[Federal Register Volume 80, Number 66 (Tuesday, April 7, 2015)]
[Proposed Rules]
[Pages 18557-18580]
[FR Doc No: 2015-07819]

=======================================================================
-----------------------------------------------------------------------

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 435

[EPA-HQ-OW-2014-0598; FRL-9917-78-OW]
RIN 2040-AF35

Effluent Limitations Guidelines and Standards for the Oil and Gas
Extraction Point Source Category

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

-----------------------------------------------------------------------

SUMMARY: EPA proposes a Clean Water Act (CWA) regulation that would
better protect human health and the environment and protect the
operational integrity of publicly owned treatment works (POTWs) by
establishing pretreatment standards that would prevent the discharge of
pollutants in wastewater from onshore unconventional oil and gas
extraction facilities to POTWs. Unconventional oil and gas (UOG)
extraction wastewater can be generated in large quantities and contains
constituents that are potentially harmful to human health and the
environment. Because they are not typical of POTW influent wastewater,
some UOG extraction wastewater constituents can be discharged,
untreated, from the POTW to the receiving stream; can disrupt the
operation of the POTW (e.g., by inhibiting biological treatment); can
accumulate in biosolids (sewage sludge), limiting their use; and can
facilitate the formation of harmful disinfection by-products (DBPs).
Based on the information collected by EPA, the requirements in this
proposal reflect current industry practices for unconventional oil and
gas extraction facilities, therefore, EPA does not project the proposed
rule will impose any costs or lead to pollutant removals, but will
ensure that such current industry best practice is maintained over
time.

DATES: Comments on this proposed rule must be received on or before
June 8, 2015. EPA will conduct a public hearing on the proposed
pretreatment standards on May 29, 2015 at 1:00 p.m. in the EPA East
Building, Room 1153, 1201 Constitution Avenue NW., Washington, DC.

ADDRESSES: Submit your comments on the proposed rule, identified by
Docket No. EPA-HQ-OW-2014-0598 by one of the following methods:
     http://www.regulations.gov: Follow the on-line
instructions for submitting comments.
     Email<EMAIL_ADDRESS>Attention Docket ID No. EPA-HQ-
OW-2014-0598.
     Mail: Water Docket, U.S. Environmental Protection Agency,
Mail code: 4203M, 1200 Pennsylvania Ave. NW., Washington, DC 20460.
Attention Docket ID No. EPA-HQ-OW-2014-0598. Please include three
copies.
     Hand Delivery: Water Docket, EPA Docket Center, EPA West
Building Room 3334, 1301 Constitution Ave. NW., Washington, DC,
Attention Docket ID No. EPA-HQ-OW-2014-0598. Such deliveries are only
accepted during the Docket's normal hours of operation, and you should
make special arrangements for deliveries of boxed information by
calling<PHONE_NUMBER>.
    Instructions: Direct your comments to Docket No. EPA-HQ-OW-2014-
0598. EPA's policy is that all comments received will be included in
the public docket without change and can be made available online at
http://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be
Confidential Business Information (CBI) or other information whose
disclosure is restricted by statute. Do not submit information that you
consider to be CBI or otherwise protected through http://www.regulations.gov or email. The http://www.regulations.gov Web site
is an ``anonymous access'' system, which means EPA will not know your
identity or contact information unless you provide it in the body of
your comment. If you send an email comment directly to EPA without
going through http://www.regulations.gov your email address will be
automatically captured and included as part of the comment that is
placed in the public docket and made available on the Internet. If you
submit an electronic comment, EPA recommends that you include your name
and other contact information in the body of your comment and with any
disk or CD-ROM you submit. If EPA cannot read your comment due to
technical difficulties and cannot contact you for clarification, EPA
will not be able to consider your comment. Electronic files should
avoid the use of special characters, any form of encryption, and be
free of any defects or viruses.
    Docket: All documents in the docket are listed in the http://www.regulations.gov index. A detailed record index, organized by
subject, is available on EPA's Web site at http://water.epa.gov/scitech/wastetech/guide/oilandgas/unconv.cfm. Although listed in the
index, some information is not publicly available, e.g., CBI or other
information whose disclosure is restricted by statute. Certain other
material, such as copyrighted material, will be publicly available only
in hard copy. Publicly available docket materials are available either
electronically in http://www.regulations.gov or in hard copy at the
Water Docket in EPA Docket Center, EPA/DC, EPA West, Room 3334, 1301
Constitution Ave. NW., Washington, DC. The Public Reading Room is open
from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal
holidays. The telephone number for the Public Reading Room is 202-566-
1744,

and the telephone number for the Water Docket is<PHONE_NUMBER>.
    Pretreatment Hearing Information: EPA will conduct a public hearing
on the proposed pretreatment standards on May 29, 2015 at 1:00 p.m. in
the East Building, Room 1153, 1201 Constitution Avenue NW., Washington,
DC. Registration is not required for this public hearing, however pre-
registration will be possible via a link on EPA's Web site: at http://water.epa.gov/scitech/wastetech/guide/oilandgas/unconv.cfm. During the
hearing, the public will have an opportunity to provide oral comment to
EPA on the proposed pretreatment standards. EPA will not address any
issues raised during the hearing at that time but these comments will
be included in the public record for the rule. For security reasons, we
request that you bring photo identification with you to the meeting.
Also, if you let us know in advance of your plans to attend, it will
expedite the process of signing in. Seating will be provided on a
first-come, first-served basis. Please note that parking is very
limited in downtown Washington, and use of public transit is
recommended. EPA Headquarters complex is located near the Federal
Triangle Metro station. Upon exiting the Metro station, walk east to
12th Street. On 12th Street, walk south to Constitution Avenue. At the
corner, turn right onto Constitution Avenue and proceed to EPA East
Building entrance.

FOR FURTHER INFORMATION CONTACT: For technical information, contact
Lisa Biddle, Engineering and Analysis Division, Telephone: 202-566-
0350; email<EMAIL_ADDRESS>For economic information, contact
Karen Milam, Engineering and Analysis Division, Telephone: 202-566-
1915; email<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

Table of Contents

I. Regulated Entities
II. How To Submit Comments
III. Supporting Documentation
IV. Overview
V. Legal Authority
VI. Purpose and Summary of Proposed Rule
    A. Purpose of the Regulatory Action
    B. Summary of the Proposed Rule
    C. Summary of Costs and Benefits
VII. Solicitation of Data and Comments
VIII. Background
    A. Clean Water Act
    B. Effluent Limitations Guidelines and Standards Program
    1. Best Practicable Control Technology Currently Available (BPT)
    2. Best Conventional Pollutant Control Technology (BCT)
    3. Best Available Technology Economically Achievable (BAT)
    4. Best Available Demonstrated Control Technology (BADCT)/New
Source Performance Standards (NSPS)
    5. Pretreatment Standards for Existing Sources (PSES) and
Pretreatment Standards for New Sources (PSNS)
    C. Oil and Gas Extraction Effluent Guidelines Rulemaking History
    1. Subpart C: Onshore
    2. Subpart E: Agricultural and Wildlife Use
    D. State Pretreatment Requirements That Apply to UOG Extraction
Wastewater
    E. Related Federal Requirements in the Safe Drinking Water Act
IX. Summary of Data Collection
    A. Site Visits and Contacts With Treatment Facilities and
Vendors
    B. Meetings with Stakeholder Organizations
    1. Stakeholder Organizations
    2. State Stakeholders
    C. Secondary Data Sources
    D. Drilling Info Desktop[supreg] Data Set
    E. EPA Hydraulic Fracturing Study
X. Description of the Oil and Gas Industry
    A. Economic Profile
    B. Industry Structure and Economic Performance
    C. Financial Performance
XI. Scope
XII. Unconventional Oil and Gas Extraction: Resources, Process, and
Wastewater
    A. Unconventional Oil and Gas Extraction Resources
    B. Unconventional Oil and Gas Extraction Process
    1. Well Drilling
    2. Well Completion
    3. Production
    C. UOG Extraction Wastewater
    1. Drilling Wastewater
    2. Produced Water
    D. UOG Extraction Wastewater Characteristics
    1. Total Dissolved Solids (TDS) and TDS-Contributing Ions
    2. Organic Constituents
    3. Radioactive Constituents
    E. Wastewater Management and Disposal Practices
    1. Injection into Disposal Wells
    2. Reuse in Fracturing
    3. Transfer to Centralized Waste Treatment Facilities
    4. Transfer to POTWs
XIII. Subcategorization
XIV. Proposed Regulation
    A. Discussion of Options
    1. PSES and PSNS Option Selection
    2. Other Options Considered
    B. Pollutants of Concern
    C. POTW Pass Through Analysis
XV. Environmental Impacts
    A. Pollutants
    B. Impacts From the Discharge of Pollutants Found in UOG
Extraction Wastewater
    C. Impact on Surface Water Designated Uses
    1. Drinking Water Uses
    2. Aquatic Life Support Uses
    3. Livestock Watering Uses
    4. Irrigation Uses
    5. Industrial Uses
XVI. Non-Water Quality Environmental Impacts Associated With the
Proposed Rule
XVII. Implementation
    A. Implementation Deadline
    B. Upset and Bypass Provisions
    C. Variances and Modifications
XVIII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health and Safety Risks
    H. Executive Order 13211: Energy Effects
    I. National Technology Transfer Advancement Act
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations

I. Regulated Entities

    Entities potentially regulated by this proposed action include:

------------------------------------------------------------------------
                                                        North American
                                                           Industry
           Category            Examples of regulated    Classification
                                      entities          System (NAICS)
                                                             Code
------------------------------------------------------------------------
Industry.....................  Crude Petroleum and                211111
                                Natural Gas
                                Extraction.
                               Natural Gas Liquid                 211112
                                Extraction.
------------------------------------------------------------------------

    This section is not intended to be exhaustive, but rather provides
a guide for readers regarding entities likely to be regulated by this
proposed action. Other types of entities that do not meet the above
criteria could also be regulated. To determine whether your facility
would be regulated by this proposed action, you should carefully
examine

the applicability criteria listed in 40 CFR 435.30 and the definitions
in 40 CFR 435.33(b) of the proposed rule and detailed further in
Section XI--Scope, of this preamble. If you still have questions
regarding the proposed applicability of this action to a particular
entity, consult the person listed for technical information in the
preceding FOR FURTHER INFORMATION CONTACT section.

II. How To Submit Comments

    The public can submit comments in written or electronic form. (See
the ADDRESSES section above.) Electronic comments must be identified by
the Docket No. EPA-HQ-OW-2014-0598 and must be submitted as a MS Word,
WordPerfect, or ASCII text file, avoiding the use of special characters
and any form of encryption. EPA requests that any graphics included in
electronic comments also be provided in hard-copy form. EPA also will
accept comments and data on disks in the aforementioned file formats.
Electronic comments received on this notice can be filed online at many
Federal Depository Libraries. No confidential business information
(CBI) should be sent by email.

III. Supporting Documentation

    The proposed rule is supported by a number of documents including
the Technical Development Document for Proposed Effluent Limitations
Guidelines and Standards for Oil and Gas Extraction (TDD), Document No.
EPA-821-R-15-003 (DCN SGE00704). This and other supporting documents
are available in the public record for this proposed rule and on EPA's
Web site at http://water.epa.gov/scitech/wastetech/guide/oilandgas/unconv.cfm.

