rock mass
1E-9 cm/sec 1E-4 cm/sec
Figure 2 shows the seepage velocity from the fracture zone to an overlying aquifer based on the
average gradients shown in Figure 1 over a range of hydraulic conductivity values and for the
maximum aquifer depth of 1000 feet. For all lesser aquifer depths, the seepage velocity would
138
Russell, William L., 1972, “Pressure-Depth Relations in Appalachian Region”, AAPG Bulletin, March 1972, v. 56, 

No. 3, p. 528-536. 

139
Arthur, J.D., et al, 2008. “Hydraulic Fracturing Considerations for Natural Gas Wells of the Marcellus Shale,” 

Presented at Ground Water Protection Council 2008 Annual Forum, September 21-24, 2008, Cincinnati, Ohio. 

140
Zhang, Lianyang, 2005. Engineering Properties of Rocks, Elsevier Geo-Engineering Book Series, Volume 4, 

Amsterdam. 


August 2009

Final SGEIS 2015, Page A11-5

27

 NYSERDA
Agreement No. 9679

be lower. For all of the analyses presented in this report, the porosity is taken as 10%, the
reported total porosity for the Marcellus Shale.141 Total porosity equals the contribution from
both micro-pores within the intact rock and void space due to fractures. For the overlying strata,
the analyses also use the same value for total porosity of 10% which is in the lower range of the
typical values for sandstones and shales. This may result in a slight overestimation of the
calculated seepage velocity, and an underestimation of the required travel time and available
pore storage volume.
1.0E+01

10% Porosity
Pore pressure at bottom of aquifer = 0
Pore pressure in fracture zone = 110% of the horizontal stress at the top of the shale
Depth to Bottom of Aquifer = 1000 ft

SEEPAGE VELOCITY in ft/day

1.0E+00

1.0E-01

HYDRAULIC
CONDUCTIVITY
in cm/sec

1.0E-02

1.0E-04
1.0E-05
1.0E-06
1.0E-07

1.0E-03

1.0E-04
2,000

1.0E-08

3,000

4,000

5,000

6,000

7,000

8,000

9,000

DEPTH TO TOP OF SHALE in feet

Figure 2: Seepage velocity as a function of hydraulic conductivity

Figure 2 shows that the seepage of hydraulic fracturing fluid would be limited to no more than
10 feet per day, and would be substantially less under most conditions. Since the cumulative
amount of time that the fracturing pressure would be applied for all steps of a typical fracture
stage is less than one day, the corresponding seepage distance would be similarly limited.
It is important to note that the seepage velocities shown in Figure 2 are based on average
gradients between the fracture zone and the overlying aquifer. The actual gradients and
seepage velocities will be influenced by non-steady state conditions and by variations in the
hydraulic conductivities of the various strata.

141

DOE, Office of Fossil Energy, 2009. State Oil and National Gas Regulations Designed to Protect Water
Resources, May 2009.

August 2009

Final SGEIS 2015, Page A11-6

28

 NYSERDA
Agreement No. 9679

1.2.4.4 Required travel time
The time that the fracturing pressure would need to be maintained for the fracturing fluid to flow
from the fracture zone to an overlying aquifer is given by

t=
where

t

d 2 − d1

(11)

v

= required travel time

INJECTION TIME REQUIRED FOR FLOW TO REACH AQUIFER in years

1.0E+05
Pore pressure in fracture zone = 110% of the horizontal stress at the top of the shale
Pore pressure at bottom of aquifer = 0
Depth to Bottom of Aquifer = 1000 ft
10% Porosity

HYDRAULIC
CONDUCTIVITY
in cm/sec

1.0E+04

1.0E-04
1.0E-05
1.0E-06
1.0E-07
1.0E-08

1.0E+03

1.0E+02

1.0E+01

1.0E+00

Length of typical frac stage < 1 day = 3E-03 years
1.0E-01
2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

DEPTH TO TOP OF SHALE in feet

Figure 3: Injection time required for fracture fluid to reach aquifer as a function of hydraulic
conductivity

Figure 3 shows the required travel time based on the average gradients shown in Figure 1 over
a range of hydraulic conductivity values and for the maximum aquifer depth of 1000 feet. For all
lesser aquifer depths, the required flow time would be longer. The required flow times under the
fracturing pressure is several orders of magnitude greater than the duration over which the
fracturing pressure would be applied.
Figure 4 presents the results of a similar analysis, but with the hydraulic conductivity held at
1E-5 cm/sec and considering various depths to the bottom of the aquifer. Compared to a 1000
ft. deep aquifer, 10 to 20 more years of sustained fracturing pressure would be required for the
fracturing fluid to reach an aquifer that was only 200 ft. deep.
The required travel times shown relate to the movement of the groundwater. Dissolved
chemicals would move at a slower rate due to retardation. The retardation factor, which is the
August 2009

Final SGEIS 2015, Page A11-7

29

 NYSERDA
Agreement No. 9679

ratio of the chemical movement rate compared to the water movement rate, is always between
0.0 and 1.0, so the required travel times for any dissolved chemical would be greater than those
shown in Figures 3 and 4.

INJECTION TIME REQUIRED FOR FLOW TO REACH AQUIFER in years

70

10% Porosity
Hydraulic Conductivity = 1E-5 cm/sec
Pore pressure at bottom of aquifer = 0
Pore pressure in fracture zone = 110% of the horizontal stress at the top of the shale

60

50

40

30

DEPTH TO BOTTOM
OF AQUIFER (ft)

200
400

20

600
800
1000

10

Length of typical frac stage < 1 day
0
2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

DEPTH TO TOP OF SHALE in feet

Figure 4: Injection time required for flow to reach aquifer as a function of aquifer depth

1.2.4.5 Pore storage volume
The fourth aspect to consider in evaluating the potential for adverse impacts to overlying
aquifers is the volume of fluid injected compared to the volume of the void spaces and fractures
that the fluid would need to fill in order to flow from the fracture zone to the aquifer. Figure 5
shows the void volume based on 10% total porosity for the geologic materials for various
combinations of depths for the bottom of an aquifer and for the top of the shale, calculated as
follows:

V = d1 − d 2 × n ×
where

V

43,560 ft 2 7.48 gal
×
acre
ft 3

(12)

= volume of void spaces and fractures

A typical slickwater fracturing treatment in a horizontal well would use less than 4 million gallons
of fracturing fluid, and some portion of this fluid would be recovered as flowback. The void
volume, based on 10% total porosity, for the geologic materials between the bottom of an
aquifer at 1,000 ft. depth and the top of the shale at a 2,000 ft. depth is greater than 32 million
gallons per acre. Since the expected area of a well spacing unit is no less than the equivalent of
August 2009

Final SGEIS 2015, Page A11-8

30

 NYSERDA
Agreement No. 9679

40 acres per well,142,143,144,145 the fracturing fluid could only fill about 0.3% of the overall void
space. Alternatively, if the fracturing fluid were to uniformly fill the overall void space, it would be
diluted by a factor of over 300. As shown in Figure 5, for shallower aquifers and deeper shales,
the void volume per acre is significantly greater.
12

VOID VOLUME PER ACRE in million gallons

10% Porosity
Pore pressure at bottom of aquifer = 0
Pore pressure in fracture zone = 110% of the horizontal stress at the top of the shale
250

10

200

8

150

6
DEPTH TO BOTTOM
OF AQUIFER (ft)

200
400

100

4

600
800
1000
50

2

VOID VOLUME PER 40 ACRE SPACING UNIT in billion gallons

300

Typical volume of hydraulic fracturing fluid ≤ 4 million gallons per horizontal well
Typical well spacing unit area ≥ 40 acres per well
0
2,000

3,000

4,000

5,000

6,000

7,000

8,000

0
9,000

DEPTH TO TOP OF SHALE in feet

Figure 5: Comparison of void volume to frac fluid volume

1.2.5 Flow through fractures, faults, or unplugged borings
It is theoretically possible but extremely unlikely that a flow path such as a network of open
fractures, an open fault, or an undetected and unplugged wellbore could exist that directly
connects the hydraulically fractured zone to an aquifer. The open flow path would have a much
smaller area of flow leading to the aquifer and the resistance to flow would be lower. In such an
improbable case, the flow velocity would be greater, the time required for the fracturing fluid to
reach the aquifer would be shorter, and the storage volume between the fracture zone and the
aquifer would be less than in the scenarios described above. The probability of such a
combination of unlikely conditions occurring simultaneously (deep aquifer, shallow fracture
142

Infill wells could result in local increases in well density.
New York regulations (Part 553.1 Statewide spacing) require a minimum spacing of 1320 ft. from other oil and gas
wells in the same pool. This spacing equals 40 acres per well for wells in a rectangular grid.
144
New York Codes, Rules, and Regulations, Title 6 Department of Environmental Conservation, Chapter V
Resource Management Services, Subchapter B Mineral Resources, 6 NYCRR Part 553.1 Statewide spacing, (as of 5
April 2009).
145
NYSDEC, 2009, “Final Scope for Draft Supplemental Generic Environmental Impact Statement (dSGEIS) on the
Oil, Gas And Solution Mining Regulatory Program, Well Permit Issuance For Horizontal Drilling and High-Volume
Hydraulic Fracturing to Develop the Marcellus Shale and Other Low-permeability Gas Reservoirs”, February 2009.
143

August 2009

Final SGEIS 2015, Page A11-9

31

 NYSERDA
Agreement No. 9679

zone, and open flow path) is very small. The fracturing contractor would notice an anomaly if
these conditions led to the inability to develop or maintain the predicted fracturing pressure.
During flowback, the same conditions would result in a high rate of recapture of the frac fluid
from the open flow path, decreasing the potential for any significant adverse environmental
impacts. Moreover, during production the gradients along the open flow path would be toward
the production zone, flushing any stranded fracturing fluid in the fracture or unplugged wellbore
back toward the production well.
1.2.6 Geochemistry
The ability of the chemical constituents of the additives in fracturing fluids to migrate from the
fracture zone are influenced not just by the forces governing the flow of groundwater, but also
by the properties of the chemicals and their interaction with the subterranean environment. In
addition to direct flow to an aquifer, the constituents of fracturing fluid would be affected by
limitations on solubility, adsorption and diffusion.
1.2.6.1 Solubility
The solubility of a substance indicates the propensity of the substance to dissolve in a solvent,
in this case, groundwater. The substance can continue to dissolve up to its saturation
concentration, i.e. its solubility. Substances with high solubilities in water have a higher
likelihood of moving with the groundwater flow at high concentrations, whereas substances with
low solubilities may act as longer term sources at low level concentrations. The solubilities of
many chemicals proposed for use in hydraulic fracturing in New York State are not well
established or are not available in standard databases such as the IUPAC-NIST Solubility
Database.146
The solubility of a chemical determines the maximum concentration of the chemical that is likely
to exist in groundwater. Solubility is temperature dependent, generally increasing with
temperature. Since the temperature at the depths of the gas shales is higher than the
temperature closer to the surface where a usable aquifer may lie, the solubility in the aquifer will
be lower than in the shale formation.
Given the depth of the New York gas shales and the distance between the shales and any
overlying aquifer, chemicals with high solubilities would be more likely to reach an aquifer at
higher concentrations than chemicals of low solubility. Based on the previously presented fluid
flow calculations, the concentrations would be significantly lower than the initial solubilities due
to dilution.
1.2.6.2 Adsorption
Adsorption occurs when molecules of a substance bind to the surface of another material. As
chemicals pass through porous media or narrow fractures, some of the chemical molecules may
adsorb onto the mineral surface. The adsorption will retard the flow of the chemical constituents
relative to the rate of fluid flow. The retardation factor, expressed as the ratio of the fluid flow
velocity to the chemical movement velocity, generally is higher in fine grained materials and in
materials with high organic content. The Marcellus shale is both fine grained and of high organic
content, so the expected retardation factors are high. The gray shales overlying the Marcellus
146

IUPAC-NIST Solubility Database, Version 1.0, NIST Standard Reference Database 106, URL:
http://srdata.nist.gov/solubility/index.aspx.

August 2009

Final SGEIS 2015, Page A11-10

32

 NYSERDA
Agreement No. 9679

shale would also be expected to substantially retard any upward movement of fracturing
chemicals.
The octanol-water partition coefficient, commonly expressed as Kow, is often used in
environmental engineering to estimate the adsorption of chemicals to geologic materials,
especially those containing organic materials. Chemicals with high partition coefficients are
more likely to adsorb onto organic solids and become locked in the shale, and less likely to
remain in the dissolve phase than are chemicals with low partition coefficients.
The partition coefficients of many chemicals proposed for use in hydraulic fracturing in New
York State are not well established or are not available in standard databases. The partition
coefficient is inversely proportional to solubility, and can be estimated from the following
equation147

log K ow = −0.862 log S w + 0.710 
where

  Kow
Sw

(13)

= octanol-water partition coefficient 

= solubility in water at 20ºC in mol/liter 


Adsorption in the target black shales or the overlying gray shales would effectively remove
some percentage of the chemical mass from the groundwater for long periods of time, although
as the concentration in the water decreased some of the adsorbed chemicals could repartition
back into the water. The effect of adsorption could be to lower the concentration of dissolved
chemicals in any groundwater migrating from the shale formation.
1.2.6.3 Diffusion
Through diffusion, chemicals in fracturing fluids would move from locations with higher
concentrations to locations with lower concentrations. Diffusion may cause the transport of
chemicals even in the absence of or in a direction opposed to the gradient driving fluid flow.
Diffusion is a slow process, but may continue for a very long time. As diffusion occurs, the
concentration necessarily decreases. If all diffusion were to occur in an upward direction (an
unlikely, worst-case scenario) from the fracture zone to an overlying freshwater aquifer, the
diffused chemical would be dispersed within the intervening void volume and be diluted by at
least an average factor of 160 based on the calculated pore volumes in Section 1.2.4.5. Since a
concentration gradient would exist from the fracture zone to the aquifer, the concentration at the
aquifer would be significantly lower than the calculated average. Increased vertical distance
between the aquifer and the fracture zone due to shallower aquifers and deeper shales would
further increase the dilution and reduce the concentration reaching the aquifer.
1.2.6.4 Chemical interactions
Mixtures of chemicals in a geologic formation will behave differently than pure chemicals
analyzed in a laboratory environment, so any estimates based on the solubility, adsorption, or
diffusion properties of individual chemicals or chemical compounds should only be used as a
guide to how they might behave when injected with other additives into the shale. Co-solubilities
can change the migration properties of the chemicals and chemical reactions can create new
compounds.
147

Chiou, Cary T., Partition and adsorption of organic contaminants in environmental systems, John Wiley & Sons,
New York, 2002, p.57.

August 2009

Final SGEIS 2015, Page A11-11

33

 NYSERDA
Agreement No. 9679

1.2.7 Conclusions
Analyses of flow conditions during hydraulic fracturing of New York shales help explain why
hydraulic fracturing does not present a reasonably foreseeable risk of significant adverse
environmental impacts to potential freshwater aquifers. Specific conditions or analytical results
supporting this conclusion include:
● The developable shale formations are separated from potential freshwater aquifers by at
least 1,000 feet of sandstones and shales of moderate to low permeability.
● The fracturing pressures which could potentially drive fluid from the target shale
formation toward the aquifer are applied for short periods of time, typically less than one day
per stage, while the required travel time for fluid to flow from the shale to the aquifer under
those pressures is measured in years.
● The volume of fluid used to fracture a well could only fill a small percentage of the void
space between the shale and the aquifer.
● Some of the chemicals in the additives used in hydraulic fracturing fluids would be
adsorbed by and bound to the organic-rich shales.
● Diffusion of the chemicals throughout the pore volume between the shale and an aquifer
would dilute the concentrations of the chemicals by several orders of magnitude.
● Any flow of frac fluid toward an aquifer through open fractures or an unplugged wellbore
would be reversed during flowback, with any residual fluid further flushed by flow toward the
production zone as pressures decline in the reservoir during production.
The historical experience of hydraulic fracturing in tens of thousands of wells is consistent with
the analytical conclusion. There are no known incidents of groundwater contamination due to
hydraulic fracturing.

August 2009

Final SGEIS 2015, Page A11-12

34

 Appendix 12
Beneficial Use Determination (BUD)
Notification Regarding Road Spreading
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

New York State Department of Environmental Conservation
Division of Solid and Hazardous Materials
Bureau of Solid Waste, Reduction and Recycling, gth Floor

....,

625 Broadway, Albany, New York 12233-7253
Phone: (518) 402-8704
Website:

•

FAX: (518) 402-9024

www.dec.ny.gov

Alexander 8. Grannis
Commissioner

January 2009

NOTICE TO 

GAS AND OIL WELL & LPG STORAGE 

FLUID HAULERS 

All gas or oil well drilling and production fluids including but not limited to brine and fracturing
fluids, and brine from liquefied petroleum gas (LPG) well storage operations, transported for
disposal, road spreading, reuse in another gas or oil well, or recycling must be specifically
identified in Part C and D of the New York State Waste Transporter Permit Application Form.
Transporters must idcntify the type of fluid proposed to be transported in Section C in the Non­
Hazardous Industrial/Commercial box and the Disposal or Destination Facility (or Use) in Part
D.
Fracture fluids obtained during flowback operations may not be spread on roads and must be
disposed at facilities authorized by the Department. Such disposal facilities must be identified in
Part D of the pennit application. If fluids are to be transported for use or reuse at another gas or
oil well, that location must be identified in Part D of the pennit application.
With respect to fluids transported under a Waste Transporter Penni.t, only production brines or
brine from LPG storage operations may be used for road spreading. Drilling, fracing, and
plugf,ring fluids are not acceptable for road spreading.
Any person, including any govemment entity, applying for a Part 364 permit or pennit
modification to use production brine from oil or gas wells or brine from LPG well storage
operations for road spreading purposes (i.e. road de-icing, dust suppression, or road stabilization)
must submit a petition for a beneficial use detennination (BUD). If a contract hauler is applying
for a Part 364 permit or permit modification to deliver brine to a government agency for road
spreading purposes, that govemment agency must submit the BUD petition. The BUD must be
granted and the Part 364 permit/modification must be issued before brine can be removed from
the well or LPG storage site for road spreading purposes or storage at an otlsite facility.
The BUD petition must include:
I. An original letter signed and dated by the government agency representative or other property
owner authorizing the use of brine on the locations identified in below item 3.

Final SGEIS 2015, Page A12-1

 2. The name, address and telephone number of the person, company or government official 


seeking the approval. 

· 3. An identification (or map) of the specific roads or other areas that are to receive the brine and
any brine storage locations, excluding the well site storage locations.
4. The physical address of the brine storage locations from which the brine is hauled.
5. F or each well field

or

LPG storage facility, a chemical analysis of a representative sample of

the brine performed by a NYSDOH approved laboratory for the following parameters: calcium,
sodium, chloride, magnesium, total dissolved solids, pH, iron, barium, lead, sulfate, oil & grease,
benzene, ethylbenzene, toluene, and xylene. Depending upon the analytical results, the
Department may require additional analyses. (This analysis is not required for brine from a LPG
well operation with a valid New York State SPDES permit.)
6. A road spreading plan that includes a description of the procedures to prevent the brine from
flowing or running off into streams, creeks, lakes and other bodies of water. The plan should
include:
·

•

•

•

a description of how the brine will be applied, including the equipment to be used and the
method for controlling the rate of application. In general this should indicate that the
brine is applied by use of a spreader bar or similar spray device with shut-off controls in
the cab of the truck; and with vehicular equipment that is dedicated to this use or cleaned
of previously transported waste materials prior to this use;
the proposed rate and frequency of application;
a description of application restrictions. For dust control and road stabilization use this
description should indicate that the brine is not applied: after daylight hours; within 50
feet of a stream, creek, lake or other body of water; on sections of road having a grade
exceeding I 0 percent; or on wet roads, during rain, or when rain is imminent. For road·
deicing use, this description should indicate that the brine is applied in accordance
NYSDOT Guidelines for Anit-Tcing with Liquids and include any other restrictions.

7. Where applicable, a brine storage plan that includes:
•

•

•

a description of the type, material, size, and number of storage tanks and the maximum
anticipated storage;
procedures for run off and nm-on control;
provisions for secondary containment; and 

a contingency plan. 


If you have any questions concerning your pennit, please feel free to call this office at
(518) 402-8707. You may also visit our public website at the address above for infonnation and
forms to download or print.

Waste Transporter Permit Program

Final SGEIS 2015, Page A12-2

 Appendix 13
Radiological Data Production Brine from
NYS Marcellus Wells
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

NYS Marcellus Radiological Data from Production Brine
Well

API #

Date
Collected

Town (County)

Maxwell 1C

31-101-22963-03-01

10/7/2008

Caton (Steuben)

Frost 2

31-097-23856-00-00

10/8/2008

Orange (Schuyler)

Webster T1

31-097-23831-00-00

10/8/2008

Orange (Schuyler)

Parameter

Result +/- Uncertainty

Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238
Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238
Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238

17,940 +/- 8,634 pCi/L
4,765 +/- 3,829 pCi/L
-2.26 +/- 5.09 pCi/L
-0.748 +/- 4.46 pCi/L
9.27 +/- 46.8 pCi/L
37.8 +/- 21.4 pCi/L
2,472 +/- 484 pCi/L
874 +/- 174 pCi/L
53.778 +/- 8.084 pCi/L
0.359 +/- 0.221 pCi/L
0.065 +/- 0.103 pCi/L
0.383 +/- 0.349 pCi/L
0.077 +/- 0.168 pCi/L
0.077 +/- 0.151 pCi/L
14,530 +/-3,792 pCi/L
4,561 +/- 1,634 pCi/L
2.54 +/- 4.64 pCi/L
-1.36 +/- 3.59 pCi/L
-9.03 +/- 36.3 pCi/L
31.6 +/- 14.6 pCi/L
2,647 +/- 494 pCi/L
782 +/- 157 pCi/L
47.855 +/- 9.140 pCi/L
0.859 +/- 0.587 pCi/L
0.286 +/- 0.328 pCi/L
0.770 +/- 0.600 pCi/L
0.113 +/- 0.222 pCi/L
0.431 +/- 0.449 pCi/L
123,000 +/- 23,480 pCi/L
12,000 +/- 2,903 pCi/L
1.32 +/- 5.76 pCi/L
-2.42 +/- 4.76 pCi/L
-18.3 +/- 44.6 pCi/L
34.5 +/- 15.6 pCi/L
16,030 +/- 2,995 pCi/L
912 +/- 177 pCi/L
63.603 +/- 9.415 pCi/L
0.783 +/- 0.286 pCi/L
0.444 +/- 0.213 pCi/L
0.232 +/- 0.301 pCi/L
0.160 +/- 0.245 pCi/L
-0.016 +/- 0.015 pCi/L

Final SGEIS 2015, Page A13-1

 Well

API #

Date
Collected

Town (County)

Calabro T1

31-097-23836-00-00

3/26/2009

Orange (Schuyler)

Maxwell 1C

31-101-22963-03-01

4/1/2009

Caton (Steuben)

Haines 1

31-101-14872-00-00

4/1/2009

Avoca (Steuben)

Parameter
Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238
Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238
Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238

Final SGEIS 2015, Page A13-2

Result +/- Uncertainty
18,330 +/- 3,694 pCi/L
-324.533 +/- 654 pCi/L
3.14 +/- 7.19 pCi/L
0.016 +/- 5.87 pCi/L
17.0 +/- 51.9 pCi/L
24.2 +/- 13.6 pCi/L
13,510 +/- 2,655 pCi/L
929 +/- 179 pCi/L
45.0 +/- 8.41 pCi/L
2.80 +/- 1.44 pCi/L
-0.147 +/- 0.645 pCi/L
1.91 +/- 1.82 pCi/L
0.337 +/- 0.962 pCi/L
0.765 +/- 1.07 pCi/L
3,968 +/- 1,102 pCi/L
618 +/- 599 pCi/L
-0.443 +/- 3.61 pCi/L
-1.840 +/- 2.81 pCi/L
17.1 +/- 29.4 pCi/L
26.4 +/- 8.38 pCi/L
7,885 +/- 1,568 pCi/L
234 +/- 50.5 pCi/L
147 +/- 23.2 pCi/L
1.37 +/- 0.918 pCi/L
0.305 +/- 0.425 pCi/L
1.40 +/- 1.25 pCi/L
0.254 +/- 0.499 pCi/L
0.508 +/- 0.708 pCi/L
54.6 +/- 37.4 pCi/L
59.3 +/- 58.4 pCi/L
0.476 +/- 2.19 pCi/L
-0.166 +/- 2.28 pCi/L
7.15 +/- 19.8 pCi/L
0.982 +/- 4.32 pCi/L
0.195 +/- 0.162 pCi/L
0.428 +/- 0.335 pCi/L
0.051 +/- 0.036 pCi/L
0.028 +/- 0.019 pCi/L
0.000 +/- 0.007 pCi/L
0.000 +/- 0.014 pCi/L
0.000 +/- 0.005 pCi/L
-0.007 +/- 0.006 pCi/L

 Well

API #

Date
Collected

Town (County)

Haines 2

31-101-16167-00-00

4/1/2009

Avoca (Steuben)

Carpenter 1

31-101-26014-00-00

4/1/2009

Troupsburg
(Steuben)

Zinck 1

31-101-26015-00-00

4/1/2009

Woodhull
(Steuben)

Parameter
Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238
Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238
Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238

Final SGEIS 2015, Page A13-3

Result +/- Uncertainty
70.0 +/- 47.8 pCi/L
6.79 +/- 54.4 pCi/L
2.21 +/- 1.64 pCi/L
1.42 +/- 2.83 pCi/L
5.77 +/- 15.2 pCi/L
2.43 +/- 3.25 pCi/L
0.163 +/- 0.198 pCi/L
0.0286 +/- 0.220 pCi/L
0.048 +/- 0.038 pCi/L
0.040 +/- 0.022 pCi/L
-0.006 +/- 0.011 pCi/L
0.006 +/- 0.019 pCi/L
0.006 +/- 0.013 pCi/L
-0.013 +/- 0.009 pCi/L
7,974 +/- 1,800 pCi/L
1,627 +/- 736 pCi/L
2.26 +/- 4.97 pCi/L
-0.500 +/- 3.84 pCi/L
49.3 +/- 38.1 pCi/L
30.4 +/- 11.0 pCi/L
5,352 +/- 1,051 pCi/L
138 +/- 37.3 pCi/L
94.1 +/- 14.9 pCi/L
1.80 +/- 0.946 pCi/L
0.240 +/- 0.472 pCi/L
0.000 +/- 0.005 pCi/L
0.000 +/- 0.005 pCi/L
-0.184 +/- 0.257 pCi/L
9,426 +/- 2,065 pCi/L
2,780 +/- 879 pCi/L
5.47 +/- 5.66 pCi/L
0.547 +/- 4.40 pCi/L
-16.600 +/- 42.8 pCi/L
48.0 +/- 15.1 pCi/L
4,049 +/- 807 pCi/L
826 +/- 160 pCi/L
89.1 +/- 14.7 pCi/L
0.880 +/- 1.23 pCi/L
0.000 +/- 0.705 pCi/L
-0.813 +/- 0.881 pCi/L
-0.325 +/- 0.323 pCi/L
-0.488 +/- 0.816 pCi/L

 Well

API #

Date
Collected

Town (County)

Schiavone 2

31-097-23226-00-01

4/6/2009

Reading
(Schuyler)

Parker 1

31-017-26117-00-00

4/2/2009

Oxford
(Chenango)

WGI 10

31-097-23930-00-00

4/6/2009

Dix (Schuyler)

Parameter
Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238
Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238
Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238

Final SGEIS 2015, Page A13-4

Result +/- Uncertainty
16,550 +/- 3,355 pCi/L
1,323 +/- 711 pCi/L
1.46 +/- 5.67 pCi/L
-2.550 +/- 5.11 pCi/L
20.6 +/- 42.7 pCi/L
30.6 +/- 12.1 pCi/L
15,140 +/- 2,989 pCi/L
957 +/- 181 pCi/L
38.7 +/- 7.45 pCi/L
1.68 +/- 1.19 pCi/L
0.153 +/- 0.301 pCi/L
3.82 +/- 2.48 pCi/L
0.354 +/- 0.779 pCi/L
0.354 +/- 0.923 pCi/L
3,914 +/- 813 pCi/L
715 +/- 202 pCi/L
4.12 +/- 3.29 pCi/L
-1.320 +/- 2.80 pCi/L
-9.520 +/- 24.5 pCi/L
1.39 +/- 6.35 pCi/L
1,779 +/- 343 pCi/L
201 +/- 38.9 pCi/L
15.4 +/- 3.75 pCi/L
1.25 +/- 0.835 pCi/L
0.000 +/- 0.385 pCi/L
1.82 +/- 1.58 pCi/L
0.304 +/- 0.732 pCi/L
0.304 +/- 0.732 pCi/L
10,970 +/- 2,363 pCi/L
1,170 +/- 701 pCi/L
1.27 +/- 5.17 pCi/L
0.960 +/- 4.49 pCi/L
14.5 +/- 37.5 pCi/L
15.2 +/- 8.66 pCi/L
6,125 +/- 1,225 pCi/L
516 +/- 99.1 pCi/L
130 +/- 20.4 pCi/L
2.63 +/- 1.39 pCi/L
0.444 +/- 0.213 pCi/L
0.000 +/- 0.702 pCi/L
1.17 +/- 1.39 pCi/L
0.389 +/- 1.01 pCi/L

 Well

WGI 11

API #

31-097-23949-00-00

Date
Collected

4/6/2009

Town (County)

Parameter

Dix (Schuyler)

Gross Alpha
Gross Beta
Cesium-137
Cobalt-60
Ruthenium-106
Zirconium-95
Radium-226
Radium-228
Thorium-228
Thorium-230
Thorium-232
Uranium-234
Uranium-235
Uranium-238

Final SGEIS 2015, Page A13-5

Result +/- Uncertainty
20,750 +/- 4,117 pCi/L
2,389 +/- 861 pCi/L
4.78 +/- 6.95 pCi/L
-0.919 +/- 5.79 pCi/L
-19.700 +/- 49.8 pCi/L
9.53 +/- 11.8 pCi/L
10,160 +/- 2,026 pCi/L
1,252 +/- 237 pCi/L
47.5 +/- 8.64 pCi/L
1.55 +/- 1.16 pCi/L
-0.141 +/- 0.278 pCi/L
0.493 +/- 0.874 pCi/L
0.000 +/- 0.540 pCi/L
-0.123 +/- 0.172 pCi/L

 This page intentionally left blank.

