United States Office of Water EPA-820-R-16-003
Environmental Protection Washington, DC 20460 June 2016
Agency
&EPA Technical Development
Document for the Effluent
Limitations Guidelines and
Standards for the Oil and
Gas Extraction Point Source
Category
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&EPA
United States
Environmental Protection
Agency
Technical Development Document for the
Effluent Limitations Guidelines and
Standards for the Oil and Gas Extraction
Point Source Category
EPA-820-R-16-003
JUNE 2016
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 AND BACKGROUND 1
1 Introduction 1
1.1 Purpose and Summary of the Rule 1
1.2 How to Use This Document 1
2 Regulatory Background 2
2.1 Background on Effluent Limitations Guidelines and Pretreatment
Standards 2
2.2 The National Pretreatment Program (40 CFR part 403) 5
2.3 Oil and Gas Extraction ELG Rulemaking History 8
3 State Pretreatment Requirements 9
4 Related Federal Requirements 11
CHAPTERS. SCOPE AND INDUSTRY DESCRIPTION 12
1 Unconventional Oil and Gas 12
1.1 Overview of Oil and Gas Resources 12
1.2 Scope of This Rulemaking 14
2 Industry Description: UOG Well Development Process 22
2.1 UOG Exploration 23
2.2 UOG Well Drilling and Construction 24
2.3 UOG Well Completion 27
2.4 UOG Production 32
3 Industry Description: UOG Well Drilling and Completion Activity 33
3.1 Historical and Current UOG Drilling Activity 33
3.2 UOG Resource Potential 37
3.3 Current and Projections of Future UOG Well Completions 38
CHAPTER C. UNCONVENTIONAL OIL AND GAS EXTRACTION WASTEWATER VOLUMES
AND CHARACTERISTICS 40
1 Fracturing Fluid Characteristics 41
1.1 Base Fluid Composition 42
1.2 Additives 43
1.3 Fracturing Fluids 47
2 UOG Extraction Wastewater Volumes 48
2.1 UOG Extraction Wastewater Volumes by Resource and Well Trajectory 48
2.2 UOG Produced Water Volumes by Formation 53
IV
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Table of Contents
CONTENTS (Continued)
Page
3 UOG Extraction Wastewater Characterization 59
3.1 Availability of Data for UOG Extraction Wastewater Characterization 59
3.2 UOG Extraction Wastewater Constituent Categories 59
3.3 UOG Produced Water Characterization Changes over Time 80
CHAPTER D. UOG EXTRACTION WASTEWATER MANAGEMENT AND DISPOSAL
PRACTICES 82
1 Overview of UOG Extraction Wastewater Management and Disposal Practices 82
2 Injection into Disposal Wells 88
2.1 Regulatory Framework for Underground Injection 89
2.2 Active Disposal Wells and Volumes 89
2.3 Underground Injection of UOG Wastewaters 92
3 Reuse/Recycle in Fracturing 95
3.1 Reuse/Recycle Strategies 97
3.2 Reuse/Recycle Drivers 100
3.3 Other Considerations for Reuse/Recycle 105
4 Transfer to CWT Facilities 107
4.1 Types of CWT Facilities 107
4.2 Active CWT Facilities Accepting UOG Extraction Wastewater 109
5 Discharge to POTWs Ill
5.1 POTW Background and Treatment Levels 112
5.2 History of POTW Acceptance of UOG Extraction Wastewater 115
5.3 How UOG Extraction Wastewater Constituents Interact with POTWs 120
CHAPTERE. REFERENCE FLAGS AND LIST 155
CHAPTERF. APPENDICES 169
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List of Tables
LIST OF TABLES
Page
Table A-l. Summary of State Regulations/Guidance 10
Table B-l. Summary of State Regulatory Definitions 16
Table B-2. Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product
Type (as of October 9, 2015) 36
Table B-3. UOG Potential by Resource Type as of January 1, 2013 38
Table C-l. Sources for Base Fluid in Hydraulic Fracturing 43
Table C-2. Fracturing Fluid Additives, Common Compounds, and Common Uses 44
Table C-3. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in
Gas Wells from FracFocus (2011-2013) 46
Table C-4. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in
Oil Wells from FracFocus (2011-2013) 46
Table C-5. Median Drilling Wastewater Volumes for UOG Horizontal and Vertical Wells
in Pennsylvania 51
Table C-6. Drilling Wastewater Volumes Generated per Well by UOG Formation 51
Table C-7. UOG Well Flowback Recovery by Resource Type and Well Trajectory 52
Table C-8. Long-Term Produced Water Generation Rates by Resource Type and Well
Trajectory 53
Table C-9. Produced Water Volume Generation by UOG Formation 54
Table C-10. Concentrations of Select Classical and Conventional Constituents in UOG
Drilling Wastewater from Marcellus Shale Formation Wells 61
Table C-l 1. Concentrations of Select Classical and Conventional Constituents in UOG
Produced Water 62
Table C-12. Concentrations of Bromide and Sulfate in UOG Drilling Wastewater from
Marcellus Shale Formation Wells 67
Table C-13. Concentrations of Select Anions and Cations Contributing to TDS in UOG
Produced Water 68
Table C-14. Concentrations of Select Organic Constituents in UOG Drilling Wastewater
from Marcellus Shale Formation Wells 69
Table C-15. Concentrations of Select Organic Constituents in UOG Produced Water 70
Table C-l6. Concentrations of Select Metal Constituents in UOG Drilling Wastewater
from Marcellus Shale Formation Wells 71
Table C-17. Concentrations of Select Metal Constituents in UOG Produced Water 73
VI
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List of Tables
LIST OF TABLES (Continued)
Page
Table C-18. Concentrations of Select Radioactive Constituents in UOG Drilling
Wastewater from Marcellus Shale Formation Wells 77
Table C-19. Concentrations of Select Radioactive Constituents in UOG Produced Water 77
Table C-20. Concentrations of Radioactive Constituents in Rivers, Lakes, Groundwater,
and Drinking Water Sources Throughout the United States (pCi/L) 78
Table D-l. UOG Produced Water Management Practices 86
Table D-2. Distribution of Active Class II Disposal Wells Across the United States
(Primarily 2012 and 2013 Data) 91
Table D-3. Distribution of Active Class II Disposal Wells on Tribal Lands (2014 Data) 92
Table D-4. Reuse/Recycle Practices in 2012 as a Percentage of Total Produced Water
Generated as Reported by Respondents to 2012 Survey 97
Table D-5. Reported Reuse/Recycle Criteria 102
Table D-6. Reported Reuse/Recycle Practices as a Percentage of Total Fracturing
Volume 103
Table D-7. Number of CWT Facilities That Have Accepted or Plan to Accept UOG
Extraction Wastewater, by State 110
Table D-8. Typical Composition of Untreated Domestic Wastewater 112
Table D-9. Typical Percent Removal Capabilities from POTWs with Secondary
Treatment 114
Table D-10. U.S. POTWs by Treatment Level in 2012 115
Table D-l 1. POTWs That Accepted UOG Extraction Wastewater Directly from Onshore
UOG Operators 117
Table D-12. Percentage of Total POTW Influent Wastewater Composed of UOG
Extraction Wastewater at POTWs Accepting Wastewater from UOG
Operators 119
Table D-l3. Summary of Studies About POTWs Receiving Oil and Gas Extraction
Wastewater Pollutants 121
Table D-14. Clairton Influent Oil and Gas Extraction Wastewater Characteristics 125
Table D-l 5. Trucked COG Extraction Wastewater Treated at McKeesport POTW from
November 1 Through 7, 2008 126
Table D-16. McKeesport POTW Removal Rates Calculated for Local Limits Analysis 127
Table D-17. Constituent Concentrations in UOG Extraction Wastewater Treated at the
McKeesport POTW Before Mixing with Other Influent Wastewater 128
vii
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List of Tables
LIST OF TABLES (Continued)
Page
Table D-18. McKeesport POTW Effluent Concentrations With and Without UOG
Extraction Wastewater 129
Table D-19. Charleroi POTW Paired Influent/Effluent Data and Calculated Removal
Rates 131
Table D-20. Franklin Township POTW Effluent Concentrations With and Without
Industrial Discharges from the Tri-County CWT Facility 134
Table D-21. TDS Concentrations in Baseline and Pilot Study Wastewater Samples at
Warren POTW 137
Table D-22. EPA Region 5 Compliance Inspection Sampling Data 137
Table D-23. Inhibition Threshold Levels for Various Treatment Processes 139
Table D-24. Industrial Wastewater Volumes Received by New Castle POTW (2007-
2009) 144
Table D-25. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW
(NPDES Permit Number PA0027511) 145
Table D-26. Concentrations of DBFs in Effluent Discharges at One POTW Not
Accepting Oil and Gas Wastewater and at Two POTWs Accepting Oil and
Gas Wastewater (jig/L) 151
Table E-l. Source List 155
Table F-l. TDD Supporting Memoranda and Other Relevant Documents Available in
FDMS 169
Table F-2. Crosswalk Between TDD and Supporting Memoranda 171
Table F-3. UOG Resource Potential: Shale as of January 1,2013 179
Table F-4. UOG Resource Potential: Tight as of January 1,2013 180
Vlll
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List of Figures
LIST OF FIGURES
Page
Figure B-l. Historical and Projected Crude Oil Production by Resource Type 13
Figure B-2. Historical and Projected Natural Gas Production by Resource Type 13
Figure B-3. Major U.S. Shale Plays (Updated April 13,2015) 20
Figure B-4. Major U.S. Tight Plays (Updated June 6, 2010) 21
Figure B-5. UOG Extraction Wastewater 23
Figure B-6. Horizontal (A), Vertical (B), and Directional (C) Drilling Schematic 25
Figure B-7. Length of Time to Drill a Well in Various UOG Formations (2012 through
2014) 27
Figure B-8. Hydraulic Fracturing Schematic 29
Figure B-9. Freshwater Impoundment 30
Figure B-10. Vertical Gas and Water Separator 31
Figure B-l 1. Fracturing Tanks 32
Figure B-12. Produced Water Storage Tanks 33
Figure B-13. Number of Active U.S. Onshore Rigs by Trajectory and Product Type over
Time 35
Figure B-14. Projections of UOG Well Completions 39
Figure C-l. UOG Extraction Wastewater Volumes for Marcellus Shale Wells in
Pennsylvania (2004-2014) 49
Figure C-2. Ranges of Typical Produced Water Generation Rates over Time After
Fracturing 50
Figure C-3. Anions and Cations Contributing to TDS Concentrations in Shale and Tight
Oil and Gas Formations 65
Figure C-4. Chloride, Sodium, and Calcium Concentrations in Flowback and Long-Term
Produced Water (LTPW) from Shale and Tight Oil and Gas Formations 66
Figure C-5. Barium Concentrations in UOG Produced Water from Shale and Tight Oil
and Gas Formations 76
Figure C-6. Constituent Concentrations over Time in UOG Produced Water from the
Marcellus and Barnett Shale Formations 81
Figure D-l. UOG Produced Water Management Methods 83
Figure D-2. UOG Drilling Wastewater Management Methods 84
Figure D-3. Management of UOG Drilling Wastewater Generated by UOG Wells in
Pennsylvania (2008-2014) 87
ix
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List of Figures
LIST OF FIGURES (Continued)
Page
Figure D-4. Active Disposal Wells and CWT Facilities Identified in the Appalachian
Basin 88
Figure D-5. U.S. Injection for Disposal Volume and UOG Production over Time 93
Figure D-6. Injection for Disposal Volume and Crude Oil Production over Time in North
Dakota 94
Figure D-7. Injection for Disposal Volume, Cumulative Bakken Wells Drilled, and
Cumulative Disposal Wells Drilled in North Dakota 94
Figure D-8. Flow Diagram of On-the-Fly UOG Produced Water Treatment for
Reuse/Recycle 100
Figure D-9. Hypothetical UOG Produced Water Generation and Base Fracturing Fluid
Demand over Time 104
Figure D-10. UOG Extraction Wastewater Management Practices Used in the Marcellus
Shale (Top: Southwestern Region; Bottom: Northeastern Region) 106
Figure D-l 1. Number of Known Active CWT Facilities over Time in the Marcellus and
Utica Shale Formations Ill
Figure D-12. Typical Process Flow Diagram at aPOTW 113
Figure D-13. Clairton POTW: Technical Evaluation of Treatment Processes' Ability to
Remove Chlorides and TDS 124
Figure D-14. McKeesport POTW: Technical Evaluation of Treatment Processes' Ability
to Remove Chlorides and TDS 126
Figure D-l5. Ridgway POTW: Annual Average Daily Effluent Concentrations and
POTW Flows 130
Figure D-l6. Johnstown POTW: Annual Average Daily Effluent Concentrations and
POTW Flows 141
Figure D-l7. California POTW: Annual Average Daily Effluent Concentrations and
POTW Flows 142
Figure D-l8. Charleroi POTW: Annual Average Daily Effluent Concentrations and
POTW Flows 143
Figure D-19. Barium Sulfate Scaling in Haynesville Shale Pipe 148
Figure D-20. THM Speciation in a Water Treatment Plant (1999-2013) 153
Figure F-l. Constituent Concentrations over Time in UOG Produced Water from the
Marcellus and Barnett Shale Formations 182
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Abbreviations
AO
API
Bcf
BDL
BOD5
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
NPDES
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
National Pollutant Discharge Elimination System
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
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 mud
Drilling wastewater
GLOSSARY1
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 produced water, brine, salt water, water, steam,
polymers, or carbon dioxide into oil-bearing formations to recover
residual oil and—in some limited applications—natural gas.2
Crude oil3 and natural gas4 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
mud.
The circulating fluid (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 mud
(fluid) and drill cuttings during the drilling process.
1 The definitions of terms in the Glossary are only meant to apply to the terms as used throughout the Technical
Development Document for the Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point
Source Category (TDD) and the TDD supporting documentation.
2 The injection of fluids for hydraulic fracturing is also a form of enhanced recovery. See Legal Environmental
Assistance Foundation v. EPA, 276 F.3d 1253 (llth Cir. 2001). However, Congress amended the Safe Drinking
Water Act to exempt hydraulic fracturing (except where diesel fuels are used) from regulation under the UIC
program (SDWA Section 1421(d)(l)). Because there are currently no Class II permits for hydraulic fracturing
activities, EPA did not consider wells that have been hydraulically fractured within the context of this TDD.
3 Crude oil includes "lease condensates," components that are liquid at ambient temperature and pressure.
4 Natural gas can include "natural gas liquids," components that are liquid at ambient temperature and pressure.
Xlll
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Glossary
Flowback
Formation water
Hydraulic fracturing
Hydraulic fracturing base
fluid
Hydraulic fracturing fluid
Long-term produced
water (LTPW)
Naturally occurring
radioactive material
(NORM)
Non-TDS removal
technologies
Produced sand
Produced water (brine)
Proppant
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, and 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 primary component of fracturing fluid to which proppant
(sand) and chemicals are added. Hydraulic fracturing 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 may consist of only fresh water or a
mixture of fresh water, brackish water and/or reused/recycled
wastewater.
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 hydraulic
fracturing base fluid.
The produced water generated during the production phase of the
well, after the initial flowback process, which can include
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, including suspended solids, oil and grease and
bacteria, or remove and/or exchange 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 TDS in UOG extraction 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 fluid (brine) brought up from the hydrocarbon-bearing strata
during the extraction of oil and gas, and includes, where present,
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.
xiv
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Glossary
Publicly owned treatment
works (POTW)
Source water
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)
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.
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 typically
include non-TDS removal technologies for pretreatment (e.g.,
TSS, oil and grease).
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 oil5 and natural gas6 produced by a well drilled into a shale
and/or tight formation (including, but not limited to, shale gas,
shale oil, tight gas, tight oil). For the purpose of the 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 (including, but not limited to, drilling muds,
drill cuttings, produced sand, produced water).
5 Grade oil includes "lease condensates," components that are liquid at ambient temperature and pressure.
6 Natural gas can include "natural gas liquids," components that are liquid at ambient temperature and pressure.
xv
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Chapter A—Introduction
Chapter A. INTRODUCTION AND BACKGROUND
1 INTRODUCTION
1.1 Purpose and Summary of the Rule
The EPA is publishing a final Clean Water Act (CWA) regulation that better protects
human health and the environment and protects the operational integrity of publicly owned
treatment works (POTWs) by establishing pretreatment standards that prevent the discharge of
pollutants in wastewater from onshore unconventional oil and gas (UOG) extraction facilities to
POTWs (also called municipal wastewater treatment plants). UOG extraction wastewater can be
generated in large quantities and has constituents that are potentially harmful to human health
and the environment. Because these constituents are not typical of POTW influent wastewater,
some UOG extraction wastewater constituents can be discharged, untreated, from the POTW to
the receiving stream; can disrupt the operation of the POTW (e.g., by inhibiting biological
treatment); can accumulate in biosolids (sewage sludge), limiting its use; and can facilitate the
formation of harmful disinfection byproducts (DBFs).
Based on the information collected by the EPA, the requirements in this final rule reflect
current industry practices for onshore UOG extraction facilities. Therefore, the EPA does not
project that the final rule will impose any costs or lead to pollutant removals: rather, it will
ensure that such current industry best practice is maintained over time.
1.2 How to Use This Document
This document supports the EPA's development of pretreatment standards for UOG
extraction wastewater. The remainder of Chapter A describes the regulatory background for this
rulemaking and related federal regulations. Subsequent chapters provide further detail on what
"unconventional oil and gas" means in the context of this rulemaking, then further detail on
UOG resources, extraction processes, and wastewater generation. The subsequent chapters also
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 the EPA's Quality Policy and Information Quality Guidelines.
The 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 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., 73) and document control numbers (DCNs) (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
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Chapter A—Introduction
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, DCN, source citation, and data source quality flag.
Appendix F includes two tables with 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 it discusses. Table F-l also lists the relevant TDD sections associated
with each memorandum. Table F-2 contains further 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 applicable.
2 REGULATORY BACKGROUND
Wastewater discharges from crude oil7 and natural gas8 extraction facilities are subject to
federal regulation. Section A.2.1 describes effluent limitations guidelines and standards (ELGs),
which are federal regulations that control pollutants in industrial wastewater discharges to waters
of the United States and POTWs, respectively. Section A.2.2 discusses the national pretreatment
program (40 CFR part 403). Section A.2.3 describes ELGs specifically for the Oil and Gas
Extraction point source category (40 CFR part 435).
2.1 Background on Effluent Limitations Guidelines and Pretreatment Standards
Congress passed the Federal Water Pollution Control Act Amendments of 1972, also
known as the CWA, to "restore and maintain the chemical, physical, and biological integrity of
the Nation's waters" (33 U.S.C. 1251(a)). The CWA establishes a comprehensive program for
protecting our nation's waters. Among its core provisions, it prohibits the discharge of pollutants
from a point source to waters of the United States, except as authorized under the CWA. Under
its Section 402, discharges may be authorized through a National Pollutant Discharge
Elimination System (NPDES) permit. The CWA establishes a two-pronged approach for these
permits, technology-based controls that establish the floor of performance for all dischargers, and
water-quality-based limits where the technology-based limits are insufficient for the discharge to
meet applicable water quality standards. To serve as the basis for the technology-based controls,
the CWA authorizes the EPA to establish national technology-based effluent limitations
guidelines and new source performance standards (NSPS) for discharges from different
categories of point sources, such as industrial, commercial, and public sources, that discharge
directly into waters of the United States.
Direct dischargers (those discharging directly to surface waters) must comply with
effluent limitations in NPDES permits. Technology-based effluent limitations in NPDES permits
for direct dischargers are derived from effluent limitations guidelines (CWA Sections 301 and
304) and NSPS (CWA Section 306) promulgated by the EPA, or based on best professional
judgment where the EPA has not promulgated an applicable effluent guideline or NSPS (CWA
7 Grade oil includes "lease condensates," components that are liquid at ambient temperature and pressure.
8 Natural gas can include "natural gas liquids," components that are liquid at ambient temperature and pressure.
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Chapter A—Introduction
Section 402(a)(l)(B) and 40 CFR 125.3). The effluent guidelines and NSPS established by
regulation for categories of industrial dischargers are based on the degree of control that can be
achieved using various levels of pollution control technology, as specified in the Act.
The EPA promulgates national effluent guidelines and NSPS for major industrial
categories for three classes of pollutants:
• Conventional pollutants (total suspended solids, oil and grease, biochemical oxygen
demand [BOD5], fecal coliform, and pH), as outlined in CWA Section 304(a)(4) and
40 CFR 401.16
• Toxic pollutants (e.g., metals such as arsenic, mercury, selenium, and chromium; and
organic pollutants such as benzene, benzo-a-pyrene, phenol, and naphthalene), as
outlined in Section 307(a) of the Act, 40 CFR 401.15, and 40 CFR part 423,
Appendix A
• Nonconventional pollutants, which are those pollutants that are not categorized as
conventional or toxic (e.g., ammonia-N, phosphorus, and TDS)
The CWA also authorizes the EPA to promulgate nationally applicable pretreatment
standards that restrict pollutant discharges from facilities that discharge pollutants indirectly, by
sending wastewater to POTWs, as outlined in Sections 307(b) and (c) and 33 U.S.C. 1317(b) and
(c). Specifically, the CWA authorizes the EPA to establish pretreatment standards for those
pollutants in wastewater from indirect dischargers that the EPA determines are not susceptible to
treatment by a POTW or which would interfere with POTW operations. Pretreatment standards
must be established to prevent the discharge of any pollutant that can pass through, interfere
with, or is otherwise incompatible with POTW operations (CWA Sections 307(b) and (c)).
There are four types of standards applicable to direct dischargers (facilities that discharge
directly to surface waters), and two types of standards applicable to indirect dischargers
(facilities that discharge to POTWs), described in detail below. Subsections 1 through 4 describe
standards for direct discharges and subsection 5 describes standards for indirect discharges.
2.1.1 Best Practicable Control Technology Currently Available (BPT)
Traditionally, the EPA defines BPT effluent limitations based on the average of the best
performances of facilities within the industry, grouped to reflect various ages, sizes, processes, or
other common characteristics. BPT effluent limitations control conventional, toxic, and
nonconventional pollutants. In specifying BPT, the EPA looks at a number of factors. The EPA
first considers the cost of achieving effluent reductions in relation to the effluent reduction
benefits. The Agency also considers the age of equipment and facilities, the processes employed,
engineering aspects of the control technologies, any required process changes, non-water-quality
environmental impacts (including energy requirements), and such other factors as the
Administrator deems appropriate. See CWA Section 304(b)(l)(B). If existing performance is
uniformly inadequate, however, the EPA can establish limitations based on higher levels of
control than what is currently in place in an industrial category, if it determines that the
technology is available in another category or subcategory and can be practically applied.
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Chapter A—Introduction
2.1.2 Best Conventional Pollutant Control Technology (BCT)
The 1977 amendments to the CWA require the EPA to identify additional levels of
effluent reduction for conventional pollutants associated with BCT technology for discharges
from existing industrial point sources. In addition to other factors specified in Section
304(b)(4)(B), the CWA requires that the EPA establish BCT limitations after consideration of a
two-part "cost reasonableness" test. The EPA explained its methodology for the development of
BCT limitations on July 9, 1986 (51 Fed. Reg. 24974). Section 304(a)(4) designates the
following as conventional pollutants: BOD5, total suspended solids (TSS), fecal coliform, pH,
and any additional pollutants defined by the Administrator as conventional. The Administrator
designated oil and grease as an additional conventional pollutant on July 30, 1979 (44 Fed. Reg.
44501;40CFR401.16).
2.1.3 Best Available Technology Economically Achievable (BA T)
BAT represents the second level of stringency for controlling direct discharge of toxic
and nonconventional pollutants. In general, BAT-based effluent guidelines and NSPS represent
the best available economically achievable performance of facilities in the industrial subcategory
or category. Following the statutory language, the EPA considers the technological availability
and the economic achievability in determining what level of control represents BAT (CWA
Section 301(b)(2)(A)). Other statutory factors that the EPA considers in assessing BAT are the
cost of achieving BAT effluent reductions, the age of equipment and facilities involved, the
process employed, potential process changes, and non-water-quality environmental impacts,
including energy requirements and such other factors as the Administrator deems appropriate
(CWA Section 304(b)(2)(B)). The Agency retains considerable discretion in assigning the weight
to be accorded these factors (Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1045, D.C. Cir. 1978).
2.1.4 Best Available Demonstrated Control Technology (BADCT)/New Source Performance
Standards (NSPS)
NSPS reflect effluent reductions that are achievable based on the best available
demonstrated control technology (BADCT). Owners of new facilities have the opportunity to
install the best and most efficient production processes and wastewater treatment technologies.
As a result, NSPS should represent the most stringent controls attainable through the application
of the BADCT for all pollutants (that is, conventional, nonconventional, and toxic pollutants). In
establishing NSPS, the EPA is directed to take into consideration the cost of achieving the
effluent reduction and any non-water quality environmental impacts and energy requirements
(CWA section 306(b)(l)(B)).
2.1.5 Pretreatment Standards for Existing Sources (PSES) and New Sources (PSNS)
As discussed above, Section 307(b) of the Act calls for the EPA to issue pretreatment
standards for discharges of pollutants from existing sources to POTWs. Section 307(c) of the Act
calls for the EPA to promulgate PSNS. Both standards are designed to prevent the discharge of
pollutants that pass through, interfere with, or are otherwise incompatible with the operation of
POTWs. Categorical pretreatment standards for existing sources are technology-based and are
analogous to BPT and BAT effluent limitations guidelines, and thus the Agency typically
considers the same factors in promulgating PSES as it considers in promulgating BAT. See
Natural Resources Defense Council v. EPA, 790 F.2d 289, 292 (3rd Cir. 1986). Similarly, in
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Chapter A—Introduction
establishing pretreatment standards for new sources, the Agency typically considers the same
factors in promulgating PSNS as it considers in promulgating NSPS (BADCT).
2.2 The National Pretreatment Program (40 CFR part 403)
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 (19 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 (Ills). To distinguish small, simple Ills (e.g., coin-operated laundries, commercial car
washes) from larger, more complex lUs (e.g., crude oil refineries, steel mills), the EPA
established a category called significant Ills (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 CFR part 403.
Pretreatment Program Implementation
Control authorities implement and
enforce the National Pretreatment Program.
The Control Authority refers to the POTW if
the POTW has an approved Pretreatment
Program, or the state or the EPA if the
POTW does not have an approved Program.
Most of the responsibility for implementing
the National Pretreatment Program rests on
local municipalities. For example, 40 CFR
403.8(a) requires that POTWs designed to
treat more than 5 million gallons per day
(MGD) of wastewater and receiving
pollutants from Ills that pass through or
interfere with the POTW's operation must
establish a local pretreatment program.9 The
POTW's NPDES permit will include
requirements for developing a local
pretreatment program that will control the
wastewater discharged to the POTW by Ills.
