Detailed Study of the
Centralized Waste Treatment
Point Source Category
for Facilities Managing
Oil and Gas Extraction Wastes
EPA-821-R-18-004
U.S. Environmental Protection Agency
Engineering and Analysis Division
Office of Water
1200 Pennsylvania Avenue, NW
Washington, D.C. 20460
www.epa.gov/eg
May 2018

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Contents
CONTENTS
Page
1.	Executive Summary	1-1
2.	Introduction	2-1
2.1 References	2-4
3.	Existing Effluent Limitations Guidelines for Oil and Gas Extraction
Wastes	3-1
3.1	Effluent Guidelines Background	3-1
3.2	Centralized Waste Treatment Point Source Category Effluent Guidelines	3-2
3.3	Oil and Gas Extraction Point Source Category Effluent Guidelines	3-4
3.4	Interrelationship Between the CWT and Oil and Gas Extraction Effluent
Guidelines	3-5
3.5	References	3-7
4.	Industry Profile	4-1
4.1	Overview of the CWT Industry and the Segment Receiving and Treating
Oil and Gas Extraction Wastewaters	4-1
4.2	Profile of CWT Facilities	4-5
4.3	In-Scope CWT Facility Summaries	4-13
4.3.1	Byrd/Judsonia Water Reuse/Recycle Facility	4-21
4.3.2	Clarion/Altela Environmental Services (CAES)	4-22
4.3.3	Eureka Resources, Standing Stone Facility	4-23
4.3.4	Eureka Resources, Williamsport 2nd Street Plant	4-25
4.3.5	Fairmont Brine Processing, LLC	4-25
4.3.6	Fluid Recovery Services: Franklin Facility	4-27
4.3.7	Fluid Recovery Services: Josephine Facility	4-28
4.3.8	Fluid Recovery Services: Creekside Treatment Facility	4-29
4.3.9	Max Environmental Technologies, Inc - Yukon Facility	4-30
4.3.10	Patriot Water Treatment, LLC	4-31
4.3.11	Waste Treatment Corporation	4-33
4.4	Other Facilities Treating Oil and Gas Extraction Wastes	4-35
4.5	Demand for CWT Services for Managing Oil and Gas Extraction Wastes	4-36
4.6	Competition and Cost Pass-Through Potential in OGE/UOG Activity
Basins	4-37
4.7	Location and Number of Onshore Oil and Gas Extraction Wells	4-37
4.8	Proximity of Production Wells to CWT Facilities	4-39
4.9	References	4-41
5.	Wastewater Characterization and Management	5-1
5.1	Types of Oil and Gas Extraction Waste and Wastewater Characteristics	5-1
5.1.1	Drilling Wastes	5-2
5.1.2	Produced Water	5-7
5.2	CWT Wastewater Characteristics	5-17
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes	i

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Contents
CONTENTS (Continued)
Page
5.2.1	DMR Data	5-17
5.2.2	EPA Sampling Data	5-19
5.3	Oil and Gas Extraction Wastewater Volumes and Management Practices	5-28
5.4	References	5-31
6.	Wastewater Management Practices	6-1
6.1	Chemical Precipitation	6-2
6.1.1	Principle and Process Description	6-2
6.1.2	Capabilities and Limitations	6-2
6.2	Costs	6-6
6.2.1 Vendors	6-7
6.3	Filtration/Flotation/Sedimentation	6-8
6.3.1	Principle and Process Descriptions	6-8
6.3.2	Capabilities and Limitations	6-10
6.3.3	Costs	6-11
6.3.4	Vendors	6-12
6.4	Evaporation/Condensation	6-12
6.4.1	Principle and Process Description	6-13
6.4.2	Capabilities and Limitations	6-15
6.4.3	Costs	6-20
6.4.4	Vendors	6-22
6.5	Crystallization	6-23
6.5.1	Principle and Process Description	6-23
6.5.2	Capabilities and Limitations	6-23
6.5.3	Costs	6-29
6.5.4	Vendors	6-30
6.6	Reverse Osmosis	6-31
6.6.1	Principle and Process Description	6-31
6.6.2	Capabilities and Limitations	6-32
6.6.3	Costs	6-38
6.6.4	Vendors	6-39
6.7	Biological Treatment	6-40
6.7.1	Principle and Process Description	6-40
6.7.2	Capabilities and Limitations	6-41
6.7.3	Costs	6-43
6.7.4	Vendors	6-43
6.8	Summary	6-44
6.9	Performance Data Reference Information	6-45
6.10	References	6-46
7.	Pollutant Discharge Loadings	7-1
7.1	Direct Di scharges	7-2
7.2	Indirect Discharges	7-4
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes	ii

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Contents
CONTENTS (Continued)
Page
7.3	Summary of Pollutant Loadings for Discharging CWT Facilities
Accepting Oil and Gas Extraction Wastewater	7-5
7.4	References	7-6
8.	Economic Profile	8-1
8.1	Facilities and Firms Receiving and Treating OGE Wastewater	8-1
8.1.1	40 CFR Part 437 In- Scope CWT Facilities that Treat Oil and Gas
Extraction Wastes	8-3
8.1.2	Other Facilities that Treat Oil and Gas Extraction Wastes	8-3
8.1.3	Commercial and Non- Commercial CWT Facilities	8-4
8.2	Demand for CWT facilities that Treat Oil and Gas Wastewater and Output
Projections	8-4
8.3	Regional Trend/Outlook Discussion for CWT facilities that Treat Oil and
Gas Wastewater	8-5
8.4	Financial Outlook for CWT facilities that Treat Oil and Gas Extraction
Wastewater	8-6
8.5	References	8-6
9.	Environmental Impacts	9-1
9.1	Constituents in O&G Wastewater at CWT Facilities	9-1
9.1.1	TDS	9-1
9.1.2	Halides	9-2
9.1.3	Metals	9-3
9.1.4	TENORM	9-3
9.1.5	Other Constituents	9-4
9.2	Exposure Pathways for CWT Waste Streams	9-5
9.2.1	Discharge of CWT Effluent to Rivers and Streams	9-5
9.2.2	Solid Waste and Sludge	9-5
9.2.3	Transportation Spills and Accidental Releases	9-8
9.2.4	Air Emissions	9-8
9.3	Downstream Impacts of CWT Effluent	9-9
9.3.1	TDS	9-9
9.3.2	Chloride	9-11
9.3.3	Bromide	9-13
9.3.4	Metals	9-15
9.3.5	TENORM	9-15
9.3.6	Summary: Impacts to Water Quality and Sediment	9-18
9.4	Human Health Impacts	9-20
9.4.1	Documented Drinking Water Impacts	9-20
9.4.2	Potential Human Health Impacts	9-23
9.5	Aquatic Life Impacts	9-26
9.5.1	Documented Aquatic Life Impacts	9-26
9.5.2	Potential Aquatic Life Impacts	9-30
9.6	Other Impacts	9-31
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes	iii

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Contents
CONTENTS (Continued)
Page
9.6.1	Impacts to POTWs	9-31
9.6.2	Impacts to Other Water Uses	9-32
9.6.3	Air Quality Impacts	9-35
9.7	Data Gaps	9-36
9.7.1	Lack of Chemical Information	9-36
9.7.2	Geography	9-36
9.7.3	Direct Impacts Data	9-36
9.8	References	9-37
10. Data Sources	10-1
10.1	NPDES Permits and Fact Sheets	10-1
10.2	EPA Databases	10-1
10.3	EPA'sCWT Rulemaking	10-2
10.4	EPA's Oil and Gas Extraction Rulemakings	10-2
10.5	U.S. Geological Survey Data	10-3
10.6	Data from State Agencies	10-3
10.7	Drillinginfo's (DI) Desktop® Database	10-3
10.8	Literature and Internet Searches	10-4
10.9	References	10-4
Appendix A: REGULATORY TABLES
Appendix B: WELL COUNT DATA
Appendix C: PROFILE OF THE NAICS CODES TRADITIONALLY ASSOCIATED WITH
THE CWT INDUSTRY
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
IV

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List of Tables
LIST OF TABLES
Page
Table 3-1. Applicability of Effluent Guidelines Levels of Control to Types of Discharger	3-2
Table 3-2. Pollutant Classes Regulated by Effluent Guidelines Levels of Control	3-2
Table 3-3. Pollutant Categories Regulated Under Each Subpart of the CWT Effluent
Guidelines and Standards	3-4
Table 3-4. Levels of Control by Subcategory in the Oil and Gas Extraction
Effluent Guidelines	3-4
Table 3-5. Subparts of 40 CFR Part 435 and their Applicability and Limitations	3-5
Table 4-1. NAICS Codes of Centralized Waste Treatment Industry and Other Industries
Providing Wastewater Services to Oil and Gas Extraction Operations	4-3
Table 4-2. Business Models for Firms Offering Wastewater Management
Services to the Oil and Gas Extraction Industry	4-4
Table 4-3. Direct Discharging CWT Facilities in 2016, Identified by the DMR Pollutant
Loading Tool	4-6
Table 4-4. Summary of In-Scope Discharging CWT Facilities Treating Oil and Gas
Extraction Wastes	4-12
Table 4-5. List of Facilities Visited by EPA	4-13
Table 4-6. In-Scope Facility Summary - Location Information	4-14
Table 4-7. In-Scope Facility Summary - Permit and Discharge Information	4-16
Table 4-8. In-Scope Facility Summary - Wastes Accepted	4-17
Table 4-9. In-Scope Facility Summary - Treatment Technologies Utilized	4-18
Table 4-10. In-Scope Facility Summary - Effluent Limitations for Select Parameters Not
Currently Regulated at 40 CFR Part 437 (Monthly Averages)	4-19
Table 4-11. In-Scope Facility Summary - Effluent Limitations for Select Parameters Not
Currently Regulated at 40 CFR Part 437 (Daily Maximums)	4-20
Table 4-12. Select Oil and Gas Wastewater Treatment Facilities with TDS
Removal Technologies	4-35
Table 4-13. Counts of Total Oil and Gas Extraction Wells and Oil and Gas Extraction
Wells within 100 Miles of a CWT Facility, by State	4-40
Table 5-1. Ra-226, Ra-228, K-40, Gross Alpha and Gross Beta Activity in Drilling Fluids
(PA DEP, 2016)	5-4
Table 5-2. Ra-226, Ra-228, K-40, Gross Alpha and Gross Beta Activity in Fracturing
Fluids (PA DEP, 2016)	5-4
Table 5-3. Concentrations of Select Pollutants in Drilling Wastewater (Rost, 2010a and
2010b)	5-5
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes	v

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List of Tables
LIST OF TABLES (Continued)
Page
Table 5-4. Concentrations of Select Pollutants in Drilling Wastewater (U.S. EPA, 2013)	5-5
Table 5-5. Concentrations of Select Pollutants in Drilling Wastewater	5-6
Table 5-6. Type and Purpose of Additives used in Well Development, Stimulation
and Maintenance	5-8
Table 5-7. Identified Data Sources for Produced Water Characteristics	5-9
Table 5-8. Concentrations of Select Pollutants in Produced Water (ORD, 2014)	5-13
Table 5-9. Ra-226, Ra-228, K-40, Gross Alpha and Gross Beta Activity in Unfiltered
Produced Water (PA DEP, 2016)	5-14
Table 5-10. Concentrations of Select Pollutants in Wyoming Produced Water (WY
OGCC, 2015)	5-14
Table 5-11. Flowback and Produced Water Constituents from Hydraulically Fractured
Colorado Wells (Havics, 2011)	5-15
Table 5-12. Produced Water Constituents from Hydraulically Fractured Wells
(McElreath, 2011)	5-15
Table 5-13. Produced Water Constituents from Bakken Oil Formation Wells (Stepan,
2010)	5-16
Table 5-14. Average Concentration of Select Pollutants in Process Wastewater Reported
in 2016 Discharge Monitoring Reports for In-Scope CWT Facilities	5-19
Table 5-15. Analytical Methods for the CWT Study Sampling Program	5-20
Table 5-16. EPA Sampling Results for Anticline and Eureka Facilities	5-22
Table 5-17. Ten States with the Highest Oil and Gas Produced Water Volumes in 2012	5-29
Table 5-18. Produced Water Management Practices and Volumes for 2012	5-30
Table 6-1. Chemical Precipitants and Targeted Pollutants	6-2
Table 6-2. EPA Chemical Precipitation Sampling Data at Eureka Resources	6-3
Table 6-3. Bench-Scale Chemical Precipitation Data	6-4
Table 6-4. Full-Scale Chemical Treatment Data	6-4
Table 6-5. Sludge Generation Rates from Chemical Precipitation Units Treating Oil
and Gas Extraction Wastewater	6-6
Table 6-6. Chemical Precipitation Capital and O&M Costs for Oil and Gas Extraction
Wastewater Applications	6-7
Table 6-7. Chemical Precipitation Costs at CWT Facilities	6-7
Table 6-8. Chemical Precipitation Technology Vendors for Oil and
Gas Extraction Wastewater	6-8
Table 6-9. Bench-Scale Filtration Treatment Performance Data	6-10
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
VI

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List of Tables
LIST OF TABLES (Continued)
Page
Table 6-10. Filtration/Sedimentation/Flotation Capital and O&M Costs for Oil and
Gas Extraction Wastewater Applications	6-12
Table 6-11. Filtration/Sedimentation/Flotation Technology Vendors for Oil and
Gas Extraction Wastewater	6-12
Table 6-12. Treatment Performance Data, Thermal Distillation	6-16
Table 6-13. Treatment Performance Data, MVR	6-17
Table 6-14. Evaporation/Condensation Influent TDS Concentration, Energy
Consumption, and Water Recovery	6-19
Table 6-15. Evaporation/Condensation Capital and O&M Costs for Oil and Gas
Extraction Wastewater Applications	6-21
Table 6-16. Evaporation/Condensation Costs at CWT Facilities	6-22
Table 6-17. Evaporation/Condensation Technology Vendors for Oil and Gas
Extraction Wastewater	6-22
Table 6-18. EPA Crystallization Sampling Data at Eureka Resources	6-24
Table 6-19. Crystallization Influent TDS Concentration, Energy Use per Barrel of
Influent Wastewater, and Water Recovery	6-28
Table 6-20. Crystallization Capital and O&M Costs for Oil and Gas Extraction
Wastewater Applications	6-29
Table 6-21. Crystallization Costs at Commercial CWT Facilities	6-30
Table 6-22. Crystallization Technology Vendors for Oil and Gas Extraction Wastewater	6-31
Table 6-23. EPA Reverse Osmosis Sampling Data at Eureka Resources	6-32
Table 6-24. GE Pilot Membrane Filtration and RO Performance Data	6-34
Table 6-25. Newpark Environmental Services Reverse Osmosis Performance Data	6-34
Table 6-26. Newfield Exploration Advanced Oxidation Process/Reverse Osmosis
Performance Data	6-35
Table 6-27. Ecolotron RO Membrane Performance Data	6-36
Table 6-28. Anticline Disposal Performance Data for Treatment System Incorporating
Reverse Osmosis	6-36
Table 6-29. Reverse Osmosis Influent TDS Concentration, Energy Use, and
Water Recovery	6-38
Table 6-30. Reverse Osmosis Capital and O&M Costs for Oil and Gas
Extraction Wastewater Applications	6-39
Table 6-31. Reverse Osmosis Treatment Cost at CWT Facilities	6-39
Table 6-32. Reverse Osmosis Technology Vendors for Oil and
Gas Extraction Wastewater	6-40
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes	vii

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List of Tables
LIST OF TABLES (Continued)
Page
Table 6-33. EPA MBR Sampling Data at Eureka Resources	6-41
Table 6-34. MBR Laboratory Performance Data	6-42
Table 6-35. Biological Treatment Technology Vendors for Oil and Gas
Extraction Wastewater	6-44
Table 6-36. Performance Data Quality Review	6-45
Table 7-1. In-Scope Facilities Accepting Oil and Gas Extraction Wastes	7-1
Table 7-2. Annual Pollutant Loading Discharges in Pounds for In-Scope CWT Facilities
Calculated Using DMR Pollutant Loading Tool Output with 2016 Reported Data	7-3
Table 7-3. Annual Pollutant Loading Discharges in TWPE for In-Scope CWT Facilities
Calculated Using DMR Pollutant Loading Tool Output with 2016 Reported Data	7-4
Table 7-4. 2015 Pollutant Loadings Discharged by Indirect Discharger Patriot Water
Treatment, LLC	7-5
Table 8-1. Facilities Known to Provide OGE-Related CWT Services	8-2
Table 8-2. States with the Highest Number of Facilities Treating Oil and Gas Extraction
Wastewater	8-4
Table 9-1. Chemical Categories in HF Fluids	9-4
Table 9-2. Metal Concentrations Upstream, in CWT Effluent, and Downstream (all units
in mg/L)	9-15
Table 9-3. Selected Case Study from EPA's UOG TDD Report Summarizing Results
from POTWs Accepting Wastewater Containing O&G Extraction Wastewater
Pollutants	9-32
Table 9-4. Tolerances of Livestock to TDS (Salinity) in Drinking Water	9-33
Table 9-5. Interpretation of Water Quality based on TDS for Cattle in Areas where
Sulfates are Prevalent	9-33
Table 9-6. Permissible Limits for Classes of Irrigation Water	9-34
Table 9-7. General Sodium Irrigation Water Classifications	9-35
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
Vlll

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List of Figures
LIST OF FIGURES
Page
Figure 4-1. CWT Facilities Identified for 2000 Rulemaking	4-6
Figure 4-2. Direct Discharging CWT Facilities in 2016, Identified by the DMR Pollutant
Loading Tool	4-7
Figure 4-3. CWT and Oil and Gas Wastewater Treatment Facilities by Permit Type
and Discharge Status	4-10
Figure 4-4. In-Scope Facility Map	4-15
Figure 4-5. Aerial View of Judsonia Treatment Facility	4-22
Figure 4-6. Aerial View of CAES Facility	4-23
Figure 4-7. Aerial View of Eureka Standing Stone Facility	4-24
Figure 4-8. Aerial View of Eureka 2nd Street Facility	4-25
Figure 4-9. Aerial View of Fairmont Brine Facility	4-27
Figure 4-10. Aerial View of Fluid Recovery Services Franklin Facility	4-28
Figure 4-11. Aerial View of Fluid Recovery Services Josephine Facility	4-29
Figure 4-12. Aerial View of Fluid Recovery Services Creekside Facility	4-30
Figure 4-13. Aerial View of Max Environmental Technologies, Inc. Yukon Facility	4-31
Figure 4-14. Aerial View of Patriot Water Treatment, LLC Facility	4-33
Figure 4-15. Aerial View of Waste Treatment Corporation Facility	4-34
Figure 4-16. Density of U.S. Onshore Oil and Gas Well Locations	4-38
Figure 4-17. Number of Active U.S. Onshore Rigs by Trajectory and Product Type
over Time	4-39
Figure 5-1. Oil and Gas Produced Water Constituent Concentration Data (USGS National
Produced Waters Geochemical Database, V2.2)	5-12
Figure 5-2. Oil and Gas Produced Water TDS Concentration by Basin (USGS National
Produced Waters Geochemical Database, V2.2)	5-12
Figure 9-1. HF Water Life Cycle	9-7
Figure 9-2. TDS Concentrations from Sites Upstream of Effluent Discharge, Effluent
from Facilities Treating O&G Wastewater, and Downstream of Discharge Sites	9-10
Figure 9-3. Chloride Concentrations from Sites Upstream of Effluent Discharge, Effluent
from Facilities Treating O&G Wastewater, and Downstream of Discharge Sites	9-12
Figure 9-4. Bromide Concentrations from Sites Upstream of Effluent Discharge, Effluent
from Facilities Treating O&G Wastewater, and Downstream of Discharge Sites	9-14
Figure 9-5. Radium Concentrations in Water Above and Below CWT Outfall	9-16
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes	ix

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List of Figures
LIST OF FIGURES (Continued)
Page
Figure 9-6. Radium Concentrations in Sediment Above and Below CWT Outfall	9-17
Figure 9-7. Chloride and bromide surface water enrichment factors on a log scale at a
brine treatment facility treating O&G wastewater	9-19
Figure 9-8. Specific conductivity measurements at the CWT discharge point (grey
shading) and at a monitoring site -12 km downstream (black lines)	9-22
Figure 9-9. Observed increases in bromide and chloride concentrations at sites -12 km,
44 km, and 52 km downstream of CWT facility, respectively, along the Allegheny
River	9-23
Figure 9-10. Drinking water intakes and public wells potentially impacted by CWTs
discharging treated O&G wastewater	9-25
Figure 9-11. Specific conductance measurements at the six monitoring transects	9-28
Figure 9-12. Percent survival of caged unionid mussels at the six monitoring transects	9-29
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes	x

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List of Acronyms and Abbreviations
LIST OF ACRONYMS AND ABBREVIATIONS
BAT
Best available technology economically achievable
bbl
Barrels
BCT
Best conventional control technology
BOD
Biochemical oxygen demand
bpd
Barrels per day
BPJ
Best professional judgment
BPT
Best practicable control technology currently available
BTEX
Benzene, toluene, ethylbenzene and xylenes
CBM
Coalbed methane
CFR
Code of Federal Regulations
COD
Chemical oxygen demand
CWA
Clean Water Act
CWT
Centralized waste treatment
D&B
Dun & Bradstreet
DI
Drillinginfo
DMR
Discharge Monitoring Reports
DOE
Department of Energy
DOI
Department of Interior
ECHO
Enforcement and Compliance History Online
EIA
Energy Information Administration
ELGs
Effluent Limitations Guidelines and Standards
EPA
Environmental Protection Agency
FRS
Federal Registry System
GWPC
Ground Water Protection Council
HEM
Hexane Extractable Material
LM-HT
Low momentum - high turbulence
MBR
Membrane bioreactor
ME
Multiple effect
MGD
Million gallons per day
MVC
Mechanical vapor compression
MWCO
Molecular weight cutoff
NAICS
North American Industry Classification System
NPDES
National Pollutant Discharge Elimination System
NSPS
New Source Performance Standards
O&G
Oil and gas extraction
O&M
Operating and maintenance
PA DEP
Pennsylvania Department of Environmental Protection
POTW
Publicly owned treatment works
PSES
Pretreatment standards for existing sources
PSNS
Pretreatment standards for new sources
RO
Reverse osmosis
RS
Rapid spray
SBA
Small Business Association
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
XI

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Section 1 -Executive Summary
SGT- HEM
Silica Gel Treated N-Hexane Extractable Material
SIC
Standard Industrial Classification
SUSB
Statistics of U.S. Businesses
TDD
Technical Development Document
TDS
Total dissolved solids
TENORM
Technologically Enhanced Naturally Occurring Radioactive Materials
TOC
Total organic carbon
TPH
Total petroleum hydrocarbons
TRI
Toxics Release Inventory
TSS
Total suspended solids
TVC
Thermal vapor compression
TWF
Toxic weighting factors
TWPE
Toxic-weighted pound equivalent
USGS
United States Geological Survey
WQBEL
Water-quality based effluent limitations
ZLD
Zero liquid discharge
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
Xll

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Section 1 -Executive Summary
1. Executive Summary
The U.S. Environmental Protection Agency (EPA) regulates discharges from centralized
waste treatment (CWT) facilities through the existing effluent limitations guidelines and
pretreatment standards (ELGs) found at 40 CFRPart 437. CWT facilities accept for treatment,
recovery or reuse a variety of wastes and wastewaters. EPA first promulgated the CWT ELGs in
2000. At that time, while EPA was aware that some CWT facilities were accepting wastes from
oil and gas extraction activities, this practice was not prevalent.
Since 2000, CWT facilities have been increasingly used to manage wastes such as
produced water, drilling wastes and hydraulic fracturing fluids generated by oil and gas
extraction operations. This is due to a number of factors, such as the increased utilization of
hydraulic fracturing to extract oil and gas. Given changes in the industry since 2000, particularly
with respect to management of oil and gas extraction wastes, EPA has undertaken a detailed
study of the CWT industry. A primary goal of the study is to determine if the existing CWT
regulations should be updated given changes in the industry, specifically related to facilities that
accept oil and gas extraction wastes.
As part of this study, EPA has evaluated several aspects of the CWT industry. This report
details several areas, including:
•	The current universe of 40 CFR Part 437 CWT facilities that EPA is aware of that accept oil
and gas extraction wastes for discharge either directly to waters of the United States or
indirectly via publicly-owned treatment works (POTWs). A lesser focus are facilities that
accept oil and gas extraction wastes and discharge under a different effluent guideline (such
as the Oil and Gas Extraction ELGs at 40 CFR Part 435) and facilities that accept oil and gas
extraction wastes but do not discharge (i.e., facilities that treat for recycle or reuse).
•	The current regulatory status of these facilities, including the basis for National Pollutant
Discharge Elimination System (NPDES) permits issued to these facilities, factors such as the
wastewater parameters contained in these permits, and the types and quantities of wastes
accepted for management.
•	Characteristics of wastewaters from oil and gas extraction activities that are currently or
could potentially be managed by CWT facilities.
•	Technologies applicable to treatment of wastewaters from oil and gas extraction activities,
including their cost and performance.
•	Economic and financial characteristics of the CWT industry and facilities that manage oil
and gas extraction wastes.
•	Documented and potential human health and environmental impacts of discharges from
CWT facilities managing oil and gas extraction wastewater.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
1-1

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Section 1 -Executive Summary
•	Generation and management of treatment residuals at CWT facilities, and transfer of
pollutants to other media (solid waste, air emissions).
EPA has collected data from a variety of sources, including publicly-available
information (facility permits, literature), Clean Water Act (CWA) section 308 data collection,
and wastewater sampling.
EPA has made the following observations regarding the CWT industry and CWT
facilities that manage oil and gas extraction wastes:
•	Although EPA has identified many existing CWT facilities, little information is readily
available to determine whether some of these facilities would be affected by changes to
EPA's existing regulations at Part 437. A primary data gap is knowledge about the types of
wastewaters accepted, specifically whether wastewater from oil and gas extraction facilities
are accepted, and the basis for NPDES permits issued to these facilities.
•	EPA identified 11 facilities that accept oil and gas extraction wastes as of 2017, discharge
those wastes after treatment and are subject to the Part 437 ELGs (or information available to
EPA indicates will be subject to Part 437 when permits are re-issued). These are the facilities
considered to be "in-scope" for the purpose of this study.
•	Oil and gas extraction wastes can contain a variety of constituents, including biochemical
oxygen demand (BOD), bromide, chloride, chemical oxygen demand (COD), specific
conductivity, sulfate, total dissolved solids (TDS), total suspended solids (TSS), barium,
potassium, sodium, strontium, benzene, ethylbenzene, toluene, xylenes, sulfide, gross alpha,
gross beta, radium 226, and radium 228.
•	The pollutants present in and characteristics of oil and gas extraction wastes can vary greatly.
Factors that can influence the pollutants contained in and the characteristics of these wastes
include the source formation for the oil and gas, the type of drilling and whether stimulation
methods are used, the types and quantities of additives used during drilling and well
development, and the age of the well.
•	The range of pollutants present in these wastes typically require the use of a multi-step
treatment train to meet discharge standards.
•	Of those facilities that are in-scope for this study, variation exists in types of treatment
technologies employed. Some facilities employ multi-step treatment systems specifically
designed to remove pollutants commonly found in oil and gas extraction wastes. Other
facilities use treatment, such as chemical precipitation, that remove specific pollutants but
provide little or no removal of the many other pollutants commonly found in these wastes. As
a result, some facilities discharge much greater quantities of pollutants, such as total
dissolved solids and chlorides, than others.
•	Costs for technologies to remove TDS can be high, but nonetheless can be cost-competitive
when factors such as transportation to alternate treatment or disposal methods (such as to
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Section 1 -Executive Summary
injection wells) are considered. In addition, technologies (such as evaporation) are available
that use waste heat from other industrial sources that, where co-located, can significantly
reduce costs of treatment.
•	EPA approved analytical methods do not exist for many constituents found in oil and gas
extraction wastes. In addition, some constituents (such as total dissolved solids) found in oil
and gas extraction wastes can interfere with EPA approved analytical methods and
significantly affect the ability to detect and quantify the level of some analytes.
•	The current ELGs at 40 CFR Part 437 do not contain limitations for many of the pollutants
commonly found in oil and gas extraction wastes. Many of these pollutants are not included
on the current list of priority pollutants.
•	The manner in which permitting and control authorities have permitted facilities that accept
oil and gas extraction wastes for discharge varies. Some facilities are permitted under Part
437 while others are not. As a result, discharge limitations in permits are not consistent
across the industry. A number of facilities operate under expired permits that do not contain
limitations for many of the pollutants found in oil and gas extraction wastes; several facilities
are in the process of permit renewals that may change the limitations contained in future
permits.
•	A lack of clarity exists among the regulated community regarding applicability of the current
CWT effluent guidelines to facilities that treat oil and gas extraction wastes. Some of this is
centered on the interpretation of what constitutes "off-site" in the context of oil and gas
operations and whether Part 437 or Part 435 effluent limitations should be applied to
facilities treating oil and gas extraction wastes. While EPA has provided clarification of this
for operations in the Marcellus Shale region, questions still arise.
•	The cyclical market for commodities, including the recent drop in oil and gas prices from
2014 through 2016, has affected the CWT industry that accepts oil and gas extraction wastes.
Data available to EPA indicates that some facilities have reduced operations or ceased
operating, in part because producers have also reduced operations or ceased operating, or
sought cheaper wastewater management solutions. In addition, several new discharge permits
have been issued for facilities that have yet to be constructed, in part because of the reduced
demand for treating wastewater for discharge. It is not clear if or when these facilities may be
constructed or begin operations.
•	The demand for CWT services is directly related to the amount of wastewater requiring
management. If increased oil and gas exploration occurs in the future, an increase in the
volume of wastes produced would also be expected. It is difficult to predict whether the
demand for oil and gas CWT services will increase or decrease in the future, as that demand
is directly tied to commodities that are subject to market fluctuations. In addition,
competition exists from other management options, such as disposal wells. However,
concerns regarding induced seismicity and reduced disposal well capacity may result in
greater demand for CWT facilities treating these wastes.
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Section 1 -Executive Summary
•	Removal of barium and co-precipitation of radium may create a solid waste management
issue at CWT facilities treating oil and gas extraction wastes. More efficient barium removal
from the wastewater in the presence of sufficient radium may result in solid waste that
exhibits radioactivity at levels that preclude disposal in most landfills. In addition, it is
plausible that radioisotopes in wastewater treatment residuals disposed in landfills may
subsequently be released to the environment through leachate. The level of radioactivity
present in oil and gas extraction wastes is a function of source formation characteristics.
•	Management of brines and salts produced from technologies such as reverse osmosis,
evaporators, and crystallizers may present a solid waste management issue. Disposal of these
residuals in landfills has the potential to increase salinity of landfill leachate. Residuals that
have marketable characteristics can be produced at CWT facilities. Producing saleable
residuals or materials that can be beneficially reused may offset treatment costs. Other
management options for these residuals include injection into disposal wells.
•	CWT effluents may have elevated levels of TDS, halides, metals, and technologically
enhanced naturally occurring radioactive materials (TENORM) relative to the receiving
streams into which they are discharged dependent upon the treatment technology utilized by
the CWT. These elevated concentrations are detectable in samples collected downstream of
CWT facility discharge points. The distance over which these elevated concentrations are
detectable depends on site-specific factors such as source formation, CWT facility discharge
volume, upstream concentrations of constituents, and river flow.
•	Documented and potential impacts to both aquatic life and human health related to
discharges from CWT facilities treating oil and gas extraction wastewater exist due to the
prevalence of some pollutants. Levels of pollutants downstream from CWT facility
discharges have been reported to exceed applicable thresholds, such as primary and
secondary drinking water standards and acute and chronic water quality criteria for protection
of aquatic life.
•	In a number of cases, CWT effluents have been shown to adversely affect downstream
aquatic life and, in one case, have been shown to affect survival of riffleshell mussels, a
federally-listed endangered species (e.g., Patnode et al., 2015).
•	Multiple drinking water intakes are situated downstream of CWTs accepting oil and gas
extraction wastewater within distances at which impacts to drinking water from CWTs have
previously been identified. Drinking water treatment plants downstream of CWT facilities
treating oil and gas extraction wastewater have noted a shift in the composition of DBPs
from mostly chlorinated DBPs to mostly brominated DBPs (McTigue et al., 2014), which are
more toxic than their chlorinated analogues. These shifts could affect human health from
consumption of treated waters.
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Section 2-Introduction
2. Introduction
Recent advances in horizontal drilling, hydraulic fracturing, and other enhanced
exploration and production technologies have made the extraction of oil and natural gas from
certain formations more technically achievable and economically viable than in past decades.
These advanced drilling and production techniques have resulted in dramatic increases in the
number of oil and gas wells drilled in the United States. For example, the number of
hydraulically fractured wells increased from approximately 36,000 in 2010 to over 300,000 in
2015 (U.S. DOE, 2016). From 1990 to the late 2000s, the United States' dependence on imports
of petroleum and other liquid fuels rose as domestic crude oil production declined. Similarly,
natural gas production rose slightly during the 1990s and then began to decline in the early part
of the last decade. However, following these advances in drilling and production techniques,
both oil and natural gas production have risen dramatically, transforming the U.S. oil and gas
industry (U.S. DOE, 2014).
The increase in domestic oil and gas extraction has caused higher demand for centralized
waste treatment (CWT) services. This has led to both the creation of startup CWT companies and
to larger, established waste management companies augmenting their offerings for oil and gas
water and waste management services. For example, in 2013, Waste Management (a large waste
management company) acquired two energy service companies operating in the Bakken Shale of
North Dakota (Reuters, 2014; Waste Management, 2013). In addition, established oil and gas
service companies have become involved in CWT services. As evidenced by these changes, the
business and technical operation models for providing wastewater management services are
evolving rapidly with new service models and technologies emerging. Wastewater management
services for oil and gas operations, which may include CWT-type services, are being provided by
businesses that lie outside of the traditional CWT industry.
The rise in the number of oil and gas wells and the new types of oil and gas exploration
utilized in the United States have led to changes in the volumes and characteristics of solid waste
and wastewater that require management. Oil and gas extraction wastewaters can vary greatly
depending on the oil and gas source formation, the direction of oil and gas extraction (i.e.,
vertical, horizontal, or diagonal), the additives being used, and the age of the well.
The current ELGs at 40 CFR Part 437 were promulgated in 2000 (and amended in 2003)
and were developed prior to these recent changes in the oil and gas extraction industry. As a
result, the pollutants regulated in the ELGs may not include pollutants that exist in oil and gas
extraction wastewaters and the technology basis for the ELGs may not address these pollutants.
Therefore, CWT facilities accepting oil and gas extraction wastes may not currently install
adequate treatment for these wastes, and discharges from CWT facilities accepting oil and gas
extraction wastes have the potential to contribute to a range of human health and environmental
impacts.
In addition, treatment of oil and gas extraction wastewaters may create solid waste
management issues. Solid wastes from these facilities may contain high levels of radioactivity,
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 2-Introduction
which would preclude them from being disposed of at most landfills. In addition, solid wastes
generated by oil and gas extraction wastewater treatment may have high levels of salts.
CWT facilities accepting oil and gas extraction wastewater may be regulated under the
current CWT ELGs or regulated using other methods, including under 40 CFR Part 435 or local
limits using best professional judgement. There is some room for interpretation as to what
constitutes "off-site" in the context of oil and gas operations and whether Part 437 or Part 435
ELGs should be applied to facilities treating oil and gas extraction wastes (this issue is described
in Section 3.4).
EPA developed this study to help the Agency determine if any action should be taken to
address CWT facilities' treatment of oil and gas extraction wastes. These actions may include
(but are not limited to) revising the existing CWT regulations at 40 CFR Part 437 or further
evaluating the industry. The study will inform EPA's determination of future steps by providing
information on the following questions:
•	What regulations currently apply to CWT facilities in general, and specifically CWT
facilities treating oil and gas extraction wastes? Do these current regulations adequately
address the pollutants generated by the oil and gas extraction industry?
•	How many CWT facilities treating oil and gas extraction wastes currently exist? How many
of them discharge to surface waters or to POTWs? How many of them have no discharge, for
example because they recycle wastewater or inject wastewater into disposal wells?
•	How are facilities treating oil and gas extraction wastes currently permitted? How many are
permitted under 40 CFR Part 437 or 40 CFR Part 435? What other methods are used to
regulate these facilities?
•	How many oil and gas extraction wells exist in the United States? Are these wells located in
proximity to CWT facilities?
•	What are the types and characteristics of oil and gas extraction wastewater? What pollutants
are present in these types of wastewater? How much wastewater is generated by the industry?
•	What technologies can be used to treat oil and gas extraction wastewaters? How do these
technologies work? How much do these technologies cost? How effectively do these
technologies treat the pollutants found in oil and gas extraction wastes?
•	What are the pollutant loads generated by CWT facilities that treat and discharge oil and gas
extraction wastes? What quantity of toxic pollutants are discharged by these facilities as a
function of the volume of wastewater treated?
•	What are the economic business models used by CWT facilities treating oil and gas
extraction wastes and what are their financial performance and condition? What are the
operating market and competition characteristics of the relevant CWT service market?
•	What is the industry outlook for both CWT facilities and oil and gas extraction operations?
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Section 2-Introduction
•	What are the documented and potential human health and environmental impacts from
discharges from CWT facilities managing oil and gas extraction wastes? What are the
impacts of disposal of treatment residuals?
The remainder of this report presents EPA's investigations, analyses, and findings,
organized as follows:
•	Section 3 summarizes the existing CWT ELGs found at 40 CFR Part 437 and the existing oil
and gas extraction ELGs at 40 CFR Part 435. This section also describes important
interrelationships between these two regulations, such as applicability and definitions
specific to each regulation.
•	Section 4 presents a profile of the CWT industry. This profile describes the data sources EPA
used to identify existing CWT facilities and other oil and gas wastewater treatment facilities
across the country. EPA provides available information on in-scope facilities, which are the
subset of facilities that are permitted for discharge under the 40 CFR Part 437 regulations and
that accept oil and gas extraction wastes. Section 4 also provides a limited profile of the
number and location of oil and gas extraction wells to provide a basis for understanding the
industry's potential need for CWT services.
•	Section 5 presents data and information on characteristics of wastes generated by oil and gas
extraction activities. These data are primarily from exploration and production (E&P)
activities. EPA has not included data on characteristics of wastes from midstream and
downstream activities, although some of these wastes are managed at CWT facilities. Section
5 also presents waste characterization data specific to CWT facilities treating oil and gas
extraction wastes, including sampling conducted by EPA specifically for this detailed study.
•	Section 6 describes wastewater management practices that are applicable to oil and gas
extraction wastes and therefore may be relevant to CWT facilities managing these wastes.
Information and data on performance, costs and treatment residuals produced are presented,
where available.
•	Section 7 presents estimates of the pollutant loadings discharged by in-scope CWT facilities,
based on Discharge Monitoring Report (DMR) data for directly discharging facilities and
data collected by EPA for indirectly discharging facilities.
•	Section 8 presents an economic profile of the CWT industry for facilities that accept oil and
gas extraction wastewater and describes the industry outlook.
•	Section 9 discusses documented and potential human health and environmental impacts from
discharges from CWT facilities managing oil and gas extraction wastes. Discussion of
treatment residuals is also included in this section.
•	Section 10 details the data sources used throughout EPA's analyses.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 2-Introduction
2.1 References
1.	Reuters. 2014. Reuters Fundamentals: Big Cat Energy Corp. 11 July 2014.
Accessed July 16, 2014. DCN CWT00170
2.	United States Department of Energy (U.S. DOE). 2016. United States Energy
Information Administration (EIA). Today in Energy: Hydraulically fractured
wells provide two-thirds of U.S. natural gas production. 5 May 2016. Available
electronically at: https://www.eia.gov/todavinenergy/detail.php?id=26112. DCN
CWT00539
3.	United States Department of Energy (U.S. DOE). 2014. United States Energy
Information Administration (EIA). Annual Energy Outlook 2014 with Projections
to 2040. April 2014. Available electronically at:
http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf. DCN CWT00171
4.	Waste Management, Inc. 2013. "Waste Management Acquires Two North Dakota
Energy Services Companies." August 1, 2013. Available electronically at:
https://www.wm.com/about/press-room/2013/2013Q801 NDAcquisitions.isp.
DCN CWT00172
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Section 3-Existing Effluent Limitations Guidelines for Oil and Gas extraction Wastes
3. Existing Effluent Limitations Guidelines for Oil and Gas Extraction
Wastes
This section describes the existing ELGs that may apply to discharges of oil and gas
extraction wastes. Section 3.1 provides background on the effluent guidelines program and
process. Section 3.2 describes the ELGs that apply to the CWT point source category, which is
the primary focus of this detailed study. ELGs that apply to the oil and gas extraction category
are described in Section 3.3. While this study is not specifically evaluating the existing oil and
gas extraction ELGs, this information is presented as a basis of comparison to the requirements
applicable to CWT facilities treating those wastewaters. In addition, it is important to
characterize the interrelationships between these two rules to understand the instances where the
CWT ELGs apply and the instances where the oil and gas ELGs apply.
3.1 Effluent Guidelines Background
ELGs are national wastewater discharge standards that are
developed by EPA on an industry-by-industry basis. These are
technology-based regulations and are intended to represent the
greatest pollutant reductions that are economically achievable for
an industry. The standards for direct dischargers are incorporated
into NPDES permits issued by states and EPA regional offices,
and standards for indirect dischargers are incorporated into
permits or other control mechanisms issued by pretreatment
authorities.
When developing ELGs, EPA identifies the best available
technology that is economically achievable for that industry and
sets regulatory requirements based on the performance of that
technology. The ELGs do not require facilities to install the
specific technology identified by EPA; however, the regulations
do require facilities to achieve the same level of pollutant
reductions. ELGs can apply to both existing dischargers and new
dischargers. ELGs also establish different levels of control for
specific classes of pollutants (priority pollutants, conventional
pollutants and nonconventionalpollutants).
The direct discharge pollution control guidelines that are
developed by EPA in ELGs include: best practicable control
technology currently available (BPT), best conventional pollutant
control technology (BCT), best available technology
economically achievable (BAT), and new source performance
standards (NSPS). The indirect discharge pollution control
standards that are developed by EPA in ELGs include
pretreatment standards for existing sources (PSES) and
Direct Discharger
A point source that
discharges pollutants to
waters of the United
States.
Indirect Discharger
A facility that discharges
pollutants to a publicly-
owned treatment works
(municipal sewage
treatment plant).
Priority Pollutants
A list of 126 toxic
pollutants, last modified
in 1981, that are
frequently found in water
samples, produced in
significant quantities and
have approved EPA
methods for detection.
Conventional Pollutants
Biochemical oxygen
demand, total suspended
solids, fecal coliform, pH
and oil and grease.
Nonconventional Pollutants
All other pollutants not
considered priority or
conventional pollutants.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 3-Existing Effluent Limitations Guidelines for Oil and Gas extraction Wastes
pretreatment standards for new sources (PSNS). Table 3-1 illustrates the types of dischargers and
the different levels of control in ELGs. Table 3-2 illustrates the classes of pollutants addressed by
different levels of control in ELGs.
Table 3-1. Applicability of Effluent Guidelines Levels of Control to Types of Discharger
T\pe of Dischiiriic r Rciiulnkd
HPT
IKT
HAT
NSPS
PS I S
PSNS
Existing Direct Dischargers
•
•
•



New Direct Dischargers



•


Existing Indirect Dischargers




•

New Indirect Dischargers





•
Table 3-2. Pollutant Classes Regulated by Effluent Guidelines Levels of Control
Polliiliinls RciiiihiU'd
HPT
IKT
HAT
NSPS
PS I S
PSNS
Priority Pollutants
•

•
•
•
•
Conventional Pollutants
•
•

•


Nonconventional Pollutants
•

•
•
•
•
3.2 Centralized Waste Treatment Point Source Category Effluent Guidelines
Discharges from CWT facilities are regulated under 40
CFR Part 437. CWT facilities accept waste from off-site for
disposal, recovery or recycling. CWT facilities may also treat
on-site generated wastes. EPA defines off-site as "outside the
boundaries of a facility" (40 CFR 437.2(n)).
The CWT category does not apply to discharges of
wastewater from facilities that are subject to other categorical
discharge standards when they receive wastes from off-site for
treatment or recovery that are subject to the same ELGs as the
on-site generated wastes. Similarly, the CWT category does not
apply to discharges of wastewater from facilities that receive off-site wastes whose nature and
treatment are compatible with the treatment of on-site (non-CWT) wastes. The CWT category
does not apply to operations engaged exclusively in landfilling and/or the treatment of landfill
wastewaters, whether generated on- or off-site. See 40 CFR Part 437.1 for additional details
regarding the applicability of the CWT category.
CWT wastewater means any wastewater generated as a result of CWT activities. CWT
wastewater sources may include liquid waste receipts, solubilization water, used oil-emulsion
breaking wastewater, tanker truck/drum/roll-off box washes, equipment washes, air pollution
control scrubber blow-down, laboratory-derived wastewater, on-site landfill wastewaters, and
contaminated storm water.
40 CFR part 437 defines a
CWT facility as: "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 off-
site. "
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Section 3-Existing Effluent Limitations Guidelines for Oil and Gas extraction Wastes
The guidelines at 40 CFRPart 437 categorize CWT facilities into four subparts:
•	Subpart A: Metals Treatment and Recovery
•	Subpart B: Oils Treatment and Recovery
•	Subpart C: Organics Treatment and Recovery
•	Subpart D: Multiple Wastestreams
The technologies considered BPT in the CWT ELGs include primary precipitation,
liquid-solid separation, secondary precipitation, clarification, and sand filtration for Subpart A;
emulsion breaking/gravity separation, secondary gravity separation, and dissolved air flotation
for Subpart B; and equalization and biological treatment for Subpart C. For Subpart D, the
limitations were derived by combining BPT limitations from the three other subparts, selecting
the most stringent values where they overlap. Therefore, the technology basis for Subpart D
limitations reflects the technology basis for the applicable subparts. EPA adopted BCT and BAT
effluent limitations for all subparts of the CWT industry based on the same technologies selected
as the basis for BPT for each subpart.
EPA promulgated NSPS Subpart B and C limitations based on the same technology basis
as BPT/BCT/BAT. However, for Subpart A, the NSPS technology basis includes selective
metals precipitation, liquid-solid separation, secondary precipitation, and tertiary precipitation
and clarification. As was the case for BPT/BCT/BAT, the technology basis for Subpart D NSPS
limitations reflects the technology basis for the applicable subparts.
In addition to the direct discharge limitations, 40 CFR Part 437 established pretreatment
standards for indirect discharges from CWT facilities to POTWs. For Subpart A and Subpart C,
EPA based the PSES on the same technology basis as BPT. For Subpart B, EPA based PSES on
emulsion breaking/gravity separation and dissolved air flotation. As was the case for BPT/BAT,
the technology bases for pretreatment standards for Subpart D reflect the technology bases for
the applicable subparts.
EPA based the PSNS for Subpart B and Subpart C on the same technology basis as
NSPS. EPA based Subpart A PSNS on the same technology basis as BPT. As was the case for
PSES, the technology basis for Subpart D PSNS reflects the technology basis for the applicable
subparts.
Since the pollutants present and the technology basis varies by subpart, the pollutants
regulated within each subpart vary. Table 3-3 shows the pollutant categories that are regulated
under each of the subparts in the CWT rule for both direct and indirect discharging facilities.
Appendix A lists the individual pollutants contained in the effluent limitations and pretreatment
standards in the rule. The pollutant categories that are regulated under Subpart D reflect the
categories for the applicable subparts making up the multiple wastestreams.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 3-Existing Effluent Limitations Guidelines for Oil and Gas extraction Wastes
Table 3-3. Pollutant Categories Regulated Under Each Subpart of the CWT Effluent
Guidelines and Standards

Suhpiirl A
Suhpiirl D
Suhpiirl (
Polliiliinl ( iilci»on
Diivcl
Indirect
Diivcl
Indirect
Diivcl
Indirect
bod5




•

Oil and Grease
•

•



TSS
•

•

•

Metals
•
•
•
•
•

Organics


•
•
•
•
Cyanide
•
•




3.3 Oil and Gas Extraction Point Source Category Effluent Guidelines
Discharges from oil and gas extraction activities are subject to ELGs at 40 CFR Part 435.
These regulations are subcategorized based on the location where the activities take place
(onshore, offshore and in coastal areas), and the levels of control vary for each subpart. Table 3-4
shows the levels of control that are contained in the oil and gas extraction ELGs. These
regulations address wastewater discharges from activities such as field exploration, drilling,
production, well treatment and well completion activities.
Table 3-4. Levels of Control by Subcategory in the Oil and Gas Extraction
Effluent Guidelines
T\pc of l)ischiiri*cr Kc*»uliilcd
DPI
D( 1
DAI
NSPS
PS I S
PSNS
Offshore Subcategory
•
•
•
•


Onshore Subcategory"1
•



•
•
Coastal Subcategory
•
•
•
•
•
•
" PSES and PSNS for the onshore category were promulgated in June 2016 for unconventional oil and gas extraction
activities. Pretreatment standards currently do not exist for onshore conventional extraction activities.
Table 3-5 provides additional details on the applicability and limitations contained in
these subparts. Additional details are provided in Appendix A.
Some of the waste streams addressed by the guidelines for 40 CFR Part 435 include:
•	Produced water which is brought up from the hydrocarbon-bearing strata during the
extraction of oil and gas;
•	Produced sand which is the slurried particles used in hydraulic fracturing, the accumulated
formation sands and scales particles generated during production;
•	Drilling fluids which are the circulating fluids used in the rotary drilling of wells;
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 3-Existing Effluent Limitations Guidelines for Oil and Gas extraction Wastes
•	Drill cuttings generated from drilling into subsurface geologic formations and carried out
from the wellbore with the drilling fluid;
•	Well treatment fluid which is any fluid used to restore or improve productivity by physically
or chemically altering the hydrocarbon-bearing strata after a well has been drilled;
•	Workover fluid which are additives used in a producing well for maintenance, repair, or
abandonment; and
•	Well completion fluids which are additives used to prevent damage to the well bore during
operations which prepare the drilled well for production.
Table 3-5. Subparts of 40 CFR Part 435 and their Applicability and Limitations
Siihpiirl
Tide
\|)|)lic;il)ilil>
Description
A
Offshore
Subcategory
Facilities located in waters that are
seaward of the inner boundary of the
territorial seas as defined in 502(g) of
the CWA.
Both numeric and zero discharge.
C
Onshore
Subcategory
Facilities located landward of the inner
boundary of the territorial seas as
defined in 40 CFR 125. l(gg) and which
are not included within subpart D, E, or
F
BPT regulations require zero discharge of
produced water for direct dischargers.
PSES and PSNS require zero discharge for
unconventional oil and gas extraction facilities.
D
Coastal
Subcategory
Facilities located in or on a water of the
United States landward of the inner
boundary of the territorial seas, or as
defined at 40 CFR 435.40(b)(1)
Zero discharge as BAT for the coastal
subcategory (except for Cook Inlet) and zero
discharge pretreatment standards.
E
Agricultural
and Wildlife
Water Use
Subcategory
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.
Subpart E requires no discharge of waste
pollutants into navigable waters from any
source other than produced water. Produced
water discharges have a daily maximum
limitation of 35 mg/L for oil and grease by the
application of the BPT.
F
Stripper
Subcategory
Onshore facilities which produce 10
barrels per well per calendar day or less
of crude oil and which are operating at
the maximum feasible rate of
production and in accordance with
recognized conservation practices.
This subcategory has no limitations.
Technology-based limitations are developed on
a case-by-case basis or in a state-wide general
permit.
Note: Subpart B and H (Coalbed Methane) requirements are reserved. Subpart G requirements prevent moving
effluent produced in one subcategory to another subcategory for disposal under less stringent requirements.
In general, 40 CFR Part 435 prohibits the discharge of pollutants from oil and gas
extraction facilities, with a few exceptions. Appendix A contains additional details on the
limitations and standards contained in the oil and gas ELGs.
3.4 Interrelationship Between the CWT and Oil and Gas Extraction Effluent Guidelines
As described above, CWT facilities typically receive wastes from a variety of sources
with different characteristics. A facility must receive waste from off-site to be regulated under
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 3-Existing Effluent Limitations Guidelines for Oil and Gas extraction Wastes
the CWT ELGs. EPA has published several resources to help permit writers and control
authorities determine applicability of the CWT ELGs1. When determining whether it is
appropriate to apply the CWT ELGs to a particular facility, the permit writer or control authority
considers a number of factors, including: (1) the location of the facility in relation to where the
wastes are generated to determine if wastes are received from off-site; (2) the number of
generators of the waste; (3) the nature of the wastes, and in particular whether all of the wastes
are from a single ELGs category; and (4) the method(s) of delivery of the wastes (e.g., via
pipeline, conduit, or truck, rail car, etc.).
When a CWT facility accepts waste from a single ELGs category from off-site (which
may be the case with CWT facilities that accept waste exclusively from oil and gas extraction
activities), the CWT regulations do apply to those wastes. However, if the CWT facility receives
wastewater on a continuous basis from five or fewer generators with consistent profiles, the
permit writer or control authority could set alternative limits that are based on the limitations and
standards applicable to the waste where it was generated. If the wastes are from the oil and gas
sector, and since the oil and gas ELGs are generally zero discharge (for onshore facilities), the
permit writer or control authority could set zero discharge standards for the CWT facility.
Another key question that arises with respect to oil and gas extraction activities and CWT
facilities is how to determine if a facility is located off-site. EPA defines site at 40 CFR 122.2 as
"the land or water area where any 'facility or activity' is physically located or conducted,
including adjacent land used in connection with the facility or activity." Facility or activity
means any NPDES "point source" or any other facility or activity (including land or
appurtenances thereto) that is subject to regulation under the NPDES program."
EPA issued a compliance guide and associated frequently asked questions (FAQs) to
explain, among other things, the relationship between the CWT ELGs and the oil and gas
extraction ELGs for natural gas drilling in the Marcellus shale (U.S. EPA, 201 la, 201 lb). In the
FAQs, EPA indicates that for gas drilling activities:
(T)he land identified in the drilling permit; including the locations of wells,
access roads, lease areas, and any lands where the facility is conducting its
exploratory, development or production activities, or adjacent lands used in
connection with the facility or activity, would constitute the site. Land that is
outside the boundaries of that area is considered to be "off site. "
While these FAQs provide clarity on the question of what constitutes off-site in the
context of Marcellus shale gas extraction activities, EPA has not provided any additional
information or guidance beyond what is contained in the existing CWT ELGs record and the
CWT Small Entity Compliance guide and FAQs for other oil and gas extraction activities across
the country. As a result, there may be questions from both industry and regulatory entities about
1 See the EPA Small Entity Compliance Guide and FAQ addenda at https://www.epa.gov/eg/centralized-waste-
treatment-effluent-guidelines-documents.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
3-6

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Section 3-Existing Effluent Limitations Guidelines for Oil and Gas extraction Wastes
whether the oil and gas ELGs or the CWT ELGs should apply to a specific facility treating oil
and gas extraction wastes.
3.5 References
1.	U.S. EPA. 2001. Small Entity Compliance Guide: Centralized Waste Treatment
Effluent Limitations Guidelines and Pretreatment Standards (40 CFR 437) and
addenda. EPA-821-b-001-003. DCN CWT00144
2.	U.S. EPA. 201 la. Regulating Natural Gas Drilling in the Marcellus Shale under
the NPDES Program. Memorandum from James A. Hanlon, Director, Office of
Wastewater Management to Water Division Directors, Regions 1-10. (March 17)
DCN CWT00540
3.	U.S. EPA. 201 lb. Natural Gas Drilling in the Marcellus Shale NPDES Program
Frequently Asked Questions. (March 16). DCN CWT00541
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
3-7

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Section 4-Industry Profile
4. Industry Profile
Oil and gas exploration and production activities generate a variety of waste materials
requiring management. These waste materials include produced waters, spent drilling fluids,
used drilling muds and drill cuttings. Many waste materials, such as produced waters, are
recycled and reused in exploration and production operations. However, in many instances
disposal of these materials is needed. Many disposal options are available, including injection in
Class IIUIC wells, stabilization and solidification and subsequent disposal in landfills, and
transfer to CWT facilities. The options selected depend on factors such as cost and proximity to
the source generating the waste. CWT facilities provide a valuable service to the oil and gas
industry, particularly in areas where certain disposal options (such as underground injection)
may be limited.
To better understand the scope and extent to which CWT facilities are used by the oil and
gas extraction industry to manage wastes, EPA prepared a profile of the CWT industry. This
industry profile is intended to:
•	Identify CWT facilities nationwide, including a summary of facilities' discharge status,
location, permitting methods, and whether or not they accept oil and gas extraction
wastewaters.
•	Provide further details about the subset of facilities that accept oil and gas extraction wastes
and discharge wastewater. For facilities EPA determined to be "in-scope" of this study, the
profile describes characteristics of these facilities, such as type of treatment, discharge status
and volume, and types and characteristics of wastes accepted.
•	Present a limited evaluation of the oil and gas extraction industry, including the current
universe of oil and gas extraction wells and summary data on wastewater production and
management, where available.
•	Evaluate the proximity of oil and gas extraction wells to all CWT facilities and the "in-
scope" facilities to determine the potential market for CWT services for oil and gas
extraction wastewater.
4.1 Overview of the CWT Industry and the Segment Receiving and Treating Oil and
Gas Extraction Wastewaters
The CWT industry is composed of facilities that treat and/or recover nonhazardous or
hazardous waste, wastewater, and/or other used materials generated by industrial facilities. Based
on previous EPA regulatory analysis for the CWT industry, CWT activity has traditionally
occurred in three North American Industry Classification System (NAICS) sectors: Hazardous
Waste Treatment and Disposal (NAICS 562211), Other Nonhazardous Waste Treatment and
Disposal (NAICS 562219) and Materials Recovery Facilities (NAICS 562920) (U.S. EPA,
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-1

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Section 4-Industry Profile
2010).2 Detailed information on the CWT industry can be found in the "Development Document
for Final Effluent Limitations Guidelines and Standards for the Centralized Waste Treatment
Industry" (U.S. EPA, 2016f; EPA-821-R-00-020) and in the Economic Analysis of Final Effluent
Limitations Guidelines and Standards for the Centralized Waste Treatment Industry" (U.S. EPA,
2001; EPA-821 -R-00-024).
In recent years, an increase in production of oil and gas utilizing hydraulic fracturing has
changed the character and quantity of wastewaters that must be managed as part of oil and gas
extraction. As a result, the business and technical operation models for providing wastewater
management services to the oil and gas extraction industry are evolving rapidly with new service
models and technologies emerging in some regions. Wastewater management services for oil and
gas extraction operations, including CWT-type services, are being provided by businesses that lie
outside the definition of the traditional CWT industry.
Table 4-1 lists NAICS codes for (1) the three traditional CWT industry segments, and (2)
NAICS codes for other sectors which may provide services to oil and gas operations. It is
possible, given the evolving business models for oil and gas wastewater services, that some
facilities providing CWT services to the oil and gas extraction industry may fall into one or more
of these sectors. More information on this table is provided in Chapter 8.
Based on research of trade publications, company websites, and general online searches,
EPA identified five business classifications that provide wastewater management services to the
oil and gas extraction industry, as described in Table 4-2.
Diversified waste management firms provide general environmental and waste
management services, including transportation or hauling of waste, landfill services, and other
waste services, and include such firms as Waste Management, the largest provider of waste
management environmental services in North America. Firms in these industry segments provide
wastewater treatment and management services to oil and gas operations, but these services are
only part of the company's overall business.
2 For the 2000 Final Centralized Waste Treatment Rule, EPA relied on information gathered from a 1990 survey
questionnaire and comments to the 1996 Notice of Data Availability (NOD A) to determine the universe of CWT
facilities. Based on these two data sources, EPA determined that there were 223 CWT facilities in scope of the 2000
rule. The majority of respondents identified their industry as SIC 4953: Refuse Systems. This SIC code maps to five
NAICS codes, three of which were determined to be in scope: NAICS 562211, NAICS 562219, and NAICS 562920.
In a 2010 Regulatory Flexibility Act analysis, EPA assumed that facilities in these three NAICS industry segments
represented the entire CWT industry and were all subject to the 2000 Final CWT Rule (U.S. EPA, 2010).
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
Table 4-1. NAICS Codes of Centralized Waste Treatment Industry and Other Industries
Providing Wastewater Services to Oil and Gas Extraction Operations
NAICS
Tradilional
l-'acililics Included
CWT Indusln Sectors
562211
Hazardous Waste Treatment and Disposal
562219
Other Nonhazardous Waste Treatment and Disposal
562920
Materials Recovery
Other Sectors Providing Wastewater Services to Oil and Gas Operators
211111
Crude Petroleum and Natural Gas Extraction
212321
Construction Sand and Gravel Mining
213111
Drilling Oil and Gas Wells
213112
Support Activities for Oil and Gas Operations
237110
Water and Sewer Line and Related Structures Construction
237310
Highway, Street, and Bridge Construction
325180
Other Basic Inorganic Chemical Manufacturing
333132
Oil and Gas Field Machinery and Equipment Manufacturing
333318
Other Commercial and Service Industry Machinery Manufacturing
424720
Petroleum and Petroleum Products Merchant Wholesalers
454390
Other Direct Selling Establishments
484230
Specialized Freight Trucking, Long-Distance
488390
Other Support Activities for Water Transportation
541611
Administrative Management and General Management Consulting Services
541620
Environmental Consulting Services
541712
Research and Development in the Physical, Engineering, and Life Sciences (except Biotechnology)
551112
Offices of Other Holding Companies
561210
Facilities Support Services
Source: U.S. EPA, 2017a; U.S. Census, 2016.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-3

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Section 4-Industry Profile
Table 4-2. Business Models for Firms Offering Wastewater Management
Services to the Oil and Gas Extraction Industry
lillsilK'NN
(hissiriciUion
l'.\illll|)lo l il lll-I.O\C'l
N.\I( S Codes
Diversified Waste
Management
562211 (Hazardous Waste Treatment and Disposal);
562219 (Other Nonhazardous Waste Treatment and Disposal);
562920 (Materials Recovery)
Engineering and
Environmental Services
541330 (Engineering Services);
333318 (Other Commercial and Service Industry Machinery Manufacturing)
Wastewater Management
and Environmental Services
for Oil and Gas Extraction
541611 (Administrative Management and General Management Consulting
Services);
541620 (Environmental Consulting Services)
Traditional Energy/Oilfield
Services
213112 (Support Activities for Oil and Gas Operations);
333132 (Oil and Gas Field Machinery and Equipment Manufacturing)
Oil and Gas Extraction
Operators
213112 (Support Activities for Oil and Gas Operations);
211111 (Crude Petroleum and Natural Gas Extraction)
Engineering and environmental services companies are those that focus on areas such as
construction, engineering design, and technology development and do not limit their services
primarily to the oil and gas industry. The firms that fall in this category, such as Aquatech,
provide logistics support, wastewater technologies, and facility planning to both oil and gas firms
and CWT firms. In many cases, these firms sell their technology or services to other firms, or
provide onsite wastewater management and treatment services. However, in some cases, these
firms may own or operate a CWT facility as well. An example of this type of firm is Veolia.
In addition to engineering and environmental services firms, there are traditional
wastewater management firms, for which wastewater management services and environmental
services in the oil and gas industry is their primary business. These firms provide services such
as waste and wastewater hauling, treatment, storage, and disposal to oil and gas producers, and,
in some cases, were started to serve the growing need for wastewater treatment specifically
within this industry. One such firm, Eureka Resources, began in 2008 and serves oil and gas
producers operating in the Marcellus shale in Pennsylvania (Eureka Resources, 2016).
Firms in the traditional energy/oilfield services category, such as National Oilwell Varco,
provide field services to oil and gas companies. These services have traditionally involved a
range of technical and engineering/construction-type services, including reservoir
characterization, drilling, downhole, and production and gathering services. While many of these
firms have historically provided waste management services to operators, the recent rise in the
use of water for oil and gas production has seen these companies take on a new role in
wastewater management services. For these firms, oil and gas exploration and production
companies serve as the primary customers. An example of this type of firm is Chesapeake
Energy.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
A number of oil and gas operators, such as Encana, manage their own wastewater
treatment. These firms may purchase wastewater treatment technologies from other companies or
rely on other firms for management and operation services but own their wastewater treatment
services. In addition, a number of joint ventures, strategic alliances, and agreements have
emerged among oilfield and environmental service firms to either develop treatment
technologies and systems or to offer expanded water services. These ventures involve businesses
with primary operations that fall in a range of industry sectors.
4.2 Profile of CWT Facilities
EPA regulates discharges from CWT facilities pursuant to ELGs under 40 CFR Part 437,
as discussed in Section 3. EPA defines a CWT facility in part 437 as "any facility that treats (for
disposal, recycling or recovery of material) any hazardous or non-hazardous industrial waste,
hazardous or non-hazardous industrial wastewater, and/or used material received from off-site."
The operations of CWT facilities are quite varied. As noted in the Technical
Development Document (TDD) for the 2000 CWT ELGs (U.S. EPA, 2000), some CWT
facilities treat used materials or wastes from a few generating facilities while others treat wastes
from dozens or more generators. Some treat non-hazardous wastes exclusively while others treat
hazardous and non-hazardous wastes. Some primarily treat concentrated wastes while others
primarily treat dilute wastes. Some primarily perform either wastewater treatment or materials
recovery and recycling, while others perform both.
EPA identified 223 CWT facilities (U.S. EPA, 2000) as part of the 2000 rulemaking (65
FR 81267). Of these 223 facilities, 14 were identified as direct dischargers to waters of the U.S.,
151 were indirect dischargers and 58 were zero or alternative dischargers.3 Figure 4-1 shows a
map of the CWT facilities that were identified in the public record for the 2000 rulemaking.
Using EPA's DMR Pollutant Loading Tool, EPA identified 21 direct discharging
facilities associated with the CWT point source category that submitted DMR data for the
reporting year 2016. These facilities are listed in Table 4-3 and shown on Figure 4-2. [Note that
the DMR Pollutant Loading Tool typically assigns facilities to point source categories based on
NAICS Code (i.e., facilities are not required to report point source categories in their DMRs).
Because the CWT point source category does not align directly with NAICS codes, CWT
facilities are identified through their prior association with the CWT category, such as their
inclusion in the 2000 rulemaking. Therefore, this list may not be complete for the reasons
described in Section 4.1.] In addition, indirect discharging CWT facilities are not required to
submit DMRs and therefore EPA has no national data set to identify the current universe of these
facilities. For these reasons, EPA developed a list of CWT facilities to be used for this study, as
described below.
3 Zero and alternative discharge methods include deep well injection, incineration, evaporation, transfer to another
off-site facility (such as another CWT facility), and facilities that generate no wastewater.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-5

