United States Office of Water EPA-820-R-16-003 

Environmental Protection Washington, DC 20460 June 2016

Agency 

Technical Development 

Document for the Effluent 

Limitations Guidelines and 

Standards for the Oil and 

Gas Extraction Point Source 

Category
Technical Development Document for the 

Effluent Limitations Guidelines and 

Standards for the Oil and Gas Extraction

Point Source Category

EPA-820-R-16-003

JUNE 2016

U.S. Environmental Protection Agency

Office of Water (4303T)

Washington, DC 20460
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 AND BACKGROUND ......................................................................... 1

1 Introduction......................................................................................................................... 1

1.1 Purpose and Summary of the Rule.......................................................................... 1

1.2 How to Use This Document.................................................................................... 1

2 Regulatory Background ...................................................................................................... 2

2.1 Background on Effluent Limitations Guidelines and Pretreatment 

Standards................................................................................................................. 2

2.2 The National Pretreatment Program (40 CFR part 403)......................................... 5

2.3 Oil and Gas Extraction ELG Rulemaking History ................................................. 8

3 State Pretreatment Requirements........................................................................................ 9

4 Related Federal Requirements.......................................................................................... 11

CHAPTER B. SCOPE AND INDUSTRY DESCRIPTION ..................................................................... 12

1 Unconventional Oil and Gas............................................................................................. 12

1.1 Overview of Oil and Gas Resources..................................................................... 12

1.2 Scope of This Rulemaking.................................................................................... 14

2 Industry Description: UOG Well Development Process.................................................. 22

2.1 UOG Exploration.................................................................................................. 23

2.2 UOG Well Drilling and Construction................................................................... 24

2.3 UOG Well Completion ......................................................................................... 27

2.4 UOG Production ................................................................................................... 32

3 Industry Description: UOG Well Drilling and Completion Activity................................ 33

3.1 Historical and Current UOG Drilling Activity ..................................................... 33

3.2 UOG Resource Potential....................................................................................... 37

3.3 Current and Projections of Future UOG Well Completions................................. 38

CHAPTER C. UNCONVENTIONAL OIL AND GAS EXTRACTION WASTEWATER VOLUMES 

AND CHARACTERISTICS ......................................................................................... 40

1 Fracturing Fluid Characteristics........................................................................................ 41

1.1 Base Fluid Composition........................................................................................ 42

1.2 Additives............................................................................................................... 43

1.3 Fracturing Fluids................................................................................................... 47

2 UOG Extraction Wastewater Volumes............................................................................. 48

2.1 UOG Extraction Wastewater Volumes by Resource and Well Trajectory........... 48

2.2 UOG Produced Water Volumes by Formation..................................................... 53
Table of Contents

CONTENTS (Continued)

Page

v

3 UOG Extraction Wastewater Characterization................................................................. 59

3.1 Availability of Data for UOG Extraction Wastewater Characterization .............. 59

3.2 UOG Extraction Wastewater Constituent Categories........................................... 59

3.3 UOG Produced Water Characterization Changes over Time ............................... 80

CHAPTER D. UOG EXTRACTION WASTEWATER MANAGEMENT AND DISPOSAL 

PRACTICES ............................................................................................................. 82

1 Overview of UOG Extraction Wastewater Management and Disposal Practices............ 82

2 Injection into Disposal Wells............................................................................................ 88

2.1 Regulatory Framework for Underground Injection .............................................. 89

2.2 Active Disposal Wells and Volumes .................................................................... 89

2.3 Underground Injection of UOG Wastewaters....................................................... 92

3 Reuse/Recycle in Fracturing............................................................................................. 95

3.1 Reuse/Recycle Strategies...................................................................................... 97

3.2 Reuse/Recycle Drivers........................................................................................ 100

3.3 Other Considerations for Reuse/Recycle ............................................................ 105

4 Transfer to CWT Facilities ............................................................................................. 107

4.1 Types of CWT Facilities..................................................................................... 107

4.2 Active CWT Facilities Accepting UOG Extraction Wastewater........................ 109

5 Discharge to POTWs ...................................................................................................... 111

5.1 POTW Background and Treatment Levels......................................................... 112

5.2 History of POTW Acceptance of UOG Extraction Wastewater......................... 115

5.3 How UOG Extraction Wastewater Constituents Interact with POTWs ............. 120

CHAPTER E. REFERENCE FLAGS AND LIST............................................................................... 155

CHAPTER F. APPENDICES......................................................................................................... 169
List of Tables

vi

LIST OF TABLES

Page

Table A-1. Summary of State Regulations/Guidance....................................................................10

Table B-1. Summary of State Regulatory Definitions...................................................................16

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

Type (as of October 9, 2015).......................................................................................36

Table B-3. UOG Potential by Resource Type as of January 1, 2013 ............................................38

Table C-1. Sources for Base Fluid in Hydraulic Fracturing ..........................................................43

Table C-2. Fracturing Fluid Additives, Common Compounds, and Common Uses.....................44

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

Gas Wells from FracFocus (2011–2013).....................................................................46

Table C-4. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in 

Oil Wells from FracFocus (2011–2013)......................................................................46

Table C-5. Median Drilling Wastewater Volumes for UOG Horizontal and Vertical Wells 

in Pennsylvania ............................................................................................................51

Table C-6. Drilling Wastewater Volumes Generated per Well by UOG Formation.....................51

Table C-7. UOG Well Flowback Recovery by Resource Type and Well Trajectory....................52

Table C-8. Long-Term Produced Water Generation Rates by Resource Type and Well 

Trajectory.....................................................................................................................53

Table C-9. Produced Water Volume Generation by UOG Formation...........................................54

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

Drilling Wastewater from Marcellus Shale Formation Wells .....................................61

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

Produced Water............................................................................................................62

Table C-12. Concentrations of Bromide and Sulfate in UOG Drilling Wastewater from 

Marcellus Shale Formation Wells................................................................................67

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

Produced Water............................................................................................................68

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

from Marcellus Shale Formation Wells.......................................................................69

Table C-15. Concentrations of Select Organic Constituents in UOG Produced Water.................70

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

from Marcellus Shale Formation Wells.......................................................................71

Table C-17. Concentrations of Select Metal Constituents in UOG Produced Water....................73
List of Tables

LIST OF TABLES (Continued)

Page

vii

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

Wastewater from Marcellus Shale Formation Wells...................................................77

Table C-19. Concentrations of Select Radioactive Constituents in UOG Produced Water ..........77

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

and Drinking Water Sources Throughout the United States (pCi/L)...........................78

Table D-1. UOG Produced Water Management Practices ............................................................86

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

(Primarily 2012 and 2013 Data) ..................................................................................91

Table D-3. Distribution of Active Class II Disposal Wells on Tribal Lands (2014 Data) ............92

Table D-4. Reuse/Recycle Practices in 2012 as a Percentage of Total Produced Water 

Generated as Reported by Respondents to 2012 Survey .............................................97

Table D-5. Reported Reuse/Recycle Criteria...............................................................................102

Table D-6. Reported Reuse/Recycle Practices as a Percentage of Total Fracturing 

Volume.......................................................................................................................103

Table D-7. Number of CWT Facilities That Have Accepted or Plan to Accept UOG 

Extraction Wastewater, by State ................................................................................110

Table D-8. Typical Composition of Untreated Domestic Wastewater........................................112

Table D-9. Typical Percent Removal Capabilities from POTWs with Secondary 

Treatment ...................................................................................................................114

Table D-10. U.S. POTWs by Treatment Level in 2012...............................................................115

Table D-11. POTWs That Accepted UOG Extraction Wastewater Directly from Onshore 

UOG Operators..........................................................................................................117

Table D-12. Percentage of Total POTW Influent Wastewater Composed of UOG 

Extraction Wastewater at POTWs Accepting Wastewater from UOG 

Operators....................................................................................................................119

Table D-13. Summary of Studies About POTWs Receiving Oil and Gas Extraction 

Wastewater Pollutants................................................................................................121

Table D-14. Clairton Influent Oil and Gas Extraction Wastewater Characteristics....................125

Table D-15. Trucked COG Extraction Wastewater Treated at McKeesport POTW from 

November 1 Through 7, 2008....................................................................................126

Table D-16. McKeesport POTW Removal Rates Calculated for Local Limits Analysis ...........127

Table D-17. Constituent Concentrations in UOG Extraction Wastewater Treated at the 

McKeesport POTW Before Mixing with Other Influent Wastewater.......................128
List of Tables

LIST OF TABLES (Continued)

Page

viii

Table D-18. McKeesport POTW Effluent Concentrations With and Without UOG 

Extraction Wastewater...............................................................................................129

Table D-19. Charleroi POTW Paired Influent/Effluent Data and Calculated Removal 

Rates...........................................................................................................................131

Table D-20. Franklin Township POTW Effluent Concentrations With and Without 

Industrial Discharges from the Tri-County CWT Facility.........................................134

Table D-21. TDS Concentrations in Baseline and Pilot Study Wastewater Samples at 

Warren POTW ...........................................................................................................137

Table D-22. EPA Region 5 Compliance Inspection Sampling Data ...........................................137

Table D-23. Inhibition Threshold Levels for Various Treatment Processes...............................139

Table D-24. Industrial Wastewater Volumes Received by New Castle POTW (2007–

2009) ..........................................................................................................................144

Table D-25. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW 

(NPDES Permit Number PA0027511) ......................................................................145

Table D-26. Concentrations of DBPs in Effluent Discharges at One POTW Not 

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

Gas Wastewater (μg/L)..............................................................................................151

Table E-1. Source List .................................................................................................................155

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

FDMS.........................................................................................................................169

Table F-2. Crosswalk Between TDD and Supporting Memoranda.............................................171

Table F-3. UOG Resource Potential: Shale as of January 1, 2013..............................................179

Table F-4. UOG Resource Potential: Tight as of January 1, 2013 ..............................................180
List of Figures

ix

LIST OF FIGURES

Page

Figure B-1. Historical and Projected Crude Oil Production by Resource Type............................13

Figure B-2. Historical and Projected Natural Gas Production by Resource Type.........................13

Figure B-3. Major U.S. Shale Plays (Updated April 13, 2015).....................................................20

Figure B-4. Major U.S. Tight Plays (Updated June 6, 2010) ........................................................21

Figure B-5. UOG Extraction Wastewater......................................................................................23

Figure B-6. Horizontal (A), Vertical (B), and Directional (C) Drilling Schematic.......................25

Figure B-7. Length of Time to Drill a Well in Various UOG Formations (2012 through 

2014) ............................................................................................................................27

Figure B-8. Hydraulic Fracturing Schematic.................................................................................29

Figure B-9. Freshwater Impoundment...........................................................................................30

Figure B-10. Vertical Gas and Water Separator............................................................................31

Figure B-11. Fracturing Tanks.......................................................................................................32

Figure B-12. Produced Water Storage Tanks................................................................................33

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

Time .............................................................................................................................35

Figure B-14. Projections of UOG Well Completions....................................................................39

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

Pennsylvania (2004–2014)...........................................................................................49

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

Fracturing.....................................................................................................................50

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

Oil and Gas Formations...............................................................................................65

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

Produced Water (LTPW) from Shale and Tight Oil and Gas Formations...................66

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

and Gas Formations .....................................................................................................76

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

Marcellus and Barnett Shale Formations.....................................................................81

Figure D-1. UOG Produced Water Management Methods ...........................................................83

Figure D-2. UOG Drilling Wastewater Management Methods.....................................................84

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

Pennsylvania (2008–2014)...........................................................................................87
List of Figures

LIST OF FIGURES (Continued)

Page

x

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

Basin ............................................................................................................................88

Figure D-5. U.S. Injection for Disposal Volume and UOG Production over Time ......................93

Figure D-6. Injection for Disposal Volume and Crude Oil Production over Time in North 

Dakota ..........................................................................................................................94

Figure D-7. Injection for Disposal Volume, Cumulative Bakken Wells Drilled, and 

Cumulative Disposal Wells Drilled in North Dakota ..................................................94

Figure D-8. Flow Diagram of On-the-Fly UOG Produced Water Treatment for 

Reuse/Recycle............................................................................................................100

Figure D-9. Hypothetical UOG Produced Water Generation and Base Fracturing Fluid 

Demand over Time ....................................................................................................104

Figure D-10. UOG Extraction Wastewater Management Practices Used in the Marcellus 

Shale (Top: Southwestern Region; Bottom: Northeastern Region)...........................106

Figure D-11. Number of Known Active CWT Facilities over Time in the Marcellus and 

Utica Shale Formations..............................................................................................111

Figure D-12. Typical Process Flow Diagram at a POTW ...........................................................113

Figure D-13. Clairton POTW: Technical Evaluation of Treatment Processes’ Ability to 

Remove Chlorides and TDS ......................................................................................124

Figure D-14. McKeesport POTW: Technical Evaluation of Treatment Processes’ Ability 

to Remove Chlorides and TDS ..................................................................................126

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

POTW Flows .............................................................................................................130

Figure D-16. Johnstown POTW: Annual Average Daily Effluent Concentrations and 

POTW Flows .............................................................................................................141

Figure D-17. California POTW: Annual Average Daily Effluent Concentrations and 

POTW Flows .............................................................................................................142

Figure D-18. Charleroi POTW: Annual Average Daily Effluent Concentrations and 

POTW Flows .............................................................................................................143

Figure D-19. Barium Sulfate Scaling in Haynesville Shale Pipe ................................................148

Figure D-20. THM Speciation in a Water Treatment Plant (1999–2013)...................................153

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

Marcellus and Barnett Shale Formations...................................................................182
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

NPDES National Pollutant Discharge Elimination System

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

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 produced water, brine, salt water, water, steam, 

polymers, or carbon dioxide into oil-bearing formations to recover 

residual oil and—in some limited applications—natural gas.2

Conventional oil and gas 

(COG) resources

Crude oil3 and natural gas4 that is produced by a well drilled into 

a geologic formation in which the reservoir and fluid 

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

wellbore.

Drill cuttings The particles generated by drilling into subsurface geologic 

formations and carried out from the wellbore with the drilling 

mud.

Drilling mud The circulating fluid (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 mud

(fluid) and drill cuttings during the drilling process.

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

Development Document for the Effluent Limitations Guidelines and Standards for the Oil and Gas Extraction Point 

Source Category (TDD) and the TDD supporting documentation. 2 The injection of fluids for hydraulic fracturing is also a form of enhanced recovery. See Legal Environmental 

Assistance Foundation v. EPA, 276 F.3d 1253 (11th Cir. 2001). However, Congress amended the Safe Drinking 

Water Act to exempt hydraulic fracturing (except where diesel fuels are used) from regulation under the UIC 

program (SDWA Section 1421(d)(1)). Because there are currently no Class II permits for hydraulic fracturing 

activities, EPA did not consider wells that have been hydraulically fractured within the context of this TDD. 3 Crude oil includes “lease condensates,” components that are liquid at ambient temperature and pressure.

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

fluid

The primary component of fracturing fluid to which proppant 

(sand) and chemicals are added. Hydraulic fracturing base fluids 

are typically water-based; however there are cases of non-aqueous 

fracturing fluids (e.g., compressed nitrogen, propane, carbon 

dioxide). Water-based fluid may consist of only fresh water or a 

mixture of fresh water, brackish water and/or reused/recycled 

wastewater.

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 hydraulic 

fracturing base fluid.

Long-term produced 

water (LTPW)

The produced water generated during the production phase of the 

well, after the initial flowback process, which can include 

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, including suspended solids, oil and grease and

bacteria, or remove and/or exchange certain ions that can cause 

scale to form on equipment and interfere with fracturing chemical 

additives. These technologies are not designed to reduce the levels 

of dissolved constituents, which are the majority of compounds 

that contribute to TDS in UOG extraction wastewater.

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 fluid (brine) brought up from the hydrocarbon-bearing strata 

during the extraction of oil and gas, and includes, where present, 

formation water, injection water, and any chemicals added 

downhole or during the oil/water separation process. 

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.
Glossary

GLOSSARY (Continued)

xv

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.

TDS removal technologies Technologies capable of removing dissolved constituents that 

contribute to TDS (e.g., sodium, chloride, calcium) as well as the 

constituents removed by non-TDS removal technologies. 

Treatment systems with these treatment technologies typically 

include non-TDS removal technologies for pretreatment (e.g., 

TSS, oil and grease).

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 oil5 and natural gas6 produced by a well drilled into a shale 

and/or tight formation (including, but not limited to, shale gas, 

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

definition of UOG does not include CBM.

UOG extraction 

wastewater

Wastewater sources associated with production, field exploration, 

drilling, well completion, or well treatment for unconventional oil 

and gas extraction (including, but not limited to, drilling muds, 

drill cuttings, produced sand, produced water).

 5 Crude oil includes “lease condensates,” components that are liquid at ambient temperature and pressure. 6 Natural gas can include “natural gas liquids,” components that are liquid at ambient temperature and pressure.
Chapter A—Introduction

1

Chapter A. INTRODUCTION AND BACKGROUND

1 INTRODUCTION

1.1 Purpose and Summary of the Rule

The EPA is publishing a final Clean Water Act (CWA) regulation that better protects 

human health and the environment and protects the operational integrity of publicly owned 

treatment works (POTWs) by establishing pretreatment standards that prevent the discharge of 

pollutants in wastewater from onshore unconventional oil and gas (UOG) extraction facilities to 

POTWs (also called municipal wastewater treatment plants). UOG extraction wastewater can be 

generated in large quantities and has constituents that are potentially harmful to human health 

and the environment. Because these constituents are not typical of POTW influent wastewater, 

some UOG extraction wastewater constituents can be discharged, untreated, from the POTW to 

the receiving stream; can disrupt the operation of the POTW (e.g., by inhibiting biological 

treatment); can accumulate in biosolids (sewage sludge), limiting its use; and can facilitate the 

formation of harmful disinfection byproducts (DBPs).

Based on the information collected by the EPA, the requirements in this final rule reflect 

current industry practices for onshore UOG extraction facilities. Therefore, the EPA does not 

project that the final rule will impose any costs or lead to pollutant removals: rather, it will 

ensure that such current industry best practice is maintained over time. 

1.2 How to Use This Document

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

extraction wastewater. The remainder of Chapter A describes the regulatory background for this 

rulemaking and related federal regulations. Subsequent chapters provide further detail on what 

“unconventional oil and gas” means in the context of this rulemaking, then further detail on 

UOG resources, extraction processes, and wastewater generation. The subsequent chapters also 

describe the quantity and quality of wastewater generated and the practices industry uses to 

manage and/or dispose of UOG extraction wastewater. 

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

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

The EPA’s quality assurance (QA) and quality control (QC) activities for this rulemaking 

include the development, approval, and implementation of Quality Assurance Project Plans for 

the use of environmental data generated or collected from sampling and analyses, existing 

databases, and literature searches. 

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

the document by reference ID numbers (e.g., 73) and document control numbers (DCNs) (e.g., 

DCN SGE00586). Information presented in this document was taken from existing data sources, 

including state and federal agency databases, journal articles and technical papers, technical 

references, vendor websites, and industry/vendor telephone calls, meetings, and site visits. The 

EPA classified the quality of the data sources with a “data source quality flag,” assigning ratings 

from “A” for peer-reviewed journal articles and documents prepared by or for a government 

agency to “D” for documents prepared by a source that could not be verified and that do not 
Chapter A—Introduction

2

include citation information, such as some newspaper articles and conference presentations. For 

each source cited in this document, the reference list in Chapter E includes the reference ID 

number, DCN, source citation, and data source quality flag. 

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

certain topics, tables, and/or figures contained in the TDD. Table F-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 it discusses. Table F-1 also lists the relevant TDD sections associated 

with each memorandum. Table F-2 contains further information about each table and figure in 

the TDD, including the original source(s) of information for the data presented in the table or 

figure and the relevant memorandum and attachments, where applicable. 

2 REGULATORY BACKGROUND

Wastewater discharges from crude oil7 and natural gas8 extraction facilities are subject to 

federal regulation. Section A.2.1 describes effluent limitations guidelines and standards (ELGs),

which are federal regulations that control pollutants in industrial wastewater discharges to waters 

of the United States and POTWs, respectively. Section A.2.2 discusses the national pretreatment 

program (40 CFR part 403). Section A.2.3 describes ELGs specifically for the Oil and Gas 

Extraction point source category (40 CFR part 435).

2.1 Background on Effluent Limitations Guidelines and Pretreatment Standards

Congress passed the Federal Water Pollution Control Act Amendments of 1972, also 

known as the CWA, to “restore and maintain the chemical, physical, and biological integrity of 

the Nation’s waters” (33 U.S.C. 1251(a)). The CWA establishes a comprehensive program for 

protecting our nation’s waters. Among its core provisions, it prohibits the discharge of pollutants 

from a point source to waters of the United States, except as authorized under the CWA. Under 

its Section 402, discharges may be authorized through a National Pollutant Discharge 

Elimination System (NPDES) permit. The CWA establishes a two-pronged approach for these 

permits, technology-based controls that establish the floor of performance for all dischargers, and 

water-quality-based limits where the technology-based limits are insufficient for the discharge to 

meet applicable water quality standards. To serve as the basis for the technology-based controls, 

the CWA authorizes the EPA to establish national technology-based effluent limitations 

guidelines and new source performance standards (NSPS) for discharges from different 

categories of point sources, such as industrial, commercial, and public sources, that discharge 

directly into waters of the United States. 

Direct dischargers (those discharging directly to surface waters) must comply with 

effluent limitations in NPDES permits. Technology-based effluent limitations in NPDES permits 

for direct dischargers are derived from effluent limitations guidelines (CWA Sections 301 and 

304) and NSPS (CWA Section 306) promulgated by the EPA, or based on best professional 

judgment where the EPA has not promulgated an applicable effluent guideline or NSPS (CWA 

 7 Crude oil includes “lease condensates,” components that are liquid at ambient temperature and pressure. 8 Natural gas can include “natural gas liquids,” components that are liquid at ambient temperature and pressure.
Chapter A—Introduction

3

Section 402(a)(1)(B) and 40 CFR 125.3). The effluent guidelines and NSPS established by 

regulation for categories of industrial dischargers are based on the degree of control that can be 

achieved using various levels of pollution control technology, as specified in the Act. 

The EPA promulgates national effluent guidelines and NSPS for major industrial 

categories for three classes of pollutants:

• Conventional pollutants (total suspended solids, oil and grease, biochemical oxygen 

demand [BOD5], fecal coliform, and pH), as outlined in CWA Section 304(a)(4) and 

40 CFR 401.16

• Toxic pollutants (e.g., metals such as arsenic, mercury, selenium, and chromium; and 

organic pollutants such as benzene, benzo-a-pyrene, phenol, and naphthalene), as 

outlined in Section 307(a) of the Act, 40 CFR 401.15, and 40 CFR part 423, 

Appendix A

• Nonconventional pollutants, which are those pollutants that are not categorized as 

conventional or toxic (e.g., ammonia-N, phosphorus, and TDS)

The CWA also authorizes the EPA to promulgate nationally applicable pretreatment 

standards that restrict pollutant discharges from facilities that discharge pollutants indirectly, by 

sending wastewater to POTWs, as outlined in Sections 307(b) and (c) and 33 U.S.C. 1317(b) and 

(c). Specifically, the CWA authorizes the EPA to establish pretreatment standards for those 

pollutants in wastewater from indirect dischargers that the EPA determines are not susceptible to 

treatment by a POTW or which would interfere with POTW operations. Pretreatment standards 

must be established to prevent the discharge of any pollutant that can pass through, interfere 

with, or is otherwise incompatible with POTW operations (CWA Sections 307(b) and (c)). 

There are four types of standards applicable to direct dischargers (facilities that discharge 

directly to surface waters), and two types of standards applicable to indirect dischargers 

(facilities that discharge to POTWs), described in detail below. Subsections 1 through 4 describe 

standards for direct discharges and subsection 5 describes standards for indirect discharges.

2.1.1 Best Practicable Control Technology Currently Available (BPT) 

Traditionally, the EPA defines BPT effluent limitations based on the average of the best 

performances of facilities within the industry, grouped to reflect various ages, sizes, processes, or 

other common characteristics. BPT effluent limitations control conventional, toxic, and 

nonconventional pollutants. In specifying BPT, the EPA looks at a number of factors. The EPA 

first considers the cost of achieving effluent reductions in relation to the effluent reduction 

benefits. The Agency also considers the age of equipment and facilities, the processes employed, 

engineering aspects of the control technologies, any required process changes, non-water-quality 

environmental impacts (including energy requirements), and such other factors as the 

Administrator deems appropriate. See CWA Section 304(b)(1)(B). If existing performance is 

uniformly inadequate, however, the EPA can establish limitations based on higher levels of 

control than what is currently in place in an industrial category, if it determines that the 

technology is available in another category or subcategory and can be practically applied.
Chapter A—Introduction

4

2.1.2 Best Conventional Pollutant Control Technology (BCT)

The 1977 amendments to the CWA require the EPA to identify additional levels of 

effluent reduction for conventional pollutants associated with BCT technology for discharges 

from existing industrial point sources. In addition to other factors specified in Section 

304(b)(4)(B), the CWA requires that the EPA establish BCT limitations after consideration of a 

two-part “cost reasonableness” test. The EPA explained its methodology for the development of 

BCT limitations on July 9, 1986 (51 Fed. Reg. 24974). Section 304(a)(4) designates the 

following as conventional pollutants: BOD5, total suspended solids (TSS), fecal coliform, pH, 

and any additional pollutants defined by the Administrator as conventional. The Administrator 

designated oil and grease as an additional conventional pollutant on July 30, 1979 (44 Fed. Reg. 

44501; 40 CFR 401.16).

2.1.3 Best Available Technology Economically Achievable (BAT)

BAT represents the second level of stringency for controlling direct discharge of toxic 

and nonconventional pollutants. In general, BAT-based effluent guidelines and NSPS represent 

the best available economically achievable performance of facilities in the industrial subcategory 

or category. Following the statutory language, the EPA considers the technological availability 

and the economic achievability in determining what level of control represents BAT (CWA 

Section 301(b)(2)(A)). Other statutory factors that the EPA considers in assessing BAT are the 

cost of achieving BAT effluent reductions, the age of equipment and facilities involved, the 

process employed, potential process changes, and non-water-quality environmental impacts, 

including energy requirements and such other factors as the Administrator deems appropriate

(CWA Section 304(b)(2)(B)). The Agency retains considerable discretion in assigning the weight 

to be accorded these factors (Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1045, D.C. Cir. 1978). 

2.1.4 Best Available Demonstrated Control Technology (BADCT)/New Source Performance 

Standards (NSPS)

NSPS reflect effluent reductions that are achievable based on the best available 

demonstrated control technology (BADCT). Owners of new facilities have the opportunity to 

install the best and most efficient production processes and wastewater treatment technologies. 

As a result, NSPS should represent the most stringent controls attainable through the application 

of the BADCT for all pollutants (that is, conventional, nonconventional, and toxic pollutants). In 

establishing NSPS, the EPA is directed to take into consideration the cost of achieving the 

effluent reduction and any non-water quality environmental impacts and energy requirements

(CWA section 306(b)(1)(B)).

2.1.5 Pretreatment Standards for Existing Sources (PSES) and New Sources (PSNS)

As discussed above, Section 307(b) of the Act calls for the EPA to issue pretreatment 

standards for discharges of pollutants from existing sources to POTWs. Section 307(c) of the Act 

calls for the EPA to promulgate PSNS. Both standards are designed to prevent the discharge of 

pollutants that pass through, interfere with, or are otherwise incompatible with the operation of 

POTWs. Categorical pretreatment standards for existing sources are technology-based and are 

analogous to BPT and BAT effluent limitations guidelines, and thus the Agency typically 

considers the same factors in promulgating PSES as it considers in promulgating BAT. See

Natural Resources Defense Council v. EPA, 790 F.2d 289, 292 (3rd Cir. 1986). Similarly, in 
Chapter A—Introduction

5

40 CFR 403.5(b) notes eight categories of pollutant 

discharge prohibitions: 

1. Pollutants that create a fire or explosion hazard in 

the POTW

2. Pollutants that will cause corrosive structural 

damage to the POTW

3. Solid or viscous pollutants in amounts that will 

obstruct the flow in the POTW, resulting in 

interference

4. Any pollutant, including oxygen-demanding 

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

flow rate and/or pollutant concentration that will 

interfere with the POTW

5. Heat in amounts that will inhibit biological activity 

in the POTW, resulting in interference

6. Petroleum oil, nonbiodegradable cutting oil, or 

products of mineral oil origin in amounts that will 

cause interference or pass-through

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

vapors, or fumes within the POTW in a quantity that 

may cause acute worker health and safety problems

8. Any trucked or hauled pollutants, except at 

discharge points designated by the POTW

establishing pretreatment standards for new sources, the Agency typically considers the same 

factors in promulgating PSNS as it considers in promulgating NSPS (BADCT).

2.2 The National Pretreatment Program (40 CFR part 403)

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

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

introduction to the program (19 DCN SGE00249), these regulations apply to all non-domestic 

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

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

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

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 CFR part 403.

Pretreatment Program Implementation 

Control authorities implement and 

enforce the National Pretreatment Program. 

The Control Authority refers to the POTW if 

the POTW has an approved Pretreatment 

Program, or the state or the EPA if the 

POTW does not have an approved Program. 

Most of the responsibility for implementing 

the National Pretreatment Program rests on 

local municipalities. For example, 40 CFR

403.8(a) requires that POTWs designed to 

treat more than 5 million gallons per day 

(MGD) of wastewater and receiving 

pollutants from IUs that pass through or 

interfere with the POTW’s operation must 

establish a local pretreatment program.

9 The 

POTW’s NPDES permit will include 

requirements for developing a local 

pretreatment program that will control the 

wastewater discharged to the POTW by IUs.

The National Pretreatment Program 

regulations identify specific requirements 

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

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

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

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

6

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 technologybased 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 CFR 403.5(a) and (b), respectively.

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

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

pollutants that are limited in the POTW’s NPDES permit are prohibited from passthrough by the general prohibitions.

• Specific prohibitions in 40 CFR 403.5(b) forbid eight categories of pollutant 

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

system. Pollutant discharges outside these defined categories are not specifically 

prohibited.

Categorical pretreatment standards. As discussed in Section A.2.1, the CWA authorizes 

the EPA to promulgate national categorical pretreatment standards for industrial sources that 

discharge to POTWs. Developed by the EPA on an industry-specific basis, categorical 

pretreatment standards set regulatory requirements based on the performance of technology. 

These requirements typically limit discharges of toxic and nonconventional pollutants that could 

cause pass-through or interference.

10 Categorical pretreatment standards represent a baseline 

level of control that every IU in the category must meet, without regard to the individual POTW 

to which it discharges. 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 

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

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

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

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

the candidate technology basis.
Chapter A—Introduction

7

residential sources), and implement a system to control industrial discharges. Additional 

information can be found in the EPA’s 2004 Local Limits Development Guidance (80 DCN 

SGE00602).

Responsibilities of Control Authorities and IUs

The Control Authority (POTW, state, or EPA) controls the discharges from the IU 

through an individual control mechanism, often called an IU permit. The Control Authority may 

also issue general permits under certain conditions if it has adequate legal authority and 

approval. POTWs with approved local pretreatment programs must have procedures for: 

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

introduced to the POTW

• 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 (19 DCN SGE00249). The 

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

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

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

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

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

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

Hauled Wastewater

As discussed in the EPA’s Introduction to the National Pretreatment Program (19 DCN 

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

accept trucked wastewater. An IU may truck its wastewater to a POTW when it is outside the 

POTW’s service area (e.g., in a rural area) and is not connected to the collection system. Just like 

wastewater received through the collection system, trucked wastewater is subject to the General 

Pretreatment Regulations and is also subject to applicable categorical pretreatment standards. 

Therefore, the POTW must regulate hauled wastewater from CIUs or hauled wastewater that 

otherwise qualifies the discharger as an IU in accordance with the requirements of the General 

Pretreatment Regulations and any applicable categorical pretreatment standards, including any 

applicable requirements for permitting and inspecting the facility that generates the wastewater. 
Chapter A—Introduction

8 

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

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

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

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

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

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

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

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

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

hauled waste without considering the implications of its acceptance (see 40 CFR part 260). 

2.3 Oil and Gas Extraction ELG Rulemaking History

The EPA first promulgated the Oil and Gas Extraction ELGs (40 CFR part 435) in 1979, 

and substantially amended the regulation in 1993 (Offshore), 1996 (Coastal), and 2001 

(Synthetic-Based Drilling Fluids). The Oil and Gas Extraction industrial category is 

subcategorized11 in 40 CFR part 435 as follows: 

• Subpart A: Offshore

• Subpart C: Onshore

• Subpart D: Coastal

• Subpart E: Agricultural and Wildlife Water Use

• Subpart F: Stripper Wells

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

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

and gas industry. The limitations for direct dischargers in the Onshore Subcategory represent 

Best Practicable Control Technology Currently Available (BPT). Based on the availability and 

economic practicability of underground injection technologies, the BPT-based limitations for 

direct dischargers require zero discharge of pollutants to waters of the United States. However, 

there are currently no requirements in subpart C that apply to onshore oil and gas extraction 

facilities that are “indirect dischargers,” i.e., those that send their discharges to POTWs.

Although oil and gas resources occur in unconventional formations in offshore and coastal 

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

onshore in regions where the regulations in subpart C (Onshore) and subpart E (Agricultural and 

Wildlife Water Use) apply; thus, the gap in onshore regulations is the focus of this final rule. For 

this reason, only the regulations that apply to onshore oil and gas extraction are described in 

more detail here.

Note that facilities that accept oil and gas extraction wastewater from offsite may be 

subject to requirements in 40 CFR part 437, the Centralized Waste Treatment category (see 

Section D.4 for more information). 

 

11 Subpart B is reserved. 
Chapter A—Introduction

9

Subpart C: Onshore Subcategory 

Applicability. As set forth in 40 CFR 435.30, subpart C applies to facilities engaged in 

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

extraction industry, located landward of the inner boundary of the territorial seas—and not 

included in the definition of other subparts, including subpart D (Coastal) at 40 CFR 435.40.

Direct discharge requirements. The regulations at 40 CFR 435.32 specify the following 

for BPT:

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

from any source associated with production, field exploration, drilling, well 

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

and produced sand). 

Subpart E: Agricultural and Wildlife Use Subcategory

Applicability. As set forth in 40 CFR 435.50, subpart E applies to onshore facilities 

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

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

the United States. Definitions in 40 CFR 435.51(c) explain that the term “use in agricultural or 

wildlife propagation” means that two things are true:

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

watering or other agricultural uses.

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

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

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

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

produced sands). Therefore, the only allowable discharge under this subpart is produced water12

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

and grease concentration not exceeding 35 mg/L.

3 STATE PRETREATMENT REQUIREMENTS 

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

storage, and disposal of oil and gas extraction wastewater, including regulations concerning 

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

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

by limiting the management and disposal options available to operators. Table A-1 summarizes 

state regulations and/or guidance related to UOG extraction wastewater discharges to POTWs.

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

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

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

added downhole or during the oil/water separation process.”
Chapter A—Introduction

10

Table A-1. Summary of State Regulations/Guidance

State

State 

Authority(s)

State Code

(Source DCN) State’s Relevant Regulations or Guidance

PA

EPA 

Region 3; 

PA DEP

25 PA Code Ch. 

95.10 

(14 SGE00187; 

148 SGE00982; 

63 SGE00545)

The Pennsylvania Code, amended in 2010, states that waters of 

Pennsylvania will not exceed a threshold of 500 mg/L of TDS. In addition, 

the standard is applied specifically to the natural gas sector, which PA DEP 

based on several factors. Discharge loads of TDS authorized by PA DEP 

are exempt from the regulation until the net load is to be increased. It is 

important to note that only an increase in net TDS load is considered to be 

a new or expanding discharge loading. Further (according to PA Bulletin, 

Doc. No. 10-1572, 14 DCN SGE00187), the pretreatment requirements are 

“that POTWs may accept these wastewaters only if the wastes are first 

treated at a CWT facility and meet the end-of-pipe effluent standards 

imposed by the rule. In effect, the final rule regulates these indirect 

discharges in a manner consistent with direct discharges of these wastes.” 

OH OH EPA; 

OH DNR

OH R.C. Title 

15, Chapter 

1509, part 

22(C)(1) 

(149 SGE00983)

The Ohio Revised Code includes a provision that describes the acceptable 

disposal of brine:13 injection into an underground formation, surface 

application, enhanced recovery, or in any other manner that is approved by 

a permit. This provision applies to any well except an exempt 

Mississippian well.14

WV WV DEP (129 SGE00766; 

130 SGE00767)

A WV DEP guidance document “discourages POTWs from accepting 

wastewater from oil and gas operations.” This document groups coalbed 

methane and Marcellus Shale wastewaters together. WV DEP discourages 

this practice “because these wastewaters essentially pass through sewage 

treatment plants and can cause inhibition and interference with treatment 

plant operations” (130 DCN SGE00767).

MI MI DEQ

MI Oil and Gas 

Regulations, part 

324.703

(20 SGE00254)

Michigan’s Oil and Gas Regulations discuss the well permittee’s 

responsibility for handling waste. The regulations dictate that oil and gas 

waste must be injected into an underground well such that there is no 

additional wastewater stream.

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

Protection Agency; OH DNR—Ohio Department of Natural Resources; R.C.—Revised Code; WVDEP—West 

Virginia Department of Environmental Protection; MI DEQ—Michigan Department of Environmental Quality

 13 The Ohio EPA defines brine as “all saline geological formation water resulting from, obtained from, or produced 

in connection with the exploration, drilling, or production of oil or gas, including saline water resulting from, 

obtained from, or produced in connection with well stimulation or plugging of a well.”

14 OH R.C. Section 1509.01 defines an “exempt Mississippian well” as a well that (1) was drilled and completed 

before January 1, 1980; (2) is in an unglaciated part of the state; (3) was completed in a reservoir no deeper than the 

Mississippian Big Injun sandstone in areas underlain by Pennsylvanian or Permian stratigraphy, or the Mississippian 

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

domestic use.
Chapter A—Introduction

11

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

Protect State Oil and Gas Water Resources (162 DCN SGE01077) describes a survey of 27 oiland-gas-producing states15

regarding the use of POTWs for discharging production fluids including flowback 

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

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

would not allow it as a matter of policy, and nine indicated it was either regulated 

by another state agency or would otherwise be allowed under certain 

circumstances....[A]s of 2013, six state oil and gas agencies had permitting 

requirements for POTWs accepting this waste.

In 2015, State Review of Oil & Gas Environmental Regulations, Inc. (STRONGER)16

published voluntary guidelines to help states develop effective oil and gas regulatory programs 

for production wastes (197 DCN SGE01208).

4 RELATED FEDERAL REQUIREMENTS

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

regulations to protect underground sources of drinking water through underground injection 

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

found at 40 CFR parts 144 through 148, and specifically prohibit any underground injection not 

authorized by UIC permit (40 CFR 144.11). They classify underground injection into six classes; 

wells that inject fluids brought to the surface in connection with oil and gas production are 

classified as Class II UIC wells (see Section D.2 for more information). Thus, an onshore oil and 

gas extraction facility that seeks to meet zero discharge requirements through underground 

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

permit.

 15 Alabama, Alaska, Arkansas, California, Colorado, Florida, Illinois, Indiana, Kansas, Kentucky, Louisiana, 

Michigan, Mississippi, Montana, Nebraska, New Mexico, New York, North Dakota, Ohio, Oklahoma, 

Pennsylvania, South Dakota, Texas, Utah, Virginia, West Virginia, and Wyoming. 16 STRONGER’s mission is to assist states in documenting the environmental regulations associated with the 

exploration, development, and production of crude oil and natural gas (214 DCN SGE01331).
Chapter B—Scope and Industry Description

12

Chapter B. SCOPE AND INDUSTRY DESCRIPTION

As described in Chapter A, this document provides background information and data 

considered in the development of the revised ELGs for the Oil and Gas Extraction point source 

category to address discharges from UOG extraction facilities to POTWs. To provide context for 

discussions of UOG extraction wastewater volumes and characteristics (Chapter C) and 

management and disposal practices (Chapter D), this chapter contains:

• An overview of UOG and the scope of this rulemaking

• A discussion of the UOG well development process, with a focus on the processes 

that generate UOG extraction wastewater

• A description of the industry, including historical and current UOG drilling and 

completion activity and total UOG resource potential

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

document in the record, titled Profile of the Unconventional Oil and Gas Industry, (212 DCN 

SGE01277).

1 UNCONVENTIONAL OIL AND GAS

1.1 Overview of Oil and Gas Resources

The United States has developed oil and gas resources since 1821 (1 DCN SGE00010). 

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

hydraulic fracturing made it possible to more economically produce oil and natural gas from 

tight and shale resources (164 DCN SGE01095). The Energy Information Administration 

(EIA)’s Annual Energy Outlook (AEO), which publishes historical and projected future oil and 

gas production by resource type, shows the increasingly large role of UOG. The EIA’s 2015

AEO projects that, in the next 30 years, the majority of the country’s crude oil17 and natural gas18

will come from unconventional resources (194 DCN SGE01192). Figure B-1 and Figure B-2

show the historical and future profiles of conventional oil and gas (COG) and UOG production 

in the United States by resource type according to the EIA.19 Coalbed methane (CBM) and COG 

are included in some of the figures in this chapter, but are identified separately within each 

figure. 

