United States Office of Water EPA

- 821 -R- 15

- 003 Environmental Protection Washington, DC 20460 March 2015 Agency



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

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

EPA -821-R-15-003

March 2015

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

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

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

2 Existing Discharge Regulations for Oil and Gas Extraction Facility Wastewater ............. 3 2.1 Federal Regulations ................................................................................................ 3 2.2 State Pretreatment Requirements That Apply to UOG Extraction Wastewater .............................................................................................................. 9

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

C HAPTER 

### B. B ACKGROUND ON 

### U NCONVENTIONAL 

### O IL AND 

### G AS 

### E XTRACTION 

### ........................ 15

1 Overview of UOG Resources ........................................................................................... 15 1.1 How UOG Resources Were Formed

..................................................................... 18 1.2 Geological Characteristics of UOG Resources ..................................................... 19

2 UOG Well Development Process ..................................................................................... 20 2.1 UOG Well Drilling and Construction ................................................................... 21 2.2 UOG Well Completion ......................................................................................... 24 2.3 Production ............................................................................................................. 29

3 UOG Well Drilling and Completion Activity ................................................................... 30 3.1 Historical and Current UOG Drilling Activity ..................................................... 30 3.2 UOG Resource Potential ....................................................................................... 34 3.3 Current and Projections of Future UOG Well Completions ................................. 35

C HAPTER 

### C. U NCONVENTIONAL 

### O IL AND 

### G AS 

### E XTRACTION 

### W ASTEWATER 

### V OLUMES

AND 

### C HARACTERISTICS 

### ......................................................................................... 37

1 Fracturing Fluid Characteristics ........................................................................................ 39 1.1 Base Fluid Composition ........................................................................................ 39 1.2 Additives ............................................................................................................... 40 1.3 Fracturing Fluids ................................................................................................... 44

2 UOG Extraction Wastewater Volumes ............................................................................. 44 2.1 UOG Extraction Wastewater Volumes by Resource and Well Trajectory ........... 45 2.2 UOG Produced Water Volumes by Formation ..................................................... 50

3 UOG Extraction Wastewater Characterization ................................................................. 55 3.1 Availability of Data for UOG Extraction Wastewater Characterization .............. 55 3.2 UOG Extraction Wastewater Constituent Categories ........................................... 56 3.3 UOG Produced Water Characterization Changes over Time ............................... 75

C HAPTER 

### D. UOG E XTRACTION 

### W ASTEWATER 

### M ANAGEMENT AND 

### D ISPOSAL 

### P RACTICES 

### ............................................................................................................. 77Table of Contents



### CONTENTS (Continued)

Page

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

2 Injection into Disposal Wells ............................................................................................ 84 2.1 Regulatory Framework for Underground Injection .............................................. 84 2.2 Active Disposal Wells and Volumes .................................................................... 85 2.3 Underground Injection Considerations ................................................................. 86

3 Reuse/Recycl e in Fracturing ............................................................................................. 87 3.1 Reuse/Recycle Strategies ...................................................................................... 89 3.2 Reuse/Recycle Drivers .......................................................................................... 92 3.3 Other Considerations for Reuse/Recycle .............................................................. 96

4 Transfer to CWT Facilities ............................................................................................... 98 4.1 Types of CWT Facilities ....................................................................................... 98 4.2 Active CWT Facilities Accepting UOG Extraction Wastewater ........................ 100

5 Discharge to POTWs ...................................................................................................... 102 5.1 POTW Background and Treatment Levels ......................................................... 103 5.2 History of POTW Acceptance of UOG Extraction Wastewater ......................... 106 5.3 How UOG Extraction Wastewater Constituents Interact with POTWs ............. 111

C HAPTER 

### E. R EFERENCE 

### F LAGS AND 

### L IST 

### ............................................................................... 146

C HAPTER 

### F. A PPENDICES 

### ......................................................................................................... 161

Appendix F .1 Reference Files in FDMS

............................................................................... 161

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

Appendix F.3 Constituent Concentrations over Time in UOG Produced Water from Marcellus and Barnett Shale Formations .................................................................. 175List of Tables



### vi LIST OF TABLES Page

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

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

Table B

- 2. Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product Type (as of November 8, 2013) ...................................................................................33

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

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

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

Table C -3. Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in Gas and Oil Wells from Frac Focus (2011-2013) .........................................................43

Table C

- 4. Median Drilling Wastewater Volumes for UOG Horizontal and Vertical Wells in Pennsylvania ............................................................................................................47

Table C

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

Table C

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

Table C

- 7. Long

- Term Produced Water Generation Rates by Resource Type and Well Trajectory .....................................................................................................................50

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

Table C

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

Table C -10. Concentrations of Select Classical and Conventional Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells .....................................57

Table C -11. Concentrations of Select Classical and Conventional Constituents in UOG Produced Water ............................................................................................................58

Table C -12. Concentrations of Select Anions and Cations Contributing to TDS in UOG Drilling Wastewater from Marcellus Shale Formation Wells .....................................63

Table C -13. Concentrations of Select Anions and Cations Contributing to TDS in UOG Produced Water ............................................................................................................64

Table C -14. Concentrations of Select Organic Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells .......................................................................65

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

Table C

- 16. Concentrations of Select Metal Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells .......................................................................68List of Tables



### LIST OF TABLES (Continued)

Page

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

Table C -18. Concentrations of Select Radioactive Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells ...................................................72

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

Table C -20. Concentrations of Radioactive Constituents in Rivers, Lakes, Groundwater, and Drinking Water Sources Throughout the United States (pCi/L) ...........................73

Table D

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

Table D

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

Table D

- 3. Reuse/Recycle Practices in 2012 as a Percentage of Total Produced Water Generated as Reported by Respondents to 2012 Survey .............................................88

Table D

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

Table D

- 5. Reported Reuse/Recycle Practices as a Percentage of Total Fracturing Volume .........................................................................................................................95

Table D

- 6. Number, by State, of CWT Facilities That Have Accepted or Plan to Accept UOG Extraction Wastewater .....................................................................................101

Table D

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

Table D -8. Typical Percent Removal Capabilities from POTWs with Secondary Treatment ...................................................................................................................105

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

Table D -10. POTW s That Accepted UOG Extraction Wastewater from Onshore UOG Operators ....................................................................................................................108

Table D

- 11. Percentage of Total POTW Influent Wastewater Composed of UOG Extraction Wastewater at POTWs Accepting Wastewater from UOG Operators ....................................................................................................................110

Table D -12. Summary of Studies About POT Ws Receiving Oil and Gas Extraction Wastewater Pollutants ................................................................................................112

Table D

- 13. Clairton Influent Oil and Gas Extraction Wastewater Charac teristics ....................116

Table D

- 14. Trucked COG Extraction Wastewater Treated at McKeesport POTW from November 1 Through 7, 2008 ....................................................................................117

Table D

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



### LIST OF TABLES (Continued)

Page

viii Table D -16. Constituent Concentrations in UOG Extraction Wastewater Treated at the McKeesport POTW Before Mixing with Other Influent Wastewater .......................119

Table D -17. McKeesport POTW Effluent Concentrations With and Without UOG Extraction Wastewater ...............................................................................................120

Table D -18. Charleroi POTW Paired Influent/Effluent Data and Calculated Removal Rates ...........................................................................................................................122

Table D -19. Franklin Township POTW Effluent Concentrations With and Without Industrial Discharges from the Tri-County CWT Facility .........................................125

Table D -20. TDS Concentrations in Baseline and Pilot Study Wastewater Samples at Warren POTW ...........................................................................................................128

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

Table D -22. Inhibition Threshold Levels for Various Treatment Processes a 

### ..............................130

Table D -23. Industrial Wastewater Volumes Received by New Castle POTW (2007– 2009) ..........................................................................................................................135

Table D

- 24. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW (NPDES Permit Number PA0027511) ......................................................................136

Table D -25. Concentrations of DBPs in Effluent Discharges at One POTW Not Accepting Oil and Gas Wastewater and at Two POTWs Accepting Oil and Gas Wastewater (μg/L) ..............................................................................................142

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

Table F -1. TDD Supporting Memoranda and Other Relevant Documents Available in FDMS .........................................................................................................................161

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

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

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



### ix LIST OF FIGURES Page

Figure A

- 1. UOG Extraction Wastewater ........................................................................................2

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

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

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

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

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

Figure B

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

Figure B -7. Length of Time to Drill a Well in Various UOG Formations as Reported for the First Quarter of 2012 through the Third Quarter of 2013 ......................................24

Figure B

- 8. Hydraulic Fracturing Schematic .................................................................................26

Figure B

- 9. Freshwater Impoundment ...........................................................................................27

Figure B

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

Figure B

- 11. Fracturing Tanks .......................................................................................................29

Fi gure B -12. Produced Water Storage Tanks ................................................................................30

Figure B -13. Number of Active U.S. Onshore Rigs by Trajectory and Product Type over Time .............................................................................................................................31

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

Figure C

- 1. UOG Extraction Wastewater Volumes for Marcellus Shale Wells in Pennsylvania (2004 –2013) ...........................................................................................46

Figure C

- 2. Ranges of Typical Produced Water Generation Rates over Time After Fracturing .....................................................................................................................47

Figure C -3. Anions and Cations Contributing to TDS Concentrations in Shale and Tight Oil and Gas Formations ...............................................................................................61

Figure C -4. Chloride, Sodium, and Calcium Concentrations in Flowback and Long- Term Produced Water (LTPW) from Shale and Tight Oil and Gas Formations ...................62

Figure C -5. Barium Concentrations in UOG Produced Water from Shale and Tight Oil and Gas Formations .....................................................................................................71

Figure C -6. Constituent Concentrations over Time in UOG Produced Water from the Marcellus and Barnett Shale Formations .....................................................................76

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



### LIST OF FIGURES (Continued)

Page

x Figure D

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

Figure D

- 3. Management of UOG Drilling Wastewater Generated by UOG Wells in Pennsylvania (2008 –2013) ...........................................................................................82

Figure D

- 4. Active Disposal Wells and CWT Facilities Identified in the Appalachian Basin ............................................................................................................................83

Figure D -5. Flow Diagram of On-the- Fly UOG Produced Water Treatment for Reuse/Recycle ..............................................................................................................91

Figure D -6. Hypothetical UOG Produced Water Generation and Base Fracturing Fluid Demand over Time ......................................................................................................96

Figure D

- 7. UOG Extraction Wastewater Management Practices Used in the Marcellus Shale (Top: Southwestern Region; Bottom: Northeastern Region) .............................97

Figure D -8. Number of Known Active CWT Facilities over Time in the Marcellus and Utica Shale Formations ..............................................................................................102

Figure D

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

Figure D -10. Clairton POTW: Technical Evaluation of Treatment Processes’ Ability to Remove Chlorides and TDS ......................................................................................115

Figure D -11. McKeesport POTW: Te chnical Evaluation of Treatment Processes’ Ability to Remove Chlorides and TDS ..................................................................................117

Figure D -12. Ridgway POTW: Annual Average Daily Effluent Concentrations and POTW Flows .............................................................................................................121

Figure D -13. Johnstown POTW: Annual Average Daily Effluent Concentrations and POTW Flows .............................................................................................................132

Figure D -14. California POTW: Annual Average Daily Effluent Concentrations and POTW Flows .............................................................................................................133

Figure D -15. Charleroi POTW: Annual Average Daily Effluent Concentrations and POTW Flows .............................................................................................................134

Figure D

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

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

Figure F -1. Constituent Concentrations over Time in UOG Produced Wat er from the Marcellus and Barnett Shale Formations ...................................................................175Abbreviations



### 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 BPD 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 waste treatment DBP disinfection byproduct DMR d ischarge monitoring 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 recovery gpd gallons per day IU industrial user LTPW long-term produced water MG million gallons MGD million gallons per day mg/L milligrams per liter MI DEQ Michigan Department of Environmental Quality NORM naturally occurring radioactive material OH DNR Ohio Department of Natural Resources ORD Office of Research and Development PA DEP Pennsylvania Department of Environmental Protection pCi picocurie PESA Petroleum Equipment Suppliers Association POTW publicly owned treatment works SIU significant industrial user SRB sulfate

- reducing bacteria TDD techn ical development document TDS total dissolved solids TENORM technologically

- enhanced naturally occurring radioactive material THM trihalomethane TOC total organic 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



### Base fluid The primary component of fracturing fluid to which proppant (sand) and chemicals are added. Base fluids are typically water

based; however there are cases of non

- aqueous fracturing fluids (e.g., compressed nitrogen, propane, carbon dioxide). Water- based fluid can consist of only fresh water or a mixture of fresh water, brackish water and/or reused/recycled wastewater. Biochemical oxygen demand (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 disp osal, recycling or recovery of material) any hazardous or nonhazardous industrial wastes, hazardous or non-hazardous industrial wastewater, and/or used material received from offsite. Chemical oxygen demand (COD) The amount of oxygen needed to oxidize rea ctive 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 associated with oil and gas production.
Class II UIC enhanced recovery well A well that inject s brine, water, steam, polymers, or carbon dioxide into oil-bearing formations to recover residual oil and—in some limited applications —natural gas. This is also known as secondary or tertiary recovery. Conventional oil and gas (COG) resou rces Crude oil and natural gas that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the oil and natural gas to readily flow to the wellbore Drill cuttings The particles generated by drilling into subsurface geologic formations and carried out from the wellbore with the drilling fluid. Drilling fluid The circulating fluid (e.g., mud) used in the rotary drilling of wells to clean and condition the hole and to counterbalance formation pressure. Drilling wastewater The liquid waste stream separated from recovered drilling fluid (e.g., mud) and drill cuttings.

1 The definitions of terms in the Glossary are only meant to apply to the terms as used throughout the Technical Development Document for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction (TDD) and the TDD supporting documentation

.G lossary



### GLOSSARY (Continued)

xiv Flowback The produced water generated in the initial period after hydraulic fracturing prior to production (i.e., fracturing fluid, injection water, any chemicals added downhole, varying amounts of formation water). See long -term produced water.
Formation water W ater that occurs naturally within the pores of rock. Hydraulic fracturing Fracturing of rock at depth with fluid pressure. Hydraulic fracturing at depth may be accomplished by pumping water or other liquid or gaseous fluid into a well at high pressures. Hydraulic fracturing fluid The fluid , consisting of a base fluid and chemical additives, used to fracture rock in the hydraulic fracturing process. Hydraulic fracturing fluids are used to initiate and/or expand fractures, as well as to transport proppant into fractures. See base fluid. Long

- term produced water (LTPW) The produced water generated during the production phase of the well after the initial flowback process (includes increasing amounts of formation water). Naturally occurring radioactive mate rial (NORM) M aterial that contains radionuclides at concentrations found in
nature. See also technologically

- enhanced radioactive material (TENORM)
Non

- TDS removal technologies Technologies that remove non

- dissolved constituents from
wastewater.
Produced sand The slurried particles used in hydraulic fracturing, the accumulated formation sands, and scales particles generated during production. Produced sand also includes desander discharge from the produced water waste stream, and blowdown of the water pha se from the produced water treating system. Produced water (brine) The water (brine) brought up from the hydrocarbon

- bearing strata during the extraction of oil and gas, and can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process. Proppant A granular substance (e.g., sand grains, aluminum pellets) that is carried in suspension by the fracturing fluid and that serves to keep the cracks open when fracturing fluid is withdrawn after a fractur e treatment. Publicly owned treatment works (POTW) Any device and system used in the storage, treatment, recycling and reclamation of municipal sewage or industrial wastes of a liquid nature that is owned by a state or municipality. This definition includ es 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.G lossary



### GLOSSARY (Continued)

xv TDS removal technologies Technologies capable of removing dissolved constituents (e.g., sodium, chloride, calcium) in addition to the constituents removed by non-TDS removal technologies. Technologically

- enhanced naturally occurring radioactive material (TENORM) Naturally occurring radionuclides that human activity has concentrated or exposed to the environment.

Total dissolved solids (TDS) A measure of the matter, including salts (e.g., sodium, chloride, nitrate), organic matter, and minerals dissolved in water.Standard Method 2540C-1997, ASTM D5907-03, and USGS I1750-85. Total organic carbon (TOC) The concentration of organic material in a sample as represented by the weight percent of organic carbon. Standard Method 5310 (B- D) -2000, ASTM D7573-09 and D4839

- 03, an AOAC method, and a USGS method. Total suspended solids (TSS) The matter that remains as residue upon evaporation. Suspended solids include the settable solids that will settle to the bottom of a cone-shaped container in a 60 minute period.Standard Method 2540 D-1997, ASTM D5907-03, and USGS I3765

- 85. Unconventional oil and gas (UOG) Crude oil and natural gas produced by a well drilled into a low porosity, low permeability formation (including, but not limited to, shale gas, shale oil, tight gas, tight oil). For the purpose of the proposed rule, the definition of UOG does not include C BM.
UOG extraction
wastewater Wastewater sources associated with production, field exploration, drilling, well completion, or well treatment for unconventional oil and gas extraction (e.g., drilling muds, drill cuttings, produced sand, produced water).Chapter A

— Introduction



### 1 

## Chapter A. I NTRODUCTION



### 1 B ACKGROUND ON 

### O IL AND 

### G AS 

### E XTRACTION



### Recent advances in well development that combine hydraulic fracturing and horizontal drilling have dramatically improved the technical and economic feasibility of oil and gas extraction from unconventional resources. As a result, in 2012, United States ( U. S. ) crude oil and natural gas production reached their highest level s in more than 15 and 30 years , respectively

. The U.S. Department of Energy ( DOE ) reports these increases to be a direct result of advances in hydraulic fracturing and horizontal drilling. Further, the DOE projects that natural gas production in the U.S. will increase by 56 percent by 2040, compared to 201 2 production levels . Similarly

, the DOE projects that by 2019, crude oil production in the U.S. will increase by 48 percent compared to 2012 production levels (31 DCN SGE 00989).

This t echnical development document (TDD) provides background information and data considered in the development of revised effluent limitations guidelines and standards (ELGs) proposed for the Oil and Gas Extraction point source category to address discharges from unconventional oil and gas (UOG) extraction facilities to municipal wastewater treatment plants. UOG consists of crude oil and natural gas 2 

### produced by wells drilled into a low porosity, low permeability formation . UOG resources include shale oil and gas, resources that were formed, and remain, in low

- permeability shale. UOG resources also include tight oil and gas, resources that were formed in a source rock and migrated into a reservoir rock such as sandstone, siltstones, or carbonates. As explained in the preamble to the proposed rule, although coalbed methane (CBM) would fit the definition of UOG in the proposed rule, the proposed rule would not apply to pollutant discharges to POTWs associated with CBM extraction. 3 

### The remainder of the information presented in this document is specific to the UOG resources subject to the proposed rule and therefore excludes CBM unless explicitly indicated otherwise.

Development of UOG resources typically requires hydraulic fracturing of the reservoir rock by injecting fracturing fluid at high pressures to create a network of fissures in the rock formations, giv ing the oil and/or natural gas a pathway to travel to the well for extraction. P ressure within the low- permeability formations forces a portion of these fracturing fluids back to the surface. The fluid that returns is typically referred to as “flowback.” Produced water consists of flowback that flows from the well initially and the long

- term produced water that flows from the well during oil and gas production. Produced water also includes any chem icals that are added downhole or added to fracturing or drilling fluids that are then injected downhole, as well as chemicals that are added during the process of separating the oil and/or gas from the
wastewater.

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

3 EPA notes that the requirements in the existing effluent guideli nes for direct dischargers also do not apply to coalbed methane extraction, as this industry did not exist at the time that the effluent guidelines were developed and was not considered by the Agency in establishing the effluent guidelines ( 160 DCN SGE00761). To reflect the fact that neither the proposed pretreatment standards nor the existing effluent guideline requirements apply to coalbed methane ext raction, EPA is expressly reserving a separate unregulated subcategory for coalbed methane in the proposed rule. For information on coalbed methane, see http://water.epa.gov/scitech/wastetech/guide/oilandgas/cbm.cfm.Chapter A

— Introduction



### 2 As depicted in Figur e A-1 , produced water, drilling wastewater

, and produced sand are collectively referred to as UOG extraction wastewater.



## UOG Extraction Wastewater Wastewater sources associated with production, field exploration, drilling, well completion, or well treatment for unconventional oil and gas extraction (e.g.

, drilling muds , drill cuttings, produced sand, produced water)

Drilling Wastewater: the liquid waste stream separated from recovered drilling fluid (e.g., mud ) and drill cuttings during the drilling process a Produced Sand: the slurried particles used in hydraulic fracturing, the accumulated formation sands and scales particles generated during production (40 CFR 435.11( aa )) Produced Water: the water (brine) brought up from the hydrocarbon

bearing strata during the extraction of oil and gas and can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process (40 CFR 435.11(bb))

Flowback : produced water generated in the initial period after hydraulic fracturing prior to production (i.e., fracturing fluid, injection water, any chemicals added downhole , and varying amounts of formation water) Long

- term Produced Water: produced water generated during the production

phase of the well after the initial flowback process (includes increasing amounts of formation water) Chemicals added during the oil/water separation process (40 CFR 435.11(bb))

a

– Drilling fluid (mud) is the circulating fluid used in the rotary drilling of wells to clean and condition the hole and to counterbalance formation pressure. Drill cuttings means the particles generated by drilling into subsurface geologic formations and carried out from t he wellbore with the drilling fluid.



### Fig ure A-1. UOG Extraction Wastewater

This document supports the EPA’s development of pretreatment standards for UOG extraction wastewater. The remainder of this chapter describes existing discharge regulations for UOG extraction wastewater. S ubsequent chapters provide additional detail on UOG resources, extraction processes

, and wastewater generation. They describe the quantity and quality of wastewater generated and the practices industry uses to manage and/or dispose of UOG extraction wastewater.

The pretreatment standards for UOG extraction wastewater are based on data generated or obtained in accordance with EPA’s Quality Policy and Information Quality Guidelines. EPA’s quality assurance (QA) and quality control (QC) activities for this rulemaking include the development, approval, and implementation of Quality Assurance Project Plans for the use ofChapter A

— Introduction



### 3 environmental data generated or collected from sampling and analyses, existing databases, and literature searches.

References cited in this document are listed in Chapter E and ar e identified in the body of the document by reference ID number s ( e.g., 149 ) and DCN (e.g., DCN SGE00586). Information presented in this document was taken from existing data sources, including state and federal agency databases, journal articles and technical papers, technical references, vendor websites, and industry/vendor telephone calls, meetings, and site visits. The EPA classified the quality of the data sources with a “data source quality flag”

, assigning ratings from “A” for peer

- reviewed journal articles and documents prepared by or for a government agency to “D” for documents prepared by a source that could not be verified and that do not include citation information, such as some newspaper articles and conference presentations. For each source cited in this document, the reference list in Chapter E includes the reference ID number, document control number (DCN), source citation, and data source quality flag.

Appendix F.1 includes two tables with more information about where to find more data about certain topics, tables, and/or figures contained in the TDD. Table F-1 lists supporting memoranda along with their associated DCNs and a brief description of the type of information covered in the memoranda

. Each supporting memorand um includes a section about QC activities related to the data and/or analyses discussed in the given memoranda. Table F-1 also lists the relevant TDD sections associated with each memorandum. Table F-2 contains additional information about each table and figure in the TDD, including the original source (s) of information for the data presented in the table or fi gure and the relevant memorandum and attachments, where relevant

.

2 E XISTING 

### D ISCHARGE 

### R EGULATIONS FOR 

### O IL AND 

### G AS 

### E XTRACTION 

### F ACILITY 

### W ASTEWATER



### Wastewater discharges from oil and gas extraction facilities are subject to federal, state, and local regulatio ns. Section A. 2.1 describes federal regulations affecting the discharge of oil and gas extraction wastewater directly into waters of the United States and indirectly to municipal wastewater treatment plants (known as publicly owned treatment works, or POTWs), including ELGs for the Oil and G as E xtraction point s ource c ategory (40 C.F.R. part 435) as well as the national pretreatment program (40 C.F.R. part 403). In addition to applicable federal requirements, some states specifically regulate the management, storage, and disposal of UOG extraction wastewater. Section A. 2.2 discusses state

- specific requirements that the EPA has identified that relate to UOG extraction wastewater pollutant discharges to POTWs.

2.1 Federal Regulations

The national clean water indust rial regulatory program is authorized under S ections 30 1, 304, 306, and 307 of the Clean Water Act ( CWA ). The se sections direct the EPA to promulgate categorical regulations through six levels of control:

• Best p racticable control technology currently a vailable (BPT)

• Best available technology economically achievable (BAT)

• Best conventional pollutant control technology (BCT)Chapter A

— Introduction



### 4 • New source performance standards (NSPS)

• Pretreatment standards for existing sources (PSES)

• Pretreatment standards for new sources (PSNS)

For point sources that discharge pollutants directly into th e waters of the United States (direct dischargers), the national

- level ELGs promulgated by the EPA (i.e., BPT, BAT, BCT, and NSPS) are implemented through National Pollutant Discharge Elimination System (NPDES) permits 4 

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

, the EPA promulgates national categorical pretreatment s tandards (i.e., PSES and PSNS) that apply to discharges to POTWs and are enforced by local, state
, and federal authorities. See CWA Sections 307(b) and (c) for the EPA’s authority to develop pretreatment standards.

The EPA issues ELGs for categories of dischargers

— groups with common characteristics, such as a manufacturing process or commercial activity (e.g., battery manufacturing, airport deicing)

. The EPA may divide a point source categ ory into groupings called “ subcategories ” to provide a method for addressing variations among products, processes, and other factors, which result in distinctly different effluent characteristics that affect the determination of the technology basis for categorical regulations

. ELGs are national in scope and apply to all facilities within a category or subcategory 5 

### that discharge wastewater. In establishing these controls, the EPA assesses , among other things:

• T he performance and availability of the best pollution control technologies or pollution prevention practices for the category or subcategory as a whole.

• T he economic achievability of those technologies, which can include consideration of the affordability of achieving reductions in pollutant discharge s. 40 C.F.R. part 403.5(b) notes eight categories of pollutant discharge prohibitions :

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 flo w rate and/or pollutant concentration that will interfere with the POTW
5. Heat in amounts that will inhibit biological activity in the POTW resulting in interference
6. Petroleum oil, nonbiodegradable cutting oil, or products of mineral oil origin in amounts th at will cause interference or pass through
7. Pollutants that result in the presence of toxic gases, vapors, or fumes within the POTW in a quantity that may cause acute worker health and safety problems
8. Any trucked or hauled pollutants, except at discharge
po ints designated by the POTW 

### 2.1.1 Th e National Pretreatment Program (40 C.F.R. Part 403)

The 1972 CWA established the National Pretreatment Program to address wastewater discharged from industries to POTWs . POTWs collect wastewater from

4 Facilities that do not discharge or p ropose not to discharge (zero dischargers) may apply for permit coverage for upset or bypass defense to cover discharges resulting from unforeseen incidents that otherwise would cause a violation of CWA Section 301 (i.e., discharge without a permit) ( 82 DCN SGE 00531 ).

5 The EPA may subcategorize a category based on appropriate factors, including facility size. See CWA Section 304(b)(2)(b)a. These factors may affect the availability and affordability of pollution control technologies.Chapter A

— Introduction



### 5 hom es, commercial buildings, and industrial facilities via a series of pipes, known as a collection system, to a treatment plant. In some cases, dischargers may haul wastewater to the treatment plant by tanker truck. Industrial wastewater, commingled with dom estic wastewater, is treated by the POTW and discharged to a receiving water body. Under the CWA, in order to discharge

w astewater, the POTW must have a NPDES permit that may limit the type and quantity of pollutants that it may discharge.

T o implement th e National Pretreatment Program

, the EPA developed t he General Pretreatment Regulations to protect POTW operations. As described in Chapter 2 of the EPA’s introduction to the program ( 171 DCN SGE 00249), these regulations apply to all non- domestic

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

u sers (IUs). To distinguish small, simple IUs (e.g., coin -operated laundries

, commercial car washes) from larger, more complex IUs (e.g., oil refineries

, steel mills), the EPA has established a category called s ignificant IU s (SIU s ). The General Pretreatment Regulations apply to all nondom estic sources that introduce pollutants into a POTW and are intended to protect POTW operations from “pass through” and “interference

. ” See the textbox for a list of prohibited pollutant discharges, as defined by 40 C.F.R. part 403.

Pretreatment Program Implementation

Most of the responsibility for implementing the National Pretreatment Program rests on local municipalities. For example, 40 C.F.R. part 403.8(a) requires that POTWs designed to treat more than 5 million gallons per day ( MGD ) of wastewater and receiving pollutants from IUs that pass through or interfere with the POTW’s operation must establish a local pretreatment
program. 6 

### The POTW’s NPDES permit will include requirements for developing a local pretreatment program that will control the wastewater discharged to the POTW by IUs.

The National Pretreatment Program regulations identify specific requirements that apply
to IUs, additional requirements that apply to all SIUs, and certain requirements that apply only to categor ical industrial users (CIUs) . There are three types of national pretreatment requirements:

• Prohibited discharge standards that include general and specific prohibition on discharges

• Categorical pretreatment standards

• Local limits

Prohibited discharge standards. The prohibited discharge standards are not technology

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

. All IUs

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

— are subject to the general and specific prohibitions identified in 40 C.F.R. parts 403.5(a) and (b), respectively.

6 POTWs designed to treat less than 5 MGD may be required by their A pproval A uthority to develop a local pretreatment program if the nature or volume of the industrial influent, treatment pr ocess upsets, violations of POTW effluent limitations, contamination of municipal sludge, or other circumstances warrant in order to prevent interference with the POTW or pass through.Chapter A

— Introduction



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

or interfere with it s 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 through by the general prohibitions.

• Specific prohibitions in 40 C.F.R. part 403.5(b) prohibit eight categories of pollutant discharges that will harm POTW workers or the POTW, including the collection system. Pollutant discharges outside these defined categories are not specifically prohibited.

Categorical pretreatment standards.

As discussed in Section A. 2.1 , the CWA authorizes the EPA to promulgate national categorical pretreatment standards for industrial sources that discharge to POTWs. Developed by the EPA on an industry

- specific basis, categorical pretreatment standards are based on the best available technology that is economically achievable for that industry on a national level, and set regulatory requirements based on the perform ance of that technology. These requirements limit discharges of toxic and nonconventional pollutants that could cause pass through or cause interference

. 7 

### Categorical pretreatment standards represent a baseline level of control that all IUs in the category must meet, without regard to the POTW they discharge to. IUs subject to categorical pretreatment standards are known as CIUs. The EPA establishes two types of categorical pretreatment standards for CIUs: PSES and PSNS.

Local limits. Developed by individu al POTWs, local limits address the specific needs and concerns of the POTW, its sludge, and its receiving waters. Typically, POTWs develop local limits 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 residential sources), and implement a system to control industrial discharges. Additional information can be found in the EPA ’s 2004 Local Limits Development Guidance ( 165 DCN SGE 00602 )

. Responsibilities of POTWs and IUs

The POTW controls the discharges from the IU through an individual control mechanism , often called an IU permit. The POTW may also issue gene ral permits under certain conditions if it has adequate legal authority and approval. POTWs with approved local pretreatment programs must have procedures for:

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

7 In determining whether a pollutant would pass through POTWs for categ orical pretreatment standards, EPA generally compares the percentage of a pollutant removed by well

- operated POTWs performing secondary treatment to the percentage removed by a candidate technology basis. A pollutant is determined to pass through POTWs whe n the median percentage removed nationwide by well

- operated POTWs is less than the median percentage removed by the candidate technology basis.Chapter A

— Introduction



### 7 • Communicating applicable standards and requirements to IUs

• Receiving and analyzing reports

• Inspecting IUs, including annual inspections of SIUs

• S ampling in certain cases

• Investigating noncompliance with pretreatment standards and requirements

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

Each IU of a POTW is responsible for compliance with applicable federal, state, and local pretreatment standards and requirements.

Approval Authority

POTWs establish local pretreatment programs to control discharges from non

- domestic sources. These programs must be approved by the Approval Authority

, w hich is also responsible for overseeing implementation and enforcement of the programs ( 171 DCN SGE00249 ). The Approval Authority is t he director in a NPDES authorized s tate with an approved state pretreatment program, or the appropriate EPA regional administrator in a non

- NPDES authorized

s tate or NPDES state without an approved state pretreatment program. A s tate may have an NPDES permit program but lack a state pretreatment program. One example is Pennsylvania, which the EPA has authorized for the NPDES program but not for the pretreatment program. EPA Region 3 is the Approval Authority for POTW pretreatment programs in Pennsylvania.

Hauled Wastewater

As discussed in the EPA’s Introduction to the National Pretreatment Program ( 171 DCN SGE00249) , in addition to receiving wastewater through the collection system, many POTWs accept trucked wastewater. IUs may truck their wastewate r to the POTW when the facility is outside the POTW’s service area (e.g., located in a rural area) and is not connected to the collection system. Just like wastewater received through the collection system, trucked wastewater is subject to the General Pret reatment Regulations and may also be subject to categorical pretreatment standards. Therefore, the POTW must regulate hauled wastewater from CIUs or hauled wastewater that otherwise qualifies the discharger as an IU in accordance with the requirements of t he General Pretreatment Regulations and any applicable categorical pretreatment standards, including any applicable requirements for permitting and inspecting the facility that generates the wastewater.

Section 403.5(b)(8) of the General Pretreatment Regu lations specifically prohibits the introduction of any trucked or hauled pollutants to the POTW, except at discharge points designated by the POTW. As explained in Introduction to the National Pretreatment Program ( 171 DCN 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 w aste 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 hauled waste without consideration of the implications of its acceptance (s ee 40 C.F.R. part 260).Chapter A

— Introduction



### 8 2.1.2 ELGs for the Oil and Gas Extraction Point Source Category (40 C.F.R. Part 435)

The EPA promulgated the Oil and Gas Extraction ELGs ( 40 C.F.R. p art 435 ) in 1979, and amended the regulation in 1993, 1996, and 2001. The Oil and Gas Extraction industrial category is subcategorized 8 

### as follows:

• Subpart A: Offshore

• Subpart C: Onshore

• Subpart D: Coastal

• Subpart E: Agricultural and Wildlif e Water Use

• Subpart F: Stripper Wells

The existing s ubpart C and s ubpart E regulation s cover wastewater discharges from field exploration, drilling, production, well treatment, and well completion activities in the onsh ore oil and gas industry. Although oil and gas resources occur in unconventional formations in offshore and coastal regions, recent development of UOG resources in the U nited S tates has occurred primarily onshore in regions to which the regulations in s ubpart C ( onshore ) and s ubpart E (a gricultural and w ildlife w ater u se) apply and thus, only the regulations that apply to onshore oil and gas extraction are described in more detail here

. Note that the scope of the existing O il and G as E xtraction ELG does not similarly apply to privately o wned wastewater treatment facilities that accept oil and gas extraction wastewater from offsite that are also not engaged in production, field exploration, drilling, well completion, or well treatment. Discharges from such facilities are not subject to 40 C.F.R. p art 435, but rather are subject to requirements in 40 C.F.R. p art 437, the Centralized Waste Treatment c ategory (see Section D. 4 for more information).

Direct Discharge Requirements for Onshore Oil and Gas Extraction Facilities

Subpart C: Onshore Subcategory Applicability. As set forth in 40 C.F.R. part 435.30, subpart C applies to facilities engaged in production, field exploration, drilling, well compl etion

, and well treatment in the oil and gas extraction industry

, located landward of the inner boundary of the territorial seas

— and not included in the definition of other subparts, including s ubpart D (Coastal ) at 40 C.F.R. part 435.40.

Direct discharge requirements. The regulations at 40 C.F.R. part 435.32 specify the following for BPT :

...there shall be no discharge of waste water pollutants into navigable waters from any source associated with production, field exploration, drilling, well completion, o r well treatment ( i.e. , produced water, drilling muds, drill cuttings, and produced sand).

The existing regulations do not include national categorical pretreatment standards for discharges to POTWs.

8 Subpart B is reserved.Chapter A

— Introduction



### 9 Subpart E: Agricultural and Wildlife Use Subcategory 9


### Subpart E applies to onshore facilities located in the continental United States and west of the 98th meridian for which the produced water has a use in agriculture or wildlife propagation when discharged into waters of the United S tates

. Applicability. As set forth in 40 C.F.R. part 435.50, subpart E applies to onshore facilities located in the continental United States and west of the 98th meridian for which the produced water has a use in agriculture or wildlife propagation when discharged into navigable waters. Definitions in 40 C.F.R. part 435.51 (c) explain that t he term “use in agricultural or wildlife propagation” means:

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

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

Direct discharge requirements. Subpart E prohibits the discharge of waste pollutants into navigable waters from any source (other than produced water) associated with production, fiel d exploration, drilling, well completion, or well treatment (i.e., drilling muds, drill cuttings, produced sands). Therefore, the only allowable discharge under this subpart is produced water 10 

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

2.2 State Pretreatment Requirements T hat Apply to UOG Extraction Wastewater

In addition to applicable federal requir ements, some states regulate the management, storage, and disposal of UOG extraction wastewater, including regulations concerning pollutant discharges to POTWs from oil and gas extraction facilities. In addition to pretreatment requirements, some states have indirectly addressed the issue of pollutant discharges to POTWs by limiting the management and disposal options available to operators. Table A-1 , beginning on the next page, summarizes how Pennsylvania, Ohio, West Virginia, and Michigan responded to UOG extraction wastewater discharges into their POTWs.

The Groundwater Protection Council’s (GWPC) 2014 report Regulations Designed to Protect State Oil and Gas Water R esources describes that, as part of their study, GWPC “surveyed the study states 11 

### regarding the use of POTWs for discharging production fluids including flowback water. Of the states responding, three indicated this practice was banned by

9 While pollutant discharges from onshore oil and gas extraction produced water are allowed under subpart E in certain geographic locations for use in agriculture or wildlife propagation, EPA has not found that these types of permits are typically written f or unconventional oil and gas extraction wastewater (as defined for the proposed rule).

10 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 define d as “the water (brine) brought up from the hydrocarbon

- bearing strata during the extraction of oil and gas, and can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process.”

11 GWPC reviewed dat a for the following 27 oil and gas producing states : Alabama, Alaska, Arkansas, California, Colorado, Florida, Illinois, Indiana, Kansas, Kentucky, Louisiana, Michigan, Mississippi, Montana, Nebraska, New Mexico, New York, North Dakota, Ohio, Oklahoma, Pennsylvania, South Dakota, Texas, Utah, Virginia, West Virginia, and Wyoming

.Chapter A

— Introduction



### 10 regulation, five states did not have a regulation covering this disposal method but would not allow it as a matter of policy, and nine indicated it was either regulated by another state agency or would otherwise be allowed under certain circumstances

.... [A] s of 2013, six st ate oil and gas agencies had permitting requirements for POTWs accepting this waste” ( 77 DCN SGE01077).Chapter A

— Introduction



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

State Relevant State Authority (s) State Authority Website(s) Description of State’s Relevant Requirements

Pennsylvania EPA Region 3, PA DEP PA DEP: http://www.depwe b.state.pa.us/ PA Code, Chapter 95 : http://www.pacode .com/secure/data/0 25/chapter95/chap 95toc.html Pennsylvania amende d 25 Pennsylvania Code Ch. 95.10 on August 21, 2010. According to PA Bulletin, Doc

. No. 10

- 1572 ( 130 DCN SGE 00187) (available at http://www.pabulletin.com/secure/data/vol40/40

- 34/1572.html ) This final form rulemaking ensures the continued protection of this Commonwealth's water resources from new and expanded sources of TDS. Most importantly, the final

- form rulemaking guarantees that waters of this Commonwealth will not exceed a threshold of 500 mg/L

. In addition, the bulletin specifies A higher standard of 500 mg/L is being applied specifically to the natural gas sector, based on several factors

. The bulletin also explains the following, regarding existing authorized discharges, addressed in Section 95.10(a)(1) This section makes it clear that discharge loads of TDS authorized by the Department, under NPDES permits or other authority that were iss ued or reissued prior to the effective date of this final

- form rulemaking, are exempt from the regulation until the net load is to be increased. It is important to note that only an increase in net TDS load is considered to be a new or expanding discharge loading

. The bulletin also explains the pretreatment requirements described in Section 95.10(b)(3)(ii), including the final rule establishes that POTWs may accept these wastewaters only if the wastes are first treated at a CWT facility and meet the end

- of

- pipe effluent standards imposed by the rule. In effect, the final rule regulates these indirect discharges in a manner consistent with direct discharges of these wastes. On April 19, 2011, PA DEP requested that Marcellus Shale natural gas drillers volunta rily cease delivering their wastewater to 15 wastewater treatment plants which currently accept it and have “grandfathered” status with respect to PA DEP’s Total Dissolved Solids regulations ( 170 DCN SGE 00982). On April 20, 2011, the Marcellus Shale Coalition wrote a response to PA DEP that stated I write to you today to express our commitment to meet the call of the Department of Environmental Protection (DEP) to halt the delivery of flowback and produced water from shale gas extraction to the facilities that currently accept it under special provisions of last year’s Total Dissolved Solids (TDS) regulations. Our members are carefully reviewing their operations and support achieving this milestone by May 19, 2011 ( 111 DCN SGE 00545).Chapter A

— Introduction



### 12 Table A

- 1 . Summary of State Regulations

State Relevant State Authority (s) State Authority Website(s) Description of State’s Relevant Requirements

Ohio OH EPA, OH DNR O H EPA: http://www.epa.stat e.oh.us/

OH DNR: http://ohiodnr.gov/

Ohio R.C. 15, Chapter 1509 : http://codes.ohio.go v/orc/1509 Ohio R.C. Title 15, Chapter 1509

, p art 22(C)(1) ( 128 DCN SGE 00983)

, includes the provision that

brine 12 from any well except an exempt Mississippian well 13 shall be disposed of only as follows: by injection into an underground formation, including annular disposal if approved by rule of the chief, which injection shall be subject to division (D) of this section; by surface application in accordance with sect ion 1509.226 of the Revised Code; in association with a method of enhanced recovery as provided in section 1509.21 of the Revised Code; [or] in any other manner not specified in divisions (C)(1)(a) to (c) of this section that is approved by a permit or ord er issued by the chief.