Appendix 14
Department of Public Service
Environmental Management and Construction
Standards and Practices – Pipelines
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

ENVIRONMENTAL MANAGEMENT AND CONSTRUCTION 

STANDARDS AND PRACTICES 

CHECK-OFF LIST: PART III

PIPELINE 

III. General Planning Objectives and Procedures
1. Planning Objectives
1.1 Supervision and Inspection
1.1.1 Environmental Inspection
1.1.2 Responsibilities of Environmental Inspector

3
3
5
5
5

2. Procedures for the Identification and Protection of Sensitive Resources
2.1 Rare and Endangered Species & Their Habitats
2.2 Cultural Resources
2.3 Streams, Wetlands & Other Water Resources
2.4 Active Agricultural Lands
2.5 Alternative/Conflicting Land Uses
2.6 Steep Slopes, Highly Erodible Soils & Flood Plains
2.7 Timber Resources, Commercial Sugarbushes & Unique/Old Growth Forests
2.8 Officially Designated Visual Resources

6
7
8
9
9
10
10
11
11

3. Land Requirements
3.1 Objectives
3.2 Pipeline Routing
3.3 Right-Of-Way Width
3.3.1 Permanent ROW
3.3.2 Temporary ROW
3.3.3 Extra Work Space
3.3.4 Associated/Appurtenant Facilities: Meter Site
3.3.5 Compressor Stations
3.3.6 Storage, Fabrication and other Construction Related Sites
3.3.7 Permanent Disposal Sites

12
12
12
13
13
13
13
14
15
15
16

4. Site Preparation
4.1 Objectives
4.2 Staking and ROW Delineation

16
16
17

5. Clearing in Upland Areas
5.1 Objectives
5.2 Definitions
5.3 Equipment

17
17
18
18

Final SGEIS 2015, Page A14-1

 5.4 Clearing Methods & Procedures in Upland Areas
5.5 Log Disposal
5.5.1 Construction Use
5.5.2 Log Piles
5.5.3 Sale
5.5.4 Chipping
5.6 Slash and Stump Disposal
5.6.1 Stacking and Scattering
5.6.2 Chipping
5.6.3 Burning
5.6.4 Hauling
5.6.5 Burial
5.7 Vegetation Buffer Areas
5.8 Walls and Fences
5.8.1 Stone Walls
5.8.2 Fences

19
20
20
20
21
21
21
21
22
22
22
23
23
24
24
24

6. Grading in Upland Locations
6.1 Objectives
6.2 Techniques and Equipment
6.3 Topsoil Stripping and Segregation
6.3.1 No Stripping
6.3.2 Ditchline
6.3.3 Ditch and Spoil
6.3.4 Full Width
6.4 Access Road & Construction Paths
6.4.1 Objectives
6.4.2 Construction Paths
6.4.3 Off ROW Access Roads

25
25
25
26
26
27
27
27
28
28
28
29

7. Erosion and Sedimentation Control
7.1 Objectives
7.2 Measures and Devices
7.2.1 Hay Bales and Silt Fence
7.2.2 Water Diversion Devices
7.2.2.1 Waterbars
7.2.2.2 Swales and Berms
7.2.2.3 Side Ditches
7.2.2.4 French Drains
7.2.2.5 Culverts
7.2.2.6 Sediment Retention Ponds and Filtration Devices
7.2.2.7 Catchment Basins
7.2.2.8 Mulch and Other Soil Stabilizers
7.2.2.9 Driveable Berms
7.3 Fugitive Dust Emissions

29
29
30
30
31
31
32
32
32
33
33
33
34
34
34

Final SGEIS 2015, Page A14-2

 8. Trenching
8.1 Objectives
8.2 Trenching Equipment
8.3 Ditch Width and Cover Requirements
8.4 Length of Open Trench
8.5 Ditch Plugs
8.6 Blasting
8.6.1 Preconstruction Studies
8.6.2 Monitoring and Inspection
8.6.3 Time Constraints and Notification
8.6.4 Remediation

34
34
35
35
36
36
37
37
38
38
38

9. Pipelaying
9.1 Objectives
9.2 Stringing
9.3 Fabrication
9.4 Trench Dewatering
9.5 Lowering In
9.6 Trench Breakers
9.7 Padding
9.8 Backfilling

39
39
39
40
40
41
41
41
41

10. Waterbody Crossings
10.1 Objectives
10.2 Definition
10.2.1 Categories and Classifications
10.3 Spill Prevention
10.4 Buffer Areas
10.5 Installation
10.5.1 Equipment Crossings
10.5.2 Concrete Coating
10.6 Dry Crossing Methods
10.6.1 Trenching
10.6.2 Lowering-in / Pipe Placement
10.6.3 Trench Backfill
10.6.4 Cleanup and Restoration
10.7 Dry Stream Crossing Techniques
10.7.1 Bores and Pipe Push
10.7.2 Directional Drilling
10.7.3 Other Dry Crossing Methods
10.7.3.1 Flume Method
10.7.3.2 Dam and Pump Method

42
42
42
43
44
45
45
45
46
47
47
48
48
48
49
49
49
50
50
51

11. Wetland Crossings

Final SGEIS 2015, Page A14-3

 11.1 Objectives
11.2 Regulatory Agencies and Requirements
11.3 Wetland Identification and Delineation
11.4 Timing and Scheduling Constraints
11.5 Clearing Methods
11.6 Construction Path and Access Road Construction
11.6.1 No Road or Pathway
11.6.2 Bridges and Flotation Devices
11.6.3 Timber Mats
11.6.4 Log Rip Rap (Corduroy) Roads
11.6.5 Filter Fabric and Stone Roads
11.7 Grading
11.8 Trenching
11.8.1 Standard Trenching
11.8.2 Trenching from Timber Mats
11.8.3 One Pass In-line Trenching
11.8.4 Modified One Pass In-Line
11.9 Directional Drill and Conventional Bore
11.10 Spoil Placement and Control
11.10.1 Topsoil Stripping
11.11 Ditch Plugs in Wetlands
11.12 Pipe Fabrication and Use
11.12.1 Concrete Coated Pipe
11.12.2 Fabrication
11.13 Trench Dewatering
11.14 Backfill
11.15 Cleanup and Restoration
11.15.1 Restoration
11.15.2 Cleanup

52
53
53
54
54
55
55
56
56
56
57
58
58
58
59
59
59
59
60
60
61
61
61
61
62
62
63
63
63

12. Agricultural Lands
12.1 Objectives
12.2 Types of Agricultural Lands/mowed meadow
12.3 Clearing
12.4 Grading and Topsoil Segregation
12.4.1 Grading
12.4.2 Topsoiling
12.4.2.1 Cropland
12.4.2.2 Pasture/Grazing/mowed meadow
12.5 Drain Tiles
12.6 Trenching
12.7 Backfilling
12.8 Cleanup and Restoration
12.9 Revegetation
12.9.1 Seed Mixtures

63
64
64
65
65
65
65
65
66
66
67
67
68
68
68

Final SGEIS 2015, Page A14-4

 12.9.2 Timing
12.9.3 Mulching
12.9.4 Temporary Diversion Berms
12.10 Remediation and Monitoring

69
69
69
69

13. Testing

70

14. General Cleanup and Restoration
14.1 Objectives
14.2 Cleanup
14.3 Restoration
14.3.1 Wooded and non-agricultural Uplands
14.3.1.1 Grading
14.3.1.2 Lime Application
14.3.1.3 Fertilizing
14.3.1.4 Discing and Raking
14.3.1.5 Seeding and Planting
14.3.2 Restoration – Urban Residential

71
71
71
73
73
73
74
74
75
75
77

15. Noise Impact Mitigation
15.1 Objectives
15.2 Noise Sensitive Receptors
15.3 Remediation and Control
15.3.1 Noise Control Measures for Equipment And Linear Construction
15.3.2 Noise Control Measures for Point Source Noise Producers
15.4 Compressor Stations

77
77
78
78
78
79
80

16. Transportation and Utility Crossings
16.1 Objectives
16.2 Road and Highway Crossings
16.2.1 Permitting
16.2.2 Preconstruction Planning
16.2.3 Road Crossing Methods
16.2.3.1 Trenched Open-Cut
16.2.3.2 Trenchless, Bore/Direct Drill
16.2.4 Longitudinal In-Road Construction
16.2.5 Signs
16.2.6 Repairs and Restoration
16.3 Canal Crossings
16.3.1 Scheduling
16.3.2 Construction
16.3.3 Restoration
16.4 Railroad Crossings
16.5 Utility Crossings
16.5.1 Overhead Electric Facilities

80
80
81
81
81
82
82
83
83
84
85
85
85
86
86
86
87
87

Final SGEIS 2015, Page A14-5

 16.5.1.1 Perpendicular Crossings
16.5.1.2 Linear ROW Co-occupation
16.5.2 Underground Utility Crossings

87
88
90

17. Hazardous Materials
17.1 Objectives
17.2 Regulatory Concerns
17.3 Spill Control Equipment
17.3.1 Upland
17.3.2 Waterborne Equipment
17.4 Storage and Handling
17.4.1 Storage
17.4.2 Equipment Refueling
17.5 Spill Response Procedures
17.6 Excavation and Disposal
17.7 Hazardous Waste Contact

90
90
90
93
93
94
94
94
95
96
96
96

18. Pipeline Operation, ROW Management & Maintenance
18.1 Objectives
18.2 ROW Maintenance
18.3 Inspection
18.4 Vegetation Maintenance
18.4.1 Mechanical Treatment
18.4.2 Chemical Treatment
18.4.2.1 Stem Specific Treatments
18.4.2.1.1 Basal Treatments
18.4.2.1.2 Stem Injection
18.4.2.1.3 Cut and Treat
18.4.2.2 Non Stem-specific Applications

97
97
97
98
98
99
99
99
99
100
100
100

19. Communications and Compliance
19.1 Communication with Staff and the Commission
19.1.1 Pre-filing Contact
19.1.2 Post-filing Contact
19.1.3 Post Certification Contact
19.2 Compliance with Commission Orders

101
101
101
101
101
101

Final SGEIS 2015, Page A14-6

 Appendix 15
Hydraulic Fracturing –
15 Statements from Regulatory Officials
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

 

Part A

Congressional Testimony

 

This page intentionally left blank.

STATEMENT OF
SCOTTKELL
ON BEHALF OF THE
GROUND WATER PROTECTION COUNCIL 

HOUSE COMMITTEE ON NATURAL RESOURCES 

SUBCOMMITTEE ON ENERGY AND MINERAL RESOURCES 

WASHINGTON, D.C. 

JUNE4 , 2009 


Mr. Chairman, thank you for the opportunity to testify today. My name is Scott
Kell. I am President of the Ground Water Protection Council (GWPC) and appear here
today on its behalf. I am also Deputy Chief of the Ohio Department of Natural
Resources Division of Mineral Resources Management. With me today are Mike
Paque, Executive Director of the GWPC, Dave Bolin, Assistant Director of the Alabama
Oil and Gas Board, and Lori Wrotenbery, Director of the Oklahoma Corporation
Commission's Oil and Gas Conservation Division . Within our respective States, we are
responsible for implementing the state regulations governing the exploration and
development of oil and natural gas resources. First and foremost, we are resource
protection professionals committed to stewardship of water resources in the exercise of
our authority.
The GWPC is a non-profit association of state agencies responsible for environmental
safeguards related to ground water. The members of the association consist of state
ground water and underground injection control regulators. The GWPC provides a
forum through which its state members work with federal scientists and regulators,
environmental groups, industry, and other stakeholders to advance protection of ground
water resources through development of policy and regulation that is based on sound
science . I have included a list of the GWPC Board of Directors in our written
submission.
The GWPC understands that our nation's water and energy needs are intertwined, and
that demand for both resources is increasjng. Smart energy policy will consider and
minimize impacts to water resources.
With respect to the protection of water resources, the GWPC recently published two
reports of note. The first of these reports is called Modem Shale Gas Development in
the United States: A Primer (http./lwww.gwpc.orgle­
libraryldocumentslgenerai!Shale%20Gas%20Primer%202009.pd0. The primer
discusses the regulatory framework, policy issues, and technical aspects of developing
unconventional shale gas resources. As you know, there are numerous deep shale gas
basins in the United States, which contain trillions of cubic feet of natural gas. The
environmentally responsible development of these resources is of critical importance to
the energy security of the U.S. Recently, however, there has been concern raised
about the methods used to tap these valuable resources. Technologies such as

Final SGEIS 2015, Page A15A-1

 hydraulic fracturing have been characterized as being environmentally risky and
inadequately regu lated . The primer is designed to provide accurate technical
information to assist policy makers in their understanding of these issues.
In recent months, the states have become aware of press reports and websites alleging
that six states have documented over one thousand incidents of ground water
contamination resulting from the practice of hydraulic fracturing . Such reports are not
accurate. Attached to my testimony are signed statements from state officials
representing Ohio, Pennsylvania, New Mexico, Alabama, and Texas, responding to
these allegations.
From the standpoint of the GWPC, the most critical issue is protection of water
resources. As such, our goal is to ensure that oil and gas development is managed in a
way that does not create unnecessary and unwarranted risks to water. As a state
regulatory official, I can assure you that our regulations are focused on this task.
This leads me to the second report the GWPC has recently published.
This report, entitled State Oil and Gas Regulations Designed to Protect Water
Resources, (http://www.gwpc.org/e­
library/documents/generai/Oil%20and%20Gas%20Regulation%20Report%20Final%20
with%20Cover%205-27-2009.pdf) evaluates regulations implemented by state oil and
gas regulatory agencies as they relate to the protection of water. To prepare this report,
the GWPC rev iewed the regulations of the twenty-seven states that, when combined,
account for more than 99.8% of all the oil and natural gas extracted in the U.S . annually.
To prepare this report, each state's regulatory requirements were studied with respect
to their water protection capacity. The study evaluated regulated processes such as
well drilling, construction, and plugging, above-ground storage tanks, pits and a number
of other topics. The report also contains a statistical analysis of state regulations. As a
result of our regulatory review and analysis, the GWPC concluded that state oil and gas
regulations are adequately designed to directly protect water resources t hrough the
application of specific programmatic elements such as permitting, well construction,
hydraulic fracturing , waste handling , and well plugging requirements. While State
regulations are generally adequate, the GWPC report makes the following
recommendations .
First, a study of effective hydraulic fracturing practices should be considered for the
purpose of developing Best Management Practices (BMPs) that can be adjusted to fit
the specific conditions of individual states. A one-size-fits-all federal program is not the
most effective way to regulate in this area. BMPs related to hydraulic fracturing would
assist states and operators in ensuring the safety of the practice. Of special concern
are zones in close proximity to underground sources of drinking water, as determined
by the state regulatory authority.
Second, the state review process conducted by the national non-profit organization
State Review of Oil and Natural Gas Environmental Regulations (STRONGER) is an
effective tool in assessing the capability of state programs to manage exploration and
production waste and in measuring program improvement over time. This process
should be expanded, where appropriate, to include state oil and gas programmatic

Final SGEIS 2015, Page A15A-2

 elements not covered by the current state rev iew guidelines. STRONGER is currently
convening a stakeholder workgroup to consider drafting guidelines for state regulation
of hyd raulic fracturing .
Finally, the GWPC concludes that implementation and advancement of electronic data
management systems has enhanced state regulatory capacity and focus. However,
further work is needed in the areas of paper-to-digital data conversion and inclusion of
more environmental, or water related data. States should continue to develop
comprehensive elect ron ic data management systems and incorporate w idely scattered
environmental data as expeditiously as possible . Federal agencies should provide
financial assistance to states in these efforts.
In conclusion , Mr. Chairman and Committee Members, we believe that state regulations
are designed to provide the level of water protection needed to assure water resources
remain both viable and available . The states are continuously striving to improve both
the regu latory language and the programmatic tools used to implement that language .
In th is regard, the GWPC will continue to assist states w ith their regulatory needs for the
purpose of protecting water, our most vita l natural resource .
Thank you .

Final SGEIS 2015, Page A15A-3

 DISCLOSURE REQUIREMENT
Required by House Rule XI, clause 2(g)
and Rules of the Committee on Resources
1. Name: Scott R. Kell
2. Business Address: 2045 Morse Rd., Columbus, OH 43229-6605
3. Business Phone Number: 614-265-7058
4. Organization you are representing: The Ground Water Protection Council
5. Any training or educational certificates, diplomas or degrees or other educational experiences which add to
your qualifications to testify on or knowledge of the subject matter of the hearing: Bachelor's Degree in
Geology from Mount Union College and a Masters Degree in Geology from Kent State University.
6. Any professional licenses, certifications, or affiliations held which are relevant to your qualifications to testify
on or knowledge of the subject matter of the hearing:
7. Any employment, occupation, ownership in a firm or business, or work-related experiences which relate to your
qualifications to testify on or knowledge of the subject matter of the hearing:

8. Any offices, elected positions, or representational capacity held in the organization on whose behalf you are
testifying: Chief ofthe Ohio Department of Natural Resources, Division of Mineral Resources Management;
President of the Ground Water Protection Council

9. Any federal grants or contracts (including subgrants or subcontracts) from the Department of the Interior
(and /or other agencies invited) which you have received in the last three years, including the source and the
amount of each grant or contract: Office of Surface Mining, 2008 National Technology Transfer Grant,
RBDMS-W, $200,000

10. Any federal grants or contracts (including subgrants or subcontracts) the Department of the Interior (and /or
other agencies invited) which were received in the last three years by the organization(s) which you represent
at this hearing, including the source and amount of each grant or contract: Office of Surface Mining, 2008
National Technology Transfer Grant, RBDMS-W, $200,000

11. Any other information you wish to convey which might aid the members of the Committee to better
understand the context of your testimony:

June 2, 2009 (5:31PM)- non governmental witness

Final SGEIS 2015, Page A15A-4

 GWPC Board of Directors 

Sarah Pillsbury
New Hampshire Department Of Environmental
Services
95 Hazen Drive
Concord, NH 03302
John T. Barndt 

Delaware Dept Of Natural Resources 

& Environmental Control 

89 Kings Highway 

Dover, DE 1990 I 

Joseph J. Lee, P.G.
Pennsylvania Dept. Of Environmental Protection
Bureau Of Watershed Management
P.O. Box 8555 

Harrisburg, PA 170 15-8555 


David Terry
Massachusetts Dept O f Environmental Protection
One Winter Street, 6th Floor
Boston, MA 02108
Bradley J. Field 

New York Dept. Of Environmental Conservation 

Division Of Mineral Resources 

625 Broadway 

Albany, NY 12233-6500 

James Martin 

West Virginia Dept. Of Environmental Protection 

Office Of Oil & Gas 

60 I 57th Street, SE 

Charleston, WV 25304 

Jamie L. Crawford
Mississippi Dept. Of Environmental Quality
Office Of Land and Water Resources
P.O. Box 2309 

Jackson, MS 39225 


David Bolin
Alabama State Oil and Gas Board
P.O. Box 869999 

Tuscaloosa, AL 35486-6999 

Scott R. Kell 

Ohio Department Of Natural Resources 

2045 Morse Rd. 

Columbus, OH 43229-6605 


Jon L. Craig 

Oklahoma Department Of Environmental Quality 

707 N. Robinson, 8th Floor 

Oklahoma City, OK 73102 

Marty L. Link
Nebraska Department Of Environmental Q uality
P.O. Box 98922 

Lincoln, NE 68509-8922 


Michael Lemcke
Wisco nsin Department Of Natural Resources
P.O. Box 7921 

Madison, WI 53707 

Leslie Savage 

Texas Railroad Commission 

170 1 N. Congress 

P.O. Box 12967, Capitol Station 

Austin, TX 78711-2967 


Stan Belieu 

Nebraska Oil and Gas Conservation Commission 

922 Illinois Street, P.O. Box 399 

Sidney, NE 69162 


Kevin Frederick, P.G. 

Wyoming Dept. of Environmental Quality 

DEQ/WQD 

122 W. 25th ST. - 4W 

Cheyenne, WY 82002 


John Norma n 

Alaska Oil and Gas Conservation Commission 

333 West 7th Avenue, Suite 100 

Anchorage, AK 99501-3935 

Peter T Goodmann 

Kentucky Division of Water 

14 Reilly Road 

Frankfort, KY 4060 I 


Tom Richmond 

Montana Board of Oil & Gas Conservation 

2535 St. John's A venue 

Billings, MT 59102 

Harold P. Bopp 

California Department Of Conservation 

Div Of Oil, Gas, and Geothermal Resources 

80 I K Street, MS 20-20 

Sacramento, CA 95814-3530 


Mike Paque, Executive Director 

The Ground Water Protection Council 

13308 N. MacArthur Boulevard 

Oklahoma City, OK 73 I 42 


Final SGEIS 2015, Page A15A-5

 Attachment I - GWPC Testimony to the House Committee on Natural Resources, Subcommittee
on energy and Mineral Resources, June 4, 2009

State Oil and Natural Gas Regulations Designed to
Protect Water Resources
EXECUTIVE SUMMARY
Over the past several years the GWPC has been asked, "Do state oil and gas regulations protect water?"
How do their rules apply? Are they adequate? The first step in answering these questions is to evaluate
the regulatory frameworks within which programs operate. That is the purpose of this report.
State regulation of oil and natural gas exploration and production activities are approved under state Jaws
that typically include a prohibition against causing harm to the environment. This premise is at the heart
of the regulatory process. The regulation of oil and gas field activities is managed best at the state level
where regional and local conditions are understood and where regulations can be tailored to fit the needs
of the local environment. Hence, the experience, knowledge and information necessary to regulate
effectively most commonly rests with state regulatory agencies. Many state agencies use programmatic
tools and documents to apply state Jaws including regulations, formal and informal guidance, field rules,
and Best Management Practices (BMPs). They are also equipped to conduct field inspections,
enforcement/oversight, and witnessing of specific operations like well construction, testing and plugging.
Regulations alone cannot convey the full measure of a regulatory program. To gain a more complete
understanding of how regulatory programs actually function, one has to evaluate the use of state guides,
manuals, environmental policy processes, environmental impact statements, requirements established by
permit and many other practices. However, that is not the purpose of this study. This study evaluates the
language of state oil and gas regulations as they relate to the direct protection of water resources. lt is not
an evaluation of state programs.
To conduct the study, state oil and gas regulations were reviewed in the following areas: I) permitting, 2)
well construction, 3) hydraulic fracturing, 4) temporary abandonment, 5) well plugging, 6) tanks, 7) pits,
and 8) waste handling and spills. Within each area specific sub-areas were included to broaden the scope
of this review. For example, in the area of pits, a review was conducted of sub-areas such as pit liners,
siting, construction, use, duration and closure. The selection of the twenty-seven states for this study was
based upon the last full-year list (2007) of producing states compiled by the U.S. Energy Information
Administration.
ln the area of well construction, state regulations were evaluated to determine whether the setting of
surface casing below ground water zones was required, whether cement circulation on surface casing was
also required, and whether the state utilized recognized cement standards. Attachment 3 is a listing of the
programmatic areas and sub-areas reviewed.
After evaluation, each state was given the opportunity to review and comment on the findings and to
provide updated information concerning their regu lations. Thirteen states responded. These responses
were incorporated into the study.
One of the most important accomplishments ofthe study was the development of a regulations reference

document (Addendum). This document contains excerpted language from each state's oil and gas
regulations related to the programmatic areas included in the study. Hyperlinks to web versions of each

Final SGEIS 2015, Page A15A-6

 state's oil and gas regu lations are included as well as some of the fonns used by state agencies to
implement those regulations. A web enabled version of the study (to be completed by Septe mber, 2009)
will also contain numerous hyperlinked text segments designed to provide the reader with an easy and
effective way to review references and regulations.

Key Messages and Suggested Actions:
Key Message l : State oil and gas regulations are adequately designed to directly protect water resources
through the application of specific programmatic elements such as pennitting, well construction, well
plugging, and temporary abandonment requirements.
Suggested Action I: States should review current regulations in several programmatic areas to detennine
whether or not they meet an appropriate level of specificity (e.g. use of standard cements, plugging
materials, pit liners, siting criteria, and tank construction standards etc .. . )
Key Message 2: Experience s uggests that state oil and gas regulations related to well construction are
designed to be protective of ground water resources relative to the potential effects of hydraulic
fracturing. However, development of Best Management Practices (BMPs) related to hydraulic fracturing
would assist states and operators in insuring continued safety of the practice; especially as it relates to
hydraulic fracturing of zones in close proximity to ground water, as detennined by the regulatory
authority.
Suggested Action 2: A study of effective hydraulic fracturing practices should be considered for the
purpose of developing (BMPs); which can be adjusted to fit the specific conditions of individual states.
Key Message 3: Many states divide jurisdiction over certain elements of oil and gas regulation between
the oil and gas agency and other state water protection agencies. This is particularly evident in the areas
of waste handling and spill management.
Suggested Action 3: States with split jurisdiction of programs should insure that fonnal memorandums of
agreement (MOAs) between agencies exist and that these MOAs are maintain ed to provide more effective
and efficient implementation of regulations.
Key Message 4: The state review process conducted by the national non-profit organization State Review
of Oil and Natural Gas Environmental Regulations (STRONGER) is an effective tool in assessing the
capabili ty of state programs to manage exploration and production waste and in measuring program
improvement over time.
Suggested Action 4: The state review process should be continued and, where appropriate, expanded to
include state oil and gas programmatic elements not covered by the current state review guidelines.
Key Message 5: The implementation and advancement or electronic data managemen t systems has
enhanced regulatory capacity and focus. However, further work is needed in the areas of paper-to-digital
data conversion and inclusion of more environmental data.
Suggested Action 5: States should continue to develop and install comprehensive e lectronic data
management systems, convert paper records to electronic fonnats and incorporate widely scattered
environmental data as expeditiously as possible. Federal agencies should provide financial assistance to
states in these efforts.

Final SGEIS 2015, Page A15A-7

 Attachment 2 - GWPC Testimony to the House Committee on Natural Resources, Subcommittee
on energy and Mineral Resources, June 4, 2009

Modern Shale Gas Development-in the United States: A Primer
EXECUTIVE SUMMARY
Natural gas production from hydrocarbon rich shale formations, known as "shale gas," is one of the
most rapidly expanding trends in onshore domestic oil and gas exploration and production today.
In some areas, this has included bringing drilling and production to regions of the country that have
seen little or no activity in the past. New oil and gas developments bring change to the
environmental and socio-economic landscape, particularly in those areas where gas development is
a new activity. With these changes have come questions about the nature of shale gas development,
the potential environmental impacts, and the ability of the current regulatory structure to deal with
this development. Regulators, policy makers, and the public need an objective source of information
on which to base answers to these questions and decisions about how to manage the challenges
that may accompany shale gas development.
Natural gas plays a key role in meeting U.S. energy demands. Natural gas, coal and oil supply about
85% of the nation's energy, with natural gas supplying about 22% of the total. The percent
contribution of natural gas to the U.S. energy supply is expected to remain fairly constant for the
next 20 years.
The United States has abundant natural gas resources. The Energy Information Admi nistration
estimates that the U.S. has more than 1, 744 trillion cubic feet (tcf) of technically recoverable natural
gas, including 211 tcf of proved reserves (the discovered, economically recoverable fraction of the
original gas-in-place). Technically recoverable unconventional gas (shale gas, tight sands, and
coalbed methane) accounts for 60% of the onshore recoverable resource. At the U.S. production
rates for 2007, about 19.3 tcf, the current recoverable resource estimate provides enough natural
gas to supply the U.S. for the next 90 years. Separate estimates of the shale gas resource extend this
supply to 116 years.
Natural gas use is distributed across several sectors of the economy. It is an important energy
source for the industrial, commercial and electrical generation sectors, and also serves a vital role
in residential heating. Although forecasts vary in their outlook for future demand for natural gas,
they all have one thing in common: natural gas will continue to play a significant role in the U.S.
energy picture for some time to come.
The lower 48 states have a wide distribution of highly organic shales containing vast resources of
natural gas. Already, the fledgling Barnett Shale play in Texas produces 6% of all natural gas
produced in the lower 48 States. Three factors have come together in recent years to make shale
gas production economically viable: 1) advances in horizontal drilling, 2) advances in hydraulic
fracturing, and, perhaps most importantly, 3) rapid increases in natural gas prices in the last
several years as a result of significant supply and demand pressures. Analysts have estimated that
by 2011 most new reserves growth (50% to 60%, or approximately 3 bcfjday) will come from
unconventional shale gas reservoirs. The total recoverable gas resources in four new shale gas
plays (the Haynesville, Fayetteville, Marcellus, and Woodford) may be over 550 tcf. Total annual
production volumes of 3 to 4 tcf may be sustainable for decades. This potential for production in the

Final SGEIS 2015, Page A15A-8

 known onshore shale basins, coupled with other unconventional gas plays, is predicted to
contribute significantly to the U.S.'s domestic energy outlook.
Shale gas is present across much of the lower 48 States. The most active shales to date are the
Barnett Shale, the Haynesville/Bossier Shale, the Antrim Shale, the Fayetteville Shale, the
Marcellus Shale, and the New Albany Shale. Each of these gas shale basins is different and each has
a unique set of exploration criteria and operational challenges. Because of these differences, the
development of shale gas resources in each of these areas faces potentially unique opportunities
and challenges.
The development and production of oil and gas in the U.S., including shale gas, are regulated under
a complex set of federal, state, and local laws that address every aspect of exploration and
operation. All of the laws, regulations, and permits that apply to conventional oil and gas
exploration and production activities also apply to shale gas development. The U.S. Environmental
Protection Agency administers most of the fede rallaws, although development on federally-owned
land is managed primarily by the Bureau of Land Management (part of the Department of the
Interior) and the U.S. Forest Service (part of the Department ofAgriculture).ln addition, each state
in which oil and gas is produced has one or more regulatory agencies that permit wells, including
their design, location, spacing, operation, and abandonment, as well as environmental activities and
discharges, including water management and disposal, waste management and disposal, air
emissions, underground injection, wildlife impacts, surface disturbance, and worker health and
safety. Many of the federal laws are implemented by the states under agreements and plans
approved by the appropriate federal agencies.
A series of federal laws governs most environmental aspects of shale gas development. For
example, the Clean Water Act regulates surface discharges of water associated with shale gas
drilling and production, as well as storm water runoff from production sites. The Safe Drinking
Water Act regulates the underground injection of fluids from shale gas activities. The Clean Air Act
limits air emissions from engines, gas processing equipment, and other sources associated with
drilling and production. The National Environmental Policy Act (NEPA) requires that exploration
and production on federal lands be thoroughly analyzed for environmental impacts. Most of these
federal laws have provisions for granting "primacy" to the states (i.e., state agencies implement the
programs with federal oversight).
State agencies not only implement and enforce federal laws; they also have their own sets of state
laws to administer. The states have broad powers to regulate, permit, and enforce all shale gas
development activities- the drilling and fracture of the well, production operations, management
and disposal of wastes, and abandonment and plugging of the well. State regulation of the
environmental practices related to shale gas development, usually with federal oversight, can more
effectively address the regional and state-specific character of the activities, compared to one­
sizefits-all regulation at the federal level. Some of these specific factors include: geology, hydrology,
climate, topography, industry characteristics, development history, state legal structures,
population density, and local economics. State laws often add additional levels of environmental
protection and requirements. Also, several states have their own versions of the federal NEPA law,
requiring environmental assessments and reviews at the state level and extending those reviews
beyond federal lands to state and private lands.
A key element in the emergence of shale gas production has been the refinement of cost-effective
horizontal drilling and hydraulic fracturing technologies. These two processes, along with the
implementation of protective environmental management practices, have allowed shale gas