The National Pretreatment Program
regulations identify specific requirements
40 CFR 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
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 one to prevent
interference with the POTW or pass through.
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Chapter A—Introduction
that apply to Ills, 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 Ills—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 CFR 403.5(a) and (b), respectively.
• General prohibitions forbid 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 CFR 403.5(b) forbid 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 set regulatory requirements based on the performance of technology.
These requirements typically limit discharges of toxic and nonconventional pollutants that could
cause pass-through or interference.10 Categorical pretreatment standards represent a baseline
level of control that every IU in the category must meet, without regard to the individual POTW
to which it discharges. 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
10 In determining whether a pollutant would pass through POTWs for categorical pretreatment standards, the 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
residential sources), and implement a system to control industrial discharges. Additional
information can be found in the EPA's 2004 Local Limits Development Guidance (80 DCN
SGE00602;.
Responsibilities of Control Authorities and Ills
The Control Authority (POTW, state, or EPA) controls the discharges from the IU
through an individual control mechanism, often called an IU permit. The Control Authority 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 Ills, and the character and volume of pollutants from Ills
introduced to the POTW
• Communicating applicable standards and requirements to Ills
• Receiving and analyzing reports
• Inspecting Ills, 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 (19 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 a
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 (19 DCN
SGE00249), in addition to receiving wastewater through the collection system, many POTWs
accept trucked wastewater. An IU may truck its wastewater to a POTW when it is outside the
POTW's service area (e.g., 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 is also subject to applicable 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.
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Chapter A—Introduction
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
(19 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 industrial
hauled waste without considering the implications of its acceptance (see 40 CFR part 260).
2.3 Oil and Gas Extraction ELG Rulemaking History
The EPA first promulgated the Oil and Gas Extraction ELGs (40 CFR part 435) in 1979,
and substantially amended the regulation in 1993 (Offshore), 1996 (Coastal), and 2001
(Synthetic-Based Drilling Fluids). The Oil and Gas Extraction industrial category is
subcategorized11 in 40 CFR part 435 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. The limitations for direct dischargers in the Onshore Subcategory represent
Best Practicable Control Technology Currently Available (BPT). Based on the availability and
economic practicability of underground injection technologies, the BPT-based limitations for
direct dischargers require zero discharge of pollutants to waters of the United States. However,
there are currently no requirements in subpart C that apply to onshore oil and gas extraction
facilities that are "indirect dischargers," i.e., those that send their discharges to POTWs.
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 where the regulations in subpart C (Onshore) and subpart E (Agricultural and
Wildlife Water Use) apply; thus, the gap in onshore regulations is the focus of this final rule. For
this reason, only the regulations that apply to onshore oil and gas extraction are described in
more detail here.
Note that facilities that accept oil and gas extraction wastewater from offsite may be
subject to requirements in 40 CFR part 437, the Centralized Waste Treatment category (see
Section D.4 for more information).
11 Subpart B is reserved.
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Chapter A—Introduction
Subpart C: Onshore Subcategory
Applicability. As set forth in 40 CFR 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 CFR 435.40.
Direct discharge requirements. The regulations at 40 CFR 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).
Subpart E: Agricultural and Wildlife Use Subcategory
Applicability. As set forth in 40 CFR 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 of
the United States. Definitions in 40 CFR 435.51(c) explain that the term "use in agricultural or
wildlife propagation" means that two things are true:
• The produced water is of good enough quality to be used for wildlife or livestock
watering or other agricultural uses.
• 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 water12
that meets the "good enough quality" and actual use requirements described above, with an oil
and grease concentration not exceeding 35 mg/L.
3 STATE PRETREATMENT REQUIREMENTS
In addition to applicable federal requirements, some states regulate the management,
storage, and disposal of oil and gas 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 summarizes
state regulations and/or guidance related to UOG extraction wastewater discharges to POTWs.
12 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."
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Chapter A—Introduction
Table A-l. Summary of State Regulations/Guidance
State
State
Authority(s)
State Code
(Source DCN)
State's Relevant Regulations or Guidance
PA
EPA
Region 3;
PADEP
25 PA Code Ch.
95.10
(14 SGE00187;
148 SGE00982;
63 SGE00545)
The Pennsylvania Code, amended in 2010, states that waters of
Pennsylvania will not exceed a threshold of 500 mg/L of TDS. In addition,
the standard is applied specifically to the natural gas sector, which PA DEP
based on several factors. Discharge loads of TDS authorized by PA DEP
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. Further (according to PA Bulletin,
Doc. No. 10-1572, 14 DCN SGE00187), the pretreatment requirements are
"that POTWs 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."
OH
OH EPA;
OHDNR
OH R.C. Title
15, Chapter
1509, part
22(C)(1)
(149 SGE00983)
The Ohio Revised Code includes a provision that describes the acceptable
disposal of brine:13 injection into an underground formation, surface
application, enhanced recovery, or in any other manner that is approved by
a permit. This provision applies to any well except an exempt
Mississippian well.: 4
WV
WVDEP
(129 SGE00766;
130 SGE00767)
A WV DEP guidance document "discourages POTWs from accepting
wastewater from oil and gas operations." This document groups coalbed
methane and Marcellus Shale wastewaters together. WV DEP discourages
this practice "because these wastewaters essentially pass through sewage
treatment plants and can cause inhibition and interference with treatment
plant operations" (130 DCN SGE00767).
MI
MIDEQ
MI Oil and Gas
Regulations, part
324.703
(20 SGE00254)
Michigan's Oil and Gas Regulations discuss the well permittee's
responsibility for handling waste. The regulations dictate that oil and gas
waste must be injected into an underground well such that there is no
additional wastewater stream.
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
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."
14 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.
10
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Chapter A—Introduction
The Groundwater Protection Council's (GWPC's) 2014 report Regulations Designed to
Protect State Oil and Gas Water Resources (162 DCN SGE01077) describes a survey of 27 oil-
and-gas-producing states15
regarding the use ofPOTWsfor discharging production fluids including flowback
water. Of the states responding, three indicated this practice was banned by
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.
In 2015, State Review of Oil & Gas Environmental Regulations, Inc. (STRONGER)16
published voluntary guidelines to help states develop effective oil and gas regulatory programs
for production wastes (197 DCN SGE01208).
4 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 CFR parts 144 through 148, and specifically prohibit any underground injection not
authorized by UIC permit (40 CFR 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 disposal well
permit.
15 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.
16 STRONGER's mission is to assist states in documenting the environmental regulations associated with the
exploration, development, and production of crude oil and natural gas (214 DCN SGE01331).
11
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Chapter B—Scope and Industry Description
Chapter B. SCOPE AND INDUSTRY DESCRIPTION
As described in Chapter A, this document provides background information and data
considered in the development of the revised ELGs for the Oil and Gas Extraction point source
category to address discharges from UOG extraction facilities to POTWs. To provide context for
discussions of UOG extraction wastewater volumes and characteristics (Chapter C) and
management and disposal practices (Chapter D), this chapter contains:
• An overview of UOG and the scope of this rulemaking
• A discussion of the UOG well development process, with a focus on the processes
that generate UOG extraction wastewater
• A description of the industry, including historical and current UOG drilling and
completion activity and total UOG resource potential
Relevant national economic information about the UOG industry is included in a separate
document in the record, titled Profile of the Unconventional Oil and Gas Industry, (212 DCN
SGE01277).
1 UNCONVENTIONAL OIL AND GAS
1.1 Overview of Oil and Gas Resources
The United States has developed oil and gas resources since 1821 (1 DCN SGE00010).
Beginning around 2000, advances in technologies such as horizontal drilling and advances in
hydraulic fracturing made it possible to more economically produce oil and natural gas from
tight and shale resources (164 DCN SGE01095). The Energy Information Administration
(EIA)'s Annual Energy Outlook (AEO), which publishes historical and projected future oil and
gas production by resource type, shows the increasingly large role of UOG. The EIA's 2015
AEO projects that, in the next 30 years, the majority of the country's crude oil17 and natural gas18
will come from unconventional resources (194 DCN SGE01192). Figure B-l and Figure B-2
show the historical and future profiles of conventional oil and gas (COG) and UOG production
in the United States by resource type according to the EIA.19 Coalbed methane (CBM) and COG
are included in some of the figures in this chapter, but are identified separately within each
figure.
17 Grade oil includes "lease condensates," components that are liquid at ambient temperature and pressure.
18 Natural gas can include "natural gas liquids," components that are liquid at ambient temperature and pressure.
19 In Figure B-l, the EIA refers to all types of unconventional oil including shale as "tight oil." As explained in
Section B.I, this TDD differentiates between shale and tight oil.
12
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Chapter B—Scope and Industry Description
12
Post-2013 data are projections
i Tight Shale Oil
i Onshore Conventional
(Lower 4 8)
Offshore (Lower 48)
Alaska
2012 2016 2020 2024 2028 2032 2036 2040
Source: Created by the EPA using data from the EIA's 2015 AEO (194 DCN SGE01192)
Figure B-l. Historical and Projected Crude Oil Production by Resource Type
20
40
35
-Post-2013 data are projections
I Shale gas
i Tight gas
Coal bed methane
i Onshore Conventional
(Lower 48)
Offshore (Lower 48)
Alaska
2012 2016 2020 2024 2028 2032 2036 2040
Source: Created by the EPA using data from the EIA's 2015 AEO (194 DCN SGE01192)
Figure B-2. Historical and Projected Natural Gas Production by Resource Type
21
20 The EIA reported these data as "tight oil" production but stated that they include production from both shale oil
formations (e.g., Bakken, Eagle Ford) and tight oil formations (e.g., Austin Chalk). Condensates are included in
crude oil production. Alaska includes conventional onshore and offshore production in Figure B-l.
21 Alaska includes conventional onshore and offshore production in Figure B-2.
13
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Chapter B—Scope and Industry Description
1.2 Scope of This Rulemaking
The scope of this final rule is specific to pretreatment standards for onshore oil and gas
extraction facilities (subpart C) of 40 CFR part 435. The EPA did not propose to reopen the
regulatory requirements applicable to any other subpart or to the requirements for direct
dischargers in subpart C. Rather, the scope of the final rule amends subpart C only to add
requirements for indirect dischargers where there currently are none. Further, the final rule
establishes requirements for wastewater discharges from UOG extraction facilities to POTWs. It
does not establish requirements for wastewater discharges from COG or CBM extraction
facilities. EPA reserves such standards for a future rulemaking, if appropriate. Section B.I.2.1
describes publicly available information defining onshore UOG extraction facilities, Section
E.I.2.2 describes EPA's record of UOG operators' understanding of the names and types of
formations from which they extract, and Section B.I.2.3 shows how EPA used this information
to define the scope of this rule.
1.2.1 Description of UOG Resources in Publicly Available Sources
Onshore UOG extraction facilities make up the universe that would be subject to this
final rule. For purposes of the final rule, the EPA is defining "unconventional oil and gas" as
"crude oil and natural gas produced by a well drilled into a shale and/or tight formation
(including, but not limited to, shale gas, shale oil, tight gas, tight oil)." This definition is
generally consistent with those in other readily available sources, but—as indicated above—for
purposes of this final rule, it does not extend to CBM. The following list presents examples of
similar definitions from publicly available sources:
• A report by the Energy Water Initiative (EWI)22 titled U.S. Onshore Unconventional
Exploration and Production Water Management Case Studies defines unconventional
as "Oil and natural gas production from shale and tight (low permeability)
formations—a relatively new method of production—as compared to traditional oil
and gas well drilling and production that tapped underground reserves with greater
permeability" (224 DCN SGE01344).
• The 2014 Federal Multi-Agency Collaboration on Unconventional Oil and Gas
Research states "Unconventional oil and gas (UOG) refers to resources such as shale
gas, shale oil, tight gas, and tight oil that cannot be produced economically through
standard drilling practices" (214 DCN SGE01330).
• The U.S. Geological Survey (USGS) has described UOG resources as including shale
and tight resources in several published documents.
— USGS's 2014 report titled U.S. Geological Survey Assessments of Continuous
(Unconventional) Oil and Gas Resources, 2000 to 2011, categorizes resources
into four distinct reservoir categories: "shale gas, coalbed gas, tight gas, and
continuous oil" (211 DCN SGE01275).
22 EWI is a collaborative effort among participating members of the U.S. oil and natural gas industry including
Anadarko Petroleum, Apache Corporation, BP America Production Company, Chesapeake Energy Corporation,
ConocoPhillips, Devon Energy, Marathon Oil, Newfield Exploration Company, Pioneer Natural Resources USA,
Inc., QEP Resources, Inc., Southwestern Energy, Talisman Energy USA Inc.
23 USGS sometimes refers to unconventional resources as "continuous" resources.
14
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Chapter B—Scope and Industry Description
— USGS's 2015 report titled Trends in Hydraulic Fracturing... in the United States
from 1947 through 2010—Data Analysis and Comparison to the Literature states
that "...development of unconventional, continuous accumulations of oil, gas, and
natural gas liquids, including tight oil and gas, coalbed methane, and shale gas..."
(164DCNSGE01095).
• Papers published by the Society of Petroleum Engineers (SPE) have described UOG
as including shale and tight oil and gas. For example, SPE's 2012 paper titled
Comparisons and Contrasts of Shale Gas and Tight Gas Developments, North
American Experience and Trends includes the phrases "The more recent growth in
natural gas production from unconventional tight and especially shale reservoirs is a
result of technological advances (hydraulic fracturing and horizontal wells" and
"...unconventional gas resources, including CBM, Shale Gas, and Tight Gas" (57
DCN SGE00527).
• A survey by the American Petroleum Institute (API) and the American Natural Gas
Alliance states, "...unconventional wells are considered to be shale gas wells, coal
bed wells, and tight sand wells which must be fractured to produce economically" (28
DCN SGE00291).
• IHS, Inc.'s 2012 report titled America's New Energy Future: The Unconventional Oil
and Gas Revolution and the US Economy (111 DCN SGE00728) states, "Today,
unconventional natural gas—which includes shale gas, as well as natural gas from
tight sands formations and coal bed methane—accounts for nearly 65% of US natural
gas production" and "...'tight oil' or 'unconventional'—crude oil and condensate
production from sources such as shale and other low permeability rocks..."
• Scientific journal articles often indicate the names of formations that are considered
to be unconventional formations. For example, Warner et al., 2014, use the phrase
"The development of several unconventional formations (e.g., Marcellus, Barnett, and
Fayetteville)..." (173 DCN SGE01166). Similarly, Lewis, 2012, identifies
".. .unconventional gas exploration in the Marcellus shale..." (35 DCN SGE00345).
The EPA also looked at available state definitions, finding that four states have defined
"unconventional oil and gas" in their regulations. As expected, many of these definitions are
specific to resources and formations within those states. Table B-l summarizes these states'
definitions.
15
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Chapter B—Scope and Industry Description
Table B-l. Summary of State Regulatory Definitions
State
Code,
Chapter, or
Section
Regulatory Definition
DCN
AK
AS
38.05.965(14)
"Nonconventional gas" means coalbed methane, gas contained in shales,
or gas hydrates.
204 SGE01250
AR
Rule B-43
(a) For purposes of this rule, unconventional sources of supply shall
mean those common sources of supply that are identified as the
Fayetteville Shale, the Moorefield Shale, and the Chattanooga Shale
Formations, or their stratigraphic shale equivalents, as described in
published stratigraphic nomenclature recognized by the Arkansas
Geological Survey or the United States Geological Survey.
(b) For purposes of this rule, conventional sources of supply shall mean
all common sources of supply that are not defined as unconventional
sources of supply in section (a) above.
205 SGE01251
OK
165:10-3-28.
(b)(20)
"Unconventional reservoir" shall mean a common source of supply that
is a shale or a coalbed. "Unconventional reservoir" shall also mean any
other common source of supply designated as such by Commission
order or rule.
"Conventional reservoir" shall mean a common source of supply that is
not an unconventional reservoir.
206 SGE01252
PA
PA Code,
Chapter 78.
Oil and Gas
Wells
Unconventional formation—A geological shale formation existing
below the base of the Elk Sandstone or its geologic equivalent
stratigraphic interval where natural gas generally cannot be produced at
economic flow rates or in economic volumes except by vertical or
horizontal well bores stimulated by hydraulic fracture treatments or by
using multilateral well bores or other techniques to expose more of the
formation to the well bore.
Unconventional well—A bore hole drilled or being drilled for the
purpose of or to be used for the production of natural gas from an
unconventional formation.
Conventional formation—A formation that is not an unconventional
207 SGE01253
formation.
1.2.2 VOG Operators' Understanding of VOG Resources and Formations
Oil and gas industry representatives are aware of the names and types of formations from
which they are producing natural gas or crude oil. The EPA conducted several calls and site
visits with industry representatives; the documentation from these calls and site visits shows that
operators know both the names of the formations in which they are active and whether the
formations are shale or tight (e.g., tight sands, carbonates). The following list presents some
examples of operators' knowledge on these subjects:
• On February 29, 2012, the EPA met with members of the oil and gas industry to
discuss economic and engineering topics for this rulemaking. Two applicable
excerpts from the meeting notes (54 DCN SGE00521) are:
— "Apache is looking at potential closed loop fracturing projects in the Eagle Ford
and Barnett shale plays of Texas."
16
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Chapter B—Scope and Industry Description
— "...[HJydraulic fracturing in tight sands and shale is very similar. However, a few
minor differences include: tight sands fracturing fluids may require more clay
control additives than shale fracturing fluids; tight sands fracturing fluids may not
need the same viscosity as shale fracturing fluids."
The Petroleum Equipment Suppliers Association (PESA) surveyed 206 oil and gas
operators regarding the outlook for domestic unconventional resources. Some of the
results of the survey, including a graph of "Frac Jobs Targeting Selected Formations
in North America," indicate tight gas, shales, CBM, etc. (70 DCN SGE00575).
In a conference call with the EPA, North Star Disposal specified that it receives water
from shale gas operations. Figure 1 of the North Star conference call notes shows all
the "Pennsylvania Marcellus Shale Gas Wells" that sent wastewater to North Star in
2011, indicating that North Star knows which gas wells are in shale formations. North
Star is a drilling and operating company; as of July 2, 2012 (the date of the
conference call), it owned seven underground injection wells (23 DCN SGE00279).
After a site visit with Anadarko Petroleum on June 26, 2012, the EPA was given
information about the company's active operations. Anadarko specified its active
operation in formations categorized as shale gas, shale oil, and tight gas. Table 3-1 in
the Anadarko site visit report lists Anadarko's active U.S. formations by name (e.g.,
Eagle Ford) and type (e.g., shale oil) (24 DCN SGE00280).
In a conference call with the EPA, BLX, Inc., indicated that it knows which wells are
conventional versus unconventional, as well as which formation it is drilling into. For
example, the call notes state that "BLX...has drilled conventional wells since 1986
and decided to drill their first Marcellus well in 2006." The conference call took place
on May 15, 2012 (25 DCN SGE00283).
EPA conducted a site visit with Citrus Energy on June 19, 2012, and the operator
indicated that they know which basin and/or formation they are drilling into. During
the site visit, Citrus Energy representatives listed two specific basins/formations in
which it was (or had been) active: "Prior to drilling in the Marcellus region, Citrus
was active in the Anadarko basin in Oklahoma and Barnett Shale in Texas" (21 DCN
SGE00275).
In a conference call with the EPA, ConocoPhillips provided a count of its shale wells
by formation; it also mentioned "an on-going recycling pilot project for produced
water from a conventional formation." The conference call took place on November
5, 2012 (100 DCN SGE00695).
During the 2012 Tight Oil Water Management Summit Conference in Denver,
Colorado, the EPA attended a presentation by Katherine Fredriksen from Consol
Energy. Consol specified that the water discussed in the presentation was "produced
water from [its] shale operations" (33 DCN SGE00305.A10).
During the 2014 Produced Water Reuse Initiative Conference in Denver, Colorado,
the EPA attended a presentation by Erik Anglund from Anadarko Petroleum. The
presentation showed Anadarko's operations throughout the country and categorized
them as either "shale play," "natural gas," or "oil and natural gas" (160 DCN
SGE01017.A05).
17
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Chapter B—Scope and Industry Description
Operators must complete and submit a well completion report to their governing state oil
and gas agency after completing each new oil and gas well. All states require operators to submit
information on the geologic formation name (e.g., Bakken, Marcellus)24 in which the well is
completed, and all states except Florida require information about the well completion method
(e.g., hydraulic fracturing, acidization). The fact that well completion reports require the
formation name demonstrates that operators will have that information. These well completion
reports are further discussed in Section B.2.3 and in a separate memorandum to the record, titled
Well Completion Reports Memorandum (210 DCN SGE01263).
Information from the well completion reports is ultimately reported, along with other
reports,25 into a national database of wells called Drillinginfo (DI) Desktop® (176 DCN
SGE01170). DI is an oil and gas research firm in Austin, Texas. The DI Desktop® database
contains a record (i.e., row) for each oil and gas well drilled in the United States.26 Basic well
data contained in DI Desktop® for each well include the API number,27 state, basin, formation,
OQ
operator, and well trajectory. For much of the underlying data that support this TDD, the EPA
relied on analysis of the DI Desktop® well database described in a separate memorandum titled
Analysis of DI Desktop® (182 DCN SGE01180).
1.2.3 Rule Applicability
The final rule establishes requirements for wastewater discharges from UOG extraction
facilities to POTWs. Based on the definition of unconventional oil and gas: crude oil and natural
gas produced by a well drilled into a shale and/or tight formation (including, but not limited to,
shale gas, shale oil, tight gas, tight oil), the EPA was able to identify shale and tight formations
in the United States using publicly-available sources. The list of shale and/or tight formations is
published by the U.S. Energy Information Administration (EIA), and the name of the formation
into which a well is drilled is reported in well completion reports required by all States and
compiled into the national database owned by DI (see section above).
The U.S. EIA publishes summary maps of natural gas in the Lower 48 States and North
America and the maps are separated into the following: Conventional Fields, Shale Gas and Oil
Plays (193 DCN SGE01191), Major Tight Gas Plays, which includes tight gas and tight oil29 (11
24 Well completion reports sometimes refer to the formation as the "reservoir" or "pool."
25 Operators must submit other types of reports to state oil and gas agencies in addition to well completion reports.
Examples include production reports (crude oil, natural gas, and produced water), well integrity reports, well closure
reports, etc.
26 The database is subject to restrictions on its use and dissemination. Based on the license agreement for the version
of the database used to support these rulemaking analyses, access to the raw data in the database is limited to ERG
(EPA's contractor) and EPA personnel only, although summary data developed using queries may be disseminated
more widely. Wholesale "data dumps" may not be disseminated electronically. All disseminations of such summary
data, however, should cite Drillinginfo as the source of the information.
27 An API number is a unique identifier assigned to each well drilled for oil and gas in the United States.
28 DI Desktop® includes more technical information about each well such as depth, completion date, spud date,
annual crude oil, natural gas, and produced water production per well.
29 For example, the tight gas map (11 DCN SGE00155) shows the Austin Chalk formation in the West Gulf Coast
Basin. In its Assumptions to the 2015 Annual Energy Outlook report, the EIA shows that about half of the
technically recoverable resource in the Austin Chalk is crude oil.
18
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Chapter B—Scope and Industry Description
DCN SGE00155), Coalbed Methane Fields, and Offshore Fields (208 DCN SGE01255). Figure
B-3 and Figure B-4 show the UOG resources, respectively, in the lower 48 states.30 The EIA also
periodically publishes a list of all known UOG formation names in its AEO reports. The most
recent list can be found in Table 9.3 of the EIA's Assumptions to the 2015 Annual Energy
Outlook report (192 DCN SGE01190). Appendix F (Table F-3 and Table F-4) provides an
updated and more thorough list of UOG formations than what is shown in the EIA maps below
(i.e., Figure B-3 and Figure B-4).
The EPA was able to identify UOG wells using the basin and formation name in DI
Desktop® in combination with a list of known UOG formations published in Table 9.3 of the
EIA's Assumptions to the 2015 Annual Energy Outlook report (192 DCN SGE01190). Formation
names are also reported with the well completion reports as explained in Section B.2.3 (210
DCN SGE01263). This list of known UOG formations generally matches the formations shown
in the EIA's shale and tight plays maps provided in Figure B-3 (193 DCN SGE01191) and
Figure B-4 (11 DCN SGE00155). EPA used the combination of the formation names listed in DI
Desktop®, the EIA list of the known UOG formations, and the EIA shale and tight plays maps to
distinguish between shale and tight formations.
30 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.
19
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Chapter B—Scope and Industry Description
San Joaquin
Basin
Monterey-
Temblor
Monterey
Santa Maria-,
Ventura-Los
Angeles Basins
Montana
Thrust NioSrara*
Bet
Cody Heath>
O ^
'*£*? Powder Three
^-s"L_Rrver Basin Forks
,,'Willis-ton
Basin
Manning
Canyon
Hermosa
w
'atadox Basin
Pierre
Lewis
' San Juan *aton Ar«taito>rti.
Basm Basln
Pab Duro
C^c.fl
'iForestCity
Basin
?,C?!10" Chsrokee Platform
Mulkv
X
=odford FayetteVi"e Chattan-
h Aikoma Basin Hack Warrior /I
Abo-Yeso"" Bas"J^5*ntl I re^in / +
Ardmore Basin lrl~"4 ~
Ft Worth
Bone spring"'
Current play • Oldest stacked play
•Mixed shalg & chalk play
Current play -1 nternrediate depttVage stacked pby "Mixed shale & limeaotie play
***Mixed sJiale £ dolostone-
Current play - Shallowest youngest stacked play siitstone-sandsione piaj
*"*Mlxed stialA fi fcm*stone-
Prospective play s,»s.o««ar.ds.<™ pia,
Basin
H worm
Basin Haynesville-
Bamett Bossier
£^--T-^,
Spraberry**" ) Tuscaloosa
Pernian Basin y,
^J ^
Eagle Ford
Neal
Valley & Ridge
Province
iLA-MS Sal Basin
Western
Gulf;
Source: 193 DCN SGE01191
Figure B-3. Major U.S. Shale Plays (Updated April 13, 2015)
20
-------
Chapter B—Scope and Industry Description
Bowdoin- -,
Greenhorn
North-Central
Montana Area
Judrm River-
.Bigbprn Basin -Eagle
.Cretaceous
I / J.*
-^
MBerfea-Mu nyk vi lie
Bradford- Venango-B k
edifia.'Ciir'lton-Tus^arora
Hiobrara Chalk
Cleveland
Red Fork
jranrte Wash
Pictured Cliffs
Dakoia SaqJuan
Basin ,
Travis Peajf
Bossier /
Cotton Vilfey
-- Gilmer Lime
Pe nn -Perm Carbon 3te
~- Permian
Basin
Wilcoai-obo\
Olmos
Tight Gas Plays
Stacked Plays
— Shallowest .'' Youngest
- Deepes-1 .' Oldest
Inter -Basin Areas
Source: 11 DCN SGE00155
Figure B-4. Major U.S. Tight Plays (Updated June 6, 2010)
21
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Chapter B—Scope and Industry Description
2 INDUSTRY DESCRIPTION: UOG WELL DEVELOPMENT PROCESS
UOG well development includes the following processes: exploration, well pad
construction, well drilling and construction, well treatment and completion (e.g., stimulation)31,
and production. Before UOG well development, operators must obtain surface use agreements,
mineral leases, and permits. These steps can take a few months to several years to complete.
