United States Office of Water EPA-821-R-15-003
Environmental Protection Washington, DC 20460 March 2015
Agency
&EPA Technical Development
Document for Proposed
Effluent Limitations
Guidelines and Standards
for Oil and Gas Extraction
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&EPA
United States
Environmental Protection
Agency
Technical Development Document for
Proposed Effluent Limitations Guidelines
and Standards for Oil and Gas Extraction
EPA-821-R-15-003
March 2015
U.S. Environmental Protection Agency
Office of Water (4303T)
Washington, DC 20460
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Acknowledgements and Disclaimer
This document was prepared by the Environmental Protection Agency. Neither the United States
Government nor any of its employees, contractors, subcontractors, or their employees make any
warrant, expressed or implied, or assume any legal liability or responsibility for any third party's
use of or the results of such use of any information, apparatus, product, or process discussed in
this report, or represents that its use by such party would not infringe on privately owned rights.
Questions regarding this document should be directed to:
U.S. EPA Engineering and Analysis Division (4303T)
1200 Pennsylvania Avenue NW
Washington, DC 20460
(202) 566-1000
in
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Table of Contents
TABLE OF CONTENTS
Page
CHAPTER A. INTRODUCTION 1
1 Background on Oil and Gas Extraction 1
2 Existing Discharge Regulations for Oil and Gas Extraction Facility Wastewater 3
2.1 Federal Regulations 3
2.2 State Pretreatment Requirements That Apply to UOG Extraction
Wastewater 9
3 Related Federal Requirements 14
CHAPTER B. BACKGROUND ON UNCONVENTIONAL OIL AND GAS EXTRACTION 15
1 Overview of UOG Resources 15
1.1 How UOG Resources Were Formed 18
1.2 Geological Characteristics of UOG Resources 19
2 UOG Well Development Process 20
2.1 UOG Well Drilling and Construction 21
2.2 UOG Well Completion 24
2.3 Production 29
3 UOG Well Drilling and Completion Activity 30
3.1 Historical and Current UOG Drilling Activity 30
3.2 UOG Resource Potential 34
3.3 Current and Projections of Future UOG Well Completions 35
CHAPTER C. UNCONVENTIONAL OIL AND GAS EXTRACTION WASTEWATER VOLUMES
AND CHARACTERISTICS 37
1 Fracturing Fluid Characteristics 39
1.1 Base Fluid Composition 39
1.2 Additives 40
1.3 Fracturing Fluids 44
2 UOG Extraction Wastewater Volumes 44
2.1 UOG Extraction Wastewater Volumes by Resource and Well Trajectory 45
2.2 UOG Produced Water Volumes by Formation 50
3 UOG Extraction Wastewater Characterization 55
3.1 Availability of Data for UOG Extraction Wastewater Characterization 55
3.2 UOG Extraction Wastewater Constituent Categories 56
3.3 UOG Produced Water Characterization Changes over Time 75
CHAPTER D. UOG EXTRACTION WASTEWATER MANAGEMENT AND DISPOSAL
PRACTICES 77
iv
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Table of Contents
CONTENTS (Continued)
Page
1 Overview of UOG Extraction Wastewater Management and Disposal Practices 77
2 Injection into Disposal Wells 84
2.1 Regulatory Framework for Underground Injection 84
2.2 Active Disposal Wells and Volumes 85
2.3 Underground Injection Considerations 86
3 Reuse/Recycle in Fracturing 87
3.1 Reuse/Recycle Strategies 89
3.2 Reuse/Recycle Drivers 92
3.3 Other Considerations for Reuse/Recycle 96
4 Transferto CWT Facilities 98
4.1 Types of CWT Facilities 98
4.2 Active CWT Facilities Accepting UOG Extraction Wastewater 100
5 Discharge to POTWs 102
5.1 POTW Background and Treatment Levels 103
5.2 History of POTW Acceptance of UOG Extraction Wastewater 106
5.3 How UOG Extraction Wastewater Constituents Interact with POTWs Ill
CHAPTERE. REFERENCE FLAGS AND LIST 146
CHAPTERF. APPENDICES 161
Appendix F.I Reference Files in FDMS 161
Appendix F.2 UOG Resource Potential by Shale and Tight Formations 172
Appendix F.3 Constituent Concentrations over Time in UOG Produced Water from
Marcellus andBarnett Shale Formations 175
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List of Tables
LIST OF TABLES
Page
Table A-l. Summary of State Regulations 11
Table B-l. Characteristics of Reservoirs Containing UOG and COG Resources 20
Table B-2. Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product
Type (as of November 8, 2013) 33
Table B-3. UOG Potential by Resource Type as of January 1, 2012 35
Table C-l. Sources for Base Fluid in Hydraulic Fracturing 40
Table C-2. Fracturing Fluid Additives, Main Compounds, and Common Uses 41
Table C-3. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in
GasandOilWellsfromFracFocus(2011-2013) 43
Table C-4. Median Drilling Wastewater Volumes for UOG Horizontal and Vertical Wells
in Pennsylvania 47
Table C-5. Drilling Wastewater Volumes Generated per Well by UOG Formation 48
Table C-6. UOG Well Flowback Recovery by Resource Type and Well Trajectory 49
Table C-7. Long-Term Produced Water Generation Rates by Resource Type and Well
Trajectory 50
Table C-8. Produced Water Volume Generation by UOG Formation 51
Table C-9. Availability of Data for UOG Extraction Wastewater Characterization 55
Table C-10. Concentrations of Select Classical and Conventional Constituents in UOG
Drilling Wastewater from Marcellus Shale Formation Wells 57
Table C-l 1. Concentrations of Select Classical and Conventional Constituents in UOG
Produced Water 58
Table C-12. Concentrations of Select Anions and Cations Contributing to TDS in UOG
Drilling Wastewater from Marcellus Shale Formation Wells 63
Table C-13. Concentrations of Select Anions and Cations Contributing to TDS in UOG
Produced Water 64
Table C-14. Concentrations of Select Organic Constituents in UOG Drilling Wastewater
from Marcellus Shale Formation Wells 65
Table C-15. Concentrations of Select Organic Constituents in UOG Produced Water 66
Table C-16. Concentrations of Select Metal Constituents in UOG Drilling Wastewater
from Marcellus Shale Formation Wells 68
VI
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List of Tables
LIST OF TABLES (Continued)
Page
Table C-17. Concentrations of Select Metal Constituents in UOG Produced Water 69
Table C-18. Concentrations of Select Radioactive Constituents in UOG Drilling
Wastewater from Marcellus Shale Formation Wells 72
Table C-19. Concentrations of Select Radioactive Constituents in UOG Produced Water 72
Table C-20. Concentrations of Radioactive Constituents in Rivers, Lakes, Groundwater,
and Drinking Water Sources Throughout the United States (pCi/L) 73
Table D-l. UOG Produced Water Management Practices 81
Table D-2. Distribution of Active Class II Disposal Wells Across the United States 85
Table D-3. Reuse/Recycle Practices in 2012 as a Percentage of Total Produced Water
Generated as Reported by Respondents to 2012 Survey 88
Table D-4. Reported Reuse/Recycle Criteria 94
Table D-5. Reported Reuse/Recycle Practices as a Percentage of Total Fracturing
Volume 95
Table D-6. Number, by State, of CWT Facilities That Have Accepted or Plan to Accept
UOG Extraction Wastewater 101
Table D-7. Typical Composition of Untreated Domestic Wastewater 103
Table D-8. Typical Percent Removal Capabilities from POTWs with Secondary
Treatment 105
Table D-9. U.S. POTWs by Treatment Level in 2008 105
Table D-10. POTWs That Accepted UOG Extraction Wastewater from Onshore UOG
Operators 108
Table D-l 1. Percentage of Total POTW Influent Wastewater Composed of UOG
Extraction Wastewater at POTWs Accepting Wastewater from UOG
Operators 110
Table D-12. Summary of Studies About POTWs Receiving Oil and Gas Extraction
Wastewater Pollutants 112
Table D-13. Clairton Influent Oil and Gas Extraction Wastewater Characteristics 116
Table D-14. Trucked COG Extraction Wastewater Treated at McKeesport POTW from
November 1 Through 7, 2008 117
Table D-l5. McKeesport POTW Removal Rates Calculated for Local Limits Analysis 118
vn
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List of Tables
LIST OF TABLES (Continued)
Page
Table D-16. Constituent Concentrations in UOG Extraction Wastewater Treated at the
McKeesport POTW Before Mixing with Other Influent Wastewater 119
Table D-17. McKeesport POTW Effluent Concentrations With and Without UOG
Extraction Wastewater 120
Table D-18. Charleroi POTW Paired Influent/Effluent Data and Calculated Removal
Rates 122
Table D-19. Franklin Township POTW Effluent Concentrations With and Without
Industrial Discharges from the Tri-County CWT Facility 125
Table D-20. TDS Concentrations in Baseline and Pilot Study Wastewater Samples at
Warren POTW 128
Table D-21. EPA Region 5 Compliance Inspection Sampling Data 128
Table D-22. Inhibition Threshold Levels for Various Treatment Processes3 130
Table D-23. Industrial Wastewater Volumes Received by New Castle POTW (2007-
2009) 135
Table D-24. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW
(NPDES Permit Number PA0027511) 136
Table D-25. Concentrations of DBFs in Effluent Discharges at One POTW Not
Accepting Oil and Gas Wastewater and at Two POTWs Accepting Oil and
Gas Wastewater (|ig/L) 142
Table E-l. Source List 146
Table F-l. TDD Supporting Memoranda and Other Relevant Documents Available in
FDMS 161
Table F-2. Crosswalk Between TDD and Supporting Memoranda 163
Table F-3. UOG Resource Potential: Shale as of January 1,2012 172
Table F-4. UOG Resource Potential: Tight as of January 1,2012 173
Vlll
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List of Figures
LIST OF FIGURES
Page
Figure A-l. UOG Extraction Wastewater 2
Figure B-l. Historical and Projected Oil Production by Resource Type 16
Figure B-2. Historical and Projected Natural Gas Production by Resource Type 17
Figure B-3. Major U.S. Shale Plays (Updated May 9, 2011) 17
Figure B-4. Major U.S. Tight Plays (Updated June 6, 2010) 18
Figure B-5. Geology of Formations Containing Various Hydrocarbons 19
Figure B-6. Horizontal (A), Vertical (B), and Directional (C) Drilling Schematic 22
Figure B-7. Length of Time to Drill a Well in Various UOG Formations as Reported for
the First Quarter of 2012 through the Third Quarter of 2013 24
Figure B-8. Hydraulic Fracturing Schematic 26
Figure B-9. Freshwater Impoundment 27
Figure B-10. Vertical Gas and Water Separator 28
Figure B-ll. Fracturing Tanks 29
Figure B-12. Produced Water Storage Tanks 30
Figure B-l3. Number of Active U.S. Onshore Rigs by Trajectory and Product Type over
Time 31
Figure B-14. Projections of UOG Well Completions 36
Figure C-l. UOG Extraction Wastewater Volumes for Marcellus Shale Wells in
Pennsylvania (2004-2013) 46
Figure C-2. Ranges of Typical Produced Water Generation Rates over Time After
Fracturing 47
Figure C-3. Anions and Cations Contributing to TDS Concentrations in Shale and Tight
Oil and Gas Formations 61
Figure C-4. Chloride, Sodium, and Calcium Concentrations in Flowback and Long-Term
Produced Water (LTPW) from Shale and Tight Oil and Gas Formations 62
Figure C-5. Barium Concentrations in UOG Produced Water from Shale and Tight Oil
and Gas Formations 71
Figure C-6. Constituent Concentrations over Time in UOG Produced Water from the
Marcellus and Barnett Shale Formations 76
Figure D-l. UOG Produced Water Management Methods 78
ix
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List of Figures
LIST OF FIGURES (Continued)
Page
Figure D-2. UOG Drilling Wastewater Management Methods 78
Figure D-3. Management of UOG Drilling Wastewater Generated by UOG Wells in
Pennsylvania (2008-2013) 82
Figure D-4. Active Disposal Wells and CWT Facilities Identified in the Appalachian
Basin 83
Figure D-5. Flow Diagram of On-the-Fly UOG Produced Water Treatment for
Reuse/Recycle 91
Figure D-6. Hypothetical UOG Produced Water Generation and Base Fracturing Fluid
Demand over Time 96
Figure D-7. UOG Extraction Wastewater Management Practices Used in the Marcellus
Shale (Top: Southwestern Region; Bottom: Northeastern Region) 97
Figure D-8. Number of Known Active CWT Facilities over Time in the Marcellus and
Utica Shale Formations 102
Figure D-9. Typical Process Flow Diagram at aPOTW 104
Figure D-10. Clairton POTW: Technical Evaluation of Treatment Processes' Ability to
Remove Chlorides and TDS 115
Figure D-l 1. McKeesport POTW: Technical Evaluation of Treatment Processes' Ability
to Remove Chlorides and TDS 117
Figure D-12. Ridgway POTW: Annual Average Daily Effluent Concentrations and
POTW Flows 121
Figure D-l3. Johnstown POTW: Annual Average Daily Effluent Concentrations and
POTW Flows 132
Figure D-14. California POTW: Annual Average Daily Effluent Concentrations and
POTW Flows 133
Figure D-l5. Charleroi POTW: Annual Average Daily Effluent Concentrations and
POTW Flows 134
Figure D-16. Barium Sulfate Scaling in Haynesville Shale Pipe 139
Figure D-17. THM Speciation in a Water Treatment Plant (1999-2013) 144
Figure F-l. Constituent Concentrations over Time in UOG Produced Water from the
Marcellus and Barnett Shale Formations 175
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Abbreviations
AO
API
Bcf
BDL
BOD 5
BPD
BPT
CaCO3
CBM
Ci
CIU
COD
COG
CWA
CWT
DBF
DMR
DOE
EIA
ELGs
EPA
EUR
gpd
IU
LTPW
MG
MGD
mg/L
MIDEQ
NORM
OHDNR
ORD
PADEP
pCi
PESA
POTW
SIU
SRB
TDD
IDS
TENORM
THM
TOC
TRR
ABBREVIATIONS
Administrative Order
American Petroleum Institute
billion cubic feet
below method detection limit
biochemical oxygen demand
barrels per day
best practicable control technology currently available
calcium carbonate
coalbed methane
curie
categorical industrial user
chemical oxygen demand
conventional oil and gas
Clean Water Act
centralized waste treatment
disinfection byproduct
discharge monitoring report
Department of Energy
Energy Information Administration
Effluent Limitations Guidelines and Standards
U.S. Environmental Protection Agency
estimated ultimate recovery
gallons per day
industrial user
long-term produced water
million gallons
million gallons per day
milligrams per liter
Michigan Department of Environmental Quality
naturally occurring radioactive material
Ohio Department of Natural Resources
Office of Research and Development
Pennsylvania Department of Environmental Protection
picocurie
Petroleum Equipment Suppliers Association
publicly owned treatment works
significant industrial user
sulfate-reducing bacteria
technical development document
total dissolved solids
technologically-enhanced naturally occurring radioactive material
trihalomethane
total organic carbon
technically recoverable resource
XI
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Abbreviations
ABBREVIATIONS (Continued)
UIC underground injection control
UOG unconventional oil and gas
USGS U.S. Geological Survey
UV ultraviolet
WV DEP West Virginia Department of Environmental Protection
xn
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Glossary
Base fluid
Biochemical oxygen
demand (BOD5)
Centralized waste
treatment (CWT) facility
Chemical oxygen demand
(COD)
Class IIUIC disposal well
Class II UIC enhanced
recovery well
Conventional oil and gas
(COG) resources
Drill cuttings
Drilling fluid
Drilling wastewater
GLOSSARY1
The primary component of fracturing fluid to which proppant
(sand) and chemicals are added. Base fluids are typically water-
based; however there are cases of non-aqueous fracturing fluids
(e.g., compressed nitrogen, propane, carbon dioxide). Water-based
fluid can consist of only fresh water or a mixture of fresh water,
brackish water and/or reused/recycled wastewater.
The amount of oxygen consumed by biodegradation processes
during a standardized test. The test usually involves degradation
of organic matter in a discarded waste or an effluent.
Standard Method 5210 B-2001, USGS 1-1578-78, and an AOAC
method.
Any facility that treats (for disposal, recycling or recovery of
material) any hazardous or nonhazardous industrial wastes,
hazardous or non-hazardous industrial wastewater, and/or used
material received from offsite.
The amount of oxygen needed to oxidize reactive chemicals in a
water system, typically determined by a standardized test
procedure.
Standard Method 5220 (B-D)-1997, ASTM D1252-06 (A), EPA
Method 410.3 (Rev. 1978), USGS 1-3560-85, and an AOAC
method.
A well that injects brines and other fluids associated with the
production of oil and natural gas or natural gas storage operations.
Class II disposal wells can only be used to dispose of fluids
associated with oil and gas production.
A well that injects brine, water, steam, polymers, or carbon
dioxide into oil-bearing formations to recover residual oil and—in
some limited applications—natural gas. This is also known as
secondary or tertiary recovery.
Crude oil and natural gas that is produced by a well drilled into a
geologic formation in which the reservoir and fluid characteristics
permit the oil and natural gas to readily flow to the wellbore
The particles generated by drilling into subsurface geologic
formations and carried out from the wellbore with the drilling
fluid.
The circulating fluid (e.g., mud) used in the rotary drilling of
wells to clean and condition the hole and to counterbalance
formation pressure.
The liquid waste stream separated from recovered drilling fluid
(e.g., mud) and drill cuttings.
1 The definitions of terms in the Glossary are only meant to apply to the terms as used throughout the Technical
Development Document for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction
(TDD) and the TDD supporting documentation.
Xlll
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Glossary
Flowback
Formation water
Hydraulic fracturing
Hydraulic fracturing fluid
Long-term produced
water (LTPW)
Naturally occurring
radioactive material
(NORM)
Non-TDS removal
technologies
Produced sand
Produced water (brine)
Proppant
Publicly owned treatment
works (POTW)
Source water
GLOSSARY (Continued)
The produced water generated in the initial period after hydraulic
fracturing prior to production (i.e., fracturing fluid, injection
water, any chemicals added downhole, varying amounts of
formation water). See long-term produced water.
Water that occurs naturally within the pores of rock.
Fracturing of rock at depth with fluid pressure. Hydraulic
fracturing at depth may be accomplished by pumping water or
other liquid or gaseous fluid into a well at high pressures.
The fluid, consisting of a base fluid and chemical additives, used
to fracture rock in the hydraulic fracturing process. Hydraulic
fracturing fluids are used to initiate and/or expand fractures, as
well as to transport proppant into fractures. See base fluid.
The produced water generated during the production phase of the
well after the initial flowback process (includes increasing
amounts of formation water).
Material that contains radionuclides at concentrations found in
nature.
See also technologically-enhanced radioactive material
(TENORM)
Technologies that remove non-dissolved constituents from
wastewater.
The slurried particles used in hydraulic fracturing, the
accumulated formation sands, and scales particles generated
during production. Produced sand also includes desander
discharge from the produced water waste stream, and blowdown
of the water phase from the produced water treating system.
The water (brine) brought up from the hydrocarbon-bearing strata
during the extraction of oil and gas, and can include formation
water, injection water, and any chemicals added downhole or
during the oil/water separation process.
A granular substance (e.g., sand grains, aluminum pellets) that is
carried in suspension by the fracturing fluid and that serves to
keep the cracks open when fracturing fluid is withdrawn after a
fracture treatment.
Any device and system used in the storage, treatment, recycling
and reclamation of municipal sewage or industrial wastes of a
liquid nature that is owned by a state or municipality. This
definition includes sewers, pipes, or other conveyances only if
they convey wastewater to a POTW providing treatment.
Water used to make up base fluid in hydraulic fracturing
operations. Examples include surface water (e.g., ponds, rivers,
lakes), ground water, reused/recycled oil and gas extraction
wastewater, and treated industrial and municipal wastewater.
xiv
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Glossary
TDS removal technologies
Technologically-enhanced
naturally occurring
radioactive material
(TENORM)
Total dissolved solids
(TDS)
Total organic carbon
(TOC)
Total suspended solids
(TSS)
Unconventional oil and
gas (UOG)
UOG extraction
wastewater
GLOSSARY (Continued)
Technologies capable of removing dissolved constituents (e.g.,
sodium, chloride, calcium) in addition to the constituents removed
by non-TDS removal technologies.
Naturally occurring radionuclides that human activity has
concentrated or exposed to the environment.
A measure of the matter, including salts (e.g., sodium, chloride,
nitrate), organic matter, and minerals dissolved in water.
Standard Method 2540C-1997, ASTM D5907-03, and USGS I-
1750-85.
The concentration of organic material in a sample as represented
by the weight percent of organic carbon.
Standard Method 5310 (B-D)-2000, ASTM D7573-09 and
D4839-03, an AOAC method, and a USGS method.
The matter that remains as residue upon evaporation. Suspended
solids include the settable solids that will settle to the bottom of a
cone-shaped container in a 60 minute period.
Standard Method 2540 D-1997, ASTM D5907-03, and USGS I-
3765-85.
Crude oil and natural gas produced by a well drilled into a low
porosity, low permeability formation (including, but not limited
to, shale gas, shale oil, tight gas, tight oil). For the purpose of the
proposed rule, the definition of UOG does not include CBM.
Wastewater sources associated with production, field exploration,
drilling, well completion, or well treatment for unconventional oil
and gas extraction (e.g., drilling muds, drill cuttings, produced
sand, produced water).
xv
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Chapter A—Introduction
Chapter A. INTRODUCTION
1 BACKGROUND ON OIL AND GAS EXTRACTION
Recent advances in well development that combine hydraulic fracturing and horizontal
drilling have dramatically improved the technical and economic feasibility of oil and gas
extraction from unconventional resources. As a result, in 2012, United States (U.S.) crude oil and
natural gas production reached their highest levels in more than 15 and 30 years, respectively.
The U.S. Department of Energy (DOE) reports these increases to be a direct result of advances in
hydraulic fracturing and horizontal drilling. Further, the DOE projects that natural gas production
in the U.S. will increase by 56 percent by 2040, compared to 2012 production levels. Similarly,
the DOE projects that by 2019, crude oil production in the U.S. will increase by 48 percent
compared to 2012 production levels (31 DCN SGE00989).
This technical development document (TDD) provides background information and data
considered in the development of revised effluent limitations guidelines and standards (ELGs)
proposed for the Oil and Gas Extraction point source category to address discharges from
unconventional oil and gas (UOG) extraction facilities to municipal wastewater treatment plants.
UOG consists of crude oil and natural gas produced by wells drilled into a low porosity, low
permeability formation. UOG resources include shale oil and gas, resources that were formed,
and remain, in low-permeability shale. UOG resources also include tight oil and gas, resources
that were formed in a source rock and migrated into a reservoir rock such as sandstone,
siltstones, or carbonates. As explained in the preamble to the proposed rule, although coalbed
methane (CBM) would fit the definition of UOG in the proposed rule, the proposed rule would
not apply to pollutant discharges to POTWs associated with CBM extraction.3 The remainder of
the information presented in this document is specific to the UOG resources subject to the
proposed rule and therefore excludes CBM unless explicitly indicated otherwise.
Development of UOG resources typically requires hydraulic fracturing of the reservoir
rock by injecting fracturing fluid at high pressures to create a network of fissures in the rock
formations, giving the oil and/or natural gas a pathway to travel to the well for extraction.
Pressure within the low-permeability formations forces a portion of these fracturing fluids back
to the surface. The fluid that returns is typically referred to as "flowback." Produced water
consists of flowback that flows from the well initially and the long-term produced water that
flows from the well during oil and gas production. Produced water also includes any chemicals
that are added downhole or added to fracturing or drilling fluids that are then injected downhole,
as well as chemicals that are added during the process of separating the oil and/or gas from the
wastewater.
Natural gas can include "natural gas liquids," components that are liquid at ambient temperature and pressure.
3 EPA notes that the requirements in the existing effluent guidelines for direct dischargers also do not apply to
coalbed methane extraction, as this industry did not exist at the time that the effluent guidelines were developed and
was not considered by the Agency in establishing the effluent guidelines (160 DCN SGE00761). To reflect the fact
that neither the proposed pretreatment standards nor the existing effluent guideline requirements apply to coalbed
methane extraction, EPA is expressly reserving a separate unregulated subcategory for coalbed methane in the
proposed rule. For information on coalbed methane, see
http://water.epa.gov/scitech/wastetech/guide/oilandgas/cbm.cfm.
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Chapter A—Introduction
As depicted in Figure A-l, produced water, drilling wastewater, and produced sand are
collectively referred to as UOG extraction wastewater.
UOG Extraction Wastewater
Wastewater sources associated with production, field exp loration, drilling, well comp letion, or well
treatment for unconventional oil and gas extraction (e.g., drilling muds, drill cuttings, p reduced sand,
produced water)
Drilling Wastewater: the liquid waste
stream separated from recovered drilling
fluid(e.g., mud)anddrill cuttings during
the drilling process3
Produced Sand: theslurried particles
used in hydraulic fracturing, the
accumulated formation sands and scales
particles generated during production
(40CFR435.11(aa))
Produced Water: the water (brine)
brought up from the hy drocarbon-
bearingstrata during the extraction of oil
and gas and can include formation water,
injection water, and any chemicals added
downhole or during the oil/water
separation process (40 CFR 435.11 (bb))
Flowback: produced water generated in
the initial period afterhydraulic
fracturingprior to production (i.e.,
fracturingfluid, injection water, any
chemicals added downhole, and vary ing
amounts of formation water)
Long-term Produced Water: produced
water genera ted during the production
phase of the well afterthe initial
flowback process (includes increasing
amounts of formation water)
Chemicals added during the oil/ water
separation process (40 CFR 435.11 (bb))
a - FJrilling fluid (mud) is the circulating fluid used in the rotary drilling of wells to clean and condition the hole and to counterbalance formation
pressure. Drill cuttings means the particles generated by drilling into subsurface geologic formations and carried out from the wellbore with the
drilling fluid.
Figure A-l. UOG Extraction Wastewater
This document supports the EPA's development of pretreatment standards for UOG
extraction wastewater. The remainder of this chapter describes existing discharge regulations for
UOG extraction wastewater. Subsequent chapters provide additional detail on UOG resources,
extraction processes, and wastewater generation. They describe the quantity and quality of
wastewater generated and the practices industry uses to manage and/or dispose of UOG
extraction wastewater.
The pretreatment standards for UOG extraction wastewater are based on data generated
or obtained in accordance with EPA's Quality Policy and Information Quality Guidelines. EPA's
quality assurance (QA) and quality control (QC) activities for this rulemaking include the
development, approval, and implementation of Quality Assurance Project Plans for the use of
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Chapter A—Introduction
environmental data generated or collected from sampling and analyses, existing databases, and
literature searches.
References cited in this document are listed in Chapter E and are identified in the body of
the document by reference ID numbers (e.g., 149) and DCN (e.g., DCN SGE00586). Information
presented in this document was taken from existing data sources, including state and federal
agency databases, journal articles and technical papers, technical references, vendor websites,
and industry/vendor telephone calls, meetings, and site visits. The EPA classified the quality of
the data sources with a "data source quality flag", assigning ratings from "A" for peer-reviewed
journal articles and documents prepared by or for a government agency to "D" for documents
prepared by a source that could not be verified and that do not include citation information, such
as some newspaper articles and conference presentations. For each source cited in this document,
the reference list in Chapter E includes the reference ID number, document control number
(DCN), source citation, and data source quality flag.
Appendix F.I includes two tables with more information about where to find more data
about certain topics, tables, and/or figures contained in the TDD. Table F-l lists supporting
memoranda along with their associated DCNs and a brief description of the type of information
covered in the memoranda. Each supporting memorandum includes a section about QC activities
related to the data and/or analyses discussed in the given memoranda. Table F-l also lists the
relevant TDD sections associated with each memorandum. Table F-2 contains additional
information about each table and figure in the TDD, including the original source(s) of
information for the data presented in the table or figure and the relevant memorandum and
attachments, where relevant.
2 EXISTING DISCHARGE REGULATIONS FOR OIL AND GAS EXTRACTION FACILITY
WASTEWATER
Wastewater discharges from oil and gas extraction facilities are subject to federal, state,
and local regulations. Section A.2.1 describes federal regulations affecting the discharge of oil
and gas extraction wastewater directly into waters of the United States and indirectly to
municipal wastewater treatment plants (known as publicly owned treatment works, or POTWs),
including ELGs for the Oil and Gas Extraction point source category (40 C.F.R. part 435) as well
as the national pretreatment program (40 C.F.R. part 403). In addition to applicable federal
requirements, some states specifically regulate the management, storage, and disposal of UOG
extraction wastewater. Section A.2.2 discusses state-specific requirements that the EPA has
identified that relate to UOG extraction wastewater pollutant discharges to POTWs.
2.1 Federal Regulations
The national clean water industrial regulatory program is authorized under Sections 301,
304, 306, and 307 of the Clean Water Act (CWA). These sections direct the EPA to promulgate
categorical regulations through six levels of control:
• Best practicable control technology currently available (BPT)
• Best available technology economically achievable (BAT)
• Best conventional pollutant control technology (BCT)
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Chapter A—Introduction
• New source performance standards (NSPS)
• Pretreatment standards for existing sources (PSES)
• Pretreatment standards for new sources (PSNS)
For point sources that discharge pollutants directly into the waters of the United States
(direct dischargers), the national-level ELGs promulgated by the EPA (i.e., BPT, BAT, BCT, and
NSPS) are implemented through National Pollutant Discharge Elimination System (NPDES)
permits4 as authorized by CWA Sections 301(a), 301(b), and 402. For sources that discharge to
POTWs, the EPA promulgates national categorical pretreatment standards (i.e., PSES and PSNS)
that apply to discharges to POTWs and are enforced by local, state, and federal authorities. See
CWA Sections 307(b) and (c) for the EPA's authority to develop pretreatment standards.
The EPA issues ELGs for categories of dischargers—groups with common
characteristics, such as a manufacturing process or commercial activity (e.g., battery
manufacturing, airport deicing). The EPA may divide a point source category into groupings
called "subcategories" to provide a method for addressing variations among products, processes,
and other factors, which result in distinctly different effluent characteristics that affect the
determination of the technology basis for categorical regulations. ELGs are national in scope and
apply to all facilities within a category or subcategory5 that discharge wastewater. In establishing
these controls, the EPA assesses, among other things:
2.1.1
• The performance and availability
of the best pollution control
technologies or pollution
prevention practices for the
category or subcategory as a
whole.
• The economic achievability of
those technologies, which can
include consideration of the
affordability of achieving
reductions in pollutant
discharges.
The National Pretreatment Program
(40 C.F.R. Part 403)
The 1972 CWA established the
National Pretreatment Program to address
wastewater discharged from industries to
POTWs. POTWs collect wastewater from
40 C.F.R. part 403.5(b) notes eight categories of
pollutant discharge prohibitions:
1. Pollutants that create a fire or explosion hazard in
the POTW
2. Pollutants that will cause corrosive structural
damage to the POTW
3. Solid or viscous pollutants in amounts that will
obstruct the flow in the POTW, resulting in
interference
4. Any pollutant, including oxygen-demanding
pollutants (e.g., BOD), released in a discharge at a
flow rate and/or pollutant concentration that will
interfere with the POTW
5. Heat in amounts that will inhibit biological activity
in the POTW resulting in interference
6. Petroleum oil, nonbiodegradable cutting oil, or
products of mineral oil origin in amounts that will
cause interference or pass through
7. Pollutants that result in the presence of toxic gases,
vapors, or fumes within the POTW in a quantity that
may cause acute worker health and safety problems
8. Any trucked or hauled pollutants, except at discharge
points designated by the POTW
4 Facilities that do not discharge or propose not to discharge (zero dischargers) may apply for permit coverage for
upset or bypass defense to cover discharges resulting from unforeseen incidents that otherwise would cause a
violation of CWA Section 301 (i.e., discharge without a permit) (82 DCN SGE00531).
5 The EPA may subcategorize a category based on appropriate factors, including facility size. See CWA Section
304(b)(2)(b)a. These factors may affect the availability and affordability of pollution control technologies.
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Chapter A—Introduction
homes, commercial buildings, and industrial facilities via a series of pipes, known as a collection
system, to a treatment plant. In some cases, dischargers may haul wastewater to the treatment
plant by tanker truck. Industrial wastewater, commingled with domestic wastewater, is treated by
the POTW and discharged to a receiving water body. Under the CWA, in order to discharge
wastewater, the POTW must have a NPDES permit that may limit the type and quantity of
pollutants that it may discharge.
To implement the National Pretreatment Program, the EPA developed the General
Pretreatment Regulations to protect POTW operations. As described in Chapter 2 of the EPA's
introduction to the program (171 DCN SGE00249), these regulations apply to all non-domestic
sources that introduce pollutants into a POTW. Non-domestic sources are referred to as industrial
users (lUs). To distinguish small, simple lUs (e.g., coin-operated laundries, commercial car
washes) from larger, more complex lUs (e.g., oil refineries, steel mills), the EPA has established
a category called significant lUs (SIUs). The General Pretreatment Regulations apply to all
nondomestic sources that introduce pollutants into a POTW and are intended to protect POTW
operations from "pass through" and "interference." See the textbox for a list of prohibited
pollutant discharges, as defined by 40 C.F.R. part 403.
Pretreatment Program Implementation
Most of the responsibility for implementing the National Pretreatment Program rests on
local municipalities. For example, 40 C.F.R. part 403.8(a) requires that POTWs designed to treat
more than 5 million gallons per day (MGD) of wastewater and receiving pollutants from lUs that
pass through or interfere with the POTW's operation must establish a local pretreatment
program.6 The POTW's NPDES permit will include requirements for developing a local
pretreatment program that will control the wastewater discharged to the POTW by lUs.
The National Pretreatment Program regulations identify specific requirements that apply
to lUs, additional requirements that apply to all SIUs, and certain requirements that apply only to
categorical industrial users (CIUs). There are three types of national pretreatment requirements:
• Prohibited discharge standards that include general and specific prohibition on
discharges
• Categorical pretreatment standards
• Local limits
Prohibited discharge standards.
The prohibited discharge standards are not technology-based and are intended to prevent
the POTW from receiving pollutants(s) that may cause pass through or interference. All lUs—
regardless of whether they are subject to any other national, state, or local pretreatment
requirements—are subject to the general and specific prohibitions identified in 40 C.F.R. parts
403.5(a) and (b), respectively.
6 POTWs designed to treat less than 5 MGD may be required by their Approval Authority to develop a local
pretreatment program if the nature or volume of the industrial influent, treatment process upsets, violations of
POTW effluent limitations, contamination of municipal sludge, or other circumstances warrant in order to prevent
interference with the POTW or pass through.
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Chapter A—Introduction
• General prohibitions prohibit the discharge of substances that pass through the POTW
or interfere with its operation. Note that under the definition of "pass through," only
pollutants that are limited in the POTW's NPDES permit are prohibited from pass
through by the general prohibitions.
• Specific prohibitions in 40 C.F.R. part 403.5(b) prohibit eight categories of pollutant
discharges that will harm POTW workers or the POTW, including the collection
system. Pollutant discharges outside these defined categories are not specifically
prohibited.
Categorical pretreatment standards.
As discussed in Section A.2.1, the CWA authorizes the EPA to promulgate national
categorical pretreatment standards for industrial sources that discharge to POTWs. Developed by
the EPA on an industry-specific basis, categorical pretreatment standards are based on the best
available technology that is economically achievable for that industry on a national level, and set
regulatory requirements based on the performance of that technology. These requirements limit
discharges of toxic and nonconventional pollutants that could cause pass through or cause
interference.7 Categorical pretreatment standards represent a baseline level of control that all lUs
in the category must meet, without regard to the POTW they discharge to. lUs subject to
categorical pretreatment standards are known as CIUs. The EPA establishes two types of
categorical pretreatment standards for CIUs: PSES and PSNS.
Local limits.
Developed by individual POTWs, local limits address the specific needs and concerns of
the POTW, its sludge, and its receiving waters. Typically, POTWs develop local limits for
discharges from all SIUs, not just CIUs. To evaluate the need for local limits, the POTW will
survey the lUs subject to the pretreatment program, determine the pollutants discharged and
whether they present a reasonable potential for pass through or interference, evaluate the
capability of the POTW system to address pollutants received by all users (lUs and residential
sources), and implement a system to control industrial discharges. Additional information can be
found in the EPA's 2004 Local Limits Development Guidance (165 DCN SGE00602;.
Responsibilities of POTWs and Ills
The POTW controls the discharges from the IU through an individual control
mechanism, often called an IU permit. The POTW may also issue general permits under certain
conditions if it has adequate legal authority and approval. POTWs with approved local
pretreatment programs must have procedures for:
• Identifying all possible lUs, and the character and volume of pollutants from lUs
introduced to the POTW
7 In determining whether a pollutant would pass through POTWs for categorical pretreatment standards, EPA
generally compares the percentage of a pollutant removed by well-operated POTWs performing secondary treatment
to the percentage removed by a candidate technology basis. A pollutant is determined to pass through POTWs when
the median percentage removed nationwide by well-operated POTWs is less than the median percentage removed by
the candidate technology basis.
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Chapter A—Introduction
• Communicating applicable standards and requirements to lUs
• Receiving and analyzing reports
• Inspecting lUs, including annual inspections of SIUs
• Sampling in certain cases
• Investigating noncompliance with pretreatment standards and requirements
• Reporting to the Approval Authority (i.e., state or regional pretreatment program)
Each IU of a POTW is responsible for compliance with applicable federal, state, and
local pretreatment standards and requirements.
Approval Authority
POTWs establish local pretreatment programs to control discharges from non-domestic
sources. These programs must be approved by the Approval Authority, which is also responsible
for overseeing implementation and enforcement of the programs (171 DCN SGE00249). The
Approval Authority is the director in a NPDES authorized state with an approved state
pretreatment program, or the appropriate EPA regional administrator in a non-NPDES authorized
state or NPDES state without an approved state pretreatment program. A state may have an
NPDES permit program but lack a state pretreatment program. One example is Pennsylvania,
which the EPA has authorized for the NPDES program but not for the pretreatment program.
EPA Region 3 is the Approval Authority for POTW pretreatment programs in Pennsylvania.
Hauled Wastewater
As discussed in the EPA's Introduction to the National Pretreatment Program (171 DCN
SGE00249), in addition to receiving wastewater through the collection system, many POTWs
accept trucked wastewater. lUs may truck their wastewater to the POTW when the facility is
outside the POTW's service area (e.g., located in a rural area) and is not connected to the
collection system. Just like wastewater received through the collection system, trucked
wastewater is subject to the General Pretreatment Regulations and may also be subject to
categorical pretreatment standards. Therefore, the POTW must regulate hauled wastewater from
CIUs or hauled wastewater that otherwise qualifies the discharger as an IU in accordance with
the requirements of the General Pretreatment Regulations and any applicable categorical
pretreatment standards, including any applicable requirements for permitting and inspecting the
facility that generates the wastewater.
Section 403.5(b)(8) of the General Pretreatment Regulations specifically prohibits the
introduction of any trucked or hauled pollutants to the POTW, except at discharge points
designated by the POTW. As explained in Introduction to the National Pretreatment Program
(171 DCN SGE00249), Section 403.5(b)(8) of the General Pretreatment Regulations is the only
pretreatment requirement specifically addressing hauled wastewater. POTWs are not required to
have waste hauler control programs. However, POTWs that accept any hazardous waste by
truck, rail, or dedicated piping at the POTW facility are considered treatment, storage, and
disposal facilities (TSDFs) subject to management requirements under the Resource
Conservation and Recovery Act (RCRA). Consequently, a POTW should not accept hauled
waste without consideration of the implications of its acceptance (see 40 C.F.R. part 260).
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Chapter A—Introduction
2.1.2 ELGsfor the Oil and Gas Extraction Point Source Category (40 C.F.R. Part 435)
The EPA promulgated the Oil and Gas Extraction ELGs (40 C.F.R. part 435) in 1979,
and amended the regulation in 1993, 1996, and 2001. The Oil and Gas Extraction industrial
category is subcategorized8 as follows:
• Subpart A: Offshore
• Subpart C: Onshore
• Subpart D: Coastal
• Subpart E: Agricultural and Wildlife Water Use
• Subpart F: Stripper Wells
The existing subpart C and subpart E regulations cover wastewater discharges from field
exploration, drilling, production, well treatment, and well completion activities in the onshore oil
and gas industry. Although oil and gas resources occur in unconventional formations in offshore
and coastal regions, recent development of UOG resources in the United States has occurred
primarily onshore in regions to which the regulations in subpart C (onshore) and subpart E
(agricultural and wildlife water use) apply and thus, only the regulations that apply to onshore oil
and gas extraction are described in more detail here.
Note that the scope of the existing Oil and Gas Extraction ELG does not similarly apply
to privately owned wastewater treatment facilities that accept oil and gas extraction wastewater
from offsite that are also not engaged in production, field exploration, drilling, well completion,
or well treatment. Discharges from such facilities are not subject to 40 C.F.R. part 435, but rather
are subject to requirements in 40 C.F.R. part 437, the Centralized Waste Treatment category (see
Section D.4 for more information).
Direct Discharge Requirements for Onshore Oil and Gas Extraction Facilities
Subpart C: Onshore Subcategory
Applicability. As set forth in 40 C.F.R. part 435.30, subpart C applies to facilities
engaged in production, field exploration, drilling, well completion, and well treatment in the oil
and gas extraction industry, located landward of the inner boundary of the territorial seas—and
not included in the definition of other subparts, including subpart D (Coastal) at 40 C.F.R. part
435.40.
Direct discharge requirements. The regulations at 40 C.F.R. part 435.32 specify the
following for BPT:
...there shall be no discharge of waste water pollutants into navigable waters from any
source associated with production, field exploration, drilling, well completion, or well
treatment (i.e., produced water, drilling muds, drill cuttings, and produced sand).
The existing regulations do not include national categorical pretreatment standards for
discharges to POTWs.
1 Subpart B is reserved.
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Chapter A—Introduction
Subpart E: Agricultural and Wildlife Use Subcategory9
Subpart E applies to onshore facilities located in the continental United States and west of
the 98th meridian for which the produced water has a use in agriculture or wildlife propagation
when discharged into waters of the United States.
Applicability. As set forth in 40 C.F.R. part 435.50, subpart E applies to onshore facilities
located in the continental United States and west of the 98th meridian for which the produced
water has a use in agriculture or wildlife propagation when discharged into navigable waters.
Definitions in 40 C.F.R. part 435.51(c) explain that the term "use in agricultural or wildlife
propagation" means:
• The produced water is of good enough quality to be used for wildlife or livestock
watering or other agricultural uses; and
• The produced water is actually put to such use during periods of discharge.
Direct discharge requirements. Subpart E prohibits the discharge of waste pollutants into
navigable waters from any source (other than produced water) associated with production, field
exploration, drilling, well completion, or well treatment (i.e., drilling muds, drill cuttings,
produced sands). Therefore, the only allowable discharge under this subpart is produced water10
that meets the "good enough quality" and actual use requirements described above, with an oil
and grease concentration not exceeding 35 mg/L.
2.2 State Pretreatment Requirements That Apply to UOG Extraction Wastewater
In addition to applicable federal requirements, some states regulate the management,
storage, and disposal of UOG extraction wastewater, including regulations concerning pollutant
discharges to POTWs from oil and gas extraction facilities. In addition to pretreatment
requirements, some states have indirectly addressed the issue of pollutant discharges to POTWs
by limiting the management and disposal options available to operators. Table A-l, beginning on
the next page, summarizes how Pennsylvania, Ohio, West Virginia, and Michigan responded to
UOG extraction wastewater discharges into their POTWs.
The Groundwater Protection Council's (GWPC) 2014 report Regulations Designed to
Protect State Oil and Gas Water Resources describes that, as part of their study, GWPC
"surveyed the study states11 regarding the use of POTWs for discharging production fluids
including flowback water. Of the states responding, three indicated this practice was banned by
9 While pollutant discharges from onshore oil and gas extraction produced water are allowed under subpart E in
certain geographic locations for use in agriculture or wildlife propagation, EPA has not found that these types of
permits are typically written for unconventional oil and gas extraction wastewater (as defined for the proposed rule).
10 Produced water is not defined in subpart C (onshore) or subpart E (agricultural and wildlife use). For subparts A
(offshore) and D (coastal), produced water is defined as "the water (brine) brought up from the hydrocarbon-bearing
strata during the extraction of oil and gas, and can include formation water, injection water, and any chemicals
added downhole or during the oil/water separation process."
11 GWPC reviewed data for the following 27 oil and gas producing states: Alabama, Alaska, Arkansas, California,
Colorado, Florida, Illinois, Indiana, Kansas, Kentucky, Louisiana, Michigan, Mississippi, Montana, Nebraska, New
Mexico, New York, North Dakota, Ohio, Oklahoma, Pennsylvania, South Dakota, Texas, Utah, Virginia, West
Virginia, and Wyoming.
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Chapter A—Introduction
regulation, five states did not have a regulation covering this disposal method but would not
allow it as a matter of policy, and nine indicated it was either regulated by another state agency
or would otherwise be allowed under certain circumstances.... [A]s of 2013, six state oil and gas
agencies had permitting requirements for POTWs accepting this waste" (77 DCN SGE01077).
10
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Chapter A—Introduction
Table A-l. Summary of State Regulations
State
Relevant
State
Authority
(s)
State Authority
Website(s)
Description of State's Relevant Requirements
Pennsylvania
EPA
Regions,
PADEP
PADEP:
http://www.depwe
b. state.pa.us/
PA Code, Chapter
95:
http://www.pacode
. com/secure/data/0
25/chapter95/chap
95toc.html
Pennsylvania amended 25 Pennsylvania Code Ch. 95.10 on August 21, 2010. According to PA Bulletin, Doc.
No. 10-1572 (130 DCN SGE00187) (available at http://www.pabulletin.com/secure/data/vol40/40-
34/1572.htmT)
This final form rulemaking ensures the continued protection of this Commonwealth's water resources from
new and expanded sources ofTDS. Most importantly, the final-form rulemaking guarantees that waters of
this Commonwealth will not exceed a threshold of 500 mg/L.