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Section 4-Industry Profile
,
Note: This figure excludes one facility located in Hawaii.
Figure 4-1. CWT Facilities Identified for 2000 Rulemaking
Table 4-3. Direct Discharging CWT Facilities in 2016, Identified by the DMR Pollutant
Loading Tool
l-';icilil> Niimo
< i(\
Sliilc
Clean Harbors Baton Rouge, LLC
Baton Rouge
LA
Clean Harbors PPM, LLC
Ashtabula
OH
Clean Harbors White Castle, LLC - White Castle Landfarm
White Castle
LA
CWM Chemical Services - Model City Site
Model City
NY
Envirite of Illinois Inc. - Harvey
Harvey
IL
Fort Martin Power Station
Maidsville
WV
Harford Waste Disposal Center
Street
MD
Max Environmental - Yukon Facility
Yukon
PA
Montgomery Co. Resource Recovery Facility
Dickerson
MD
North Kansas City Sewer LDF
Kansas City
MO
North Regional Treatment Plant
Beaumont
TX
Oiltanking Houston, Inc.
Houston
TX
Reserve Environmental Services
Ashtabula
OH
Rush Township Treatment Plant
Moshannon
PA
SET Environmental
Houston
TX
SID #8 Saunders County Waste Water Treatment Facility
Fremont
NE
Encycle/Texas Inc.
Corpus Christi
TX
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-6

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Section 4-Industry Profile
Table 4-3. Direct Discharging CWT Facilities in 2016, Identified by the DMR Pollutant
Loading Tool
l-';icilil> Niiim-
Cii>
S(;ik'
US Ecology
Robstown
TX
Vopak Logistics Services - Deer Park Terminal
La Porte
TX
Waste Control Specialists
Andrews
TX
Waste Treatment Corp.
Warren
PA
Orrsvss
Figure 4-2. Direct Discharging CWT Facilities in 2016, Identified by the DMR Pollutant
Loading Tool
In identifying facilities potentially in-scope of this study, EPA evaluated the list of CWT
facilities from the 2000 CWT rulemaking. EPA expects that some of the CWT facilities
identified as part of the 2000 rulemaking are no longer in business. EPA also expects that
additional facilities have begun operation since 2000. EPA also expects that some facilities have
changed ownership, name, or discharge status. Given these factors, and that the 2000 rulemaking
list of facilities did not in some cases identify whether those facilities accepted waste from oil
and gas extraction activities, EPA did not consider the 2000 list to be the best source of data to
identify current CWT facilities that accept oil and gas extraction wastes. Rather, EPA relied
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-7

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Section 4-Industry Profile
primarily on other data sources to identify potentially in-scope facilities for this detailed study.
These data sources include:
•	The rulemaking record supporting EPA's ELGs rulemaking activities for
Unconventional Oil and Gas Extraction (40 CFR 435, Subpart C);
•	The record supporting the Effluent Guidelines Program Plans under section
304(m) of the CWA;
•	State NPDES and oil and gas permitting agencies and on-line databases;
•	Literature and periodicals;
•	Information from facilities and technology vendors (for example, through
websites, newsletters, or contact via site visits or phone conversations);
•	Input from trade groups and industry stakeholders;
•	Conference proceedings; and
•	EPA data systems such as Envirofacts4 and Enforcement and Compliance History
Online (ECHO).5
EPA combined information from these data sources into one dataset and reviewed this
dataset for duplicate records and accuracy. EPA collected information on facility location,
treatment capacity, and treatment type when available, as well as information such as facility
addresses, NPDES permit numbers, and Federal Registry System (FRS) identification numbers.
As a result of this effort, EPA prepared an updated CWT facility list (ERG, 2018). In total, EPA
identified 426 facilities nationwide6. For each of these facilities, EPA attempted to identify
whether the facility accepts oil and gas extraction wastes, such as produced water, fracturing
fluids, drilling fluids, drilling cuttings, etc. For those eight facilities where information indicated
that the facility does accept (or previously had accepted) oil and gas extraction wastes, EPA then
further evaluated whether each facility discharges process wastewater and how the facility is
permitted for discharge (e.g., under an effluent guideline or some other mechanism). Based on
this information, the list of 426 CWT facilities was organized by the following categories of
facilities (ERG, 2018):
•	Facilities permitted for discharge under the CWT ELGs at 40 CFR Part 437;
•	Facilities permitted for discharge under 40 CFR 435, Subpart E or F;
•	Facilities that do not discharge process wastewater but may be permitted to
discharge other wastewater (such as stormwater);
4	Envirofacts is available online at: httos://www3.epa.gov/enviro/.
5	ECHO is available online at: https://echo.epa. gov/.
6	Note EPA did not devote significant resources towards obtaining updated information on the status of facilities
identified for the 2000 rulemaking since EPA did not expect most of these facilities to be in-scope of EPA's detailed
study of CWTs accepting oil and gas extraction wastes. As a result, some of these facilities are likely no longer in
operation and/or information contained in U.S. EPA, 2017a is likely not current.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
•	Facilities that discharge wastewater from coalbed methane (CBM) extraction7;
•	Facilities permitted for discharge under other authority, such as Best Professional
Judgement or general permits;
•	Facilities with unknown discharge status and/or unknown basis for permitting8;
•	Zero discharge facilities located at oil and gas extraction wells and off-site9;
•	Facilities that applied for NPDES permits, but as of late 2016 had not installed
treatment and were not discharging oil and gas extraction wastewaters;
•	Facilities that ceased operations; and
•	Facilities with incomplete information and therefore it is not known whether oil
and gas extraction wastes are accepted for treatment.
Figure 4-3 shows information EPA has obtained on the 426 facilities identified. This
information should be considered a snapshot in time as of June 2017. EPA identified 210
facilities that potentially accept oil and gas extraction wastes. This includes 12 facilities that
accept only CBM wastes. Excluding CBM facilities, the number of facilities is 198. EPA has
little data available on the types of wastes accepted at many of these facilities, and therefore it is
likely that some of these facilities accept waste from activities such as crude oil storage rather
than from oil and gas extraction activities. EPA identified eight facilities that do not accept oil
and gas extraction wastes. EPA also identified 192 facilities for which information was not
readily available to determine whether oil and gas extraction wastes are accepted. Most of these
facilities are likely oil recyclers and facilities that provide CWT services for other (non-oil and
gas extraction) industrial waste sources. It is important to acknowledge that this list is limited
because EPA has incomplete information on existing indirect discharging CWT facilities, as
these facilities are not required to report to EPA. Additional data collection would be needed to
determine the types of wastes that are accepted at these facilities.
Of the 198 facilities identified as accepting oil and gas extraction wastes, 98 discharge
wastewater from waste treatment activities (also called process wastewater); 100 facilities do not
discharge process wastewater (but may have other discharges, such as stormwater or sanitary
waste); and discharge status is not known for 12 facilities.
7	Although EPA identified some CBM treatment facilities as part of this data gathering exercise, this was not a
primary purpose of this effort and the list prepared is not comprehensive.
8	Additional research will be needed to determine whether any of these facilities would be affected by changes to
EPA's CWT ELGs.
9	EPA was able to identify little information from public sources on many of these facilities. Therefore, the list
identified by EPA should not be considered comprehensive. In addition, some of these facilities are temporary
facilities located at well sites, and therefore may no longer be in operation.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-9

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Section 4-Industry Profile
42o Facilities Identified
8 Facilities Do Not Accept Oil and
Gas Extraction Wastewater
210 Facilities
Accept Oil
and Gas
Extraction
Wastewater
192 Facilities
Not Known if
Accept Oil
and Gas
Extraction
Wastewater
4 Facilities Closed
12 Facilities Permitted for
Discharge. Treatment not Installed
98 Facilities
Discharge
Process
Wastewater
100 Facilities
Do Not
Discharge
Process
Wastewater
12 Facilities
Not Known if
Discharge
Wastewater

I I Permi lied
I nder Pari 4.i7:;
l.i Permitted
I nder Pari 4."? 5
Subparts I - & I
12 Coallx'd
Methane
I 'aci lilies
(•>2 Oilier
I nkiiou n
* Includes facilities that are not currently permitted under Part
437, but which are expected to be when permits are reissued.
+ Includes general permits, BP J, and facilities where EPA did
not obtain permits and therefore basis for permitting is not
currently known.
Some facilities have stormwater discharge permits.
Figure 4-3. CWT and Oil and Gas Wastewater Treatment Facilities by Permit Type
and Discharge Status
Some facilities are permitted for discharge, but do not discharge wastewater from oil and
gas extraction waste treatment. Rather, the oil and gas extraction wastes are segregated from
other waste streams for treatment and/or management and are not discharged. EPA collected
information on some of these facilities to assess the broader CWT market. Additionally, EPA
identified several facilities that had obtained NPDES permits to discharge; however, information
available to EPA indicates that these facilities had not yet been constructed or had not yet
installed necessary treatment to meet effluent limitations as of late 2016.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
EPA identified 13 facilities that are permitted for discharge under the oil and gas ELGs at
40 CFR Part 43510. EPA collected information (such as type of treatment in place) from some of
these facilities. EPA also identified 12 coalbed methane treatment facilities (EPA did not collect
any additional information on these facilities because EPA evaluated CBM and determined in
2013 not to pursue a rulemaking for this industry). There were 62 facilities for which EPA did
not identify the permitting mechanism and did not identify any information indicating that these
facilities are in-scope of this study. Limitations on available information regarding the discharge
status and nature of the wastes accepted at facilities possibly caused EPA to mischaracterize
some proportion of facilities; additional data collection will be needed to make determinations
about facilities' activities and applicability. For the purposes of this study, EPA only considered
facilities in-scope if the wastewater accepted, discharge status, and permitting mechanism could
all be confirmed.
For this study EPA is primarily interested in those facilities that accept wastes from oil
and gas extraction activities and that are permitted for discharge (and are or have discharged)
under the CWT ELGs at 40 CFR Part 437. EPA has focused most of its data collection activities
on this subset of facilities. In addition, there are some facilities that are not currently permitted
under Part 437, but information available to EPA indicates that these facilities will be subject to
the CWT ELGs when permits are re-issued. These facilities are also in-scope for this study since
these facilities may be affected by any changes to Part 437 requirements in the future. EPA has
identified 11 facilities that accept oil and gas extraction wastes and are either currently permitted
under Part 437 or information available to EPA indicates will be permitted under Part 437 when
NPDES permits are reissued. These 11 facilities are the primary focus of this study. Table 4-4
lists the facilities that EPA has identified as being in-scope, or potentially in-scope, for this
study.
For each of the potentially in-scope facilities identified in Table 4-4, EPA attempted to
obtain additional information, such as types and quantities of wastes accepted, and treatment
technologies utilized. EPA collected information and data using a variety of methods, including
internet searches and review of NPDES permits. EPA held teleconferences with personnel at
some facilities to obtain details of the operations at those facilities. In addition, EPA conducted
site visits at select in-scope facilities, as well as other facilities that manage oil and gas extraction
wastewaters, to collect information about each facility's operations, wastewater management
practices and treatment technologies. Table 4-5 lists the facilities that EPA visited as part of this
study. EPA prepared a Site Visit Report for each of the facility site visits; these references are
also listed in the table.
10 These facilities were identified incidentally during EPA's search for Part 437 facilities; therefore, this is not a
comprehensive list and there may be more Part 435 facilities.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
Table 4-4. Summary of In-Scope Discharging CWT Facilities Treating Oil and Gas
Extraction Wastes
l-':icilil\ Niimo
< i(\
Sliiio
Dischiiriic
Tj pi-
l-';icilil> Noll's
Byrd/Judsonia Water
Reuse/Recycle Facility
Judsonia
AR
Direct
Facility is permitted for discharge, but
operates almost exclusively as a recycle
facility and discharges infrequently.
Clarion Altela Environmental
Services (CAES)
Clarion
PA
Direct
Facility is permitted for discharge, but as of
late 2016 facility was not accepting
wastewater for discharge.
Eureka Resources, Standing
Stone Facility
Wysox
PA
Direct

Eureka Resources,
Williamsport 2nd Street Plant
Williamsport
PA
Indirect

Fairmont Brine Processing,
LLC
Fairmont
WV
Direct

Fluid Recovery Services:
Franklin Facility (Aquatech)
Franklin
PA
Direct
Facility is not currently permitted under part
437, but revised permit expected to contain
part 437 limitations.
Fluid Recovery Services:
Josephine Facility (Aquatech)
Josephine
PA
Direct
Facility is not currently permitted under part
437, but revised permit expected to contain
part 437 limitations.
Fluid Recovery Services:
Creekside Facility (Aquatech)
Creekside
PA
Direct
Facility is not currently permitted under part
437, but revised permit expected to contain
part 437 limitations
Max Environmental
Technologies, Inc - Yukon
Facility
Yukon
PA
Direct
Accepts drilling muds and cuttings for
stabilization and solidification along with
other industrial wastes. Facility is permitted
for discharge of CWT wastes.
Patriot Water Treatment, LLC
Warren
OH
Indirect

Waste Treatment Corporation
Warren
PA
Direct

Note: EPA identified one additional facility, the Cares McKean facility in Pennsylvania, that was previously
permitted under Part 437. However, the most recent permit for this facility issued in 2016 no longer includes the
CWT ELGs indicating that this facility no longer discharges process wastewater from Part 437-regulated activities.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
Table 4-5. List of Facilities Visited by EPA
l-';icilil> Niiim*
I.ociilion
Diilc of Visit
Silo Visit Report
(i(;Uinn
Anticline Disposal
Pinedale, WY
August 29, 2016
ERG, 2016b
Fluid Recovery Services, Josephine Facility
Indiana, PA
June 2, 2016
ERG, 2016a
Eureka Resources, Standing Stone Facility
Wysox, PA
June 1, 2016
ERG, 2017b
Fairmont Brine Processing, LLC
Fairmont, WV
December 8, 2015
ERG, 2016d
Patriot Water Treatment, LLC
Warren, OH
October 28, 2014
U.S. EPA, 2015b
Seneca Resources Corporation
Covington, PA
August 6, 2014
U.S. EPA, 2015d
Nuverra Appalachian Water Services
Masontown, PA
July 29, 2014
U.S. EPA, 2014
Reserved Environmental Services, LLC
Mt. Pleasant, PA
July 28, 2014
U.S. EPA, 2015c
McCutcheon Enterprises Inc.
Apollo, PA
July 28, 2014
U.S. EPA, 2015a
4.3 In-Scope CWT Facility Summaries
The following discussion summarizes information obtained by EPA for each of the
potentially in-scope facilities identified in Table 4-4. A series of tables is presented that includes
relevant information collected for each facility. In addition, a discussion of each facility presents
key information and findings.
Table 4-6 shows the address and latitude/longitude for each potentially in-scope facility.
As can be seen, with the exception of the Byrd/Judsonia facility in Arkansas, all of the
potentially in-scope facilities are located near the Marcellus shale region. The locations of in-
scope facilities are shown in Figure 4-4.
Table 4-7 shows the type of discharge (either direct or indirect) for each potentially in-
scope facility, as well as the NPDES permit number, applicable subpart of the CWT ELGs that
forms the basis of the technology-based effluent limitations in each permit and the receiving
water body each facility discharges to. Two of the facilities, the Eureka Resources 2nd Street
plant and the Patriot Water Treatment, LLC plant are indirect dischargers while the remaining
facilities are permitted for direct discharge.
Table 4-8 shows the types of wastes accepted at each facility, based on various data
sources. One source, the Pennsylvania Department of Environmental Protection Oil and Gas
reporting website11, uses reports of waste disposition provided by producers. As this data is self-
reported by the producers of the waste, it is possible that producers may indicate an incorrect
waste type. EPA has not verified the accuracy of these reports.
Table 4-9 lists some of the treatment technologies utilized at each facility, taken from
publicly available sources such as NPDES permit fact sheets or internet searches. It is
noteworthy that the level of treatment in-place at facilities varies, with some facilities using
11 https ://www .paoilandgasreporting. state .pa.us/publicreports/Modules/W elcome/Agreement. aspx.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-13

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Section 4-Industry Profile
technologies such as evaporation or distillation that are capable of removing dissolved solids
(such as chlorides) while others provide only limited treatment such as chemical precipitation.
There are pollutants that are found in oil and gas extraction wastes that are not currently
regulated by the CWT ELGs. Permits for some facilities contain limitations for some of these
pollutants, which are based on water quality criteria or other factors. Table 4-10 and Table 4-11
show the permit limitations for select pollutants that are not contained in the current CWT ELGs
at 40 CFR part 437, but that are commonly associated with certain oil and gas extraction wastes
such as produced waters. Pollutants include barium, strontium, bromide, gross alpha and beta
radiation, radium (226 and/or 228) TDS, chlorides and osmotic pressure. As can be seen in these
tables, some of the permits for in-scope facilities contain numeric effluent limitations or
monitoring requirements for these pollutants, while others do not.
Table 4-6. In-Scope Facility Summary - Location Information
l-';icilil> Niimc
l-';icilil> Address-1
l.iililudi'
l.on^iludc1'
Byrd/Judsonia Water Reuse/Recycle Facility
4301 Highway 157 N
Judsonia, AR
35.443
-91.691
Clarion Altela Environmental Services (CAES)
3099 Piney Dam Rd
Clarion, PA
41.170
-79.437
Eureka Resources, Standing Stone Facility
34640 Route 6
Wysox, PA
41.748
-76.332
Eureka Resources, Williamsport 2nd Street Plant
419 2nd Street
Williamsport, PA
41.237
-77.008
Fairmont Brine Processing, LLC
168 AFR Drive
Fairmont, WV
39.507
-80.126
Fluid Recovery Services: Franklin Facility
5148 U.S. Route 322
Franklin, PA
41.373
-79.798
Fluid Recovery Services: Josephine Facility
931 Bells Mill Rd.
Josephine, PA
40.482
-79.171
Fluid Recovery Services: Creekside Treatment
Facility
5035 U.S. Route 110 West
Creekside, PA
40.677
-79.186
Max Environmental Technologies, Inc - Yukon
Facility
233 Max Lane
Yukon, PA
40.212
-79.699
Patriot Water Treatment, LLC
2840 Sferra Ave
Warren, OH
41.261
-80.824
Waste Treatment Corporation
123 West Harmar Street
Warren, PA
41.839
-79.161
a Addresses obtained from permit documents, may be approximate or may be office location, not facility location.
b Latitude/Longitude may be for permitted outfall or facility.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-14

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Section 4-Industry Profile
Minneapolis
Kansas
City
Quebec
Ottawa
Albany-
Be
Provit
St Louis
Indianapolis Co,umbu
Cincinnati
Louisville
Oklahoma
City
Dallas
Nashville b,8B|!|e Sr.
mphis	0iartt'
Greenville
Birmingham
Atlanta
Figure 4-4. In-Scope Facility Map
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-15

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Section 4-Industry Profile
Table 4-7. In-Scope Facility Summary - Permit and Discharge Information
l-'iiciliM Niimo
T\ pe of
Dischiiriic
Dischiii'^o
Perm il
Number
cwt r.i.Cs
Siihpiiii
Reeei\iiiii Wilier or
porw
I5\ id liidsnina Waler Reuse Reevele
Facility
Direct
ARUU52U51
B
1 mianied inhiil;ii\ ol
Holcomb Branch
Clarion Altela Environmental Services
(CAES)
Direct
PA0103632
D
Piney Creek
Eureka Resources, Standing Stone
Facility
Direct
PA0232351
D
Susquehanna River
Eureka Resources, Williamsport 2nd
Street Plant
Indirect to
POTW
NDWD C-20b
C
City of Williamsport, PA
Fairmont Brine Processing, LLC
Direct
WVO116408
D
Monongahela River
Fluid Recovery Services: Franklin
Facility
Direct
PA0101508
N/Aa
Allegheny River
Fluid Recovery Services: Josephine
Facility
Direct
PA0095273
N/Aa
Blacklick Creek
Fluid Recovery Services: Creekside
Treatment Facility
Direct
PA0095443
N/Aa
McKee Run
Max Environmental Technologies, Inc -
Yukon Facility
Direct
PA0027715
A
Sewickley Creek
Patriot Water Treatment, LLC
Indirect to
POTW
N/Ab
C
City of Warren, OH
Waste Treatment Corporation
Direct
PAO102784
A
Allegheny River
a Current NPDES permit does not contain 40 CFR Part 437 ELGs.
b Indirect discharging facilities do not hold NPDES permits, but instead comply with pretreatment standards which
are generally implemented through control agreements issued by the POTW.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-16

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Section 4-Industry Profile
Table 4-8. In-Scope Facility Summary - Wastes Accepted
l-'iicilil> Niimc
T\ pes of \\ .isles Accepled
I);il;i Sou reels)
Byrd/Judsonia Water
Reuse/Recycle Facility
Treated fluids from the exploration, production
and development of oil and/or gas operations.
Site Visit; NPDES permit;
Questionnaire
Clarion Altela Environmental
Services (CAES)
Drilling fluid waste, fracturing fluid waste,
produced fluid, servicing fluid.
PA DEP Oil and Gas Reporting
Website - Waste Reports
Eureka Resources, Standing
Stone Facility
Drilling fluid waste, fracturing fluid waste,
produced fluid, other oil and gas wastes
(unspecified).
PA DEP Oil and Gas Reporting
Website - Waste Reports; Site
Visit and Questionnaire
Eureka Resources,
Williamsport 2nd Street Plant
Drilling fluid waste, fracturing fluid waste,
produced fluid, servicing fluid.
PA DEP Oil and Gas Reporting
Website - Waste Reports
Fairmont Brine Processing,
LLC
Drilling fluid waste, fracturing fluid waste,
produced fluid.
PA DEP Oil and Gas Reporting
Website - Waste Reports; Site
Visit and Questionnaire
Fluid Recovery Services:
Franklin Facility
Drilling fluid waste, fracturing fluid waste,
produced fluid, servicing fluid.
PA DEP Oil and Gas Reporting
Website - Waste Reports
Fluid Recovery Services:
Josephine Facility
Drilling fluid waste, fracturing fluid waste,
produced fluid, servicing fluid.
PA DEP Oil and Gas Reporting
Website - Waste Reports; Site
Visit and Questionnaire
Fluid Recovery Services:
Creekside Treatment Facility
Drilling fluid waste, fracturing fluid waste,
produced fluid.
PA DEP Oil and Gas Reporting
Website - Waste Reports
Max Environmental
Technologies, Inc - Yukon
Facility
Drill cuttings, drilling fluid waste, flowback
fracturing sand, fracturing fluid waste,
produced fluid.
PA DEP Oil and Gas Reporting
Website - Waste Reports
Patriot Water Treatment, LLC
Drill cuttings, drilling fluid waste, fracturing
fluid waste, other oil and gas wastes
(unspecified), produced fluid, servicing fluid.
PA DEP Oil and Gas Reporting
Website - Waste Reports; Site
Visit and Questionnaire
Waste Treatment Corporation
Drill cuttings, drilling fluid waste, fracturing
fluid waste, produced fluid, servicing fluid.
PA DEP Oil and Gas Reporting
Website - Waste Reports;
Questionnaire
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-17

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Section 4-Industry Profile
Table 4-9. In-Scope Facility Summary - Treatment Technologies Utilized
l-':icilil\ Niimc
1 roiiliiHMil Technologies I lili/od
Design or Permit led
1 IVillllHMII ( il|)iicil>
(li;illons/(l;i\)
Byrd/Judsonia Water
Reuse/Recycle Facility
Sedimentation basins, induced gas flotation, bag
filter, mechanical vapor recompression.
168,000 (permitted)
Clarion Altela Environmental
Services (CAES)
Sedimentation basins, chemical precipitation,
thermal distillation (AltelaRain®).
62,500 (permitted)
Eureka Resources, Standing
Stone Facility
Clarification, chemical precipitation, mechanical
vapor recompression, membrane biological reactors,
ion exchange, reverse osmosis.
420,000 (pretreatment for
recycle)
210,000 (crystallization)
Eureka Resources,
Williamsport 2nd Street Plant
Clarification, chemical precipitation, mechanical
vapor recompression.
337,500 (permitted)
Fairmont Brine Processing,
LLC
Chemical precipitation, oil/water separation, bag
filter, granulated activated carbon filter, evaporation
and crystallization, ion exchange.
210,000
Fluid Recovery Services:
Franklin Facility
Aeration, oil/water separation, chemical
precipitation, clarification.
300,000 (permitted)
Fluid Recovery Services:
Josephine Facility
Oil/water separation, aeration, chemical
precipitation, clarification, bag filtration.
155,000 (permitted)
Fluid Recovery Services:
Creekside Treatment Facility
Oil/water separation, chemical precipitation,
clarification, bag filtration.
63,000 (permitted)
Max Environmental
Technologies, Inc - Yukon
Facility
Lime neutralization, flocculation, sedimentation.
173,000 (average)
Patriot Water Treatment, LLC
Settling, chemical precipitation, clarification.
100,000
Waste Treatment Corporation
Chemical precipitation, filtration, oil/water
separation, mechanical vapor recompression.
213,000 (permitted)
Note: Information obtained from facility permits, fact sheets or internet searches.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-18

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Section 4-Industry Profile
Table 4-10. In-Scope Facility Summary - Effluent Limitations for Select Parameters Not Currently Regulated at 40 CFR Part 437
(Monthly Averages)




Monthly \\or;i!ii' r.lTliieiil l.imiliilious



l-';ieilil> Name
Oiitl'iill
liiii'iiiin
(mii/l.)
Slmnliiim
(m Si/I.)
limmirie
(mii/l.)
Cross A
(p("i/l -)
(¦ ross IS
(|)(i/l.)
Kiidium
22(. + 22X
(p('i/l.)
IDS
(mii/l.)
( hloriries
(mii/l.)
Osmotic
Pressure
(mOs/kii)
Byrd/Judsonia Water Reuse/Recycle Facility
001
--
Monitor*
--
—
Monitor*
Monitor
(Ra226)*
354
94
~
Clarion Altela Environmental Services
(CAES)
501
10
10
Monitor
Monitor
~
Monitor
500
250
3,571
Eureka Resources, Standing Stone Facility
002
10
10
--
--
~
~
500
250
~
Eureka Resources, Williamsport 2nd Street
Plant
1
2.0
2.0
Monitor
Monitor*
Monitor*
Monitor*
250
125
~
Fairmont Brine Processing, LLC
001
Monitor
Monitor
Monitor
7.5
498
2.5
Monitor
Monitor
~
Fluid Recovery Services: Franklin Facility
001
Monitor
Monitor
--
--
~
~
Monitor
147**
~
Fluid Recovery Services: Josephine Facility
001
114
--
--
~
~
~
Monitor
Monitor
Monitor
Fluid Recovery Services: Creekside
401
14.64
--
--
~
~
~
Monitor
Monitor
483
Treatment Facility
501
13.78
--
--
~
--
~
Monitor
Monitor
4,128
Max Environmental Technologies, Inc -
001
4.0
--
~
~
~
--
--
--
1,000
Yukon Facility
201
--
--
~
--
~
~
--
~
--
Patriot Water Treatment, LLC
--
--
--
--
~
~
~
~
~
~
Waste Treatment Corporation
001
--
--
~
~
~
~
~
Monitor
Monitor
- No effluent limitation listed in permit.
* Quarterly.
** Mass-based limitation (lbs/min).
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-19

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Section 4-Industry Profile
Table 4-11. In-Scope Facility Summary - Effluent Limitations for Select Parameters Not Currently Regulated at 40 CFR Part 437
(Daily Maximums)
l-';icilil> Name
OiiHiill
liiii'iiiin
(niii/l.)
Slmnliiim
(inii/l.)
I);iil\ \
limmiric
(inii/l.)
;i\iillli ill 1
Cross A
(|)(i/l.)
rriiieni i.im
(il'OSS IS
(p('i/l.)
iliilions
Kiidium
22(. + 22X
(p('i/l.)
IDS
(iiiii/l.)
Chlorides
(m Si/I.)
Osmotic
Pressure
(mOs/kii)
Byrd/Judsonia Water Reuse/Recycle
Facility
001
-
-
-
-
-
-
534
141
-
Clarion Altela Environmental Services
(CAES)
501
20
20
-
-
-
-
1,000
500
7,142
Eureka Resources, Standing Stone Facility
002
20
20
~
~
~
--
1,000
500
~
Eureka Resources, Williamsport 2nd Street
Plant
1
3.0
3.0
-
-
-
-
375
188
-
Fairmont Brine Processing, LLC
001
--
--
~
15
1000
5
~
--
~
Fluid Recovery Services: Franklin Facility
001
--
--
~
--
~
~
~
245**
~
Fluid Recovery Services: Josephine Facility
001
228
--
~
~
"
~
~
--
--
Fluid Recovery Services: Creekside
Treatment Facility
401
29.28
--
--
~
~
--
--
--
980***
501
27.56
--
~
~
~
~
~
~
5,879***
Max Environmental Technologies, Inc -
Yukon Facility
001
8.0
--
~
--
~
~
~
~
2,000
201
--
--
~
~
~
~
~
~
~
Patriot Water Treatment, LLC
--
--
--
~
~
"
~
50,000*
~
--
Waste Treatment Corporation
001
-
-
-
-
-
-
-
-
-
- No effluent limitation listed in permit.
* Maximum allowable TDS in indirect discharge is 50,000 mg/L or 41,700 lbs/day. Facility pays a surcharge for TDS above 1,500 mg/L.
**Mass-based limitation (lbs/min).
*** Instantaneous maximum.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-20

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Section 4-Industry Profile
4.3.1 Byrd/Judsonia Water Reuse/Recycle Facility
This facility began operating in 2013 and manages wastewater from wells operated by
Southwestern Energy's Fayetteville shale operations. The facility is permitted for discharge;
however, it is EPA's understanding from discussions with representatives of Southwestern
Energy that the facility rarely discharges treated wastewater. Instead, wastewater is reused in
other oil and gas operations. EPA conducted a site visit at the Judsonia facility in September
2013 (U.S. EPA, 2015e) as part of EPA's unconventional oil and gas extraction rulemaking (81
FR 41845). In addition, in 2016 the facility completed a technical and an economic questionnaire
obtained under authority of section 308 of the Clean Water Act. At the time of the 2013 site visit,
the treatment technologies utilized included sedimentation, oil skimming, aeration, Purestream
Services' induced gas flotation (IGF) technology to remove suspended solids and oils, bag
filtration and evaporation using Purestream Services' mechanical vapor recompression (MVR)
technology. The condensate from the MVR is stored in holding tanks until recycled for reuse in
well development or discharged. Concentrated brine is stored in a brine tank prior to disposal or
reuse.
The facility is permitted under the CWT ELGs, with direct discharge limitations from
Subpart B, NSPS (40 CFR 437.24). The technology-based effluent limitations serve as the basis
of the permit limits for some metals (arsenic, chromium, cobalt and tin) as well as all organic
parameters found at 437.24. The permit contains limits that are more stringent than the CWT
NSPS limitations for TSS, oil and grease and several metals (cadmium, copper, lead, mercury
and zinc). In addition, the permit contains limitations for several parameters not included in the
CWT Subpart B ELGs (carbonaceous biochemical oxygen demand (BOD), ammonia-nitrogen
(NFb-N), dissolved oxygen (DO), chlorides, sulfates, total dissolved solids (TDS), chromium
(III), chromium (VI), nickel, silver and cyanide). The permit also contains monitoring
requirements, but no limitations, for radium-226, strontium-90, gross beta radiation, and chronic
whole effluent toxicity (WET).
See Figure 4-5 for an aerial view of the facility. The sedimentation basins, the aerated
impoundment and the holding tanks are clearly visible. U.S. EPA, 2015e contains additional
details on this facility.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-21

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Section 4-Industry Profile
MMMI
¦¦¦¦¦¦¦
Figure 4-5. Aerial View of Judsonia Treatment Facility
4.3.2 Clarion/Altela Environmental Services (CAES)
This commercial facility is co-located with a power plant and permitted to discharge
several wastestreams including treated shale gas extraction wastewater. EPA did not conduct a
site visit at this facility, but did have a phone call with representatives of Altela, Inc. (Altela) in
November 2015 to obtain additional facility information. The facility operates the AltelaRain®
evaporative technology. The technology was developed with Department of Energy funding and
described in a series of reports including NETL, 2011 and U.S. DOE, 2014. The facility also
includes technologies to pretreat the wastewater prior to the evaporative technology, described at
U.S. EPA, 2017b.
The facility is permitted under the CWT ELGs, with direct discharge limitations from
Subpart D, NSPS (40 CFR 437.45(b)). There is an internal monitoring point (IMP) 501 in the
permit that contains the limitations for the treated shale gas extraction wastewater. The CWT
ELGs serve as the basis of the permit limits for all parameters regulated at 40 CFR 437.45(b),
with the exception of oil and grease. The oil and grease limitations in the permit are more
stringent than the technology-based limitations at 40 CFR 437.45(b). IMP 501 also includes
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-22

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Section 4-Industry Profile
limitations for several additional parameters not regulated at 40 CFR 437.45(b) (TDS, osmotic
pressure, barium, strontium and chloride) and also requires monitoring and reporting for
ammonia-nitrogen, total uranium, bromide, gross alpha, and radium 226/228. Figure 4-6 shows
an aerial view of the CAES facility. Several impoundments are visible, as well as a building that
houses the treatment system and evaporators.

Figure 4-6. Aerial View of CAES Facility
4.3.3 Eureka Resources, Standing Stone Facility
Eureka Resources operates two commercial CWT facilities in Pennsylvania - the
Standing Stone facility located in Bradford County and the Reach Road facility located in the
city of Williamsport. EPA conducted a site visit of the Standing Stone facility in June 2016. In
addition, in 2016 the facility completed a technical and an economic questionnaire obtained
under authority of section 308 of the Clean Water Act. EPA also conducted wastewater sampling
at the Standing Stone facility in 2016. A discussion of the sampling data collected is included in
Sections 5 and 7 of this report.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
Eureka Resources utilizes a variety of technologies at their facilities, including oil/water
separation, chemical precipitation, distillation and crystallization using mechanical vapor
recompression, biological treatment utilizing membrane biological reactors, and reverse osmosis.
Eureka also employs methanol rectification to recover methanol and reduce the organic content
of the wastewater. Eureka Resources recovers marketable by-products during treatment, such as
methanol, sodium chloride and calcium chloride. See Figure 4-7 for an aerial view of the
Standing Stone facility.
The Standing Stone facility is permitted under the CWT ELGs, with direct discharge
limitations from Subpart C, NSPS (40 CFR 437.34). The technology-based effluent limitations
serve as the basis of the permit limits for all pollutants regulated at 437.34. In addition, there are
discharge limitations for pollutants not contained in the CWT ELGs at 437.34 (TDS, chloride, oil
and grease, NH3-N, barium, iron and strontium). The permit also contains monitoring
requirements, but no effluent limitations, for nitrogen compounds and phosphorus.
—
¦Sail
	
—
	
	
.BUM
HHgpi
mKHMm
BBB

aWMMil
				

tit
Figure 4-7. Aerial View of Eureka Standing Stone Facility
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-24

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Section 4-Industry Profile
4.3.4 Eureka Resources, Williamsport 2nd Street Plant
Eureka Resources operates a commercial CWT facility in Williamsport, PA servicing
operators in the Marcellus Shale region. EPA conducted a site visit at the Eureka Williamsport
facility in June 2012 as part of EPA's unconventional oil and gas extraction rulemaking (81 FR
41845). At that time, the facility was permitted to accept wastewaters from drilling, fracturing
and production. The facility offers treated wastewater for reuse to operators, and also can
discharge indirectly to the Williamsport, PA POTW. Treatment technologies utilized at the
facility include chemical precipitation, clarification, and evaporation/condensation using
mechanical vapor recompression. See the Eureka Site Visit Report for additional information
obtained during the EPA site visit of the facility (U.S. EPA, 2012).
The facility is permitted under the CWT ELGs, with indirect discharge limitations from
Subpart C, PSNS (40 CFR 437.36). The technology-based effluent limitations serve as the basis
of the permit limits for all pollutants regulated at 437.36. In addition, the facility is subject to
numeric local limits for TDS, chloride, COD, arsenic, barium, copper, lead, strontium, sulfates,
and oil and grease. The facility is also subject to monitoring requirements for a range of other
pollutants, notably bromide, surfactants, methanol, glycols, gross alpha/beta radiation, and
radium 226/228. Figure 4-8 shows an aerial view of the facility.
Figure 4-8. Aerial View of Eureka 2nd Street Facility
4.3.5 Fairmont Brine Processing, LLC
Fairmont Brine Processing, LLC (Fairmont) operates a commercial CWT facility in
Fairmont, WV that provides wastewater treatment services for producers in the Marcellus Shale
region. EPA conducted a site visit at the Fairmont facility in December 2015. See U.S. EPA,
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
4-25

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Section 4-Industry Profile
2015d for additional details on this facility. In addition, in 2016 the facility completed an
economic questionnaire obtained under authority of section 308 of the Clean Water Act.
The treatment system at the facility incorporates a number of technologies, including oil
water separation, chemical precipitation for barium and metals removal, bag filtration for solids
removal, granulated activated carbon filtration for organics control, evaporation/crystallization
for TDS and chlorides removal, and ion exchange for final polishing for ammonia. The
evaporative system uses a multiple-effect process and the facility recovers marketable by-
products during treatment, such as sodium chloride crystals and calcium chloride solutions.
The Fairmont Brine facility is permitted under the CWT ELGs, with direct discharge
limitations from Subpart D NSPS with combined wastes from Subpart A and B (40 CFR
437.45(c)). The technology-based effluent limitations serve as the basis of the permit limits for
all parameters regulated under this subpart. In addition, there are more stringent daily limitations
for total copper and bis(2-ethylhexyl) phthalate in the permit. The permit also contains numeric
effluent limitations for several pollutants not included in the CWT ELGs (ammonia-nitrogen,
residual chlorine, gross alpha and gross beta radiation, radium 226/228 and chronic toxicity) and
monitoring requirements, but no limitations, for a number of additional pollutants (including
chloride, barium, strontium, lithium and bromide).
See Figure 4-9 for an aerial view of the facility. The unloading area, process building,
and impoundments are clearly visible.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
Figure 4-9. Aerial View of Fairmont Brine Facility
4.3.6 Fluid Recovery Services: Franklin Facility
Fluid Recovery Services (FRS) operates four commercial CWT facilities servicing
operators in and around Pennsylvania. The parent company of FRS is Aquatech International
LLC. As of late 2016, three of the FRS facilities were discharging wastewater. A fourth facility
(the Rouseville facility), was not discharging wastewater and was being used only as a waste
transfer facility as treatment necessary to meet discharge limitations had not yet been installed12.
The Franklin facility utilizes treatment technologies including aeration, oil/water
separation, chemical precipitation and clarification (PADEP, 2008a). As of April 2017, the
facility does not have treatment in place to remove TDS or chlorides. The discharge permit does
not contain the CWT effluent limitations - discharge limitations are based on BPJ and water
quality criteria. However, it is EPA's understanding that the facility will be subject to the CWT
12 The Rouseville facility is permitted for discharge under the CWT ELGs with direct discharge limitations from
Subpart D NSPS with combined waste receipts from Subparts A, B and C (40 CFR 437.45(b)). The permit also
contains limitations for TDS and chloride. See NPDES permit number PA0263516.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
ELGs when the permit is reissued at some point in the future. The current NPDES permit
includes limitations for oil and grease, TSS, iron, copper and silver. The permit also contains a
mass-based limitation on chloride. The permit restricts discharge to a maximum of 0.30 MGD,
and the daily maximum chloride limitation is 245 pounds per minute. The permit also includes
additional monitoring requirements, notably for barium, strontium and TDS. The NPDES permit
expired in February 2015, and the facility is currently operating under an administratively
continued permit. Figure 4-10 shows an aerial view of the facility.
Figure 4-10. Aerial View of Fluid Recovery Services Franklin Facility
4.3.7 Fluid Recovery Services: Josephine Facility
EPA conducted a site visit at the Josephine facility in June of 2016. In addition, the
facility completed a technical and an economic questionnaire obtained under authority of section
308 of the Clean Water Act. At the time of the site visit, the facility was operating a treatment
system consisting of oil/water separation, aeration, chemical precipitation, clarification and bag
filtration (PA DEP, 2008b). As of April 2017, the facility does not have treatment in place to
remove TDS or chlorides. Similar to the Franklin facility, the discharge permit for the Josephine
facility does not contain the CWT effluent limitations. However, it is EPA's understanding that
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
the facility will be subject to the CWT ELGs when the permit is reissued at some point in the
future. The current NPDES permit includes limitations for oil and grease, TSS, iron and barium.
The permit does not contain any limitation on chlorides or TDS, although it does contain
monitoring requirements for TDS, chlorides and osmotic pressure. The permit restricts discharge
to a maximum of 0.155 MGD. The NPDES permit expired in June 2013, and the facility is
currently operating under an administratively continued permit. See Figure 4-11 for an aerial
view of the facility.
Figure 4-11. Aerial View of Fluid Recovery Services Josephine Facility
4.3.8 Fluid Recovery Services: Creekside Treatment Facility
The Creekside facility utilizes treatment technologies including aeration, oil/water
separation, chemical precipitation and clarification (PADEP, 2013). As of April 2017, the
facility does not have treatment in place to remove TDS or chlorides. Similar to both the
Josephine and Franklin facilities, the discharge permit does not contain the CWT effluent
limitations. However, it is EPA's understanding that the facility will be subject to the CWT
ELGs when the permit is reissued at some point in the future. The current NPDES permit
includes limitations for oil and grease, TSS, iron, barium and osmotic pressure. The permit does
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not contain any limitation on chloride or TDS, although the permit does contain monitoring
requirements for these parameters. The permit restricts discharge to a maximum of 0.045 MGD.
The NPDES permit expired in July 2013, and the facility is currently operating under an
administratively continued permit. Figure 4-12 shows an aerial view of the facility.
Figure 4-12. Aerial View of Fluid Recovery Services Creekside Facility
4.3.9 Max Environmental Technologies, Inc - Yukon Facility
This facility includes a landfill and on-site hazardous waste treatment system. The most
recent NPDES permit was issued in July 2004. The permit expired in July 2009 and has been
administratively continued. This site is permitted to accept several different wastes and contains
several permitted outfalls. Internal outfall 201 is for the hazardous liquid slurry treatment system,
and the effluent limitations are based on 40 CFR 437 subpart A.
The pollution report for the facility (PA DEP, 2004) indicates that the average discharge
of outfall 201 is 173,000 gpd and that this is an intermittent discharge. The pollution report also
indicates that the facility discharges continuously thorough outfall 001 at an average discharge of
280,000 gpd. Outfall 001 includes several waste streams, such as treated pickle liquor
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wastewater from iron and steel manufacturing, treated waste storage area storm water, mine
drain wastewater, and leachate from the co-located landfill. Effluent limitations for outfall 001
are based on various sources.
While the facility accepts waste from oil and gas extraction activities, and the PA DEP oil
and gas reporting website indicates producers have utilized the facility for management of
several different waste types, information obtained from the Pennsylvania Department of
Environmental Protection indicates that these wastes are not discharged under the NPDES
permit, but rather are solidified for disposal. Therefore, while the facility is currently permitted
under Part 437, and the facility does accept oil and gas extraction wastes, the facility would not
be affected by any changes to Part 437 given EPA's current understanding of operations.
Figure 4-13. Aerial View of Max Environmental Technologies, Inc. Yukon Facility
4.3.10 Patriot Water Treatment, LLC
This facility is a commercial facility permitted for indirect discharge to the City of
Warren, Ohio POTW. EPA conducted a site visit of the Patriot Water Treatment, LLC (Patriot)
facility on October 28, 2014. In addition, the facility completed a technical and an economic
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questionnaire obtained under authority of section 308 of the Clean Water Act. At the time of the
site visit, the facility was treating oil and gas extraction wastewater, industrial wastewater and oil
and gas drilling muds. Treatment for oil and gas extraction wastewater at the facility consists of
settling, chemical precipitation and clarification. The facility does not have technologies for TDS
or chlorides removal. The permit with the City of Warren allows for a daily discharge up to
100,000 gallons per day at 50,000 mg/L (or approximately 41,700 pounds per day) of TDS from
treating oil and gas extraction wastewaters. The facility also accepts wastewater from industrial
sources, which is treated through a parallel treatment train consisting of chemical precipitation
and clarification. Drilling muds are centrifuged to separate solids and liquids, or else mixed with
sawdust to absorb water. Additional details of the facility can be found at U.S. EPA, 2015b.
The facility's permit contains pretreatment standards from the CWT ELGs, Subpart C,
PSNS (40 CFR 437.36) and the limitations for copper, zinc, acetone, acetophenone, 2-butanone,
phenol and pyridine that apply to direct discharging facilities as well (40 CFR 437.31). In
addition, the permit incorporates ordinance effluent limitations for additional pollutants
including metals, free cyanide, ammonia, pH, COD, TDS, and TSS. Effluent concentrations
exceeding daily maximum discharge limitations for COD, TDS, and TSS (600 mg/L, 1,500
mg/L, and 250 mg/L, respectively) are subject to additional surcharge. The permit also contains
monitoring requirements but no limitations for cadmium, lead, silver and total cyanide. Figure
4-14 shows an aerial view of the Patriot facility.
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Section 4-Industry Profile
—
Figure 4-14. Aerial View of Patriot Water Treatment, LLC Facility
4.3.11 Waste Treatment Corporation
Waste Treatment Corporation operated a commercial CWT facility in Warren, PA13. EPA
did not conduct a site visit at this facility; however, the facility did provide details regarding
operations and treatment technologies utilized at the facility (Roddy, 2016). The facility accepted
wastewater for discharge from wells defined as conventionally drilled according to Pennsylvania.
The facility indicated that, as of June 2016, wastewater from unconventionally (as defined by
Pennsylvania) drilled wells was not being discharged14. Technologies used at the site include
13	This facility closed in November, 2017.
14	Pennsylvania defines an unconventional formation as "A geological shale formation existing below the base of the
Elk Sandstone or its geologic equivalent stratigraphic interval where natural gas generally cannot be produced at
economic flow rates or in economic volumes except by vertical or horizontal well bores stimulated by hydraulic
fracture treatments or by using multilateral well bores or other techniques to expose more of the formation to the
well bore."
In April 2011, the Pennsylvania Secretary of Environmental Protection requested that all unconventional oil and gas
developers cease taking wastewater to processing facilities and sewage treatment plants.
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oil/water separation, chemical precipitation, clarification, filtration and mechanical vapor
recompression for TDS and chlorides removal.
The facility is permitted under the CWT ELGs, with direct discharge limitations for
internal outfalls 101 and 201 from Subpart A, BAT (40 CFR 437.13). The permit also includes
BAT cyanide limitations. The technology-based effluent limitations serve as the basis of the
permit limits for all metals and cyanide found at 437.13. The permit also contains limitations for
oil and grease, TSS, iron, aluminum and selenium for outfalls 101 and 201, and CBODs and total
residual chlorine for outfall 201. Outfall 001, which receives wastewater from internal outfalls
101 and 201 as well as stormwater, includes limitations for cadmium, fecal coliform and
acrylamide, and monitoring requirements for chlorides, osmotic pressure and toxics. The permit
for this facility expired in November of 2008 and has been administratively continued. Figure
4-15 shows an aerial view of the facility.
¦
1
Wmm

Figure 4-15. Aerial View of Waste Treatment Corporation Facility
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Section 4-Industry Profile
4.4 Other Facilities Treating Oil and Gas Extraction Wastes
Although EPA identified 11 facilities as being potentially in-scope of this study, there are
a number of other facilities in the country that are managing oil and gas extraction wastes. These
facilities may be treating wastewater for discharge under the beneficial reuse provisions of 40
CFR 435 Subpart E, treating wastewater for uses such as irrigation or groundwater recharge,
treating wastewater for reuse in oil and gas operations, or evaporating wastewater as a means of
disposal.
As these facilities are not the focus of this study, EPA did not collect comprehensive
information about these facilities. EPA identified only a few state data systems that are available
on-line that can be used to identify these facilities, and there is limited information available
from these data systems to indicate characteristics of these facilities, such as the types of waste
accepted and whether any process wastewater is discharged. Information collected about these
facilities is included in the CWT facility list (ERG, 2018).
The information collected by EPA indicates that there are a variety of treatment systems
in use across the country at these not-in-scope facilities. While these facilities are likely not
subject to the CWT ELGs, information about these facilities (such as the type, cost and
performance of treatment technologies) is relevant to this study as this information is potentially
transferrable to in-scope facilities. Therefore, Table 4-12 summarizes select facilities that are not
in-scope, but identified as having relevant information on treatment technology cost and
performance. This table is limited to facilities that include technologies for TDS removal.
Table 4-12. Select Oil and Gas Wastewater Treatment Facilities with TDS
Removal Technologies

l.ociilion
l-';icilil> Nolcs
Source
Chevron, San Ardo
Water Reclamation
Facility
San Ardo,
CA
This facility discharges to shallow groundwater recharge basins.
The facility is not permitted to discharge to surface water.
Treatment includes induced gas flotation, walnut shell filtration,
ion exchange, and reverse osmosis.
Webb, 2009
Anticline Disposal
Boulder,
WY
This facility is permitted to discharge produced water under the
beneficial reuse provisions of the oil and gas ELGs (40 CFR 435
Subpart E). Treatment includes anaerobic and aerobic biological
treatment, coagulation, flocculation, sand filters, ultrafiltration,
reverse osmosis and ion exchange.
EPA conducted wastewater sampling at the Anticline Disposal
facility. A discussion of the sampling data collected is included in
Sections 5 and 7 of this report. In addition, the facility completed
a technical and an economic questionnaire obtained under
authority of section 308 of the Clean Water Act.
ERG, 2016b
Freeport-
McMoRan Oil and
Gas Produced
Water Reclamation
Facility
Arroyo
Grande,
CA
This facility is permitted to discharge produced water to Pismo
Creek. Treatment includes microfiltration, reverse osmosis and
ion exchange.
Facility
Permit
(CA0050628)
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4.5 Demand for CWT Services for Managing Oil and Gas Extraction Wastes
As the level of exploration, development, and production activity by oil and gas firms
increases, so does the generation of wastes requiring management. Many factors affect the
amount of wastes generated, the amount requiring disposal and how oil and gas firms decide to
manage those wastes. These factors include:
•	The amount of wastewater that is able to be reused or recycled. Wastewater
can be treated on- or offsite and reused or mixed with freshwater and reused to
drill or fracture new wells. This use may require various levels of treatment,
depending on the quality of the produced water and operational needs in a
particular oil or gas formation (Veil, 2015). Reuse depends on the number of new
wells being drilled. As drilling activity slows, so does the need for recycled
wastewater. Consequently, the need for other management options may increase
in these instances.
•	The amount of wastewater that is injected underground for disposal.
Underground injection for disposal is a common onshore practice, but requires
presence of suitable injection wells. Most Class II wells suitable for oil and gas
wastewater injection are in Texas, California, Oklahoma, and Kansas (U.S. EPA,
undated). Where access to disposal wells is limited, demand for other wastewater
management options (including CWT services) may be higher. In addition,
concerns over induced seismicity may limit injection well capacity in certain
areas, resulting in increased demand for alternative management options.
•	Transportation Costs of Alternatives. A number of economic factors can
influence relative costs of alternative waste and wastewater management services.
For example, trucking is a principal form of transportation of wastewater,
and may account for 65 to 80 percent of total wastewater management costs
(Warlick, 2014). Reuse or recycle of wastewater can be an economical
wastewater management solution, especially if transport is not needed or trucking
distances are limited. Other important considerations include the location of the
wastewater relative to new oil and gas wells, underground injection wells, or
CWT facilities, as proximity might make treatment or disposal a more economical
option. Also, piping wastewater, where permissible, can reduce transportation
costs.
•	Other technical factors. The quantity and quality of produced water depends on
the location of drilling (producing formation), as does the quality and quantity of
water needed for drilling and fracturing (U.S. EPA, 2015).
As the number of producing wells increases, it is likely that the demand for CWT
services will increase as well. This is particularly true in areas where other disposal options or
reuse options are limited. The demand for CWT services depends on both the type and quantity
of producing wells as well as the level of drilling activity. Demand also depends on crude oil and
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
natural gas prices. Between their peak of $105.79 per barrel in June 2014 and April 2016, crude
oil spot prices fell about 60 percent (U.S. DOE, 2016a). In the first quarter of 2014, Henry Hub
gas prices averaged $5.20 per million Btu (mmBtu) before falling as much as 66 percent to $1.76
per mmBtu in April 2016 (U.S. DOE, 2016b). This decrease in oil and gas prices has led to a
drop in drilling activity, with rig counts falling 73 percent between October 2014 and April 2016
(Zborowski, 2016). With fewer opportunities for reuse/recycle, increasing volumes have been
sent to CWT facilities for treatment and discharge services (Litvak, 2016). More recently, crude
oil and Henry Hub prices have recovered slightly but remain below their 2014 peaks. In
November 2017, the Henry Hub price averaged $3.01 per mmBtu, and crude oil spot prices
averaged $56.64 per barrel (U.S. DOE, 2017a; U.S. DOE, 2017b). In addition, drilling activity
has recovered, with the rig count as of the week ending December 8, 2017 at 931, up from the
all-time low of 480 in March 2016 (OGJ, 2017; Zborowski, 2016).
4.6	Competition and Cost Pass-Through Potential in OGE/UOG Activity Basins
As stated above, proximity to oil and gas operations is an important consideration for
firms providing CWT services. Demand and the types of services needed vary across market
areas tied to natural resource basins. Large diversified waste management companies often
compete with smaller regional companies for wastewater volumes.
Generally, CWT facilities are one of several options for wastewater management. Certain
regional and local areas may have constraints on the total number of options available for
wastewater management, and CWT facilities must interact with potential competitors in that
market structure. The market share for CWT facilities differs across these different regional and
local areas giving CWT facilities different abilities to adjust price in relation to prospective
competition, oil and gas operations density and proximity, and regulatory requirements.
4.7	Location and Number of Onshore Oil and Gas Extraction Wells
EPA evaluated the number and location of existing onshore15 oil and gas extraction wells
(excluding CBM) to provide an overview of potential wastewater sources that might be managed
by CWT facilities. For this evaluation, EPA used Drillinginfo's (DI) Desktop® Well File
Database, a nationwide database of all oil and gas wells (ERG, 2016e) to develop a list of all
active oil and gas wells (excluding CBM wells) by basin (as defined by DI Desktop®). This list
was developed in March 2015 and reflects 2014 well counts.
Appendix B presents the total number of active wells within each oil and gas basin (as of
2014), as well as the number of wells by state. Over 1.1 million wells were identified in the DI
Desktop® database. The Permian basin had the largest number of wells with almost 300,000
wells.
15 EPA's analysis did not consider the number and location of offshore or coastal wells.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
Figure 4-16 is a map illustrating the concentration of onshore wells throughout the
country. As can be seen from Figure 4-16, there are several locations where oil and gas wells are
clustered around the U.S. For example, Texas has a large number (nearly 519,000) of oil and gas
wells.
D
Source: Based on 2014 data from Drillinginfo's Desktop® Well File Database, obtained in 2015.
Note: The lowest density locations on the map have up to 0.2 wells per square kilometer, the highest density
locations have more than 3.9 wells per square kilometer.
Figure 4-16. Density of U.S. Onshore Oil and Gas Well Locations
Figure 4-17 shows the estimated total number of active drilling rigs in the United States
between January 2000 and October 2015 and shows drilling trajectory (i.e., directional,
horizontal, vertical) and product type (i.e., crude oil, natural gas). While these counts include rigs
that are drilling for CBM, it paints an overall picture of oil and gas activities in the United States.
The sharp decreases in active drilling rigs observed in 2009 and 2015 are likely attributed to the
sudden drop in natural gas and crude oil prices experienced in those years. (U.S. EPA, 2016f)
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
2,250
Tola I Actwe figs
2,000
^ Y\
"tWwK-	1
1,750
1,500
1.250
1.000
750
500
250
0
\
Year
Source: U.S. EPA, 2016f (Section B.3.1, Figure B-13)
Figure 4-17. Number of Active U.S. Onshore Rigs by Trajectory and Product Type
over Time
4.8 Proximity of Production Wells to CWT Facilities
To understand the potential market for CWT services for oil and gas extraction wastes,
EPA evaluated the number of active oil and gas wells that are located proximally to known CWT
facilities (ERG, 2017c). In conducting this evaluation, EPA evaluated proximity of all wells to
the 11 in-scope facilities and performed a second analysis of the proximity of all wells to all Part
437 facilities in the CWT facility list. It is important to acknowledge that this analysis is limited
because EPA has incomplete information on existing indirect discharging CWT facilities, as
these facilities are not required to report to EPA. However, this evaluation does provide a useful
screening to evaluate the number of wells that could potentially utilize CWT facilities for
management of their wastes and identify areas that are currently not well served by CWT
facilities.
For this analysis, EPA compared the CWT facility lists (in-scope and all Part 437) to a
list of active oil and gas wells obtained from the DI Desktop® Well File Database. The total
count of wells is based on the "Active Oil and Gas Wells" table of DI Desktop database, refined
to include only wells with "Property Type" COM (completion), LEASE, and WELL that have
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 4-Industry Profile
non-zero latitude and longitude values. EPA assumed that a separation of 100 miles or less
between a well and a CWT facility constitutes a reasonable estimate of a generally economical
transport distance for when a CWT facility could potentially be a viable alternative to treat
wastes from a given well.
With respect to the 11 in-scope facilities, EPA estimates that approximately 148,500
active wells (or 13 percent of the total number of wells) are located within 100 miles of at least
one in-scope facility (see Table 4-13). Of the over 1.1 million active wells considered in this
analysis on the national scale, EPA estimates that approximately 280,000 (or 25 percent of the
total number of wells) are located within 100 miles of at least one part 437 CWT facility. Results
by state are summarized in Table 4-13 (ERG, 2017c).
Table 4-13. Counts of Total Oil and Gas Extraction Wells and Oil and Gas Extraction
Wells within 100 Miles of a CWT Facility, by State
Slsile
Tolsil Well
(on III
Wells \\ illiin 100 Miles
of si I'sii't 4J"7 CWT lsieilil\
Wells Williin 100 Miles
of sin In-Scope CW T l-'sieilil>
Con ill
Pereenlsiiie
( (III III
Pereenlsiiie
AL
6,458
548
8.49%
0
0.00%
AK
1,825
0
0.00%
0
0.00%
AZ
25
0
0.00%
0
0.00%
AR
10,077
8,906
88.4%
5,638
56.0%
CA
23,187
5,327
23.0%
0
0.00%
CO
39,884
0
0.00%
0
0.00%
FL
60
60
100%
0
0.00%
KS
101,541
5,608
5.52%
0
0.00%
KY
14,505
13,798
95.1%
0
0.00%
LA
35,677
3,220
9.03%
0
0.00%
MD
3
3
100%
3
100%
MI
11,904
798
6.70%
0
0.00%
MS
3,361
1,754
52.2%
0
0.00%
MO
7
0
0.00%
0
0.00%
MT
9,839
0
0.00%
0
0.00%
NE
1,764
66
3.74%
0
0.00%
NV
60
0
0.00%
0
0.00%
NM
44,319
0
0.00%
0
0.00%
NY
8,979
8,978
99.9%
8,957
99.8%
ND
11,776
0
0.00%
0
0.00%
OH
39,170
37,999
97.0%
35,751
91.3%
OK
59,553
27,123
45.5%
0
0.00%
OR
15
14
93.3%
0
0.00%
PA
65,609
65,609
100%
65,609
100%
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Section 4-Industry Profile
Table 4-13. Counts of Total Oil and Gas Extraction Wells and Oil and Gas Extraction
Wells within 100 Miles of a CWT Facility, by State
Slalc
Total Well
(on III
Wells \\ illiin 100 Miles
of a Pai l 4J"7 CWT lacili(\
Wells Williin 100 Miles
ol'an In-Scope CWT l';icili(\
(on III
Pei veil I a lie
(on 111
Percentage
SD
220
0
0.00%
0
0.00%
TN
1,742
525
30.1%
0
0.00%
TX
518,939
54,494
10.5%
0
0.00%
UT
12,450
0
0.00%
0
0.00%
VA
6,195
6,195
100%
0
0.00%
WV
48,365
38,983
80.6%
32,552
67.3%
WY
31,239
0
0.00%
0
0.00%
Total
1,108,748
280,008
25.3%
148,510
13.4%
As seen in the table, many states appear underserved in terms of their access to CWT
facilities, but some of these states might not have a need for CWT facilities, depending on other
disposal options. For example, Texas has almost 519,000 oil and gas extraction wells, but only
about 10 percent of those wells are within 100 miles of a CWT facility. However, Texas has over
32,000 active disposal wells (Railroad Commission of Texas, 2014). This availability of disposal
wells reduces the demand for waste management at CWT facilities. In contrast, all of
Pennsylvania's oil and gas extraction wells are within 100 miles of a CWT facility. This is true
for the subset of in-scope facilities as well. Since Pennsylvania has few brine disposal wells
(only eight brine disposal wells were permitted in Pennsylvania at the time of the study
(McCurdy, 2015)), CWT services may be in higher demand in that state.
4.9 References
1.	Drillinginfo, Inc. 2015. DI Desktop® March 2015 Download CBI. DCN
CWT00368
2.	ERG. 2016a. CBI Aquatech Site Visit Report. DCN CWT00159
3.	ERG 2016b. CBI Enclosure 7 NGL Anticline Site Visit Report. DCN
CWT00152
4.	ERG. 2016d. Fairmont Brine Site Visit Report. DCN CWT00116
5.	ERG. 2016e. Proposed Approach for Data Analysis and Quality Assurance Using
Drillinginfo's (DI) Desktop® Well File Database. DCN CWT00367
6.	ERG. 2017a. Centralized Waste Treatment Facility List Comment from EPA
Regions Memorandum. DCN CWT00256
7.	ERG. 2017b. Sanitized Eureka Site Visit Report. DCN CWT00308
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Section 4-Industry Profile
8.	ERG. 2017c. Centralized Waste Treatment Facilities and Oil and Gas Wells
Locational Analysis. DCN CWT00366
9.	ERG. 2018. Centralized Waste Treatment Facility List Approach Memo. DCN
CWT00215
10.	Eureka Resources. 2016. Web. Accessed 28 April 2016. Available electronically
at: http://eureka-resources.com/about-us/. DCN CWT00174
11.	McCurdy, Rick. Underground Injection Wells for Produced Water Disposal.
Chesapeake Energy Corp. DCN CWT00146
12.	National Energy Technology Laboratory (NETL). 2011. A Comparative Study of
the Mississippian Barnett Shale, Fort Worth Baskin, and Devonian Marcellus
Shale, Appalachian Basin. NETL-2011/1478. DCN CWT00369
13.	PA DEP. 2004. MAX Environmental Technologies Inc NPDES Permit.
PA0027715. DCN CWT00305
14.	PA DEP. 2008a. Fluid Recovery Services - Franklin Facility NPDES Permit.
PA0101508. DCN CWT00370
15.	PA DEP. 2008b. Josephine Treatment Facility NPDES Permit. PA0095273. DCN
CWT00371
16.	PA DEP. 2013. Creekside Treatment facility NPDES Permit. PA0095443DCN
CWT00372
17.	Railroad Commission of Texas. 2014. Commercial Recycling & Surface Disposal
Facilities. DCN CWT00092
18.	Roddy, Kelly. 2016. Waste Treatment Corporation Questions. (June 3). DCN
CWT00373
19.	U.S. DOE. 2014. The Water-Energy Nexus: Challenges and Opportunities. DCN
CWT00294
20.	U.S. EPA. 2000. Development Document for the CWT Point Source Category.
EPA 821-R-00-020. Available online at:
http://water.epa.gov/scitech/wastetech/guide/cwt/develop index.cfm. DCN
CWT00324
21.	U.S. EPA. 2001. Economic Analysis of Final Effluent Limitations Guidelines and
Standards for the Centralized Waste Treatment Industry. EPA-821-R-00-024.
DCN CWT00384
22.	U.S. EPA. 2010. Regulatory Flexibility Act Section 610 Review of Effluent
Limitations Guidelines and Standards for the Centralized Waste Treatment
Industry. DCN CWT00222
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Section 4-Industry Profile
23.	U.S. EPA. 2012. Site Visit Report Eureka Resources, LLC Marcellus Shale Gas
Operations. (February 25). DCN CWT00036
24.	U.S. EPA. 2014. Site Visit Report for Nuverra Appalachian Water Services,
Masontown, PA, Centralized Waste Treatment. (January 25). DCN CWT00062
25.	U.S. EPA. 2015a. Sanitized Site Visit Report for McCutcheon Enterprises Inc.
Apollo, PA - Centralized Waste Treatment. DCN CWT00307
26.	U.S. EPA. 2015b. Site Visit Report for Patriot Water Treatment LLC, Warren,
OH, Centralized Waste Treatment Facility. (March 3). DCN CWT00064
27.	U.S. EPA. 2015c. Site Visit Report for Reserved Environmental Services, LLC,
Mt. Pleasant, PA, Centralized Waste Treatment. (February 10). DCN CWT00063
28.	U.S. EPA. 2015d. Site Visit Report Seneca Resources Corporation, Covington,
PA. (February 4). DCN CWT00054
29.	U.S. EPA. 2015e. Site Visit Report: Southwestern Energy Fayetteville Shale Gas
Operations. Sanitized. DCN CWT00266
30.	U.S. EPA. 2016f. Technical Development Document for Effluent Limitations
Guidelines and Standards for Oil and Gas Extraction. June 2016.:
https://www.epa.gov/sites/production/files/2015-
06/documents/uog proposal tdd 03-2015.pdf. DCN CWT00019
31.	U.S. EPA. 2017a. Envirofacts Database, https://www3.epa.gov/enviro/. DCN
CWT00263
32.	U.S. EPA. 2017b. Sanitized Meeting Report Altela, Inc. and Clarion Altela
Environmental Services (CAES) Clarion, PA. DCN CWT00310
33.	United States Census Bureau (U.S. Census). 2016. North American Industry
Classification System Search. Available electronically at:
http://www.census.gov/cgi-bin/sssd/naics/naicsrch. DCN CWT00217
34.	Webb, Charles. 2009. Desalination of Oilfield-Produced Water at the San Ardo
Water Reclamation Facility, CA. Society of Petroleum Engineers. SPE121520.
DCN CWT00280
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Section 5-Wastewater Characterization and Management
5. Wastewater Characterization and Management
To understand whether the current CWT ELGs are adequately managing wastewater
discharges from CWT facilities accepting oil and gas extraction wastes, EPA collected and
evaluated data regarding oil and gas wastewater characteristics, as well as data characterizing
discharges from CWT facilities accepting oil and gas extraction wastes. These data are primarily
taken from publicly available sources. EPA also conducted sampling at two facilities that
discharge treated oil and gas extraction wastewater. Section 5.1 presents data broadly
characterizing oil and gas extraction wastes and wastewater. Section 5.2 presents data on
wastewater received at and discharged from in-scope CWT facilities, as well as data collected
during EPA's sampling activities. Section 5.3 presents information about the volumes of
wastewater generated by the oil and gas extraction industry and how that wastewater is currently
managed.
5.1 Types of Oil and Gas Extraction Waste and Wastewater Characteristics
The exploration, development and production of oil and gas reserves vary markedly from
region to region (U.S. Congress, 1992). There are a number of solid and liquid waste materials
generated during oil and gas exploration, extraction and production, and these waste materials
may be managed by CWT facilities. The nature and characteristics and quantity of the wastes
generated depend upon a number of factors, such as the type of drilling, the characteristics of the
formation, the depth of the well and the type and quantity of chemical additives used during
drilling, production and well maintenance activities.
During drilling activities conducted for exploratory purposes and for production wells,
solid and slurry materials such as drill cuttings and drilling muds are generated. These materials
contain rock removed by the drill bit as well as water or oil-based fluids and additives, such as
barite, that are pumped down the drilling pipe for purposes such as lubrication and to counteract
the pressure contained in the formation.
Many wells generate large volumes of produced water, which is natural water contained
in the oil or gas-bearing rock formations. Produced water can be very saline depending on the
formation. In addition, depending on the source rock of the formation and the hydrocarbons
present, produced water may contain pollutants such as TENORM16 and benzene. Other
constituents of produced water include chemicals added for well treatment, such as corrosion
inhibitors (U.S. Congress, 1992).
16 Technologically enhanced Naturally Occurring Radioactive material, or TENORM, is defined by EPA as
"Naturally occurring radioactive materials that have been concentrated or exposed to the accessible environment as a
result of human activities such as manufacturing, mineral extraction, or water processing."
"Technologically enhanced" means that the radiological, physical, and chemical properties of the radioactive
material have been concentrated or further altered by having been processed, or beneficiated, or disturbed in a way
that increases the potential for human and/or environmental exposures.
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Section 5-Wastewater Characterization and Management
In wells that are hydraulically fractured, fracturing fluid - typically consisting of water, a
number of chemical additives and a proppant (such as sand) - is pumped down the well bore
under pressure to create and hold open fractures in the target formation that allow for the flow of
oil and gas. Some fracturing fluid, as well as water from the formation, returns to the surface as
flow-back.
Chemicals used in well servicing and maintenance, such as work-over fluids, can be
contained in wastewaters that are generated by wells. Other waste sources include well
completion, treatment and stimulation fluids; sediment, water and other tank bottoms; oily
debris; contaminated soils; produced sands; and residuals from wastewater treatment systems
located at the well site.
Once oil and gas enter the distribution system, wastes such as compressor station water
are generated. Wastes generated from these mid-stream operations may also be managed at CWT
facilities. In addition, downstream operations such as refining, storage and oil recycling may
generate a number of wastes that may be transferred to CWT facilities for management.
However, these wastes are not the focus of this study. The existing CWT regulations contain an
oily wastes subcategory that are applicable to these downstream wastes.
The amount of characterization data available in the literature varies by waste and
wastewater type, as well as location. For some waste types and for some basins, little data are
available. In addition, wastes received at CWT facilities typically originate from many different
well locations that are in various stages of development. As a result, wastes may contain
mixtures of several different waste streams from various sources. For purposes of this study,
EPA is most interested in drilling fluid wastes, fracturing fluid wastes and produced waters as
these are the primary waste materials (by volume) reported as being accepted at CWT facilities.
5.1.1 Drilling Wastes
Drilling activities generate a number of waste materials, such as drill cuttings and spent
drilling fluids. The solid materials are typically separated from the liquid materials using
separation technologies such as shakers and centrifuges. Some of the muds may remain on the
cuttings, depending on the degree of separation accomplished. These solid materials are typically
treated or solidified/stabilized and then buried on-site, sent off-site to landfills, or diverted to
other uses. These materials may also be managed by CWT facilities. Liquid wastes separated
from the cuttings and spent drilling fluids may also be solidified/stabilized, or diverted to
treatment either on-site of off-site. Off-site management options also include transfer to CWT
facilities.
There are two main types of drilling fluids: water-based and non-aqueous systems.
Water-based fluids consist of water (either fresh or brackish) with various additives to achieve
the desired characteristics. Non-aqueous systems use a non-water soluble base fluid with water
or brine dispersed within the base fluid. Non-aqueous drilling fluids include diesel, mineral oils,
and synthetic-based fluids. There are a variety of materials added to drilling fluids. Materials
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Section 5-Wastewater Characterization and Management
such as barite, clay, salts, polymers, diesel and synthetic oils, alkalines, surfactants, organic
polymers, and droplets of emulsified oil are common constituents of drilling fluids (National
Petroleum Council, 2011; Caen and Darley, 2011). Many of these materials would be expected
to be found in wastewaters generated from drilling activities. Drilling fluids may also contain
priority pollutants, such as polynuclear aromatic hydrocarbons.
EPA has identified data describing drilling wastewater and fracturing fluid
characteristics. These data include technical evaluations of the impact of oil and gas extraction
wastewater pollutants on POTW unit processes completed in response to Administrative Orders
issued to a number of POTWs by PA DEP (Rost, 2010a and Rost, 2010b). All the data identified
by EPA was specific to the Marcellus Shale. It should be noted that drilling wastewater
commonly contains recycled produced water that has been minimally treated to make it suitable
for re-use. As a result, drilling wastewater from wells using recycled water will differ from other
wells where fresh water is utilized to formulate the drilling fluids.
Huffmyer (2013) examines the various techniques of drilling fluid waste treatment,
including treatment of well head fluid, drill cuttings, drilling mud, and wastewater, and provides
examples of reuse potential ranging from hydrocarbon use for energy recovery to drill cuttings
incorporated into road base material. The author also provides a brief analysis of an example
facility in the Marcellus shale region to highlight common influent contaminants and reuse
applications. Typical drilling waste characteristics described include highly variable levels of
strontium (10 - 1,400 mg/L), sulfate (0 - 1,500 mg/L), barium (25 - 2,000 mg/L), TSS (200 -
2,000 mg/L), and TDS (3,000 - 80,000 mg/L).
The PA DEP TENORM Study (PA DEP, 2016) conducted radiological surveys to assess
the potential for exposure to TENORM by the general public and people working with wastes
from O&G exploration. The study encompassed well sites, wastewater treatment plants, landfills,
gas distribution and end use, and brine-treated roads and included sampling of solids, liquids,
natural gas, air, and surface radioactivity. The study found notable activity in many samples of
drilling fluids (Table 5-1) and fracturing fluids (Table 5-2).
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Section 5-Wastewater Characterization and Management
Table 5-1. Ra-226, Ra-228, K-40, Gross Alpha and Gross Beta Activity in Drilling
Fluids (PA DEP, 2016)
Piinimolor
Minimum
Miixiniiiin
Mi'riiiin
Number of
Samples
Number of Non-
Deleels or /.cm
\ ;ilues
Gross Alpha (pCi/L)
ND
3,820
2,700
5
3
Gross Beta (pCi/L)
ND
3,940
2,600
5
3
Radium 226 (pCi/L)
1,510
4,940
2,010
5
0
Radium 228 (pCi/L)
162
466
216
5
0
Potassium 40 (pCi/L)
420
11,400
5,220
5
0
ND = Non-Detect.
Table 5-2. Ra-226, Ra-228, K-40, Gross Alpha and Gross Beta Activity in Fracturing
Fluids (PA DEP, 2016)
Piiriimclcr
Minimum
M;i\iiiin in
Mori i;in
Nilmher ol
Siimplos
NiiiiiIht ol' Non-
1 KM eels or Zero
\ iilues
Gross Alpha (pCi/L)
<1.39
54,100
5,020
11
0
Gross Beta (pCi/L)
<1.63
14,900
1,010
11
0
Radium 226 (pCi/L)
64
21,000
2,160
11
0
Radium 228 (pCi/L)
<9
1,640
218
11
0
Potassium 40 (pCi/L)
<21
456
283
11
0
Rost, 2010a and Rost 2010b are letters from the City of McKeesport to PA DEP in
response to PA DEP's Administrative Order on October 23, 2008, and each present analytical
results from samples of wastes, including drilling waste. The McKeesport POTW analytical data
was collected because the facility accepted wastewater from oil and gas extraction operations.
Select parameters from samples of drilling wastes (identified as "drill water" and "pit water" in
the references) are summarized in Table 5-3. These data show high dissolved solids, as well as
varying concentrations of other pollutants such as barium, strontium and sulfate. Samples also
exhibited radioactivity measured as gross alpha and gross beta.
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Section 5-Wastewater Characterization and Management
Table 5-3. Concentrations of Select Pollutants in Drilling Wastewater (Rost, 2010a
and 2010b)
Soiiito
Pni'iiiiKMor
Minimum
M;i\iiiin in
I nils
NiiiiiIh'I' of
S;i in pies

