United States Office of Water EPA-821-R-15-003

Environmental Protection Washington, DC 20460 March 2015

Agency

Technical Development 

Document for Proposed 

Effluent Limitations 

Guidelines and Standards 

for Oil and Gas Extraction
Technical Development Document for 

Proposed Effluent Limitations Guidelines 

and Standards for Oil and Gas Extraction

EPA-821-R-15-003 

March 2015 

U.S. Environmental Protection Agency 

Office of Water (4303T) 

Washington, DC 20460
Acknowledgements and Disclaimer

iii

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 
Table of Contents

iv

TABLE OF CONTENTS

Page 

CHAPTER A. INTRODUCTION ........................................................................................................ 1

1 Background on Oil and Gas Extraction .............................................................................. 1

2 Existing Discharge Regulations for Oil and Gas Extraction Facility Wastewater ............. 3

2.1 Federal Regulations ................................................................................................ 3

2.2 State Pretreatment Requirements That Apply to UOG Extraction 

Wastewater .............................................................................................................. 9

3 Related Federal Requirements .......................................................................................... 14

CHAPTER B. BACKGROUND ON UNCONVENTIONAL OIL AND GAS EXTRACTION ........................ 15

1 Overview of UOG Resources ........................................................................................... 15

1.1 How UOG Resources Were Formed..................................................................... 18

1.2 Geological Characteristics of UOG Resources ..................................................... 19

2 UOG Well Development Process ..................................................................................... 20

2.1 UOG Well Drilling and Construction ................................................................... 21

2.2 UOG Well Completion ......................................................................................... 24

2.3 Production ............................................................................................................. 29

3 UOG Well Drilling and Completion Activity ................................................................... 30

3.1 Historical and Current UOG Drilling Activity ..................................................... 30

3.2 UOG Resource Potential ....................................................................................... 34

3.3 Current and Projections of Future UOG Well Completions ................................. 35

CHAPTER C. UNCONVENTIONAL OIL AND GAS EXTRACTION WASTEWATER VOLUMES 

AND CHARACTERISTICS ......................................................................................... 37

1 Fracturing Fluid Characteristics ........................................................................................ 39

1.1 Base Fluid Composition ........................................................................................ 39

1.2 Additives ............................................................................................................... 40

1.3 Fracturing Fluids ................................................................................................... 44

2 UOG Extraction Wastewater Volumes ............................................................................. 44

2.1 UOG Extraction Wastewater Volumes by Resource and Well Trajectory ........... 45

2.2 UOG Produced Water Volumes by Formation ..................................................... 50

3 UOG Extraction Wastewater Characterization ................................................................. 55

3.1 Availability of Data for UOG Extraction Wastewater Characterization .............. 55

3.2 UOG Extraction Wastewater Constituent Categories ........................................... 56

3.3 UOG Produced Water Characterization Changes over Time ............................... 75

CHAPTER D. UOG EXTRACTION WASTEWATER MANAGEMENT AND DISPOSAL 

PRACTICES ............................................................................................................. 77
Table of Contents

CONTENTS (Continued)

Page 

v

1 Overview of UOG Extraction Wastewater Management and Disposal Practices ............ 77

2 Injection into Disposal Wells ............................................................................................ 84

2.1 Regulatory Framework for Underground Injection .............................................. 84

2.2 Active Disposal Wells and Volumes .................................................................... 85

2.3 Underground Injection Considerations ................................................................. 86

3 Reuse/Recycle in Fracturing ............................................................................................. 87

3.1 Reuse/Recycle Strategies ...................................................................................... 89

3.2 Reuse/Recycle Drivers .......................................................................................... 92

3.3 Other Considerations for Reuse/Recycle .............................................................. 96

4 Transfer to CWT Facilities ............................................................................................... 98

4.1 Types of CWT Facilities ....................................................................................... 98

4.2 Active CWT Facilities Accepting UOG Extraction Wastewater ........................ 100

5 Discharge to POTWs ...................................................................................................... 102

5.1 POTW Background and Treatment Levels ......................................................... 103

5.2 History of POTW Acceptance of UOG Extraction Wastewater ......................... 106

5.3 How UOG Extraction Wastewater Constituents Interact with POTWs ............. 111

CHAPTER E. REFERENCE FLAGS AND LIST ............................................................................... 146

CHAPTER F. APPENDICES ......................................................................................................... 161

Appendix F.1 Reference Files in FDMS............................................................................... 161

Appendix F.2 UOG Resource Potential by Shale and Tight Formations ............................. 172

Appendix F.3 Constituent Concentrations over Time in UOG Produced Water from 

Marcellus and Barnett Shale Formations .................................................................. 175
List of Tables

vi 

LIST OF TABLES

Page 

Table A-1. Summary of State Regulations ....................................................................................11

Table B-1. Characteristics of Reservoirs Containing UOG and COG Resources .........................20

Table B-2. Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product 

Type (as of November 8, 2013) ...................................................................................33

Table B-3. UOG Potential by Resource Type as of January 1, 2012 ............................................35

Table C-1. Sources for Base Fluid in Hydraulic Fracturing ..........................................................40

Table C-2. Fracturing Fluid Additives, Main Compounds, and Common Uses............................41

Table C-3. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in 

Gas and Oil Wells from FracFocus (2011-2013) .........................................................43

Table C-4. Median Drilling Wastewater Volumes for UOG Horizontal and Vertical Wells 

in Pennsylvania ............................................................................................................47

Table C-5. Drilling Wastewater Volumes Generated per Well by UOG Formation .....................48

Table C-6. UOG Well Flowback Recovery by Resource Type and Well Trajectory ....................49

Table C-7. Long-Term Produced Water Generation Rates by Resource Type and Well 

Trajectory .....................................................................................................................50

Table C-8. Produced Water Volume Generation by UOG Formation ...........................................51

Table C-9. Availability of Data for UOG Extraction Wastewater Characterization .....................55

Table C-10. Concentrations of Select Classical and Conventional Constituents in UOG 

Drilling Wastewater from Marcellus Shale Formation Wells .....................................57

Table C-11. Concentrations of Select Classical and Conventional Constituents in UOG 

Produced Water ............................................................................................................58

Table C-12. Concentrations of Select Anions and Cations Contributing to TDS in UOG 

Drilling Wastewater from Marcellus Shale Formation Wells .....................................63

Table C-13. Concentrations of Select Anions and Cations Contributing to TDS in UOG 

Produced Water ............................................................................................................64

Table C-14. Concentrations of Select Organic Constituents in UOG Drilling Wastewater 

from Marcellus Shale Formation Wells .......................................................................65

Table C-15. Concentrations of Select Organic Constituents in UOG Produced Water .................66

Table C-16. Concentrations of Select Metal Constituents in UOG Drilling Wastewater 

from Marcellus Shale Formation Wells .......................................................................68
List of Tables

LIST OF TABLES (Continued)

Page 

vii

Table C-17. Concentrations of Select Metal Constituents in UOG Produced Water ....................69

Table C-18. Concentrations of Select Radioactive Constituents in UOG Drilling 

Wastewater from Marcellus Shale Formation Wells ...................................................72

Table C-19. Concentrations of Select Radioactive Constituents in UOG Produced Water ..........72

Table C-20. Concentrations of Radioactive Constituents in Rivers, Lakes, Groundwater, 

and Drinking Water Sources Throughout the United States (pCi/L) ...........................73

Table D-1. UOG Produced Water Management Practices ............................................................81

Table D-2. Distribution of Active Class II Disposal Wells Across the United States ...................85

Table D-3. Reuse/Recycle Practices in 2012 as a Percentage of Total Produced Water 

Generated as Reported by Respondents to 2012 Survey .............................................88

Table D-4. Reported Reuse/Recycle Criteria.................................................................................94

Table D-5. Reported Reuse/Recycle Practices as a Percentage of Total Fracturing 

Volume .........................................................................................................................95

Table D-6. Number, by State, of CWT Facilities That Have Accepted or Plan to Accept 

UOG Extraction Wastewater .....................................................................................101

Table D-7. Typical Composition of Untreated Domestic Wastewater ........................................103

Table D-8. Typical Percent Removal Capabilities from POTWs with Secondary 

Treatment ...................................................................................................................105

Table D-9. U.S. POTWs by Treatment Level in 2008 .................................................................105

Table D-10. POTWs That Accepted UOG Extraction Wastewater from Onshore UOG 

Operators ....................................................................................................................108

Table D-11. Percentage of Total POTW Influent Wastewater Composed of UOG 

Extraction Wastewater at POTWs Accepting Wastewater from UOG 

Operators ....................................................................................................................110

Table D-12. Summary of Studies About POTWs Receiving Oil and Gas Extraction 

Wastewater Pollutants ................................................................................................112

Table D-13. Clairton Influent Oil and Gas Extraction Wastewater Characteristics ....................116

Table D-14. Trucked COG Extraction Wastewater Treated at McKeesport POTW from 

November 1 Through 7, 2008 ....................................................................................117

Table D-15. McKeesport POTW Removal Rates Calculated for Local Limits Analysis ...........118
List of Tables

LIST OF TABLES (Continued)

Page 

viii

Table D-16. Constituent Concentrations in UOG Extraction Wastewater Treated at the 

McKeesport POTW Before Mixing with Other Influent Wastewater .......................119

Table D-17. McKeesport POTW Effluent Concentrations With and Without UOG 

Extraction Wastewater ...............................................................................................120

Table D-18. Charleroi POTW Paired Influent/Effluent Data and Calculated Removal 

Rates ...........................................................................................................................122

Table D-19. Franklin Township POTW Effluent Concentrations With and Without 

Industrial Discharges from the Tri-County CWT Facility .........................................125

Table D-20. TDS Concentrations in Baseline and Pilot Study Wastewater Samples at 

Warren POTW ...........................................................................................................128

Table D-21. EPA Region 5 Compliance Inspection Sampling Data ...........................................128

Table D-22. Inhibition Threshold Levels for Various Treatment Processesa ..............................130

Table D-23. Industrial Wastewater Volumes Received by New Castle POTW (2007–

2009) ..........................................................................................................................135

Table D-24. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW 

(NPDES Permit Number PA0027511) ......................................................................136

Table D-25. Concentrations of DBPs in Effluent Discharges at One POTW Not 

Accepting Oil and Gas Wastewater and at Two POTWs Accepting Oil and 

Gas Wastewater (μg/L) ..............................................................................................142

Table E-1. Source List .................................................................................................................146

Table F-1. TDD Supporting Memoranda and Other Relevant Documents Available in 

FDMS .........................................................................................................................161

Table F-2. Crosswalk Between TDD and Supporting Memoranda .............................................163

Table F-3. UOG Resource Potential: Shale as of January 1, 2012 ..............................................172

Table F-4. UOG Resource Potential: Tight as of January 1, 2012 ..............................................173
List of Figures

ix

LIST OF FIGURES

Page 

Figure A-1. UOG Extraction Wastewater ........................................................................................2

Figure B-1. Historical and Projected Oil Production by Resource Type .......................................16

Figure B-2. Historical and Projected Natural Gas Production by Resource Type .........................17

Figure B-3. Major U.S. Shale Plays (Updated May 9, 2011) ........................................................17

Figure B-4. Major U.S. Tight Plays (Updated June 6, 2010) ........................................................18

Figure B-5. Geology of Formations Containing Various Hydrocarbons .......................................19

Figure B-6. Horizontal (A), Vertical (B), and Directional (C) Drilling Schematic .......................22

Figure B-7. Length of Time to Drill a Well in Various UOG Formations as Reported for 

the First Quarter of 2012 through the Third Quarter of 2013 ......................................24

Figure B-8. Hydraulic Fracturing Schematic .................................................................................26

Figure B-9. Freshwater Impoundment ...........................................................................................27

Figure B-10. Vertical Gas and Water Separator ............................................................................28

Figure B-11. Fracturing Tanks .......................................................................................................29

Figure B-12. Produced Water Storage Tanks ................................................................................30

Figure B-13. Number of Active U.S. Onshore Rigs by Trajectory and Product Type over 

Time .............................................................................................................................31

Figure B-14. Projections of UOG Well Completions ....................................................................36

Figure C-1. UOG Extraction Wastewater Volumes for Marcellus Shale Wells in 

Pennsylvania (2004–2013)...........................................................................................46

Figure C-2. Ranges of Typical Produced Water Generation Rates over Time After 

Fracturing .....................................................................................................................47

Figure C-3. Anions and Cations Contributing to TDS Concentrations in Shale and Tight 

Oil and Gas Formations ...............................................................................................61

Figure C-4. Chloride, Sodium, and Calcium Concentrations in Flowback and Long-Term 

Produced Water (LTPW) from Shale and Tight Oil and Gas Formations ...................62

Figure C-5. Barium Concentrations in UOG Produced Water from Shale and Tight Oil 

and Gas Formations .....................................................................................................71

Figure C-6. Constituent Concentrations over Time in UOG Produced Water from the 

Marcellus and Barnett Shale Formations .....................................................................76

Figure D-1. UOG Produced Water Management Methods ...........................................................78
List of Figures

LIST OF FIGURES (Continued)

Page 

x 

Figure D-2. UOG Drilling Wastewater Management Methods .....................................................78

Figure D-3. Management of UOG Drilling Wastewater Generated by UOG Wells in 

Pennsylvania (2008–2013)...........................................................................................82

Figure D-4. Active Disposal Wells and CWT Facilities Identified in the Appalachian 

Basin ............................................................................................................................83

Figure D-5. Flow Diagram of On-the-Fly UOG Produced Water Treatment for 

Reuse/Recycle ..............................................................................................................91

Figure D-6. Hypothetical UOG Produced Water Generation and Base Fracturing Fluid 

Demand over Time ......................................................................................................96

Figure D-7. UOG Extraction Wastewater Management Practices Used in the Marcellus 

Shale (Top: Southwestern Region; Bottom: Northeastern Region) .............................97

Figure D-8. Number of Known Active CWT Facilities over Time in the Marcellus and 

Utica Shale Formations ..............................................................................................102

Figure D-9. Typical Process Flow Diagram at a POTW .............................................................104

Figure D-10. Clairton POTW: Technical Evaluation of Treatment Processes’ Ability to 

Remove Chlorides and TDS ......................................................................................115

Figure D-11. McKeesport POTW: Technical Evaluation of Treatment Processes’ Ability 

to Remove Chlorides and TDS ..................................................................................117

Figure D-12. Ridgway POTW: Annual Average Daily Effluent Concentrations and 

POTW Flows .............................................................................................................121

Figure D-13. Johnstown POTW: Annual Average Daily Effluent Concentrations and 

POTW Flows .............................................................................................................132

Figure D-14. California POTW: Annual Average Daily Effluent Concentrations and 

POTW Flows .............................................................................................................133

Figure D-15. Charleroi POTW: Annual Average Daily Effluent Concentrations and 

POTW Flows .............................................................................................................134

Figure D-16. Barium Sulfate Scaling in Haynesville Shale Pipe ................................................139

Figure D-17. THM Speciation in a Water Treatment Plant (1999–2013) ...................................144

Figure F-1. Constituent Concentrations over Time in UOG Produced Water from the 

Marcellus and Barnett Shale Formations ...................................................................175
Abbreviations

xi

ABBREVIATIONS

AO Administrative Order

API American Petroleum Institute

Bcf billion cubic feet 

BDL below method detection limit

BOD5 biochemical oxygen demand

BPD barrels per day

BPT best practicable control technology currently available

CaCO3 calcium carbonate

CBM coalbed methane

Ci curie

CIU categorical industrial user

COD chemical oxygen demand

COG conventional oil and gas 

CWA Clean Water Act

CWT centralized waste treatment

DBP disinfection byproduct 

DMR discharge monitoring report

DOE Department of Energy

EIA Energy Information Administration

ELGs Effluent Limitations Guidelines and Standards 

EPA U.S. Environmental Protection Agency 

EUR estimated ultimate recovery

gpd gallons per day 

IU industrial user 

LTPW long-term produced water 

MG million gallons

MGD million gallons per day

mg/L milligrams per liter 

MI DEQ Michigan Department of Environmental Quality 

NORM naturally occurring radioactive material

OH DNR Ohio Department of Natural Resources 

ORD Office of Research and Development

PA DEP Pennsylvania Department of Environmental Protection 

pCi picocurie 

PESA Petroleum Equipment Suppliers Association 

POTW publicly owned treatment works 

SIU significant industrial user

SRB sulfate-reducing bacteria

TDD technical development document 

TDS total dissolved solids 

TENORM technologically-enhanced naturally occurring radioactive material

THM trihalomethane

TOC total organic carbon 

TRR technically recoverable resource
Abbreviations

ABBREVIATIONS (Continued)

xii

UIC underground injection control 

UOG unconventional oil and gas 

USGS U.S. Geological Survey 

UV ultraviolet

WV DEP West Virginia Department of Environmental Protection
Glossary

xiii

GLOSSARY1

Base fluid The primary component of fracturing fluid to which proppant 

(sand) and chemicals are added. Base fluids are typically waterbased; however there are cases of non-aqueous fracturing fluids 

(e.g., compressed nitrogen, propane, carbon dioxide). Water-based 

fluid can consist of only fresh water or a mixture of fresh water, 

brackish water and/or reused/recycled wastewater.

Biochemical oxygen 

demand (BOD5) 

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 I-1578-78, and an AOAC 

method. 

Centralized waste 

treatment (CWT) facility

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.

Chemical oxygen demand 

(COD)

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 I-3560-85, and an AOAC 

method.

Class II UIC disposal well 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. 

Class II UIC enhanced 

recovery well

A well that injects brine, water, steam, polymers, or carbon 

dioxide into oil-bearing formations to recover residual oil and—in 

some limited applications—natural gas. This is also known as 

secondary or tertiary recovery.

Conventional oil and gas 

(COG) resources

Crude oil and natural gas that is produced by a well drilled into a 

geologic formation in which the reservoir and fluid characteristics 

permit the oil and natural gas to readily flow to the wellbore 

Drill cuttings The particles generated by drilling into subsurface geologic 

formations and carried out from the wellbore with the drilling 

fluid. 

Drilling fluid The circulating fluid (e.g., mud) used in the rotary drilling of 

wells to clean and condition the hole and to counterbalance 

formation pressure. 

Drilling wastewater The liquid waste stream separated from recovered drilling fluid 

(e.g., mud) and drill cuttings. 

 

1 The definitions of terms in the Glossary are only meant to apply to the terms as used throughout the Technical 

Development Document for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

(TDD) and the TDD supporting documentation. 
Glossary

GLOSSARY (Continued)

xiv

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, varying amounts of 

formation water). See long-term produced water. 

Formation water Water that occurs naturally within the pores of rock.

Hydraulic fracturing 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. 

Hydraulic fracturing fluid The fluid, consisting of a base fluid and chemical additives, used 

to fracture rock in the hydraulic fracturing process. Hydraulic 

fracturing fluids are used to initiate and/or expand fractures, as 

well as to transport proppant into fractures. See base fluid. 

Long-term produced 

water (LTPW)

The produced water generated during the production phase of the 

well after the initial flowback process (includes increasing 

amounts of formation water). 

Naturally occurring 

radioactive material 

(NORM)

Material that contains radionuclides at concentrations found in 

nature. 

See also technologically-enhanced radioactive material 

(TENORM)

Non-TDS removal 

technologies

Technologies that remove non-dissolved constituents from 

wastewater.

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, and blowdown 

of the water phase from the produced water treating system.

Produced water (brine) 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. 

Proppant 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.

Publicly owned treatment 

works (POTW) 

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. 

Source water 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.
Glossary

GLOSSARY (Continued)

xv 

TDS removal technologies Technologies capable of removing dissolved constituents (e.g., 

sodium, chloride, calcium) in addition to the constituents removed 

by non-TDS removal technologies. 

Technologically-enhanced 

naturally occurring 

radioactive material 

(TENORM)

Naturally occurring radionuclides that human activity has 

concentrated or exposed to the environment. 

Total dissolved solids 

(TDS)

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 I1750-85. 

Total organic carbon 

(TOC)

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.

Total suspended solids 

(TSS)

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 I3765-85.

Unconventional oil and 

gas (UOG) 

Crude oil and natural gas produced by a well drilled into a low 

porosity, low permeability formation (including, but not limited 

to, shale gas, shale oil, tight gas, tight oil). For the purpose of the 

proposed rule, the definition of UOG does not include CBM.

UOG extraction 

wastewater

Wastewater sources associated with production, field exploration, 

drilling, well completion, or well treatment for unconventional oil 

and gas extraction (e.g., drilling muds, drill cuttings, produced 

sand, produced water). 
Chapter A—Introduction

1 

Chapter A. INTRODUCTION

1 BACKGROUND ON OIL AND GAS EXTRACTION

Recent advances in well development that combine hydraulic fracturing and horizontal 

drilling have dramatically improved the technical and economic feasibility of oil and gas 

extraction from unconventional resources. As a result, in 2012, United States (U.S.) crude oil and 

natural gas production reached their highest levels in more than 15 and 30 years, respectively. 

The U.S. Department of Energy (DOE) reports these increases to be a direct result of advances in 

hydraulic fracturing and horizontal drilling. Further, the DOE projects that natural gas production 

in the U.S. will increase by 56 percent by 2040, compared to 2012 production levels. Similarly, 

the DOE projects that by 2019, crude oil production in the U.S. will increase by 48 percent 

compared to 2012 production levels (31 DCN SGE00989). 

This technical development document (TDD) provides background information and data 

considered in the development of revised effluent limitations guidelines and standards (ELGs) 

proposed for the Oil and Gas Extraction point source category to address discharges from 

unconventional oil and gas (UOG) extraction facilities to municipal wastewater treatment plants. 

UOG consists of crude oil and natural gas2 produced by wells drilled into a low porosity, low

permeability formation. UOG resources include shale oil and gas, resources that were formed, 

and remain, in low-permeability shale. UOG resources also include tight oil and gas, resources 

that were formed in a source rock and migrated into a reservoir rock such as sandstone, 

siltstones, or carbonates. As explained in the preamble to the proposed rule, although coalbed 

methane (CBM) would fit the definition of UOG in the proposed rule, the proposed rule would 

not apply to pollutant discharges to POTWs associated with CBM extraction.3 The remainder of 

the information presented in this document is specific to the UOG resources subject to the 

proposed rule and therefore excludes CBM unless explicitly indicated otherwise.

Development of UOG resources typically requires hydraulic fracturing of the reservoir 

rock by injecting fracturing fluid at high pressures to create a network of fissures in the rock 

formations, giving the oil and/or natural gas a pathway to travel to the well for extraction. 

Pressure within the low-permeability formations forces a portion of these fracturing fluids back 

to the surface. The fluid that returns is typically referred to as “flowback.” Produced water 

consists of flowback that flows from the well initially and the long-term produced water that 

flows from the well during oil and gas production. Produced water also includes any chemicals 

that are added downhole or added to fracturing or drilling fluids that are then injected downhole, 

as well as chemicals that are added during the process of separating the oil and/or gas from the 

wastewater.

 

2 Natural gas can include “natural gas liquids,” components that are liquid at ambient temperature and pressure.

3 EPA notes that the requirements in the existing effluent guidelines for direct dischargers also do not apply to 

coalbed methane extraction, as this industry did not exist at the time that the effluent guidelines were developed and 

was not considered by the Agency in establishing the effluent guidelines (160 DCN SGE00761). To reflect the fact 

that neither the proposed pretreatment standards nor the existing effluent guideline requirements apply to coalbed 

methane extraction, EPA is expressly reserving a separate unregulated subcategory for coalbed methane in the 

proposed rule. For information on coalbed methane, see 

http://water.epa.gov/scitech/wastetech/guide/oilandgas/cbm.cfm.
Chapter A—Introduction

2 

As depicted in Figure A-1, produced water, drilling wastewater, and produced sand are 

collectively referred to as 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 (e.g., drilling muds, drill cuttings, produced sand, 

produced water)

Drilling Wastewater: the liquid waste 

stream separated from recovered drilling 

fluid (e.g., mud) and drill cuttings during 

the drilling processa

Produced Sand: the slurried particles 

used in hydraulic fracturing, the 

accumulated formation sands and scales 

particles generated during production 

(40 CFR 435.11(aa))

Produced Water: the water (brine) 

brought up from the hydrocarbonbearing 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 (40 CFR 435.11(bb))

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)

Long-term Produced Water: produced 

water generated during the production 

phase of the well after the initial 

flowback process (includes increasing 

amounts of formation water)

Chemicals added during the oil/water 

separation process (40 CFR 435.11(bb))

a – Drilling fluid (mud) is the circulating fluid used in the rotary drilling of wells to clean and condition the hole and to counterbalance formation 

pressure. Drill cuttings means the particles generated by drilling into subsurface geologic formations and carried out from the wellbore with the 

drilling fluid. 

Figure A-1. UOG Extraction Wastewater 

This document supports the EPA’s development of pretreatment standards for UOG 

extraction wastewater. The remainder of this chapter describes existing discharge regulations for 

UOG extraction wastewater. Subsequent chapters provide additional detail on UOG resources, 

extraction processes, and wastewater generation. They describe the quantity and quality of 

wastewater generated and the practices industry uses to manage and/or dispose of UOG 

extraction wastewater. 

The pretreatment standards for UOG extraction wastewater are based on data generated 

or obtained in accordance with EPA’s Quality Policy and Information Quality Guidelines. EPA’s 

quality assurance (QA) and quality control (QC) activities for this rulemaking include the 

development, approval, and implementation of Quality Assurance Project Plans for the use of 
Chapter A—Introduction

3 

environmental data generated or collected from sampling and analyses, existing databases, and 

literature searches. 

References cited in this document are listed in Chapter E and are identified in the body of 

the document by reference ID numbers (e.g., 149) and DCN (e.g., DCN SGE00586). Information 

presented in this document was taken from existing data sources, including state and federal 

agency databases, journal articles and technical papers, technical references, vendor websites, 

and industry/vendor telephone calls, meetings, and site visits. The EPA classified the quality of 

the data sources with a “data source quality flag”, assigning ratings from “A” for peer-reviewed 

journal articles and documents prepared by or for a government agency to “D” for documents 

prepared by a source that could not be verified and that do not include citation information, such 

as some newspaper articles and conference presentations. For each source cited in this document, 

the reference list in Chapter E includes the reference ID number, document control number 

(DCN), source citation, and data source quality flag. 

Appendix F.1 includes two tables with more information about where to find more data 

about certain topics, tables, and/or figures contained in the TDD. Table F-1 lists supporting 

memoranda along with their associated DCNs and a brief description of the type of information 

covered in the memoranda. Each supporting memorandum includes a section about QC activities 

related to the data and/or analyses discussed in the given memoranda. Table F-1 also lists the 

relevant TDD sections associated with each memorandum. Table F-2 contains additional 

information about each table and figure in the TDD, including the original source(s) of 

information for the data presented in the table or figure and the relevant memorandum and 

attachments, where relevant. 

2 EXISTING DISCHARGE REGULATIONS FOR OIL AND GAS EXTRACTION FACILITY 

WASTEWATER

Wastewater discharges from oil and gas extraction facilities are subject to federal, state, 

and local regulations. Section A.2.1 describes federal regulations affecting the discharge of oil 

and gas extraction wastewater directly into waters of the United States and indirectly to

municipal wastewater treatment plants (known as publicly owned treatment works, or POTWs), 

including ELGs for the Oil and Gas Extraction point source category (40 C.F.R. part 435) as well 

as the national pretreatment program (40 C.F.R. part 403). In addition to applicable federal 

requirements, some states specifically regulate the management, storage, and disposal of UOG 

extraction wastewater. Section A.2.2 discusses state-specific requirements that the EPA has 

identified that relate to UOG extraction wastewater pollutant discharges to POTWs. 

2.1 Federal Regulations

The national clean water industrial regulatory program is authorized under Sections 301, 

304, 306, and 307 of the Clean Water Act (CWA). These sections direct the EPA to promulgate 

categorical regulations through six levels of control: 

• Best practicable control technology currently available (BPT)

• Best available technology economically achievable (BAT)

• Best conventional pollutant control technology (BCT) 
Chapter A—Introduction

4 

• New source performance standards (NSPS) 

• Pretreatment standards for existing sources (PSES)

• Pretreatment standards for new sources (PSNS)

For point sources that discharge pollutants directly into the waters of the United States 

(direct dischargers), the national-level ELGs promulgated by the EPA (i.e., BPT, BAT, BCT, and 

NSPS) are implemented through National Pollutant Discharge Elimination System (NPDES) 

permits4 as authorized by CWA Sections 301(a), 301(b), and 402. For sources that discharge to 

POTWs, the EPA promulgates national categorical pretreatment standards (i.e., PSES and PSNS) 

that apply to discharges to POTWs and are enforced by local, state, and federal authorities. See 

CWA Sections 307(b) and (c) for the EPA’s authority to develop pretreatment standards. 

The EPA issues ELGs for categories of dischargers—groups with common 

characteristics, such as a manufacturing process or commercial activity (e.g., battery 

manufacturing, airport deicing). The EPA may divide a point source category into groupings 

called “subcategories” to provide a method for addressing variations among products, processes, 

and other factors, which result in distinctly different effluent characteristics that affect the 

determination of the technology basis for categorical regulations. ELGs are national in scope and 

apply to all facilities within a category or subcategory5 that discharge wastewater. In establishing 

these controls, the EPA assesses, among other things: 

• The performance and availability 

of the best pollution control 

technologies or pollution 

prevention practices for the 

category or subcategory as a 

whole. 

• The economic achievability of 

those technologies, which can 

include consideration of the 

affordability of achieving 

reductions in pollutant 

discharges. 

40 C.F.R. part 403.5(b) notes eight categories of 

pollutant discharge prohibitions: 

1. Pollutants that create a fire or explosion hazard in 

the POTW

2. Pollutants that will cause corrosive structural 

damage to the POTW

3. Solid or viscous pollutants in amounts that will 

obstruct the flow in the POTW, resulting in 

interference

4. Any pollutant, including oxygen-demanding 

pollutants (e.g., BOD), released in a discharge at a 

flow rate and/or pollutant concentration that will 

interfere with the POTW

5. Heat in amounts that will inhibit biological activity 

in the POTW resulting in interference

6. Petroleum oil, nonbiodegradable cutting oil, or 

products of mineral oil origin in amounts that will 

cause interference or pass through

7. Pollutants that result in the presence of toxic gases, 

vapors, or fumes within the POTW in a quantity that 

may cause acute worker health and safety problems

8. Any trucked or hauled pollutants, except at discharge 

points designated by the POTW

2.1.1 The National Pretreatment Program 

(40 C.F.R. Part 403) 

The 1972 CWA established the 

National Pretreatment Program to address 

wastewater discharged from industries to 

POTWs. POTWs collect wastewater from 

 

4 Facilities that do not discharge or propose not to discharge (zero dischargers) may apply for permit coverage for 

upset or bypass defense to cover discharges resulting from unforeseen incidents that otherwise would cause a 

violation of CWA Section 301 (i.e., discharge without a permit) (82 DCN SGE00531). 5 The EPA may subcategorize a category based on appropriate factors, including facility size. See CWA Section 

304(b)(2)(b)a. These factors may affect the availability and affordability of pollution control technologies.
Chapter A—Introduction

5 

homes, commercial buildings, and industrial facilities via a series of pipes, known as a collection 

system, to a treatment plant. In some cases, dischargers may haul wastewater to the treatment 

plant by tanker truck. Industrial wastewater, commingled with domestic wastewater, is treated by 

the POTW and discharged to a receiving water body. Under the CWA, in order to discharge 

wastewater, the POTW must have a NPDES permit that may limit the type and quantity of 

pollutants that it may discharge. 

To implement the National Pretreatment Program, the EPA developed the General 

Pretreatment Regulations to protect POTW operations. As described in Chapter 2 of the EPA’s 

introduction to the program (171 DCN SGE00249), these regulations apply to all non-domestic 

sources that introduce pollutants into a POTW. Non-domestic sources are referred to as industrial 

users (IUs). To distinguish small, simple IUs (e.g., coin-operated laundries, commercial car 

washes) from larger, more complex IUs (e.g., oil refineries, steel mills), the EPA has established 

a category called significant IUs (SIUs). The General Pretreatment Regulations apply to all 

nondomestic sources that introduce pollutants into a POTW and are intended to protect POTW 

operations from “pass through” and “interference.” See the textbox for a list of prohibited 

pollutant discharges, as defined by 40 C.F.R. part 403. 

Pretreatment Program Implementation 

Most of the responsibility for implementing the National Pretreatment Program rests on 

local municipalities. For example, 40 C.F.R. part 403.8(a) requires that POTWs designed to treat 

more than 5 million gallons per day (MGD) of wastewater and receiving pollutants from IUs that 

pass through or interfere with the POTW’s operation must establish a local pretreatment 

program.6 The POTW’s NPDES permit will include requirements for developing a local 

pretreatment program that will control the wastewater discharged to the POTW by IUs. 

The National Pretreatment Program regulations identify specific requirements that apply

to IUs, 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 IUs—

regardless of whether they are subject to any other national, state, or local pretreatment 

requirements—are subject to the general and specific prohibitions identified in 40 C.F.R. parts 

403.5(a) and (b), respectively. 

 

6 POTWs designed to treat less than 5 MGD may be required by their Approval Authority to develop a local 

pretreatment program if the nature or volume of the industrial influent, treatment process upsets, violations of 

POTW effluent limitations, contamination of municipal sludge, or other circumstances warrant in order to prevent 

interference with the POTW or pass through.
Chapter A—Introduction

6 

• General prohibitions prohibit the discharge of substances that pass through the POTW 

or interfere with its operation. Note that under the definition of “pass through,” only 

pollutants that are limited in the POTW’s NPDES permit are prohibited from pass

through by the general prohibitions. 

• Specific prohibitions in 40 C.F.R. part 403.5(b) prohibit eight categories of pollutant 

discharges that will harm POTW workers or the POTW, including the collection 

system. Pollutant discharges outside these defined categories are not specifically 

prohibited. 

Categorical pretreatment standards. 

As discussed in Section A.2.1, the CWA authorizes the EPA to promulgate national 

categorical pretreatment standards for industrial sources that discharge to POTWs. Developed by 

the EPA on an industry-specific basis, categorical pretreatment standards are based on the best 

available technology that is economically achievable for that industry on a national level, and set 

regulatory requirements based on the performance of that technology. These requirements limit 

discharges of toxic and nonconventional pollutants that could cause pass through or cause 

interference.

7 Categorical pretreatment standards represent a baseline level of control that all IUs 

in the category must meet, without regard to the POTW they discharge to. IUs 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 IUs 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 (IUs and residential 

sources), and implement a system to control industrial discharges. Additional information can be 

found in the EPA’s 2004 Local Limits Development Guidance (165 DCN SGE00602). 

Responsibilities of POTWs and IUs

The POTW controls the discharges from the IU through an individual control 

mechanism, often called an IU permit. The POTW may also issue general permits under certain 

conditions if it has adequate legal authority and approval. POTWs with approved local 

pretreatment programs must have procedures for: 

• Identifying all possible IUs, and the character and volume of pollutants from IUs 

introduced to the POTW

 

7 In determining whether a pollutant would pass through POTWs for categorical pretreatment standards, EPA 

generally compares the percentage of a pollutant removed by well-operated POTWs performing secondary treatment 

to the percentage removed by a candidate technology basis. A pollutant is determined to pass through POTWs when 

the median percentage removed nationwide by well-operated POTWs is less than the median percentage removed by 

the candidate technology basis.
Chapter A—Introduction

7 

• Communicating applicable standards and requirements to IUs

• Receiving and analyzing reports

• Inspecting IUs, including annual inspections of SIUs

• Sampling in certain cases

• Investigating noncompliance with pretreatment standards and requirements 

• Reporting to the Approval Authority (i.e., state or regional pretreatment program)

Each IU of a POTW is responsible for compliance with applicable federal, state, and 

local pretreatment standards and requirements. 

Approval Authority 

POTWs establish local pretreatment programs to control discharges from non-domestic 

sources. These programs must be approved by the Approval Authority, which is also responsible 

for overseeing implementation and enforcement of the programs (171 DCN SGE00249). The 

Approval Authority is the director in a NPDES authorized state with an approved state 

pretreatment program, or the appropriate EPA regional administrator in a non-NPDES authorized 

state or NPDES state without an approved state pretreatment program. A state may have an 

NPDES permit program but lack a state pretreatment program. One example is Pennsylvania, 

which the EPA has authorized for the NPDES program but not for the pretreatment program. 

EPA Region 3 is the Approval Authority for POTW pretreatment programs in Pennsylvania.

Hauled Wastewater 

As discussed in the EPA’s Introduction to the National Pretreatment Program (171 DCN 

SGE00249), in addition to receiving wastewater through the collection system, many POTWs 

accept trucked wastewater. IUs may truck their wastewater to the POTW when the facility is 

outside the POTW’s service area (e.g., located in a rural area) and is not connected to the 

collection system. Just like wastewater received through the collection system, trucked 

wastewater is subject to the General Pretreatment Regulations and may also be subject to 

categorical pretreatment standards. Therefore, the POTW must regulate hauled wastewater from 

CIUs or hauled wastewater that otherwise qualifies the discharger as an IU in accordance with 

the requirements of the General Pretreatment Regulations and any applicable categorical 

pretreatment standards, including any applicable requirements for permitting and inspecting the 

facility that generates the wastewater. 

Section 403.5(b)(8) of the General Pretreatment Regulations specifically prohibits the 

introduction of any trucked or hauled pollutants to the POTW, except at discharge points 

designated by the POTW. As explained in Introduction to the National Pretreatment Program

(171 DCN SGE00249), Section 403.5(b)(8) of the General Pretreatment Regulations is the only 

pretreatment requirement specifically addressing hauled wastewater. POTWs are not required to 

have waste hauler control programs. However, POTWs that accept any hazardous waste by 

truck, rail, or dedicated piping at the POTW facility are considered treatment, storage, and 

disposal facilities (TSDFs) subject to management requirements under the Resource 

Conservation and Recovery Act (RCRA). Consequently, a POTW should not accept hauled 

waste without consideration of the implications of its acceptance (see 40 C.F.R. part 260). 
Chapter A—Introduction

8 

2.1.2 ELGs for the Oil and Gas Extraction Point Source Category (40 C.F.R. Part 435) 

The EPA promulgated the Oil and Gas Extraction ELGs (40 C.F.R. part 435) in 1979, 

and amended the regulation in 1993, 1996, and 2001. The Oil and Gas Extraction industrial 

category is subcategorized8

 as follows: 

• Subpart A: Offshore 

• Subpart C: Onshore 

• Subpart D: Coastal 

• Subpart E: Agricultural and Wildlife Water Use

• Subpart F: Stripper Wells

The existing subpart C and subpart E regulations cover wastewater discharges from field 

exploration, drilling, production, well treatment, and well completion activities in the onshore oil 

and gas industry. Although oil and gas resources occur in unconventional formations in offshore 

and coastal regions, recent development of UOG resources in the United States has occurred 

primarily onshore in regions to which the regulations in subpart C (onshore) and subpart E 

(agricultural and wildlife water use) apply and thus, only the regulations that apply to onshore oil 

and gas extraction are described in more detail here. 

Note that the scope of the existing Oil and Gas Extraction ELG does not similarly apply 

to privately owned wastewater treatment facilities that accept oil and gas extraction wastewater

from offsite that are also not engaged in production, field exploration, drilling, well completion, 

or well treatment. Discharges from such facilities are not subject to 40 C.F.R. part 435, but rather 

are subject to requirements in 40 C.F.R. part 437, the Centralized Waste Treatment category (see 

Section D.4 for more information). 

Direct Discharge Requirements for Onshore Oil and Gas Extraction Facilities

Subpart C: Onshore Subcategory 

Applicability. As set forth in 40 C.F.R. part 435.30, subpart C applies to facilities 

engaged in production, field exploration, drilling, well completion, and well treatment in the oil 

and gas extraction industry, located landward of the inner boundary of the territorial seas—and 

not included in the definition of other subparts, including subpart D (Coastal) at 40 C.F.R. part 

435.40. 

Direct discharge requirements. The regulations at 40 C.F.R. part 435.32 specify the 

following for BPT: 

...there shall be no discharge of waste water pollutants into navigable waters from any 

source associated with production, field exploration, drilling, well completion, or well 

treatment (i.e., produced water, drilling muds, drill cuttings, and produced sand). 

The existing regulations do not include national categorical pretreatment standards for 

discharges to POTWs.

 

8 Subpart B is reserved. 
Chapter A—Introduction

9 

Subpart E: Agricultural and Wildlife Use Subcategory9 

Subpart E applies to onshore facilities located in the continental United States and west of 

the 98th meridian for which the produced water has a use in agriculture or wildlife propagation 

when discharged into waters of the United States. 

Applicability. As set forth in 40 C.F.R. part 435.50, subpart E applies to onshore facilities 

located in the continental United States and west of the 98th meridian for which the produced 

water has a use in agriculture or wildlife propagation when discharged into navigable waters. 

Definitions in 40 C.F.R. part 435.51(c) explain that the term “use in agricultural or wildlife 

propagation” means: 

• The produced water is of good enough quality to be used for wildlife or livestock 

watering or other agricultural uses; and 

• The produced water is actually put to such use during periods of discharge. 

Direct discharge requirements. Subpart E prohibits the discharge of waste pollutants into 

navigable waters from any source (other than produced water) associated with production, field 

exploration, drilling, well completion, or well treatment (i.e., drilling muds, drill cuttings, 

produced sands). Therefore, the only allowable discharge under this subpart is produced water10

that meets the “good enough quality” and actual use requirements described above, with an oil 

and grease concentration not exceeding 35 mg/L. 

2.2 State Pretreatment Requirements That Apply to UOG Extraction Wastewater

In addition to applicable federal requirements, some states regulate the management, 

storage, and disposal of UOG extraction wastewater, including regulations concerning pollutant 

discharges to POTWs from oil and gas extraction facilities. In addition to pretreatment 

requirements, some states have indirectly addressed the issue of pollutant discharges to POTWs 

by limiting the management and disposal options available to operators. Table A-1, beginning on 

the next page, summarizes how Pennsylvania, Ohio, West Virginia, and Michigan responded to 

UOG extraction wastewater discharges into their POTWs.

The Groundwater Protection Council’s (GWPC) 2014 report Regulations Designed to 

Protect State Oil and Gas Water Resources describes that, as part of their study, GWPC 

“surveyed the study states11 regarding the use of POTWs for discharging production fluids 

including flowback water. Of the states responding, three indicated this practice was banned by 

 

9 While pollutant discharges from onshore oil and gas extraction produced water are allowed under subpart E in 

certain geographic locations for use in agriculture or wildlife propagation, EPA has not found that these types of 

permits are typically written for unconventional oil and gas extraction wastewater (as defined for the proposed rule).

10 Produced water is not defined in subpart C (onshore) or subpart E (agricultural and wildlife use). For subparts A 

(offshore) and D (coastal), produced water is defined as “the water (brine) brought up from the hydrocarbon-bearing 

strata during the extraction of oil and gas, and can include formation water, injection water, and any chemicals 

added downhole or during the oil/water separation process.”

11 GWPC reviewed data for the following 27 oil and gas producing states: Alabama, Alaska, Arkansas, California, 

Colorado, Florida, Illinois, Indiana, Kansas, Kentucky, Louisiana, Michigan, Mississippi, Montana, Nebraska, New 

Mexico, New York, North Dakota, Ohio, Oklahoma, Pennsylvania, South Dakota, Texas, Utah, Virginia, West 

Virginia, and Wyoming. 
Chapter A—Introduction

10 

regulation, five states did not have a regulation covering this disposal method but would not 

allow it as a matter of policy, and nine indicated it was either regulated by another state agency 

or would otherwise be allowed under certain circumstances.... [A]s of 2013, six state oil and gas 

agencies had permitting requirements for POTWs accepting this waste” (77 DCN SGE01077). 
Chapter A—Introduction

11 

Table A-1. Summary of State Regulations 

State

Relevant 

State 

Authority

(s)

State Authority 

Website(s) Description of State’s Relevant Requirements

Pennsylvania

EPA 

Region 3, 

PA DEP

PA DEP: 

http://www.depwe

b.state.pa.us/ 

PA Code, Chapter 

95: 

http://www.pacode

.com/secure/data/0

25/chapter95/chap

95toc.html 

Pennsylvania amended 25 Pennsylvania Code Ch. 95.10 on August 21, 2010. According to PA Bulletin, Doc.

No. 10-1572 (130 DCN SGE00187) (available at http://www.pabulletin.com/secure/data/vol40/40-

34/1572.html) 

This final form rulemaking ensures the continued protection of this Commonwealth's water resources from 

new and expanded sources of TDS. Most importantly, the final-form rulemaking guarantees that waters of 

this Commonwealth will not exceed a threshold of 500 mg/L. 

In addition, the bulletin specifies

A higher standard of 500 mg/L is being applied specifically to the natural gas sector, based on several 

factors.

The bulletin also explains the following, regarding existing authorized discharges, addressed in Section 

95.10(a)(1)

This section makes it clear that discharge loads of TDS authorized by the Department, under NPDES 

permits or other authority that were issued or reissued prior to the effective date of this final-form 

rulemaking, are exempt from the regulation until the net load is to be increased. It is important to note that 

only an increase in net TDS load is considered to be a new or expanding discharge loading. 

The bulletin also explains the pretreatment requirements described in Section 95.10(b)(3)(ii), including 

the final rule establishes 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.

On April 19, 2011, PA DEP requested that

Marcellus Shale natural gas drillers voluntarily cease delivering their wastewater to 15 wastewater 

treatment plants which currently accept it and have “grandfathered” status with respect to PA DEP’s Total 

Dissolved Solids regulations (170 DCN SGE00982).

On April 20, 2011, the Marcellus Shale Coalition wrote a response to PA DEP that stated

I write to you today to express our commitment to meet the call of the Department of Environmental 

Protection (DEP) to halt the delivery of flowback and produced water from shale gas extraction to the 

facilities that currently accept it under special provisions of last year’s Total Dissolved Solids (TDS) 

regulations. Our members are carefully reviewing their operations and support achieving this milestone by 

May 19, 2011 (111 DCN SGE00545).
Chapter A—Introduction

12 

Table A-1. Summary of State Regulations

State

Relevant 

State 

Authority

(s)

State Authority 

Website(s) Description of State’s Relevant Requirements

Ohio OH EPA, 

OH DNR

OH EPA:

http://www.epa.stat

e.oh.us/

OH DNR: 

http://ohiodnr.gov/ 

Ohio R.C. 15, 

Chapter 1509: 

http://codes.ohio.go

v/orc/1509

Ohio R.C. Title 15, Chapter 1509, part 22(C)(1) (128 DCN SGE00983), includes the provision that

brine12 from any well except an exempt Mississippian well13 shall be disposed of only as follows: by 

injection into an underground formation, including annular disposal if approved by rule of the chief, which 

injection shall be subject to division (D) of this section; by surface application in accordance with section 

1509.226 of the Revised Code; in association with a method of enhanced recovery as provided in section 

1509.21 of the Revised Code; [or] in any other manner not specified in divisions (C)(1)(a) to (c) of this 

section that is approved by a permit or order issued by the chief.

West 

Virginia WVDEP

WVDEP: 

http://www.dep.wv

.gov/Pages/default.

aspx 

A WVDEP guidance document about POTWs accepting oil and gas wastewater (218 DCN SGE00767) notes 

that

The USEPA and WVDEP discourage POTWs from accepting wastewater from oil and gas operations such 

as coal bed methane and Marcellus Shale wastewaters because these wastewaters essentially pass through 

sewage treatment plants and can cause inhibition and interference with treatment plant operations.