In addition, the bulletin specifies
A higher standard of 500 mg/L is being applied specifically to the natural gas sector, based on several
factors.
The bulletin also explains the following, regarding existing authorized discharges, addressed in Section
95.10(a)(l)
This section makes it clear that discharge loads ofTDS authorized by the Department, under NPDES
permits or other authority that were issued or reissued prior to the effective date of this final-form
rulemaking, are exempt from the regulation until the net load is to be increased. It is important to note that
only an increase in net TDS load is considered to be a new or expanding discharge loading.
The bulletin also explains the pretreatment requirements described in Section 95.10(b)(3)(ii), including
the final rule establishes thatPOTWs may accept these wastewaters only if the wastes are first treated at a
CWT'facility and meet the end-of-pipe effluent standards imposed by the rule. In effect, the final rule
regulates these indirect discharges in a manner consistent with direct discharges of these wastes.
On April 19, 2011, PA DEP requested that
Marcellus Shale natural gas drillers voluntarily cease delivering their wastewater to 15 wastewater
treatment plants which currently accept it and have "grandfathered" status with respect to PA DEP's Total
Dissolved Solids regulations (170 DCN SGE00982).
On April 20, 2011, the Marcellus Shale Coalition wrote a response to PA DEP that stated
/ write to you today to express our commitment to meet the call of the Department of Environmental
Protection (DEP) to halt the delivery offlowback and produced water from shale gas extraction to the
facilities that currently accept it under special provisions of last year's Total Dissolved Solids (TDS)
regulations. Our members are carefully reviewing their operations and support achieving this milestone by
May 19, 2011 (111 DCN SGE00545).
11
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Chapter A—Introduction
Table A-l. Summary of State Regulations
State
Ohio
West
Virginia
Relevant
State
Authority
(s)
OH EPA,
OHDNR
WVDEP
State Authority
Website(s)
OH EPA:
http://www.epa.stat
e.oh.us/
OHDNR:
http://ohiodnr.sov/
Ohio R.C. 15,
Chapter 1509:
http://codes.ohio.so
v/orc/1509
WVDEP:
http://www.dep.wv
. sov/Pases/default.
aspx
Description of State's Relevant Requirements
Ohio R.C. Title 15, Chapter 1509, part 22(C)(1) (128 DCN SGE00983), includes the provision that
brine12 from any well except an exempt Mississippian well13 shall be disposed of only as follows: by
injection into an underground formation, including annular disposal if approved by rule of the chief, which
injection shall be subject to division (D) of this section; by surface application in accordance with section
1509.226 of the Revised Code; in association with a method of enhanced recovery as provided in section
1509.21 of the Revised Code; [or] in any other manner not specified in divisions (C)(l)(a) to (c) of this
section that is approved by a permit or order issued by the chief.
A WVDEP guidance document about POTWs accepting oil and gas wastewater (218 DCN SGE00767) notes
that
The USEPA and WVDEP discourage POTWs from accepting wastewater from oil and gas operations such
as coal bed methane andMarcellus Shale wastewaters because these wastewaters essentially pass through
sewage treatment plants and can cause inhibition and interference with treatment plant operations.
The Ohio EPA defines brine as "all saline geological formation water resulting from, obtained from, or produced in connection with the exploration, drilling,
or production of oil or gas, including saline water resulting from, obtained from, or produced in connection with well stimulation or plugging of a well."
13 OH R.C. Section 1509.01 defines an "exempt Mississippian well" as a well that (1) was drilled and completed before January 1, 1980; (2) is in an unglaciated
part of the state; (3) was completed in a reservoir no deeper than the Mississippian Big Injun sandstone in areas underlain by Pennsylvanian or Permian
stratigraphy, or the Mississippian Berea sandstone in areas directly overlain by Permian stratigraphy; and (4) is used primarily to provide oil or gas for domestic
use.
12
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Chapter A—Introduction
Table A-l. Summary of State Regulations
State
Michigan
Relevant
State
Authority
(s)
MIDEQ
State Authority
Website(s)
MI DEQ:
http://www.michis
an.gov/deq
Michigan Oil and
Gas Regulations:
http://www.michig
an. gov/documents/
deq/oss-oilandsas-
rees 263032 7.odf
Description of State's Relevant Requirements
Michigan's Oil and Gas Regulations, part 324.703 (120 DCN SGE00254), state that
A permittee of a well shall inject oil or gas field fluid wastes, or both, into an approved underground
formation in a manner that prevents waste. The disposal formation shall be isolated from fresh water strata
by an impervious confining formation.
Sources: 130 DCN SGE00187; 120 DCN SGE00254; 104 DCN SGE00545; 198 DCN SGE00766; 218 DCN SGE00767; 170 DCN SGE00982; 128 DCN
SGE00983
Abbreviations: PA DEP—Pennsylvania Department of Environmental Protect; OH EPA—Ohio Environmental Protection Agency; OH DNR—Ohio
Department of Natural Resources; R.C.—Revised Code; WVDEP—West Virginia Department of Environmental Protection; MI DEQ—Michigan Department
of Environmental Quality
13
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Chapter A—Introduction
3 RELATED FEDERAL REQUIREMENTS
As required by the Safe Drinking Water Act Section 1421, the EPA has promulgated
regulations to protect underground sources of drinking water through underground injection
control (UIC) programs that regulate the injection of fluids underground. These regulations are
found at 40 C.F.R. parts 144 through 148, and specifically prohibit any underground injection
not authorized by UIC permit (40 C.F.R. part 144.11). They classify underground injection into
six classes; wells that inject fluids brought to the surface in connection with oil and gas
production are classified as Class II UIC wells (see Section D.2 for more information). Thus, an
onshore oil and gas extraction facility that seeks to meet zero discharge requirements through
underground injection of wastewater must dispose of the wastewater in a well with a Class II
UIC disposal well permit.
14
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Chapter B—Background on Unconventional Oil and Gas Extraction
Chapter B. BACKGROUND ON UNCONVENTIONAL OIL AND GAS EXTRACTION
To provide context for discussions of UOG extraction wastewater volumes and
characteristics (Chapter C) and management and disposal practices (Chapter D), this chapter
describes the following:
• What UOG resources are in context of the proposed rule, differences between
unconventional and conventional resources, differences between types of UOG
resources, and where UOG resources are located
• How UOG wells are developed and the development processes that generate
wastewater
• Historical, current, and projected future UOG well drilling activity
Relevant national economic information about the UOG industry is included in a separate
memorandum to the record, titled Profile of the Oil and Gas Extraction (OGE) Sector, with
Focus on Unconventional Oil and Gas (UOG) Extraction (2 DCN SGE00932).
Oil and gas resources are defined as the total in-place hydrocarbon contained in porous
rock formations. There are several ways to classify oil and gas resources. Throughout this TDD,
the EPA typically classifies resources into conventional and unconventional resources. For
purposes of the proposed rule, the EPA is proposing to define "unconventional oil and gas"
(UOG) as "crude oil and natural gas14 produced by a well drilled into a low porosity, low
permeability formation (including, but not limited to, shale gas, shale oil, tight gas, tight oil)." As
explained in the preamble to the proposed rule and in Section A.I, although CBM would fit the
definition of UOG in the proposed rule, the proposed rule would not apply to pollutant
discharges to POTWs associated with CBM extraction.
The different types of unconventional resources (shale, tight) and how they differ from
conventional resources are discussed in more detail in Section B.2.1. UOG and conventional oil
and gas (COG) resources can be further classified by the type of hydrocarbon: oil, natural gas,
and natural gas condensates. Literature often refers to formations that co-produce natural gas
condensates15 along with oil and/or natural gas as liquid rich formations. Formations that
primarily produce oil also co-produce natural gas known as "associated gas" (206 DCN
SGE00623). Formations that only produce dry natural gas are known as non-associated gas
resources.
1 OVERVIEW OF UOG RESOURCES
The Energy Information Administration (EIA) publishes historical and projected future
oil and gas production by resource type in its Annual Energy Outlooks (AEOs). Beginning
around 2000, advances in technologies such as horizontal drilling and advances in hydraulic
fracturing made it possible to economically produce oil and natural gas from tight and shale
14 Natural gas can include "natural gas liquids," components that are liquid at ambient temperature and pressure.
15 Natural gas condensates include light hydrocarbons such as ethanes, propanes, and butanes. When gas
condensates are depressurized at the wellhead, they condense into a liquid phase. When processed at the refinery,
the finished byproducts of natural gas condensates are referred to as natural gas liquids and have high market value.
15
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Chapter B—Background on Unconventional Oil and Gas Extraction
resources (209 DCN SGE01095). The EIA's 2014 AEO projects that, in the next 30 years, the
majority of the country's natural gas will come from unconventional resources and that
unconventional oil production will continue to increase substantially (31 DCN SGE00989).
Figure B-l and Figure B-2 show the historical and future profiles of COG and UOG production
in the United States by resource type according to the EIA.16 CBM and COG are included in
some of the figures in this chapter, but are identified separately within each figure. Section B.3
summarizes historical and current trends in UOG drilling in more detail on a well basis.
Figure B-3 and Figure B-4 show the major shale and tight UOG resources, respectively,
in the lower 48 states. Appendix F (Table F-3 and Table F-4) provides an updated and more
thorough list of UOG formations by basin as the EIA maps shown below only show major UOG
formations as of May 2011. Geological characteristics of UOG resources shown in Figure B-3
and Figure B-4 are described in detail in Section B. 1.2.1?
History
2011
Projections
1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040
Source: 158 DCN SGE00487
Figure B-l. Historical and Projected Oil Production by Resource Type
In Figure B-l, the EIA refers to all types of unconventional oil including shale as "tight oil." As explained in
Section B. 1, EPA differentiates between shale and tight oil for the purpose of this TDD.
17 The EIA uses the term "play" to describe subsets of UOG resources in Figure B-3 and Figure B-4, which are
similar to the term "formation" as used in this TDD.
16
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Chapter B—Background on Unconventional Oil and Gas Extraction
History
2D12
Projections
19SD 2330 23'C 2020
Source: 31 DCN SGE00989
203D
234C
Figure B-2. Historical and Projected Natural Gas Production by Resource Type
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Monterey
Sans Mar.a.v ';,
Ventura. Lo= '
Angetes
Excsflo- ;
Mulky^phe'Diee' Ratfc^n X. AJbany
^* I \S ' *^j-
Vfoodfoi* >ayetrevil^ X
•, »" / Chattanojoga _ . -; --•/
Arhoma Basin &*** Wafr&][
/ Easini' —-Conasauga
(noyd- ( £ Valte^a Ridge
eia
PrcEpective plays
Stacked plays
.. S^a-bwestr' youngest
^^— Intermediate depth; age
Deepest*' oldest
Source: 157 DCN SGE00153
Figure B-3. Major U.S. Shale Plays (Updated May 9, 2011)
17
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Chapter B—Background on Unconventional Oil and Gas Extraction
Greefl
- River Basin \\
Mesaverde- r
Lan co-Lewis
Was ate h- ,
Mesaveide -*
. JJrt* Basin Jif, *Vj
Man cos
Source: 156 DCN SGE00155
Figure B-4. Major U.S. Tight Plays (Updated June 6, 2010)
The key differences between UOG and COG resources are the geological characteristics
of the formations that contain the resources. UOG resources include shale oil and gas resources
that were formed, and remain, in low-permeability shale. UOG resources also include tight oil
and gas resources that were formed in a source rock and migrated into a reservoir rock such as
sandstone, siltstones, or carbonates. The permeability and porosity of tight oil and gas reservoirs
are lower than that of COG reservoirs, but generally higher than that of shale oil and gas
reservoirs (100 DCN SGE00527). As mentioned above, while CBM is sometimes referred to as
an unconventional resource, the proposed rule does not apply to CBM, and therefore the scope of
this document does not include CBM.
1.1 How UOG Resources Were Formed
Differences in how conventional and unconventional resources were formed can be
explained in terms of the source and resource rock.18 The following explains these differences,
which are also illustrated in Figure B-5 (100 DCN SGE00527; 113 DCN SGE00547; 211 DCN
SGE00114).
• Oil and gas in conventional resources were formed in a source rock, migrated
through the surrounding permeable rock, and eventually became trapped by a
confining rock layer forming non-continuous accumulations. The final reservoir rock
has high permeability and porosity.
1 The source rock is the type of rock in which the oil and/or gas formed. The reservoir rock is the type of rock in
which the oil and/or gas is contained at the time of production.
18
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Chapter B—Background on Unconventional Oil and Gas Extraction
Oil and gas in tight resources, similar to conventional resources, were formed in a
source rock and migrated until they reached a confining layer of rock. Tight resources
occur in a mixture of continuous and non-continuous accumulations. They differ from
conventional resources in that the oil and gas accumulated in a reservoir rock with
relatively low permeability and porosity.19
Oil and gas in shale resources were formed in and remained in the source rock,
making it also the reservoir rock. Consequently, shale reservoirs occur in continuous
accumulations over large geographic areas. Shale reservoirs have the lowest
permeability and porosity out of all resource types (see Section B.2.2 for more
information about hydraulic fracturing).
Conventional
non-associated
Conventional
oil and
associated gas
Source: 155 DCN SGE00594
Figure B-5. Geology of Formations Containing Various Hydrocarbons20
1.2 Geological Characteristics of UOG Resources
UOG resources are typically developed using advanced completion and well drilling
techniques because they have unique geologic characteristics that differ from conventional
resources. These are summarized in Table B-l. COG reservoirs have relatively high porosities
and permeabilities, so economical oil and gas production typically relies on natural pressure
Because tight oil and gas exists in multiple types of reservoir rocks, EPA refers to it generally as "tight" oil and
gas in this report as opposed to "tight sands" because that reference is not all inclusive of the different types of tight
formations.
20 "Associated" gas accumulates with oil in a formation. "Non-associated" gas accumulates separately from oil in a
formation (206 DCN SGE00623).
19
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Chapter B—Background on Unconventional Oil and Gas Extraction
gradients with open-hole completion techniques (see Section B.2.2 for more information about
well completion). UOG reservoirs have extremely low porosity and permeability, typically
requiring rigorous stimulation (e.g., hydraulic fracturing) during well completion to produce oil
and gas economically (113 DCN SGE00547; 100 DCN SGE00527; 211 DCN SGE00114).
Although it is not necessary to create fractures to obtain oil and gas from conventional reservoirs,
hydraulic fracturing can still be used to increase production from COG wells (100 DCN
SGE00527; 146 DCN SGE00291)21. UOG formations are also more likely to occur in
continuous accumulations, as explained in Section B. 1.1. As a result, UOG wells are more likely
to be drilled horizontally.
Table B-l. Characteristics of Reservoirs Containing UOG and COG Resources
Reservoir
Characteristic
Reservoir rock type
Source rock
Accumulation type
Porosity
Permeability
Well trajectory13
Completion method
COG Resources
Sandstones, siltstones, or
carbonates
No
Non-continuous
High (>10%)
High (>100 mD)a
Mostly vertical
Open hole completions and
natural reservoir pressure0
UOG Resources
Tight
Sandstones, siltstones, or
carbonates
No
Continuous or non-continuous
Low (<10%)
Low(<0.1mD)a
Mixture of vertical and
horizontal
Hydraulic fracturing and/or
acidizationd
Shale
Shales
Yes
Continuous
Low (<10%)
Low(<0.001mD)a
Mostly horizontal
Hydraulic fracturing
Sources: 211 DCN SGE00114; 86 DCN SGE00533; 100 DCN SGE00527; 109 DCN SGE00345
a—The millidarcy (mD) is a measurement of permeability (i.e., ability for fluid flow within a rock). Higher
permeability means fluids flow more readily.
b—Well trajectories are described in more detail in Section B.2.1.
c—As COG wells age, operators may also use enhanced recovery techniques such as water or steam injection to
enhance production. COG wells may also be hydraulically fractured.
d—Acidization is the process of dissolving undesired rocks from the wellbore using acidic fluids in order to
improve fluid flow from the reservoir (18 DCN SGE00966).
2 UOG WELL DEVELOPMENT PROCESS
UOG well development includes the following processes: well pad construction, well
drilling and construction, well completion, and production. UOG well completion includes well
stimulation such as hydraulic fracturing, acidization, or a combination of hydraulic fracturing
and acidization. The return of injected fluids to the surface, commonly referred to as the
"flowback process," is also part of the UOG well completion process. Before UOG well
development, operators conduct exploration and obtain surface use agreements, mineral leases,
and permits. These steps can take a few months to several years to complete. When they are
A survey conducted by American Petroleum Institute (API) and the American Natural Gas Alliance (ANGA),
included well completion information for 5,307 well completions in 2010, consisting of a mixture of conventional
and unconventional wells. The survey also showed that 69 percent of conventional wells were hydraulically
fractured.
20
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Chapter B—Background on Unconventional Oil and Gas Extraction
completed, operators begin the well development process, as described in the following
subsections.
The largest UOG extraction wastewater volumes generated during the UOG well
development process are flowback and long-term produced water (see Section C.2 for
characteristics of each). UOG well drilling also generates drilling wastewater. Throughout the
well development process, many materials are transported to the well pad. These materials
include well casing and tubing, fuel (e.g., diesel or liquefied natural gas), and base fluid, sand,
and chemicals for hydraulic fracturing. Operators must also transport UOG extraction
wastewater from the well to the ultimate wastewater management or disposal location—e.g., a
centralized waste treatment (CWT) facility, an underground injection well for disposal, another
well for reuse. Sand, chemicals, and construction materials are typically transported to the well
pad by truck, but fracturing base fluid (e.g., fresh water, recycled UOG produced water) and
UOG extraction wastewater may be transported via truck or temporary piping (191 DCN
SGE00625; 178 DCN SGE00635; 179 DCN SGE00275).
2.1 UOG Well Drilling and Construction
Drilling occurs in two phases: exploration and development. Exploration involves the
drilling of wells to locate hydrocarbon-bearing formations and to determine the size and
production potential of hydrocarbon reserves. Development involves drilling production wells
once a hydrocarbon reserve has been discovered and delineated. The following discussion will
focus on the drilling of production wells.
After the well pad is constructed, operators drill and construct the well. Operators use one
of the three drilling trajectories below to drill for UOG (see Figure B-6). See Table B-3 for a
breakdown of active UOG wells as of 2011 by drilling traj ectory.
• Vertical drilling is the drilling of a wellbore straight down into the ground. In UOG
well drilling, vertical well drilling is more commonly used for tight wells than shale
wells (100 DCN SGE00527). For shale, vertical drilling is used by operators during
the exploration phase of field development (178 DCN SGE00635), in shallow
formations (e.g., Antrim shale), or by small entity operators who may be unable to
make large investments in horizontal wells (39 DCN SGE00283). Vertical drilling
has historically been used for COG wells.
• Directional drilling is the drilling of a wellbore at an angle off the vertical to reach
an end location not directly below the well pad. Directional drilling is used where a
well pad cannot be constructed directly above the resource (e.g., in rough terrain).
Directional drilling is common in conventional and unconventional tight formations
that occur as accumulations as illustrated in Section B.I.
• Horizontal drilling, the most advanced drilling technique, allows operators to drill
vertically down to a desired depth, about 500 feet above the target formation (called
the "kickoff point"), and then gradually turn the drill 90 degrees to continue drilling
laterally. Horizontal drilling exposes the producing formation via a long horizontal
lateral, which can vary in length between 1,000 and 5,000 feet (154 DCN SGE00593;
206 DCN SGE00623). Horizontal drilling is the most commonly used method in
continuous shale and tight formations (24 DCN SGE00354; 78 DCN SGE00010).
21
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Chapter B—Background on Unconventional Oil and Gas Extraction
Source: 154 DCN SGE00593 (edited by the EPA)
Figure B-6. Horizontal (A), Vertical (B), and Directional (C) Drilling Schematic
Because shale reservoirs occur in continuous accumulations over large geographic areas,
operators drilling in these resources typically drill multiple horizontal wells on each well pad
(191 DCN SGE00625; 178 DCN SGE00635; 179 DCN SGE00275). However, tight reservoirs
occur in both continuous and non-continuous accumulations; therefore, operators may drill
multiple horizontal wells or a single directional or vertical well on a well pad, depending on the
location and accumulation type of the tight reservoir. Directional and horizontal well
configurations give operators access to more of the producing formation and therefore reduce
surface disturbance (24 DCN SGE00354; 212 DCN SGE00011). Operators may drill one or two
horizontal wells on a well pad initially and move on to the next pad. When this happens, the
operator typically comes back to drill out the remaining wells on the pad after the initial wells
show economical production and favorable conditions.
Drilling for oil and gas is generally performed by rotary drilling methods, which involve
the use of a rotating drill bit that grinds through the earth's crust as it descends. Well drilling is
an iterative process that includes several sequences of drilling, installing casing, and cementing
of succeeding sections of the well (178 DCN SGE00635). During drilling, operators inject
drilling fluids down the wellbore to cool the drill bit, to circulate fragments of rock (i.e., drill
cuttings) back to the surface so they do not clog the wellbore, and to control downhole pressure.
Operators use one of the following types of drilling fluids depending on which portion of the
well they are drilling (55 DCN SGE00740):
• Compressed gases: During the beginning phase of drilling an UOG well (i.e., the
initial drilling close to the surface), compressed gases may be used to minimize costs.
Dry air, nitrogen gas, mist, foam, and aerated fluids are included in this category.
Favorable conditions include sufficient oil and/or gas prices, available drilling rigs, available fracturing crews, and
permits.
22
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Chapter B—Background on Unconventional Oil and Gas Extraction
• Water-based: At several thousand feet deep, operators typically use water-based
drilling fluids (i.e., drilling mud), which provide more robust fluid properties at these
depths than compressed gases. Water-based drilling fluids may contain salts,23 barite,
polymers, lime, and gels as additives.
• Oil-based: For drilling at deep depths and/or the horizontal laterals of wells,
operators may use oil-based mud to maintain more consistent fluid properties at the
higher temperatures and pressures that are associated with deeper depths. Oil-based
drilling fluids may use diesel oil and/or mineral oils and contain emulsifiers, barite,
and gels as additives.
• Synthetic-oil-based: For drilling at deep depths and/or the horizontal laterals of
wells, operators may also use synthetic-oil-based fluids which are similar to oil-based
fluids. However, instead of using diesel oil and/or mineral oils, synthetic oil-based
fluids use organic fluids (e.g., esters, polyeolefins, acetal, ether, and linear alkyl
benzenes) that exhibit similar fluid properties as diesel and mineral oils. Synthetic-
oil-based fluids have been referred as more environmentally friendly24 than oil-based
fluids but are also more expensive (162 DCN SGE01006; 17 DCN SGE01009).
When returned to the surface, drill cuttings (solids) are removed from the drilling fluids
using shakers, desilters, and centrifuges. This results in drill cuttings and a wastewater stream,
referred to as drilling wastewater. Drilling wastewater is either reused/recycled in a closed loop
process or otherwise managed (e.g., transferred to a CWT facility) (124 DCN SGE00090; 178
DCN SGE00635).
Well drilling and construction typically lasts between five days and two months,
depending on well depth and how familiar operators are with the specific formation. Figure B-7
shows that drilling time generally decreases as UOG operators become more familiar and
efficient at drilling in a UOG formation (9 DCN SGE00503; 178 DCN SGE00635; 26 DCN
SGE00516). Figure B-7 also compares drilling phase durations among UOG formations (e.g.,
Granite Wash requires 40 to 50 days for drilling while Barnett requires 10 or fewer days).
23 The UOG industry may refer to water-based drilling fluids that contain salts as "salt mud."
24 Using synthetic-oil-based drilling fluids results in a lower volume of wastewater that must be disposed of. They
also have lower toxicities, lower concentrations of certain priority pollutants, lower bioaccumulation potential, and
faster biodegradation rates than oil-based drilling fluid.
23
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Chapter B—Background on Unconventional Oil and Gas Extraction
Granite Wash
Haynesville
Woodford
Williston
Eagle Ford
Marcellus
Mississippian
Permian
Utica
Fayetteville
Bamett
DJ-Niobrara
1Q2012 2Q2012
Source: 48 DCN SGE00693
3Q2012 4Q2012 1Q2013 2Q2013 Q3-2013
Figure B-7. Length of Time to Drill a Well in Various UOG Formations as Reported for the
First Quarter of 2012 through the Third Quarter of 2013
2.2 UOG Well Completion
After the well is drilled and constructed, the well completion process begins. "Well
completion" is a general term used to describe the process of bringing a wellbore into production
once drilling and well construction are completed (33 DCN SGE00984). The UOG well
completion process involves many steps, including cleaning the well to remove drilling fluids
and debris, perforating the casing that lines the producing formation,25 inserting production
tubing to transport the hydrocarbon fluids to the surface, installing the surface wellhead,
stimulating the well (e.g., hydraulic fracturing), setting plugs in each stage, and eventually
drilling the plugs out of the well. It also includes the flowback process, in which fluids injected
during well stimulation return to the surface. The following two subsections describe the well
stimulation and flowback processes that are common for UOG well completion.
25 In some instances, open-hole completions may be used, where the well is drilled into the top of the target
formation and casing is set from the top of the formation to the surface. Open-hole well completions leave the
bottom of the wellbore uncased.
24
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Chapter B—Background on Unconventional Oil and Gas Extraction
2.2.1 VOG Well Completion: Well Stimulation
Because UOG resources are extracted from formations with low porosity and
permeability, UOG wells are typically developed using more advanced stimulation technologies
than traditionally used on COG wells to create higher permeability in the reservoir that allows
operators to produce oil and gas economically. UOG well stimulation techniques include but are
not limited to hydraulic fracturing, acidization, or a combination of fracturing and acidization (18
DCN SGE00966). The most common technique for UOG wells is hydraulic fracturing, discussed
in the rest of this subsection (see Section B.3.3) (78 DCN SGE00010). Hydraulic fracturing of
COG wells is becoming more common, but traditionally COG wells have been completed with
open-hole techniques allowing the oil and/or gas resources to flow naturally (109 DCN
SGE00345; 86 DCN SGE00533).
Operators typically fracture UOG wells in multiple stages to maintain the high pressures
necessary to fracture the reservoir rock. Stages are fractured starting with the stage at the end of
the wellbore and working back toward the wellhead. The number of stages depends on lateral
length. Because horizontal laterals are 1,000 to 5,000 feet long, operators may use between eight
and 23 stages for horizontal wells (177 DCN SGE00276). Vertical wells are typically only
fractured with one stage (78 DCN SGE00010). A fracturing crew can typically fracture two to
three stages per day when operating 12 hours per day or four to five stages per day when
operating 24 hours per day.26 Consequently, a typical well may take two to seven days to
complete (87 DCN SGE00239; 124 DCN SGE00090). The following processes are performed
for each stage:
• Perforation—Operators lower a perforation gun into the stage using a line wire. The
perforation gun releases an explosive charge to create holes that penetrate
approximately 1 foot into the formation rock in a radial fashion. These perforations
create a starting point for the hydraulic fractures.
• Hydraulic fracturing—Operators inject fracturing fluids (e.g., water, sand, and other
additives) down the wellbore to highly pressurize the formation to the point where
small fractures are created in the rock (see Figure B-8).27 See Section C.I for
information about fracturing fluid volumes and characteristics.
• Stage plugging—Once the stage is hydraulically fractured, a stage plug is inserted
down the wellbore, separating it from additional stages until all stages are completed.
26 The hours per day depends on the operator, local ordinances, and weather.
27 The first stage is fractured with what is known as the pad fracture. The pad is the injection of high-pressure water
and chemical additives without proppant (i.e., solid material designed to keep fractures open to allow gas to flow
from the producing formation) to create the initial fractures into the formation. After the pad is pumped downhole,
proppant is introduced to the fracturing fluid for the additional stages.
25
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Chapter B—Background on Unconventional Oil and Gas Extraction
Source: 168 DCN SGE00604
Figure B-8. Hydraulic Fracturing Schematic
The components of fracturing fluid (i.e., base fluid, sand, chemical additives) are
typically stored on the well pad before hydraulic fracturing begins. (See Section C.I for a more
detailed description of the fracturing fluid composition.) Operators may store fresh water in
storage impoundments (see Figure B-9) or fracturing tanks that typically range from 10,500 to
21,000 gallons (250 to 500 barrels) in size (see Figure B-ll) (190 DCN SGE00280; 179 DCN
SGE00275; 177 DCN SGE00276). Operators that reuse/recycle UOG produced water in
subsequent fracturing jobs typically store the reused/recycled wastewater in fracturing tanks
and/or pits (190 DCN SGE00280). Operators typically have sand trucks and pump trucks onsite
during the hydraulic fracturing process. The sand trucks contain the sand prior to mixing in the
fracturing fluid and the pump trucks pump the fracturing fluid down the wellbore during each
stage of fracturing.
26
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Chapter B—Background on Unconventional Oil and Gas Extraction
_ JB/iai2Qf2 11:12
Source: 179 DCN SGE00275
Figure B-9. Freshwater Impoundment
2.2.2 UOG Well Completion: Flowback Process
After all of the stages of a well have been hydraulically fractured, the stage plugs are
drilled out of the wellbore and the pressure at the wellhead is released. Releasing the pressure
allows a portion of produced water to return to the wellhead; this waste stream is often referred
to as "flowback." Industry commonly refers to this as the flowback process (178 DCN
SGE00635). The flowback consists of a portion of the fluid injected into the wellbore combined
with formation water. At the wellhead, a combination of flowback water, sand, oil, and/or gas is
routed through phase separators, which separate products from wastes. Industry uses different
types of separators depending on a number of factors (e.g., formation, resource type). Figure
B-10 shows an example of a separator used for dry gas production (i.e., only requires gas and
water separation because there is no oil production).
Higher volumes of flowback water are generated in the beginning of the flowback
process; flowback rates decrease as the well goes into the production phase. Operators typically
store flowback in fracturing tanks onsite before treatment or transport offsite.28 In addition to
flowback, small quantities of oil and/or gas may be produced during the initial flowback process.
The small quantities of produced gas may be flared; if the operator is using "green completions,"
Fracturing tanks cannot be transported from one site to another when they contain wastewater. Wastewater is
typically transported via trucks with capacities of about 4,200 to 5,000 gallons (100 to 120 barrel) or via pipe (178
DCN SGE00635).
27
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Chapter B—Background on Unconventional Oil and Gas Extraction
the gas may instead be captured.29 If oil is produced, oil/water separators may be used30 or the oil
may be recovered from the flowback water after it is transported offsite.
Source: 191 DCN SGE00625
Figure B-10. Vertical Gas and Water Separator
Flowback typically lasts from a few days to a few weeks (78 DCN SGE00010; 212 DCN
SGE00011; 204 DCN SGE00622; 153 DCN SGE00592; 80 DCN SGE00286). At some wells,
the majority of fracturing fluid may be recovered within a few hours (78 DCN SGE00010; 212
DCN SGE00011; 204 DCN SGE00622; 153 DCN SGE00592; 80 DCN SGE00286). A 2009
report published by the Ground Water Protection Council and ALL Consulting stated that
operators recover between 10 and 70 percent of the fracturing fluid that they inject down the
wellbore (78 DCN SGE00010; 153 DCN SGE00592; 80 DCN SGE00286). Section C.3.1
provides more details on flowback generation rates over time and fracturing fluid recovery
percentages for specific UOG formations.
On April 17, 2012, the U.S. EPA issued regulations, required by the Clean Air Act, requiring the natural gas
industry to reduce air pollution by using green completions, or reduced emission completions. EPA has identified a
transition period until January 1, 2015, to allow operators to locate and install green completion equipment (40
C.F.R. part 60 and 63).
30 Operators sometimes use chemicals during the oil/water phase separation process.
28
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Chapter B—Background on Unconventional Oil and Gas Extraction
Source: 191 DCN SGE00625
Figure B-ll. Fracturing Tanks
2.3 Production
After the flowback process, the well begins producing oil and/or gas. During this
production phase, UOG wells produce oil and/or gas and water. This water, called "long-term
produced water" in this report, consists primarily of formation water and continues to be
produced throughout the lifetime of the well, though typically at much lower rates than flowback
(153 DCN SGE00592). Long-term produced water rates range from less than a barrel up to 4,200
gallons (100 barrels) per day (see Chapter C) and gradually decrease over the life of the well.31
The rates vary with each well because they are dependent on formation characteristics and the
completion success of the given well (see Chapter C for information about flowback and long-
term produced water volumes and characteristics).
When the well enters the production phase, operators typically remove the fracturing
tanks that were used during flowback and store long-term produced water in permanent above-
ground storage tanks referred to as produced water tanks with capacities that range from 4,200 to
33,600 gallons (100 to 800 barrels) (see Figure B-12) (190 DCN SGE00280; 179 DCN
SGE00275; 183 DCN SGE00636). The number of produced water tanks depends on the number
of wells that are producing on the well pad and the volume of water produced by each well. Most
operators configure water piping on the well pad so that each well has a designated produced
water tank (178 DCN SGE00635; 177 DCN SGE00276).
31 The life of an UOG well varies significantly by well. Some wells are expected to produce up to 40 years without
further stimulation, while others may only produce economically for 10 years (80 DCN SGE00286).
29
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Chapter B—Background on Unconventional Oil and Gas Extraction
Source: 179 DCN SGE00275
Figure B-12. Produced Water Storage Tanks
3 UOG WELL DRILLING AND COMPLETION ACTIVITY
The following subsections describe historical, current, and projections of future UOG
drilling activity, including:
Historical and current UOG well drilling activity
Total estimated UOG resource potential
Current and projections of future UOG well completions
3.1 Historical and Current UOG Drilling Activity
Since 2000, hydraulic fracturing coupled with drilling directional and horizontal
wellbores in unconventional formations has increased (209 DCN SGE01095). More recently,
drilling has also increased in liquid-rich formations.32 Baker Hughes, one of the world's largest
oilfield services companies, periodically publishes location and other data for active U.S. rigs.33
Figure B-13 shows Baker Hughes' estimates of total number of active drilling rigs in the United
Liquid-rich formations are those that either primarily produce oil or primarily co-produce natural gas with gas
condensates (i.e., hydrocarbons such as ethanes, propanes, and butanes). When gas condensates are depressurized at
the wellhead, they condense into a liquid phase.
33 Baker Hughes obtains data in part from RigData, a company that sells rig and well data. Rig data Baker Hughes
publishes are reported in major newspapers and journals (e.g., Oil and Gas Journal) and are used by the industry as
an indicator for demand of oil and gas equipment.
30
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Chapter B—Background on Unconventional Oil and Gas Extraction
States between January 2000 and November 2013 and shows drilling trajectory (i.e., directional,
horizontal, vertical) and product type (i.e., oil, gas). These counts include rigs that are drilling for
CBM and COG. Both horizontal drilling and oil well drilling have increased since 2000. (As of
November 15, 2013, 63 percent of rigs were drilling horizontal wells compared to 6 percent in
January 2000. 34) In 2009, horizontal well drilling surpassed vertical well drilling for the first
time in the United States. Shortly after, in 2011, oil well drilling surpassed gas for the first time
since 1993 (7 DCN SGE00504).
,250
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
\ear
Source: 48 DCN SGE00693
Figure B-13. Number of Active U.S. Onshore Rigs by Trajectory and Product Type over
Time35
Table B-2 shows the active drilling rigs in the United States by formation or basin,
broken down by well trajectory and resource type, as of November 2013. Based on data reported
by Baker Hughes and rig counts reported in other literature, the majority of rigs were drilling
Another 13 percent of wells were being drilled directionally in the United States as of November 8, 2013.
35 The sharp decrease in active drilling rigs observed in 2009 is likely attributed to the sudden drop in natural gas
and crude oil prices also experienced in 2009 (31 DCN SGE00989).
31
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Chapter B—Background on Unconventional Oil and Gas Extraction
into unconventional formations at this time (8 DCN SGE00502; 159 DCN SGE00595). Where
Baker Hughes did not specify the formation being drilled, counts may include a mixture of rigs
that are drilling for UOG, CBM, and COG. In 2012, nearly 1,800 active rigs drilled about 36,000
wells (9 DCN SGE00503).
32
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Chapter B—Background on Unconventional Oil and Gas Extraction
Table B-2. Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product Type (as of November 8, 2013)
Basinb
Permian
Other d
Western Gulf
Williston
Appalachian
Anadarko
Anadarko
Denver J.
Anadarko
TX-LA-MS
Salt
Fort Worth
Appalachian
Arkoma
Formation1"
c
c
Eagle Ford
c,e
Marcellus
Mississippi
Lime
Granite Wash
Niobrara
Woodfordf
Haynesville
Barnett
Utica
Fayetteville
Resource
Type"
Mix
Mix
Shale
Mostly shale6
Shale
Tight
Tight
Shale
Shale
Shale
Shale
Shale
Shale
Total
Gas Rigs by Well Trajectory
Directional
0
48
0
0
10
0
0
0
1
0
0
2
0
61
Horizontal
6
20
26
0
61
9
8
18
17
38
18
17
9
253
Vertical
1
20
0
0
8
0
0
0
0
0
0
0
0
29
Total
Gas
7
88
26
0
85
9
8
18
18
38
18
19
9
343
Oil Rigs by Well Trajectory"
Directional
21
55
17
16
0
2
0
o
3
2
0
0
0
0
116
Horizontal
206
139
174
155
0
58
50
25
27
2
9
15
0
860
Vertical
235
85
9
4
0
6
2
5
3
0
9
2
0
360
Total
Oil
462
279
200
175
0
66
52
33
32
2
18
17
0
1,336
Total
Rigs
469
367
226
175
85
75
60
51
50
40
36
36
9
1,679
Sources: 48 DCN SGE00693
a—Oil rigs include six "miscellaneous" rigs reported by Baker Hughes (8 DCN SGE00502).
b—Baker Hughes (8 DCN SGE00502) reported a mixture of basins and formations. The EPA classified them by resource type (i.e., shale, tight) when specific
formations were reported. When formations were not reported, the EPA classified the resource type as a "mix" of resources (conventional, tight, shale).
c—Baker Hughes reported basin as opposed to formation for these areas. Therefore, these areas may include rigs drilling in conventional and unconventional
formations.
d—The majority of the "Other" rigs were drilling in Texas, Louisiana, Wyoming, California, Utah, and Colorado. The remaining rigs in the "Other" category
were distributed evenly throughout the United States.
e—The majority of these rigs are expected to have been drilling in the Bakken shale formation based on rig counts reported by the EIA( 159 DCN SGE00595).
f—This formation includes the Woodford-Cana, Arkoma Woodford, and Ardmore Woodford formations.
33
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Chapter B—Background on Unconventional Oil and Gas Extraction
3.2 UOG Resource Potential
Assessments by the U.S. Geological Survey (USGS) and the EIA show substantial
potential for new UOG wells. Using the USGS and EIA assessments, this section quantifies how
many new UOG wells may be drilled in the future (i.e., new well potential) to estimate the
potential number of new UOG extraction wastewater sources. The EIA also calculates new well
potential in its AEO but only for several sub-formations.36 The EPA used the EIA methodology
to calculate new well potential for all UOG formations.37 This analysis is documented in more
detail in a separate memorandum titled Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for
Oil and Gas Extraction (48 DCN SGE00693; 50 DCN SGE00693.A02).
The two EIA-reported parameters that the EPA used to calculate new well potential are
described below. The EIA's estimates of resource potential are primarily based on geological
characteristics published by the USGS, which in turn rely on historical production data from
existing wells and the technology deployed at the time of assessment. However, the EIA adjusts
these estimates annually to account for the ongoing changes in drilling and completion practices
and to account for formations not yet assessed by the USGS (32 DCN SGE00988; 31 DCN
SGE00989).
• Estimated ultimate recovery per well (EUR)—EUR is the quantity of oil and/or gas
that is produced by a single well over its life.
• Technically recoverable resources (TRR)—The TRR is the quantity of oil and/or
gas producible from a geological formation using current drilling and completion
technology. The EIA's TRR estimates are functions of total formation geographic
area (square miles), the portion of formation land area that can be developed for oil
and gas extraction, average well spacing assuming that the formation is fully
developed, and EUR per well. TRR is the sum of proven reserves and unproven
resources.38
To evaluate new well potential, the EPA calculated new well potential for each formation
or sub-formation by dividing the TRR by the EUR. Table B-3 summarizes the total new well
potential the EPA calculated for the four UOG resource types.39 It also shows the approximate
number of current wells based on the EPA's analysis of Drillinginfo's (DI) Desktop® well
database (29 DCN SGE00520). Appendix F provides EUR and TRR on a formation basis based
on this analysis. To calculate total TRR and new well potential by resource type, the EPA
36 For example, the Assumptions to the 2014 AEO reported new well potential for several, but not all, Bakken sub-
formations: 29,186 wells. The EPA estimated approximately 28,562 new Bakken wells for the same Bakken sub
formations. Differences between EIA and EPA new well potential are due to rounding (32 DCN SGE00988).
37 These estimates do not factor in future changes to TRR estimates by the EIA, advances in drilling technology, or
economic conditions that ultimately affect how many wells UOG operators drill over time (31 DCN SGE00989; 32
DCN SGE00988).
38 Proven reserves are resources that are currently developed commercially or have been demonstrated with
reasonable certainty to be recoverable in future years under existing economic conditions and current technologies.
Unproven resources are resources that have been confirmed by exploratory drilling but are not yet commercially
developed.
39 These estimates only include shale and tight oil and gas resources. It does not include CBM or COG.
34
-------
Chapter B—Background on Unconventional Oil and Gas Extraction
summed the TRR and the new well potential for all formations in each resource type shown in
Table F-2 and Table F-3. The results presented in Table B-3 show that the UOG new well
potential is much greater than the active well count. The EPA estimates that approximately 2.2
million potential new UOG wells—with associated extraction wastewater—may be drilled in the
future.
Table B-3. UOG Potential by Resource Type as of January 1, 2012
Resource
Type
Shale gas
Shale oil
Tight gas
Tight oil
All UOG
Weighted
Average Oil
EUR
(MMbls per
well)
0.007
0.079
0.006
0.105
0.027
Weighted
Average Gas
EUR(Bcfper
well)
0.543
0.099
0.483
0.076
0.411
Total Oil TRR
(MMbls)
6,200
26,300
4,200
22,500
59,200
Total Gas
TRR (Bcf)
501,500
33,100
352,200
16,400
903,200
Total New
Well
Potential
(Beginning in
2012)
923,000
333,000
729,000
215,000
2,200,000
2010-2011
Active Well
Countb
H: 22,400
D: 1,820
V: 15,100
U: 15,300
H: 5,620
D: 9,230
V: 59,600
U: 32,800
H: 28,000
D: 11,100
V: 74,700
U: 48,100
Sources: 48 DCN SGE00693
a—Gas production from shale and tight oil resources is associated gas that is produced simultaneously with oil.
b—Well counts are based on ERG's Analysis of 'DIDesktop® memorandum (45 DCN SGE00963). These well
counts may not be all-inclusive.
Abbreviations: MMbls-million barrels; Bcf-billion cubic feet of gas; EUR—estimated ultimate recovery (per well);
TRR—technically recoverable resources; H—horizontal; D—directional; V—vertical; U—trajectory unknown
3.3 Current and Projections of Future UOG Well Completions
In 2012 alone, more than 22,00040 oil and gas wells were hydraulically fractured
nationwide (199 DCN SGE00585). As previously explained, hydraulic fracturing is currently the
most popular well stimulation technique for UOG wells. A survey conducted by the American
Petroleum Institute (API) and the American Natural Gas Alliance (ANGA) shows that, as of
2010, nearly all unconventional wells were being completed using hydraulic fracturing (146
DCN SGE00291).41 Operators may also refracture existing oil and gas wells. Based on a national
database maintained by IHS, Inc., 0.13 to 0.35 percent of well completions involving hydraulic
fracturing from 2000 to 2010 were reported as refracturing of existing oil and gas wells (210
The actual number of wells fractured in 2012 is greater than 22,000 because this number is based on FracFocus
data and some states where fracturing is common (e.g., Michigan) did not yet require reporting to FracFocus in
2012.
41 This survey included well completion information for 5,307 well completions in 2010, consisting of a mixture of
conventional and unconventional wells. The survey results showed that more than 96 percent of tight gas wells and
99 percent of shale gas wells surveyed were hydraulically fractured. The survey also showed that 69 percent of
conventional wells were hydraulically fractured.
35
-------
Chapter B—Background on Unconventional Oil and Gas Extraction
DCN SGE01095.A09). A more recent survey of 205 UOG operators conducted by the Petroleum
Equipment Suppliers Association (PESA)42 shows that in 2012 and 2013 approximately 10
percent of well completions involving hydraulic fracturing were refracturing of existing oil and
gas wells (136 DCN SGE00575).
In 2012, IHS, Inc. estimated the total number of UOG wells that UOG operators may
complete through 2035 (94 DCN SGE00728). The EPA generated Figure B-14 using data
published by fflS (48 DCN SGE00693). The figure shows the projected number of UOG wells39
completed annually and cumulatively. Unconventional gas is further broken down into tight gas
and shale gas. The projections estimated by IHS show a gradual increase in annual UOG well
completions through 2035.
12,000
10,000
-s
% s.ooo
I
c
w
= 6.000
4.000
27000
— ~ Arrvjl L'mjnvaitiQLal Oil
— — Arn-jl L"£-:OEV3:tiOE3l Gai
---- ArrTjl Ti Ett Ga=
....... Annal State Oa;
ivj Urconvsitioral Oil
250,000
- 200.000
- 150,000
100.00C
- 50rOOO
=
5
2025
Year
2030
2035
Source: 48 DCN SGE00693
Figure B-14. Projections of UOG Well Completions
The PESA represents the energy industry's manufacturers and oilfield service and supply companies. Its mission
is to promote and advocate for policies that will support the oilfield service sector's continued job creation,
technological innovation, and economic stability.
