Summary of Input on Oil and Gas
Extraction Wastewater Management
Practices Under the Clean Water Act
EPA-821-S19-001
U.S. Environmental Protection Agency
Engineering and Analysis Division
Office of Water
1200 Pennsylvania Avenue, NW
Washington, D.C. 20460
Final May 2020
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Disclaimer
DISCLAIMER
This document is not a regulation, nor is it guidance on how to comply with regulations.
Thus, this document does not impose legally binding requirements on the U.S.
Environmental Protection Agency, states, tribes, or the regulated community, and the
general description provided here may not apply to a particular situation based upon the
circumstances. This document does not confer legal rights or impose legal obligations upon
any member of the public.
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Contents
CONTENTS
Page
1. Executive Summary 1
2. Study Scope and Goals 5
3. Background 7
3.1 Produced Water Characteristics 7
3.2 Management of Produced Waters 9
3.3 The EPA's Clean Water Act Regulations for Produced Water 11
3.3.1 Technology-Based Effluent Limitations 11
3.3.2 Water Quality-Based Effluent Limitations 16
4. The EPA's Outreach to Stakeholders 18
4.1 Major Themes from State Agencies 20
4.2 Major Themes from Tribes 24
4.3 Major Themes from Oil and Gas Industry Members 25
4.4 Major Themes from Members of NGOs 28
4.5 Major Themes from Members of Academia 29
4.6 Major Themes from Other Entities 31
5. Summary and Next Steps 32
6. References 33
Summary of Input Oil and Gas Extraction Wastewater Management Practices i
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List of Tables
LIST OF TABLES
Page
Table 3-1. Type and Purpose of Additives used in Well Development, Stimulation
and Maintenance 8
Table 3-2. Applicability of Effluent Guidelines Levels of Control to Types of
Discharger 12
Table 3-3. Pollutant Classes Regulated by Effluent Guidelines Levels of Control 12
Table 3-4. Levels of Control by Subcategory in the Oil and Gas Extraction
Effluent Guidelines 13
Table 3-5. Subparts of 40 CFR Part 435 and their Applicability and Limitations 14
Table 4-1. List of Engagement Activities in 2018 19
Summary of Input Oil and Gas Extraction Wastewater Management Practices ii
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List of Figures
LIST OF FIGURES
Page
Figure 3-1. Concentration of Select Constituents in Oil and Gas Produced Water
(USGS National Produced Waters Geochemical Database, V2.2) 9
Figure 3-2. Produced Water Management Options 10
Figure 3-3. Map of 98th Meridian* 15
Summary of Input Oil and Gas Extraction Wastewater Management Practices iii
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Section 1 -Executive Summary
1. Executive Summary
Large volumes of wastewater are generated in the oil and gas industry, and
projections show that these volumes are likely to increase. Currently, the majority of
produced water is managed via reuse within the oil field for practices such as enhanced oil
recovery, or by disposing of it using a practice known as underground injection where that
water can no longer be accessed or used. The limits of injection are evident in some areas,
and new approaches are becoming necessary. Some states and stakeholders are asking
whether it makes sense to continue to waste this water, particularly in water scarce areas
of the country, and what steps would be necessary to treat and renew it for other purposes.
As a result, the U.S. Environmental Protection Agency (EPA) conducted a study
evaluating management of produced waters1 from onshore oil and gas extraction activities.
The EPA wanted to better understand produced water generation, management, and
disposal options at the regional, state and local levels for both conventional and
unconventional2 onshore oil and gas extraction. While the EPA looked at a variety of
alternatives for reuse of produced water, ultimately, the EPA's study goal was to evaluate
approaches to manage oil and gas extraction wastewaters generated at onshore facilities.
EPA had previously studied facilities that treat and discharge oil and gas extraction
wastewaters to surface waters that are regulated under the Clean Water Act (CWA) (for
purposes of this report, "surface waters"3) in the Centralized Waste Treatment Study (U.S.
EPA, 2018). A second goal was to better understand any potential need for, and any
concerns over, additional discharge options under the CWA for onshore oil and gas
wastewater.
During the EPA's outreach activities, stakeholders raised several concerns regarding
additional discharge options for treated produced waters. The main concerns were related
to the amount of available data on the chemistry of produced waters and the performance
of treatment technologies. A related concern was the availability of analytical methods for
measuring the constituents in produced water, and the potential toxicity of these
constituents. Stakeholders were also concerned about potential impacts to downstream
users, such as impacts to drinking water utilities. These are considerations that are
1 For purposes of this study, EPA is using the definition of produced water found at 40 CFR Part 435 which is:
"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."
2 EPA defines unconventional oil and gas at 40 CFR 435.33(a)(2)(i) as "crude oil and natural gas produced by
a well drilled into a shale and/or tight formation (including, but not limited to, shale gas, shale oil, tight gas,
tight oil)."
3Only waters that meet the definition of "waters of the United States" are regulated under the CWA 33 U.S.C.
1362 (7). Therefore, the term "surface waters" as used in this report refers to "waters of the United States."
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Section 1 -Executive Summary
important as the EPA considers next steps for its CWA programs related to produced water
management.
The EPA currently regulates discharges of oil and gas wastewater under the oil and
gas extraction effluent limitations guidelines and pretreatment standards (ELGs) found at
40 CFR part 435. For onshore oil and gas producers, except stripper wells4 and coalbed
methane wells,5 and producer facilities west of the 98th meridian,6 discharges of pollutants
from produced water to surface waters are prohibited. In addition, discharges from
centralized waste treatment (CWT) facilities that accept produced water are regulated
under ELGs found at 40 CFR part 437. 40 CFR part 437 provides for discharge to surface
waters and contains numerical limitations for such discharges.
The characteristics, quantity and quality of the wastes generated during oil and gas
exploration and production (E&P) activities depend upon factors such as the
characteristics of the formation, the type of drilling employed, the depth of the well and the
type and quantity of chemical additives used during drilling, production and well
maintenance and stimulation activities. Solid wastes such as drill cuttings are typically
managed through landfilling or on-site disposal. Some produced water is reused within the
oil field for enhanced oil recovery or for hydraulic fracturing. Produced water that is not
reused has historically been managed as a waste via Class I and II underground injection
control (UIC) disposal wells under the Safe Drinking Water Act (SDWA) or disposal in on-
site evaporation or seepage pits. While management via UIC disposal wells continues to be
the predominant management approach for disposal of produced water in the United
States, produced water is increasingly being recycled and reused within the oil and gas
field for hydraulic fracturing activities. While opportunities exist to recycle/reuse produced
water outside of the oilfield, this management approach is rare. Some produced water is
currently used for irrigation of crops. Road spreading of produced water for dust and ice
control is also occurring in some states. Off-site CWT facilities are also used to manage
these wastewaters. In addition, some produced water is managed at publicly-owned
treatment works (POTWs7).
Currently, discharge of oil and gas extraction wastewaters to surface waters is
occurring in limited geographic areas of the country. Discharges west of the 98th meridian
for agriculture and wildlife propagation are occurring primarily in Wyoming; these
produced waters generally receive limited treatment in most cases, consisting primarily of
settling and/or skimming. Indirect discharge via POTWs is primarily occurring in
Pennsylvania; these produced waters receive limited or no treatment prior to transfer to
4 See 40 CFR 435 Subpart F
5 See 40 CFR 435 Subpart H
6 See 40 CFR 435 Subpart E (44 FR 22075).
7 The discharge of pollutants from unconventional oil and gas extraction activities to POTWs is prohibited (40
CFR Part 435.33 and 435.34).
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Section 1 -Executive Summary
the POTW. Discharge via CWT facilities are occurring primarily in the Marcellus and Utica
shale areas of Pennsylvania, Ohio and West Virginia; these wastewaters receive varying
levels of treatment, ranging from simple physical/chemical treatment to advanced
treatment utilizing membranes or distillation.
Representatives of state agencies that the EPA engaged for this study generally
supported increasing opportunities for management of oil and gas wastewaters including
discharge of oil and gas extraction and production wastewater. Reasons include providing
additional flexibility for producers, opportunities to address water scarcity concerns and to
provide additional water for agriculture. Representatives of some agencies raised concerns
regarding the treatability of produced waters and the unknown human health and
ecological risks that might occur. Such risk is primarily a function of the unknown
chemistry of many produced waters. In addition, management of treatment residuals,
particularly the salts and radioactive material that would be generated, were identified as
concerns.
Representatives of tribes generally expressed concern about increasing
opportunities for discharge, however some tribal representatives supported discharge to
address water scarcity and to allow for continued resource development on tribal lands.