 

12 The Ohio EPA defines brine as “all saline geological formation water resulting from, obtained from, or produced in connection with the exploration, drilling, 

or production of oil or gas, including saline water resulting from, obtained from, or produced in connection with well stimulation or plugging of a well.”

13 OH R.C. Section 1509.01 defines an “exempt Mississippian well” as a well that (1) was drilled and completed before January 1, 1980; (2) is in an unglaciated 

part of the state; (3) was completed in a reservoir no deeper than the Mississippian Big Injun sandstone in areas underlain by Pennsylvanian or Permian 

stratigraphy, or the Mississippian Berea sandstone in areas directly overlain by Permian stratigraphy; and (4) is used primarily to provide oil or gas for domestic 

use.
Chapter A—Introduction

13 

Table A-1. Summary of State Regulations

State

Relevant 

State 

Authority

(s)

State Authority 

Website(s) Description of State’s Relevant Requirements

Michigan MI DEQ

MI DEQ: 

http://www.michig

an.gov/deq 

Michigan Oil and 

Gas Regulations:

http://www.michig

an.gov/documents/

deq/ogs-oilandgasregs_263032_7.pdf

Michigan’s Oil and Gas Regulations, part 324.703 (120 DCN SGE00254), state that

A permittee of a well shall inject oil or gas field fluid wastes, or both, into an approved underground 

formation in a manner that prevents waste. The disposal formation shall be isolated from fresh water strata 

by an impervious confining formation.

Sources: 130 DCN SGE00187; 120 DCN SGE00254; 104 DCN SGE00545; 198 DCN SGE00766; 218 DCN SGE00767; 170 DCN SGE00982; 128 DCN 

SGE00983 

Abbreviations: PA DEP—Pennsylvania Department of Environmental Protect; OH EPA—Ohio Environmental Protection Agency; OH DNR—Ohio 

Department of Natural Resources; R.C.—Revised Code; WVDEP—West Virginia Department of Environmental Protection; MI DEQ—Michigan Department 

of Environmental Quality
Chapter A—Introduction

14 

3 RELATED FEDERAL REQUIREMENTS

As required by the Safe Drinking Water Act Section 1421, the EPA has promulgated 

regulations to protect underground sources of drinking water through underground injection 

control (UIC) programs that regulate the injection of fluids underground. These regulations are 

found at 40 C.F.R. parts 144 through 148, and specifically prohibit any underground injection 

not authorized by UIC permit (40 C.F.R. part 144.11). They classify underground injection into 

six classes; wells that inject fluids brought to the surface in connection with oil and gas 

production are classified as Class II UIC wells (see Section D.2 for more information). Thus, an 

onshore oil and gas extraction facility that seeks to meet zero discharge requirements through 

underground injection of wastewater must dispose of the wastewater in a well with a Class II 

UIC disposal well permit.
Chapter B—Background on Unconventional Oil and Gas Extraction

15 

Chapter B. BACKGROUND ON UNCONVENTIONAL OIL AND GAS EXTRACTION

To provide context for discussions of UOG extraction wastewater volumes and 

characteristics (Chapter C) and management and disposal practices (Chapter D), this chapter

describes the following: 

• What UOG resources are in context of the proposed rule, differences between 

unconventional and conventional resources, differences between types of UOG 

resources, and where UOG resources are located

• How UOG wells are developed and the development processes that generate 

wastewater

• Historical, current, and projected future UOG well drilling activity

Relevant national economic information about the UOG industry is included in a separate 

memorandum to the record, titled Profile of the Oil and Gas Extraction (OGE) Sector, with 

Focus on Unconventional Oil and Gas (UOG) Extraction (2 DCN SGE00932). 

Oil and gas resources are defined as the total in-place hydrocarbon contained in porous 

rock formations. There are several ways to classify oil and gas resources. Throughout this TDD, 

the EPA typically classifies resources into conventional and unconventional resources. For 

purposes of the proposed rule, the EPA is proposing to define “unconventional oil and gas”

(UOG) as “crude oil and natural gas14 produced by a well drilled into a low porosity, low

permeability formation (including, but not limited to, shale gas, shale oil, tight gas, tight oil).” As 

explained in the preamble to the proposed rule and in Section A.1, although CBM would fit the 

definition of UOG in the proposed rule, the proposed rule would not apply to pollutant 

discharges to POTWs associated with CBM extraction.

The different types of unconventional resources (shale, tight) and how they differ from 

conventional resources are discussed in more detail in Section B.2.1. UOG and conventional oil 

and gas (COG) resources can be further classified by the type of hydrocarbon: oil, natural gas, 

and natural gas condensates. Literature often refers to formations that co-produce natural gas 

condensates15 along with oil and/or natural gas as liquid rich formations. Formations that 

primarily produce oil also co-produce natural gas known as “associated gas” (206 DCN 

SGE00623). Formations that only produce dry natural gas are known as non-associated gas 

resources. 

1 OVERVIEW OF UOG RESOURCES

The Energy Information Administration (EIA) publishes historical and projected future 

oil and gas production by resource type in its Annual Energy Outlooks (AEOs). Beginning 

around 2000, advances in technologies such as horizontal drilling and advances in hydraulic 

fracturing made it possible to economically produce oil and natural gas from tight and shale 

 

14 Natural gas can include “natural gas liquids,” components that are liquid at ambient temperature and pressure. 

15 Natural gas condensates include light hydrocarbons such as ethanes, propanes, and butanes. When gas 

condensates are depressurized at the wellhead, they condense into a liquid phase. When processed at the refinery, 

the finished byproducts of natural gas condensates are referred to as natural gas liquids and have high market value. 
Chapter B—Background on Unconventional Oil and Gas Extraction

16 

resources (209 DCN SGE01095). The EIA’s 2014 AEO projects that, in the next 30 years, the 

majority of the country’s natural gas will come from unconventional resources and that 

unconventional oil production will continue to increase substantially (31 DCN SGE00989). 

Figure B-1 and Figure B-2 show the historical and future profiles of COG and UOG production 

in the United States by resource type according to the EIA.16 CBM and COG are included in 

some of the figures in this chapter, but are identified separately within each figure. Section B.3

summarizes historical and current trends in UOG drilling in more detail on a well basis.

Figure B-3 and Figure B-4 show the major shale and tight UOG resources, respectively, 

in the lower 48 states. Appendix F (Table F-3 and Table F-4) provides an updated and more 

thorough list of UOG formations by basin as the EIA maps shown below only show major UOG 

formations as of May 2011. Geological characteristics of UOG resources shown in Figure B-3

and Figure B-4 are described in detail in Section B.1.2.

17 

Source: 158 DCN SGE00487

Figure B-1. Historical and Projected Oil Production by Resource Type

 

16 In Figure B-1, the EIA refers to all types of unconventional oil including shale as “tight oil.” As explained in 

Section B.1, EPA differentiates between shale and tight oil for the purpose of this TDD.

17 The EIA uses the term “play” to describe subsets of UOG resources in Figure B-3 and Figure B-4, which are

similar to the term “formation” as used in this TDD.
Chapter B—Background on Unconventional Oil and Gas Extraction

17 

Source: 31 DCN SGE00989

Figure B-2. Historical and Projected Natural Gas Production by Resource Type

Source: 157 DCN SGE00153

Figure B-3. Major U.S. Shale Plays (Updated May 9, 2011) 
Chapter B—Background on Unconventional Oil and Gas Extraction

18 

Source: 156 DCN SGE00155

Figure B-4. Major U.S. Tight Plays (Updated June 6, 2010) 

The key differences between UOG and COG resources are the geological characteristics 

of the formations that contain the resources. UOG resources include shale oil and gas resources 

that were formed, and remain, in low-permeability shale. UOG resources also include tight oil 

and gas resources that were formed in a source rock and migrated into a reservoir rock such as 

sandstone, siltstones, or carbonates. The permeability and porosity of tight oil and gas reservoirs 

are lower than that of COG reservoirs, but generally higher than that of shale oil and gas 

reservoirs (100 DCN SGE00527). As mentioned above, while CBM is sometimes referred to as 

an unconventional resource, the proposed rule does not apply to CBM, and therefore the scope of 

this document does not include CBM. 

1.1 How UOG Resources Were Formed

Differences in how conventional and unconventional resources were formed can be 

explained in terms of the source and resource rock.18 The following explains these differences, 

which are also illustrated in Figure B-5 (100 DCN SGE00527; 113 DCN SGE00547; 211 DCN 

SGE00114). 

• Oil and gas in conventional resources were formed in a source rock, migrated 

through the surrounding permeable rock, and eventually became trapped by a 

confining rock layer forming non-continuous accumulations. The final reservoir rock 

has high permeability and porosity. 

 

18 The source rock is the type of rock in which the oil and/or gas formed. The reservoir rock is the type of rock in 

which the oil and/or gas is contained at the time of production. 
Chapter B—Background on Unconventional Oil and Gas Extraction

19 

• Oil and gas in tight resources, similar to conventional resources, were formed in a 

source rock and migrated until they reached a confining layer of rock. Tight resources 

occur in a mixture of continuous and non-continuous accumulations. They differ from 

conventional resources in that the oil and gas accumulated in a reservoir rock with 

relatively low permeability and porosity.19

• Oil and gas in shale resources were formed in and remained in the source rock, 

making it also the reservoir rock. Consequently, shale reservoirs occur in continuous 

accumulations over large geographic areas. Shale reservoirs have the lowest 

permeability and porosity out of all resource types (see Section B.2.2 for more 

information about hydraulic fracturing). 

Source: 155 DCN SGE00594

Figure B-5. Geology of Formations Containing Various Hydrocarbons20

1.2 Geological Characteristics of UOG Resources

UOG resources are typically developed using advanced completion and well drilling 

techniques because they have unique geologic characteristics that differ from conventional 

resources. These are summarized in Table B-1. COG reservoirs have relatively high porosities 

and permeabilities, so economical oil and gas production typically relies on natural pressure 

 

19 Because tight oil and gas exists in multiple types of reservoir rocks, EPA refers to it generally as “tight” oil and 

gas in this report as opposed to “tight sands” because that reference is not all inclusive of the different types of tight 

formations. 

20 “Associated” gas accumulates with oil in a formation. “Non-associated” gas accumulates separately from oil in a 

formation (206 DCN SGE00623).
Chapter B—Background on Unconventional Oil and Gas Extraction

20 

gradients with open-hole completion techniques (see Section B.2.2 for more information about 

well completion). UOG reservoirs have extremely low porosity and permeability, typically 

requiring rigorous stimulation (e.g., hydraulic fracturing) during well completion to produce oil 

and gas economically (113 DCN SGE00547; 100 DCN SGE00527; 211 DCN SGE00114). 

Although it is not necessary to create fractures to obtain oil and gas from conventional reservoirs, 

hydraulic fracturing can still be used to increase production from COG wells (100 DCN 

SGE00527; 146 DCN SGE00291)

21. UOG formations are also more likely to occur in 

continuous accumulations, as explained in Section B.1.1. As a result, UOG wells are more likely 

to be drilled horizontally. 

Table B-1. Characteristics of Reservoirs Containing UOG and COG Resources

Reservoir 

Characteristic COG Resources

UOG Resources

Tight Shale

Reservoir rock type Sandstones, siltstones, or 

carbonates

Sandstones, siltstones, or 

carbonates Shales

Source rock No No Yes

Accumulation type Non-continuous Continuous or non-continuous Continuous

Porosity High (>10%) Low (<10%) Low (<10%)

Permeability High (>100 mD)

a Low (<0.1 mD)a Low (<0.001 mD)a

Well trajectoryb Mostly vertical Mixture of vertical and 

horizontal Mostly horizontal

Completion method Open hole completions and 

natural reservoir pressurec

Hydraulic fracturing and/or 

acidizationd Hydraulic fracturing

Sources: 211 DCN SGE00114; 86 DCN SGE00533; 100 DCN SGE00527; 109 DCN SGE00345

a—The millidarcy (mD) is a measurement of permeability (i.e., ability for fluid flow within a rock). Higher 

permeability means fluids flow more readily.

b—Well trajectories are described in more detail in Section B.2.1. 

c—As COG wells age, operators may also use enhanced recovery techniques such as water or steam injection to 

enhance production. COG wells may also be hydraulically fractured. 

d—Acidization is the process of dissolving undesired rocks from the wellbore using acidic fluids in order to 

improve fluid flow from the reservoir (18 DCN SGE00966).

2 UOG WELL DEVELOPMENT PROCESS

UOG well development includes the following processes: well pad construction, well 

drilling and construction, well completion, and production. UOG well completion includes well 

stimulation such as hydraulic fracturing, acidization, or a combination of hydraulic fracturing 

and acidization. The return of injected fluids to the surface, commonly referred to as the 

“flowback process,” is also part of the UOG well completion process. Before UOG well 

development, operators conduct exploration and obtain surface use agreements, mineral leases, 

and permits. These steps can take a few months to several years to complete. When they are 

 

21 A survey conducted by American Petroleum Institute (API) and the American Natural Gas Alliance (ANGA), 

included well completion information for 5,307 well completions in 2010, consisting of a mixture of conventional 

and unconventional wells. The survey also showed that 69 percent of conventional wells were hydraulically 

fractured.
Chapter B—Background on Unconventional Oil and Gas Extraction

21 

completed, operators begin the well development process, as described in the following 

subsections. 

The largest UOG extraction wastewater volumes generated during the UOG well 

development process are flowback and long-term produced water (see Section C.2 for 

characteristics of each). UOG well drilling also generates drilling wastewater. Throughout the 

well development process, many materials are transported to the well pad. These materials 

include well casing and tubing, fuel (e.g., diesel or liquefied natural gas), and base fluid, sand, 

and chemicals for hydraulic fracturing. Operators must also transport UOG extraction 

wastewater from the well to the ultimate wastewater management or disposal location—e.g., a 

centralized waste treatment (CWT) facility, an underground injection well for disposal, another 

well for reuse. Sand, chemicals, and construction materials are typically transported to the well 

pad by truck, but fracturing base fluid (e.g., fresh water, recycled UOG produced water) and 

UOG extraction wastewater may be transported via truck or temporary piping (191 DCN 

SGE00625; 178 DCN SGE00635; 179 DCN SGE00275).

2.1 UOG Well Drilling and Construction

Drilling occurs in two phases: exploration and development. Exploration involves the 

drilling of wells to locate hydrocarbon-bearing formations and to determine the size and 

production potential of hydrocarbon reserves. Development involves drilling production wells 

once a hydrocarbon reserve has been discovered and delineated. The following discussion will 

focus on the drilling of production wells.

After the well pad is constructed, operators drill and construct the well. Operators use one 

of the three drilling trajectories below to drill for UOG (see Figure B-6). See Table B-3 for a 

breakdown of active UOG wells as of 2011 by drilling trajectory. 

• Vertical drilling is the drilling of a wellbore straight down into the ground. In UOG 

well drilling, vertical well drilling is more commonly used for tight wells than shale 

wells (100 DCN SGE00527). For shale, vertical drilling is used by operators during 

the exploration phase of field development (178 DCN SGE00635), in shallow 

formations (e.g., Antrim shale), or by small entity operators who may be unable to 

make large investments in horizontal wells (39 DCN SGE00283). Vertical drilling 

has historically been used for COG wells. 

• Directional drilling is the drilling of a wellbore at an angle off the vertical to reach 

an end location not directly below the well pad. Directional drilling is used where a 

well pad cannot be constructed directly above the resource (e.g., in rough terrain). 

Directional drilling is common in conventional and unconventional tight formations 

that occur as accumulations as illustrated in Section B.1. 

• Horizontal drilling, the most advanced drilling technique, allows operators to drill 

vertically down to a desired depth, about 500 feet above the target formation (called 

the “kickoff point”), and then gradually turn the drill 90 degrees to continue drilling 

laterally. Horizontal drilling exposes the producing formation via a long horizontal 

lateral, which can vary in length between 1,000 and 5,000 feet (154 DCN SGE00593; 

206 DCN SGE00623). Horizontal drilling is the most commonly used method in 

continuous shale and tight formations (24 DCN SGE00354; 78 DCN SGE00010). 
Chapter B—Background on Unconventional Oil and Gas Extraction

22 

Source: 154 DCN SGE00593 (edited by the EPA) 

Figure B-6. Horizontal (A), Vertical (B), and Directional (C) Drilling Schematic 

Because shale reservoirs occur in continuous accumulations over large geographic areas, 

operators drilling in these resources typically drill multiple horizontal wells on each well pad

(191 DCN SGE00625; 178 DCN SGE00635; 179 DCN SGE00275). However, tight reservoirs 

occur in both continuous and non-continuous accumulations; therefore, operators may drill 

multiple horizontal wells or a single directional or vertical well on a well pad, depending on the 

location and accumulation type of the tight reservoir. Directional and horizontal well 

configurations give operators access to more of the producing formation and therefore reduce

surface disturbance (24 DCN SGE00354; 212 DCN SGE00011). Operators may drill one or two 

horizontal wells on a well pad initially and move on to the next pad. When this happens, the 

operator typically comes back to drill out the remaining wells on the pad after the initial wells 

show economical production and favorable conditions.22 

Drilling for oil and gas is generally performed by rotary drilling methods, which involve

the use of a rotating drill bit that grinds through the earth’s crust as it descends. Well drilling is 

an iterative process that includes several sequences of drilling, installing casing, and cementing 

of succeeding sections of the well (178 DCN SGE00635). During drilling, operators inject 

drilling fluids down the wellbore to cool the drill bit, to circulate fragments of rock (i.e., drill 

cuttings) back to the surface so they do not clog the wellbore, and to control downhole pressure. 

Operators use one of the following types of drilling fluids depending on which portion of the 

well they are drilling (55 DCN SGE00740): 

• Compressed gases: During the beginning phase of drilling an UOG well (i.e., the 

initial drilling close to the surface), compressed gases may be used to minimize costs. 

Dry air, nitrogen gas, mist, foam, and aerated fluids are included in this category. 

 

22 Favorable conditions include sufficient oil and/or gas prices, available drilling rigs, available fracturing crews, and 

permits. 
Chapter B—Background on Unconventional Oil and Gas Extraction

23 

• Water-based: At several thousand feet deep, operators typically use water-based 

drilling fluids (i.e., drilling mud), which provide more robust fluid properties at these 

depths than compressed gases. Water-based drilling fluids may contain salts,

23 barite, 

polymers, lime, and gels as additives. 

• Oil-based: For drilling at deep depths and/or the horizontal laterals of wells, 

operators may use oil-based mud to maintain more consistent fluid properties at the 

higher temperatures and pressures that are associated with deeper depths. Oil-based 

drilling fluids may use diesel oil and/or mineral oils and contain emulsifiers, barite, 

and gels as additives. 

• Synthetic-oil-based: For drilling at deep depths and/or the horizontal laterals of 

wells, operators may also use synthetic-oil-based fluids which are similar to oil-based 

fluids. However, instead of using diesel oil and/or mineral oils, synthetic oil-based 

fluids use organic fluids (e.g., esters, polyeolefins, acetal, ether, and linear alkyl 

benzenes) that exhibit similar fluid properties as diesel and mineral oils. Syntheticoil-based fluids have been referred as more environmentally friendly24 than oil-based 

fluids but are also more expensive (162 DCN SGE01006; 17 DCN SGE01009). 

When returned to the surface, drill cuttings (solids) are removed from the drilling fluids 

using shakers, desilters, and centrifuges. This results in drill cuttings and a wastewater stream,

referred to as drilling wastewater. Drilling wastewater is either reused/recycled in a closed loop 

process or otherwise managed (e.g., transferred to a CWT facility) (124 DCN SGE00090; 178

DCN SGE00635). 

Well drilling and construction typically lasts between five days and two months, 

depending on well depth and how familiar operators are with the specific formation. Figure B-7

shows that drilling time generally decreases as UOG operators become more familiar and 

efficient at drilling in a UOG formation (9 DCN SGE00503; 178 DCN SGE00635; 26 DCN 

SGE00516). Figure B-7 also compares drilling phase durations among UOG formations (e.g., 

Granite Wash requires 40 to 50 days for drilling while Barnett requires 10 or fewer days).

 

23 The UOG industry may refer to water-based drilling fluids that contain salts as “salt mud.”

24 Using synthetic-oil-based drilling fluids results in a lower volume of wastewater that must be disposed of. They 

also have lower toxicities, lower concentrations of certain priority pollutants, lower bioaccumulation potential, and 

faster biodegradation rates than oil-based drilling fluid.
Chapter B—Background on Unconventional Oil and Gas Extraction

24 

Source: 48 DCN SGE00693

Figure B-7. Length of Time to Drill a Well in Various UOG Formations as Reported for the 

First Quarter of 2012 through the Third Quarter of 2013 

2.2 UOG Well Completion 

After the well is drilled and constructed, the well completion process begins. “Well 

completion” is a general term used to describe the process of bringing a wellbore into production 

once drilling and well construction are completed (33 DCN SGE00984). The UOG well 

completion process involves many steps, including cleaning the well to remove drilling fluids 

and debris, perforating the casing that lines the producing formation,

25 inserting production 

tubing to transport the hydrocarbon fluids to the surface, installing the surface wellhead, 

stimulating the well (e.g., hydraulic fracturing), setting plugs in each stage, and eventually 

drilling the plugs out of the well. It also includes the flowback process, in which fluids injected 

during well stimulation return to the surface. The following two subsections describe the well 

stimulation and flowback processes that are common for UOG well completion. 

 

25 In some instances, open-hole completions may be used, where the well is drilled into the top of the target 

formation and casing is set from the top of the formation to the surface. Open-hole well completions leave the 

bottom of the wellbore uncased.
Chapter B—Background on Unconventional Oil and Gas Extraction

25 

2.2.1 UOG Well Completion: Well Stimulation

Because UOG resources are extracted from formations with low porosity and 

permeability, UOG wells are typically developed using more advanced stimulation technologies 

than traditionally used on COG wells to create higher permeability in the reservoir that allows 

operators to produce oil and gas economically. UOG well stimulation techniques include but are 

not limited to hydraulic fracturing, acidization, or a combination of fracturing and acidization (18

DCN SGE00966). The most common technique for UOG wells is hydraulic fracturing, discussed 

in the rest of this subsection (see Section B.3.3) (78 DCN SGE00010). Hydraulic fracturing of 

COG wells is becoming more common, but traditionally COG wells have been completed with 

open-hole techniques allowing the oil and/or gas resources to flow naturally (109 DCN 

SGE00345; 86 DCN SGE00533).

Operators typically fracture UOG wells in multiple stages to maintain the high pressures 

necessary to fracture the reservoir rock. Stages are fractured starting with the stage at the end of 

the wellbore and working back toward the wellhead. The number of stages depends on lateral

length. Because horizontal laterals are 1,000 to 5,000 feet long, operators may use between eight 

and 23 stages for horizontal wells (177 DCN SGE00276). Vertical wells are typically only 

fractured with one stage (78 DCN SGE00010). A fracturing crew can typically fracture two to 

three stages per day when operating 12 hours per day or four to five stages per day when 

operating 24 hours per day.26 Consequently, a typical well may take two to seven days to 

complete (87 DCN SGE00239; 124 DCN SGE00090). The following processes are performed

for each stage: 

• Perforation—Operators lower a perforation gun into the stage using a line wire. The 

perforation gun releases an explosive charge to create holes that penetrate 

approximately 1 foot into the formation rock in a radial fashion. These perforations 

create a starting point for the hydraulic fractures.

• Hydraulic fracturing—Operators inject fracturing fluids (e.g., water, sand, and other 

additives) down the wellbore to highly pressurize the formation to the point where 

small fractures are created in the rock (see Figure B-8).27 See Section C.1 for 

information about fracturing fluid volumes and characteristics. 

• Stage plugging—Once the stage is hydraulically fractured, a stage plug is inserted 

down the wellbore, separating it from additional stages until all stages are completed. 

 

26 The hours per day depends on the operator, local ordinances, and weather. 

27 The first stage is fractured with what is known as the pad fracture. The pad is the injection of high-pressure water 

and chemical additives without proppant (i.e., solid material designed to keep fractures open to allow gas to flow 

from the producing formation) to create the initial fractures into the formation. After the pad is pumped downhole, 

proppant is introduced to the fracturing fluid for the additional stages.
Chapter B—Background on Unconventional Oil and Gas Extraction

26 

Source: 168 DCN SGE00604

Figure B-8. Hydraulic Fracturing Schematic

The components of fracturing fluid (i.e., base fluid, sand, chemical additives) are 

typically stored on the well pad before hydraulic fracturing begins. (See Section C.1 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-11) (190 DCN SGE00280; 179 DCN 

SGE00275; 177 DCN SGE00276). Operators that reuse/recycle UOG produced water in 

subsequent fracturing jobs typically store the reused/recycled wastewater in fracturing tanks 

and/or pits (190 DCN SGE00280). Operators typically have sand trucks and pump trucks onsite 

during the hydraulic fracturing process. The sand trucks contain the sand prior to mixing in the 

fracturing fluid and the pump trucks pump the fracturing fluid down the wellbore during each 

stage of fracturing.
Chapter B—Background on Unconventional Oil and Gas Extraction

27 

Source: 179 DCN SGE00275

Figure B-9. Freshwater Impoundment

2.2.2 UOG Well Completion: Flowback Process

After all of the stages of a well have been hydraulically fractured, the stage plugs are 

drilled out of the wellbore and the pressure at the wellhead is released. Releasing the pressure 

allows a portion of produced water to return to the wellhead; this waste stream is often referred 

to as “flowback.” Industry commonly refers to this as the flowback process (178 DCN 

SGE00635). The flowback consists of a portion of the fluid injected into the wellbore combined 

with formation water. At the wellhead, a combination of flowback water, sand, oil, and/or gas is

routed through phase separators, which separate products from wastes. Industry uses different 

types of separators depending on a number of factors (e.g., formation, resource type). Figure 

B-10 shows an example of a separator used for dry gas production (i.e., only requires gas and 

water separation because there is no oil production). 

Higher volumes of flowback water are generated in the beginning of the flowback 

process; flowback rates decrease as the well goes into the production phase. Operators typically 

store flowback in fracturing tanks onsite before treatment or transport offsite.28 In addition to 

flowback, small quantities of oil and/or gas may be produced during the initial flowback process. 

The small quantities of produced gas may be flared; if the operator is using “green completions,” 

 

28 Fracturing tanks cannot be transported from one site to another when they contain wastewater. Wastewater is 

typically transported via trucks with capacities of about 4,200 to 5,000 gallons (100 to 120 barrel) or via pipe (178

DCN SGE00635). 
Chapter B—Background on Unconventional Oil and Gas Extraction

28 

the gas may instead be captured.

29 If oil is produced, oil/water separators may be used30 or the oil 

may be recovered from the flowback water after it is transported offsite. 

Source: 191 DCN SGE00625 

Figure B-10. Vertical Gas and Water Separator 

Flowback typically lasts from a few days to a few weeks (78 DCN SGE00010; 212 DCN 

SGE00011; 204 DCN SGE00622; 153 DCN SGE00592; 80 DCN SGE00286). At some wells, 

the majority of fracturing fluid may be recovered within a few hours (78 DCN SGE00010; 212

DCN SGE00011; 204 DCN SGE00622; 153 DCN SGE00592; 80 DCN SGE00286). A 2009 

report published by the Ground Water Protection Council and ALL Consulting stated that

operators recover between 10 and 70 percent of the fracturing fluid that they inject down the 

wellbore (78 DCN SGE00010; 153 DCN SGE00592; 80 DCN SGE00286). Section C.3.1

provides more details on flowback generation rates over time and fracturing fluid recovery 

percentages for specific UOG formations. 

 

29 On April 17, 2012, the U.S. EPA issued regulations, required by the Clean Air Act, requiring the natural gas 

industry to reduce air pollution by using green completions, or reduced emission completions. EPA has identified a 

transition period until January 1, 2015, to allow operators to locate and install green completion equipment (40 

C.F.R. part 60 and 63).

30 Operators sometimes use chemicals during the oil/water phase separation process.
Chapter B—Background on Unconventional Oil and Gas Extraction

29 

Source: 191 DCN SGE00625

Figure B-11. Fracturing Tanks 

2.3 Production

After the flowback process, the well begins producing oil and/or gas. During this

production phase, UOG wells produce oil and/or gas and water. This water, called “long-term

produced water” in this report, consists primarily of formation water and continues to be 

produced throughout the lifetime of the well, though typically at much lower rates than flowback 

(153 DCN SGE00592). Long-term produced water rates range from less than a barrel up to 4,200 

gallons (100 barrels) per day (see Chapter C) and gradually decrease over the life of the well.31

The rates vary with each well because they are dependent on formation characteristics and the 

completion success of the given well (see Chapter C for information about flowback and longterm produced water volumes and characteristics). 

When the well enters the production phase, operators typically remove the fracturing

tanks that were used during flowback and store long-term produced water in permanent aboveground storage tanks referred to as produced water tanks with capacities that range from 4,200 to 

33,600 gallons (100 to 800 barrels) (see Figure B-12) (190 DCN SGE00280; 179 DCN 

SGE00275; 183 DCN SGE00636). The number of produced water tanks depends on the number 

of wells that are producing on the well pad and the volume of water produced by each well. Most 

operators configure water piping on the well pad so that each well has a designated produced 

water tank (178 DCN SGE00635; 177 DCN SGE00276). 

 

31 The life of an UOG well varies significantly by well. Some wells are expected to produce up to 40 years without 

further stimulation, while others may only produce economically for 10 years (80 DCN SGE00286). 
Chapter B—Background on Unconventional Oil and Gas Extraction

30 

Source: 179 DCN SGE00275

Figure B-12. Produced Water Storage Tanks

3 UOG WELL DRILLING AND COMPLETION ACTIVITY

The following subsections describe historical, current, and projections of future UOG 

drilling activity, including: 

• Historical and current UOG well drilling activity 

• Total estimated UOG resource potential

• Current and projections of future UOG well completions 

3.1 Historical and Current UOG Drilling Activity 

Since 2000, hydraulic fracturing coupled with drilling directional and horizontal 

wellbores in unconventional formations has increased (209 DCN SGE01095). More recently, 

drilling has also increased in liquid-rich formations.32 Baker Hughes, one of the world’s largest 

oilfield services companies, periodically publishes location and other data for active U.S. rigs.33

Figure B-13 shows Baker Hughes’ estimates of total number of active drilling rigs in the United 

 

32 Liquid-rich formations are those that either primarily produce oil or primarily co-produce natural gas with gas 

condensates (i.e., hydrocarbons such as ethanes, propanes, and butanes). When gas condensates are depressurized at 

the wellhead, they condense into a liquid phase.

33 Baker Hughes obtains data in part from RigData, a company that sells rig and well data. Rig data Baker Hughes 

publishes are reported in major newspapers and journals (e.g., Oil and Gas Journal) and are used by the industry as 

an indicator for demand of oil and gas equipment.
Chapter B—Background on Unconventional Oil and Gas Extraction

31 

States between January 2000 and November 2013 and shows drilling trajectory (i.e., directional, 

horizontal, vertical) and product type (i.e., oil, gas). These counts include rigs that are drilling for 

CBM and COG. Both horizontal drilling and oil well drilling have increased since 2000. (As of 

November 15, 2013, 63 percent of rigs were drilling horizontal wells compared to 6 percent in 

January 2000.34) In 2009, horizontal well drilling surpassed vertical well drilling for the first

time in the United States. Shortly after, in 2011, oil well drilling surpassed gas for the first time 

since 1993 (7 DCN SGE00504). 

Source: 48 DCN SGE00693

Figure B-13. Number of Active U.S. Onshore Rigs by Trajectory and Product Type over 

Time35

Table B-2 shows the active drilling rigs in the United States by formation or basin, 

broken down by well trajectory and resource type, as of November 2013. Based on data reported 

by Baker Hughes and rig counts reported in other literature, the majority of rigs were drilling 

 

34 Another 13 percent of wells were being drilled directionally in the United States as of November 8, 2013.

35 The sharp decrease in active drilling rigs observed in 2009 is likely attributed to the sudden drop in natural gas 

and crude oil prices also experienced in 2009 (31 DCN SGE00989).
Chapter B—Background on Unconventional Oil and Gas Extraction

32 

into unconventional formations at this time (8 DCN SGE00502; 159 DCN SGE00595). Where 

Baker Hughes did not specify the formation being drilled, counts may include a mixture of rigs 

that are drilling for UOG, CBM, and COG. In 2012, nearly 1,800 active rigs drilled about 36,000 

wells (9 DCN SGE00503). 
Chapter B—Background on Unconventional Oil and Gas Extraction

33 

Table B-2. Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product Type (as of November 8, 2013)

Basinb Formationb 

Resource 

Typeb

Gas Rigs by Well Trajectory Oil Rigs by Well Trajectorya

Total 

Directional Horizontal Vertical Rigs

Total 

Gas Directional Horizontal Vertical

Total 

Oil

Permian —c Mix 0 6 1 7 21 206 235 462 469

Other d —c Mix 48 20 20 88 55 139 85 279 367

Western Gulf Eagle Ford Shale 0 26 0 26 17 174 9 200 226

Williston —c,e Mostly shalee 0 0 0 0 16 155 4 175 175

Appalachian Marcellus Shale 10 67 8 85 0 0 0 0 85

Anadarko Mississippi 

Lime Tight 0 9 0 9 2 58 6 66 75

Anadarko Granite Wash Tight 0 8 0 8 0 50 2 52 60

Denver J. Niobrara Shale 0 18 0 18 3 25 5 33 51

Anadarko Woodfordf Shale 1 17 0 18 2 27 3 32 50

TX-LA-MS 

Salt Haynesville Shale 0 38 0 38 0 2 0 2 40

Fort Worth Barnett Shale 0 18 0 18 0 9 9 18 36

Appalachian Utica Shale 2 17 0 19 0 15 2 17 36

Arkoma Fayetteville Shale 0 9 0 9 0 0 0 0 9

Total 61 253 29 343 116 860 360 1,336 1,679

Sources: 48 DCN SGE00693

a—Oil rigs include six “miscellaneous” rigs reported by Baker Hughes (8 DCN SGE00502). 

b—Baker Hughes (8 DCN SGE00502) reported a mixture of basins and formations. The EPA classified them by resource type (i.e., shale, tight) when specific 

formations were reported. When formations were not reported, the EPA classified the resource type as a “mix” of resources (conventional, tight, shale).

c—Baker Hughes reported basin as opposed to formation for these areas. Therefore, these areas may include rigs drilling in conventional and unconventional 

formations.

d—The majority of the “Other” rigs were drilling in Texas, Louisiana, Wyoming, California, Utah, and Colorado. The remaining rigs in the “Other” category 

were distributed evenly throughout the United States. 

e—The majority of these rigs are expected to have been drilling in the Bakken shale formation based on rig counts reported by the EIA (159 DCN SGE00595).

f—This formation includes the Woodford-Cana, Arkoma Woodford, and Ardmore Woodford formations.
Chapter B—Background on Unconventional Oil and Gas Extraction

34 

3.2 UOG Resource Potential

Assessments by the U.S. Geological Survey (USGS) and the EIA show substantial 

potential for new UOG wells. Using the USGS and EIA assessments, this section quantifies how 

many new UOG wells may be drilled in the future (i.e., new well potential) to estimate the 

potential number of new UOG extraction wastewater sources. The EIA also calculates new well 

potential in its AEO but only for several sub-formations.36 The EPA used the EIA methodology 

to calculate new well potential for all UOG formations.

37 This analysis is documented in more 

detail in a separate memorandum titled Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for 

Oil and Gas Extraction (48 DCN SGE00693; 50 DCN SGE00693.A02). 

The two EIA-reported parameters that the EPA used to calculate new well potential are 

described below. The EIA’s estimates of resource potential are primarily based on geological 

characteristics published by the USGS, which in turn rely on historical production data from 

existing wells and the technology deployed at the time of assessment. However, the EIA adjusts 

these estimates annually to account for the ongoing changes in drilling and completion practices 

and to account for formations not yet assessed by the USGS (32 DCN SGE00988; 31 DCN 

SGE00989). 

• Estimated ultimate recovery per well (EUR)—EUR is the quantity of oil and/or gas 

that is produced by a single well over its life.

• Technically recoverable resources (TRR)—The TRR is the quantity of oil and/or 

gas producible from a geological formation using current drilling and completion 

technology. The EIA’s TRR estimates are functions of total formation geographic 

area (square miles), the portion of formation land area that can be developed for oil 

and gas extraction, average well spacing assuming that the formation is fully 

developed, and EUR per well. TRR is the sum of proven reserves and unproven 

resources.38

To evaluate new well potential, the EPA calculated new well potential for each formation 

or sub-formation by dividing the TRR by the EUR. Table B-3 summarizes the total new well 

potential the EPA calculated for the four UOG resource types.

39 It also shows the approximate 

number of current wells based on the EPA’s analysis of Drillinginfo’s (DI) Desktop® well 

database (29 DCN SGE00520). Appendix F provides EUR and TRR on a formation basis based 

on this analysis. To calculate total TRR and new well potential by resource type, the EPA

 

36 For example, the Assumptions to the 2014 AEO reported new well potential for several, but not all, Bakken subformations: 29,186 wells. The EPA estimated approximately 28,562 new Bakken wells for the same Bakken sub 

formations. Differences between EIA and EPA new well potential are due to rounding (32 DCN SGE00988).

37 These estimates do not factor in future changes to TRR estimates by the EIA, advances in drilling technology, or 

economic conditions that ultimately affect how many wells UOG operators drill over time (31 DCN SGE00989; 32

DCN SGE00988).

38 Proven reserves are resources that are currently developed commercially or have been demonstrated with 

reasonable certainty to be recoverable in future years under existing economic conditions and current technologies. 

Unproven resources are resources that have been confirmed by exploratory drilling but are not yet commercially 

developed.

39 These estimates only include shale and tight oil and gas resources. It does not include CBM or COG. 
Chapter B—Background on Unconventional Oil and Gas Extraction

35 

summed the TRR and the new well potential for all formations in each resource type shown in 

Table F-2 and Table F-3. The results presented in Table B-3 show that the UOG new well 

potential is much greater than the active well count. The EPA estimates that approximately 2.2 

million potential new UOG wells—with associated extraction wastewater—may be drilled in the 

future. 

Table B-3. UOG Potential by Resource Type as of January 1, 2012

Resource 

Type

Weighted 

Average Oil 

EUR

(MMbls per 

well)

Weighted 

Average Gas 

EUR (Bcf per 

well)

Total Oil TRR 

(MMbls)

Total Gas 

TRR (Bcf)

Total New 

Well 

Potential

(Beginning in 

2012)

2010-2011 

Active Well 

Countb

Shale gas 0.007 0.543 6,200 501,500 923,000 H: 22,400

D: 1,820

V: 15,100

U: 15,300 Shale oil 0.079 0.099 26,300 33,100 333,000

Tight gas 0.006 0.483 4,200 352,200 729,000 H: 5,620

D: 9,230

V: 59,600

U: 32,800 Tight oil 0.105 0.076 22,500 16,400 215,000

All UOG 0.027 0.411 59,200 903,200 2,200,000

H: 28,000

D: 11,100

V: 74,700

U: 48,100

Sources: 48 DCN SGE00693

a—Gas production from shale and tight oil resources is associated gas that is produced simultaneously with oil. 

b—Well counts are based on ERG’s Analysis of DI Desktop® memorandum (45 DCN SGE00963). These well 

counts may not be all-inclusive.

Abbreviations: MMbls-million barrels; Bcf-billion cubic feet of gas; EUR—estimated ultimate recovery (per well); 

TRR—technically recoverable resources; H—horizontal; D—directional; V—vertical; U—trajectory unknown

3.3 Current and Projections of Future UOG Well Completions

In 2012 alone, more than 22,00040 oil and gas wells were hydraulically fractured 

nationwide (199 DCN SGE00585). As previously explained, hydraulic fracturing is currently the 

most popular well stimulation technique for UOG wells. A survey conducted by the American 

Petroleum Institute (API) and the American Natural Gas Alliance (ANGA) shows that, as of 

2010, nearly all unconventional wells were being completed using hydraulic fracturing (146

DCN SGE00291).41 Operators may also refracture existing oil and gas wells. Based on a national 

database maintained by IHS, Inc., 0.13 to 0.35 percent of well completions involving hydraulic 

fracturing from 2000 to 2010 were reported as refracturing of existing oil and gas wells (210

 

40 The actual number of wells fractured in 2012 is greater than 22,000 because this number is based on FracFocus 

data and some states where fracturing is common (e.g., Michigan) did not yet require reporting to FracFocus in 

2012.

41 This survey included well completion information for 5,307 well completions in 2010, consisting of a mixture of 

conventional and unconventional wells. The survey results showed that more than 96 percent of tight gas wells and 

99 percent of shale gas wells surveyed were hydraulically fractured. The survey also showed that 69 percent of 

conventional wells were hydraulically fractured. 
Chapter B—Background on Unconventional Oil and Gas Extraction

36 

DCN SGE01095.A09). A more recent survey of 205 UOG operators conducted by the Petroleum 

Equipment Suppliers Association (PESA)42 shows that in 2012 and 2013 approximately 10 

percent of well completions involving hydraulic fracturing were refracturing of existing oil and 

gas wells (136 DCN SGE00575). 

In 2012, IHS, Inc. estimated the total number of UOG wells that UOG operators may 

complete through 2035 (94 DCN SGE00728). The EPA generated Figure B-14 using data 

published by IHS (48 DCN SGE00693). The figure shows the projected number of UOG wells39

completed annually and cumulatively. Unconventional gas is further broken down into tight gas 

and shale gas. The projections estimated by IHS show a gradual increase in annual UOG well 

completions through 2035. 

Figure B-14. Projections of UOG Well Completions

Source: 48 DCN SGE00693

 

42 The PESA represents the energy industry’s manufacturers and oilfield service and supply companies. Its mission 

is to promote and advocate for policies that will support the oilfield service sector’s continued job creation, 

technological innovation, and economic stability. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

37 

Chapter C. UNCONVENTIONAL OIL AND GAS EXTRACTION WASTEWATER 

VOLUMES AND CHARACTERISTICS

Since 2000, horizontal drilling and hydraulic fracturing of UOG resources has increased

dramatically (209 DCN SGE01095). The EIA, in its 2014 AEO, projects that, within the next 30 

years, the majority of the country’s natural gas will come from unconventional resources and 

unconventional oil production will continue to increase substantially (31 DCN SGE00989). 

Consequently, industry experts expect UOG produced water volumes to continue to increase (34

DCN SGE00708; 98 DCN SGE00479; 95 DCN SGE00722; 141 DCN SGE00768.A01; 72 DCN 

SGE00768.A25). 

This chapter discusses UOG extraction wastewater volumes and characteristics. The EPA 

is proposing to define “UOG extraction wastewater” as sources of wastewater pollutants 

associated with production, field exploration, drilling, well completion, or well treatment.

43 This 

includes the following sources: 

• Produced water—the water (brine) brought up from the hydrocarbon-bearing strata 

during the extraction of oil and gas. This can include formation water, injection water, 

and any chemicals added downhole or during the oil/water separation process. Based 

on the stage of completion and production the well is in, produced water can be 

further broken down into the following components: 

— Flowback—the wastewater generated by UOG wells during the flowback 

process of well completion. After the hydraulic fracturing procedure is 

completed and pressure is released, the direction of fluid flow reverses, 

and the fluid flows up through the wellbore to the surface. The water that 

returns to the surface is commonly referred to as “flowback.” 

— Long-term produced water—the wastewater generated by UOG wells 

during the production phase after the initial flowback process. Long-term 

produced water continues to be produced throughout the lifetime of the 

well.

• Drill cuttings—the particles generated by drilling into subsurface geologic formations 

and carried out from the wellbore with the drilling fluid (mud). 

• Drilling wastewater—the liquid waste stream separated from recovered drilling fluid 

(mud) and drill cuttings during the drilling process. Drilling fluid is the circulating 

fluid used in the rotary drilling of wells to clean and condition the hole and to 

counterbalance formation pressure. 

• Produced sand—the slurried particles used in hydraulic fracturing, the accumulated 

formation sands, and scales particles generated during production. Produced sand also 

includes desander discharge from the produced water waste stream, as well as

blowdown of the water phase from the produced water treatment system.

 

43 Stormwater is not considered a source of UOG extraction wastewater. In general, no permit is required for 

discharges of stormwater from any field activities or operations associated with oil and gas production, except as 

specified in 40 C.F.R. part 122.26(c)(1)(iii) for discharges of a reportable quantity or that contribute to a violation of 

a water quality standard. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

38 

The EPA identified drilling wastewater and produced water as the major sources of 

wastewater pollutants associated with UOG extraction, so these wastewaters are described 

further below. The following subsections discuss volumes and chemical constituents found in 

fracturing fluid typically used by UOG operators and volumes and characteristics of drilling 

wastewater, flowback, and long-term produced water generated by UOG operations. The EPA 

identified this information from existing data sources, including state and federal agency 

databases, journal articles and technical papers, technical references, industry/vendor telephone 

calls, industry site visits, and meetings with industry. The EPA reported the data exactly as 

reported in existing literature throughout Chapter C. In some instances, the EPA compiled the 

existing data into a separate document to compile and analyze the data. These separate 

memoranda, referenced throughout Chapter C, are titled Unconventional Oil and Gas (UOG) 

Produced Water Volumes and Characterization Data Compilation (56 DCN SGE00724) and 

Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed 

Effluent Limitations Guidelines and Standards for Oil and Gas Extraction (48 DCN SGE00693). 

Section C.1 discusses the characteristics of fracturing fluid,

44 Section C.2 discusses 

typical volumes of UOG extraction wastewater, and Section C.3 presents constituents that are 

typically found in UOG extraction wastewater. Section C.3 extensively discusses TDS, a 

parameter that is often used to characterize UOG extraction wastewater because it provides a 

measure of dissolved matter including salts (e.g., sodium, chloride, nitrate), metals, minerals, and 

organic material (1 DCN SGE00046). Data in Section C.3 show that sodium chloride makes up 

the majority of TDS in UOG produced water. The data also show that chloride contributes 

heavily to the makeup of TDS in UOG drilling wastewater. TDS is not a specific chemical, but is 

defined as the portion of solids that pass through a filter with a nominal pore size of 2.0 μm or 

less as specified by Standard Method 2540C-1997.45 Because TDS in UOG produced water

primarily consists of inorganic salts and other ionic species, conductivity measurements may also 

be used to estimate TDS.

46 High measurements of specific conductivity are indicative of high 

TDS concentrations. 

TDS and chloride are potential concerns in the management of UOG extraction 

wastewater because of the high concentrations of these parameters in the wastewater. UOG 

produced water can have TDS concentrations up to 400,000 mg/L, which is over 10 times the 

concentration of TDS typically found in seawater (i.e., 35,000 mg/L). Chapter D discusses UOG 

extraction wastewater management and disposal practices. Section D.3 discusses 

reusing/recycling UOG extraction wastewater in hydraulic fracturing and the different factors 

(e.g., pollutant concentrations) that operators consider when reusing/recycling UOG extraction 

wastewater. Section D.5 discusses the problems that a POTW may experience if high 

concentrations of TDS and other UOG extraction wastewater constituents are present in POTW 

influent. 

 

44 The type of fracturing fluid and total fracturing fluid volume may dictate the characteristics of UOG produced 

water and are therefore described in this chapter.