36
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Chapter C. UNCONVENTIONAL OIL AND GAS EXTRACTION WASTEWATER
VOLUMES AND CHARACTERISTICS
Since 2000, horizontal drilling and hydraulic fracturing of UOG resources has increased
dramatically (209 DCN SGE01095). The EIA, in its 2014 AEO, projects that, within the next 30
years, the majority of the country's natural gas will come from unconventional resources and
unconventional oil production will continue to increase substantially (31 DCN SGE00989).
Consequently, industry experts expect UOG produced water volumes to continue to increase (34
DCN SGE00708; 98 DCN SGE00479; 95 DCN SGE00722; 141 DCN SGE00768.A01; 72 DCN
SGE00768.A25).
This chapter discusses UOG extraction wastewater volumes and characteristics. The EPA
is proposing to define "UOG extraction wastewater" as sources of wastewater pollutants
associated with production, field exploration, drilling, well completion, or well treatment.43 This
includes the following sources:
• Produced water—the water (brine) brought up from the hydrocarbon-bearing strata
during the extraction of oil and gas. This can include formation water, injection water,
and any chemicals added downhole or during the oil/water separation process. Based
on the stage of completion and production the well is in, produced water can be
further broken down into the following components:
— Flowback—the wastewater generated by UOG wells during the flowback
process of well completion. After the hydraulic fracturing procedure is
completed and pressure is released, the direction of fluid flow reverses,
and the fluid flows up through the wellbore to the surface. The water that
returns to the surface is commonly referred to as "flowback."
— Long-term produced water—the wastewater generated by UOG wells
during the production phase after the initial flowback process. Long-term
produced water continues to be produced throughout the lifetime of the
well.
• Drill cuttings—the particles generated by drilling into subsurface geologic formations
and carried out from the wellbore with the drilling fluid (mud).
• Drilling wastewater—the liquid waste stream separated from recovered drilling fluid
(mud) and drill cuttings during the drilling process. Drilling fluid is the circulating
fluid used in the rotary drilling of wells to clean and condition the hole and to
counterbalance formation pressure.
• Produced sand—the slurried particles used in hydraulic fracturing, the accumulated
formation sands, and scales particles generated during production. Produced sand also
includes desander discharge from the produced water waste stream, as well as
blowdown of the water phase from the produced water treatment system.
43 Stormwater is not considered a source of UOG extraction wastewater. In general, no permit is required for
discharges of stormwater from any field activities or operations associated with oil and gas production, except as
specified in 40 C.F.R. part 122.26(c)(l)(iii) for discharges of a reportable quantity or that contribute to a violation of
a water quality standard.
37
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
The EPA identified drilling wastewater and produced water as the major sources of
wastewater pollutants associated with UOG extraction, so these wastewaters are described
further below. The following subsections discuss volumes and chemical constituents found in
fracturing fluid typically used by UOG operators and volumes and characteristics of drilling
wastewater, flowback, and long-term produced water generated by UOG operations. The EPA
identified this information from existing data sources, including state and federal agency
databases, journal articles and technical papers, technical references, industry/vendor telephone
calls, industry site visits, and meetings with industry. The EPA reported the data exactly as
reported in existing literature throughout Chapter C. In some instances, the EPA compiled the
existing data into a separate document to compile and analyze the data. These separate
memoranda, referenced throughout Chapter C, are titled Unconventional Oil and Gas (UOG)
Produced Water Volumes and Characterization Data Compilation (56 DCN SGE00724) and
Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed
Effluent Limitations Guidelines and Standards for Oil and Gas Extraction (48 DCN SGE00693).
Section C.I discusses the characteristics of fracturing fluid,44 Section C.2 discusses
typical volumes of UOG extraction wastewater, and Section C.3 presents constituents that are
typically found in UOG extraction wastewater. Section C.3 extensively discusses TDS, a
parameter that is often used to characterize UOG extraction wastewater because it provides a
measure of dissolved matter including salts (e.g., sodium, chloride, nitrate), metals, minerals, and
organic material (1 DCN SGE00046). Data in Section C.3 show that sodium chloride makes up
the majority of TDS in UOG produced water. The data also show that chloride contributes
heavily to the makeup of TDS in UOG drilling wastewater. TDS is not a specific chemical, but is
defined as the portion of solids that pass through a filter with a nominal pore size of 2.0 jim or
less as specified by Standard Method 2540C-1997.45 Because TDS in UOG produced water
primarily consists of inorganic salts and other ionic species, conductivity measurements may also
be used to estimate TDS.46 High measurements of specific conductivity are indicative of high
TDS concentrations.
TDS and chloride are potential concerns in the management of UOG extraction
wastewater because of the high concentrations of these parameters in the wastewater. UOG
produced water can have TDS concentrations up to 400,000 mg/L, which is over 10 times the
concentration of TDS typically found in seawater (i.e., 35,000 mg/L). Chapter D discusses UOG
extraction wastewater management and disposal practices. Section D.3 discusses
reusing/recycling UOG extraction wastewater in hydraulic fracturing and the different factors
(e.g., pollutant concentrations) that operators consider when reusing/recycling UOG extraction
wastewater. Section D.5 discusses the problems that a POTW may experience if high
concentrations of TDS and other UOG extraction wastewater constituents are present in POTW
influent.
44 The type of fracturing fluid and total fracturing fluid volume may dictate the characteristics of UOG produced
water and are therefore described in this chapter.
45 40 C.F.R. part 136 lists standard method 2540C as an approved test method for TDS.
46 The electrical conductivity of water is directly related to the concentration of dissolved ionized solids in the water.
38
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
1 FRACTURING FLUID CHARACTERISTICS
As discussed in Section B.2.2, most UOG resources (e.g., tight oil, shale gas) are
stimulated using hydraulic fracturing. Hydraulic fracturing of UOG resources typically requires
high volumes of fracturing fluid, consisting of a base fluid mixed with proppant (e.g., sand) and
chemicals. The quantity of each fracturing fluid component varies by operator, basin, formation,
and resource type. The remainder of this subsection discusses the sources used for base fluid,
concentrations of chemical additives, and observed constituents in fracturing fluids.
1.1 Base Fluid Composition
The primary component of fracturing fluid is the base fluid to which proppant (sand) and
chemicals are added. Fracturing fluids are typically water-based, though cases of non-aqueous
fracturing fluids are documented in the literature (e.g., compressed nitrogen, propane) (209 DCN
SGE01095). Base fluid typically consists of only fresh water (surface, groundwater, or municipal
water) or a mixture of fresh water, reused/recycled UOG produced water, and/or other sources
(e.g., treated municipal wastewater, groundwater) (126 DCN SGE00639; 136 DCN SGE00575).
The PESA reports the following percentages of UOG operators using each water source as
fracturing fluid in the United States (136 DCN SGE00575):
• Surface water (e.g., rivers, lakes) (40 percent)
• Groundwater (36 percent)
• City/ municipal water47 (16 percent)
• Recycled UOG produced water (7 percent)48
• Industrial wastewater (1 percent)
Table C-l shows the composition of base fluid for basins and/or formations with
available data. Fresh water sources are those generally characterized by having low
concentrations of dissolved salts and other TDS (e.g., ponds, lakes, rivers, certain underground
aquifers). Brackish sources are those with more salinity than freshwater, but not as much as
seawater (e.g., other industrial wastewater, certain groundwater aquifers). Fresh water is the most
common source of base fluid across all basins. As shown in Table C-l, brackish sources are used
more often in arid regions (e.g., the Permian and Gulf Coast basins in Texas and New Mexico).
For basins/formations where the EPA identified projected data in addition to historic data, the
EPA created a separate set of columns for each basin/formation combination. Projected
percentages for the year 2020 are reported parenthetically in Table C-l.
In general, the fraction of base fluid that can be composed of UOG produced water is
limited by two factors (125 DCN SGE00556; 148 DCN SGE00710):
47 The PESA does not specify whether this water source is potable drinking water or treated municipal effluent (136
DCN SGE00575).
48 The amount oft
See Section D.2 for more information about UOG wastewater reuse/recycle.
48 The amount of UOG wastewater that is reused/recycled in fracturing fluid varies significantly by UOG formation.
39
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Produced water volume—When large volumes of flowback and long-term produced
water are generated by other UOG wells in the area, reuse/recycle wastewater can
make up a larger portion of base fluid water on average.
Produced water quality—When the concentration of TDS in UOG produced water
rapidly increases after fracturing, it may have less potential for reuse/recycle as a
source of base fluid to fracture another well (148 DCN SGE00710).
Table C-l. Sources for Base Fluid in Hydraulic Fracturing
Basin
All California
Basins
Anadarko
Appalachian
Arkoma
Fort Worth
Gulf Coast
Permian (Far
West)
Permian
(Midland)
TX-LA-MS
Nationwide
UOG Formation
All formations
All formations
Marcellus (PA)
Marcellus (WV)
Fayetteville
Barnett
Eagle Ford
All formations
All formations
All formations
All formations
Resource Type
shale and tight
shale and tight
shale
shale
shale
shale
shale
shale and tight
shale and tight
shale and tight
shale and tight
Percentage of Total Base Fluid Used for Hydraulic
Fracturing"
Fresh Waterb
96
50 (40)
82 to 90
77 to 83c'd
70
92 (75)
80 (50)
20 (20)
68 (35)
95 (90)
40
Brackish Waterb
0
30 (30)
0
C
0
3(15)
20 (40)
80 (30)
30 (40)
0(0)
53
Reused/Recycled
UOG Produced
Water
4
20 (30)
10 to 18
6 to 10
30
5(10)
0(10)
0(50)
2(25)
5(10)
7
Sources: 48 DCN SGE00693
a— Projected data for the year 2020 are shown parenthetically which were reported as the "most likely" scenario by
Nicot et al. 2012 (126 DCN SGE00639).
b— Fresh water is naturally occurring water on the Earth's surface. Examples include ponds, lakes, rivers and
streams, and certain underground aquifers. Fresh water is generally characterized by having low concentrations of
dissolved salts. Brackish water is water that has more salinity than fresh water, but not as much as seawater.
Example sources include certain underground aquifers, effluent from publicly owned treatment plants (POTWs), and
wastewater from other industries.
c—In addition to the 77 to 83 percent fresh water reported for the Marcellus shale in WV, 6 to 17 percent of base
fluid was reported as "purchased water" and 1 to 3 percent was reported as groundwater both of which could be
fresh or brackish. Neither of these values are included in this table.
d—Hansen et al. 2013 (84 DCN SGE00532) reported this data as "surface water".
"—" indicates no data.
1.2 Additives
In addition to base fluid, operators add proppant and chemicals to adjust the fracturing
fluid properties. Proppant generally makes up 10 percent or less of the total fracturing fluid by
mass. Chemical additives in total typically make up less than 0.5 percent of the total fracturing
40
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
fluid by mass (78 DCN SGE00010). The additives and the quantity of additives used in
fracturing fluid depend on the formation geology, base fluid characteristics, and UOG operator
(201 DCN SGE00721; 3 DCN SGE00070; 70 DCN SGE00780; 73 DCN SGE00781). Fracturing
fluid additives are constantly evolving as UOG operators determine the most efficient
composition to use for each fracture job. There are two general types of water-based fracturing
fluids:
• Slickwater fracturing fluids consist of small quantities of friction reducer, biocides,
scale inhibitors, surfactants, and propping agents. Operators generally use slickwater
designs to fracture dry natural gas producing formations (148 DCN SGE00710; 40
DCN SGE00705).
• Gel fracturing fluids include higher quantities of gels to increase fluid viscosity that
enables the fluid to carry higher concentrations of propping agents into the formation.
Using gel fracturing fluids requires less total base fluid volume than using slickwater
fracturing fluids, but gel fracturing fluids contain more additives and proppant.
Consequently, gel fracturing fluids are more complex than slickwater fracturing fluids
and are more sensitive to the quality of base fluid (148 DCN SGE00710; 40 DCN
SGE00705). Operators generally use gel fracturing fluids to fracture liquid-rich
formations (40 DCN SGE00705).
In 2015, the EPA's Office of Research and Development (ORD) released a report
summarizing additives used by operators based on public disclosures to FracFocus49 (201 DCN
SGE00721). In addition, several sources have published information regarding fracturing fluid
additives and their uses in hydraulic fracturing (3 DCN SGE00070; 70 DCN SGE00780; 73
DCN SGE00781; 18 DCN SGE00966). Table C-2 shows specific additives used by operators
categorized by purpose. Many additives can have multiple purposes depending on the exact
design of the fracturing fluid. Table C-3 shows concentrations of the most common chemicals
identified by operators in the FracFocus public disclosures, summarized in the EPA report, for
hydraulically fractured gas and oil wells.
Table C-2. Fracturing Fluid Additives, Main Compounds, and Common Uses
Additive
Type3
Acid
Biocide
Breaker
Common
Compound(s)b
Hydrochloric acid;
Muriatic acid
Glutaraldehyde; 2,2-
dibromo-3-
nitrilopropionamide
Peroxydisulfates; salts
Purpose
Removes cement and drilling mud from casing perforations prior to
fracturing fluid injection.
Inhibits growth of organisms that could produce gases (particularly
hydrogen sulfide) that could contaminate methane gas; prevents the growth
of bacteria that can reduce the ability of the fluid to carry proppant into the
fractures by breaking down the gelling agent.
Reduces the viscosity of the fluid by "breaking down" the gelling agents in
order to release proppant into fractures and enhance the recovery of the
fracturing fluid.
Operators submit reports for individual wells to FracFocus. These reports include date of completion, well type
(oil, gas), total fracturing fluid volume, well API number, well depth, location coordinates, and the concentrations of
additives. These reports mostly represent wells completed in UOG formations but may also include some in
conventional and coalbed methane formations.
41
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-2. Fracturing Fluid Additives, Main Compounds, and Common Uses
Additive
Type3
Clay
stabilizer
Corrosion
inhibitor
Crosslinker
Friction
reducer
Gel
Iron control
pH adjusting
agent
Proppant
Scale
inhibitor
Surfactant
Common
Compound(s)b
Potassium chloride
Ammonium bisulfite;
methanol
Borate salts; potassium
hydroxide
Petroleum distillates
Guar gum;
hydroxyethyl cellulose
Citric acid
Acetic acid; potassium
or sodium carbonate
Quartz; sand; silica
Ethylene glycol
Isopropanol;
naphthalene
Purpose
Creates a brine carrier fluid that prohibits fluid interaction (e.g., swelling)
with formation clays; interaction between fracturing fluid and formation
clays could block pore spaces and reduce permeability.
Reduces rust formation on steel tubing, well casings, tools, and tanks (used
only in fracturing fluids that contain acid).
Increases fluid viscosity to allow the fluid to carry more proppant into the
fractures.
Minimizes friction, allowing fracturing fluids to be injected at optimum
rates and pressures.
Increases fracturing fluid viscosity, allowing the fluid to carry more
proppant into the fractures.
Sequestering agent that prevents precipitation of metal oxides, which could
plug the formation.
Adjusts and controls the pH of the fluid in order to maximize the
effectiveness of other additives such as crosslinkers.
Used to hold open the hydraulic fractures, allowing the gas or oil to flow to
the production well.
Prevents the precipitation of carbonate and sulfate scales (e.g., calcium
carbonate, calcium sulfate, barium sulfate) in pipes and in the formation.
Reduces the surface tension of the fracturing fluids to improve fluid
recovery from the well after fracture is completed.
Sources: 201 DCN SGE00721; 3 DCN SGE00070; 70 DCN SGE00780; 73 DCN SGE00781; 18 DCN SGE00966
a—Operators do not use all of the chemical additives in hydraulic fracturing fluid for a single well: they decide
which additives to use on a well-by-well basis.
b—The specific compounds used in a given fracturing operation will vary depending on company preference, base
fluid quality, and site-specific characteristics of the target formation.
42
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-3. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in Gas and Oil Wells from FracFocus (2011-
2013)
Specific Constituents
Hydrochloric acid
Guargum
Phenolic resin
Distillates, petroleum, hydrotreated light
Ethylene glycol
Potassium hydroxide
Methanol
Ethanol
Saline
Sodium hydroxide
Glutaraldehyde
Peroxydisulfuric acid, diammonium salt
Solvent naphtha, petroleum, heavy arom.
2-Butoxyethanol
Isopropanol
Acetic acid
Citric acid
2,2-Dibromo-3-nitrilopropionamide
Naphthalene
Propargyl alcohol
CAS
Number
7647-01-0
9000-30-0
9003-35-4
64742-47-8
107-21-1
1310-58-3
67-56-1
64-17-5
7647-14-5
1310-73-2
111-30-8
7727-54-0
64742-94-5
111-76-2
67-63-0
64-19-7
77-92-9
10222-01-2
91-20-3
107-19-7
Maximum Concentration in Hydraulic Fracturing Fluid (% by mass)
Gasa
Number of
Reported
Uses
12,351
3,586
—
11,897
5,493
—
12,269
6,325
3,608
4,656
5,635
4,618
3,287
3,325
8,008
3,563
4,832
3,668
3,294
5,811
Median
Concentration
0.078
0.10
—
0.017
0.0061
—
0.0020
0.0023
0.0091
0.0036
0.0084
0.0045
0.0044
0.0035
0.0016
0.0025
0.0017
0.0018
0.0012
0.000070
5th to 95th
Percentile
Concentration
0.0063-0.67
0.00057-0.38
—
0.0021-0.27
0.000080-0.24
—
0.000040-0.053
0.00012-0.090
0-0.12
0.000020-0.088
0.00091-0.023
0.000050-0.045
0.000030-0.030
0.000010-0.041
0.000010-0.051
0-0.028
0.000050-0.011
0.000070-0.022
0.0000027-0.0050
0.000010-0.0016
Oilb
Number of
Reported
Uses
10,029
9,110
3,109
10,566
10,307
7,206
12,484
3,536
3,692
8,609
5,927
10,350
3,821
4,022
8,031
4,623
3,310
—
—
5,599
Median
Concentration
0.29
0.17
0.13
0.087
0.023
0.013
0.022
0.026
0.0071
0.010
0.0065
0.0076
0.0060
0.0053
0.0063
0.0047
0.0047
—
—
0.00022
5th to 95th
Percentile
Concentration
0.013-1.8
0.027-0.43
0.019-2.0
0.00073-0.39
0.00086-0.098
0.000010-0.052
0.00064-0.16
0.000020-0.16
0-0.27
0.00005-0.075
0.00027-0.020
0.00028-0.067
0-0.038
0-0.17
0.00007-0.22
0-0.047
0.00016-0.024
—
—
0.000030-0.0030
Source: 48 DCN SGE00693
a—Represents 17,035 FracFocus disclosures for gas wells.
b—Represents 17,640 FracFocus disclosures for oil wells.
"—" indicates this additive was not commonly reported.
43
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
1.3 Fracturing Fluids
Fracturing fluid is the final mixture of base fluid and additives. Its total volume depends
on the well trajectory (i.e., vertical, directional, horizontal) and the type of fracturing fluid used
(e.g., gel, slickwater) (209 DCN SGE01095). Operators fracture UOG wells using 50,000 to over
10 million gallons (1,200 to over 238,000 barrels) of fracturing fluid per well along with up to
millions of pounds of sand (i.e., proppant). Operators typically fracture horizontal wells in eight
to 23 stages, using between 250,000 and 420,000 gallons (6,000 and 10,000 barrels) of fracturing
fluid per stage (190 DCN SGE00280). Literature reports that tight oil and gas wells typically
require less fracturing fluid than shale oil and gas wells (86 DCN SGE00533). Typical volumes
of fracturing fluid vary by UOG formation, well trajectory, number of stages, and resource type
and are provided in Section C.2.
The concentrations of TDS in fracturing fluid are often low (<20,000 mg/L) compared to
levels found in UOG produced water, which suggests that the majority of the TDS in UOG
produced water is contributed by the formation (see Section C.3) (16 DCN SGE00110, 85 DCN
SGE00414). Other constituents, such as total organic carbon (TOC) and biochemical oxygen
demand (BODs), have been found at higher concentrations in fracturing fluid than in flowback
and long-term produced water. For example, one study of Marcellus UOG produced water found
median concentrations of BOD5 in fracturing fluid of about 1,70050 mg/L but BOD5 in the
corresponding flowback and long-term produced water of 30051 mg/L or less on average (85
DCN SGE00414). As indicated in Table C-2 and Table C-3, organic materials (which contribute
to BOD5 and TOC) are typical chemical additives in fracturing fluid (85 DCN SGE00414).
2 UOG EXTRACTION WASTEWATER VOLUMES
As explained previously, UOG wells generate three main types of wastewater over the
life of the well: drilling wastewater, flowback, and long-term produced water (these latter two
are collectively referred to as produced water). These wastewater streams' flow rates and total
volumes generated per well vary based on several factors, including:
• Time since flowback commenced
• Resource type (e.g., shale oil, tight gas)
• Specific geology properties (e.g., presence of naturally occurring water)
• Well trajectory (i.e., horizontal, directional, vertical)
The following two subsections quantify wastewater volumes generated during the UOG
well development process. Section C.2.1 summarizes general trends in UOG extraction
wastewater volumes for each part of the well development process by resource type and well
50 This study reported 1,700 mg/L as the median concentration based on 19 samples. The overall range of BOD was
4.3 to 47,400 mg/L.
51 This study reported 330 mg/L as the median concentration based on 19 flowback samples. The overall range of
BOD was 30 to 1,440 mg/L.
44
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
trajectory. Section C.2.2 provides detailed produced water volumes by UOG formation and well
trajectory.52
2.1 UOG Extraction Wastewater Volumes by Resource and Well Trajectory
This section quantifies the volumes of UOG extraction wastewater generated, on a per
well basis, for the following three wastewater components:
• Drilling wastewater
• Flowback
• Long-term produced water
Flowback and long-term produced water are the largest volumes of UOG extraction
wastewater. Figure C-l shows a breakdown of UOG extraction wastewater volumes generated
from Marcellus shale wells in Pennsylvania based on data from PA DEP's statewide waste
production reports for all wells active between 2004 and 2013 (46 DCN SGE00739). This trend
varies by formation and, sometimes, within formations. However, a general rule of thumb for all
UOG formations is that the total volume of UOG produced water (i.e., flowback, long-term
produced water) generated by a well over its lifetime is approximately 50 percent flowback and
50 percent long-term produced water—despite the fact that flowback is generated over less than
30 days and long-term produced water is generated over the well life, which may be more than
10 years (94 DCN SGE00728).53
Section C.2.2 does not include drilling wastewater volumes by formation and drill type because EPA identified
less detailed data for drilling wastewater volumes compared to UOG produced water volumes.
53 Figure C-l shows that long-term produced water is more than 50 percent of total UOG produced water for
Marcellus shale wells likely because Marcellus wells generate relatively lower flowback volumes compared to other
UOG formations (see Table C-8).
45
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Horizontal (5,320 wells)
(Total UOG Extraction
Wastewater: 3,116Mgal)
Vertical (724 wells)
(Total UOG Extraction
Wastewater: 296Mgal)
Drilling
Wastewater, 9%
Drilling
Wastewater, 6%
Long-term
Produced Water,
58%
Long-term
Produced Water,
59
Flowback, 35%
Sources: 46 DCN SGE00739
Figure C-l. UOG Extraction Wastewater Volumes for Marcellus Shale Wells in
Pennsylvania (2004-2013)
Figure C-2 shows the quantities of produced water (i.e., flowback, long-term produced
water) generated from UOG wells from the time of well completion to the end of the well life.
The produced water generation rates reflect aggregated data from multiple UOG formations;
"n" is the number of data points for each time period.55 As shown in the figure, UOG produced
water generation rates are highest immediately after well completion, when there is little or no
oil and gas production (flowback). During the transition from the flowback process to production
(within weeks of well completion), produced water generation rates decrease significantly and
eventually level out. During production, produced water generation rates gradually decrease over
the life of the well (long-term produced water).
54
As explained in Chapter B, the length of the flowback process is variable. Literature generally reports it as 30
days or less (83 DCN SGE00532). Other operators report it as only lasting five days (151 DCN SGE00350).
55 Data for the first 90 days represent the Marcellus, Barnett, Woodford, Codell-Niobrara, Bakken, and Fayetteville
UOG formations. Data beyond 90 days (long-term produced water) are from Table C-8.
46
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
175.000
Source: 56 DCN SGE00724
Tim e Af te r Fracturing
Figure C-2. Ranges of Typical Produced Water Generation Rates over Time After
Fracturing
2.1.1 Drilling Wastewater
Volumes of drilling wastewater typically increase with the length of the wellbore. For
example, a vertical well will typically produce a smaller volume of drilling wastewater than a
horizontal well drilled into the same formation, because the latter requires additional drilling
fluid to complete the horizontal lateral (46 DCN SGE00739). Table C-4 illustrates this trend for
UOG wells drilled into the Marcellus formation in Pennsylvania.
Table C-4. Median Drilling Wastewater Volumes for UOG Horizontal and Vertical Wells
in Pennsylvania
Well
Trajectory
Horizontal
Vertical
Median Drilling Fluid
Volume per Well
(gallons)
46,000
37,000
Range of Drilling Fluid
Volume per Well (gallons) a
3,200-210,000
5,000-210,000
Typical Total
Measured Depth b
10,000-11,000
6,000-7,000
Number of
Data Points
3,055
209
Source: 46 DCN SGE00739
a— These ranges are based on the 10th and 90th percentile of volumes reported for individual wells.
b— Total measured depth is the true length of wellbore drilled (i.e., sum of the vertical and horizontal).
47
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
The EPA collected information on volumes of drilling wastewater generated per well.
Table C-5 shows typical volumes generated by UOG wells by resource type and formation.
Operators report that nearly all of the drilling fluid used per well is recovered as wastewater at
the end of drilling.56 Therefore, where it had information on drilling fluid volumes but not the
resulting drilling wastewater volume, the EPA assumed the former is representative of the latter.
Table C-5. Drilling Wastewater Volumes Generated per Well by UOG Formation
Resource
Type
Shale
Tight
Shale
Shale
Shale
Tight
Tight
Shale
Shale
Tight
Shale
Formation
Haynesville
Anadarko Basinb
Niobrara
Barnett
Permian Basinb
Granite Wash
Cleveland
Eagle Ford
Utica
Mississippi Lime
Marcellus
Range (gallons)
420,000-1,100,000
222,000^20,000
C
170,000-500,000
95,200-420,000
C
C
130,000^20,000
C
C
2,400 - 170,000
Median
(gallons)
600,000
310,000
300,000
250,000
210,000
200,000
200,000
160,000
100,000
100,000
92,000
Typical Total
Measured Depth"
(feet)
13,000 - 19,000
C
7,500 - 13,000
8,500 - 14,000
C
C
C
6,000 - 16,000
6,000 - 19,000
C
7,300 - 13,000
Number of Data
Points
5
2
1
6
8
1
1
7
1
1
2,072
Source: 55 DCN SGE00740
a—Total measured depth is the true length of wellbore drilled (i.e., sum of the vertical and horizontal).
b—Specific formation was not reported.
c—The EPA identified only one data point for these formations. Therefore, there is no range to display.
2.1.2 Produced Water: Flowback
As described above, for purposes of this document, produced water includes flowback in
addition to long-term produced water. Table C-6 quantifies the portion of fracturing fluid
returned as flowback.5 Because the volume of fracturing fluid used during well stimulation
CO
affects flowback quantities, fracturing fluid volumes are also listed. Given data in the table,
total flowback volumes typically range between 26,000 to 300,000 gallons (620 to 7,000 barrels)
per well. On average, horizontal shale wells generate the highest volumes of flowback. In terms
of wastewater management, operators must consider that the flowback process generates large
volumes of wastewater in a short period of time (e.g., 30 days) compared to long-term produced
water that is generated in small volumes over a long period of time.
Some drilling fluid volume may be lost downhole and/or to moisture in the cuttings, but these losses account for a
relatively small percentage of the total volume (191 DCN SGE00625).
57 The EPA explains how it differentiated between flowback and long-term produced water volumes in literature in
its memorandum Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data
Compilation (56 DCN SGE00724).
58 Approximate flowback volumes can be estimated by multiplying total fracturing volume by the percent of
fracturing fluid returned during flowback. However, EPA does not show this calculation in Table C-6 because not
all data sources report both fracturing fluid volume and percent of fracturing fluid recovered as flowback.
48
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
59
Table C-6. UOG Well Flowback Recovery3* by Resource Type and Well Trajectory
Resource
Type
Shale
Tight
Trajectory
H
D
V
H
D
V
Fracturing Fluid (MG)a
Median
4.0
1.6
1.2
2.2
0.60
0.31
Range
0.13-15
0.051-12
0.015-22
0.042-9.4
0.056-4.0
0.019-4.0
Number of
Data Points
50,053
124
4,152
765
693
1,287
Flowback (Percent of Fracturing
Fluid Returned)3
Median
6
14
24
7
6
8
Range
1-50
4-31
7-75
7-60
0-60
1-83
Number of
Data Points
6,488
19
18
39
263
48
Source: 56 DCN SGE00724 (Data are based on aggregated data from Table C-8, which contains volumes by
formation)
a—Most of the underlying fracturing fluid volume data and percentages of fracturing fluid returned as flowback
were reported in different sources. To avoid representing the data incorrectly, the EPA did not calculate total
flowback volume for Table C-6.
Abbreviations: MG—million gallons; H—horizontal well; D—directional well; v—vertical well
2.1.3 Produced Water: Long-Term Produced Water
Long-term produced water rates remain relatively constant60 over the well life compared
to flowback rates (178 DCN SGE00635). Table C-7 quantifies long-term produced water rates in
gallons per day by UOG resource and well trajectory. Median long-term produced water rates
range from about 380 to 900 gallons (9 to 21 barrels) per day. A comparison of median long-term
produced water rates for shale formation wells, as listed in the table, shows that horizontal shale
wells have higher median generation rates than directional and vertical shale wells. On the other
hand, median long-term produced water rates for tight formation wells in Table C-7 show that
vertical tight wells have higher generation rates than directional and horizontal tight wells, but
horizontal wells have the highest maximum generation rate.
Flowback recovery is the percent of total fracturing fluid injected during hydraulic fracturing that returns to the
wellhead during the flowback process.
60 Note that long-term produced water rates typically gradually decrease over the well life. However, the change is
small relative to flowback.
49
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-7. Long-Term Produced Water Generation Rates by Resource Type and Well
Trajectory
Resource
Type
Shale
Tight
Trajectory
H
D
V
H
D
V
Long-Term Produced Water Generation Rates (gpd per well)3
Median
900
480
380
620
750
570
Range
0-19,000
22-8,700
0-4,600
0-120,000
12-1,800
0-4,000
Number of Data Points
22,222
695
12,393
2,394
3,816
21,393
Sources: 56 DCN SGE00724
a—Based on aggregated data from Table C-8, which contains volumes by formation.
Abbreviations: gpd—gallons per day; H—horizontal well; D—directional well; V—vertical well
2.2 UOG Produced Water Volumes by Formation
Table C-8 shows the underlying UOG produced water volumes by formation and well
trajectory used to generate the summary statistics in Section C.2.1. The data in Table C-8 are
specific to UOG formations and are sorted alphabetically by basin and then from highest median
fracturing fluid volume to lowest within each formation. Because the EPA identified less detailed
data by formation for drilling wastewater, Table C-8 does not include drilling wastewater
volumes.
Data in Table C-8 illustrate that volumes of flowback and flow rates of long-term
produced water vary by formation. For example, UOG horizontal wells drilled into the Barnett
shale formation in the Fort Worth basin generate 920 gallons (22 barrels) per day of long-term
produced water compared to 110 gallons (3 barrels) per day for horizontal wells drilled into the
Eagle Ford shale formation in the Western Gulf basin (206 DCN SGE00623). In some cases,
produced water even varies geographically within the same formation, which is not evident in
Table C-8. For example, operators report that wells drilled in the northeast portion of the
Marcellus shale formation (in Pennsylvania) generate less produced water than wells drilled in
the southwest portion of the Marcellus shale formation (in West Virginia) (178 DCN
SGE00635).
50
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-8. Produced Water Volume Generation by UOG Formation
Basin
Anadarko
Appalachian
Arkoma
Denver J.
UOG
Formation
Granite Wash
Woodford
Mississippi
Lime
Cleveland
Marcellus
Utica
Fayetteville
Niobrara
Codell-Niobrara
Muddy J
Codell
Resource
Type
tight
shale
tight
tight
shale
shale
shale
shale
tight
tight
tight
Drill
Type
H
V
H
H
H
V
H
V
H
H
H
V
H
D
V
D
V
D
V
Fracturing Fluid (MG)
Median
6.2
0.56
4.7
1.8
0.81
0.69
4.4
2.6
4.0
5.1
2.6
0.32
2.6
0.45
0.30
0.59
0.28
0.28
0.27
Rangeb
0.20-9.4
0.050-
3.0
1.0-12
0.82-2.4
0.20-4.0
0.11-3.0
0.90-11
0.53-6.6
1.0-11
1.7-11
0.73-3.4
0.27-3.3
0.15-2.7
0.21-
0.47
0.13-
0.46
0.25-
0.62
0.16-
0.62
0.21-
0.46
0.13-
0.46
Number of
Data Points3
77
26
2,239
428
144
4
14,010
66
150
1,668
69
367
62
116
592
162
292
78
185
Flowback (% of Fracturing
Fluid Returned)
Median
—
—
34
—
—
—
7
40
4
—
13
11
7
—
—
—
—
—
—
Rangeb
7-22
—
20-50
50
12-40
—
4-47
21-60
2-27
10-20
6-25
7-35
—
—
—
—
—
—
—
Number of
Data Points3
2
2
o
3
1
2
2
4,374
7
73
2
16
9
32
0
0
0
0
0
0
Long-Term Produced Water
Rates (gpd)
Median
1,300
500
5,500
—
82
32
860
230
510
430
680
340
34
—
29
230
55
—
—
Rangeb
0-2,200
170-1,300
3,200-
6,400
37,000-
120,000
20-300
6.6-170
54-13,000
100-1,200
210-1,200
150-2,300
260-810
240-600
19-140
—
13-65
64-390
9.3-500
—
—
Number of
Data Points3
273
2,413
198
4
571
390
4,984
714
82
2,305
250
5,474
32
0
1,677
o
3
129
0
0
51
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-8. Produced Water Volume Generation by UOG Formation
Basin
Fort Worth
Green River
Illinois
Michigan
Permian
San Juan
UOG
Formation
Barnett
Hilliard-Baxter-
Mancos
Lance
Mesaverde
(Green River)
New Albany
Antrim
Avalon & Bone
Spring
Barnett-
Woodford
Wolfcamp
Spraberry
Devonian (TX)
Mesaverde (San
Juan)
Resource
Type
shale
shale
tight
tight
shale
shale
shale
shale
shale
shale
tight
shale
tight
Drill
Type
H
V
H
V
D
D
V
H
V
D
H
H
H
D
V
V
H
V
D
Fracturing Fluid (MG)
Median
3.6
1.3
1.7
1.3
1.2
0.23
0.17
—
—
2.2
1.1
2.1
1.4
1.3
0.81
—
0.32
0.27
—
Rangeb
1.0-7.3
0.4-1.9
1.0-5.6
0.81-3.5
0.76-1.9
0.16-
0.31
0.081-
0.29
—
0.050
0.94-4.5
0.73-2.8
0.5-4.5
1.1-3.9
0.26-1.7
0.078-
1.7
1.0
0.13-
0.89
0.12-1.0
—
Number of
Data Points3
23,917
3,589
2
29
180
73
14
0
1
20
17
2
55
12
60
1
10
16
0
Flowback (% of Fracturing
Fluid Returned)
Median
30
—
—
3
6
8
21
—
—
13
—
—
—
16
—
—
—
—
—
Rangeb
21-40
—
—
1-50
1-17
0-37
6-83
—
25-75
5-31
—
—
—
15-20
—
—
—
—
—
Number of
Data Points3
11
0
0
31
170
61
11
0
2
16
0
0
0
3
0
0
0
0
0
Long-Term Produced Water
Rates (gpd)
Median
920
250
37
410
860
190
290
—
—
950
0
—
3,000
310
910
870
880
400
18
Rangeb
160-4,200
170-580
15-58
250-580
360-1,200
150-440
140-610
2,900
4,600
220-2,400
0-2,300
—
210-
19,000
22-8,700
130-1,700
100-4,000
310-1,800
150-3,000
12-260
Number of
Data Points3
10,349
3,318
7
1,050
1,140
445
1,081
2
1
183
37
0
104
259
926
66
381
162
48
52
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-8. Produced Water Volume Generation by UOG Formation
Basin
TX-LA-MS
Western
Gulf
UOG
Formation
Dakota
Haynesville
Cotton Valley
Travis Peak
Bossier
Austin Chalk
Eagle Ford
Pearsall
Wilcox Lobo
Resource
Type
tight
shale
tight
tight
shale
tight
shale
shale
tight
Drill
Type
V
D
H
V
H
D
V
H
V
H
V
D
H
H
V
H
H
V
D
Fracturing Fluid (MG)
Median
0.2
0.12
5.3
0.61
4.2
0.48
0.28
3.0
0.90
2.7
0.40
0.28
0.94
5.0
2.9
3.7
2.1
0.21
0.058
Rangeb
0.063-
0.22
0.070-
0.30
0.95-15
0.14-3.5
0.25-6.0
0.084-
4.0
0.019-
0.94
0.25-6.0
0.20-4.0
1.7-3.6
0.19-1.7
0.13-
0.80
0.58-1.3
1.0-14
2.0-4.1
3.3-4.1
0.66-2.6
0.06-
0.60
0.056-
0.076
Number of
Data Points3
19
52
3,222
9
30
24
76
2
2
2
16
21
15
2,485
9
2
4
14
3
Flowback (% of Fracturing
Fluid Returned)
Median
—
4
5
—
—
—
—
—
—
—
—
—
—
4
—
—
—
—
—
Rangeb
—
1-40
5-30
—
<60
<60
<60
—
—
—
—
—
—
2-8
—
—
—
—
—
Number of
Data Points3
0
30
3
0
2
2
2
0
0
0
0
0
0
1,800
0
0
0
0
0
Long-Term Produced Water
Rates (gpd)
Median
65
160
1,700
210
770
950
640
200
980
750
470
320
720
110
—
200
330
620
—
Rangeb
29-120
41-370
84-1,800
56-850
130-2,700
630-1,800
370-1,800
39-1,700
330-1,800
610-1,200
180-1,100
130-1,300
290-2,400
9.1-250
—
54-370
62-740
330-1,400
—
Number of
Data Points3
6
379
1,249
263
335
1,801
10,717
5
1,380
25
1,203
253
1,097
498
0
12
77
1,514
0
53
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-8. Produced Water Volume Generation by UOG Formation
Basin
Williston
UOG
Formation
Vicksburg
Olmos
Bakken
Resource
Type
tight
tight
shale
Drill
Type
V
D
V
H
V
Fracturing Fluid (MG)
Median
0.16
0.11
—
2.0
1.1
Rangeb
0.084-
0.60
0.10-
0.13
0.15
0.35-10
0.35-2.9
Number of
Data Points3
20
4
2
2,203
12
Flowback (% of Fracturing
Fluid Returned)
Median
—
—
—
19
—
Rangeb
—
—
—
5-47
—
Number of
Data Points3
0
0
0
206
0
Long-Term Produced Water
Rates (gpd)
Median
1,000
—
—
680
1,000
Rangeb
650-1,900
—
—
380-1,500
340-3,100
Number of
Data Points3
937
0
0
1,739
222
Sources: 56 DCN SGE00724
a—For some formations, the number of data points was not reported in the data source. In these instances, this table reports that number as 1, except if the source reported
a range in which case this table reports the number of data points as 2.
b—For some formations, if only one data point was reported, the EPA reported it in the range column and did not report a median value.
"—" indicates no data.
Abbreviations: MG—million gallons; H—horizontal well; D—directional well; V—vertical well
54
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
3 UOG EXTRACTION WASTEWATER CHARACTERIZATION
As discussed in Chapter B, UOG operations generate wastewater that includes drilling
wastewater, flowback, and long-term produced water. Drilling wastewater is generated during
the initial drilling of the well and typically maintains the characteristics of the drilling fluid, but
also contains additional solids (i.e., drill cuttings) that are generated during the well drilling
process. Flowback may contain the specific fracturing fluid composition (e.g., chemical
additives, base fluid) used by each UOG operator as well as chemical constituents present in the
UOG formation (80 DCN SGE00286; 16 DCN SGE00110). Long-term produced water typically
mimics the characteristics of the UOG formation, which often contributes, in part, to high
concentrations of select naturally occurring ions (124 DCN SGE00090). The volumes and
characteristics of UOG extraction wastewater may vary significantly between basins, between
formations, and sometimes between wells within the same formation (see Section C.2 for a
discussion of UOG extraction wastewater volumes) (153 DCN SGE00592). The following
subsections describe the characteristics of UOG extraction wastewater.
3.1 Availability of Data for UOG Extraction Wastewater Characterization
The EPA identified concentration data for constituents commonly found in UOG
extraction wastewater. These constituents include, primarily, total dissolved solids (TDS),
anions/cations, metals, hardness, and radioactive constituents. The EPA presents summarized
UOG extraction wastewater characterization data in the following subsections, which are
organized into five constituent categories: classical and conventional, organic, metal, radioactive,
and other. Table C-9 shows relative quantities of data found for each constituent category. The
number of stars indicates the amount of data available, where one star indicates less data and five
stars indicates more data.
Table C-9. Availability of Data for UOG Extraction Wastewater Characterization
Constituent
Category
Classical and
conventional3
Organic
Metal
Radioactive
Other
Examples of Constituents Included Within Category
TDS, TSS, COD, BOD5, pH, conductivity, chloride, sodium,
calcium
Ethylbenzene, toluene
Barium, strontium, magnesium, potassium, iron, copper, zinc
Radium-226, radium-228, gross alpha, gross beta
Guar gum, microorganisms
Amount of
Available
Produced
Water Data
*****
***
*****
**
*
Amount of
Available
Drilling
Wastewater
Data
**
*
**
*
*
a—The classical and conventional constituent category also includes a discussion of the anions and cations that
contribute to TDS. These anions and cations are italicized in the examples column.
For all of the constituent categories, data on concentrations are less available for 1)
produced water specifically generated from tight oil and gas wells and 2) drilling wastewater
generated at all UOG wells. The EPA presents available data in the following subsections.
55
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
3.2 UOG Extraction Wastewater Constituent Categories
The data in the following subsections are representative of UOG extraction wastewater
characteristics as presented in the literature for the entire UOG industry.61 The data show
combined characterization data for shale and tight reservoirs as well as for oil and gas resources.
Regarding UOG produced water, the EPA sometimes presents the data as flowback and long-
term produced water individually. In other instances, the data are presented as UOG produced
water, which includes both flowback and long-term produced water.
3.2.1 Classical and Conventional Constituents in UOG Extraction Wastewater
Table C-10 presents typical concentrations of select classical and conventional
constituents that are present in UOG drilling wastewater. According to one CWT facility
operator, TSS is high in returned drilling fluid before cuttings are removed. Depending on how
well the cuttings are removed by the operator, solids can be as high as 50 percent by mass in
drilling wastewater (37 DCN SGE00245) (see Section B.2.1). The EPA identified the following
limitations to the data presented in Table C-10:
• Fewer data points (i.e., less than 30 data points) were available for each parameter.
• All of the data came from the Marcellus shale formation.
Table C-ll presents typical concentrations of select classical and conventional
constituents that are present in UOG produced water. The EPA identified the following
limitations to the data presented in Table C-ll:
• Fewer data points (i.e., less than 30 data points) were available for ammonia and
phosphate.
• The majority of data associated with alkalinity, BOD5, chemical oxygen demand
(COD), specific conductivity, TOC, and TSS came from the Marcellus shale
formation.
• The majority of data associated with chloride and TDS came from the Eagle Ford
shale formation.
• The majority of data associated with pH came from the Woodford-Cana-Caney shale
formation.
61 Note that the lack of data for select constituents may not necessarily imply that those constituents are not present
in the wastewater, but rather that they were not measured and/or reported in the existing literature. Refer to 56 DCN
SGE00724 for additional details on the parameters reported in the literature reviewed. The accompanying database
includes non detect, below detection, or zero values that were reported in the literature reviewed.
56
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-10. Concentrations of Select Classical and Conventional Constituents in UOG
Drilling Wastewater from Marcellus Shale Formation Wells62
Parameter
Alkalinity
Ammonia
BOD5
Chloride
COD
Hardness as CaCO3
Oil and grease
pH
Phosphate
Specific
conductivity
TDS
TSS
Units
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
SU
mg/L
uS/cm
mg/L
mg/L
Range
110-42,000
0.98-35
80-1,100
160-23,000
150-9,300
1,400-46,000
NDM50
6.8-12
b
1,100-60,000
560-80,000
120-600,000
Median
1,600
7
390
12,000
1,800
4,400
2.5
9.0
16
19,000
31,000
28,000
Number
of Data
Points
11
8
8
12
8
12
8
12
4
10
14
16
Number of Detects
11
8
8
12
8
12
8
12
4
10
14
16
Formation
Represented
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Source: 55 DCN SGE00740
a—Source did not report detection limit.
b—Source only reported median value.
Abbreviations: mg/L—milligrams per liter; ND—non detect; SU—standard units; uS/cm—microsiemens per
centimeter
Drilling wastewater may contain differing amounts of drill cuttings depending on how the operator chooses to
remove drill cuttings from drilling wastewater.