Those who expressed concern raised issues about the unknown chemistry of produced
waters and the impacts to surface waters which have important cultural uses.
Nationally, there is broad support amongst the oil and natural gas industry and its
service providers for additional wastewater management options including to treat and
discharge produced waters more broadly. However, support is not universal as some oil
and natural gas companies are satisfied with the current regulatory structure and others
perceive potential liability concerns associated with alternatives such as discharge. While
discharge west of the 98th meridian is currently an option for oil and natural gas producers,
use of the beneficial reuse provision under Subpart E outside of the State of Wyoming is
rare. Based on information provided in this study, this is primarily due to the availability of
other wastewater management options that are lower cost, such as reuse within the oil and
gas field or disposal in Class II UIC wells, as well as the cost associated with treating
produced waters to a level suitable for discharge. Industry indicated that unless the
produced water has total dissolved solids concentrations generally of less than a few
thousand milligrams per liter, treatment using membranes (e.g., reverse osmosis) or
distillation would be necessary to generate water that is suitable for agricultural uses or for
discharge to surface waters. The cost of such treatment is not currently competitive where
other wastewater management options are available. However, treatment for discharge
may be cost-competitive where other options are limited. For example, producers indicated
that in some areas of Pennsylvania treatment for discharge would currently be cost-
competitive with other available wastewater management options. This is primarily driven
by the cost for trucking produced water to other management or disposal options.
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Section 1 -Executive Summary
Some environmental NGOs expressed opposition to, and raised concerns about,
expanding options for discharge of produced waters. They also expressed concern about
current available options for discharge. Concerns raised relate to the unknown nature of
produced water chemistry, documented problems from discharges that are currently
occurring or that have occurred in the past, the current limited treatment for some current
discharges of produced water and the toxicity of produced water and its constituents.
Other NGOs (and associations of state regulators) see potential benefits related to water
availability associated with increased opportunities for discharge of treated produced
waters. In addition, some are supportive of additional discharge options, seeing
opportunities to generate revenue from the treated produced water and to facilitate
growth in oil and gas extraction.
Those in academia that the EPA engaged identified concerns related to the unknown
chemistry of produced waters and the limited amount of data regarding treatability of
produced waters. These concerns include the risk to human health or environmental
implications of discharge. Some in academia stressed the need for additional research into
these topics, noting that some studies are currently underway. Some also saw the potential
for reducing the cost and improving the performance of treatment technologies that could
make treatment for discharge more cost-competitive with other management options.
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Section 2-Study Scope and Goals
2. Study Scope and Goals
Recent advances in oil and gas 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). Production from shale gas and tight oil
resource areas is projected to grow through 2050 because of the large size of the
associated resources, according to the U.S. Energy Information Administration's Annual
Energy Outlook 2018 (U.S. DOE, 2018). The rise in the number of oil and gas wells has also
led to the generation of large volumes of produced water. As an example, in 2017, oil and
natural gas production in New Mexico produced 37.8 billion gallons of produced water
according to the New Mexico Energy, Minerals and Natural Resources Department.
Nationally, the Ground Water Protection Council estimates in their 2019 Produced Water
Report that produced water generation in 2012 was 890 billion gallons. In some areas,
produced water generation is increasing. Data in the report Sustainable Produced Water
Policy, Regulatory Framework, and Management in the Texas Oil and Natural Gas Industry:
2019 and Beyond (Texas Alliance of Energy Producers and IPAA) estimates that in 2017 the
total volume of produced water generated in Texas was more than 357 billion gallons, and
estimates that volume increasing to over 630 billion gallons per year by 2023. As explained
in the Executive Summary, currently most of this wastewater is managed by disposing of it
in a practice known as deep underground injection, where that wastewater can generally
no longer be accessed or reused. Representatives of some states and stakeholders are
asking whether it makes sense to continue to treat produced water as a waste or rather
look at the produced water as a potential resource. This may be particularly important as
forty out of fifty State water managers expect freshwater shortages to occur in their states
in the next ten years.8
In spring of 2018, the EPA embarked on this study to better understand produced
water generation, management, and disposal options at the regional, state and local levels
for both conventional and unconventional onshore oil and gas extraction. The EPA's study
goal was to evaluate approaches to manage oil and gas extraction wastewaters generated
at onshore facilities, including but not limited to an assessment of technologies for facilities
that treat and discharge oil and gas extraction wastewaters to surface waters. A second
goal was to understand any potential need for, and any concerns over, additional discharge
options for onshore oil and gas wastewater. To do so, as described in Section 4, the EPA
engaged with representatives of state agencies that are responsible for oil and gas
permitting and water and waste management, tribes, industry, academia, environmental
groups, and other stakeholders to solicit information from their individual perspectives on
topics surrounding produced water management.
8 Government Accountability Office [GAO] 2014. Freshwater: Supply Concerns Continue and Uncertainties
Complicate Planning. GAO-14-430.
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Section 2-Study Scope and Goals
This report details the information obtained during the EPA's outreach to
stakeholders on these topics. The information in this report will help the EPA determine
whether any future actions by EPA are appropriate to further address oil and gas
extraction wastewater.
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Section 3-Background
3. Background
3.1 Produced Water Characteristics
Oil and gas exploration and production (E&P) activities generate a variety of waste
materials requiring management. These waste materials include produced waters, spent
drilling fluids, used drilling muds and drill cuttings. Produced water is the largest
wastewater source by volume generated during oil and gas extraction. 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.
The ratio of produced water to hydrocarbon recovered in oil and gas extraction in the U.S.
can vary greatly across different formations. For example, stakeholders reported ratios of
produced water to oil ranging from less than 1:1 to more than 100:1. Naturally occurring
constituents include, but are not limited to, bromide, calcium, chloride, magnesium, sulfate,
and radioactive materials. Materials added downhole include hydraulic fracturing
chemicals, well stimulation chemicals and well maintenance chemicals. Over time, the
characteristics and volume of produced water generated for a well can change. In addition,
periodic well maintenance and stimulation activities can affect produced water
characteristics and generation rates.
The purpose, quantity and characteristics of materials utilized during well
development, stimulation and maintenance are diverse. For example, the EPA identified
some 692 unique ingredients reported for additives, base fluids and proppants contained
in more than 39,000 FracFocus9 disclosures provided by the Ground Water Protection
Council (GWPC) (U.S. EPA, 2015). Table 3-1 describes the types and purposes of some
additives used in well development, stimulation and well maintenance activities.
There are many sources of produced water characterization data available. A source
that the EPA identified is the USGS National Produced Waters Geochemical Database (USGS
database), containing geochemical data for produced water and other deep formation
waters from wells in the United States (USGS, 2014). The USGS database is periodically
updated (for example, Version 2.1 includes data for almost 60,000 wells in 36 states,
sampled between 1900 and 2012). Data for select parameters from Version 2.2 of the USGS
database are shown in Figure 3-1 as box and whisker plots, showing the minimum
(excluding non-detect values), 25th percentile, median, 75th percentile and maximum values
for each parameter.10 As illustrated in Figure 3-1, the concentration of these select
9 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.
10 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.
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Section 3-Background
parameters varies greatly. Another source of data and information is the June 2019 GWPC
Produced Water Report, that examines current regulations, practices, and research needed
to expand the use of produced water as a resource. A more complete discussion of
produced water characteristics can be found in U.S. EPA, 2016; U.S. EPA, 2016b; and U.S.
EPA, 2018.
Table 3-1. Type and Purpose of Additives used in Well Development, Stimulation
and Maintenance
Ciitofjorv of
Additive •'
lAiimple
Constituents h
I'lirposo
Acid
Hydrochloric acid;
muriatic acid
Removes cement and drilling fluid from casing perforations prior to
fracturing fluid injection.
Biocide
Glutaraldehyde;
2,2-dibromo-3-
nitrilopropionamide
Inhibits growth of organisms that could produce gases (particularly
hydrogen sulfide) that could contaminate methane gas; prevents the
growth of bacteria that can reduce the ability of the fluid to carry
proppant into the fractures by breaking down the gelling agent.
Breaker
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
Acetaldehyde; formic
acid
Reduces rust formation on steel tubing, well casings, tools, and tanks.
Crosslinker
Borate salts;
potassium hydroxide
Increases fluid viscosity to allow the fluid to carry more proppant
into the fractures.
Friction
Reducer
Polyacrylamide
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 fractures created in the formation, 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
Ethoxylated glycols;
alcohol ethoxylates
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.