When they are completed, operators begin the well development process, as described in the
following subsections.
Throughout the well development process, many materials are transported to the well
pad. These materials include well casing and tubing; fuel (e.g., diesel, liquefied natural gas); and
base fluid, sand, and chemicals for hydraulic fracturing. 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) may be transported via truck or temporary piping (92
DCN SGE00625; 95 DCN SGE00635; 21 DCN SGE00275).
The largest volumes of UOG extraction wastewater generated during well development
are flowback, which is generated during the well completion process, and long-term produced
water, which is generated during production (see Section C.2 for characteristics of each). UOG
well drilling also generates wastewater, referred to in this document as drilling wastewater. As
shown in Figure B-5, produced water, drilling wastewater, and produced sand are collectively
referred to as UOG extraction wastewater.
31 Well treatment is a generic term that describes actions performed to a well such as well cleaning, stimulation, and
isolation, which are generally performed during well completion, the process of bringing a wellbore into production
after well drilling.
22
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Chapter B—Scope and Industry Description
UOG Extraction Wastewater
UOG Extraction Wastewater: wastewater sources associated with production, field exploration, drilling, well
completion, or well treatment for unconventional oil and gas extraction (including, but not limited to, drilling muds,
drill cuttings, produced sand, produced water).
1
Drilling Wastewater: the liquid
waste stream separated from
recovered drilling mud (fluid)3
and drill cuttings'1 during the
drilling process
1
Flowback: produced water
generated in the initial period
after hydraulic fracturing prior to
production (i.e., fracturing fluid,
injection water, any chemicals
added downhole, and varying
amounts of formation water)
Produced Water: the fluid
(brine) brought up from the
hydrocarbon-bearing strata
during the extraction of oil and
gas, and includes, where present,
formation water, injection water.
and any chemicals added
downhole or during the oil/water
separation process
Long-term Produced Water:
produced water generated during
the production phase of the well
after the initial flowback process
which can include increasing
amounts of formation water
1
Produced Sand: the slurried
particles used in hydraulic
fracturing, the accumulated
formation sands and scales
particles generated during
production (40 CFR 435. 1 l(aa))
1
Chemicals: added during the
oil/water separation process (40
CFR435.11(bb))
a—Drilling mud is the circulating fluid (mud) used in the rotary drilling of wells to clean and condition the hole and
to counterbalance formation pressure.
b—Drilling cuttings are the particles generated by drilling into subsurface geologic formations and carried out from
the wellbore with the drilling mud.
Figure B-5. UOG Extraction Wastewater
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, or another well for reuse. UOG extraction wastewater
is transported via truck or temporary piping (92 DCN SGE00625; 95 DCN SGE00635; 21 DCN
SGE00275).
2.1 UOG Exploration
Before well construction, a UOG operator conducts exploration—either before or after
obtaining a lease, depending on the site-specific circumstances. During exploration, UOG
operators use geological data (e.g., formation depth, formation thickness, formation slope,
permeability, porosity) to target the most favorable UOG formation from which to produce crude
oil and/or natural gas (22 DCN SGE00276). Operators can obtain geological data using some of
the following methods (22 DCN SGE00276):
23
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Chapter B—Scope and Industry Description
• Offset production data—analysis of existing production data from nearby wells.
• Existing drilling data logs—analysis of data logs from drilling existing wells.
• Seismic data—analysis of data collected using specially equipped trucks that send
and receive sound waves through the ground. Special service providers convert the
received sound waves into 2D or 3D images of the formation.
Geologists analyze the geological data and recommend well locations based on the areas
with the highest production potential. It is not always possible to drill in the exact location
recommended by a geologist due to several factors such as topography, environmentally
sensitive habitats, water availability, state restrictions for siting, or surface access restrictions
from land owners. In these situations, operators find the closest possible drilling location that
will still allow for the effective production of crude oil and/or natural gas from the well (95 DCN
SGE00635).
2.2 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 (explained in Section B.2.1). Development
involves drilling production wells once a hydrocarbon reserve has been discovered and
delineated. 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 by well trajectory as of 2014.
• 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 for
shale wells (57 DCN SGE00527). For shale wells, vertical drilling is typically used
by operators during the exploration phase of well development (95 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 (25 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 when 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 typically can vary in length between 1,000 and 5,000 feet (76 DCN
SGE00593; 91 DCN SGE00623). Horizontal drilling is the most common method for
continuous UOG formations (37 DCN SGE00354; 1 DCN SGE00010).
24
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Chapter B—Scope and Industry Description
Source: 76 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 (92
DCN SGE00625; 95 DCN SGE00635; 21 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 reduce surface disturbance (37 DCN
SGE00354; 2 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 the remaining wells on the pad after the initial wells show favorable economic conditions32
and production (95 DCN SGE00635).
Drilling for crude oil and natural gas is generally performed by rotary drilling, in which a
rotating drill bit grinds through the earth's crust as it descends. Well drilling and construction is
an iterative process that includes several sequences of drilling, installing casing, and cementing
succeeding sections of the well (95 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 (183 DCN SGE01181):
• Compressed gases. During the beginning phase of drilling a UOG well (i.e., the
initial drilling close to the surface), compressed gases may be used to minimize costs.
This category includes dry air, nitrogen gas, mist, foam, and aerated fluids.
Favorable conditions include sufficient oil and/or gas prices, available drilling rigs, available fracturing crews, and
permits.
25
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Chapter B—Scope and Industry Description
• 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,33 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. These are similar to oil-based
fluids; instead of using diesel oil and/or mineral oils, though, they use organic fluids
(e.g., esters, polyolefins, acetal, ether, and linear alkyl benzenes) with similar fluid
properties as diesel and mineral oils. Synthetic-oil-based fluids have been referred to
as more environmentally friendly34 than oil-based fluids but are also more expensive
(157 DCN SGE01006; 158 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 liquid waste stream,
referred to as drilling wastewater. Typically, drilling wastewater is immediately reused/recycled
for drilling the same well through a closed loop process. After well drilling is complete or when
the drilling wastewater can no longer be reused/recycled,35 operators manage it through other
methods (e.g., reuse/recycle for drilling another well, transfer to a CWT facility, injection for
disposal) (169 DCN SGE01125; 95 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 (201 DCN SGE01234; 95 DCN SGE00635; 52 DCN
SGE00516). Figure B-7 also compares drilling phase durations among UOG formations (e.g.,
Granite Wash requires 30 to 50 days for drilling while Barnett requires 10 or fewer days).
33 The UOG industry may refer to water-based drilling fluids that contain salts as "salt mud."
34 Using synthetic-oil-based drilling fluids results in a lower volume of wastewater that must be disposed. They also
have lower toxicities, lower concentrations of certain priority pollutants, lower bioaccumulation potential, and faster
biodegradation rates than oil-based drilling fluid.
35
At the stage when the drilling mud (fluids) can no longer be reused/recycled they are sometimes referred to as
"spent" or "spent drilling fluids."
26
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Chapter B—Scope and Industry Description
Granite Wash
Haynesville
Woodford
—Williston
Eagle Ford
Marcellus
Mississippian
Permian
Utica
Fayetteville
Harriett
DJ-Niobrara
Source: 179 DCN SGE01179
*The most recent quarter of well count data is preliminary and is subject to revision.
Figure B-7. Length of Time to Drill a Well in Various UOG Formations
(2012 through 2014)
2.3 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 is completed (150 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,36 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.
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.
27
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Chapter B—Scope and Industry Description
After operators complete a new oil and gas well for production, they must submit a well
completion report to the governing state oil and gas agency. All states require that the well
completion reports contain the following information (210 DCN SGE01263):
• Well API number
• Well completion technique (e.g., hydraulic fracturing, acidization)
• Formation, pool, or reservoir name in which the well is completed (e.g., Marcellus)
These well completion reports are documented in a separate memorandum to the record,
titled Memorandum to the Record Discussing Well Completion Reports (210 DCN SGE01263).
The following two subsections describe the well stimulation and flowback processes of well
completion that are commonly part of UOG well development.
2.3.1 UOG Well Completion: Well Stimulation
UOG well stimulation techniques include but are not limited to hydraulic fracturing,
acidization, or a combination of fracturing and acidization (146 DCN SGE00966; 225 DCN
SGE01345). The most common well stimulation technique for UOG wells is hydraulic
fracturing, discussed in the rest of this subsection (also refer to Section B.I) (1 DCN SGE00010).
Hydraulic fracturing of COG wells is also becoming more common, but traditionally COG wells
have been completed with open-hole techniques that allow the oil and/or gas resources to flow
naturally (35 DCN SGE00345; 61 DCN SGE00533).
Operators typically fracture UOG wells in multiple stages to achieve 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 (22 DCN SGE00276). Vertical wells are typically only
fractured with one stage (1 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.37 Consequently, a typical well may take two to seven days to
complete (15 DCN SGE00239; 169 DCN SGE01125). 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 about 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).38 See Section C.I for
information about fracturing fluid volumes and characteristics.
37
38
7 The hours per day depends on the operator, local ordinances, and weather.
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
28
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Chapter B—Scope and Industry Description
• 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.
Jt_ Jl JL
Source: 82 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) (24 DCN SGE00280; 21 DCN
SGE00275; 22 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 (24 DCN SGE00280; 195 DCN SGE01206). 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.
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.
29
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Chapter B—Scope and Industry Description
Source: 21 DCN SGE00275
Figure B-9. Freshwater Impoundment
2.3.2 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 (95 DCN
SGE00635). The flowback consists of a portion of the fluid injected into the wellbore and can be
combined with formation water. At the wellhead, a combination of flowback water, sand, and
product (crude oil, condensates, and/or natural gas) is routed through phase separators, which
separate products from wastes. Industry uses different types of separators depending on a number
of factors such as the type of production (i.e., crude oil, natural gas, condensate). 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 crude oil or condensate production).
Higher volumes of flowback water are generated in the beginning of the flowback
process and flowback rates decrease as the well goes into the production phase. Operators
typically store flowback in fracturing tanks onsite before treatment or transport offsite.39 In
addition to flowback, small quantities of crude oil, condensates, and/or natural gas may be
produced during the initial flowback process. The small quantities of produced gas may be flared
39 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 (95
DCN SGE00635).
30
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Chapter B—Scope and Industry Description
40
or if the operator is using "green completions," the gas may instead be captured. If oil is
produced, oil/water separators may be used
water after it is transported offsite.
41
or the oil may be recovered from the flowback
Source: 92 DCN SGE00625
Figure B-10. Vertical Gas and Water Separator
Flowback typically lasts from a few days to a few weeks (1 DCN SGE00010; 2 DCN
SGE00011; 90 DCN SGE00622; 75 DCN SGE00592; 27 DCN SGE00286). At some wells, the
majority of fracturing fluid may be recovered within a few hours (1 DCN SGE00010; 2 DCN
SGE00011; 90 DCN SGE00622; 75 DCN SGE00592; 27 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 (1
DCN SGE00010; 75 DCN SGE00592; 27 DCN SGE00286). Section C.3.1 provides more details
on flowback generation rates over time and fracturing fluid recovery percentages for specific
UOG formations.
40 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. The EPA identified a
transition period until January 1, 2015, to allow operators to locate and install green completion equipment (40 CFR
parts 60 and 63).
41 Operators sometimes use chemicals during the oil/water phase separation process.
31
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Chapter B—Scope and Industry Description
Source: 92 DCN SGE00625
Figure B-ll. Fracturing Tanks
2.4 UOG Production
After the flowback process, the well enters the production phase. During this phase, UOG
wells produce crude oil, condensates, and/or natural gas and water. This water, called "long-term
produced water" in this TDD, consists primarily of formation water and continues to be
produced throughout the lifetime of the well, though typically at much lower rates than flowback
(75 DCN SGE00592). Long-term produced water rates range from less than a barrel up to 4,200
gallons (100 barrels) per day and gradually decrease over the life of the well.42 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 to collect water during flowback. Produced water that is separated from the
product (crude oil, condensates, and/or natural gas) is stored 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) (24 DCN SGE00280; 21 DCN SGE00275; 96 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
(95 DCN SGE00635; 22 DCN SGE00276).
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 (27 DCN SGE00286).
32
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Chapter B—Scope and Industry Description
Source: 21 DCN SGE00275
Figure B-12. Produced Water Storage Tanks
3 INDUSTRY DESCRIPTION: 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 proj ections 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 (164 DCN SGE01095). More recently,
drilling has also increased in liquid-rich formations.43 Baker Hughes, one of the world's largest
oilfield services companies, periodically publishes location and other data for active U.S. rigs.44
43 Liquid-rich formations are those that either primarily produce crude 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.
44 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.
33
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Chapter B—Scope and Industry Description
Figure B-13 shows Baker Hughes' estimates of total number of active drilling rigs in the United
States between January 2000 and October 2015 and shows drilling trajectory (i.e., directional,
horizontal, vertical) and product type (i.e., crude oil, natural gas). While these counts include rigs
that are drilling for CBM and COG, drilling for UOG surpassed drilling in CBM and COG by the
late 2000's (194 DCN SGE01192). Both horizontal drilling and oil well drilling have increased
since 2000. As of October 9, 2015, 79 percent of rigs were drilling horizontal wells compared to
6 percent in January 2000.45 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 (202 DCN SGE01235). In 2014, approximately 1,800 active rigs drilled
over 37,000 wells (201 DCN SGE01234). Baker Hughes has not yet released the drilled well
count for 2015. As footnoted on Figure B-13, the number of active rigs drilling new wells
decreased significantly after 2014 likely due to low natural gas and crude oil prices (194 DCN
SGE01192).
1 Another seven percent of rigs were drilling directional wells in the United States as of October 9, 2015.
34
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Chapter B—Scope and Industry Description
if!
£
a
IB
5
',
1
-
41
-£
3
Year
Source: 179 DCN SGE01179
Figure B-13. Number of Active U.S. Onshore Rigs by Trajectory and Product Type over
Time46
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 October 2015. Based on data reported by Baker
Hughes and rig counts reported in other literature, the majority of rigs were drilling into
unconventional formations at this time (200 DCN SGE01233; 76 DCN SGE00595). Where
Baker Hughes did not specify the formation being drilled into, counts may include a mixture of
rigs that are drilling for UOG, CBM, and COG. Note that the number of active rigs has continued
to decline and the March 4, 2016, count was 463 active rigs in the United States (217 DCN
SGE01335).
The sharp decreases in active drilling rigs observed in 2009 and 2015 are likely attributed to the sudden drop in
natural gas and crude oil prices experienced in those years (194 DCN SGE01192).
35
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Chapter B—Scope and Industry Description
Table B-2. Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product Type (as of October 9, 2015)
Basin3
Permian
Otherd
Western Gulf
Williston
Appalachian
Anadarko
Anadarko
Denver
Anadarko
TX-LA-MS
Salt
Fort Worth
Appalachian
Arkoma
Formation"
c
c
Eagle Ford
c,e
Marcellus
Mississippian
Granite Wash
Niobrara
Woodfordf
Haynesville
Barnett
Utica
Fayetteville
Resource
Type3
Mix
Mix
Shale
Mostly shale6
Shale
Tight
Tight
Shale
Shale
Shale
Shale
Shale
Shale
Total
Gas Rigs by Well Trajectory
Directional
0
25
0
0
0
0
0
0
0
0
0
0
0
25
Horizontal
5
20
12
0
45
0
5
5
6
23
3
15
4
143
Vertical
0
11
0
0
1
0
0
0
0
0
0
0
0
12
Total
Gas
5
56
12
0
46
0
5
5
6
23
o
6
15
4
180
Oil Rigs by Well Trajectory11
Directional
4
19
0
2
0
0
0
0
1
0
0
1
0
27
Horizontal
182
66
65
62
0
11
6
19
40
0
0
3
0
454
Vertical
44
41
3
1
0
2
0
3
0
1
o
6
i
0
99
Total
Oil
230
126
68
65
0
13
6
22
41
1
3
5
0
580
Total
Rigs
235
182
80
65
46
13
11
27
47
24
6
20
4
760
Sources: 179 DCN SGEO1179
a—Baker Hughes (200 DCN SGE01233) 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).
b—Oil rigs include six "miscellaneous" rigs reported by Baker Hughes (200 DCN SGE01233).
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 rigs in the "Other" category 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 (76 DCN SGE00595).
f—This formation includes the Woodford-Cana, Arkoma Woodford, and Ardmore Woodford formations.
36
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Chapter B—Scope and Industry Description
3.2 UOG Resource Potential
This section quantifies how many new UOG wells may be drilled in the future (i.e., new
well potential), using USGS and EIA assessments, to estimate the potential number of new UOG
extraction wastewater sources. Assessments by the USGS and the EIA show substantial potential
for new UOG wells. The EIA also calculates new UOG well potential in its AEO, but because it
is only for several sub-formations,47 the EPA calculated new well potential for all UOG
formations.48 This analysis is the same as the EIA methodology and is documented in a separate
memorandum titled Data Compilation Memorandum for the Technical Development Document
for Effluent Limitations Guidelines and Standards for Oil and Gas Extraction (TDD) (179 DCN
SGE01179; 180 DCN SGEO1179.A02).
The two EIA-reported parameters that the EPA used to calculate new well potential are:
• Estimated ultimate recovery per well (EUR). EUR is the quantity of crude oil
and/or natural gas that is produced by a single well over its life.
• Technically recoverable resources (TRR). The TRR is the quantity of crude oil
and/or natural 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.49
EIA published these parameters for all known UOG formations in Table 9.3 of the EIA's
Assumptions to the 2015 Annual Energy Outlook report (192 DCN SGE01190). The EIA's
estimates of these parameters 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 (192 DCN SGE01190).
To evaluate new well potential, the EPA calculated new well potential for each formation
or sub-formation by dividing the TRR by the EUR. Appendix F provides EUR and TRR on a
formation basis based on this analysis. To calculate total TRR and new well potential by resource
47 For example, the Assumptions to the 2015 Annual Energy Outlook reported new well potential for several, but not
all, Bakken sub-formations: 13,045 wells (192 DCN SGE01190, Table 9.5, Bakken Central). The EPA estimated
approximately 13,072 new Bakken wells for the same Bakken sub formations (180 DCN SGEO 1179.A02).
Differences between EIA and EPA new well potential are due to rounding.
48 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 (192 DCN SGE01190;
194DCNSGE01192).
49 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.
37
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Chapter B—Scope and Industry Description
type, the EPA summed the TRR and the new well potential for all formations in each resource
type shown in Table F-2 and Table F-3. Table B-3 summarizes the total new well potential the
EPA calculated for the four UOG resource types.50
Table B-3. UOG Potential by Resource Type as of January 1, 2013
Resource
Type
Shale gas
Shale oil
Tight gas
Tight oil
All UOG
Weighted
Average" Oil
EUR
(MMbls per well)
0.008
0.096
0.016
0.095
0.035
Weighted
Average" Gas
EUR (Bcf
per well)
0.534
0.146
0.447
0.124
0.395
Total Oil TRR
(MMbls)
7,300
43,900
12,000
21,200
84,400
Total Gas
TRR (Bcf)b
515,900
66,800
339,100
27,700
949,500
Total New Well
Potential
(Beginning in
2013)
967,000
456,000
758,000
224,000
2,405,000
Active 2014
UOG Well
Count0
H: 56, 801
D: 1,836
V: 15,877
U: 17,755
H: 11,175
D: 12,565
V: 82,954
U: 36,208
H: 67,976
D: 14,401
V: 98,831
U: 53,963
Sources: 179 DCN SGEO1179
a—Weighted averages are based on total oil or gas TRR (i.e., formations with more TRR were given more weight
than formations with less TRR).
b—Gas production from shale and tight oil resources is associated gas that is produced simultaneously with oil.
c—Well counts are based on ERG's DI Desktop® data analysis explained in the Analysis ofDI Desktop®
memorandum (182 DCN SGE01180). They 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
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 2.4 million potential new UOG
wells—with associated extraction wastewater—may be drilled in the future. Table B-3 also
shows the approximate number of active UOG wells in 2014, broken out by well trajectory and
resource type, based on the EPA's analysis of the DI Desktop® well database (176 DCN
SGE001170; 182 DCN SGEO 1180).
3.3 Current and Projections of Future UOG Well Completions
In 2013 and 2014 alone, more than 27,00051 oil and gas wells were hydraulically
fractured nationwide each year (175 DCN SGE01169). As previously explained, hydraulic
fracturing is currently the most popular well stimulation technique for UOG wells. A survey
50 These estimates only include shale and tight oil and gas resources. They do not include CBM or COG.
51 This is based on EPA's analysis of FracFocus (186 DCN SGE01184). The actual number of wells fractured is
likely greater because some states where fracturing is common (e.g., Michigan) did not yet require reporting to
FracFocus during these years.
38
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Chapter B—Scope and Industry Description
conducted by the API and the American Natural Gas Alliance shows that, as of 2010, nearly all
unconventional wells were being completed using hydraulic fracturing (28 DCN SGE00291).52
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 (165 DCN
SGE01095.A09). A more recent survey of 205 UOG operators conducted by PESA53 shows that
in 2012 and 2013 about 10 percent of well completions involving hydraulic fracturing were
refracturing of existing oil and gas wells (70 DCN SGE00575).
In 2012, HIS, Inc. estimated the total number of UOG wells that UOG operators may
complete through 2035 (111 DCN SGE00728). The EPA generated Figure B-14 using data
published by HIS, Inc. (179 DCN SGE01179). The figure shows the projected number of UOG
wells completed annually and cumulatively. Unconventional gas is further broken down into
tight gas and shale gas. The projections estimated by HIS, Inc., show a gradual increase in annual
UOG well completions through 2035.
12,000
10.000
•s
f
s,ooo
=3
6,000
4.00C
2,000
Aoii^l Ti sht Gas
^^^~ CuaiJative Unconventional Gas
^^— rvi-ivlativa TV.-nrfJTtiiM-jl Oil
250,000
I
150,000 u
- 100,000
U
- 50,000
2025
Yeir
2030
2015 2020
Source: 179 DCN SGE01179
Figure B-14. Projections of UOG Well Completions
2035
52 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.
53 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.
39
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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 (164 DCN SGE01095). The EIA, in its 2015 AEO, projects that, within the next 30
years, the majority of the country's crude oil54 and natural gas55 will come from unconventional
resources (194 DCN SGE01192). Consequently, industry experts expect UOG produced water
volumes to continue to increase (103 DCN SGE00708; 46 DCN SGE00479; 107 DCN
SGE00722; 131 DCN SGE00768.A01; 132 DCN SGE00768.A25).
This chapter discusses UOG extraction wastewater volumes and characteristics. This
includes the following sources (see Figure B-5 above):
• Produced water—the fluid (brine) brought up from the hydrocarbon-bearing strata
during the extraction of crude oil and natural gas, and includes, where present,
formation water, injection water, and any chemicals added downhole or during the
oil/water separation process. Based on the type of oil and gas extraction method,
produced water can be further broken down into the following components:
— Flowback—the produced water generated in the initial period after hydraulic
fracturing prior to production (i.e., fracturing fluid, injection water, any chemicals
added downhole, and varying amounts of formation water). 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 produced water generated during the
production phase of the well after the initial flowback process which can include
increasing amounts of formation water. Long-term produced water continues to
be produced throughout the lifetime of the well.
• Drilling wastewater—the liquid waste stream separated from recovered drilling
mud56 (fluid) and drill cuttings57 during the drilling process.
• 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.
The EPA identified drilling wastewater and produced water as the major sources of
wastewater pollutants associated with UOG extraction, so these wastewaters are described
54 Grade oil includes "lease condensates," components that are liquid at ambient temperature and pressure.
55 Natural gas can include "natural gas liquids," components that are liquid at ambient temperature and pressure.
56 Drilling mud is the circulating fluid (mud) used in the rotary drilling of wells to clean and condition the hole and
to counterbalance formation pressure.
57 Drill cuttings are the particles generated by drilling into subsurface geologic formations and carried out from the
wellbore with the drilling mud.
40
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
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/reports, academic papers/reports, 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 (186
DCN SGE01184) and Data Compilation Memorandum for the Technical Development
Document (TDD) for Effluent Limitations Guidelines and Standards for Oil and Gas Extraction
(179DCNSGE01179).
Section C.I discusses the characteristics of fracturing fluid,58 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 (3 DCN SGE00046). Data in Section C.3 show that sodium and chloride make
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-1997.59 Because TDS in UOG produced water
primarily consists of inorganic salts and other ionic species, conductivity measurements may also
be used to estimate TDS.60 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.
1 FRACTURING FLUID CHARACTERISTICS
As discussed in Section B.2.3, 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,
58 The type of fracturing fluid and total fracturing fluid volume may influence the characteristics of UOG produced
water and are therefore described in this chapter.
59 40 CFR part 136 lists Standard Method 2540C as an approved test method for TDS.
60 The electrical conductivity of water is directly related to the concentration of dissolved ionized solids in the water.
41
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
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) (164 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) (97 DCN SGE00639; 70 DCN SGE00575).
PES A reports the following percentages of UOG operators using each water source as fracturing
fluid in the United States (70 DCN SGE00575):
• Surface water (e.g., rivers, lakes) (40 percent)
• Groundwater (36 percent)
• City/ municipal water61 (16 percent)
• Recycled UOG produced water (7 percent)62
• 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
projected values 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 (66 DCN SGE00556; 105 DCN SGE00710):
• 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 (105 DCN SGE00710).
61 PESA does not specify whether this water source is potable drinking water or treated municipal effluent (70 DCN
SGE00575).
62 The amount of UOG wastewater that is reused/recycled in fracturing fluid varies significantly by UOG formation.
See Section D.2 for more information about UOG wastewater reuse/recycle.
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-l. Sources for Base Fluid in Hydraulic Fracturing
Basin
All CA basins
Appalachian
Anadarko
Arkoma
Fort Worth
Gulf Coast
Permian (Far West)
Permian (Midland)
TX-LA-MS
Nationwide
UOG Formation
All formations
Marcellus (PA)
Marcellus (WV)
All formations
Fayetteville
Barnett
Eagle Ford
All formations
All formations
All formations
All formations
Resource
Type
Shale and tight
Shale
Shale
Shale and tight
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
82 to 90
77 to 83c'd
50 (40)
70
92 (75)
80 (50)
20 (20)
68 (35)
95 (90)
40
Brackish Waterb
0
0
C
30 (30)
0
3(15)
20 (40)
80 (30)
30 (40)
0(0)
53
Reu sed/Recycled
UOG Produced
Water
4
10 to 18
6 to 10
20 (30)
30
5(10)
0(10)
0(50)
2(25)
5(10)
7
Sources: 179 DCN SGEO1179
a—Parentheses contain projected data for the year 2020, reported as the "most likely" scenario by Nicot et al. 2012
(97 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 brackish water 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 (60 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
fluid by mass (1 DCN SGE00010). The additives and the quantity of additives used in fracturing
fluid depend on the formation geology, base fluid characteristics, and UOG operator (106 DCN
SGE00721; 4 DCN SGE00070; 136 DCN SGE00780; 137 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 (105 DCN SGE00710; 101
DCN SGE00705).