57
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-ll. Concentrations of Select Classical and Conventional Constituents in UOG Produced Water
Parameter
Alkalinity
Ammonia
Bicarbonate
BOD 5
Carbonate
Chlorideb
COD
Hardness as CaCO3
Oil and grease
pH
Phosphate
Specific conductivity
Units
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
SU
mg/L
uS/cm
Range
7.5-1,600
39-350
0 - 19,000
2-12,000
0 - 13,000
64-230,000
99-37,000
160-110,000
0.21-1,500
3.9-12
12-88
0.11-760,000
Median
140
110
290
160
0
73,000
3,200
21,000
5.6
6.5
31
120,000
Number of Data Points"
265
13
6,352
154
59
2,190
149
80
134
5,233
4
162
Number of Detects
265
13
6,352
153
59
2,190
149
80
99
5,233
4
162
Formations Represented"
Barnett (29); Eagle Ford (1); Marcellus (232);
Woodford-Cana-Caney (3)
Marcellus (5); Niobrara (5); Woodford-Cana-
Caney (3)
Bakken (398); Barnett (6); Cleveland (11); Cotton
Valley/Bossier (3); Dakota (3); Eagle Ford
(2,925); Lansing Kansas City (16); Marcellus
(154); Mesaverde/Lance (5); Morrow (1); New
Albany (1); Oswego (5); Pearsall (3); Spraberry
(26); Woodford-Cana-Caney (2,795)
Barnett (28); Marcellus (122); Medina/Clinton-
Tuscarora (1); Woodford-Cana-Caney (3)
Bakken (20); Barnett (4); Cotton Valley/Bossier
(2); Dakota (3); Eagle Ford (4); Spraberry (26)
Bakken (22); Barnett (144); Cleveland (11);
Cotton Valley/Bossier (25); Dakota (3); Eagle
Ford (1651); Granite Wash/Atoka (1); Marcellus
(287); Mesaverde/Lance (5); New Albany (1);
Niobrara (5); Pearsall (3); Spraberry (26); Utica
(1); Woodford-Cana-Caney (5)
Barnett (23); Marcellus (122); Medina/Clinton-
Tuscarora (1); Woodford-Cana-Caney (3)
Barnett (15); Marcellus (65)
Barnett (23); Marcellus (108); Woodford-Cana-
Caney (3)
Bakken (420); Barnett (30); Cleveland (4); Cotton
Valley/Bossier (3); Dakota (3); Eagle Ford (1600);
Fayetteville (2); Lansing Kansas City (16);
Marcellus (300); Medina/Clinton-Tuscarora (3);
Mesaverde/Lance (5); Morrow (1); Oswego (5);
Spraberry (26); Woodford-Cana-Caney (2815)
Barnett (1); Marcellus (1); Woodford-Cana-Caney
(2)
Bakken (9); Barnett (25); Dakota (3); Marcellus
(103); Spraberry (19); Woodford-Cana-Caney (3)
58
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-ll. Concentrations of Select Classical and Conventional Constituents in UOG Produced Water
Parameter
TDS
TOC
TSS
Units
mg/L
mg/L
mg/L
Range
320^00,000
1.2-5,700
4-14,000
Median
100,000
65
130
Number of Data Points"
2,164
129
150
Number of Detects
2,164
124
150
Formations Represented"
Bakken (11); Barrett (38); Bradford- Venango-Elk
(5); Cleveland (11); Cotton Valley/Bossier (3);
Dakota (3); Devonian (11); Eagle Ford (1647);
Fayetteville (4); Green River (1);
Haynesville/Bossier (2); Marcellus (373);
Mesaverde/Lance (5); Mississippi Lime (3); New
Albany (1); Niobrara (8); Pearsall (3); Spraberry
(26); Utica (1); Woodford-Cana-Caney (8)
Bakken (2); Barnett (28); Marcellus (96);
Woodford-Cana-Caney (3)
Bakken (2); Barnett (29); Eagle Ford (1);
Marcellus (113); Woodford-Cana-Caney (5)
Source: 56 DCN SGE00724
a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these
instances, there were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified.
b—The EPA assumed values reported as "Cl" in the wastewater characterization data were meant to represent "chloride" values.
Abbreviations: mg/L—milligrams per liter; SU—standard units; uS/cm—microsiemens per centimeter
59
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
COD is a measure of the amount of oxygen needed to oxidize organic matter in
wastewater using a strong chemical oxidant; therefore, it is an indicator of the presence of
organic constituents in wastewater. As reported in Table C-ll, the median COD concentration
found in UOG produced water is 3,200 mg/L. However, researchers have shown that
concentrations of COD may be influenced by chloride, bromide, alkaline earth metals (e.g.,
barium, calcium), and reduced inorganic constituents (e.g., sulfide, nitrite). As shown in Table
C-13, the median concentrations of sulfide and nitrite in UOG produced water are less than 10
mg/L, indicating that they are not likely to have an influence on the COD concentrations.
However, chloride, bromide, and alkaline earth metals are present at higher concentrations than
reduced inorganic constituents in UOG produced water and may interfere with COD sample
measurements (227 DCN SGE00725). In Table C-ll, the relatively low median TOC
concentration (65 mg/L) and BOD5 concentration (160 mg/L) compared to the COD
concentration likely indicates that some of the COD measurements reported in existing literature
experienced interference from high concentrations of chloride, bromide, and group II alkaline
earth metals. Therefore, reported COD concentrations may be higher than actual COD
concentrations in UOG produced water.
TDS, which is regularly measured in UOG produced water, provides a measure of
dissolved matter including salts (e.g., sodium, chloride, nitrate), metals, minerals, and organic
material (1 DCN SGE00046). TDS is not a specific chemical, but is defined as the portion of
solids that pass through a filter with a nominal pore size of 2.0 jim or less (Standard Method
2540C-1997, ASTM D5907-03, and USGS 1-1750-85). Salts are the majority of TDS in UOG
produced water, and sodium chloride often constitutes approximately 50 percent of the TDS in
UOG produced water (1 DCN SGE00046). As reported in Table C-ll, the concentration of TDS
in UOG produced water is approximately 10 percent by weight.
Calcium and other group II alkaline earth metals (e.g., strontium, barium, magnesium)
also contribute to the TDS in UOG produced water.
Figure C-3 shows the primary anions and cations that contribute to TDS in UOG
produced water in various shale and tight oil and gas formations. Data for all of the anions and
cations contributing to TDS were not available for all formations. For example, the EPA did not
identify any sodium concentration data in the Pearsall formation. Similarly, the EPA did not
identify any chloride concentration data in the Spraberry formation. These missing data will
account for some of the remaining TDS concentrations that are currently shown as "other
dissolved constituents" in Figure C-3.
60
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
400,000
350,000
300,000
250,000
Other Dissolved Constituents
Potassium
Barium
Bromide
Magnesium
Strontium
Calcium
Sodium
Chloride
EPA assumed values reported as "Cl" in the wastewater characterization data were meant to represent "chloride" values and were reported as such
in Table C-ll.
Source: 56 DCN SGE00724
Figure C-3. Anions and Cations Contributing to TDS Concentrations in Shale and Tight
Oil and Gas Formations63
As shown in Figure C-3, of those chemicals specifically identified as contributing to
TDS, sodium, chloride, and calcium ions make up the majority of TDS in UOG produced water.
Additional ions that may contribute to the TDS in UOG produced water include bromide,
fluoride, nitrate, nitrite, phosphate, and sulfate. Figure C-4 shows ranges of concentrations of
sodium, chloride, and calcium contributing to TDS in UOG flowback and long-term produced
water. The data used to create this figure include constituent concentration data from flowback or
long-term produced water generated at a shale or tight oil and gas well. The data show that
concentrations of these constituents are typically higher in long-term produced water than in
flowback.
In Figure C-3, the EPA indicates tight oil and gas formations by "**" after the formation name. The EPA assumed
values reported as "Cl" in the wastewater characterization data were meant to represent "chloride" values and has
reported them as such in Figure C-3.
61
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
1,000,000
100,000
I
e
.S
o
U
10,000
1,000
100 -
TDS - TDS - Chloride- Chloride- Sodium- Sodium- Calcium- Calcium
Flowback LTPW Flowback LTPW Flowback LTPW Flowback LTPW
EPA assumed values reported as "Cl" in the wastewater characterization data were meant to represent "chloride" values and were reported as
such in Table C-ll.
Source: 56 DCN SGE00724
Figure C-4. Chloride, Sodium, and Calcium Concentrations in Flowback and Long-Term
Produced Water (LTPW) from Shale and Tight Oil and Gas Formations
Table C-12 presents typical concentrations of additional constituents that may contribute
to TDS in drilling wastewater. The EPA identified the following limitations to the data presented
in the table:
• Fewer data points (i.e., less than 30 data points) were available for all parameters.
• All of the data came from the Marcellus shale formation.
Table C-13 presents typical concentrations of additional constituents that may contribute
to TDS in UOG produced water. The EPA identified the following limitations to the data
presented in the table:
• Less data (i.e., less than 30 data points) were available for nitrite and phosphate.
• All of the available data for nitrite and sulfide came from the Marcellus shale
formation.
• The majority of the data associated with nitrate came from the Bakken shale
formation.
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
• The majority of the data associated with bromide and fluoride came from the
Marcellus shale formation.
• The majority of the data associated with sulfate came from the Woodford-Cana-
Caney shale formation.
Table C-12. Concentrations of Select Anions and Cations Contributing to TDS in UOG
Drilling Wastewater from Marcellus Shale Formation Wells
Parameter
Bromide
Sulfate
Units
mg/L
mg/L
Range
23-210
ND-1,600
Median
110
220
Number
of Data
Points
5
13
Number of Detects
5
10
Formation
Represented
Marcellus
Marcellus
Source: 55 DCN SGE00740
Abbreviation: mg/L—milligrams per liter
63
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-13. Concentrations of Select Anions and Cations Contributing to TDS in UOG Produced Water
Parameter
Bromide
Fluoride
Nitrate
Nitrite
Phosphate
Sulfate
Sulfide
Units
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Range
0.20-3,100
0.045-390
0.30-920
5.0-5.0b
12-88
0-7,200
0.80-30
Median
510
2.5
0.30
5.0
31
270
3.0
Number of
Data Points
111
99
110
2
4
4,711
76
Number of
Detects
111
97
110
2
4
4,687
69
Formations Represented (Number of Associated Data Points)3
Harriett (23); Marcellus (85); Woodford-Cana-Caney (3)
Harriett (23); Marcellus (73); Woodford-Cana-Caney (3)
Bakken (107); Marcellus (3)
Marcellus (2)
Barnett (1); Marcellus (1); Woodford-Cana-Caney (2)
Bakken (424); Barnett (3 1); Cleveland (9); Cotton Valley/Bossier (1);
Dakota (3); Devonian (4); Eagle Ford (1,166); Fayetteville (2); Lansing
Kansas City (15); Marcellus (301); Medina/Clinton-Tuscarora (2);
Mesaverde/Lance (4); Morrow (1); New Albany (1); Niobrara (5); Oswego
(4); Pearsall (3); Spraberry (26); Woodford-Cana-Caney (2,709)
Marcellus (76)
Source: 56 DCN SGE00724
a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these
instances, there were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified.
b—Only two data points were identified for nitrite concentrations in UOG produced water and both data points reported the same value.
Abbreviation: mg/L—milligrams per liter
64
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
3.2.2 Organic Constituents in UOG Extraction Wastewater
Table C-14 presents concentration data from existing literature on organic constituents in
UOG drilling wastewater. The EPA identified the following limitations to the data presented in
the table:
• Fewer data points (i.e., less than 30) were available for each parameter.
• All of the data came from the Marcellus shale formation.
Table C-15 presents concentration data from existing literature on organic constituents in
UOG produced water. The EPA identified the following limitations to the data presented in the
table:
• All of the available data for carbon disulfide, ethanol, methanol, methyl chloride, and
tetrachloroethylene came from the Marcellus shale formation.
• The majority of the data associated with each of the organic constituents presented in
the table came from the Marcellus shale formation.
Table C-14. Concentrations of Select Organic Constituents in UOG Drilling Wastewater
from Marcellus Shale Formation Wells
Parameter
Benzene
Ethylbenzene
Ethylene glycol
Toluene
Xylene (m,p)
Xylene (o)
Units
ug/L
ug/L
mg/L
ug/L
ug/L
ug/L
Range
NDa-40
b
b
NDa-80
b
b
Median
NDa
9.6
500
NDa
88
22
Number of
Data Points
20
4
1
20
4
4
Number of
Detects
5
4
1
8
4
4
Formation
Represented
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Source: 55 DCN SGE00740
a—Source did not report detection limit.
b—Source only reported median value.
Abbreviations: ND—non detect; mg/L—milligrams per liter; ug/L—micrograms per liter
65
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-15. Concentrations of Select Organic Constituents in UOG Produced Water
Parameter
1 ,2,4-trimethylbenzene
1,3,5 -trimethy Ibenzene
Acetone
Benzene
Carbon disulfide
Chlorobenzene
Chloroform
Ethanol
Ethylbenzene
Isopropylbenzene
Methanol
Methyl chloride
Naphthalene
Phenol
Pyridine
Tetrachloroethylene
Toluene
Xylenes
Units
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
ug/L
Range
0.54-4,000
0.64-1,900
5.9-160,000
0.99-800,000
5.0-7,300
0-500
0-500
1,000-230,000
0.63-8,900
0.53-500
3,200-4,500,000
2.0-500
0.50-1,400
0.70-160
1.1-2,600
5.0-5,000
0.91-1,700,000
3.0-440,000
Median
5.0
5.0
40
8.5
5.0
5.0
5.0
10,000
5.0
5.0
10,000
5.0
5.0
2.0
86
5.0
6.0
15
Number of
Data Points
92
85
96
144
68
72
77
53
130
83
55
95
129
111
91
95
149
136
Number of
Detects
89
81
86
122
67
70
75
53
104
69
55
69
103
83
90
68
125
111
Formations Represented
(Number of Associated Data Points)3
Barnett (25); Marcellus (67)
Barnett (18); Marcellus (67)
Barnett (22); Marcellus (74)
Barnett (25); Marcellus (111); Niobrara (5); Woodford-Cana-
Caney (3)
Marcellus (68)
Marcellus (69); Woodford-Cana-Caney (3)
Barnett (5); Marcellus (69); Woodford-Cana-Caney (3)
Marcellus (53)
Barnett (18); Marcellus (108); Medina/Clinton-Tuscarora (1);
Woodford-Cana-Caney (3)
Barnett (16); Marcellus (67)
Marcellus (55)
Marcellus (95)
Barnett (39); Marcellus (90)
Barnett (17); Marcellus (91); Woodford-Cana-Caney (3)
Barnett (24); Marcellus (67)
Marcellus (95)
Barnett (25); Marcellus (115); Medina/Clinton-Tuscarora (1);
Niobrara (5); Woodford-Cana-Caney (3)
Barnett (20); Marcellus (112); Medina/Clinton-Tuscarora (1);
Woodford-Cana-Caney (3)
Source: 56 DCN SGE00724
a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these instances,
there were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified.
Abbreviation: ug/L—micrograms per liter
66
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-3 includes concentration data for ethanol, methanol, and naphthalene, suggesting
that a portion of the concentrations of these constituents found in UOG produced water (see
Table C-15) may have originated from the fracturing fluid. Methanol is typically used in
fracturing fluid as a biocide, corrosion inhibitor, crosslinker, and surfactant; ethanol is also used
as a biocide and surfactant (see Table C-2).
Operators may use methanol as an antifreezing agent at UOG operations in areas with
seasonal temperature fluctuations. Methanol may be used at the wellhead to avoid freezing in the
wellbore or at compressor stations to prevent equipment from freezing.
The EPA did not identify any quantitative information about diesel-range organics or
total petroleum hydrocarbons in UOG produced water. However, Table C-3 shows that
petroleum distillates are typically used in fracturing fluid at 0.0021 to 0.27 percent by mass. The
EPA ORD's 2015 Evaluation of Hydraulic Fracturing Fluid Data from the FracFocus Chemical
Disclosure Registry 1.0 contains additional information about these constituents (201 DCN
SGE00721).
3.2.3 Metals in VOG Extraction Wastewater
UOG extraction wastewater contains varying concentrations of numerous metals.
Table C-16 presents concentration data from existing literature for the metals most
common in UOG drilling wastewater. The EPA identified the following limitations to the data
presented in the table:
• Fewer data points (i.e., less than 30) were available for each parameter.
• All of the data came from the Marcellus shale formation.
Table C-17 presents concentration data from existing literature for the metals most
common in UOG produced water. The EPA identified the following limitations to the data
presented in the table:
• Fewer data (i.e., less than 30 data points) were available for vanadium.
• All of the available data for vanadium came from the Marcellus shale formation.
• The majority of the data associated with aluminum, antimony, arsenic, beryllium,
boron, cadmium, cobalt, copper, iron, lead, lithium, manganese, mercury,
molybdenum, nickel, selenium, silver, strontium, thallium, tin, titanium, and zinc
came from the Marcellus shale formation.
• The majority of the data associated with calcium, magnesium, potassium, and sodium
came from the Eagle Ford and Woodford-Cana-Caney shale formations.
• The majority of the data associated with chromium came from the Bakken shale
formation.
67
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-16. Concentrations of Select Metal Constituents in UOG Drilling Wastewater
from Marcellus Shale Formation Wells
Parameter
Aluminum
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Potassium
Selenium
Silver
Sodium
Strontium
Zinc
Units
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Range
1.7-6,900
NDa-4.2
2.6-2,000
NDa-0.018
NDa-2.7
NDa-0.0050
150-15,000
NDa-ll
NDa-1.8
NDa-17
4.2-18,000
NDa-8.0
NDa-1.2
NDa-3,600
NDa-350
NDa-0.029
b
NDa-16
b
NDa-0.11
NDa-0.010
170-16,000
1.8-1,500
NDa-38
Median
38
NDa
13
NDa
0.17
NDa
1,300
0.010
NDa
0.83
86
0.35
NDa
290
4.3
NDa
0.10
0.55
8,800
NDa
NDa
2,900
21
2.1
Number of
Data Points
12
12
14
8
8
8
13
12
8
8
12
12
8
12
12
8
1
12
4
8
8
12
13
12
Number of
Detects
12
6
14
2
4
1
13
8
3
6
12
10
1
11
11
2
1
9
4
3
1
12
13
10
Formation
Represented
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Marcellus
Source: 55 DCN SGE00740
a—Source did not report detection limit.
b—Source only reported median value.
Abbreviation: mg/L—milligrams per liter; ND—non detect
68
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-17. Concentrations of Select Metal Constituents in UOG Produced Water
Parameter
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Lithium
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Units
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Range
0.048 - 47
0.0089-0.5
0.004-0.5
0 - 16,000
0.0009 - 420
0.018-150
0-1.2
13 - 130,000
0.0066 - 260
0.0045 - 25
0-4.2
0.95-810
0-5
0.5-430
3 - 27,000
0.12-43
0-0.3
0.003 - 13
0.007 - 4
Median
0.45
0.047
0.057
19
0.04
14
0.0086
6,700
0.3
0.5
0.14
39
0.03
52
670
1.7
0.0002
0.038
0.12
Number of
Data Points
159
112
132
1,097
114
148
134
5,336
383
124
147
407
133
120
3,562
235
115
140
151
Number of
Detects
128
79
96
1,096
72
134
92
5,335
349
92
107
380
96
120
3,549
221
85
118
121
Formations Represented (Number of Associated Data Points)3
Bakken (4); Barnett (31); Marcellus (116); Woodford-Cana-Caney (3)
Barnett (9); Marcellus (103)
Barnett (15); Marcellus (114); Woodford-Cana-Caney (3)
Bakken (3 12); Barnett (38); Cotton Valley/Bossier (2); Dakota (3); Devonian (4); Eagle
Ford (8); Fayetteville (2); Lansing Kansas City (7); Marcellus (209); Medina/Clinton-
Tuscarora (1); Morrow (1); Utica (1); Woodford-Cana-Caney (508)
Barnett (2); Marcellus (112)
Bakken (8); Barnett (32); Eagle Ford (1); Marcellus (102); Niobrara (5)
Barnett (16); Marcellus (115); Woodford-Cana-Caney (3)
Bakken (426); Barnett (39); Cleveland (1 1); Cotton Valley/Bossier (3); Dakota (3);
Devonian (4); Eagle Ford (1644); Fayetteville (2); Lansing Kansas City (15); Marcellus
(342); Medina/Clinton-Tuscarora (2); Mesaverde/Lance (5); Morrow (1); New Albany
(1); Oswego (5); Pearsall (3); Spraberry (26); Woodford-Cana-Caney (2804)
Bakken (234); Barnett (26); Marcellus (115); Woodford-Cana-Caney (3)
Barnett (16); Eagle Ford (1); Marcellus (103)
Bakken (2); Barnett (22); Marcellus (115); Woodford-Cana-Caney (3)
Bakken (22); Barnett (35); Cotton Valley/Bossier (2); Dakota (3); Eagle Ford (10);
Fayetteville (2); Marcellus (300); Spraberry (26); Utica (1); Woodford-Cana-Caney (6)
Bakken (1); Barnett (15); Marcellus (113); Woodford-Cana-Caney (3)
Barnett (31); Marcellus (89)
Bakken (426); Barnett (39); Cleveland (1 1); Cotton Valley/Bossier (3); Dakota (3);
Devonian (4); Eagle Ford (1621); Fayetteville (2); Lansing Kansas City (15); Marcellus
(326); Medina/Clinton-Tuscarora (2); Mesaverde/Lance (5); Morrow (1); New Albany
(1); Oswego (5); Pearsall (3); Spraberry (26); Woodford-Cana-Caney (1069)
Bakken (7); Barnett (37); Cotton Valley/Bossier (2); Dakota (3); Eagle Ford (6);
Fayetteville (2); Marcellus (155); Spraberry (19); Woodford-Cana-Caney (3)
Barnett (11); Marcellus (101); Woodford-Cana-Caney (3)
Bakken (1); Barnett (29); Marcellus (105)
Barnett (27); Eagle Ford (1); Marcellus (116); Woodford-Cana-Caney (3)
69
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-17. Concentrations of Select Metal Constituents in UOG Produced Water
Parameter
Potassium
Selenium
Silver
Sodium
Strontium
Thallium
Tin
Titanium
Vanadium
Zinc
Units
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
Range
0 - 8,500
0.0043 - 0.5
0.00073 - 0.5
64 - 430,000
0 - 8,000
0.0049 - 1
0.0038 - 3
0-8
0.063 - 40
0-250
Median
3,100
0.05
0.05
39,000
750
0.1
1
0.19
0.63
0.2
Number of
Data Points
715
110
115
3,449
253
120
80
111
27
160
Number of
Detects
699
75
75
3,448
251
83
78
80
2
135
Formations Represented (Number of Associated Data Points)3
Bakken (382); Barnett (36); Cleveland (3); Cotton Valley/Bossier (3); Eagle Ford (149);
Marcellus (136); Medina/Clinton-Tuscarora (2); Mesaverde/Lance (1); Woodford-Cana-
Caney (3)
Barnett (7); Marcellus (103)
Marcellus (112); Woodford-Cana-Caney (3)
Bakken (426); Barnett (38); Cleveland (1 1); Cotton Valley/Bossier (3); Dakota (3);
Devonian (4); Eagle Ford (1631); Fayetteville (2); Lansing Kansas City (16); Marcellus
(202); Medina/Clinton-Tuscarora (2); Mesaverde/Lance (5); Morrow (1); New Albany
(1); Niobrara (5); Oswego (5); Spraberry (26); Woodford-Cana-Caney (1068)
Bakken (10); Barnett (35); Cotton Valley/Bossier (2); Dakota (3); Devonian (4); Eagle
Ford (8); Fayetteville (2); Marcellus (183); Medina/Clinton-Tuscarora (2); Utica (1);
Woodford-Cana-Caney (3)
Barnett (13); Marcellus (104); Woodford-Cana-Caney (3)
Barnett (10); Marcellus (69)
Barnett (16); Marcellus (94)
Marcellus (26)
Bakken (2); Barnett (32); Eagle Ford (1); Fayetteville (2); Marcellus (116); Woodford-
Cana-Caney (3)
Source: 56 DCN SGE00724
a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these instances, there
were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified.
Abbreviation: mg/L—milligrams per liter
70
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
As discussed in Section C.3.2.1, sodium and calcium are two of the primary constituents
that contribute to IDS in UOG produced water. Other metals with median concentrations
between 100 mg/L and 750 mg/L are magnesium and strontium, which are group II alkaline
earth metals. Low-solubility salts of these metals (e.g., barium sulfate) commonly precipitate in
pipes and valves, forming scale. Barium is commonly found in higher concentrations in
produced water from the Marcellus and Devonian shale formations than in produced water from
other UOG formations. Figure C-5 shows the concentrations of barium in UOG produced water
from various shale and tight oil and gas formations on a log scale. Median concentrations of
heavy metals (e.g., chromium, copper, nickel, zinc, lead, mercury, arsenic) in UOG produced
water are less than 1 mg/L, much lower than the concentrations of the alkaline earth metals.
10,000.0
1,000.0
.2
| 100.0
I
o
U
£
_s
05 10.0
1.0
-95th
--75th
--50th (Median)
-25th
- 5th
Barnett Cotton Valley/Bossier Devonian
Fayetteville
Marcellus
Source: 56 DCN SGE00724
Figure C-5. Barium Concentrations in UOG Produced Water from Shale and Tight Oil and
Gas Formations
3.2.4 Radioactive Constituents in UOG Extraction Wastewater
Oil and gas formations contain varying levels of naturally occurring radioactive material
(NORM) resulting from uranium and thorium decay, which can be transferred to UOG produced
water. Radioactive decay products typically include radium-226 and radium-228 (54 DCN
SGE00933). The EPA identified limited available data (primarily from the Marcellus Shale
71
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
formation) on some radioactive constituents in UOG extraction wastewater, including radium-
226, radium-228, gross alpha, and gross beta, and therefore focused the radioactive constituent
discussion and data presentation on these parameters. ERG's Radioactive Materials in the
Unconventional Oil and Gas (UOG) Industry memorandum (54 DCN SGE00933) contains a
more detailed discussion of this topic.
The EPA identified limited radioactive constituent concentration data for UOG drilling
wastewater. Table C-18 shows the available data from the Marcellus shale formation.
Table C-18. Concentrations of Select Radioactive Constituents in UOG Drilling
Wastewater from Marcellus Shale Formation Wells
Parameter
Gross alpha
Gross beta
Units
pCi/L
pCi/L
Range
17-3,000
32-4,200
Median
130
1,200
Number of
5
5
5
5
Marcellus
Marcellus
Sources: 55 DCN SGE00740
Abbreviation: pCi/L—picocuries per liter
Similarly, the EPA identified limited radioactive constituent concentration data for UOG
produced water. As presented in Table C-19, most available data characterize produced water
from the Marcellus formation; limited data were available from the Niobrara formation. Radium-
226 and radium-228 are both found in UOG produced water, with radium-226 concentrations
generally two to five times greater than radium-228 concentrations.
The EPA identified the following limitations to the data presented in the table:
• Limited or no radioactive constituent concentration data were available for the
majority of shale and tight formations.
• Many EPA methods are known to experience interference from high TDS
concentrations or the presence of Group II elements, which are typical of UOG
extraction wastewater, and may result in an underestimation of reported values.
ERG's Radioactive Materials in the Unconventional Oil and Gas (UOG) Industry
memorandum (54 DCN SGE00933) discusses potential interference issues associated
with various EPA methods and notes that the following methods may experience
interference from UOG extraction wastewater: 900.0 Gross Alpha and Gross Beta
Radioactivity, 903.0 Alpha-Emitting Radium Isotopes, and 903.1 Radium-226, Radon
Emanation Technique.
Table C-19. Concentrations of Select Radioactive Constituents in UOG Produced Water
Parameter
Gross
alpha
Gross
alpha
Gross beta
Formation
Marcellus
Niobrara
Marcellus
Method(s)
900.0
900.0
900.0
Range (pCi/L)
8.7 - 120,000
620^,000
6.8-21,000
Median (pCi/L)
8,700
1,800
1,600
Number of
Data Points
74
3
73
Number of
Detects
74
3
72
72
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-19. Concentrations of Select Radioactive Constituents in UOG Produced Water
Parameter
Gross beta
Radium-
226
Radium-
226
Radium-
228
Radium-
228
Formation
Niobrara
Marcellus
Niobrara
Marcellus
Niobrara
Method(s)
900.0
90 1.1 Mod., 903.0,
903.1, y-spectrometry
90 1.1 Mod.
901.1.903.0,904.0,7-
spectrometry
90 1.1 Mod.
Range (pCi/L)
250-1,200
0.16-27,000
170-900
0 - 1,900
100-460
Median (pCi/L)
760
1,700
620
470
330
Number of
Data Points
3
103
3
94
3
Number of
Detects
3
101
3
92
3
Sources: 56 DCN SGE00724
Abbreviations: pCi/L—picocuries per liter; NA—not available
As a point of comparison, Table C-20 includes data from a 2014 International Atomic
Energy Agency report (96 DCN SGE00769) that included radium isotope concentrations in
rivers, lakes, groundwater, and drinking water. Data for radium-228 were limited, but the
average of measured concentrations of radium-226 found in U.S. rivers and lakes was 0.56 pCi/L
(21 mBq/L). The median concentrations of radium-226 and radium-228 in UOG produced water
in at least one of the formations presented in Table C-19 was above the maximum naturally
occurring concentration in U.S. rivers, lakes, groundwater, or drinking water presented in Table
C-20. Radium in groundwater may originate from rocks, soil, and other naturally occurring
materials, which are likely also the origins of a portion of the radium in UOG produced water.
Table C-20. Concentrations of Radioactive Constituents in Rivers, Lakes, Groundwater,
and Drinking Water Sources Throughout the United States (pCi/L)
Parameter
Radium-226
Location Description
Boise, Idaho — well water
Florida — groundwater
Florida — well water
Hudson River
Illinois — well water
Illinois Lake
Iowa — well water
Iowa — well water
Joliet, Illinois — well water
Lake Ontario
Memphis, Tennessee — well water
Miami, Florida — well water
Mississippi River
Ottawa County, OK — well water
Sarasota, Florida — groundwater
South Carolina — well water
Minimum
—
ND
0.20
—
0.020
0.059
0.10
1.8
—
0.04
—
—
0.010
0.10
1.5
2.7
Maximum
—
76
3.3
—
23
1.3
48
25
—
1.7
—
—
1.1
15
24
27
Average
0.10
—
—
0.032
—
—
—
—
6.5
—
0.21
0.48
—
—
—
—
73
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-20. Concentrations of Radioactive Constituents in Rivers, Lakes, Groundwater,
and Drinking Water Sources Throughout the United States (pCi/L)
Parameter
Radium-228
Location Description
South Texas — groundwater
Suwannee River
U.S. drinking water
Utah — well water
Wichita, Kansas — groundwater
Iowa — well water
South Carolina — well water
U.S. drinking water
Minimum
0.40
—
0.011
1.0
—
0.60
4.7
0
Maximum
170
—
4.9
20
—
6.3
12
0.014
Average
—
0.20
—
—
0.23
—
—
—
Source: 96 DCN SGE00769
"—"—Data were not reported.
Note: Data are presented as they were reported, either as a range (i.e., minimum, maximum) or as an average
value.
Abbreviations: pCi/L—picocuries per liter; ND—non detect
In January 2015, PA DEP announced the results of a study of radioactive elements in
UOG extraction wastewater, sludge, and drill cuttings. Although PA DEP concluded "...[tjhere
is little potential for radiological exposure to workers and members of the public from handling
and temporary storage of [flowback fluid and] produced water on natural gas well sites," they
did conclude "...[tjhere is a potential for radiological environmental impacts from spills of
produced water [and flowback fluid] on natural gas well sites and from spills that could occur
from the transportation and delivery of ... [these] fluid[s]" (135 DCN SGE01028).
3.2.5 Other Constituents in VOG Extraction Wastewater
UOG produced water may also contain guar gum, which is a polymer that is commonly
used in fracturing fluid to transport the proppant to the end of the wellbore (see Table C-2 and
Table C-3). Guar gum may be found in UOG produced water at concentrations between 100
mg/L and 20,000 mg/L (193 DCN SGE00616). Guar gum treatment requires a breakdown of the
polymer and is a consideration for UOG operators who are reusing/recycling wastewater for
fracturing.
Microorganisms are also found in UOG drilling wastewater and produced water.
Microorganisms may be present in concentrations as high as 1 x 109 organisms per 100 mL in
UOG produced water (193 DCN SGE00616). Sulfate-reducing bacteria (SRB) are one
classification of a naturally occurring microorganism that may be found in UOG produced water
and drilling wastewater. SRB can cause problems during reuse/recycle of UOG produced water
because they can reduce and/or precipitate metals and ions, potentially causing scale in the
wellbore. They can also create hydrogen sulfide,64 a potential human health concern that is also
highly corrosive and can harm the well casing and wellbore (201 DCN SGE00721).
64 Exposure to low concentrations of hydrogen sulfide may cause difficulty breathing and/or irritation to the eyes,
nose, or throat. Exposure to high concentrations of hydrogen sulfide may cause headaches, poor memory,
unconsciousness and death (4 DCN SGE00723).
74
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
3.3 UOG Produced Water Characterization Changes over Time
Concentrations of IDS, radioactive elements, and organic compounds vary across
different formations and over time. However, for the vast majority of formations for which data
are available, the data demonstrate that flowback and long-term produced water are both
influenced by constituents present in the formation. For example, concentrations of select
naturally occurring constituents commonly found in shale formations (e.g., bromide, magnesium)
are found in elevated concentrations in flowback compared to hydraulic fracturing fluid. The
elevated concentrations indicate that the formation is contributing concentrations of these
constituents to the flowback. Similarly, concentrations of TDS and TDS-contributing
constituents (e.g., sodium, chloride, calcium) increase over time as formation water and the
dissolution of constituents out of the formation contribute to long-term produced water.
RPSEA's 2012 Characterization of Flowback Waters from the Marcellus and the Barnett
Shale Regions (85 DCN SGE00414) presents sampling data from 19 sites in the Marcellus shale
and five sites in the Barnett shale. The sampled constituents include a wide array of classicals,
conventionals, organics, and metals. Where possible, these constituents were sampled at day 0,
day 1, day 5, day 14, and day 90. Figure C-6 presents median data for select constituents as
reported in the RPSEA report. Figure F-l in the appendices presents median data for additional
constituents as reported in the RPSEA report.
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
250.000
200.000
150,000
100.000
50.000
50.000
40.000
30.000
20.000
10,000
-IDS
-Chloride
- Hardness (as CaCO3)
Sodium
Calcium
- Strontium
Marcellus Shale Wastewater
Barnett Shale Wastewater
DayO Dayl Day 5 Day 14
Source: The EPA generated this figure using data from 85 DCN SGE00414.
Day 90
Figure C-6. Constituent Concentrations over Time in UOG Produced Water from the
Marcellus and Barnett Shale Formations
76
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Chapter D. UOG EXTRACTION WASTEWATER MANAGEMENT AND DISPOSAL
PRACTICES
During the lifetime of a well, UOG extraction generates large volumes of UOG extraction
wastewater that contain constituents potentially harmful to human health and the environment, as
discussed in Chapter C. This creates a need for appropriate wastewater management
infrastructure and disposal practices. Except in limited circumstances,65 the existing effluent
guidelines for oil and gas extraction prohibit the onsite direct discharge of wastewater into waters
of the United States. Historically, operators primarily managed their wastewater via underground
injection (where available). This section discusses the methods used by UOG operators to
manage and dispose of UOG extraction wastewater.
1 OVERVIEW OF UOG EXTRACTION WASTEWATER MANAGEMENT AND DISPOSAL
PRACTICES
For management of UOG produced water, UOG operators primarily use the three
methods listed below and shown in Figure D-l (188 DCN SGE00613; 177 DCN SGE00276; 76
DCN SGE00528).
• Dispose of wastewater via underground injection, using Class II UIC disposal wells
("disposal wells")
• Reuse/recycle wastewater in subsequent fracturing jobs
• Transfer wastewater to a CWT facility
Across the United States, operators most often manage their produced water via disposal
wells. For management of drilling wastewater, which includes drill cuttings and drilling fluids,
operators primarily use the methods listed below and shown in Figure D-2 (55 DCN SGE00740).
• Disposal via disposal wells
• Reuse/recycle in subsequent drilling and/or fracturing jobs
• Transfer to a CWT facility
• Onsite burial66
• Disposal via landfill
• Land application
In select areas, UOG operators also use evaporation ponds for disposal of UOG produced
water and drilling wastewater. However, there are certain requirements for using evaporation
ponds, including very dry climates, which mainly occur in the western United States (148 DCN
65 While the existing oil and gas extraction ELG allows onshore oil and gas extraction wastewater generated west of
the 98th meridian to be permitted for discharge when the water is of good enough quality for agricultural and wildlife
uses (see 40 C.F.R. part 435 subpart E), the EPA has not found that these types of permits are typically written for
UOG extraction wastewater (as defined for the proposed rule).
66 Onsite burial involves temporary fluid storage in on-site open earthen or lined pits with burial of residual solids
after fluids are solidified, removed from the top, or evaporated.
77
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
SGE00710). Evaporation ponds also require a large, flat site, and they perform best only during
select months of the year (e.g., May through October) (114 DCN SGE00779.A24).
o
UOG Well
^ r
O
Injection into Class
II disposal wells
Treatment
in the field
Reuse in
fracturing
UOG Wells
Legend
Treated UOG Produced Water
Untreated UOG Produced Water
CWT
facilities
POTWs
water
Figure D-l. UOG Produced Water Management Methods
UOG well
O
> r
Burial
V
Landfill
^'
O
Legend
Treated drilling wastewater
Untreated drilling wastewater
Treatment
in the field
CWT
facilities
POTWs
Injection into class
II disposal we 11s
Sur
w
*
Surface
water
Reuse/Recycle
Figure D-2. UOG Drilling Wastewater Management Methods
78
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
UOG operators' frequency of use of each of the aforementioned UOG extraction
wastewater management options varies by operator, by formation, and sometimes within each
region of the formation (139 DCN SGE00579; 177 DCN SGE00276; 178 DCN SGE00635; 55
DCN SGE00740). Table D-l describes how UOG operators manage produced water specifically
in basins containing major UOG formations, which varies by basin and formation. As detailed
above, historically, the oil and gas industry has most commonly managed produced water by
underground injection (25 DCN SGE00182), but the industry is increasingly turning to
reuse/recycle and, in some geographic areas, transferring to CWT facilities to manage growing
volumes of wastewater (see Section D.3 and Section D.4) (43 DCN SGE00596; 92 DCN
SGE00707; 34 DCN SGE00708).
The literature does not contain the same level of detailed information about drilling
wastewater management practices as is provided for produced water management in Table D-l.
However, the EPA did identify comprehensive data for management of drilling wastewater
generated by Marcellus shale wells located in Pennsylvania. Figure D-3 shows management
practices used by UOG operators in Pennsylvania for managing their UOG drilling wastewater
from 2008 to 2013. In recent years (2010 to 2013), transfer to CWT facilities, reuse/recycle in
drilling or fracturing, and injection for disposal—in that order—were the most common practices
(46 DCN SGE00739) for UOG drilling wastewater management in Pennsylvania. In addition to
this detailed information about drilling wastewater management in Pennsylvania, the EPA
obtained information from a large UOG operator regarding its Fayetteville shale operations. This
operator reported that it reuses/recycles the majority of its drilling wastewater in drilling
subsequent wells and the remainder is disposed of via disposal wells (191 DCN SGE00625).
To illustrate how management practices used by UOG operators vary geographically, the
EPA mapped the locations of known CWT facilities and disposal wells in the Appalachian basin
(containing the Utica and Marcellus shale formations).67 Figure D-4 compares the east and west
portions of the basin, thus illustrating basin and formation differences in wastewater
management practices. The east side of the basin contains very few underground disposal wells,
but contains a high density of CWT facilities that have accepted or plan to accept UOG produced
water from operators. In contrast, the west side has an abundance of disposal wells and injection
for disposal is the primary wastewater management practice.
The remaining subsections in Chapter D describe UOG produced water management
practices: how disposal in disposal wells is the most common practice, how reuse/recycle in
fracturing fluid is increasing, and how increasing numbers of CWT facilities are accepting UOG
produced water and drilling wastewater where disposal wells are limited. Although operators
have discharged UOG extraction wastewater to POTWs, these discharges were discontinued in
2011 (46 DCN SGE00739; 80 DCN SGE00286; 109 DCN SGE00345; 139 DCN SGE00579).
After describing the three management alternatives that the UOG industry uses (i.e., injection
into disposal wells, reuse/recycle in fracturing, transfer to CWT facility), Chapter D ends with a
discussion of POTWs and how they cannot remove some of the constituents in UOG extraction
wastewater and drilling wastewater. The end of Chapter D also presents EPA-collected data
67 The EPA obtained information about CWT facilities accepting UOG extraction wastewater from publicly
available sources. Therefore, the list of CWT facilities the EPA identified may not be complete.
79
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
indicating that POTWs have not received any UOG extraction wastewater between 2011 and the
present (data are current up through the end of 2013).
80
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-l. UOG Produced Water Management Practices
Basin
Michigan
Appalachian
Anadarko
Arkoma
Fort Worth
Permian
TX-LA-MS Salt
West Gulf
Denver Julesburg
Piceance; Green
River
Williston
UOG Formation
Antrim
Marcellus/Utica (PA)
Marcellus/Utica (WV)
Marcellus/Utica (OH)
Granite Wash
Mississippi Lime
Woodford, Cana,
Caney
Fayetteville
Barnett
Avalon/Bone Springs,
Wolfcamp, Spraberry
Haynesville
Eagle Ford, Pearsall
Niobrara
Mesaverde/Lance
Bakken
Resource
Type
Shale gas
Shale gas
Shale gas/oil
Shale gas/oil
Tight gas
Tight oil
Shale gas/oil
Shale gas
Shale gas
Shale/tight
oil/gas
Tight gas
Shale gas/oil
Shale gas/oil
Tight gas
Shale oil
Reuse or
Recycle
XXX
XXX
XX
XX
X
X
XX
X
X
X
X
X
X
X
Injection for
Disposal
XXX
XX
XX
XXX
XXX
XXX
XXX
XX
XXX
XXX
XXX
XXX
XXX
XX
XXX
CWT
Facilities
XX
X
X
xa
xa
xa
xa
xa
X
X
X
Notes
Limited disposal wells in east
Reuse/recycling limited but is being
evaluated
Few existing disposal wells; new CWT
facilities are under construction
Reuse/recycle not typically effective due to
high TDS early in flowback and abundance
of disposal wells
Reuse/recycle not typically effective due to
high TDS early in flowback and abundance
of disposal wells
Also managed through evaporation to
atmosphere in ponds in this region
Reuse/recycling limited but is being
evaluated
Available
Datab
Qualitative
Quantitative
Quantitative
Mixed
Mixed
Qualitative
Qualitative
Mixed
Mixed
Mixed
Mixed
Mixed
Mixed
Qualitative
Mixed
Sources: 48 DCN SGE00693
a—CWT facilities identified in these formations are all operator-owned.
b—This column indicates the type of data the EPA based the number of Xs on. In most cases, the EPA used a mixture of qualitative and quantitative data sources
along with engineering judgment to determine the number of Xs.
XXX—The majority (>50%) of wastewater is managed with this management practice; XX—A moderate portion (>10% and <50%) of wastewater is managed with
this management practice; X—This management practice has been documented in this location, but for a small (<10%) or unknown percent of wastewater.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
100%
2008 2009 2010 2011
Year
2012
2013
0%
I Annual UOG Drilling WastewaterVolurne
I Underground Injection
IPOTW
CWT Facility
I Other
Reuse/Recycle
Landfill
Sources: 46 DCN SGE00739
Figure D-3. Management of UOG Drilling Wastewater Generated by UOG Wells in
Pennsylvania (2008-2013)
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Sources: Generated by the EPA using data from 43 DCN SGE00596 and 41 DCN SGE00736
Figure D-4. Active Disposal Wells and CWT Facilities Identified in the Appalachian
Basin68
0 The active disposal wells data for New York were last updated in September 2009 for New York and December
2013 for Pennsylvania. The last update for the active disposal wells data in Ohio and West Virginia is unknown. The
EPA accessed the Ohio data in February 2013 and the West Virginia data in December 2013. The CWT facility data
were last updated at the end of 2013, based on publicly available information.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
2 INJECTION INTO DISPOSAL WELLS
Historically, underground injection has been the most common wastewater management
method among UOG operators. In 2010, the EPA and industry stakeholders estimated that over
90 percent of oil and gas produced water (conventional and unconventional) was disposed of via
Class II injection wells (207 DCN SGE00623). Underground injection involves pumping wastes
into an underground formation with a confining layer of impermeable rock. The formation must
also be porous enough to accept the wastewater. In its underground injection well control
program codified in 40 C.F.R. parts 144 to 148, the EPA established six classes of underground
injection wells (173 DCN SGE00132):
• Class I industrial and municipal waste disposal wells
• Class II oil and gas related injection wells
• Class III mining wells
• Class IV shallow hazardous and radioactive injection wells (banned)
• Class V any not covered in Class I through IV (e.g., leach fields)
• Class VI carbon dioxide storage or sequestration
Class II injection wells serve three major purposes:
• Injection of hydrocarbons for storage
• Injection of fluids for disposal (i.e., disposal wells)
• Injection of fluids for enhanced recovery (i.e., enhanced recovery wells)
Approximately 20 percent of Class II wells in the United States are disposal wells; the
remaining 80 percent are mostly enhanced recovery wells (173 DCN SGE00132). Injection for
disposal typically involves injecting wastewater into a porous and non-oil-and-gas-containing
reservoir. Industry does not use enhanced recovery wells for disposing of UOG extraction
wastewater because most enhanced recovery projects consist of a closed-loop system with two or
more wells: at least one producing well and at least one enhanced recovery well. Operators of
enhanced recovery projects typically route the wastewater generated by the producing well
directly back to the adjacent enhanced recovery well (206 DCN SGE00623; 173 DCN
SGE00132; 188 DCN SGE00613). Available literature and communication with industry
indicates that industry only hauls UOG extraction wastewater to Class II disposal wells and does
not use Class II enhanced recovery wells. In fact, the leading method of UOG extraction
wastewater management throughout the United States is injection into a Class II disposal well
(51 DCN SGE00693.A03). However, all types of oil and gas extraction wastewater (e.g.,
conventional, CBM, UOG) may be disposed of in Class II disposal wells.
