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 Oi l and Gas Extraction Point Source Category

EPA

- 82 0

- R

- 1 6

- 003

JUNE 201 6

U.S. Environmental Protection Agency Office of Water (4303T) Washington, DC 20460Acknowledgements 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

- 1000Table of Contents



### iv TABLE OF CONTENTS

Page

C HAPTER 

### A. I NTRODUCTION AND 

### B ACKGROUND



### ................................ ................................ ......... 1

1 Introdu ction

................................ ................................ ................................ ......................... 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 Nationa l 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

C HAPTER 

### B. S COPE AND 

### I NDUSTRY 

### D ESCRIPTION



### ................................ ................................ ..... 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

C HAPTER 

### C. U NCONVENTION AL 

### O IL AND 

### G AS 

### E XTRACTION 

### W ASTEWATER 

### V OLUMES

AND 

### C HARACTERISTICS



### ................................ ................................ ......................... 40

1 Fracturing Fluid Characteristics

................................ ................................ ........................ 41 1.1 Base Fluid Compositi on

................................ ................................ ........................ 42 1.2 Additives

................................ ................................ ................................ ............... 43 1.3 Fracturing Fluids

................................ ................................ ................................ ... 47

2 UOG Extraction Wa stewater Volumes

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

........... 48 2.2 UOG Produced Water Volumes by For mation

................................ ..................... 53Table 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

C HAPTER 

### D. UOG E XTRACTION 

### W ASTEWATER 

### M ANAGEMENT AND 

### D ISPOSAL 

### P RACTICES



### ................................ ................................ ................................ ............. 82

1 Overview of UOG Extraction Wastewater Management and Disposal Pr actices

............ 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

C HAPTER 

### E. R EFERENCE 

### F LAGS AND 

### L IST



### ................................ ................................ ............... 155

C HAPTER 

### F. A PP ENDICES



### ................................ ................................ ................................ ......... 169List of Tables



### vi LIST OF TABLES Page

Table A

- 1. Summary of State Regulations/Guidance

................................ ................................ .... 10

Tab le 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 i n 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 Produc ed 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 an d 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 Constit uents 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 C onstituents in UOG Produced Water

.................... 73List 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, Lake s, 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 L ands (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. P OTWs 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 POTW s 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

....................... 128List 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 C alculated 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 b y 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

Tab le E

- 1. Source List

................................ ................................ ................................ ................. 155

Table F

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

................................ ................................ ................................ ......................... 169

Table F

- 2. Crosswal k Between TDD and Supporting Memoranda

................................ ............. 171

Table F

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

................................ .............. 179

Table F

- 4. UOG Resou rce Potential: Tight as of January 1, 2013

................................ .............. 180List 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

F igure 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 an d 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 Concentrat ions 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)

................................ ................................ ........................... 87List 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 Pro duction over Time

...................... 93

Figure D

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

................................ ................................ ................................ .......................... 94

Figure D

- 7. I njection 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
R euse/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 Chloride s and TDS

................................ ................................ .................. 126

Figure D

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

................................ ................................ ................................ ............. 130

Figure D

- 16. Johnstown PO TW: 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 Produ ced Water from the Marcellus and Barnett Shale Formations

................................ ................................ ... 182Abbreviations



### xi A BBREVIATIONS

AO Administrative Order
API American Petroleum Institute
B cf billion cubic feet
BDL below method detection limit BOD 5 

### biochemical oxygen demand
BP D barrels per day
BPT best practicable control technology currently available CaCO 3 

### calcium carbonate CBM coalbed methane Ci c urie CIU categorical industrial user COD chemical oxygen demand COG conventional oil and gas CWA Clean Water Act CWT c entraliz ed w aste treatment DBP disinfection byproduct
DMR d ischarge m onitoring r eport DOE Department of Energy
EIA Energy Information Administration ELGs Effluent Limitations Guidelines and Standards
EPA U.S. Environmental Protection Agency
EUR estimated ultimate reco very 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 Nati onal 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 publ icly 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 org anic carbon
TRR technically recoverable resourceAbbreviations



### 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 ProtectionGlossary



### xiii GLOSSARY 1



### Biochemical oxygen dema nd (BOD 5 

### ) 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 offs ite. 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 inject s 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

asso ciated with oil and gas production. Class II UIC enhanced recovery well A well that inject s 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 C rude oil 3 

### and natural gas 4 

### 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 wellbor e

. 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 o nly 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 di esel fuels are used) from regulation under the UIC program (SDWA S ection 1421(d)(1)). Because there are currently no Class II permits for hydraulic fracturing activities, E PA 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 hyd raulic 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. H y draulic 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 f racturing b ase f

luid The primary component of fracturing fluid to which proppant (sand) and chemicals are added. Hydraulic fracturing b ase 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 proc ess. 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 o f the well

, after the initial flowback process

, which can include increasing amounts of formation water. Naturally occurring radioactive material (NORM) M aterial that contains radionuclides at concentrations found in

nature

. See also technologically

- enhan ced radioactive material (TENORM)

. Non

- TDS removal technologies T echnologies 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 fo rm 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 Th e 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 t he 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 downhol e 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 fra cture 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 in cludes 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

op erations. 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 T echnologies 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 radioa ctive 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 min erals dissolved in water. Standard Method 2540C

- 1997, ASTM D5907

- 03, and USGS I

1750

- 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 6 0

- minute period. Standard Method 2540 D

- 1997, ASTM D5907

- 03, and USGS I

3765

- 85. Unconventional oil and gas (UOG) C rude oil 5 

### and natural gas 6 

### 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 unconventiona l oil and gas extraction ( including, but not limited to, drilling muds, drill cuttings, produced sand, produced water).

5 Crude oil includes “le ase 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. I NTRODUCTION AND 

## B ACKGROUND



### 1 I NTRODUCTION



### 1.1 P urpose and Summary of the Rule

The EPA is publishing a final Clean Water Act (CWA) regulati on 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 unconventio nal 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 the se 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

t reatment); 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 industr y practices for onshore UOG extraction facilities . T herefore, 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 reg ulations

. S ubsequent 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 envir onmental 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 referenc e ID number s ( e.g ., 73 ) and document control number s ( DCN s ) (e.g., DCN SGE00586 )

. Information presented in this document was taken from existing data sources, including state and federal agency databases, journal a rticles 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

- r eviewed 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 notChapter A

— Introduction



### 2 include citation information, such as some newspaper articles and conference presentations. F or 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 include s two tables with information about where to find m ore 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 su pporting memorand um includes a section about QC activities related to the data and/or analyses it discusse s

. Table F

- 1 also lists the relevant TDD sections associated with each memorandum. Table F

- 2 conta ins 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 R EGULATORY 

### B ACKGROUND



### Wastewater discharges from crude oil 7 

### and natural gas 8 

### extraction facilities are subject to federal regulation

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

, which are federal regulations that control pollu tants 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 O il and G as E xtraction p oint s ource c ategory (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 t he 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 disch arge of pollutants from a point source to waters of the U nited S tates, 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 t wo

- 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 quali ty 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 U nited S tates

.
Direct dischargers (those discharging directly to surface waters) must comply with effluent limitations in NPDES permits. Technol ogy

- 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 n ot 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 categorie s 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 [ BOD 5 

### ] , fe cal coliform, and pH), as outlined in CWA Section 304(a)(4) and 40 CFR 401.16

• T oxic pollutants (e.g., metals such as arsenic, mercury, selenium, and chromium; and organic pollutants suc h 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

• N onconventional pollutants, w hich are those pollutants that are not categorized as conventional or toxic (e.g., amm onia

- 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) an d (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 ty pes 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 t echnologies, 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 B est 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 limi tations on July 9, 1986 (51 Fed. Reg. 24974). Section 304(a)(4) designates the following as conventional pollutants: BOD 5 

### , total suspended solids (TSS), fecal coliform, pH, and any additional pollutants defined by the Administrator as conventional. The Adm inistrator 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 S ection 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 ( CW A 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 P erformance 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, t he 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 Source s (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 designe d 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 li mitations 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 (3 rd 

### Cir. 1986). Similarly, inChapter A

— Introduction



### 5 40 CFR 403.5(b) notes eight categories of pollutant discharge prohibi tions :

1. P ollutants 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. A ny 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 interfe rence
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 caus e acute worker health and safety problems

8. Any trucked or hauled pollutants, except at discharge points designated by the POTW 

### establishing pretreatmen t 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)

T o implement the National Pretreatment Program

, the EPA dev eloped t he General Pretreatment Regulations to protect POTW operations. As described in Chapter 2 of the EPA’s introduction to the program ( 19 DCN SGE 00249 )

, these regulations apply to all non

- domestic

sources that introduce pollutants into a POTW. N on

- domestic sources are referred to as i ndustrial

u sers (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 mill s), the EPA established a category called s ignificant IU s (SIU s ). 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 th e 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) re quires 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 wil l 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 A pproval A uthority 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 o r 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

• Ca tegorical pretreatment standards

• Local limits

Prohibited discharge standards. The prohibited discharge standards are not technology

based and are intended to prevent the POTW from receiving pollutants(s) that may cause pass through or interference. All IUs

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

— are subject to the general and specific prohibitions identified in 40 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 a re prohibited from pass

throu gh by the general prohibitions

.

• Specific pro hibitions 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 pretr eatment 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 discharge s . IUs subject to categorical pretreatment standards are known as CIUs. The EPA establishes tw o types of categorical pretreatment standards for CIUs: PSES and PSNS.

Local limits. Developed by i ndividual POTWs , local limits address the specific needs and concerns of the POTW, its sludge, and its receiving waters. Typically, POTWs develop local limit s for di scharge s 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 r emoved 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 SGE 00602 )

.
Responsibilities of Control Authorities and IUs

The Control Authority ( POTW , state

, or EPA) controls the discharges from the IU through an individual control mechanism , ofte n 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, a nd the character and volume of pollutants from IUs introduced to the POTW

• C ommunicating applicable standards and requirements to IUs

• Receiving and analyzing reports

• Inspecting IUs, including annual inspections of SIUs

• S ampling in certain cases

• Investigatin g noncompliance with pretreatment standards and requirements

• R eporting to the A pproval A uthority ( 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 A pproval A uthority

, w hich is also responsible for overseeing implementation and enfor cement of the programs ( 19 DCN SGE00249 ). The Approval Authority is t he director in a NPDES a uthorized s tate with an approved state pretreatment program, or the appropriate EPA regional administrator in a non

- NPDES a uthorized

s tate or NPDES state without an approved state pretreatment program. A s tate 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 SGE 00249) , 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 collect ion 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 wa stewater 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 requirement s 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 des ignated by the POTW. As explained in Introduction to the National Pretreatment Program ( 19 DCN SGE 00249), 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 (TSDF s ) 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 (s ee 40 CFR part 260).

2.3 Oil and Gas Ex traction ELG Rulemaking History

The EPA first promulgated the Oil and Gas Extraction ELGs ( 40 CFR part 4 35 ) in 1979, and substantially amended the regulation in 1993 ( O ffshore ), 1996 ( C oastal ), and 2001 (Synthetic- Based Drilling Fluids ). The Oil and Gas Extraction industrial category is subcategorized 11 

### in 40 CFR part 435 as follows:

• Subpart A: Offshore

• Sub part 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 u nderground injection technologies, the BPT

- based limitations for direct dischargers require zero discharge of pollutants to waters of the U nited S tates . 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 U nited S tates has occ urred 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 p art 437, the Centralized Waste Treatment category (see Section D. 4 for more information).

11 Subpart B is reserv ed.Chapter A

— Introduction



### 9 Subpart C: Onshore Subcategory
Applicability. As set forth in 40 CFR 435.30, s ubpart 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 s ubparts

, including s ubpart 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, dril ling muds, drill cuttings, and produced sand).

Subpart E: Agricultural and Wildlife Use Subcategory
Applicability. As set forth in 40 CFR 435.50, s ubpart E applies to onshore facilities located in the continental United States and west of the 98th meridia n 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 t he term “use in agricultural or wildlife propagation” means that two t hings are true :

• T he produced water is of good enough quality to be used for wildlife or livestock watering or other agricultural uses

.

• T he produced water is actually put to such use during periods of discharge

. Direct discharge requirements. Subpart E pr ohibits 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). T herefore, the only allowable discharge under this subpart is produced water 12 

### that meets the “good enough quality” and actual use requirements described above , with an oil and grease concentration not exceeding 35 mg/L.

3 S TATE 

### P RETREATMENT 

### R EQUIREMENTS



### In a ddition 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 g uidance related to UOG extraction wastewater discharges to POTWs.

12 Produced water is not defined in s ubpart C ( o nshore) or s ubpart E ( a gricultural and w ildlife u se). For s ubparts A ( o ffshore) and D ( c oastal), produced water is defined as “ the water (brine) brought up from the hydrocarbon

- bearing strata during the e xtraction 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

P A EPA Region 3;
PA DEP 25 PA Code Ch. 95.10 ( 14 SGE00187; 148 SG E00982; 63 SGE00545) The Pennsylvania Code, amended in 2010, st ates 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 ) , t he 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 ind irect 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 de scribes 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 SG E00767) A WV DEP guidance document “ discourages POTWs from accepting wastewater from oil and gas operations

. ” This document groups coalbed methan e 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 SG E00767 )

.

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 regulation s 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 “exemp t 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 oil

and

- gas

- producing states 15



### regarding the use of POTWs for discharging production fluids including flowback water. Of the states resp onding, 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 ot herwise 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



### pu blished voluntary gui delines to help states develop effective oil and gas regulatory programs for production wastes ( 197 DCN SGE01208).

4 R ELATED 

### F EDERAL 

### R EQUIREMENTS


### 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 p rohibit 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 w ells (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 w ith a Class II disposal well permit.

15 Alabama, Alaska, Arkansas, California, Colorado, Florida, Illinois, India na, 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 docume nting the environmental regulations associated with the exploration, development

, and producti on of crude oil and natural gas ( 214 DCN SGE01331).

### Chapter B

— S cope and Industry Description

12 

## Chapter B. S COPE AND 

## I NDUSTRY 

## D ESCRIPTION



### 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 Extrac tion point source category to address discharges from UOG extraction facilities to POTWs

. To provide context for discussions of UOG extraction wastewater volume s and characteristics ( Chapter C ) and management and disposal pract ices ( Chapter D ), this chapter contains :

• An o verview of UOG and the scope of this rulemaking

• A discussion of the UOG w ell d evelopment p rocess , with a focus on the processes that generate UOG extraction wastewater

• A description of the i ndustry , i nclud ing h istoric al and c urrent UOG d rilling and completion a ctivity and total UOG r esource p otential

Relevant national economic information about the UOG industry is included in a separate document in the record, titled Profile of the Un conventional Oil and Gas Industry

, ( 212 DCN SGE 0 1277 ).

1 U NCONVENTIONAL 

### O IL AND 

### G AS



### 1.1 Overview of Oil and Gas Resources

The United States has developed oil and gas resources since 1821 ( 1 D CN 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 )

. T he 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 EI A’s 201 5 AEO projects that, in the next 30 years, the majority of the country’s crude oil 17 

### and natural gas 18



### will come from unconventional resources ( 194 DCN SGE 0 1192 ). Figur e B

- 1 and Figure B

- 2 show the historic al and future profiles of conventional oil and gas ( COG ) and UOG production in the U nited S tates by resource type according to the EIA. 19 

### C oalbed methane (C BM ) and COG

are incl uded 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 sh ale as “tight oil

. ” As explained in Section B. 1

, this TDD differentiates between shale and tight oil.

### Chapter B

— S cope and Industry Description

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



### Figure B

- 1

. Historic al and Projected Crude Oil Production by Resource Type 20

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



### Figure B

- 2

. Historic al an d Projected Natural Gas Production by Resource Type 21

20 The EIA reported these data as “tight oil” production but stated that they include production from both shale oil formation s (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 convention al 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 reope n 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 futur e 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 operator s ’ 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 “c rude o il and natural gas produced by a well drilled into a shale and/or tight format ion (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 source s:

• A report by the Energy Water Initiative (EWI) 22 

### titled U.S. Onshore Unconventional Exploration and Production Water Management Case Studies defines unconventional as “O il 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 ).

• T he 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 SGE 01330).

• The U .S. Geolog ical 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, categorize s resources into four distinct reservoir categories: “shale gas, coalbed gas, tight gas, and continuous oil ” ( 211 DCN SGE0 1275).

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

— S cope and Industry Description

15 — USGS’s 2015 report titled Trends in H ydraulic F racturing

... in the U nited States from 1947 t hrough 2010

— Data Analysis and Comparison to the Literature state s 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 es pecially 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 “T he 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 r esources and formations within those state s

. 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 doc umentation from these calls and site visits show s 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 oper ators’ k nowledge 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, unconvent ional 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 n omenclature recognized by the Arkansas Geological Survey or the U nited 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 SG E01251

OK 165:10 -3- 28. (b)(20) “ Unconventional reservoir ” shall mean a common source of supply that is a shale or a coal bed. “Unconventional reservoir” shall also mean any other common source of supply designated as such b y 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 exce pt 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

p urpose of or to be used for the production of natural gas fr om an unconventional formation.
Conventional formation

— A formation that is not an unconventional formation. 207 SGE01253

### Chapter B

— S cope and Industry Description

17 — “... [H] ydraulic fracturing in tight sands and shale is very similar. However, a few minor differences includ e: 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) survey ed 206 oil and gas operators regarding the outlook for domestic unconventional resources. S o me 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 receive s water from s hale g as operations. Figure 1 of the North Star conference call notes shows all the “Pennsylvania Marcellus Shale Ga s 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 format ions 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 t ype (e.g., shale oil) ( 24 DCN SGE00280 ).

• In a conference call with the EPA

, BLX, Inc., indicated that it know s 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 act ive in the Anadarko basin in Oklahoma and Barn ett 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

- goin g recycling pilot project for produced water from a conventional formation.” The conference call took place on Novem ber 5, 2012 ( 100 DCN SGE00695).

• During the 2012 Tight Oil Water Management Summit Conference in De nver, 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 SGE 00305.A10).