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Section 3-Background
Figure 3-1. Concentration of Select Constituents in Oil and Gas Produced Water
(USGS National Produced Waters Geochemical Database, V2.2)
Produced Water Constituent Concentrations
100000
10000
100
10
0.1
0.01
Barium Boron Bromide HEM MBAS Ra226 + 228 Strontium TOC
(18,387) (2,419) (5,283) (111) (97) (190) (7,615) (375)
[11,369] [2,180] [4,875] [92] [89] [184] [6,969] [368]
Sulfate TDS Chloride
(100,066) (96,427) (105,903)
[93,056] [96,421] [105,816]
Note: For each constituent, the total number of samples are shown in parentheses and the number of samples
with values greater than the detection limit are shown in brackets (for example, there were 18,387 samples
for barium, 11,369 of which were greater than the detection limit).
3.2 Management of Produced Waters
Figure 3-2 depicts produced water management options. The predominant disposal
option for produced waters is use of Class II UIC wells (identified as injection in Figure 3-2).
These wells are regulated under the Safe Drinking Water Act (SDWA). Disposal wells are
prevalent in most oil and gas producing areas of the country. Some produced waters are
also used for practices such as enhanced oil recovery11 or to recharge aquifers, which is
generally also subject to UIC regulation under the SDWA.
Some produced waters are managed on-site or within the oil and gas field using
evaporation ponds or seepage pits. Recycling and reuse of produced waters for exploration
and production operations within the oil and gas field is another primary means of
produced water management. Some treatment may be required to render the water
suitable for reuse in hydraulic fracturing. Another management strategy is the use of
produced water for dust suppression and deicing, though some states are looking more
closely at this practice and restricting or removing this as an option. These management
11 Enhanced oil recovery is generally subject to Class II UIC regulation (40 CFR 144.6(b)(2). However, the
injection of fluids for hydraulic fracturing is exempt from regulation under the SDWA, except where diesel
fuels are used. SDWA section 1421 (d) (1) (B) (ii).
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Section 3-Background
approaches are not subject to CWA NPDES permitting requirements if they do not
discharge to surface waters.12
Figure 3-2. Produced Water Management Options
Treatment
Via Pipeline
rrr= -m
Produced
Water
(Single
Operator)
reated
water
Via I ruck
Produced V|a P>pe"ne ^
Via Truck
Water
(Multiple
Operators)
Re-use/Recycle Water Within the
Oil and Natural Gas Industry
Surface Water Discharges
Industrial Use/Commercial Sales
Outside the Oil and Natural Gas
Industry
Agricultural Uses
Municipal Uses
Subsurface Discharges for
Groundwater Management
Currently in limited instances produced waters are used for irrigation of crops. This
practice currently occurs primarily in California, although limited use has occurred in other
states. In California, produced waters are used for irrigation of a variety of crops, including
those for human consumption. Use in agriculture that does not involve discharge to surface
waters does not require a CWA NPDES permit.
Discharge of produced waters to surface waters is currently allowed west of the 98th
meridian under Subpart E of 40 CFR 435, and this is occurring primarily in Wyoming. Also,
discharges from stripper wells and coalbed methane extraction under Subpart F and
Subpart H of 40 CFR part 435, respectively, are allowed, with requirements for these
discharges developed on a case by case basis by the permitting authority.13 Subpart E, F
and H discharges to surface waters require NPDES permits (see additional information
below). In addition, producers can transfer produced water from some types of wells to
12 The U.S. EPA authorities discussed in this paper are not the only statutory and regulatory authorities that
may be implicated when produced water is re-used, recycled, treated or discharged. For example, the disposal
of RCRA non-hazardous waste is generally subject to EPA RCRA standards in 40 CFR 257 or 258. In addition
to federal regulations many state laws and regulations may apply.
13 Discharges of wastewater from coalbed methane and stripper wells are not within the scope of this study.
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Section 3-Background
POTWs for management and subsequent discharge. However, discharge of pollutants from
unconventional wells to POTWs is prohibited (40 CFR part 435.33 and 435.34).
Another option for management of produced waters is transfer off-site for
management. Options include transfer to another industry or municipality for use (for
example, for cooling water) or transfer to off-site CWT facilities. While transfer off-site for
other uses is currently not widespread, the practice of transferring produced waters off-
site to a CWT facility does commonly occur in the Marcellus Shale producing areas
including Pennsylvania, Ohio and West Virginia. CWT facilities that discharge to surface
water are subject to EPA's CWT ELGs in 40 CFR part 437.
3.3 The EPA's Clean Water Act Regulations for Produced Water
The CWA establishes the basic structure for regulating discharges into surface
waters. Under the CWA, it is unlawful to discharge any pollutant from a point source into
surface waters except as authorized by a NPDES permit (see CWA sections 301 and 402) or
by certain other specified statutory provisions. The NPDES program aims to protect and
restore the quality of water bodies (e.g., rivers, lakes and coastal waters) through permit
requirements by monitoring and controlling pollutants discharged from point sources. The
EPA's NPDES permit regulations require permittees to report compliance with NPDES
permit limits via periodic Discharge Monitoring Reports (DMR) submitted to the
permitting authority. A NPDES permit must include any applicable technology-based
effluent limitations (TBELS) and, if there is a reasonable potential to cause or contribute to
an instream excursion above applicable water quality standards, additional water quality-
based effluent limitations (WQBELS). Currently forty-seven states are authorized to issue
NPDES permits; however as of December 2018, the EPA issues NPDES permits for onshore
oil and gas extraction activities in six states (Idaho, Massachusetts, New Hampshire, New
Mexico, Oklahoma and Texas) as well as certain territories and tribal lands.
3.3.1 Technology-Based Effluent Limitations
ELGs are generally the source of technology-based
effluent limitations. ELGs are national wastewater discharge
standards that are developed by the EPA on an industry-by-
industiy 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 the EPA regional offices, and standards for
indirect dischargers directly apply and may be incorporated
into permits or other control mechanisms issued by
pretreatment authorities. Where the EPA has not established
ELGs for direct dischargers in a particular industry, permitting authorities develop permit-
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).
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Section 3-Background
specific technology-based requirements according to their best professional judgement
(BPJ).
When developing ELGs, the 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 the 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
nonconventional pollutants).
The direct discharge pollution control guidelines that
are developed by the EPA in ELGs include: best practicable
control technology currently available (BPT), best conventional
pollutant control technology (BCT), best available technology
economically achievable (BAT), and best available
demonstrated control technology for new sources, or new
source performance standards (NSPS). The analogous indirect
discharge pollution control standards that are developed by
the EPA in ELGs are pretreatment standards for existing
sources (PSES) and pretreatment standards for new sources
(PSNS). Table 3-2 illustrates the types of dischargers and the
different levels of control in ELGs and Table 3-3 illustrates the classes of pollutants
addressed by different levels of control in ELGs.
Table 3-2. Applicability of Effluent Guidelines Levels of Control to Types of
Discharger
'I'ypo of Disclmifjor Ue^ukited
hi»t
HCT
HAT
NSI'S
i'si:s
I'SNS
Exisling Dirccl Dischargers
•
•
•
New Direct Dischargers
•
Existing Indirect Dischargers
•
New Indirect Dischargers
•
Table 3-3. Pollutant Classes Regulated by Effluent Guidelines Levels of Control
Pollutants Ue^ukitod
hi»t
HCT
HAT
NSI'S
i'si:s
I'SNS
Priority Pollutants
•
•
•
•
•
Conventional Pollutants
•
•
•
Nonconventional Pollutants
•
•
•
•
•
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.
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Section 3-Background
Discharges from oil and gas extraction facilities are subject to ELGs at 40 CFR Part
435. These regulations are subcategorized (e.g., 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
Typo ofDisclmr^or Uc^ukited
IJPT
UCT
HAT
NSPS
PSI-S
PSNS
Offshore Subcategory
•
•
•
•
Onshore Subcategory a
•
•
•
Coastal Subcategory
•
•
•
•
•
•
a 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.
Waste streams addressed by the guidelines for 40 CFR Part 435 for the onshore
category include:
• Drill cuttings, which are the particles generated by drilling into subsurface geologic
formations and carried out from the wellbore with the drilling fluid.
• Drilling fluid or mud, which are the circulating fluid used in the rotary drilling of wells
to clean and condition the hole and to counterbalance formation pressure.
• Produced sand, which are the slurried particles used in hydraulic fracturing, the
accumulated formation sands, and scales particles generated during production.
Produced sand also includes desander discharge from the produced water waste
stream, and blowdown of the water phase from the produced water treating system.
