North Carolina oil and gas study under session law 2011-276

              North Carolina Oil and Gas Study under
Session Law 2011­276
April 30, 2012
Prepared by the North Carolina Department of Environment and Natural Resources and
the North Carolina Department of Commerce
Acknowledgments
The following staff at the Department of Environment and Natural Resources and the
Department of Commerce worked tirelessly to make this report possible. DENR is grateful for
the efforts of these individuals. DENR is also grateful to the hundreds of members of the public
who submitted comments, helping us strengthen the final report.
Lead Authors
Robin Smith, Assistant Secretary for the Environment
Trina Ozer
Oil and Gas Resources, Oil and Gas Exploration and Extraction, Management and Reclamation
of Drilling Sites, Naturally Occurring Radioactive Materials and Seismic Activity
Jeff Reid
Jim Simons
Ken Taylor
Water Supply Impacts
Don Rayno
Water Quality Impacts
Rick Bolich
Ted Bush
Deborah Gore
Karen Higgins
Evan Kane
Sandra Moore
Ken Pickle
Jon Risgaard
Thomas Slusser
Chuck Wakild
Impacts to Fish, Wildlife and Important Natural Areas
John Finnegan
Linda Pearsall
Judy Ratcliffe
Air Quality Impacts
Mike Abraczinskas
Sheila Holman
Sushma Masemore
William Willets
Disposal, Storage and Transportation of Solid Waste
Jack Butler
Helen Cotton
Ellen Lorscheider
Dexter Matthews
Ed Mussler
Mark Poindexter
Michael Scott
Economic Impacts
Kristin Bunn
Stephanie McGarrah, Assistant Secretary for Labor and Economic Analysis
Sara Nienow
Chuck Sathrum
Christa Wagner Vinson
Jon Williams, Assistant Secretary for Energy
Social Impacts
Daniel Raimi
Proposed Regulatory Framework
Robin Smith
Review and Additional Input
Kari Barsness
Diana Kees
Additional Assistance
The following staff members from the Department of Health and Human Services, the
Department of Transportation and the Wildlife Resources Commission also contributed to this
report:
Department of Transportation
Cary Clemmons
Judy Corley‐Lay
Department of Health and Human Services
James Albright
Lee Cox
Diana Sulas
Wildlife Resources Commission
Vann Stancil
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Table of Contents
Executive Summary ...................................................................................................................................... 1
Background .......................................................................................................................................... 1
Study Limitations ................................................................................................................................. 1
Key Findings ......................................................................................................................................... 2
Community, Infrastructure and Social Impacts .................................................................................... 8
Regulatory Program .............................................................................................................................. 9
Conclusions and Recommendations ................................................................................................... 10
Funding recommendations ................................................................................................................. 11
Water and air quality recommendations ............................................................................................ 11
Hydraulic fracturing fluids recommendations .................................................................................... 11
Waste management standards ........................................................................................................... 11
Regulatory program recommendations .............................................................................................. 12
Permitting recommendations ............................................................................................................. 12
Data management recommendations ................................................................................................ 12
Emergency response recommendations ............................................................................................ 12
Local government authority recommendations ................................................................................. 12
Address liability .................................................................................................................................. 12
Public participation ............................................................................................................................. 13
Additional research recommendations .............................................................................................. 13
Introduction ............................................................................................................................................... 15
Section 1 – Potential Oil and Gas Resources .............................................................................................. 17
A. Overview of the Triassic Basins ...................................................................................................... 17
B. Organic geochemical data.............................................................................................................. 21
C. Estimating the resources ............................................................................................................... 28
2012 USGS resource assessment ........................................................................................................ 28
1995 USGS oil and gas resource assessment ...................................................................................... 29
North Carolina Geologic Survey gas recovery estimates .................................................................... 29
Recent data from the Butler #3 and Simpson #1 wells ....................................................................... 30
D. Anticipated industry behavior ....................................................................................................... 31
Leasing of mineral rights ..................................................................................................................... 31
Commercial interest ............................................................................................................................ 32
Section 2 – Oil and Gas Exploration and Extraction .................................................................................... 35
A. How hydrocarbons are generated and trapped in the Earth ........................................................ 35
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Hydrocarbons 101 ............................................................................................................................... 35
Conventional and unconventional resources ..................................................................................... 35
B. Methods used to find hydrocarbons ............................................................................................. 36
Gravity and magnetic characteristics .................................................................................................. 37
Seismic reflection ............................................................................................................................... 37
Organic geochemistry indicators ........................................................................................................ 39
C. Methods to extract hydrocarbons ................................................................................................. 40
Process of shale gas development ...................................................................................................... 40
Alternative fracturing techniques ....................................................................................................... 42
Section 3 – Potential infrastructure impacts .............................................................................................. 45
A. Water supply ................................................................................................................................. 45
Data sources ....................................................................................................................................... 47
Water use and potential supply .......................................................................................................... 48
Existing regulatory structure for water withdrawals for shale gas exploration and production ....... 69
Estimated water needs for gas well development ............................................................................. 72
Conclusions related to water supply ................................................................................................... 79
B. Road and bridge infrastructure ...................................................................................................... 84
Existing condition and effects of increased use .................................................................................. 84
Existing road conditions ...................................................................................................................... 87
Costs for road repair or replacement ................................................................................................. 88
Safety considerations .......................................................................................................................... 89
Road impacts ...................................................................................................................................... 89
Weight limits ...................................................................................................................................... 90
Management options .......................................................................................................................... 91
C. Transportation methods ................................................................................................................ 92
Rail transportation .............................................................................................................................. 92
Transportation of fresh water ............................................................................................................. 92
Transportation of gas .......................................................................................................................... 92
D. Domestic wastewater treatment ................................................................................................... 97
Section 4 – Potential environmental and health impacts ........................................................................... 99
A. Constituents and contaminants associated with hydraulic fracturing .......................................... 99
The use of chemicals in hydraulic fracturing ...................................................................................... 99
Classes of chemicals used ................................................................................................................. 100
Use of proprietary chemicals ............................................................................................................ 102
Health information related to hydraulic fracturing fluids ................................................................ 102
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Chemicals used aboveground ........................................................................................................... 107
Regulation of hydraulic fracturing chemical disclosure .................................................................... 108
Existing regulation of trade secrets in North Carolina ...................................................................... 112
Conclusions related to hydraulic fracturing additives ...................................................................... 112
B. Hydrogeologic framework of the Triassic Basins ......................................................................... 113
Well locations and groundwater use ................................................................................................ 115
C. Potential groundwater impacts ................................................................................................... 119
Stray gas migration ........................................................................................................................... 119
Well construction .............................................................................................................................. 120
Potential releases to groundwater ................................................................................................... 123
Potential public health impacts ........................................................................................................ 127
Conclusions related to groundwater ................................................................................................ 127
D. Process wastewater ..................................................................................................................... 128
Wastewater characteristics .............................................................................................................. 128
On‐site storage of drilling fluids, hydraulic fracturing fluids, produced water and flowback .......... 130
Disposal options for wastewaters ..................................................................................................... 131
E. Surface water impacts and stormwater management ................................................................ 139
Erosion and sedimentation issues during production and following reclamation of well pads ....... 141
Post‐development runoff .................................................................................................................. 142
Stream and wetland impacts ............................................................................................................ 142
Environmentally sensitive site design ............................................................................................... 143
Surface spills and releases from the well pad ................................................................................... 144
Spills and releases during transportation and storage ..................................................................... 145
Potential public health impacts ........................................................................................................ 145
Conclusions related to surface water impacts and stormwater management ................................ 145
F. Land application of oil and gas wastes ........................................................................................ 146
G. Air quality impacts ....................................................................................................................... 147
Air emissions .................................................................................................................................... 147
Emission sources associated with natural gas extraction and production, including venting and
flaring ............................................................................................................................................... 149
Air quality permitting requirements ................................................................................................. 152
Potential public health impacts ........................................................................................................ 154
Conclusions related to air quality impacts ........................................................................................ 156
H. Impacts on fish, wildlife and important natural areas ................................................................. 156
Publicly owned lands in North Carolina’s Triassic Basins ................................................................. 157
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Important natural areas of North Carolina’s Triassic Basins............................................................. 160
Rare species of the Triassic Basins .................................................................................................... 171
Potential impacts to fish, wildlife and important natural areas based on studies from other states
......................................................................................................................................................... 178
I. Management and reclamation of drilling sites (including orphaned sites) ................................. 189
Definitions ........................................................................................................................................ 189
History of oil and gas exploration in North Carolina ......................................................................... 189
Oil and gas exploration well database data field explanation .......................................................... 191
Summary .......................................................................................................................................... 192
J. Management of naturally occurring radioactive materials (NORMs) ......................................... 192
N.C. Geological Survey (NCGS) measurements and sampling .......................................................... 194
K. Potential for increased seismic activity ....................................................................................... 195
Earthquakes 101 ............................................................................................................................... 196
Possible case of seismicity induced by hydraulic fracturing ............................................................. 198
Arkansas case of disposal wells inducing earthquakes ..................................................................... 198
Ohio and another case of induced seismicity ................................................................................... 199