45 40 C.F.R. part 136 lists standard method 2540C as an approved test method for TDS.

46 The electrical conductivity of water is directly related to the concentration of dissolved ionized solids in the water.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

39 

1 FRACTURING FLUID CHARACTERISTICS

As discussed in Section B.2.2, most UOG resources (e.g., tight oil, shale gas) are 

stimulated using hydraulic fracturing. Hydraulic fracturing of UOG resources typically requires 

high volumes of fracturing fluid, consisting of a base fluid mixed with proppant (e.g., sand) and 

chemicals. The quantity of each fracturing fluid component varies by operator, basin, formation, 

and resource type. The remainder of this subsection discusses the sources used for base fluid, 

concentrations of chemical additives, and observed constituents in fracturing fluids. 

1.1 Base Fluid Composition

The primary component of fracturing fluid is the base fluid to which proppant (sand) and 

chemicals are added. Fracturing fluids are typically water-based, though cases of non-aqueous 

fracturing fluids are documented in the literature (e.g., compressed nitrogen, propane) (209 DCN 

SGE01095). Base fluid typically consists of only fresh water (surface, groundwater, or municipal 

water) or a mixture of fresh water, reused/recycled UOG produced water, and/or other sources 

(e.g., treated municipal wastewater, groundwater) (126 DCN SGE00639; 136 DCN SGE00575). 

The PESA reports the following percentages of UOG operators using each water source as 

fracturing fluid in the United States (136 DCN SGE00575): 

• Surface water (e.g., rivers, lakes) (40 percent) 

• Groundwater (36 percent) 

• City/ municipal water47 (16 percent) 

• Recycled UOG produced water (7 percent)

48

• Industrial wastewater (1 percent) 

Table C-1 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-1, brackish sources are used 

more often in arid regions (e.g., the Permian and Gulf Coast basins in Texas and New Mexico). 

For basins/formations where the EPA identified projected data in addition to historic data, the 

EPA created a separate set of columns for each basin/formation combination. Projected 

percentages for the year 2020 are reported parenthetically in Table C-1. 

In general, the fraction of base fluid that can be composed of UOG produced water is 

limited by two factors (125 DCN SGE00556; 148 DCN SGE00710):

 

47 The PESA does not specify whether this water source is potable drinking water or treated municipal effluent (136

DCN SGE00575).

48 The amount 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. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

40 

• Produced water volume—When large volumes of flowback and long-term produced 

water are generated by other UOG wells in the area, reuse/recycle wastewater can 

make up a larger portion of base fluid water on average.

• Produced water quality—When the concentration of TDS in UOG produced water 

rapidly increases after fracturing, it may have less potential for reuse/recycle as a 

source of base fluid to fracture another well (148 DCN SGE00710). 

Table C-1. Sources for Base Fluid in Hydraulic Fracturing

Basin UOG Formation Resource Type

Percentage of Total Base Fluid Used for Hydraulic 

Fracturinga 

Fresh Waterb Brackish Waterb

Reused/Recycled 

UOG Produced

Water

All California 

Basins All formations shale and tight 96 0 4

Anadarko All formations shale and tight 50 (40) 30 (30) 20 (30)

Appalachian

Marcellus (PA) shale 82 to 90 0 10 to 18

Marcellus (WV) shale 77 to 83c,d --c 6 to 10

Arkoma Fayetteville shale 70 0 30

Fort Worth Barnett shale 92 (75) 3 (15) 5 (10)

Gulf Coast Eagle Ford shale 80 (50) 20 (40) 0 (10)

Permian (Far 

West) All formations shale and tight 20 (20) 80 (30) 0 (50)

Permian 

(Midland) All formations shale and tight 68 (35) 30 (40) 2 (25)

TX-LA-MS All formations shale and tight 95 (90) 0 (0) 5 (10)

Nationwide All formations shale and tight 40 53 7

Sources: 48 DCN SGE00693

a— Projected data for the year 2020 are shown parenthetically which were reported as the “most likely” scenario by 

Nicot et al. 2012 (126 DCN SGE00639).

b— Fresh water is naturally occurring water on the Earth's surface. Examples include ponds, lakes, rivers and 

streams, and certain underground aquifers. Fresh water is generally characterized by having low concentrations of 

dissolved salts. Brackish water is water that has more salinity than fresh water, but not as much as seawater.

Example sources include certain underground aquifers, effluent from publicly owned treatment plants (POTWs), and 

wastewater from other industries.

c—In addition to the 77 to 83 percent fresh water reported for the Marcellus shale in WV, 6 to 17 percent of base 

fluid was reported as “purchased water” and 1 to 3 percent was reported as groundwater both of which could be 

fresh or brackish. Neither of these values are included in this table. 

d—Hansen et al. 2013 (84 DCN SGE00532) reported this data as “surface water”.

“—” indicates no data.

1.2 Additives

In addition to base fluid, operators add proppant and chemicals to adjust the fracturing 

fluid properties. Proppant generally makes up 10 percent or less of the total fracturing fluid by 

mass. Chemical additives in total typically make up less than 0.5 percent of the total fracturing 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

41 

fluid by mass (78 DCN SGE00010). The additives and the quantity of additives used in 

fracturing fluid depend on the formation geology, base fluid characteristics, and UOG operator

(201 DCN SGE00721; 3 DCN SGE00070; 70 DCN SGE00780; 73 DCN SGE00781). Fracturing 

fluid additives are constantly evolving as UOG operators determine the most efficient 

composition to use for each fracture job. There are two general types of water-based fracturing 

fluids: 

• Slickwater fracturing fluids consist of small quantities of friction reducer, biocides, 

scale inhibitors, surfactants, and propping agents. Operators generally use slickwater 

designs to fracture dry natural gas producing formations (148 DCN SGE00710; 40

DCN SGE00705). 

• Gel fracturing fluids include higher quantities of gels to increase fluid viscosity that 

enables the fluid to carry higher concentrations of propping agents into the formation. 

Using gel fracturing fluids requires less total base fluid volume than using slickwater 

fracturing fluids, but gel fracturing fluids contain more additives and proppant. 

Consequently, gel fracturing fluids are more complex than slickwater fracturing fluids 

and are more sensitive to the quality of base fluid (148 DCN SGE00710; 40 DCN 

SGE00705). Operators generally use gel fracturing fluids to fracture liquid-rich 

formations (40 DCN SGE00705). 

In 2015, the EPA’s Office of Research and Development (ORD) released a report 

summarizing additives used by operators based on public disclosures to FracFocus49 (201 DCN 

SGE00721). In addition, several sources have published information regarding fracturing fluid 

additives and their uses in hydraulic fracturing (3 DCN SGE00070; 70 DCN SGE00780; 73

DCN SGE00781; 18 DCN SGE00966). Table C-2 shows specific additives used by operators 

categorized by purpose. Many additives can have multiple purposes depending on the exact 

design of the fracturing fluid. Table C-3 shows concentrations of the most common chemicals 

identified by operators in the FracFocus public disclosures, summarized in the EPA report, for 

hydraulically fractured gas and oil wells. 

Table C-2. Fracturing Fluid Additives, Main Compounds, and Common Uses

Additive 

Typea 

Common 

Compound(s)b Purpose

Acid Hydrochloric acid; 

Muriatic acid

Removes cement and drilling mud from casing perforations prior to 

fracturing fluid injection. 

Biocide

Glutaraldehyde; 2,2-

dibromo-3-

nitrilopropionamide

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.

Breaker Peroxydisulfates; salts

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.

 

49 Operators submit reports for individual wells to FracFocus. These reports include date of completion, well type 

(oil, gas), total fracturing fluid volume, well API number, well depth, location coordinates, and the concentrations of 

additives. These reports mostly represent wells completed in UOG formations but may also include some in 

conventional and coalbed methane formations.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

42 

Table C-2. Fracturing Fluid Additives, Main Compounds, and Common Uses

Additive 

Typea 

Common 

Compound(s)b Purpose

Clay 

stabilizer Potassium chloride

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.

Corrosion 

inhibitor

Ammonium bisulfite; 

methanol 

Reduces rust formation on steel tubing, well casings, tools, and tanks (used 

only in fracturing fluids that contain acid).

Crosslinker Borate salts; potassium 

hydroxide

Increases fluid viscosity to allow the fluid to carry more proppant into the 

fractures.

Friction 

reducer Petroleum distillates Minimizes friction, allowing fracturing fluids to be injected at optimum 

rates and pressures.

Gel Guar gum; 

hydroxyethyl cellulose

Increases fracturing fluid viscosity, allowing the fluid to carry more 

proppant into the fractures.

Iron control Citric acid Sequestering agent that prevents precipitation of metal oxides, which could 

plug the formation.

pH adjusting 

agent

Acetic acid; potassium 

or sodium carbonate

Adjusts and controls the pH of the fluid in order to maximize the 

effectiveness of other additives such as crosslinkers. 

Proppant Quartz; sand; silica Used to hold open the hydraulic fractures, allowing the gas or oil to flow to 

the production well.

Scale 

inhibitor Ethylene glycol Prevents the precipitation of carbonate and sulfate scales (e.g., calcium 

carbonate, calcium sulfate, barium sulfate) in pipes and in the formation.

Surfactant Isopropanol; 

naphthalene

Reduces the surface tension of the fracturing fluids to improve fluid 

recovery from the well after fracture is completed.

Sources: 201 DCN SGE00721; 3 DCN SGE00070; 70 DCN SGE00780; 73 DCN SGE00781; 18 DCN SGE00966

a—Operators do not use all of the chemical additives in hydraulic fracturing fluid for a single well: they decide 

which additives to use on a well-by-well basis.

b—The specific compounds used in a given fracturing operation will vary depending on company preference, base 

fluid quality, and site-specific characteristics of the target formation.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

43 

Table C-3. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in Gas and Oil Wells from FracFocus (2011-

2013)

Specific Constituents

CAS 

Number

Maximum Concentration in Hydraulic Fracturing Fluid (% by mass)

Gasa Oilb

Number of 

Reported 

Uses

Median 

Concentration

5th to 95th 

Percentile 

Concentration

Number of 

Reported 

Uses

Median 

Concentration

5th to 95th 

Percentile 

Concentration

Hydrochloric acid 7647-01-0 12,351 0.078 0.0063–0.67 10,029 0.29 0.013–1.8

Guar gum 9000-30-0 3,586 0.10 0.00057–0.38 9,110 0.17 0.027–0.43

Phenolic resin 9003-35-4 — — — 3,109 0.13 0.019–2.0

Distillates, petroleum, hydrotreated light 64742-47-8 11,897 0.017 0.0021–0.27 10,566 0.087 0.00073–0.39

Ethylene glycol 107-21-1 5,493 0.0061 0.000080–0.24 10,307 0.023 0.00086–0.098

Potassium hydroxide 1310-58-3 — — — 7,206 0.013 0.000010–0.052

Methanol 67-56-1 12,269 0.0020 0.000040–0.053 12,484 0.022 0.00064–0.16

Ethanol 64-17-5 6,325 0.0023 0.00012–0.090 3,536 0.026 0.000020–0.16

Saline 7647-14-5 3,608 0.0091 0–0.12 3,692 0.0071 0–0.27

Sodium hydroxide 1310-73-2 4,656 0.0036 0.000020–0.088 8,609 0.010 0.00005–0.075

Glutaraldehyde 111-30-8 5,635 0.0084 0.00091–0.023 5,927 0.0065 0.00027–0.020

Peroxydisulfuric acid, diammonium salt 7727-54-0 4,618 0.0045 0.000050–0.045 10,350 0.0076 0.00028–0.067

Solvent naphtha, petroleum, heavy arom. 64742-94-5 3,287 0.0044 0.000030–0.030 3,821 0.0060 0–0.038

2-Butoxyethanol 111-76-2 3,325 0.0035 0.000010–0.041 4,022 0.0053 0–0.17

Isopropanol 67-63-0 8,008 0.0016 0.000010–0.051 8,031 0.0063 0.00007–0.22

Acetic acid 64-19-7 3,563 0.0025 0–0.028 4,623 0.0047 0–0.047

Citric acid 77-92-9 4,832 0.0017 0.000050–0.011 3,310 0.0047 0.00016–0.024

2,2-Dibromo-3-nitrilopropionamide 10222-01-2 3,668 0.0018 0.000070–0.022 — — —

Naphthalene 91-20-3 3,294 0.0012 0.0000027–0.0050 — — —

Propargyl alcohol 107-19-7 5,811 0.000070 0.000010–0.0016 5,599 0.00022 0.000030–0.0030

Source: 48 DCN SGE00693

a—Represents 17,035 FracFocus disclosures for gas wells.

b—Represents 17,640 FracFocus disclosures for oil wells.

“—” indicates this additive was not commonly reported.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

44 

1.3 Fracturing Fluids

Fracturing fluid is the final mixture of base fluid and additives. Its total volume depends 

on the well trajectory (i.e., vertical, directional, horizontal) and the type of fracturing fluid used 

(e.g., gel, slickwater) (209 DCN SGE01095). Operators fracture UOG wells using 50,000 to over 

10 million gallons (1,200 to over 238,000 barrels) of fracturing fluid per well along with up to 

millions of pounds of sand (i.e., proppant). Operators typically fracture horizontal wells in eight 

to 23 stages, using between 250,000 and 420,000 gallons (6,000 and 10,000 barrels) of fracturing 

fluid per stage (190 DCN SGE00280). Literature reports that tight oil and gas wells typically 

require less fracturing fluid than shale oil and gas wells (86 DCN SGE00533). Typical volumes 

of fracturing fluid vary by UOG formation, well trajectory, number of stages, and resource type 

and are provided in Section C.2. 

The concentrations of TDS in fracturing fluid are often low (<20,000 mg/L) compared to 

levels found in UOG produced water, which suggests that the majority of the TDS in UOG 

produced water is contributed by the formation (see Section C.3) (16 DCN SGE00110, 85 DCN 

SGE00414). Other constituents, such as total organic carbon (TOC) and biochemical oxygen 

demand (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 1,70050 mg/L but BOD5 in the 

corresponding flowback and long-term produced water of 30051 mg/L or less on average (85

DCN SGE00414). As indicated in Table C-2 and Table C-3, organic materials (which contribute 

to BOD5 and TOC) are typical chemical additives in fracturing fluid (85 DCN SGE00414).

2 UOG EXTRACTION WASTEWATER VOLUMES

As explained previously, UOG wells generate three main types of wastewater over the 

life of the well: drilling wastewater, flowback, and long-term produced water (these latter two 

are collectively referred to as produced water). These wastewater streams’ flow rates and total 

volumes generated per well vary based on several factors, including: 

• Time since flowback commenced

• Resource type (e.g., shale oil, tight gas) 

• Specific geology properties (e.g., presence of naturally occurring water)

• Well trajectory (i.e., horizontal, directional, vertical) 

The following two subsections quantify wastewater volumes generated during the UOG 

well development process. Section C.2.1 summarizes general trends in UOG extraction 

wastewater volumes for each part of the well development process by resource type and well 

 

50 This study reported 1,700 mg/L as the median concentration based on 19 samples. The overall range of BOD was 

4.3 to 47,400 mg/L. 

51 This study reported 330 mg/L as the median concentration based on 19 flowback samples. The overall range of 

BOD was 30 to 1,440 mg/L.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

45 

trajectory. Section C.2.2 provides detailed produced water volumes by UOG formation and well 

trajectory.

52

2.1 UOG Extraction Wastewater Volumes by Resource and Well Trajectory

This section quantifies the volumes of UOG extraction wastewater generated, on a per 

well basis, for the following three wastewater components: 

• Drilling wastewater 

• Flowback

• Long-term produced water

Flowback and long-term produced water are the largest volumes of UOG extraction 

wastewater. Figure C-1 shows a breakdown of UOG extraction wastewater volumes generated

from Marcellus shale wells in Pennsylvania based on data from PA DEP’s statewide waste 

production reports for all wells active between 2004 and 2013 (46 DCN SGE00739). This trend 

varies by formation and, sometimes, within formations. However, a general rule of thumb for all 

UOG formations is that the total volume of UOG produced water (i.e., flowback, long-term 

produced water) generated by a well over its lifetime is approximately 50 percent flowback and 

50 percent long-term produced water—despite the fact that flowback is generated over less than 

30 days and long-term produced water is generated over the well life, which may be more than 

10 years (94 DCN SGE00728).53

 

52 Section C.2.2 does not include drilling wastewater volumes by formation and drill type because EPA identified 

less detailed data for drilling wastewater volumes compared to UOG produced water volumes.

53 Figure C-1 shows that long-term produced water is more than 50 percent of total UOG produced water for 

Marcellus shale wells likely because Marcellus wells generate relatively lower flowback volumes compared to other 

UOG formations (see Table C-8).
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

46 

Sources: 46 DCN SGE00739

Figure C-1. UOG Extraction Wastewater Volumes for Marcellus Shale Wells in 

Pennsylvania (2004–2013) 

Figure C-2 shows the quantities of produced water (i.e., flowback, long-term produced 

water) generated from UOG wells from the time of well completion to the end of the well life. 

The produced water generation rates reflect aggregated data from multiple UOG formations;

54

“n” is the number of data points for each time period.55 As shown in the figure, UOG produced 

water generation rates are highest immediately after well completion, when there is little or no 

oil and gas production (flowback). During the transition from the flowback process to production 

(within weeks of well completion), produced water generation rates decrease significantly and 

eventually level out. During production, produced water generation rates gradually decrease over 

the life of the well (long-term produced water).

 

54 As explained in Chapter B, the length of the flowback process is variable. Literature generally reports it as 30 

days or less (83 DCN SGE00532). Other operators report it as only lasting five days (151 DCN SGE00350). 55 Data for the first 90 days represent the Marcellus, Barnett, Woodford, Codell-Niobrara, Bakken, and Fayetteville 

UOG formations. Data beyond 90 days (long-term produced water) are from Table C-8. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

47 

Source: 56 DCN SGE00724 

Figure C-2. Ranges of Typical Produced Water Generation Rates over Time After 

Fracturing

2.1.1 Drilling Wastewater

Volumes of drilling wastewater typically increase with the length of the wellbore. For 

example, a vertical well will typically produce a smaller volume of drilling wastewater than a 

horizontal well drilled into the same formation, because the latter requires additional drilling 

fluid to complete the horizontal lateral (46 DCN SGE00739). Table C-4 illustrates this trend for 

UOG wells drilled into the Marcellus formation in Pennsylvania.

Table C-4. Median Drilling Wastewater Volumes for UOG Horizontal and Vertical Wells 

in Pennsylvania 

Well 

Trajectory

Median Drilling Fluid 

Volume per Well

(gallons)

Range of Drilling Fluid 

Volume per Well (gallons) a

Typical Total 

Measured Depth b 

Number of 

Data Points

Horizontal 46,000 3,200–210,000 10,000–11,000 3,055

Vertical 37,000 5,000–210,000 6,000–7,000 209

Source: 46 DCN SGE00739

a— These ranges are based on the 10th and 90th percentile of volumes reported for individual wells.

b— Total measured depth is the true length of wellbore drilled (i.e., sum of the vertical and horizontal).
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

48 

The EPA collected information on volumes of drilling wastewater generated per well. 

Table C-5 shows typical volumes generated by UOG wells by resource type and formation. 

Operators report that nearly all of the drilling fluid used per well is recovered as wastewater at 

the end of drilling.56 Therefore, where it had information on drilling fluid volumes but not the 

resulting drilling wastewater volume, the EPA assumed the former is representative of the latter. 

Table C-5. Drilling Wastewater Volumes Generated per Well by UOG Formation

Resource 

Type Formation Range (gallons)

Median

(gallons)

Typical Total 

Measured Deptha

(feet)

Number of Data 

Points

Shale Haynesville 420,000–1,100,000 600,000 13,000 – 19,000 5

Tight Anadarko Basinb 222,000–420,000 310,000 --c 2

Shale Niobrara —c 300,000 7,500 – 13,000 1

Shale Barnett 170,000–500,000 250,000 8,500 – 14,000 6

Shale Permian Basinb 95,200–420,000 210,000 --c 8

Tight Granite Wash —c 200,000 --c 1

Tight Cleveland —c 200,000 --c 1

Shale Eagle Ford 130,000–420,000 160,000 6,000 – 16,000 7

Shale Utica —c 100,000 6,000 – 19,000 1

Tight Mississippi Lime —c 100,000 --c 1

Shale Marcellus 2,400 – 170,000 92,000 7,300 – 13,000 2,072

Source: 55 DCN SGE00740

a—Total measured depth is the true length of wellbore drilled (i.e., sum of the vertical and horizontal).

b—Specific formation was not reported.

c—The EPA identified only one data point for these formations. Therefore, there is no range to display.

2.1.2 Produced Water: Flowback 

As described above, for purposes of this document, produced water includes flowback in 

addition to long-term produced water. Table C-6 quantifies the portion of fracturing fluid 

returned as flowback.

57 Because the volume of fracturing fluid used during well stimulation 

affects flowback quantities, fracturing fluid volumes are also listed. Given data in the table,

58

total flowback volumes typically range between 26,000 to 300,000 gallons (620 to 7,000 barrels) 

per well. On average, horizontal shale wells generate the highest volumes of flowback. In terms 

of wastewater management, operators must consider that the flowback process generates large 

volumes of wastewater in a short period of time (e.g., 30 days) compared to long-term produced 

water that is generated in small volumes over a long period of time.

 

56 Some drilling fluid volume may be lost downhole and/or to moisture in the cuttings, but these losses account for a 

relatively small percentage of the total volume (191 DCN SGE00625). 57 The EPA explains how it differentiated between flowback and long-term produced water volumes in literature in 

its memorandum Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data 

Compilation (56 DCN SGE00724).

58 Approximate flowback volumes can be estimated by multiplying total fracturing volume by the percent of 

fracturing fluid returned during flowback. However, EPA does not show this calculation in Table C-6 because not 

all data sources report both fracturing fluid volume and percent of fracturing fluid recovered as flowback.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

49 

Table C-6. UOG Well Flowback Recovery59 by Resource Type and Well Trajectory

Resource 

Type Trajectory

Fracturing Fluid (MG)

a 

Flowback (Percent of Fracturing 

Fluid Returned)a 

Median Range

Number of 

Data Points Median Range

Number of 

Data Points

Shale

H 4.0 0.13–15 50,053 6 1–50 6,488

D 1.6 0.051–12 124 14 4–31 19

V 1.2 0.015–22 4,152 24 7–75 18

Tight

H 2.2 0.042–9.4 765 7 7–60 39

D 0.60 0.056–4.0 693 6 0–60 263

V 0.31 0.019–4.0 1,287 8 1–83 48

Source: 56 DCN SGE00724 (Data are based on aggregated data from Table C-8, which contains volumes by 

formation) 

a—Most of the underlying fracturing fluid volume data and percentages of fracturing fluid returned as flowback 

were reported in different sources. To avoid representing the data incorrectly, the EPA did not calculate total 

flowback volume for Table C-6. 

Abbreviations: MG—million gallons; H—horizontal well; D—directional well; v—vertical well

2.1.3 Produced Water: Long-Term Produced Water

Long-term produced water rates remain relatively constant60 over the well life compared 

to flowback rates (178 DCN SGE00635). Table C-7 quantifies long-term produced water rates in 

gallons per day by UOG resource and well trajectory. Median long-term produced water rates 

range from about 380 to 900 gallons (9 to 21 barrels) per day. A comparison of median long-term 

produced water rates for shale formation wells, as listed in the table, shows that horizontal shale 

wells have higher median generation rates than directional and vertical shale wells. On the other 

hand, median long-term produced water rates for tight formation wells in Table C-7 show that 

vertical tight wells have higher generation rates than directional and horizontal tight wells, but 

horizontal wells have the highest maximum generation rate. 

 

59 Flowback recovery is the percent of total fracturing fluid injected during hydraulic fracturing that returns to the 

wellhead during the flowback process.

60 Note that long-term produced water rates typically gradually decrease over the well life. However, the change is 

small relative to flowback.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

50 

Table C-7. Long-Term Produced Water Generation Rates by Resource Type and Well 

Trajectory

Resource 

Type Trajectory

Long-Term Produced Water Generation Rates (gpd per well)a

Median Range Number of Data Points

Shale

H 900 0–19,000 22,222

D 480 22–8,700 695

V 380 0–4,600 12,393

Tight

H 620 0–120,000 2,394

D 750 12–1,800 3,816

V 570 0–4,000 21,393

Sources: 56 DCN SGE00724

a—Based on aggregated data from Table C-8, which contains volumes by formation. 

Abbreviations: gpd—gallons per day; H—horizontal well; D—directional well; V—vertical well

2.2 UOG Produced Water Volumes by Formation

Table C-8 shows the underlying UOG produced water volumes by formation and well 

trajectory used to generate the summary statistics in Section C.2.1. The data in Table C-8 are

specific to UOG formations and are sorted alphabetically by basin and then from highest median 

fracturing fluid volume to lowest within each formation. Because the EPA identified less detailed 

data by formation for drilling wastewater, Table C-8 does not include drilling wastewater 

volumes. 

Data in Table C-8 illustrate that volumes of flowback and flow rates of long-term 

produced water vary by formation. For example, UOG horizontal wells drilled into the Barnett 

shale formation in the Fort Worth basin generate 920 gallons (22 barrels) per day of long-term 

produced water compared to 110 gallons (3 barrels) per day for horizontal wells drilled into the 

Eagle Ford shale formation in the Western Gulf basin (206 DCN SGE00623). In some cases, 

produced water even varies geographically within the same formation, which is not evident in 

Table C-8. For example, operators report that wells drilled in the northeast portion of the 

Marcellus shale formation (in Pennsylvania) generate less produced water than wells drilled in 

the southwest portion of the Marcellus shale formation (in West Virginia) (178 DCN 

SGE00635). 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

51 

Table C-8. Produced Water Volume Generation by UOG Formation

Basin

UOG 

Formation

Resource 

Type

Drill

Type

Fracturing Fluid (MG)

Flowback (% of Fracturing 

Fluid Returned)

Long-Term Produced Water 

Rates (gpd)

Median Rangeb

Number of 

Data Pointsa Median Rangeb

Number of 

Data Pointsa Median Rangeb

Number of 

Data Pointsa

Anadarko

Granite Wash tight

H 6.2 0.20–9.4 77 — 7–22 2 1,300 0–2,200 273

V 0.56 0.050–

3.0 26 — — 2 500 170–1,300 2,413

Woodford shale H 4.7 1.0–12 2,239 34 20–50 3 5,500 3,200–

6,400 198

Mississippi 

Lime tight H 1.8 0.82–2.4 428 — 50 1 — 37,000–120,000 4 

Cleveland tight

H 0.81 0.20–4.0 144 — 12–40 2 82 20–300 571

V 0.69 0.11–3.0 4 — — 2 32 6.6–170 390

Appalachian

Marcellus shale

H 4.4 0.90–11 14,010 7 4–47 4,374 860 54–13,000 4,984

V 2.6 0.53–6.6 66 40 21–60 7 230 100–1,200 714

Utica shale H 4.0 1.0–11 150 4 2–27 73 510 210–1,200 82

Arkoma Fayetteville shale H 5.1 1.7–11 1,668 — 10–20 2 430 150–2,300 2,305

Denver J.

Niobrara shale

H 2.6 0.73–3.4 69 13 6–25 16 680 260–810 250

V 0.32 0.27–3.3 367 11 7–35 9 340 240–600 5,474

Codell-Niobrara tight

H 2.6 0.15–2.7 62 7 — 32 34 19–140 32

D 0.45 0.21–

0.47 116 — — 0 — — 0 

V 0.30 0.13–

0.46 592 — — 0 29 13–65 1,677

Muddy J tight

D 0.59 0.25–

0.62 162 — — 0 230 64–390 3 

V 0.28 0.16–

0.62 292 — — 0 55 9.3–500 129

Codell tight

D 0.28 0.21–

0.46 78 — — 0 — — 0 

V 0.27 0.13–

0.46 185 — — 0 — — 0 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

52 

Table C-8. Produced Water Volume Generation by UOG Formation

Basin

UOG 

Formation

Resource 

Type

Drill

Type

Fracturing Fluid (MG)

Flowback (% of Fracturing 

Fluid Returned)

Long-Term Produced Water 

Rates (gpd)

Median Rangeb

Number of 

Data Pointsa Median Rangeb

Number of 

Data Pointsa Median Rangeb

Number of 

Data Pointsa

Fort Worth Barnett shale

H 3.6 1.0–7.3 23,917 30 21–40 11 920 160–4,200 10,349

V 1.3 0.4–1.9 3,589 — — 0 250 170–580 3,318

Green River

Hilliard-BaxterMancos shale H 1.7 1.0–5.6 2 — — 0 37 15–58 7 

Lance tight

V 1.3 0.81–3.5 29 3 1–50 31 410 250–580 1,050

D 1.2 0.76–1.9 180 6 1–17 170 860 360–1,200 1,140

Mesaverde 

(Green River) tight

D 0.23 0.16–

0.31 73 8 0–37 61 190 150–440 445

V 0.17 0.081–

0.29 14 21 6–83 11 290 140–610 1,081

Illinois New Albany shale H — — 0 — — 0 — 2,900 2

Michigan Antrim shale V — 0.050 1 — 25–75 2 — 4,600 1

Permian

Avalon & Bone 

Spring

shale D 2.2 0.94–4.5 20 13 5–31 16 950 220–2,400 183

shale H 1.1 0.73–2.8 17 — — 0 0 0–2,300 37

BarnettWoodford shale H 2.1 0.5–4.5 2 — — 0 — — 0 

Wolfcamp shale

H 1.4 1.1–3.9 55 — — 0 3,000 210–

19,000 104

D 1.3 0.26–1.7 12 16 15–20 3 310 22–8,700 259

V 0.81 0.078–

1.7 60 — — 0 910 130–1,700 926

Spraberry tight V — 1.0 1 — — 0 870 100–4,000 66

Devonian (TX) shale

H 0.32 0.13–

0.89 10 — — 0 880 310–1,800 381

V 0.27 0.12–1.0 16 — — 0 400 150–3,000 162

San Juan Mesaverde (San 

Juan) tight D — — 0 — — 0 18 12–260 48
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

53 

Table C-8. Produced Water Volume Generation by UOG Formation

Basin

UOG 

Formation

Resource 

Type

Drill

Type

Fracturing Fluid (MG)

Flowback (% of Fracturing 

Fluid Returned)

Long-Term Produced Water 

Rates (gpd)

Median Rangeb

Number of 

Data Pointsa Median Rangeb

Number of 

Data Pointsa Median Rangeb

Number of 

Data Pointsa

Dakota tight

V 0.2 0.063–

0.22 19 — — 0 65 29–120 6 

D 0.12 0.070–

0.30 52 4 1–40 30 160 41–370 379

TX-LA-MS

Haynesville shale

H 5.3 0.95–15 3,222 5 5–30 3 1,700 84–1,800 1,249

V 0.61 0.14–3.5 9 — — 0 210 56–850 263

Cotton Valley tight

H 4.2 0.25–6.0 30 — <60 2 770 130–2,700 335

D 0.48 0.084–

4.0 24 — <60 2 950 630–1,800 1,801

V 0.28 0.019–

0.94 76 — <60 2 640 370–1,800 10,717

Travis Peak tight

H 3.0 0.25–6.0 2 — — 0 200 39–1,700 5

V 0.90 0.20–4.0 2 — — 0 980 330–1,800 1,380

Bossier shale

H 2.7 1.7–3.6 2 — — 0 750 610–1,200 25

V 0.40 0.19–1.7 16 — — 0 470 180–1,100 1,203

D 0.28 0.13–

0.80 21 — — 0 320 130–1,300 253

Western 

Gulf

Austin Chalk tight H 0.94 0.58–1.3 15 — — 0 720 290–2,400 1,097

Eagle Ford shale

H 5.0 1.0–14 2,485 4 2–8 1,800 110 9.1–250 498

V 2.9 2.0–4.1 9 — — 0 — — 0

Pearsall shale H 3.7 3.3–4.1 2 — — 0 200 54–370 12

Wilcox Lobo tight

H 2.1 0.66–2.6 4 — — 0 330 62–740 77

V 0.21 0.06–

0.60 14 — — 0 620 330–1,400 1,514

D 0.058 0.056–

0.076 3 — — 0 — — 0 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

54 

Table C-8. Produced Water Volume Generation by UOG Formation

Basin

UOG 

Formation

Resource 

Type

Drill

Type

Fracturing Fluid (MG)

Flowback (% of Fracturing 

Fluid Returned)

Long-Term Produced Water 

Rates (gpd)

Median Rangeb

Number of 

Data Pointsa Median Rangeb

Number of 

Data Pointsa Median Rangeb

Number of 

Data Pointsa

Vicksburg tight

V 0.16 0.084–

0.60 20 — — 0 1,000 650–1,900 937

D 0.11 0.10–

0.13 4 — — 0 — — 0 

Olmos tight V — 0.15 2 — — 0 — — 0

Williston Bakken shale

H 2.0 0.35–10 2,203 19 5–47 206 680 380–1,500 1,739

V 1.1 0.35–2.9 12 — — 0 1,000 340–3,100 222

Sources: 56 DCN SGE00724

a—For some formations, the number of data points was not reported in the data source. In these instances, this table reports that number as 1, except if the source reported 

a range in which case this table reports the number of data points as 2. 

b—For some formations, if only one data point was reported, the EPA reported it in the range column and did not report a median value. 

 “—” indicates no data.

Abbreviations: MG—million gallons; H—horizontal well; D—directional well; V—vertical well
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

55 

3 UOG EXTRACTION WASTEWATER CHARACTERIZATION

As discussed in Chapter B, UOG operations generate wastewater that includes drilling 

wastewater, flowback, and long-term produced water. Drilling wastewater is generated during 

the initial drilling of the well and typically maintains the characteristics of the drilling fluid, but 

also contains additional solids (i.e., drill cuttings) that are generated during the well drilling 

process. Flowback may contain the specific fracturing fluid composition (e.g., chemical 

additives, base fluid) used by each UOG operator as well as chemical constituents present in the 

UOG formation (80 DCN SGE00286; 16 DCN SGE00110). Long-term produced water typically 

mimics the characteristics of the UOG formation, which often contributes, in part, to high 

concentrations of select naturally occurring ions (124 DCN SGE00090). The volumes and 

characteristics of UOG extraction wastewater may vary significantly between basins, between 

formations, and sometimes between wells within the same formation (see Section C.2 for a 

discussion of UOG extraction wastewater volumes) (153 DCN SGE00592). The following 

subsections describe the characteristics of UOG extraction wastewater.

3.1 Availability of Data for UOG Extraction Wastewater Characterization

The EPA identified concentration data for constituents commonly found in UOG 

extraction wastewater. These constituents include, primarily, total dissolved solids (TDS), 

anions/cations, metals, hardness, and radioactive constituents. The EPA presents summarized 

UOG extraction wastewater characterization data in the following subsections, which are 

organized into five constituent categories: classical and conventional, organic, metal, radioactive, 

and other. Table C-9 shows relative quantities of data found for each constituent category. The 

number of stars indicates the amount of data available, where one star indicates less data and five 

stars indicates more data.

Table C-9. Availability of Data for UOG Extraction Wastewater Characterization

Constituent 

Category Examples of Constituents Included Within Category

Amount of 

Available 

Produced 

Water Data

Amount of 

Available 

Drilling 

Wastewater 

Data

Classical and 

conventionala

TDS, TSS, COD, BOD5, pH, conductivity, chloride, sodium, 

calcium ★★★★★ ★★

Organic Ethylbenzene, toluene ★★★ ★

Metal Barium, strontium, magnesium, potassium, iron, copper, zinc ★★★★★ ★★

Radioactive Radium-226, radium-228, gross alpha, gross beta ★★ ★

Other Guar gum, microorganisms ★ ★

a—The classical and conventional constituent category also includes a discussion of the anions and cations that 

contribute to TDS. These anions and cations are italicized in the examples column.

For all of the constituent categories, data on concentrations are less available for 1) 

produced water specifically generated from tight oil and gas wells and 2) drilling wastewater 

generated at all UOG wells. The EPA presents available data in the following subsections. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

56 

3.2 UOG Extraction Wastewater Constituent Categories

The data in the following subsections are representative of UOG extraction wastewater 

characteristics as presented in the literature for the entire UOG industry.

61 The data show 

combined characterization data for shale and tight reservoirs as well as for oil and gas resources. 

Regarding UOG produced water, the EPA sometimes presents the data as flowback and longterm produced water individually. In other instances, the data are presented as UOG produced 

water, which includes both flowback and long-term produced water.

3.2.1 Classical and Conventional Constituents in UOG Extraction Wastewater

Table C-10 presents typical concentrations of select classical and conventional 

constituents that are present in UOG drilling wastewater. According to one CWT facility 

operator, TSS is high in returned drilling fluid before cuttings are removed. Depending on how 

well the cuttings are removed by the operator, solids can be as high as 50 percent by mass in 

drilling wastewater (37 DCN SGE00245) (see Section B.2.1). The EPA identified the following 

limitations to the data presented in Table C-10: 

• Fewer data points (i.e., less than 30 data points) were available for each parameter. 

• All of the data came from the Marcellus shale formation. 

Table C-11 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-11: 

• Fewer data points (i.e., less than 30 data points) were available for ammonia and 

phosphate. 

• The majority of data associated with alkalinity, BOD5, chemical oxygen demand 

(COD), specific conductivity, TOC, and TSS came from the Marcellus shale 

formation. 

• The majority of data associated with chloride and TDS came from the Eagle Ford 

shale formation. 

• The majority of data associated with pH came from the Woodford-Cana-Caney shale 

formation. 

 

61 Note that the lack of data for select constituents may not necessarily imply that those constituents are not present

in the wastewater, but rather that they were not measured and/or reported in the existing literature. Refer to 56 DCN 

SGE00724 for additional details on the parameters reported in the literature reviewed. The accompanying database 

includes non detect, below detection, or zero values that were reported in the literature reviewed. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

57 

Table C-10. Concentrations of Select Classical and Conventional Constituents in UOG 

Drilling Wastewater from Marcellus Shale Formation Wells62

Parameter Units Range Median

Number 

of Data 

Points Number of Detects

Formation 

Represented

Alkalinity mg/L 110–42,000 1,600 11 11 Marcellus

Ammonia mg/L 0.98–35 7 8 8 Marcellus

BOD5 mg/L 80–1,100 390 8 8 Marcellus

Chloride mg/L 160–23,000 12,000 12 12 Marcellus

COD mg/L 150–9,300 1,800 8 8 Marcellus

Hardness as CaCO3 mg/L 1,400–46,000 4,400 12 12 Marcellus

Oil and grease mg/L NDa–150 2.5 8 8 Marcellus

pH SU 6.8–12 9.0 12 12 Marcellus

Phosphate mg/L —b 16 4 4 Marcellus

Specific 

conductivity μS/cm 1,100–60,000 19,000 10 10 Marcellus

TDS mg/L 560–80,000 31,000 14 14 Marcellus

TSS mg/L 120–600,000 28,000 16 16 Marcellus

Source: 55 DCN SGE00740

a—Source did not report detection limit.

b—Source only reported median value.

Abbreviations: mg/L—milligrams per liter; ND—non detect; SU—standard units; μS/cm—microsiemens per 

centimeter

 

62 Drilling wastewater may contain differing amounts of drill cuttings depending on how the operator chooses to 

remove drill cuttings from drilling wastewater.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

58 

Table C-11. Concentrations of Select Classical and Conventional Constituents in UOG Produced Water

Parameter Units Range Median Number of Data Pointsa Number of Detects Formations Representeda

Alkalinity mg/L 7.5–1,600 140 265 265 Barnett (29); Eagle Ford (1); Marcellus (232); 

Woodford-Cana-Caney (3)

Ammonia mg/L 39–350 110 13 13 Marcellus (5); Niobrara (5); Woodford-CanaCaney (3)

Bicarbonate mg/L 0 – 19,000 290 6,352 6,352

Bakken (398); Barnett (6); Cleveland (11); Cotton 

Valley/Bossier (3); Dakota (3); Eagle Ford 

(2,925); Lansing Kansas City (16); Marcellus 

(154); Mesaverde/Lance (5); Morrow (1); New 

Albany (1); Oswego (5); Pearsall (3); Spraberry 

(26); Woodford-Cana-Caney (2,795)

BOD5 mg/L 2–12,000 160 154 153 Barnett (28); Marcellus (122); Medina/ClintonTuscarora (1); Woodford-Cana-Caney (3)

Carbonate mg/L 0 – 13,000 0 59 59

Bakken (20); Barnett (4); Cotton Valley/Bossier 

(2); Dakota (3); Eagle Ford (4); Spraberry (26)

Chlorideb mg/L 64–230,000 73,000 2,190 2,190

Bakken (22); Barnett (144); Cleveland (11); 

Cotton Valley/Bossier (25); Dakota (3); Eagle 

Ford (1651); Granite Wash/Atoka (1); Marcellus 

(287); Mesaverde/Lance (5); New Albany (1); 

Niobrara (5); Pearsall (3); Spraberry (26); Utica 

(1); Woodford-Cana-Caney (5)

COD mg/L 99–37,000 3,200 149 149 Barnett (23); Marcellus (122); Medina/ClintonTuscarora (1); Woodford-Cana-Caney (3)

Hardness as CaCO3 mg/L 160–110,000 21,000 80 80 Barnett (15); Marcellus (65)

Oil and grease mg/L 0.21–1,500 5.6 134 99 Barnett (23); Marcellus (108); Woodford-CanaCaney (3)

pH SU 3.9–12 6.5 5,233 5,233

Bakken (420); Barnett (30); Cleveland (4); Cotton 

Valley/Bossier (3); Dakota (3); Eagle Ford (1600); 

Fayetteville (2); Lansing Kansas City (16); 

Marcellus (300); Medina/Clinton-Tuscarora (3); 

Mesaverde/Lance (5); Morrow (1); Oswego (5); 

Spraberry (26); Woodford-Cana-Caney (2815)

Phosphate mg/L 12–88 31 4 4 Barnett (1); Marcellus (1); Woodford-Cana-Caney 

(2)

Specific conductivity μS/cm 0.11–760,000 120,000 162 162 Bakken (9); Barnett (25); Dakota (3); Marcellus 

(103); Spraberry (19); Woodford-Cana-Caney (3)
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

59 

Table C-11. Concentrations of Select Classical and Conventional Constituents in UOG Produced Water

Parameter Units Range Median Number of Data Pointsa Number of Detects Formations Representeda

TDS mg/L 320–400,000 100,000 2,164 2,164

Bakken (11); Barnett (38); Bradford-Venango-Elk 

(5); Cleveland (11); Cotton Valley/Bossier (3); 

Dakota (3); Devonian (11); Eagle Ford (1647); 

Fayetteville (4); Green River (1); 

Haynesville/Bossier (2); Marcellus (373); 

Mesaverde/Lance (5); Mississippi Lime (3); New 

Albany (1); Niobrara (8); Pearsall (3); Spraberry 

(26); Utica (1); Woodford-Cana-Caney (8)

TOC mg/L 1.2–5,700 65 129 124 Bakken (2); Barnett (28); Marcellus (96); 

Woodford-Cana-Caney (3)

TSS mg/L 4–14,000 130 150 150 Bakken (2); Barnett (29); Eagle Ford (1); 

Marcellus (113); Woodford-Cana-Caney (5)

Source: 56 DCN SGE00724

a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these 

instances, there were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified. 

b—The EPA assumed values reported as “Cl” in the wastewater characterization data were meant to represent “chloride” values. 

Abbreviations: mg/L—milligrams per liter; SU—standard units; μS/cm—microsiemens per centimeter
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

60 

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-11, the median COD concentration 

found in UOG produced water is 3,200 mg/L. However, researchers have shown that 

concentrations of COD may be influenced by chloride, bromide, alkaline earth metals (e.g., 

barium, calcium), and reduced inorganic constituents (e.g., sulfide, nitrite). As shown in Table 

C-13, the median concentrations of sulfide and nitrite in UOG produced water are less than 10 

mg/L, indicating that they are not likely to have an influence on the COD concentrations. 

However, chloride, bromide, and alkaline earth metals are present at higher concentrations than 

reduced inorganic constituents in UOG produced water and may interfere with COD sample 

measurements (227 DCN SGE00725). In Table C-11, the relatively low median TOC 

concentration (65 mg/L) and BOD5 concentration (160 mg/L) compared to the COD 

concentration likely indicates that some of the COD measurements reported in existing literature 

experienced interference from high concentrations of chloride, bromide, and group II alkaline 

earth metals. Therefore, reported COD concentrations may be higher than actual COD 

concentrations in UOG produced water. 

TDS, which is regularly measured in UOG produced water, provides a measure of 

dissolved matter including salts (e.g., sodium, chloride, nitrate), metals, minerals, and organic 

material (1 DCN SGE00046). TDS is not a specific chemical, but is defined as the portion of 

solids that pass through a filter with a nominal pore size of 2.0 μm or less (Standard Method 

2540C-1997, ASTM D5907-03, and USGS I-1750-85). Salts are the majority of TDS in UOG 

produced water, and sodium chloride often constitutes approximately 50 percent of the TDS in 

UOG produced water (1 DCN SGE00046). As reported in Table C-11, the concentration of TDS 

in UOG produced water is approximately 10 percent by weight. 

Calcium and other group II alkaline earth metals (e.g., strontium, barium, magnesium) 

also contribute to the TDS in UOG produced water. 

Figure C-3 shows the primary anions and cations that contribute to TDS in UOG 

produced water in various shale and tight oil and gas formations. Data for all of the anions and 

cations contributing to TDS were not available for all formations. For example, the EPA did not 

identify any sodium concentration data in the Pearsall formation. Similarly, the EPA did not 

identify any chloride concentration data in the Spraberry formation. These missing data will 

account for some of the remaining TDS concentrations that are currently shown as “other 

dissolved constituents” in Figure C-3. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

61 

Source: 56 DCN SGE00724

Figure C-3. Anions and Cations Contributing to TDS Concentrations in Shale and Tight 

Oil and Gas Formations63

As shown in Figure C-3, of those chemicals specifically identified as contributing to 

TDS, sodium, chloride, and calcium ions make up the majority of TDS in UOG produced water. 

Additional ions that may contribute to the TDS in UOG produced water include bromide, 

fluoride, nitrate, nitrite, phosphate, and sulfate. Figure C-4 shows ranges of concentrations of 

sodium, chloride, and calcium contributing to TDS in UOG flowback and long-term produced 

water. The data used to create this figure include constituent concentration data from flowback or 

long-term produced water generated at a shale or tight oil and gas well. The data show that 

concentrations of these constituents are typically higher in long-term produced water than in 

flowback. 

 

63 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. 

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

Concentration (mg/L)

Other Dissolved Constituents

Potassium

Barium

Bromide

Magnesium

Strontium

Calcium

Sodium

Chloride

EPA assumed values reported as “Cl” in the wastewater characterization data were meant to represent “chloride” values and were reported as such 

in Table C-11.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

62 

10

100

1,000

10,000

100,000

1,000,000

TDS -

Flowback

TDS -

LTPW

Chloride -

Flowback

Chloride -

LTPW

Sodium -

Flowback

Sodium -

LTPW

Calcium -

Flowback

Calcium 

LTPW

Concentration (mg/L)

n=118

n=123 n=91

n=43 n=108

n=575

n=97

n=580

EPA assumed values reported as “Cl” in the wastewater characterization data were meant to represent “chloride” values and were reported as 

such in Table C-11.