• Produced water, which are the fluids brought up from the hydrocarbon-bearing strata
during the extraction of oil and gas, and includes, where present, formation water,
injection water, and any chemicals added downhole or during the oil/water separation
process.
The oil and gas extraction effluent guidelines also contain several subparts,
applicable to production activities in different locations and/or to different types of wells.
Table 3-5 provides additional details on the applicability and limitations contained in these
subparts. Offshore and coastal facilities are not part of the scope of this study.
The onshore category under Subpart C prohibits the direct discharge of pollutants
from oil and gas extraction facilities and prohibits the indirect discharge of pollutants from
unconventional wells to POTWs. This is called a zero discharge of pollutants standard.
However, onshore producers can currently discharge produced water under Subpart E for
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Section 3-Background
facilities located west of the 98th meridian (see Figure 3-3). In addition, there are currently
no national pretreatment standards for discharges to POTWs for wells that do not meet the
EPA's definition of unconventional (see 40 CFR 435.33 and 435.34).
Table 3-5. Subparts of 40 CFR Part 435 and their Applicability and Limitations
Subpart
Title
Applicability
Description
A
Offshore
Subcategory14
Facilities located in waters that are
seaward of the inner boundary of
the territorial seas as defined in
502(g) of the CWA.
BPT, BAT, BCT and NSPS regulations
require numeric limits for some
wastestreams in certain locations. For
other wastestreams in certain locations,
the rule requires zero discharge.
C
Onshore
Subcategory
Facilities located landward of the
inner boundary of the territorial
seas as defined in 40 CFR 125.1(gg)
and which are not included within
subparts D, E, or F
BPT regulations require zero discharge of
produced water for direct dischargers.
PSES and PSNS regulations require zero
discharge for unconventional oil and gas
extraction facilities.
D
Coastal15
Subcategory
Facilities located in or on a water of
the United States landward of the
inner boundary of the territorial
seas (40 CFR 435.40(a), or as
defined at 40 CFR 435.40(b)(1)
BAT regulations require zero discharge
(except for Cook Inlet) and PSES
regulations require zero discharge.
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.
Requires no discharge of wastewater
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, and
must be "of good enough quality" for
wildlife or agricultural use.
F
Stripper16
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.
Contains no ELG-based limitations.
Technology-based limitations are
developed on a case-by-case basis in an
individual or in a state-wide general
permit using BPJ.
H
Coalbed
Methane17
Subcategory
Facilities engaged on extraction of
Coalbed Methane
Contains no ELG-based limitations.
Technology-based limitations are
developed on a case-by-case basis in an
individual or in a state-wide general
permit using BPJ.
. Mote: Subpart B is reserved. Subpart G requirements prevent moving effluent produced in one subcategory to
another subcategory for disposal under less stringent requirements.
14 Not included in the scope of this study.
15 Not included in the scope of this study.
16 Not included in the scope of this study
17 Not included in the scope of this study
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Section 3-Background
Figure 3-3. Map of 98th Meridian*
Calgary
Vancouver
o
Seattle
o 0°
C-
•z-
-A
"s>
(f
San Francisco
o A
•qL - i \
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Section 3-Background
A 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. The 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."
The 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, 2011c,
2011d). In the FAQs, the 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 are not legally binding, they provide information that may be
useful to permitting authorities to help inform decisions on what constitutes off-site in the
context of Marcellus shale gas extraction activities.
3.3.2 Water Quality-Based Effluent Limitations
WQBELS are the second main component of NPDES permits. When drafting a NPDES
permit, a permit writer must consider the impact of the proposed discharge on the quality
of the receiving water. Water quality goals for a waterbody are defined by state water
quality standards. By analyzing the effect of a discharge on the receiving water, a permit
writer could find that technology-based effluent limitations alone will not be sufficient to
meet the applicable water quality standards. In such cases, the CWA and its implementing
regulations require development of WQBELs. WQBELs help meet the CWA objective of
restoring and maintaining the chemical, physical, and biological integrity of the nation's
waters and help to ensure attainment of the designated uses of waters established by the
state which include the protection and propagation of fish, shellfish and wildlife, and
recreation in and on the water [fishable/swimmable).
WQBELs are designed to protect water quality by ensuring that water quality
standards are met in the receiving water. When TBELS based on the requirements of 40
CFR 125.3(a) are not sufficient to meet water quality standards, additional or more
stringent effluent limitations and conditions, such as WQBELs, are included in NPDES
permits.
CWA section 301(b)(1)(C) requires that permits include any effluent limitations
necessary to meet water quality standards. To satisfy that requirement, permit writers
evaluate effluents to determine if pollutants in the effluent would cause, have the
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Section 3-Background
reasonable potential to cause, or contribute to the excursion of water quality criteria
adopted in a state's water quality standards, even after attainment of a TBEL (40 CFR
122.44(d)(l)(i)). Where such "reasonable potential" is found, the permit writer must
include a WQBEL for such pollutant(s). After completing that process, the permit writer
determines the final effluent limitations, includes any compliance schedules and interim
effluent limitations, as appropriate, and documents all his or her decisions and calculations
in the fact sheet or statement of basis of the permit.
In the context of discharges of oil and gas extraction wastewaters, permit writers
would consider the applicable TBELs contained in either the oil and gas extraction or CWT
ELGs, or BPJ-based TBELS for subcategories not subject to limitations in the ELGs, and any
applicable state or tribal water quality standards. Since the existing CWT ELGs and Subpart
E Oil and Gas ELGs do not contain limitations for many pollutants that can be found in
produced waters, additional or more-stringent WQBELs may apply to such discharges.
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Section 4-The EPA's Outreach to Stakeholders
4. The EPA's Outreach to Stakeholders
In support of the goal of the study, the EPA conducted outreach with a variety of
stakeholders across the country to better understand produced water management
practices and challenges. This outreach included in-person meetings, as well as conference
calls and webinars. During these discussions, the EPA discussed with a wide range of
stakeholders their experiences with produced water management. The goal of these
discussions was to better understand produced water generation, management, and
disposal options at the regional, state and local levels. Participants shared their individual
perspectives on several topical areas, including:
• Produced water management - the pros and cons with the status quo.
• Produced water management alternative options such as treatment technologies,
availability of alternatives and drivers for alternative management practices.
• Current or future produced water management barriers to alternatives.
• Concerns related to federal regulations that allow, in some instances, for the
discharge of treated produced water to surface waters or to municipal wastewater
treatment.
• Challenges to developing permit limits for facilities that treat and discharge
produced waters.
• Appropriate level of treatment required for produced waters that would be
discharged to surface waters or Publicly Owned Treatment Works (POTWs).
• Existing state regulations and requirements that conflict with a different federal
approach to produced water management (e.g., water rights).
The EPA also held a public meeting on October 9, 2018 to report on what it had
learned to date and provide stakeholders the opportunity to provide additional individual
input.18 The EPA engaged with the stakeholders identified in Table 4-1 during the study. A
summary of the information gleaned from these discussions, organized by category of
entity, follows. The summaries present the individual thoughts and opinions of the
participants in the various meetings, and do not necessarily represent the official positions
of the entities identified in Table 4-1. The EPA has not verified the accuracy of the
information provided by stakeholders, nor has the Agency provided any interpretation or
opinions regarding the information received.
18 To view EPA's presentation, see: https: //www.epa.gov/eg/oil-and-gas-extraction-wastewater-
management-studv-documents.