Aluminum
1.7
6,916
mg/L
7

Ammonia
0.98
34.98
Mg/L
7

Barium
2.55
471
mg/L
7

BODs
79.8
1,119
Mg/L
7

Chloride
158
23,469
mg/L
7
Rost, 2010a
COD
153
9,270
mg/L
7
Gross Alpha
16.6
3,022
pCi/L
5

Gross Beta
32.49
4,172
pCi/L
5

Sodium
167
15,726
mg/L
7

Strontium
1.8
65
mg/L
7

Sulfate
ND
525
mg/L
7

TDS
557
39,500
mg/L
7
ND: Non-Detect.
U.S. EPA, 2013 is the supporting technical document for the Oil and Gas Exploration and
Production Waste Exemption. This source includes analyses of drilling fluid wastewater in
Pennsylvania in 2009. Drilling fluid wastewater contained high levels of salts, as well as high
levels of strontium and barium (see Table 5-4 for example data).
Table 5-4. Concentrations of Select Pollutants in Drilling Wastewater (U.S. EPA, 2013)
Piiriimolor
Value (inii/l.)
Barium
20.9
Benzene
ND
Bromide
205
Chloride
17,500
COD
947
Sodium
12,200
Strontium
20.8
Sulfate
663
TDS
36,100
Toluene
ND
TSS
168
ND: Non-Detect.
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Section 5-Wastewater Characterization and Management
Ziemkiewicz, 2013 conducted a Phase 1 study titled Assessing Environmental Impacts of
Horizontal Gas Well Drilling Operations, endeavoring to identify any potential health effects of
oil and gas exploration in the Marcellus Shale Formation on nearby communities. This report
contains a literature review of drilling waste as well as a liquid waste stream characterization.
The study characterized drilling mud, cuttings, and other fluids, identifying high levels of
sodium, potassium and chloride. Results of analysis of drilling wastewater samples for select
parameters are shown in Table 5-5. The reference provided one value for each parameter, which
was the average of four samples. Note that the samples taken during this study were collected
prior to the well reaching the Marcellus Shale formation.
Table 5-5. Concentrations of Select Pollutants in Drilling Wastewater
PiimnuMor
Value
I nils
Aluminum
1,208
mg/L
Barium
12.8
mg/L
Benzene
40.3
Hg/L
Bromide
22.5
mg/L
Chloride
14,640
mg/L
Ethylbenzene
9.55
Hg/L
Potassium
8,792
mg/L
Sodium
2,859
mg/L
Strontium
40.2
mg/L
Sulfate
1,568
mg/L
TDS
34,550
mg/L
Toluene
80.4
Hg/L
TSS
47,300
mg/L
Xylene (total m, p and o)
109.7
Hg/L
Source: (Ziemkiewicz, 2013)
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Section 5-Wastewater Characterization and Management
5.1.2 Produced Water
Produced water is the largest wastewater source by
volume generated during oil and gas extraction17. Produced water
is the fluid (often called brine) brought up from the hydrocarbon-
bearing strata during the extraction of oil and gas and includes,
where present, formation water, injection water, and any
chemicals added downhole or during drilling, production or
maintenance processes. Naturally occurring constituents include
bromide, magnesium, and radioactive materials (U.S. EPA,
2016b). Materials added down-hole include hydraulic fracturing
chemicals, well stimulation chemicals and well maintenance
chemicals.
The purpose, quantity and characteristics of materials utilized during well development,
stimulation and maintenance are diverse. For example, EPA identified some 692 unique
ingredients reported for additives, base fluids and proppants contained in more than 39,000
FracFocus18 disclosures provided by the Groundwater Protection Council (GWPC) (U.S. EPA,
2015a).
Table 5-6 describes the types and purposes of additives used in hydraulic fracturing, well
development and well maintenance activities.
EPA defines produced water
at 40 CFR 435.1 l(bb) 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."
17	Coalbed methane extraction often generates produced water as a by-product of the gas extraction process. EPA is
not aware of any Part 437 CWT facilities that are managing large quantities of CBM produced water. Rather,
facilities managing CBM wastewater are permitted for discharge using best professional judgement. As a result,
EPA does not discuss CBM wastewater further in this report. See U.S. EPA, 2010 for additional information on
CBM wastewaters.
18	FracFocus is a publicly accessible website managed by GWPC and the Interstate Oil and Gas Compact
Commission (IOGCC) where oil and gas production well operations can disclose information about ingredients used
in hydraulic fracturing fluids at individual wells.
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Section 5-Wastewater Characterization and Management
Table 5-6. Type and Purpose of Additives used in Well Development, Stimulation
and Maintenance
("sili'Sion of
A(l(lili\c;>
I-Aiimplc
(oil si iliienl s1'
Purpose
Acid
1 Isdi'ochloi'ic acid,
muriatic acid
kcmo\ cs cemeiil and drilling lluid from casing perforations prior lo
fracturing fluid injection.
Biocide
Glutaraldehyde;
2,2-dibromo-3-
nitrilopropionamide
Inhibits growth of organisms that could produce gases (particularly
hydrogen sulfide) that could contaminate methane gas; prevents the
growth of bacteria that can reduce the ability of the fluid to carry
proppant into the fractures by breaking down the gelling agent.
Breaker
Peroxydisulfate salts
Reduces the viscosity of the fluid by breaking down the gelling agents to
release proppant into fractures and enhance the recovery of the fracturing
fluid.
Clay
Stabilizer
Potassium chloride
Creates a brine carrier fluid that prohibits fluid interaction (e.g., swelling)
with formation clays; interaction between fracturing fluid and formation
clays could block pore spaces and reduce permeability.
Corrosion
Inhibitor
Ammonium bisulfite
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;
sodium hydroxide
Adjusts and controls the pH of the fluid to maximize the effectiveness of
other additives such as crosslinkers.
Proppant
Quartz;
sand;
silica
Used to hold open the hydraulic fractures, allowing the natural gas or
crude oil to flow to the production well.
Scale
Inhibitor
methylene phosphonic
acid, polyacrylate
Prevents the precipitation of carbonate and sulfate scales (e.g., calcium
carbonate, calcium sulfate, barium sulfate) in pipes and in the formation.
Surfactant
Isopropanol;
naphthalene
Reduces the surface tension of the fracturing fluids to improve fluid
recovery from the well after fracture is completed.
Sources: U.S. EPA, 2015; Acharya, 2011; FracFocus, 2014; CCST, 2014; ExxonMobil Corporation, 2014.
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.
Data describing produced water sometimes differentiates between the initial flowback
period and long-term produced water. Generally, produced water generated in the initial time
period after hydraulic fracturing would be expected to contain a higher proportion of additives,
while subsequent produced water would be expected to more closely approximate the formation
water. For purposes of this study, EPA is generally not concerned with differentiation of
wastewater characteristics between the initial flowback period and longer-term produced water.
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Section 5-Wastewater Characterization and Management
This is because a typical CWT facility would be expected to receive wastewater from a variety of
wells in various stages of exploration and production. Wastewater from various wells and from
various producers are typically mixed prior to treatment.
Table 5-7 lists data sources EPA identified that contain data on produced water. For each
reference, a brief description of the content of each data source is provided. Some of these
sources present original data, and some also present data from other sources. References that
contain data from other sources are indicated.
Table 5-7. Identified Data Sources for Produced Water Characteristics
Reference
( onicnl
\ch;irya, 2011"
Developed a cosi-el leeli\e wnler recovers process lor low I I)S produced water from llie
Woodford formation of Oklahoma. Details in the study include fracturing fluid composition.
Benko, 2008a
Literature review of approximately 33,000 data records, including data housed by USGS. Noted
highly variable levels of TDS and identified common pollutants present in produced water in the
western U.S.
Boschee, 2014a
Reports options for reuse and recycling of produced water. Reports average TDS by producing
region.
Bruff, 2011
Performed pre- and post-treatment water quality analysis of produced water in Pennsylvania.
Reported significant radium and TDS in produced water before treatment.
Campbell, 2012
Used isotope investigation to determine characteristics of produced water TDS in northeastern
and southwestern Pennsylvania.
Coleman, 2011
Reviewed analytical results for produced water from four shale plays. Reports that produced
water characteristics are highly variable within and between formations.
Dunkel, 2012
Discusses options for improved water management in Texas. Details of study include analytical
results of produced water from the Permian basin.
Gradient, 2009
Conducted exposure analysis of produced water waste to microbial POTW treatment processes.
Reported that no disruption of biological treatment was expected to occur.
Haluszcsak,
2012a
Conducted chemical analysis of late-stage produced water from Marcellus wells in Pennsylvania.
Determined high concentrations of TDS, chloride, bromide, sodium, calcium, barium, radium-
226 and radium-228.
Hansen et al,
2013a
Review of WVDEP, PADEP, and FracFocus Chemical Database Download records for
Marcellus gas wells, focusing on water use and reuse. Also includes a discussion of waste
generation in Pennsylvania.
Haiju, 2009
Discusses water quality of Bakken produced water (North Dakota, Montana), noting salinity as
high as 200,000 mg/L.
Havics, 2011
Study of fracturing fluid composition in Colorado. Noted high levels of salts, and detected
benzene and low levels of radioactivity.
Hayes et al.,
2012
Report characterizing flowback waters from 19 sites in Pennsylvania and West Virginia, and 5
sites in northern Texas. Noted high concentrations of TDS, COD, and high hardness in
Pennsylvania/ West Virginia; noted lower levels of TDS and COD in Texas.
Hayes, 2011;
Hayes et al.,
2012
Presents characterization of flowback waters and produced waters West Virginia, Pennsylvania
and Texas.
Horn, 2009
Describes a technology for mobile treatment of produced water for reuse. Notes that the process
would be ineffective at high chloride levels.
Johnson &
Harry, 2014
Produced water reuse feasibility study in the Uinta region. Noted relatively low levels of TDS in
untreated water.
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Section 5-Wastewater Characterization and Management
Table 5-7. Identified Data Sources for Produced Water Characteristics
Reference
( onienl
Kimball. 2012
Provides an analysis of produced water treatment and reuse systems. Includes review of TDS
levels across 10 regions of the U.S.
Maguire-Boyle
& Barron, 2014
Study reporting organic compounds found in produced water. Determined that shale produced
water contains fewer organic constituents than CBM produced water.
Mantell, 2011
Technical workshop for hydraulic fracturing water management. Highlights variations in
produced water quality between shale plays.
Mazoch, 2012
Study of Fayetteville shale region in Arkansas and Oklahoma. Notes low concentrations of TDS
and metals.
McElreath,
2011
Comparison of western and eastern U.S. fracturing fluid composition. Noted no significant
difference in conventional parameters, but some higher gross beta in the eastern U.S.
NYSDEC, 1999
Presents radioactivity analysis with 49 data points in New York for oil and gas waste.
NYSDEC, 2009
Draft proposed regulatory action regarding Marcellus shale, with full scale environmental review
for New York. Includes produced water characteristics based on samples from West Virginia and
Pennsylvania.
NYDEC, 2011
Revision of NYSDEC, 2009. Includes produced water characteristics, noted as high in TDS,
surfactants, and metals.
ORD, 2014
Hydraulic fracturing data public record to support EPA ORD's Hydraulic Fracturing Study.
PADEP, 2016
TENORM evaluated for exposure to workers and public, primarily in northwestern
Pennsylvania. Noted high levels of radium from unconventional wells and low levels of radium
from conventional wells.
Palacios, 2012a
Review of produced water quality testing in south Texas. Contains comparison of produced
water and groundwater TDS content (produced water being on average 86,000 mg/L higher in
concentration).
Rimassa, 2009
Laboratory produced water analysis from samples in northeast Texas and northwest Colorado.
Result for Texas showed much higher TDS (147,000 mg/L) than Colorado (33,100 mg/L).
Rowan, 201 la
Study of radium content in produced water in Pennsylvania and New York. Indicates wide range
of radium content within Marcellus produced waters. Also indicated a correlation between TDS
and radium content in Pennsylvania.
Silva et al.,
2013
Reviews pretreatment targets for barium and radium for produced water in Pennsylvania. Notes
high levels of TDS, and higher levels of radium and barium in central and eastern Pennsylvania.
Slutz, 2012
Notes strategies for produced water management. Contains characterization data for flowback
from several shale plays.
Stepan, 2010
Outlines treatment and reuse opportunities in Bakken region (northwest U.S.). Details flow and
concentration of pollutants over time.
Tipton, 2012
Outlines Oklahoma and Arkansas produced water reuse. Notes moderate to high TDS.
U.S. DOE, 2013
Report from U.S. DOE on produced water management options. Notes relative levels of salinity.
U.S. EPA, 1976
Supporting document for oil and gas effluent guidelines rulemaking effort. Noted high TDS for 7
regions in California, Texas, Louisiana, and Wyoming.
USGS, 2014a
USGS Produced Waters Geochemical Database, updated version of 2002 USGS Produced
Waters Database. Draws from 25 databases, publications, or reports.
Volz, 201 la
Produced water characterization in western Pennsylvania. Noted high levels of barium, benzene,
and high TDS.
Warner, 201311
Study of impact of produced water disposal on water quality in western Pennsylvania. Noted
substantially higher levels of radium 226 in sediments at point of discharge than at upstream
sediments.
Williams. 201 la
Reviewed measurements of radionuclides of produced waters in the Marcellus region. Noted
increasing TDS, chlorides, barium, and radioisotope concentrations as flowback volumes
increased.
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Section 5-Wastewater Characterization and Management
Table 5-7. Identified Data Sources for Produced Water Characteristics
Reference
( onicnl
Williams,
unknown3
This presentation describes the geology, development, and impact on water-resources of
hydraulic fracturing in the Marcellus shale.
WY OGCC,
2015
Database of well analytical test results in Wyoming. Five produced water results above 100,000
mg/L TDS, and 51 results less than 100,000 mg/L TDS.
Yoxtheimer,
2012
Presentation on produced water treatment and reuse strategies. Notes water quality results for
Bakken, Eagle Ford, Permian, and Utica formations.
Ziemkiewicz,
2013
Final Report for West Virginia DEP on the water quality literature review and field monitoring
of active shale gas wells. Includes results of the literature review, water and waste stream
monitoring including the plan, data analysis, and results.
a Reference presents data from another source.
EPA selected a subset of these sources to describe in further detail and summarize the
produced water characteristics These sources were selected because of their data quality and
quantity and their ability to represent a range of oil and gas produced water characteristics and
constituents across the countries. More detailed summaries of these reports are presented below.
The USGS National Produced Waters Geochemical Database (USGS database) contains
geochemical data for produced water and other deep formation waters from wells in the United
States. The USGS created the database by compiling data from existing databases, publications,
and reports; removing duplicates; and performing quality control procedures (USGS, 2014). The
database is periodically updated (Version 2.1 includes data for almost 60,000 wells in 36 states19,
sampled between 1900 and 2012). Data for select parameters from Version 2.2 of the USGS,
database is shown in Figure 5-1 as box and whisker plots, showing the minimum (excluding non-
detect values), 25th percentile, median, 75th percentile and maximum values for each parameter20.
For each constituent, the total number of samples as well as the number of samples with values
greater than the detection limit are shown in parentheses (for example, there were 18,387
samples for barium, 11,369 of which were greater than the detection limit). As illustrated in
Figure 5-1, the concentration of these select parameters varies greatly across the country. An
example is TDS, which can vary significantly by basin. Figure 5-2 shows the box and whisker
plots with TDS concentration data for the 10 basins with the greatest number of samples
contained in Version 2.2 of the USGS database (TDS values below 10 mg/L are not shown in
this plot). As illustrated by these data, TDS concentrations for samples contained in the database
vary greatly, both within a specific basin and across different basins.
19	States include: Alabama, Alaska, Arizona, Arkansas, California, Colorado, Florida, Georgia, Idaho, Illinois,
Indiana, Iowa, Kansas, Kentucky, Louisiana, Maryland, Michigan, Mississippi, Missouri, Montana, Nebraska,
Nevada, New Mexico, New York, North Dakota, Ohio, Oklahoma, Oregon, Pennsylvania, South Dakota, Texas,
Utah, Virginia, Washington, West Virginia, and Wyoming.
20	These plots were generated by extracting all data from the database for conventional hydrocarbon, shale gas, tight
gas and tight oil well types. Zero values and entries listed as unknown were excluded from the counts and statistics.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-11

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Section 5-Wastewater Characterization and Management
Produced Water Constituent Concentrations
1000000
100000
10000
1000
100
10
Isb
E
0,01
0.001
Boron
{2,419)
Bromide
(5,283)
[11,369] [2,1.80] [4,875]
HEM
(111)
[92]
MBAS Ra226 + 228 Strontium TOC Sulfate IDS
(97) (190) (7,615) (375) (100,066) (96,427)
[89]	[184] [6,969] [368] [93,056] [96,421]
Figure 5-1. Oil and Gas Produced Water Constituent Concentration Data (USGS National
Produced Waters Geochemical Database, V2.2)
Produced Water IDS Concentrations (mg/L) by Basin
100

10000
1000
100

Big Horn Central Chautauqua Green River Gulf Coast Permian Powder River
I'niift Ptatform
:>n Wind River
Figure 5-2. Oil and Gas Produced Water TDS Concentration by Basin (USGS National
Produced Waters Geochemical Database, V2.2)
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-12

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Section 5-Wastewater Characterization and Management
It should be noted that the USGS database has limitations. The earliest reported data
included in the database are from the early 1900s. Analytical methods have evolved since that
time, and the older data may not be as accurate or directly comparable to the newer data. In
addition, not all of the records have a sample collection date. Also, analytical methods are not
provided for all reported values.
Another data source (ORD, 2014) included produced water sampling results for
Hogback, Conoco Phillips, Williams Production, and Clayton Williams Energy operators from
2004 to 2010. Data was collected for the U.S. EPA Office of Research and Development's
general solicitation of data related to hydraulic fracturing. The public docket for that effort
contains all related data and documents (EPA-HQ-ORD-2010-0674). The non-CBI data used in
this report contains over 4,500 data points, with 2,690 of those reported results above detection
limits. An average of 34,506 mg/L of TDS was recorded. Data for other select pollutants, such as
radium, bromide, barium, and strontium, are shown in Table 5-8.
Table 5-8. Concentrations of Select Pollutants in Produced Water (ORD, 2014)
Piinimolor
Minimum
Miiximiim
I nils
Number nl'
Siiinpk's
Nil in her of
/.cm \ iiliK's-
Number of
Non-l)e(ee(s
Barium
0.963
787
mg/L
34
9
0
Benzene
0.0015
1.7
mg/L
9
0
0
BOD
244
2,120
mg/L
8
0
0
Bromide
270
798
mg/L
8
0
0
Chloride
698
141,200
mg/L
152
0
0
COD
1,360
3,070
mg/L
8
0
0
Ethylbenzene
ND
0.035
mg/L
8
0
6
Potassium
0
2,190
mg/L
28
5
0
Sodium
733
63,284
mg/L
61
0
0
Specific Conductivity
4,880
198,100
uS/cm
32
0
0
Strontium
ND
4,370
mg/L
32
0
1
Sulfate
ND
3,350
mg/L
45
0
1
TDS
2,861
226,733
mg/L
45
0
0
Toluene
0.0016
1
mg/L
9
0
0
TSS
57
353
mg/L
8
0
0
Xylenes
ND
0.39
mg/L
10
0
6
ND - Non-Detect
* Some values were reported by producers as being zero, but may in fact be non-detects.
As discussed in Section 5.1.1, the PA DEP conducted a study (PA DEP, 2016) evaluating
TENORM at several facilities associated with oil and gas extraction activities, including CWTs.
Samples were collected of several waste materials, including produced water. The report for this
study noted significant activity in some produced water samples. Filtering produced water had no
significant effect on radioactivity, indicating the radium was likely soluble. Results of TENORM
in produced water samples presented in this study are summarized in Table 5-9.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 5-Wastewater Characterization and Management
Table 5-9. Ra-226, Ra-228, K-40, Gross Alpha and Gross Beta Activity in Unfiltered
Produced Water (PA DEP, 2016)
Piinimolor
Minimum
Miixiniiiin
Mi'riiiin
NunilK-r of
Siimplcs
Number of Non-
Delecls or Zcm
\ ;ilues
Gross Alpha (pCi/L)
<465
41,700
9,760
13
4
Gross Beta (pCi/L)
<225
7,600
2,300
13
4
Radium 226 (pCi/L)
<81
26,600
4,490
13
1
Radium 228 (pCi/L)
26
1,900
636
13
0
Potassium 40 (pCi/L)
<31
852
220
13
1
WY OGCC, 2015 is the underlying data set for the "Water Analysis" data provided on
the WY OGCC website (http://wogcc.state.wv.us/warchoiceMenu.cfm). The data set contains
monitoring data for chloride, potassium, sodium, sulfate, and TDS for produced waters in
Wyoming from 1940 to 2014.
Table 5-10. Concentrations of Select Pollutants in Wyoming Produced Water (WY
OGCC, 2015)
Piiriimolor
Minimum
Miixiniiiin
I nils
Number of
Siimplcs
NunilHT of Non-
Delecls or Zcm
\ ;ilues
Chloride
478
29,197
mg/L
3,077
NR
Potassium
18
2,200
mg/L
2,639
NR
Sodium
1,475
18,500
mg/L
3,057
NR
Sulfate
8
390
mg/L
2,757
NR
TDS
4,017
64,800
mg/L
3,071
NR
NR - Not reported
Havics, 2011 evaluated several media associated with hydraulic fracturing activities in
Colorado. Havics collected 25 flowback and 10 produced water samples (plus duplicates and QA
samples) from four basins in Colorado: Piceance, Denver-Julesburg, San Juan, and Raton.
Barium, benzene, boron, chloride, ethylbenzene, naphthalene, nickel, toluene, total
xylenes, trimethylbenzene (TMB), and TEPH were detected in 100 percent of the flowback fluid
samples. Barium, boron, chloride, and nickel were detected in 100 percent of produced water
samples. The author noted that barium, boron, chloride and nickel are naturally occurring in the
formation waters, and therefore at least a portion of the concentration of these constituents in
samples can be attributed to the formation (as opposed to additives used during fracturing).
Havics also reported maximum gross alpha and gross beta activity for flowback fluids of 274 and
4,030 pCi/L, respectively.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 5-Wastewater Characterization and Management
Comparing data from this reference, it is notable that concentrations of select constituents
are much higher in samples identified as flowback than in those identified as produced water.
Table 5-11 shows select data from this reference.
Table 5-11. Flowback and Produced Water Constituents from Hydraulically
Fractured Colorado Wells (Havics, 2011)
Piii'iimclor
Minimum
M;i\iiiin in
I nils
Number of
S;i in pies
NiiiiiIht of Non-
IK'locls
Barium
0.009
180
mg/L
35
0
Benzene
ND
9.7
mg/L
46
8
Chloride
17
32,000
mg/L
48
0
Ethylbenzene
ND
7.1
mg/L
46
11
Gross Alpha
ND
274
pCi/L
48
38
Gross Beta
ND
4,030
pCi/L
48
27
Naphthalene
ND
6
mg/L
48
11
Toluene
ND
110
mg/L
47
10
m+p-Xylene
ND
120
mg/L
47
10
o-Xylene
ND
17
mg/L
47
10
1,2,4-Trimethylbenzene
ND
17
mg/L
46
11
1,3,5 -Trimethy lbenzene
ND
12
mg/L
47
10
ND - Non-detect
McElreath, 2011 is a study from Chesapeake Energy comparing hydraulic fracturing fluid
composition to constituent concentrations in produced waters following hydraulic fracturing
from the Western and Eastern U.S. The author presents a time series of produced water
characterization data for specified intervals following hydraulic fracturing, showing how the
concentration of constituents changes over time. The produced water analytical results include
volatile and semi-volatile organic compounds, metals, radionuclides, chloride and TDS. Select
results from the study are shown in Table 5-12.
Table 5-12. Produced Water Constituents from Hydraulically Fractured Wells
(McElreath, 2011)
Piiniiiu'lcr
Minimum
M;i\imiim
I nils
Nil in her ol
S;i in pies
NiiiiiIht ol' Non-
IK'locls
Benzene
1
797
Hg/L
12
0
Chloride
126
81,500
mg/L
12
0
Gross Alpha
620
6,600
pCi/L
6
0
Gross Beta
ND
2,400
pCi/L
5
1
Radium 226
167
1,050
pCi/L
6
0
Radium 228
101
867
pCi/L
6
0
Sodium
95
38,100
mg/L
12
0
Sulfate
2
162
mg/L
12
0
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-15

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Section 5-Wastewater Characterization and Management
Table 5-12. Produced Water Constituents from Hydraulically Fractured Wells
(McElreath, 2011)
Piii'iimolor
Minimum
Miiximum
I nils
Number of
Siimplos
Number of Non-
IK'U'Cls
IDS
1,500
153,000
mg/L
18
0
Toluene
1
1,650
Hg/L
12
0
ND - Non detect
Stepan, 2010 is a treatment and reuse study of produced water from the Bakken oil
formation in North Dakota. The project analyzed fracturing flowback water data from five
different oil producers operating at various locations in the Bakken. Calculated TDS levels in the
produced water were as high as 219,000 mg/L. Select produced water data collected from this
study are presented in Table 5-13.
Table 5-13. Produced Water Constituents from Bakken Oil Formation Wells (Stepan,
2010)
Piimmolor
Minimum
Miiximum
I nils
Nil ill hoi' of
Siimplos
Number of Non-
IK'U'Cls
Barium
ND
24.6
mg/L
7
2
Chloride
500
133,000
mg/L
7
0
Potassium
ND
5,770
mg/L
7
1
Sodium
540
74,600
mg/L
7
0
Specific Conductivity
3,000
205,000
uS/cm
5
0
Strontium
4
1,010
mg/L
6
0
Sulfate
300
1,000
mg/L
7
0
TDS (calculated)
150,000
219,000
mg/L
3
0
ND - Non detect
The preceding discussion presented select data on produced water characteristics
contained in several references. As can be seen from these data, the concentration and prevalence
of constituents varies greatly across the country. This is expected, since formation characteristics
and the type and quantity of additives utilized by producers during well development varies. This
has implications for proper management of produced waters at CWT facilities, as the choice of
treatment technology must be appropriate to treat the wastewater to meet discharge standards and
to protect receiving water quality. Additional data on produced water characteristics can be
found in ERG, 2018a, which is a compilation of multiple original data sources; the presentation
of information summarized in the compilation and presented here may not include all the data
included in each reference, but only those relevant to the study.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-16

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Section 5-Wastewater Characterization and Management
5.2 CWT Wastewater Characteristics
EPA utilized several data sources to characterize wastewater discharged by CWT
facilities that manage oil and gas extraction wastes. These include data contained in facility
discharge monitoring reports (DMRs), data collected from CWA 308 letters sent to select
facilities, and sampling conducted by EPA. EPA also evaluated the Toxics Release Inventory
(TRI); however, none of the in-scope facilities reported data to TRI.21
5.2.1 DMRData
EPA used the EPA DMR Pollutant Loading Tool (U.S. EPA, 2016a) to characterize
concentrations of pollutants in process wastewater discharges22 reported by in-scope CWT
facilities. Data reported in DMRs include pollutants that are regulated in NPDES permits,
including technology-based and water quality-based effluent limitations. Discharges reported in
DMRs may not include all pollutants of interest for this industry as facilities report only those
pollutants required to be monitored by their NPDES permit. DMR data are available only for
direct dischargers with NPDES permits and not for facilities discharging indirectly via publicly
owned treatment works (POTW). Also, DMR data may not be available for permitted direct
dischargers classified as "minor sources".
EPA extracted data from the DMR Pollutant Loadings Tool for calendar year 2016. Eight
of the 11 in-scope CWT facilities submitted DMRs for 2016; however, some DMR data
submitted was not for process wastewater, and was instead for discharges such as stormwater or
sanitary waste.
The eight facilities submitting 2016 DMR data were:
•	Byrd/Judsonia Water Reuse/Recycle Facility: This facility submitted data for all
12 months in 2016. However, only one month (February) reported non-zero flow.
These data are summarized in Table 5-14.
•	Clarion Altela Environmental Services (CAES): This facility submitted data for
one month, and the data did not contain process wastewater.
•	Eureka Resources, Standing Stone Facility: This facility submitted process
wastewater data for one month in 2016 (December). These data are summarized
in Table 5-14.
21	Facilities report discharges to EPA's TRI program only if they meet the employee criteria (i.e., 10 or more
employees) and TRI chemical threshold(s).
22	Some permits include reporting requirements for stormwater discharges. EPA did not include data from outfalls
that were comprised solely of stormwater in the data summaries presented in this section.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-17

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Section 5-Wastewater Characterization and Management
•	Fairmont Brine Processing, LLC: This facility submitted process wastewater data
for six months in 2016. For one of these months, the facility reported zero flow.
Data for months with reported flow are summarized in Table 5-14.
•	Fluid Recovery Services: Franklin Facility (Aquatech): This facility submitted
process wastewater data for each month in 2016. These data are summarized in
Table 5-14.
•	Fluid Recovery Services: Josephine Facility (Aquatech): This facility submitted
process wastewater data for each month in 2016. These data are summarized in
Table 5-14.
•	Max Environmental Technologies, Inc. - Yukon Facility: This facility submitted
process wastewater data for each month in 2016. However, these data did not
include data from the internal outfall that received wastewater from the
centralized waste treatment portion of the facility. It is EPA's understanding that
the facility does not currently discharge wastewater from such operations.
•	Waste Treatment Corporation: This facility reported data for each month in 2016.
Non-zero flow was reported for 7 of the 12 months. As noted in Section 4.3.11,
this facility has a permit to discharge; however, this facility reported only minimal
discharge (e.g., 543 pounds of chloride) on DMRs in 2016. This facility closed in
2017, which may have influenced the limited data reported in 2016. In
comparison, the facility reported in excess of 34 million pounds of chloride in
2014 and 7.8 million pounds of chloride in 2015 DMRs.
The three facilities with no 2016 DMR data were:
•	Eureka Resources, Williamsport 2nd Street Plant: This facility discharges
indirectly and therefore does not report DMR data.
•	Fluid Recovery Services: Creekside Facility: As noted in Section 4.3.8, this
facility has a permit to discharge; however, this facility did not report any
discharge on DMRs in 2016 (perhaps because this facility is classified as a minor
source).
•	Patriot Water Treatment, LLC: This facility discharges indirectly and therefore
does not report DMR data.
The concentration data for select pollutants for each of the facilities reporting DMR data
in 2016 is presented in Table 5-14. Values are the average of all reported values for the
monitoring year. For facilities with more than one month of data available, EPA used V2 of the
detection limit for reported non-detect values in calculating the average for the reporting year. If
all reported values were non-detects, EPA did not calculate an average concentration but rather
indicated that all values were reported as non-detect. The complete DMR dataset for 2016 can be
found in ERG, 2018b.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-18

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Section 5-Wastewater Characterization and Management
Table 5-14. Average Concentration of Select Pollutants in Process Wastewater Reported in
2016 Discharge Monitoring Reports for In-Scope CWT Facilities
Polliiliinl
I nils
l-';icilil>
li\ rd/Jiidsoni;i
Wsiler
Uciisc/Ucoclc
l;icili(>
I'.iiivkii
Resources.
Siiindinii
SlOllC
l";icili(\
l-'iiii'iiionl
Urine
Proccssinji
I-In id
Ucco\ cr\
Son ices:
Imnklin
l;icili(>
I-In id
Rcco\ cr\
Sen ices:
Josephine
l;icili(>
Barium, lolal uii Ba;
nig L

0.05
2.99
"" •)?
o.So
Bromide (as Br)
mg/L


14.71


Chloride (as CI)
mg/L
76.93
5
781.2
72,339
74,975
Nitrogen, ammonia total (as
N)
mg/L
0.147
2.77
2.86


Oil & grease
mg/L
ND
ND

ND
3.57
Radiation, gross alpha
pCi/L


16.39


Radium 226 + radium 228,
total
pCi/L


15.17


Solids, total dissolved
mg/L
191.9
ND
847.8
107,522
151,713
Strontium, total (as Sr)
mg/L

0.11
16.73
149.35

Sulfate, total (as S04)
mg/L
13.03

16.32


# of Months with Non-Zero Flow
1
1
5
12
12
Note: This table presents the average concentration of pollutants as reported in DMRs calculated with non-
detects set equal to half the detection limit. Averages were not calculated if all data for a particular pollutant were
non-detects.
ND: All values reported were non-detects.
Blank values indicate that the facility did not report any data for that pollutant in process wastewater discharges.
Notable observations from the DMR data are the low concentration of barium, which is
expected since all facilities reporting barium incorporate chemical precipitation into their
treatment trains. The two Fluid Recovery Services facilities report high chloride and TDS, which
is expected since these facilities do not incorporate TDS removal technologies. This is in
comparison to the Eureka Resources and Fairmont Brine facilities, which have much lower TDS
owing to the utilization of evaporation/crystallization technologies. The only facility reporting
radium and gross alpha radiation, Fairmont Brine, showed low activity in reported samples.
Strontium was also markedly lower in the Eureka Resources and Fairmont Brine facilities as
opposed to the Franklin Facility. None of the facilities reporting oil and grease showed
appreciable concentrations of this pollutant. Additional DMR data can be found in ERG, 2018b.
5.2.2 EPA Sampling Data
EPA collected sampling data at the Pinedale Anticline Waste Treatment Facility
(Anticline) in Pinedale, WY and the Eureka Resources, Standing Stone Facility (Eureka) in
Wysox, PA. Both facilities were fully operational and active commercial CWT facilities that
treat oil and gas extraction wastewaters and directly discharged their treated effluent at the time
of sampling in 2016. The sampling team collected a grab sample from various stages of
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-19

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Section 5-Wastewater Characterization and Management
treatment at both facilities to characterize untreated wastewater, treated effluent, intermediate
treatment points, and treatment residuals generated at these facilities.
Both facilities accept wastewater from multiple oil and gas producers, have NPDES
permits authorizing direct discharge of treated effluent, discharge their treated water on an as
needed basis depending upon alternate users of the treated water, and have treatment
technologies that are designed to reduce TDS and other pollutants of interest in the final effluent.
Anticline operates a multi-stage treatment system that includes oil/water separation, chemically-
assisted clarification, media filtration, biological treatment, reverse osmosis (RO), and boron ion
exchange (Schafer, 2010). The Eureka facility operates a multi-stage treatment system that
includes chemical precipitation, evaporation/crystallization, biological treatment, ion exchange,
and RO (U.S. EPA, 2017b).
EPA selected a comprehensive list of analytes for testing provided in Table 5-15 along
with the test methods. These included classical wet chemistry, anions, metals, gasoline and diesel
range organics, volatile organics, semi-volatile organics, alcohols, radiological measurements,
and WET tests. Several of these parameters were analyzed using multiple methods, including
anions, volatile organics, and semi-volatile organics to determine if any particular method had
fewer interferences with the high TDS wastewater. For details on the sampling methods, facility
treatment technology, and analytes tested for, see each facility's respective Sampling and
Analysis Plans (U.S. EPA, 2017c; U.S. EPA, 2017d)
Table 5-15. Analytical Methods for the CWT Study Sampling Program
Anal.Mc
Method (Tcchni(|iic)
(iroup 1 Classical Wcl Chemisln

Tulal Dissolved Solids ( I DS)
SM 254U C-1997 (Gi'av iniuli'iu)
Total Suspended Solids (TSS)
SM 2540 D-1997 (Gravimetric)
Specific Conductance
SM 2510 B-1997 (Conductivity Meter)
Alkalinity
SM 2320 B-1997 (Titration)
Group II Classical Wet Chemistry
Chemical Oxygen Demand (COD)
EPA 410.4 (Spectrophotometric)
Total Organic Carbon (TOC)
SM 5310 B-2000 (Combustion)
Ammonia
EPA 350.1 (Colorimetric)
Oilier Classical Wei (hcmisln
n-Hexane Extractable Material (HEM) and Silica Gel
Treated n-Hexane Extractable Material (SGT-HEM)
EPA 1664A (Gravimetric)
Biochemical Oxygen Demand (BOD5)
SM 5210 B-2001
Total Hardness
SM 2340 C-1997 (Titrimetric)
Anions
Fluoride, Chloride, Nitrite, Ortho-Phosphate, Bromide,
Nitrate, Sulfate
ASTM D4237 (Suppressed Ion Chromatography)
Fluoride, Chloride, Nitrite, Ortho-Phosphate-p, Bromide,
Nitrate, Sulfate, Bromate, Chlorite, Chlorate
EPA 300.0 (Ion Chromatography)
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-20

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Section 5-Wastewater Characterization and Management
Table 5-15. Analytical Methods for the CWT Study Sampling Program
Aiiiil.Mi-
Mclhuri ( l oclini(|iio)
l oliil Mcliils

Trace Elements
EPA 200.8
Mercury
EPA 245.1 or 245.2 (Cold Vapor Atomic Absorption)
Hexavalent Chromium
SM 3500-CrB-2009 (Colorimetric)
Oriiiinics
Diesel Range
EPA 3520C (sample preparation), EPA 8015C
(analysis) (Gas Chromatography)
Gasoline Range
EPA 5030B (sample preparation), EPA 8015C
(analysis) (Gas Chromatography)
Volatile Organic Compounds
EPA 5030 or EPA 5035/8260C (Gas
Chromatography/Mass Spectroscopy)
Volatile Organic Compounds
EPA 624 (Gas Chromatography/Mass Spectroscopy)
Semivolatile Organic Compounds
EPA 3520C/8270D (Gas Chromatography/Mass
Spectroscopy)
Semivolatile Organic Compounds
EPA 625 (Gas Chromatography)
Alcohols
EPA 8260C, 8270D, and 8015C (Gas
Chromatography/Mass Spectroscopy)
Kii(lio:icli\os
Total Radium 226 (Liquid Samples)
EPA 903.1 (Radon Emanation)
Total Radium 228 (Liquid Samples)
EPA 904.0 (Radiochemical/Precipitation)
Total Radium 226 and 228 (Solid Samples)
EPA 901.1 (Gamma Spectroscopy)
Gross Alpha/Beta (Liquid Samples)
EPA 900.0
Gross Alpha/Beta (Solid Samples)
EPA 900.0
\\ hole I.ITIiic'iK 1 o\icil> (\\ 11 1 )
Acute Nonvertebrate
Ceriodaphnia dubia EPA 2002.0
Acute Vertebrate
Pimephalespromelas EPA 2000.0
Chronic Nonvertebrate
Ceriodaphnia dubia EPA 1002.0
Chronic Vertebrate
Pimephales promelas EPA 1000.0
Table 5-16 presents the effluent sampling results for Anticline and the influent and
effluent sampling results for Eureka. [Note that because Anticline has claimed their influent and
all in-process sampling results as confidential, only their effluent data are presented.] The table
presents all analytes that were detected at either facility for all methods, as well as a general
indication of percent reduction for the Eureka facility. In addition, this table indicates whether a
specific analyte is currently regulated under the CWT effluent guidelines at 40 CFR Part 437.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-21

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Section 5-Wastewater Characterization and Management
Table 5-16. EPA Sampling Results for Anticline and Eureka Facilities


Keunhiled under
40 ( I K 437
Anlieline

I'.iirekii

An;il> (o
I nil
Snhp;irl
A
Snhp;irl
1}
Siihpiirl
<
I'llTliienl
1 n riiienl
I'llTliienl
Pereenl
Reduction
Cliissiciil Wei Chemisln








Alkalinity, Total as CaCCb
mg/L



11
76
9.23
87.9%
pH
S.U.
Yes
Yes
Yes
9.2
6.03
7.15
NC
Biochemical Oxygen Demand (BOD5)
mg/L


Yes
1.53
80
3.72
95.4%
Chemical Oxygen Demand (COD)
mg/L



12.7
15,700
16.1
99.9%
Conductivity
Hmhos/cm



177
180,000
34.6
>99.9%
Hardness as CaC03
mg/L



3.89
74,400
283
99.6%
n-Hexane Extractable Material (HEM)
mg/L
Yes
Yes

ND (1.14)
88.1
ND (1.14)
>98.7%
Nitrogen, Ammonia
mg/L



ND (0.017)
124
0.0578
>99.9%
Silica Gel Treated n-Hexane Extractable
Material (SGT-HEM)
mg/L
Yes
Yes

ND (1.14)
62.2
ND (1.14)
>98.2%
Total Dissolved Solids (TDS)
mg/L



78.6
174,000
14.3
>99.9%
Total Organic Carbon (TOC)
mg/L



0.419
829
0.59
99.9%
Total Suspended Solids (TSS)
mul.
Yes
Yes
Yes
ND (0.633)
545
\T) (0 (,V,)
>99.9%
Anions Method 300.0








Bromide
mg/L



0.327
725
ND (0.067)
>99.9%
Chloride
mg/L



45.1
95,500
2.05
>99.9%
Nitrate
mg/L



ND (0.033)
ND (33)
0.977
NC
Sulfate
me/1,



ND (0.133)
6^ 2
0 265
99.6%
Anions Method AS IM 1)423^








Bromide - UV
mg/L



0.265
839.7
ND (NR)
NC
Bromide - Conductivity
mg/L



0.291
834.5
ND (NR)
NC
Nitrate - Conductivity
mg/L



ND(NR)
ND (NR)
4.215
NC
Nitrate - UV
mg/L



ND(NR)
ND (NR)
4.441
NC
Sulfate - Conductivity
mg/L



ND(NR)
ND (NR)
ND (NR)
NC
Sulfate - UV
mg/L



ND(NR)
ND (NR)
ND (NR)
NC
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-22

-------
Section 5-Wastewater Characterization and Management
Table 5-16. EPA Sampling Results for Anticline and Eureka Facilities


Kcunhilcri under
40 ( I K 4J-?
Anticline

I'.iiivkii

An;il> (o
I nil
Siihpiirl
A
Siihpiirl
1}
Siihpiirl
<
I.ITIuoiK
InHiionl
r.lTliicnl
Pc'ITOlK
Reduction
l oliil Mcliils








Antimony*
M-g/L
Yes


ND (1)
ND (100)
ND (1)
NC
Arsenic
M-g/L
Yes
Yes

ND (1.7)
440
ND (1.7)
>99.6%
Barium
M-g/L



78.4
11,000,000
15.4
>99.9%
Boron
M-g/L



ND (7.5)
3,710
81.6
97.8%
Cadmium
Mg/L
Yes
Yes

ND (0.3)
12.1
ND (0.3)
>97.5%
Calcium
Mg/L



442
21,700,000
204
>99.9%
Chromium*
Mg/L
Yes
Yes

ND (3)
ND (60)
ND (3)
NC
Cobalt
Mg/L
Yes
Yes

ND (0.1)
20.3
ND (0.1)
>99.5%
Copper
Mg/L
Yes
Yes
Yes
ND (0.35)
1,430
1.21
99.9%
Cyanide
Mg/L
Yes


NS
NS
NS
NC
Iron
Mg/L



ND (33)
117,000
ND (33)
>99.9%
Lead
Mg/L
Yes
Yes

ND (0.5)
3.53
ND (0.5)
>85.8%
Lithium
Mg/L



9.53
185,000
9.01
>99.9%
Magnesium
Mg/L



ND (10)
1,240,000
ND (10)
>99.9%
Manganese
Mg/L



1.21
9,520
ND (1)
>99.9%
Mercury*
Mg/L
Yes
Yes

ND (0.067)
ND (0.67)
ND (0.067)
NC
Molybdenum
Mg/L



ND (0.3)
6.34
ND (0.3)
>95.3%
Nickel
Mg/L
Yes


ND (0.5)
210
ND (0.5)
>99.8%
Phosphorous
Mg/L



ND (15)
736
ND (15)
>98.0%
Potassium
Mg/L



275
282,000
ND (80)
>99.9%
Selenium
Mg/L
Yes


ND (2)
1,660
ND (2)
>99.9%
Silica
Mg/L



238
10,800
97.2
99.1%
Silver
Mg/L
Yes


ND (0.4)
9.72
ND (0.4)
>95.9%
Sodium
Mg/L



36600
43,700,000
7,910
>99.9%
Strontium
Mg/L



39.6
5,670,000
34.7
>99.9%
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-23

-------
Section 5-Wastewater Characterization and Management
Table 5-16. EPA Sampling Results for Anticline and Eureka Facilities


Keuuliiled under
40 ( I K 4J-?
Anlieline

I'.iirekii

AiiiilMe
I nil
Siihpiirl
A
Siihpiirl
1}
Siihpiirl
<
IHTIiienl
InHiienl
I'HTIiienl
Percent
Reduction
Tin*
M-g/L
Yes
Yes

ND (1)
ND (20)
ND (1)
NC
Titanium*
l-ig/L
Yes


ND (2)
ND (40)
ND (2)
NC
Vanadium*
Hg/L
Yes


ND (4.5)
ND (450)
ND (4.5)
NC
Zinc
Hg/L
Yes
Yes
Yes
ND (3.5)
2,820
7.4
99.7%
Diesel Riiiiiie ()r»;inies








Diesel kaimc ()i uanics
MUl.