IV. Overview

    This preamble describes the reasons for the proposed rule; the
legal authority for the proposed rule; a summary of the options
considered for the proposal; background information, including terms,
acronyms, and abbreviations used in this document; and the technical
and economic methodologies used by the Agency to develop the proposed
rule. In addition, this preamble also solicits comment and data from
the public.

V. Legal Authority

    EPA proposes this regulation under the authorities of sections 101,
301, 304, 306, 307, 308, and 501 of the CWA, 33 U.S.C. 1251, 1311,
1314, 1316, 1317, 1318, 1324, and 1361.

VI. Purpose and Summary of Proposed Rule

A. Purpose of the Regulatory Action

    Responsible development of America's oil and gas resources offers
important economic, energy security, and environmental benefits. EPA is
working with states and other stakeholders to understand and address
potential impacts of hydraulic fracturing, an important process
involved in producing unconventional oil and natural gas, so the public
has confidence that oil and natural gas production will proceed in a
safe and responsible manner.\1\ EPA is moving forward with several
initiatives to provide regulatory clarity with respect to existing laws
and using existing authorities where appropriate to enhance human
health and environmental safeguards. This proposed rule would fill a
gap in existing federal wastewater regulations to ensure that the
current practice of not sending wastewater discharges from this sector
to POTWs continues into the future. This proposed rule does not,
however, address the practice of underground injection of wastewater
discharges from this sector since such activity is not subject to the
CWA but rather the Safe Drinking Water Act (SDWA) (see TDD Chapter
A.3).
---------------------------------------------------------------------------

    \1\ For more information on EPA's continued engagement with
states and other stakeholders, see: http://www2.epa.gov/hydraulicfracturing.
---------------------------------------------------------------------------

    Recent advances in the well completion process, combining hydraulic
fracturing and horizontal drilling, have made extraction of oil and
natural gas from low permeability, low porosity geologic formations
(referred to hereafter as unconventional oil and gas (UOG) resources)
more technologically and economically feasible than it had been. As a
result, according to the U.S. Department of Energy (DOE), in 2012, U.S.
crude oil and natural gas production reached their highest levels in
more than 15 and 30 years, respectively (DCN SGE00989). DOE projects
natural gas production in the U.S. will likely increase by 56 percent
by 2040, compared to 2012 production levels (DCN SGE00989). Similarly,
DOE projects that by 2019, crude oil production in the United States
(U.S.) will increase by 48 percent compared to 2012 production levels
(DCN SGE00989).
    Hydraulic fracturing is used to extract oil and natural gas from
highly impermeable rock formations, such as shale rock, by injecting
fracturing fluids at high pressures to create a network of fissures in
the rock formations and give the oil and/or natural gas a pathway to
travel to the well for extraction. Pressure within the low
permeability, low porosity geologic formations forces wastewaters, as
well as oil and/or gas, to the surface. In this proposed rulemaking,
oil and gas extraction includes production, field exploration,
drilling, well completion, and/or well treatment; wastewater sources
associated with these activities in low permeability, low porosity
formations are collectively referred to as UOG extraction wastewater.
    Direct discharges of oil and gas extraction wastewater pollutants
from onshore oil and gas resources, including UOG resources, to waters
of the U.S. have been regulated since 1979 under the existing Oil and
Gas Effluent Limitations Guidelines and Standards (ELGs) (40 CFR part
435), the majority of which fall under subpart C, the Onshore
Subcategory. The limitations for direct dischargers in the Onshore
Subcategory represent Best Practicable Control Technology Currently
Available (BPT). Based on the availability and economic practicability
of underground injection technologies, the BPT-based limitations for
direct dischargers require zero discharge of pollutants to waters of
the U.S. However, there are currently no requirements in subpart C that
apply to onshore oil and gas extraction facilities that are ``indirect
dischargers,'' i.e., those that send their discharges to POTWs
(municipal wastewater treatment facilities) which treat the water
before discharging it to waters of the U.S.
    UOG extraction wastewater can be generated in large quantities and
contains constituents that are potentially harmful to human health and
the environment. Wastewater from UOG wells often contains high
concentrations of total dissolved solids (TDS) (salt content). The
wastewater can also contain various organic chemicals, inorganic
chemicals, metals, and naturally-occurring radioactive materials
(referred to as technologically enhanced naturally occurring
radioactive material or TENORM).\2\ This potentially harmful wastewater
creates a need for appropriate wastewater

management infrastructure and management practices. Historically,
operators primarily managed their wastewater via underground injection
(where available). Where UOG wells were drilled in areas with limited
underground injection wells, and/or there was a lack of wastewater
management alternatives, it became more common for operators to look to
public and private wastewater treatment facilities to manage their
wastewater.
---------------------------------------------------------------------------

    \2\ Naturally occurring radioactive materials that have been
concentrated or exposed to the accessible environment as a result of
human activities such as manufacturing, mineral extraction, or water
processing is referred to as technologically enhanced naturally
occurring radioactive material (TENORM). ``Technologically
enhanced'' means that the radiological, physical, and chemical
properties of the radioactive material have been altered by having
been processed, or beneficiated, or disturbed in a way that
increases the potential for human and/or environmental exposures.
(See EPA 402-r-08-005-v2)
---------------------------------------------------------------------------

    POTWs collect wastewater from homes, commercial buildings, and
industrial facilities and pipe it to their sewage treatment plant. In
some cases, industrial dischargers can haul wastewater to the treatment
plant by tanker truck. The industrial wastewater, commingled with
domestic wastewater, is treated by the POTW and discharged to a
receiving waterbody. However, most POTWs are designed primarily to
treat municipally generated, not industrial, wastewater. They typically
provide at least secondary level treatment and, thus, are designed to
remove suspended solids and organic material using biological
treatment. As mentioned previously, wastewater from UOG extraction can
contain high concentrations of TDS, radioactive elements, metals,
chlorides, sulfates, and other dissolved inorganic constituents that
POTWs are not designed to remove. Because they are not typical of POTW
influent wastewater, some UOG extraction wastewater constituents can be
discharged, untreated, from the POTW to the receiving stream; can
disrupt the operation of the POTW (e.g., by inhibiting biological
treatment); can accumulate in biosolids (sewage sludge), limiting their
use; and can facilitate the formation of harmful DBPs.
    Under section 307(b) of the CWA, there are general and specific
prohibitions on the discharge to POTWs of pollutants in specified
circumstances in order to prevent ``pass through'' or ``interference.''
Pass through is defined as whenever the introduction of pollutants from
a user will result in a discharge that causes or contributes to a
violation of any requirement of the POTW permit. See 40 CFR 403.3(p).
Interference means a discharge that, among other things, inhibits or
disrupts the POTW or prevents biosolids use consistent with the POTW's
chosen method of disposal. See 40 CFR 403.3(k). These general and
specific prohibitions must be implemented through local limits
established by POTWs in certain cases. See 40 CFR 403.5(c). POTWs with
approved pretreatment programs must develop and enforce local limits to
implement the general prohibitions on user discharges that pass through
or interfere with the POTW or discharges to the POTW prohibited under
the specific prohibitions in 40 CFR 403.5(b). In the case of POTWs not
required to develop a pretreatment program, the POTWs must develop
local limits where there is interference or pass through and the limits
are necessary to ensure compliance with the POTW's National Pollutant
Discharge Elimination System (NPDES) permit or biosolids use.
    Under section 307(b) of the CWA, EPA is authorized to establish
nationally applicable pretreatment standards for industrial categories
that discharge indirectly (i.e., requirements for an industrial
discharge category that sends its wastewater to any POTW) for key
pollutants, such as TDS and its constituents, not susceptible to
treatment by POTWs or for pollutants that would interfere with the
operation of POTWs. Generally, EPA designs nationally applicable
pretreatment standards for categories of industry (also referred to as
categorical pretreatment standards) to ensure that wastewaters from
direct and indirect industrial dischargers are subject to similar
levels of treatment. EPA, in its discretion under section 304(g) of the
Act, periodically evaluates indirect dischargers not subject to
categorical pretreatment standards to identify potential candidates for
new pretreatment standards. To date, EPA has not established nationally
applicable pretreatment standards for the onshore oil and gas
extraction point source subcategory.
    To legally discharge wastewater, the POTW must have an NPDES permit
that limits the type and quantity of pollutants that it can discharge.
Discharges from POTWs are subject to the secondary treatment effluent
limitations at 40 CFR part 133, which address certain conventional
pollutants but do not address the main parameters of concern in UOG
extraction wastewater (e.g., TDS, chloride, radionuclides, etc.). POTWs
are also subject to water quality-based effluent limitations (WQBELs)
where necessary to protect state water quality standards, as required
under CWA section 301(b)(1)(C).
    It is currently uncommon for POTWs to establish local limits for
some of the parameters of concern identified for this proposed
rulemaking. This is due to a number of factors, including lack of
sufficient information regarding pollutants in the wastewater being
sent to POTWs; lack of national water quality recommendations for key
pollutants, such as TDS; and lack of state water quality criteria for
such key pollutants in some states, all of which can create significant
informational hurdles to including appropriate WQBELs in POTW permits.
Where a POTW's permit does not contain a WQBEL for all of the
constituents of concern in the wastewater being sent to POTWs, it is
difficult to demonstrate pass through of industrial pollutants (because
``pass through'' here means making the POTW exceed its permit limits),
and thus difficult for POTWs to establish local limits to implement the
general prohibition in the pretreatment regulations. See Section XV.
for additional information.
    As a result of the gap in federal CWA regulations, increases in
onshore oil and gas extraction from UOG resources and the related
generation of wastewater requiring management, concerns over the level
of treatment provided by public wastewater treatment facilities, as
well as potential interference with treatment processes, and concerns
over water quality and aquatic life impacts that can result from
inadequate treatment, EPA proposes technology-based categorical
pretreatment standards under the CWA for discharges of pollutants into
POTWs from existing and new onshore UOG extraction facilities in
subpart C of 40 CFR part 435. Consistent with existing BPT-based
requirements for direct dischargers in this subcategory, EPA proposes
pretreatment standards for existing and new sources (PSES and PSNS,
respectively) that would prohibit the indirect discharge of wastewater
pollutants associated with onshore UOG extraction facilities.
    Based on the information reviewed as part of this proposed
rulemaking, this proposed prohibition reflects current industry
practice. EPA has not identified any existing onshore UOG extraction
facilities that currently discharge UOG extraction wastewater to POTWs.
However, because onshore unconventional oil and gas extraction
facilities have discharged to POTWs in the past, and because the
potential remains that some facilities can consider discharging to
POTWs in the future, EPA proposes this rule.

B. Summary of the Proposed Rule

    EPA proposes pretreatment standards for existing and new sources
(PSES and PSNS, respectively) that would prohibit the indirect
discharge of wastewater pollutants associated with onshore UOG
extraction facilities. EPA is defining UOG extraction wastewater as
sources of wastewater pollutants associated with production, field
exploration, drilling, well completion, or well treatment for

unconventional oil and gas extraction (e.g., produced water (which
includes formation water, injection water, and any chemicals added
downhole or during the oil/water separation process); drilling muds;
drill cuttings; produced sand). According to sources surveyed by EPA
(see Section IX), there are no known discharges to POTWs from UOG
extraction at the time of this proposal. UOG extraction wastewater is
typically managed through disposal via underground injection wells,
reuse in subsequent fracturing jobs, or transfer to a privately owned
wastewater treatment facility (see Section XII.E). EPA proposes PSES
and PSNS that would require zero discharge of pollutants and be
effective on the effective date of this rule.
    EPA does not propose pretreatment standards for wastewater
pollutants associated with conventional oil and gas extraction
facilities at this time (see Section XIV). EPA proposes to reserve such
standards to a future rulemaking, if appropriate.