West Virginia WVDEP WVDEP: http://www.dep.wv .gov/Pages/default.
aspx A WVDEP guidance document about POTWs accepting oil and gas wastewater ( 218 DCN SGE00767) notes that The USEPA and WVDEP discourage POTWs from accepting wastewater from oil and gas operations such as coal bed methane and Marcellus Shale wastewaters because these wastewaters essentially pass through sewage treatment plants and can cause inhibition and interference with treatment plant operations.

12 The Ohio EPA defines brine as “all saline geological formation water resulting from, obtained from, or produced in connection with the exploration, drilling, or production of oil or gas, including saline water resulting from, obtained from, or produced in connection with well stimulation or plugging of a well.”

13 OH R.C. Section 1509.01 defines an “exempt Mississippian well” as a well that (1) was drilled and completed before January 1, 1980; (2) is in an unglaciated part of the state; (3) was completed in a reservoir no deeper than the Mississippian Big Injun sandstone in areas underlain by Pennsylvanian or Permian stratigraphy, or the Mississippian Berea sandstone in areas directly overlain by Permian stratigraphy; and (4) is used primar ily to provide oil or gas for domestic

use.Chapter A

— Introduction



### 13 Table A

- 1 . Summary of State Regulations

State Relevant State Authority (s) State Authority Website(s) Description of State’s Relevant Requirements

Michigan MI DEQ MI DEQ: http://www.michig an.gov/deq Michigan Oil and Gas Regulations: http://www.michig an.gov/documents/ deq/ogs

- oilandgas

regs_263032_7.pdf Michigan’s Oil and Gas Regulations

, part 324.703 ( 120 DCN SGE00254)

, state that A permittee of a well shall inject oil or gas field fluid wastes, or both, into an approved underground formation in a manner that prevents waste. The disposal formation shall be isolated from fresh water strata by an impervious confining formation.

Sources: 130 DCN SGE 00187 ; 120 DCN SGE00254 ; 104 DCN SGE 00545 ; 198 DCN SGE 00766 ; 218 DCN SGE 00767 ; 170 DCN SGE 00982 ; 128 DCN SGE0098 3

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 QualityChapter A

— Introduction



### 14 3 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 regu lations are found at 40 C.F.R. parts 144 through 148, and specifically prohibit any underground injection not authorized by UIC permit (40 C.F.R. part 144.11). They classify underground injection into six classes; wells that inject fluids brought to the su rface in connection with oil and gas production are classified as Class II UIC wells (see Section D. 2 for more information). Thus, an onshore oil and gas extractio n facility that seeks to meet zero discharge requirements through underground injection of wastewater must dispose of the wastewater in a well with a Class II UIC disposal well permit.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 15 

## Chapter B. B ACKGROUND ON 

## U NCONVENTIONAL 

## O IL AND 

## G AS 

## E XTRACTION



### To provide context for discussions of UOG extraction wastewater volumes and characteristics ( Chapter C ) and management and disposal practices ( Chapter D ), this chapter describes the following:

• What UOG resources are in context of the proposed rule

, differences between unconventional and conventional resources , differences between types of UOG

resources, and where UOG resources are located

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

• Historical, current, and project ed future UOG well drilling activity

Relevant national economic information about the UOG industry is included in a separate memorand um to the record, titled Profile of the Oil and Gas Extraction (OGE) Sector, with Focus on Unconventional Oil and Gas (UOG) Extraction ( 2 DCN SGE 00932).

Oil and gas resources are defined as the total in

- place hydrocarbon contained in porous rock formations. There are several ways to classify oil and gas resources. Throughout this TDD, the EPA typically classifies resources into conventional and unconventional resources

. For purposes of the proposed rule

, the EPA is proposing to define “unconventional oil and gas” (UOG) as “c rude o il and natural gas 14 

### produced b y a well drilled into a low porosity, low permeability formation (including, but not limited to, shale gas, shale oil, tight gas, tight oil) .” As explained in the preamble to the proposed rule and in Section A. 1 , although CBM would fit the definition of UOG in the proposed rule, the proposed rule would not apply to pollutant discharges to POTWs associated with CBM extraction.

The d ifferent types of u nconventional resources (shale, tight) and how they differ from conventional resources are discussed in more detail in Section B. 2.1

. UOG and conventional oil and g as (COG) r esources can be further classified by the type of hydrocarbon: oil, natural gas, and natural gas condensates. Literature often refers to formations that co

- produce natural gas condensates 15 

### along with oil and/or natural gas as liquid rich formatio ns. Formations that primarily produce oil also co

- produce natural gas known as “associated gas” ( 206 DCN SGE 00623). F ormations that only produce dry natural gas are known as non

- associated gas

resources.

1 O VERVIEW OF 

### UOG R ESOURCES



### The Energy Information Administration ( EIA ) publishes historical and projected future oil and gas production by resource type in its Annual Energy Outlook s (AEO s ). Beginning around 2000, advances in technologies such as horizontal drilling and advances in hydraulic fracturing made it possible to economically produce oil and natural gas from tight and shale

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

15 Natural gas condensates include light hydrocarbons such as ethanes, propanes, and butanes. When gas condensates are depressurized at the wellhead, they condense into a liquid phase. When processed at the refinery, the finished byproducts of natural gas condensates are referred to as natural gas liquids and have high market value.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 16 resources ( 209 DCN SGE01095)

. The EIA’s 2014 AEO projects that

, in the next 30 years , the majority of the country’s natural gas will come from unconventional resources and that unconventional oil production w ill continue to increase substantial ly ( 31 DCN SGE 00989 ). Figure B-1 and Figure B-2 show the historical and future profile s of COG and UOG production in the U nited S tates by resource type according to the EIA. 16 

### CBM and COG are included in some of the figures in this chapter, but are identified separately within each figure

. Section B. 3 summarizes historical and current trends in UOG drilling in more detail on a well basis.

Figure B-3 and Figure B-4 sh ow the major shale and tight UOG resources

, respectively

, in the lowe r 48 states. Appendix F ( Table F-3 and Table F-4 ) provide s an updated and more thorough list of UOG formations by basin as the EIA maps shown below only show major UOG formations as of May 2011. Geological characteristics of UOG resources shown in Figure B-3 and Figure B-4 are described in detail in Section B. 1.2

. 17

Source: 158 DCN SGE 00487



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

16 In Figure B-1

, the EIA refers to all types of unconventional oil including shale as “tight oil

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

17 The EIA uses the term “play” to describe subsets of UOG resources in Figure B-3 and Figure B-4 , which are similar to the term “ formation ” as used in this TDD.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 17 Source: 31 DCN SGE 00989



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

Source: 157 DCN SGE 00153



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



### — Background on Unconventional Oil and Gas Extraction



### 18 Sour c e: 156 DCN SGE 00155



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

The key difference s between UOG and COG resources are the geological characteristics of the formation s that contain the resource s. UOG reso urces include shale oil and gas resources that were formed, and remain, in low

- permeability shale. UOG resources also include tight oil and gas resources that were formed in a source rock and migrated into a reservoir rock such as sandstone, siltstones, or carbonates. The permeability and porosity of tight oil and gas reservoirs are lower than that of COG reservoirs, but generally higher than that of shale oil and gas reservoirs ( 100 DCN SGE 00527). As mentioned above, w hile CBM is sometimes referred to as an unconventional resource, the proposed rule does not apply to CBM, and therefore the scope of this document does not include CBM

.

1.1 How UOG Resources Were Form ed

Differences in how conventional and unconventional resources were formed can be explained in terms of the source and resource rock. 18 

### The following explains these differences, which are also illustrated in Figure B-5 ( 100 DCN SGE 00527 ; 113 DCN SGE 00547; 211 DCN SGE 00114).

• Oil and gas in conventional resources were formed in a source rock, migrated through the surrounding permeable rock, and eventually became trapped by a confining rock layer forming non

- continuous accumulations. The final reservoir rock has high permeability and porosity.

18 The source rock is the type of rock in which the oil and/or gas formed. The reservoir roc k is the type of rock in which the oil and/or gas is contained at the time of production.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 19 • Oil and gas in tight resources, similar to conventional resources, were formed in a source rock and migrated until they reached a confining layer of rock. Tight resour ces occur in a mixture of continuous and non

- continuous accumulations. They differ from conventional resources in that the oil and gas accumulated in a reservoir rock with relatively low permeability and porosity. 19



### • Oil and gas in shale resources were formed in and remained in the source ro ck, making it also the reservoir rock. Consequently, shale reservoirs occur in continuous accumulations over large geographic areas. Shale reservoirs have the lowest permeability and porosity out of al l resource types (see Section B. 2.2 for more information about hydraulic fracturing).

Source : 155 DCN SGE 00594



### Figure B-5. Geology of Formations Containing Various Hydrocarbons 20



### 1.2 Geological Characteristics of UOG Resources

UOG resources are typically developed using advanced completion and well drilling techniques because they have unique geologic characteristics that differ from conventional

resources . These are summarized in Table B-1

. COG reservoirs have relatively high porosities and permeabilities

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

19 Because tight oil and gas exists in multiple types of reservoir rocks, EPA refers to it generally as “tight” oil and gas in this report as opposed to “tight sands” because that reference is not all inclusive of the different types of tight formations.

20 “Associated” gas accumulates with oil in a formation. “Non

- associated” gas accumulates separately from oil in a formation ( 206 DCN SGE00623).Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 20 gradients with open- hole completion techniques (see Section B. 2.2 for more information about well completion). UOG reservoirs have extremely low porosity and permeability

, typically requiring rigorous stimulation ( e.g., hydra ulic fracturing) during well completion to produce oil and gas economically ( 113 DCN SGE 00547; 100 DCN SGE 00527; 211 DCN SGE 00114). Although it is not necessary to create fractures to obtain oil and gas from conventional reservoirs, hydraulic fracturing can still be used to increase production from COG well s ( 100 DCN SGE 00527 ; 146 DCN SGE00291 ) 21



### . UOG formations are also more likely to occur in

con tinuous accumulations

, as explained in Section B. 1.1 . As a result, UOG wells are more likely to be drilled horizontally.

Table B

- 1 . Characteristics of Reservoirs Containing UOG and COG Resources

Reservoir Characteristic COG Resources UOG Resources Tight Shale

Reservoir r ock t ype Sandstones, siltstones, or carbonates Sandstones, siltstones, or carbonates Shales

Source r ock No No Yes

Accumulation t ype Non

- continuous Continuous or non

- continuous Continuous Porosity High ( >10% ) Low ( <10% ) Low ( <10% ) Permeability High ( >100 mD ) a Low ( < 0 .1 mD ) a Low ( < 0

. 00 1 mD ) a

Well t rajectory b Mostly vertical Mixture of vertical and horizontal Mostly horizontal

Completion m ethod Open hole completions and

n atural reservoir pressure c Hydraulic fracturing and/or acidization d Hydraulic f racturing

Source s : 211 DCN SGE 00114; 86 DCN SGE 00533 ; 100 DCN SGE 00527 ; 109 DCN SGE 00345

a— The millidarcy (mD) is a measurement of permeability (i.e., ability for fluid flow within a rock). Higher permeability means fluids flow more readily. b— Well trajectories are described in more detail in Section B. 2.1

. c— As COG wells age, operators may also use enhanced recovery techniques such as water or steam injection t o enhance production. COG wells may also be hydraulically fractured

. d— Acidization is the process of dissolving undesired rocks from the wellbore using acidic fluids in order to improv e fluid flow from the reservoir ( 18 DCN SGE 00966).



### 2 UOG W ELL 

### D EVELOPMENT 

### P ROCESS



### UOG well development includes the following processes : well pad construction, well drilling and construction, well completion, and production. UO G well completion includes well stimulation such as hydraulic fracturing, acidization, or a combination of hydraulic fracturing and acidization. The return of injected fluids to the surface, commonly referred to as the “flowback process

, ” is also part of t he UOG well completion process. Before UOG well development , operators conduct exploration and obtain surface use agreements, mineral leases, and permits. These steps can take a few months to several years to complete. When they are

21 A survey conducted by American Petroleum Institute (API) and the American Natural Gas Alliance (ANGA), included well completion information for 5,307 well completions in 2010 , consisting of a mixture of conventional and unconventional wells. The survey also showed that 69 percent of conventional wells were hydraulically fractured.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 21 completed, operators be gin the well development process , as described in the following subsections.

The largest UOG extraction wastewater volumes generated during the UOG well development process are flowback and long- term produced water (see Section C. 2 for characteristics of each ). UOG well drilling also generates drilling wastewater. Throughout the well development process, many materials are transported to the well pad. These materials in clude well casing and tubing, fuel (e.g., diesel or liquefied natural gas), and base fluid, sand, and chemicals for hydraulic fracturing. Operators must also transport UOG extraction
wastewater from the well to the ultimate wastewater management or disposal location —e.g., a centralized waste treatment ( CWT ) facility, an underground injection well for disposal, another well for reuse

. Sand, chemicals, and construction m aterials are typically transported to the well pad by truck, but fracturing base fluid (e. g., fresh water, recycled UOG produced water ) and UOG extraction wastewate r may be transported via truck or temporary piping ( 191 DCN SGE 00625; 178 DCN SGE 00635; 179 DCN SGE 00275 ).

2.1 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 formatio ns and to determine the size and production potential of hydrocarbon reserves. Development involve s drilling production wells once a hydrocarbon reserve has been discovered and delineated. The following discussion will focus on the drilling of production w ells.

After the well pad is constructed, operators drill and construct the well. Operators use one of the three drilling trajectories below to drill for UOG (see Figure B-6 ). See Table B-3 for a breakdown of active UOG wells as of 2011 by drilling trajectory

.

• Vertical 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 shale wells ( 100 DCN SGE 00527 ). For shale, vertical drilling is used by operators during the exploration phase of field development ( 178 DCN SGE 00635) , in shallow formations (e.g., Antrim shale), or by small entity operators who may be unable to make large investments in horizontal wells ( 39 DCN 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 directl y below the well pad. Directional drilling is used where a well pad cannot be constructed directly above the resource (e.g., in rough terrain ). Directional drilling is common in conventional and unconventional tight formations that occur as accumulations a s 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 latera l, which can vary in length between 1,000 and 5,000 feet ( 154 DCN SGE 00593; 206 D CN SGE 00623). Horizontal drilling is the most commonly used method in continuous shale and tight formations ( 24 DCN SGE 00354; 78 DCN SGE 00010).Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 22 Sou rce: 154 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 la rge geographic areas, operators drilling in these resources typically drill multiple hor izontal wells on each well pad ( 191 DCN SGE 00625; 178 DCN SGE 00635; 179 DCN SGE 00275) . However, tight reservoirs occur in both continuous and non

- continuous accumulations; therefore, operators ma y drill multiple horizontal wells or a single directional or vertical well on a well pad, depending on the location and accumulation type of the tight reservoir. Directional and horizontal well configurations give operat ors access to more o f the producing formation and therefore reduce surface disturbance ( 24 DCN SGE 00354; 212 D CN SGE 0 0011). Operators may drill one or two horizontal wells on a well pad initially and move on to the next pad. When this happens, the operator typically comes back to drill out the remaining wells on the pad after the initial wells show economical production and favorable conditions. 22



### Drilling for oil and gas is generally performed by rotary drilling methods

, which involve the use of a rotating drill bit that grinds through the earth’s crust as it descends. Well drilling is an iterative process that includes several sequences of drilling, installing casing, and cementing of succeeding sections of the well ( 178 DCN 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

. Ope rators use one of the following types of d rilling fluid s depending on which portion of the well they are drilling ( 55 DCN SGE 00740):

• Compressed gases: During the beginning phase of drilling an UOG well (i.e., the initial drilling close to the surface), compressed gases may be used to minimize costs

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

22 Favorable conditions include sufficient oil and/or gas prices, available drilling rigs, availab le fracturing crews, and permits.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 23 • Water- based: At sever al 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

, 23 

### barite, polymers, lime, and g els 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 associated with deeper depths. Oil

- based drilling fluids may use diesel oil and/or mineral oils and contain emulsifiers, barite, and gels as additives

.

• Synthetic -oil- based: For dri lling at deep depths and/or the horizontal laterals of wells , operators may also use synthetic-oil- based fluids which are similar to oil

- based fluids. However, instead of using diesel oil and/or mineral oils, synthetic oil- based fluids use organic fluids (e.g., esters, polyeolefins, acetal, ether, and linear alkyl benzenes) that exhibit similar fluid properti es as diesel and mineral oils. Synthetic

oil-based fluids have been referred as more environmentally friendly 24 

### than oil- based fluids but are also more expensive ( 162 DCN SGE01006; 17 DCN SGE01009).

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

, and centrifuges

. This results in drill cuttings and a wastewater stream, referred to as drilling wastewater . Drilling wastewater is either reused/recycled in a closed loop
process or otherwise managed (e.g., transferred to a CWT facilit y) ( 124 DCN SGE 00090; 178 DCN SGE 00635).

Wel l drilling and construction typically lasts between five days and two months, depending on well depth and how familiar operators are with the specific formation. Figure B-7 shows that drilling time generally decreases as UOG operators become more familiar and efficient at drilling in a UOG formation ( 9 DCN SGE 00503 ; 178 DCN SGE 00635; 26 DCN SGE 00516 ). Figure B-7 also compares drilling phase durations among UOG formations (e.g., Granite Wash requires 40 to 50 days for drilling while Barnett requires 10 or fewer days).

23 The UOG industry may refer to water

- based drilling fluids that contain salts as “salt mud.”

24 Using synthetic

- oil

- based drilling fluids results in a lower volume of wastewater that must be disposed of. They also have lo wer toxicities, lower concentrations of certain priority pollutants, lower bioaccumulation potential, and faster biodegradation rates than oil

- based drilling fluid.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 24 Source: 48 D CN SGE00693



### Figure B-7. Length of Time to Drill a Well in Various UOG Formations as Reported for the First Quarter of 2012 through the Third Quarter of 2013

2.2 UOG Well Completion

After the well is drilled and constructed, the well completion process begins. “Well completion ” is a general term used to describe the process of bringing a wellbore into production once drilling and well construction are completed ( 33 DCN SGE 00984). The UOG w ell

c ompletion process involves many steps , including cleaning the well to remove drilling fluids and debris, perforating the casing that lines the producing formation

, 25 

### inserting production tubing to transport the hydrocarbon fluids to the surface, installing the surface wellhead

, stimulating the well (e.g., hydraulic fracturing) , setting plugs in each stage, and eventually drilling the plugs out of the well. It also i ncludes the flowback process, in which fluids injected during well stimulation return to the surface. The following two subsections describe the well stimulation and flowback processes that are common for UOG well completion

.

25 In some instances, open

- hole completions may be used, where the well is drilled into the top of the target formation and casing is set from the top of the formation to the surface. Open

- hole well completions leave the bottom of the wellbore uncased.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 25 2.2.1 UOG Well Completion: Well Stimulation Because UOG resources are extracted from formations with low porosity and permeability, UOG wells are typically developed using more advanced stimulation technologies than traditionall y used on COG wells to create higher permeability in the reservoir that allows operators to produce oil and gas economically. UOG well stimulation techniques include but are not limited to hydraulic fracturing, acidization, or a combination of fracturing and acidization ( 18 DCN SGE 00966). The most common technique for UO G wells is hydraulic fracturing , discussed in the rest of this subsection (see Section B. 3.3 ) ( 78 DCN SGE 00010 ). H ydraulic fracturing of COG wells is becoming more common, but traditionally COG wells h ave been completed with open-hole techniques allowing the oil and/or gas resources to flow naturally ( 109 DCN SGE 00345; 86 DCN SGE 00533 ).

O perators typically fracture UOG wells in multiple sta ges to maintain the high pressures necessary to fracture the reservoir rock. Stages are fractured starting with the stage at the end of the wellbore and working back toward the wellhead. T he number of stages depends on lateral len gth

. Because horizontal la terals are 1,000 to 5,000 feet long, o perators may use between eight and 23 stages for horizontal wells ( 177 DCN SGE 00276 ). Vertical wells are typically only fractured with one stage ( 78 DCN SGE 00010 ). A fracturing crew can typically fracture two to three stages per day when operating 12 hours per day or four to five stages per day when operating 24 hours per day. 26 

### Consequently, a typical well may take two to seven days to complete ( 87 DCN SGE 00239; 124 DCN SGE 00090). The following processes are performed for each stage :

• Perforation

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

• Hydraulic f racturing

— Operators inject fracturing fluids ( e.g. , water, sand, and other additives) down the wellbore to highly pressurize the formation to the point where small fractures are created in the rock (s ee Figure B-8 ). 27 

### See Section C. 1 for information about fracturing fluid volumes and characteristics.

• Stage plugging

— Once the stage is hydraulically fractured, a stage plug is inserted down the wellbore, separating it from additional stages until all stages are completed.

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

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

- pressure water and chemical additives without proppant (i.e., solid material designed to keep fractures open to allow gas to flow from the producing formation ) to create the initial fractures into the formation. After the pad is pumped downhole, proppant is introduced to the fracturing fluid for the additional stages.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 26 Source : 168 DCN 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 ) ( 190 DCN SGE 00280; 179 DCN SGE 00275; 177 DCN SGE 00276). Operators that reuse /recycle UOG produced water in

s ubsequent fracturing jobs typically store the reused /recycled wastewater in fracturing tanks and/or pits ( 190 DCN SGE 00280). Oper ators typically have s and trucks and pump trucks onsite during the hydraulic fracturing process. The sand trucks contain the sand prior to mixing in the fracturing fluid and the pump trucks pump the fracturing fluid down the wellbore during each stage of fracturing.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 27 Source: 179 DCN SGE 00275



### Figure B-9 . Freshwater Impoundment

2.2.2 UOG Well Completion: Flowback Process

After all of the stages of a well have been hydraulically fractured

, the stage plugs are drilled out of the wellbore and the pressure at the wellhead is released. Releasing the pressure allows a portion of produced water to return to the wellhead; this waste st ream is often referred to as “flowback .” Industry commonly refers to this as the flowback process ( 178 DCN SGE 00635). The flowback consists of a portion of the fluid injected into the wellbore combined with formation water. At the wellhead, a combination of flowback water, sand, oil, and /or gas is routed through phase separators , which separate products from wastes. Industry uses different types of separators depending on a number of factors (e.g., formation, resource type). Figure B-10 shows an example of a separator used for dry gas production (i.e., only req uires gas and water separation because there is no oil production).

Higher volumes of flowback water are generated i n the beginning of the flowback
process ; f lowback rates decrease as the well goes into the production phase. O perators typically store flow back in fracturing tanks onsite before treatment or transport offsite. 28 

### In addition to flowback , small quantities of oil and/or gas may be produced during the initial flowback process. The small quantities of produced gas may be flared ; if the operator is using “ green completions ,”

28 Fracturing tanks cannot be transported from one site to another when they contain wastewater. Wastewater is typically transported via trucks with capacities of about 4,200 to 5,000 gallons (100 to 120 barrel ) or via pipe ( 178 DCN SGE00 635 ).Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 28 the gas may instead be captured

. 29 

### If oil is produced, oil/water separators may be used 30 

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

Source: 191 DCN SGE 00625



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

Flowba ck typic ally lasts from a few days to a few weeks ( 78 DCN SGE 00010; 212 DCN SGE 00011; 204 DCN SGE 00622; 153 DCN SGE 00592; 80 DCN SGE 00286). At some wells, the majority of fracturing fluid may be recovered within a few hours ( 78 DCN SGE 00010; 212 DCN SGE 00011; 204 DCN SGE 00622; 153 DCN SGE 00592; 80 DCN SGE 00286 ). A 2009 report published by the Ground Water Protection Council and ALL Consulting stated that
ope rat ors recover between 10 and 70 percent of the f racturing fluid that they inje ct down the wellbore ( 78 DCN SGE 00010; 153 D CN SGE 00592; 80 DCN SGE 00286). Section C. 3.1 provides more details on flowback generation rates over time and fracturing fluid recovery
p ercentages for specific UOG formations.

29 On April 17 , 2012, the U.S. EPA issued regulations, required by the Clean Air Act, requiring the natural gas industry to reduce air pollution by using green completions, or reduced emission completions. EPA has identified a transition period until January 1, 2015

, to allow operators to locate and install green completion equipment (40 C.F.R. part 60 and 63).

30 Operators sometimes use chemicals during the oil/water phase separation process.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 29 Source: 191 DCN SGE 00625



### Figure B-11. Fracturing Tanks

2.3 Production

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

. During th is production phase, UOG wells produce oil and/or gas and water. This water, called “ long- term
p roduced water ” in this report, consists primarily of formation water and continues to be produced throughout the lifetime of the well, though typically at much lower rates than flowback ( 153 DCN SGE 00592)

. Long

- term p roduced water rates range from less than a barrel up to 4,200 gallons ( 100 barrels) per day (see Chapter C ) and gradually decrease over the life of the well. 31


### The rates vary with each well because they are dependent on formation characteristics and the completion success of the given well (see Chapter C for information about flowback and long

term produced water volumes and characteristics).

When the well enters the production phase, operators typically remove t he fracturing tanks that were used during flowback and store long

- term produced wate r in permanent above

ground storage tanks referred to as produced water tanks with capacities that range from 4,200 to 33,600 gallons (100 to 800 barrels ) (see Figure B-12 ) ( 190 DCN SGE 00280; 179 DCN SGE 00275; 183 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 ( 178 DCN SGE 00635; 177 DCN SGE 00276).

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

, while others may only produce economically for 10 years ( 80 DCN SGE00 286).Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 30 Source: 179 DCN SGE 00275



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

3 UOG W ELL 

### D RILLING AND 

### C OMPLETION 

### A CTIVITY



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

• Historical and current UOG well drilling activity

• Total estimated UO G resource potential

• Current and projections of future UOG well completions

3.1 Historical and Current UOG Drilling Activity

Since 2000, hydraulic fracturing coupled with drilling directional and horizontal wellbores in unconventional formations has increased ( 209 DCN SGE01095). More recently, drilling has also increased in liquid

- rich formations. 32 

### Baker Hughes, one of the world’s largest oilfield services companies, periodically publishes location and other data for active U.S. rigs. 33 

### Figure B-13 shows Baker Hughes’ estimates of total number of active d rilling rigs in the U nited

32 Liquid

- rich formations are those that either primarily produce oil or primarily co

- produce natural gas with gas condensates (i.e., hydrocarbons such as ethanes, propanes, and butanes). When gas condensates are depressurized at the wellhead, they condense into a liquid phase.

33 Baker Hughes obtains data in part from RigData, a company that sells rig and well data. Rig data Baker Hughes publishes are reported in major newspaper s and journals (e.g., Oil and Gas Journal ) and are used by the industry as an indicator for demand of oil and gas equipment.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 31 S tates between January 2000 and November 2013 and shows drilling trajectory ( i.e., directional, horizontal, v ertical) and product type (i.e., oil, gas). These counts include rigs that are drilling for CBM and COG

. Both horizontal drilling and oil well drilling have increased since 2000. ( As of November 15, 2013, 63 percent of rigs were drilling horizontal wells compared to 6 percent in January 2000. 34 

### ) In 2009, horizontal well drilling surpassed vertical well drilling for the first time in the U nited S tates . Shortly after, in 2011, oil well drilling surpassed gas for the first time since 1993 ( 7 DCN SGE 00504).

Source: 48 DCN SGE00693



### Figure B-13. Number of Active U.S. Onshore Rigs by Trajectory and Product Type over Time 35



### 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 November 2013. Based on data reported by Baker Hughes and rig counts reported in other literature, the majority of rigs were drilling

34 An other 13 percent of wells were being drilled directionally in the U nited S tates as of November 8, 2013.

35 The sharp decrease in active drilling rigs observed in 2009 is likely attributed to the sudden drop in natural gas and crude oil prices also experienced in 2009 ( 31 DCN SGE00989).Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 32 into unconventional formations at this time ( 8 DCN SGE 00502; 159 DCN SGE 00595). Where Baker Hughes did not specify the formation bei ng drilled , counts may include a mixture of rigs that are drilling for UOG, CBM , and COG

. In 2012, nearly 1,800 active rigs drilled about 36,000 wells ( 9 DCN SGE 00503).Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 33 Table B

- 2 . Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product Type (as of November 8, 2013)

Basin b Formation b Resou rce Type b Gas Rigs by Well Trajectory Oil Rigs by Well Trajectory a

Total Rigs Directional Horizontal Vertical Total Gas Directional Horizontal Vertical Total Oil

Permian

— c Mix 0 6 1 7 21 206 235 462 469

Other d

— c Mix 48 20 20 88 55 139 85 279 367

Western Gulf Eagle Ford Shale 0 26 0 26 17 174 9 200 226

Williston

— c,e Mostly s hale e 0 0 0 0 16 155 4 175 175 Appalachian Marcellus Shale 10 67 8 85 0 0 0 0 85

Anadarko Mississippi Lime Tight 0 9 0 9 2 58 6 66 75

Anadarko Granite Wash Tight 0 8 0 8 0 50 2 52 60

Denver J. Niobrara Shale 0 18 0 18 3 25 5 33 51

Anadarko Woodford f Shale 1 17 0 18 2 27 3 32 50

TX

- LA

- MS Salt Haynesville Shale 0 38 0 38 0 2 0 2 40

Fort Worth Barnett Shale 0 18 0 18 0 9 9 18 36 Appalachian Utica Shale 2 17 0 19 0 15 2 17 36

Arkoma Fayetteville Shale 0 9 0 9 0 0 0 0 9

Total 61 253 29 343 116 860 360 1,336 1,679

Source s : 48 DCN SGE0069 3

a— Oil rigs include six “miscellaneous” rigs reported by Baker Hughes ( 

### 8 DCN SGE00502)

. b— Baker Hughes ( 

### 8 DCN SGE00502) reported a mixture of basins and format ions. 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 (co nventional, tight, shale).

c— Baker Hughes reporte d basin as opposed to formation for these areas. Therefore, these areas may include rigs drilling in conventional and unconve ntional formations. d— The majority of the “Other” rigs were drilling in Texas, Louisiana, Wyoming, California, Utah, and Colorado. The remaining rigs in the “Other” category were distributed evenly throughout the 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 ( 159 DCN SGE00595). f

— This formation includes the Woodford

- Cana, Arkoma Woodford, and Ardmore Woodford formations.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 34 3.2 UOG Resource Potential

Assessments by the U .S. Geological Survey (USGS) and the EIA show substantial potential for new UOG wells. Using the USGS and EIA assessments, this section quantifies how
many new UOG wells may be drilled in the future (i.e., new well potential) to estimate the potential numb er of new UOG extraction wastewater sources. The EIA also calculates new well potential in its AEO but only for several sub

- formations. 36 

### The EPA used the EIA methodology to calculate new well potential for all UOG formations

. 37 

### Th is analysis is documented in more detail in a separate memorandum titled Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction ( 48 DCN SGE 00693 ; 50 DCN SGE 00693.A0 2).

The two EIA

- reported parameters that the EPA used to ca lculate new well potential are described below. The EIA’s estimates of resource potential are primarily based on geological characteristics published by the USGS

, which in turn rely on historical production data from existing wells and the technology deplo yed at the time of assessment. However, the EIA adjusts these estimates annually to account for the ongoing changes in drilling and completion practices and to account for formations not yet assessed by the USGS ( 32 DCN SGE 00988 ; 31 DCN SGE 00989 ).

• Estimated ultimate recovery per well (EUR)

— EUR is the quantity of oil and/or gas that is produced by a single well over its life.

• Technically recoverable resources (TRR) —The TRR is the quantity of oil and/or gas producible from a geological 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 area that can be developed for oil and gas extraction, average well spacing assuming that the formation is fully developed, and EUR per well. TRR is the sum of proven reserves and unproven

resources. 38



### To evaluate new well potential, the EPA calculated new well potential for each formation or sub -formation by dividing the TRR by the EUR. Table B-3 summarizes the total new well potential the EPA calculated for the four UOG resource types

. 39 

### It also shows the approximate number of current wells based on the EPA ’s analysis of D rillingi nfo’s (DI) D esktop® well database ( 29 DCN SGE00520 ). Appendix F provides EUR and TRR on a for mation basis based on this analysis

. To calculate total TRR and new well potential by resource type, the EPA

36 For ex ample, the Assumptions to the 201 4 AEO reported new wel l potential for several, but not all, Bakken sub

formations: 29,186 wells. The EPA estimated approximately 28,562 new Bakken wells for the same Bakken sub formations . Differences between EIA and EPA ne w well potential are due to rounding ( 32 DCN SGE00988 ).

37 These estimates do not factor in future changes to TRR estimates by the EIA, advances in drilling technology, or economic conditions that ultimately affect how many wells UOG operators drill over time ( 31 DCN SGE00989; 32 DCN SGE00988 ).

38 Proven reserves are resources that are currently developed commercially or have been demonstrated with reasonable certainty to be recoverable in future years under existing economic conditions and current technologies. Unproven resources are resources that have been confirmed by exploratory drilling but are not yet commercially developed.

39 These estimates only include shale and tight oil and gas resources. It does not include CBM or COG

.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 35 summed the TRR and the new well potential for all formations in each resource type shown in Table F-2 and Table F-3

. The results presented in Table B-3 show that the UOG n ew well potential is much greater than the active well count. The EPA estimates that approximately 2.2 million potential new UOG wells

— with associated extraction wastewater

— may be drilled in the future.

Table B

- 3

. UOG Po tential by Resource Type as of January 1, 201 2

Resource

Type Weighted Average Oil EUR (MMbls per well) Weighted Average Gas EUR (Bcf per well) Total Oil TRR (MMbls) Total Gas TRR (Bcf) Total New Well Potential (Beginning in 201 2 ) 2010

- 2011 Active Well Count b

Shale g as 0.007 0.54 3 6,200 501,500 923,000 H: 22,400 D: 1,820 V: 15,100 U: 15,300 Shale o il 0.079 0.099 26,300 33,100 333,000

Tight g as 0.006 0.483 4,200 352,200 729,000 H: 5,620 D: 9,230 V: 59,600 U: 32,800 Tight o il 0.105 0.076 22,500 16,400 215,000

All UOG 0.027 0.411 59,200 903,200 2,200,000 H: 28 ,000 D: 11, 1 00 V: 7 4,7 00 U: 4 8

, 1 00

Source s : 48 DCN SGE 00693

a—G as production from shale and tight oil resources is associated gas that is produced simultaneously with oil. b—W ell counts are based on ERG’s A nalysis of DI Desktop® memorandum ( 45 DCN SGE00963) . These well counts may not be all

- inclusive.

Abbreviations : MMbls

- million barrels; Bcf -b illion cubic feet of gas; EUR —e stimated u ltimate recovery (per well); TRR —t echnically recoverable resources; H— horizontal ; D

— directional ; V —v ertical; U

— trajectory unknown



### 3.3 Current and Projections of Future UOG Well Completions

In 2012 alone, more than 22,000 40 

### oil and gas wells were hydraulically fractured nationwide ( 199 DCN SGE00585). As previously explained, hydraulic fracturing is currently the most popu lar well stimulation technique for UOG wells. A s urvey conducted by the American Petroleum Institute ( API ) and the American Natural Gas Alliance (ANGA) shows that, as of 2010, nearly all unconventional wells were being completed using hydraulic fracturing ( 146 DCN SGE 00291). 41 

### 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 reported as refracturing of existing oil and gas wells ( 210

40 The actual number of wells fractured in 2012 is greater than 22,000 because this number is based on FracFocus data and some states where fracturing is common (e.g., Michigan) did not yet require reporting to FracFocus in 2012.

41 This survey included well comp letion information for 5,307 well completions in 2010, consisting of a mixture of conventional and unconventional wells. The survey results showed that more than 96 percent of tight gas wells and 99 percent of shale gas wells surveyed were hydraulically fractured. The survey also showed that 69 percent of conventional wells were hydraulically fractured.Chapter B



### — Background on Unconventional Oil and Gas Extraction



### 36 DCN SGE01 095.A09 ). A more recent survey of 205 UOG operators conducted by the Petroleum Equipment Suppliers Association (PESA) 42 

### shows that in 2012 and 2013 approximately 10 percent of well completions involving hydraulic fracturing were refracturing of existing oil and
gas wells ( 136 DCN SGE00575).

In 2012, IHS, Inc. estimated the total number of UOG wells that UOG operators may complete through 2035 ( 94 DCN SGE 00728). The EPA generated Figure B-14 using data publ ished by I H S ( 48 DCN SGE 00693) . The figure shows the projected number of UOG wells 39 

### completed annually and cumulatively. Unconventional gas is further broken down into tight gas and shale gas. The projections estimated by IHS show a gradual increase in annual UOG well completions through 2035.

Figure B-14. Projections of UOG Well Completions Source: 48 DCN SGE00693

42 The PESA represents the energy industry’s manufacturers and oilfield service and supply companies. Its mission is to promote and advocate for policies th at will support the oilfield service sector’s continued job creation, technological innovation, and economic stability.Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 37 

## 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 ( 209 DCN SGE01095) . The EIA, in its 2014 AEO, projects that, within the next 30 years, the majority of the country’s natural gas will come from unconventional resources and unconventional oil prod uction will continue to increase substantially ( 31 DCN SGE 00989 ). Consequently, industry experts expect UOG produced water volumes to continue to incr ease ( 34 DCN SGE 00708; 98 DCN SGE 00479; 95 DCN SGE 00722 ; 141 DCN SGE 00768.A01; 72 DCN SGE 00768.A25 ).

This chapter discusses UOG extraction wastewater volumes and characteristics. The EPA is proposing to define “ UOG extraction wastewater ” as sources of wastewater pollutants associated with production, field exploration, drilling, well completion, or well treatment

. 43 

### This includes the following sources:

• P roduced water

— the water (brine) brought up from the hydrocarbon

- bearing strata during the extraction of oil and gas. This can include formation water, injection water, and any chemicals added downhole or during the oil/water separation process . Based on the stage of completion and production the well is in, produced water can be further br oken down into the following components:

— Flowback

— the wastewater generated by UOG wells during the flowback process of well completion. After the hydraulic fracturing procedure is completed and pressure is released, the direction of fluid flow reverses,

an d the fluid flows up through the wellbore to the surface. The water that returns to the surface is commonly referred to as “flowback.”

— Long

- term produced water

— the wastewater generated by UOG wells during the production phase after the initial flowback pro cess. Long

- term produced water continues to be produced throughout the lifetime of the well.

• Drill cuttings

— the particles generated by drilling into subsurface geologic formations and carried out from the wellbore with the drilling fluid (mud).

• Drilling w astewater

— the liquid waste stream separated from recovered drilling fluid (mud) and drill cuttings during the drilling process. Drilling fluid is the circulating fluid used in the rotary drilling of wells to clean and condition the hole and to counterbalance formation pressure

.

• P roduced sand —t he slurried particles used in hydraulic fracturing, the accumulated formation sands

, and scale s particles generated during production. Produced sand also includes desander discharge from the produced water waste stream

, as well as blowdown of the water phase from the produced water treat ment system.

43 Stormwater is not considered a source of UOG extraction wastewater. In general, no permit is required for discharges of stormwater from any field activities or operations associated with oil and gas production, except as specified in 40 C.F.R. part 122.26(c)(1)(iii) for discharges of a reportable quantity or that contribute to a violation of a water quality standard

.Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 38 The EPA identified drilling wastewater and produced water as the major sources of wastewater pollutants associated with UOG extraction, so these wastewaters are described f urther below. The following subsections discuss volumes and chemical constituents found in fracturing fluid typically used by UOG operators and volumes and characteristics of drilling wastewater, flowback, and long- term produced water generated by UOG oper ations. The EPA identified this information from existing data sources, including state and federal agency databases, journal articles and technical papers, technical references, industry/vendor telephone calls, industry site visits

, and meetings with indu stry. The EPA reported the data exactly as reported in existing literature throughout Chapter C. In some instances, the EPA compiled the existing data into a separate document to compile and analyze the data. These separate memoranda, referenced throughout Chapter C

, are titled Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation ( 56 DCN SGE 00724 ) and Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction ( 48 DCN SGE 00693).

Section C. 1 discusses the characteristics of fracturing fluid

, 44 

### Section C. 2 discusses typical volumes of UOG ex traction wastewater , and Section C. 3 presents constituents that are typically found in UOG extraction wastewater. Section C. 3 extensively discusses TDS

, a parameter that is often used to characterize UOG extraction waste water because it provides a measure of dissolved matter including salts (e.g., sodium, chloride, nitrate), metals, minerals , and organic material ( 1 DCN SGE 00046 ). Data in Section C. 3 show that sodium chloride makes up the majority 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. 45 

### Because TDS in UOG produced water primarily consists of inorganic salts and othe r ionic species, conductivity measurements may also be used to estimate TDS

. 46 

### High measurements of specific conductivity are indicative of high TDS concentrations.

TDS and chloride are potential concerns in the management of UOG extraction wastewater beca use of the high concentrations of these parameters in the wastewater. UOG produced water can have TDS concentrations up to 400,000 mg/L, which is over 10 times the concentration of TDS typically found in seawater (i.e., 35,000 mg/L). Chapter D discusses UO G extraction wastewater management and disposal practices. Section D.3 discusses reusing/recycling UOG extraction wastewater in hydraulic fracturing and the different factors (e.g., pollutant concentrations) that operators consider when reusing/recycling U OG extraction wastewater. Section D. 5 discusses the problems that a POTW may experience if high concentrations of TDS and other UOG extraction wastewater constitue nts are present in POTW influent.