• During the 201 4 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 a s either “shale play,” “natural gas,” or “oil and natural gas” ( 160 DCN SGE010 17.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 complet ing 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., hyd raulic 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 memorand um 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 

### in to a national database of wells called Drillinginfo (DI) Desktop ® 

### ( 176 DCN SGE01170). DI is an oil and gas researc h 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

T he final rule establishe s requirements for wastewater discharges from UOG extraction fac ilities 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) , t he EPA was able to identify shale and tight formations in the United States using publicly- available sources . The list of shale and/or tight formation s 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 separa ted into the following: Conventional Fields, Shale Gas and Oil Plays ( 193 DCN SGE01191), Major Tight Gas Plays, which includes tight gas and tight oil 29 

### ( 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 diss eminated 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 SGE0015 5) 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

— S cope and Industry Description

19 DCN SGE001 55), C oalbed Methane Fields, and Offshore Fields ( 208 DCN SGE 01255). Figure
B

- 3 and Figure B

- 4 sh ow the UOG resources, resp ectively, 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). F ormation

name s 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

— S cope and Industry Description

20 Source: 193 DCN SGE01191



### Figure B

- 3 . Major U.S. Shale Plays (Updated Apri l 13, 2015)

### Chapter B

— S cope and Industry Description

21 Sour ce: 11 DCN SGE 00155



### Figure B

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

### Chapter B

— S cope and Industry Description

22 2 I NDUSTRY 

### D ESCRIPTION 

### : UOG W ELL 

### D EVELOPMENT 

### P ROCESS


### UOG well developmen t includes the following process es : exploration, well pad construction, well drilling and construction, w ell treatment and completion (e.g., stimulation) 31



### , and production. Before UOG well development , operators must obtain surface use agreements, mineral l eases, 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 a re 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

m aterials are typically transported to the well pad by truck, but fracturing base fluid (e.g., fresh water, recycled UOG produced water ) may be transpo rted via truck or temporary piping ( 92 DCN SGE 00625; 95 D CN SGE 00635; 21 DCN SGE 00275 ).

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 , w hich 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 t hat 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—D rilling mud is the circulating fluid (mud) used in the rotary drilling of wells to clean and condition the hole and to counterbalanc e formation pressure. b—D rilling 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 Wastew ater

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 wastewate r 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 conduct s 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 productio n data —analysis of existing production data from nearby wells.

• Ex isting drilling data logs

— analysis of data logs from drilling existing wells.

• Seismic data

— anal ysis 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.

G eologists analyze the geological data and recomm end 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 availabili ty, state restrictions for siting, or surface access restriction s from land owners. In these situations, operators find the closest possible drilling location that will still allow for the effective produc tion of crude oil and/or natural gas from the well ( 95 DCN SGE00 635 ).

2.2 UOG Well Drilling and Construction

Drilling occurs in two phases: e xploration and development. Exploration involv es 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 constr ucted, 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 wel ls by well trajectory as of 2014.

• Vertical d rilling 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 SGE 00527). For shale wells , vertical drilling is typically used by operators during the exploration phase of well development ( 95 DCN SGE 00635), in shallow formations (e.g., Antrim shale), or by small en tity operators who may be unable to make large investments in horizontal wells ( 25 DCN SGE 00283). Vertical drilling has historically been used for COG wells.

• Directional d rilling 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 whe n a well pad cannot be constructed directly above the resource (e.g., in rough terrain). Directional drilling is common in conventional and un conventional tight formations that occur as accumulations as illustrated in Section B. 1

.

• Horizontal d rilling , 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 SGE 00593; 91 DCN SGE 00623). Horizontal drilling is the most common method for continuous UOG formations ( 37 DCN SGE 00354; 1 DCN SGE 00010 ).

### Chapter B

— S cope and Industry Description

25 Source: 76 DCN SGE 00593 (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 SGE 00625; 95 DCN SGE 00635; 21 DCN SGE 00275 ) . 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 configuration s give operators access to more of the produci ng formation and reduce surface disturbance ( 37 DCN SGE 00354; 2 DCN SGE 00011). Operators may drill one or two horizontal wells on a well pad initially and move on to the ne xt pad. When this happens, the operator typically comes back to drill the remaining wells on the pad after the initial wells show favorable economic conditions 32



### and production ( 95 DCN SGE00 635 )

.
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 ca sing, and cementing succeeding sections of the well ( 95 DCN SGE 00635 ) . During drilling, operators inject d rilling 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 d rilling fluids depending on which portion of the well they are drilling ( 183 DC N SGE01181 ):

• Compressed gases

. During th e 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 d ry air, nitrogen gas, mist, foam

, and aerated fluids

.

32 Favorable conditions include suffic ient oil and/or gas prices, available drilling rigs, available fracturing crews, and permits.

### Chapter B

— S cope and Industry Description

26 • Water

- based

. At several thousand feet deep, operators typically use water

- based drill ing 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 dri lling 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 associat ed 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 dri lling 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 dies el and mineral oils. Synthetic

- oil

- based fluids have been referred to

as more environmentally friendly 34 

### 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 . Typicall y, d rilling 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 facilit y , injection for disposal ) ( 169 DCN SGE01125 ; 95 DCN SGE 00635)

.
Well drilling and construction typica lly 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 UO G operators become more f amiliar and efficient at drilling in a UOG form ation ( 201 DCN SGE 0 1234 ; 95 DCN SGE 00635; 52 DCN SGE 00516 ). 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 volu me 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 m ud (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

*T he 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 SGE 00984 ). The UOG w ell 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 injec ted 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 con tain 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., Marcel lus)

These well completion reports are documented in a separate memorand um to the record, titled Memorandum to the Record Discussing Well Completion Reports ( 210 DCN SGE01263)

. The following two subsections describ e 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 co mbination of fracturing and acidization ( 146 DCN SGE 00966 ; 225 DCN SGE01345 ). The most common well stimulation technique for UO G 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 complete d with open- hole techniques that allow the oil and/or gas resources to flow naturally ( 35 DCN SGE 00345; 61 DCN SGE 00533 ).

O perators 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. T he number of stages depends on lateral len gth. Because horizontal laterals are 1,000 to 5,000 feet long, o perators 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 t o complete ( 15 DCN SGE 00239; 169 DCN SGE01125 ). The following processes are performed for each stage :

• Perforation. Operators lower a perforation gun into the stage using a l ine wire. The perforation gun releases an explosive charge to create holes that penetrate a bout 1 foot into the formation rock in a radial fashion. These perforations create a starting point for the hydraulic fractures.

• Hydraulic f racturing

. Operators inje ct 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 fractur e. 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

— S cope 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 com pleted.

Source : 82 DCN SGE 00604



### Figure B

- 8 . Hydraulic Fracturing Schematic

T he components of fracturing fluid (i.e., base fluid

, sand, chemical additives) are typically stored on the well pad before hydraulic fracturing begins. ( S ee 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 barrel s ) in size (see Figure B

- 11 ) ( 24 DCN SGE 00280; 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 SGE 00280 ; 195 DCN SGE01206 ). Operators typically have sand trucks and pump trucks onsite during the hydraulic fracturing process. The sand trucks contain th e 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 th e pad is pumped downhole, proppant is introduced to the fracturing fluid for the additional stages.

### Chapter B— Scope and Industry Description

30 Sour ce: 21 DCN SG E00275



### 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 pr essure 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 SGE 00635 ). The flowback co nsists 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 us ed 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 i n the beginning of the flowback

process and f lowback rates decrease as the wel l goes into the production phase. O perators 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 t ransported via trucks with capacities of about 4,200 to 5,000 gallons (100 to 120 barrel) or via pipe ( 95 DCN SGE00635 ).

### Chapter B

— S cope 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 used 41 

### or the oil may be recovered from the flowback

w ater after it is transported offsite.

Source: 92 DCN SGE 00625



### 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 SGE 00622; 75 DCN SGE 00592; 27 DCN SGE 00286). At some wells, the majority of fracturing fluid may be recovered within a few hours ( 1 DCN SGE00010 ; 2 DCN SGE00011 ; 90 DCN SGE 00622; 75 DCN SGE 00592; 27 DCN SGE 00286). A 2009 report published by the Ground Water Protection Council and ALL Consulting stated that operators

recov er between 10 and 70 percent of the fracturing fluid that they inject down the wellbore ( 1 DCN SGE00010 ; 75 DCN SGE 00592; 27 DCN S GE 00286). Section C. 3.1 pro vides more details on flowback generation rates over time and fracturing fluid recovery p ercentages 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 part s 60 and 63).

41 Operators sometimes use chemicals du ring the oil/water phase separation process.

### Chapter B— Scope and Industry Description

32 Source: 92 DCN SGE 00625



### Fi gure B-11. Fracturing Tanks

2.4 UOG Production

After the flowback process, the well enters the production phase . During th is phase, UOG wells produce crude oil , condensates, and/or natural gas and water. This wat er, called “ long- term
p roduced 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 SGE 00592). Long- term p roduced 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 t he 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 re move 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 SGE 00280 ; 21 DCN SGE00275 ; 96 DCN SGE 00636). 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 SGE 00635; 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 yea rs ( 27 DCN SG E00286 ).

### Chapter B

— S cope and Industry Description

33 So urce: 21 DCN SGE00 275



### Figure B

- 12 . Produced Water Storage Tanks

3 I NDUSTRY 

### D ESCRIPTION 

### : UOG W ELL 

### D RILLING AND 

### C OMPLETION 

### A CTIVITY


### The following subsections describe historic al , current, and projections of future UOG drilling activity , incl uding:

• Historical and current UOG well drilling activity

• Total e stimated UOG resource potential

• Current and p rojections of future UOG well completions

3.1 Historical and Current UOG Drilling Activity

Since 2000, hydraulic fracturing coupled with drilling dir ectional 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 oilfi eld 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

— S cope and Industry Description

34 Figure B

- 13 shows Baker Hughes’ estimates of total number of active drilling rigs in the U nited S tates between January 2 000 and October 2015 and shows drilling trajectory ( i.e., directional, horizontal, v ertical) and product type ( i.e., crude oil, natural gas). While these counts include rigs that are drilling for CBM and COG , drilling for UOG surpasse d drilling in CBM and COG by the late 2000’s ( 194 DCN SGE01192). Both horizontal drilling and oil well drill ing have increased since 2000. As of October 9 , 201 5

, 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 U nited S tates . Shortly after, in 2011, oil well drilling surpassed gas for the first time since 19 93 ( 202 DCN SGE 0 1235 ). 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 An other seven percent of rigs were drilling directional wells in the U nited S tates as of October 9, 2015

.

### Chapter B

— S cope and Industry Description

35 Source: 179 DCN SGE01179



### Figure B

- 13 . Number of Active U.S. Onshore Rigs by Trajectory and Product Type over Time 46



### Table B

- 2 shows the active drilling rigs in the U nited S tates 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 DC N SGE 0 1233 ; 76 DCN SGE 00595). Where Baker Hughes did not specify the formation being drilled into , counts may includ e a mixture of rigs that are drilling for U OG, CBM

, and COG

. Note that the number of active rigs has c ontinued to decline and the March 4 , 2016

, count was 463 active rigs in the United S tates ( 217 DC N SGE01335).

46 The sharp decreases in active drilling rigs observed i n 2009 and 2015 are likely attributed to the sudden drop in natural gas and crude oil prices experienced in those years ( 194 DCN SGE0 1192).

### Chapter B

— S cope 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 )

Basin a Formation a Resource Type a Gas Rigs by Well Trajectory Oil Rigs by Well Trajectory b

Total Rigs Directional Horizontal Vertical Tota l Gas Directional Horizontal Vertical Total Oil

Permian

— c Mix 0 5 0 5 4 182 44 230 235

Other d

— 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 s hale e 0 0 0 0 2 62 1 65 65 Appalachian Marc ellus 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 Woodford f 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

Source s : 179 DCN S GE01179

a

— Baker Hug hes ( 200 DCN SGE0 1233 ) 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 DC N SGE01233).

c

— Baker Hughes reported basin as opposed to formation for these areas. Therefore, these areas may include rigs drilling in conventional and unconvent ional 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 U nited S tates

.

e

— The majority of these rigs are expected to have been drilling in the Bakken shale formation based on rig counts reported by t he EIA ( 76 DCN SGE00595 ).

f

— This formation includes the Woodford

- Cana, Arkoma Woodford, and Ardmore Woodford formations.

### Chapter B

— S cope 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 b ecause it is only for several sub

- formations

, 47 

### t he EPA calculate d new well potential for all UOG formations

. 48 

### Th is analysis is the same as the EIA methodology and is documented in a separate memorandum titled Data Compilation Memorandum for the Technical D evelopment Document for Effluent Limitations Guidelines and Standards for Oil and Gas Extraction (TDD) ( 179 DCN SGE01179 ; 180 DCN SGE01179 .A 0 2).

The two EIA

- reported param eters 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 i s the quantity of crude oil and/or natural gas producible from a geological for mation 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 a rea 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 formati ons in Table 9.3 of the EIA’s Assumptions to the 2015 Annual Energ y 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 a ccount for formations not yet assessed by the USGS ( 192 DCN SGE01 1 90 ).

To evaluate new well potential, the EPA calculated new well potential for each formation or sub

- formation by dividing the TRR by the EUR. Appen dix F provide s EUR and TRR on a for mation 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 potenti al 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 forma tion s ( 180 D CN SGE01179.A0 2). 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 ultim ately 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

rea sonable 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

— S cope 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 Po tential by Resource Type as of January 1, 2013

Resource

Type Weighted Average a Oil EUR (MMbls per well) Weighted Average a 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

Count c

Shale gas 0.008 0.534 7,300 515,900 967,000 H: 56, 801 D: 1,8 36 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: 3 6,208 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

Sourc e s : 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

— G as production from shale and tight oil resources is associated gas that is produced simultaneously with oil.

c

— W ell counts are based on ERG’s DI Desktop ® da ta analysis explained in the Analysis of DI Desktop ® memorandum ( 182 DCN SGE01180 ). They may not be all

- inclusive.
Abbreviations : MMbls

— million barrels; Bcf

— b illion cubic feet of gas; EUR

— e stimated u ltimate recovery (per well); TR R

— t echnically recoverable resources; H

— horizontal ; D

— directional ; V

— v ertical; 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 SGE011 8 0 )

.

3.3 Current and Projecti ons of Future UOG Well Completions

In 201 3 and 2014 alone, more than 2 7 ,000 51 

### oil and gas wells were hydraulically fractured nationwide each year ( 175 DCN SGE0 1169 ). As previously explained, hydraulic fracturing is currently the most popular well stimulation technique for UOG wells. A s urvey

50 These estimates onl y 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 f racturing is common (e.g., Michigan) did not yet require reporting to FracFocus during these years.

### Chapter B

— S cope and Industry Description

39 conducted by the API and the American Natural Gas Alliance show s that, as of 2010, nearly all unconventional wells were being completed using hydraulic fracturing ( 28 DCN SGE 00291). 52 

### Operators may also refracture existing oil and gas w ells. 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 re ported as refracturing of existing oil and gas wells ( 165 DCN SGE01095 .A09 ). A more recent survey of 205 UOG operators conducted by PESA 53 

### shows that in 2012 and 2013 about 10 percent of well completions involving h ydraulic 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 SGE 00728). 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 ann ually 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 e nergy 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. U NCONVENTIONAL 

## O IL AND 

## G AS 

## E XTRACTION 

## W ASTEWATER 

## V OLUMES AND 

## C HARACTERISTICS



### 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 oil 54 

### and natural gas 55 

### will come from unconventional

r esources ( 194 DCN SGE01192). Consequently, industry experts expect UOG produced water volumes to continue to increase ( 103 DCN SGE 00708; 46 DCN SGE 00479; 107 DCN SGE 00722 ; 131 DCN SGE 00768.A 0 1; 132 DCN SGE 00768

. A25 ).

This chapter discusses UOG extraction wast ewater 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, a nd include s , 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 comp onents:

— 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) . A fter the hydraulic fracturi ng 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 wa stewater

— the liquid waste stream sep arated from recovered drilling mud 56 

### ( fluid ) and drill cuttings 57 

### during the drilling process.

• Produced sand

— t he slurried particles used in hydraulic fracturing, the accumulated formation sands and scale s particles genera ted 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 treat ment system.

The EPA identified drilling wastewater and produced water as the m ajor 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 drillin g 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 volume s and characte ristics 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 p apers /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, t he EPA compiled the existing data into a separate document to compile and analyze th e 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
Documen t (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 waste water

, and Section C. 3 presents constituents that are typically found in UOG extraction waste water. Section C. 3 extensively discusses TDS

, a parameter that is often used to characterize UOG extraction waste water because it provides a measure of disso lved matter including salts (e.g., sodium, chloride, nitrate), metals, minerals , and organic material ( 3 DCN SGE 00046). Data in Section C. 3 show that sodium and chloride make up the maj ority of TDS in UOG produced water. The d ata 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 conce ntrations 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 F RACTURING 

### F LUID 

### C HARACTERISTICS



### As discussed i n 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 m ixed 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 p art 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 a dditives, 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 consist s 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 SGE 00639; 70 DCN SGE 00575)

. PESA reports the following percentages of UOG operators using each water source as fracturing fluid in the United States ( 70 DCN SGE 00575 ) :

• Surface water (e.g., rivers, lakes) (40 percent )

• Groundwater (36 percent )

• City / m unicipal water 61 

### (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

p rojected values for the year 2020 are reported parenthetically in Table C

- 1

.
In general, the fraction of base fluid that can be comp o sed of UOG produced water is limited by two factors ( 66 DCN SGE 00556 ; 105 DCN SGE 00710 ):

• Produced water volume

. When large volumes of flowback and long

- term produced water are generated by other UOG wells in the area , reuse/ recycl e wastewater can make up a larger portion of base fluid water on average.

• Produced water quality

. Whe n the concentr ation of TDS in UOG produced water rapidly increases after fracturing

, it may have less potential for reuse/recycl e as a source of base fluid to fracture another well ( 105 DCN SGE 00710 )

.