 17 Crude oil includes “lease condensates,” components that are liquid at ambient temperature and pressure. 18 Natural gas can include “natural gas liquids,” components that are liquid at ambient temperature and pressure.

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

Section B.1, this TDD differentiates between shale and tight oil.
Chapter B—Scope and Industry Description

13

Source: Created by the EPA using data from the EIA’s 2015 AEO (194 DCN SGE01192)

Figure B-1. Historical and Projected Crude Oil Production by Resource Type20

Source: Created by the EPA using data from the EIA’s 2015 AEO (194 DCN SGE01192)

Figure B-2. Historical and Projected Natural Gas Production by Resource Type21

 20 The EIA reported these data as “tight oil” production but stated that they include production from both shale oil 

formations (e.g., Bakken, Eagle Ford) and tight oil formations (e.g., Austin Chalk). Condensates are included in 

crude oil production. Alaska includes conventional onshore and offshore production in Figure B-1. 21 Alaska includes conventional onshore and offshore production in Figure B-2.
Chapter B—Scope and Industry Description

14 

1.2 Scope of This Rulemaking

The scope of this final rule is specific to pretreatment standards for onshore oil and gas 

extraction facilities (subpart C) of 40 CFR part 435. The EPA did not propose to reopen the 

regulatory requirements applicable to any other subpart or to the requirements for direct 

dischargers in subpart C. Rather, the scope of the final rule amends subpart C only to add 

requirements for indirect dischargers where there currently are none. Further, the final rule 

establishes requirements for wastewater discharges from UOG extraction facilities to POTWs. It 

does not establish requirements for wastewater discharges from COG or CBM extraction 

facilities. EPA reserves such standards for a future rulemaking, if appropriate. Section B.1.2.1

describes publicly available information defining onshore UOG extraction facilities, Section 

B.1.2.2 describes EPA’s record of UOG operators’ understanding of the names and types of 

formations from which they extract, and Section B.1.2.3 shows how EPA used this information 

to define the scope of this rule. 

1.2.1 Description of UOG Resources in Publicly Available Sources 

Onshore UOG extraction facilities make up the universe that would be subject to this 

final rule. For purposes of the final rule, the EPA is defining “unconventional oil and gas” as 

“crude oil and natural gas produced by a well drilled into a shale and/or tight formation 

(including, but not limited to, shale gas, shale oil, tight gas, tight oil).” This definition is 

generally consistent with those in other readily available sources, but—as indicated above—for 

purposes of this final rule, it does not extend to CBM. The following list presents examples of 

similar definitions from publicly available sources: 

• A report by the Energy Water Initiative (EWI)22 titled U.S. Onshore Unconventional 

Exploration and Production Water Management Case Studies defines unconventional 

as “Oil and natural gas production from shale and tight (low permeability) 

formations—a relatively new method of production—as compared to traditional oil 

and gas well drilling and production that tapped underground reserves with greater 

permeability” (224 DCN SGE01344).

• The 2014 Federal Multi-Agency Collaboration on Unconventional Oil and Gas 

Research states “Unconventional oil and gas (UOG) refers to resources such as shale 

gas, shale oil, tight gas, and tight oil that cannot be produced economically through 

standard drilling practices” (214 DCN SGE01330). 

• The U.S. Geological Survey (USGS) has described UOG resources as including shale 

and tight resources in several published documents. 

— USGS’s 2014 report titled U.S. Geological Survey Assessments of Continuous 

(Unconventional)23 Oil and Gas Resources, 2000 to 2011, categorizes resources 

into four distinct reservoir categories: “shale gas, coalbed gas, tight gas, and 

continuous oil” (211 DCN SGE01275). 

 

22 EWI is a collaborative effort among participating members of the U.S. oil and natural gas industry including 

Anadarko Petroleum, Apache Corporation, BP America Production Company, Chesapeake Energy Corporation, 

ConocoPhillips, Devon Energy, Marathon Oil, Newfield Exploration Company, Pioneer Natural Resources USA, 

Inc., QEP Resources, Inc., Southwestern Energy, Talisman Energy USA Inc.

23 USGS sometimes refers to unconventional resources as “continuous” resources.
Chapter B—Scope and Industry Description

15

— USGS’s 2015 report titled Trends in Hydraulic Fracturing...in the United States 

from 1947 through 2010—Data Analysis and Comparison to the Literature states 

that “...development of unconventional, continuous accumulations of oil, gas, and 

natural gas liquids, including tight oil and gas, coalbed methane, and shale gas...” 

(164 DCN SGE01095).

• Papers published by the Society of Petroleum Engineers (SPE) have described UOG 

as including shale and tight oil and gas. For example, SPE’s 2012 paper titled 

Comparisons and Contrasts of Shale Gas and Tight Gas Developments, North 

American Experience and Trends includes the phrases “The more recent growth in 

natural gas production from unconventional tight and especially shale reservoirs is a 

result of technological advances (hydraulic fracturing and horizontal wells” and

“...unconventional gas resources, including CBM, Shale Gas, and Tight Gas” (57

DCN SGE00527).

• A survey by the American Petroleum Institute (API) and the American Natural Gas 

Alliance states, “...unconventional wells are considered to be shale gas wells, coal 

bed wells, and tight sand wells which must be fractured to produce economically” (28

DCN SGE00291). 

• IHS, Inc.’s 2012 report titled America’s New Energy Future: The Unconventional Oil 

and Gas Revolution and the US Economy (111 DCN SGE00728) states, “Today, 

unconventional natural gas—which includes shale gas, as well as natural gas from 

tight sands formations and coal bed methane—accounts for nearly 65% of US natural 

gas production” and “...‘tight oil’ or ‘unconventional’—crude oil and condensate 

production from sources such as shale and other low permeability rocks...”

• Scientific journal articles often indicate the names of formations that are considered 

to be unconventional formations. For example, Warner et al., 2014, use the phrase 

“The development of several unconventional formations (e.g., Marcellus, Barnett, and 

Fayetteville)...” (173 DCN SGE01166). Similarly, Lewis, 2012, identifies 

“...unconventional gas exploration in the Marcellus shale...” (35 DCN SGE00345).

The EPA also looked at available state definitions, finding that four states have defined 

“unconventional oil and gas” in their regulations. As expected, many of these definitions are 

specific to resources and formations within those states. Table B-1 summarizes these states’ 

definitions.
Chapter B—Scope and Industry Description

16 

1.2.2 UOG Operators’ Understanding of UOG Resources and Formations

Oil and gas industry representatives are aware of the names and types of formations from 

which they are producing natural gas or crude oil. The EPA conducted several calls and site 

visits with industry representatives; the documentation from these calls and site visits shows that 

operators know both the names of the formations in which they are active and whether the 

formations are shale or tight (e.g., tight sands, carbonates). The following list presents some 

examples of operators’ knowledge on these subjects: 

• On February 29, 2012, the EPA met with members of the oil and gas industry to

discuss economic and engineering topics for this rulemaking. Two applicable 

excerpts from the meeting notes (54 DCN SGE00521) are: 

— “Apache is looking at potential closed loop fracturing projects in the Eagle Ford 

and Barnett shale plays of Texas.”

Table B-1. Summary of State Regulatory Definitions

State

Code, 

Chapter, or 

Section Regulatory Definition DCN

AK AS 

38.05.965(14)

“Nonconventional gas” means coalbed methane, gas contained in shales, 

or gas hydrates. 204 SGE01250

AR Rule B-43

(a) For purposes of this rule, unconventional sources of supply shall 

mean those common sources of supply that are identified as the 

Fayetteville Shale, the Moorefield Shale, and the Chattanooga Shale 

Formations, or their stratigraphic shale equivalents, as described in 

published stratigraphic nomenclature recognized by the Arkansas 

Geological Survey or the United States Geological Survey.

(b) For purposes of this rule, conventional sources of supply shall mean 

all common sources of supply that are not defined as unconventional 

sources of supply in section (a) above.

205 SGE01251

OK 165:10-3-28. 

(b)(20)

“Unconventional reservoir” shall mean a common source of supply that 

is a shale or a coalbed. “Unconventional reservoir” shall also mean any 

other common source of supply designated as such by Commission 

order or rule.

“Conventional reservoir” shall mean a common source of supply that is

not an unconventional reservoir.

206 SGE01252

PA

PA Code, 

Chapter 78. 

Oil and Gas 

Wells

Unconventional formation—A geological shale formation existing 

below the base of the Elk Sandstone or its geologic equivalent 

stratigraphic interval where natural gas generally cannot be produced at 

economic flow rates or in economic volumes except by vertical or 

horizontal well bores stimulated by hydraulic fracture treatments or by 

using multilateral well bores or other techniques to expose more of the 

formation to the well bore.

Unconventional well—A bore hole drilled or being drilled for the 

purpose of or to be used for the production of natural gas from an 

unconventional formation.

Conventional formation—A formation that is not an unconventional 

formation.

207 SGE01253
Chapter B—Scope and Industry Description

17

— “...[H]ydraulic fracturing in tight sands and shale is very similar. However, a few 

minor differences include: tight sands fracturing fluids may require more clay 

control additives than shale fracturing fluids; tight sands fracturing fluids may not 

need the same viscosity as shale fracturing fluids.”

• The Petroleum Equipment Suppliers Association (PESA) surveyed 206 oil and gas 

operators regarding the outlook for domestic unconventional resources. Some of the 

results of the survey, including a graph of “Frac Jobs Targeting Selected Formations 

in North America,” indicate tight gas, shales, CBM, etc. (70 DCN SGE00575).

• In a conference call with the EPA, North Star Disposal specified that it receives water 

from shale gas operations. Figure 1 of the North Star conference call notes shows all 

the “Pennsylvania Marcellus Shale Gas Wells” that sent wastewater to North Star in 

2011, indicating that North Star knows which gas wells are in shale formations. North 

Star is a drilling and operating company; as of July 2, 2012 (the date of the 

conference call), it owned seven underground injection wells (23 DCN SGE00279).

• After a site visit with Anadarko Petroleum on June 26, 2012, the EPA was given 

information about the company’s active operations. Anadarko specified its active 

operation in formations categorized as shale gas, shale oil, and tight gas. Table 3-1 in 

the Anadarko site visit report lists Anadarko’s active U.S. formations by name (e.g., 

Eagle Ford) and type (e.g., shale oil) (24 DCN SGE00280).

• In a conference call with the EPA, BLX, Inc., indicated that it knows which wells are 

conventional versus unconventional, as well as which formation it is drilling into. For 

example, the call notes state that “BLX...has drilled conventional wells since 1986 

and decided to drill their first Marcellus well in 2006.” The conference call took place 

on May 15, 2012 (25 DCN SGE00283).

• EPA conducted a site visit with Citrus Energy on June 19, 2012, and the operator 

indicated that they know which basin and/or formation they are drilling into. During 

the site visit, Citrus Energy representatives listed two specific basins/formations in 

which it was (or had been) active: “Prior to drilling in the Marcellus region, Citrus 

was active in the Anadarko basin in Oklahoma and Barnett Shale in Texas” (21 DCN 

SGE00275).

• In a conference call with the EPA, ConocoPhillips provided a count of its shale wells 

by formation; it also mentioned “an on-going recycling pilot project for produced 

water from a conventional formation.” The conference call took place on November 

5, 2012 (100 DCN SGE00695).

• During the 2012 Tight Oil Water Management Summit Conference in Denver, 

Colorado, the EPA attended a presentation by Katherine Fredriksen from Consol 

Energy. Consol specified that the water discussed in the presentation was “produced 

water from [its] shale operations” (33 DCN SGE00305.A10).

• During the 2014 Produced Water Reuse Initiative Conference in Denver, Colorado, 

the EPA attended a presentation by Erik Anglund from Anadarko Petroleum. The 

presentation showed Anadarko’s operations throughout the country and categorized 

them as either “shale play,” “natural gas,” or “oil and natural gas” (160 DCN 

SGE01017.A05).
Chapter B—Scope and Industry Description

18 

Operators must complete and submit a well completion report to their governing state oil 

and gas agency after completing each new oil and gas well. All states require operators to submit 

information on the geologic formation name (e.g., Bakken, Marcellus)24 in which the well is 

completed, and all states except Florida require information about the well completion method 

(e.g., hydraulic fracturing, acidization). The fact that well completion reports require the 

formation name demonstrates that operators will have that information. These well completion 

reports are further discussed in Section B.2.3 and in a separate memorandum to the record, titled 

Well Completion Reports Memorandum (210 DCN SGE01263). 

Information from the well completion reports is ultimately reported, along with other 

reports,25 into a national database of wells called Drillinginfo (DI) Desktop® (176 DCN

SGE01170). DI is an oil and gas research firm in Austin, Texas. The DI Desktop® database 

contains a record (i.e., row) for each oil and gas well drilled in the United States.26 Basic well 

data contained in DI Desktop® for each well include the API number,27 state, basin, formation, 

operator, and well trajectory.28 For much of the underlying data that support this TDD, the EPA 

relied on analysis of the DI Desktop® well database described in a separate memorandum titled 

Analysis of DI Desktop® (182 DCN SGE01180).

1.2.3 Rule Applicability

The final rule establishes requirements for wastewater discharges from UOG extraction 

facilities to POTWs. Based on the definition of unconventional oil and gas: crude oil and natural 

gas produced by a well drilled into a shale and/or tight formation (including, but not limited to, 

shale gas, shale oil, tight gas, tight oil), the EPA was able to identify shale and tight formations 

in the United States using publicly-available sources. The list of shale and/or tight formations is 

published by the U.S. Energy Information Administration (EIA), and the name of the formation 

into which a well is drilled is reported in well completion reports required by all States and 

compiled into the national database owned by DI (see section above). 

The U.S. EIA publishes summary maps of natural gas in the Lower 48 States and North 

America and the maps are separated into the following: Conventional Fields, Shale Gas and Oil 

Plays (193 DCN SGE01191), Major Tight Gas Plays, which includes tight gas and tight oil29 (11

 

24 Well completion reports sometimes refer to the formation as the “reservoir” or “pool.”

25 Operators must submit other types of reports to state oil and gas agencies in addition to well completion reports. 

Examples include production reports (crude oil, natural gas, and produced water), well integrity reports, well closure 

reports, etc.

26 The database is subject to restrictions on its use and dissemination. Based on the license agreement for the version 

of the database used to support these rulemaking analyses, access to the raw data in the database is limited to ERG 

(EPA’s contractor) and EPA personnel only, although summary data developed using queries may be disseminated 

more widely. Wholesale “data dumps” may not be disseminated electronically. All disseminations of such summary 

data, however, should cite Drillinginfo as the source of the information.

27 An API number is a unique identifier assigned to each well drilled for oil and gas in the United States. 

28 DI Desktop® includes more technical information about each well such as depth, completion date, spud date, 

annual crude oil, natural gas, and produced water production per well.

29 For example, the tight gas map (11 DCN SGE00155) shows the Austin Chalk formation in the West Gulf Coast 

Basin. In its Assumptions to the 2015 Annual Energy Outlook report, the EIA shows that about half of the 

technically recoverable resource in the Austin Chalk is crude oil.
Chapter B—Scope and Industry Description

19

DCN SGE00155), Coalbed Methane Fields, and Offshore Fields (208 DCN SGE01255). Figure 

B-3 and Figure B-4 show the UOG resources, respectively, in the lower 48 states.30 The EIA also 

periodically publishes a list of all known UOG formation names in its AEO reports. The most 

recent list can be found in Table 9.3 of the EIA’s Assumptions to the 2015 Annual Energy 

Outlook report (192 DCN SGE01190). Appendix F (Table F-3 and Table F-4) provides an 

updated and more thorough list of UOG formations than what is shown in the EIA maps below 

(i.e., Figure B-3 and Figure B-4).

The EPA was able to identify UOG wells using the basin and formation name in DI 

Desktop® in combination with a list of known UOG formations published in Table 9.3 of the 

EIA’s Assumptions to the 2015 Annual Energy Outlook report (192 DCN SGE01190). Formation 

names are also reported with the well completion reports as explained in Section B.2.3 (210

DCN SGE01263). This list of known UOG formations generally matches the formations shown 

in the EIA’s shale and tight plays maps provided in Figure B-3 (193 DCN SGE01191) and 

Figure B-4 (11 DCN SGE00155). EPA used the combination of the formation names listed in DI 

Desktop®, the EIA list of the known UOG formations, and the EIA shale and tight plays maps to 

distinguish between shale and tight formations.

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

similar to the term “formation” as used in this TDD.
Chapter B—Scope and Industry Description

20

Source: 193 DCN SGE01191

Figure B-3. Major U.S. Shale Plays (Updated April 13, 2015)
Chapter B—Scope and Industry Description

21

Source: 11 DCN SGE00155

Figure B-4. Major U.S. Tight Plays (Updated June 6, 2010)
Chapter B—Scope and Industry Description

22

2 INDUSTRY DESCRIPTION: UOG WELL DEVELOPMENT PROCESS

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

construction, well drilling and construction, well treatment and completion (e.g., stimulation)31, 

and production. Before UOG well development, operators must obtain surface use agreements, 

mineral leases, and permits. These steps can take a few months to several years to complete. 

When they are completed, operators begin the well development process, as described in the 

following subsections. 

Throughout the well development process, many materials are transported to the well 

pad. These materials include well casing and tubing; fuel (e.g., diesel, liquefied natural gas); and 

base fluid, sand, and chemicals for hydraulic fracturing. Sand, chemicals, and construction 

materials are typically transported to the well pad by truck, but fracturing base fluid (e.g., fresh 

water, recycled UOG produced water) may be transported via truck or temporary piping (92

DCN SGE00625; 95 DCN SGE00635; 21 DCN SGE00275).

The largest volumes of UOG extraction wastewater generated during well development 

are flowback, which is generated during the well completion process, and long-term produced 

water, which is generated during production (see Section C.2 for characteristics of each). UOG 

well drilling also generates wastewater, referred to in this document as drilling wastewater. As 

shown in Figure B-5, produced water, drilling wastewater, and produced sand are collectively 

referred to as UOG extraction wastewater. 

 31 Well treatment is a generic term that describes actions performed to a well such as well cleaning, stimulation, and 

isolation, which are generally performed during well completion, the process of bringing a wellbore into production 

after well drilling.
Chapter B—Scope and Industry Description

23 

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

to counterbalance formation pressure.

b—Drilling cuttings are the particles generated by drilling into subsurface geologic formations and carried out from 

the wellbore with the drilling mud. 

Figure B-5. UOG Extraction Wastewater 

Operators must also transport UOG extraction wastewater from the well to the ultimate 

wastewater management or disposal location—e.g., a centralized waste treatment (CWT) facility, 

an underground injection well for disposal, or another well for reuse. UOG extraction wastewater 

is transported via truck or temporary piping (92 DCN SGE00625; 95 DCN SGE00635; 21 DCN 

SGE00275).

2.1 UOG Exploration 

Before well construction, a UOG operator conducts exploration—either before or after 

obtaining a lease, depending on the site-specific circumstances. During exploration, UOG 

operators use geological data (e.g., formation depth, formation thickness, formation slope, 

permeability, porosity) to target the most favorable UOG formation from which to produce crude 

oil and/or natural gas (22 DCN SGE00276). Operators can obtain geological data using some of 

the following methods (22 DCN SGE00276):
Chapter B—Scope and Industry Description

24 

• Offset production data—analysis of existing production data from nearby wells. 

• Existing drilling data logs—analysis of data logs from drilling existing wells.

• Seismic data—analysis of data collected using specially equipped trucks that send 

and receive sound waves through the ground. Special service providers convert the 

received sound waves into 2D or 3D images of the formation. 

Geologists analyze the geological data and recommend well locations based on the areas 

with the highest production potential. It is not always possible to drill in the exact location 

recommended by a geologist due to several factors such as topography, environmentally 

sensitive habitats, water availability, state restrictions for siting, or surface access restrictions 

from land owners. In these situations, operators find the closest possible drilling location that 

will still allow for the effective production of crude oil and/or natural gas from the well (95 DCN

SGE00635).

2.2 UOG Well Drilling and Construction

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

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

production potential of hydrocarbon reserves (explained in Section B.2.1). Development 

involves drilling production wells once a hydrocarbon reserve has been discovered and 

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

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

breakdown of active UOG wells by well trajectory as of 2014. 

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

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

shale wells (57 DCN SGE00527). For shale wells, vertical drilling is typically used 

by operators during the exploration phase of well development (95 DCN SGE00635), 

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

unable to make large investments in horizontal wells (25 DCN SGE00283). Vertical 

drilling has historically been used for COG wells. 

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

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

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

Directional drilling is common in conventional and unconventional tight formations 

that occur as accumulations as illustrated in Section B.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 typically can vary in length between 1,000 and 5,000 feet (76 DCN 

SGE00593; 91 DCN SGE00623). Horizontal drilling is the most common method for 

continuous UOG formations (37 DCN SGE00354; 1 DCN SGE00010).
Chapter B—Scope and Industry Description

25

Source: 76 DCN SGE00593 (edited by the EPA)

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

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

operators drilling in these resources typically drill multiple horizontal wells on each well pad (92

DCN SGE00625; 95 DCN SGE00635; 21 DCN SGE00275). However, tight reservoirs occur in 

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

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

and accumulation type of the tight reservoir. Directional and horizontal well configurations give 

operators access to more of the producing formation and reduce surface disturbance (37 DCN 

SGE00354; 2 DCN SGE00011). Operators may drill one or two horizontal wells on a well pad 

initially and move on to the next pad. When this happens, the operator typically comes back to 

drill the remaining wells on the pad after the initial wells show favorable economic conditions32

and production (95 DCN SGE00635). 

Drilling for crude oil and natural gas is generally performed by rotary drilling, in which a 

rotating drill bit grinds through the earth’s crust as it descends. Well drilling and construction is 

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

succeeding sections of the well (95 DCN SGE00635). During drilling, operators inject drilling 

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

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

use one of the following types of drilling fluids depending on which portion of the well they are 

drilling (183 DCN SGE01181):

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

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

This category includes dry air, nitrogen gas, mist, foam, and aerated fluids.

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

permits. 
Chapter B—Scope and Industry Description

26

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

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

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

33 barite, 

polymers, lime, and gels as additives.

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

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

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

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

and gels as additives.

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

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

fluids; instead of using diesel oil and/or mineral oils, though, they use organic fluids 

(e.g., esters, polyolefins, acetal, ether, and linear alkyl benzenes) with similar fluid 

properties as diesel and mineral oils. Synthetic-oil-based fluids have been referred to 

as more environmentally friendly34 than oil-based fluids but are also more expensive

(157 DCN SGE01006; 158 DCN SGE01009).

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

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

referred to as drilling wastewater. Typically, drilling wastewater is immediately reused/recycled 

for drilling the same well through a closed loop process. After well drilling is complete or when 

the drilling wastewater can no longer be reused/recycled,

35 operators manage it through other 

methods (e.g., reuse/recycle for drilling another well, transfer to a CWT facility, injection for 

disposal) (169 DCN SGE01125; 95 DCN SGE00635).

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

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

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

efficient at drilling in a UOG formation (201 DCN SGE01234; 95 DCN SGE00635; 52 DCN 

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

Granite Wash requires 30 to 50 days for drilling while Barnett requires 10 or fewer days).

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

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

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

biodegradation rates than oil-based drilling fluid. 35 At the stage when the drilling mud (fluids) can no longer be reused/recycled they are sometimes referred to as 

“spent” or “spent drilling fluids.”
Chapter B—Scope and Industry Description

27 

Source: 179 DCN SGE01179

*The most recent quarter of well count data is preliminary and is subject to revision. 

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

(2012 through 2014) 

2.3 UOG Well Completion 

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

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

once drilling and well construction is completed (150 DCN SGE00984). The UOG well 

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

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

36 inserting production 

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

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

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

during well stimulation return to the surface. 

 

36 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—Scope and Industry Description

28 

After operators complete a new oil and gas well for production, they must submit a well 

completion report to the governing state oil and gas agency. All states require that the well 

completion reports contain the following information (210 DCN SGE01263): 

• Well API number 

• Well completion technique (e.g., hydraulic fracturing, acidization) 

• Formation, pool, or reservoir name in which the well is completed (e.g., Marcellus)

These well completion reports are documented in a separate memorandum to the record, 

titled Memorandum to the Record Discussing Well Completion Reports (210 DCN SGE01263). 

The following two subsections describe the well stimulation and flowback processes of well 

completion that are commonly part of UOG well development. 

2.3.1 UOG Well Completion: Well Stimulation

UOG well stimulation techniques include but are not limited to hydraulic fracturing, 

acidization, or a combination of fracturing and acidization (146 DCN SGE00966; 225 DCN 

SGE01345). The most common well stimulation technique for UOG wells is hydraulic 

fracturing, discussed in the rest of this subsection (also refer to Section B.1) (1 DCN SGE00010).

Hydraulic fracturing of COG wells is also becoming more common, but traditionally COG wells 

have been completed with open-hole techniques that allow the oil and/or gas resources to flow 

naturally (35 DCN SGE00345; 61 DCN SGE00533).

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

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

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

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

and 23 stages for horizontal wells (22 DCN SGE00276). Vertical wells are typically only 

fractured with one stage (1 DCN SGE00010). A fracturing crew can typically fracture two to 

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

operating 24 hours per day.37 Consequently, a typical well may take two to seven days to 

complete (15 DCN SGE00239; 169 DCN SGE01125). The following processes are performed

for each stage: 

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

perforation gun releases an explosive charge to create holes that penetrate about 1 

foot into the formation rock in a radial fashion. These perforations create a starting 

point for the hydraulic fractures. 

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

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

small fractures are created in the rock (see Figure B-8).38 See Section C.1 for 

information about fracturing fluid volumes and characteristics. 

 

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

38 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 
Chapter B—Scope and Industry Description

29

• 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. 

Source: 82 DCN SGE00604

Figure B-8. Hydraulic Fracturing Schematic

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

typically stored on the well pad before hydraulic fracturing begins. (See Section C.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) (24 DCN SGE00280; 21 DCN 

SGE00275; 22 DCN SGE00276). Operators that reuse/recycle UOG produced water in 

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

and/or pits (24 DCN SGE00280; 195 DCN SGE01206). Operators typically have sand trucks and 

pump trucks onsite during the hydraulic fracturing process. The sand trucks contain the sand 

prior to mixing in the fracturing fluid and the pump trucks pump the fracturing fluid down the 

wellbore during each stage of fracturing.

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

proppant is introduced to the fracturing fluid for the additional stages.
Chapter B—Scope and Industry Description

30 

Source: 21 DCN SGE00275

Figure B-9. Freshwater Impoundment

2.3.2 UOG Well Completion: Flowback Process

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

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

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

to as “flowback.” Industry commonly refers to this as the flowback process (95 DCN

SGE00635). The flowback consists of a portion of the fluid injected into the wellbore and can be 

combined with formation water. At the wellhead, a combination of flowback water, sand, and 

product (crude oil, condensates, and/or natural gas) is routed through phase separators, which

separate products from wastes. Industry uses different types of separators depending on a number 

of factors such as the type of production (i.e., crude oil, natural gas, condensate). Figure B-10

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

separation because there is no crude oil or condensate production). 

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

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

typically store flowback in fracturing tanks onsite before treatment or transport offsite.39 In 

addition to flowback, small quantities of crude oil, condensates, and/or natural gas may be 

produced during the initial flowback process. The small quantities of produced gas may be flared

 

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

typically transported via trucks with capacities of about 4,200 to 5,000 gallons (100 to 120 barrel) or via pipe (95

DCN SGE00635). 
Chapter B—Scope and Industry Description

31

or if the operator is using “green completions,” the gas may instead be captured.

40 If oil is 

produced, oil/water separators may be used41 or the oil may be recovered from the flowback 

water after it is transported offsite.

Source: 92 DCN SGE00625

Figure B-10. Vertical Gas and Water Separator

Flowback typically lasts from a few days to a few weeks (1 DCN SGE00010; 2 DCN 

SGE00011; 90 DCN SGE00622; 75 DCN SGE00592; 27 DCN SGE00286). At some wells, the 

majority of fracturing fluid may be recovered within a few hours (1 DCN SGE00010; 2 DCN 

SGE00011; 90 DCN SGE00622; 75 DCN SGE00592; 27 DCN SGE00286). A 2009 report 

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

recover between 10 and 70 percent of the fracturing fluid that they inject down the wellbore (1

DCN SGE00010; 75 DCN SGE00592; 27 DCN SGE00286). Section C.3.1 provides more details 

on flowback generation rates over time and fracturing fluid recovery percentages for specific 

UOG formations. 

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

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

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

parts 60 and 63). 41 Operators sometimes use chemicals during the oil/water phase separation process.
Chapter B—Scope and Industry Description

32 

Source: 92 DCN SGE00625

Figure B-11. Fracturing Tanks 

2.4 UOG Production

After the flowback process, the well enters the production phase. During this phase, UOG

wells produce crude oil, condensates, and/or natural gas and water. This water, called “long-term 

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

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

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

gallons (100 barrels) per day and gradually decrease over the life of the well.42 The rates vary 

with each well because they are dependent on formation characteristics and the completion 

success of the given well (see Chapter C for information about flowback and long-term produced 

water volumes and characteristics). 

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

tanks that were used to collect water during flowback. Produced water that is separated from the 

product (crude oil, condensates, and/or natural gas) is stored in permanent above-ground storage 

tanks referred to as produced water tanks with capacities that range from 4,200 to 33,600 gallons

(100 to 800 barrels) (see Figure B-12) (24 DCN SGE00280; 21 DCN SGE00275; 96 DCN

SGE00636). The number of produced water tanks depends on the number of wells that are 

producing on the well pad and the volume of water produced by each well. Most operators 

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

(95 DCN SGE00635; 22 DCN SGE00276).

 

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

further stimulation, while others may only produce economically for 10 years (27 DCN SGE00286). 
Chapter B—Scope and Industry Description

33

Source: 21 DCN SGE00275

Figure B-12. Produced Water Storage Tanks

3 INDUSTRY DESCRIPTION: UOG WELL DRILLING AND COMPLETION ACTIVITY

The following subsections describe historical, current, and projections of future UOG 

drilling activity, including:

• Historical and current UOG well drilling activity 

• Total estimated UOG resource potential

• Current and 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 (164 DCN SGE01095). More recently, 

drilling has also increased in liquid-rich formations.

43 Baker Hughes, one of the world’s largest 

oilfield services companies, periodically publishes location and other data for active U.S. rigs.44

 43 Liquid-rich formations are those that either primarily produce crude oil or primarily co-produce natural gas with 

gas condensates (i.e., hydrocarbons such as ethanes, propanes, and butanes). When gas condensates are 

depressurized at the wellhead, they condense into a liquid phase.

44 Baker Hughes obtains data in part from RigData, a company that sells rig and well data. Rig data Baker Hughes 

publishes are reported in major newspapers and journals (e.g., Oil and Gas Journal) and are used by the industry as 

an indicator for demand of oil and gas equipment.
Chapter B—Scope and Industry Description

34

Figure B-13 shows Baker Hughes’ estimates of total number of active drilling rigs in the United 

States between January 2000 and October 2015 and shows drilling trajectory (i.e., directional, 

horizontal, vertical) and product type (i.e., crude oil, natural gas). While these counts include rigs 

that are drilling for CBM and COG, drilling for UOG surpassed drilling in CBM and COG by the 

late 2000’s (194 DCN SGE01192). Both horizontal drilling and oil well drilling have increased 

since 2000. As of October 9, 2015, 79 percent of rigs were drilling horizontal wells compared to 

6 percent in January 2000.45 In 2009, horizontal well drilling surpassed vertical well drilling for 

the first time in the United States. Shortly after, in 2011, oil well drilling surpassed gas for the 

first time since 1993 (202 DCN SGE01235). In 2014, approximately 1,800 active rigs drilled 

over 37,000 wells (201 DCN SGE01234). Baker Hughes has not yet released the drilled well 

count for 2015. As footnoted on Figure B-13, the number of active rigs drilling new wells 

decreased significantly after 2014 likely due to low natural gas and crude oil prices (194 DCN 

SGE01192).

 45 Another seven percent of rigs were drilling directional wells in the United States as of October 9, 2015.
Chapter B—Scope and Industry Description

35

Source: 179 DCN SGE01179

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

Time46

Table B-2 shows the active drilling rigs in the United States by formation or basin, broken down 

by well trajectory and resource type, as of October 2015. Based on data reported by Baker 

Hughes and rig counts reported in other literature, the majority of rigs were drilling into 

unconventional formations at this time (200 DCN SGE01233; 76 DCN SGE00595). Where 

Baker Hughes did not specify the formation being drilled into, counts may include a mixture of 

rigs that are drilling for UOG, CBM, and COG. Note that the number of active rigs has continued 

to decline and the March 4, 2016, count was 463 active rigs in the United States (217 DCN 

SGE01335).

 46 The sharp decreases in active drilling rigs observed in 2009 and 2015 are likely attributed to the sudden drop in 

natural gas and crude oil prices experienced in those years (194 DCN SGE01192).
Chapter B—Scope and Industry Description

36

Table B-2. Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product Type (as of October 9, 2015)

Basina Formationa

Resource 

Typea

Gas Rigs by Well Trajectory Oil Rigs by Well Trajectoryb

Total 

Directional Horizontal Vertical Rigs

Total 

Gas Directional Horizontal Vertical

Total 

Oil

Permian —c Mix 0 5 0 5 4 182 44 230 235

Otherd —c Mix 25 20 11 56 19 66 41 126 182

Western Gulf Eagle Ford Shale 0 12 0 12 0 65 3 68 80

Williston —c,e Mostly shalee 0 0 0 0 2 62 1 65 65

Appalachian Marcellus Shale 0 45 1 46 0 0 0 0 46

Anadarko Mississippian Tight 0 0 0 0 0 11 2 13 13

Anadarko Granite Wash Tight 0 5 0 5 0 6 0 6 11

Denver Niobrara Shale 0 5 0 5 0 19 3 22 27

Anadarko Woodfordf Shale 0 6 0 6 1 40 0 41 47

TX-LA-MS 

Salt Haynesville Shale 0 23 0 23 0 0 1 1 24

Fort Worth Barnett Shale 0 3 0 3 0 0 3 3 6

Appalachian Utica Shale 0 15 0 15 1 3 1 5 20

Arkoma Fayetteville Shale 0 4 0 4 0 0 0 0 4

Total 25 143 12 180 27 454 99 580 760

Sources: 179 DCN SGE01179

a—Baker Hughes (200 DCN SGE01233) reported a mixture of basins and formations. The EPA classified them by resource type (i.e., shale, tight) when specific 

formations were reported. When formations were not reported, the EPA classified the resource type as a “mix” of resources (conventional, tight, shale).

b—Oil rigs include six “miscellaneous” rigs reported by Baker Hughes (200 DCN SGE01233).

c—Baker Hughes reported basin as opposed to formation for these areas. Therefore, these areas may include rigs drilling in conventional and unconventional 

formations.

d—The majority of the rigs in the “Other” category were drilling in Texas, Louisiana, Wyoming, California, Utah, and Colorado. The remaining rigs in the 

“Other” category were distributed evenly throughout the United States. 

e—The majority of these rigs are expected to have been drilling in the Bakken shale formation based on rig counts reported by the EIA (76 DCN SGE00595).

f—This formation includes the Woodford-Cana, Arkoma Woodford, and Ardmore Woodford formations.
Chapter B—Scope and Industry Description

37

3.2 UOG Resource Potential

This section quantifies how many new UOG wells may be drilled in the future (i.e., new 

well potential), using USGS and EIA assessments, to estimate the potential number of new UOG 

extraction wastewater sources. Assessments by the USGS and the EIA show substantial potential 

for new UOG wells. The EIA also calculates new UOG well potential in its AEO, but because it 

is only for several sub-formations,

47 the EPA calculated new well potential for all UOG 

formations.

48 This analysis is the same as the EIA methodology and is documented in a separate 

memorandum titled Data Compilation Memorandum for the Technical Development Document

for Effluent Limitations Guidelines and Standards for Oil and Gas Extraction (TDD) (179 DCN 

SGE01179; 180 DCN SGE01179.A02).

The two EIA-reported parameters that the EPA used to calculate new well potential are:

• Estimated ultimate recovery per well (EUR). EUR is the quantity of crude oil 

and/or natural gas that is produced by a single well over its life.

• Technically recoverable resources (TRR). The TRR is the quantity of crude oil 

and/or natural gas producible from a geological formation using current drilling and 

completion technology. The EIA’s TRR estimates are functions of total formation 

geographic area (square miles), the portion of formation land area that can be 

developed for oil and gas extraction, average well spacing assuming that the 

formation is fully developed, and EUR per well. TRR is the sum of proven reserves 

and unproven resources.49

EIA published these parameters for all known UOG formations in Table 9.3 of the EIA’s 

Assumptions to the 2015 Annual Energy Outlook report (192 DCN SGE01190). The EIA’s 

estimates of these parameters are primarily based on geological characteristics published by the 

USGS, which in turn rely on historical production data from existing wells and the technology 

deployed at the time of assessment. However, the EIA adjusts these estimates annually to 

account for the ongoing changes in drilling and completion practices and to account for 

formations not yet assessed by the USGS (192 DCN SGE01190).

To evaluate new well potential, the EPA calculated new well potential for each formation 

or sub-formation by dividing the TRR by the EUR. Appendix F provides EUR and TRR on a 

formation basis based on this analysis. To calculate total TRR and new well potential by resource 

 47 For example, the Assumptions to the 2015 Annual Energy Outlook reported new well potential for several, but not 

all, Bakken sub-formations: 13,045 wells (192 DCN SGE01190, Table 9.5, Bakken Central). The EPA estimated 

approximately 13,072 new Bakken wells for the same Bakken sub formations (180 DCN SGE01179.A02). 

Differences between EIA and EPA new well potential are due to rounding.

48 These estimates do not factor in future changes to TRR estimates by the EIA, advances in drilling technology, or 

economic conditions that ultimately affect how many wells UOG operators drill over time (192 DCN SGE01190; 

194 DCN SGE01192).

49 Proven reserves are resources that are currently developed commercially or have been demonstrated with 

reasonable certainty to be recoverable in future years under existing economic conditions and current technologies. 

Unproven resources are resources that have been confirmed by exploratory drilling but are not yet commercially 

developed.
Chapter B—Scope and Industry Description

38

type, the EPA summed the TRR and the new well potential for all formations in each resource 

type shown in Table F-2 and Table F-3. Table B-3 summarizes the total new well potential the 

EPA calculated for the four UOG resource types.

50

Table B-3. UOG Potential by Resource Type as of January 1, 2013

Resource 

Type

Weighted 

Averagea Oil 

EUR

(MMbls per well)

Weighted 

Averagea Gas 

EUR (Bcf 

per well)

Total Oil TRR 

(MMbls)

Total Gas 

TRR (Bcf)b

Total New Well 

Potential

(Beginning in 

2013)

Active 2014 

UOG Well 

Countc

Shale gas 0.008 0.534 7,300 515,900 967,000 H: 56, 801

D: 1,836

V: 15,877

U: 17,755 Shale oil 0.096 0.146 43,900 66,800 456,000

Tight gas 0.016 0.447 12,000 339,100 758,000 H: 11,175

D: 12,565

V: 82,954

U: 36,208 Tight oil 0.095 0.124 21,200 27,700 224,000

All UOG 0.035 0.395 84,400 949,500 2,405,000

H: 67,976

D: 14,401

V: 98,831

U: 53,963

Sources: 179 DCN SGE01179

a—Weighted averages are based on total oil or gas TRR (i.e., formations with more TRR were given more weight 

than formations with less TRR).

b—Gas production from shale and tight oil resources is associated gas that is produced simultaneously with oil.

c—Well counts are based on ERG’s DI Desktop® data analysis explained in the Analysis of DI Desktop®

memorandum (182 DCN SGE01180). They may not be all-inclusive.

Abbreviations: MMbls—million barrels; Bcf—billion cubic feet of gas; EUR—estimated ultimate recovery (per 

well); TRR—technically recoverable resources; H—horizontal; D—directional; V—vertical; U—trajectory 

unknown

The results presented in Table B-3 show that the UOG new well potential is much greater 

than the active well count. The EPA estimates that approximately 2.4 million potential new UOG 

wells—with associated extraction wastewater—may be drilled in the future. Table B-3 also 

shows the approximate number of active UOG wells in 2014, broken out by well trajectory and 

resource type, based on the EPA’s analysis of the DI Desktop® well database (176 DCN 

SGE001170; 182 DCN SGE01180).

3.3 Current and Projections of Future UOG Well Completions

In 2013 and 2014 alone, more than 27,00051 oil and gas wells were hydraulically 

fractured nationwide each year (175 DCN SGE01169). As previously explained, hydraulic 

fracturing is currently the most popular well stimulation technique for UOG wells. A survey 

 50 These estimates only include shale and tight oil and gas resources. They do not include CBM or COG.

51 This is based on EPA’s analysis of FracFocus (186 DCN SGE01184). The actual number of wells fractured is 

likely greater because some states where fracturing is common (e.g., Michigan) did not yet require reporting to 

FracFocus during these years.
Chapter B—Scope and Industry Description

39

conducted by the API and the American Natural Gas Alliance shows that, as of 2010, nearly all

unconventional wells were being completed using hydraulic fracturing (28 DCN SGE00291).52

Operators may also refracture existing oil and gas wells. Based on a national database 

maintained by IHS, Inc., 0.13 to 0.35 percent of well completions involving hydraulic fracturing 

from 2000 to 2010 were reported as refracturing of existing oil and gas wells (165 DCN

SGE01095.A09). A more recent survey of 205 UOG operators conducted by PESA53 shows that 

in 2012 and 2013 about 10 percent of well completions involving hydraulic fracturing were 

refracturing of existing oil and gas wells (70 DCN SGE00575).