44 The type of fract uring fluid and total fracturing fluid volume may dictate the characteristics of UOG produced water and are therefore described in this chapter.

45 40 C.F.R. p art 136 lists standard method 2540C as an approved test method for TDS.

46 The electrical conductiv ity of water is directly related to the concentration of dissolved ionized solids in the water.Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 39 1 F RACTURING 

### F LUID 

### C HARACTERISTICS



### As discussed in Section B. 2.2 , most UOG resources (e.g., tight oil, shale gas) are stimulated using hydraulic fracturing. Hydraulic fracturing of UOG resources typically requires high volumes of fracturing fluid, consisting of a base fluid mixed with proppant (e.g., sand) and chemicals. The quantity of each fracturing fluid component varies by operator, basin, formation, and resource type. The remainder of this subsection discusses the sources used for base fluid,
concentr ations of chemical additives, and observed constituents in fracturing fluids.

1.1 Base Fluid Composition

The primary component of fracturing fluid is the base fluid to which proppant (sand) and chemicals are added. Fracturing fluids are typically water

- based , though cases of non -aqueous fracturing fluids are documented in the literature (e.g., compressed nitrogen, propane) ( 209 DCN SGE01095). Base fluid typ ically consists of only fresh water (surface, groundwater, or municipal water) or a mixture of fresh water

, reused/recycled UOG produced water, and/or other sources (e.g., treated municipal wastewater, groundwater) ( 126 DCN SGE 00639 ; 136 DCN SGE 00575)

. The PESA reports the following percentages of UOG operators using each water source as fracturing fluid in the Unit ed States ( 136 DCN SGE 00575):

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

• Groundwater (36 percent )

• City/m unicipal water 47 

### (16 percent )

• Recycled UOG produced water (7 percent ) 48



### • Industrial wastewater (1 percent )

Table C-1 shows the composition of base fluid for basins and/or formations with available data. Fresh water sources are those generally characterized by having low concentrations of dissolved salts and other TDS (e.g., ponds, lakes, rivers, certain underground aquifers ). Brackish sources are those with more salinity than freshwater, but not as much as
seawater (e.g., other industrial wastewater

, certain groundwater aquifers). Fresh water is the most

common source of base fluid across all basins. As shown in Table C-1 , brackish sources are used more often in arid regions (e.g., the Permian and Gulf Coast basins in Texas and New Mexico). For basins/formations where the EPA identified projected data in addition to historic data

, the E PA created a separate set of columns for each b asin/formation combination. P rojected percentages 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 fac tors ( 125 DCN SGE 00556 ; 148 DCN SGE 00710 ):

47 The PESA does not specify whether this water source is potable drinking water or treated municipal effluent ( 136 DCN SGE00575).

48 The amount of UOG wastewater that is reused/recycled in fracturing fluid varies significantly by UOG formation. See Section D. 2 for more information about UOG wastewater reuse/recycl e.Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 40 • Produced water volume

— When large volumes of flowback and long

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

• Produced water quality —When the concentration of TDS in UOG produced water rapidly increases after fracturing

, it may have less potential for reuse/recycl e as a source of base fluid to fracture another well ( 148 DCN SGE 00710).

Table C

- 1

. Sources for Base Fluid in Hydraulic Fracturing

Basin UOG Formation Resourc e Type Percentage of Total Base Fluid Used for Hydraulic Fracturing a

Fresh Water b Brackish Water b Reused/Recycled UOG Produced Water
All California Basins All formations shale and tight 96 0 4

Anadarko All formations shale and tight 50 (40) 30 (30) 20 (30)

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

-- c 6 to 10

Arkoma Fayetteville shale 70 0 30

Fort Worth Barnett shale 92 (75) 3 (15) 5 (10)

Gulf Coast Eagle Ford shale 80 (50) 20 (40) 0 (10)

Permian (Far West) All formations shale and tight 20 (20) 80 (30) 0 (50)

Permian (Midland) All formations shale and tight 68 (35) 30 (40) 2 (25)

TX

- LA

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

Nationwide All formations shale and tight 40 53 7

Source s : 48 DCN SGE 00693

a— Projected data for the year 2020 are shown parenthetically which were reported as the “most likely” scenario by Nic ot et al. 201 2 ( 126 DCN SGE00639).

b— Fresh water is naturally occurring water on the Earth's surface. Examples include ponds, lakes, rivers and streams, and certain underground aquifers. Fresh water is generally characterized by having low concentrations of dissolved salts. Brackish water is water that has more salinity than fresh water, but not as much as seawater. Example sources include certain underground aquifers , effluent from publicly owned treatment plants (POTWs), and wastewater from other industries.

c— In addition to the 77 to 83 percent fresh water reported for the Marcellus shale in WV

, 6 to 17 percent of base fluid was reported as “ purchased water ” and 1 t o 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 ( 84 DCN SGE00532) reported this data as “surface water”.

“— ” indicates no data.



### 1.2 Additives

In addition to base fluid, operators add proppant and chemicals to adjust the fracturing fluid propertie s. 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 fracturingChapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 41 fluid by ma ss ( 78 DCN SGE 00010 ). The additives and the quantity of additives used in fracturing fluid depend on the formation geo logy , base fluid char acteristics, and UOG operator ( 201 DCN SGE 00721; 3 DCN SGE 00070; 70 DCN SGE 00780; 73 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, surfactants, and propping agents. Operators generally use slickwater designs to fracture dry natural gas producing formations ( 148 DCN SGE 00710; 40 DCN SGE 00705).

• Gel fracturing 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 ( 148 DCN SGE 00710; 40 DCN SGE 00705). Operators generally use gel frac turing fluids to fracture liquid

- rich formations ( 40 DCN SGE 00705).

In 2015, the EPA’s Office of Research and Development (ORD) released a report summarizing additives used by operators based on public disclosures to FracFo cus 49 

### ( 201 DCN SGE 00721). In addition, several sources have published information regarding fracturing fluid additives and their uses in hydraulic fracturing ( 3 DCN SGE00070; 70 DCN SGE00780; 73 DCN SGE00781; 18 DCN SGE00966 ). Table C-2 shows specific additives used by operators

ca tegorized by purpose

. Many additives can have multiple purposes depending on the exact design of the fractur ing fluid. Table C-3 shows concentrations of the most common chemicals identified by operators in the FracFocus public disclosures, summarized in the EPA report, for hydraulically fractured gas and oil wells

.

Table C

- 2

. Fracturing Fluid Additives, Main Compounds, and Common Uses

Additive

Type a Common Compound(s) b Purpose

Acid Hydrochloric acid; Muriatic acid Removes cement and drilling mud from casing perforations prior to fracturing fluid injection

.

Biocide Glutaraldehyde; 2,2

- dibromo -3- nitrilopropionamide Inhibits growth of organisms that could produce gases (particularly hydrogen sulfide) that could contaminate methane gas; prevents the growth of bacteria that can reduce the ability of the fluid to carry proppant into the fractures by breaking down the gel ling agent.

Breaker Peroxydisulfates; salts Reduces the viscosity of the fluid by “ breaking down ” the gelling agents in order to release proppant into fractures and enhance the recovery of the fracturing fluid.

49 Operators submit reports for individual wells to FracFocus. These reports include date of completion, well type (oil, gas)

, total fracturing fluid volume, well API number, well depth, location coordinates, and the concentrations of additives. These reports mostly represent wells completed in UOG formations but may also include some in conventional and coalbed methane formation s.Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 42 Table C

- 2

. Fracturing Fluid Additives, Main Compounds, and Common Uses

Additive

Type a Common Compound(s) b Purpose

Clay stabilizer Potassium chloride Creates a brine carrier fluid that prohibits fluid interaction (e.g., swelling) with formation clays; interaction between fracturing fluid and formation clays could block pore spaces and reduce permeability.

Corrosion inhibitor Ammonium bisulfite; methano l Reduces rust formation on steel tubing, well casings, tools, and tanks (used only in fracturing fluids that contain acid).

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

Friction reducer Petroleum distillates Minimizes friction

, allowing fracturing fluids to be injected at optimum rates and pressures.

Gel Guar gum; hydroxyethyl cellulose Increases fracturing fluid viscosity, allowing the fluid to carry more proppant into the fractures.

Iron control Citric acid Sequestering agent that prevents precipitation of metal oxides, which could plug the formation.
pH adjusting agent Acetic acid; potassium or sodium carbonate Adjusts and controls the pH of the fluid in order to maximize the effectiveness of other additives such as crosslinkers

.

Proppant Quartz; sand ; silica Used to hold open the hydraulic fractures

, allowing the gas or oil to flow to the production well.

Scale inhibitor Ethylene glycol Prevents the precipitation of carbonate and sulfate scales (e.g., calcium carbonate, calcium sulfate, barium sulfate) in pipes and in the formation.

Surfactant Isopropanol;

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

Source s : 201 DCN SGE 00721 ; 3 DCN SGE 00070; 70 DCN SGE 00780 ; 73 DCN SGE 00781 ; 18 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 company preference, base fluid quality

, and site

- specific characteristics of the target formation.Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 43 Table C

- 3

. Most Frequently Reported Additive Ingredient s Used in Fracturing Fluid in Gas and Oil Wells from FracFocus (2011

- 2013)

Specific Constituents CAS Number Maximum Concentration in Hydraulic Fracturing Fluid (% by mass)

Gas a Oil b

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

H ydrochloric acid 7647

- 01

- 0 12,351 0.078 0.0063

– 0.67 10,029 0.29 0.013

– 1.8 Guar gum 9000

- 30

- 0 3,586 0.10 0.00057

– 0.38 9,110 0.17 0.027

– 0.43

Phenolic resin 9003

- 35

- 4

— — — 3,109 0.13 0.019

– 2.0 Distillates, petroleum, hydrotreated light 64742

- 47

- 8 11,897 0.017 0.0021

– 0.27 10,566 0.087 0.00073

– 0.39 Ethylene glycol 107

- 21

- 1 5,493 0.0061 0.000080

– 0.24 10,307 0.023 0.00086

– 0.098 Potassium hydroxide 1310

- 58

- 3

— — — 7,206 0.013 0.000010

– 0.052

Methanol 67

- 56

- 1 12,269 0.0020 0.000040

– 0.053 12,484 0.022 0.00064

– 0.16

Ethanol 64

- 17

- 5 6,325 0.0023 0.00012

– 0.090 3,536 0.026 0.000020

– 0.16

Saline 7647

- 14

- 5 3,608 0.0091 0

– 0.12 3,692 0.0071 0

– 0.27 Sodium hydroxide 1310

- 73

- 2 4,656 0.0036 0.000020

– 0.088 8,609 0.010 0.00005

– 0.075 Glutaraldehyde 111

- 30

- 8 5,635 0.0084 0.00091

– 0.023 5,927 0.0065 0.00027

– 0.020 Peroxydisulfuric acid, diammonium salt 7727

- 54

- 0 4,618 0.0045 0.000050

– 0.045 10,350 0.0076 0.00028

– 0.067 Solvent naphtha, petroleum, heavy arom. 64742

- 94

- 5 3,287 0.0044 0.000030

– 0.030 3,821 0.0060 0

– 0.038

2

- Butoxyethanol 111

- 76

- 2 3,325 0.0035 0.000010

– 0.041 4,022 0.0053 0

– 0.17 Isopropanol 67

- 63

- 0 8,008 0.0016 0.000010

– 0.051 8,031 0.0063 0.00007

– 0.22

Acetic acid 64

- 19

- 7 3,563 0.0025 0

– 0.028 4,623 0.0047 0

– 0.047

Citric acid 77

- 92

- 9 4,832 0.0017 0.000050

– 0.011 3,310 0.0047 0.00016

– 0.024 2,2

- Dibromo

- 3

- nitrilopropionamide 10222

- 01

- 2 3,668 0.0018 0.000070

– 0.022

— — — Naphthalene 91

- 20

- 3 3,294 0.0012 0.0000027

– 0.0050

— — — Propargyl alcohol 107

- 19

- 7 5,811 0.000070 0.000010

– 0.0016 5,599 0.00022 0.000030

– 0.0030

Source: 48 DCN SGE 00693

a— Represents 17,035 FracFocus disclosures for gas wells. b— Represents 17,640 FracFocus dis closures for oil wells.

“— ” indicates this additive was not commonly reported

.Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 44 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, sli ckwater) ( 209 DCN SGE01095 ). Operators fracture UOG wells using 50,000 to over 10 million gallons (1,200 to over 238,000 barrels ) of fracturing fluid per well along with up to millions of pounds of sand (i.e., proppant) . Operators typically fracture horizontal wells in eight to 23 stages

, using between 250,000 and 420,000 gallons ( 6,000 and 10,000 barrels ) of fracturing fluid per stage ( 190 DCN SGE 00280). Literature reports that tight oil and gas wells typically require less fracturing fluid than shale oil and gas wel ls ( 86 DCN SGE 00 533). Typical volumes of fracturing fluid vary by UOG formation, well trajectory

, number of stages, and resource type and are provided in Section C. 2

. The concentrations of TDS in fracturing fluid are often low (< 20 ,000 mg/L) compared to levels found in UOG produced water , which suggests that the majority of the TD S in UOG produced water is contributed by the formation (see Section C. 3 ) ( 16 DCN SGE 00110, 85 DCN 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 concentration s of BOD 5 

### in fracturing fluid of about 1,700 50 

### mg/L but BOD 5 

### in the corresponding f lowback and long

- term produced water of 300 51 

### mg/L or less on average ( 85 DCN SGE 00414 ). As indicated in Table C-2 and Table C-3 , organic materials (which contribute to BOD 5 

### and TOC) are typical chemical additives in fracturing fluid ( 85 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 the well: drilling wastewater, flowback, and long

- term produced water (these 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 since flowback commenced

• R esource type (e.g., shale oil, tight gas)

• Specific geology properties ( e.g., presence of naturally occurring water)

• Well trajectory (i.e., horizontal, directional, vertical)

The following two subsections quantify wastewater volumes generated during the UOG well development process. Section C. 2.1 summarizes general trends in UOG extraction wastewater volumes for each part of the well development process by resource type and well

50 This study reported 1,700 mg/L as the median concentration based on 19 samples. The overall range of BOD was 4.3 to 47,400 mg/L.

51 This study reported 330 mg/L as the median concentration based on 19 flowback samples. The overall range of BOD was 30 to 1,440 mg/L.Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 45 trajectory

. Section C. 2.2 provides detailed produced water volumes by UOG formation and well trajectory

. 52



### 2.1 UOG Extraction Wastewater Volumes by Resource and Well Trajectory

This section quantifies the volumes o f UOG extraction wastewater generated

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

• Drilling wastewater

• Flowback

• Long-term produced water

Flowback and long

- term produced water are the largest volumes of UOG extraction
wastewater. Figure C-1 shows a breakdown of UOG extraction wastewater volumes generated from Marcellus shale wells in Pennsylvania based on data from PA DEP’s state wide waste production reports for all wells active between 2004 and 2013 ( 46 DCN SGE 00739 ). 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, long

- term produced water) generated by a well over its lifetime is approximately 50 percent flowback and 50 percent long

- term produced water

— despite the fact that flowback is generated over less than 30 days and long- term produced water is generated over the well life , which may be more than 10 years ( 94 DCN SGE 00728). 53

52 Section C. 2.2 does not include drilling wastewater volumes by formation and drill type because EPA identified less detailed data fo r drilling wastewater volumes compared to UOG produced water volumes.

53 Figure C-1 shows that long

- term produced water is more than 50 percent of tota l UOG p roduced water for Marcellus shale wells likely because Marcellus wells generate relatively lower flowback volumes compared to other UOG formations (see Table C-8 ).Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 46 Source s : 46 DCN SGE 00739



### Figure C-1 . UOG Extraction Wastewater Volumes for Marcellus Shale Wells in Pennsylvania (2004–2013)

Figure C-2 shows the quantities of produced water (i.e., flowback , long- term produced
water ) generated from UOG wells from the time of well completion t o the end of the well life. The produced water generation rates reflect aggregated data from multiple UOG formations ; 54


### “n” is the number of data points for each time period. 55 

### As shown in the figure

, UOG produced water generation rates are highest immediately after well completion

, when there is little or no oil and gas production (flowback). During the transition from the flowback process to production (within weeks of well completion), produced water generation rates decrease significantly and

eve ntually level out

. During production, produced water generation rates gradually decrease over the life of the well (long- term produced water).

54 As explained in Chapter B , the length of the flowback process is variable. Literature generally reports it as 30 days or less ( 83 DCN SGE00 532). Other operators report it as only lasting five days ( 151 DCN SGE00 350)

. 55 Data for the first 90 days represent the Marcellus, Barnett, Woodford, Codell

- Niobrara, Bakken, and Fayetteville UOG formations. Data beyond 90 days (long

- term produced water) are from Table C-8

.Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 47 Source: 56 DCN SGE0072 4



### Figure C-2. Ranges of Typical 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 wastewater than a horizontal well drilled into the same formation, because the latter requir es additional drilling fluid to complete the horizontal lateral ( 46 DCN SGE 00739). Table C-4 illustrates this trend for UOG wells drilled into the Marcellus formation in Pennsylvania.

Table C

- 4 . Median Drilling Wastewater Volumes for UOG Horizontal and Vertical Wells in Pennsylvania

Well Trajectory Median Drilling Fluid Volume per Well ( g allons) Range of Drilling Fluid Volume per Well (gallons) a Typical Total Measured Depth b Number of Data Points

Horizontal 46,000 3,200

– 210,000 10,000

– 11,000 3,055

Vertical 37,000 5,000

– 210,000 6,000

– 7,000 209

Source: 46 DCN SGE00739

a— These ranges are based on the 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 horizontal).Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



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

. Table C-5 shows typical volumes generated by UOG wells by resource type and formation

. Operators report that nearly all of the drilling fluid used per well is recovered as wastewater at the end of drilling. 56 

### Therefore, where it had information on drilling fluid volumes but not the resulting drilling wastewater volume, the EPA assumed the former is representative of the latter

.

Table C

- 5

. Drilling Wastewater Volumes Generated per Well by UOG Formation

Resource

Type Formation Range (gallons) Median (gallons) Typical Total Measured Depth a (feet) Number of Data Points

Shale Haynesville 4 20 ,000

– 1,100 ,000 600,000 1 3 ,000

– 1 9 ,000 5 Tight Anadarko Basin b 222,000

– 420 ,000 310,000

-- c 2

Shale Niobrara

— c 300,000 7

, 5 00

– 1 3 ,000 1

Shale Barnett 170 ,000

– 500 ,000 250,000 8

, 5 00

– 1 4 ,000 6

Shale Permian Basin b 95

, 200

– 420

, 000 210,000

-- c 8 Tight Granite Wash

— c 200,000

-- c 1 Tight Cleveland

— c 200,000

-- c 1

Shale Eagle Ford 1 30 ,000

– 420,000 160,000 6 ,000

– 1 6 ,000 7

Shale Utica

— c 100,000 6 ,000

– 1 9 ,000 1 Tight Mississippi Lime

— c 100,000

-- c 1

Shale Marcellus 2,400

– 170,000 92,000 7

, 300

– 13 ,000 2,072

Source: 55 DCN SGE 00740

a— Total measured depth is the true length of wellbore drilled (i.e., sum of the vertical and horizontal). b— Specific formation was not reported.

c— The EPA identified only one data point for these formations. Therefore, there is no range to display.



### 2.1.2 Produced Water: Flowback As described above, for purposes of this document , produced water includes flowback in addition to long

- term produced water. Table C-6 quantifies the portion of fracturing fluid returned as flowback

. 57 

### Because the volume of fracturing fluid used during well stimulation affects flowback quantities, fracturing fluid volumes are also listed. Given data in the table

, 58



### t otal flowback volumes typically range between 2 6 ,000 to 300 ,000 gallons (620 to 7,0 00 barrels ) per well. On average, horizontal shale wells generate the highest volumes of flowback. In terms of wastewater manageme nt, operators must consider that the flowback process generates large volumes of wastewater in a short period of time ( e.g., 30 days) compared to long- term produced water that is generated in small volumes over a long period of time.

56 Some drilling fluid volume may be lost downhole and/or to moisture in the cuttings, but these losses account for a relatively small percentage of the total volume ( 191 DCN SGE00 625).

57 The EPA explains how it differentiated between flowback and long

- term produced water volumes in literature in it s memorandum Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation ( 56 DCN SGE00724 ).

58 Approximate flowback volumes can be estimated by multiplying total fracturing volume by the percent of fractur ing fluid returned during flowback. However, EPA does not show this calculation in Table C-6 because not all data sources report both fracturing fluid volume and percent of fracturing fluid recovered as flowback.Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 49 Table C-6. UOG Well Flowback Recovery 59 

### by Resource Type and Well Trajectory

Resource

Type Trajectory Fracturing Fluid ( MG ) a Flowback (Percent of Fracturing Fluid Returned) a

Median Range Number of Data Points Median Range Number of Data Points

Shale H 4 .0 0.13

– 15 50,053 6 1

– 50 6,488

D 1. 6 0.0 51

– 12 124 14 4

– 3 1 19

V 1.2 0. 01 5

– 22 4,152 2 4 7

– 75 18

Tight H 2.2 0.042

– 9.4 765 7 7

– 60 39

D 0.6 0 0.0 56

– 4 .0 693 6 0

– 60 263

V 0.3 1 0.0 19

– 4 .0 1,2 87 8 1

– 83 48

Source: 56 DCN SGE00724 ( Data are based on aggregated data from Table C-8 

### , which contains volumes by formation )

a— Most of the underlying fracturing fluid volume data and percent ages of fracturing fluid returned as flowback were reported in different sources

. To avo id representing the data incorrectly, t he EPA did not calculate total flowback volume for Table C-6

. Abbreviations: MG

— million gallons; H—h orizontal well ; D

— directional well; v—v ertical well



### 2.1.3 Produced Water: Long

- Term Produced Water
Long- term produced water rates remain relatively constant 60 

### over the well life compared to flowback rates ( 178 DCN SGE 00635). Table C-7 quantifies long- term produced water rates in gallons per day by UOG resource and well trajectory . Median long

- term produced water rates range from about 380 to 900 gallons (9 to 21 barrels) p er day. A comparison of median long- term produced water rates for shale formation wells, as listed in the table, shows that horizontal shale wells have higher median generation rates than directional and vertical shale wells. On the other hand, median long

- term produced water rates for tight formation wells in Table C-7 show that vertical tight wells have higher generation rates than direct ional and horizontal tight wells, but horizontal wells have the highest maximum generation rate

.

59 Flowback recovery is the percent of total fracturing fluid injected during hydraulic fracturing that returns to the wellhead during the flowback process.

60 Note that long

- term produced water rates typically gradually decrease over the well life. However, the change is small relative to flowback.Chapter C —U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 50 Table C

- 7

. Long

- Term Produced Water Generation Rates by Resource Type and Well Trajectory

Resource

Type Traject ory Long

- Term Produced Water Generation Rates (gpd per well) a

Median Range Number of Data Points

Shale H 900 0

– 1 9 ,000 22,222

D 480 22

– 8,7 00 695

V 3 80 0

– 4,600 12, 393

Tight H 620 0

– 120,000 2,394

D 750 12

– 1,8 00 3,816

V 570 0

– 4 ,000 21,393

Source s: 56 DCN SGE 00724

a—B ased on aggregated data from Table C-8 

### , which contains volumes by formation

. 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-8 shows the underlying UOG produced water volumes by formation and well trajectory used to generate the summary statistics in Section C. 2.1

. The data in Table C-8 are specific to UOG formations and are sorted alphabetically by basin a nd then from highest median fracturing fluid volume to lowest within each formation . Because the EPA identified less detailed data by formation for drilling wastewater, Table C-8 does not include drilling wastewater volumes.

Data in Table C-8 illustrate that volumes of flowback and flow rates of long- term produced water vary by formation

. For example, UOG horizontal wells drilled into the Barnett shale formation in the Fort Worth basin generate 920 gallons ( 22 barrels) per day of long

- term produced water compared to 110 gallons ( 3 barrels) per day for horizontal wel ls drilled into the Eagle Ford shale formation in the Western Gulf basi n ( 206 DCN SGE 00623). In some cases, produced water even varies geographically within the same formation , which is not evident in Table C-8

. For example, operators report that wells drilled in the northeast portion of the Marcellus shale formation (in Pennsylvania) generate less produced water than wells drilled in the southwest portion of the Marcellus shale for mation (in West Virginia ) ( 178 DCN SGE 00635 ).Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 51 Ta ble C

- 8

. Produced Water Volume Generation by UOG Formation

Basin UOG Formation Resource Type Drill Type Fracturing Fluid ( M G ) Flowback (% of Fracturing Fluid Returned) Long

- Term Produced Water Rates ( g pd)

Median Range b Number of Data Points a Median Range b Number of Data Points a Median Range b Number of Data Points a

Anadarko Granite Wash tight H 6.2 0.20

– 9.4 77

— 7

– 22 2 1,300 0

– 2,200 273

V 0.56 0.050

– 3.0 26 — — 2 500 170

– 1,300 2,413

Woodford shale H 4.7 1.0

– 12 2,239 34 20

– 50 3 5,500 3,200

– 6,400 198

Mississippi Lime tight H 1.8 0.82

– 2.4 428 — 50 1 — 37,000

– 120,000 4

Cleveland tight H 0.81 0.20

– 4.0 144

— 12

– 40 2 82 20

– 300 571

V 0.69 0.11

– 3.0 4

— — 2 32 6.6

– 170 390

Appalachian Marcellus shale H 4.4 0.90

– 11 14,010 7 4

– 47 4,374 860 54

– 13,000 4,984

V 2.6 0.53

– 6.6 66 40 21

– 60 7 230 100

– 1,200 714

Utica shale H 4.0 1.0

– 11 150 4 2

– 27 73 510 210

– 1,200 82

Arkoma Fayetteville shale H 5.1 1.7

– 11 1,668

— 10

– 20 2 430 150

– 2,300 2,305

Denver J. Niobrara shale H 2.6 0.73

– 3.4 69 13 6

– 25 16 680 260

– 810 250

V 0.32 0.27

– 3.3 367 11 7

– 35 9 340 240

– 600 5,474

Codell

- Niobrara tight H 2.6 0.15

– 2.7 62 7

— 32 34 19

– 140 32

D 0.45 0.21

– 0.47 116 — — 0 — — 0

V 0.30 0.13

– 0.46 592 — — 0 29 13

– 65 1,677

Muddy J tight D 0.59 0.25

– 0.62 162 — — 0 230 64

– 390 3

V 0.28 0.16

– 0.62 292 — — 0 55 9.3

– 500 129

Codell tight D 0.28 0.21

– 0.46 78 — — 0 — — 0

V 0.27 0.13

– 0.46 185 — — 0 — — 0Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 52 Ta ble C

- 8

. Produced Water Volume Generation by UOG Formation

Basin UOG Formation Resource Type Drill Type Fracturing Fluid ( M G ) Flowback (% of Fracturing Fluid Returned) Long

- Term Produced Water Rates ( g pd)

Median Range b Number of Data Points a Median Range b Number of Data Points a Median Range b Number of Data Points a

Fort Worth Barnett shale H 3.6 1.0

– 7.3 23,917 30 21

– 40 11 920 160

– 4,200 10,349

V 1.3 0.4

– 1.9 3,589

— — 0 250 170

– 580 3,318

Green River Hilliard

- Baxter

Mancos shale H 1.7 1.0

– 5.6 2 — — 0 37 15

– 58 7

Lance tight V 1.3 0.81

– 3.5 29 3 1

– 50 31 410 250

– 580 1,050

D 1.2 0.76

– 1.9 180 6 1

– 17 170 860 360

– 1,200 1,140

Mesaverde (Green River) tight D 0.23 0.16

– 0.31 73 8 0– 37 61 190 150

– 440 445

V 0.17 0.081

– 0.29 14 21 6– 83 11 290 140

– 610 1,081

Illinois New Albany shale H

— — 0

— — 0

— 2,900 2 Michigan Antrim shale V

— 0.05 0 1

— 25

– 75 2

— 4,600 1

Permian Avalon & Bone Spring shale D 2.2 0.94

– 4.5 20 13 5

– 31 16 950 220

– 2,400 183

shale H 1.1 0.73

– 2.8 17

— — 0 0 0

– 2,300 37

Barnett

Woodford shale H 2.1 0.5

– 4.5 2 — — 0 — — 0

Wolfcamp shale H 1.4 1.1

– 3.9 55 — — 0 3,000 210

– 19,000 104

D 1.3 0.26

– 1.7 12 16 15

– 20 3 310 22

– 8,700 259

V 0.81 0.078

– 1.7 60 — — 0 910 130

– 1,700 926

Spraberry tight V

— 1.0 1

— — 0 870 100

– 4,000 66

Devonian (TX) shale H 0.32 0.13

– 0.89 10 — — 0 880 310

– 1,800 381

V 0.27 0.12

– 1.0 16

— — 0 400 150

– 3,000 162

San Juan Mesaverde (San Juan) tight D — — 0 — — 0 18 12

– 260 48Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 53 Ta ble C

- 8

. Produced Water Volume Generation by UOG Formation

Basin UOG Formation Resource Type Drill Type Fracturing Fluid ( M G ) Flowback (% of Fracturing Fluid Returned) Long

- Term Produced Water Rates ( g pd)

Median Range b Number of Data Points a Median Range b Number of Data Points a Median Range b Number of Data Points a

Dakota tight V 0.2 0.063

– 0.22 19 — — 0 65 29

– 120 6

D 0.12 0.070

– 0.30 52 4 1– 40 30 160 41

– 370 379

TX

- LA

- MS Haynesville shale H 5.3 0.95

– 15 3,222 5 5

– 30 3 1,700 84

– 1,800 1,249

V 0.61 0.14

– 3.5 9

— — 0 210 56

– 850 263

Cotton Valley tight H 4.2 0.25

– 6.0 30

— <60 2 770 130

– 2,700 335

D 0.48 0.084

– 4.0 24 — <60 2 950 630

– 1,800 1,801

V 0.28 0.019

– 0.94 76 — <60 2 640 370

– 1,800 10,717

Travis Peak tight H 3.0 0.25

– 6.0 2

— — 0 200 39

– 1,700 5

V 0.90 0.20

– 4.0 2

— — 0 980 330

– 1,800 1,380

Bossier shale H 2.7 1.7

– 3.6 2

— — 0 750 610

– 1,200 25

V 0.40 0.19

– 1.7 16

— — 0 470 180

– 1,100 1,203

D 0.28 0.13

– 0.80 21 — — 0 320 130

– 1,300 253

Western

Gulf Austin Chalk tight H 0.94 0.58

– 1.3 15

— — 0 720 290

– 2,400 1,097

Eagle Ford shale H 5.0 1.0

– 14 2,485 4 2

– 8 1,800 110 9.1

– 250 498

V 2.9 2.0

– 4.1 9

— — 0

— — 0

Pearsall shale H 3.7 3.3

– 4.1 2

— — 0 200 54

– 370 12

Wilcox Lobo tight H 2.1 0.66

– 2.6 4

— — 0 330 62

– 740 77

V 0.21 0.06

– 0.60 14 — — 0 620 330

– 1,400 1,514

D 0.058 0.056

– 0.076 3 — — 0 — — 0Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 54 Ta ble C

- 8

. Produced Water Volume Generation by UOG Formation

Basin UOG Formation Resource Type Drill Type Fracturing Fluid ( M G ) Flowback (% of Fracturing Fluid Returned) Long

- Term Produced Water Rates ( g pd)

Median Range b Number of Data Points a Median Range b Number of Data Points a Median Range b Number of Data Points a

Vicksburg tight V 0.16 0.084

– 0.60 20 — — 0 1,000 650

– 1,900 937

D 0.11 0.10

– 0.13 4 — — 0 — — 0

Olmos tight V

— 0.15 2

— — 0

— — 0

Williston Bakken shale H 2.0 0.35

– 10 2,203 19 5

– 47 206 680 380

– 1,500 1,739

V 1.1 0.35

– 2.9 12

— — 0 1,000 340

– 3,100 222

Source s: 56 DCN SGE 00724

a— For some formations, the number of data points was not reported in the data source. In these instances, this table reports th at number as 1, except if the source reported a range in which case this table reports the number of data points as 2

. b— For some formations, if only one data point was reported, the EPA reported it in the range column and did not report a median value

. “— ” indicates no data.

Abbreviations: MG

— million gallons; H— horizontal well ; D— directional well ; V— vertical wellChapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 55 3 UOG E XTRACTION 

### W ASTEWATER 

### C HARACTERIZATION



### As discussed in Chapter B , UOG operations generate wastewater that includes drilling wastewater, flowback, and long

- term produced water

. Drilling wastewater is generated during the initial drilling of the well and typically maintains the characteristics of the drilling fluid , but also contains additional solids (i.e., drill cuttings) that are generated during the well drilling
process

. Flowback may contain the specific fracturing fluid composition (e.g., chem ical additives, base fluid) used by each UOG operator as well as chemical constituents present in the UOG formation ( 80 DCN SGE 00286; 16 DCN SGE 00110). Long

- term produced water typically mimics the characteristics of the UOG formation, which often contributes, in part, to high concentrations of select naturally occurring ions ( 124 DCN SGE 00090). The volumes and characteristics of UOG extraction wastewater may vary significantly between basins

, between formations, and sometimes between wells within the same formation (s ee Section C. 2 for a discussion of UOG extraction wastewater volumes) ( 153 DCN SGE 00592 ). The following subsections describe the characteristics of UOG extraction wastewater.

3.1 Availability of Data for UOG Extraction Wastewater Characteriza tion

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 s ummarized UOG extraction wastewater characterization data in the following subsection s , which are organized into five constituent categories: classical and conventional, organic, metal, radioactive

, and other

. Table C-9 s hows relative quantities of data found for each constituent category. The number of stars indicates the amount of data available, where one star indicates less data and five
stars indicates more data.

Table C

- 9

. Availability of Data for UOG Extraction Wastewater Characterization

Constituent

Category Examples of Constituents Included Within Category Amount of Available Produced Water Data Amount of Available Drilling Wastewater Data
Classical and

c onventional a TDS, TSS, COD, BOD 5 , pH, conductivity, chloride, sodium, calcium ★★★★★ ★★

Organic E thylbenzene, toluene ★★★ ★
Metal B arium, strontium, magnesium, potassium, iron, copper, zinc ★★★★★ ★★
Radioactive R adium

- 226, radium

- 228, gross alpha, gross beta ★★ ★

Other G uar gum, microorganisms ★ ★

a

— The classical and conventional constituent category also includes a discussion of the anions and cations that contribute to TDS. These anions and cations are italicized in the examples column

.


### For all of the constituent categories, data on concentrations are less available for 1) produced water specifically generated from tight oil and gas wells and 2) drilling wastewater generated at all UOG wells. The EPA presents available data in the following subsections.Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 56 3.2 UOG Extraction Wastewater C onstituent Categories

The data in the following subsections are representative of UOG extraction wastewater characteristics as presented in the literature for the entire UOG industry

. 61 

### The data show combined characterization data for shale and tight reservoirs as well as for oil and gas resources. Regarding UOG produced water

, the EPA sometimes presents the data as flowback and long

term produced water individually . In other instances, the data are presented as UOG produced
water , which includes both flowback and long- term produced water.

3.2.1 Classical and Conventional Constituents in UOG Extraction W astew ater

Table C-10 presents typical concentrations of select classical and conventional constituents that are present in UOG drilling wastewater. 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 ( 37 DCN SGE 00245) ( see Section B. 2.1 ) . The EPA identified the following limitations to the data presen ted in Table C-10 :

• Fewer data points (i.e., less than 30 data points) were available for each parameter

.

• All of the data came from the Marcellus shale formation.

Table C-11 presents typical concentrations of select classical and conventional constituents that are present in UOG produced water . The EPA identified the following limitations to the data presented in Table C-11 :

• Fewer data points (i.e., less than 30 data points) were available for ammoni a and phosphate.

• The majority of data associated with alkalinity, BOD 5 

### , chemical oxygen demand ( COD ) , specific conductivity, TOC, and TSS came from the Marcellus shale formation.

• The majority of data associated with chloride and TDS came from the Eagle Fo rd shale formation.

• The majority of data associated with pH came from the Woodford- Cana

- Caney shale formation.

61 Note that t he lack of data for select constituents may not necessarily imply that those constituents are not present in the wastewater , but rather that they were not measured and/or reported in the existing liter ature . Refer to 56 DCN SGE00724 for additional details on the parameters reported in the literature reviewed. The accompanying database includes non detect, below detection, or zero values that w ere reported in the literature reviewed

.Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 57 Table C

- 10

. Concentrations of Select Classical and Conventional Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells 62

Parameter Units Range Median Number of Data Points Number of Detects Formation Represented Alkalinity mg/L 110

– 42,000 1,600 11 11 Marcellus
Ammonia mg/L 0.98

– 35 7 8 8 Marcellus

BOD 5 mg/L 80

– 1,100 390 8 8 Marcellus
Chloride mg/L 160

– 23,000 12,000 12 12 Marcellus

COD mg/L 150

– 9,300 1,800 8 8 Marcellus
Hardness as CaCO 3 mg/L 1, 4 00

– 46,000 4, 4 00 12 12 Marcellus
Oil and g rease mg/L ND a

– 150 2.5 8 8 Marcellus pH SU 6.8

– 12 9.0 12 12 Marcellus Phosphate mg/L

— b 16 4 4 Marcellus Specific

c onduct ivity μS/cm 1,100

– 60,000 19 ,000 10 10 Marcellus

TDS mg/L 560

– 80,000 31 ,000 14 14 Marcellus

TSS mg/L 120

– 600,000 2 8 ,000 1 6 1 6 Marcellus

Source: 55 DCN SGE00740

a— Source did not report detection limit. b— Source only reported median value.

Abbreviations: m g /L

— milligrams per liter; ND

— non detect; SU

— sta ndard units; μS/cm

— microsiemens per

c entimeter

62 Drilling wastewater may contain differing amounts of drill cuttings depending on how the operator chooses to remove drill cuttings from drilling wastewater.Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 58 Table C-11 . Concentrations of Select Classical and Conventional Constituents in UOG Produced Water

Parameter Units Range Median Number of Data Points a Number of Detects Formations Represented a

Alkalinity mg/L 7.5

– 1,600 140 265 265 Barnett (29); Eagle Ford (1); Marcellus (232); Woodford

- Cana

- Caney (3)

Ammonia mg/L 39

– 350 110 13 13 Marcellus (5); Niobrara (5); Woodford

- Cana

Caney (3)

Bicarbonate mg/L 0

– 19,000 290 6,352 6,352 Bakken (398); Barnett (6); Cleveland (11); Cotton Valley/Bossier (3); Dakota (3); Eagle Ford (2,925); Lansing Kansas City (16); Marcellus (154); Mesaverde/Lance (5); Morrow (1); New Albany (1); Oswego (5); Pearsall (3); Spraberry (26); Woodford

- Cana

- Caney (2,795)

BOD 5 mg/L 2– 12,000 160 154 153 Barnett (28); Marcellus (122); Medina/Clinton

Tuscarora (1); Woodford

- Cana

- Caney (3)

Carbonate mg/L 0

– 1 3,000 0 59 59 Bakken (20); Barnett (4); Cotton Valley/Bossier (2); Dakota (3); Eagle Ford (4); Spraberry (26)

Chloride b mg/L 64

– 230,000 73,000 2,190 2,190 Bakken (22); Barnett (144); Cleveland (11); Cotton Valley/Bossier (25); Dakota (3); Eagle Ford (1651); Granite Wash/Atoka (1); Marcellus (287); Mesaverde/Lance (5); New Albany (1); Niobrara (5); Pearsall (3); Spraberry (26); Utica (1); Woodford

- Cana

- Caney (5)

COD mg/L 99

– 37,000 3,200 149 149 Barnett (23); Marcellus (122); Medina/Clinton

Tuscarora (1); Woodford

- Cana

- Caney (3)
Hardness as CaCO 3 mg/L 160

– 110,000 21,000 80 80 Barnett (15); Marcellus (65)

Oil and grease mg/L 0.21

– 1,500 5.6 134 99 Barnett (23); Marcellus (108); Woodford

- Cana

Caney (3)

pH SU 3.9

– 12 6.5 5,233 5,233 Bakken (420); Barnett (30); Cleveland (4); Cotton Valley/Bossier (3); Dakota (3); Eagle Ford (1600); Fayetteville (2); Lansing Kansas City (16); Marcellus (300); Medina/Clinton

- Tuscarora (3); Mesaverde/Lance (5); Morrow (1); Oswego (5); Spraberry (26); Woodford

- Cana

- Caney (2815)
Phosphate mg/L 12

– 88 31 4 4 Barnett (1); Marcellus (1); Woodford

- Cana

- Caney (2)
Specific c onductivity μ S/cm 0.11

– 760,000 120,000 162 162 Bakken (9); Barnett (25); Dakota (3); Marcellus (103); Spraberry (19); Woodford

- Cana

- Caney (3)Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 59 Table C-11 . Concentrations of Select Classical and Conventional Constituents in UOG Produced Water

Parameter Units Range Median Number of Data Points a Number of Detects Formations Represented a

TDS mg/L 320

– 400,000 100,000 2,164 2,164 Bakken (11); Barnett (38); Bradford

- Venango

- Elk (5); Cleveland (11); Cotton Valley/Bossier (3); Dakota (3); Devonian (11); Eagle Ford (1647); Fayetteville (4); Green River (1); Haynesville/Bossier (2); Marcellus (373); Mesaverde/Lance (5); Mississippi Lime (3); New Albany (1); Niobrara (8); Pearsall (3); Spraberry (26); Utica (1); Woodford

- Cana

- Caney (8)

TOC mg/L 1.2

– 5,700 65 129 124 Bakken (2); Barnett (28); Marcellus (96); Woodford

- Cana

- Caney (3)

TSS mg/L 4– 14,000 130 150 150 Bakken (2); Barnett (29); Eagle Ford (1); Marcellus (113); Woodford

- Cana

- Caney (5)

Source: 56 DCN SGE 00724

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 the se instances, there were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified. b— The EPA assumed values reported as “Cl” in the wastewater characterization data were meant to represent “chloride” val ues

. Abbreviations: mg /L

— milligrams per liter; SU

— sta ndard units; μS/cm

— microsiemens per centimeterChapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 60 COD is a measure of the amount of oxygen needed to oxidize organic matter in
wastewater using a strong chemical oxidant ; therefore, it is an indicator of the presence of organic constituents in wastewater . As reported in Table C-11 , the median COD concentration found in UOG produced water is 3, 2 00 mg/L. However, researchers have shown that concentrations of COD may be influenced by chloride, bromide, alk aline 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 ( 227 DCN SGE 00725 ). In Table C-11 , t he relatively low median TOC concentration ( 65 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 literature experienced interference from high concentrations of chloride, bromide, and group II alkaline earth metals. Therefore, reported COD concent rations may be higher than actual COD concentrations in UOG produced water

.