Final SGEIS 2015, Page A15A-9

 development to move into areas that previously would have been inaccessible. Accordingly, it is
important to understand the technologies and practices employed by the industry and their ability
to prevent or minimize the potential effects of shale gas development on human health and the
environment and on the quality of life in the communities in which shale gas production is located. ·
Modern shale gas development is a technologically driven process for the production of natural gas
resources. Currently, the drilling and completion of shale gas wells includes both vertical and
horizontal wells. In both kinds of wells, casing and cement are installed to protect fresh and
treatable water aquifers. The emerging shale gas basins are expected to follow a trend similar to the
Barnett Shale play with increasing numbers of horizontal wells as the plays mature. Shale gas
operators are increasingly relying on horizontal well completions to optimize recovery and well
economics. Horizontal drilling provides more exposure to a formation than does a vertical well.
This increase in reservoir exposure creates a number of advantages over vertical wells drilling. Six
to eight horizontal wells drilled from only one well pad can access the same reservoir volume as
sixteen vertical wells. Using multi-well pads can also significantly reduce the overall number of well
pads, access roads, pipeline routes, and production facilities required, thus minimizing habitat
disturbance, impacts to the public, and the overall environmental footprint.
The other technological key to the economic recovery of shale gas is hydraulic fracturing, which
involves the pumping of a fracturing fluid under high pressure into a shale formation to generate
fractures or cracks in the target rock formation. This allows the natural gas to flow out of the shale
to the well in economic quantities. Ground water is protected during the shale gas fracturing
process by a combination of the casing and cement that is installed when the well is drilled and the
thousands of feet of rock between the fracture zone and any fresh or treatable aquifers. For shale
gas development, fracture fluids are primarily water based fluids mixed with additives that help the
water to carry sand proppant into the fractures. Water and sand make up over 98% of the fracture
fluid, with the rest consisting of various chemical additives that improve the effectiveness of the
fracture job. Each hydraulic fracture treatment is a highly controlled process designed to the
specific conditions of the target formation.
The amount of water needed to drill and fracture a horizontal shale gas well generally ranges from
about 2 million to 4 million gallons, depending on the basin and formation characteristics. While
these volumes may seem very large, they are small by comparison to some other uses of water, such
as agriculture, electric power generation, and municipalities, and generally represent a small
percentage of the total water resource use in each shale gas area. Calculations indicate that water
use for shale gas development will range from less than 0.1% to 0.8% of total water use by basin.
Because the development of shale gas is new in some areas, these water needs may still challenge
supplies and infrastructure. As operators look to develop new shale gas plays, communication with
local water planning agencies, state agencies, and regional water basin commissions can help
operators and communities to coexist and effectively manage local water resources. One key to the
successful development of shale gas is the ident ification of water supplies capable of meeting the
needs of a development company for drilling and fracturing water without interfering with
community needs. While a variety of options exist, the conditions of obtaining water are complex
and vary by region.
After the drilling and fracturing of the well are completed, water is produced along with the natural
gas. Some of this water is returned fracture fluid and some is natural formation water. Regardless of
the source, these produced waters that move back through the wellhead with the gas represent a
stream that must be managed. States, local governments, and shale gas operators seek to manage
produced water in a way that protects surface and ground water resources and, if possible, reduces

Final SGEIS 2015, Page A15A-10

 future demands for fresh water. By pursuing the pollution prevention hierarchy of "Reduce, Re-use,
and Recycle" these groups are examining both traditional and innovative approaches to managing
shale gas produced water. This water is currently managed through a variety of mechanisms,
including underground injection, treatment and discharge, and recycling. New water treatment
technologies and new applications of existing technologies are being developed and used to treat
shale gas produced water for reuse in a variety of applications. This allows shale gas-associated
produced water to be viewed as a potential resource in its own right.
Some soils and geologic formations contain low levels of naturally occurring radioactive material
(NORM). When NORM is brought to the surface during shale gas drilling and production operations,
it remains in the rock pieces of the drill cuttings, remains in solution with produced water, or,
under certain conditions, precipitates out in scales or sludges. The radiation from this
NORM is weak and cannot penetrate dense materials such as the steel used in pipes and tanks.
Because the general public does not come into contact with gas field equipment for extended
periods, there is very little exposure risk from gas field NORM. To protect gas field workers, OSHA
requires employers to evaluate radiation hazards, post caution signs and provide personal
protection equipment when radiation doses could exceed regulatory standards. Although
regulations vary by state, in general, if NORM concentrations are less than regulatory standards,
operators are allowed to dispose of the material by methods approved for standard gas field waste.
Conversely, if NORM concentrations are above r egulatory limits, the material must be disposed of at
a licensed facility. These regulations, standards, and practices ensure that shale gas operations
present negligible risk to the general public and to workers with respect to potential NORM
exposure.
Although natural gas offers a number of environmental benefits over other sources of energy,
particularly other fossil fuels, some air emissions commonly occur during exploration and
production activities. Emissions may include NOx, volatile organic compounds, particulate matter,
SOz, and methane. EPA sets standards, monitors the ambient air across the U.S., and has an active
enforcement program to control air emissions from all sources, including the shale gas industry.
Gas field emissions are controlled and minimized through a combination of government regulation
and voluntary avoidance, minimization, and mitigation strategies.
The primary differences between modern shale gas development and conventional natural gas
development are the extensive uses of horizontal drilling and high-volume hydraulic fracturing. The
use of horizontal drilling has not introduced any new environmental concerns. In fact, the reduced
number of horizontal wells needed coupled with the ability to drill multiple wells from a single pad
has significantly reduced surface disturbances and associated impacts to wildlife, dust , noise, and
traffic. Where shale gas development has intersected with urban and industrial settings, regulators
and industry have developed special practices to alleviate nuisance impacts, impacts to sensitive
environmental resources, and interference with existing businesses. Hydraulic fracturing has been
a key technology in making shale gas an affordable addition to the Nation's energy supply, and the
technology has proved to be an effective stimulation technique. While some challenges exist with
water availability and water management, innovative regional solutions are emerging that allow
shale gas development to continue while ensuring that the water needs of other users are not
affected and that surface and ground water quality is protected. Taken together, state and federal
requirements along with the technologies and practices developed by industry serve to reduce
environmental impacts from shale gas operations.

Final SGEIS 2015, Page A15A-11

 Ohio Department of Natural Resources 

TED Sl'RJ<:KL\NO, GOVERNOR

SEAN D. LOGAN, OIRilC:TOR

.1Dhn F. Husted, Chief
Division ofMineral Resources Management
2045 Morse Road, Building H-3
Columbus, OH 43229-6693
Phone: {614} 265-6633 Fax: {614} 265-7999

May 27, 2009

Mike Paque
Executive Director
Ground Water Protection Council
13309 North MacArthur Boulevard
Oklahoma City, Oklahoma 73142
Dear Mike:
In recent months, the Ohio Department of Natural Resources, Division of Mineral
Resources Management (DMRM) has become aware of website and media releases
reporting that the State of Ohio has documented cases of ground water contamination
caused by the standard industry practice of hydraulic fracturing. Such reports are not
accurate. For example, some articles inaccurately portrayed hydraulic fracturing as the
cause of a natural gas incident in Bainbridge Township of Geauga County that resulted
in an in-home explosion in December 2007. This portrayal is not consistent with the
findings or conclusions of the DMRM.
DMRM completed a thorough investigation into the cause of a natural gas invasion into
fresh water aquifers in Bainbridge Township. The DMRM investigation found that this
incident was caused by a defective primary cement job on the production casing, which
was further complicated by operator error. As a consequence of this finding, the
operator corrected the construction problem by completing remedial cementing
operations. The findings and conclusions of this Investigation are available on the web
at http://www.dnr.state.oh.us/bainbridge/tabid/20484/default.aspx.
While an explosion significantly damaged one house, the investigation did not find any
evidence to support the claim "that pressure caused by hydraulic fracturing pushed the
gas...through a system of cracks into the ground water aquifer" as reported by some
media accounts. In actuality, the team of geologists who completed the evaluation of
the gas invasion incident in Bainbridge Township concluded that the problem would
have occurred even if the well had never been stimulated by hydraulic fracturing.
After 25 years of investigating citizen complaints of contamination, DMRM geologists
have not documented a single incident involving contamination of ground water
attributed to hydraulic fracturing. Over this time, the Ohio DMRM has consistently taken
decisive action to address oil and gas exploration and production practices that have
caused documented incidents of ground water contamination. The DMRM has initiated
amendments to statutes and rules, designed permit conditions, refined standards

ohiounr.com

Final SGEIS 2015, Page A15A-12

 Mr. Mike Paque
May 27, 2009
Page 2

operating procedures, and developed best management practices to improve protection
of ground water resources. These actions resulted in substantive changes including;
1.   elimination of tens of thousands of earthen pits for produced water storage;

2.   development of a model Class II brine injection well program;
3.   development of technical standards for synthetic liners used in pits during drilling
operations;
4.   tighter standards for construction and mechanical integrity testing for annular
disposal wells;
5.   detailed plugging regulations; and,
6.   establishment of an orphaned well plugging program funded by a severance tax
on oil and gas production.
The Ohio DMRM will continue to assign the highest priority to improving protection of
water resources and public health and safety.
In conclusion, the Ohio DMRM has not identified hydraulic fracturing as a significant
threat to ground water resources.
Sincerely,

Scott R. Kell, Deputy Chief
SRK/csc
Enclosure
cc:   Cathryn Loucas, Deputy Director, ODNR
Mike Shelton, Chief, Legislative Services, ODNR
John Husted, Chief, DMRM

Page 2 of 3

Final SGEIS 2015, Page A15A-13

 Pennsylvania Department of Environmental Protection
Rachel Carson State Office Building
P.O. Box 8555
Harrisburg, PA 17105-8555
June 1, 2009

Bu reau of Watershed Management

717-772-4048

Michael Paque, Executive Director
Ground Water Protection Council
13308 North MacArthur Boulevard
Oklahoma City, OK 73142
Dear Mr. Paque:

I am the program manager for Pennsylvania's Ground Water Protection Program in the
Pennsylvania Department of Environmental Protection (DEP). I have been concerned about
press reports stating extensive groundwater pollution and contamination of underground sources
ofdrinking water in Pennsylvania, as a result of hydraulic fracturing to stimulate gas production
from deep, gas bearing rock formations. DEP has not concluded that the activity of hydraulic
fracturing of these formations has caused wide-spread groundwater contami nation.
After review ofDEP's complaint database and interviews with regional staff that
investigate groundwater contamination related to oil and gas activities, no groundwater pollution
or disruption ofunderground sources ofdrinking water has been attributed to hydraulic
fracturing of deep gas formations. All investigated cases that have found pollution, which are
Jess then 80 in over 15 years of records, have been pri marily related to physical drilling through
the aquifers, improper design or setting of upper and middle well casings, or operator negligence.
If you have any questions or concerns, you may contact me by e-mail at
josless@state.pa.us or by telephone at 717-772-4048.
Sincerely,

~J.t)~
Joseph J. Lee, Jr., P.G., chief
Source Protection Section
Division of Water Use Planning

,, ,, f qual Oppor1 unuy l mployl•r

www.de p.state.pa.us

Final SGEIS 2015, Page A15A-14

 '.

.

~

Mark Fesmire
Division Director

Oil ConservatiOn Division

May 29, 2009

Mr. Michael Paque, Executive Director
Ground Water Protection Council
13308 N. MacArthur Blvd: ·
Oklahoma City, OK 73142
Dear Mike:
As per your request. have reviewed the New Mexico Oil Conservation
Division Data concerning water contamination caused by Hypraulic
Fracturing in New Mexico.
While we do currently .list approximately 421 ground water contamination
cases caused by pits and approximately an equal number caused by other
contamination mechanisms, we have found no example of contamination of
usable water where the cause was claimed to. be hydraulic fracturing.
Sincerely,,

/:/

.

7

·/;:?:y E. /--------~--

\

\


Mark E. Fesmire,PE 

Director, New Mexico Oil Conservation Division 


Oil Conservation Division 

1220 South St. Francis Drive" Santa Fe, New Mexico 87505 

Phone (505) 476-3440 ·Fax (505} 476-3462 • ~.emnrd .state .nm.us/O CO 


'

Final SGEIS 2015, Page A15A-15

.

. .

.

.

.

..

 STATE OIL AND GAS BOARD OF ALABAMA 

OIL AND GAS BOARD

420 Hackberry Lane
P. 0. Box 869999
TuscaLoosa, Alabama 35486-6999
Phone (205)349-2852
Fax (205)349-2861
www. ogb.state. a/. us

James H. Griggs, Chairman
Charles E. (Ward) Pearson, Vice Chairman
Rebecca Wright Pritchett, Member
Berry H. (Nick) Tew, Jr., Secretary
S. Marvin Rogers, Counsel

Berry H. (Nick) Tew, Jr. 

Oil and Gas Supervisor 

May 27,2009

Mr. Michel Paque, Executive Director
Ground Water Protection Council 

13308 N. MacArthur Blvd. 

Oklahoma City, OK 73142

Dear Mr. Paque:
This letter is in response to your recent inquiry regarding any cases of drinking water
contamination that have resulted from hydraulic fracturing operations to sti mulate oil and gas wells in
Alabama. I can state with authority that there have been no documented cases of drinking water
contamination caused by such hydraulic fracturing operations in our State.
The U.S. Environmental Protection Agency (EPA) approved the State Oil and Gas Board's
(Board) Class II Underground Injection Control (UIC) Program in August 1982, pursuant to Section 1425
of the Safe Drinking Water Act (SDWA). T his approval was made after EPA determined that the Board's
program accomplished the objectives of the SDWA, that being to protect underground sources of drinking
water. Obtaining primacy for the Class II UIC Program, however, was not the beginning of the Board's
ground-water protection programs. These programs, to include the regulation and approval of hydraulic
fracturing operations, have been actively implemented continually since the Board was established in
1945, pursuant to its legislative mandates.
The point to be made here is that the State of Alabama has a vested interest in protecting its
drinking water sources and has adequate rules and regulations, as well as statutory mandates, to protect
those sources from all oil and gas operations. The fact that there has been no documented case of
contamination from these operations, to include hydraulic fracturing, is a testament to the proactive
regulation of the industry by the Board. Additional federal regulations will not provide any greater leve l
of protection for our drinking water sources than is currently being provided.
If we can be of further assistance in this matter, please let me know.

Sincerely,

~- c. (JtrL__
David E. Bolin
Deputy Director

Mobile Regional Office, 4173 Commanders Drive, Mobile, AL 36615- 1421, Phone (251) 438-4848

Final SGEIS 2015, Page A15A-16

 RAILROAD COMMISSION OF TEXAS 

CHAIRMAN VICTOR G. CARRILLO 


May 29,2009
Mike Paque, Executive Director
Ground Water Protection Agency
13308 N. MacArthur Blvd.
Oklahoma City, OK 73142
Re:

Hydraulic Fracturing of Gas Wells in Texas

Dear Mr. Paque:
I am pleased that representatives of the Ground Water Protection Council will be appearing before the
U.S. House Committee on Natural Resources next week on the issue of hydraulic fracturing. I was asked
to participate but had a longstanding commitment to tour energy projects in Canada that prevented me
from personally participating.
I sincerely hope that you will clear up the misconception that there are "thousands" of contamination
cases in Texas and other states resulting from hydraulic fracturing. The Railroad Commission of Texas is
the chief regulatory agency over oil and gas activities in this state. Though hydraulic fracturing has been
used for over 50 years in Texas, our records do not indicate a single documented contamination case
associated with hydraulic fracturing.
The Texas Groundwater Protectio n Committee (TGPC) tracks groundwater pollution in Texas. All Texas
water protection agencies, inc luding the Railroad Commission, are members. Each year, the T GPC
publishes a Joint Groundwater Monitoring and Contamination Report, which can be found at
http://www.tceq.state.tx..us/comm exec/forms pubs/pubs/sfr/056 07 index.html. The 2007 report cites a
total of 354 active groundwater cases attributed to oil and gas activity - this in a state with over 255,000
active oil and gas wells. The majority of these cases are associated with previous practices that are no
longer allowed, or result from activity now prohibited by our existing regulations. A few cases were due
to blowouts that primarily occur during drilling activity. Not one of these cases was caused by hydraulic
fracturing activity.
Hydraulic fracturing plays a key role in the development of virtually all unconventional gas resources in
Texas. As of this year, over 11,000 gas wells have been completed (and hydraulically fractured) in the
Barnett Shale reservoir, one of the nation's most active and largest natural gas fields. Since 2000, over
five trillion cubic feet of gas has been produced from this one reservoir and the Barnett Shale production
currently contributes over 20% of Texas' total natural gas production. While the volume of gas-in-place
in the Barnett Shale is estimated to be over 27 trillion cubic feet, recovery of the gas is difficult because
of the shale's low permeability. The remarkable success ofthe Barnett Shale results in large part from the
use of horizontal drilling coupled with hydraulic fracturing. Even with this intense activity, there are no
known instances of ongo ing groundwater contamination in the Barnett Shale play .

P.O. Box 12967 *Austin, Texas 7871 1-2967

* Phone (512) 463-7131 * Fax (512) 463-7161

Final SGEIS 2015, Page A15A-17

 Regulation of oil and gas exploration and production activities, including hydraulic fracturing, has
traditionally been the province of the states. Most oil and gas producing state have had effective
programs in place for decades. Regulating hydraulic fracturing as underground injection under the
federal Safe Drinking Water Act would impose significant additional costs and regulatory burdens and
could ultimately reverse the significant U.S. domestic unconventional gas reserve additions of recent
years - harming domestic energy security. I urge the U.S. Congress to leave the regulatory authority over
hydraulic fraturing and other oil and gas activities where it belongs - at the state level.

Sincerely,

dC___n_.
Victor G. Carrillo, Chairman
Railroad Commission ofTexas

cc:  

Commissioner Michael Williams
Commissioner Elizabeth Ames Jones
John J. Tintera, Executive Director

Page 2 of2
Final SGEIS 2015, Page A15A-18

  

Part 

Statements from
Oil Gas Regulators from 12 Member States

 

This page intentionally left blank.

REGULATORY STATEMENTS ON HYDRAULIC FRACTURING


SUBMITTED BY THE STATES


JUNE 2009 

The following statements were issued by state regulators for the record related to hydraulic
fracturing in their states. Statements have been compiled for this document.
ALABAMA:
Nick Tew, Ph.D., P.G.
Alabama State Geologist & Oil and Gas Supervisor
President, Association of American State Geologists
There have been no documented cases of drinking water contamination that have resulted from
hydraulic fracturing operations to stimulate oil and gas wells in the State of Alabama.
The U.S. Environmental Protection Agency (EPA) approved the State Oil and Gas Board of
Alabama’s (Board) Class II Underground Injection Control (UIC) Program in August 1982,
pursuant to Section 1425 of the Safe Drinking Water Act (SDWA). This approval was made
after EPA determined that the Board’s program accomplished the objectives of the SDWA, that
is, the protection of underground sources of drinking water. Obtaining primacy for the Class II
UIC Program, however, was not the beginning of the Board’s ground-water protection programs.
These programs, which include the regulation and approval of hydraulic fracturing operations,
have been continuously and actively implemented since the Board was established in 1945,
pursuant to its mission and legislative mandates.
The State of Alabama, acting through the Board, has a vested interest in protecting its drinking
water sources and has adequate rules and regulations, as well as statutory mandates, to protect
these sources from all oil and gas operations, including hydraulic fracturing. The fact that there
has been no documented case of contamination from these operations, including hydraulic
fracturing, is strong evidence of effective regulation of the industry by the Board. In our view,
additional federal regulations will not provide any greater level of protection for our drinking
water sources than is currently being provided.

ALASKA:
Cathy Foerster
Commissioner
Alaska Oil and Gas Conservation Commission
There have been no verified cases of harm to ground water in the State of Alaska as a result of
hydraulic fracturing.
State regulations already exist in Alaska to protect fresh water sources. Current well construction
standards used in Alaska (as required by Alaska Oil and Gas Conservation Commission statutes

Final SGEIS 2015, Page A15B-1

 and regulations) properly protect fresh drinking waters. Surface casing is always set well below
fresh waters and cemented to surface. This includes both injectors and producers as the
casing/cementing programs are essentially the same in both types of wells. There are additional
casings installed in wells as well as tubing which ultimately connects the reservoir to the surface.
The AOGCC requires rigorous testing to demonstrate the effectiveness of these barriers
protecting fresh water sources.
By passing this legislation [FRAC Act] it is probable that every oil and gas well within the State
of Alaska will come under EPA jurisdiction. EPA will then likely set redundant construction
guidelines and testing standards that will merely create duplicate reporting and testing
requirements with no benefit to the environment. Additional government employees will be
required to monitor the programs, causing further waste of taxpayer dollars.
Material safety data sheets for all materials used in oil and gas operations are required to be
maintained on location by Hazard Communication Standards of OSHA. Therefore, requiring
such data in the FRAC bill is, again, merely duplicate effort with and accomplishes nothing new.

COLORADO:
David Neslin
Director
Colorado Oil and Gas Conservation Commission
To the knowledge of the Colorado Oil and Gas Conservation Commission staff, there has been
no verified instance of harm to groundwater caused by hydraulic fracturing in Colorado.
INDIANA:
Herschel McDivitt
Director
Indiana Department of Natural Resources
There have been no instances where the Division of Oil and Gas has verified that harm to
groundwater has ever been found to be the result of hydraulic fracturing in Indiana. In fact, we
are unaware of any allegations that hydraulic fracturing may be the cause of or may have been a
contributing factor to an adverse impact to groundwater in Indiana.
The Division of Oil and Gas is the sole agency responsible for overseeing all aspects of oil and
gas production operations as directed under Indiana’s Oil and Gas Act. Additionally, the
Division of Oil and Gas has been granted primacy by the U.S. Environmental Protection Agency,
to implement the Underground Injection Control (UIC) Program for Class II wells in Indiana
under the Safe Drinking Water Act.

Final SGEIS 2015, Page A15B-2

 KENTUCKY:
Kim Collings, EEC
Director
Kentucky Division of Oil and Gas
In Kentucky, there have been alleged contaminations from citizen complaints but nothing that
can be substantiated, in every case the well had surface casing cemented to surface and
production casing cemented.
LOUISIANA:
James Welsh
Commissioner of Conservation
Louisiana Department of Natural Resources
The Louisiana Office of Conservation is unaware of any instance of harm to groundwater in the
State of Louisiana caused by the practice of hydraulic fracturing. My office is statutorily
responsible for regulation of the oil and gas industry in Louisiana, including completion
technology such as hydraulic fracturing, underground injection and disposal of oilfield waste
operations, and management of the major aquifers in the State of Louisiana.
MICHIGAN:
Harold Fitch
Director, Office of Geological Survey
Department of Environmental Quality
My agency, the Office of Geological Survey (OGS) of the Department of Environmental
Quality, regulates oil and gas exploration and production in Michigan. The OGS issues permits
for oil and gas wells and monitors all aspects of well drilling, completion, production, and
plugging operations, including hydraulic fracturing.
Hydraulic fracturing has been utilized extensively for many years in Michigan, in both deep
formations and in the relatively shallow Antrim Shale formation. There are about 9,900 Antrim
wells in Michigan producing natural gas at depths of 500 to 2000 feet. Hydraulic fracturing has
been used in virtually every Antrim well.
There is no indication that hydraulic fracturing has ever caused damage to ground water or other
resources in Michigan. In fact, the OGS has never received a complaint or allegation that
hydraulic fracturing has impacted groundwater in any way.

Final SGEIS 2015, Page A15B-3

 OKLAHOMA:
Lori Wrotenbery
Director, Oil and Gas Conservation Division
Oklahoma Corporation Commission
You asked whether there has been a verified instance of harm to groundwater in our state from
the practice of hydraulic fracturing. The answer in no. We have no documentation of such an
instance. Furthermore, I have consulted the senior staffs of our Pollution Abatement
Department, Field Operations Department, and Technical Services Department, and they have no
recollection of having ever received a report, complaint, or allegation of such an instance. We
also contacted the senior staffs of the Oklahoma Department of Environmental Quality, who
likewise, have no such knowledge or information.
While there have been incidents of groundwater contamination associated with oil and gas
drilling and production operations in the State of Oklahoma, none of the documented incidents
have been associated with hydraulic fracturing. Our agency has been regulating oil and gas
drilling and production operations in the state for over 90 years. Tens of thousands of hydraulic
fracturing operations have been conducted in the state in the last 60 years. Had hydraulic
fracturing caused harm to groundwater in our state in anything other than a rare and isolated
instance, we are confident that we would have identified that harm in the course of our
surveillance of drilling and production practices and our investigation of groundwater
contamination incidents.
TENNESSEE:
Paul Schmierbach
Manager
Tennessee Department of Environmental Conservation
We have had no reports of well damage due to fracking.
TEXAS:
Victor G. Carrillo
Chairman
Railroad Commission of Texas
The practice of reservoir stimulation by hydraulic fracturing has been used safely in Texas for
over six decades in tens of thousands of wells across the state.
Recently in his introductory Statement for the Record (June 9, 2009) of the Fracturing
Responsibility and Awareness of Chemicals (FRAC) Act, Senator Robert Casey stated:

Final SGEIS 2015, Page A15B-4

 “Now, the oil and gas industry would have you believe that there is no threat to drinking
water from hydraulic fracturing. But the fact is we are already seeing cases in
Pennsylvania, Colorado, Virginia, West Virginia, Alabama, Wyoming, Ohio, Arkansas,
Utah, Texas, and New Mexico where residents have become ill or groundwater has
become contaminated after hydraulic fracturing operations began in the area.”
This statement perpetuates the misconception that there are many surface or groundwater
contamination cases in Texas and other states due to hydraulic fracturing. This is not true and
here are the facts: Though hydraulic fracturing has been used for over 60 years in Texas, our
Railroad Commission records do not reflect a single documented surface or groundwater
contamination case associated with hydraulic fracturing.
Hydraulic fracturing plays a key role in the development of unconventional gas resources in
Texas. As of this year, over 11,000 gas wells have been completed - and hydraulically fractured
- in the Newark East (Barnett Shale) Field, one of the nation’s largest and most active natural gas
fields. Since 2000, over 5 Tcf (trillion cubic feet) of gas has been produced from this one
reservoir and Barnett Shale production currently contributes over 20% of total Texas natural gas
production (over 7 Tcf in 2008 – more than a third of total U.S. marketed production). While the
volume of gas-in-place in the Barnett Shale is estimated to be over 27 Tcf, conventional recovery
of the gas is difficult because of the shale’s low permeability. The remarkable success of the
Barnett Shale results in large part from the use of horizontal drilling coupled with hydraulic
fracturing. Even with this intense activity, there are no known instances of ongoing surface or
groundwater contamination in the Barnett Shale play.
Regulating oil and gas exploration and production activities, including hydraulic fracturing, has
traditionally been the province of the states, which have had effective programs in place for
decades. Regulating hydraulic fracturing as underground injection under the federal Safe
Drinking Water Act would impose significant additional costs and regulatory burdens and could
ultimately reverse the significant U.S. domestic unconventional gas reserve additions of recent
years – substantially harming domestic energy security. Congress should maintain the status quo
and let the states continue to responsibly regulate oil and gas activities, including hydraulic
fracturing.
In summary, I am aware of no verified instance of harm to groundwater in Texas from the
decades long practice of hydraulic fracturing.

SOUTH DAKOTA:
Fred Steece
Oil and Gas Supervisor
Department of Environment and Natural Resource
Oil and gas wells have been hydraulically fractured, "fracked," in South Dakota since oil was
discovered in 1954 and since gas was discovered in 1970. South Dakota has had rules in place,
dating back to the 1940’s, that require sufficient surface casing and cement to be installed in

Final SGEIS 2015, Page A15B-5

 wells to protect ground water supplies in the state’s oil fields. Producing wells are required to
have production casing and cement, and tubing with packers installed. The casing, tubing, and
cement are all designed to protect drinking waters of the state as well as to prevent commingling
of water and oil and gas in the subsurface. In the 41 years that I have supervised oil and gas
exploration, production and development in South Dakota, no documented case of water well or
aquifer damage by the fracking of oil or gas wells, has been brought to my attention. Nor am I
aware of any such cases before my time.

WYOMING:
Rick Marvel
Engineering Manager
Wyoming Oil and Gas Conservation Commission
Tom Doll
Oil and Gas Commission Supervisor
Wyoming Oil and Gas Conservation Commission
•   No documented cases of groundwater contamination from fracture stimulations in
Wyoming.
•   No documented cases of groundwater contamination from UIC regulated wells in
Wyoming.
•   Wyoming took primacy over UIC Class II wells in 1982, currently 4,920 Class II wells
permitted.
Wyoming’s 2008 activity:
•   Powder River Basin Coalbed Wells – 1,699 new wells, no fracture stimulation.
•   Rawlins Area (deeper) Coalbed Wells – 109 new wells, 100% fracture stimulated.
•   Statewide Conventional Gas Wells – 1,316 new wells, 100% fracture stimulated – many
wells with multi-zone fracture stimulations in each well bore, some staged and some
individual fracture stimulations.
•   Statewide Oil Wells – 237 new wells, 75% fracture stimulated.
The Wyoming Oil and Gas Commission Rules and Regulations are specific in requiring the
operator receive approval prior to performing hydraulic fracturing treatments. The Rules require
the operator to provide detailed information regarding the hydraulic fracturing process, to
include the source of water and/or trade name fluids, type of proponents, as well as estimated
pump pressures. After the treatment is complete the operator is required to provide actual
fracturing data in detail and resulting production results.
Under Chapter 3, Section 8 (c) The Application for Permit to Drill or Deepen (Form 1)
states…”information shall also be given relative to the drilling plan, together with any other
information which may be required by the Supervisor. Where multiple Applications for Permit

Final SGEIS 2015, Page A15B-6

 to Drill will be sought for several wells proposed to be drilled to the same zone within an area of
geologic similarity, approval may be sought from the Supervisor to file a comprehensive drilling
plan containing the information required above which will then be referenced on each
Application for Permit to Drill.” Operators have been informed by Commission staff to include
detailed information regarding the hydraulic fraction stimulation process on the Form 1
Application for Permit to Drill.
The Rules also state, in Chapter 3, Section 1 (a) “A written notice of intention to do work or to
change plans previously approved on the original APD and/or drilling and completion plan
(Chapter 3, Section 8 (c)) must be filed with the Supervisor on the Sundry Notice (Form 4),
unless otherwise directed, and must reach the Supervisor and receive his approval before the
work is begun. Approval must be sought to acidize, cleanout, flush, fracture, or stimulate a well.
The Sundry Notice must include depth to perforations or the openhole interval, the source of
water and/or trade name fluids, type proponents, as well as estimated pump pressures. Routine
activities that do not affect the integrity of the wellbore or the reservoir, such as pump
replacements, do not require a Sundry Notice. The Supervisor may require additional
information.” Most operators will submit the Sundry Notice Form 4 to provide the specific
detail for the hydraulic fracturing treatment even though the general information might have
been provided under the Form 1 Application for Permit to Drill.
After the hydraulic fracture treatment is complete, results must be reported to the Supervisor.
Chapter 3, Section 12 Well Completion or Recompletion Report and Log (Form 3) state “upon
completion or recompletion of a well, stratigraphic test or core hole, or the completion of any
remedial work such as plugging back or drilling deeper, acidizing, shooting, formation
fracturing, squeezing operations, setting a liner, gun perforating, or other similar operations not
specifically covered herein, a report on the operation shall be filed with the Supervisor. Such
report shall present a detailed account of the work done and the manner in which such work was
performed; the daily production of the oil, gas, and water both prior to and after the operation;
the size and depth of perforations; the quantity of sand, crude, chemical, or other materials
employed in the operation and any other pertinent information of operations which affect the
original status of the well and are not specifically covered herein.”

Final SGEIS 2015, Page A15B-7

 This page intentionally left blank.