Source: 56 DCN SGE00724

Figure C-4. Chloride, Sodium, and Calcium Concentrations in Flowback and Long-Term 

Produced Water (LTPW) from Shale and Tight Oil and Gas Formations 

Table C-12 presents typical concentrations of additional constituents that may contribute 

to TDS in drilling wastewater. The EPA identified the following limitations to the data presented 

in the table: 

• Fewer data points (i.e., less than 30 data points) were available for all parameters.

• All of the data came from the Marcellus shale formation.

Table C-13 presents typical concentrations of additional constituents that may contribute 

to TDS in UOG produced water. The EPA identified the following limitations to the data 

presented in the table: 

• Less data (i.e., less than 30 data points) were available for nitrite and phosphate. 

• All of the available data for nitrite and sulfide came from the Marcellus shale 

formation. 

• The majority of the data associated with nitrate came from the Bakken shale 

formation. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

63 

• The majority of the data associated with bromide and fluoride came from the 

Marcellus shale formation.

• The majority of the data associated with sulfate came from the Woodford-CanaCaney shale formation.

Table C-12. Concentrations of Select Anions and Cations Contributing to TDS in UOG 

Drilling Wastewater from Marcellus Shale Formation Wells

Parameter Units Range Median

Number 

of Data 

Points Number of Detects

Formation 

Represented

Bromide mg/L 23–210 110 5 5 Marcellus

Sulfate mg/L ND–1,600 220 13 10 Marcellus

Source: 55 DCN SGE00740

Abbreviation: mg/L—milligrams per liter
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

64 

Table C-13. Concentrations of Select Anions and Cations Contributing to TDS in UOG Produced Water

Parameter Units Range Median

Number of 

Data Points

Number of 

Detects Formations Represented (Number of Associated Data Points)a

Bromide mg/L 0.20–3,100 510 111 111 Barnett (23); Marcellus (85); Woodford-Cana-Caney (3)

Fluoride mg/L 0.045–390 2.5 99 97 Barnett (23); Marcellus (73); Woodford-Cana-Caney (3)

Nitrate mg/L 0.30–920 0.30 110 110 Bakken (107); Marcellus (3)

Nitrite mg/L 5.0–5.0b 5.0 2 2 Marcellus (2)

Phosphate mg/L 12-88 31 4 4 Barnett (1); Marcellus (1); Woodford-Cana-Caney (2)

Sulfate mg/L 0–7,200 270 4,711 4,687

Bakken (424); Barnett (31); Cleveland (9); Cotton Valley/Bossier (1); 

Dakota (3); Devonian (4); Eagle Ford (1,166); Fayetteville (2); Lansing 

Kansas City (15); Marcellus (301); Medina/Clinton-Tuscarora (2); 

Mesaverde/Lance (4); Morrow (1); New Albany (1); Niobrara (5); Oswego 

(4); Pearsall (3); Spraberry (26); Woodford-Cana-Caney (2,709)

Sulfide mg/L 0.80–30 3.0 76 69 Marcellus (76)

Source: 56 DCN SGE00724

a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these 

instances, there were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified.

b—Only two data points were identified for nitrite concentrations in UOG produced water and both data points reported the same value.

Abbreviation: mg/L—milligrams per liter
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

65 

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 Units Range Median

Number of 

Data Points

Number of 

Detects

Formation 

Represented

Benzene μg/L NDa–40 NDa 20 5 Marcellus

Ethylbenzene μg/L —b 9.6 4 4 Marcellus

Ethylene glycol mg/L —b 500 1 1 Marcellus

Toluene μg/L NDa–80 NDa 20 8 Marcellus

Xylene (m,p) μg/L —b 88 4 4 Marcellus

Xylene (o) μg/L —b 22 4 4 Marcellus

Source: 55 DCN SGE00740

a—Source did not report detection limit.

b—Source only reported median value.

Abbreviations: ND—non detect; mg/L—milligrams per liter; μg/L—micrograms per liter
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

66 

Table C-15. Concentrations of Select Organic Constituents in UOG Produced Water

Parameter Units Range Median

Number of 

Data Points

Number of 

Detects

Formations Represented 

(Number of Associated Data Points)a

1,2,4-trimethylbenzene μg/L 0.54–4,000 5.0 92 89 Barnett (25); Marcellus (67)

1,3,5-trimethylbenzene μg/L 0.64–1,900 5.0 85 81 Barnett (18); Marcellus (67)

Acetone μg/L 5.9–160,000 40 96 86 Barnett (22); Marcellus (74)

Benzene μg/L 0.99–800,000 8.5 144 122 Barnett (25); Marcellus (111); Niobrara (5); Woodford-CanaCaney (3)

Carbon disulfide μg/L 5.0–7,300 5.0 68 67 Marcellus (68)

Chlorobenzene μg/L 0–500 5.0 72 70 Marcellus (69); Woodford-Cana-Caney (3)

Chloroform μg/L 0–500 5.0 77 75 Barnett (5); Marcellus (69); Woodford-Cana-Caney (3)

Ethanol μg/L 1,000–230,000 10,000 53 53 Marcellus (53)

Ethylbenzene μg/L 0.63–8,900 5.0 130 104 Barnett (18); Marcellus (108); Medina/Clinton-Tuscarora (1); 

Woodford-Cana-Caney (3)

Isopropylbenzene μg/L 0.53–500 5.0 83 69 Barnett (16); Marcellus (67)

Methanol μg/L 3,200–4,500,000 10,000 55 55 Marcellus (55)

Methyl chloride μg/L 2.0–500 5.0 95 69 Marcellus (95)

Naphthalene μg/L 0.50–1,400 5.0 129 103 Barnett (39); Marcellus (90)

Phenol μg/L 0.70–460 2.0 111 83 Barnett (17); Marcellus (91); Woodford-Cana-Caney (3)

Pyridine μg/L 1.1–2,600 86 91 90 Barnett (24); Marcellus (67)

Tetrachloroethylene μg/L 5.0–5,000 5.0 95 68 Marcellus (95)

Toluene μg/L 0.91–1,700,000 6.0 149 125 Barnett (25); Marcellus (115); Medina/Clinton-Tuscarora (1); 

Niobrara (5); Woodford-Cana-Caney (3)

Xylenes μg/L 3.0–440,000 15 136 111 Barnett (20); Marcellus (112); Medina/Clinton-Tuscarora (1); 

Woodford-Cana-Caney (3)

Source: 56 DCN SGE00724

a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these instances, 

there were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified.

Abbreviation: μg/L—micrograms per liter
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

67 

Table C-3 includes concentration data for ethanol, methanol, and naphthalene, suggesting 

that a portion of the concentrations of these constituents found in UOG produced water (see 

Table C-15) may have originated from the fracturing fluid. Methanol is typically used in 

fracturing fluid as a biocide, corrosion inhibitor, crosslinker, and surfactant; ethanol is also used 

as a biocide and surfactant (see Table C-2).

Operators may use methanol as an antifreezing agent at UOG operations in areas with 

seasonal temperature fluctuations. Methanol may be used at the wellhead to avoid freezing in the 

wellbore or at compressor stations to prevent equipment from freezing. 

The EPA did not identify any quantitative information about diesel-range organics or 

total petroleum hydrocarbons in UOG produced water. However, Table C-3 shows that 

petroleum distillates are typically used in fracturing fluid at 0.0021 to 0.27 percent by mass. The 

EPA ORD’s 2015 Evaluation of Hydraulic Fracturing Fluid Data from the FracFocus Chemical 

Disclosure Registry 1.0 contains additional information about these constituents (201 DCN 

SGE00721). 

3.2.3 Metals in UOG Extraction Wastewater

UOG extraction wastewater contains varying concentrations of numerous metals. 

Table C-16 presents concentration data from existing literature for the metals most 

common in UOG drilling wastewater. The EPA identified the following limitations to the data 

presented in the table: 

• Fewer data points (i.e., less than 30) were available for each parameter.

• All of the data came from the Marcellus shale formation. 

Table C-17 presents concentration data from existing literature for the metals most 

common in UOG produced water. The EPA identified the following limitations to the data 

presented in the table: 

• Fewer data (i.e., less than 30 data points) were available for vanadium. 

• All of the available data for vanadium came from the Marcellus shale formation.

• The majority of the data associated with aluminum, antimony, arsenic, beryllium, 

boron, cadmium, cobalt, copper, iron, lead, lithium, manganese, mercury, 

molybdenum, nickel, selenium, silver, strontium, thallium, tin, titanium, and zinc 

came from the Marcellus shale formation.

• The majority of the data associated with calcium, magnesium, potassium, and sodium 

came from the Eagle Ford and Woodford-Cana-Caney shale formations. 

• The majority of the data associated with chromium came from the Bakken shale 

formation. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

68 

Table C-16. Concentrations of Select Metal Constituents in UOG Drilling Wastewater

from Marcellus Shale Formation Wells

Parameter Units Range Median

Number of 

Data Points

Number of 

Detects

Formation 

Represented

Aluminum mg/L 1.7–6,900 38 12 12 Marcellus

Arsenic mg/L NDa–4.2 NDa 12 6 Marcellus

Barium mg/L 2.6–2,000 13 14 14 Marcellus

Beryllium mg/L NDa–0.018 NDa 8 2 Marcellus

Boron mg/L NDa–2.7 0.17 8 4 Marcellus

Cadmium mg/L NDa–0.0050 NDa 8 1 Marcellus

Calcium mg/L 150–15,000 1,300 13 13 Marcellus

Chromium mg/L NDa–11 0.010 12 8 Marcellus

Cobalt mg/L NDa–1.8 NDa 8 3 Marcellus

Copper mg/L NDa–17 0.83 8 6 Marcellus

Iron mg/L 4.2–18,000 86 12 12 Marcellus

Lead mg/L NDa–8.0 0.35 12 10 Marcellus

Lithium mg/L NDa–1.2 NDa 8 1 Marcellus

Magnesium mg/L NDa–3,600 290 12 11 Marcellus

Manganese mg/L NDa–350 4.3 12 11 Marcellus

Mercury mg/L NDa–0.029 NDa 8 2 Marcellus

Molybdenum mg/L —b 0.10 1 1 Marcellus

Nickel mg/L NDa–16 0.55 12 9 Marcellus

Potassium mg/L —b 8,800 4 4 Marcellus

Selenium mg/L NDa–0.11 NDa 8 3 Marcellus

Silver mg/L NDa–0.010 NDa 8 1 Marcellus

Sodium mg/L 170–16,000 2,900 12 12 Marcellus

Strontium mg/L 1.8–1,500 21 13 13 Marcellus

Zinc mg/L NDa–38 2.1 12 10 Marcellus

Source: 55 DCN SGE00740

a—Source did not report detection limit.

b—Source only reported median value.

Abbreviation: mg/L—milligrams per liter; ND—non detect
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

69 

Table C-17. Concentrations of Select Metal Constituents in UOG Produced Water

Parameter Units Range Median

Number of 

Data Points

Number of 

Detects Formations Represented (Number of Associated Data Points)a

Aluminum mg/L 0.048 - 47 0.45 159 128 Bakken (4); Barnett (31); Marcellus (116); Woodford-Cana-Caney (3)

Antimony mg/L 0.0089 - 0.5 0.047 112 79 Barnett (9); Marcellus (103)

Arsenic mg/L 0.004 - 0.5 0.057 132 96 Barnett (15); Marcellus (114); Woodford-Cana-Caney (3)

Barium mg/L 0 - 16,000 19 1,097 1,096 

Bakken (312); Barnett (38); Cotton Valley/Bossier (2); Dakota (3); Devonian (4); Eagle 

Ford (8); Fayetteville (2); Lansing Kansas City (7); Marcellus (209); Medina/ClintonTuscarora (1); Morrow (1); Utica (1); Woodford-Cana-Caney (508)

Beryllium mg/L 0.0009 - 420 0.04 114 72 Barnett (2); Marcellus (112)

Boron mg/L 0.018 - 150 14 148 134 Bakken (8); Barnett (32); Eagle Ford (1); Marcellus (102); Niobrara (5)

Cadmium mg/L 0 - 1.2 0.0086 134 92 Barnett (16); Marcellus (115); Woodford-Cana-Caney (3)

Calcium mg/L 13 - 130,000 6,700 5,336 5,335 

Bakken (426); Barnett (39); Cleveland (11); Cotton Valley/Bossier (3); Dakota (3); 

Devonian (4); Eagle Ford (1644); Fayetteville (2); Lansing Kansas City (15); Marcellus 

(342); Medina/Clinton-Tuscarora (2); Mesaverde/Lance (5); Morrow (1); New Albany 

(1); Oswego (5); Pearsall (3); Spraberry (26); Woodford-Cana-Caney (2804)

Chromium mg/L 0.0066 - 260 0.3 383 349 Bakken (234); Barnett (26); Marcellus (115); Woodford-Cana-Caney (3)

Cobalt mg/L 0.0045 - 25 0.5 124 92 Barnett (16); Eagle Ford (1); Marcellus (103)

Copper mg/L 0 - 4.2 0.14 147 107 Bakken (2); Barnett (22); Marcellus (115); Woodford-Cana-Caney (3)

Iron mg/L 0.95 - 810 39 407 380 Bakken (22); Barnett (35); Cotton Valley/Bossier (2); Dakota (3); Eagle Ford (10); 

Fayetteville (2); Marcellus (300); Spraberry (26); Utica (1); Woodford-Cana-Caney (6)

Lead mg/L 0 - 5 0.03 133 96 Bakken (1); Barnett (15); Marcellus (113); Woodford-Cana-Caney (3)

Lithium mg/L 0.5 - 430 52 120 120 Barnett (31); Marcellus (89)

Magnesium mg/L 3 - 27,000 670 3,562 3,549 

Bakken (426); Barnett (39); Cleveland (11); Cotton Valley/Bossier (3); Dakota (3); 

Devonian (4); Eagle Ford (1621); Fayetteville (2); Lansing Kansas City (15); Marcellus 

(326); Medina/Clinton-Tuscarora (2); Mesaverde/Lance (5); Morrow (1); New Albany 

(1); Oswego (5); Pearsall (3); Spraberry (26); Woodford-Cana-Caney (1069)

Manganese mg/L 0.12 - 43 1.7 235 221 Bakken (7); Barnett (37); Cotton Valley/Bossier (2); Dakota (3); Eagle Ford (6); 

Fayetteville (2); Marcellus (155); Spraberry (19); Woodford-Cana-Caney (3)

Mercury mg/L 0 - 0.3 0.0002 115 85 Barnett (11); Marcellus (101); Woodford-Cana-Caney (3)

Molybdenum mg/L 0.003 - 13 0.038 140 118 Bakken (1); Barnett (29); Marcellus (105)

Nickel mg/L 0.007 - 4 0.12 151 121 Barnett (27); Eagle Ford (1); Marcellus (116); Woodford-Cana-Caney (3)
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

70 

Table C-17. Concentrations of Select Metal Constituents in UOG Produced Water

Parameter Units Range Median

Number of 

Data Points

Number of 

Detects Formations Represented (Number of Associated Data Points)a

Potassium mg/L 0 - 8,500 3,100 715 699 

Bakken (382); Barnett (36); Cleveland (3); Cotton Valley/Bossier (3); Eagle Ford (149); 

Marcellus (136); Medina/Clinton-Tuscarora (2); Mesaverde/Lance (1); Woodford-CanaCaney (3)

Selenium mg/L 0.0043 - 0.5 0.05 110 75 Barnett (7); Marcellus (103)

Silver mg/L 0.00073 - 0.5 0.05 115 75 Marcellus (112); Woodford-Cana-Caney (3)

Sodium mg/L 64 - 430,000 39,000 3,449 3,448 

Bakken (426); Barnett (38); Cleveland (11); Cotton Valley/Bossier (3); Dakota (3); 

Devonian (4); Eagle Ford (1631); Fayetteville (2); Lansing Kansas City (16); Marcellus 

(202); Medina/Clinton-Tuscarora (2); Mesaverde/Lance (5); Morrow (1); New Albany 

(1); Niobrara (5); Oswego (5); Spraberry (26); Woodford-Cana-Caney (1068)

Strontium mg/L 0 - 8,000 750 253 251 

Bakken (10); Barnett (35); Cotton Valley/Bossier (2); Dakota (3); Devonian (4); Eagle 

Ford (8); Fayetteville (2); Marcellus (183); Medina/Clinton-Tuscarora (2); Utica (1); 

Woodford-Cana-Caney (3)

Thallium mg/L 0.0049 - 1 0.1 120 83 Barnett (13); Marcellus (104); Woodford-Cana-Caney (3)

Tin mg/L 0.0038 - 3 1 80 78 Barnett (10); Marcellus (69)

Titanium mg/L 0 - 8 0.19 111 80 Barnett (16); Marcellus (94)

Vanadium mg/L 0.063 - 40 0.63 27 2 Marcellus (26)

Zinc mg/L 0 - 250 0.2 160 135 Bakken (2); Barnett (32); Eagle Ford (1); Fayetteville (2); Marcellus (116); WoodfordCana-Caney (3)

Source: 56 DCN SGE00724

a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these instances, there 

were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified.

Abbreviation: mg/L—milligrams per liter
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

71 

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. Other metals with median concentrations 

between 100 mg/L and 750 mg/L are magnesium and strontium, which are group II alkaline 

earth metals. Low-solubility salts of these metals (e.g., barium sulfate) commonly precipitate in 

pipes and valves, forming scale. Barium is commonly found in higher concentrations in 

produced water from the Marcellus and Devonian shale formations than in produced water from 

other UOG formations. Figure C-5 shows the concentrations of barium in UOG produced water

from various shale and tight oil and gas formations on a log scale. Median concentrations of 

heavy metals (e.g., chromium, copper, nickel, zinc, lead, mercury, arsenic) in UOG produced 

water are less than 1 mg/L, much lower than the concentrations of the alkaline earth metals. 

1.0

10.0

100.0

1,000.0

10,000.0

Barnett Cotton Valley/Bossier Devonian Fayetteville Marcellus

Barium Concentration (mg/L)

Source: 56 DCN SGE00724

Figure C-5. Barium Concentrations in UOG Produced Water from Shale and Tight Oil and 

Gas Formations

3.2.4 Radioactive Constituents in UOG Extraction Wastewater

Oil and gas formations contain varying levels of naturally occurring radioactive material 

(NORM) resulting from uranium and thorium decay, which can be transferred to UOG produced 

water. Radioactive decay products typically include radium-226 and radium-228 (54 DCN 

SGE00933). The EPA identified limited available data (primarily from the Marcellus Shale 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

72 

formation) on some radioactive constituents in UOG extraction wastewater, including radium226, radium-228, gross alpha, and gross beta, and therefore focused the radioactive constituent 

discussion and data presentation on these parameters. ERG’s Radioactive Materials in the 

Unconventional Oil and Gas (UOG) Industry memorandum (54 DCN SGE00933) contains a 

more detailed discussion of this topic. 

The EPA identified limited radioactive constituent concentration data for UOG drilling 

wastewater. Table C-18 shows the available data from the Marcellus shale formation. 

Table C-18. Concentrations of Select Radioactive Constituents in UOG Drilling 

Wastewater from Marcellus Shale Formation Wells

Number of Number of Formations 

Parameter Units Range Median Data Points Detects Represented

Gross alpha pCi/L 17–3,000 130 5 5 Marcellus

Gross beta pCi/L 32–4,200 1,200 5 5 Marcellus

Sources: 55 DCN SGE00740

Abbreviation: pCi/L—picocuries per liter

Similarly, the EPA identified limited radioactive constituent concentration data for UOG 

produced water. As presented in Table C-19, most available data characterize produced water 

from the Marcellus formation; limited data were available from the Niobrara formation. Radium226 and radium-228 are both found in UOG produced water, with radium-226 concentrations 

generally two to five times greater than radium-228 concentrations. 

The EPA identified the following limitations to the data presented in the table: 

• Limited or no radioactive constituent concentration data were available for the 

majority of shale and tight formations. 

• Many EPA methods are known to experience interference from high TDS 

concentrations or the presence of Group II elements, which are typical of UOG 

extraction wastewater, and may result in an underestimation of reported values.

ERG’s Radioactive Materials in the Unconventional Oil and Gas (UOG) Industry

memorandum (54 DCN SGE00933) discusses potential interference issues associated 

with various EPA methods and notes that the following methods may experience 

interference from UOG extraction wastewater: 900.0 Gross Alpha and Gross Beta 

Radioactivity, 903.0 Alpha-Emitting Radium Isotopes, and 903.1 Radium-226, Radon 

Emanation Technique. 

Table C-19. Concentrations of Select Radioactive Constituents in UOG Produced Water

Parameter Formation Method(s) Range (pCi/L) Median (pCi/L)

Number of 

Data Points

Number of 

Detects

Gross 

alpha Marcellus 900.0 8.7 - 120,000 8,700 74 74

Gross 

alpha Niobrara 900.0 620–4,000 1,800 3 3

Gross beta Marcellus 900.0 6.8 - 21,000 1,600 73 72
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

73 

Table C-19. Concentrations of Select Radioactive Constituents in UOG Produced Water

Parameter Formation Method(s) Range (pCi/L) Median (pCi/L)

Number of 

Data Points

Number of 

Detects

Gross beta Niobrara 900.0 250–1,200 760 3 3

Radium226 Marcellus901.1 Mod., 903.0, 

903.1, γ-spectrometry 0.16 - 27,000 1,700 103 101

Radium226 Niobrara 901.1 Mod. 170–900 620 3 3

Radium228 Marcellus901.1. 903.0, 904.0, γspectrometry 0 - 1,900 470 94 92

Radium228 Niobrara 901.1 Mod. 100–460 330 3 3

 Sources: 56 DCN SGE00724

Abbreviations: pCi/L—picocuries per liter; NA—not available

As a point of comparison, Table C-20 includes data from a 2014 International Atomic 

Energy Agency report (96 DCN SGE00769) that included radium isotope concentrations in 

rivers, lakes, groundwater, and drinking water. Data for radium-228 were limited, but the 

average of measured concentrations of radium-226 found in U.S. rivers and lakes was 0.56 pCi/L 

(21 mBq/L). The median concentrations of radium-226 and radium-228 in UOG produced water 

in at least one of the formations presented in Table C-19 was above the maximum naturally 

occurring concentration in U.S. rivers, lakes, groundwater, or drinking water presented in Table 

C-20. Radium in groundwater may originate from rocks, soil, and other naturally occurring 

materials, which are likely also the origins of a portion of the radium in UOG produced water. 

Table C-20. Concentrations of Radioactive Constituents in Rivers, Lakes, Groundwater, 

and Drinking Water Sources Throughout the United States (pCi/L)

Parameter Location Description Minimum Maximum Average

Boise, Idaho—well water — — 0.10

Florida—groundwater ND 76 —

Florida—well water 0.20 3.3 —

Hudson River — — 0.032

Illinois—well water 0.020 23 —

Radium-226 Illinois Lake 0.059 1.3 —

Iowa—well water 0.10 48 —

Iowa—well water 1.8 25 —

Joliet, Illinois—well water — — 6.5

Lake Ontario 0.04 1.7 —

Memphis, Tennessee—well water — — 0.21

Miami, Florida—well water — — 0.48

Mississippi River 0.010 1.1 —

Ottawa County, OK—well water 0.10 15 —

Sarasota, Florida—groundwater 1.5 24 —

South Carolina—well water 2.7 27 —
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

74 

Table C-20. Concentrations of Radioactive Constituents in Rivers, Lakes, Groundwater, 

and Drinking Water Sources Throughout the United States (pCi/L)

Parameter Location Description Minimum Maximum Average

South Texas—groundwater 0.40 170 —

Suwannee River — — 0.20

U.S. drinking water 0.011 4.9 —

Utah—well water 1.0 20 —

Wichita, Kansas—groundwater — — 0.23

Radium-228

Iowa—well water 0.60 6.3 —

South Carolina—well water 4.7 12 —

U.S. drinking water 0 0.014 —

Source: 96 DCN SGE00769

“—”—Data were not reported. 

Note: Data are presented as they were reported, either as a range (i.e., minimum, maximum) or as an average 

value. 

Abbreviations: pCi/L—picocuries per liter; ND—non detect

In January 2015, PA DEP announced the results of a study of radioactive elements in 

UOG extraction wastewater, sludge, and drill cuttings. Although PA DEP concluded “...[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,” they 

did conclude “...[t]here is a potential for radiological environmental impacts from spills of 

produced water [and flowback fluid] on natural gas well sites and from spills that could occur 

from the transportation and delivery of ...[these] fluid[s]” (135 DCN SGE01028).

3.2.5 Other Constituents in UOG Extraction Wastewater

UOG produced water may also contain guar gum, which is a polymer that is commonly 

used in fracturing fluid to transport the proppant to the end of the wellbore (see Table C-2 and 

Table C-3). Guar gum may be found in UOG produced water at concentrations between 100 

mg/L and 20,000 mg/L (193 DCN SGE00616). Guar gum treatment requires a breakdown of the 

polymer and is a consideration for UOG operators who are reusing/recycling wastewater for 

fracturing. 

Microorganisms are also found in UOG drilling wastewater and produced water. 

Microorganisms may be present in concentrations as high as 1 × 109 organisms per 100 mL in 

UOG produced water (193 DCN SGE00616). Sulfate-reducing bacteria (SRB) are one 

classification of a naturally occurring microorganism that may be found in UOG produced water

and drilling wastewater. SRB can cause problems during reuse/recycle of UOG produced water 

because they can reduce and/or precipitate metals and ions, potentially causing scale in the 

wellbore. They can also create hydrogen sulfide,

64 a potential human health concern that is also 

highly corrosive and can harm the well casing and wellbore (201 DCN SGE00721). 

 

64 Exposure to low concentrations of hydrogen sulfide may cause difficulty breathing and/or irritation to the eyes, 

nose, or throat. Exposure to high concentrations of hydrogen sulfide may cause headaches, poor memory, 

unconsciousness and death (4 DCN SGE00723).
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

75 

3.3 UOG Produced Water Characterization Changes over Time

Concentrations of TDS, radioactive elements, and organic compounds vary across 

different formations and over time. However, for the vast majority of formations for which data 

are available, the data demonstrate that flowback and long-term produced water are both 

influenced by constituents present in the formation. For example, concentrations of select 

naturally occurring constituents commonly found in shale formations (e.g., bromide, magnesium) 

are found in elevated concentrations in flowback compared to hydraulic fracturing fluid. The 

elevated concentrations indicate that the formation is contributing concentrations of these 

constituents to the flowback. Similarly, concentrations of TDS and TDS-contributing 

constituents (e.g., sodium, chloride, calcium) increase over time as formation water and the 

dissolution of constituents out of the formation contribute to long-term produced water. 

RPSEA’s 2012 Characterization of Flowback Waters from the Marcellus and the Barnett 

Shale Regions (85 DCN SGE00414) presents sampling data from 19 sites in the Marcellus shale 

and five sites in the Barnett shale. The sampled constituents include a wide array of classicals, 

conventionals, organics, and metals. Where possible, these constituents were sampled at day 0, 

day 1, day 5, day 14, and day 90. Figure C-6 presents median data for select constituents as 

reported in the RPSEA report. Figure F-1 in the appendices presents median data for additional 

constituents as reported in the RPSEA report. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

76 

Source: The EPA generated this figure using data from 85 DCN SGE00414. 

Figure C-6. Constituent Concentrations over Time in UOG Produced Water from the 

Marcellus and Barnett Shale Formations
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

77 

Chapter D. UOG EXTRACTION WASTEWATER MANAGEMENT AND DISPOSAL 

PRACTICES

During the lifetime of a well, UOG extraction generates large volumes of UOG extraction 

wastewater that contain constituents potentially harmful to human health and the environment, as 

discussed in Chapter C. This creates a need for appropriate wastewater management 

infrastructure and disposal practices. Except in limited circumstances,

65 the existing effluent 

guidelines for oil and gas extraction prohibit the onsite direct discharge of wastewater into waters 

of the United States. Historically, operators primarily managed their wastewater via underground 

injection (where available). This section discusses the methods used by UOG operators to 

manage and dispose of UOG extraction wastewater.

1 OVERVIEW OF UOG EXTRACTION WASTEWATER MANAGEMENT AND DISPOSAL 

PRACTICES 

For management of UOG produced water, UOG operators primarily use the three 

methods listed below and shown in Figure D-1 (188 DCN SGE00613; 177 DCN SGE00276; 76

DCN SGE00528). 

• Dispose of wastewater via underground injection, using Class II UIC disposal wells

(“disposal wells”)

• Reuse/recycle wastewater in subsequent fracturing jobs

• Transfer wastewater to a CWT facility

Across the United States, operators most often manage their produced water via disposal 

wells. For management of drilling wastewater, which includes drill cuttings and drilling fluids, 

operators primarily use the methods listed below and shown in Figure D-2 (55 DCN SGE00740). 

• Disposal via disposal wells

• Reuse/recycle in subsequent drilling and/or fracturing jobs 

• Transfer to a CWT facility

• Onsite burial66

• Disposal via landfill 

• Land application

In select areas, UOG operators also use evaporation ponds for disposal of UOG produced 

water and drilling wastewater. However, there are certain requirements for using evaporation 

ponds, including very dry climates, which mainly occur in the western United States (148 DCN 

 

65 While the existing oil and gas extraction ELG allows onshore oil and gas extraction wastewater generated west of 

the 98th meridian to be permitted for discharge when the water is of good enough quality for agricultural and wildlife 

uses (see 40 C.F.R. part 435 subpart E), the EPA has not found that these types of permits are typically written for 

UOG extraction wastewater (as defined for the proposed rule).

66 Onsite burial involves temporary fluid storage in on-site open earthen or lined pits with burial of residual solids 

after fluids are solidified, removed from the top, or evaporated.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

78 

SGE00710). Evaporation ponds also require a large, flat site, and they perform best only during 

select months of the year (e.g., May through October) (114 DCN SGE00779.A24). 

CWT 

facilities

POTWs

Treatment 

in the field 

Surface 

water

Reuse in 

fracturing

UOG Wells

UOG Well

Legend

Treated UOG Produced Water

Untreated UOG Produced Water

Injection into Class 

II disposal wells

Figure D-1. UOG Produced Water Management Methods 

CWT 

facilities

POTWs

Treatment 

in the field 

Surface 

water

Reuse/Recycle

UOG well Legend

Treated drilling wastewater

Untreated drilling wastewater

Injection into class 

II disposal wells

Burial Landfill

Figure D-2. UOG Drilling Wastewater Management Methods 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

79 

UOG operators’ frequency of use of each of the aforementioned UOG extraction 

wastewater management options varies by operator, by formation, and sometimes within each 

region of the formation (139 DCN SGE00579; 177 DCN SGE00276; 178 DCN SGE00635; 55

DCN SGE00740). Table D-1 describes how UOG operators manage produced water specifically 

in basins containing major UOG formations, which varies by basin and formation. As detailed 

above, historically, the oil and gas industry has most commonly managed produced water by

underground injection (25 DCN SGE00182), but the industry is increasingly turning to 

reuse/recycle and, in some geographic areas, transferring to CWT facilities to manage growing 

volumes of wastewater (see Section D.3 and Section D.4) (43 DCN SGE00596; 92 DCN 

SGE00707; 34 DCN SGE00708). 

The literature does not contain the same level of detailed information about drilling 

wastewater management practices as is provided for produced water management in Table D-1. 

However, the EPA did identify comprehensive data for management of drilling wastewater 

generated by Marcellus shale wells located in Pennsylvania. Figure D-3 shows management 

practices used by UOG operators in Pennsylvania for managing their UOG drilling wastewater 

from 2008 to 2013. In recent years (2010 to 2013), transfer to CWT facilities, reuse/recycle in 

drilling or fracturing, and injection for disposal—in that order—were the most common practices

(46 DCN SGE00739) for UOG drilling wastewater management in Pennsylvania. In addition to 

this detailed information about drilling wastewater management in Pennsylvania, the EPA

obtained information from a large UOG operator regarding its Fayetteville shale operations. This 

operator reported that it reuses/recycles the majority of its drilling wastewater in drilling

subsequent wells and the remainder is disposed of via disposal wells (191 DCN SGE00625). 

To illustrate how management practices used by UOG operators vary geographically, the 

EPA mapped the locations of known CWT facilities and disposal wells in the Appalachian basin 

(containing the Utica and Marcellus shale formations).

67 Figure D-4 compares the east and west 

portions of the basin, thus illustrating basin and formation differences in wastewater 

management practices. The east side of the basin contains very few underground disposal wells, 

but contains a high density of CWT facilities that have accepted or plan to accept UOG produced 

water from operators. In contrast, the west side has an abundance of disposal wells and injection 

for disposal is the primary wastewater management practice. 

The remaining subsections in Chapter D describe UOG produced water management 

practices: how disposal in disposal wells is the most common practice, how reuse/recycle in 

fracturing fluid is increasing, and how increasing numbers of CWT facilities are accepting UOG 

produced water and drilling wastewater where disposal wells are limited. Although operators 

have discharged UOG extraction wastewater to POTWs, these discharges were discontinued in 

2011 (46 DCN SGE00739; 80 DCN SGE00286; 109 DCN SGE00345; 139 DCN SGE00579). 

After describing the three management alternatives that the UOG industry uses (i.e., injection 

into disposal wells, reuse/recycle in fracturing, transfer to CWT facility), Chapter D ends with a 

discussion of POTWs and how they cannot remove some of the constituents in UOG extraction 

wastewater and drilling wastewater. The end of Chapter D also presents EPA-collected data

 

67 The EPA obtained information about CWT facilities accepting UOG extraction wastewater from publicly 

available sources. Therefore, the list of CWT facilities the EPA identified may not be complete.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

80 

indicating that POTWs have not received any UOG extraction wastewater between 2011 and the 

present (data are current up through the end of 2013).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

81 

Table D-1. UOG Produced Water Management Practices

Basin UOG Formation

Resource 

Type

Reuse or 

Recycle

Injection for 

Disposal

CWT 

Facilities Notes

Available 

Datab 

Michigan Antrim Shale gas XXX Qualitative

Appalachian Marcellus/Utica (PA) Shale gas XXX XX XX

Limited disposal wells in east

Quantitative

Marcellus/Utica (WV) Shale gas/oil XXX XX X Quantitative

Marcellus/Utica (OH) Shale gas/oil XX XXX X Mixed

Anadarko Granite Wash Tight gas XX XXX Xa Mixed

Mississippi Lime Tight oil X XXX Reuse/recycling limited but is being 

evaluated Qualitative

Woodford, Cana, 

Caney

Shale gas/oil X XXX Xa

Qualitative

Arkoma Fayetteville Shale gas XX XX Xa Few existing disposal wells; new CWT

facilities are under construction Mixed

Fort Worth Barnett Shale gas X XXX Xa Reuse/recycle not typically effective due to 

high TDS early in flowback and abundance 

of disposal wells

Mixed

Permian Avalon/Bone Springs, 

Wolfcamp, Spraberry

Shale/tight 

oil/gas

X XXX Xa

Mixed

TX-LA-MS Salt Haynesville Tight gas X XXX Reuse/recycle not typically effective due to 

high TDS early in flowback and abundance 

of disposal wells

Mixed

West Gulf Eagle Ford, Pearsall Shale gas/oil X XXX X Mixed

Denver Julesburg Niobrara Shale gas/oil X XXX X Mixed

Piceance; Green 

River

Mesaverde/Lance Tight gas X XX X Also managed through evaporation to 

atmosphere in ponds in this region Qualitative

Williston Bakken Shale oil X XXX Reuse/recycling limited but is being 

evaluated Mixed

Sources: 48 DCN SGE00693

a—CWT facilities identified in these formations are all operator-owned.

b—This column indicates the type of data the EPA based the number of Xs on. In most cases, the EPA used a mixture of qualitative and quantitative data sources 

along with engineering judgment to determine the number of Xs.

XXX—The majority (≥50%) of wastewater is managed with this management practice; XX—A moderate portion (≥10% and <50%) of wastewater is managed with 

this management practice; X—This management practice has been documented in this location, but for a small (<10%) or unknown percent of wastewater. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

82 

Sources: 46 DCN SGE00739

Figure D-3. Management of UOG Drilling Wastewater Generated by UOG Wells in 

Pennsylvania (2008–2013) 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

83 

Sources: Generated by the EPA using data from 43 DCN SGE00596 and 41 DCN SGE00736

Figure D-4. Active Disposal Wells and CWT Facilities Identified in the Appalachian 

Basin68

 

68 The active disposal wells data for New York were last updated in September 2009 for New York and December 

2013 for Pennsylvania. The last update for the active disposal wells data in Ohio and West Virginia is unknown. The 

EPA accessed the Ohio data in February 2013 and the West Virginia data in December 2013. The CWT facility data 

were last updated at the end of 2013, based on publicly available information.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

84 

2 INJECTION INTO DISPOSAL WELLS

Historically, underground injection has been the most common wastewater management 

method among UOG operators. In 2010, the EPA and industry stakeholders estimated that over 

90 percent of oil and gas produced water (conventional and unconventional) was disposed of via 

Class II injection wells (207 DCN SGE00623). Underground injection involves pumping wastes 

into an underground formation with a confining layer of impermeable rock. The formation must 

also be porous enough to accept the wastewater. In its underground injection well control 

program codified in 40 C.F.R. parts 144 to 148, the EPA established six classes of underground 

injection wells (173 DCN SGE00132): 

• Class I industrial and municipal waste disposal wells

• Class II oil and gas related injection wells

• Class III mining wells

• Class IV shallow hazardous and radioactive injection wells (banned) 

• Class V any not covered in Class I through IV (e.g., leach fields) 

• Class VI carbon dioxide storage or sequestration 

Class II injection wells serve three major purposes: 

• Injection of hydrocarbons for storage 

• Injection of fluids for disposal (i.e., disposal wells)

• Injection of fluids for enhanced recovery (i.e., enhanced recovery wells)

Approximately 20 percent of Class II wells in the United States are disposal wells; the 

remaining 80 percent are mostly enhanced recovery wells (173 DCN SGE00132). Injection for 

disposal typically involves injecting wastewater into a porous and non-oil-and-gas-containing 

reservoir. Industry does not use enhanced recovery wells for disposing of UOG extraction 

wastewater because most enhanced recovery projects consist of a closed-loop system with two or 

more wells: at least one producing well and at least one enhanced recovery well. Operators of 

enhanced recovery projects typically route the wastewater generated by the producing well 

directly back to the adjacent enhanced recovery well (206 DCN SGE00623; 173 DCN 

SGE00132; 188 DCN SGE00613). Available literature and communication with industry 

indicates that industry only hauls UOG extraction wastewater to Class II disposal wells and does

not use Class II enhanced recovery wells. In fact, the leading method of UOG extraction 

wastewater management throughout the United States is injection into a Class II disposal well 

(51 DCN SGE00693.A03). However, all types of oil and gas extraction wastewater (e.g., 

conventional, CBM, UOG) may be disposed of in Class II disposal wells. 

2.1 Regulatory Framework for Underground Injection

The EPA’s regulations on underground injection wells are described in Chapter A. States, 

territories, and tribes have the option of requesting primacy, or primary enforcement authority, 

from the EPA for the Class II wells within their boundaries. In order to receive primacy, the state 

underground injection program must meet the EPA’s regulatory requirements to prevent 

underground injection that endangers drinking water sources, or have a program determined to 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

85 

be effective as the federal standards. Currently, the EPA has delegated Class II primacy to 39 

states, three territories and two tribes. The EPA has authority over the Class II UIC programs in 

the remaining 11 states, two territories and all other tribes (184 DCN SGE00611).

2.2 Active Disposal Wells and Volumes

The availability of underground injection for disposal varies by state. Some states have a 

large number of Class II injection wells (e.g., Texas, Oklahoma, Kansas) while others have few 

(e.g., Virginia, South Dakota). The EPA tabulated active Class II disposal wells using data from 

state agencies and EPA direct implementation programs. More information about how the EPA

compiled data from state agencies is documented in a separate memorandum titled Analysis of 

Active Underground Injection for Disposal Wells (41 DCN SGE00736; 42 DCN 

SGE00736.A01). 

Table D-2 presents the number of active Class II disposal wells by state (41 DCN 

SGE00736; 42 DCN SGE00736.A01). It also includes average daily disposal rates for disposal 

wells on a gallon-per-well-per-day basis for each state. Daily disposal rates of individual disposal 

wells vary significantly, reflecting the geology of the underlying formation (176 DCN 

SGE00279). The average disposal rate per well estimates in the table are not exact but rather are 

general approximations based on a number of assumptions which are described in detail in 

ERG’s memorandum Analysis of Active Underground Injection for Disposal Wells (41 DCN

SGE00736). Lastly, Table D-2 presents the total state disposal rate based on the active number of 

disposal wells and average daily disposal rates per well. States are first sorted by geographic 

region, then by the total state disposal rate. States with no disposal rate data are sorted by highest 

to lowest count of active Class II disposal wells.

Table D-2. Distribution of Active Class II Disposal Wells Across the United States

Geographic Region 

(from the EIA) State

Number of Active 

Disposal Wellsa 

Average Disposal 

Rate Per Well

(gpd/well)b 

Total State 

Disposal Rate 

(MGD)

Alaska Alaska 45 182,000 8.2

East

Illinois 1,054 —c —c

Michigan 779g 16,600 13

Ohio 188 8,900 1.7

Indiana 183 3,580 0.66

West Virginia 66 7,180 0.47

Virginia 12 17,500 0.21

Kentucky 58 1,750 0.10

Pennsylvania 9 6,380 0.057

New York 10d 3,530 0.035

Tennessee 0 0 0

Maryland 0 0 0

Minnesota 0 0 0

North Carolina 0 0 0

Gulf Coast/Southwest Texas 7,876 54,200 430
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

86 

Table D-2. Distribution of Active Class II Disposal Wells Across the United States 

Geographic Region 

(from the EIA) State

Number of Active 

Disposal Wellsa 

Average Disposal 

Rate Per Well

(gpd/well)b 

Total State 

Disposal Rate 

(MGD)

Louisiana 2,448 42,100 100

New Mexico 736 48,600 36

Mississippi 499 69,500 35

Alabama 85 44,200 3.8

Mid-Continent

Oklahoma 4,622g 35,900 170

Kansas 5,516 20,900 120

Arkansas 611e 30,900 19

Nebraska 113 18,100 2.0

Missouri 11 1,270 0.014

Northern Great Plains

North Dakota 395 31,600 12

Montana 199 31,100 6.2

South Dakota 21 10,200 0.21

Rocky Mountains

Wyoming 330 —c —c

Colorado 294 50,200 15

Utah 109 74,400 8.1

Arizona 0 0 0

West Coast California 826 77,800 64

All other states (NV, FL, OR, IA, and WA)f 42 89,400 3.8

Total 27,137 40,400 1,040

Sources: 41 DCN SGE00736

a—Number of active disposal wells is based primarily on data from 2012 to 2014.

b—Typical injection volumes per well are based on historical annual volumes for injection for disposal divided by 

the number of active disposal wells during the same year (primarily data 2007 to 2013). These approximations are 

based on a number of assumptions which are detailed in ERG’s Analysis of Active Underground Injection for 

Disposal Wells memorandum (41 DCN SGE00736).

c—Disposal rates and/or number of disposal wells is unknown.

d—These wells are not currently permitted to accept UOG extraction wastewater (source: 186 DCN SGE00726).

e—Only 24 of the 614 active disposal wells in Arkansas are in the northern half of the state, close to the Fayetteville 

formation (6 DCN SGE00499).

f—These are states that have minimal oil and gas activity. The number of wells shown for these states may include 

all types of Class II wells (e.g., Class II enhanced recovery wells) and therefore is an upper estimate (167 DCN 

SGE00138). All other states not listed in this table have minimal oil and gas activity and no active disposal wells.

g—With the exception of Oklahoma and Michigan, wells on tribal lands have not been intentionally included. Wells 

on tribal lands may be counted if state databases contained them. 

Abbreviations: gpd—gallons per day; MGD—million gallons per day

2.3 Underground Injection Considerations

In many UOG formations, distances from the average producing well to the nearest 

disposal well are short and disposal capacity is abundant, making it the least expensive UOG 

extraction wastewater management practice (178 DCN SGE00635). There is no widespread 

discussion in the industry about lack of injection well disposal capacity (188 DCN SGE00613) 

nationally, suggesting that there is enough capacity in place and; therefore, potential for 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

87 

continued acceptance of UOG extraction wastewater. However, as illustrated above, 

underground injection for disposal capacity in close proximity is much less available in certain 

portions of the United States. Another consideration is freshwater availability. In some areas 

with plentiful underground injection for disposal capacity where water scarcity is a problem, 

there is a concern about permanently disposing of UOG produced water underground rather than 

using it to supplement freshwater needs in subsequent hydraulic fracturing jobs (75 DCN 

SGE00760; 142 DCN SGE00583). 

Commercial injection for disposal well operators may surcharge operators to dispose of 

flowback (176 DCN SGE00279). Injection well operators impose the surcharge because 

flowback has a lower density than long-term produced water. Injection of high-density 

wastewater requires less power (i.e., pumping) than injecting less-dense wastewater,69 and the 

injection rate (i.e., barrels per day per well) is inversely proportional to the injection pressure due 

to technical and permit limitations. As a result, disposal well operators must inject lower-density 

flowback at a lower flow rate and more power. 

3 REUSE/RECYCLE IN FRACTURING

As of 2013, many operators evaluate reusing/recycling UOG extraction wastewater

before deciding to manage it via another method (i.e., disposal well or CWT facility) (188 DCN 

SGE00613; 38 DCN SGE00521; 177 DCN SGE00276). Reuse/recycle involves mixing 

flowback and/or long-term produced water from previously fractured wells with other source 

water70 to create the base fluid71 used in a subsequent well fracture (1 DCN SGE00046). 

Operators typically transport the wastewater, by truck or pipe, from storage to the fracturing site 

just before and during hydraulic fracturing. Operators typically store the wastewater in 10,500- 

to 21,000-gallon (200- to 500-barrel) fracturing tanks onsite until they are ready to blend it with 

other source water during the hydraulic fracture. When hydraulic fracturing begins, they pump 

the stored UOG produced water for reuse and other source water to a blender to form the base 

fluid. The blending usually occurs upstream of other steps such as fracturing chemical addition 

or pressurization by the pump trucks (191 DCN SGE00625). 

Since the late 2000s, UOG operators have increased wastewater reuse/recycle (188 DCN 

SGE00613). In the early development of UOG (i.e., the early to mid-2000s), most operators 

believed that reuse/recycle was not technically feasible because high TDS concentrations in 

UOG extraction wastewater adversely affected fracturing chemical additives and/or formation

geology (188 DCN SGE00613). As a result, operators used only fresh water as base fluid for 

fracturing. One of the changes that contributed to more widespread reuse of wastewater as a base 

fluid is that fracturing service providers were able to design fracturing additives to tolerate base 

fluids with higher concentrations of TDS (194 DCN SGE00691; 38 DCN SGE00521; 188 DCN 

SGE00613; 208 DCN SGE00095). 

 

69 The density of flowback is typically close to that of fresh water (8 pounds per gallon), while the density of 

produced water can be greater than 10 pounds per gallon (176 DCN SGE00279).