TDS

, which is regularly measured in UOG produced water

, provides a measure of dissolved matter including salts (e.g., sodium, chloride, nitrate), metals, minerals, and organic material ( 1 DCN SGE 00046 ). TDS is not a specific chemical, but is defined as the portion of solids that pass through a filter with a nominal pore size of 2.0 μm or less (Standard Method 2540C- 1997, ASTM D5907

- 03, and USGS I -1750-85 ). Salts are the majority of TDS in UOG produced water

, and sodium chloride often constitutes approximately 50 percent of the TDS in UOG produced water ( 1 DCN SGE 00046). As reported in Table C-11 , the concentration of TDS in UOG produced water is approximately 10 percent by weight.

Calcium and other group II alkaline earth metals (e.g., strontium, barium, magnesium) also contribute t o the TDS in UOG produced water.

Figure C-3 shows the primary anions and cations that contribute to TDS in UOG produced water in various shale and tight oil and gas formations. Data for all of the anions and cations contributing to TDS were not available for all formations. For example, the EPA did not identify any sodium concentration data in the Pearsall formation. Similarly, the EPA did not identify any chloride concentration data in the Spraberry formation. These missing data will account for some of the remaining TDS concentrations that are currently shown as “other dissolved constituents” in Figure C-3

.Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 61 Source: 56 DCN SGE00724



### Figure C-3 . Anions and Cations Contributing to TDS Concentrations in Shale and Tight Oil and Gas Formations 63



### As shown in Figure C-3

, of those chemicals specifically identified as contributing to TDS, sodium, chloride, and calcium ions make up the majority of TDS in UOG produced water

. A dditional ions that may contribute to the TDS in UOG produced water include bromide, fluoride, nitrate, nitrite, phosphate, and sulfate. Figure C-4 shows ranges of concentrations of sodium, chloride, and calcium contributing to TDS in UOG flowback and long

- term produced water. The data used to create this figure include constituent conce ntration data from flowback or long- term produced water generated at a shale or tight oil and gas well. The data show that concentrations of these constituents are typically higher in long

- term produced water than in flowback

.

63 In Figure C-3 , the EPA indicates 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 meant to represent “chloride” values and has reported them as such in Figure C-3

. 0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000Concentration (mg/L) Other Dissolved Constituents

Potassium

Barium

Bromide
Magnesium

Strontium

Calcium

Sodium

Chloride

EPA assumed values reported as “Cl” in the wastewater characterization data were meant to represent “chloride” values and wer e r eported as such in Table C

- 11.Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 62 10 100 1,000 10,000 100,000 1,000,000

TDS

- Flowback TDS

- LTPW Chloride

- Flowback Chloride

- LTPW Sodium

- Flowback Sodium

- LTPW Calcium

- Flowback Calcium LTPWConcentration (mg/L) n=118

n=123 n=91

n=43 n=108 n=575

n=97

n=580

EPA assumed values reported as “Cl” in the wastewater characterization data were meant to represent “chloride” values and were r eported as such in Table C

- 11.

Source: 56 DCN SGE00724



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

- Term Produced Water (LTPW) from Shale and Tight Oil and Gas Formations

Table C-12 presents typical concentrations of additional constituents that may contribute to TDS in drilling wastewater

. The EPA identified the following limitations to the data presented in the table :

• Fewer data points (i.e., less than 30 data points) were available for all parameters.

• All of the data came from the Marcellus shale formation.

Table C-13 presents typical concentrations of additional constituents that may contribute to TDS in UOG produced water . The EPA identified the following limitations to the data
prese nted 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 and sulfide came from the Marcellus shale formation.

• The majority of the data associated with nitrate came from th e Bakken shale formation.Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 63 • The majority of the data associated with bromide and fluoride came from the Marcellus shale formation.

• The majority of the data associated with sulfate came from the Woodford- Cana

Caney shale formation.

Table C

- 12 . Concentrations of Select Anions and Cations Contributing to TDS in UOG Drilling Wastewater from Marcellus Shale Formation Wells

Parameter Units Range Median Number of Data Points Number of Detects Formation Represented

B romide mg/L 23

– 210 110 5 5 Marcellus
Sulfate mg/L ND

– 1,600 220 13 10 Marcellus

Source : 55 DCN SGE 00740 Abbreviation: mg/L

— milligrams per literChapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 64 Table C

- 13

. Concentrations of Select Anions and Cations Contributing to TDS in UOG Produced Water

Parameter Units Range Median Number of Data Points Number of Detects Formations Represented (Number of Associated Data Points) a

Bromide mg/L 0.2 0

– 3,100 510 111 111 Barnett (23); Marcellus (85); Woodford

- Cana

- Caney (3)
Fluoride mg/L 0.045

– 390 2.5 99 97 Barnett (23); Marcellus (73); Woodford

- Cana

- Caney (3)
Nitrate mg/L 0.3 0

– 920 0.3 0 110 110 Bakken (107); Marcellus (3)
Nitrite mg/L 5 .0

– 5 .0 b 5 .0 2 2 Marcellus (2) Phosphate mg/L 12

- 88 31 4 4 Barnett (1); Marcellus (1); Woodford

- Cana

- Caney (2)

Sulfate mg/L 0– 7,200 270 4,711 4,687 Bakken (424); Barnett (31); Cleveland (9); Cotton Valley/Bossier (1); Dakota (3); Devonian (4); Eagle Ford (1,166); Fayetteville (2); Lansing Kansas City (15); Marcellus (301); Medina/Clinton

- Tuscarora (2); Mesaverde/Lance (4); Morrow (1); New Albany (1); Niobrara (5); Oswego (4); Pearsall (3); Spraberry (26); Woodford

- Cana

- Caney (2,709 )

Sulfide mg/L 0.8 0

– 30 3 .0 76 6 9 Marcellus (76)

Source: 56 DCN SGE 00724

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 the se 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.

A

bbreviation: mg/L

— milligrams per literChapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 65 3.2.2 Organic Constituents in UOG Extraction W astewater

Table C-14 presents concentration data from existing literature on organic constituents in UOG drilling wastewater

. The EPA identified the following limitations to the data presented in the table :

• Fewer data points (i.e., less than 30) were available for each parameter.

• All of the data came from the Marcellus shale formation.

Table C-15 presents concentration data from existing literature on organic constituents in UOG produced water. The EPA identified the following limitations to the data presented in the table :

• All of the available data for carbon disulfide, ethanol, methanol, methyl chloride, and tetrachloroethylene came from the Marcellus shale formation.

• The majority of the data associated with each of the organic constituents presented in the table came from the Marcellus shale formation.

Table C

- 14

. Concentrations of Select Organic Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells

Parameter Units Range Median Number of Data Points Number of Detects Formation Represented

Benzene μg/L 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: 55 DCN SGE00740

a— Source did not report detection limit. b— Source only reported median value.

Abbreviations: ND

— non detect; mg/L

— milligrams per liter; μg/L

— micrograms per literChapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 66 Table C

- 15

. Concentrations of Select Organic Constituents in UOG Produced Water

Parameter Units Range Median Number of Data Points Number of Detects Formations Represented (Number of Associated Data Points) a 1,2,4

- t rimethylbenzene μg/L 0.54

– 4,000 5 .0 92 89 Barnett (25); Marcellus (67) 1,3,5

- t rimethylbenzene μg/L 0.64

– 1,900 5.0 85 81 Barnett (18); Marcellus (67)

Acetone μg/L 5.9

– 160,000 40 96 8 6 Barnett (22); Marcellus (74)

Benzene μg/L 0.99

– 800,000 8.5 144 12 2 Barnett (25); Marcellus (111); Niobrara (5); Woodford

- Cana

Caney (3)
Carbon d isulfide μg/L 5 .0

– 7,300 5.0 68 6 7 Marcellus (68)
Chlorobenzene μg/L 0

– 500 5.0 72 7 0 Marcellus (69); Woodford

- Cana

- Caney (3)
Chloroform μg/L 0

– 500 5.0 77 7 5 Barnett (5); Marcellus (69); Woodford

- Cana

- Caney (3)
Ethanol μg/L 1,000

– 230,000 10,000 53 53 Marcellus (53)

Ethylbenzene μg/L 0.63

– 8,900 5.0 130 104 Barnett (18); Marcellus (108); Medina/Clinton

- Tuscarora (1); Woodford

- Cana

- Caney (3) Isopropylbenzene μg/L 0.53

– 500 5.0 83 69 Barnett (16); Marcellus (67)
Methanol μg/L 3,200

– 4,500,000 10,000 55 55 Marcellus (55) Methyl c hloride μg/L 2 .0

– 500 5.0 95 69 Marcellus (95) Naphthalene μg/L 0.5 0

– 1,400 5.0 129 103 Barnett (39); Marcellus (90)
Phenol μg/L 0.7 0

– 460 2 .0 111 8 3 Barnett (17); Marcellus (91); Woodford

- Cana

- Caney (3) Pyridine μg/L 1.1

– 2,600 86 91 90 Barnett (24); Marcellus (67) Tetrachloroethylene μg/L 5 .0

– 5,000 5.0 95 68 Marcellus (95)

Toluene μg/L 0.91

– 1,700,000 6 .0 149 12 5 Barnett (25); Marcellus (115); Medina/Clinton

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

- Cana

- Caney (3)

Xylenes μg/L 3 .0

– 440,000 15 136 11 1 Barnett (20); Marcellus (112); Medina/Clinton

- Tuscarora (1); Woodford

- Cana

- Caney (3)

Source: 56 DCN SGE 00724

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 the se 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

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 67 Table C-3 includes concentration data for ethanol, methanol, and naphthalene, suggesting that a portion of the concentrations of these constituents found in UOG produced water (see Table C-15 ) may have originated from the fracturing fluid. Methanol is typically used in fracturing fluid as a biocide, corrosion inhibitor, crosslinker, and surfactant; ethanol is also used as a biocide and surfactant (see Table C-2 ).

Operators may use methanol as an antifreezing agent at UOG operations in areas with seasonal temperature fluctuations. Methanol may be used at the wellhead to avoid freezing in the wellbore or at compressor stations to prevent equipment from freezing.

The EPA did not identify any quantitative information about diesel

- range organics or total petroleum hydrocarbons in UOG produced water

. However, Table C-3 shows that petroleum distillates are typically used in fracturing fluid at 0.0021 to 0.27 percent by mass . The EPA ORD’s 2015 Evaluation of Hydraulic Fracturing Fluid Data from the FracFocus Chemical Dis closure Registr y 1.0 contains additional information about these constituents ( 201 DCN SGE00721).

3.2.3 Metals in UOG Extraction W astewater

UOG extraction waste water contains varying concentrations of numerous metals.

Table C-16 presents concentration data from existing literature for the metals most common in UOG dril ling wastewater . The EPA identified the following limitations to the data presented in the table :

• Fewer data points (i.e., less than 30) were available for each parameter.

• All of the data came from the Marcellus shale formation.

Table C-17 presents concentration data from existing literature for the metals most

common in UOG produced water . The EPA identified the following limitations to the data presented in the table :

• Fewer data (i.e. , less than 30 data points) were available for vanadium.

• All of the available data for vanadium came from the Marcellus shale formation.

• The majority of the data asso ciated with aluminum, antimony, arsenic, beryllium, boron, cadmium, cobalt, copper, iron, lead, lithium, manganese, merc ury, molybdenum, nickel, selenium, silver, strontium, thallium, tin, titanium, and zinc came from the Marcellus shale formation.

• The maj ority of the data associated with calcium, magnesium, potassium

, and sodium came from the Eagle Ford and Woodford- Cana

- Caney shale formation s.

• The majority of the data associated with chromium came from the Bakken shale formation.Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 68 Table C

- 16 . Concentrations of Select Metal Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells

Parameter Units Range Median Number of Data Points Number of Detects Formation Represented
Aluminum mg/L 1.7

– 6,900 38 12 12 Marcellus
Arsenic mg/L ND a

– 4.2 ND a 12 6 Marcellus
Barium mg/L 2.6

– 2,000 13 14 14 Marcellus Beryllium mg/L ND a

– 0.018 ND a 8 2 Marcellus

Boron mg/L ND a

– 2.7 0.17 8 4 Marcellus
Cadmium mg/L ND a

– 0.0050 ND a 8 1 Marcellus
Calcium mg/L 150

– 15,000 1,300 1 3 1 3 Marcellus
Chromium mg/L ND a

– 11 0.010 12 8 Marcellus
Cobalt mg/L ND a

– 1.8 ND a 8 3 Marcellus Copper mg/L ND a

– 17 0.83 8 6 Marcellus

Iron mg/L 4.2

– 18,000 86 12 12 Marcellus
Lead mg/L ND a

– 8.0 0.35 12 10 Marcellus
Lithium mg/L ND a

– 1.2 ND a 8 1 Marcellus Magnesium mg/L ND a

– 3,600 290 12 11 Marcellus Manganese mg/L ND a

– 350 4.3 12 11 Marcellus Mercury mg/L ND a

– 0.029 ND a 8 2 Marcellus Molybdenum mg/L

— b 0.10 1 1 Marcellus
Nickel mg/L ND a

– 16 0.55 12 9 Marcellus
Potassium mg/L

— b 8,800 4 4 Marcellus
Selenium mg/L ND a

– 0.11 ND a 8 3 Marcellus
Silver mg/L ND a

– 0.010 ND a 8 1 Marcellus
Sodium mg/L 170

– 16,000 2,900 12 12 Marcellus
Strontium mg/L 1.8

– 1,500 21 1 3 1 3 Marcellus
Zinc mg/L ND a

– 38 2.1 12 10 Marcellus

Source: 55 DCN SGE00740

a— Source did not report detection limit. b— Source only reported median value. Abbreviation: mg/L

— milligrams per liter; ND

— non detectChapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 69 Table C

- 17

. Concentrations of Select Metal Constituents in UOG Produced Water

Parameter Units Range Median Number of Data Points Number of Detects Formations Represented (Number of Associated Data Points) a

Aluminum mg/L 0.048

- 47 0.45 159 128 Bakken (4); Barnett (31); Marcellus (116); Woodford

- Cana

- Caney (3) Antimony mg/L 0.0089

- 0.5 0.047 112 79 Barnett (9); Marcellus (103)
Arsenic mg/L 0.004

- 0.5 0.057 132 96 Barnett (15); Marcellus (114); Woodford

- Cana

- Caney (3)

Barium mg/L 0 - 16,000 19 1, 097 1,096 Bakken (312); Barnett (38); Cotton Valley/Bossier (2); Dakota (3); Devonian (4); Eagle Ford (8); Fayetteville (2); Lansing Kansas City (7); Marcellus (209); Medina/Clinton

Tuscarora (1); Morrow (1); Utica (1); Woodford

- Cana

- Caney (508) Beryl lium mg/L 0.0009

- 420 0.04 114 72 Barnett (2); Marcellus (112)

Boron mg/L 0.018

- 150 14 148 134 Bakken (8); Barnett (32); Eagle Ford (1); Marcellus (102); Niobrara (5)
Cadm ium mg/L 0

- 1.2 0.0086 134 92 Barnett (16); Marcellus (115); Woodford

- Cana

- Caney (3)

Calc ium mg/L 13 - 130,000 6,700 5, 336 5,335 Bakken (426); Barnett (39); Cleveland (11); Cotton Valley/Bossier (3); Dakota (3); Devonian (4); Eagle Ford (1644); Fayetteville (2); Lansing Kansas City (15); Marcellus (342); Medina/Clinton

- Tuscarora (2); Mesave rde/Lance (5); Morrow (1); New Albany (1); Oswego (5); Pearsall (3); Spraberry (26); Woodford

- Cana

- Caney (2804)
Chromium mg/L 0.0066

- 260 0.3 383 349 Bakken (234); Barnett (26); Marcellus (115); Woodford

- Cana

- Caney (3)
Cobalt mg/L 0.0045

- 25 0.5 124 92 Barnett (16); Eagle Ford (1); Marcellus (103) Copper mg/L 0

- 4.2 0.14 147 107 Bakken (2); Barnett (22); Marcellus (115); Woodford

- Cana

- Caney (3)

Iron mg/L 0.95 - 810 39 407 380 Bakken (22); Barnett (35); Cotton Valley/Bossier (2); Dakota (3); Eagle Ford (10 ); Fayetteville (2); Marcellus (300); Spraberry (26); Utica (1); Woodford

- Cana

- Caney (6)
Lead mg/L 0

- 5 0.03 133 96 Bakken (1); Barnett (15); Marcellus (113); Woodford

- Cana

- Caney (3)
Lithium mg/L 0.5

- 430 52 120 120 Barnett (31); Marcellus (89)

Magn esium mg/L 3 - 27,000 670 3, 562 3,549 Bakken (426); Barnett (39); Cleveland (11); Cotton Valley/Bossier (3); Dakota (3); Devonian (4); Eagle Ford (1621); Fayetteville (2); Lansing Kansas City (15); Marcellus (326); Medina/Clinton

- Tuscarora (2); Mesaverd e/Lance (5); Morrow (1); New Albany (1); Oswego (5); Pearsall (3); Spraberry (26); Woodford

- Cana

- Caney (1069)

Manganese mg/L 0.12 - 43 1.7 235 221 Bakken (7); Barnett (37); Cotton Valley/Bossier (2); Dakota (3); Eagle Ford (6); Fayetteville (2); Marcellus ( 155); Spraberry (19); Woodford

- Cana

- Caney (3) Mercury mg/L 0

- 0.3 0.0002 115 85 Barnett (11); Marcellus (101); Woodford

- Cana

- Caney (3) Moly bdenum mg/L 0.003

- 13 0.038 140 118 Bakken (1); Barnett (29); Marcellus (105)
Nickel mg/L 0.007

- 4 0.12 151 121 Barnett (27); Eagle Ford (1); Marcellus (116); Woodford

- Cana

- Caney (3)Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 70 Table C

- 17

. Concentrations of Select Metal Constituents in UOG Produced Water

Parameter Units Range Median Number of Data Points Number of Detects Formations Represented (Number of Associated Data Points) a

Potassium mg/L 0 - 8,500 3,100 715 699 Bakken (382); Barnett (36); Cleveland (3); Cotton Valley/Bossier (3); Eagle Ford (149); Marcellus (136); Medina/Clinton

- Tuscarora (2); Mesaverde/Lance (1); Woodford

- Cana

Caney (3)
Selenium mg/L 0.0043

- 0.5 0.05 110 75 Barnett (7); Marcellus (103)
Silver mg/L 0.00073

- 0.5 0.05 115 75 Marcellus (112); Woodford

- Cana

- Caney (3)

Sodium mg/L 64 - 430,000 39,000 3, 449 3,448 Bakken (426); Barnett (38); Cleveland (11); Cotton Valley/Bossier (3); Dakota (3); Devonian (4); Eagle Ford (1631); Fayetteville (2); Lansing Kansas City (16); Marcellus (202); Medina/Clinton

- Tuscarora (2); Mesaverde/Lance (5); Morrow (1); New Albany (1); Niobrara (5); Oswego (5); Spraberry (26); Woodford

- Cana

- Caney (1068)

Strontium mg/L 0 - 8,000 750 253 251 Bakken (10); Barnett (35); Cotton Valley/Bossier (2); Dakota (3); Devonian (4); Eagle Ford (8); Fayetteville (2); Marcellus (183); Medina/Clinton

- Tuscarora (2); Utica (1); Woodford

- Cana

- Caney (3)
Thallium mg/L 0.0049

- 1 0.1 120 83 Barnett (13); Marcellus (104); Woodford

- Cana

- Caney (3)
Tin mg/L 0.0038

- 3 1 80 78 Barnett (10); Marcellus (69)
Titanium mg/L 0

- 8 0.19 111 80 Barnett (16); Marcellus (94)
Vanadium mg/L 0.063

- 40 0.63 27 2 Marcellus (26)

Zinc mg/L 0 - 250 0.2 160 135 Bakken (2); Barnett (32); Eagle Ford (1); Fayetteville (2); Marcellus (116); Woodford

Cana

- Caney (3)

Source: 56 DCN SGE 00724

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 the se instances, there were data points reported in existing literature for which an associated shale or tight oil and gas formation was not identified.

Abbreviation: m g/L

— milligrams per literChapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 71 As discussed in Section C. 3.2.1 , sodium and calcium are two of the primary constituents that contribute to TDS in UOG produced water. Other metals with median concentrations between 100 mg/L and 7 5 0 mg/L are magnesium and strontium, which are group II alkaline earth metals . Low

- solubility salts of these metals (e.g., barium sulfate) commonly precipitate in pipes and valves

, forming scale. Barium is commonly found in higher concentrations in produced water from the Marcellus and Devonian shale formations than in produced water from other UOG formation s. Figure C-5 shows the concentrations of barium in UOG produced water from various shale and tight oil and g as 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.

1.0 10.0 100.0 1,000.0 10,000.0

Barnett Cotton Valley/Bossier Devonian Fayetteville MarcellusBarium Concentration (mg/L)

Source: 56 DCN SGE 00724



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

3.2.4 Radioactive Constituents in UOG Extraction Wastewater Oil and gas formations contain varying levels of naturally occurring radioactive material ( NORM ) resulting from uranium and thorium decay , which can be transferred to UOG produced
water

. Radioactive decay products typically include radium

- 226 and radium -228 ( 54 DCN SGE 00933) . The EPA identified limited available data (primarily from the Marcellus ShaleChapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 72 formation) on some radioactive constituents in UOG extraction waste water, including radium

226, ra dium- 228, gross alpha, and gross beta, and therefore focused the radioactive constituent discussion and data presentation on these parameters. ERG’s Radioactive Materials in the Unconventional Oil and Gas (UOG) Industry memorandum ( 54 DCN SGE00933) contains a more detailed discussion of this topic.

The EPA identified limited radioactive constituent concentration data for UOG drilling
wastewater

. Table C-18 shows the available data from the Marcellus shale formation

.

Table C-18. Concentrations of Select Radioactive Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells

Number of Number of Formations Parameter Units Range Median Data Points Detects Represented Gross alpha pCi/L 17

– 3,000 130 5 5 Marcellus

Gross beta pCi/L 32

– 4,200 1,200 5 5 Marcellus

Source s : 55 DCN SGE00740 Abbreviation: pCi/L

— picocuries per liter



### Similarly, the EPA identified limited radioactive constituent concentration data for UOG produ ced water

. As presented in Table C-19 , most available data characterize produced water from the Marcellus formation; limited data were available from the Niobrara formation. Radium

226 and radium- 228 are both found in UOG produced water, with radium- 226 concentrations generally two to five times greater than radium-228 concentrations.

The EPA identified the following limitations to the data presented in the table :

• Limited or no radioactive constituent concentration data were available for the majority of shale and tight formations.

• Many EPA methods are known to experience interference from high TDS concentrations or the presence of Group II elements , w hich are typical of UOG extraction wastewater, and may result in an underestimation of reported values. ERG’s Radioactive Materials in the Unconventional Oil and Gas (UOG) Industry memorandum (54 DCN SGE00933) discusses potential interference issues associated with various EPA methods and notes that the following methods may experience interference from UOG extraction wastewater: 900.0 Gross Alpha and Gr oss Beta Radioactivity, 903.0 Alpha- Emitting Radium Isotopes, and 903.1 Radium-226, Radon Emanation Technique.

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

Parameter Formation Method(s) Range (pCi/L) Median (pCi/L) Number of Data Points Number of Detects

Gross alpha Marcellus 900.0 8.7

- 120,000 8,700 74 74

Gross alpha Niobrara 900.0 620

– 4,000 1,800 3 3
Gross beta Marcellus 900.0 6.8

- 21,000 1,600 73 72Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



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

Parameter Formation Method(s) Range (pCi/L) Median (pCi/L) Number of Data Points Number of Detects
Gross beta Niobrara 900.0 250

– 1,200 760 3 3

Radium

226 Marcellus 901.1 Mod., 903.0, 903.1, γ

- spectrometry 0.16

- 27,000 1,700 103 101

Radium

226 Niobrara 901.1 Mod. 170

– 900 620 3 3

Radium

228 Marcellus 901.1. 903.0, 904.0, γ

spectrometry 0

- 1,900 470 94 92

Radium

228 Niobrara 901.1 Mod. 100

– 460 330 3 3

Source s : 56 DCN SGE00724 Abbreviations: pCi/L

— picocuries per liter; NA

— n ot a vailable



### As a point of comparison, Table C -20 includes data from a 2014 International Atomic Energy Agency report ( 96 DCN SGE 00769) that included radium isotope concentrations in rivers, lakes, groundwater, and drinking water. Data for radium

- 228 were limited, but the average of measured concentrations of radium

- 226 found in U.S. rivers and lakes was 0.56 pCi/L (21 mBq/L)

. The median concentrations of radium

- 226 and radium

- 228 in UOG produced water in at least one of the formations presented in Table C-19 was above the maximum naturally occurring c oncentration in U.S. rivers, lakes, groundwater, or drinking water presented in Table C-20 . Radium in groundwater may originate from rocks, soil, and other naturally occurring materials, which are likely also the origins of a portion of the radium in UOG produced water.

Table C

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

a nd 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

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 74 Table C

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

a nd 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 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 0 0.014

— Source: 96 DCN SGE 00769

“—”— D ata 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

— non detect



### In January 2015, PA DEP announced the results of a study of radioactive elements in UOG extraction wastewater, sludge, and drill cuttings. Although PA DEP concluded “...[t]here is little potential for radiological exposure to workers and members of the public from handling and temporary storage of [flowback fluid and] produced water on natural gas well sites,” they did conclude “...[t]here is a potential for radiological environmental impacts from spills of produced water [and flowback fluid] on natural gas well sites and from spills that could occur from the transportation and delivery of ...[these] fluid[s]” ( 135 DCN SGE01028 ).

3.2.5 Other Constituents in UOG Extraction 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 and Table C-3 ). Guar gum may be found in UOG produced water at concentrations between 100 mg/L and 20,000 mg/ L ( 193 DCN SGE 00 616). Guar gum treatment requires a breakdown of the polymer and is a consideration for UOG operators who are reusing/recycling wastewater for fracturing.

Microorganisms are also found in UOG drilling wastewater and produced wate r

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

### organisms per 100 mL in UOG produced water ( 193 DCN SGE 00616). Sulfate

- reducing bacteria (SRB) are one classification of a naturally occurring microorganism that may be found in UOG produced water and drilling wastewater

. SRB can cause problems during reuse/recycle of UOG produced water because they can reduc e and/or precipita te metals and ions, potentially causing scale in the wellbore. They can also create hydrogen sulfide

, 64 

### a potential human health concern that is also highly corrosive and can harm the well casing and wellbore ( 201 DCN SGE00721).

64 Exposu re to low concentrations of hydrogen sulfide may cause difficulty breathing and/or irritation to the eyes, nose, or throat. Exposure to high concentrations of hydrogen sulfide may cause headaches, poor memory, unconsciousness and death ( 4 DCN SGE00723 ).Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



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

Concentrations of TDS, radioactive elements, and organic compounds vary across different formations and over time. However, f o r the vast majority of formations for which data

are available , the data demonstrate that flowback and long

- term produced water are both influenced by constituents present in the formation. For example, concentrations of select naturally occurring constitu ents 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

cons tituents to the flowback. Similarly, concentrations of TDS and TDS -contributing constituents (e.g., sodium, chloride

, calcium) increase over time as formation water and the dissolution of constituents out of the formation contribute to long- term produced water

.

RPSEA’s 2012 Characterization of Flowback Waters from the Marcellus and the Barnett Shale Regions ( 85 DCN SGE00414) presents sampling data from 19 sites in the Marcellus shale and five sites in the Barnett shale. The sampled constituents include a wide array of classicals, conventionals, organics, and metals. Where possible, these constituents were sampled at day 0, day 1, day 5, day 14, and day 90. Figure C-6 presents median data for select constituents as reported in the RPSEA report. Figure F-1 in the appendices presents median data for additional constituents as reported in the RPSEA report.Chapter C

— U nconventional Oil and Gas Extraction Wastewater Volumes and Characteristics



### 76 Source: The EPA generated this figure using data from 85 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



### 77 

## Chapter D. UOG E XTRACTION 

## W ASTEWATER 

## M ANAGEMENT AND 

## D ISPOSAL 

## P RACTICES



### During the lifetime of a well, UOG extraction generates large volumes of UOG extraction wastewater that contain constituents potentially harmful to human health and the environment, as discussed in Chapter C . Th is create s a need for appropriate wastewater management infrastructure and disposal practices

. Except in limited circumstances

, 65 

### the existing effluent guidelines for oil and gas extraction prohibit the onsite direct discharge of wastewater into waters of the U nited S tates . Historically, operators primarily managed their wastewater via underground injection (where available). This section discuss es the me thods used by UOG operators to manage and dispose of UOG extraction wastewater.

1 O VERVIEW OF 

### UOG E XTRACTION 

### W ASTEWATER 

### M ANAGEMENT AND 

### D ISPOSAL 

### P RACTICES



### For management of UOG produced water , UOG operators primarily use the three methods listed below and shown in Figure D-1 ( 188 DCN SGE 00613; 177 DCN SGE 00276; 76 DCN SGE 00528).

• Dispose of wastewater via underground injection, using Class II UIC disposal wells (“disposal wells”)

• Reuse/recycle wastewater in subsequent fracturing jobs

• Transfer wastewate r to a CWT facility

Across the United States, operators most often manage their produced water via disposal wells. For management of drilling wastewater, which includes drill cuttings and drilling fluids, operators primarily use the methods listed below an d shown in Figure D-2 ( 55 DCN SGE 00740 ).

• Dispos al via disposal wells

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

• Transfer to a CWT facility

• Onsite burial 66



### • Disposal via landfill

• Land application

In sel ect 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 tate s ( 148 DCN

65 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 discharge when the water is of good enough quality for agricultural and wildlife uses (see 40 C.F.R. p art 435 s ubpart E) , the EPA has not found that these types of permits are typically written for UOG extraction wastewater (as defined for the proposed rule).

66 Onsite burial involves t emporary fluid storage in on

- site open earthen or lined pits with burial of residual solids after fluids are solidified, removed from the top, or evaporated.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 78 SGE 00710). Evaporation ponds also require a large, flat site

, and they perform best only during select months of the year (e.g., May throug h October) ( 114 DCN SGE 00779.A24 ).

CWT facilities

POTWs Treatment in the field

Surface

water

Reuse in fracturing UOG Wells

UOG Well Legend

Treated UOG Produced Water

Untreated UOG Produced Water

Injection into Class

II disposal wells



### Fig ure D-1 . UOG Produced Water Management Methods

CWT facilities

POTWs Treatment in the field

Surface

water

Reuse/Recycle UOG well Legend

Treated drilling wastewater

Untreated drilling wastewater

Injection into class

II disposal wells Landfill Burial



### Fig ure D-2. UOG Drilling Wastewater Management MethodsChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 79 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 ( 139 DCN SGE 00579; 177 DCN SGE 00276; 178 DCN SGE 00635 ; 55 DCN SGE 00740 ). Table D-1 describes how UOG operators manage produced water specifically in basins containing major UOG formations, which varies by basin and formation. As detailed above, historically, the oil and gas industry has most commonly managed produced water by underground injection ( 25 DCN SGE 00182), 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 Secti on D. 3 and Section D. 4 ) ( 43 DCN SGE 00596; 92 DCN SGE 00707; 34 DCN SGE 00708).

The literature does not contain the same level of detailed information about drilling
wastewater management practices as is provided for produced water management in Table D-1

. However, the EPA did identify comprehensive data for management of drilling wastewater generated by Marcellus shale wells located in Pennsylvania. Figure D-3 shows management practices used by UOG operators in Pennsylvania for managing their UOG drilling wastewater from 200 8 to 2013. In recent years (2010 to 2013) , transfer to CWT facilit ies , reuse/recycle in drilling or fracturing, and injection for disposal

— in that order

— were the most common practices ( 46 DCN SGE 00739) for UOG drilling wastewater management in Pennsylvania

. In addition to this detailed information about drilling wastewater management in Pennsylvania, the EPA obtained informati on from a large UOG 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 wells ( 191 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)

. 67 

### Figure D-4 compares the east and west portions of th e basin, thus illustrating b asin and formation differences in wastewater management practices

. The east side of the b asin contains very few underground disposal wells, but contains a high density of CWT facilitie s that have accepted or plan to accept UOG p roduced 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 fracturing 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, these discharges were discontinued in 2011 ( 46 DCN SGE 00739; 80 DCN SGE 00286; 109 DCN SGE 00345; 139 DCN SGE 00579). After desc ribing the three management alternatives that the UOG industry uses (i.e., injection into disposal wells, reuse/recycle in fracturing, transfer to CWT facility), Chapter D ends with a discussion of POTWs and how they cannot remove some of the constituents in UOG extraction
wastewater and drilling wastewater . The end of Chapter D also presents EPA

- collected data

67 The EPA obtained information about CWT facilities accepting UOG extraction wastew ater from publicly available sources. Therefore, the list of CWT facilities the EPA identified may not be complete.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 80 indicating that POTWs have not received any UOG extraction wastewater between 2011 and the present (data are current up through the end of 2013).Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 81 Table D

- 1

. UOG Produced Water Management Practices

Basin UOG Formation Resource Type Reuse or Recycle Injection for Disposal CWT Facilities Notes Available Data b
Michigan Antrim Shale gas XXX Qualitative Appalachian Marcellus/Utica (PA) Shale gas XXX XX XX Limited disposal wells in east Quantitative Marcellus/Utica (WV) Shale gas / oil XXX XX X Quantitative Marcellus/Utica (OH) Shale gas / oil XX XXX X Mixed

Anadarko Granite Wash Tight gas XX XXX 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 effective 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/recycle not typically effective due to high TDS early in flowback and abundance of disposal wells Mixed

West Gulf Eagle Ford , Pearsall Shale gas / oil X XXX X Mixed Denver Julesburg Niobrara Shale gas / oil X XXX X Mixed
Piceance; Green River Mesaverde/Lance Tight gas X XX X Also managed through evaporation to atmosphere in ponds in this region Qualitative

Williston Bakken Shale oil X XXX Reuse/recycling limited but is being evaluated Mixed

Source s : 48 DCN SGE 00693

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 qualitative and quantitative data sources along with engineering judgment to determine the number of Xs. XXX

— The majority (≥ 50%) of wastewater is managed with this management practice ; XX

— A moderate portion (≥ 10% and <50%) of wastewater is managed with this management practice ; X— This management practice has been documented in this location

, but for a small (<10%) or unknown percent of wastewater

.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 82 Source s : 46 DCN SGE 00739



### Figure D-3. Management of UOG Drilling Wastewater Generated by UOG Wells in Pennsylvania (2008–2013)Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 83 Sources: Generated by the EPA using data from 43 DCN SGE 00596 and 41 DCN SGE 00736



### Figure D-4 . Active Disposal Wells and CWT Facilities Identified in the Appalachian Basin 68

68 The active disposal wells data for New York were last updated in September 2009 for New York and December 2013 for Pennsylvania. The last update for the active disposal wells data in Ohio and West Virginia is unknown. The EPA accessed the Ohio data in February 2013 and the West Virginia data in December 2013. The CWT facility data were last updated at the end of 2013, based on publicly available information.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 84 2 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 injection wells ( 207 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 w astewater. In its underground injection well control program codified in 40 C.F.R. parts 144 to 148, the EPA established six classes of underground injection wells ( 173 DCN SGE 00132):

• Class I in dustrial and municipal waste disposal wells

• Class II oil and gas related injection wells

• Class III mining wells

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

• Class V 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 purposes:

• 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 wells in the U nited S tates are disposal wells ; the remaining 80 percent are mostly enhanced recovery wells ( 173 DCN SGE 00132) . Injection for disposal typically involves injecting wastewater into a porous and non

- oil

- and

- gas -containing reservoir. Industry does not use enhanced recovery wells for disposing of UOG extraction wastewater because most enhanced recovery projects consist of a closed

- loop system with two or more wells: at least one producing well and at least one enhanced recovery well. Operators of enhanced re covery projects typically route the wastewater generated by the producing well directly back to the adjacent enhanced recovery well ( 206 DCN SGE 00623; 173 DCN SGE 00132; 188 DCN SGE 00613). Availa ble literature and communication with industry indicates that industry only hauls UOG extraction wastewater to Class II disposal wells 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 well ( 51 DCN SGE 00693.A03 ). 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 to prevent underground injection that endangers drinking water sources, or have a program determined toChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 85 be effective as the federal standards. Currently, the EPA has delegated Class II primacy to 39 states, three territories and two tribes. The EPA has authority over the Class II UIC programs in the remaining 11 states, two territories and all other tribes ( 184 DCN SGE 00611 ).

2.2 Active Disposal Wells and Volumes

The availability of underground injection for disposal varies by state. Some states have a large number of Class II injection wells (e.g., Texas, Oklahoma, Kansas) while others have few (e.g., Virginia, South Dakota) . The EPA tabulated active Class II disposal wells using data from state agencies and EPA direct implementation programs

. More information about how the EPA compiled data from state agencies is documented in a separate memorandum titled Analysis of Active Underground Injection for Disposal Wells ( 41 DCN S GE 00736 ; 42 DCN SGE 00736.A01).

Table D-2 presents the number of active Class II disposal wells by state ( 41 DCN SGE 00736 ; 42 DCN SGE 00736.A01 ). It also includes average daily disposal rates for disposal wells on a gallon -per- well

- per

- day basis for each state . D aily disposal rates of individual disposal wells vary significantly , reflecting the geology of the underlying formation ( 176 DCN SGE 00279). The average disposal rate per well estimates in the table are not exact but rather are
gen eral approximations based on a number of assumptions which are d escribed in d etail in ERG’s memo randum Analysis of Active Underground Injection for Disposal Wells ( 41 DCN SGE00736). Lastly, Table D-2 presents the total state disposal rate based on the active number of disposal wells and average daily disposal rates per well. States are first sorted by geographic region , then by the total state disposal rate

. States with no disposal rate data are sorted by highest to lowest count of active Class II disposal wells.

Table D

- 2 . Distribution of Active Class II Disposal Wells Across the United State s

Geographic Region

(from the EIA) State Number of Active Disposal Wells a Average Disposal Rate Per Well

(gpd/well) b Total State Disposal Rate (MGD)

Alaska Alaska 45 182,000 8.2

East Illinois 1,054

— c

— c Michigan 779 g 16,600 13

Ohio 188 8,900 1.7

Indiana 183 3,580 0.66 West Virginia 66 7,180 0.47 Virginia 12 17,500 0.21 Kentucky 58 1,750 0.1 0 Pennsylvania 9 6,380 0.057

New York 10 d 3,530 0.035

Tennessee 0 0 0 Maryland 0 0 0

Minnesota 0 0 0

North Carolina 0 0 0

Gulf Coast/Southwest Texas 7,876 54,200 430Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 86 Table D-2 . Distribution of Active Class II Disposal Wells Across the United State s

Geographic Region

(from the EIA) State Number of Active Disposal Wells a Average Disposal Rate Per Well

(gpd/well) b Total State Disposal Rate (MGD)

Louisiana 2,448 42,100 100

New Mexico 736 48,600 36 Mississippi 499 69,500 35

Alabama 85 44,200 3.8

Mid

- Continent Oklahoma 4,622 g 35,900 170

Kansas 5,516 20,900 120

Arkansas 611 e 30,900 19

Nebraska 113 18,100 2 .0

Missouri 11 1,270 0.014

Northern Great Plains North Dakota 395 31,600 12

Montana 199 31,100 6.2

South Dakota 21 10,200 0.21

Rocky Mountains Wyoming 330

— c

— c

Colorado 294 50,200 15

Utah 109 74,400 8.1

Arizona 0 0 0

West Coast California 826 77,800 64 All other states (NV, FL, OR, IA, and WA) f 42 89,400 3.8

Total 27,1 37 40,400 1,0 40
Source s : 41 DCN SGE 00736

a— Number of active disposal wells is based primarily on data from 2012 to 2014. b— Typical injection volumes per well are based on historic al annual volumes for injection for disposal divided by the number of active disposal wells during the same year (primarily data 2007 to 2013)

. These approximations are based on a number of assumptions which are detailed in ERG’s Analysis of Active Underground Injection for Disposal Wells memorandum ( 41 DCN SGE00736).

c— Disposal rates and/or number of disposal wells is unknown. d— These wells are not currently permitted to accept UOG extraction wastewater (source: 186 DCN SGE00726).

e— Only 24 of the 614 active disposal wells in Arkansas are in the northe rn half of the state, close to the Fayetteville formation ( 

### 6 DCN SGE00499). f— These are states that have minimal oil and gas activity

. The number of wells shown for these states may include all types of Class II wells (e.g., Class II enhanced recovery wells) and therefore is an upper estimate ( 167 DCN SGE 00138 ). All other states not listed in this table have minimal oil and gas activity and no active disposal wells.
g— With the exception of Oklahoma and Michigan, wells on tribal lands have not been intentionally included. Wells on tribal lands may be counted if state databases contained them

. Abbreviations: gpd

— gallons per day ; MGD

— million gallons per day



### 2.3 Underground Injection Considerations

In many UOG formations, distances from the average producing well to the nearest disp osal well are short and disposal capacity is abundant

, making it the least expensive UOG extraction wastewater management practic e ( 178 DCN SGE 00635). There is no widespread discussion in the industry about lack of injection well disposal capacity ( 188 DCN SGE 00613) nationally, suggesting that there is enough capacity in place and ; therefore, potential forChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 87 continued acceptance of UOG extraction wastewater. However, as illustrated above, underground injection for disposal capacity in close proximity is much less available in certain portions of the U nited S tates . An other consideration is freshwater availability . I n some areas with plentiful underground injection for disp osal capacity where water scarcity is a problem, there is a concern about permanently disposing of UOG produced water underground rather than using it to supplement freshwater needs in subsequent hydraulic fracturing jobs ( 75 DCN SGE 00760; 142 DCN SGE 00583).