C. Summary of Costs and Benefits

    Because the data reviewed by EPA show that the UOG extraction
industry is not currently managing wastewaters by sending them to
POTWs, the proposed rule causes no incremental change to current
industry practice that EPA measured as compliance costs or monetized
benefits.
    Still, EPA has considered that while states, localities, and POTWs
are not currently approving these wastewaters for acceptance at POTWs,
some POTWs continue to receive requests to accept UOG extraction
wastewater (DCN SGE00742; DCN SGE00743; DCN SGE00762). This proposed
rule would provide regulatory certainty and would eliminate the burden
on POTWs to analyze such requests.
    The proposed rule would also eliminate the need to develop
requirements in states where UOG extraction is not currently occurring,
but is likely to occur in the future. There are few states where
existing regulations address UOG extraction wastewater discharges to
POTWs (see Section VIII.D. and TDD Chapter A.2.). While EPA knows there
will likely be some reduction in state and POTW staff time and
resources, EPA did not attempt to estimate, quantitatively, monetary
savings associated with the reduced burden to states and localities
that would result from this proposed rule.
    Most POTWs are not able to sufficiently treat TDS and many other
pollutants in UOG extraction wastewater, and thus this proposed rule
would potentially prevent elevated TDS and the presence of other
pollutants in POTW effluent. Prevention of the discharge of TDS
accomplished by the proposed rule would further protect water quality
because national water quality criteria recommendations have not yet
been established for many constituents of TDS.
    The proposed rule could impose some costs on industry if
discharging wastewaters to POTWs becomes economically attractive to UOG
operations relative to other management options such as reuse or
disposal via underground injection wells in the future. EPA did not
estimate these potential compliance costs or environmental benefits
because of the uncertainty about future demand for POTWs to accept UOG
extraction wastewaters and the associated incremental costs or
benefits.

VII. Solicitation of Data and Comments

    EPA solicits comments on the proposed rule, including EPA's
rationale as described in this preamble. EPA seeks comments on issues
specifically identified in this document as well as any other issues
that are not specifically addressed in this document. Comments are most
helpful when accompanied by specific examples and supporting data.
Specifically, EPA solicits information and data on the following
topics.
    1. EPA's proposed definitions of UOG and UOG extraction wastewater
and specifically whether the proposed definition of unconventional oil
and gas is sufficiently clear to enable oil and gas extraction
operators and/or pretreatment authorities to determine whether specific
wastewaters are from conventional or unconventional sources. See
Section XII.
    2. Whether or not there are any existing onshore UOG extraction
facilities that currently discharge UOG extraction wastewater to POTWs
in the U.S. See Section XII.E.4. If existing discharges to POTWs are
identified, EPA requests comment on whether or not the proposed
effective date remains appropriate. See Section XVII.
    3. Costs and benefits to POTWs, states, and localities associated
with the proposed rule. See Section VI.C.
    4. Volumes of, and pollutants and concentrations in, wastewater
generated from UOG extraction. See Section XII.
    5. The nature and frequency of requests received by POTWs to accept
UOG extraction wastewater, and the likelihood that such requests will
continue to be submitted in the future. EPA is particularly interested
in hearing from POTWs and states on this matter. See Section VI.C. and
Section XIV.A.2.
    6. Volumes of, and pollutants and concentrations in, wastewater
generated from conventional oil and gas extraction. See Section
XIV.A.2.c.
    7. The prevalence of conventional oil and gas wastewater discharges
to POTWs, including information on any pretreatment that could be
applied, geologic formations the gas or oil is extracted from, and
locations within the U.S. See Section XII. and Section XIV.A.2.
    8. Removal and ``pass through'' of UOG extraction wastewater
pollutants at POTWs. See Section XIV. and Section XII.E.4.
    9. The environmental impacts of UOG extraction wastewater
discharges to POTWs. See Section XV.

VIII. Background

A. Clean Water Act

    Congress passed the Federal Water Pollution Control Act Amendments
of 1972, also known as the CWA, to ``restore and maintain the chemical,
physical, and biological integrity of the Nation's waters.'' 33 U.S.C.
1251(a). The CWA establishes a comprehensive program for protecting our
nation's waters. Among its core provisions, the CWA prohibits the
discharge of pollutants from a point source to waters of the U.S.,
except as authorized under the CWA. Under section 402 of the CWA,
discharges can be authorized through a NPDES permit. The CWA
establishes a two-pronged approach for these permits, technology-based
controls that establish the floor of performance for all dischargers,
and water quality-based limits where the technology-based limits are
insufficient for the discharge to meet applicable water quality
standards. To serve as the basis for the technology-based controls, the
CWA authorizes EPA to establish national technology-based effluent
limitations guidelines and new source performance standards for
discharges from different categories of point sources, such as
industrial, commercial, and public sources, that discharge directly
into waters of the U.S.
    The CWA also authorizes EPA to promulgate nationally applicable
pretreatment standards that restrict pollutant discharges from
facilities that discharge pollutants indirectly, by sending wastewater
to POTWs, as outlined in sections 307(b) and (c) and 33 U.S.C. 1317(b)
and (c). Specifically, the CWA authorizes that EPA establish
pretreatment standards for those pollutants in wastewater from indirect
dischargers that EPA determines are not susceptible to treatment by a
POTW or which would interfere with POTW

operations. Pretreatment standards must be established to prevent the
discharge of any pollutant that can pass through, interfere with, or
are otherwise incompatible with POTW operations. CWA sections 307(b)
and (c). The legislative history of the 1977 CWA amendments explains
that pretreatment standards are technology-based and analogous to BAT
effluent limitations for the removal of toxic pollutants. As further
explained in the legislative history, the combination of pretreatment
and treatment by the POTW is intended to achieve the level of treatment
that would be required if the industrial source were making a direct
discharge. Conf. Rep. No. 95-830, at 87 (1977), reprinted in U.S.
Congress. Senate. Committee on Public Works (1978), A Legislative
History of the CWA of 1977, Serial No. 95-14 at 271 (1978).
    Direct dischargers (those discharging directly to surface waters)
must comply with effluent limitations in NPDES permits. Technology-
based effluent limitations in NPDES permits for direct dischargers are
derived from effluent limitations guidelines (CWA sections 301 and 304)
and new source performance standards (CWA section 306) promulgated by
EPA, or based on best professional judgment (BPJ) where EPA has not
promulgated an applicable effluent guideline or new source performance
standard (CWA section 402(a)(1)(B) and 40 CFR 125.3). Additional
limitations based on water quality standards are also required to be
included in the permit where necessary to meet water quality standards.
CWA section 301(b)(1)(C). The effluent guidelines and new source
performance standards are established by regulation for categories of
industrial dischargers and are based on the degree of control that can
be achieved using various levels of pollution control technology, as
specified in the Act.
    EPA promulgates national effluent guidelines and new source
performance standards for major industrial categories for three classes
of pollutants: (1) Conventional pollutants (total suspended solids, oil
and grease, biochemical oxygen demand (BOD5), fecal
coliform, and pH), as outlined in CWA section 304(a)(4) and 40 CFR
401.16; (2) toxic pollutants (e.g., metals such as arsenic, mercury,
selenium, and chromium; and organic pollutants such as benzene, benzo-
a-pyrene, phenol, and naphthalene), as outlined in section 307(a) of
the Act, 40 CFR 401.15 and 40 CFR part 423, appendix A; and (3)
nonconventional pollutants, which are those pollutants that are not
categorized as conventional or toxic (e.g., ammonia-N, phosphorus, and
TDS).

B. Effluent Limitations Guidelines and Standards Program

    EPA develops ELGs that are technology-based regulations for
specific categories of dischargers. EPA bases these regulations on the
performance of control and treatment technologies. The legislative
history of CWA section 304(b), which is the heart of the effluent
guidelines program, describes the need to press toward higher levels of
control through research and development of new processes,
modifications, replacement of obsolete plants and processes, and other
improvements in technology, taking into account the cost of controls.
Congress has also stated that EPA need not consider water quality
impacts on individual water bodies as the guidelines are developed; see
Statement of Senator Muskie (October 4, 1972), reprinted in U.S. Senate
Committee on Public Works, Legislative History of the Water Pollution
Control Act Amendments of 1972, Serial No. 93-1, at 170).
    There are four types of standards applicable to direct dischargers
(facilities that discharge directly to surface waters), and two types
of standards applicable to indirect dischargers (facilities that
discharge to POTWs), described in detail below. Subsections 1 through 4
describe standards for direct discharges and subsection 5 describes
standards for indirect discharges.
1. Best Practicable Control Technology Currently Available (BPT)
    Traditionally, EPA defines BPT effluent limitations based on the
average of the best performances of facilities within the industry,
grouped to reflect various ages, sizes, processes, or other common
characteristics. BPT effluent limitations control conventional, toxic,
and nonconventional pollutants. In specifying BPT, EPA looks at a
number of factors. EPA first considers the cost of achieving effluent
reductions in relation to the effluent reduction benefits. The Agency
also considers the age of equipment and facilities, the processes
employed, engineering aspects of the control technologies, any required
process changes, non-water quality environmental impacts (including
energy requirements), and such other factors as the Administrator deems
appropriate. See CWA section 304(b)(1)(B). If, however, existing
performance is uniformly inadequate, EPA can establish limitations
based on higher levels of control than what is currently in place in an
industrial category, when based on an Agency determination that the
technology is available in another category or subcategory, and can be
practically applied.
2. Best Conventional Pollutant Control Technology (BCT)
    The 1977 amendments to the CWA require EPA to identify additional
levels of effluent reduction for conventional pollutants associated
with BCT technology for discharges from existing industrial point
sources. In addition to other factors specified in section
304(b)(4)(B), the CWA requires that EPA establish BCT limitations after
consideration of a two-part ``cost reasonableness'' test. EPA explained
its methodology for the development of BCT limitations in July 9, 1986
(51 FR 24974). Section 304(a)(4) designates the following as
conventional pollutants: BOD5, total suspended solids (TSS),
fecal coliform, pH, and any additional pollutants defined by the
Administrator as conventional. The Administrator designated oil and
grease as an additional conventional pollutant on July 30, 1979 (44 FR
44501; 40 CFR part 401.16).
3. Best Available Technology Economically Achievable (BAT)
    BAT represents the second level of stringency for controlling
direct discharge of toxic and nonconventional pollutants. In general,
BAT-based effluent guidelines and new source performance standards
represent the best available economically achievable performance of
facilities in the industrial subcategory or category. Following the
statutory language, EPA considers the technological availability and
the economic achievability in determining what level of control
represents BAT. CWA section 301(b)(2)(A). Other statutory factors that
EPA considers in assessing BAT are the cost of achieving BAT effluent
reductions, the age of equipment and facilities involved, the process
employed, potential process changes, and non-water quality
environmental impacts, including energy requirements and such other
factors as the Administrator deems appropriate. CWA section
304(b)(2)(B). The Agency retains considerable discretion in assigning
the weight to be accorded these factors. Weyerhaeuser Co. v. Costle,
590 F.2d 1011, 1045 (D.C. Cir. 1978).
4. Best Available Demonstrated Control Technology (BADCT)/New Source
Performance Standards (NSPS)
    NSPS reflect effluent reductions that are achievable based on the
best available demonstrated control