Summary .......................................................................................................................................... 201
L. Disposal, storage and transportation of hazardous and non‐hazardous solid waste ................. 202
Solid waste types known to be generated in the shale gas industry ................................................ 205
Available types of solid waste disposal in North Carolina ................................................................ 205
Possible waste‐handling problems associated with the shale gas industry ..................................... 207
Recycling of waste ............................................................................................................................. 208
Section 5 – Potential economic impacts ................................................................................................... 209
A. Introduction ................................................................................................................................ 209
Limits to economic input‐output models ......................................................................................... 211
B. Economic impacts ........................................................................................................................ 211
Employment ..................................................................................................................................... 212
Financial impact to the state’s economy .......................................................................................... 214
C. Timing of the realization of economic benefits ........................................................................... 214
D. Other issues ................................................................................................................................ 215
Agriculture, wineries and the local food industry ............................................................................. 215
Travel and tourism ............................................................................................................................ 216
Residential issues .............................................................................................................................. 216
E. Potential impacts to North Carolina energy consumers from developing the shale play ........... 217
F. Fiscal impacts to local government ............................................................................................. 218
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G. Additional state resources needed to provide regulatory oversight ........................................... 219
H. Comparison of existing bonding requirements to those in other states ..................................... 221
I. Comparison of existing severance taxes to severance taxes or royalty payments in other oil and
gas states .............................................................................................................................................. 225
J. Use of special assessments .......................................................................................................... 227
Corporate income taxes .................................................................................................................... 227
Pennsylvania’s impact fee ................................................................................................................. 227
New York’s property tax on natural gas ........................................................................................... 227
Real property taxes ........................................................................................................................... 228
Sales and use taxes ........................................................................................................................... 228
Other fees and taxes ......................................................................................................................... 228
K. Estimate of revenue generated by severance taxes or royalties at levels comparable to other oil
and gas states....................................................................................................................................... 230
L. Fees for permitting oil and gas exploration and production activities ........................................ 232
Well permitting fees in North Carolina and other states ................................................................. 232
Well abandonment fees and other well fees in North Carolina and other states ............................ 235
Other environmental permitting fees in North Carolina .................................................................. 236
M. Recommendations for funding state regulatory oversight ......................................................... 236
Appropriate level of severance taxes or royalty payments .............................................................. 236
Recommendations for new or modified permit fees ....................................................................... 236
N. Other recommended uses for oil and gas revenue ..................................................................... 236
Section 6 – Potential social impacts .......................................................................................................... 239
A. Potential impacts on housing availability .................................................................................... 239
Examples from other states .............................................................................................................. 239
Distributional impacts ....................................................................................................................... 240
Rental housing stock and affordability in potentially affected North Carolina counties ................. 241
Estimated vacant rental units in the Dan and Deep River basins ..................................................... 243
Housing options ............................................................................................................................... 246
B. Potential impacts on property values .......................................................................................... 248
Drilling sites ...................................................................................................................................... 248
Natural gas pipelines ......................................................................................................................... 249
Natural gas processing facilities ........................................................................................................ 250
Valuation and mortgage issues ......................................................................................................... 250
Analysis of data on property values .................................................................................................. 251
Limitations of data analysis ............................................................................................................... 252
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Counties included in analysis of property values .............................................................................. 253
C. Potential impacts on demand for social services ........................................................................ 253
Potential for decreased demand on social services.......................................................................... 253
Housing assistance ............................................................................................................................ 253
Traffic and policing ............................................................................................................................ 254
Emergency services ........................................................................................................................... 255
Schools ............................................................................................................................................. 255
Other social services ......................................................................................................................... 256
D. Potential impacts on recreation activities ................................................................................... 257
Game lands ...................................................................................................................................... 257
Bike routes ....................................................................................................................................... 257
Boating access points and major water bodies ................................................................................ 257
E. Potential impacts on commercial and residential development ................................................. 257
Commercial development in other shale regions ............................................................................. 257
Implications of changes in rental costs ............................................................................................. 258
Implications of changes in property values ...................................................................................... 259
Water supply issues in commercial and residential development ................................................... 259
F. Potential noise impacts ................................................................................................................ 259
Access road construction .................................................................................................................. 260
Pad construction ............................................................................................................................... 261
Vertical and horizontal drilling .......................................................................................................... 261
Hydraulic fracturing .......................................................................................................................... 263
Site reclamation and sustained production ...................................................................................... 264
Pipeline construction ........................................................................................................................ 264
Compressor stations ......................................................................................................................... 265
G. Potential visual impacts ............................................................................................................... 265
Access road and pad construction .................................................................................................... 266
Drilling, lighting and storage ............................................................................................................. 267
Hydraulic fracturing, flaring and water impoundments ................................................................... 268
Completion and reclamation ............................................................................................................ 268
Pipeline construction ........................................................................................................................ 269
H. Potential impacts on crime rates ................................................................................................. 273
Examples from other states .............................................................................................................. 273
Statistical analysis overview .............................................................................................................. 274
Statistical analysis results.................................................................................................................. 274
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Discussion of results .......................................................................................................................... 275
Data analysis limitations ................................................................................................................... 276
Implications for North Carolina ........................................................................................................ 277
I. Potential community impacts ...................................................................................................... 280
Distributional impacts and potential for community division .......................................................... 280
Landowner coalitions ........................................................................................................................ 281
Quality of life .................................................................................................................................... 281
Implications for North Carolina ........................................................................................................ 283
Section 7 – Proposed Regulatory Framework ........................................................................................... 285
A. Guidance for a regulatory framework ......................................................................................... 285
Federal regulation ............................................................................................................................. 285
Summary .......................................................................................................................................... 288
B. STRONGER guidelines for state oil and gas programs ................................................................. 288
1. Develop formal standards for natural gas exploration and development ................................... 289
2. Develop technical criteria for oil and gas activity ......................................................................... 290
3. Use stakeholder groups to develop an oil and gas program ........................................................ 290
C. State regulatory programs ........................................................................................................... 290
Technical standards common to oil and gas states .......................................................................... 291
D. Other sources of recommended standards ................................................................................. 298
1. New York Supplemental Draft Generic Environmental Impact Statement .................................. 298
2. American Petroleum Institute guidance ....................................................................................... 300
3. Report of the Secretary of Energy’s Advisory Board, Shale Gas Production Subcommittee ........ 301
4. Guidance under development ...................................................................................................... 302
E. State policies to guide decisions on hydraulic fracturing ............................................................ 303
F. Recommended regulatory framework ........................................................................................ 304
G. Conclusion ................................................................................................................................... 307
Section 8 – Consumer protection and legal issues ................................................................................... 309
Section 9 – Recommendations and limitations ........................................................................................ 311
A. Recommendations ....................................................................................................................... 311
Funding recommendations ............................................................................................................... 312
Water and air quality recommendations .......................................................................................... 312
Hydraulic fracturing fluids recommendations .................................................................................. 312
Waste management standards ......................................................................................................... 312
Regulatory program recommendations ............................................................................................ 312
Permitting recommendations ........................................................................................................... 313
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Data management recommendations .............................................................................................. 313
Emergency response recommendations .......................................................................................... 313
Local government authority recommendations ............................................................................... 313
Address liability ................................................................................................................................ 313
Public participation ........................................................................................................................... 313
Additional research recommendations ............................................................................................ 313
Funding recommendations ............................................................................................................... 314
Water and air quality recommendations .......................................................................................... 315
Hydraulic fracturing fluids recommendations .................................................................................. 318
Waste management standards ......................................................................................................... 318
Regulatory program recommendations ............................................................................................ 320
Permitting recommendations ........................................................................................................... 322