In 2012, HIS, Inc. estimated the total number of UOG wells that UOG operators may 

complete through 2035 (111 DCN SGE00728). The EPA generated Figure B-14 using data 

published by HIS, Inc. (179 DCN SGE01179). The figure shows the projected number of UOG 

wells completed annually and cumulatively. Unconventional gas is further broken down into 

tight gas and shale gas. The projections estimated by HIS, Inc., show a gradual increase in annual 

UOG well completions through 2035. 

Source: 179 DCN SGE01179

Figure B-14. Projections of UOG Well Completions

 52 This survey included well completion information for 5,307 well completions in 2010, consisting of a mixture of 

conventional and unconventional wells. The survey results showed that more than 96 percent of tight gas wells and 

99 percent of shale gas wells surveyed were hydraulically fractured. The survey also showed that 69 percent of 

conventional wells were hydraulically fractured. 

53 PESA represents the energy industry’s manufacturers and oilfield service and supply companies. Its mission is to 

promote and advocate for policies that will support the oilfield service sector’s continued job creation, technological 

innovation, and economic stability. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

40

Chapter C. UNCONVENTIONAL OIL AND GAS EXTRACTION WASTEWATER 

VOLUMES AND CHARACTERISTICS

Since 2000, horizontal drilling and hydraulic fracturing of UOG resources has increased

dramatically (164 DCN SGE01095). The EIA, in its 2015 AEO, projects that, within the next 30 

years, the majority of the country’s crude oil54 and natural gas55 will come from unconventional 

resources (194 DCN SGE01192). Consequently, industry experts expect UOG produced water

volumes to continue to increase (103 DCN SGE00708; 46 DCN SGE00479; 107 DCN 

SGE00722; 131 DCN SGE00768.A01; 132 DCN SGE00768.A25).

This chapter discusses UOG extraction wastewater volumes and characteristics. This 

includes the following sources (see Figure B-5 above):

• Produced water—the fluid (brine) brought up from the hydrocarbon-bearing strata 

during the extraction of crude oil and natural gas, and includes, where present, 

formation water, injection water, and any chemicals added downhole or during the 

oil/water separation process. Based on the type of oil and gas extraction method, 

produced water can be further broken down into the following components:

— Flowback—the produced water generated in the initial period after hydraulic 

fracturing prior to production (i.e., fracturing fluid, injection water, any chemicals 

added downhole, and varying amounts of formation water). After the hydraulic 

fracturing procedure is completed and pressure is released, the direction of fluid 

flow reverses, and the fluid flows up through the wellbore to the surface. The 

water that returns to the surface is commonly referred to as “flowback.”

— Long-term produced water—the produced water generated during the 

production phase of the well after the initial flowback process which can include 

increasing amounts of formation water. Long-term produced water continues to 

be produced throughout the lifetime of the well.

• Drilling wastewater—the liquid waste stream separated from recovered drilling 

mud56 (fluid) and drill cuttings57 during the drilling process. 

• Produced sand—the slurried particles used in hydraulic fracturing, the accumulated 

formation sands and scales particles generated during production. Produced sand also 

includes desander discharge from the produced water waste stream, as well as

blowdown of the water phase from the produced water treatment system.

The EPA identified drilling wastewater and produced water as the major sources of 

wastewater pollutants associated with UOG extraction, so these wastewaters are described 

 54 Crude oil includes “lease condensates,” components that are liquid at ambient temperature and pressure. 55 Natural gas can include “natural gas liquids,” components that are liquid at ambient temperature and pressure. 56 Drilling mud is the circulating fluid (mud) used in the rotary drilling of wells to clean and condition the hole and 

to counterbalance formation pressure.

57 Drill cuttings are the particles generated by drilling into subsurface geologic formations and carried out from the 

wellbore with the drilling mud. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

41

further below. The following subsections discuss volumes and chemical constituents found in 

fracturing fluid typically used by UOG operators and volumes and characteristics of drilling 

wastewater, flowback, and long-term produced water generated by UOG operations. The EPA 

identified this information from existing data sources, including state and federal agency 

databases, journal articles and technical papers/reports, academic papers/reports, technical 

references, industry/vendor telephone calls, industry site visits, and meetings with industry. The 

EPA reported the data exactly as reported in existing literature throughout Chapter C. In some 

instances, the EPA compiled the existing data into a separate document to compile and analyze 

the data. These separate memoranda, referenced throughout Chapter C, are titled Unconventional 

Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation (186

DCN SGE01184) and Data Compilation Memorandum for the Technical Development 

Document (TDD) for Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

(179 DCN SGE01179).

Section C.1 discusses the characteristics of fracturing fluid,

58 Section C.2 discusses 

typical volumes of UOG extraction wastewater, and Section C.3 presents constituents that are 

typically found in UOG extraction wastewater. Section C.3 extensively discusses TDS, a 

parameter that is often used to characterize UOG extraction wastewater because it provides a 

measure of dissolved matter including salts (e.g., sodium, chloride, nitrate), metals, minerals, and 

organic material (3 DCN SGE00046). Data in Section C.3 show that sodium and chloride make

up the majority of TDS in UOG produced water. The data also show that chloride contributes 

heavily to the makeup of TDS in UOG drilling wastewater. TDS is not a specific chemical, but is 

defined as the portion of solids that pass through a filter with a nominal pore size of 2.0 μm or 

less as specified by Standard Method 2540C-1997.

59 Because TDS in UOG produced water

primarily consists of inorganic salts and other ionic species, conductivity measurements may also 

be used to estimate TDS.

60 High measurements of specific conductivity are indicative of high 

TDS concentrations. 

TDS and chloride are potential concerns in the management of UOG extraction 

wastewater because of the high concentrations of these parameters in the wastewater. UOG 

produced water can have TDS concentrations up to 400,000 mg/L, which is over 10 times the 

concentration of TDS typically found in seawater (i.e., 35,000 mg/L). Chapter D discusses UOG 

extraction wastewater management and disposal practices.

1 FRACTURING FLUID CHARACTERISTICS

As discussed in Section B.2.3, most UOG resources (e.g., tight oil, shale gas) are 

stimulated using hydraulic fracturing. Hydraulic fracturing of UOG resources typically requires 

high volumes of fracturing fluid, consisting of a base fluid mixed with proppant (e.g., sand) and 

chemicals. The quantity of each fracturing fluid component varies by operator, basin, formation, 

 58 The type of fracturing fluid and total fracturing fluid volume may influence the characteristics of UOG produced 

water and are therefore described in this chapter.

59 40 CFR part 136 lists Standard Method 2540C as an approved test method for TDS. 60 The electrical conductivity of water is directly related to the concentration of dissolved ionized solids in the water.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

42

and resource type. The remainder of this subsection discusses the sources used for base fluid, 

concentrations of chemical additives, and observed constituents in fracturing fluids. 

1.1 Base Fluid Composition

The primary component of fracturing fluid is the base fluid to which proppant (sand) and 

chemicals are added. Fracturing fluids are typically water-based, though cases of non-aqueous 

fracturing fluids are documented in the literature (e.g., compressed nitrogen, propane) (164 DCN 

SGE01095). Base fluid typically consists of only fresh water (surface, groundwater, or municipal 

water) or a mixture of fresh water, reused/recycled UOG produced water, and/or other sources 

(e.g., treated municipal wastewater, groundwater) (97 DCN SGE00639; 70 DCN SGE00575). 

PESA reports the following percentages of UOG operators using each water source as fracturing 

fluid in the United States (70 DCN SGE00575):

• Surface water (e.g., rivers, lakes) (40 percent)

• Groundwater (36 percent)

• City/ municipal water61 (16 percent)

• Recycled UOG produced water (7 percent)

62

• Industrial wastewater (1 percent)

Table C-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 

projected values 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 (66 DCN SGE00556; 105 DCN SGE00710):

• Produced water volume. When large volumes of flowback and long-term produced 

water are generated by other UOG wells in the area, reuse/recycle wastewater can 

make up a larger portion of base fluid water on average.

• Produced water quality. When the concentration of TDS in UOG produced water

rapidly increases after fracturing, it may have less potential for reuse/recycle as a 

source of base fluid to fracture another well (105 DCN SGE00710).

 61 PESA does not specify whether this water source is potable drinking water or treated municipal effluent (70 DCN 

SGE00575).

62 The amount of UOG wastewater that is reused/recycled in fracturing fluid varies significantly by UOG formation. 

See Section D.2 for more information about UOG wastewater reuse/recycle.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

43

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 CA basins All formations Shale and tight 96 0 4

Appalachian Marcellus (PA) Shale 82 to 90 0 10 to 18

Marcellus (WV) Shale 77 to 83c,d —c 6 to 10

Anadarko All formations Shale and tight 50 (40) 30 (30) 20 (30)

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: 179 DCN SGE01179

a—Parentheses contain projected data for the year 2020, reported as the “most likely” scenario by Nicot et al. 2012

(97 DCN SGE00639).

b—Fresh water is naturally occurring water on the Earth’s surface. Examples include ponds, lakes, rivers and 

streams, and certain underground aquifers. Fresh water is generally characterized by having low concentrations of 

dissolved salts. Brackish water is water that has more salinity than fresh water, but not as much as seawater.

Example brackish water sources include certain underground aquifers, effluent from publicly owned treatment 

plants (POTWs), and wastewater from other industries.

c—In addition to the 77 to 83 percent fresh water reported for the Marcellus shale in WV, 6 to 17 percent of base 

fluid was reported as “purchased water” and 1 to 3 percent was reported as groundwater both of which could be 

fresh or brackish. Neither of these values are included in this table.

d—Hansen et al. 2013 (60 DCN SGE00532) reported this data as “surface water.”

“—” indicates no data.

1.2 Additives

In addition to base fluid, operators add proppant and chemicals to adjust the fracturing 

fluid properties. Proppant generally makes up 10 percent or less of the total fracturing fluid by 

mass. Chemical additives in total typically make up less than 0.5 percent of the total fracturing 

fluid by mass (1 DCN SGE00010). The additives and the quantity of additives used in fracturing 

fluid depend on the formation geology, base fluid characteristics, and UOG operator (106 DCN 

SGE00721; 4 DCN SGE00070; 136 DCN SGE00780; 137 DCN SGE00781). Fracturing fluid 

additives are constantly evolving as UOG operators determine the most efficient composition to 

use for each fracture job. There are two general types of water-based fracturing fluids:

• Slickwater fracturing fluids consist of small quantities of friction reducer, biocides, 

scale inhibitors, surfactants, and propping agents. Operators generally use slickwater 

designs to fracture dry natural gas producing formations (105 DCN SGE00710; 101

DCN SGE00705). 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

44

• Gel fracturing fluids include higher quantities of gels to increase fluid viscosity that 

enables the fluid to carry higher concentrations of propping agents into the formation. 

Using gel fracturing fluids requires less total base fluid volume than using slickwater 

fracturing fluids, but gel fracturing fluids contain more additives and proppant. 

Consequently, gel fracturing fluids are more complex than slickwater fracturing fluids 

and are more sensitive to the quality of base fluid (105 DCN SGE00710; 101 DCN 

SGE00705). Operators generally use gel fracturing fluids to fracture liquid-rich 

formations43 (101 DCN SGE00705). 

In 2015, the EPA’s Office of Research and Development (ORD) released a report 

summarizing additives used by operators based on public disclosures to FracFocus63 (106 DCN 

SGE00721). In addition, several sources have published information regarding fracturing fluid 

additives and their uses in hydraulic fracturing (4 DCN SGE00070; 136 DCN SGE00780; 137

DCN SGE00781; 146 DCN SGE00966). Table C-2 shows specific additives used by operators 

categorized by purpose. Many additives can have multiple purposes depending on the exact 

design of the fracturing fluid. Table C-3 and Table C-4 show the medians and ranges (5th to 95th

percentile) of the maximum possible fluid concentrations reported by operators of the most 

frequently reported ingredients in the FracFocus public disclosures, summarized in the EPA

ORD report, for hydraulically fractured gas and oil wells. Ingredients in Table C-3 and Table 

C-4 are sorted from highest to lowest median of the maximum concentrations.

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

Additive 

Typea

Common 

Compound(s)b Purpose

Acid Hydrochloric acid; 

muriatic acid

Removes cement and drilling fluid 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.

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.

 63 Operators submit reports for individual wells to FracFocus. These reports include date of completion, well type 

(oil, gas), total fracturing fluid volume, well API number, well depth, location coordinates, and the concentrations of 

additives. These reports mostly represent wells completed in UOG formations but may also include some in 

conventional and CBM formations.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

45

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

Additive 

Typea

Common 

Compound(s)b Purpose

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 natural gas or crude 

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: 106 DCN SGE00721; 4 DCN SGE00070; 136 DCN SGE00780; 137 DCN SGE00781; 146 DCN 

SGE00966

a—Operators do not use all of the chemical additives in hydraulic fracturing fluid for a single well: they decide 

which additives to use on a well-by-well basis.

b—The specific compounds used in a given fracturing operation will vary depending on company preference, base 

fluid quality, and site-specific characteristics of the target formation.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

46

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

Gas Wells from FracFocus (2011–2013)

Specific Constituents CAS Number

Maximum Concentration in Hydraulic Fracturing

Fluid (% by Mass)

a

Number of 

Reported Uses

Median 

Concentration

5th to 95th

Percentile 

Concentration

Water 7732-18-5 7,998 0.18 0.000090–91

Guar gum 9000-30-0 3,586 0.1 0.00057–0.38

Hydrochloric acid 7647-01-0 12,351 0.078 0.0063–0.67

Distillates, petroleum, hydrotreated light 64742-47-8 11,897 0.017 0.0021–0.27

Sodium chloride 7647-14-5 3,608 0.0091 0–0.12

Glutaraldehyde 111-30-8 5,635 0.0084 0.00091–0.023

Ethylene glycol 107-21-1 5,493 0.0061 0.000080–0.24

Peroxydisulfuric acid, diammonium salt 7727-54-0 4,618 0.0045 0.000050–0.045

Solvent naphtha, petroleum, heavy arom. 64742-94-5 3,287 0.0044 0.000030–0.030

Sodium hydroxide 1310-73-2 4,656 0.0036 0.000020–0.088

2-Butoxyethanol 111-76-2 3,325 0.0035 0.000010–0.041

Acetic acid 64-19-7 3,563 0.0025 0–0.028

Quartz 14808-60-7 3,758 0.0024 0.000030–11

Ethanol 64-17-5 6,325 0.0023 0.00012–0.090

Methanol 67-56-1 12,269 0.002 0.000040–0.053

2,2-Dibromo-3-nitrilopropionamide 10222-01-2 3,668 0.0018 0.000070–0.022

Citric acid 77-92-9 4,832 0.0017 0.000050–0.011

Isopropanol 67-63-0 8,008 0.0016 0.000010–0.051

Naphthalene 91-20-3 3,294 0.0012 0.0000027–0.0050

Propargyl alcohol 107-19-7 5,811 0.00007 0.000010–0.0016

Source: 106 DCN SGE00721

a—Represents 17,035 FracFocus disclosures for gas wells.

Note: See Table 9 in the original source for further details about this data and how to interpret it (U.S. EPA. 2015. 

Analysis of Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure Registry 1.0. Office of 

Research and Development. 106 DCN SGE00721).

Table C-4. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in 

Oil Wells from FracFocus (2011–2013)

Specific Constituents CAS Number

Maximum Concentration in Hydraulic Fracturing

Fluid (% by Mass)

a

Number of 

Reported Uses

Median 

Concentration

5th to 95th

Percentile 

Concentration

Water 7732-18-5 8,538 1 0.0050–9.1

Hydrochloric acid 7647-01-0 10,029 0.29 0.013–1.8

Guar gum 9000-30-0 9,110 0.17 0.027–0.43
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

47

Table C-4. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in 

Oil Wells from FracFocus (2011–2013)

Specific Constituents CAS Number

Maximum Concentration in Hydraulic Fracturing

Fluid (% by Mass)

a

Number of 

Reported Uses

Median 

Concentration

5th to 95th

Percentile 

Concentration

Phenolic resin 9003-35-4 3,109 0.13 0.019–2.0

Distillates, petroleum, hydrotreated light 64742-47-8 10,566 0.087 0.00073–0.39

Ethanol 64-17-5 3,536 0.026 0.000020–0.16

Ethylene glycol 107-21-1 10,307 0.023 0.00086–0.098

Methanol 67-56-1 12,484 0.022 0.00064–0.16

Potassium hydroxide 1310-58-3 7,206 0.013 0.000010–0.052

Sodium hydroxide 1310-73-2 8,609 0.01 0.00005–0.075

Peroxydisulfuric acid, diammonium salt 7727-54-0 10,350 0.0076 0.00028–0.067

Sodium chloride 7647-14-5 3,692 0.0071 0–0.27

Glutaraldehyde 111-30-8 5,927 0.0065 0.00027–0.020

Isopropanol 67-63-0 8,031 0.0063 0.00007–0.22

Solvent naphtha, petroleum, heavy arom. 64742-94-5 3,821 0.006 0–0.038

2-Butoxyethanol 111-76-2 4,022 0.0053 0–0.17

Acetic acid 64-19-7 4,623 0.0047 0–0.047

Citric acid 77-92-9 3,310 0.0047 0.00016–0.024

Quartz 14808-60-7 8,577 0.0041 0.000040–12

Source: 106 DCN SGE00721

a—Represents 17,640 FracFocus disclosures for oil wells.

Note: See Table 8 in the original source for further details about this data and how to interpret it (U.S. EPA. 2015. 

Analysis of Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure Registry 1.0. Office of 

Research and Development. 106 DCN SGE00721).

1.3 Fracturing Fluids

Fracturing fluid is the final mixture of base fluid and additives. Its total volume depends 

on the well trajectory (i.e., vertical, directional, horizontal) and the type of fracturing fluid used 

(e.g., gel, slickwater) (164 DCN SGE01095). Operators fracture UOG wells using from 50,000 

to over 10 million gallons (1,200 to over 238,000 barrels) of fracturing fluid per well with up to a 

million or more pounds of sand (i.e., proppant). Operators typically fracture horizontal wells in 

eight to 23 stages, using between 250,000 and 420,000 gallons (6,000 and 10,000 barrels) of 

fracturing fluid per stage (24 DCN SGE00280). Literature reports that tight oil and gas wells 

typically require less fracturing fluid than shale oil and gas wells (61 DCN SGE00533). Typical 

volumes of fracturing fluid vary by UOG formation, well trajectory, number of stages, and 

resource type and are provided in Section C.2.

The concentrations of TDS in fracturing fluid are often low (<20,000 mg/L) compared to 

levels found in UOG produced water, which suggests that the majority of the TDS in UOG 

produced water is contributed by the formation (see Section C.3) (6 DCN SGE00110, 44 DCN 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

48

SGE00414). Other constituents, such as total organic carbon (TOC) and biochemical oxygen 

demand (BOD5), have been found at higher concentrations in fracturing fluid than in flowback 

and long-term produced water. For example, one study of Marcellus UOG produced water found 

median concentrations of BOD5 in fracturing fluid of about 1,70064 mg/L but BOD5 in the 

corresponding flowback and long-term produced water of 30065 mg/L or less on average (44

DCN SGE00414). As indicated in Table C-2, Table C-3, and Table C-4 organic materials (which 

contribute to BOD5 and TOC) are typical chemical additives in fracturing fluid (44 DCN 

SGE00414).

2 UOG EXTRACTION WASTEWATER VOLUMES

As explained previously, UOG wells generate three main types of wastewater over the 

life of the well: drilling wastewater, flowback, and long-term produced water (the latter two are 

collectively referred to as produced water). These wastewater streams’ flow rates and total 

volumes generated per well vary based on several factors, including:

• Time since flowback commenced

• Resource type (e.g., shale oil, tight gas)

• Specific geology properties 

• Whether the producing formation is dry or contains formation water

• Well trajectory (i.e., horizontal, directional, vertical)

The following two subsections quantify wastewater volumes generated during the UOG 

well development process. Section C.2.1 summarizes general trends in UOG extraction 

wastewater volumes for each part of the well development process by resource type and well 

trajectory. Section C.2.2 provides detailed produced water volumes by UOG formation and well 

trajectory.

66

2.1 UOG Extraction Wastewater Volumes by Resource and Well Trajectory

This section quantifies the volumes of UOG extraction wastewater generated, on a per 

well basis, for the following three wastewater components:

• Drilling wastewater

• Flowback

• Long-term produced water

Flowback and long-term produced water are the largest volumes of UOG extraction 

wastewater. Figure C-1 shows a breakdown of UOG extraction wastewater volumes generated

 64 This study reported 1,700 mg/L as the median concentration based on 19 samples. The overall range of BOD was 

4.3 to 47,400 mg/L. 

65 This study reported 330 mg/L as the median concentration based on 19 flowback samples. The overall range of 

BOD was 30 to 1,440 mg/L.

66 Section C.2.2 does not include drilling wastewater volumes by well trajectory because EPA identified drilling 

wastewater volumes data without well trajectory information.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

49

from Marcellus shale wells in Pennsylvania based on data from PA DEP’s statewide waste 

production reports for all wells active between 2004 and 2014 (184 DCN SGE01182). This trend 

varies by formation and, sometimes, within formations. However, a general rule of thumb for all 

UOG formations is that the total volume of UOG produced water (i.e., flowback and long-term 

produced water) generated by a well over its lifetime is approximately 50 percent flowback and 

50 percent long-term produced water—despite the fact that flowback is generated over a short 

period of time and long-term produced water is generated over the well life, which may be more 

than 10 years (111 DCN SGE00728).67

Sources: 184 DCN SGE01182

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

Pennsylvania (2004–2014)

Figure C-2 shows the quantities of produced water (i.e., flowback and long-term 

produced water) generated from UOG wells from the time of well completion to the end of the

well life. The produced water generation rates reflect aggregated data from multiple UOG 

formations;

68 “n” is the number of data points for each time period.69 As shown in the figure, 

UOG produced water generation rates are highest immediately after well completion, when there 

 67 Figure C-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-9). 68 As explained in Chapter B, the length of the flowback process is variable. Literature generally reports it as 30 

days or less (60 DCN SGE00532). Other operators report it as only lasting five days (36 DCN SGE00350). 69 Data for the first 90 days represent the Marcellus, Barnett, Woodford, Codell-Niobrara, Bakken, and Fayetteville 

UOG formations. Data beyond 90 days (long-term produced water) are from Table C-9. 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

50

is little or no crude oil and natural gas production (flowback). During the transition from the 

flowback process to production (within weeks of well completion), produced water generation 

rates decrease significantly and eventually level out. During production, produced water 

generation rates gradually decrease over the life of the well (long-term produced water).

Source: 186 DCN SGE01184

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

Fracturing

2.1.1 Drilling Wastewater

Volumes of drilling wastewater typically increase with the length of the wellbore. For 

example, a vertical well will typically produce a smaller volume of drilling wastewater than a 

horizontal well drilled into the same formation, because the latter requires additional drilling 

fluid to complete the horizontal lateral (184 DCN SGE01182). Table C-5 illustrates this trend for 

UOG wells drilled into the Marcellus formation in Pennsylvania.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

51

Table C-5. Median Drilling Wastewater Volumes for UOG Horizontal and Vertical Wells 

in Pennsylvania

Well 

Trajectory

Median Drilling 

Wastewater Volume per 

Well(Gallons)

Range of Drilling Fluid 

Volume per Well (Gallons) a

Typical Total 

Measured Depth b

Number of 

Data Points

Horizontal 50,000 3,400–200,000 7,300–13,000 3,961

Vertical 35,000 5,000–190,000 6,000–7,000 230

Source: 184 DCN SGE01182

a— These ranges are based on the 10th and 90th percentile of volumes reported for individual wells.

b— Total measured depth is the true length of wellbore drilled (i.e., sum of the vertical and horizontal).

The EPA collected information on volumes of drilling wastewater generated per well.

Table C-6 shows typical ranges of drilling wastewater generated by UOG wells by resource type

and formation. Operators report that nearly all of the drilling fluid used per well is recovered as 

wastewater at the end of drilling.70 Therefore, where it had information on drilling fluid volumes 

but not the resulting drilling wastewater volume, the EPA assumed the former is representative 

of the latter.

Table C-6. Drilling Wastewater Volumes Generated per Well by UOG Formation

Resource 

Type Formation

Typical Drilling 

Wastewater Volume 

Range (Gallons per Well)

Typical Total 

Measured Depthb

(Feet)

Number of Data 

Points

Shale Haynesville 420,000–1,100,000 13,000–19,000 5

Tight Anadarko Basinb 200,000–420,000 —c 2

Shale Niobrara 300,000a 7,500–13,000 1

Shale Barnett 170,000–500,000 8,500–14,000 6

Shale Permian Basinb 84,000–420,000 —c 8

Tight Granite Wash 200,000a —c 1

Tight Cleveland 200,000a —c 1

Shale Eagle Ford 130,000–420,000 6,000–16,000 7

Shale Utica 100,000a 6,000–19,000 1

Tight Mississippi Lime 100,000a —c 1

Shale Marcellus 3,400–200,000d

(median: 50,000) 7,300–13,000 3,962

Source: 183 DCN SGE01181

a—Only one data point was identified for these formations. Therefore, there is no range to display.

b—Total measured depth is the true length of wellbore drilled (i.e., sum of the vertical and horizontal).

c—Information is unknown.

d—Due to the large number of volume data points for the Marcellus formation, the EPA calculated the 10th and 90th

percentile values to represent the typical volume range and to eliminate outliers. The EPA was also able to calculate 

a median for the Marcellus due to the large number of data points. For all other formations, the EPA used the 

reported maximum and minimum volume range reported because of the limited number of data points.

 70 Some drilling fluid volume may be lost downhole and/or to moisture in the cuttings, but these losses account for a 

relatively small percentage of the total volume (92 DCN SGE00625).
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

52

2.1.2 Produced Water: Flowback

As described above, for purposes of this document, produced water includes flowback in 

addition to long-term produced water. Table C-7 quantifies the portion of fracturing fluid 

returned as flowback.

71 Because the volume of fracturing fluid used during well stimulation 

affects flowback quantities, fracturing fluid volumes are also listed. Based on the data in Table 

C-7,

72 total flowback volumes typically range between 40,000 to 1,100,000 gallons (950 to 

25,000 barrels) per well. On average, horizontal shale wells generate the highest volumes of 

flowback. In terms of wastewater management, operators must consider that the flowback 

process generates large volumes of wastewater in a short period of time (e.g., 30 days) compared 

to long-term produced water that is generated in small volumes over a long period of time.

Table C-7. UOG Well Flowback Recovery73 by Resource Type and Well Trajectory

Resource 

Type Trajectory

Fracturing Fluid (MG)

a

Flowback Recovery (Percent of 

Fracturing Fluid Returned)a

Weighted 

Averageb Range

Number of 

Data Points

Weighted 

Averageb Range

Number of 

Data Points

Shale

H 4.2 0.091–24 80,388 7 0–580 7,377

D 1.4 0.037–20 340 33 12–57 36

V 1.1 0.015–19 5,197 96 2–581 57

Tight

H 3.4 0.069–12 7,301 12 0–60 75

D 0.5 0.046–4 3,581 10 0–60 342

V 1 0.016–4 10,852 4 0–60 130

Source: 186 DCN SGE01184

a—Most of the underlying fracturing fluid volume data and flowback recovery data were reported in different 

sources. To avoid representing the data incorrectly, the EPA did not calculate total flowback volume for Table C-7.

Data are based on aggregated data from Table C-9, which contains volumes by formation. 

b—The weighted averages are based on the number of data points (i.e., formation/trajectory combinations with more 

data points were given more weight than those based on fewer data points). 

Abbreviations: MG—million gallons; H—horizontal well; D—directional well; v—vertical well

2.1.3 Produced Water: Long-Term Produced Water

Long-term produced water rates remain relatively constant74 over the well life compared 

to flowback rates (95 DCN SGE00635). Table C-8 quantifies long-term produced water rates in 

 71 The EPA explains how it differentiated between flowback and long-term produced water volumes in literature in 

its memorandum Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data 

Compilation (186 DCN SGE01184). 72 Approximate flowback volumes can be estimated by multiplying total fracturing volume by the percent of 

fracturing fluid returned during flowback. However, EPA does not show this calculation in Table C-7 because not 

all data sources report both fracturing fluid volume and percent of fracturing fluid recovered as flowback. 73 Flowback recovery is the percent of total fracturing fluid injected during hydraulic fracturing that returns to the 

wellhead during the flowback process.

74 Note that long-term produced water rates typically gradually decrease over the well life. However, the change is 

small relative to flowback.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

53

gallons per day by UOG resource and well trajectory. Typical (i.e., weighted average values in 

Table C-8) long-term produced water rates range from about 390 to 1,100 gallons (9 to 26 

barrels) per day. A comparison of median long-term produced water rates for shale formation 

wells, as listed in the table, shows that horizontal shale wells have higher rates than directional 

and vertical shale wells. Similarly, for tight formation wells in Table C-8, horizontal wells have 

the highest typical long-term produced water generation rates.

Table C-8. Long-Term Produced Water Generation Rates by Resource Type and Well 

Trajectory

Resource 

Type Trajectory

Long-Term Produced Water Generation Rates (gpd per Well)

a

Weighted Averageb Range Number of Data Points

Shale

H 1,100 0–29,000 43,893

D 820 0.83–12,000 1,493

V 500 4.8–51,000 12,551

Tight

H 980 10–120,000 4,692

D 390 15–8,200 10,784

V 650 0.71–2,100 34,624

Sources: 186 DCN SGE01184

a—Data are based on aggregated data from Table C-9, which contains volumes by formation. 

b—The weighted averages are based on the number of data points (i.e., formation/trajectory combinations with more 

data points were given more weight than those based on fewer data points). 

Abbreviations: gpd—gallons per day; H—horizontal well; D—directional well; V—vertical well

2.2 UOG Produced Water Volumes by Formation

Table C-9 shows UOG produced water volumes by UOG formation and well trajectory; 

these data were used to generate the summary statistics in Section C.2.1. The data in Table C-9

are sorted alphabetically by basin. Because the EPA identified less data by formation for drilling 

wastewater, Table C-9 does not include drilling wastewater volumes.

Data in Table C-9 illustrate that volumes of flowback and flow rates of long-term 

produced water vary by formation. For example, horizontal UOG wells drilled into the Barnett 

shale formation in the Fort Worth basin generate 530 gallons (13 barrels) per day of long-term 

produced water compared to 1,900 gallons (45 barrels) per day for horizontal UOG wells drilled 

into the Eagle Ford shale formation in the Western Gulf basin (91 DCN SGE00623). In some 

cases, produced water even varies geographically within the same formation, which is not 

evident in Table C-9. For example, operators report that wells drilled in the northeast portion of 

the Marcellus shale formation (in Pennsylvania) generate less produced water than wells drilled 

in the southwest portion of the Marcellus shale formation (in West Virginia) (95 DCN

SGE00635).
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

54

Table C-9. Produced Water Volume Generation by UOG Formation

Basin

UOG 

Formation

Resource 

Type

Well 

Trajectory

Fracturing Fluid (MG)

Flowback Recovery (% of 

Fracturing Fluid Returned)

Long-Term Produced Water Rates 

(gpd)

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Caney Shale H 8.1 4.4–12 11 — — 0 — — 0

Cleveland Tight

H 1.7 0.2–4 928 — 12–40 2 410 59–2,000 1,160

V 0.18 0.033–3 15 50 50–50 1 66 56–400 130

Granite Wash Tight

H 4.9 0.2–8.3 924 — 6.5–22 2 980 10–2,400 762

V 0.53 0.085–3 72 50 50–50 1 520 330–790 1,397

D — — 0 — — 0 480 160–940 83

Anadarko Mississippi 

Lime Tight

H 2 1.3–5 3,301 50 50–50 1 — 37,000–

120,000 4

V 0.34 0.016–0.71 59 — — 0 10 0.71–38 16

Woodford Shale

H 5.2 1–12 3,243 34 20–50 3 5,500 3,200–6,400 198

V 0.36 0.015–1.6 11 — — 0 — — 0

D 1.6 0.21–1.9 10 — — 0 — — 0

ClintonMedina Tight V — — 0 — — 0 7.9 7.3–11 551

Devonian Shale V — — 0 — — 0 13 4.8–19 197

Appalachian Marcellus Shale

H 4.6 0.9–11 17,316 7.1 4–47 4,374 820 54–13,000 6,494

V 0.25 0.11–5.4 116 40 21–60 7 200 94–1,000 741

D 0.16 0.092–0.17 6 — — 0 — — 0

Utica Shale H 6.8 1–13 1,108 2.5 0.66–27 684 800 420–1,700 764

Arkoma Fayetteville Shale H 5 1.7–11 3,014 — 10–20 2 430 150–2,300 2,305

Codell Tight

H 3.5 2.4–7.1 234 16 — 36 400 110–1,100 179

Denver J. V 0.23 0.11–0.46 97 0 0–4 13 59 47–120 158

D 0.26 0.14–0.5 362 0 0–3 8 46 18–71 667
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

55

Table C-9. Produced Water Volume Generation by UOG Formation

Basin

UOG 

Formation

Resource 

Type

Well 

Trajectory

Fracturing Fluid (MG)

Flowback Recovery (% of 

Fracturing Fluid Returned)

Long-Term Produced Water Rates 

(gpd)

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

CodellNiobrara Tight

H 2.8 2.7–5.4 65 7.2 7.2–7.2 32 75 19–560 38

V 0.3 0.15–0.4 490 2.8 — 21 33 13–65 2,113

D 0.4 0.2–0.46 806 0 0–5 11 45 28–70 1,853

Muddy J Tight

H 1.4 0.44–2.6 6 — — 0 860 220–1,100 6

V 0.27 0.12–0.45 139 0.09 — 15 120 52–550 340

D 0.42 0.17–0.62 758 0 0–0 11 63 39–110 1,106

Niobrara Shale

H 2.9 1.9–5.1 1,435 16 1.8–100 173 760 120–1,300 1,213

V 0.24 0.015–0.31 455 33 1.6–90 29 330 15–600 5,808

D 0.36 0.13–2.9 25 — — 0 41 8.1–590 38

Barnett Shale

H 3.7 1–7.3 26,495 30 21–40 11 530 240–4,200 11,957

Fort Worth V 1.3 0.38–1.9 3,773 — — 0 230 140–390 2,416

D 1.2 0.48–1.6 96 — — 0 210 79–410 481

Green River

HilliardBaxterMancos

Shale

H 1.7 1–5.6 2 — — 0 — — 0

D — — 0 — — 0 35 14–56 10

Lance Tight

H — — 0 — — 0 730 350–1,100 6

V 1.5 0.82–3.9 37 3.3 0.88–50 38 610 410–840 61

D 0.97 0.65–2.1 881 12 1.8–40 187 650 420–1,100 2,787

Mancos Shale

H 15 1.8–24 24 3.1 0.063–17 8 770 — 26

D 5.4 0.12–20 10 — — 0 140 0.83–1,400 36

Mesaverde Tight

H — — 0 — — 0 220 130–480 5

V 0.16 0.13–0.22 21 18 6.3–43 15 440 120–780 33

D 0.19 0.11–0.3 448 9.3 0.7–36 94 380 150–610 856

Illinois New Albany Shale H — — 0 — — 0 2,940 2,940–2,940 1

Michigan Antrim Shale V 0.05 0.05–0.05 1 — 25–75 2 1,300 530–4,600 7
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

56

Table C-9. Produced Water Volume Generation by UOG Formation

Basin

UOG 

Formation

Resource 

Type

Well 

Trajectory

Fracturing Fluid (MG)

Flowback Recovery (% of 

Fracturing Fluid Returned)

Long-Term Produced Water Rates 

(gpd)

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Permian

Avalon & 

Bone Spring

Shale

H 2.3 1.2–5.7 965 19 4.9–40 48 2,700 2,100–5,700 1,171

V 0.4 0.07–1.3 21 — — 0 2,000 1,000–4,800 68

D 1.8 1.2–3.4 40 33 12–57 36 1,300 800–3,300 94

BarnettWoodford Shale H 2.1 0.5–4.5 2 — — 0 — — 0

Delaware Shale

H 1.3 0.42–3 85 79 9.7–230 20 9,400 5,000–29,000 232

V 0.19 0.044–0.38 141 210 84–580 19 1,600 1,100–3,800 412

D 0.26 0.15–0.4 47 — — 0 4,500 2,400–5,700 90

Devonian 

(TX) Shale

H 0.47 0.091–5.5 43 — — 0 1,700 630–2,700 325

V 0.14 0.075–1 187 — — 0 3,700 1,400–5,400 306

D 0.11 0.037–0.13 11 — — 0 2,400 250–12,000 40

Morrow Tight

V — — 0 — — 0 130 41–290 7

D — — 0 — — 0 140 34–2,200 66

Spraberry Tight

H 1.3 0.069–6.5 29 — — 0 1,000 420–3,800 41

V 0.91 0.071–1.6 449 — — 0 1,000 670–1,500 936

D 1 0.06–1.5 16 — — 0 1,200 660–2,500 42

Trend Area Tight

H 8.3 2.4–12 991 — — 0 890 530–3,900 457

V 1.1 0.58–1.9 8,733 — — 0 780 690–920 15,494

D 1 0.4–1.7 41 — — 0 620 370–1,500 50

Wolfcamp Shale

H 6.7 1.4–12 1,775 16 12–23 12 3,500 450–15,000 1,237

V 1.6 0.18–2.3 383 — — 0 780 460–1,400 1,142

D 1.8 0.17–3 12 — — 0 1,700 750–3,600 170

Piceance & 

Uinta

Mesaverde Tight D — — 0 — — 0 510 130–700 52

Hermosa Shale D — — 0 — — 0 47 27–260 21

Powder 

River Mowry Shale H 2.5 0.76–7.4 15 15 4.3–580 14 450 61–2,100 16
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

57

Table C-9. Produced Water Volume Generation by UOG Formation

Basin

UOG 

Formation

Resource 

Type

Well 

Trajectory

Fracturing Fluid (MG)

Flowback Recovery (% of 

Fracturing Fluid Returned)

Long-Term Produced Water Rates 

(gpd)

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

San Juan

Dakota Tight

V 0.16 0.061–0.34 85 1.6 — 22 75 35–490 81

D 0.12 0.063–0.32 136 4.1 1.1–60 29 230 53–950 511

Mesaverde Tight

V — — 0 — — 0 43 14–560 5

D — — 0 — — 0 21 15–180 49

Pictured 

Cliffs Tight

H — — 0 — — 0 370 190–720 7

D — — 0 — — 0 4,700 1,200–8,200 6

TX-LA-MS

Bossier Shale

H 3.8 2.6–5.4 12 — — 0 37 5.6–370 47

V 0.61 0.22–1.7 82 — — 0 230 4.8–480 1,143

D 0.55 0.18–1.1 48 — — 0 150 1.2–300 304

Cotton Valley Tight

H 4.4 0.25–8.5 433 60 60–60 1 710 410–2,600 689

V 0.27 0.018–1.4 355 60 60–60 1 700 490–890 9,267

D 0.45 0.046–4 79 60 60–60 1 620 240–980 1,912

Haynesville Shale

H 5.7 0.95–15 3,855 5.2 5.2–30 3 910 84–1,200 2,575

V 0.9 0.2–2.5 2 — — 0 330 210–560 230

D 3.9 1.9–7.3 35 — — 0 660 130–1,200 204

Travis Peak Tight

H 3 0.25–6 2 — — 0 710 110–4,200 7

V 0.17 0.032–4 36 — — 0 630 270–930 1,046

D — — 0 — — 0 520 140–800 134

Tuscaloosa Shale

H 11 6.1–14 28 — — 0 — — 0

V 13 4.7–19 11 — — 0 7,400 220–51,000 64

Austin Chalk Tight

H 1.7 0.83–5.4 134 — — 0 2,200 980–5,100 752

Western 

Gulf

V — — 0 — — 0 97 21–1,500 51

Eagle Ford Shale

H 4.8 1–14 12,810 4.2 2.1–8.4 1,800 1,900 88–6,200 7,971

V 0.94 0.23–2 8 — — 0 1,200 510–2,300 12

D — — 0 — — 0 4,300 3,000–5,600 5

Edwards Tight H — — 0 — — 0 2,300 1,000–24,000 266
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

58

Table C-9. Produced Water Volume Generation by UOG Formation

Basin

UOG 

Formation

Resource 

Type

Well 

Trajectory

Fracturing Fluid (MG)

Flowback Recovery (% of 

Fracturing Fluid Returned)

Long-Term Produced Water Rates 

(gpd)

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

Weighted 

Averagea Rangeb

Number 

of Data 

Pointsc

V — — 0 — — 0 560 150–2,100 32

D — — 0 — — 0 160 69–290 6

Olmos Tight

H 1.9 0.37–6 246 — — 0 180 13–700 229

V 0.11 0.078–0.21 50 — — 0 78 52–370 1,120

D — — 0 — — 0 51 15–470 16

Pearsall Shale H 3.5 1.6–5.6 47 — — 0 160 53–1,500 51

Vicksburg Tight

V 0.21 0.072–0.61 158 — — 0 700 330–990 702

D 0.23 0.11–0.63 40 — — 0 830 390–1,400 193

Wilcox Lobo Tight

H 0.33 0.082–2.4 8 — — 0 370 250–610 84

V 0.1 0.042–0.6 56 — — 0 650 400–940 1,084

D 0.094 0.058–0.16 14 — — 0 500 300–4,200 395

Williston Bakken Shale

H 2.4 0.35–10 8,103 19 5–47 225 910 500–3,800 7,309

V 0.16 0.04–2.7 6 — — 0 2,400 150–5,100 5

Sources: 186 DCN SGE01184

a—Weighted averages are based on the number of data points reported by each data source (i.e., data sources that reported volume data for a particular 

formation/trajectory combination based on a large number of data points were given more weight than those based on fewer data points).

b—For some formations, if only one data point was reported, the EPA reported it in the range column and did not report a weighted average value.