70 Source water is any fluid that makes up fracturing base fluid. See Section C.1.1. 71 Base fluid is the primary component of fracturing fluid to which proppant and chemicals are added. See Section 

C.1.1. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

88 

To date, slickwater fracturing fluid designs (defined in Section C.1) are the most 

accommodating for using base fluid that contains the high end of the TDS criteria ranges (see 

Table D-4 in section D.3.2 for these ranges) (188 DCN SGE00613; 40 DCN SGE00705; 193

DCN SGE00616). Gel designs (defined in Section C.1), which are typically used to fracture 

liquid rich plays (e.g., Bakken), are more complex and industry currently finds them to be less 

compatible with high concentrations of TDS than slickwater designs (40 DCN SGE00705; 188

DCN SGE00613; 193 DCN SGE00616). As a result, at present, gel designs require base fluid 

that meets the low end of the TDS criteria ranges (see Table D-4 in section D.3.2 for these 

ranges). This is primarily because TDS interferes with the properties of the cross-linked gels 

inherent to gel fracturing fluid designs. Industry also reports that boron is a constituent of 

concern for reuse/recycle when using gel recipes because it interferes with the intended delayed 

activation of cross-linked gels (193 DCN SGE00616; 40 DCN SGE00705). This may be 

changing: industry has recently demonstrated the use of higher-TDS base fluid in gel fracturing 

as new chemical additives are becoming available for gel designs that tolerate higher TDS 

concentrations72 (110 DCN SGE00667; 40 DCN SGE00705).

PESA surveyed 205 UOG operators about their wastewater management practices in 

2012 (136 DCN SGE00575).

73 Table D-3 presents the survey results. Nationally, UOG operators 

reported reusing/recycling 23 percent of total produced water generated. The results also showed 

that most operators anticipate reusing/recycling higher percentages of their produced water in the 

two to three years following the survey. Other research firms that gather data on UOG extraction 

wastewater management report similar findings (34 DCN SGE00708; 122 DCN SGE00709). For 

example, IHS Inc. estimates that in 2013 operators reused/recycled 16 percent of UOG produced 

water nationwide and expects this number to double by 2022 (34 DCN SGE00708). The EPA

participated in several site visits and conference calls with operators in several formations that 

have been able to reuse/recycle 100 percent of their produced water under certain circumstances 

(178 DCN SGE00635; 179 DCN SGE00275; 191 DCN SGE00625; 183 DCN SGE00636). 

Table D-3. Reuse/Recycle Practices in 2012 as a Percentage of Total Produced Water 

Generated as Reported by Respondents to 2012 Survey

Basin UOG Formation

Resource 

Type

Percent of 

Wastewater 

Reused/Recycled 

for Fracturing

Percent of 

Wastewater 

Managed Using 

Other Methodsa 

Percent of 

Respondents 

Planning to Increase 

Reuse/Recycle

Appalachian Marcellus/Utica Shale gas/oil 74 26 50

TX-LA-MS 

Salt

Haynesville Shale gas 30 70 67

Arkoma Fayetteville Shale gas 30 70 67

Western Gulf Eagle Ford Shale gas/oil 16 84 60

Fort Worth Barnett Shale gas 13 87 86

Permian Avalon; BarnettWoodfordShale gas/oil 7 93 67

Williston Bakken Shale oil 5 95 56

 

72 One vendor reported that testing of new additives for gel designs that allow the use of high-TDS base fluid is

underway. This vendor expected the cost for these chemicals to initially be high (40 DCN SGE00705).

73 Out of the 205 respondents, 143 represented operators active in major U.S. UOG plays. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

89 

Table D-3. Reuse/Recycle Practices in 2012 as a Percentage of Total Produced Water 

Generated as Reported by Respondents to 2012 Survey

Basin UOG Formation

Resource 

Type

Percent of 

Wastewater 

Reused/Recycled 

for Fracturing

Percent of 

Wastewater 

Managed Using 

Other Methodsa 

Percent of 

Respondents 

Planning to Increase 

Reuse/Recycle

Gulf Coast (Austin Chalk, Cotton 

Valley, Vicksburg)b 

Unknown 10 90 100

Mid-Continent (Woodford, Cana, 

Caney, Granite Wash)b 

Unknown 25 75 68

Rockies (Niobrara, Mancos)b Unknown 14 86 100

Weighted average 23 77 55

Source: 136 DCN SGE00575

a—PESA (136 DCN SGE00575) reported this as “disposal” but did not clearly describe what it means.

b—PESA (136 DCN SGE00575) did not specify basin or formation for these areas. The EPA provided formation 

names that are present in these areas if not already previously listed above. 

3.1 Reuse/Recycle Strategies

Operators can reuse/recycle UOG extraction wastewater for fracturing through different 

strategies. An operator’s choice of strategy depends on many factors, which Section D.3.2

describes in detail. The following subsections discuss direct reuse/recycle without treatment and 

reuse/recycle after treatment. 

3.1.1 Direct Reuse/Recycle for Fracturing Without Treatment

Many operators reuse/recycle their wastewater for fracturing without any treatment (i.e., 

only blending with fresh water) or with minimal treatment such as sedimentation or filtration to 

remove suspended solids. The primary purpose of the blending is to control TDS concentrations 

(193 DCN SGE00616; 194 DCN SGE00691). When using this strategy, operators either 

transport UOG extraction wastewater directly to the next well they are fracturing or transport it 

to a temporary storage area offsite until they are ready to fracture the next well. 

Reuse/recycle without treatment accounts for a large portion of all wastewater that 

industry reuses/recycles. In PESA’s 2012 survey (136 DCN SGE00575), UOG operators 

reported that 54 percent of produced water reused/recycled by the UOG industry in 2012 for 

fracturing requires minimal or no treatment. In addition, the EPA conducted several site visits 

and conference calls with operators that have increasingly reused/recycled wastewater with no 

treatment (178 DCN SGE00635; 179 DCN SGE00275; 191 DCN SGE00625; 183 DCN 

SGE00636; 177 DCN SGE00276). 

3.1.2 Reuse/Recycle in Fracturing After Treatment

Operators also reuse/recycle UOG extraction wastewater after some type of treatment. 

Where treatment is employed, the UOG industry typically uses one of two levels of treatment: 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

90 

• Non-TDS removal technologies—technologies that remove non-dissolved74

constituents from wastewater, including suspended solids, oil and grease, bacteria, 

and/or certain ions that can cause scale to form on equipment and interfere with

fracturing chemical additives. These technologies are not designed to reduce the 

levels of dissolved constituents, which are the majority of compounds that contribute 

to TDS in UOG extraction wastewater.

• TDS removal technologies—technologies capable of removing dissolved 

constituents that contribute to TDS (e.g., sodium, chloride, calcium) as well as the 

constituents removed by non-TDS removal technologies. Treatment systems with 

these treatment technologies include non-TDS removal technologies for pretreatment 

(e.g., TSS, oil and grease). 

Each of these levels of treatment is described in more detail below. Also see the EPA’s 

report titled Unconventional Oil and Gas (UOG) Extraction Wastewater Treatment Technologies

(203 DCN SGE00692), which discusses treatment technologies used to treat UOG produced 

water. 

Non-TDS Removal Technologies 

As discussed in Section D.3, there are constituents in UOG extraction wastewater other 

than TDS that operators may need to remove or destabilize before reuse/recycle. In particular, 

they may need to reduce constituents that may cause scale, formation damage, and/or 

interference between chemical additives and the formation geology (203 DCN SGE00692). 

These constituents include suspended solids, oil and grease, bacteria, and certain ions (e.g., iron, 

calcium, magnesium, and barium). Non-TDS removal technologies used to treat UOG extraction 

wastewater for reuse/recycle include (188 DCN SGE00613; 208 DCN SGE00095): 

• Solids removal (e.g., sedimentation, filtration, dissolved air flotation) 

• Chemical precipitation

• Electrocoagulation

• Advanced oxidation precipitation 

Industry often uses non-TDS removal technologies to remove or destabilize the 

aforementioned constituents. This treatment may be done in the field at the well site or off-site at 

a CWT facility. One method used in the field to treat UOG extraction wastewater is referred to as

“on the fly” treatment, where the wastewater is treated as fluids are mixed for hydraulic 

fracturing. 

Figure D-5 shows a simplified flow diagram of on-the-fly treatment of UOG produced 

water for reuse/recycle. In this practice, the operator treats the mixture of UOG produced water

and other source water concurrently with the hydraulic fracturing process. Therefore, wastewater 

 

74 EPA has categorized treatment technologies into two categories in this document: those that are designed to 

remove dissolved constituents and those that are not designed to remove dissolved constituents. However, it should 

be noted that some of the technologies in the non-TDS removal category do in fact remove some dissolved 

constituents. For example, chemical precipitation will remove certain metals. However, these technologies typically 

will not remove salts and hardness, which are the primary components of TDS in UOG extraction wastewater.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

91 

treatment occurs at relatively high flow rates equivalent to the rate of hydraulic fracturing.75

Other than the treatment unit, there is no additional equipment required in this setup that is not 

already required for hydraulic fracturing (e.g., additional storage typically required for treated 

wastewater). This eliminates or reduces the following (30 DCN SGE00331):76

• Transporting wastewater for reuse/recycle to a CWT facility and then transporting it 

again to the next well for fracturing

• Procuring the services of a CWT facility

• Purchasing or renting storage containers, and renting space on which to keep the 

storage containers, for treated wastewater

Fracturing 

fluid

Proppant and 

chemicals

Blender

UOG produced 

water treatment 

system

Base 

fluid

Nearby 

impoundment or 

pond

Well

Other source 

water

Pump 

trucks

Treated 

base 

fluid

Fracturing tanks with 

untreated wastewater

Well pad

Blender

Source: Generated by EPA using 30 SGE00331.

Figure D-5. Flow Diagram of On-the-Fly UOG Produced Water Treatment for 

Reuse/Recycle

TDS Removal Technologies 

In general, TDS removal technologies convert influent wastewater into two streams: 

concentrated brine and low-TDS water (i.e., distillate). As discussed in the introduction to 

 

75 Operators typically hydraulically fracture wells at rates of 2,520 to 5,040 gallons (60 to 120 barrels) per minute. 

On-the-fly treatment technologies must be capable of treating wastewater at the same rate (203 DCN SGE00692). 

76 The most common technology for on-the-fly treatment is advanced oxidation. This technology eliminates the need 

to add biocide to the fracturing fluid to prevent bacteria growth.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

92 

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 (188 DCN SGE00613; 208 DCN 

SGE00095) reverse osmosis (when TDS is less than approximately 50,000 mg/L) and 

evaporation/condensation and crystallization (203 DCN SGE00692). Some vendors currently 

offer skid-mounted mobile TDS removal units for reuse/recycle in the field (203 DCN 

SGE00692). The EPA also identified several CWT facilities owned by operators that use TDS 

removal technologies (e.g., evaporation/condensation) (84 DCN SGE00284). 

3.2 Reuse/Recycle Drivers

The reuse/recycle strategy operators choose depends on many different factors. The 

following subsections describe the two biggest drivers (148 DCN SGE00710): 

• Pollutant concentrations in UOG extraction wastewater compared to maximum 

acceptable pollutant concentrations for base fluid (described in more detail in Section 

D.3.2.1) 

• Volume of UOG extraction wastewater available for reuse/recycle compared to total 

volume of base fluid required for fracturing a new well (described in more detail in 

Section D.3.2.2) 

These factors vary by formation and operator; therefore, the potential for 

reusing/recycling UOG extraction wastewater for fracturing also varies by formation and 

operator. These two drivers ultimately affect the level of treatment required, if any, and the total 

cost for reuse/recycle. Operators always consider the total cost per barrel for reuse/recycle as 

compared to other management alternatives.

3.2.1 Pollutant Concentrations in Available UOG Extraction Wastewater for Reuse/Recycle 

Operators typically consider TDS when they evaluate whether they can reuse/recycle 

their wastewater and, if so, what level of treatment is required prior to reuse/recycle (148 DCN 

SGE00710). Operators are more likely to reuse/recycle UOG extraction wastewater with low 

TDS and high volumes to avoid TDS treatment and/or minimize freshwater usage. As explained

in Section C.3.2.1 and shown in Figure C-6, TDS concentrations increase over time as the flow 

rate decreases after fracturing (148 DCN SGE00710, 85 DCN SGE00414, 27 DCN SGE00357, 

151 DCN SGE00350, 191 DCN SGE00625). Therefore, operators are more likely to 

reuse/recycle flowback than long-term produced water because concentrations of TDS in 

flowback, on average, are lower than concentrations in long-term produced water (see Section 

C.3.2.1) (148 DCN SGE00710). 

Some operators are able to reuse/recycle long-term produced water with no or minimal 

TDS treatment, as observed by the EPA in the Marcellus and Fayetteville shale formations (183

DCN SGE00636; 178 DCN SGE00635; 191 DCN SGE00625). However, this may not be 

possible in all UOG formations. As shown in Chapter C, the maximum concentration of TDS 

and the rate at which that concentration is reached are functions of the underlying geology. This 

means that, in some basins, the TDS concentrations for long-term produced water may be lower 

than the TDS concentrations for flowback in other basins. For example, in the Bakken formation, 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

93 

TDS concentrations in flowback increase rapidly to levels as high as 200,000 mg/L (within five 

days after fracturing), which may limit the volume of this wastewater capable of being used for 

reuse/recycle (151 DCN SGE00350).77 On the other hand, the Fayetteville shale formation

generates a maximum of 40,000 mg/L TDS in long-term produced water (191 DCN 

SGE00625).78 

If operators reuse/recycle UOG extraction wastewater that contains too much of certain 

constituents, the fracturing fluid, well, and/or formation may undergo one or more of the 

following problems (3 DCN SGE00070): 

• Fluid instability (change in fluid properties) 

• Well plugging (restriction of flow)

• Well bacteria growth (buildup of bacteria on casing)

• Well scaling (accumulation of precipitated solids) 

• Formation damage (restriction of flow in the reservoir) 

Table D-4 shows ranges of observed or recommended constituent concentration criteria 

for the fracturing base fluid and the associated effect that the fluid or well may experience with 

concentrations in excess of the criteria. These ranges represent general values that industry 

reports, not values specific to one UOG formation. The exact criteria an operator uses depend on 

operator preference, geology, and the fracturing fluid chemistry (e.g., slickwater, gel), but the 

selected criteria typically fall within the ranges shown in Table D-4. 

 

77 This report determined that only the initial five percent of the injected fracturing fluid volume that returns to the 

surface contains TDS less than 60,000 mg/L in the Bakken, based on sampling data for 62 wells. 78 This operator reported that they are able to reuse all of their UOG wastewater due to low TDS concentrations.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

94 

Table D-4. Reported Reuse/Recycle Criteria

Constituent

Reasons for Limiting 

Concentrations

Recommended or Observed Base Fluid Target 

Concentrations (mg/L,a After Blending)

TDS Fluid stability 500–70,000

Chloride Fluid stability 2,000–90,000

Sodium Fluid stability 2,000–5,000

Metals

Iron Scaling 1–15

Strontium Scaling 1

Barium Scaling 2–38

Silica Scaling 20

Calcium Scaling 50–4,200

Magnesium Scaling 10–1,000

Sulfate Scaling 124–1,000

Potassium Scaling 100–500

Scale formersb Scaling 2,500–2,500

Phosphate Not reported 10

Other

TSS Plugging 50–1,500

Oil Fluid stability 5–25

Boron Fluid stability 0–10

pH (SU) Fluid stability 6.5–8.1

Bacteria (counts/mL) Bacterial growth 0–10,000

Sources: 48 DCN SGE00693

a—Unless otherwise noted.

b—Includes total of barium, calcium, manganese, and strontium.

Abbreviations: mg/L—milligrams per liter; SU—standard units; mL—milliliter

3.2.2 Base Fluid Demand for Fracturing

The amount of wastewater used in fracturing fluid make up depends not just on 

wastewater pollutants and concentrations but also on wastewater quantity compared to the 

amount of water required for the base fluid. 

Water Demand at the Well Level

The volume of fracturing fluid required per well for fracturing may also influence the 

level of treatment or blending ratio necessary to meet the base fluid pollutant criteria in Table 

D-4. The blending ratio is the volume of reused/recycled wastewater as a percent of the total 

base fluid volume used to fracture a specific well. The blending ratio depends on the wastewater 

pollutants and concentrations as well as on the volume of UOG extraction wastewater available 

and the total volume of base fluid required. Operators must consider how much wastewater is 

generated by nearby wells with respect to how much fracturing fluid is required to fracture a 

subsequent well. In areas where produced water volume generation is high and/or the required

total base fluid volume for fracturing is low, operators may use a high blending ratio. As 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

95 

explained above, this high ratio may require more treatment depending on TDS and other 

constituent concentrations. On the other hand, in formations where produced water volume

generation is low and total base fluid fracturing volume is high, operators may use a low 

blending ratio. A low blending ratio can typically be used with little to no treatment (179 DCN 

SGE00275; 178 DCN SGE00635; 188 DCN SGE00613). Table D-5 shows observed blending 

ratios for various formations. This table also includes theoretical upper end blending ratios as 

presented in literature which are based on the typical fracturing fluid volume and produced water 

volume generated per well79 for each formation (215 DCN SGE00627; 126 DCN SGE00639; 

and 194 DCN SGE00691). 

Table D-5. Reported Reuse/Recycle Practices as a Percentage of Total Fracturing Volume

Basin Formation

Resource 

Type

Observed Blending 

Ratioa (%)

Estimated Maximum Potential 

Blending Ratiob (%)

Anadarko

Cleveland Tight — 10–40

Granite Wash Tight — 10–40

Mississippi Lime Tight — 50

Appalachian

Marcellus Shale 10–12 10–40

Utica Shale — 10–40 

Arkoma Fayetteville Shale 6–30 —

Denver J. Niobrara Shale — 10–40 

Fort Worth Barnett Shale 4–6 10–40 

Permian —c Shale/tight 2–40 50 

TX-LA-MS Salt Haynesville Shale 5 5–10 

Tuscaloosa Marine Shale 25 —

Western Gulf Eagle Ford Shale — 10–40 

Sources: 48 DCN SGE00693

Note: Data years represented range from 2009 to 2013.

a— Actual observed volumes of reused/recycled UOG extraction wastewater as a percentage of fracturing fluid 

volume.

b— Estimated maximum blending ratio based on typical flowback volume per well compared to typical fracturing 

volume per well as presented in 215 DCN SGE00627; 126 DCN SGE00639; and 194 DCN SGE00691. 

c— References do not specify a specific formation.

“—” indicates no data.

Water Demand at the Formation Level 

Although reuse/recycle has become popular as a way to manage UOG extraction 

wastewater, it is anticipated to become less attractive as a formation matures and the operator 

drills and fractures fewer wells (148 DCN SGE00710). As a formation matures, the volume of 

base fluid needed to fracture new wells may be less than the volume of produced water generated 

by producing wells in the area (191 DCN SGE00625). Figure D-6 illustrates this concept80 with

a hypothetical situation for an operator in a single formation as reported by an operator (20 DCN 

SGE00305.A03). During early years of development, the base fluid demand for fracturing wells 

 

79 This theoretical value reported in literature is irrespective of constituent concentrations.

80 This concept assumes that operators do not typically share wastewater for reuse in fracturing. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

96 

always exceeds the volume of produced water generated. This provides favorable conditions for 

reuse/recycle. As drilling decreases, the volume of base fluid needed decreases below the volume 

of produced wastewater generated. Consequently, the operator must find an alternative for at 

least some portion of the produced water (e.g., disposal well). 

Source: 48 DCN SGE00693 (Generated by the EPA based on figure in 20 DCN SGE00305.A03) 

Figure D-6. Hypothetical UOG Produced Water Generation and Base Fracturing Fluid 

Demand over Time

3.3 Other Considerations for Reuse/Recycle

In addition to the level of treatment required for reuse/recycle, operators consider the 

following as they decide whether to reuse/recycle their wastewater:

• Wastewater transportation

• Wastewater storage

• Source water availability and cost 

3.3.1 Transportation 

Transportation requirements affect the wastewater reuse/recycle potential in a specific 

area. While not explicitly stated above, the location of the producing well(s) relative to the 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

97 

location of disposal well(s), CWT facilities, and/or a subsequent well(s) to be drilled is also a 

consideration. Operators must determine and compare the cost (dollars per barrel) to transport 

the wastewater for all management scenarios.

Further, when an UOG well generating wastewater is far from alternative management 

approaches such as a disposal well or CWT facility, reuse/recycle may also be more economical. 

The distance between disposal wells and CWT facilities from the UOG well generating the 

wastewater can vary by formation and even within formations. For example, Figure D-7 shows 

how operators in the northeast region of the Marcellus reused/recycled a higher percentage of 

wastewater compared to the southwestern region between 2008 and 2011 (139 DCN SGE00579). 

This is due to the fact that Marcellus wells in the southwestern part of Pennsylvania are closer to 

disposal wells in Ohio, whereas Marcellus wells in the northeast portion of Pennsylvania are 

more than 200 miles from disposal wells in Ohio. As a result, it is typically less expensive per 

barrel to reuse/recycle the wastewater in the northeast than to transport it to a disposal well in 

Ohio because transportation alone can cost as much as $13 per barrel (180 DCN SGE00300). 

Source: Graphic reprinted with permission from Brian Rahm (139 DCN SGE00579) 

Note: “a” and “b” for 2010 and 2011 represent the first and second half of the year, respectively.

Figure D-7. 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 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

98 

stored before reuse in a subsequent well81 (179 DCN SGE00275). For example, an operator who 

is considering reusing extraction wastewater for fracturing that fractures 12 wells per year in an 

area will need to store wastewater for approximately one month before the next fracturing job. In 

comparison, an operator who fractures 50 wells per year in an area may only need to store 

wastewater for a week before they can reuse/recycle it in the next fracturing job (39 DCN 

SGE00283). Section B.2.1 explains UOG extraction wastewater storage options in more detail. 

3.3.3 Source Water Availability

Operators that successfully reuse/recycle their wastewater can reduce the total volume of 

other types of source water they need to use for base fluids, creating an offset in costs associated 

with source water (208 DCN SGE00095). Fresh water from rivers and streams is relatively 

abundant and inexpensive in some areas, but in others it can be a stressed resource. Seasonal 

droughts can cause a high demand for resources and operators can experience inflated 

acquisition costs. Reuse/recycle is more likely to be driven by these reasons for operators in arid 

or drought-prone regions than for operators in regions where freshwater and groundwater 

resources are abundant and inexpensive (142 DCN SGE00583; 148 DCN SGE00710). This is 

because as the cost of fresh water and groundwater increases, the offset in costs from 

reusing/recycling wastewater to replace other source water also increases.

82 Examples of such 

areas include California, the Denver Julesburg and Permian basins, and the Eagle Ford shale 

formation (148 DCN SGE00710). In addition, as mentioned above, a lack of disposal wells in 

some areas may be another driver behind wastewater reuse/recycle activity in some areas (e.g., 

Marcellus shale).

4 TRANSFER TO CWT FACILITIES

Some operators manage UOG extraction wastewater by transporting it to CWT facilities. 

Treated UOG extraction wastewater at CWT facilities is either discharged83 or returned to the 

operator for reuse/recycle in fracturing. Operators may choose to use CWT facilities primarily 

when other wastewater management options (e.g., disposal wells) are not available where they 

are operating (148 DCN SGE00710; 138 DCN SGE00139; 25 DCN SGE00182). 

This section provides a general overview of the types of CWT facilities that exist and that 

UOG operators may use for wastewater management, typical CWT facility treatment processes, 

CWT facilities that EPA is aware of that have in the past or currently accept UOG extraction 

wastewater, and considerations for using CWT facilities to manage UOG extraction wastewater. 

4.1 Types of CWT Facilities

A CWT facility is any facility that treats (for disposal, recycling, or recovery of material) 

any hazardous or nonhazardous industrial wastes, hazardous or non-hazardous industrial 

wastewater, and/or used material received from offsite (40 C.F.R 437.2(c)). CWT facilities that 

accept UOG extraction wastewater are sometimes run by the UOG operator and are sometimes 

 

81 This is primarily because many operators rent fracturing tanks on a per-tank-per-day basis. Even if operators 

purchase fracturing tanks instead, the effective cost to the operator still increases as storage time increases.

82 Transportation distances may also affects costs.

83 Discharge includes both indirect discharge (to a POTW) and direct discharge (to surface water).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

99 

run by an entity not engaged in the oil and gas extraction business. Since UOG development 

ramped up in the late 2000s, new CWT facilities that accept extraction wastewater from 

operators have become available (43 DCN SGE00596), mostly in areas with less underground 

injection capacity. In addition, many UOG operators have vertically integrated their companies 

by purchasing or constructing their own CWT facilities (see Section D.2.2) (43 DCN 

SGE00596). Some CWT facilities accept only oil and gas wastewater while others accept a 

variety of industrial wastewater. They follow different discharge practices: 

• Zero discharge (treated wastewater is typically reused in fracturing or disposed of in 

an Class II disposal well) 

• Discharge (to surface waters or POTWs)

• Multiple discharge options (a mix of discharge and zero discharge) 

Pollutant discharges to surface waters or to POTWs from CWT facilities are not subject 

to the Oil and Gas Extraction ELGs (40 C.F.R. part 435). Rather, they are subject to the 

Centralized Waste Treatment ELGs promulgated in 40 C.F.R. part 437. Unlike the Oil and Gas 

Extraction ELGs, 40 C.F.R. part 437 includes limitations and standards for both direct and 

indirect dischargers. 

The level of treatment CWT facilities use depends on the fate of the treated wastewater. 

The two primary types of treatment technologies are non-TDS removal technologies84 and TDS 

removal technologies85, defined in Section D.3. In general, CWT facilities typically use nonTDS removal technologies for treatment before reuse/recycle and TDS removal technologies for 

treatment before indirect or direct discharge. 

4.1.1 Zero Discharge CWT Facilities

After treatment, a zero discharge CWT facility does not discharge the wastewater to 

surface water or a POTW. Instead, it typically returns the wastewater to UOG operators for 

reuse/recycle in fracturing.86 CWT facilities that accept UOG extraction wastewater from 

operators and fall into this category typically allow them to unload a truckload of wastewater for 

treatment and take a load of treated wastewater on a cost-per-barrel basis (37 DCN SGE00245). 

Others may allow an operator to unload a truckload of wastewater for a surcharge without taking 

a load of treated wastewater, as long as other operators need additional treated wastewater. Most 

of these CWT facilities provide minimal (i.e., non-TDS removal) treatment, but some also use 

TDS-removal technologies. 

4.1.2 Discharging CWT Facilities 

Some CWT facilities discharge treated wastewater either indirectly to a POTW or 

directly to surface waters. As discussed in Section A.2.1.1, discharges from the CWT facility to 

 

84 Examples of CWT facilities using this level of treatment are described in 191 DCN SGE00625; 178 DCN 

SGE00635, 37 DCN SGE00245, 116 DCN SGE00481, and 89 DCN SGE00379.

85 Examples of CWT facilities using this level of treatment are described in 93 DCN SGE00476, 23 DCN 

SGE00366, 19 DCN SGE00367, and 140 DCN SGE00374.

86 Zero discharge CWT facilities may also evaporate the wastewater or send it to underground injection wells (205

DCN SGE00374). 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

100 

the POTW are controlled by an Industrial User Agreement that must incorporate the pretreatment 

standards set out in 40 C.F.R. part 437 and requirements set out in 40 C.F.R. part 403. Surface 

water discharges from CWT facilities are controlled by NDPES permits that include pollutant 

discharge limitations based on water-quality-based limitations and the technology-based 

limitations set out in 40 C.F.R. part 437. The level of treatment typically depends on the 

requirements in the NPDES permit, which may or may not include restrictions on TDS. Directdischarging CWT facilities use a mixture of TDS and non-TDS removal technologies. However, 

new state regulations in Pennsylvania, for example, have led direct-discharging CWT facilities to 

use more TDS removal technologies (43 DCN SGE00596). 

4.1.3 CWT Facilities with Multiple Discharge Options

Some discharging83 CWT facilities may also recycle a portion of the treated wastewater. 

Consequently, these types of CWT facilities may employ both non-TDS and TDS removal 

technologies. One such facility is Eureka Resources in Williamsport, Pennsylvania. The Eureka 

CWT facility holds a General Permit (WMGR123NC005)87 from PA DEP that includes limits88

for TDS (500 mg/L), chloride (25 mg/L), and radium-226 + radium-228 (5 pCi/L), among 

others. The Eureka CWT facility uses a non-TDS removal technology (chemical treatment) 

followed by a TDS removal technology (evaporation/condensation) (180 DCN SGE00300). 

Operators may take a load of treated wastewater for reuse/recycle that the facility treated using 

the non-TDS removal technology train or using the entire treatment train (both non-TDS and 

TDS removal technologies). There are no permit limits that must to be met for wastewater that is 

treated for reuse. The level of treatment is based on the operators’ specifications.

4.2 Active CWT Facilities Accepting UOG Extraction Wastewater

To date, the EPA has identified 73 CWT facilities that have accepted or plan to accept 

UOG extraction wastewater. Most of them accept only oil and gas wastewater, not wastewater 

from other industries. Table D-6 shows the total number of CWT facilities, by state, that have 

accepted or plan to accept UOG extraction wastewater. The table includes a breakdown by 

treatment level and facility discharge type (described in Section D.4.1). The majority of these 

facilities can treat between 87,000 and 1,200,000 gallons (2,100 and 29,000 barrels) per day (43

DCN SGE00596).89 

To generate Table D-6, the EPA used information from state agencies (e.g., PA DEP 

statewide waste reports), CWT facility websites, and news articles. The collected information is 

documented in a separate memorandum titled Analysis of Centralized Waste Treatment (CWT) 

Facilities Accepting UOG Extraction Wastewater (43 DCN SGE00596), which lists known 

CWT facilities along with information such as permit number, location, treatment capacity, and 

treatment level when available. Because few states keep comprehensive lists of CWT facilities, 

 

87 More information available online at: 

http://files.dep.state.pa.us/Waste/Bureau%20of%20Waste%20Management/WasteMgtPortalFiles/SolidWaste/Resid

ual_Waste/GP/WMGR123.pdf. 88 In addition to setting discharge limitations to the nearby POTW, Eureka’s General Permit allows it to treat 

wastewater for reuse purposes only, in which case there are no actual limits.

89 To exclude outliers, the EPA presents the 10th and 90th percentiles of reported treatment capacities at CWT 

facilities. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

101 

Table D-6 likely underestimates the number of CWT facilities accepting UOG extraction 

wastewater.

90

Table D-6. Number, by State, of CWT Facilities That Have Accepted or Plan to Accept 

UOG Extraction Wastewater 

State

UOG Formation(s)

Served

Zero Discharge CWT 

Facilitiesa 

CWT Facilities That 

Discharge to a Surface 

Water or POTWa 

CWT Facilities with 

Multiple Discharge 

Optionsa

Total 

Known 

Facilities

Non-TDS 

Removal 

TDS 

Removal

Non-TDS 

Removal

TDS 

Removal

Non-TDS 

Removal 

TDS 

Removal 

AR Fayetteville 2 0 0 0 0 1 3

CO Niobrara, Piceance 

Basin 3(1) 0 0 0 0 0 3 

ND Bakken 0 1 (1) 0 0 0 0 1

OH Utica, Marcellus 10 (7) 0 1 0 0 0 11

OK Woodford 2 0 0 0 0 0 2

PA Utica, Marcellus 23 7(3) 6 0 0 3 (1) 39

TX Eagle Ford, Barnett, 

Granite Wash 1 3 0 0 0 0 4 

WV Marcellus, Utica 4 (2) 0 0 0 1 1 6

WY Mesaverde and Lance 0 2 0 0 0 2 4

Total 45 13 7 0 1 7 73

Sources: 43 DCN SGE00596

a—Number of facilities includes facilities that have not yet opened but are under construction, pending permit 

approval, or are in the planning stages. Facilities that are not accepting UOG extraction wastewater but plan to in the 

future are noted parenthetically.

This information shows that CWT facilities have developed in regions of increasing oil 

and gas production, especially in areas where capacities for other management practices are less 

available (138 DCN SGE00139). To illustrate this, the EPA analyzed the number of active CWT

facilities available to Marcellus shale and Utica shale operators where there are few disposal 

wells in some parts of the region.

91 Figure D-4 illustrates how the eastern half of the 

Appalachian basin contains many CWT facilities and few disposal wells and the western half 

contains many disposal wells and few CWT facilities. Figure D-8 shows the trend over time of 

active CWT facilities available to operators in the Marcellus and Utica shales,92 along with the 

number of UOG wells drilled. The number of CWT facilities available to operators in the 

Marcellus and Utica shales has increased with the number of wells drilled. The EPA observed a 

similar trend in the Fayetteville shale formation in Arkansas. Although Arkansas has several 

hundred active disposal wells, only 24 wells are located in the northern half of the state in close 

proximity to Fayetteville shale wells (41 DCN SGE00736). As a result, the largest active 

operator in the Fayetteville shale has constructed three CWT facilities. The EPA anticipates that 

 

90The information in Table D-6 is current as of 2013; it is possible that since 2013 some listed CWT facilities have 

closed and/or some CWT facilities not listed have begun operation. 91 This analysis included Pennsylvania, West Virginia, and Ohio.

92 The Marcellus and Utica shale formations are in the Appalachian basin.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

102 

more CWT facilities will become available near UOG formations where access to disposal wells 

is limited as additional UOG wells are drilled.

Sources: 43 DCN SGE00596

Figure D-8. Number of Known Active CWT Facilities over Time in the Marcellus and 

Utica Shale Formations 

5 DISCHARGE TO POTWS

In locations where disposal wells and CWT facilities are limited or transportation 

distances are a factor, operators have, in the past, managed UOG extraction wastewater by 

discharge to POTWs. This practice can be problematic because POTWs do not use technologies 

that can remove some UOG extraction wastewater constituents (e.g., TDS). Also, constituents in 

UOG extraction wastewater such as TDS may interfere with POTW operations and may increase 

pollutant loads in receiving streams to the detriment of downstream water use (80 DCN 

SGE00286; 109 DCN SGE00345; 139 DCN SGE00579; 82 DCN SGE00531; 226 DCN 

SGE00633; 77 DCN SGE01077).93 

 

93 GWPC, 2014 (77 DCN SGE01077) states, “For a POTW to accept a waste stream for treatment, the facility must 

show that the accepted waste will not interfere with the treatment process or pass through the facility untreated. 

Since POTWs are typically not designed to treat fluids with constituents found in produced water (e.g., high TDS 

concentrations, hydrocarbons, etc.), problems have occurred as a result of produced water being sent to POTWs 

including impacts to the treatment process or the discharge of constituents at levels detrimental to the receiving 

water body.”
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

103 

This section provides an overview of typical treatment processes used at POTWs, a 

discussion of how constituents commonly found in UOG extraction wastewater interact with 

POTWs (including examples of POTWs that have been used to manage UOG extraction 

wastewater), a review of POTWs that have accepted UOG extraction wastewater, and the current 

status of UOG extraction wastewater discharges to POTWs. 

5.1 POTW Background and Treatment Levels

40 C.F.R. part 403.3(q) defines a POTW as “a treatment works as defined by section 212 

of the [Clean Water] Act,

94 which is owned by a State or municipality.” POTWs are designed to 

treat residential, commercial, and industrial wastewater, focusing on the removal of suspended 

solids and dissolved organic constituents. Table D-7 presents concentrations of weak, moderate, 

and strong domestic wastewater as would be typically experienced by a POTW (i.e., influent). 

Table D-7. Typical Composition of Untreated Domestic Wastewater

Constituent

Concentrations (mg/L)

Weak Moderate Strong

TDS 270 500 860

COD 250 430 800

TSS 120 210 400

BOD5 110 190 350

TOC 80 140 260

Oil and grease 50 90 100

Chlorides 30 50 90

Nitrogen, total 20 40 70

Sulfate 20 30 50

Phosphorus, total 4 7 12

Nitrates 0 0 0

Nitrites 0 0 0

Source: 119 DCN SGE00167

Abbreviation: mg/L—milligrams per liter

Typical treatment processes used at POTWs are categorized into the following levels: 

• Primary treatment, capable of removing some suspended solids and organic matter 

from influent wastewater using unit operations such as screening and clarification. 

• Secondary treatment, capable of removing additional suspended solids and 

biodegradable organic matter from influent wastewater using biological treatment 

processes, such as activated sludge and trickling filters. Secondary treatment is 

sometimes followed by chlorination or ultraviolet (UV) disinfection to reduce 

microbial pathogens. 

 

94 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.” 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

104 

• Tertiary (advanced) treatment, capable of removing other pollutants, such as 

nutrients, not removed in secondary treatment using processes such as 

nitrification/denitrification and activated carbon adsorption (119 DCN SGE00167). 

Figure D-9 shows a typical process flow diagram for a POTW. The processes shown 

include primary treatment (screen, grit chamber, primary clarifier), secondary treatment 

(trickling filter, aeration, secondary clarifier), and disinfection (chlorine). The diagram also 

shows sludge treatment (gravity thickening, digestion, filter press) before use/disposal (e.g., land 

application). 

Source: 165 DCN SGE00602

Figure D-9. Typical Process Flow Diagram at a POTW 

In general, the average POTW in the United States has primary and secondary treatment. 

In addition to treated wastewater, POTW treatment processes produce residual solids (sludge), 

including biosolids generated during biological treatment and other suspended material removed 

in clarifiers. Most POTWs apply additional treatment to the sludge, typically gravity thickening 

followed by stabilization (e.g., anaerobic digestion) and dewatering (e.g., filter press). After this 

additional treatment, most sludge is either put to a beneficial use (e.g., land application, soil 

enrichment) or disposed of in a landfill or incinerator (161 DCN SGE00599). 

Table D-8 shows typical removal percentages for various constituents. As discussed, 

removal rates for suspended solids are high (90 percent for TSS) and removal rates for metals 

and salts are low (6 percent for cobalt, 8 percent for TDS).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

105 

Table D-8. Typical Percent Removal Capabilities from POTWs with Secondary Treatment

Constituent

POTW Percent 

Removal (%) Constituent

POTW Percent 

Removal (%)

Aluminum 91 Mercury 72

Ammonia as nitrogen 39 Molybdenum 19

Antimony 67 Naphthalene 95

Arsenic 66 Nickel 51

Barium 16 Oil and grease (as HEM) 86

Beryllium 72 Phenol 95

BOD5 89 Phenolics, total recoverable 57

Boron 30 Phosphorus, total 57

Cadmium 90 Pyridine 95

Calcium 9 Selenium 34

Carbon disulfide 84 Silver 88

Chloride 57 Sodium 3

Chlorobenzene 96 Sulfate 85

Chloroform 73 Sulfide 57

Chromium 80 TDS 8

Cobalt 6 Thallium 72

COD 81 Tin 42

Copper 84 Titanium 92

Cyanide 70 TOC 70

Ethylbenzene 94 Toluene 96

Fluoride 61 Total petroleum hydrocarbons 57

Iron 82 TSS 90

Lead 77 Vanadium 10

Magnesium 14 Xylenes (m+p, m, o+p, o) 65 to 95

Manganese 36 Zinc 79

Source: 164 DCN SGE00600

Note: 164 DCN SGE00600 references data from the November 5, 1999, updated 50-POTW study and the RREL 

database compiled for the CWT effluent guidelines.

Table D-9 shows the breakdown of U.S. POTWs categorized according to their level of 

treatment. As of 2008, secondary treatment was the most common level of treatment at POTWs.

Table D-9. U.S. POTWs by Treatment Level in 2008

Treatment Level

Percent of 

Facilities (%)

Number of 

Facilities

Design Capacity 

(MGD)

Less than secondary (e.g., primary) 0.2 30 546

Secondary 49.4 7,302 17,765

Greater than secondary (e.g., tertiary, advanced) 34.3 5,071 23,710

No discharge 15.2 2,251 2,557

Partial treatmenta 0.8 115 287

Total 99.9 14,769 44,866

Source: 166 DCN SGE00603
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

106 

a—These facilities provide some treatment to wastewater and discharge their effluent to other wastewater facilities 

for further treatment and discharge. 

Abbreviation: MGD—million gallons per day

5.2 History of POTW Acceptance of UOG Extraction Wastewater

As operators began extracting oil and gas from unconventional formations, UOG 

operators discharged wastewater to POTWs in some cases (80 DCN SGE00286; 109 DCN 

SGE00345; 139 DCN SGE00579).95 The EPA located the most comprehensive data about this 

practice in Pennsylvania. Therefore, this subsection primarily discusses data from PA DEP, 

though it also includes discussions about a few POTWs in West Virginia and New York. The PA 

DEP data indicate that the majority of UOG operators in Pennsylvania who decided to discharge 

to POTWs did so by 200896 (127 DCN SGE00188). To identify POTWs that accepted 

wastewater from UOG operations,97 the EPA reviewed the following sources: 

• Notes from calls with regional and state pretreatment program coordinators (182

DCN SGE00742, 192 DCN SGE00743) 

• Notes from an EPA-state implementation pilot project with the Environmental 

Council of the States in coordination with the Association of Clean Water 

Administrators (196 DCN SGE00762) 

• EPA Region 3’s website (174 DCN SGE00368) 

• Site visits, conference calls, and meetings with industry representatives (188 DCN 

SGE00613; 38 DCN SGE00521), UOG operators (191 DCN SGE00625; 178 DCN 

SGE00635; 179 DCN SGE00275; 190 DCN SGE00280), CWT facilities (181 DCN 

SGE00299; 180 DCN SGE00300; 37 DCN SGE00245; 36 DCN SGE00244), and 

Native American tribal groups (202 DCN SGE00785).

• PA DEP’s statewide waste report data98 (127 DCN SGE00188; 46 DCN SGE00739) 

• The U.S. DOE’s 2010 Water Management Technologies Used by Marcellus Shale 

Gas Producers report (212 DCN SGE00011) 

• Publicly available data sources identified through Internet searches

The EPA compiled and analyzed much of these existing data in a separate document, Publicly 

Owned Treatment Works (POTW) Memorandum for the Technical Development Document

(TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

(52 DCN SGE00929). This memorandum is referenced throughout Section D.5. 

 

95 EPA acknowledges that COG operators are still using POTWs as a viable option for disposal of COG wastewater.

96 EPA did not identify any information indicating when POTWs in New York began accepting of UOG extraction 

wastewater. EPA also could not definitely determine when UOG operators in Pennsylvania began discharging UOG 

extraction wastewater at POTWs because the 2007 PA DEP Waste Report data are incomplete.

97 EPA could not determine the date when POTWs began accepting UOG wastewater in all instances. The EPA has 

documentation that all POTWs in Pennsylvania stopped accepting UOG extraction wastewater by the end of 2011.

98 PA DEP’s waste report data provide wastewater volumes by well over time and management/disposal information 

as it was reported by the oil and gas well operator to PA DEP. ERG’s memorandum titled Analysis of Pennsylvania 

Department of Environmental Protection’s (PA DEP) Oil and Gas Waste Reports provides more detail (46 DCN 

SGE00739).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

107 

The EPA identified POTWs that, at one time, accepted wastewater from UOG operators 

generated by Marcellus shale wells. Table D-10 presents information about POTWs that have 

accepted UOG extraction wastewater directly from onshore UOG operators. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

108 

Table D-10. POTWs That Accepted UOG Extraction Wastewater from Onshore UOG Operators

Facility Name

NPDES 

Permit No. City State

POTW Currently Accepting UOG 

Wastewater from UOG Operator?

Year POTW Stopped Accepting UOG 

Wastewater from UOG Operator

Allegheny Valley Joint Sewer 

Authority PA0026255 Cheswick PA No 2008

Altoona Water Authority—Easterly 

WWTP PA0027014 Altoona PA No 2011

Belle Vernon Borough PA0092355 Belle Vernon PA No 2009

Borough of Jersey Shore PA0028665 Jersey Shore PA No 2010

Brownsville Municipal Authority PA0022306 Brownsville PA No 2008

California Borough PA0022241 California PA No 2009

Charleroi Borough PA0026891 Charleroi PA No 2008

City of Auburn NY0021903 Auburn NY No 2008

City of Johnstown Redevelopment 

Authority—Dornick Point PA0026034 Johnstown PA No 2010

City of McKeesport PA0026913 McKeesport PA No 2011

City of Watertown SPDES NY 

002 5984 Watertown NY No 2010

Clairton Municipal Authority PA0026824 Clairton PA No 2011

Clearfield Municipal Authority PA0026310 Clearfield PA No 2009

Dravosburg PA0028401 Dravosburg PA No 2008

Lock Haven City STP PA0025933 Lock Haven PA No 2008

Mon Valley Sewage Authority PA0026158 Donora PA No 2008

Moshannon Valley Authority STP PA0037966 Rush Township PA No 2009

Reynoldsville Sewer Authority PA0028207 Reynoldsville PA No 2011

Ridgway Borough PA0023213 Ridgway PA No 2011

Waynesburg Borough Water System PA0020613 Waynesburg PA No 2008

Source: 52 DCN SGE00929
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

109 

Based on data collected through June 2014, the EPA concluded that none of the POTWs 

listed in Table D-10 currently accept wastewater directly from UOG operations. That is, no UOG 

extraction wastewater is currently being managed by discharging to any of the POTWs in this 

table. This is, in large part, a result of UOG operators’ compliance with PA DEP’s April 2011 

request that they stop discharging UOG extraction wastewater to POTWs (see Section A.2.2).

PA DEP data indicate that UOG operators in Pennsylvania stopped sending their waste to 

POTWs in 2011 (127 DCN SGE00188). Furthermore, the EPA has not been able to identify any 

POTW in any state that is accepting UOG extraction wastewater directly from an operator. In 

addition, the EPA collected data about UOG operations on tribal reservations, UOG operators 

that are affiliated with Indian tribes, and POTWs owned or operated by tribes that may accept 

industrial wastewater (202 DCN SGE00785). According to this information, there are no tribes 

operating UOG wells that discharge wastewater to POTWs, nor are there any tribes that own or 

operate POTWs that accept UOG extraction wastewater. As such, the EPA concludes that 

operators have determined that discharge to a POTW is not a necessary and/or appropriate option 

for managing UOG extraction wastewater. 

The EPA is aware of a few cases where UOG operators discharge wastewater to CWT 

facilities for treatment and those CWT facilities discharge to POTWs. As explained in Section 

A.2.1.2, such discharges are not subject to the ELGs for the oil and gas extraction category 

which is the subject of the proposed rule. Rather, discharges to POTWs from CWT facilities are 

subject to ELGs for the Centralized Waste Treatment Category (40 C.F.R. part 437). 

The EPA reviewed PA DEP statewide waste reports (46 DCN SGE00739) and discharge

monitoring report (DMR) data (175 DCN SGE00608) to identify the total volumes of UOG 

extraction wastewater and average total influent wastewater for each POTW. Using these data 

sources, the EPA calculated the maximum annual average daily99 percentage of UOG extraction 

wastewater accepted by the POTW as shown in Table D-11. 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-11 also presents the year in which the maximum annual average daily volume 

occurred and the corresponding UOG extraction wastewater volume being accepted by the 

POTW during that year. The contribution of UOG extraction wastewater out of the total volume 

of wastewater treated at the POTW is typically a small percentage (less than 1 percent). 

However, based on the data presented in Table D-11, the contribution of UOG extraction 

wastewater was much higher (e.g., up to 21 percent) for some POTWs for some years. 