technology (BADCT). Owners of new facilities have the opportunity to
install the best and most efficient production processes and wastewater
treatment technologies. As a result, NSPS should represent the most
stringent controls attainable through the application of the BADCT for
all pollutants (that is, conventional, nonconventional, and toxic
pollutants). In establishing NSPS, EPA is directed to take into
consideration the cost of achieving the effluent reduction and any non-
water quality environmental impacts and energy requirements. CWA
section 306(b)(1)(B).
5. Pretreatment Standards for Existing Sources (PSES) and New Sources
(PSNS)
    As discussed above, section 307(b) of the Act calls for EPA to
issue pretreatment standards for discharges of pollutants from existing
sources to POTWs. Section 307(c) of the Act calls for EPA to promulgate
pretreatment standards for new sources (PSNS). Both standards are
designed to prevent the discharge of pollutants that pass through,
interfere with, or are otherwise incompatible with the operation of
POTWs. Categorical pretreatment standards for existing sources are
technology-based and are analogous to BPT and BAT effluent limitations
guidelines, and thus the Agency typically considers the same factors in
promulgating PSES as it considers in promulgating BAT. See Natural
Resources Defense Council v. EPA, 790 F.2d 289, 292 (3rd Cir. 1986).
Similarly, in establishing pretreatment standards for new sources, the
Agency typically considers the same factors in promulgating PSNS as it
considers in promulgating NSPS (BADCT).

C. Oil and Gas Extraction Effluent Guidelines Rulemaking History

    EPA promulgated the first Oil and Gas Extraction ELGs (40 CFR part
435) in 1979, and substantially amended the regulation in 1993
(Offshore), 1996 (Coastal), and 2001 (Synthetic-based drilling fluids).
The Oil and Gas Extraction industry is subcategorized in 40 CFR part
435 as follows: (1) Subpart A: Offshore; (2) subpart C: Onshore; (3)
subpart D: Coastal; (4) subpart E: Agricultural and Wildlife Water Use;
and (5) subpart F: Stripper.
    The existing subpart C regulation covers wastewater discharges from
field exploration, drilling, production, well treatment, and well
completion activities in the oil and gas industry. Although
unconventional oil and gas resources occur in offshore and coastal
regions, recent development of UOG resources in the U.S. has occurred
primarily onshore in regions to which the regulations in subpart C
(Onshore) and subpart E (Agricultural and Wildlife Water Use) apply and
thus, the gap in onshore regulations is the focus of this proposed
rulemaking effort. For this reason, only the regulations that apply to
onshore oil and gas extraction are described in more detail here.
1. Subpart C: Onshore
    Subpart C applies to facilities engaged in the production, field
exploration, drilling, well completion, and well treatment in the oil
and gas extraction industry which are located landward of the inner
boundary of the territorial seas--and which are not included in the
definition of other subparts--including subpart D (Coastal). The
regulations at 40 CFR 435.32 specify the following for BPT: There shall
be no discharge of waste water pollutants into navigable waters from
any source associated with production, field exploration, drilling,
well completion, or well treatment (i.e., produced water, drilling
muds, drill cuttings, and produced sand). The existing regulations do
not include national categorical pretreatment standards for discharges
to POTWs. The existing oil and gas extraction ELGs did not establish
requirements that would apply to privately-owned wastewater treatment
facilities that accept oil and gas extraction wastewaters but that are
not engaged in production, field exploration, drilling, well
completion, or well treatment. Discharges from such facilities are not
subject to 40 CFR part 435, but rather are subject to requirements in
40 CFR part 437, the Centralized Waste Treatment Category.
2. Subpart E: Agricultural and Wildlife Use
    Subpart E applies to onshore facilities located in the continental
U.S. and west of the 98th meridian for which the produced water has a
use in agriculture or wildlife propagation when discharged into
navigable waters. Definitions in 40 CFR 435.51(c) explain that the term
``use in agricultural or wildlife propagation'' means that (1) the
produced water is of good enough quality to be used for wildlife or
livestock watering or other agricultural uses; and (2) the produced
water is actually put to such use during periods of discharge. The
regulations at 40 CFR 435.52 specify that the only allowable discharge
is produced water, with an oil and grease concentration not exceeding
35 milligrams per liter (mg/L). The BPT regulations prohibit the
discharge of waste pollutants into navigable waters from any source
(other than produced water) associated with production, field
exploration, drilling, well completion, or well treatment (i.e.,
drilling muds, drill cuttings, produced sands).

D. State Pretreatment Requirements That Apply to UOG Extraction
Wastewater

    In addition to applicable federal requirements, some states
regulate the management, storage, and disposal of UOG extraction
wastewater, including regulations concerning pollutant discharges to
POTWs from oil and gas extraction facilities. In addition to
pretreatment requirements, some states have indirectly addressed the
issue of pollutant discharges to POTWs by limiting the management and
disposal options available for operators to use.
    During initial development of Marcellus shale gas resources, some
operators managed UOG wastewater by transfer to POTWs. EPA did not
identify other areas in the U.S. where POTWs routinely accepted UOG
extraction wastewaters. Refer to TDD Chapter A.2 which summarizes how
Pennsylvania, Ohio, and West Virginia responded to UOG extraction
wastewater discharges into their POTWs. EPA did not identify any state
level requirements that require zero discharges of pollutants from UOG
operations to POTWs in the same manner as the proposed rule.

E. Related Federal Requirements in the Safe Drinking Water Act

    As required by the SDWA section 1421, EPA has promulgated
regulations to protect underground sources of drinking water through
Underground Injection Control (UIC) programs that regulate the
injection of fluids underground. These regulations are found at 40 CFR
parts 144-148, and specifically prohibit any underground injection not
authorized by UIC permit. 40 CFR 144.11. The regulations classify
underground injection into six classes; wells that inject fluids
brought to the surface in connection with oil and gas production are
classified as Class II UIC wells. Thus, onshore oil and gas extraction
facilities that seek to meet the zero discharge requirements of the
existing ELGs or proposed pretreatment standard through underground
injection of wastewater must obtain a Class II UIC permit for such
disposal.

IX. Summary of Data Collection

    In developing the proposed rule, EPA considered information
collected through site visits and telephone contacts with UOG facility
operators, facilities that treat and/or dispose of UOG extraction
wastewater, and wastewater management equipment

vendors. EPA also collected information through outreach to
stakeholders including industry organizations, environmental
organizations, and state regulators. EPA conducted an extensive review
of published information and participated in industry conferences and
webinars. The following describes EPA's data collection activities that
support the proposed rule.

A. Site Visits and Contacts With Treatment Facilities and Vendors

    EPA conducted seven site visits between May, 2012 and September,
2013 to UOG extraction companies and UOG extraction wastewater
treatment facilities. The purpose of these visits was to collect
information about facility operations, wastewater generation and
management practices, and wastewater treatment and reuse. Six of the
seven visits were to facilities in Pennsylvania, and one was in
Arkansas, however, information collected often covered operations
beyond just those visited during the site visits, at times including
company operations in many UOG formations across the U.S. In addition
to site visits, EPA conducted 11 telephone conferences or meetings with
UOG operators and facilities that treat and/or dispose of UOG
extraction wastewater. EPA collected detailed information from the
facilities visited and contacted, such as information about the
operations associated with wastewater generation, wastewater treatment,
and reuse. EPA also contacted 11 vendors of equipment and processes
used to manage and treat UOG extraction wastewater. EPA prepared site
visit and telephone meeting reports, and telephone call reports
summarizing the collected information. EPA has included in the public
record site visit reports, meeting reports, and telephone contact
reports that contain all information collected for which facilities
have not asserted a claim of CBI.

B. Meetings With Stakeholder Organizations

    Since announcing initiation of this proposed rulemaking activity,
EPA has actively reached out to interested stakeholders to solicit
input from well operators, industry trade associations, interested
regulatory authorities, technology vendors, and environmental
organizations. Stakeholder involvement in the regulatory development
process is essential to the success of this effort. EPA will continue
to engage with the affected regulated sector and concerned stakeholders
throughout the rulemaking process.
1. Stakeholder Organizations
    In addition to the site visit related activities described above,
EPA participated in multiple meetings with industry stakeholders, their
representatives, and/or their members, including America's Natural Gas
Alliance (ANGA), American Petroleum Institute (API) and the Independent
Petroleum Association of America (IPAA). The purpose of the meetings
was to discuss EPA's thinking concerning a pretreatment standard for
the UOG extraction industry, to better understand industry wastewater
management practices, and to gather information to inform its proposed
rulemaking (see DCN SGE00967).
    EPA participated in conference calls with the environmental
stakeholders, Environmental Defense Fund (EDF) and Clean Water Action.
The purpose of these meetings was to explain EPA's thinking about the
standard under development and learn about the perspectives of these
stakeholders regarding wastewater management in the UOG extraction
industry.
    EPA participated in a two conference calls with the Center for
Sustainable Shale Development (CSSD), a collaborative group made up of
environmental organizations, philanthropic foundations, and energy
companies from the Appalachian Basin. The purpose of these calls was to
learn about the performance standards under development by the CSSD for
sustainable shale gas development, based on an ``independent, third-
party evaluation process.''
2. State Stakeholders
    In an effort to improve future implementation of any UOG
regulation, EPA initiated an EPA-State implementation pilot project
coordinated by the Environmental Council of States (ECOS) and the
Association of Clean Water Administrators (ACWA) to draw on experience
of state agency experts. Through this pilot project, EPA has been able
to more thoroughly consider the strengths and weaknesses of different
approaches in order to select one that produces environmental results
while more fully considering implementation burden. This pilot effort
with the states has also been an opportunity to hear ideas on how
technology innovation can be fostered during both development and
implementation of the regulation.
    In addition to the state implementation pilot, EPA also reached out
to EPA regional, as well as state, pretreatment coordinators. One way
EPA did this was by participating in calls, where EPA staff learned
about past or present discharges to POTWs from UOG operations. See DCN
SGE00742; DCN SGE00743.

C. Secondary Data Sources

    EPA conducted an extensive search and review of published
information about UOG development, wastewater generation and management
practices, and wastewater treatment, disposal, and reuse. Because of
the rapid developments in the UOG industry, in addition to reviewing
published information, EPA participated in more than 10 industry
conferences and webinars between March 2012 and June 2014. Presenters
at these conferences provided information about current industry
wastewater management practices. EPA also obtained information from EPA
Regions and states. EPA Region 3 provided information about the
development of the Marcellus shale gas industry and disposal of shale
gas wastewater, including discharges to POTWs.

D. Drilling Info Desktop[supreg] Data Set

    EPA used a propriety database of all oil and gas wells in the U.S.,
called DI Desktop[supreg], obtained from DrillingInfo. This
comprehensive database includes information such as well API number,
operator name, basin (e.g., Western Gulf), formation (e.g., Eagle
Ford), well depth, drilling type (horizontal, directional, vertical),
and completion date. It also includes annual oil, gas, and water
production for each well. EPA primarily used this database to quantify
and identify locations of existing UOG wells, quantify wastewater
generation rates, and supplement geological information (e.g., basin,
formation) in other data sources.