\i)<:ui
		
SI 5
<><> 99.7%
Ynhilile Oi'^iinie Compounds Method
S2WIC








1,2,4-Trimethylbenzene
l-ig/L



ND (0.3)
0.8
ND (0.3)
>62.5%
2-Butanone*
Hg/L


Yes
ND (3)
ND (3)
ND (3)
NC
Acetone
Hg/L


Yes
26.3
33.3
ND (3)
>91.0%
Chlorobenzene
Hg/L



0.38
ND (0.3)
ND (0.3)
NC
Ethylbenzene
l-ig/L



ND (0.3)
ND (0.3)
ND (0.3)
NC
m,p-Xylenes
Hg/L



ND (0.3)
0.72
ND (0.3)
>58.3%
o-Xylene
Hg/L



ND (0.3)
0.48
ND (0.3)
>37.5%
Ynhilile Oriiiinic Compounds Method
(.24








Chlorobenzene
M-g/L



ND (0.333)
ND (0.333)
ND (0.333)
NC
Ethylbenzene
Hg/L



ND (0.333)
0.34
ND (0.333)
>2.06%
Isopropyl Alcohol
Hg/L



ND (16.7)
291
ND (16.7)
>94.3%
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-24

-------
Section 5-Wastewater Characterization and Management
Table 5-16. EPA Sampling Results for Anticline and Eureka Facilities


Rciiii luted uiuk'i-






40 ( I K 4J-?
Anticline

I'.iirckii

An;il> (o
I nil
Siihpiirl
A
Siihpiirl
1}
Siihpiirl
(
r.lTlncnl
InHiicnl
influent
Percent
Reduction
Scmi\ol;ililc Oriiiinic Compounds Method (>25






2,4,6-Trichlorophenol*
M-g/L


Yes
ND (3)
ND (30)
ND (2.75)
NC
Acetophenone*
l-ig/L


Yes
ND (3)
ND (30)
ND (2.75)
NC
Bis(2-ethylhexyl)phthalate
Hg/L

Yes

ND (3)
ND (30)
ND (2.75)
NC
Butylbenzylphthalate*
Hg/L

Yes

ND (3)
ND (30)
ND (2.75)
NC
Carbazole*
Hg/L

Yes

ND (0.3)
ND (3)
ND (0.275)
NC
Fluoranthene*
l-ig/L

Yes

ND (0.3)
ND (3)
ND (0.275)
NC
m,p-Cresols*
Hg/L


Yes
ND (3.7)
ND (37)
ND (3.39)
NC
n-Decane*
Hg/L

Yes

ND (3)
ND (30)
ND (2.75)
NC
n-Octadecane*
Hg/L

Yes

ND (3)
ND (30)
ND (2.75)
NC
o-Cresol*
l-ig/L


Yes
ND (3)
ND (30)
ND (2.75)
NC
Phenol*
Hg/L


Yes
ND (3)
ND (30)
ND (2.75)
NC
Pyridine*
M-g/L


Yes
ND (3)
ND (30)
ND (2.75)
NC
Scmi\ol;ililc Oriiiinic Compounds Method 3520(7X2701)
2,4,6-Trichlorophenol*
Hg/L


Yes
ND (2)
ND (20)
ND (2)
NC
2-Butoxyethanol
Mg/L



ND (1)
566
ND (1)
>99.8%
Bis(2-ethylhexyl)phthalate
Hg/L

Yes

ND (2)
ND (20)
3.33
NC
Butylbenzylphthalate*
Hg/L

Yes

ND (1)
ND (10)
ND (1)
NC
Carbazole*
Hg/L

Yes

ND (3)
ND (30)
ND (3)
NC
Fluoranthene*
Hg/L

Yes

ND (1)
ND (10)
ND (1)
NC
Phenol*
Hg/L


Yes
ND (2)
ND (20)
ND (2)
NC
Pyridine*
Hg/L


Yes
ND (1)
ND (10)
ND (1)
NC
Alcohols
Ethanol
UgL



\D 				
31,800
\l) 			
_<>() 99.7%
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-25

-------
Section 5-Wastewater Characterization and Management
Table 5-16. EPA Sampling Results for Anticline and Eureka Facilities


Rciiiiliik'd under
40 ( I K 43^
Anticline

I'.iiivkii

An;il> (o
I nil
Siihpiirl
A
Siihpiirl
1}
Siihpiirl
<
I.ITIuoiK
InHiionl
r.lTliicnl
IVlTOlH
Reduction
K;idioiicli\cs (l.i(|iiid)








Gross Alpha
pCi/L



ND (3)
5,900
ND (3)
>99.9%
Gross Beta
pCi/L



ND (4)
6,000
ND (4)
>99.9%
Total Radium 226
pCi/L



ND (1)
10,300
0.16
>99.9%
Total Radium 228
pCi/L



1.1
1,320
0.74
99.9%
K;idio;icli\cs (Solid)
Gross Alpha
pCi/g



6.3
NS
9.2
NC
Gross Beta
pCi/g



6.1
NS
4
NC
Total Radium 226
pCi/g



5.69
NS
451
NC
Total Radium 228
pCi/g



3.06
NS
40.3
NC
NS is Not Sampled; ND is Not Detected (value in parenthesis is detection limit); NC is Not Calculated; NR is Not Reported
* Indicates a 40 CFR 437 regulated pollutant that was not detected in any samples.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-26

-------
Section 5-Wastewater Characterization and Management
The Table 5-16 results exclude tentatively identified compounds and any analytes where
all results were below the detection limit, with the exception of 40 CFR 437 regulated pollutants.
A more comprehensive discussion of Eureka's intermediate sampling results based on each
treatment step can be found in Chapter 6.
Of the 34 CWT regulated pollutants at 40 CFR 437, 18 regulated pollutants were not
detected in any of the samples from Anticline or Eureka using any test method. These are
indicated with an asterisk (*) in Table 5-16. Note that cyanide is the only 40 CFR 437 regulated
pollutant (under subpart A) that was not analyzed for at any sampling point at either facility;
cyanide was not analyzed for because it was not reasonably expected to be present in oil and gas
extraction wastewater.
The influent wastewater at Eureka contained particularly high levels of four classical wet
chemistry pollutants: COD, conductivity, hardness, and TDS. There were high levels of the
common ions, chloride, sodium, calcium, magnesium, and to a lesser extent sulfate, along with
elevated concentrations of bromide, as well as most of the metals, such as barium and strontium.
As would be expected for wastewater from the Marcellus, there are elevated levels of radium in
the influent. Most of the organics were at low concentrations to below detection levels. The
exceptions being organics in the diesel and gasoline range as well as high levels of alcohols,
ethanol and methanol, the alcohols being added as part of the recovery process. The Eureka
sampling data results indicate a significant reduction in the concentration of all detected
pollutants. Lastly, in comparing the effluents from the two facilities, the Anticline data is fairly
similar to Eureka's in terms of analytes detected and concentrations reported. Any comparison
between the two facilities is difficult to make due to the different treatment trains employed and
the different wastewater being treated, Anticline being located in Wyoming and Eureka in
Pennsylvania.
Whole effluent toxicity testing was also performed on the effluent samples from both
facilities. The results showed that both facilities generated effluent discharges that were not
acutely toxic to C. dubia or fathead minnows, nor were they chronically toxic to C. dubia.
However, while Anticline's effluent was not chronically toxic to flathead minnows (NOEC of
100 percent), the effluent from Eureka was found to be slightly chronically toxic to fathead
minnows (NOEC of 50 percent). For the two chronic tests conducted on Eureka's effluent
sample, the second and third renewal samples were shipped with inadequate ice and arrived at
the testing laboratory well above the recommended 0-6°C range. As a result, EPA decided to not
use the second renewal sample but continue with the test using the third renewal sample on day
3, 4, 5, and 6. It is unknown what effect this might have had, if any, on the toxicity tests.
Anions, volatile organics, and semi-volatile organics were all analyzed using two
separate analytical methods for both facilities to determine if any particular method had fewer
interferences from the high TDS wastewater. For the analysis of anions, bromide and nitrate
were detected in the same samples using either test method (Method 300.0 or Method ASTM
D4237) and procedure (UV or conductivity). However, Method 300.0 detected concentrations of
sulfate in the Anticline effluent and the Eureka influent that were not detected by the ASTM
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-27

-------
Section 5-Wastewater Characterization and Management
D4237 Method. Additional testing would be required to determine which constituents may have
been responsible for the observed differences and at what concentrations they become a problem.
Four volatile organic analytes were measured using two methods: Method 8260C and
Method 624. Ethylbenzene was detected only by Method 624. Chlorobenzene and o-xylene were
detected by only Method 8260C. Generally speaking, Method 8260C and Method 624 had
similar detection limits, but the methods have different lists of compounds that are measured. For
example, isopropyl alcohol is detected by Method 624 but only appears as a tentatively identified
compound in Method 8260C. For semi-volatile organics, which were analyzed using Method 625
and Method 3520C/8070D, bis(2-ethylhexyl) phthalate was detected by Method 3520C/8070D
and not by Method 625. Once again, additional testing would be required to determine which
constituents may have been responsible for the observed differences and at what concentrations
they become a problem. Since the techniques and instruments used to analyze for organics
differs from those employed for inorganics, it may be possible that the component responsible
for the observed difference in organics may be different from that for inorganics.
Refer to the Sampling Episode Reports for these two sampling events for the complete
dataset generated by these two sampling episodes, analysis of all sampling points, residual
sample results, and data quality discussion (US. EPA, 2017a and U.S. EPA, 2017b).
5.3 Oil and Gas Extraction Wastewater Volumes and Management Practices
Limited national data currently exist on the volume of wastewater generated by oil and
gas extraction activities and the volumes being managed at CWT facilities. As discussed earlier
in this report, EPA has identified only 11 CWT facilities nationally that accept oil and gas
extraction wastes and discharge wastewater and are therefore in-scope for this study. As noted,
there are a number of facilities that accept oil and gas extraction wastes nationally but do not
discharge. These facilities instead treat wastewater for reuse in hydraulic fracturing or other uses.
There are national data sets on the volumes of wastewater managed at these facilities, which are
outside the scope of this study.
According to the U.S. DOI's 2011 report entitled "Oil and Gas Produced Water
Management and Beneficial Use in the Western United States", between 7 to 10 barrels (294 to
420 gallons) of water are produced for every barrel of crude oil produced. Reservoirs have
naturally existing formation water, with oil reserves containing larger volumes of water than gas
reserves. As the oil and gas reserves deplete over time and wells age, the volume of produced
water generated can increase relative to the amount of oil or gas produced (U.S. DOI, 2011).
The oil and gas industry has most commonly managed produced water by underground
injection (Clark & Veil, 2009). For example, disposal of oil and gas extraction wastewaters in
Texas is primarily through disposal wells - there were over 32,000 active disposal wells in Texas
in 2014 (Railroad Commission of Texas, 2014). In contrast, Pennsylvania has only eight
permitted brine disposal wells as of 2011 (McCurdy, 2011). Where other management options
exist, such as injection or reuse in hydraulic fracturing, there may be little need for CWT
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-28

-------
Section 5-Wastewater Characterization and Management
facilities that treat and discharge wastewater. However, where other management options are
limited, there may be greater demand for CWT services for managing oil and gas extraction
wastes. In some geographic areas, the industry may rely on CWT facilities, in part, to manage
growing volumes of wastewater. (Horn et al., 2013; Environmental Leader, 2013)
A comprehensive study of U.S. oil and gas extraction produced water volumes and
management practices was published in 2009 called "Produced Water Volumes and Management
Practices in the United States" (U.S. DOE, 2009). This study used oil and gas industry data from
the year 2007. The study collected data by sending information requests to state agencies asking
them to report precise and accurate data for oil and gas wells. Data from each state were
compiled, and the resulting dataset estimated that approximately 21 billion barrels of produced
water were generated in 2007 (U.S. DOE, 2009).
In 2015, the DOE study was updated to include 2012 data (GWPC, 2015). The 2012 data
estimated that oil production in the U.S. increased by about 29 percent between 2007 and 2012
and gas production by 22 percent; however, water production increased by only one percent.
Table 5-17 lists the ten states with the highest volumes of wastewater generation by oil and gas
extraction operations, as reported by GWPC, 2015. Texas and California generated about 50
percent of all the produced water generated in 2012.
Table 5-17. Ten States with the Highest Oil and Gas Produced Water Volumes in 2012
Stall'
Volume of Oil and (>as 1'\ 1 raclion
\\ aslowalor in 2012 (million bbl/\r)
Percenlajie of 1 otal I .S. Oil and (ias
I'.xlraclion \\ a slow a (or ("'»)
Texas
7,435
35
California
3,074
15
Oklahoma
2,325
11
Wyoming
2,178
10
Kansas
1,061
5
Louisiana
927
4
Alaska
769
4
Colorado
358
2
North Dakota
291
1
Mississippi
231
1
U.S. Total (million bbl/yr)
21,180
Source: GWPC, 2015.
Table 5-18 shows quantities of wastewater reported in the 2015 GWPC report for on-
shore facilities. The majority of water from onshore wells is injected for enhanced recovery or
disposal. The next most common management technique for onshore produced water is offsite
commercial disposal.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-29

-------
Section 5-Wastewater Characterization and Management
Table 5-18. Produced Water Management Practices and Volumes for 2012

Onshore Toisil (million

Miiiiiiuomonl Pniclicc
l)bl/\n
I'mTiil.igi* of Onshore ("'iii
liijecUoii lor Liilianced Rccon er\
"^u
4o.2
Injection for Disposal
7,950
39.8
Surface Discharge
605
3.0
Evaporation
691
3.5
Offsite Commercial Disposal
1,370
6.9
Beneficial Reuse
126
0.6
Total Produced Water Managed
20,000
100
Source: GWPC, 2015.
While the GWPC 2015 report (and the U.S. DOE, 2009 report) are the most
comprehensive studies analyzing national trends in wastewater volumes from oil and gas
extraction, there are other resources that EPA reviewed. For example:
•	Drillinglnfo (DI) Desktop® database. Although the DI Desktop® database
includes annual oil, gas, and produced water production records for all oil and gas
wells (including inactive wells and underground injection wells that do not
produce oil and/or gas), the DI Desktop® database has incomplete wastewater
volume data, including inconsistent naming conventions, spelling errors and wells
with an "N/A", "0", "N", or blank as basin type (U.S. EPA, 2016b).
•	USGS National Produced Waters Geochemical Database. EPA evaluated the
USGS database, which includes geochemical data for almost 60,000 wells in the
36 states where O&G exploration occurs. However, the database does not include
wastewater flow volumes.
•	Office of Technology Assessment. A congressional report detailing the
management technologies and practices as of 1992. Surface impoundments,
landfilling, land application, discharges to surface waters, and waste reduction
were possible practices. Sixty-two percent of produced water was injected for
enhanced oil recovery, while 29 percent was injected into a disposal well. Only 6
percent of produced water was discharged.
•	State Data. No federal regulatory agency requires producers or states to track oil
and gas extraction wastewater volume data or its submission. Consequently, most
states do not collect or maintain produced water information. Of the few states
that do maintain datasets, water production or management information is not
reported consistently from state to state, making it difficult to compile into a
single database. Databases from Ohio, Colorado, New Mexico, North Dakota, and
Wyoming state agencies include monthly or annual produced water volumes per
well (depending on the state), and include well API number, formation name, well
completion date, and/or well trajectory.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-30

-------
Section 5-Wastewater Characterization and Management
—	PA DEP. Statewide data downloads (i.e., waste reports data) are published
in six-month reporting periods (i.e., January to June, July to December).
For each reporting period, the data downloads include the following types
of information: API number of the well that generated waste, waste
quantity and type, and waste management information. The data
downloads also provide information about the facility where the waste was
disposed, including the facility name, permit number, and location.
—	Texas Railroad Commission (TXRRC). List of permitted commercial
recycling and surface waste facilities with permit number and expiration
date information. Commercial recycling and surface waste facilities are
organized into the following groups: Recycling, Pits, Stationary Treatment
Facilities, Landfarm/Landtreatment Facilities, and Reclamation Plants.
5.4 References
1.	Acharya, Harish R. 2011. Cost Effective Recovery of Low-TDS Frac Flowback
Water for Reuse. GE Global Research. U.S. DOE NETL. DCN CWT00005
2.	Benko, K.L. and Drewes, J.E. 2008. Produced Water in the Western US:
Geographical Distribution, Occurrence, and Composition. US Bureau of
Reclamation. DCN CWT00149
3.	Boschee, Pam. 2014. Produced and Flowback Water Recycling and Reuse:
Economics, Limitations, and Technology. (February). DCN CWT00242
4.	Bruff, Matthew. 2011. An Integrated Water Treatment Technology Solution for
Sustainable Water Resource Management in the Marcellus Shale. DCN
CWT00325
5.	Caen, R., Darley, et al. 2011. Composition and Properties of Drilling and
Completion Fluids. 6th edition. Gulf Professional Publishing: Waltham, MA.
DCN CWT00334
6.	Campbell, E., et al. 2012. Geochemical and Strontium Isotope Characterization of
Produced Waters from Marcellus Shale Natural Gas Extraction. DCN CWT00326
7.	CCST. 2014. Advanced Well Stimulation Technologies in California: An
Independent Review of Scientific and Technical Information. DCN CWT00331
8.	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. DCN
CWT00358
9.	Coleman, Nancy. 2011 Chesapeake Energy. Produced Formation Water Sample
Results from Shale Plays. DCN CWT00327
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
5-31

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Section 5-Wastewater Characterization and Management
10.	Dunkel, Michael. 2012. The Economics of Water Management. Pioneer Natural
Resources. DCN CWT00332
11.	Environmental Leader. 2013. Unconventional E&P $8 Billion of US Water
Services Market. (November 11). DCN CWT00021
12.	ERG. 2005. Draft Toxic Weighting Factor Development in Support of CWA
304(m) Planning Process. (July 29). DCN CWT00001.
13.	ERG. 2016a. Conventional Oil and Gas Memorandum for the Record. Effluent
Limitations Guidelines and Standards for the Oil and Gas Extraction Point Source
Category. DCN CWT00128
14.	ERG. 2016b. Conventional Oil and Gas Memo for the Record - Attachment 2:
COG Wastewater Characterization Analysis. Effluent Limitations Guidelines and
Standards for the Oil and Gas Extraction Point Source Category. DCN
CWT00128.A02
15.	ERG. 2016c. Conventional Oil and Gas Memo for the Record - Attachment 3:
COG Wastewater Characterization Database. Effluent Limitations Guidelines and
Standards for the Oil and Gas Extraction Point Source Category. DCN
CWT00128.A03
16.	ERG. 2016d. UOG Produced Water Volumes and Characterization Data
Compilation Memorandum. DCN CWT00061
17.	ERG. 2016e. Oil and Gas Drilling Wastewater Memorandum Attachment 1: UOG
Drilling Wastewater Volume and Characterization Data Excel File. DCN
CWT00148.A01
18.	ERG. 2018a. Oil and Gas Wastewater Characterization Memorandum. DCN
CWT00374
19.	ERG. 2018b. Analysis of DMR Pollutant Data and Loadings Calculations. DCN
CWT00542
20.	ExxonMobil Corporation. 2014. Hydraulic Fracturing Fluid. XTO Energy.
Downloaded on 6/13/2014. DCN CWT00329
21.	FracFocus. 2014. What Chemicals Are Used? DCN CWT00330
22.	Gradient. 2009. Evaluation of Potential Impacts of Hydraulic Fracturing
Flowback Fluid Additives on Microbial Processes in POTWs. DCN CWT00335
23.	GWPC. 2015. Clark, C.E., and J.A. Veil. U.S. Produced Water Volumes and
Management Practices in 2012. (April). DCN CWT000158
24.	Haluszcsak, Lara O. 2012. Geochemical evaluation of flowback brine from
Marcellus gas wells in Pennsylvania, USA. Department of Geosciences.
Pennsylvania State University. DCN CWT00385
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 5-Wastewater Characterization and Management
25.	Hansen, E; Mulvaney, D; Betcher, M. 2013. Water Resource Reporting and Water
Footprint from Marcellus Shale Development in WV and PA. (October 30). DCN
CWT00336
26.	Harju, John. EERC (NGPWC) Bakken Water Opportunities Assessment North
Dakota Petroleum Council Annual Meeting September 2009. DCN CWT00337
27.	Havics, Andrew, 2011. Fracing & Associated Media Composition in Colorado.
In: Proceedings of the Technical Workshops for the Hydraulic Fracturing Study:
Fate and Transport. EPA 600/R-l 1/047 May 2011. DCN CWT00338
28.	Hayes, T. 2011. Characterization of Marcellus Shale and Barnett Shale Flowback
Waters and Technology Development for Water Reuse. DCN CWT00339
29.	Hayes, Thomas; et al. 2012. Evaluation of the Aqua Pure Mechanical Vapor
Recompression System in the Treatment of Shale Gas Flowback Water. RPSEA.
DCN CWT00043
30.	Horn, Aaron. 2009. Breakthrough Mobile Water Treatment Converts 75% of
Fracturing Flowback Fluid to Fresh Water and Lowers C02 Emissions. SPE.
DCN CWT00038
31.	Horn, A; Patton, M; Hu, J. 2013. Minimum Effective Dose: A Study of Flowback
and Produced Fluid Treatment for Use as Hydraulic Fracturing Fluid. DCN
CWT00320
32.	Huffmyer, Russell and Gehucheten, John. 2013. Recovering Valuable Byproducts
from Oil and Gas Wastes. HDR Engineering, Inc. IWC-13-37. (November 17).
DCN CWT00340
33.	Johnson, Tommy and Harry, David. 2014. Uinta Water Management. Water
Management for Shale Plays Conference. (May 28). DCN CWT00341
34.	Robert Kimball. 2012. Key Considerations for Frac Flowback / Produced Water
Reuse and Treatment. CDM Smith. DCN CWT00342
35.	Maguire-Boyle, S.J. and Barron, A.R. 2014. Organic compounds in produced
waters from shale gas wells. Royal Society of Chemistry. DCN CWT00344
36.	Mantell, Matthew, Chesapeake Energy Corp. 2011. Produced Water Reuse and
Recycling Challenges and Opportunities Across Major Shale Plays. DCN
CWT00345
37.	MarkMazoch. 2012. Fayetteville Shale. Southwestern Energy. DCN CWT00346
38.	McElreath, Debra. 2011. Comparison of Hydraulic Fracturing Fluids Composition
with Produced Formation Water Quality Following Fracturing. In: Proceedings of
the Technical Workshops for the Hydraulic Fracturing Study: Fate and Transport.
EPA 600/R-l 1/047 May 2011. DCN CWT00347
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 5-Wastewater Characterization and Management
39.	McCurdy, Rick. 2011. Chesapeake Energy Corp. Underground Injection Wells
for Produced Water Disposal. DCN CWT00378
40.	Murray, K.E. 2013. Examining Water Production Volumes and Produced Water
Quality in the Mississippi Lime to Develop Appropriate Management Strategies.
DCN CWT00348
41.	National Petroleum Council (NPC). 2011. Waste Management Paper #2-24.
Technology Subgroup of the Operations & Environment Task Group. (September
15). DCN CWT00130
42.	NYSDEC. 1999. An Investigation of Naturally Occurring Radioactive Materials
(NORM) in Oil and Gas Wells in New York State. DEC Publication. DCN
CWT00333
43.	NYSDEC. 2009. Supplemental Generic Environmental Impact Statement
(SGEIS) on the Oil, Gas, and Solution Mining Regulatory Program. DCN
CWT00343
44.	NYSDEC. 2011. Supplemental Generic Environmental Impact Statement
(SGEIS) on the Oil, Gas, and Solution Mining Regulatory Program: Info
Requests. DCN CWT00349
45.	Office of Research and Development (ORD). 2014. Wastewater Quality Data
Manipulation. DCN CWT00350
46.	Palacios, Virginia. 2012. Baseline Groundwater Quality Testing Needs in the
Eagle Ford Shale Region April 2012. DCN CWT00352
47.	Pennsylvania Department of Environmental Protection (PA DEP). 2016.
Technologically Enhanced Naturally Occurring Radioactive Materials
(TENORM) Study Report. DCN CWT00131
48.	Railroad Commission of Texas. 2014. Commercial Recycling & Surface Disposal
Facilities. DCN CWT00092
49.	Rimassa, Shawn; Howard, Paul; Blow, Kristel; Schlumberger. 2009. Optimizing
Fracturing Fluids from Flowback Water. Society of Petroleum Engineers. DCN
CWT00353
50.	Rost, J. (2010a). Municipal Authority of the City of McKeesport Analysis of Gas
Well Wastewaters as Required Under the PA DEP Administrative Order Dated
October 23, 2008 (File 1). DCN CWT00132
51.	Rost, J. (2010b). Municipal Authority of the City of McKeesport Analysis of Gas
Well Wastewaters as Required Under the PA DEP Administrative Order Dated
October 23, 2008 (File 2). DCN CWT00133
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 5-Wastewater Characterization and Management
52.	Rowan, E.L., et al. 2011. Radium content of oil and gas field prod waters in the
nrthrn App Basin. USGS Scientific Investigations Report 2011-5135. DCN
CWT00316
53.	Silva, J; Gettings, R; Kostedt, W; Watkins, V. 2013. Pretreatment Targets for Salt
Recovery from Marcellus Shale Gas Produced Water. DCN CWT00354
54.	Schafer, Lee. 2010. SLIDES - A Working Model for Oil and Gas Produced Water
Treatment: Opportunities and Obstacles to Reducing the Environmental Footprint
of Natural Gas Development in Uintah Basin (October 14).
http://scholar.law.colorado.edu/reducing-environmental-footprint-of-natural-gas-
development-in-uintah-basin/7. DCN CWT00377
55.	Slutz, J; Anderson, J; Broderick, R; Horner, P. 2012. Key Shale Gas Water
Management Strategies: An Economic Assessment Tool. (September 11). DCN
CWT00355
56.	Stepan, D.J., et. al. 2010. Bakken Water Opportunities Assessment -Phase 1.
Energy & Environmental Research Center, University of North Dakota. Prepared
for National Energy Technology Laboratory. DCN CWT00356
57.	Tipton, Steven, Newfield Exploration. 2011. Mid-Continent Water Management
for Stimulation Operations. DCN CWT00357
58.	U.S. Congress, Office of Technology Assessment, 1992. Managing Industrial
Solid Wastes from Manufacturing, Mining, Oil and Gas Production, and Utility
Coal Combustion - Background Paper, OTA-BP-O-82. Washington, DC: U.S.
Government printing Office (February). DCN CWT00376
59.	U.S. DOE. 2009. Clark, C.E., and J.A. Veil. Produced Water Volumes and
Management Practices in the United States. (September). DCN CWT00014
60.	U.S. DOE. 2013. DOE Projects to Advance Environmental Science and
Technology. DCN CWT00207
61.	U.S. DOI. 2011. Katie Guerra, Katharine Dahm, and Steve Dundorf. Oil and Gas
Produced Water Management and Beneficial Use in the Western United States.
(September). DCN CWT00157
62.	U.S. EIA. 2015. Assumptions to the Annual Energy Outlook 2015. DCN
CWT00375
63.	U.S. EPA. 1976. Development Document for Interim Final Effluent Limitations
Guidelines and Proposed New Source Performance Standards for the Oil and Gas
Extraction Point Source Category. (September). DCN CWT00134
64.	U.S. EPA. 2010. Coalbed Methane Extraction: Detailed Study Report. DCN
CWT00002
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 5-Wastewater Characterization and Management
65.	U.S. EPA. 2013. Key Documents About Mid-Atlantic Oil and Gas Extraction.
Attachment 1 - Technical Supporting Documents. EPA-HQ-RCRA-1988-0069
DCN CWT00386.A01
66.	U.S. EPA. 2015a. Analysis of Hydraulic Fracturing Fluid Data from the
FracFocus Chemical Disclosure Registry 1.0. (March). DCN CWT00328
67.	U.S. EPA. 2015b. Site Visit Report: Southwestern Energy Fayetteville Shale Gas
Operations. Sanitized. DCN CWT00046
68.	U.S. EPA. 2016a. Discharge Monitoring Report (DMR) Pollutant Loading Tool.
Accessed on 6/17/2016. Available online at: http://cfpub.epa.gov/dmr/. DCN
CWT00135
69.	U.S. EPA. 2016b. Technical Development Document for Effluent Limitations
Guidelines and Standards for Oil and Gas Extraction. EPA-820-R-16-003. DCN
CWT00019
70.	U.S. EPA. 2017a. Anticline Sampling Episode Report. DCN CWT00161
71.	U.S. EPA. 2017b. Eureka Sampling Episode Report. DCN CWT00162
72.	U.S. EPA. 2017c. CBI_ Anticline Site-Specific Sampling Plan. DCN CWT00117
73.	U.S. EPA. 2017d. Sanitized Eureka Standing Stone Sampling and Analysis Plan.
DCN CWT00309
74.	U.S. Geological Survey (USGS). 2014. National Produced Waters Geochemical
Database v2.1 (Provisional) - Documentation. DCN CWT00129
75.	Volz, Conrad; Ferrar, Kyle; Michanowicz, Drew et. al. 2011. Contaminant
Characterization of Effluent from PA Brine Treatment Josephine Facility. DCN
CWT00359
76.	Warner et al. 2013. Impacts of Shale Gas Wastewater Disposal on Water Quality
in Western PA. Environmental Science & Technology 47(20): 11849-11857.
DCN CWT00360
77.	Williams, John. 2011. Marcellus Shale-Gas Development and Water-Resource
Issues. USGS: New York Water Science Center. DCN CWT00361
78.	Williams, John. n.d. The Marcellus Shale Gas Play: Geology, Development, and
Water-Resource Impact Mitigation. USGS: New York Water Science Center.
DCN CWT00362
79.	WY OGCC. 2015. Wyoming Oil and Gas Conservation Commission (WY
OGCC) Water Data Memorandum - Attachment 1: Raw Data from WY OGCC.
DCN CWT00363
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 5-Wastewater Characterization and Management
80.	Yoxtheimer, Dave. 2012. Flowback Treatment and Reuse Strategies for Tight Oil
Formations. Penn State Marcellus Center for Outreach and Research. DCN
CWT00364
81.	Ziemkiewicz, P. 2013. Water Quality Literature Review and Field Monitoring of
Active Shale Gas Wells. (February 15). DCN CWT00365
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
6. Wastewater Management Practices
CWT facilities that manage oil and gas extraction wastewaters use a variety of treatment
technologies, depending on characteristics of the wastewater received and the treatment
objectives. Facilities that treat oil and gas extraction wastewater for reuse treat the water so that
it is "just clean enough" to be reused in fracturing (Dale, 2013). This primarily consists of
disinfection, and removal of suspended solids (TSS), oil and grease, and other constituents that
can interfere with fracturing fluid chemicals, damage the formation, cause scaling down the
wellbore and in equipment, or otherwise interfere with well production and integrity. Over the
years, the oil and gas extraction industry has progressed toward the understanding that total
dissolved solids (TDS) removal is not necessary for reuse (ERG, 2014; Papso et al., 2010; Lord
et al., 2013; Horn et al., 2013). When treating for reuse, facilities typically use chemical
precipitation and/or filtration/flotation/sedimentation. These treatment techniques do not reduce
TDS.
At facilities that are treating water for discharge, the limitations in NPDES permits or
control agreements drive the selection of technology. Effluent limitations for individual
parameters may be based on categorical discharge limitations contained in 40 CFR 437 and/or
water-quality based effluent limitations (WQBELS), state derived limits, local limits, or other
regulatory requirements.
The following subsections present an overview of wastewater treatment technologies that
are applicable to the treatment of oil and gas extraction wastes and that are used at CWT
facilities managing these wastes. Information and data provided for each of the technologies
includes the process description, treatment costs, and vendors that EPA is currently aware of that
market the technology for the treatment of oil and gas extraction wastewater. In addition, EPA
provides treatment capabilities and limitations, including the ability to remove select pollutants
commonly found in oil and gas extraction wastewaters, including BOD, bromide, chloride, COD,
specific conductivity, sulfate, TDS, TSS, barium, potassium, sodium, strontium, benzene,
ethylbenzene, toluene, xylenes, sulfide, gross alpha radiation, gross beta radiation, radium 226,
and radium 228.
EPA estimated the pollutant removal efficiencies23, of these technologies using paired
influent and effluent concentrations (i.e., performance data) reported in literature, where
possible. Sampling data collected by EPA at two oil and gas wastewater treatment facilities are
also provided, if those facilities used that specific technology. If effluent concentration was
23 For purposes of this report, EPA calculates the removal efficiency of technologies as (influent concentration -
effluent concentration)/(influent concentration). Where an effluent value was reported as a non-detect, EPA
calculated the removal efficiency using the reported detection limit and qualified the removal efficiency with a ">"
indicator indicating that the removal efficiency was greater than the calculated value. The reported detection limit
was used in this report for calculating removal efficiencies specifically due to the variety of different data sources
referenced in Chapter 6. This approach using the detection limit may differ from other approaches used by EPA to
calculate removal efficiencies of technologies in other documents. In the remainder of this report, Vi of the detection
limit was used for calculations such as estimating the average effluent concentration and estimating pollutant loads
discharged at facilities based on DMR data.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-1

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Section 6-Wastewater Management Practices
reported as not detected, EPA used the reported detection level in calculating the removal
efficiency when possible.
6.1 Chemical Precipitation
6.1.1 Principle and Process Description
In chemical precipitation, chemicals are added to wastewater to change the physical
properties of dissolved and suspended pollutants, so they can be removed by settling, flotation,
or filtration. This is accomplished by adding a treatment chemical (precipitant) to the wastewater
that reacts with the targeted pollutant and forms an insoluble solid (precipitate). The insoluble
solids are suspended in the wastewater, then removed through settling, flotation, and/or filtration.
Chemical precipitation can be used to treat oil and gas extraction wastewater prior to reuse, or as
a component of a treatment train prior to discharge.
Table 6-1 lists some chemical precipitants and the pollutants they remove. In oil and gas
extraction wastewater applications, the targeted pollutants include TSS, multivalent cations, and
heavy metals (U.S. EPA, 2016c). The most commonly used chemical precipitants include
calcium hydroxide (i.e., lime) and sodium hydroxide (i.e., caustic soda). One of the underlying
principles dictating chemical precipitation design and operation is that a precipitate's solubility is
correlated to pH. Each precipitate has a different solubility at different pH ranges (Metcalf and
Eddy, 2003). As a result, a chemical precipitation operation involves careful control of pH to
optimize pollutant removal. Since different precipitates have different solubilities at different pH
levels, it may not be possible to remove all pollutants in a one-step precipitation process. To
maximize pollutants removed, multiple stages of precipitation may be necessary, using different
pH levels and chemical precipitants (U.S. EPA, 2000a).
Table 6-1. Chemical Precipitants and Targeted Pollutants
( Ih-iiiic;il Pivcipiliiiil
T;iriic(c
-------
Section 6-Wastewater Management Practices
EPA collected samples in September 2016 at Eureka Resources, where chemical
precipitation is part of its treatment train. The values reported for influent and effluent in Table
6-2 represent samples taken from storage tanks prior to and after treatment by chemical
precipitation. As can be seen from these data, certain trends are readily observable, such as the
lower effluent concentrations for n-hexane extractable material (HEM), barium and radium.
While the removal of barium and radium were expected, the system also produced notable
removal of HEM. Also to be expected is the relatively poor removal of the alcohols and the total
organic carbon (TOC). One other item of note is the apparent poor removal of strontium, a
component can be readily removed by this treatment process (additional data can be found in
U.S. EPA, 2017).
Table 6-2. EPA Chemical Precipitation Sampling Data at Eureka Resources
( onsliliionl
I nils
in riiioni
( OlllTIIII'illioil
1-1ITI ii i'ill
Co neon trillion
( iilciiliilod
Kcmo\;il r.lTicicno
HEM
mg/L
88.1
1.85
97.9%
SGT-HEM
mg/L
62.2
ND (1.18)
>98.1%
TOC
mg/L
829
424
48.9%
Barium
mg/L
11,000
3,280
70.2%
Strontium
mg/L
5,670
4,770
15.9%
DRO
mg/L
173
52.7
69.5%
TPH
mg/L
6.46
0.658
89.8%
Radium-226
pCi/L
10,300
2,170
78.9%
Radium-228
pCi/L
1,320
311
76.4%
Gross Alpha
pCi/L
5,900
1,320
77.6%
Gross Beta
pCi/L
6,000
1,160
80.7%
Ethanol
mg/L
31.8
15.6
50.9%
Methanol
mg/L
91.4
79.2
13.3%
ND—Not detected (number in parenthesis is sample detection limit, which was used to calculate removal
efficiency).
Source: U.S. EPA, 2017
While data are available in the literature on the performance of chemical precipitation in
managing industrial wastewater, a more limited dataset exists specifically for oil and gas
extraction wastewaters. For example, Acharya et al. (2011) conducted bench-scale treatability
tests of flowback water from wells in the Woodford shale in Oklahoma. The testing included
chemical precipitation using lime and soda ash (sodium carbonate). Results of these treatability
tests for pollutants of interest are shown in Table 6-3. Hayes et al. (2012) conducted full-scale
testing of treatment of wastewater from Barnett Shale wells in Texas. The testing included a
preconditioning step using caustic and polymer, with clarification in a lamella separator, with the
primary purpose being removal of iron. TPH was also reported to be removed, with the author
attributing this to co-removal with TSS. In addition, benzene, toluene, ethylbenzene, and xylene
(BTEX) removal was reported, likely through surface volatilization in the rapid mix tank. EPA
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-3

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Section 6-Wastewater Management Practices
did not present this data here because the report qualifies that the data were impacted by an upset
event. Papso et al. (2010) conducted chemical treatment and sedimentation of flowback fluid
from eastern Marcellus shale wells prior to reuse in fracturing operations. The primary purposes
of treatment were reducing scale-formers (such as iron), suspended solids and microorganisms.
Specific chemical additives were not identified by the authors. Reported reductions are presented
in Table 6-4.
A constituent in some oil and gas wastewaters is TENORM, from elements such as
radium. For example, Rowan et al. (2011) described high radium activity in Marcellus shale
waters up to 18,000 picocuries per liter. The three references described above do not provide
data on the performance of chemical precipitation in reducing radium concentrations. However,
there are other studies in the literature describing radium removal through chemical precipitation.
For example, Zhang et al. (2014) evaluated the equilibria and kinetics of co-precipitation of
radium with barium and strontium sulfate under varying ionic strength conditions that are
representative of brines generated during unconventional oil and gas extraction activities. Sivla
et al. (2012a) describes several approaches for pretreating produced water to reduce barium and
radium prior to evaporation and crystallization, including sulfate precipitation. In addition,
chemical precipitation for barium removal via sulfate precipitation (with co-precipitation of
radium) is a technology used at several of the CWT facilities that EPA reviewed as part of this
study.
Table 6-3. Bench-Scale Chemical Precipitation Data
( onslilncnl
I nils
in riiioni
C cuiceii 1 r:ilion
I'IITIiiciiI ( uncoillr;ilinn
( iilculiilod KoiikimiI
r.lTick'iio
11LM
ill-L
2,100
\D to;
99.
TOC
mg/L
18.4
6
67.4%
Barium
mg/L
30.7
0.147
99.5%
Strontium
mg/L
152
6.43
95.8%
Source: Acharya et al., 2011
ND—Not detected (number in parenthesis is sample detection limit, which was used to calculate removal
efficiency).
Table 6-4. Full-Scale Chemical Treatment Data
( oustiliienl
I nils
In riiicnl
( oniTiilr;ilion
I'IITIiiciiI ( onccnMillion
Reported Renin\;il
r.lTicicno
Barium
mg/L
596
43
93%
Calcium
mg/L
736
540
28%
Magnesium
mg/L
127
49
61%
Iron, total
mg/L
7.9
1.0
87%
Strontium
mg/L
228
174
25%
Source: Papso et al., 2010
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-4

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Section 6-Wastewater Management Practices
6.1.2.1 Residuals
Chemical precipitation generates sludge that is typically dewatered before landfill
disposal. Levels of radioactivity in treatment residuals from chemical precipitation vary
depending on the source of the wastewater and may exceed landfill acceptability limits,
depending on state regulations and applicable permits. For example, Zhang et al. (2014)
estimated that given an initial radium and barium concentration in produced water of 3,000
picocuries per liter and 685 mg per liter, respectively, the estimated level of radium activity in
precipitates would range from 2,571 to 18,087 picocuries per gram of barium sulfate precipitate
produced. TENORM limits for municipal waste landfills typically range from 5 to 50 picocuries
per gram (Zhang et al., 2014). While the radium activity calculated by Zhang et al. does not
correct for entrained water and other sulfates that would be expected to precipitate at a CWT
facility, the numbers are indicative of high activity measured in sludge. CWT operators at
facilities that EPA contacted or visited stated that it is common to screen residuals for
radioactivity prior to transport to landfills (U.S. EPA, 2014; U.S. EPA, 2012; ERG, 2012a; U.S.
EPA, 2015f; U.S. EPA, 2016b).
EPA found that CWT facilities typically operate barium sulfate precipitation systems
only to a level sufficient to meet discharge permit limitations, as more efficient operation can
result in the generation of sludge with radium activity exceeding landfill disposal thresholds.
With this in mind, more efficient removal of barium, radium and strontium from wastewaters
using sulfate precipitation may produce treatment residuals that are costly to manage. An
alternative is to use a treatment process that does not concentrate radium in sludge. Silva et al.
(2012) describe a modified lime-soda process that precipitates both barium and radium as
carbonates, which can then be treated with concentrated hydrochloric acid to produce a barium
and radium chloride solution that can be managed via underground injection.
Table 6-5 shows estimated sludge generation rates from chemical precipitation units
treating oil and gas extraction wastewater. In general, for properly designed and operated
facilities, higher influent wastewater TDS and TSS concentrations result in higher sludge
generation rates (Silva, 2012). The treatment systems associated with the data in Table 6-5 are
operated to remove barium, strontium, magnesium, calcium, radium, and TSS from oil and gas
extraction wastewater.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-5

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Section 6-Wastewater Management Practices
Table 6-5. Sludge Generation Rates from Chemical Precipitation Units Treating Oil
and Gas Extraction Wastewater
Tj pe of
Pivcipiliilion
I Milium IDS
( oiicoiili'iilioii
(m»/l.)
Inl'lui'iil l-'low
Kiilo
(l)|)d)
1 (Hill \\ iislo
(ii'iH'i'iilion
(Ions per d;i\)
\\ iislc (.encnKinn
(pounds per
hiirrcl ol°
\\;is(c\\;ikT
llVillO(l)
UiTi'ivncc
Caustic Addition
45,000 - 80,000
4,000 - 6,000
5-6
1.7-3
Hayes et al.,
2012
Lime-Soda
34,000 - 59,000
NR
NR
3.68-7.84
Acharya,
2012
Sulfate Precipitation
132,000
NR
NR
3.69-8.21
Silva, 2012
Lime-Soda
132,000
NR
NR
14.07-25
Silva, 2012
Modified Lime-Soda
132,000
NR
NR
1.49-8.23
Silva, 2012
Sodium Sulfate and Lime-
Soda
100,000
4,000
10-30
5-15
U.S. EPA,
2012
NR—Not Reported
6.2 Costs
Capital costs of chemical precipitation include costs for mixing tanks, a settling tank
(clarifier) and/or filtration system, chemical feed systems, piping, low-pressure pumps, and
monitoring equipment. Advanced monitoring equipment may be necessary to improve system
control and reliability. In addition, chemical precipitation may require investment for wastewater
equalization and storage (e.g., impoundments, tanks).
The operating costs associated with chemical precipitation include energy to operate low-
pressure pumps and mixers, chemical precipitants, and labor costs. Operating costs also depend
on the quality of influent wastewater and the desired quality of the effluent wastewater, which
will impact the type and quantity of the chemical precipitants and therefore the chemical cost.
One of the largest operating costs is the cost of the chemical precipitant. Another large operating
cost is sludge management and disposal.
Table 6-6 shows approximate capital and operating and maintenance (O&M) costs for
purchased or rented chemical precipitation treatment systems, as reported in the literature. Table
6-7 shows approximate costs incurred by oil and gas extraction operators for chemical
precipitation treatment of produced water at a CWT facility. One commercial CWT facility
stated that when influent TDS concentrations are higher than 150,000 mg/L, they charge
operators extra to cover the increased chemical demand (U.S. EPA, 2012).
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-6

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Section 6-Wastewater Management Practices
Table 6-6. Chemical Precipitation Capital and O&M Costs for Oil and Gas Extraction
Wastewater Applications
Vendor ;inri
Tcchnolo^
NsilllC
S\Mcm
Description
Cosl
liiisis
( ;ip;icil>
(MCI))
( iipiliil
Cos!
(S per iipd)
O&M Cost
(S per hhh
Kenliil or
r.l'l'ee(i\e Com
(S per hhl)-'
Reference
Fountain Quail
Water
Management,
LLC's Rover
Mobile
System
Rental
0.420
N/A
N/A
1.00-4.00
Hayes et al.,
2012; Hefley
etal.,2011
JS Meyer
Engineering
Mobile
System
NR
NR
NR
2.10
NR
JS Meyer
Engineering,
2015
Not Specified
Plant
Purchase
1.200
5 to 6b
NR
NR
U.S. EPA,
2015f
Not Specified
System
Purchase
NR
NR
0.15-0.30
<2.00
Acharya,
2011
Not Specified
Unit
Purchase
0.022
20.8
NR
0.50-3.00
URS, 2011
0.720
1.4
N/A—Not applicable; NR—Not reported
a Represents rental cost if the cost basis was rental and is inclusive of O&M. Represents total effective cost when
cost basis is purchase, which includes amortized capital costs and O&M costs combined. When the cost basis is
purchased, total effective cost is included only when a reference reported amortized capital costs.
b This is the estimated capital cost for the entire treatment plant. Costs for just the chemical precipitation treatment
system were not provided.
Table 6-7. Chemical Precipitation Costs at CWT Facilities
C\\ 1 l ;icili(> Nsime"
T\ pe of
Sen ice
( oninierciiil C\\ 1
Price for 1 rc;ilmcnl
(S per hhl)
Reference
Eureka Resources, LLC
Reuse Only
7 to 9b
U.S. EPA, 2012
Clean Streams, LLC
15 to 18b
U.S. EPA, 2014
Reserved Environmental Services, LLC
7°
ERG, 2012a
Nuverra Appalachian Water Services
4 to 7°
U.S. EPA, 2015d
Patriot Water Treatment
Discharge to POTW
3.36 to 21°
U.S. EPA, 2015e
NR—Not reported
a All facilities listed are located in the Appalachian Basin where Marcellus and Utica gas are produced.
b Cost of treatment.
0 Price quoted to users.
6.2.1 Vendors
Table 6-8 lists vendors of chemical precipitation technologies that EPA has identified that
offer treatment systems designed specifically for oil and gas extraction wastewater, along with
capacity information on available systems.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
Table 6-8. Chemical Precipitation Technology Vendors for Oil and
Gas Extraction Wastewater
Ycmlor
IVcliiioln;i\
N;inu'
Sjsk'in
Description
Sii rl'iicc
l-ociiprint (l'l:);i
( :i|)iicil>
(h|)(h
UtTcmuv
Anguil Aqua Systems
NR
NR
NR
NR
Anguil Aqua Systems,
2016
AquaTech International
Corporation
MoTreat
Mobile
System
Unit fits on
mobile trailer
1,700 -
6,900
All Consulting, 2011b
CoilChem, LLC
CoilChem
Mobile
System
640
20,000
ERG, 2016b
Fountain Quail Water
Management, LLC
Rover
Mobile
System
1,100
10,000
Hayes et al., 2012
Gradiant Corporation
Selective
Chemical
Extraction
Fixed
System
NR
12,000
Gradiant, 2016
JS Meyer Engineering
JSM
Mobile
System
NR
NR
JS Meyer Engineering,
2015
MI-SWACO
Frac Water
Reclamation
System
Mobile
System
NR
3,000
M-I SWACO, 2009
NR—Not reported
a Includes only the primary treatment unit, not storage for wastewater, chemicals, or sludge (solid waste).
6.3 Filtration/Flotation/Sedimentation
CWT facilities often use physical separation technologies including filtration, flotation,
and sedimentation to remove free oil and TSS. CWT facilities most often use
filtration/sedimentation/flotation to treat oil and gas extraction wastewater prior to reuse, or as a
component of a treatment train prior to other physical, chemical or biological treatment. In
addition, filtration or sedimentation is typically a component of a chemical precipitation system
to remove precipitates.
6.3.1 Principle and Process Descriptions
6.3.1.1 Filtration
Filtration works by routing wastewater through a porous media composed of rock, glass,
walnut shell, sand, or other suitable material to separate oil and suspended solids. Gravity,
centrifugal force, pressure, or a vacuum forces the wastewater through the media, which may be
a single fixed bed, multiple fixed layers, or a moving bed (U.S. EPA, 1998). Suspended solids
are trapped in the pores between the grains of the media (typically greater than 3 |im) and remain
as the water passes through. As the media filter captures increasing amounts of solids, the
pressure drop across the filter bed increases until it reaches a threshold at which point a
backwash cycle is used to remove the accumulated solids. Filter backwash is typically recycled
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
to the first unit of the treatment system, such as a sedimentation basin. Other filter types, such as
disposable bags or cartridges, do not use a backwash cycle and instead are replaced when spent.
Wastewater may also be filtered through ceramic or polymeric membranes using a
pressure differential. Membrane filtration systems include media with pore sizes 0.1-3 |im
(microfiltration), 0.01-0.1 |im (ultrafiltration), 0.01-0.001 |im (nanofiltration) and 0.001-0.0001
|im (reverse osmosis). Microfiltration removes conventional clays, humic acids, bacteria, algae,
cysts, and other suspended solids. Ultrafiltration also removes viruses, color, odor, and some
colloidal natural organic matter. Microfiltration and ultrafiltration require trans-membrane
pressure of 1-30 pounds per square inch (psi) to operate (Colorado School of Mines, 2009).
Nanofiltration fills the gap between ultrafiltration and reverse osmosis, operating at intermediate
pressures to remove multivalent ions and small molecules. Reverse osmosis operates at applied
pressures ranging from 250 to 1,180 psi to push water through the membrane while blocking ions
and other dissolved material (TDS) from passing (Hayes, 2004). Reverse osmosis for TDS
removal is described in Section 6.6 and not further discussed in this section.
Many applications for oil and gas extraction wastewater treatment use multiple stage
filtration where each subsequent stage uses a smaller pore size than the previous stage to
optimize performance. For example, one facility that EPA visited treats oil and gas extraction
wastewater using 100, 50, 25, and 10-micron filters sequentially to remove suspended solids
(U.S. EPA, 2014). In addition, at another facility, an operator reported they use 100 followed by
20-micron filters prior to reuse (U.S. EPA, 2015b).
6.3.1.2	Sedimentation
Sedimentation removes suspended solids by gravity settling. Sedimentation works by
adjusting holding times, either by batch process or controlled flow through an impoundment or
tank, that provides sufficient time for suspended solids to settle to the bottom. Dispersed oil and
grease may also float to the surface for simultaneous removal. Various tank configurations, such
as inclined plate settler or lamella clarifier can be used to increase efficiency. Sedimentation is
most effective in removing suspended solids with specific gravities significantly greater than 1.0.
6.3.1.3	Flotation
Gas flotation is the process of using fine bubbles to induce oil and suspended particles to
rise to the surface of a tank where they can be collected and removed. Gas bubbles are
introduced into the wastewater and attach to the particles. With the bubbles and particles
attached, the effective specific gravity of the two combined is less than that of water, allowing
the suspended particles to rise to the surface with the bubbles (U.S. EPA, 1998). The gas bubbles
are typically air, nitrogen, or other inert gases (Colorado School of Mines, 2009).
Two categories of gas flotation technologies are used to treat oil and gas extraction
wastewater: dissolved gas flotation and induced gas flotation. These two categories differ by the
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
method used to create the bubbles. Consequently, the bubble sizes differ for each method
(Colorado School of Mines, 2009).
•	Dissolved Gas Flotation - Gas is injected into wastewater in a pressurized retention tank or
pipe, allowing the gas to dissolve into the wastewater. When the wastewater enters the
flotation tank, the pressure is reduced, causing fine air bubbles to be released.
•	Induced Gas Flotation - Bubbles are generated or injected near the bottom of the flotation
unit by mechanical means such as a propeller or diffuser.
6.3.2 Capabilities and Limitations
Filtration/sedimentation/flotation technologies primarily remove suspended solids and
dispersed oil and grease (Colorado School of Mines, 2009; U.S. EPA, 2015a). EPA identified
one reference with performance data for filtration in oil and gas extraction applications
(Ziemkiewicz et al., 2012). In this study, bench-scale testing was first done to evaluate different
filter media. Performance data from the bench-scale testing for pollutants of interest is shown in
Table 6-9. The table includes untreated influent pollutant concentrations, effluent pollutant
concentrations, and the calculated pollutant removal efficiencies. A full-scale 5,000 barrels per
day multi-media filtration mobile treatment unit was then evaluated using mixtures of Utica and
Marcellus produced waters along with other sources such as collected rain water. The goal of the
treatment was to provide treated water for reuse in fracturing operations. Demonstration-scale
performance data for this system for one site treating Marcellus flowback water was reported
which showed a TSS reduction from 360 to 244 mg/L or 32% reduction.
Table 6-9. Bench-Scale Filtration Treatment Performance Data
( niiMilui'iil
in riii cm
( oiKTiilmlion
(mji/l.)
KITIiicnl ( oiKTiilriilion
Uiiniic
(mii/l.)
( iilculiilod KciikimiI l.lfickno
<"»)
Barium
172 - 2,290
93 - 1,520
34-56
TSS
99 - 882
81 -681
20-23
Sulfate
0-414
0-101
0-76
Source: Ziemkiewicz et al., 2012
Note: EPA used the reported detection level in calculating the removal efficiency when value was reported.
Flotation demonstrated the following removal efficiency when treating oil and gas
extraction wastewater on multiple scales (e.g., bench and field) (Colorado School of Mines,
2009):
•	Oil and grease: 93 percent removal efficiency;
•	Chemical Oxygen Demand (COD): 75 percent removal efficiency; and
•	Suspended solids: Removal of suspended solids down to 25 microns in size.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
6.3.2.1 Residuals
Filtration
As noted earlier, solids collected in the filtration media during filtration periodically need
to be removed to restore optimum removal efficiency. This can be achieved by backwashing the
filter, with the backwash water typically recycled to the treatment system inlet, or by replacing
and disposing the filter bag or cartridge. A small fraction of wastewater may be lost during
backwash cycles or entrained in sludge (Colorado School of Mines, 2009). With bag or cartridge
filters, once the filter capacity is spent, the bag or cartridge is typically disposed of in a landfill.
Sedimentation
The frequency with which solids must be removed from a sedimentation basin depend
upon concentration in the influent. But regardless of the concentration, at some point solids must
be removed from the bottom of the basin. In cases where solids must be removed from an
impoundment, they are typically dredged from the bottom of the impoundment on a periodic
basis and disposed of offsite, commonly at a landfill. With lamella clarifiers, solids are removed
from the bottom of the clarifier and dewatered prior to disposal, usually by landfilling. Typically,
all the influent is recovered as treated wastewater. However, some volume may be entrained in
sludge or, depending on the region, lost to evaporation (Colorado School of Mines, 2009).
Flotation
During flotation, air bubbles, particulates, and free oil droplets form foam on the surface.
This foam may be skimmed off for disposal. Note that flotation does not remove soluble oil
constituents, which remain in the effluent (Colorado School of Mines, 2009). Free oil, if present
in sufficient quantity and quality, can be separated and sold.
6.3.3 Costs
Capital costs of filtration, sedimentation, and flotation include costs for settling tanks,
basin liners, pressurized gas tanks, piping, low-pressure pumps, monitoring equipment,
membrane systems, and filters. Operating costs associated with filtration, sedimentation, and
flotation include energy to pump water and pressurize the system, replacement filters, additive
chemicals, disposal of generated solids, and labor costs.
Table 6-10 shows approximate capital and O&M costs for purchased or rented flotation,
sedimentation, and filtration treatment systems, as reported in the literature. One facility (Clean
Streams, LLC) reported that oil and gas extraction operators paid CWT facilities $1.00 per barrel
to treat oil and gas extraction wastewater with 100,000 mg/L TDS for reuse using filtration,
sedimentation, and flotation treatment (U.S. EPA, 2014).
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Section 6-Wastewater Management Practices
Table 6-10. Filtration/Sedimentation/Flotation Capital and O&M Costs for Oil and
Gas Extraction Wastewater Applications
Ti-iliiiiilu»\
Yi'iuliir
( iisl li;isis
(MCI))
C;i|)il;il
ClISl
(S |KT
(MiM Cusi
(S |kt l);irivl)
Ki'iihil in-
Kl'IWliw Cusi (S
|kt l);irivl)
kll'l'IVIHl'
Filtration
NR
Purchase
0.025
12.00
Low
NR
URS, 2011
Sedimentation
NR
Purchase or
Rental
0.63
NR
NR
0.15-0.40
Smith, 2014
Gas Flotation
Purestream
Purchase or
Rental
0.11
2.40-3.80
NR
0.50
Purestream,
2011; U.S. EPA,
2013b
NR—Not reported; MGD—million gallons per day; gpd—gallons per day; bbl—barrels.
" Capital costs are based on the MGD capacity of the facility.
b Represents rental cost if the cost basis was rental and is inclusive of O&M. Represents total effective cost when
cost basis is purchase, which includes amortized capital costs and O&M costs combined.
6.3.4 Vendors
Table 6-11 lists vendors of filtration, sedimentation, and floatation technologies that EPA
has identified that offer treatment systems designed specifically for oil and gas extraction
wastewater.
Table 6-11. Filtration/Sedimentation/Flotation Technology Vendors for Oil and
Gas Extraction Wastewater
Yemlor
Tcchnolo<^
Tcchnolo*^
N;i mo
Sii rl';icc
l-'ooiprinl (ll-f
( :i|):icil> (l)|)d)
Reference
Anguil Aqua
Systems
Sedimentation13
NR
NR
NR
Anguil Aqua Systems,
2016
FilterSure
Media Filtration
NR
Trailer mounted
5,000
Ziemkiewicz, 2012
Purestream
Gas Flotation
IGF and IGF+
Trailer mounted
2,500
U.S. EPA, 2013b
NR—Not reported; IGF—induced gas flotation separator; IGF+— induced gas flotation separator plus.
a Only includes the primary treatment unit, not storage for wastewater, chemicals, or sludge (solid waste).
b This vendor offers a chemical precipitation treatment technology that incorporates tube settlers into the process.
6.4 Evaporation/Condensation
Evaporation/condensation is used by CWT facilities to separate high TDS wastewater
into distilled water and concentrated brine. Evaporation/condensation may be used when very
pure treated water is desired (e.g., to meet requirements for discharging to streams or POTWs)
(Metcalf and Eddy, 2003) or when costs for alternative disposal are high (e.g., in the Marcellus
because of limited availability of disposal wells) (U.S. EPA, 2012, Colorado School of Mines,
2009, U.S. EPA, 2015a; Kasey, 2009). Evaporation/condensation is also useful where TDS
exceeds approximately 50,000 mg/L, as other TDS removal technologies such as reverse osmosis
become ineffective (see Section 6.6). At higher TDS concentrations, evaporation/condensation
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
remains an effective treatment process, especially if low-cost energy is available (e.g., waste heat
or waste methane from co-located facilities).
6.4.1 Principle and Process Description
The evaporation/condensation treatment process removes water from wastewater through
evaporation (converting liquid to vapor), reducing the wastewater volume and concentrating
wastewater pollutants in the brine. The evaporated water vapor is either vented to the atmosphere
or condensed as a clean distillate/condensate. For evaporation to occur, the liquid water
molecules at the surface must have vapor pressure greater than the vapor pressure of the
surrounding gas. Most of the pollutants present in the wastewater are unable to evaporate.24 As a
result, they remain in the wastewater that has not evaporated, creating concentrated brine. As
evaporation continues, the pollutants in the brine become more concentrated. When pollutant
concentrations reach their solubility limits, dissolved material will precipitate out of the
concentrated stream (which is not desired for normal operation).
Evaporation/condensation technologies differ in the method used for evaporation. For
vapor pressure to become greater than atmospheric pressure, vapor pressure can be increased,
atmospheric pressure can be decreased, or both. Factors used to increase the rate of evaporation
for wastewater treatment are listed below:
•	Pressure - If atmospheric pressure decreases, the rate of evaporation increases. This can be
accomplished by technologies that operate under partial vacuum.
•	Temperature - As temperature increases, the rate of evaporation increases. This can be
accomplished using technologies that increase the temperature of the wastewater.
•	Surface Area - As the surface area of the water that is in contact with the air increases, the
rate of evaporation increases. This can be accomplished by spraying the wastewater into
droplets.
•	Air Movement - As the flow rate of air at the liquid surface increases, the rate of
evaporation increases. This can be accomplished using fans to push or pull air through the
unit.
Three types of evaporation/condensation processes are used for oil and gas extraction
wastewater treatment: vapor compression; multiple stage flash and multiple effect; and rapid
spray. A discussion of each type follows.
24 Some pollutants, such as solvents and light hydrocarbons, may evaporate along with the water vapor. These may
pass through the treatment or be recovered using a hydrocarbon recovery unit.
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Section 6-Wastewater Management Practices
6.4.1.1	Vapor Compression (VC) Evaporation/Condensation
Two types of vapor compression processes are mechanical vapor compression (MVC)
and thermal vapor compression (TVC). The difference between these two types is how the water
vapor pressure is increased. MVC primarily uses a mechanical compressor25 to add energy into
the system, while TVC uses a heat source to add energy, such as a gas burner. Both types of
vapor compression technologies are used in oil and gas extraction wastewater applications, but
mechanical compressors have some advantages:
•	Mechanical compressors start up more quickly, run on electricity, and are less expensive than
thermal vapor compression (U.S. EPA, 2012).
•	Thermal vapor compression requires a closed loop system consisting of a working fluid (e.g.,
steam, oil) and boiler. This configuration increases the overall size of the system.
6.4.1.2	Multiple Stage Flash (MSF) and Multiple Effect (ME)
Evaporation/Condensation
In MSF and ME evaporation/condensation, the main evaporation vessel operates at
reduced pressure to facilitate evaporation. When the pressure decreases, preheated wastewater
can be evaporated at temperatures lower than 212 0 F (Colorado School of Mines, 2009). The
primary difference between MSF and ME evaporation/condensation is that the reduced pressure
and high temperatures are carried out in separate vessels in ME evaporation, but in only one
main vessel in MSF evaporation. Although decreasing the pressure requires energy input, less
energy is then required to increase the temperature of the influent wastewater.
6.4.1.3	Rapid Spray (RS) Evaporation/Condensation
In RS evaporation, wastewater is evaporated by spraying it in small droplets into a heated
air stream. The evaporation generates water vapor and concentrated brine as with other
evaporation technologies. The specific configuration differs by manufacturer, but in a typical
system the exhaust/brine mixture enters an entrainment separator where the concentrated brine is
separated from the exhaust and drains into a sump located under the separator. A sump pump
transfers brine and solids from the sump to a thickener tank, where salt solids/brine settle to the
bottom and are removed, while the lower-density supernatant liquid (lower salt content) is
recycled back to the evaporator section. The supernatant recycle rate is adjusted to achieve the
target brine salt concentration. Water vapor (steam) is typically released directly to the
atmosphere from the separator. However, as an option, the steam can be routed to a shell and
25 Mechanical vapor compression also typically includes a heat source (e.g., a gas-fired boiler) but it only operates
during startup operations and then periodically during steady state operation. The boiler runs approximately two
percent of operational time, according to one CWT operator (U.S. EPA, 2012a). Because mechanical vapor
compression does not rely on heat, it does not require steam or a boiler, making MVC more suitable for mobile
treatment units than TVC.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
tube heat exchanger to condense it into distillate. Cooling water for the heat exchanger is
provided by wastewater feed.
6.4.2 Capabilities and Limitations
6.4.2.1 Targeted Pollutants and Treatment Effectiveness
Evaporation/condensation technologies can remove a wide range of wastewater
pollutants, including suspended solids, dissolved organic matter, dissolved inorganic matter,
biological contaminants (e.g., bacteria and viruses), and radioactive elements (Metcalf and Eddy,
2003). With respect to oil and gas extraction wastewaters, evaporation/condensation can be used
to concentrate anions such as chloride and bromide, and metals such as barium, boron, calcium,
iron, lithium, potassium, sodium and strontium into the brine solution, resulting in significant
reductions in TDS in the treated effluent.
Typical influent TDS concentrations for cost effective operation can range from 20,000
mg/L to 125,000 mg/L, and effluent concentrations can be less than 10 mg/L (U.S. EPA, 2012;
U.S. EPA, 2015a; All Consulting, 201 lh; Colorado School of Mines, 2009). Influent TDS
concentrations, in theory, can be as high as the supersaturation concentration for TDS
(approximately 300,000 mg/L),26 but at the expense of higher energy input and lower distilled
water recovery. One CWT facility that uses evaporation/condensation suggested that the
economics of the technology become unfavorable when TDS concentrations reached 125,000
mg/L (U.S. EPA, 2012). Case studies in the literature demonstrate that evaporation/condensation
units can operate with TDS concentrations as high as 195,000 mg/L (Bruff, 2011). The Heartland
Technologies Partners (Heartland) low momentum - high turbulence (LM-HT®) Concentrator is
able to treat water with TDS concentrations of up to 235,000 mg/L (U.S. EPA, 2015c).
Constituents with evaporation temperatures lower than water could evaporate and exit the
system in the water vapor stream. Examples include ammonia (U.S. EPA, 2015a) and light
hydrocarbons (ERG, 2012a). Light hydrocarbons can be separated from the water vapor using a
dedicated recovery unit prior to water vapor condensation. The hydrocarbons recovered from this
add-on unit have the potential to be sold (ERG, 2012a).
EPA identified two references with field-scale performance data on evaporation/
condensation of oil and gas extraction wastewaters. The first (Bruff, 2011) evaluated the
performance of an Altela ARS-4000 thermal distillation system treating Marcellus well
wastewater. This study included both bench-scale and field-scale testing. In the field-scale
testing, the system was operated from August 2010 through April 2011. Pretreatment prior to the
evaporation system consisted of a 100-micron bag filter to remove suspended solids.
Performance data for pollutants of interest are presented in Table 6-12. These results are
calculated averages from four reported sampling events. The system demonstrated removal of
26 This is the approximate supersaturation concentration for sodium chloride, the primary component of TDS found
in oil and gas extraction wastewater. Several vendors indicated that supersaturation occurs at approximately 300,000
mg/L TDS (Mertz, 2011; ERG, 201 Id; Wilson, 2011).
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
TDS and chloride, COD, barium and strontium, radium, bromide and acetone. A second
reference (Hayes et al., 2012) evaluated the performance of an MVR system treating shale gas
wastewater from wells in the Barnett Shale in Texas. Water samples were collected twice weekly
during a 60-day period in 2011, yielding 18 days of samples. Pretreatment prior to the MVR
consisted of clarification using caustic as well as addition of anti-foam agents and corrosion
control and a five-micron bag filter. Performance data from the system for pollutants of interest
is presented in Table 6-13. Influent data were collected after the clarifier and bag filter, and the
paper presented median influent data collected from a combined dataset from three MVRs
operated at the site. EPA calculated that the MVR system achieved a 99% reduction in TDS, a
98% reduction in barium, a 95% reduction in BTEX and a nearly 100% reduction in strontium.
Table 6-12. Treatment Performance Data, Thermal Distillation
( cinslitiienl
I nil
\\cr;ilic In I'll Kill
( OIHTIIII'illioil
A\er;iiic I.ITIikiK
('uiici'iilr;iliuii
( iilculiilcd A\emtio
Rcino\;il r.fl'ick'iio
IDS
ill-L
:~,89i
loo
99.4" u
TSS
mg/L
66
3
94.6%
COD
mg/L
280
36.4
86.7%
Chloride
mg/L
12,256
75.2
99.3%
Sodium
mg/L
5,772
34.6
99.3%
Barium
mg/L
321
1.9
99.3%
Strontium
mg/L
299
1.6
99.3%
Gross Alpha
pCi/L
357
2.4
99.0%
Gross Beta
pCi/L
323
0.7
99.4%
Radium 226
pCi/L
150
1.4
99.0%
Radium 228
pCi/L
59
0.6
98.8%
DRO
mg/L
5
2.8
38.7%
Bromide
mg/L
125
0.7
99.4%
Acetone
mg/L
10,958
576
94.9%
Source: Bruff, 2011
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Section 6-Wastewater Management Practices
Table 6-13. Treatment Performance Data, MVR

Modiiin liifliiciil
Modiiin 1. HI u on (


( <>iiiTiilr;ilioii
( <>iiiTiilr;ilioii
( iilciiliiK'ri KciikimiI
Coiisiiiiioiil
(iiiii/l.)