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Section 4-The EPA's Outreach to Stakeholders
Table 4-1. List of Engagement Activities in 2018
Month
Culls/Mooti iifp»
April, 2018
New Mexico, Office of the State Engineer (4/24)
New Mexico, Energy, Mineral and Natural Resources Dept. (4/24)
New Mexico Environment Department (4/24)
New Mexico Oil and Gas Association (4/25)
May, 2018
Interstate Oil and Gas Compact Commission (IOGCC) (5/8)
Texas Commission on Environmental Quality (CEQ) (5/11)
American Exploration and Production Council (5/15)
American Petroleum Institute (API) Upstream Group and Independent Petroleum
Association of America (5/15)
Department of Energy (DOE), Office of Oil and Natural Gas (5/15)
Louisiana Department of Environmental Quality (5/18)
Groundwater Protection Council (GWPC) (5/18)
Western States Land Commissioners Association (5/21)
EPA Region 8 states, including Colorado, Wyoming, North Dakota state agencies (5/21)
EPA Region 8 Academia - Colorado State University, Colorado School of Mines, Berkeley,
University of Wyoming (5/21)
Western Energy Alliance (5/22)
EPA Region 8 Environmental NGO Stakeholders (5/22)
Clean Water Action (5/23)
Natural Resource Defense Council (5/23)
Texas Water Board (5/24)
California Water Boards (5/24)
June, 2018
National Tribal Water Council Meeting (6/6)
Texas Oil and Gas Association (6/19)
Environmental Defense Fund (6/19)
Texas Independent Producers and Royalty Owners Association (6/19)
Gulf Coast Authority (6/20)
Environmental NGOs (6/20)
Texas Water Development Board; Texas CEQ; Texas Railroad Commission (6/20)
Environmental Council of States (6/20)
Texas Alliance of Energy Producers (6/21)
Texas Bureau of Economic Geology (6/21)
Jicarilla Apache Nation (6/26)
EPA Tribal Program Managers Update Call (6/28)
July, 2018
Western States Land Commissioners Association meeting in Duluth, MN (7/8-12)
Region 1 Regional Tribal Operations Committee (Tribal) Call (7/11)
National Tribal Water Council Update (Tribal) Call (7/11)
Region 6 Regional Tribal Operations Committee (Tribal) Call (7/11)
Texas General Land Office (7/17)
Bureau of Land Management (7/18)
PolyCera (7/18)
Region 9 Regional Tribal Operations Committee (Tribal) Call (7/18)
Tasman Geosciences (7/19)
The Pacific Institute, Clean Water Action, Environmental Working Group (7/23)
California Independent Petroleum Association (7/23)
Western States Petroleum Association (7/23)
California Water Quality Boards and California EPA (7/24)
University of California Berkeley, and Lawrence Berkeley National Laboratory (7/24)
California Division of Oil, Gas, and Geothermal Resources (7/25)
Site Visits Chevron San Ardo, Sentinel Peak Arroyo Grande, Chevron Kern River (7/25 -
7/26)
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Section 4-The EPA's Outreach to Stakeholders
Table 4-1. List of Engagement Activities in 2018
Month
Culls/Mooti iifp»
Region 8 Regional Tribal Operations Committee (Tribal) Call (7/25)
Albaron (7/30)
August, 2018
Region 4 Regional Tribal Operations Committee (Tribal) Call (8/01)
University of New Mexico (8/2)
Produced Water Society (8/6)
Wilsa Holdings (8/8)
National Tribal Water Council Update (Tribal) Call (8/8)
SOURCEWATER (8/14)
University of Oklahoma and Oklahoma State University (8/21)
Oklahoma Oil and Gas Association, Oklahoma Independent Petroleum Association and
Industry Stakeholders (8/21)
Exxon Research and Development (8/22)
Ground Water Protection Council, National Rural Water Association, OK Rural Water
Association, State Review of Oil and Natural Gas Environmental Regulations (8/22)
Interstate Oil and Gas Compact Commission (8/23)
Oklahoma Water Resources Board, Corporation Commission, Department of
Environmental Quality, Department of Agriculture, Food and Forestry (8/23)
Region 7 Regional Tribal Operations Committee (Tribal) Call (8/23)
Health Effects Institute (8/30)
September, 2018
TX Alliance of Energy Producers (9/4)
Groundwater Protection Council - New Orleans (9/10-13)
Exxon (9/21)
Eureka Resources (9/21)
Pennsylvania Academia (Penn State, University of Pittsburgh) (9/25)
United States Department of Energy National Energy Technology Laboratory (9/25)
Pennsylvania Department of Environmental Protection (9/26)
Pennsylvania Grade Crude Oil Coalition, Pennsylvania Independent Petroleum Producers
Association, Pennsylvania Independent Oil and Gas Association, Marcellus Shale Coalition
(9/26)
Pennsylvania Crude Development Advisory Council (9/27)
October, 2018
American Petroleum Institute (10/3)
Utah Division of Water Quality (10/4)
October 9 Public Meeting in DC
United States Department of Energy and Sandia National Laboratories (10/15)
Wind River (Northern Arapaho) Tribe (10/15)
Wind River (Eastern Shoshone) Tribe (10/17)
November, 2018
NALCO (11/8)
4.1 Major Themes from State Agencies
Meetings with states included representatives from agencies responsible for NPDES
permitting, oil and gas permitting, wastewater management, and other aspects of produced
water management. The EPA also met with users of water, such as state agriculture
departments. The EPA did not meet with agencies from every state, but instead focused
efforts on those states with significant oil and gas E&P activities and produced water
generation. Some states currently issue permits for produced water discharges (for
example, west of the 98th meridian); others do not.
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Section 4-The EPA's Outreach to Stakeholders
Some state agency representatives were supportive of additional discharge options
for treated produced water. The reasons identified were varied. One primary theme was
that treated produced water could be an additional source of water to augment surface and
groundwater supplies. Some states with significant oil and gas extraction activity are also
arid or semi-arid where water scarcity is a current and growing problem. If produced
water could be treated to a level suitable for discharge, these state agency representatives
see this as a benefit. Potential downstream users of the water that were identified include
agriculture, municipalities and industry. In addition to providing water to downstream
users, state agency representatives indicated that discharge of treated produced water
could help meet downstream water allocations and interstate water compacts. The concept
of re-branding produced water from a waste product requiring management to a potential
valuable resource was a common theme.
Some state agency representatives noted that the oil and gas industry can be a
significant user of fresh water in certain areas, given that water is often required for
drilling and hydraulic fracturing activities. In many cases, industry relies on withdrawal
from surface water or groundwater supplies to obtain needed water. After use in E&P
activities, this water may be reused within the oil and gas field, but in many cases, is
ultimately disposed of in Class II UIC wells where it is no longer part of the water cycle.
State agency representatives indicated that treating this water for discharge and
reintroduction to the water cycle would help to preserve or augment freshwater supplies.
On a related note, representatives of one state agency indicated that there has been
discussion of recovering water injected into Class II UIC disposal wells for reuse within oil
and gas operations; this could reduce freshwater imports into the oil and gas sector.
State agency representatives also indicated that allowing producers to treat and
discharge produced water closer to where it is generated would reduce the need for
transport via trucks or pipelines. Transport of produced water can be costly and brings
with it the risks of spills or illicit discharge. In addition, truck traffic can damage roads and
increase the risk of traffic accidents and associated injuries and fatalities. Also, truck traffic
can be disruptive to those located along trucking routes. State agency representatives
indicated that reducing trucking could provide benefits to air quality as well due to reduced
emissions.
In states where water rights and water allocation law are established, there were
questions about who would own produced water that is treated for discharge.
Representatives of some state agencies indicated that there has been or is ongoing work to
clarify ownership and water rights for discharged produced water, while others indicated
that this question has yet to be addressed. Regardless of ownership, selling or obtaining
royalties from discharge of treated produced water was identified as another potential
benefit, as someone (either the state, a landowner, industry or some other entity) would
own the water and therefore could benefit financially from selling the water and any
mineral co-products extracted from the water.
Representatives of some state agencies indicated that there are existing and
emerging constraints on Class II UIC disposal well capacity due to over-pressurization of
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Section 4-The EPA's Outreach to Stakeholders
receiving formations which can lead to induced seismicity. This was particularly of note in
areas of the Permian basin in New Mexico and Texas. Also, in discussions with some state
agencies induced seismicity was identified as a constraint. However, these concerns were
not limited to just those states. Representatives of some state agencies were keenly
concerned about the capacity of formations being used for disposal to meet the future
demand, particularly when factoring in projected increases in E&P activities. They noted
that where formation disposal capacity is insufficient to meet demand, other, perhaps more
costly, options would be needed. They were concerned that this could impact the ability of
producers to continue producing in certain areas, or at a minimum would increase their
costs which may reduce E&P activity. Implications to state royalty revenue, as well as
employment impacts, were identified as potential consequences. They indicated that
providing additional options for discharge of treated produced water could help to reduce
injection disposal capacity concerns in those areas, although potentially the costs could be
higher.
Some state agency representatives indicated that as existing disposal options
become more constrained, and as the cost of disposal increases, producers could abandon
wells. Identifying and plugging these wells could be a significant cost for the state. In
addition, they indicated that increasing disposal costs could increase the occurrence of
illegal dumping. Therefore, according to them, it would be desirable to maintain existing
management options, as well as to provide additional options.
Some state agency representatives were not supportive of providing additional
discharge options for treated produced waters. One reason identified was that existing
management options are sufficient. These options, including reuse within the oil and gas
field or disposal in Class II UIC disposal wells, were identified as widely available and
preferable to surface discharge. Also, representatives of one state agency indicated that
they did not support changes to the existing Subpart E beneficial reuse provisions but were
not opposed to expanding discharge options.