 

99 PA DEP waste reports provided the total volume of UOG extraction wastewater delivered to the POTW each year. 

The EPA divided the annual volume by 365 to calculate the annual average daily flow of UOG extraction 

wastewater accepted at the POTW.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

110 

Table D-11. Percentage of Total POTW Influent Wastewater Composed of UOG 

Extraction Wastewater at POTWs Accepting Wastewater from UOG Operators

POTW Name

NPDES 

Permit No.

Maximum 

Annual 

Average Daily

UOG 

Extraction

Wastewater

Volume 

Accepted 

(gpd)

Corresponding 

Total Annual

Average Daily 

Influent Flow to 

POTW (MGD)a

Maximum 

Annual 

Average Daily 

UOG 

Extraction

Wastewater

Percent of 

POTW 

Influent (%)

Year of 

Maximum 

Annual Average 

Daily UOG

Extraction

Wastewater 

Volume

Belle Vernon Borough PA0092355 93,000 0.44 21b 2008

California Borough PA0022241 84,000 0.60 14 2008

Charleroi Borough PA0026891 180,000 1.74 10 2008

Waynesburg Borough 

Water System PA0020613 56,000 0.58 9.7 2008

Mon Valley Sewage 

Authority PA0026158 67,000 3.47 1.9 2008

City of Johnstown 

Redevelopment 

Authority—Dornick Point

PA0026034 130,000 9.47 1.4 2008

Brownsville Municipal 

Authority PA0022306 9,400 0.88 1.1 2008

City of Auburn NY0021903 1,800 0.20 0.91 2008

Borough of Jersey Shore PA0028665 6,000 0.69 0.88 2008

Allegheny Valley Joint 

Sewer Authority PA0026255 30,000 4.30 0.69 2008

Ridgway Borough PA0023213 4,500 0.97 0.47 2010

Dravosburg PA0028401 1,300 0.33 0.39 2008

Clairton Municipal 

Authority PA0026824 12,000 4.15 0.30 2009

Moshannon Valley 

Authority STP PA0037966 3,400 2.29 0.15 2008

Reynoldsville Sewer 

Authority PA0028207 930 0.80 0.12 2010

City of McKeesport PA0026913 11,000 16.25 0.07 2009

Bellefonte Water 

Treatment Plant PA0020486 1,400 1.99 0.07 2008

Lock Haven City STP PA0025933 1,800 2.84 0.06 2008

Altoona Water Authority PA0027014 2,500 6.86 0.04 2011

Sources: 52 DCN SGE00929

a—This is the total influent wastewater flow to the POTW (domestic sewage and UOG extraction wastewater) in 

the year associated with the maximum UOG extraction wastewater volume received by the POTW. 

b—The average total flow through the POTW (MGD) in 2008 was calculated using the average of four months of 

available data (September 2008 through December 2008).

Abbreviations: gpd—gallons per day; MGD—million gallons per day
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

111 

5.3 How UOG Extraction Wastewater Constituents Interact with POTWs

POTWs are likely effective in treating only some of the pollutants in UOG extraction 

wastewater. Most POTWs are designed to primarily treat domestic wastewater. They typically 

provide at least secondary-level treatment and, thus, are designed to remove suspended solids 

and organic material. However, secondary treatment technologies are not designed to treat the 

high concentrations of TDS, radioactive constituents, metals, chlorides, sulfates, and other 

dissolved inorganic constituents found in UOG extraction wastewater.

100 Because they are not 

typical of POTW influent wastewater, UOG extraction wastewater constituents:

• May be discharged, untreated, from the POTW to the receiving stream 

• May disrupt the operation of the POTW (e.g., by exceeding permit limits for BOD5

or TSS in discharges, by inhibiting sludge settling)

• May accumulate in sludge, limiting its use

• May facilitate the formation of disinfection byproducts (DBPs)

Where available, the EPA reviewed the following information related to POTWs that 

have accepted UOG extraction wastewater:

• Local limit evaluations completed by POTWs’ pretreatment program coordinators 

• Technical evaluations of the impact of oil and gas wastewater pollutants on POTW 

unit processes completed in response to Administrative Orders (AOs)101 issued to a 

number of POTWs by PA DEP

• Pass through analyses completed by POTWs 

• DMR data from times when POTWs accepted UOG extraction wastewater

In many cases, POTWs that accepted UOG extraction wastewater also accepted COG 

extraction wastewater. Because the UOG extraction wastewater constituents that are discussed in 

this chapter are also present in COG extraction wastewater (205 DCN SGE00956; 18 DCN

SGE00966), information and studies on the treatability of these constituents by POTWs (or their 

impacts on POTWs) are similarly relevant when those POTWs are accepting only COG 

extraction wastewater and/or a combination of COG and UOG extraction wastewater. In most of 

the case studies presented in this chapter, the POTWs that were accepting UOG extraction 

wastewater were also accepting COG wastewater.

The EPA also reviewed common textbooks on wastewater treatment technology 

effectiveness. These textbooks indicated that POTWs would likely be ineffective for treatment of 

certain pollutants in UOG extraction wastewater, such as TDS and many pollutants that 

 

100 Some POTWs provide tertiary treatment, which removes additional nutrients as well as constituents targeted for 

removal using secondary treatment. Similar to secondary treatment, tertiary treatment processes are not designed to 

treat the high concentrations of TDS, radioactive constituents, metals, chlorides, sulfates, and other dissolved 

inorganic constituents found in UOG extraction wastewater.

101 PA DEP issued AOs to many POTWs in Pennsylvania that were accepting or suspected to begin accepting 

wastewater from UOG operations. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

112 

contribute to TDS (164 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-12 summarizes the POTW studies and analyses that are presented in Section 

D.5.3.1 and Section D.5.3.2. Section D.5.3.1 discusses the potential for UOG pollutants to be 

discharged, untreated, from POTWs. Section D.5.3.2 discusses the potential for UOG wastewater 

pollutants to cause or contribute to inhibition and disruption at POTWs. 

Table D-12. Summary of Studies About POTWs Receiving Oil and Gas Extraction 

Wastewater Pollutants

POTW Summary of Study Findings

POTWs Accepting Wastewater from Oil and Gas Operators

Clairton, PA, POTW Treatment system influent and effluent samples show minimal or no TDS and chloride 

removals. See Section D.5.3.1.1.

McKeesport, PA, POTW Treatment system influent and effluent samples show less than 10% removal of TDS, 

chloride, sulfate, and magnesium at the POTW. See Section D.5.3.1.1.

Ridgway, PA, POTW 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 Section D.5.3.1.1.

Charleroi, PA, POTW 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 Section D.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.

Clarksburg, WV, POTW 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 Section D.5.3.1.1.

Johnstown, PA, POTW 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.

California, PA, POTW 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.

Waynesburg, PA, POTW High-salinity UOG produced water impacted biological growth in trickling filter. See 

Section D.5.3.2.1.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

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Table D-12. Summary of Studies About POTWs Receiving Oil and Gas Extraction 

Wastewater Pollutants

POTW Summary of Study Findings

POTWs Accepting Wastewater Containing UOG Extraction Wastewater Pollutants from Other Industrial 

Sources (e.g., CWT Facilities)

Franklin, PA, POTW The Franklin POTW received industrial discharges from the Tri-County CWT facility 

(which received oil and gas extraction wastewater). The CWT facility targeted removal 

of TSS and oil and grease by filtration, flocculation, and skimming.

TDS and chloride concentrations in effluent from the POTW were higher when the 

POTW was accepting industrial wastewater from the Tri-County CWT facility and 

decreased after it stopped accepting wastewater from this CWT facility. See Section 

D.5.3.1.2.

Wheeling, WV, POTW The Wheeling POTW received oil and gas extraction wastewater from operators as 

well as industrial wastewater discharges from the Liquid Asset Disposal (LAD) CWT 

facility. The LAD CWT facility uses ultra-filtration, ozonation, and reverse osmosis to 

target the removal of chlorides prior to discharge to the Wheeling POTW.

The POTW experienced higher concentrations of chloride in POTW effluent while 

accepting UOG extraction wastewater from UOG operators and from the LAD CWT 

facility (which receives oil and gas extraction wastewater). See Section D.5.3.1.2. 

The POTW experienced interference with biological treatment from accepting UOG 

extraction wastewater pollutants via the LAD CWT facility’s industrial discharge. The 

POTW also experienced an upset that required the introduction of a “seed” sludge to 

maintain microbial activity in treatment processes. See Section D.5.3.2.2.

Warren, OH, POTW The Warren POTW receives industrial wastewater discharges from the Patriot CWT 

facility. The Patriot CWT facility uses primary treatment processes (e.g., settlement 

tanks, clarifier tanks) to target the removal of suspended solids and metals from UOG 

extraction wastewater before discharge to the Warren POTW. 

Influent and effluent TDS and chloride concentrations at the Warren POTW show 

minimal or no TDS or chloride removals. See Section D.5.3.1.2.

Brockway, PA, POTW The Brockway POTW received natural-gas-related wastewater treated by the Dannic 

Energy Corporation CWT facility.102

The POTW experienced higher concentrations of TDS in POTW effluent while 

accepting industrial discharges from the CWT facility containing oil and gas extraction 

wastewater pollutants. See Section D.5.3.1.2. 

The POTW experienced scum formation on clarifiers as well as increased sludge 

generation and high concentrations of barium in the sludge, while treating industrial 

discharges from the CWT facility. See Section D.5.3.2.2.

New Castle, PA, POTW The New Castle POTW received industrial wastewater from the Advanced Waste 

Services CWT facility (which treats oil and gas wastewater). The CWT facility uses 

the following treatment processes: solids settling, surface oil skimming, pH 

adjustment, and (occasional) flocculation.

The POTW experienced numerous effluent TSS permit limit exceedances while 

accepting industrial discharges from the CWT facility. The CWT facility discharge 

was associated with adverse impacts on sludge settling in final clarifiers at the POTW. 

See Section D.5.3.2.2.

 

102 EPA could not find information about the treatment processes used by the Dannic Energy Corporation CWT 

facility.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

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5.3.1 UOG Extraction Wastewater Constituents Discharged Untreated from POTWs

As described in Section D.5.3, the EPA reviewed studies and analyses relevant to 

POTWs accepting wastewater containing pollutants found in UOG extraction wastewater. 

Consistent with wastewater treatment literature, the POTWs described in these studies 

demonstrated that some UOG extraction wastewater pollutants are not removed by POTWs and 

are discharged untreated to receiving streams. 

5.3.1.1 Case Studies of POTWs Accepting Oil and Gas Extraction Wastewater 

Clairton, PA, POTW

The Clairton POTW discharges to Peters Creek, which flows into the Monongahela River 

and treats influent wastewater using screening and grit removal, comminutors (i.e., grinders),103

aeration basins, clarifiers, activated sludge, aerobic digestion, and chlorine disinfection. The 

Clairton POTW is permitted to treat a maximum of 6 MGD (107 DCN SGE00758).

On October 23, 2008, PA DEP issued an AO to the Clairton POTW that established

requirements for its acceptance of oil and gas wastewater. The AO required the Clairton POTW 

to restrict the volume of oil and gas wastewater it accepts to a flow rate no greater than 1 percent

of the average daily flow. The AO also required the POTW to evaluate the potential impacts of 

oil and gas production wastewater on its treatment processes. The technical evaluation noted 

(107 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-10 shows the results from the 24-hour composite sampling that occurred over 

five days in December 2008. According to PA DEP data (46 DCN SGE00739), in 2008, the 

Clairton POTW was accepting oil and gas wastewater amounting to an average of 0.05 percent 

of the POTW flow. Looking at the average measured concentrations, the results indicate little or 

no removal of TDS or chloride. 

 

103 A comminutor is a machine that reduces the particle size of wastewater solids using a cutting device.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

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Figure D-10. Clairton POTW: Technical Evaluation of Treatment Processes’ Ability to 

Remove Chlorides and TDS

Sources: 52 DCN SGE00929

Note: The data presented in this figure are based on five 24-hour composite samples taken from 

December 8, 2008, through December 12, 2008.

Clairton POTW’s consultant completed a pass through analysis in August 2009 (137

DCN SGE00748). Having collected two sets of influent concentration data from two different oil 

and gas wells, the consultant stated that the O&G Well No. 2 wastewater “was not characteristic 

of the oil and gas wastewater routinely accepted by the CMA POTW.” Therefore, the EPA only 

included the wastewater characteristic data for O&G Well No. 1, as reported in the pass through 

analysis (see Table D-13). The pass through analysis assumes zero percent removal of TDS at 

the POTW and concludes that (137 DCN SGE00748): 

The result of the mass balance analyses clearly indicates that TDS is untreated resulting 

in a “pass-through” to receiving waters...The hypothetical mass balance 

review...indicates that if higher concentrations of TDS are introduced into the POTW, 

the concentration and loading of TDS to the receiving waters increases proportionally. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

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Table D-13. Clairton Influent Oil and Gas Extraction Wastewater 

Characteristics

Parameter

Wastewater Concentrations (mg/L)

O&G Well No. 1

Barium 294

Calcium 3,060

Chloride 44,700

Magnesium 1,210

Sodium 84,500

TDS 76,000

TSS 1,600

Source: 137 DCN SGE00748

Abbreviation: mg/L—milligrams per liter

McKeesport, PA, POTW

The McKeesport POTW discharges to the Monongahela River and treats wastewater 

using screening and grit removal, aeration, clarification, activated sludge, aerobic digestion, and 

chlorine disinfection (108 DCN SGE00745). The McKeesport POTW began accepting COG 

wastewater in 2008 and UOG extraction wastewater in 2009. The POTW stopped accepting both 

COG and UOG extraction wastewater in December 2011 (46 DCN SGE00739). 

On October 23, 2008, PA DEP issued an AO to the McKeesport POTW that allowed it to 

accept oil and gas wastewater in amounts no greater than 1 percent of its average daily flow, 

among other requirements. The AO also required the POTW to evaluate the potential impacts of 

oil and gas production wastewater on its treatment processes. The POTW conducted this 

technical evaluation in November 2008. According to PA DEP data (46 DCN SGE00739), in 

2008, the McKeesport POTW was accepting only COG wastewater. The evaluation (106 DCN 

SGE00757) noted: 

The results of the samples taken and analyzed through the MACM [Municipal Authority 

of the City of McKeesport] WWTP indicate that there is no reduction in concentration of 

TDS and chlorides through the plant processes. This is not unexpected as conventional 

sewage treatment facilities are not designed to remove dissolved constituents such as 

TDS and chlorides. 

Figure D-11 shows the results from 24-hour composite sampling over seven days in 

November 2008. The results indicate no removal of TDS or chloride. According to the manifests 

included in the technical evaluation (106 DCN SGE00757), McKeesport treated trucked 

wastewater from conventional wells during the seven-day sampling period. These wastewater 

sources are summarized in Table D-14, below.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

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Figure D-11. McKeesport POTW: Technical Evaluation of Treatment Processes’ Ability to 

Remove Chlorides and TDS

Sources: 52 DCN SGE00929

Note: The data presented in this figure are based on seven 24-hour composite samples taken from November 1, 

2008, through November 7, 2008.

Table D-14. Trucked COG Extraction Wastewater Treated at McKeesport POTW from 

November 1 Through 7, 2008

Date Waste Typea Volume (gallons) Chlorides (mg/L) Chlorides (lbs)

November 3, 2008 Brine 3,780 155,000 4,886

November 4, 2008 Flow-back 3,780 145,000 4,571

November 6, 2008 Flow-back 3,780 155,000 4,886

November 6, 2008 Frac 4,620 20,000 771

November 7, 2008 Frac 4,620 20,000 771

Source: 108 DCN SGE00745

a—According to data from the technical evaluation, some waste streams were referred to as “frac” and “flow-back,” 

indicating that the conventional wells were hydraulically fractured.

Abbreviations: mg/L—milligrams per liter; lbs—pounds

McKeesport POTW’s consultant completed a headworks loading analysis in March 2011 

(108 DCN SGE00745). As part of the analysis, the consultant completed monthly sampling of 

the influent and effluent of the POTW from February 2010 through January 2011 and determined 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

118 

the average removal percentages based on the sampling results. During the time of sampling, a 

combination of UOG and COG wastewater contributed no more than 1 percent of the average 

daily flow and municipal wastewater made up the remaining influent to the McKeesport POTW. 

Table D-15 presents the percent removals calculated during this analysis and shows that the 

POTW removed less than 7 percent of the influent TDS and less than 5 percent of the influent 

chloride. Effluent TDS concentrations ranged from 600 to 1,500 mg/L while the facility accepted 

both UOG and COG wastewater during the sampling period (108 DCN SGE00745).

Table D-15. McKeesport POTW Removal Rates Calculated for Local Limits Analysis

Parameter Removal Rates (%)

Sulfate 3.94

Chloride 4.44

TDS 6.43

Magnesium 6.62

Strontium 18.47

Bromide 26.99

Barium 71.64

Source: 108 DCN SGE00745

Note: The data presented in this table are based on timed composite samples obtained once a month for 12 months 

from February 2010 through January 2011. 

A 2013 study by Ferrar et al. (71 DCN SGE00525) analyzed constituents in effluent 

wastewater discharged from two POTWs in Pennsylvania, first while the POTWs accepted 

industrial discharges containing UOG extraction wastewater pollutants (either from a CWT 

facility or from a UOG operator) and again after the POTWs stopped accepting those industrial 

discharges. The study included effluent sampling at the McKeesport POTW in 2010 while the 

POTW was accepting UOG extraction wastewater. The study specifically reported that the 

facility was accepting UOG extraction wastewater during the sampling but did not mention COG 

wastewater. Based on PA DEP data, the EPA is aware that the POTW accepted both UOG and 

COG wastewater in 2010; however, details were not available concerning whether COG 

wastewater was accepted on the specific days of the sampling. The UOG extraction wastewater, 

received from operators via tanker trucks, was stored in holding tanks, then mixed with 

municipal wastewater in the primary clarifier. The study sampled POTW effluent in October 

2010, when the POTW was accepting UOG extraction wastewater and again in December 2011, 

after the POTW had stopped accepting COG and UOG extraction wastewater.

104 The study also 

collected one sample in November 2010 of UOG extraction wastewater before it was mixed with 

the municipal influent105 (see Table D-16). 

On October 19, 2010, when Ferrar et al. collected their POTW effluent sample, they 

reported that the McKeesport POTW treated 13,020 gallons of UOG extraction wastewater, and 

the average daily flow of the POTW was 9.6 MGD, indicating that the UOG extraction 

 

104 The PA DEP waste reports data (46 DCN SGE00739) show that the McKeesport POTW stopped accepted COG 

and UOG wastewater after 2011.

105 Note that the one-time sample of influent UOG extraction wastewater was not collected at the same time as either 

of the effluent sampling events.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

119 

wastewater accounted for 0.14 percent of the total influent.

106 The remaining influent wastewater 

consisted of municipal wastewater typically treated by the POTW (see Table D-7 for typical 

constituent concentrations in municipal wastewater). 

Table D-17 shows the range and mean effluent concentrations, as measured by Ferrar et 

al., at the McKeesport POTW while they were accepting UOG extraction wastewater and after 

they had stopped accepting UOG extraction wastewater. As noted above, the study reported that 

the McKeesport POTW accepted an average daily flow of 9.6 MGD during the October 2010 

sampling event. However, they did not report the average daily flow during the December 2011 

sampling event. Although they reported that the facility was accepting UOG extraction 

wastewater on the first effluent sampling date (October 19, 2010), sampling data for that influent 

UOG extraction wastewater (like the data presented in Table D-16) were not available. Therefore 

it is not possible to know whether the data presented in Table D-16 are representative of the 

UOG extraction wastewater influent on the date of the effluent sampling presented in Table 

D-17. As discussed in Section C.3, UOG extraction wastewater characteristics vary over time 

and from well to well.

Table D-16. Constituent Concentrations in UOG Extraction Wastewater Treated at the 

McKeesport POTW Before Mixing with Other Influent Wastewater 

Analytea Concentrations in UOG Extraction Wastewater 

Treated at McKeesport POTW (mg/L)b

Barium 106

Calcium 1,690

Magnesium 203

Strontium 324

Bromide 151

Chloride 17,000

Sulfate 53.1

TDS 24,200

Source: 71 DCN SGE00525

a—Organic analytes were not detected in samples.

b—Sample date: 11/10/2010. Reported values are based on only one sample taken for each analyte. Samples were 

collected from a UOG extraction wastewater holding tank before mixture and dilution with influent municipal 

wastewater.

Abbreviation: mg/L—milligrams per liter

 

106 Ferrar et al. (71 DCN SGE00525) noted that since the total volume of UOG wastewater was released at one time, 

the actual dilution might have been 0.81 percent UOG wastewater in the effluent when it was discharged (8–12 

hours later).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

120 

Table D-17. McKeesport POTW Effluent Concentrations With and Without UOG 

Extraction Wastewater 

Analytea

Effluent Concentrations Measured While 

POTW Was Accepting UOG Extraction 

Wastewater (mg/L)b

Effluent Concentrations Measured After 

POTW Had Stopped Accepting UOG 

Extraction Wastewater (mg/L)c

Mean Range Mean Range

Barium 0.55 0.21–0.81 0.036 0.034–0.039

Calciumd 50.3 42.4–55.9 58.8 56.6–63.4

Magnesiumd 10.3 8.96–11.2 13.61 13.2–14.4

Strontium 1.63 0.924–2.26 0.228 0.219–0.237

Bromide 0.600 0.231–0.944 0.119 0.08–0.43

Chloride 228.7 150–377 136.8 133–142

Sulfate 98.1 81.2–139 65.9 64.4–67.2

TDS 562.2 466–648 494.2 464–524

Source: 71 DCN SGE00525

a—Organic analytes were not detected in samples.

b—Sample date: 10/19/2010. Reported values are based on the mean, minimum, and maximum of 24 samples taken 

for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.

c—Sample date: 12/1/2011. Reported values are based on the mean, minimum, and maximum of nine samples taken 

for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.

d—The effluent concentrations of calcium and magnesium increased after the POTW had stopped accepting UOG 

extraction wastewater. Ferrar et al. (71 DCN SGE00525) suggest that the increased concentrations of these ions may 

be from high influent calcium and magnesium concentrations in other wastewater treated by the McKeesport POTW 

(e.g., COG wastewater).

Abbreviation: mg/L—milligrams per liter

Ridgway, PA, POTW

Ridgway Borough operates a POTW that discharges to the Clarion River and has a 

maximum monthly average design rate of 2.2 MGD. The Ridgway POTW uses screening and 

grit removal, an equalization tank, aeration tanks, clarifiers, a chlorination feed system, a 

chlorine contact tank, aerobic digesters, and a belt filter press. This POTW began accepting both 

COG and UOG extraction wastewater in 2009. It stopped accepting UOG extraction wastewater 

in 2011 but continued accepting COG wastewater, and still was as of the end of 2013.107 The 

total oil and gas wastewater volume accounted for less than 2 percent of the total POTW influent 

volume during 2009 through 2011 on average (46 DCN SGE00739). The POTW’s total annual 

average daily flow rate ranges between 0.8 and 1.3 MGD, based on 2008 to 2013 DMR data (175

DCN SGE00608). 

The EPA created Figure D-12 using the sampling data submitted in the EPA’s DMR 

Loading Tool (175 DCN SGE00608) and PA DEP waste reports data (46 DCN SGE00739). 

Each effluent concentration data point represents the average of 12 monthly average data points 

as calculated and reported by the DMR Loading Tool. PA DEP waste reports provided the total 

 

107 Ridgway’s October 2011 NPDES permit (131 DCN SGE00755) notes that “no more than 20,000 gallons/day of 

natural gas wastewater from shallow well operations shall be treated at the facility. The acceptance of wastewater 

generated from shale oil extraction activities is prohibited.” 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

121 

volume of UOG and COG wastewater delivered to the POTW each year. The EPA divided the 

annual volume by 365 to calculate the annual average daily flow. As shown in Figure D-12, in 

2010, the Ridgway POTW experienced effluent TDS concentrations greater than 6,000 mg/L on 

average and effluent chloride concentrations greater than 2,500 mg/L on average while it was 

accepting the greatest volume of oil and gas wastewater, including that from UOG operators. As 

a point of comparison, in 2008, before accepting any oil and gas wastewater, the POTW 

experienced effluent TDS and chloride concentrations around 1,000 mg/L. 

Figure D-12. Ridgway POTW: Annual Average Daily Effluent Concentrations and POTW 

Flows

Sources: 52 DCN SGE00929

To comply with the requirements of the Ridgway Borough Pretreatment Program, the 

Ridgway POTW completed a local limits analysis in January 2014 that included paired POTW 

influent and effluent data. The samples were collected for 10 consecutive days in October and 

November 2013 after the POTW stopped accepting UOG extraction wastewater but was still 

accepting COG wastewater. Of particular interest is the fact that Ridgway POTW’s contractor
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

122 

estimated zero percent removals for TDS, chloride, and sulfate. All three of these constituents 

are found in UOG extraction wastewater (88 DCN SGE00756). 

Charleroi, PA, POTW

The Charleroi POTW uses an equalization tank, screening and grit removal, 

sedimentation, activated sludge, and chlorine disinfection. It began accepting both COG and 

UOG extraction wastewater in January 2005 and stopped accepting it in 2008 (11 DCN 

SGE00751; 46 DCN SGE00739). The total oil and gas wastewater accounted for up to 32 

percent of the total POTW influent volume during 2008, on average. UOG extraction wastewater 

accounted for 10 percent of total POTW influent during 2008 on average (46 DCN SGE00739). 

The POTW’s average annual flow rate ranges between 1.4 and 1.9 MGD based on 2008 through 

2013 DMR data (175 DCN SGE00608). The EPA identified case studies showing potential for 

both pass through (Section D.5.3.1.1) and inhibition/disruption (Section D.5.3.2.1) at the

Charleroi POTW. 

In 2008, PA DEP issued an AO requiring the Charleroi POTW to evaluate how accepting 

oil and gas production wastewater affects its treatment processes, among other things (11 DCN 

SGE00751). Charleroi’s technical evaluation noted that the POTW typically rejects influent oil 

and gas wastewater with TDS concentrations greater than 30,000 mg/L or chloride 

concentrations greater than 15,000 mg/L. As part of the technical evaluation, Charleroi sampled 

influent wastewater (including UOG extraction wastewater) and effluent wastewater over a 24-

hour period. The total oil and gas wastewater treated during this period was 150,650 gallons

(3,587 barrels) and the total wastewater treated was 1,559,000 gallons (37,120 barrels). 

Therefore, the oil and gas wastewater accounted for 9.7 percent of the total influent to the plant 

during the sampling period (11 DCN SGE00751). Table D-18 shows the results of the sampling 

and the calculated removal rates. The data show that TDS is not removed by the Charleroi 

POTW treatment processes.

Table D-18. Charleroi POTW Paired Influent/Effluent Data and Calculated Removal Rates

Parameter

Influent Concentration 

(mg/L)

Effluent Concentration 

(mg/L) Removal Rate (%)

Aluminum 2.34 0.656 72

Ammonia, as N 14.4 4.52 68.6

Barium 0.177 0.171 3.4

BOD5 84 1.00 98.8

Hardness, as CaCO3 265 260 1.9

Oil and grease 29 5 82.8

Phosphorus 0.49 0.3 38.8

TDS 1,020 1,030 0

TSS 116 21 81.9

Source: 11 DCN SGE00751

Abbreviation: mg/L—milligrams per liter
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

123 

Clarksburg, WV, POTW

The Clarksburg POTW has a maximum capacity of 8 MGD and uses screening, a cyclone 

hydrogritter, clarifiers, aeration basins, and chlorine disinfection. The Clarksburg POTW started

accepting “gas well wastewater” (i.e., brine) in July 2008 on a trial basis and continued through 

at least March 2009. Three frac tanks were set up on the treatment plant site and the brine (i.e., 

oil and gas extraction wastewater) was metered into the POTW’s pump station wet well at a 

constant continuous flow rate. Total POTW flow was at least 5 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 they 

could continue accepting the gas wastewater as long as they were not violating their existing 

effluent limitations (21 DCN SGE00749; 121 DCN SGE00552). In July 2009, WV DEP sent a 

letter to the Clarskburg Sanitary Board with a list of requirements that would be imposed, if they 

decided to accept oil and gas related wastewater (221 DCN SGE01113). The letter also stated 

that

...WVDEP discourages POTWs from accepting wastewater from oil and gas operations 

such as...marcellus shale wastewaters because these wastewater essentially pass through 

sewage treatment plants and can cause inhibition and interference with treatment plant 

operations. The wastewaters from these types of operations contain high levels of 

chloride, dissolved solid, sulfate, and other pollutants. POTWs provide little to no 

treatment of these pollutants and could potentially lead to water quality issues in the 

receiving stream.

In April 2013, WV DEP verified that no POTWs in WV were accepting UOG extraction 

wastewater (196 DCN SGE00762; 198 DCN SGE00766). 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

124 

5.3.1.2 Case Studies About POTWs Accepting Wastewater from Other Industrial 

Sources Containing UOG Pollutants 

Franklin Township, PA, POTW

The Franklin Township POTW discharges to the lower fork of Ten Mile Creek, a 

tributary to the Monongahela River, and treats influent wastewater using aeration, rotating 

biological contactors, clarification, filtration, and chlorination (74 DCN SGE00746). The 

Franklin Township POTW accepted industrial wastewater from the Tri-County Wastewater 

CWT facility until March 2011. During that time, the Tri-County CWT facility was accepting 

oil and gas extraction wastewater. The CWT facility targeted removal of TSS and oil and grease 

by filtration, flocculation, and skimming, but certain pollutants in the UOG extraction 

wastewater such as TDS remained in the treated effluent from the CWT facility. The industrial 

wastewater received from Tri-County Wastewater accounted for approximately 5.4 percent of 

the Franklin POTW’s 0.982 MGD effluent by volume in November 2010 (71 DCN SGE00525). 

On December 4, 2008, the Franklin POTW entered into a Consent Order and Agreement 

with PA DEP108 regarding effluent discharges containing elevated levels of TDS. Paragraph G of 

the order notes that 

Neither the STP [Franklin POTW] nor the Pretreatment Facility [Tri-County CWT 

Facility] currently has treatment facilities for the removal of Total Dissolved Solids.

Ferrar et al. (71 DCN SGE00525) analyzed constituents in effluent wastewater 

discharged from the Franklin Township POTW during the period before and after it accepted 

industrial wastewater from the Tri-County Wastewater CWT facility. Table D-19 shows the 

mean and range of effluent concentrations at the Franklin Township POTW during the period it 

accepted industrial wastewater from the CWT facility and after they stopped. Ferrar et al. 

analyzed pollutants typically found in UOG extraction wastewater; they report a mean effluent 

TDS concentration of 3,860 mg/L from the Franklin Township POTW while it was accepting 

wastewater from the Tri-County CWT facility and a mean effluent TDS concentration of 398 

mg/L from the POTW after it stopped. The mean effluent concentrations for all pollutants 

presented in Table D-19 were higher when the POTW was accepting the industrial discharge 

from the Tri-County CWT facility, suggesting that pollutants were discharged from the POTW 

without treatment. Based on the treatment technologies currently in place at the Franklin 

Township POTW, one would expect little to no treatment of the common constituents in UOG 

extraction wastewater. Ferrar et al. concluded: 

This research provides preliminary evidence that these and similar WWTPs may not be 

able to provide sufficient treatment for this wastewater stream, and more thorough 

monitoring is recommended.

 

108 PA DEP had issued an AO to the Franklin POTW in October 2008, but the Consent Order and Agreement 

superseded that order. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

125 

Table D-19. Franklin Township POTW Effluent Concentrations With and Without 

Industrial Discharges from the Tri-County CWT Facility 

Analytea

Effluent Concentrations from Franklin 

Township POTW Measured While POTW 

Was Accepting Wastewater from CWT

Facility (mg/L)b

Effluent Concentrations from Franklin 

Township POTW Measured After POTW 

Had Stopped Accepting Wastewater from 

CWT Facility (mg/L)c

Mean Range Mean Range

Barium 5.99 4.27–7.72 0.141 0.124–0.156

Calcium 231 207–268 40.6 38.8–43.5

Magnesium 32.6 29.1–36.6 8.63 8.04–9.11

Manganese 0.228 0.204–0.249 0.112 0.102–0.144

Strontium 48.3 41.8–56.1 0.236 0.226–0.249

Bromide 20.9 14.3–28.0 <0.016 <0.016

Chloride 2,210 1,940–2,490 61.9 57.5–64.6

Sulfate 137 117–267 65.6 60.0–75.0

TDS 3,860 3,350–4,440 398 376–450

Source: 71 DCN SGE00525

a—Organic analytes were not detected in samples.

b—Sample date: 11/10/2010. Reported values are based on the mean, minimum, and maximum of 24 samples taken 

for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.

c—Sample date: 11/7/2011. Reported values are based on the mean, minimum, and maximum of nine samples taken 

for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.

Abbreviation: mg/L—milligrams per liter

Wheeling, WV, POTW

The Wheeling POTW has primary and secondary treatment operations, including primary 

clarification, solids and floatable materials removal, and disinfection (115 DCN SGE00999). The 

Wheeling POTW accepted industrial wastewater from the Liquid Asset Disposal (LAD) CWT 

facility through August 2009109 and wastewater directly from UOG operators in 2008110. The 

LAD CWT facility accepted a variety of wastewater from the following sources: sewage 

facilities, storm water from an international airport, and gas well development and production 

wastewater, among others. The LAD CWT facility is a SIU and was authorized to discharge into 

the Wheeling, WV POTW (SIU Permit No. 0014) (219 DCN SGE00485). The LAD CWT 

facility uses ultra-filtration, ozonation, and reverse osmosis to target the removal of chlorides 

prior to discharges to the Wheeling POTW (101 DCN SGE00996). 

The EPA analyzed sampling data submitted in its DMR Loading Tool (175 DCN 

SGE00608) and PA DEP waste reports data (46 DCN SGE00739) and found that the effluent 

concentrations of chloride experienced by the Wheeling POTW in 2008 were higher when it was 

accepting UOG extraction wastewater and industrial discharges from the LAD CWT facility than 

 

109 EPA did not identify the date on which the Wheeling POTW began accepting wastewater from the LAD CWT 

facility. However, the LAD CWT SIU Permit No. 0014 was issued in August 2004 (22 DCN SGE01000).

110 The Wheeling POTW may have accepted UOG extraction wastewater directly from operators in years other than 

2008, but EPA only identified acceptance directly from operators in 2008 (127 DCN SGE00188).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

126 

after it stopped. In 2008, the POTW accepted an average of 5,400 gallons/day of UOG extraction 

wastewater and had an average effluent chloride concentration of 650 mg/L. Comparatively, in 

2011, the POTW did not accept any UOG extraction wastewater and had an average effluent 

chloride concentration of 130 mg/L.

111 Data from an August 2009 letter from WV DEP to the 

City of Wheeling states (222 DCN SGE01114) 

The agency has determined that the 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 (219 DCN SGE00485). 

Therefore, the UOG extraction wastewater and the industrial wastewater accepted by the 

Wheeling POTW from the LAD CWT facility likely contributed to the elevated effluent chloride 

concentrations. 

Warren, OH, POTW

The city of Warren operates a 16 MGD POTW that discharges to the Mahoning River. 

The POTW employs screening and grit removal, primary settling, activated sludge aeration, final 

clarification, chlorination, dechlorination, and post-aeration treatment processes. Solid residuals 

are thickened by dissolved air flotation, dewatered using a belt filter press, stabilized with lime, 

and disposed of by land application or by distribution and marketing of usable end products. 

In May 2009, the Warren POTW and its customer, the Patriot Water Treatment CWT

facility,

112 began discussions with the Ohio EPA about accepting UOG produced water. Patriot 

planned to accept UOG produced water from shale gas operations, treat the wastewater to 

remove heavy metals and other constituents, and discharge the treated industrial wastewater to 

the Warren POTW. In preparation for acceptance of treated industrial wastewater from the CWT 

facility that would contain pollutants found in UOG produced water, the Warren POTW 

undertook a pilot study to show that accepting wastewater containing pollutants found in UOG 

produced water would not cause any problems with Mahoning River water quality. Patriot’s 

treatment of UOG produced water includes reduction in heavy metal concentration, but not TDS 

or chloride. The Ohio EPA worked with Patriot and the Warren POTW to develop a pilot 

treatment study that evaluated the effects of pretreated UOG produced water on the POTW. The 

 

111 The data about quantities of UOG extraction wastewater accepted by the Wheeling POTW are from the PA DEP 

waste report data and are reflective of volumes of UOG extraction wastewater accepted from UOG operators in 

Pennsylvania. The Wheeling POTW may be accepting additional UOG extraction wastewater from UOG operators 

in West Virginia or other nearby states; these volumes of wastewater are not captured in this discussion.

112 The Patriot CWT facility uses primary treatment processes (e.g., settlement tanks, clarifier tanks) to target the 

removal of suspended solids and metals prior to discharge.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

127 

study also evaluated the receiving stream (Mahoning River) water quality, upstream and 

downstream of the POTW discharge (5 DCN SGE00497; 35 DCN SGE00522).

The pilot study began on February 9, 2010, and ran for eight weeks. It focused on 

collecting data from the Warren POTW and did not include sampling at the Patriot CWT facility. 

The summarized TDS and chloride data from the study are presented in Table D-20. The Warren 

POTW reported typical flow rates of 13.38 MGD and accepted the following volumes of 

wastewater from the Patriot CWT facility over the eight weeks (percentage of total POTW flow 

accounted for by Patriot CWT facility’s industrial wastewater is noted parenthetically)113 (193

DCN SGE00616): 

• Week 1: 5 days @ 20,000 gallons (0.15 percent) 

• Week 2: 5 days @ 40,000 gallons (0.30 percent) 

• Week 3: 5 days @ 60,000 gallons (0.45 percent) 

• Week 4: 5 days @ 80,000 gallons (0.60 percent) 

• Week 5: 5 days @ 100,000 gallons (0.75 percent) 

• Week 6: 5 days @ 100,000 gallons (0.75 percent) 

• Week 7: 5 days @ 100,000 gallons (0.75 percent) 

• Week 8: 5 days @ 100,000 gallons (0.75 percent) 

Table D-20 shows the average paired influent and effluent TDS concentrations measured 

prior to start up and during the pilot study. Baseline samples were collected when the POTW was 

not accepting wastewater from the Patriot CWT facility. The pilot study description states that 

the influent samples (baseline and pilot study) include only municipal influent and do not include 

any wastewater from the Patriot CWT facility.

114 The data show that TDS and chloride 

concentrations increased in the influent and effluent samples over time both during the baseline 

sampling and after the Warren POTW accepted wastewater from the Patriot CWT facility. The 

effluent concentrations of TDS and chloride increased at higher percentages over the influent 

concentration during the pilot study, when the POTW was accepting wastewater from the Patriot 

CWT facility (193 DCN SGE00616), suggesting that TDS and chloride were not removed by the 

POTW. 

 

113 All flows were introduced into the Warren POTW over an eight-hour period.

114 The Warren POTW pilot study description states that “Raw [influent] does not have any Patriot influence or plant 

return flows.” The report author also noted increases in the TDS and chloride concentrations over the period of the 

study and suggested that “these increases are most likely due to seasonal fluctuations within the collection system as 

a result of user operations or seasonal runoff from spring rains” (193 DCN SGE00616).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

128 

Table D-20. 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 584 599 2.6

Chloride 143 157 9.8

Eight-Week Pilot Study Samples

TDS 679 885 30.3

Chloride 239 348 45.6

Source: 193 DCN SGE00616

Abbreviation: mg/L—milligrams per liter

From September 12 through 16, 2011, EPA Region 5 inspected and collected wastewater 

samples at the Warren POTW and noted that (193 DCN SGE00616) 

the POTW had not experienced any of the following conditions since accepting the brine 

waste water from the Patriot CWT facility: 

• Diminished or inhibited performance of the biological treatment processes 

• Adverse impacts to the downstream water quality 

• Adverse impacts to the quality of the facility’s biosolids

The compliance inspection indicated that the Warren POTW was in compliance with all 

of its NPDES permit limitations. Table D-21 shows the results of EPA Region 5’s wastewater 

sample analyses conducted during their September 2011 inspection. The compliance inspection 

data show minimal to no TDS removals by the POTW and minimal chloride removals. 

Table D-21. EPA Region 5 Compliance Inspection Sampling Data

Pollutant 

Warren POTW Influent Concentration 

(mg/L)a

Warren POTW Effluent Concentration 

(mg/L)a

Average Range Average Range

TDS 726 686–748 726 648–778

Chloride 361 345–374 213 191–252

Sulfate 250 243–256 77 68–84

TSS 95.0 67.0–112 <4 NAb

BOD5 33.3 27.7–39.0 <2 NAb

Bromide 5.25 5.01–5.43 1.57 1.40–1.89

Fluoride 3.62 3.36–4.13 1.83 1.40–2.14

Source: 193 DCN SGE00616

a—Samples were taken on four days (9/12/2013, 9/13/2013, 9/14/2013, and 9/15/2013).

b—All four samples were reported as below the detection limit.

Abbreviation: mg/L—milligrams per liter
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

129 

As of June 2014, the Warren POTW was still accepting wastewater from the Patriot 

CWT facility (200 DCN SGE00786). Its NPDES permit allows it to accept a maximum of 

100,000 gallons of “wastewater from a regulated CWT facility that is tributary to the City’s 

collection system” per day (0.67 percent of its maximum total daily flow) at a maximum TDS 

concentration of 50,000 mg/L (217 DCN SGE00295). 

Brockway, PA, POTW

The Brockway POTW treats industrial and domestic wastewater using screens, aerated 

basins, oxidation ditches, clarifiers, aerobic sludge digestion, UV disinfection, and post-aeration. 

Its NPDES permit (issued on July 3, 2012, and expiring on July 31, 2017) allows it to accept up 

to 14,000 gpd of “natural gas related wastewater,” none of which may be from “Shale Gas 

Extraction related activities” (132 DCN SGE00931). As of June 2014, the Brockway POTW was 

still accepting natural-gas-related wastewater treated by the Dannic Energy Corporation CWT 

facility. The Brockway POTW is sampling and reporting the required parameters on PA DEP’s 

electronic DMR system (eDMR) (132 DCN SGE00931). The permit includes limits for pH, 

carbonaceous 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 (99 DCN SGE00753). 

5.3.2 UOG Extraction Wastewater Constituents and POTW Inhibition and Disruption 

In addition to the discharge of pollutants not treated by a POTW, the presence of certain 

pollutants in industrial wastewater discharges can have the following effects on the receiving 

POTW: 

• Inhibition or disruption of the POTW’s treatment processes and/or operations 

• Inhibition or disruption of the POTW’s sludge processes, including sludge disposal 

processes

• Harm to POTW workers

The EPA investigated how pollutants in industrial wastewater discharges, which may 

contain constituents found in UOG extraction wastewater, might inhibit the performance of 

typical POTW treatment processes. Table D-22 presents inhibition threshold levels for activated 

sludge and nitrification, two treatment processes commonly used at POTWs, for select UOG 

constituents identified in Section C.3.

115 The EPA recognizes that POTW treatment processes 

will not be exposed to UOG constituents at the concentrations they are found in UOG produced 

water (i.e., flowback, long-term produced water). 

 

115 EPA also presents specific inhibition thresholds for anaerobic digestion and trickling filters, but the UOG 

constituent concentrations are not as likely to exceed the thresholds, so they were not included in Table D-22. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

130 

As discussed in Section A.2.1.1, POTWs establish local limits to control pollutant 

discharges that present a reasonable potential for pass through or interference with POTW 

operations. The inhibition levels presented in the EPA’s guidance represent concentrations that 

would reduce the effectiveness or otherwise interfere with the treatment operations for treatment 

commonly used at POTWs. Inhibition of activated sludge processes at a POTW could impair 

BOD5 removal and TSS removal (particularly if sludge settling is affected). Inhibition of 

nitrification, a process that some POTWs use to convert ammonia to nitrate/nitrite (which may 

be part of the activated sludge process or a separate biological treatment stage), may impair the 

POTW’s ability to remove ammonia and nutrients in the wastewater.

Table D-22. Inhibition Threshold Levels for Various Treatment Processesa

Pollutant

Reported Range of Activated Sludge 

Inhibition Threshold Levels (mg/L)a

Reported Range of Nitrification Inhibition 

Threshold Levels (mg/L)a

Ammonia 480 NA

Arsenic 0.1 1.5

Benzene 100–500, 125–500 NA

Cadmium 1–10 5.2

Chloride NA 180

Chloroform NA 10

Chromium, total 1–100 0.25–1.9, 1–100 (trickling filter)

Copper 1 0.05–0.48

Ethylbenzene 200 NA

Lead 1–5, 10–100 0.5

Mercury 0.1–1, 2.5 as Hg(II) NA

Naphthalene 500, 500, 500 NA

Nickel 1–2.5, 5 0.25–0.5, 5

Phenol 50–200, 200, 200 4, 4–10

Sulfide 25–30 NA

Toluene 200 NA

Zinc 0.3–5, 5–10 0.08–0.5

Source: 165 DCN SGE00602

a—Where multiple values are listed (divided by commas), the data were reported individually in 165 DCN 

SGE00602 by different sources.

Abbreviations: mg/L—milligrams per liter; NA—not available

Because all POTWs are required to control TSS and 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 BOD5 permit limit 

exceedances with the acceptance of oil and gas extraction wastewater.

The following subsections present case studies that discuss inhibition/disruption at 

POTWs that accepted wastewater containing pollutants found in UOG extraction wastewater. 

The purpose of these subsections is to identify instances of inhibition/disruption, or potential 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

131 

inhibition/disruption, at POTWs associated with the acceptance of UOG extraction wastewater 

pollutants. 

5.3.2.1 Case Studies About POTWs Accepting Wastewater from Oil and Gas 

Extraction Facilities 

Johnstown, PA, POTW

The Johnstown POTW uses screening, grit removal, high-purity oxygen activated sludge 

aeration with integrated fixed-film activated sludge, final clarification, and chlorination (133

DCN SGE00930). The Johnstown POTW accepted both UOG and COG wastewater before 2008 

and stopped accepting both in 2011 (46 DCN SGE00739). The total oil and gas wastewater 

accounted for less than 3 percent of the total POTW influent volume during the acceptance 

period on average. The POTW’s annual average daily flow rate ranges between 9.0 and 10.5 

MGD based on 2008 through 2013 DMR data (175 DCN SGE00608). 

The EPA created Figure D-13 using the sampling data submitted in its DMR Loading 

Tool (175 DCN SGE00608) and PA DEP waste reports data (46 DCN SGE00739). Each effluent 

concentration data point represents the average of 12 monthly average data points as calculated 

and reported by the Loading Tool. PA DEP waste reports provided the total volume of UOG and 

COG wastewater delivered to the POTW each year. The EPA divided the annual volume by 365 

to calculate the annual average daily flow. As shown in Figure D-13, the Johnstown POTW 

experienced a much larger number of permit limit exceedances during the period when they were 

accepting the greatest volume of oil and gas extraction wastewater. In a December 2012 letter 

regarding the 2011 annual pretreatment report, Johnstown’s pretreatment coordinator stated, 

[We] know that the treatment plant no longer accepts gas drilling waste,116 and we 

anticipate that the number of violations will decrease. 

Further, Section C.3.2.1 presents data showing that TSS concentrations in drilling 

wastewater may be higher than TSS concentrations in UOG produced water.