I'llTicieiio
Ammonia
84
64
23.8%
Barium
6
0.1
98.3%
Boron
16
0.4
97.5%
BTEX
2.1
0.1
95.2%
Calcium
2,705
0.8
100%
Iron
2
0.1
95.0%
Lithium
11
0.1
99.1%
Magnesium
296
0.1
100%
Phosphorous
2
0.1
95.0%
Potassium
349
0.1
100%
Sodium
12,100
3.6
100%
Strontium
483
0.1
100%
Sulfates
205
5
97.6%
TDS
46,900
103
99.8%
TPH
4
4
0%
TSS
132
4
97.0%
Source: Hayes et al., 2012
Note: EPA used the detection level in calculating the removal efficiency when value was reported.
6.4.2.2	Design and Operation Considerations
One of the challenges with evaporation/condensation is the tendency for heat exchange
surfaces (e.g., piping) to lose their heat transfer quality due to scaling. When these surfaces have
diminished heat transfer capabilities, more energy input is required, making the overall process
less energy efficient. Scaling occurs when inorganic salts precipitate onto pipes and equipment.
Major contributors to scaling are salts of multivalent cations (e.g., calcium, barium, magnesium).
Prior to evaporation/condensation, oil and gas extraction wastewater is typically
pretreated by chemical precipitation and filtration to reduce scale-causing constituents, which are
present in high concentrations. Rigorous pretreatment can be avoided if the
evaporation/condensation unit is operated at higher than atmospheric pressures, as increased
pressure allows inorganic salts to remain dissolved in the water at higher temperatures, reducing
the tendency for scaling (Mertz, 2011; URS, 2011). One exception is the Heartland LM-HT®
technology that is designed to operate at supersaturated concentrations without the need for
pretreatment or operating under pressure (U.S. EPA, 2015c).
6.4.2.3	Residuals
Evaporation/condensation processes generate a concentrated brine stream. Because
chemical precipitation is typically used for pretreatment in oil and gas extraction applications, a
solid waste stream will also be generated (see 6.1 for solid waste generation from chemical
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
precipitation). Both Bruff, 2011 and Hayes, 2012 include data on constituent concentrations in
the concentrated brine generated by evaporation/condensation. The concentrated brine stream
contains all the salt products contained in the influent water, but at higher concentrations than the
influent. This includes any radioactive elements present in the influent wastewater that are not
removed by pretreatment. The brine can be managed in several ways. Options may include:
•	Injection into a disposal well;
•	Use as well kill fluid;
•	Use as additive for drilling fluid; and
•	Further treatment via crystallization (U.S. EPA, 2012; U.S. EPA, 2014; URS,
2011).
6.4.2.4 Energy Use
Evaporation/condensation is an energy-intensive treatment technology. TVC systems
require a burner or boiler (Colorado School of Mines, 2009). MVC units require compressors
that run on electricity (Mertz, 2011); however, most MVC systems still require a small boiler or
burner to assist in startup operations (U.S. EPA, 2012). In some field applications, electricity is
generated using natural gas fired generators that use gas produced at the well site.
Evaporation/condensation systems can be designed to use waste or low-grade energy.
One example was the CARES facility near Mt. Jewett, Pennsylvania that treated oil and gas
extraction wastewater (CARES, unknown date). This facility was adjacent to the McKean
County landfill and used landfill gas27 to power specifically-designed boilers to generate steam
for their AltelaRain® treatment system (NETL, unknown date). Another source for low-grade
energy in oil and gas extraction wastewater applications is waste heat from compressor stations
(e.g., as is used at the Heartland LM-HT® system located in Covington, PA) (Heartland
Technology Partners, 2014; U.S. EPA, 2015c).
Table 6-14 reports energy usage per barrel of influent wastewater for some pilot- and
full-scale projects using evaporation/condensation to treat oil and gas extraction wastewater.
Table 6-14 includes the associated influent TDS concentrations of the wastewater being treated
and resulting water recovery percentages. Since many of the units require both electricity and
some type of fuel, the energy requirement is presented in three columns: electrical (e.g., pumps,
compressors), fuel (e.g., natural gas for a burner), and the total energy required, if reported.
27 Landfill gas is low-grade natural gas (approximately 52 percent methane) produced from decomposition of
organic materials within the landfill.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-18

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Section 6-Wastewater Management Practices
Table 6-14. Evaporation/Condensation Influent TDS Concentration, Energy Consumption, and Water Recovery





r.iu-r»\ ( iiiisiinipiiiui



I'ilul- tir
I'ull-Siiik-
I'niji-il
Vi-mlnr
Ti-ihimlfir;ilnr
' > lK"
lnlliK'iil I DS
('iiiuviilniliiiii
(111^/1.)
(k\\ h/l)l)l)
I'lii-I
(M( 1 )
luliil
(k\\ h/l)l>l)
\\ iik-r
kl-l lH l'l'\
Co)
Pi HUT
Si ill I'l l"
lii'l'i- ri'ii ii-

Purestream
AVARA
Mechanical
Vapor
20,000-40,000
6
N/A
6
80
Electrical
U.S. EPA,
2015a

212 Resources
Vacom
Multiple Effect
-30,000
1.3
NR
1.3
90
Electricity or
Wellhead Natural
Gas
Colorado
School of
Mines, 2009;
Mertz, 2011
Full-Scale
Project
Fountain Quail Water
Management, LLC
NOMAD
Mechanical
Vapor
60,000-80,000
NR
0.07
4.6
60-90
50 kW Generator3
Hayes et al.,
2012;
Roman,
2011

Heartland Technology
Partners
LM-HT®
Rapid Spray
Up to 235,000
NR
NR
NR
NR
Uses Waste Heat
from Compressor
Stations or Runs
on Natural Gas
Heartland
Technology
Partners,
2014; U.S.
EPA, 2015c

NR
NR
Mechanical
Vapor
110,000-130,000
NR
NR
6.5-7.5
50
Wellhead Gas
Generator
Shaw, 2011

Altela Inc.
AltelaRain™
Multiple effect
25,300-195,000
2-2.5
5-10
NR
45-90
Electricity, Natural
Gas, Onsite Waste
Heat, Solar Panels
Bruff, 2011
Pilot-Scale
Project
GE Water & Process
Technologies
NR
Mechanical
Vapor
<128,000
NR
NR
2.1-2.9
60-95
Electricity or
Natural Gas
Colorado
School of
Mines, 2009;
Wilson,
2011
N/A—Not available; NR—Not reported; mg/L—milligrams per liter; MCF—million cubic feet; kWh— kilowatt-hour; bbl— barrel.
" Runs on natural gas directly from well head or electricity.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-19

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Section 6-Wastewater Management Practices
6.4.3 Costs
Capital costs of evaporation/condensation include costs for the pretreatment system, the
evaporation/condensation unit, low-pressure pumps, and monitoring equipment. Operating costs
include energy for low-pressure pumps, energy for evaporation, brine management and disposal,
and labor (Wilkerson, 2013; Dale, 2013). The technology is energy-intensive; however, several
studies concluded that if waste heat (e.g., low-grade steam or low-grade natural gas) is used, the
technology remains effective and cost is significantly reduced (Beckman, 2008, Colorado School
of Mines, 2009, Bruff, 2011).
Table 6-15 shows approximate capital and O&M costs for evaporation/condensation
reported in the literature for purchased and rented treatment systems. The costs do not include
pretreatment systems such as precipitation and filtration. Table 6-16 shows approximate prices
charged by three CWT facilities that use(d) evaporation/condensation and the TDS concentration
of the influent water that the evaporation/condensation system treated. All of the facilities use
electricity or natural gas to power the evaporation/condensation treatment unit.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-20

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Section 6-Wastewater Management Practices
Table 6-15. Evaporation/Condensation Capital and O&M Costs for Oil and Gas
Extraction Wastewater Applications
Yi-nriiir iiiul
Ti-ihniiln»\
Niiiiu-
S\sk-I11
Ih'siTiplion
Inl'liii'iil I DS
('oiHvnlmlion
(m"/!.)-1
I nil
(MCI))
Ciisl
Ifcisis
C;i|)il;il
Ciisl
(S |KT »|)ll)
O&M C ost
(S |KT 1)1)1)
Ki'iihil hi*
I'.ITi'iliv i'
Cusl
(S |KT 1)1)1)''
Ki-li-muv
AltelaRain
Plant
25,300-
195,000
NR
Purchase
8
0.14-0.89
5.24
Bruff, 2011
212 Resources
Plant
-20,000
0.168
Purchase
30
0.30-0.50°
3.00-5.00
212 Resources,
2011; ERG, 2012a;
Mertz, 2011
Heartland
Technology
Partners LM-
HT®
Plant
235,000
0.03
Purchase
93 to 127
2.0-3.0
NR
Heartland, 2014;
U.S. EPA, 2015c
Fountain Quail
NOMAD
Plant
45,000 -
80,000
0.315
Purchase
NR
NR
2.57-4.50
Hayes etal., 2012;
Jay, 2008; U.S.
EPA, 2013a
Mobile
system
NR
0.105
Purchase
38
0.94
5.00-6.00
Hefley, 2011
NR
Mobile
system
110,000-
130,000
0.060
Purchase
100
2.40
5.40
Shaw, 2011
Purestream
Mobile
System
NR
0.053
Purchase
22 to 44
1.29
2.00-3.00
Purestream, 2011;
U.S. EPA, 2013b
GE
Mobile
system
<128,000
0.072
Purchase
or Rental
34
NR
2.50-6.50
Purestream, 2011.
U.S. EPA, 1998,
ERG, 2016c
NR—Not reported
a Data are sampling data/characteristic of source water from each reference.
b Represents rental cost if the cost basis was rental and is inclusive of O&M. Represents total effective cost when
cost basis is purchase, which includes amortized capital costs and O&M costs combined. When the cost basis is
purchased, total effect cost is only included when a reference reported amortized capital costs.
0 Electricity costs only.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-21

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Section 6-Wastewater Management Practices
Table 6-16. Evaporation/Condensation Costs at CWT Facilities
CWT l iicili(>
N;i mo
( lean Siicams.
LLC a
Tro;ilo(l
W iislowiilor
Shale (ias
In I'lii on 1 IDS
( (iiiooiili'iilion
(inii/l.)
|00.000
Tj po of
Son ioo
Reuse
Prioo for
Tro;ilmonl
(S por hhl)
(. S 25
Yosir of
Cosl
2<) 12
Uoforonoo
i s \.\>\, :


-------
Section 6-Wastewater Management Practices
6.5 Crystallization
Crystallization converts high TDS wastewater into distilled water (low TDS) and solid
salt crystals. Unlike evaporation/condensation that generates concentrated brine, as described in
Section 6.4, crystallization can be used as a zero-liquid discharge (ZLD) technology if the
distilled vapor is vented, rather than condensed. This technology may also be used for treating oil
and gas extraction wastewater when very pure treated water is desired (e.g., to meet requirements
for discharging to streams or POTWs) (Metcalf and Eddy, 2003) or when costs for alternative
disposal are high (e.g., in the Marcellus because of limited availability of disposal wells) (U.S.
EPA, 2012, Colorado School of Mines, 2009; U.S. EPA, 2015a; Kasey, 2009).
6.5.1	Principle and Process Description
Crystallization is similar to evaporation/condensation. Both technologies evaporate water
from wastewater by manipulating temperature and pressure. Crystallization differs from
evaporation/condensation in that sufficient water is evaporated that the brine stream becomes
"supersaturated" with salts, causing the salts to precipitate out of the solution, forming solid salt
crystals (Colorado School of Mines, 2009).
In crystallization systems designed for oil and gas extraction wastewater treatment, the
evaporated water vapor is either recovered through condensation or vented into the atmosphere.
According to the literature, both MVC and TVC technologies are used. EPA is also aware of one
facility that uses RS technology for crystallization (see the description of the Heartland LM-HT®
Concentrator in Section 6.4.2).
6.5.2	Capabilities and Limitations
6.5.2.1 Targeted Pollutants and Treatment Effectiveness
Crystallizers are capable of treating oil and gas extraction wastewaters with extremely
high TDS concentrations (All Consulting, 201 lg). Crystallization treatment technologies operate
most efficiently when the influent wastewater is already near its supersaturation concentration
for TDS (300,000 mg/L for sodium chloride). EPA did not identify detailed data in the literature
on pollutant removal for crystallization. Given the similarity of the process to evaporation/
condensation, pollutant removal for crystallization is also likely similar (see Section 6.4).
Evaporation/condensation typically produces effluent (condensate) TDS concentrations of less
than 50 mg/L (All Consulting, 201 lg).
EPA collected samples in September 2016 at Eureka Resources, which incorporates
crystallization as part of its treatment train. Table 6-18 shows the EPA crystallization sampling
data collected at this facility for select pollutants of interest. As can be seen from these data, the
crystallization removed constituents found in oil and gas extraction wastewaters, including
bromide, COD, TOC, barium, strontium, boron, TDS, chloride, and radium 226 and 228. In
addition, the alcohols ethanol and methanol increased in concentration after crystallization since
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-23

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Section 6-Wastewater Management Practices
these components evaporate and exit the system in the water vapor stream. Additional
performance data can be found in U.S. EPA, 2017.
Table 6-18. EPA Crystallization Sampling Data at Eureka Resources
Coiisiiiiioiil
I nils
Inl'lui'iil
( (iiK'oiilriilion
I'llTliicnl
C cinceii 1 i';ilion
( iilciiliilcd Kcmo\:il
ll'lick-no
Bromide3
mg/L
796
0.186
100%
Bromideb
mg/L
882
ND (NR)
NC
Bromide0
mg/L
855
ND (NR)
NC
COD
mg/L
12,500
ND (895)
>93%
TOC
mg/L
424
121
71.5%
Barium
mg/L
3,280
0.837
100%
Strontium
mg/L
4,770
0.966
100%
DRO
mg/L
52.700
17.7
66%
TPH
mg/L
0.658
0.341
48.2%
Ra-226
pCi/L
2,170
0.550
100%
Ra-228
pCi/L
311
ND (1)
100%
Gross Alpha
pCi/L
1,320
3.00
100%
Gross Beta
pCi/L
1,160
ND (4)
100%
TDS
mg/L
187,000
14.3
100%
Ammonia
mg/L
147
41.1
72.0%
Chloride
mg/L
102,000
11.4
100%
Sulfate
mg/L
127
0.583
100%
Boron
mg/L
2.74
0.143
94.8%
Calcium
mg/L
24,000
5.380
100%
Lithium
mg/L
174
0.0482
100%
Sodium
mg/L
47,900
3.62
100%
Ethanol
mg/L
15.6
22.3
NC
Methanol
mg/L
79.2
150
NC
NC - Not Calculated; NR - Not Reported; ND - Not Detected (Detection Limit value in parenthesis).
Source: U.S. EPA, 2017
Note: EPA used the reported detection level in calculating the removal efficiency.
aUsing EPA method 300.0.
b Using ASTM method D4237 conductivity.
c Using ASTM method D4237 UV.
6.5.2.2 Design and Operation Considerations
In oil and gas extraction wastewater treatment applications, crystallizers have been added
to existing evaporation/condensation treatment systems. In these designs, the concentrated brine
generated by evaporation/condensation becomes the influent to the crystallization unit (U.S.
EPA, 2012). However, in some cases, stand-alone crystallization units are used to treat oil and
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-24

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Section 6-Wastewater Management Practices
gas extraction wastewaters. In either case, the influent wastewater is typically pretreated to
reduce concentrations of multivalent cations (e.g., calcium, magnesium, strontium, barium)
(Shaw, 2011; U.S. EPA, 2012). Removal of these cations has three benefits (Shaw, 2011):
•	Reduced Corrosion and Capital Costs - Multivalent cations are corrosive to
equipment. Pretreatment to reduce corrosion allows downstream equipment, such as
the crystallization unit, to be constructed of less expensive materials, reducing capital
costs.
•	Reduced Operating Costs - Removing multivalent cations allows for a lower
operating temperature, resulting in energy savings. This is because the solubility limit
of concentrated brine that contains multivalent cations is higher than that of
concentrated brine that does not contain multivalent cations.
•	Purity of Solid Crystals - When multivalent cations and other pollutants are
removed prior to crystallization, the salt crystal is very pure sodium chloride. One
CWT facility suggested the solid crystals are 98 percent pure sodium chloride, which
has potential value in industrial applications (U.S. EPA, 2012).
Regardless of the type of crystallizer used, equipment is affected by scaling and corrosion
in the same way that evaporation/condensation units are affected (All Consulting, 201 lg).
Common pretreatment alternatives include settling, chemical precipitation, and filtration to
remove suspended solids and other undesired constituents (e.g., iron) (Colorado School of
Mines, 2009; Adams, 2011; U.S. EPA, 2012).
An alternative to removing multivalent cations before crystallization is to operate the
crystallization unit at reduced pressure using a vacuum and chilling system, which decreases the
boiling temperature of the solution (Shaw, 2011). Since the solubility limit of multivalent cations
will not be reached at decreased boiling temperature, the unit can be constructed of less
expensive materials (due to reduced corrosion), reducing capital costs. This alternative design
eliminates the need to pretreat the influent wastewater to remove multivalent cations (Shaw,
2011). However, pretreatment may still be needed to remove other constituents such as TSS and
iron (Adams, 2011).
Ambient temperature can also be a design consideration. Because crystallization is a
thermal technology, low winter temperatures increase energy requirements. A fixed heat
exchange capacity and lower temperatures result in a lower rate of evaporation and capacity (i.e.,
barrels treated per day). For example, one vendor reported that capacity may be as low as 200
barrels per day (bpd) in the winter and as high as 450 bpd in the summer for a specific mobile
system (Adams, 2011).
6.5.2.3 Residuals
If the crystallization unit is operated so that the water vapor is collected and condensed,
recovered treated wastewater (condensate) can be reused for hydraulic fracturing or other
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-25

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Section 6-Wastewater Management Practices
purposes by oil and gas operators. Crystallization can recover more than 80 percent of the
influent wastewater (U.S. EPA, 2012).
Crystallization of oil and gas extraction wastewater can produce a solid crystal residue of
high quality sodium chloride (up to 98 percent purity) (U.S. EPA, 2012). Several options exist
for disposing of the solid crystals or recovering them as saleable byproducts, including:
•	Hauling to landfill for disposal;
•	Returning to operators to use as an additive in drilling fluid28;
•	Selling for use has highway deicer; and
•	Selling for use as a raw material for industrial processes.
States may regulate the use of the crystallized solids. For example, Pennsylvania requires
that all salts generated by oil and gas facilities that are used for deicing or as a raw material in an
industrial process meet applicable standards in Pennsylvania Department of Environmental
Protection's (PA DEP) General Permit. This permit provides 21 specific quality standards for
salt crystals, including maximum levels of two radioactive constituents: thorium 232 (2 pCi/kg)
and uranium 238 (2 pCi/g) (PA DEP, 2012).
Crystallization will also generate a brine purge stream that must be managed. For
example, a crystallizer treating 210,000 gallons per day of oil and gas extraction wastewater with
a TDS concentration of 100,000 mg/L could generate approximately 38,000 gallons per day of
purge (U.S. EPA, 2012; U.S. EPA, 2013a). Depending on the composition of the original
wastewater the concentration of calcium chloride could be high enough to be a valuable by-
product. One CWT facility reported that if the calcium chloride concentration is at least 35
percent, the purge stream would be a saleable byproduct for other industrial applications (U.S.
EPA, 2012).29 Sodium chloride is sold as road salt, pool salt, and for specific industrial uses.
Calcium chloride could also be used for road salt, and there are some oil and gas uses (e.g.,
brining agent), among other uses. The Fairmont Brine Processing facility produces up to 80 tons
a day of rock salt which is used for de-winterizing operations (Fairmont Brine Processing, 2015).
6.5.2.4 Energy Use
Crystallization is an energy-intensive treatment technology because of the large amount
of energy required to evaporate the influent wastewater to generate solid crystals (URS, 2011).
Most units use natural gas burners as an energy source, but a variety of alternatives have been
tested.
28	Salt may be used as an additive in drilling fluid to increase density and/or increase the fluid's electrical
conductivity.
29	Calcium chloride may be added to drilling fluid to increase density and/or increase electrical conductivity.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
Vendors attempt to offset energy demand by designing units that can use alternative
energy sources, such as waste heat from compressor stations and solar energy (U.S. EPA, 2015b
and Adams, 2011). For example, Epiphany Solar Water Systems offers a crystallizer treatment
unit that uses concentrated solar energy30 (Pettengill, 2012). Consol Energy, Inc. pilot tested the
system in 2012. Epiphany's company website states that its technologies were treating produced
water as of 2016, but no information was provided about facilities using the technologies
(Epiphany Water Solutions, 2016).
Table 6-19 reports energy use per barrel of influent wastewater based on data reported by
vendors. Table 6-19 also includes TDS concentrations of untreated water entering the treatment
system, and resulting water recovery percentages. Because many of the units require both
electrical energy and fuels, the energy requirement is presented in three columns: electrical (e.g.,
pumps, compressors), fuel (e.g., natural gas for a burner to produce steam), and the total energy
required, if reported.
30 In this technology, solar thermal energy is collected using mirrors and reflected onto a central point. A working
fluid with high thermal energy capacity (e.g., antifreeze) passes through this central point to be heated by the
concentrated solar energy.
6-27
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes

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Section 6-Wastewater Management Practices
Table 6-19. Crystallization Influent TDS Concentration, Energy Use per Barrel of Influent Wastewater, and Water Recovery
Yenrior
Technulo*^
N;i mo
ini'iiicm ids
( < i neon li'ii lit in
(mji/l.)
I'll K'l
I'.loclriciil
(k\\ li/hl>l)
ii\ ( oilMIIll
Sle.im
(Ions)'1
)lion
Idlill
(k\\ li/hhl)
\\;i(er
Uee»\ en
Addilioiiiil Notes
Referenee
II)
INTEVRAS
EVRAS™
NR
NR
N/A
1.9 - 2.1b
NR
Uses waste heat from compressor
stations or runs on natural gas.
INTEVRAS,
2011
Epiphany Solar
Water Systems
E3H
NR
NR
N/A
NR
80
Uses concentrated solar energy.
Pettengill,
2012
Heartland
Technology Partners,
LLC
LM-HT®
NR
NR
N/A
NR
NR
Uses waste heat from compressor
stations or runs on natural gas.
Heartland,
2014
Not Specified
Not Specified
132,000
0.5-1.7
-14
NR
NR
Assuming waste steam is
available.
Shaw, 2011
Not Specified
Not Specified
>40,000
NR
NR
4.2-11
NR
None.
Colorado
School of
Mines, 2009
N/A—Not available; NR—Not reported; TDS—total dissolved solids; mg/L—milligrams per liter; kWh—kilowatt-hour; bbl—barrel.
a Waste steam from other industrial processes may be used to improve economics.
b Vendor reported the power requirement for the pumps and fans alone as 30 kW to treat 325 barrels per day, assuming waste heat is available. Assuming a 90- to
95-percent capacity, electrical consumption is between 1.9 and 2.1 kWh per barrel of influent wastewater. Additional energy is required if waste heat is not available.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-28

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Section 6-Wastewater Management Practices
6.5.3 Costs
Capital costs of crystallization include costs for the pretreatment system,
evaporation/condensation unit, low-pressure pumps, and monitoring equipment. The operating
costs associated with crystallization include energy for low-pressure pumps and evaporation and
labor costs (Wilkerson, 2013; Dale, 2013). The energy costs are highest among all technologies
used to treat oil and gas extraction wastewater, unless low-grade or waste energy is used (e.g.,
waste heat from compressor stations, solar energy) (Beckman, 2008; Colorado School of Mines,
2009; Bruff, 2011). Management and disposal of residuals is another operating cost. Factors that
affect the costs for crystallization include feed water quality, energy source, and disposition of
residuals.
Table 6-20 shows approximate capital and O&M costs for crystallization when a
treatment system is purchased or rented. Table 6-21 shows approximate prices charged by CWT
facilities for crystallization. Another facility estimated that the crystallization process would cost
operators $15 to $18 per barrel ($0.36 to $0.43 per gallon), including pretreatment (U.S. EPA,
2014). However, other facilities in the Marcellus have multiple facilities already operating that
use crystallization (U.S. EPA, 2012; U.S. EPA, 2016, U.S. EPA, 2016a).
Table 6-20. Crystallization Capital and O&M Costs for Oil and Gas Extraction
Wastewater Applications
Yomlor or
Tochnolo*^
N;i mo
S\s(om
Description
In I'lii on 1 IDS
Coiicoiilr;ilion
(nisi/I.)'1
Cosl
liiisis
C;ip;ioil>
(MCI))
( iipiliil
Cosl
(S por»pd)
O&M
Cosl
(S por
hhl)
Konliil or
r.fl'oc(i\o
Cosl
(S por hhl)1'
Roforonco
NOMAD
Unit
25U,UUU to
300,000°
Purchase
0.21
33
NR
NR
U.S. EPA,
2012
NR
Plant
110,000-
130,000
Purchase
or
Rental
0.25
120
3.50
11 to 22
Shaw,
2011
NR
System
40,000 -
150,000
Purchase
0.25
45
3.70
NR
Keister,
2012
GE
Plant
-130,000
NR
1.0
NR
NR
5.00 to 6.80
Tinto,
2012
NR
System
NR
Rental
NR
N/A
N/A
1.00-3.00
more than
evaporation/
condensation
ERG,
2014
N/A—Not available; NR—Not reported;
a These concentrations are examples provided in the sources.
b Represents rental cost if the cost basis was rental and is inclusive of O&M. Represents total effective cost when
cost basis is purchase, which includes amortized capital costs and O&M costs combined. When the cost basis is
purchased, total effective cost is only included when a reference reported amortized capital costs.
0 The typical influent to the plant has a TDS concentration around 100,000 mg/L. The TDS concentration presented
in the reference is the author's assumed concentration for the actual influent to the crystallization unit, which is the
effluent wastewater from an evaporator.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-29

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Section 6-Wastewater Management Practices
Table 6-21. Crystallization Costs at Commercial CWT Facilities
(AM
l-';icilil> Name
Trcalcri
\\ aMcwalcr
Infliicnl IDS
( oiicoiiI r;ilion
(niii/l.)
T\ pc of
Sen ice
( ommcrcial
CWT Price lor
Trcalmciil
(S per hhh
Year
of
Cosl
Reference
Fairmont Brine
Processing
Shale gas
250,000 to
300,000
Discharge to
surface water or
reuse.
5.50-8.00
2014
Litvak, 2014;
ERG, 2016a
Eureka
Resources, LLC
Williamsport
Shale gas
250,000 to
300,000a
Discharge to
POTW or reuse.
10.80- 11.00b
2013
U.S. EPA,
2012a
NR
NR
>100,000
Reuse only.
5.00 - 6.80°
1998
Tinto, 2012
NR—Not reported
" The typical influent to the plant has a TDS concentration around 100,000 mg/L. The TDS concentration presented
in the reference is the author's assumed concentration for the actual influent to the crystallization unit, which is the
effluent wastewater from an evaporator.
b Cost may be as low as $7 per barrel to the operator if the residuals can be sold for beneficial use to other industries.
0 Costs were reported by the source; the author assumed that the hypothetical CWT facility is owned and operated
by the vendor, and that the operator brings wastewater to the plant for treatment on a contractual basis.
6.5.4 Vendors
Table 6-22 lists vendors of crystallization technologies that EPA is aware of that offer
treatment systems designed specifically for oil and gas extraction wastewater.
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Section 6-Wastewater Management Practices
Table 6-22. Crystallization Technology Vendors for Oil and Gas Extraction Wastewater
Yi'iiriur
'loch lining
N;i mo
Sjslom
Description
Sii rl';icc
l oot prim
(I'lV
( ;ip;ici(\
(bpd)
Oilier Nolos
Reference
Epiphany Solar
Water Systems
E3H
Non-mobile
NR, fits
on well
pad
10-100
Ladi unit ib bized for one
well, but can be scaled up
for a multi-well pad. Uses
concentrated solar energy in
lieu of fuel.
Pettengill,
2012
Fountain Quail
Energy Services
NOMAD
Non-mobile
1,500
2,000
Multiple units may be
deployed at a single
location.
Hayes et al.,
2012
Heartland
Technology
Partners, LLC
LM-HT®
Mobile
NR
1,000
Can be designed for low-
grade waste heat use.
New Mexico,
2014; U.S.
EPA, 2015c
Stationary
NR
6,300
INTEVRAS
Technologies,
LLC.
EVRAS™
Semi-mobile
820
200 - 400
Can be designed for low-
grade waste heat use.
All
Consulting,
201 Id;
Adams, 2011;
INTEVRAS,
2011
Veolia
CoLD®
Mobile
NR
-6,000
The collected distillate from
the crystallizer can be
returned to the drill operator
as water to be used in
additional fracking
operations
Shaw,2011
NR—Not reported; bpd—barrels per day; ft2—square feet.
a Only includes the primary treatment unit, not storage for wastewater, chemicals, or sludge (solid waste).
6.6 Reverse Osmosis
6.6.1 Principle and Process Description
In reverse osmosis (RO), pressure is used to force water through semi-permeable
membranes that allow water, but not dissolved solids, to flow through. The RO membrane
separates constituents from wastewater based not only on size differences but also based on
electrostatic charge. RO membranes will repel most charged particles (ions) but allow neutral
molecules like water and dissolved gases to pass through. Since TDS is primarily composed of
ions such as sodium (Na+) and chloride (CI") that are repelled by RO membranes, RO is well
suited for desalination provided the TDS concentration is not too high (Weber, 1972).
The name "reverse osmosis" derives from osmosis, the spontaneous flow of water from a
dilute solution to a concentrated solution, which occurs when the two solutions are separated by
a semi-permeable membrane (Weber, 1972). In "reverse" osmosis, water flows from a
concentrated solution to a dilute solution. This is accomplished when a pressure greater than the
osmotic pressure is applied to the concentrated water, driving water through the membrane to the
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Section 6-Wastewater Management Practices
dilute solution. The membrane prevents ions from passing, leaving a concentrated solution
behind (Metcalf and Eddy, 2003).
In a typical wastewater treatment RO unit, hydraulic pumps apply pressure to the influent
wastewater. The process requires pressures ranging from 250 to 1,180 psi, depending on the
osmotic pressure (related to TDS concentration) of the influent wastewater (Hayes, 2004). The
applied pressure pushes the water through the membrane while the membrane blocks the ions
(TDS) from passing. The influent wastewater separates into two streams: treated wastewater and
concentrated brine. In the literature, the treated wastewater is referred to as permeate and the
concentrated brine is referred to as concentrate (Colorado School of Mines, 2009).
6.6.2 Capabilities and Limitations
6.6.2.1 Targeted Pollutants and Treatment Effectiveness
RO is used to remove dissolved organic and inorganic constituents, such as ions, acids,
sugars, dyes, natural resins, salts, BOD, COD, and radioactive elements from wastewater
(Colorado School of Mines, 2009). The typical upper limit of TDS concentration in the
wastewater for cost-effective operation is 45,000 to 50,000 mg/L (All Consulting, 201 lh;
Alexander, 2011). Higher TDS concentrations increase osmotic pressure to the point where
excessive energy is required to generate enough applied pressure to reverse the osmotic flow,
making the process prohibitively expensive. RO can achieve effluent TDS concentrations less
than 200 mg/L, depending on the composition of the influent wastewater (URS, 2011). One
vendor suggests that RO is the most cost-effective treatment for oil and gas extraction
wastewater when TDS is less than 30,000 mg/L (Alexander, 2011).
EPA collected samples in September 2016 at Eureka Resources, which incorporates RO
as part of its treatment train. Table 6-23 shows the EPA RO sampling data collected at this
facility for pollutants of interest. As can be seen from these data, the system removed
constituents found in oil and gas extraction wastewaters, including COD, TDS, barium,
strontium, and DRO (additional data can be found in U.S. EPA, 2017). In this case, RO is a final
polishing step after the wastewater had already been treated by chemical precipitation,
crystallization, membrane bio-reactor, and ion exchange.
Table 6-23. EPA Reverse Osmosis Sampling Data at Eureka Resources
( onMiliicnl
Inl'lncul Coiiccnlmlion
lilTliicnl Concern ml ion
( iilcnliilcd Kcmo\;il r.lTicicno
COD mm 1.)
489
16.1
96.7%
TDS (mg/L)
150
14.3
90.5%
Barium (mg/L)
0.589
0.0154
97.4%
Strontium (mg/L)
1.32
0.0347
97.4%
DRO (mg/L)
0.828
0.0835
89.9%
NC - Not Calculated
Source: U.S. EPA, 2017
Note: EPA used the reported detection level in calculating the removal efficiency when possible.
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Section 6-Wastewater Management Practices
EPA identified several references in the literature that contain data on the performance of
RO in treating oil and gas extraction wastewater, these data sources are summarized below, and
their performance data are presented in the next 5 tables.
•	All Consulting (2006) reported pilot-study data on the feasibility of membrane filtration
technologies of a GE system for the treatment of produced water in California near
Bakersfield, shown in Table 6-24. Calculated percent removals of the RO component are 97
percent for sodium and 98 percent for chloride. The report also shows the intermediate
performance data of the whole physical/chemical treatment system, which incorporated
demineralization, ultrafiltration, followed by nanofiltration, and then RO.
•	Data from Newpark Environmental Services cited in All Consulting (2006) from three
locations treating produced water from CBM facilities are shown in Table 6-25. The data
labeled as influent to RO is wastewater that had undergone physical/chemical pretreatment.
The calculated percent reductions in TDS for these three locations ranged from 96.9 to 99.5
percent.
•	Horn (2009) provided data on the performance of a pilot-scale treatment system combining
an advanced oxidation process with RO for treating produced waters in the Woodford Shale
from Newfield Exploration. Data for the entire system is provided in Table 6-26 (the
reference did not provide data for just the RO portion of the system). The system removed
TDS, chloride, organics, barium and radium 226.
•	Ecolotron (2012) provided data on the performance of an electrocoagulation system with a
subsequent RO unit treating wastewaters from three locations. Table 6-27 provides
performance data for the RO membrane treatment portion of this system. Removal of barium,
strontium, sodium and chloride was reported.
•	Shafer (2010) reported on the performance of the Anticline Disposal treatment system in
Pinedale, Wyoming that uses RO. Although this reference did not provide data for just the
RO portion of the system, data for the entire treatment system are shown in Table 6-28. The
system begins with an API separator, followed by anaerobic then aerobic basins, leading into
a clarifier. After a sand filter, the wastewater flows to an MBR, and then to the RO unit.
Additional treatment is then used: electrocoagulation, another RO unit, and then ion
exchange before discharge.
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Section 6-Wastewater Management Practices
Table 6-24. GE Pilot Membrane Filtration and RO Performance Data
( onsliliienl
RO liil'liioiil-' ( oneenlr;ilion
diiii/l.)
KO Perme;Me ( onceii(r;ilion (nig/I.)
Sodium
5,250
144
Calcium
163
5
Magnesium
115
2
Potassium
77
2
Ammonium
68
2
Chloride
4,710
114
Sulfate
ND
ND
Oil
ND
ND
ND - Not Detected
Source: All Consulting, 2006
a Permeate from ultrafiltration followed by nanofiltration, prior to RO.
Table 6-25. Newpark Environmental Services Reverse Osmosis Performance Data
C (iiisliliioul
( uneenl ml ions (m»/l.)
Piiii-chile. \\ Y
lii» Mills. I \
(;illelle.\\ Y
1 n I'liieii 1
1! I'll ii en 1
InHiienl
IHTIiienl
1 n riiienl
r.lTliienl
Chloride
-
-
8,922
355
-
-
Sodium
-
-
5,140
217
-
-
TDS
3,004
93
19,053
93.1
1,358
46
Source: Newpark Environmental Services cited in ALL Consulting, 2006
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Section 6-Wastewater Management Practices
Table 6-26. Newfield Exploration Advanced Oxidation Process/Reverse Osmosis
Performance Data
Consliliicnl
I nils
In I'll Kill
( oiicon 1 r;ilion
I'llTliicnl
Conconlriilion
Reported Rcmn\;il
I'llTiciciio
TDS
mg/L
13,833
128
99.1%
Chloride
mg/L
8,393
27
99.7%
Chemical Oxygen Demand
mg/L
248
2
99.3%
BOD - 5 Day
mg/L
196
9
95.4%
Total Organic Carbon
mg/L
65.4
3.0
95.4%
Ammonia as N
mg/L
39.9
1.1
97.2%
Barium
mg/L
34.9
0.0
99.9%
Sulfate
mg/L
23.5
0.0
100%
Oil & Grease
mg/L
13.8
1.1
92.3%
Phenolics
mg/L
0.111
0.051
54.4%
Phenol
(ig/L
38.6
0.0
100%
Bis(2-chloroethyl)ether
(ig/L
38.3
0.0
100%
Xylenes, total
(ig/L
24.3
0.0
100%
Toluene
(ig/L
5.62
0.97
82.7%
Benzene
(ig/L
4.73
0.00
100%
Ethylbenzene
(ig/L
4.25
0.00
100%
Gross Alpha
pCi/L
265
0
100%
Gross Beta
pCi/L
72.0
0.0
100%
Radium 226
pCi/L
81.8
0.0
100%
Radium 228
pCi/L
7.34
0.00
100%
Source: Horn, 2009
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Section 6-Wastewater Management Practices
Table 6-27. Ecolotron RO Membrane Performance Data
Consliliicnl
I nils
liiHiienl
( onceiilralion
I'llTluenl
( onccnlralinn
Calculated Kcmo\al
l-HTicieno
Eagle Ford
Barium
mg/L
5.96
0.2
96.6%
Sodium
mg/L
8,630
88.3
99.0%
Strontium
mg/L
24.1
0.0987
95.9%
Chlorides
mg/L
18,400
93.6
99.5%
Eagle Ford
Barium
mg/L
3
0.1
96.7%
Sodium
mg/L
23,100
906
96.1%
Strontium
mg/L
352
5.8
98.4%
Chlorides
mg/L
42,700
985
97.7%
Colorado
Barium
mg/L
14
5
64.3%
Chlorides
mg/L
25,080
600
97.6%
Source: Ecolotron, 2012
Table 6-28. Anticline Disposal Performance Data for Treatment System Incorporating
Reverse Osmosis
( onsliliienl
I nils
Topical In I'll Kill
( onceiilralion
lllTliienl
( onceiilralion
(alculaled
Kcmo\al
I'HTicicno
IDS
mg/L
8,000 - 15,000
41
99.5% - 99.7%
Boron
mg/L
15-30
0.750
95.0% - 97.5%
Chloride
mg/L
3,600 - 6,750
18
99.5% - 99.7%
Sulfates
mg/L
10 - 100
ND
NC
BTEX
Hg/L
28,000 - 80,000
ND
NC
DRO
Hg/L
77,000 - 1,100,000
ND
NC
Gasoline Range Organics
Hg/L
88,000 - 420,000
ND
NC
Methanol
mg/L
40 - 1,500
ND
NC
Oil &Grease
mg/L
50 - 2,400
ND
NC
ND - Not Detected; NC - Not Calculated
Source: Shafer, 2010
6.6.2.2 Design and Operation Considerations
RO is most efficient and cost-effective when treating wastewater with TDS
concentrations less than 50,000 mg/L; therefore, it is generally only used to treat flowback or
produced waters from formations that generate relatively low TDS concentrations (Ely, 2011)
Additionally, RO may be used as a polishing step. The most challenging problem with RO is
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Section 6-Wastewater Management Practices
that, even with proper pretreatment, membranes are subject to fouling.31 Constituents that
contribute to fouling include metal hydroxides, colloidal and particulate foulants, precipitates or
salts, organic materials (e.g., oil, humic acids), and biologicals (e.g., microbes, bacteria)
(Alexander, 2011; Colorado School of Mines, 2009). Membrane fouling will lead to reduced
treatment efficiency and higher volumes of concentrated brine. To minimize scaling and reduce
membrane fouling, pretreatment and chemical addition are typically required (Colorado School
of Mines, 2009, All Consulting, 201 lh). Usually scale control occurs first and can include pH
adjustment or antiscalant addition. After scale control, the wastewater is filtered to remove
particulate matter (TSS). Finally, wastewater may also be disinfected to reduce biofouling of the
membrane (Crittenden, 2005). Even with proper pretreatment, periodic chemical cleaning is
needed to remove foulants from the membrane. Cleaning chemicals may include hydrochloric
acid and sodium hydroxide (Colorado School of Mines, 2009). Examples of pretreatment prior to
RO specifically used in oil and gas extraction applications include advanced oxidation and
precipitation, induced gas flotation, filtration, and electrocoagulation.
6.6.2.3	Residuals
RO generates concentrated brine. At higher influent TDS concentrations, water recovery
decreases, resulting in a larger volume of concentrate and higher disposal costs (URS, 2011;
Colorado School of Mines, 2009; Asano, 2007). High water recovery (75 to 90 percent) and
reduced concentrated brine generation is possible if influent TDS is below approximately
25,000 mg/L (URS, 2011). One vendor estimated that water recovery drops to 60 percent when
influent TDS concentration reaches 30,000 mg/L, and to 25 percent when influent TDS
concentration reaches 50,000 mg/L (Alexander, 2011). Disposal methods for concentrated brine
include evaporation in ponds (Red Dessert, 2013; Themaat, 2012) and injection to a Class II
disposal well (Themaat, 2012).
6.6.2.4	Energy Use
RO requires electrical energy to run the pumps that pressurize the influent wastewater
(Hayes, 2004). A general rule of thumb in industry is that for every 100 mg/L increase of
influent TDS concentration, an additional 1 psi of applied pressure is required (Alexander, 2011).
When the required applied pressure increases, energy requirement also increases. In general, RO
pumps are powered by electricity purchased from off-site generation (i.e., the grid). Burnett
(2011) suggested alternative methods of powering RO units. These methods include
microturbines (which require low grade gas), solar panels (if the system has low pressure
requirements), and wind turbines. Burnett (2011) described a mobile wind turbine unit that is
capable of providing enough power for pretreatment operations such as media filtration, but not
enough to run the high-pressure hydraulic pumps required for RO.
31 Membrane fouling occurs when dissolved and suspended solids deposit onto a membrane surface, degrading
overall performance. Specific declines in performance include a decrease in permeate quality and water recovery
percentage.
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Section 6-Wastewater Management Practices
Table 6-29 reports energy use for RO per barrel of influent wastewater. Influent and
effluent TDS concentrations are also included, together with the final water recovery percent.
Table 6-29. Reverse Osmosis Influent TDS Concentration, Energy Use, and
Water Recovery
Yeiulor
Technolo^ \;ime
Inl'lucul IDS
( oiKTiilmlion
(mji/l.)
r.ncr;i\ I so
(k\\h per
hhl)
\\;iler
Uecn\er\
Reference
Ecosphere
Technologies, Inc.
Ozonix ™, includes AOP
for pretreatment.
13,800
2.184
75
Colorado School
of Mines, 2009;
Horn, 2013
Not Specified
NR, includes filtration for
pretreatment.
500-25,000
0.02-0.4
60-85
Asano, 2007;
Horn, 2013
Not Specified
Mobile unit designed by
Chevron, includes
electrocoagulation for
pretreatment.
45,000
1
NR
Panu et al., 2013
Not Specified
N/A, includes softening and
filtration for pretreatment.
20,000-47,000
0.5-1.6
30-60
Asano, 2007;
Horn, 2013
NR—Not reported
6.6.3 Costs
The major capital costs associated with RO are the RO unit and hydraulic pumps that can
withstand the corrosivity of the high TDS in oil and gas extraction wastewater. A major
operating cost associated with RO is membrane replacement, which is expected to occur every
three to seven years for oil and gas extraction wastewater applications, according to Colorado
School of Mines (2009). According to Burnett (2011), unconventional oil and gas wastewater
treatment requires annual membrane replacement. Energy required for the pumps and brine
management and disposal are the other major operating costs (Colorado School of Mines, 2009).
Table 6-30 shows approximate RO capital and O&M costs. The reported data show that
overall cost of RO units depends on influent wastewater quality. As influent TDS concentrations
increase, the capital and operational costs increase. This is because larger and more robust pumps
and membranes are required as the applied pressure increases (with the increase of TDS). Table
6-31 shows approximate prices CWT facilities charge to oil and gas extraction operators for
treatment including RO. Costs do not include pretreatment steps.
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Section 6-Wastewater Management Practices
Table 6-30. Reverse Osmosis Capital and O&M Costs for Oil and Gas
Extraction Wastewater Applications
Vendor ;iihI
Tcclinolo<£\
Nil mo
Sjslcm
Description
Inllucm
'l'l)S
( OIICCIII
I'iilion
(inji/l.)
( ;ip;icil>
(MCI))
( osl
Biisis
( iipiliil
(osl
(S per
iipd)
O&M
(osl
(S per
hhl)
Kenliil or
r.fl'ecli\e
(osl
(S/hhl)1
Reference
General
Mobile System
with Electro-
coagulation and
Dissolved Air
Flotation
-50,000
0.063
Purchase
and Rental
17.7
1.51
4.38
Panu et al.,
2013
Ecosphere
Energy
Services, Inc.
Mobile System
20,000 -
30,000
0.144
NR
NR
NR
3.50-
4.00
212
Resources,
2011
Siemens
Mobile System
-30,000
NR
Purchase
1.0-
4.0
NR
NR
Alexander,
2011
General
Mobile System
with Filtration
20,000 -
47,000
NR
Purchase
3.0 to
7.0
0.08
NR
Colorado
School of
Mines,
2009
NR—Not reported
a Represents rental cost if the cost basis was rental and is inclusive of O&M. Represents total effective cost when
cost basis is purchase, which includes amortized capital costs and O&M costs combined. When the cost basis is
purchased, total effective cost is only included when a reference reported amortized capital costs.
Table 6-31. Reverse Osmosis Treatment Cost at CWT Facilities
CWT l;icilil\
Niime
Tj pe of
o(;
1 iirineiil I DS
( oncen 1 r;ilion
(m»/l.)
Tj pe of
Sen ice
( oiniiierciiil
Price for
Trciilmciil
(S per hhl)
Yesir of
(osl
Reference
Anticline
Disposal, LLC
Tight
Gas
-20,000
Discharge treated
wastewater to surface
water.
2.50-3.50
2006
Puder,
2006
Red Desert
Reclamation,
LLC3
Tight
Gas
<30,000
Reuse treated wastewater
in fracturing and
evaporate concentrated
brine in ponds.
2.00-3.00
2013
Red
Desert,
2013
a Facility is no longer in commercial operation.
6.6.4 Vendors
Table 6-32 lists vendors of reverse osmosis technologies that EPA is aware of that offer
treatment systems designed specifically for oil and gas extraction wastewater.
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Section 6-Wastewater Management Practices
Table 6-32. Reverse Osmosis Technology Vendors for Oil and Gas Extraction Wastewater
Ycmlor
Tccli lining
N;i mo
Sjslcm
Description
Sii rl'sice
l oot print
i IV)"
( ;ip;ici(\
(hpri)
Oilier Noles
Reference
Ecosphere
Technologies, Inc.
Ozonix ™
Mobile
380
7,200
Includes Advanced
Oxidation Process
(AOP) as pretreatment.
Ecosphere
Technologies,
Inc., 2011;
Horn, 2009
GeoPure
Hydrotechnologies
NR
NR
NR
5,000
None.
All Consulting,
2011c
M-I SWACO
GPRI
Designs™
NR
NR
5,000
None.
All Consulting,
2011e
Omni Water Solutions,
Inc.
HIPPO®
Mobile
NR
2,500 -
10,000
Includes pretreatment.
Omni Water
Solutions, 2014
Siemens Water
Technologies
FracTreat
Mobile
NR
NR
Includes pretreatment.
Alexander,
2011; Asano,
2007
Veolia Water Solutions
& Technologies
OPUS™
Mobile or
stationary
NR
10,000
Includes chemical
softening,
degasification, and
media filtration.
CO Department
of Public
Health and
Env, 2011,
2011; All
Consulting,
201 If
NR—Not reported
a Only includes the primary treatment unit, not storage for wastewater, chemicals, or sludge (solid waste).
6.7 Biological Treatment
Biological treatment is a broad category of treatment which includes many different
technologies. This section provides an overview of biological treatment and discusses the
specific technologies most commonly used for oil and gas extraction wastewater.
6.7.1 Principle and Process Description
Biological wastewater treatment systems use microorganisms to consume biodegradable
soluble organic contaminants and bind the less soluble portions into flocculant, which is removed
from the system typically in a clarifter. Biological treatment may be aerobic, anaerobic, anoxic,
or a combination of these technologies. Aerobic biological treatment is the degradation of
organic impurities by bacteria that can thrive in the presence of oxygen (also called aerobes)
(Mittal, 2011); this treatment takes place in an aerobic bioreactor which is typically aerated.
Anaerobic biological treatment is the degradation of organic impurities by bacteria that thrive
only in the absence of oxygen (also called anaerobes) (Mittal, 2011). Anoxic systems are
typically used for denitrification (conversion of nitrate to nitrogen gas) using facultative bacteria
that thrive in the absence of dissolved oxygen and instead use oxygen in the form of nitrous
oxides.
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Section 6-Wastewater Management Practices
One type of biological treatment system used to treat oil and gas extraction wastewater is
a membrane bioreactor (MBR). In an MBR the wastewater from a bioreactor passes through
membranes for solid-liquid separation instead of clarifiers. The membrane separation processes
typically used in an MBR are microfiltration or ultrafiltration. The membranes are usually made
of plastic or ceramic materials but can be made of metal (Radjenovic et al., 2008). Similar to RO,
the effluent from the membrane is called permeate and the rejected fluid is called the concentrate
(Sutton, 2006).
Anticline Disposal's Jensen facility uses both anaerobic and aerobic biological treatment
to treat produced waters. Wastewater flows from a large anaerobic lagoon to an aerated lagoon
and then to a clarifier where added chemicals aid in flocculation, coagulation, and settling of
biomass. From the clarifier, the wastewater flows to sand filters (Shafer, 2010). Effluent from
this process can be reused by oil and gas extraction operations, or further processed through an
activated sludge bioreactor, an MBR, and other subsequent treatment for discharge to surface
waters (Shafer, 2010). Eureka Resources also incorporates MBR into their treatment train for
discharge of produced waters (McManus et al., 2015).
6.7.2 Capabilities and Limitations
Biological treatment is mainly used to remove suspended organics, dissolved/colloidal
organic matter, and possibly nutrients. However, other wastewater constituents may be removed
by biological treatment because they are either biologically degraded (e.g., methanol) or
collected in the flocculent and removed from the wastewater with the other solids (e.g.,
particulate metals).
EPA collected samples in September 2016 at Eureka Resources that incorporated MBRs
as part of the treatment train. Table 6-33 shows the data collected at this facility for pollutants of
interest. As can be seen from these data, the systems removed constituents found in oil and gas
extraction wastewaters, including oil and grease/hexane extractable material,, diesel range
organics, total petroleum hydrocarbons, and alcohols (additional data can be found in U.S. EPA,
2017).
Table 6-33. EPA MBR Sampling Data at Eureka Resources
( (insliliionl
Inl'lui'iil ('(iiicoiili'iilioii
IHTIucnl ( oiktii trillion
( iik'iihili'ri KciikimiI I.ITicic'no
Ammonia (mg/L)
41.1
0.259
99.4%
TOC (mg/L)
121
2.540
97.9%
DRO (mg/L)
17.7
10.2
42.4%
2-Butoxyethanol
1.08
ND (0.001)
>99.9%
Ethanol (mg/L)
22.3
ND (3)
>86.5%
Methanol (mg/L)
150
ND (0.25)
>99.8%
ND - Not Detected (Detection Limit value in parenthesis)
Source: U.S. EPA, 2017
Note: EPA used the reported detection level in calculating the removal efficiency.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
EPA identified limited performance data for biological treatment specific to oil and gas
extraction wastewater treatment in the literature. Kose et al. (2012) evaluated the performance of
a submerged MBR in the laboratory for the treatment of brackish oil and natural gas field
produced water in Turkey. Table 6-34 presents the results of this study. Reductions in COD, oil
and grease and TPH were reported.
Table 6-34. MBR Laboratory Performance Data
( oiisiiiiioiil
Reported Influent Rnniio
(niii/l.)
Reported IITIikiK Riiniic
(niii/l.)
Reported Remo\;tl KITicicno
COD
1,500 - 3,000
<500
80-85
Oil and Grease
31 -50
7 - 15
60-85
TPH
1,030-2,210
<8 - 185
82-99
Source: Kose et al, 2012
6.7.2.1	Design and Operation Considerations
Biological processes can be sensitive to variations in influent flow and organic loads.
Also, sludge buildup can be a concern, especially in aerobic treatment processes, which generate
more sludge than anaerobic treatment processes. Biological treatment has a high energy
requirement for aeration which increases with wastewater strength (high concentration of
organics). Also, the efficiency of this treatment process is temperature dependent, so the systems
may need to be heated, which adds to energy costs. Aerobic processes only operate within a
fixed pH range of 6.5 to 8.5 (U.S. EPA, 2000b). If there is insufficient alkalinity to buffer the
system, the pH must be maintained by chemical addition, which adds to the treatment cost.
A significant concern with MBR is membrane fouling, which can cause a decrease in
permeate flux rate. Fouling may be the result of material adsorbing to the membrane, biofilm
growing on the membrane, precipitation of inorganic material, or membrane aging (Radjenovic
et al., 2008). Fouling may be controlled by a variety of management techniques, including a
regular physical and chemical cleaning regimen. Physical cleaning of the membranes may
consist of either back flushing or rinsing the membranes and scouring with air bubbles. Chemical
cleaning methods include the use of either alkaline or acidic chemicals.
6.7.2.2	Residuals
In most biological treatment systems, the clarifier separates the biomass from the treated
wastewater. Sludge is removed regularly from the system, sometimes continuously. Landfilling
is a typical method of disposal. In anaerobic lagoons, there is minimal generation of solids.
Solids are typically removed infrequently by dredging the lagoon. Depending on the design of
the lagoon, this cleanout may occur every several years or even less frequently.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
6.7.3	Costs
Capital costs for biological treatment include costs for a bioreactor or lagoon, clarifier
and/or filtration system, pumps, and monitoring equipment. Operation and maintenance costs
include electricity, sludge disposal costs, plant maintenance costs and labor costs. Electricity
costs account for the energy required to operate the aeration tanks as well as the pumps and
mixers. The energy requirements depend upon the device employed, but range from 1 to 4
kWh/day (U.S. EPA, 2000b). Operating costs are directly proportional to the quality of
wastewater supplied for treatment. Labor costs are also a factor due to maintenance performed
by semi-skilled personnel and/or operational problems for onsite blower, mechanical aerator
tanks, pump and pipe clogging, electrical, motor failure, corrosion and/or failure of controls, and
electrical malfunctions (U.S. EPA, 2000b).
Capital costs for MBRs include the items listed above for other activated sludge systems,
and in addition, the costs of the membranes. Operating costs, in addition to those listed above,
include the chemical and labor costs for cleaning the membranes and increased power
requirements for pumping water through the membranes.
The cost effectiveness of an anaerobic biological treatment depends upon many factors
such as ability to use biogas, power costs, and sludge disposal costs (U.S. EPA, 2000b). Capital
costs of general anaerobic biological treatment mainly include the cost of construction and costs
for the pretreatment system or monitoring equipment. Operational costs include costs for pH
control chemicals and nutrients, and labor costs for periodic sludge removal.
6.7.4	Vendors
Lagoons and activated sludge systems may be designed and constructed by facilities
without the use of a vendor. MBR systems are more complex and require specific vendors. Table
6-35 lists some vendors of MBR technology.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
Table 6-35. Biological Treatment Technology Vendors for Oil and Gas
Extraction Wastewater
Vendor
Tcchnolo*^ \;imc
S\s(cm
Description
Sii rf;icc
l-'ooiprinl (I'l")¦'
( ;ip;icil>
(l)|)d)
Reference
General Electric-
Zenon Environmental
Zee Weed ZW-500
Submerged
Membrane
495.14
NR
Radjenovic, 2008
Koch Membrane
Systems
PURON® MBR
Submerged
Membrane
3,552 - 19,375
NR
Koch Membrane
Systems, 2015
KUBOTA
Corporation
Kubota Submerged
Membrane Unit®
(SMU)
Submerged
Membrane
86 - 6,243
NR
KUBOTA Corp.,
2015
ADI System Inc.
ADI-AnMBR
Anaerobic
Membrane
Bioreactor
NR
NR
ADI Systems Inc.,
2015
NR—Not reported
a Only includes the primary treatment unit, not storage for wastewater, chemicals, or sludge (solid waste).
6.8 Summary
The preceding discussions described technologies that EPA identified that are currently
being used at CWT facilities to treat oil and gas extraction wastewaters. In addition to those
technologies previously described, there are additional technologies that are or have been used as
part of a treatment train at these facilities, for example for polishing of treated effluent prior to
discharge or as pretreatment steps prior to other technologies. An example of such a technology
is ion exchange. Additionally, other technologies have been used or researched for treating oil
and gas extraction wastewaters, either in the laboratory or at other (non-CWT) facilities that may
be applicable to CWT facilities. These include electrocoagulation, electrodialysis reversal,
capacitative deionization, membrane distillation and forward osmosis. Many of these
technologies are described by Ahmadun et al. (2009).
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
6.9 Performance Data Reference Information
EPA reviewed multiple data sources to produce the data contained in this section. These
data sources include journal articles and technical papers, technical references, industry/vendor
telephone queries, facility site visits, technology fact sheets, and vendor websites. Table 6-36
lists the performance data sources in this section along with notes on the scale of the study (if
applicable). The scale may be bench, pilot, demonstration, or full, as described below. In some
cases, the data source included multiple studies which represented multiple scales. In cases
where the data source summarized and presented data or information from other studies, or
presented only data from other studies, the type of scale was reported as not applicable (N/A).
•	Bench - very small scale, in-laboratory testing;
•	Pilot - larger than bench, but still small scale; sometimes in a laboratory;
•	Demonstration - large scale, not full-size; and
•	Full - full-sized; usually operating at a facility.
Table 6-36 also contains a Source Type number that indicates the type of reference the
information was obtained from. These numbers correspond to the following:
1.	Journal articles, documents prepared by or documents prepared for a government
agency (e.g., EPA site visit reports, industry meeting notes).
2.	Documents prepared by a source32 that include verifiable information (e.g.,
operator reports, vendor documents, university publications).
3.	Documents prepared by a verified source that do not include citation information
(e.g., operator reports, vendor documents, conference presentations).
Table 6-36. Performance Data Quality Review
Author. Yciir
Sliuh Scale
Source
Tj pc
Author. Year
Siuclj Scale
Source
Tjpe
212 Resources, 2011
Full Scale
3
Hornetal., 2013
Full Scale
2
Acharya, 2011
Bench Scale
1
Horn, 2009
Pilot Scale
2
ADI System Inc., 2015
Full Scale
3
INTEVRAS Technologies,
LLC, 2011
Full Scale
3
All Consulting, 2006
Multiple
2
JS Meyer Engineering, 2015
Full Scale
2
All Consulting, 2011a
Full Scale
3
Keister, 2012
Pilot Scale
2
All Consulting, 2011b
Full Scale
3
Kose et al., 2012
Bench Scale
1
All Consulting, 2011c
Full Scale
3
KUBOTA Corporation,
2015
Full Scale
3
32 The EPA considered sources as verifiable if we were able to find information about the author outside of the
reference document. For example, EPA primarily verified information by looking for company/organization
websites that confirmed the author's affiliation with the oil and gas extraction industry.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
Table 6-36. Performance Data Quality Review
Aullior. Yc;ir
Sliuh Sciilo
Soiiito
1 > |)C
Aullior. Yi-iir
Siuclj Scale
Source
Tjpe
All Consulting, 201 Id
Full Scale
3
Litvak, 2014
Pilot Scale
3
All Consulting, 201 le
Full Scale
3
Lord et al., 2013
Bench Scale
2
All Consulting, 201 If
Full Scale
3
Mittal, 2011
Pilot Scale
1
Anguil Aqua Systems, 2016
Full Scale
3
M-I SWACO, 2009
Full Scale
3
Asano, 2007
Pilot Scale
1
Papso et al., 2010
Full Scale
2
AquaTech International
Corporation, 2011
Full Scale
3
Puder, 2006
Full Scale
2
Beckman, 2008
Pilot Scale
2
Radjenovic, 2008
Multiple
3
Bruff, 2011
Multiple
2
Roman, Jaime, 2011
Full Scale
3
CARES, Unknown
Full Scale
3
Shafer, 2010
Full Scale
2
CO Department of Public
Health and Env, 2011
Full Scale
1
Shaw, 2011
Full Scale
3
Colorado School of Mines
(CSM), 2009
Multiple
1
Silva, 2012
Full Scale
3
Crittendon et al., 2005
Multiple
1
Smith, 2014
Pilot Scale
1
Dale, 2013
Pilot Scale
3
Sutton, 2006
Demonstration
Scale
2
ERG, 2016a
N/A
1
U.S. EPA, 1998
Multiple
3
ERG, 2016b
Full Scale
1
U.S. EPA, 2000a
Multiple
1
ERG, 2016c
Multiple
1
U.S. EPA, 2013a
Full Scale
1
ERG, 2014
Full Scale
1
U.S. EPA, 2013b
Multiple
1
ERG, 2012a
Full Scale
1
U.S. EPA, 2014
Full Scale
1
ERG, 2012b
Full Scale
1
U.S. EPA, 2015a
Pilot Scale
1
Ecolotron, 2012
Demonstration
Scale
2
U.S. EPA, 2015c
Full Scale
1
Ecosphere Technologies Inc.,
2011
Full Scale
2
U.S. EPA, 2015d
Full Scale
1
Fairmont Brine Processing,
2015
Full
2
U.S. EPA, 2015e
Full Scale
1
Gradiant, 2016
Full Scale
3
U.S. EPA, 2015f
Full Scale
1
Hayes, 2004
Pilot Scale
1
URS, 2011
Full Scale
3
Hayes et al., 2012
Full Scale
3
Ziemkiewicz et al., 2012
Bench Scale
2
Heartland Technology
Partners, LLC, 2014
Full Scale
3