“—” indicates no data.

c—For some formations, the number of data points was not reported in the data source. In these instances, this table reports that number as 1, except if the source 

reported a range in which case this table reports the number of data points as 2.

Abbreviations: MG—million gallons; H—horizontal well; D—directional well; V—vertical well
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

59

3 UOG EXTRACTION WASTEWATER CHARACTERIZATION

As discussed in Chapter B, UOG operations generate wastewater that includes drilling 

wastewater, flowback, and long-term produced water. Drilling wastewater is generated during 

the initial drilling of the well and typically maintains the characteristics of the drilling fluid, but 

also contains additional solids (i.e., drill cuttings) that are generated during the well drilling 

process. Flowback may contain the specific fracturing fluid composition (e.g., chemical 

additives, base fluid) used by each UOG operator as well as chemical constituents present in the 

UOG formation (27 DCN SGE00286; 6 DCN SGE00110). Long-term produced water typically 

mimics the characteristics of the UOG formation, which often contributes, in part, to high 

concentrations of select naturally occurring ions (169 DCN SGE01125). The volumes and 

characteristics of UOG extraction wastewater may vary significantly between basins, between 

formations, and sometimes between wells within the same formation (see Section C.2 for a 

discussion of UOG extraction wastewater volumes) (75 DCN SGE00592). The following 

subsections describe the characteristics of UOG extraction wastewater.

3.1 Availability of Data for UOG Extraction Wastewater Characterization

The EPA identified concentration data for constituents commonly found in UOG

extraction wastewater. These constituents include, primarily, total dissolved solids (TDS), 

anions/cations, metals, hardness, and radioactive constituents. The EPA presents summarized 

UOG extraction wastewater characterization data in the following subsections, which are 

organized into five constituent categories: classical and conventional,

75 organic, metal, 

radioactive, and other. For all of the constituent categories, there are fewer data available for 

drilling wastewater than for produced water generated at all UOG wells. The EPA presents 

available data in the following subsections.

3.2 UOG Extraction Wastewater Constituent Categories

The data in the following subsections are representative of UOG extraction wastewater 

characteristics as presented in the literature for the entire UOG industry.

76 The data show 

combined characterization data for shale and tight reservoirs as well as for oil and gas resources. 

Regarding UOG produced water, the EPA sometimes presents the data as flowback and long-

 75 Note that section 304(a)(4) of the Clean Water Act (CWA) designates the following as “conventional” pollutants: 

biochemical oxygen demand (BOD5), total suspended solids (TSS), fecal coliform, pH, and any additional pollutants 

the EPA defines as conventional. The Agency designated “oil and grease” as an additional conventional pollutant on 

July 30, 1979 (see 44 FR 44501). The CWA does not define “classical pollutant.” Rather, pollutants that are not 

designated as either conventional or toxic are considered nonconventional pollutants. An example would be TDS. In 

the discussion of pollutants in UOG wastewaters contained in Chapter C of the TDD, the EPA has organized the 

discussion according to the categories in Table C-9, which includes the category “Classical and conventional.” In 

this context, “Classical and conventional” refers to a range of parameters that are determined via classical wet 

chemistry analytical methods, including some CWA 304(a)(4) conventional pollutants as well as other parameters 

such as nutrients, alkalinity, hardness, COD, etc.

76 Note that the lack of data for select constituents may not necessarily imply that those constituents are not present

in the wastewater, but rather that they were not measured and/or reported in the existing literature. Refer to 186

DCN SGE01184 for additional details on the parameters reported in the literature reviewed. The accompanying 

database (187 DCN SGE01184.A13) includes nondetect, below detection, or zero values that were reported in the 

literature reviewed.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

60

term produced water individually. In other instances, the data are presented as UOG produced 

water, which includes both flowback and long-term produced water. Some data sources reported 

characterization data as an aggregate (i.e., produced water) and others specified data as 

representing flowback or long-term produced water. Given the uncertainty of which stage the 

aggregate data represents, EPA presented it as produced water. However, where the type of 

produced water was specified, EPA presents the specified data because some constituent 

concentrations vary between flowback and long-term produced water. 

3.2.1 Classical and Conventional Constituents in UOG Extraction Wastewater

Table C-10 presents typical concentrations of select classical and conventional 

constituents that are present in UOG drilling wastewater.77 According to one CWT facility 

operator, TSS is high in returned drilling fluid before cuttings are removed. Depending on how 

well the cuttings are removed by the operator, solids can be as high as 50 percent by mass in 

drilling wastewater (18 DCN SGE00245) (see Section B.2.1). The EPA identified the following

limitations to the data presented in Table C-10:

• Fewer data points (i.e., less than 30 data points) were available for each parameter.

• Only data representing drilling wastewater from Marcellus shale formation wells 

were available.

• All of the data came from the Marcellus shale formation.

Table C-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), hardness as CaCO3, oil and grease, specific conductivity, TOC, and TSS 

came from the Marcellus shale formation. 

 77 Table C-10 presents the number of detects, which represents the number of data points underlying sources 

indicated were a detected value. This nomenclature is used throughout the TDD.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

61

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

Drilling Wastewater from Marcellus Shale Formation Wells78

Parameter Units Range Median

Number of Data 

Points

Number of

Detects

Alkalinity mg/L 110–42,000 1,600 11 11

Ammonia mg/L 0.98–35 7 8 8

BOD5 mg/L 80–1,100 390 8 8

Chloride mg/L 160–23,000 12,000 12 12

COD mg/L 150–9,300 1,800 8 8

Hardness as CaCO3 mg/L 1,400–46,000 4,400 12 12

Oil and grease mg/L NDa–150 2.5 8 8

pH SU 6.8–12 9.0 12 12

Phosphate mg/L —b 16 4 4

Specific 

conductivity μS/cm 1,100–60,000 19,000 10 10

TDS mg/L 560–80,000 31,000 14 14

TSS mg/L 120–600,000 28,000 16 16

Source: 183 DCN SGE01181

a—Source did not report detection limit.

b—Source only reported median value.

Abbreviations: mg/L—milligrams per liter; ND—nondetect; SU—standard units; μS/cm—microsiemens per 

centimeter

 78 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

62

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 41–1,100 140 265 265 Barnett (29); Eagle Ford (1); Marcellus (232); Woodford-CanaCaney (3)

Ammonia mg/L 40–270 110 13 13 Marcellus (5); Niobrara (5); Woodford-Cana-Caney (3)

Bicarbonate mg/L 130–2,000 700 10,206 7,274

Bakken (399); Barnett (6); Cleveland (11); Codell (9); Cody (38); 

Cotton Valley/Bossier (3); Dakota (35); Eagle Ford (2925); Frontier 

(224); Hilliard-Baxter-Mancos (32); Lance (1905); Lansing Kansas 

City (16); Lewis (54); Mancos (2); Marcellus (154); Mesaverde 

(461); Mesaverde/Lance (13); Mesaverde/Lance/Lewis (878); 

Morrow (1); Mowry (5); New Albany (1); Niobrara (189); Oswego 

(5); Pearsall (3); Spraberry (26); Woodford-Cana-Caney (2811)

BOD mg/L 22–1,300 160 154 153 Barnett (28); Marcellus (122); Medina/Clinton-Tuscarora (1); 

Woodford-Cana-Caney (3)

Carbonate mg/L 0–270 53 205 144

Bakken (20); Barnett (4); Codell (2); Cody (1); Cotton 

Valley/Bossier (2); Dakota (3); Eagle Ford (4); Frontier (16); Lance 

(23); Lewis (6); Mesaverde (51); Mesaverde/Lance/Lewis (39); 

Niobrara (8); Spraberry (26)

Chlorideb mg/L 9,900–130,000 70,000 5,228 2,190

Bakken (22); Barnett (144); Cleveland (11); Codell (9); Cody (17); 

Cotton Valley/Bossier (25); Dakota (3); Eagle Ford (1651); Granite 

Wash/Atoka (1); Hilliard-Baxter-Mancos (33); Lance (1843); 

Marcellus (287); Mesaverde/Lance (5); Mesaverde/Lance/Lewis 

(943); Mowry (5); New Albany (1); Niobrara (193); Pearsall (3); 

Spraberry (26); Utica (1); Woodford-Cana-Caney (5)

COD mg/L 1,000–14,000 3,200 149 149 Barnett (23); Marcellus (122); Medina/Clinton-Tuscarora (1); 

Woodford-Cana-Caney (3)

Hardness as CaCO3 mg/L 2,200–77,000 21,000 80 80 Barnett (15); Marcellus (65)

Oil and grease mg/L 4.6–120 5.6 134 99 Barnett (23); Marcellus (108); Woodford-Cana-Caney (3)

pH SU 5.7–8.1 7 9,154 6,147

Bakken (421); Barnett (31); Cleveland (4); Codell (9); Cody (41); 

Cotton Valley/Bossier (3); Dakota (35); Eagle Ford (1601); 

Fayetteville (2); Frontier (223); Hilliard-Baxter-Mancos (33); 

Lance (1933); Lansing Kansas City (16); Lewis (54); Mancos (2); 

Marcellus (301); Medina/Clinton-Tuscarora (3); Mesaverde (460); 

Mesaverde/Lance (13); Mesaverde/Lance/Lewis (917); Morrow (1); 

Mowry (5); Niobrara (189); Spraberry (26); Woodford-Cana-Caney 

(2831)

Phosphate mg/L 12–77 31 4 4 Barnett (1); Marcellus (1); Woodford-Cana-Caney (2)
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

63

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

Specific conductivity μS/

cm 25,000–380,000 120,000 165 165 Bakken (9); Barnett (26); Dakota (3); Eagle Ford (1); Marcellus (104); Spraberry (19); Woodford-Cana-Caney (3)

TDS mg/L 13,000–210,000 94,000 5,196 2,164

Bakken (11); Barnett (38); Bradford-Venango-Elk (5); Cleveland 

(11); Codell (9); Cody (17); Cotton Valley/Bossier (3); Dakota (3); 

Devonian (11); Eagle Ford (1647); Fayetteville (4); Green River 

(1); Haynesville/Bossier (2); Hilliard-Baxter-Mancos (33); Lance 

(1839); Marcellus (373); Mesaverde/Lance (5); 

Mesaverde/Lance/Lewis (942); Mississippi Lime (3); Mowry (5); 

New Albany (1); Niobrara (195); Pearsall (3); Spraberry (26); Utica 

(1); Woodford-Cana-Caney (8)

TOC mg/L 9.7–610 82 132 127 Bakken (2); Barnett (29); Eagle Ford (1); Marcellus (97); 

Woodford-Cana-Caney (3)

TSS mg/L 23–850 140 38 38 Bakken (2); Barnett (29); Eagle Ford (1); Marcellus (113); 

Woodford-Cana-Caney (5)

Source: 186 DCN SGE01184

a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these 

instances, there were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified. 

b—The EPA assumed values reported as “Cl” in the wastewater characterization data were meant to represent “chloride” values.

Abbreviations: mg/L—milligrams per liter; SU—standard units; μS/cm—microsiemens per centimeter
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

64

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 (109 DCN SGE00725). In Table C-11, the relatively low median TOC 

concentration (82 mg/L) and BOD5 concentration (160 mg/L) compared to the COD 

concentration likely indicates that some of the COD measurements reported in existing literature 

experienced interference from high concentrations of chloride, bromide, and group II alkaline 

earth metals. Therefore, reported COD concentrations may be higher than actual COD 

concentrations in UOG produced water.

TDS, which is regularly measured in UOG produced water, provides a measure of 

dissolved matter including salts (e.g., sodium, chloride, nitrate), metals, minerals, and organic 

material (3 DCN SGE00046). TDS is determined by measuring the portion of solids that pass 

through a filter with a nominal pore size of 2.0 μm or less (Standard Method 2540C-1997, 

ASTM D5907-03, and USGS I-1750-85). Salts, specifically sodium and chloride, are the 

majority (i.e., much greater than 50 percent) of TDS in UOG produced water (26 DCN

SGE00284). Calcium and other group II alkaline earth metals (e.g., strontium, barium, 

magnesium) also contribute to the TDS in UOG produced water.

Figure C-3 shows the primary anions and cations that contribute to TDS in UOG 

produced water in various shale and tight oil and gas formations. The data presented in Figure 

C-3 represents approximately 26,000 samples. Data for all of the anions and cations contributing 

to TDS were not available for all formations. For example, the EPA did not identify any sodium 

concentration data in the Pearsall formation. Specifically, for this figure, the “other dissolved 

constituents” were captured by EPA by subtracting the sum of the listed parameters (e.g., 

sodium, chloride) from the total TDS concentration reported for the formation.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

65

Source: 186 DCN SGE01184

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

Oil and Gas Formations79

As shown in Figure C-3, of those constituents specifically identified as contributing to 

TDS, sodium, chloride, and calcium ions make up the majority of TDS in UOG produced water

according to available data. Additional ions that may contribute to the TDS in UOG produced 

water include bromide, fluoride, nitrate, nitrite, phosphate, and sulfate. Figure C-4 contains box 

and whisker plots of TDS, chloride, sodium, and calcium data for UOG flowback and long-term 

produced water. The plots show the fifth percentile, first quartile, median, third quartile, and 95th

percentile values of the data. The data used to create this figure include constituent concentration 

data from flowback or long-term produced water generated from UOG wells. The data show that 

concentrations of TDS and chloride are typically higher in long-term produced water than in 

flowback.

 79 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.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

66

Source: 186 DCN SGE01184

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

Produced Water (LTPW) from Shale and Tight Oil and Gas Formations80

Table C-12 presents typical concentrations of bromide and sulfate, which may contribute 

to TDS in drilling wastewater. The EPA identified the following limitations to the data presented 

in the table:

• Fewer data points (i.e., less than 30 data points) were available for these parameters.

• All of the data came from the Marcellus shale formation.

Table C-13 presents typical concentrations of additional constituents that may contribute 

to TDS in UOG produced water. The EPA identified the following limitations to the data 

presented in the table:

• Less data (i.e., less than 30 data points) were available for nitrite and phosphate.

• All of the available data for nitrite came from the Marcellus shale formation.

 80 The EPA assumed values reported as “Cl” in the wastewater characterization data were meant to represent 

“chloride” values and has reported them as such in Figure C-4.
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

67

• The majority of the data associated with nitrate came from the Bakken shale 

formation.

• The majority of the data associated with bromide, fluoride, and sulfide came from the 

Marcellus shale formation.

Table C-12. Concentrations of Bromide and Sulfate in UOG Drilling Wastewater from 

Marcellus Shale Formation Wells

Parameter 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: 183 DCN SGE01181

Abbreviation: mg/L—milligrams per liter
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

68

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

Parameter Units Range Median

Number of 

Data Pointsa

Number of 

Detects Formations Represented (Number of Associated Data Points)a

Bromide mg/L 81–1,200 510 111 111 Barnett (23); Marcellus (85); Woodford-Cana-Caney (3)

Fluoride mg/L 0.5–5 2.5 99 97 Barnett (23); Marcellus (73); Woodford-Cana-Caney (3)

Nitrate mg/L 0.3–190 0.3 110 110 Bakken (107); Marcellus (3)

Nitrite mg/L —b 5 2 2 Marcellus (2)

Phosphate mg/L 12–77 31 4 4 Barnett (1); Marcellus (1); Woodford-Cana-Caney (2); 

Sulfate mg/L 8.9–700 110 8,203 5,451

Bakken (425); Barnett (31); Cleveland (9); Codell (1); Cody (27); Cotton 

Valley/Bossier (1); Dakota (28); Devonian (4); Eagle Ford (1166); 

Fayetteville (2); Frontier (123); Hilliard-Baxter-Mancos (28); Lance (1722); 

Lansing Kansas City (15); Lewis (52); Mancos (2); Marcellus (301); 

Medina/Clinton-Tuscarora (2); Mesaverde (438); Mesaverde/Lance (11); 

Mesaverde/Lance/Lewis (916); Morrow (1); Mowry (5); New Albany (1); 

Niobrara (133); Oswego (4); Pearsall (3); Spraberry (26); Woodford-CanaCaney (2726)

Sulfide mg/L 1.7–3.2 3 79 72 Barnett (1); Eagle Ford (1); Marcellus (77)

Source: 186 DCN SGE01184

a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these 

instances, there were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified.

b—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

69

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: 183 DCN SGE01181

a—Source did not report detection limit.

b—Source only reported median value.

Abbreviations: ND—nondetect; mg/L—milligrams per liter; μg/L—micrograms per liter
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

70

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

Parameter Units Range Median

Number of 

Data Pointsa

Number of 

Detects

Formations Represented 

(Number of Associated Data Points)a

1,2,4-Trimethylbenzene μg/L 1.1–100 5 92 89 Barnett (25); Marcellus (67)

1,3,5-Trimethylbenzene μg/L 3–130 5 85 81 Barnett (18); Marcellus (67)

Acetone μg/L 12–1,100 40 96 86 Barnett (22); Marcellus (72)

Benzene μg/L 4.8–3,700 8.5 144 122 Barnett (25); Marcellus (111); Niobrara (5); Woodford-CanaCaney (3)

Carbon disulfide μg/L 5–250 5 68 67 Marcellus (68)

Chlorobenzene μg/L 0–100 5 72 70 Marcellus (69); Woodford-Cana-Caney (3)

Chloroform μg/L 0–100 5 77 75 Barnett (5); Marcellus (69); Woodford-Cana-Caney (3)

Ethanol μg/L 5,000–20,000 10,000 53 53 Marcellus (53)

Ethylbenzene μg/L 3.4–130 5 130 104 Barnett (18); Marcellus (108); Medina/Clinton-Tuscarora (1); 

Woodford-Cana-Caney (3)

Isopropylbenzene μg/L 5–100 5 83 69 Barnett (16); Marcellus (67)

Methanol μg/L 5,000–180,000 10,000 55 55 Marcellus (55)

Methyl chloride μg/L 5–100 5 95 69 Marcellus (95)

Naphthalene μg/L 1.8–110 5 129 103 Barnett (39); Marcellus (90)

Phenol μg/L 1.9–56 2 111 83 Barnett (17); Marcellus (91); Woodford-Cana-Caney (3)

Pyridine μg/L 7.9–900 86 91 90 Barnett (24); Marcellus (67)

Tetrachloroethylene μg/L 5–100 5 95 68 Marcellus (95)

Toluene μg/L 2–2,900 6 149 125 Barnett (25); Marcellus (115); Medina/Clinton-Tuscarora (1); 

Niobrara (5); Woodford-Cana-Caney (3)

Xylenes μg/L 5.2–850 15 136 111 Barnett (20); Marcellus (112); Medina/Clinton-Tuscarora (1); 

Woodford-Cana-Caney (3)

Source: 186 DCN SGE01184

a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these instances, 

there were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified.

Abbreviation: μg/L—micrograms per liter
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

71

Table C-3 indicates that ethanol, methanol, and naphthalene are commonly reported 

additives to fracturing fluid. This suggests that at least some portion of the concentrations of 

these constituents found in UOG produced water (see Table C-15) may have originated from the 

fracturing fluid. Methanol is typically used in fracturing fluid as a biocide, corrosion inhibitor, 

crosslinker, and surfactant; ethanol is also used as a biocide and surfactant (see Table C-2).

Operators may also use methanol as an antifreezing agent at UOG operations in areas with 

seasonal temperature fluctuations. Methanol may be used at the wellhead to avoid freezing in the 

wellbore or at compressor stations to prevent equipment from freezing (95 DCN SGE00635).

The EPA did not identify any quantitative information about diesel-range organics or 

total petroleum hydrocarbons in UOG produced water. However, Table C-3 and Table C-4 show 

that petroleum distillates are typically used in fracturing fluid. The EPA ORD’s 2015 Analysis of 

Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure Registry 1.0 contains 

additional information about these constituents (106 DCN SGE00721). 

3.2.3 Metals in 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 

commonly detected in UOG drilling wastewater. The EPA identified the following limitations to 

the data presented in the table:

• Fewer data points (i.e., less than 30 data points) were available for each parameter.

• All of the data came from the Marcellus shale formation. 

Table C-17 presents concentration data from existing literature for the metals most 

commonly detected in UOG produced water. The EPA identified the following limitations to the 

data presented in the table:

• The majority of the data associated with aluminum, antimony, arsenic, beryllium, 

boron, cadmium, cobalt, copper, lead, lithium, manganese, mercury, molybdenum, 

nickel, phosphorus, selenium, silver, strontium, thallium, tin, titanium, vanadium, and 

zinc came from the Marcellus shale formation.

• The majority of the data associated with iron came from the Lance tight formation. 

• The majority of the data associated with chromium came from the Bakken shale 

formation. 

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

from Marcellus Shale Formation Wells

Parameter Units Range Median

Number of 

Data Points

Number of 

Detects

Aluminum mg/L 1.7–6,900 38 12 12

Arsenic mg/L NDa–4.2 NDa 12 6

Barium mg/L 2.6–2,000 13 14 14

Beryllium mg/L NDa–0.018 NDa 8 2
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

72

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

Boron mg/L NDa–2.7 0.17 8 4

Cadmium mg/L NDa–0.0050 NDa 8 1

Calcium mg/L 150–15,000 1,300 13 13

Chromium mg/L NDa–11 0.010 12 8

Cobalt mg/L NDa–1.8 NDa 8 3

Copper mg/L NDa–17 0.83 8 6

Iron mg/L 4.2–18,000 86 12 12

Lead mg/L NDa–8.0 0.35 12 10

Lithium mg/L NDa–1.2 NDa 8 1

Magnesium mg/L NDa–3,600 290 12 11

Manganese mg/L NDa–350 4.3 12 11

Mercury mg/L NDa–0.029 NDa 8 2

Molybdenum mg/L —b 0.10 1 1

Nickel mg/L NDa–16 0.55 12 9

Potassium mg/L —b 8,800 4 4

Selenium mg/L NDa–0.11 NDa 8 3

Silver mg/L NDa–0.010 NDa 8 1

Sodium mg/L 170–16,000 2,900 12 12

Strontium mg/L 1.8–1,500 21 13 13

Zinc mg/L NDa–38 2.1 12 10

Source: 183 DCN SGE01181

a—Source did not report detection limit 

b—Source only reported median value

Abbreviation: mg/L—milligrams per liter; ND—nondetect
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

73

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

Parameter Units Range Median

Number of 

Data Pointsa

Number of 

Detects Formations Represented (Number of Associated Data Points)a

Aluminum mg/L 0.13–2 0.48 206 175 Bakken (4); Barnett (31); Eagle Ford (5); Frontier (1); Lance (7); Marcellus (114); 

Mesaverde (37); Mesaverde/Lance (2); Woodford-Cana-Caney (3)

Antimony mg/L 0.01–0.1 0.047 112 79 Barnett (9); Marcellus (103)

Arsenic mg/L 0.014–0.11 0.06 135 99 Barnett (16); Eagle Ford (1); Marcellus (115); Woodford-Cana-Caney (3)

Barium mg/L 2.1–790 18 1,191 1,190

Bakken (312); Barnett (39); Cotton Valley/Bossier (2); Dakota (3); Devonian (4); Eagle 

Ford (10); Fayetteville (2); Frontier (10); Lance (21); Lansing Kansas City (7); Marcellus 

(210); Medina/Clinton-Tuscarora (1); Mesaverde (38); Mesaverde/Lance (8); Morrow (1); 

Utica (1); Woodford-Cana-Caney (522)

Beryllium mg/L 0.02–0.04 0.04 114 72 Barnett (2); Marcellus (112)

Boron mg/L 3.1–67 14 151 137 Bakken (8); Barnett (33); Eagle Ford (2); Marcellus (103); Niobrara (5)

Cadmium mg/L 0.0014–0.05 0.0086 134 92 Barnett (16); Marcellus (115); Woodford-Cana-Caney (3)

Calcium mg/L 16–16,000 190 9,272 6,261

Bakken (427); Barnett (40); Cleveland (11); Codell (9); Cody (41); Cotton Valley/Bossier 

(3); Dakota (35); Devonian (4); Eagle Ford (1645); Fayetteville (2); Frontier (223); 

Hilliard-Baxter-Mancos (33); Lance (1942); Lansing Kansas City (15); Lewis (53); 

Mancos (2); Marcellus (343); Medina/Clinton-Tuscarora (2); Mesaverde (461); 

Mesaverde/Lance (13); Mesaverde/Lance/Lewis (917); Morrow (1); Mowry (5); New 

Albany (1); Niobrara (189); Oswego (5); Pearsall (3); Spraberry (26); Woodford-CanaCaney (2821)

Chromium mg/L 0.021–0.9 0.3 386 352 Bakken (234); Barnett (27); Eagle Ford (6); Marcellus (116); Woodford-Cana-Caney (3)

Cobalt mg/L 0.013–5 0.5 124 92 Barnett (16); Eagle Ford (5); Marcellus (103)

Copper mg/L 0.024–0.5 0.13 150 110 Bakken (2); Barnett (23); Eagle Ford (6); Marcellus (116); Woodford-Cana-Caney (3)

Iron mg/L 4–170 38 3,070 383

Bakken (22); Barnett (36); Codell (8); Cody (6); Cotton Valley/Bossier (2); Dakota (3); 

Eagle Ford (11); Fayetteville (2); Hilliard-Baxter-Mancos (32); Lance (1767); Marcellus 

(301); Mesaverde/Lance/Lewis (772); Mowry (3); Niobrara (72); Spraberry (26); Utica 

(1); Woodford-Cana-Caney (6)

Lead mg/L 0.013–0.42 0.03 133 96 Bakken (1); Barnett (15); Eagle Ford (1); Marcellus (113); Woodford-Cana-Caney (3)

Lithium mg/L 4.6–150 44 155 132 Barnett (32); Eagle Ford (1); Hilliard-Baxter-Mancos (4); Lance (4); Lewis (1); Marcellus 

(90); Mesaverde (8); Mesaverde/Lance/Lewis (4); Niobrara (11)
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

74

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

Parameter Units Range Median

Number of 

Data Pointsa

Number of 

Detects Formations Represented (Number of Associated Data Points)a

Magnesium mg/L 3–1,300 40 7,116 4,374

Bakken (427); Barnett (40); Cleveland (11); Codell (9); Cody (39); Cotton Valley/Bossier 

(3); Dakota (28); Devonian (4); Eagle Ford (1622); Fayetteville (2); Frontier (213); 

Hilliard-Baxter-Mancos (33); Lance (1791); Lansing Kansas City (15); Lewis (52); 

Mancos (2); Marcellus (327); Medina/Clinton-Tuscarora (2); Mesaverde (391); 

Mesaverde/Lance (13); Mesaverde/Lance/Lewis (778); Morrow (1); Mowry (4); New 

Albany (1); Niobrara (188); Oswego (5); Pearsall (3); Spraberry (26); Woodford-CanaCaney (1086)

Manganese mg/L 0.47–9 1.7 238 224 Bakken (7); Barnett (38); Cotton Valley/Bossier (2); Dakota (3); Eagle Ford (8); 

Fayetteville (2); Marcellus (156); Spraberry (19); Woodford-Cana-Caney (3)

Mercury mg/L 0.000029–

0.00025 0.0002 118 88 Barnett (12); Eagle Ford (1); Marcellus (102); Woodford-Cana-Caney (3)

Molybdenum mg/L 0.014–0.4 0.038 140 118 Bakken (1); Barnett (29); Eagle Ford (5); Marcellus (105)

Nickel mg/L 0.019–2 0.14 154 124 Barnett (28); Eagle Ford (6); Marcellus (117); Woodford-Cana-Caney (3)

Phosphorus mg/L 0.065–2.5 0.2 105 103 Bakken (6); Barnett (24); Eagle Ford (1); Marcellus (71); Woodford-Cana-Caney (3)

Potassium mg/L 13–5,100 120 4,074 1,447

Bakken (382); Barnett (37); Cleveland (3); Cody (34); Cotton Valley/Bossier (3); Dakota 

(22); Eagle Ford (150); Frontier (163); Hilliard-Baxter-Mancos (26); Lance (1709); Lewis 

(39); Marcellus (137); Medina/Clinton-Tuscarora (2); Mesaverde (423); Mesaverde/Lance 

(9); Mesaverde/Lance/Lewis (818); Mowry (5); Niobrara (109); Woodford-Cana-Caney 

(3)

Selenium mg/L 0.025–0.05 0.05 110 75 Barnett (7); Marcellus (103)

Silver mg/L 0.0093–

0.087 0.05 115 75 Marcellus (112); Woodford-Cana-Caney (3)

Sodium mg/L 1,500–

80,000 5,400 7,404 4,382

Bakken (427); Barnett (39); Cleveland (11); Codell (9); Cody (41); Cotton Valley/Bossier 

(3); Dakota (35); Devonian (4); Eagle Ford (1632); Fayetteville (2); Frontier (226); 

Hilliard-Baxter-Mancos (33); Lance (1938); Lansing Kansas City (16); Lewis (54); 

Mancos (2); Marcellus (203); Medina/Clinton-Tuscarora (2); Mesaverde (465); 

Mesaverde/Lance (13); Mesaverde/Lance/Lewis (933); Morrow (1); Mowry (5); New 

Albany (1); Niobrara (193); Oswego (5); Spraberry (26); Woodford-Cana-Caney (1085)

Strontium mg/L 1.5–3,500 360 325 323

Bakken (10); Barnett (36); Cotton Valley/Bossier (2); Dakota (3); Devonian (4); Eagle 

Ford (9); Fayetteville (2); Frontier (2); Lance (21); Marcellus (184); Medina/ClintonTuscarora (2); Mesaverde (38); Mesaverde/Lance (8); Utica (1); Woodford-Cana-Caney 

(3)

Thallium mg/L 0.017–0.5 0.1 120 83 Barnett (13); Marcellus (104); Woodford-Cana-Caney (3)
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

75

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

Parameter Units Range Median

Number of 

Data Pointsa

Number of 

Detects Formations Represented (Number of Associated Data Points)a

Tin mg/L 0.021–2 1 86 84 Barnett (12); Eagle Ford (3); Marcellus (71)

Titanium mg/L 0.024–0.5 0.19 114 83 Barnett (17); Eagle Ford (2); Marcellus (95)

Vanadium mg/L 0.18–26 4.2 30 5 Barnett (1); Eagle Ford (2); Marcellus (27)

Zinc mg/L 0.06–1.5 0.2 163 138 Bakken (2); Barnett (33); Eagle Ford (6); Fayetteville (2); Marcellus (117); WoodfordCana-Caney (3)

Source: 186 DCN SGE01184

a—In some instances the sum of the number of data points associated with individual formations does not equal the total number of data points. In these instances, there 

were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified.

Abbreviation: mg/L—milligrams per liter
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

76

As discussed in Section C.3.2.1, sodium and calcium are two of the primary constituents 

that contribute to TDS in UOG produced water. Strontium, which is a group II alkaline earth 

metal, is another metal that contributes to TDS in UOG produced water, with a median 

concentration in the data evaluated by the EPA of 360 mg/L. Low-solubility salts of alkaline 

earth metals (e.g., barium sulfate) commonly precipitate in pipes and valves, forming scale (12

DCN SGE00167). Barium is commonly found in higher concentrations in produced water from 

the Marcellus and Devonian shale formations than in produced water from other UOG

formations, according to data evaluated by the EPA. Figure C-5 shows box and whisker plots of

the concentrations of barium in UOG produced water from various shale and tight oil and gas 

formations on a log scale. Median concentrations of heavy metals (e.g., chromium, copper, 

nickel, zinc, lead, mercury, arsenic) in UOG produced water are less than 1 mg/L, much lower 

than the concentrations of the alkaline earth metals.

Source: 186 DCN SGE01184

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

Gas Formations

3.2.4 Radioactive Constituents in 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 (188 DCN 

0.1

1.0

10.0

100.0

1,000.0

10,000.0 Barium Concentration (mg/L)
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

77

SGE01185). The EPA identified limited available data (primarily from the Marcellus Shale 

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 (188 DCN SGE01185) contains a 

more detailed discussion of this topic.

The EPA identified limited radioactive constituent concentration data for UOG drilling 

wastewater. Table C-18 shows the available data from the Marcellus shale formation.

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

Wastewater from Marcellus Shale Formation Wells

Parameter Units Range Median

Number of Data 

Points

Number of 

Detects

Gross alpha pCi/L 17–3,000 130 5 5

Gross beta pCi/L 32–4,200 1,200 5 5

Sources: 183 DCN SGE01181

Abbreviation: pCi/L—picocuries per liter

Similarly, the EPA identified limited radioactive constituent concentration data for UOG 

produced water. As presented in Table C-19, most available data characterize produced water 

from the Marcellus formation; limited data were available from the Niobrara formation. 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 (188 DCN SGE01185) discusses potential interference issues 

associated with various EPA methods and notes that the following methods may 

experience interference from some UOG extraction wastewater: 900.0, Gross Alpha 

and Gross Beta Radioactivity; 903.0, Alpha-Emitting Radium Isotopes; and 903.1,

Radium-226, Radon Emanation Technique.

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

Parameter Formation Method(s)

Range

(pCi/L)

Median

(pCi/L)

Number of 

Data Points

Number 

of Detects

Gross alpha Marcellus 900.0 4.7–24,000 8,700 103 101

Gross alpha Niobrara 900.0 300–820 1,800 3 3

Gross beta Marcellus 900.0 0.66–1,700 1,600 94 92
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

78

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 900.0 170–420 760 3 3

Radium-226 Marcellus 901.1 Mod., 903.0, 903.1, γspectrometry 10–88,000 1,700 74 74

Radium-226 Niobrara 901.1 Mod. 960–3,300 620 3 3

Radium-228 Marcellus 901.1, 903.0, 904.0, γspectrometry 15–16,000 470 73 72

Radium-228 Niobrara 901.1 Mod. 400–1,100 330 3 3

Sources: 186 DCN SGE01184

Abbreviation: pCi/L—picocuries per liter

As a point of comparison, Table C-20 includes data from a 2014 International Atomic 

Energy Agency report (134 DCN SGE00769) that included radium isotope concentrations in 

rivers, lakes, groundwater, and drinking water from public water systems. Data for radium-228 

were limited, but the average of measured concentrations of radium-226 found in U.S. rivers and 

lakes was 0.56 pCi/L (21 millibecquerel per liter). The median concentrations of radium-226 and 

radium-228 in UOG produced water in the Marcellus and Niobrara formations presented in 

Table C-19 were above the maximum naturally occurring concentration in U.S. rivers, lakes, 

groundwater, or drinking water from public water systems presented in Table C-20. Radium in 

groundwater may originate from rocks, soil, and other naturally occurring materials, which are 

likely also the origins of a portion of the radium in UOG produced water. 

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

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

Parameter 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

79

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 from public water 

systems 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 from public water 

systems 0 0.014 —

Source: 134 DCN SGE00769

“—”—Data were not reported.

Note: Data are presented as they were reported, either as a range (i.e., minimum, maximum) or as an average 

value.

Abbreviations: pCi/L—picocuries per liter; ND—nondetect

In January 2015, PA DEP announced the results of a study of radioactive elements in 

UOG extraction wastewater, sludge, and drill cuttings. Although PA DEP concluded “...[t]here 

is little potential for radiological exposure to workers and members of the public from handling 

and temporary storage of [flowback fluid and] produced water on natural gas well sites,” it did 

conclude “...[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]” (161 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, Table 

C-3, and Table C-4). Guar gum may be found in UOG produced water at concentrations between 

100 mg/L and 20,000 mg/L (88 DCN SGE00616). Guar gum treatment requires a breakdown of 

the polymer and is a consideration for UOG operators who are reusing/recycling wastewater for 

fracturing. 

Microorganisms are also found in UOG drilling wastewater and produced water. 

Microorganisms may be present in concentrations as high as 1 × 109 organisms per 100 mL in 

UOG produced water (88 DCN SGE00616). Sulfate-reducing bacteria (SRB) are one 

classification of a naturally occurring microorganism that may be found in UOG produced water

and drilling wastewater. SRB can cause problems during reuse/recycle of UOG produced water 

because they can reduce and/or precipitate metals and ions, potentially causing scale in the 
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

80

wellbore. They can also create hydrogen sulfide,

81 a potential human health concern that is also 

highly corrosive and can harm the well casing and wellbore (106 DCN SGE00721).

3.3 UOG Produced Water Characterization Changes over Time

Concentrations of TDS, radioactive elements, metals, and organic compounds vary across 

different formations and over time. However, for the vast majority of formations for which data 

are available, the data demonstrate that flowback and long-term produced water are both 

influenced by constituents present in the formation. For example, concentrations of select 

naturally occurring constituents commonly found in shale formations (e.g., bromide, magnesium) 

are found in elevated concentrations in flowback compared to hydraulic fracturing fluid. The 

elevated concentrations indicate that the formation is contributing concentrations of these 

constituents to the flowback. Similarly, concentrations of TDS and TDS-contributing 

constituents (e.g., sodium, chloride, calcium) increase over time as formation water and the 

dissolution of constituents out of the formation contribute to long-term produced water.

RPSEA’s 2012 Characterization of Flowback Waters from the Marcellus and the Barnett 

Shale Regions (44 DCN SGE00414) presents sampling data from 19 sites in the Marcellus shale 

and five sites in the Barnett shale. The sampled constituents include a wide array of classical, 

conventional and organic parameters and metals. Where possible, these constituents were 

sampled at day 0, day 1, day 5, day 14, and day 90. Figure C-6 presents median data for select 

constituents as reported in the RPSEA report. Figure F-1 in the appendices presents median data 

for additional constituents as reported in the RPSEA report.

 81 Exposure to low concentrations of hydrogen sulfide may cause difficulty breathing and/or irritation to the eyes, 

nose, or throat. Exposure to high concentrations of hydrogen sulfide may cause headaches, poor memory, 

unconsciousness, and death (108 DCN SGE00723).
Chapter C—Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics

81

Source: The EPA generated this figure using data from 44 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

82

Chapter D. UOG EXTRACTION WASTEWATER MANAGEMENT AND DISPOSAL 

PRACTICES

During the lifetime of a well, UOG extraction generates large volumes of UOG extraction 

wastewater that contain constituents potentially harmful to human health and the environment. 

This creates a need for appropriate wastewater management infrastructure and disposal practices.

Except in limited circumstances,

82 the existing effluent guidelines for oil and gas extraction 

prohibit the onsite direct discharge of wastewater into waters of the United States. Historically, 

operators primarily managed their wastewater via underground injection using Class II enhanced 

recovery and disposal wells, where available. In fact, in 2010, the EPA and industry stakeholders 

estimated that over 90 percent of oil and gas produced water (conventional and unconventional) 

was disposed of via Class II enhanced recovery and disposal wells (91 DCN SGE00623). This 

section discusses the methods used by UOG operators to manage and dispose of UOG extraction 

wastewater.

1 OVERVIEW OF UOG EXTRACTION WASTEWATER MANAGEMENT AND DISPOSAL 

PRACTICES 

UOG operators primarily use three methods for management of UOG produced water (86

DCN SGE00613; 22 DCN SGE00276; 58 DCN SGE00528):

• Dispose of wastewater via Class II disposal wells (“disposal wells”) 

• Reuse/recycle wastewater in subsequent fracturing jobs

• Transfer wastewater to a CWT facility

UOG operators primarily use the following methods for management of drilling 

wastewater, which includes drill cuttings and drilling fluids83 (183 DCN SGE01181):

• Disposal via disposal wells

• Reuse/recycle in subsequent drilling and/or fracturing jobs

• Transfer to a CWT facility

• Onsite burial84

• Disposal via landfill

• Land application

 82 While the existing oil and gas extraction ELG allows onshore oil and gas extraction wastewater generated west of 

the 98th meridian to be permitted for discharge when the water is of good enough quality for agricultural and wildlife 

uses (see 40 CFR part 435 subpart E), EPA has not found that these types of permits are typically written for UOG

extraction wastewater as defined for in this document for the final rule. 83 As discussed in Chapter B, drilling muds (fluids) are reused/recycled until they are considered “spent,” i.e., they 

can no longer be reused/recycled, at this stage they are sometimes referred to as “spent drilling fluids.”