Data management recommendations .............................................................................................. 323
Emergency response recommendations .......................................................................................... 324
Local government authority recommendations ............................................................................... 324
Address liability ................................................................................................................................ 324
Public participation ........................................................................................................................... 325
Additional research recommendations ............................................................................................ 325
B. Limitations .................................................................................................................................. 327
Section 10 – Appendices ........................................................................................................................... 329
A. Appendix A: Bridges in the Triassic Basins with minimum clearance .......................................... 329
B. Appendix B: Maps of recreation areas......................................................................................... 333
Maps of state, county, and local parks ............................................................................................. 333
Maps of game lands in the Triassic Basins ........................................................................................ 341
Maps of bike routes in the Triassic Basins ........................................................................................ 345
Maps of boat access points and major water bodies in the Triassic Basins ..................................... 349
Map sources ..................................................................................................................................... 352
C. Appendix C: Common noise sources and levels at 50 feet .......................................................... 353
D. Appendix D: Statistical analysis methodology ............................................................................. 354
Counties included in analysis ............................................................................................................ 354
Regression Results ............................................................................................................................ 354
Data plots ......................................................................................................................................... 359
E. Appendix E: STRONGER Report.................................................................................................... 363
F. Appendix F: Session Law 2011‐276 .............................................................................................. 445
G. Appendix G: Summary of Public Comments ................................................................................ 453
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General comments ............................................................................................................................ 453
Conclusion of the report ................................................................................................................... 455
Shale gas resource ............................................................................................................................ 456
Geology ............................................................................................................................................ 457
Water supply impacts ....................................................................................................................... 458
Roads ................................................................................................................................................ 461
Pipelines ........................................................................................................................................... 462
Hydraulic fracturing fluids ................................................................................................................. 462
Groundwater impacts ....................................................................................................................... 464
Wastewater ...................................................................................................................................... 465
Surface water impacts and stormwater management ..................................................................... 468
Setbacks and areas prohibited from drilling ..................................................................................... 469
Air quality impacts ............................................................................................................................ 469
Impacts on fish, wildlife and important natural areas ...................................................................... 471
Waste management .......................................................................................................................... 472
Management and reclamation of drilling sites ................................................................................. 473
Naturally Occurring Radioactive Materials ....................................................................................... 473
Public health impacts ........................................................................................................................ 473
Economic impacts ............................................................................................................................. 473
Regulatory agency funding and staffing ........................................................................................... 475
Social impacts................................................................................................................................... 477
Environmental justice ....................................................................................................................... 478
Regulatory framework ...................................................................................................................... 480
Water use laws ................................................................................................................................. 481
Consumer protection ........................................................................................................................ 481
Local government authority .............................................................................................................. 482
Comments about draft recommendations ....................................................................................... 483
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Table of Figures
Figure 1‐1. Exposed North Carolina Triassic Basins ...................................................................... 17
Figure 1‐2. Triassic paleogeography approximately 210 million years ago, from Ron Blakey, NAU
Geology.. ............................................................................................................................... 18
Figure 1‐3. The Mesozoic Basins of the eastern United States.. .................................................. 19
Figure 1‐4. Cross‐section from northwest to southeast across the Sanford sub‐basin. .............. 20
Figure 1‐5.Total Organic Carbon (TOC) as a percentage for samples from eight wells (seven coal
holes and one oil test hole). ................................................................................................. 23
Figure 1‐6. Maturity (Tmax) for multiple wells. These data are color‐coded to the five wells. ... 24
Figure 1‐7. Map of part of the Sanford sub‐basin showing the seismic lines (yellow), the coal
mine locations, coal exploration holes and oil and gas test wells.. ...................................... 25
Figure 1‐8. Map of the depth to basement of the Sanford sub‐basin.. ........................................ 27
Figure 1‐9. Map of the thickness of the organic‐rich shale (Cumnock Formation) in the Sanford
sub‐basin.. ............................................................................................................................. 28
Figure 2‐1. Model of the different types of conventional and unconventional oil and gas
resources.. ............................................................................................................................. 36
Figure 2‐2. Seismic Reflection Line 113 across the Sanford sub‐basin, Deep River Basin. .......... 38
Figure 2‐3. Interpretation of Seismic Reflection Line 113 across the Sanford sub‐basin, Deep
River Basin. ............................................................................................................................ 39
Figure 3‐1. Triassic Basins and Upper Dan River and Deep River Sub‐basins ............................... 46
Figure 3‐2. Triassic Basins and Subwatersheds Used in this Analysis ........................................... 47
Figure 3‐3. Sanford and Durham Sub‐basins and Study Area....................................................... 49
Figure 3‐4. Wadesboro Triassic Sub‐basin and Study Area .......................................................... 54
Figure 3‐5. Dan River Triassic Basin Study Area with Wells and Surface Water Intakes .............. 57
Figure 3‐6. Hydrologic Areas of Similar Potential to Sustain Low Flows in North Carolina ......... 62
Figure 3‐7. Sanford Triassic Sub‐basin Study Area ....................................................................... 63
Figure 3‐8. Hydrologic Areas – Sanford and Durham Sub‐basins of Deep River Triassic Basin .... 64
Figure 3‐9. Hydrologic Areas ‐ Wadesboro Sub‐unit .................................................................... 67
Figure 3‐10. Dan River Triassic Basins Study Area ........................................................................ 67
Figure 3‐11. Hydrologic Areas ‐ Dan River Triassic Basins ............................................................ 68
Figure 3‐12. Construction of Underground Pipeline .................................................................... 97
Figure 4‐1. Diabase dikes and sills (red) and faults (labeled black lines) cross‐cutting
sedimentary rocks of the Deep River Triassic Basin northwest of Sanford. ....................... 114
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Figure 4‐2. Typical Oil or Gas Well Schematic, excluding the horizontal portion of the well .... 121
Figure 4‐3. Publicly Owned Lands in the Dan River Triassic Basin .............................................. 158
Figure 4‐4. Publicly Owned Lands in the Northern Portion of the Deep River Basin ................. 159
Figure 4‐5. Publicly Owned Lands in the Southern Portion of the Deep River Basin ................. 159
Figure 4‐6. SNHAs in the Dan River Triassic Basin ...................................................................... 165
Figure 4‐7. SNHAs in the Northern Portion of the Deep River Basin .......................................... 166
Figure 4‐8. SNHAs in the Southern Portion of the Deep River Basin .......................................... 167
Figure 4‐9. SNHAs in the Wadesboro Sub‐basin ......................................................................... 168
Figure 4‐10. Time series of the number of exploration oil and gas wells completed in North
Carolina.. ............................................................................................................................. 190
Figure 4‐11. Observed radiation from shale rock along the south‐facing quarry wall at the
CEMEX mine north of Eden, N.C. ........................................................................................ 195
Figure 4‐12. Colored spheres show the location of microseismic events generated by hydraulic
fracturing. ............................................................................................................................ 197
Figure 5‐1. Estimated Revenues Using Other States’ Tax Collections ........................................ 232
Figure 6‐1. Demographics and Economics of Housing in Deep River Basin Counties ................ 241
Figure 6‐2. Demographics and Economics of Housing in the Dan River Basin Counties ............ 242
Figure 6‐3. Housing Characteristics of Counties in the Deep River Basin, 2005‐2009 ............... 242
Figure 6‐4. Housing Characteristics of Counties in the Dan River Basin, 2005‐2009 ................. 243
Figure 6‐5. Estimated Vacant Rental Units in Dan River Basin, 2010 ......................................... 244
Figure 6‐6. Estimated Vacant Rental Units in Durham Sub‐basin, 2010 .................................... 244
Figure 6‐7. Estimated Vacant Rental Units in Sanford Sub‐basin, 2010 ..................................... 245
Figure 6‐8. Estimated Vacant Rental Units in Wadesboro Sub‐basin, 2010 ............................... 245
Figure 6‐9. Hydraulic Fracturing in Upshur Valley, West Virginia (Marcellus region) ................ 264
Figure 6‐10. Natural Gas Compressor Stations in North Carolina .............................................. 265
Figure 6‐11. Accessing Shale Field via Vertical Drilling ............................................................... 266
Figure 6‐12. Accessing Shale Field via Horizontal Drilling .......................................................... 267
Figure 6‐13. Drilling Rig from Two Miles..................................................................................... 270
Figure 6‐14. Marcellus “Double Rig” ........................................................................................... 271
Figure 6‐15. Hydraulic Fracturing Operation, Canadian County, Oklahoma .............................. 271
Figure 6‐16. Lighting and Natural Gas Flaring at a Marcellus Natural Gas Well, Pennsylvania . 272
Figure 6‐17. Brine Tanks at a Producing Well, Bradford County, Pennsylvania ......................... 272
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Figure 6‐18. Dan River Basin Population Density ....................................................................... 278
Figure 6‐19. Durham Sub‐basin Population Density ................................................................... 279
Figure 6‐20. Sanford Sub‐basin Population Density ................................................................... 279
Figure 6‐21. Wadesboro sub‐basin population density .............................................................. 280
Figure 10‐1. Anson County State, County and Local Parks ......................................................... 333
Figure 10‐2. Chatham County State, County and Local Parks .................................................... 334
Figure 10‐3. Davie County State, County and Local Parks .......................................................... 334
Figure 10‐4. Durham County State, County and City Parks ........................................................ 335
Figure 10‐5. Granville County State, County and Local Parks ..................................................... 335
Figure 10‐6. Lee County State, County and Local Parks ............................................................. 336
Figure 10‐7. Montgomery County State, County and City Parks ................................................ 336
Figure 10‐8. Moore County State, County and City Parks .......................................................... 337
Figure 10‐9. Orange County State, County and City Parks ......................................................... 337
Figure 10‐10. Richmond County State, County and City Parks ................................................... 338
Figure 10‐11. Rockingham County State, County and City Parks ............................................... 338
Figure 10‐12. Stokes County State, County and City Parks ........................................................ 339
Figure 10‐13. Union County State, County and City Parks ......................................................... 339
Figure 10‐14. Wake County State, County and City Parks .......................................................... 340
Figure 10‐15. Yadkin County State, County and City Parks ........................................................ 340
Figure 10‐16. Dan River Basin and Game Lands ......................................................................... 341
Figure 10‐17. Durham Sub‐Basin and Game Lands .................................................................... 342
Figure 10‐18. Sanford Sub‐Basin and Game Lands ..................................................................... 343
Figure 10‐19. Wadesboro Sub‐Basin and Game lands................................................................ 344
Figure 10‐20. Dan River Basin and Bike Routes .......................................................................... 345
Figure 10‐21. Durham Sub‐Basin and Bike Routes ..................................................................... 346
Figure 10‐22. Sanford Sub‐Basin and Bike Routes ...................................................................... 347
Figure 10‐23. Wadesboro Sub‐Basin and Bike Routes ................................................................ 348
Figure 10‐24. Dan River Basin, Boat Access Points and Major Water Bodies ............................ 349
Figure 10‐25. Durham Sub‐Basin, Boat Access Points and Major Water Bodies ....................... 350
Figure 10‐26. Sanford Sub‐Basin, Boat Access Points and Major Water Bodies ........................ 351
Figure 10‐27. Wadesboro Sub‐Basin, Boat Access Points and Major Water Bodies .................. 352
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Figure 10‐28. Texas Barnett Region, Index of Change in Gas Production and Index of Nonviolent
Crime Rates with Least Fit Squares Line ............................................................................. 359
Figure 10‐29. Colorado Western Slope Region, Index of Change in Gas Production and Index of
Violent Crime Rates with Least Fit Squares Line................................................................. 360
Figure 10‐30. Wyoming Green River Basin Region, Index of Change in Gas Production and Index