61 PESA does not specify whether this water source is potable drinking water or treated municipal effluent ( 7 0 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/recycl e

.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 Fracturing a

Fresh Water b Brackish Water b Reused/Recycled UOG Produced Water

All CA b asi ns All formations S hale and tight 96 0 4

Appalachian Marcellus (PA) S hale 82 to 90 0 10 to 18
Marcellus (WV) S hale 77 to 83 c ,d

— c 6 to 10

Anadarko All formations S hale and tight 50 (40) 30 (30) 20 (30)

Arkoma Fayetteville S hale 70 0 30

Fort Worth Bar nett S hale 92 (75) 3 (15) 5 (10)

Gulf Coast Eagle Ford S hale 80 (50) 20 (40) 0 (10)
Permian (Far West) All formations S hale and tight 20 (20) 80 (30) 0 (50)
Permian (Midland) All formations S hale and tight 68 (35) 30 (40) 2 (25)

TX

- LA

- MS All formations S hale and tight 95 (90) 0 (0) 5 (10)

Nationwide All formations S hale and tight 40 53 7

Source s : 179 DCN SGE01179

a

— Parentheses contain p rojected data for the year 2020

, reported as the “most likely” scenario by Nic o t et al. 201 2 ( 97 DCN SGE006 39).
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 va lues are included in this table

. d

— H ansen et al. 2013 ( 60 DCN SGE00532) reported this data as “surface water .”

“

— ” indicates no data.



### 1.2 Additives

In addition to base fluid , oper ators add proppant and chemicals to adjust the fracturing fluid properties. Prop p ant generally make s 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 fl uid 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 SGE 00721 ; 4 DCN SGE 00070 ; 136 DCN SGE 00780 ; 137 DCN SGE 00781 )

. 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 fluid s :

• Slickwater fracturing fluids consist of small quantities of friction reducer, biocides, scale inhibitors, su rfactants, and propping agents. Operators generally use slickwater designs to fracture dry natural gas producing formations ( 105 DCN SGE 00710; 101 DCN SGE 00705).Chapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 44 • Gel fract uring fluids include higher quantities of gels to increase fluid viscosity that enable s the fluid to carry higher concentrations of propping agents into the formation. Using gel fracturing fluids require s 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 SGE 00710; 101 DCN SGE 00705). Operators generally use gel fracturing fluids to fracture liquid

- rich formations 43 

### ( 101 DCN SGE 00705).

In 2015

, the EPA ’s Office of Research and Development (ORD) released a report summarizing additives used by o perators based on public disclosures to FracFocus 63 

### ( 106 DCN SGE 00721)

. 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 (5 th 

### to 95 th 

### percentile) of the maximum possible fluid concentrations reported by opera tors 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

Type a 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 sul fide) 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 for mation 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 f racturing fluids that contain acid).

Crosslinker Borate salts; potassium hydroxide Increases fluid viscosity to allow the fluid to carry more proppant into the fractures.

63 Oper ators 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 mos tly 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

Type a Common Compound(s) b Purpose

Friction reducer Petroleum distillates Minimizes friction

, allowing fracturing flui ds 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 precipita tion 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 sulf ate, barium sulfate) in pipes and in the formation.

Surfactant Isopropanol;

n aphthalene Reduces the surface tension of the fracturing fluids to improve fluid recovery from the well after fracture is completed.

Source s : 106 DCN SGE 00721 ; 4 DCN SGE00070 ; 136 DCN SGE 00780 ; 137 DCN SGE 00781 ; 146 DCN SGE 00966

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 com pany 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 Ingredient s Used in Fracturing Fluid in Gas Wells from FracFocus ( 2011

– 2013)

Specific Constituents CAS Number Maximum Concentration in Hydraulic Fracturing Fluid (% by M ass ) a

Number of Reported Uses Median Concentration 5 th to 95 th
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 0.0 00020

– 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 0.000 010

– 0.0016

Source: 106 DCN SGE0 0 721

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 Hydrau lic 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 Ing redients Used in Fracturing Fluid in Oil Wells from FracFocus (2011

– 2013)

Specific Constituents CAS Number Maximum Concentration in Hydraulic Fracturing Fluid (% by M ass ) a

Number of Reported Uses Median Concentration 5 th to 95 th
Percentile Concentrati on
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

– 0.43Chapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 47 Table C

- 4 . Most Frequently Reported Additive Ing redients Used in Fracturing Fluid in Oil Wells from FracFocus (2011

– 2013)

Specific Constituents CAS Number Maximum Concentration in Hydraulic Fracturing Fluid (% by M ass ) a

Number of Reported Uses Median Concentration 5 th to 95 th
Percentile Concentrati on
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, he avy 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 SGE0 0721

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 Fluid s
Fracturing fluid is t he 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 2 50,000 and 420,000 gallons ( 6,000 and 10,000 barrels ) of fracturing flui d per stage ( 24 DCN SGE 00280). Literature reports that tight oil and gas wells typically require less fracturing fluid than shale oil and gas well s ( 61 DCN SGE 00533). Typic al volumes of fracturing fluid var y 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 SGE 00110, 44 DCNChapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 48 SGE 00414). Other constituents, such as total organic carbon ( TOC ) and biochemical oxygen demand ( BOD 5 

### ) , 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 BOD 5 

### in fracturing fluid of about 1,700 64 

### mg/L but BOD 5 

### in the corresponding flowback and long

- term produced water of 300 65 

### mg/L or less on average ( 44 DCN SGE 00414). As indicated in Table C

- 2

, Table C

- 3

, and Table C

- 4 organic materials (which contribute to BOD 5 

### and TOC) are typical chemical additives in fracturing fluid ( 44 DCN SGE 00414).

2 UOG E XTRACTION 

### W ASTEWATER 

### V OLUMES


### As explained previously, UOG wells generate three main types of wastewater over the life of t he well: drilling wastewater, flowback , and long

- term produced water (the lat t er two are collectively referred to as produced water) . The se wastewater streams’ flow rates and total volumes generated per well vary based on several factors , including :

• T ime s ince flowback commenced

• R esource 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 quan tify 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

tra jectory

. 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 wast ewater generated

, on a per well basis , for the following three wastewater components :

• Drilling wastewater

• Flowback

• L ong

- 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 generat ed

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 r eported 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 E PA 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 D CN SGE01182 ). This trend varies by formation and

, sometimes, within formation s

. 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 produce d water) generated by a well over its lifet ime 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 SGE 00728 ). 67

Source s : 184 D CN SGE01182



### Figure C

- 1 . UOG Extraction Wastewater Vol umes for Marcellus Shale Wells in Pennsylvania (2004

– 201 4 )

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 co mpletion

, when there

67 Figure C

- 1 shows that long

- term produced water is more than 50 percent of total UOG p roduced water for Marcellus shale wells lik ely 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 f ive days ( 36 DC N SGE00350).

69 Data for the first 90 days repre sent 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 lev el 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 . Range s of T ypical Produced Water Generation Rates o ver 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 wastew ater than a horizontal well drilled into the same formation, because the latter requires additional drilling fluid to complete the horizontal lateral ( 184 D CN SGE01182 )

. Table C

- 5 illustra tes 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( G allons ) Range of Drilling Fluid Volume per Well ( G allons ) 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 D CN SGE01182

a

— These ranges are based on the 10 th and 90 th 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 h orizontal).



### The EPA collected information on volumes of drilling w astewater generated per well

. Table C

- 6 shows typical ranges of drilling wastewater generated by UOG wells by resource type and formation

. Operators report that nea rly 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 Depth b ( Feet ) Number of Data Points

Shale Haynesville 420,000

– 1,100,000 1 3 ,000

– 1 9 ,000 5 Tight Anadarko Basin b 200,000

– 420,000

— c 2

Shale Niobrara 300,000 a 7

, 5 00

– 1 3 ,000 1

Shale Barnett 170,000

– 500,000 8

, 5 00

– 1 4 ,000 6

Shale Permian Basin b 84,000

– 420,000

— c 8 Tight G ranite Wash 200,000 a

— c 1 Tight Cleveland 200,000 a

— c 1

Shale Eagle Ford 130,000

– 420,000 6 ,000

– 1 6 ,000 7

Shale Utica 100,000 a 6 ,000

– 1 9 ,000 1 Tight Mississippi Lime 100,000 a

— c 1

Shale Marcellus 3,400

– 200,000 d (median: 50,000) 7

, 300

– 13 ,000 3,96 2

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 ho rizontal).

c

— Information is unknown.
d

— Due to the large number of volume data points for the Marcellus formation, the EPA calculated the 10 th and 90 th 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

. F or all other formations , t he 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 descri bed 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 

### t otal flowback volumes typically range between 40,000 to 1,1 00 ,000 gallons ( 950 to 25

, 0 00 barrel s ) 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) c ompared

to long

- term produced water that is generated in small volumes over a long period of time.

Table C

- 7

. UOG Well Flowback Recovery 73 

### by Resource Type and Well Trajectory

Resource

Type Trajectory Fracturi ng Fluid ( MG ) a Flowback Recovery (Percent of Fracturing Fluid Returned) a
Weighted Average b Range Number of Data Points Weighted Average b Range Number of Data Points

Shale H 4.2 0.091

– 24 80,388 7 0

– 5 8 0 7,377

D 1.4 0.037

– 20 340 33 12

– 57 36

V 1.1 0.0 15

– 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 recover y data were reported in different

sources

. To avoid representing the data incorrectly, t he EPA did not calculate total flowback volume for Table C

- 7

. Data are based on a ggregated 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

— h orizontal well ; D

— directional well; v

— v ertical well



### 2.1.3 Produced Water: Long

- Term Produced Water

L ong

- term produced water rates remain relatively constant 74 

### over the well life compared

to flowback rates ( 95 DCN SGE 00635). Table C

- 8 quantifies long

- term produced water rates in

71 The EPA explains how it differentiated between flowback and long

- term produce d 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 grad ually 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 sh ale 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 Average b 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

Source s : 186 DCN SGE01184

a

— Data are based on a ggregated data from Table C

- 9 , which contains volumes by formation.
b

— T he 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 fewe r data points). Abbreviations: gpd

— gallons per day; H

— h orizontal well ; D

— directional well ; V

— v ertical well



### 2.2 UOG Produced Water Volumes by Formation

Table C

- 9 s hows UOG produced water volume s by UOG formation and w ell 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 ident ified 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

, 9 00 gallons ( 45 bar rels) per day for horizontal UOG wel ls drilled into the Eagle Ford shale formation in the Western Gulf basin ( 91 DCN SGE 00623). In some cases, produced water even varies geographically within the same formation, wh ich 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 s outhwest portion of the Marcellus shale formation (in West Virginia) ( 95 DCN SGE 00635).Chapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 54 Table C

- 9 . Produced Water Volume Generation by UOG Formation

Basin UOG Formati on Resource Type Well Trajectory Fracturing Fluid (M G ) Flowback Recovery (% of Fracturing Fluid Returned) Long

- Term Produced Water Rates ( g pd)

Weighted Average a Range b Number of Data Points c Weighted Average a Range b Number of Data Points c Weighted A verage a Range b Number of Data Points c
Caney S hale H 8.1 4.4

– 12 11

— — 0

— — 0

Cleveland T ight 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 T ight 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 T ight 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 S hale 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

Clinton

Medina T ight V

— — 0

— — 0 7.9 7.3

– 11 551

Devonian S hale V

— — 0

— — 0 13 4.8

– 19 197

Appalachian Marcellus S hale H 4.6 0.9

– 11 17,316 7.1 4

– 47 4,374 820 5 4

– 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 S hale H 6.8 1

– 13 1,108 2.5 0.66

– 27 684 800 420

– 1,700 764

Arkoma Fayetteville S hale H 5 1.7

– 11 3,014

— 10

– 20 2 430 150

– 2,300 2,305

Codell T ight 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 667Chapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 55 Table C

- 9 . Produced Water Volume Generation by UOG Formation

Basin UOG Formati on Resource Type Well Trajectory Fracturing Fluid (M G ) Flowback Recovery (% of Fracturing Fluid Returned) Long

- Term Produced Water Rates ( g pd)

Weighted Average a Range b Number of Data Points c Weighted Average a Range b Number of Data Points c Weighted A verage a Range b Number of Data Points c

Codell

Niobrara T ight 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 T ight 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 S hale 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 S hale 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 Hilliard

Baxter

Mancos S hale H 1.7 1

– 5.6 2

— — 0

— — 0

D

— — 0

— — 0 35 14

– 56 10

Lance T ight 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 S hale 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 T ight 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 S hale H

— — 0

— — 0 2,940 2,940

– 2,940 1 Michigan Antrim S hale V 0.05 0.05

– 0.05 1

— 25

– 75 2 1,300 530

– 4,600 7Chapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 5 6 Table C

- 9 . Produced Water Volume Generation by UOG Formation

Basin UOG Formati on Resource Type Well Trajectory Fracturing Fluid (M G ) Flowback Recovery (% of Fracturing Fluid Returned) Long

- Term Produced Water Rates ( g pd)

Weighted Average a Range b Number of Data Points c Weighted Average a Range b Number of Data Points c Weighted A verage a Range b Number of Data Points c

Permian Avalon & Bone Spri ng S hale 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

Barnett

Woodford S hale H 2.1 0.5

– 4.5 2

— — 0

— — 0

Delaware S hale 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) S hale 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 T i ght V

— — 0

— — 0 130 41

– 290 7

D

— — 0

— — 0 140 34

– 2,200 66

Spraberry T ight 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 T ight H 8.3 2.4

– 12 9 91

— — 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 S hale 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 T ight D

— — 0

— — 0 510 130

– 700 52

Hermosa S hale D

— — 0

— — 0 47 27

– 260 21

Powder

River Mowry S hale H 2.5 0.76

– 7.4 15 15 4.3

– 580 14 450 61

– 2,100 16Chapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 57 Table C

- 9 . Produced Water Volume Generation by UOG Formation

Basin UOG Formati on Resource Type Well Trajectory Fracturing Fluid (M G ) Flowback Recovery (% of Fracturing Fluid Returned) Long

- Term Produced Water Rates ( g pd)

Weighted Average a Range b Number of Data Points c Weighted Average a Range b Number of Data Points c Weighted A verage a Range b Number of Data Points c

San Juan Dakota T ight 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 T ight V

— — 0

— — 0 43 14

– 560 5

D

— — 0

— — 0 21 15

– 180 49

Pictured

Cl iffs T ight H

— — 0

— — 0 370 190

– 720 7

D

— — 0

— — 0 4,700 1,200

– 8,200 6

TX

- LA

- MS Bossie r S hale 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 T ight 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 S hale 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 T ight H 3 0.25

– 6 2

— — 0 71 0 110

– 4,200 7

V 0.17 0.032

– 4 36

— — 0 630 270

– 930 1,046

D

— — 0

— — 0 520 140

– 800 134

Tuscaloosa S hale H 11 6.1

– 14 28

— — 0

— — 0

V 13 4.7

– 19 11

— — 0 7,400 220

– 51,000 64

Austin Chalk T ight H 1.7 0.83

– 5.4 134

— — 0 2,200 980

– 5,100 752

West ern

Gulf V

— — 0

— — 0 97 21

– 1,500 51

Eagle Ford S hale 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 T ight H

— — 0

— — 0 2,300 1,000

– 24,000 266Chapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 58 Table C

- 9 . Produced Water Volume Generation by UOG Formation

Basin UOG Formati on Resource Type Well Trajectory Fracturing Fluid (M G ) Flowback Recovery (% of Fracturing Fluid Returned) Long

- Term Produced Water Rates ( g pd)

Weighted Average a Range b Number of Data Points c Weighted Average a Range b Number of Data Points c Weighted A verage a Range b Number of Data Points c

V

— — 0

— — 0 560 150

– 2,100 32

D

— — 0

— — 0 160 69

– 290 6

Olmos T ight 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 S hale H 3.5 1.6

– 5.6 47

— — 0 160 53

– 1,500 51

Vicksb urg T ight 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 T ight 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 3 95

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

Source s : 186 DCN SGE01184

a

— W eighted averages are based on the number of data points reported by each da ta 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 wa s 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 num ber 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 wellChapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 59 3 UOG E XTRACTION 

### W ASTEWATER 

### C HARACTERIZATION



### As discuss ed 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) us ed by each UOG operator as well as chemical constituents present in the UOG formation ( 27 DCN SGE 00286; 6 DCN SGE 00110 ). Long

- term produced water typically mimics the chara cteristics of the UOG formation, which often contributes, in part, to high concentrations of select naturally occurring ion s ( 169 DC N 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 SGE 00592 ). 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 . The se 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 subsec tion s , 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 generate d 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 lit erature 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 (BOD 5 ), 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.” Rat her, 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, t he 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 chem istry 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 t he lack of data for select constituents may not necessarily imply that those constitu ents 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 w ere reported in the literature reviewed

.Chapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 60 term produced wat er 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 s ome constituent concentrations vary between flowback and long

- term produced water.

3.2.1 Classical and Conventional Constituents in UOG Extraction W astew ater

Table C

- 10 presents typical concentrations of select classica l and conventional constituents that are present in UOG drilling wastewater. 77 

### A ccording 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 SGE 00245) ( 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 cam e 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 limitation s 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, BOD 5 

### , chemical oxygen demand ( COD )

, hardness as CaCO 3 

### , 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 Wells 78

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

BOD 5 mg/L 80

– 1,100 390 8 8

Chloride mg/L 160

– 23,000 12,000 12 12

C OD mg/L 150

– 9,300 1,800 8 8

Hardness as CaCO 3 mg/L 1,400

– 46,000 4,400 12 12 Oil and grease mg/L ND a

– 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

TS S 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: m g /L

— milligrams per liter; ND

— nondetect; SU

— sta ndard units; μS/ cm

— microsiemens per centimeter

78 Drilling wastewater may contain differing amounts of drill cuttings depending on how the operator chooses to

re move 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 Points a Number of Detects Format ions Represented a

Alkalinity mg/L 41

– 1,100 140 265 265 Barnett (29); Eagle Ford (1); Marcellus (232); Woodford

- Cana

Caney (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); Mesav erde (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/Lew is (39); Niobrara (8); Spraberry (26)

Chloride b 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

- Man cos (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); Marcel lus (122); Medina/Clinton

- Tuscarora (1); Woodford

- Cana

- Caney (3)
Hardness as CaCO 3 mg/L 2,200

– 77,000 21,000 80 80 Barnett (15); Marcellus (65)
Oil and g rease 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); Manc os (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 Points a Number of Detects Format ions Represented a

Specific conductivity μ S/

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); Ea gle 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 numbe r 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 identifie d.
b

— The EPA assumed values reported as “Cl” in the wastewater characterization data were meant to represent “chloride” val ues

. Abbreviations: mg /L

— milligrams per liter; SU

— sta ndard units; μS/cm

— microsiemens per centimeterChapter 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, 2 00 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, chlorid e, 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 SGE 00725 )

. In Table C

- 11 , t he relatively low median TOC concentration ( 82 mg/L) and BOD 5 

### concentration ( 160 mg/L ) compared to the COD concentration likely indicates that some of the COD measurements reported in existing lit erature 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 o f 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 pro duced 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 ca tions 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 , t he “other dissolved constituents” were captured by EPA by subtra cting 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 Cation s Contributing to TDS Concentrations in Shale and Tight Oil and Gas Formations 79



### 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 contain s 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 95 th 

### percentile values of the data. The data used to create t his figure include constituent concentration data from flowback or long

- term produced water generated from UOG well s . 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 t ight oil and gas formations b y “**” after the formation name. The EPA assumed values reported as “Cl” in the wastewater characterization data were m eant 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 Formations 80



### 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 :

• L ess 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 format ion.