2.1 Regulatory Framework for Underground Injection
The EPA's regulations on underground injection wells are described in Chapter A. States,
territories, and tribes have the option of requesting primacy, or primary enforcement authority,
from the EPA for the Class II wells within their boundaries. In order to receive primacy, the state
underground injection program must meet the EPA's regulatory requirements to prevent
underground injection that endangers drinking water sources, or have a program determined to
84
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
be effective as the federal standards. Currently, the EPA has delegated Class II primacy to 39
states, three territories and two tribes. The EPA has authority over the Class II UIC programs in
the remaining 11 states, two territories and all other tribes (184 DCN SGE00611).
2.2 Active Disposal Wells and Volumes
The availability of underground injection for disposal varies by state. Some states have a
large number of Class II injection wells (e.g., Texas, Oklahoma, Kansas) while others have few
(e.g., Virginia, South Dakota). The EPA tabulated active Class II disposal wells using data from
state agencies and EPA direct implementation programs. More information about how the EPA
compiled data from state agencies is documented in a separate memorandum titled Analysis of
Active Underground Injection for Disposal Wells (41 DCN SGE00736; 42 DCN
SGE00736.A01).
Table D-2 presents the number of active Class II disposal wells by state (41 DCN
SGE00736; 42 DCN SGE00736.A01). It also includes average daily disposal rates for disposal
wells on a gallon-per-well-per-day basis for each state. Daily disposal rates of individual disposal
wells vary significantly, reflecting the geology of the underlying formation (176 DCN
SGE00279). The average disposal rate per well estimates in the table are not exact but rather are
general approximations based on a number of assumptions which are described in detail in
ERG's memorandum Analysis of Active Underground Injection for Disposal Wells (41 DCN
SGE00736). Lastly, Table D-2 presents the total state disposal rate based on the active number of
disposal wells and average daily disposal rates per well. States are first sorted by geographic
region, then by the total state disposal rate. States with no disposal rate data are sorted by highest
to lowest count of active Class II disposal wells.
Table D-2. Distribution of Active Class II Disposal Wells Across the United States
Geographic Region
(from the EIA)
Alaska
East
Gulf Coast/Southwest
State
Alaska
Illinois
Michigan
Ohio
Indiana
West Virginia
Virginia
Kentucky
Pennsylvania
New York
Tennessee
Maryland
Minnesota
North Carolina
Texas
Number of Active
Disposal Wells"
45
1,054
779g
188
183
66
12
58
9
10d
0
0
0
0
7,876
Average Disposal
Rate Per Well
(gpd/well)b
182,000
C
16,600
8,900
3,580
7,180
17,500
1,750
6,380
3,530
0
0
0
0
54,200
Total State
Disposal Rate
(MGD)
8.2
C
13
1.7
0.66
0.47
0.21
0.10
0.057
0.035
0
0
0
0
430
85
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-2. Distribution of Active Class II Disposal Wells Across the United States
Geographic Region
(from the EIA)
Mid-Continent
Northern Great Plains
Rocky Mountains
West Coast
State
Louisiana
New Mexico
Mississippi
Alabama
Oklahoma
Kansas
Arkansas
Nebraska
Missouri
North Dakota
Montana
South Dakota
Wyoming
Colorado
Utah
Arizona
California
All other states (NV, FL, OR, IA, and WA)f
Total
Number of Active
Disposal Wells"
2,448
736
499
85
4,622g
5,516
611e
113
11
395
199
21
330
294
109
0
826
42
27,137
Average Disposal
Rate Per Well
(gpd/well)b
42,100
48,600
69,500
44,200
35,900
20,900
30,900
18,100
1,270
31,600
31,100
10,200
C
50,200
74,400
0
77,800
89,400
40,400
Total State
Disposal Rate
(MGD)
100
36
35
3.8
170
120
19
2.0
0.014
12
6.2
0.21
C
15
8.1
0
64
3.8
1,040
Sources: 41 DCN SGE00736
a—Number of active disposal wells is based primarily on data from 2012 to 2014.
b—Typical injection volumes per well are based on historical annual volumes for injection for disposal divided by
the number of active disposal wells during the same year (primarily data 2007 to 2013). These approximations are
based on a number of assumptions which are detailed in ERG's Analysis of Active Underground Injection for
Disposal Wells memorandum (41 DCN SGE00736).
c—Disposal rates and/or number of disposal wells is unknown.
d—These wells are not currently permitted to accept UOG extraction wastewater (source: 186 DCN SGE00726).
e—Only 24 of the 614 active disposal wells in Arkansas are in the northern half of the state, close to the Fayetteville
formation (6 DCN SGE00499).
f—These are states that have minimal oil and gas activity. The number of wells shown for these states may include
all types of Class II wells (e.g., Class II enhanced recovery wells) and therefore is an upper estimate (167 DCN
SGE00138). All other states not listed in this table have minimal oil and gas activity and no active disposal wells.
g—With the exception of Oklahoma and Michigan, wells on tribal lands have not been intentionally included. Wells
on tribal lands may be counted if state databases contained them.
Abbreviations: gpd—gallons per day; MGD—million gallons per day
2.3 Underground Injection Considerations
In many UOG formations, distances from the average producing well to the nearest
disposal well are short and disposal capacity is abundant, making it the least expensive UOG
extraction wastewater management practice (178 DCN SGE00635). There is no widespread
discussion in the industry about lack of injection well disposal capacity (188 DCN SGE00613)
nationally, suggesting that there is enough capacity in place and; therefore, potential for
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
continued acceptance of UOG extraction wastewater. However, as illustrated above,
underground injection for disposal capacity in close proximity is much less available in certain
portions of the United States. Another consideration is freshwater availability. In some areas
with plentiful underground injection for disposal capacity where water scarcity is a problem,
there is a concern about permanently disposing of UOG produced water underground rather than
using it to supplement freshwater needs in subsequent hydraulic fracturing jobs (75 DCN
SGE00760; 142 DCN SGE00583).
Commercial injection for disposal well operators may surcharge operators to dispose of
flowback (176 DCN SGE00279). Injection well operators impose the surcharge because
flowback has a lower density than long-term produced water. Injection of high-density
wastewater requires less power (i.e., pumping) than injecting less-dense wastewater,69 and the
injection rate (i.e., barrels per day per well) is inversely proportional to the injection pressure due
to technical and permit limitations. As a result, disposal well operators must inject lower-density
flowback at a lower flow rate and more power.
3 REUSE/RECYCLE IN FRACTURING
As of 2013, many operators evaluate reusing/recycling UOG extraction wastewater
before deciding to manage it via another method (i.e., disposal well or CWT facility) (188 DCN
SGE00613; 38 DCN SGE00521; 177 DCN SGE00276). Reuse/recycle involves mixing
flowback and/or long-term produced water from previously fractured wells with other source
water70 to create the base fluid71 used in a subsequent well fracture (1 DCN SGE00046).
Operators typically transport the wastewater, by truck or pipe, from storage to the fracturing site
just before and during hydraulic fracturing. Operators typically store the wastewater in 10,500-
to 21,000-gallon (200- to 500-barrel) fracturing tanks onsite until they are ready to blend it with
other source water during the hydraulic fracture. When hydraulic fracturing begins, they pump
the stored UOG produced water for reuse and other source water to a blender to form the base
fluid. The blending usually occurs upstream of other steps such as fracturing chemical addition
or pressurization by the pump trucks (191 DCN SGE00625).
Since the late 2000s, UOG operators have increased wastewater reuse/recycle (188 DCN
SGE00613). In the early development of UOG (i.e., the early to mid-2000s), most operators
believed that reuse/recycle was not technically feasible because high IDS concentrations in
UOG extraction wastewater adversely affected fracturing chemical additives and/or formation
geology (188 DCN SGE00613). As a result, operators used only fresh water as base fluid for
fracturing. One of the changes that contributed to more widespread reuse of wastewater as a base
fluid is that fracturing service providers were able to design fracturing additives to tolerate base
fluids with higher concentrations of IDS (194 DCN SGE00691; 38 DCN SGE00521; 188 DCN
SGE00613; 208 DCN SGE00095).
69 The density of flowback is typically close to that of fresh water (8 pounds per gallon), while the density of
produced water can be greater than 10 pounds per gallon (176 DCN SGE00279).
70 Source water is any fluid that makes up fracturing base fluid. See Section C. 1.1.
71 Base fluid is the primary component of fracturing fluid to which proppant and chemicals are added. See Section
C.I.I.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
To date, slickwater fracturing fluid designs (defined in Section C.I) are the most
accommodating for using base fluid that contains the high end of the IDS criteria ranges (see
Table D-4 in section D.3.2 for these ranges) (188 DCN SGE00613; 40 DCN SGE00705; 193
DCN SGE00616). Gel designs (defined in Section C.I), which are typically used to fracture
liquid rich plays (e.g., Bakken), are more complex and industry currently finds them to be less
compatible with high concentrations of TDS than slickwater designs (40 DCN SGE00705; 188
DCN SGE00613; 193 DCN SGE00616). As a result, at present, gel designs require base fluid
that meets the low end of the TDS criteria ranges (see Table D-4 in section D.3.2 for these
ranges). This is primarily because TDS interferes with the properties of the cross-linked gels
inherent to gel fracturing fluid designs. Industry also reports that boron is a constituent of
concern for reuse/recycle when using gel recipes because it interferes with the intended delayed
activation of cross-linked gels (193 DCN SGE00616; 40 DCN SGE00705). This may be
changing: industry has recently demonstrated the use of higher-TDS base fluid in gel fracturing
as new chemical additives are becoming available for gel designs that tolerate higher TDS
concentrations72 (110 DCN SGE00667; 40 DCN SGE00705).
PESA surveyed 205 UOG operators about their wastewater management practices in
2012 (136 DCN SGE00575).73 Table D-3 presents the survey results. Nationally, UOG operators
reported reusing/recycling 23 percent of total produced water generated. The results also showed
that most operators anticipate reusing/recycling higher percentages of their produced water in the
two to three years following the survey. Other research firms that gather data on UOG extraction
wastewater management report similar findings (34 DCN SGE00708; 122 DCN SGE00709). For
example, IHS Inc. estimates that in 2013 operators reused/recycled 16 percent of UOG produced
water nationwide and expects this number to double by 2022 (34 DCN SGE00708). The EPA
participated in several site visits and conference calls with operators in several formations that
have been able to reuse/recycle 100 percent of their produced water under certain circumstances
(178 DCN SGE00635; 179 DCN SGE00275; 191 DCN SGE00625; 183 DCN SGE00636).
Table D-3. Reuse/Recycle Practices in 2012 as a Percentage of Total Produced Water
Generated as Reported by Respondents to 2012 Survey
Basin
Appalachian
TX-LA-MS
Salt
Arkoma
Western Gulf
Fort Worth
Permian
Williston
UOG Formation
Marcellus/Utica
Haynesville
Fayetteville
Eagle Ford
Barnett
Avalon; Barnett-
Woodford
Bakken
Resource
Type
Shale gas/oil
Shale gas
Shale gas
Shale gas/oil
Shale gas
Shale gas/oil
Shale oil
Percent of
Wastewater
Reused/Recycled
for Fracturing
74
30
30
16
13
7
5
Percent of
Wastewater
Managed Using
Other Methods3
26
70
70
84
87
93
95
Percent of
Respondents
Planning to Increase
Reuse/Recycle
50
67
67
60
86
67
56
One vendor reported that testing of new additives for gel designs that allow the use of high-TDS base fluid is
underway. This vendor expected the cost for these chemicals to initially be high (40 DCN SGE00705).
73 Out of the 205 respondents, 143 represented operators active in major U.S. UOG plays.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-3. Reuse/Recycle Practices in 2012 as a Percentage of Total Produced Water
Generated as Reported by Respondents to 2012 Survey
Basin
UOG Formation
Gulf Coast (Austin Chalk, Cotton
Valley, Vicksburg)b
Mid-Continent (Woodford, Cana,
Caney, Granite Wash)b
Rockies (Niobrara, Mancos)b
Resource
Type
Unknown
Unknown
Unknown
Weighted average
Percent of
Wastewater
Reused/Recycled
for Fracturing
10
25
14
23
Percent of
Wastewater
Managed Using
Other Methods"
90
75
86
77
Percent of
Respondents
Planning to Increase
Reuse/Recycle
100
68
100
55
Source: 136 DCN SGE00575
a—PESA (136 DCN SGE00575) reported this as "disposal" but did not clearly describe what it means.
b—PESA (136 DCN SGE00575) did not specify basin or formation for these areas. The EPA provided formation
names that are present in these areas if not already previously listed above.
3.1 Reuse/Recycle Strategies
Operators can reuse/recycle UOG extraction wastewater for fracturing through different
strategies. An operator's choice of strategy depends on many factors, which Section D.3.2
describes in detail. The following subsections discuss direct reuse/recycle without treatment and
reuse/recycle after treatment.
3.1.1 Direct Reuse/Recycle for Fracturing Without Treatment
Many operators reuse/recycle their wastewater for fracturing without any treatment (i.e.,
only blending with fresh water) or with minimal treatment such as sedimentation or filtration to
remove suspended solids. The primary purpose of the blending is to control TDS concentrations
(193 DCN SGE00616; 194 DCN SGE00691). When using this strategy, operators either
transport UOG extraction wastewater directly to the next well they are fracturing or transport it
to a temporary storage area offsite until they are ready to fracture the next well.
Reuse/recycle without treatment accounts for a large portion of all wastewater that
industry reuses/recycles. In PESA's 2012 survey (136 DCN SGE00575), UOG operators
reported that 54 percent of produced water reused/recycled by the UOG industry in 2012 for
fracturing requires minimal or no treatment. In addition, the EPA conducted several site visits
and conference calls with operators that have increasingly reused/recycled wastewater with no
treatment (178 DCN SGE00635; 179 DCN SGE00275; 191 DCN SGE00625; 183 DCN
SGE00636; 177 DCN SGE00276).
3.1.2 Reuse/Recycle in Fracturing After Treatment
Operators also reuse/recycle UOG extraction wastewater after some type of treatment.
Where treatment is employed, the UOG industry typically uses one of two levels of treatment:
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
• Non-TDS removal technologies—technologies that remove non-dissolved74
constituents from wastewater, including suspended solids, oil and grease, bacteria,
and/or certain ions that can cause scale to form on equipment and interfere with
fracturing chemical additives. These technologies are not designed to reduce the
levels of dissolved constituents, which are the majority of compounds that contribute
to IDS in UOG extraction wastewater.
• TDS removal technologies—technologies capable of removing dissolved
constituents that contribute to TDS (e.g., sodium, chloride, calcium) as well as the
constituents removed by non-TDS removal technologies. Treatment systems with
these treatment technologies include non-TDS removal technologies for pretreatment
(e.g., TSS, oil and grease).
Each of these levels of treatment is described in more detail below. Also see the EPA's
report titled Unconventional Oil and Gas (UOG) Extraction Wastewater Treatment Technologies
(203 DCN SGE00692), which discusses treatment technologies used to treat UOG produced
water.
Non-TDS Removal Technologies
As discussed in Section D.3, there are constituents in UOG extraction wastewater other
than TDS that operators may need to remove or destabilize before reuse/recycle. In particular,
they may need to reduce constituents that may cause scale, formation damage, and/or
interference between chemical additives and the formation geology (203 DCN SGE00692).
These constituents include suspended solids, oil and grease, bacteria, and certain ions (e.g., iron,
calcium, magnesium, and barium). Non-TDS removal technologies used to treat UOG extraction
wastewater for reuse/recycle include (188 DCN SGE00613; 208 DCN SGE00095):
• Solids removal (e.g., sedimentation, filtration, dissolved air flotation)
• Chemical precipitation
• Electrocoagulation
• Advanced oxidation precipitation
Industry often uses non-TDS removal technologies to remove or destabilize the
aforementioned constituents. This treatment may be done in the field at the well site or off-site at
a CWT facility. One method used in the field to treat UOG extraction wastewater is referred to as
"on the fly" treatment, where the wastewater is treated as fluids are mixed for hydraulic
fracturing.
Figure D-5 shows a simplified flow diagram of on-the-fly treatment of UOG produced
water for reuse/recycle. In this practice, the operator treats the mixture of UOG produced water
and other source water concurrently with the hydraulic fracturing process. Therefore, wastewater
74 EPA has categorized treatment technologies into two categories in this document: those that are designed to
remove dissolved constituents and those that are not designed to remove dissolved constituents. However, it should
be noted that some of the technologies in the non-TDS removal category do in fact remove some dissolved
constituents. For example, chemical precipitation will remove certain metals. However, these technologies typically
will not remove salts and hardness, which are the primary components of TDS in UOG extraction wastewater.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
75
treatment occurs at relatively high flow rates equivalent to the rate of hydraulic fracturing.
Other than the treatment unit, there is no additional equipment required in this setup that is not
already required for hydraulic fracturing (e.g., additional storage typically required for treated
wastewater). This eliminates or reduces the following (30 DCN SGE00331):
76
Transporting wastewater for reuse/recycle to a CWT facility and then transporting it
again to the next well for fracturing
Procuring the services of a CWT facility
Purchasing or renting storage containers, and renting space on which to keep the
storage containers, for treated wastewater
Nearby
impoundment or
pond
Other source
water
Well pad
Blender
Base
fluid
UOG produced
water treatment
system
Treated
base
fluid
Fracturing
fluid
L_
Fracturing tanks with
untreated wastewater
....J
Source: Generated by EPA using 30 SGE00331.
Figure D-5. Flow Diagram of On-the-Fly UOG Produced Water Treatment for
Reuse/Recycle
TDS Removal Technologies
In general, TDS removal technologies convert influent wastewater into two streams:
concentrated brine and low-TDS water (i.e., distillate). As discussed in the introduction to
Operators typically hydraulically fracture wells at rates of 2,520 to 5,040 gallons (60 to 120 barrels) per minute.
On-the-fly treatment technologies must be capable of treating wastewater at the same rate (203 DCN SGE00692).
76 The most common technology for on-the-fly treatment is advanced oxidation. This technology eliminates the need
to add biocide to the fracturing fluid to prevent bacteria growth.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Section D.3, operators have learned that low-TDS base fluid is not necessarily required for
fracturing. However, some operators may still use IDS removal technologies to treat wastewater
for reuse/recycle in fracturing. IDS removal technologies that UOG operators have used to treat
UOG extraction wastewater for reuse/recycle include (188 DCN SGE00613; 208 DCN
SGE00095) reverse osmosis (when TDS is less than approximately 50,000 mg/L) and
evaporation/condensation and crystallization (203 DCN SGE00692). Some vendors currently
offer skid-mounted mobile TDS removal units for reuse/recycle in the field (203 DCN
SGE00692). The EPA also identified several CWT facilities owned by operators that use TDS
removal technologies (e.g., evaporation/condensation) (84 DCN SGE00284).
3.2 Reuse/Recycle Drivers
The reuse/recycle strategy operators choose depends on many different factors. The
following subsections describe the two biggest drivers (148 DCN SGE00710):
• Pollutant concentrations in UOG extraction wastewater compared to maximum
acceptable pollutant concentrations for base fluid (described in more detail in Section
D.3.2.1)
• Volume of UOG extraction wastewater available for reuse/recycle compared to total
volume of base fluid required for fracturing a new well (described in more detail in
Section D.3.2.2)
These factors vary by formation and operator; therefore, the potential for
reusing/recycling UOG extraction wastewater for fracturing also varies by formation and
operator. These two drivers ultimately affect the level of treatment required, if any, and the total
cost for reuse/recycle. Operators always consider the total cost per barrel for reuse/recycle as
compared to other management alternatives.
3.2.1 Pollutant Concentrations in Available UOG Extraction Wastewater for Reuse/Recycle
Operators typically consider TDS when they evaluate whether they can reuse/recycle
their wastewater and, if so, what level of treatment is required prior to reuse/recycle (148 DCN
SGE00710). Operators are more likely to reuse/recycle UOG extraction wastewater with low
TDS and high volumes to avoid TDS treatment and/or minimize freshwater usage. As explained
in Section C.3.2.1 and shown in Figure C-6, TDS concentrations increase over time as the flow
rate decreases after fracturing (148 DCN SGE00710, 85 DCN SGE00414, 27 DCN SGE00357,
151 DCN SGE00350, 191 DCN SGE00625). Therefore, operators are more likely to
reuse/recycle flowback than long-term produced water because concentrations of TDS in
flowback, on average, are lower than concentrations in long-term produced water (see Section
C.3.2.1) (148 DCN SGE00710).
Some operators are able to reuse/recycle long-term produced water with no or minimal
TDS treatment, as observed by the EPA in the Marcellus and Fayetteville shale formations (183
DCN SGE00636; 178 DCN SGE00635; 191 DCN SGE00625). However, this may not be
possible in all UOG formations. As shown in Chapter C, the maximum concentration of TDS
and the rate at which that concentration is reached are functions of the underlying geology. This
means that, in some basins, the TDS concentrations for long-term produced water may be lower
than the TDS concentrations for flowback in other basins. For example, in the Bakken formation,
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
TDS concentrations in flowback increase rapidly to levels as high as 200,000 mg/L (within five
days after fracturing), which may limit the volume of this wastewater capable of being used for
reuse/recycle (151 DCN SGE00350).77 On the other hand, the Fayetteville shale formation
generates a maximum of 40,000 mg/L TDS in long-term produced water (191 DCN
SGE00625).78
If operators reuse/recycle UOG extraction wastewater that contains too much of certain
constituents, the fracturing fluid, well, and/or formation may undergo one or more of the
following problems (3 DCN SGE00070):
• Fluid instability (change in fluid properties)
• Well plugging (restriction of flow)
• Well bacteria growth (buildup of bacteria on casing)
• Well scaling (accumulation of precipitated solids)
• Formation damage (restriction of flow in the reservoir)
Table D-4 shows ranges of observed or recommended constituent concentration criteria
for the fracturing base fluid and the associated effect that the fluid or well may experience with
concentrations in excess of the criteria. These ranges represent general values that industry
reports, not values specific to one UOG formation. The exact criteria an operator uses depend on
operator preference, geology, and the fracturing fluid chemistry (e.g., slickwater, gel), but the
selected criteria typically fall within the ranges shown in Table D-4.
77 This report determined that only the initial five percent of the injected fracturing fluid volume that returns to the
surface contains TDS less than 60,000 mg/L in the Bakken, based on sampling data for 62 wells.
78 This operator reported that they are able to reuse all of their UOG wastewater due to low TDS concentrations.
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Table D-4. Reported Reuse/Recycle Criteria
Constituent
TDS
Chloride
Sodium
Reasons for Limiting
Concentrations
Fluid stability
Fluid stability
Fluid stability
Recommended or Observed Base Fluid Target
Concentrations (mg/L,a After Blending)
500-70,000
2,000-90,000
2,000-5,000
Metals
Iron
Strontium
Barium
Silica
Calcium
Magnesium
Sulfate
Potassium
Scale formers'3
Phosphate
Scaling
Scaling
Scaling
Scaling
Scaling
Scaling
Scaling
Scaling
Scaling
Not reported
1-15
1
2-38
20
50-4,200
10-1,000
124-1,000
100-500
2,500-2,500
10
Other
TSS
Oil
Boron
pH (SU)
Bacteria (counts/mL)
Plugging
Fluid stability
Fluid stability
Fluid stability
Bacterial growth
50-1,500
5-25
0-10
6.5-8.1
0-10,000
Sources: 48 DCN SGE00693
a—Unless otherwise noted.
b—Includes total of barium, calcium, manganese, and strontium.
Abbreviations: mg/L—milligrams per liter; SU—standard units; mL—milliliter
3.2.2 Base Fluid Demand for Fracturing
The amount of wastewater used in fracturing fluid make up depends not just on
wastewater pollutants and concentrations but also on wastewater quantity compared to the
amount of water required for the base fluid.
Water Demand at the Well Level
The volume of fracturing fluid required per well for fracturing may also influence the
level of treatment or blending ratio necessary to meet the base fluid pollutant criteria in Table
D-4. The blending ratio is the volume of reused/recycled wastewater as a percent of the total
base fluid volume used to fracture a specific well. The blending ratio depends on the wastewater
pollutants and concentrations as well as on the volume of UOG extraction wastewater available
and the total volume of base fluid required. Operators must consider how much wastewater is
generated by nearby wells with respect to how much fracturing fluid is required to fracture a
subsequent well. In areas where produced water volume generation is high and/or the required
total base fluid volume for fracturing is low, operators may use a high blending ratio. As
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
explained above, this high ratio may require more treatment depending on TDS and other
constituent concentrations. On the other hand, in formations where produced water volume
generation is low and total base fluid fracturing volume is high, operators may use a low
blending ratio. A low blending ratio can typically be used with little to no treatment (179 DCN
SGE00275; 178 DCN SGE00635; 188 DCN SGE00613). Table D-5 shows observed blending
ratios for various formations. This table also includes theoretical upper end blending ratios as
presented in literature which are based on the typical fracturing fluid volume and produced water
volume generated per well79 for each formation (215 DCN SGE00627; 126 DCN SGE00639;
and 194DCNSGE00691).
Table D-5. Reported Reuse/Recycle Practices as a Percentage of Total Fracturing Volume
Basin
Anadarko
Appalachian
Arkoma
Denver J.
Fort Worth
Permian
TX-LA-MS Salt
Western Gulf
Formation
Cleveland
Granite Wash
Mississippi Lime
Marcellus
Utica
Fayetteville
Niobrara
Barnett
c
Haynesville
Tuscaloosa Marine
Eagle Ford
Resource
Type
Tight
Tight
Tight
Shale
Shale
Shale
Shale
Shale
Shale/tight
Shale
Shale
Shale
Observed Blending
Ratio3 (%)
—
—
—
10-12
—
6-30
—
4-6
2-40
5
25
—
Estimated Maximum Potential
Blending Ratiob (%)
10-40
10-40
50
10-40
10-40
—
10-40
10-40
50
5-10
—
10-40
Sources: 48 DCN SGE00693
Note: Data years represented range from 2009 to 2013.
a— Actual observed volumes of reused/recycled UOG extraction wastewater as a percentage of fracturing fluid
volume.
b— Estimated maximum blending ratio based on typical flowback volume per well compared to typical fracturing
volume per well as presented in 215 DCN SGE00627; 126 DCN SGE00639; and 194 DCN SGE00691.
c— References do not specify a specific formation.
"—" indicates no data.
Water Demand at the Formation Level
Although reuse/recycle has become popular as a way to manage UOG extraction
wastewater, it is anticipated to become less attractive as a formation matures and the operator
drills and fractures fewer wells (148 DCN SGE00710). As a formation matures, the volume of
base fluid needed to fracture new wells may be less than the volume of produced water generated
by producing wells in the area (191 DCN SGE00625). Figure D-6 illustrates this concept80 with
a hypothetical situation for an operator in a single formation as reported by an operator (20 DCN
SGE00305.A03). During early years of development, the base fluid demand for fracturing wells
79 This theoretical value reported in literature is irrespective of constituent concentrations.
80 This concept assumes that operators do not typically share wastewater for reuse in fracturing.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
always exceeds the volume of produced water generated. This provides favorable conditions for
reuse/recycle. As drilling decreases, the volume of base fluid needed decreases below the volume
of produced wastewater generated. Consequently, the operator must find an alternative for at
least some portion of the produced water (e.g., disposal well).
O
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
UOG Produced Water
Generation
Demand for Fracturing
UOG produced water
generation exceeds
demand for fracturing
0.0
2010
2015
2020
2035
2040
2045
2050
2025 2030
Year
Source: 48 DCN SGE00693 (Generated by the EPA based on figure in 20 DCN SGE00305.A03)
Figure D-6. Hypothetical UOG Produced Water Generation and Base Fracturing Fluid
Demand over Time
3.3 Other Considerations for Reuse/Recycle
In addition to the level of treatment required for reuse/recycle, operators consider the
following as they decide whether to reuse/recycle their wastewater:
• Wastewater transportation
• Wastewater storage
• Source water availability and cost
3.3.1 Transportation
Transportation requirements affect the wastewater reuse/recycle potential in a specific
area. While not explicitly stated above, the location of the producing well(s) relative to the
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
location of disposal well(s), CWT facilities, and/or a subsequent well(s) to be drilled is also a
consideration. Operators must determine and compare the cost (dollars per barrel) to transport
the wastewater for all management scenarios.
Further, when an UOG well generating wastewater is far from alternative management
approaches such as a disposal well or CWT facility, reuse/recycle may also be more economical.
The distance between disposal wells and CWT facilities from the UOG well generating the
wastewater can vary by formation and even within formations. For example, Figure D-7 shows
how operators in the northeast region of the Marcellus reused/recycled a higher percentage of
wastewater compared to the southwestern region between 2008 and 2011 (139 DCN SGE00579).
This is due to the fact that Marcellus wells in the southwestern part of Pennsylvania are closer to
disposal wells in Ohio, whereas Marcellus wells in the northeast portion of Pennsylvania are
more than 200 miles from disposal wells in Ohio. As a result, it is typically less expensive per
barrel to reuse/recycle the wastewater in the northeast than to transport it to a disposal well in
Ohio because transportation alone can cost as much as $13 per barrel (180 DCN SGE00300).
2008 2
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
o 1
stored before reuse in a subsequent well (179 DCN SGE00275). For example, an operator who
is considering reusing extraction wastewater for fracturing that fractures 12 wells per year in an
area will need to store wastewater for approximately one month before the next fracturing job. In
comparison, an operator who fractures 50 wells per year in an area may only need to store
wastewater for a week before they can reuse/recycle it in the next fracturing job (39 DCN
SGE00283). Section B.2.1 explains UOG extraction wastewater storage options in more detail.
3.3.3 Source Water Availability
Operators that successfully reuse/recycle their wastewater can reduce the total volume of
other types of source water they need to use for base fluids, creating an offset in costs associated
with source water (208 DCN SGE00095). Fresh water from rivers and streams is relatively
abundant and inexpensive in some areas, but in others it can be a stressed resource. Seasonal
droughts can cause a high demand for resources and operators can experience inflated
acquisition costs. Reuse/recycle is more likely to be driven by these reasons for operators in arid
or drought-prone regions than for operators in regions where freshwater and groundwater
resources are abundant and inexpensive (142 DCN SGE00583; 148 DCN SGE00710). This is
because as the cost of fresh water and groundwater increases, the offset in costs from
oa
reusing/recycling wastewater to replace other source water also increases. Examples of such
areas include California, the Denver Julesburg and Permian basins, and the Eagle Ford shale
formation (148 DCN SGE00710). In addition, as mentioned above, a lack of disposal wells in
some areas may be another driver behind wastewater reuse/recycle activity in some areas (e.g.,
Marcellus shale).
4 TRANSFER TO CWT FACILITIES
Some operators manage UOG extraction wastewater by transporting it to CWT facilities.
Treated UOG extraction wastewater at CWT facilities is either discharged83 or returned to the
operator for reuse/recycle in fracturing. Operators may choose to use CWT facilities primarily
when other wastewater management options (e.g., disposal wells) are not available where they
are operating (148 DCN SGE00710; 138 DCN SGE00139; 25 DCN SGE00182).
This section provides a general overview of the types of CWT facilities that exist and that
UOG operators may use for wastewater management, typical CWT facility treatment processes,
CWT facilities that EPA is aware of that have in the past or currently accept UOG extraction
wastewater, and considerations for using CWT facilities to manage UOG extraction wastewater.
4.1 Types of CWT Facilities
A CWT facility is any facility that treats (for disposal, recycling, or recovery of material)
any hazardous or nonhazardous industrial wastes, hazardous or non-hazardous industrial
wastewater, and/or used material received from offsite (40 C.F.R 437.2(c)). CWT facilities that
accept UOG extraction wastewater are sometimes run by the UOG operator and are sometimes
81 This is primarily because many operators rent fracturing tanks on a per-tank-per-day basis. Even if operators
purchase fracturing tanks instead, the effective cost to the operator still increases as storage time increases.
82 Transportation distances may also affects costs.
83 Discharge includes both indirect discharge (to a POTW) and direct discharge (to surface water).
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
run by an entity not engaged in the oil and gas extraction business. Since UOG development
ramped up in the late 2000s, new CWT facilities that accept extraction wastewater from
operators have become available (43 DCN SGE00596), mostly in areas with less underground
injection capacity. In addition, many UOG operators have vertically integrated their companies
by purchasing or constructing their own CWT facilities (see Section D.2.2) (43 DCN
SGE00596). Some CWT facilities accept only oil and gas wastewater while others accept a
variety of industrial wastewater. They follow different discharge practices:
• Zero discharge (treated wastewater is typically reused in fracturing or disposed of in
an Class II disposal well)
• Discharge (to surface waters or POTWs)
• Multiple discharge options (a mix of discharge and zero discharge)
Pollutant discharges to surface waters or to POTWs from CWT facilities are not subject
to the Oil and Gas Extraction ELGs (40 C.F.R. part 435). Rather, they are subject to the
Centralized Waste Treatment ELGs promulgated in 40 C.F.R. part 437. Unlike the Oil and Gas
Extraction ELGs, 40 C.F.R. part 437 includes limitations and standards for both direct and
indirect dischargers.
The level of treatment CWT facilities use depends on the fate of the treated wastewater.
The two primary types of treatment technologies are non-TDS removal technologies84 and TDS
removal technologies85, defined in Section D.3. In general, CWT facilities typically use non-
TDS removal technologies for treatment before reuse/recycle and TDS removal technologies for
treatment before indirect or direct discharge.
4.1.1 Zero Discharge CWT Facilities
After treatment, a zero discharge CWT facility does not discharge the wastewater to
surface water or a POTW. Instead, it typically returns the wastewater to UOG operators for
reuse/recycle in fracturing.86 CWT facilities that accept UOG extraction wastewater from
operators and fall into this category typically allow them to unload a truckload of wastewater for
treatment and take a load of treated wastewater on a cost-per-barrel basis (37 DCN SGE00245).
Others may allow an operator to unload a truckload of wastewater for a surcharge without taking
a load of treated wastewater, as long as other operators need additional treated wastewater. Most
of these CWT facilities provide minimal (i.e., non-TDS removal) treatment, but some also use
TDS-removal technologies.
4.1.2 Discharging CWT Facilities
Some CWT facilities discharge treated wastewater either indirectly to a POTW or
directly to surface waters. As discussed in Section A.2.1.1, discharges from the CWT facility to
84 Examples of CWT facilities using this level of treatment are described in 191 DCN SGE00625; 178 DCN
SGE00635, 37 DCN SGE00245, 116 DCN SGE00481, and 89 DCN SGE00379.
85 Examples of CWT facilities using this level of treatment are described in 93 DCN SGE00476, 23 DCN
SGE00366, 19 DCN SGE00367, and 140 DCN SGE00374.
86 Zero discharge
DCN SGE00374).
86 Zero discharge CWT facilities may also evaporate the wastewater or send it to underground injection wells (205
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
the POTW are controlled by an Industrial User Agreement that must incorporate the pretreatment
standards set out in 40 C.F.R. part 437 and requirements set out in 40 C.F.R. part 403. Surface
water discharges from CWT facilities are controlled by NDPES permits that include pollutant
discharge limitations based on water-quality-based limitations and the technology-based
limitations set out in 40 C.F.R. part 437. The level of treatment typically depends on the
requirements in the NPDES permit, which may or may not include restrictions on TDS. Direct-
discharging CWT facilities use a mixture of TDS and non-TDS removal technologies. However,
new state regulations in Pennsylvania, for example, have led direct-discharging CWT facilities to
use more TDS removal technologies (43 DCN SGE00596).
4.1.3 CWT Facilities with Multiple Discharge Options
OQ
Some discharging CWT facilities may also recycle a portion of the treated wastewater.
Consequently, these types of CWT facilities may employ both non-TDS and TDS removal
technologies. One such facility is Eureka Resources in Williamsport, Pennsylvania. The Eureka
CWT facility holds a General Permit (WMGR123NC005)87 from PA DEP that includes limits88
for TDS (500 mg/L), chloride (25 mg/L), and radium-226 + radium-228 (5 pCi/L), among
others. The Eureka CWT facility uses a non-TDS removal technology (chemical treatment)
followed by a TDS removal technology (evaporation/condensation) (180 DCN SGE00300).
Operators may take a load of treated wastewater for reuse/recycle that the facility treated using
the non-TDS removal technology train or using the entire treatment train (both non-TDS and
TDS removal technologies). There are no permit limits that must to be met for wastewater that is
treated for reuse. The level of treatment is based on the operators' specifications.
4.2 Active CWT Facilities Accepting UOG Extraction Wastewater
To date, the EPA has identified 73 CWT facilities that have accepted or plan to accept
UOG extraction wastewater. Most of them accept only oil and gas wastewater, not wastewater
from other industries. Table D-6 shows the total number of CWT facilities, by state, that have
accepted or plan to accept UOG extraction wastewater. The table includes a breakdown by
treatment level and facility discharge type (described in Section D.4.1). The majority of these
facilities can treat between 87,000 and 1,200,000 gallons (2,100 and 29,000 barrels) per day (43
DCNSGE00596).89
To generate Table D-6, the EPA used information from state agencies (e.g., PA DEP
statewide waste reports), CWT facility websites, and news articles. The collected information is
documented in a separate memorandum titled Analysis of Centralized Waste Treatment (CWT)
Facilities Accepting UOG Extraction Wastewater (43 DCN SGE00596), which lists known
CWT facilities along with information such as permit number, location, treatment capacity, and
treatment level when available. Because few states keep comprehensive lists of CWT facilities,
87 More information available online at:
http://files.dep.state.pa.us/Waste/Bureau%20of%20Waste%20Mamgement/WasteMgtPortalFiles/SolidWaste/Resid
ual Waste/GP/WMGR123.pdf.
88 In addition to setting discharge limitations to the nearby POTW, Eureka's General Permit allows it to treat
wastewater for reuse purposes only, in which case there are no actual limits.
89 To exclude outliers, the EPA presents the 10th and 90th percentiles of reported treatment capacities at CWT
facilities.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-6 likely underestimates the number of CWT facilities accepting UOG extraction
90
wastewater.
Table D-6. Number, by State, of CWT Facilities That Have Accepted or Plan to Accept
UOG Extraction Wastewater
State
AR
CO
ND
OH
OK
PA
TX
WV
WY
UOG Formation(s)
Served
Fayetteville
Niobrara, Piceance
Basin
Bakken
Utica, Marcellus
Woodford
Utica, Marcellus
Eagle Ford, Barnett,
Granite Wash
Marcellus, Utica
Mesaverde and Lance
Total
Zero Discharge CWT
Facilities"
Non-TDS
Removal
2
3(1)
0
10(7)
2
23
1
4(2)
0
45
TDS
Removal
0
0
1(1)
0
0
7(3)
3
0
2
13
CWT Facilities That
Discharge to a Surface
Water or POTWa
Non-TDS
Removal
0
0
0
1
0
6
0
0
0
7
TDS
Removal
0
0
0
0
0
0
0
0
0
0
CWT Facilities with
Multiple Discharge
Options"
Non-TDS
Removal
0
0
0
0
0
0
0
1
0
1
TDS
Removal
1
0
0
0
0
3(1)
0
1
2
7
Total
Known
Facilities
3
3
1
11
2
39
4
6
4
73
Sources: 43 DCN SGE00596
a—Number of facilities includes facilities that have not yet opened but are under construction, pending permit
approval, or are in the planning stages. Facilities that are not accepting UOG extraction wastewater but plan to in the
future are noted parenthetically.
This information shows that CWT facilities have developed in regions of increasing oil
and gas production, especially in areas where capacities for other management practices are less
available (138 DCN SGE00139). To illustrate this, the EPA analyzed the number of active CWT
facilities available to Marcellus shale and Utica shale operators where there are few disposal
wells in some parts of the region.91 Figure D-4 illustrates how the eastern half of the
Appalachian basin contains many CWT facilities and few disposal wells and the western half
contains many disposal wells and few CWT facilities. Figure D-8 shows the trend over time of
active CWT facilities available to operators in the Marcellus and Utica shales,92 along with the
number of UOG wells drilled. The number of CWT facilities available to operators in the
Marcellus and Utica shales has increased with the number of wells drilled. The EPA observed a
similar trend in the Fayetteville shale formation in Arkansas. Although Arkansas has several
hundred active disposal wells, only 24 wells are located in the northern half of the state in close
proximity to Fayetteville shale wells (41 DCN SGE00736). As a result, the largest active
operator in the Fayetteville shale has constructed three CWT facilities. The EPA anticipates that
90The information in Table D-6 is current as of 2013; it is possible that since 2013 some listed CWT facilities have
closed and/or some CWT facilities not listed have begun operation.
91
This analysis included Pennsylvania, West Virginia, and Ohio.
! The Marcellus and Utica shale formations are in the Appalachian basin.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
more CWT facilities will become available near UOG formations where access to disposal wells
is limited as additional UOG wells are drilled.
60
50
10,000
—*— Cumulative £ of Active CWT Facilities
Cumulative ff of Pending CWT Facilities
-•-Cumulative £ of Marcellus & Utica Wells Drilled
•fi
2006
2008
2010
2012
2014
Year
Sources: 43 DCN SGE00596
Figure D-8. Number of Known Active CWT Facilities over Time in the Marcellus and
Utica Shale Formations
5 DISCHARGE TO POTWs
In locations where disposal wells and CWT facilities are limited or transportation
distances are a factor, operators have, in the past, managed UOG extraction wastewater by
discharge to POTWs. This practice can be problematic because POTWs do not use technologies
that can remove some UOG extraction wastewater constituents (e.g., TDS). Also, constituents in
UOG extraction wastewater such as TDS may interfere with POTW operations and may increase
pollutant loads in receiving streams to the detriment of downstream water use (80 DCN
SGE00286; 109 DCN SGE00345; 139 DCN SGE00579; 82 DCN SGE00531; 226 DCN
SGE00633; 77 DCN SGE01077).93
93 GWPC, 2014 (77 DCN SGE01077) states, "For a POTW to accept a waste stream for treatment, the facility must
show that the accepted waste will not interfere with the treatment process or pass through the facility untreated.
Since POTWs are typically not designed to treat fluids with constituents found in produced water (e.g., high TDS
concentrations, hydrocarbons, etc.), problems have occurred as a result of produced water being sent to POTWs
including impacts to the treatment process or the discharge of constituents at levels detrimental to the receiving
water body."
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
This section provides an overview of typical treatment processes used at POTWs, a
discussion of how constituents commonly found in UOG extraction wastewater interact with
POTWs (including examples of POTWs that have been used to manage UOG extraction
wastewater), a review of POTWs that have accepted UOG extraction wastewater, and the current
status of UOG extraction wastewater discharges to POTWs.
5.1 POTW Background and Treatment Levels
40 C.F.R. part 403.3(q) defines a POTW as "a treatment works as defined by section 212
of the [Clean Water] Act,94 which is owned by a State or municipality." POTWs are designed to
treat residential, commercial, and industrial wastewater, focusing on the removal of suspended
solids and dissolved organic constituents. Table D-7 presents concentrations of weak, moderate,
and strong domestic wastewater as would be typically experienced by a POTW (i.e., influent).
Table D-7. Typical Composition of Untreated Domestic Wastewater
Constituent
TDS
COD
TSS
BOD5
TOC
Oil and grease
Chlorides
Nitrogen, total
Sulfate
Phosphorus, total
Nitrates
Nitrites
Concentrations (mg/L)
Weak
270
250
120
110
80
50
30
20
20
4
0
0
Moderate
500
430
210
190
140
90
50
40
30
7
0
0
Strong
860
800
400
350
260
100
90
70
50
12
0
0
Source: 119 DCN SGE00167
Abbreviation: mg/L—milligrams per liter
Typical treatment processes used at POTWs are categorized into the following levels:
• Primary treatment, capable of removing some suspended solids and organic matter
from influent wastewater using unit operations such as screening and clarification.
• Secondary treatment, capable of removing additional suspended solids and
biodegradable organic matter from influent wastewater using biological treatment
processes, such as activated sludge and trickling filters. Secondary treatment is
sometimes followed by chlorination or ultraviolet (UV) disinfection to reduce
microbial pathogens.
Section 212 of the CWA defines the term "treatment works" as "any devices and systems used in the storage,
treatment, recycling, and reclamation of municipal sewage or industrial wastes of a liquid nature."
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
• Tertiary (advanced) treatment, capable of removing other pollutants, such as
nutrients, not removed in secondary treatment using processes such as
nitrification/denitrification and activated carbon adsorption (119 DCN SGE00167).
Figure D-9 shows a typical process flow diagram for a POTW. The processes shown
include primary treatment (screen, grit chamber, primary clarifier), secondary treatment
(trickling filter, aeration, secondary clarifier), and disinfection (chlorine). The diagram also
shows sludge treatment (gravity thickening, digestion, filter press) before use/disposal (e.g., land
application).
Raw Waste water
A
Diagram A
Bar
Screen
and Grit
Chamber
High Rate
Sludge
Diqester
C ^ S D
Land
Application
Source: 165 DCN SGE00602
Figure D-9. Typical Process Flow Diagram at a POTW
In general, the average POTW in the United States has primary and secondary treatment.
In addition to treated wastewater, POTW treatment processes produce residual solids (sludge),
including biosolids generated during biological treatment and other suspended material removed
in clarifiers. Most POTWs apply additional treatment to the sludge, typically gravity thickening
followed by stabilization (e.g., anaerobic digestion) and dewatering (e.g., filter press). After this
additional treatment, most sludge is either put to a beneficial use (e.g., land application, soil
enrichment) or disposed of in a landfill or incinerator (161 DCN SGE00599).
Table D-8 shows typical removal percentages for various constituents. As discussed,
removal rates for suspended solids are high (90 percent for TSS) and removal rates for metals
and salts are low (6 percent for cobalt, 8 percent for TDS).