6.10 References
1.	212 Resources. 2011. Vendor profile: 212 Resources. All Consulting. DCN
CWT00112
2.	Acharya, Harish; Henderson, Claire; Matis, Hope; Kommepalli, Hareesh; Moore,
Brian; Wang, Hua, 2011. Cost Effective Recovery ofLow-TDS Frac Flowback
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
Water for Re-use. Prepared by GE Global Research. Prepared for U.S. DOE
NETL. (June). DCN CWT00005
3.	Adams, Andy. 2011. EVRAS Evaporation Technology. Intevras & Layne Water.
(September 26). DCN CWT00058
4.	ADI System Inc. 2015. Vendor Profile: Anaerobic Membrane Bioreactor (ADI-
AnMBR). Available at:
http://www.adisvstemsinc.com/pdfs/ADI AnMBR brochure Final.pdf. DCN
CWT00185. DCN CWT00185
5.	Ahmadun et al., 2009. Review of Technologies for Oil and Gas Produced Water
Treatment. Journal of Hazardous Materials. Volume 179 (2-3). DCN CWT00322
6.	Alexander, Jerry. 2011. Telephone Communication with J. Alexander, Siemens,
S. Hays, ERG "Siemens Reverse Osmosis Technology." (September 28). DCN
CWT00059
7.	All Consulting, LLC. 2006. A Guide to Practical Management of Produced Water
from Onshore Oil and Gas Operations in the United States. Interstate Oil and Gas
Commission and ALL Consulting. (October). DCN CWT00318
8.	All Consulting. 201 la. Vendor Profile: Altela. DCN CWT00238
9.	All Consulting. 2011b. Vendor Profile: AquaTech. DCN CWT00231
10.	All Consulting. 201 lc. Vendor Profile: GeoPure Hydrotechnologies. DCN
CWT00232
11.	All Consulting. 201 Id. Vendor Profile: INTEVRAS Technologies, LLC. DCN
CWT00233
12.	All Consulting. 201 le. Vendor Profile: MISWACO. DCN CWT00234
13.	All Consulting. 201 If. Vendor Profile: Veolia. DCN CWT00235
14.	All Consulting. 201 lg. Water Treatment Technology Fact Sheet: Crystallization.
DCN CWT00011
15.	All Consulting. 201 lh. Water Treatment Technology Fact Sheet: Reverse
Osmosis. DCN CWT00012
16.	Anguil Aqua Systems. 2016. Frac Water Reuse Technologies. DCN CWT00248
17.	AquaTech International Corporation. 2011. Mobile Water Distillation System.
Online at: http://www.aquatech.eom/portals/0/MoVap%20Cut%20Sheet-01.pdf.
DCN CWT00239
18.	Asano, Takashi. 2007. Water Reuse: An Integrated Approach to Managing the
World's Water Resources. McGraw-Hill. DCN CWT00008
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 6-Wastewater Management Practices
19.	Beckman, James R. 2008. Devaporation Desalination 5,000-Gallon-per-Day
Pilot Plant. Desalination and Water Purification Research and Development
Program Report No. 120. (June). Contract No. 03-FC-81-0905. DCN CWT00009
20.	Bruff, Matthew. 2011. An Integrated Water Treatment Technology Solution for
Sustainable Water Resource Management in the Marcellus Shale. Altela Inc.,
Argonne National Laboratory. DCN CWT00102
21.	Burnett, D. 2011. Telephone Communication with David Burnett, Global
Petroleum Research Institute, and Sarah Hays, Eastern Research Group, Inc. DCN
CWT00314
22.	CARES. Unknown. CARES McKean. Available online at:
http://www.caresforwater.com/location/cares-mckean. DCN CWT00040
23.	CO Department of Public Health and Env. 2011. CDPS Fact Sheet To Permit
Number C00048739 Bopco, L.P., Yellow Creek Water Mgmt Facility Rio Blanco
Co. DCN CWT00236
24.	Colorado School of Mines (CSM). 2009. An Integrated Framework for Treatment
and Management of Produced Water, 1st edition (November). DCN CWT00188
25.	Crittenden, John, et al., 2005. Water Treatment: Principles and Design. John
Wiley & Sons, Inc. 2nd edition. DCN CWT00027
26.	Dale, Walter. 2013. H20ForwarcfM Service - Sustainable Development of
Completions. Halliburton. Technical presentation presented at the 2013 Produced
Water Reuse Initiative Conference (October 30). DCN CWT00048
27.	Eastern Research Group, Inc. (ERG). 2016a. 6th Annual Shale Plays Water
Management Marcellus and Utica 2016 Conference Notes. DCN CWT00249
28.	Eastern Research Group, Inc. (ERG). 2016b. CoilChem, LLC Treatment
Technology Memorandum. DCN CWT00246
29.	Eastern Research Group, Inc. (ERG). 2016c. Unconventional Oil and Gas (UOG)
Produced Water Volumes and Characterization Data Compilation Memorandum.
DCN CWT00323
30.	Eastern Research Group, Inc. (ERG). 2014. Notes on Meeting with Hydrozonix,
LLC on 7 February 2014. DCN CWT00241
31.	Eastern Research Group, Inc. (ERG). 2012a. Notes on Conference Call with 212
Resources. Eastern Research Group, Inc. DCN CWT00029
32.	Eastern Research Group, Inc. (ERG). 2012b. Notes on Conference Call with
Reserved Environmental Services, LLC, and Eastern Research Group, Inc.
(February 1). DCN CWT00015
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Section 6-Wastewater Management Practices
33.	Ecolotron Water Recovery Systems. 2012. Treatment of Flow Back and Produced
Water from the Hydraulic Fracturing of Oil - Shale. DCN CWT00039
34.	Ecosphere Technologies Inc. 2011. Vendor Profile: Ecosphere Technologies, Inc.
ALL Consulting. DCN CWT00113
35.	Ely, John W., et al., 2011. Game Changing Technology for Treating and
Recycling Frac Water. Society of Petroleum Engineering. SP SPE-214545-PP.
DCN CWT00313
36.	Epiphany Water Solutions. 2016. Epiphany Water Solutions News. Available at
http://www.epiphanyws.com/news/. DCN CWT00382
37.	Fairmont Brine Processing. 2015. Presentation from Shale Gas Innovation and
Commercialization Center Technology Showcase. Available online at:
http://www.sgicc.Org/uploads/8/4/3/l/8431164/fairmont brine processing.pdf.
DCN CWT00191
38.	Gradiant. 2016. Gradiant: Operations, www.gradiant.com/operations. DCN
CWT00247
39.	Hayes, Tom. 2004. The Electrodialysis Alternative for Produced Water
Management. Gas Technology Institute. (Summer). DCN CWT00028
40.	Hayes, Thomas et al., 2012. Evaluation of the Aqua Pure Mechanical Vapor
Recompression System in the Treatment of Shale Gas Flow back Water Report No.
08122-05.11. Research Partnership to Secure Energy for America (RPSEA). DCN
CWT00043
41.	Heartland Technology Partners, LLC. 2014. Core Technologies. Available online
at: http://www.heartlandtech.com/about/core-technologies/. DCN CWT00003
42.	Hefley, William, et al., 2011. The Economic Impact of the Value Chain of a
Marcellus Shale Well. University of Pittsburgh. (August). DCN CWT00103
43.	Horn, Aaron, et al., 2013. Minimum Effective Dose: A Study of Flowbackand
Produced Fluid Treatment for Use as Hydraulic Fracturing Fluid. Hydrozonix,
LLC (March 18). DCN CWT00320
44.	Horn, Aaron. 2009. Breakthrough Mobile Water Treatment Converts 75% of
Fracturing Flowback Fluid to Fresh Water and Lowers C02 Emissions. Society
of Petroleum Engineering. DCN CWT00038
45.	INTEVRAS Technologies, LLC. 2011. EVRAS™ Evaporative Reduction and
Solidification. Available online at:
http://www.lavneintevras.com/downloads/Evras/technical/EVRAS Summary w
Heat Rates.pdf. DCN CWT00013
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Section 6-Wastewater Management Practices
46.	Ewing, Jay. 2008. Taking a Proactive Approach to Water Recycling in the Barnett
Shale. Devon Energy. DCN CWT00104
47.	JS Meyer Engineering. 2015. Oil and Gas Frack, Produced, Flowback Water
Processing Technology. DCN CWT00245.A01
48.	Kasey, Pam. 2009. Gas Well Drilling Brine Treatment Facility Opens in Fairmont
- AOP Clearwater LLC is set to begin operation of its gas well drilling brine
recycling facility in Fairmont. The State Journal. DCN CWT 00044
49.	Keister, Timothy. 2012. Sequential Precipitation - Fractional Crystallization
Treatment ofMarcellus Shale Flowback and Production Wastewaters.
ProChemTech International, Inc. DCN CWT00192
50.	Koch Membrane Systems. 2015. Vendor Profile: PURON® HOLLOW FIBER
MODULES. Available at: http://www.kochmembrane.com/PDFs/Data-
Sheets/Hollow-Fiber/UF/puron-mbr-modules-psh330-660-1800-datasheet.aspx.
DCN CWT00193
51.	Kose, Borte; et al., 2012. Performance evaluation of a submerged membrane
bioreactor for the treatment of brackish oil and natural gas field produced water.
Desalination. (January). Available at:
http://dx.doi.Org/10.1016/i.desal.2011.10.016. DCN CWT00195
52.	KUBOTA Corporation. 2015. Vendor Profile: Kubota Submerged Membrane
Unit®. Available at: http://www.kubota-
membrane.com/uploads/2014/09/18/Kubota%20Brochure.pdf. DCN CWT00194
53.	Litvak, Anya. 2014. Engineering Firm ventures into Wastewater, LNG. Pittsburgh
Post-Gazette. DCN CWT00110
54.	Lord, LeBas, et al., 2013. Development and Use of High-TDS Recycled Produced
Water for Crosslinked-Gel-Based Hydraulic Fracturing. Society of Petroleum
Engineers. DCN CWT00321
55.	McManus, Ertel and Bogdan. May, 2015. A Sustainable Choice for Oil and Gas
Wastewater Treatment/Recycling. PBI Environmental Law Forum. DCN
CWT00315
56.	Mertz, Barry. 2011. Telephone Communication with Barry Mertz, 212 Resource
Corporation, and Brent Ruminski, Eastern Research Group, Inc. DCN CWT00056
57.	Metcalf and Eddy, Inc. 2003. Wastewater Engineering: Treatment and Reuse.
McGraw-Hill, Inc. 4th edition. DCN CWT00026
58.	Mittal, Arun. 2011. Biological Wastewater Treatment. Water Today. Available
online at: http://www.watertodav.org/Article%20Archieve/Aquatech%2012.pdf.
DCN CWT00196
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Section 6-Wastewater Management Practices
59.	M-I SWACO. 2009. Frac Water Reclamation System Reduces Operator's Water
Cost. DCN CWT00240
60.	New Mexico Energy, Minerals and Natural Resources Department (NMEMND).
2014. OCD Permitting: Well Search. DCN CWT00230
61.	NETL. Unknown Date. DOE Projects to Advance Environmental Science and
Technology, https://www.epa.gov/sites/production/files/documents/bruff-
trifold.pdf. DCN CWT00387
62.	Omni Water Solutions. 2014. Frac Water. Treating Flowback and Produced Water
for Re-Use. DCN CWT00237
63.	PA DEP. 2012. General Permit WMGR123 Processing and Beneficial Use of Oil
and Gas Liquid Waste. Available at:
http://files.dep.state.pa.us/Waste/Bureau%20of%20Waste%20Management/Waste
MgtPortalFiles/SolidWaste/Residual Waste/GP/WMGR123 .pdf. DCN
CWT00273
64.	Panu, Marc et al., 2013. Design of a Mobile Wastewater Treatment System for
Hydraulic Fracturing Waste. Chevron Group. (April 19). DCN CWT00099
65.	Papso, John, et al., 2010. Gas Well Treated with 100% Reused Frac Fluid.
Exploration and Production. (August). Available at:
http://www.swsi.com/pdf/Cabot SWSI reuse.pdf. DCN CWT00007
66.	Pettengill, Ron. 2012. Innovative Water Management Strategies for Future
Marcellus Development. Epiphany Solar Systems. DCN CWT00033
67.	Puder, M.G., and J. A. Veil. 2006. Offsite Commercial Disposal of O&GE&P
Waste: Availability, Options, and Costs. Argonne National Laboratory. DCN
CWT00097
68.	Purestream. 2011. Welcome to Purestream. (January). Available at:
http://purestreamtechnologv.com/downloads/purestream-technology-overview-
2011. pdf. DCN CWT00106
69.	Radjenovic, Matosic, Mijatovic, Petrovic, and Barcelo. 2008. Membrane
Bioreactor as an Advanced Wastewater Treatment Technology. DCN CWT00197
70.	Red Desert. 2013. Red Desert: Facilities. Available online at:
http://reddesertwater.com/facilities.html. DCN CWT00042
71.	Roman, Jaime. 2011. Fountain Quail NOMAD Evaporator. Fountain Quail.
(October 26). DCN CWT00060
72.	Rowan, E.L., et al., 2011. Radium content of oil and gas field prod waters in the
nrthrn App Basin. USGS Scientific Investigations Report 2011-5135. DCN
CWT00316
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Section 6-Wastewater Management Practices
73.	Shafer, Lee. 2010. A Working Model for Oil and Gas Produced Water Treatment.
Technical presentation from the Opportunities and Obstacles to Improving the
Environmental Footprint of Energy Extraction in the Uintah Basin Workshop.
DCN CWT00107
74.	Shaw, William. 2011. The Real Cost of ZLD for Shale Gas Frac Water in the
Marcellus Shale Play. HPD, LLC, a Veolia Water Solutions and Technologies
company. (September). DCN CWT00055
75.	Silva, James. 2012. Produced Water Pretreatment for Water Recovery and Salt
Production. (January 26). Report 08122-36. DCN CWT00032
76.	Smith, Daniel. 2014. Determining the Minimum Treatment Levels Required for
Production Efficiency: Stating the Lowest Acceptable Water Quality Levels for
Effective Reuse in Fracs. Apache. Technical presentation presented at 5th Annual
Shale Play Water Management 2014 - Southern States Conference. (November
19). DCN CWT00114
77.	Sutton, Paul M. 2006. Membrane Bioreactors for Industrial Wastewater
Treatment: Applicability and Selection of Optimal System Configuration.
Available at http J/www, environmental-
expert.eom/Files%5C5306%5Carticles%5C11542%5C259.pdf. DCN CWT00199
78.	Themaat, Johan. 2012. Water Infrastructure Versus Mobile Options for Treating
and Disposing Fracking and Produced Water. High Sierra Water Services. DCN
CWT00034
79.	Tinto, Joseph. 2012. Water Recovery via Thermal Evaporative Processes for High
Saline Frac Water Flow back. Technical Presentation from the 2012 International
Water Conference. DCN CWT00108
80.	U.S. Environmental Protection Agency (U.S. EPA). 1998. Development
Document for Proposed Effluent Limitations Guidelines and Standards for the
Centralized Waste Treatment Industry. EPA 821-R-98-020. (December). DCN
CWT00053
81.	U.S. Environmental Protection Agency (U.S. EPA). 2000a. Wastewater
Technology Fact Sheet: Chemical Precipitation. EPA-832-F-00-018.
(September). DCN CWT00010
82.	U.S. Environmental Protection Agency (U.S. EPA). 2000b. Decentralized
Systems Technology Fact Sheet: Aerobic Treatment. Washington, D.C.
(September). EPA-832-F-00-031. DCN CWT00200
83.	U.S. Environmental Protection Agency (U.S. EPA). 2012. Site Visit Report
Eureka Resources, LLC. Marcellus Shale Gas Operations. DCN CWT00036
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Section 6-Wastewater Management Practices
84.	U.S. Environmental Protection Agency (U.S. EPA). 2013a. Summary of the
Technical Workshop on Wastewater Treatment and Related Modeling. (April 18).
DCN CWT00045.
85.	U.S. Environmental Protection Agency (U.S. EPA). 2013b. Treatment
Technologies Relevant to the Unconventional Oil and Gas Industry. DCN
CWT00227
86.	U.S. Environmental Protection Agency (U.S. EPA). 2014. Site Visit Report US
Gas Field Fluids Management (formerly Clean Streams). Marcellus Shale Gas
Operations. DCN CWT00035
87.	U.S. Environmental Protection Agency (U.S. EPA). 2015a. Sanitized Site Visit
Report Southwestern Energy Fayetteville Shale Operations. DCN CWT00266
88.	U.S. Environmental Protection Agency (U.S. EPA). 2015b. Site Visit Report
Chesapeake Energy Corporation Marcellus Shale Gas Operations (Sanitized).
DCN CWT00111
89.	U.S. Environmental Protection Agency (U.S. EPA). 2015c. Site Visit Report
Seneca Resources Corporation Covington, PA. DCN CWT00054
90.	U.S. Environmental Protection Agency (U.S. EPA). 2015d. Site Visit Report for
Nuverra Appalachian Water Services inMasontown, PA. DCN CWT00062
91.	U.S. Environmental Protection Agency (U.S. EPA). 2015e. Site Visit Report for
Patriot Water Treatment LLC in Warren, OH. DCN CWT00064
92.	U.S. Environmental Protection Agency (U.S. EPA). 2015f. Site Visit Report for
Reserved Environmental Services, LLC Mt. Pleasant, PA. DCN CWT00063
93.	U.S. Environmental Protection Agency (U.S. EPA). 2016a. Site Visit Report
Eureka Resources, Standing Stone Facility Wysox, PA. DCN CWT00153
94.	U.S. Environmental Protection Agency (U.S. EPA). 2016b. Site Visit Report
Fairmont Brine Processing, LLC Fairmont, WV. DCN CWT00116
95.	U.S. EPA. 2016c. Unconventional Oil & Gas Extraction Wastewater Treatment
Technologies. DCN CWT00051
96.	U.S. Environmental Protection Agency (U.S. EPA). 2017. Sampling Episode
Report For Eureka Resources Standing Stone Wysox, Pennsylvania. DCN
CWT00162
97.	URS. 2011. Water-Related Issues Associated with Gas Production in the
Marcellus Shale. Prepared in support of the Supplemental Generic Environmental
Impact Statement for Natural Gas Production. (March). DCN CWT00006
98.	Weber, Walter. 1972. Physicochemical Processes for Water Quality Control.
University of Michigan. Wiley-Interscience. DCN CWT00025
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-53

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Section 6-Wastewater Management Practices
99.	Wilkerson, Tommy. 2013. Strategies for Sustainable Water Transport Lessons
Learned in the Marcellus Applied to the Niobrara. Carrizo Oil and Gas, Inc.
Technical presentation presented at the 2013 Produced Water Reuse Initiative
Conference. (October 30). DCN CWT00049
100.	Wilson, M. 2011. Telephone Communication with M. Wilson, GE, and B.
Ruminski, ERG. "GE Power and Water: Wastewater Treatment Technologies."
Nov 10. DCN CWT00057
101.	Zhang et al., 2014. Co-precipitation of Radium with Barium and Strontium
Sulfate and its Impact on the Fate of Radium during Treatment of Produced Water
from Unconventional Gas Extraction. Environmental Science and Technology,
Volume 48. DCN CWT00317
102.	Ziemkiewicz, Paul et al., 2012. Zero Discharge Water Management for
Horizontal Shale Gas Well Development. West Virginia Water Research Institute.
Department of Energy (DOE). DCN CWT00383
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
6-54

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Section 7-Pollutant Discharge Loadings
7. Pollutant Discharge Loadings
EPA estimated the quantity of pollutants discharged from in-scope facilities for the 2016
reporting year. To develop these estimates, EPA used a combination of Discharge Monitoring
Report (DMR) data from 2016 and responses to EPA's data request under section 308(a) of the
Clean Water Act.33 As described in Section 4.3, EPA is aware of nine in-scope direct
discharging and two in-scope indirect discharging CWT facilities. These facilities are listed in
Table 7-1, which also notes whether a facility is a major or non-major discharger under
NPDES34. As noted previously, the Max Environmental Technologies, Inc. Yukon Facility does
not discharge oil and gas extraction wastes under the CWT effluent guidelines and therefore the
pollutants reported in the DMRs are reflective of other discharges from the facility. Therefore,
EPA has not summarized DMR data for this facility.
As described in Section 5.2.1, DMR data from treating oil and gas extraction process
wastewater is available from five facilities for reporting year 2016. For each of these five
facilities, EPA estimated the total pounds of pollutants discharged from treating oil and gas
extraction wastewater. In addition, EPA estimated the toxicity of these wastewater discharges
using pollutant-specific toxic weighting factors (TWFs) to account for the relative toxicity of
different pollutants. (TWF values and a discussion of their development are available in ERG,
2005.). EPA calculated pollutant toxic weighted pound equivalents (TWPEs) for each pollutant
by multiplying the pollutant load (in pounds) by its TWF.
Table 7-1. In-Scope Facilities Accepting Oil and Gas Extraction Wastes
N;iino of (lie l ;icili(\
( il>. Sliiio
Si ;i 1 ii s
(Mii.joi'/Miiioi')
Byrd/Judsonia Water Reuse/Recycle Facility
Judsonia, AR
Minor
Clarion Altela Environmental Services (CAES)
Clarion, PA
Minor
Eureka Resources, Standing Stone Facility
Wysox, PA
Minor
Fairmont Brine Processing, LLC
Fairmont, WV
Minor
Fluid Recovery Service: Franklin Facility
Franklin, PA
Major
Fluid Recovery Service: Josephine Facility
Josephine, PA
Major
Fluid Recovery Services: Creekside Treatment Facility
Creekside, PA
Minor
Max Environmental Technologies, Inc. Yukon Facility
Yukon, PA
Minor
Waste Treatment Corporation*
Warren, PA
Major
Eureka Resources, Williamsport 2nd Street Plant
Williamsport, PA
N/A (indirect discharge)
Patriot Water Treatment, LLC
Warren, OH
N/A (indirect discharge)
*Note this facility has closed as of November, 2017.
33	TRI data were not available for any of the nine facilities. Only facilities meeting specific size and discharge
thresholds are required to report to TRI.
34	Major or federally-reportable facilities are those for which states must submit compliance and enforcement data to
EPA. See https://echo.epa.gov/tools/data-downloads/icis-npdes-download-summarv for more information.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
7-1

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Section 7-Pollutant Discharge Loadings
7.1 Direct Discharges
EPA reviewed the 2016 DMR data to estimate the pollutant loadings discharged by each
in-scope CWT facility that accepts oil and gas extraction wastewater and directly discharges
treated wastewater. EPA obtained 2016 DMR pollutant data for seven of the nine facilities that
discharge directly. Only minimal data were available for Waste Treatment Corporation in 2016
DMRs, and therefore EPA did not calculate annual loads for this facility. The Byrd/Judsonia
Water Reuse/Recycle Facility has a NPDES permit to discharge but rarely discharges and instead
primarily reuses water in other oil and gas operations. EPA did not calculate annual loadings for
this facility. The Fluid Recovery Services: Creekside Facility has an NPDES permit, but the
facility did not report any discharge on DMRs in 2016. EPA was unable to identify any publicly-
available sources of data to estimate discharge loadings for the Creekside Facility in 2016;
therefore, EPA did not calculate the pollutant loadings for the Creekside facility for 2016.
EPA's DMR Pollutant Loading Tool calculates pollutant loadings discharged using the
pollutant concentrations and wastewater flows and/or pollutant loadings reported by facilities on
their DMRs. The tool also estimates toxic weighted pound equivalents (TWPEs) by multiplying
the loadings by toxic weighting factors (TWFs). EPA developed TWFs for use in the ELGs
development program to allow comparison of pollutants with varying toxicities (ERG, 2005).
More information about the DMR Pollutant Loading Tool calculations is available in the tool's
user guide.35
Table 7-2 and Table 7-3 present these 2016 pollutant loadings discharged in pounds and
TWPE, respectively, as calculated by the DMR Pollutant Loading Tool (ERG, 2018). Note that
the tool will only calculate loadings for pollutants included in a facility's NPDES permit for
which monitoring is required. For these calculations, EPA downloaded monitoring period data
from the DMR Pollutant Loading Tool. EPA calculated loads only for outfall locations
associated with process wastewater, as defined in the facility permits. Calculated loads that
incorporate at least one non-detect value are indicated in the table. If a pollutant was reported as
non-detect values for some months but had detected values in other months, the loadings were
calculated with the non-detects set equal to half the detection limit. If a pollutant was reported as
non-detect for all reported months for a particular facility, EPA did not calculate a load for that
pollutant for that facility. Note that both Fluid Recovery Services facilities reported 12 months of
data, Fairmont Brine reported five months, and Eureka Resources Standing Stone reported only
one month of data.
35 DMR Pollutant Loading Tool user guide: https://echo.epa.gov/trends/loading-tool/resources/technical-support-
document.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
7-2

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Section 7-Pollutant Discharge Loadings
Table 7-2. Annual Pollutant Loading Discharges in Pounds for In-Scope CWT Facilities
Calculated Using DMR Pollutant Loading Tool Output with 2016 Reported Data


Polliiliinl l.o;i(liniis. Pounds per Year


I'.uivkii

I-In id
I-In id

Polliiliinl
Rcsou rccs.
S(;ni(lin
-------
Section 7-Pollutant Discharge Loadings
Table 7-3. Annual Pollutant Loading Discharges in TWPE for In-Scope CWT Facilities
Calculated Using DMR Pollutant Loading Tool Output with 2016 Reported Data


Pulliiliinl l oiidiniis. Pounds per Year

Polllllillll
luiTkii
Rcsoii ires.
Shiiidinii
Slonc
l-'iicilil>
l-'ii i nil o ill
Brine
Processing
I-In id
Uccn\ on
Scr\ ices:
Irnnklin
hicililj
I-In id
Uccn\ cr\
Son ices:
Josephine
l";icili(\
Tolsil Reported
Aluminum, total recoverable
NR
0.055
NR
NR
0.055
Arsenic, total recoverablea
NR
0.095
NR
NR
0.095
Barium, total (as Ba)
0.001
0.326
2.09
4.66
7.08
Benzene
NR
0.003
NR
NR
0.003
Beryllium, total recoverable (as Be)
NR
0.001
NR
NR
0.001
Boron, total recoverable
NR
0.245
NR
NR
0.245
Chloride (as CI)
0.002
1.11
632
606
1,240
Chlorine, total residual
NR
0.045
NR
NR
0.045
Chloroform
NR
0.000
NR
NR
0.000
Chromium, hexavalent dissolved
(as Cr)
NR
0.006
NR
NR
0.006
Copper, total recoverablea
ND
0.376
ND
NR
0.376
Dibromochloromethane
NR
0.001
NR
NR
0.001
Fluoride, total (as F)
NR
0.420
NR
NR
0.420
Iron, total recoverable
NR
0.191
ND
ND
0.191
Lithium, total (as Li)
NR
0.246
NR
NR
0.246
Nickel, total recoverable"
NR
0.103
NR
NR
0.103
Nitrogen, ammonia total (as N)
0.040
0.162
NR
NR
0.202
Selenium, total recoverable
NR
0.042
NR
NR
0.042
Strontium, total (as Sr)
0.00003
0.020
1.19 b
NR
1.21
Sulfate
NR
0.004
NR
NR
0.004
Vanadium, total (as V)a
NR
0.008
NR
NR
0.008
Zinc, total (as Zn)a
0.010
NR
NR
NR
0.010
Zinc, total recoverablea
NR
0.027
NR
NR
0.027
a Indicates a pollutant is regulated under 40 CR Part 437.
b Indicates a pollutant that had some months of non-detected values included in the loadings calculation (and set
equal to half the detection limit). Pollutants with all months of non-detected values are not included in the table.
NR = Not reported by that facility.
7.2 Indirect Discharges
Indirect discharging facilities do not report monitoring data on DMRs, so EPA attempted
to identify other sources of information to estimate pollutant loadings discharged by these
facilities. Patriot Water Treatment, LLC provided 2015 monthly monitoring concentration data
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
7-4

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Section 7-Pollutant Discharge Loadings
in response to EPA's data request under section 308 of the Clean Water Act. EPA averaged these
monthly monitoring data, then multiplied the average concentrations by annual wastewater flows
reported by the facility in their response to EPA's 308 data request to calculate annual pollutant
loadings discharged (ERG, 2018). If a pollutant was reported as non-detect values for some
months but had detected values in other months, the loadings were calculated with the non-
detects set equal to half the detection limit. If a pollutant was reported as non-detect in all
months, loadings were not calculated fort that pollutant; pollutants with non-detects every month
include antimony, arsenic, cadmium, cyanide, mercury and selenium. The pounds of pollutant
loadings per year were multiplied by the pollutant TWFs to calculate TWPE per year. Table 7-4
presents the estimated 2015 pollutant loadings for Patriot Water Treatment, LLC to the POTW.
EPA notes that the POTW would be expected to remove some portion of these pollutant loadings
prior to discharge to the receiving waters.
Table 7-4. 2015 Pollutant Loadings Discharged by Indirect Discharger Patriot Water
Treatment, LLC
I'olliiliinl N;iim-
Indirect l)isch;iriic loiidiniis
(I'oii nds/Ycnr)
Indirect Dischiiriie l.o;idiniis
iTWPr./Ywir)
TDS
7,740,000
-
COD
262,000
-
Barium
27,200
54.2
Bromide b
23,800
-
TSSa
26,100
-
Ammonia (as N)
5,840
6.48
Copper, total11
152
94.7
Lead, totala
33.4
74.8
Zinc, totala •b
27.0
1.08
Molybdenum, total
23.0
4.60
Silver, totala
8.69
143
Nickel, totala •b
8.59
0.859
Chromium, hexavalent totalb
5.51
2.81
Chromium, totala ¦b
4.85
0.340
a Indicates a pollutant is regulated under 40 CR Part 437.
b Indicates a pollutant that had some months of non-detected values included in the loadings calculation (and set
equal to half the detection limit). Pollutants with all months of non-detected values are not included in the table.
Eureka Second Street facility also responded to EPA's data request; however, the facility
did not provide discharge monitoring data as part of their response. EPA was unable to identify
other publicly-available data to estimate loadings for this facility.
7.3 Summary of Pollutant Loadings for Discharging CWT Facilities
Accepting Oil and Gas Extraction Wastewater
Multiple pollutants with the highest loadings in pounds per year are not regulated under
40 CFRPart 437, such as TDS, chloride, ammonia, COD, and strontium. Several of the
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
7-5

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Section 7-Pollutant Discharge Loadings
pollutants with the highest TWPE per year are also not regulated under 40 CFR Part 437, such as
ammonia, chloride, silver, barium, and molybdenum.
Note that this pollutant loadings analysis has the following limitations:
•	This analysis does not include all facilities, since EPA did not have data to calculate annual
loads from all facilities. The one notable direct discharging facility missing from the analysis
is the Creekside treatment facility. This facility does discharge, and currently does not
incorporate TDS removal technologies. One indirect discharging facility (Eureka Resources,
Williamsport) is also known to be operating and discharging
•	Only pollutants being monitored and reported are included, so different facilities monitor
different pollutants, and there may be other pollutants present in the wastewater that are not
accounted for in this estimate.
•	In some cases, annual pollutant loadings discharged are calculated based on less than 12
months of data.
•	Some of the direct discharging facilities did not report any (or minimal) discharges on DMRs
in 2016 because they did not discharge in 2016 (such as the Byrd/Judsonia Water
Reuse/Recycle Facility, which is known to rarely discharge), or the DMR data may have
been missing from the DMR Pollutant Loadings Tool for other reasons.
•	While setting non-detect values equal to half the detection limit may create an over or under
estimate of actual pollutant loadings discharged from a facility, this approach is reasonable
given that the actual concentration of pollutant in the discharge would be expected to be
between zero and the reported detection limit.
7.4 References
1.	ERG. 2005. Draft Toxic Weighting Factor Development in Support of CWA
304(m) Planning Process. (July 29). DCN CWT00001
2.	U.S. EPA. 2016. Discharge Monitoring Report (DMR) Pollutant Loading Tool.
Accessed on June 17, 2016. Available online at:
https://echo.epa.gov/trends/loading-tool/. DCN CWT00135
3.	ERG, 2018. Analysis of DMR Pollutant Data and Loadings Calculations. DCN
CWT00542
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
7-6

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Section 8-Economic Profile
8. Economic Profile
As described in Chapter 4, EPA has identified eleven facilities that accept oil and gas
extraction wastes and are either currently permitted under Part 437 or information available to
EPA indicates will be permitted under Part 437 when NPDES permits are reissued. More
broadly, EPA identified many facilities that accept these wastes but do not discharge, and
numerous facilities that are currently permitted under Part 437 but do not accept these wastes.
EPA also identified a number of facilities where incomplete information is currently available to
EPA to determine if these facilities are in-scope of this study (although EPA's preliminary
review of these facilities indicates the few, if any, are likely to be in-scope of this study).
In preparing an economic profile of the industry, EPA has evaluated the subset of
facilities that are known by EPA to be in-scope of this study, meaning current 40 CFR Part 437
facilities (or those that will likely be subject to Part 437 when permits are reissued) that accept
oil and gas extraction wastes and discharge treated wastewater, as well as trends within the
broader set of facilities known to accept oil and gas wastes. EPA discusses the subset of in-scope
facilities and the subset's trends in this profile chapter, followed by broader industry trends in
Appendix C.
EPA is also interested in the economics of the broader industry defined by the three
NAICS codes in which CWT activity has traditionally occurred, as described in Section 4.1,
because facilities that currently do not provide oil and gas extraction wastewater treatment
services may decide to enter the market in the future. However, these industry sectors reflect
much broader industry activity and capture firms and facilities that are not CWT firms and
facilities. A profile of these NAICS codes is provided in Appendix C.
EPA notes that the increase in investment of technologically advanced CWT facilities, or
investment to build new ones, shows an emergence of new business models for provision of
wastewater and other water-related services for oil and gas operations. This may have come
about given how the CWT industry is affected by the expansion of the oil and gas industry and
the resulting increase and change in characteristics of oil and gas extraction wastewater. Given
these factors, EPA continues to study and review data that may provide insight into the potential
economic impacts that might result from changes to the CWT effluent limitations guidelines
(ELGs). The CWT industry's ability to withstand compliance costs in general is primarily
influenced by two factors: (1) the extent to which the industry may be expected to shift
compliance costs to its customers through price increases and (2) the financial health of the
industry and its general business outlook.
8.1 Facilities and Firms Receiving and Treating OGE Wastewater
As described in Section 4.2, EPA identified 198 facilities that are known to accept OGE
wastewater (excluding facilities that only accept CBM wastewater). Of these, 98 discharge
process wastewater. Parent and/or facility information was obtained from Hoover's for 66 of
these facilities (D&B, 2016). No information was available for the remaining 32 facilities. Table
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
8-1

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Section 8-Economic Profile
8-1 presents basic summary statistics of the set of 66 CWT facilities, by NAICS code and as
totals.
Table 8-1. Facilities Known to Provide OGE-Related CWT Services
NAICS
NAICS
Description
Number of
huililk-s
Number
<>l'
I'irms
Tol;il I'irm
r.m|>lo\ men 1
A\er:i»e
l'!iii|)ln\ meiil
per I'irm
O.
o
SllKlll
Business
lnl;il
l.slini;iled
Revenue
(S millions)
562211
Hazardous Waste Treatment and
Disposal
2
2
13,000
6,500
100%
$15,042.2
562219
Other Nonhazardous Waste
Treatment and Disposal
29
3
47,396
15,799
33%
$15,042.2
562920
Materials Recovery
3
3
3,882
1,294
33%
$1,697.6
211111
Crude Petroleum and Natural Gas
Extraction
9
5
11,304
2,261
20%
$17,215.3
212321
Construction Sand and Gravel
Mining
1
1
1
1
100%
$0.1
213111
Drilling Oil and Gas Wells
1
1
61
61
100%
$13.4
213112
Support Activities for Oil and Gas
Operations
4

2,752
917
67%
$4,421.7
237110
Water and Sewer Line and Related
Structures Construction
1
1
12
12
100%
$1.3
237310
Highway, Street, and Bridge
Construction
1
1
15
15
100%
$9.1
325180
Other Basic Inorganic Chemical
Manufacturing
1
1
25
25
100%
$1.2
333132
Oil and Gas Field Machinery and
Equipment Manufacturing
1
1
50,197
50,197
0%
$14,760.0
333318
Other Commercial and Service
Industry Machinery Manufacturing
3
1
500
500
100%
$141.6
424720
Petroleum and Petroleum Products
Merchant Wholesalers
1
1
3,100
3,100
0%
$1,680.0
454390
Other Direct Selling Establishments
1
1
1
1
100%
$0.0
484230
Specialized Freight Trucking,
Long-Distance
2
1
17
17
100%
$3.2
488390
Other Support Activities for Water
Transportation
1
1
17
17
100%
$0.9
541611
Administrative Management and
General Management Consulting
Services
2
1
50
50
0%
$10,100.0
541620
Environmental Consulting Services
2

34
17
100%
$3.0
541712
Research and Development in the
Physical, Engineering, and Life
Sciences (except Biotechnology)
1
1
9
9
100%
$0.7
551112
Offices of Other Holding
Companies
1
1
34
34
100%
$3.9
561210
Facilities Support Services
1
1
3
3
0%
$0.2
Tiihil
66
33
132,410
4,012
64%
S65,0'J5.4
Source: D&B, 2016; ERG, 2016.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
8-2

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Section 8-Economic Profile
8.1.1	40 CFR Part 437 In- Scope CWT Facilities that Treat Oil and Gas Extraction Wastes
As described in Section 4.3, EPA received economic questionnaire responses from 6
facilities: Byrd/Judsonia Water Reuse/Recycle Facility; Eureka Resources, Standing Stone
Facility; Fairmont Brine Processing, LLC; Fluid Recovery Services, Josephine Facility; Patriot
Water Treatment, LLC; and Waste Treatment Corporation. The majority of facilities claimed
CBI for their financial data. Without a minimum of three data points with which to mask the data
within an average, EPA is unable to publish any data identified as CBI or any calculations using
said data. This is consistent with Statistical Policy Working Paper 22: Report on Statistical
Disclosure Limitation Methodology (Federal Committee on Statistical Methodology, 2005)
which describes the limitations on reporting data when it does not meet the threshold of three or
more data points. Since much of the data obtained in the economic questionnaires does not meet
this threshold, EPA decided to not include the economic questionnaire data in this report.
Instead, the reader may view the blank copy of the financial form in the record of the study
docket to see what kind of information was requested from these facilities (U.S. EPA, 2016).
8.1.2	Other Facilities that Treat Oil and Gas Extraction Wastes
Based on information in EPA's CWT facility list, 187 facilities accept oil and gas
extraction wastes but are not in-scope of the current study. An additional 12 facilities only accept
CBM wastes, and are also not in-scope of the current study. These numbers may be
underestimated because other facilities may accept wastes that could potentially be oil and gas
extraction wastes, but EPA lacks information for these facilities. In addition, there may be
additional facilities that were not identified by EPA.
As discussed in Section 4.4, EPA received financial information from one non-in-scope
facility. Again, given that this facility requested their information be CBI, and the threshold of 3
or more data points required for reporting sensitive data, EPA decided to not include this
information in this report. Instead, the reader may view the blank copy of the financial form in
the record of the study docket to see what kind of information was requested from these
facilities.
Table 8-2 lists the top eight states with the largest number of facilities treating oil and gas
extraction wastewater. The states in Table 8-2 account for 90 percent of the 210 facilities treating
oil and gas extraction wastewater. Pennsylvania and Texas have the highest number of facilities
treating oil and gas extraction wastewater, accounting for almost 50 percent of the total number.
For a full list of States that have facilities treating oil and gas wastewater, see Table B-2.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
8-3

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Section 8-Economic Profile
Table 8-2. States with the Highest Number of Facilities Treating Oil and Gas Extraction
Wastewater
Sliilo
l-'iicililios Accepting Oil ;nul (>:is I'Mr;iclion \\;is(cs '
Number of I'iicililics
Pcrccnliiiic of Tnl;il
Pennsylvania
57
27%
Texas
47
22%
Wyoming
21
10%
Ohio
16
8%
Colorado
15
7%
Louisiana
14
7%
North Dakota
11
5%
West Virginia
5
2%
a Includes the 189 of the 210 facilities on EPA's CWT facility list known to accept oil and gas extraction wastes.
8.1.3 Commercial and Non- Commercial CWT Facilities
EPA was able to identify only 85 (40 percent) of CWT facilities as being either
commercial or non-commercial. Conclusive information was not available for the remaining
facilitates. Of these 85 facilities, 51 facilities (60 percent) were commercial and 40 percent were
non-commercial. Non-commercial facilities include those owned by an oil and gas operator that
do not accept waste from other operators.
8.2 Demand for CWT facilities that Treat Oil and Gas Wastewater and Output
Projections
Increasing extraction and production of oil and gas resources will likely lead to increased
need for wastewater management options, including treatment at CWTs. Natural gas production
has increased substantially since 2005 due to shale gas production, and crude oil production has
increased substantially since 2008 due to tight oil and shale oil production. In 2008, shale gas
and tight oil plays was the third largest source for natural gas production (lower 48 onshore
conventional production and tight gas were the leading sources), and by 2010 became the
number one source of U.S. production (U.S. DOE, 2016a). Most of this increase has come since
2010 from the Marcellus formation, which is now by far the biggest U.S. producer of shale gas
(U.S. DOE, 2017b). Likewise, between 2008 and 2015, tight and shale oil production grew
almost ten times, due mostly to increased production in the Eagle Ford and Bakken formations
(U.S. DOE, 2016e).
However, crude oil prices have fallen considerably since the summer of 2014. The 60
percent fall in crude oil prices since they peaked in June 2014, along with low natural gas prices,
has had significant adverse effects on OGE firms. In the short term, this is likely to continue, as
prices are expected to recover slowly. U.S. crude oil production, which averaged 9.4 million
barrels per day (bpd) in 2015 and 8.9 million bpd in 2016, is projected to average 8.7 million bpd
in 2017 and 9.3 million bpd in 2018 (U.S. DOE, 2017a). U.S. rig counts continued to fall through
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2016, and a significant recovery was not expected until the end of 2016 (Zborowski, 2016).
Recovery has occurred in 2017, with the rig count as of the week ending December 8, 2017 at
931, up from the all-time low of 480 in March 2016 (OGJ, 2017; Zborowski, 2016).
The long-term outlook is more favorable. Henry Hub natural gas prices are forecast to
increase through 2030 then remain relatively flat through 2040, and Brent crude oil prices are
forecast to increase more quickly than gas prices, through 2040 (U.S. DOE, 2017a). And while
many factors will affect further development, and forecasts inevitably involve considerable
uncertainty, U.S. crude oil production is expected to continue to increase through 2025, and U.S.
natural gas production is projected to increase through 2040 (U.S. DOE, 2017a). This growth,
along with an increasing water cut (the ratio of produced water to oil production), environmental
regulations, and water scarcity, is expected to drive capital expenditures on equipment for
treating produced water (Stanic, 2014). Growth depends on the production profile of individual
wells, the cost of drilling and operating the wells, and the revenue generated.
Wastewater generation, and therefore demand for CWT services, will not only depend on
overall oil and gas production, but also on the type of production. For conventional vertical well
production, there is little water used for drilling, but lifetime produced water volumes can be
high. The opposite is typically the case with horizontal drilling and hydraulic fracturing, which
can require large amounts of water. At hydraulically fractured wells, initial flowback is high but
lifetime produced water is much lower (Veil, 2015). In 2005, tight and shale oil production
totaled approximately 136 million barrels, representing 7 percent of total crude oil production in
the United States. In 2015, tight and shale oil production increased to approximately 1,658
million barrels, or 48 percent of total crude oil production (U.S. DOE, 2016c; U.S. DOE, 2016f).
This ratio is expected to remain relatively constant, with tight and shale oil projected to represent
about 45 percent of total crude oil production in 2040 (U.S. DOE, 2015). In 2005, shale gas
production totaled approximately 1,134 billion cubic feet (bcf), or 6 percent of total U.S. natural
gas marketed production. In 2015, shale gas production increased to 15,252 bcf, 53 percent of
total natural gas marketed production (U.S. DOE, 2016b; U.S. DOE, 2016d). This fraction
increases when tight gas is considered in addition to shale gas. By 2040, tight and shale gas
production is projected to represent 75 percent of total U.S. dry production (U.S. DOE, 2015).36
8.3 Regional Trend/Outlook Discussion for CWT facilities that Treat Oil and Gas
Wastewater
Due to the variability of oil and gas reservoirs by region, the changes in OGE activities
and the need for wastewater treatment will also likely vary by region. EIA predicts that U.S. dry
natural gas production will continue to increase through 2040, and crude oil production will
increase through 2025 and then decline (U.S. DOE, 2017a).
36 EIA reports historical shale gas production as marketed production, but projects natural gas production as dry
production in its Annual Energy Outlook. Dry natural gas production equals marketed production less extraction
losses.
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Lower 48 onshore crude oil production will show the strongest growth in the
Dakotas/Rocky Mountain region, which includes the Bakken formation, followed by the
Southwest region, which includes the Permian basin. Lower 48 onshore dry natural gas
production will show the strongest growth in the East region, which includes the Marcellus Shale
and Utica Shale, followed by the Gulf Coast region and Dakotas/Rocky Mountain region.
Between 2013 and 2040, more than half of the projected growth in shale gas production comes
from the Haynesville and Marcellus formations (U.S. DOE, 2015).
Whether an increase in wastewater generation translates to an increase in demand for
CWT services depends on the feasibility and relative cost of alternative management options.
Though underground injection has historically been the preferred method for managing
wastewater in the majority of shale gas plays, in the Marcellus play, for example, only a few
areas provide suitable underground injection zones (Arthur et al., 2009). Faced with high
trucking costs to transport wastewater to injection wells in Ohio or West Virginia, oil and gas
operators in Pennsylvania may turn to treatment for reuse/recycle or other CWT services. These
circumstances, along with the projected growth in Marcellus shale gas production, may favor
higher growth in demand for CWT services in that region than in other areas.
Wyoming may also be a potential location for growth in demand for CWT services.
While produced water can be managed through injection in permitted disposal or enhanced
recovery wells or evaporated in surface ponds, the state does also allow discharge to surface
waters (Still et al., 2012)37. Demand for CWT services may also increase in Ohio and Oklahoma,
due to concerns over induced seismicity from underground injection of oil and gas extraction
wastes (Ohio DNR, undated, Rubenstein and Mahani, 2015).
8.4	Financial Outlook for CWT facilities that Treat Oil and Gas Extraction Wastewater
Generally, EPA has noted that the more recent increase in oil prices (from 2016 onward),
along with the ability for some in-scope CWT facilities to learn their business better (e.g., work
out technology and process matters, or incentivize with by-product sales) has allowed the CWT
industry to improve its financial outlook. The drop in oil prices in 2015 and early 2016 reduced
the financial well-being of these facilities, but the more recent price increasing trends have
helped to now change some of this narrative. With the price of oil projected to continue to
increase (U.S. DOE, 2017a), EPA will continue to review the cyclical market's financial outlook.
8.5	References
1. Arthur, Daniel J., Brian Bohm, and Mark Layne. 2009. Considerations for
development of Marcellus Shale gas. World Oil. July 2009. ALL Consulting.
Available electronically at: http://www.all-
llc.com/publicdownloads/W00709Arthur.pdf. DCN CWT00209
37 Since Wyoming is located west of the 98th meridian, discharges may be authorized under 40 CFR 435 Subpart E.
Therefore, the need for 40 CFR Part 437 facilities is unknown.
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2.	Ohio Department of Natural Resources (Ohio DNR). Undated. Flowback
(Wastewater) from Hydraulic Fracturing. Accessed 28 April 2016. Available at:
http://oilandgas.ohiodnr.gov/portals/oilgas/pdf/factsheets/wastewater-
flowback 0815.pdf. DCN CWT00210
3.	Oil and Gas Journal. 2017. "Baker Hughes: US Rig Count Ticks up 2 Units to
931." December 8, 2017. Accessed December 14, 2017. Available electronically
at: http://www.ogi.com/articles/2017/12/baker-hughes-us-rig-count-ticks-up-2-
units-to-931.html. DCN CWT00390
4.	Rubenstein, Justin L. and Mahani, Alireza Babaie. Myths and Facts on
Wastewater Injection, Hydraulic Fracturing, Enhanced Oil Recovery, and Induced
Seismicity. SeismologicalResearch Letters. Volume 86, Number 4, July/August
2015. DCN CWT00391
5.	Stanic, Jelena. Unconventional Oil and Gas Production Drives Trends in Water
Management and Treatment. Oil and Gas Facilities. August 2014. DCN
CWT00211
6.	Still, Dean P., Alfred M. Elser, and Frederick J. Crockett. 2012. Reasonable
Foreseeable Development Scenario for Oil and Gas Buffalo Field Office Planning
Area, Wyoming. 16 August 2012. United States Department of the Interior (U.S.
DOI), Bureau of Land Management (BLM), Wyoming State Office Reservoir
Management Group. DCN CWT00212
7.	United States Department of Energy (U.S. DOE). 2017a. Energy Information
Administration (EIA). Annual Energy Outlook 2017. Available electronically at:
https://www.eia.gov/outlooks/aeo/pdf/0383(2013).pdf. DCN CWT0394
8.	United States Department of Energy (U.S. DOE). 2017b. Energy Information
Administration (EIA). U.S. Dry Shale Gas Production. Accessed December 14,
2017. Available electronically at:
https://www.eia.gOv/energvexplained/data/U.S.%20dry%20shale%20gas%20prod
uction.xlsx. DCN CWT00395
9.	United States Department of Energy (U.S. DOE). 2016a. Energy Information
Administration (EIA). Annual Energy Outlook 2016 Figure Data: Figure MT-46.
U.S. dry natural gas production by source in the Reference case, 1990-2040
(trillion cubic feet). Accessed December 14, 2017. Available electronically at:
https://www.eia.gov/outlooks/archive/aeol6/excel/figmt46 data.xls. DCN
CWT00396
10.	United States Department of Energy (U.S. DOE). 2016b. United States Energy
Information Administration (EIA). Natural Gas Gross Withdrawals and
Production: Marketed Production. Accessed April 27, 2016. Available
electronically at:
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http://www.eia.gov/dnav/ng/ng prod sum a epgO vgm mmcf a.htm. DCN
CWT00224
11.	United States Department of Energy (U.S. DOE). 2016c. United States Energy
Information Administration (EIA). U.S. Crude Oil Production (Thousand barrels).
Accessed April 27, 2016. Available electronically at:
http://www.eia.gov/dnav/pet/pet crd crpdn adc mbbl m.htm. DCN CWT00225
12.	United States Department of Energy (U.S. DOE). 2016d. United States Energy
Information Administration (EIA). U.S. Dry Shale Gas Production. Accessed
April 27, 2016. Available electronically at:
http://www.eia.gov/energy in brief/article/shale in the united states.cfm. DCN
CWT00226
13.	United States Department of Energy (U.S. DOE). 2016e. Energy Information
Administration (EIA). U.S. Tight Oil Production Estimates: Monthly. Accessed
April 27, 2016. Available electronically at:
https://www.eia.gOv/energvexplained/data/U.S.%20tight%20oil%20production.xl
sx. DCN CWT00400
14.	United States Department of Energy (U.S. DOE). 2016f. United States Energy
Information Administration (EIA). U.S. Tight Oil Production - Selected Plays.
Accessed April 27, 2016. Available electronically at:
http://www.eia.gov/energy in brief/article/shale in the united states.cfm. DCN
CWT00401
15.	United States Department of Energy (U.S. DOE). 2015. United States Energy
Information Administration (EIA). Annual Energy Outlook 2015 with Projections
to 2040. April 2015. Available electronically at:
http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf. DCN CWT00229
16.	United States Environmental Protection Agency (U.S. EPA). 2006. Economic
Analysis of Effluent Limitations Guidelines and Standards for the Centralized
Waste Treatment Industry. December 2006. DCN CWT00220
17.	United States Environmental Protection Agency (U.S. EPA). 2010. Regulatory
Flexibility Act Section 610 Review of Effluent Limitations Guidelines and
Standards for the Centralized Waste Treatment Industry. DCN CWT00222
18.	United States Environmental Protection Agency (U.S. EPA). 2016. Blank 308
Questionnaire. DCN CWT00405
19.	Federal Committee on Statistical Methodology. 2005. Statistical Policy Working
Paper 22: Report on Statistical Disclosure Limitation Methodology Version 2.
Washington, DC: U. S. Office of Management and Budget. DCN CWT00543
20.	Veil, J. 2015. U.S Produced Water Volumes and Management Practices in 2012.
April 2015. DCN CWT00158
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21. Zborowski, Matt. 2016. "U.S. rig count hits all-time low in recorded data." Oil
and Gas Journal. Available electronically at:
http://www.ogi.com/articles/2016/03/bhi-us-rig-count-hits-all-time-low-in-
recorded-data.html. DCN CWT00184
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9. Environmental Impacts
Centralized waste treatment facilities accepting oil & gas extraction (O&G) wastewaters
can release pollutants into the environment that impact aquatic ecosystems and human health.
Potential pollutants can reach the environment (1) through effluent discharging to surface waters
either directly from a CWT facility or indirectly from publicly owned treatment works (POTWs)
accepting treated CWT effluent; (2) during managed use of wastewater, such as irrigation; and
(3) by releases from storage impoundments and spills. Direct discharges of treated effluent from
CWT facilities accepting O&G wastewater have caused environmental impacts, particularly on
water quality, drinking water, and aquatic health. This chapter addresses the documented and
potential human health and environmental impacts associated with CWT facilities accepting
O&G wastewater and presents specific case studies to illustrate these impacts.
Section 9.1 of this chapter discusses pollutants associated with CWTs accepting O&G
wastewater and their origins, including total dissolved solids (TDS), halides, metals,
radionuclides (primarily radium), and other chemicals in hydraulic fracturing (HF) injection
fluids. Section 9.2 explores the pathways through which pollutants in O&G wastewater accepted
by CWTs can interact with the environment. Section 9.3 analyzes the downstream impact to
water quality from CWT effluent containing treated O&G wastewater. Section 9.4 discusses
documented and potential human health impacts from CWTs accepting O&G wastewater.
Section 9.5 discusses documented and potential aquatic life impacts. Section 9.6 describes other
environmental impacts from CWTs accepting O&G wastewater, such as impacts to POTW
efficiency, impacts to irrigation or livestock watering uses, and impacts to air. Finally, Section
9.7 addresses data gaps that exist in the literature on environmental impacts from CWTs
accepting O&G wastewaters.
9.1 Constituents in O&G Wastewater at CWT Facilities
Effluents from CWT facilities treating O&G wastewater have been associated with
alterations in downstream surface water quality in individual receiving streams (e.g., Warner et
al., 2013; Ferrar et al., 2013) as well as at the watershed level (e.g., Wilson and VanBriesen,
2012; Olmstead et al., 2013; Vidic et al., 2013). Extraction techniques, such as hydraulic
fracturing (HF), became a major source of O&G wastewater in the early 2000s (Wilson and
VanBriesen, 2012; U.S. EPA, 2016c). HF wastewater has been characterized as either flowback
water or produced water in some references. Some pollutants of potential concern from an
environmental or human health perspective in O&G wastewater include TDS; halides (e.g.,
bromide, chloride, and iodide); metals; technologically enhanced naturally occurring radioactive
materials (TENORM); and a wide range of poorly characterized chemicals in injected fluids
including surfactants, biocides, wetting agents, scale inhibitors, and organic compounds.
9.1.1 TDS
TDS is a quantitative measure of the amount of dissolved inorganic and organic
substances in water. Compounds constituting TDS include ionic salts (e.g. carbonate,
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bicarbonate, chloride, fluoride, sulfate, phosphate, nitrate, calcium, magnesium, sodium,
potassium), dissolved metals (e.g., boron, copper, lead, zinc), and small amounts of organic
matter. TDS is commonly used as a parameter to assess water quality, and can be regulated (e.g.,
Pennsylvania Code, 2011).
Wastewaters from O&G operations commonly have high concentrations of TDS. TDS is
contributed to these wastewaters from the targeted formation either from brines in the formation
or from interaction of injected fluid with the formation. Previous work cites two possible
mechanisms that increase TDS levels in produced waters from HF. The first mechanism is ion
dissolution from the underground rock formation upon interaction with the injected HF fluid
(Blauch et al., 2009). The second mechanism is that brines trapped within sedimentary rock pore
space dissolve into the HF fluid during the HF process (Dresel and Rose, 2010; Haluszczak et
al., 2013). A variety of processes can create brines in rock pore space, resulting in brine chemical
composition that varies among rock formations (Dresel and Rose, 2010). Because each major oil
or gas play has a distinctive rock and brine composition, the range of TDS concentrations in
produced waters varies by extraction location. For example, O&G wastewater from the
Fayetteville shale has been reported to have a TDS range of 3,000-80,000 mg/L (Alleman,
2011), while water from the Marcellus Shale has been reported to have a range of 10,000-
300,000 mg/L (e.g., Wilson et al., 2014). TDS concentrations in non-HF O&G wastewater have
similar ranges to HF wastewaters; Wilson et al. (2014) report a median TDS concentration from
conventional O&G plays of about 238,000 mg/L, with a standard deviation of about 63,000
mg/L.
If CWT facilities lack TDS removal technologies such as RO or distillation, these
facilities will not remove the ions that contribute to TDS concentrations, and these constituents
become part of the CWT waste stream. High concentrations of TDS degrade the potability of
drinking water, generally on the basis of taste, and can corrode water transport pipes. Based on
results from panels of tasters rating the palatability of drinking water, taste begins to degrade at
TDS levels above approximately 300 mg/L, and taste becomes unacceptable at concentrations
greater than ~ 1,200 mg/L (Bruvold and Ongerth, 1969). High levels of TDS can also negatively
affect aquatic biota through increases in salinity, loss of osmotic balance in tissues, and toxicity
of individual ions. Increases in salinity cause shifts in biotic communities, limit biodiversity,
exclude less-tolerant species and cause acute or chronic effects at specific life stages (Weber-
Scannell and Duffy, 2007). High TDS levels can also adversely affect agriculture irrigation and
livestock watering.
9.1.2 Halides
High concentrations of halides (e.g., bromide, chloride, iodide) are often present in
produced water and in the discharged effluents from CWT facilities treating O&G wastewater
that lack specific technologies for their removal (Ferrar et al., 2013; Parker et al., 2014). As one
component of TDS, halides originate from the rock and brine formations (Dresel and Rose,
2010). Haluszczak et al. (2013) note that in the Marcellus region, halide concentrations in
produced water are similar to those from conventionally drilled O&G wells, and the elevated
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concentrations are likely from brine in the rock formation. While HF injection fluids generally
have low chloride concentrations (~ 82 mg/1) (Haluszczak et al., 2013), the median chloride
concentration from flowback from 8 wells (taken at 14 days after injection) was 98,300 mg/L
(Haluszczak et al., 2013).
At high concentrations, halides such as chloride can be directly toxic to aquatic
organisms (Corsi et al., 2010). Halides also pose potential drinking water concerns due to their
reactivity and potential to form disinfection byproducts (DBPs) that can have adverse effects on
human health (e.g., Hladik et al., 2014; McTigue et al., 2014; Harkness et al., 2015). See Section
9.3.3 for a detailed description of DBP formation.
9.1.3	Metals
O&G wastewaters treated at CWT facilities commonly have high concentrations of
metals, including barium, calcium, iron, magnesium, manganese, and strontium (e.g., Haluszczak
et al., 2013). These metals occur naturally in the brines located within O&G formations. EPA has
established chemical-specific national recommended water quality criteria for some of these
metals (e.g., Ba, Mn, Fe) based on a variety of human health or ecological benchmarks.
Produced waters and CWT facility effluent have been reported to routinely exceed many of these
criteria (e.g., Ferrar et al., 2013).
9.1.4	TENORM
Naturally occurring radioactive materials primarily come from uranium-thorium decay
sequences (e.g., Ra226, Ra228) and are present in virtually all environmental media, including
rocks and soils. These radionuclides can become mobilized through the O&G extraction and
wastewater treatment processes, and as such are technologically enhanced or TENORM. Soluble
radionuclides are commonly present in produced water, with the specific makeup of nuclides and
isotopic composition dependent on the geological formation (Rowan et al., 2011). For many
O&G producing formations, this distinct isotopic "signature" is discernible even after facility
treatment, and can be a useful tracer for O&G wastes in downstream waters and sediments
(Rowan et al., 2011; Warner et al., 2013).
HF and shale gas drilling operations bring TENORM to the surface during production
operations because subsurface geologic formations commonly contain higher amounts of
radioactive isotopes than surface rock or soil (Haluszczak et al., 2013) and radioactive isotopes
desorb into solution at high salinity (Sturchio et al., 2001). TENORM can be present in CWT
effluent and can, under favorable environmental conditions, precipitate out in receiving waters or
be incorporated into downstream sediment. TENORM can also concentrate in waste sludge
generated by CWT processes, resulting in materials that have radioactivity levels exceeding the
ambient levels in the geologic formations. When not handled correctly, TENORM contamination
may pose potential human health concerns for wastewater plant staff or landfill operators (PA
DEP, 2015).
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9.1.5 Other Constituents
Other potential pollutants in O&G wastewater include chemicals contained in injection
fluids, such as surfactants, biocides, wetting agents, scale inhibitors, and organic compounds.
The composition of some HF chemicals are disclosed to the public, while others are considered
confidential business information (CBI) and HF service companies have not released information
on those chemicals to the public or regulatory agencies (U.S. EPA, 2012; Elliott et al., 2017).
EPA released a report on HF effects on drinking water resources, "Study of the Potential Impacts
of Hydraulic Fracturing on Drinking Water Resources," in 2012 (U.S. EPA, 2012). The report
provides a list of known chemicals that HF service companies use in HF activities and additional
chemicals that have been detected in flowback and produced water. Elliott et al. (2017) reviewed
the reported list of 925 chemicals to determine their impacts to human health. They found that
76% of the chemicals do not have toxicity information. For the 240 chemicals with toxicity
information, 65% are associated with developmental or reproductive toxicity.
Stringfellow et al. (2014) reviewed 81 known fracturing fluid chemicals for potential
toxicity to humans and effects on water treatment. They categorized the chemicals into
functional classes (Table 9-1) defined by the intended use or purpose. Not all chemicals analyzed
are used at every well. Stringfellow et al. (2014) concluded that biocides in HF fluid are a high
concern because many of those chemicals are classified as toxic to human health or the
environment. Additionally, many fracturing chemicals (such as gelling agents) that have high or
moderate chemical oxygen demand (COD) can cause problems to wastewater treatment
processes. Stringfellow et al. (2014) estimated that HF wastewater has high COD and can cause
treatment challenges.
Table 9-1. Chemical Categories in HF Fluids
( hoiniciil cuk'iion
Purpose
Gelling agents
Increases the viscosity to better transport into fractures
Friction reducers
Reduces fluid surface tension to help remove HF fluid from the geologic formations
Crosslinkers
Binds molecules to increase viscosity and elasticity for better HF fluid transport
Breaker
Chemicals used to "break" the gelling agent used in fracking that decrease solution
viscosity and improve flow
pH adjuster
Adjusts pH to improve effectiveness of other chemicals in HF fluid
Biocides
Controls bacteria to prevent chemical degradation and damage to well materials
Corrosion inhibitors
Creates protective layer on well materials to prevent corrosion from HF fluid
chemicals
Scale inhibitors
Prevents scaling to reduce blockages
Iron control
Prevents iron precipitates from forming within the fractures; helps increase
permeability and well productivity
Clay stabilizers
Prevents clays within formation from swelling
Surfactants
Controls viscosity and helps improve fluid recovery after fracturing
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Because of the information gap in the chemical make-up of HF fluids and the information
gap for 76% of the known HF fluid chemicals, this chapter does not contain specific impacts
analyses on water quality, aquatic life, or human health from HF fluid chemicals.
9.2 Exposure Pathways for CWT Waste Streams
Environmental and human exposure to pollutants in O&G wastewater can occur through
multiple pathways related to treatment at CWT facilities. Environmental releases and human
interactions with pollutants can occur from discharge of treated effluent to the environment,
during transport to CWT treatment facilities, during CWT treatment itself, or through other
waste streams such as sludge, spills, and fugitive emissions. Rozell and Reaven (2012) estimated
that wastewater disposal at treatment facilities had the highest environmental contamination risk
and potential environmental harm when compared to other potential exposure pathways (e.g.,
transportation spills, well casing leaks, leaks through fractured rock, drilling site discharge). This
section summarizes these exposure pathways for CWT waste streams (Figure 9-1). The
remainder of the document describes in more detail the concentrations of constituents in CWT
effluents and the effects of these constituents on downstream water quality, when CWT facilities
discharge directly to surface water.
9.2.1	Discharge of CWT Effluent to Rivers and Streams
CWT facilities that hold direct discharge permits can release wastewater directly to rivers
and streams after treatment. Treatment processes do not always effectively remove all of the
constituents that originate from O&G extraction. As a result, the effluent from these facilities can
contain high concentrations of O&G related compounds, and therefore discharge of treated
effluent can represent a significant pathway for potential releases to the environment. Section 9.3
summarizes the concentrations of pollutants in CWT effluent and the effects of these discharges
on downstream water quality. Sections 9.4 and 9.5 describe the human health and aquatic life
impacts from these discharges in receiving waters.
9.2.2	Solid Waste and Sludge
TENORM can be present in sediments and particulates from O&G operations, and
dissolved TENORM co-precipitates with other ions during certain treatment processes such as
chemical precipitation. As a result, TENORM and associated radioactivity tends to become
concentrated in the residual solids or sludge produced by the treatment unit. Solid residual waste
enriched in TENORM can also be generated during storage of flowback and produced waters in
impoundments prior to treatment (Zhang et al., 2015). CWT operators must periodically remove,
dewater, and dispose of sludge. The dewatering process creates filter cakes, which can contain
elevated levels of radium. Handling of these produced water treatment sludge poses potential
human health and environmental concerns (e.g., Belcher and Resnikoff, 2013; Brown, 2014),
although a recent evaluation of the human health implications of this pathway suggest that
exposure of workers may not be a significant concern (PA DEP, 2015).
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Different wastewater treatment methods for O&G wastewaters can result in varying
levels of TENORM in solid residual waste (sludge) (PA DEP, 2015). The ability to dispose
sludge in landfills depends on the level of radioactivity, as states have different regulations on
what constitutes radioactive waste and how and where it can be disposed. This situation is
complicated by the non-uniformity in regulatory language, administrative codes, and regulating
authorities (e.g., Litvak, 2016). For some states, there is little or no regulatory language, while
other states prohibit disposal of TENORM, and still others indicate that disposal decisions are
made on a case-by-case basis (Abt Associates, 2016). TENORM-enriched sludge disposed in
landfills can produce TENORM-enriched leachate, therefore leaching of solid residual waste in
landfills may also be a concern (Zhang et al., 2015).
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Water abstraction
Chemical mixing
Surf*e» wtter