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
• 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 (105 DCN SGE00710; 101 DCN
SGE00705). Operators generally use gel fracturing fluids to fracture liquid-rich
formations43 (101 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 FracFocus63 (106 DCN
SGE00721). In addition, several sources have published information regarding fracturing fluid
additives and their uses in hydraulic fracturing (4 DCN SGE00070; 136 DCN SGE00780; 137
DCN SGE00781; 146 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 and Table C-4 show the medians and ranges (5th to 95th
percentile) of the maximum possible fluid concentrations reported by operators of the most
frequently reported ingredients in the FracFocus public disclosures, summarized in the EPA
ORD report, for hydraulically fractured gas and oil wells. Ingredients in Table C-3 and Table
C-4 are sorted from highest to lowest median of the maximum concentrations.
Table C-2. Fracturing Fluid Additives, Common Compounds, and Common Uses
Additive
Type3
Acid
Biocide
Breaker
Clay
stabilizer
Corrosion
inhibitor
Crosslinker
Common
Compound(s)b
Hydrochloric acid;
muriatic acid
Glutaraldehyde; 2,2-
dibromo-3-
nitrilopropionamide
Peroxydisulfates; salts
Potassium chloride
Ammonium bisulfite;
methanol
Borate salts; potassium
hydroxide
Purpose
Removes cement and drilling fluid 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.
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.
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 CBM formations.
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-2. Fracturing Fluid Additives, Common Compounds, and Common Uses
Additive
Type3
Friction
reducer
Gel
Iron control
pH adjusting
agent
Proppant
Scale
inhibitor
Surfactant
Common
Compound(s)b
Petroleum distillates
Guar gum;
hydroxyethyl cellulose
Citric acid
Acetic acid; potassium
or sodium carbonate
Quartz; sand; silica
Ethylene glycol
Isopropanol;
naphthalene
Purpose
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 natural gas or crude
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: 106 DCN SGE00721; 4 DCN SGE00070; 136 DCN SGE00780; 137 DCN SGE00781; 146 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.
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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 Wells from FracFocus (2011-2013)
Specific Constituents
Water
Guar gum
Hydrochloric acid
Distillates, petroleum, hydrotreated light
Sodium chloride
Glutaraldehyde
Ethylene glycol
Peroxydisulfuric acid, diammonium salt
Solvent naphtha, petroleum, heavy arom.
Sodium hydroxide
2-Butoxyethanol
Acetic acid
Quartz
Ethanol
Methanol
2,2-Dibromo-3-nitrilopropionamide
Citric acid
Isopropanol
Naphthalene
Propargyl alcohol
CAS Number
7732-18-5
9000-30-0
7647-01-0
64742-47-8
7647-14-5
111-30-8
107-21-1
7727-54-0
64742-94-5
1310-73-2
111-76-2
64-19-7
14808-60-7
64-17-5
67-56-1
10222-01-2
77-92-9
67-63-0
91-20-3
107-19-7
Maximum Concentration in Hydraulic Fracturing
Fluid (% by Mass)3
Number of
Reported Uses
7,998
3,586
12,351
11,897
3,608
5,635
5,493
4,618
3,287
4,656
3,325
3,563
3,758
6,325
12,269
3,668
4,832
8,008
3,294
5,811
Median
Concentration
0.18
0.1
0.078
0.017
0.0091
0.0084
0.0061
0.0045
0.0044
0.0036
0.0035
0.0025
0.0024
0.0023
0.002
0.0018
0.0017
0.0016
0.0012
0.00007
5th to 95th
Percentile
Concentration
0.000090-91
0.00057-0.38
0.0063-0.67
0.0021-0.27
0-0.12
0.00091-0.023
0.000080-0.24
0.000050-0.045
0.000030-0.030
0.000020-0.088
0.000010-0.041
0-0.028
0.000030-11
0.00012-0.090
0.000040-0.053
0.000070-0.022
0.000050-0.011
0.000010-0.051
0.0000027-0.0050
0.000010-0.0016
Source: 106 DCN SGE00721
a—Represents 17,035 FracFocus disclosures for gas wells.
Note: See Table 9 in the original source for further details about this data and how to interpret it (U.S. EPA. 2015.
Analysis of Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure Registry 1.0. Office of
Research and Development. 106 DCN SGE00721).
Table C-4. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in
Oil Wells from FracFocus (2011-2013)
Specific Constituents
Water
Hydrochloric acid
Guar gum
CAS Number
7732-18-5
7647-01-0
9000-30-0
Maximum Concentration in Hydraulic Fracturing
Fluid (% by Mass)3
Number of
Reported Uses
8,538
10,029
9,110
Median
Concentration
1
0.29
0.17
5th to 95th
Percentile
Concentration
0.0050-9.1
0.013-1.8
0.027-0.43
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-4. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in
Oil Wells from FracFocus (2011-2013)
Specific Constituents
Phenolic resin
Distillates, petroleum, hydrotreated light
Ethanol
Ethylene glycol
Methanol
Potassium hydroxide
Sodium hydroxide
Peroxydisulfuric acid, diammonium salt
Sodium chloride
Glutaraldehyde
Isopropanol
Solvent naphtha, petroleum, heavy arom.
2-Butoxyethanol
Acetic acid
Citric acid
Quartz
CAS Number
9003-35-4
64742-47-8
64-17-5
107-21-1
67-56-1
1310-58-3
1310-73-2
7727-54-0
7647-14-5
111-30-8
67-63-0
64742-94-5
111-76-2
64-19-7
77-92-9
14808-60-7
Maximum Concentration in Hydraulic Fracturing
Fluid (% by Mass)3
Number of
Reported Uses
3,109
10,566
3,536
10,307
12,484
7,206
8,609
10,350
3,692
5,927
8,031
3,821
4,022
4,623
3,310
8,577
Median
Concentration
0.13
0.087
0.026
0.023
0.022
0.013
0.01
0.0076
0.0071
0.0065
0.0063
0.006
0.0053
0.0047
0.0047
0.0041
5th to 95th
Percentile
Concentration
0.019-2.0
0.00073-0.39
0.000020-0.16
0.00086-0.098
0.00064-0.16
0.000010-0.052
0.00005-0.075
0.00028-0.067
0-0.27
0.00027-0.020
0.00007-0.22
0-0.038
0-0.17
0-0.047
0.00016-0.024
0.000040-12
Source: 106 DCN SGE00721
a—Represents 17,640 FracFocus disclosures for oil wells.
Note: See Table 8 in the original source for further details about this data and how to interpret it (U.S. EPA. 2015.
Analysis of Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure Registry 1.0. Office of
Research and Development. 106 DCN SGE00721).
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) (164 DCN SGE01095). Operators fracture UOG wells using from 50,000
to over 10 million gallons (1,200 to over 238,000 barrels) of fracturing fluid per well with up to a
million or more 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 (24 DCN SGE00280). Literature reports that tight oil and gas wells
typically require less fracturing fluid than shale oil and gas wells (61 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) (6 DCN SGE00110, 44 DCN
47
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
SGE00414). Other constituents, such as total organic carbon (TOC) and biochemical oxygen
demand (BOD5), 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 1,70064 mg/L but BOD5 in the
corresponding flowback and long-term produced water of 30065 mg/L or less on average (44
DCN SGE00414). As indicated in Table C-2, Table C-3, and Table C-4 organic materials (which
contribute to BODs and TOC) are typical chemical additives in fracturing fluid (44 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 (the 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
• Whether the producing formation is dry or contains formation 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
trajectory. Section C.2.2 provides detailed produced water volumes by UOG formation and well
trajectory.66
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
64 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.
65 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.
66 Section C.2.2 does not include drilling wastewater volumes by well trajectory because EPA identified drilling
wastewater volumes data without well trajectory information.
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
from Marcellus shale wells in Pennsylvania based on data from PA DEP's statewide waste
production reports for all wells active between 2004 and 2014 (184 DCN SGE01182). 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 and 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 a short
period of time and long-term produced water is generated over the well life, which may be more
than 10 years (111 DCN SGE00728).67
Horizontal (6,964 wells)
(Total UOG Extraction
Wastewater: 4,855 Mgal)
Drilling
Wastewater, 7%
Vertical (764 wells)
(Total UOG Extraction
Wastewater: 328 Mgal)
Drilling
Wastewater, 6%
Long-term
reduced Water,
62%
Sources: 184 DCN SGE01182
Figure C-l. UOG Extraction Wastewater Volumes for Marcellus Shale Wells in
Pennsylvania (2004-2014)
Figure C-2 shows the quantities of produced water (i.e., flowback and 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;68 "n" is the number of data points for each time period.69 As shown in the figure,
UOG produced water generation rates are highest immediately after well completion, when there
67 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-9).
68 As explained in Chapter B, the length of the flowback process is variable. Literature generally reports it as 30
days or less (60 DCN SGE00532). Other operators report it as only lasting five days (36 DCN SGE00350).
69 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-9.
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
is little or no crude oil and natural 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).
175,000
Time After Fracturing
Source: 186 DCN SGE01184
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 (184 DCN SGE01182). Table C-5 illustrates this trend for
UOG wells drilled into the Marcellus formation in Pennsylvania.
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-5. Median Drilling Wastewater Volumes for UOG Horizontal and Vertical Wells
in Pennsylvania
Well
Trajectory
Horizontal
Vertical
Median Drilling
Wastewater Volume per
Well(Gallons)
50,000
35,000
Range of Drilling Fluid
Volume per Well (Gallons) a
3,400-200,000
5,000-190,000
Typical Total
Measured Depth b
7,300-13,000
6,000-7,000
Number of
Data Points
3,961
230
Source: 184 DCN SGE01182
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).
The EPA collected information on volumes of drilling wastewater generated per well.
Table C-6 shows typical ranges of drilling wastewater 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.70 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-6. 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
Typical Drilling
Wastewater Volume
Range (Gallons per Well)
420,000-1,100,000
200,000-420,000
300,000a
170,000-500,000
84,000-420,000
200,000a
200,000a
130,000-420,000
100,000a
100,000a
3,400-200,000d
(median: 50,000)
Typical Total
Measured Depthb
(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
7,300-13,000
Number of Data
Points
5
2
1
6
8
1
1
7
1
1
3,962
Source: 183 DCN SGE01181
a—Only one data point was identified for these formations. Therefore, there is no range to display.
b—Total measured depth is the true length of wellbore drilled (i.e., sum of the vertical and horizontal).
c—Information is unknown.
d—Due to the large number of volume data points for the Marcellus formation, the EPA calculated the 10th and 90th
percentile values to represent the typical volume range and to eliminate outliers. The EPA was also able to calculate
a median for the Marcellus due to the large number of data points. For all other formations, the EPA used the
reported maximum and minimum volume range reported because of the limited number of data points.
70 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 (92 DCN SGE00625).
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
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-7 quantifies the portion of fracturing fluid
returned as flowback.71 Because the volume of fracturing fluid used during well stimulation
affects flowback quantities, fracturing fluid volumes are also listed. Based on the data in Table
72
C-7, total flowback volumes typically range between 40,000 to 1,100,000 gallons (950 to
25,000 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.
Table C-7. UOG Well Flowback Recovery73 by Resource Type and Well Trajectory
Resource
Type
Shale
Tight
Trajectory
H
D
V
H
D
V
Fracturing Fluid (MG)a
Weighted
Average1"
4.2
1.4
1.1
3.4
0.5
1
Range
0.091-24
0.037-20
0.015-19
0.069-12
0.046-4
0.016-4
Number of
Data Points
80,388
340
5,197
7,301
3,581
10,852
Flowback Recovery (Percent of
Fracturing Fluid Returned)3
Weighted
Average1"
7
33
96
12
10
4
Range
0-580
12-57
2-581
0-60
0-60
0-60
Number of
Data Points
7,377
36
57
75
342
130
Source: 186 DCN SGE01184
a—Most of the underlying fracturing fluid volume data and flowback recovery data were reported in different
sources. To avoid representing the data incorrectly, the EPA did not calculate total flowback volume for Table C-7.
Data are based on aggregated data from Table C-9, which contains volumes by formation.
b—The weighted averages are based on the number of data points (i.e., formation/trajectory combinations with more
data points were given more weight than those based on fewer data points).
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 constant74 over the well life compared
to flowback rates (95 DCN SGE00635). Table C-8 quantifies long-term produced water rates in
71 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 (186 DCN SGE01184).
72 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-7 because not
all data sources report both fracturing fluid volume and percent of fracturing fluid recovered as flowback.
73 Flowback recovery is the percent of total fracturing fluid injected during hydraulic fracturing that returns to the
wellhead during the flowback process.
74 Note that long-term produced water rates typically gradually decrease over the well life. However, the change is
small relative to flowback.
52
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
gallons per day by UOG resource and well trajectory. Typical (i.e., weighted average values in
Table C-8) long-term produced water rates range from about 390 to 1,100 gallons (9 to 26
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 rates than directional
and vertical shale wells. Similarly, for tight formation wells in Table C-8, horizontal wells have
the highest typical long-term produced water generation rates.
Table C-8. 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
Weighted Average1"
1,100
820
500
980
390
650
Range
0-29,000
0.83-12,000
4.8-51,000
10-120,000
15-8,200
0.71-2,100
Number of Data Points
43,893
1,493
12,551
4,692
10,784
34,624
Sources: 186DCN SGE01184
a—Data are based on aggregated data from Table C-9, which contains volumes by formation.
b—The weighted averages are based on the number of data points (i.e., formation/trajectory combinations with more
data points were given more weight than those based on fewer data points).
Abbreviations: gpd—gallons per day; H—horizontal well; D—directional well; V—vertical well
2.2 UOG Produced Water Volumes by Formation
Table C-9 shows UOG produced water volumes by UOG formation and well trajectory;
these data were used to generate the summary statistics in Section C.2.1. The data in Table C-9
are sorted alphabetically by basin. Because the EPA identified less data by formation for drilling
wastewater, Table C-9 does not include drilling wastewater volumes.
Data in Table C-9 illustrate that volumes of flowback and flow rates of long-term
produced water vary by formation. For example, horizontal UOG wells drilled into the Barnett
shale formation in the Fort Worth basin generate 530 gallons (13 barrels) per day of long-term
produced water compared to 1,900 gallons (45 barrels) per day for horizontal UOG wells drilled
into the Eagle Ford shale formation in the Western Gulf basin (91 DCN SGE00623). In some
cases, produced water even varies geographically within the same formation, which is not
evident in Table C-9. 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) (95 DCN
SGE00635).
53
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-9. Produced Water Volume Generation by UOG Formation
Basin
Anadarko
Appalachian
Arkoma
Denver J.
UOG
Formation
Caney
Cleveland
Granite Wash
Mississippi
Lime
Woodford
Clinton-
Medina
Devonian
Marcellus
Utica
Fayetteville
Codell
Resource
Type
Shale
Tight
Tight
Tight
Shale
Tight
Shale
Shale
Shale
Shale
Tight
Well
Trajectory
H
H
V
H
V
D
H
V
H
V
D
V
V
H
V
D
H
H
H
V
D
Fracturing Fluid (MG)
Weighted
Average"
8.1
1.7
0.18
4.9
0.53
—
2
0.34
5.2
0.36
1.6
—
—
4.6
0.25
0.16
6.8
5
3.5
0.23
0.26
Rangeb
4.4-12
0.2-4
0.033-3
0.2-8.3
0.085-3
—
1.3-5
0.016-0.71
1-12
0.015-1.6
0.21-1.9
—
—
0.9-11
0.11-5.4
0.092-0.17
1-13
1.7-11
2.4-7.1
0.11-0.46
0.14-0.5
Number
of Data
Points0
11
928
15
924
72
0
3,301
59
3,243
11
10
0
0
17,316
116
6
1,108
3,014
234
97
362
Flowback Recovery (% of
Fracturing Fluid Returned)
Weighted
Average"
—
—
50
—
50
—
50
—
34
—
—
—
—
7.1
40
—
2.5
—
16
0
0
Rangeb
—
12-40
50-50
6.5-22
50-50
—
50-50
—
20-50
—
—
—
—
4^7
21-60
—
0.66-27
10-20
—
0-4
0-3
Number
of Data
Points0
0
2
1
2
1
0
1
0
3
0
0
0
0
4,374
7
0
684
2
36
13
8
Long-Term Produced Water Rates
(gpd)
Weighted
Average"
—
410
66
980
520
480
—
10
5,500
—
—
7.9
13
820
200
—
800
430
400
59
46
Rangeb
—
59-2,000
56-400
10-2,400
330-790
160-940
37,000-
120,000
0.71-38
3,200-6,400
—
—
7.3-11
4.8-19
54-13,000
94-1,000
—
420-1,700
150-2,300
110-1,100
47-120
18-71
Number
of Data
Points0
0
1,160
130
762
1,397
83
4
16
198
0
0
551
197
6,494
741
0
764
2,305
179
158
667
54
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-9. Produced Water Volume Generation by UOG Formation
Basin
Fort Worth
Green River
Illinois
Michigan
UOG
Formation
Codell-
Niobrara
Muddy J
Niobrara
Barnett
Hilliard-
Baxter-
Mancos
Lance
Mancos
Mesaverde
New Albany
Antrim
Resource
Type
Tight
Tight
Shale
Shale
Shale
Tight
Shale
Tight
Shale
Shale
Well
Trajectory
H
V
D
H
V
D
H
V
D
H
V
D
H
D
H
V
D
H
D
H
V
D
H
V
Fracturing Fluid (MG)
Weighted
Average"
2.8
0.3
0.4
1.4
0.27
0.42
2.9
0.24
0.36
3.7
1.3
1.2
1.7
—
—
1.5
0.97
15
5.4
—
0.16
0.19
—
0.05
Rangeb
2.7-5.4
0.15-0.4
0.2-0.46
0.44-2.6
0.12-0.45
0.17-0.62
1.9-5.1
0.015-0.31
0.13-2.9
1-7.3
0.38-1.9
0.48-1.6
1-5.6
—
—
0.82-3.9
0.65-2.1
1.8-24
0.12-20
—
0.13-0.22
0.11-0.3
—
0.05-0.05
Number
of Data
Points0
65
490
806
6
139
758
1,435
455
25
26,495
3,773
96
2
0
0
37
881
24
10
0
21
448
0
1
Flowback Recovery (% of
Fracturing Fluid Returned)
Weighted
Average"
7.2
2.8
0
—
0.09
0
16
33
—
30
—
—
—
—
—
3.3
12
3.1
—
—
18
9.3
—
—
Rangeb
7.2-7.2
—
0-5
—
—
0-0
1.8-100
1.6-90
—
21-40
—
—
—
—
—
0.88-50
1.8-40
0.063-17
—
—
6.3-43
0.7-36
—
25-75
Number
of Data
Points0
32
21
11
0
15
11
173
29
0
11
0
0
0
0
0
38
187
8
0
0
15
94
0
2
Long-Term Produced Water Rates
(gpd)
Weighted
Average"
75
33
45
860
120
63
760
330
41
530
230
210
—
35
730
610
650
770
140
220
440
380
2,940
1,300
Rangeb
19-560
13-65
28-70
220-1,100
52-550
39-110
120-1,300
15-600
8.1-590
240-4,200
140-390
79-410
—
14-56
350-1,100
410-840
420-1,100
—
0.83-1,400
130-480
120-780
150-610
2,940-2,940
530-4,600
Number
of Data
Points0
38
2,113
1,853
6
340
1,106
1,213
5,808
38
11,957
2,416
481
0
10
6
61
2,787
26
36
5
33
856
1
7
55
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-9. Produced Water Volume Generation by UOG Formation
Basin
Permian
Piceance &
Uinta
Powder
River
UOG
Formation
Avalon &
Bone Spring
Barnett-
Woodford
Delaware
Devonian
(TX)
Morrow
Spraberry
Trend Area
Wolfcamp
Mesaverde
Hermosa
Mo wry
Resource
Type
Shale
Shale
Shale
Shale
Tight
Tight
Tight
Shale
Tight
Shale
Shale
Well
Trajectory
H
V
D
H
H
V
D
H
V
D
V
D
H
V
D
H
V
D
H
V
D
D
D
H
Fracturing Fluid (MG)
Weighted
Average"
2.3
0.4
1.8
2.1
1.3
0.19
0.26
0.47
0.14
0.11
—
—
1.3
0.91
1
8.3
1.1
1
6.7
1.6
1.8
—
—
2.5
Rangeb
1.2-5.7
0.07-1.3
1.2-3.4
0.5-4.5
0.42-3
0.044-0.38
0.15-0.4
0.091-5.5
0.075-1
0.037-0.13
—
—
0.069-6.5
0.071-1.6
0.06-1.5
2.4-12
0.58-1.9
0.4-1.7
1.4-12
0.18-2.3
0.17-3
—
—
0.76-7.4
Number
of Data
Points0
965
21
40
2
85
141
47
43
187
11
0
0
29
449
16
991
8,733
41
1,775
383
12
0
0
15
Flowback Recovery (% of
Fracturing Fluid Returned)
Weighted
Average"
19
—
33
—
79
210
—
—
—
—
—
—
—
—
—
—
—
—
16
—
—
—
—
15
Rangeb
4.9-40
—
12-57
—
9.7-230
84-580
—
—
—
—
—
—
—
—
—
—
—
—
12-23
—
—
—
—
4.3-580
Number
of Data
Points0
48
0
36
0
20
19
0
0
0
0
0
0
0
0
0
0
0
0
12
0
0
0
0
14
Long-Term Produced Water Rates
(gpd)
Weighted
Average"
2,700
2,000
1,300
—
9,400
1,600
4,500
1,700
3,700
2,400
130
140
1,000
1,000
1,200
890
780
620
3,500
780
1,700
510
47
450
Rangeb
2,100-5,700
1,000-4,800
800-3,300
—
5,000-29,000
1,100-3,800
2,400-5,700
630-2,700
1,400-5,400
250-12,000
41-290
34-2,200
420-3,800
670-1,500
660-2,500
530-3,900
690-920
370-1,500
450-15,000
460-1,400
750-3,600
130-700
27-260
61-2,100
Number
of Data
Points0
1,171
68
94
0
232
412
90
325
306
40
7
66
41
936
42
457
15,494
50
1,237
1,142
170
52
21
16
56
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-9. Produced Water Volume Generation by UOG Formation
Basin
San Juan
TX-LA-MS
Western
Gulf
UOG
Formation
Dakota
Mesaverde
Pictured
Cliffs
Bossier
Cotton Valley
Haynesville
Travis Peak
Tuscaloosa
Austin Chalk
Eagle Ford
Edwards
Resource
Type
Tight
Tight
Tight
Shale
Tight
Shale
Tight
Shale
Tight
Shale
Tight
Well
Trajectory
V
D
V
D
H
D
H
V
D
H
V
D
H
V
D
H
V
D
H
V
H
V
H
V
D
H
Fracturing Fluid (MG)
Weighted
Average"
0.16
0.12
—
—
—
—
3.8
0.61
0.55
4.4
0.27
0.45
5.7
0.9
3.9
3
0.17
—
11
13
1.7
—
4.8
0.94
—
—
Rangeb
0.061-0.34
0.063-0.32
—
—
—
—
2.6-5.4
0.22-1.7
0.18-1.1
0.25-8.5
0.018-1.4
0.046-4
0.95-15
0.2-2.5
1.9-7.3
0.25-6
0.032-4
—
6.1-14
4.7-19
0.83-5.4
—
1-14
0.23-2
—
—
Number
of Data
Points0
85
136
0
0
0
0
12
82
48
433
355
79
3,855
2
35
2
36
0
28
11
134
0
12,810
8
0
0
Flowback Recovery (% of
Fracturing Fluid Returned)
Weighted
Average"
1.6
4.1
—
—
—
—
—
—
—
60
60
60
5.2
—
—
—
—
—
—
—
—
—
4.2
—
—
—
Rangeb
—
1.1-60
—
—
—
—
—
—
—
60-60
60-60
60-60
5.2-30
—
—
—
—
—
—
—
—
—
2.1-8.4
—
—
—
Number
of Data
Points0
22
29
0
0
0
0
0
0
0
1
1
1
3
0
0
0
0
0
0
0
0
0
1,800
0
0
0
Long-Term Produced Water Rates
(gpd)
Weighted
Average"
75
230
43
21
370
4,700
37
230
150
710
700
620
910
330
660
710
630
520
—
7,400
2,200
97
1,900
1,200
4,300
2,300
Rangeb
35-490
53-950
14-560
15-180
190-720
1,200-8,200
5.6-370
4.8-480
1.2-300
410-2,600
490-890
240-980
84-1,200
210-560
130-1,200
110-4,200
270-930
140-800
—
220-51,000
980-5,100
21-1,500
88-6,200
510-2,300
3,000-5,600
1,000-24,000
Number
of Data
Points0
81
511
5
49
7
6
47
1,143
304
689
9,267
1,912
2,575
230
204
7
1,046
134
0
64
752
51
7,971
12
5
266
57
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-9. Produced Water Volume Generation by UOG Formation
Basin
Williston
UOG
Formation
Olmos
Pearsall
Vicksburg
Wilcox Lobo
Bakken
Resource
Type
Tight
Shale
Tight
Tight
Shale
Well
Trajectory
V
D
H
V
D
H
V
D
H
V
D
H
V
Fracturing Fluid (MG)
Weighted
Average"
—
—
1.9
0.11
—
3.5
0.21
0.23
0.33
0.1
0.094
2.4
0.16
Rangeb
—
—
0.37-6
0.078-0.21
—
1.6-5.6
0.072-0.61
0.11-0.63
0.082-2.4
0.042-0.6
0.058-0.16
0.35-10
0.04-2.7
Number
of Data
Points0
0
0
246
50
0
47
158
40
8
56
14
8,103
6
Flowback Recovery (% of
Fracturing Fluid Returned)
Weighted
Average"
—
—
—
—
—
—
—
—
—
—
—
19
—
Rangeb
—
—
—
—
—
—
—
—
—
—
—
5^7
—
Number
of Data
Points0
0
0
0
0
0
0
0
0
0
0
0
225
0
Long-Term Produced Water Rates
(gpd)
Weighted
Average"
560
160
180
78
51
160
700
830
370
650
500
910
2,400
Rangeb
150-2,100
69-290
13-700
52-370
15-470
53-1,500
330-990
390-1,400
250-610
400-940
300-4,200
500-3,800
150-5,100
Number
of Data
Points0
32
6
229
1,120
16
51
702
193
84
1,084
395
7,309
5
Sources: 186DCN SGE01184
a—Weighted averages are based on the number of data points reported by each data source (i.e., data sources that reported volume data for a particular
formation/trajectory combination based on a large number of data points were given more weight than those based on fewer data points).
b—For some formations, if only one data point was reported, the EPA reported it in the range column and did not report a weighted average value.