of Violent Crime Rates with Least Fit Squares Line ............................................................ 360
Figure 10‐31. Wyoming Green River Basin Region, Index of Change in Oil Production and Index
of Total Crime Rates with Least Fit Squares Line ................................................................ 361
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Table of Tables
Table 1‐1. Stages of Thermal Maturity ......................................................................................... 22
Table 1‐2. Interpreted Maturation Based on Vitrinite Reflectance Values .................................. 22
Table 3‐1. USGS Drainage Area Nomenclature ............................................................................. 46
Table 3‐2. Sanford and Durham Sub‐basins ‐ County Population ................................................ 51
Table 3‐3. Sanford and Durham Sub‐basin ‐ Population Served by a Local Water Supply Plan
(LWSP) Water System ........................................................................................................... 52
Table 3‐4. Sanford and Durham Sub‐unit ‐ Water Demands from Local Water Supply Plans ..... 52
Table 3‐5. Sanford and Durham Sub‐basins ‐ Population and Water Demands of County
Residents Not Served by a LWSP System ............................................................................. 52
Table 3‐6. Sanford and Durham Sub‐basins Agricultural Water Use............................................ 53
Table 3‐7. Wadesboro Triassic Sub‐basin County Population ...................................................... 55
Table 3‐8. Wadesboro Triassic Sub‐basin Local Water Supply Plan Service Population .............. 55
Table 3‐9. Wadesboro Triassic Sub‐basin Local Water Supply Plan Water Use ........................... 55
Table 3‐10. Wadesboro Triassic Sub‐basin Water Demands ‐ Non‐LWSP residents .................... 56
Table 3‐11. Wadesboro Sub‐basin Agricultural Water Use .......................................................... 56
Table 3‐12. Dan River Triassic Basin ‐ County Population ............................................................ 58
Table 3‐13. Dan River Triassic Basin ‐ Population Served by a Local Water Supply Plan Water
System .................................................................................................................................. 58
Table 3‐14. Dan River Triassic Basin ‐ Water Demands from Local Water Supply Plans .............. 58
Table 3‐15. Dan River Triassic Basin ‐ Population and Water Demands of County Residents Not
Served by a LWSP System ..................................................................................................... 58
Table 3‐16. Dan River Triassic Basin ‐ Agricultural Water Use ..................................................... 59
Table 3‐17. Analysis Scenario Descriptions .................................................................................. 77
Table 3‐18. Triassic Public Water Supply Wells (gpm = gallons per minute)................................ 82
Table 3‐19. NYSDEC Assumed Construction and Development Times ......................................... 85
Table 3‐20. Estimated Number of One‐Way (Loaded) Trips per Well: Horizontal Well1 ............. 86
Table 3‐21. Pavement Conditions in Sample of Roads in the Triassic Basin ................................ 87
Table 4‐1. Categories and Purposes of Additives Proposed for Use in New York State ............. 101
Table 4‐2. Summary of Domestic Water Use in Counties containing the Deep River and Dan
River Triassic Basins in 2005 ............................................................................................... 118
Table 4‐3. Summary of the Sources of Groundwater Contamination from Oil and Gas Production
in Ohio and Texas ................................................................................................................ 126
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Table 4‐4. Typical Range of Concentrations for Some Common Constituents of Flowback Water
in Western Pennsylvania ..................................................................................................... 129
Table 4‐5. Definitions for SNHA Significance Rankings ............................................................... 160
Table 4‐6. Nationally Significant Natural Heritage Areas within the Triassic Basins (Rank A) ... 161
Table 4‐7. Statewide Significant Natural Heritage Areas within the Triassic Basin (Rank B) ..... 162
Table 4‐8. Regionally Significant Natural Heritage Areas within the Triassic Basin (Rank C) ..... 163
Table 4‐9. County Significant Natural Heritage Areas within the Triassic Basin (Rank D) .......... 164
Table 4‐10. Natural Communities within the Triassic Basin ....................................................... 171
Table 4‐11. Federally or State‐Listed Endangered or Threatened Plant Species ....................... 173
Table 4‐12. Federally or State‐Listed Endangered or Threatened Animal Species .................... 174
Table 4‐13. Sample of Hydraulic Fracturing Fluid Composition by Weight ................................ 203
Table 5‐1. Model Assumptions ................................................................................................... 210
Table 5‐2. Potential Well Field .................................................................................................... 211
Table 5‐3. Annual Employment Impacts ..................................................................................... 213
Table 5‐4. Top 10 Industry Sectors Impacted ............................................................................. 213
Table 5‐5. Annual Economic Impacts .......................................................................................... 214
Table 5‐6. Summary of State Oil and Gas Well Bonding Requirements, , , ............................... 223
Table 5‐7. Severance and Corporate Income Tax Rates for Various Natural Gas‐Producing States
............................................................................................................................................ 226
Table 5‐8. Severance Tax Collections per Million Cubic Feet for 2009 ...................................... 231
Table 5‐9. Estimated Revenues Based on Other States’ Tax Collections ................................... 231
Table 5‐10. Permit Fees for Drilling Natural Gas Wells in Selected States ................................. 234
Table 5‐11. Annual Fees for Well Permit Holders in Arkansas ................................................... 235
Table 5‐12. Annual Production Fees for Wells in Louisiana ....................................................... 235
Table 6‐1. Commute Times (in minutes) to North Carolina Shale Regions ................................ 247
Table 6‐2. Change in Average Property Values, 2009‐2012 ....................................................... 252
Table 6‐3. HUD Daytime Land Use Compatibility Guidelines for Noise ..................................... 260
Table 6‐4. Distance in Feet/Sound Pressure Levels in Decibels ................................................. 260
Table 6‐5. Distance in Feet/Sound Pressure Levels in Decibels ................................................. 261
Table 6‐6. Distance in Feet/Sound Pressure Levels in Decibels ................................................. 262
Table 6‐7. Distance in Feet/Sound Pressure Levels in Decibels ................................................. 262
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Table 6‐8. Distance in Feet/Sound Pressure Levels in Decibels ................................................. 263
Table 6‐9. Distances, in Miles, Between Potential Shale Regions and North Carolina Compressor
Stations* ............................................................................................................................. 269
Table 6‐10. Population Densities in Oil/Gas regions, and in the North Carolina Deep and Dan
River Basin Regions ............................................................................................................. 278
Table 10‐1. Bridges in the Triassic Basins with Minimum Clearance ......................................... 329
Table 10‐2. Natural Gas Production Changes and Crime Rates per 100,000 People: “T” and “P”
Values ................................................................................................................................. 355
Table 10‐3. Natural Gas Production Changes and Crime Rates per 100,000 People: Coefficients
and Confidence Intervals .................................................................................................... 356
Table 10‐4. Oil Production Changes and Crime Rates per 100,000 People: “T” and “P” Values 357
Table 10‐5. Oil Production Changes and Crime Rates per 100,000 People: Coefficients and
Confidence Intervals ........................................................................................................... 358
North Carolina Oil and Gas Study April 2012
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Executive Summary
Background
In Session Law 2011‐276, the North Carolina General Assembly directed the North Carolina
Department of Environment and Natural Resources (DENR), the Department of Commerce
(Commerce), and the Department of Justice, in conjunction with the nonprofit Rural
Advancement Foundation International (RAFI), to study the issue of oil and gas exploration in
the state and specifically the use of directional and horizontal drilling and hydraulic fracturing
for natural gas production.
DENR researched oil and gas resources present in the Triassic Basins (Section 1 of this report),
methods of exploration and extraction of oil and gas (Section 2), potential impacts on
infrastructure, including roads, pipelines and water and wastewater services (Section 3),
potential environmental and health impacts (Section 4), potential social impacts (Section 6),
and potential oversight and administrative issues associated with an oil and gas regulatory
program (Section 7).
S.L. 2011‐276 directed the Department of Commerce, in consultation with DENR, to gather
information on potential economic impacts of natural gas exploration and development
(Section 5 of this report). Department of Commerce prepared Sections 5.A through 5.F of the
report that discuss job creation and other projected economic impacts of natural gas drilling.
DENR prepared Sections 5.G though 5.N that address the different financial tools (such as
bonding requirements and severance taxes) used by oil and gas producing states to assure
funding for reclamation of drilling sites, cover regulatory costs and offset public infrastructure
costs.
The law directed the Consumer Protection Division of the Department of Justice to study
consumer protection and legal issues relevant to oil and gas exploration in the state, including
matters of contract and property law, mineral leases and landowner rights. The Consumer
Protection Division was directed to consult with RAFI on the consumer protection issues. The
Department of Justice did not provide this section to DENR, and it is therefore not included in
this report; the Department of Justice will release the consumer protection section separately.
Study Limitations
As requested by the General Assembly, this report analyzes the potential environmental,
health, economic, social and consumer protection impacts that an oil and gas extraction
industry may have in North Carolina. The analysis is constrained by the limited information
available at this time. We do not have detailed or comprehensive information on the extent
and richness of the shale gas resource in North Carolina. For purposes of this report we have
been forced to extrapolate from data gathered from only two wells in the Sanford sub‐basin;
those well values have been averaged to project an estimate of the natural gas resource
potentially available in that sub‐basin. Since there are only two data points and the two wells
have significantly different values, it is not clear how well the average value represents the
resource throughout the Sanford sub‐basin. This report generally uses the Sanford sub‐basin as
the basic unit for analysis of all impacts because the available data came from that sub‐basin.
North Carolina Oil and Gas Study April 2012
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The Sanford sub‐basin represents only a fraction of the total Triassic basin formations in the
state – approximately 59,000 acres out of a total of 785,000 acres.
These limitations carry over into the assessment of both potential economic and environmental
impacts. DENR projected the number of wells and total gas production for the Sanford sub‐basin,
using the limited data derived from averaging the values of two wells. Those projections
are used throughout the report as the basis for assessing economic and environmental impacts.
Many impacts of natural gas extraction will vary based on local characteristics, such as water
resources and even the weather. For example, the depth and quality of groundwater resources
in the Triassic basins of North Carolina appear to be very different from conditions in the
Marcellus shale formations in Pennsylvania. North Carolina does not seem to have as great a
separation between potential drinking water resources and the gas‐producing zone;
understanding the geology and groundwater hydrology of North Carolina’s shale formations
will be critical to ensuring protection of drinkable groundwater. In terms of infrastructure
impacts, weather can be an important factor. A local government official in Pennsylvania told
DENR staff that when the natural gas industry first came to Pennsylvania from the South, oil
and gas operators were surprised at how the harshness of the winters magnified the road
damage caused by heavy oil and gas trucks.
There are some aspects of oil and natural gas extraction for which data is extremely limited
even at a national level; the limited time available to prepare this report prevented us from
taking into account additional research that is currently underway. This includes EPA’s research
on potential groundwater impacts in Pavillion, Wyo., and Dimock, Pa., and EPA’s study of
hydraulic fracturing and its potential impact on drinking water resources. EPA’s first report of
results related to drinking water is expected in 2012; the final report is not expected until 2014.
To our knowledge, no comprehensive studies are currently available on the long‐term impacts
to health from hydraulic fracturing for natural gas, and DENR is not qualified to conduct such a
study. DENR recognizes that questions remain about health impacts. The EPA drinking water
study may provide additional insight on health effects.
Key Findings
North Carolina’s potential shale gas resource
Most of the N.C. Geological Survey’s information on potential shale gas resources in the state
comes from the Sanford sub‐basin of the Deep River geologic basin — a 150‐mile‐long area that
runs from Granville County southwestward across Durham, Orange, Wake, Chatham, Lee,
Moore, Montgomery, Richmond, Anson and Union counties into South Carolina.
The Deep River Basin is one of several similar geologic formations in North Carolina that cover
approximately 785,000 acres.
The available organic geochemical and seismic data has caused NCGS to focus on an area of
more than 59,000 acres in the Sanford sub‐basin as the most promising location for organic‐rich
shale and coals from which natural gas can be extracted.
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The shale formation in this area can be found at depths generally ranging between 2,100 and
6,000 feet below the surface. This particular shale formation has a maximum thickness of 800
feet and an average thickness that ranges from 180 to 540 feet.
Hydraulic Fracturing
Natural gas extraction by hydraulic fracturing involves drilling a well vertically and then
horizontally into the shale formation. The natural gas production company perforates the well
and then pumps fracturing fluid into the well under pressure to fracture the shale.
Fracturing fluids may be composed primarily of water and a proppant (such as sand) to keep
the fractures open. Water and sand represent between 98 percent and 99.5 percent of the
fracturing fluid. The fluid also includes chemical additives used to condition the water. Additives
may be used to thicken or thin the fluid, prevent corrosion of the well casing, kill bacteria or for
other purposes.
The exact makeup of fracturing fluid varies from company to company and may also be
adjusted based on conditions at the individual well site. Several hundred chemical compounds
have been identified by the industry as chemicals that have been used in fracturing fluid. Any
single fracturing fluid generally contains between 6 and 12 chemical additives.
Some chemicals that have been used in fracturing fluids, such as diesel fuel, have raised
concern because of potential health impacts. EPA has discouraged use of diesel fuel in hydraulic
fracturing.
Environmental Impacts
Water Supply: Hydraulic fracturing requires between 3 and 5 million gallons of water per well.
To put this in perspective, a number of small cities in North Carolina withdraw 5 million gallons
per day to serve their water system customers.
Based on some informed assumptions about the number of wells that could potentially be
located in the Sanford sub‐basin and the pace of well development, there appear to be
adequate surface water supplies to meet the needs of the industry.
The timing of water withdrawals will need to be managed, however, to avoid injury to other
water users and the environment. Under existing state law, water withdrawals do not require a
state permit except in the Central Coastal Plain Capacity Use Area where a permitting program
exists to manage withdrawals from two depleted aquifers. The Capacity Use Area permitting
program does not overlap with any part of the shale formation. As a result, the state currently
has no ability to ensure that groundwater or surface water withdrawals for natural gas
development will be appropriately managed to avoid stream impacts and conflicts with other
water users. A 3 million gallon withdrawal made over a three‐day period (which is technically
possible for the industry) has a much greater potential impact than a 3 million gallon
withdrawal made over the course of three weeks. In the absence of permit conditions to
prevent rapid withdrawals, streams could run dry and other water users may be harmed.