6ro«niwattr
Proppant
Chemic.il
Storage
V
Mamters

C|..f J
HUiCt
storage
Pumping trucks
Injection
f iowback
Wastewater & waste treatment
Recycling facility
waste Ife
atu Hps
Fluirf/flowback
storage
Contaliwfs/Unki Open/closed oil
Surface watftr
ksti'sik Sfltl
Operational release
Source: Modified from Vandecasteele et al. (2015), Figure 4.
Figure 9-1. HF Water Life Cycle38.
38 The conceptual model shows the intended pathways of chemical transport (blue lines) and accidental chemical releases (red lines) that can occur in the HF process.
This chapter focuses on information on the wastewater treatment portion of the water cycle.
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9.2.3	Transportation Spills and A ccidental Releases
Another pathway for environmental releases of pollutants from disposal of O&G
wastewater at CWTs is the potential for spills of wastewater during transportation from O&G
wells or at treatment facilities. Spills of untreated wastewaters can negatively impact water
quality and aquatic life, and those impacts can persist in the environment for years. Flowback
water spills in the Marcellus Shale region have been shown to negatively impact aquatic life
including fish and macroinvertebrates (Grant et al., 2016). Impacts from reported O&G
wastewater spills in North Dakota persisted for up to four years after the spill events and
included elevated TDS, contaminants (including selenium, lead, and ammonia), and
accumulation of radium in soil and sediment (Lauer et al., 2016).
The likelihood of spills during transportation increases as the volume of wastewater and
number of trips increases (Belcher and Resnikoff, 2013; Rahm et al., 2013; Hansen, 2014).
Maloney et al. (2017) studied accidental spills in Pennsylvania, New Mexico, Colorado, and
North Dakota and determined that wastewater is one of the top three materials spilled in HF-
related activities.
Generally, states regulate the handling, storing, and transport of HF wastewater (Hansen,
2014). Some states, such as Pennsylvania, regulate the waste under waste management laws that
provide detailed standards for storing and transporting waste, and procedures for spills or
accidental discharges. Regulations in Ohio also require fracturing wastewater haulers to install
and use electronic transponders to monitor their shipments (Thorn, 2012).
9.2.4	Air Emissions
Wastewater from O&G extraction often contains volatile organic compounds (VOCs),
such as benzene, toluene and napthalene, which can volatilize from wastewater into the air.
VOCs can contain hazardous air pollutants (HAPs39), criteria pollutants, and greenhouse gases.
Some VOCs also participate in the formation of ozone (O3), which can cause ground-level smog
and lead to potential impairment of lung function (Colborn et al., 2011).
The O&G industrial sector is one of the largest sources of VOC emissions to air in the
United States. In 2008, the industry accounted for approximately 12% of VOC emissions
nationwide while representing 67% of VOC emissions released by industrial source categories
(Clark and Veil, 2009). VOCs in O&G wastewater can either originate from the injected fluid
makeup or from the formation (U.S. EPA, 2016a). Varying amounts and species of VOCs have
been found from different O&G formations (Strong et al., 2013; Ziemkiewicz, 2013; Cluff et al.,
2014; Akob et al., 2015; Butkovskyi et al., 2017). Currently there is limited information on VOC
emissions related to O&G wastewater treatment at CWT facilities. However, CWTs often have
impoundments or ponds to store or settle wastewater before it is treated. Wastewater stored in an
39 HAPs, also known as toxic air pollutants or air toxics, are pollutants that are known or suspected to cause cancer
or other serious health effects, such as reproductive effects or birth defects, or adverse environmental effects. EPA
has listed National Emission Standards for 187 HAPs as toxic air pollutants to the environment.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 9-Environmental Impacts
open-air impoundment at a CWT accepting O&G wastewater has been shown to emit VOCs into
the air (Field et al., 2015).
9.3 Downstream Impacts of CWT Effluent
This section summarizes available data from the literature on pollutant concentrations in
CWT effluent, and concentrations of these constituents in receiving waters upstream and
downstream of CWT discharge points. The data presented here are direct summaries of values
reported in the literature. In some cases, the values reported in the literature are means from
multiple sampling points; whereas in other cases these values are individual measurements from
single analyses. Downstream concentrations of pollutants are compared to applicable thresholds.
Thresholds can include primary (maximum contaminant level or MCL) and secondary (SMCL)
drinking water standards, acute (criteria maximum concentration or CMC) and chronic (criterion
continuous concentration or CCC) water quality criteria for protection of aquatic life, and other
ecological or human health thresholds determined in scientific literature. EPA did not attempt to
standardize these values or perform additional statistical analyses on the reported values. Section
9.4 describes in more detail the documented and potential impacts of these pollutants on human
health. Section 9.5 summarizes documented and potential impacts to aquatic life.
9.3.1 TDS
There is not an MCL for TDS, but EPA has established an SMCL for TDS of 500 mg/L
(U.S. EPA, 2016a). The SMCLs are non-health related guidelines that focus on aesthetic
qualities of water, such as taste or odor. CWT effluent concentrations of TDS have been reported
to exceed this SMCL: based on a review of available literature, TDS concentrations in CWT
effluent range from 562 to 186,625 mg/L (Volz et al., 2011; Wilson and VanBriesen, 2012;
Ferrar et al., 2013; Warner et al., 2013; Wilson et al., 2014). To illustrate the range in TDS
concentrations in CWT effluent and to show the impact CWT facilities have on receiving waters'
TDS concentrations, EPA summarized documented TDS concentrations from the literature
(Sources: PA DEP, 2009, 2013; Volz et al., 2011; Wilson and VanBriesen, 2012; Ferrar et al.,
2013; Warner et al., 2013; Wilson et al., 2014) in Figure 9-2. The blue line is the SMCL (500
mg/L) and the grey band represents the lowest concentrations of TDS that negatively affect
zooplankton, fish, and macroinvertebrates (700 to 2,000 mg/L). Note that the concentrations in
Figure 9-2 are on a logarithmic scale in order to illustrate the full range of reported
concentrations.
As shown in Figure 9-2, TDS concentrations in effluent and in receiving waters
downstream of these CWT facilities are higher than upstream concentrations. Upstream
concentrations ranged from 104 to 246 mg/L (PA DEP, 2009, 2013; Warner et al., 2013), while
downstream concentrations ranged from 250 mg/L to 5,926 mg/L. The large variability in
downstream TDS concentrations occurs because studies report results from sites located at
varying distances from the effluent discharge location; two of the studies had sites over 300
meters downstream (PA DEP, 2013; Warner et al., 2013).
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Section 9-Environmental Impacts
Based on the available literature, TDS concentrations downstream from the CWT
discharge points evaluated in these studies exceed the SMCL, and these elevated concentrations
can be harmful to freshwater aquatic life. For comparative purposes, freshwater is defined by
TDS concentrations less than 1,000 mg/L, and water is classified as brackish for concentrations
between 1,000 and 10,000 mg/L. As shown in Figure 9-2, TDS concentrations upstream of the
CWT discharge points evaluated in these studies are typically in the freshwater range, but high
TDS inputs from CWT effluents can elevate the downstream concentrations to the brackish
water category.
TDS
10
cn
&
c
O
*+_•
A3
4_»
C
m
u
c
O
u
10
10
Upstream (N=4)
Effluent (N=7)
Downstream (N=5)
Figure 9-2. TDS Concentrations from Sites Upstream of Effluent Discharge, Effluent from
Facilities Treating O&G Wastewater, and Downstream of Discharge Sites
The elevated TDS concentrations downstream from CWT discharge points can negatively
affect aquatic life such as fish, zooplankton, and macroinvertebrates. Several studies summarized
by Scannell and Jacobs (2001) have indicated that TDS concentrations greater than 700 mg/L
reduce growth, decrease survival rates, and alter behavior in macroinvertebrate communities
(e.g., Hamilton et al., 1975; Khangarot, 1991; Hoke et al., 1992; Mount et al., 1997; Tietge et al.,
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Section 9-Environmental Impacts
1997). Based on laboratory bioassays with Ceriodaphnia dubia, Hoke et al. (1992) calculated
that the TDS concentration that is lethal to 50% of these zooplankton (LC50) was 735 mg/L.
For coho salmon and rainbow trout, TDS concentrations greater than 750 mg/L can
decrease fertilization success (Stekoll et al., 2001). Multiple fish species (i.e., fathead minnows,
rainbow trout, Atlantic salmon, brook trout, northern pike, walleye pike, and rainbow trout) have
reduced survival rates and hatching success at TDS concentrations greater than 1,200 mg/L
(Stoss et al., 1977; Ketola et al., 1988; Koel and Peterka, 1995; Tietge et al., 1997; EVS
Environmental Consultants, 1998; Stekoll et al., 2001). Additionally, a field study in
Pennsylvania indicated that impairment for fish communities occurs between 2,000 to 2,300
mg/L (Kimmel and Argent, 2010).
The toxicity of TDS to aquatic organisms can vary widely depending on its ionic
composition (Mount et al., 1997). Individual ion salts exert differing levels of toxicity, but
toxicity can also change and increase with interactions between ions, including those present in
upstream waters (Mount et al., 1993). Johnson et al. (2014) used brines with ion compositions
representative of produced water effluent to determine that larval mayfly growth and
development are inhibited at TDS concentrations of 767 mg/L in such ionic compositions.
Conductivity is often measured in situ as a proxy for TDS, which cannot be measured
directly in the field. PA DEP (2013) and Patnode et al. (2015) reported field measurements
showing that conductivity increased by an order of magnitude or more at sites downstream from
CWT discharge points compared to upstream sites. In those two studies, upstream conductivity
measurements were below 200 |iS/cm, whereas downstream conductivity ranged from 200 to
8,400 |iS/cm. Another Pennsylvania Department of Environmental Protection (PA DEP) study
observed conductivity concentrations increase from 290 |iS/cm to over 1,300 |iS/cm downstream
of a CWT facility (PA DEP, 2009). Kimmel and Argent (2010) and Johnson et al. (2014) suggest
that conductivity values greater than 1,000 |iS/cm can negatively affect fish assemblages and
macroinvertebrate growth and survival; thus, these elevated conductivity measurements resulting
from CWT discharge are a potential threat to aquatic life.
9.3.2 Chloride
The national recommended water quality criteria for protection of aquatic life for chloride
range from a chronic CCC of 230 mg/L to an acute CMC of 860 mg/L (U.S. EPA, 2017). EPA
created these criteria to provide guidance to state and tribal governments to protect aquatic life.
The CCC is the maximum concentration for chronic exposure of a pollutant to aquatic life
without causing negative effects. The CMC is the maximum concentration for acute exposure of
a pollutant to aquatic life without causing negative effects. Effluent concentrations documented
in the literature from CWTs treating O&G wastewater can exceed these criteria by many orders
of magnitude, ranging from 229 mg/L to 117,625 mg/L (Volz et al., 2011; Wilson and
VanBriesen, 2012; Ferrar et al., 2013; PA DEP, 2013; Warner et al., 2013; Wilson et al., 2014).
Figure 9-3 shows the range in chloride concentrations reported in the literature for upstream,
CWT effluent, and downstream locations (Sources: Short et al., 1991; PA DEP, 2009, 2013;
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 9-Environmental Impacts
Volz et al., 2011; Wilson and VanBriesen, 2012; Ferrar et al., 2013; Warner et al., 2013; Hladik
et al., 2014; Wilson et al., 2014; U.S. EPA, 2015b; Landis et al., 2016). The green line is the
CMC (860 mg/L), the blue line is the CCC (230 mg/L), and the red line is the concentration that
caused increased mortality in unionid mussels (80 mg/L) (Patnode et al., 2015). Reported
upstream concentrations range from 13.9 to 68 mg/L while downstream concentrations range
from 15 to 17,386 mg/L (Short et al., 1991; PA DEP, 2009, 2013; Warner et al., 2013; Hladik et
al., 2014; U.S. EPA, 2015b; Landis et al., 2016). The large variability in downstream chloride
concentrations occurs because many studies reported results from sites located at varying
distances from the effluent discharge location; two of the studies we compiled had sites over 50
km downstream (U.S. EPA, 2015b; Landis et al., 2016).
Chloride
io-
10
10:
10'
Upstream (N=10)	Effluent (N=7)	Downstream (N=18)
Figure 9-3. Chloride Concentrations from Sites Upstream of Effluent Discharge, Effluent
from Facilities Treating O&G Wastewater, and Downstream of Discharge Sites
In addition to the CCC and CMC guidelines, a number of studies document specific
effects of elevated chloride concentrations on aquatic life. Chloride concentrations as low as 100
mg/L have been shown to alter diatom species composition (e.g., Zimmermann-Timm, 2007),
and Ziemann et al. (2001) demonstrated that freshwater diatom species decline when chloride
concentrations are greater than 400 mg/L. Fish have varying degrees of tolerance to chloride
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 9-Environmental Impacts
concentrations. Fathead minnows and rainbow trout have decreased early life-stage survival for
chronic exposure at concentrations between 870 and 1,500 mg/L (Sigel, 2007). Lethality
increases for fathead minnow, brook trout, bluegills, and Indian carp, for acute exposures to
chloride concentrations between 3,000 and 12,000 mg/L (Sigel, 2007). Aquatic invertebrates are
more sensitive to elevated chloride levels than fish. Cladocerons have reduced reproductive
success and survival in chronic exposures to chloride at 440 to 735 mg/L (Sigel, 2007).
9.3.3 Bromide
Bromide is another component of TDS and, like chloride, the concentrations at sites
upstream and downstream of CWT facilities sites follows a pattern similar to TDS (Figure 9-4).
(Sources: Volzetal., 2011; Wilson and VanBriesen, 2012; Ferraretal., 2013; PA DEP, 2013;
States et al., 2013; Warner et al., 2013; Hladik et al., 2014; McTigue et al., 2014; Wilson et al.,
2014; U.S. EPA, 2015a; Landis et al., 2016; Weaver et al., 2016). In regard to CWT facilities,
there are more studies reporting bromide concentrations than TDS and chloride because elevated
bromide concentrations in source water can increase formation of certain disinfectant byproducts
(DBPs) during drinking water treatment processes. DBPs form when organic material contacts
disinfectants used in the drinking water treatment process such as chlorine, chloramine, chlorine
dioxide, or O3. DBPs include compounds such as trihalomethanes (THMs) (e.g., chloroform,
bromodichloromethane, dibromochloromethane, bromoform) and haloacetic acids (HAAs)
(Hladik et al., 2014). When halides such as bromide are present in water, the resulting DBPs
formed are brominated.
Some DBPs are regulated, including total trihalomethanes (TTHM) (0.080 mg/L MCL),
five specific HAAs (0.060 mg/L MCL), and bromate (0.010 mg/L) (U.S. EPA, 2015a). EPA
does not regulate bromide. However, U.S. EPA describes how high bromide levels can lead to
increases in the concentrations of these harmful trihalomethanes, and notes that drinking water
utilities should be concerned about the effects of upstream bromide discharges on their
operations (U.S. EPA, 2015a).
Bromide reacts with disinfectants during the water treatment process to form bromine.
Bromine then reacts with organic matter to create brominated DBPs (Wang et al., 2016).
Bromine reacts faster and more efficiently than chlorine (Westerhoff et al., 2004; McTigue et al.,
2014), therefore as bromide concentrations increase in source water, brominated DBPs increases
(Wang et al., 2016), and the speciation of DBPs shifts from chlorinated to brominated
(Pourmoghaddas et al., 1993).
Brominated DBPs have been found to be more cytotoxic and genotoxic than their
chlorinated analogs, and therefore their increased formation poses an increased health risk
(Echigo et al., 2004; Richardson et al., 2007, Harkness et al., 2015). Regli et al. (2015) found that
increased bromide concentrations (0.050 mg/L increase) in source water increases bladder cancer
risk over a lifetime. Wang et al. (2016) found that even low (0.02-0.04 mg/L) bromide
concentrations in source water were associated with increased cancer risk due to TTHMs. Due to
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 9-Environmental Impacts
the higher toxicity of the brominated forms of DBPs, cancer risk significantly increased even if
the finished water met the current TTHM MCL.
Bromide concentrations exceeding -0.1 mg/L in source water are associated with
increased risk of brominated DBP formation in finished drinking water (e.g., Landis et al., 2016;
Weaver et al., 2016).
Bromide
1Q:
O) 10"
E
c
o
f0
s_
+_>
c
QJ
U
C
o
u
10
10l
10"
Upstream (N=19)
Effluent (N=23)
Downstream (N=35)
Figure 9-4. Bromide Concentrations from Sites Upstream of Effluent Discharge, Effluent
from Facilities Treating O&G Wastewater, and Downstream of Discharge Sites
Natural bromide concentrations in surface waters away from the coast are generally low
(States et al., 2013); based on our data compilation, documented bromide concentrations
upstream of CWT facilities range from 0.03 to 0.64 mg/L (PA DEP, 2013; States et al., 2013;
Warner et al., 2013; Hladik et al., 2014; U.S. EPA, 2015b; Landis et al., 2016). Bromide
concentrations in CWT effluent vary greatly (ranging from 0.60 to 8,290 mg/L; see Volz et al.,
2011; Wilson and VanBriesen, 2012; Ferrar et al., 2013; PA DEP, 2013; McTigue et al., 2014;
Wilson et al., 2014; Weaver et al., 2016), with the highest effluent concentration reported in the
literature exceeding the 0.1 mg/L level by four orders of magnitude. Downstream concentrations
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Section 9-Environmental Impacts
range from 0.07 to 138 mg/L, with 75% of the reported results exceeding the 0.1 mg/L level.
Figure 9-4 summarizes the ranges of literature reported upstream, effluent, and downstream
bromide concentrations.
There are currently no aquatic life criteria or standard limits for bromide. The primary
concern related to elevated bromide concentrations is DBPs formed during drinking water
treatment processes. The blue line in Figure 9-3 is the 0.1 mg/L value, where drinking water
treatment facilities can experience elevated levels of bromide-associated DBPs. Landis et al.
(2016) observed elevated downstream bromide concentrations over 50 km away from a CWT
discharge site. Warner et al. (2013) also observed persistent elevated bromide concentrations
downstream of CWT facilities treating O&G wastewater. Boxes 9.1 and 9.2 provide more details
on the effects of CWT facilities on instream bromide concentrations and DBP formation.
9.3.4 Metals
Metals such as barium, lithium, and strontium can all be components of O&G
wastewater, but few studies of CWTs focus on the impacts of metals on receiving waters. Table
9-2 provides the range of concentrations reported in relevant literature for upstream, effluent, and
downstream concentrations for those three metals. EPA has not developed an MCL or other
regulatory criteria for lithium, but barium and strontium have MCLs of 2 and 3 mg/L,
respectively (Table 9-2) (U.S. EPA, 2016b). Concentrations of barium and strontium in CWT
effluent are high enough to elevate downstream concentrations above the respective MCLs.
However, elevated concentrations of these metals may not persist further downstream due to
reactive natures (Warner et al., 2013).
Table 9-2. Metal Concentrations Upstream, in CWT Effluent,
and Downstream (all units in mg/L)
Moliil
I psliviim
i-i rriiioni
Dow nsliviini
MCL
Barium
0.05 to 1.3
0.99 to 27.3
0.15 to 10.9
2.0
Lithium
< 0.025
3.36
0.31 to 0.66
No MCL
Strontium
0.05 to 0.19
42 to 2,981
0.49 to 73
3.0
9.3.5 TENORM
Produced waters contain elevated levels of TENORM. Effluent from CWT facilities
treating O&G wastewater have a wide-range of 226Ra and 228Ra concentrations, depending on the
source formation from which the O&G is extracted and the type and efficiency of treatment
employed. For example, Marcellus Shale produced waters tend to contain higher TENORM
levels than waters from other formations (Rowan et al., 2011). In produced waters, radium
activity and TDS levels are positively correlated (Rowan et al., 2011), and radium adsorption to
particles increases as salinity decreases (Vengosh et al., 2014). As a result, when high-salinity
CWT effluent mixes with the low-salinity receiving water, radionuclides tend to adsorb into
stream sediment. Because Ra-combined (226Ra + 228Ra) is adsorbed into sediment instead of
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Section 9-Environmental Impacts
traveling in the water column downstream, this section summarizes both sediment and water
concentration data for TENORM.
Figure 9-5 and Figure 9-6 show the effluent concentrations for radium (226Ra ,228Ra, and
Ra-combined) and the impact to downstream water and sediment concentrations. Data in Figure
9-5 are from a PA DEP (2013) study investigating the effects of CWT and POTW discharge on
water quality and aquatic life. The green line is the MCL for Ra-combined (5 pCi/L). The Ra-
combined concentration in effluent averaged 25.1 pCi/L. At 50 m downstream, the mean Ra-
combined concentration was 11.06 pCi/L, which exceeds the Ra-combined MCL of 5 pCi/L. At
400 m downstream from the effluent discharge, Ra-combined remained elevated compared to
upstream values (0.312 to 0.632 pCi/L), but fell below the MCL to 4.3 pCi/L.
30
25
3 20
|
1.5
03
+j
c
m
u
c _
o 10
u
5
0
-50 0 50 100 150 200 250 300 350 400
Distance from Outfall (m)
Figure 9-5. Radium Concentrations in Water Above and Below CWT Outfall
Sources: PA DEP, 2013; Warner et al., 2013
CWT facilities typically discharge to freshwater sources, so elevated sediment
concentrations of TENORM are often localized downstream of effluent discharge sites as radium
adsorbs to sediments. The data in Figure 9-6 are from three studies: Warner et al., 2013; PA
DEP, 2013; and PA DEP, 2016. PA DEP (2016) reported sediment Ra-combined concentration
Water Radium Data: CWT facilities
i "	r
•	Ra-226
® Ra-228
•	Ra-combined
II	I
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Section 9-Environmental Impacts
for nine samples from four CWT outfalls; they ranged from 3.4 to 507.9 pCi/g, with a mean
concentration of 104.0 pCi/g.
Warner et al. (2013) measured radium concentrations in sediment upstream, downstream,
and at the discharge location. They found that radium was substantially reduced in the treated
effluent relative to the source produced water (> 90 percent), but 226Ra levels in stream sediments
were measured at 15-240 pCi/g at the point of discharge. These sediment concentrations are
approximately 200 times greater than radioactivity found in upstream and background sediments
(0.6-1.2 pCi/g) and exceed many states' radioactive rules or regulations for unrestricted solid
waste disposal, which range from 5-30 pCi/g (Abt Associates, 2016). Although no directly
applicable federal regulatory thresholds exist for radium levels in downstream sediments, to
provide additional context the EPA's health-based soil cleanup criterion for surface soil at
Superfund (Comprehensive Environmental Response, Compensation and Liability Act,
CERCLA) sites with radioactive contamination is 5 pCi/g 226Ra (PA DEP, 2016).
103
102
13
ns
O
Cl
c
•H 10i
CO 10
4=
c
s
c
o
O
10°
10 1
-500	0	500	1000	1500	2000
Distance from Outfalf (m)
Figure 9-6. Radium Concentrations in Sediment Above and Below CWT Outfall
Sources: PA DEP, 2013, 2016; Warner etal., 2013.
PA DEP analyzed radium concentrations in sediments above and below a CWT facility
discharge point (PA DEP, 2013). Like the Warner et al. (2103) study, PA DEP found elevated
Sediment Radium Data: CWT facilities
Ra-226
O Ra-228
Ra-combined
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Section 9-Environmental Impacts
Ra-combined levels in the sediment approximately 50 m downstream (1.8-2.1 pCi/g) compared
to upstream levels (0.8-0.9 pCi/g). Sediment concentrations at the CWT discharge location
ranged from 73.9-85.5 pCi/g, over 70 times higher than the upstream concentrations, and above
the upper range (30 pCi/g) for states' regulations for solid waste disposal (Abt Associates, 2016).
Ra-combined sediment concentrations are elevated (ranging from 1.1 to 205 pCi/g)
within 300 m of the discharge site (PA DEP, 2013; Warner et al., 2013). The Ra-combined
sediment concentrations decrease with increasing distance from the outfall. Both PA DEP (2013)
and Warner et al. (2013) noted that sediment concentrations resemble upstream or background
concentrations at distances greater than 300 to 400 m downstream of the discharge outfall.
However, concentrations immediately after the outfall (0 to 10 m) range from 64 to 205 pCi/g,
which is over 60 pCi/g above background sediment levels. For comparison, EPA remediation
goals for CERCLA sites is 5 pCi/g above background levels (PA DEP, 2016).
9.3.6 Summary: Impacts to Water Quality and Sediment
CWT facilities treating O&G wastewater and discharging to surface waters have direct
and measurable impacts on downstream surface waters and sediment. As shown in Figure 9-2
through Figure 9-6, reported effluent and downstream concentrations are higher than upstream
concentrations in the surface water for TDS, chloride, bromide, metals, and TENORM. In many
instances, downstream concentrations exceed applicable aquatic and/or drinking water
thresholds, indicating that the elevated downstream concentrations can negatively affect human
health or aquatic life. Documented and potential impacts to human health and aquatic life are
discussed in more detail in Sections 9.4 and 9.5.
Figure 9-2 through Figure 9-6 also demonstrate the wide range in effluent and
downstream concentrations of O&G constituents. Many factors influence the effluent and
downstream concentrations. First, CWTs accept and treat a range of wastewater types. The total
volume of O&G wastewater treated at a given CWT facility is variable. Therefore, the effect
O&G wastewater has on effluents is dependent on the CWT treatment and discharge schedule.
Additionally, the downstream concentrations vary because upstream flow and concentrations and
the effluent flow and concentrations vary over time. Generally, higher concentrations for
constituents in surface water occur when effluent volume and concentrations are high, and the
receiving water has low flow, thereby having a small dilution effect. Downstream concentrations
for constituents are lower when the receiving water has high flow compared to the effluent
discharge volume.
Because the effect CWT facilities have on downstream water quality is variable, Warner
et al. (2013) calculated an annual average enrichment factor for pollutants discharged from
facilities accepting O&G wastewater to determine how much impact CWT facilities had on
downstream waters (see Box 1). Even with variability in effluent concentrations and upstream
conditions, there is a clear impact to downstream concentrations from CWT effluent. In the
following sections, documented and potential impacts from elevated concentrations for
pollutants from CWT effluent are discussed.
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Section 9-Environmental Impacts
BOX 1. INSTREAM IMPACTS: ENRICHMENT FACTORS
Warner et al. (2013) calculated enrichments factors (EFs) downstream of a CWT facility accepting
O&G wastewater to understand the magnitude of impact CWT facilities have on receiving waters. The
EF for a constituent is the ratio of the downstream concentration divided by the upstream
concentration, effectively showing what proportion of the downstream chemical concentration is from
CWT effluent discharge. In this study, the EFs at the CWT discharge site for bromide and chloride
reached maximums of 12.000 and 6.000. respectively. Because the variability in upstream and
discharge conditions influences EF results. Warner et al. (2013) calculated average yearly EFs for
constituents to estimate the average CWT facility contributions over a year. They used the 2012
average upstream and effluent constituent concentration, and the average streamflow and CWT
discharge rate to calculate average yearly EFs. The estimated average yearly EF for chloride and
bromide were 4.5 and 12 times the upstream concentrations. Warner et al. (2013) determined that
downstream concentrations were significantly higher than corresponding upstream concentrations.
The dashed line represents the estimated average yearly enrichment factor for each constituent.
lOOOO
1000
100
10
1
» .7 ii
X
E-uwccst Average Yeort j 4 ix.
i	i * i.tA...i	« *
-303 0 3C0 COG 900 1200 1500 1SOO
Distance from Effluent {meters!
10 CO 00
10000
lofin
Ki'VK1	>' 12*}
-300 0 300 mo 900 1200 15CXI 1800
Distance frcmfcffluent (meters)
2010
2011a
?mih
2012a
201213
2010
¦ 2011a
20 lib
201,2a
Z'JUh
Source: Warner et al., 2013, Figures 3a and 3b.
Figure 9-7. Chloride and Bromide Surface Water Enrichment Factors on a Log Scale at a
Brine Treatment Facility Treating O&G Wastewater
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Section 9-Environmental Impacts
9.4 Human Health Impacts
9.4.1 Documented Drinking Water Impacts
As summarized in Section 9.3, CWT effluent has been reported to contain high
concentrations of halides, including bromide and chloride. Halides are precursors for DBPs,
which can form when drinking water disinfection processes interact with organic and inorganic
matter in intake waters. DBPs can have potential adverse effects on human health (Hladik et al.,
2014). Because brominated species of these compounds tend to be more toxic than chlorinated
analogs (e.g., McTigue et al., 2014), one of the primary human health concerns related to CWT
effluent is the downstream formation of brominated DBPs during drinking water treatment. An
increase in halides in intake waters could also affect the ability of conventional drinking water
plants to comply with the Stage 2 Disinfectants/Disinfection Byproducts Rule (DBPR).40
O&G wastewater brines typically have distinct Br/CI ratios, which provide a potential
way to identify the sources of these brines within a watershed (Ziemkiewicz et al., 2013; Landis
et al., 2016). In streams that are impacted by multiple anthropogenic sources of bromide, several
studies have found that CWT discharges are the primary contributors to elevated bromide at
drinking water intakes (U.S. EPA, 2015b; Landis et al., 2016). Upon the U.S. Congress urging
that EPA study the effects of HF on drinking water resources, EPA investigated the sources of
inorganic species to public drinking water systems (PDWS) intakes during low flow conditions
in 2012 in the Allegheny River (U.S. EPA, 2015b). The objectives of this "source
apportionment" study were to quantify the cumulative contribution of CWT facilities that
primarily treat HF wastewater to two PDWS intakes, and to distinguish their contribution from
other potential sources of bromide.
The predominant sources of bromide identified in this study were: (1) treated O&G
wastewater discharged from CWT facilities and (2) coal fired power plants with flue gas
desulfurization (FGD). CWT facilities contributed the majority of the bromide (89%) to one
PDWS intake 51 km downstream of the facility. A combination of CWT facilities (37%) and
FGD (59%) contributed most of the bromide found at a second intake (U.S. EPA, 2015b), which
was 90 km downstream from the nearest CWT facility. EPA source apportionment techniques
may serve as a useful tool to quantify contaminant impacts in other complex river systems with
multiple source discharges.
Results from Landis et al. (2016) support EPA's findings. They found that elevated
halides measured during low river flow conditions resulted from discharges of CWT effluents
containing characteristically lower Cl~ : Br ratios than the receiving waters. Landis et al. (2016)
found a clear chemical signature of CWT discharges at a PDWS intake approximately 50 km
40 The Stage 1 DBPR reduces drinking water exposure to DBPs. The rule applies to community water systems that
add a disinfectant to the drinking water during any part of the treatment process. The Stage 2 DBPR strengthens
public health protection by tightening compliance monitoring requirements for TTHM and HAAs. The rule targets
public water systems with the greatest risk (https://www.epa.gov/dwreginfo/stage-1 -and-stage-2-disinfectants-and-
disinFcction-byproducts-rules).
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Section 9-Environmental Impacts
downstream of a CWT facility. Although this signal was present during periods of both low and
high flow, the effect was lower at high flow, and diminished at a second a PDWS intake
-150 km downstream. Field sampling results from the Allegheny River demonstrated that both
bromide and chloride concentrations increase significantly during periods of CWT facility
operation (e.g., Landis et al., 2016; see Box 2).
Elevated concentrations of bromide are associated with increased DBP concentrations in
drinking water treatment facilities. Parker et al. (2014) demonstrated that both total and
brominated DBPs increase markedly in finished water with the addition of even highly diluted
flowback waters containing bromide to the source water. States et al. (2013) and Wang et al.
(2016) documented correlations between bromide concentrations at drinking water intakes and
concentrations of both brominated and TTHMs in finished water in the Allegheny and
Monongahela rivers, respectively. Wang et al. (2016) did not determine the source of bromide,
but States et al. (2013) determined that CWT facilities contributed approximately 51% of the
elevated bromide concentrations observed in their study.
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Section 9-Environmental Impacts
BOX 2A. HALIDES AND DBPS IN THE ALLEGHENY RIVER
In 2010. the Pittsburgh Water and Sewer Authority (PWSA) observed a significant increase in the
concentration of total THMs. especially brominated THMs. in its finished water. The cause of this
increase was traced back to elevated levels of bromide in PWSA's raw source water (States et al..
2013). PWSA was concerned about brominated THMs because their conventional treatment process
(enhanced coagulation and secondary sedimentation) was ineffective at removing bromide (States
et al.. 2013).
To trace the elevated bromide to its source. Landis et al. (2016) measured specific conductance and
halide concentrations at 6 sites along the upper Allegheny River during the spring, summer and fall of
2012 downstream from a CWT facility. Using specific conductivity measured at the CWT discharge site
and at sites downstream, the authors calculated travel time of effluent from the CWT facility to each of
the downstream locations (Figure 9-8). After adjusting for this travel time, the authors calculated the
enrichment of bromide and chloride concentrations downstream due to CWT facility discharges.
At is the estimated travel time of the CWT effluent plume, as measured from the lag between peaks.
1600
t.-osday vVcd-c-oda, "Ii-.-?<3ay Friday Saturday
260
- 240
- 220
- 180
<£>•

J?
AW
JV
r 160
K&


Source: Landis et al., 2016, Figure 2.						
Figure 9-8. Specific Conductivity Measurements at the CWT Discharge Point (grey shading)
and at a Monitoring Site ~ 12 km Downstream (black lines)
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Section 9-Environmental Impacts
BOX 2B. HALIDES AND DBPS IN THE ALLEGHENY RIVER
Landis et al. (2016) compared downstream bromide concentrations during CWT operating hours
versus non-operating hours. Figure 9-9 shows that during CWT operation, bromide increased by
~ 75 ppb (0.075 mg/L) at a distance of 12 km downstream of the CWT discharge point, and ~ 25 ppb
(0.025 mg/L) as far as 50 km downstream. Similarly, chloride concentrations increased by an average
of ~ 8 ppm (8 mg/L) and ~ 5 ppm (5 mg/L). respectively, at 12 and 50 km downstream. When CWT
effluent impacted the stream, both bromide and chloride concentrations had statistically significant
increases as far as 50 km downstream of the facility. Landis et al. (2016) concluded that CWT effluent
elevates in-stream bromide concentrations during hours of operation, and those increases can
increase total THMs and the relative percentage of brominated THMs at drinking water treatment
facilities.
"Impacted" concentrations were measured during CWT operation, and "Non-Impacted" values were
measured while CWT facility was not discharging.
200 -] j#j Non-fmpactBd
*
150 H
I
100
!
50 -j
O - I
f*j«4ifip5ic(«l Impacted

21"* -tn;
T
Source: Landis et al., 2016, Figure 4.					
Figure 9-9. Observed Increases in Bromide and Chloride Concentrations at Sites ~12 km,
44 km, and 52 km Downstream of CWT Facility, Respectively, Along the Allegheny River
9.4.2 Potential Human Health Impacts
Documented increases in bromide concentrations in rivers receiving CWT effluent,
combined with the known human health effects of brominated THMs in drinking water,
demonstrate that CWT effluent poses human health risks related to drinking water
contamination. In watersheds where O&G activities are active and CWT facilities are present,
studies have shown evidence of a shift in surface water ionic composition toward relatively
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Section 9-Environmental Impacts
greater amounts of bromide (McTigue et al., 2014). Box 3 shows the proximity of several CWT
facilities accepting and discharging O&G wastewaters to drinking water intakes or sources in the
Marcellus Shale region to demonstrate the number of sources that could potentially be affected
by elevated bromide discharges from these facilities (ERG, 2017)41.
41 This analysis did not evaluate actual discharge concentrations of bromide from these facilities, not did it consider
whether treatment is in place to control bromide discharges. This analysis is intended to illustrate the nexus between
CWT facilities discharging treated O&G wastewaters and downstream drinking water intakes and sources.
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Section 9-Environmental Impacts
BOX 3. PROXIMITY ANALYSIS OF DRINKING WATER INTAKES
TO CWTS DISCHARGING TREATED O&G WASTEWATER.
Discharges of treated O&G wastewaters from CWTs. and specifically elevated bromide levels associated
with those discharges, have been shown to impact downstream drinking water quality by increasing DBP
formation at drinking water intakes. To analyze the number of drinking water intakes potentially impacted
by CWTs. a proximity analysis was used to determine the number of intakes downstream of select CWTs
accepting O&G wastewater and discharging to surface waters in the Marcellus Shale region. Documented
literature has reported that drinking water intakes within 50 km. 90 km. and 100 km downstream of CWTs
discharging treated O&G wastewater show increased bromide levels that can impact drinking water
quality (U.S. EPA. 2015b: Weaver et al.. 2016). The proximity analysis also identified sole source aquifers
and public drinking wells within 5 miles (8 km) of these CWTs. This distance has been previously used to
investigate drinking water impacts from facilities to public wells (ERG. 2013). Results of the analysis
identified 3 drinking water intakes within 50 km downstream of facilities. 16 intakes within 100 km
downstream of facilities. 143 public wells within 8 km of facilities, and no sole source aquifers within
5 miles of facilities.

Erie
V
o
/




r
^ v—r

I N J

LEGEND
Downstream Reaches
	0-50 Km Downstream of
CWT Facility
50-100 Km Downstream
of CWT Facility
Shape: Count of Wolis within
8 Km of Outfall
A
0
\ y 1-10
[7J 11-20
21-30
31-40
Stream Order (Size)
4-5
6-7
-• -• 8-9
Color: Count of Intakes within
100 Km Downstream
0
1-2
3-4
5-6
7
W.
Number within
symbol -
count of intakes
within 100 km
downstream
Figure 9-10. Drinking Water Intakes and Public Wells Potentially Impacted by CWTs
Discharging Treated O&G Wastewater
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Section 9-Environmental Impacts
High levels of bromide and iodide, such as those found in effluent from CWT facilities
accepting O&G wastewater, can pose greater human health risks than other halides because
brominated and iodinated DBPs tend to be more cyto- and genotoxic than their chlorinated
analogues (Harkness et al., 2015). Regli et al. (2015) estimated that bromide concentration
increases in drinking water sources can increase the risk of bladder cancer. Wang et al. (2016)
also estimated that brominated DBPs significantly increase the cancer risk level if bromide is not
properly removed or reduced in source waters.
There has been relatively little recent study regarding health effects associated with the
ingestion of TDS in drinking water. However, associations between various health effects and
specific constituents and hardness (rather than TDS concentrations) have been investigated
(WHO, 1996). The World Health Organization dropped its health-based recommendations for
TDS in 1993, instead retaining 1,000 mg/L as a secondary standard for "organoleptic purposes."
Under the Federal Safe Drinking Water Act, EPA established National Secondary
Drinking Water Regulations for non-mandatory water quality standards for several chemicals
including TDS. EPA established the SMCL for TDS at a recommended level of 500 mg/L. This
value is used largely as guidance to help public water systems manage their drinking water for
aesthetic considerations, such as taste, color, and odor. EPA does not enforce SMCLs, nor is
there a requirement that public water systems meet these levels.
9.5 Aquatic Life Impacts
9.5.1 Documented Aquatic Life Impacts
Many of the constituents in CWT effluent can negatively affect aquatic life. In this
section, we discuss documented direct impacts to aquatic life from CWT effluent discharges. In
the next section, we also review potential negative impacts to aquatic life from elevated
concentrations of pollutants downstream of CWT facilities. The primary documented effects to
aquatic life from CWT facilities are population and community shifts, degradation of biological
integrity, and lethality.
9.5.1.1 Change in Population Composition
A study by PA DEP documented shifts in population structure for macroinvertebrate and
phytoplankton communities upstream and downstream of CWT discharges. Based on this study,
upstream locations contained a higher percentage of pollution-intolerant macroinvertebrate
species compared to pollution-tolerant species. Macroinvertebrate populations located
downstream of brine discharges (Short et al., 1991) and CWT facilities (PA DEP, 2009, 2013)
showed reduce species richness and contained a higher percentage of pollution-tolerant
compared to pollution-intolerant species. Phytoplankton communities followed a similar pattern
shift in taxa, with an elevated percentage of brackish water taxa found in downstream locations
compared to upstream locations (PA DEP, 2009).
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Section 9-Environmental Impacts
In another study, native unionid mussel composition was also negatively affected
downstream of CWT discharge (Patnode et al., 2015). In the Patnode et al. (2015) study, stream
locations with elevated conductivity measurements downstream of CWT discharge had reduced
abundance and diversity compared to upstream locations with lower conductivity.
9.5.1.2	Biological Integrity
PA DEP created an Index of Biotic Integrity (IBI) for macroinvertebrates as a means to
measure a stream's ability to support aquatic life and evaluate population differences between
locations (PA DEP, 2015). The IBI integrates information from multiple metrics (i.e. total taxa
richness, Shannon diversity, percent pollution sensitive individuals) to provide a comprehensive
assessment of the macroinvertebrate population for a given stream size and season. In two
separate PA DEP studies (PA DEP, 2009, 2013), the researchers found significant decreases in
IBI scores at sites downstream of CWT discharges compared to upstream sites, suggesting that
downstream sites are negatively impacted by CWT effluent. Additionally, in the 2013 study, the
IBI scores for downstream sites were below the aquatic life use (ALU) thresholds, meaning those
sites were not supporting aquatic life.
9.5.1.3	Lethality
Patnode et al. (2015) performed an in-situ study on the lethality of CWT effluent to
juvenile unionid mussels, which are a federally listed endangered species. Using caged mussels
at an array of sites downstream of a CWT facility, these authors found that mussel survival
decreased significantly at sites with high specific conductivity related to the CWT discharge.
Box 4 summarizes the results of this study.
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Section 9-Environmental Impacts
BOX 4A. EFFECTS OF CWT EFFLUENT ON UNIONID MUSSELS
Patnode et al. (2015) documented significant impacts of brine discharges on unionid mussels in the upper
Allegheny River of Pennsylvania. The authors used a combination of caged and in situ mussels to compare
survival at sites upstream and downstream of two National Pollutant Discharge Elimination System outfall
points: one from a municipal wastewater treatment plant and one from a brine treatment facility. Only the
brine treatment facility treated O&G wastewater. Over the course of the experiment, the authors also
collected a continuous time series of specific conductance at each site, as a proxy for chloride
concentrations in the CWT effluent.
The authors observed significant reductions in survival of caged mussels for the downstream sites closest to
the two facilities, particularly where increases in specific conductance from CWT discharges were most
significant (e.g.. sites M2-M4: see Figure 9-11 and Figure 9-12). Survival was most significantly reduced
along the left descending bank of the river, where field transects documented the highest specific
conductance during two synoptic sampling rounds. Significant reductions in survival relative to controls
began after approximately 30 days of exposure, with complete mortality of the exposed mussels after
approximately 60 days. The authors used these data to develop a dose-response curve for specific
conductance, which they related back to chloride concentrations using grab samples collected over the
course of the experiment. The dose-response curve indicates that chloride concentrations greater than - 80
mg/L create added mortality of unionid mussels relative to reference conditions.
M1 = 0.5 km upstream: M2 = below municipal wastewater plant and above brine treatment facility: M3-M6 =
approximately 100 in. 0.5 km. 2.5 km. and 4.0 km downstream from the brine treatment facility, respectively.
J100O
I*
1

8/24 4/19 WS4 mm W3 w8 Wis WW WM WM WM 46/11
m -	
am an* W24 an? ws wa wis wta was vx tort i#i toiu
wm k» w w« »a vu ma wm, m* torn mm
¦ WD
wm mm m« wr> vi «* wis via wis we toe jm w»
L
am Wit *4 w» v» v» mm wi» «» mm mt mm vm»
Figure 9-11. Specific Conductance Measurements at the Six Monitoring Transects
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Section 9-Environmental Impacts
BOX 4B. EFFECTS OF CWT EFFLUENT ON UNIONID MUSSELS
RD1-2 = right descending bank sites 1-2: LD1-2 = left descending bank sites 1-2: PT = most upstream
point in each transect. M1 = 0.5 km upstream: M2 = between wastewater and brine treatment facilities:
M3-M6 = downstream sites approximately 100 m. 0.5 km. 2.5 km. and 4.0 km downstream from
wastewater treatment facility, respectively.
O 10 20 30 4 0 50 SO
Exposure (days)
» - RD1 " BE »RP2	LD1 -"44^LD2
Exposure (days)
Figure 9-12. Percent Survival of Caged Unionid Mussels at the Six Monitoring Transects
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Section 9-Environmental Impacts
9.5.2 Potential Aquatic Life Impacts
High levels of TDS can impact aquatic biota through increases in salinity, loss of osmotic
balance in tissues, and toxicity of individual ions. Increases in salinity can cause shifts in biotic
communities, limit biodiversity, exclude less-tolerant species and cause acute or chronic effects
at specific life stages (Weber-Scannell and Duffy, 2007). Aquatic macroinvertebrates exhibit
slower growth and reduced survival, and fish species have reduced hatching and survival rates at
TDS concentrations of- 750 mg/L (Hoke et al., 1992; Scannell and Jacobs, 2001; Stekoll et al.,
2001). The 48-hour LC50 (lethal dose to kill 50% of a population) for macroinvertebrates ranges
from 735 to 4,000 mg/L, depending on the life stage (Hoke et al., 1992).
There is a lack of literature on the effects of CWT effluent on fish. However, compared to
macroinvertebrates, Short et al. (1991) found the fish populations appeared to tolerate higher
levels of salinity in affected locations. Compared to macroinvertebrates, fish are more mobile, so
their exposure to elevated pollutants from CWT facilities needs to be studied.
In a detailed study of plant communities associated with irrigation drains, Hallock and
Hallock (1993) reported substantial changes in marsh communities. When TDS increased from
270 to 1,170 mg/L, both coontail (Ceratophyllus demersum) and cattail (Typha sp.) were nearly
eliminated. Derry et al. (2003) reported that salinity and aquatic biodiversity were inversely
related in lake water. The literature compiled by Weber-Scannell and Duffy (2007) provides
detailed information regarding toxicity of plant and animal species for a large taxonomic range.
Such community changes are somewhat analogous to the shift and/or elimination of taxa along
the salinity gradient found, for example, at the confluence of freshwaters into estuaries.
Toxicity of the major ions comprising TDS can vary. For example, Mount et al. (1993)
found that toxicity of Wyoming oilfield produced waters to the water flea Ceriodaphnia dubia
was closely correlated to concentrations of chloride. Tyree et al. (2016) found that even small
sublethal additions of sodium (at or above 14 mg/L Na) impacted detritivore growth and leaf
consumption. Toxicity of produced waters can often be attributed entirely to major ions that
comprise TDS, demonstrating the importance of controlling releases of TDS into surface waters
(Tietge et al., 1997).
Controlling release of TDS into surface waters is likely to become more important as
salinization is increasing in many freshwater streams through the United States (Kaushal et al.,
2005). Other stressors besides CWTs contribute TDS to surface waters (Entrekin et al., 2015),
decreasing their ability to absorb additional TDS releases, and baseline chloride concentrations
in many rural streams are predicted to exceed the CCC for aquatic life within the next century
(Kaushal et al., 2005). General salinization of freshwater streams already impairs many U.S.
streams and causes wide-ranging problems for ecosystems including enhanced colonization of
invasive or alien species, shifts in biogeochemical cycles, decreased riparian vegetation, and
changes in composition of primary producers (Canedo-Argiielles et al., 2013).
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Section 9-Environmental Impacts
9.6 Other Impacts
Previous sections in this chapter focused on the impacts to human health and aquatic life
resulting from CWT discharges to surface waters. Release of O&G wastewater treated at CWTs
can also impact the environment through other pathways discussed in Section 9.2. This section
summarizes other documented and potential impacts from CWT operations on POTWs,
irrigation for agriculture, watering livestock, and air emissions.
9.6.1 Impacts to POTWs
Treatment processes at POTWs are not effective at removing all types of pollutants in
O&G wastewater. Furthermore, high concentrations of dissolved chemical constituents (e.g.,
TDS) in O&G wastewater can prevent POTW treatment processes from working properly.
EPA's "Technical Development Document for the Effluent Limitations Guidelines and
Standards for the Oil and Gas Extraction Point Source Category" (UOG TDD) (U.S. EPA,
2016c) explains the General Pretreatment Regulations (40 CFR 435) promulgated in 2016 to
protect POTW operations from receiving untreated unconventional O&G wastewater that can
disrupt their ability to effectively treat influent wastewater. Prior to EPA's pretreatment
standards, the PA DEP requested in April 2011 that UOG operators stop sending their
wastewater to POTWs. Although the EPA regulation prevents O&G operations from sending
wastewater directly to POTWs, CWT facilities treating O&G wastewater can still discharge their
effluent to POTWs.
Indirect discharges to POTWs from CWTs accepting O&G wastewater can be high in
TDS if adequate treatment is not in place. TDS in wastewaters is not removed by typical POTW
treatment processes and can "pass through" the treatment process largely undiminished (except
by dilution with other secondary effluent), eventually being discharged into the POTW's
receiving waters. High concentrations of salt, organics, and heavy metals in wastewater can also
disrupt the biological component of the treatment process in many POTWs, and can therefore
affect the efficiency of POTWs to treat wastewater (Lefebvre and Moletta, 2006; U.S. EPA,
2016c).
The adverse effects of high TDS can be attributed to high osmotic stress or inhibition of
the biological components used in the organic degradation process. Past studies reveal that
salinity decreases organic matter removal efficiencies, increases effluent turbidity due to poor
sludge settling in the secondary sedimentation unit, and causes reductions in the mixed liquor
floe protozoan population in an activated sludge system (Woolard and Irvine, 1995; Kargi and
Dincer, 1998; Dan, 2001). Kargi and Dincer (1996) reported adverse effects of salt on aerobic
attached growth treatment processes such as trickling filters or rotating biological contactors. In
general, conventional processes are not effective in treating wastewaters containing more than 3
percent salt content (equivalent to 30,000 mg/L of total ions) (Woolard and Irvine, 1995).
Adaptation and acclimation of microorganisms to high salinity has been shown to be possible for
aerobic treatment, but results are variable, condition-dependent, and generally limited to systems
with less than 5% salt (50,000 mg/L) (Lefevbre and Moletta, 2006).
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Section 9-Environmental Impacts
Anaerobic treatment processes are also adversely affected by high TDS, as the anaerobic
process is somewhat more sensitive to salts than activated sludge processes (Chen et al., 2008).
Biogas production and COD removal by anaerobic treatment processes such as anaerobic filter,
upflow anaerobic sludge bed (UASB), and batch reactor were inhibited significantly at salt
content above 30,000 mg NaCl/L (de Baere et al., 1984; Feijoo et al., 1995). Methanogenesis has
been shown to be inhibited above sodium concentrations of 10,000 mg/L (Lefebvre and Moletta,
2006).
EPA's UOG TDD report (U.S. EPA, 2016c) summarized the effects on POTWs from
treated CWT effluents affected by UOG wastewater (Table 9-3). Based on U.S. EPA (2016c),
POTWs did not adequately treat pollutants such as total suspended solids (TSS) and TDS.
Additionally, many of the POTWs summarized in the UOG TDD report indicated that CWT
wastewater caused fouling and disruption of their treatment equipment and processes.
Table 9-3. Selected Case Study from EPA's UOG TDD Report Summarizing Results from
POTWs Accepting Wastewater Containing O&G Extraction Wastewater Pollutants
POTW
Siiiniiiiin (il'sludv llmliniis
New Castle, PA, POTW
The New Castle POTW received industrial wastewater from the Advanced Waste
Services CWT facility (which treated O&G wastewater). The CWT facility uses the
following treatment processes: solids settling, surface oil skimming, pH adjustment,
and (occasional) flocculation.
The POTW experienced numerous effluent TSS permit limit exceedances while
accepting industrial discharges from the CWT facility. The CWT facility discharge
was associated with adverse impacts on sludge settling in final clarifiers at the
POTW.
Source: U.S. EPA, 2016c, Table D-13
9.6.2 Impacts to Other Water Uses
9.6.2.1 Livestock
High TDS concentrations in raw water for livestock watering may adversely affect
animal health by several possible mechanisms. The solutes comprising elevated TDS decrease
the ability of water within organisms to transport materials (e.g., nutrients, waste products) by
decreasing the body's ability to dissolve additional solutes. Solutes also create adverse effects
such as dehydration, which affects cells and tissues. Further, excess solutes in drinking water
consume metabolic resources that could otherwise be used for growth, milk production, or
fighting off disease. Drinking water TDS levels in the 1.5 percent (15,000 mg/L) to 3 percent
(30,000 mg/L) range are usually fatal to most terrestrial animals (Raisbeck et al., 2008).
Domestic livestock (cattle, sheep, goats, horses, pigs) have varying degrees of sensitivity
to TDS in drinking water (Table 9-4). Sheep are more tolerant of saline water than most
domestic species, and will drink it if introduced to the saline water over a period of several
weeks (Tomas et al., 1973).
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Section 9-Environmental Impacts
Table 9-4. Tolerances of Livestock to TDS (Salinity) in Drinking Water
l.i\cstock
'l'l)S (m»/l.)
No ;i(l\ crsc effects
on iiiiiniiils
expected
Aniiiiiils m;i\ hii\c iniliiil
rclucliincc lo drink or Micro m;i\
ho some scouring, hul slock
should iidiipi without loss of
production
l.oss ol'production nnd ;i decline in
iiiiiniiil condition ;ind hciillh would
he expected: slock m;i\ tolcmlc these
lc\cls for short periods if introduced
uriidu;ill>
Beef cattle
0-4,000
4,000-5,000
5,000-10,000
Dairy cattle
0-2,400
2,400-4,000
4,000-7,000
Sheep
0-4,000
4,000-10,000
10,000-13,000
Horses
0-4,000
4,000-6,000
6,000-7,000
Pigs
0-4,000
4,000-6,000
6,000-8,000
Poultry
0-2,000
2,000-3,000
3,000-4,000
Source: Anzecc, 2000.
Water high in salt content can compromise performance and health of beef cattle living in
arid environments in two ways: (1) reduced water and feed intake and (2) induced trace mineral
deficiencies (Patterson and Johnson, 2003). Beef cattle may voluntarily consume less of the
poor-quality water, which in turn results in reduced consumption of dry matter (NRC, 1996).
Table 9-5 shows the increasing health effects to beef cattle as TDS levels in drinking water
increase.
Table 9-5. Interpretation of Water Quality based on TDS for
Cattle in Areas where Sulfates are Prevalent
IDS (inii/l.)
Interprctiilion
Suggested iiclion
Less than 2,000
Safe. Levels greater than 1,000 may have some
laxative effect and may reduce availability of
trace minerals.
None required.
2,000-3,000
Generally safe. May reduce performance,
should not affect health.
Monitor water, especially as weather gets
hot.
3,000-5,000
Marginal. May reduce performance and affect
health.
Test water for sulfates. Monitor water.
5,000-7,000
Poor water. Performance and health depression
expected in times of high temperatures.
Test for sulfates. Use for low producing
stock.
7,000-10,000
Dangerous. Performance and health depression
expected.
Do not use for pregnant or lactating cattle.
Sulfates likely to be high.
Greater than 10,000
Extremely dangerous. Not suitable for
livestock.
Do not use.
Source: Patterson and Johnson, 2003.
Because of uncertainty regarding the chemical composition and potential toxicity of TDS,
the Wyoming Extension Service recommends use of waters with TDS concentrations less than
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Section 9-Environmental Impacts
500 mg/L to ensure safety from almost all inorganic constituents. Above 500 mg/L, they
recommend that the waters be tested and individual constituents contributing to TDS be
identified, quantified, and evaluated (Raisbeck et al., 2008).
9.6.2.2 Irrigation
For irrigation usage, the primary water quality concern is that salinity associated with
high TDS waters can affect crop yield in the short term, and the soil structure in the long term
(Colorado Department of Public Health & Environment, 2008). The electrical conductivity (EC)
in irrigation water directly affects the soil water EC; if soils exceed certain EC thresholds, plant
growth is decreased (Compton, 2011). In addition, a number of trace elements may be found in
high TDS water that can limit its use for irrigation. Among concerns associated with the use of
high TDS waters for irrigation is the accretion of carbonate deposits that may clog irrigation
pipes and coat the inside of water holding tanks.
The primary direct impacts of high salinity water on plant crops include physiological
drought, increased osmotic potential of soil, specific ion toxicity, leaf burn, and nutrient uptake
interferences (Bauder et al., Undated). In general, for various classes of crops the salinity
tolerance decreases in the following order: forage crops, field crops, vegetables, fruits.
The suitability of water for irrigation is classified using several different measurements,
including TDS and EC, which is usually measured in the field. Figure 9-6 shows a classification
of waters of varying TDS concentrations for irrigation suitability.
Table 9-6. Permissible Limits for Classes of Irrigation Water
("hiss of wiilcr
I'.lccli'iciil conriuclmlv'
(dS/m)
( oncenlr;itioiis of TDS In
iiiK'lric img/l.)
Class 1. Excellent
0.250
175
Class 2. Good
0.250-0.750
175-275
Class 3. Permissible13
0.750-2.0
525-1,400
Class 4. Doubtful0
2.0-3.0
1,400-2,100
Class 5. Unsuitable0
3.0
>2,100
Source: AgriLife Extension, 2003.
a TDS (mg/L) ~ EC (dS/m) x 640 for EC < 5 dS/m.
b Leaching needed if used.
0 Good drainage needed, and sensitive plants will have difficulty obtaining stands.
In addition to short-term impacts to crop plants, irrigating with high TDS water can result
in a long-term hazard in which salts or sodium in the water gradually accumulate in the soil
layers and eventually decrease soil productivity. The susceptibility of soils to this degradation is
dependent on the soil type and structure. Sandy soils are less likely than finely textured soils to
accumulate salts or sodium, and they can be more easily leached to remove salts or sodium. Soils
with a high-water table or poor drainage are more susceptible to salt or sodium accumulation.
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Section 9-Environmental Impacts
The most common method of estimating the suitability of a soil for crop production is
through calculation of its sodicity as estimated by the soil's sodium absorption ratio (SAR).42
Table 9-7 presents a general irrigation water classification system based on SAR values.
However, the actual field-observed impacts are very site-specific depending on soil and crop
system (Bauder et al., Undated).
Several states have taken steps to protect waters used for irrigation from high TDS
discharges, particularly from produced waters. For example, Montana and Colorado have
adopted standards that require limits on EC and SAR to be incorporated into discharge permits
for facilities discharging into waters used for irrigation (e.g., Colorado Department of Public
Health & Environment, 2008; Compton, 2011).
Table 9-7. General Sodium Irrigation Water Classifications
SAR Millies
Sodium hii/iii'd ol'\\;i(cr
Cumim-uls
1-9
Low
Use of sodium sensitive crops must be cautioned
10-17
Medium
Amendments (such as gypsum) and leaching
needed.
18-25
High
Generally unsuitable for continuous use
26 or greater
Very high
Generally unsuitable for use
Source: Bauder et al., Undated.
9.6.3 Air Quality Impacts
Reliable data characterizing VOC emissions from active CWT facilities associated with
O&G activities appear to be relatively scarce. Field et al. (2015) found a CWT treating O&G
wastewater was a significant source of non-methane hydrocarbons and influenced ozone at
downwind monitoring sites. However, review of the scientific literature and internet searches did
not provide much monitoring data of VOCs emission at CWT facilities. One potential reason
may be a lack of VOCs in the waste stream entering CWT facilities in certain areas. Storage and
transport of the wastewater prior to receipt at the CWT facility may mean that much of the
hydrocarbons are lost prior to entry and are not present in the influent. Finally, given the
uncertain concentrations of VOCs in the influent, facility operators simply estimate potential to
emit (PTE) emission rates based on EPA-approved emission factors and are not required to do
any air monitoring.
For example, the Fairmont Brine Processing facility in West Virginia (Marcellus Shale
play) provided a detailed process description to the West Virginia Department of Environmental
Protection (WV DEP) (FBP, 2016). The raw source water received by this facility is from gas
development and production, but it is treated at the facility to remove oil and suspended solids.
The treated water is sold to natural gas well drilling companies as make-up water for HF
activities or is discharged, while the brine is concentrated, resulting in sodium and calcium
42 The SAR value is equal to | /Va |/VK | Ca 21+1 /Wg21 )/2} with all concentrations as milliequivalents per liter.
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Section 9-Environmental Impacts
chloride salts as marketable by-products. For this facility, the regulated air pollutant emission for
VOCs was estimated at PTE 0.48 lbs. per hour (2.09 tons/yr). Accordingly, the facility does not
directly monitor VOC emissions from the air, but simply uses emission factors to estimate them.
Human health risk from CWTs processing O&G wastewater may be low, but further research is
needed.
9.7 Data Gaps
This chapter has presented data and information from literature focused on O&G
wastewater treatment at CWT facilities and the subsequent human and environmental impacts.
Documented impacts and case studies show known interactions between CWTs accepting O&G
wastewater, the environments into which they are released, and downstream entities or
ecosystems. Potential impacts can be determined from comparisons made between known
releases of pollutants from CWTs and known thresholds. However, data gaps still exist related to
the impacts of CWTs accepting O&G wastewater and the pollutants they may release.
9.7.1	Lack of Chemical Information
O&G wastewaters contain a variety of chemicals, from sources such as HF fluid
additives, well stimulation and well maintenance activities. In addition, the source formation can
contribute various constituents. The chemical concentrations in O&G wastewater (outlined in
Section 9.1.5 and discussed in Section 5), particularly for HF fluids, have not been widely
characterized in publicly available literature. Subsequently, researchers have not studied the
impacts of these varied chemicals on CWT treatment abilities or the efficacy of CWT facilities
treating those chemicals. Because the HF fluid chemicals in effluent are generally not
documented, many constituents have not been tested, and therefore impacts from those chemicals
to human health and aquatic life are unknown.
9.7.2	Geography
The majority of the data presented in this chapter come from the Marcellus Shale region.
HF services in other locations perform on-site recycling and reuse of produced waters, and can
re-inject wastewaters, significantly reducing or eliminating the need to send wastewater to CWT
facilities. Because Pennsylvania previously did not allow wastewater reinjection (PA DEP,
2016), and because the Marcellus Shale region is less conducive to deep-well injection, a higher
volume of O&G wastewater is sent to CWT facilities in the Marcellus region than some other
plays. Subsequently, PA DEP and other researchers have studied the impacts of CWT effluent on
the environment. O&G wastewater characteristics vary by formation, so more data from O&G
wastewater treatment in other geographic locations is needed to properly characterize impacts to
human health and the environment.
9.7.3	Direct Impacts Data
This chapter contains data from available studies investigating direct water quality and
aquatic biotic impacts from CWT effluent. However, additional research on direct impacts to
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Section 9-Environmental Impacts
downstream water quality, aquatic life, and human health would provide a more robust analysis
on the total effects of CWT O&G wastewater treatment. Additionally, very few of the studies we
evaluated here investigated the distance to which impacts extend downstream from CWT
outfalls. From the studies reviewed here (PA DEP, 2013; Warner et al., 2013), it is clear that
pollutant concentrations decrease as distance from outfall increases and the effluent mixes with
the receiving waters. However, more research is needed to better characterize the distance and
magnitude of impacts downstream.
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Section 9-Environmental Impacts
07283. California University of PA, California, PA. January. Available:
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67.	Pennsylvania Department of Environmental Protection (PADEP). 2016.
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drinking water supplies. Environmental Science and Technology 48: 111 61—
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69.	Patnode, K.A., E. Hittle, R.M. Anderson, L. Zimmerman, and J.W. Fulton. 2015.
Effects of high salinity wastewater discharges on unionid mussels in the
Allegheny River, Pennsylvania. Journal of Fish and Wildlife Management
6(l):55-70. doi: 10.3996/052013-JFWM-033. DCN CWT00476
70.	Patterson, T. and P. Johnson. 2003. Effects of Water Quality on Beef Cattle.
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CWT00477
71.	Pennsylvania Code. 2011. § 95.10. Treatment Requirements for New and
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72.	Pourmoghaddas, H., A.A. Stevens, R.N. Kinman, R.C. Dressman, L.A. Moore,
and J.C. Ireland. 1993. Effect of bromide ion on formation of HAAs during
chlorination. Journal American Water Works Association 85(l):82-87. DCN
CWT00479
73.	Rahm, B.G., J.T. Bates, L.R. Bertoia, A.E. Galford, D.A. Yoxtheimer, and S.J.
Riha. 2013. Wastewater management and Marcellus shale gas development:
Trends, drivers, and planning implications. Journal of Environmental
Management 120:105-113. Available:
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74.	Raisbeck, M.F., S.L. Riker, C.M. Tate, R. Jackson, M.A. Smith, K.J. Reddy, and
J.R. Zygmunt. 2008. Water Quality for Wyoming Livestock and Wildlife. A
Review of the Literature Pertaining to the Health Effects of Inorganic
Contaminants. University of Wyoming Department of Veterinary Science,
Laramie. DCN CWT00481
75.	Regli, S., J. Chen, M. Messner, M. Elovitz, F. Letkiewicz, R. Pegram, T. Pepping,
S. Richardson, and J. Wright. 2015. Estimating potential increased bladder cancer
risk due to increased bromide concentrations in sources of disinfected drinking
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
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Section 9-Environmental Impacts
water. Environmental Science and Technology 49:13094-13102. DCN
CWT00482
76.	Richardson, S.D., M.J. Plewa, E.D. Wagner, R. Schoeny, and D.M. DeMarini.
2007. Occurrence, genotoxicity, and carcinogenicity of regulated and emerging
disinfection by-products in drinking water: A review and roadmap for research.
Mutation Research 636(1-3): 178-242. DCN CWT00483
77.	Rowan, E.L., M.A. Engle, C.S. Kirby, and T.F. Kraemer. 2011. Radium Content
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(USA): Summary and Discussion of Data. Scientific Investigations Report 2011—
5135. U.S. Geological Survey, Reston, VA. Available:
https://pubs.usgs.gov/sir/2011/5135/pdf/sir2011-5135.pdf. Accessed 6/30/2017.
DCN CWT00316
78.	Rozell, D.J. and S.J. Reaven. 2012. Water pollution risk associated with natural
gas extraction from the Marcellus shale. Risk Analysis 32(8): 1382-1393. doi:
10.1111/j .1539-6924.2011.01757.x. DCN CWT00485
79.	Scannell, P.W. and L.L. Jacobs. 2001. Effects of Total Dissolved Solids on
Aquatic Organisms: A Literature Review. Technical Report No. 01-06. Alaska
Department of Fish and Game, Division of Habitat and Restoration. June. DCN
CWT00486
80.	Short, T., J. Black, and W. Birge. 1991. Ecology of a saline stream: Community
responses to spatial gradients of environmental conditions. Hydrobiologia
226:167-178. DCN CWT00487
81.	Sigel, L. 2007. Hazard Identification for Human and Ecological Effects of
Sodium Chloride Road Salt. 1-93 Chloride TMDL Study. New Hampshire
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82.	Skalak, K.J., M.A. Engle, E.L. Rowan, G.D. Jolly, K.M. Conko, A.J. Benthem,
and T.F. Kraemer. 2014. Surface disposal of produced waters in western and
southwestern Pennsylvania: Potential for accumulation of alkali-earth elements in
sediments. International Journal of Coal Geology 126:162-170. Available:
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83.	States, S., G. Cyprych, M. Stoner, F. Wydra, J. Kuchta, J. Monnell, and L.
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drinking water. .Journal American Water Works Association 105(8):E432-E448.
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84.	Stekoll, M., W. Smoker, I. Wang, and B. Failor. 2001. Fourth Quarter 2000
Report for ASTF Grant #98-012. Project: Salmon as a Bioassay Model of Effects
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Section 9-Environmental Impacts
85.	Stoss, V.J., S. Buyukhatipoglu, and W. Holtz. 1977. The influence of certain
electrolytes on the induction of sperm motility in rainbow trout (Salmo gairdneri).
Zuchthyg 12:178-184. (Abstract and summary translated.) DCN CWT00492
86.	Stringfellow, W.T., J.K. Domen, M.K. Camarillo, W.L. Sandelin, and S. Borglin.
2014. Physical, chemical, and biological characteristics of compounds used in
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CWT00493
87.	Strong, L., T. Gould, L. Kasinkas, M. Sadowsky, A. Aksan, and L. Wacektt.
2013. Biodegradation in waters from hydraulic fracturing: chemistry,
microbiology, and engineering. J. Environ. Eng. 140(5): B4013001-1-B4013001-
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88.	Sturchio, N., J. Banner, C. Binz, L. Heraty, and M. Musgrove. 2001. Radium
geochemistry of ground waters in Paleozoic carbonate aquifers, midcontinent,
USA. Applied Geochemistry 16:109-122. DCN CWT00495
89.	Thorn, T.H. 2012. Environmental Issues Surrounding Shale Gas Production. The
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Apr IGU%20Environmental%20Issues%20and%20Shale%20Gas.pdf. Accessed
7/28/2017. DCN CWT00496
90.	Tietge, J.E., J.R. Hockett, and J.E. Evans. 1997. Major ion toxicity of six
produced waters to three freshwater species: Application of ion toxicity models
and TIE procedures. Environmental Toxicology and Chemistry 16(10):2002-
2008. DCN CWT00497
91.	Tomas, F.M., G.B. Jones, B.J. Potter, and G.L. Langsford. 1973. Influence of
saline drinking water on mineral balances in sheep. AustJAgric Res 24:377-386.
DCN CWT00498
92.	Tyree, M., N. Clay, S. Polaskey, and S. Entrekin. 2016. Salt in our streams: Even
small sodium additions can have negative effects on detritivores. Hydrobiologia
775(1): 109-122. DCN CWT00499
93.	U.S. EPA. 2001. Radionuclides Rule: A Quick Reference Guide. EPA 816-F-01-
003. U.S. Environmental Protection Agency, Office of Water. June. Available:
https://nepis.epa.gov/Exe/ZyPDF.cgi?Dockev=30006644.txt. Accessed
7/28/2017. DCN CWT00500
94.	U.S. EPA. 2012. Study of the Potential Impacts of Hydraulic Fracturing on
Drinking Water Resources: Progress Report. Progress Report. EPA/601/R-
12/011. December. Available:
https://www.epa.gov/sites/production/files/documents/hf-report20121214.pdf.
Accessed 6/30/2017. DCN CWT00024
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Section 9-Environmental Impacts
95.	U.S. EPA. 2013. Radionuclides in Drinking Water. Reverse Osmosis. U.S.
Environmental Protection Agency. Available:
http://cfpub.epa.gov/safewater/radionuclides/radionuclides.cfm?action=Rad Reve
rse%20Qsmosis. Accessed 6/30/2017. DCN CWT00502
96.	U.S. EPA. 2015a. Environmental Assessment for the Effluent Limitations
Guidelines and Standards for the Steam Electric Power Generating Point Source
Category. EPA-821-R-15-006. U.S. Environmental Protection Agency, Office of
Water. September. Available: https://www.epa.gov/sites/production/files/2015-
10/documents/steam-electric-envir 10-20-15.pdf. Accessed 7/28/2017. DCN
CWT00503
97.	U.S. EPA. 2015b. Sources Contributing Inorganic Species to Drinking Water
Intakes During Low Flow Conditions on the Alleghany River in Western
Pennsylvania. EPA/600/R-14/430. U.S. Environmental Protection Agency, Office
of Research and Development. May. Available:
https://www.epa.gov/sites/production/files/2015-
05/documents/epa source apportionment rpt final 07mav2015 508 km.pdf.
Accessed 7/28/2017. DCN CWT00504
98.	U.S. EPA. 2016a. Hydraulic Fracturing for Oil and Gas: Impacts from the
Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United
States. EPA-600-R-16-236ES. Executive Summary. U.S. Environmental
Protection Agency, Office of Research and Development. December. Available:
http://ofmpub.epa.gov/eims/eimscomm.getfile7p download id=530159.
Accessed 7/28/2017. DCN CWT00505
99.	U.S. EPA. 2016b. National Primary Drinking Water Standards. U.S.
Environmental Protection Agency, Office of Water. Available:
http://water.epa.gOv/drink/contaminants/#Inorganic. Accessed 7/28/2017. DCN
CWT00506
100.	U.S. EPA. 2016c. Technical Development Document for the Effluent Limitations
Guidelines and Standards for the Oil and Gas Extraction Point Source Category.
EPA-820-R-16-003. U.S. Environmental Protection Agency, Office of Water,
Washington, DC. June. Available:
https://www.epa.gov/sites/production/files/2016-06/documents/uog oil-and-gas-
extraction tdd 2016.pdf. Accessed 7/28/2017. DCN CWT00019
101.	U.S. EPA. 2017. National Recommended Water Quality Criteria - Aquatic Life
Criteria Table. U.S. Environmental Protection Agency. Available:
https://www.epa.gov/wqc/national-recommended-water-qualitv-criteria-aquatic-
life-criteria-table. Accessed 6/27/2017. DCN CWT00508
102.	USGS. 2012 Water Quality Studied in Areas of Unconventional Oil and Gas
Development, Including Areas where Hydraulic Fracturing Techniques are Used,
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Section 9-Environmental Impacts
in the United States. Fact Sheet 2012-3049. United States Geological Survey.
Department of the Interior. April. DCN CWT00509
103.	Vandecasteele, I., I.M. Rivero, S. Sala, C. Baranzelli, R. Barranco, O. Batelaan,
and C. Lavalle. 2015. Impact of shale gas development on water resources: A case
study in northern Poland. Environmental Management 55:1285-1299. DCN
CWT00510
104.	Vengosh, A., R.B. Jackson, N. Warner, T.H. Darrah, and A. Kondash. 2014. A
critical review of the risks to water resources from unconventional shale gas
development and hydraulic fracturing in the United States. Environmental Science
& Technology 48(15):8334-8348. DCN CWT00511
105.	Vidic, R.D., S.L. Brantley, J.M. Vandenbossche, D. Yoxtheimer, and J.D. Abad.
2013. Impact of shale gas development on regional water quality. Science
340(6134), 1235009. Available: http://doi.org/10.1126/science.12350Q9.
Accessed 6/30/2017. DCN CWT00512
106.	Volz, C.D., K. Ferrar, D. Michanowicz, C. Christen, S. Kearney, M. Kelso, and S.
Mai one. 2011. Contaminant Characterization of Effluent from Pennsylvania Brine
Treatment Inc., Josephine Facility Being Released into Blacklick Creek, Indiana
County, Pennsylvania. Implications for Disposal of Oil and Gas Flor/Back Fluids
from Brine Treatment Plants. Center for Healthy Environments and Communities,
Department of Environmental and Occupational Health, Graduate School of
Health, University of Pittsburgh. March 25. Available:
https://archive.org/stream/ContaminantCharacterizationOfEffluentFromPennsvlva
niaBrineTreatment/Josephine V2 CHEC 2011 divu.txt. Accessed 6/30/2017.
DCN CWT00359
107.	Wang, Y., M.J. Small, and J.M. VanBriesen. 2016. Assessing the risk associated
with increasing bromide in drinking water sources in the Monongahela River,
Pennsylvania. J. Environ. Eng. 143(3):04016089-1-04016089-10. doi:
10.1061/(ASCE)EE. 1943-7870.0001175. DCN CWT00514
108.	Warner, N.R., C.A. Christie, R.B. Jackson, and A. Vengosh. 2013. Impacts of
shale gas wastewater disposal on water quality in western Pennsylvania.
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http://doi.org/10.1021/es402165b. Accessed 6/30/20107. DCN CWT00077
109.	Weaver, J.S., J. Xu, and S.C. Mravik. 2016. Scenario analysis of the impact on
drinking water intakes from bromide in the discharge of treated oil and gas
wastewater. Journal of Environmental Engineering 142(1):04015050-1-14. doi.
10.1061/(ASCE)EE. 1943-7870.0000968. DCN CWT00516
110.	Weber-Scannell, P. and L. Duffy. 2007. Effects of total dissolved solids on
aquatic organisms: A review of literature and recommendations for salmonid
species. American Journal of Environmental Sciences 3:1-6. DCN CWT00517
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Section 9-Environmental Impacts
111.	Westerhoff, P., P. Chao, and H. Mash. 2004. Reactivity of natural organic matter
with aqueous chlorine and bromine. Water Res. 3 8(6): 1502—1513. DCN
CWT00518
112.	WHO. 1996. Total dissolved solids in drinking-water. In Guidelines for Drinking-
Water Quality, 2nd ed. Vol. 2. Health Criteria and Other Supporting Information.
WHO/SDE/WSH/03.04/16. World Health Organization, Geneva. DCN
CWT00519
113.	Wilson, J., Y. Wang, and J. VanBriesen. 2014. Sources of high total dissolved
solids to drinking water supply in southwestern Pennsylvania. Journal of
Environmental Engineering 140(5): 1-10. DCN CWT00520
114.	Wilson, J.M. and J.M. VanBriesen. 2012. Oil and gas produced water
management and surface drinking water sources in Pennsylvania. Environmental
Practice 14(December):288-300. DCN CWT00521
115.	Woolard C.R. and R.L. Irvine. 1995. Treatment of hypersaline wastewater in the
sequencing batch reactor. Wat. Res. 29(4): 1159-1168. DCN CWT00522
116.	Zhang, T., R.W. Hammack, and R.D. Vidic. 2015. Fate of radium in Marcellus
Shale flowback water impoundments and assessment of associated health risks.
Environ. Sci. Technol. 49(15):9347-9354. DCN CWT00523
117.	Ziemann, H., L. Kies, and C.-J. Schulz. 2001. Desalinization of running waters
III. Changes in the structure of diatom assemblages caused by a decreasing salt
load and changing ion spectra in the river Wipper (Thuringia, Germany).
Limnologica 31:257e280. DCN CWT00524
118.	Ziemkiewicz, P., J. Hause, B. Gutta, J. Fillhart, B. Mack, and M. O'Neal. 2013.
Final Report - Water Quality Literature Review and Field Monitoring of Active
Shale Gas Wells. Phase I for "Assessing Environmental Impacts of Horizontal
Gas Well Drilling Operations." Prepared for West Virginia Department of
Environmental Protection, Charleston, WV, by West Virginia Water Research
Institute, Morgantown, WV. February 15. Available:
http://publichealth.hsc.wvu.edu/media/1045/water-report-phase-i-submitted-feb-
20-2013.pdf. Accessed 6/30/2017. DCN CWT00525
119.	Ziemkiewicz, P.F. 2013. Characterization of liquid waste streams from shale gas
development. AGHDrilling, Oil, Gas 30(l):297-309. DCN CWT00526
120.	Zimmermann-Timm, H. 2007. Salinisation of inland waters. In Water Uses and
Human Impacts on the Water Budget, J. Lozan, H. GraBl, P. Hupfer, L. Menzel,
and C. Schonwiese (eds.). Verlag Wissenschaftliche Auswertungen/GEO,
Hamburg, pp. 133-136. DCN CWT00527
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Section 10-Data Sources
10. Data Sources
EPA evaluated information from various sources during preparation of this Detailed
Study. EPA used these data to develop an industry profile and identify in-scope facilities, gather
information on wastewater characteristics and potential pollution control technologies, estimate
the pollutant discharge loadings for the in-scope facilities, and review environmental impacts
associated with discharges from these facilities. The following subsections discuss the data
sources and their use and limitations.
10.1	NPDES Permits and Fact Sheets
The CWA requires direct dischargers (i.e., facilities that discharge wastewaters from any
point source into receiving waters) to control their discharges according to effluent guidelines
and water quality-based effluent limitations included in NPDES permits. EPA reviewed NPDES
permits of CWT facilities identified during the study and, where available, accompanying fact
sheets to identify the sources of wastewater at CWT facilities and to determine how the
wastewaters are currently regulated (i.e., effluent limitations for specific parameters and their
basis). As part of the NPDES permit review, EPA contacted state permit writers to obtain
additional information or clarify permit information. EPA only reviewed available NDPES
permits for a select number of facilities.
10.2	EPA Databases
EPA used data from Envirofacts43 and Enforcement and Compliance History Online
(ECHO)44 to help identify CWT facilities and collect information about those facilities. These
databases provide information such as facility addresses, NPDES permit numbers, and Federal
Registry System (FRS) identification numbers.
EPA also used data from agency databases to characterize the wastewater characteristics
and pollutant loadings associated with CWT facilities. These data were obtained from Discharge
Monitoring Reports (DMRs) and the Toxics Release Inventory (TRI) using the EPA DMR
Pollutant Loadings Tool. DMR data are submitted by facilities in accordance with their NPDES
permits. Facilities may be required to report discharges to TRI, subject to certain size and
discharge thresholds. DMR and TRI data limitations include:
Facilities Reporting:
• The subset of facilities included in DMR database are only direct dischargers with NPDES
permits and not facilities discharging indirectly via publicly owned treatment works
(POTWs). In addition, DMR data may not be available for permitted direct dischargers
classified as "minor sources."
43	Envirofacts is available online at: http://www .epa. gov/envirofw/.
44	ECHO is available online at: http://echo.epa.gov/.
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Section 10-Data Sources
•	TRI includes both direct and indirect dischargers, but facilities report discharges to EPA's
TRI program only if they meet the employee criteria (i.e., 10 or more employees) and TRI
chemical threshold(s).
Pollutants Reported:
•	In DMRs, facilities report discharges only for pollutants required to be reported by their
NPDES permit and not all pollutants that may be present in wastewater discharges.
•	In TRI, reporting of facility discharges is limited to pollutants included in the TRI toxic
chemical list45. Values reported to TRI are often based on estimates and not on measurements
of wastewater flow and pollutant concentrations.
10.3	EPA's CWT Rulemaking
The CWT Point Source Category is regulated under 40 CFR Part 437. These ELGs were
promulgated in 2000 and amended in 2003. EPA reviewed documents developed in support of
the CWT rulemaking, including the Development Document for the Effluent Limitations and
Guidelines for the Centralized Waste Treatment Category (U.S. EPA, 2000). EPA used this
information to help develop the list of CWT facilities. These data are limited by their age.
Primarily, many facilities accepting oil and gas extraction wastewater were constructed after
2003, and many facilities have closed or changed ownership since then, as well.
10.4	EPA's Oil and Gas Extraction Rulemakings
Discharges from oil and gas extraction activities are regulated under 40 CFR Part 435.
The ELGs for this category were promulgated in 1979, and amended in 1993, 1996, 2001, and
2016. EPA consulted documents prepared in support of the 1979 rulemaking, including the
Development Document for Interim Final Effluent Limitations Guidelines and Proposed New
Source Performance Standards for the Oil and Gas Extraction Point Source Category (U.S.
EPA, 1976). EPA used the information to characterize wastewater from various oil and gas
extraction operations.
EPA also used information collected as part of development of the 2016 pretreatment
standards established for the Oil and Gas Extraction Point Source Category (U.S. EPA, 2016).
EPA used information collected about CWT facilities and treatment technologies for oil and gas
extraction wastewater. EPA also used data from the 2016 rulemaking to help characterize oil and
gas extraction wastewater. These data are limited to primarily unconventional oil and gas
operations.
45Information about TRI's toxic chemical list is available online at: http://www2.epa.gov/toxics-release-inventorv-
tri-program/tri-listed-chemicals.
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Section 10-Data Sources
10.5 U.S. Geological Survey Data
Oil and gas extraction wastewater data were collected from the U.S. Geological Survey
(USGS) National Produced Waters Geochemical Database which includes geochemical data for
over 60,000 wells in 36 states (V 2.1). The database is considered sufficiently accurate based on
EPA quality procedures to provide an indication of tendencies in water composition from
geographically and geologically defined areas. However, the USGS database has the following
limitations:
•	The database was compiled using other existing databases, publications, and reports, and the
reliabilities and uncertainties associated with these data sources are not quantified.
•	Although USGS attempted to remove all duplicates and invalid data, the culling of
unrepresentative data is incomplete. Most of the obvious redundant entries were removed
from this database. Many of the remaining records represent multiple samples of the same
well. Therefore, aggregate statistics may be weighted by relatively few wells
10.6	Data from State Agencies
EPA evaluated the 2016 Pennsylvania DEP Technologically Enhanced Naturally
Occurring Radioactive Materials (TENORM) study report (PA DEP, 2016). The objective of this
study was to quantify the amount of TENORM associated with oil and gas drilling in
Pennsylvania. The study evaluated TENORM exposure at locations such as well pads,
wastewater treatment plants, landfills, and gas distribution facilities and included sampling of
solids, liquids, natural gas, ambient air, and surface radioactivity. EPA used Appendix M of the
TENORM report as a source of wastewater characterization data for the area and examined the
levels of naturally occurring radiation in materials and media associated with oil and gas
development.
EPA also evaluated information about CWT facilities prepared by state permitting
agencies, including the Ohio Environmental Protection Agency, Pennsylvania Department of
Environmental Protection, West Virginia Department of Natural Resources, Texas Railroad
Commission, Wyoming Oil and Gas Conservation Commission, and Colorado Oil and Gas
Information Service.
Data limitations on information obtained from state agencies include regional specificity,
variations in reporting methods, variations in naming conventions, and variations in quantity
based on the number of active operators and the number of participating operators.
10.7	Drillinginfo's (PI) Desktop® Database
EPA used Drillinginfo's (DI) Desktop database to provide a broad overview of the
current size and scope of the oil and gas extraction industry by characterizing counts of existing
wells by basin. For this data analysis, the DI Desktop® database was downloaded on March 30,
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Section 10-Data Sources
2015, and reflects wells drilled through 2014. The database includes annual oil, gas, and
produced water production records for all oil and gas wells including inactive wells and
underground injection wells that do not produce oil and/or gas.
The DI Desktop® database has some limitations, which EPA attempted to resolve via
data review and correction on the database tables (ERG, 2016). For example, the database
contains inconsistent naming conventions, spelling errors and wells with "N/A", "0", "N", or
blank as basin type. Even after efforts to correct data problems, there were still 850 wells with
incomplete data (out of over 1 million total wells).
10.8	Literature and Internet Searches
EPA conducted literature and Internet searches to collect information on various aspects
of oil and gas extraction operations. The information collection objectives of these searches
included characterizing wastewaters and pollutants originating from these operations,
characterizing the environmental impacts of these wastewaters, and identifying applicable
regulations. EPA used journal articles, reference texts, and company press releases obtained from
Internet searches. EPA attended and reviewed papers presented at the 2014 International Water
Conference, the 2014 World Shale Gas Summit, the 2014 Water Environment Federation Annual
Technical Exhibition and Conference (WEFTEC), the 2014 and 2015 Shale Play Management
Conference, and the 2016 Marcellus and Utica Produced Water Conference. EPA's literature and
internet searches were thorough, but not absolute. The data are limited to what was available and
reviewed by EPA.
10.9	References
1.	ERG. 2016. Proposed Approach for Data Analysis and Quality Assurance Using
Drillinginfo's (DI) Desktop® Well File Database. (January 20). DCN
CWT00173.
2.	Pennsylvania Department of Environmental Protection (PA DEP). 2016.
Technologically Enhanced Naturally Occurring Radioactive Materials
(TENORM) Study Report. Rev 1. DCN CWT00131.
3.	U.S. EPA. 2000. Development Document for Effluent Limitation Guidelines and
Standards for the Centralized Waste Treatment Industry - Final. DCN
CWT00324.
4.	U.S. EPA. 1976. Development Document for Interim Final Effluent Limitations
Guidelines and Proposed New Source Performance Standards for the Oil and Gas
Extraction Point Source Category. (September). DCN CWT00134.
5.	U.S. EPA. 2016. Technical Development Document for Effluent Limitations
Guidelines and Standards for Oil and Gas Extraction. EPA-820-R-16-003. DCN
CWT00019
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Section 10-Data Sources
6. U.S. Geological Survey (USGS). 2014. National Produced Waters Geochemical
Database v2.1 (Provisional) - Documentation. DCN CWT00129.
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Appendix A
Regulatory Tables