Appendix 16
Applicability of NOx RACT Requirements for
Natural Gas Production Facilities
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Applicability of NOX RACT Requirements for Natural Gas Production Facilities
New York State’s air regulation 6 NYCRR 227-2, Reasonably Available Control Technology
(RACT) for Oxides of Nitrogen (NOX), applies to boilers (furnaces) and internal combustion
engines at major sources.
The requirements of 227-2 include emission limits, stack testing, and annual tune-ups, among
others. Many facilities whose potential to emit (PTE) air pollutants would make them
susceptible to NOX RACT requirements can limit, or “cap”, their emissions using the limits
within the New York State Department of Environmental Conservation’s (Department) Air
Emissions Permits applicability thresholds to avoid this regulation.
New York State has two different major source thresholds for NOX RACT and permitting.
Downstate (in New York City and Nassau, Suffolk, Westchester, Rockland, and Lower Orange
Counties) the major source permitting and NOX RACT requirements apply to facilities with a
PTE of 25 tons/yr or more of NOX. For the rest of the state (where the majority of natural gas
production facilities are anticipated to be located), the threshold is a PTE of 100 tons/yr or more
of NOX.
If the stationary engines at a natural gas production facility exceed the applicability levels or if
the PTE at the facility would classify it as a Major NOX source, the following compliance
options are available:
1. Develop a NOX RACT compliance plan and apply for a Title V permit.
2. Limit the facility’s emissions to remain under the NOX RACT applicability levels by
applying for one of two New York State Air Emissions permits, depending on how
low emissions can be limited.
The permitting options for facilities that wish to limit, or “cap”, their emissions by establishing
appropriate permit conditions are described below.
New York State’s air regulation 6 NYCRR Part 201, Permits and Registrations, includes a
provision that allows a facility to register if its actual emissions are less than 50% of the
applicability thresholds (less than 12.5 tons/yr downstate and less than 50 tons/yr upstate). This
permit option is known as “cap by rule” registration.
Part 201 also includes a provision that allows a facility to limit its emissions by obtaining a State
Facility Permit, if its actual emissions are above the 50% level but below the applicability level
(between 12.5 and 25 tons/yr downstate and between 50 and 100 tons/yr upstate).
If the facility NOX emissions cannot be capped below the applicability levels, then the facility
should immediately develop a NOX RACT compliance plan. This plan should contain the
necessary steps (purchase of equipment and controls, installation of equipment, source testing,
submittal of permit application, etc.) and projected completion dates required to bring the facility
into compliance. This plan is to be submitted to the appropriate Department Regional Office as
soon as possible. In this case the facility would also be subject to Title V, and a Title V air
permit application must be prepared and submitted.
Final SGEIS 2015, Page A16-1

 This page intentionally left blank.

Appendix 17
Applicability of 40 CFR Part 63
Subpart ZZZZ (Engine MACT) for
Natural Gas Production Facilities –
Final Rule
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Applicability of 40 CFR Part 63 Subpart ZZZZ (Engine MACT)
for Natural Gas Production Facilities – Final Rule

EPA published a final rule on August 20, 2010 revising 40 CFR Part 63, Subpart ZZZZ, in order
to address hazardous air pollutant (HAP) emissions from existing stationary reciprocating
internal combustion engines (RICE) located at area sources. A major source of HAP emissions is
a stationary source that emits or has the potential to emit any single HAP at a rate of 10 tons or
more per year or any combination of HAPs at a rate of 25 tons or more per year. An area source
of HAP emissions is a source that is not a major source.

Available emissions data show that several HAP, which are formed during the combustion
process or which are contained within the fuel burned, are emitted from stationary engines. The
HAPs which have been measured in emission tests conducted on natural gas fired and diesel
fired RICE include: 1,1,2,2-tetrachloroethane, 1,3-butadiene, 2,2,4-trimethylpentane,
acetaldehyde, acrolein, benzene, chlorobenzene, chloroethane, ethylbenzene, formaldehyde,
methanol, methylene chloride, n-hexane, naphthalene, polycyclic aromatic hydrocarbons,
polycyclic organic matter, styrene, tetrachloroethane, toluene, and xylene. Metallic HAPs from
diesel fired stationary RICE that have been measured are: cadmium, chromium, lead, manganese,
mercury, nickel, and selenium. Although numerous HAPs may be emitted from RICE, only a
few account for essentially all of the mass of HAP emissions from stationary RICE. These
HAPs are: formaldehyde, acrolein, methanol, and acetaldehyde. EPA is proposing to limit
emissions of HAPs through emissions standards for formaldehyde for non-emergency four
stroke-cycle rich burn (4SRB) engines and through emission standards for carbon monoxide
(CO) for all other engines.

The applicable emission standards (at 15% oxygen) or management practices for existing RICE
located at area sources are provided in the table below.

In addition to emission standards and management practices, certain stationary CI RICE located
at existing area sources are subject to fuel requirements. Stationary non-emergency diesel-fueled
CI engines greater than 300 HP with a displacement of less than 30 liters per cylinder located at

Final SGEIS 2015, Page A17-1

 existing area sources must only use diesel fuel meeting the requirements of 40 CFR 80.510(b),
which requires that diesel fuel have a maximum sulfur content of 15 ppm and either a minimum
cetane index of 40 or a maximum aromatic content of 35 volume percent.

Emission standards at 15 percent O2, as applicable,
or management practice
Subcategory

Except during periods of startup

47 ppmvd CO or 93% CO reduction
Non‐Emergency 4SLB* >500HP

During periods of startup
Minimize the engine’s time spent at idle
and minimize the engine’s startup time
at startup to a period needed for
appropriate and safe loading of the
engine, not to exceed 30 minutes, after
which time the non-startup emission
limitations apply.

Non‐Emergency 4SRB** >500HP

Change oil and filter every 1440 hours;
inspect spark plugs every 1440 hours;
and inspect all hoses and belts every
1440 hours and re-place as necessary.
2.7 ppmvd formaldehyde or 76%
formaldehyde reduction.

Non‐Emergency CI >500HP

23 ppmvd CO or 70% CO reduction

Same as above

Non‐Emergency CI*** 300‐
500HP

49 ppmvd CO or 70% CO reduction

Same as above

Non‐Emergency 4SLB ≤500HP

Non‐Emergency CI ≤300HP

Change oil and filter every 1000 hours;
inspect air cleaner every 1000 hours;
and inspect all hoses and belts every
500 hours and re-place as necessary.

*4SLB - four stroke-cycle lean burn
**4SRB - four stroke-cycle rich burn
***CI - compression ignition

Final SGEIS 2015, Page A17-2

Same as above

Same as above

Same as above

 Appendix 18
Definition of Stationary Source or Facility for
the Determination of Air Permit Requirements
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Definition of Stationary Source or Facility
for the Determination of Air Permit Requirements
Summary
The Department must determine the applicability of air permitting regulations and requirements
to natural gas drilling activities in the Marcellus Shale formation. Specifically, the Department
must determine applicable regulations and permit requirements for:
•

sources subject to stationary source permitting under 6 NYCRR Part 201.
major stationary source - one that emits or has the potential to emit any of the following:
o 100 tons per year (Tpy) or more of any regulated air pollutant (NOX, SO2, CO,
PM2.5, PM10); 50 Tpy of VOC.
o 10 Tpy or more of any individual Hazardous Air Pollutant (HAP); or
o 25 Tpy or more of any combination of HAPs.

•

sources subject to New Source Performance Standards (NSPS)

•

sources subject to National Emission Standards for Hazardous Air Pollutants (NESHAP),
and

•

6 NYCRR Part 231 for major new or major modifications to existing sources subject to
preconstruction review requirements under Prevention of Significant Deterioration (PSD)
and/or Non-Attainment New Source Review (NSR)

In addition to threshold criteria detailed in regulation and guidance, the Department must
evaluate a variety of technical and factual information to assess applicability of these rules to
specific sources through the permit application process. These evaluations, as they pertain to
natural gas drilling activities in the Marcellus Shale formation, are discussed herein, including 1)
whether emissions from two or more pollutant-emitting activities should be aggregated into a
single major stationary source for purposes of NSR and Title V programs; and 2) how to assess
NESHAP applicability given the unique regulatory definition of “facility” for the oil and gas
industry.
Major Stationary Source Determinations for Criteria Pollutants
PSD, NSR and Title V operating permit program (Title V) regulations apply to certain sources
with the potential to emit pollutants in excess of the major source thresholds. To assess
applicability, the Department must evaluate whether emissions from two or more pollutantemitting activities should be aggregated into a single major stationary source. The evaluation
begins with the federal definition of “stationary source” at 40 CFR 52.21(b)(5) and a similar
definition for major source under 6 NYCRR 201-2.1(b)(21). The federal definition reads “any
building, structure, facility, or installation which emits or may emit a regulated NSR pollutant.”
“Building, structure, facility, or installation” is further defined in 40 CFR 52.21(b)(6):

Final SGEIS 2015, Page A18-1

 Building, structure, facility, or installation means all of the pollutant-emitting activities
which belong to the same industrial grouping, are located on one or more contiguous or
adjacent properties, and are under the control of the same person (or persons under
common control) except the activities of any vessel. Pollutant-emitting activities shall be
considered as part of the same industrial grouping if they belong to the same “Major
Group” (i.e., which have the same first two digit code) as described in the Standard
Industrial Classification Manual, 1972, as amended by the 1977 Supplement (U. S.
Government Printing Office stock numbers 4101–0066 and 003–005–00176–0,
respectively).
To identify pollutant-emitting activity that belongs to the same building, structure, facility, or
installation, permitting authorities rely on the following three criteria: 1) whether the activities
belong to the same industrial grouping; 2) whether the activities are located on one or more
contiguous or adjacent properties; and 3) whether the activities are under the control of the same
person (or person under common control). 1 These criteria are applied case-by-case to make the
major stationary source determination.
Since the original 1992 GEIS, DEC reviewed numerous source determinations from EPA
permitting actions, guidance provided by EPA to inform permitting actions by other permitting
authorities, and source determination protocol developed by other states. These documents have
been informative. However, EPA has clearly stated that “no single determination can serve as an
adequate justification for how to treat any other source determination for pollutant-emitting
activities with different fact-specific circumstances.” 2 “Therefore, while the prior agency
statements and determinations related to oil and gas activities and other similar sources may be
instructive, they are not determinative in resolving the source determination issue…, particularly
where a state with independent permitting authority is making the determination and the prior
agency statements had… substantially different fact-specific circumstances.” 3 As such, DEC
will formulate case-specific source determinations based on the foregoing, federal and state
regulation, evolving case law, industry data and the specific facts of each air permit application.
These determinations will be made during the review of permit applications for compressor
stations which are associated with Marcellus Shale activities.
The three source determination criteria are discussed in more detail below.
1) Do the pollutant-emitting activities belong to the same industrial grouping or “Major
Group”? In formulating the definition of “source,” EPA uses a Standard Industrial
Classification (SIC) code for distinguishing between sets of activities on the basis of their
functional interrelationships. 4 Each source is to be classified according to its primary

1

2
3

4

Memorandum from Gina McCarthy, EPA Assistant Administrator, to Regional Administrators, Sept. 22, 2009,
available at http://www.epa.gov/region7/air/nsr/nsrmemos/oilgaswithdrawal.pdf
Id.
In The Matter Of Anadarko Petroleum Corporation, Frederick Compressor Station, Order Responding To
Petitioners' Request That The Administrator Object To Issuance Of A State Operating Permit, February 2, 2011,
Petition Number: VIII-2010-4.
45 FR 52695, at 31.

Final SGEIS 2015, Page A18-2

 activity, which is determined by its principal product or group of products produced or
distributed, or services rendered. 5
The Standard Industrial Classification Manual lists activities associated with oil and gas
extraction in Major Group 13 and activities associated with natural gas transmission in Major
Group 49. Establishments primarily engaged in operating oil and gas field properties,
including wells, are grouped into Major Group 13. The Standard Industrial Classification
Manual does not expressly list all equipment, such as midstream compressor stations, in
Major Group 13, nor Major Group 49. Therefore, the Department may look to other
information, such as federal and state regulations, industry data, and gas gathering
agreements, to help make the source determination. For instance, under NESHAP, EPA
regulates compressor stations that transport natural gas to a natural gas processing plant 6 in
accordance with natural gas production facilities, Major Group 13. 7 In the absence of a
natural gas processing plant, EPA regulates a compressor station in accordance with natural
gas production facilities where the compressor station is prior to the point of custody
transfer. 8 If the compressor station is after the point of custody transfer, EPA regulates the
compressor station in accordance with natural gas transmission and storage facilities, Major
Group 49. In relevant part, custody transfer means the transfer of natural gas to pipelines
after processing or treatment. 9
Where the pollutant-emitting activities do not belong to the same industrial grouping or
“Major Group,” the Department will ascertain whether one activity serves exclusively as a
support facility for the other. In the Preamble to its 1980 PSD regulations, EPA “clarifies
that “support facilities” that “convey, store, or otherwise assist in the production of the
principal product” should be considered under one source classification, even when the
support facility has a different two-digit SIC code. 10
2) Are the pollutant-emitting activities contiguous or adjacent? EPA has routinely relied on
the plain meaning of the word “contiguous,” that is - being in actual contact; touching along
a boundary or at a point. However, “the more difficult assessment is determining whether …
a non-contiguous [pollutant-emitting activity] might be considered “adjacent.” 11 First, EPA
has not established a specific distance between activities in assessing whether such activities
are adjacent. 12 Second, “the concept of “interdependency,” which many individual EPA
determinations consider, is not discussed in the 1980 Preamble or mentioned in the federal
PSD or Title V regulations defining “source.” 13 “[I]nterdependency is a factor that has
evolved over time in various case-by-case determinations. While interdependency is a
5

45 FR 52695, at 32.
40 CFR §63.761, Natural gas processing plant.
7
40 CFR §63.761, Facility.
8
40 CFR §63.760(a)(3)
9
40 CFR §63.761, Custody transfer.
10
45 Fed. Reg. 52676 (August 9, 1980)
11
Response of Colorado Department of Public Health and Environment, Air Pollution Control Division, to Order
Granting Petition for Objection to Permit, July 14, 2010, at 15, http://www.cdphe.state.co.us/ap/down/KMOrderResponseDocumentJuly142010.pdf
12
Id.
13
Id. at 14
6

Final SGEIS 2015, Page A18-3

 consideration, it is not an express element of the actual three-part test set forth in regulation,
and in the context of oil and gas infrastructure, it may have reduced relevance to an agency
determination” 14 Nevertheless, to be thorough, DEC staff will consider the nature of the
relationship between the facilities and the degree of interdependence between them. 15
However, interdependence alone may not be dispositive of whether the non-contiguous
emissions points should be aggregated in this context.
A “high level of connectedness and interdependence between two activities” is needed to
deem them adjacent, and “interdependence requires that the two activities rely on each other
– not just that one activity relies on the other activity. 16 Furthermore, “a determination of
interdependence requires that the two activities rely upon each other exclusively; i.e., one
activity cannot operate or occur without the other. The case-by-case determinations indicate
that if activities operate independently and one activity does not act solely as a support
operation for the other, the activities should not be deemed contiguous or adjacent.” 17 In
guidance provided by EPA to the Utah Division of Air Quality, 18 EPA recommended using
the following indicators as determinative of adjacency for two Utility Trailer Manufacturing
Company facilities: 1) whether the location of the new facility was chosen because of its
proximity to the existing facility; 2) whether materials would routinely be transferred back
and forth between the two facilities; 3) whether managers and other workers would be shared
between the two facilities; and 4) whether the production process itself would be split
between the two facilities. 19 While DEC will use these and other questions to inform its
source determination, some questions may have reduced relevance in the oil and gas
industry. For instance, the location of oil and gas activity, proximate or otherwise, may “be
controlled by land agreements, access issues, geologic formations, terrain, and, in other
situations, by federal or state land management agencies, such as the Bureau of Land
Management for oil and gas production on federal lands,” 20 and thus not necessarily
indicative of interdependence.
3) Are the activities under common control? To assess common control, EPA has
historically relied on the Securities and Exchange Commission’s definition of control as
follows: The term control (including the terms controlling, controlled by and under common
control with) means the possession, direct or indirect, of the power to direct or cause the
direction of the management and policies of a person (or organization or association),
whether through the ownership of voting shares, by contract or otherwise. The following
questions have been used previously and in more recent actions by EPA to determine
14

Id. at 36
Letter from Cheryl Newton, U.S. EPA, to Scott Huber, Summit Petroleum Corporation, October 18, 2010, at 4,
http://www.epa.gov/region07/air/title5/t5memos/singler5.pdf
16
Response of Colorado Department of Public Health and Environment, Air Pollution Control Division, to Order
Granting Petition for Objection to Permit, July 14, 2010, at 21, http://www.cdphe.state.co.us/ap/down/KMOrderResponseDocumentJuly142010.pdf
17
Id. at 36 – 37.
18
Letter from Richard Long of EPA Region VIII to Lynn Menlove of Utah Division of Air Quality, dated May 21,
1998. http://www.epa.gov/region07/air/title5/t5memos/util-trl.pdf
19
Response of Colorado Department of Public Health and Environment, Air Pollution Control Division, to Order
Granting Petition for Objection to Permit, July 14, 2010, at 20, http://www.cdphe.state.co.us/ap/down/KMOrderResponseDocumentJuly142010.pdf
20
Id. at 40
15

Final SGEIS 2015, Page A18-4

 “common control”: 21 1) Whether control has been established through ownership of two
entities by the same parent corporation or a subsidiary of the parent corporation; 2) Whether
control has been established by a contractual arrangement giving one entity decision making
authority over the operations of the second entity; 3) Whether there is a contract for service
relationship between the two entities in which one sells all of its product to the other under a
single purchase or contract; 4) Whether there is a support or dependency relationship
between the two entities such that one would not exist “but for” the other?
Thus, the Department will use answers to the following questions to help guide the casespecific source determinations for natural gas drilling activities in the Marcellus Shale
formation that may be subject to NSR and Title V for criteria pollutants.
1. Do the pollutant-emitting activities belong to the same industrial grouping or “Major
Group” as described in the Standard Industrial Classification Manual?
a. What is the primary activity engaged in by the facility?
b. If the pollutant-emitting activities do not belong to the same industrial grouping or
Major Group, does one activity serve exclusively as a support facility for the
other?
2. Are the pollutant-emitting activities contiguous or adjacent?
a. Are the pollutant-emitting activities contiguous? Do they share a boundary or
touch each other physically?
b. If the pollutant-emitting facilities are non-contiguous, are they proximate or
interdependent?
c. Was the location of the new facility chosen because of its proximity to the
existing facility?
d. Will materials routinely be transferred back and forth between the two facilities?
e. Will managers and other workers be shared between the two facilities?
f. Will the production process be split between the two facilities?
3. Are the activities under common control?
a. Has control been established through ownership of two entities by the same parent
corporation or a subsidiary of the parent corporation?
b. Has control been established by a contractual arrangement giving one entity
decision making authority over the operations of the second entity?
c. Is there a contract for service relationship between the two entities in which one
sells all of its product to the other under a single purchase or contract?

21

Letter from Kathleen Henry of EPA Region III to John Slade of Pennsylvania DEP, dated 1/15/99. Also, Letter
from Richard Long of EPA Region VIII to Margie Perkins, Air Pollution Control Division, Colorado Department
of Public Health Environment, dated October 1, 1999,
http://www.epa.gov/region07/air/nsr/nsrmemos/frontran.pdf

Final SGEIS 2015, Page A18-5

 d. Is there an exclusive support or dependency relationship between the two entities
such that one would not exist “but for” the other?
NESHAPS Applicability for Hazardous Air Pollutants
“[I]n the hazardous air pollutant (HAP) arena, EPA has expressly determined, consistent with
Congress’ statutory mandate in the [Clean Air Act] CAA, 42 U.S.C. § 7412(n)(4)(A), oil and gas
production field facilities are typically not industrial facilities that should be aggregated.” 22 The
CAA, 42 U.S.C. § 7412, defines “major source” as any stationary source or group of stationary
sources located within a contiguous area and under common control that emits or has the
potential to emit considering controls, in the aggregate, 10 tons per year or more of any
hazardous air pollutant or 25 tons per year or more of any combination of hazardous air
pollutants; and “area source” as any stationary source of hazardous air pollutants that is not a
major source. Notwithstanding this definition, Section 7412(n)(4)(A) exempts oil and gas wells
and pipeline facilities from the requirement to aggregate with contiguous sources under common
control when deciding if the source is a major source for NESHAPS applicability.
In the context of hazardous air pollutants, EPA declared that “[s]uch facilities generally are not
in close proximity to or co-located with one another (contiguous) and located within an area
boundary, the entirety of which (other than roads, railroads, etc.), is under the physical control of
the same owner.” 23,24 In light of this, EPA developed a unique definition of facility for the oil
and gas industry NESHAP regulations (40 CFR 63 Subparts HH and HHH). For HAP major
source determinations, the EPA-promulgated definition of “facility” states that “pieces of
production equipment or groupings of equipment located on different oil and gas leases, mineral
fee tracts, lease tracts . . . or separate surface sites, whether or not connected by a road,
waterway, power line or pipeline, shall not be considered part of the same facility.” 25,26 EPA
defines a “surface site” at 40 CFR 63.761 of Subpart HH as “ Surface site means any
combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the
immediate physical location upon which equipment is physically affixed”.
Accordingly, to determine applicability of the NESHAPs rules governing Oil and Gas
Production and Natural Gas Transmission industry sectors, the regulatory definition of facility
authorized by CAA, 42 U.S.C. § 7412(n)(4)(A) and found at 40 CFR 63 Subparts HH and HHH,
must be used. The Department will follow this definition in determining the regulatory
applicability of NESHAPS requirements for HAPS. This opens up the possibility that a
“facility” definition for a certain permit application may result in a determination of “major
source” for purposes of NSR or Title V permitting, but which will consist of several area source
surface sites for the purposes of NESHAP applicability. Guided by EPA’s three source
determination criteria and the underlying recommendation to use case specific facts, the
22

Id. at 23
63 Fed. Reg. 6288, 6303 (Feb. 6, 1998)
24
Response of Colorado Department of Public Health and Environment, Air Pollution Control Division, to Order
Granting Petition for Objection to Permit, July 14, 2010, at 23, http://www.cdphe.state.co.us/ap/down/KMOrderResponseDocumentJuly142010.pdf
25
64 Fed. Reg. 32610, 32630 (June 17, 1999)
26
Response of Colorado Department of Public Health and Environment, Air Pollution Control Division, to Order
Granting Petition for Objection to Permit, July 14, 2010, at 23, http://www.cdphe.state.co.us/ap/down/KMOrderResponseDocumentJuly142010.pdf
23

Final SGEIS 2015, Page A18-6

 Department will consider all pertinent information on a case-by-case basis in arriving at its
conclusions during source permitting review.

Final SGEIS 2015, Page A18-7

 This page intentionally left blank.

Appendix 18A
Evaluation of Particulate Matter and Nitrogen
Oxides Emissions Factors and
Potential Aftertreatment Controls for Nonroad
Engines for Marcellus Shale Drilling and
Hydraulic Fracturing Operations
Updated/revised 2015

Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Evaluation of Particulate Matter and Nitrogen Oxides Emissions Factors and
Potential Aftertreatment Controls for Nonroad Engines for Marcellus Shale Drilling
and Hydraulic Fracturing Operations

Nonroad Emissions Standards
Tables 1 and 2 describe the EPA emissions standards for nonroad diesel engines relevant to
natural gas well drilling and hydraulic fracturing. These standards are contained in 40 CFR Parts
89 and 1039. These standards may be considered worst case emission levels. Table 1 covers
engines rated from 600-750 horsepower. Table 2 covers engines rated at more than 750
horsepower that are not installed in a generator set. Engines are held to these standards for a
useful life of the lesser of 8000 hours or 10 years. Actual operating lifetimes are likely much
longer.
Table 1. Nonroad Engine Standards for Engines Rated Between 600 and 750 Horsepower
Standard
Tier 1
Tier 2
Tier 3
Tier 4 interim
Tier 4

Initial
Year
1996
2002
2006
2011

PM
(g/bhp*hr)
0.4
0.15
0.15
0.01

NOX
(g/bhp/hr)
6.9
4.32
2.7
1.35

HC
(g/bhp*hr)
1.0
0.48
0.3
0.14

2014

0.01

0.3

0.14

Notes
4.8 g/bhp*hr NOX + HC standard
3.0 g/bhp*hr NOX + HC standard
NOX standard half-way between
Tier 3 and Tier 4

Tier 2 and Tier 3 NOX and hydrocarbon standards are an additive NOX plus hydrocarbon (HC)
standard. For Tier 2 the limit is 4.8 g/bhp*hr. For Tier 3 the limit is reduced to 3.0 g/bhp*hr. In
order to use the standards as conservative emissions limits, it is necessary to apportion the
emission limit between the two pollutants. The Tables apportion 90% of the emissions to NOX
and the remaining 10% to hydrocarbons. EPA and European Union (EU) emissions tiers that
have separate NOX and hydrocarbon standards, not requiring exhaust aftertreatment, generally
have the NOX standard equaling 86-88% of the sum of the two standards. It should be noted that
data supplied on behalf of industry (1) assumed that 100% of these emissions are NOX, which is
deemed conservative.
There is no official “Tier 4 interim” standard for engines in the Table 1 horsepower class.
Beginning in 2011, 50% of the engines in the class are supposed to meet the Tier 4 NOX
standards. This would increase to 100% in 2014. When faced with the exact same phase-in
schedule from 2007-2010 for highway diesel engines, manufacturers universally chose to
initially certify all engines to a Family Emissions Level half way between the old standard and
the new standard, and postpone the NOX aftertreatment requirements for three years. Thus, the
NOX emissions level of 1.35 g/bhp*hr in the Table is the average of the Tier 3 and Tier 4
standards.

Final SGEIS 2015, Page A18A-1

 Table 2. Nonroad Engine Standards for Engines Rated Above 750 Horsepower (Updated 2012)
Standard
Tier 1
Tier 2
Tier 4 interim
Tier 4 final
Tier 4 final

Initial
Year
2000
2006
2011
2015
2015

PM
(g/bhp*hr)
0.4
0.15
0.075
0.03
0.02

NOX
(g/bhp/hr)
6.9
4.32
2.6
2.6
0.5

HC
Notes
(g/bhp*hr)
1.0
0.48
4.8 g/bhp*hr NOX + HC standard
0.3
0.14
0.14
Generator sets only

Tier 1 and Tier 2 standards for engines rated above 750 horsepower are the same as the
corresponding standards for engines rated between 600 and 750 horsepower. Again, the Tier 2
NOX plus hydrocarbon standard is apportioned 90% NOX and 10% hydrocarbon. There are no
Tier 3 standards for these engines. The Tier 4 interim standards are promulgated standards.
Also, the Tier 4 standards for engines rated above 750 horsepower not installed in generator sets
may not force the use of NOX aftertreatment, although at least one manufacturer reportedly
intends to use SCR on these engines by 2015 (2).
Final Tier 4 standards for generator sets rated above 750 hp are significantly more stringent than
the corresponding standards for other engines. Some drilling rigs are designed with electric
motors to drive various pieces of equipment rather than mechanical or hydraulic drives. Electric
drive pumps for hydraulic fracturing may also be possible. The use of electric drive equipment
would allow the use of lower emission diesel engines in the future, as well as the possibility of
the use of grid electricity where sufficient electrical power is available.
Retrofit of Exhaust Aftertreatment
Prior to Tier 4, none of the new engine standards were stringent enough to require exhaust
aftertreatment. Current highway engine standards require aftertreatment to meet both the PM
and NOX standards. Furthermore, there is now substantial experience with retrofitting exhaust
aftertreatment to highway engines and stationary engines. Particulate matter control
technologies include: Diesel Oxidation Catalysts (DOC) which oxidize hydrocarbons and carbon
based particulate matter, and particulate filters or “traps” where particulate matter is collected
and oxidized. Where exhaust conditions are suitable Continuously Regenerating Diesel
Particulate Filters (CRDPF) are common. In other cases, particularly when exhaust temperatures
are too low, active traps may be used. Active traps use an external energy supply (usually
electricity or a secondary fuel burner) to oxidize particulate matter rather than relying solely on
exhaust heat. Active trap retrofits may require more complex control systems.
NOX control technologies include: Selective Catalytic Reduction (SCR) which uses ammonia
(usually supplied as urea), Lean NOX Catalysts, or Lean NOX Traps (also referred to as “NOX
absorbers”) to reduce NOX emissions. Although in the past EPA had identified the Lean NOX
Traps as a promising technology, it has not been applied to the size class of the drilling and
hydraulic fracturing engines. In addition, the lean NOX Catalyst system’s NOX reduction would

Final SGEIS 2015, Page A18A-2

 be insufficient to meet the ultimate engine standards. Thus, for NOX control, the SCR system is
recommended.
Table 3 lists the aftertreatment effectiveness claimed by one manufacturer, Johnson Matthey, 1 as
an example for retrofit installations on stationary engines (3).
Table 3. Exhaust Aftertreatment Retrofit Effectiveness
Technology
Diesel Oxidation
Catalyst
Particulate Trap
Particulate Trap and
SCR

Abbreviation

PM Emissions
Reduction (%)

NOX Emissions
Reduction (%)

HC Emissions
Reduction (%)

DOC

30%

0

90%

CRDPF
SCR-DPF
(SCRT)

85%

0

90%

85%

90%

90%

Johnson Matthey has EPA certification of its SCR-DPF system (referred to as SCRT) as a
verified retrofit for some classes of highway diesel engines. That verification is for a 70% NOX
emissions reduction (4). The development of Johnson Matthey’s retrofit system is described by
Conway and coworkers (5). This certification does not negate the 90% reduction expected for
these nonroad engines due to factors discussed below.
The SCR and CRDPF technologies are the dominant technologies used to meet the current
highway emissions standards, and are expected to dominate the exhaust aftertreatment market for
many large nonroad diesel engine classes. There are other NOX control technologies; however
their applicability appears to be limited to smaller engines, such as those in light duty vehicles.
Feasibility of Exhaust Aftertreatment
As discussed above, SCR and CRDPF technologies are widely used to control NOX and PM
emissions from diesel cycle internal combustion engines, including engines both larger and
smaller than well drilling and hydraulic fracturing engines. These technologies are used both on
new engines and as retrofits to existing engines.
No exhaust aftertreatment retrofits for these engines and duty cycles have been verified by EPA
or the California Air Resources Board (CARB). Both verification programs are voluntary. The
primary purpose of the EPA verification program is to verify eligibility for federal diesel
emission reduction retrofit grants. The primary purpose of the CARB program is to verify
emissions reductions for use by engine owners in complying with California’s Airborne Toxic
Control Measures for diesel particulate matter. To the Department’s knowledge no exhaust
retrofits for the gas well drilling rig and hydraulic fracturing engines expected to be used in
developing the Marcellus Shale formation in New York have been submitted to either
verification program.

1

Listing of this manufacturer does not imply any form of endorsement. Other manufacturers could provide similar
aftertreatment information.