Water Quality: In the Sanford sub‐basin, there appears to be much less separation between
groundwater used for drinking water and the gas‐producing layer than in other gas‐producing
states. Water supply wells of up to 1,000 feet deep have been found in North Carolina’s Triassic
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Basins and the depth to which freshwater extends is unknown. Some of the shale that might be
tapped for natural gas in the Triassic Basins of North Carolina lies at depths of 3,000 feet or less.
(By contrast, the Pennsylvania shale gas resource lies at depths of roughly 10,000 feet or more
and the deepest water supply wells are generally no more than 600 feet deep.)
At least two recent studies have found higher levels of methane in groundwater near natural
gas wells that had been hydraulically fractured. In Pavillion, Wyo., EPA found methane of
thermogenic origin and organic chemicals consistent with those used in hydraulic fracturing
fluids in both monitoring wells and water supply wells. Conditions in Pavillion are not
necessarily representative of most shale plays, however; the hydraulic fracturing that occurred
in Pavillion involved injection of hydraulic fracturing fluids directly into the same formation
tapped by water supply wells.
A study in Pennsylvania found that water supply wells close to active exploration and
production wells in the Marcellus shale have higher levels of dissolved methane than wells
farther away. The study did not find constituents of hydraulic fracturing fluids in any of the
water supply wells that were sampled. The study did find methane in water supply wells. The
methane had an isotopic signature indicating that it originated from deep, thermogenic sources
consistent with a Marcellus shale source, rather than from shallow biogenic sources. The lack of
pre‐drilling groundwater samples make it difficult to definitively link the methane to drilling
practices.
Water quality problems have been associated with oil and gas operations generally; the
problems can result from a number of production activities other than hydraulic fracturing. A
Groundwater Protection Council study found that most Texas groundwater contamination
incidents related to oil and gas activity reviewed were traced to either the production phase of
well operations or involved waste management and disposal.
Oil and gas exploration and production can disturb large areas of land to develop access roads,
well pads, impoundments and other infrastructure. These activities have impacts very similar to
the stormwater impacts of any large development project: sedimentation and erosion, water
pollution, increased peak discharges, increased frequency and severity of flooding, and other
stormwater concerns. Unlike other construction projects, oil and gas exploration and
production activities are exempt from federal Clean Water Act stormwater requirements.
Air Quality: Federal Clean Air Act standards have only been adopted for natural gas processing
facilities. In 2011, EPA developed draft standards for air emissions from natural gas exploration
and production activities. As proposed, the rules would affect gas wellheads, centrifugal
compressors, reciprocating compressors, pneumatic controllers, storage vessels and
sweetening units. Until the proposed rules go into effect, no federal new source performance
standards or hazardous air pollution standards apply to emissions from these natural gas
exploration and production activities. EPA finalized the rules on April 17, 2012, but industry is
not required to implement all of the provisions of the rules until 2015.
A recent New York Environmental Impact Statement estimated that statewide NOx emissions
could be increased by 3.7 percent from hydraulic fracturing operations and as much as 10.4
percent in the upstate New York area where the Marcellus Shale is located. These increases in
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NOx emissions raise concerns for the impact on ozone concentrations and the state’s ability to
attain and maintain compliance with the federal ozone standard.
The state air toxics program requires a source of state‐regulated toxic air pollutants to
demonstrate compliance with the ambient air levels at the property boundary. Shale gas
production often occurs under a lease of property that may be owned and in some cases
occupied by another person. If natural gas production occurs on a residential property or farm,
the property owner or occupant may be exposed to unhealthy concentrations of toxic
pollutants.
Earthquakes: Hydraulic fracturing fluid under pressure cracks the surrounding rock; these
cracks generate vibrations while breaking that can be picked up by sensitive geophones.
Data from other states suggests that the process of hydraulic fracturing causes microseismic
events that do not pose a threat to the environment or human health or safety. An Oklahoma
Geologic Survey study of an earthquake complaint near a hydraulic fracturing operation found
that seismographs had recorded as many as 50 very small events on the day of the complaint.
Most of the earthquakes occurred within a 24‐hour period after the hydraulic fracturing
operations had ceased and were so minor (between 1 and 2.4 on the Richter scale) that they
could not be felt.
Most reports of significantly increased earthquake activity have occurred in regions where
disposal wells are operated and related to underground injection of waste rather than hydraulic
fracturing. Only a small fraction of injection wells have caused significant seismic activity.
Limiting injection volumes, decreasing pressure and distributing the waste between more
disposal wells have been shown to reduce and even eliminate induced seismicity, while reusing
and recycling of wastewater can reduce the need for other waste management options.
Wastewater and Solid Waste: Between 9 and 35 percent of the fluid pumped into a well for
hydraulic fracturing returns to the surface as “flowback” shortly after fracturing. During the
remainder of the productive life of the well, a much smaller volume of wastewater is generated
more or less continuously as the well produces gas; this wastewater is produced water.
In many states, flowback or produced water from a drilling operation can be disposed of by
underground injection. N.C. General Statute 143‐214.2(b) prohibits the use of wells for waste
disposal.
It is not clear that injection wells would be a feasible option for managing produced waters
from a gas well in the Triassic Basins of North Carolina. The areas with potential for natural gas
development have not been sufficiently characterized to determine whether the formations
would be suitable for disposal of shale gas production wastewater. The sedimentary rocks of
these basins generally have very low permeability, and natural fractures are responsible for
nearly all of the permeability and groundwater movement in these basins. Disposal by injection
into fractured rock presents difficulty in predicting the fate and transport of the injected
wastewaters. These conditions suggest that Triassic Basins in North Carolina generally do not
have suitable hydrogeologic conditions for disposal by injection.
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Some wastewater streams can go to a municipal wastewater treatment plant. These waste
streams can be difficult to treat in a conventional wastewater treatment plant, however, and it
would be advisable to require pretreatment.
A number of states allow land‐application of produced water from hydraulic fracturing. The
acceptability of wastewater for that purpose may depend on its quality at the time of land
application since high levels of salts and chlorides can be a problem.
Chesapeake Energy is currently recycling and reusing 95 percent of the flowback water that
returns to the surface (only a small percentage of the volume of water used in hydraulic
fracturing) by a filtering process.
EPA has exempted “drilling fluids, produced waters, and other wastes associated with the
exploration, development or production of crude oil, natural gas or geothermal energy” from
regulation under the Resource Conservation and Recovery Act (RCRA) ‐‐ the federal statute that
regulates hazardous waste.
Since some exploration and production wastes may have the characteristics of hazardous
wastes, but are not regulated under RCRA, oil and gas‐producing states have generally
developed specific standards for handling exploration and production wastes. North Carolina
does not have standards that specifically address disposal of or transportation of exploration
and production waste.
Since North Carolina statutes and rules have not been written to address these particular types
of wastes, existing state rules would allow disposal of all RCRA‐exempt exploration and
production wastes (other than oils and liquid hydrocarbons) in a municipal solid waste (MSW)
landfill. Although North Carolina has strong standards for design and construction of both
industrial and MSW landfills, those standards were not developed for disposal of hazardous
waste.
Economic Analysis
The economic impact analysis focuses on the statewide economic impact of gas drilling
activities in the Sanford sub‐basin. (The Sanford sub‐basin is approximately 59,000 acres of the
785,000 acres of the Triassic Basins in North Carolina.) The analysis does not take site
preparation, leasing of land, hydraulic fracturing or extraction, production or transmission of
gas into consideration.
Review of studies from other parts of the country show that a large infusion of economic
activity from shale gas drilling will increase the incomes of some individuals and communities
and will add jobs. Without reliable expenditure inputs for North Carolina, however, it remains
uncertain how much wealth, income or benefits from long‐term employment would accrue to
Lee, Chatham and surrounding counties.
For its analysis, the Department of Commerce used the IMPLAN modeling tool. IMPLAN allows
researchers to develop local level input‐output models to estimate the economic impacts
associated with marginal changes in the economy, such as “shocks” of new production or
output.
North Carolina Oil and Gas Study April 2012
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The model estimates that 36 percent of drilling investments will be spent locally with North
Carolina vendors. Since North Carolina does not presently have a developed fossil fuel
extraction industry, there will likely be substantial economic “leakages” as dollars are spent
outside the North Carolina economy. For example, drilling requires specialized equipment that
is not available from in‐state companies.
The IMPLAN model estimates drilling activities in the Sanford sub‐basin would sustain an
average of 387 jobs per annum over the seven‐year time period studied:
• In the peak well year, drilling activities are estimated to sustain 858 jobs over a one‐year
period.
• In Year 1, the year with the lowest level of drilling expenditures, the IMPLAN model
estimates that 59 jobs will be either created or partially supported by these
expenditures.
At the completion of all drilling activities in the state, it is estimated the economy will have
increased output by $453 million. Output represents the level of all economic activity from
production and is typically larger than value added impacts, which measure the direct change in
North Carolina’s gross domestic product (GDP). Anticipated drilling activities are estimated to
positively affect the state’s GDP by $292 million by year 2019.
It is not likely that North Carolina’s shale play will be developed in the near‐term. IHS Global
Insight, in a December 2011 study for the American Natural Gas Alliance, reported that six
prominent plays are expected to account for more than 90 percent of U.S. shale capacity by
2035. North Carolina was not on this list and, at this time, does not appear on U.S. Geological
Survey maps of North American shale plays.
Low natural gas prices also make activity in North Carolina unlikely in the near‐term. The Energy
Information Administration’s preliminary 2012 Annual Energy Outlook assumes that with
increased production, average annual wellhead prices for natural gas will remain below $5 per
thousand cubic feet (2010 dollars) through 2023. Low prices make it less likely that the industry
will move from areas already in production to a new and unproven area.
Bonding: North Carolina Session Law 2011‐276 revised the amount of the bond required for an
oil and gas‐drilling permit to $5,000 plus $1 per linear foot. Under North Carolina’s law, the
bond only covers proper closure and abandonment of the well. The bond does not cover the
costs of restoring the surface of the site to pre‐existing conditions or remediation of any
contamination caused by the drilling operation.
States vary significantly in the amount of bond required per well, but typically the uses of those
bonds extend beyond well closure and often cover site reclamation.
As one measure of the adequacy of bond requirements for wells on public lands, the General
Accounting Office (GAO) looked at the cost to the Bureau of Land Management of reclaiming
orphan wells. Over a 21‐year period, BLM spent about $3.8 million to reclaim 295 orphaned
wells, or an average of about $12,900 per well. The GAO report states that “the amount spent
per reclamation project varied greatly, from a high of $582,829 for a single well in Wyoming in
fiscal year 2008 to a low of $300 for 3 wells in Wyoming in fiscal year 1994.” The BLM also
North Carolina Oil and Gas Study April 2012
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estimated the costs of wells it has yet to reclaim at approximately $1.7 million for 102
orphaned wells, an average of roughly $16,700 per well.