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 t he 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 N D

– 1,600 220 13 10 Marcellus

Source : 183 DCN SGE01181 Abbreviation: mg/L

— milligrams per literChapter 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 Points a 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)

Fluorid e 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); L ance (1722); Lansing Kansas City (15); Lewis (52); Mancos (2); Marcellus (301); Medina/Clinton

- Tuscarora (2); Mesaverde (438); Mesaverde/Lance (11); Mesaverde/Lance/Lewis (916); Morrow (1); Mowry (5); New Albany (1); Niobrara (133); Oswego (4); Pearsall (3 ); Spraberry (26); Woodford

- Cana

Caney (2726)

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 individua l 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 literChapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 69 3.2.2 Organic Constituents in UOG Extraction W astew ater

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 th e 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 ca me 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 Poi nts Number of Detects Formation Represented

Benzene μg/L ND a

– 40 ND a 20 5 Marcellus Ethylbenzene μg/L

— b 9.6 4 4 Marcellus Ethylene glycol mg/L

— b 500 1 1 Marcellus

Toluene μg/L ND a

– 80 ND a 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 literChapter 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 Points a Number of Detects Formations Represented (Number of Associated Data Poin ts) a
1,2,4

- Trimethylbenzene μ g/L 1.1

– 100 5 92 89 Barnett (25); Marcellus (67)
1,3,5

- Trimethylbenzene μ g/L 3

– 130 5 85 81 Barnett (18); Marcellus (67)

Acetone μ g/L 12

– 1,100 40 96 86 Barnett (22); Marcellus (72)

Benzene μ g/L 4.8

– 3,700 8.5 144 122 Barnett (25); Marcellus (111); Niobrara (5); Woodford

- Cana

Caney (3)

Carbon d isulfide μ g/L 5

– 250 5 68 67 Marcellus (68)

Chlorobenzene μ g/L 0

– 100 5 72 70 Marcellus (69); Woodford

- Cana

- Caney (3)

Chloroform μ g/L 0

– 100 5 77 75 Barnett (5); Marcellus ( 69); Woodford

- Cana

- Caney (3)

Ethanol μ g/L 5,000

– 20,000 10,000 53 53 Marcellus (53)

Ethylbenzene μ g/L 3.4

– 130 5 130 104 Barnett (18); Marcellus (108); Medina/Clinton

- Tuscarora (1); Woodford

- Cana

- Caney (3) Isopropylbenzene μ g/L 5

– 100 5 83 69 Barnett (16); Marcellus (67)

Methanol μ g/L 5,000

– 180,000 10,000 55 55 Marcellus (55) Methyl c hloride μ g/L 5

– 100 5 95 69 Marcellus (95) Naphthalene μ g/L 1.8

– 110 5 129 103 Barnett (39); Marcellus (90)

Phenol μ g/L 1.9

– 56 2 111 83 Barnett (17); Marcellus (91); Woodford

- Cana

- Caney (3) Pyridine μ g/L 7.9

– 900 86 91 90 Barnett (24); Marcellus (67) Tetrachloroethylene μ g/L 5

– 100 5 95 68 Marcellus (95)

Toluene μ g/L 2

– 2,900 6 149 125 Barnett (25); Marcellus (115); Medina/Clinton

- Tuscarora (1); Niobrara (5 ); Woodford

- Cana

- Caney (3)

Xylenes μ g/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 literChapter 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 suggest s that a t least some portion of the concentrations of these constituents foun d 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 U OG produced water

. However, Table C

- 3 and Table C

- 4 show that petroleum distillates are typically used in fracturing fluid . The EPA ORD’s 201 5 Analysis of Hydraulic Fracturing Fluid Data from the FracFocu s Chemical Disclosure Registr y 1.0 contains additional information about these constituents ( 106 DCN SGE00 721)

.

3.2.3 Metals in UOG Extraction W astew ater

UOG extraction waste water contains varying concentrations of nume rous metals.

Table C

- 16 presents concentration data from existing literature for the metals most

common ly 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 met als most

common ly 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, lithiu m, manganese, merc ury, 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

Pa rameter Units Range Median Number of Data Points Number of Detects

Aluminum mg/L 1.7

– 6,900 38 12 12

Arsenic mg/L ND a

– 4.2 ND a 12 6

Barium mg/L 2.6

– 2,000 13 14 14 Beryllium mg/L ND a

– 0.018 ND a 8 2Chapter 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

Pa rameter Units Range Median Number of Data Points Number of Detects

Boron mg/L ND a

– 2.7 0.17 8 4

Cadmium mg/L ND a

– 0.0050 ND a 8 1

Calcium mg/L 150

– 15,000 1,300 13 13

Chromium mg/L ND a

– 11 0.010 12 8

Cobalt mg/L ND a

– 1.8 ND a 8 3 Copper mg/L ND a

– 17 0.83 8 6

Iron mg/L 4.2

– 18,000 86 12 12

Lead mg/L ND a

– 8.0 0.35 12 10

Lithium mg/L ND a

– 1.2 ND a 8 1 Magnesium mg/L ND a

– 3,600 290 12 11
Manganese mg/L ND a

– 350 4.3 12 11
Mercury mg/L ND a

– 0.029 ND a 8 2 Molybdenum mg/L

— b 0.10 1 1

Nickel mg/L ND a

– 16 0.55 12 9

Potassium mg/L

— b 8,800 4 4

Selenium mg/L ND a

– 0.11 ND a 8 3

Silver mg/L ND a

– 0.010 ND a 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 ND a

– 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

— non detectChapter 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 Points a 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); Barne tt (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); Marcellu s (343); Medina/Clinton

- Tuscarora (2); Mesaverde (461); Mesaverde/Lance (13); Mesaverde/Lance/Lewis (917); Morrow (1); Mowry (5); New Albany (1); Niobrara (189); Oswego (5); Pearsall (3); Spraberry (26); Woodford

- Cana

Caney (2821)

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); Mar cellus (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); Mesav erde/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 Barne tt (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 Points a 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); Cot ton 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 (3 91); Mesaverde/Lance (13); Mesaverde/Lance/Lewis (778); Morrow (1); Mowry (4); New Albany (1); Niobrara (188); Oswego (5); Pearsall (3); Spraberry (26); Woodford

- Cana

Caney (1086)

Manganese mg/L 0.47

– 9 1.7 238 224 Bakken (7); Barnett (38); Cotton Valley/B ossier (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); Fayet teville (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/Clinton

Tuscarora (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 Points a 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); Ea gle Ford (6); Fayetteville (2); Marcellus (117); Woodford

Cana

- Caney (3)

Source: 186 DCN SGE01184

a

— In some instances the sum of the number of data points associated with individual formations does not equal the total number of d ata 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 identif ied.
Abbreviation: m g/L

— milligrams per literChapter 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 m edian

concentr ation 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 formation s , 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 formation s on a log scale. M edian concentrations of h eavy metals (e.g., chromium, copper, nickel, zinc, lead, mercury, arsenic) in UOG produced water ar e 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

wat er

. Radioactive decay products typically include radium

- 226 and radium

- 228 ( 188 DCN 0.1 1.0 10.0 100.0 1,000.0 10,000.0Barium 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 constituen ts in UOG extraction waste water, including radium

226, radium

- 228, gross alpha, and gross beta, and therefore focused the radioactive constituent discussion and data pr esentation on these parameters. ERG’s Radioactive Materials in the Unconventional Oil an d Gas (UOG) Industry memorandum ( 188 DCN SGE01185 ) contains a more detailed discussion of this topic

.

The EPA identified l imited 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 Shal e 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

Source s : 183 DCN SGE01181 Abbreviation: pCi/L

— picocu ries 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; lim ited data were available from the Niobrara formation. Radium

226 and radium

- 228 are both found in UOG produced water, with radium

- 226 concentrations generally two to five times greater than radium

- 228 concentrations.

The EPA identified the following limit ations 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 pre sence 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 (p Ci/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 92Chapter 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 (p Ci/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, γ

spectrometry 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, γ

spectrometry 15

– 16,000 470 73 72

Radium

- 228 Niobrara 901.1 Mod. 400

– 1,100 33 0 3 3

Source s : 186 DCN SGE01184
Abbreviatio n: 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 SGE 00769) 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 r adium

- 226 found in U.S. rivers and lakes was 0.56 pCi/L (21 m illibecquerel 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 w ere 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, Groundwat er, and Drinking Water Sources Throughout the United States (pCi/L)

Parameter Location Description Min imum Max imum Average
Boise, Idaho

— well water

— — 0.1 0

Florida

— groundwater ND 7 6

— Florida

— well water 0.20 3. 3

— Hudson River

— — 0.032

Illinois

— well water 0.02 0 2 3

— 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

— — 0.4 8 Mississippi River 0.01 0 1. 1

— Ottawa County, OK

— well water 0.10 15

— Sarasota, Florida

— groundwater 1.5 24

— South Carolina

— well water 2.7 2 7

—Chapter C

— Unconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 79 Table C

- 20 . Concentrations of Radioactive Constituents in Rivers, Lakes, Groundwat er, and Drinking Water Sources Throughout the United States (pCi/L)

Parameter Location Description Min imum Max imum 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

— — 0.2 3

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: 13 4 DCN SGE 00769

“

— ”

— 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

. Abbreviation s : pCi/L

— picocuries per liter; ND

— nondetect



### In January 2015, PA DEP announced the r esults 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 o f [ 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 W astew ater

UOG produced water may also contain g uar 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 SGE 0 0 616). Guar gum treatment requires a breakdown of the polymer and is a consideration for UOG operators who are reusing/recycling wastewater for fracturing.

Microorganis ms are also found in UOG drilling wastewater and produced water

. Microorganisms may be present in concentrations as high as 1 × 10 9 

### organisms per 100 mL in UOG produced water ( 88 DCN SGE 00616). Sulfate

- reducing bac teria (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 reduc e and/or precipita te metals a nd ions, potentially causing scale in theChapter 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, f or the vast majority of formations for which data

are available , t he 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 TD S

- 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 M arcellus 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 SGE 00414

. 

### Figure C

- 6 . Constituent Concentrations o ver Time in UOG Produced Water from the Marcellus and Barnett Shale FormationsChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 82 

## Chapter D. UOG E XTRACTION 

## W ASTEWATER 

## M ANAGEMENT AND 

## D ISPOSAL 

## P RACTICES



### During the lifeti me of a well, UOG extraction generates large volumes of UOG extraction wastewater that contain constituents potentially harmful to human health and the environment. Th is create s a need for appropriate wastewater management infrastructure and disposal pract ices

. 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 U nited S tates . Historically, operators primarily managed their wastewater via undergro und injection using Class II enhanced recovery and disposal wells

, where available. In fact, i n 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 discuss es the methods used by UOG operators to manage and dispose of UOG extraction

wastewater.

1 O VERVIEW OF 

### UOG E XTRACTION 

### W ASTEWATER 

### M ANAGEM ENT AND 

### D ISPOSAL 

### P RACTICES



### UOG operators primarily use three methods for management of UOG produced w ater ( 86 DCN SGE 00613; 22 DCN SGE00276 ; 58 DCN SGE 00528 ) :

• Dispose of wastewater via Class II disposal wells (“disposal wells”)

• Reuse /recycle wastewater in subsequent fracturing jobs

• Transfer wastewater to a CWT facility

UOG o perators primarily use the following methods f or manageme nt of drilling
wastewater, which includes drill cuttings and drilling fluids 83 

### ( 183 DCN SGE01181 ) :

• Dispos al via disposal wells

• Reuse/ recycle in subsequent drilling and/or fracturing jobs

• Transfer to a CWT facility

• Onsite burial 84



### • Disposal via l andfill

• Land application

82 While t he existing oil and gas extraction ELG allows onshore oil and gas extraction wastewater generated west of the 98 th meridian to be permitted for discha rge when the water is of good enough quality for agricultural and wildlife uses (see 40 CFR p art 435 s ubpart 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 t emporary 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 illustra te the primary management methods for UOG produced water and drilling wastewater, respectively. In s elect 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 th e western U nited S ta tes ( 105 DCN SGE 00710). 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 SGE 00779.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 wellsChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 84 Figure D

- 2

. UOG Drilling Wastewater Management Methods

UOG o perators’ frequency of use of each of the aforementioned UOG extraction

wastewater management options vari es by operator, by formation, and sometimes within each region of the formation ( 71 DCN SGE 00579; 22 DCN SGE00276 ; 95 DCN SGE 00635 ; 37 DCN SGE0 0354 ; 105 DCN SGE00710 ). Table D

- 1 descr ibes 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 inje ction ( 171 DCN SGE 0 1128 ), 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 SGE 00707; 103 DCN SGE 00708 ). 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 regulat ory requirements, wastewater quality and volume, and operator

- specific risk management policies ( 91 DCN SGE00623). I n some areas of the U.S.

, there may be additional considerations that drive change from traditiona l 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 seis mic 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 Landfill BurialChapter 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 200 8 to 201 4 . In recent years (2010 to 201 4 ), transfer to CWT facilit ies , reuse/recycle in drilling or fracturing, and injection for disposal

— in that order

— were the most comm on 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 fr om the fifth largest U.S. oil and gas operator regarding its Fayetteville shale operations. This operator reported that it reuse s /recycle s the majority of its drilling wastewater in drilling subsequent wells and the remainder is disposed of via disposal we lls ( 92 DCN SGE 00625 )

.
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 b asin and formation differences in wastewater management practices

. The east side of the b asin contains ve ry few underground disposal wells, but contains a high density of CWT facilitie s 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 well s is the most common practice

, how reuse/recycle in fractur ing fluid is increasing

, and how increasing numbers of CWT facilitie s are accepting UOG produced water and drilling wastewater where disposal wells are limited. Although operators have dischar ged UOG extraction wastewater to POTWs in the past

, information available to EPA indicates that these discharges w ere discontinued in 2011 ( 184 DCN SGE01182 ; 27 DCN SGE 00286; 35 DCN SGE 00345; 71 DCN SGE 00579). 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 tha t POTWs have not received any UOG extraction

wastewater between 2011 and the end of 201 4 . 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 Data b

Michigan Antrim Shale gas XXX Qualitative

Appalachian Marcellus/Utica (PA) Shale gas XX X 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 X a Mixed
Mississippi Lime Tight oil X XXX Reuse /recycl ing limited but is being evaluated Qualitative

Woodford

, Cana

, Caney Shale gas / oil X XXX X a Qualitative

Arkoma Fayetteville Shale gas XX XX X a Few existing disposal wells; new CWT facilities are under construction Mixed

Fort Worth Barnett Shale gas X XXX X a 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

o il /gas X XXX X a Mixed

TX

- LA

- MS Salt Haynesville Tight gas X XXX Reuse/r ecycle 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 Ti ght 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

Source s : 179 DCN SGE01179

a

— CWT facilitie s 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 qualitativ e and quantitative data sources along with engineering jud gment 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 Source s : 184 D CN SGE01182



### Figure D

- 3 . Management of UOG Drilling Wastewater Generated by UOG Wells in Pennsylvania (200 8

– 201 4 )Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 88 Sources: Generated by the EPA using data f rom 178 D CN SGE01178 and 190 DCN SGE01187



### Figure D

- 4 . Active Disposal Wells and CWT Facilities Identified in the Appalachian Basin 87



### 2 I NJECTION INTO 

### D ISPOSAL 

### W ELLS


### Historically, underground injection has been the most common wastewater management method among UOG operators. In 2010, the EPA and industry stakeholders estimated that ov er 90 percent of oil and gas produced water (conventional and unconventional) wa s disposed of via Class II enhanced recovery and disposal wells ( 91 DCN SGE 00623 ). 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 201 3 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 progra m codified in 40 CFR parts 144 to 148, the EPA established six classes of underground injection wells ( 8 DCN SGE 00132 ):

• Class I in dustrial and municipal waste disposal wells

• Class II oil and gas related injection w ells

• Class III mining wells

• Class IV shallow hazardous and radioactive injection wells (banned)

• Class V a ny 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 p urposes:

• Inj ection of hydrocarbons for storage

• Injection of fluids for disposal ( i.e., disposal wells)

• Inj ection of fluids for enhanced recovery ( i.e., enhanced recovery wells)

Approximately 20 percent of Class II injection wells in the U nited S tates are Class II disposal wells ; the remaining 80 percent are mostly Class II enhanced recovery wells ( 8 DCN SGE 00132) . Injection into Class II disposal wells typically involves injecting wastewater into a porous and non

- o il

- 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 a nd 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 SGE 00623; 8 DCN SGE00132 ; 86 DCN SGE 00613). Available literature and communication with industry indicates that industry only hauls UOG extraction wastewater to Class II disposal wel ls and do es not use Class II enhanced recovery wells. In fact, t he leading method of UOG extraction wastewater management throughout the U nited S tates is injection into a Class II disposal wel l ( 181 D CN SGE01179 .A 0 3 ). However, a ll 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 territ ories

, 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 SGE 0 0611 ).

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 fewChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 90 (e.g., Virginia, South Dakota) . The EPA tabulated active Class II disposal wells using dat a 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 .A 0 1 )

.

Table D

- 2 presents the number of active Class II disposal wells by state ( 190 DCN SGE01187 ; 191 DCN SGE01187 .A 0 1 ). Only states with active disposal wells are listed; all other states have zero active disposal wells. Table D

- 2 also includ es 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 dispo sal wells and total state disposal rate. Average disposal rates of individual wells vary significantly , reflecting the geology of the underlying formation ( 23 DCN SGE 00279 ). States are first sorted by geographic

re gion, 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 Tabl e D

- 2 are not exact but rather are general approximations based on a number of assumptions

, listed below and d escribed in more d etail in a separate memo randum

, 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.