Commercial i njection for disposal well operators may surcharge operators to dispose of flowback ( 176 DCN SGE 00279 ). Injection well operators impose the surcharge because flowback has a low er density than long- term produced water. Injection of high -density wastewater requires less power (i.e. , pumping) than injecting less

- dense wastewater, 69 

### and the injection rate (i.e., barrels per day per well) is inversely proportional to the injection pressure due to technical and permit limitations. As a result, disposal well operators must inject lower -de nsity flowback at a lower flow rate and more power.

3 R EUSE 

### /R ECYCLE IN 

### F RACTURING



### As of 2013

, many operators evaluate reusing/recycling UOG extraction wastewater before deciding to manage it via another method (i.e., disposal well or CWT facility ) ( 188 DCN SGE 00613; 38 DCN SGE 00521; 177 DCN SGE 00276). Reuse/recycl e involves mixing flowback and/or long

- term produced water from previously fr actured wells with other source
water 70 

### to create the ba se fluid 71 

### used in a subsequent well fractur e ( 1 DCN SGE 00046). Operators typically transport the wastewater, by truck or pipe , from storage to the fracturing site just before and during hydraulic fracturing. Operators typically store the wastewater in 10,500- to 21,000- gallon (200- to 500

- barrel ) fracturing tanks onsite until they are ready to blend it with other source water during the hydraulic fracture. When hydraulic fracturing begins , they pump the stored UOG produced water for reuse and other source water to a blender to form the base fluid. The blending usually occurs upstream of other steps such as fracturing chemical add ition or pressurization by the pump trucks ( 191 DCN SGE 00625 ).

S ince the late 2000s, UOG operators have increased wastewater reuse/recycle ( 188 DCN SGE 00613 ). 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 geolog y ( 188 DCN SGE 0061 3). 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 provide r s were able to design fracturing additives to toler ate base fluids with higher concentrations of TDS ( 194 DCN SGE 00691; 38 DCN SGE 00521; 188 DCN SGE 00613; 208 DCN SGE 00095).

69 The d ensity of flowback is typically close to that of fresh water (8 pounds per gallon)

, while th e density of produced water can be greater than 10 pounds per gallon ( 176 DCN SGE00 279).

70 Source water is any fluid that makes up fracturing base fluid. See Section C. 1.1

. 71 Base fluid is the primary component of fracturing fluid to which proppant and chemicals are added. See Section C. 1.1

.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 88 To date, slickwater fracturing fluid designs (defined in Section C. 1 ) are the most accommodating for using base fluid that contains the high end of the TDS criteria ranges (see Table D-4 in section D. 3.2 for these ranges) ( 188 DCN SGE 00613; 40 DCN SGE 00705; 193 DCN SGE 00616). Gel designs (defined in Section C. 1 ), which are typically used to fractur e liquid rich plays (e.g., Bakken), are more complex and industry currently finds them to be less compatible with high concentrations of TDS than slickwater designs ( 40 D CN SGE 00705; 188 DCN SGE 00613; 193 DCN SGE 00616). As a result, at present, g el designs require base fluid that meets the low end of the TDS criteria ranges (see Table D-4 in section D. 3.2 for these ranges)

. This is primarily because TDS interferes with the properties of the cross

- linked gels inhere nt to gel fracturing fluid designs. Indust ry also reports that boron is a constituent of concern for reuse/recycle when using gel recipes because it interferes with the intended delayed activation of cross

- linked gels ( 193 DCN SGE 00616; 40 DCN SGE 00705). T his may be changing : industry has recently demonstrated the use of higher

- TD S base fluid in gel fracturing as new chemical additives are becoming available for gel designs that tolerate higher TDS concentrations 72 

### ( 110 DCN SGE 00667; 40 DCN SGE 00705 ).

PESA surveyed 205 UOG operators about their wastewater management pr actices in 2012 ( 136 DCN SGE00575)

. 73 

### Table D-3 presents the survey results. Nationally, UOG operators reported reusing/recycling 23 percent of total produced water generated. The results also showed that most operators anticipate reusing/ recycling higher percentages of their produced water in the two to three years following the survey. Other research firms that gather data on UOG extraction wastewater management report similar findings ( 34 DCN SGE 00708; 122 DCN SGE 00709). For example, IHS Inc. estimates that in 2013 operators reused/recycled 16 percent of UOG produced
water nationwide and expects this number to double by 2022 ( 34 DCN SGE 00708) . The EPA participated in several si te visits and conference calls with operators in several formations that have been able to reuse/recycle 100 percent of their produced water under certain circumstances ( 178 DCN SGE 00635; 179 DCN SGE 00275; 191 DCN SGE 00625; 183 DCN SGE 00636).

Table D

- 3

. 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 Salt Haynesville Shale gas 30 70 67

Arkoma Fayetteville Shale gas 30 70 67
Western Gulf Eagle Ford Shale gas / oil 16 84 60

Fort Worth Barnett Shale gas 13 87 86

Permian Avalon; Barnett

Woodford Shale g as / o il 7 93 67

Williston Bakken Shale oil 5 95 56

72 One vendor reported that testing of new additives for gel designs that allow the use of high

- TDS base fluid is underway. This vendor expected the cos t for these chemicals to initially be high ( 40 DCN SGE00 705).

73 Out of the 205 respondents, 143 represented operators active in major U.S. UOG plays.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 89 Table D-3. 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 Gulf Coast (Austin Chalk, Cotton Valley, Vicksburg) b Unknown 10 90 100

Mid

- Continent (Woodford, Cana, Caney, Granite Wash) b Unknown 25 75 68

Rockies (Niobrara, Mancos) b Unknown 14 86 100 Weighted average 23 77 55

Source: 136 DCN SGE 00575

a— PESA ( 136 DCN SGE 00575 ) reported this as “disposal” but did not clearly describe what it means. b— PESA ( 136 DCN SGE 00575 ) did not specify basin or formation for these areas . The EPA provided formation names that are present in these areas if not already previously listed above.



### 3.1 Reuse/Recycle Strategies

Operators can reuse/recycle UOG extraction wastewater for fracturing through different strategies. An operator’s choice of strategy depends on many factors, which Section D. 3.2 describes in detail. The following subsections discuss direct reuse/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 remove suspended solids. The primary purpose of the blending is to control TDS concentrations ( 193 DCN SGE 00616; 194 D CN SGE 00691). When using this strategy, operators either transport UOG extraction wastewater directly to the next well they are fracturing or transport it to a temporary storage area offsite until they are ready to fracture the next well.

Reuse/recycle wi thout treatment accounts for a large portio n of all wastewater that industry reuse s /recycles. In PESA’s 2012 survey ( 136 DCN SGE00575)

, UOG operators reported that 54 percent of produced water reused/recycled by the UOG industry in 2012 for fracturing requires minim al or no treatment. In addition, the EPA conducted severa l site visits and conference calls with operators that have increasingly reused/recycled wastewater with no treatment ( 178 DCN SGE 00635; 179 DCN SGE 00275; 191 DCN SGE 00625; 183 DCN SGE 00636; 177 DCN SGE 00276).

3.1.2 Reuse/Recycl e in Fracturing After Treatment Operators also reuse/recycle UOG extraction wastewater after some type of treatment. Where treatment is employed, t he UOG industry typically uses one of two levels of treatment:Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 90 • Non

- TDS removal technologies —t echnologies that remove non-dissolved 74 

### constituents from wastewater, including suspended solids, oil and grease, bacteria, and /or certain ions that can cause scale to form on equipment and interfere with fracturing chemical additives. These technologies are not designed to reduce the levels of dissolved constituents, which are the ma jority of compounds that contribute
to TDS in UOG extraction wastewater.

• TDS removal technologies —technologies capable of removing dissolved constituents that contribute to TDS (e.g., sodium, chloride, calcium) as well as the constituents removed by non- TD S removal technologies

. Treatment systems with these treatment technologies include non-TDS removal technologies for pretreatment (e.g., TSS, oil and grease).

Each of these levels of treatment is described in more detail below. Also see the EPA ’s report titled Unconventional Oil and Gas (UOG) Extraction Wastewater Treatment Technologies ( 203 DCN SGE 00692), which discusses treatment technologies used to treat UOG produced
water

.

Non -TDS Removal Technologies

As discussed in Section D. 3

, there are constituents in UOG extraction w astewater other than TDS that operators may need to remove or destabilize before reuse / recycle

. In particular, they may need to reduce constituents that may cause scale, formation damage, and/or interference between chemical additives and the formation geology ( 203 DCN SGE 00692). These constituents include suspended solids, oil and grease, bacteria, and certain ions (e.g., iron, calcium, magnesium, and barium). Non

- TDS removal techno logies used to treat UOG extraction
wastewater for reuse/recycle include ( 188 DCN SGE 00613; 208 DCN SGE 00095):

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

• Chemical precipitation

• Electroco agulation

• Advanced oxidation precipitation

Industry often uses non- TDS removal technologies to remove or destabilize the aforementioned constituents. This treatment may be done in the field at the well site or off

- site at a CWT facility. One me thod used in the field to treat UOG extraction wastewater is referred to as “on the fly” treatment, where the wastewater is treated as fluids are mixed for hydraulic fracturing.

Figure D-5 shows a simplified flow diagram of on -the- fly treatment of UOG produced water for reuse/ recycle . In this practice, the operator treats the mixture of UOG produced water and other source water concurrently with the hydraulic fracturing process. Therefore, wastewater

74 EPA has categorized treatment technologies into two categories in this document: those that are designed to remove dissolved constituents and those that are not designed to remove dissolved constituents. However, it should be noted that some of the tech nologies in the non

- TDS removal category do in fact remove some dissolved constituents. For example, chemical precipitation will remove certain metals. However, these technologies typically will not remove salts and hardness, which are the primary componen ts of TDS in UOG extraction wastewater.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 91 treatment occurs at relatively high flow rates equivalent to the rate of hydraulic fracturing. 75 

### Other than the treatment unit, there is no additional equipment required in this setup that is not already required for hydraulic fracturing (e.g., additional storage typically required for treated
wastewater ). This eliminates or reduces the following ( 30 DCN SGE 00331 ): 76



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

• Procuring 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

Fracturing fluid

Proppant and

chemicals Blender UOG produced

water treatment system Base fluid Nearby impoundment or pond

Well Other source

water

Pump trucks Treated

base fluid

Fracturing tanks with untreated wastewater Well pad

Blender

Source: Generated by EPA using 30 SGE00331.



### Figure D-5. Flow Diagram of On- the

- Fly UOG Produced Water Treatment for Reuse/Recycle

TDS Removal Technologies

In general, TDS removal technologies convert influent wastewater into two streams: concentrated brine and low

- TDS water (i.e., distillate). As discussed in the introduction to

75 Operators typically hydraulically fracture wells at rates of 2,520 to 5,040 gallons (60 to 120 barrels ) per minute. On

- the

- fly treatment technologies must be capable of treating wastewater at the same rate ( 203 DCN SGE00 692).

76 The most common technology for on

- the

- fly treatment is advanced oxidation. This technology eliminates the need to add biocide to the fr acturing fluid to prevent bacteria growth.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 92 Section D. 3 , operators have learned that low

- TDS base fluid is not necessarily required for fract uring. However, some operators may still use TDS removal technologies to treat wastewater for reuse/recycle in fracturing

. TDS removal technologies that UOG operators have used to treat UOG extraction wastewater for reuse/recycl e include ( 188 DCN SGE 00613; 208 DCN SGE 00095) reverse osmosis (when TDS is less than approximately 50,000 mg/L) and evaporation/condensation and crystallization ( 203 DCN SGE 00692). Some vendors currently offer skid

- mounted mobile TDS removal units for reuse/recycle in the field ( 203 DCN SGE 00692) . The EPA also identified several CWT facilitie s owned by operators that use TDS removal technologies (e.g., evaporation/condensation) ( 84 DCN SGE 00284).

3.2 Reuse/Recycle Drivers

The reuse/recycle strategy operators cho o se depends on many different factors. The following subsections describe the two biggest drive rs ( 148 DCN SGE 00710):

• Pollutant concentrations in UOG extraction wastewater compared to maximum acceptable pollutant concentration s for base fluid (describe d in more detail in Section D. 3.2.1 )

• Volume of UOG extraction wastewater available for reuse/recycle compared to total volume of base fluid required for fracturing a new well (described in more detail in Section D. 3.2.2 )

These f actors vary by formation and operator; therefore, the potential for reusing/recycling UOG extraction wastewater for fracturing also varies by formation and operator. These two drivers ultimately affect the level of treatment required, if any, and the total cost for reuse/recycle. Operators always consider the total cost per barrel for reuse/recycl e as compared to other management 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 prior to reuse/recycle ( 148 DCN SGE 00710). 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 Sect ion C. 3.2.1 and shown in Figure C-6 , TDS concentrations increase over time as the flow rate decreases after fracturing ( 148 DCN SGE 00710, 85 DCN SGE 00414, 27 DCN SGE 00357, 151 DCN SGE 00350, 191 DCN SGE 00625). Th erefore, 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 produ ced water (see Section C. 3.2.1 ) ( 148 DCN SGE 00710).

S ome operators are able to reuse/recycle long

- term produced wat er with no or minimal TDS treatment

, as observed by the EPA in the Marcellus and Fayetteville shale formations ( 183 DCN SGE 00636; 178 DCN SGE 00635; 191 DCN SGE 00625). However, this may not be
pos sible 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 be lower than the TDS concentrations for flowback in other basins. For example, in the Bakken formation,Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 93 TDS concentrations in flowback increase rapidly to levels as high as 200,000 mg/L ( within five days after fracturing ), which m ay limit the volume of this wastewater capable of being used for reuse/recyc le ( 151 DCN SGE 00350). 77 

### On the other hand, the Fayetteville shale formation generates a maximum of 40,000 mg/L TDS in long

- term produced water ( 191 DCN SGE 0062 5). 78



### If operators reuse/recycle UOG extraction wastewater that contains too much of certain constituents, the fracturing fluid, well , and/or formation may undergo one or more of the following problems ( 3 DCN SGE 00070):

• Fluid instability (change in fluid properties)

• Well plugging (restriction of flow)

• Well bacteria growth (buildup of bacteria on casing)

• Well scaling (accumulation of precipitated solids)

• Formation damage (restriction of flow in the reservoir)

Table D-4 shows ranges of observed or recommended constituent concentration criteria for the fracturing base fluid and the associated effect that the fluid or well may experience with concentrations in excess of the criteria. These ranges represent general values that industry reports, not values specific to one UOG formation. The exact criteria an operator uses depend on operator preference, geology, and the fracturing fluid chemistry (e.g., slickwater, gel) , but the selected criteria typically fall within the ranges shown in Table D-4

.

77 This report determined tha t only the initial five percent of the injected fracturing fluid volume that returns to the surface contains TDS less than 60,000 mg/L in the Bakken

, based on sampling data for 62 wells

. 78 This operator reported that they are able to reuse all of their UOG wastewater due to low TDS concentrations.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 94 Table D

- 4

. Reported Reuse/ Recycl e Criteria

Constituent Reasons for Limiting Concentrations Recommended or Observed Base Fluid Target Concentrations (mg/L, a After Blending)

TDS Fluid stability 500

– 70,000
Chloride Fluid stability 2,000

– 90,000
Sodium Fluid stability 2,000

– 5,000

Metals

Iron Scaling 1

– 15

Strontium Scaling 1

Barium Scaling 2

– 38
Silica Scaling 20
Calcium Scaling 50

– 4,200 Magnesium Scaling 10

– 1,000
Sulfate Scaling 124

– 1,000

Potassium Scaling 100

– 500

Scale f ormers b Scaling 2,500

– 2,500 Phosphate Not r eported 10

Other

TSS Plugging 50

– 1,500
Oil Fluid stability 5

– 25

Boron Fluid stability 0

– 10 pH (SU) Fluid stability 6.5

– 8.1

Bacteria (counts/mL) Bacterial growth 0

– 10,000

Source s : 48 DCN SGE 00693

a— Unless otherwise noted. b— Includes total of barium, calcium, manganese, and strontium. Abbreviations: mg/L

— milligrams per liter; SU

— st andard units; mL

— milliliter



### 3.2.2 Base Fluid Demand for Fracturing The amount of wastewater used in fracturing fluid make up depends not just on
wastewater pollutants and concentrations but also on wastewater quantity compared to the amount of water required fo r the base fluid

.

Water Demand at the Well Level

The volume of fracturing fluid required per well for fracturing may also influence the level of treatment or blending ratio necessary to meet the base fluid pollutant criteria in Table D-4 . The blending ratio is the volume of reused/recycled wastewater as a percent of the total base fluid volume used to fracture a specific well. The blending ratio depends on the wastewater pollutants and concentrations as well as on the volume of UOG extraction wastewater available and the total volume of base fluid required. Operators must consider how much wastewater is generated by nearby well s with respect to how much fracturi ng fluid is required to fracture a subsequent well. In areas where produced water volume generation is high and/or the required total base fluid volume for fracturing is low, operators may use a high blend ing ratio. AsChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 95 explained above, this high ratio may require more treatment depending on TDS and other constituent concentrations. On the other hand, in formations where produced water volume generation is low and total base fluid fracturing volume is high , operators may use a low blending ratio . A low blending ratio can typically be used with little to no treatment ( 179 DCN SGE 00275; 178 DCN SGE 00635; 188 DCN SGE 00613 ). Table D-5 shows observed blending ratios for various formations. This table also includes theoretical upper end blending ratios as presented in literature which are based on the typical fracturing fluid volume and produced water volume generated per well 79 

### for each formation ( 215 DCN SGE00627; 126 DCN SGE00639; and 194 DCN SGE00691).

Table D

- 5

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

Basin Formation Resource Type Observed Blending 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

– 10

Tuscaloosa Marine Shale 25

— Western Gulf Eagle Ford Shale

— 10

– 40

Source s : 48 DCN SGE 00693

Note: Data years represented range from 2009 to 2013.

a— Actual observed volumes of reused/recycled UOG extraction wastewater as a perce ntage of fracturing fluid volume. b— Estimated maximum blending ratio b ased on typical flowback volume per well compared to typical fracturing volume per well as presented in 215 DCN SGE 00627; 126 DCN SGE 00639; and 194 DCN SGE 00691.

c— References do not specify a specific formation.

“— ” indicates no data.



### Water Demand at the Formation Level

Although reuse/recycle has become popular as a way to manage UOG extraction wastewater, it is anticipated to become less attractive as a formation m atures and the operator drills and fractures fewer wells ( 148 DCN SGE00710). As a formation matures, the volume of base fluid needed to fracture new we lls may be less than the volume of produced water generated by producing wells in the area ( 191 DCN SGE00625). Figure D-6 illustrates this concept 80 

### with a hypothetical situation for an operator in a single formation as reported by an operator ( 20 DCN SGE00305.A03) . During early years of development

, the base fluid demand for fract uring wells

79 This theoretical value reported in literature is irrespective of constituent concentrations.

80 This concept assumes that operators do not ty pically share wastewater for reuse in fracturing.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 96 always exceeds the volume of produced wate r generated

. This provides favorable conditions for

reuse /recycle . As drilling decreases, the volume of base fluid needed decreases below the volume of produced wastewater generated. Consequently, the operator must find an alternative for at least some portion of the produced water ( e.g., disposal well ).

Source: 48 DCN SGE 00693 ( Generated by the EPA based on figure in 20 DCN SGE 00305.A 03)



### Figure D-6. Hypothetical UOG Pro duced Wa ter Generation and Base Fracturing Fluid Demand o ver Time

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

• Wastewater storage

• Source water availability and cost

3.3.1 Transportation Transportation requirements affect the wastewater reuse/recycle potential in a specific

area. While not explicitly stated above, the location of the producing well (s) relative to theChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 97 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 bar rel) to transport the wastewater for all management scenarios.

Further, w hen an UOG well generating wastewater is far from alternative management approaches such as a disposal well or CWT facility, reuse/recycle may also be more economical. The distance be tween disposal wells and CWT facilities from the UOG well generating the wastewater can vary by formation and even within formations. For example

, Figure D-7 shows how operators in the northeast region of the Marcellus reused/recycled a higher percentage of wastewater compared to the southwestern region between 2008 and 2011 ( 139 DCN SGE 00579 ). This is due to the fact that Marcellus wells in the southwestern part of Pennsylvania are closer to disposal wells in Ohio

, whereas Marcellus wells in t he northeast portion of Pennsylvania are more than 200 miles from disposal wells in Ohio. As a result, it is typically le ss expensive per barrel to reuse/recycle the wastewater in the northeast than to transport it to a disposal well in Ohio because transp ortation alone can cost as much as $13 per barrel ( 180 DCN SGE 00300).

Sou rce: Graphic reprinted with permission from Brian Rahm ( 139 DCN SGE 00579 ) Note: “a” and “b” for 2010 and 2011 represent the first and second half of the year

, respectively.



### Figure D-7. UOG Extraction Wastewater Management Practices Used in the Marcellus Shale ( Top : Southwestern Region ; Bottom : Northeastern Region)

3.3.2 Storage Storage requirements and the number of wells the operator is drilling per unit time under its drilling program may also dictate when operators can reuse/recycle wastewater. In general, the effective storage cost to the operator increases the longer UOG extraction wastewater isChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 98 stored before reuse in a subsequent well 81 

### ( 179 DCN SGE 00275 ). For example, an operator who is considering reusing extraction wastewater for fracturing that fractures 12 wells per year in an area will need to store wastewater for approximately one month before the next fracturing job. In comparison, an operator who fractures 50 wells per year in an area may only need to store wastewater for a week before they can reuse /recycle it in the next fracturing job ( 39 DCN SGE 00283 ). Section B. 2.1 explains UOG extraction wastewater storage options in more detail

.

3.3.3 Source Water Availability
Operators that successfully reuse/recycle their wastewater can reduce the total volume of other types of source water they need to use for base flui ds, creating an offset in costs associated with source water ( 208 DCN SGE 00095). 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 groundwater resources are abundant and inexpensive ( 142 DCN SGE 00583; 148 DCN SGE 00710). This is because as the cost of fresh water and groundwater increases , the offset in costs from reusing/recycling wastewater to replace other source water also increases

. 82 

### Examples of such areas include California, the Denver Julesburg and Permian basins, and the Eagle Ford shale formation ( 148 DCN 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., Marcellu s 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 83 

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

, disposal well s) are not available where they are operating ( 148 DCN SGE 00710; 138 DCN SGE 00139; 25 DCN SGE 00182 ).

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 accept 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 nonhazardous industrial wastes, hazardous or non

- hazardous industrial wastewater, and/or used material received from offsite (40 C .F. R 437.2(c)). CWT facilities that

acc ept UOG extraction wastewater are sometimes run by the UOG operator and are sometimes

81 This is primarily because many operators rent fracturing tanks on a per

- tank

- per

- day basis. Even if operators purchase fracturing tanks instead, the effective cost to the operator still increases as stor age time increases.

82 Transportation distances may also affects costs.

83 Discharge includes both indirect discharge (to a POTW) and direct discharge (to surface water).Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 99 run by an entity not engaged in the oil and gas extraction business. Since UOG development ramped up in the late 2000s, new CWT facilities that accept extraction wastewat er from operators have become available ( 43 DCN SGE 00596) , mostly in areas with less underground injection capacity . In addition, many UOG operators ha ve vertically integrated their companies by purchasing or constructing their own CWT facilities (see Section D. 2.2 ) ( 43 DCN SGE 00596). Some CWT facilities accept only oil and gas wastewater while other s accept a variety of industrial wastewater . They follow different discharge practices:

• Zero discharge (treated wastewater is typically reused in fracturing or disposed of in

an Class II disposal well)

• Discharge (to surface waters or POTWs)

• Multiple disch arge options (a mix of d ischarge and zero discharge )

Pollutant discharges to surface waters or to POTWs from CWT facilities are not subject
to the O il and G as E xtraction ELGs (40 C.F.R. part 435) . Rather, they are subject to the Centralized Waste Treatment ELGs promulgated in 40 C.F.R. p art 437. Unlike the Oil and Gas Extraction ELGs, 40 C.F.R. p art 437 includes limitations and standards for both direct and indirect dischargers

. The level of treatment CWT facilities use depends on the fate of the treated wastewater. The two primary types of treatment technologies are non- TDS removal technologies 84 

### and TDS removal technologies 85



### , defined in Section D. 3

. In general, CWT facilities typically use non

TDS removal technologies for treatment before reuse/recycle and TDS removal technologies for
treatment before indirect or direct discharge.

4.1.1 Z ero Discharge CWT Facilities
After treatment, a zero dis charge CWT facilit y does not discharge the wastewater to surface water or a POTW. Instead, it typically return s the wastewater to UOG operators for reuse/recycle in fracturing. 86 

### CWT facilities that accept UOG extraction wastewater from operators and fall into this category typically allow them to unload a truckload of wastewater for treatment and take a load of treated wastewater on a cost

- per

- barrel b asis ( 37 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 wastewater. Most of these CWT facilities provide mi nimal (i.e., non

- TDS removal) treatment

, but some also use TDS

- removal technologies

.

4.1.2 Discharging CWT Facilities

Some CWT facilities discharge treated wastewater either indirectly to a POTW or directly to surface waters. As discussed in Section A. 2.1.1 , discharges from the CWT facility to

84 Examples of CWT facilities using this level of treatment are described in 191 DCN SGE00 625; 178 DCN SGE00 635, 37 DCN SGE00 245, 116 DCN SGE00 481, and 89 DCN SGE00 379.

85 Examples of CWT facilities using this level of treatment are described in 93 DCN SGE00 476, 23 DCN SGE00 366, 19 DCN SGE00 367, and 140 DCN SGE00 374.

86 Zero discharge CWT facilities may also evaporate the wastewater or send it to underground injection wells ( 205 DCN SGE00 374).Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 100 the POTW are controlled by an Industrial User Agreement that must incorporate the pretreatment standards set out in 40 C.F.R. p art 437 and requirements set out in 40 C.F.R. 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 C.F.R. 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, new state regulations in Pennsylvania, for example, have led direct

- discharging CWT facilities to use more TDS removal technologies ( 43 DCN SGE00596).

4.1.3 CWT Facilities with Multiple Discharge Options Some discharging 83 

### CWT facilities may also recycle a portion of the treated wastewater

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

- TDS and TDS removal technologies. One such facility is Eureka Resources in Williamsport, Pennsylvania. The Eureka C WT facility holds a General Permit ( WMGR123NC005) 87 

### from PA DEP that includes limits 88 

### 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 technolog y (evaporation/condensation) ( 180 DCN SGE 00300). O perators may take a load of treated wastewater for reuse/recycle that the facility treated using the non

- TDS removal technology train or using the entire treatment train (both non

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

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

4.2 Active CWT Facilitie s Accepting UOG Extraction Wastewater

To date

, the EPA has identified 73 CWT facilities that have accepted or plan to a ccept UOG extraction wastewater. Most of them acc ept only oil and gas wastewater

, not wastewater from other industries. Table D-6 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 ty pe ( 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 29,0 00 barrels ) per day ( 43 DCN SGE 00596). 89



### To generate Table D -6

, the EPA used information from state agencies (e.g., PA DEP statewide waste reports), CWT facility websites, and news articles. The collected information is documented in a separate memorandu m titled Analysis of Centralized Waste Treatment (CWT) Facilities Accepting UOG Extraction Wastewater ( 43 DCN SGE 00596) , which list s known CWT faciliti es along with information such as permit number, location, treatment capacity, and treatment level when available

. Because few states keep comprehensive lists of CWT facilities

,

87 More information available online at: http://files.dep.state.pa.us/Waste/Bureau%20of%20Waste%20Management/WasteMgtPortalFiles/SolidWaste/Resid ual_Waste/GP/WMGR123.pdf

. 88 In addition to setting discharge limitations to the nearby POTW, Eureka’s General Permit allows it to treat wastewater for reuse purposes only, in which ca se there are no actual limits.

89 To exclude outliers, the EPA presents the 10 th and 90 th percentiles of reported treatment capacities at CW T facilities

.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 101 Table D-6 likely underestimate s the number of CWT facilities accepting UOG extraction
wastewater

. 90



### Table D

- 6 . Number , by State, of CWT Facilities That Hav e Accepted or Plan to Accept UOG Extraction Wastewater

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 23 7 (3) 6 0 0 3 (1) 3 9

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 45 13 7 0 1 7 73

Source s : 43 DCN SGE 00596

a— Number of facilities includes facilities that have not yet opened but are under construction, pending permit approval, or are in the planning stages. Facilities that are not accepting UOG extraction wastewater but plan to in the future are noted parenthetically.



### This information shows that CWT facilities have develop ed in regions of increasing oil and gas production , especially in areas where capacities for other management practices are less available ( 138 DCN SGE 00139 ). To illustrate this, the EPA analyzed the number of act ive CWT facilitie s available to Marcellus s hale and Utica s hale operators where there are few disposal wells in some parts of the region

. 91 

### 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 -8 shows the trend over time of active CWT facilitie s available to operators in the Marcellus and Utica s hale s, 92 

### along with the number of UOG wells dr ille d. The number of CWT facilities available to operators in the Marcellus and Utica s hale s has increased with the number of wells drilled . The EPA observed a similar trend in the Fayetteville s hale formation in Arkansas. Although Arkansas has several hun dred active disposal wells, only 24 wells are located in the northern half of the state in close proximity to Fayetteville shale wells ( 41 DCN SGE 00736). As a result, the largest active operator in the Fayetteville shale has constructed three CWT facilities . The EPA anticipates that

90 The information in Table D -6 is current as of 2013; it is possible that since 2013 some listed CWT facilities have closed and/or some CWT facilities not listed have begun operation

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

92 The Marcellus and Utica s hale formations are in the Appalachian b asin.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 102 more CWT facilities will become available near UOG formations where access to disposal wells is limited as additional UOG wells are drilled.

Source s: 43 DCN SGE 00596



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

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 discharge to POTWs. Th is practice can be problematic because POTWs do not use technolo gies 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 downstrea m water use ( 80 DCN SGE 00286; 109 DCN SGE 00345; 139 DCN SGE 00579; 82 DCN SGE 00531 ; 226 DCN SGE 00633 ; 77 DCN SGE01077 ). 93

93 GWPC, 2014 ( 77 DCN SGE01077) states, “For a POTW t o 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 pr oduced 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

wa ter body.”Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 103 This section provides an overview of typical treatment processes used at POTWs, a discussion of how constituents commonly found in UOG extraction wastewater interact with POTWs ( including examples of POTWs that have been used to manage UOG extraction
wastewater ) , a review of POTWs that have accepted UOG extraction wastewater , and the current status of UOG extraction wastewater discharges to POTWs

.

5.1 POTW Background and Treatment Levels

40 C.F.R. p art 403.3(q) defines a POTW as “a treatment works as defined by section 212 of the [Clean Water] Act

, 94 

### which is owned by a State or municipality.” POTWs are designed to treat residential, commercial, and industrial wastewater, focusing on t he removal of suspended solids and dissolved organic constituents. Table D-7 presents concentrations of weak, moderate, and strong domestic wastewater as would be typ ically experienced by a POTW (i.e., influent).

Table D

- 7

. Typical Composition of Untreated Domestic Wastewater

Constituent Concentrations (mg/L)

Weak Moderate Strong

TDS 270 500 860

COD 250 430 800

TSS 120 210 400

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

Nitrates 0 0 0

Nitrites 0 0 0

Source: 119 DCN SGE 00 167 Abbreviation: mg/L

— milligrams per liter



### T ypical treatment processes used at POTWs are categorized into the following levels :

• Primary treatment , capable of removing some suspended solids and organic matter from influent wastewater using unit operations such as screening and clarification.

• Secondary treatment , capable of removing additional suspended solids and biodegradable organic matter from in fluent wastewater using biological treatment processes, such as activated sludge and trickling filters. Secondary treatment is sometimes followed by chlorination or ultraviolet (UV) disinfection to reduce microbial pathogens.

94 Section 212 of the CWA defines the term “treatment works” as “any devices and systems used in the storage, treatment, recycling, and reclamation of municipal sewage or industrial wastes of a liquid nature .”Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 104 • Tertiary (advanced) treatment , capable of remov ing other pollutants, such as nutrients, not removed in secondary treatment using processes such as nitrification/denitrification and activated carbon adsorptio n ( 119 DCN SGE 00167).

Figure D-9 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 also shows sludge treatment (gravity thickening, digestion, filter press) before use/disposal (e.g., land application).

Sourc e: 165 DCN SGE 00602



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

In general, the average POTW in the United States has primary and secondary treatment. In addition to treated wastewater, POTW treatment processes produce residual solids (sludge), including biosolids generated during biological treatment and other suspend ed material removed in clarifiers. Most POTWs apply additional treatment to the sludge, typically gravity thickening followed by stabilization (e.g., anaerobic digestion) and dewatering (e.g., filter press). After this additional treatment, most sludge is either put to a beneficial use (e.g., land application, soil enrichment) or disposed of in a landfill or incinerator ( 161 DCN SGE 00599).

Table D-8 shows typical removal percentages for various constituents. As discussed, removal rates for suspended solids are high (90 percent for TSS) and removal rates for metals

a nd salts are low (6 percent for cobalt, 8 percent for TDS ).Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 105 Table D

- 8 . Typical Percent Removal Capabilities from POTWs with Secondary Treatment

Constituent POTW Percent Removal (%) Constituent POTW Percent Removal (%)
Aluminum 91 Mercury 72
Ammonia a s n itrogen 39 Molybdenum 19 Antimony 67 Naphthalene 95
Arsenic 66 Nickel 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
Chlorobenzene 96 Sulfate 85
Chloroform 73 Sulfide 57
Chromium 80 TDS 8
Cobalt 6 Thallium 72

COD 81 Tin 42 Copper 84 Titanium 92 Cyanide 70 TOC 70 Ethylbenzene 94 Toluene 96
Fluoride 61 Total petroleum hydrocarbons 57

Iron 82 TSS 90
Lead 77 Vanadium 10 Magnesium 14 Xylenes (m+p, m, o+p, o) 65 to 95 Manganese 36 Zinc 79

Source: 164 DCN SGE 00600 Note: 164 DCN SGE 00600 references data from the November 5, 1999

, updated 50

- POTW study a nd the RREL database compiled for the CWT effluent guidelines.



### Table D-9 shows the breakdown of U.S. POTWs categorized according to their level of
treatment . As of 2008, s econdary treatment was the most common level of treatment at POTWs.

Table D

- 9 . U.S. POTWs by Treatment Level in 200 8

Treatment Level Percent of Facilities (%) Number of Facilities Design Capacity (MGD) Less than secondary (e.g., primary) 0.2 30 546 Secondary 49.4 7,302 17,765 Greater than secondary (e.g., tertiary, advanced) 34.3 5,071 23,710 No discharge 15.2 2,251 2,557

Partial treatment a 0.8 115 287

Total 99.9 14,769 44,866
Source: 166 DCN SGE 00603Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 106 a— These facilities provide some treatment to wastewater and discharge their effluent to other wastewater facilities for further treatment and discharge.

Abbreviation: MGD

— millio n gallons per day



### 5.2 History of POTW Acceptance of UOG Extraction Wastewater

As operators began extracting oil and gas from unconventional formations, UOG operators discharged wastewater to PO TWs in some cases ( 80 DCN SGE 00286; 109 DCN SGE 00345; 139 DCN SGE 00579). 95 

### The EPA located the most comprehensive data about this practice in Pennsylvania. Therefore, this subsection primarily discusses data from PA DEP

, though it also includes discussions about a few POTWs in West Virginia and New York . The PA DEP data indicate that the majority of UOG operators in Pennsylvania who decided to discharge to POTWs did so by 2008 96 

### ( 127 DCN SGE 00188 ). To identif y POTWs that accepted
wastewater from UOG operations, 97 

### the EPA reviewed the following sources:

• Notes from calls with regional and state pretreatment program coordinat ors ( 182 DCN SGE 00742, 192 DCN 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 ( 196 DCN SGE 00762)

• EPA Region 3’s website ( 174 DCN SGE 00368)

• Site visits, conference calls , and meetings w ith industry representatives ( 188 DCN SGE 00613; 38 DCN SGE 00521), UOG operators ( 191 DCN SGE 00625; 178 DCN SGE 00635; 179 DCN SGE 00275; 190 DCN SGE 00280), CWT facilities ( 181 DCN SGE 00299; 180 DCN SGE 00300; 37 DCN SGE 00245; 36 DCN SGE 00244), and Native American tr ibal groups ( 202 DCN SGE 00785 ).

• PA DEP’s statewide waste report data 98 

### ( 127 DCN SGE 00188 ; 46 DCN SGE 00739)

• The U.S. DOE’s 2010 Water Management Technologies Used by Marcellus Shale Gas Producers report ( 212 DCN SGE 00011)

• Publicly available data sources identified through Internet searches

The EPA compiled and analyzed much of these existing data in a separate document

, Publicly Owned Treatment Works ( POTW ) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction ( 52 DCN SGE00929 ). Thi s m emorandum is referenced throughout Section D. 5

.

95 EPA acknowledges that COG operator s are still using POTWs as a viable option for disposal of COG wastewater.

96 EPA did not identify any information indicating when POTWs in New York began accepting of UOG extraction wastewater. EPA also could not definitely determine when UOG operators in Pennsylvania began discharging UOG extraction wastewater at POTWs because the 2007 PA DEP Waste Report data are incomplete.

97 EPA could not determine the date when POTWs began accepting UOG wastewater in all instances. The EPA has documentation that all PO TWs in Pennsylvania stopped accepting UOG extraction wastewater by the end of 2011.

98 PA DEP’s waste report data provide wastewater volumes by well over time and management/disposal information as it was reported by the oil and gas well operator to PA DEP. ERG’s memorandum titled Analysis of Pennsylvania Department of Environmental Protection’s (PA DEP) O il and Gas Waste Reports provides more detail ( 46 DCN SGE00 739).Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 107 The EPA identified POTWs that, at one time, accepted wastewater from UOG operators generated by Marcellus shale wells

. Table D-10 presents information about POTWs that have accepted UOG extraction wastewater directly from onshore UOG operators.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 108 Table D

- 10

. POTWs That Accepted UOG Extraction Wastewater from Onshore UOG Operators

Facility Name NPDES Permit No. City State POTW Currently Accepting UOG 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 Vernon Borough PA0092355 Belle Vernon PA No 2009 Borough of Jersey Shore PA0028665 Jersey Shore PA No 2010

Brownsville Municipal Authority PA0022306 Brownsville PA No 2008 California Borough PA0022241 California PA No 2009 Charleroi Borough PA0026891 Charleroi PA No 2008 City of Auburn NY0021903 Auburn NY No 2008 City of Johnstown Redevelopment Authority

— Dornick Point PA0026034 Johnstown PA No 2010

City of McKeesport PA0026913 McKeesport PA No 2011

City of Watertown SPDES NY 002 5984 Watertown NY No 2010

Clairton Municipal Authority PA0026824 Clairton PA No 2011 Clearfield Municipal Authority PA0026310 Clearfield PA No 2009 Dravosburg PA0028401 Dravosburg PA No 2008 Lock Haven City STP PA0025933 Lock Haven PA No 2008 Mon Valley Sewage Authority PA0026158 Donora PA No 2008 Moshannon Valley Authority STP PA0037966 Rush Township PA No 2009 Reynoldsville Sewer Authority PA0028207 Reynoldsville PA No 2011 Ridgway Borough PA0023213 Ridgway PA No 2011 Waynesburg Borough Water System PA0020613 Waynesburg PA No 2008

Source: 52 DCN SGE 00929Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 109 Based on data collected through June 2014, the EPA concluded that none of the POTWs listed in Table D-10 currently accept wastewater directly from UOG operations. That is, no UOG extraction wastewater is currently being managed by discharging to any of the POTWs in this table. This is , in large part, a result of UOG operators’ compliance with PA DEP’s April 2011 request that they stop discharging UOG extraction wastewater to POTWs (see Section A. 2.2 ). PA DEP data indicate that UOG operators in Pennsylvania stopped sending their waste to POTWs in 2011 ( 127 DCN SGE 00188) . Furthermore, the EPA has not been able to identify any POTW in any state that is accepting UOG extraction wastewater directly from an operator. In addition, the EPA collected data about UOG operations on t ribal r eserva tions , UOG operators that are affiliated with Indian t ribes , and POTWs owned or operated by t ribes that may accept industrial wastewater ( 202 DCN SGE 00785 ). According to this information, there are no tribes operating UOG wells that discharge wastewater to POTWs

, nor are there any tribes that own or operate POTWs that accept UOG ex traction wastewater

. As such, the EPA concludes that operators have determined that discharge to a POTW is not a necessary and/or appropriate option for managing UOG extraction wastewater

.