Final SGEIS 2015, Page A18A-3

 Lack of verification does not necessarily preclude commercial application of a retrofit.
However, verification, which requires significant work by the applicant, does provide benefits to
all parties. Verification provides assurances regarding the level of emissions control, and
assurance that the control equipment will continue to be effective over a period of time. The
verification programs also impose warranty requirements.
The intended duty cycle of the engine is an important factor in the design of emissions control
systems. Particularly critical for CRDPF installations is the exhaust temperature. Exhaust
temperature must be high enough, frequently enough, to oxidize accumulated particulate matter.
Failure to regenerate the particulate trap can lead to engine damage. The exhaust temperatures
reported on behalf of industry (800-900 °F) (1) are high enough to support aftertreatment
retrofits which require minimum temperatures of roughly 250 °C (<500 °F) (4) (5). The fraction
of time when exhaust temperatures are at the industry reported temperatures is not known. The
frequency and duration of events where the exhaust temperature would be below minimum
requirements is also unknown, and important to the feasibility of the exhaust aftertreatment.
Physical configuration also places constraints on exhaust aftertreatment design. CRDPFs in
particular are significantly larger than typical exhaust system components. Exhaust
aftertreatment must be located near the engine to maximize the use of available exhaust heat.
However, the exhaust system cannot interfere with the safe use of the equipment. This may be
less of a problem for drilling rigs and hydraulic fracturing equipment than for mobile machinery
since they are physically static during drilling or hydraulic fracturing. Physical configuration
issues are more difficult to address when retrofitting existing equipment than when designing
new equipment.
In the event that CRDPFs are not feasible for a specific application, DOCs may provide a
feasible intermediate level of control. Exhaust aftertreatment consisting of SCR and DOCs has
been retrofitted to Caterpillar 3512 generator set engines used on drill rigs in Wyoming (6).
Emissions of Nitrogen Dioxide
Nitrogen Dioxide (NO2) is not explicitly regulated via EPA engine emissions standards. It is a
component of the regulated pollutant NOX. However, primary NO2 emissions are a concern in
the Marcellus Shale evaluation since for the evaluation of the new 1 hour NO2 standard, specific
emission factor estimates are necessary to assure that modeling results account for the NO2
portion of the emissions.
Conventional information indicates that roughly 5% of NOX emissions from internal combustion
engines are NO2; the balance are NO. However, European researchers have noted that ambient
NO2 concentrations have not been declining despite declining NOX emissions from engines and
vehicles. This has led to some investigation of the NO2 fraction of primary NOX emissions from
highway vehicles. The most comprehensive summary is by Grice, et al (7), who needed the data
for model inputs. These researchers found that the conventional use of 5% NO2 holds for
gasoline engines. The NO2 fraction for diesel engines varies for different emissions control
technologies, but is always greater than 5%. The data are summarized based on European
emissions standards which must be translated into aftertreatment technology level.
Final SGEIS 2015, Page A18A-4

 NO2 fractions for diesels range between 10% and 55% (7). EURO II engines, which have no
exhaust aftertreatment, have an NO2 fraction of 11%. This NO2 fraction is used for Tier 1, Tier
2, and Tier3 engines with no retrofitted aftertreatment. For particulate trap equipped EURO III
engines the NO2 fraction is 35%. This NO2 fraction is used for cases with either a DOC or a
CRDPF either standard or retrofitted. The oxidation reactions in DOCs oxidize some NO to NO2
along with the desired oxidation of hydrocarbons and particulate carbon. Indeed, oxidation
catalysts are placed ahead of CRDPFs to produce NO2 for use in oxidizing particulate matter to
regenerate the PM trap. NO2 oxidizes carbon at a lower temperature than O2.
Finally, Grice et. al. chose to use a NO2 fraction of 10% for engines equipped with SCR (EURO
IV and later). However, the data for the SCR equipped engines was particularly sparse. This
uncertainty is discussed further below.
For light duty vehicles equipped with NOX aftertreatment an NO2 fraction of 55% was reported.
Light duty vehicle NOX control generally avoids SCR, with its requirement that the operator
maintain the urea supply. These alternative NOX aftertreatment technologies have not proven
viable for heavy duty truck engines, never mind the even larger engines to be used in Marcellus
Shale drilling and hydraulic fracturing. Thus the 55% NO2 fraction does not have any
applicability here.
Table 4 below summarizes the recommended NO2 fractions.
Table 4. NO2 Emissions as Fraction of NOX Emissions
Technology
No Exhaust Aftertreatment
Diesel Oxidation Catalyst or Particulate Trap
SCR (with or without DOC or CRDPF)

Fraction NO2 (in %)
11
35
10 (see text)

Specifying a single NO2 fraction for an engine technology is clearly a simplification.
Researchers have documented variation in the NO2 fraction depending on engine load (8) and
exhaust temperature (9). The NO2 fractions in Table 4 for engines without SCR could be low for
engines operated at low loads and low exhaust temperatures. They appear to better reflect the
emissions at higher loads more in line with the operations expected during drilling and hydraulic
fracturing.
Given the particularly high level of uncertainty regarding the NO2 fraction when SCR is used, a
review of the chemistry involved might help. SCR generally converts NOX to N2. There are
several different reactions involved (10), (11), (12). One of these reactions, the “fast” SCR
reaction, is much faster (and has lower minimum temperature requirements) than the others.
2NH3 + NO + NO2 →2N2 + 3H2O
The fast SCR reaction generally goes to completion before any of the other reactions become
significant. This leads to a desire to have a NO2 fraction near 50% at the SCR reactor inlet.
Final SGEIS 2015, Page A18A-5

 However, given variations in the NO2 consumption by a CRT and variations in engine load and
engine out exhaust gas composition, consistently providing the SCR reactor with a 50:50 NO2 to
NO ratio would be quite difficult.
As long as the exhaust gases remain in the SCR reactor after the fast SCR reaction has exhausted
one of the NOX species, other chemical reactions will continue to reduce NOX. The reaction for
NO produces nitrogen and water. Several competing reactions are possible for NO2. Some of
these produce ammonium nitrate or nitrous oxide in addition to nitrogen.
Another concern with SCR is “ammonia slip,” the emission of ammonia injected into the exhaust
stream but not consumed. Oxidation catalysts are employed after SCR reactors to oxidize
ammonia to nitrogen. This catalyst could also oxidize NO to NO2. Thus, it cannot be
completely ruled out that NOX emissions from SCR equipped engines may consist of more than
10% NO2, possibly with an upper bound of 35%. However, further review of the literature
regarding the chemistry of ammonia slip catalysts leads to the conclusion that oxidation of NO to
NO2 is not a major concern. The desired reaction in the ammonia slip catalyst is the oxidation of
ammonia to nitrogen and water. Competing reactions form NO and N2O, but not NO2 (13). The
fate of NO in an ammonia slip catalyst is to react with ammonia and form N2O. NO2 production
would likely only begin if the ammonia was exhausted. The chemical reaction mechanism of
ammonia oxidation is well known, it is an intermediate step in the industrial production of nitric
acid (14). Given that there is no apparent path to NO2 formation as long as NH3 is present,
greater confidence can be placed in a NO2 emission estimate of 10% of NOX for SCR equipped
engines.
Thus, actual data summarized by Grice et. al., although sparse, currently suggests that we
consider the DOC/CRDPF NO2 fraction of 10% as the appropriate factor. Regardless of the
actual NO2 fraction of the NOX emissions from a SCR equipped engine (retrofitted or standard),
SCR will provide the lowest NO2 and NOX emissions achievable with diesel engines.
Emission Rates for Various Emissions Standards Tiers & Exhaust Aftertreatment Retrofit
Options
Considering the different Tiers of engine standards, the variety of possible exhaust aftertreatment
retrofits, and the uncertainty in the NO2 fraction of NOX emissions from SCR equipped engines,
there are in excess of 20 different emissions cases possible. Calculations were performed by
Barnes (15) (16), but only the pertinent part of these results are presented in Tables 5 and 6.
These emissions rates are estimated from the relevant U.S. EPA standards presented in Tables 1
and 2. In cases where a NOX + HC standard was promulgated, the standard is apportioned 90%
NOX, 10% HC. Effectiveness of exhaust aftertreatment retrofits are based on Table 3. Where
the claimed retrofit effectiveness reduces an emission rate below a subsequent standard expected
to require the same exhaust aftertreatment technology, the subsequent standard (the higher
number) is used as the emissions rate. NO2 emission rates are calculated from NOX emission
rates using factors presented in Table Four. For SCR-equipped engines the NO2 fraction of 10 %
of the NOX emissions is presented. Note that for Tier 4 engines above 750 hp a case where SCR

Final SGEIS 2015, Page A18A-6

 is standard (and thus cannot be retrofitted) is presented in addition to the original assumption that
SCR would not be utilized to meet the 2.6 g/bhp*hr NOX standard.
Table 5. Emissions Factors for Engines between 600 and 750 Horsepower
Air Drilling Engines

Tier 1

Effective
Year
1996

Tier 2

2002

Tier 3

2006

Tier 4

2011

Tier 4

2014

Standard

Retrofit
None
DOC
CRDPF
SCR-DPF
None
DOC
CRDPF
SCR-DPF
None
DOC
CRDPF
SCR-DPF
None
SCR
None

PM
(g/bhp*hr)
0.4
0.28
0.06
0.06
0.15
0.105
0.03
0.03
0.15
0.105
0.03
0.03
0.01
0.01
0.01

NOX
(g/bhp*hr)
6.9
6.9
6.9
0.69
4.32
4.32
4.32
0.432
2.7
2.7
2.7
0.3
1.35
0.3
0.3

HC
(g/bhp*hr)
1.0
0.14
0.14
0.14
0.48
0.14
0.14
0.14
0.3
0.14
0.14
0.14
0.14
0.14
0.14

NO2
(g/bhp*hr)
0.759
2.415
2.415
0.069
0.475
1.512
1.512
0.043
0.297
0.945
0.945
0.03
0.473
0.03
0.03

Table 6. Emissions Factors for Engines Greater than 750 Horsepower
Drilling Rig and Hydraulic Fracturing Engines (Updated 2012)

Tier 1

Effective
Year
2000

Tier 2

2006

Tier 4 interim

2011

Tier 4

2015

Standard

Tier 4
SCR Standard
Tier 4
Generator Set

Retrofit
None
DOC
CRDPF
SCR-DPF
None
DOC
CRDPF
SCR-DPF
None
CRDPF
SCR-DPF
None
SCR-DPF
None
None

PM
(g/bhp*hr)
0.4
0.28
0.06
0.06
0.15
0.105
0.03
0.03
0.075
0.03
0.03
0.03
0.03
0.03

NOX
(g/bhp*hr)
6.9
6.9
6.9
0.69
4.32
4.32
4.32
0.432
2.6
2.6
0.3
2.6
0.3
2.6

HC
(g/bhp*hr)
1.0
0.14
0.14
0.14
0.48
0.14
0.14
0.14
0.3
0.14
0.14
0.14
0.14
0.14

NO2
(g/bhp*hr)
0.759
2.415
2.415
0.069
0.475
1.512
1.512
0.043
0.91
0.91
0.03
0.91
0.03
0.26

0.02

0.5

0.14

0.05

Final SGEIS 2015, Page A18A-7

 Natural Gas Engines
For the most part, industry uses diesel engines for oil and gas drilling and hydraulic fracturing
operations. Natural gas fired engines have been used in some instances. Natural gas engines
must either be spark-ignition or a pilot fuel (generally diesel fuel) is necessary to initiate
compression ignition (17). The latter are referred to as “dual-fueled.”
Large nonroad spark-ignition engines are certified under 40 CFR Part 1048. Since 2007 these
engines have been certified to Tier 2 standards. Note that this is not the same Tier 2 as the
nonroad compression-ignition standards referenced in Tables 1 and 2 above. Manufacturers
have a choice of six different NOX + HC standards, depending on the choice of carbon monoxide
standard. In keeping with the methodology used above for diesel engines, the most lenient NOX
+ HC standards serve as the basis for conservative emission factors.
The only relevant standard is the NOX + HC standard. Additional information is necessary to
derive, NOX, PM, hydrocarbon, and NO2 emission factors. This is provided by data published by
the National Renewable Energy Laboratory regarding comparative testing of natural gas fueled
trucks and buses versus comparable diesel fueled vehicles (18) (19). These limited data suggest
that approximately 95% of the total NOX and nonmethane hydrocarbon (the hydrocarbon
measure specified in Part 1048 for natural gas fueled engines) is NOX. NO2 emissions are
approximately 17% of total NOX emissions. In the absence of PM standards the most stringent
diesel PM standard from Table 2 is used. In the bus testing referenced in (19) the natural gas
buses had PM emissions comparable to particulate trap equipped diesels. Emission factors for
natural gas fueled spark-ignition engines are summarized in Table 7.
Table 7. Emission Factors for Natural Gas Fueled Spark-Ignition Engines (New 2012)
Standard
Tier 2

Effective Year
2007

PM
(g/bhp*hr)
0.03

NOX
(g/bhp*hr)
1.9

HC
(g/bhp*hr)
0.1

NO2
(g/bhp*hr)
0.32

Duel fueled compression-ignition engines would be certified to the same standards as diesel
engines of the same model year and horsepower class. They also can be operated solely on
diesel fuel. Consequently emission factors derived for diesel engines would apply equally to
duel fueled engines.
Summary
Between 2000 and 2015 nonroad engines will have gone through four or five (depending on
engine power) different sets of emissions standards. PM mass reduction over this timeframe will
be 93% for the largest engines and 98% for engines rated between 600 and 750 horsepower.
NOX emissions will be reduced 96% for the 600 to 750 horsepower engines, but only 62% for
the larger engines. Much of these emissions reductions can be achieved without premature
replacement of older engines by retrofitting exhaust aftertreatment to these engines. However,
successful retrofits are dependent on the details of the engines and duty cycles involved, and
have not been verified for drilling and hydraulic fracturing engines. An additional consideration
with these retrofits is that PM aftertreatment in the absence of SCR will increase NO2 emissions.
Final SGEIS 2015, Page A18A-8

 This concern also applies to current and future Tier 4 engines which may have PM aftertreatment
but not NOX aftertreatment.
Bibliography
1. ALL Consulting. NY DEC SGEIS Information Requests and Industry Responses; Chapter 7.
s.l. : Independent Oil & Gas Association, October 14, 2009.
2. Cummins, Inc. Cummins Emission Technology Portfolio. 2011. Bulletin 4087225 Rev.
11/11.
3. Johnson Matthey Catalysts. Emissions Solutions for Stationary Engines. Johnson Matthey
Catalysts. [Online] [Cited: November 24, 2010.]
http://ect.jmcatalysts.com/site.asp?siteid=836&pageid=888&furtherid=945.
4. U.S. EPA. Letter from Jim Blubaugh ( U.S.EPA) to Ajay Joshi (Johnson Matthey). August 11,
2010. Verficiation of Selective Cataltyic Reduction Technology for on-road heavy duty diesel
engines, p. 2 pages.
5. Combined SCR and DPF Technology for Heavy Duty Diesel Retrofit. Conway, Ray, et al.
Detroit, Michigan : SAE Technical Paper Series, 2005. 2005-01-1862.
6. Oseniga, Mike. Cleaner Air Comes to PAPA. Diesel Progress North American Edition. April
2009.
7. Recent Trends and Projections of Primary NO2 emissions in Europe. Grice, Susannah, et al.
2009, Atmospheric Environment, pp. 2154-2167.
8. The Effect of a Diesel Oxidation Catalyst and a Catalyzed Particulate Filter on the Emissions
from a Heavy Duty Diesel Engine. Lakkireddy, Venkata R., et al. s.l. : SAE Technical Paper
Series, 2006. 2006-01-0875.
9. Diesel NO/NO2/NOX Emissions - New Experiences and Challenges. Czerwinski, Jan,
Peterman, Jean-Luc and Comte, Pierre. s.l. : SAE Technical Paper Series, 2007. 2007-010321.
10. Study of a Fe-Zeolite-based System as NH3-SCR Catalyst for Diesel Exhaust Aftertreatment.
Grossale, Antonio, Nova, Isabella and Tronconi, Enrico. 2008, Catalysis Today, pp. 18-27.
11. A Comparative Study of "Standard," "Fast," and "NO2" SCR Reactions over Fe/Zeolite
Catalyst. Iwasaki, Masaoki and Shinjoh, Hirofumi. 2010, Applied Catalysis A: General, pp.
71-77.
12. Spatially Resolving SCR Reactions over a Fe/Zeolite Catalyst. Luo, Jin-Yong, et al. 2011,
Applied Catalysis B: Environmental, pp. 110-119.

Final SGEIS 2015, Page A18A-9

 13. Simulation of Automotive NH3 Oxidation Catalysts Based on Pre-computed Rate Data from
Mechanistic Surface Kinetics. Votsmeier, M., et al. 2010, Catalysis Today, Vol. 151, pp. 271277.
14. NH3-Slip Catalytsts: Experiments Versus Mechanistic Modeling. Scheuer, A., et al. 2009,
Topics in Catalysis, Vol. 52, pp. 1847-1851.
15. Barnes, David L. Nonroad Engine Emissions Rate estimates.xlsx. March 8, 2011.
16. —. Nonroad Emissions Estimates.xlsx. March 8, 2011.
17. Natural-gas fueled spark-ignition (SI) and compression-ignition (CI) engine performance
and emissions. Korakianits, T., Namasivayam, A.M. and Crookes, R.J. 2011, Progress in
Energy and Combustion Science, Vol. 37, pp. 89-112.
18. Lyford-Pike, E.J. An Emission and Performance Comparisonof the Natural Gas C-Gas Plus
Engine in Heavy-Duty Trucks. National Renewable Energy Laboratory. 2003. NREL/SR-54032863.
19. Melendez, M., et al. Emission Testing of Washington Area Transit Authority (WMATA)
Natural Gas and Diesel Transit Buses. National Renewable Energy Laboratory. 2005.
NREL/TP-540-36355.

Final SGEIS 2015, Page A18A-10

 Appendix 18B
Cost Analysis of Mitigation of NO2
Emissions and Air Impacts By Selected
Catalytic Reduction (SCR) Treatment
Updated/revised 2015

Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Cost Analysis of Mitigation of NO2 Emissions and Air Impacts by
Selective Catalytic Reduction (SCR) Treatment
1. Introduction
Equipping fracturing engines with post-combustion NOX control equipment could be a potential
option for mitigating the modeled exceedances of the 1 hour NO2 National Ambient Air Quality
Standard. Selective Catalytic Reduction (SCR) is a proven technology for reducing oxides of
nitrogen (NOX) emissions from mobile and stationary combustion sources. Although SCR
systems have not been applied to fracturing engines, it may be possible to adapt the technology
to this class of engines. This technology involves the use of a urea solution (32.5 percent urea)
which converts NOX to nitrogen gas via a catalyst.
An estimate of the mitigation costs based on costs for stationary engines 1 is presented in this
appendix. The purpose of these estimates is to determine the cost per ton of NOX removal for a
relative comparison to cost thresholds used by the Department for NOX RACT purposes at
stationary sources. 2 Any reference to specific manufacturers (in footnotes) does not constitute an
endorsement, but merely presents the specific information source.
The remainder of this appendix is divided into three sections. First, an estimate is developed
regarding how many jobs and how many hours a hydraulic fracturing engine could be used each
year in Section 2. In the third section of the appendix, the costs of installing and operating a
SCR system on a typical 2250 hp hydraulic fracturing engine are presented. In the fourth
section, an estimate of the cost per ton of NOX removed from the exhaust stream is presented for
each engine tier.
2. Operation of Hydraulic Fracturing Engines
According to ALL Consulting, hydraulic fracturing engines will be used at any given well pad
for no more than 14 days. Mobilization and de-mobilization activities are expected to take a
total of four days. Hydraulic fracturing activities are expected to take ten days per well pad (five
days per well). 3 At most, a hydraulic fracturing engine could be used for 26 jobs per year.
Allowing for additional travel time, maintenance and vacations, the Department is assuming an
engine will be used for approximately 20 jobs per year in the Marcellus play. Further, it was
assumed that these engines will be used for a maximum of five hydraulic fracturing events per
day and will operate two hours per event at their maximum loading and emissions. 4 Therefore, a
hydraulic fracturing engine could be used up to 2,000 hours per year at the maximum load:

1

Hydraulic fracturing engines are considered nonroad sources.
See: http://www.dec.ny.gov/regs/4217.html
3
“NY DEC SGEIS Information Requests”, ALL Consulting, September 16, 2010, page 39.
4
“Horizontally Drilled/High-Volume Hydraulically Fractured Wells, Air Emissions Data”, August 26, 2009,
page 9.
2

Final SGEIS 2015, Page A18B-1

 (20 jobs/year)(10 days/job)(5 hydraulic fracturing events/day)(2 hours/hydraulic fracturing
event) = 2,000 hours/year

3. Reduction of Oxides of Nitrogen and Costs
Selective catalytic reduction (SCR) is a proven technology for reducing NOX emissions.
Department is assuming that this technology is the most likely post-combustion control
could potentially be used to reduce NOX emissions from hydraulic fracturing engines
Appendix 20). The Department considered capital, periodic and annual costs in the
estimates discussed in this section.

The
that
(see
cost

Capital Costs
The capital cost for a SCR system was assumed to be $80 per hp. 5 Installation costs were
assumed to be 60 percent of the system cost. 6 Taxes were assumed to be eight (8) percent of the
system cost. The estimated capital cost for a typical 2250 hp hydraulic fracturing engine is
$302,400 as detailed below:
System Cost:
Installation:
Taxes:
Total:

$180,000
$108,000
$ 14,400
$302,400

Periodic Costs
The periodic costs considered by the Department were for replacing SCR catalysts every five
years. 7 It was assumed that the replacement costs were seven (7) percent of the system costs 8
and installation 60 percent of the replacement cost. The periodic costs (at year 5) were estimated
to be $20,160 as detailed below:
Catalyst Replacement:
Installation:
Total:

$12,600
$ 7,560
$20,160

5

CARB 2010. Regulatory Analysis for Revisions to Stationary Diesel Engine Air Toxic Control Measure.
Appendix B. Analysis of Technical Feasibility and Costs of Aftertreatment Controls on Emergency Diesel
Engines.

6

Plant Design and Economics for Chemical Engineers, Third Edition, M.S. Peters and K. D. Timmerhaus, 1980,
pages 168-169.
E-mail from Wilson Chu (Johnson Matthey) to John Barnes (NYSDEC) dated January 24, 2008.
E-mail from Chad Whiteman (Institute of Clean Air Companies) to John Barnes dated November 27, 2007 and email from Wilson Chu (Johnson-Matthey) to John Barnes dated January 24, 2008.

7
8

Final SGEIS 2015, Page A18B-2

 Annual Costs
The quantity of reagent used depends upon the amount of NOX coming from the engine. The
control efficiency for SCRs was assumed to be 90 percent for engines. The emission rates
factored into this analysis are presented in Table 1 (see Appendix 20). Further, it was assumed
that hydraulic fracturing engines will be operated at 50 percent of capacity. 9 The urea
requirement for each pound of NOX treated in an SCR is 0.2088 gallons. 10
Table 1: NOX Emission Rates for Tier 2, Interim 4 (I4) and 4 Hydraulic Fracturing Engines
Tier
NOX (without control) 11
#
(g/bhp-h)
2
4.32
Interim 4 (I4)
2.60
4
2.60

NOX (with control)
g/bhp-h
0.43
0.26
0.26

The urea requirements range from 1.21 gallons per hour (gal/h) for a Tier 4 engine to 2.01 gal/h
for a Tier 2 engine. The estimated cost of urea is $3.67 per gallon. 12
In addition to the reagent requirements, annual insurance costs were estimated to be one (1)
percent of the system cost 13 and maintenance costs were assumed to be six (6) percent of the
system cost. 14 A summary of the annual costs is presented below:

Reagent:
Insurance:
Maintenance:
Total:

Tier 2
$14,800
$ 3,000
$18,100
$35,900

Tier I4
$ 8,900
$ 3,000
$18,100
$30,000

Tier 4
$ 8,900
$ 3,000
$18,100
$30,000

Annualized Cost
A discount rate of seven (7) percent was used to convert the above costs into an equivalent
annual cost for a 10-year horizon. The estimated annualized costs are presented in the next
section.

9

“Horizontally Drilled/High-Volume Hydraulically Fractured Wells, Air Emissions Data”, August 26, 2009, p. 10.
E-mail from Michael Baran (Johnson Matthey) to John Barnes, April 17, 2008.
11
See Appendix 20. The values in the second column of Table 1 are assumed to be the NOx emissions in the
exhaust gas coming from the engine chamber.
12
E-mail from Wilson Chu (Johnson Matthey) to John Barnes (NYSDEC) dated January 24, 2008. Also factored
was Consumer Price Index data: www.bls.gov/cpi/cpid0801.pdf and www.bls.gov/cpi/cpid0211.pdf.
13
Plant Design and Economics for Chemical Engineers, Third Edition, M.S. Peters and K. D. Timmerhaus, 1980,
page 202.
14
Ibid, page 200.
10

Final SGEIS 2015, Page A18B-3

 4. Cost Effectiveness Analysis
The cost effectiveness (cost per ton of NOX treated) of applying SCR controls on Tier 2, I4 and 4
hydraulic fracturing engines is presented in Table 2. .Hydraulic fracturing engines equipped
with SCRs will have emission rates ranging from 0.26 g/bhp-h (Tier 4) to 0.43 g/bhp-h (Tier 2).
The estimated cost per ton of NOX control is greater than the Department’s $5,000 per ton
threshold for NOX RACT (Reasonably Available Control Technology – Subpart 227-2) used to
determine cost-effectiveness of controls at major stationary sources.
Table 2: Cost Effectiveness of SCR Control on Hydraulic Fracturing Engines
Engine Tier
2
I4
4

Annualized Cost
$81,050
$75,170
$75,170

NOX Removed (tons)
9.64
5.80
5.80

Final SGEIS 2015, Page A18B-4

Cost Effectiveness (ton-1)
$ 8,400
$12,950
$12,950

 Appendix 18C
Regional On-Road Mobile Source Emission
Estimates from EPA’s MOVES Model and
Single-Pad PM2.5 Estimates from
MOBILE 6 Model
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

2007 Annual Mobile Source Emissions
MOVES 2010a Based Inventory Runs
Includes all MOVES Emission Processes Except Evap. Permeation, Evap. Vapor Venting & Evap. Fuel Leaks
 
Base Emissions
FIPS

36001
36003
36007
36009
36011
36013
36015
36017
36023
36025
36029
36037
36039
36051
36053
36065
36067
36069
36071
36077
36095
36097
36099
36101
36105
36107
36109
36111
36121
36123

County

ALBANY
ALLEGANY
BROOME
CATTARUAGUS
CAYUGA
CHAUTAQUA
CHEMING
CHENANGO
CORTLAND
DELAWARE
ERIE
GENESEE
GREENE
LIVINGSTON
MADISON
ONEIDA
ONONDAGA
ONTARIO
ORANGE
OTSEGO
SCHOHARIE
SCHUYLER
SENECA
STEUBEN
SULLIVAN
TIOGA
TOMPKINS
ULSTER
WYOMING
YATES

PM25 
PM10 
CO
Total
Total
(Tons/Yr) (Tons/Yr) (Tons/Yr) (Tons/Yr) (Tons/Yr) (Tons/Yr)
NOX

VOC

8423.0
1436.5
4807.1
2446.6
2020.5
4178.1
2113.2
1066.9
1653.3
1224.2
19260.0
3035.1
1997.6
1911.9
1797.8
4997.0
11468.5
3628.0
7527.5
1620.0
1505.6
558.3
1234.1
3969.5
1481.6
1398.8
1727.3
4114.3
999.9
477.8

3323.7
495.0
1998.9
839.0
774.2
1410.3
861.3
510.5
543.1
539.2
7997.4
855.2
672.1
683.9
729.6
2222.6
4535.9
1241.3
3123.6
640.5
496.2
215.0
401.9
1197.4
752.4
599.9
790.5
1895.8
414.6
222.1

SO2

64.2
8.5
36.2
15.0
13.6
26.5
15.1
7.9
11.1
9.0
138.2
20.5
14.1
12.3
13.1
38.1
82.3
25.5
49.7
11.4
11.6
3.8
8.3
24.2
11.8
10.5
12.8
36.0
6.5
3.2

356.3
63.8
209.0
107.9
84.0
184.6
89.3
43.8
71.8
50.1
798.8
127.1
83.1
83.5
73.4
211.2
501.2
150.8
302.3
70.1
62.0
22.8
52.1
173.8
58.4
57.6
72.3
156.2
42.3
19.3

339.0 51044.0
60.9
7205.9
198.5 30424.5
103.0 12115.4
80.2 11210.1
176.3 20379.8
85.2 12366.7
41.5
7513.7
68.5
8158.8
47.5
8013.5
760.4 117094.0
121.5 13116.7
79.3 10151.8
79.6 10006.3
69.9 10881.9
200.7 32376.2
477.7 66575.9
144.0 18507.6
286.3 53982.4
66.6
9659.1
59.0
7964.9
21.7
3102.1
49.8
5979.4
166.3 17845.0
55.3 11050.7
54.9
8538.5
68.8 11227.7
148.2 29231.2
40.4
5827.2
18.4
3152.6

Emissions resulting from additonal VMT from proposed drilling 
activity
PM25 
PM10 
SO2
NOX
VOC
CO
Total
Total
(Tons/Yr) (Tons/Yr) (Tons/Yr) (Tons/Yr) (Tons/Yr) (Tons/Yr)
8447.2
1458.5
4830.2
2468.7
2043.2
4200.5
2137.1
1089.4
1675.5
1246.3
19282.6
3057.1
2020.1
1934.2
1820.3
5020.6
11492.9
3650.8
7551.6
1641.8
1527.7
580.9
1256.6
3991.3
1504.9
1423.3
1751.6
4138.3
1022.8
500.8

Final SGEIS 2015, Page A18C-1

3326.2
497.1
2001.2
841.2
776.5
1412.5
863.8
512.8
545.3
541.3
7999.7
857.4
674.4
686.1
731.8
2225.1
4538.4
1243.7
3126.0
642.6
498.4
217.4
404.2
1199.5
754.7
602.6
793.1
1898.4
416.9
224.5

64.3
8.6
36.3
15.0
13.7
26.6
15.1
7.9
11.1
9.1
138.3
20.6
14.2
12.4
13.2
38.1
82.4
25.6
49.8
11.5
11.7
3.9
8.4
24.3
11.9
10.6
12.9
36.1
6.6
3.3

357.6
64.8
210.2
108.9
85.2
185.7
90.5
44.9
72.9
51.1
799.9
128.2
84.2
84.6
74.6
212.4
502.4
152.0
303.6
71.1
63.1
23.9
53.2
174.9
59.6
58.9
73.5
157.5
43.5
20.5

340.2 51067.1
61.9
7227.5
199.6 30447.8
104.0 12137.9
81.3 11231.9
177.3 20402.2
86.4 12390.9
42.6
7535.9
69.6
8180.9
48.6
8034.7
761.5 117116.0
122.6 13138.1
80.4 10174.1
80.7 10028.8
71.0 10903.7
201.8 32399.3
479.0 66600.0
145.1 18529.9
287.5 54005.2
67.6
9681.4
60.1
7987.0
22.9
3122.9
50.8
6002.1
167.3 17867.0
56.5 11070.8
56.2
8561.8
70.1 11250.9
149.4 29254.8
41.5
5847.9
19.6
3173.5

 Total For 
Counties 
in 
Marcellus 
Shale 
Area

104,080

40,983

741

4,379

4,170

Estimated additional mobile source emissions resulting from 
additional VMT associated with proposed gas drilling *
PM25 
PM10 
SO2
NOX
VOC
CO
Total
Total
(Tons/Yr)

(Tons/Yr)

(Tons/Yr)

(Tons/Yr)

(Tons/Yr)

614,703

104,767

41,053

743

4,413

4,203

615,372

Percentage increase in emissions assuming all wells operating 
PM25 
PM10 
SO2
NOX
VOC
CO
Total
Total
0.66%

(Tons/Yr)

686.7
70.0
2.5
34.4
33.3
668.6
Well pad emissions assuming total emissions split equally across all 
0.28
0.03
0.00
0.01
0.01
0.27