Some state agency representatives were concerned about the potential human
health and ecological implications of broader surface discharge and identified many
unknowns around produced water composition and treatability as primary reasons for this
concern. They indicated that little is known about produced water composition, due to the
variety of chemicals used by industry in fracturing, stimulation and well maintenance
activities. While producers are required to disclose the chemicals used in hydraulic
fracturing in some cases, some state agency representatives reported that these disclosures
are often incomplete due to the proprietary nature of formulations. They indicated that
many of these compounds have not been evaluated for human health and aquatic toxicity,
and treatability has not been determined. Also, downhole reactions and transformations
have not been assessed. In addition, formation water and E&P practices vary across
production areas and basins, further confounding evaluation of produced water
characteristics.
Some state agency representatives identified several impediments to additional
discharge of treated produced waters. A primary impediment identified was that the cost of
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Section 4-The EPA's Outreach to Stakeholders
treatment could be significantly greater than other management options. They noted that
in most areas, the nature of produced water would require extensive treatment to remove
constituents such as barium, technologically enhanced naturally occuring radioactive
material (TENORM), hardness, organics, and dissolved solids such as chlorides. Treatment
consisting of technologies including chemical precipitation, reverse osmosis, and thermal
evaporation were identified as necessary to generate discharge-quality water. Also,
treatment residuals such as concentrated brines, crystallized salts and sludges would
require management, which would add to costs. Management of TENORM-containing
sludges was identified as a particular challenge. Where produced waters contain radium, it
was described that treatment will concentrate radioactivity in sludges or other residuals.
Depending on the radioactivity of these materials, management options were identified as
being limited and costly. In addition, they noted the potential for release to the
environment through spills or through landfill leachate. Given the extensive treatment that
may be appropriate, as well as residuals management concerns, doubts were raised as to
whether treatment for discharge would be cost-competitive with other options such as
reuse within the oil and gas field or disposal in Class II UIC disposal wells. However, states
agency representatives did indicate that recovering valuable co-products, such as lithium
or rare-earth metals from the treatment residuals, could improve the economics of
treatment for discharge. They noted that this might spur growth of other industries that
can utilize these co-products, such as battery manufacturing.
Some state agency representatives reported that they lack technical expertise in
permitting discharges under the NPDES program and would look to the EPA to provide this
expertise. NPDES permits include both technology-based and water quality-based effluent
limitations, and they indicated that determining the water quality limitations could be
challenging since standards and criteria do not exist for many constituents in produced
water. In addition, they noted that production may occur in areas where receiving waters
are high quality and therefore it could be difficult for dischargers to meet stringent water
quality standards. In particular, meeting standards for chlorides in receiving waters was
identified as a potential challenge. Also, some state agency representatives indicated that
there are no surface waters in the vicinity of much E&P activities, so discharge to surface
waters would not be a viable option even if regulations allowed for it. They also indicated
that there would be a public perception challenge associated with allowing discharge to
surface waters.
Many state agency representatives indicated that the timeline required to obtain
NPDES permits could be an impediment to broader discharge. They indicated that
producers may desire the ability to discharge for a short-duration as the need arises,
perhaps at multiple locations within their operations. This is different than typical NPDES
dischargers which tend to be established facilities discharging long-term. Given the many
steps involved in issuing permits, they observed that producers may not be able to obtain
permits in the timeframe desired. They indicated that a general permit might be a good
option for this industry to address concerns over the time required to issue permits.
Another option would be for producers to utilize fixed CWT facilities that manage produced
waters from multiple production operations. This could be a commercial facility that
accepts produced waters from multiple operators, or a facility owned and operated
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Section 4-The EPA's Outreach to Stakeholders
exclusively by one producer for just their wells. State agency representatives indicated that
some producers are currently installing water management infrastructure to centralize
their water recycling operations, and that this may lead to construction of treatment plants
for discharge in the future. While issuing a permit to such a fixed facility may still require
considerable time, they indicated that such an option may be feasible. However, there were
questions about how to permit CWT facilities and what the governing ELGs would be,
particularly if such a facility treats only oil and gas extraction wastewater. There were
requests for the EPA to clarify this, and to revisit the definitions in the CWT ELGs to provide
more flexibility for oil and gas operations such as to allow a CWT facility to accept oil and
gas wastewater via pipeline. In some states, the EPA issues NPDES permits which means
the state has less control of the permit issuance process. State agency representatives
acknowledged that obtaining authorization from the EPA for the NPDES program, where
they do not already have it, would be an option, however they identified barriers to
delegation such as staffing and funding.
While state agency representatives indicated that reuse of produced water within
the oil and gas field is desirable, there are some existing state laws or regulations that can
interfere with reuse, particularly sharing water between producers. As a result, there is less
recycling occurring than could potentially occur. According to these state agency
representatives, changes to state legislation would be necessary to remove these barriers.
They also indicated that in some cases, land owners require producers to purchase
freshwater from them as part of the lease. If freshwater must be purchased, then there is
less incentive to reuse produced waters for E&P activities. Consequently, additional
produced water is generated that would subsequently require disposal. They indicated that
as the total volume of wastewater requiring disposal increases, additional management
options including discharge maybe desirable.
Some state agency representatives indicated that better data on produced water
generation, reuse and injection well utilization could help manage disposal well capacity
concerns. For example, they indicated that if some areas are becoming over-pressurized,
then remedial actions such as limiting the volumes that specific injection disposal wells can
accept could be implemented. They indicated that requiring injection disposal well
operators to report volumes of water accepted or well pressures at a greater frequency
could help with management of those wells. Additionally, requiring more reporting from
producers on produced water disposition was identified as an aid for management of
injection disposal wells.
4.2 Major Themes from Tribes
Some tribes were supportive of additional discharge options as this would allow for
continued development of oil and gas resources on tribal lands. However, they would want
the discharges to meet water quality standards and be protective of the environment. Some
tribes currently have discharges of produced water to water bodies located within tribal
lands, consistent with the beneficial reuse provisions of 40 CFR 435 Subpart E. Continued
discharge of this water is important for both economical as well as ecological and wildlife
considerations. Tribes would also be interested in identifying additional uses for treated
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Section 4-The EPA's Outreach to Stakeholders
produced water outside of agriculture and wildlife propagation, including direct use by the
tribe to supplement water supplies. However, they indicated that additional information on
the performance of treatment technologies, as well as financial assistance, would be
needed.
Other tribes were not supportive of additional discharge options for produced
water. These tribes indicated that they were concerned about the environmental and
human health implications of discharge. In addition, many surface waters have important
tribal uses such as fishing or ceremonial practices, and these tribes were concerned about
potential impacts to water quality that may affect those uses. There were also questions
about which specific water bodies would potentially be affected.
4.3 Major Themes from Oil and Gas Industry Members
Most in industry were supportive of additional discharge options for treated
produced water. The exception were some producers who were currently discharging
under the Subpart E beneficial reuse provisions, who did not see the need for additional
discharge options and did not support regulatory changes. Industry indicated that while
reuse of produced water within the oil and gas field is their preferred management option,
this is not feasible in some cases. Examples include when demand for reuse decreases as
drilling activity decreases or when produced water transportation costs make reuse not
cost-competitive with other water sources. Where reuse is not feasible, and where injection
disposal well capacity is limited, treatment followed by surface discharge may be viable if it
were a more widely available option. This includes treatment and discharge by CWT
facilities or discharge by industry themselves if regulations were changed to allow
discharge. Some in industry also indicated that indirect discharge via POTWs should
continue to be an available option and would prefer that the EPA establish non-zero
numerical pretreatment standards.
A common theme among discussions with industry representatives is that options
for produced water should be expanded. Those in the oil and gas extraction industry
pointed to other industries that are permitted to discharge wastewater and would like
there to be equity in this respect. An example given was petroleum refineries, which can
discharge wastewater yet the oil and gas extraction industry that supplies petroleum to the
refineries has limited discharge options. Some indicated that the technology is available to
treat produced water to a level that meets water quality standards designed to protect the
designated use. Industry representatives noted that this may not have been the case when
the oil and gas extraction ELGs were written, but treatment technology has changed since
then. They believe that the EPA can determine what technology is necessary to treat
produced water to be suitable for discharge, pointing to the EPA's 2018 CWT study.