• Calculati on 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 w as 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 permitt ed 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 w ells 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 g enerate 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 t he 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 vol umes 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 Regi on

(from the EIA) State Number of Active Disposal Wells a 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 10 d 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 640 e 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

Tota l 26,400 41,300 1,050

Sourc e : 190 DCN SGE01187

a

— Number of active disposal wells is based primarily on data from 2012 to 201 3

.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 92 b

— Typical injection volumes per well are based on historic al annual volumes for inject ion 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 D isposal Wells ( 190 DCN SGE01187 ).

c

— Disposal rates and volumes are unkn own. d

— These wells are not currently permitted to accept UOG extraction wastewater (sour ce: 110 DCN S GE 00726 ).

e

— Only 24 of the 6 40 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

80 8 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

7 50 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, i njection 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 ( so lid lines ), and UOG production in the
U nited S tates (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 fo rmation 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 N orth 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 we lls 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 U nited S tates, additional injection for disposal capacity will become available as demand increases with increas ed 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 U nited S tates

.

Source : 171 DCN SGE01128 ; 194 DCN SGE01192; 213 DCN SGE01322; 220 DCN SGE01339; 221 DCN SGE01340



### Figure D

- 5 . U.S. Injection for Disposal Volume and UOG Production over Time 88

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; 21 9 DCN SGE01337 ; 13 DCN SGE00182; 171 DCN SGE01128; 221 DCN SGE01340



### Figure D

- 6

. I njection 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 DakotaChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 95 Operators of c ommercial i njection well s for disposal may impose a surcharge to dispose of flowback ( 23 DCN SGE 00279 ). Injection well operators impose the surcharge because flowback has a low er density than long

- term produced water. Injec tion 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 limita tions. As a result, disposal well operators must inject lower

density flowback at a lower flow rate and typically use more power.

3 R EUSE 

### /R ECYCLE IN 

### F RACTURING



### M any operators evaluate reusing/recycling UOG extraction wastewater before deciding to manage it via another method (i.e., disposal well or CWT facility ) ( 86 DCN SGE 00613; 54 DCN SGE 00521; 22 DCN SGE00276 ). Reuse/recycl e involv es mixing flowback and/or long

term produced water from previously fractured wells with other source water 90 

### to create the base fluid 91 

### used in a subsequent well fracture ( 3 DCN SGE00046 ). Operators typically transpo rt 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 (2 5 0

- 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 st eps such as fracturing chemical addition or pressurization by the pump trucks ( 92 DCN SGE 00625).

Since the late 2000s, UOG operators have increased wastewater reuse/recycle ( 86 DCN SGE 00613 ; 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 SGE 00613). 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 SGE 00691; 54 DCN SGE 00521; 86 DCN SGE 00613; 5 DCN SGE 00095).

To date, sli ckwater 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 S ection D. 3.2 for these ranges) ( 86 DCN SGE 00613; 101 DCN SGE 00705; 88 DCN S GE 00616). 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 wi th high concentrations of TDS than slickwater designs ( 101 DCN SGE 00705; 86 DCN SGE 00613; 88 DCN SGE 00616). As a result, at presen t, gel designs require

89 The d ensity 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 g allon ( 23 DCN SGE00279).

90 Sourc e 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 S ection D. 3.2 for these ranges) . This is primarily because TDS inte rferes 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 o f cross

- linked gels ( 88 DCN SGE 00616; 101 DCN SGE 00705). T his 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 concentrations 92 

### ( 98 DCN SGE 00667; 101 DCN SGE 00705 ).

PESA surveyed 205 UOG operat ors 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 p ercent 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 extra ction wastewater management report similar findings ( 103 DCN SGE 00708; 104 DCN SGE 00709). For example, IHS

, Inc.

, estimates that in 2013 operators reused/recycled 16 percen t of UOG produced water nationwide and expects this number to double by 2022 ( 103 DCN SGE 00708)

. 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 SGE 00635; 21 DCN SGE00275 ; 92 DCN SG E 00625; 96 DCN SGE 00636 )

.

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

. R euse/ R ecycle 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 Methods a Percent of Respondents Planning to Increase Reuse/Recycl e Appalachian Marcellus/Utica Shale gas / oil 74 26 50

TX

- LA

- MS Sal t 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; Barnett

Woodford Shale g as / o il 7 93 67

Williston Bakken Shale oil 5 95 56

Gul f 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 SGE 00575

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 strateg ies ( 174 DC N 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/recycl e without treatment and reuse/recycl e after treatment.

3.1.1 Direct Reuse/Recycl e 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

re move suspended solids. The primary purpose of the blending is to control TDS concentrations ( 88 DCN SGE 00616; 99 DCN SGE 00691 )

. When using this strategy, operators either t ransport 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 portio n of all wastew ater that industry reuse s /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 n o treatment. In addition, the EPA conducted several site visits and conference calls with operators that have increasingly reused/recycled wastewater with noChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 98 treatment ( 95 DCN SGE 00635; 21 DCN SGE 00275; 92 DCN SGE 00625; 96 DCN SGE 00636; 22 DCN SGE00276).

3.1.2 Reuse/Recycl e in Fracturing After Treatment
Op erators 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 —t echnologies that remove non- dissolved 94



### constituen ts 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 th e 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, ca lcium) 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 tr eat 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 i nclude 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 D CN SGE 00613; 5 DCN SGE00095 ):

• Solids removal (e.g., sedimentation, filtration, dissolved air flotation)

• Chemical precipitation

• Electroco agulation

• 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 use s no n

- 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 me thod used i n the field to treat UOG extraction wastewater is referred to as “o n 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 t he 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 SGE 00331): 96



### • Transporting wastewater for reuse/recycl e to a CWT facility and then transporting it again to the next well for fracturing

• Procur ing the services of a C WT 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 f or 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 EP A using 34 S GE 00331.



### Figure D-8. Flow Diagram of On- the

- Fly UOG Produced Water Treatment for Reu se/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 neces sarily required for fracturing. However, some operators may still use TDS removal technologies to
treat wastewater for reuse/recycle in fracturing

. TDS re moval technologies that UOG operators have used to treat UOG extraction wastewater for reuse/ recycl e 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 SGE 00284 ).

3.2 Reuse/Recycle Drivers

The reuse/recycle strategy operators choo se depends on many different factors. The following subsections describe the two biggest drivers ( 105 DCN SGE 00710 ):

• Pollutant concentrations i n UOG extraction wastewater compared to maximum acceptable pollutant concentration s 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

BlenderChapter 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 f actors vary by formation and operator; therefore, the potential for reusing/recycling UOG extraction wastewater for fr acturing 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/recycl e as compared to other ma nagement alternatives.

3.2.1 Pollutant Concentrations in Available UOG Extraction Wastewater for Reuse/Recycl e Operators typically consider TDS when they evaluate whether they can reuse/ recycle their wastewater and, if so, what level of treatment is required pri or 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 Se ction C. 3.2.1 and shown in Figure C-6 , TDS concentrations increase over time as the flow rate decreases after fracturing ( 105 D CN SGE00710, 44 DCN SGE00414, 38 DCN SGE00357, 36 DCN SGE00350, 92 DCN SGE00625) . T heref ore, 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).

S ome 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. A s 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 b e 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 thi s wastewater capable of being used for reuse/recyc le ( 36 DCN SGE 00350). 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 SGE 00625). 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 instabi lity (change in fluid properties)

• Well plugging (restriction of flow)

• Well bacteria growth (buildup of bacteria on casing)

97 Data available to EPA indicates tha t only the initial five percent of the injected fracturing fluid volu me 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

concent rations 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 Concentr ations 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 Scali ng 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 f ormers b Scaling 2,500 Phosphate Not r eported 10

Other

TSS Plugging 50

– 1,500

Oil Fluid stability 5

– 25

Boron F luid 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 strontiu m. 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 qu antity 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

T he volume of fra cturing 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

. T he 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 well s with respect to how much fracturing fluid is required to fr acture 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 blend ing ratio. As explained above, this high ratio may require more treatment dep ending 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 blend ing ratio

. A low blend ing ratio can typically be used with little to no treatment ( 21 DCN SGE00275 ; 95 DCN SGE 00635; 86 DCN SGE 00613). Ta ble D

- 6 shows observed blending ratios for various formations. This table also includes theoretical upper end blending ratios as presented in literature

, based on the typical fracturing fluid volume and produced water volume generated per well 99 

### for each f ormation ( 93 DCN SGE00627; 97 DCN SGE00639; 99 DCN SGE00691)

.

Table D

- 6

. Reported R euse/Recycle Practices as a Percentage of Total Fracturing Volume

Basin Formation Resource Type Observed Blending Ratio a (%) Estimated Maximum Potential Blending Ratio b (%)

Anadarko Cleveland Tight

— 10

– 40

Granite Wash Tight

— 10

– 4 0 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

– 1 0

Tuscaloosa Marine Shale 25

—
Western Gulf Eagle Ford Shale

— 10

– 40

Source s : 179 DCN SGE01179

Note: Data years represented range from 2009 to 2013.

a

— Actual observed volumes of reused/recycled UOG extractio n 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 valu e 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 extr action 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 concept 100 

### with a hy pothetical 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 o f produced wate r generated

. T his 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 dis pose of at least some portion of the produced water such as injection in disposal well s or transfer the wastewater to CWT facilities

.

Source : 179 DCN SGE01179 ( Generated by the EPA based on figure in 32 DCN S GE 00305.A 0 3 )



### Figure D

- 9 . Hypothetical UOG Pro duced Wa ter Generation and Base Fracturing Fluid Demand o ver 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 /recycl e , operators consider the following as they decide whether to reuse/recycle their wastewater:

• Waste water transportation

• Waste water storage

• Source water availability and cost

3.3.1 Transportation
Transportation requirem ents 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 facilit ies, 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, w hen a UOG well generating wastewater is far from management approaches such as a disposal well or CWT fa cility, 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 SGE 00579). This is due to the fact that Marcel lus 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 le ss expensive per b arrel 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 SGE 00300).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 Was tewater 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 op erators 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 well 101 

### ( 21 DCN SGE 00275). For exampl e, 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 job s

. 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 SGE 00283). Section B. 2 explai ns UOG extraction w astewater 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 offse t 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 ). F resh 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/recycl e 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 groundw ater resources are abundant and inexpensive ( 72 DCN SGE 00583; 105 DCN SGE 00710 ; 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 formati on ( 105 DCN SGE 00710). 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 T RANSFER TO 

### CWT F ACILITIES


### Some operators manage UOG extraction wastewater by transporting it to CWT facilities. Treated UOG extraction wastewater at CWT facilities is either discharged 103 

### or returned to the operator for reuse/recycle in fracturing. Operators may choose to u se CWT facilities primarily when other wastewater management options (e.g.

, disposal well s) are not available where they are operating ( 105 DCN SGE 00710; 10 DCN SGE 00139 ).

This section provides a general overview of the type s of CWT facilitie s that exist and that UOG operators may use for wastewater management

, typical CWT facility treatment processes, CWT facilitie s that EPA is aware of that have in the past or currently a ccept UOG extraction

wastewater , and considerations for using CWT facilitie s to manage UOG extraction wastewater

.

4.1 Types of CWT Facilitie s
A CWT facility is any facility that treats (for disposal, recycling

, or recovery of material) any hazardous or nonhaz ardous 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 SGE0 1178 ) , 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 reu sed 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 d ischarge and zero discharge )

Pollutant discharges to surface waters or to POTWs from CWT facilities may not be subjec t to the O il and G as E xtraction ELGs (40 CFR part 435) . Rather, they may be subject to the CWT ELGs promulgated in 40 CFR p art 437. Unlike the Oil and Gas Extraction ELGs, 40 CFR p art 437 includes limitations and standards for both direct and indirect disc hargers

.

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 technologies 104 

### and TDS removal technologies

, 105 

### def ined 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 c urrently use a mix of TDS and non

- TDS removal technologies

. 106



### 4.1.1 Z ero Discharge CWT Facilities

After treatment, a zero discharge CWT facilit y does not discharge the wastewater to surface water or a POTW. Instead, it typically return s the wastewater to UOG oper ators 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

- p er

- barrel basis ( 18 DCN SGE 00245). 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 wa stewater. 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 su rface 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 p art 437 and requirements set out in 40 CFR p art 403. Surface water d ischarges 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 depend s on the requirements in the NPDES permit

, which may or may not include restrictions on TDS. Direct

discharging CWT facilities use a mixture of TDS and non

- TDS removal technologies . However,

104 Examples of CWT facilities using this level of treatment are described in 92 DCN SGE00625; 95 DCN SGE00635, 18 DCN SGE00245, 47 DCN SGE00481, and 43 DCN SGE00379.

105 Examples of CWT facilities using this level of treatment are described in 45 DCN SGE00476, 39 DCN SGE00366, 40 DCN SGE00367, and 42 DCN SGE00374.

106 EPA is currently aware of several discharging CWT facilities accepting oil and gas wastes that, as of early 2016, do not utilize TDS removal technologies. See 178 DC N 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 o r 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 discharging 108 

### CWT facilities may als o recycle a portion of the treated wastewater

. Consequently, these types of CWT facilities may employ both non

- TDS and TDS removal technologies

. One su ch facility is Eureka Resources in Williamsport, Pennsylvania. The Eureka C WT facility holds a General Pe rmit ( WMGR123NC005 ) 109 

### from PA DEP that includes limits 110 

### 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 tec hnology (evaporation/ condensation) ( 31 DCN SGE 00300 ). 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 treat ment train (both non

TDS and TDS removal technologies ). There are no NPDES permit limits that must be met for wastewater that is treated for reuse

. The level of treatment is based on the operators ’ specifications.

4.2 Active CWT Facilitie s Accepting UOG Extrac tion Wastewater

T o date

, the EPA has identified 7 4 CWT facilities that have accepted or plan to a ccept 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 facilitie s , by state

, that have accepted or plan to accept UOG extraction wastewater. The table includes a breakdown by treatment level and facilit y discharge type ( described in Section D. 4.1 ) . The majority of these facilities can treat between 87 ,000 and 1,200 ,000 gallons ( 2

, 1 00 and 2 9

, 0 00 barrels ) per day ( 178 DCN SGE01178 ). 111



### To generate Table D

- 7

, th e 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 Ac cepting UOG Extraction Wastewater ( 178 DCN SGE01178 ) , which list s known CWT facilities along with information such as permit number, location, treatment capacity, and treatment level when available

. Because few sta tes 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 additi on 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 10 th and 90 th percentiles of report ed treatment capacities at CW T facilities

.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 110 Table D

- 7 likely underestimate s 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 Facilities a CWT Facilities That Discharge to a Surface Water or POTW a CWT Facilities with Multiple Discharge Options a 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 2 2 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 Mes averde and Lance 0 2 0 0 0 2 4

Total 4 4 13 9 0 1 7 7 4

Source s : 178 DC N 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 kno wn facilities

.



### This information shows that CWT facilities have develop ed in regions of increasing oil and gas production, especially in areas where capacities for other management practices are less available ( 10 DCN SGE 00139). To illustrate this, the EPA analyzed the number of active CWT facilities available to Marcellus s hale and Utica s hale operators where there are few disposal wells in some parts of the region

. 113 

### Figure D

- 4 illustrat es 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 tr end over time of active CWT facilities available to operators in the Marcellus and Utica s hale s, 114 

### along with the number of UOG wells drilled. The number of CWT facilities available to operators in the Marcellus and Utica s hale s has increased with the numbe r of wells drilled . The EPA observed a similar trend in the Fayetteville s hale formation in Arkansas. Although Arkansas has several

112 The 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 T his analysis include d Pennsylvania, West Virginia, and Ohio.

114 The Marcellus and Utica s hale formations are in the Appalachian b asin.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 Fayettevill e shale wells ( 190 DCN S GE01187 ). 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.

Source s : 178 DC N SGE01178



### Figure D

- 11 . Number of Known Active CWT Facili t ies over Time in the Marcellus and Utica Shale Formation s

5 D ISCHARGE TO 

### POTW S


### 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 discha rge to POTWs. Th i s 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 andChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 112 affect downstream water use ( 27 DCN SGE 00286; 35 DCN SGE 00345; 71 DCN SGE 00579; 59 DCN SGE 00 531 ; 94 DCN SGE 00633 ; 162 DCN SGE01077 ). 115



### This section pro vides 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 [Cl ean 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

Constit uent Concentrations (mg/L)

Weak Moderate Strong

TDS 270 500 860

COD 250 430 800

TSS 120 210 400

BOD 5 110 190 350

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

Nitr ates 0 0 0

Nitrites 0 0 0

Source: 12 DC N SGE 00 1 67 Abbreviation: mg/L

— milligrams per liter



### T ypical 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 removi ng 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 remov ing other pollutants, such as nutrients, not removed in secondary treatment using processes such as nitrification/denitrification and activated carbon adsorptio n ( 12 DCN SGE 00167 ).

Figure D

- 12 shows a typical process flow diagram for a POTW. The processes shown include primary treatment (screen, g rit chamber, primary clarifier), secondary treatment ( trickling filter, aeration, secondary clarifier )

, and disinfection ( chlorine ). The diagram a lso shows sludge treatment (gravity thickening, digestion, filter press) before use/disposal (e.g., land application).

Sourc e: 80 DCN SGE 00 602



### Figure D

- 12 . Typical Process Flow Dia gram 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 an d 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 thisChapter 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 SGE 005 99).

Table D

- 9 shows typical removal perc entages 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 a s n itrogen 39 Molybdenum 19 Antimony 67 Naphthalene 95

Arsenic 66 N ickel 51

Barium 16 Oil and g rease (as HEM) 86 Beryllium 72 Phenol 95

BOD 5 89 Phenolics, total recoverable 57

Boron 30 Phosphorus, total 57

Cadmium 90 Pyridine 95

Calcium 9 Selenium 34

Carbon d isulfide 84 Silver 88

Chloride 57 Sodium 3

Chlorobenzen e 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
Magne sium 14 Xylenes (m+p, m, o+p, o) 65 to 95
Manganese 36 Zinc 79

Source: 79 DCN SGE 00600

Note: 79 DCN SGE 006 00 references data from the November 5, 1999

, updated 50

- POTW study and the RREL database compil ed 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, s econdary treatment was the most common level of treatment at POTWs.