84 Onsite burial involves temporary fluid storage in onsite open earthen or lined pits with burial of residual solids 

after fluids are solidified, removed from the top, or evaporated.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

83

Figure D-1 and Figure D-2 illustrate the primary management methods for UOG 

produced water and drilling wastewater, respectively. In select areas, UOG operators also use 

evaporation ponds for disposal of UOG produced water and drilling wastewater. However, there 

are certain requirements for using evaporation ponds, including very dry climates, which mainly 

occur in the western United States (105 DCN SGE00710). Evaporation ponds also require a 

large, flat site, and they perform best only during select months of the year (e.g., May through 

October) (135 DCN SGE00779.A24).

Figure D-1. UOG Produced Water Management Methods

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
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

84

Figure D-2. UOG Drilling Wastewater Management Methods

UOG operators’ frequency of use of each of the aforementioned UOG extraction 

wastewater management options varies by operator, by formation, and sometimes within each 

region of the formation (71 DCN SGE00579; 22 DCN SGE00276; 95 DCN SGE00635; 37 DCN 

SGE00354; 105 DCN SGE00710). Table D-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 (171 DCN SGE01128), but the industry is increasingly 

turning to reuse/recycle and, in some geographic areas, transferring to CWT facilities to manage 

growing volumes of wastewater (see Section D.3 and Section D.4) (178 DCN SGE01178; 102

DCN SGE00707; 103 DCN SGE00708). Although cost is the primary factor, operators also 

consider other factors for wastewater management decisions such as proximity to management 

options (e.g., CWT facilities, Class II injection wells), climate, federal or state regulatory 

requirements, wastewater quality and volume, and operator-specific risk management policies 

(91 DCN SGE00623). In some areas of the U.S., there may be additional considerations that 

drive change from traditional use of Class II injection wells to other wastewater management 

practices.85

The literature does not contain the same level of detailed information about drilling 

wastewater management practices as is provided for produced water management in Table D-1. 

However, the EPA did identify comprehensive data for management of drilling wastewater 

 85 For example, some studies suggest that Class II UIC wells have been associated with nearby seismic activity (198

DCN SGE01216; 226 DCN SGE01351; 227 DCN SGE01352) and in some cases the use of those wells have been 

restricted (227 DCN SGE01352). If use of a particular Class II UIC well becomes restricted, operators may utilize 

other options such as transfer to a different Class II UIC well, reuse/recycle and transfer to a CWT.

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
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

85

generated by Marcellus shale wells located in Pennsylvania. Figure D-3 shows management 

practices used by UOG operators in Pennsylvania for managing their UOG drilling wastewater 

from 2008 to 2014. In recent years (2010 to 2014), transfer to CWT facilities, reuse/recycle in 

drilling or fracturing, and injection for disposal—in that order—were the most common practices

for UOG drilling wastewater management in Pennsylvania (184 DCN SGE01182). In addition to 

this detailed information about drilling wastewater management in Pennsylvania, the EPA

obtained information from the fifth largest U.S. oil and gas operator regarding its Fayetteville 

shale operations. This operator reported that it reuses/recycles the majority of its drilling 

wastewater in drilling subsequent wells and the remainder is disposed of via disposal wells (92

DCN SGE00625). 

To illustrate how management practices used by UOG operators vary geographically, the 

EPA mapped the locations of known CWT facilities and disposal wells in the Appalachian basin 

(containing the Utica and Marcellus shale formations).

86 Figure D-4 compares the east and west 

portions of the basin, thus illustrating basin and formation differences in wastewater 

management practices. The east side of the basin contains very few underground disposal wells, 

but contains a high density of CWT facilities that have accepted or plan to accept UOG produced 

water from operators. In contrast, the west side has an abundance of disposal wells and injection 

for disposal is the primary wastewater management practice. 

The remaining subsections in Chapter D describe UOG produced water management 

practices: how disposal in disposal wells is the most common practice, how reuse/recycle in 

fracturing fluid is increasing, and how increasing numbers of CWT facilities are accepting UOG 

produced water and drilling wastewater where disposal wells are limited. Although operators 

have discharged UOG extraction wastewater to POTWs in the past, information available to EPA 

indicates that these discharges were discontinued in 2011 (184 DCN SGE01182; 27 DCN 

SGE00286; 35 DCN SGE00345; 71 DCN SGE00579). After describing the three management 

alternatives that the UOG industry uses (i.e., injection into disposal wells, reuse/recycle in 

fracturing, transfer to CWT facility), Chapter D ends with a discussion of POTWs and how they 

cannot remove some of the constituents in UOG extraction wastewater. The end of Chapter D

also presents EPA-collected data indicating that POTWs have not received any UOG extraction 

wastewater between 2011 and the end of 2014. EPA received no data during the public comment 

period on the proposed rule to indicate that this is still not the case.

 86 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

86

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 used 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 used 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: 179 DCN SGE01179

a—CWT facilities identified in these formations are all operator-owned.

b—This column indicates the type of data the EPA based the number of Xs on. In most cases, the EPA used a mixture of qualitative and quantitative data sources 

along with engineering judgment to determine the number of Xs.

XXX—The majority (≥50%) of wastewater is managed with this management practice; XX—A moderate portion (≥10% and <50%) of wastewater is managed 

with this management practice; X—This management practice has been documented in this location, but for a small (<10%) or unknown percent of wastewater. 

Blanks indicate the management practices has not been documented in the given location.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

87

Sources: 184 DCN SGE01182

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

Pennsylvania (2008–2014)
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

88

Sources: Generated by the EPA using data from 178 DCN SGE01178 and 190 DCN SGE01187

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

Basin87

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 enhanced recovery and disposal wells (91 DCN SGE00623). Underground injection 

involves pumping wastes into an underground formation with a confining layer of impermeable 

rock. The formation must also be porous enough to accept the wastewater. In its underground 

 87 The active disposal wells data were last updated in December 2013 for Pennsylvania. The last update for the 

active disposal wells data in Ohio and West Virginia is unknown. The EPA accessed the Ohio data in February 2013 

and the West Virginia data in December 2013. The CWT facility data were last updated at the end of 2014, based on 

publicly available information.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

89

injection well control program codified in 40 CFR parts 144 to 148, the EPA established six

classes of underground injection wells (8 DCN SGE00132):

• Class I industrial and municipal waste disposal wells

• Class II oil and gas related injection wells

• Class III mining wells

• Class IV shallow hazardous and radioactive injection wells (banned)

• Class V any not covered in Class I through IV (e.g., leach fields)

• Class VI carbon dioxide storage or sequestration

Class II injection wells serve three major purposes: 

• Injection of hydrocarbons for storage

• Injection of fluids for disposal (i.e., disposal wells)

• Injection of fluids for enhanced recovery (i.e., enhanced recovery wells)

Approximately 20 percent of Class II injection wells in the United States are Class II 

disposal wells; the remaining 80 percent are mostly Class II enhanced recovery wells (8 DCN 

SGE00132). Injection into Class II disposal wells typically involves injecting wastewater into a 

porous and non-oil-and-gas-containing reservoir. Industry does not use Class II enhanced 

recovery wells for disposing of UOG extraction wastewater because most enhanced recovery 

projects consist of a closed-loop system with two or more wells: at least one producing well and 

at least one enhanced recovery well. Operators of enhanced recovery projects typically route the 

wastewater generated by the producing well directly back to the adjacent enhanced recovery well 

(91 DCN SGE00623; 8 DCN SGE00132; 86 DCN SGE00613). Available literature and 

communication with industry indicates that industry only hauls UOG extraction wastewater to 

Class II disposal wells and does not use Class II enhanced recovery wells. In fact, the leading 

method of UOG extraction wastewater management throughout the United States is injection 

into a Class II disposal well (181 DCN SGE01179.A03). However, all types of oil and gas 

extraction wastewater (e.g., conventional, CBM, UOG) may be disposed of in Class II disposal 

wells.

2.1 Regulatory Framework for Underground Injection

The EPA’s regulations on underground injection wells are described in Chapter A. States, 

territories, and tribes have the option of requesting primacy, or primary enforcement authority, 

from the EPA for the Class II wells within their boundaries. In order to receive primacy, the state 

underground injection program must meet the EPA’s regulatory requirements or have a program 

determined to be effective to prevent underground injection that endangers drinking water 

sources. Currently, the EPA has delegated Class II primacy to 39 states, three territories, and two 

tribes. The EPA has authority over the Class II UIC programs in the remaining 11 states, two 

territories and all other tribes (84 DCN SGE00611).

2.2 Active Disposal Wells and Volumes

The availability of underground injection for disposal varies by state. Some states have a 

large number of Class II injection wells (e.g., Texas, Oklahoma, Kansas) while others have few 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

90

(e.g., Virginia, South Dakota). The EPA tabulated active Class II disposal wells using data from 

state agencies and EPA direct implementation programs. More information about how the EPA

compiled data from state agencies is documented in a separate memorandum titled Analysis of 

Active Underground Injection for Disposal Wells (190 DCN SGE01187; 191 DCN 

SGE01187.A01).

Table D-2 presents the number of active Class II disposal wells by state (190 DCN 

SGE01187; 191 DCN SGE01187.A01). Only states with active disposal wells are listed; all other 

states have zero active disposal wells. Table D-2 also includes total state disposal rate on a 

million gallon per day basis for each state. Lastly, Table D-2 presents average disposal rates on a 

gallon per day per well basis for each state based on the active number of disposal wells and total 

state disposal rate. Average disposal rates of individual wells vary significantly, reflecting the 

geology of the underlying formation (23 DCN SGE00279). States are first sorted by geographic 

region, then by the total state disposal rate. States with no disposal volume and rate data are 

sorted by highest to lowest count of active Class II disposal wells.

The average disposal rate per well estimates in Table D-2 are not exact but rather are 

general approximations based on a number of assumptions, listed below and described in more 

detail in a separate memorandum, Analysis of Active Underground Injection for Disposal Wells

(190 DCN SGE01187). 

• Calculation of the average disposal rate per well (gpd/well). The EPA included all 

wells identified as active even if some of these wells reported zero injection volume. 

This assumption may decrease the average disposal rate per well but only affects 

states where the EPA used state databases as the source for injection volumes (NM, 

AK, and OK). However, the EPA excluded wells that were identified as just being 

drilled because they could not have injected any wastewater.

• Calculation of the state disposal rate (MGD). The EPA included the number of 

disposal wells identified as currently being drilled (e.g., under construction) in the 

active number of disposal wells. This assumption may increase the current state 

injection rates but was intended to capture wells that will inevitably come online in 

the near future. However, the EPA excluded wells from all calculations that were 

only permitted or proposed new well projects because these wells may be terminated 

even after they are permitted or proposed (i.e., may never come online).

• Missing volume data. The EPA was unable to identify injected volumes for Illinois,

which has a substantial number of active disposal wells. Therefore, the total volume 

of produced water injected into disposal wells in the nation estimated by this analysis 

may be an underestimate. Also, there is no available injection volume data for wells 

on tribal lands.

• Number of active disposal wells on tribal lands. It was unclear if the underlying 

data sources EPA used to generate Table D-2 included Class II disposal wells on 

tribal lands. Therefore, Table D-3 presents the number of active Class II disposal 

wells on tribal lands reported by the EPA’s Office of Ground Water and Drinking 

Water (OGWDW) (159 DCN SGE01012; 190 DCN SGE01187; 191 DCN 

SGE01187.A01). Table D-3 includes over 800 active Class II disposal wells located 

on tribal lands in eight different states. Tribes are first sorted by geographic region, 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

91

then by the number of active Class II disposal wells. No disposal volumes or rate data 

were available for Class II disposal wells on tribal lands. 

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

(Primarily 2012 and 2013 Data)

Geographic Region 

(from the EIA) State

Number of Active 

Disposal Wellsa

Average Disposal 

Rate per Well

(gpd/Well)

b

State Disposal 

Rate (MGD)

Alaska Alaska 45 182,000 8.2

East

Illinois 1,054 —c —c

Michigan 772 16,200 13

Florida 14 246,000 3.4

Indiana 208 7,950 1.7

Ohio 190 8,570 1.6

West Virginia 64 6,970 0.45

Kentucky 58 4,650 0.27

Virginia 12 17,500 0.21

Pennsylvania 9 6,380 0.057

New York 10d 33.7 0.00034

Gulf Coast/Southwest

Texas 7,876 52,100 410

Louisiana 2,448 40,300 99

New Mexico 736 48,600 36

Mississippi 499 24,200 12

Alabama 85 53,300 4.5

Mid-Continent

Kansas 5,516 25,600 140

Oklahoma 3,837 35,900 140

Arkansas 640e 25,400 16

Nebraska 113 19,100 2.2

Missouri 11 2,270 0.025

Iowa 3 —c —c

Northern Great Plains

North Dakota 395 53,300 21

Montana 199 32,700 6.5

South Dakota 15 17,400 0.26

Rocky Mountains

Wyoming 335 107,000 36

Colorado 292 48,800 14

Utah 118 83,400 9.8

West Coast

California 826 86,800 72

Nevada 10 54,600 0.55

Oregon 9 —c —c

Washington 1 —c —c

Total 26,400 41,300 1,050

Source: 190 DCN SGE01187

a—Number of active disposal wells is based primarily on data from 2012 to 2013.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

92

b—Typical injection volumes per well are based on historical annual volumes for injection for disposal divided by 

the number of active disposal wells during the same year (primarily 2012 to 2013 data). These approximations are 

based on a number of assumptions, detailed in a separate memorandum, Analysis of Active Underground Injection 

for Disposal Wells (190 DCN SGE01187).

c—Disposal rates and volumes are unknown.

d—These wells are not currently permitted to accept UOG extraction wastewater (source: 110 DCN SGE00726).

e—Only 24 of the 640 active disposal wells in Arkansas are in the northern half of the state, close to the Fayetteville 

formation (50 DCN SGE00499).

Abbreviations: gpd—gallons per day; MGD—million gallons per day

Table D-3. Distribution of Active Class II Disposal Wells on Tribal Lands (2014 Data)

Geographic Region 

(from the EIA)

Tribe 

ID Tribe Name

Associated 

State

Number of 

Active 

Disposal 

Wells

East 472 Saginaw Chippewa Indian Tribe MI 7

Gulf Coast/Southwest

701 Jicarilla Apache Nation NM 1

751 Ute Mountain Tribe of the Ute Mountain Reservation NM 2

Mid Continent

930 Osage Nation OK 775

812 Pawnee Nation OK 5

809 Apache Tribe OK 2

824 Sac & Fox Nation OK 2

808 Comanche Nation OK 1

Northern Great Plains

201 Blackfeet Tribe of the Blackfeet Indian Reservation MT 6

301 Three Affiliated Tribes of the Fort Berthold Reservation ND 5

Rocky Mountains

687 Ute Indian Tribe of the Uintah & Ouray Reservation UT 48

750

Southern Ute Indian Tribe of the Southern Ute 

Reservation CO 31

281 Arapahoe Tribe of the Wind River Reservation WY 4

Total 889

Source: 190 DCN SGE01187

2.3 Underground Injection of UOG Wastewaters

Nationally, injection for disposal volumes have increased as crude oil and natural gas 

production has increased. Figure D-5 shows the trend over time of injection for disposal volumes 

(blue bars), total crude oil and natural gas production (solid lines), and UOG production in the 

United States (dotted lines). The annual injection for disposal volume increased from 1995 to 

2012 as UOG production ramped up significantly over the same period. The EPA observed a 

similar trend in the Bakken shale formation in North Dakota. Figure D-6 shows the trend over 

time of injection for disposal volumes in North Dakota (blue bars), total crude oil production in 

North Dakota (solid black line), and Bakken shale crude oil production in North Dakota (dotted 

black line). The annual injection for disposal volume increased from 1998 to 2013 as crude oil 

production ramped up significantly over the same period. Figure D-7 further demonstrates how 

additional disposal wells were drilled over the same time period in North Dakota to meet the 

increased disposal demand.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

93

The EPA anticipates that in many parts of the United States, additional injection for 

disposal capacity will become available as demand increases with increased UOG production.

However, as illustrated above in Table D-2, underground injection for disposal capacity in close 

proximity to producing wells is much less available in certain portions of the United States.

Source: 171 DCN SGE01128; 194 DCN SGE01192; 213 DCN SGE01322; 220 DCN SGE01339; 221 DCN 

SGE01340

Figure D-5. U.S. Injection for Disposal Volume and UOG Production over Time88

 88 Total crude oil and natural gas production includes lease condensates, CBM, onshore conventional, offshore, 

conventional onshore Alaska, and offshore Alaska. Unconventional crude oil production also includes lease 

condensates.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

94

Source: 218 DCN SGE01336; 219 DCN SGE01337; 13 DCN SGE00182; 171 DCN SGE01128; 221 DCN 

SGE01340

Figure D-6. Injection for Disposal Volume and Crude Oil Production over Time in North 

Dakota

Source: 67 DCN SGE00557; 13 DCN SGE00182; 171 DCN SGE01128; 221 DCN SGE01340

Figure D-7. Injection for Disposal Volume, Cumulative Bakken Wells Drilled, and 

Cumulative Disposal Wells Drilled in North Dakota
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

95

Operators of commercial injection wells for disposal may impose a surcharge to dispose 

of flowback (23 DCN SGE00279). Injection well operators impose the surcharge because 

flowback has a lower density than long-term produced water. Injection of high-density 

wastewater requires less power (i.e., pumping) than the injection of less-dense wastewater,89 and 

the injection rate (i.e., barrels per day per well) is inversely proportional to the injection pressure 

due to technical and permit limitations. As a result, disposal well operators must inject lowerdensity flowback at a lower flow rate and typically use more power. 

3 REUSE/RECYCLE IN FRACTURING

Many operators evaluate reusing/recycling UOG extraction wastewater before deciding 

to manage it via another method (i.e., disposal well or CWT facility) (86 DCN SGE00613; 54

DCN SGE00521; 22 DCN SGE00276). Reuse/recycle involves mixing flowback and/or longterm produced water from previously fractured wells with other source water90 to create the base 

fluid91 used in a subsequent well fracture (3 DCN SGE00046). Operators typically transport the 

wastewater, by truck or pipe, from storage to the fracturing site just before and during hydraulic 

fracturing. Operators typically store the wastewater in 10,500- to 21,000-gallon (250- to 500-

barrel) fracturing tanks onsite until they are ready to blend it with other source water during the 

hydraulic fracture. When hydraulic fracturing begins, they pump the stored UOG produced water

for reuse and other source water to a blender to form the base fluid. The blending usually occurs 

upstream of other steps such as fracturing chemical addition or pressurization by the pump trucks 

(92 DCN SGE00625). 

Since the late 2000s, UOG operators have increased wastewater reuse/recycle (86 DCN 

SGE00613; 172 DCN SGE01143; 199 DCN SGE01231). In the early development of UOG (i.e., 

the early to mid-2000s), most operators believed that reuse/recycle was not technically feasible 

because high TDS concentrations in UOG extraction wastewater adversely affected fracturing 

chemical additives and/or formation geology (86 DCN SGE00613). As a result, operators used 

only fresh water as base fluid for fracturing. One of the changes that contributed to more 

widespread reuse of wastewater as a base fluid is that fracturing service providers were able to 

design fracturing additives to tolerate base fluids with higher concentrations of TDS (99 DCN 

SGE00691; 54 DCN SGE00521; 86 DCN SGE00613; 5 DCN SGE00095).

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-5 in Section D.3.2 for these ranges) (86 DCN SGE00613; 101 DCN SGE00705; 88

DCN SGE00616). Gel fracturing fluid designs (defined in Section C.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 (101 DCN 

SGE00705; 86 DCN SGE00613; 88 DCN SGE00616). As a result, at present, gel designs require 

 89 The density of flowback is typically close to that of fresh water (8 pounds per gallon), while the density of 

produced water can be greater than 10 pounds per gallon (23 DCN SGE00279).

90 Source water is any fluid that makes up fracturing base fluid. See Section C.1.1.

91 Base fluid is the primary component of fracturing fluid to which proppant and chemicals are added. See Section 

C.1.1.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

96

base fluid that meets the low end of the TDS criteria ranges (see Table D-5 in Section D.3.2 for 

these ranges). This is primarily because TDS interferes with the properties of the cross-linked 

gels inherent to gel fracturing fluid designs. Industry also reports that boron is a constituent of 

concern for reuse/recycle when using gel recipes because it interferes with the intended delayed 

activation of cross-linked gels (88 DCN SGE00616; 101 DCN SGE00705). This may be 

changing: industry has demonstrated the use of higher-TDS base fluid in 2013 to 2014 for gel 

fracturing as new chemical additives are becoming available for gel designs that tolerate higher 

TDS concentrations92 (98 DCN SGE00667; 101 DCN SGE00705).

PESA surveyed 205 UOG operators about their wastewater management practices in 

2012 (70 DCN SGE00575).

93 Table D-4 presents the survey results. Nationally, UOG operators 

reported reusing/recycling 23 percent of total produced water generated. The results also showed 

that most operators anticipate reusing/recycling higher percentages of their produced water in the 

two to three years following the survey. Other research firms that gather data on UOG extraction 

wastewater management report similar findings (103 DCN SGE00708; 104 DCN SGE00709). 

For example, IHS, Inc., estimates that in 2013 operators reused/recycled 16 percent of UOG 

produced water nationwide and expects this number to double by 2022 (103 DCN SGE00708). 

The EPA participated in several site visits and conference calls with operators in several 

formations that have been able to reuse/recycle 100 percent of their produced water under certain 

circumstances (95 DCN SGE00635; 21 DCN SGE00275; 92 DCN SGE00625; 96 DCN

SGE00636).

 92 One vendor reported that testing of new additives for gel designs that allow the use of high-TDS base fluid is 

underway. This vendor expected the cost for these chemicals to initially be high (101 DCN SGE00705).

93 Out of the 205 respondents, 143 represented operators active in major U.S. UOG plays. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

97

Table D-4. 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; BarnettWoodford Shale gas/oil 7 93 67

Williston Bakken Shale oil 5 95 56

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

Total sample (as reported by PESA) 23 77 55

Source: 70 DCN SGE00575

a—PESA (70 DCN SGE00575) reported this as “disposal” but did not clearly describe what it means.

b—PESA (70 DCN SGE00575) did not specify basin or formation for these areas. The EPA provided formation 

names that are present in these areas if not already previously listed above. 

3.1 Reuse/Recycle Strategies

Operators can reuse/recycle UOG extraction wastewater for fracturing through different 

strategies (174 DCN SGE01168). An operator’s choice of strategy depends on many factors, 

which Section D.3.2 describes in detail. The following subsections discuss direct reuse/recycle 

without treatment and reuse/recycle after treatment. 

3.1.1 Direct Reuse/Recycle for Fracturing Without Treatment

Many operators reuse/recycle their wastewater for fracturing without any treatment (i.e., 

only blending with fresh water) or with minimal treatment such as sedimentation or filtration to 

remove suspended solids. The primary purpose of the blending is to control TDS concentrations 

(88 DCN SGE00616; 99 DCN SGE00691). When using this strategy, operators either transport 

UOG extraction wastewater directly to the next well they are fracturing or transport it to a 

temporary storage area offsite until they are ready to fracture the next well. 

Reuse/recycle without treatment accounts for a large portion of all wastewater that 

industry reuses/recycles. In PESA’s 2012 survey (70 DCN SGE00575), UOG operators reported 

that 54 percent of produced water reused/recycled by the UOG industry in 2012 for fracturing 

requires minimal or no treatment. In addition, the EPA conducted several site visits and 

conference calls with operators that have increasingly reused/recycled wastewater with no 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

98 

treatment (95 DCN SGE00635; 21 DCN SGE00275; 92 DCN SGE00625; 96 DCN SGE00636; 

22 DCN SGE00276). 

3.1.2 Reuse/Recycle in Fracturing After Treatment

Operators also reuse/recycle UOG extraction wastewater after some type of treatment. 

Where treatment is employed, the UOG industry typically uses one of two levels of treatment: 

• Non-TDS removal technologies—technologies that remove non-dissolved94

constituents from wastewater, including suspended solids, oil and grease and bacteria,

or remove and/or exchange certain ions that can cause scale to form on equipment 

and interfere with fracturing chemical additives. These technologies are not designed 

to reduce the levels of dissolved constituents, which are the majority of compounds 

that contribute to 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 typically include non-TDS removal technologies for 

pretreatment (e.g., TSS, oil and grease). 

Each of these levels of treatment is described in more detail below. Also see the EPA’s 

report titled Unconventional Oil and Gas (UOG) Extraction Wastewater Treatment Technologies

(189 DCN SGE01186), which discusses treatment technologies used to treat UOG produced 

water. 

Non-TDS Removal Technologies 

As discussed in Section D.3, there are constituents in UOG extraction wastewater other 

than TDS that operators may need to remove or destabilize before reuse/recycle. In particular, 

they may need to reduce constituents that may cause scale, formation damage, and/or 

interference between chemical additives and the formation geology (189 DCN SGE01186). 

These constituents include suspended solids, oil and grease, bacteria, and certain ions (e.g., iron, 

calcium, magnesium, and barium). Non-TDS removal technologies used to treat UOG extraction 

wastewater for reuse/recycle include (86 DCN SGE00613; 5 DCN SGE00095):

• Solids removal (e.g., sedimentation, filtration, dissolved air flotation) 

• Chemical precipitation

• Electrocoagulation 

• Advanced oxidation precipitation 

• Disinfection

 

94 The EPA has categorized treatment technologies into two categories in this document: those that are designed to 

remove dissolved constituents and those that are not designed to remove dissolved constituents. However, it should 

be noted that some of the technologies in the non-TDS removal category do in fact remove some dissolved 

constituents. For example, chemical precipitation or ion exchange may be used to remove certain metals or 

compounds that can cause scaling. However, these technologies typically will not remove salts and hardness, which 

are the primary components of TDS in UOG extraction wastewater.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

99

Industry often uses non-TDS removal technologies to remove or destabilize the 

aforementioned constituents. This treatment may be done in the field at the well site or offsite at 

a CWT facility. One method used in the field to treat UOG extraction wastewater is referred to as

“on the fly” treatment, where the wastewater is treated as fluids are mixed for hydraulic 

fracturing. 

Figure D-8 shows a simplified flow diagram of on-the-fly treatment of UOG produced 

water for reuse/recycle. In this practice, the operator treats the mixture of UOG produced water

and other source water concurrently with the hydraulic fracturing process. Therefore, wastewater 

treatment occurs at relatively high flow rates equivalent to the rate of hydraulic fracturing.95

Other than the treatment unit, there is no additional equipment required in this setup that is not 

already required for hydraulic fracturing (e.g., additional storage typically required for treated 

wastewater). This eliminates or reduces the following (34 DCN SGE00331):96

• Transporting wastewater for reuse/recycle to a CWT facility and then transporting it 

again to the next well for fracturing

• Procuring the services of a CWT facility

• Purchasing or renting storage containers, and renting space on which to keep the 

storage containers, for treated wastewater

 95 Operators typically hydraulically fracture wells at rates of 2,520 to 5,040 gallons (60 to 120 barrels) per minute. 

On-the-fly treatment technologies must be capable of treating wastewater at the same rate (189 DCN SGE01186). 96 The most common technology for on-the-fly treatment is advanced oxidation. This technology eliminates the need 

to add biocide to the fracturing fluid to prevent bacteria growth.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

100 

Source: Generated by EPA using 34 SGE00331.

Figure D-8. Flow Diagram of On-the-Fly UOG Produced Water Treatment for 

Reuse/Recycle

TDS Removal Technologies 

In general, TDS removal technologies convert influent wastewater into two streams: 

concentrated brine and low-TDS water (i.e., distillate or permeate). As discussed in the 

introduction to Section D.3, operators have learned that low-TDS base fluid is not necessarily 

required for fracturing. However, some operators may still use TDS removal technologies to 

treat wastewater for reuse/recycle in fracturing. TDS removal technologies that UOG operators 

have used to treat UOG extraction wastewater for reuse/recycle include reverse osmosis (when 

TDS is less than approximately 50,000 mg/L) and evaporation/condensation and crystallization

(86 DCN SGE00613; 5 DCN SGE00095; 189 DCN SGE01186). Some vendors currently offer

skid-mounted mobile TDS removal units for reuse/recycle in the field (189 DCN SGE01186). 

The EPA also identified several CWT facilities that treat UOG extraction wastewater that use 

TDS removal technologies (e.g., evaporation/condensation) (26 DCN SGE00284). 

3.2 Reuse/Recycle Drivers

The reuse/recycle strategy operators choose depends on many different factors. The 

following subsections describe the two biggest drivers (105 DCN SGE00710):

• Pollutant concentrations in UOG extraction wastewater compared to maximum 

acceptable pollutant concentrations for base fluid (described in more detail in Section 

D.3.2.1) 

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
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

101 

• 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 (105 DCN

SGE00710). Operators are more likely to reuse/recycle UOG extraction wastewater with low 

TDS and high volumes to avoid TDS treatment and/or minimize freshwater usage. As explained 

in Section C.3.2.1 and shown in Figure C-6, TDS concentrations increase over time as the flow 

rate decreases after fracturing (105 DCN SGE00710, 44 DCN SGE00414, 38 DCN SGE00357, 

36 DCN SGE00350, 92 DCN SGE00625). Therefore, operators are more likely to reuse/recycle 

flowback than long-term produced water because concentrations of TDS in flowback, on 

average, are lower than concentrations in long-term produced water (see Section C.3.2.1) (105

DCN SGE00710). 

Some operators are able to reuse/recycle long-term produced water with no or minimal 

TDS treatment, as observed by the EPA in the Marcellus and Fayetteville shale formations (96

DCN SGE00636; 95 DCN SGE00635; 92 DCN SGE00625). However, this may not be possible 

in all UOG formations. As shown in Chapter C, the maximum concentration of TDS and the rate 

at which that concentration is reached are functions of the underlying geology. This means that, 

in some basins, the TDS concentrations for long-term produced water may be lower than the 

TDS concentrations for flowback in other basins. For example, in the Bakken formation, TDS 

concentrations in flowback increase rapidly to levels as high as 200,000 mg/L (within five days 

after fracturing), which may limit the volume of this wastewater capable of being used for 

reuse/recycle (36 DCN SGE00350).97 On the other hand, data indicates that long-term produced 

water in the Fayetteville shale formation has less than 40,000 mg/L TDS (92 DCN SGE00625).98 

If operators reuse/recycle UOG extraction wastewater that contains too much of certain 

constituents, the fracturing fluid, well, and/or formation may undergo one or more of the 

following problems (4 DCN SGE00070): 

• Fluid instability (change in fluid properties)

• Well plugging (restriction of flow) 

• Well bacteria growth (buildup of bacteria on casing) 

 

97 Data available to EPA indicates that only the initial five percent of the injected fracturing fluid volume that returns 

to the surface contains TDS less than 60,000 mg/L in the Bakken. This is based on sampling data for 62 wells.

98 This operator reported that it is able to reuse all of its UOG wastewater due to low TDS concentrations.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

102 

• Well scaling (accumulation of precipitated solids)

• Formation damage (restriction of flow in the reservoir)

Table D-5 shows ranges of observed or recommended constituent concentration criteria 

for the fracturing base fluid and the associated effect that the fluid or well may experience with 

concentrations in excess of the criteria. These ranges represent general values that industry 

reports, not values specific to one UOG formation. The exact criteria an operator uses depend on 

operator preference, geology, and the fracturing fluid chemistry (e.g., slickwater, gel), but the 

selected criteria typically fall within the ranges shown in Table D-5. 

Table D-5. Reported Reuse/Recycle Criteria

Constituent

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

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: 179 DCN SGE01179

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. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

103

Water Demand at the Well Level

The volume of fracturing fluid required per well for fracturing may also influence the 

level of treatment or blending ratio necessary to meet the base fluid pollutant criteria in Table 

D-5. The blending ratio is the volume of reused/recycled wastewater as a percent of the total 

base fluid volume used to fracture a specific well. The blending ratio depends on the wastewater 

pollutants and concentrations as well as on the volume of UOG extraction wastewater available 

and the total volume of base fluid required. Operators consider how much wastewater is 

generated by nearby wells with respect to how much fracturing fluid is required to fracture a 

subsequent well. In areas where produced water volume generation is high and/or the required

total base fluid volume for fracturing is low, operators may use a high blending ratio. As 

explained above, this high ratio may require more treatment depending on TDS and other 

constituent concentrations. On the other hand, in formations where produced water volume

generation is low and total base fluid fracturing volume is high, operators may use a low 

blending ratio. A low blending ratio can typically be used with little to no treatment (21 DCN 

SGE00275; 95 DCN SGE00635; 86 DCN SGE00613). Table D-6 shows observed blending 

ratios for various formations. This table also includes theoretical upper end blending ratios as 

presented in literature, based on the typical fracturing fluid volume and produced water volume 

generated per well99 for each formation (93 DCN SGE00627; 97 DCN SGE00639; 99 DCN

SGE00691).

Table D-6. Reported Reuse/Recycle Practices as a Percentage of Total Fracturing Volume

Basin 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: 179 DCN SGE01179

Note: Data years represented range from 2009 to 2013.

a— Actual observed volumes of reused/recycled UOG extraction wastewater as a percentage of fracturing fluid 

volume.

b— Estimated maximum blending ratio based on typical flowback volume per well compared to typical fracturing 

volume per well as presented in 93 DCN SGE00627; 97 DCN SGE00639; and 99 DCN SGE00691. 

c— References do not specify a specific formation.

 99 This theoretical value reported in literature is irrespective of constituent concentrations.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

104

“—” indicates no data.

Water Demand at the Formation Level

Although reuse/recycle has become popular as a way to manage UOG extraction 

wastewater, it is anticipated to become less attractive as a formation matures and the operator 

drills and fractures fewer wells (105 DCN SGE00710). As a formation matures, the volume of 

base fluid needed to fracture new wells may be less than the volume of produced water generated 

by producing wells in the area (92 DCN SGE00625). Figure D-9 illustrates this concept100 with a 

hypothetical situation for an operator in a single formation as reported by an operator (32 DCN

SGE00305.A03). During early years of development, the base fluid demand for fracturing wells 

always exceeds the volume of produced water generated. This provides favorable conditions for 

reuse/recycle. As drilling decreases, the volume of base fluid needed decreases below the volume 

of produced wastewater generated. Consequently, the operator must find an alternative to dispose 

of at least some portion of the produced water such as injection in disposal wells or transfer the 

wastewater to CWT facilities. 

Source: 179 DCN SGE01179 (Generated by the EPA based on figure in 32 DCN SGE00305.A03)

Figure D-9. Hypothetical UOG Produced Water Generation and Base Fracturing Fluid 

Demand over Time

 100 This concept assumes that operators do not typically share wastewater for reuse in fracturing. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

105 

3.3 Other Considerations for Reuse/Recycle

In addition to the level of treatment required for reuse/recycle, operators consider the 

following as they decide whether to reuse/recycle their wastewater:

• Wastewater transportation

• Wastewater storage

• Source water availability and cost 

3.3.1 Transportation 

Transportation requirements affect the wastewater reuse/recycle potential in a specific 

area. While not explicitly stated above, the location of the producing well(s) relative to the 

location of disposal well(s), CWT facilities, and/or a subsequent well(s) to be drilled is also a 

consideration. Operators must determine and compare the cost (dollars per barrel) to transport 

the wastewater for all management scenarios.

Further, when a UOG well generating wastewater is far from management approaches 

such as a disposal well or CWT facility, reuse/recycle may also be more economical. The 

distance between disposal wells and CWT facilities from the UOG well generating the 

wastewater can vary by formation and even within formations. For example, Figure D-10 shows 

how operators in the northeast region of the Marcellus reused/recycled a higher percentage of 

wastewater than in the southwestern region between 2008 and 2011 (71 DCN SGE00579). This 

is due to the fact that Marcellus wells in the southwestern part of Pennsylvania are closer to 

disposal wells in Ohio, whereas Marcellus wells in the northeast portion of Pennsylvania are 

more than 200 miles from disposal wells in Ohio. As a result, it is typically less expensive per 

barrel to reuse/recycle the wastewater in the northeast than to transport it to a disposal well in 

Ohio because transportation alone can cost as much as $13 per barrel (31 DCN SGE00300). 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

106 

Source: Graphic reprinted with permission from Brian Rahm (71 DCN SGE00579). 

Note: “a” and “b” for 2010 and 2011 represent the first and second half of the year, respectively.

Figure D-10. UOG Extraction Wastewater Management Practices Used in the Marcellus 

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

3.3.2 Storage 

Storage requirements and the number of wells the operator is drilling per unit time under 

its drilling program may also dictate when operators can reuse/recycle wastewater. In general, 

the effective storage cost to the operator increases the longer UOG extraction wastewater is 

stored before reuse in a subsequent well101 (21 DCN SGE00275). For example, an operator that

is considering reusing/recycling extraction wastewater for fracturing and fractures 12 wells per 

year in an area may need to store wastewater an average of one month between fracturing jobs. 

In comparison, an operator that fractures 50 wells per year in an area may only need to store 

wastewater an average of one week before being able to reuse/recycle it in the next fracturing job 

(25 DCN SGE00283). Section B.2 explains UOG extraction wastewater storage options in more 

detail. 

3.3.3 Source Water Availability

Operators that successfully reuse/recycle their wastewater can reduce the total volume of 

other types of source water they need to use for base fluids, creating an offset in costs associated 

 

101 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.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

107

with source water (5 DCN SGE00095). Fresh water from rivers and streams is relatively 

abundant and inexpensive in some areas, but in others it can be a stressed resource. Seasonal 

droughts can cause a high demand for resources and operators can experience inflated 

acquisition costs. Reuse/recycle is more likely to be driven by these reasons for operators in arid 

or drought-prone regions than for operators in regions where freshwater and groundwater 

resources are abundant and inexpensive (72 DCN SGE00583; 105 DCN SGE00710; 196 DCN

SGE01207). This is because as the cost of fresh water and groundwater increases, the offset in 

costs from reusing/recycling wastewater to replace other source water also increases.

102

Examples of such areas include California, the Denver Julesburg and Permian basins, and the 

Eagle Ford shale formation (105 DCN SGE00710). In addition, as mentioned above, a lack of 

disposal wells in some areas may be another driver behind wastewater reuse/recycle activity in 

some areas (e.g., Marcellus shale).

4 TRANSFER TO CWT FACILITIES

Some operators manage UOG extraction wastewater by transporting it to CWT facilities. 

Treated UOG extraction wastewater at CWT facilities is either discharged103 or returned to the 

operator for reuse/recycle in fracturing. Operators may choose to use CWT facilities primarily 

when other wastewater management options (e.g., disposal wells) are not available where they 

are operating (105 DCN SGE00710; 10 DCN SGE00139). 

This section provides a general overview of the types of CWT facilities that exist and that 

UOG operators may use for wastewater management, typical CWT facility treatment processes, 

CWT facilities that EPA is aware of that have in the past or currently accept UOG extraction 

wastewater, and considerations for using CWT facilities to manage UOG extraction wastewater. 

4.1 Types of CWT Facilities

A CWT facility is any facility that treats (for disposal, recycling, or recovery of material) 

any hazardous or nonhazardous industrial wastes, hazardous or non-hazardous industrial 

wastewater, and/or used material received from offsite (40 CFR 437.2(c)). CWT facilities that 

accept UOG extraction wastewater are sometimes run by the UOG operator and are sometimes 

run by an entity not engaged in the oil and gas extraction business. Since UOG development 

ramped up in the late 2000s, new CWT facilities that accept extraction wastewater from 

operators have become available (178 DCN SGE01178), mostly in areas with less underground 

injection capacity. In addition, many UOG operators have vertically integrated their companies 

by purchasing or constructing their own CWT facilities (see Section D.2.3) (178 DCN 

SGE01178). Some CWT facilities accept only oil and gas wastewater while others accept a 

variety of industrial wastewater. They follow different discharge practices:

• Zero discharge (treated wastewater is typically reused in fracturing or disposed of in a 

Class II disposal well)

• Discharge (to surface waters or POTWs)

 102 Transportation distances may also affect costs. 103 Discharge includes both indirect discharge (to a POTW) and direct discharge (to surface water).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

108

• Multiple discharge options (a mix of discharge and zero discharge)

Pollutant discharges to surface waters or to POTWs from CWT facilities may not be 

subject to the Oil and Gas Extraction ELGs (40 CFR part 435). Rather, they may be subject to 

the CWT ELGs promulgated in 40 CFR part 437. Unlike the Oil and Gas Extraction ELGs, 40 

CFR part 437 includes limitations and standards for both direct and indirect dischargers.

The level of treatment CWT facilities accepting UOG wastewaters use depends on factors 

such as the fate of the treated wastewater. The two primary types of treatment technologies are 

non-TDS removal technologies104 and TDS removal technologies,

105 defined in Section D.3. In 

general, CWT facilities typically accepting UOG wastewaters use non-TDS removal 

technologies for treatment before reuse/recycle. Direct and indirect discharging CWT facilities

accepting UOG wastewaters currently use a mix of TDS and non-TDS removal technologies.