Industry representatives indicated that technology on the production side has also
changed since the oil and gas extraction ELGs were written. An example is the continued
advances in horizontal and directional drilling. The volume of water used in drilling and
fracturing these wells is much greater than was previously used. Therefore, more produced
water is generated which presents management challenges. Also, some formations produce
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Section 4-The EPA's Outreach to Stakeholders
much greater quantities of water as compared to oil and gas. While drilling and well
development activities are taking place, there is a demand for reuse of produced water
within the oil and gas field. However, once resource areas become more developed the
water demand for E&P activities decreases. When this occurs, the amount of produced
water requiring disposal may increase. This may increase disposal costs, particularly if
insufficient injection disposal well capacity exists. Industry representatives indicated that
treating and discharging produced water should be an available option in these cases and
that treatment for discharge may be cost-competitive with other management options.
Also, there may be short-term or long-term slowdowns in drilling activity if commodity
prices decrease. The associated decrease in water demand could present water
management challenges that could be addressed via a surface water discharge option.
Industry representatives indicated that currently reuse within the oil and gas field
and disposal in Class II UIC wells are generally the least-cost methods of managing
produced water. In the near-term industry does not see this changing on a national scale.
Reuse is the preferred method of management and is utilized where possible. One major
operator stated that they would not support the use of treated produced water outside the
oilfield due to a lack of science around treatment efficacy and associated liability risks.
There are some impediments to reuse, including perceived liability as well as business
competition. In addition, existing state regulations were identified as barriers to reuse in
some areas. Where reuse is not available, disposal in Class II UIC disposal wells is
frequently utilized. Costs for injection disposal were reported to generally be less than $1
per barrel of produced water. In addition, disposal wells were reported to be plentiful in
most areas such that trucking or piping costs to these wells is low. As a comparison,
treatment for discharge may cost several dollars per barrel, and may be $10 or more per
barrel depending on the market and the level of treatment needed. According to industry,
even when considering potential reductions in transportation costs, treatment for
discharge would still cost more than injection disposal in most cases. However, industry
indicated that there are currently specific areas of the country where reuse and disposal
options are limited, and that treatment and discharge would be utilized if more discharge
options were available. A primary driver is the distances that produced water must be
transported to disposal options. Industry also indicated that there are specific areas of the
country (an example is the Permian Basin) where disposal at some injection wells is
limited, for example due to concerns over induced seismicity. In these cases, operators
have had to transport produced water greater distances for disposal. Industry is concerned
that as the quantity of produced water increases as production of oil and gas increases, that
injection disposal well capacity will be insufficient to meet demand. Also, industry noted
that regulatory agencies are reevaluating the suitability of some currently used injection
zones and may limit or prohibit injection in those areas in the future. Industry indicated
that as injection capacity decreases, other produced water management options would be
needed.
While use of CWT facilities is currently limited as they exist only in certain areas of
the country, producers indicated that they would use commercial facilities if they were
available and cost-competitive with other disposal options. Producers indicated that they
have discussed increasing CWT availability with vendors and water service companies.
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However, these companies frequently want long-term contracts with producers before
investing in treatment plants. Producers generally are reluctant to engage in such contracts
due to the potential for unknown market factors. Producers indicated that they would
prefer to have the ability to bring mobile treatment systems to the well sites when needed,
which would be less costly than trucking or piping wastewater to centralized treatment
facilities.
Industry representatives noted that treatment for discharge has benefits for
addressing water scarcity, since much oil and gas E&P activity occurs in arid or semi-arid
areas of the country. In these areas, surface water supplies can be sparse and treated
produced water could help augment these supplies. This water would also be available for
subsequent downstream uses, including by the oil and gas industry. Using receiving
streams as conveyance for treated produced water could reduce trucking or piping costs.
Industry representatives also indicated that discharging treated produced water
could be a potential revenue source, as downstream users may pay for the water. However,
this would depend on water rights and ownership of the water. Industry indicated that
ownership of the treated produced water is something that lacks clear definition in some
states. Industry also noted that there is the potential to recover valuable co-products from
treating produced water. As with water rights, ownership of the minerals that might be
extracted from produced waters is something that industry noted lacks clarity in some
states. There is the potential that royalties may need to be paid to the landowners for any
co-products extracted from treated produced water, but this is an issue that would be
settled under state law.
Industry representatives are concerned that the ability to economically manage
produced water may affect the economics of extracting oil and gas resources in some areas.
If the costs and regulatory burden for managing produced water are too high, certain areas
may not be developed. In addition, areas that are currently producing resources may need
to be prematurely shut-in if produced water management costs significantly increase.
Expanding the option for surface discharge could help the economics of such projects.
Like states, industry representatives identified the time required to obtain NPDES
permits as a potential impediment to broader surface water discharge. The timeline for
deciding whether or not to proceed with a given oil and gas extraction project, they pointed
out, is typically much shorter than the time it historically takes to develop, propose and
finalize an NPDES permit. Industry indicated that some states have experience writing
NPDES permits for oil and gas extraction facilities under 40 CFR 435 Subpart E, while other
states have not written permits for oil and gas extraction wastewater discharges. Also,
some states do not have delegation of all or part of the NPDES program. Industry indicated
that they would like to have the option to treat and discharge produced water at or near
the well site as the need arises and obtain authorization to discharge on a prompt timeline.
Given that NPDES permits may contain both technology-based and water quality-based
effluent limitations, there was concern over the ability to meet water quality standards in
certain areas where surface waters are of high quality. In addition, there was concern that
permits would not be obtained in a timely manner given that the need to discharge may be
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periodic and of short duration. Industry indicated that a general permit would be a
potential solution as this was viewed as being more flexible and perhaps coverage under a
general permit could be obtained more quickly than an individual permit. Industry also
indicated that were the EPA to revise its regulations to allow for broader surface discharge,
there are potential barriers at the state level to issuing NPDES permits that may be difficult
to overcome in some cases. Examples given were meeting water quality-based effluent
limitations and antidegradation requirements.
With respect to produced water characterization, producers noted that they disclose
much of the constituents used in hydraulic fracturing. While noting that some constituents
are proprietary, they indicated that in many cases it is the provider of the additive that
claims confidentially and not the producer. Thus, they can provide the name of the additive
but not the actual composition of the additive. They also noted that many of these
proprietary constituents are non-toxic and would not pose a risk to the environment if
discharged. However, they did note that some constituents can exhibit aquatic toxicity and
they work with service companies to reduce the toxicity of constituents they use. They also
indicated that treatment technologies are effective in removing the range of constituents
present in produced waters and that the level of treatment can be adjusted based on the
intended use of the treated produced waters.
4.4 Major Themes from Members of NGOs
The primary concern raised by NGO representatives was the potential toxicity and
human health and ecological implications of discharges of produced waters. This is due to
the large number of chemical compounds used in hydraulic fracturing, well maintenance
and other E&P activities. There are also constituents naturally present in producing
formations that are contained in the resulting produced water. NGO representatives
observed that many chemicals have little data on toxicity. In addition, they noted that
disclosure requirements may be incomplete and much of the data that is disclosed is
proprietary, further complicating assessment of toxicity and risk. They further noted that
the chemistry of produced water is constantly changing as new chemical formulations
enter the market and as advances in hydraulic fracturing occur, and that activities such as
well maintenance and stimulation may use different chemistries. Another concern was the
transformation of chemical constituents into other chemical compounds due to the high
temperature and pressures that may occur within the well. NGO representatives indicated
that little is known about these transformations and the toxicity of the transformation
products that may occur.
Some NGO representatives were also concerned that analytical methods do not exist
for many of the chemical compounds used in E&P activities. In addition, they indicated that
the high salinity of many produced waters can interfere with certain analytical approaches,
complicating quantification of constituents in produced water. They were concerned that
analytical shortcomings can complicate assessment of the human health and ecological risk
associated with discharges of produced water.
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Section 4-The EPA's Outreach to Stakeholders
Another concern was that only limited treatment technology performance data
exists for many compounds present in produced water. They were concerned that it would
be difficult to determine the appropriate treatment technologies, and to assess whether
those treatment technologies are adequately removing constituents in produced water,
given these data gaps. Given the data uncertainty, NGO representatives expressed concern
that increased opportunities for discharge would result in human health and ecological
impacts.