"—" indicates no data.
c—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.
Abbreviations: MG—million gallons; H—horizontal well; D—directional well; V—vertical well
58
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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 (27 DCN SGE00286; 6 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 (169 DCN SGE01125). 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) (75 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,75 organic, metal,
radioactive, and other. For all of the constituent categories, there are fewer data available for
drilling wastewater than for produced water generated at all UOG wells. The EPA presents
available data in the following subsections.
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.76 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-
75 Note that section 304(a)(4) of the Clean Water Act (CWA) designates the following as "conventional" pollutants:
biochemical oxygen demand (BOD5), total suspended solids (TSS), fecal coliform, pH, and any additional pollutants
the EPA defines as conventional. The Agency designated "oil and grease" as an additional conventional pollutant on
July 30, 1979 (see 44 FR 44501). The CWA does not define "classical pollutant." Rather, pollutants that are not
designated as either conventional or toxic are considered nonconventional pollutants. An example would be TDS. In
the discussion of pollutants in UOG wastewaters contained in Chapter C of the TDD, the EPA has organized the
discussion according to the categories in Table C-9, which includes the category "Classical and conventional." In
this context, "Classical and conventional" refers to a range of parameters that are determined via classical wet
chemistry analytical methods, including some CWA 304(a)(4) conventional pollutants as well as other parameters
such as nutrients, alkalinity, hardness, COD, etc.
76 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 186
DCN SGE01184 for additional details on the parameters reported in the literature reviewed. The accompanying
database (187 DCN SGE01184.A13) includes nondetect, below detection, or zero values that were reported in the
literature reviewed.
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
term produced water individually. In other instances, the data are presented as UOG produced
water, which includes both flowback and long-term produced water. Some data sources reported
characterization data as an aggregate (i.e., produced water) and others specified data as
representing flowback or long-term produced water. Given the uncertainty of which stage the
aggregate data represents, EPA presented it as produced water. However, where the type of
produced water was specified, EPA presents the specified data because some constituent
concentrations vary between 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.77 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 (18 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.
• Only data representing drilling wastewater from Marcellus shale formation wells
were available.
• 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), hardness as CaCOs, oil and grease, specific conductivity, TOC, and TSS
came from the Marcellus shale formation.
77 Table C-10 presents the number of detects, which represents the number of data points underlying sources
indicated were a detected value. This nomenclature is used throughout the TDD.
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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 Wells78
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
NDa-150
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
Source: 183 DCN SGE01181
a—Source did not report detection limit.
b—Source only reported median value.
Abbreviations: mg/L—milligrams per liter; ND—nondetect; 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.
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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
Carbonate
Chlorideb
COD
Hardness as CaCO3
Oil and grease
pH
Phosphate
Units
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
mg/L
SU
mg/L
Range
41-1,100
40-270
130-2,000
22-1,300
0-270
9,900-130,000
1,000-14,000
2,200-77,000
4.6-120
5.7-8.1
12-77
Median
140
110
700
160
53
70,000
3,200
21,000
5.6
7
31
Number of
Data Points3
265
13
10,206
154
205
5,228
149
80
134
9,154
4
Number of
Detects
265
13
7,274
153
144
2,190
149
80
99
6,147
4
Formations Represented"
Barnett (29); Eagle Ford (1); Marcellus (232); Woodford-Cana-
Caney (3)
Marcellus (5); Niobrara (5); Woodford-Cana-Caney (3)
Bakken (399); Barnett (6); Cleveland (11); Codell (9); Cody (38);
Cotton Valley/Bossier (3); Dakota (35); Eagle Ford (2925); Frontier
(224); Hilliard-Baxter-Mancos (32); Lance (1905); Lansing Kansas
City (16); Lewis (54); Mancos (2); Marcellus (154); Mesaverde
(461); Mesaverde/Lance (13); Mesaverde/Lance/Lewis (878);
Morrow (1); Mowry (5); New Albany (1); Niobrara (189); Oswego
(5); Pearsall (3); Spraberry (26); Woodford-Cana-Caney (2811)
Barnett (28); Marcellus (122); Medina/Clinton-Tuscarora (1);
Woodford-Cana-Caney (3)
Bakken (20); Barnett (4); Codell (2); Cody (1); Cotton
Valley/Bossier (2); Dakota (3); Eagle Ford (4); Frontier (16); Lance
(23); Lewis (6); Mesaverde (51); Mesaverde/Lance/Lewis (39);
Niobrara (8); Spraberry (26)
Bakken (22); Barnett (144); Cleveland (11); Codell (9); Cody (17);
Cotton Valley /Bossier (25); Dakota (3); Eagle Ford (1651); Granite
Wash/Atoka (1); Hilliard-Baxter-Mancos (33); Lance (1843);
Marcellus (287); Mesaverde/Lance (5); Mesaverde/Lance/Lewis
(943); Mowry (5); New Albany (1); Niobrara (193); 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 (421); Barnett (31); Cleveland (4); Codell (9); Cody (41);
Cotton Valley/Bossier (3); Dakota (35); Eagle Ford (1601);
Fayetteville (2); Frontier (223); Hilliard-Baxter-Mancos (33);
Lance (1933); Lansing Kansas City (16); Lewis (54); Mancos (2);
Marcellus (301); Medina/Clinton-Tuscarora (3); Mesaverde (460);
Mesaverde/Lance (13); Mesaverde/Lance/Lewis (917); Morrow (1);
Mowry (5); Niobrara (189); Spraberry (26); Woodford-Cana-Caney
(2831)
Barnett (1); Marcellus (1); Woodford-Cana-Caney (2)
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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
Specific conductivity
TDS
TOC
TSS
Units
uS/
cm
mg/L
mg/L
mg/L
Range
25,000-380,000
13,000-210,000
9.7-610
23-850
Median
120,000
94,000
82
140
Number of
Data Points3
165
5,196
132
38
Number of
Detects
165
2,164
127
38
Formations Represented"
Bakken (9); Barnett (26); Dakota (3); Eagle Ford (1); Marcellus
(104); Spraberry (19); Woodford-Cana-Caney (3)
Bakken (11); Barnett (38); Bradford- Venango-Elk (5); Cleveland
(11); Codell (9); Cody (17); Cotton Valley/Bossier (3); Dakota (3);
Devonian (11); Eagle Ford (1647); Fayetteville (4); Green River
(1); Haynesville/Bossier (2); Hilliard-Baxter-Mancos (33); Lance
(1839); Marcellus (373); Mesaverde/Lance (5);
Mesaverde/Lance/Lewis (942); Mississippi Lime (3); Mowry (5);
New Albany (1); Niobrara (195); Pearsall (3); Spraberry (26); Utica
(1); Woodford-Cana-Caney (8)
Bakken (2); Barnett (29); Eagle Ford (1); Marcellus (97);
Woodford-Cana-Caney (3)
Bakken (2); Barnett (29); Eagle Ford (1); Marcellus (113);
Woodford-Cana-Caney (5)
Source: 186 DCN SGE01184
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
63
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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 (109 DCN SGE00725). In Table C-ll, the relatively low median TOC
concentration (82 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 (3 DCN SGE00046). TDS is determined by measuring 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, specifically sodium and chloride, are the
majority (i.e., much greater than 50 percent) of TDS in UOG produced water (26 DCN
SGE00284). 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. The data presented in Figure
C-3 represents approximately 26,000 samples. 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. Specifically, for this figure, the "other dissolved
constituents" were captured by EPA by subtracting the sum of the listed parameters (e.g.,
sodium, chloride) from the total TDS concentration reported for the formation.
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Chapter C — Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
400,000
350,000
300,000
250,000
a> 1
s
200,000
150,000
a 100,000
Q
50,000
0
I
Other Dissolved Constituents
Potassium
Barium
Bromide
Magnesium
i Strontium
i Calcium
Sodium
i Chloride
V
Source: 186 DCN SGE01184
/
Figure C-3. Anions and Cations Contributing to TDS Concentrations in Shale and Tight
79
Oil and Gas Formations
As shown in Figure C-3, of those constituents specifically identified as contributing to
TDS, sodium, chloride, and calcium ions make up the majority of TDS in UOG produced water
according to available data. Additional ions that may contribute to the TDS in UOG produced
water include bromide, fluoride, nitrate, nitrite, phosphate, and sulfate. Figure C-4 contains box
and whisker plots of TDS, chloride, sodium, and calcium data for UOG flowback and long-term
produced water. The plots show the fifth percentile, first quartile, median, third quartile, and 95th
percentile values of the data. The data used to create this figure include constituent concentration
data from flowback or long-term produced water generated from UOG wells. The data show that
concentrations of TDS and chloride 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.
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
1,000,000
100,000
10,000
1.000
100
TDS-
Flowback
Source: 186 DCN SGE01184
IDS- Chloride- Chloride- Sodium- Sodiurn- Calcium- Calcium
LTPW Flowback LTPW Flowback LTPW Flowback LTPW
Figure C-4. Chloride, Sodium, and Calcium Concentrations in Flowback and Long-Term
Produced Water (LTPW) from Shale and Tight Oil and Gas Formations80
Table C-12 presents typical concentrations of bromide and sulfate, which 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 these 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 came from the Marcellus shale formation.
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-4.
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
• The majority of the data associated with nitrate came from the Bakken shale
formation.
• The majority of the data associated with bromide, fluoride, and sulfide came from the
Marcellus shale formation.
Table C-12. Concentrations of Bromide and Sulfate 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: 183 DCN SGE01181
Abbreviation: mg/L—milligrams per liter
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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
81-1,200
0.5-5
0.3-190
b
12-77
8.9-700
1.7-3.2
Median
510
2.5
0.3
5
31
110
3
Number of
Data Points"
111
99
110
2
4
8,203
79
Number of
Detects
111
97
110
2
4
5,451
72
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 (425); Barnett (31); Cleveland (9); Codell (1); Cody (27); Cotton
Valley /Bossier (1); Dakota (28); Devonian (4); Eagle Ford (1166);
Fayetteville (2); Frontier (123); Hilliard-Baxter-Mancos (28); Lance (1722);
Lansing Kansas City (15); Lewis (52); Mancos (2); Marcellus (301);
Medina/Clinton-Tuscarora (2); Mesaverde (438); Mesaverde/Lance (11);
Mesaverde/Lance/Lewis (916); Morrow (1); Mowry (5); New Albany (1);
Niobrara (133); Oswego (4); Pearsall (3); Spraberry (26); Woodford-Cana-
Caney (2726)
Barnett (1); Eagle Ford (1); Marcellus (77)
Source: 186DCN SGE01184
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
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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: 183 DCN SGE01181
a—Source did not report detection limit.
b—Source only reported median value.
Abbreviations: ND—nondetect; mg/L—milligrams per liter; ug/L—micrograms per liter
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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
Ethy Ibenzene
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
1.1-100
3-130
12-1,100
4.8-3,700
5-250
0-100
0-100
5,000-20,000
3.4-130
5-100
5,000-180,000
5-100
1.8-110
1.9-56
7.9-900
5-100
2-2,900
5.2-850
Median
5
5
40
8.5
5
5
5
10,000
5
5
10,000
5
5
2
86
5
6
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 (72)
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: 186DCN SGE01184
a—In some instances the sum of the number of data points associated with individual formations
there were data points reported in existing literature for which an associated shale or tight oil and
Abbreviation: ug/L—micrograms per liter
does not equal the total number of data points. In these instances,
gas formation was not identified.
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
Table C-3 indicates that ethanol, methanol, and naphthalene are commonly reported
additives to fracturing fluid. This suggests that at least some 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 also 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 (95 DCN SGE00635).
The EPA did not identify any quantitative information about diesel-range organics or
total petroleum hydrocarbons in UOG produced water. However, Table C-3 and Table C-4 show
that petroleum distillates are typically used in fracturing fluid. The EPA ORD's 2015 Analysis of
Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure Registry 1.0 contains
additional information about these constituents (106 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
commonly detected 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 data points) 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
commonly detected in UOG produced water. The EPA identified the following limitations to the
data presented in the table:
• The majority of the data associated with aluminum, antimony, arsenic, beryllium,
boron, cadmium, cobalt, copper, lead, lithium, manganese, mercury, molybdenum,
nickel, phosphorus, selenium, silver, strontium, thallium, tin, titanium, vanadium, and
zinc came from the Marcellus shale formation.
• The majority of the data associated with iron came from the Lance tight formation.
• The majority of the data associated with chromium came from the Bakken shale
formation.
Table C-16. Concentrations of Select Metal Constituents in UOG Drilling Wastewater
from Marcellus Shale Formation Wells
Parameter
Aluminum
Arsenic
Barium
Beryllium
Units
mg/L
mg/L
mg/L
mg/L
Range
1.7-6,900
NDa-4.2
2.6-2,000
NDa-0.018
Median
38
NDa
13
NDa
Number of
Data Points
12
12
14
8
Number of
Detects
12
6
14
2
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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
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
Range
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
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
8
8
13
12
8
8
12
12
8
12
12
8
1
12
4
8
8
12
13
12
Number of
Detects
4
1
13
8
o
6
6
12
10
1
11
11
2
1
9
4
o
6
i
12
13
10
Source: 183 DCN SGE01181
a—Source did not report detection limit
b—Source only reported median value
Abbreviation: mg/L—milligrams per liter; ND—nondetect
72
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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
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
Range
0.13-2
0.01-0.1
0.014-0.11
2.1-790
0.02-0.04
3.1-67
0.0014-0.05
16-16,000
0.021-0.9
0.013-5
0.024-0.5
4-170
0.013-0.42
4.6-150
Median
0.48
0.047
0.06
18
0.04
14
0.0086
190
0.3
0.5
0.13
38
0.03
44
Number of
Data Points"
206
112
135
1,191
114
151
134
9,272
386
124
150
3,070
133
155
Number of
Detects
175
79
99
1,190
72
137
92
6,261
352
92
110
383
96
132
Formations Represented (Number of Associated Data Points)3
Bakken (4); Barnett (31); Eagle Ford (5); Frontier (1); Lance (7); Marcellus (114);
Mesaverde (37); Mesaverde/Lance (2); Woodford-Cana-Caney (3)
Barnett (9); Marcellus (103)
Barnett (16); Eagle Ford (1); Marcellus (115); Woodford-Cana-Caney (3)
Bakken (3 12); Barnett (39); Cotton Valley /Bossier (2); Dakota (3); Devonian (4); Eagle
Ford (10); Fayetteville (2); Frontier (10); Lance (21); Lansing Kansas City (7); Marcellus
(210); Medina/Clinton-Tuscarora (1); Mesaverde (38); Mesaverde/Lance (8); Morrow (1);
Utica (1); Woodford-Cana-Caney (522)
Barnett (2); Marcellus (112)
Bakken (8); Barnett (33); Eagle Ford (2); Marcellus (103); Niobrara (5)
Barnett (16); Marcellus (115); Woodford-Cana-Caney (3)
Bakken (427); Barnett (40); Cleveland (11); Codell (9); Cody (41); Cotton Valley/Bossier
(3); Dakota (35); Devonian (4); Eagle Ford (1645); Fayetteville (2); Frontier (223);
Hilliard-Baxter-Mancos (33); Lance (1942); Lansing Kansas City (15); Lewis (53);
Mancos (2); Marcellus (343); Medina/Clinton-Tuscarora (2); Mesaverde (461);
Mesaverde/Lance (13); Mesaverde/Lance/Lewis (917); Morrow (1); Mowry (5); New
Albany (1); Niobrara (189); Oswego (5); Pearsall (3); Spraberry (26); Woodford-Cana-
Caney (2821)
Bakken (234); Barnett (27); Eagle Ford (6); Marcellus (116); Woodford-Cana-Caney (3)
Barnett (16); Eagle Ford (5); Marcellus (103)
Bakken (2); Barnett (23); Eagle Ford (6); Marcellus (116); Woodford-Cana-Caney (3)
Bakken (22); Barnett (36); Codell (8); Cody (6); Cotton Valley/Bossier (2); Dakota (3);
Eagle Ford (11); Fayetteville (2); Hilliard-Baxter-Mancos (32); Lance (1767); Marcellus
(301); Mesaverde/Lance/Lewis (772); Mowry (3); Niobrara (72); Spraberry (26); Utica
(1); Woodford-Cana-Caney (6)
Bakken (1); Barnett (15); Eagle Ford (1); Marcellus (113); Woodford-Cana-Caney (3)
Barnett (32); Eagle Ford (1); Hilliard-Baxter-Mancos (4); Lance (4); Lewis (1); Marcellus
(90); Mesaverde (8); Mesaverde/Lance/Lewis (4); Niobrara (11)
73
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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
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potassium
Selenium
Silver
Sodium
Strontium
Thallium
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
Range
3-1,300
0.47-9
0.000029-
0.00025
0.014-0.4
0.019-2
0.065-2.5
13-5,100
0.025-0.05
0.0093-
0.087
1,500-
80,000
1.5-3,500
0.017-0.5
Median
40
1.7
0.0002
0.038
0.14
0.2
120
0.05
0.05
5,400
360
0.1
Number of
Data Points"
7,116
238
118
140
154
105
4,074
110
115
7,404
325
120
Number of
Detects
4,374
224
88
118
124
103
1,447
75
75
4,382
323
83
Formations Represented (Number of Associated Data Points)3
Bakken (427); Barnett (40); Cleveland (11); Codell (9); Cody (39); Cotton Valley/Bossier
(3); Dakota (28); Devonian (4); Eagle Ford (1622); Fayetteville (2); Frontier (213);
Hilliard-Baxter-Mancos (33); Lance (1791); Lansing Kansas City (15); Lewis (52);
Mancos (2); Marcellus (327); Medina/Clinton-Tuscarora (2); Mesaverde (391);
Mesaverde/Lance (13); Mesaverde/Lance/Lewis (778); Morrow (1); Mowry (4); New
Albany (1); Niobrara (188); Oswego (5); Pearsall (3); Spraberry (26); Woodford-Cana-
Caney (1086)
Bakken (7); Barnett (38); Cotton Valley/Bossier (2); Dakota (3); Eagle Ford (8);
Fayetteville (2); Marcellus (156); Spraberry (19); Woodford-Cana-Caney (3)
Barnett (12); Eagle Ford (1); Marcellus (102); Woodford-Cana-Caney (3)
Bakken (1); Barnett (29); Eagle Ford (5); Marcellus (105)
Barnett (28); Eagle Ford (6); Marcellus (117); Woodford-Cana-Caney (3)
Bakken (6); Barnett (24); Eagle Ford (1); Marcellus (71); Woodford-Cana-Caney (3)
Bakken (382); Barnett (37); Cleveland (3); Cody (34); Cotton Valley/Bossier (3); Dakota
(22); Eagle Ford (150); Frontier (163); Hilliard-Baxter-Mancos (26); Lance (1709); Lewis
(39); Marcellus (137); Medina/Clinton-Tuscarora (2); Mesaverde (423); Mesaverde/Lance
(9); Mesaverde/Lance/Lewis (818); Mowry (5); Niobrara (109); Woodford-Cana-Caney
(3)
Barnett (7); Marcellus (103)
Marcellus (112); Woodford-Cana-Caney (3)
Bakken (427); Barnett (39); Cleveland (11); Codell (9); Cody (41); Cotton Valley/Bossier
(3); Dakota (35); Devonian (4); Eagle Ford (1632); Fayetteville (2); Frontier (226);
Hilliard-Baxter-Mancos (33); Lance (1938); Lansing Kansas City (16); Lewis (54);
Mancos (2); Marcellus (203); Medina/Clinton-Tuscarora (2); Mesaverde (465);
Mesaverde/Lance (13); Mesaverde/Lance/Lewis (933); Morrow (1); Mowry (5); New
Albany (1); Niobrara (193); Oswego (5); Spraberry (26); Woodford-Cana-Caney (1085)
Bakken (10); Barnett (36); Cotton Valley /Bossier (2); Dakota (3); Devonian (4); Eagle
Ford (9); Fayetteville (2); Frontier (2); Lance (21); Marcellus (184); Medina/Clinton-
Tuscarora (2); Mesaverde (38); Mesaverde/Lance (8); Utica (1); Woodford-Cana-Caney
(3)
Barnett (13); Marcellus (104); Woodford-Cana-Caney (3)
74
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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
Tin
Titanium
Vanadium
Zinc
Units
mg/L
mg/L
mg/L
mg/L
Range
0.021-2
0.024-0.5
0.18-26
0.06-1.5
Median
1
0.19
4.2
0.2
Number of
Data Points"
86
114
30
163
Number of
Detects
84
83
5
138
Formations Represented (Number of Associated Data Points)3
Barnett (12); Eagle Ford (3); Marcellus (71)
Barnett (17); Eagle Ford (2); Marcellus (95)
Barnett (1); Eagle Ford (2); Marcellus (27)
Bakken (2); Barnett (33); Eagle Ford (6); Fayetteville (2); Marcellus (117); Woodford-
Cana-Caney (3)
Source: 186 DCN SGE01184
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
75
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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 TDS in UOG produced water. Strontium, which is a group II alkaline earth
metal, is another metal that contributes to TDS in UOG produced water, with a median
concentration in the data evaluated by the EPA of 360 mg/L. Low-solubility salts of alkaline
earth metals (e.g., barium sulfate) commonly precipitate in pipes and valves, forming scale (12
DCN SGE00167). 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, according to data evaluated by the EPA. Figure C-5 shows box and whisker plots of
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,
_o
1
>rt
o
U
|
c«
n
nnn n -
inn n -
in n -
i n -
^
c_
n i
0
1
T
jr
? A
~r~t
rn r^h
n ^
95*
75*
SO^fMedian)
25*
5
f Q 9
0.1
c°
Source: 186 DCN SGE01184
Figure C-5. Barium Concentrations in UOG Produced Water from Shale and Tight Oil and
Gas Formations
3.2.4 Radioactive Constituents in VOG 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 (188 DCN
76
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
SGE01185). The EPA identified limited available data (primarily from the Marcellus Shale
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 (188 DCN SGE01185) 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 Data
Points
5
5
Number of
Detects
5
5
Sources: 183 DCN SGE01181
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 (188 DCN SGE01185) discusses potential interference issues
associated with various EPA methods and notes that the following methods may
experience interference from some 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)
4.7-24,000
300-820
0.66-1,700
Median
(pCi/L)
8,700
1,800
1,600
Number of
Data Points
103
3
94
Number
of Detects
101
o
J
92
77
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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,y-
spectrometry
90 1.1 Mod.
Range
(PCi/L)
170-420
10-88,000
960-3,300
15-16,000
400-1,100
Median
(PCi/L)
760
1,700
620
470
330
Number of
Data Points
3
74
3
73
3
Number
of Detects
3
74
3
72
3
Sources: 186DCN SGE01184
Abbreviation: pCi/L—picocuries per liter
As a point of comparison, Table C-20 includes data from a 2014 International Atomic
Energy Agency report (134 DCN SGE00769) that included radium isotope concentrations in
rivers, lakes, groundwater, and drinking water from public water systems. 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 millibecquerel per liter). The median concentrations of radium-226 and
radium-228 in UOG produced water in the Marcellus and Niobrara formations presented in
Table C-19 were above the maximum naturally occurring concentration in U.S. rivers, lakes,
groundwater, or drinking water from public water systems 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
—
—
—
—
78
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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 from public water
systems
Utah — well water
Wichita, Kansas — groundwater
Iowa — well water
South Carolina — well water
U.S. drinking water from public water
systems
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: 134 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—nondetect
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 "... [t]here
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," it did
conclude "... [fjhere 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]" (161 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, Table
C-3, and Table C-4). Guar gum may be found in UOG produced water at concentrations between
100 mg/L and 20,000 mg/L (88 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 (88 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
79
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Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics
wellbore. They can also create hydrogen sulfide,81 a potential human health concern that is also
highly corrosive and can harm the well casing and wellbore (106 DCN SGE00721).
3.3 UOG Produced Water Characterization Changes over Time
Concentrations of IDS, radioactive elements, metals, 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 (44 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 classical,
conventional and organic parameters 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.
81 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 (108 DCN SGE00723).
80
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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
•§ 60,000
I
50.000
40.000
30.000
20.000 -
10.000
-IDS
-Chloride
-Hardness (as CaC03)
Sodium
Calcium
- Strontium
Marcellus Shale Wastewater
Barnett Shale Wastewater
DayO Dayl Day 5 Day 14
Source: The EPA generated this figure using data from 44 DCN SGE00414.
Day 90
Figure C-6. Constituent Concentrations over Time in UOG Produced Water from the
Marcellus and Barnett Shale Formations
81
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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.
This creates a need for appropriate wastewater management infrastructure and disposal practices.
Except in limited circumstances,82 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 using Class II enhanced
recovery and disposal wells, where available. In fact, 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 enhanced recovery and disposal wells (91 DCN SGE00623). 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
UOG operators primarily use three methods for management of UOG produced water (86
DCN SGE00613; 22 DCN SGE00276; 58 DCN SGE00528):
• Dispose of wastewater via Class II disposal wells ("disposal wells")
• Reuse/recycle wastewater in subsequent fracturing jobs
• Transfer wastewater to a CWT facility
UOG operators primarily use the following methods for management of drilling
wastewater, which includes drill cuttings and drilling fluids83 (183 DCN SGE01181):
• Disposal via disposal wells
• Reuse/recycle in subsequent drilling and/or fracturing jobs
• Transfer to a CWT facility
• Onsite burial84
• Disposal via landfill
• Land application
82 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 CFR part 435 subpart E), EPA has not found that these types of permits are typically written for UOG
extraction wastewater as defined for in this document for the final rule.
83 As discussed in Chapter B, drilling muds (fluids) are reused/recycled until they are considered "spent," i.e., they
can no longer be reused/recycled, at this stage they are sometimes referred to as "spent drilling fluids."
84 Onsite burial involves temporary fluid storage in onsite open earthen or lined pits with burial of residual solids
after fluids are solidified, removed from the top, or evaporated.
82
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Figure D-l and Figure D-2 illustrate the primary management methods for UOG
produced water and drilling wastewater, respectively. 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 (105 DCN 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) (135 DCN SGE00779.A24).