106

4.1.1 Zero Discharge CWT Facilities

After treatment, a zero discharge CWT facility does not discharge the wastewater to 

surface water or a POTW. Instead, it typically returns the wastewater to UOG operators for 

reuse/recycle in fracturing.107 CWT facilities that accept UOG extraction wastewater from 

operators and fall into this category typically allow them to unload a truckload of wastewater for 

treatment and take a load of treated wastewater on a cost-per-barrel basis (18 DCN SGE00245).

Others may allow an operator to unload a truckload of wastewater for a surcharge without taking 

a load of treated wastewater, as long as other operators need additional treated wastewater. Most 

of these CWT facilities provide minimal (i.e., non-TDS removal) treatment, but some also use 

TDS-removal technologies.

4.1.2 Discharging CWT Facilities 

Some CWT facilities discharge treated wastewater either indirectly to a POTW or 

directly to surface waters. As discussed in Section A.2, discharges from the CWT facility to the 

POTW are controlled by an Industrial User Agreement that must incorporate the pretreatment 

standards set out in 40 CFR part 437 and requirements set out in 40 CFR part 403. Surface water 

discharges from CWT facilities are controlled by NDPES permits that include pollutant 

discharge limitations based on water-quality-based limitations and the technology-based 

limitations set out in 40 CFR part 437. The level of treatment typically depends on the 

requirements in the NPDES permit, which may or may not include restrictions on TDS. Directdischarging CWT facilities use a mixture of TDS and non-TDS removal technologies. However, 

 104 Examples of CWT facilities using this level of treatment are described in 92 DCN SGE00625; 95 DCN 

SGE00635, 18 DCN SGE00245, 47 DCN SGE00481, and 43 DCN SGE00379. 105 Examples of CWT facilities using this level of treatment are described in 45 DCN SGE00476, 39 DCN 

SGE00366, 40 DCN SGE00367, and 42 DCN SGE00374. 106 EPA is currently aware of several discharging CWT facilities accepting oil and gas wastes that, as of early 2016, 

do not utilize TDS removal technologies. See 178 DCN SGE01178 for a list of known CWT facilities accepting 

UOG wastewater and the discharge status and the level of treatment utilized at these facilities. 

107 Zero discharge CWT facilities may also evaporate the wastewater or send it to underground injection wells (42

DCN SGE00374).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

109

new state regulations in Pennsylvania, for example, have led direct-discharging CWT facilities to 

use more TDS removal technologies (178 DCN SGE01178).

4.1.3 CWT Facilities with Multiple Discharge Options

Some discharging108 CWT facilities may also recycle a portion of the treated wastewater. 

Consequently, these types of CWT facilities may employ both non-TDS and TDS removal 

technologies. One such facility is Eureka Resources in Williamsport, Pennsylvania. The Eureka 

CWT facility holds a General Permit (WMGR123NC005)

109 from PA DEP that includes

limits110 for TDS (500 mg/L), chloride (25 mg/L), and radium-226 + radium-228 (5 pCi/L), 

among others. The Eureka CWT facility uses a non-TDS removal technology (chemical 

treatment) followed by a TDS removal technology (evaporation/condensation) (31 DCN 

SGE00300). Operators may take a load of treated wastewater for reuse/recycle that the facility 

treated using the non-TDS removal technology train or using the entire treatment train (both nonTDS and TDS removal technologies). There are no NPDES permit limits that must be met for 

wastewater that is treated for reuse. The level of treatment is based on the operators’

specifications.

4.2 Active CWT Facilities Accepting UOG Extraction Wastewater

To date, the EPA has identified 74 CWT facilities that have accepted or plan to accept 

UOG extraction wastewater. Most of them accept only oil and gas wastewater, not wastewater 

from other industries. Table D-7 shows the total number of CWT facilities, by state, that have 

accepted or plan to accept UOG extraction wastewater. The table includes a breakdown by 

treatment level and facility discharge type (described in Section D.4.1). The majority of these 

facilities can treat between 87,000 and 1,200,000 gallons (2,100 and 29,000 barrels) per day (178

DCN SGE01178).111

To generate Table D-7, the EPA used information from state agencies (e.g., PA DEP 

statewide waste reports), CWT facility websites, and news articles. The collected information is 

documented in a separate memorandum titled Analysis of Centralized Waste Treatment (CWT) 

Facilities Accepting UOG Extraction Wastewater (178 DCN SGE01178), which lists known

CWT facilities along with information such as permit number, location, treatment capacity, and 

treatment level when available. Because few states keep comprehensive lists of CWT facilities, 

 108 Discharge includes both indirect discharge (to a POTW) and direct discharge (to surface water).

109 More information available online at: 

http://files.dep.state.pa.us/Waste/Bureau%20of%20Waste%20Management/WasteMgtPortalFiles/SolidWaste/Resid

ual_Waste/GP/WMGR123.pdf. 110 In addition to setting discharge limitations to the nearby POTW, Eureka’s General Permit allows it to treat 

wastewater for reuse purposes only, in which case there are no actual limits. 111 To exclude outliers, the EPA presents the 10th and 90th percentiles of reported treatment capacities at CWT 

facilities.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

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Table D-7 likely underestimates the number of CWT facilities accepting UOG extraction 

wastewater.

112

Table D-7. Number of CWT Facilities That Have Accepted or Plan to Accept UOG 

Extraction Wastewater, by State

State

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 22 7(3) 8 0 0 3 (1) 40

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 44 13 9 0 1 7 74

Sources: 178 DCN SGE01178

a—Information is current as of 2014; it is possible that since 2014 some listed CWT facilities have closed and/or 

new CWT facilities not listed have begun operation. Number of facilities includes facilities that have not yet opened 

but are under construction, pending permit approval, or are in the planning stages. Facilities that are not accepting 

UOG extraction wastewater but plan to in the future are noted parenthetically and not included in the sum of total 

known facilities.

This information shows that CWT facilities have developed in regions of increasing oil 

and gas production, especially in areas where capacities for other management practices are less 

available (10 DCN SGE00139). To illustrate this, the EPA analyzed the number of active CWT 

facilities available to Marcellus shale and Utica shale operators where there are few disposal 

wells in some parts of the region.

113 Figure D-4 illustrates how the eastern half of the 

Appalachian basin contains many CWT facilities and few disposal wells and the western half 

contains many disposal wells and few CWT facilities. Figure D-11 shows the trend over time of 

active CWT facilities available to operators in the Marcellus and Utica shales,114 along with the 

number of UOG wells drilled. The number of CWT facilities available to operators in the 

Marcellus and Utica shales has increased with the number of wells drilled. The EPA observed a 

similar trend in the Fayetteville shale formation in Arkansas. Although Arkansas has several 

 112The information in Table D-7 is current as of 2014; it is possible that since 2014 some listed CWT facilities have 

closed and/or some CWT facilities not listed have begun operation. 113 This analysis included Pennsylvania, West Virginia, and Ohio. 114 The Marcellus and Utica shale formations are in the Appalachian basin.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

111

hundred active disposal wells, only 24 wells are located in the northern half of the state in close 

proximity to Fayetteville shale wells (190 DCN SGE01187). As a result, the largest active 

operator in the Fayetteville shale has constructed three CWT facilities. The EPA anticipates that 

more CWT facilities will become available near UOG formations where access to disposal wells 

is limited as additional UOG wells are drilled.

Sources: 178 DCN SGE01178

Figure D-11. Number of Known Active CWT Facilities over Time in the Marcellus and 

Utica Shale Formations

5 DISCHARGE TO POTWS

In locations where disposal wells and CWT facilities are limited or transportation 

distances are a factor, operators have, in the past, managed UOG extraction wastewater by 

discharge to POTWs. This practice can be problematic because POTWs do not use technologies 

that can remove some UOG extraction wastewater constituents (e.g., TDS). Also, constituents in 

UOG extraction wastewater such as TDS may interfere with POTW operations and may increase 

pollutant loads in receiving streams to the detriment of receiving water quality and biota and 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

112

affect downstream water use (27 DCN SGE00286; 35 DCN SGE00345; 71 DCN SGE00579; 59

DCN SGE00531; 94 DCN SGE00633; 162 DCN SGE01077).115

This section provides an overview of typical treatment processes used at POTWs, a 

discussion of how constituents commonly found in UOG extraction wastewater interact with 

POTWs (including examples of POTWs that have been used to manage UOG extraction 

wastewater), a review of POTWs that have accepted UOG extraction wastewater, and the current 

status of UOG extraction wastewater discharges to POTWs.

5.1 POTW Background and Treatment Levels

40 CFR 403.3(q) defines a POTW as “a treatment works as defined by section 212 of the 

[Clean Water] Act,

116 which is owned by a State or municipality.” POTWs are designed to treat 

residential, commercial, and industrial wastewater, focusing on the removal of suspended solids 

and dissolved organic constituents. Table D-8 presents concentrations of weak, moderate, and 

strong domestic wastewater as would be typically experienced by a POTW (i.e., influent).

Table D-8. Typical Composition of Untreated Domestic Wastewater

Constituent

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: 12 DCN SGE00167

Abbreviation: mg/L—milligrams per liter

Typical treatment processes used at POTWs are categorized into the following levels:

 115 GWPC, 2014 (162 DCN 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.”

116 Section 212 of the CWA defines the term “treatment works” as “any devices and systems used in the storage, 

treatment, recycling, and reclamation of municipal sewage or industrial wastes of a liquid nature.”
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

113

• Primary treatment, capable of removing some suspended solids and organic matter 

from influent wastewater using unit operations such as screening and clarification. 

• Secondary treatment, capable of removing additional suspended solids and 

biodegradable organic matter from influent wastewater using biological treatment 

processes, such as activated sludge and trickling filters. Secondary treatment is 

sometimes followed by chlorination or ultraviolet (UV) disinfection to reduce 

microbial pathogens. 

• Tertiary (advanced) treatment, capable of removing other pollutants, such as 

nutrients, not removed in secondary treatment using processes such as 

nitrification/denitrification and activated carbon adsorption (12 DCN SGE00167).

Figure D-12 shows a typical process flow diagram for a POTW. The processes shown 

include primary treatment (screen, grit chamber, primary clarifier), secondary treatment 

(trickling filter, aeration, secondary clarifier), and disinfection (chlorine). The diagram also 

shows sludge treatment (gravity thickening, digestion, filter press) before use/disposal (e.g., land 

application).

Source: 80 DCN SGE00602

Figure D-12. Typical Process Flow Diagram at a POTW

In general, the average POTW in the United States has primary and secondary treatment. 

In addition to treated wastewater, POTW treatment processes produce residual solids (sludge), 

including biosolids generated during biological treatment and other suspended material removed 

in clarifiers. Most POTWs apply additional treatment to the sludge, typically gravity thickening 

followed by stabilization (e.g., anaerobic digestion) and dewatering (e.g., filter press). After this 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

114

additional treatment, most sludge is either put to a beneficial use (e.g., land application, soil 

enrichment) or disposed of in a landfill or incinerator (78 DCN SGE00599). 

Table D-9 shows typical removal percentages for various constituents. As discussed, 

removal rates for suspended solids are high (90 percent for TSS) and removal rates for metals 

and salts are low (6 percent for cobalt, 8 percent for TDS).

Table D-9. 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: 79 DCN SGE00600

Note: 79 DCN SGE00600 references data from the November 5, 1999, updated 50-POTW study and the RREL 

database compiled for the CWT effluent guidelines.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

115 

Table D-10 shows the breakdown of U.S. POTWs categorized according to their level of 

treatment. As of 2008, secondary treatment was the most common level of treatment at POTWs.

Table D-10. U.S. POTWs by Treatment Level in 2012 

Treatment Level

Percent of 

Facilities (%)a

Number of 

Facilitiesa

Combined Design 

Capacity (MGD)a

Less than secondary (e.g., primary) 0.2 34 546

Secondary 50.0 7,374 17,765

Greater than secondary (e.g., tertiary, advanced) 34.1 5,036 23,710

No discharge 15.5 2,281 2,557

Partial treatmentb 0.2 23 287

Total 100.0 14,748 44,866

Sources: 81 DCN SGE00603; 216 DCN SGE01332

a—The percent of facilities and number of facilities were taken from the 2012 Clean Watersheds Needs Survey 

(CWNS) (published in 2016, containing 2012 data), but the 2012 CWNS did not report design capacities, so they 

were taken from the 2008 CWNS.

b—These facilities provide some treatment to wastewater and discharge their effluent to other wastewater facilities 

for further treatment and discharge. 

Abbreviation: 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 (27 DCN SGE00286; 35 DCN 

SGE00345; 71 DCN SGE00579).117 The EPA located the most comprehensive data about this 

practice in Pennsylvania. Therefore, this subsection primarily discusses data from PA DEP, 

though it also includes discussions about a few POTWs in West Virginia and New York. The PA 

DEP data indicate that the majority of UOG operators in Pennsylvania who decided to discharge 

to POTWs did so by 2008118 (203 DCN SGE01245). To identify POTWs that accepted 

wastewater from UOG operations,119 the EPA reviewed the following sources: 

• Notes from calls with regional and state pretreatment program coordinators (113

DCN SGE00742, 114 DCN SGE00743) 

• Notes from an EPA-state implementation pilot project with the Environmental 

Council of the States in coordination with the Association of Clean Water 

Administrators (128 DCN SGE00762) 

• EPA Region 3’s website (41 DCN SGE00368) 

 

117 EPA acknowledges that COG operators are still using POTWs as a viable option for disposal of COG

wastewater.

118 EPA did not identify any information indicating when POTWs in New York began accepting of UOG extraction 

wastewater. EPA also could not definitely determine when UOG operators in Pennsylvania began discharging UOG 

extraction wastewater at POTWs because the 2007 PA DEP Waste Report data are incomplete.

119 EPA could not determine the date when POTWs began accepting UOG wastewater in all instances. The EPA has 

documentation that all POTWs in Pennsylvania stopped accepting UOG extraction wastewater by the end of 2011.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

116

• Site visits, conference calls, and meetings with industry representatives (86 DCN 

SGE00613; 54 DCN SGE00521), UOG operators (92 DCN SGE00625; 95 DCN 

SGE00635; 21 DCN SGE00275; 24 DCN SGE00280), CWT facilities (30 DCN 

SGE00299; 31 DCN SGE00300; 18 DCN SGE00245; 17 DCN SGE00244), and 

Native American tribal groups (138 DCN SGE00785)

• PA DEP’s statewide waste report data120 (203 DCN SGE01245; 184 DCN 

SGE01182)

• The U.S. DOE’s 2010 Water Management Technologies Used by Marcellus Shale 

Gas Producers report (2 DCN SGE00011) 

• Publicly available data sources identified through Internet searches

The EPA compiled and analyzed much of these existing data in a separate document, Publicly 

Owned Treatment Works (POTW) Memorandum for the Technical Development Document 

(TDD) (185 DCN SGE01183). This memorandum is referenced throughout Section D.5.

The EPA identified POTWs that, at one time, accepted wastewater from UOG operators 

generated by Marcellus shale wells. Table D-11 presents information about POTWs that have 

accepted UOG extraction wastewater directly from onshore UOG operators.

 120 PA DEP’s waste report data provide wastewater volumes by well over time and management/disposal 

information as it was reported by the oil and gas well operator to PA DEP. ERG’s memorandum titled Analysis of 

Pennsylvania Department of Environmental Protection’s (PA DEP) Oil and Gas Waste Reports provides more 

detail (184 DCN SGE01182).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

117

Table D-11. POTWs That Accepted UOG Extraction Wastewater Directly 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: 185 DCN SGE01183
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

118

Based on data collected through January 2016, the EPA concluded that none of the 

POTWs listed in Table D-11 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.0). PA DEP data indicate that UOG operators in Pennsylvania stopped sending their waste to 

POTWs in 2011 (203 DCN SGE01245). Furthermore, the EPA has not been able to identify any 

POTW in any state that is currently accepting UOG extraction wastewater directly from an

operator. In addition, the EPA collected data about UOG operations on tribal reservations, UOG 

operators that are affiliated with Indian tribes, and POTWs owned or operated by tribes that may 

accept industrial wastewater (138 DCN SGE00785). According to this information, there are no 

tribes currently operating UOG wells that discharge wastewater to POTWs, nor are there any 

tribes that own or operate POTWs that accept UOG extraction wastewater. EPA solicited 

additional data and information on current industry practice as well as its preliminary finding that 

no UOG facilities currently discharge to POTWs in the proposal. EPA did not receive data since 

proposal to contradict this finding.

The EPA is aware of a few cases where UOG operators discharge wastewater to CWT 

facilities for treatment and those CWT facilities discharge to POTWs. As explained in Section 

A.2.3, such discharges may not be subject to the ELGs for the oil and gas extraction category

which is the subject of the rule. Rather, discharges to POTWs from CWT facilities accepting 

UOG wastewaters may be subject to ELGs for the Centralized Waste Treatment Category (40 

CFR part 437).

The EPA reviewed PA DEP statewide waste reports (184 DCN SGE01182) and 

discharge monitoring report (DMR) data (83 DCN SGE00608) to identify the total volumes of 

UOG extraction wastewater and average total influent wastewater for each POTW. Using these 

data sources, the EPA calculated the maximum annual average daily121 percentage of UOG 

extraction wastewater accepted by the POTW as shown in Table D-12. The EPA found that 

discharges of UOG extraction wastewater from UOG operators to POTWs peaked in 2008 and 

the last known discharge was in 2011.

Table D-12 also presents the year in which the highest average daily flow occurred and 

the corresponding UOG extraction wastewater volume being accepted by the POTW during that

year. The contribution of UOG extraction wastewater out of the total volume of wastewater 

treated at the POTW is typically a small percentage (less than 1 percent). However, based on the 

data presented in Table D-12, the contribution of UOG extraction wastewater was much higher 

(e.g., up to 21 percent) for some POTWs for some years.

 121 PA DEP waste reports provided the total volume of UOG extraction wastewater delivered to the POTW each 

year. The EPA divided the annual volume by 365 to calculate the annual average daily flow of UOG extraction 

wastewater accepted at the POTW. Therefore, it is possible that UOG extraction wastewater was discharged to the 

POTWs intermittently such that actual peak daily flow of UOG extraction wastewater to the POTWs in Table D-12

was higher than the daily average.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

119

Table D-12. 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

Flow (god)

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 

Average Daily 

UOG Extraction

Wastewater 

Flow

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

City of Auburn NY0021903 1,800 0.20 0.91 2008

Brownsville Municipal 

Authority PA0022306 9,400 0.88 1.1 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 6,300 0.97 0.65 2010

Clairton Municipal 

Authority PA0026824 12,000 4.15 0.30 2009

Moshannon Valley 

Authority STP PA0037966 3,400 2.29 0.15 2008

Dravosburg PA0028401 1,300 0.33 0.39 2008

City of McKeesport PA0026913 11,000 16.25 0.07 2009

Reynoldsville Sewer 

Authority PA0028207 1,280 0.80 0.16 2010

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

Source: 185 DCN SGE01183

a—This is the total influent wastewater flow to the POTW (domestic sewage and UOG extraction wastewater) in 

the year associated with the maximum UOG extraction wastewater volume received by the POTW.

b—The average total flow through the POTW (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

120 

5.3 How UOG Extraction Wastewater Constituents Interact with POTWs

POTWs are likely effective in treating only some of the pollutants in UOG extraction 

wastewater. Most POTWs are designed to primarily treat domestic wastewater. They typically 

provide at least secondary-level treatment and, thus, are designed to remove suspended solids 

and organic material. However, secondary treatment technologies are not designed to remove the 

TDS, radioactive constituents, metals, chlorides, sulfates, and other dissolved inorganic 

constituents found in UOG extraction wastewater.

122 In addition, the performance of the 

treatment technologies utilized at POTWs can be adversely affected by high concentrations of 

constituents found in UOG extraction wastewaters. Because they are not typical of POTW 

influent wastewater, UOG extraction wastewater constituents:

• May be discharged, untreated, from the POTW to the receiving stream

• May disrupt the operation of the POTW (which may lead to exceeding permit limits 

for BOD5 or TSS in discharges or inhibiting sludge settling, for example) 

• 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)123 issued to a 

number of POTWs by PA DEP

• Pass through analyses completed by POTWs 

• DMR data from times when POTWs accepted UOG extraction wastewater

In many cases, POTWs that accepted UOG extraction wastewater also accepted COG 

extraction wastewater. Because the UOG extraction wastewater constituents that are discussed in 

this chapter are also present in COG extraction wastewater (209 DCN SGE01260; 146 DCN 

SGE00966), information and studies on the treatability of these constituents by POTWs (or their 

impacts on POTWs) are similarly relevant when those POTWs are accepting only COG 

extraction wastewater and/or a combination of COG and UOG extraction wastewater. In most of 

the case studies presented in this chapter, the POTWs that were accepting UOG extraction 

wastewater were also accepting COG wastewater.

 

122 Some POTWs provide tertiary treatment, which removes additional nutrients as well as constituents targeted for 

removal using secondary treatment. Similar to secondary treatment, tertiary treatment processes are not designed to 

remove TDS, radioactive constituents, metals, chlorides, sulfates, and other dissolved inorganic constituents found 

in UOG extraction wastewater and their performance may be adversely affected by the high concentrations of these 

pollutants. 123 PA DEP issued AOs to many POTWs in Pennsylvania that were accepting or suspected to begin accepting 

wastewater from UOG operations. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

121

The EPA also reviewed common textbooks on wastewater treatment technology 

effectiveness. These textbooks indicated that POTWs would likely be ineffective for treatment of 

certain pollutants in UOG extraction wastewater, such as TDS and many pollutants that 

contribute to TDS (79 DCN SGE00600). The EPA used all of this information to evaluate 

treatment effectiveness at POTWs, primarily for TDS.

In addition to information about POTWs accepting oil and gas extraction wastewater, the 

EPA collected available information about other discharges to POTWs from industrial sources 

containing pollutants found in UOG extraction wastewater. The case studies presented in

Sections D.5.3.1.2 and D.5.3.2.2 involve discharges to POTWs from CWT facilities that 

accepted oil and gas extraction wastewater. To the extent that a CWT facility discharges to a 

POTW and also lacks technologies that remove some oil and gas extraction pollutants (e.g.,

TDS), information on resulting POTW effluent concentrations (and/or inhibition) can be used as 

a proxy for UOG extraction operator discharges to a POTW.

Table D-13 summarizes the POTW studies and analyses that are presented in Section 

D.5.3.1 and Section D.5.3.2. Section D.5.3.1 discusses the potential for UOG pollutants to be 

discharged, untreated, from POTWs. Section D.5.3.2 discusses the potential for UOG wastewater 

pollutants to cause or contribute to inhibition and disruption at POTWs. 

Table D-13. Summary of Studies About POTWs Receiving Oil and Gas Extraction 

Wastewater Pollutants

POTW Summary of Study Findings

POTWs Accepting Wastewater from Oil and Gas Operators

Clairton, PA, POTW 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.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

122

Table D-13. Summary of Studies About POTWs Receiving Oil and Gas Extraction 

Wastewater Pollutants

POTW Summary of Study Findings

Waynesburg, PA, POTW High-salinity UOG produced water impacted biological growth in trickling filter. See 

Section D.5.3.2.1.

POTWs Accepting Wastewater Containing UOG Extraction Wastewater Pollutants

from Other Industrial Sources (e.g., CWT Facilities)

Franklin, PA, POTW

The Franklin POTW received industrial discharges from the Tri-County CWT facility 

(which received oil and gas extraction wastewater). The CWT facility targeted 

removal of TSS and oil and grease by filtration, flocculation, and skimming.

TDS and chloride concentrations in effluent from the POTW were higher when the 

POTW was accepting industrial wastewater from the Tri-County CWT facility and 

decreased after it stopped accepting wastewater from this CWT facility. See Section 

D.5.3.1.2.

Wheeling, WV, POTW

The Wheeling POTW received oil and gas extraction wastewater from operators as 

well as industrial wastewater discharges from the Liquid Asset Disposal (LAD) CWT 

facility. The LAD CWT facility uses ultra-filtration, ozonation, and reverse osmosis to 

target the removal of chlorides prior to discharge to the Wheeling POTW.

The POTW experienced higher concentrations of chloride in POTW effluent while 

accepting UOG extraction wastewater from UOG operators and from the LAD CWT 

facility (which receives oil and gas extraction wastewater). See 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) and chemical precipitation to target the removal of suspended 

solids and metals from UOG extraction wastewater before discharge to the Warren 

POTW.

Influent and effluent TDS and chloride concentrations at the Warren POTW show 

minimal or no TDS or chloride removals. See 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.124

The POTW experienced higher concentrations of TDS in POTW effluent while 

accepting industrial discharges from the CWT facility containing oil and gas 

extraction wastewater pollutants. See 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.

 124 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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Table D-13. Summary of Studies About POTWs Receiving Oil and Gas Extraction 

Wastewater Pollutants

POTW Summary of Study Findings

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. 

5.3.1 UOG Extraction Wastewater Constituents Discharged Untreated from POTWs

As described in Section D.5.3, the EPA reviewed studies and analyses relevant to 

POTWs accepting wastewater containing pollutants found in UOG extraction wastewater. 

Consistent with wastewater treatment literature, the POTWs described in these studies 

demonstrated that some UOG extraction wastewater pollutants are not removed by POTWs and 

are discharged untreated to receiving streams. 

5.3.1.1 Case Studies of POTWs Accepting Oil and Gas Extraction Wastewater 

Clairton, PA, POTW

The Clairton POTW discharges to Peters Creek, which flows into the Monongahela River 

and treats influent wastewater using screening and grit removal, comminutors (i.e., grinders),125

aeration basins, clarifiers, activated sludge, aerobic digestion, and chlorine disinfection. The 

Clairton POTW is permitted to treat a maximum of 6 MGD (126 DCN SGE00758).

On October 23, 2008, PA DEP issued an AO to the Clairton POTW that established

requirements for its acceptance of oil and gas wastewater. The AO required the Clairton POTW 

to restrict the volume of oil and gas wastewater it accepts to a flow rate no greater than 1 percent

of the average daily flow. The AO also required the POTW to evaluate the potential impacts of 

oil and gas production wastewater on its treatment processes. The technical evaluation noted 

(126 DCN SGE00758): 

The results of the samples taken and analyzed through the CMA [Clairton 

Municipal Authority] WWTP indicate that there is little to no reduction in 

concentration of TDS and chlorides through the plant processes. This is not 

unexpected as conventional sewage treatment facilities are not designed to 

remove dissolved constituents such as TDS and chlorides. 

Figure D-13 shows the results from the 24-hour composite sampling that occurred over 

five days in December 2008. According to PA DEP data (184 DCN SGE01182), in 2008, the 

Clairton POTW was accepting oil and gas wastewater amounting to an average of 0.05 percent 

 

125 A comminutor is a machine that reduces the particle size of wastewater solids using a cutting device.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

124

of the POTW flow. Looking at the average measured concentrations, the results indicate little or 

no removal of TDS or chloride.

Source: 185 DCN SGE01183

Note: The data presented in this figure are based on five 24-hour composite samples taken from December 

8, 2008, through December 12, 2008.

Figure D-13. Clairton POTW: Technical Evaluation of Treatment Processes’ Ability to 

Remove Chlorides and TDS

Clairton POTW’s consultant completed a pass through analysis in August 2009 (117

DCN SGE00748). Having collected two sets of influent concentration data from two different oil 

and gas wells, the consultant stated that the O&G Well No. 2 wastewater “was not characteristic 

of the oil and gas wastewater routinely accepted by the CMA POTW.” Therefore, the EPA only 

included the wastewater characteristic data for O&G Well No. 1, as reported in the pass through 

analysis (see Table D-14). The pass through analysis assumes zero percent removal of TDS at 

the POTW and concludes that (117 DCN SGE00748):

The result of the mass balance analyses clearly indicates that TDS is untreated 

resulting in a “pass-through” to receiving waters...The hypothetical mass 

balance review...indicates that if higher concentrations of TDS are introduced 

into the POTW, the concentration and loading of TDS to the receiving waters 

increases proportionally.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

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Table D-14. 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: 117 DCN SGE00748

Abbreviation: mg/L—milligrams per liter

McKeesport, PA, POTW

The McKeesport POTW discharges to the Monongahela River and treats wastewater 

using screening and grit removal, aeration, clarification, activated sludge, aerobic digestion, and 

chlorine disinfection (115 DCN SGE00745). The McKeesport POTW began accepting COG 

wastewater in 2008 and UOG extraction wastewater in 2009. The POTW stopped accepting both 

COG and UOG extraction wastewater in December 2011 (184 DCN SGE01182).

On October 23, 2008, PA DEP issued an AO to the McKeesport POTW that allowed it to 

accept oil and gas wastewater in amounts no greater than 1 percent of its average daily flow, 

among other requirements. The AO also required the POTW to evaluate the potential impacts of 

oil and gas production wastewater on its treatment processes. The POTW conducted this 

technical evaluation in November 2008. According to PA DEP data (184 DCN SGE01182), in 

2008, the McKeesport POTW was accepting only COG wastewater. The evaluation (125 DCN

SGE00757) noted:

The results of the samples taken and analyzed through the MACM [Municipal 

Authority of the City of McKeesport] WWTP indicate that there is no reduction in 

concentration of TDS and chlorides through the plant processes. This is not 

unexpected as conventional sewage treatment facilities are not designed to 

remove dissolved constituents such as TDS and chlorides.

Figure D-14 shows the results from 24-hour composite sampling over seven days in 

November 2008. The results indicate no removal of TDS or chloride. According to the manifests 

included in the technical evaluation (125 DCN SGE00757), McKeesport treated trucked 

wastewater from conventional wells during the seven-day sampling period. These wastewater 

sources are summarized in Table D-15, below.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

126

Source: 185 DCN SGE01183

Note: The data presented in this figure are based on seven 24-hour composite samples taken from 

November 1, 2008, through November 7, 2008.

Figure D-14. McKeesport POTW: Technical Evaluation of Treatment Processes’ Ability to 

Remove Chlorides and TDS

Table D-15. Trucked COG Extraction Wastewater Treated at McKeesport POTW from 

November 1 Through 7, 2008

Date Waste Typea Volume (gallons) Chlorides (mg/L) Chlorides (lbs)

November 3, 2008 Brine 3,780 155,000 4,886

November 4, 2008 Flowback 3,780 145,000 4,571

November 6, 2008 Flowback 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: 115 DCN SGE00745

a—According to data from the technical evaluation, some waste streams were referred to as “frac” and “flowback,” 

indicating that the conventional wells were hydraulically fractured.

Abbreviations: mg/L—milligrams per liter; lbs—pounds

McKeesport POTW’s consultant completed a headworks loading analysis in March 2011 

(115 DCN SGE00745). As part of the analysis, the consultant completed monthly sampling of 

the influent and effluent of the POTW from February 2010 through January 2011 and determined 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

127

the average removal percentages based on the sampling results. During the time of sampling, a 

combination of UOG and COG wastewater contributed no more than 1 percent of the average 

daily flow and municipal wastewater made up the remaining influent to the McKeesport POTW. 

Table D-16 presents the percent removals calculated during this analysis and shows that the 

POTW removed less than 7 percent of the influent TDS and less than 5 percent of the influent 

chloride. Effluent TDS concentrations ranged from 600 to 1,500 mg/L while the facility accepted 

both UOG and COG wastewater during the sampling period (115 DCN SGE00745).

Table D-16. McKeesport POTW Removal Rates Calculated for Local Limits Analysis

Parameter Removal Rates (%)

Sulfate 3.94

Chloride 4.44

TDS 6.43

Magnesium 6.62

Strontium 18.47

Bromide 26.99

Barium 71.64

Source: 115 DCN SGE00745

Note: The data presented in this table are based on timed composite samples obtained once a month for 12 months 

from February 2010 through January 2011. 

A 2013 study by Ferrar et al. (56 DCN SGE00525) analyzed constituents in effluent 

wastewater discharged from two POTWs in Pennsylvania, first while the POTWs accepted 

industrial discharges containing UOG extraction wastewater pollutants (either from a CWT 

facility or from a UOG operator) and again after the POTWs stopped accepting those industrial 

discharges. The study included effluent sampling at the McKeesport POTW in 2010 while the 

POTW was accepting UOG extraction wastewater. The study specifically reported that the 

facility was accepting UOG extraction wastewater during the sampling but did not mention COG 

wastewater. Based on PA DEP data, the EPA is aware that the POTW accepted both UOG and 

COG wastewater in 2010; however, details were not available concerning whether COG 

wastewater was accepted on the specific days of the sampling. The UOG extraction wastewater, 

received from operators via tanker trucks, was stored in holding tanks, then mixed with 

municipal wastewater in the primary clarifier. The study sampled POTW effluent in October 

2010, when the POTW was accepting UOG extraction wastewater and again in December 2011, 

after the POTW had stopped accepting COG and UOG extraction wastewater.

126 The study also 

collected one sample in November 2010 of UOG extraction wastewater before it was mixed with 

the municipal influent127 (see Table D-17). 

 126 The PA DEP waste reports data (183 DCN SGE01182) show that the McKeesport POTW stopped accepted COG 

and UOG wastewater after 2011.

127 Note that the one-time sample of influent UOG extraction wastewater was not collected at the same time as either 

of the effluent sampling events.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

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On October 19, 2010, when Ferrar et al. collected their POTW effluent sample, they 

reported that the McKeesport POTW treated 13,020 gallons of UOG extraction wastewater, and 

the average daily flow of the POTW was 9.6 MGD, indicating that the UOG extraction 

wastewater accounted for 0.14 percent of the total influent.

128 The remaining influent wastewater 

consisted of municipal wastewater typically treated by the POTW (see Table D-8 for typical 

constituent concentrations in municipal wastewater). 

Table D-18 shows the range and mean effluent concentrations, as measured by Ferrar et 

al., at the McKeesport POTW while they were accepting UOG extraction wastewater and after 

they had stopped accepting UOG extraction wastewater. As noted above, the study reported that 

the McKeesport POTW accepted an average daily flow of 9.6 MGD during the October 2010 

sampling event. However, they did not report the average daily flow during the December 2011 

sampling event. Although they reported that the facility was accepting UOG extraction 

wastewater on the first effluent sampling date (October 19, 2010), sampling data for that influent 

UOG extraction wastewater (like the data presented in Table D-17) were not available. 

Therefore, it is not possible to know whether the data presented in Table D-17 are representative 

of the UOG extraction wastewater influent on the date of the effluent sampling presented in 

Table D-18. As discussed in Section C.3, UOG extraction wastewater characteristics vary over 

time and from well to well.

Table D-17. Constituent Concentrations in UOG Extraction Wastewater Treated at the 

McKeesport POTW Before Mixing with Other Influent Wastewater 

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: 56 DCN SGE00525

a—Organic analytes were not detected in samples.

b—Sample date: 11/10/2010. Reported values are based on only one sample taken for each analyte. Samples were 

collected from a UOG extraction wastewater holding tank before mixture and dilution with influent municipal 

wastewater.

Abbreviation: mg/L—milligrams per liter

 128 Ferrar et al. (56 DCN SGE00525) noted that since the total volume of UOG wastewater was released at one time, 

the actual dilution might have been 0.81 percent UOG wastewater in the effluent when it was discharged (8–12 

hours later).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

129

Table D-18. 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: 56 DCN SGE00525

a—Organic analytes were not detected in samples.

b—Sample date: 10/19/2010. Reported values are based on the mean, minimum, and maximum of 24 samples taken 

for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.

c—Sample date: 12/1/2011. Reported values are based on the mean, minimum, and maximum of nine samples taken 

for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.

d—The effluent concentrations of calcium and magnesium increased after the POTW had stopped accepting UOG 

extraction wastewater. Ferrar et al. (56 DCN SGE00525) suggest that the increased concentrations of these ions may 

be from high influent calcium and magnesium concentrations in other wastewater treated by the McKeesport POTW 

(e.g., COG wastewater).

Abbreviation: mg/L—milligrams per liter

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 2014.

129 The 

total oil and gas wastewater volume accounted for less than 2 percent of the total POTW influent 

volume during 2009 through 2011 on average (184 DCN SGE01182). The POTW’s total annual 

average daily flow rate ranges between 0.8 and 1.5 MGD, based on 2008 to 2014 DMR data (83

DCN SGE00608).

The EPA created Figure D-15 using the sampling data submitted in the EPA’s DMR 

Loading Tool (83 DCN SGE00608) and PA DEP waste reports data (184 DCN SGE01182). 

 129 Ridgway’s October 2011 NPDES permit (123 DCN SGE00755) notes that “no more than 20,000 gallons/day of 

natural gas wastewater from shallow well operations shall be treated at the facility. The acceptance of wastewater 

generated from shale oil extraction activities is prohibited.”
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

130

Each effluent concentration data point represents the average of 12 monthly average data points 

as calculated and reported by the DMR Loading Tool. PA DEP waste reports provided the total 

volume of UOG and COG wastewater delivered to the POTW each year. The EPA divided the 

annual volume by 365 to calculate the annual average daily flow. As shown in Figure D-15, in 

2010, the Ridgway POTW experienced effluent TDS concentrations greater than 6,000 mg/L on 

average and effluent chloride concentrations greater than 2,500 mg/L on average while it was 

accepting the greatest volume of oil and gas wastewater, including that from UOG operators. As 

a point of comparison, in 2008, before accepting any oil and gas wastewater, the POTW 

experienced effluent TDS and chloride concentrations around 1,000 mg/L. 

Source: 185 DCN SGE01183

Note: The annual average extraction wastewater flows for COG and UOG are presented as stacked bars in order to 

represent the total annual average oil and gas extraction wastewater influent flow.

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

Flows

To comply with the requirements of the Ridgway Borough Pretreatment Program, the 

Ridgway POTW completed a local limits analysis in January 2014 that included paired POTW 

influent and effluent data. The samples were collected for 10 consecutive days in October and 

November 2013 after the POTW stopped accepting UOG extraction wastewater but was still 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

131

accepting COG wastewater. Of particular interest is the fact that Ridgway POTW’s contractor

estimated zero percent removals for TDS, chloride, and sulfate. All three of these constituents 

are found in UOG extraction wastewater (124 DCN SGE00756).

Charleroi, PA, POTW

The Charleroi POTW uses an equalization tank, screening and grit removal, 

sedimentation, activated sludge, and chlorine disinfection. It began accepting both COG and 

UOG extraction wastewater in January 2005 and stopped accepting it in 2008 (120 DCN 

SGE00751; 184 DCN SGE01182). The total oil and gas wastewater accounted for up to 32 

percent of the total POTW influent volume during 2008, on average. UOG extraction wastewater 

accounted for 10 percent of total POTW influent during 2008 on average (184 DCN SGE01182). 

The POTW’s average annual flow rate ranges between 1.4 and 1.9 MGD based on 2008 through 

2014 DMR data (83 DCN SGE00608). The EPA identified case studies showing potential for 

both pass-through (Section D.5.3.1.1) and inhibition/disruption (Section D.5.3.2.1) at the

Charleroi POTW.

In 2008, PA DEP issued an AO requiring the Charleroi POTW to evaluate how accepting 

oil and gas production wastewater affects its treatment processes, among other things (120 DCN 

SGE00751). Charleroi’s technical evaluation noted that the POTW typically rejects influent oil 

and gas wastewater with TDS concentrations greater than 30,000 mg/L or chloride 

concentrations greater than 15,000 mg/L. As part of the technical evaluation, Charleroi sampled 

influent wastewater (including UOG extraction wastewater) and effluent wastewater over a 24-

hour period. The total oil and gas wastewater treated during this period was 150,650 gallons

(3,587 barrels) and the total wastewater treated was 1,559,000 gallons (37,120 barrels). 

Therefore, the oil and gas wastewater accounted for 9.7 percent of the total influent to the plant 

during the sampling period (120 DCN SGE00751). Table D-19 shows the results of the sampling 

and the calculated removal rates. The data show that TDS is not removed by the Charleroi 

POTW treatment processes.

Table D-19. Charleroi POTW Paired Influent/Effluent Data and Calculated Removal Rates

Parameter

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: 120 DCN SGE00751

Abbreviation: mg/L—milligrams per liter
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

132

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 it could 

continue accepting the gas wastewater as long as it was not violating its existing effluent 

limitations (118 DCN SGE00749; 64 DCN SGE00552). In July 2009, WV DEP sent a letter to 

the Clarksburg Sanitary Board with a list of requirements that would be imposed if it decided to 

accept oil-and-gas-related wastewater (166 DCN SGE01113). The letter also stated that

...WVDEP discourages POTWs from accepting wastewater from oil and gas 

operations such as...Marcellus shale wastewaters because these wastewaters

essentially pass through sewage treatment plants 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 (128 DCN SGE00762; 129 DCN SGE00766).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

133 

5.3.1.2 Case Studies About POTWs Accepting Wastewater from Other Industrial 

Sources Containing UOG Pollutants 

Franklin Township, PA, POTW

The Franklin Township POTW discharges to the lower fork of Ten Mile Creek, a 

tributary to the Monongahela River, and treats influent wastewater using aeration, rotating 

biological contactors, clarification, filtration, and chlorination (116 DCN SGE00746). The 

Franklin Township POTW accepted industrial wastewater from the Tri-County Wastewater 

CWT facility until March 2011. During that time, the Tri-County CWT facility was accepting oil 

and gas extraction wastewater. The CWT facility targeted removal of TSS and oil and grease by 

filtration, flocculation, and skimming, but certain pollutants in the UOG extraction wastewater 

such as TDS remained in the treated effluent from the CWT facility. The industrial wastewater 

received from Tri-County Wastewater accounted for approximately 5.4 percent of the Franklin 

POTW’s 0.982 MGD effluent by volume in November 2010 (56 DCN SGE00525). 