E. EPA Hydraulic Fracturing Study

    At the request of Congress, EPA's Office of Research and
Development is conducting a study to better understand any potential
impacts of hydraulic fracturing on drinking water resources. The scope
of the research includes the full lifecycle of water in hydraulic
fracturing, including wastewater management and disposal. In support of
its study, EPA conducted a series of technical workshops, including,
among others, a workshop on Wastewater Treatment and Related Modeling.
In support of the proposed rule, EPA reviewed information collected in
support of the Congressionally-mandated study and attended meetings,
workshops, and roundtable discussions pertaining to water and
wastewater management and treatment in the UOG extraction industry. See
DCN SGE00063,

DCN SGE00585, DCN SGE00604, DCN SGE00614, DCN SGE00616, DCN SGE00691,
and DCN SGE00721.

X. Description of the Oil and Gas Industry

    Oil and Gas Extraction is the exploration and production of crude
oil and natural gas from wells. Refer to Section XII for additional
background on unconventional gas resources, extraction processes, and
wastewater generation. As explained previously, the scope of this
proposed rulemaking is limited to pretreatment standards for wastewater
generated from unconventional, rather than conventional, oil and gas
extraction facilities. The description here provides a broader
description of the oil and gas industry in order to provide the context
in which the UOG industry lies.

A. Economic Profile

    The major products of the Oil and Gas Extraction Industry are
petroleum, natural gas, and natural gas liquids.\3\ Domestic
consumption of crude oil and petroleum products is met by a combination
of domestic production and imports. Like oil consumption, natural gas
consumption is met both by domestic production and imports of natural
gas, although imports contribute a much lower share of total domestic
consumption for natural gas than for oil. Domestic consumption of
natural gas rose throughout the 1980s and 1990s due to low prices
relative to prices for oil products. This led to investments in
infrastructure for natural gas, especially electric generation
facilities (DCN SGE00809). According to 2012 Energy Information
Administration (EIA) data, 8 percent of the gross domestic supply of
natural gas (from domestic production and imports) was consumed in the
natural gas production and delivery process, as lease and plant fuel (5
percent of total) and fuel for pipeline and distribution services (3
percent of total) (DCN SGE00906). The remaining 92 percent of gross
supply is available to natural gas consumers, and was delivered to the
following sectors: Electrical power (36 percent of total), industrial
(28 percent of total), residential (16 percent of total), commercial
(11 percent of total), and vehicle fuel (0.1 percent of total) (DCN
SGE00906).
---------------------------------------------------------------------------

    \3\ Natural gas can include ``natural gas liquids'' (NGLs),
components that are liquid at ambient temperature and pressure. NGLs
are hydrocarbons--in the same family of molecules as natural gas and
crude oil, composed exclusively of carbon and hydrogen. Ethane,
propane, butane, isobutane, and pentane are all NGLs.
---------------------------------------------------------------------------

    Natural gas can be produced both from conventional natural gas
deposits and unconventional deposits. Natural gas, and especially
unconventional natural gas, has become increasingly significant to the
U.S. energy economy. The rising importance of natural gas results, in
part, from its lower air pollution characteristics compared to other
fossil fuels; its substantial, and increasing, domestic supply; and the
presence of a well-developed processing and transmission/distribution
infrastructure in the U.S. (DCN SGE00010). Increased natural gas
production from shale formations also has the potential to reduce U.S.
dependence on energy-related imports.
    Between 2000 and 2012, total marketed production of natural gas in
the U.S. as a whole grew by another 25 percent, with an average annual
growth rate of 0.8 percent (DCN SGE00908). The sharp rise in production
of shale gas contributed to a lower price of natural gas, thereby
increasing the gap between prices of gas and oil, which made oil a
relatively more attractive option for producers. Beginning in 2005, the
disparity between oil and natural gas prices started to grow as oil
prices continued to rise while natural gas prices declined. Many firms
that produce both gas and oil began to focus on acquisition of, and
production from, liquids-rich formations over natural gas production
(DCN SGE00817, DCN SGE00832).
    Overall, domestic crude oil production steadily declined between
2000 and 2008, while steadily increasing after that. This shift towards
liquids production is evident in the sharp rise in production from
tight oil resources, including shale, beginning in 2008. From 2007 to
2013, the EIA estimated that tight oil production increased 10-fold,
from 0.34 to 3.48 million barrels per day (DCN SGE00902). Future
domestic demand for liquid fuels will depend on the future level of
activities dependent on liquid fuels, such as transportation. Demand
will also be affected by the fuel efficiency of the consumption
technology. The transportation sector will continue to account for the
largest share of total consumption despite its share of total
consumption falling due to improvements in vehicle efficiency. The
industrial sector is the only end-use sector likely to see an increase
in consumption of petroleum and liquids (DCN SGE00913).
    While oil and natural gas are often considered together, the way in
which prices are set for each greatly differs. While the price of oil
is set at the global level, natural gas prices for the U.S. tend to be
set regionally. In recent years, the ratio of oil prices to natural gas
prices has reached historically high levels (DCN SGE00547). While these
two products have some commonalities in their uses, oil and gas are not
perfect substitutes as they require different transportation and
processing infrastructure, and have a number of differentiated uses.
    EPA gathered information on the industry via the NAICS, which is a
standard created by the U.S. Census for use in classifying business
establishments within the U.S. economy. The industry category that
would be affected by this proposed rule is Oil and Gas Extraction
Industry (NAICS 21111). This industry has two subcategories: (1) Crude
Petroleum and Natural Gas Extraction (NAICS 211111), which is made up
of facilities that have wells with petroleum or natural gas or produce
crude petroleum from surface shale or tar sands, and Natural Gas Liquid
Extraction (NAICS 211112), which recover liquid hydrocarbons from oil
and gas field gases and sulfur from natural gas.

B. Industry Structure and Economic Performance

    According to data from the Statistics of U.S. Businesses (SUSB), in
2011 there were 6,528 firms under the overall oil and gas extraction
sector. This reflects a total 2 percent growth from 2000 to 2011 and an
average annual growth rate of 0.2 percent. The Crude Petroleum and
Natural Gas Extraction segment contributed 6,523 (or 99%) firms to the
total Oil and Gas Extraction sector, and the Natural Gas Liquid
Extraction segment contributed 136 (less than 1%) firms to the overall
sector. Although the Natural Gas Liquid Extraction segment is much
smaller in numbers compared to the Crude Petroleum and Natural Gas
Extraction segment, the total percent change in number of firms from
2000 to 2011 is much higher for natural gas liquids extraction at 62%
as compared to 2% for crude petroleum and natural gas extraction. If
the ratio of oil-to-natural gas prices remains high, there could be a
shift towards drilling in liquids-rich shale formations, making this
sector increasingly important to oil and gas extraction firms (DCN
SGE00832; DCN SGE00807; DCN SGE00817; DCN SGE00921).
    In 2011, 99% of the Oil and Gas Extraction Industry was estimated
to be small businesses when using the Small Business Administration
definition of a small business as having 500 or fewer employees.
Average revenues for firms for the overall oil and gas extraction
sector in 2007 were estimated at $54

million. This is an average revenue of $46 million per firm in the
crude petroleum and natural gas extraction segment, and average revenue
of $414 million per firm in the natural gas liquid extraction segment.
The oil and gas extraction sector overall has an average of 18
employees per firm. Breaking it out per segment, the natural gas liquid
extraction segment has an average of 74 employees per firm, whereas the
crude petroleum and natural gas extraction segment shows an average of
17 employees per firm. See the Industry Profile (DCN SGE00932) for more
information.
    The oil market is a globally integrated market with multiple supply
sources that are connected to multiple markets. Because of the
Organization of Petroleum Exporting Countries' (OPEC's) high accounting
of global oil reserves, OPEC is able to place producer quotas on
members in an effort to manage world oil prices. Other oil producers
have relatively smaller reserves and have no influence, individually,
on price (DCN SGE00854). On the other hand, global oil prices are also
greatly influenced by global demand for oil, with the largest sources
of demand being the U.S. and China (DCN SGE00854). While the U.S. is
also one of the largest crude oil producers, it remains a major
importer (demander) of oil; as a result the level of U.S. imports can
significantly influence oil prices. The recent upsurge in U.S. oil
production, largely from tight and shale oil resources, with a
consequent decline in U.S. imports, has exerted downward pressure on
international oil prices.
    In North America, specifically within the U.S., there is a
relatively mature, integrated natural gas market with a robust spot
market for the natural gas commodity. Essentially, the spot market is
the daily market, where natural gas is bought and sold for immediate
delivery. For understanding the price of natural gas on a specific day,
the spot market price is most informative. In U.S. natural gas markets,
natural gas spot prices are determined by overall supply and demand
(DCN SGE00547).
    Large volume consumers of natural gas, mainly industrial consumers
and electricity generators, generally have the ability to switch
between oil and natural gas. When the price of gas is low relative to
oil, these consumers could switch to gas, increasing demand for natural
gas and increasing gas prices. Alternatively, when gas prices are high,
demand could shift in the opposite direction causing a relative
decrease in natural gas prices (DCN SGE00921).

C. Financial Performance

    EPA reviewed financial performance of UOG extraction firms and
other oil and gas firms. EPA found no deterioration in financial
performance and conditions for UOG firms over the previous decade, and
this suggests that UOG firms are well-positioned for continued
investment in UOG exploration and development. The strong growth in
revenue and total capital outlays by the UOG firms during the latter
part of the last decade--which coincides with the growth in UOG
exploration and production activity--underscores the economic
opportunity provided by the emerging UOG resource and the industry's
commitment to investing and producing UOG for the foreseeable future.
See the Industry Profile (DCN SGE00932) for more information.