UOG Well
Legend
Treated UOG Produced Water
Untreated UOG Produced Water
Injection into Class
II disposal wells
Reuse in
fracturing
UOG Wells
Figure D-l. UOG Produced Water Management Methods
83
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
UOGwell
o
> f
Burial
Legend
Treated drilling wastewater
Untreated drilling wastewater
> r
Landfill
1 '
O
Injection into class
II disposal wells
Treatment
in the field
CWT
facilities
POTWs
Surface
water
Reuse/Recycle
Figure D-2. UOG Drilling Wastewater Management Methods
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 (71 DCN SGE00579; 22 DCN SGE00276; 95 DCN SGE00635; 37 DCN
SGE00354; 105 DCN SGE00710). 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 (171 DCN SGE01128), 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) (178 DCN SGE01178; 102
DCN SGE00707; 103 DCN SGE00708). Although cost is the primary factor, operators also
consider other factors for wastewater management decisions such as proximity to management
options (e.g., CWT facilities, Class II injection wells), climate, federal or state regulatory
requirements, wastewater quality and volume, and operator-specific risk management policies
(91 DCN SGE00623). In some areas of the U.S., there may be additional considerations that
drive change from traditional use of Class II injection wells to other wastewater management
practices.85
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
85 For example, some studies suggest that Class IIUIC wells have been associated with nearby seismic activity (198
DCN SGE01216; 226 DCN SGE01351; 227 DCN SGE01352) and in some cases the use of those wells have been
restricted (227 DCN SGE01352). If use of a particular Class II UIC well becomes restricted, operators may utilize
other options such as transfer to a different Class II UIC well, reuse/recycle and transfer to a CWT.
84
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
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 2014. In recent years (2010 to 2014), transfer to CWT facilities, reuse/recycle in
drilling or fracturing, and injection for disposal—in that order—were the most common practices
for UOG drilling wastewater management in Pennsylvania (184 DCN SGE01182). In addition to
this detailed information about drilling wastewater management in Pennsylvania, the EPA
obtained information from the fifth largest U.S. oil and gas 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 (92
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).86 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 in the past, information available to EPA
indicates that these discharges were discontinued in 2011 (184 DCN SGE01182; 27 DCN
SGE00286; 35 DCN SGE00345; 71 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. The end of Chapter D
also presents EPA-collected data indicating that POTWs have not received any UOG extraction
wastewater between 2011 and the end of 2014. EPA received no data during the public comment
period on the proposed rule to indicate that this is still not the case.
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.
85
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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 used due to high TDS
early in flowback and abundance of disposal wells
Reuse/recycle not typically used 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: 179 DCN SGEO1179
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.
Blanks indicate the management practices has not been documented in the given location.
86
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160
Chapter D—UOG Extraction Wastewater Management and Disposal Practices
100%
0
2008 2009 2010 2011
Year
Annual UOG Drilling Wastewater Volume
• Underground Injection
• POTW
CWT Facility
^^^ ^^^^^
2012 2013
• Other
Reuse/Recycle
Landfill
2014
Sources: 184DCN SGE01182
Figure D-3. Management of UOG Drilling Wastewater Generated by UOG Wells in
Pennsylvania (2008-2014)
87
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
TY.ro nk,
o
I
Hamilton
London
Lansing
Detroit ,
I Windsor
i ' I-..i ••
Bun
Rochester
NT
K
A]
j
Har
MI .i ii
5
Cincinnati
%
^
^ankfort Cha(1
'/ - . *» '
PI ' , LYAJSII A
* >-,'
* F'lM' ' Harrisburg Trenton
'' ^ ^N MLW |J
c'Phitadelphic
M xK1. i .\nn Dover
1 y °
r> Ann ^ari*-'.Ii :
O
x xy
"Annapolis
Waning!, i, PIL\»\\KI
•^4 L_^
("kV
VIRGINIA
Richmond
* CWTFacililv
Disposal Well
Marcel lus Shale Plav
I Itica Shale Plav
Sources: Generated by the EPA using data from 178 DCN SGE01178 and 190 DCN SGE01187
Figure D-4. Active Disposal Wells and CWT Facilities Identified in the Appalachian
Basin
87
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 enhanced recovery and disposal wells (91 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
! The active disposal wells data were last updated in 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 2014, based on
publicly available information.
88
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
injection well control program codified in 40 CFR parts 144 to 148, the EPA established six
classes of underground injection wells (8 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 injection wells in the United States are Class II
disposal wells; the remaining 80 percent are mostly Class II enhanced recovery wells (8 DCN
SGE00132). Injection into Class II disposal wells typically involves injecting wastewater into a
porous and non-oil-and-gas-containing reservoir. Industry does not use Class II 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
(91 DCN SGE00623; 8 DCN SGE00132; 86 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 (181 DCN SGE01179.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 or have a program
determined to be effective to prevent underground injection that endangers drinking water
sources. 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 (84 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
89
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
(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 (190 DCN SGE01187; 191 DCN
SGE01187.A01).
Table D-2 presents the number of active Class II disposal wells by state (190 DCN
SGE01187; 191 DCN SGE01187.A01). Only states with active disposal wells are listed; all other
states have zero active disposal wells. Table D-2 also includes total state disposal rate on a
million gallon per day basis for each state. Lastly, Table D-2 presents average disposal rates on a
gallon per day per well basis for each state based on the active number of disposal wells and total
state disposal rate. Average disposal rates of individual wells vary significantly, reflecting the
geology of the underlying formation (23 DCN SGE00279). States are first sorted by geographic
region, then by the total state disposal rate. States with no disposal volume and rate data are
sorted by highest to lowest count of active Class II disposal wells.
The average disposal rate per well estimates in Table D-2 are not exact but rather are
general approximations based on a number of assumptions, listed below and described in more
detail in a separate memorandum, Analysis of Active Underground Injection for Disposal Wells
(190DCNSGE01187).
• Calculation of the average disposal rate per well (gpd/well). The EPA included all
wells identified as active even if some of these wells reported zero injection volume.
This assumption may decrease the average disposal rate per well but only affects
states where the EPA used state databases as the source for injection volumes (NM,
AK, and OK). However, the EPA excluded wells that were identified as just being
drilled because they could not have injected any wastewater.
• Calculation of the state disposal rate (MGD). The EPA included the number of
disposal wells identified as currently being drilled (e.g., under construction) in the
active number of disposal wells. This assumption may increase the current state
injection rates but was intended to capture wells that will inevitably come online in
the near future. However, the EPA excluded wells from all calculations that were
only permitted or proposed new well projects because these wells may be terminated
even after they are permitted or proposed (i.e., may never come online).
• Missing volume data. The EPA was unable to identify injected volumes for Illinois,
which has a substantial number of active disposal wells. Therefore, the total volume
of produced water injected into disposal wells in the nation estimated by this analysis
may be an underestimate. Also, there is no available injection volume data for wells
on tribal lands.
• Number of active disposal wells on tribal lands. It was unclear if the underlying
data sources EPA used to generate Table D-2 included Class II disposal wells on
tribal lands. Therefore, Table D-3 presents the number of active Class II disposal
wells on tribal lands reported by the EPA's Office of Ground Water and Drinking
Water (OGWDW) (159 DCN SGE01012; 190 DCN SGE01187; 191 DCN
SGE01187.A01). Table D-3 includes over 800 active Class II disposal wells located
on tribal lands in eight different states. Tribes are first sorted by geographic region,
90
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
then by the number of active Class II disposal wells. No disposal volumes or rate data
were available for Class II disposal wells on tribal lands.
Table D-2. Distribution of Active Class II Disposal Wells Across the United States
(Primarily 2012 and 2013 Data)
Geographic Region
(from the EIA)
Alaska
East
Gulf Coast/Southwest
Mid-Continent
Northern Great Plains
Rocky Mountains
West Coast
State
Alaska
Illinois
Michigan
Florida
Indiana
Ohio
West Virginia
Kentucky
Virginia
Pennsylvania
New York
Texas
Louisiana
New Mexico
Mississippi
Alabama
Kansas
Oklahoma
Arkansas
Nebraska
Missouri
Iowa
North Dakota
Montana
South Dakota
Wyoming
Colorado
Utah
California
Nevada
Oregon
Washington
Total
Number of Active
Disposal Wells3
45
1,054
772
14
208
190
64
58
12
9
10d
7,876
2,448
736
499
85
5,516
3,837
640e
113
11
3
395
199
15
335
292
118
826
10
9
1
26,400
Average Disposal
Rate per Well
(gpd/Well)b
182,000
C
16,200
246,000
7,950
8,570
6,970
4,650
17,500
6,380
33.7
52,100
40,300
48,600
24,200
53,300
25,600
35,900
25,400
19,100
2,270
C
53,300
32,700
17,400
107,000
48,800
83,400
86,800
54,600
C
C
41,300
State Disposal
Rate (MGD)
8.2
C
13
3.4
1.7
1.6
0.45
0.27
0.21
0.057
0.00034
410
99
36
12
4.5
140
140
16
2.2
0.025
C
21
6.5
0.26
36
14
9.8
72
0.55
C
C
1,050
Source: 190 DCN SGE01187
a—Number of active disposal wells is based primarily on data from 2012 to 2013.
91
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
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 2012 to 2013 data). These approximations are
based on a number of assumptions, detailed in a separate memorandum, Analysis of Active Underground Injection
for Disposal Wells (190 DCN SGE01187).
c—Disposal rates and volumes are unknown.
d—These wells are not currently permitted to accept UOG extraction wastewater (source: 110 DCN SGE00726).
e—Only 24 of the 640 active disposal wells in Arkansas are in the northern half of the state, close to the Fayetteville
formation (50 DCN SGE00499).
Abbreviations: gpd—gallons per day; MOD—million gallons per day
Table D-3. Distribution of Active Class II Disposal Wells on Tribal Lands (2014 Data)
Geographic Region
(from the EIA)
East
Gulf Coast/Southwest
Mid Continent
Northern Great Plains
Rocky Mountains
Tribe
ID
472
701
751
930
812
809
824
808
201
301
687
750
281
Tribe Name
Saginaw Chippewa Indian Tribe
Jicarilla Apache Nation
Ute Mountain Tribe of the Ute Mountain Reservation
Osage Nation
Pawnee Nation
Apache Tribe
Sac & Fox Nation
Comanche Nation
Blackfeet Tribe of the Blackfeet Indian Reservation
Three Affiliated Tribes of the Fort Berthold Reservation
Ute Indian Tribe of the Uintah & Ouray Reservation
Southern Ute Indian Tribe of the Southern Ute
Reservation
Arapahoe Tribe of the Wind River Reservation
Associated
State
MI
NM
NM
OK
OK
OK
OK
OK
MT
ND
UT
CO
WY
Total
Number of
Active
Disposal
Wells
7
1
2
775
5
2
2
1
6
5
48
31
4
889
Source: 190 DCN SGE01187
2.3 Underground Injection of UOG Wastewaters
Nationally, injection for disposal volumes have increased as crude oil and natural gas
production has increased. Figure D-5 shows the trend over time of injection for disposal volumes
(blue bars), total crude oil and natural gas production (solid lines), and UOG production in the
United States (dotted lines). The annual injection for disposal volume increased from 1995 to
2012 as UOG production ramped up significantly over the same period. The EPA observed a
similar trend in the Bakken shale formation in North Dakota. Figure D-6 shows the trend over
time of injection for disposal volumes in North Dakota (blue bars), total crude oil production in
North Dakota (solid black line), and Bakken shale crude oil production in North Dakota (dotted
black line). The annual injection for disposal volume increased from 1998 to 2013 as crude oil
production ramped up significantly over the same period. Figure D-7 further demonstrates how
additional disposal wells were drilled over the same time period in North Dakota to meet the
increased disposal demand.
92
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
The EPA anticipates that in many parts of the United States, additional injection for
disposal capacity will become available as demand increases with increased UOG production.
However, as illustrated above in Table D-2, underground injection for disposal capacity in close
proximity to producing wells is much less available in certain portions of the United States.
400
350 -
• Annual Injection for Disposal Volume (Billion
— Totafcrude Oil Prediction (Billion Bbl)
Total Natiral Gas Production (TCF)
-Shal&Tigte Oil Production (BillionBbl)
— Shal&Ti ght Natural Gas Producti on (TCF)
1990
1995
2000
2005
2010
Source: 171 DCN SGE01128; 194 DCN SGE01192; 213 DCN SGE01322; 220 DCN SGE01339; 221 DCN
SGE01340
Figure D-5. U.S. Injection for Disposal Volume and UOG Production over Time
88
Total crude oil and natural gas production includes lease condensates, CBM, onshore conventional, offshore,
conventional onshore Alaska, and offshore Alaska. Unconventional crude oil production also includes lease
condensates.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Annual ND Injection for Disposal Volume
(MG)
Total ND Crude Oil Production (Million Bbl)
-ND Balkan Cnida Oil Production (Million Bbl)
14,000
12,000
1998
2003
2008
2013
Source: 218 DCN SGE01336; 219 DCN SGE01337; 13 DCN SGE00182; 171 DCN SGE01128; 221 DCN
SGE01340
Figure D-6. Injection for Disposal Volume and Crude Oil Production over Time in North
Dakota
18,000
700
Annual ND Injection for Disposal Volume (MG)
ND Cumulative Batten Wells Drilled
ND Cumulative Disposal Wells Drilled
3 C 2,000
u ?
M o
1998
2003
2008
2013
Year
Source: 67 DCN SGE00557; 13 DCN SGE00182; 171 DCN SGE01128; 221 DCN SGE01340
Figure D-7. Injection for Disposal Volume, Cumulative Bakken Wells Drilled, and
Cumulative Disposal Wells Drilled in North Dakota
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Operators of commercial injection wells for disposal may impose a surcharge to dispose
of flowback (23 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 the injection of less-dense wastewater,89 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 typically use more power.
3 REUSE/RECYCLE IN FRACTURING
Many operators evaluate reusing/recycling UOG extraction wastewater before deciding
to manage it via another method (i.e., disposal well or CWT facility) (86 DCN SGE00613; 54
DCN SGE00521; 22 DCN SGE00276). Reuse/recycle involves mixing flowback and/or long-
term produced water from previously fractured wells with other source water90 to create the base
fluid91 used in a subsequent well fracture (3 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 (250- 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
(92 DCN SGE00625).
Since the late 2000s, UOG operators have increased wastewater reuse/recycle (86 DCN
SGE00613; 172 DCN SGE01143; 199 DCN SGE01231). 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 (86 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 (99 DCN
SGE00691; 54 DCN SGE00521; 86 DCN SGE00613; 5 DCN SGE00095).
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-5 in Section D.3.2 for these ranges) (86 DCN SGE00613; 101 DCN SGE00705; 88
DCN SGE00616). Gel fracturing fluid 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 (101 DCN
SGE00705; 86 DCN SGE00613; 88 DCN SGE00616). As a result, at present, gel designs require
89 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 (23 DCN SGE00279).
90 Source water is any fluid that makes up fracturing base fluid. See Section C. 1.1.
91 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
base fluid that meets the low end of the IDS criteria ranges (see Table D-5 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 (88 DCN SGE00616; 101 DCN SGE00705). This may be
changing: industry has demonstrated the use of higher-TDS base fluid in 2013 to 2014 for gel
fracturing as new chemical additives are becoming available for gel designs that tolerate higher
TDS concentrations92 (98 DCN SGE00667; 101 DCN SGE00705).
PESA surveyed 205 UOG operators about their wastewater management practices in
2012 (70 DCN SGE00575).93 Table D-4 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 (103 DCN SGE00708; 104 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 (103 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 (95 DCN SGE00635; 21 DCN SGE00275; 92 DCN SGE00625; 96 DCN
SGE00636).
92 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 (101 DCN SGE00705).
93 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-4. 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
Gulf Coast (Austin Chalk, Cotton
Valley, Vicksburg)b
Mid-Continent (Woodford, Cana,
Caney, Granite Wash)b
Rockies (Niobrara, Mancos)b
Resource
Type
Shale gas/oil
Shale gas
Shale gas
Shale gas/oil
Shale gas
Shale gas/oil
Shale oil
Unknown
Unknown
Unknown
Total sample (as reported by PESA)
Percent of
Wastewater
Reused/Recycled
for Fracturing
74
30
30
16
13
7
5
10
25
14
23
Percent of
Wastewater
Managed Using
Other Methods3
26
70
70
84
87
93
95
90
75
86
77
Percent of
Respondents
Planning to Increase
Reuse/Recycle
50
67
67
60
86
67
56
100
68
100
55
Source: 70 DCN SGE00575
a—PESA (70 DCN SGE00575) reported this as "disposal" but did not clearly describe what it means.
b—PESA (70 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 (174 DCN SGE01168). 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
(88 DCN SGE00616; 99 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 (70 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
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
treatment (95 DCN SGE00635; 21 DCN SGE00275; 92 DCN SGE00625; 96 DCN SGE00636;
22 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:
• Non-TDS removal technologies—technologies that remove non-dissolved94
constituents from wastewater, including suspended solids, oil and grease and bacteria,
or remove and/or exchange 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 typically 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
(189 DCN SGE01186), 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 (189 DCN SGE01186).
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 (86 DCN SGE00613; 5 DCN SGE00095):
• Solids removal (e.g., sedimentation, filtration, dissolved air flotation)
• Chemical precipitation
• Electrocoagulation
• Advanced oxidation precipitation
• Disinfection
94 The 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 or ion exchange may be used to remove certain metals or
compounds that can cause scaling. 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
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 offsite 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-8 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
treatment occurs at relatively high flow rates equivalent to the rate of hydraulic fracturing.95
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 (34 DCN SGE00331):96
• 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
95 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 (189 DCN SGE01186).
96 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
Other source
water
r~
Well pad
Blender
Base
fluid
UOG produced
water treatment
system
Treated
base
fluid
Blender
Fracturing tanks with
untreated wastewater
Fracturing
fluid
Pump
trucks
Proppant and
chemicals
Well
o
Source: Generated by EPA using 34 SGE00331.
Figure D-8. 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 or permeate). As discussed in the
introduction to Section D.3, operators have learned that low-TDS base fluid is not necessarily
required for fracturing. However, some operators may still use TDS removal technologies to
treat wastewater for reuse/recycle in fracturing. TDS removal technologies that UOG operators
have used to treat UOG extraction wastewater for reuse/recycle include reverse osmosis (when
TDS is less than approximately 50,000 mg/L) and evaporation/condensation and crystallization
(86 DCN SGE00613; 5 DCN SGE00095; 189 DCN SGE01186). Some vendors currently offer
skid-mounted mobile TDS removal units for reuse/recycle in the field (189 DCN SGE01186).
The EPA also identified several CWT facilities that treat UOG extraction wastewater that use
TDS removal technologies (e.g., evaporation/condensation) (26 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 (105 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)
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
• 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
SectionD.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 (105 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 (105 DCN SGE00710, 44 DCN SGE00414, 38 DCN SGE00357,
36 DCN SGE00350, 92 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) (105
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 (96
DCN SGE00636; 95 DCN SGE00635; 92 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, 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 (36 DCN SGE00350).97 On the other hand, data indicates that long-term produced
water in the Fayetteville shale formation has less than 40,000 mg/L TDS (92 DCN SGE00625).98
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 (4 DCN SGE00070):
• Fluid instability (change in fluid properties)
• Well plugging (restriction of flow)
• Well bacteria growth (buildup of bacteria on casing)
97 Data available to EPA indicates 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. This is based on sampling data for 62 wells.
98 This operator reported that it is able to reuse all of its UOG wastewater due to low TDS concentrations.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
• Well scaling (accumulation of precipitated solids)
• Formation damage (restriction of flow in the reservoir)
Table D-5 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-5.
Table D-5. 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
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: 179 DCN SGEO1179
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.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
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-5. 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 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
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 (21 DCN
SGE00275; 95 DCN SGE00635; 86 DCN SGE00613). Table D-6 shows observed blending
ratios for various formations. This table also includes theoretical upper end blending ratios as
presented in literature, based on the typical fracturing fluid volume and produced water volume
generated per well" for each formation (93 DCN SGE00627; 97 DCN SGE00639; 99 DCN
SGE00691).
Table D-6. 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: 179 DCN SGEO1179
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 93 DCN SGE00627; 97 DCN SGE00639; and 99 DCN SGE00691.
c— References do not specify a specific formation.
' This theoretical value reported in literature is irrespective of constituent concentrations.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
"—" 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 (105 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 (92 DCN SGE00625). Figure D-9 illustrates this concept100 with a
hypothetical situation for an operator in a single formation as reported by an operator (32 DCN
SGE00305.A03). During early years of development, the base fluid demand for fracturing wells
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 to dispose
of at least some portion of the produced water such as injection in disposal wells or transfer the
wastewater to CWT facilities.
4.5
4.0
3.5
3.0
O
UOG Produced Water
Generation
Demand for Fracturing
UOG produced water
generation exceeds
demand for fracturing
2010
2015
2020
2035
2040
2045
2050
2025 2030
Year
Source: 179 DCN SGE01179 (Generated by the EPA based on figure in 32 DCN SGE00305.A03)
Figure D-9. Hypothetical UOG Produced Water Generation and Base Fracturing Fluid
Demand over Time
1 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
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
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 a UOG well generating wastewater is far from 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-10 shows
how operators in the northeast region of the Marcellus reused/recycled a higher percentage of
wastewater than in the southwestern region between 2008 and 2011 (71 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 (31 DCN SGE00300).
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
200B 2009 2010.1 201 Ob 2011,. 201 Ib
w POTW
CWT
Injection for disposal
| Reuse
«! Unknown
2008 2009 20IOa 2010b 20! la 201 Ib
Time period
Source: Graphic reprinted with permission from Brian Rahm (71 DCN SGE00579).
Note: "a" and "b" for 2010 and 2011 represent the first and second half of the year, respectively.
Figure D-10. UOG Extraction Wastewater Management Practices Used in the Marcellus
Shale (Top: Southwestern Region; Bottom: Northeastern Region)
3.3.2 Storage
Storage requirements and the number of wells the operator is drilling per unit time under
its drilling program may also dictate when operators can reuse/recycle wastewater. In general,
the effective storage cost to the operator increases the longer UOG extraction wastewater is
stored before reuse in a subsequent well101 (21 DCN SGE00275). For example, an operator that
is considering reusing/recycling extraction wastewater for fracturing and fractures 12 wells per
year in an area may need to store wastewater an average of one month between fracturing jobs.
In comparison, an operator that fractures 50 wells per year in an area may only need to store
wastewater an average of one week before being able to reuse/recycle it in the next fracturing job
(25 DCN SGE00283). Section B.2 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
11 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.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
with source water (5 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 (72 DCN SGE00583; 105 DCN SGE00710; 196 DCN
SGE01207). This is because as the cost of fresh water and groundwater increases, the offset in
i m
costs from 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 (105 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 discharged103 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 (105 DCN SGE00710; 10 DCN SGE00139).
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 CFR 437.2(c)). CWT facilities that
accept UOG extraction wastewater are sometimes run by the UOG operator and are sometimes
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 (178 DCN SGE01178), 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.2.3) (178 DCN
SGE01178). 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 a
Class II disposal well)
• Discharge (to surface waters or POTWs)
102 Transportation distances may also affect costs.
103 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
• Multiple discharge options (a mix of discharge and zero discharge)
Pollutant discharges to surface waters or to POTWs from CWT facilities may not be
subject to the Oil and Gas Extraction ELGs (40 CFR part 435). Rather, they may be subject to
the CWT ELGs promulgated in 40 CFR part 437. Unlike the Oil and Gas Extraction ELGs, 40
CFR part 437 includes limitations and standards for both direct and indirect dischargers.
The level of treatment CWT facilities accepting UOG wastewaters use depends on factors
such as the fate of the treated wastewater. The two primary types of treatment technologies are
non-TDS removal technologies104 and TDS removal technologies,105 defined in Section D.3. In
general, CWT facilities typically accepting UOG wastewaters use non-TDS removal
technologies for treatment before reuse/recycle. Direct and indirect discharging CWT facilities
accepting UOG wastewaters currently use a mix of TDS and non-TDS removal technologies.106
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.107 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 (18 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, discharges from the CWT facility to the
POTW are controlled by an Industrial User Agreement that must incorporate the pretreatment
standards set out in 40 CFR part 437 and requirements set out in 40 CFR 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 CFR 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,
104 Examples of CWT facilities using this level of treatment are described in 92 DCN SGE00625; 95 DCN
SGE00635, 18 DCN SGE00245, 47 DCN SGE00481, and 43 DCN SGE00379.
105 Examples of CWT facilities using this level of treatment are described in 45 DCN SGE00476, 39 DCN
SGE00366, 40 DCN SGE00367, and 42 DCN SGE00374.
106 EPA is currently aware of several discharging CWT facilities accepting oil and gas wastes that, as of early 2016,
do not utilize TDS removal technologies. See 178 DCN SGE01178 for a list of known CWT facilities accepting
UOG wastewater and the discharge status and the level of treatment utilized at these facilities.
107 Zero discharge CWT facilities may also evaporate the wastewater or send it to underground injection wells (42
DCN SGE00374).
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
new state regulations in Pennsylvania, for example, have led direct-discharging CWT facilities to
use more IDS removal technologies (178 DCN SGE01178).
4.1.3 CWT Facilities with Multiple Discharge Options
Some discharging108 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)109 from PA DEP that includes
limits110 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) (31 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 NPDES permit limits that must 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 74 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-7 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 (178
DCNSGE01178).111
To generate Table D-7, 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 (178 DCN SGE01178), 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,
108 Discharge includes both indirect discharge (to a POTW) and direct discharge (to surface water).
109 More information available online at:
http://files.dep.state.pa. usAVaste/Bureau%20of%20Waste%20ManagementAVasteMgtPortalFiles/SolidWaste/Resid
ual Waste/GP/WMGR123.pdf.
110 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.
111 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-7 likely underestimates the number of CWT facilities accepting UOG extraction
wastewater.112
Table D-7. Number of CWT Facilities That Have Accepted or Plan to Accept UOG
Extraction Wastewater, by State
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
22
1
4(2)
0
44
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
8
0
0
0
9
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
40
4
6
4
74
Sources: 178 DCN SGEO1178
a—Information is current as of 2014; it is possible that since 2014 some listed CWT facilities have closed and/or
new CWT facilities not listed have begun operation. 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 and not included in the sum of total
known facilities.
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 (10 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.113 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-l 1 shows the trend over time of
active CWT facilities available to operators in the Marcellus and Utica shales,114 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
112The information in Table D-7 is current as of 2014; it is possible that since 2014 some listed CWT facilities have
closed and/or some CWT facilities not listed have begun operation.
113 This analysis included Pennsylvania, West Virginia, and Ohio.
114 The Marcellus and Utica shale formations are in the Appalachian basin.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
hundred active disposal wells, only 24 wells are located in the northern half of the state in close
proximity to Fayetteville shale wells (190 DCN SGE01187). As a result, the largest active
operator in the Fayetteville shale has constructed three CWT facilities. The EPA anticipates that
more CWT facilities will become available near UOG formations where access to disposal wells
is limited as additional UOG wells are drilled.