On December 4, 2008, the Franklin POTW entered into a Consent Order and Agreement 

with PA DEP130 regarding effluent discharges containing elevated levels of TDS. Paragraph G of 

the order notes that 

Neither the STP [Franklin POTW] nor the Pretreatment Facility [Tri-County 

CWT Facility] currently has treatment facilities for the removal of Total 

Dissolved Solids.

Ferrar et al. (56 DCN SGE00525) analyzed constituents in effluent wastewater 

discharged from the Franklin Township POTW during the period before and after it accepted 

industrial wastewater from the Tri-County Wastewater CWT facility. Table D-20 shows the 

mean and range of effluent concentrations at the Franklin Township POTW during the period 

when it accepted industrial wastewater from the CWT facility and after it stopped. Ferrar et al. 

analyzed pollutants typically found in UOG extraction wastewater; they report a mean effluent 

TDS concentration of 3,860 mg/L from the Franklin Township POTW while it was accepting 

wastewater from the Tri-County CWT facility and a mean effluent TDS concentration of 398 

mg/L from the POTW after it stopped. The mean effluent concentrations for all pollutants 

presented in Table D-20 were higher when the POTW was accepting the industrial discharge 

from the Tri-County CWT facility, suggesting that pollutants were discharged from the POTW 

without treatment. Based on the treatment technologies currently in place at the Franklin 

Township POTW, one would expect little to no treatment of the common constituents in UOG 

extraction wastewater. Ferrar et al. concluded: 

This research provides preliminary evidence that these and similar WWTPs may 

not be able to provide sufficient treatment for this wastewater stream, and more 

thorough monitoring is recommended.

 

130 PA DEP had issued an AO to the Franklin POTW in October 2008, but the Consent Order and Agreement 

superseded that order. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

134

Table D-20. 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: 56 DCN SGE00525

a—Organic analytes were not detected in samples.

b—Sample date: 11/10/2010. Reported values are based on the mean, minimum, and maximum of 24 samples taken 

for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.

c—Sample date: 11/7/2011. Reported values are based on the mean, minimum, and maximum of nine samples taken 

for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.

Abbreviation: mg/L—milligrams per liter

Wheeling, WV, POTW

The Wheeling POTW has primary and secondary treatment operations, including primary 

clarification, solids and floatable materials removal, and disinfection (155 DCN SGE00999). The 

Wheeling POTW accepted industrial wastewater from the Liquid Asset Disposal (LAD) CWT 

facility through August 2009131 and wastewater directly from UOG operators in 2008.

132 The 

LAD CWT facility accepted a variety of wastewater from the following sources: sewage 

facilities, storm water from an international airport, and gas well development and production 

wastewater, among others. The LAD CWT facility is a SIU and was authorized to discharge into 

the Wheeling, WV, POTW (SIU Permit No. 0014) (48 DCN SGE00485). The LAD CWT 

facility uses ultra-filtration, ozonation, and reverse osmosis to target the removal of chlorides 

prior to discharges to the Wheeling POTW (152 DCN SGE00996).

The EPA analyzed sampling data submitted in its DMR Loading Tool (83 DCN 

SGE00608) and PA DEP waste reports data (184 DCN SGE01182) and found that the effluent 

concentrations of chloride experienced by the Wheeling POTW in 2008 were higher when it was 

 131 EPA did not identify the date on which the Wheeling POTW began accepting wastewater from the LAD CWT 

facility. However, the LAD CWT SIU Permit No. 0014 was issued in August 2004 (156 DCN SGE01000). 132 The Wheeling POTW may have accepted UOG extraction wastewater directly from operators in years other than 

2008, but EPA only identified acceptance directly from operators in 2008 (202 DCN SGE01245).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

135

accepting UOG extraction wastewater and industrial discharges from the LAD CWT facility than 

after it stopped. In 2008, the POTW accepted an average of 5,400 gallons/day of UOG extraction 

wastewater and had an average effluent chloride concentration of 650 mg/L. Comparatively, in 

2011, the POTW did not accept any UOG extraction wastewater and had an average effluent 

chloride concentration of 130 mg/L.

133 Data from an August 2009 letter from WV DEP to the 

City of Wheeling states (167 DCN SGE01114)

The agency has determined that the following pollutants are of concern 

associated with oil and gas related wastewaters and may have a potential for 

inhibition, interference, and pass through: total dissolved solids (TDS), sulfate, 

chloride...zinc...copper...barium ...total suspended solids, 

iron...benzene...strontium...gross alpha radiation, gross beta radiation, and 

radium 226 + radium 228. In addition to the potential for inhibition, interference, 

and pass through, these pollutants may also have an impact on sludge disposal 

requirements.

Additional data from a 2011 Consent Order from WV DEP to the Wheeling POTW indicates that 

the LAD CWT facility exceeded its 9,000-pound daily chloride limitation, in violation of its SIU 

permit, 50 times between January 8, 2009, and February 4, 2010 (48 DCN SGE00485). 

Therefore, the UOG extraction wastewater and the industrial wastewater accepted by the 

Wheeling POTW from the LAD CWT facility likely contributed to the elevated effluent chloride 

concentrations.

Warren, OH, POTW

The city of Warren operates a 16 MGD POTW that discharges to the Mahoning River. 

The POTW employs screening and grit removal, primary settling, activated sludge aeration, final 

clarification, chlorination, dechlorination, and post-aeration treatment processes. Solid residuals 

are thickened by dissolved air flotation, dewatered using a belt filter press, stabilized with lime, 

and disposed of by land application or by distribution and marketing of usable end products.

In May 2009, the Warren POTW and its customer, the Patriot Water Treatment CWT

facility,

134 began discussions with the Ohio EPA about accepting UOG produced water. Patriot 

planned to accept UOG produced water from shale gas operations, treat the wastewater to 

remove heavy metals and other constituents, and discharge the treated industrial wastewater to 

the Warren POTW. In preparation for acceptance of treated industrial wastewater from the CWT 

facility that would contain pollutants found in UOG produced water, the Warren POTW 

undertook a pilot study to show that accepting wastewater containing pollutants found in UOG 

produced water would not cause any problems with Mahoning River water quality. Patriot’s 

treatment of UOG produced water includes reduction in heavy metal concentration, but not TDS 

 133 The data about quantities of UOG extraction wastewater accepted by the Wheeling POTW are from the PA DEP 

waste report data and are reflective of volumes of UOG extraction wastewater accepted from UOG operators in 

Pennsylvania. The Wheeling POTW may be accepting additional UOG extraction wastewater from UOG operators 

in West Virginia or other nearby states; these volumes of wastewater are not captured in this discussion. 134 The Patriot CWT facility uses primary treatment processes (e.g., settlement tanks, clarifier tanks) and chemical 

precipitation to target the removal of suspended solids and metals prior to discharge.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

136

or chloride. The Ohio EPA worked with Patriot and the Warren POTW to develop a pilot 

treatment study that evaluated the effects of pretreated UOG produced water on the POTW. The 

study also evaluated the receiving stream (Mahoning River) water quality, upstream and 

downstream of the POTW discharge (55 DCN SGE00522).

The pilot study began on February 9, 2010, and ran for eight weeks. It focused on 

collecting data from the Warren POTW and did not include sampling at the Patriot CWT facility. 

The summarized TDS and chloride data from the study are presented in Table D-21. The Warren 

POTW reported typical flow rates of 13.38 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)135 (88

DCN SGE00616):

• Week 1: 5 days @ 20,000 gallons (0.15 percent)

• Week 2: 5 days @ 40,000 gallons (0.30 percent)

• Week 3: 5 days @ 60,000 gallons (0.45 percent)

• Week 4: 5 days @ 80,000 gallons (0.60 percent)

• Week 5: 5 days @ 100,000 gallons (0.75 percent)

• Week 6: 5 days @ 100,000 gallons (0.75 percent)

• Week 7: 5 days @ 100,000 gallons (0.75 percent)

• Week 8: 5 days @ 100,000 gallons (0.75 percent)

Table D-21 shows the average paired influent and effluent TDS concentrations measured 

prior to start up and during the pilot study. Baseline samples were collected when the POTW was 

not accepting wastewater from the Patriot CWT facility. The pilot study description states that 

the influent samples (baseline and pilot study) include only municipal influent and do not include 

any wastewater from the Patriot CWT facility.

136 The data show that TDS and chloride 

concentrations increased in the influent and effluent samples over time both during the baseline 

sampling and after the Warren POTW accepted wastewater from the Patriot CWT facility. The 

effluent concentrations of TDS and chloride increased at higher percentages over the influent 

concentration during the pilot study, when the POTW was accepting wastewater from the Patriot 

CWT facility (88 DCN SGE00616), suggesting that TDS and chloride were not removed by the 

POTW.

 135 All flows were introduced into the Warren POTW over an eight-hour period. 136 The Warren POTW pilot study description states that “Raw [influent] does not have any Patriot influence or plant 

return flows.” The report author also noted increases in the TDS and chloride concentrations over the period of the 

study and suggested that “these increases are most likely due to seasonal fluctuations within the collection system as 

a result of user operations or seasonal runoff from spring rains” (88 DCN SGE00616).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

137

Table D-21. TDS Concentrations in Baseline and Pilot Study Wastewater Samples at 

Warren POTW

Sample Type

Influent Concentration 

(mg/L)

Effluent Concentration 

(mg/L) Percent Increase (%)

Baseline Samples

TDS 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: 88 DCN SGE00616

Abbreviation: mg/L—milligrams per liter

From September 12 through 16, 2011, EPA Region 5 inspected and collected wastewater 

samples at the Warren POTW and noted that (88 DCN SGE00616)

the POTW had not experienced any of the following conditions since accepting 

the brine waste water from the Patriot 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-22 shows the results of EPA Region 5’s wastewater 

sample analyses conducted during their September 2011 inspection. The compliance inspection 

data show minimal to no TDS removals by the POTW and minimal chloride removals.

Table D-22. EPA Region 5 Compliance Inspection Sampling Data

Pollutant

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: 88 DCN SGE00616

a—Samples were taken on four days (9/12/2013, 9/13/2013, 9/14/2013, and 9/15/2013).

b—All four samples were reported as below the detection limit.

Abbreviation: mg/L—milligrams per liter
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

138 

As of March 2015, the Warren POTW was still accepting wastewater from the Patriot 

CWT facility (139 DCN SGE00786). Its NPDES permit allows it to accept a maximum of 

100,000 gallons of “wastewater from a regulated CWT facility that is tributary to the City’s 

collection system” per day (0.67 percent of its maximum total daily flow) at a maximum TDS 

concentration of 50,000 mg/L (29 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” (143 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) (143 DCN SGE00931). The permit includes limits for pH, 

carbonaceous BOD5, TSS, fecal coliform, ammonia-nitrogen, TDS, and osmotic pressure. The 

permit also included reporting requirements for flow, barium, strontium, uranium, chloride, 

bromide, gross alpha, and radium-226/228. 

The Brockway POTW saw increases in the effluent concentrations of TDS, which were 

below 400 mg/L before the acceptance of COG wastewater and increased to between 2,500 and 

3,000 mg/L during the acceptance of COG wastewater. Typical COG wastewater accepted by the 

Brockway POTW may have TDS concentrations over 200,000 mg/L (121 DCN SGE00753). 

5.3.2 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-23 presents inhibition threshold levels for activated 

sludge and nitrification, two treatment processes commonly used at POTWs, for select UOG 

constituents identified in Section C.3.

137 The EPA recognizes that POTW treatment processes 

will not be exposed to UOG constituents at the concentrations they are found in UOG produced 

water (i.e., flowback, long-term produced water). 

 

137 EPA also presents specific inhibition thresholds for anaerobic digestion and trickling filters, but the UOG 

constituent concentrations are not as likely to exceed the thresholds, so they were not included in Table D-23. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

139

As discussed in Section A.2.2, POTWs establish local limits to control pollutant 

discharges that present a reasonable potential for pass through or interference with POTW 

operations. The inhibition levels presented in the EPA’s 2004 Local Limits Development 

Guidance (80 DCN SGE00602) represent concentrations that would reduce the effectiveness or 

otherwise interfere with the treatment operations for treatment commonly used at POTWs. 

Inhibition of activated sludge processes at a POTW could impair BOD5 removal and TSS 

removal (particularly if sludge settling is affected). Inhibition of nitrification, a process that some 

POTWs use to convert ammonia to nitrate/nitrite (which may be part of the activated sludge 

process or a separate biological treatment stage), may impair the POTW’s ability to remove 

ammonia and nutrients in the wastewater.

Table D-23. Inhibition Threshold Levels for Various Treatment Processes

Pollutant

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: 80 DCN SGE00602

a—Where multiple values are listed (divided by commas), the data were reported individually in 80 DCN 

SGE00602 by different sources.

Abbreviations: mg/L—milligrams per liter; NA—not available

Because all POTWs are required to control TSS and BOD5, they are designed for the 

effective removal of these two parameters. Elevated concentrations of TSS and BOD5 in POTW 

discharges suggest inhibition/disruption of treatment processes. As some of the studies described 

in the following sections indicate, POTWs have linked TSS and/or 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. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

140 

The purpose of these subsections is to identify instances of inhibition/disruption, or potential 

inhibition/disruption, at POTWs associated with the acceptance of UOG extraction wastewater 

pollutants. 

5.3.2.1 Case Studies About POTWs Accepting Wastewater from Oil and Gas Extraction 

Facilities 

Johnstown, PA, POTW

The Johnstown POTW uses screening, grit removal, high-purity oxygen activated sludge 

aeration with integrated fixed-film activated sludge, final clarification, and chlorination (142

DCN SGE00930). The Johnstown POTW accepted both UOG and COG wastewater before 2008 

and stopped accepting both in 2011 (184 DCN SGE01182). The total oil and gas wastewater 

accounted for less than 3 percent of the total POTW influent volume during the acceptance 

period on average. The POTW’s annual average daily flow rate ranges between 7.9 and 17.1 

MGD based on 2008 through 2014 DMR data (83 DCN SGE00608). 

The EPA created Figure D-16 using the sampling data submitted in its DMR Loading 

Tool (83 DCN SGE00608) and PA DEP waste reports data (184 DCN SGE01182). Each effluent 

concentration data point represents the average of 12 monthly average data points as calculated 

and reported by the Loading Tool. PA DEP waste reports provided the total volume of UOG and 

COG wastewater delivered to the POTW each year. The EPA divided the annual volume by 365 

to calculate the annual average daily flow. As shown in Figure D-16, the Johnstown POTW 

experienced a much larger number of permit limit exceedances during the period when they were 

accepting the greatest volume of oil and gas extraction wastewater. In a December 2012 letter 

regarding the 2011 annual pretreatment report, Johnstown’s pretreatment coordinator stated, 

[We] know that the treatment plant no longer accepts gas drilling waste,138 and 

we anticipate that the number of violations will decrease. 

Further, Section C.3.2.1 presents data showing that TSS concentrations in drilling 

wastewater may be higher than TSS concentrations in UOG produced water.

139 The PA DEP 

waste reports data show that the Johnstown POTW accepted more drilling wastewater than any 

other POTW in Pennsylvania from 2008 through 2011. The POTW accepted the largest volume

of drilling wastewater in 2009 and 2010, which totaled over 15 million gallons and accounted for 

over 40 percent of the total influent oil and gas wastewater accepted by the POTW. In total, the 

Johnstown POTW experienced 27 TSS permit limit exceedances from 2008 through 2011, 18 of 

which were in 2009 and 2010. The POTW also experienced elevated effluent TSS concentrations 

in 2009 (61 mg/L). 

 

138 The EPA assumes that this phrase refers to both COG wastewater and UOG extraction wastewater.

139 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

141

Source: 185 DCN SGE01183

Note: The annual average extraction wastewater flows for COG and UOG are presented as stacked bars in order to 

represent the total annual average oil and gas extraction wastewater influent flow.

Figure D-16. Johnstown POTW: Annual Average Daily Effluent Concentrations and 

POTW Flows

California, PA, POTW

The California POTW uses a contact stabilization140 process to treat influent wastewater 

(140 DCN SGE00787). In 2008 and 2009, the California POTW accepted both UOG and COG 

wastewater. The total oil and gas wastewater accounted for up to 33 percent of the total POTW 

influent volume during 2008, on average. UOG extraction wastewater accounted for 14 percent 

of total POTW influent during 2008, on average (184 DCN SGE01182). The POTW’s average 

annual daily flow rate ranges between 0.5 and 0.8 MGD based on 2008 through 2014 DMR data 

(83 DCN SGE00608).

 140 Contact stabilization is a two-stage activated sludge process, consisting of a 30- to 60-minute absorptive phase 

followed by a one- to two-hour oxidation phase. Aeration volume requirements are half of those for conventional 

activated sludge (12 DCN SGE00167).
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

142

The EPA created Figure D-17 using the sampling data submitted in its DMR Loading 

Tool (83 DCN SGE00608) and PA DEP waste reports data (184 DCN SGE01182). Each effluent 

concentration data point represents the average of 12 monthly average data points as calculated 

and reported by the DMR Loading Tool. PA DEP waste reports provided the total volume of 

UOG and COG wastewater delivered to the POTW each year. The EPA divided the annual 

volume by 365 to calculate the annual average daily flow. As shown in Figure D-17, the 

California POTW experienced elevated concentrations of TSS while accepting oil and gas

wastewater. Figure D-17 also shows that the California POTW experienced three exceedances of 

its TSS permit limits.

141

Source: 185 DCN SGE01183

Note: The annual average extraction wastewater flows for COG and UOG are presented as stacked bars in order to 

represent the total annual average oil and gas extraction wastewater influent flow.

Figure D-17. California POTW: Annual Average Daily Effluent Concentrations and 

POTW Flows

Charleroi, PA, POTW

The Charleroi POTW was introduced and described in more detail in Section D.5.3.1 of

this TDD. 

 141 The California POTW had a monthly average TSS limit of 30 mg/L and a daily maximum TSS limit of 45 mg/L 

from 2008 through 2013.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

143

The EPA created Figure D-18 using the sampling data submitted in its DMR Loading 

Tool (83 DCN SGE00608) and PA DEP waste reports data (184 DCN SGE01182). Each effluent 

concentration data point represents the average of 12 monthly average data points as calculated 

and reported by the Loading Tool. PA DEP waste reports provided the total volume of UOG and 

COG wastewater delivered to the POTW each year. The EPA divided the annual volume by 365 

to calculate the annual average daily flow. As shown in Figure D-18, the Charleroi POTW 

experienced elevated concentrations of TSS and BOD5 while accepting UOG extraction 

wastewater. 

Source: 185 DCN SGE01183

Note: The annual average extraction wastewater flows for COG and UOG are presented as stacked bars in order to 

represent the total annual average oil and gas extraction wastewater influent flow.

Figure D-18. Charleroi POTW: Annual Average Daily Effluent Concentrations and POTW 

Flows142

 142 Figure D-18 shows data for 2008 through 2014, excluding 2012 and 2013 because there is no PA DEP waste 

report data or DMR Loading Tool data for the Charleroi POTW for 2012 or 2013.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

144 

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

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 (153

DCN SGE00997, 154 DCN SGE00997.A01). 

The Waynesburg POTW received a CWA §308 Request for Information from EPA 

Region 3 in February 2009. In March 2009, the Waynesburg POTW responded with a “Process 

Impact Evaluation” (119 DCN SGE00750), which stated that: 

The amount of well water that was being accepted to the treatment facility has 

had no adverse effects on the trickling filter and the bio-tower except on one 

occasion in 2007. A hauler delivered a batch of well water that impacted the 

biological growth within the trickling filter. The water was believed to 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 (65

DCN SGE00554). 

In its 2009 annual report to EPA Region 3, the New Castle POTW identified numerous 

violations of its NPDES permit limits for discharges of TSS. It also identified significant 

increases in the volume of industrial wastewater that it was receiving (see Table D-24) from 

Advanced Waste Services. New Castle’s 2009 annual report does not include the total volume of 

wastewater it treated, but its 2013 NPDES permit indicates that all permit limits were based on 

an effluent discharge rate of 17 MGD (65 DCN SGE00554; 69 DCN SGE00573).

Table D-24. Industrial Wastewater Volumes Received by New Castle POTW (2007–2009)

Year 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: 65 DCN SGE00554

a—Assuming 17 MGD is the total volume treated. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

145

The 2009 annual report (65 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. This has resulted in higher sludge blanket levels that are more 

easily upset and washed out during rainfall-induced high flow events. The 

Authority has begun using polymer flocculation to enhance settling with some 

success. However, there were numerous effluent TSS violations in 2009.

As noted in the annual report, instability in sludge blanket levels can cause increased 

washouts during large rain events, which may cause interference with biological treatment. New 

Castle reported 19 violations of its NPDES permit limits for TSS, believed to be caused by the 

acceptance of UOG extraction wastewater via the Advanced Waste Services CWT facility’s 

industrial discharge (65 DCN SGE00554). The EPA compared the violations in 2009 to the 

violations that occurred in 2011, after the New Castle POTW stopped accepting industrial 

discharges from the CWT facility (i.e., violations between May and December 2011). The EPA

identified two TSS violations during this nine-month time frame. Table D-25 shows detailed 

information about the violations in 2009 and 2011, including when they occurred, the measured 

values, and the percentage over the NPDES permit limit. The decrease in the number of TSS 

violations from 2009 to 2011, after the POTW stopped accepting industrial discharges from the 

Advanced Waste Services CWT facility, suggests that the UOG extraction wastewater pollutants 

were a contributing cause of the violations. However, the two violations in 2011 indicate that the 

UOG extraction wastewater was likely not the sole cause of interference with treatment 

processes at the POTW.

Table D-25. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW 

(NPDES Permit Number PA0027511)

Month, Year 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
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

146

Table D-25. 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 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

November 2011 TSS Weekly maximum 45 64 42

Sources: 89 DCN SGE00620; 85 DCN SGE00612

Abbreviation: mg/L—milligrams per liter

Wheeling, WV, POTW

The Wheeling POTW, introduced in Section D.5.3.1, accepted industrial wastewater 

from the LAD CWT facility, which treats oil and gas wastewater.

143 A 2011 Consent Order 

issued to the Wheeling POTW by the WV DEP indicates that the POTW experienced 

interference with biological treatment from accepting UOG extraction wastewater via the CWT

facility’s industrial discharge. The Order describes the following timeline of events (48 DCN

SGE00485):

• July 21, 2009—the Wheeling POTW experienced an upset that required several 

weeks of “vigilant action to recover” and included the introduction of a “seed” sludge 

from a nearby POTW. Plant upset conditions occurred during periods when the 

POTW exceeded discharge limits for fecal coliform and TSS.

• August 21, 2009—Meeting minutes from a meeting between Wheeling POTW and 

LAD CWT facility stated that Wheeling was accepting oil and gas wastewater “well 

above the 1% that is allowed.” The minutes also said that Wheeling was concerned 

about the lack of diversity in microorganisms and that the wastewater from LAD was 

the cause of the lack of microbial diversity.

• November 17, 2009—WVDEP inspected Wheeling POTW and noted that “[t]he 

discharge from Wheeling was slightly turbid and causing a crispy white foam in the 

receiving stream.” In addition, the Wheeling POTW experienced operational 

interference, inefficiency, or possible upset indicated by several factors including an 

increased chlorine demand, loss in effluent clarity, UV disinfection failures, and 

suspicious odors.

• May 6, 2010—Wheeling POTW representatives met with WV DEP representatives 

to discuss the draft Consent Order. The Order included numerous requirements 

including one that stated, “Upon entry of this Order, Wheeling shall continue to cease 

and desist acceptance of all oil and gas wastewater.”

 143 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

147 

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 

2008 and noticed an increase in sludge generation.

144 The POTW operators noticed a scum layer 

forming on the clarifiers because of a combination of calcium in the oil and gas wastewater and 

soaps/fats in the typical POTW influent wastewater. In addition to the scum layer on the 

clarifiers, the POTW experienced increased sludge generation and high concentrations of barium 

in the sludge (sludge barium content = 1,490 mg/kg). However, the POTW ran a hazardous 

waste determination and found that the barium content was below the hazardous waste 

classification threshold (121 DCN SGE00753). 

5.3.2.3 POTW Sludge and Scale Formation

UOG extraction wastewater is also a concern in the disruption of POTW sludge 

processes, including sludge disposal, and the disruption of POTW operations as a result of 

excessive scale formation. For example, POTWs that accept and treat wastewater high in heavy 

metals (e.g., nickel, copper, zinc) face the potential for heavy metals accumulation in sludge. A 

POTW accepting wastewater with high metals concentrations may no longer be able to 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 (9 DCN SGE00136; 161 DCN SGE01028). State and federal regulations for the transport 

and disposal of radioactive waste may limit the POTW’s options for managing sludge 

contaminated with radium and other radioactive materials derived from UOG extraction 

wastewater. POTWs with sludge containing radioactive materials may resort to underground 

injection in a Class I well,

145 disposal at a hazardous waste landfill,146 or disposal at a low-level 

radioactive waste landfill147 (87 DCN SGE00615). 

In addition to inhibiting the performance of treatment operations, UOG extraction 

wastewater may disrupt POTW operations as a result of excessive scale formation. Scale 

typically accumulates on valves, pipes, and fittings and, therefore, may interfere with POTW 

operation (e.g., restrict flow to unit processes). Scale is produced from deposits of divalent 

cations (e.g., barium, calcium, magnesium) that precipitate out of wastewater. Figure D-19

 

144 The EPA is not aware of any time when the Brockway POTW accepted UOG extraction wastewater. 145 Class I underground injection wells are used to inject hazardous wastes, industrial non-hazardous liquids, or 

municipal wastewater beneath the lowermost underground source of drinking water.

146 Hazardous waste landfills are regulated under RCRA Subtitle C. Some hazardous waste landfills are permitted to 

accept TENORM waste, while others have to request state approval before accepting TENORM waste.

147 Low-level radioactive waste landfills are licensed by the U.S. Nuclear Regulatory Commission or by a state 

under agreement with the Commission. These landfills provide a disposal option for wastes with radionuclide 

concentrations that are unable to be disposed of at municipal, industrial, or hazardous waste landfills.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

148

shows an example of barium sulfate scaling in an oil and gas pipe in the Haynesville shale 

formation.

Source: 133 DCN SGE00768.A26

Figure D-19. Barium Sulfate Scaling in Haynesville Shale Pipe

Table C-17 shows typical concentrations of barium, calcium, and strontium in UOG 

extraction wastewater, which suggest that UOG extraction wastewater may cause scale 

accumulation at POTWs. Because radium148 behaves like other divalent cations, it may also 

accumulate in scale and form TENORM: technologically enhanced naturally occurring 

radioactive material, defined as naturally occurring radioactive materials that have been 

concentrated or exposed to the accessible environment as a result of human activities (147 DCN 

SGE00978) such as manufacturing, mineral extraction, or water processing (e.g., in treatment 

processes at a POTW). PA DEP’s 2015 study report149 (161 DCN SGE01028) provides the 

following examples of solids that may contain TENORM: drill cuttings, filter sock residuals, 

impoundment sludge, tank bottom sludge, pipe scale, wastewater treatment plant sludge, and 

soils.

150 The PA DEP TENORM study report concludes that “There is little potential for 

radiological exposure to workers and members of the public from handling and temporary 

storage of filter cake at POTWs. However, there is a potential for radiological environmental 

impacts from spills and the long-term disposal of POTW filter cake.” The PA DEP TENORM 

study report includes the following recommendations for future action: 

 148 Radium is a naturally occurring radioactive element that ionizes in water to a divalent cation with chemical 

properties similar to barium, calcium, and strontium.

149 PA DEP initiated a study to collect data related to TENORM associated with oil and gas operations in 

Pennsylvania, including assessment of potential worker and public radiation exposure, TENORM disposal, and 

other environmental impacts.

150 PA DEP’s 2015 TENORM study sampled the following types of solids: surface soil impacted by sediments, filter 

cakes, soils, sludge, drill cuttings, drilling muds, proppant sand, and filter socks. PA DEP identified pipe scale as a 

source of TENORM, but did not sample for pipe scale in their 2015 TENORM study.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

149

• “Perform routine survey assessment of areas impacted with surface radioactivity to 

determine personal protective equipment (PPE) use and monitoring during future 

activity that may cause surface alpha and beta radioactivity to become airborne.”

• “Conduct additional radiological sampling and analyses and radiological surveys at 

all WWTPs accepting wastewater from O&G operations to determine if there are 

areas of contamination that require remediation; if it is necessary to establish 

radiological effluent discharge limitations; and if the development and 

implementation of a spill policy is necessary.”

The Marcellus shale formation is known to contain radium and, therefore, is of particular 

concern for TENORM generation (9 DCN SGE00136; 53 DCN SGE00519; 74 DCN 

SGE00587).

Rowan et al. (16 DCN SGE00241) report a positive correlation between TDS 

concentrations and radium activity based on data for produced water from the Marcellus shale 

and conventional formations in the Appalachian basin. Therefore, UOG formations containing 

higher concentrations of TDS will likely also contain higher radium activity and, therefore, a 

higher chance for TENORM accumulation in sludge. However, the existing literature contains

limited sampling data measuring radioactive constituents in UOG extraction wastewater (see

Table C-19). Therefore, the potential for TENORM accumulation in scale from UOG extraction 

wastewater and the subsequent health risks to worker safety at POTWs are not fully known. 

The 2015 PA DEP TENORM Study (161 DCN SGE01028) also looked into potential 

worker exposure, TENORM disposal options, and environmental impacts. PA DEP analyzed 

liquid and solid samples for alpha, beta, and gamma radiation and gas samples for radon. PA 

DEP sampled the following types of facilities, among others, as part of their study: 

• Well sites—PA DEP sampled 38 well sites (4 conventional wells and 34 

unconventional wells) from June 2013 through July 2014

• Wastewater treatment plants—PA DEP sampled 29 wastewater treatment plants 

(10 POTWs, 10 CWT facilities, and 9 zero liquid discharge (ZLDs) facilities)

PA DEP presents sample data of filter cakes from POTWs receiving oil and gas

wastewater that showed “Ra-226 and Ra-228 present above typical background concentrations in 

soil. The average Ra-226 result was 20.1 pCi/g with a large variance in the distribution, and the 

maximum result was 55.6 pCi/g. The average Ra-228 result was 8.32 pCi/g, and the maximum 

result was 32.0 pCi/g Ra-228” (161 DCN SGE01028).

PADEP concluded, “...[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.

151

However, there is a potential for radiological environmental impacts from spills and the longterm disposal of POTW-I filter cake” (161 DCN SGE01028). ERG’s Radioactive Materials in 

 151 PA DEP defines a “POTW-I” as a POTW that was considered to be influenced by having received wastewater 

from the oil and gas industry.
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

150 

the Unconventional Oil and Gas (UOG) Industry memorandum (188 DCN SGE01185) provides 

additional information and results from the PA DEP study. 

5.3.3 Potential Impacts of 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 (see Table C-11), which 

are precursors of several toxic DBPs (51 DCN SGE00509; 122 DCN SGE00754). Brominated 

DBPs are reported to have greater health risks (e.g., higher risk of cancer) than chlorinated DBPs 

(141 DCN SGE00800). Additional information and discussion on DBPs and other human and 

ecological impacts can be found in other EPA resources (163 DCN SGE01093; 170 DCN 

SGE01126). 

UOG extraction wastewater discharged to POTWs could be a potential source of DBPs in 

two scenarios: 

• When UOG extraction wastewater is disinfected at a POTW (62 DCN SGE00535) 

• When a POTW discharges wastewater including UOG extraction wastewater

pollutants to a river that is used as a source water for a downstream drinking water 

treatment plant where disinfection is used (74 DCN SGE00587) 

5.3.3.1 UOG Extraction Wastewater Disinfection at POTWs

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 (62 DCN SGE00535). 

Hladik et al. sampled effluent from three Pennsylvania POTWs, one POTW that did not 

accept oil and gas wastewater (POTW 1) and two that accepted oil and gas wastewater from oil 

and gas operators (POTW 2, POTW 3). The daily average discharge rates for the three POTWs 

were not reported. The total volume of oil and gas wastewater accepted at POTWs 2 and 3 was 

reported as ranging from 2.3 million gallons to 2.9 million gallons in 2012. Grab samples were 

collected in the river where the POTW effluent entered and were analyzed for 29 DBPs. 

Table D-26 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

151 

Table D-26. 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: 62 DCN SGE00535

Note: The EPA presents data for eight DBPs in Table D-26. Hladik et al. (62 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. (62 DCN SGE00535). 

b—Below method detection limit (BDL) indicates a value reported by Hladik et al. that was lower than the MDL. 

The EPA reported these values as BDL instead of reporting the values from Hladik et al. (62 DCN SGE00535).

Abbreviation: ND—nondetect; μg/L—micrograms per liter

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 (68 DCN 

SGE00567; 74 DCN SGE00587). 

Wilson and Van Briesen (94 DCN SGE00633) also investigated whether effluent 

discharges from POTWs were causing high TDS and bromide concentrations that would 

negatively impact drinking water treatment plants. They note that 

Like TDS, bromide is not removed at drinking water treatment plants. Thus, 

produced water management that leads to increased concentrations of bromide in 

source waters for drinking water treatment plants can lead to increased 

concentrations of DBPs in drinking water. 
Chapter D—UOG Extraction Wastewater Management and Disposal Practices

152

Wilson and Van Briesen later conclude that

Produced water management decisions should be informed by the potential 

contribution of this wastewater to the formation of disinfection by-products in 

downstream drinking water treatment plants.

States et al. (74 DCN SGE00587) conducted a drinking water treatment plant survey and 

investigated bromide concentrations in the untreated river water intake and trihalomethanes 

(THMs) (i.e., chloroform, bromoform, dibromochloromethane, bromodicholoromethane) in the 

treated, “finished” drinking water. States et al. drew the following conclusions from their study:

• Elevated bromide concentrations in the influent to the studied drinking water 

treatment plant resulted in increased concentrations of certain 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 (112 DCN SGE00735). The report discussed POTW management of 

UOG extraction wastewater and specifically noted that this is not a best management practice. 

They further reported that the discharge of high-TDS loads into surface waters that could be 

drinking water treatment intakes should be prohibited. Eshelman and Elmore state that 

Higher chloride levels cause taste and odor problems in finished water. High 

bromide levels lead to increased formation of carcinogenic disinfectant byproducts that can persist in the water to the point of consumption. Treatment of 

produced water by POTWs and other conventional wastewater treatment methods 

that do not remove salts should be prohibited in Maryland.

McTigue et al. published an article about the occurrence and consequences of bromide in 

drinking water sources (141 DCN SGE00800). They note that UOG extraction wastewater may 

contribute to recent increases in bromide-containing waste upstream of drinking water utilities, 

and thus to the increase in 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-20 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

153

Abbreviations: TTHM MCL—total trihalomethane maximum contaminant level

Source: 141 DCN SGE00800.

Figure D-20. THM Speciation in a Water Treatment Plant (1999–2013)

Another example of concerns about 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 (nondetect)

• Bromodichloromethane (nondetect)

• Dibromochloromethane (nondetect)

• 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

154

In August 2013, EPA Region 3 issued a letter (144 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 (145 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 (151 DCN SGE00985) that evaluated 

the minimum volume of UOG produced water from Marcellus shale and Fayetteville shale wells 

that, when diluted by fresh water, would generate and/or alter the formation and speciation of 

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

155

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 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. Last 

accessed on May 17, 2016: 

http://www.netl.doe.gov/File%20Library/Research/OilGas/Shale_Gas_Primer_2009.pdf

A

2 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). Last accessed on May 17, 2016: 

http://www.mde.state.md.us/programs/Land/mining/Marcellus/Documents/W

aterMgmtinMarcellusfull.pdf

A

3 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

4 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

5 SGE00095 URS. 2011. Water-Related Issues Associated with Gas Production in the 

Marcellus Shale. (March 25). B
Chapter E—Reference Flags and List

156

Table E-1. Source List

ID DCN Source Citation 

Source 

Flag

6 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

7 SGE001277 Abt Associates. 2016. Profile of the Oil and Gas Extraction (OGE) Sector, 

with Focus on Unconventional Oil and Gas (UOG) Extraction. (February 18). A

8 SGE00132 U.S. EPA. 2011. Underground Injection Control Program: Class II Wells—

Oil and Gas Related Injection Wells (Class II). Downloaded on 8/31/2011. A

9 SGE00136 U.S. EPA. 2011. Oil and Gas Production Wastes. Last accessed on May 17, 

2016: https://www.epa.gov/radiation/tenorm-oil-and-gas-production-wastes A

10 SGE00139

Puder, M.G.; Veil, J.A. 2006. Argonne National Laboratory. Offsite 

Commercial Disposal of Oil and Gas Exploration and Production Waste: 

Availability, Options, and Costs. Prepared for U.S. DOE NETL. (August).

A

11 SGE00155 U.S. Energy Information Administration (EIA). 2010. Tight Sands Gas Plays, 

Lower 48 States. Prepared by EIA Office of Oil and Gas. (June). A

12 SGE00167 Metcalf and Eddy, Inc. 2002. Wastewater Engineering: Treatment and Reuse. 

Fourth edition. McGraw-Hill, Inc. B

13 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.

A

14 SGE00187 Pennsylvania Code. 2010. Title 25: Environmental Protection. Chapter 95: 

Wastewater Treatment Requirements. (August). A

15 SGE00239 Hefley, William, et al. 2011. The Economic Impact of the Value Chain of a 

Marcellus Shale Well. University of Pittsburgh. (August). B

16 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

17 SGE00244 ERG. 2012. Camp, Meghan; Bicknell, Betsy; Ruminski, Brent. Notes on 

Conference Call with 212 Resources on 4 January 2012. (January 9). A

18 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

19 SGE00249 U.S. EPA. 2011. Introduction to the National Pretreatment Program. EPA 

833-B-11-001. (June). A

20 SGE00254

Michigan Department of Environmental Quality (MI DEQ). 2006. Michigan 

Oil and Gas Regulations: Natural Resources and Environmental Protection 

Act—Act No. 451 of the Public Acts of 1994, As Amended. Office of 

Geological Survey. (April).

A

21 SGE00275 U.S. EPA. 2012. Site Visit Report: Citrus Energy Corporation Marcellus 

Shale Gas Operations. (January 22). A

22 SGE00276 U.S. EPA. 2012. Meeting with XTO Energy, Inc. about Unconventional Oil 

and Gas Sanitized. A
Chapter E—Reference Flags and List

157

Table E-1. Source List

ID DCN Source Citation 

Source 

Flag

23 SGE00279 U.S. EPA. 2012. Meeting Summary: Conference Call with North Star 

Disposal, Inc Regarding Underground Injection Operations in Ohio. (July 2). A

24 SGE00280 U.S. EPA. 2013. Site Visit Report: Anadarko Petroleum Corporation 

Marcellus Shale Gas Operations. (January 9). A

25 SGE00283 ERG. 2012. Camp, Meghan; Ruminski, Brent. Notes on Conference Call with 

BLX, Inc on 15 May 2012. (June 11). A

26 SGE00284

Hayes, Thomas et al. 2012. Barnett and Appalachian Shale Water 

Management and Reuse Technologies. Research Partnership to Secure 

Energy for America (RPSEA).

A

27 SGE00286

Hammer, R.; VanBriesen, J. 2012. In Fracking’s Wake: New Rules Are 

Needed to Protect Our Health and Environment from Contaminated 

Wastewater. NRDC Document D:12-05-A. Natural Resources Defense 

Council. (May).

A

28 SGE00291 Shires, Terrie; Lev-on, Mairiam. 2012. Characterizing Pivotal Sources of 

Methane Emissions from Natural Gas Production. B

29 SGE00295

Warren Water Pollution Control Facility. 2011. Fact Sheet for NPDES Permit 

Renewal, Warren Water Pollution Control Facility, 2011–2012. City of 

Warren.

A

30 SGE00299 U.S. EPA. 2012. Site Visit Report: US Gas Field Fluids Management 

(formerly Clean Streams) Marcellus Shale Gas Operations. (October 9). A

31 SGE00300 U.S. EPA. 2012. Site Visit Report: Eureka Resources, LLC Marcellus Shale 

Gas Operations. (February 25). A

32 SGE00305.A03 Cheung, Timothy. 2012. Identifying the Recycling and Treatment Criteria 

That Must be Met to Avoid Scaling and Enable Successful Reuse. Shell. C

33 SGE00305.A10 Fredriksen, K. 2012. How An Operator Is Developing A Systematic Sourcing 

Strategy To Guarantee Water Availability At Minimal Costs. Consol Energy. C

34 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

35 SGE00345 Lewis, Aurana. 2012. Wastewater Generation and Disposal from Natural Gas 

Wells in Pennsylvania. Duke University. B

36 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 

Center, University of North Dakota. Prepared for National Energy 

Technology Laboratory. 