Severance Taxes: North Carolina’s Oil and Gas Conservation Act currently sets the state’s
severance tax for natural gas at 5/100 of a cent – $.0005 per 1,000 cubic feet of gas. The
revenues can only be used to pay the costs of administering the law.
North Carolina has one of the lowest severance taxes in the nation. With the exception of those
states that do not assess any severance tax, North Carolina’s tax rate was the lowest of all
states for which severance taxes were identified as part of this study. Maryland, New York and
Pennsylvania do not assess severance taxes on the production of natural gas, however,
Pennsylvania recently enacted a law imposing an “impact fee” on natural gas production, and
New York assesses a “property type production tax” on the amount of natural gas produced.
Community, Infrastructure and Social Impacts
In Pennsylvania, road impacts have been a major problem for municipalities in the Marcellus
shale region. Gas development significantly increases truck traffic on roads that often were not
designed for such heavy use. For many of Pennsylvania’s small towns, road maintenance and
repair accounts for the largest part of the town budget.
New York’s EIS estimated 1,148 one‐way heavy‐duty truck trips and 831 one‐way light‐duty
truck trips per well during the construction phase of gas development. For early well pad
development, this is a total of 2,296 round‐trip heavy‐duty truck trips and 1,662 round‐trip
light‐duty truck trips per well for all truck traffic needs; these figures assume that all water is
transported by truck rather than by pipeline.
In some states, natural gas production companies have entered into road maintenance
agreements with local government – committing to return the roads to good condition.
Pennsylvania recently enacted a local option impact assessment to provide additional revenue
to counties and towns affected by drilling activity.
Significant increases in truck traffic can lead to an increase in accidents and increased demand
for traffic control. Both place additional demand on police and other emergency services. Given
the volume and nature of the liquids being transported, accident response can be both more
complex and more time‐consuming than a typical one‐ or two‐car accident.
Spills of hazardous chemicals require labor‐ and time‐intensive responses from law
enforcement and environmental agencies. In regions unaccustomed to oil and gas activity, the
specialized nature of the response required for spills, explosions or fires related to the industry
might necessitate new equipment, training and staff. This can place a special strain on rural
areas still served by volunteer fire and rescue services.
As drilling activity has increased in certain parts of the United States, rural areas and small
towns have, in some cases, been overwhelmed by the demand for worker housing. The impact
of gas production on housing costs and availability likely depends on three key factors: 1) the
speed and scale of industry growth in a given community; 2) the existing housing capacity of a
North Carolina Oil and Gas Study April 2012
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community before drilling begins; and 3) the industry’s need to import workers skilled in gas
production activities.
Property owners who control the mineral rights to economically recoverable gas resources
under their land may see substantial increases in property values. Analysis claimed that the
taxable value of oil and gas properties in Texas’ Barnett shale region increased from $341
million to $5.9 billion, a 1,730 percent increase, from 2000‐2005. Other studies of property
values have generally shown much more modest increases.
Increased value can be attributed to two financial benefits to property owners: bonuses upon
signing an oil and gas lease agreement and royalty payments. Lease agreements can range
anywhere from $5 per acre to $20,000 per acre. On properties where lease agreements have
not been signed, potential buyers may factor an expected bonus payment into the value of the
property. Mineral owners receive royalties on income from gas production, typically earning
12.5 percent to 20 percent of the gas revenue generated at their wellhead.
Regulatory Program
The fact that oil and gas production activities are exempt from a number of federal
environmental statutes that otherwise apply to industrial activities places a special burden on
oil and gas‐producing states to create adequate state regulatory programs.
Storage and disposal of oil and gas wastes have been exempted from federal hazardous waste
regulation, specifically to allow states to develop tailored programs for management of those
wastes. Congress has also deferred to the states to regulate stormwater runoff from drilling
sites, exempting those sites from Clean Water Act permitting requirements for construction
stormwater and industrial stormwater discharges.
States that have a long history of oil and gas production typically have very detailed regulations
for well siting, well construction, wastewater disposal, storage and disposal of solid wastes, and
water use. Since North Carolina does not have an active oil and gas industry, the state does not
have standards appropriate for the special nature of these activities and the waste products
generated in the process.
Guidelines for state oil and gas regulatory programs developed by the State Review of Oil and
Natural Gas Environmental Regulations (STRONGER) recommend:
• Standards for casing and cementing sufficient to handle highly pressurized injection of
fluids into a well for purposes of fracturing bedrock and extracting gas.
• Rules requiring the driller to identify potential conduits for fluid migration; address
management of the extent of fracturing; and identify actions to be taken in response to
operational or mechanical problems.
• Standards for dikes, pits and tanks, including contingency planning and spill risk
management procedures.
• Waste characterization, including testing of fracturing fluids. Waste should be tracked to
ensure appropriate disposal.
North Carolina Oil and Gas Study April 2012
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• Prior notification of fracturing activity.
• Assessment of water use for hydraulic fracturing in terms of volume in light of water
supply, competing water uses and the environmental impacts of withdrawing water for
fracturing. Use of alternative water sources and recycling of water should be
encouraged.
Recommendations for siting standards, such as setbacks from streams, wetlands and
floodplains, can be found in the New York Department of Environmental Control EIS and in
recent legislation enacted in Pennsylvania.
In the last three years, a number of states have moved to require disclosure of the chemicals
used in hydraulic fracturing fluids to state regulatory and emergency response agencies. Several
states have also required disclosure to the public with appropriate safeguards for proprietary
information.
Oil and gas producing states have also found it necessary to address the issue of local authority
to regulate natural gas production activities. Several states that have comprehensive state oil
and gas regulatory programs continue to allow local governments to exercise some degree of
planning and zoning authority with respect to production activities.
Conclusions and Recommendations
After reviewing other studies and experiences in oil and gas‐producing states, DENR has
concluded that information available to date suggests that production of natural gas by means
of hydraulic fracturing can be done safely as long as the right protections are in place.
Production of natural gas by means of hydraulic fracturing can only be done safely in North
Carolina if the state adopts adequate safeguards in the form of regulatory standards specifically
adapted to conditions in the state and invests sufficient resources in compliance and
enforcement. Development of appropriate standards will require additional information on
North Carolina’s geology and hydrogeology to identify conditions under which hydraulic
fracturing can be done without putting the state’s water resources at risk. The ban on hydraulic
fracturing and horizontal drilling should remain in effect until both standards and a strong
compliance and enforcement program are in place. Both of these are needed before issuing
permits for hydraulic fracturing in North Carolina’s shale formations. A number of states have
experienced problems associated with natural gas exploration and development because the
appropriate measures were not in place from the beginning – forcing both the state and the
industry to react after damage had already been done.
DENR has identified a number of immediate recommendations for management of natural gas
exploration and development activities. A complete oil and gas permitting program will require
more detailed standards than it is possible to provide in this report and those standards should
be based on conditions in North Carolina. Conditions in the Triassic Basins of North Carolina are
not identical to those found in Pennsylvania or other gas‐producing states. For example, a
better understanding of the depth of usable groundwater in the Triassic Basin will be necessary
to set well construction standards that will adequately protect drinking water resources.
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Based on the research and analysis in this report, the Department of Environment and Natural
Resources, in consultation with the Department of Commerce, developed the following
recommendations for the General Assembly. These recommendations have been revised based
on public comment. It should be noted that these recommendations do not take into account
information from the Department of Justice’s section on consumer protection, because DENR
had not received that section of the report in time for preparation of the recommendations.
A brief description of each recommendation is listed; a more detailed explanation of each
recommendation is included in Section 9. The recommendations are organized by subject
matter but are not listed in order of priority.
Funding recommendations
1. Provide funding for any continued work on the development of a North Carolina
regulatory program for the natural gas industry.
2. Address the distribution of revenues from oil and gas excise taxes and fees to support the
oil and gas regulatory program, fund environmental initiatives, and support local
governments impacted by the industry.
Water and air quality recommendations
3. Collect baseline environmental quality data including groundwater, surface water and air
quality information.
4. Require oil and gas operators to operate in compliance with a DENR‐approved Water and
Wastewater Management Plan. The Water Management Plan should limit water
withdrawals to 20 percent of the 7Q10 stream flow and prohibit withdrawals during times
of drought and periods of low flows.
5. Develop a state stormwater regulatory program for oil and gas drilling sites.
Hydraulic fracturing fluids recommendations
6. Require full disclosure of all hydraulic fracturing chemicals and constituents to regulatory
agencies and to local government emergency response officials prior to drilling. The state
should encourage the industry to fully disclose that same information to the public and
require public disclosure of hydraulic fracturing chemicals and constituents with the
exception of trade secrets already protected under state law.
7. Prohibit the use of diesel fuel in hydraulic fracturing fluids
Waste management standards
8. Develop specific transportation, storage and disposal standards for management of oil
and gas wastes.
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Regulatory program recommendations
9. Develop a modern oil and gas regulatory program, taking into consideration the processes
involved in hydraulic fracturing and horizontal drilling technologies, and long‐term
prevention of physical or economic waste in developing oil and gas resources.
10. Enhance existing oil and gas well construction standards to address the additional
pressures of horizontal drilling and hydraulic fracturing.
11. Develop setback requirements and identify areas (such as floodplains) where oil and gas
exploration and production activities should be prohibited.
12. Close the gaps in regulatory authority over the siting, construction and operation of
gathering pipelines
13. Identify a source of funding for repair of roads damaged by truck traffic and heavy
equipment.
Permitting recommendations
14. Keep the environmental permitting program for oil and gas activities in DENR where it will
benefit from the expertise of state geological staff and the ability to coordinate air, land
and water permitting.
15. Develop a coordinated permitting process.
Data management recommendations
16. Improve data management capabilities and develop an e‐permitting program that is
easily accessible by the public
Emergency response recommendations
17. Ensure that state agencies, local first responders and industry are prepared to respond to
a well blowout, chemical spill or other emergency.
Local government authority recommendations
18. Clarify the extent of local government regulatory authority over oil and gas exploration
and production activities.
Address liability
19. Address the natural gas industry’s liability for environmental contamination caused by
exploration and development, particularly for groundwater contamination.
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Public participation
20. Provide additional opportunities for the public to participate in development of detailed
standards to govern gas exploration and development.
Additional research recommendations
21. Complete additional research on impacts to local governments and local infrastructure.
22. Complete additional research on potential economic impacts.
23. Complete additional research on closed‐loop systems and the potential for prohibiting
open wastewater pits.