Tab le D-10. U.S. POTWs by Treatment Level in 2012

Treatment Level Percent of Facilities (%) a Number of Facilities a Combined Design Capacity (MGD) a
Less than secondary (e.g., primary) 0.2 3 4 546 Secondary 50.0 7,374 17,765 Greater than secondary (e.g., tertiary, advanced) 34.1 5,036 23,710 No discharge 15.5 2,28 1 2,557

Partial treatment b 0.2 23 287

Total 100.0 14,748 44,866

Source s : 81 DCN SGE 00603 ; 216 DCN SGE0 1332

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 Extra ction Wastewater

As operators began extracting oil and gas from unconventional formations, UOG operators discharged wastewater to POTWs in some cases ( 27 DCN SGE 00286; 35 D CN SGE 00345; 71 DCN SGE 00579). 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 2008 118 

### ( 203 DCN SGE 01245). To identif y POTWs t hat accepted

wastewater from UOG operations, 119 

### the EPA reviewed the following sources:

• Notes from calls with regional and state pretreatment program coordinators ( 113 DCN SGE 00742, 114 D CN SGE 00743)

• 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 SGE 00762)

• EPA Region 3’s website ( 41 DCN SGE 00368)

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 dischargi ng 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 w ith industry representatives ( 86 DCN SGE 00613; 54 DCN SGE00521 ), UOG operators ( 92 DCN SGE 00625; 95 DCN SGE 00635; 21 DCN SGE00275 ; 24 DC N SGE 00280), CWT facilities ( 30 DCN SGE 00299; 31 DCN SGE 00300; 18 DCN SGE 00245; 17 DCN S GE 00244), and Native American tribal groups ( 138 DCN SGE00785 )

• PA DEP’s statewide waste report data 120 

### ( 203 DCN SGE 01245 ; 184 DCN SG E01182 )

• 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 ana lyzed much of these existing data in a separate document

, Publicly Owned Treatment Works ( POTW) Memorandum for the Technical Development Document (TDD) ( 185 DC N SGE01183 ). Thi s m emorandum is referenced throughout S ection 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 ex traction 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 Ana lysis of Pennsylvania Department of Environmental Protection’s (PA DEP) O il and Gas Waste Reports provides more detail ( 184 D CN 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 Current ly Accepting UOG W astewater f rom 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 Ver non 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 Char leroi 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 20 10
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 PA 0026158 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 Waynesbu rg PA No 2008

Source: 185 DCN SGE01183Chapter 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 f rom 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 SGE 01245 ) . Furthermo re, 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 affilia ted 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 discharg e 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

. A s 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 th e rule. Rather, discharges to POTWs from CWT facil i tie s accepting UOG wastewaters ma y be subject to ELGs for the Centr alized Waste Treatment Category (40 CFR part 437)

.

The EPA reviewed PA DEP statewide waste report s ( 184 D CN SGE01182 ) and discharge monitoring report (DMR) data ( 83 DCN SGE 00608) to identif y the total volumes of UOG extraction wastewater and average total influent wastewater for each POTW. Using these data sources, the EPA calculated the maximum annual average daily 121 

### percentage of UOG

extrac tion waste water accepted by the POTW as shown in Table D

- 12 . The EPA found that discharges of UOG extraction waste water 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 waste water volume being accepted by the POTW during that

year. The contribution of UOG extraction waste water 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 waste water was much higher (e.g

. , up to 21 percent ) for some POTWs for some years

.

121 PA DEP w aste r eports provided the total volume of UOG extraction wastewat er 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 Comp o sed of UOG Extraction W astew ater at POTWs Accepting Wastewater from UOG Operators

POTW Name NPDES Permit No. Maximum An nual Average Daily UOG Extraction W astew ater Flow ( god ) Corresponding Total Annual Average Daily Influent Flow to POTW (MGD) a Maximum Annual Average Daily UOG Extraction W astew ater Percent of

POTW Influent (%) Year of Maximum Average Daily U OG Extraction

W astew ater Flow Belle Vernon Borough PA0092355 93,000 0.44 21 b 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 Auth ority 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 S hore 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 PA0037 966 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 H aven 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 extra ction 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 throu gh December 2008). Abbreviations: gpd

— gallons per day; MGD

— million gallons per dayChapter 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 conce ntrations of constituents found in UOG extraction wastewaters. Because they are not typical of POTW influent wastewater, UOG extraction wastewater constituents:

• May be discharged, untreate d, from the POTW to the receiving stream

• May disrupt the operation o f the POTW ( which may lead to exceeding permit limits for BOD 5 

### or TSS in discharges or inhibiting sludge settling , for example)

• May accumulate in sludge, l imiting its use

• May facilitate the formation of disinfection byproducts (DBPs)

Where available, the E PA reviewed the following information related to POTWs that have accepted UOG extraction wastewater:

• Loca l limit evaluations completed by POTW s’ pretreatment program coordinators

• Technical evaluations of the impact of oil and gas wastewater pollutants on P OTW unit processes completed in response to Administrative Orders (A O s) 123 

### issued to a number of POTWs by PA DEP

• Pass through analyses completed by P OTW s

• 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 SGE 01260; 146 DCN SGE 00966) , information and studies on the treatability of these constituents by POTWs ( or their impacts on POTWs ) are s imilarly 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 suspect ed to begin accepting wastewater from UOG operations.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 121 The E PA also reviewed common textbooks on wastewater tre atment technolog y effectiveness

. T hese 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 SGE 00600 ) . 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 POTW s from CWT facilities that accepted oil and gas extraction wastewater

. T o the extent that a CWT facility discharges to a POTW and also lacks technologies that remove some oil and gas extraction pollutant s (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 a nd 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 w astewater 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 Find ings 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 l ess 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. S ee 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 BOD 5 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 BOD 5 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 BOD 5 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 Find ings

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 receive d oil and gas extraction wastewater). The CWT facility targeted removal of TSS and oi l 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 wastew ater from this CWT facility

. See Section
D. 5.3.1.2

.

Wheeling, WV

, POTW The Wheeling POTW receive d oil and gas extraction wastewater from operators as well as industrial wastewater discharges from the Liquid Ass et 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 h igher concentrations of chloride in POTW effluent w hile 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 biologi cal treatment from accepting UOG extraction wastewater pollutants via the LAD CWT facility ’s industrial discharge. The POTW also experienced an up s et that required the introduction of a “seed” sludge to maintain microbial activity in treatment processes. S ee 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 n o TDS or chloride removals. See Section D. 5.3.1.2

.

B r ockway, PA

, POTW The Brockway POTW received natural

- gas

- related wastewater treated by the Dannic Energy Corporation CWT facility. 124
The POTW experienced h ighe r 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 form ation 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



### 123 Table D-13 . Summary of Studies About POTWs Receiving Oil and Gas Extraction Wastewater Pollutants

POTW Summary of Study Find ings

New Castle, PA

, POT W 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 ( oc casional ) 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 clarifier s a t 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 relev ant to POTWs accepting wastewater containing pollutants found in UOG extraction wastewater

. Consistent with wastewater treatment literature, t he 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 wastew ater using screening and grit removal, comminutor s (i.e., grinder s), 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 SGE 00758 ).

On October 23, 2008, PA DEP issued an AO to the Clairton POTW that established requirements for its accept ance of oil and gas wastewater. The AO required the Clairton POTW to restrict the volume of oil and gas wastewater it acce pts 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 D CN SGE01182 ), in 2008, the Clairton POTW was accepting oil and gas wastewater amounting to an average of 0.0 5 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 meas ured concentrations, t he 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 p ass t hrough analysis in August 2009 ( 117 DCN SGE00748 ). Having collected two sets of influent concentration data from two different oil and gas wells , t he consultant stated that the O&G Well No. 2 wastewater “was not characteristic of th e 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 ). Th e p ass 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

- thro ugh” 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



### 125 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 SGE 00748 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, act ivated sludge, aerobic digestion, and chlorine disinfection ( 115 DCN SGE 00745). 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 perc ent 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. Accordi ng to PA DEP da ta ( 184 DCN SGE01182 ), in 2008, the McKeesport POTW was accepting only COG wastewater. The evaluation ( 125 DCN SGE 00757 ) noted :

The results of the samples ta ken 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 . Acco rding to the manifests included in the technical evaluation ( 125 DCN SGE 00757), McKeesport treated trucked wastewater from conventional wells during the seven

- day sampling period . These wastewater

sources are summa rized 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 Wastewat er Treated at McKeesport POTW from November 1 T hrough 7, 2008

Date Waste Type a Volume (gallons) Chlorides (mg/L) Chlorides (lbs)
November 3, 2008 Brine 3,780 155,000 4,886
November 4, 2008 Flow b ack 3,780 145,000 4,571
November 6, 2008 Flow b ack 3,780 1 55,000 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 DC N SGE 00745 ). As part of the analysis, the consultant c ompleted monthly sampling of the influent and effluent of the POTW from February 2010 through January 2011 and determinedChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 127 the average removal percentages based on the sampling results. During the time o f 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 remov als 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 SGE 00745 ).

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 f or 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 POTW s stopped accepting those industrial discharges

. The study included effluent sampling at the McKeespo rt 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. B ased 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 sampl ed POTW effluent in October 2010 , when the POTW was accepting UOG extraction wastewater and again in December 2011

, after the POTW had stopped accept ing COG and UOG extraction wastewater

. 126 

### The study also collect ed one sample in November 2010 of UOG extraction wastewater before it was mixed with the municipal influent 127 

### (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

o f the effluent sampling events.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 128 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 o f 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 wastewat er. 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

. A lthough they rep orted that the facility was accepting UOG extraction wastewater on the first effluent sampling date (Oc tober 19, 2010), sampling data f or that influent UOG extraction wastewater (like th e data presented in Table D

- 17 ) w ere not ava ilable. 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 Wastewat er Treated at the McKeesport POTW Before Mixing with Other Influent Wastewater

Analyte a 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

Sourc e: 56 DCN SGE 00525

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 coll ected 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 SGE 00525 ) 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

Analyte a 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 Ran ge Mean Range

Barium 0.55 0.21

– 0.81 0.036 0.034

– 0.039

Calcium d 50.3 42.4

– 55.9 58.8 56.6

– 63.4 Magnesium d 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

Sourc e: 56 DCN SGE 00525

a

— Organic analytes were not detected in samples.
b

— Sample date: 10/19/2010

. Reported values are based on the m ean, 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 a l. ( 56 DCN S GE00525 ) 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 ta nk, 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 201 1 but continued accepting COG wastewater

, and still was as of the end of 2014

. 129 

### T he total oil and gas wastewater volume accounted for less than 2 percent of the total POTW influent volume during 2009 through 2011 on averag e ( 184 D CN SGE01182 )

. The POTW’s total annual

average daily flow rate range s between 0. 8 and 1. 5 MGD

, based on 2008 to 201 4 DMR data ( 83 DCN SGE 00608 )

.

The EPA created Figure D

- 15 using the sampling data submitted in the EPA ’s DMR Loading Tool ( 83 DCN SGE 00608) 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 t he 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 r epresents 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 t o calculate the annual ave rage daily flow

. As shown in Figure D

- 15 , in 2010, the Ridgway POTW experienced effluent TDS concentrations greater than 6

, 0 00 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 concentration s 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 extrac tion 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 P OTW 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 s tillChapter 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 the se constituents are found in UOG extraction wastewater ( 124 DCN SGE 00756 ).

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 Ja nuary 2005 and stopped accepting it in 2008 ( 120 DCN SGE 00751; 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 1 0 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 M GD based on 2008 through 201 4 DMR data ( 83 DCN SGE 00608) . The EPA identified case studies showing potential for both pass

- through (Section D. 5.3.1.1 ) and inhibition/disr uption (Section D. 5.3.2.1 ) at the Charleroi POTW

.
In 2008, PA DEP issued an AO requiring the Charleroi POTW to evaluate how accept ing oi l and gas production wastewater affect s its treatment processes, among othe r things ( 120 DCN SGE 00751). 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 greate r 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 th is period was 150,650 gall ons (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 SGE 00751)

. 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

BOD 5 84 1.00 98.8
Hardness, as CaCO 3 265 260 1.9

Oil and g rease 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 SGE 00751 Abbreviation: mg/L

— milligrams per literChapter 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 t rial 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. Tot al 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 concentr ation 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

• Nov ember 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 a cceptance 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 SGE 00749; 64 DCN SGE 00552). In July 2009, WV DEP sent a letter to the Clark s burg 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... M arcellus shale wastewaters because these wastewater s 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 SGE 00762; 129 DCN SGE 00766 ).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 SGE 00746). The Franklin Township POTW accepted industrial wastewater f rom 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 filtrat ion, 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 SGE 00525).

On December 4, 2008, the Franklin POTW entered into a Consent Order and Agreement with PA DEP 130 

### 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 Tr i- 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 fo und 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 -C ounty CWT facility

, suggesting that poll utants 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. con cluded:

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 C onsent 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

Analyte a 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

– 3 6.6 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 37 6

– 450

So urce: 56 DCN SGE 00525

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 collec ted 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 disinfect ion ( 155 DCN SGE 00999). The Wheeling POTW accepted industrial wastewater from the Liquid Asset Disposal (LAD) CWT facility through August 2009 131 

### and wastewater directly from UOG operators in 2008

. 132 

### The LAD CWT facil ity 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 i nto the Wheeling, WV

, POTW (SIU Permit No. 0014) ( 48 DCN SGE 00485 )

. 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 SGE 00996 )

.

The EPA analyzed sampling da ta submitted in its DMR Loading Tool ( 83 DCN SGE 00608) and PA DEP waste reports data ( 184 D CN 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 d ate 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 waste water directly from operators in years other than 2008, but EPA only identified acceptance directly from operators in 2008 ( 202 DCN SGE 01245 ).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 stoppe d

. In 2008, the POTW accepted an average of 5,400 gallons/day of UOG extraction wastewater and had an average effluent chlo ride concentration of 650 mg/L

. C omparatively , in 2011

, the POTW did not accept any UOG extraction wastewater and had an average effl uent chloride concentration of 130 mg/L

. 133 

### Data from an August 2009 letter from WV DEP to the City of Wheeling states ( 167 DCN SGE01 114)

The agency has determined that the following pollutants are of concern
associa ted 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, gros s 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 t he 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 SGE 00485). The refore, 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 dissolve d 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 wast ewater 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 oth er 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 an d 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 SG E 00522 ).

The pilot study began o n 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 chl oride 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 week s (p ercentage of total POTW flow accounted for by Patriot CWT facility ’s industrial wastewater is noted parenthetically) 135 

### ( 88 DCN SGE 00616 ):

• Week 1: 5 days @ 20,000 gallons (0.15 percent )

• Week 2: 5 days @ 40,000 gallo ns (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 wh en 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 SGE 00616 ), suggesting that TDS and c hloride 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 als o 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 sprin g 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) Perce nt 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 SGE 00616 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 indic ated 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 NA b

BOD 5 33.3 27.7

– 39.0 <2 NA b

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 SGE 00616

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.
Abbrevi ation: mg/L

— milligrams per literChapter 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 SGE 00786). Its NPDES permit allows it to accept a maximum of 100,000 gallon s of “wastewater from a regulated CWT facility that is tributary to the City’s collection system ” per day (0.67 percent of it s maximum total daily flow) at a maximum TDS concentration of 50,000 mg/L ( 29 DCN SGE 00295).

Brockway, PA , POTW
The Brockway POTW treat s 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 exp iring 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 Brockwa y 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 SGE 00931). The permit includes limits for pH, carbonaceous BOD 5 

### , 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. Ty pical COG wastewater accepted by the Brockway POTW may have TDS concentrations over 200,000 mg/L ( 121 DCN SGE 00753).

5.3.2 UOG Extraction Wastewater Constituents and POTW Inhibition and Disruption
In addition to the discharge of pollutants not treated by a POTW, t he 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

• Inhibiti on or d isrupt ion of the POTW’s sludge processes, including sludge disposal

processes

• H ar m to POTW workers

The EPA investigated how pollutants in industrial wastewater discharges, which may contain constituents found in UOG extraction wastewater, might inhi bit 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 consti tuents 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 incl uded 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. Inh ibition of activated sludge processes at a POTW could impair BOD 5 

### 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 Trea tment 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, 20 0, 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 S GE 00602 by different sources. Abbreviations: mg/L

— milligrams per liter; NA

— not available



### Because all POTWs are required to control TSS and BOD 5 

### , they are designed for the effective removal of these two parameters. Elevated concentrations of TSS and BOD 5 

### i n 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 BOD 5 

### 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/disrupti on, 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 scree ning, grit removal, high

- purity oxygen activated sludge aeration with integrated fixed

- film activated sludge, final clarification, and chlorination ( 142 DCN SGE 00930). The Johnstown POTW accepted both UOG and COG w astewater 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 1 7.1 MGD based on 2008 through 2014 DMR data ( 83 DCN SGE 00608).

The EPA created Figure D-16 using the sampling data submitted in it s DMR Loading Tool ( 83 DCN SGE 00608) and PA DEP waste reports data ( 184 DCN SGE01182). Each effluent concentration data point represents the av erage 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 annu al 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. I n a December 2012 letter regarding the 2011 annual pretreatment report, Johnstown’s pretreatment coordinator stated,

[We] k now that the treatment plant no longer accepts gas drilling waste, 138 

### and we anticipate that the number of violations will decrease.

Fu rther, 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 large st 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, t he 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 stabilization 140 

### process to treat influent wastewater ( 140 DCN SGE 00787 ). 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 201 4 DMR data ( 83 DCN SGE 00608).

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 pha se. Aeration volume requirements are half of those for conventional activated slu dge ( 12 DCN S GE00167 ).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 SGE 00608) and PA DE P 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 prov ided 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 elevate d 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 SGE 00608) and PA DEP waste reports data ( 184 DCN SGE01182 ). E ach 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 BOD 5 

### 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

. 

### Figu re D

- 18 . Charleroi POTW : Annual Average Daily Effluent Concentrations and POTW Flows 142

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 oper ators , f rom June 200 6 to November2008. 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 range d between 0. 37 a nd 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 clarifie r, and chlorine disinfection ( 153 DCN SGE 00997, 154 DCN SGE 00997.A01).

T he 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 SGE 00750), 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 waste water

. 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, th e facility appl ies additional treatment with flocculants ( 65 DCN SGE 00554).

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 it s 2013 NPDES permit indicates that all permit limits were based on an effluent discharge rate of 17 MGD ( 65 DCN SGE 00554 ; 69 DCN SGE 00573 ).