117 The PA DEP 

waste reports data show that the Johnstown POTW accepted more drilling wastewater than any 

other POTW in Pennsylvania from 2008 through 2011. The POTW accepted the largest volume

of drilling wastewater in 2009 and 2010, which totaled over 15 million gallons and accounted for 

over 40 percent of the total influent oil and gas wastewater accepted by the POTW. In total, the 

Johnstown POTW experienced 27 TSS permit limit exceedances from 2008 through 2011, 18 of 

which were in 2009 and 2010. The POTW also experienced elevated effluent TSS concentrations 

in 2009 (61 mg/L). 

 

116 The EPA assumes that this phrase refers to both COG wastewater and UOG extraction wastewater.

117 Drilling wastewater initially includes cuttings (i.e., solids) that are partially removed by the operator before 

management or disposal. Any cuttings that remain may contribute to elevated TSS concentrations.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

132 

Figure D-13. Johnstown POTW: Annual Average Daily Effluent Concentrations and 

POTW Flows

Sources: 52 DCN SGE00929

California, PA, POTW

The California POTW uses a contact stabilization118 process to treat influent wastewater 

(10 DCN SGE00787). In 2008 and 2009, the California POTW accepted both UOG and COG 

wastewater. The total oil and gas wastewater accounted for up to 33 percent of the total POTW 

influent volume during 2008, on average. UOG extraction wastewater accounted for 14 percent 

of total POTW influent during 2008, on average (46 DCN SGE00739). The POTW’s average 

annual daily flow rate ranges between 0.5 and 0.8 MGD based on 2008 through 2013 DMR data 

(175 DCN SGE00608). 

The EPA created Figure D-14 using the sampling data submitted in its DMR Loading 

Tool (175 DCN SGE00608) and PA DEP waste reports data (46 DCN SGE00739). Each effluent 

concentration data point represents the average of 12 monthly average data points as calculated 

 

118 Contact stabilization is a two-stage activated sludge process, consisting of a 30 to 60 minute absorptive phase 

followed by a one to two hour oxidation phase. Aeration volume requirements are half of those for conventional 

activated sludge (119 DCN SGE00167).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

133 

and reported by the DMR Loading Tool. PA DEP waste reports provided the total volume of 

UOG and COG wastewater delivered to the POTW each year. The EPA divided the annual 

volume by 365 to calculate the annual average daily flow. As shown in Figure D-14, the 

California POTW experienced elevated concentrations of TSS and BOD5 while accepting oil and 

gas wastewater. Figure D-14 also shows that the California POTW experienced three 

exceedances of its TSS permit limits119 and one exceedance of its BOD5 permit limits.

120

Figure D-14. California POTW: Annual Average Daily Effluent Concentrations and 

POTW Flows

Sources: 52 DCN SGE00929

Charleroi, PA, POTW

The Charleroi POTW was introduced and described in more detail in Section D.5.3.1 of 

this TDD. 

The EPA created Figure D-15 using the sampling data submitted in its DMR Loading 

Tool (175 DCN SGE00608) and PA DEP waste reports data (46 DCN SGE00739). Each effluent 

 

119 The California POTW had a monthly average TSS limit of 30 mg/L and a daily maximum TSS limit of 45 mg/L 

from 2008 through 2013.

120 The California POTW had a monthly average BOD5 limit of 25 mg/L and a daily maximum BOD5 limit of 37.5 

mg/L from 2008 through 2012. In 2013, its daily maximum BOD5 limit changed to 40 mg/L.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

134 

concentration data point represents the average of 12 monthly average data points as calculated 

and reported by the Loading Tool. PA DEP waste reports provided the total volume of UOG and 

COG wastewater delivered to the POTW each year. The EPA divided the annual volume by 365 

to calculate the annual average daily flow. As shown in Figure D-15, the Charleroi POTW 

experienced elevated concentrations of TSS and BOD5 while accepting UOG extraction 

wastewater. 

Sources: 52 DCN SGE00929

Figure D-15. Charleroi POTW: Annual Average Daily Effluent Concentrations and POTW 

Flows121

Waynesburg, PA, POTW

The Borough of Waynesburg POTW accepted gas-exploration-related wastewater, hauled 

directly from operators, from June 2006 to November 2008. Gas well wastewater made up about 

2 percent of total inflow in 2006. The percentage increased to 8.1 percent in 2007 and 9.5 percent

 

121 Figure D-15 only shows data for 2008 through 2011 because there is no PA DEP waste report data or DMR 

Loading Tool data for the Charleroi POTW for 2012 or 2013.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

135 

in 2008. The Waynesburg POTW’s average annual daily flow rate ranged between 0.37 and 0.62 

MGD over those three years. The treatment process at Waynesburg POTW is as follows: two 

primary clarifiers, a trickling filter, a bio-tower, a final clarifier, and chlorine disinfection (12

DCN SGE00997, 13 DCN SGE00997.A01). 

The Waynesburg POTW received a CWA §308 Request for Information from EPA 

Region 3 in February 2009. In March 2009, the Waynesburg POTW responded with a “Process 

Impact Evaluation” (14 DCN SGE00750), which stated that: 

The amount of well water that was being accepted to the treatment facility has had no 

adverse effects on the trickling filter and the bio-tower except on one occasion in 2007. A 

hauler delivered a batch of well water that impacted the biological growth within the 

trickling filter. The water was believed to be frac water which possesses a high salinity 

which in turn impacted the biological growth in the trickling filter. 

5.3.2.2 Case Studies About POTWs Accepting Wastewater from Other Industrial 

Sources Containing UOG Pollutants (e.g., CWT Facilities) 

New Castle, PA, POTW

The New Castle POTW accepted industrial wastewater from the Advanced Waste 

Services CWT facility, which treats oil and gas wastewater. Advanced Waste Services CWT

facility treats “pretreated brine” (industrial wastewater) using solids settling, surface oil 

skimming, and pH adjustment. If influent wastewater does not meet Advanced Waste Services’ 

pretreatment permit requirements, the facility applies additional treatment with flocculants (223

DCN SGE00554).

In its 2009 annual report to EPA Region 3, the New Castle POTW identified numerous 

violations of its NPDES permit limits for discharges of TSS. It also identified significant 

increases in the volume of industrial wastewater that it was receiving (see Table D-23) from 

Advanced Waste Services. New Castle’s 2009 annual report does not include the total volume of 

wastewater it treated, but its 2013 NPDES permit indicates that all permit limits were based on 

an effluent discharge rate of 17 MGD (223 DCN SGE00554; 134 DCN SGE00573).

Table D-23. Industrial Wastewater Volumes Received by New Castle POTW (2007–2009)

Year Industrial Wastewater Volume (gpd) Percent of Total Volume Treated by POTWa

2007 74,278 0.44%

2008 130,608 0.77%

2009 331,381 1.95%

Source: 223 DCN SGE00554

a—Assuming 17 MGD is the total volume treated. 

The 2009 annual report (223 DCN SGE00554) states that: 

It is believed that pretreated brine wastewater from the developing oil & gas industry is 

adversely affecting the ability of the final clarifiers to separate solids via gravity settling. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

136 

This has resulted in higher sludge blanket levels that are more easily upset and washed 

out during rainfall-induced high flow events. The Authority has begun using polymer 

flocculation to enhance settling with some success. However, there were numerous 

effluent TSS violations in 2009. 

As noted in the annual report, instability in sludge blanket levels can cause increased 

washouts during large rain events, which may cause interference with biological treatment. New 

Castle reported 19 violations of its NPDES permit limits for TSS, believed to be caused by the 

acceptance of UOG extraction wastewater via the Advanced Waste Services CWT facility’s 

industrial discharge (223 DCN SGE00554). The EPA compared the violations in 2009 to the 

violations that occurred in 2011, after the New Castle POTW stopped accepting industrial 

discharges from the CWT facility (i.e., violations between May and December 2011). The EPA

identified two TSS violations during this nine-month time frame. Table D-24 shows detailed 

information about the violations in 2009 and 2011, including when they occurred, the measured 

values, and the percentage over the NPDES permit limit. The decrease in the number of TSS 

violations from 2009 to 2011, after the POTW stopped accepting industrial discharges from the 

Advanced Waste Services CWT facility, suggests that the UOG extraction wastewater pollutants 

were a contributing cause of the violations. However, the two violations in 2011 indicate that the 

UOG extraction wastewater was likely not the sole cause of interference with treatment 

processes at the POTW.

Table D-24. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW 

(NPDES Permit Number PA0027511) 

Month, Year Parameter Sample Type

NPDES Permit 

Limit (mg/L)

Measured 

Value (mg/L)

Percentage Over 

Permit Limit (%)

March 2009 TSS Weekly maximum 45 58 29

March 2009 TSS Monthly average 30 37 23

May 2009 TSS Monthly average 30 34 13

June 2009 TSS Monthly average 30 38 27

July 2009 TSS Weekly maximum 45 64 42

July 2009 TSS Monthly average 30 45 50

August 2009 TSS Weekly maximum 45 61 36

August 2009 TSS Monthly average 30 50 67

September 2009 TSS Monthly average 30 37 23

October 2009 TSS Weekly maximum 45 46 2

October 2009 TSS Monthly average 30 31 3

January 2010 TSS Weekly maximum 45 60 33

January 2010 TSS Monthly average 30 40 33

February 2010 TSS Monthly average 30 33 10

March 2010 TSS Monthly average 30 38 27

March 2010 TSS Weekly maximum 45 55 22

November 2010 TSS Monthly average 30 34 13

November 2010 TSS Weekly maximum 45 55 22

December 2010 TSS Weekly maximum 45 56 24

November 2011 TSS Monthly average 30 35 17
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

137 

Table D-24. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW 

(NPDES Permit Number PA0027511) 

Month, Year Parameter Sample Type

NPDES Permit 

Limit (mg/L)

Measured 

Value (mg/L)

Percentage Over 

Permit Limit (%)

November 2011 TSS Weekly maximum 45 64 42

Sources: 169 DCN SGE00620; 185 DCN SGE00612

Abbreviation: mg/L—milligrams per liter

Wheeling, WV, POTW

The Wheeling POTW, introduced in Section D.5.3.1, accepted industrial wastewater 

from the LAD CWT facility, which treats oil and gas wastewater122. A 2011 Consent Order 

issued to the Wheeling POTW by the WV DEP indicates that the POTW experienced 

interference with biological treatment from accepting UOG extraction wastewater via the CWT

facility’s industrial discharge. The Order describes the following timeline of events (219 DCN 

SGE00485): 

• July 21, 2009—the Wheeling POTW experienced an upset that required several 

weeks of “vigilant action to recover” and included the introduction of a “seed” sludge 

from a nearby POTW. Plant upset conditions occurred during periods when the 

POTW exceeded discharge limits for fecal coliform and TSS.

• August 21, 2009—Meeting minutes from a meeting between Wheeling POTW and 

LAD CWT facility stated that Wheeling was accepting oil and gas wastewater “well 

above the 1% that is allowed.” The minutes also said that Wheeling was concerned 

about the lack of diversity in microorganisms and that the wastewater from LAD was 

the cause of the lack of microbial diversity. 

• November 17, 2009—WVDEP inspected Wheeling POTW and noted that “[t]he 

discharge from Wheeling was slightly turbid and causing a crispy white foam in the 

receiving stream.” In addition, the Wheeling POTW experienced operational 

interference, inefficiency, or possible upset indicated by several factors including an 

increased chlorine demand, loss in effluent clarity, UV disinfection failures, and 

suspicious odors. 

• May 6, 2010—Wheeling POTW representatives met with WV DEP representatives to 

discuss the draft Consent Order. The Order included numerous requirements 

including one that stated, “Upon entry of this Order, Wheeling shall continue to cease 

and desist acceptance of all oil and gas wastewater.”

Brockway, PA, POTW

The Brockway POTW, introduced in Section D.5.3.1, was still accepting natural-gasrelated wastewater treated by the Dannic 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 

 

122 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.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

138 

2008 and noticed an increase in sludge generation.

123 The POTW operators noticed a scum layer 

forming on the clarifiers because of a combination of calcium in the oil and gas wastewater and 

soaps/fats in the typical POTW influent wastewater. In addition to the scum layer on the 

clarifiers, the POTW experienced increased sludge generation and high concentrations of barium 

in the sludge (sludge barium content = 1,490 mg/kg). However, the POTW ran a hazardous 

waste determination and found that the barium content was below the hazardous waste 

classification threshold (99 DCN SGE00753). 

5.3.2.3 POTW Sludge and Scale Formation 

UOG extraction wastewater is also a concern in the disruption of POTW sludge 

processes, including sludge disposal, and the disruption of POTW operations as a result of 

excessive scale formation. For example, POTWs that accept and treat wastewater high in heavy 

metals (e.g., nickel, copper, zinc) face the potential for heavy metals accumulation in sludge. A 

POTW accepting wastewater with high metals concentrations may no longer be able to landapply its sludge because it may violate sludge disposal rules. 

While UOG extraction wastewater does not typically contain concentrations of heavy 

metals at levels that would likely prohibit the POTW from land-applying its sludge (see Table 

C-17), the EPA has identified the potential for elevated concentrations of radium-226 and -228 in 

sludge (172 DCN SGE00136; 135 DCN SGE01028). State and federal regulations for the 

transport and disposal of radioactive waste may limit the POTW’s options for managing sludge 

contaminated with radium and other radioactive materials derived from UOG extraction 

wastewater. POTWs with sludge containing radioactive materials may resort to underground 

injection in a Class I well124, disposal at a hazardous waste landfill125, or disposal at a low-level 

radioactive waste landfill126 (189 DCN SGE00615). 

In addition to inhibiting the performance of treatment operations, UOG extraction 

wastewater may disrupt POTW operations as a result of excessive scale formation. Scale 

typically accumulates on valves, pipes, and fittings and, therefore, may interfere with POTW 

operation (e.g., restrict flow to unit processes). Scale is produced from deposits of divalent 

cations (e.g., barium, calcium, magnesium) that precipitate out of wastewater. Figure D-16

shows an example of barium sulfate scaling in an oil and gas pipe in the Haynesville shale 

formation. 

 

123 The EPA is not aware of any time when the Brockway POTW accepted UOG extraction wastewater. 124 Class I underground injection wells are used to inject hazardous wastes, industrial non-hazardous liquids, or 

municipal wastewater beneath the lowermost underground source of drinking water.

125 Hazardous waste landfills are regulated under RCRA Subtitle C. Some hazardous waste landfills are permitted to 

accept TENORM waste, while others have to request state approval before accepting TENORM waste.

126 Low-level radioactive waste landfills are licensed by the U.S. Nuclear Regulatory Commission or by a state 

under agreement with the Commission. These landfills provide a disposal option for wastes with radionuclide 

concentrations that are unable to be disposed of at municipal, industrial, or hazardous waste landfills.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

139 

Figure D-16. Barium Sulfate Scaling in Haynesville Shale Pipe

Source: 152 DCN SGE00768.A26

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 radium127 behaves like other divalent cations, it may also 

accumulate in scale and form TENORM: technologically-enhanced naturally occurring 

radioactive material, defined as naturally occurring radioactive materials that have been 

concentrated or exposed to the accessible environment as a result of human activities such as 

manufacturing, mineral extraction, or water processing (e.g., in treatment processes at a POTW).

PA DEP’s 2015 study report128 (135 DCN SGE01028) provides the following examples of solids 

that may contain TENORM: drill cuttings, filter sock residuals, impoundment sludge, tank 

bottom sludge, pipe scale, wastewater treatment plant sludge, and soils129. The PA DEP 

TENORM study report concludes that “There is little potential for radiological exposure to 

workers and members of the public from handling and temporary storage of filter cake at 

POTWs. However, there is a potential for radiological environmental impacts from spills and the 

long-term disposal of POTW filter cake.” The PA DEP TENORM study report includes the 

following recommendations for future action: 

• “Perform routine survey assessment of areas impacted with surface radioactivity to 

determine personal protective equipment (PPE) use and monitoring during future 

activity that may cause surface alpha and beta radioactivity to become airborne.” 

 

127 Radium is a naturally occurring radioactive element that ionizes in water to a divalent cation with chemical 

properties similar to barium, calcium, and strontium.

128 PA DEP initiated a study to collect data related to TENORM associated with oil and gas operations in 

Pennsylvania, including assessment of potential worker and public radiation exposure, TENORM disposal, and 

other environmental impacts.

129 PA DEP’s 2015 TENORM study sampled the following types of solids: surface soil impacted by sediments, filter 

cakes, soils, sludge, drill cuttings, drilling muds, proppant sand, and filter socks. PA DEP identified pipe scale as a 

source of TENORM, but did not sample for pipe scale in their 2015 TENORM study.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

140 

• “Conduct additional radiological sampling and analyses and radiological surveys at 

all WWTPs accepting wastewater from O&G operations to determine if there are 

areas of contamination that require remediation; if it is necessary to establish 

radiological effluent discharge limitations; and if the development and 

implementation of a spill policy is necessary.” 

The Marcellus shale formation is known to contain radium and, therefore, is of particular 

concern for TENORM generation (172 DCN SGE00136; 28 DCN SGE00519; 150 DCN 

SGE00587). 

Rowan et al. (145 DCN SGE00241) report a positive correlation between 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 (135 DCN SGE01028) also looked into potential 

worker exposure, TENORM disposal options, and environmental impacts. PA DEP analyzed 

liquid and solid samples for alpha, beta, and gamma radiation and gas samples for radon. PA 

DEP sampled the following types of facilities, among others, as part of their study: 

• Well sites – PA DEP sampled 38 well sites (4 conventional wells and 34 

unconventional wells) from June 2013 through July 2014; and

• Wastewater treatment plants – PA DEP sampled 29 wastewater treatment plants (10 

POTWs, 10 CWT facilities, and 9 zero liquid discharge (ZLDs) facilities).

PA DEP presents sample data of filter cakes from POTWs receiving oil and gas

wastewater that showed “Ra-226 and Ra-228 present above typical background concentrations in 

soil. The average Ra-226 result was 20.1 pCi/g with a large variance in the distribution, and the 

maximum result was 55.6 pCi/g. The average Ra-228 result was 8.32 pCi/g, and the maximum 

result was 32.0 pCi/g Ra-228.” (135 DCN SGE01028) 

PADEP concluded, “...[t]here is little potential for radiological exposure to workers and 

members of the public from handling and temporary storage of filter cake at POTW-I’s

130. 

However, there is a potential for radiological environmental impacts from spills and the longterm disposal of POTW-I filter cake” (135 DCN SGE01028). ERG’s Radioactive Materials in 

the Unconventional Oil and Gas (UOG) Industry memorandum (54 DCN SGE00933) provides 

additional information and results from the PA DEP study.

 

130 PA DEP defines a “POTW-I” as a POTW that was considered to be influenced by having received wastewater 

from the oil and gas industry.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

141 

5.3.3 Potential Impacts of DBP Precursors in UOG 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 DBPs. UOG extraction wastewater 

often contains elevated levels of bromide (see Table C-13) and chloride, which is a precursor of 

several toxic DBPs (15 DCN SGE00509; 214 DCN SGE00754). Brominated DBPs are reported 

to have greater health risks (e.g., higher risk of cancer) than chlorinated DBPs (118 DCN 

SGE00800). 

UOG extraction wastewater discharged to POTWs would be a potential source of DBPs 

in two scenarios: 

• When UOG extraction wastewater is disinfected at a POTW (90 DCN SGE00535) 

• When a POTW discharges wastewater including UOG extraction wastewater

pollutants to a river that is used as a source water for a downstream drinking water 

treatment plant where disinfection is used (150 DCN SGE00587) 

5.3.3.1 UOG Extraction Wastewater Disinfection at POTWs

DBPs 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 DBPs. Hladik et al. investigated whether POTW 

treatment of wastewater from COG and UOG operations (hereafter referred to as “oil and gas

wastewater”) could create DBPs, particularly brominated DBPs (90 DCN SGE00535). 

Hladik et al. sampled effluent from three Pennsylvania POTWs, one POTW that did not 

accept oil and gas wastewater (POTW 1) and two that accepted oil and gas wastewater from oil 

and gas operators (POTW 2, POTW 3). The daily average discharge for POTW 1 was 

approximately 1,200 MGD. The daily average discharges for POTWs 2 and 3 were not reported, 

but the amount of oil and gas wastewater accepted at the POTWs was reported as ranging from 

2.3 million gallons to 2.9 million gallons in 2012. Grab samples were collected in the river where 

the POTW effluent entered and were analyzed for 29 DBPs. 

Table D-25 presents sampling results showing higher concentrations of DBPs 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 DBPs in chlorinated POTW effluent. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

142 

Table D-25. Concentrations of DBPs in Effluent Discharges at One POTW Not Accepting 

Oil and Gas Wastewater and at Two POTWs Accepting Oil and Gas Wastewater (μg/L)

Facility Identifier POTW 1 POTW 1 POTW 2 POTW 3

MDL Sample Date 8/20/2012 11/28/2012 4/17/2013 4/17/2013 a

Accepted Oil and Gas Wastewater No No Yes Yes

Bromochloroiodomethane ND ND 0.10 0.12 0.02

Bromodichloromethane BDLb ND BDLb BDLb 0.10

Bromodiiodomethane ND ND 0.09 0.20 0.02

Bromoform 0.03 0.04 10.1 9.2 0.02

Chloroform 0.02 0.05 0.20 0.13 0.02

Dibromo-chloro-methane 0.05 0.05 0.83 0.51 0.02

Dibromoiodomethane ND ND 0.98 1.3 0.02

Dichloroiodomethane ND ND BDLb BDLb 0.04

Source: 90 DCN SGE00535

Note: The EPA presents data for eight DBPs in Table D-25. Hladik et al. (90 DCN SGE00535) collected data for 

29 DBPs. The concentrations of DBPs in the effluent of POTWs that had accepted oil and gas wastewater were 

higher than the concentrations in POTWs that had not accepted oil and gas wastewater in all but three samples.

a—Method detection limits (MDLs) in surface water samples, as reported by Hladik et al. (90 DCN SGE00535). 

b—Below method detection limit (BDL) indicates a value reported by Hladik et al. that was lower than the MDL. 

The EPA reported these values as BDL instead of reporting the values from Hladik et al. (90 DCN SGE00535).

Abbreviation: ND—non detect

5.3.3.2 Drinking Water Treatment Disinfection Downstream of POTWs

DBPs 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 DBPs (e.g., brominated 

trihalomethanes), downstream of POTWs that accepted UOG extraction wastewater (81 DCN 

SGE00567; 150 DCN SGE00587). 

Wilson and Van Briesen (226 DCN SGE00633) also investigated whether effluent 

discharges from POTWs were causing high TDS and bromide concentrations that would 

negatively impact drinking water treatment plants. They note that

Like TDS, bromide is not removed at drinking water treatment plants. Thus, produced 

water management that leads to increased concentrations of bromide in source waters 

for drinking water treatment plants can lead to increased concentrations of DBPs in 

drinking water. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

143 

Wilson and Van Briesen later conclude that

Produced water management decisions should be informed by the potential contribution 

of this wastewater to the formation of disinfection by-products in downstream drinking 

water treatment plants. 

States et al. (150 DCN SGE00587) conducted a drinking water treatment plant survey 

and investigated bromide concentrations in the untreated river water intake and trihalomethanes 

(THMs) (i.e., chloroform, bromoform, dibromochloromethane, bromodicholoromethane) in the 

treated, “finished” drinking water. States et al. drew the following conclusions from their study: 

• Elevated bromide concentrations in the influent to the studied drinking water 

treatment plant resulted in increased concentrations of certain DBPs, particularly 

brominated THMs, in the drinking water. 

• Drinking water treatment plants cannot effectively remove bromide from intake 

water.

• POTWs discharging treated UOG extraction wastewater (specifically from the 

Marcellus shale formation) were major contributors to the increase in bromide in the 

drinking water treatment plant intake during the period of the study. 

In February 2013, Eshelman and Elmore published a report for the Maryland Department 

of the Environment titled Recommended Best Management Practices for Marcellus Shale Gas 

Development in Maryland (69 DCN SGE00735). The report discussed POTW management of 

UOG extraction wastewater and specifically noted that this is not a best management practice. 

They further reported that the discharge of high-TDS loads into surface waters that could be 

drinking water treatment intakes should be prohibited. Eshelman and Elmore state that, 

Higher chloride levels cause taste and odor problems in finished water. High bromide 

levels lead to increased formation of carcinogenic disinfectant by-products that can 

persist in the water to the point of consumption. Treatment of produced water by POTWs 

and other conventional wastewater treatment methods that do not remove salts should be 

prohibited in Maryland. 

McTigue et al. published an article about the occurrence and consequences of bromide in 

drinking water sources (118 DCN SGE00800). They note that UOG extraction wastewater may 

contribute to recent increases in bromide-containing waste upstream of drinking water utilities, 

and thus to the increase in DBPs reported by the drinking water utilities. The authors provide an 

example of an unnamed water treatment plant (WTP E) that began experiencing influent water 

with high TDS concentrations in 2008, around the same time that UOG extraction operations 

began in the area. Figure D-17 shows the average quarterly total THM speciation from 1999 

through 2013, which shows a decrease in chlorinated DBPs and an increase in brominated DBPs 

starting around 2008. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

144 

Abbreviations: TTHM MCL – total trihalomethane maximum contaminant level

Source: 118 DCN SGE00800. 

Figure D-17. THM Speciation in a Water Treatment Plant (1999–2013) 

Another example of concerns about DBP 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 (non detect) 

• Bromodichloromethane (non detect) 

• Dibromochloromethane (non detect) 

• Bromoform (74 μg/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 DBPs. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

145 

In August 2013, EPA Region 3 issued a letter (187 DCN SGE00935) informing the 

NPDES permitting authorities in the Mid-Atlantic region that 

...conventional and nonconventional pollutants, such as bromide, must be tested by 

existing dischargers as part of the permit application process if such pollutants are 

expected to be present in effluent.

The letter goes on to state that EPA Region 3 has reason to believe that industrial 

discharges (including UOG extraction wastewater discharges) containing bromide contributed to 

elevated levels of bromide in rivers and streams that resulted in downstream impacts at drinking 

water treatment plants, including increased occurrence of DBPs. Therefore, if the parameter is 

not limited in an applicable ELG, NPDES permit applicants must either describe why the 

parameter is expected in their discharges or include quantitative data for the parameter. These 

requirements apply to the following parameters of interest in UOG extraction wastewater, among 

others (195 DCN SGE00935.A01): 

• TDS

• Chloride 

• Bromide 

• Sulfate

• Fluoride 

• Aluminum, total

• Barium, total

• Iron, total 

• Manganese, total

• Radium-226/228 

• Arsenic, total

• Selenium, total

• Benzene

• Bromoform

• Chlorobenzene 

• Chloroform 

• Ethylbenzene 

• Toluene 

• Phenol 

• Naphthalene 

• Alpha-BHC

• Beta-BHC

Parker et al. published an article in September 2014 (129 DCN SGE00985) that evaluated 

the minimum volume of UOG produced water from Marcellus shale and Fayetteville shale wells 

that, when diluted by fresh water, would generate and/or alter the formation and speciation of 

DBPs 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 DBPs. 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 DBPs. The results also show that UOG 

produced water dilution as low as 0.03 percent increases the overall formation of DBPs. 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. 
Chapter E—Reference Flags and List

146

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-1.

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-1. Source List

ID DCN Source Citation 

Source 

Flag

1 SGE00046 Abdalla, Charles W.; Drohan , Joy R.; Blunk, Kristen S.; Edson, Jessie. 2011. 

Marcellus Shale Wastewater Issues in Pennsylvania—Current and Emerging 

Treatment and Disposal Technologies. Penn State Cooperative Extension, 

College of Agricultural Sciences. 

B

2 SGE00932 Abt Associates. 2015. Profile of the Oil and Gas Extraction (OGE) Sector, 

with Focus on Unconventional Oil and Gas (UOG) Extraction. (February 18).

A

3 SGE00070 Acharya, Harish; Matis, Hope; Kommepalli, Hareesh; Moore, Brian; Wang, 

Hua. 2011. Cost Effective Recovery of Low-TDS Frac Flowback Water for 

Re-use. Prepared by GE Global Research. Prepared for US DOE NETL. 

Morgantown, WV. (June).

A 

4 SGE00723 Agency for Toxic Substances & Disease Registry (ATSDR). 2006. Hydrogen 

Sulfide ToxFAQs. (July).

A

5 SGE00497 Angelo, Tom. 2013. From Pilot Study to Daily Processing: Warren, Ohio’s 

Documentary to Hydraulic Fracturing Water Treatment. City of Warren, 

Ohio, Water Pollution Control Department. Presentation at EPA’s Study of 

Hydraulic Fracturing and Its Potential Impact on Drinking Water Resources: 

Wastewater Treatment and Related Modeling Technical Workshop. April 18, 

2013.

A

6 SGE00499 Arkansas Oil and Gas Commission (AOGC). 2013. Welcome to the Arkansas 

Oil and Gas Commission Online Production and Well Information. Accessed 

on 6/14/2013.

A
Chapter E—Reference Flags and List

147

Table E-1. Source List

ID DCN Source Citation 

Source 

Flag

7 SGE00504 Baker Hughes. 2013. North America Rotary Rig Count (Jan 2000–Current). 

(November 15). Downloaded on 11/20/2013. Available online at: 

http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-reportsother 

B

8 SGE00502 Baker Hughes. 2013. North America Rotary Rig Count Pivot Table (Feb 

2011–Current). (November 8). Downloaded on 11/11/2013. Available online 

at: http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-reportsother 

B 

9 SGE00503 Baker Hughes. 2013. U.S. Onshore Well Count. (October 11. Downloaded on 

11/11/2013. Available online at: http://phx.corporateir.net/phoenix.zhtml?c=79687&p=irol-wellcountus# 

B

10 SGE00787 Borough of California. 2009. 

for Information. (March 18).

Borough of California Response to 308 Request A

11 SGE00751 Borough of Charleroi. 2008. Re: Authority of the Borough of Charleroi 

Administrative Order. (November 21).

A

12 SGE00997 Borough of Waynesburg. 2009. Clean Water Act Section 308 Request 

Information.

for A

13 SGE00997.A01 Borough of Waynesburg. 2009. Clean Water Act Section 308 Request 

Information—Attachment 1: Acceptance Records.

for A 

14 SGE00750 Borough of Waynesburg. 2009. Waynesburg Response to Clean Water Act 

Section 308 Request for Information. (March 31).

A

15 SGE00509 Brown, Daniel; Bridgeman, John; West, John R. 2011. Predicting Chlorine 

Decay and THM Formation in Water Supply Systems. Reviews in 

Environmental Science and Bio/Technology 10:79–99.

A

16 SGE00110 Bruff, Matthew. 2011. An Integrated Water Treatment Technology Solution 

for Sustainable Water Resource Management in the Marcellus Shale. 

Prepared by Altela, Inc., Argonne National Laboratory, BLX, Inc., and CWM 

Environmental, Inc. DE-FE0000833.

A

17 SGE01009 Caen, R., Darley, H.C.H., and G. R. Gray. 2011. Composition and Properties 

of Drilling and Completion Fluids. 6th edition. Gulf Professional Publishing: 

Waltham, MA.

B

18 SGE00966 California Council on Science and Technology (CCST). 2014. Advanced 

Well Stimulation Technologies in California: An Independent Review of 

Scientific and Technical Information. Sacramento, CA.

A 

19 SGE00367 CARES. n.d. CARES McKean. Downloaded on 1/28/2013. C

20 SGE00305.A03 Cheung, Timothy. 2012. Identifying the Recycling and Treatment Criteria 

That Must be Met to Avoid Scaling and Enable Successful Reuse. Shell.

C

21 SGE00749 City of Clarksburg. 2009. Re: Clean Water 

Information. (March 2).

Act Section 308 Request for A

22 SGE01000 City of Wheeling Water Pollution Control Division. 2007. Wheeling Effluent 

Data.

A

23 SGE00366 Clarion Altela Environmental Services (CAES). n.d. CAES 

Downloaded on 1/28/2013.

Overview. C
Chapter E—Reference Flags and List

148

Table E-1. Source List

ID DCN Source Citation 

Source 

Flag

24 SGE00354 Clark, C.E.; Han, J.; Burnham, A.; Dunn, J.B.; Wang, M. 2011. Life-Cycle 

Analysis of Shale Gas and Natural Gas. Argonne National Laboratory. 

ANL/ESD/11-11.

A

25 SGE00182 Clark, C.E.; Veil, J.A. 2009. Produced Water Volumes and Management 

Practices in the United States. ANL/EVS/R-09/1. Argonne National 

Laboratory. (September)

A 

26 SGE00516 Cochener, John. 2010. Quantifying Drilling Efficiency. U.S. EIA, Office of 

Integrated Analysis and Forecasting. (June 28).

A

27 SGE00357 Cramer, John. 2011. Post-frac 

Superior Well Services. 

Flowback Analysis and Reuse Implications. B

28 SGE00519 Davies, Peter J. n.d. Radioactivity. Cornell University. B

29 SGE00520 Drillinginfo. 2011. DI Desktop® December 2011 Download. Drillinginfo, 

Inc.

B

30 SGE00331 Ely, John W.; Horn, Aaron; Cathey, Robbie; Fraim, Michael; Jakhete, 

Sanjeev. 2011. Game Changing Technology for Treating and Recycling Frac 

Water. Society of Petroleum Engineering. SP SPE-214545-PP.

A

31 SGE00989 Energy Information Administration (EIA). 2014. Annual Energy Outlook 

2014 with Projections to 2040. DOE/EIA-0383(2014).

A

32 SGE00988 Energy Information Administration (EIA). 2014. Assumptions to the 

Energy Outlook 2014.

Annual A

33 SGE00984 Energy Information Administration (EIA). 2014. Glossary. 

http://www.eia.gov/tools/glossary

Retrieved from A

34 SGE00708 Environmental Leader. 2013. Unconventional E&P “$8 Billion of US Water 

Services Market.” (November 11).

B

35 SGE00522 Environmental Review Appeals Commission, State of Ohio. 2012. Patriot 

Water Treatment, LLC, and City of Warren v. Chris Korleski, Director of 

Environmental Protection, and Scott Nally, Director of Environmental 

Protection: 2012 Decision.

A

36 SGE00244 ERG. 2012. Camp, Meghan; Bicknell, Betsy; Ruminski, Brent. Notes on 

Conference Call with 212 Resources on 4 January 2012. (January 9).

A

37 SGE00245 ERG. 2012. Camp, Meghan; Bicknell, Betsy; Ruminski, Brent. Notes on 

Conference Call with Reserved Environmental Services, LLC on 5 January 

2012. (February 1).

A

38 SGE00521 ERG. 2012. Camp, Meghan; Ruminski, Brent. Notes 

Meeting Held on 29 February 2012. (April 20).

for Shale Gas Industry A

39 SGE00283 ERG. 2012. Camp, Meghan; Ruminski, Brent. Notes on 

BLX, Inc on 15 May 2012. (June 11).

Conference Call with A

40 SGE00705 ERG. 2014. Ruminski, Brent. Notes on Call 

February 2014. (March 7.)

with Hydrozonix, LLC on 7 A 

41 SGE00736 ERG. 2015. Analysis of Active Underground Injection for Disposal Wells. A

42 SGE00736.A01 ERG. 2015. Analysis of 

Attachment 1: Injection

Active Underground Injection for Disposal Wells—

 for Disposal Well Data.

A
Chapter E—Reference Flags and List

149

Table E-1. Source List

ID DCN Source Citation 

Source 

Flag

43 SGE00596 ERG. 2015. Analysis of Centralized Waste Treatment 

Accepting UOG Extraction Wastewater.

(CWT) Facilities A

44 SGE00596.A01 ERG. 2015. Analysis of Centralized Waste Treatment Facilities (CWTs)

Accepting UOG Wastewater Attachment 1: UOG CWT List and Analysis.

A

45 SGE00963 ERG. 2015. Analysis of DI Desktop® Memorandum. A

46 SGE00739 ERG. 2015. Analysis of Pennsylvania Department of Environmental 

Protection’s (PA DEP) Oil and Gas Waste Reports.

A

47 SGE00739.A03 ERG. 2015. Analysis of Pennsylvania Department of Environmental 

Protection’s (PA DEP) Oil and Gas Waste Reports.

A

48 SGE00693 ERG. 2015. Data Compilation Memorandum for the Technical Development 

Document (TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction. Office of Water Engineering and 

Analysis Division.

A

49 SGE00693.A01 ERG. 2015. Data Compilation Memorandum for the Technical Development 

Document (TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction —Attachment 1: Onshore Oil and Gas 

Drilling Activity.

A

50 SGE00693.A02 ERG. 2015. Data Compilation Memorandum for the Technical Development 

Document (TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction —Attachment 2: EIA UOG Resource 

Potential.

A

51 SGE00693.A03 ERG. 2015. Data Compilation Memorandum for the Technical Development 

Document (TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction —Attachment 3: TDD Data 

Compilation.

A

52 SGE00929 ERG. 2015. Publicly Owned Treatment Works (POTW) Memorandum for the 

Technical Development Document (TDD) for Proposed Effluent Limitations 

Guidelines and Standards for Oil and Gas Extraction

A

53 SGE00929.A01 ERG. 2015. Publicly Owned Treatment Works (POTW) Memorandum for the 

Technical Development Document (TDD) for Proposed Effluent Limitations 

Guidelines and Standards for Oil and Gas Extraction —Attachment 1: 

POTWs Data for TDD.

A 

54 SGE00933 ERG. 2015. Radioactive Materials in the Unconventional Oil and Gas (UOG) 

Industry Memorandum.

A

55 SGE00740 ERG. 2015. Unconventional Oil and Gas (UOG) Drilling 

Memorandum.

Wastewater A

56 SGE00724 ERG. 2015. Unconventional Oil and Gas (UOG) Produced 

and Characterization Data Compilation Memorandum.

Water Volumes A

57 SGE00724.A01 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 1: UOG Produced 

Water Data Compilation.

A

58 SGE00724.A02 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 2: DI Desktop Longterm Produced Water Rates.

A
Chapter E—Reference Flags and List

150

Table E-1. Source List

ID DCN Source Citation 

Source 

Flag

59 SGE00724.A03 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 3: DI Desktop Longterm Produced Water Rates.

A

60 SGE00724.A04 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 4: FracFocus 

Fracturing Fluid Volume.

A 

61 SGE00724.A05 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 5: FracFocus 

Fracturing Fluid Volume.

A

62 SGE00724.A06 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 6: Bakken Flowback 

Water Rates.

A

63 SGE00724.A07 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 7: New Mexico 

Flowback Water Rates.

A

64 SGE00724.A08 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 8: Utica Flowback and 

Produced Water.

A

65 SGE00724.A09 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 9: Niobrara Produced 

Water Rates.

A

66 SGE00724.A10 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 10: Wyoming 

Flowback Water Rates.

A

67 SGE00724.A11 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 11: Wattenberg 

Produced Water Rates.

A

68 SGE00724.A12 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation —Attachment 12: Colorado Flowback 

Water Rates.

A

69 SGE00735 Eshelman, Keith N.; Elmore, Andrew. 2013. Recommended Best 

Management Practices for Marcellus Shale Gas Development in Maryland. 

University of Maryland Center for Environmental Science. Prepared for 

Maryland Department of the Environment. (February 18).

A

70 SGE00780 ExxonMobile. 2014. Hydraulic Fracturing Fluid. XTO Energy. Downloaded 

on 6/13/2014.

C

71 SGE00525 Ferrar, Kyle J.; Michanowicz, Drew R.; Christen, Charles L.; Mulcahy, N.; 

Malone, Samantha L.; Sharma, Ravi K. 2013. Assessment of Effluent 

contaminants from Three Facilities Discharging Marcellus Shale Wastewater 

to Surface Waters in Pennsylvania. Environmental Science & Technology 

47:3472–3481.

A

72 SGE00768.A25 Fletcher, Sarah. 2014. Water Management Infrastructure Investments: 

Decision Factors and Regional Economics. Sourcewater Cambridge 

Innovation Center at MIT.

B
Chapter E—Reference Flags and List

151

Table E-1. Source List

ID DCN Source Citation 

Source 

Flag

73 SGE00781 FracFocus. 2014. What Chemicals Are Used? B

74 SGE00746 Franklin Township Sewer Authority. 2008. Franklin Township WWTP Fact 

Sheet/Statement of Basis (NPDES PA0046426). (June 2).

A

75 SGE00760 Freyman, Monika. 2014. Hydraulic Fracturing 

Demand by the Numbers. Ceres. (February).

& Water Stress: Water B

76 SGE00528 Gilmer, Ellen. 2013. Data Show More Marcellus Wastewater, More 

Injections. E&E News. (February 22).

C

77 SGE01077 Ground Water Protection Council (GWPC). 2014. Regulations Designed to 

Protect State Oil and Gas Water Resources. Available electronically at: 

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on%20Report%20Hyperlinked%20Version%20Final-rfs.pdf

A

78 SGE00010 GWPC and ALL Consulting. 2009. Modern Shale Development in the United 

States: A Primer. U.S. DOE. Office of Fossil Energy NETL. April 2009. 

Available electronically at: 

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A

79 SGE00344 Haluszczak, Lara O.; Rose, Arthur W.; Kump, Lee R. 2012. 

Evaluation of Flowback Brine from Marcellus Gas Wells in 

USA. Applied Geochemistry 28:55–61.

Geochemical 

Pennsylvania, 

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80 SGE00286 Hammer, R.; VanBriesen, J. 2012. In Fracking’s Wake: New Rules Are 

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A

81 SGE00567 Handke, Paul. 2008. Trihalomethane Speciation and the Relationship to 

Elevated Total Dissolved Solid Concentrations Affecting Drinking Water 

Quality at Systems Utilizing the Monongahela River as a Primary Source 

During the 3rd and 4th Quarters of 2008. Pennsylvania Department of 

Environmental Protection.

A

82 SGE00531 Hanlon, James. 2011. Natural Gas Drilling in the Marcellus 

Program Frequently Asked Questions. (March 16).

Shale: NPDES A

83 SGE00532 Hansen, Evan; Mulvaney, Dustin; Betcher, Meghan. 2013. Water Resource 

Reporting and Water Footprint from Marcellus Shale Development in West 

Virginia and Pennsylvania. (October 30).

B

84 SGE00284 Hayes, Thomas et al. 2012. Barnett and Appalachian Shale Water 

Management and Reuse Technologies. Research Partnership to Secure Energy 

for America (RPSEA).

A 

85 SGE00414 Hayes, Thomas; Severin, Blaine F. 2012. Characterization of Flowback 

Waters from the Marcellus and the Barnett Shale Regions Report No. 08122-

05.09. Research Partnership to Secure Energy for America (RPSEA).

A

86 SGE00533 Heffernan, Kevin. 2012. Unconventional Resource Development and 

Hydraulic Fracturing. Red Deer River Watershed Alliance. (October 25).

B

87 SGE00239 Hefley, William, et al. 2011. The Economic Impact of the Value Chain of a 

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B
Chapter E—Reference Flags and List

152

Table E-1. Source List

ID DCN Source Citation 

Source 

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88 SGE00756 Hill Engineering, Inc. 2014. Re: Local Limits 

(January 9).

Analysis for Ridgway Borough. A

89 SGE00379 Hill, David A. 2012. 

Niobrara. Wyoming

The Future Is NOW for Water Recycling in the 

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C

90 SGE00535 Hladik, Michelle; Focazio, Michael J.; Englae, Mark. 2014. Discharges of 

Produced Waters from Oil and Gas Extraction via Wastewater Treatment 

Plants Are Sources of Disinfection By-products to Receiving Streams. 

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A

91 SGE00333 Horn, Aaron. 2009. Breakthrough Mobile Water Treatment Converts 75% of 

Fracturing Flowback Fluid to Fresh Water and Lowers CO2 Emissions. SPE 

SPE-121104-PP. Presentation at 2009 SPE Americas E&P Environmental & 

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B

92 SGE00707 Horn, Aaron; Patton, Mark; Hu, Jinxuan. 2013. Minimum Effective Dose: A 

Study of Flowback and Produced Fluid Treatment for Use as Hydraulic 

Fracturing Fluid. Hydrozonix, LLC. Presentation at American Association of 

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B

93 SGE00476 Hydro Recovery, LP. 2013. Company Info. Downloaded on 5/20/2013. C

94 SGE00728 IHS. 2012. America’s New Energy Future: The Unconventional Oil and Gas 

Revolution and the US Economy. Volume 1: National Economic 

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B

95 SGE00722 IHS. 2012. Water Management in Shale Gas Plays. (August) B

96 SGE00769 International 

Behaviour of 

(March 1).

Atomic Energy Agency (IAEA). 2014. The Environmental 

Radium: Revised Edition. Technical Report Series No. 476. 

A

97

SGE00799

Jacobs, 

(June).

Trent. 2014. Shale Revolution Revisits the Energized Fracture. JPT. A

98 SGE00479 Kadramas, Lee & Jackson, Inc. 2012. Power Forecast 2012: Williston Basin 

Oil and Gas Related Electrical Load Growth Forecast. 

B

99 SGE00753 Keister, Timothy. 2010. Marcellus Hydrofracture Flowback and Production 

Wastewater Treatment, Recycle, and Disposal Technologies. Presentation at 

The Science of Marcellus Shale. (January 29).

B

100 SGE00527 Kennedy, Robert L.; Knecht, William N.; Georgi, Daniel T. 2012. 

Comparisons and Contrasts of Shale Gas and Tight Gas Developments: North 

American Experience and Trends. SPE-SAS-245. Society of Petroleum 

Engineers.

B

101 SGE00996 Kicinski, J. 2007. Wheeling POTW Analysis 4. A

102 SGE00775 Kieler, Janet. 2012. CDPS General Permit for Discharges 

Produced-Water Treatment Facilities. (January 30).

Associated with A

103 SGE00540 Kiski Valley Water Pollution 

Enterprises, Inc. (April 21).

Control Authority. 2011. Letter to McCutcheon A

104 SGE00545 Klaber, Kathryn. 2011. Letter 

Coalition. (April 20).

to Michael Krancer, PA DEP. Marcellus Shale C
Chapter E—Reference Flags and List

153

Table E-1. Source List

ID DCN Source Citation 

Source 

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105 SGE00759 KLH Engineers. 2006. City of Wheeling: Water Pollution Control Division 

Headworks Loading Analysis. (November).

A

106 SGE00757 KLH Engineers. 2008. Technical Evaluation of the Impact of Oil and Gas 

Well Wastewaters on the Municipal Authority of the City of McKeesport 

Wastewater Treatment Facility. (November).

A

107 SGE00758 KLH Engineers. 2009. Technical Evaluation of the Impact of Oil and Gas 

Well Wastewaters on the Clairton Municipal Authority Wastewater 

Treatment Facility. (February).

A

108 SGE00745 KLH Engineers. 2011. Municipal Authority of the City of McKeesport: 

Headworks Loading Analysis for Natural Gas Drilling Wastewater Pollutants. 

(March).

B

109 SGE00345 Lewis, Aurana. 2012. Wastewater Generation and Disposal from Natural Gas 

Wells in Pennsylvania. Duke University.

B

110 SGE00667 Lord, R. LeBas; Luna, D.; Shahan, T. 2013. Development and Use of 

TDS Recycled Produced Water for Crosslinked-Gel-Based Hydraulic 

Fracturing. SPE 163824. Society of Petroleum Engineers.

High- B

111 SGE00543 Macormac, Zach. 2011. Wheeling Fined for Taking Frack 

Intelligencer/Wheeling News-Register. (October 15).