XI. Scope

    Through the proposed rule, EPA is not reopening the regulatory
requirements applicable to direct dischargers. Rather, EPA would amend
subpart C only to add requirements for indirect dischargers where there
currently are none: Specifically, pretreatment standards for facilities
engaged in oil and gas extraction from UOG sources that send their
discharges directly to POTWs. For purposes of this proposed rulemaking,
EPA proposes to define ``unconventional oil and gas (UOG)'' as ``crude
oil and natural gas \4\ produced by a well drilled into a low porosity,
low permeability formation (including, but not limited to, shale gas,
shale oil, tight gas, tight oil).'' As a point of clarification,
although coalbed methane would fit this definition, the proposed
pretreatment standards would not apply to pollutant discharges to POTWs
associated with coalbed methane extraction. EPA notes that the
requirements in the existing effluent guidelines for direct dischargers
also do not apply to coalbed methane extraction, as this industry did
not exist at the time that the effluent guidelines were developed and
was not considered by the Agency in establishing the effluent
guidelines (DCN SGE00761). To reflect the fact that neither the
proposed pretreatment standards nor the existing effluent guideline
requirements apply to coalbed methane extraction, EPA is expressly
reserving a separate unregulated subcategory for coalbed methane in the
proposed rule. For information on coalbed methane, see http://water.epa.gov/scitech/wastetech/guide/oilandgas/cbm.cfm. The remainder
of the information presented in this document is specific to the UOG
resources subject to the proposed rule.
---------------------------------------------------------------------------

    \4\ Natural gas can include ``natural gas liquids,'' components
that are liquid at ambient temperature and pressure.
---------------------------------------------------------------------------

XII. Unconventional Oil and Gas Extraction: Resources, Process, and
Wastewater

A. Unconventional Oil and Gas Extraction Resources

    For purposes of the proposed rule, UOG consists of crude oil and
natural gas \5\ produced by wells drilled into formations with low
porosity and low permeability. UOG resources include shale oil and gas,
resources that were formed, and remain, in low permeability shale. UOG
resources also include tight oil and gas, resources that were formed in
a source rock and migrated into a reservoir rock such as sandstone,
siltstones, or carbonates. The tight oil/gas reservoir rocks have
permeability and porosity lower than reservoirs of conventional oil and
gas resources but with permeability generally greater than shale. As
described above, while coalbed methane is sometimes referred to as an
unconventional resource, the proposed rule does not apply to this
industry.
---------------------------------------------------------------------------

    \5\ Natural gas can include ``natural gas liquids,'' components
that are liquid at ambient temperature and pressure.
---------------------------------------------------------------------------

B. Unconventional Oil and Gas Extraction Process

1. Well Drilling
    Prior to the well development processes described in the following
subsections, operators conduct exploration and obtain surface use
agreements, mineral leases, and permits. These steps can take a few
months to several years to complete. When completed, operators
construct the well pad and begin the well development process, as
described in the following subsections.
    Drilling occurs in two phases: exploration and development.
Exploration activities are those operations involving the drilling of
wells to locate hydrocarbon bearing formations and to determine the
size and production potential of hydrocarbon reserves. Development
activities involve the drilling of production wells once a hydrocarbon
reserve has been discovered and delineated.
    Drilling for oil and gas is generally performed by rotary drilling
methods, which involve the use of a circularly rotating drill bit that
grinds through the earth's crust as it descends. Drilling fluids (muds)
are injected down through

the drill bit via a pipe that is connected to the bit, and serve to
cool and lubricate the bit during drilling. Drilling fluids can be
water or synthetic based. Synthetic-based drilling fluids are also
referred to as non-aqueous drilling fluids. Air is also used in place
of water or synthetic based drilling fluids for the vertical phase of
wells. The rock chips that are generated as the bit drills through the
earth are termed drill cuttings. The drilling fluid also serves to
transport the drill cuttings back up to the surface through the space
between the drill pipe and the well wall (this space is termed the
annulus), in addition to controlling downhole pressure. As drilling
progresses, pipes called ``casing'' are inserted into the well to line
the well wall. Drilling continues until the hydrocarbon bearing
formations are encountered.
    In UOG resources, the crude oil and natural gas often occur
continuously within a formation. As a result, UOG drilling often
employs ``horizontal drilling.'' Horizontal drilling involves a
sequence of drilling steps: (1) Vertical (described above) and (2)
horizontal. In horizontal drilling, operators drill vertically down to
a desired depth, about 500 feet above the target formation (called the
``kickoff point''), and then gradually turn the drill approximately 90
degrees to continue drilling laterally continuously through the target
formation. UOG wells are also drilled vertically or directionally,\6\
depending on the characteristics of the formation. Directional drilling
is a technique used to drill a wellbore at an angle off of the vertical
to reach an end location not directly below the well pad; horizontal
drilling is considered a type of directional drilling. In UOG well
drilling, well depths range from approximately 1,000 to 13,500 feet
deep (but the majority of wells are drilled between 6,000 and 12,000
feet), wells often have a long horizontal lateral which can vary in
length between 1,000 and 5,000 feet, and it takes approximately 5 to 60
days to complete well drilling. See TDD, Chapter B.3.
---------------------------------------------------------------------------

    \6\ Shale oil and gas wells, are primarily drilled directionally
(and specifically horizontally), while tight oil and gas wells are
drilled vertically and directionally.n
---------------------------------------------------------------------------

2. Well Completion
    Once the target formation has been reached, and a determination has
been made as to whether or not the formation has commercial potential,
the well is made ready for production by a process termed ``well
completion.'' Well completion involves cleaning the well to remove
drilling fluids and debris, perforating the casing that lines the
producing formation \7\, inserting production tubing to transport the
hydrocarbon fluids to the surface, installing the surface wellhead,
stimulating the well, setting plugs in each stage, and eventually
drilling the plugs out of the well and allowing fluids to return to the
surface. During perforation, operators lower a perforation gun into the
stage using a line wire. The perforation gun releases an explosive
charge to create holes that penetrate approximately one foot into the
formation rock in a radial fashion. These perforations create a
starting point for the hydraulic fractures.
---------------------------------------------------------------------------

    \7\ In some instances, open-hole completions may be used, where
the well is drilled into the top of the target formation and casing
is set from the top of the formation to the surface. Open-hole well
completions leave the bottom of the wellbore uncased.
---------------------------------------------------------------------------

    Since UOG resources are extracted from formations with low porosity
and low permeability in which the natural reservoir and fluid
characteristics do not permit the oil and/or natural gas to readily
flow to the wellbore, hydraulic fracturing is often used to complete
the well and extract UOG resources.\8\ Although there are some vertical
and directional UOG wells that are hydraulically fractured, existing
literature indicates that the majority of UOG wells are horizontally
drilled and hydraulically fractured. Therefore, the remainder of this
discussion focuses on the hydraulic fracturing of horizontally drilled
UOG wells; however, all drill types (including vertical and
directional) would be covered by this proposed rule.
---------------------------------------------------------------------------

    \8\ Hydraulic fracturing techniques are also often used to
improve recovery from conventional oil and gas wells. However, the
scope of this section is focused on UOG extraction, therefore, the
application of this process to conventional wells is not further
discussed here.
---------------------------------------------------------------------------

    Hydraulic fracturing involves the injection of fracturing fluids
(e.g., mixtures of water, sand, and other additives) at high pressures
into the well to create small fractures in the rock formation. The
primary component of fracturing fluid is the base fluid into which
proppant (e.g., sand) and chemicals are added. Currently, the most
common base fluid is water; however, other fluids such as liquid
nitrogen and propane (LPG) are also used. Historically, base fluid
consisted exclusively of freshwater, but as more wastewater is
increasingly reused/recycled, base fluid can contain mixtures of fresh
water blended with reused/recycled UOG extraction wastewater. Chemical
additives, used to adjust the fracturing fluid properties, vary
according to the formation, target resource (e.g., shale oil), chemical
composition of base fluid (e.g., volume of reused/recycled wastewater
in base fluid), and operator preference (DCN SGE00721; DCN SGE00070;
DCN SGE00780; DCN SGE00781). Additives commonly include, among other
things, acids (e.g., hydrochloric acid), biocides (e.g.,
glutaraldehyde), friction reducers (e.g., ethylene glycol, petroleum
distillate), and gelling agents (e.g., guar gum, hydroxyethyl
cellulose) (DCN SGE00721; DCN SGE00070; DCN SGE00780; DCN SGE00781).
See TDD, Chapter C.1.
    The amount of fracturing fluid required per well typically depends
on the well trajectory (e.g., vertical, horizontal), well length, and
target resource (e.g., shale oil). UOG wells require between 50,000 to
over ten million gallons of fracturing fluid per well (DCN SGE00532;
DCN SGE00556; DCN SGE00637.A3). Operators typically fracture a
horizontal well in eight to 23 stages using between 250,000 and 420,000
gallons (6,000 and 10,000 barrels) of fracturing fluid per stage (DCN
SGE00280). Literature reports that tight oil and gas wells typically
require less fracturing fluid than shale oil and gas wells (DCN
SGE00533).
    Because laterals in horizontally drilled UOG wells are between
1,000 and 5,000 feet long, operators typically hydraulically fracture
horizontal wells in stages to maintain the high pressures necessary to
stimulate the well over the entire length. Stages are completed
starting with the stage at the end of the wellbore and working back
towards the wellhead.\9\ Operators use anywhere between eight and 23
stages (DCN SGE00280). A fracturing crew can fracture two to three
stages per day when operating 12 hours per day or four to five stages
per day when operating 24 hours per day.\10\ Consequently, a typical
well can take between two and seven days to complete (DCN SGE00239; DCN
SGE00090).
---------------------------------------------------------------------------

    \9\ The first stage is fractured with what is known as the pad
fracture. The pad is the injection of high pressure water and
chemical additives (no proppant) to create the initial fractures
into the formation. After the pad is pumped down hole, proppant is
introduced to the fracturing fluid for the additional stages.
    \10\ The hours per day depends on the operator, local
ordinances, and weather.
---------------------------------------------------------------------------

    Once the stage is hydraulically fractured, a stage plug is inserted
down the wellbore separating it from additional stages until all stages
are completed. After all of the stages have been completed, the plugs
are drilled out of the wellbore allowing the fracturing fluids and
other fluids to return to the surface. At the wellhead,

a combination of liquid (produced water), sand, oil, and/or gas are
routed through phase separators that separate products from wastes.
    A portion of produced water can return to the wellhead at this
time; this waste stream is often referred to as ``flowback'' and
consists of the portion of fracturing fluid injected into the wellbore
that returns to the surface during initial well depressurization often
combined with formation water.\11\ Higher volumes of water are
generated in the beginning of the flowback process. Over time, flowback
rates decrease as the well goes into the production phase. Operators
typically store flowback in 500 barrel fracturing tanks onsite before
treatment or transport offsite.\12\ In addition to flowback, small
quantities of oil and/or gas can be produced during the initial
flowback process. The small quantities of produced gas could be flared
or captured if the operator is using ``green completions'', which
involves capturing the gas rather than flaring.\13\
---------------------------------------------------------------------------

    \11\ Formation water is naturally occurring water contained in
the reservoir rock pores.
    \12\ Fracturing tanks cannot be transported when they contain
wastewater. Wastewater is typically transported via trucks with
approximately 100 to 120 barrel capacities or via pipe (DCN
SGE00635).
    \13\ On April 17, 2012, the U.S. EPA issued regulations under
the Clean Air Act, requiring the natural gas industry to reduce air
pollution by using green completions, or reduced emission
completions. EPA identified a transition period until January 1,
2015 to allow operators to locate and install green completion
equipment (40 CFR part 60 and 63).
---------------------------------------------------------------------------

    The flowback period typically lasts from a few days to a few weeks
before the production phase commences (DCN SGE00010; DCN SGE00011; DCN
SGE00622; DCN SGE00592; DCN SGE00286). At some wells, the majority of
fracturing fluid can be recovered within a few hours (DCN SGE00010; DCN
SGE00011; DCN SGE00622; DCN SGE00592; DCN SGE00286). See TDD, Chapter
B.3.
3. Production
    After the initial flowback period, the well begins producing oil
and/or gas; this next phase is referred to as the production phase.
During the production phase, UOG wells produce oil and/or gas and
generate long-term produced water. Long-term produced water, generated
during the well production phase after the initial flowback process,
consists primarily of formation water and continues to be produced
throughout the lifetime of the well, though typically at much lower
rates than flowback (DCN SGE00592). This long-term produced water is
typically stored onsite in tanks or pits (DCN SGE00280; DCN SGE00275;
DCN SGE00636) and is periodically trucked, or sometimes piped, offsite
for treatment, reuse, or disposal. See TDD, Chapter B.3.