The EPA is aware of a few cases where UOG operators discharge wastewater to CWT facilities for treatment and those CWT facilities discharge to POTWs

. As explained in Section A. 2.1.2 , such discharges are not subject to the ELGs for the oil and gas extraction category which is the subject of the proposed rule. Rather, discharges to POTWs from CWT facil i tie s are subject to ELGs for the Centr alized Waste Treatment Category (40 C.F.R. part 437).

The EPA reviewed PA DEP statewide waste reports ( 46 DCN SGE 00739 ) and discharge monitoring report (DMR) data ( 175 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 99 

### percentage of UOG extraction
wastewater accepted by the POTW as shown in Table D-11 . 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-11 also presents the year in which the maximum annual average daily volume 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 w astewater treated at the POTW is typically a small percentage (less than 1 percent )

. However , based on the data presented in Table D-11

, the contribution of UOG extraction wastewater was much higher (e.g ., up to 21 percent ) for some POTWs for some years

.

99 PA DEP w aste r eports provided the total volume of UOG extraction wastewater delivered to the POTW each year. The EPA divided the annual volume by 365 to calculate the annual average daily flow of UOG extraction
wastewate r accepted at the POTW.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 110 Table D

- 11 . Percentage of Total POTW Influent Wastewater Comp o sed of UOG Extraction W astewater at POTWs Accepting W astewater from UOG Operators

POTW Name NPDES Permit No. Maximum Annual Average Daily UOG Extraction W astew ater

Volume Accepted

( gpd ) 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 Annual Average Daily U OG Extraction W astew ater

Volume Belle Vernon Borough PA0092355 93,000 0.44 21 b 2008 California Borough PA0022241 84,000 0.60 1 4 2008 Charleroi Borough PA0026891 180,000 1.7 4 10 2008 Waynesburg Borough Water System PA0020613 56,000 0.58 9. 7 2008

Mon Valley Sewage Authority PA0026158 67,000 3.4 7 1.9 2008

City of Johnstown Redevelopment Authority

— Dornick Point PA0026034 130,000 9.4 7 1.4 2008

Brownsville Municipal Authority PA0022306 9,400 0.88 1. 1 2008

City of Auburn NY0021903 1,800 0.20 0.91 2008 Borough of Jersey Shore PA0028665 6,000 0.69 0.88 2008 Allegheny Valley Joint Sewer Authority PA0026255 30,000 4.30 0.69 2008

Ridgway Borough PA0023213 4,500 0.97 0.47 2010 Dravosburg PA0028401 1,300 0. 33 0. 39 2008 Clairton Municipal Authority PA0026824 12,000 4.1 5 0.30 2009

Moshannon Valley Authority STP PA0037966 3,400 2.2 9 0.15 2008

Reynoldsville Sewer Authority PA0028207 930 0.80 0.12 2010

City of McKeesport PA0026913 11,000 16. 25 0.07 2009

Bellefonte Water Treatment Plant PA0020486 1,400 1.99 0.07 2008

Lock Haven City STP PA0025933 1,800 2.8 4 0.06 2008 Altoona Water Authority PA0027014 2,500 6.8 6 0.04 2011

Source s : 52 DCN SGE00929

a— This is the total influent wastewater flow to the POTW (domestic sewage and UOG extraction wastewater) in the year associated with the maximum UOG extraction wastewater volume received by the POTW

. b— The average total flow through the POTW (MGD) in 2008 was calculated using the average of four months of available data (September 2008 through December 2008). Abbreviations: gpd

— gallons per day; MGD

— million gallons per dayChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 111 5.3 How U OG Extraction Wastewater Constituents Interact with POTWs

POTWs are likely effective in treating only some of the pollutants in UOG extraction
wastewater. Most POTWs are designed to primarily treat domestic wastewater. They typically provide at least secondary- level treatment and, thus, are designed to remove suspended solids and organic material. However, secondary treatment technologies are not designed to treat the high concentration s of TDS, radioactive constituents

, metals

, chlorides, sulfates, and other dissolved inorganic constituents found in UOG extraction wastewater

. 100 

### Because they are not typical of POTW influent wastewater, UOG extraction wastewater constituents:

• May be discharged, untreated, from the POTW to the receiving stream

• May disrupt the operation of the POTW (e.g., by exceeding permit limits for BOD 5 

### or TSS in discharges, by inhibiting sludge settling)

• May accumulate in sludge, l imiting its use

• May facilitate the formation of disinfection byproducts (DBPs)

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

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

• Technical evaluations of the impact of oil and gas wastewater pollutants on POTW unit processes completed in response to Administrative Orders (AOs) 101 

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

• Pass through analyses completed by 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 ( 205 DCN SGE 00956 ; 18 DCN SGE 00966) , information and studies on the treatability of these constituents by POTWs ( or their impacts on POTWs ) are similarly relevant when those POTWs are accepting only COG extraction wastewater and/or a combination of COG and UOG extraction wastewater

. In most of the case studies presented in this chapter, the POTWs that were accepting UOG extraction wastewater were also accepting COG wastewater.

The E PA also reviewed common textbooks on wastewater treatment 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

100 Some POTWs provide tertiary treatment, which removes additional nutrients as well as constituents targeted for removal using secondary treatment. Similar to secondary treatment, tertiary treatment processes are not designed to
tre at the high concentrations of TDS, radioactive constituents, metals, chlorides, sulfates, and other dissolved inorganic constituents found in UOG extraction wastewater.

101 PA DEP issued AOs to many POTWs in Pennsylvania that were accepting or suspect ed to b egin accepting wastewater from UOG operations.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 112 contribute to TDS (164 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 POTWs from CWT facilities that accept ed 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-12 s ummarizes the POTW studies and analyses that are presented in Section D. 5.3.1 and Section D. 5.3.2 . Section D. 5.3.1 discusses the potential for UOG pollutants to be discharged, untreated

, from POTWs . Section D. 5.3.2 discusses the potential for UOG wastewater pollutants to cause or contribute to inhibition and disruption at POTWs.

Table D

- 12

. Summary of Studies About POTWs Receiving Oil and Gas Extraction Wastewater Pollutants

POTW Summary of Study Findings POTWs Accepting Wastewater from Oil and Gas Operators Clairton, PA

, POTW Treatment system influent and effluent samples show minimal or no TDS and chloride removals. See Section D. 5.3.1.1

. McKeesport, PA

, POTW Treatment system influent and effluent samples show 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

. See Section D. 5.3.1.1

. Charleroi, PA

, POTW Treatment system influent and effluent samples show minimal or no TDS removal. The POTW rejects influent oil and gas wastewater with TDS greater than 30,000 mg/L and/or chloride greater than 15,000 mg/L. S ee 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

. Waynesburg, PA

, POTW High

- salinity UOG produced water impacted biological growth in trickling filter. See Section D. 5.3.2.1

.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 113 Table D

- 12

. Summary of Studies About POTWs Receiving Oil and Gas Extraction Wastewater Pollutants

POTW Summary of Study Findings POTWs Accepting Wastewater Containing UOG Extraction Wastewater Pollutants from Other Industrial Sources (e.g., CWT Facilities) Franklin, PA

, POTW The Franklin POTW received industrial discharges from the Tri

- County CWT facility (which receive d oil and gas extraction wastewater). The CWT facility targeted removal of TSS and oil and grease by filtration, flocculation, and skimming.
TDS and chloride concentrations in effluent from the POTW were higher when th e POTW was accepting industrial wastewater from the Tri

- County CWT facility and decreased after it stopped accepting wastewater from this CWT facility

. See Section D. 5.3.1.2

. Wheeling, WV

, POTW The Wheeling POTW receive d oil and gas extraction wastewater from operators as well as industrial wastewater discharges from the Liquid Asset Disposal (LAD) CWT facility. The LAD CWT facility uses ultra

- filtration, ozonation, and reverse osmosis to target the removal of chlorides p rior to discharge to the Wheeling POTW.
The POTW experienced h igher concentrations of chloride in POTW effluent while accepting UOG extraction wastewater from UOG operators and from the LAD CWT facility (which receives oil and gas extraction wastewater). S ee Section D. 5.3.1.2

. The POTW experienced interference with biological treatment from accepting UOG extraction wastewater pollutants via the LAD CWT facility ’s industrial discharge. The POTW also experienced an up s et that required the introduction of a “seed” sludge to maintain microbial activity in treatment processes. See Section D. 5.3.2.2

. Warren, OH

, POTW The Warren POTW receives industrial wastewater discharges from the Patriot CWT facility. The Patriot CWT facility uses primary treatment processes (e.g., settlement tanks, clarifier tanks) to target the removal of suspended solids and metals from UOG extraction wastewater before discharge to the Warren POTW

. Influent and effluent TDS and chloride concentrations at the Warren POTW show minimal or no TDS or chloride removals. See Section D. 5.3.1.2

. B r ockway, PA

, POTW The Brockway POTW received natural

- gas

- related wastewater treated by the Dannic Energy Corporation CWT facility. 102

The POTW experienced higher concentrations of TDS in POTW effluent while accepting industrial discharges from the CWT facility containing oil and gas extraction wastewater pollutants. See Section D. 5.3.1.2

. The POTW experienced scum formation on clarifiers as well as increased sludge generation and high concentrations of barium in the sludge, while treating industrial discharges from the CWT facility. Se e Section D. 5.3.2.2

. New Castle, PA

, POTW The New Castle POTW received industrial wastewater from the Advanced Waste Services CWT facility (which treats oil and gas wastewater). The CWT facility uses the following treatment processes: solids settling, surface oil skimming, pH adjustment, and ( occasional ) flocculation.

The POTW experienced numerous effluent TSS permit limit exceedances while accepting industrial discharges from the CWT facility . The CWT facility discharge was associated with adverse impacts on sludge settling in final clarifier s at the POTW

. See Section D. 5.3.2.2

.

102 EPA could not find information about the treatment processes used by the Dannic Energy Corporation CWT facility.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 114 5.3.1 UOG Extraction Wastewater Constituents Discharged Untreated from POTWs

As described in Section D. 5.3

, the EPA reviewed studies and analyses relevant to POTWs accepting wastewater containing pollutants found in UOG extraction wastewater

. Consistent with wastewater treatment literature, t he PO TWs 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

Th e Clairton POTW discharges to Peters Creek

, which flows into the Monongahela River and treats influent wastewater using screening and grit removal, comminutor s (i.e., grinder s), 103 

### aeration basins, clarifiers, activated sludge, aerobic digestion, and chlorine disinfection. The Clairton POTW is permitted to treat a maximum of 6 MGD ( 107 DCN 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 accepts to a flow rate no greate r 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. T he technical evaluation noted ( 107 DCN SGE 00758):

The results of the samples taken and analyzed through the CMA [Clairton Municipal Authority] WWTP indicate that there is little to no reduction in concentration of TDS and chlorides through the plant processes. This is not unexpected as conventional sewage treatment facilities are not designed to remove dissolved constituents such as TDS and chlorides.

Figure D-10 shows the results from the 24- hour composite sampling that occurred over five days in December 2008. According to PA DEP data ( 46 DCN SGE 00739), in 2008, the Clairton POTW was accepting oil and gas wastewater amounting to an average of 0.0 5 percent of the POTW flow. Looking at the average measured concentrations, t he results indicate littl e or no removal of TDS or chloride.

103 A comminutor is a machine that reduces the particle size of wastewater solids using a cutti ng device.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 115 Figure D-10. Clairton POTW: Technical Evaluation of Treatment Processes ’ Ability to Remove Chlorides and TDS Source s : 52 DCN SGE 00929 Note: The data presented in this figure are based on five 24

- hour composite samples taken from December 8, 2008

, through December 12, 2008.



### Clair ton POTW’s consultant completed a p ass through a nalysis in August 2009 ( 137 DCN SGE 00748 ). 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 the oil and gas wastewater routinely accepted by the CMA POTW

. ” Therefore, the EPA only included the wastewater characteristic data for O&G Well No. 1, as reported in the pass through analysis (see Table D-13 ). Th e pass through analysis assumes zero percent removal of TDS at the POTW and concludes that ( 137 DCN SGE 00748 ):

The result of the mass balance analyses clearly indicates that TDS is untreated resulting in a “pass-through” to receiving waters...The hypothetical mass balance review...indicates that if higher concentrations of TDS are introduced into the POTW, the concentration and loading of TDS to the receiving waters increases proportionally.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 116 Table D

- 13 . Clairton Influent Oil and Gas Extraction Wastewater Characteristics

Parameter Wastewater Concentrations (mg/L)

O&G Well No. 1
Barium 294
Calcium 3,060
Chloride 44,700 Magnesium 1,210
Sodium 84,500

TDS 76,000

TSS 1,600

Source: 137 DCN 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, activated sludge

, aerobic digestion, and chlorine disinfection ( 108 DCN SGE 00745). The McKeesport POTW began accepting COG

wa stewater in 2008 and UOG extraction wastewater in 2009. The POTW stopped accepting both COG and UOG extraction wastewater in December 2011 ( 46 DCN SGE 00739 ).

On October 23, 2008, PA DEP issued an AO to the McKeesport POTW that allowed it to accept oil and gas wastewater in amounts no greater than 1 percent of its average daily flow, among other requirements. The AO also required the POTW to evaluate the potential impacts of oil and gas production wastewater on its treatment processes. The POTW conducted this technical evaluation in November 2008. According to PA DE P data ( 46 DCN SGE 00739), in 2008, the McKeesport POTW was accepting only COG wastewater. The evaluation ( 106 DCN SGE 00757) noted:

The results of the samples taken and analyzed through the MACM [Municipal Authority of the City of McKeesport] WWTP indicate that there is no reduction in concentration o f TDS and chlorides through the plant processes. This is not unexpected as conventional sewage treatment facilities are not designed to remove dissolved constituents such as TDS and chlorides.

Figure D-11 shows the results from 24

- hour composite sampling over seven days in November 2008. The results indicate no removal of TDS or chloride . According to the manifests included in the technical evaluation ( 106 DCN SGE 00757 ), McKeesport treated trucked wastewater from conventional wells during the seven

- day sampling period. These wastewater sources are summarized in Table D-14

, below.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 117 Figure D-11 . McKeesport POTW : Technical Evaluation of Treatment Processes ’ Ability to Remove Chlorides and TDS Source s: 52 DCN SGE00929 Note: The data presented in this figure are based on seven 24

- hour composite samples taken from November 1, 2008

, through November 7, 2008.



### Table D

- 14 . Trucked COG Extraction Wastewater Treated at McKeesport POTW from November 1 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 3,780 155,000 4,886 November 6, 2008 Frac 4,620 20,000 771 November 7, 2008 Frac 4,620 20,000 771

Source : 108 DCN SGE 00745

a— According to data from the technical evaluation, some waste streams were referred to as “frac” and “flow

- back

, ” indicating that the co nventional wells were hydraulically fractured. Abbreviations: mg/L

— milligrams per liter; lbs

— pounds



### McKeesport POTW’s consultant completed a headworks loading a nalysis in March 2011 ( 108 DCN 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



### 118 the average removal percentages based on the sampling results. During the time of sampling, a combination of UOG and COG wastewater contributed no more than 1 percent of the average daily flow and municipal wastewater made up the remaining influent to the McKeesport POTW. Table D-15 presents the percent removals calculated during this analysis and shows that the POTW removed less than 7 percent of the influent TDS and less than 5 percent of the influent chloride. Effluent TDS concentrations ranged from 600 to 1,500 mg/L while the facility accepted both UOG and COG wastewater during the sampling period ( 108 DCN SGE 00745 ).

Table D

- 15

. McKeesport POTW Removal Rates Calculated for Local Limits Analysis

Parameter Removal Rates (%)
Sulfate 3.94
Chloride 4.44

TDS 6.43 Magnesium 6.62
Strontium 18.47

Bromide 26.99

Barium 71.64

Source: 108 DCN SGE00745 Note: The data presented in this table are based on timed composite samples obtained once a month for 12 months from February 2010 through January 2011.



### A 2013 study by Ferrar et al . ( 71 DCN SGE00525 ) analyzed constituents in effluent wastewater discharged from two POTWs in Pennsylvania, first while the POTWs accepted industrial discharges containing UOG extraction wastewater pollutants (either from a CWT facility or from a UOG operator) and again after the POTW s stopped accepting those industrial discharges

. The study included effluent sampling at th e McKeesport POTW in 2010 while the POTW was accepting UOG extraction wastewater. The study specifically reported that the facility was accepting UOG extraction wastewater during the sampling but did not mention COG
wastewater. B ased on PA DEP data, the EP A 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 tanke r trucks, was stored in holding tanks, then mixed with municipal wastewater in the primary clarifier. The study sampled POTW effluent in October 2010 , when the POTW was accepting UOG extraction wastewater and again in December 2011

, after the POTW had stopped accepting COG and UOG extraction wastewater

. 104 

### The study also collected one sample in November 2010 of UOG extraction wastewater before it was mixed with the municipal influent 105 

### (see Table D-16 ).

On October 19, 2010, when Ferrar et al

. collected their POTW effluent sample, they reported that the McKeesport POTW treated 13,020 gallons of UOG extraction wastewater, and the average da ily flow of the POTW was 9.6 MGD, indicating that the UOG extraction

104 The PA DEP waste reports data ( 46 DCN SGE00739 ) show that the McKeesport POTW stopped accepted COG and UOG wastewater after 2011.

105 Note that the one

- tim e sample of influent UOG extraction wastewater was not collected at the same time as either of the effluent sampling events.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 119 wastewater accounted for 0.14 percent of the total influent

. 106 

### The remaining influent wastewater consisted of municipal wastewater typically treated by the POTW (see Table D-7 for typical constituent concentrations in municipal wastewater).

Table D-17 shows the range and mean effluent concentrations , as measured by Ferrar et al., at the McKeesport POTW while they were accepting UOG extraction wastewater and after they had stopped accepting UOG extraction wastewater. As noted above, the study reported that the McKeesport POTW accepted an average daily flow of 9.6 MGD during the October 2010 sampling event. However, they did not report the average daily flow during the December 2011 sampling event . Although they reported that the facil ity 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-16 ) w ere not available. Therefore it is not possible to know whether the data presented in Table D-16 are representative of the UOG extract ion wastewater influent on the date of the effluent sampling presented in Table D-17 . As discussed in Section C. 3

, UOG extraction wastewater characteristics vary over time and from we ll to well.

Table D

- 16 . Constituent Concentrations in UOG Extraction Wastewater 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

Source: 71 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 collected from a UOG extraction wastewater holding tank before mixture and dilution with influent municipal

wastewater. Abbreviation: mg/L

— milligrams per liter

106 Ferrar et al. ( 71 DCN SGE00525 ) noted that since the total volume of UOG wastewater was released at one time, the actual dilution might have been 0.81 percent UOG wastewater in the effluent when it was dischar ged (8

– 12 hours later).Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 120 Table D

- 17

. McKeesport POTW Effluent Concentrations With and Without UOG Extraction Wastewater

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 Range 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

Source: 71 DCN SGE 00525

a— Organic analytes were not detected in samples. b— Sample date: 10/19/2010

. Reported values are based on the mean, minimum, and maximum of 24 samples taken for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water.

c— Sample date: 12/1/2011

. Reported values are based on the mean, mi nimum, and maximum of nine samples taken for each analyte taken over 24 hours. Effluent samples were collected just before mixing with surface water. d— The effluent concentrations of calcium and magnesium increased after the POTW had stopped accepting UOG extraction wastewater. Ferrar et al. ( 71 DCN SGE 00525 ) 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 maxim um monthly average design rate of 2.2 MGD. The Ridgway POTW uses screening and grit removal, an equalization tank, aeration tanks, clarifiers, a chlorination feed system, a chlorine contact tank, aerobic digesters, and a belt filter press. This POTW began accepting both COG and UOG extraction wastewater in 2009. It stopped accepting UOG extraction wastewater in 2011 but continued accepting COG wastewater
, and still was as of the end of 2013. 107 

### 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 average ( 46 DCN SGE 00739). The POTW’s total annual
average daily flow rate range s between 0. 8 and 1.3 MGD, based on 2008 to 2013 DMR data ( 175 DCN SGE 00608).

The EPA created Figure D-12 using the sampling data submitted in the EPA ’s DMR Loading Tool ( 175 DCN SGE 00608 ) and PA DEP waste reports data ( 46 DCN SGE 00739). Each effluent concentration data point represents the average of 12 monthly average data points as calculated and reported by the DMR Loading Tool. PA DEP waste reports provided the total

107 Ridgway’s October 2011 NPDES permit ( 131 DCN SGE00 755) notes that “no more than 20,000 gallons/day of natural gas wastewater from shallow well operations shall be treated at the facility. The acceptance of wastewater generated from shale oil extraction activities is prohibited .”Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 121 volume of UOG and COG wastewater delivered to th e POTW each year . The EPA divided the annual volume by 365 to calculate the annual ave rage daily flow

. As shown in Figure D-12 , 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

acce pting the greatest volume of oil and gas wastewater , including that from UOG operators

. As a point of comparison, in 2008, before accepting any oil and gas wastewater, the POTW experienced effluent TDS and chloride concentrations around 1,000 mg/L.

Figure D-12. Ridgway POTW: Annual Average Daily Effluent Concentrations and POTW Flows Sour ces: 52 DCN SGE 00929



### To com ply with the requirements of the Ridgway Borough Pretreatment Program, the Ridgway POTW completed a local limits analysis in January 2014 that included paired POTW influent and effluent data. The samples were collected for 10 consecutive days in Octo ber and November 2013 after the POTW stopped accepting UOG extraction wastewater but was still accepting COG wastewater . Of particular interest is the fact that Ridgway POTW’s contractorChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 122 estimated zero percent removals for TDS , chloride , and sulfate. All three of the se constituents are found in UOG extraction wastewater ( 88 DCN SGE 00756).

Charleroi, PA , POTW

The Charleroi POTW uses an equalization tan k, screening and grit removal, sedimentation, activated sludge, and chlorine disinfection. It began accepting both COG and UOG extraction wastewater in January 2005 and stopped accepting it in 2008 ( 11 DCN SGE 00751; 46 DCN SGE 00739) . 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 ( 46 DCN SGE 00739)

. The POTW’s average annual flow rate ranges between 1.4 and 1.9 MGD based on 2008 through 2013 DMR data ( 175 DCN SGE 00608) . The EP A identified case studies showing potential for both pass through (Section D. 5.3.1.1 ) and inhibition/disruption (Section D. 5.3.2.1 ) at the Charleroi POTW

. In 2008, PA DEP issued an AO requiring the Charleroi POTW to evaluate how accept ing oi l and gas production wastewater affect s its treatment processes , among other things ( 11 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 greater than 15,000 mg/L. As part of the technical evaluation, Charleroi sampled influent wastewater (including UOG extraction wastewater ) and effluent wastewater over a 24

- hour period. The total oil and gas was tewater treated during th is period was 150,650 gallons (3,587 barrels ) and the total wastewater treated was 1,559,000 gallons (37,120 barrels ). Therefore, the oil and gas wastewater accounted for 9.7 percent of the total influent to the plant during the sampling period ( 11 DCN SGE 00751). Table D-18 shows the results of the sampling and the calculated removal rates. The data show that TDS is not removed by the Charleroi POTW treatment processes.

Table D

- 18

. Charleroi POTW Paired Influent/Effluent Data and Calculated Removal Rates

Parameter Influent Concentration (mg/L) Effluent Concentration (mg/L) Removal Rate (%)
Aluminum 2.34 0.656 72 Ammonia, as N 14.4 4.52 68.6

Barium 0.177 0.171 3.4

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: 11 DCN SGE 00751 Abbreviation: mg/L

— milligrams per literChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 123 Clarksburg, WV, POTW

The Clarksburg POTW has a maximum capacity of 8 MGD and uses screening, a cyclone hydrogritter, clarifiers, aeration basins, and chlorine disinfection. The Clarksburg POTW started accepting “ gas well wastewater ” (i.e., brine) in July 2008 on a trial basis and continued through at least March 2009. Three frac tanks were set up on the treatment plant site and the brine (i.e., oil and gas extraction wastewater) was metered into the POTW’s pump station wet well at a constant continuous flow rate. Total POTW flow was at least 5 MGD. The amount of brine metered to the POTW was gradually increased to evaluate the effect it w ould have on the POTW performance . Clarksburg provided the following non

- comprehensive data about the quantity and chloride concentration of the brine metered to the POTW:

• July 2008, week 1: 10,000 gpd @ 50,000 mg/L chloride

• July 2008, week 2: 15,000 gpd @ 50,000 mg/L chloride

• July 2008, week 3: 17, 280 gpd @ 50,000 mg/L chloride

• July 2008, week 4: 25,000 gpd @ 50,000 mg/L chloride

• November 2008: 50,000 gpd @ 18,500 mg/L chloride

During the initial trial period in July 2008, the Clarksburg POTW superintende nt noted that effluent chloride concentrations “ exceeded the desired quantity of 235 mg/L a couple of times due to dry weather flows being below 5 MGD. ” He also noted that they would need to adjust the volume of brine in the influent to the POTW during low flow conditions , and that “ Chlorides are not removed at the facility, merely diluted to acceptable levels. ” This statement further supports the concept that TDS, of which the primary contributing ions in UOG extraction wastewater are chloride and sodium, passes through POTWs untreated.

After the trial period, Clarksburg contacted the WV DEP about modifying its NPDES permit to allow acceptance of gas wastewater. The DEP told the Clarksburg POTW that they could continue accepting the gas wastewater as long as they were not violating their existing effluent limitations ( 21 DCN SGE 00749; 121 DCN SGE 00552). In July 2009, WV DEP sent a letter to the Clarskburg Sanitary Board with a list of requirements that would be imposed, if they decided to accept oil and gas related wastewater ( 221 DCN SGE01113). The le tter also stated that

...WVDEP discourages POTWs from accepting wastewater from oil and gas operations such as...marcellus shale wastewaters because these wastewater essentially pass through sewage treatment plants and can cause inhibition and interference with treatment plant operations. The wastewaters from these types of operations contain high levels of chloride, dissolved solid, sulfate, and other pollutants. POTWs provide little to no treatment of these pollutants and could potentially lead to water quali ty issues in the receiving stream.

In April 2013, WV DEP verified that no POTWs in WV were accepting UOG extraction wastewater ( 196 DCN SGE 00762 ; 198 DCN SGE 00766).Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 124 5.3.1.2 Case Studies About POTWs Accepting Wastewater from Other Industrial Sources Containing UOG Pollutants

Franklin Township, PA , POTW

The Franklin Township POTW discharges to the lower fork of Ten Mile Creek, a tributary to the Monongahela River

, and treats influent wastewater using aeration, rotating biological contactors, clarification, filtration, and chlorination ( 74 DCN SGE 00746). The Franklin Township POTW accepted industrial wastewater from the Tri

- County Wastewater CWT facility until March 2011. During that time, the Tri

- County C WT 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 remain ed in the treated effluent from the CWT facility . The industrial wastewater received from Tri

- County Wastewater a ccounted for approximately 5.4 percent of the Franklin POTW’s 0.982 MGD effluent by volume in November 2010 ( 71 DCN SGE 00525).

On December 4, 2008, the Franklin POTW entered into a Consent Order and Agreement with PA DEP 108 

### 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 Facil ity] currently has treatment facilities for the removal of Total Dissolved Solids.

Ferrar et al . ( 71 DCN SGE 00525 ) 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-19 shows the mean and range of effluent concentrations at the Franklin Township POTW during the period it accepted industrial wastewater from the CWT facility and after they stopped. Ferrar et al. analyzed pollutants typically found in UOG extraction wastewater ; they report a mean effluent TDS concentration of 3,860 mg/L from the Franklin Township POTW while it was accepting
wastewater from the Tri

- County CWT facility and a mean effluent TDS concentration of 398 mg/L from the POTW after it stopped. The mean effluent concentrations for all pollutants presented in Table D-19 were higher when the POTW was accepting the industrial di scharge from the Tri -C ounty CWT facility

, suggesting that pollutants were discharged from the POTW without treatment. Based on the treatment technologies currently in place at the Franklin Township POTW, one would expect little to no treatment of the commo n constituents in UOG extraction wastewater. Ferrar et al. concluded :

This research provides preliminary evidence that these and similar WWTPs may not be able to provide sufficient treatment for this wastewater stream, and more thorough monitoring is recommended.

108 PA DEP had issued an AO to the Franklin POTW in October 2008 , but the Consent Order and Agreement superseded that order

.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 125 Table D

- 19

. Franklin Township POTW Effluent Concentrations With and Without Industrial Discharges from the Tri -County CWT Facility

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

– 36.6 8.63 8.04

– 9.11 Manganese 0.228 0.204

– 0.249 0.112 0.102

– 0.144
Strontium 48.3 41.8

– 56.1 0.236 0.226

– 0.249

Bromide 20.9 14.3

– 28.0 <0.016 <0.016
Chloride 2,210 1,940

– 2,490 61.9 57.5

– 64.6

Sulfate 137 117

– 267 65.6 60.0

– 75.0

TDS 3,860 3,350

– 4,440 398 376

– 450

Source: 71 DCN 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 collected just before mixing with surface water. Abbreviation: mg/L

— milligrams per liter



### Wheeling, WV, POTW

The Wheeling POTW has primary and secondary treatment operations, including primary clarification, solids and floatable materials removal, and disinfection ( 115 DCN SGE 00999). The Wheeling POTW accepted industrial wa stewater from the Liquid Asset Disposal (LAD) CWT facility through August 2009 109 

### and wastewater directly from UOG operators in 2008 110 

### . The LAD CWT facility accepted a variety of wastewater from the following sources: sewage facilities, storm water from an in ternational airport, and gas well development and production wastewater, among others. The LAD CWT facility is a SIU and was authorized to discharge into the Wheeling, WV POTW (SIU Permit No. 0014) ( 219 DCN 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 ( 101 DCN SGE 00996).

The EPA analyzed sampling data submitted in its DMR Loading Tool ( 175 DCN SGE 00608 ) and PA DEP w aste reports data ( 46 DCN SGE 00739) and found that the effluent concentrations of chloride experienced by the Wheeling POTW in 2008 were higher when it was accepting UOG extraction wastewater and industrial discha rges from the LAD CWT facility than

109 EPA did not identify the date on which the Wheeling POTW began accepting wastewater from the LAD CWT facility. However, the LAD CWT SIU Permit No. 0014 was issued in August 2004 ( 22 DCN SGE01000).

110 The Wheeling POTW may have accepted UOG extraction wastewater directly from operators in years other than 2008, but EPA only identified acceptance directly from operators in 2008 ( 127 DCN SGE 00188 ).Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 126 after it stopped. In 2008, the POTW accepted an average of 5,400 gallons/day of UOG extraction wastewater and had an average effluent chlo ride concentration of 650 mg/L . Comparatively , in 2011, the POTW did not accept an y UOG extraction wastewater and had an average effluent chloride concentration of 130 mg/L

. 111 

### Data from an August 2009 letter from WV DEP to the City of Wheeling states ( 222 DCN SGE01114)

The agency has determined that the following pollutants are of concern associated with oil and gas related wastewaters and may have a potential for inhibition, interference, and pass through: total dissolved solids (TDS), sulfate, chloride...zinc...copper...barium ...total suspended solids, iron...benzene...strontium...gross alpha radiation, gross beta radiation, and radium 226 + radium 228. In addition to the potential for inhibition, interfe rence, and pass through, these pollutants may also have an impact on sludge disposal requirements.

Additional data from a 2011 Consent Order from WV DEP to the Wheeling POTW indicates that the LAD CWT facility exceeded its 9,000

- pound daily chloride limitation, in violation of its SIU permit, 50 times between January 8, 2009

, and February 4, 2010 ( 219 DCN SGE 00485). Therefore, the UOG extraction wastewat er 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 residual s are thickened by dissolved air flotation, dewatered using a belt filter press, stabilized with lime, and disposed of by land application or by distribution and marketing of usable end products.

In May 2009, the Warren POTW and its customer, the Patriot W ater Treatment CWT facility

, 112 

### began discussions with the Ohio EPA about accepting UOG produced water. Patriot planned to accept UOG produced water from shale gas operations, treat the wastewater to remove heavy metals and other constituents, and discharge the treated industrial wastewater to the Warren POTW. In preparation for acceptance of treated industrial wastewater from the CWT facility that would contain pollutants found in UOG produced water

, the Warren POTW undertook a pilot study to show that accep ting wastewater containing pollutants found in UOG produced water would not cause any problems with Mahoning River water quality. Patriot’s treatment of UOG produced water includes reduction in heavy metal concentration, but not TDS or chloride. The Ohio E PA worked with Patriot and the Warren POTW to develop a pilot treatment study that evaluated the effects of pretreated UOG produced water on the POTW. The

111 The data about quantities of UOG extraction wastewater accepted by the Wheeling POTW are from the PA DEP waste report data and are reflective of volumes of UOG extraction wastewater accepted from UOG operators in Pennsylvania. The Wheeling POTW may be acc epting additional UOG extraction wastewater from UOG operators in West Virginia or other nearby states; these volumes of wastewater are not captured in this discussion.

112 The Patriot CWT facility uses primary treatment processes (e.g., settlement tanks, cl arifier tanks) to target the removal of suspended solids and metals prior to discharge.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 127 study also evaluated the receiving stream (Mahoning River) water quality, upstream and downstream of the POTW discharge ( 5 DCN SGE 00497 ; 35 DCN SGE 00522 ).

The pilot study began on February 9, 2010, and ran for eight weeks. It focused on collecting data from the Warren POTW and did not include sampling at the Patriot CWT facility

. The summarized TDS and chloride data from the study are presented in Table D-20

. The Warren POTW reported typical flow rates of 13.38 MGD and accepted the following volumes of wastewater from the Patriot CWT facility over the eight week s (percentage of total POTW flow accounted for by Patriot CWT facility ’s industrial wastewater is noted parenthetically) 113 

### ( 193 DCN SGE 00616 ):

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

• Week 2: 5 days @ 40,000 gallons (0.30 percent )

• Week 3: 5 days @ 60,000 gallons (0.45 percent )

• Week 4: 5 days @ 80,000 gallons (0.60 percent )

• Week 5: 5 days @ 100,000 gallons (0.75 percent )

• Week 6: 5 days @ 100,000 gallons (0.75 percent )

• Week 7: 5 days @ 100,000 gallons (0.75 percent )

• Week 8: 5 days @ 100,000 gallons (0.75 percent )

Table D-20 shows the average paired influent and effluent TDS concentrations measured prior to start up and during the pilot study. Baseline samples were collected when the POTW was not accepting wastewater from the Patriot CWT facility . The pilot study description states that the influent samples (baseline and pilot study) include only municipal influent and do not include any wastewater from the Patriot CWT facility

. 114 

### The data show that TDS and chloride concentrations increased in the influent and effluent samples over t ime both during the baseline sampling and after the Warren POTW accepted wastewater from the Patriot CWT facility . The effluent concentrations of TDS and chloride increased at higher percentages over the influent concentration during the pilot study, when the POTW was accepting wastewater from the Patriot CWT facility ( 193 DCN SGE 00616 ), suggesting that TDS and chloride were not removed by the POTW

.

113 All flows were introduced into the Warren POTW over an eight

- hour period.

114 The Warren POTW pilot study description states that “Raw [influent] does not have any Patr iot influence or plant return flows

. ” The report author also noted increases in the TDS and chloride concentrations over the period of the study and suggested that “these increases are most likely due to seasonal fluctuations within the collection system a s a result of user operations or seasonal runoff from spring rains” ( 193 DCN SGE00616 ).Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 128 Table D

- 20

. TDS Concentrations in Baseline and Pilot Study Wastewater Samples at Warren POTW

Sample Type Influent Concentration (mg/L) Effluent Concentration (mg/L) Percent Increase ( %)

Baseline Samples

TDS 584 599 2.6
Chloride 143 157 9.8 Eight

- Week Pilot Study Samples

TDS 679 885 30.3

Chloride 239 348 45.6

Source: 193 DCN 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 ( 193 DCN SGE00616)

the POTW had not experienced any of the following conditions since accepting the brine

waste water from the Patriot CWT facility :

• Dimi nished or inhibited performance of the biological treatment processes

• Adverse impacts to the downstream water quality

• Adverse impacts to the quality of the facility’s biosolids

The compliance inspection indicated that the Warren POTW was in compliance with all of its NPDES permit limitations

. Table D -21 shows the results of EPA Region 5’s wastewater sample analyses conducted during their September 2011 inspection. The compliance inspection data show minimal to no TDS removals by the POTW and minimal chloride removals.

Table D

- 21

. EPA Region 5 Compliance Inspection Sampling Data

Pollutant Warren POTW Influent Concentration (mg/L) a Warren POTW Effluent Concentration (mg/L) a Average Range Average Range

TDS 726 686

– 748 726 648

– 778
Chloride 361 345

– 374 213 191

– 252
Sulfate 250 243

– 256 77 68

– 84

TSS 95.0 67.0

– 112 <4 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: 193 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. Abbreviation: mg/L

— milligrams p er literChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 129 As of June 2014 , the Warren POTW was still accepting wastewater from the Patriot CWT facility ( 200 DCN SGE 00786). Its NPDES permit allows it to accept a maximum of 100,000 gallons of “wastewater from a regulated CWT facility that is tributary to the City’s collection system ” per day (0. 67 percent of it s maximum total daily flow) at a maximum TDS concentration of 50,000 mg/L ( 217 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 expiring on July 31, 2017 ) allows it to accept up to 14,000 gpd of “natural gas related wastewater ,” none of which may be from “Shale Gas Extraction related activities” ( 132 DCN SGE00931). As of June 2014, the Brockway POTW was still accepting natural -gas- related waste water treated by the Dannic Energy Corporation CWT facility. The Brockway POTW is sampling and reporting the required parameters on PA DEP’s electronic DMR system ( eDMR ) ( 132 DCN 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 wa stewater. Typical COG wastewater accepted by the Brockway POTW may have TDS concentrations over 200,000 mg/L ( 99 DCN SGE 00753 ).

5.3.2 UOG Extraction Wastew ater 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

• Inhibition 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 inhibit the performance of typical POTW treatment processes. Table D-22 present s inhibition threshold levels for activated sludge and nitrification, two treatment processes commonly used at POTWs, for select UOG constituents identified in Section C. 3

. 115 

### The EPA recognizes that POTW treatment processes will not be exposed to UOG constituents at the concentrations they are found in UOG produced water (i.e., flowback, long-term produced water).

115 EPA also presents specific inhibition thresholds for anaerobic digestion and trickling filters, but the UOG constituent concentrations are not as likely to exceed the thresholds, so they were not included in Table D- 22

.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 130 As discussed in Section A. 2.1.1 , POTWs establish local limits to control pollutant discharges that present a reasonable potential for pass through or interference with POTW operations. The inhibition levels presented in the EPA ’s guidance represent concentrations that would reduce the effectiveness or otherwise interfere with the treatment operations for treatment commonly used at POTWs. Inhibition of activated sludge processes at a POTW could impair 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 i mpair the POTW’s ability to remove ammonia and nutrients in the wastewater.

Table D

- 22

. Inhibition Threshold Levels for Various Treatment Processes a

Pollutant Reported Range of Activated Sludge Inhibition Threshold Levels (mg/L) a Reported Range of Nitrification Inhibition Threshold Levels (mg/L) a

Ammonia 480 NA

Arsenic 0.1 1.5

Benzene 100

– 500, 125

– 500 NA

Cadmium 1– 10 5.2

Chloride NA 180

Chloroform NA 10
Chromium, total 1– 100 0.25

– 1.9, 1

– 100 (trickling filter)
Copper 1 0.05

– 0.48 Ethylbenzene 200 NA

Lead 1– 5, 10

– 100 0.5
Mercury 0.1 –1 , 2.5 as Hg(II) NA Naphthalene 500, 500, 500 NA

Nickel 1– 2.5, 5 0.25

– 0.5, 5

Phenol 50

– 200, 200, 200 4, 4

– 10

Sulfide 25

– 30 NA

Toluene 200 NA

Zinc 0.3

– 5, 5

– 10 0.08

– 0.5

Source: 165 DCN SGE00602

a— Where multiple values are listed (divided by commas), the data were reported individually in 165 DCN SGE 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 

### in POTW discharges suggest inhibition/disruption of treatment processes. As some of the studies described in the following sections indicate, POTWs have linked TSS and/or 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. The purpose of these subsections is to identify instances of in hibition/disruption, or potentialChapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 131 inhibition/disruption, at POTWs associated with the acceptance of UOG extraction wastewater pollutants.