A

37 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

38 SGE00357 Cramer, John. 2011. Post-frac Flowback Analysis and Reuse Implications. 

Superior Well Services. B

39 SGE00366 Clarion Altela Environmental Services (CAES). n.d. CAES Overview. 

Downloaded on 1/28/2013. C
Chapter E—Reference Flags and List

158

Table E-1. Source List

ID DCN Source Citation 

Source 

Flag

40 SGE00367 CARES. n.d. CARES McKean. Downloaded on 1/28/2013. C

41 SGE00368

U.S. EPA. 2012. (Region 3). Key Documents About Mid-Atlantic Oil and 

Gas Extraction. (November 26). Last accessed on May 17, 2016: 

https://www.epa.gov/foia/oil-and-gas-extraction-mid-atlantic

A

42 SGE00374 Red Desert. n.d. What Makes Our Water Treatment & Reclamation Facility 

So Advanced? Downloaded on 1/28/2013. C

43 SGE00379 Hill, David A. 2012. The Future Is NOW for Water Recycling in the 

Niobrara. Wyoming Energy News. C

44 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

45 SGE00476 Hydro Recovery, LP. 2013. Company Info. Downloaded on 5/20/2013. C

46 SGE00479 Kadramas, Lee & Jackson, Inc. 2012. Power Forecast 2012: Williston Basin 

Oil and Gas Related Electrical Load Growth Forecast. B

47 SGE00481 McCutcheon Enterprises. 2013. Waste Reduction: A Greener Alternative for 

Treating Drilling Muds. (April). C

48 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

49 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

50 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

51 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

52 SGE00516 Cochener, John. 2010. Quantifying Drilling Efficiency. U.S. EIA, Office of 

Integrated Analysis and Forecasting. (June 28). A

53 SGE00519 Davies, Peter J. n.d. Radioactivity. Cornell University. B

54 SGE00521 ERG. 2012. Camp, Meghan; Ruminski, Brent. Notes for Shale Gas Industry 

Meeting Held on 29 February 2012. (April 20). A

55 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
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159

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56 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 

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57 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 

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B

58 SGE00528 Gilmer, Ellen. 2013. Data Show More Marcellus Wastewater, More 

Injections. E&E News. (February 22). C

59 SGE00531 Hanlon, James. 2011. Natural Gas Drilling in the Marcellus Shale: NPDES 

Program Frequently Asked Questions. (March 16). A

60 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

61 SGE00533 Heffernan, Kevin. 2012. Unconventional Resource Development and 

Hydraulic Fracturing. Red Deer River Watershed Alliance. (October 25). B

62 SGE00535

Hladik, Michelle; Focazio, Michael J.; Englae, Mark. 2014. Discharges of 

Produced Waters from Oil and Gas Extraction via Wastewater Treatment 

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A

63 SGE00545 Klaber, Kathryn. 2011. Letter to Michael Krancer, PA DEP. Marcellus Shale 

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64 SGE00552

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River Recreating & Commerce Committee Meeting 12 December 2008. Last 

access on May 17, 2016: 

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C-min-14Dec08.htm

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65 SGE00554

Widmer Engineering, Inc. 2010. New Castle Sanitation Authority, New 

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66 SGE00556

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67 SGE00557 NDIC. 2014. Basic Subscription Services—Well Index. Department of 

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68 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 

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A

69 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
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70 SGE00575 Petroleum Equipment Suppliers Association (PESA). 2012. Outlook for 

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71 SGE00579

Rahm, Brian, et al. 2013. Wastewater Management and Marcellus Shale Gas 

Development: Trends, Drivers, and Planning Implications. Journal of 

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A

72 SGE00583 Romo, Carlos; Janoe, J. Scott. 2012. Regulatory Regimes for Recycling 

Produced and Frac Flowback Water. Paper 2012-A-453-AWMA. A

73 SGE00586

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(STRONGER). 2003. West Virginia Follow-Up and Supplemental Review. 

(January).

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74 SGE00587 States, Stanley et al. 2013. Marcellus Shale Drilling and Brominated THMs in 

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75 SGE00592 U.S. Department of Energy (U.S. DOE). 2013. Water Issues Dominate Oil 

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76 SGE00593

U.S. Energy Information Administration (EIA). 1993. Drilling Sideways—A 

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77 SGE00595 U.S. Energy Information Administration (EIA). 2013. Drilling Productivity 

Report: For Key Tight Oil and Shale Gas Regions. (October). A

78 SGE00599 U.S. EPA. 1999. Biosolids Generation, Use, and Disposal in the United 

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79 SGE00600

U.S. EPA. 2003. Development Document for the Final Effluent Limitations 

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80 SGE00602

U.S. EPA. 2004. Local Limits Development Guidance Appendices. EPA 833-

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81 SGE00603 U.S. EPA. 2008. Clean Watersheds Needs Survey: 2008 Report to Congress. 

EPA 832-R-10-002. A

82 SGE00604 U.S. EPA. 2010. Hydraulic Fracturing Research Study. EPA 600-F-10-002. 

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83 SGE00608 U.S. EPA. 2012. Discharge Monitoring Report (DMR) Pollutant Loading

Tool. Downloaded on 1/28/2013. A

84 SGE00611 U.S. EPA. 2012. UIC Program Primacy. Downloaded on 10/24/2013. A

85 SGE00612 U.S. EPA. 2013. DMR Loading Tool Download for New Castle POTW 

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86 SGE00613

U.S. EPA. 2013. Meeting Summary: Meeting with Industry Representatives 

About the Unconventional Oil and Gas Effluent Guideline Rulemaking. 

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A

87 SGE00615 U.S. EPA. 2013. Radionuclides in Drinking Water: Waste Disposal Options. 

(November 26). A
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88 SGE00616 U.S. EPA. 2013. Summary of the Technical Workshop on Wastewater 

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89 SGE00620

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90 SGE00622

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91 SGE00623

U.S. Government Accountability Office (GAO). 2012. Energy-Water-Nexus: 

Information on the Quantity, Quality, and Management of Water Produced 

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A

92 SGE00625 U.S. EPA. 2013. Site Visit Report: Southwestern Energy (SWN) Fayetteville 

Shale Gas Operations Sanitized. A

93 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

94 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

95 SGE00635 U.S. EPA. 2012. Site Visit Report: Chesapeake Energy Corporation 

Marcellus Shale Gas Operations Sanitized. A

96 SGE00636 U.S. EPA. 2012. Talisman Marcellus Operations Overview. (July 23). A

97 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). 

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98 SGE00667

Lord, R. LeBas; Luna, D.; Shahan, T. 2013. Development and Use of HighTDS Recycled Produced Water for Crosslinked-Gel-Based Hydraulic 

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B

99 SGE00691

U.S. EPA. 2013. Summary of the Technical Workshop on Water Acquisition 

Modeling: Assessing Impacts Through Modeling and Other Means. 

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100 SGE00695 U.S. EPA. 2012. Conference Call with ConocoPhilips About Shale Gas 

Operations. A

101 SGE00705 ERG. 2014. Ruminski, Brent. Notes on Call with Hydrozonix, LLC on 7 

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102 SGE00707

Horn, Aaron; Patton, Mark; Hu, Jinxuan. 2013. Minimum Effective Dose: A 

Study of Flowback and Produced Fluid Treatment for Use as Hydraulic 

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B

103 SGE00708 Environmental Leader. 2013. Unconventional E&P “$8 Billion of US Water 

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104 SGE00709 Natural Gas Europe. 2012. Flowback Water Driving Flurry of Activity in 

Water Treatment (May 22). B

105 SGE00710

Slutz, James; Anderson, Jeffrey; Broderick, Richard; Horner, Patrick. 2012. 

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B

106 SGE00721 U.S. EPA. 2015. Evaluation of Hydraulic Fracturing Fluid Data from the 

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107 SGE00722 HIS. 2012. Water Management in Shale Gas Plays. (August). B

108 SGE00723 Agency for Toxic Substances & Disease Registry (ATSDR). 2006. Hydrogen 

Sulfide ToxFAQs. (July). A

109 SGE00725

Wolford, Robert. 2011. Characterization of Organics in the Marcellus Shale 

Flowback and Produced Waters. Pennsylvania State University. Master’s 

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B

110 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

111 SGE00728

HIS. 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

112 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 

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A

113 SGE00742 U.S. EPA. 2012. States Pretreatment Coordinators’ Quarterly Conference 

Call: Summary. (August 8). A

114 SGE00743 U.S. EPA. 2013. States Pretreatment Coordinators’ Bi-monthly Conference 

Call. (August 14). A

115 SGE00745

KLH Engineers. 2011. Municipal Authority of the City of McKeesport: 

Headworks Loading Analysis for Natural Gas Drilling Wastewater Pollutants. 

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B

116 SGE00746 Franklin Township Sewer Authority. 2008. Franklin Township WWTP Fact 

Sheet/Statement of Basis (NPDES PA0046426). (June 2). A

117 SGE00748 PG Environmental, LLC. 2009. Clairton Municipal Authority POTW PassThrough Analysis Appendices. (August 19). A

118 SGE00749 City of Clarksburg. 2009. Re: Clean Water Act Section 308 Request for 

Information. (March 2). A

119 SGE00750 Borough of Waynesburg. 2009. Waynesburg Response to Clean Water Act 

Section 308 Request for Information. (March 31). A

120 SGE00751 Borough of Charleroi. 2008. Re: Authority of the Borough of Charleroi 

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121 SGE00753

Keister, Timothy. 2010. Marcellus Hydrofracture Flowback and Production 

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B
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122 SGE00754

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A. 2014. A Critical Review of the Risks to Water Resources from 

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A

123 SGE00755 Pennsylvania Department of Environmental Protection (PA DEP). 2011. 

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124 SGE00756 Hill Engineering, Inc. 2014. Re: Local Limits Analysis for Ridgway Borough. 

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125 SGE00757

KLH Engineers. 2008. Technical Evaluation of the Impact of Oil and Gas 

Well Wastewaters on the Municipal Authority of the City of McKeesport 

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A

126 SGE00758

KLH Engineers. 2009. Technical Evaluation of the Impact of Oil and Gas 

Well Wastewaters on the Clairton Municipal Authority Wastewater 

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A

127 SGE00760 Freyman, Monika. 2014. Hydraulic Fracturing & Water Stress: Water 

Demand by the Numbers. Ceres. (February). B

128 SGE00762 U.S. EPA. 2013. US EPA Technology Innovation Project: ECOS/ACWA 

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129 SGE00766 U.S. EPA. 2014. Lockhart, John V. Email Correspondence between WV DEP 

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130 SGE00767

West Virginia Department of Environmental Protection (WV DEP). 2010. 

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A

131 SGE00768.A01 Robart, Alexander. 2014. E&P Infrastructure vs. Third-Party Services 

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132 SGE00768.A25

Fletcher, Sarah. 2014. Water Management Infrastructure Investments: 

Decision Factors and Regional Economics. Sourcewater Cambridge 

Innovation Center at MIT.

B

133 SGE00768.A26 Tucker, Scott. 2014. Evaluating Characteristics of Source, Flowback, & 

Produced Water for Effective Water Treatment. (May 29). B

134 SGE00769

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Behaviour of Radium: Revised Edition. Technical Report Series No. 476. 

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135 SGE00779.A24 Mastowski, Ryan. 2014. Disposal—Oil and Gas Environmental Compliance 

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136 SGE00780 ExxonMobile. 2014. Hydraulic Fracturing Fluid. XTO Energy. Downloaded 

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137 SGE00781 FracFocus. 2014. What Chemicals Are Used? B

138 SGE00785

U.S. EPA. 2015. Summary of EPA Outreach and Coordination with Indian 

Tribes for the Proposed Pretreatment Standards for UOG Extraction 

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A

139 SGE00786 U.S. EPA. 2014. UOG Workgroup—Warren, OH POTW Info Request. (June 

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140 SGE00787 Borough of California. 2009. Borough of California Response to 308 Request 

for Information. (March 18). A

141 SGE00800

McTigue, Nancy; Graf, Katherine; Brown, Richard. 2014. Occurrence and 

Consequences of Increased Bromide in Drinking Water Sources. 

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A

142 SGE00930 Pennsylvania Department of Environmental Protection (PA DEP). 2012. 

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143 SGE00931 Pennsylvania Department of Environmental Protection (PA DEP). 2012. 

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144 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

145 SGE00935.A01 U.S. EPA. 2013. Toxic Screening Analysis Spreadsheet. A

146 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

147 SGE00978 PA DEP. 2014. PA DEP TENORM Study—Update 2nd Quarter 2014 Update. A

148 SGE00982 U.S. EPA. 2011. (Region 3) Letter to PA DEP regarding disposal of 

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149 SGE00983

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Resources Management—Oil and Gas. (September 10). Downloaded October 

17, 2014.

A

150 SGE00984 Energy Information Administration (EIA). 2014. Glossary. Last accessed on 

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151 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 

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A

152 SGE00996 Kicinski, J. 2007. Wheeling POTW Analysis 4. A

153 SGE00997 Borough of Waynesburg. 2009. Clean Water Act Section 308 Request for 

Information. A

154 SGE00997.A01 Borough of Waynesburg. 2009. Clean Water Act Section 308 Request for 

Information—Attachment 1: Acceptance Records. A

155 SGE00999 McClung, L.A. 2008. Wheeling POTW Discharge Requirements. A

156 SGE01000 City of Wheeling Water Pollution Control Division. 2007. Wheeling Effluent 

Data. A

157 SGE01006

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158 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

159 SGE01012 U.S. EPA. 2014. Class II Disposal Well Inventory Update. Office of Ground 

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160 SGE01017.A05

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Freshwater for Hydraulic Frac Ops in the Context of Competition from other 

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161 SGE01028

Pennsylvania Department of Environmental Protection. 2015. 

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162 SGE01077

Ground Water Protection Council (GWPC). 2014. Regulations Designed to 

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163 SGE01093

Abt Associates. 2015. Final Annotated Bibliography for Sec XIV, 

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A

164 SGE01095

USGS. 2015. Trends in Hydraulic Fracturing Distributions & Trt Fluids, 

Additives, Proppants, & Water Volumes Applied to US Wells Drilled, 1947-

2010.

A

165 SGE01095.A09

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Additives, Proppants, & Water Volumes Applied to US Wells Drilled, 1947-

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166 SGE01113

West Virginia Department of Environmental Protection (WV DEP). 2009. 

WV/NPDES Permit No WV0023302 Clarksburg Sanitary Board Accepting 

Oil and Gas Wastewater.

A

167 SGE01114

West Virginia Department of Environmental Protection (WV DEP). 2009. 

WV/NPDES Permit No, WV0023230 City of Wheeling Accepting Oil and 

Gas Wastewater.

A

168 SGE01123 U.S. EPA. 2014. Tribal Unconventional Oil and Gas Operations and 

Wastewater Management Call Summary. A

169 SGE01125 NYSDEC. 2015. Final Supplemental Generic Environmental Impact 

Statement on the Oil, Gas, and Solution Mining Regulatory Program. A

170 SGE01126 U.S. EPA. 2015. Assessment of the Potential Impacts of Hydraulic Fracturing 

for Oil and Gas in Drinking Water Resources. ORD. A

171 SGE01128

Veil, J. 2015. US Produced Water Volumes & Management Practices in 

2012. Veil Environmental, LLC. Prepared for Ground Water Protection 

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172 SGE01143 Lyons, B. and Tintera, J.J. 2014. Sustainable Water Management in the Texas 

Oil and Gas Industry. Atlantic Council. Energy & Environment Program. B

173 SGE01166 Warner, N.R., et al. 2014. New Tracers Identify Hydraulic Fracturing Fluids 

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174 SGE01168

Myers, J.E. 2014. Chevron San Ardo Facility Unit (SAFU) Beneficial 

Produced Warer Reuse for Irrigation. Chevron. Society of Petroleum 

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A

175 SGE01169 FracFocus. 2015. FracFocus Database Version 2.0. Accessed on July 22 

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176 SGE01170 DrillingInfo, Inc. 2015. DI Desktop® March 2015 Download_CBI. B

177 SGE01177 ERG. 2016. Conventional Oil and Gas Memorandum for the Record. A

178 SGE01178 ERG. 2016. Analysis of Centralized Waste Treatment Facilities (CWTs) 

Accepting UOG Extraction Wastewater. A

179 SGE01179 ERG. 2016. Data Compilation Memorandum for the Technical Development 

Document (TDD). A

180 SGE01179.A02 ERG. 2016. Data Compilation Memorandum for the Technical Development 

Document (TDD) Attachment 2: EIA UOG Resource Potential. A

181 SGE01179.A03 ERG. 2016. Data Compilation Memorandum for the Technical Development 

Document (TDD) Attachment 3: TDD Data Compilation. A

182 SGE01180 ERG. 2016. Analysis of DI Desktop® Memorandum. A

183 SGE01181 ERG. 2016. Unconventional Oil and Gas (UOG) Drilling Wastewater 

Memorandum. A

184 SGE01182 ERG. 2016. Analysis of Pennsylvania Department of Environmental 

Protection’s Oil and Gas Waste Reports. A

185 SGE01183 ERG. 2016. Publicly Owned Treatment Works (POTW) Memorandum for the 

Technical Development Document (TDD). A

186 SGE01184 ERG. 2016. Unconventional Oil and Gas (UOG) Produced Water Volumes 

and Characterization Data Compilation Memorandum. A

187 SGE01184.A13 ERG. 2016. UOG Produced Water Volumes and Characterization Data 

Compilation—A13: UOG Wastewater Characterization Database. A

188 SGE01185 ERG. 2016. Radioactive Elements in the Unconventional Oil and Gas (UOG) 

Industry. A

189 SGE01186 U.S. EPA. 2016. Unconventional Oil & Gas Wastewater Treatment 

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190 SGE01187 ERG. 2016. Analysis of Active Underground Injection for Disposal Wells. A

191 SGE01187.A01 ERG. 2016. Analysis of Active Underground Injection for Disposal Wells—

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192 SGE01190 U.S. Energy Information Administration. 2015. Assumptions to the Annual 

Energy Outlook 2015. A

193 SGE01191 U.S. Energy Information Administration. 2015. Lower 48 States Shale Plays. 

Prepared by EIA Office of Oil and Gas. (April). A

194 SGE01192 U.S. Energy Information Administration. 2015. Annual Energy Outlook 2015 

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195 SGE01206 Cart, J. 2015. Hundreds of illicit oil wastewater pits found in Kern County. 

LA Times. D

196 SGE01207 US Govt Accountability Office. 2015. Water in the energy sector: Reducing 

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197 SGE01208 State Review of Oil and Natural Gas Environmental Regulations, Inc. 2015. 

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198 SGE01216 Ellsworth, W.L. 2013. Injection-induced earthquakes. Science 341(6142). 

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199 SGE01231

Maloney, K.O. and Yoxtheimer, D.A. 2012. Production and Disposal of 

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200 SGE01233 Baker Hughes. 2015. North America Rotary Rig Count Pivot Table (Feb 

2011–Current). (October 9). Downloaded on 10/12/2015. B

201 SGE01234 Baker Hughes. 2015. U.S. Onshore Well Count. (January 9). Downloaded on 

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202 SGE01235 Baker Hughes. 2015. North America Rotary Rig Count (Jan 2000–Current). 

(October 9). Downloaded on 10/12/2015. B

203 SGE01245 O’Connell, James, ERG. 2014. Pennsylvania Department of Environmental 

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204 SGE01250 The Alaska State Legislature. 2014. Alaska Statutes: Title 38 Chapter 5 

Section 965. A

205 SGE01251 Arkansas Oil and Gas Commission. 2015. General Rules and Regulations. A

206 SGE01252 The State of Oklahoma. 2015. The Oklahoma Register: Title 165 Chapter 10. A

207 SGE01253 The State of Pennsylvania. 1987. The Pennsylvania Code: Chapter 78. A

208 SGE01255 US EIA. 2015. Maps: Exploration, Resources, Reserves, and Production. Last 

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209 SGE01260 U.S. Geological Survey (USGS). 2014. National Produced Waters 

Geochemical Database v2.1 (Provisional). A

210 SGE01263 ERG. 2015. Memorandum to the Record Discussing Well Completion 

Reports. A

211 SGE01275 USGS. 2015. U.S. Geological Survey Assessments of Continuous 

(Unconventional) Oil and Gas Resources, 2000 to 2011. A

212 SGE01277 U.S. EPA. 2016. Profile of the Unconventional Oil and Gas Industry. EPA821-R-16-003. A

213 SGE01322 U.S. Department of Energy. 2015. US Tight Oil Production December 2015. 

U.S. Energy Information Administration (EIA). A
Chapter E—Reference Flags and List

168

Table E-1. Source List

ID DCN Source Citation 

Source 

Flag

214 SGE01330

US DOE, US DOI, US EPA. 2014. Federal Multiagency Collaboration on 

Unconventional Oil and Gas Research: A Strategy for Research and 

Development. Last accessed on May 17, 2016: 

http://unconventional.energy.gov/pdf/Multiagency_UOG_Research_Strategy.

pdf

A

215 SGE01331 STRONGER. 2016. Who We Are—STRONGER. C

216 SGE01332 U.S. EPA. 2016. Clean Watersheds Needs Survey 2012 Report to Congress. 

EPA 830-R-15-005. A

217 SGE01335 Baker Hughes. 2016. North American Rig Count Current Week Rig Count 

Summary. C

218 SGE01336 North Dakota Industrial Commission. 2015. North Dakota Drilling and 

Production Statistics Annual Production Reports: 1998-2014 Oil. A

219 SGE01337 North Dakota Industrial Commission. 2015. North Dakota Drilling and 

Production Statistics Annual Production Reports: 1998-2014 Gas. A

220 SGE01339 U.S. Department of Energy. 2014. AEO 2014 Market Trends Figure MT 53 

Data. U.S. Energy Information Administration (EIA). A

221 SGE01340 U.S. Department of Energy. 2014. AEO 2014 Market Trends Figure MT 44 

Data. U.S. Energy Information Administration (EIA). A

222 SGE01341 North Dakota Industrial Commission. 2016. North Dakota Injection Data. A

223 SGE01341.A01 Day, Ashleigh M. 2016. North Dakota Injection Data Copyright Clarification 

and Data Explanation. North Dakota Industrial Commission. A

224 SGE01344 CH2MHill. 2015. U.S. Onshore Unconventional Exploration and Production 

Water Management Case Studies. Prepared for Energy Water Initiative. B

225 SGE01345 Toxicity of acidization fluids used in California oil exploration DCN 

SGE01345 A

226 SGE01351

Weingartern, M., S. Ge, J.W., Godt, B.A. Bekins, and J.L. Rubinstein. 2015. 

High-rate injection 7 is associated with the increase in U.S. mid-continent 

seismicity. Science 348(6241), p. 1336-8 1340. June 19, 2015. doi: 

10.1126/science.aab1345. Available online at: 

http://www.ourenergypolicy.org/wp-content/uploads/2015/06/Science-2015-

Weingarten-1336-40.pdf

A

227 SGE01352 

Ohio Department of Natural Resources. 2012. Preliminary Report on the 

Northstar 1 Class II Injection Well and the Seismic Events in the 

Youngstown, Ohio, Area. (March). Available online at: 

http://oilandgas.ohiodnr.gov/portals/oilgas/downloads/northstar/reports/norths

tar-executive_summary.pdf

A
Chapter F—Appendices

169

Chapter F. APPENDICES

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

FDMS

DCN Title Description

Relevant TDD 

Section(s)

SGE01178 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

SGE01186 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

SGE01179 Data Compilation 

Memorandum for the 

Technical Development 

Document (TDD)

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

SGE01184 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

SGE01187 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

SGE01182 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

SGE01181 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

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 rule.

D.5
Chapter F—Appendices

170

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

FDMS

DCN Title Description

Relevant TDD 

Section(s)

SGE01183 Publicly Owned Treatment 

Works (POTW) 

Memorandum for the 

Technical Development 

Document (TDD)

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

SGE01277 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

SGE01185 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

SGE01180 Analysis of DI Desktop® Summarizes the DI Desktop® data source and 

where it is cited throughout the rule analyses.

B.3.2

SGE01177 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

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 A-1 Summary of State Regulations/Guidance No SGE00187, 

SGE00254, 

SGE00545, 

SGE00766, 

SGE00767, 

SGE00982, 

SGE00983

—

Figure B-1 Historical and Projected Crude Oil Production by 

Resource Type

No SGE01192 —

Figure B-2 Historical and Projected Natural Gas Production by 

Resource Type

No SGE01192 —

Figure B-3 Major U.S. Shale Plays (Updated April 13, 2015) No SGE01191 —

Figure B-4 Major U.S. Tight Plays (Updated June 6, 2010) No SGE00155 —

Figure B-5 UOG Extraction Wastewater No (Created by 

the EPA)

— —

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 SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)

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 SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)

Figure B-14 Projections of UOG Well Completions Yes SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)
Chapter F—Appendices

172

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 B-2 Active Onshore Oil and Gas Drilling Rigs by Well 

Trajectory and Product Type (as of October 9, 2015)

Yes SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)

Table B-3 UOG Potential by Resource Type as of January 1, Yes SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)

Figure C-1 UOG Extraction Wastewater Volumes for Marcellus 

Shale Wells in Pennsylvania (2004–2014)

Yes SGE01182 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 SGE01184 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 SGE01184 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 SGE01184 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 SGE01184 Unconventional Oil and Gas (UOG) 

Produced Water Volumes and 

Characterization Data Compilation

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 SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)

Table C-2 Fracturing Fluid Additives, Common Compounds, and 

Common Uses

No SGE00070, 

SGE00721, 

SGE00780, 

SGE00781, 

SGE00966

—
Chapter F—Appendices

173

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-3 Most Frequently Reported Additive Ingredients Used 

in Fracturing Fluid in Gas Wells from FracFocus 

(2011–2013)

No SGE00721 —

Table C-4 Most Frequently Reported Additive Ingredients Used 

in Fracturing Fluid in Oil Wells from FracFocus 

(2011–2013)

No SGE00721 —

Table C-5 Median Drilling Wastewater Volumes for UOG 

Horizontal and Vertical Wells in Pennsylvania

Yes SGE01182 Analysis of Pennsylvania Department of 

Environmental Protection’s (PA DEP) Oil 

and Gas Waste Reports

Table C-6 Drilling Wastewater Volumes Generated per Well by 

UOG Formation

Yes SGE01181 Unconventional Oil and Gas (UOG) 

Drilling Wastewater Memorandum

Table C-7 UOG Well Flowback Recovery by Resource Type and 

Well Trajectory

Yes SGE01184 Unconventional Oil and Gas (UOG) 

Produced Water Volumes and 

Characterization Data Compilation

Table C-8 Long-Term Produced Water Generation Rates by 

Resource Type and Well Trajectory

Yes SGE01184 Unconventional Oil and Gas (UOG) 

Produced Water Volumes and 

Characterization Data Compilation

Table C-9 Produced Water Volume Generation by UOG 

Formation

Yes SGE01184 Unconventional Oil and Gas (UOG) 

Produced Water Volumes and 

Characterization Data Compilation

Table C-10 Concentrations of Select Classical and Conventional 

Constituents in UOG Drilling Wastewater from 

Marcellus Shale Formation Wells

Yes SGE01181 Unconventional Oil and Gas (UOG) 

Drilling Wastewater Memorandum

Table C-11 Concentrations of Select Classical and Conventional 

Constituents in UOG Produced Water

Yes SGE01184 Unconventional Oil and Gas (UOG) 

Produced Water Volumes and 

Characterization Data Compilation

Table C-12 Concentrations of Bromide and Sulfate in UOG 

Drilling Wastewater from Marcellus Shale Formation 

Wells

Yes SGE01181 Unconventional Oil and Gas (UOG) 

Drilling Wastewater Memorandum
Chapter F—Appendices

174

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-13 Concentrations of Select Anions and Cations 

Contributing to TDS in UOG Produced Water

Yes SGE01184 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 SGE01181 Unconventional Oil and Gas (UOG) 

Drilling Wastewater Memorandum

Table C-15 Concentrations of Select Organic Constituents in 

UOG Produced Water

Yes SGE01184 Unconventional Oil and Gas (UOG) 

Produced Water Volumes and 

Characterization Data Compilation

Table C-16 Concentrations of Select Metal Constituents in UOG 

Produced Water

Yes SGE01181 Unconventional Oil and Gas (UOG) 

Drilling Wastewater Memorandum

Table C-17 Concentrations of Select Metal Constituents in UOG 

Produced Water

Yes SGE01184 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 SGE01181 Unconventional Oil and Gas (UOG) 

Drilling Wastewater Memorandum

Table C-19 Concentrations of Select Radioactive Constituents in 

UOG Produced Water

Yes SGE01184 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)

— —

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 (2008–2014)

Yes SGE01182 Analysis of Pennsylvania Department of 

Environmental Protection’s (PA DEP) Oil 

and Gas Waste Reports
Chapter F—Appendices

175

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-4 Active Disposal Wells and CWT Facilities Identified 

in the Appalachian Basin

No (Created by 

the EPA)

— —

Figure D-5 U.S. Injection for Disposal Volume and UOG 

Production over Time

No SGE01192;

SGE01128;

SGE01340;

SGE01339

SGE01322

—

Figure D-6 Injection for Disposal Volume and Crude Oil 

Production over Time in North Dakota

No SGE01337; 

SGE00182; 

SGE01128;

SGE01340

—

Figure D-7 Injection for Disposal Volume, Cumulative Bakken 

Wells Drilled, and Cumulative Disposal Wells Drilled 

in North Dakota

No SGE00557;

SGE00182;

SGE01128;

SGE01340

—

Figure D-8 Flow Diagram of On-the-Fly UOG Produced Water 

Treatment for Reuse/Recycle

No SGE00331 —

Figure D-9 Hypothetical UOG Produced Water Generation and 

Base Fracturing Fluid Demand over Time

Yes SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)

Figure D-10

UOG Extraction Wastewater Management Practices 

Used in the Marcellus Shale (Top: Southwestern 

Region; Bottom: Northeastern Region)

No SGE00579 —

Figure D-11 Number of Known Active CWT Facilities over Time 

in the Marcellus and Utica Shale Formation

Yes SGE01178 Analysis of Centralized Waste Treatment 

(CWT) Facilities Accepting UOG 

Extraction Wastewater

Figure D-12 Typical Process Flow Diagram at a POTW No SGE00602 —

Figure D-13 Clairton POTW: Technical Evaluation of Treatment 

Processes’ Ability to Remove Chlorides and TDS

Yes SGE01183 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical 

Development Document (TDD)
Chapter F—Appendices

176

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-14 McKeesport POTW: Technical Evaluation of 

Treatment Processes’ Ability to Remove Chlorides 

and TDS

Yes SGE01183 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical 

Development Document (TDD)

Figure D-15 Ridgway POTW: Annual Average Daily Effluent 

Concentrations and POTW Flows

Yes SGE01183 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical 

Development Document (TDD)

Figure D-16 Johnstown POTW: Annual Average Daily Effluent 

Concentrations and POTW Flows

Yes SGE01183 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical 

Development Document (TDD)

Figure D-17 California POTW: Annual Average Daily Effluent 

Concentrations and POTW Flows

Yes SGE01183 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical 

Development Document (TDD)

Figure D-18 Charleroi POTW: Annual Average Daily Effluent 

Concentrations and POTW Flows

Yes SGE01183 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical 

Development Document (TDD)

Figure D-19 Barium Sulfate Scaling in Haynesville Shale Pipe No SGE00768.A26 —

Figure D-20 THM Speciation in a Water Treatment Plant (1999–

2013)

No SGE00800 —

Table D-1 UOG Produced Water Management Practices Yes SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)

Table D-2 Distribution of Active Class II Disposal Wells Across 

the United States

Yes SGE01187 Analysis of Active Underground Injection 

for Disposal Wells

Table D-3 Distribution of Active Class II Disposal Wells on 

Tribal Lands

Yes SGE01187 Analysis of Active Underground Injection 

for Disposal Wells

Table D-4 Reuse/Recycle Practices in 2012 as a Percentage of 

Total Produced Water Generated as Reported by 

Respondents to 2012 Survey

No SGE00575 —

Table D-5 Reported Reuse/Recycle Criteria Yes SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)

Table D-6 Reported Reuse/Recycle Practices as a Percentage of 

Total Fracturing Volume

Yes SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)
Chapter F—Appendices

177

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-7 Number of CWT Facilities That Have Accepted or 

Plan to Accept UOG Extraction Wastewater

Yes SGE01178 Analysis of Centralized Waste Treatment 

(CWT) Facilities Accepting UOG 

Extraction Wastewater

Table D-8 Typical Composition of Untreated Domestic 

Wastewater

No SGE00167 —

Table D-9 Typical Percent Removal Capabilities from POTWs 

with Secondary Treatment

No SGE00600 —

Table D-10 U.S. POTWs by Treatment Level in 20 No SGE00603; 

SGE01332

—

Table D-11 POTWs That Accepted UOG Extraction Wastewater 

Directly from Onshore UOG Operators

Yes SGE01183 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical 

Development Document (TDD)

Table D-12 Percentage of Total POTW Influent Wastewater 

Composed of UOG Extraction Wastewater at POTWs 

Accepting Wastewater from UOG Operators

Yes SGE01183 Publicly Owned Treatment Works (POTW) 

Memorandum for the Technical 

Development Document (TDD)

Table D-13 Summary of Studies About POTWs Receiving Oil and 

Gas Extraction Wastewater Pollutants

No (Created by 

the EPA)

— —

Table D-14 Clairton Influent Oil and Gas Extraction Wastewater 

Characteristics

No SGE00748 —

Table D-15 Trucked COG Extraction Wastewater Treated at 

McKeesport POTW from November 1 Through 7, 

2008

No SGE00745 —

Table D-16 McKeesport POTW Removal Rates Calculated for 

Local Limits Analysis

No SGE00745 —

Table D-17 Constituent Concentrations in UOG Extraction 

Wastewater Treated at the McKeesport POTW Before 

Mixing with Other Influent Wastewater

No SGE00525 —

Table D-18 McKeesport POTW Effluent Concentrations With and 

Without UOG Extraction Wastewater

No SGE00525 —
Chapter F—Appendices

178

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-19 Charleroi POTW Paired Influent/Effluent Data and 

Calculated Removal Rates

No SGE00751 —

Table D-20 Franklin Township POTW Effluent Concentrations 

With and Without Industrial Discharges from the TriCounty CWT Facility

No SGE00525 —

Table D-21 TDS Concentrations in Baseline and Pilot Study 

Wastewater Samples at Warren POTW

No SGE00616 —

Table D-22 EPA Region 5 Compliance Inspection Sampling Data No SGE00616 —

Table D-23 Inhibition Threshold Levels for Various Treatment 

Processes

No SGE00602 —

Table D-24 Industrial Wastewater Volumes Received by New 

Castle POTW (2007–2009)

No SGE00554 —

Table D-25 NPDES Permit Limit Violations from Outfall 001 of 

the New Castle POTW (NPDES Permit Number 

PA0027511)

No SGE00612, 

SGE00620

—

Table D-26 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 —

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, 2013 Yes SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)

Table F-4 UOG Resource Potential: Tight as of January 1, 2013 Yes SGE01179 Data Compilation Memorandum for the 

Technical Development Document (TDD)

a—Unless otherwise noted, figures and/or tables not included in a supporting memorandum were taken directly from a source without calculation or interpretation. 
Chapter F—Appendices

179

Table F-3. UOG Resource Potential: Shale as of January 1, 2013

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

Devonian Shale gas 0.000 0.061 0 23,700 388,500

Marcellus Shale gas 0.003 1.581 300 148,700 94,000

Utica

Shale gas 0.002 0.470 200 53,100 112,900

Shale oil 0.043 0.092 700 1,500 16,300

Illinois New Albany Shale gas 0.000 1.188 0 29,100 24,500

Michigan Antrim Shale gas 0.000 0.120 0 12,700 105,800

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 3.588 0 73,300 20,400

Western Gulf

Eagle Ford

Shale gas 0.191 1.437 6,400 48,200 33,500

Shale oil 0.123 0.227 3,900 7,200 31,700

Pearsall Shale gas 0.000 0.676 0 4,900 7,200

Tuscaloosa Shale oil 0.112 0.021 3,200 600 28,600

Woodbine Shale oil 0.122 0.061 600 300 4,900

3—Midcontinent

Anadarko Cana Woodford

Shale gas 0.028 1.590 200 11,500 7,200

Shale oil 0.036 0.961 100 2,700 2,800

Arkoma

Caney Shale gas 0.000 0.973 0 3,100 3,200

Fayetteville Shale gas 0.000 0.899 0 20,400 22,700

Woodford Shale gas 0.000 1.342 0 6,300 4,700

Black Warrior Chattanooga Shale gas 0.000 0.968 0 1,600 1,700

4—Southwest

Fort Worth Barnett Shale gas 0.003 0.296 200 17,500 59,000

Permian

Wolfcamp Shale oil 0.085 0.347 6,100 24,900 71,800

Barnett-Woodford Shale gas 0.000 1.181 0 12,400 10,500

Avalon/BoneSpring Shale oil 0.118 0.367 2,900 9,000 24,500

5—Rocky Mountain

Denver Niobrara Shale oil 0.012 0.078 400 2,700 34,600

Greater Green River Hilliard-Baxter-Mancos Shale gas 0.000 0.293 0 10,500 35,800

5—Rocky Mountain Montana Thrust Belt All tight oil plays Shale oil 0.102 0.068 600 400 5,900
Chapter F—Appendices

180

Table F-3. UOG Resource Potential: Shale as of January 1, 2013

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

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 0.752 0 9,300 12,400

Williston

Gammon Shale gas 0.000 0.433 0 3,300 7,600

Bakken Shale oil 0.147 0.078 22,700 12,100 154,800

6—West Coast

Columbia Basin Centered Shale gas 0.000 1.620 0 12,200 7,500

San Joaquin/Los 

Angeles Monterey/Santos Shale oil 0.030 0.151 600 3,000 19,900

Sources: 179 DCN SGE01179

Abbreviations: EUR—estimated ultimate recovery (per well); MMbls—million barrels; Bcf—billion cubic feet of gas; TRR—technically recoverable resources

Table F-4. UOG Resource Potential: Tight as of January 1, 2013

EIA Region 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 0.002 0.058 400 12,400 213,800

Tuscarora Tight gas 0.000 0.724 0 4,400 6,100

Michigan Berea Sand Tight gas 0.000 0.110 0 6,600 60,000

2—Gulf Coast

TX-LA-MS Salt Cotton Valley Tight gas 0.008 1.323 800 139,300 105,300

Western Gulf

Austin Chalk Tight oil 0.061 0.116 5,500 10,400 89,700

Buda Tight oil 0.057 0.109 2,000 3,800 34,900

Olmos Tight gas 0.009 1.162 200 25,400 21,900

Vicksburg Tight gas 0.038 0.980 100 2,600 2,700

Wilcox Lobo Tight gas 0.000 1.403 0 12,800 9,100

3—Midcontinent Anadarko

Cleveland Tight gas 0.038 0.384 100 1,000 2,600

Granite Wash Tight gas 0.039 0.579 600 8,800 15,200

Red Fork Tight gas 0.000 0.459 0 900 2,000
Chapter F—Appendices

181

Table F-4. UOG Resource Potential: Tight as of January 1, 2013

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

4—Southwest Permian

Abo Tight gas 0.695 0.149 7,000 1,500 10,100

Canyon Tight gas 0.017 0.209 900 10,900 52,200

Spraberry Tight oil 0.131 0.152 10,600 12,300 80,900

5—Rocky Mountain

Denver Muddy Tight gas 0.002 0.180 100 11,500 63,900

Greater Green River All tight oil plays Tight oil 0.126 0.014 900 100 7,100

North Central 

Montana Bowdoin-Greenhorn Tight gas 0.000 0.078 0 100 1,300

Paradox Fractured Interbed Tight oil 0.534 0.427 1,000 800 1,900

San Juan

Dakota Tight gas 0.000 0.258 0 3,800 14,700

Mesaverde Tight gas 0.000 0.548 0 6,800 12,400

Pictured Cliffs Tight gas 0.000 0.262 0 100 400

SW Wyoming

Fort Union-Fox Hills Tight gas 0.007 0.792 100 12,000 15,200

Frontier Tight gas 0.018 0.312 400 7,100 22,800

Lance Tight gas 0.022 1.152 400 21,200 18,400

Lewis Tight gas 0.006 0.312 200 9,700 31,100

All tight oil plays Tight oil 0.154 0.014 1,100 100 7,100

Uinta-Piceance

Iles-Mesaverde Tight gas 0.000 0.372 0 11,900 32,000

Wasatch-Mesaverde Tight gas 0.029 0.568 500 9,800 17,300

Williams Fork Tight gas 0.006 0.692 100 11,200 16,200

All tight oil plays Tight oil 0.053 0.105 100 200 1,900

Williston Judith River-Eagle Tight gas 0.000 0.154 0 900 5,800

Wind River Mesaverde/Frontier 

Shallow Tight gas 0.018 1.131 100 6,400 5,700

Sources: 179 DCN SGE01179

Abbreviations: EUR—estimated ultimate recovery (per well); MMbls—million barrels; Bcf—billion cubic feet of gas; TRR—technically recoverable resources
Chapter F–Appendices

182

Source: The EPA generated this figure using data from 44 DCN SGE00414.

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

Marcellus and Barnett Shale Formations

Marcellus Shale

Barnett Shale