* Does NOT include Evaporative emissions processes

Final SGEIS 2015, Page A18C-2

0.17%

0.33%

0.79%

0.80%

0.11%

 Marcellus Single Pad MOBILE Model Emissions of PM2.5 for CP‐33 Comparison

Vehicle Trip Emissions 
Max 
Feet 
Distance 
Number of  travelled  travelled per  PM 2.5 EF  Emissions 
(tons)
Vehicle Type
Trucks
per site* truck (miles)  (lbs/mile)
Drill Pad and Road Construction Equipment 
45
1700
14.49
0.0003 2.18799E‐06
Drilling Rig 
30
30
1700
9.66
0.0003 1.45866E‐06
Drilling Fluid and Materials 
25‐50
50
1700
16.10
0.0003
2.4311E‐06
Drilling Equipment (casing, drill pipe, etc.) 
25‐50
50
1700
16.10
0.0003
2.4311E‐06
Completion Rig 
15
15
1700
4.83
0.0003
7.2933E‐07
Completion Fluid and Materials 
10‐20
20
1700
6.44
0.0003 9.72439E‐07
Completion Equipment – (pipe, wellhead) 
5
5
1700
1.61
0.0003
2.4311E‐07
Hydraulic Fracture Equipment (pump trucks, tanks)
150‐200
200
1700
64.39
0.0003 9.72439E‐06
Hydraulic Fracture Water
400‐600
600
1700
193.18
0.0003 2.91732E‐05
Hydraulic Fracture Sand
20‐25
25
1700
8.05
0.0003 1.21555E‐06
Flow Back Water Removal
200‐300
300
1700
96.59
0.0003 1.45866E‐05
Total
1340
431.44
6.51534E‐05
*(1 ‐ 750 foot trip onto site, 1 ‐ 100 foot trip to station, 1‐ 100 foot trip back from the station and 1‐750 foot trip off the site)
Range of 
Trucks
10‐45

Vehicle Idle Emissions
Max 
Idle Time  Hours idling 
Number of  per truck  per truck type  PM 2.5 EF 
Vehicle Type
Trucks
(hrs)**
(hrs)
(lbs/hr)
Drill Pad and Road Construction Equipment 
45
2
90.00
0.0013
Drilling Rig 
30
30
2
60.00
0.0013
Drilling Fluid and Materials 
25‐50
50
2
100.00
0.0013
Drilling Equipment (casing, drill pipe, etc.) 
25‐50
50
2
100.00
0.0013
Completion Rig 
15
15
2
30.00
0.0013
Completion Fluid and Materials 
10‐20
20
2
40.00
0.0013
Completion Equipment – (pipe, wellhead) 
5
5
2
10.00
0.0013
Hydraulic Fracture Equipment (pump trucks, tanks)
0.0013
150‐200
200
2
400.00
Hydraulic Fracture Water
400‐600
600
2
1200.00
0.0013
Hydraulic Fracture Sand
20‐25
25
2
50.00
0.0013
Flow Back Water Removal
200‐300
300
2
600.00
0.0013
Total
1340
2680.00
** Assume each truck idles at least 2 hours  over the duration of the project
Range of 
Trucks
10‐45

Final SGEIS 2015, Page A18C-3

Emissions 
(tons)
5.74901E‐05
3.83267E‐05
6.38779E‐05
6.38779E‐05
1.91634E‐05
2.55511E‐05
6.38779E‐06
0.000255511
0.000766534
3.19389E‐05
0.000383267
0.001711927

 Road Dust Emissions
Vehicle Type
Drill Pad and Road Construction Equipment 
Drilling Rig 
Drilling Fluid and Materials 
Drilling Equipment (casing, drill pipe, etc.) 
Completion Rig 
Completion Fluid and Materials 
Completion Equipment – (pipe, wellhead) 
Hydraulic Fracture Equipment (pump trucks, tanks)
Hydraulic Fracture Water
Hydraulic Fracture Sand
Flow Back Water Removal
Total

Max 
Feet 
Distance 
Range of 
Number of  travelled  travelled per  PM 2.5 EF 
Trucks
Trucks
per site* truck (miles)  (lbs/mile)
10‐45
45
1700
14.49
0.0863
30
30
1700
9.66
0.0863
25‐50
50
1700
16.10
0.0863
25‐50
50
1700
16.10
0.0863
15
15
1700
4.83
0.0863
10‐20
20
1700
6.44
0.0863
5
5
1700
1.61
0.0863
150‐200
200
1700
64.39
0.0863
400‐600
600
1700
193.18
0.0863
20‐25
25
1700
8.05
0.0863
200‐300
300
1700
96.59
0.0863
1340
431.44

Total PM 2.5 Emissions
Vehicle Trip Emissions 
Vehicle Idle Emissions
Road Dust Emissions
Total

Emissions 
Emissions 
(tons)
(lbs)
6.51534E‐05
0.13
0.001711927
3.42
1.86E‐02
37.25
0.02
40.81

Final SGEIS 2015, Page A18C-4

Emissions 
(tons)
0.000625511
0.000417007
0.000695012
0.000695012
0.000208504
0.000278005
6.95012E‐05
0.002780047
0.008340142
0.000347506
0.004170071
0.018626317

 Appendix 19
Greenhouse Gas
(GHG)
Emissions
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

 

Part A

GHG Tables

 

This page intentionally left blank.

GHG Tables (Revised July 2011, following replaces tables released in September 2009)
Table GHG-1 – Emission Rates for Well Pad1
Emission
Source/
Equipment
Type

CH4 EF

CO2 EF

Units

EF Reference2

0.014

0.00015

lbs/hr per well

Vol 8, page no. 34,
table 4-5

Fugitive Emissions
Gas Wells
Gas Wells

Field Separation Equipment
Heaters

0.027

0.001

lbs/hr per heater

Separators

0.002

0.00006

lbs/hr per separator

Dehydrators

0.042

0.001

lbs/hr per
dehydrator

Meters/Piping

0.017

0.001

lbs/hr per meter

Vol 8, page no. 34,
table 4-5
Vol 8, page no. 34,
table 4-5
Vol 8, page no. 34,
table 4-5
Vol 8, page no. 34,
table 4-5

Gathering Compressors
Large
Reciprocating
Compressor

29.252

Vented and Combusted Emissions
Normal Operations
1,775 hp
Reciprocating
not determined
Compressor
Pneumatic
0.664
Device Vents
Dehydrator
12.725
Vents
Dehydrator
45.804
Pumps
Blowdowns
Vessel BD
Compressor BD
Compressor
Starts
Upsets
Pressure Relief
Valves

1.037

lbs/hr per
compressor

1,404.716

lbs/hr per
compressor

0.024

lbs/hr per device

0.451
1.623

0.00041

0.00001

0.020

0.00071

0.045

0.00158

0.00018

0.00001

lbs/MMscf
throughput
lbs/MMscf
throughput
lbs/hr per vessel
lbs/hr per
compressor
lbs/hr per
compressor
lbs/hr per valve

1

GRI - 96 Methane
Emissions from the
Natural Gas
Industry, Final
Report

6,760 Btu/hp-hr,
2004 API, page no.
4-8
Vol 12, page no.
48, table 4-6
Vol 14, page no.
27
GRI June Final
Report
Vol 6, page no. 18,
table 4-2
Vol 6, page no. 18,
table 4-2
Vol 6, page no. 18,
table 4-2
Vol 6, page no. 18,
table 4-2

Adapted from Exhibit 2.6.1, ICF Incorporated, LLC. Technical Assistance for the Draft Supplemental Generic
EIS: Oil, Gas and Solution Mining Regulatory Program. Well Permit Issuance for Horizontal Drilling and High-

Volume Hydraulic Fracturing to Develop the Marcellus Shale and Other Low Permeability Gas Reservoirs, 

Agreement No. 9679, August 2009., pp 34-35.

2
Unless otherwise noted, all emission factors are from the Gas Research Institute, Methane Emissions from the
Natural Gas Industry, 1996. Available at: epa.gov/gasstar/tools/related.html.


Page 1 of 15
Final SGEIS 2015, Page A19A-1

 Table GHG-2 – Drilling Rig Mobilization, Site Preparation and Demobilization – GHG Emissions

Emissions Source
Transportation 4
Drill Pad and Road Construction 5
Total Emissions

Single Vertical, Single Horizontal or Four-Well Pad3
Combustion Emissions
Light Truck & Heavy Truck
Total
Vented
Light Truck & Heavy
Combined Fuel Use (gallons
Operating
Emissions
Truck Combined
diesel)
Hours
(tons CH4)
Emissions (tons CO2)
432
NA
NA
4
NA
48 hours
NA
11
432
NA
NA
15

Fugitive
Emissions
(tons CH4)
NA
NA
NA

Table GHG-3 – Completion Rig Mobilization and Demobilization – GHG Emissions

Emissions Source
Completion Rig6
Total Emissions

Single Vertical, Single Horizontal or Four-Well Pad
Combustion Emissions
Total
Light Truck & Heavy Truck
Vented
Light Truck & Heavy
Operating
Combined Fuel Use (gallons
Emissions
Truck Combined
Hours
diesel)
(tons CH4)
Emissions (tons CO2)
432
NA
NA
4
432
NA
NA
4

3

Fugitive
Emissions
(tons CH4)
NA
NA

Site preparation for a single vertical well would be less due to a smaller pad size but for simplification site preparation is assumed the same for all well

scenarios considered.

4
ALL Consulting, 2011, Exhibit19B.

5
Assumed 20 gallons of diesel fuel used per hour with 100% oxidation of fuel carbon to CO2.

6
ALL Consulting, 2011, Exhibit19B. Completion rig mobilization likely less than that for drilling rig but for simplification assumed the same.


Page 2 of 15
Final SGEIS 2015, Page A19A-2

 Table GHG-4 – Well Drilling – Single Vertical Well GHG Emissions
Single Vertical Well

Emissions
Source

Transportation7
Power
Engines8
Circulating
System9
Well Control
System10
Total
Emissions

Light
Truck &
Heavy
Truck
Combined
Fuel Use
(gallons
diesel)
788

Total
Operating
Hours

Activity
Factor

Vented
Emissions
(tons
CH4)

Combustion
Emissions
(tons CO2)

Fugitive
Emissions
(tons
CH4)

NA

NA

NA

9

NA

NA

132 hours

1

NA

74

NA

NA

132 hours

1

negligible

NA

negligible

NA

As needed

1

negligible

negligible

negligible

NA

NA

NA

negligible

83

negligible

7

ALL Consulting, 2011, Exhibit 20B. 

Power Engines include rig engines, air compressor engines, mud pump engines and electrical generator engines. Assumed 50 gallons of diesel fuel used per 

hour with 100% oxidation of fuel carbon to CO2.

9
Circulating system includes mud system piping and valves, mud-gas separator, mud pits or tanks and blooie line for air drilling. 

10
Well Control System includes well control piping and valves, BOP, choke manifold and flare line.

8

Page 3 of 15
Final SGEIS 2015, Page A19A-3

 Table GHG-5 – Well Drilling – Single Horizontal Well GHG Emissions
Single Horizontal Well

Emissions
Source

Transportation11
Power
Engines12
Circulating
System13
Well Control
System14
Total
Emissions

Light
Truck &
Heavy
Truck
Combined
Fuel Use
(gallons
diesel)
2,298

Total
Operating
Hours

Activity
Factor

Vented
Emissions
(tons
CH4)

Combustion
Emissions
(tons CO2)

Fugitive
Emissions
(tons
CH4)

NA

NA

NA

26

NA

NA

300 hours

1

NA

168

NA

NA

300 hours

1

negligible

NA

negligible

NA

As needed

1

negligible

negligible

negligible

NA

NA

NA

negligible

194

negligible

11

ALL Consulting, 2011, Exhibit19B.

Power Engines include rig engines, air compressor engines, mud pump engines and electrical generator engines. Assumed 50 gallons of diesel fuel used per 

hour with 100% oxidation of fuel carbon to CO2.

13
Circulating system includes mud system piping and valves, mud-gas separator, mud pits or tanks and blooie line for air drilling. 

14
Well Control System includes well control piping and valves, BOP, choke manifold and flare line.

12

Page 4 of 15
Final SGEIS 2015, Page A19A-4

 Table GHG-6 – Well Drilling – Four-Well Pad GHG Emissions
Four-Well Pad

Emissions
Source

Transportation15
Power
Engines16
Circulating
System17
Well Control
System18
Total
Emissions

Light
Truck &
Heavy
Truck
Combined
Fuel Use
(gallons
diesel)
9,192

Activity
Factor

Vented
Emissions
(tons
CH4)

Combustion
Emissions
(tons CO2)

Fugitive
Emissions
(tons
CH4)

NA
1,200
hours
1,200
hours

NA

NA

104

NA

1

NA

672

NA

1

negligible

NA

negligible

NA

As needed

1

negligible

negligible

negligible

NA

NA

NA

negligible

776

negligible

NA
NA

Total
Operating
Hours

15

ALL Consulting, 2011, Exhibit19B.

Power Engines include rig engines, air compressor engines, mud pump engines and electrical generator engines. Assumed 50 gallons of diesel fuel used per 

hour with 100% oxidation of fuel carbon to CO2.

17
Circulating system includes mud system piping and valves, mud-gas separator, mud pits or tanks and blooie line for air drilling. 

18
Well Control System includes well control piping and valves, BOP, choke manifold and flare line.

16

Page 5 of 15
Final SGEIS 2015, Page A19A-5

 Table GHG-7 – Well Completion – Single Vertical Well GHG Emissions
Single Vertical Well
Emissions Source
Transportation19
Hydraulic
Fracturing Pump
Engines
Line Heater
Flowback
Pits/Tanks
Flare Stack21
Rig Engines24
Site Reclamation25
Transportation for
Site Reclamation26
Total Emissions

Light Truck & Heavy
Truck Combined Fuel
Use (gallons diesel)
818

Total
Operating
Hours or
Fuel Use
NA

Activity
Factor

Vented
Emissions
(tons CH4)

Combustion
Emissions
(tons CO2)

Fugitive
Emissions
(tons CH4)

1

NA

9

NA

NA

4,833
gallons20

1

NA

54

NA

NA

72 hours

1

NA

negligible

NA

NA

72 hours

1

NA

NA

negligible

22

23

NA
NA
NA

72 hours
12 hours
24 hours

1
1
NA

12
NA
NA

1,728
4
6

280

NA

NA

NA

3

NA

NA

NA

NA

12

1,804

negligible

19

NA
NA
NA

ALL Consulting, 2011, Exhibit 20B.
ALL Consulting, 2009. Horizontally Drilled/High-Volume Hydraulically Fractured Wells Air Emissions Data, Table 11, p. 10. Assumed vertical job is one-

sixth of high-volume job.

21
Assumed no use of reduced emission completion (“REC”).
22
ICF Incorporated, LLC. Technical Assistance for the Draft Supplemental Generic EIS: Oil, Gas and Solution Mining Regulatory Program. Well Permit 

Issuance for Horizontal Drilling and High-Volume Hydraulic Fracturing to Develop the Marcellus Shale and Other Low Permeability Gas Reservoirs, August
2009, NYSERDA Agreement No. 9679. p. 28. . Vertical well not likely to produce at assumed rate due to reduced completion interval.

23
ICF Incorporated, LLC. Technical Assistance for the Draft Supplemental Generic EIS: Oil, Gas and Solution Mining Regulatory Program. Well Permit 

Issuance for Horizontal Drilling and High-Volume Hydraulic Fracturing to Develop the Marcellus Shale and Other Low Permeability Gas Reservoirs, August
2009, NYSERDA Agreement No. 9679. p. 28. Vertical well not likely to produce at assumed rate due to reduced completion interval.

24
Assumed 25 gallons of diesel fuel used per hour with 100% oxidation of fuel carbon to CO2.

25
Assumed 20 gallons of diesel fuel used per hour with 100% oxidation of fuel carbon to CO2.

26
ALL Consulting, 2011, Exhibit 20B.

20

Page 6 of 15
Final SGEIS 2015, Page A19A-6

 Table GHG-8 – Well Completion – Single Horizontal Well GHG Emissions
Single Horizontal Well
Emissions Source
Transportation27
Hydraulic
Fracturing Pump
Engines
Line Heater
Flowback
Pits/Tanks
Flare Stack29
Rig Engines32
Site Reclamation33
Transportation for
Site Reclamation34
Total Emissions

Light Truck & Heavy
Truck Combined Fuel
Use (gallons diesel)

Total
Operating
Hours or
Fuel Use

Activity
Factor

Vented
Emissions
(tons CH4)

Combustion
Emissions
(tons CO2)

Fugitive
Emissions
(tons CH4)

2,462

NA

1

NA

28

NA

NA

29,000
gallons28

1

NA

325

NA

NA

72 hours

1

NA

negligible

NA

NA

72 hours

1

NA

NA

negligible

30

31

NA
NA
NA

72 hours
24 hours
24 hours

1
1
NA

12
NA
NA

1,728
7
6

280

NA

NA

NA

3

NA

NA

NA

NA

12

2,097

negligible

27

NA
NA
NA

ALL Consulting, 2011, Exhibit 19B.
ALL Consulting, 2009. Horizontally Drilled/High-Volume Hydraulically Fractured Wells Air Emissions Data, Table 11, p. 10.

29
Assumed no use of reduced emission completion (“REC”).
30
ICF Incorporated, LLC. Technical Assistance for the Draft Supplemental Generic EIS: Oil, Gas and Solution Mining Regulatory Program. Well Permit 

Issuance for Horizontal Drilling and High-Volume Hydraulic Fracturing to Develop the Marcellus Shale and Other Low Permeability Gas Reservoirs, August
2009, NYSERDA Agreement No. 9679. p. 28.

31
ICF Incorporated, LLC. Technical Assistance for the Draft Supplemental Generic EIS: Oil, Gas and Solution Mining Regulatory Program. Well Permit 

Issuance for Horizontal Drilling and High-Volume Hydraulic Fracturing to Develop the Marcellus Shale and Other Low Permeability Gas Reservoirs, August
2009, NYSERDA Agreement No. 9679. p. 28.

32
Assumed 25 gallons of diesel fuel used per hour with 100% oxidation of fuel carbon to CO2.

33
Assumed 20 gallons of diesel fuel used per hour with 100% oxidation of fuel carbon to CO2.

34
ALL Consulting, 2011, Exhibit 19B. 

28

Page 7 of 15
Final SGEIS 2015, Page A19A-7

 Table GHG-9 – Well Completion – Four-Well Pad GHG Emissions
Four-Well Pad
Emissions Source
Transportation35
Hydraulic
Fracturing Pump
Engines
Line Heater
Flowback
Pits/Tanks
Flare Stack36
Rig Engines37
Site Reclamation38
Transportation for
Site Reclamation
Total Emissions

Light Truck & Heavy
Truck Combined Fuel
Use (gallons diesel)
9,848

Total
Operating
Hours or
Fuel Use
NA

Activity
Factor

Vented
Emissions
(tons CH4)

Combustion
Emissions
(tons CO2)

Fugitive
Emissions
(tons CH4)

NA

NA

112

NA

NA

116,000
gallons

NA

NA

1,300

NA

NA

288 hours

1

NA

negligible

NA

NA

288 hours

1

NA

NA

negligible

NA
NA
NA

288 hours
96 hours
24 hours

1
1
NA

48
NA
NA

6,912
28
6

NA
NA
NA

280

NA

NA

NA

3

NA

NA

NA

NA

48

8,361

negligible

35

ALL Consulting, 2011, Exhibit 19B.
Assumed no use of reduced emission completion (“REC”).
37
Assumed 25 gallons of diesel fuel used per hour with 100% oxidation of fuel carbon to CO2.
38
Assumed 20 gallons of diesel fuel used per hour with 100% oxidation of fuel carbon to CO2.
36

Page 8 of 15
Final SGEIS 2015, Page A19A-8

 Table GHG-10 – First-Year Well Production – Single Vertical Well GHG Emissions39
Single Vertical Well
Emissions
Source
Production
Equipment 10
Truckloads40
Wellhead
Compressor
Line Heater
Separator
Glycol
Dehydrator
Dehydrator Vents
Dehydrator
Pumps
Pneumatic
Device Vents
Meters/Piping
Vessel BD
Compressor BD
Compressor
Starts
Pressure Relief
Valves
Production Brine
Tanks
Production Brine
Removal
44Truckloads49
Total Emissions

Vehicle Miles Traveled
(VMT)

Total
Operating
Hours

Activity
Factor

Vented
Emissions
(tons CH4)

Combustion Emissions
(tons CO2)

Fugitive
Emissions
(tons CH4)

400

NA

NA

NA

1

NA

NA
NA
NA
NA

8,376 hours41
8,376 hours
8,376 hours
8,376 hours

1
1
1

NA
not determined
negligible
NA

NA
5,88342 (&443)
negligible
negligible

negligible
12344
negligible
negligible

NA

8,376 hours

1

negligible

negligible

negligible

NA

8,376 hours

1

22

45

3

46

negligible

47

NA

negligible

NA

8,376 hours

1

80

NA

8,376 hours

3

948

NA

negligible

NA
NA
NA

8,376 hours
4 hours
4 hours

1
4
4

NA
negligible
negligible

NA
NA
NA

negligible
negligible
negligible

NA

4 hours

4

negligible

NA

negligible

NA

4 hours

5

negligible

NA

negligible

NA

8,376 hours

1

negligible

NA

negligible

1,760

NA

NA

NA

3

NA

NA

NA

NA

111

5,894

123

39

First-Year production is the production period in the first year after drilling and completion activities have been concluded. Assumed production 10 mmcfd per well. However,

vertical well not likely to produce at assumed rate due to reduced completion interval.

40
Assumed roundtrip of 40 miles.

41
Calculated by subtracting total time required to drill and complete one vertical well (16 days) from 365 days.

42
Combustion emission, Emissions Factor (EF) of 1,404.716 lbs per hour.

43
Fugitive emission, Emissions Factor (EF) of 1.037 lbs per hour.

44
One compressor at Emissions Factor (EF) of 29.252 lbs per hour.

45
Emissions Factor (EF) of 12.725 lbs. per mmcf throughput.

46
Vented emission, Emissions Factor (EF) of 1.623 lbs per mmcf throughput.

47
Emissions Factor (EF) of 45.804 lbs. per mmcf throughput.

48
Emissions Factor (EF) of 0.664 lbs per hour.

49
Assumed roundtrip of 40 miles.


Page 9 of 15
Final SGEIS 2015, Page A19A-9

 Table GHG-11 – First-Year Well Production – Single Horizontal Well GHG Emissions50
Single Horizontal Well
Emissions
Source
Production
Equipment
10 Truckloads51
Wellhead
Compressor
Line Heater
Separator
Glycol
Dehydrator
Dehydrator Vents
Dehydrator
Pumps
Pneumatic
Device Vents
Meters/Piping
Vessel BD
Compressor BD
Compressor
Starts
Pressure Relief
Valves
Production Brine
Tanks
Production Brine
Removal
44Truckloads60
Total Emissions

Vehicle Miles Traveled
(VMT)

Total
Operating
Hours

Activity
Factor

Vented
Emissions
(tons CH4)

Combustion Emissions
(tons CO2)

Fugitive
Emissions
(tons CH4)

400

NA

NA

NA

1

NA

NA
NA
NA
NA

7,944 hours52
7,944 hours
7,944 hours
7,944 hours

1
1
1

NA
not determined
negligible
NA

NA
5,58053 (&454)
negligible
negligible

negligible
12255
negligible
negligible

NA

7,944 hours

1

negligible

negligible

negligible

NA

7,944 hours

1

21

56

3

57

negligible

58

NA

negligible

NA

7,944 hours

1

76

NA

7,944 hours

3

959

NA

negligible

NA
NA
NA

7,944 hours
4 hours
4 hours

1
4
4

NA
negligible
negligible

NA
NA
NA

negligible
negligible
negligible

NA

4 hours

4

negligible

NA

negligible

NA

4 hours

5

negligible

NA

negligible

NA

7,944 hours

1

negligible

NA

negligible

1,760

NA

NA

NA

3

NA

NA

NA

NA

106

5,591

122

50

First-Year production is the production period in the first year after drilling and completion activities have been concluded. Assumed production 10 mmcfd per well.

Assumed roundtrip of 40 miles.

52
Calculated by subtracting total time required to drill and complete one horizontal well (34 days) from 365 days.

53
Combustion emission, Emissions Factor (EF) of 1,404.716 lbs per hour.

54
Fugitive emission, Emissions Factor (EF) of 1.037 lbs per hour.

55
One compressor at Emissions Factor (EF) of 29.252 lbs per hour.

56
Emissions Factor (EF) of 12.725 lbs. per mmcf throughput.

57
Vented emission, Emissions Factor (EF) of 1.623 lbs per mmcf throughput.

58
Emissions Factor (EF) of 45.804 lbs. per mmcf throughput.

59
Emissions Factor (EF) of 0.664 lbs per hour.

60
Assumed roundtrip of 40 miles.

51

Page 10 of 15
Final SGEIS 2015, Page A19A-10

 Table GHG-12 – First-Year Well Production – Four-Well Pad GHG Emissions61
Four-Well Pad
Emissions
Source
Production
Equipment
10 Truckloads62
Wellhead
Compressor
Line Heater
Separator
Glycol
Dehydrator
Dehydrator Vents
Dehydrator
Pumps
Pneumatic
Device Vents
Meters/Piping
Vessel BD
Compressor BD
Compressor
Starts
Pressure Relief
Valves
Production Brine
Tanks
Production Brine
Removal 176
Truckloads71
Total Emissions

Vehicle Miles Traveled
(VMT)

Total
Operating
Hours

Activity
Factor

Vented
Emissions
(tons CH4)

Combustion Emissions
(tons CO2)

Fugitive
Emissions
(tons CH4)

1,600

NA

NA

NA

3

NA

NA
NA
NA
NA

5,496 hours63
5,496 hours
5,496 hours
5,496 hours

1
1
1

NA
not determined
negligible
NA

NA
3,86064 (&365)
negligible
negligible

negligible
8066
negligible
negligible

NA

5,496 hours

1

negligible

negligible

negligible

NA

5,496 hours

1

58

67
69

8

68

negligible

NA

5,496 hours

1

210

NA

negligible

NA

5,496 hours

3

670

NA

negligible

NA
NA
NA

5,496 hours
16 hours
16 hours

4
8
8

NA
negligible
negligible

NA
NA
NA

negligible
negligible
negligible

NA

16 hours

8

negligible

NA

negligible

NA

16 hours

10

negligible

NA

negligible

NA

5,496 hours

2

negligible

NA

negligible

7,040

NA

NA

NA

11

NA

NA

NA

NA

274

3,885

80

61

First-Year production is the production period in the first year after drilling and completion activities have been concluded. Assumed production 10 mmcfd per well.

Assumed roundtrip of 40 miles.

63
Calculated by subtracting total time required to drill and complete four horizontal wells (136 days) from 365 days.

64
Combustion emission, Emissions Factor (EF) of 1,404.716 lbs per hour.

65
Fugitive emission, Emissions Factor (EF) of 1.037 lbs per hour.

66
One compressor at Emissions Factor (EF) of 29.252 lbs per hour.

67
Emissions Factor (EF) of 12.725 lbs. per mmcf throughput.

68
Vented emission, Emissions Factor (EF) of 1.623 lbs per mmcf throughput.

69
Emissions Factor (EF) of 45.804 lbs. per mmcf throughput.

70
Emissions Factor (EF) of 0.664 lbs per hour.

71
Assumed roundtrip of 40 miles.

62

Page 11 of 15
Final SGEIS 2015, Page A19A-11

 Table GHG-13 – Post-First Year Annual Well Production – Single Vertical or Single Horizontal Well GHG Emissions72
Single Vertical Well or Single Horizontal Well
Emissions
Source

Vehicle Miles Traveled
(VMT)

Wellhead
Compressor
Line Heater
Separator
Glycol
Dehydrator
Dehydrator Vents
Dehydrator
Pumps
Pneumatic
Device Vents
Meters/Piping
Vessel BD
Compressor BD
Compressor
Starts
Pressure Relief
Valves
Production Brine
Tanks
Production Brine
Removal
50Truckloads81
Total Emissions

NA
NA
NA
NA

Total
Operating
Hours
8,760 hours73
8,760 hours
8,760 hours
8,760 hours

NA

8,760 hours

72

Activity
Factor
1
1
1
1

Vented
Emissions
(tons CH4)
NA
not determined
negligible
NA

NA
6,15374 (&575)
negligible
negligible

Fugitive
Emissions
(tons CH4)
negligible
12876
negligible
negligible

negligible

negligible

Combustion Emissions
(tons CO2)

negligible
77

3

78

negligible

NA

8,760 hours

1

23

NA

8,760 hours

1

8479

NA

negligible

NA

8,760 hours

3

980

NA

negligible

NA
NA
NA

8,760 hours
4 hours
4 hours

1
4
4

NA
negligible
negligible

NA
NA
NA

negligible
negligible
negligible

NA

4 hours

4

negligible

NA

negligible

NA

4 hours

5

negligible

NA

negligible

NA

8,760 hours

1

negligible

NA

negligible

2,000

NA

NA

NA

3

NA

NA

NA

NA

116

6,164

128

Assumed production 10 mmcfd per well.

73

Hours in 365 days.
74
Combustion emission, Emissions Factor (EF) of 1,404.716 lbs per hour.
75
Fugitive emission, Emissions Factor (EF) of 1.037 lbs per hour.
76
One compressor at Emissions Factor (EF) of 29.252 lbs per hour.
77
Emissions Factor (EF) of 12.725 lbs. per mmcf throughput.
78
Vented emission, Emissions Factor (EF) of 1.623 lbs per mmcf throughput.
79
Emissions Factor (EF) of 45.804 lbs. per mmcf throughput.
80
Emissions Factor (EF) of 0.664 lbs per hour.
81
Assumed roundtrip of 40 miles.

Page 12 of 15
Final SGEIS 2015, Page A19A-12

 Table GHG-14 – Post-First Year Annual Well Production – Four-Well Pad GHG Emissions82
Four-Well Pad
Emissions
Source

Vehicle Miles Traveled
(VMT)

Wellhead
Compressor
Line Heater
Separator
Glycol
Dehydrator
Dehydrator Vents
Dehydrator
Pumps
Pneumatic
Device Vents
Meters/Piping
Vessel BD
Compressor BD
Compressor
Starts
Pressure Relief
Valves
Production Brine
Tanks
Production Brine
Removal
200Truckloads91
Total Emissions

NA
NA
NA
NA

Total
Operating
Hours
8,760 hours83
8,760 hours
8,760 hours
8,760 hours

NA

8,760 hours

82

Activity
Factor
1
1
1
1

Vented
Emissions
(tons CH4)
NA
not determined
negligible
NA

NA
6,15384 (&585)
negligible
negligible

Fugitive
Emissions
(tons CH4)
negligible
12886
negligible
negligible

negligible

negligible

Combustion Emissions
(tons CO2)

negligible
87

88

NA

8,760 hours

1

93

12

negligible

NA

8,760 hours

1

33589

NA

negligible

NA

8,760 hours

3

990

NA

negligible

NA
NA
NA

8,760 hours
16 hours
16 hours

4
8
8

NA
negligible
negligible

NA
NA
NA

negligible
negligible
negligible

NA

16 hours

8

negligible

NA

negligible

NA

16 hours

10

negligible

NA

negligible

NA

8,760 hours

2

negligible

NA

negligible

8,000

NA

NA

NA

13

NA

NA

NA

NA

437

6,183

128

Assumed production 10 mmcfd per well.

83

Hours in 365 days.
84
Combustion emission, Emissions Factor (EF) of 1,404.716 lbs per hour.
85
Fugitive emission, Emissions Factor (EF) of 1.037 lbs per hour.
86
One compressor at Emissions Factor (EF) of 29.252 lbs per hour.
87
Emissions Factor (EF) of 12.725 lbs. per mmcf throughput.
88
Vented emission, Emissions Factor (EF) of 1.623 lbs per mmcf throughput.
89
Emissions Factor (EF) of 45.804 lbs. per mmcf throughput.
90
Emissions Factor (EF) of 0.664 lbs per hour.
91
Assumed roundtrip of 40 miles.