5.3.2.1 Case Studies About POTWs Accepting Wastewater from Oil and Gas Extraction Facilities

Johnstown, PA, POTW

The Johnstow n POTW uses screening, grit removal, high

- purity oxygen activated sludge aeration with integrated fixed

- film activated sludge, final clarification, and chlorination ( 133 DCN SGE 00930). The Johnstown POTW accepted both UOG and COG wastewater before 2008 and stopped accepting both in 2011 ( 46 DCN SGE 00739) . The total oil and gas wastewater accounted for less than 3 percent of the total POTW influent volume during the acceptance period on average. The POTW’s annual average daily flow rate ranges between 9.0 and 10.5 MGD based on 2008 through 2013 DMR data ( 175 DCN SGE 00608).

The EPA created Figure D-13 using the sampling data submitted in it s DMR Loading Tool ( 175 DCN SGE 00608 ) and PA DEP w aste reports data ( 46 DCN SGE 00739). Each effluent concentration data point represents the average of 12 monthly average data points as calculated and reported by the Loading Tool. PA DEP waste reports provided the total volume of UOG and COG wastewater delivered to the POTW each year . The EPA divided the annual volume by 365 to calculate the annual average daily flow. As shown in Figure D-13 , the Johnstown POTW experienced a much larger number of permit limit exceedances during the period when they were accepting the greatest volume of oil and gas extraction wastewater. In a December 2012 letter regarding the 2011 annual pretreatment report, Johnstown’s pretreatment coordinator stated,

[We] k now that the treatment plant no longer accepts gas drilling waste, 116 

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

Further, Section C. 3.2.1 presents data showing that TSS concentrations in drilling
wastewater may be higher than TSS concentrations in UOG produced water

. 117 

### The PA DEP waste reports data show that the Johnstown POTW accepted more drilling wastewater than any other POTW in Pennsylvania from 2008 through 2011 . The POTW accepted the large st volume of drilling wastewater in 2009 and 2010, which totaled over 15 million gallons and accounte d 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).

116 The EPA assumes that this phrase refers to both COG wastewater and UOG extraction wastewater.

117 Drilling wastewater initially includes cuttings (i.e., solids) that are partially removed by the operator before management or disposal. Any cuttings that remain may contribute to elevated TSS concentrations.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 132 Figure D-13. Johnstown POTW: Annual Average Daily Effluent Concentrations and POTW Flows Sources: 52 DCN SGE 00929



### California, PA, POTW

The California POTW uses a contact stabilization 118 

### process to treat influent wastewater ( 10 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 ( 46 DCN SGE 00739) . The POTW’s average annual daily flow rate ranges between 0.5 and 0.8 MGD based on 2008 through 2013 DMR data ( 175 DCN SGE 00608).

The EPA created Figure D-14 using the sampling data submitted in it s DMR Loading Tool ( 175 DCN SGE 00608 ) and PA DEP w aste reports data ( 46 DCN SGE 00739). Each effluent concentration data point represents the average of 12 monthly average data points as calculated

118 Contact stabilization is a two

- stage activated sludge process, consisting of a 30 to 60 minute absorptive phase followed by a one to two hour oxidation phase. Aeration volume requirements are half o f those for conventional

ac tivated sludge ( 119 DCN SGE00 167 ).Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 133 and reported by the DMR Loading Tool. PA DEP waste reports provided the total volume of UOG and COG wastewater delivered to the POTW each year . The EPA divided the annual volume by 365 to calculate the annual average daily flow. As shown in Figure D-14 , the California POTW experienced elevated concentrations of TSS and BOD 5 

### while accepting oil and
gas wastewater. Figure D-14 also shows that the California POTW experienced three exceedances of its TSS permit limits 119 

### and one exceedance of its BOD 5 

### permit limits

. 120



### Figure D-14. California POTW: Annual Average Daily Effluent Concentrations and POTW Flows Sources: 52 DCN SGE 00929



### Charleroi, PA , POTW

The Charleroi POTW w as introduced and described in more detail in Section D. 5.3.1 of this TDD

.

The EPA created Figure D-15 using the sampling data submitted in it s DMR Loading Tool ( 175 DCN SGE 00608 ) and PA DE P w aste reports data ( 46 DCN SGE 00739). Each effluent

119 The California POTW had a monthly average TSS limit of 30 mg/L and a daily maximum TSS limit of 45 mg/L from 2008 through 2013.

120 The California POTW had a monthly average BO D 5 limit of 25 mg/L and a daily maximum BOD 5 limit of 37.5 mg/L from 2008 through 2012. In 2013, its daily maximum BOD 5 limit changed to 40 mg/L.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 134 concentration data point represents the average of 12 monthly average data points as calculated and reported by the Loading Tool. PA DEP waste reports provided the total volume of UOG and COG wastewater delivered to the POTW each year . The EPA divided the annual volume by 365 to calculate the annual average daily flow. As shown in Figure D-15 , the Charleroi POTW experienced elevated concentrations of TSS and BOD 5 

### while accepting UOG extraction
wastewater.

Sources: 52 DCN SGE 00929



### Figure D-15. Charleroi POTW: Annual Average Daily Effluent Concentrations and POTW Flows 121



### Waynesburg, PA, POTW

The Borough of Waynesburg POTW accepted gas -exploration- related wastewater , hauled directly from operators , f rom June 200 6 to November 2008. Gas well wastewater made up about 2 percent of total inflow in 2006. The percentage increased to 8.1 percent in 2007 and 9.5 percent

121 Figure D- 15 only sh ows data for 2008 through 2011 because there is no PA DEP waste report data or DMR Loading Tool data for the Charleroi POTW for 2012 or 2013.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 135 in 2008. The Waynesburg POTW’s average annual daily flow rate range d between 0. 37 and 0. 62 MGD over those three years

. The treatment process at Waynesburg POTW is as follows: two primary clarifiers, a trickling filter, a bio

- tower, a final clarifie r, and chlorine disinfection ( 12 DCN SGE 00997, 13 DCN SGE 00997.A01).

T he Waynesburg P OTW received a CWA § 308 Request for Information from EPA Region 3 in February 2009. In March 2009, the Waynesburg POTW responded with a “Process Impact Evaluation” ( 14 DCN 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 wastewater

. Advanced W aste Services CWT facility treats “pretreated brine” (industrial wastewater) using solids settling, surface oil skimming, and pH adjustment. If influent wastewater does not meet Advanced Waste Services ’ pretreatment permit requirements, the facility appl ie s additional treatment with flocculants ( 223 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-23 ) 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 ( 223 DCN SGE 00554 ; 134 DCN SGE 00573 ).

Table D

- 23

. 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 : 223 DCN SGE 00554

a

— Assuming 17 MGD is the total volume treated.



### The 2009 annual report ( 223 DCN SGE 00554) states that :

It is believed that pretreated brine wastewater from the developing oil & gas industry is adversely affecting the ability of the final clarifiers to separate solids via gravity settling.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 136 This has resulted in higher sludge blanket levels that are more easily upset and washed out during rainfall-induced high flow events. The Authority has begun using polymer flocculation to enhance settling with some success. However, there were numerous effluent TSS violations in 2009.

As noted in the annual report , instability in sludge blanket levels can cause increased washouts during large rain events, which may cause interference with biological treatm ent. New Castle reported 19 violations of its NPDES permit limits for TSS, believed to be caused by the acceptance of UOG extraction wastewater via the Advanced Waste Services CWT facility’s industrial discharge ( 223 DCN 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 CWT facility (i.e. , violations between May and December 2011) . The EPA identified two TSS violations during this nine

- month time frame

. Table D-24 shows detailed information about the violations in 2009 and 2011

, including when they occurred, the measured values, and the percentage over the NPDES permit limit. The decrease in the number of TSS violations from 2009 to 2011, after the POTW stopped acc epting industrial discharges from the Advanced Waste Services CWT facility , suggests that the UOG extraction wastewater pollutants

were a contributing cause of the violations. However, the two violations in 2011 indicate that the UOG extraction wastewater was likely not the sole cause of interference with treatment processes at the POTW.

Table D

- 24

. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW ( NPDES Permit Number PA0027511)

Month, Yea r 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 maximum 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 27

Mar ch 2010 TSS Weekly maximum 45 55 22

Nov ember 2010 TSS Monthly average 30 34 13

Nov ember 2010 TSS Weekly maximum 45 55 22

Dec ember 2010 TSS Weekly maximum 45 56 24

Nov ember 2011 TSS Monthly average 30 35 17Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 137 Table D

- 24

. NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW ( NPDES Permit Number PA0027511)

Month, Yea r Parameter Sample Type NPDES Permit Limit (mg/L) Measured Value (mg/L) Percentage Over Permit Limit (%)

Nov ember 2011 TSS Weekly maximum 45 64 42

Source s : 169 DCN SGE 00620 ; 185 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 122



### . A 2011 Consent Order issued to the Wheeling POTW by the WV DEP indicates that the POTW experienced interference with biological treatment from accepting UOG extraction wastewater via the CWT facility ’s industrial discharge. The Order describes the following timeline of events ( 219 DCN 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 occurred during periods when the POTW exceeded discharge limits for fecal coliform and TSS.

• August 21, 2009

— Meeting minutes from a meeting between Wheeling POTW and LAD CWT facility stated that Wheeling was accepting oil and gas wastewater “well above the 1% that is allowed

. ” The minutes also said that Wheeling was concerned about the lack of diversity in microorganisms and that the wastewater from LAD was the cause of the lack of mi crobial 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 interferen ce, inefficiency, or possible upset indicated by several factors including an increased chlorine demand, loss in effluent clarity, UV disinfection failures, and suspicious odors.

• May 6, 2010— Wheeling POTW representatives met with WV DEP representatives to discuss the draft Consent Order. The Order included numerous requirements including one that stated, “Upon entry of this Order, Wheeling shall continue to cease and desist acceptance of all oil and gas wastewater.”

Brockway, PA, POTW

The Brockway POTW, introduced in Section D. 5.3.1 , was still accepting natural

- gas

related wastewater treated by the Dannic Energy Corporation CWT facility as of June 2014. Before acc epting COG wastewater, Brockway POTW installed an oil/solids separator and aerated equalization tank. The POTW began accepting COG wastewater starting in November

122 As described in Section D. 5.3.1 , the Wheeling POTW accepted industrial wastewater from the LAD CWT facility through August 2009 and wastewater directly from UOG operators in 2008.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 138 2008 and noticed an increase in sludge generation

. 123 

### Th e POTW operators noticed a scum layer f orming 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 co ncentrations of barium in the sludge (sludge barium content = 1,490 mg/kg). However, the POTW ran a hazardous waste determination and found that the barium content was below the hazardous waste classification threshold ( 99 DCN 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, including sludge disposal, and the disruption of POTW operations as a result of excessive scale formation. For example, POTWs that accept and treat wastewater high in heavy metals (e.g., nickel, copper, zinc) face the potential for heavy metals accumulation in sludge. A POTW accepting wastewater with h igh 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 -apply ing its sludge (see Table C-17 ), the EPA has identified the potential for elevated concentrations of radium-226 and -228 in sludge ( 172 DCN SGE 00136 ; 135 DCN SGE01028 ). State and federal regulations for the transport and disposal of radioactive waste may limit the POTW’s options for managing sludge contaminated with radium and other radioactiv e materials derived from UOG extraction wastewater. POTWs with sludge containing radioactive materials may resort to underground injection in a Class I well 124



### , disposal at a hazardous waste landfill 125



### , or disposal at a low

- level radioactive waste landfill 126 

### ( 189 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-16 shows an example of barium sulfate scaling in an oil and gas pipe in the Haynesvill e shale formation.

123 The EPA is not aware of any time when the Brockway POTW accepted UOG extraction wastewater.

124 Class I underground injection wells are used to inject hazardous wastes, industrial non

- hazardous liquids, or municipal wastewater beneath the lowermost underground source of drinking water.

125 Hazardous waste landfills are regulated under RCRA Subtitle C. Some hazardous waste landfills are permitted to accept TENORM waste, while others have to request state approval before accepting TENORM waste.

126 Low

- level radioactive waste landfills are licensed by the U.S. Nuclear Regulatory Commission or by a state

un der agreement with the Commission . These landfills provide a disposal option for wastes with radionuclide concentrations that are unable to be disposed of at municipal, industrial, or hazardous waste landfills.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 139 Figure D-16 . Barium Sulfate Scaling in Haynesville Shale Pipe Source: 152 DCN SGE 00768.A26



### Tabl e C-17 shows typical concentrations of barium, calcium, and strontium in UOG extraction wastewater, which suggest that UOG extraction wastewater may cause scale accumulation at POTWs. Because radium 127 

### behaves like other divalent cations, it may also accumulate in scale and form TENORM : technologically

- enhanced naturally occurring radioactive material, defined as naturally occurring radioactive materials that have been concentrated or exposed to the ac cessible environment as a result of human activities such as manufacturing, mineral extraction, or water processing (e.g., in treatment processes at a POTW). PA DEP’s 2015 study report 128 

### ( 135 DCN SGE01028) provides the following examples of solids that may contain TENORM: drill cuttings, filter sock residuals, impoundment sludge, tank bottom sludge, pipe scale, wastewater treatmen t plant sludge, and soils 129



### . The PA DEP TENORM study report concludes that “There is little potential for radiological exposure to workers and members of the public from handling and temporary storage of filter cake at POTWs. However, there is a potential for radiological environmental impacts from spills and the long- term disposal of POTW filter cake.” The PA DEP TENORM study report includes the following recommendations for future action:

• “ Perform routine survey assessment of areas impacted with surface r adioactivity to determine personal protective equipment (PPE) use and monitoring during future activity that may cause surface alpha and beta radioactivity to become airborne. ”

127 Radium is a naturally occurring radioactive element that ionizes in water to a divalent cation with chemical properties similar to barium, calcium, and strontium.

128 PA DEP initiated a study to collect data related to TENORM associated with oil and gas operations in Pennsylvania, including assessmen t of potential worker and public radiation exposure, TENORM disposal, and other environmental impacts.

129 PA DEP’s 2015 TENORM study sampled the following types of solids: surface soil impacted by sediments, filter cakes, soils, sludge, drill cuttings, drilling muds, proppant sand, and filter socks. PA DEP identified pipe scale as a source of TENORM, but did not sample for pipe scale in their 2015 TENORM study.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 140 • “Conduct additional radiological sampling and analyses and radiological surveys at all WWTPs accepting wastewater from O&G operations to determine if there are areas of contamination that require remediation; if it is necessary to establish radiological effluent discharge limitations; and if the development and implementation of a spill policy is necessary. ”

The Marcellus shale formation is known to contain radium and

, therefore, is of particular concern for TENORM generation ( 172 DCN SGE 00136 ; 28 DCN SGE 00519 ; 150 DCN SGE 00587 ).

Rowan et al. ( 145 DCN SGE00241) report a positive correlation between TDS concentrations and radium activity based on data for produced water from the Marcellus shale and conventional formations in the Appalachian basin. Therefore, UOG formations containing higher concentrations of TDS will likely also contain higher radium activity and

, therefore, a higher chance for TENORM accumulation in sludge. However, 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 scale from UOG extraction
wastewater and the subsequent health risks to worker safety at POTWs are not fully known.

The 2015 P A DEP TENORM Study ( 135 DCN SGE01028) also looked into potential worker exposure, TENORM disposal 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; and

• 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 distribution, and the maximum result was 55.6 pCi/g. The average Ra

- 228 result was 8.32 pCi/g, and the maximum result was 32.0 pCi/g Ra-228.” ( 135 DCN SGE01028)

PADEP concluded, “...[t]here is little potential for radiological exposure to workers and members of the public from handling and temporary storage of filter cake at POTW

- I’ s 130



### . However, there is a potential for radiological environmental impacts from spills and the long

term disposal of POTW

- I filter cake ” ( 135 DCN SGE01028). ERG’s Radioactive Materials in the Unconventional Oil and Gas (UOG) Industry memo randum ( 54 DCN SGE00933) provides additional information and results from the PA DEP study.

130 PA DEP defines a “POTW

- I” as a POTW that was considered to be influenced by having received wastewater from the oil and gas industry.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 141 5.3.3 Potential Impacts of DBP Precursors in UOG Extraction Wastewater Disinfection, especially chlorination of drinking water and wastewater, is used to reduce outbreaks of waterborne disease. As well as killing pathogenic microbes, though, disinfection can produce a variety of toxic halo

- organic c ompounds called DBPs. UOG e xtraction wastewater often contains elevated levels of bromide (see Table C-13 ) and chloride, which is a precursor of several toxic DBPs ( 15 DCN SGE 00509; 214 DCN SGE 00754 ). Brominated DBPs are reported to have greater health risks (e.g., higher risk of cancer) than chlorinated DBPs ( 118 DCN SGE 00800).

UOG extraction wastewater discharged to POTWs would be a potential source of DBPs in two scenarios:

• When UOG extraction wastewater is disinfected at a POTW ( 90 DCN SGE 00535)

• When a POTW discharges wastewater including UOG extraction wastewater pollutants to a river that is used as a source water for a downstream drinking wa ter treatment plant where disinfection is used ( 150 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 concentrations of bromide (see Section C. 2.2 ), treatment of UOG extraction wastewater at POTWs with disinfection processes can create DBPs. Hladik et al. investigated whether POTW treatment of wastewater from COG and UOG operations (hereafter referre d to as “oil and gas wastewater”) could create DBPs, particularly brominated DBPs ( 90 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 for POTW 1 was approximately 1,200 MGD. The daily average discharges for POTWs 2 and 3 were not reported, but the amount of oil and gas wastewater accepted at the POTWs was reported as ranging from 2.3 million gallons to 2.9 million gallons in 20 12. Grab samples were collected in the river where the POTW effluent entered and were analyzed for 29 DBPs.

Table D-25 presents sampling results showi ng 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



### 142 Table D-25. Concentrations of DBPs in Effluent Discharges at One POTW Not Accepting Oil and Gas Wastewater and at Two POTWs Accepting Oil and Gas Wastewater (μg/L)

Facility Identifier POTW 1 POTW 1 POTW 2 POTW 3

MDL 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: 90 DCN SGE 00535

Note: The EPA presents data for eight DBPs in Table D- 25 . Hladik et al

. ( 90 DCN SGE00535) collected data for 29 DBPs. The concentrations of DBPs in the effluent of POTWs that had accepted oil and gas wastewater were higher than the concentrations in POTWs that had no t 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. ( 90 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 from Hladik et al. ( 90 DCN SGE 00535 ).

Abbreviation: ND

— n on d etect



### 5.3.3.2 Drinking Water Treatment Disinfection Downstream of POTWs

DBPs form when disinfectants (e.g., chlorine), natural organic matter, and bromide or iodide react. Therefore, they can form in drinking water treatment plants that use disinfection processes. Beginning in 2008, researchers in Pennsylvania detected high concentrations of bromide, a pollutant that facilitates the formation of toxic DBPs (e.g., brominated trihalomethanes)

, downstream of POTWs that accepted UOG extraction wastewater ( 81 DCN SGE 00567; 150 D CN SGE 00587 ).

Wilson and Van Briesen ( 226 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



### 143 Wilson and Van Briesen later conclude that

Produced water management decisions should be informed by the potential contribution of this wastewater to the formation of disinfection by-products in downstream drinking water treatment plants.

States et al. ( 150 DCN SGE00587) c onducted a drinking water treatment plant survey and investigated bromide concentrations in the untreated river water intake and trihalomethanes ( THMs ) (i.e., chloroform, bromoform, dibromochloromethane, bromodicholoromethane) in the treated, “finished” drinking water. States et al. drew the following conclusions from their study:

• Elevated bromide concentrations in the influent to the studied drinking water treatment plant resulted in increased concentrations of certain DBPs, particularly brominated THMs, in the drinking water.

• Drinking water treatment plants cannot effectively remove bromide from intake
water.

• POTWs discharging treated UOG extraction wastewater (specifically from the Marcellus shale formation) were major contributors to the increase in bro mide in the drinking water treatment plant intake during the period of the study.

In February 2013, Eshelman and Elmore published a report for the Maryland Department of the Environment titled Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland ( 69 DCN SGE 00735). The report discussed POTW management of UOG extraction wastewater and specifically noted that this is not a best management practice. They further reported that the discharge of high

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

Higher chloride levels cause taste and odor problems in finished water. High bromide levels lead to increased formation of carcinogenic disinfectant by-products that can persist in the water to the point of consumption. Treatment of produced water by POTWs and other conventional wastewater treatment methods that do not remove salts should be prohibited in Maryland.

McTigue et al. published an article about the occurrence and consequences of bromide in drinking water sources ( 118 DCN 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 utilit ies. The authors provide an example of an unnamed water treatment plant (WTP E) that began experiencing influent water with high TDS concentrations in 2008, around the same time that UOG extraction operations began in the area. Figure D-17 shows the average quarterly total THM speciation from 1999 through 2013, which shows a decrease in chlorinated DBPs and an increase in brominated DBPs starting around 2008.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 144 Abbreviations: TTHM MCL – total trihalomethane maximum contaminant level Source: 118 DCN SGE00800

. 

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

Another example of concerns about DBP formation from oil and g as wastewater is shown in PA DEP’s response to a comment on Ridgway POTW’s NPDES permit renewal . The comment, from the University of Pittsburgh, stated that, “bromide can create trihalomethane byproducts. ” PA DEP’s response noted that trihalomethanes are m ade up of one of the following (followed parenthetically by measured effluent concentrations from the Ridgway POTW) :

• Chloroform (non detect )

• Bromodichloromethane (non detect )

• Dibromochloromethane ( non detect )

• Bromoform (74 μg/L)

PA DEP noted that the effluent concentration of bromoform was low enough not to be of concern compared to water quality limits. However, it is studying the impact of bromides on surface waters. PA DEP recognizes that UOG extraction wastewater has the poten tial to contribute to the formation of DBPs.Chapter D

— UOG Extraction Wastewater Management and Disposal Practices



### 145 I n August 2013, EPA Region 3 issued a letter ( 187 DCN SGE 00935) informing the NPDES permitting authorities in the Mid

- Atlantic region that

...conventional and nonconventional pollutants, such as bromid e, must be tested by existing dischargers as part of the permit application process if such pollutants are expected to be present in effluent.

The letter goes o n to state that EPA Region 3 has reason to believe that industrial discharges (including UOG extraction wastewater discharges) containing bromide contributed to elevated levels of bromide in rivers and streams that resulted in downstream impacts at drinkin g water treatment plants, including increased occurrence of DBPs. Therefore, if the parameter is not limited in an applicable ELG, NPDES permit applicants must either describe why the parameter is expected in their discharges or include quantitative data for the parameter. These requirements apply to the following parameters of interest in UOG extraction wastewater, among others ( 195 DCN SGE 00935.A01):

• TDS

• Chloride

• Bromide

• Sulfate

• Fluoride

• Aluminum, total

• Barium, total

• Iron, total

• Manganese, total

• Radium-226/228

• Arsenic, total • Selenium, total

• Benzene

• Bromoform

• Chlorobenzene

• Chloroform

• Ethylbenzene

• Toluene

• Phenol

• Naphthalene

• Alpha- BHC

• Beta

- BHC

Parker et al. published an article in September 2014 ( 129 DCN 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 trea tment.

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 res ult in altered speciation toward the formation of brominated and iodinated 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 wa ter discharges or installing halide

- specific removal techniques in CWT facilities and/or POTWs that are accepting UOG produced water for
treatment

.Chapter E

—

Reference Flags and List



### 146 

## Chapter E. 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 for the TDD . The EPA identified all of the information described in this TDD from these types of existing data sources , which are listed in Table E-1.

The EPA assigned one of the following data source quality flags to each of the sources referenced in this TDD:

• Source quality 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 quality f lag “B”: Documents prepared by a verified source that include citation information (e.g., operator reports, vendor documents, university publications)

• Source quality f lag “C”: Documents prepared by a verified source that do not include citation information (e.g., operator reports, vendor documents, conference presentations)

• Source quality flag “D”: Documents prepared by a source that could not be verified and that do not include citation information

Table E-1 . Source List

ID DCN Source Citation Source Flag

1 SGE 00046 Abdalla, Charles W.; Drohan , Joy R.; Blunk, Kristen S.; Edson, Jessie. 2011. Marcellus Shale Wastewater Issues in Pennsylvania

— Current and Emerging Treatment and Disposal Technologies. Penn State Cooperative Extension, College of Agricultural Sciences. B

2 SGE 00932 Abt Associates. 2015. Profile of the Oil and Gas Extraction (OGE) Sector, with Focus on Unconventional Oil and Gas (UOG) Extraction. (February 18). A

3 SGE 00070 Acharya, Harish; Matis, Hope; Kommepalli, Hareesh; Moore, Brian; Wang, Hua. 2011. Cost Effective Recovery of Low

- TDS Frac Flowback Water for Re

- use. Prepared by GE Global Research. Prepared for US DOE NETL. Morgantown, WV. (June). A

4 SGE 00723 Agency for Toxic Substances & Disease Registry (ATSDR). 2006. Hydrogen Sulfide ToxFAQs. (July). A

5 SGE 00497 Angelo, Tom. 2013. From Pilot Study to Daily Processing: Warren, Ohio’s Documentary to Hydraulic Fracturing Water Treatment. City of Warren, Ohio, Water Pollution Control Department. Presentation at EPA’s Study of Hydraulic Fracturing and Its Potential Impact on Drinking Water Resources: Wastewater Treatment and Related Modeling Technical Workshop. April 18, 2013. A

6 SGE 00499 Arkansas Oil and Gas Commission (AOG C). 2013. Welcome to the Arkansas Oil and Gas Commission Online Production and Well Information. Accessed on 6/14/2013. AChapter E

—

Reference Flags and List



### 147 Table E-1 . Source List

ID DCN Source Citation Source Flag

7 SGE 00504 Baker Hughes. 2013. North America Rotary Rig Count (Jan 2000

– Current). (November 15). Downloaded on 11/20/2013. Available online at: http://phx.corporate

- ir.net/phoenix.zhtml?c=79687&p=irol

- reportsother B

8 SGE 00502 Baker Hughes. 20 13. North America Rotary Rig Count Pivot Table (Feb 2011

– Current). (November 8). Downloaded on 11/11/2013. Available online at: http://phx.corporate

- ir.net/phoenix.zhtml?c=79687&p=irol

- reportsother B

9 SGE 00503 Baker Hughes. 2013. U.S. Onshore Well Count. (October 11. Downloaded on 11/11/2013. Available online at: http://phx.corporate

ir.net/phoenix.zhtml?c=79687&p=irol

- wellcountus# B

1 0 SGE 00787 Borough of California. 2009. for Information. (March 18). Borough of Ca lifornia Response to 308 Request A

11 SGE 00751 Borough of Charleroi. 2008. Re: Authority of the Borough of Charleroi Administrative Order. (November 21). A

12 SGE 00997 Borough of Waynesburg. 2009. Clean Water Act Section 308 Request Information. for A

13 SGE 00997.A 01 Borough of Waynesburg. 2009. Clean Water Act Section 308 Request Information

— Attachment 1: Acceptance Records. for A

14 SGE 00750 Borough of Waynesburg. 2009. Waynesburg Response to Clean Water Act Section 308 Request for Information. (March 31). A

15 SGE 00509 Brown, Daniel; Bridgeman, John; West, John R. 2011. Predicting Chlorine Decay and THM Formation in Water Supply Systems. Reviews in Environmental Science and Bio/Technology 10:79

– 99. A

16 SGE 00110 Bruff, Matthew. 2011. An Integrated Water Treatment Technology Solution for Sustainable Water Resource Management in the Marcellus Shale. Prepared by Altela, Inc., Argonne National Laboratory, BLX, Inc., and CWM Environmental, Inc. DE

- FE0000833. A

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

18 SGE 00966 California Council on Science and Technology (CCST). 2014. Advanced Well Stimulation Technologies in California: An Independent Review of Scient ific and Technical Information. Sacramento, CA. A

19 SGE 00367 CARES. n.d. CARES McKean. Downloaded on 1/28/2013. C

20 SGE 00305.A 0 3 Cheung, Timothy. 2012. Identifying the Recycling and Treatment Criteria That Must be Met to Avoid Scaling and Enable Successful Reuse. Shell. C

21 SGE 00749 City of Clarksburg. 2009. Re: Clean Water Informa tion. (March 2). Act Section 308 Request for A

22 SGE 01000 City of Wheeling Water Pollution Control Division. 2007. Wheeling Effluent Data. A

23 SGE 00366 Clarion Altela Environmental Services (CAES). n.d. CAES Downloaded on 1/28/2013. Overview. CChapter E

—

Reference Flags and List



### 148 Table E-1 . Source List

ID DCN Source Citation Source Flag

24 SGE 00354 Clark, C.E.; Han, J.; Burnham, A.; Dunn, J.B.; Wang, M. 2011. Life

- Cycle Analysis of Shale Gas and Natural Gas. Argonne National Laboratory. ANL/ESD/11

- 11. A

25 SGE 00182 Clark, C.E.; Veil, J.A. 2009. Produced Water Volumes and Management Practices in the United States. ANL/EVS/R

- 09/1. Argonne National Laboratory. (September) A

26 SGE 00516 Cochener, John. 2010. Quantifying Drilling Efficiency. U.S. EIA, Office of Integrated Analysis and Forecasting. (June 28). A

27 SGE 00357 Cramer, John. 2011. Post

- frac Superior Well Services. Flowback Analysis and Reuse Implications. B

28 SGE 00519 Davies, Peter J. n.d. Radioactivity. Cornell University. B

29 SGE 00520 Drillinginfo. 2011. DI Desktop® December 2011 Download. Drillinginfo, Inc. B

30 SGE 00331 Ely, John W.; Horn, Aaron; Cathey, Robbie; Fraim, Michael; Jakhete, Sanjeev. 2011. Game Changing Technology for Treating and Recycling Frac Water. Society of Petroleum Engineering. SP SPE

- 214545

- PP. A

31 SGE 00989 Energy Information Administration (EIA). 2014. Annual Energy Outlook 2014 with Projections to 2040. DOE/EIA

- 0383(2014). A

32 SGE 00988 Energy Information Administration (EIA). 2014. Assumptions to the Energy Outlook 2014. Annual A

33 SGE 00984 Energy Information Administration (EIA). 2014. Glossary. http://www.eia.gov/tools/glossary Retrieved from A

34 SGE 00708 Environmental Leader. 2013. Unconventional E&P “$8 Billion of US Water Services Market.” (November 11). B

35 SGE 00522 Environmental Review Appeals Commission, State of Ohio. 2012. Patriot Water Treatment, LLC, and City of Warren v. Chris Korleski, Director of Environmental Protection, and Scott Nally, Director of Environmental Protection: 2012 Decision. A

36 SGE 00244 ERG. 2012. Camp, Meghan; Bicknell, Betsy; Ruminski, Brent. Notes on Conference Call with 212 Resources on 4 January 2012. (January 9). A

37 SGE 00245 ERG. 2012. Camp, Meghan; Bicknell, Betsy; Ruminski, Brent. Notes on Conference Call with Reserved Environmental Services, LLC on 5 January 2012. (February 1). A

38 SGE 00521 ERG. 2012. Camp, Meghan; Ruminski, Brent. Notes Meeting Held on 29 February 2012. (April 20). for Shale Gas Industry A

39 SGE 00283 ERG. 2012. Camp, Meghan; Ruminski, Brent. Notes on BLX, Inc on 15 May 2012. (June 11). Conference Call with A

40 SGE 00705 ERG. 2014. Ruminski, Brent. Notes on Call February 2014. (March 7.) with Hydrozonix, LLC on 7 A

41 SGE 00736 ERG. 201 5 . Analysis of Active Underground Injection for Disposal Wells. A

42 SGE 00736.A 0 1 ERG. 201 5

. Analysis of Attachment 1: Injection Active Underground Injection for Disposal Wells

— for Disposal Well Data. AChapter E

—

Reference Flags and List



### 149 Table E-1 . Source List

ID DCN Source Citation Source Flag

43 SGE 00596 ERG. 201 5 . Analysis of Centralized Waste Treatment Accepting UOG Extraction Wastewater. (CWT) Facilities A

44 SGE 00596.A 0 1 ERG. 2015. Analysis of Centralized Waste Treatment Facilities (CWTs) Accepting UOG Wastewater Attachment 1: UOG CWT List and Analysis. A

45 SGE 009 63 ERG . 201 5

. A nalysis of DI Desktop® Memorandum. A

46 SGE 00739 ERG. 201 5 . Analysis of Pennsylvania Department of Environmental Protection’s (PA DEP) Oil and Gas Waste Reports. A

47 SGE 00739.A 0 3 ERG. 201 5 . Analysis of Pennsylvania Department of Environmental Protection’s (PA DEP) Oil and Gas Waste Reports. A

48 SGE 00693 ERG. 2015. Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction. Office of Water Engineering and Analysis Division. A

49 SGE 00693.A 0 1 ERG. 2015. Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

— Attachment 1: Onshore Oil and Gas Drilling Activity. A

50 SGE 00693.A 0 2 ERG. 2015. Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

— Attachment 2: EIA UOG Resource Potential. A

51 SGE 00693.A 0 3 ERG. 2015. Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

— Attachment 3: TDD Data Compilation. A

52 SGE 00929 ERG. 2015 . Publicly Owned Treatment Works (POTW) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction A

53 SGE 00929.A 01 ERG. 201 5

. Publicly Owned Treatment Works (POTW) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction — Attachment 1: POTWs Data f or TDD. A

54 SGE 00933 ERG. 201 5

. Radioactive Materials in the Unconventional Oil and Gas (UOG) Industry Memorandum

. A

55 SGE 00740 ERG. 201 5

. Unconventional Oil and Gas (UOG) Drilling Memorandum

. Wastewater A

56 SGE 00724 ERG . 201 5 . Unconventional Oil and Gas (UOG) Produced and Char acterization Data Compilation Memorandum

. Water Volumes A

57 SGE 00724.A01 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

— Attachment 1: UOG Produced Water Data Compilation. A

58 SGE 00724.A 0 2 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

— Attachment 2: DI Desktop Long

term Produced Water Rates. AChapter E

—

Reference Flags and List



### 150 Table E-1 . Source List

ID DCN Source Citation Source Flag

59 SGE 00724.A 0 3 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

— Attachment 3: DI Desktop Long

term Produced Water Rates. A

60 SGE 00724.A 04 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

— Attachment 4: FracFocus Fracturing Fluid Volume. A

61 SGE 00724.A 0 5 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

— Attachment 5: FracFocus Fracturing Fluid Volume. A

62 SGE 00724.A 0 6 ERG. 201 5

. Unconventional Oil and Gas (UOG) Produced Water Volumes and Char acterization Data Compilation — Attachment 6: Bakken Flowback Water Rates. A

63 SGE 00724.A 0 7 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

— Attachment 7: New Mexico Flowback Water Rates. A

64 SGE 00724.A 0 8 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

— Attachment 8: Utica Flowback and Produced Water. A

65 SGE 00724.A 0 9 ERG. 2015. Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

— Attachment 9: Niobrara Produced Water Rates. A

66 SGE 00724.A10 ERG. 201 5

. Unconventional Oil and Gas (UOG) Produced Water Volumes and Char acterization Data Compilation — Attachment 10: Wyoming Flowback Water Rates. A

67 SGE 00724.A11 ERG. 201 5

. Unconventional Oil and Gas (UOG) Produced Water Volumes and Char acterization Data Compilation — Attachment 11: Wattenberg Produced Water Rates. A

68 SGE 00724.A12 ERG. 201 5

. Unconventional Oil and Gas (UOG) Produced Water Volumes and Char acterization Data Compilation — Attachment 12: Colorado Flowback Water Rates. A

69 SGE 00735 Eshelman, Keith N.; Elmore, Andrew. 2013. Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland. University of Maryland Center for Environmental Science. Prepared for Maryland Department of the Environment. (February 18). A

70 SGE 00780 ExxonMobile. 2014. Hydraulic Fracturing Fluid. XTO Energy. Downloaded on 6/13/2014. C

71 SGE 00525 Ferrar, Kyle J.; Michanowicz, Drew R.; Christen, Charles L.; Mulcahy, N.; Malone, Samantha L.; Sharma, Ravi K. 2013. Assessment of Effluent contaminants from Three Facilities Discharging Marcellus Shale Wastewater to Surface Waters in Pennsylvania. Environmental Science & Technology 47:3472

– 3481. A

72 SGE 00768.A25 Fletcher, Sarah. 2014. Water Management Infrastructure Investments: Decision Factors and Regional Economics. Sourcewater Cambridge Innovation Center at MIT. BChapter E

—

Reference Flags and List



### 151 Table E-1 . Source List

ID DCN Source Citation Source Flag

73 SGE 00781 FracFocus. 2014. What Chemicals Are Used? B

7 4 SGE 00746 Franklin Township Sewer Authority. 2008. Franklin Township WWTP Fact Sheet/Statement of Basis (NPDES PA0046426). (June 2). A

75 SGE 00760 Freyman, Monika. 2014. Hydraulic Fracturing Demand by the Numbers. Ceres. (February). & Water Stress: Water B

76 SGE 00528 Gilmer, Ellen. 2013. Data Show More Marcellus Wastewater, More Injections. E&E News. (February 22). C

77 SGE01077 Ground Water Protection Council ( GWPC ) . 20 14

. Regulations Designed to Protect State Oil and Gas Water Resources. Available electronically at: http://www.gwpc.org/sites/default/files/files/Oil%20and%20Gas%20Regulati on%20Report%20Hyperlinked%20Version%20Final

- rfs.p df A

78 SGE 00010 GWPC and ALL Consulting. 2009. Modern Shale Development in the United States: A Primer. U.S. DOE. Office of Fossil Energy NETL. April 2009. Available electronically at: http://www.netl.doe.gov/File%20Library/Research/Oil

Gas/Shale_Gas_Primer_2009.pdf A

79 SGE 00344 Haluszczak, Lara O.; Rose, Arthur W.; Kump, Lee R. 2012. Evaluation of Flowback Brine from Marcellus Gas Wells in USA. Applied Geochemistry 28:55

– 61. Geochemical Pennsylvania, A

80 SGE 00286 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

81 SGE 00567 Handke, Paul. 2008. Trihalomethane Speciation and the Relationship to Elevated Total Dissolved Solid Concentrations Affecting Drinking Water Quality at Systems Utilizing the Mon ongahela River as a Primary Source During the 3rd and 4th Quarters of 2008. Pennsylvania Department of Environmental Protection. A

82 SGE 00531 Hanlon, James. 2011. Natural Gas Drilling in the Marcellus Program Frequently Asked Questions. (March 16). Shale: NPDES A

83 SGE 00532 Hansen, Evan; Mulvaney, Dustin; Betcher, Meghan. 2013. Water Resource Reporting and Water Footprint from Marcellus Shale Development in West Virginia and Pennsylvania. (October 30). B

84 SGE 00284 Hayes, Thomas et al. 2012. Barnett and Appalachian Shale Water Management and Reuse Technologies. Research Partnership to Secure Energy for America (RPSEA). A

85 SGE 00414 Hayes, Thomas; Severin, Blai ne F. 2012. Characterization of Flowback Waters from the Marcellus and the Barnett Shale Regions Report No. 08122

- 05.09. Research Partnership to Secure Energy for America (RPSEA). A

86 SGE 00533 Heffernan, Kevin. 2012. Unconventional Resource Development and Hydraulic Fracturing. Red Deer River Watershed Alliance. (October 25). B

87 SGE 00239 Hefley, William, et al. 2011. The Economic Impact of the Value Chain of a Marcellus Shale Well. University of Pittsburgh. (August). BChapter E

—

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88 SGE 00756 Hill Engineering, Inc. 2014. Re: Local Limits (January 9). Analysis for Ridgway Borough. A

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90 SGE 00535 Hladik, Michelle; Focazio, Michael J.; Englae, Mark. 2014. Discharges of Produced Waters from Oil and Gas Extraction via Wastewater Treatment Plants Are Sources of Disinfection By

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91 SGE 00333 Horn, Aaron. 2009. Breakthrough Mobile Water Treatment Converts 75% of Fracturing Flowback Fluid to Fresh Water and Lowers CO 2 Emissions. SPE SPE

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92 SGE 00707 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 Geologists’ Geosciences Technology Workshop. (March 18). B

93 SGE 00476 Hydro Recovery, LP. 2013. Company Info. Downloaded on 5/20/2013. C

94 SGE 00728 IHS. 2012. America’s New Energy Future: The Unconventional Oil and Gas Revolution and the US Economy. Volume 1: National Economic Contributions. B

95 SGE 00722 IHS. 2012. Water Management in Shale Gas Plays. (August) B

96 SGE 00769 International Behaviour of (March 1). Atomic Energy Agency (IAEA). 2014. The Environmental Radium: Revised Edition. Technical Report Series No. 476. A

97 SGE00799 Jacobs, (June). Trent. 2014. Shale Revolution Revisits the Energized Fracture. JPT. A

98 SGE 00479 Kadramas, Lee & Jackson, Inc. 2012. Power Forecast 2012: Williston Basin Oil and Gas Related Electrical Load Growth Forecast. B

99 SGE 00753 Keister, Timothy. 2010. Marcellus Hydrofracture Flowback and Production Wastewater Treatment, Recycle, and Disposal Technologies. Presentation at The Science of Marcellus Shale. (January 29). B

100 SGE 00527 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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101 SGE 00996 Kicinski, J. 2007. Wheeling POTW Analysis 4. A

102 SGE 00775 Kieler, Janet. 2012. CDPS General Permit for Discharges Produced

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103 SGE 00540 Kiski Valley Water Pollution Enterprises, Inc. (April 21). Control Authority. 2011. Letter to McCutcheon A

104 SGE 00545 Klaber, Kathryn. 2011. Letter Coalition. (April 20). to Michael Krancer, PA DEP. Marcellus Shale CChapter E

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107 SGE 00758 KLH Engineers. 2009. Technical Evaluation of the Impact of Oil and Gas Well Wastewaters on the Clairton Municipal Authority Wastewater Treatment Facility. (February). A