24. Complete additional research on the ability of the air toxics program to protect
landowners who lease their land for natural gas extraction and production activities.
25. Complete additional research on air emissions from hydraulic fracturing operations.
26. Complete additional research on the shale gas resource.
27. Complete additional research on groundwater resources in the Triassic Basins.
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Introduction
The North Carolina Geological Survey (NCGS) has identified a potentially valuable natural gas
resource in the Triassic Basins of North Carolina. Preliminary results show that at least 59,000
acres in the Sanford sub‐basin of the Deep River Basin contain organic‐rich shale and coals from
which natural gas can be captured. The NCGS continues to collect and analyze data on the
potential for natural gas resources in the Triassic Basins, including the Dan River Basin and the
other areas of the Deep River Basin. At the same time, the U.S. Geological Survey is working on
an assessment of natural gas resources for all Mesozoic basins along the East Coast, which
includes the Triassic Basins of North Carolina. Results from the USGS assessment will not be
available until the summer of 2012.
In 2011, interest in the potential natural gas resource in North Carolina prompted the North
Carolina General Assembly to direct the North Carolina Department of Environment and
Natural Resources (DENR), the Department of Commerce (Commerce), and the Department of
Justice, in conjunction with the nonprofit Rural Advancement Foundation International (RAFI),
to study the issue of oil and gas exploration in the state and specifically the use of directional
and horizontal drilling and hydraulic fracturing for that purpose.
Session Law 2011‐276 directs DENR to address a number of issues related to the exploration
and production of oil and gas. S.L. 2011‐276 also assigns certain sections of the report to other
departments and organizations. DENR was assigned to report on oil and gas resources present
in the Triassic Basins (Section 1 of this report), methods of exploration and extraction of oil and
gas (Section 2), potential impacts on infrastructure, including roads, pipelines and water and
wastewater services (Section 3), potential environmental and health impacts (Section 4),
potential social impacts (Section 6), and potential oversight and administrative issues
associated with an oil and gas regulatory program (Section 7).
The law directs the Department of Commerce, in consultation with the Department of
Environment and Natural Resources, to gather information on potential economic impacts of
natural gas exploration and development (Section 5 of this report). Commerce prepared
Sections 5.A through 5.F of this report which discusses job creation and other projected
economic impacts of natural gas drilling. DENR prepared Sections 5.G though 5.N which address
the different financial tools (such as bonding requirements and severance taxes) used by oil and
gas producing states to assure funding for reclamation of drilling sites, cover regulatory costs,
and offset public infrastructure costs.
The law directs the Consumer Protection Division of the Department of Justice to study
consumer protection and legal issues relevant to oil and gas exploration in the state, including
matters of contract and property law, mineral leases, and landowner rights (Section 8). The
Consumer Protection Division is directed to consult with RAFI on this section.
Recommendations and limitations are discussed in Section 9 of this report.
North Carolina Oil and Gas Study April 2012
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Section 1 – Potential Oil and Gas Resources
A. Overview of the Triassic Basins
The geologic term “basin” refers to a low area in the earth’s crust, formed by the warping of the
crust from mountain‐building forces, in which sediments have accumulated. The Triassic Basins
in North Carolina are elongated basins bounded by faults along their long sides. These basins
formed 235 to 200 million years ago, during the Triassic Period, when Africa and North America
were beginning to split apart to form the Atlantic Ocean. This type of basin is called a rift valley.
Four Triassic Basins are exposed and outcrop at the earth’s surface in North Carolina: Deep
River, Dan River, Davie and the Ellerbe (see Figure 1‐1). The Dan River Basin is the North
Carolina portion of continuous rift basin that extends from Stokes County northwest across
Rockingham County and into Virginia. In Virginia, the basin is called the Danville.
Figure 1‐1. Exposed North Carolina Triassic Basins
The Deep River is a 150‐mile‐long rift basin that runs from Granville County southwestward
across Durham, Orange, Wake, Chatham, Lee, Moore, Montgomery, Richmond, Anson and
Union counties into South Carolina. The basin is subdivided into three sub‐basins: Durham,
Sanford and Wadesboro. The Ellerbe Basin in Richmond County has been interpreted as an
erosional remnant of the larger Deep River Basin. The areas of these basins are: Davie – 20.04
square miles, Dan River – 152.02 square miles and Deep River – 1,211.07 square miles.
North Carolina Oil and Gas Study April 2012
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The rift basins began to form approximately 210 million years ago with the breakup of the
supercontinent Pangea (a large land mass that divided to become Africa and North America),
which preceded the later opening of the Atlantic Ocean. Dr. Ron Blakey of Northern Arizona
University is a paleogeographer who has reconstructed the shape of the continental
landmasses over time. Figure 1‐2 shows the Triassic paleogeography at the time when rifting
had formed a series of freshwater lakes. At that time, North Carolina was located near the
equator and sediment accumulated within the basins.
Figure 1‐2. Triassic paleogeography approximately 210 million years ago, from Ron Blakey,
NAU Geology. North Carolina can be identified from the current state outlines shown on the
continent.
The Deep River Basin has a steeply dipping eastern border fault. Approximately 7,000 feet of
Triassic strata has been deposited in this basin. The organic shale part of this basin is
interpreted by geologists as shallow lake deposits that are similar to the African Rift Valley
lakes, which are forming as the African tectonic plate is splitting apart today.
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The Piedmont physiographic province included all Triassic or Mesozoic rift basins along the east
coast of the United States: Hartford‐Deerfield (Mass., Conn.), Newark (N.Y., N.J., Pa.),
Gettysburg (Pa., Md.), Culpeper (Md., Va.), Taylorsville (Md., Va.), Richmond (Va.), Dan River‐
Danville (Va., N.C.), and Deep River (N.C., S.C.). Figure 1‐3 illustrates the extent of the Mesozoic
basins. During the Mesozoic era, North Carolina was near the equator.
Figure 1‐3. The Mesozoic Basins of the eastern United States. The city of Raleigh is shown for
reference and the Sanford sub‐basin in outline by a red box.
To better understand the geology within the basin, we can look at a cross‐section or vertical
slice through the earth from the northwest to the southeast across the Sanford sub‐basin of the
Deep River Basin (Figure 1‐4). What this section shows is an up to 800‐foot thick organic‐rich
sedimentary rock (or shale) called the Cumnock Formation. The Cumnock Formation is
sandwiched between the Sanford Formation sandstones above and the Pekin Formation
North Carolina Oil and Gas Study April 2012
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sandstones below. The Cumnock Formation extends more than eight miles across the sub‐basin.
Figure 1‐4. Cross‐section from northwest to southeast across the Sanford sub‐basin.
Four of the eight oil and gas exploration wells drilled in the Sanford sub‐basin are located along
Seismic Section 113, which is parallel to the published cross‐section in Figure 1‐4. The depths
from the surface to the top of the Cumnock formation for those four wells are: Butler #1 –
1,960 feet; Simpson #1 – 2,380 feet; V.R. Gross – 2,360 feet; and Bobby Hall – 4,190 feet.
As early as the Revolutionary War period, the Deep River Basin was known to produce coal.
Underground coal mining occurred in the 1920s to 1940s. A 1925 mine explosion in Farmville,
N.C., which killed 53 miners, was blamed in part on excess coal gas.
In 1974, a division of Chevron drilled the first oil exploration well (V.R. Gross LE‐OT‐1‐74) in Lee
County. In 1981, North American Exploration Inc. drilled six coal exploration holes in Moore (4)
and Chatham (2) counties, and in 1982, Richard Beutel and Associates drilled the first coal‐bed
methane exploration well (Dummit‐Palmer LE‐OT‐1‐82). In 1983, Seaboard Exploration and
Production Company drilled two more wells (Butler #1 LE‐OT‐1‐83 and Bobby Hall #1 LE‐OT‐2‐
83).
In 1985 and 1986, seismic reflection lines that crisscrossed the sub‐basin were collected to
provide better target selection for future drilling. The location for the seismic lines, especially
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the down dip section (Line 113) was configured to pass as close as possible to the locations of
prior unsuccessful wells (Dummit‐Palmer, V.R. Gross and Bobby Hall #1). The seismic data had
not been fully processed in 1987 when Sanford Exploration drilled the Elizabeth Gregson #1 (LE‐OT‐
1‐87) well; that well missed the entire organic shale formation.
Four years passed before Equitable Resources Exploration drilled Butler #2 (LE‐OT‐1‐91) in
1991, along the Seismic Line 113. Again the results from the well gave indications of modest oil
and/or gas shows, but not a potential conventional oil or gas resource.
In 1998, Amvest drilled two wells, one located along Seismic Line 113 (Simpson #1 LE‐OT‐1‐98)
and the other several miles off the line (Butler #3). Both wells were perforated and Amvest
attempted to hydraulically fracture the wells using nitrogen foam. That fracturing effort was
unsuccessful in both wells, but the wells flowed gas and Amvest placed a wellhead containing
several pressure shut‐off valves (also known as a Christmas tree) on each completed well.
Eleven years later in March 2009, the two wells were sampled for natural gas and pressure
tested. The pressure at the Simpson #1 well was 250 pounds per square inch (psi) and the
pressure at Butler #3 was 900 psi.
B. Organic geochemical data
In 2008, Jeffrey Reid and Robert Milici published the organic geochemical data for the Deep
River in the United States Geological Survey (USGS) Open File Report 2008‐1108.1 This report
marked the first recognition by the North Carolina Geological Survey (NCGS) of this thick
section of organic shale as a potential gas resource. The next year, the NCGS published
“Information Circular 36: Natural Gas and Oil in North Carolina.”2 That same year, the NCGS
issued Open‐File Report 2009‐013 and gas samples were taken from both shut‐in wells, Simpson
#1 and Butler #3. NCGS made a series of presentations and briefings to interested industry,
governmental and environmental groups in 2009 and 2010.
For the successful commercial production of oil and gas, geologists look at three indicators in
the shale: total organic carbon (TOC), kerogen type and thermal maturity. TOC is indicative of
the quantity of organic matter available for the formation of hydrocarbons.
Kerogen type is an indication of the type of organic matter. When organic matter is buried in a
basin, it is exposed to increasingly higher subsurface temperatures. When heated to
temperatures of approximately 60°C or higher, kerogen yields bitumen – the fraction of organic
matter that is soluble in organic solvents. Further heating then creates liquid hydrocarbons and
hydrocarbon gas. Oil is produced within a certain temperature range, called the “oil window.”
As temperatures increase beyond the oil window, the hydrocarbons are cracked into natural
1Reid, Jeffrey C. and Robert C. Milici. “Hydrocarbon Source Rocks in the Deep River and Dan River Triassic Basins,
North Carolina.” U.S. Geological Survey Open‐File Report 2008‐1108.