Table D-24. Industrial Wastewater Volumes Received by New Castle POTW (2007 –2009)

Year Industrial Wastewater Volume ( gpd ) Percent of Total Volume Treated by POTW a

2007 74,278 0.44%

2008 130,608 0.77%

2009 331,381 1.95%

Source: 65 DCN SGE 00554

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 SGE 00554 ) states that :

It is believed that pretreated brine wastewater from t he 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 fl ow 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 a nnual report , instability in sludge blanket levels can cause increased washo uts 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 SGE 00554 ) . 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 CW T 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

, inc luding 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 faci lity

, 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 (%)

Mar ch 2009 TSS Weekly maximum 45 58 29

Mar ch 2009 TSS Monthly average 30 37 23 May 2009 TSS Monthly average 30 34 13

Jun e 2009 TSS Monthly average 30 38 27

Jul y 2009 TSS Weekly maximum 45 64 42

Jul y 2009 TSS Monthly average 30 45 50 Aug ust 2009 TSS Weekly maximum 45 61 36 Aug ust 2009 TSS Monthly average 30 50 67 Sep tember 2009 TSS Monthly average 30 37 23

Oct ober 2009 TSS Weekly maximum 45 46 2

Oct ober 2009 TSS Monthly average 30 31 3

Jan uary 2010 TSS Weekly ma ximum 45 60 33

Jan uary 2010 TSS Monthly average 30 40 33

Feb ruary 2010 TSS Monthly average 30 33 10

Mar ch 2010 TSS Monthly average 30 38 27Chapter 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 (%)

Mar ch 2010 TSS Weekly maximum 45 55 22

Nov ember 2010 TSS Monthly average 30 34 13

Nov ember 2010 TSS Weekly max imum 45 55 22

Dec ember 2010 TSS Weekly maximum 45 56 24

Nov ember 2011 TSS Monthly average 30 35 17

Nov ember 2011 TSS Weekly maximum 45 64 42

Source s : 89 DCN SGE 00620 ; 85 DCN SGE 00612 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 Whe eling 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 SGE 00485 ):

• 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 occurre d 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 incr eased 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 includin g 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 natur al -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 startin g in November 2008 and noticed an increase in sludge generation

. 144 

### Th e 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 SGE 00753).

5.3.2.3 POTW Sludge and Scale Formation

UOG extraction wastewater is also a concern in the disruption of POTW sludge processes, inc luding 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 i n sludge. A POTW accepting wastewater with high metals concentrations may no longer be able to land

apply its sludge because it may violate sludge disposal rules.

While UOG extraction wastewater does not typically contain concentrations of heavy metals at levels that would likely prohibit the POTW from land- applying its sludge (see Table C-17 ), the EPA has identified the potential for elevated concentrations of radium

- 226 and -228 in sludge ( 9 DCN SGE 00136 ; 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 

### disp osal at a hazardous waste landfill

, 146 

### or disposal at a low

- level radioactive w aste landfill 147 

### ( 87 DCN SGE 00615 ).

In addition to inhibiting the performance of treatment operations, UOG extraction wastewater may disrupt PO T W 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 e xtraction 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 SGE 00768 .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 sca le accumulation at POTWs. Because radium 148 

### 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 hav e 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 report 149 

### ( 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, wastew ater 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 naturall y 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 Pennsylvan ia, 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, sludg e, 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 w ith 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 radiolo gical 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 implement ation 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 SGE 00519 ; 74 DCN SGE 00587 ).

Rowan et al

. ( 16 DCN SGE00241) report a positive correlation between TDS concentrations and radium activity based on data for produc ed 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 accumulatio n in sludge. However, t he existing literature contains limited sampling data measuring radioactive constituents in UOG extraction wastewater (see Table C

- 19 ) . Therefore, the potential for TENORM accumulation in sca le 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 d isposal options, and environmental impacts. PA DEP analyzed l iquid 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:

• W ell sites

— PA DEP sampled 38 well sites (4 conventional wells and 34 unconventional wells) from June 2013 through July 2014

• W astewater 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 cake s 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 distribut ion, 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

- 22 8” ( 161 DCN SGE01028)

.
PADEP concluded, “...[t] here is little potential for radiologica l 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 long

term disposal of POTW

- I filter cake” ( 161 DCN SGE01028 ) . ERG’s Radioactive Materials in

151 PA DEP defines a “POTW

- I” as a POTW that was considered to be influenced by having received wastewater from the oil and gas industry.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 D EP 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, disinfecti on 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 ) , wh ich

are precursor s of several toxic DBPs ( 51 DCN SGE 00509; 122 DCN SGE 00754). Brominated DBPs are reported to have greater health risks (e.g., higher risk of cancer) than chlorinated DBPs ( 141 DCN SGE 00800 ). Additional information and discussion on DBPs and other human and ecological impacts can be found in other EPA resources ( 163 DCN SGE010 93; 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 SGE 00535)

• When a POTW discharge s 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 SGE 00587)

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

co ncentrations 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 operatio ns (hereafter referred to as “ oil and gas wastewater”) could create DBPs, particularly brominated DBPs ( 62 DCN SGE 00535).

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 POTW s 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 s ampling results showing higher concentration s 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 w aste w ater may contribute to the formation of DBP s 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 a Sample Date 8/20/2012 11/28/2012 4/17/2013 4/17/2013 Accepted Oil and Gas Wastewater No No Yes Yes

Bromochloroiodomethane ND ND 0.10 0.12 0.02

Bromodichloro methane BDL b ND BDL b BDL b 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 BDL b BDL b 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 d etection limits (MDLs) in surface water samples

, as reported by Hladik et al. ( 62 DCN SGE 00535)

. 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 fr om Hladik et al. ( 62 DCN SGE 005 35 ).
Abbreviation: ND —n on d etect ; μ g/L

— mi cro grams 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 DBP s (e.g., brominated trihalomethanes)

, downstream of POTWs that accepted UOG extraction wastewater ( 68 DCN SGE 00567; 74 DCN SGE 00587).

Wilson and Van Briesen ( 94 DCN SGE 00633 ) 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, bromodich oloromethane) 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 ce rtain 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) wer e 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 Ma nagement 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 pra ctice. They further reported that the dis charge of high

- TDS loads into surface waters that could be drinking water treatment intakes should be p rohibited. Eshelman and Elmore state that

Higher chloride levels cause taste and odor problems in finished wate r. High bromide levels lead to increased formation of carcinogenic disinfectant by

products that can persist in the water to the point of consumption. Treatment of produced water by POTWs and other conventional wastewater treatment methods that do not remo ve 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 SGE 00800 )

. 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 renewa l . 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 fr om 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 limi ts. 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 I n August 2013, EPA Region 3 issued a letter ( 144 DCN SGE00935) informing the NPDES permitting authorities in the Mid

- Atlantic r egion that

... conventional and nonconventional pollutants, such as bromide, must be tested by existing dischargers as part of the permit application process if such p ollutants 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 i n 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

param eter 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 SGE 00935.A 0 1 ) :

• 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

Parke r et al. published an article in September 2014 ( 151 DCN SGE 00985) 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 dilutio n as low as 0.01 percent could result in altered speciation toward the formation of brominated and iodinat ed DBPs. The results also show that UOG produced water di lution 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

treatm ent

.Chapter E

—

Reference Flags and List



### 155 

## Chapter E. R EFERENCE 

## F LAGS AND 

## L IST



### 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 f or 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 q uality f lag “A ”

— j ournal articles and documents prepared by or for a government agency (e.g., EPA site visit reports, industry meeting notes)

• Source q uality f lag “B”

— d ocuments prepared by a verified source that include citation information (e.g ., operator reports, vendor documents, university publications)

• Source q uality f lag “C”

— d ocuments prepared by a verified source that do not include citation information (e.g., operator reports, vendor documents, conference presentations)

• Source q uality f la g “D”

— d ocuments 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/Oil

Gas/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 aterMgm tinMarcellusfull.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 C ooperative 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). BChapter E

—

Reference Flags and List



### 1 56 Table E

- 1 . Source List

ID DCN Source Citation Source Flag

6 SGE00110 Bruff, Matthew. 2 011. 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 I I 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

, 201 6 : 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 Practi ces 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 Tr eatment Requirements. (August). A

15 SG E00239 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 i n 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 Ca ll 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 G as Operations. (January 22). A

22 SGE00276 U.S. EPA. 2012. Meeting with XTO Energy, Inc. about Unconventional Oil and Gas Sanitized. AChapter 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 Sta r 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 S GE00283 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. Resea rch 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 Pollu tion 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 Str eams) 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 W ater 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 La boratory. 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. 2 011. 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. CChapter E

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40 SGE00367 CARES. n

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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

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- 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 th e 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. (Apri l). 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 Ange lo, 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 (AOG C). 2013. Welcome to the Arkansas Oil and Gas Commission Online Production a nd 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 Univer sity. 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. 201 2. Patriot Water Treatment, LLC, and City of Warren v. Chris Korleski, Director of Environmental Protection, and Scott Nally, Director of Environmental Protection: 2012 Decision. AChapter E

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56 SGE00525 Ferrar, Kyle J.; Michanowicz, Drew R.; C hristen, Charles L.; Mulcahy, N.; Malone, Samantha L.; Sharma, Ravi K. 2013. Assessment of Effluent contaminants from Three Facilities Discharging Marcellus Shale Wastewater to Surface Waters in Pennsylvania. Environmental Science & Technology 47:3472

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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

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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 Frequ ently 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, Ma rk. 2014. Discharges of Produced Waters from Oil and Gas Extraction via Wastewater Treatment Plants Are Sources of Disinfection By

- products to Receiving Streams. Science of the Total Environment 466

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63 SGE00545 Klabe r, Kathryn. 2011. Letter to Michael Krancer, PA DEP. Marcellus Shale Coalition. (April 20). C

64 SGE00552 Mon River Recreation and Commerce Committee. 2009. Minutes of Mon River Recreating & Commerce Committee Meeting 12 December 200 8. Last access on May 17, 2016 : http://www.monriversummit.org/MRRCC_archive/MRRCC_minutes/MRRC C

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65 SGE00554 Widmer Eng ineering, Inc. 2010. New Castle Sanitation Authority, New Castle, Lawerance County, Pennsylvania: Annual Pretreatment Report, 2009 Operating Year. Prepared for New Castle Sanitation Authority. A

66 SGE00556 Nicot, Jean

- Philippe, et a l. 2011. Current and Projected Water Use in the Texas Mining and Oil and Gas Industry. University of Texas at Austin, Bureau of Economic Geology. Prepared for Texas Water Development Board. A

67 SGE00557 NDIC. 2014. Basic Subscriptio n Services

— Well Index. Department of Mineral Resources, Oil and Gas Division. Last Accessed on 1/27/2014. A

68 SGE00567 Handke, Paul. 2008. Trihalomethane Speciation and the Relationship to Elevated Total Dissolved Solid Concentratio ns Affecting Drinking Water Quality at Systems Utilizing the Monongahela River as a Primary Source During the 3 rd and 4 th Quarters of 2008. Pennsylvania Department of Environmental Protection. 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. AChapter E

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70 SGE00575 Petroleum Equipment Suppliers Association (PESA) . 2012. Outlook for Domestic Unconventional Resources. Presentation at PESA Annual Meeting. B

71 SGE00579 Rahm, Brian, et al. 2013. Wastewater Management and Marcellus Shale Gas Development: Trends, Drivers, and Planning Implication s. Journal of Environmental Management 120:105

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72 SGE00583 Romo, Carlos; Janoe, J. Scott. 2012. Regulatory Regimes for Recycling Produced and Frac Flowback Water. Paper 2012

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73 SGE00586 St ate Review of Oil and Natural Gas Environmental Regulations (STRONGER). 2003. West Virginia Follow

- Up and Supplemental Review. (January). A

74 SGE00587 States, Stanley et al. 2013. Marcellus Shale Drilling and Brominated THMs in Pitt sburgh, Pa., Drinking Water. Journal AWWA. (August). A

75 SGE00592 U.S. Department of Energy (U.S. DOE). 2013. Water Issues Dominate Oil and Gas Production. E&P Focus. (Fall). A

76 SGE00593 U.S. Energy Informat ion Administration (EIA). 1993. Drilling Sideways

— A Review of Horizontal Well Technology and Its Domestic Application. DOE/EIA

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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 States. EPA 530

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79 SGE00600 U.S. EPA. 2003. Development Document for the Final Effluent Limitations Guidelines and Standards for the Metal Products and Machinery Point Source Category. EPA 821

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80 SGE00602 U.S. EPA. 2004. Local Limits Development Guidance Appendices. EPA 833

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- 002B. (July). Last accessed on May 17, 2016 : http://www.epa.gov/npdes/pubs/final_local_limits_appendices.pdf A

81 SGE00603 U.S. EPA. 2008. Clean Watersheds Needs Survey: 2008 Report to Congress. EPA 832

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82 SGE00604 U.S. EPA. 2010. Hydraulic Fracturing Research Study. EPA 600

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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 Pri macy. Downloaded on 10/24/2013. A

85 SGE00612 U. S. EPA. 2013. DMR Loading Tool Download for New Castle POTW (NPDES No. PA0027511). Downloaded on 11/22/2013. A

86 SGE00613 U.S. EPA. 2013. Meeting Summary: Meeting with Industry Representatives About the Unconventional Oil and Gas Ef fluent Guideline Rulemaking. (February 28). A

87 SGE00615 U.S. EPA. 2013. Radionuclides in Drinking Water: Waste Disposal Options. (November 26). AChapter E

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88 SGE00616 U.S. EPA. 2013. Summary of the Technical Workshop on Wastewater Treatment and Related Modeling. (April 18). A

89 SGE00620 U.S. EPA. 2011. (Region 3) Administrative Order for Compliance and Request for Information, EPA Docket No. CWA

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90 SGE00622 U.S. Geological Survey (USGS). 2013. Water Resources and Shale Gas/Oil Production in the Appalachian Basin

— Critical Issues and Evolving Developments. (August). Last accessed on May 17, 2016 : http://pubs.usgs.gov/of/2013/1137/pdf/ofr2013

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91 SGE00623 U.S. Government Accountability Office (GAO). 2012. Energy

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- Nexus: Information on the Quantity, Quality, and Management of Water Produ ced During Oil and Gas Production. (January). GAO

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92 SGE00625 U.S. EPA. 2013. Site Visit Report: Southwestern Energy (SWN) Fayetteville Shale Gas Operations Sanitized. A

93 SGE00627 Vidic, Radisav; Br antley, 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
Ma nagement 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 Min ing Water Use Report. University of Texas at Austin, Bureau of Economic Geology. (September). A

98 SGE00667 Lord, R. LeBas; Luna, D.; Shahan, T. 2013. Development and Use of High

TDS Recycled Produced Water for Crosslinked

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- Based Hydraulic Fracturing. SPE 163824. Society of Petroleum Engineers. B

99 SGE00691 U.S. EPA. 2013. Summary of the Technical Workshop on Water Acquisition Modeling: Assessing Impacts Through Modeling and Other Means. (September). A

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 February 2014. (March 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 Fracturing Fluid. Hydrozonix, LLC. Presentation at American Association of Petroleum Geolog ists’ Geosciences Technology Workshop. (March 18). B

103 SGE00708 Environmental Leader. 2013. Unconventional E&P “$8 Billion of US Water Services Market.” (November 11). BChapter E

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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. Key Shale Gas Water Management Strategies: An Economic Assessment Tool . SPE 157532. Society of Petroleum Engineers. (September 11). B

106 SGE00721 U.S. EPA. 2015. Evaluation of Hydraulic Fracturing Fluid Data from the FracFocus Chemical Disclosure Registry 1.0. (March). A

107 SG E00722 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. 20 11. Characterization of Organics in the Marcellus Shale Flowback and Produced Waters. Pennsylvania State University. Master’s Thesis. (August). 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 Contributions. 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 Maryland Department o f the Environment. (February 18). 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. (March). 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 Pass

Through Anal ysis 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 Clea n Water Act Section 308 Request for Information. (March 31). A

120 SGE00751 Borough of Charleroi. 2008. Re: Authority of the Borough of Charleroi Administrative Order. (November 21). A

121 SGE00753 Keister, Tim othy. 2010. Marcellus Hydrofracture Flowback and Production Wastewater Treatment, Recycle, and Disposal Technologies. Presentation at The Science of Marcellus Shale. (January 29). BChapter E

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122 SGE00754 Vengosh, A.; Jackson, Robert B.; Warne r, N.; Darrah, Thomas H.; Kondash, A. 2014. A Critical Review of the Risks to Water Resources from Unconventional Shale Gas Development and Hydraulic Fracturing in the United States. Environmental Science & Technology 48(15):8334

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123 SGE00755 Pennsylvania Department of Environmental Protection (PA DEP). 2011. NPDES Permit No. PA0023213 (Borough of Ridgway). (October). A

124 SGE00756 Hill Engineering, Inc. 2014. Re: Local Limits Analysis for Ridgway Borou gh. (January 9). A

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 Wastewater Treatment Facility. (November). A

126 SGE00758 KLH Engineers. 2009. Technical Evaluation of the Impact of Oil and Gas Well Wastewaters on the Clairton Municipal Authority Wastewater Treatment Facility. (February). A

127 SGE00760 Freyman, Monika. 2014. Hydraul ic Fracturing & Water Stress: Water Demand by the Numbers. Ceres. (February). B

128 SGE00762 U.S. EPA. 2013. US EPA Technology Innovation Project: ECOS/ACWA Conference Call. (April 25). A

129 SGE00766 U.S. EPA. 2014. Lockhart, John V. Email Correspondence between WV DEP and EPA. (June 3). A

130 SGE00767 West Virginia Department of Environmental Protection (WV DEP). 2010. Letter to City of Follansbee Re: WV/NPDES Permit No. WV0020273 Accept ing Oil and Gas Wastewater. (December 15). A

131 SGE00768.A01 Robart, Alexander. 2014. E&P Infrastructure vs. Third

- Party Services Regional Economic & Environmental Factors. PacWest Consulting Partners. B

132 S GE00768.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 Characteristi cs of Source, Flowback, & Produced Water for Effective Water Treatment. (May 29). B

134 SGE00769 International Atomic Energy Agency (IAEA). 2014. The Environmental Behaviour of Radium: Revised Edition. Technical Report Series No. 476