108 SGE 00745 KLH Engineers. 2011. Municipal Authority of the City of McKeesport: Headworks Loading Analysis for Natural Gas Drilling Wastewater Pollutants. (March). B

109 SGE 00345 Lewis, Aurana. 2012. Wastewater Generation and Disposal from Natural Gas Wells in Pennsylvania. Duke University. B

110 SGE 00667 Lord, R. LeBas; Luna, D.; Shahan, T. 2013. Development and Use of TDS Recycled Produced Water for Crosslinked

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111 SGE 00543 Macormac, Zach. 2011. Wheeling Fined for Taking Frack Intelligencer/Wheeling News

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112 SGE 00544 Marcellus Shale Coalition (MSC) and PA Independent Oil and Gas Association (PIOGA). 2013. Field Sampling Plan: Characterization of Naturally Occurring Radioactive Materials in the Oil and Gas Field. (November 4). B

113 SGE 00547 Massachusetts Institute of Technology (MIT). 2011. Gas: An Interdisciplinary MIT Study. The Future of Natural B

114 SGE 00779.A24 Mastowski, Ryan. 2014. Disposal

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115 SGE 00999 McClung, L.A. 2008. Wheeling POTW Discharge Requirements. A

116 SGE 00481 McCutcheon Enterprises. 2013. Waste Reduction: Treating Drilling Muds. (April). A Greener Alternative for C

117 SGE 00006.A 0 4 McElreath, Debra. 2011. Comparison of Hydraulic Fracturing Fluids Composition with Produced Formation Water Quality Following Fracturing

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122 SGE 00709 Natural Gas Europe. 2012. Flowback Water Water Treatment (May 22). Driving Flurry of Activity in B

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124 SGE 00090 New York State Department of Environmental Conservation (NYSDEC). 2011. Supplemental Generic Environmental Impact Statement on the Oil, Gas, and Solution Mining Regulatory Program: Well Permit Issuance for Horizontal Drilling and High

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12 5 SGE 00556 Nicot, Jean

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126 SGE 00639 Nicot, Jean

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127 SGE 00188 O'Connell, James, ERG. 2014. Pennsylvania Department of Environmental Prote ction’s (PA DEP) Statewide Oil and Gas Waste Reports. (December). A

128 SGE00983 Ohio Revised Code . 2012. Title 15, Chapter 1509: Division of Oil and Gas Resources Management – Oil and Gas. (September 10). Downloaded October 17, 2014. A

129 SGE 00985 Parker, Kimberly M.; Zeng, Teng; Harkness, Jennifer; Vengosh, Avner; Mitch, William A. 2014. Enhanced Formation of Disinfection Byproducts in Shale Gas Wastewater

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130 SGE 00187 Pennsylvania Code. 2010. Title 25: Environmental Protection. Chapter 95: Wastewater Treatment Requirements. (August). Available online at: http://www.pacode.com/secure/data/025/chapter95/chap95toc.html A

131 SGE 00755 Pennsylvania Department of Environmental Protection (PA DEP). 2011. NPDES Permit No. PA0023213 (Borough of Ridgway). (October). A

132 SGE 00931 Pennsylvania Department of Environmental Protection (PA DEP). 2012. Brockway Area Sewer Authority

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133 SGE 00930 Pennsylvania Department of Environmental Protection (PA DEP). 2012. Johnstown Redevelopment Authority (PA0026034)

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134 SGE 00573 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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135 SGE01028 Pennsylvania Department of Environmental Protection. 2015. Technologically Enhanced Naturally Occurring Radioactive Materials (TENORM) Study Report. A

136 SGE 00575 Petroleum Equipment Suppliers Association (PESA). 2012. Domestic Unconventional Resources. Presentation at PESA Outlook for Annual Meeting. B

137 SGE 00748 PG Environmental, LLC. 2009. Clairton Mun icipal Authority POTW Pass

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138 SGE 00139 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). Available online at: http://www.evs.anl.gov/pub/doc/ANL

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139 SGE 00579 Rahm, Brian, et al. 2013. Wastewater Management and Marcellus Shale Gas Development: Tre nds, Drivers, and Planning Implications. Journal of Environmental Management 120:105

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140 SGE 00374 Red Desert. n.d. What Makes Our Water Treatment So Advanced? Downloaded on 1/28/2013. & Reclamation Facility C

141 SGE 00768.A 0 1 Robart, Alexander. 2014. E&P Infrastructure vs. Third

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142 SGE 00583 Romo, Carlos; Janoe, J. Scott. 2012. Regulatory Regimes for Recycling Produced and Frac Flowback Water. Paper 2012

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143 SGE 00986 Rost, J. 2010. Municipal Authority of the City of McKeesport: Analysis of Gas Well Wastewaters as Required Under the PA DEP Administrative Order Dated October 23, 2008. (August 12). A

144 SGE 00987 Rost, J. November 2010. Municipal Authority of the City of McKeesport Analysis of Gas Well Wastewaters as Required Under the PA DEP Administrative Order Dated October 23, 2008. A

145 SGE 00241 Rowan, E.L., et al. 2011. Radium Content of Oil

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146 SGE 00291 Shires, Terrie; Lev

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147 SGE 00731 Silva, James; Gettings, Rachel; Kostedt, William; Watkins, Vicki. 2013. Pretreatment Targets for Salt Recovery from Marcellus Shale Gas Produced Water. GE Global Research Center. IWC

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148 SGE 00710 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

149 SGE 00586 State Review of Oil and Natural Gas Environmental Regulations (STRONGER). 2003. West Virginia Follow

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150 SGE 00587 States, Stanley et al. 2013. Marcellus Shale Drilling and Brominated THMs in Pittsburgh, Pa., Drinking Water. Journal AWWA. (August). AChapter E

—

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151 SGE 00350 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

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152 SGE 00768.A26 Tucker, Scott. 2014. Evaluating Characteristics of Source, Flowback, Produced Water for Effective Water Treatment. (May 29). & B

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154 SGE 00593 U.S. Energy Information Administration (EIA). 1993. Drilling Sideways

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156 SGE 00155 U.S. Energy Information Administration (EIA). 2010. Tight Sands Gas Plays, Lower 48 States. Prepared by EIA Office of Oil and Gas. (June). A

157 SGE 00153 U.S. Energy Information Administration (EIA). 2011. Lower 48 States Shale Plays. Prepared by EIA Office of Oil and Gas. (May). A

158 SGE 00487 U.S. Energy Information Administration (EIA). 2013. Annual Energy Outlook 2013 with Projections to 2040. DOE/EIA

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159 SGE 00595 U.S. Energy Information Administration (EIA). 2013. Drilling Productivit y Report: For Key Tight Oil and Shale Gas Regions. (October). A

160 SGE00761 U.S. EPA. 1989. Letter from T.P. O'Farrell (EPA) to C.B. Harriman (Steptoe & Johnson) about applicability of 40 C .F. R 435 Subpart C to CBM operations. A

161 SGE 00599 U.S. EPA. 1999. Biosolids Generation, Use, and Disposal in the United States. EPA 530

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

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163 SGE 00601 U.S. EPA. 2001. Small Entity Compliance Guide: Centralized Waste Treatment Effluent Limitations Guidelines and Pretreatment Standards (40C

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164 SGE 00600 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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165 SGE 00602 U.S. EPA. 2004. Local Limits Development Guidance Appendices. EPA 833

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166 SGE 00603 U.S. EPA. 2008. Clean Watersheds Needs Survey: 2008 Report to Congress. EPA 832 -R- 10

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167 SGE 00138 U.S. EPA. 2010. 2010 UIC Well Inventory 2010. Available http://water.epa.gov/type/groundwater/uic/class2/index.cfm online at: A

168 SGE 00604 U.S. EPA. 2010. Hydraulic Fracturing Research Study. EPA 600

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169 SGE 00620 U.S. EPA. 2011. (Region 3) Administrative Order for Compliance and Request for Information, EPA Docket No. CWA

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

171 SGE 00249 U.S. EPA. 2011. Introduction to the 833 -B- 11

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172 SGE 00136 U.S. EPA. 2011. Oil and Gas Production Wastes. http://www.epa.gov/radiation/tenorm/oilandgas.html A

173 SGE 00132 U.S. EPA. 2011. Underground Injection Control Program: Class II Wells

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174 SGE 00368 U.S. EPA. 2012. (Reg ion 3). Key Documents About Mid

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175 SGE 00608 U.S. EPA. 2012. Discharge Monitoring Report (DMR) Pollutant Tool. Downloaded on 1/28/2013. Available online at: http://cfpub.epa.gov/dmr/ Loading A

176 SGE 00279 U.S. EPA. 2012. Meeting Summary: Conference Call with North Star Disposal, Inc Regarding Underground Injection Operations in Ohio. (July 2). A

177 SGE 00276 U.S. EPA. 2012. Meeting with XTO Energy, Inc. about Unconventional Oil and Gas Sanitized. A

178 SGE 00635 U.S. EPA. 2012. Site Visit Report: Chesapeake Energy Corporation Marcellus Shale Gas Operations Sanitized. A

179 SGE 00275 U.S. EPA. 2012. Site Visit Report: Citrus Energy Shale Gas Operations. (January 22). Corporation Marcellus A

180 SGE 00300 U.S. EPA. 2012. Site Visit Report: Eureka Gas Operations. (February 25). Resources, LLC Marcellus Shale A

181 SGE 00299 U.S. EPA. 2012. Site Visit Report: US Gas Field Fluids Management (formerly Clean Streams) Marcellus Shale Gas Operations. (October 9). A

182 SGE 00742 U.S. EPA. 2012. States Pretreatment Coordinators' Call: Summary. (August 8). Quarterly Conference A

183 SGE 00636 U.S. EPA. 2012. Talisman Marcellus Operations Overview. (July 23). A

184 SGE 00611 U.S. EPA. 2012. UIC Program Primacy. Downloaded on 10/24/2013. Available online at: http://water.epa.gov/type/groundwater/uic/Primacy.cfm A

185 SGE 00612 U.S. EPA. 2013. DMR Loading Tool Download for New (NPDES No. PA0027511). Downloaded on 11/ 22/2013. Castle POTW AChapter E

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186 SGE 00726 U.S. EPA. 2013. Email Chain between Jacqueline Rios, Frank Brock, and Lisa Biddle About UICs in NY Taking Oil and Gas Wastewater. (November 13). A

187 SGE 00935 U.S. EPA. 2013. Letter to Lee McDonnell, PA DEP, Informing NPDES Permitting Authorities of Testing as Part of the Permit Application Process. (August 28). A

188 SGE 00613 U.S. EPA. 2013. Meeting Summary: Meeting with Industry Representatives About the Unconventional Oil and Gas Effluent Guideline Rulemaking. (February 28). A

189 SGE 00615 U.S. EPA. 2013. Radionuclides in Drinking Water: Waste Disposal Options. (November 26). A

190 SGE 00280 U.S. EPA. 2013. Site Visit Report: Anadarko Petroleum Marcellus Shale Gas Operations. (January 9). Corporation A

191 SGE 00625 U.S. EPA. 2013. Site Visit Report: Southwestern Energy (SWN) Shale Gas Operations Sanitized. Fayetteville A

192 SGE 00743 U.S. EPA. 2013. States Pretreatment Coordinators’ Bi

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193 SGE 00616 U.S. EPA. 2013. Summary of the Technical Workshop on Wastewater Treatment and Related Modeling. (April 18). A

194 SGE 00691 U.S. EPA. 2013. Summary of Modeling: Assessing Impacts (September). the Technical Workshop on Water Acquisition Through Modeling and Other Means. A

195 SGE 00935.A 0 1 U.S. EPA. 2013. Toxic Screening Analysis Spreadsheet. A

196 SGE 00762 U.S. EPA. 2013. US EPA Technology Innovation Project: ECOS/ACWA Conference Call. (April 25). A

197 SGE 00585 U.S. EPA. 2014. FracFocus Database. Office of Research and Development (ORD). A

198 SGE 00766 U.S. EPA. 2014. Lockhart, John V. Email Correspondence and EPA. (June 3). between WV DEP A

199 SGE 00783 U.S. EPA. 2014. Thorium. (February 28). Available online at: http://www.epa.gov/radiation/radionuclides/thorium.html A

200 SGE 00786 U.S. EPA. 2014. UOG Workgroup

— Warren, OH POTW 19). Info Request. (June A

201 SGE 00721 U.S. EPA. 201 5 . Evaluation of Hydraulic Fracturing Fluid Data FracFocus Chemical Disclosure Registry 1.0. (March). from the A

202 SGE 00785 U.S. EPA. 201 5 . Summary of Tribal Outreach Regarding Pretreatment Standards for Unconventional Oil and Gas (UOG) Extraction Wastewater

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203 SGE 00692 U.S. EPA . 201 5 . Unconventional Oil Treatment Technologies. & Gas (UOG) Extraction Wastewater A

204 SGE 00622 U.S. Geological Survey (USGS). 2013. Water Resources and Shale Gas/Oil Production in the Appalachian Basin

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206 SGE 00623 U.S. Government Accountability Office (GAO). 2012. Energy

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207 SGE 00624 University of Michigan. 2013. Hydraulic Fracturing in the State of Michigan. Graham Sustainability Institute Integrated Assessment Report Series. (September). B

208 SGE 00095 URS. 2011. Water

- Related Issues Marcellus Shale. (March 25). Associated with Gas Production in the B

209 SGE01095 USGS. 2015. Trends in Hydraulic Fracturing Distributions & Trt Fluids, Additives, Proppants, & Water Volumes Applied to US Wells Drilled, 1947

- 2010. A

210 SGE01095.A09 USGS. 2015. Trends in Hydraulic Fracturing Distributions & Trt Fluids, Additives, Proppants, & Water Volumes Applied to US Wells Drilled, 1947

- 2010: Attachment 9: Frac_Trtm_Type.xlsx A

211 SGE 00114 Van Dyke, Staffan. 2010. Tight Gas Sandstone: Is It Truly Unconventional? Oil & Gas Evaluation Report. (October). C

212 SGE 00011 Veil, John A. 2010. Water Management Technologies Used by Marcellus Shale Gas Producers. Prepared by Argonne National Laboratory. Prepared for U.S. DOE NETL. (July). Available at: http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/W aterMgmtinMar cellusfull.pdf A

213 SGE 00093 Veil, John; Puder, Markus G.; Elcock, Deborah; Redweik, Robert J. 2004. A White Paper Describing Produced Water from Production of Crude Oil, Natural Gas, and Coal Bed Methane. Prepared by Argonne National Laboratory. Prepared for U.S. DOE NETL. (January). A

214 SGE 00754 Vengosh, A.; Jackson, Robert B.; Warner, N.; Darrah, Thomas H.; Kondash, A. 2014. A Critical Review of the Risks to Water Resources from Unconventional Shale Gas Development and Hydraulic Fracturing in the United States. Environmental Science & Technology 48(15):8334

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215 SGE 00627 Vidic, Radisav; Brantley, S.L.; Vandenbossche, J.M.; Yoxtheimer, D.; Abad, J.D. 2013. Impact of Shale Gas Development on Regional Water Quality. Science 340( 6134). B

216 SGE 00629 Warner, Nathaniel R.; Christie, Cidney A.; Jackson, Robert B.; Vengosh, Avner. 2013. Impacts of Shale Gas Wastewater Disposal on Water Quality in Western Pennsylvania. Environmental Science & Technology 47(20):11849

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217 SGE 00295 Warren Water Pollution Control Facility. 2011. Fact Sheet for NPDES Permit Renewal, Warren Water Pollution Control Facility, 2011

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218 SGE 00767 West Virginia Department of Environmental Protection (WV DEP). 2010. Letter to City of Follansbee Re: WV/NPDES Permit No. WV0020273 Accepting Oil and Gas Wastewater. (December 15). AChapter E

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219 SGE 00485 West Virginia Department of Environmental Protection (WV DEP). 2011. Consent Order Issued Under the Water Pollution Control Act, West Virginia Code, Chapter 22, Article 11. A

220 SGE 00488 West Virginia Department of Environmental Pr otection (WV DEP). 2012. NPDES Water Pollution Control Permit WV0116441. Reserved Environmental Services CWT Permit. A

221 SGE01113 West Virginia Department of Environmental Protection (WV DEP). 2009. WV/NPDES Permit No WV0023302 Clarksburg Sanitary Board Accepting Oil and Gas Wastewater. A

222 SGE01114 West Virginia Department of En vironmental Protection (WV DEP) . 2009. WV/NPDES Permit No, WV0023230 City of Wheeling Accepting Oil and Gas Wastewater. A

223 SGE 00554 Widmer Engineering, Inc. 2010. New Castle Sanitation Authority, New Castle, Lawerance County, Pennsylvania: Annual Pretreatment Report, 2009 Operating Year. Prepared for New Castle Sanitation Authority. A

224 SGE 00064 Williams, John. 2011. Marcellus Shale

- Gas Development and Water

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225 SGE 00632 Williams, John. n.d. The Marcellus Shale Gas Play: Geology, Development, and Water

- Resource Impact Mitigation. USGS: New York Water Science Center. A

226 SGE 00633 Wilson, Jessica; Van Briesen, Jeanne. 2013. Oil and Gas Produced Water Management and Surface Drinking Water Sources in Pennsylvania. Environmental Practice 14(4):288

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227 SGE 00725 Wolford, Robert. 2011. Characterization of Organics in the Marcellus Shale Flowback and Produced Waters. Pennsylvania State University. Master’s Thesis. (August). B

228 SGE 00774 Ziemkiewicz, Paul. 2013. Water Quality Literature Review and Field Monitoring of Active Shale Gas Wells. Phase I: Assessing Environmental Impacts of Horizontal Gas Well Drilling Operations. West Virginia Department of Environmental Protection. (Fe bruary 15). AChapter F

—

Appendices



### 161 

## Chapter F. A PPENDICES



### A PPENDIX 

### F.1 R EFERENCE 

### F ILES IN 

### FDMS

Table F

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

DCN Title Description Relevant TDD Section(s)

SGE00596 Analysis of Centralized Waste Treatment (CWT) Facilities Accepting UOG Extraction Wastewater Describes the various data sources used to identify CWT facilities that have accepted UOG wastewater and explains the different CWT facility analyses that are presented in
Section D. 

### 4 of the TDD. D. 1

, D. 

### 4

SGE00692 Unconventional Oil and Gas (UOG) Extraction Wastewater Treatment Technologies Summarizes technologies that are currently

use d to treat UOG wastewater at full

- scale operations and technologies not currently used to treat UOG extraction wastewater, but which may be applied in the future

. D. 

### 3

SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction Explains various data analyses presented in Chapters B, C, and D of the TDD, involving well drilling and construction, historical and current drilling activity, UOG resource potential, fracturing fluid chemical additives, and reuse/r ecycle. B. 3 , C.Intro, C. 

### 1

, C. 

### 2 , D. 

### 1 , D. 

### 2

, D. 

### 3

SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation Describes the various data sources used to identify UOG wastewater volumes and characteristics data and explains the process that was used to standardize and summarize the data. B. 3 , C.Intro , C. 

### 2

, C. 

### 3

SGE00736 Analysis of Active Underground Injection for Disposal Wells Explains the compilation of underground injection wells data from various sources

. D. 1 , D. 

### 2 , D. 

### 4

SGE00739 Analysis of Pennsylvania Department of Environmental Protection’s (PA DEP) Oil and Gas Waste Reports Explains the PA DEP waste reports data and explains the processes that were used to analyze the data. C. 2 , D. 

### 1 , D. 

### 5

SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater Explains the well drilling process in more detail, with focus on drilling wastewater volumes and constituent concentrations. B. 2 , C. 

### 2 , C. 

### 3

, D. 

### 1Chapter F

—

Appendices



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

DCN Title Description Relevant TDD Section(s)

SGE00785 Summary of Tribal Outreach Regarding Pretreatment Standards for Unconventional Oil and Gas (UOG) Extraction Wastewater Summarizes the data collected as part of the tribal outrea ch efforts associated with the proposed rule. D. 

### 5

SGE00929 Publicly Owned Treatment Works (POTW) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction Describes the various data sources used to identify POTWs that have accepted UOG wastewater and explains the different POTW analyses that are presented in Section D. 

### 5 of the TDD. D. 

### 5

SGE00932 Profile of the Oil and Gas Extraction (OGE) Sector

, with Focus on Unconventional Oil and Gas (UOG) Extraction Provides economic background information about the oil and gas industry. B.Intro

SGE00933 Radioactive Materials in the Unconventional Oil and Gas (UOG) Industry Provides background information about radioactive elements in the UOG industry, with focus on radium

- 226 and radium

- 228. C. 3 , D. 

### 5

SGE00963 Analysis of DI Desktop ® Summarizes the DI Desktop® data source and where it is cited throughout the proposed rule analyses. B. 3.2

SGE01016 Conventional Oil and Gas (COG) Memorandum for the Record Summarizes COG extraction wastewater characteristics and management and disposal practices used for COG extraction wastewater. N/A

N/A

—

Not ApplicableChapter F

—

Appendices



### 163 Table F

- 2

. Crosswalk Between TDD and Supporting Memoranda

TDD Table or Figure Number TDD Table/Figure Title In a Supporting Memo (Y/N)? a Source or Supporting Memo DCN (s) Supporting Memo Title (s) Figure A

- 1 UOG Extraction Wastewater No (Created by the EPA) — —

Table A

- 1 Summary of State Regulations No SGE00187, SGE00254, SGE00545, SGE00766, SGE00767, SGE00982, SGE00983 —

Figure B

- 1 Historical and Projected Oil Production by Resource Type No SGE00487

—

Figure B

- 2 Historical and Projected Natural Gas Production by Resource Type No SGE00989

—

Figure B

- 3 Major U.S. Shale Plays (Updated May 9, 2011) No SGE00153

— Figure B

- 4 Major U.S. Tight Plays (Updated June 6, 2010) No SGE00155

— Figure B

- 5 Geology of Formations Containing Various Hydrocarbons No SGE00594

—

Figure B

- 6 Horizontal (A), Vertical (B), and Directional (C) Drilling Schematic No SGE00593

—

Figure B

- 7 Length of Time to Drill a Well in Various UOG Formations Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction Figure B

- 8 Hydraulic Fracturing Schematic No SGE00604

— Figure B

- 9 Freshwater Impoundment No SGE00275

— Figure B

- 10 Vertical Gas and Water Separator No SGE00625

— Figure B

- 11 Fracturing Tanks No SGE00625

— Figure B

- 12 Produced Water Storage Tanks No SGE00275

— Figure B

- 13 Number of Active U.S. Onshore Rigs by Trajectory and Product Type over Time Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas ExtractionChapter F

—

Appendices



### 164 Table F

- 2

. Crosswalk Between TDD and Supporting Memoranda

TDD Table or Figure Number TDD Table/Figure Title In a Supporting Memo (Y/N)? a Source or Supporting Memo DCN (s) Supporting Memo Title (s) Figure B

- 14 Projections of UOG Well Completions Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

Table B

- 1 Characteristics of Reservoirs Containing UOG and COG Resources No SGE00114, SGE00345, SGE00527, SGE00533 —

Table B

- 2 Active Onshore Oil and Gas Drilling Rigs by Well Trajectory and Product Type (as of November 8, 2013) Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

Table B

- 3 UOG Potential by Resource Type as of January 1, 2012 Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction Figure C

- 1 UOG Extraction Wastewater Volumes for Marcellus Shale Wells in Pennsylvania (2004

– 2013) Yes SGE00739 Analysis of Pennsylvania Department of Environmental Protection’s (PA DEP) Oil and Gas Waste Reports

Figure C

- 2 Ranges of Typical Produced Water Generation Rates over Time After Fracturing Yes SGE00 724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

Figure C-3 Anions and Cations Contributing to TDS Concentrations in Shale and Tight Oil and Gas Formations Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

Figure C

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

- Term Produced Water (LTPW) from Shale and Tight Oil and Gas Formations Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

Figure C

- 5 Barium Concentrations in UOG Produced Water from Shale and Tight Oil and Gas Formations Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data CompilationChapter F

—

Appendices



### 165 Table F

- 2

. Crosswalk Between TDD and Supporting Memoranda

TDD Table or Figure Number TDD Table/Figure Title In a Supporting Memo (Y/N)? a Source or Supporting Memo DCN (s) Supporting Memo Title (s) Figure C

- 6 Constituent Concentrations over Time in UOG Produced Water from the Marcellus and Barnett Shale Formations No SGE00414

—

Table C

- 1 Sources for Base Fluid in Hydraulic Fracturing Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

Table C

- 2 Fracturing Fluid Additives, Main Compounds, and Common Uses No SGE00070, SGE00721, SGE00780, SGE00781, SGE00966 —

Table C

- 3 Most Frequently Reported Additive Ingredients Used in Fracturing Fluid in Gas and Oil Wells from FracF ocus (2011

- 2013) Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

Table C

- 4 Median Drilling Wastewater Volumes for UOG Horizontal and Vertical Wells in Pennsylvania Yes SGE00739 Analysis of Pennsylvania Department of Environmental Protection’s (PA DEP) Oil and Gas Waste Reports

Table C

- 5 Drilling Wastewater Volumes Generated per Well by UOG Formation Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater

Table C

- 6 UOG Well Flowback Recovery by Resource Type an d Well Trajectory Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

Table C

- 7 Long

- Term Produced Water Generation Rates by Resource Type and Well Trajectory Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

Table C

- 8 Produced Water Volume Generation by UOG Formation Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilat ion

Table C

- 9 Availability of Data for UOG Extraction Wastewater Characterization No (Created by th e EPA) — —

Table C

- 10 Concentrations of Select Classical and Conventional Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling WastewaterChapter F

—

Appendices



### 166 Table F

- 2

. Crosswalk Between TDD and Supporting Memoranda

TDD Table or Figure Number TDD Table/Figure Title In a Supporting Memo (Y/N)? a Source or Supporting Memo DCN (s) Supporting Memo Title (s)

Table C

- 11 Concentrations of Select Classical and Conventional Constituents in UOG Produced Water Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

Table C

- 12 Concentrations of Select Anions and Cations Contributing to TDS in UOG Drilling Wastewater from Marcellus Shale Formation Wells Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater

Table C

- 13 Concentrations of Select Anions and Cations Contributing to TDS in UOG Produced Water Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

Table C

- 14 Concentrations of Select Organic Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater

Table C

- 15 Concentrations of Select Organic Constituents in UOG Produced Water Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

Table C

- 16 Conc entrations of Select Metal Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater

Table C

- 17 Concentrations of Select Metal Constituents in UOG Produced Water Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

Table C

- 18 Concentrations of Select Radioactive Constituents in UOG Drilling Wastewater from Marcellus Shale Formation Wells Yes SGE00740 Unconventional Oil and Gas (UOG) Drilling Wastewater

Table C

- 19 Concentrations of Select Radioactive Constituents in UOG Produced Water Yes SGE00724 Unconventional Oil and Gas (UOG) Produced Water Volumes and Characterization Data Compilation

Table C

- 20 Conc entrations of Radioactive Constituents in Rivers, Lakes, Groundwater, and Drinking Water Sources Throughout the United States (pCi/L) No SGE00769

—

Figure D

- 1 UOG Produced Water Management Methods No (Created by the EPA) — —Chapter F

—

Appendices



### 167 Table F

- 2

. Crosswalk Between TDD and Supporting Memoranda

TDD Table or Figure Number TDD Table/Figure Title In a Supporting Memo (Y/N)? a Source or Supporting Memo DCN (s) Supporting Memo Title (s) Figure D

- 2 UOG Drilling Wastewater Management Methods No (Created by the EPA) — —

Figure D

- 3 Management of UOG Drilling Wastewater Generated by UOG Wells in Pennsylvania (2008

– 2013) Yes SGE00739 Analysis of Pennsylvania Department of Environmental Protection’s (PA DEP) Oil and Gas Waste Reports

Figure D

- 4 Active Disposal Wells and CWT Facilities Identified in the Appalachian Basin No (Created by the EPA) — —

Figure D

- 5 Flow Diagram of On

- the

- Fly UOG Produced Water Treatment for Reuse/Recycle No SGE00331

—

Figure D

- 6 Hypothetical UOG Produced Water Generation and Base Fracturing Fluid Demand over Time Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

Figure D -7 UOG Extraction Wastewater Management Practices Used in the Marcellus Shale (Top: Southwestern Region; Bottom: Northeastern Region) No SGE00579

—

Figure D

- 8 Number of Known Active CWT Facilities over Time in the Marcellus and Utica Shale Formation Yes SGE00596 Analysis of Centralized Waste Treatment (CWT) Facilities Accepting UOG Extraction Wastewater

Figure D

- 9 Typical Process Flow Diagram at a POTW No SGE00602

— Figure D

- 10 Clairton POTW: Technical Evaluation of Treatment Processes’ Ability to Remove Chlorides and TDS Yes SGE00929 Publicly Owned Treatment Works (POTW) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction Figure D

- 11 McKeesport POTW: Technical Evaluation of Treatment Processes’ Ability to Remove Chlorides and TDS Yes SGE00929 Publicly Owned Treatment Works (POTW) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas ExtractionChapter F

—

Appendices



### 168 Table F

- 2

. Crosswalk Between TDD and Supporting Memoranda

TDD Table or Figure Number TDD Table/Figure Title In a Supporting Memo (Y/N)? a Source or Supporting Memo DCN (s) Supporting Memo Title (s) Figure D

- 12 Ridgway POTW: Annual Average Daily Effluent Concentrations and POTW Flows Yes SGE 00929 Publicly Owned Treatment Works (POTW) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction Figure D

- 13 Johnstown POTW: Annual Average Daily Effluent Concentrations and POTW Flows Yes SGE00929 Publicly Owned Treatment Works (POTW) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction Figure D

- 14 California POTW: Annual Average Daily Effluent Concentrations and POTW Flows Yes SGE00929 Publicly Owned Treatment Works (POTW) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction Figure D

- 15 Charleroi POTW: Annual Average Daily Effluent Concentrations and POTW Flows Yes SGE00929 Publicly Owned Treatment Works (POTW) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extractio n Figure D

- 16 Barium Sulfate Scaling in Haynesville Shale Pipe No SGE00768.A26

—

Figure D

- 17 THM Speciation in a Water Treatment Plant (1999

– 2013) No SGE00800

—

Table D

- 1 UOG Produced Water Management Practices Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

Table D

- 2 Distribution of Active Class II Disposal Wells Across the United States Yes SGE00736 Analysis of Active Underground Injection for Disposal Wells

Table D

- 3 Reuse/Recycle Practices in 2012 as a P ercentage of Total Produced Water Generated as Reported by Respondents to 2012 Survey No SGE00575

—Chapter F

—

Appendices



### 169 Table F

- 2

. Crosswalk Between TDD and Supporting Memoranda

TDD Table or Figure Number TDD Table/Figure Title In a Supporting Memo (Y/N)? a Source or Supporting Memo DCN (s) Supporting Memo Title (s)

Table D

- 4 Reported Reuse/Recycle Criteria Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

Table D

- 5 Reported Reuse/Recycle Practices as a Percentage of Total Fracturing Volume Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

Table D

- 6 Number, by State, of CWT Facilities That Have Accepted or Plan to Accept UOG Extraction Wastewater Yes SGE00596 Analysis of Centralized Waste Treatment (CWT) Facilities Accepting UOG Extraction Wastewater

Table D

- 7 Typical Composition of Untreated Domestic Wastewater No SGE00167

—

Table D

- 8 Typical Percent Removal Capabilities from POTWs with Secondary Treatment No SGE00600

—

Table D

- 9 U.S. POTWs by Treatment Level in 2008 No SGE00603

— Table D

- 10 POTWs That Accepted UOG Extraction Wastewater from Onshore UOG Operators Yes SGE00929 Publicly Owned Treatment Works (POTW) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extractio n Table D

- 11 Percentage of Total POTW Influent Wastewater Composed of UOG Extraction Wastewater at POTWs Accepting Wastewater from UOG Operators Yes SGE00929 Publicly Owned Treatment Works (POTW) Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

Table D

- 12 Summary of Studies About POTWs Receiving Oil and Gas Extraction Wastewater Pollutants No (Created by the EPA) — —

Table D

- 13 Clairton Influent Oil and Gas Extraction Wastewater Characteristics No SGE00748

—

Table D

- 14 Trucked COG Extraction Wastewater Treated at McKeesport POTW from November 1 Through 7, 2008 No SGE00745

—Chapter F

—

Appendices



### 170 Table F

- 2

. Crosswalk Between TDD and Supporting Memoranda

TDD Table or Figure Number TDD Table/Figure Title In a Supporting Memo (Y/N)? a Source or Supporting Memo DCN (s) Supporting Memo Title (s)

Table D

- 15 McKeesport POTW Removal Rates Calculated for Local Limits Analysis No SGE00745

—

Table D

- 16 Constituent Concentrations in UOG Extraction Wastewater Treated at the McKeesport POTW Before Mixing with Other Influent Wastewater No SGE00525

—

Table D

- 17 McKeesport POTW Effluent Concentrations With and Without UOG Extraction Wastewater No SGE00525

—

Table D

- 18 Charleroi POTW Paired Influent/Effluent Data and Calculated Removal Rates No SGE00751

—

Table D

- 19 Franklin Township POTW Effluent Concentrations With and Without Industrial Discharges from the Tri

- County CWT Facility No SGE00525

—

Table D

- 20 TDS Concentrations in Baseline and Pilot Study Wastewater Samples at Warren POTW No SG E00616

—

Table D

- 21 EPA Region 5 Compliance Inspection Sampling Data No SGE00616

—

Table D

- 22 Inhibition Threshold Levels for Various Treatment Processesa No SGE00602

—

Table D

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

– 2009) No SGE00554

—

Table D

- 24 NPDES Permit Limit Violations from Outfall 001 of the New Castle POTW (NPDES Permit Number PA0027511) No SGE00612, SGE00620

—

Table D

- 25 Concentrations of DBPs in Effluent Discharges at One POTW Not Accepting Oil and Gas Wastewater and at Two POTWs Accepting Oil and Gas Wastewater (μg/L ) No SGE00535

—

Figure F

- 1 Constituent Concentrations over Time in UOG Produced Water from the Marcellus and Barnett Shale Formations No SGE00414

—Chapter F

—

Appendices



### 171 Table F

- 2

. Crosswalk Between TDD and Supporting Memoranda

TDD Table or Figure Number TDD Table/Figure Title In a Supporting Memo (Y/N)? a Source or Supporting Memo DCN (s) Supporting Memo Title (s)

Table F

- 1 TDD Supporting Memoranda and Other Relevant Documents Available in FDMS No (Created b y the EPA) — —

Table F

- 2 Crosswalk Between TDD and Supporting Memoranda No (Created by the EPA) — —

Table F

- 3 UOG Resource Potential: Shale as of January 1, 2012 Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

Table F

- 4 UOG Resource Potential: Tight as of January 1, 2012 Yes SGE00693 Data Compilation Memorandum for the Technical Development Document (TDD) for Proposed Effluent Limitations Guidelines and Standards for Oil and Gas Extraction

a— Unless otherwise noted, figures and/or tables not included in a supporting memorandum were taken directly from a source witho ut calculation or interpretation.Chapter F

—

Appendices



### 172 A PPENDIX 

### F. 2 UOG R ESOURCE 

### P OTENTIAL BY 

### S HALE AND 

### T IGHT 

### F ORMATIONS



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

Gas EUR UOG Formation Resource Oil EUR ( MM b ls ( Bcf per Oil TRR Gas TRR New Well EIA Region EIA Basin Name Type per well) well) (MMbls) (Bcf) Potential

1— East Appalachian Devonian Shale g as 0.000 0.058 0 20,800 358,600

Marcellus Shale g as 0.000 1.317 0 118,900 90,300

Utica Shale g as 0.000 0.330 0 37,400 113,500

Shale o il 0.063 0.057 1,000 900 15,900

Illinois New Albany Shale g as 0.000 1.721 0 41,700 24,200 Michigan Antrim Shale g as 0.000 0.157 0 15,300 97,500

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 0.000 3.455 0 70,900 20,500

Western Gulf Eagle Ford Shale g as 0.177 1.549 6,100 53,400 34,500

Shale o il 0.101 0.212 3,300 6,900 32,500

Pearsall Shale g as 0.000 1.090 0 7,800 7,200

Tuscaloosa Shale o il 0.092 0.019 2,900 600 31,600

Woodbine Shale o il 0.108 0.054 600 300 5,600

3— Midcontinent Anadarko Cana Woodford Shale g as 0.014 1.232 100 8,900 7,200

Shale o il 0.038 0.415 100 1,100 2,700

Arkoma Caney Shale g as 0.000 0.330 0 1,100 3,300 Fayetteville Shale g as 0.000 1.284 0 29,800 23,200

Woodford Shale g as 0.000 1.422 0 6,700 4,700

Black Warrior Chattanooga Shale g as 0.000 0.970 0 1,600 1,600

4— Southwest Barnett Shale Gas Shale g as 0.000 0.377 0 20,300 53,900

Permian Wolfcamp Shale o il 0.068 0.217 3,400 10,900 50,200

Barnett

- Woodford Shale g as 0.000 1.513 0 15,800 10,400 Avalon/BoneSpring Shale o il 0.080 0.000 2,000 0 25,000

5— Rocky Mountain Denver Niobrara Shale o il 0.011 0.073 400 2,700 37,000

Greater Green River Hilliard

- Baxter

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

—

Appendices



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

EIA Region EIA Basin UOG Formation Name Resource Type Oil EUR ( MM b ls
per well) Gas EUR ( Bcf per

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

5— Rocky Mountain Montana Thrust Belt All t ight o il p lays Shale o il 0.113 0.075 600 400 5,300

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 Shale g as 0.000 0.880 0 10,900 12,400

Williston Gammon Shale g as 0.000 0.440 0 3,400 7,700

Bakken Shale o il 0.142 0.096 9,300 6,300 65,500

6— West Coast Columbia Basin Centered Shale g as 0.000 1.400 0 12,200 8,700 San Joaquin/Los Angeles Monterey/Santos Shale o il 0.502 0.502 600 600 1,200

Source s : 48 DCN SGE 00693

Abbreviations: EUR

— estimated ultimate recovery (per well); MMbls

— million barrels; B cf —b illion cubic feet of gas; TRR —t echnically recoverable resources



### Table F-4. UO G Resource Potential: Tight as of January 1, 2012

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 Clinton

- Medina Tight g as 0.003 0.060 500 11,700 195,000

Tuscarora Tight g as 0.000 2.172 0 4,400 2,000 Michigan Berea Sand Tight g as 0.000 0.143 0 8,100 56,600

2— Gulf Coast TX

- LA

- MS Salt Cotton Valley Tight g as 0.009 1.472 900 152,700 103,700

Western Gulf Olmos Tight g as 0.005 1.093 100 23,600 21,600 Vicksburg Tight g as 0.000 1.473 0 3,900 2,600

Wilcox Lobo Tight g as 0.000 1.404 0 10,100 7,200

Austin Chalk Tight o il 0.086 0.048 7,600 4,300 88,800

Buda Tight o il 0.108 0.070 3,700 2,400 34,300

3— Midcontinent Anadarko Cleveland Tight g as 0.036 0.394 100 1,100 2,800

Granite Wash Tight g as 0.046 0.948 600 12,300 13,000Chapter F

—

Appendices



### 174 Table F

- 4

. UO G Resource Potential: Tight as of January 1, 2012

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

Red Fork Tight g as 0.000 0.593 0 1,000 1,700

4— Southwest Permian Abo Tight g as 0.101 0.182 1,000 1,800 9,900 Canyon Tight g as 0.002 0.209 100 10,900 52,200 Spraberry Tight o il 0.108 0.113 8,100 8,500 75,200

5— Rocky Mountain Denver Muddy Tight g as 0.000 0.182 0 11,500 63,200

Greater Green River All Tight Oil Plays Tight o il 0.135 0.015 900 100 6,700

North Central Montana Bowdoin -G reenhorn Tight g as 0.000 0.151 0 300 2,000

Paradox Fractured Interbed Tight o il 0.543 0.434 1,000 800 1,800

San Juan Dakota Tight g as 0.000 0.416 0 6,100 14,700

Mesaverde Tight g as 0.000 0.464 0 5,800 12,500

Pictured Cliffs Tight g as 0.000 0.397 0 200 500

SW Wyoming Fort Union

- Fox Hills Tight g as 0.000 1.047 0 15,800 15,100

Frontier Tight g as 0.009 0.273 200 6,200 22,700

Lance Tight g as 0.016 1.012 300 18,700 18,500

Lewis Tight g as 0.000 0.248 0 7,700 31,000 All Tight Oil Plays Tight o il 0.165 0.015 1,100 100 6,700

Uinta

- Piceance Iles

- Mesaverde Tight g as 0.000 0.502 0 17,100 34,100

Wasatch

- Mesaverde Tight g as 0.023 0.463 400 8,200 17,700

Williams Fork Tight g as 0.000 0.456 0 7,600 16,700 All Tight Oil Plays Tight o il 0.056 0.111 100 200 1,800

Williston Judith River

- Eagle Tight g as 0.000 0.158 0 1,000 6,300

Wind River Mesaverde/Frontier Shallow Tight g as 0.000 0.768 0 4,400 5,700

Source s: 48 DCN SGE 00693

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



### 175 A PPENDIX 

### F.3 C ONSTITUENT 

### C ONCENTRATIONS OVER 

### T IME IN 

### UOG P RODUCED 

### W ATER FROM 

### M ARCELLUS AND 

### B ARNETT 

### S HALE 

### F ORMATIONS

Source: The EPA generated this figure using data from 85 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