Page 13 of 15
Final SGEIS 2015, Page A19A-13

 Table GHG-15 – Estimated First-Year Green House Gas Emissions from Single Vertical Well
Single Vertical Well

Drilling Rig
Mobilization, Site
Preparation and
Demobilization
Completion Rig
Mobilization and
Demobilization
Well Drilling
Well Completion
including
Hydraulic
Fracturing and
Flowback
Well Production
Total

CO2 (tons)

CH4 (tons)

CH4 Expressed as
CO2e (tons)92

Total Emissions
from Proposed
Activity CO2e (tons)

447

NA

NA

447

432

NA

NA

432

83

negligible

negligible

83

1,804

12

300

2,104

5,894
8,660

234
246

5,850
6,150

11,744
14,810

Table GHG-16 – Estimated First-Year Green House Gas Emissions from Single Horizontal Well
Single Horizontal Well

Drilling Rig
Mobilization, Site
Preparation and
Demobilization
Completion Rig
Mobilization and
Demobilization
Well Drilling
Well Completion
including
Hydraulic
Fracturing and
Flowback
Well Production
Total

CO2 (tons)

CH4 (tons)

CH4 Expressed as
CO2e (tons)93

Total Emissions
from Proposed
Activity CO2e (tons)

447

NA

NA

447

432

NA

NA

432

194

negligible

negligible

194

2,097

12

300

2,397

5,591
8,761

228
240

5,700
6,000

11,291
14,761

Table GHG-17 – Estimated Post First-Year Annual Green House Gas Emissions from Single
Vertical Well or Single Horizontal Well
Single Vertical Well or Single Horizontal Well94

Well Production
92
93

CO2 (tons)

CH4 (tons)

CH4 Expressed as
CO2e (tons)95

6,164

244

6,100

Total Emissions
from Proposed
Activity CO2e
(tons)
12,264

Equals CH4 (tons) multiplied by 25 (100-Year GWP).
Equals CH4 (tons) multiplied by 25 (100-Year GWP).

94

Assumed production 10 mmcfd per well. However, vertical well not likely to produce at assumed rate due to reduced
completion interval, and therefore emission estimates are conservative for vertical well production.
95

Equals CH4 (tons) multiplied by 25 (100-Year GWP).

Page 14 of 15
Final SGEIS 2015, Page A19A-14

 Table GHG-18 – Estimated First-Year Green House Gas Emissions from Four-Well Pad
Four-Well Pad

Drilling Rig
Mobilization, Site
Preparation and
Demobilization
Completion Rig
Mobilization and
Demobilization
Well Drilling
Well Completion
including
Hydraulic
Fracturing and
Flowback
Well Production
Total

CO2 (tons)

CH4 (tons)

CH4 Expressed as
CO2e (tons)96

Total Emissions
from Proposed
Activity CO2e (tons)

447

NA

NA

447

432

NA

NA

432

776

negligible

negligible

776

8,361

48

1,200

9,561

3,885
13,901

354
402

8,850
10,050

12,735
23,951

Table GHG-19 – Estimated Post First-Year Annual Green House Gas Emissions from Four-Well
Pad
Four-Well Pad

Well Production

96
97

CO2 (tons)

CH4 (tons)

CH4 Expressed as
CO2e (tons)97

6,183

565

14,125

Equals CH4 (tons) multiplied by 25 (100-Year GWP).
Equals CH4 (tons) multiplied by 25 (100-Year GWP).

Page 15 of 15
Final SGEIS 2015, Page A19A-15

Total Emissions
from Proposed
Activity CO2e
(tons)
20,300

 This page intentionally left blank.

 

Part 

Sample Calculations for Combustion Emissions
from Mobile Sources

 

This page intentionally left blank.

Sample Calculation for Combustion Emissions (CO2) from Mobile Sources1

INPUT DATA: A fleet of heavy-duty (HD) diesel trucks travels 70,000 miles during the year. The trucks are equipped with advance control systems. 

CALCULATION METHODOLOGY: 

The fuel usage of the fleet is unknown, so the first step in the calculation is to convert from miles traveled to a volume of diesel fuel consumed basis. This 

calculation is performed using the default fuel economy factor of 7 miles/gallon for diesel heavy trucks provided API’s Table 4-10. 

70,000

݈݈݃ܽ‫݈ ݁ݏ݁݅݀݊݋‬
݈݈݃ܽ‫݀݁݉ݑݏ݊݋ܿ ݈݁ݏ݁݅݀ ݏ݊݋‬
݈݉݅݁‫ݏ‬
ൈ
ൌ 10,000
‫݁ݒ݋݉ ݐ݆ܿ݁݋ݎ݌‬
7 ݈݉݅݁‫ݏ‬
‫ݐ݆ܿ݁݋ݎ݌‬

Carbon dioxide emissions are estimated using a fuel-based factor provided in API’s Table 4-1. This factor is provided on a heat basis, so the fuel consumption
must be converted to an energy input basis. This conversion is carried out using a recommended diesel heating value of 5.75×106 Btu/bbl (HHV), given in Table
3-5 of this document. Thus, the fuel heat rate is:
ܾܾ݈
5.75 ‫ ݔ‬10଺ ‫ݑݐܤ‬
‫ݑݐܤ‬
݈݈݃ܽ‫ݏ݊݋‬
ൈ
ൈ
ൌ 1,369,047,619
ሺ‫ܸܪܪ‬ሻ
10,000

ܾܾ݈
‫݁ݒ݋݉ ݐ݆ܿ݁݋ݎ݌‬
‫ ݁ݒ݋݉ ݐ݆ܿ݁݋ݎ݌‬42 ݈݈݃ܽ‫ݏ݊݋‬
According to API’s Table 4-1, the fuel basis CO2 emission factor for diesel fuel (diesel oil) is 0.0742 tonne CO2/106 Btu (HHV basis).
Therefore, CO2 emissions are calculated as follows, assuming 100% oxidation of fuel carbon to CO2:
‫ݑݐܤ‬
‫ܱܥݏ݁݊݊݋ݐ‬2
‫ܱܥ݁݊݊݋ݐ‬2
1,369,047,619

‫ ݑݐܤ‬ൌ 101.78
ൈ 0.0742
଺
‫݁ݒ݋݉ ݐ݆ܿ݁݋ݎ݌‬
‫݁ݒ݋݉ ݐ݆ܿ݁݋ݎ݌‬
10
To convert tonnes to US short tons:
101.78 ‫ ݏ݁݊݊݋ݐ‬ൈ 2204.62

1

݈ܾ‫ݏ‬
݈ܾ‫ݏ‬
‫ܱܥ‬2
ൊ 2000
ൌ 112.19 ‫ݏ݊݋ݐ‬
‫݁݊݊݋ݐ‬
‫݊݋ݐ ݐݎ݋݄ݏ‬
‫݁ݒ݋݉ ݐ݆ܿ݁݋ݎ݌‬

American Petroleum Institute (API). Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry, Washington DC, 2004; amended 2005. pp. 4-39, 4-40.

Final SGEIS 2015, Page A19B-1

 This page intentionally left blank.

Appendix 20
PROPOSED
Pre-Frac Checklist and Certification
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

PRE-FRAC CHECKLIST AND CERTIFICATION

Well Name and Number:
(as shown on the Department-issued well permit)
API Number:
Well Owner:
Planned Frac Commencement Date:
Yes


No


Well drilled, cased and cemented in accordance with well permit, or in accordance with
revisions approved by the Regional Mineral Resources Manager on the dates listed below and
revised wellbore schematic filed in regional Mineral Resources office.
Approval Date & Brief Description of Approved Revision(s)
(attach additional sheets if necessary)





All depths where fresh water, brine, oil and/or gas were encountered or circulation was lost
during drilling operations are recorded on the attached sheet. Additional sheets are attached
which describe how any lost circulation zones were addressed.





Enclosed radial cement bond evaluation log and narrative analysis of such, or other
Department-approved evaluation, and consideration of appropriate supporting data per Section
6.4 “Other Testing and Information” of American Petroleum Institute (API) Guidance
Document HF1 (First Edition, October 2009) verifies top of cement and effective cement bond
at least 500 feet above the top of the formation to be fractured or at least 300 feet into the
previous casing string. If intermediate casing was not installed, or if was not production
casing was not cemented to surface, then provide the date of approval by the Department and a
brief description of justification.
Approval Date & Brief Description of Justification
(attach additional sheets if necessary)





Per Section 7.1 “General” under the heading “Well Construction Guidelines” of American
Petroleum Institute (API) Guidance Document HF1 (First Edition, October 2009), a
representative blend of the cement used for the production casing was bench tested in
accordance with API 10A Specification for Cements and Materials for Well Cementing
(Twenty-Fourth Edition, December 2010) and was found to be of sufficient strength to
withstand the maximum anticipated treatment pressure during hydraulic fracturing operations.





If fracturing operations will be performed down casing, then the pre-fracturing pressure tests
required by permit conditions will be conducted and fracturing operations will only commence
if the tests are successful. Any unsuccessful test will be reported to the Department and
remedial measures will be proposed by the operator and must be approved by the Department
prior to further operations.





All other information collected while drilling, listed below, verifies that all observed gas zones
are isolated by casing and cement and that the well is properly constructed and suitable for
high-volume hydraulic fracturing.

Final SGEIS 2015, Page A20-1

 PRE-FRAC CHECKLIST AND CERTIFICATION

Date and Brief Description of Information Collected
(attach additional sheets if necessary)




Fracturing products used will be the same products identified in the well permit application
materials or otherwise identified and approved by the Department.

I hereby affirm under penalty of perjury that information provided on this form is true to the best of
my knowledge and belief. False statements made herein are punishable as a Class A misdemeanor
pursuant to Section 210.45 of the Penal Law.
Printed or Typed Name and Title of Authorized Representative
Signature, Date

INSTRUCTIONS FOR PRE-FRAC CHECKLIST AND CERTIFICATION
The completed and signed form, and treatment plan must be received by the appropriate Regional
office at least 3 days prior to the commencement of hydraulic fracturing operations. The treatment
plan must include a profile showing anticipated pressures and volume of fluid for pumping the first
stage. It must also include a description of the planned treatment interval for the well (i.e., top and
bottom of perforations expressed in both True Vertical Depth (TVD) and True Measured Depth
(TMD)). The operator may conduct hydraulic fracturing operations provided 1) all items on the
checklist are affirmed by a response of “Yes,” 2) the Pre-Frac Checklist And Certification, and
treatment plan are received by the Department at least 3 days prior to hydraulic fracturing and 3) all
other pre-frac notification requirements are met as specified elsewhere. The well owner is prohibited
from conducting hydraulic fracturing operations on the well without additional Department
review and approval if a response of “No” is provided to any of the items in the pre-frac
checklist.
SIGNATURE SECTION
Signature Section - The person signing the Pre-Frac Checklist And Certification must be authorized
to do so on the Organizational Report on file with the Division of Mineral Resources.

Final SGEIS 2015, Page A20-2

 Appendix 21
Publicly Owned Treatment Works (POTWs)
With Approved Pretreatment Programs
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Pretreatment Facilities and Associated WWTPs

Region

Pretreatment Program

Facility

SPDES Number

1

Nassau County DPW - this facility
is tracked under Cedar Creek in
PCS.

Inwood STP
Bay Park STP
***Cedar Creek WPCP

NY0026441
NY0026450
NY0026859

Glen Cove (C)

Glen Cove STP

NY0026620

Suffolk DPW

Suffolk Co. SD #3 - Southwest

NY0104809

2

New York City DEP

Wards Island WPCP
Owls Head WPCP
Newtown Creek WPCP
Jamaica WPCP
North River WPCP
26th Ward WPCP
Coney Island WPCP
Red Hook WPCP
Tallman Island WPCP
Bowery Bay WPCP
Rockaway WPCP
Oakwood Beach WPCP
Port Richmond WPCP
Hunts Point WPCP

NY0026131
NY0026166
NY0026204
NY0026115
NY0026247
NY0026212
NY0026182
NY0027073
NY0026239
NY0026158
NY0026221
NY0026174
NY0026107
NY0026191

3

Suffern (V)

Suffern

NY0022748

Orangetown SD #2

NY0026051

Orange County SD #1

Harriman STP

NY0027901

Newburgh (C)

Newburgh WPCF

NY0026310

Westchester County

Blind Brook
Mamaroneck
New Rochelle
Ossining
Port Chester
Peekskill
Yonkers Joint

NY0026719
NY0026701
NY0026697
NY0108324
NY0026786
NY0100803
NY0026689

Rockland County SD #1

4

5

NY0031895

Poughkeepsie (C)

Poughkeepsie STP

NY0026255

New Windsor (T)

New Windsor STP

NY0022446

Beacon (C)

Beacon STP

NY0025976

Haverstraw Joint Regional Sewer
Board

Haverstraw Joint Regional Stp

NY0028533

Kingston (C)

Kingston (C) WWTF

NY0029351

Amsterdam (C)

Amsterdam STP

NY0020290

Albany County

North WWTF
South WWTF

NY0026875
NY0026867

Schenectady (C)

Schenectady WPCP

NY0020516

Rennselaer County SD #1

Rennselaer County SD #1

NY0087971

Plattsburgh (C)

City of Plattsburgh WPCP

NY0026018

Glens Falls (C)

Glens Fall (C)

NY0029050

Gloversville-Johnstown Joint
Board

NY0026042

Saratoga County SD #1

NY0028240

Final SGEIS 2015, Page A21-1

 Region

Pretreatment Program

Facility

SPDES Number

6

Little Falls (C)

Little Falls WWTP

NY0022403

Herkimer County

Herkimer County SD

NY0036528

Rome (C)

Rome WPCF

NY0030864

Ogdensburg (C)

City of Ogdensburg WWTP

NY0029831

7

Oneida County

NY0025780

Watertown

NY0025984

Auburn (C)

Auburn STP

Fulton (C)

8

NY0026301

Oswego (C)

Westside Wastewater Facility
Eastside Wastewater Facility

NY0029106
NY0029114

Cortland (C)

LeRoy R. Summerson WTF

NY0027561

Endicott (V)

Endicott WWTF

NY0027669

Ithaca (C)

NY0026638

Binghamton-Johnson City

NY0024414

Onondaga County

Metropolitan Syracuse
Baldwinsville/Seneca Knolls
Meadowbrook/Limestone
Oak Orchard
Wetzel Road

NY0027081
NY0030571
NY0027723
NY0030317
NY0027618

Canandaigua (C)

Canandaigua STP

NY0025968

Webster (T)

Walter W. Bradley WPCP

NY0021610

Monroe County

Frank E VanLare STP
Northwest Quadrant STP

NY0028339
NY0028231

Batavia (C)
Geneva (C)

NY0026514
Marsh Creek STP

Newark (V)

9

NY0021903

NY0027049
NY0029475

Chemung County

Chemung County SD #1
Chemung County - Elmira
Chemung County - Baker Road

NY0036986
NY0035742
NY0246948

Middleport (V)

Middleport (V) STP

NY0022331

North Tonawanda (C)

NY0026280

Newfane STP (T)

NY0027774

Erie County Southtowns

Erie County Southtowns
Erie County SD #2 - Big Sister

NY0095401
NY0022543

Niagara County

Niagara County SD #1

NY0027979

Blasdell (V)

Blasdell

NY0020681

Buffalo Sewer Authority

Buffalo (C)

NY0028410

Amherst SD (T)

NY0025950

Niagara Falls (C)

NY0026336

Tonawanda (T)

Tonawanda (T) SD #2 WWTP

NY0026395

Lockport (C)

NY0027057

Olean STP (C)

NY0027162

Jamestown STP (C)

NY0027570

Dunkirk STP (C)

NY0027961

Final SGEIS 2015, Page A21-2

 Mini-Pretreatment Facilities

Region
3
3
3
4
4
4
4
4
4
4
4
4
4
4
7
7
7
7
7
7
7
7
7
7
7
8
8
8
8
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9

Facility
Arlington WWTP
Port Jervis STP
Wallkill (T) STP
Canajoharie (V) WWTP
Colonie (T) Mohawk View WPCP
East Greenbush (T) WWTP
Hoosick Falls (V) WWTP
Hudson (C) STP
Montgomery co SD#1 STP
Park Guilderland N.E. IND STP
Rotterdam (T) SD2 STP
Delhi (V) WWTP
Hobart (V) WWTP
Walton (V) WWTP
Canastota (V) WPCP
Cayuga Heights (V) WWTP
Moravia (V) WWTP
Norwich (C) WWTP
Oak Orchard STP
Oneida (C) STP
Owego (T) SD#1
Owego WPCP #2
Sherburne (V) WWTP
Waverly (V) WWTP
Wetzel Road WWTP
Avon (V) STP
Bath (V) WWTP
Bloomfield (V) WWTP
Clifton Springs (V) WWTP
Clyde (V) WWTP
Corning (C) WWTP
Dundee STP
Erwin (T) WWTP
Holley (V) WPCP
Honeoye Falls (V) WWTP
Hornell (C) WPCP
Marion STP
Ontario (T) STP
Seneca Falls (V) WWTP
Walworth SD #1
Akron (V) WWTP
Arcade (V) WWTP
Attica (V) WWTP
East Aurora (V) STP
Gowanda (V)

Final SGEIS 2015, Page A21-3

SPDES Number
NY0026271
NY0026522
NY0024422
NY0023485
NY0027758
NY0026034
NY0024821
NY0022039
NY0107565
NY0022217
NY0020141
NY0020265
NY0029254
NY0027154
NY0029807
NY0020958
NY0022756
NY0021423
NY0030317
NY0026956
NY0022730
NY0025798
NY0021466
NY0031089
NY0027618
NY0024449
NY0021431
NY0024007
NY0020311
NY0023965
NY0025721
NY0025445
NY0023906
NY0023256
NY0025259
NY0023647
NY0031569
NY0027171
NY0033308
NY0025704
NY0031003
NY0026948
NY0021849
NY0028436
NY0032093

 This page intentionally left blank.

Appendix 22
POTW Procedures for Accepting HighVolume Hydraulic Fracturing Wastewater
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

POTW Procedures for Accepting High-Volume Hydraulic Fracturing Wastewater

The following procedure shall be followed when a Publically Owned Treatment Works (POTW)
proposes to accept high-volume hydraulic fracturing wastewater from a well driller or other
development company. Page 5 of this appendix shows a simplified flowchart of this process.
Please note that this disposal option is limited to the extent that municipal POTWs which utilize
biological wastewater treatment are generally optimized for the removal of domestic wastewater
and as such are not designed to treat several of the contaminants present in high-volume
hydraulic fracturing wastewater. In addition to the above concerns, the additional monitoring
and laboratory costs which will result from additional monitoring conditions in the permit must
also be considered prior to deciding to accept this source of wastewater.

1. The POTW operator receives a request to accept flowback water from a well driller.
Prior to submitting this request to the Department for approval, the POTW should review
the request to assure that it includes, at a minimum:
a. The volume of water to be sent to wastewater treatment plant in gallons per unit
time (e.g. 25,000 gallons per day);
b. Whether the discharge is a one-time disposal, or will be an ongoing source of
wastewater to the POTW;
c. A characterization of high-volume hydraulic fracturing wastewater quality
including all high-volume hydraulic facturing parameters of concern and NORM
analysis;
d. A characterization of existing POTW wastewater quality including:
i. Sample results for all high-volume hydraulic fracturing parameters of
concern, and
ii. the results of short term high intensity monitoring for both TDS (in mg/l)
and Radium 226 (in piC/l), consisting of the results of ten (10) samples
each of existing influent, sludge, and effluent from the POTW.
e. The source of the wastewater (well name, well developer, Mineral Resources
permit number, and location(s) of the wells); and

Final SGEIS 2015, Page A22-1

 f. A list of all additives used in the hydraulic fracturing process at the source
well(s).

2. The POTW shall forward the above request to the Bureau of Water Permits, 625
Broadway, Albany NY 12233-3505 along with the following supporting information:
a. Documentation of existing EPA and Departmental approval of the facility’s
headworks analysis for the acceptance of high-volume hydraulic fracturing
wastewater; or a completed headworks analysis for the high-volume hydraulic
fracturing specific parameters of concern for Department and USEPA approval;
b. Demonstration of available POTW capacity to accept the proposed volume of
high-volume hydraulic fracturing wastewater; and
c. Confirmation that the facility has an approved USEPA pretreatment or
Department mini-pretreatment program as part of its SPDES permit.

3. The Division of Water will review the submitted information to determine whether the
high-volume hydraulic fracturing wastewater source has been adequately characterized.
If additional information is necessary, the Division of Water will request additional
sampling and source information from the POTW.

4. The Division of Water will review the facility’s SPDES permit to determine whether the
permit needs to be modified to include high-volume hydraulic fracturing specific
monitoring, limits, and reporting conditions.

5. Concurrently with 3. and 4. above, if a headworks analysis for the high-volume hydraulic
fracturing specific parameters of concern was submitted for approval, the Division of
Water will forward a copy of the headworks analysis to the USEPA Region 2 office for
its review and approval. The Division of Water and USEPA Region 2 will review the
facility’s headworks analysis to assure that the POTW is capable of accepting the
proposed volume and quantity of high-volume hydraulic fracturing wastewater

Final SGEIS 2015, Page A22-2

 6. The Department will send a determination regarding the request to the permittee
following the Division of Water and USEPA’s analysis of the request. If the request is
approved, the POTW may accept high-volume hydraulic fracturing wastewater from the
requested source at the specified maximum concentrations and requested discharge rate
following receipt of Departmental approval, which will include the following
components:
a. Approval of submitted headworks analysis by the Department and USEPA; and
b. SPDES permit modification with high-volume hydraulic fracturing specific
monitoring, limits, and reporting conditions, including;
i. Specification of the source and maximum discharge rate of the highvolume hydraulic fracturing wastewater to be accepted;
ii. Influent radium-226 and TDS limits;
iii. Effluent limits and/or monitoring for NORM, TDS, and other high-volume
hydraulic fracturing parameters of concern;
iv. Periodic confirmatory sampling of influent wastewater for high-volume
hydraulic fracturing parameters of concern to assure that the
characteristics of the influent wastewater have not changed substantially
from the characterization provided in the approval request;
v. periodic sludge sampling to assure that the concentration of radionuclides
in the sludge do not exceed 5 piC/g; and
vi. Any other monitoring conditions necessary to assure that the discharge
from the POTW does not cause or contribute to a violation of NYS water
quality standards.

7. If the Department does not approve the acceptance of flowback water, a written denial
will be sent to the permittee with the reason(s) for denial. These reasons could include,
but not be limited to: inadequate receiving water assimilative capacity, NORM
concentrations in excess of the applicable influent Radium-226 limit of 15- piC/l, influent
concentrations of any other parameters in excess of the levels acceptable in the approved
headworks analysis, or inadequate POTW capacity.

Final SGEIS 2015, Page A22-3

 8. Following approval and permit modification, the POTW must notify the Department
whenever:
a. The facility wishes to increase the quantity of high-volume hydraulic fracturing
wastewater accepted from this source;
b. The facility wishes to accept any volume of high-volume hydraulic fracturing
wastewater from a new or additional source;
c. The high-volume hydraulic fracturing wastewater contains NORM or TDS in
excess of the influent limits for these parameters; or
d. The facility has decided to stop accepting high-volume hydraulic fracturing
wastewater from one or more sources.
The notifications in a. – c. would be treated as a request for a new source of high-volume
hydraulic fracturing wastewater, and would be processed in accordance with Items 1-7 above.

Final SGEIS 2015, Page A22-4

 Flowchart for acceptance of High Volume Hydraulic Fracturing (HVHF) wastewater by
publicly owned treatment works (POTWs)

POTW operator
request to accept
flowback water
from a well driller

Approved
pretreatment or
mini-pretreatment
program?

NYSDEC DOW reviews

POTW's SPDES permit


No

Yes

Have EPA
and DOW approved
the facility's
headworks analysis for
acceptance of
flowback water?

NYSDEC reviews

representative

flowback water

qualityand quantity info


Has flowback
water been fully
characterized for
parameters of concern
and volume?

No

Yes
Flowback water
may not be accepted
by this POTW at this
time
Yes

Does flowback
water contain NORM or
TDS in excess of
influent trigger
concentrations?

Yes

No
No

DOW requests
additional sampling and
source information

Does
sampling
indicate that
flowback contains
NORM or TDS in
excess of trigger
conc?

Periodic
confirmatory
sampling of
influent
wastewater

Contingency
plan for
alternative
disposal of
flowback
water

No

Yes

No
Yes

Has SPDES
permit been modified to
include influent and effluent
limits and monitoring for
flowback water
parameters?

HVHF water from this source
may be accepted by this POTW at
the proposed rate

Yes

Does POTW have
available capacity?

Final SGEIS 2015, Page A22-5

No

 This page intentionally left blank.

Appendix 23
USEPA Natural Gas STAR Program
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

TO:  

Peter Briggs, New York State Department of Environmental Conservation,
Mineral Resources

FROM:  

Jerome Blackman, Natural Gas STAR International

DATE: 

September 1, 2009

RE:

 Natural Gas Star

This memo lists methane emission mitigation options applicable in exploration and production;
in reference to your inquiry. Natural Gas STAR Partners have reported a number of voluntary
activities to reduce exploration and production methane emissions, and major project types are
listed and summarized below and may help focus your research as you review the resources
available on the Natural Gas STAR website.
In addition to these practices and technologies is an article that lists the same and several more
cost effective options for producers to reduce methane emissions. Please refer to the link below.
Cost-Effective Methane Emissions Reductions for Small and Midsize Natural Gas Producers
www.epa.gov/gasstar/documents/CaseStudy.pdf
Reduced Emission Completions
Traditionally, “cleaning up” drilled wells, before connecting them to a production sales line,
involves producing the well to open pits or tankage where sand, cuttings, and reservoir fluids are
collected for disposal and the produced natural gas is vented to the atmosphere. Partners reported
using a “green completion” method in which tanks, separators, dehydrators are brought on site to
clean up the gas sufficiently for delivery to sales. The result is reducing completion emissions,
creating an immediate revenue stream, and less solid waste.
Partner Recommended Opportunity from the Natural Gas STAR website:
www.epa.gov/gasstar/documents/greencompletions.pdf
BP Experience Presentation with Reduced Emission Completions
www.epa.gov/gasstar/documents/workshops/2008-annual-conf/smith.pdf
Green Completion Presentation from a Tech-Transfer Workshop in 2005 at Houston, TX
www.epa.gov/gasstar/documents/workshops/houston-2005/green_c.pdf
Optimize Glycol Circulation and Install of Flash Tank Separators in Dehydrator
In dehydrators, as triethylene glycol (TEG) absorbs water, it also absorbs methane, other volatile
organic compounds (VOCs), and hazardous air pollutants (HAPs). When the TEG is regenerated
through heating, absorbed methane, VOCs, and HAPs are vented to the atmosphere with the
water, wasting gas and money. Many wells produce gas below the initial design capacity yet

Final SGEIS 2015, Page A23-1

 TEG circulation rates remain two or three times higher than necessary, resulting in little
improvement in gas moisture quality but much higher methane emissions and fuel use.
Optimizing circulation rates reduces methane emissions at negligible cost. Installing flash tank
separators on glycol dehydrators further reduces methane, VOC, and HAP emissions and saves
even more money. Flash tanks can recycle typically vented gas to the compressor suction and/or
used as a fuel for the TEG reboiler and compressor engine.
Lessons Learned Document from the Natural Gas STAR website:
www.epa.gov/gasstar/documents/ll_flashtanks3.pdf
Dehydrator Presentation from a 2008 Tech-Transfer Workshop in Charleston, WV:
www.epa.gov/gasstar/documents/workshops/2008-tech-transfer/charleston_dehydration.pdf
Replacing Glycol Dehydrators with Desiccant Dehydrators
Natural Gas STAR Partners have found that replacing glycol dehydrators with desiccant
dehydrators reduces methane, VOC, and HAP emissions by 99 percent and also reduces
operating and maintenance costs. In a desiccant dehydrator, wet gas passes through a drying bed
of desiccant tablets. The tablets pull moisture from the gas and gradually dissolve in the process.
Replacing a glycol dehydrator processing 1 million cubic feet per day (MMcfd) of gas with a
desiccant dehydrator can save up to $9,232 per year in fuel gas, vented gas, operation and
maintenance (O&M) costs, and reduce methane emissions by 444 thousand cubic feet (Mcf) per
year.
Lessons Learned Document from the Natural Gas STAR website:
www.epa.gov/gasstar/documents/ll_desde.pdf
Directed Inspection and Maintenance
A directed inspection and maintenance (DI&M) program is a proven, cost-effective way to
detect, measure, prioritize, and repair equipment leaks to reduce methane emissions. A DI&M
program begins with a baseline survey to identify and quantify leaks. Repairs that are costeffective to fix are then made to the leaking components. Subsequent surveys are based on data
from previous surveys, allowing operators to concentrate on the components that are most likely
to leak and are profitable to repair.
Lessons Learned Documents from the Natural Gas STAR website:
www.epa.gov/gasstar/documents/ll_dimgasproc.pdf
www.epa.gov/gasstar/documents/ll_dimcompstat.pdf
Partner Recommended Opportunity from the Natural Gas STAR website:
www.epa.gov/gasstar/documents/conductdimatremotefacilities.pdf
DI&M Presentation from a Tech-Transfer Workshop in 2008 at Midland, TX
www.epa.gov/gasstar/documents/workshops/2008-tech-transfer/midland4.ppt

Final SGEIS 2015, Page A23-2

 Appendix 24
Key Features of USEPA Natural Gas STAR
Program
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Key Features of USEPA Natural Gas STAR Program1
Complete information on the Natural Gas STAR Program is given in USEPA’s web site
(http://epa.gov/gasstar/index.html)
•  Participation in the program is voluntary.
•  Program outreach is provided through the web site, annual national two-day implementation
workshop, and sector– or activity – specific technology transfer workshops or webcasts, often
with a regional focus (approximately six to nine per year).
•  Companies agreeing to join (“Partners”) commit to evaluating Best Management Practices
(BMP) and implementing them when they are cost-effective for the company. In addition, “
…partners are encouraged to identify, implement, and report on other technologies and
practices to reduce methane emissions (referred to as Partner Reported Opportunities or
PROs ).”
•  Best Management Practices are a limited set of reduction measures identified at the initiation
of the program as widely applicable. PROs subsequently reported by partners have increased
the number of reduction measures.
•  The program provides calculation tools for estimating emissions reductions for BMPs and
PROs, based on the relevant features of the equipment and application.
•  Projected emissions reductions for some measures can be estimated accurately and simply;
for example, reductions from replacing high-bleed pneumatic devices with low-bleed devices
are a simple function of the known bleed rates of the respective devices, and the methane
content of the gas. For others, such as those involving inspection and maintenance to detect
and repair leaks, emissions reductions are difficult to anticipate because the number and
magnitude of leaks is initially unknown or poorly estimated.
•  Tools are also provided for estimating the economics of emission reduction measures, as a
function of factors such as gas value, capital costs, and operation and maintenance costs.
•  Technical feasibility is variable between measures and is often site- or application- specific.
For example, in the Gas STAR Lessons Learned for replacing high-bleed with low-bleed
pneumatic devices, it is estimated that “nearly all” high-bleed devices can feasibly be
replaced with low-bleed devices. Some specific exceptions are listed, including very large
valves requiring fast and/or precise response, commonly on large compressor discharge and
bypass controllers.
•  Partners report emissions reductions annually, but the individual partner reports are
confidential. Publicly reported data are aggregated nationally, but include total reductions by
sector and by emissions reduction measure.