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-8. Typical Percent Removal Capabilities from POTWs with Secondary Treatment
Constituent
Aluminum
Ammonia as nitrogen
Antimony
Arsenic
Barium
Beryllium
BOD5
Boron
Cadmium
Calcium
Carbon disulfide
Chloride
Chlorobenzene
Chloroform
Chromium
Cobalt
COD
Copper
Cyanide
Ethylbenzene
Fluoride
Iron
Lead
Magnesium
Manganese
POTW Percent
Removal (%)
91
39
67
66
16
72
89
30
90
9
84
57
96
73
80
6
81
84
70
94
61
82
77
14
36
Constituent
Mercury
Molybdenum
Naphthalene
Nickel
Oil and grease (as HEM)
Phenol
Phenolics, total recoverable
Phosphorus, total
Pyridine
Selenium
Silver
Sodium
Sulfate
Sulfide
TDS
Thallium
Tin
Titanium
TOC
Toluene
Total petroleum hydrocarbons
TSS
Vanadium
Xylenes (m+p, m, o+p, o)
Zinc
POTW Percent
Removal (%)
72
19
95
51
86
95
57
57
95
34
88
3
85
57
8
72
42
92
70
96
57
90
10
65 to 95
79
Source: 164 DCN SGE00600
Note: 164 DCN SGE00600 references data from the November 5, 1999, updated 50-POTW study and the RREL
database compiled for the CWT effluent guidelines.
Table D-9 shows the breakdown of U.S. POTWs categorized according to their level of
treatment. As of 2008, secondary treatment was the most common level of treatment at POTWs.
Table D-9. U.S. POTWs by Treatment Level in 2008
Treatment Level
Less than secondary (e.g., primary)
Secondary
Greater than secondary (e.g., tertiary, advanced)
No discharge
Partial treatment3
Total
Percent of
Facilities (%)
0.2
49.4
34.3
15.2
0.8
99.9
Number of
Facilities
30
7,302
5,071
2,251
115
14,769
Design Capacity
(MGD)
546
17,765
23,710
2,557
287
44,866
Source: 166 DCN SGE00603
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
a—These facilities provide some treatment to wastewater and discharge their effluent to other wastewater facilities
for further treatment and discharge.
Abbreviation: MOD—million gallons per day
5.2 History of POTW Acceptance of UOG Extraction Wastewater
As operators began extracting oil and gas from unconventional formations, UOG
operators discharged wastewater to POTWs in some cases (80 DCN SGE00286; 109 DCN
SGE00345; 139 DCN SGE00579).95 The EPA located the most comprehensive data about this
practice in Pennsylvania. Therefore, this subsection primarily discusses data from PA DEP,
though it also includes discussions about a few POTWs in West Virginia and New York. The PA
DEP data indicate that the majority of UOG operators in Pennsylvania who decided to discharge
to POTWs did so by 200896 (127 DCN SGE00188). To identify POTWs that accepted
wastewater from UOG operations,97 the EPA reviewed the following sources:
• Notes from calls with regional and state pretreatment program coordinators (182
DCN SGE00742, 192 DCN SGE00743)
• Notes from an EPA-state implementation pilot project with the Environmental
Council of the States in coordination with the Association of Clean Water
Administrators (196 DCN SGE00762)
• EPA Region 3's website (174 DCN SGE00368)
• Site visits, conference calls, and meetings with industry representatives (188 DCN
SGE00613; 38 DCN SGE00521), UOG operators (191 DCN SGE00625; 178 DCN
SGE00635; 179 DCN SGE00275; 190 DCN SGE00280), CWT facilities (181 DCN
SGE00299; 180 DCN SGE00300; 37 DCN SGE00245; 36 DCN SGE00244), and
Native American tribal groups (202 DCN SGE00785).
• PA DEP's statewide waste report data98 (127 DCN SGE00188; 46 DCN SGE00739)
• The U.S. DOE's 2010 Water Management Technologies Used by Marcellus Shale
Gas Producers report (212 DCN SGE00011)
• Publicly available data sources identified through Internet searches
The EPA compiled and analyzed much of these existing data in a separate document, Publicly
Owned Treatment Works (POTW) Memorandum for the Technical Development Document
(TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction
(52 DCN SGE00929). This memorandum is referenced throughout Section D.5.
95 EPA acknowledges that COG operators are still using POTWs as a viable option for disposal of COG wastewater.
96 EPA did not identify any information indicating when POTWs in New York began accepting of UOG extraction
wastewater. EPA also could not definitely determine when UOG operators in Pennsylvania began discharging UOG
extraction wastewater at POTWs because the 2007 PA DEP Waste Report data are incomplete.
97 EPA could not determine the date when POTWs began accepting UOG wastewater in all instances. The EPA has
documentation that all POTWs in Pennsylvania stopped accepting UOG extraction wastewater by the end of 2011.
98 PA DEP's waste report data provide wastewater volumes by well over time and management/disposal information
as it was reported by the oil and gas well operator to PA DEP. ERG's memorandum titled Analysis of Pennsylvania
Department of Environmental Protection's (PA DEP) Oil and Gas Waste Reports provides more detail (46 DCN
SGE00739).
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
The EPA identified POTWs that, at one time, accepted wastewater from UOG operators
generated by Marcellus shale wells. Table D-10 presents information about POTWs that have
accepted UOG extraction wastewater directly from onshore UOG operators.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-10. POTWs That Accepted UOG Extraction Wastewater from Onshore UOG Operators
Facility Name
Allegheny Valley Joint Sewer
Authority
Altoona Water Authority — Easterly
WWTP
Belle Vernon Borough
Borough of Jersey Shore
Brownsville Municipal Authority
California Borough
Charleroi Borough
City of Auburn
City of Johnstown Redevelopment
Authority — Dornick Point
City of McKeesport
City of Watertown
Clairton Municipal Authority
Clearfield Municipal Authority
Dravosburg
Lock Haven City STP
Mon Valley Sewage Authority
Moshannon Valley Authority STP
Reynoldsville Sewer Authority
Ridgway Borough
Waynesburg Borough Water System
NPDES
Permit No.
PA0026255
PA0027014
PA0092355
PA0028665
PA0022306
PA0022241
PA0026891
NY0021903
PA0026034
PA0026913
SPDES NY
002 5984
PA0026824
PA0026310
PA0028401
PA0025933
PA0026158
PA0037966
PA0028207
PA0023213
PA0020613
City
Cheswick
Altoona
Belle Vernon
Jersey Shore
Brownsville
California
Charleroi
Auburn
Johnstown
McKeesport
Watertown
Clairton
Clearfield
Dravosburg
Lock Haven
Donora
Rush Township
Reynoldsville
Ridgway
Waynesburg
State
PA
PA
PA
PA
PA
PA
PA
NY
PA
PA
NY
PA
PA
PA
PA
PA
PA
PA
PA
PA
POTW Currently Accepting UOG
Wastewater from UOG Operator?
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
No
Year POTW Stopped Accepting UOG
Wastewater from UOG Operator
2008
2011
2009
2010
2008
2009
2008
2008
2010
2011
2010
2011
2009
2008
2008
2008
2009
2011
2011
2008
Source: 52 DCN SGE00929
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Based on data collected through June 2014, the EPA concluded that none of the POTWs
listed in Table D-10 currently accept wastewater directly from UOG operations. That is, no UOG
extraction wastewater is currently being managed by discharging to any of the POTWs in this
table. This is, in large part, a result of UOG operators' compliance with PA DEP's April 2011
request that they stop discharging UOG extraction wastewater to POTWs (see Section A.2.2).
PA DEP data indicate that UOG operators in Pennsylvania stopped sending their waste to
POTWs in 2011 (127 DCN SGE00188). Furthermore, the EPA has not been able to identify any
POTW in any state that is accepting UOG extraction wastewater directly from an operator. In
addition, the EPA collected data about UOG operations on tribal reservations, UOG operators
that are affiliated with Indian tribes, and POTWs owned or operated by tribes that may accept
industrial wastewater (202 DCN SGE00785). According to this information, there are no tribes
operating UOG wells that discharge wastewater to POTWs, nor are there any tribes that own or
operate POTWs that accept UOG extraction wastewater. As such, the EPA concludes that
operators have determined that discharge to a POTW is not a necessary and/or appropriate option
for managing UOG extraction wastewater.
The EPA is aware of a few cases where UOG operators discharge wastewater to CWT
facilities for treatment and those CWT facilities discharge to POTWs. As explained in Section
A.2.1.2, such discharges are not subject to the ELGs for the oil and gas extraction category
which is the subject of the proposed rule. Rather, discharges to POTWs from CWT facilities are
subject to ELGs for the Centralized Waste Treatment Category (40 C.F.R. part 437).
The EPA reviewed PA DEP statewide waste reports (46 DCN SGE00739) and discharge
monitoring report (DMR) data (175 DCN SGE00608) to identify the total volumes of UOG
extraction wastewater and average total influent wastewater for each POTW. Using these data
sources, the EPA calculated the maximum annual average daily" percentage of UOG extraction
wastewater accepted by the POTW as shown in Table D-ll. The EPA found that discharges of
UOG extraction wastewater from UOG operators to POTWs peaked in 2008 and the last known
discharge was in 2011.
Table D-ll also presents the year in which the maximum annual average daily volume
occurred and the corresponding UOG extraction wastewater volume being accepted by the
POTW during that year. The contribution of UOG extraction wastewater out of the total volume
of wastewater treated at the POTW is typically a small percentage (less than 1 percent).
However, based on the data presented in Table D-ll, the contribution of UOG extraction
wastewater was much higher (e.g., up to 21 percent) for some POTWs for some years.
99 PA DEP waste reports provided the total volume of UOG extraction wastewater delivered to the POTW each year.
The EPA divided the annual volume by 365 to calculate the annual average daily flow of UOG extraction
wastewater accepted at the POTW.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-ll. Percentage of Total POTW Influent Wastewater Composed of UOG
Extraction Wastewater at POTWs Accepting Wastewater from UOG Operators
POTW Name
Belle Vernon Borough
California Borough
Charleroi Borough
Waynesburg Borough
Water System
Mon Valley Sewage
Authority
City of Johnstown
Redevelopment
Authority — Dornick Point
Brownsville Municipal
Authority
City of Auburn
Borough of Jersey Shore
Allegheny Valley Joint
Sewer Authority
Ridgway Borough
Dravosburg
Clairton Municipal
Authority
Moshannon Valley
Authority STP
Reynoldsville Sewer
Authority
City of McKeesport
Bellefonte Water
Treatment Plant
Lock Haven City STP
Altoona Water Authority
NPDES
Permit No.
PA0092355
PA0022241
PA0026891
PA0020613
PA0026158
PA0026034
PA0022306
NY0021903
PA0028665
PA0026255
PA0023213
PA0028401
PA0026824
PA0037966
PA0028207
PA0026913
PA0020486
PA0025933
PA0027014
Maximum
Annual
Average Daily
UOG
Extraction
Wastewater
Volume
Accepted
(gpd)
93,000
84,000
180,000
56,000
67,000
130,000
9,400
1,800
6,000
30,000
4,500
1,300
12,000
3,400
930
11,000
1,400
1,800
2,500
Corresponding
Total Annual
Average Daily
Influent Flow to
POTW (MGD)a
0.44
0.60
1.74
0.58
3.47
9.47
0.88
0.20
0.69
4.30
0.97
0.33
4.15
2.29
0.80
16.25
1.99
2.84
6.86
Maximum
Annual
Average Daily
UOG
Extraction
Wastewater
Percent of
POTW
Influent (%)
21b
14
10
9.7
1.9
1.4
1.1
0.91
0.88
0.69
0.47
0.39
0.30
0.15
0.12
0.07
0.07
0.06
0.04
Year of
Maximum
Annual Average
Daily UOG
Extraction
Wastewater
Volume
2008
2008
2008
2008
2008
2008
2008
2008
2008
2008
2010
2008
2009
2008
2010
2009
2008
2008
2011
Sources: 52 DCN SGE00929
a—This is the total influent wastewater flow to the POTW (domestic sewage and UOG extraction wastewater) in
the year associated with the maximum UOG extraction wastewater volume received by the POTW.
b—The average total flow through the POTW (MOD) in 2008 was calculated using the average of four months of
available data (September 2008 through December 2008).
Abbreviations: gpd—gallons per day; MOD—million gallons per day
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
5.3 How UOG Extraction Wastewater Constituents Interact with POTWs
POTWs are likely effective in treating only some of the pollutants in UOG extraction
wastewater. Most POTWs are designed to primarily treat domestic wastewater. They typically
provide at least secondary-level treatment and, thus, are designed to remove suspended solids
and organic material. However, secondary treatment technologies are not designed to treat the
high concentrations of TDS, radioactive constituents, metals, chlorides, sulfates, and other
dissolved inorganic constituents found in UOG extraction wastewater.100 Because they are not
typical of POTW influent wastewater, UOG extraction wastewater constituents:
• May be discharged, untreated, from the POTW to the receiving stream
• May disrupt the operation of the POTW (e.g., by exceeding permit limits for BOD5
or TSS in discharges, by inhibiting sludge settling)
• May accumulate in sludge, limiting its use
• May facilitate the formation of disinfection byproducts (DBFs)
Where available, the EPA reviewed the following information related to POTWs that
have accepted UOG extraction wastewater:
• Local limit evaluations completed by POTWs' pretreatment program coordinators
• Technical evaluations of the impact of oil and gas wastewater pollutants on POTW
unit processes completed in response to Administrative Orders (AOs)101 issued to a
number of POTWs by PA DEP
• Pass through analyses completed by POTWs
• DMR data from times when POTWs accepted UOG extraction wastewater
In many cases, POTWs that accepted UOG extraction wastewater also accepted COG
extraction wastewater. Because the UOG extraction wastewater constituents that are discussed in
this chapter are also present in COG extraction wastewater (205 DCN SGE00956; 18 DCN
SGE00966), information and studies on the treatability of these constituents by POTWs (or their
impacts on POTWs) are similarly relevant when those POTWs are accepting only COG
extraction wastewater and/or a combination of COG and UOG extraction wastewater. In most of
the case studies presented in this chapter, the POTWs that were accepting UOG extraction
wastewater were also accepting COG wastewater.
The EPA also reviewed common textbooks on wastewater treatment technology
effectiveness. These textbooks indicated that POTWs would likely be ineffective for treatment of
certain pollutants in UOG extraction wastewater, such as TDS and many pollutants that
100 Some POTWs provide tertiary treatment, which removes additional nutrients as well as constituents targeted for
removal using secondary treatment. Similar to secondary treatment, tertiary treatment processes are not designed to
treat the high concentrations of TDS, radioactive constituents, metals, chlorides, sulfates, and other dissolved
inorganic constituents found in UOG extraction wastewater.
101 PA DEP issued AOs to many POTWs in Pennsylvania that were accepting or suspected to begin accepting
wastewater from UOG operations.
Til
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
contribute to IDS (164 DCN SGE00600). The EPA used all of this information to evaluate
treatment effectiveness at POTWs, primarily for IDS.
In addition to information about POTWs accepting oil and gas extraction wastewater, the
EPA collected available information about other discharges to POTWs from industrial sources
containing pollutants found in UOG extraction wastewater. The case studies presented in
Sections D.5.3.1.2 and D.5.3.2.2 involve discharges to POTWs from CWT facilities that
accepted oil and gas extraction wastewater. To the extent that a CWT facility discharges to a
POTW and also lacks technologies that remove some oil and gas extraction pollutants (e.g.,
TDS), information on resulting POTW effluent concentrations (and/or inhibition) can be used as
a proxy for UOG extraction operator discharges to a POTW.
Table D-12 summarizes the POTW studies and analyses that are presented in Section
D.5.3.1 and Section D.5.3.2. Section D.5.3.1 discusses the potential for UOG pollutants to be
discharged, untreated, from POTWs. Section D.5.3.2 discusses the potential for UOG wastewater
pollutants to cause or contribute to inhibition and disruption at POTWs.
Table D-12. Summary of Studies About POTWs Receiving Oil and Gas Extraction
Wastewater Pollutants
POTW
Summary of Study Findings
POTWs Accepting Wastewater from Oil and Gas Operators
|Clairton,PA,POTW
McKeesport, PA, POTW
Ridgway, PA, POTW
Charleroi, PA, POTW
Clarksburg, WV, POTW
Johnstown, PA, POTW
California, PA, POTW
Waynesburg, PA, POTW
Treatment system influent and effluent samples show minimal or no TDS and chloride
removals. See SectionD.5.3.1.1.
Treatment system influent and effluent samples show less than 10% removal of TDS,
chloride, sulfate, and magnesium at the POTW. See SectionD.5.3.1.1.
TDS and chloride concentrations in effluent from the POTW were highest when the
POTW was accepting the greatest volume of oil and gas extraction wastewater
(including UOG extraction wastewater). Local limits analysis assumed zero percent
removal of TDS, chloride, and sulfate at the POTW. See SectionD.5.3.1.1.
Treatment system influent and effluent samples show minimal or no TDS removal.
The POTW rejects influent oil and gas wastewater with TDS greater than 30,000 mg/L
and/or chloride greater than 15,000 mg/L. See SectionD.5.3.1.1.
Higher concentrations of TSS and BOD5 in POTW effluent when the POTW was
accepting UOG extraction wastewater. See Section D. 5. 3. 2.1.
The POTW accepted UOG extraction wastewater, but chlorides were not removed,
merely diluted. It also exceeded the desired effluent chloride concentrations during dry
weather flows. See SectionD.5.3.1.1.
Higher concentrations of TSS and BOD5 in POTW effluent, including 52 permit limit
exceedances, when the POTW was accepting UOG extraction wastewater. See Section
D.5.3.2.1.
Higher concentrations of TSS and BOD5 in POTW effluent, including four permit
limit exceedances, when the POTW was accepting UOG extraction wastewater. See
Section D.5.3.2.1.
High-salinity UOG produced water impacted biological growth in trickling filter. See
Section D.5.3.2.1.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-12. Summary of Studies About POTWs Receiving Oil and Gas Extraction
Wastewater Pollutants
POTW
Summary of Study Findings
POTWs Accepting Wastewater Containing UOG Extraction Wastewater Pollutants from Other Industrial
Sources (e.g., CWT Facilities)
Franklin, PA, POTW
The Franklin POTW received industrial discharges from the Tri-County CWT facility
(which received oil and gas extraction wastewater). The CWT facility targeted removal
of TSS and oil and grease by filtration, flocculation, and skimming.
TDS and chloride concentrations in effluent from the POTW were higher when the
POTW was accepting industrial wastewater from the Tri-County CWT facility and
decreased after it stopped accepting wastewater from this CWT facility. See Section
D.5.3.1.2.
Wheeling, WV, POTW
The Wheeling POTW received oil and gas extraction wastewater from operators as
well as industrial wastewater discharges from the Liquid Asset Disposal (LAD) CWT
facility. The LAD CWT facility uses ultra-filtration, ozonation, and reverse osmosis to
target the removal of chlorides prior to discharge to the Wheeling POTW.
The POTW experienced higher concentrations of chloride in POTW effluent while
accepting UOG extraction wastewater from UOG operators and from the LAD CWT
facility (which receives oil and gas extraction wastewater). See Section D.5.3.1.2.
The POTW experienced interference with biological treatment from accepting UOG
extraction wastewater pollutants via the LAD CWT facility's industrial discharge. The
POTW also experienced an upset that required the introduction of a "seed" sludge to
maintain microbial activity in treatment processes. See Section D.5.3.2.2.
Warren, OH, POTW
The Warren POTW receives industrial wastewater discharges from the Patriot CWT
facility. The Patriot CWT facility uses primary treatment processes (e.g., settlement
tanks, clarifier tanks) to target the removal of suspended solids and metals from UOG
extraction wastewater before discharge to the Warren POTW.
Influent and effluent TDS and chloride concentrations at the Warren POTW show
minimal or no TDS or chloride removals. See SectionD.5.3.1.2.
Brockway, PA, POTW
The Brockway POTW received natural-gas-related wastewater treated by the Dannie
Energy Corporation CWT facility.102
The POTW experienced higher concentrations of TDS in POTW effluent while
accepting industrial discharges from the CWT facility containing oil and gas extraction
wastewater pollutants. See SectionD.5.3.1.2.
The POTW experienced scum formation on clarifiers as well as increased sludge
generation and high concentrations of barium in the sludge, while treating industrial
discharges from the CWT facility. See Section D.5.3.2.2.
New Castle, PA, POTW
The New Castle POTW received industrial wastewater from the Advanced Waste
Services CWT facility (which treats oil and gas wastewater). The CWT facility uses
the following treatment processes: solids settling, surface oil skimming, pH
adjustment, and (occasional) flocculation.
The POTW experienced numerous effluent TSS permit limit exceedances while
accepting industrial discharges from the CWT facility. The CWT facility discharge
was associated with adverse impacts on sludge settling in final clarifiers at the POTW.
See SectionD.5.3.2.2.
EPA could not find information about the treatment processes used by the Dannie Energy Corporation CWT
facility.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
5.3.1 UOG Extraction Wastewater Constituents Discharged Untreated from POTWs
As described in Section D.5.3, the EPA reviewed studies and analyses relevant to
POTWs accepting wastewater containing pollutants found in UOG extraction wastewater.
Consistent with wastewater treatment literature, the POTWs described in these studies
demonstrated that some UOG extraction wastewater pollutants are not removed by POTWs and
are discharged untreated to receiving streams.
5.3.1.1 Case Studies of POTWs Accepting Oil and Gas Extraction Wastewater
Clairton, PA, POTW
The Clairton POTW discharges to Peters Creek, which flows into the Monongahela River
and treats influent wastewater using screening and grit removal, comminutors (i.e., grinders),103
aeration basins, clarifiers, activated sludge, aerobic digestion, and chlorine disinfection. The
Clairton POTW is permitted to treat a maximum of 6 MGD (107 DCN SGE00758).
On October 23, 2008, PA DEP issued an AO to the Clairton POTW that established
requirements for its acceptance of oil and gas wastewater. The AO required the Clairton POTW
to restrict the volume of oil and gas wastewater it accepts to a flow rate no greater than 1 percent
of the average daily flow. The AO also required the POTW to evaluate the potential impacts of
oil and gas production wastewater on its treatment processes. The technical evaluation noted
(107DCNSGE00758):
The results of the samples taken and analyzed through the CMA [Clairton Municipal
Authority] WWTP indicate that there is little to no reduction in concentration ofTDSand
chlorides through the plant processes. This is not unexpected as conventional sewage
treatment facilities are not designed to remove dissolved constituents such as TDS and
chlorides.
Figure D-10 shows the results from the 24-hour composite sampling that occurred over
five days in December 2008. According to PA DEP data (46 DCN SGE00739), in 2008, the
Clairton POTW was accepting oil and gas wastewater amounting to an average of 0.05 percent
of the POTW flow. Looking at the average measured concentrations, the results indicate little or
no removal of TDS or chloride.
103 A comminutor is a machine that reduces the particle size of wastewater solids using a cutting device.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
I
2,500
2,000 —:=:
1,500
1,000
500
o
IDS Cl IDS Cl IDS Cl IDS Cl IDS Cl IDS Cl
Sources: 52 DCN SGE00929
Note: The data presented in this figure are based on five 24-hour composite samples taken from
December 8, 2008, through December 12, 2008.
Figure D-10. Clairton POTW: Technical Evaluation of Treatment Processes' Ability to
Remove Chlorides and TDS
Clairton POTW's consultant completed a pass through analysis in August 2009 (137
DCN SGE00748). Having collected two sets of influent concentration data from two different oil
and gas wells, the consultant stated that the O&G Well No. 2 wastewater "was not characteristic
of the oil and gas wastewater routinely accepted by the CMA POTW." Therefore, the EPA only
included the wastewater characteristic data for O&G Well No. 1, as reported in the pass through
analysis (see Table D-13). The pass through analysis assumes zero percent removal of TDS at
the POTW and concludes that (137 DCN SGE00748):
The result of the mass balance analyses clearly indicates that TDS is untreated resulting
in a "pass-through" to receiving waters... The hypothetical mass balance
review... indicates that if higher concentrations of TDS are introduced into the POTW,
the concentration and loading of TDS to the receiving waters increases proportionally.
Influent after
Grit Removal
and Screening
After Pre-
Aeration Tanks
—
n
y
After Primary
Settling Tanks
— i
After Activated
Sludge
1
1
After Final
Settling Tanks
After Chlorine
Disinfection
Maximum
Average
Minimum
i 1
1
1
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-13. Clairton Influent Oil and Gas Extraction Wastewater
Characteristics
Parameter
Barium
Calcium
Chloride
Magnesium
Sodium
TDS
TSS
Wastewater Concentrations
(mg/L)
O&GWellNo. 1
294
3,060
44,700
1,210
84,500
76,000
1,600
Source: 137 DCN SGE00748
Abbreviation: mg/L—milligrams per liter
McKeesport, PA, POTW
The McKeesport POTW discharges to the Monongahela River and treats wastewater
using screening and grit removal, aeration, clarification, activated sludge, aerobic digestion, and
chlorine disinfection (108 DCN SGE00745). The McKeesport POTW began accepting COG
wastewater in 2008 and UOG extraction wastewater in 2009. The POTW stopped accepting both
COG and UOG extraction wastewater in December 2011 (46 DCN SGE00739).
On October 23, 2008, PA DEP issued an AO to the McKeesport POTW that allowed it to
accept oil and gas wastewater in amounts no greater than 1 percent of its average daily flow,
among other requirements. The AO also required the POTW to evaluate the potential impacts of
oil and gas production wastewater on its treatment processes. The POTW conducted this
technical evaluation in November 2008. According to PA DEP data (46 DCN SGE00739), in
2008, the McKeesport POTW was accepting only COG wastewater. The evaluation (106 DCN
SGE00757) noted:
The results of the samples taken and analyzed through the MACM [Municipal Authority
of the City of McKeesport] WWTP indicate that there is no reduction in concentration of
TDS and chlorides through the plant processes. This is not unexpected as conventional
sewage treatment facilities are not designed to remove dissolved constituents such as
TDS and chlorides.
Figure D-ll shows the results from 24-hour composite sampling over seven days in
November 2008. The results indicate no removal of TDS or chloride. According to the manifests
included in the technical evaluation (106 DCN SGE00757), McKeesport treated trucked
wastewater from conventional wells during the seven-day sampling period. These wastewater
sources are summarized in Table D-14, below.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
700
600
"oil
o
•3
o
U
500
400
300
200
100
0
Influent
Grit
Primary Effluent
Effluent
IDS Cl
Sources: 52 DCN SGE00929
IDS
Cl
IDS
Cl
IDS
Cl
Note: The data presented in this figure are based on seven 24-hour composite samples taken from November 1,
2008, through November 7, 2008.
Figure D-ll. McKeesport POTW: Technical Evaluation of Treatment Processes' Ability to
Remove Chlorides and TDS
Table D-14. Trucked COG Extraction Wastewater Treated at McKeesport POTW from
November 1 Through 7, 2008
Date
November 3, 2008
November 4, 2008
November 6, 2008
November 6, 2008
November 7, 2008
Waste Type"
Brine
Flow-back
Flow-back
Frac
Frac
Volume (gallons)
3,780
3,780
3,780
4,620
4,620
Chlorides (mg/L)
155,000
145,000
155,000
20,000
20,000
Chlorides (Ibs)
4,886
4,571
4,886
771
771
Source: 108 DCN SGE00745
a—According to data from the technical evaluation, some waste streams were referred to as "frac" and "flow-back,"
indicating that the conventional wells were hydraulically fractured.
Abbreviations: mg/L—milligrams per liter; Ibs—pounds
McKeesport POTW's consultant completed a headworks loading analysis in March 2011
(108 DCN SGE00745). As part of the analysis, the consultant completed monthly sampling of
the influent and effluent of the POTW from February 2010 through January 2011 and determined
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
the average removal percentages based on the sampling results. During the time of sampling, a
combination of UOG and COG wastewater contributed no more than 1 percent of the average
daily flow and municipal wastewater made up the remaining influent to the McKeesport POTW.
Table D-15 presents the percent removals calculated during this analysis and shows that the
POTW removed less than 7 percent of the influent TDS and less than 5 percent of the influent
chloride. Effluent TDS concentrations ranged from 600 to 1,500 mg/L while the facility accepted
both UOG and COG wastewater during the sampling period (108 DCN SGE00745).
Table D-15. McKeesport POTW Removal Rates Calculated for Local Limits Analysis
Parameter
Sulfate
Chloride
TDS
Magnesium
Strontium
Bromide
Barium
Removal Rates (%)
3.94
4.44
6.43
6.62
18.47
26.99
71.64
Source: 108 DCN SGE00745
Note: The data presented in this table are based on timed composite samples obtained once a month for 12 months
from February 2010 through January 2011.
A 2013 study by Ferrar et al. (71 DCN SGE00525) analyzed constituents in effluent
wastewater discharged from two POTWs in Pennsylvania, first while the POTWs accepted
industrial discharges containing UOG extraction wastewater pollutants (either from a CWT
facility or from a UOG operator) and again after the POTWs stopped accepting those industrial
discharges. The study included effluent sampling at the McKeesport POTW in 2010 while the
POTW was accepting UOG extraction wastewater. The study specifically reported that the
facility was accepting UOG extraction wastewater during the sampling but did not mention COG
wastewater. Based on PA DEP data, the EPA is aware that the POTW accepted both UOG and
COG wastewater in 2010; however, details were not available concerning whether COG
wastewater was accepted on the specific days of the sampling. The UOG extraction wastewater,
received from operators via tanker trucks, was stored in holding tanks, then mixed with
municipal wastewater in the primary clarifier. The study sampled POTW effluent in October
2010, when the POTW was accepting UOG extraction wastewater and again in December 2011,
after the POTW had stopped accepting COG and UOG extraction wastewater.104 The study also
collected one sample in November 2010 of UOG extraction wastewater before it was mixed with
the municipal influent105 (see Table D-16).
On October 19, 2010, when Ferrar et al. collected their POTW effluent sample, they
reported that the McKeesport POTW treated 13,020 gallons of UOG extraction wastewater, and
the average daily flow of the POTW was 9.6 MGD, indicating that the UOG extraction
104 The PA DEP waste reports data (46 DCN SGE00739) show that the McKeesport POTW stopped accepted COG
and UOG wastewater after 2011.
105 Note that the one-time sample of influent UOG extraction wastewater was not collected at the same time as either
of the effluent sampling events.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
wastewater accounted for 0.14 percent of the total influent.106 The remaining influent wastewater
consisted of municipal wastewater typically treated by the POTW (see Table D-7 for typical
constituent concentrations in municipal wastewater).
Table D-17 shows the range and mean effluent concentrations, as measured by Ferrar et
al., at the McKeesport POTW while they were accepting UOG extraction wastewater and after
they had stopped accepting UOG extraction wastewater. As noted above, the study reported that
the McKeesport POTW accepted an average daily flow of 9.6 MGD during the October 2010
sampling event. However, they did not report the average daily flow during the December 2011
sampling event. Although they reported that the facility was accepting UOG extraction
wastewater on the first effluent sampling date (October 19, 2010), sampling data for that influent
UOG extraction wastewater (like the data presented in Table D-16) were not available. Therefore
it is not possible to know whether the data presented in Table D-16 are representative of the
UOG extraction wastewater influent on the date of the effluent sampling presented in Table
D-17. As discussed in Section C.3, UOG extraction wastewater characteristics vary over time
and from well to well.
Table D-16. Constituent Concentrations in UOG Extraction Wastewater Treated at the
McKeesport POTW Before Mixing with Other Influent Wastewater
Analyte"
Barium
Calcium
Magnesium
Strontium
Bromide
Chloride
Sulfate
TDS
Concentrations in UOG Extraction Wastewater
Treated at McKeesport POTW (mg/L)b
106
1,690
203
324
151
17,000
53.1
24,200
Source: 71 DCN SGE00525
a—Organic analytes were not detected in samples.
b—Sample date: 11/10/2010. Reported values are based on only one sample taken for each analyte. Samples were
collected from a UOG extraction wastewater holding tank before mixture and dilution with influent municipal
wastewater.
Abbreviation: mg/L—milligrams per liter
106 Ferrar et al. (71 DCN SGE00525) noted that since the total volume of UOG wastewater was released at one time,
the actual dilution might have been 0.81 percent UOG wastewater in the effluent when it was discharged (8-12
hours later).
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-17. McKeesport POTW Effluent Concentrations With and Without UOG
Extraction Wastewater
Analyte"
Barium
Calciumd
Magnesium"1
Strontium
Bromide
Chloride
Sulfate
TDS
Effluent Concentrations Measured While
POTW Was Accepting UOG Extraction
Wastewater (mg/L)b
Mean
0.55
50.3
10.3
1.63
0.600
228.7
98.1
562.2
Range
0.21-0.81
42.4-55.9
8.96-11.2
0.924-2.26
0.231-0.944
150-377
81.2-139
466-648
Effluent Concentrations Measured After
POTW Had Stopped Accepting UOG
Extraction Wastewater (mg/L)c
Mean
0.036
58.8
13.61
0.228
0.119
136.8
65.9
494.2
Range
0.034-0.039
56.6-63.4
13.2-14.4
0.219-0.237
0.08-0.43
133-142
64.4-67.2
464-524
Source: 71 DCN SGE00525
a—Organic analytes were not detected in samples.
b—Sample date: 10/19/2010. Reported values are based on the mean, minimum, and maximum of 24 samples taken
for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.
c—Sample date: 12/1/2011. Reported values are based on the mean, minimum, and maximum of nine samples taken
for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.
d—The effluent concentrations of calcium and magnesium increased after the POTW had stopped accepting UOG
extraction wastewater. Ferrar et al. (71 DCN SGE00525) suggest that the increased concentrations of these ions may
be from high influent calcium and magnesium concentrations in other wastewater treated by the McKeesport POTW
(e.g., COG wastewater).
Abbreviation: mg/L—milligrams per liter
Ridgway, PA, POTW
Ridgway Borough operates a POTW that discharges to the Clarion River and has a
maximum monthly average design rate of 2.2 MGD. The Ridgway POTW uses screening and
grit removal, an equalization tank, aeration tanks, clarifiers, a chlorination feed system, a
chlorine contact tank, aerobic digesters, and a belt filter press. This POTW began accepting both
COG and UOG extraction wastewater in 2009. It stopped accepting UOG extraction wastewater
in 2011 but continued accepting COG wastewater, and still was as of the end of 2013.107 The
total oil and gas wastewater volume accounted for less than 2 percent of the total POTW influent
volume during 2009 through 2011 on average (46 DCN SGE00739). The POTW's total annual
average daily flow rate ranges between 0.8 and 1.3 MGD, based on 2008 to 2013 DMR data (175
DCN SGE00608).
The EPA created Figure D-12 using the sampling data submitted in the EPA's DMR
Loading Tool (175 DCN SGE00608) and PA DEP waste reports data (46 DCN SGE00739).
Each effluent concentration data point represents the average of 12 monthly average data points
as calculated and reported by the DMR Loading Tool. PA DEP waste reports provided the total
107 Ridgway's October 2011 NPDES permit (131 DCN SGE00755) notes that "no more than 20,000 gallons/day of
natural gas wastewater from shallow well operations shall be treated at the facility. The acceptance of wastewater
generated from shale oil extraction activities is prohibited."
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
volume of UOG and COG wastewater delivered to the POTW each year. The EPA divided the
annual volume by 365 to calculate the annual average daily flow. As shown in Figure D-12, in
2010, the Ridgway POTW experienced effluent TDS concentrations greater than 6,000 mg/L on
average and effluent chloride concentrations greater than 2,500 mg/L on average while it was
accepting the greatest volume of oil and gas wastewater, including that from UOG operators. As
a point of comparison, in 2008, before accepting any oil and gas wastewater, the POTW
experienced effluent TDS and chloride concentrations around 1,000 mg/L.
o
C
i
I
7.000
6.000
5;000
4.000
3,000
2,000
1,000
14.0
12.0
- 10.0
UOG \Vaste\vater Acceptance Period
11TSS
Exceed in ces
(2 009-i Oil)
4.0
2.0
0.0
2008 2009
2010 2011 2012 2013
Year
1*
9
a s
O 3
B
Annual Average COG Extraction Wastewater How
TDS
Annual Average UOG Extraction Wastewater Flow
Chloride
Sources: 52 DCN SGE00929
Figure D-12. Ridgway POTW: Annual Average Daily Effluent Concentrations and POTW
Flows
To comply with the requirements of the Ridgway Borough Pretreatment Program, the
Ridgway POTW completed a local limits analysis in January 2014 that included paired POTW
influent and effluent data. The samples were collected for 10 consecutive days in October and
November 2013 after the POTW stopped accepting UOG extraction wastewater but was still
accepting COG wastewater. Of particular interest is the fact that Ridgway POTW's contractor
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
estimated zero percent removals for TDS, chloride, and sulfate. All three of these constituents
are found in UOG extraction wastewater (88 DCN SGE00756).
Charleroi, PA, POTW
The Charleroi POTW uses an equalization tank, screening and grit removal,
sedimentation, activated sludge, and chlorine disinfection. It began accepting both COG and
UOG extraction wastewater in January 2005 and stopped accepting it in 2008 (11 DCN
SGE00751; 46 DCN SGE00739). The total oil and gas wastewater accounted for up to 32
percent of the total POTW influent volume during 2008, on average. UOG extraction wastewater
accounted for 10 percent of total POTW influent during 2008 on average (46 DCN SGE00739).
The POTW's average annual flow rate ranges between 1.4 and 1.9 MGD based on 2008 through
2013 DMR data (175 DCN SGE00608). The EPA identified case studies showing potential for
both pass through (Section D.5.3.1.1) and inhibition/disruption (Section D.5.3.2.1) at the
Charleroi POTW.
In 2008, PA DEP issued an AO requiring the Charleroi POTW to evaluate how accepting
oil and gas production wastewater affects its treatment processes, among other things (11 DCN
SGE00751). Charleroi's technical evaluation noted that the POTW typically rejects influent oil
and gas wastewater with TDS concentrations greater than 30,000 mg/L or chloride
concentrations greater than 15,000 mg/L. As part of the technical evaluation, Charleroi sampled
influent wastewater (including UOG extraction wastewater) and effluent wastewater over a 24-
hour period. The total oil and gas wastewater treated during this period was 150,650 gallons
(3,587 barrels) and the total wastewater treated was 1,559,000 gallons (37,120 barrels).
Therefore, the oil and gas wastewater accounted for 9.7 percent of the total influent to the plant
during the sampling period (11 DCN SGE00751). Table D-18 shows the results of the sampling
and the calculated removal rates. The data show that TDS is not removed by the Charleroi
POTW treatment processes.
Table D-18. Charleroi POTW Paired Influent/Effluent Data and Calculated Removal Rates
Parameter
Aluminum
Ammonia, as N
Barium
BOD 5
Hardness, as CaCO3
Oil and grease
Phosphorus
TDS
TSS
Influent Concentration
(mg/L)
2.34
14.4
0.177
84
265
29
0.49
1,020
116
Effluent Concentration
(mg/L)
0.656
4.52
0.171
1.00
260
5
0.3
1,030
21
Removal Rate (%)
72
68.6
3.4
98.8
1.9
82.8
38.8
0
81.9
Source: 11 DCN SGE00751
Abbreviation: mg/L—milligrams per liter
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Clarksburg, WV, POTW
The Clarksburg POTW has a maximum capacity of 8 MOD and uses screening, a cyclone
hydrogritter, clarifiers, aeration basins, and chlorine disinfection. The Clarksburg POTW started
accepting "gas well wastewater" (i.e., brine) in July 2008 on a trial basis and continued through
at least March 2009. Three frac tanks were set up on the treatment plant site and the brine (i.e.,
oil and gas extraction wastewater) was metered into the POTW's pump station wet well at a
constant continuous flow rate. Total POTW flow was at least 5 MOD. The amount of brine
metered to the POTW was gradually increased to evaluate the effect it would have on the POTW
performance. Clarksburg provided the following non-comprehensive data about the quantity and
chloride concentration of the brine metered to the POTW:
• July 2008, week 1: 10,000 gpd @ 50,000 mg/L chloride
• July 2008, week 2: 15,000 gpd @ 50,000 mg/L chloride
• July 2008, week 3: 17, 280 gpd @ 50,000 mg/L chloride
• July 2008, week 4: 25,000 gpd @ 50,000 mg/L chloride
• November 2008: 50,000 gpd @ 18,500 mg/L chloride
During the initial trial period in July 2008, the Clarksburg POTW superintendent noted that
effluent chloride concentrations "exceeded the desired quantity of 235 mg/L a couple of times
due to dry weather flows being below 5 MGD." He also noted that they would need to adjust the
volume of brine in the influent to the POTW during low flow conditions, and that "Chlorides are
not removed at the facility, merely diluted to acceptable levels." This statement further supports
the concept that TDS, of which the primary contributing ions in UOG extraction wastewater are
chloride and sodium, passes through POTWs untreated.
After the trial period, Clarksburg contacted the WV DEP about modifying its NPDES
permit to allow acceptance of gas wastewater. The DEP told the Clarksburg POTW that they
could continue accepting the gas wastewater as long as they were not violating their existing
effluent limitations (21 DCN SGE00749; 121 DCN SGE00552). In July 2009, WV DEP sent a
letter to the Clarskburg Sanitary Board with a list of requirements that would be imposed, if they
decided to accept oil and gas related wastewater (221 DCN SGE01113). The letter also stated
that
... WVDEP discourages POTWs from accepting wastewater from oil and gas operations
such as...marcellus shale wastewaters because these wastewater essentially pass through
sewage treatment plants andean cause inhibition and interference with treatment plant
operations. The wastewaters from these types of operations contain high levels of
chloride, dissolved solid, sulfate, and other pollutants. POTWs provide little to no
treatment of these pollutants and could potentially lead to water quality issues in the
receiving stream.
In April 2013, WV DEP verified that no POTWs in WV were accepting UOG extraction
wastewater (196 DCN SGE00762; 198 DCN SGE00766).
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
5.3.1.2 Case Studies About POTWs Accepting Wastewater from Other Industrial
Sources Containing UOG Pollutants
Franklin Township, PA, POTW
The Franklin Township POTW discharges to the lower fork of Ten Mile Creek, a
tributary to the Monongahela River, and treats influent wastewater using aeration, rotating
biological contactors, clarification, filtration, and chlorination (74 DCN SGE00746). The
Franklin Township POTW accepted industrial wastewater from the Tri-County Wastewater
CWT facility until March 2011. During that time, the Tri-County CWT facility was accepting
oil and gas extraction wastewater. The CWT facility targeted removal of TSS and oil and grease
by filtration, flocculation, and skimming, but certain pollutants in the UOG extraction
wastewater such as TDS remained in the treated effluent from the CWT facility. The industrial
wastewater received from Tri-County Wastewater accounted for approximately 5.4 percent of
the Franklin POTW's 0.982 MOD effluent by volume in November 2010 (71 DCN SGE00525).
On December 4, 2008, the Franklin POTW entered into a Consent Order and Agreement
with PA DEP108 regarding effluent discharges containing elevated levels of TDS. Paragraph G of
the order notes that
Neither the STP [Franklin POTW] nor the Pretreatment Facility [Tri-County CWT
Facility] currently has treatment facilities for the removal of Total Dissolved Solids.
Ferrar et al. (71 DCN SGE00525) analyzed constituents in effluent wastewater
discharged from the Franklin Township POTW during the period before and after it accepted
industrial wastewater from the Tri-County Wastewater CWT facility. Table D-19 shows the
mean and range of effluent concentrations at the Franklin Township POTW during the period it
accepted industrial wastewater from the CWT facility and after they stopped. Ferrar et al.
analyzed pollutants typically found in UOG extraction wastewater; they report a mean effluent
TDS concentration of 3,860 mg/L from the Franklin Township POTW while it was accepting
wastewater from the Tri-County CWT facility and a mean effluent TDS concentration of 398
mg/L from the POTW after it stopped. The mean effluent concentrations for all pollutants
presented in Table D-19 were higher when the POTW was accepting the industrial discharge
from the Tri-County CWT facility, suggesting that pollutants were discharged from the POTW
without treatment. Based on the treatment technologies currently in place at the Franklin
Township POTW, one would expect little to no treatment of the common constituents in UOG
extraction wastewater. Ferrar et al. concluded:
This research provides preliminary evidence that these and similar WWTPs may not be
able to provide sufficient treatment for this wastewater stream, and more thorough
monitoring is recommended.
108 pA DEp had issued an AO to the Franklin POTW in October 2008, but the Consent Order and Agreement
superseded that order.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-19. Franklin Township POTW Effluent Concentrations With and Without
Industrial Discharges from the Tri-County CWT Facility
Analyte"
Barium
Calcium
Magnesium
Manganese
Strontium
Bromide
Chloride
Sulfate
TDS
Effluent Concentrations from Franklin
Township POTW Measured While POTW
Was Accepting Wastewater from CWT
Facility (mg/L)b
Mean
5.99
231
32.6
0.228
48.3
20.9
2,210
137
3,860
Range
4.27-7.72
207-268
29.1-36.6
0.204-0.249
41.8-56.1
14.3-28.0
1,940-2,490
117-267
3,350-4,440
Effluent Concentrations from Franklin
Township POTW Measured After POTW
Had Stopped Accepting Wastewater from
CWT Facility (mg/L)c
Mean
0.141
40.6
8.63
0.112
0.236
0.016
61.9
65.6
398
Range
0.124-0.156
38.8-43.5
8.04-9.11
0.102-0.144
0.226-0.249
0.016
57.5-64.6
60.0-75.0
376-450
Source: 71 DCN SGE00525
a—Organic analytes were not detected in samples.
b—Sample date: 11/10/2010. Reported values are based on the mean, minimum, and maximum of 24 samples taken
for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.
c—Sample date: 11/7/2011. Reported values are based on the mean, minimum, and maximum of nine samples taken
for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.
Abbreviation: mg/L—milligrams per liter
Wheeling, WV, POTW
The Wheeling POTW has primary and secondary treatment operations, including primary
clarification, solids and floatable materials removal, and disinfection (115 DCN SGE00999). The
Wheeling POTW accepted industrial wastewater from the Liquid Asset Disposal (LAD) CWT
facility through August 2009109 and wastewater directly from UOG operators in 2008uo. The
LAD CWT facility accepted a variety of wastewater from the following sources: sewage
facilities, storm water from an international airport, and gas well development and production
wastewater, among others. The LAD CWT facility is a SIU and was authorized to discharge into
the Wheeling, WV POTW (SIU Permit No. 0014) (219 DCN SGE00485). The LAD CWT
facility uses ultra-filtration, ozonation, and reverse osmosis to target the removal of chlorides
prior to discharges to the Wheeling POTW (101 DCN SGE00996).