2North Carolina Geological Survey. “Information Circular 36: Natural Gas and Oil in North Carolina.”
http://www.geology.enr.state.nc.us/pubs/PDF/NCGS_IC_36_Oil_and_Gas.pdf
3Reid, Jeffrey C. and Kenneth B. Taylor. “Shale Gas Potential in Triassic Strata of the Deep River Basin, Lee and
Chatham Counties, North Carolina with pipeline and infrastructure data.” North Carolina Geological Survey Open‐file
Report 2009‐01.
North Carolina Oil and Gas Study April 2012
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gas. Type I kerogen indicates lake deposits with oil prone rocks. Type II indicates marine
deposits with oil prone rocks. Type III indicates gas prone source rocks.4
Thermal maturity dictates the wetness of the gas. Natural gas that contains less methane and
more ethane and other complex hydrocarbons is called wet gas. Natural gas that occurs
without these liquid hydrocarbons is called dry gas. Table 1‐1 below shows the stages of
thermal maturity.
Table 1‐1. Stages of Thermal Maturity5
Stage of Thermal
Maturity
Temperature Process Product
Immature <60°C
Bacterial and plant organic
matter converted to
kerogens and bitumen
Methane generated by
microbial activity
Mature 60°C ‐ 160°C
Rock generates and expels
most of its oil
Oil
Postmature >160°C
Postmature for oil/mature
for gas
Condensate / wet gas and
at higher temperatures,
dry gas only
Thermal maturity of sedimentary rocks is evaluated based on vitrinite reflectance values (%Ro),
thermal alteration and a parameter called T max. Vitrinite reflectance is a measure of the
amount of light reflected by vitrinite (an organic component of kerogens) when examined
under a microscope. Vitrinite reflectance is used as a measure of thermal maturity because it is
sensitive to temperature ranges in a way that corresponds to hydrocarbon generation. It is
measured by immersing grains of vitrinite in oil, and it is expressed as percent reflectance in oil,
Ro. Table 1‐2 shows thermal maturity based on vitrinite reflectance values.
Table 1‐2. Interpreted Maturation Based on Vitrinite Reflectance Values6
Vitrinite Reflectance (%Ro) Thermal Maturity
<0.60 Immature
0.60 – 1.00 Oil window
1.00 – 1.40 Condensate / wet gas window
>1.40 Dry gas window
4Jarvie, Dan. “Evaluation of Hydrocarbon Generation and Storage in the Barnet Shale, Ft. Worth Basin, Texas.”
Humble Instruments & Services, Inc. 2004. Accessed February 19, 2012.
http://blumtexas.tripod.com/sitebuildercontent/sitebuilderfiles/humblebarnettshaleprespttc.pdf
5Pennsylvania Department of Conservation and Natural Resources. “Thermal Maturation and Petroleum
Generation.” Accessed February 19, 2012.
http://www.dcnr.state.pa.us/topogeo/oilandgas/sourcerock_maturation.aspx.
6Jarvie, 2004.
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Tmax is the temperature at which the maximum release of hydrocarbons from cracking of
kerogen occurs during organic decomposition. Tmax indicates the stage of maturation of the
organic matter.
Analysis of the organic‐rich lake sediments in the Triassic Basin showed that they are
predominantly gas‐prone with some oil shows. The TOC data exceeds the conservative 1.4
percent threshold necessary for hydrocarbon expulsion (Figure 1‐5). The average TOC for the
samples tested from the eight wells is 5.06 percent, 3.6 times the 1.4 percent threshold.7
Figure 1‐5.Total Organic Carbon (TOC) as a percentage for samples from eight wells (seven
coal holes and one oil test hole).
Geochemical laboratory tests also showed the organic matter is derived from terrestrial Type III
woody (coaly) material and from lacustrine Type I (algal material), which is a preliminary
indicator for wet gas (natural gas with light oil condensates). The quantity of potential gas
volumes or the potential gas condensates is unknown from the geochemical test.
The thermal alteration index (TAI) data, which is used to determine the temperature rock has
attained during its history, combined with the vitrinite reflectance data for the sediments in the
7 Reid and Milici, 2008.
North Carolina Oil and Gas Study April 2012
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Triassic Basin, indicate levels of thermal maturity suitable to generate hydrocarbons. The
maturity for a composite of data from five wells is shown in Figure 1‐6. Samples from the
Dummit‐Palmer well range from immature to overmature. This well was located near a diabase
dike – an intrusion of molten magma into the sedimentary basin shortly after the basin formed.
The diabase heated the organic‐rich shale and caused the hydrocarbons to be “overcooked;” as
a result, these shales would not be suitable for the commercial production of oil or gas. For
samples from the U.S. Bureau of Mines coal exploration hole #2, the data are clustering in the
oil window to the condensate‐wet gas zone. For data from the Simpson #1 well, more samples
are in the condensate‐wet gas zone.
Figure 1‐6. Maturity (Tmax) for multiple wells. These data are color‐coded to the five wells.
Combining the organic geochemical data with the interpretation of the 1985‐86 seismic data
delineated a potential target location with an area of more than 59,000 acres, which is shown in
Figure 1‐7. This compilation map shows the location of seismic lines, detailed geologic mapping
from Reinemund (1947, 1955), the location of the coal mines, coal exploration holes, oil and gas
test wells and the two interpreted geologic cross‐sections by Reinemund.
The hill shade relief topography that forms the bottom layer of this figure is derived from LiDAR
(Light Detection and Ranging), a remote sensing technology that illuminates targets with light.
The LiDAR was collected by the N.C. Floodplain Mapping Program in 2002. Several igneous
North Carolina Oil and Gas Study April 2012
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intrusive bodies (diabase dikes) are shown in red on the geologic map. The elevation tends to
follow the diabase dikes, since these rocks weather quickly, but the ridges along their length are
due to the baking of the country rock.
Figure 1‐7. Map of part of the Sanford sub‐basin showing the seismic lines (yellow), the coal
mine locations, coal exploration holes and oil and gas test wells. The red line shows the
approximately 59,000 acres where the vitrinite reflectance (%Ro) is greater than or equal to
0.8. The underlying geologic map is from Reinemund (1955) and the hill shade elevation is
from LiDAR (N.C. Floodplain Mapping, 2002). The two green lines that run from the northwest
to southeast on the map are the locations of two geologic cross‐sections A – A’ and B – B’
constructed by Reinemund (1955).
In 1978 and 1979, the U.S. Army Corps of Engineers (USACE) contracted with N.C. State
University and later with the University of North Carolina at Chapel Hill to investigate potential
groundwater resources in the land adjacent to the future site of the Jordan Lake. During those
investigations, the USACE was looking for groundwater resources in the diabase dikes to sustain
potable water usage by campers at campsites around the lake.
The intrusion of the diabase dikes and sills at temperatures of 1,200 degrees Fahrenheit baked
the country rock, which significantly reduced the country rock’s permeability. As the diabase
cooled, cracks formed inside the dikes and sills, which provided avenues for water to further
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weather the diabase. This process provides the potential for a tabular body of groundwater to
be held by the country rock like a cistern.
Using hand‐held proton precession magnetometers, students from the two schools collected
data from dozens of traverses to find and map the dike locations. Profiles across the dikes were
analyzed to determine the dike orientation. Next, electrical resistivity profiles were collected to
determine if there were indicators of groundwater in the weathered dikes.
For dikes with the lowest resistivity measurements, USACE contractors drilled test wells and
conducted pump tests to assess potential groundwater resources. While both schools found
groundwater in the diabase dikes, the resources were insufficient to support the proposed
number of campsites. Today, dikes in the Triassic basins are sometimes a source of
groundwater. The country rock within about half of the thickness of the dike or sill is altered by
the intrusive heat and will become less permeable. Any oil and gas within those zones is
destroyed. It is unclear at this time if natural gas exploration companies would see advantages
in drilling near the diabase dikes and sills. While several peer‐reviewed studies on gas migration
in Pennsylvania have been published on the migration of thermogenic methane from deep
sources such as the Marcellus and the Utica shales, current data for northeastern Pennsylvania
shows the thermogenic methane is sources from the upper Devonian Catskill Formation, not
the deeper sources.8 Three‐dimensional seismic reflection data, some collected using three‐component
geophones, would provide the best indicator of the presence of dikes, sills and
faults. This information would assist the state by providing a better understanding of the
structure of the Triassic rocks.
To better understand the geometry and structure of the Sanford sub‐basin, Figure 1‐8 shows
the depth to basement. This map is calculated from the depth to the metamorphic and igneous
rocks that are under the Mesozoic sediments. The thickness of the organic‐rich shale is shown
in Figure 1‐9. Both of these maps are plotted using meters (30 meters ~ 100 feet).
8 Molofsky, Lisa J, J.A. Connor, S. K. Farhat, A.S. Wylie, Jr., T. Wagner (2011). Methane in Pennsylvania water wells
unrelated to Marcellus shale fracturing , Oil and Gas Journal (December 5, 2011 edition), 12 pp.
North Carolina Oil and Gas Study April 2012
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Figure 1‐8. Map of the depth to basement of the Sanford sub‐basin. The dark blue to purple
region, which is under Seismic Line 113, indicates the deepest part of the basin is 7,100 feet
below the surface. Another deep point in the sub‐basin is found in Moore County. The units
are in meters and each color ramp indicates 100 meters (i.e. ~300 feet).
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Figure 1‐9. Map of the thickness of the organic‐rich shale (Cumnock Formation) in the Sanford
sub‐basin. The units are in meters and the average thickness ranges from 60 meters (~180
feet) to 180 meters (~540 feet).
C. Estimating the resources
2012 USGS resource assessment
In 2010, DENR provided data collected and analyzed by the North Carolina Geological Survey to
the U.S. Geological Survey (USGS) for use in a national resource assessment of Mesozoic basins
across the United States. USGS provided a modest grant to the N.C. Geological Survey to
convert paper records in the NCGS archive (geophysical logs, maps, reports, seismic lines,
geochemical analyses and lithologic logs) to digital form.
The N.C. Geological Survey completed conversion and analysis of the information in December
2010. On July 12‐13, 2011, Dr. Jeff Reid, the principal research geologist on this project, and Mr.
Jim Simons, State Geologist, briefed USGS on the North Carolina data as part of the USGS
geological assessment of Mesozoic resources.
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Gas Resource Terms
Technically recoverable gas:
The total amount of a
resource, both discovered
and undiscovered, that is
thought to be recoverable
with available technology,
regardless of economics.
Only about 20 percent of this
gas can actually be recovered
using today’s technology.
Original gas‐in‐place: The
entire volume of gas
contained in the reservoir,
reg