. (March 1). A

135 SGE00779.A24 Mastowski, Ryan. 2014. Disposal

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- 14). B

136 SGE00780 ExxonMobile. 2014. Hydraulic Fracturing Fluid. XTO Energy. Downloaded on 6/13/2014. C

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
Wastewater. A

139 SGE00786 U.S. EPA. 2014. UOG Workgroup

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ID DCN Source Citation Source Flag

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. Environmental Engineering & Technology, Inc. A

142 SGE00930 Pennsylvania Department of Environmental Protection (PA DEP). 2012. Johnstown Redevelopment Authority (PA0026034)

— Final Fact Sheet 2012. A

143 SGE00931 Pennsylvania Department of Environmental Protect ion (PA DEP). 2012. Brockway Area Sewer Authority

— PA0028428

— Final Permit 2012. A

144 SGE00935 U.S. EPA. 2013. Letter to Lee McDonnell, PA DEP, Informing NPDES Permitting Authorities of Testing as Part of the Permit Application Proces s. (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 Calif ornia: An Independent Review of Scientific and Technical Information. Sacramento, CA. A

147 SGE00978 PA DEP. 2014. PA DEP TENORM Study

— Update 2 nd Quarter 2014 Update. A

148 SGE00982 U.S. EPA. 2011. (Region 3) L etter to PA DEP regarding disposal of Marcellus Shale wastewater. (May 12). A

149 SGE00983 Ohio Revised Code. 2012. Title 15, Chapter 1509: Division of Oil and Gas Resources Management

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150 SGE00984 Energy Information Administration (EIA). 2014. Glossary. Last accessed on May 17, 2016 : http://www.eia.gov/tools/glossary A

151 SGE009 85 Parker, Kimberly M.; Zeng, Teng; Harkness, Jennifer; Vengosh, Avner; Mitch, William A. 2014. Enhanced Formation of Disinfection Byproducts in Shale Gas Wastewater

- Impacted Drinking Water Supplies. Environmental Science & Technology 48(19):11161

– 11169. A

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 W aynesburg. 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 Wa ter Pollution Control Division. 2007. Wheeling Effluent
Data. A

157 SGE01006 U.S. EPA. 2000. Development Document for Final Effluent Limitations Guidelines and Standards for Synthetic

- Based Drilling Fluids and Other Non

Aqueous Drill ing Fluids in the Oil and Gas Extraction Point Source Category. EPA

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ID DCN Source Citation Source Flag

158 SGE01009 Caen, R., Darley, H.C.H., and G. R. Gray. 2011. Composition and Properties of Drilling and Completion Fluids. 6 th edition. G ulf Professional Publishing: Waltham, MA. B

159 SGE01012 U.S. EPA. 2014. Class II Disposal Well Inventory Update. Office of Ground Water and Drinking Water. (July 29). A

160 SGE01017.A05 Anglund, E. 2014. Rev O ps Strategies for Sourcing Large Volumes of Freshwater for Hydraulic Frac Ops in the Context of Competition from other Ind. C

161 SGE01028 Pennsylvania Department of Environmental Protection. 2015. Technologically Enhanced Naturally Occurring Radioactive Materials (TENORM) Study Report. A

162 SGE01077 Ground Water Protection Council (GWPC). 2014. Regulations Designed to Protect State Oil and Gas Water Resources. Last accessed on May 17, 2016 : http://www.gwpc.org/sites/default/files/files/Oil%20and%20Gas%20Regulati on%20Report%20Hyperlinked%20Version%20Final

- rfs.pdf A

163 SGE01093 Abt Associates. 2015. Final Annotated Bibl iography for Sec XIV,
Env ironmental Impacts, of the Preamble for “ELG and Standards for the O&G Extraction Point Source Cat; Prop Rule” 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 USGS. 2015. Trends in Hydraulic Fracturing Distributions & Trt Fluids, Addit ives, Proppants, & Water Volumes Applied to US Wells Drilled, 1947

- 2010: Attachment 9: Frac_Trtm_Type.xlsx

. A

166 SGE01113 West Virginia Department of Environmental Protection (WV DEP). 2009. WV/NPDES Permit No WV0023302 Clarksburg S anitary 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 Soluti on Mining Regulatory Program. A

17 0 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 Produc ed Water Volumes & Management Practices in 2012. Veil Environmental, LLC. Prepared for Ground Water Protection Council (GWPC). A

172 SGE01143 Lyons, B. and Tintera, J.J. 2014. Sustainable Water Management in the Texas Oil and Gas Ind ustry. Atlantic Council. Energy & Environment Program. B

173 SGE01166 Warner, N.R., et al. 2014. New Tracers Identify Hydraulic Fracturing Fluids and Accidental Releases from Oil and Gas Operations. AChapter E

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ID DCN Source Citation Source Flag

174 SGE01 168 Myers, J.E. 2014. Chevron San Ardo Facility Unit (SAFU) Beneficial Produced Warer Reuse for Irrigation. Chevron. Society of Petroleum Engineers. A

175 SGE01169 FracFocus. 2015. FracFocus Database Version 2.0. Accessed on July 22 2015. A

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 Documen t (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 Characte rization 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. Unconvent ional Oil & Gas Wastewater Treatment Technologies. U.S. EPA Office of Water, Engineering and Analysis Division

. A

190 SGE01187 ERG. 2016. Analysis of Active Underground Injection for Disposal Wells. A

191 SGE01 187.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

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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 En ergy Outlook 2015 with Projections to 2040. DOE/EIA

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195 SGE01206 Cart, J. 2015. Hundreds of illicit oil wastewater pits found in Kern County. LA Times

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196 SGE01207 US Govt Accountabil ity Office. 2015. Water in the energy sector: Reducing freshwater use in hydraulic fracturing & thermoelectric power plant cooling. A

197 SGE01208 State Review of Oil and Natural Gas Environmental Regulations, Inc. 2015. STRONGER: 20 15 Guidelines. A

198 SGE01216 Ellsworth, W.L. 2013. Injection

- induced earthquakes. Science 341(6142). July 12, 2013. doi: 43 10.1126/science.1225942. A

199 SGE01231 Maloney, K.O. and Yoxtheimer, D.A. 2012. Prod uction and Disposal of Waste Materials from Gas and Oil Extraction from the Marcellus Shale Play in Pennsylvania. Environmental Practice. A

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 10/12/2015. B

202 SGE01235 Baker Hughes. 2015. North America Rotary Rig Count (Ja n 2000

– Current). (October 9). Downloaded on 10/12/2015. B

203 SGE01245 O ’ Connell, James, ERG. 2014. Pennsylvania Department of Environmental Protection’s (PA DEP) Statewide Oil and Gas Waste Reports. (December). A

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 Stat e 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, Re serves, and Production. Last accessed on May 17, 2016: http://www.eia.gov/maps/maps.htm A

209 SGE01260 U.S. Geological Survey (USGS). 2014. National Produced Waters Geochemical Databa se 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. EPA

821

- R

- 16

- 003. A

213 SGE01322 U.S. Department of Energy. 2015. US Tight Oil Production Decembe r 2015. U.S. Energy Information Administration (EIA). AChapter 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 Ma y 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 I nitiative. B

225 SGE01345 Toxicity of acidization fluids used in California oil exploration DCN SGE01345 A

226 SGE01351 Weingartern, M., S. G e, 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 Natu ral 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 AChapter F

—

Appendices



### 169 

## Chapter F. A PPENDICES



### Table F

- 1 . TDD Supporting Memoranda and Other Relevant D ocuments 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 ac cepted 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

use d to treat UOG wastewater at full

- scale operations and technologies not currently used to treat UOG extraction wastew ater, 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 (U OG) 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 Unconve ntional Oil and Gas (UOG) Extraction Wastewater Summarizes the data collected as part of the tribal outrea ch efforts associated with the rule. D. 5Chapter F

—

Appendices



### 170 Table F

- 1 . TDD Supporting Memoranda and Other Relevant D ocuments 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. I ntro

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 an d 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 applicableChapter F

—

Appendices



### 171 Table F

- 2

. Cross walk 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 S GE01179 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

. Cross walk 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 Was te 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 O il and Gas (UOG) Produced Water Volumes and Characterization Data Compilation Figure C

- 4 Chloride, Sodium, and Calcium Concentrations in Flowback and Long

- Term Produced Wat er (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 Sour ces for Base Fluid in Hydraulic Fracturing Yes SGE01179 Data Compilation Memorandum for the Technical Development Document (TDD)

Table C

- 2 Fracturing Fluid Additives, Com mon Compounds, and Common Uses No SGE00070, SGE00721, SGE00780, SGE00781, SGE00966 —Chapter F

—

Appendices



### 173 Table F

- 2

. Cross walk 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 Ga s 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 Enviro nmental 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 fr om Marcellus Shale Formation Wells Yes SGE01181 Unconventional Oil and Gas (UOG) Drilling Wastewater Memorandum

Table C

- 11 Concentrations of Select Classical and Conventio nal 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 MemorandumChapter F

—

Appendices



### 174 Table F

- 2

. Cross walk 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 Cha racterization 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 P ennsylvania (2008

– 2014) Yes SGE01182 Analysis of Pennsylvania Department of Environmental Protection’s (PA DEP) Oil and Gas Waste ReportsChapter F

—

Appendices



### 175 Table F

- 2

. Cross walk 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 SGE01 192 ; SGE01128 ; SGE01340; SGE01339 SGE01322 —

Figure D

- 6 Injection for Disposal Volume and Crude Oil Production over Time in North Dakota No SGE01337 ; SGE00182; SGE01128 ; SGE01 340 —

Figure D

- 7 Injection for Disposal Volume, Cumulative Bakken Wells Drilled, and Cumulative Disposal Wells Drilled in North Dakota No SGE00557; SGE00182; SGE01128; SGE 01340 —

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 Evaluatio n 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

. Cross walk 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 Techni cal Development Document (TDD) Figure D

- 18 Charleroi POTW: Annual Average Daily Effluent Concentrations and POTW Flows Yes SGE01183 Publicly Owned Treatment Works ( POTW)
M emorandum 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 Prac tices Yes SGE01179 Data Compilation Memorandum for the Technical Development Document (TDD)

Table D

- 2 Distribution of Active Class II Disposal Wells Across the United Sta tes 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 Analysi s 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

. Cross walk 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 UO G 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 SGE0060 3 ; SGE0 1332 —

Table D

- 11 POTWs That Accepted UOG Extraction Wastewater Directly from Onshore UOG 

### Operators Yes SGE01183 Publicly Owned Treatment Works ( POTW) Memorandum fo r 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 Receivin g 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 Extra ction Wastewater Treated at the McKeesport POTW Before Mixing with Other Influent Wastewater No SGE00525

—

Table D

- 18 McKeesport POTW Effluent Concentrations With and With out UOG Extraction Wastewater No SGE00525

—Chapter F

—

Appendices



### 178 Table F

- 2

. Cross walk 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 Tri

County 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

—

Tabl e D

- 24 Industrial Wastewater Volumes Received by New Castle POTW (2007

– 2009) No SGE00554

—

Table D

- 25 NPDES Permit Limit Violatio ns 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 Wa ter 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 Reso urce 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 w ithout 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 ( MM b ls

per well) Gas EUR ( Bcf per

well) Oil TRR (MMbls) Gas TRR (Bcf) New Well Potential

1

— East Appalachian Devonian Shale g as 0.000 0.061 0 23,700 388,500

Marcellus Shale g as 0.003 1.581 300 148,700 94,000

Utica Shale g as 0.002 0.470 200 53,100 112,900

Shale o il 0.043 0.092 700 1,500 16, 300

Illinois New Albany Shale g as 0.000 1.188 0 29,100 24,500 Michigan Antrim Shale g as 0.000 0.120 0 12,700 105,800

2

— Gulf Coast Black Warrior Floyd

- Neal/Conasauga Shale g as 0.000 1.520 0 4,300 2,800

TX

- LA

- MS Salt Haynesville

- Bossier Shale g as 0.00 0 3.588 0 73,300 20,400

Western Gulf Eagle Ford Shale g as 0.191 1.437 6,400 48,200 33,500

Shale o il 0.123 0.227 3,900 7,200 31,700

Pearsall Shale g as 0.000 0.676 0 4,900 7,200

Tuscaloosa Shale o il 0.112 0.021 3,200 600 28,600

Woodbine Shale o il 0.122 0.061 600 300 4,900

3

— Midcontinent Anadarko Cana Woodford Shale g as 0.028 1.590 200 11,500 7,200

Shale o il 0.036 0.961 100 2,700 2,800

Arkoma Caney Shale g as 0.000 0.973 0 3,100 3,200 Fayetteville Shale g as 0.000 0.899 0 20,400 22,700

Woodford Shale g as 0.000 1.342 0 6,300 4,700

Black Warrior Chattanooga Shale g as 0.000 0.968 0 1,600 1,700

4

— Southwest Fort Worth Barnett Shale g as 0.003 0.296 200 17,500 59,000

Permian Wolfcamp Shale o il 0.085 0.347 6,100 24,900 71,800

Barnett

- W oodford Shale g as 0.000 1.181 0 12,400 10,500 Avalon/BoneSpring Shale o il 0.118 0.367 2,900 9,000 24,500

5

— Rocky Mountain Denver Niobrara Shale o il 0.012 0.078 400 2,700 34,600

Greater Green River Hilliard

- Baxter

- Mancos Shale g as 0.000 0.293 0 10,500 35,800

5

— Rocky Mountain Montana Thrust Belt All t ight o il p lays Shale o il 0.102 0.068 600 400 5,900Chapter 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 ( MM b ls

per well) Gas EUR ( Bcf per

well) Oil TRR (MMbls) Gas TRR (Bcf) New Well Potential

Powder River All t ight o il p lays Shale o il 0.035 0.040 2,100 2,400 60,000

San Juan Lewis Shale g as 0.000 2.200 0 9,800 4,500

Uinta

- Piceance Mancos S hale g as 0.000 0.752 0 9,300 12,400

Williston Gammon Shale g as 0.000 0.433 0 3,300 7,600

Bakken Shale o il 0.147 0.078 22,700 12,100 154,800

6

— West Coast Columbia Basin Centered Shale g as 0.000 1.620 0 12,200 7,500 San Joaquin/Los Angeles Monterey/S antos Shale o il 0.030 0.151 600 3,000 19,900

Source s : 179 DCN SGE01179
Abbreviations : EUR

— estimated ultimate recovery (per well); MMbls

— million barrels; B cf

—

b illion cubic feet of gas; TRR

— t echnically recoverable r esources



### Table F

- 4

. UO G Resource Potential: Tight as of January 1, 2013

EIA Region EIA Basin UOG Formation Name Resource Type Oil EUR ( MM b ls

per well) Gas EUR ( Bcf per

well) Oil TRR (MMbls) Gas TRR (Bcf) N ew Well Potential

1

— East Appalachian Clinton

- Medina Tight g as 0.002 0.058 400 12,400 213,800

Tuscarora Tight g as 0.000 0.724 0 4,400 6,100 Michigan Berea Sand Tight g as 0.000 0.110 0 6,600 60,000

2

— Gulf Coast TX

- LA

- MS Salt Cotton Valley Tight g as 0. 008 1.323 800 139,300 105,300

Western Gulf Austin Chalk Tight o il 0.061 0.116 5,500 10,400 89,700

Buda Tight o il 0.057 0.109 2,000 3,800 34,900

Olmos Tight g as 0.009 1.162 200 25,400 21,900 Vicksburg Tight g as 0.038 0.980 100 2,600 2,700

Wilc ox Lobo Tight g as 0.000 1.403 0 12,800 9,100

3

— Midcontinent Anadarko Cleveland Tight g as 0.038 0.384 100 1,000 2,600

Granite Wash Tight g as 0.039 0.579 600 8,800 15,200

Red Fork Tight g as 0.000 0.459 0 900 2,000Chapter F

—

Appendices



### 181 Table F

- 4

. UO G Resource Potential: Tight as of January 1, 2013

EIA Region EIA Basin UOG Formation Name Resource Type Oil EUR ( MM b ls

per well) Gas EUR ( Bcf per

well) Oil TRR (MMbls) Gas TRR (Bcf) N ew Well Potential

4

— Southwest Permian Abo Tight g as 0. 695 0.149 7,000 1,500 10,100 Canyon Tight g as 0.017 0.209 900 10,900 52,200 Spraberry Tight o il 0.131 0.152 10,600 12,300 80,900

5

— Rocky Mountain Denver Muddy Tight g as 0.002 0.180 100 11,500 63,900

Greater Green River All t ight o il p lays Tight o i l 0.126 0.014 900 100 7,100

North Central
Montana Bowdoin

- G reenhorn Tight g as 0.000 0.078 0 100 1,300

Paradox Fractured Interbed Tight o il 0.534 0.427 1,000 800 1,900

San Juan Dakota Tight g as 0.000 0.258 0 3,800 14,700

Mesaverde Tight g as 0.000 0 .548 0 6,800 12,400

Pictured Cliffs Tight g as 0.000 0.262 0 100 400

SW Wyoming Fort Union

- Fox Hills Tight g as 0.007 0.792 100 12,000 15,200

Frontier Tight g as 0.018 0.312 400 7,100 22,800

Lance Tight g as 0.022 1.152 400 21,200 18,400

Lewis Ti ght g as 0.006 0.312 200 9,700 31,100

All t ight o il p lays Tight o il 0.154 0.014 1,100 100 7,100

Uinta

- Piceance Iles

- Mesaverde Tight g as 0.000 0.372 0 11,900 32,000

Wasatch

- Mesaverde Tight g as 0.029 0.568 500 9,800 17,300

Williams Fork Tight g as 0 .006 0.692 100 11,200 16,200

All t ight o il p lays Tight o il 0.053 0.105 100 200 1,900

Williston Judith River

- Eagle Tight g as 0.000 0.154 0 900 5,800

Wind River Mesaverde/Frontier Shallow Tight g as 0.018 1.131 100 6,400 5,700

Source s : 179 DCN SGE01179
Abbreviations : EUR

— estimated ultimate recovery (per well); MMbls

— million barrels; B cf

—

b illion cubic feet of gas; TRR

— t echnically recoverable resourcesChapter F

–

Appendices



### 182 Source: The EPA generated this figure using data from 44 DCN SGE00414.



### Figure F

- 1 . Constituent Concentrations o ver Time in UOG Produced Water from the Marcellus and Barnett Shale Formations Marcellus Shale

Barnett Shale