100
90
80
14.000
-4—Cumulative # of Active CWT Facilities
- - Cumulative # of Pending CWT Facilities
of Marcellus & Utica Wells Drilled
0
2004 2006
Sources: 178 DCN SGEO1178
200S
2010
2012
2014
Figure D-ll. 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 receiving water quality and biota and
111
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
affect downstream water use (27 DCN SGE00286; 35 DCN SGE00345; 71 DCN SGE00579; 59
DCNSGE00531;94DCNSGE00633; 162 DCN SGEO1077).""
115
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 CFR 403.3(q) defines a POTW as "a treatment works as defined by section 212 of the
[Clean Water] Act,116 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-8 presents concentrations of weak, moderate, and
strong domestic wastewater as would be typically experienced by a POTW (i.e., influent).
Table D-8. 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: 12 DCN SGE00167
Abbreviation: mg/L—milligrams per liter
Typical treatment processes used at POTWs are categorized into the following levels:
115 GWPC, 2014 (162 DCN SGEO 1077) 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."
116 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."
112
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
• 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.
• 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 (12 DCN SGE00167).
Figure D-12 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 Wastewater
Diagram A
Bar
Screen
and Grit
Chamber
Trickling I . / Secondary
Filter \ Clarifier
Chlorine
Contact
Chambers
Secondary
Clarifier
Primary
Clarifier
High Rate
Gravity 1 . J S|udg8 t „
Thickenerl 1 Digester
Sludge
Degritter
Land
Application
Source: 80 DCN SGE00602
Figure D-12. 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
113
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
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 (78 DCN SGE00599).
Table D-9 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 IDS).
Table D-9. 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: 79 DCN SGE00600
Note: 79 DCN SGE00600 references data from the November 5, 1999, updated 50-POTW study and the RREL
database compiled for the CWT effluent guidelines.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-10 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-10. U.S. POTWs by Treatment Level in 2012
Treatment Level
Less than secondary (e.g., primary)
Secondary
Greater than secondary (e.g., tertiary, advanced)
No discharge
Partial treatment13
Total
Percent of
Facilities (%)a
0.2
50.0
34.1
15.5
0.2
100.0
Number of
Facilities"
34
7,374
5,036
2,281
23
14,748
Combined Design
Capacity (MGD)a
546
17,765
23,710
2,557
287
44,866
Sources: 81 DCN SGE00603; 216 DCN SGE01332
a—The percent of facilities and number of facilities were taken from the 2012 Clean Watersheds Needs Survey
(CWNS) (published in 2016, containing 2012 data), but the 2012 CWNS did not report design capacities, so they
were taken from the 2008 CWNS.
b—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 (27 DCN SGE00286; 35 DCN
SGE00345; 71 DCN SGE00579).117 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 2008118 (203 DCN SGE01245). To identify POTWs that accepted
wastewater from UOG operations,119 the EPA reviewed the following sources:
• Notes from calls with regional and state pretreatment program coordinators (113
DCN SGE00742, 114 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 (128 DCN SGE00762)
• EPA Region 3's website (41 DCN SGE00368)
117 EPA acknowledges that COG operators are still using POTWs as a viable option for disposal of COG
wastewater.
118 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.
119 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.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
• Site visits, conference calls, and meetings with industry representatives (86 DCN
SGE00613; 54 DCN SGE00521), UOG operators (92 DCN SGE00625; 95 DCN
SGE00635; 21 DCN SGE00275; 24 DCN SGE00280), CWT facilities (30 DCN
SGE00299; 31 DCN SGE00300; 18 DCN SGE00245; 17 DCN SGE00244), and
Native American tribal groups (138 DCN SGE00785)
• PA DEP's statewide waste report data120 (203 DCN SGE01245; 184 DCN
SGE01182)
• The U.S. DOE's 2010 Water Management Technologies Used by Marcellus Shale
Gas Producers report (2 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) (185 DCN SGE01183). This memorandum is referenced throughout Section D.5.
The EPA identified POTWs that, at one time, accepted wastewater from UOG operators
generated by Marcellus shale wells. Table D-ll presents information about POTWs that have
accepted UOG extraction wastewater directly from onshore UOG operators.
120 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 (184 DCN SGE01182).
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-ll. POTWs That Accepted UOG Extraction Wastewater Directly 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: 185 DCN SGE01183
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Based on data collected through January 2016, the EPA concluded that none of the
POTWs listed in Table D-l 1 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.O). PA DEP data indicate that UOG operators in Pennsylvania stopped sending their waste to
POTWs in 2011 (203 DCN SGE01245). Furthermore, the EPA has not been able to identify any
POTW in any state that is currently 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 (138 DCN SGE00785). According to this information, there are no
tribes currently operating UOG wells that discharge wastewater to POTWs, nor are there any
tribes that own or operate POTWs that accept UOG extraction wastewater. EPA solicited
additional data and information on current industry practice as well as its preliminary finding that
no UOG facilities currently discharge to POTWs in the proposal. EPA did not receive data since
proposal to contradict this finding.
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.2.3, such discharges may not be subject to the ELGs for the oil and gas extraction category
which is the subject of the rule. Rather, discharges to POTWs from CWT facilities accepting
UOG wastewaters may be subject to ELGs for the Centralized Waste Treatment Category (40
CFR part 437).
The EPA reviewed PA DEP statewide waste reports (184 DCN SGE01182) and
discharge monitoring report (DMR) data (83 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 daily121 percentage of UOG
extraction wastewater accepted by the POTW as shown in Table D-12. 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-12 also presents the year in which the highest average daily flow 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-12, the contribution of UOG extraction wastewater was much higher
(e.g., up to 21 percent) for some POTWs for some years.
121 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. Therefore, it is possible that UOG extraction wastewater was discharged to the
POTWs intermittently such that actual peak daily flow of UOG extraction wastewater to the POTWs in Table D-12
was higher than the daily average.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-12. 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
City of Auburn
Brownsville Municipal
Authority
Borough of Jersey Shore
Allegheny Valley Joint
Sewer Authority
Ridgway Borough
Clairton Municipal
Authority
Moshannon Valley
Authority STP
Dravosburg
City of McKeesport
Reynoldsville Sewer
Authority
Bellefonte Water
Treatment Plant
Lock Haven City STP
Altoona Water Authority
NPDES
Permit No.
PA0092355
PA0022241
PA0026891
PA0020613
PA0026158
PA0026034
NY0021903
PA0022306
PA0028665
PA0026255
PA0023213
PA0026824
PA0037966
PA0028401
PA0026913
PA0028207
PA0020486
PA0025933
PA0027014
Maximum
Annual
Average Daily
UOG
Extraction
Wastewater
Flow (god)
93,000
84,000
180,000
56,000
67,000
130,000
1,800
9,400
6,000
30,000
6,300
12,000
3,400
1,300
11,000
1,280
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
0.20
0.88
0.69
4.30
0.97
4.15
2.29
0.33
16.25
0.80
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
0.91
1.1
0.88
0.69
0.65
0.30
0.15
0.39
0.07
0.16
0.07
0.06
0.04
Year of
Maximum
Average Daily
UOG Extraction
Wastewater
Flow
2008
2008
2008
2008
2008
2008
2008
2008
2008
2008
2010
2009
2008
2008
2009
2010
2008
2008
2011
Source: 185 DCN SGE01183
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 remove the
TDS, radioactive constituents, metals, chlorides, sulfates, and other dissolved inorganic
constituents found in UOG extraction wastewater.122 In addition, the performance of the
treatment technologies utilized at POTWs can be adversely affected by high concentrations of
constituents found in UOG extraction wastewaters. 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 (which may lead to exceeding permit limits
for BODs or TSS in discharges or inhibiting sludge settling, for example)
• 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)123 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 (209 DCN SGE01260; 146 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.
122 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
remove TDS, radioactive constituents, metals, chlorides, sulfates, and other dissolved inorganic constituents found
in UOG extraction wastewater and their performance may be adversely affected by the high concentrations of these
pollutants.
123 PA DEP issued AOs to many POTWs in Pennsylvania that were accepting or suspected to begin accepting
wastewater from UOG operations.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
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
contribute to TDS (79 DCN SGE00600). The EPA used all of this information to evaluate
treatment effectiveness at POTWs, primarily for TDS.
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-13 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-13. 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
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.
121
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-13. Summary of Studies About POTWs Receiving Oil and Gas Extraction
Wastewater Pollutants
POTW
Summary of Study Findings
Waynesburg, PA, POTW
High-salinity UOG produced water impacted biological growth in trickling filter. See
Section D.5.3.2.1.
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 SectionD.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) and chemical precipitation 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.124
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.
EPA could not find information about the treatment processes used by the Dannie Energy Corporation CWT
facility.
122
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-13. Summary of Studies About POTWs Receiving Oil and Gas Extraction
Wastewater Pollutants
POTW
Summary of Study Findings
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.
New Castle PA POTW
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 Section D.5.3.2.2.
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),125
aeration basins, clarifiers, activated sludge, aerobic digestion, and chlorine disinfection. The
Clairton POTW is permitted to treat a maximum of 6 MGD (126 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
(126 DCN SGE00758):
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 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-13 shows the results from the 24-hour composite sampling that occurred over
five days in December 2008. According to PA DEP data (184 DCN SGE01182), in 2008, the
Clairton POTW was accepting oil and gas wastewater amounting to an average of 0.05 percent
125 A comminutor is a machine that reduces the particle size of wastewater solids using a cutting device.
123
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
of the POTW flow. Looking at the average measured concentrations, the results indicate little
no removal of TDS or chloride.
2,500 T i
Influent after AfterPre- After Primary After Activated After Final i After Chlorine
or
2Cfif|
2nnn
3
icentration (nig
3
3 C
3 C
3
cripi
Influent after
Grit Removal
and Screening
•
After Pre-
Aeration Tanks
—
—
1
After Primary
Settling Tanks
1
'
After Activated
Sludge
— 1
—
1 1
u
1
;
After Final
Settling Tanks
—
After Chlorine
Disinfection
Maximum
Average
Minimum
—
i — i
i —
i —
TDS
Cl
TDS
Cl
TDS
Cl
TDS
Cl
TDS
Cl
TDS
Cl
Source: 185 DCN SGE01183
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-13. 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 (117
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-14). The pass through analysis assumes zero percent removal of TDS at
the POTW and concludes that (117 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.
124
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-14. 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: 117 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 (115 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 (184 DCN SGE01182).
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 (184 DCN SGE01182), in
2008, the McKeesport POTW was accepting only COG wastewater. The evaluation (125 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-14 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 (125 DCN SGE00757), McKeesport treated trucked
wastewater from conventional wells during the seven-day sampling period. These wastewater
sources are summarized in Table D-15, below.
125
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
700
600 -
ol
£
o
3
S3
—
500
400
300
200
100
0
Influent
Grit
Primary-Effluent
Effluent
IDS
Cl
IDS
Cl
IDS
Cl
IDS Cl
Source: 185 DCN SGE01183
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-14. McKeesport POTW: Technical Evaluation of Treatment Processes' Ability to
Remove Chlorides and TDS
Table D-15. 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
Flowback
Flowback
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: 115 DCN SGE00745
a—According to data from the technical evaluation, some waste streams were referred to as "frac" and "flowback,"
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
(115 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
126
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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-16 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 (115 DCN SGE00745).
Table D-16. 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: 115 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. (56 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.126 The study also
collected one sample in November 2010 of UOG extraction wastewater before it was mixed with
the municipal influent127 (see Table D-17).
126 The PA DEP waste reports data (183 DCN SGE01182) show that the McKeesport POTW stopped accepted COG
and UOG wastewater after 2011.
127 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
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
wastewater accounted for 0.14 percent of the total influent.128 The remaining influent wastewater
consisted of municipal wastewater typically treated by the POTW (see Table D-8 for typical
constituent concentrations in municipal wastewater).
Table D-18 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-17) were not available.
Therefore, it is not possible to know whether the data presented in Table D-17 are representative
of the UOG extraction wastewater influent on the date of the effluent sampling presented in
Table D-18. As discussed in Section C.3, UOG extraction wastewater characteristics vary over
time and from well to well.
Table D-17. 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: 56 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
128 Ferrar et al. (56 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-18. 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: 56 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. (56 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
Ridgwav, 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 2014.129 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 (184 DCN SGE01182). The POTW's total annual
average daily flow rate ranges between 0.8 and 1.5 MGD, based on 2008 to 2014 DMR data (83
DCN SGE00608).
The EPA created Figure D-15 using the sampling data submitted in the EPA's DMR
Loading Tool (83 DCN SGE00608) and PA DEP waste reports data (184 DCN SGE01182).
129 Ridgway's October 2011 NPDES permit (123 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
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
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, 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.
7,000
6.000
14.0
5.000
I
= 4;000
a
o
£ 3.000
a
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
accepting COG wastewater. Of particular interest is the fact that Ridgway POTW's contractor
estimated zero percent removals for TDS, chloride, and sulfate. All three of these constituents
are found in UOG extraction wastewater (124 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 (120 DCN
SGE00751; 184 DCN SGE01182). 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 (184 DCN SGE01182).
The POTW's average annual flow rate ranges between 1.4 and 1.9 MGD based on 2008 through
2014 DMR data (83 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 (120 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 (120 DCN SGE00751). Table D-19 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-19. Charleroi POTW Paired Influent/Effluent Data and Calculated Removal Rates
Parameter
Aluminum
Ammonia, as N
Barium
BOD5
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: 120 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 firac 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 MGD. 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 it could
continue accepting the gas wastewater as long as it was not violating its existing effluent
limitations (118 DCN SGE00749; 64 DCN SGE00552). In July 2009, WV DEP sent a letter to
the Clarksburg Sanitary Board with a list of requirements that would be imposed if it decided to
accept oil-and-gas-related wastewater (166 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 wastewaters
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 (128 DCN SGE00762; 129 DCN SGE00766).
132
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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 (116 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 (56 DCN SGE00525).
On December 4, 2008, the Franklin POTW entered into a Consent Order and Agreement
with PA DEP130 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. (56 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-20 shows the
mean and range of effluent concentrations at the Franklin Township POTW during the period
when it accepted industrial wastewater from the CWT facility and after it 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-20 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.
130 PA DEP had issued an AO to the Franklin POTW in October 2008, but the Consent Order and Agreement
superseded that order.
133
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-20. 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
38.8^3.5
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: 56 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 (155 DCN SGE00999). The
Wheeling POTW accepted industrial wastewater from the Liquid Asset Disposal (LAD) CWT
facility through August 2009131 and wastewater directly from UOG operators in 2008.132 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) (48 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 (152 DCN SGE00996).
The EPA analyzed sampling data submitted in its DMR Loading Tool (83 DCN
SGE00608) and PA DEP waste reports data (184 DCN SGE01182) and found that the effluent
concentrations of chloride experienced by the Wheeling POTW in 2008 were higher when it was
131 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 (156 DCN SGE01000).
132 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 (202 DCN SGE01245).
134
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
accepting UOG extraction wastewater and industrial discharges from the LAD CWT facility than
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.133 Data from an August 2009 letter from WV DEP to the
City of Wheeling states (167 DCN SGE01114)
The agency has determined that the following pollutants are of concern
associated with oil and gas related 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 (48 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,134 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
133 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.
134 The Patriot CWT facility uses primary treatment processes (e.g., settlement tanks, clarifier tanks) and chemical
precipitation to target the removal of suspended solids and metals prior to discharge.
135
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
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
study also evaluated the receiving stream (Mahoning River) water quality, upstream and
downstream of the POTW discharge (55 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-21. 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)135 (88
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-21 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.136 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 (88 DCN SGE00616), suggesting that TDS and chloride were not removed by the
POTW.
135 All flows were introduced into the Warren POTW over an eight-hour period.
136 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" (88 DCN SGE00616).
136
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-21. TDS Concentrations in Baseline and Pilot Study Wastewater Samples at
Warren POTW
Sample Type
Influent Concentration
(mg/L)
Effluent Concentration
(mg/L)
Percent Increase (%)
Baseline Samples
TDS
Chloride
584
143
599
157
2.6
9.8
Eight- Week Pilot Study Samples
TDS
Chloride
679
239
885
348
30.3
45.6
Source: 88 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 (88 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-22 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-22. EPA Region 5 Compliance Inspection Sampling Data
Pollutant
TDS
Chloride
Sulfate
TSS
BOD5
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
3.36^1.13
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: 88 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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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
As of March 2015, the Warren POTW was still accepting wastewater from the Patriot
CWT facility (139 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 IDS
concentration of 50,000 mg/L (29 DCN SGE00295).
Brockwav, 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" (143 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) (143 DCN SGE00931). The permit includes limits for pH,
carbonaceous BOD5, 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 (121 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-23 presents inhibition threshold levels for activated
sludge and nitrification, two treatment processes commonly used at POTWs, for select UOG
constituents identified in Section C.3.137 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).
137 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-23.
138
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
As discussed in Section A.2.2, 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 2004 Local Limits Development
Guidance (80 DCN SGE00602) 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-23. 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: 80 DCN SGE00602
a—Where multiple values are listed (divided by commas), the data were reported individually in 80 DCN
SGE00602 by different sources.
Abbreviations: mg/L—milligrams per liter; NA—not available
Because all POTWs are required to control TSS and BOD5, 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.
139
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
The purpose of these subsections is to identify instances of inhibition/disruption, or potential
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 (142
DCN SGE00930). The Johnstown POTW accepted both UOG and COG wastewater before 2008
and stopped accepting both in 2011 (184 DCN SGE01182). 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 7.9 and 17.1
MGD based on 2008 through 2014 DMR data (83 DCN SGE00608).
The EPA created Figure D-16 using the sampling data submitted in its DMR Loading
Tool (83 DCN SGE00608) and PA DEP waste reports data (184 DCN SGE01182). 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-16, 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,13S 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.139 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).
138
139
The EPA assumes that this phrase refers to both COG wastewater and UOG extraction wastewater.
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.
140
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
300
i
a
Annual Average COG Extraction Wastewater F low
Annual Average UOG Extraction Wastewater Flow
TSS
BOD-5
UOG Wastewater Acceptance
Period
6 Total Eiceedances
(2012 - 2014)
I- 0
2010
2011
2013
2014
2008 2009
Source: 185 DCN SGE01183
Note: The annual average extraction wastewater flows for COG and UOG are presented as stacked bars in order to
represent the total annual average oil and gas extraction wastewater influent flow.
Figure D-16. Johnstown POTW: Annual Average Daily Effluent Concentrations and
POTW Flows
California, PA, POTW
140
The California POTW uses a contact stabilization process to treat influent wastewater
(140 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 (184 DCN SGE01182). The POTW's average
annual daily flow rate ranges between 0.5 and 0.8 MGD based on 2008 through 2014 DMR data
(83 DCN SGE00608).
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 (12 DCN SGE00167).
141
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
The EPA created Figure D-17 using the sampling data submitted in its DMR Loading
Tool (83 DCN SGE00608) and PA DEP waste reports data (184 DCN SGE01182). 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 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-17, the
California POTW experienced elevated concentrations of TSS while accepting oil and gas
wastewater. Figure D-17 also shows that the California POTW experienced three exceedances of
its TSS permit limits.141
200 j-
UOG Wastewater
Acceptance Period
Annual Average COG Extraction Wastewater Flow
Annual Average UOG Extraction Wastewater Flow
TSS
s/i
IK
- *
If. "— '
— a
5
2008
2009
2010
2011
2012
2013
2014
a
a
Source: 185 DCN SGE01183
Note: The annual average extraction wastewater flows for COG and UOG are presented as stacked bars in order to
represent the total annual average oil and gas extraction wastewater influent flow.
Figure D-17. 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.
141 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.
142
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
The EPA created Figure D-18 using the sampling data submitted in its DMR Loading
Tool (83 DCN SGE00608) and PA DEP waste reports data (184 DCN SGE01182). 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-18, the Charleroi POTW
experienced elevated concentrations of TSS and BODs 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
2008
2014
Source: 185 DCN SGE01183
Note: The annual average extraction wastewater flows for COG and UOG are presented as stacked bars in order to
represent the total annual average oil and gas extraction wastewater influent flow.
Figure D-18. Charleroi POTW: Annual Average Daily Effluent Concentrations and POTW
Flows
142
Figure D-18 shows data for 2008 through 2014, excluding 2012 and 2013 because there is no PA DEP waste
report data or DMR Loading Tool data for the Charleroi POTW for 2012 or 2013.
143
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Wavnesburg, 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
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 (153
DCN SGE00997, 154 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" (119 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 (65
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-24) 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 (65 DCN SGE00554; 69 DCN SGE00573).
Table D-24. 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 POTW
0.44%
0.77%
1.95%
Source: 65 DCN SGE00554
a—Assuming 17 MGD is the total volume treated.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
The 2009 annual report (65 DCN SGE00554) states that:
It is believed thatpretreated brine wastewater from the developing oil & gas
industry is adversely affecting the ability of the final clarifiers to separate solids
via gravity settling. 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 (65 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-25 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-25. 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
Parameter
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
NPDES Permit
Limit (mg/L)
45
30
30
30
45
30
45
30
30
45
30
45
30
30
30
Measured
Value (mg/L)
58
37
34
38
64
45
61
50
37
46
31
60
40
33
38
Percentage Over
Permit Limit (%)
29
23
13
27
42
50
36
67
23
2
3
33
33
10
27
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-25. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW
(NPDES Permit Number PA0027511)
Month, Year
March 20 10
November 20 10
November 20 10
December 20 10
November 20 11
November 20 11
Parameter
TSS
TSS
TSS
TSS
TSS
TSS
Sample Type
Weekly maximum
Monthly average
Weekly maximum
Weekly maximum
Monthly average
Weekly maximum
NPDES Permit
Limit (mg/L)
45
30
45
45
30
45
Measured
Value (mg/L)
55
34
55
56
35
64
Percentage Over
Permit Limit (%)
22
13
22
24
17
42
Sources: 89 DCN SGE00620; 85 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 wastewater.143 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 (48 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."
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
Brockwav, 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
2008 and noticed an increase in sludge generation.144 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 (121 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 (9 DCN SGE00136; 161 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 well,145 disposal at a hazardous waste landfill,146 or disposal at a low-level
radioactive waste landfill147 (87 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-19
144 The EPA is not aware of any time when the Brockway POTW accepted UOG extraction wastewater.
145 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.
146 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.
147 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.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
shows an example of barium sulfate scaling in an oil and gas pipe in the Haynesville shale
formation.
Source: 133 DCN SGE00768.A26
Figure D-19. 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
accumulation at POTWs. Because radium148 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 (147 DCN
SGE00978) such as manufacturing, mineral extraction, or water processing (e.g., in treatment
processes at a POTW). PA DEP's 2015 study report149 (161 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
soils.150 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:
148 Radium is a naturally occurring radioactive element that ionizes in water to a divalent cation with chemical
properties similar to barium, calcium, and strontium.
149 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.
150 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.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
• "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."
• "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 (9 DCN SGE00136; 53 DCN SGE00519; 74 DCN
SGE00587).
Rowan et al. (16 DCN SGE00241) report a positive correlation between TDS
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 (161 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
• 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" (161 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-Fs.151
However, there is a potential for radiological environmental impacts from spills and the long-
term disposal of POTW-I filter cake" (161 DCN SGE01028). ERG's Radioactive Materials in
151 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.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
the Unconventional Oil and Gas (UOG) Industry memorandum (188 DCN SGE01185) provides
additional information and results from the PA DEP study.
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 (see Table C-ll), which
are precursors of several toxic DBFs (51 DCN SGE00509; 122 DCN SGE00754). Brominated
DBFs are reported to have greater health risks (e.g., higher risk of cancer) than chlorinated DBFs
(141 DCN SGE00800). Additional information and discussion on DBFs and other human and
ecological impacts can be found in other EPA resources (163 DCN SGE01093; 170 DCN
SGE01126).
UOG extraction wastewater discharged to POTWs could be a potential source of DBFs in
two scenarios:
• When UOG extraction wastewater is disinfected at a POTW (62 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 (74 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 (62 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 rates for the three POTWs
were not reported. The total volume of oil and gas wastewater accepted at POTWs 2 and 3 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-26 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.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
Table D-26. 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
Bromodichloromethane
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: 62 DCN SGE00535
Note: The EPA presents data for eight DBFs in Table D-26. Hladik et al. (62 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. (62 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. (62 DCN SGE00535).
Abbreviation: ND—nondetect; ug/L—micrograms per liter
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 (68 DCN
SGE00567; 74 DCN SGE00587).
Wilson and Van Briesen (94 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.
151
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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. (74 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 (112 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 (141 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-20 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.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
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0.16
0.14
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Abbreviations: TTHM MCL—total trihalomethane maximum contaminant level
Source: 141 DCN SGE00800.
Figure D-20. THM Speciation in a Water Treatment Plant (1999-2013)
Another example of concerns about DBF formation from oil and gas wastewater is shown
in PA DEP's response to a comment on Ridgway POTW's NPDES permit renewal. The
comment, from the University of Pittsburgh, stated that "bromide can create trihalomethane
byproducts." PA DEP's response noted that trihalomethanes are made up of one of the following
(followed parenthetically by measured effluent concentrations from the Ridgway POTW):
• Chloroform (nondetect)
• Bromodichloromethane (nondetect)
• Dibromochloromethane (nondetect)
• Bromoform (74 |ig/L)
PA DEP noted that the effluent concentration of bromoform was low enough not to be of
concern compared to water quality limits. However, it is studying the impact of bromides on
surface waters. PA DEP recognizes that UOG extraction wastewater has the potential to
contribute to the formation of DBFs.
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Chapter D—UOG Extraction Wastewater Management and Disposal Practices
In August 2013, EPA Region 3 issued a letter (144 DCN SGE00935) informing the
NPDES permitting authorities in the Mid-Atlantic region that
...conventionalandnonconventionalpollutants, 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 (145 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 (151 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.
154
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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
DCN
SGE00010
SGE00011
SGE00046
SGE00070
SGE00095
Source Citation
GWPC and ALL Consulting. 2009. Modern Shale Development in the United
States: A Primer. U.S. DOE. Office of Fossil Energy NETL. April 2009. Last
accessed on May 17, 2016:
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17
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DCN
SGE00110
SGE001277
SGE00132
SGE00136
SGE00139
SGE00155
SGE00167
SGE00182
SGE00187
SGE00239
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SGE00244
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SGE00280
SGE00283
SGE00284
SGE00286
SGE00291
SGE00295
SGE00299
SGE00300
SGE00305.A03
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SGE00331
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SGE00592
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SGE00627
SGE00633
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SGE00709
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128
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130
131
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DCN
SGE00754
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Source
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A
A
A
A
B
A
A
A
B
B
B
A
B
C
B
A
A
163
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Chapter E—Reference Flags and List
Table E-l. Source List
ID
140
141
142
143
144
145
146
147
148
149
150
151
152
153
154
155
156
157
DCN
SGE00787
SGE00800
SGE00930
SGE00931
SGE00935
SGE00935.A01
SGE00966
SGE00978
SGE00982
SGE00983
SGE00984
SGE00985
SGE00996
SGE00997
SGE00997.A01
SGE00999
SGE01000
SGE01006
Source Citation
Borough of California. 2009. Borough of California Response to 308 Request
for Information. (March 18).