The EPA analyzed sampling data submitted in its DMR Loading Tool (175 DCN
SGE00608) and PA DEP waste reports data (46 DCN SGE00739) and found that the effluent
concentrations of chloride experienced by the Wheeling POTW in 2008 were higher when it was
accepting UOG extraction wastewater and industrial discharges from the LAD CWT facility than
EPA did not identify the date on which the Wheeling POTW began accepting wastewater from the LAD CWT
facility. However, the LAD CWT SIU Permit No. 0014 was issued in August 2004 (22 DCN SGE01000).
110 The Wheeling POTW may have accepted UOG extraction wastewater directly from operators in years other than
2008, but EPA only identified acceptance directly from operators in 2008 (127 DCN SGE00188).
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
after it stopped. In 2008, the POTW accepted an average of 5,400 gallons/day of UOG extraction
wastewater and had an average effluent chloride concentration of 650 mg/L. Comparatively, in
2011, the POTW did not accept any UOG extraction wastewater and had an average effluent
chloride concentration of 130 mg/L.111 Data from an August 2009 letter from WV DEP to the
City of Wheeling states (222 DCN SGE01114)
The agency has determined that the follow ing pollutants are of concern associated with
oil and gas r elated wastewaters and may have a potential for inhibition, interference, and
pass through: total dissolved solids (TDS), sulfate, chloride... zinc... copper... barium
... total suspended solids, iron... benzene... strontium... gross alpha radiation, gross beta
radiation, and radium 226 + radium 228. In addition to the potential for inhibition,
interference, and pass through, these pollutants may also have an impact on sludge
disposal requirements.
Additional data from a 2011 Consent Order from WV DEP to the Wheeling POTW indicates that
the LAD CWT facility exceeded its 9,000-pound daily chloride limitation, in violation of its SIU
permit, 50 times between January 8, 2009, and February 4, 2010 (219 DCN SGE00485).
Therefore, the UOG extraction wastewater and the industrial wastewater accepted by the
Wheeling POTW from the LAD CWT facility likely contributed to the elevated effluent chloride
concentrations.
Warren, OH, POTW
The city of Warren operates a 16 MGD POTW that discharges to the Mahoning River.
The POTW employs screening and grit removal, primary settling, activated sludge aeration, final
clarification, chlorination, dechlorination, and post-aeration treatment processes. Solid residuals
are thickened by dissolved air flotation, dewatered using a belt filter press, stabilized with lime,
and disposed of by land application or by distribution and marketing of usable end products.
In May 2009, the Warren POTW and its customer, the Patriot Water Treatment CWT
facility,112 began discussions with the Ohio EPA about accepting UOG produced water. Patriot
planned to accept UOG produced water from shale gas operations, treat the wastewater to
remove heavy metals and other constituents, and discharge the treated industrial wastewater to
the Warren POTW. In preparation for acceptance of treated industrial wastewater from the CWT
facility that would contain pollutants found in UOG produced water, the Warren POTW
undertook a pilot study to show that accepting wastewater containing pollutants found in UOG
produced water would not cause any problems with Mahoning River water quality. Patriot's
treatment of UOG produced water includes reduction in heavy metal concentration, but not TDS
or chloride. The Ohio EPA worked with Patriot and the Warren POTW to develop a pilot
treatment study that evaluated the effects of pretreated UOG produced water on the POTW. The
111 The data about quantities of UOG extraction wastewater accepted by the Wheeling POTW are from the PA DEP
waste report data and are reflective of volumes of UOG extraction wastewater accepted from UOG operators in
Pennsylvania. The Wheeling POTW may be accepting additional UOG extraction wastewater from UOG operators
in West Virginia or other nearby states; these volumes of wastewater are not captured in this discussion.
112 The Patriot CWT facility uses primary treatment processes (e.g., settlement tanks, clarifier tanks) to target the
removal of suspended solids and metals prior to discharge.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
study also evaluated the receiving stream (Mahoning River) water quality, upstream and
downstream of the POTW discharge (5 DCN SGE00497; 35 DCN SGE00522).
The pilot study began on February 9, 2010, and ran for eight weeks. It focused on
collecting data from the Warren POTW and did not include sampling at the Patriot CWT facility.
The summarized TDS and chloride data from the study are presented in Table D-20. The Warren
POTW reported typical flow rates of 13.38 MOD and accepted the following volumes of
wastewater from the Patriot CWT facility over the eight weeks (percentage of total POTW flow
accounted for by Patriot CWT facility's industrial wastewater is noted parenthetically)113 (193
DCN SGE00616):
• Week 1: 5 days @ 20,000 gallons (0.15 percent)
• Week 2: 5 days @ 40,000 gallons (0.30 percent)
• Week 3: 5 days @ 60,000 gallons (0.45 percent)
• Week 4: 5 days @ 80,000 gallons (0.60 percent)
• Week 5: 5 days @ 100,000 gallons (0.75 percent)
• Week 6: 5 days @ 100,000 gallons (0.75 percent)
• Week 7: 5 days @ 100,000 gallons (0.75 percent)
• Week 8: 5 days @ 100,000 gallons (0.75 percent)
Table D-20 shows the average paired influent and effluent TDS concentrations measured
prior to start up and during the pilot study. Baseline samples were collected when the POTW was
not accepting wastewater from the Patriot CWT facility. The pilot study description states that
the influent samples (baseline and pilot study) include only municipal influent and do not include
any wastewater from the Patriot CWT facility.114 The data show that TDS and chloride
concentrations increased in the influent and effluent samples over time both during the baseline
sampling and after the Warren POTW accepted wastewater from the Patriot CWT facility. The
effluent concentrations of TDS and chloride increased at higher percentages over the influent
concentration during the pilot study, when the POTW was accepting wastewater from the Patriot
CWT facility (193 DCN SGE00616), suggesting that TDS and chloride were not removed by the
POTW.
113 All flows were introduced into the Warren POTW over an eight-hour period.
114 The Warren POTW pilot study description states that "Raw [influent] does not have any Patriot influence or plant
return flows." The report author also noted increases in the TDS and chloride concentrations over the period of the
study and suggested that "these increases are most likely due to seasonal fluctuations within the collection system as
a result of user operations or seasonal runoff from spring rains" (193 DCN SGE00616).
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Table D-20. TDS Concentrations in Baseline and Pilot Study Wastewater Samples at
Warren POTW
Influent Concentration
(mg/L)
Effluent Concentration
(mg/L)
Percent Increase (%)
584
599
2.6
157
679
885
30.3
239
348
45.6
Source: 193 DCN SGE00616
Abbreviation: mg/L—milligrams per liter
From September 12 through 16, 2011, EPA Region 5 inspected and collected wastewater
samples at the Warren POTW and noted that (193 DCN SGE00616)
the POTW had not experienced any of the following conditions since accepting the brine
waste water from the Patriot CWTfacility:
• Diminished or inhibited performance of the biological treatment processes
• Adverse impacts to the downstream water quality
• Adverse impacts to the quality of the facility's biosolids
The compliance inspection indicated that the Warren POTW was in compliance with all
of its NPDES permit limitations. Table D-21 shows the results of EPA Region 5's wastewater
sample analyses conducted during their September 2011 inspection. The compliance inspection
data show minimal to no TDS removals by the POTW and minimal chloride removals.
Table D-21. EPA Region 5 Compliance Inspection Sampling Data
Pollutant
TDS
Chloride
Sulfate
TSS
BOD 5
Bromide
Fluoride
Warren POTW Influent Concentration
(mg/L)a
Average
726
361
250
95.0
33.3
5.25
3.62
Range
686-748
345-374
243-256
67.0-112
27.7-39.0
5.01-5.43
3.36-4.13
Warren POTW Effluent Concentration
(mg/L)a
Average
726
213
77
<4
<2
1.57
1.83
Range
648-778
191-252
68-84
NAb
NAb
1.40-1.89
1.40-2.14
Source: 193 DCN SGE00616
a—Samples were taken on four days (9/12/2013, 9/13/2013, 9/14/2013, and 9/15/2013).
b—All four samples were reported as below the detection limit.
Abbreviation: mg/L—milligrams per liter
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As of June 2014, the Warren POTW was still accepting wastewater from the Patriot
CWT facility (200 DCN SGE00786). Its NPDES permit allows it to accept a maximum of
100,000 gallons of "wastewater from a regulated CWT facility that is tributary to the City's
collection system" per day (0.67 percent of its maximum total daily flow) at a maximum TDS
concentration of 50,000 mg/L (217 DCN SGE00295).
Brockway, PA, POTW
The Brockway POTW treats industrial and domestic wastewater using screens, aerated
basins, oxidation ditches, clarifiers, aerobic sludge digestion, UV disinfection, and post-aeration.
Its NPDES permit (issued on July 3, 2012, and expiring on July 31, 2017) allows it to accept up
to 14,000 gpd of "natural gas related wastewater," none of which may be from "Shale Gas
Extraction related activities" (132 DCN SGE00931). As of June 2014, the Brockway POTW was
still accepting natural-gas-related wastewater treated by the Dannie Energy Corporation CWT
facility. The Brockway POTW is sampling and reporting the required parameters on PA DEP's
electronic DMR system (eDMR) (132 DCN SGE00931). The permit includes limits for pH,
carbonaceous BODs, TSS, fecal coliform, ammonia-nitrogen, TDS, and osmotic pressure. The
permit also included reporting requirements for flow, barium, strontium, uranium, chloride,
bromide, gross alpha, and radium-226/228.
The Brockway POTW saw increases in the effluent concentrations of TDS, which were
below 400 mg/L before the acceptance of COG wastewater and increased to between 2,500 and
3,000 mg/L during the acceptance of COG wastewater. Typical COG wastewater accepted by the
Brockway POTW may have TDS concentrations over 200,000 mg/L (99 DCN SGE00753).
5.3.2 VOG Extraction Wastewater Constituents and POTW Inhibition and Disruption
In addition to the discharge of pollutants not treated by a POTW, the presence of certain
pollutants in industrial wastewater discharges can have the following effects on the receiving
POTW:
• Inhibition or disruption of the POTW's treatment processes and/or operations
• Inhibition or disruption of the POTW's sludge processes, including sludge disposal
processes
• Harm to POTW workers
The EPA investigated how pollutants in industrial wastewater discharges, which may
contain constituents found in UOG extraction wastewater, might inhibit the performance of
typical POTW treatment processes. Table D-22 presents inhibition threshold levels for activated
sludge and nitrification, two treatment processes commonly used at POTWs, for select UOG
constituents identified in Section C.3.115 The EPA recognizes that POTW treatment processes
will not be exposed to UOG constituents at the concentrations they are found in UOG produced
water (i.e., flowback, long-term produced water).
115 EPA also presents specific inhibition thresholds for anaerobic digestion and trickling filters, but the UOG
constituent concentrations are not as likely to exceed the thresholds, so they were not included in Table D-22.
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As discussed in Section A.2.1.1, POTWs establish local limits to control pollutant
discharges that present a reasonable potential for pass through or interference with POTW
operations. The inhibition levels presented in the EPA's guidance represent concentrations that
would reduce the effectiveness or otherwise interfere with the treatment operations for treatment
commonly used at POTWs. Inhibition of activated sludge processes at a POTW could impair
BOD5 removal and TSS removal (particularly if sludge settling is affected). Inhibition of
nitrification, a process that some POTWs use to convert ammonia to nitrate/nitrite (which may
be part of the activated sludge process or a separate biological treatment stage), may impair the
POTW's ability to remove ammonia and nutrients in the wastewater.
Table D-22. Inhibition Threshold Levels for Various Treatment Processes"
Pollutant
Ammonia
Arsenic
Benzene
Cadmium
Chloride
Chloroform
Chromium, total
Copper
Ethylbenzene
Lead
Mercury
Naphthalene
Nickel
Phenol
Sulfide
Toluene
Zinc
Reported Range of Activated Sludge
Inhibition Threshold Levels (mg/L)a
480
0.1
100-500, 125-500
1-10
NA
NA
1-100
1
200
1-5, 10-100
0.1-1, 2.5 as Hg(II)
500, 500, 500
1-2.5, 5
50-200, 200, 200
25-30
200
0.3-5, 5-10
Reported Range of Nitrification Inhibition
Threshold Levels (mg/L)a
NA
1.5
NA
5.2
180
10
0.25-1.9, 1-100 (trickling filter)
0.05-0.48
NA
0.5
NA
NA
0.25-0.5, 5
4, 4-10
NA
NA
0.08-0.5
Source: 165 DCN SGE00602
a—Where multiple values are listed (divided by commas), the data were reported individually in 165 DCN
SGE00602 by different sources.
Abbreviations: mg/L—milligrams per liter; NA—not available
Because all POTWs are required to control TSS and BODs, they are designed for the
effective removal of these two parameters. Elevated concentrations of TSS and BOD5 in POTW
discharges suggest inhibition/disruption of treatment processes. As some of the studies described
in the following sections indicate, POTWs have linked TSS and/or BODs permit limit
exceedances with the acceptance of oil and gas extraction wastewater.
The following subsections present case studies that discuss inhibition/disruption at
POTWs that accepted wastewater containing pollutants found in UOG extraction wastewater.
The purpose of these subsections is to identify instances of inhibition/disruption, or potential
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inhibition/disruption, at POTWs associated with the acceptance of UOG extraction wastewater
pollutants.
5.3.2.1 Case Studies About POTWs Accepting Wastewater from Oil and Gas
Extraction Facilities
Johnstown, PA, POTW
The Johnstown POTW uses screening, grit removal, high-purity oxygen activated sludge
aeration with integrated fixed-film activated sludge, final clarification, and chlorination (133
DCN SGE00930). The Johnstown POTW accepted both UOG and COG wastewater before 2008
and stopped accepting both in 2011 (46 DCN SGE00739). The total oil and gas wastewater
accounted for less than 3 percent of the total POTW influent volume during the acceptance
period on average. The POTW's annual average daily flow rate ranges between 9.0 and 10.5
MGD based on 2008 through 2013 DMR data (175 DCN SGE00608).
The EPA created Figure D-13 using the sampling data submitted in its DMR Loading
Tool (175 DCN SGE00608) and PA DEP waste reports data (46 DCN SGE00739). Each effluent
concentration data point represents the average of 12 monthly average data points as calculated
and reported by the Loading Tool. PA DEP waste reports provided the total volume of UOG and
COG wastewater delivered to the POTW each year. The EPA divided the annual volume by 365
to calculate the annual average daily flow. As shown in Figure D-13, the Johnstown POTW
experienced a much larger number of permit limit exceedances during the period when they were
accepting the greatest volume of oil and gas extraction wastewater. In a December 2012 letter
regarding the 2011 annual pretreatment report, Johnstown's pretreatment coordinator stated,
[We] know that the treatment plant no longer accepts gas drilling waste,116 and we
anticipate that the number of violations will decrease.
Further, Section C.3.2.1 presents data showing that TSS concentrations in drilling
wastewater may be higher than TSS concentrations in UOG produced water.117 The PA DEP
waste reports data show that the Johnstown POTW accepted more drilling wastewater than any
other POTW in Pennsylvania from 2008 through 2011. The POTW accepted the largest volume
of drilling wastewater in 2009 and 2010, which totaled over 15 million gallons and accounted for
over 40 percent of the total influent oil and gas wastewater accepted by the POTW. In total, the
Johnstown POTW experienced 27 TSS permit limit exceedances from 2008 through 2011, 18 of
which were in 2009 and 2010. The POTW also experienced elevated effluent TSS concentrations
in 2009 (61 mg/L).
116 The EPA assumes that this phrase refers to both COG wastewater and UOG extraction wastewater.
117 Drilling wastewater initially includes cuttings (i.e., solids) that are partially removed by the operator before
management or disposal. Any cuttings that remain may contribute to elevated TSS concentrations.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Annual Average COG Extra ctionWasteirater Flow
Annual Average UOG Extra ctionWasteirater Flow
-TSS
BOD-5
300
200S 2009 2010 2011
Year
2012
2013
c
+•>
55
LOG V. i3te\vater Acceptance
Period
6 Total Exceed an ces
(2012-2013)
Sources: 52 DCN SGE00929
Figure D-13. Johnstown POTW: Annual Average Daily Effluent Concentrations and
POTW Flows
California, PA, POTW
The California POTW uses a contact stabilization118 process to treat influent wastewater
(10 DCN SGE00787). In 2008 and 2009, the California POTW accepted both UOG and COG
wastewater. The total oil and gas wastewater accounted for up to 33 percent of the total POTW
influent volume during 2008, on average. UOG extraction wastewater accounted for 14 percent
of total POTW influent during 2008, on average (46 DCN SGE00739). The POTW's average
annual daily flow rate ranges between 0.5 and 0.8 MGD based on 2008 through 2013 DMR data
(175 DCN SGE00608).
The EPA created Figure D-14 using the sampling data submitted in its DMR Loading
Tool (175 DCN SGE00608) and PA DEP waste reports data (46 DCN SGE00739). Each effluent
concentration data point represents the average of 12 monthly average data points as calculated
Contact stabilization is a two-stage activated sludge process, consisting of a 30 to 60 minute absorptive phase
followed by a one to two hour oxidation phase. Aeration volume requirements are half of those for conventional
activated sludge (119 DCN SGE00167).
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
and reported by the DMR Loading Tool. PA DEP waste reports provided the total volume of
UOG and COG wastewater delivered to the POTW each year. The EPA divided the annual
volume by 365 to calculate the annual average daily flow. As shown in Figure D-14, the
California POTW experienced elevated concentrations of TSS and BOD 5 while accepting oil and
gas wastewater. Figure D-14 also shows that the California POTW experienced three
exceedances of its TSS permit limits119 and one exceedance of its BOD5 permit limits.120
200
Annual Average COG Extraction Wastewater Plow
Annual Average UOG Extraction Wastewater Plow
-•—TSS
BOD-5
2008
2009
2010 2011
Year
2012
2013
180
160 •£
UOG Wastewater Acceptance Period
Sources: 52 DCN SGE00929
Figure D-14. California POTW: Annual Average Daily Effluent Concentrations and
POTW Flows
Charleroi, PA, POTW
The Charleroi POTW was introduced and described in more detail in Section D.5.3.1 of
this TDD.
The EPA created Figure D-15 using the sampling data submitted in its DMR Loading
Tool (175 DCN SGE00608) and PA DEP waste reports data (46 DCN SGE00739). Each effluent
119 The California POTW had a monthly average TSS limit of 30 mg/L and a daily maximum TSS limit of 45 mg/L
from 2008 through 2013.
120 The California POTW had a monthly average BOD5 limit of 25 mg/L and a daily maximum BOD5 limit of 37.5
mg/L from 2008 through 2012. In 2013, its daily maximum BOD5 limit changed to 40 mg/L.
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concentration data point represents the average of 12 monthly average data points as calculated
and reported by the Loading Tool. PA DEP waste reports provided the total volume of UOG and
COG wastewater delivered to the POTW each year. The EPA divided the annual volume by 365
to calculate the annual average daily flow. As shown in Figure D-15, the Charleroi POTW
experienced elevated concentrations of TSS and BOD5 while accepting UOG extraction
wastewater.
500
Annual Average COG Extraction Wastewater Flow
Annual Average UOG Extraction Wastewater Flow
TSS
BOD-5
POTW Stopped Accepting
UOG Wastewater
100
- 50
2008
Sources: 52 DCN SGE00929
2009
2010
2011
Year
Figure D-15. Charleroi POTW: Annual Average Daily Effluent Concentrations and POTW
Flows121
Waynesburg, PA, POTW
The Borough of Waynesburg POTW accepted gas-exploration-related wastewater, hauled
directly from operators, from June 2006 to November 2008. Gas well wastewater made up about
2 percent of total inflow in 2006. The percentage increased to 8.1 percent in 2007 and 9.5 percent
Figure D-15 only shows data for 2008 through 2011 because there is no PA DEP waste report data or DMR
Loading Tool data for the Charleroi POTW for 2012 or 2013.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
in 2008. The Waynesburg POTW's average annual daily flow rate ranged between 0.37 and 0.62
MOD over those three years. The treatment process at Waynesburg POTW is as follows: two
primary clarifiers, a trickling filter, a bio-tower, a final clarifier, and chlorine disinfection (12
DCN SGE00997, 13 DCN SGE00997.A01).
The Waynesburg POTW received a CWA §308 Request for Information from EPA
Region 3 in February 2009. In March 2009, the Waynesburg POTW responded with a "Process
Impact Evaluation" (14 DCN SGE00750), which stated that:
The amount of well water that was being accepted to the treatment facility has had no
adverse effects on the trickling filter and the bio-tower except on one occasion in 2007. A
hauler delivered a batch of well water that impacted the biological growth within the
trickling filter. The water was believed to befrac water which possesses a high salinity
which in turn impacted the biological growth in the trickling filter.
5.3.2.2 Case Studies About POTWs Accepting Wastewater from Other Industrial
Sources Containing UOG Pollutants (e.g., CWT Facilities)
New Castle, PA, POTW
The New Castle POTW accepted industrial wastewater from the Advanced Waste
Services CWT facility, which treats oil and gas wastewater. Advanced Waste Services CWT
facility treats "pretreated brine" (industrial wastewater) using solids settling, surface oil
skimming, and pH adjustment. If influent wastewater does not meet Advanced Waste Services'
pretreatment permit requirements, the facility applies additional treatment with flocculants (223
DCN SGE00554).
In its 2009 annual report to EPA Region 3, the New Castle POTW identified numerous
violations of its NPDES permit limits for discharges of TSS. It also identified significant
increases in the volume of industrial wastewater that it was receiving (see Table D-23) from
Advanced Waste Services. New Castle's 2009 annual report does not include the total volume of
wastewater it treated, but its 2013 NPDES permit indicates that all permit limits were based on
an effluent discharge rate of 17 MGD (223 DCN SGE00554; 134 DCN SGE00573).
Table D-23. Industrial Wastewater Volumes Received by New Castle POTW (2007-2009)
Year
2007
2008
2009
Industrial Wastewater Volume (gpd)
74,278
130,608
331,381
Percent of Total Volume Treated by POTWa
0.44%
0.77%
1.95%
Source: 223 DCN SGE00554
a—Assuming 17 MGD is the total volume treated.
The 2009 annual report (223 DCN SGE00554) states that:
It is believed that pretreated brine wastewater from the developing oil & gas industry is
adversely affecting the ability of the final clarifiers to separate solids via gravity settling.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
This has resulted in higher sludge blanket levels that are more easily upset and washed
out during rainfall-induced high flow events. The Authority has begun using polymer
flocculation to enhance settling with some success. However, there were numerous
effluent TSS violations in 2009.
As noted in the annual report, instability in sludge blanket levels can cause increased
washouts during large rain events, which may cause interference with biological treatment. New
Castle reported 19 violations of its NPDES permit limits for TSS, believed to be caused by the
acceptance of UOG extraction wastewater via the Advanced Waste Services CWT facility's
industrial discharge (223 DCN SGE00554). The EPA compared the violations in 2009 to the
violations that occurred in 2011, after the New Castle POTW stopped accepting industrial
discharges from the CWT facility (i.e., violations between May and December 2011). The EPA
identified two TSS violations during this nine-month time frame. Table D-24 shows detailed
information about the violations in 2009 and 2011, including when they occurred, the measured
values, and the percentage over the NPDES permit limit. The decrease in the number of TSS
violations from 2009 to 2011, after the POTW stopped accepting industrial discharges from the
Advanced Waste Services CWT facility, suggests that the UOG extraction wastewater pollutants
were a contributing cause of the violations. However, the two violations in 2011 indicate that the
UOG extraction wastewater was likely not the sole cause of interference with treatment
processes at the POTW.
Table D-24. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW
(NPDES Permit Number PA0027511)
Month, Year
March 2009
March 2009
May 2009
June 2009
July 2009
July 2009
August 2009
August 2009
September 2009
October 2009
October 2009
January 20 10
January 20 10
February 20 10
March 20 10
March 20 10
November 20 10
November 20 10
December 20 10
November 20 11
Parameter
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
TSS
Sample Type
Weekly maximum
Monthly average
Monthly average
Monthly average
Weekly maximum
Monthly average
Weekly maximum
Monthly average
Monthly average
Weekly maximum
Monthly average
Weekly maximum
Monthly average
Monthly average
Monthly average
Weekly maximum
Monthly average
Weekly maximum
Weekly maximum
Monthly average
NPDES Permit
Limit (mg/L)
45
30
30
30
45
30
45
30
30
45
30
45
30
30
30
45
30
45
45
30
Measured
Value (mg/L)
58
37
34
38
64
45
61
50
37
46
31
60
40
33
38
55
34
55
56
35
Percentage Over
Permit Limit (%)
29
23
13
27
42
50
36
67
23
2
o
J
33
33
10
27
22
13
22
24
17
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-24. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW
(NPDES Permit Number PA0027511)
Month, Year
November 20 11
Parameter
TSS
Sample Type
Weekly maximum
NPDES Permit
Limit (mg/L)
45
Measured
Value (mg/L)
64
Percentage Over
Permit Limit (%)
42
Sources: 169 DCN SGE00620; 185 DCN SGE00612
Abbreviation: mg/L—milligrams per liter
Wheeling, WV, POTW
The Wheeling POTW, introduced in Section D.5.3.1, accepted industrial wastewater
from the LAD CWT facility, which treats oil and gas wastewater122. A 2011 Consent Order
issued to the Wheeling POTW by the WV DEP indicates that the POTW experienced
interference with biological treatment from accepting UOG extraction wastewater via the CWT
facility's industrial discharge. The Order describes the following timeline of events (219 DCN
SGE00485):
• July 21, 2009—the Wheeling POTW experienced an upset that required several
weeks of "vigilant action to recover" and included the introduction of a "seed" sludge
from a nearby POTW. Plant upset conditions occurred during periods when the
POTW exceeded discharge limits for fecal coliform and TSS.
• August 21, 2009—Meeting minutes from a meeting between Wheeling POTW and
LAD CWT facility stated that Wheeling was accepting oil and gas wastewater "well
above the 1% that is allowed." The minutes also said that Wheeling was concerned
about the lack of diversity in microorganisms and that the wastewater from LAD was
the cause of the lack of microbial diversity.
• November 17, 2009—WVDEP inspected Wheeling POTW and noted that "[t]he
discharge from Wheeling was slightly turbid and causing a crispy white foam in the
receiving stream." In addition, the Wheeling POTW experienced operational
interference, inefficiency, or possible upset indicated by several factors including an
increased chlorine demand, loss in effluent clarity, UV disinfection failures, and
suspicious odors.
• May 6, 2010—Wheeling POTW representatives met with WV DEP representatives to
discuss the draft Consent Order. The Order included numerous requirements
including one that stated, "Upon entry of this Order, Wheeling shall continue to cease
and desist acceptance of all oil and gas wastewater."
Brockway, PA, POTW
The Brockway POTW, introduced in Section D.5.3.1, was still accepting natural-gas-
related wastewater treated by the Dannie Energy Corporation CWT facility as of June 2014.
Before accepting COG wastewater, Brockway POTW installed an oil/solids separator and
aerated equalization tank. The POTW began accepting COG wastewater starting in November
As described in Section D.5.3.1, the Wheeling POTW accepted industrial wastewater from the LAD CWT
facility through August 2009 and wastewater directly from UOG operators in 2008.
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Chapter D — UOG Extraction Wastewater Management and Disposal Practices
1 9^ ___ ___
2008 and noticed an increase in sludge generation. The POTW operators noticed a scum layer
forming on the clarifiers because of a combination of calcium in the oil and gas wastewater and
soaps/fats in the typical POTW influent wastewater. In addition to the scum layer on the
clarifiers, the POTW experienced increased sludge generation and high concentrations of barium
in the sludge (sludge barium content = 1,490 mg/kg). However, the POTW ran a hazardous
waste determination and found that the barium content was below the hazardous waste
classification threshold (99 DCN SGE00753).
5.3.2.3 POTW Sludge and Scale Formation
UOG extraction wastewater is also a concern in the disruption of POTW sludge
processes, including sludge disposal, and the disruption of POTW operations as a result of
excessive scale formation. For example, POTWs that accept and treat wastewater high in heavy
metals (e.g., nickel, copper, zinc) face the potential for heavy metals accumulation in sludge. A
POTW accepting wastewater with high metals concentrations may no longer be able to land-
apply its sludge because it may violate sludge disposal rules.
While UOG extraction wastewater does not typically contain concentrations of heavy
metals at levels that would likely prohibit the POTW from land-applying its sludge (see Table
C-17), the EPA has identified the potential for elevated concentrations of radium-226 and -228 in
sludge (172 DCN SGE00136; 135 DCN SGE01028). State and federal regulations for the
transport and disposal of radioactive waste may limit the POTW's options for managing sludge
contaminated with radium and other radioactive materials derived from UOG extraction
wastewater. POTWs with sludge containing radioactive materials may resort to underground
injection in a Class I well124, disposal at a hazardous waste landfill125, or disposal at a low-level
radioactive waste landfill126 (189 DCN SGE00615).
In addition to inhibiting the performance of treatment operations, UOG extraction
wastewater may disrupt POTW operations as a result of excessive scale formation. Scale
typically accumulates on valves, pipes, and fittings and, therefore, may interfere with POTW
operation (e.g., restrict flow to unit processes). Scale is produced from deposits of divalent
cations (e.g., barium, calcium, magnesium) that precipitate out of wastewater. Figure D-16
shows an example of barium sulfate scaling in an oil and gas pipe in the Haynesville shale
formation.
123 The EPA is not aware of any time when the Brockway POTW accepted UOG extraction wastewater.
124 Class I underground injection wells are used to inject hazardous wastes, industrial non-hazardous liquids, or
municipal wastewater beneath the lowermost underground source of drinking water.
125 Hazardous waste landfills are regulated under RCRA Subtitle C. Some hazardous waste landfills are permitted to
accept TENORM waste, while others have to request state approval before accepting TENORM waste.
126 Low-level radioactive waste landfills are licensed by the U.S. Nuclear Regulatory Commission or by a state
under agreement with the Commission. These landfills provide a disposal option for wastes with radionuclide
concentrations that are unable to be disposed of at municipal, industrial, or hazardous waste landfills.
138
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Source: 152 DCN SGE00768.A26
Figure D-16. Barium Sulfate Scaling in Haynesville Shale Pipe
Table C-17 shows typical concentrations of barium, calcium, and strontium in UOG
extraction wastewater, which suggest that UOG extraction wastewater may cause scale
1 97
accumulation at POTWs. Because radium behaves like other divalent cations, it may also
accumulate in scale and form TENORM: technologically-enhanced naturally occurring
radioactive material, defined as naturally occurring radioactive materials that have been
concentrated or exposed to the accessible environment as a result of human activities such as
manufacturing, mineral extraction, or water processing (e.g., in treatment processes at a POTW).
PA DEP's 2015 study report128 (135 DCN SGE01028) provides the following examples of solids
that may contain TENORM: drill cuttings, filter sock residuals, impoundment sludge, tank
bottom sludge, pipe scale, wastewater treatment plant sludge, and soils129. The PA DEP
TENORM study report concludes that "There is little potential for radiological exposure to
workers and members of the public from handling and temporary storage of filter cake at
POTWs. However, there is a potential for radiological environmental impacts from spills and the
long-term disposal of POTW filter cake." The PA DEP TENORM study report includes the
following recommendations for future action:
• "Perform routine survey assessment of areas impacted with surface radioactivity to
determine personal protective equipment (PPE) use and monitoring during future
activity that may cause surface alpha and beta radioactivity to become airborne."
127 Radium is a naturally occurring radioactive element that ionizes in water to a divalent cation with chemical
properties similar to barium, calcium, and strontium.
128 PA DEP initiated a study to collect data related to TENORM associated with oil and gas operations in
Pennsylvania, including assessment of potential worker and public radiation exposure, TENORM disposal, and
other environmental impacts.
129 PA DEP's 2015 TENORM study sampled the following types of solids: surface soil impacted by sediments, filter
cakes, soils, sludge, drill cuttings, drilling muds, proppant sand, and filter socks. PA DEP identified pipe scale as a
source of TENORM, but did not sample for pipe scale in their 2015 TENORM study.
139
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
• "Conduct additional radiological sampling and analyses and radiological surveys at
all WWTPs accepting wastewater from O&G operations to determine if there are
areas of contamination that require remediation; if it is necessary to establish
radiological effluent discharge limitations; and if the development and
implementation of a spill policy is necessary."
The Marcellus shale formation is known to contain radium and, therefore, is of particular
concern for TENORM generation (172 DCN SGE00136; 28 DCN SGE00519; 150 DCN
SGE00587).
Rowan et al. (145 DCN SGE00241) report a positive correlation between IDS
concentrations and radium activity based on data for produced water from the Marcellus shale
and conventional formations in the Appalachian basin. Therefore, UOG formations containing
higher concentrations of TDS will likely also contain higher radium activity and, therefore, a
higher chance for TENORM accumulation in sludge. However, the existing literature contains
limited sampling data measuring radioactive constituents in UOG extraction wastewater (see
Table C-19). Therefore, the potential for TENORM accumulation in scale from UOG extraction
wastewater and the subsequent health risks to worker safety at POTWs are not fully known.
The 2015 PA DEP TENORM Study (135 DCN SGE01028) also looked into potential
worker exposure, TENORM disposal options, and environmental impacts. PA DEP analyzed
liquid and solid samples for alpha, beta, and gamma radiation and gas samples for radon. PA
DEP sampled the following types of facilities, among others, as part of their study:
• Well sites - PA DEP sampled 38 well sites (4 conventional wells and 34
unconventional wells) from June 2013 through July 2014; and
• Wastewater treatment plants - PA DEP sampled 29 wastewater treatment plants (10
POTWs, 10 CWT facilities, and 9 zero liquid discharge (ZLDs) facilities).
PA DEP presents sample data of filter cakes from POTWs receiving oil and gas
wastewater that showed "Ra-226 and Ra-228 present above typical background concentrations in
soil. The average Ra-226 result was 20.1 pCi/g with a large variance in the distribution, and the
maximum result was 55.6 pCi/g. The average Ra-228 result was 8.32 pCi/g, and the maximum
result was 32.0 pCi/g Ra-228." (135 DCN SGE01028)
PADEP concluded, "...[tjhere is little potential for radiological exposure to workers and
members of the public from handling and temporary storage of filter cake at POTW-I's130.
However, there is a potential for radiological environmental impacts from spills and the long-
term disposal of POTW-I filter cake" (135 DCN SGE01028). ERG's Radioactive Materials in
the Unconventional Oil and Gas (UOG) Industry memorandum (54 DCN SGE00933) provides
additional information and results from the PA DEP study.
130 PA DEP defines a "POTW-I" as a POTW that was considered to be influenced by having received wastewater
from the oil and gas industry.
140
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
5.3.3 Potential Impacts of DBF Precursors in VOG Extraction Wastewater
Disinfection, especially chlorination of drinking water and wastewater, is used to reduce
outbreaks of waterborne disease. As well as killing pathogenic microbes, though, disinfection
can produce a variety of toxic halo-organic compounds called DBFs. UOG extraction wastewater
often contains elevated levels of bromide (see Table C-13) and chloride, which is a precursor of
several toxic DBFs (15 DCN SGE00509; 214 DCN SGE00754). Brominated DBFs are reported
to have greater health risks (e.g., higher risk of cancer) than chlorinated DBFs (118 DCN
SGE00800).
UOG extraction wastewater discharged to POTWs would be a potential source of DBFs
in two scenarios:
• When UOG extraction wastewater is disinfected at a POTW (90 DCN SGE00535)
• When a POTW discharges wastewater including UOG extraction wastewater
pollutants to a river that is used as a source water for a downstream drinking water
treatment plant where disinfection is used (150 DCN SGE00587)
5.3.3.1 UOG Extraction Wastewater Disinfection at POTWs
DBFs can form within a POTW when disinfectants (e.g., chlorine, chloramine), natural
organic matter, and bromide or iodide react. Because UOG extraction wastewater contains high
concentrations of bromide (see Section C.2.2), treatment of UOG extraction wastewater at
POTWs with disinfection processes can create DBFs. Hladik et al. investigated whether POTW
treatment of wastewater from COG and UOG operations (hereafter referred to as "oil and gas
wastewater") could create DBFs, particularly brominated DBFs (90 DCN SGE00535).
Hladik et al. sampled effluent from three Pennsylvania POTWs, one POTW that did not
accept oil and gas wastewater (POTW 1) and two that accepted oil and gas wastewater from oil
and gas operators (POTW 2, POTW 3). The daily average discharge for POTW 1 was
approximately 1,200 MGD. The daily average discharges for POTWs 2 and 3 were not reported,
but the amount of oil and gas wastewater accepted at the POTWs was reported as ranging from
2.3 million gallons to 2.9 million gallons in 2012. Grab samples were collected in the river where
the POTW effluent entered and were analyzed for 29 DBFs.
Table D-25 presents sampling results showing higher concentrations of DBFs in the
majority of the effluent samples from POTWs that had accepted oil and gas wastewater from oil
and gas operators. Hladik et al.'s results show that COG and UOG extraction wastewater may
contribute to the formation of DBFs in chlorinated POTW effluent.
141
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-25. Concentrations of DBFs in Effluent Discharges at One POTW Not Accepting
Oil and Gas Wastewater and at Two POTWs Accepting Oil and Gas Wastewater (ug/L)
Facility Identifier
Sample Date
Accepted Oil and Gas Wastewater
Bromochloroiodomethane
Bromodichloro methane
Bromodiiodomethane
Bromoform
Chloroform
Dibromo-chloro-methane
Dibromoiodomethane
Dichloroiodomethane
POTW1
8/20/2012
No
ND
BDLb
ND
0.03
0.02
0.05
ND
ND
POTW1
11/28/2012
No
ND
ND
ND
0.04
0.05
0.05
ND
ND
POTW 2
4/17/2013
Yes
0.10
BDLb
0.09
10.1
0.20
0.83
0.98
BDLb
POTW 3
4/17/2013
Yes
0.12
BDLb
0.20
9.2
0.13
0.51
1.3
BDLb
MDLa
0.02
0.10
0.02
0.02
0.02
0.02
0.02
0.04
Source: 90 DCN SGE00535
Note: The EPA presents data for eight DBFs in Table D-25. Hladik et al. (90 DCN SGE00535) collected data for
29 DBFs. The concentrations of DBFs in the effluent of POTWs that had accepted oil and gas wastewater were
higher than the concentrations in POTWs that had not accepted oil and gas wastewater in all but three samples.
a—Method detection limits (MDLs) in surface water samples, as reported by Hladik et al. (90 DCN SGE00535).
b—Below method detection limit (BDL) indicates a value reported by Hladik et al. that was lower than the MDL.
The EPA reported these values as BDL instead of reporting the values from Hladik et al. (90 DCN SGE00535).
Abbreviation: ND—non detect
5.3.3.2 Drinking Water Treatment Disinfection Downstream of POTWs
DBFs form when disinfectants (e.g., chlorine), natural organic matter, and bromide or
iodide react. Therefore, they can form in drinking water treatment plants that use disinfection
processes. Beginning in 2008, researchers in Pennsylvania detected high concentrations of
bromide, a pollutant that facilitates the formation of toxic DBFs (e.g., brominated
trihalomethanes), downstream of POTWs that accepted UOG extraction wastewater (81 DCN
SGE00567; 150 DCN SGE00587).
Wilson and Van Briesen (226 DCN SGE00633) also investigated whether effluent
discharges from POTWs were causing high TDS and bromide concentrations that would
negatively impact drinking water treatment plants. They note that
Like TDS, bromide is not removed at drinking water treatment plants. Thus, produced
water management that leads to increased concentrations of bromide in source waters
for drinking water treatment plants can lead to increased concentrations of DBFs in
drinking water.
142
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Wilson and Van Briesen later conclude that
Produced water management decisions should be informed by the potential contribution
of this wastewater to the formation of disinfection by-products in downstream drinking
water treatment plants.
States et al. (150 DCN SGE00587) conducted a drinking water treatment plant survey
and investigated bromide concentrations in the untreated river water intake and trihalomethanes
(THMs) (i.e., chloroform, bromoform, dibromochloromethane, bromodicholoromethane) in the
treated, "finished" drinking water. States et al. drew the following conclusions from their study:
• Elevated bromide concentrations in the influent to the studied drinking water
treatment plant resulted in increased concentrations of certain DBFs, particularly
brominated THMs, in the drinking water.
• Drinking water treatment plants cannot effectively remove bromide from intake
water.
• POTWs discharging treated UOG extraction wastewater (specifically from the
Marcellus shale formation) were major contributors to the increase in bromide in the
drinking water treatment plant intake during the period of the study.
In February 2013, Eshelman and Elmore published a report for the Maryland Department
of the Environment titled Recommended Best Management Practices for Marcellus Shale Gas
Development in Maryland (69 DCN SGE00735). The report discussed POTW management of
UOG extraction wastewater and specifically noted that this is not a best management practice.
They further reported that the discharge of high-TDS loads into surface waters that could be
drinking water treatment intakes should be prohibited. Eshelman and Elmore state that,
Higher chloride levels cause taste and odor problems in finished water. High bromide
levels lead to increased formation of carcinogenic disinfectant by-products that can
persist in the water to the point of consumption. Treatment of produced water by POTWs
and other conventional wastewater treatment methods that do not remove salts should be
prohibited in Maryland.
McTigue et al. published an article about the occurrence and consequences of bromide in
drinking water sources (118 DCN SGE00800). They note that UOG extraction wastewater may
contribute to recent increases in bromide-containing waste upstream of drinking water utilities,
and thus to the increase in DBFs reported by the drinking water utilities. The authors provide an
example of an unnamed water treatment plant (WTP E) that began experiencing influent water
with high TDS concentrations in 2008, around the same time that UOG extraction operations
began in the area. Figure D-17 shows the average quarterly total THM speciation from 1999
through 2013, which shows a decrease in chlorinated DBFs and an increase in brominated DBFs
starting around 2008.
143
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
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-------
Chapter D—UOG Extraction Wastewater Management and Disposal Practices
In August 2013, EPA Region 3 issued a letter (187 DCN SGE00935) informing the
NPDES permitting authorities in the Mid-Atlantic region that
...conventional and nonconventional pollutants, such as bromide, must be tested by
existing dischargers as part of the permit application process if such pollutants are
expected to be present in effluent.
The letter goes on to state that EPA Region 3 has reason to believe that industrial
discharges (including UOG extraction wastewater discharges) containing bromide contributed to
elevated levels of bromide in rivers and streams that resulted in downstream impacts at drinking
water treatment plants, including increased occurrence of DBFs. Therefore, if the parameter is
not limited in an applicable ELG, NPDES permit applicants must either describe why the
parameter is expected in their discharges or include quantitative data for the parameter. These
requirements apply to the following parameters of interest in UOG extraction wastewater, among
others (195 DCN SGE00935.A01):
• TDS • Selenium, total
• Chloride • Benzene
• Bromide • Bromoform
• Sulfate • Chlorobenzene
• Fluoride • Chloroform
• Aluminum, total • Ethylbenzene
• Barium, total • Toluene
• Iron, total • Phenol
• Manganese, total • Naphthalene
• Radium-226/228 • Alpha-BHC
• Arsenic, total • Beta-BHC
Parker et al. published an article in September 2014 (129 DCN SGE00985) that evaluated
the minimum volume of UOG produced water from Marcellus shale and Fayetteville shale wells
that, when diluted by fresh water, would generate and/or alter the formation and speciation of
DBFs after chlorination, chloramination, and ozonation treatment.
Parker et al. suspect that, due to the increased salinity of UOG produced water, elevated
bromide and iodide in UOG produced water may promote the formation of DBFs. The results
show that UOG produced water dilution as low as 0.01 percent could result in altered speciation
toward the formation of brominated and iodinated DBFs. The results also show that UOG
produced water dilution as low as 0.03 percent increases the overall formation of DBFs. Parker
et al. suggest either eliminating UOG produced water discharges or installing halide-specific
removal techniques in CWT facilities and/or POTWs that are accepting UOG produced water for
treatment.
145
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Chapter E—Reference Flags and List
Chapter E. REFERENCE FLAGS AND LIST
The EPA reviewed existing data sources, including state and federal agency databases,
journal articles and technical papers, technical references, industry/vendor telephone queries, and
vendor websites to gather information for the TDD. The EPA identified all of the information
described in this TDD from these types of existing data sources, which are listed in Table E-l.
The EPA assigned one of the following data source quality flags to each of the sources
referenced in this TDD:
• Source quality flag "A": Journal articles and documents prepared by or for a
government agency (e.g., EPA site visit reports, industry meeting notes)
• Source quality flag "B": Documents prepared by a verified source that include
citation information (e.g., operator reports, vendor documents, university
publications)
• Source quality flag "C": Documents prepared by a verified source that do not
include citation information (e.g., operator reports, vendor documents, conference
presentations)
• Source quality flag "D": Documents prepared by a source that could not be verified
and that do not include citation information
Table E-l. Source List
ID
1
2
3
4
5
6
DCN
SGE00046
SGE00932
SGE00070
SGE00723
SGE00497
SGE00499
Source Citation
Abdalla, Charles W.; Drohan , Joy R.; Blunk, Kristen S.; Edson, Jessie. 2011.
Marcellus Shale Wastewater Issues in Pennsylvania — Current and Emerging
Treatment and Disposal Technologies. Perm State Cooperative Extension,
College of Agricultural Sciences.
Abt Associates. 2015. Profile of the Oil and Gas Extraction (OGE) Sector,
with Focus on Unconventional Oil and Gas (UOG) Extraction. (February 18).
Acharya, Harish; Matis, Hope; Kommepalli, Hareesh; Moore, Brian; Wang,
Hua. 201 1. Cost Effective Recovery of Low-TDS Frac Flowback Water for
Re-use. Prepared by GE Global Research. Prepared for US DOE NETL.