C. UOG Extraction Wastewater

    UOG extraction wastewater, as EPA proposes to define it (see
Section VII.B.) includes the following sources of wastewater
pollutants: \14\
---------------------------------------------------------------------------

    \14\ Stormwater is not considered a source of UOG extraction
wastewater. In general, no permit is required for discharges of
stormwater from any field activities or operations associated with
oil and gas production, except as specified in 40 CFR
122.26(c)(1)(iii) for discharges of a reportable quantity or that
contribute to a violation of a water quality standard.
---------------------------------------------------------------------------

     Produced water--the water (brine) brought up from the
hydrocarbon-bearing strata during the extraction of oil and gas. This
can include formation water, injection water, and any chemicals added
downhole or during the oil/water separation process. Based on the stage
of completion and production the well is in, produced water can be
further broken down into the following components:
    [cir] Flowback--After the hydraulic fracturing procedure is
completed and pressure is released, the direction of fluid flow
reverses, and the fluid flows up through the wellbore to the surface.
The water that returns to the surface is commonly referred to as
``flowback.''
    [cir] Long-term produced water--This is the wastewater generated by
UOG wells during the production phase of the well after the flowback
process. Long-term produced water continues to be produced throughout
the lifetime of the well.
     Drilling wastewater, including pollutants from:
    [cir] Drill cuttings--The particles generated by drilling into
subsurface geologic formations and carried out from the wellbore with
the drilling fluid.
    [cir] Drilling muds--The circulating fluid (mud) used in the rotary
drilling of wells to clean and condition the hole and to counterbalance
formation pressure.
     Produced sand--The slurried particles used in hydraulic
fracturing, the accumulated formation sands and scales particles
generated during production. Produced sand also includes desander
discharge from the produced water waste stream, and blowdown of the
water phase from the produced water treating system.
    EPA identified drilling wastewater and produced water as the major
sources of wastewater pollutants associated with UOG extraction,
therefore, these wastewaters are described further below.
1. Drilling Wastewater
    As discussed in Section XII.B.1., operators inject drilling fluids
down the well bore during drilling to cool the drill bit and to remove
fragments of rock (drill cuttings) from the wellbore (DCN SGE00090; DCN
SGE00274). Drilling fluid can be water or synthetic based. Air has
recently been used in place of drilling fluids in the vertical phase of
wells. Operators can use a combination of drilling fluids and air
during the drilling process of a single well. The drilling fluid used
depends on the properties of the formation, the depth, and associated
regulations, safety, and cost considerations (DCN SGE00090; DCN
SGE00635; TDD Chapter B.3).
    When returned to the surface, ground rock removed from the wellbore
(drill cuttings) is entrained in the drilling fluid. Operators separate
the solids from the drilling fluid on the surface, striving to remove
as much solids (drill cuttings) from the drilling fluid as possible.
The separation process generates two streams: a solid waste stream
referred to as drill cuttings and a liquid waste stream referred to as
drilling wastewater. Operators typically transfer their drill cuttings
to a landfill (DCN SGE00090; DCN SGE00635). Drilling wastewater is
often reused/recycled until well drilling is complete (though in some
cases it is processed for discharge and/or disposal).
    At the end of drilling, operators use a variety of practices to
manage drilling wastewater, primarily reuse/recycle in drilling
subsequent wells. The following list presents drilling wastewater
management options used by UOG operators (DCN SGE00740):
     Reuse/recycle wastewater in subsequent drilling and/or
fracturing jobs \15\
---------------------------------------------------------------------------

    \15\ Synthetic fluids, which are more expensive than water-based
drilling fluid, are almost always reused/recycled in drilling
additional wells.
---------------------------------------------------------------------------

     Disposal via landfill \16\
---------------------------------------------------------------------------

    \16\ Burial and landfill disposal options are generally limited
to ``semisolid'' waste. Solidification processes may occur prior to
transferring the waste to the landfill or they may occur at the
landfill. (DCN SGE00139).
---------------------------------------------------------------------------

     Disposal via underground injection wells
     Land application
     Transfer wastewater to a centralized waste treatment (CWT)
facility
     On-site burial \16\
    Nearly all of the volume of drilling fluid circulated during
drilling is recovered as drilling wastewater and requires management.
Typical drilling wastewater volumes for UOG drilling

vary from 100,000 to 300,000 gallons per well depending primarily on
vertical depth, horizontal length, and the well bore diameter (DCN
SGE00740).
2. Produced Water
a. Flowback
    As explained above, the portion of produced water that returns to
the wellhead after the plugs are drilled out of the wellbore is often
referred to as ``flowback'' and the largest daily volume of produced
water generated occurs during the flowback period. Over time, flowback
rates decrease as the well begins to produce oil and gas. Initially,
flowback has characteristics that can resemble the fracturing fluid.
During the flowback period, the generated wastewater increasingly
resembles characteristics of the underlying formation.
    The volume of flowback produced by a well varies, and it is often
looked at in relation to the volume of the fracturing fluid used to
fracture the well (as explained in Section XII.B.2. above, fracturing
fluid volumes used depend on many factors, including the total number
of stages drilled). Flowback recovery percentages also vary due to
factors such as resource type (e.g., shale oil) and well trajectory and
have been documented anywhere between 3 and 75 percent of the volume of
the fracturing fluid injected, with median flowback recovery between 4
and 29 percent (DCN SGE00724). These percent recoveries can result in
total flowback volumes ranging from less than 210,000 gallons per well
to more than 2,100,000 gallons per well (5,000 to 50,000 barrels per
well) (DCN SGE00724). See TDD, Chapter C. 2.
b. Long-term Produced Water
    After flowback generation, long-term produced water is generated
during the well production phase. Long-term produced water has
characteristics that primarily reflect the formation. The long-term
produced water flow rate from a UOG well gradually decreases over time.
In addition, the amount of produced water generated per well varies by
formation. Median long-term produced water flow rates vary by resource
type (e.g., shale oil) and well trajectory and can be between 200 and
800 gallons per day (4.8 to 19 barrels per day), depending on well
trajectory, formation type and well age (DCN SGE00635; DCN SGE00724).
See TDD, Chapter C.2.

D. UOG Extraction Wastewater Characteristics

    EPA reviewed published characterization data for UOG extraction
wastewater. Produced water data included measurements of TDS, anions/
cations, metals, hardness, radioactive constituents, and organics. The
characteristics of UOG produced water vary primarily depending on the
characteristics of the UOG formation (DCN SGE00090). Drilling
wastewater characterization data included suspended solids, salts,
metals, and organics. Because drilling wastewater is typically
recycled/re-used for drilling another well, detailed pollutant specific
information is less readily available for drilling wastewater than for
produced water. As such, the remainder of this section is specific to
produced water.\17\
---------------------------------------------------------------------------

    \17\ As explained above, produced water includes both flowback
and long-term produced water.
---------------------------------------------------------------------------

1. TDS and TDS-Contributing Ions
    TDS provides a measure of the dissolved matter, including salts
(e.g., sodium, chloride, nitrate), organic matter, and minerals (DCN
SGE00046). TDS is not a specific chemical, but is defined as the
portion of solids that pass through a filter with a nominal pore size
of 2.0 micron ([micro]m) or less (EPA Method 160.1). Table XII-1. shows
ranges and median TDS concentrations associated with various shale and
tight oil and gas formations.

                 Table XII-1--Concentrations of TDS in Produced Waters in Various UOG Formations
----------------------------------------------------------------------------------------------------------------
                                                                                TDS median
   Shale/tight oil and gas formation       TDS concentration range (mg/L)   concentration (mg/   Number of data
                                                                                L)               points
----------------------------------------------------------------------------------------------------------------
Bakken.................................  98,000-220,000...................            150,000                 13
Barnett................................  25,000-150,000...................             50,000                 40
Bradford-Venango-Elk (Tight)...........  32,000-400,000...................            180,000                  5
Cleveland (Tight)......................  84,000-220,000...................            120,000                 11
Cotton Valley/Bossier (Tight)..........  110,000-230,000..................            170,000                  3
Dakota (Tight).........................  2,900-7,700......................              6,000                  3
Devonian...............................  320-250,000......................            130,000                 11
Eagle Ford.............................  3,700-89,000.....................             21,000              1,648
Fayetteville...........................  13,000-57,000....................             25,000                  6
Haynesville/Bossier....................  110,000-120,000..................            120,000                  2
Marcellus..............................  680-350,000......................             92,000                383
Mississippi Lime (Tight)...............  .................................            150,000                  1
New Albany.............................  .................................             88,000                  1
Niobrara...............................  39,000-140,000...................            100,000                  8
Pearsall...............................  300,000-380,000..................            370,000                  3
Spraberry (Tight)......................  58,000-160,000...................            130,000                 26
Utica..................................  6,500-44,000.....................             16,000                  8
Woodford-Cana-Caney....................  14,000-110,000...................             36,000                  8
----------------------------------------------------------------------------------------------------------------
Source: See TDD, Chapter C.3.

    Salts are the majority of TDS in UOG produced water, and sodium
chloride constitutes approximately 50 percent of the TDS in UOG
produced water (DCN SGE00046). In addition to sodium and chloride, UOG
produced water typically contains divalent cations such as calcium,
strontium, magnesium, and, in some formations, barium and radium. Other
ions such as potassium, bromide, fluoride, nitrate, nitrite, phosphate,
and sulfate can also contribute to TDS in UOG produced water. Metals,
other than those contributing to TDS (e.g., calcium, magnesium,
strontium), are typically

not found in high concentrations in UOG produced water. Table XII-2.
presents ranges and median concentrations of TDS and TDS-contributing
ions in UOG produced water. Based on available data, concentrations of
TDS and TDS-contributing ions, including divalent cations, typically
increase from flowback to long-term produced water. See TDD, Chapter
C.3.

               Table XII-2--Concentrations of TDS and TDS-Contributing Ions in UOG Produced Waters
----------------------------------------------------------------------------------------------------------------
                                                                                Median
              Constituent                    Concentration range (mg/L)     concentration (mg/   Number of data
                                                                                L)               points
----------------------------------------------------------------------------------------------------------------
TDS....................................  20-400,000.......................            110,000              2,223
Chloride...............................  64-230,000.......................             48,000              2,063
Sodium.................................  64-98,000........................             25,000              1,913
Calcium................................  13-34,000........................              3,400              2,068
Strontium..............................  0-8,000..........................                580                207
Magnesium..............................  3-15,000.........................                570              2,030
Bromide................................  0.2-4,300........................                540                119
Potassium..............................  0-5,800..........................                290                344
Barium.................................  0-16,000.........................                100                289
Sulfate................................  0-3,400..........................                 71              1,585
Phosphate..............................  12-88............................                 12                  3
Nitrate................................  5-10.............................                  5                  3
Nitrite................................  .................................                  5                  2
Fluoride...............................  0.045-390........................                2.5                 99
----------------------------------------------------------------------------------------------------------------
Source: See TDD, Chapter C.3.