McTigue, Nancy; Graf, Katherine; Brown, Richard. 2014. Occurrence and
Consequences of Increased Bromide in Drinking Water Sources.
Environmental Engineering & Technology, Inc.
Pennsylvania Department of Environmental Protection (PA DEP). 2012.
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Pennsylvania Department of Environmental Protection (PA DEP). 2012.
Brockway Area Sewer Authority— PA0028428— Final Permit 2012.
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. Toxic Screening Analysis Spreadsheet.
California Council on Science and Technology (CCST). 2014. Advanced
Well Stimulation Technologies in California: An Independent Review of
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PA DEP. 2014. PA DEP TENORM Study— Update 2nd Quarter 2014 Update.
U.S. EPA. 201 1. (Region 3) Letter to PA DEP regarding disposal of
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17, 2014.
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Mitch, William A. 2014. Enhanced Formation of Disinfection Byproducts in
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Science & Technology 48(19): 11 161-1 1169.
Kicinski, J. 2007. Wheeling POTW Analysis 4.
Borough of Waynesburg. 2009. Clean Water Act Section 308 Request for
Information.
Borough of Waynesburg. 2009. Clean Water Act Section 308 Request for
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McClung, L.A. 2008. Wheeling POTW Discharge Requirements.
City of Wheeling Water Pollution Control Division. 2007. Wheeling Effluent
Data.
U.S. EPA. 2000. Development Document for Final Effluent Limitations
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164
-------
Chapter E—Reference Flags and List
Table E-l. Source List
ID
158
159
160
161
162
163
164
165
166
167
168
169
170
171
172
173
DCN
SGE01009
SGE01012
SGE01017.A05
SGE01028
SGE01077
SGE01093
SGE01095
SGE01095.A09
SGE01113
SGE01114
SGE01123
SGE01125
SGE01126
SGE01128
SGE01143
SGE01166
Source Citation
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of Drilling and Completion Fluids. 6th edition. Gulf Professional Publishing:
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U.S. EPA. 2014. Class II Disposal Well Inventory Update. Office of Ground
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Anglund, E. 2014. Rev Ops Strategies for Sourcing Large Volumes of
Freshwater for Hydraulic Frac Ops in the Context of Competition from other
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Pennsylvania Department of Environmental Protection. 2015.
Technologically Enhanced Naturally Occurring Radioactive Materials
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Ground Water Protection Council (GWPC). 2014. Regulations Designed to
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http://www.swpc.ors/sites/default/files/files/Oil%20and%20Gas%20Resulati
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Abt Associates. 2015. Final Annotated Bibliography for Sec XIV,
Environmental Impacts, of the Preamble for "ELG and Standards for the
O&G Extraction Point Source Cat; Prop Rule"
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,
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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.
U.S. EPA. 2014. Tribal Unconventional Oil and Gas Operations and
Wastewater Management Call Summary.
NYSDEC. 2015. Final Supplemental Generic Environmental Impact
Statement on the Oil, Gas, and Solution Mining Regulatory Program.
U.S. EPA. 2015. Assessment of the Potential Impacts of Hydraulic Fracturing
for Oil and Gas in Drinking Water Resources. ORD.
Veil, J. 2015. US Produced Water Volumes & Management Practices in
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Lyons, B. and Tintera, J.J. 2014. Sustainable Water Management in the Texas
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Warner, N.R., et al. 2014. New Tracers Identify Hydraulic Fracturing Fluids
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B
A
165
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Chapter E—Reference Flags and List
Table E-l. Source List
ID
174
175
176
177
178
179
180
181
182
183
184
185
186
187
188
189
190
191
192
193
194
DCN
SGE01168
SGE01169
SGE01170
SGE01177
SGE01178
SGE01179
SGE01179.A02
SGE01179.A03
SGE01180
SGE01181
SGE01182
SGE01183
SGE01184
SGE01184.A13
SGE01185
SGE01186
SGE01187
SGE01187.A01
SGE01190
SGE01191
SGE01192
Source Citation
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Produced Warer Reuse for Irrigation. Chevron. Society of Petroleum
Engineers.
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Drillinglnfo, Inc. 2015. DI Desktop® March 2015 Download_CBI.
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ERG. 2016. Data Compilation Memorandum for the Technical Development
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ERG. 2016. Data Compilation Memorandum for the Technical Development
Document (TDD) Attachment 2: EIA UOG Resource Potential.
ERG. 2016. Data Compilation Memorandum for the Technical Development
Document (TDD) Attachment 3 : TDD Data Compilation.
ERG. 2016. Analysis of DI Desktop® Memorandum.
ERG. 2016. Unconventional Oil and Gas (UOG) Drilling Wastewater
Memorandum.
ERG. 2016. Analysis of Pennsylvania Department of Environmental
Protection's Oil and Gas Waste Reports.
ERG. 2016. Publicly Owned Treatment Works (POTW) Memorandum for the
Technical Development Document (TDD).
ERG. 2016. Unconventional Oil and Gas (UOG) Produced Water Volumes
and Characterization Data Compilation Memorandum.
ERG. 2016. UOG Produced Water Volumes and Characterization Data
Compilation — A13: UOG Wastewater Characterization Database.
ERG. 2016. Radioactive Elements in the Unconventional Oil and Gas (UOG)
Industry.
U.S. EPA. 2016. Unconventional Oil & Gas Wastewater Treatment
Technologies. U.S. EPA Office of Water, Engineering and Analysis Division.
ERG. 2016. Analysis of Active Underground Injection for Disposal Wells.
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Attachment 1 : Injection for Disposal Well Data.
U.S. Energy Information Administration. 2015. Assumptions to the Annual
Energy Outlook 2015.
U.S. Energy Information Administration. 2015. Lower 48 States Shale Plays.
Prepared by EIA Office of Oil and Gas. (April).
U.S. Energy Information Administration. 2015. Annual Energy Outlook 2015
with Projections to 2040. DOE/EIA-0383 (2015). (April).
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A
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A
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A
A
166
-------
Chapter E—Reference Flags and List
Table E-l. Source List
ID
195
196
197
198
199
200
201
202
203
204
205
206
207
208
209
210
211
212
213
DCN
SGE01206
SGE01207
SGE01208
SGE01216
SGE01231
SGE01233
SGE01234
SGE01235
SGE01245
SGE01250
SGE01251
SGE01252
SGE01253
SGE01255
SGE01260
SGE01263
SGE01275
SGE01277
SGE01322
Source Citation
Cart, J. 2015. Hundreds of illicit oil wastewater pits found in Kern County.
LA Times.
US Govt Accountability Office. 2015. Water in the energy sector: Reducing
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Baker Hughes. 2015. U.S. Onshore Well Count. (January 9). Downloaded on
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Baker Hughes. 2015. North America Rotary Rig Count (Jan 2000-Current).
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Arkansas Oil and Gas Commission. 2015. General Rules and Regulations.
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D
A
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A
B
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B
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A
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A
A
A
A
167
-------
Chapter E—Reference Flags and List
Table E-l. Source List
ID
214
215
216
217
218
219
220
221
222
223
224
225
226
227
DCN
SGE01330
SGE01331
SGE01332
SGE01335
SGE01336
SGE01337
SGE01339
SGE01340
SGE01341
SGE01341.A01
SGE01344
SGE01345
SGE01351
SGE01352
Source Citation
US DOE, US DOI, US EPA. 2014. Federal Multiagency Collaboration on
Unconventional Oil and Gas Research: A Strategy for Research and
Development. Last accessed on May 17, 2016:
http://unconventional.enersv.sov/pdf/Multiasencv UOG Research Stratesv.
Bdf
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EPA 830-R-15-005.
Baker Hughes. 2016. North American Rig Count Current Week Rig Count
Summary.
North Dakota Industrial Commission. 2015. North Dakota Drilling and
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North Dakota Industrial Commission. 2015. North Dakota Drilling and
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U.S. Department of Energy. 2014. AEO 2014 Market Trends Figure MT 53
Data. U.S. Energy Information Administration (El A).
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Data. U.S. Energy Information Administration (El A).
North Dakota Industrial Commission. 2016. North Dakota Injection Data.
Day, Ashleigh M. 2016. North Dakota Injection Data Copyright Clarification
and Data Explanation. North Dakota Industrial Commission.
CH2MHill. 2015. U.S. Onshore Unconventional Exploration and Production
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Toxicity of acidization fluids used in California oil exploration DCN
SGE01345
Weingartern, M., S. Ge, J.W., Godt, B.A. Bekins, and J.L. Rubinstein. 2015.
High-rate injection 7 is associated with the increase in U.S. mid-continent
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A
C
A
C
A
A
A
A
A
A
B
A
A
A
168
-------
Chapter F—Appendices
Chapter F. APPENDICES
Table F-l. TDD Supporting Memoranda and Other Relevant Documents Available in
FDMS
DCN
SGE01178
SGE01186
SGE01179
SGE01184
SGE01187
SGE01182
SGE01181
SGE00785
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)
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
Summary of Tribal Outreach
Regarding Pretreatment
Standards for Unconventional
Oil and Gas (UOG)
Extraction 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.
Summarizes the data collected as part of the
tribal outreach efforts associated with the rule.
Relevant TDD
Section(s)
D.I, D.4
D.3
B. 3, C.Intro, C.I,
C.2,D. 1,0.2, 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
D.5
169
-------
Chapter F—Appendices
Table F-l. TDD Supporting Memoranda and Other Relevant Documents Available in
FDMS
DCN
SGE01183
SGE01277
SGE01185
SGE01180
SGE01177
Title
Publicly Owned Treatment
Works (POTW)
Memorandum for the
Technical Development
Document (TDD)
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
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 rule analyses.
Summarizes COG extraction wastewater
characteristics and management and disposal
practices used for COG extraction wastewater.
Relevant TDD
Section(s)
D.5
B. Intro
C.3,D.5
B.3.2
N/A
N/A—not applicable
170
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table or
Figure Number
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-l 1
Figure B-12
Figure B-13
Figure B-14
TDD Table/Figure Title
Summary of State Regulations/Guidance
Historical and Projected Crude Oil Production by
Resource Type
Historical and Projected Natural Gas Production by
Resource Type
Major U.S. Shale Plays (Updated April 13, 2015)
Major U.S. Tight Plays (Updated June 6, 2010)
UOG Extraction Wastewater
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
Projections of UOG Well Completions
In a
Supporting
Memo (Y/N)?a
No
No
No
No
No
No (Created by
the EPA)
No
Yes
No
No
No
No
No
Yes
Yes
Source or
Supporting Memo
DCN(s)
SGE00187,
SGE00254,
SGE00545,
SGE00766,
SGE00767,
SGE00982,
SGE00983
SGE01192
SGE01192
SGE01191
SGE00155
—
SGE00593
SGE01179
SGE00604
SGE00275
SGE00625
SGE00625
SGE00275
SGE01179
SGE01179
Supporting Memo Title(s)
—
—
—
—
—
—
Data Compilation Memorandum for the
Technical Development Document (TDD)
—
—
—
—
—
Data Compilation Memorandum for the
Technical Development Document (TDD)
Data Compilation Memorandum for the
Technical Development Document (TDD)
171
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table or
Figure Number
Table B-2
Table B-3
Figure C-l
Figure C-2
Figure C-3
Figure C-4
Figure C-5
Figure C-6
Table C-l
Table C-2
TDD Table/Figure Title
Active Onshore Oil and Gas Drilling Rigs by Well
Trajectory and Product Type (as of October 9, 2015)
UOG Potential by Resource Type as of January 1,
UOG Extraction Wastewater Volumes for Marcellus
Shale Wells in Pennsylvania (2004-2014)
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
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, Common Compounds, and
Common Uses
In a
Supporting
Memo (Y/N)?a
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
Yes
No
Source or
Supporting Memo
DCN(s)
SGE01179
SGE01179
SGE01182
SGE01184
SGE01184
SGE01184
SGE01184
SGE00414
SGE01179
SGE00070,
SGE00721,
SGE00780,
SGE00781,
SGE00966
Supporting Memo Title(s)
Data Compilation Memorandum for the
Technical Development Document (TDD)
Data Compilation Memorandum for the
Technical Development Document (TDD)
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
Data Compilation Memorandum for the
Technical Development Document (TDD)
172
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table or
Figure Number
Table C-3
Table C-4
Table C-5
Table C-6
Table C-7
Table C-8
Table C-9
Table C-10
Table C- 11
Table C-12
TDD Table/Figure Title
Most Frequently Reported Additive Ingredients Used
in Fracturing Fluid in Gas Wells from FracFocus
(2011-2013)
Most Frequently Reported Additive Ingredients Used
in Fracturing Fluid in Oil Wells from FracFocus
(2011-2013)
Median Drilling Wastewater 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
Concentrations of Select Classical and Conventional
Constituents in UOG Drilling Wastewater from
Marcellus Shale Formation Wells
Concentrations of Select Classical and Conventional
Constituents in UOG Produced Water
Concentrations of Bromide and Sulfate in UOG
Drilling Wastewater from Marcellus Shale Formation
Wells
In a
Supporting
Memo (Y/N)?a
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Source or
Supporting Memo
DCN(s)
SGE00721
SGE00721
SGE01182
SGE01181
SGE01184
SGE01184
SGE01184
SGE01181
SGE01184
SGE01181
Supporting Memo Title(s)
Analysis of Pennsylvania Department of
Environmental Protection's (PA DEP) Oil
and Gas Waste Reports
Unconventional Oil and Gas (UOG)
Drilling Wastewater Memorandum
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 Memorandum
Unconventional Oil and Gas (UOG)
Produced Water Volumes and
Characterization Data Compilation
Unconventional Oil and Gas (UOG)
Drilling Wastewater Memorandum
173
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table or
Figure Number
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
Figure D-2
Figure D-3
TDD Table/Figure Title
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
Produced Water
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
UOG Drilling Wastewater Management Methods
Management of UOG Drilling Wastewater Generated
by UOG Wells in Pennsylvania (2008-2014)
In a
Supporting
Memo (Y/N)?a
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No (Created by
the EPA)
No (Created by
the EPA)
Yes
Source or
Supporting Memo
DCN(s)
SGE01184
SGE01181
SGE01184
SGE01181
SGE01184
SGE01181
SGE01184
SGE00769
—
—
SGE01182
Supporting Memo Title(s)
Unconventional Oil and Gas (UOG)
Produced Water Volumes and
Characterization Data Compilation
Unconventional Oil and Gas (UOG)
Drilling Wastewater Memorandum
Unconventional Oil and Gas (UOG)
Produced Water Volumes and
Characterization Data Compilation
Unconventional Oil and Gas (UOG)
Drilling Wastewater Memorandum
Unconventional Oil and Gas (UOG)
Produced Water Volumes and
Characterization Data Compilation
Unconventional Oil and Gas (UOG)
Drilling Wastewater Memorandum
Unconventional Oil and Gas (UOG)
Produced Water Volumes and
Characterization Data Compilation
—
—
Analysis of Pennsylvania Department of
Environmental Protection's (PA DEP) Oil
and Gas Waste Reports
174
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table or
Figure Number
Figure D-4
Figure D-5
Figure D-6
Figure D-7
Figure D-8
Figure D-9
Figure D-10
Figure D-ll
Figure D-12
Figure D-13
TDD Table/Figure Title
Active Disposal Wells and CWT Facilities Identified
in the Appalachian Basin
U.S. Injection for Disposal Volume and UOG
Production over Time
Injection for Disposal Volume and Crude Oil
Production over Time in North Dakota
Injection for Disposal Volume, Cumulative Bakken
Wells Drilled, and Cumulative Disposal Wells Drilled
in North Dakota
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
In a
Supporting
Memo (Y/N)?a
No (Created by
the EPA)
No
No
No
No
Yes
No
Yes
No
Yes
Source or
Supporting Memo
DCN(s)
—
SGE01192;
SGE01128;
SGE01340;
SGE01339
SGE01322
SGE01337;
SGE00182;
SGE01128;
SGE01340
SGE00557;
SGE00182;
SGE01128;
SGE01340
SGE00331
SGE01179
SGE00579
SGE01178
SGE00602
SGE01183
Supporting Memo Title(s)
—
—
Data Compilation Memorandum for the
Technical Development Document (TDD)
Analysis of Centralized Waste Treatment
(CWT) Facilities Accepting UOG
Extraction Wastewater
—
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical
Development Document (TDD)
175
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table or
Figure Number
Figure D-14
Figure D-15
Figure D-16
Figure D-17
Figure D-18
Figure D-19
Figure D-20
Table D-l
Table D-2
Table D-3
Table D-4
Table D-5
Table D-6
TDD Table/Figure Title
McKeesport POTW: Technical Evaluation of
Treatment Processes' Ability to Remove Chlorides
andTDS
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
Distribution of Active Class II Disposal Wells on
Tribal Lands
Reuse/Recycle Practices in 2012 as a Percentage of
Total Produced Water Generated as Reported by
Respondents to 2012 Survey
Reported Reuse/Recycle Criteria
Reported Reuse/Recycle Practices as a Percentage of
Total Fracturing Volume
In a
Supporting
Memo (Y/N)?a
Yes
Yes
Yes
Yes
Yes
No
No
Yes
Yes
Yes
No
Yes
Yes
Source or
Supporting Memo
DCN(s)
SGE01183
SGE01183
SGE01183
SGE01183
SGE01183
SGE00768.A26
SGE00800
SGE01179
SGE01187
SGE01187
SGE00575
SGE01179
SGE01179
Supporting Memo Title(s)
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical
Development Document (TDD)
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical
Development Document (TDD)
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical
Development Document (TDD)
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical
Development Document (TDD)
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical
Development Document (TDD)
—
—
Data Compilation Memorandum for the
Technical Development Document (TDD)
Analysis of Active Underground Injection
for Disposal Wells
Analysis of Active Underground Injection
for Disposal Wells
Data Compilation Memorandum for the
Technical Development Document (TDD)
Data Compilation Memorandum for the
Technical Development Document (TDD)
176
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table or
Figure Number
Table D-7
Table D-8
Table D-9
Table D-10
Table D-ll
Table D-12
Table D-13
Table D-14
Table D-15
Table D-16
Table D-17
Table D-18
TDD Table/Figure Title
Number 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 20
POTWs That Accepted UOG Extraction Wastewater
Directly 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
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
In a
Supporting
Memo (Y/N)?a
Yes
No
No
No
Yes
Yes
No (Created by
the EPA)
No
No
No
No
No
Source or
Supporting Memo
DCN(s)
SGE01178
SGE00167
SGE00600
SGE00603;
SGE01332
SGE01183
SGE01183
—
SGE00748
SGE00745
SGE00745
SGE00525
SGE00525
Supporting Memo Title(s)
Analysis of Centralized Waste Treatment
(CWT) Facilities Accepting UOG
Extraction Wastewater
—
—
—
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical
Development Document (TDD)
Publicly Owned Treatment Works (POTW)
Memorandum for the Technical
Development Document (TDD)
—
—
—
—
177
-------
Chapter F—Appendices
Table F-2. Crosswalk Between TDD and Supporting Memoranda
TDD Table or
Figure Number
Table D-19
Table D-20
Table D-21
Table D-22
Table D-23
Table D-24
Table D-25
Table D-26
Figure F-l
Table F-l
Table F-2
Table F-3
Table F-4
TDD Table/Figure Title
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
Processes
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
PA0027511)
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
TDD Supporting Memoranda and Other Relevant
Documents Available in FDMS
Crosswalk Between TDD and Supporting Memoranda
UOG Resource Potential: Shale as of January 1, 2013
UOG Resource Potential: Tight as of January 1, 2013
In a
Supporting
Memo (Y/N)?a
No
No
No
No
No
No
No
No
No
No (Created by
the EPA)
No (Created by
the EPA)
Yes
Yes
Source or
Supporting Memo
DCN(s)
SGE00751
SGE00525
SGE00616
SGE00616
SGE00602
SGE00554
SGE00612,
SGE00620
SGE00535
SGE00414
—
—
SGE01179
SGE01179
Supporting Memo Title(s)
—
—
—
—
—
—
—
Data Compilation Memorandum for the
Technical Development Document (TDD)
Data Compilation Memorandum for the
Technical Development Document (TDD)
a—Unless otherwise noted, figures and/or tables not included in a supporting memorandum were taken directly from a source without calculation or interpretation.
178
-------
Chapter F—Appendices
Table F-3. UOG Resource Potential: Shale as of January 1, 2013
EIA Region
i iiast
2— Gulf Coast
4 Southwest
5 — Rocky Mountain
EIA Basin
Appalachian
Illinois
Michigan
Black Warrior
TX-LA-MS Salt
Western Gulf
Anadarko
Arkoma
Black Warrior
Fort Worth
Permian
Denver
Greater Green River
Montana Thrust Belt
UOG Formation
Name
Devonian
Marcellus
uuca
New Albany
Antrim
Floyd-Neal/Conasauga
Haynesville-Bossier
Eagle Ford
Pearsall
Tuscaloosa
Woodbine
Cana Woodford
Caney
Fayetteville
Woodford
Chattanooga
Barnett
Wolfcamp
Barnett- Woodford
Avalon/BoneSpring
Niobrara
Hilliard-Baxter-Mancos
All tight oil plays
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
Shale oil
Oil EUR (MMbls
per well)
0.000
0.003
0.002
0.043
0.000
0.000
0.000
0.000
0.191
0.123
0.000
0.112
0.122
0.028
0.036
0.000
0.000
0.000
0.000
0.003
0.085
0.000
0.118
0.012
0.000
0.102
Gas EUR
(Bcfper
well)
0.061
1.581
0.470
0.092
1.188
0.120
1.520
3.588
1.437
0.227
0.676
0.021
0.061
1.590
0.961
0.973
0.899
1.342
0.968
0.296
0.347
1.181
0.367
0.078
0.293
0.068
OilTRR
(MMbls)
0
300
200
700
0
0
0
0
6,400
3,900
0
3,200
600
200
100
0
0
0
0
200
6,100
0
2,900
400
0
600
GasTRR
(Bcf)
23,700
148,700
53,100
1,500
29,100
12,700
4,300
73,300
48,200
7,200
4,900
600
300
11,500
2,700
3,100
20,400
6,300
1,600
17,500
24,900
12,400
9,000
2,700
10,500
400
New Well
Potential
388,500
94,000
112,900
16,300
24,500
105,800
2,800
20,400
33,500
31,700
7,200
28,600
4,900
7,200
2,800
3,200
22,700
4,700
1,700
59,000
71,800
10,500
24,500
34,600
35,800
5,900
179
-------
Chapter F—Appendices
Table F-3. UOG Resource Potential: Shale as of January 1, 2013
EIA Region
6— West Coast
EIA Basin
Powder River
San Juan
Uinta-Piceance
Williston
Columbia
San Joaquin/Los
Angeles
UOG Formation
Name
All tight oil plays
Lewis
Mancos
Gammon
Bakken
Basin Centered
Monterey/Santos
Resource
Type
Shale oil
Shale gas
Shale gas
Shale gas
Shale oil
Shale gas
Shale oil
Oil EUR (MMbls
per well)
0.035
0.000
0.000
0.000
0.147
0.000
0.030
Gas EUR
(Bcfper
well)
0.040
2.200
0.752
0.433
0.078
1.620
0.151
OilTRR
(MMbls)
2,100
0
0
0
22,700
0
600
GasTRR
(Bcf)
2,400
9,800
9,300
3,300
12,100
12,200
3,000
New Well
Potential
60,000
4,500
12,400
7,600
154,800
7,500
19,900
Sources: 179 DCN SGEO1179
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, 2013
EIA Region
1— East
oun t^oast
3 — Midcontinent
EIA Basin
Appalachian
Michigan
TX-LA-MS Salt
Western Gulf
Anadarko
UOG Formation
Name
Clinton-Medina
Tuscarora
Berea Sand
Cotton Valley
Austin Chalk
Buda
Olmos
Vicksburg
Wilcox Lobo
Cleveland
Granite Wash
Red Fork
Resource
Type
Tight gas
Tight gas
Tight gas
Tight gas
Tight oil
Tight oil
Tight gas
Tight gas
Tight gas
Tight gas
Tight gas
Tight gas
Oil EUR (MMbls
per well)
0.002
0.000
0.000
0.008
0.061
0.057
0.009
0.038
0.000
0.038
0.039
0.000
Gas EUR
(Bcf per
well)
0.058
0.724
0.110
1.323
0.116
0.109
1.162
0.980
1.403
0.384
0.579
0.459
OilTRR
(MMbls)
400
0
0
800
5,500
2,000
200
100
0
100
600
0
GasTRR
(Bcf)
12,400
4,400
6,600
139,300
10,400
3,800
25,400
2,600
12,800
1,000
8,800
900
New Well
Potential
213,800
6,100
60,000
105,300
89,700
34,900
21,900
2,700
9,100
2,600
15,200
2,000
180
-------
Chapter F—Appendices
Table F-4. UOG Resource Potential: Tight as of January 1, 2013
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
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 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)
0.695
0.017
0.131
0.002
0.126
0.000
0.534
0.000
0.000
0.000
0.007
0.018
0.022
0.006
0.154
0.000
0.029
0.006
0.053
0.000
0.018
Gas EUR
(Bcfper
well)
0.149
0.209
0.152
0.180
0.014
0.078
0.427
0.258
0.548
0.262
0.792
0.312
1.152
0.312
0.014
0.372
0.568
0.692
0.105
0.154
1.131
OilTRR
(MMbls)
7,000
900
10,600
100
900
0
1,000
0
0
0
100
400
400
200
1,100
0
500
100
100
0
100
GasTRR
(Bcf)
1,500
10,900
12,300
11,500
100
100
800
3,800
6,800
100
12,000
7,100
21,200
9,700
100
11,900
9,800
11,200
200
900
6,400
New Well
Potential
10,100
52,200
80,900
63,900
7,100
1,300
1,900
14,700
12,400
400
15,200
22,800
18,400
31,100
7,100
32,000
17,300
16,200
1,900
5,800
5,700
Sources: 179 DCN SGEO1179
Abbreviations: EUR—estimated ultimate recovery (per well); MMbls—million barrels;
Bcf—billion cubic feet of gas; TRR—technically recoverable resources
181
-------
Chapter F-Appendices
::s::c.cc
1,600.00
1,400.00
1,200.00
1,000.00
s::c.;:c
400.00
200.00
700
Marcellus Shale
zz
77
Bamett Shale
Day 0 Day 1 Day 5 Day 14 Day 90
Source: The EPA generated this figure using data from 44 DCN SGE00414.
Figure F-l. Constituent Concentrations over Time in UOG Produced Water from the
Marcellus and Barnett Shale Formations
182
------- |