Morgantown, WV. (June).
Agency for Toxic Substances & Disease Registry (ATSDR). 2006. Hydrogen
Sulfide ToxFAQs. (July).
Angelo, Tom. 2013. From Pilot Study to Daily Processing: Warren, Ohio's
Documentary to Hydraulic Fracturing Water Treatment. City of Warren,
Ohio, Water Pollution Control Department. Presentation at EPA's Study of
Hydraulic Fracturing and Its Potential Impact on Drinking Water Resources:
Wastewater Treatment and Related Modeling Technical Workshop. April 18,
2013.
Arkansas Oil and Gas Commission (AOGC). 2013. Welcome to the Arkansas
Oil and Gas Commission Online Production and Well Information. Accessed
on 6/14/2013.
Source
Flag
B
A
A
A
A
A
146
-------
Chapter E—Reference Flags and List
Table E-l. Source List
ID
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
DCN
SGE00504
SGE00502
SGE00503
SGE00787
SGE00751
SGE00997
SGE00997.A01
SGE00750
SGE00509
SGE00110
SGE01009
SGE00966
SGE00367
SGE00305.A03
SGE00749
SGE01000
SGE00366
Source Citation
Baker Hughes. 2013. North America Rotary Rig Count (Jan 2000-Current).
(November 15). Downloaded on 11/20/2013. Available online at:
http://phx.corporate-ir.nef phoemx.zhtml?c=79687&p=irol-reportsother
Baker Hughes. 2013. North America Rotary Rig Count Pivot Table (Feb
2011-Current). (November 8). Downloaded on 11/11/2013. Available online
at: http://phx.corporate-ir.nef phoemx.zhtml?c=79687&p=irol-reportsother
Baker Hughes. 2013. U.S. Onshore Well Count. (October 11. Downloaded on
11/11/2013. Available online at: http://phx.corporate-
ir.net/phoenix. zhtml?c=79687&p=irol-wellcountus#
Borough of California. 2009. Borough of California Response to 308 Request
for Information. (March 18).
Borough of Charleroi. 2008. Re: Authority of the Borough of Charleroi
Administrative Order. (November 21).
Borough of Waynesburg. 2009. Clean Water Act Section 308 Request for
Information.
Borough of Waynesburg. 2009. Clean Water Act Section 308 Request for
Information — Attachment 1 : Acceptance Records.
Borough of Waynesburg. 2009. Waynesburg Response to Clean Water Act
Section 308 Request for Information. (March 3 1).
Brown, Daniel; Bridgeman, John; West, JohnR. 2011. Predicting Chlorine
Decay and THM Formation in Water Supply Systems. Reviews in
Environmental Science and Bio/Technology 10:79-99.
Bruff, Matthew. 201 1. An Integrated Water Treatment Technology Solution
for Sustainable Water Resource Management in the Marcellus Shale.
Prepared by Altela, Inc., Argonne National Laboratory, BLX, Inc., and CWM
Environmental, Inc. DE-FE0000833.
Caen, R., Darley, H.C.H., and G. R. Gray. 2011. Composition and Properties
of Drilling and Completion Fluids. 6th edition. Gulf Professional Publishing:
Waltham, MA.
California Council on Science and Technology (CCST). 2014. Advanced
Well Stimulation Technologies in California: An Independent Review of
Scientific and Technical Information. Sacramento, CA.
CARES. n.d. CARES McKean. Downloaded on 1/28/2013.
Cheung, Timothy. 2012. Identifying the Recycling and Treatment Criteria
That Must be Met to Avoid Scaling and Enable Successful Reuse. Shell.
City of Clarksburg. 2009. Re: Clean Water Act Section 308 Request for
Information. (March 2).
City of Wheeling Water Pollution Control Division. 2007. Wheeling Effluent
Data.
Clarion Altela Environmental Services (CAES). n.d. CAES Overview.
Downloaded on 1/28/2013.
Source
Flag
B
B
B
A
A
A
A
A
A
A
B
A
C
C
A
A
C
147
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Chapter E—Reference Flags and List
Table E-l. Source List
ID
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
DCN
SGE00354
SGE00182
SGE00516
SGE00357
SGE00519
SGE00520
SGE00331
SGE00989
SGE00988
SGE00984
SGE00708
SGE00522
SGE00244
SGE00245
SGE00521
SGE00283
SGE00705
SGE00736
SGE00736.A01
Source Citation
Clark, C.E.; Han, I; Burnham, A.; Dunn, J.B.; Wang, M. 2011. Life-Cycle
Analysis of Shale Gas and Natural Gas. Argonne National Laboratory.
ANL/ESD/11-11.
Clark, C.E.; Veil, J.A. 2009. Produced Water Volumes and Management
Practices in the United States. ANL/EVS/R-09/1. Argonne National
Laboratory. (September)
Cochener, John. 2010. Quantifying Drilling Efficiency. U.S. EIA, Office of
Integrated Analysis and Forecasting. (June 28).
Cramer, John. 2011. Post-frac Flowback Analysis and Reuse Implications.
Superior Well Services.
Davies, Peter J. n.d. Radioactivity. Cornell University.
Drillinginfo. 2011. DI Desktop® December 20 11 Download. Drillinginfo,
Inc.
Ely, John W.; Horn, Aaron; Cathey, Robbie; Fraim, Michael; Jakhete,
Sanjeev. 201 1. Game Changing Technology for Treating and Recycling Frac
Water. Society of Petroleum Engineering. SP SPE-214545-PP.
Energy Information Administration (EIA). 2014. Annual Energy Outlook
2014 with Projections to 2040. DOE/EIA-0383(2014).
Energy Information Administration (EIA). 2014. Assumptions to the Annual
Energy Outlook 20 14.
Energy Information Administration (EIA). 2014. Glossary. Retrieved from
http ://www. eia. gov/tools/glossary
Environmental Leader. 2013. Unconventional E&P "$8 Billion of US Water
Services Market." (November 11).
Environmental Review Appeals Commission, State of Ohio. 2012. Patriot
Water Treatment, LLC, and City of Warren v. Chris Korleski, Director of
Environmental Protection, and Scott Nally, Director of Environmental
Protection: 2012 Decision.
ERG. 2012. Camp, Meghan; Bicknell, Betsy; Ruminski, Brent. Notes on
Conference Call with 212 Resources on 4 January 2012. (January 9).
ERG. 2012. Camp, Meghan; Bicknell, Betsy; Ruminski, Brent. Notes on
Conference Call with Reserved Environmental Services, LLC on 5 January
2012. (February 1).
ERG. 2012. Camp, Meghan; Ruminski, Brent. Notes for Shale Gas Industry
Meeting Held on 29 February 2012. (April 20).
ERG. 2012. Camp, Meghan; Ruminski, Brent. Notes on Conference Call with
BLX, Inc on 15 May 2012. (June 11).
ERG. 2014. Ruminski, Brent. Notes on Call with Hydrozonix, LLC on 7
February 2014. (March 7.)
ERG. 2015. Analysis of Active Underground Injection for Disposal Wells.
ERG. 2015. Analysis of Active Underground Injection for Disposal Wells —
Attachment 1: Injection for Disposal Well Data.
Source
Flag
A
A
A
B
B
B
A
A
A
A
B
A
A
A
A
A
A
A
A
148
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Chapter E—Reference Flags and List
Table E-l. Source List
ID
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
DCN
SGE00596
SGE00596.A01
SGE00963
SGE00739
SGE00739.A03
SGE00693
SGE00693.A01
SGE00693.A02
SGE00693.A03
SGE00929
SGE00929.A01
SGE00933
SGE00740
SGE00724
SGE00724.A01
SGE00724.A02
Source Citation
ERG. 2015. Analysis of Centralized Waste Treatment (CWT) Facilities
Accepting UOG Extraction Wastewater.
ERG. 2015. Analysis of Centralized Waste Treatment Facilities (CWTs)
Accepting UOG Wastewater Attachment 1: UOG CWT List and Analysis.
ERG. 2015. Analysis of DI Desktop® Memorandum.
ERG. 2015. Analysis of Pennsylvania Department of Environmental
Protection's (PA DEP) Oil and Gas Waste Reports.
ERG. 2015. Analysis of Pennsylvania Department of Environmental
Protection's (PA DEP) Oil and Gas Waste Reports.
ERG. 2015. Data Compilation Memorandum for the Technical Development
Document (TDD) for Proposed Effluent Limitations Guidelines and
Standards for Oil and Gas Extraction. Office of Water Engineering and
Analysis Division.
ERG. 2015. Data Compilation Memorandum for the Technical Development
Document (TDD) for Proposed Effluent Limitations Guidelines and
Standards for Oil and Gas Extraction — Attachment 1 : Onshore Oil and Gas
Drilling Activity.
ERG. 2015. Data Compilation Memorandum for the Technical Development
Document (TDD) for Proposed Effluent Limitations Guidelines and
Standards for Oil and Gas Extraction — Attachment 2: El A UOG Resource
Potential.
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SGE00724.A03
SGE00724.A04
SGE00724.A05
SGE00724.A06
SGE00724.A07
SGE00724.A08
SGE00724.A09
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SGE00735
SGE00780
SGE00525
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SGE00760
SGE00528
SGE01077
SGE00010
SGE00344
SGE00286
SGE00567
SGE00531
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SGE00414
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SGE00756
SGE00379
SGE00535
SGE00333
SGE00707
SGE00476
SGE00728
SGE00722
SGE00769
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DCN
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SGE00758
SGE00745
SGE00345
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SGE00543
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SGE00552
SGE00709
SGE00644
SGE00090
SGE00556
SGE00639
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ID
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
DCN
SGE01028
SGE00575
SGE00748
SGE00139
SGE00579
SGE00374
SGE00768.A01
SGE00583
SGE00986
SGE00987
SGE00241
SGE00291
SGE00731
SGE00710
SGE00586
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164
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DCN
SGE00350
SGE00768.A26
SGE00592
SGE00593
SGE00594
SGE00155
SGE00153
SGE00487
SGE00595
SGE00761
SGE00599
SGE01006
SGE00601
SGE00600
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167
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169
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172
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175
176
177
178
179
180
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183
184
185
DCN
SGE00138
SGE00604
SGE00620
SGE00982
SGE00249
SGE00136
SGE00132
SGE00368
SGE00608
SGE00279
SGE00276
SGE00635
SGE00275
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SGE00299
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U.S. EPA. 2013. DMR Loading Tool Download for New Castle POTW
(NPDES No. PA0027511). Downloaded on 117 22/2013.
Source
Flag
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A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
157
-------
Chapter E—Reference Flags and List
Table E-l. Source List
ID
186
187
188
189
190
191
192
193
194
195
196
197
198
199
200
201
202
203
204
DCN
SGE00726
SGE00935
SGE00613
SGE00615
SGE00280
SGE00625
SGE00743
SGE00616
SGE00691
SGE00935.A01
SGE00762
SGE00585
SGE00766
SGE00783
SGE00786
SGE00721
SGE00785
SGE00692
SGE00622
Source Citation
U.S. EPA. 2013. Email Chain between Jacqueline Rios, Frank Brock, and
Lisa Biddle About UICs in NY Taking Oil and Gas Wastewater. (November
13).
U.S. EPA. 2013. Letter to Lee McDonnell, PA DEP, Informing NPDES
Permitting Authorities of Testing as Part of the Permit Application Process.
(August 28).
U.S. EPA. 2013. Meeting Summary: Meeting with Industry Representatives
About the Unconventional Oil and Gas Effluent Guideline Rulemaking.
(February 28).
U.S. EPA. 2013. Radionuclides in Drinking Water: Waste Disposal Options.
(November 26).
U.S. EPA. 2013. Site Visit Report: Anadarko Petroleum Corporation
Marcellus Shale Gas Operations. (January 9).
U.S. EPA. 2013. Site Visit Report: Southwestern Energy (SWN) Fayetteville
Shale Gas Operations Sanitized.
U.S. EPA. 2013. States Pretreatment Coordinators' Bi-monthly Conference
Call. (August 14).
U.S. EPA. 2013. Summary of the Technical Workshop on Wastewater
Treatment and Related Modeling. (April 18).
U.S. EPA. 2013. Summary of the Technical Workshop on Water Acquisition
Modeling: Assessing Impacts Through Modeling and Other Means.
(September).
U.S. EPA. 2013. Toxic Screening Analysis Spreadsheet.
U.S. EPA. 2013. US EPA Technology Innovation Project: ECOS/ACWA
Conference Call. (April 25).
U.S. EPA. 2014. FracFocus Database. Office of Research and Development
(ORD).
U.S. EPA. 2014. Lockhart, John V. Email Correspondence between WV DEP
and EPA. (June 3).
U.S. EPA. 2014. Thorium. (February 28). Available online at:
http ://www. epa. gov/radiation/radionuclides/thorium. html
U.S. EPA. 2014. UOG Workgroup— Warren, OH POTW Info Request. (June
19).
U.S. EPA. 2015. Evaluation of Hydraulic Fracturing Fluid Data from the
FracFocus Chemical Disclosure Registry 1.0. (March).
U.S. EPA. 2015. Summary of Tribal Outreach Regarding Pretreatment
Standards for Unconventional Oil and Gas (UOG) Extraction Wastewater.
U.S. EPA. 2015. Unconventional Oil & Gas (UOG) Extraction Wastewater
Treatment Technologies.
U.S. Geological Survey (USGS). 2013. Water Resources and Shale Gas/Oil
Production in the Appalachian Basin — Critical Issues and Evolving
Developments. (August). Available online at:
http://pubs.usgs.gov/of/2013/! 137/pdf/ofr2013-l 137.pdf
Source
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A
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A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
A
158
-------
Chapter E—Reference Flags and List
Table E-l. Source List
ID
205
206
207
208
209
210
211
212
213
214
215
216
217
218
DCN
SGE00956
SGE00623
SGE00624
SGE00095
SGE01095
SGE01095.A09
SGE00114
SGE00011
SGE00093
SGE00754
SGE00627
SGE00629
SGE00295
SGE00767
Source Citation
U.S. Geological Survey (USGS). 2014. National Produced Waters
Geochemical Database v2.0 (Provisional).
U.S. Government Accountability Office (GAO). 2012. Energy-Water-Nexus:
Information on the Quantity, Quality, and Management of Water Produced
During Oil and Gas Production. (January). GAO-12-156.
University of Michigan. 2013. Hydraulic Fracturing in the State of Michigan.
Graham Sustainability Institute Integrated Assessment Report Series.
(September).
URS. 201 1. Water-Related Issues Associated with Gas Production in the
Marcellus Shale. (March 25).
USGS. 2015. Trends in Hydraulic Fracturing Distributions & Trt Fluids,
Additives, Proppants, & Water Volumes Applied to US Wells Drilled, 1947-
2010.
USGS. 2015. Trends in Hydraulic Fracturing Distributions & Trt Fluids,
Additives, Proppants, & Water Volumes Applied to US Wells Drilled, 1947-
2010: Attachment 9: Frac Trim Type.xlsx
Van Dyke, Staffan. 2010. Tight Gas Sandstone: Is It Truly Unconventional?
Oil & Gas Evaluation Report. (October).
Veil, John A. 2010. Water Management Technologies Used by Marcellus
Shale Gas Producers. Prepared by Argonne National Laboratory. Prepared for
U.S. DOE NETL. (July). Available at:
http ://www. mde . state . md.us/programs/Land/mining/marcellus/DocumentsAV
aterMgmtinMarcellusfull.pdf
Veil, John; Puder, Markus G.; Elcock, Deborah; Redweik, Robert J. 2004. A
White Paper Describing Produced Water from Production of Crude Oil,
Natural Gas, and Coal Bed Methane. Prepared by Argonne National
Laboratory. Prepared for U.S. DOE NETL. (January).
Vengosh, A.; Jackson, Robert B.; Warner, N.; Darrah, Thomas H.; Kondash,
A. 2014. A Critical Review of the Risks to Water Resources from
Unconventional Shale Gas Development and Hydraulic Fracturing in the
United States. Environmental Science & Technology 48(15):8334-8348.
Vidic, Radisav; Brantley, S.L.; Vandenbossche, J.M.; Yoxtheimer, D.; Abad,
J.D. 2013. Impact of Shale Gas Development on Regional Water Quality.
Science 340(6134).
Warner, Nathaniel R.; Christie, Cidney A.; Jackson, Robert B.; Vengosh,
Avner. 2013. Impacts of Shale Gas Wastewater Disposal on Water Quality in
Western Pennsylvania. Environmental Science & Technology 47(20): 11849-
11857.
Warren Water Pollution Control Facility. 201 1. Fact Sheet for NPDES Permit
Renewal, Warren Water Pollution Control Facility, 201 1-2012. City of
Warren.
West Virginia Department of Environmental Protection (WV DEP). 20 10.
Letter to City of Follansbee Re: WV/NPDES Permit No. WV0020273
Accepting Oil and Gas Wastewater. (December 15).
Source
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A
A
B
B
A
A
C
A
A
A
B
A
A
A
159
-------
Chapter E—Reference Flags and List
Table E-l. Source List
ID
219
220
221
222
223
224
225
226
227
228
DCN
SGE00485
SGE00488
SGE01113
SGE01114
SGE00554
SGE00064
SGE00632
SGE00633
SGE00725
SGE00774
Source Citation
West Virginia Department of Environmental Protection (WV DEP). 201 1.
Consent Order Issued Under the Water Pollution Control Act, West Virginia
Code, Chapter 22, Article 11.
West Virginia Department of Environmental Protection (WV DEP). 2012.
NPDES Water Pollution Control Permit WV01 16441. Reserved
Environmental Services CWT Permit.
West Virginia Department of Environmental Protection (WV DEP). 2009.
WV/NPDES Permit No WV0023302 Clarksburg Sanitary Board Accepting
Oil and Gas Wastewater.
West Virginia Department of Environmental Protection (WV DEP). 2009.
WV/NPDES Permit No, WV0023230 City of Wheeling Accepting Oil and
Gas Wastewater.
Widmer Engineering, Inc. 2010. New Castle Sanitation Authority, New
Castle, Lawerance County, Pennsylvania: Annual Pretreatment Report, 2009
Operating Year. Prepared for New Castle Sanitation Authority.
Williams, John. 2011. Marcellus Shale-Gas Development and Water-
Resource Issues. USGS: New York Water Science Center.
Williams, John. n.d. The Marcellus Shale Gas Play: Geology, Development,
and Water-Resource Impact Mitigation. USGS: New York Water Science
Center.
Wilson, Jessica; VanBriesen, Jeanne. 2013. Oil and Gas Produced Water
Management and Surface Drinking Water Sources in Pennsylvania.
Environmental Practice 14(4):288-300.
Wolford, Robert. 2011. Characterization of Organics in the Marcellus Shale
Flowback and Produced Waters. Pennsylvania State University. Master's
Thesis. (August).
Ziemkiewicz, Paul. 2013. Water Quality Literature Review and Field
Monitoring of Active Shale Gas Wells. Phase I: Assessing Environmental
Impacts of Horizontal Gas Well Drilling Operations. West Virginia
Department of Environmental Protection. (February 15).
Source
Flag
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A
A
A
A
A
A
A
B
A
160
-------
Chapter F—Appendices
Chapter F. APPENDICES
APPENDIX F.I REFERENCE FILES IN FDMS
Table F-l. TDD Supporting Memoranda and Other Relevant Documents Available in
FDMS
DCN
SGE00596
SGE00692
SGE00693
SGE00724
SGE00736
SGE00739
SGE00740
Title
Analysis of Centralized
Waste Treatment (CWT)
Facilities Accepting UOG
Extraction Wastewater
Unconventional Oil and Gas
(UOG) Extraction
Wastewater Treatment
Technologies
Data Compilation
Memorandum for the
Technical Development
Document (TDD) for
Proposed Effluent
Limitations Guidelines and
Standards for Oil and Gas
Extraction
Unconventional Oil and Gas
(UOG) Produced Water
Volumes and
Characterization Data
Compilation
Analysis of Active
Underground Injection for
Disposal Wells
Analysis of Pennsylvania
Department of Environmental
Protection's (PA DEP) Oil
and Gas Waste Reports
Unconventional Oil and Gas
(UOG) Drilling Wastewater
Description
Describes the various data sources used to
identify CWT facilities that have accepted
UOG wastewater and explains the different
CWT facility analyses that are presented in
Section D. 4 of the TDD.
Summarizes technologies that are currently
used to treat UOG wastewater at full-scale
operations and technologies not currently used
to treat UOG extraction wastewater, but which
may be applied in the future.
Explains various data analyses presented in
Chapters B, C, and D of the TDD, involving
well drilling and construction, historical and
current drilling activity, UOG resource
potential, fracturing fluid chemical additives,
and reuse/recycle.
Describes the various data sources used to
identify UOG wastewater volumes and
characteristics data and explains the process
that was used to standardize and summarize
the data.
Explains the compilation of underground
injection wells data from various sources.
Explains the PA DEP waste reports data and
explains the processes that were used to
analyze the data.
Explains the well drilling process in more
detail, with focus on drilling wastewater
volumes and constituent concentrations.
Relevant TDD
Section(s)
D.1,D.4
D.3
B.3, C.Intro, C.I,
C.2,D.1,D.2,
D.3
B.3, C.Intro, C.2,
C.3
D.1,D.2,D.4
C.2,D.1,D.5
B.2, C.2, C.3,
D.I
161
-------
Chapter F—Appendices
Table F-l. TDD Supporting Memoranda and Other Relevant Documents Available in
FDMS
DCN
SGE00785
SGE00929
SGE00932
SGE00933
SGE00963
SGE01016
Title
Summary of Tribal Outreach
Regarding Pretreatment
Standards for Unconventional
Oil and Gas (UOG)
Extraction Wastewater
Publicly Owned Treatment
Works (POTW)
Memorandum for the
Technical Development
Document (TDD) for
Proposed Effluent
Limitations Guidelines and
Standards for Oil and Gas
Extraction
Profile of the Oil and Gas
Extraction (OGE) Sector,
with Focus on
Unconventional Oil and Gas
(UOG) Extraction
Radioactive Materials in the
Unconventional Oil and Gas
(UOG) Industry
Analysis of DI Desktop®
Conventional Oil and Gas
(COG) Memorandum for the
Record
Description
Summarizes the data collected as part of the
tribal outreach efforts associated with the
proposed rule.
Describes the various data sources used to
identify POTWs that have accepted UOG
wastewater and explains the different POTW
analyses that are presented in Section D.5 of
the TDD.
Provides economic background information
about the oil and gas industry.
Provides background information about
radioactive elements in the UOG industry,
with focus on radium-226 and radium-228.
Summarizes the DI Desktop® data source and
where it is cited throughout the proposed rule
analyses.
Summarizes COG extraction wastewater
characteristics and management and disposal
practices used for COG extraction wastewater.
Relevant TDD
Section(s)
D.5
D.5
B.Intro
C.3,D.5
B.3.2
N/A
N/A—Not Applicable
162
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table
or Figure
Number
Figure A-l
Table A-l
Figure B-l
Figure B-2
Figure B-3
Figure B-4
Figure B-5
Figure B-6
Figure B-7
Figure B-8
Figure B-9
Figure B-10
Figure B- 11
Figure B-12
Figure B-13
TDD Table/Figure Title
UOG Extraction Wastewater
Summary of State Regulations
Historical and Projected Oil Production by
Resource Type
Historical and Projected Natural Gas
Production by Resource Type
Major U.S. Shale Plays (Updated May 9, 2011)
Major U.S. Tight Plays (Updated June 6, 2010)
Geology of Formations Containing Various
Hydrocarbons
Horizontal (A), Vertical (B), and Directional
(C) Drilling Schematic
Length of Time to Drill a Well in Various
UOG Formations
Hydraulic Fracturing Schematic
Freshwater Impoundment
Vertical Gas and Water Separator
Fracturing Tanks
Produced Water Storage Tanks
Number of Active U.S. Onshore Rigs by
Trajectory and Product Type over Time
In a
Supporting
Memo
(Y/N)?a
No (Created
by the EPA)
No
No
No
No
No
No
No
Yes
No
No
No
No
No
Yes
Source or Supporting
Memo DCN(s)
—
SGE00187, SGE00254,
SGE00545, SGE00766,
SGE00767, SGE00982,
SGE00983
SGE00487
SGE00989
SGE00153
SGE00155
SGE00594
SGE00593
SGE00693
SGE00604
SGE00275
SGE00625
SGE00625
SGE00275
SGE00693
Supporting Memo Title(s)
—
—
—
—
—
—
—
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
—
—
—
—
—
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
163
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table
or Figure
Number
Figure B-14
Table B-l
Table B-2
Table B-3
Figure C-l
Figure C-2
Figure C-3
Figure C-4
Figure C-5
TDD Table/Figure Title
Projections of UOG Well Completions
Characteristics of Reservoirs Containing UOG
and COG Resources
Active Onshore Oil and Gas Drilling Rigs by
Well Trajectory and Product Type (as of
Novembers, 2013)
UOG Potential by Resource Type as of January
1,2012
UOG Extraction Wastewater Volumes for
Marcellus Shale Wells in Pennsylvania (2004-
2013)
Ranges of Typical Produced Water Generation
Rates over Time After Fracturing
Anions and Cations Contributing to TDS
Concentrations in Shale and Tight Oil and Gas
Formations
Chloride, Sodium, and Calcium Concentrations
in Flowback and Long-Term Produced Water
(LTPW) from Shale and Tight Oil and Gas
Formations
Barium Concentrations in UOG Produced
Water from Shale and Tight Oil and Gas
Formations
In a
Supporting
Memo
(Y/N)?a
Yes
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Source or Supporting
Memo DCN(s)
SGE00693
SGE00114, SGE00345,
SGE00527, SGE00533
SGE00693
SGE00693
SGE00739
SGE00724
SGE00724
SGE00724
SGE00724
Supporting Memo Title(s)
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
—
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
Analysis of Pennsylvania Department of Environmental
Protection's (PA DEP) Oil and Gas Waste Reports
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
164
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table
or Figure
Number
Figure C-6
Table C-l
Table C-2
Table C-3
Table C-4
Table C-5
Table C-6
Table C-7
Table C-8
Table C-9
Table C-10
TDD Table/Figure Title
Constituent Concentrations over Time in UOG
Produced Water from the Marcellus and
Barnett Shale Formations
Sources for Base Fluid in Hydraulic Fracturing
Fracturing Fluid Additives, Main Compounds,
and Common Uses
Most Frequently Reported Additive Ingredients
Used in Fracturing Fluid in Gas and Oil Wells
from FracFocus (20 1 1 -20 1 3)
Median Drilling Waste water Volumes for
UOG Horizontal and Vertical Wells in
Pennsylvania
Drilling Wastewater Volumes Generated per
Well by UOG Formation
UOG Well Flowback Recovery by Resource
Type and Well Trajectory
Long-Term Produced Water Generation Rates
by Resource Type and Well Trajectory
Produced Water Volume Generation by UOG
Formation
Availability of Data for UOG Extraction
Wastewater Characterization
Concentrations of Select Classical and
Conventional Constituents in UOG Drilling
Wastewater from Marcellus Shale Formation
Wells
In a
Supporting
Memo
(Y/N)?a
No
Yes
No
Yes
Yes
Yes
Yes
Yes
Yes
No (Created
by the EPA)
Yes
Source or Supporting
Memo DCN(s)
SGE00414
SGE00693
SGE00070, SGE00721,
SGE00780, SGE00781,
SGE00966
SGE00693
SGE00739
SGE00740
SGE00724
SGE00724
SGE00724
—
SGE00740
Supporting Memo Title(s)
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
Analysis of Pennsylvania Department of Environmental
Protection's (PA DEP) Oil and Gas Waste Reports
Unconventional Oil and Gas (UOG) Drilling Wastewater
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
—
Unconventional Oil and Gas (UOG) Drilling Wastewater
165
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table
or Figure
Number
Table C-ll
Table C-12
Table C-13
Table C-14
Table C-15
Table C-16
Table C-17
Table C-18
Table C-19
Table C-20
Figure D-l
TDD Table/Figure Title
Concentrations of Select Classical and
Conventional Constituents in UOG Produced
Water
Concentrations of Select Anions and Cations
Contributing to TDS in UOG Drilling
Wastewater from Marcellus Shale Formation
Wells
Concentrations of Select Anions and Cations
Contributing to TDS in UOG Produced Water
Concentrations of Select Organic Constituents
in UOG Drilling Wastewater from Marcellus
Shale Formation Wells
Concentrations of Select Organic Constituents
in UOG Produced Water
Concentrations of Select Metal Constituents in
UOG Drilling Wastewater from Marcellus
Shale Formation Wells
Concentrations of Select Metal Constituents in
UOG Produced Water
Concentrations of Select Radioactive
Constituents in UOG Drilling Wastewater from
Marcellus Shale Formation Wells
Concentrations of Select Radioactive
Constituents in UOG Produced Water
Concentrations of Radioactive Constituents in
Rivers, Lakes, Groundwater, and Drinking
Water Sources Throughout the United States
(pCi/L)
UOG Produced Water Management Methods
In a
Supporting
Memo
(Y/N)?a
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No (Created
by the EPA)
Source or Supporting
Memo DCN(s)
SGE00724
SGE00740
SGE00724
SGE00740
SGE00724
SGE00740
SGE00724
SGE00740
SGE00724
SGE00769
—
Supporting Memo Title(s)
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
Unconventional Oil and Gas (UOG) Drilling Wastewater
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
Unconventional Oil and Gas (UOG) Drilling Wastewater
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
Unconventional Oil and Gas (UOG) Drilling Wastewater
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
Unconventional Oil and Gas (UOG) Drilling Wastewater
Unconventional Oil and Gas (UOG) Produced Water
Volumes and Characterization Data Compilation
—
166
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table
or Figure
Number
Figure D-2
Figure D-3
Figure D-4
Figure D-5
Figure D-6
Figure D-7
Figure D-8
Figure D-9
Figure D-10
Figure D- 11
TDD Table/Figure Title
UOG Drilling Wastewater Management
Methods
Management of UOG Drilling Wastewater
Generated by UOG Wells in Pennsylvania
(2008-2013)
Active Disposal Wells and CWT Facilities
Identified in the Appalachian Basin
Flow Diagram of On-the-Fly UOG Produced
Water Treatment for Reuse/Recycle
Hypothetical UOG Produced Water Generation
and Base Fracturing Fluid Demand over Time
UOG Extraction Wastewater Management
Practices Used in the Marcellus Shale (Top:
Southwestern Region; Bottom: Northeastern
Region)
Number of Known Active CWT Facilities over
Time in the Marcellus and Utica Shale
Formation
Typical Process Flow Diagram at a POTW
Clairton POTW: Technical Evaluation of
Treatment Processes' Ability to Remove
Chlorides and TDS
McKeesport POTW: Technical Evaluation of
Treatment Processes' Ability to Remove
Chlorides and TDS
In a
Supporting
Memo
(Y/N)?a
No (Created
by the EPA)
Yes
No (Created
by the EPA)
No
Yes
No
Yes
No
Yes
Yes
Source or Supporting
Memo DCN(s)
—
SGE00739
—
SGE00331
SGE00693
SGE00579
SGE00596
SGE00602
SGE00929
SGE00929
Supporting Memo Title(s)
—
Analysis of Pennsylvania Department of Environmental
Protection's (PA DEP) Oil and Gas Waste Reports
—
—
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
Analysis of Centralized Waste Treatment (CWT)
Facilities Accepting UOG Extraction Wastewater
—
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical Development Document
(TDD) for Proposed Effluent Limitations Guidelines and
Standards for Oil and Gas Extraction
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical Development Document
(TDD) for Proposed Effluent Limitations Guidelines and
Standards for Oil and Gas Extraction
167
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table
or Figure
Number
Figure D-12
Figure D-13
Figure D-14
Figure D-15
Figure D-16
Figure D-17
Table D-l
Table D-2
Table D-3
TDD Table/Figure Title
Ridgway POTW: Annual Average Daily
Effluent Concentrations and POTW Flows
Johnstown POTW: Annual Average Daily
Effluent Concentrations and POTW Flows
California POTW: Annual Average Daily
Effluent Concentrations and POTW Flows
Charleroi POTW: Annual Average Daily
Effluent Concentrations and POTW Flows
Barium Sulfate Scaling in Haynesville Shale
Pipe
THM Speciation in a Water Treatment Plant
(1999-2013)
UOG Produced Water Management Practices
Distribution of Active Class II Disposal Wells
Across the United States
Reuse/Recycle Practices in 2012 as a
Percentage of Total Produced Water Generated
as Reported by Respondents to 2012 Survey
In a
Supporting
Memo
(Y/N)?a
Yes
Yes
Yes
Yes
No
No
Yes
Yes
No
Source or Supporting
Memo DCN(s)
SGE00929
SGE00929
SGE00929
SGE00929
SGE00768.A26
SGE00800
SGE00693
SGE00736
SGE00575
Supporting Memo Title(s)
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical Development Document
(TDD) for Proposed Effluent Limitations Guidelines and
Standards for Oil and Gas Extraction
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical Development Document
(TDD) for Proposed Effluent Limitations Guidelines and
Standards for Oil and Gas Extraction
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical Development Document
(TDD) for Proposed Effluent Limitations Guidelines and
Standards for Oil and Gas Extraction
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical Development Document
(TDD) for Proposed Effluent Limitations Guidelines and
Standards for Oil and Gas Extraction
—
—
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
Analysis of Active Underground Injection for Disposal
Wells
168
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table
or Figure
Number
Table D-4
Table D-5
Table D-6
Table D-7
Table D-8
Table D-9
Table D-10
Table D- 11
Table D-12
Table D-13
Table D-14
TDD Table/Figure Title
Reported Reuse/Recycle Criteria
Reported Reuse/Recycle Practices as a
Percentage of Total Fracturing Volume
Number, by State, of CWT Facilities That
Have Accepted or Plan to Accept UOG
Extraction Wastewater
Typical Composition of Untreated Domestic
Wastewater
Typical Percent Removal Capabilities from
POTWs with Secondary Treatment
U.S. POTWs by Treatment Level in 2008
POTWs That Accepted UOG Extraction
Wastewater from Onshore UOG Operators
Percentage of Total POTW Influent
Wastewater Composed of UOG Extraction
Wastewater at POTWs Accepting Wastewater
from UOG Operators
Summary of Studies About POTWs Receiving
Oil and Gas Extraction Wastewater Pollutants
Clairton Influent Oil and Gas Extraction
Wastewater Characteristics
Trucked COG Extraction Wastewater Treated
at McKeesport POTW from November 1
Through 7, 2008
In a
Supporting
Memo
(Y/N)?a
Yes
Yes
Yes
No
No
No
Yes
Yes
No (Created
by the EPA)
No
No
Source or Supporting
Memo DCN(s)
SGE00693
SGE00693
SGE00596
SGE00167
SGE00600
SGE00603
SGE00929
SGE00929
—
SGE00748
SGE00745
Supporting Memo Title(s)
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
Analysis of Centralized Waste Treatment (CWT)
Facilities Accepting UOG Extraction Wastewater
—
—
—
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical Development Document
(TDD) for Proposed Effluent Limitations Guidelines and
Standards for Oil and Gas Extraction
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical Development Document
(TDD) for Proposed Effluent Limitations Guidelines and
Standards for Oil and Gas Extraction
—
—
169
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table
or Figure
Number
Table D-15
Table D-16
Table D-17
Table D-18
Table D-19
Table D-20
Table D-21
Table D-22
Table D-23
Table D-24
Table D-25
Figure F-l
TDD Table/Figure Title
McKeesport POTW Removal Rates Calculated
for Local Limits Analysis
Constituent Concentrations in UOG Extraction
Wastewater Treated at the McKeesport POTW
Before Mixing with Other Influent Wastewater
McKeesport POTW Effluent Concentrations
With and Without UOG Extraction Wastewater
Charleroi POTW Paired Influent/Effluent Data
and Calculated Removal Rates
Franklin Township POTW Effluent
Concentrations With and Without Industrial
Discharges from the Tri-County CWT Facility
TDS Concentrations in Baseline and Pilot
Study Wastewater Samples at Warren POTW
EPA Region 5 Compliance Inspection
Sampling Data
Inhibition Threshold Levels for Various
Treatment Processesa
Industrial Wastewater Volumes Received by
New Castle POTW (2007-2009)
NPDES Permit Limit Violations from Outfall
001 of the New Castle POTW (NPDES Permit
Number PA00275 11)
Concentrations of DBFs in Effluent Discharges
at One POTW Not Accepting Oil and Gas
Wastewater and at Two POTWs Accepting Oil
and Gas Wastewater (ug/L)
Constituent Concentrations over Time in UOG
Produced Water from the Marcellus and
Barnett Shale Formations
In a
Supporting
Memo
(Y/N)?a
No
No
No
No
No
No
No
No
No
No
No
No
Source or Supporting
Memo DCN(s)
SGE00745
SGE00525
SGE00525
SGE00751
SGE00525
SGE00616
SGE00616
SGE00602
SGE00554
SGE00612, SGE00620
SGE00535
SGE00414
Supporting Memo Title(s)
—
—
—
—
—
—
—
170
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table
or Figure
Number
Table F-l
Table F-2
Table F-3
Table F-4
TDD Table/Figure Title
TDD Supporting Memoranda and Other
Relevant Documents Available in FDMS
Crosswalk Between TDD and Supporting
Memoranda
UOG Resource Potential: Shale as of January
1,2012
UOG Resource Potential: Tight as of January
1,2012
In a
Supporting
Memo
(Y/N)?a
No (Created
by the EPA)
No (Created
by the EPA)
Yes
Yes
Source or Supporting
Memo DCN(s)
—
—
SGE00693
SGE00693
Supporting Memo Title(s)
—
—
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
Data Compilation Memorandum for the Technical
Development Document (TDD) for Proposed Effluent
Limitations Guidelines and Standards for Oil and Gas
Extraction
a—Unless otherwise noted, figures and/or tables not included in a supporting memorandum were taken directly from a source without calculation or interpretation.
171
-------
Chapter F—Appendices
APPENDIX F.2 UOG RESOURCE POTENTIAL BY SHALE AND TIGHT FORMATIONS
Table F-3. UOG Resource Potential: Shale as of January 1, 2012
EIA Region
i iiast
2— Gulf Coast
4 Southwest
EIA Basin
Illinois
Michigan
Black Warrior
TX-LA-MS Salt
Western Gulf
Arkoma
Black Warrior
Barnett
Permian
Denver
Greater Green River
UOG Formation
Name
Devonian
Marcellus
uuca
New Albany
Antrim
Floyd-Neal/Conasauga
Haynesville-Bossier
Pearsall
Tuscaloosa
Woodbine
Caney
Fayetteville
Woodford
Chattanooga
Shale Gas
Wolfcamp
Barnett- Woodford
Avalon/BoneSpring
Niobrara
Hilliard-Baxter-Mancos
Resource
Type
Shale gas
Shale gas
Shale gas
Shale oil
Shale gas
Shale gas
Shale gas
Shale gas
Shale gas
Shale oil
Shale gas
Shale oil
Shale oil
Shale gas
Shale oil
Shale gas
Shale gas
Shale gas
Shale gas
Shale gas
Shale oil
Shale gas
Shale oil
Shale oil
Shale gas
Oil EUR (MMbls
per well)
0.000
0.000
0.000
0.063
0.000
0.000
0.000
0.000
0.177
0.101
0.000
0.092
0.108
0.014
0.038
0.000
0.000
0.000
0.000
0.000
0.068
0.000
0.080
0.011
0.000
Gas EUR
(Bcf per
well)
0.058
1.317
0.330
0.057
1.721
0.157
1.520
3.455
1.549
0.212
1.090
0.019
0.054
1.232
0.415
0.330
1.284
1.422
0.970
0.377
0.217
1.513
0.000
0.073
0.293
OilTRR
(MMbls)
0
0
0
1,000
0
0
0
0
6,100
3,300
0
2,900
600
100
100
0
0
0
0
0
3,400
0
2,000
400
0
GasTRR
(Bcf)
20,800
118,900
37,400
900
41,700
15,300
4,300
70,900
53,400
6,900
7,800
600
300
8,900
1,100
1,100
29,800
6,700
1,600
20,300
10,900
15,800
0
2,700
10,500
New Well
Potential
358,600
90,300
113,500
15,900
24,200
97,500
2,800
20,500
34,500
32,500
7,200
31,600
5,600
7,200
2,700
3,300
23,200
4,700
1,600
53,900
50,200
10,400
25,000
37,000
35,800
172
-------
Chapter F—Appendices
Table F-3. UOG Resource Potential: Shale as of January 1, 2012
EIA Region
•
6— West Coast
EIA Basin
Montana Thrust Belt
Powder River
San Juan
Uinta-Piceance
Columbia
San Joaquin/Los
Angeles
UOG Formation
Name
All tight oil plays
All tight oil plays
Lewis
Mancos
Gammon
Bakken
Basin Centered
Monterey/Santos
Resource
Type
Shale oil
Shale oil
Shale gas
Shale gas
Shale gas
Shale oil
Shale gas
Shale oil
Oil EUR (MMbls
per well)
0.113
0.035
0.000
0.000
0.000
0.142
0.000
0.502
Gas EUR
(Bcfper
well)
0.075
0.040
2.200
0.880
0.440
0.096
1.400
0.502
OilTRR
(MMbls)
600
2,100
0
0
0
9,300
0
600
GasTRR
(Bcf)
400
2,400
9,800
10,900
3,400
6,300
12,200
600
New Well
Potential
5,300
60,000
4,500
12,400
7,700
65,500
8,700
1,200
Sources: 48 DCN SGE00693
Abbreviations: EUR—estimated ultimate recovery (per well); MMbls—million barrels; Bcf—billion cubic feet of gas; TRR—technically recoverable resources
Table F-4. UOG Resource Potential: Tight as of January 1, 2012
EIA Region
1— East
0 rjulf Pr>Qct
EIA Basin
Appalachian
Michigan
TX-LA-MS Salt
Western Gulf
UOG Formation
Name
Clinton-Medina
Tuscarora
Berea Sand
Cotton Valley
Olmos
Vicksburg
Wilcox Lobo
Austin Chalk
Buda
Cleveland
Granite Wash
Resource
Type
Tight gas
Tight gas
Tight gas
Tight gas
Tight gas
Tight gas
Tight gas
Tight oil
Tight oil
Tight gas
Tight gas
Oil EUR (MMbls
per well)
0.003
0.000
0.000
0.009
0.005
0.000
0.000
0.086
0.108
0.036
0.046
Gas EUR
(Bcf per
well)
0.060
2.172
0.143
1.472
1.093
1.473
1.404
0.048
0.070
0.394
0.948
OilTRR
(MMbls)
500
0
0
900
100
0
0
7,600
3,700
100
600
GasTRR
(Bcf)
11,700
4,400
8,100
152,700
23,600
3,900
10,100
4,300
2,400
1,100
12,300
New Well
Potential
195,000
2,000
56,600
103,700
21,600
2,600
7,200
88,800
34,300
2,800
13,000
173
-------
Chapter F—Appendices
Table F-4. UOG Resource Potential: Tight as of January 1, 2012
EIA Region
4 — Southwest
EIA Basin
Permian
Denver
Greater Green River
North Central
Montana
Paradox
San Juan
SW Wyoming
Williston
Wind River
UOG Formation
Name
Red Fork
Abo
Canyon
Spraberry
Muddy
All Tight Oil Plays
Bowdoin-Greenhorn
Fractured Interbed
Dakota
Mesaverde
Pictured Cliffs
Fort Union-Fox Hills
Frontier
Lance
Lewis
All Tight Oil Plays
Iles-Mesaverde
Wasatch-Mesaverde
Williams Fork
All Tight Oil Plays
Judith River-Eagle
Mesaverde/Frontier
Shallow
Resource
Type
Tight gas
Tight gas
Tight gas
Tight oil
Tight gas
Tight oil
Tight gas
Tight oil
Tight gas
Tight gas
Tight gas
Tight gas
Tight gas
Tight gas
Tight gas
Tight oil
Tight gas
Tight gas
Tight gas
Tight oil
Tight gas
Tight gas
Oil EUR (MMbls
per well)
0.000
0.101
0.002
0.108
0.000
0.135
0.000
0.543
0.000
0.000
0.000
0.000
0.009
0.016
0.000
0.165
0.000
0.023
0.000
0.056
0.000
0.000
Gas EUR
(Bcfper
well)
0.593
0.182
0.209
0.113
0.182
0.015
0.151
0.434
0.416
0.464
0.397
1.047
0.273
1.012
0.248
0.015
0.502
0.463
0.456
0.111
0.158
0.768
OilTRR
(MMbls)
0
1,000
100
8,100
0
900
0
1,000
0
0
0
0
200
300
0
1,100
0
400
0
100
0
0
GasTRR
(Bcf)
1,000
1,800
10,900
8,500
11,500
100
300
800
6,100
5,800
200
15,800
6,200
18,700
7,700
100
17,100
8,200
7,600
200
1,000
4,400
New Well
Potential
1,700
9,900
52,200
75,200
63,200
6,700
2,000
1,800
14,700
12,500
500
15,100
22,700
18,500
31,000
6,700
34,100
17,700
16,700
1,800
6,300
5,700
Sources: 48 DCN SGE00693
Abbreviations: EUR—estimated ultimate recovery (per well); MMbls—million barrels; Bcf-
-billion cubic feet of gas; TRR—technically recoverable resources
174
-------
Chapter F-Appendices
APPENDIX F.3 CONSTITUENT CONCENTRATIONS OVER TIME IN UOG PRODUCED
WATER FROM MARCELLUS AND BARNETT SHALE FORMATIONS
1,800.00
1.600.00
1,400.00
1.200.00
1,000.00
s:c.:c
=::."
400.00
200.00
300
Marcellus Shale
z
77
Barnett Shale
DayO Dayl Day 5 Day 1- Day 90
Source: The EPA generated this figure using data from 85 DCN SGE00414.
Figure F-l. Constituent Concentrations over Time in UOG Produced Water from the
Marcellus and Barnett Shale Formations
175
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