Water. The D

112 SGE00544 Marcellus Shale Coalition (MSC) and PA Independent Oil and Gas 

Association (PIOGA). 2013. Field Sampling Plan: Characterization of 

Naturally Occurring Radioactive Materials in the Oil and Gas Field. 

(November 4).

B

113 SGE00547 Massachusetts Institute of Technology (MIT). 2011. 

Gas: An Interdisciplinary MIT Study.

The Future of Natural B

114 SGE00779.A24 Mastowski, Ryan. 2014. Disposal—Oil and Gas Environmental Compliance 

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B

115 SGE00999 McClung, L.A. 2008. Wheeling POTW Discharge Requirements. A

116 SGE00481 McCutcheon Enterprises. 2013. Waste Reduction: 

Treating Drilling Muds. (April).

A Greener Alternative for C 

117 SGE00006.A04 McElreath, Debra. 2011. Comparison of Hydraulic Fracturing Fluids 

Composition with Produced Formation Water Quality Following Fracturing—

Implications for Fate and Transport. Chesapeake Energy.

C

118 SGE00800 McTigue, Nancy; Graf, Katherine; Brown, Richard. 2014. Occurrence and 

Consequences of Increased Bromide in Drinking Water Sources. 

Environmental Engineering & Technology, Inc.

A

119 SGE00167 Metcalf and Eddy, Inc. 2002. Wastewater Engineering: Treatment and Reuse. 

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B

120 SGE00254 Michigan Department of Environmental Quality (MI DEQ). 2006. Michigan 

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A
Chapter E—Reference Flags and List

154

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ID DCN Source Citation 

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121 SGE00552 Mon River Recreation and Commerce Committee. 2009. Minutes of Mon 

River Recreating & Commerce Committee Meeting 12 December 2008. 

Available online at: 

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C-min-14Dec08.htm

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122 SGE00709 Natural Gas Europe. 2012. Flowback Water 

Water Treatment (May 22).

Driving Flurry of Activity in B

123 SGE00644 New Mexico Energy, Minerals and Natural Resources Department 

(NMEMND). 2014. OCD Permitting: Well Search.

A

124 SGE00090 New York State Department of Environmental Conservation (NYSDEC). 

2011. Supplemental Generic Environmental Impact Statement on the Oil, 

Gas, and Solution Mining Regulatory Program: Well Permit Issuance for 

Horizontal Drilling and High-Volume Hydraulic Fracturing to Develop the 

Marcellus Shale and Other Low-Permeability Gas Reservoirs. Preliminary 

Revised Draft.

A

125 SGE00556 Nicot, Jean-Philippe, et al. 2011. Current and Projected Water Use in the 

Texas Mining and Oil and Gas Industry. University of Texas at Austin, 

Bureau of Economic Geology. Prepared for Texas Water Development Board.

A

126 SGE00639 Nicot, Jean-Philippe; Reedy, Robert C.; Costley, Ruth A.; Huang, Yun. 2012. 

Oil & Gas Water Use in Texas: Update to the 2011 Mining Water Use Report. 

University of Texas at Austin, Bureau of Economic Geology. (September). 

A

127 SGE00188 O'Connell, James, ERG. 2014. Pennsylvania Department of Environmental 

Protection’s (PA DEP) Statewide Oil and Gas Waste Reports. (December).

A 

128 SGE00983 Ohio Revised Code. 2012. Title 15, Chapter 1509: Division of Oil and Gas 

Resources Management – Oil and Gas. (September 10). Downloaded October 

17, 2014.

A

129 SGE00985 Parker, Kimberly M.; Zeng, Teng; Harkness, Jennifer; Vengosh, Avner; 

Mitch, William A. 2014. Enhanced Formation of Disinfection Byproducts in 

Shale Gas Wastewater-Impacted Drinking Water Supplies. Environmental 

Science & Technology 48(19):11161–11169.

A

130 SGE00187 Pennsylvania Code. 2010. Title 25: Environmental Protection. Chapter 95: 

Wastewater Treatment Requirements. (August). Available online at: 

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A

131 SGE00755 Pennsylvania Department of Environmental Protection (PA DEP). 2011. 

NPDES Permit No. PA0023213 (Borough of Ridgway). (October).

A

132 SGE00931 Pennsylvania Department of Environmental Protection (PA DEP). 2012. 

Brockway Area Sewer Authority—PA0028428—Final Permit 2012.

A

133 SGE00930 Pennsylvania Department of Environmental Protection (PA DEP). 2012. 

Johnstown Redevelopment Authority (PA0026034)—Final Fact Sheet 2012.

A

134 SGE00573 Pennsylvania Department of Environmental Protection (PA DEP). 2013. 

NPDES Permit No. PA0027511 (New Castle Sanitation Authority). Effective 

date: March 1, 2013. Expiration date: February 28, 2018.

A
Chapter E—Reference Flags and List

155

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ID DCN Source Citation Flag

135 SGE01028 Pennsylvania Department of Environmental Protection. 2015. 

Technologically Enhanced Naturally Occurring Radioactive Materials 

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A

136 SGE00575 Petroleum Equipment Suppliers Association (PESA). 2012. 

Domestic Unconventional Resources. Presentation at PESA 

Outlook for 

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B 

137 SGE00748 PG Environmental, LLC. 2009. Clairton Municipal Authority POTW PassThrough Analysis Appendices. (August 19).A

138 SGE00139 Puder, M.G.; Veil, J.A. 2006. Argonne National Laboratory. Offsite 

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Availability, Options, and Costs. Prepared for U.S. DOE NETL. (August). 

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A

139 SGE00579 Rahm, Brian, et al. 2013. Wastewater Management and Marcellus Shale Gas 

Development: Trends, Drivers, and Planning Implications. Journal of 

Environmental Management 120:105–113.

A

140 SGE00374 Red Desert. n.d. What Makes Our Water Treatment 

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& Reclamation Facility C

141 SGE00768.A01 Robart, Alexander. 2014. E&P Infrastructure vs. Third-Party Services 

Regional Economic & Environmental Factors. PacWest Consulting Partners.

B

142 SGE00583 Romo, Carlos; Janoe, J. Scott. 2012. Regulatory Regimes for Recycling 

Produced and Frac Flowback Water. Paper 2012-A-453-AWMA. 

A

143 SGE00986 Rost, J. 2010. Municipal Authority of the City of McKeesport: Analysis of 

Gas Well Wastewaters as Required Under the PA DEP Administrative Order 

Dated October 23, 2008. (August 12).

A

144 SGE00987 Rost, J. November 2010. Municipal Authority of the City of McKeesport 

Analysis of Gas Well Wastewaters as Required Under the PA DEP 

Administrative Order Dated October 23, 2008.

A

145 SGE00241 Rowan, E.L., et al. 2011. Radium Content of Oil- and Gas-Field Produced 

Waters in the Northern Appalachian Basin (USA)—Summary and Discussion 

of Data. U.S. Geological Survey Scientific Investigations Report 2011–5135.

A

146 SGE00291 Shires, Terrie; Lev-on, Mairiam. 2012. Characterizing Pivotal Sources of 

Methane Emissions from Natural Gas Production.

B

147 SGE00731 Silva, James; Gettings, Rachel; Kostedt, William; Watkins, Vicki. 2013. 

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Water. GE Global Research Center. IWC-13-38.

A

148 SGE00710 Slutz, James; Anderson, Jeffrey; Broderick, Richard; Horner, Patrick. 2012. 

Key Shale Gas Water Management Strategies: An Economic Assessment 

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B

149 SGE00586 State Review of Oil and Natural Gas Environmental Regulations 

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A

150 SGE00587 States, Stanley et al. 2013. Marcellus Shale Drilling and Brominated THMs in 

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A 
Chapter E—Reference Flags and List

156

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ID DCN Source Citation 

Source 

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151 SGE00350 Stepan, Daniel J.; Shockey, Richard E.; Kurz, Bethany A.; Kalenze, Nicholas 

S.; Cowan, Robert M.; Ziman, Joshua J.; Harju, John A. 2010. Bakken Water 

Opportunities Assessment—Phase 1. Energy & Environmental Research 

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A

152 SGE00768.A26 Tucker, Scott. 2014. Evaluating Characteristics of Source, Flowback, 

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& B

153 SGE00592 U.S. Department of Energy (U.S. DOE). 2013. Water Issues 

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154 SGE00593 U.S. Energy Information Administration (EIA). 1993. Drilling Sideways—A 

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A

155 SGE00594 U.S. Energy Information Administration (EIA). 2010. Schematic Geology of 

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A

156 SGE00155 U.S. Energy Information Administration (EIA). 2010. Tight Sands Gas Plays,

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A

157 SGE00153 U.S. Energy Information Administration (EIA). 2011. Lower 48 States Shale 

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A

158 SGE00487 U.S. Energy Information Administration (EIA). 2013. Annual Energy 

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A

159 SGE00595 U.S. Energy Information Administration (EIA). 2013. Drilling Productivity 

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A

160 SGE00761 U.S. EPA. 1989. Letter from T.P. O'Farrell (EPA) to C.B. Harriman (Steptoe 

& Johnson) about applicability of 40 C.F.R 435 Subpart C to CBM 

operations.

A

161 SGE00599 U.S. EPA. 1999. Biosolids Generation, Use, and Disposal in the United 

States. EPA 530-R-99-009. (September).

A

162 SGE01006 U.S. EPA. 2000. Development Document for Final Effluent Limitations 

Guidelines and Standards for Synthetic-Based Drilling Fluids and Other NonAqueous Drilling Fluids in the Oil and Gas Extraction Point Source Category. 

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A 

163 SGE00601 U.S. EPA. 2001. Small Entity Compliance Guide: Centralized Waste 

Treatment Effluent Limitations Guidelines and Pretreatment Standards 

(40C.F.R 437). EPA 821-B-01-003.

A

164 SGE00600 U.S. EPA. 2003. Development Document for the Final Effluent Limitations 

Guidelines and Standards for the Metal Products and Machinery Point Source 

Category. EPA 821-B-03-001. (February).

A

165 SGE00602 U.S. EPA. 2004. Local Limits Development Guidance Appendices. EPA 833-

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A

166 SGE00603 U.S. EPA. 2008. Clean Watersheds Needs Survey: 2008 Report to Congress. 

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A
Chapter E—Reference Flags and List

157

Table E-1. Source List

ID DCN Source Citation 

Source 

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167 SGE00138 U.S. EPA. 2010. 2010 UIC Well Inventory 2010. Available 

http://water.epa.gov/type/groundwater/uic/class2/index.cfm

online at: A

168 SGE00604 U.S. EPA. 2010. Hydraulic Fracturing Research Study. EPA 600-F-10-002. 

(June).

A

169 SGE00620 U.S. EPA. 2011. (Region 3) Administrative Order for Compliance and 

Request for Information, EPA Docket No. CWA-03-2011-0272DN. 

(September 28).

A

170 SGE00982 U.S. EPA. 2011. (Region 3) Letter to PA DEP regarding disposal of 

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A

171 SGE00249 U.S. EPA. 2011. Introduction to the 

833-B-11-001. (June).

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172 SGE00136 U.S. EPA. 2011. Oil and Gas Production Wastes. 

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A

173 SGE00132 U.S. EPA. 2011. Underground Injection Control Program: Class II Wells—

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174 SGE00368 U.S. EPA. 2012. (Region 3). Key Documents About Mid-Atlantic Oil and 

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A

175 SGE00608 U.S. EPA. 2012. Discharge Monitoring Report (DMR) Pollutant 

Tool. Downloaded on 1/28/2013. Available online at: 

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Loading A

176 SGE00279 U.S. EPA. 2012. Meeting Summary: Conference Call with North Star 

Disposal, Inc Regarding Underground Injection Operations in Ohio. (July 2). 

A

177 SGE00276 U.S. EPA. 2012. Meeting with XTO Energy, Inc. about Unconventional Oil 

and Gas Sanitized.

A 

178 SGE00635 U.S. EPA. 2012. Site Visit Report: Chesapeake Energy Corporation 

Marcellus Shale Gas Operations Sanitized.

A

179 SGE00275 U.S. EPA. 2012. Site Visit Report: Citrus Energy 

Shale Gas Operations. (January 22).

Corporation Marcellus A

180 SGE00300 U.S. EPA. 2012. Site Visit Report: Eureka 

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181 SGE00299 U.S. EPA. 2012. Site Visit Report: US Gas Field Fluids Management 

(formerly Clean Streams) Marcellus Shale Gas Operations. (October 9).

A

182 SGE00742 U.S. EPA. 2012. States Pretreatment Coordinators'

Call: Summary. (August 8).

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183 SGE00636 U.S. EPA. 2012. Talisman Marcellus Operations Overview. (July 23). A

184 SGE00611 U.S. EPA. 2012. UIC Program Primacy. Downloaded on 10/24/2013. 

Available online at: http://water.epa.gov/type/groundwater/uic/Primacy.cfm

A

185 SGE00612 U.S. EPA. 2013. DMR Loading Tool Download for New 

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Castle POTW A
Chapter E—Reference Flags and List

158

Table E-1. Source List

ID DCN Source Citation 

Source 

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186 SGE00726 U.S. EPA. 2013. Email Chain between Jacqueline Rios, Frank Brock, and 

Lisa Biddle About UICs in NY Taking Oil and Gas Wastewater. (November 

13).

A

187 SGE00935 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).

A 

188 SGE00613 U.S. EPA. 2013. Meeting Summary: Meeting with Industry Representatives 

About the Unconventional Oil and Gas Effluent Guideline Rulemaking. 

(February 28).

A

189 SGE00615 U.S. EPA. 2013. Radionuclides in Drinking Water: Waste Disposal Options. 

(November 26).

A

190 SGE00280 U.S. EPA. 2013. Site Visit Report: Anadarko Petroleum 

Marcellus Shale Gas Operations. (January 9).

Corporation A

191 SGE00625 U.S. EPA. 2013. Site Visit Report: Southwestern Energy (SWN) 

Shale Gas Operations Sanitized.

Fayetteville A

192 SGE00743 U.S. EPA. 2013. States Pretreatment Coordinators’ Bi-monthly Conference 

Call. (August 14).

A 

193 SGE00616 U.S. EPA. 2013. Summary of the Technical Workshop on Wastewater 

Treatment and Related Modeling. (April 18).

A

194 SGE00691 U.S. EPA. 2013. Summary of 

Modeling: Assessing Impacts 

(September).

the Technical Workshop on Water Acquisition 

Through Modeling and Other Means. 

A

195 SGE00935.A01 U.S. EPA. 2013. Toxic Screening Analysis Spreadsheet. A

196 SGE00762 U.S. EPA. 2013. US EPA Technology Innovation Project: ECOS/ACWA 

Conference Call. (April 25).

A

197 SGE00585 U.S. EPA. 2014. FracFocus Database. Office of Research and Development 

(ORD).

A

198 SGE00766 U.S. EPA. 2014. Lockhart, John V. Email Correspondence 

and EPA. (June 3).

between WV DEP A

199 SGE00783 U.S. EPA. 2014. Thorium. (February 28). Available online at: 

http://www.epa.gov/radiation/radionuclides/thorium.html

A

200 SGE00786 U.S. EPA. 2014. UOG Workgroup—Warren, OH POTW 

19).

Info Request. (June A

201 SGE00721 U.S. EPA. 2015. Evaluation of Hydraulic Fracturing Fluid Data 

FracFocus Chemical Disclosure Registry 1.0. (March). 

from the A

202 SGE00785 U.S. EPA. 2015. Summary of Tribal Outreach Regarding Pretreatment 

Standards for Unconventional Oil and Gas (UOG) Extraction Wastewater. 

A

203 SGE00692 U.S. EPA. 2015. Unconventional Oil 

Treatment Technologies.

& Gas (UOG) Extraction Wastewater A

204 SGE00622 U.S. Geological Survey (USGS). 2013. Water Resources and Shale Gas/Oil 

Production in the Appalachian Basin—Critical Issues and Evolving 

Developments. (August). Available online at: 

http://pubs.usgs.gov/of/2013/1137/pdf/ofr2013-1137.pdf

A
Chapter E—Reference Flags and List

159

Table E-1. Source List

Source 

ID DCN Source Citation Flag

205 SGE00956 U.S. Geological Survey (USGS). 2014. National Produced Waters 

Geochemical Database v2.0 (Provisional).

A

206 SGE00623 U.S. Government Accountability Office (GAO). 2012. Energy-Water-Nexus: 

Information on the Quantity, Quality, and Management of Water Produced 

During Oil and Gas Production. (January). GAO-12-156.

A

207 SGE00624 University of Michigan. 2013. Hydraulic Fracturing in the State of Michigan. 

Graham Sustainability Institute Integrated Assessment Report Series. 

(September).

B

208 SGE00095 URS. 2011. Water-Related Issues 

Marcellus Shale. (March 25).

Associated with Gas Production in the B

209 SGE01095 USGS. 2015. Trends in Hydraulic Fracturing Distributions & Trt Fluids, 

Additives, Proppants, & Water Volumes Applied to US Wells Drilled, 1947-

2010.

A

210 SGE01095.A09 USGS. 2015. Trends in Hydraulic Fracturing Distributions & Trt Fluids, 

Additives, Proppants, & Water Volumes Applied to US Wells Drilled, 1947-

2010: Attachment 9: Frac_Trtm_Type.xlsx

A

211 SGE00114 Van Dyke, Staffan. 2010. Tight Gas Sandstone: Is It Truly Unconventional? 

Oil & Gas Evaluation Report. (October).

C

212 SGE00011 Veil, John A. 2010. Water Management Technologies Used by Marcellus 

Shale Gas Producers. Prepared by Argonne National Laboratory. Prepared for 

U.S. DOE NETL. (July). Available at: 

http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/W

aterMgmtinMarcellusfull.pdf

A

213 SGE00093 Veil, John; Puder, Markus G.; Elcock, Deborah; Redweik, Robert J. 2004. A 

White Paper Describing Produced Water from Production of Crude Oil, 

Natural Gas, and Coal Bed Methane. Prepared by Argonne National 

Laboratory. Prepared for U.S. DOE NETL. (January).

A

214 SGE00754 Vengosh, A.; Jackson, Robert B.; Warner, N.; Darrah, Thomas H.; Kondash, 

A. 2014. A Critical Review of the Risks to Water Resources from 

Unconventional Shale Gas Development and Hydraulic Fracturing in the 

United States. Environmental Science & Technology 48(15):8334–8348.

A

215 SGE00627 Vidic, Radisav; Brantley, S.L.; Vandenbossche, J.M.; Yoxtheimer, D.; Abad, 

J.D. 2013. Impact of Shale Gas Development on Regional Water Quality. 

Science 340(6134).

B

216 SGE00629 Warner, Nathaniel R.; Christie, Cidney A.; Jackson, Robert B.; Vengosh, 

Avner. 2013. Impacts of Shale Gas Wastewater Disposal on Water Quality in 

Western Pennsylvania. Environmental Science & Technology 47(20):11849–

11857.

A

217 SGE00295 Warren Water Pollution Control Facility. 2011. Fact Sheet for NPDES Permit 

Renewal, Warren Water Pollution Control Facility, 2011–2012. City of 

Warren.

A

218 SGE00767 West Virginia Department of Environmental Protection (WV DEP). 2010. 

Letter to City of Follansbee Re: WV/NPDES Permit No. WV0020273 

Accepting Oil and Gas Wastewater. (December 15).

A
Chapter E—Reference Flags and List

160

Table E-1. Source List

Source 

ID DCN Source Citation Flag

219 SGE00485 West Virginia Department of Environmental Protection (WV DEP). 2011. 

Consent Order Issued Under the Water Pollution Control Act, West Virginia 

Code, Chapter 22, Article 11. 

A

220 SGE00488 West Virginia Department of Environmental Protection (WV DEP). 2012. 

NPDES Water Pollution Control Permit WV0116441. Reserved 

Environmental Services CWT Permit.

A 

221 SGE01113 West Virginia Department of Environmental Protection (WV DEP). 2009. 

WV/NPDES Permit No WV0023302 Clarksburg Sanitary Board Accepting 

Oil and Gas Wastewater.

A

222 SGE01114 West Virginia Department of Environmental Protection (WV DEP). 2009. 

WV/NPDES Permit No, WV0023230 City of Wheeling Accepting Oil and 

Gas Wastewater.

A

223 SGE00554 Widmer Engineering, Inc. 2010. New Castle Sanitation Authority, New 

Castle, Lawerance County, Pennsylvania: Annual Pretreatment Report, 2009 

Operating Year. Prepared for New Castle Sanitation Authority.

A

224 SGE00064 Williams, John. 2011. Marcellus Shale-Gas Development and WaterResource Issues. USGS: New York Water Science Center.A

225 SGE00632 Williams, John. n.d. The Marcellus Shale Gas Play: Geology, Development, 

and Water-Resource Impact Mitigation. USGS: New York Water Science 

Center.

A

226 SGE00633 Wilson, Jessica; Van Briesen, Jeanne. 2013. Oil and Gas Produced Water 

Management and Surface Drinking Water Sources in Pennsylvania. 

Environmental Practice 14(4):288–300.

A

227 SGE00725 Wolford, Robert. 2011. Characterization of Organics in the Marcellus Shale 

Flowback and Produced Waters. Pennsylvania State University. Master’s 

Thesis. (August).

B

228 SGE00774 Ziemkiewicz, Paul. 2013. Water Quality Literature Review and Field 

Monitoring of Active Shale Gas Wells. Phase I: Assessing Environmental 

Impacts of Horizontal Gas Well Drilling Operations. West Virginia 

Department of Environmental Protection. (February 15).

A
Chapter F—Appendices

161

Chapter F. APPENDICES

APPENDIX F.1 REFERENCE FILES IN FDMS

Table F-1. TDD Supporting Memoranda and Other Relevant Documents Available in 

FDMS

DCN Title Description

Relevant TDD 

Section(s)

SGE00596 Analysis of Centralized 

Waste Treatment (CWT) 

Facilities Accepting UOG 

Extraction Wastewater

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.

D.1, D.4

SGE00692 Unconventional Oil and Gas 

(UOG) Extraction 

Wastewater Treatment 

Technologies

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.

D.3 

SGE00693 Data Compilation 

Memorandum for the 

Technical Development 

Document (TDD) for 

Proposed Effluent 

Limitations Guidelines and 

Standards for Oil and Gas 

Extraction

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.

B.3, C.Intro, C.1, 

C.2, D.1, D.2, 

D.3 

SGE00724 Unconventional Oil and Gas 

(UOG) Produced Water 

Volumes and 

Characterization Data 

Compilation

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.

B.3, C.Intro, C.2, 

C.3 

SGE00736 Analysis of Active 

Underground Injection for 

Disposal Wells

Explains the compilation of underground 

injection wells data from various sources. D.1, D.2, D.4

SGE00739 Analysis of Pennsylvania 

Department of Environmental 

Protection’s (PA DEP) Oil 

and Gas Waste Reports

Explains the PA DEP waste reports data and 

explains the processes that were used to 

analyze the data. C.2, D.1, D.5 

SGE00740 Unconventional Oil and Gas 

(UOG) Drilling Wastewater

Explains the well drilling process in more 

detail, with focus on drilling wastewater 

volumes and constituent concentrations.

B.2, C.2, C.3, 

D.1
Chapter F—Appendices

162

Table F-1. TDD Supporting Memoranda and Other Relevant Documents Available in 

FDMS

DCN Title Description

Relevant TDD 

Section(s)

SGE00785 Summary of Tribal Outreach 

Regarding Pretreatment 

Standards for Unconventional 

Oil and Gas (UOG) 

Extraction Wastewater

Summarizes the data collected as part of the 

tribal outreach efforts associated with the 

proposed rule.

D.5 

SGE00929 Publicly Owned Treatment 

Works (POTW) 

Memorandum for the 

Technical Development 

Document (TDD) for 

Proposed Effluent 

Limitations Guidelines and 

Standards for Oil and Gas 

Extraction

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.

D.5 

SGE00932 Profile of the Oil and Gas 

Extraction (OGE) Sector, 

with Focus on 

Unconventional Oil and Gas 

(UOG) Extraction

Provides economic background information 

about the oil and gas industry.

B.Intro

SGE00933 Radioactive Materials in the 

Unconventional Oil and Gas 

(UOG) Industry

Provides background information about 

radioactive elements in the UOG industry, 

with focus on radium-226 and radium-228.

C.3, D.5 

SGE00963 Analysis of DI Desktop® Summarizes the DI Desktop® data source and 

where it is cited throughout the proposed rule

analyses.

B.3.2

SGE01016 Conventional Oil and Gas 

(COG) Memorandum for the 

Record

Summarizes COG extraction wastewater 

characteristics and management and disposal 

practices used for COG extraction wastewater.

N/A

N/A—Not Applicable
Chapter F—Appendices

163 

Table F-2. Crosswalk Between TDD and Supporting Memoranda

TDD Table 

or Figure 

Number TDD Table/Figure Title

In a 

Supporting 

Memo 

(Y/N)?a 

Source or Supporting 

Memo DCN(s) Supporting Memo Title(s)

Figure A-1 UOG Extraction Wastewater No (Created 

by the EPA)

— —

Table A-1 Summary of State Regulations No SGE00187, SGE00254, 

SGE00545, SGE00766, 

SGE00767, SGE00982, 

SGE00983

—

Figure B-1 Historical and Projected Oil Production by 

Resource Type

No SGE00487 —

Figure B-2 Historical and Projected Natural Gas 

Production by Resource Type

No SGE00989 —

Figure B-3 Major U.S. Shale Plays (Updated May 9, 2011) No SGE00153 —

Figure B-4 Major U.S. Tight Plays (Updated June 6, 2010) No SGE00155 —

Figure B-5 Geology of Formations Containing Various 

Hydrocarbons

No SGE00594 —

Figure B-6 Horizontal (A), Vertical (B), and Directional 

(C) Drilling Schematic

No SGE00593 —

Figure B-7 Length of Time to Drill a Well in Various 

UOG Formations

Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

Figure B-8 Hydraulic Fracturing Schematic No SGE00604 —

Figure B-9 Freshwater Impoundment No SGE00275 —

Figure B-10 Vertical Gas and Water Separator No SGE00625 —

Figure B-11 Fracturing Tanks No SGE00625 —

Figure B-12 Produced Water Storage Tanks No SGE00275 —

Figure B-13 Number of Active U.S. Onshore Rigs by 

Trajectory and Product Type over Time

Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction
Chapter F—Appendices

164 

Table F-2. Crosswalk Between TDD and Supporting Memoranda

TDD Table 

or Figure 

Number TDD Table/Figure Title

In a 

Supporting 

Memo 

(Y/N)?a 

Source or Supporting 

Memo DCN(s) Supporting Memo Title(s)

Figure B-14 Projections of UOG Well Completions Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

Table B-1 Characteristics of Reservoirs Containing UOG 

and COG Resources

No SGE00114, SGE00345, 

SGE00527, SGE00533

—

Table B-2 Active Onshore Oil and Gas Drilling Rigs by 

Well Trajectory and Product Type (as of 

November 8, 2013)

Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

Table B-3 UOG Potential by Resource Type as of January 

1, 2012

Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

Figure C-1 UOG Extraction Wastewater Volumes for 

Marcellus Shale Wells in Pennsylvania (2004–

2013)

Yes SGE00739 Analysis of Pennsylvania Department of Environmental 

Protection’s (PA DEP) Oil and Gas Waste Reports

Figure C-2 Ranges of Typical Produced Water Generation 

Rates over Time After Fracturing

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation

Figure C-3

Anions and Cations Contributing to TDS 

Concentrations in Shale and Tight Oil and Gas 

Formations

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation

Figure C-4 Chloride, Sodium, and Calcium Concentrations 

in Flowback and Long-Term Produced Water 

(LTPW) from Shale and Tight Oil and Gas 

Formations

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation

Figure C-5 Barium Concentrations in UOG Produced 

Water from Shale and Tight Oil and Gas 

Formations

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation
Chapter F—Appendices

165 

Table F-2. Crosswalk Between TDD and Supporting Memoranda

TDD Table 

or Figure 

Number TDD Table/Figure Title

In a 

Supporting 

Memo 

(Y/N)?a 

Source or Supporting 

Memo DCN(s) Supporting Memo Title(s)

Figure C-6 Constituent Concentrations over Time in UOG 

Produced Water from the Marcellus and 

Barnett Shale Formations

No SGE00414 —

Table C-1 Sources for Base Fluid in Hydraulic Fracturing Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

Table C-2 Fracturing Fluid Additives, Main Compounds, 

and Common Uses

No SGE00070, SGE00721, 

SGE00780, SGE00781, 

SGE00966

—

Table C-3 Most Frequently Reported Additive Ingredients 

Used in Fracturing Fluid in Gas and Oil Wells 

from FracFocus (2011-2013)

Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

Table C-4 Median Drilling Wastewater Volumes for 

UOG Horizontal and Vertical Wells in 

Pennsylvania

Yes SGE00739 Analysis of Pennsylvania Department of Environmental 

Protection’s (PA DEP) Oil and Gas Waste Reports

Table C-5 Drilling Wastewater Volumes Generated per 

Well by UOG Formation

Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater

Table C-6 UOG Well Flowback Recovery by Resource 

Type and Well Trajectory

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation

Table C-7 Long-Term Produced Water Generation Rates 

by Resource Type and Well Trajectory

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation

Table C-8 Produced Water Volume Generation by UOG 

Formation

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation

Table C-9 Availability of Data for UOG Extraction 

Wastewater Characterization

No (Created 

by the EPA)

— —

Table C-10 Concentrations of Select Classical and 

Conventional Constituents in UOG Drilling 

Wastewater from Marcellus Shale Formation 

Wells

Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater
Chapter F—Appendices

166 

Table F-2. Crosswalk Between TDD and Supporting Memoranda

TDD Table 

or Figure 

Number TDD Table/Figure Title

In a 

Supporting 

Memo 

(Y/N)?a 

Source or Supporting 

Memo DCN(s) Supporting Memo Title(s)

Table C-11 Concentrations of Select Classical and 

Conventional Constituents in UOG Produced 

Water

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation

Table C-12 Concentrations of Select Anions and Cations 

Contributing to TDS in UOG Drilling 

Wastewater from Marcellus Shale Formation 

Wells

Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater

Table C-13 Concentrations of Select Anions and Cations 

Contributing to TDS in UOG Produced Water

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation

Table C-14 Concentrations of Select Organic Constituents 

in UOG Drilling Wastewater from Marcellus 

Shale Formation Wells

Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater

Table C-15 Concentrations of Select Organic Constituents 

in UOG Produced Water

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation

Table C-16 Concentrations of Select Metal Constituents in 

UOG Drilling Wastewater from Marcellus 

Shale Formation Wells

Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater

Table C-17 Concentrations of Select Metal Constituents in 

UOG Produced Water

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation

Table C-18 Concentrations of Select Radioactive 

Constituents in UOG Drilling Wastewater from 

Marcellus Shale Formation Wells

Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater

Table C-19 Concentrations of Select Radioactive 

Constituents in UOG Produced Water

Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water 

Volumes and Characterization Data Compilation

Table C-20 Concentrations of Radioactive Constituents in 

Rivers, Lakes, Groundwater, and Drinking 

Water Sources Throughout the United States 

(pCi/L)

No SGE00769 —

Figure D-1 UOG Produced Water Management Methods No (Created 

by the EPA)

— —
Chapter F—Appendices

167 

Table F-2. Crosswalk Between TDD and Supporting Memoranda

TDD Table 

or Figure 

Number TDD Table/Figure Title

In a 

Supporting 

Memo 

(Y/N)?a 

Source or Supporting 

Memo DCN(s) Supporting Memo Title(s)

Figure D-2 UOG Drilling Wastewater Management 

Methods

No (Created 

by the EPA)

— —

Figure D-3 Management of UOG Drilling Wastewater 

Generated by UOG Wells in Pennsylvania 

(2008–2013)

Yes SGE00739 Analysis of Pennsylvania Department of Environmental 

Protection’s (PA DEP) Oil and Gas Waste Reports

Figure D-4 Active Disposal Wells and CWT Facilities 

Identified in the Appalachian Basin

No (Created 

by the EPA)

— —

Figure D-5 Flow Diagram of On-the-Fly UOG Produced 

Water Treatment for Reuse/Recycle

No SGE00331 —

Figure D-6 Hypothetical UOG Produced Water Generation 

and Base Fracturing Fluid Demand over Time

Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

Figure D-7

UOG Extraction Wastewater Management 

Practices Used in the Marcellus Shale (Top: 

Southwestern Region; Bottom: Northeastern 

Region)

No SGE00579 —

Figure D-8 Number of Known Active CWT Facilities over 

Time in the Marcellus and Utica Shale 

Formation

Yes SGE00596 Analysis of Centralized Waste Treatment (CWT) 

Facilities Accepting UOG Extraction Wastewater

Figure D-9 Typical Process Flow Diagram at a POTW No SGE00602 —

Figure D-10 Clairton POTW: Technical Evaluation of 

Treatment Processes’ Ability to Remove 

Chlorides and TDS

Yes SGE00929 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical Development Document 

(TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction

Figure D-11 McKeesport POTW: Technical Evaluation of 

Treatment Processes’ Ability to Remove 

Chlorides and TDS

Yes SGE00929 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical Development Document 

(TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction
Chapter F—Appendices

168 

Table F-2. Crosswalk Between TDD and Supporting Memoranda

TDD Table 

or Figure 

Number TDD Table/Figure Title

In a 

Supporting 

Memo 

(Y/N)?a 

Source or Supporting 

Memo DCN(s) Supporting Memo Title(s)

Figure D-12 Ridgway POTW: Annual Average Daily 

Effluent Concentrations and POTW Flows

Yes SGE00929 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical Development Document 

(TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction

Figure D-13 Johnstown POTW: Annual Average Daily 

Effluent Concentrations and POTW Flows

Yes SGE00929 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical Development Document 

(TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction

Figure D-14 California POTW: Annual Average Daily 

Effluent Concentrations and POTW Flows

Yes SGE00929 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical Development Document 

(TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction

Figure D-15 Charleroi POTW: Annual Average Daily 

Effluent Concentrations and POTW Flows

Yes SGE00929 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical Development Document 

(TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction

Figure D-16 Barium Sulfate Scaling in Haynesville Shale 

Pipe

No SGE00768.A26 —

Figure D-17 THM Speciation in a Water Treatment Plant 

(1999–2013)

No SGE00800 —

Table D-1 UOG Produced Water Management Practices Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

Table D-2 Distribution of Active Class II Disposal Wells 

Across the United States

Yes SGE00736 Analysis of Active Underground Injection for Disposal 

Wells

Table D-3 Reuse/Recycle Practices in 2012 as a 

Percentage of Total Produced Water Generated 

as Reported by Respondents to 2012 Survey

No SGE00575 —
Chapter F—Appendices

169 

Table F-2. Crosswalk Between TDD and Supporting Memoranda

TDD Table 

or Figure 

Number TDD Table/Figure Title

In a 

Supporting 

Memo 

(Y/N)?a 

Source or Supporting 

Memo DCN(s) Supporting Memo Title(s)

Table D-4 Reported Reuse/Recycle Criteria Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

Table D-5 Reported Reuse/Recycle Practices as a 

Percentage of Total Fracturing Volume

Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

Table D-6 Number, by State, of CWT Facilities That 

Have Accepted or Plan to Accept UOG 

Extraction Wastewater

Yes SGE00596 Analysis of Centralized Waste Treatment (CWT) 

Facilities Accepting UOG Extraction Wastewater

Table D-7 Typical Composition of Untreated Domestic 

Wastewater

No SGE00167 —

Table D-8 Typical Percent Removal Capabilities from 

POTWs with Secondary Treatment

No SGE00600 —

Table D-9 U.S. POTWs by Treatment Level in 2008 No SGE00603 —

Table D-10 POTWs That Accepted UOG Extraction 

Wastewater from Onshore UOG Operators

Yes SGE00929 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical Development Document 

(TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction

Table D-11 Percentage of Total POTW Influent 

Wastewater Composed of UOG Extraction 

Wastewater at POTWs Accepting Wastewater 

from UOG Operators

Yes SGE00929 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical Development Document 

(TDD) for Proposed Effluent Limitations Guidelines and 

Standards for Oil and Gas Extraction

Table D-12 Summary of Studies About POTWs Receiving 

Oil and Gas Extraction Wastewater Pollutants

No (Created 

by the EPA)

— —

Table D-13 Clairton Influent Oil and Gas Extraction 

Wastewater Characteristics

No SGE00748 —

Table D-14 Trucked COG Extraction Wastewater Treated 

at McKeesport POTW from November 1 

Through 7, 2008

No SGE00745 —
Chapter F—Appendices

170 

Table F-2. Crosswalk Between TDD and Supporting Memoranda

TDD Table 

or Figure 

Number TDD Table/Figure Title

In a 

Supporting 

Memo 

(Y/N)?a 

Source or Supporting 

Memo DCN(s) Supporting Memo Title(s)

Table D-15 McKeesport POTW Removal Rates Calculated 

for Local Limits Analysis

No SGE00745 —

Table D-16 Constituent Concentrations in UOG Extraction 

Wastewater Treated at the McKeesport POTW 

Before Mixing with Other Influent Wastewater

No SGE00525 —

Table D-17 McKeesport POTW Effluent Concentrations 

With and Without UOG Extraction Wastewater

No SGE00525 —

Table D-18 Charleroi POTW Paired Influent/Effluent Data 

and Calculated Removal Rates

No SGE00751 —

Table D-19 Franklin Township POTW Effluent 

Concentrations With and Without Industrial 

Discharges from the Tri-County CWT Facility

No SGE00525 —

Table D-20 TDS Concentrations in Baseline and Pilot 

Study Wastewater Samples at Warren POTW

No SGE00616 —

Table D-21 EPA Region 5 Compliance Inspection 

Sampling Data

No SGE00616 —

Table D-22 Inhibition Threshold Levels for Various 

Treatment Processesa

No SGE00602 —

Table D-23 Industrial Wastewater Volumes Received by 

New Castle POTW (2007–2009)

No SGE00554 —

Table D-24 NPDES Permit Limit Violations from Outfall 

001 of the New Castle POTW (NPDES Permit 

Number PA0027511)

No SGE00612, SGE00620 —

Table D-25 Concentrations of DBPs in Effluent Discharges 

at One POTW Not Accepting Oil and Gas 

Wastewater and at Two POTWs Accepting Oil 

and Gas Wastewater (μg/L)

No SGE00535 —

Figure F-1 Constituent Concentrations over Time in UOG 

Produced Water from the Marcellus and 

Barnett Shale Formations

No SGE00414 —
Chapter F—Appendices

171 

Table F-2. Crosswalk Between TDD and Supporting Memoranda

TDD Table 

or Figure 

Number TDD Table/Figure Title

In a 

Supporting 

Memo 

(Y/N)?a 

Source or Supporting 

Memo DCN(s) Supporting Memo Title(s)

Table F-1 TDD Supporting Memoranda and Other 

Relevant Documents Available in FDMS

No (Created 

by the EPA)

— —

Table F-2 Crosswalk Between TDD and Supporting 

Memoranda

No (Created 

by the EPA)

— —

Table F-3 UOG Resource Potential: Shale as of January 

1, 2012

Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

Table F-4 UOG Resource Potential: Tight as of January 

1, 2012

Yes SGE00693 Data Compilation Memorandum for the Technical 

Development Document (TDD) for Proposed Effluent 

Limitations Guidelines and Standards for Oil and Gas 

Extraction

a—Unless otherwise noted, figures and/or tables not included in a supporting memorandum were taken directly from a source without calculation or interpretation. 
Chapter F—Appendices

172 

APPENDIX F.2 UOG RESOURCE POTENTIAL BY SHALE AND TIGHT FORMATIONS

Table F-3. UOG Resource Potential: Shale as of January 1, 2012 

Gas EUR 

UOG Formation Resource Oil EUR (MMbls (Bcf per Oil TRR Gas TRR New Well 

EIA Region EIA Basin Name Type per well) well) (MMbls) (Bcf) Potential

1—East

Appalachian

Devonian Shale gas 0.000 0.058 0 20,800 358,600

Marcellus Shale gas 0.000 1.317 0 118,900 90,300

Utica

Shale gas 0.000 0.330 0 37,400 113,500

Shale oil 0.063 0.057 1,000 900 15,900

Illinois New Albany Shale gas 0.000 1.721 0 41,700 24,200

Michigan Antrim Shale gas 0.000 0.157 0 15,300 97,500

2—Gulf Coast

Black Warrior Floyd-Neal/Conasauga Shale gas 0.000 1.520 0 4,300 2,800

TX-LA-MS Salt Haynesville-Bossier Shale gas 0.000 3.455 0 70,900 20,500

Western Gulf

Eagle Ford

Shale gas 0.177 1.549 6,100 53,400 34,500

Shale oil 0.101 0.212 3,300 6,900 32,500

Pearsall Shale gas 0.000 1.090 0 7,800 7,200

Tuscaloosa Shale oil 0.092 0.019 2,900 600 31,600

Woodbine Shale oil 0.108 0.054 600 300 5,600

3—Midcontinent

Anadarko Cana Woodford

Shale gas 0.014 1.232 100 8,900 7,200

Shale oil 0.038 0.415 100 1,100 2,700

Arkoma

Caney Shale gas 0.000 0.330 0 1,100 3,300

Fayetteville Shale gas 0.000 1.284 0 29,800 23,200

Woodford Shale gas 0.000 1.422 0 6,700 4,700

Black Warrior Chattanooga Shale gas 0.000 0.970 0 1,600 1,600

4—Southwest

Barnett Shale Gas Shale gas 0.000 0.377 0 20,300 53,900

Permian

Wolfcamp Shale oil 0.068 0.217 3,400 10,900 50,200

Barnett-Woodford Shale gas 0.000 1.513 0 15,800 10,400

Avalon/BoneSpring Shale oil 0.080 0.000 2,000 0 25,000

5—Rocky Mountain

Denver Niobrara Shale oil 0.011 0.073 400 2,700 37,000

Greater Green River Hilliard-Baxter-Mancos Shale gas 0.000 0.293 0 10,500 35,800
Chapter F—Appendices

173 

Table F-3. UOG Resource Potential: Shale as of January 1, 2012 

EIA Region EIA Basin

UOG Formation 

Name

Resource 

Type

Oil EUR (MMbls 

per well)

Gas EUR 

(Bcf per 

well)

Oil TRR 

(MMbls)

Gas TRR 

(Bcf)

New Well 

Potential

5—Rocky Mountain

Montana Thrust Belt All tight oil plays Shale oil 0.113 0.075 600 400 5,300

Powder River All tight oil plays Shale oil 0.035 0.040 2,100 2,400 60,000

San Juan Lewis Shale gas 0.000 2.200 0 9,800 4,500

Uinta-Piceance Mancos Shale gas 0.000 0.880 0 10,900 12,400

Williston

Gammon Shale gas 0.000 0.440 0 3,400 7,700

Bakken Shale oil 0.142 0.096 9,300 6,300 65,500

6—West Coast

Columbia Basin Centered Shale gas 0.000 1.400 0 12,200 8,700

San Joaquin/Los 

Angeles Monterey/Santos Shale oil 0.502 0.502 600 600 1,200

Sources: 48 DCN SGE00693

Abbreviations: EUR—estimated ultimate recovery (per well); MMbls—million barrels; Bcf—billion cubic feet of gas; TRR—technically recoverable resources

Table F-4. UOG Resource Potential: Tight as of January 1, 2012 

EIA Region EIA Basin

UOG Formation 

Name

Resource 

Type

Oil EUR (MMbls 

per well)

Gas EUR 

(Bcf per 

well)

Oil TRR 

(MMbls)

Gas TRR 

(Bcf)

New Well 

Potential

1—East Appalachian

Clinton-Medina Tight gas 0.003 0.060 500 11,700 195,000

Tuscarora Tight gas 0.000 2.172 0 4,400 2,000

Michigan Berea Sand Tight gas 0.000 0.143 0 8,100 56,600

2—Gulf Coast

TX-LA-MS Salt Cotton Valley Tight gas 0.009 1.472 900 152,700 103,700

Western Gulf

Olmos Tight gas 0.005 1.093 100 23,600 21,600

Vicksburg Tight gas 0.000 1.473 0 3,900 2,600

Wilcox Lobo Tight gas 0.000 1.404 0 10,100 7,200

Austin Chalk Tight oil 0.086 0.048 7,600 4,300 88,800

Buda Tight oil 0.108 0.070 3,700 2,400 34,300

3—Midcontinent Anadarko

Cleveland Tight gas 0.036 0.394 100 1,100 2,800

Granite Wash Tight gas 0.046 0.948 600 12,300 13,000
Chapter F—Appendices

174 

Table F-4. UOG Resource Potential: Tight as of January 1, 2012

EIA Region EIA Basin

UOG Formation 

Name

Resource 

Type

Oil EUR (MMbls 

per well)

Gas EUR 

(Bcf per 

well)

Oil TRR 

(MMbls)

Gas TRR 

(Bcf)

New Well 

Potential

Red Fork Tight gas 0.000 0.593 0 1,000 1,700

4—Southwest Permian

Abo Tight gas 0.101 0.182 1,000 1,800 9,900

Canyon Tight gas 0.002 0.209 100 10,900 52,200

Spraberry Tight oil 0.108 0.113 8,100 8,500 75,200

5—Rocky Mountain

Denver Muddy Tight gas 0.000 0.182 0 11,500 63,200

Greater Green River All Tight Oil Plays Tight oil 0.135 0.015 900 100 6,700

North Central 

Montana Bowdoin-Greenhorn Tight gas 0.000 0.151 0 300 2,000

Paradox Fractured Interbed Tight oil 0.543 0.434 1,000 800 1,800

San Juan

Dakota Tight gas 0.000 0.416 0 6,100 14,700

Mesaverde Tight gas 0.000 0.464 0 5,800 12,500

Pictured Cliffs Tight gas 0.000 0.397 0 200 500

SW Wyoming

Fort Union-Fox Hills Tight gas 0.000 1.047 0 15,800 15,100

Frontier Tight gas 0.009 0.273 200 6,200 22,700

Lance Tight gas 0.016 1.012 300 18,700 18,500

Lewis Tight gas 0.000 0.248 0 7,700 31,000

All Tight Oil Plays Tight oil 0.165 0.015 1,100 100 6,700

Uinta-Piceance

Iles-Mesaverde Tight gas 0.000 0.502 0 17,100 34,100

Wasatch-Mesaverde Tight gas 0.023 0.463 400 8,200 17,700

Williams Fork Tight gas 0.000 0.456 0 7,600 16,700

All Tight Oil Plays Tight oil 0.056 0.111 100 200 1,800

Williston Judith River-Eagle Tight gas 0.000 0.158 0 1,000 6,300

Wind River Mesaverde/Frontier 

Shallow Tight gas 0.000 0.768 0 4,400 5,700

Sources: 48 DCN SGE00693

Abbreviations: EUR—estimated ultimate recovery (per well); MMbls—million barrels; Bcf—billion cubic feet of gas; TRR—technically recoverable resources
Chapter F–Appendices

175 

APPENDIX F.3 CONSTITUENT CONCENTRATIONS OVER TIME IN UOG PRODUCED 

WATER FROM MARCELLUS AND BARNETT SHALE FORMATIONS

Source: The EPA generated this figure using data from 85 DCN SGE00414.

Figure F-1. Constituent Concentrations over Time in UOG Produced Water from the 

Marcellus and Barnett Shale Formations

Marcellus Shale

Barnett Shale