1

New Mexico Environment Department, Oil and Gas Greenhouse Gas Emissions Reductions. December 2007, pp. 19-20.

Final SGEIS 2015, Page A24-1

 This page intentionally left blank.

Appendix 25
Reduced Emissions Completion (REC)
Executive Summary
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Reduced Emissions Completions – Executive Summary1
High prices and high demand for natural gas, have seen the natural gas production industry
move into development of the more technologically challenging unconventional gas reserves
such as tight sands, shale and coalbed methane. Completion of new wells and re-working
(workover) of existing wells in these tight formations typically involves hydraulic fracturing of
the reservoir to increase well productivity. Removing the water and excess proppant (generally
sand) during completion and well clean-up may result in significant releases of natural gas and
methane emissions to the atmosphere.
Conventional completion of wells (a process that cleans the well bore of stimulation fluids
and solids so that the gas has a free path from the reservoir) results in gas being either vented or
flared. Vented gas results in large amounts of methane, volatile organic compounds (VOCs),
and hazardous air pollutants (HAPs) emissions to the atmosphere while flared gas results in
carbon dioxide emissions.
Reduced emissions completion (REC) – also known as reduced flaring completion – is a
term used to describe an alternate practice that captures gas produced during well completions
and well workovers following hydraulic fracturing. Portable equipment is brought on site to
separate the gas from the solids and liquids so that the gas is suitable for injection into the sales
pipeline. Reduced emissions completions help to mitigate methane, VOC, and HAP emissions
during the well flowback phase and can eliminate or significantly reduce the need for flaring.
RECs have become a popular practice among Natural Gas STAR production partners. A
total of eight different partners have reported performing reduced emissions completions in their
operations. RECs have become a major source of methane emission reductions since 2000.
Between 2000 and 2005 emissions reductions from RECs have increased from 200 MMcf to
over 7,000 MMcf. This represents additional revenue from natural gas sales of over $65 million
in 2005 (assuming $7/Mcf gas prices).

Method for
Reducing Gas Loss

Volume of
Natural
Gas
Savings
(Mcf/yr)1

Value of
Natural Gas
Savings ($/yr)2

Additional
Savings ($/yr)3

Set-up
Costs
($/yr)

Equipment
Rental and
Labor Costs
($)

Other
Costs
($/yr)4

Payback
(Months)5

Reduced Emissions
Completion

270,000

1,890,000

197,500

15,000

212,500

129,500

3

1.
2.
3.
4.
5.

Based on an annual REC program of 25 completions per year
Assuming $7/Mcf gas
Savings from recovering condensate and gas compressed to lift fluids
Cost of gas used to fuel compressor and lift fluids
Time required to recover the entire annual cost of the program

1
Adapted from ICF Incorporated, LLC. Technical Assistance for the Draft Supplemental Generic EIS: Oil, Gas and Solution Mining
Regulatory Program. Well Permit Issuance for Horizontal Drilling and High-Volume Hydraulic Fracturing to Develop the Marcellus
Shale and Other Low Permeability Gas Reservoirs, Task 2 – Technical Analysis of Potential Impacts to Air, Agreement No. 9679,
August 2009. Appendix 2.1.

Final SGEIS 2015, Page A25-1

 This page intentionally left blank.

Appendix 26
Instructions for Using the
On-Line Searchable Database to
Locate Drilling Applications
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

How to Use the Online Searchable Database to Find Information about Recently 

Filed Permit Applications 

The online searchable database can be found at http://www.dec.ny.gov/cfmx/extapps/GasOil/. It is a very user
friendly program and can be used to conduct both simple and complex searches.

How to Conduct a Simple Search
1.   Select Wells Data to begin your search.

Search Database
•   General seardl TiPSJH elp
Se l User Pre-fe re nces

•   Company Data
Wells D.;.la

111C~!!!!!!!!!!!I

,   .Mnual Well Production
Well Transfers
•   Geologic Formation
Geologic f iElds

For mor e information :
Or,•lsi<m afl.loin'"r;;l Resources
Environmen! al Na~io;; Bulletin lor l.lineraJs

2.

Select your search criteria. Use the drop down arrow next to API Number to select your search criteria.

Build Search Here

3.   To find a new permit application, enter Permit Application Date is Greater Than or E qual to , and the
date that you would like to search from. Enter Permit Application Data is Greater Than or Equal to
Ill/year to find all permit applications filed during a specific year. Click the Submit button.

Bui1d Searc h Here
L
I P-'-ermit.:....:AP"-"
. .:....:....:.
P.::..:
Iic:..::.
a t::..::
io.:..c.n.::...
Date
::c:.:.....__

_,_""]
v   I Greater TI1an or Equal to v \\~....111!2_
_-'-009_ _ _ _ ____,

t
Final SGEIS 2015, Page A26-1

 4.   View results. By selecting the View Map hyperlink, a new window will open to Google Maps showing
the well location along with latitude and longitude information. The results from your query can be
saved to your computer as either an Excel spreadsheet (xls) or as a comma separated value file (csv) by
clicking the appropriate Export button at the bottom the results screen. Clicking a hyperlink in the
Company Name column will provide contact information for the company.

Wells Data Search
St:uc:b P~!trrs :(O.o S~<kJ
• Per~ ~i<:ation Date Greater Than or Equal to ·uo112009..

I

E>Jlortlll.S

II

E~pon CSV

- 1'

»r

l1003.2011li00Q-2
KIA

HIA

'""

2011£

.....

II/A

'""

2$3<!

VrewiJ•p iQ

3100l2534101)Q-1
V-!wii1CI L9

o•

RyanJ 1

$U90

111111;!!!!!!!!11

J..! 11:"'alft.!l

C.u !iii9FI)'

ec.,

0<!1

US fltr9y

£ut::m

Oe\ocbllr.:nl

••

II Last SO I

]I Nt)(! SO

c•.,

CallfeM!bs.l Cctdi:l~n.tl.!l CtmkaJ'I)'

C'011~.W

Ccnfldul~o~l

1100025342()1)()-1

U.~o-£1
0~'00~

r

Vlll:ns

Confll~l.u.l ~..,

Andonr \\'ttle-.nlk

1:.01

How to Narrow or Expand Your Search Utilizing the AND Button
1. Select Wells Data to begin your search.

Search Database
General Search TliiSJHelo
Set User Preferences.
• company o ata
Wells D.aia

wtl•~

C"onft::~"'!W ~~lUI)'

111111;1111•

Pnnual W(lll Pro dudlon

Well Transfers
G(!Oioglc Fo rmalion
Geologic Fielgs

For more information:
or.~sian of IA.iner~l Resources
Environmen!a l No(iO.O Bulletin lor l.linerals

Final SGEIS 2015, Page A26-2

C:.a n fe~~IW

S-:nltn

B

Co nflf~l~

 2.

Select your search criteria. To find all permit applications filed in 2009 that target a specific geologic
formation, select Permit Application Date is Greater Than or Equal to 1/l/2009. Click the AND button.

Build Search Here

I Submit IIfa.ND I

I,_P_e_rm_lt_Ap_,_,_pli_ca_ti_on_ Da
--'­te_ _--=:J
" l [Grealer TI1an or Equal to v 1\._1_11_12_00_9_ _ _ _ _ __.

tt
3.

Select your next set ofsearch criteria. To find all permit applications filed in 2009 for the Marcellus
formation, select Objective Formation equals Marcellus. Click the Submit button.

Wells Data Sea rch
S<o.."'th ""="""[C:o B~ci<l

•

Perm~

Application Date Greater Than or Equlll lo "61(0t/2009" AND

General s~uch Tip:s!H~ Ip

Build search Here

IObjee'lo-e Foomalloo

4.

View Results.

Scntt.b PMi1meten ::(Go n~cl:)

• Parmlt .AppllcalioA O~to 13roate<Than or Equal to ""1)1(() 112009· ANO
• Objeeti\oe Form~tion \'flV~J I~ "'t.tprcellus·

l

EJ<po~ XLS

II

~rl iCSV

Crtt~e~~~~~

31007263900000

tu.tt.

Vr w

IVA

21139D

K.>Jt IH

tc"l>c~is

1:1

AR

IJ.arcelti.s llot

Ill

AR

lla rcci\Ja

1:1.

AR

ll__,Tc::fus

M pbet!f"

LLC

Chc-....,.~~.e

3100116l91CiODD
tuA

V fi'J•'J

IVA

Ve..., 1lo\P ~

~·

~11t2H

26-19"2

K..Jt~H

~18iocl11>

LLC

Ch...,eof.:

tuA

V "r:w

lilA

~;:~abchU

LLC

IICI(
Appl""~

ll6t
Appk'.a.bl!

Broomr

f'enta.11

Broci'TMI

Fenleft

Broome

f enllll111

Final SGEIS 2015, Page A26-3

uew ne\5 ei2SI2009 6129·'2CO

ChEM~OO

fork!

then.s.:~ga

Fon;o

~u~~~

forf.:s

Wkleat

F

F

UewFl(!l::l

Wl<l<.ll

tWt~F.e\5

\'lidC.Jt

~cc~

012>12110

~.12009

6/291200

 How to Narrow Your Search to Applications Submitted For a Specific County
1.

Select Wells Data to begin your search.

Search Database
GGn@l31Seardl TlpsJH lllll 

Set UserPreferences 


•   Cornp any D ata

Wells Daia 1111C~!!!!!!I
JiJ\nual W<!lll PfOCIUct!On
Well Transfers 

Geologic Fo rmalion 

Geologic Frelds 


For mor e i nformation :
Dr.~si<m orl.lineral Resources
Environmental No(iCE Bulletin lor f.linerals

2.

Select your search criteria. To find a ll permit applications filed in 2009 in a specific county, select Permit
Application Date is Greater Than or Equal to 1/1/2009. Click the AND bllltton.

Build Search 'H ere
[Permit Application Dale

3.

Select your next set ofsearch crite ria. To find all permits applied for in 2009 in Allegany County, select
County equals Allegany. Click the Su bmit button.

W ell s Data Search
~·web Por.nt~e<s1~• 816:)

• Permil ~ion Ovlo Grouler Thun ooEQUI! Io ·ol/0112009" ANiJ

Con"'o<l Se>~ch lopo,·nolp

Build Searc h Here

ICou<Oy

Final SGEIS 2015, Page A26-4

 Appendix 27
NYSDOH Radiation Survey Guidelines
and Sample Radioactive Materials
Handling License
Final
Supplemental Generic Environmental Impact Statement

www.dec.ny.gov

 This page intentionally left blank.

Radiological Survey Requirements
I. Instrumentation
Instrumentation utilized to determine exposure rates must be capable of measuring 1 microrem to at
least 3 millirem per hour.
A pressurized ionization detector/instrument is an optimal choice for gamma exposure rate
measurements because the displayed reading provides a true (accurate) exposure rate, therefore no
correction factor is necessary.
An instrument with a sodium iodide detector calibrated to cesium-137 (typical/standard calibration) has
a high sensitivity but may require the use of a correction factor to determine the true exposure rates
associated with the energy emissions from NORM isotopes. Provide a description of the
instrumentation including the make(s) and model number(s) of the instrument(s) and detector(s).
(Detector information is not needed for instruments that use a detector that is physically mounted
within the instrument body.) The instrument must be designed for exposure rate measurement of
gamma emissions with energies similar to NORM. Caution: radiological survey instruments may not
be safe for use in environments with combustible vapors - Consult the manufacturer.
II. General
Performance of daily (on days of use) operational check is recommended. This can be accomplished
by measuring a radiation source of known activity to confirm that instrument is properly functioning,
i.e., the reading is consistent from measurement to measurement.
Instruments must be used within the manufacturer's recommended operational conditions, i.e.
temperature, etc.
It is recommended that the user remove batteries from instruments during periods of non-use to avoid
potential damage from “leaking” batteries.
III. Survey Procedure
Confirm that the instrument is calibrated and functioning properly.
The background exposure rate should be measured in an area unaffected by elevated NORM prior to
measuring equipment (pipes, tanks, etc.). (Typical background readings are in the range of 3-15 uR/hr
but can vary.)
The orientation of the instrument is important. In general the face/front of the instrument should be
directed toward the surface being measured.
For instruments that have an audio function the switch should be in the on position. The audio feature
will assist the user in identifying elevated exposure rates.
The survey instruments or detector should be held close (within approximately 1 inch) to the surface of
the item being surveyed.
Final SGEIS 2015, Page A27-1

 The instrument reading should be taken after sufficient time is allowed for the reading to stabilize,
generally 10-20 seconds.
Surveys should be conducted systematically. In general, follow the gas production train. Equipment
that exceeds 50 uR/hour should be marked/tagged.
Maintain survey records for a period of 5 years. The records include the date, name of person who
conducted the survey, the background exposure rate (in an unaffected area), the survey instrument
description/make, model, serial number, calibration date, and a diagram or sketch of the areas surveyed
and the survey data.
IV. Survey Frequency
Radiological survey data must be conducted within 6 months following the start of gas production and
at intervals not to exceed 12 months thereafter.
The permit tee must conduct surveys of all equipment used on the production train prior to disposal,
recycling or transfer to any entity.
Equipment that exceeds 50microrem/hr is subject licensure by the New York State Department of
Health.
V. Survey data reports
Survey data must be submitted within 30 days following the survey, and must contain the information
required by Section III.

Final SGEIS 2015, Page A27-2

 NEW YORK STATE

DEPARTMENT OF HEALTH

BUREAU OF ENVIRONMENTAL RADIATION PROTECTION


Radiation Guide 1.15


GUIDE FOR APPLICATION TO

POSSESS NATURALLY OCCURRING RADIOACTIVE 

MATERIAL (NORM)

INCIDENT TO NATURAL GAS INDUSTRY


Final SGEIS 2015, Page A27-3

 I. INTRODUCTION
PURPOSE OF GUIDE
The purpose of this regulatory guide is to provide assistance to applicants in preparing applications for
new licenses for the possession of naturally occurring radioactive materials (NORM) incident to natural gas
exploration and production. This regulatory guide is intended to provide you, the applicant, with information that
will enable you to understand specific regulatory requirements and licensing policies as they apply to the license
activities proposed.
After you are issued a license, you must conduct your program in accordance with (1) the statements,
representations and procedures contained in your application; (2) the terms and conditions of the license; and (3)
the Department of Health's regulations in 10 NYCRR 16 and 12 NYCRR 38. The information you provide in
your application should be clear, specific and accurate.
II. FILING AN APPLICATION

You, as the applicant for a materials license, must complete Items 1 through 4 and 18 on the attached
application form. For other applicable Items, submit the information on supplementary pages. Each separate
sheet or document submitted with the application should be identified and keyed to the item number on the
application to which it refers. All typed pages, sketches, and, if possible, drawings should be on 8 ½ x 11 inch
paper to facilitate handling and review. If larger drawings are necessary, they should be folded to 8 ½ x
11inches. You should complete all items in the application in sufficient detail for the Department to determine
that your equipment, facilities, training and experience, and radiation safety program are adequate to protect
health and to minimize danger to life and property.
You must submit two copies of your application with attachments. Retain one copy of the application for
yourself, because the license will require that you possess and use licensed material in accordance with the
statements and representations in your application and in any supplements to it.
Mail your completed application and the required non-refundable triennial fee ($3000) to:
New York State Department of Health
Bureau of Environmental Radiation Protection
Flanigan Square, 547 River Street
Troy, New York 12180
Please Note: Applications received without fees will not be processed .

Final SGEIS 2015, Page A27-4

 III. CONTENTS OF AN APPLICATION


Item 1. Name and address.
Enter the name and corporate address of the applicant and the telephone
number of company management. The name of the firm must appear exactly as it appears on legal
papers authorizing the conduct of business. Indicate if the name and address are different from those
listed on the NYS Department of Environmental Conservation, Division of Mineral Resources
Permits to Drill.
Item 2A. Addresses at which radioactive material will be used.
List all addresses and locations where radioactive material will be used or
stored, i.e., the NYS Department of Environmental Conservation, Division of Mineral Resources
Permits to Drill Nos., well name, and town name.
2.B. Not applicable
Item 3. Nature of business
Enter the nature of the business the applicant is engaged in and the name and
telephone number (including area code) of the individual to be contacted in connection with this
application.
Item 4. Previous radioactive materials license
Enter any previous or current radioactive materials license numbers and
identify the issuing agency. Also indicate whether you possess any radioactive material under a
general license.
Describe the circumstances of any denial, revocation or suspension of a radioactive materials license
previously held.
Item 5. Department to Use Radioactive Material
Not Applicable
Item 6. Individual Users of Radioactive Materials
Not Applicable,
Item 7. Radiation Safety Officer
State the name, title and contact information (phone, fax, and e-mail) of the person designated by, and
responsible to, management for the coordination of the radiation safety program. This person will be
named on the license as the Radiation Safety Officer. He/she will be responsible to oversee and
ensure that licensed radioactive material is possessed in accordance with regulations and the
radioactive materials license.
Item 8. Radioactive Material
No response is required. The license will list Naturally Occurring Radioactive Material (NORM).

Final SGEIS 2015, Page A27-5

 Item 9. Purpose for which Radioactive Material Will be Used
No response is required. (The type of use will be specified on the license as
possession and maintenance of radiologically contaminated equipment, with specific limitations.)
Item 10. Training of individual users
Persons who perform radiological surveys that are required by regulation and
radioactive materials license must receive initial and annual radiation protection training. The scope
of training needs to be commensurate with their duties. Appendix A contains a model training
program. Confirm that you will follow the model or submit your proposed training program for
review.
Item 11. Experience with radioactive materials for individual users
No response is required. Implementation of a training program as required in
Item 10 of the application addresses Item 11 for the scope of license tasks.
Item 12. Instrumentation
Instrumentation utilized to determine exposure rates must be capable of measuring 1 microrem to at
least 3 millirem per hour.
A pressurized ionization detector/instrument is an optimal choice for gamma exposure rate
measurements because the displayed reading provides a true (accurate) exposure rate, therefore no
correction factor is necessary.
An instrument with a sodium iodide detector calibrated to cesium-137 (typical/standard calibration)
has a high sensitivity but may require the use of a correction factor to determine the true exposure
rates associated with the energy emissions from NORM isotopes. Provide a description of the
instrumentation including the make(s) and model number(s) of the instrument(s) and detector(s).
(Detector information is not needed for instruments that use a detector that is physically mounted
within the instrument body.) The instrument must be designed for exposure rate measurement of
gamma emissions with energies similar to NORM. Caution: radiological survey instruments may not
be safe for use in environments with combustible vapors - Consult the manufacturer.
A model procedure for conducting a radiological survey is provided in Appendix C.
Item 13. Calibration and operational checks of instrumentation
Instrument calibrations must be performed before first use of the instrument and at intervals not to
exceed 12 months by an entity that is licensed by the US Nuclear Regulatory Commission or an
Agreement State to perform radiological survey instrument calibrations. The instrument must be
checked for proper operation (minimally a battery condition check must be performed, and a response
to a radiation source is recommended) on each day of use. Records of instrument calibrations must
be maintained for a period of 5 years for review by the Department. Confirm that calibrations and
daily battery checks will be performed as indicated above and that instrument calibration records will
be maintained.

Final SGEIS 2015, Page A27-6

 Item 14. Personnel monitoring and bioassays
Not applicable.
Item 15. Facilities and Equipment
Submit simple sketches of any storage area(s), pipe yards, etc., for contaminated equipment.
Item 16. Radiation Protection Program
The applicant does not need to establish a comprehensive radiation safety
program. However, the applicant needs to implement a radiation protection program that is
commensurate with the type of radioactive material authorized by the license. Appendix B contains a
model radiation protection program. Please confirm that you will implement the model program or
submit your proposed program for review.
Item 17. Waste Disposal
The applicant must plan for proper disposal of radiologically contaminated
equipment when their use has been discontinued. Confirm that you will dispose of radiologically
contaminated items in accordance with all applicable state and federal requirements.
Item 18. Certification
Provide the signature of the chief executive officer of the corporation or legal
entity applying for the license or of an individual authorized by management to sign official
documents and to certify that all information in this application is accurate to the best of the signator's
knowledge and belief.

IV. AMENDMENTS TO LICENSES
Licensees are required to conduct their programs in accordance with statements, representations and
procedures contained in the license application and supporting documents. The license must therefore be
amended if the licensee plans to make any changes in the facilities, equipment, procedures, and authorized
users or radiation safety officer, or the radioactive material to be used.
Applications for license amendments may be filed either on the application form or in letter form. The
application should identify the license by number and should clearly describe the exact nature of the changes,
additions, or deletions. References to previously submitted information and documents should be clear and
specific and should identify the pertinent information by date, page and paragraph.

Final SGEIS 2015, Page A27-7

 APPENDIX A Training Program for Individuals Performing Radiological Survey Measurements.
The applicant/licensee may use the services of a health physicist, licensed medical physicist or an individual
who is authorized by a radioactive materials license to conduct radiological surveys. In these situations, the
applicant/licensee needs to obtain documentation that the individual is qualified. Examples of
documentation include a radioactive materials license that names the person as an authorized user, or copy of
a resume for the health physicist or licensed medical physicist. Records of training must be maintained for a
period of 5 years.

However, if the applicant/licensee plans to use his/her staff to conduct surveys, such individuals must receive
training.
Individuals must demonstrate competence in the following subjects that prior to being approved to perform
required surveys. Training must be conducted by an individual who is knowledgeable in health physics
principles and procedures.
I. Fundamentals of Radiation Safety
A. Characteristics of radiation
B. Units of radiation dose and quantity of radioactivity
C. Levels of radiation from sources of radiation
D. Methods of minimizing radiation dose:
1. working time
2. working distance
3. shielding
II. Radiation Detection Instruments
A. Use of radiation survey instruments
1. operational
2. calibration
B. Survey techniques
III. Requirements of the regulations and License Conditions
IV. Records of training will be maintained for a period of 5 years. Records will include the date of training,
name of persons trained, name of the trainer and his/her employer, a copy of the training agenda or topics
covered, and the results of any test or determination of proficiency. Records will be maintained for review
by the Department.

Final SGEIS 2015, Page A27-8

 APPENDIX B

Radiation Protection Program

I. Responsibility
A. The owner/licensee will delegate authority to the Radiation Safety Officer to implement the
program and the responsibility to oversee the day to day oversight of the program
B. Ensure that individuals receive initial and annual radiation protection training.
C. Ensure that radiological surveys are performed in an effective manner and at the time intervals
required by the License.
D. Ensure that notifications required by regulations and License Conditions are made.
E. Ensure that an inventory of radiologically contaminated equipment is maintained.
F. Ensure that contaminated equipment in storage is labeled as containing radioactive material and is
not released for unrestricted use.
G. Ensure that radioactive waste is disposed in accordance with all applicable state and federal
requirements.
H. Ensure that only entities that have a specific license to perform decontamination perform service
of equipment that exceeds 50 microrem at any accessible surface.
II. Maintain Records of:
A. Radiation Protection Training Program
B. Results of radiological surveys including instrumentation calibrations and operational checks.
C. Inventories of contaminated equipment
D. Waste disposal records
E. Service of contaminated equipment that exceeds 50 microrem at any accessible surface, including
documentation of the service provider's radioactive materials license.
F. Radiological survey data
G. Maintain a complete radioactive materials license

Final SGEIS 2015, Page A27-9

 APPENDIX C
Radiological Survey Guidance
I. General
Performance of daily (on days of use) operational check is recommended. This can be accomplished by
measuring a radiation source of known activity to confirm that instrument is properly functioning, i.e., the
reading is consistent from measurement to measurement.
Instruments must be used within the manufacturer's recommended operational conditions, i.e. temperature,
etc.
It is recommended that the user remove batteries from instruments during periods of non-use to avoid
potential damage from “leaking” batteries.
II Survey Procedure
Confirm that the instrument is calibrated and functioning properly.
The background exposure rate should be measured in an area unaffected by elevated NORM prior to
measuring equipment (pipes, tanks, etc.). (Typical background readings are in the range of 3-15 uR/hr but
can vary.)
The orientation of the instrument is important. In general the face/front of the instrument should be directed
toward the surface being measured.
For instruments that have an audio function the switch should be in the on position. The audio feature will
assist the user in identifying elevated exposure rates.
The survey instruments or detector should be held close (within approximately 1 inch) to the surface of the
item being surveyed.
The instrument reading should be taken after sufficient time is allowed for the reading to stabilize, generally
10-20 seconds.
Surveys should be conducted systematically. In general, follow the gas production train. Equipment that
exceeds 50 uR/hour should be marked/tagged.
Maintain survey records for a period of 5 years. The records include the date, name of person who
conducted the survey, the background exposure rate (in an unaffected area), the survey instrument
description/make, model, serial number, calibration date, and a diagram or sketch of the areas surveyed and
the survey data.

Final SGEIS 2015, Page A27-10

 NEW YORK STATE DEPARTMENT OF HEALTH

RADIOACTIVE MATERIALS LICENSE


Pursuant to the Public Health Law and Part 16 of the New York State Sanitary Code,
and in reliance on statements and representations heretofore made by the licensee designated below,
a license is hereby issued authorizing radioactive material(s) for the purpose(s), and at the place(s)
designated below. The license is subject to all applicable rules, regulations, and orders now or hereafter
in effect of all appropriate regulatory agencies and to any conditions specified below.

1.  

Name

3.

License Number

4.

a.

Effective Date
_______________

b. 

Expiration Date

_______________________
2.  

Address
_______________________
_______________________

Attention:
Radiation Safety Officer

_______________
5.  

Reference Number
DH No. _____

6. 

Radioactive Materials
(element & mass no.) 

7.

Chemical and/or
Physical Form

8.

Maximum quantity
licensee may possess
at one time

A. 

Radium 226

A.

Any

A.

As necessary

B. 

Naturally Occurring
Radioactive Material 

(NORM)


B.

Any

B.

As necessary


9.   Authorized use. The authorized locations of use are those specified in New York State Department
of Environmental Conservation Permit to Drill Nos. __________.
A.  The licensee is authorized for possession only of NORM listed in License Condition No. 6 as
contamination in equipment incidental to oil and gas exploration and production.
B. 

The licensee may perform maintenance, not inculding decontamination or removal of scale
containing radioactive material on equipment that does not exceed 50 microrem per hour at any
accessible point.Only a licensee authorized by the US Nuclear Regulatory Commission or an

Doc:BOIL\Oil and Gas 

10/2009
Final SGEIS 2015, Page A27-11

 NEW YORK STATE DEPARTMENT OF HEALTH

RADIOACTIVE MATERIALS LICENSE

Agreement State to perform decontamination and decommissioning services shall service
equipment that exceeds 50 microrem per hour at any accessible point.
10.  

A.

Radioactive material listed in Item 6 shall be used by, or under the supervision of the
Radiation Safety Officer.
B.

C. 

11.  

The licensee shall notify the Department by letter within 30 days if the Radiation Safety
Officer permanently discontinues performance of duties under the license.

Except as specifically provided otherwise by this license, the licensee shall possess and use
licensed material described in Items 6, 7 and 8 of this license, in accordance with statements,
representations, and procedures contained in the documents (including any enclosures) listed
below:
A. Application for New York State Department of Health Radioactive Materials License dated
___________, signed by ___________.
B. Letter dated ___________, signed by _____________.
The New York State Department of Health’s regulations shall govern the licensee’s
statements in applications or letters unless the statements are more restrictive than the
regulations.

12.

A. 

Transportation of licensed radioactive material shall be subject to all regulations of the
U.S. Department of Transportation and other agencies of the United States having
jurisdiction insofar as such regulations relate to the packaging of radioactive material,
marking and labeling of the packages, loading and storage of packages, monitoring
requirements, accident reporting, and shipping papers.

B. 

Transportation of low level radioactive waste shall be in accordance with the regulations
of the New York State Department of Environmental Conservation as contained in
6 NYCRR Part 381.

13.  

The licensee shall have available appropriate survey instruments which shall be maintained
operational and shall be calibrated before initial use and at subsequent intervals not exceeding
twelve months by a person specifically authorized by the U.S. Nuclear Regulatory Commission
or an Agreement State to perform such services. Records of all calibrations shall be kept a
minimum of five years.

14,  

The licensee shall conduct gamma exposure rate measurements of accessable areas of gas
production equipment within 6 months of the effective date of the license and at subsequent

Doc:BOIL\Oil and Gas 

10/2009
Final SGEIS 2015, Page A27-12

 NEW YORK STATE DEPARTMENT OF HEALTH

RADIOACTIVE MATERIALS LICENSE

intervals not to exceed 12 months. The licensee shall maintain measurement records for review
by the Department. The licensee shall notify the Department within 7 calendar days following
identification of any exposure rate measurement that meet or exceed 2 millirem per hour.
Notification may be made by phone or in writing.
15.  

Equipment in storage that exceeds 50 microrem per hour at any accessible point shall be labeled
by means of paint or durable label or tag.

16.  

The licensee shall maintain an inventory of equipment, including but not limited to tubular
goods, piping, vessels, wellheads, separators, etc., that exceeds 50 microrem per hour at any
accessible point. The records of the inventories shall be maintained for inspection by the
Department, and shall include the location and description of the items, and the date that items
were entered on the inventory record.

17.  

A.

Before treatment or disposal of any gas production water in a manner that could result in
discharge or release to the environment, the licensee shall obtain from the New York
State Department of Environmental Conservation either:
i) A valid permit, or
ii) A letter stating that no permit is required.

B. 

The licensee shall maintain the letter or valid permit required in paragraph A of this
condition on file for the duration of the license and make such letter or permit available
for inspection by the Department upon request.

18.  

The licensee shall submit complete decontamination procedures to the Department for approval
ninety (90) days prior to the termination of operations involving radioactive materials.

19.  

Plans of facilities which the licensee intends to dedicate to operations involving the use of
radioactive material shall be submitted to the Department for review and approval prior to any
such use.

20.  

The licensee shall maintain records of information important to safe and effective
decommissioning at the location listed in License Condition No. 2 and at other locations as the
licensee chooses. The records shall be maintained until this license is terminated by the
Department and shall include:
A. Records of spills or other unusual occurrences involving the spread of contamination
in and around the facility, equipment, or site;
B. As-built drawings and modifications of structures and equipment in restricted areas
where radioactive materials are used and/or stored, and locations of possible inaccessible
contamination, such as buried pipes, which may be subject to contamination;

Doc:BOIL\Oil and Gas 

10/2009
Final SGEIS 2015, Page A27-13

 NEW YORK STATE DEPARTMENT OF HEALTH

RADIOACTIVE MATERIALS LICENSE

C. Records of the cost estimate performed for the decommissioning funding plan or the
amount certified for decommissioning, and records of the funding method used for
assuring funds if either a funding plan or certification is used.

21.  

The licensee may transfer contaminated equipment that exceeds 50 microrem at any accessible
point to a Department licensee if the equipment is to be used in the oil and gas industry. The
licensee shall maintain records of each transfer of equipment authorized by this License
Condition.

FOR THE NEW YORK STATE DEPARTMENT OF HEALTH

Date: 
CJB/ : 

By _______________________________________
Charles J. Burns, Chief
Radioactive Materials Section
Bureau of Environmental Radiation Protection

C:\Documents and Settings\smg03\Local Settings\Temp\notes6030C8\Draft Gas and Oil Industry
revison 1.doc

Doc:BOIL\Oil and Gas 

10/2009
Final SGEIS 2015, Page A27-14