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Appendix A-Regulatory Tables
Appendix A: Reference Tables
Table A-l. Pollutants Regulated at 40 CFR Part 437
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•
•
•
198
Oil & Grease
•

•



•
141
TSS
•

•

•

•
281
Antimony
•
•




•
107
Arsenic
•
•
•



•
203
Cadmium
•
•
•



•
192
Chromium
•
•
•
•


•
2,192
Cobalt
•
•
•
•


•
245
Copper
•
•
•
•
•

•
998
Lead
•
•
•
•


•
328
Mercury
•
•
•



•
158
Nickel
•
•




•
707
Silver
•
•




•
137
Tin
•
•
•
•


•
408
Titanium
•
•




•
502
Vanadium
•
•




•
304
Zinc
•
•
•
•
•

•
877
Cyanide
•
•





0
Acetone




•

•
117
Acetophenone




•


0
Bis(2-ethylhexyl) phthalate


•
•


•
0
2-Butanone




•


0
Butylbenzyl phthalate


•




0
Carbazole


•
•



0
n-Decane


•
•


•
1
Fluoranthene


•
•



0
n-Octadecane


•
•


•
1
o-Cresol




•
•
•
1
p-Cresol




•
•

0
Phenol




•

•
160
Pyridine




•

•
157
2,4,6-Trichlorophenol




•
•

0
aNote: This table indicates whether a particular pollutant was found in oil and gas extraction wastewater and presents the
number of sample values that were reported above the detection limit in EPA's consolidated data set (for both drilling
wastewater and produced water) and EPA's samples. A complete listing of all pollutants and the number of values reported
above the detection limit can be found in EPA's Wastewater Characterization Memorandum (ERG, 2018a). Note that not
all pollutants were included in every data source or sampling episode. In addition, there may be other data sources available
that EPA did not review.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
A-l

-------
Appendix A-Regulatory Tables
Table A-2. Limitations for 40 CFR Part 437 Subparts A, B, and C
ki'^uliik'd
I'linuiK'kT
Ul* l/ISC 1 /ISA
l);iil\
M:i vim inn
(111^/1.)
Siil>|);iri A
l/PSKS/PSNS1
M;i\imiim
Month l\
A\it;i»i-

l);iil\
M;i \ im n in

-------
Appendix A-Regulatory Tables
Table A-3. PSES Limitations for 40 CFR Part 437 Subpart B (Oils)
Piii'iiiiKMor
l);iil\ Miixiiniiin
(inii/l.)
Miixiiniiin Mon(hl\
(mii/l.l
Chromium
0.947
0.487
Cobalt
56.4
18.8
Copper
0.405
0.301
Lead
0.222
0.172
Tin
0.249
0.146
Zinc
6.95
4.46
Bis(2-etfaylhexyl) phthalate
0.267
0.158
Carbazole
0.392
0.233
n-Decane
5.79
3.31
Fluoranthene
0.787
0.393
n-Octadecane
1.22
0.925
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
A-3

-------
Appendix A-Regulatory Tables
Table A-4. BPT/BCT/BAT Limitations for 40 CFR Part 437 Subpart D (Multiple)1
I'iiriiiiKMcr
Combined
Siihpiirls .
I);iil\
M;i\imiim
(in»/l.)
\\ iislo from
V. li. ;iiul (
M;i\imiim
Muni hl\
n l hl\
Amt;i»i-

l);iil\
M;i \ im inn
V\ iislo from
A mill (
M;i\imiim
Muni h l\
Awr;i»i-

-------
Appendix A-Regulatory Tables
Table A-5. NSPS Limitations for 40 CFR Part 437 Subpart D (Multiple)
I'iiriiiiKMcr
Combined
Subparts .
I);iil\
M;i\imiim
(in»/l.)
V\ iislo from
V. li. ;iiul (
Mmillib
A\it;i»i-
diili/l >
( o in billed
Siih|)iirl>
l);iil\
M;i\imiim
(m»/l.)
V\ iislo from
A iind 1}
M;i\iiiiiiin
Monllib
A\lTil»l-

l);iil\
M:i\imum
(m»/l.)
V\ iislo from
A iind (
M;i\imiim
Mmillib
A\it;i»i-
(m»/l.)
( oinbined
Sub|);ir(>
l):iil>
M;i\imiim

-------
Appendix A-Regulatory Tables
Table A-6. PSES Limitations for 40 CFR Part 437 Subpart D (Multiple)
I'iiriiiiKMcr
Combined
Siihpiirls .
I);iil\
M;i\imiim
(in»/l.)
\\ iislo from
V. li. ;iiul (
M:i\iniiiiii
Muni hl\
A\it;i»i-
( (unbilled
Suhpiir
l);iil\
M;i\imiim
\\ iislo from
s A iind 1}
M;i\imiim
Mi >n l hl\
A\it;i»i-

l);iil\
M;i \ im inn
V\ iislo from
A ;md (
M;i\imiim
Muni h l\
A\it;i»i-
( o in billed
Suhpiirl
l);iil\
M;i\iiiiuin

-------
Appendix A-Regulatory Tables
Table A-7. PSNS Limitations for 40 CFR Part 437 Subpart D (Multiple)
I'iiriiiiKMcr
Combined
Siihpiirls .
I);iil\
M;i\imiim
(in»/l.)
\\ iislo from
V. li. ;iiul (
M:i\iniiiiii
Muni hl\
A\it;i»i-
( (unbilled
Suhpiir
l);iil\
M;i\imiim
\\ iislo from
s A iind 1}
M;i\imiim
Mi >n l hl\
A\it;i»i-

l);iil\
M;i \ im inn
V\ iislo from
A ;md (
M;i\imiim
Muni h l\
A\it;i»i-
( o in billed
Suhpiirl
l);iil\
M;i\iiiiuin

-------
Appendix A-Regulatory Tables
Table A-8. BPT Oil and Grease Limitations for 40 CFR Part 435 Subparts A
(Offshore) and D (Coastal)

Siihpiii'l A (Offshore)
Suhpiirl 1) (( oiis(iil)
\\ .isle Source
Miixiniiiin
M ;i\iimi in
Mon(hl\
A\er;iiic
(iiiii/l.)
l);iil\
Kosidiiiil
Chlorine
Minimum
(inji/1.)
l);iil\
Miixiinuni
(mji/l-l
M:i\iimi in
Monlhlv
l);iil\
Kosidiiiil
Chlorine
Minimum

-------
Appendix A-Regulatory Tables
Table A-9. BAT, BCT, and NSPS Limitations for 40 CFR Part 435 Subpart A (Offshore)
\\ ;is(e Source
Polliiliinl Piii'iiiiHMor
Suhpiirl A (O
HAT/ NSPS
Tslioiv)
IKT
Produced water
Oil and Grease
One-day max: 42 mg/1;
Monthly average: 29 mg/1
One-day max: 72 mg/k
Monthly average: 48
mg/1
Drilling fluids and drill cuttings for
facilities located within 3 miles from
shore

ND1
ND1
Drilling fluids and drill cuttings for
facilities located beyond 3 miles from
shore: water-based drilling fluids and
associated drill cuttings
SPP Toxicity
Minimum: 96-hour LC502: 3%
NA
Free Oil
ND3
ND2
Diesel Oil
ND
NA
Mercury
1 mg/kg dry weight maximum
NA
Cadmium
3 mg/kg dry weight maximum
NA
Drilling fluids and drill cuttings for
facilities located beyond 3 miles from
shore: non- aqueous drilling fluids

ND
NA
Drill cuttings associated with non-
aqueous fluids
Free Oil
NA
ND
Drill cuttings associated with non-
aqueous fluids stock limitations (Ci6-
Ci8 internal olefin)
Mercury
1 mg/kg dry weight maximum
NA
Cadmium
3 mg/kg dry weight maximum
NA
Polynuclear Aromatic
Hydrocarbons
Max ratio: lxlCT5 4
NA
Sediment Toxicity
Max ratio: 1.0 4
NA
Biodegradation Rate
Max ratio: 1.0 4
NA
Drill cuttings associated with non-
aqueous fluids discharge limitations
Diesel Oil
ND
NA
SPP Toxicity
Minimum: 96-hour LC502: 3%
NA
Sediment Toxicity
Max ratio: 1.0 4
NA
Formation Oil
ND5
NA
Base Fluid Retained on
Cuttings
Max ratio: 6.9 g-NAF base
fluid/100 g-wet drill cutting4
NA
Free Oil
NA
ND
Well treatment, completion, and
workover fluids
Oil and Grease
One-day max: 42 mg/1;
Monthly average: 29mg/l
ND
Deck drainage
Free Oil
ND6
ND
Produced sand

ND
ND
Domestic waste
Foam
ND
NA
Floating Solids
BAT: NA
NSPS: ND
ND
Other Domestic Waste
NA
See 33 CFR Part 151
Sanitary M10
Residual Chlorine
BAT: NA
NSPS: Minimum: 1 mg/1.
Minimum: 1 mg/1
Sanitary M91M
Floating Solids
NA
ND
NA - Not applicable.
ND - No discharge.
1	All Alaskan facilities are subject to the drilling fluids and drill cuttings discharge limitations for facilities located beyond 3
miles offshore.
2	As determined by the suspended particulate phase (SPP) toxicity test. See 40 CFR Part 435.1 l(gg).
3	As determined by the static sheen test. See 40 CFR Part 435.1 l(hh).
4	For the definition of all ratios, please see 40 CFR Part 435.
5	As determined before drilling fluids are shipped offshore by the EPA Method 1655, and as determined prior to discharge
by EPA Method 1670 applied to drilling fluid removed from drill cuttings.
6	As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving water (visual
sheen).
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
A-9

-------
Appendix A-Regulatory Tables
Table A-10. BAT, BCT, and NSPS Limitations for 40 CFR Part 435 Subpart D (Coastal)
Siiviim
Polliiliinl
Piii'iiiiHMcr
Siihpii
HAT/ NSPS
-1 1) (( (lilSlill)
BCT
Produced water for all coastal areas except
Cook Inlet
Oil and Grease
ND
One-day max: 72 mg/1;
Monthly average: 48 mg/1.
Produced water for Cook Inlet
Oil and Grease
One-day max: 42 mg/1;
Monthly average: 29
mg/1
One-day max: 72 mg/1;
Monthly average: 48 mg/1.
Drilling fluids, drill cuttings and dewatering
effluent for all coastal areas except Cook
Inlet.1

ND
ND
Water based drilling fluids, drill cuttings and
dewatering effluent for all coastal Cook Inlet
areas
SPP Toxicity
Minimum: 96-hour
LC502: 3%
NA
Free Oil
ND3
ND2
Diesel Oil
ND
NA
Mercury
1 mg/kg dry weight
maximum
NA
Cadmium
3 mg/kg dry weight
maximum
NA
Non- Aqueous drilling fluids drilling fluids,
drill cuttings and dewatering effluent for all
coastal Cook Inlet areas

ND
ND
Drill cuttings associated with non- aqueous
fluids for all coastal Cook Inlet areas
Free Oil
ND4
ND2
Well treatment, completion, and workover
fluids
Free Oil
NA
ND2
Well treatment, completion, and workover
fluids for all coastal areas except Cook Inlet

ND
ND
Well treatment, completion, and workover
fluids for Cook Inlet
Oil and Grease
One-day max: 42 mg/1;
Monthly average:
29mg/l
ND
Produced sand

ND
ND
Deck drainage
Free Oil
ND5
ND5
Domestic waste
Foam
ND
NA
Floating Solids and
Garbage
BAT: NA
NSPS: ND
ND
Sanitary Ml.
Residual Chlorine
BAT: NA
NSPS: Minimum: 1
mg/1
Minimum: 1 mg/1
Sanitary M91M
Floating Solids
BAT: NA
NSPS: ND
ND
1	BAT limitations for dewatering effluent are applicable prospectively, BAT limitations in this rule are not applicable to
discharges of dewatering effluent from reserve pits which as of the effective date of this rule no longer receive drilling
fluids and drill cuttings. Limitations on such discharges shall be determined by the NPDES permit issuing authority.
2	As determined by the suspended particulate phase (SPP) toxicity test. See 40 CFR Part 435.1 l(gg).
3	As determined by the static sheen test. See 40 CFR Part 435.41(ff).
4	When Cook Inlet operators cannot comply with this no discharge requirement due to technical limitations (see appendix 1
of subpart D of this part), Cook Inlet operators shall meet the same stock limitations (C16-C18 internal olefin) and
discharge limitations for drill cuttings associated with non-aqueous drilling fluids for operators in Offshore waters (see 40
CFR Part 435.13) to discharge drill cuttings associated with non-aqueous drilling fluids.
5	As determined by the presence of a film or sheen upon or a discoloration of the surface of the receiving water (visual
sheen).
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
A-10

-------
Appendix B
Well Count Data

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Appendix B—Well Count Data
Appendix B: Well Count Data
The total number of wells that were active in 2014 may have been higher than estimated
because of incomplete entries in the DI Desktop® Well File Database. EPA did not include these
wells in the counts presented in Table B-l. Table B-2 shows the number of wells by state. Note
that states not contained in this table did not have any onshore oil and gas extraction wells as of
2014.
Table B-l. Total Number of Active Onshore Oil and Gas
Extraction Wells in Each Basin (2014)
liiisin \;iiik'
Number <»r\\cNs
Slides Included
Permian
295,308
NM, TX
Appalachian
187,981
AL, KY, MD, NY, OH, PA, TN, VA, WV
Anadarko
93,855
CO, KS, OK, TX
Texas and Louisiana Gulf Coast
84,951
LA, TX
Ft. Worth
79,210
TX
East Texas
49,268
TX
Arkla
32,184
AR, LA, MS, TX
Cherokee
23,641
KS
San Juan
23,432
CO, NM
Denver Julesburg
22,908
CO, NE, WY
Central Kansas Uplift
20,891
KS
San Joaquin
17,728
CA
Arkoma
17,119
AR, NM, OK
Williston
16,972
MT, ND, SD
Chautauqua Platform
15,053
KS, OK
Powder River
13,654
MT, SD, WY
Michigan
11,966
MI, OH
Uinta
11,478
UT
Piceance
11,173
CO
Green River
10,924
CO, UT, WY
Forest City
9,811
KS, MO, NE
South Oklahoma Folded Belt
8,258
OK, TX
Sedgwick
7,404
KS
Nemaha Anticline
6,017
KS
Ouachita Folded Belt
5,522
OK, TX
Black Warrior
4,801
AL, MS
Mississippi and Alabama Gulf Coast
3,800
AL, FL, LA, MS
Palo Duro
3,626
OK, TX
Los Angeles
3,602
CA
Sweet Grass Arch
3,582
MT
Raton
3,569
CO, NM
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
B-l

-------
Appendix B—Well Count Data
Table B-l. Total Number of Active Onshore Oil and Gas
Extraction Wells in Each Basin (2014)
liiisin \;iiik'
Number <»r\\cNs
Slides Included
Wind River
2,722
WY
Big Horn
2,698
MT, WY
Las Animas Arch
1,767
CO, KS
Central Western Overthurst
1,764
WY
Arctic Slope
1,502
AK
Illinois
1,448
AR, KY
Chadron Arch
1,282
KS, NE
Paradox
1,036
CO, UT
Central Montana Uplift
918
MT
Ventura
831
CA
Cincinnati Arch
774
KY, OH
Santa Maria
630
CA
Salina
419
CA, KS, NE
Cook Inlet
305
AK
Sacramento
275
CA
Great Basin
58
NV
Black Mesa
25
AZ
North Park
24
CO
Gom- Shelf
23
TX
Wasatch Uplift
23
UT
Arctic Ocean, ST.
18
AK
Northern Coast PRVC
13
CA
Eel River
4
CA
Half Moon
1
CA
Reported as "N/A", "0", "N", or blank
850
CA, FL, KS, LA, MI, NV, OR, TX, UT
Total
1,119,098

CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
B-2

-------
Appendix B—Well Count Data
Table B-2. Total Number of Active Onshore Oil and Gas
Extraction Wells in Each State (2014)
Sliilo
Nil in her of Wells
Sliilo
Number of Wells
AK
1,825
NE
1,814
AL
6,469
NM
44,319
AR
10,081
NV
68
AZ
25
NY
8,980
CA
23,187
OH
39,194
CO
39,884
OK
59,829
FL
68
OR
15
KS
101,541
PA
66,793
KY
16,831
SD
220
LA
36,055
TN
1,751
MD
3
TX
524,153
MI
11,928
UT
12,450
MO
10
VA
6,201
MS
3,365
wv
49,185
MT
9,839
WY
31,239
ND
11,776
National Total
1,119,098
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
B-3

-------
Appendix C
Profile of the NAICS Codes Traditionally
Associated with the CWT Industry

-------
This page intentionally left blank.

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Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
Appendix C: Profile of the NAICS Codes Traditionally Associated with the CWT Industry
As discussed in Section 4.1, CWT activity has traditionally occurred in three North
American Industry Classification System (NAICS) sectors: Hazardous Waste Treatment and
Disposal (NAICS 562211), Other Nonhazardous Waste Treatment and Disposal (NAICS
562212) and Materials Recovery Facilities (NAICS 562920) (U.S. EPA, 2006).46 This appendix
reviews a number of metrics that provide insight into operational and market structure, economic
performance, and financial health of the NAICS codes traditionally associated with the CWT
industry. Because these industry sectors reflect the traditional CWT industry, they include
operations that are much broader in customer base than the oil and gas industry and other non-
CWT facilities. Table C-l provides a description of each of the three NAICS codes traditionally
associated with the CWT industry.
EPA used data from the most recent years of Statistics of U.S. Businesses (SUSB) and
the Economic Census published by the U.S. Census Bureau (2015 and 2012, respectively). This
is a limitation to EPA's full understanding of the most recent trends in the traditional CWT
industry.
Table C-l. Total facilities in NAICS codes associated with traditional
Centralized Waste Treatment Industry
NAICS
NAICS
IK'scriplion
l-'acililios Included
Number «l"
l-'acililics
562211
Hazardous Waste
Treatment and
Disposal
(1) operating treatment and/or disposal facilities for hazardous waste
or (2) the combined activity of collecting and/or hauling of
hazardous waste materials within a local area and operating
treatment or disposal facilities for hazardous waste.
892
562219
Other
Nonhazardous
Waste Treatment
and Disposal
(1) operating nonhazardous waste treatment and disposal facilities
(except landfills, combustors, incinerators and sewer systems or
sewage treatment facilities) or (2) the combined activity of collecting
and/or hauling of nonhazardous waste materials within a local area
and operating waste treatment or disposal facilities (except landfills,
combustors, incinerators and sewer systems, or sewage treatment
facilities). Compost dumps are included in this industry.
283
562920
Materials
Recovery
(1) operating facilities for separating and sorting recyclable materials
from nonhazardous waste streams (i.e., garbage) and/or (2) operating
facilities where commingled recyclable materials, such as paper,
plastics, used beverage cans, and metals, are sorted into distinct
categories.
1,455
Total
2,630
Source: U.S. DOC, 2015 (SUSB).
46 For the 2000 Final Centralized Waste Treatment Rule, EPA relied on information gathered from a 1990 survey questionnaire
and comments to the 1996 Notice of Data Availability (NODA) to determine the universe of CWT facilities. Based on these two
data sources, EPA determined that there were 223 CWT facilities in scope. The majority of respondents identified their industry
as SIC 4953: Refuse Systems. This SIC code maps to five NAICS codes, three of which were determined to be in scope: NAICS
562211, NAICS 562219, and NAICS 562920. For the 2010 RFA analysis, EPA assumed that facilities in these three NAICS
industry segments represented the entire CWT industry and were all subject to the 2000 Final CWT Rule (U.S. EPA, 2010).
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
C-l

-------
Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
C.l Facilities over 10 years
Table C-2 reports the number of establishments for the three analyzed CWT segments
from SUSB for 2005 through 2015. In terms of the number of facilities, Other Nonhazardous
Waste Treatment and Disposal (NAICS 562219) is the smallest segment of the analyzed sector,
accounting for only 11 percent, while Materials Recovery (NAICS 562920) is the largest
segment, accounting for 55 percent of all facilities in 2015. Since 2005, overall, the number of
facilities grew steadily at an average annual growth rate of approximately 4 percent, which
resulted in an overall increase of nearly 44 percent. This growth profile occurred in all three
segments.
Table C-2. Number of Establishments by Industry Sector and Year
\ i-;ir
1 l;i/.;il'(l(ius \\;isk-
l lViilllKllI ;iihI l)is|)iis:il
(NAICS 5r,2211)
Ollu-r \
-------
Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
the previous rulemaking, only 4 of the 211 facilities surveyed (less than 2 percent) were
noncommercial (U.S. EPA, 2006).
The commercial status of CWT facilities may be an important factor in assessing the
possible impact of higher operating costs resulting from potential changes to the current CWT
ELGs. Commercial CWT facilities face price competition both among themselves and from the
potential for on-site waste treatment, which may be more financially advantageous than
purchasing CWT services from separate providers. This is true for CWT facilities that treat oil
and gas wastewater, as well. Commercial CWT facilities thus face limitations in passing
regulation-induced price increases onto customers depending on the extent of competition among
commercial CWT facilities and the latent competitive effect from waste generators, which
possess the option of developing their own CWT capabilities.
Since strictly noncommercial CWT facilities are owned and operated as an integrated
service within the companies that generate the waste they treat, a regulation-induced increase in
operating costs is not likely to result in a market-observed price increase for CWT services. This
is true for CWT facilities that treat oil and gas wastewater, as well. However, the increase in
operating costs may result in higher prices for the final sale products manufactured by the waste-
generating facilities within the company and, in turn, potentially result in lower output depending
on the market power possessed by a given parent entity. Contract noncommercial facilities -
which may be owned by more than one waste producer but are still captive providers of CWT
services in an integrated operation - are in similar circumstances. Thus, while the price limiting
effect from competition among CWT facilities may not be present among noncommercial CWT
facilities in the same way as it is present for commercial CWT facilities, the owners of
noncommercial CWTs nonetheless may face competition in the pricing of their final products.
As a result, increased production costs, due to a revised CWT rule, may lead to lower output and
revenue reductions among these entities. This in turn would affect the quantity of waste
generated and the demand for and quantity of CWT services provided in this business structure.
C.2 Firms over 10 years
Parent entities have the ability to conduct business transactions and make business
decisions affecting facilities they own; consequently, depending on market conditions, existing
firms could be forced out of business or forced to merge with other (CWT or non-CWT) firms as
a result of regulation-induced increases in operating costs. The degree of consolidation of firms
can be an indication of the industry's financial health. Further, less favorable CWT market
conditions may deter non-CWT companies from entering the CWT industry. To assess how
CWT industry concentration might have changed over time in response to fluctuations in
economic conditions, EPA looked at the number of firms reported by SUSB.
As reported in Table C-3 the number of firms (as opposed to establishments) have also
fluctuated since 2005. Since 2005, the number of firms increased by 23 percent, at an annual
average growth rate of about 2 percent. By segment, the number of firms in Hazardous Waste
Treatment and Disposal (NAICS 562211) decreased by nearly 9 percent. In contrast, the number
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
C-3

-------
Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
of firms in Other Nonhazardous Waste Treatment and Disposal (NAICS 562219) and Materials
Recovery (NAICS 562920) increased by 16 percent and 36 percent, respectively. The number of
firms in the Hazardous Waste Treatment and Disposal (NAICS 562211) segment increased
continuously until 2007 when it began to decline until 2013, with a brief increase in 2011, before
increasing to 2015. On the other hand, there were relatively large increases in the number of
firms in the Materials Recovery (NAICS 562920) segment in 2007, 2008, and 2012. The
increase in the number of firms in the Other Nonhazardous Waste Treatment and Disposal
(NAICS 562219) segment was caused by a large increase in 2014 (28 percent) and 2015 (6
percent), despite declines in 2003 (27 percent), 2008 (17 percent), and 2012 (23 percent).
Table C-3. Number of Firms by Industry Segment and Year



Oilier Nonha/.ardous





1 la/.ardous \\ asle
\\ asle Treatment and





Trcalmcnl
and Disposal
Disposal Sen ices
Materials Keio\er\



(NAICS 5r,22l 1)
(NAICS 56221'))
(NAICS 562')20)
Total CWT
^ i ;i r
Number
" ii Change
Number
"/« Change
Number
" ii Change
Number
" ii Change
2005
466
1.3%
191
1.6%
765
-2.3%
1,422
-0.6%
2006
471
1.1%
203
6.3%
803
5.0%
1,477
3.9%
2007
451
-4.2%
222
9.4%
884
10.1%
1,557
5.4%
2008
429
-4.9%
185
-16.7%
937
6.0%
1,551
-0.4%
2009
427
-0.5%
195
5.4%
920
-1.8%
1,542
-0.6%
2010
422
-1.2%
214
9.7%
920
0.0%
1,556
0.9%
2011
433
2.6%
216
0.9%
921
0.1%
1,570
0.9%
2012
430
-0.7%
160
-25.9%
1,079
17.2%
1,669
6.3%
2013
420
-2.3%
163
1.9%
1,085
0.6%
1,668
-0.1%
2014
421
0.2%
209
28.2%
1,074
-1.0%
1,704
2.2%
2015
426
1.2%
221
5.7%
1,042
-3.0%
1,689
-0.9%
2005 - 2015 1 ';iI'isiiii
Total Percent
Change

-8.6%

15.7%

36.2%

22.7%
Annual Average
Growth Rate

-0.9%

1.5%

3.1%

1.7%
Source: U.S. DOC, 2005-2015 (SUSB).
Given only minor year-to-year fluctuations in the number of CWT firms but as a general
trend overall, an increase in the number of firms in the CWT industry between 2005 and 2015, it
appears that, in general, market conditions have not encouraged mergers and acquisitions or
prevented new firms from entering the industry identified by these NAICS codes. It is possible
that the economic downturn and uncertainty reflected in volatile financial markets deterred some
more conservative CWT market players from merging with and/or acquiring other market
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
C-4

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Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
players. Such was the case with Waste Management Inc., one of the major market players, which
decided not to acquire Republic Services Group in 2008.47
However, such conservative behavior is not characteristic of the entire industry; after
Waste Management Inc. withdrew its offer, Republic Services Group acquired a larger
competitor Allied Waste (De La Merced, 2008).48 More recently, some business analysts cite a
trend towards increased consolidation in the overall waste services industry, which includes
CWT services. This activity was spurred by financial weakness and declining asset values among
smaller waste services firms due to the economic weakness and financial stress beginning in
2007, coupled with a higher level of financial strength among larger firms. In this case, the
larger, financially stronger firms can acquire the smaller, less financially resilient, businesses at
depressed asset prices. As the economy strengthens and waste volumes increase, this
consolidation would leave the larger firms in an overall stronger market position (Waste
Management Inc., 2011; Republic Services Inc., 2011; S&P, 2011a; S&P, 2011b).
C.3 Presence of Small Businesses over ten years
The Small Business Association (SB A) provides guidelines for how to define small
businesses for each industry (6-digit NAICS). For the Hazardous Waste Treatment and Disposal
(NAICS 562211) and Other Nonhazardous Waste Treatment and Disposal (NAICS 562219)
segments, the SB A guidelines indicate that a business qualifies as a small business if its annual
revenue is below $38.5 million; for the Materials Recovery (NAICS 562920) segment, annual
revenue below $20.5 million qualifies as a small business (U.S. SB A, 2016). Due to the lack of
data available to identify the size of entities based on their revenue, EPA employed the "100 or
fewer employees" threshold as the basis for assessing the presence of small businesses in the
CWT industry for the purposes of this profile. This threshold is based on analysis conducted in
the Regulatory Flexibility Act Section 610 Review of the Effluent Limitations Guidelines and
Standards for the Centralized Waste Treatment Industry report. Similar to the analysis conducted
for that review, EPA used SUSB data to estimate the number of small firms in the CWT industry
and the three CWT segments (U.S. EPA, 2010).
From 2005 to 2015, the majority of firms in all three NAICS segments (85 to 94 percent)
were designated as small when using the "100 or fewer employees threshold" (Table C-4). The
Materials Recovery segment (NAICS 562920) had the highest percentage of small firms until
2009, when the percentage of small firms in the Other Nonhazardous Treatment and Disposal
(NAICS 562219) segment rose to 93 percent. The total number of CWT firms with 100 or fewer
47	Waste Management, Inc. is the largest waste disposal company in North America. The company provides
collection, transfer, recycling and resource recovery, as well as disposal services. It also owns U.S. waste-to-energy
facilities. For more information on Waste Management, Inc. see http://www.wm.com/index.isp.
48	After the merger, the company is called Republic Services, Inc. and is currently the third largest U.S. provider in
the non-hazardous solid waste industry. It provides collection services to commercial, industrial, municipal, and
residential consumers. For more information on Republic Services, Inc., see http://www.alliedwaste.com/.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
C-5

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Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
employees grew almost continuously throughout the analysis period, except for a slight decline
in 2008-2009.
Overall, however, from 2005 to 2015, the total number of firms increased by 19 percent,
while the number of firms with greater than 100 employees (i.e., large businesses) increased by
39 percent. Thus, for the full analysis period, the presence of smaller firms (based on the "100 or
fewer employees" threshold) decreased compared to larger firms.
The pattern of change in the presence of small and large businesses during the 2005-2015
analysis period varies among the three CWT segments:
•	In the Hazardous Waste Treatment and Disposal segment (NAICS 562211), the number of
small firms decreased by 10 percent, while the number of large firms increased by 4 percent.
•	In the Other Nonhazardous Waste Treatment and Disposal segment (NAICS 562219), the
number of small entities increased by 19 percent, while the number of large entities
decreased by 17 percent.
•	In the Materials Recovery segment (NAICS 562920), the number of small firms increased by
32 percent, while the number of large firms increased by 93 percent.
Consequently, while there was a shift towards large entities in the Hazardous Waste
Treatment and Disposal segment (NAICS 562211) and the Materials Recovery segment (NAICS
562920), there was a shift towards smaller entities in the Other Nonhazardous Waste Treatment
and Disposal segment (NAICS 562219) between 2005 and 2015.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
C-6

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Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
Table C-4. Number of Firms by Employment Size, Industry Segment, and Year -
Using the "100 or Fewer Employees" SBA Size Threshold
^ i';i r
l!mplo\ iiu-nl
Group
lla/.ardous Waste
Trealmenl and
Disposal (NAICS
5f>2211)
Other
Noil ha/.ardous
Wasle Trealmeiil
and Disposal
(NAICS 5r,22l*>)
Materials Keio\er\
(NAICS 5r.2*>2(»)
Total CWT
Number
"...of
Total
Number
"..of
Total
N urn her
"i.or
l ot a 1
Number
% of
Total
2005
<100
412
88%
173
91%
711
93%
1,296
91%
>100
54
12%
18
9%
54
7%
126
9%
2006
<100
413
88%
181
89%
740
92%
1,334
90%
>100
58
12%
22
11%
63
8%
143
10%
2007
<100
396
88%
199
90%
820
93%
1,415
91%
>100
55
12%
23
10%
64
7%
142
9%
2008
<100
369
86%
170
92%
863
92%
1,402
90%
>100
60
14%
15
8%
74
8%
149
10%
2009
<100
367
86%
182
93%
847
92%
1,396
91%
>100
60
14%
13
7%
73
8%
146
9%
2010
<100
369
86%
199
93%
847
92%
1,415
91%
>100
53
13%
15
7%
73
8%
141
9%
2011
<100
378
86%
202
94%
841
91%
1,421
91%
>100
55
13%
14
6%
80
9%
149
9%
2012
<100
365
85%
150
94%
981
91%
1,496
90%
>100
65
15%
10
6%
98
9%
173
10%
2013
<100
359
85%
154
94%
982
91%
1,495
90%
>100
61
15%
9
6%
103
9%
173
10%
2014
<100
364
86%
196
94%
973
91%
1,533
90%
>100
57
14%
13
6%
101
9%
171
10%
2015
<100
370
87%
206
93%
938
90%
1,514
90%
> 100
56
13%,
15
7%,
104
10%,
175
10%,
20(15-2015 Comparison
Total Percent
Change
<100

-10.2%

19.1%

31.9%

16.8%
>100

3.7%

-16.7%

92.6%

38.9%
Annual
Average
Growth Rate
<100

-1.1%

1.8%

2.8%

1.6%
>100

0.4%

-1.8%

6.8%

3.3%
Sources: U.S. DOC,2005-2015 (SUSB).
The changes that occur in the average size of firms, based on employment, are another
indicator of relative small business presence in the industry. During 2005 through 2015, the
average number of employees per firm in the industry increased (Table C-5), from 29 employees
per firm in 2005 to 31 employees per firm in 2015. Specifically, the average number of
employees per firm increased in the Hazardous Waste Treatment and Disposal (NAICS 562211)
segment (33 percent) and the Materials Recovery (NAICS 562920) segment (9 percent) while
decreasing in the Other Nonhazardous Waste Treatment and Disposal (NAICS 562219) segment
(27 percent). However, during this time, this number fluctuated within the all three industry
segments and by industry segment. The year-to-year changes do not show any obvious trends in
the average firm size, measured by the average number of employees.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
C-7

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Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
Table C-5. Average Number of Employees per Firm by Segment and Year
^ ciir
1 la/.ardous \\ asle
Trcalmclll and Disposal
(NAICS 5^2211)
Oilier Nonha/.ardous
Wasle Trealmeiil and
Disposal Sen ices
(NAICS 5f.22l9)
Materials Keco\er\
(NAICS 5r.2*>20)
Tolal
Number
"¦« Change
Nil in her
"¦'II Change
Nil in her
Change
Nil in her
"¦¦ii Change
2()()S
49
-1.2%
17
-4.5%
19
2 8%
29
0 6%
2006
56
13.9%
17
0.0%
20
2.2%
31
7.5%
2007
53
-6.1%
20
16.5%
16
-16.7%
27
-11.4%
2008
54
1.2%
15
-22.4%
17
5.4%
27
-1.4%
2009
48
-9.7%
14
-10.2%
18
1.4%
26
-5.6%
2010
51
4.9%
14
-0.1%
18
1.8%
26
2.4%
2011
56
10.9%
15
4.9%
20
11.2%
29
11.2%
2012
80
42.7%
13
-9.4%
20
-0.8%
35
18.9%
2013
73
-9.2%
11
-16.6%
20
3.0%
33
-5.9%
2014
67
-7.6%
11
2.5%
20
-1.7%
31
-6.3%
2015
66
-2.1%
12
10.4%
21
4.9%
31
1.9%
2005-2015 Comparison
Total Percent
Change

33.1%

-27.3%

8.5%

7.8%
Annual Average
Growth Rate

2.9%

-3.1%

0.8%

0.8%
Sources: U.S. DOC, 2005-2015 (SUSB).
C.4 Economic Performance over 10 years
Any declines in the amount of wastes treated and/or profitability in the industry would
likely manifest as declines in industry employment, revenue, and other measures of economic
performance.
Table C-6 presents the number of employees for the overall industry and by segment for
2005 through 2015. From 2005 to 2015, total industry employment increased substantially, by 28
percent. At the segment level, employment increased in the Hazardous Waste Treatment and
Disposal segment (NAICS 562211) and the Materials Recovery segment (NAICS 562920),
showing substantial increases by about 22 percent and 48 percent, respectively, between 2005
and 2015. However, during the same time period, the number of employees in the Other
Nonhazardous Treatment and Disposal segment (NAICS 562219) decreased by approximately
16 percent. Major losses in the number of employees within the Other Nonhazardous Treatment
and Disposal segment (NAICS 562219) came in 2008 and 2012 with approximately 35 percent
and 33 percent decreases, respectively.
Given (1) the increase in the number of employees in the overall industry since 2005, and
(2) the lack of a pattern in the employment growth trends in the period, there is no basis for
concluding that there were contractions in activity and reduced employment in the industry
during the last decade.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
C-8

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Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
Data from the Economic Census for years 2002, 2007, and 2012 on revenue,
employment, and payroll can also provide insight into the effects on the industry of changing
conditions through the period of analysis.49
Between 2002 and 2012, the industry grew in revenue, employment, annual payroll and
revenue less payroll, shown in Table C-7 Likewise, the Hazardous Waste Treatment and
Disposal (NAICS 562211) and Materials Recovery (NAICS 562920) experienced increases in all
four metrics during the period of analysis. Only the Other Nonhazardous Treatment and Disposal
segment (NAICS 562219), the smallest segment, reported a decrease in the four reported metrics.
The generally strong performance at both the industry and segment level suggests that there were
no adverse effects on the industry despite fluctuations in general economic conditions.
Table C-6. Number of Employees by CWT Segment and Year

lla/.ardoiis Wasle
Trealnienl and
Disposal (NAICS
5r,2211)
Oilier Nonha/.ardous
\\ asle Treatment and
Disposal
(NAICS 5r,221*>»
Materials Keio\er\
(NAICS 5f.2'J20)
Tolal CWT
Number
"¦•u Change
N inn her
" ii Change
Number
" ii Change
N u in her
"¦•'ii Change
2()()S
23 0^9
0.1%
-s ~)H~)
_
14,744
()
41,075
() (Wo



2006
26,556
15.2%
3,477
6.3%
15,820
7.3%
45,853
11.6%
2007
23,869
-10.1%
4,429
27.4%
14,514
-8.3%
42,812
-6.6%
2008
22,985
-3.7%
2,863
-35.4%
16,215
11.7%
42,063
-1.7%
2009
20,649
-10.2%
2,710
-5.3%
16,137
-0.5%
39,496
-6.1%
2010
21,400
3.6%
2,971
9.6%
16,429
1.8%
40,800
3.3%
2011
24,342
13.7%
3,146
5.9%
18,291
11.3%
45,779
12.2%
2012
34,489
41.7%
2,111
-32.9%
21,268
16.3%
57,868
26.4%
2013
30,581
-11.3%
1,794
-15.0%
22,020
3.5%
54,395
-6.0%
2014
28,319
-7.4%
2,357
31.4%
21,419
-2.7%
52,095
-4.2%
2015
28,055
-0.9%
2,751
16.7%
21,795
1.8%
52,601
1.0%
2005 - 2013 Comparison
Total Percent
Change

21.7%

-15.9%

47.8%

28.1%
Annual Average
Growth Rate

2.0%

-1.7%

4.0%

2.5%
Sources: U.S. DOC, 2005-2015 (SUSB.
49 Employment data from the Economic Census may differ from employment numbers previously reported based on
SUSB data.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
C-9

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Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
Table C-7. Key Economic Performance Statistics for Segments and Total of all
Three, 2002-2012
^ ear
Number of
KslaMishmeiils
ke\elllle
(Millions; S20I3)
Annual Pax roll
(Millions; S20I3)
Ke\elllle Less
Pax roll
(Millions; S20I3)
Number of
l!mplo\ees

Ma/ardous Waste Treatment and Disposal (NAICS 56221 1)

2Q02
696
$4,344
$1,234
$3,110
21,566
2007
779
$6,326
$2,014
$4,311
34,396
2012
853
$6,724
$1,700
$5,025
30,168
Total Percent Change
2002-2012
22.6%
54.8%
37.8%
61.6%
39.9%
Average Annual Growth
Rate 2002-2012
2.1%
4.5%
3.3%
4.9%
3.4%
Other
Nonha/ardous \\ asle Treatment and Disposal Sen ices (NAICS 5r«2211>)

2002
199
$731
$182
$549
3,673
2007
227
$758
$171
$588
3,170
2012
181
$361
$71
$290
1,365
Total Percent Change
2002-2012
-9.0%
-50.6%
-61.0%
-47.1%
-62.8%
Average Annual Growth
Rate 2002-2012
-0.9%
-6.8%
-9.0%
-6.2%
-9.4%
Materials Keco\er\ (NAICS 562920)
2002
938
$2 299
$513
$1,787
14,752
2007
1,129
$4,987
$666
$4,321
16,808
2012
1,429
$5,705
$792
$4,913
21,918
Total Percent Change
2002-2012
52.3%
148.1%
54.5%
175.0%
48.6%
Average Annual Growth
Rate 2002-2012
4.3%
9.5%
4.4%
10.6%
4.0%
Total
2002
1,833
$7,374
$1,928
$5,446
39,991
2007
2,135
$12,071
$2,851
$9,221
54,374
2012
2,463
$12,791
$2,563
$10,228
53,451
Total Percent Change
2002-2012
34.4%
73.4%
32.9%
87.8%
33.7%
Average Annual Growth
Rate 2002-2012
3.0%
5.7%
2.9%
6.5%
2.9%
Sources: U.S. DOC, 2002, 2007, and 2012 (EC); U.S. DOC, 2014.
As discussed earlier, as demand for off-site waste treatment fell in response to the recent
(2008) economic downturn and surging fuel prices, which resulted in higher prices of waste
management services, CWT companies in the broader waste services industry faced increasing
competitive pressures and revenue losses. In their attempts to reduce their operating costs and
ensure their overall business remained competitive, some larger waste management companies
divested underperforming assets, while undertaking "tuck-in" acquisitions of smaller haulers in
line with their "internalization" strategy.50 This "internalization" strategy enables companies to
reduce capital and expenses used in routing, personnel, equipment and vehicle maintenance,
50 An example of a "tuck-in" acquisition is an acquisition of a collection facility strategically located near an
existing disposal facility, which generally enhances an existing route structure.
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
C-10

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Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
inventories, and back-office administration. It also enables companies to provide a wider range
of services and retain existing and attract new clients, thereby improving their revenue
generation. The breadth of waste management services and familiarity with a wide range of
waste management practices put these companies in a better position to help their customers to
minimize waste they generate, identify recycling opportunities and the most efficient ways to
collect and dispose of waste. To grow customer loyalty, some CWT companies also made
conscious efforts to improve their customer service. Smaller CWT companies have faced greater
challenges maintaining their market share and profitability in a soft economic environment
(Waste Management Inc., 2011; Republic Services Inc., 2011; S&P, 201 la; S&P, 201 lb).
C.5 References
1.	De La Merced, Michael J. 2008. "$11 Billion in Deals Canceled in Tumult." The
New York Times. October 13, 2008. Available electronically at:
http://www.nvtimes.com/20Q8/10/14/business/14deal.html? r=0. DCN
CWT00528
2.	Republic Services, Inc. 2011. Form 10-K for the Fiscal Year Ended December 31,
2010. Filed on February 18, 2011. Available electronically at:
http://phx.corporate-ir.net/phoenix.zhtml?c=8238 l&p=irol-sec. DCN CWT00223
3.	Standard & Poor's (S&P). 201 la. Standard & Poor's Stock Report: Republic
Services Inc. September 3, 2011. DCN CWT00530
4.	Standard & Poor's (S&P). 201 lb. Standard & Poor's Stock Report: Waste
Management Inc. September 3, 2011. DCN CWT00531
5.	United States Department of Commerce (U.S. DOC). 2014. Table 1.1.9. Implicit
Price Deflators for Gross Domestic Product. March 27, 2014. Accessed April 17,
2014. Available electronically at:
http://www.bea.gov/iTable/iTable. cfm?ReqID=9&step=l#reqid=9&step=3&isuri
=1&903=13. DCN CWT00219
6.	United States Department of Commerce (U.S. DOC). 2005-2015. U.S. Bureau of
the Census. Statistics of U.S. Businesses (SUSB). Available electronically at:
https://www.census.gov/econ/susb/. DCN CWT00252
7.	United States Department of Commerce (U.S. DOC). 2002, 2007, and 2012. U.S.
Bureau of the Census. Economic Census (EC). DCN CWT00221
8.	United States Environmental Protection Agency (U.S. EPA). 2010. Regulatory
Flexibility Act Section 610 Review of Effluent Limitations Guidelines and
Standards for the Centralized Waste Treatment Industry. DCN CWT00222
9.	United States Small Business Administration (U.S. SBA). 2016. Table of Small
Business Size Standards Matched to North American Industry Classification
System Codes. February 26, 2016. Available electronically at:
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
C-ll

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Appendix C—Profile of the NAICS Codes Traditionally Associated with the CWT Industry
https://www.sba.gov/sites/default/files/files/Size Standards Table.pdf. DCN
CWT00214
10. Waste Management, Inc. 2011. Form 10-K for the Fiscal Year Ended December
31, 2010. Filed on February 17, 2011. Available electronically at:
http://investors.wm.com/phoenix.zhtml?c=l 19743&p=irol-sec. DCN CWT00218
CWT Point Source Category for Facilities Managing Oil and Gas Extraction Wastes
C-12

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