Some NGO representatives were also concerned that states lack sufficient water
quality criteria for many of the constituents present in produced water. As a result, they
were concerned that NPDES permits may not be protective of water quality. They also
noted that there is little data about the synergistic effects that may occur due to the
presence of multiple constituents in produced water discharges. NGO representatives were
also concern that since much E&P activities occur in arid and semi-arid areas, discharges
will occur primarily to intermittent and ephemeral streams. According to these NGO
representatives, discharging water to such streams may alter the hydraulic and hydrologic
regime of the stream, causing concerns such as erosion. They stated that such discharges
may also alter the vegetation or biota present in and adjacent to the stream. Further, they
stated that discharges to such streams receive little or no dilution by the receiving water,
increasing the risk of adverse effects from discharges, and noted that any upsets to
treatment systems discharging to such stream, or spills into such stream, could magnify
adverse effects.
Some NGO representatives were opposed to the EPA revising ELGs to allow for
broader discharge of produced water, stating that it is not the EPA's responsibility to solve
industry's water management problem. They identified the increasing volume of water
used for well completions as a primary driver for constraints on management of produced
water and suggested that industry moderate the pace of drilling activities. They were
concerned that changes to ELGs to allow for broader discharge options would be a
weakening of existing regulations. They also stated that a zero discharge of pollutants
standard remains available to the industry, that this is the goal of the CWA, and therefore
the EPA should not revise this standard.
Some NGO representatives saw potential benefit from produced water discharges
due to water scarcity concerns. While acknowledging discharges of treated produced water
could be used for agriculture, water supply and other uses, they indicated that they would
want such discharges to be protective of the receiving water quality and downstream uses.
In addition, selling treated produced water could generate additional revenue in some
cases. Also, some NGOs indicated that providing additional options for industry can help to
promote continued oil and gas development, which has an economic benefit for
communities, states and landowners.
4.5 Major Themes from Members of Academia
Those in the academic community that were engaged highlighted knowledge gaps
regarding produced water that complicates assessment of the need for and the implications
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of discharge of treated produced water from many production areas. For example, they
indicated that there is little available data regarding the chemical composition of produced
water. Produced water characteristics vary considerably between formations and are
influenced not only by the production method but also by the chemical formulations used
in hydraulic fracturing, well maintenance and well stimulation. In addition, possible
transformations inside the well of constituents can complicate characterization of
produced water. Academia representatives also indicated that analytical methods for
monitoring of constituents in produced water are lacking.
Some in academia indicated that, due to the lack of data, it is difficult to determine
what treatment technologies are needed to treat produced water to a level that is suitable
for discharge. Limited data also makes it difficult to assess the toxicity of produced water,
and the possible environmental implications of discharge. Academia is currently
researching additional approaches for assessing the toxicity of produced water, such as
bioassays. In addition, they indicated that some research done to date shows potential
environmental implications, such as radium accumulating in sediments downstream of
discharge sources and accumulating in aquatic organisms and possible toxic effects from
some constituents in produced waters.
In addition to data gaps for produced water composition, toxicity, and treatability,
there are gaps in information on produced water generation and disposition. According to
academia, there are few requirements for tracking of where produced water is generated
and in what quantities, and where it is transported for subsequent management. There is
little data available on how much produced water is managed in injection disposal wells,
and what the pressures are in those wells. Given the lack of data, academia indicated that it
is difficult to determine where injection pressures may be increasing and where problems
such as induced seismicity may occur. In addition, academia noted that there is little data
on the fate of produced water injected into some formations due to complex geology and
the lack of monitoring data. Academia further noted that in cases where data does exist, its
availability may be delayed such that timely assessment of implications and adjustments
(such as reducing injection volumes) may be difficult.
Those academics engaged noted that while there are existing technologies available
for treating produced waters for discharge, the cost is still high compared to other
management options. Research is ongoing into lower cost treatment technologies, such as
advanced membranes. In addition, they indicated that use of waste heat for thermal
distillation could significantly reduce treatment costs. One source of waste heat that was
identified are natural gas compressor stations. In addition, natural gas that is currently
flared could instead be used to drive thermal distillation systems or converted into
electricity for powering membrane treatment systems. Academia identified several issues
with treatment for discharge, including increased air emissions from treatment systems
and residuals management. With respect to residuals, managing the large quantities of salts
that would be produced from widespread adoption of distillation/crystallization as well as
TENORM containing sludges were identified as particular challenges.
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Section 4-The EPA's Outreach to Stakeholders
4.6 Major Themes from Other Entities
In addition to people from states, tribes, the oil and gas extraction industry, NGOs
and academia, the EPA met with other stakeholders such as POTWs, technology vendors
and service providers. These stakeholders provided additional input to the EPA from their
individual perspectives.
Generally, the EPA heard from associations that represent POTWs that these
facilities do not want to accept produced water because the treatment technology they
employ will not treat produced waters. A primary constituent of concern is TDS and
chlorides which are not removed by the treatment technologies in place at the vast
majority of POTWs. However, at least one POTW would like to build plants specifically
designed to treat produced water for discharge and would like the EPA to revise its
regulations to allow POTWs to accept these wastewaters. This POTW indicated that
produced water management options are limited in some areas and that building plants
suitable for treating and discharging produced water could address capacity limitations.
There are many vendors, service providers and water treatment companies
currently offering produced water management options for producers and the EPA met
with some of them. Several indicated that they are actively exploring treatment
technologies to reduce the cost of produced water treatment. They indicated that the cost
of treatment that includes desalination is much higher than the cost to reuse produced
water in the oil and gas field or to inject into disposal wells. They indicated that recovering
and selling co-products is necessary to offset treatment costs and be profitable. One
company indicated that it may be difficult to recover these co-products with mobile
treatment systems given that extensive pretreatment prior to desalinization is needed to
remove contaminants that may otherwise partition into the co-products. Also, establishing
markets for co-products can be difficult due to the lack of standard specifications and
varying state requirements. It was also stated that it is not easy to treat produced water in
some cases due to the high TDS and mineral content which can degrade and damage
treatment equipment. Also, residuals management such as TENORM-containing sludges
can be a substantial cost.
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Section 5-Summary and Next Steps
5. Summary and Next Steps
The EPA obtained input from a variety of states, tribes and stakeholders concerning
produced water management under the CWA and that input is described herein. While
some entities were supportive of expanding discharge opportunities which would increase
flexibility while reducing costs and increase available water supplies, others were not
supportive due to concerns such as potential environmental or human health implications.
Expressions of support and concern were reinforced by input letters received by the EPA
during the public input period of the draft report19 (the EPA accepted public input during
May and June of 2019). The EPA has considered the information obtained during the
outreach activities, as well as during the public input period, in preparing this final report.
The Agency intends to announce next steps for produced water management under the
CWA in subsequent communications.
19 The public input letters are available at Regulations.gov under Docket ID No. EPA-HQ-OW-2018-0618.
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Section 6-References
6. References
1. Acharya, Harish R. 2011. Cost Effective Recovery of Low-TDS Frac Flowback
Water for Reuse. GE Global Research. U.S. DOE NETL.
2. CCST. 2014. Advanced Well Stimulation Technologies in California: An
Independent Review of Scientific and Technical Information.
3. ExxonMobil Corporation. 2014. Hydraulic Fracturing Fluid. XTO Energy.
4. FracFocus. 2014. What Chemicals Are Used?
5. Government Accountability Office (GAO) 2014. Freshwater: Supply Concerns
Continue and Uncertainties Complicate Planning. GAO-14-430.
6. GWPC, 2019. Produced Water Report: Regulations, Current Practices, And
Research Needs. Ground Water Protection Council, Oklahoma City, OK. June,
2019
7. 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. United States Department of Energy. 5 May 2016.
8. U.S. DOE. 2018. United States Energy Information Administration (EIA).
Annual Energy Outlook 2018. United States Department of Energy. 6
February 2018.
9. U.S. EPA. 2015. Analysis of Hydraulic Fracturing Fluid Data from the
FracFocus Chemical Disclosure Registry 1.0. EPA/601/R-14/003.
10. U.S. EPA. 2016. Hydraulic Fracturing for Oil and Gas: Impacts from the
Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United
States (Final Report). U.S. Environmental Protection Agency, Washington, DC,
EPA/600/R-16/236F.
11. U.S. EPA. 2016b. Technical Development Document for the Effluent
Limitations Guidelines and Standards for the Oil and Gas Extraction Point
Source Category. U.S. Environmental Protection Agency, Washington, DC,
EPA-820-R-16-003.
12. U.S. EPA. 2018. Detailed Study of the Centralized Waste Treatment Point
Source Category for Facilities Managing Oil and Gas Extraction Wastes. U.S.
Environmental Protection Agency, Washington, DC, EPA 821-R-18-004.
13. USGS. 2014. National Produced Waters Geochemical Database v2.1
(Provisional) - Documentation. U.S. Geological Survey.
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