2. Organic Constituents
    Organic constituents in UOG produced water can originate from both
the fracturing fluid that is injected down the wellbore and from the
UOG formation itself. Organic constituents and hydrocarbons in UOG
produced water appear to be less frequently sampled in comparison to
the well-documented TDS concentrations. EPA has reviewed available data
on organic pollutants in produced water and found a range of pollutant
concentrations: phenol (0.7 to 460 parts per billion (ppb)), pyridine
(1.1 to 2,600 ppb), benzene (0.99 to 800,000 ppb), ethyl benzene (0.63
to 650 ppb), toluene (0.91 to 1,700,000 ppb), and total xylenes (3 to
440,000 ppb) (DCN SGE00724). See TDD, Chapter C.3.
3. Radioactive Constituents
    Oil and gas formations contain varying levels of radioactivity
resulting from uranium decay which can be transferred to UOG produced
water. Radioactive decay products typically include uranium 238, radium
226, and radium 228. EPA identified available data on some radioactive
elements in UOG produced water, including radium 226, radium 228, gross
alpha, and gross beta, and, therefore, focused the radioactive
constituent discussion and data presentation on data for these
parameters. Radium 226, which has a half-life over 1,000 years, has
been found in UOG produced water at concentrations up to 16,900
picocuries per liter (pCi/L) (DCN SGE00241; DCN SGE00724). As a point
of comparison, the International Atomic Energy Agency (IAEA) published
a report in 2014 that included radium isotope concentrations in rivers
and lakes. The average of measured concentrations of radium 226 found
in U.S. rivers and lakes was 0.56 pCi/L (21 millibecquerel per liter
(mBq/L)) and the measured values ranged from 0.01 to 1.7 pCi/L (0.37 to
63 mBq/L) (DCN SGE00769). Data for radium 228 were limited.
    Data characterizing produced water radioactivity concentrations
were not available for all shale and tight oil and gas formations.
However, the available data \18\ from five different tight or shale oil
and gas formations show that the concentrations of one or more
radioactive constituents (radium 226, radium 228, gross alpha, gross
beta) in UOG produced water was above naturally occurring
concentrations in rivers and lakes throughout the world. The highest
reported radium 228 value was in the Ganges River in India and was
measured at 0.07 pCi/L (2.6 mBq/L). (See DCN SGE00769)
---------------------------------------------------------------------------

    \18\ A report was released by the Pennsylvania Department of
Environmental Protection, titled ``Technologically Enhanced
Naturally Occurring Radioactive Materials (TENORM) Study Report'' on
January 15, 2015. These data have not yet been incorporated into
EPA's analyses. The report presents additional data for the
Marcellus Shale formation, which is one of the five formations for
which EPA has identified additional data sources. See TDD Chapter
C.3 and DCN SGE00933.
---------------------------------------------------------------------------

E. Wastewater Management and Disposal Practices

    Historically, UOG operators primarily managed their wastewater
using the following four methods: \19\
---------------------------------------------------------------------------

    \19\ Occasionally, UOG operators in the western U.S. may use
evaporation as a means of wastewater management.
---------------------------------------------------------------------------

     Disposal via underground injection wells;
     Reuse in subsequent fracturing jobs;
     Transfer to a POTW; or
     Transfer to a privately owned wastewater treatment
facility (also called a CWT facility).\20\
---------------------------------------------------------------------------

    \20\ Operators may haul wastewater to CWT facilities that handle
the wastewater by (1) treating for reuse; (2) direct discharging to
surface water; or (3) indirect discharging to surface water through
a POTW.
---------------------------------------------------------------------------

    (DCN SGE00613; DCN SGE00276); DCN SGE00528).
    The frequency with which UOG operators use each of the management
options listed above varies by operator, formation, and sometimes
within each region of the formation (DCN SGE00579; DCN SGE00276).
Relative cost is also an important factor for an UOG operator when
considering how to manage their wastewater. This proposed rule
addresses only transfers to a POTW. Historically, the oil and gas
industry has most commonly managed its wastewater by underground
injection (DCN SGE00182), but the industry is increasingly turning to
reuse, and in some areas transfer to CWT facilities, to manage
increasing volumes of UOG extraction wastewater (see TDD, Chapter D).

1. Injection into Disposal Wells
    Underground injection involves pumping wastes into a deep
underground formation with a confining layer of impermeable rock. The
receiving formation must also be porous enough to accept the
wastewater. In previous decades, and in most oil and gas basins,
drillers found underground injection of oil and gas extraction
wastewater to be the most economical and reliable means of disposal;
this is similarly the case today (DCN SGE00623). As of 2009, over 90
percent of oil and gas wastewater (conventional and unconventional) was
disposed of via Class II injection wells (DCN SGE00623; DCN SGE00132).
    The availability of underground injection as a disposal method
varies by state. Some states have a large number of Class II disposal
wells (e.g., Texas, Oklahoma, Kansas) while others have very few (e.g.,
Pennsylvania, West Virginia). In many UOG formations, distances from
the average producing well to the nearest disposal well are short and
disposal capacity is abundant making it the least expensive disposal
practice (DCN SGE00635).
2. Reuse in Fracturing
    Reuse involves mixing flowback and/or long-term produced water from
previously fractured wells with source water \21\ to create the base
fluid used to fracture a new well (DCN SGE00046). Reused UOG extraction
wastewater is typically transported, by truck, from storage to the
fracturing site just prior to the start of hydraulic fracturing. When
hydraulic fracturing commences, the stored UOG wastewater is pumped
from the fracturing tanks and blended with source water to form the
base fluid. The blending occurs upstream of other steps such as sand
and fracturing chemical addition or pressurization by the pump trucks
(DCN SGE00625).
---------------------------------------------------------------------------

    \21\ Source waters may include freshwater, ground water, treated
municipal wastewater, and other industrial wastewater.
---------------------------------------------------------------------------

    In considering whether to reuse wastewater, operators evaluate
wastewater generation rates compared to water demand for new fracturing
jobs, water quality and treatment requirements for use in fracturing,
and the risks and costs of wastewater management and transportation for
reuse compared to disposal, or transfer practices. Typically, for an
operator to reuse wastewater, the cost per barrel for reuse must be
less than the cost per barrel for disposal or transfer (DCN SGE00095).
The cost for reuse depends on several factors that vary by formation
and operator; and, therefore, the potential for reusing UOG extraction
wastewater for fracturing varies by formation and operator.
    Since the late 2000s, UOG operators have increased wastewater reuse
(DCN SGE00613). The Petroleum Equipment Suppliers Association (PESA)
surveyed 205 UOG operators in 2012 about their wastewater management
practices. Survey results included 143 operators active in major UOG
formations. UOG operators reported reusing 23 percent of the total
volume of wastewater generated to refracture another well. The survey
results also showed that most operators anticipated reusing higher
percentages of their wastewater in the two to three years following the
survey (DCN SGE00707; DCN SGE00708; DCN SGE00575). EPA participated in
several site visits and conference calls with operators in several UOG
formations that have been able to reuse 100 percent of the volume of
their wastewater under certain circumstances (DCN SGE00625; DCN
SGE00635; DCN SGE00275; DCN SGE00636).
3. Transfer to Centralized Waste Treatment Facilities
    Some operators manage UOG extraction wastewater by transporting it
to CWT facilities for treatment. Following treatment, these facilities
can return it to an operator for reuse to fracture another well (``zero
discharge'') and/or discharge it, either to surface water or to a POTW.
Operators can choose to use CWT facilities if they drill and complete
relatively few wells, making discharging to CWT facilities more
feasible than investing in other management options (DCN SGE00300), or
if other wastewater management options are not available or cost
effective in the region where they are operating (DCN SGE00139; DCN
SGE00182). EPA identified 73 commercial CWT facilities that accept UOG
extraction wastewater. See TDD, Chapter D.3. EPA found that the number
of CWT facilities available to operators in the Marcellus and Utica
Shale formations has increased with the number of wells drilled. A
similar trend was observed in the Fayetteville Shale formation in
Arkansas (DCN SGE00704).
    Operators can haul their wastewater to ``zero discharge'' CWT
facilities that treat but do not discharge UOG extraction wastewater,
either to surface water or to a POTW. Instead, they return the
wastewater to UOG operators for reuse in subsequent hydraulic
fracturing jobs. Commercial CWT facilities that fall into this category
typically allow operators to unload a truck load of wastewater for
treatment and take a load of treated wastewater on a cost per barrel
basis (DCN SGE00245). Some of these facilities offer operators the
option of unloading a truck load of wastewater without taking a load of
treated wastewater for a surcharge, as long as other operators are in
need of additional treated wastewater. The CWT facility can also
provide this service if it can dispose of the wastewater without
discharge (DCN SGE00299). For example, one facility in Wyoming treats
UOG extraction wastewater for reuse by removing TDS and other
pollutants through electrocoagulation followed by reverse osmosis (RO).
The facility evaporates the concentrated brine from the RO unit in
large evaporation ponds to dispose of wastewater not reused by
operators (DCN SGE00374).
    Some operators can haul their wastewater to CWT facilities that
discharge directly to surface waters. Discharges from these CWT
facilities are controlled by NDPES permits that include pollutant
discharge limitations based on the technology-based ELGs set out in 40
CFR part 437 (representing the floor), or more stringent WQBELs where
the technology-based effluent limits are not sufficiently stringent to
meet applicable state water quality standards. The ELGs established by
EPA for CWTs do not include limitations for TDS; however, to meet
applicable state water quality standards, direct discharging CWT
facilities can use treatment processes (e.g., evaporation/condensation,
reverse osmosis) that remove TDS.
    Finally, other operators can haul their wastewater to CWT
facilities that discharge indirectly to a POTW. Discharges from the CWT
facility to the POTW are controlled by an Industrial User Agreement
(IUA) that must incorporate the pretreatment standards set out in 40
CFR part 437.
4. Transfer to POTWs
    Historically, in locations such as in Pennsylvania where disposal
wells and CWT facilities were limited, operators managed UOG extraction
wastewater by transfer to POTWs (DCN SGE00011; DCN SGE00739; DCN
SGE00598). This practice can be problematic because POTWs are not able
to remove many of the constituents found in UOG extraction wastewater
(DCN SGE00011; DCN SGE00600; DCN SGE00765). Because they are not
typical of POTW influent wastewater, UOG extraction wastewater
constituents can be discharged, largely untreated, from the POTW to the
receiving stream; can disrupt the operation of the POTW (e.g., by
inhibiting biological treatment); can accumulate in biosolids, limiting
their

use; and can facilitate the formation of harmful DBPs (which are a
concern for downstream drinking water uses). These constituents can
interfere with POTW operations and can increase salt loads in receiving
streams to the detriment of downstream water use. (DCN SGE00286; DCN
SGE00345; DCN SGE00579; DCN SGE00531; DCN SGE00633). See TDD, Chapter
D.5. As discussed above, EPA has not been able to identify any existing
UOG discharges at present to POTWs (DCN SGE00579; DCN SGE00286; DCN
SGE00345). The lack of existing discharges to POTWs can be attributed
to the availability of one or more cost effective alternative
wastewater management options (injection for disposal, reuse/recycling,
and transfer to a CWT), concerns about inability of POTWs to treat such
waste appropriately, and concerns that such discharges can disrupt POTW
treatment processes. In a few cases, they can also be associated with
state-level drivers (see TDD Chapter A.2).

XIII. Subcategorization

    In developing ELGs, EPA can divide an industry category into
groupings called ``subcategories'' to provide a method for addressing
variations among products, processes, and other factors, which result
in distinctly different effluent characteristics that affect the
determination of the ``best available'' technology. See Texas Oil & Gas
Ass'n. v. U.S. EPA, 161 F.3d 923, 939-40 (5th Cir. 1998). Regulation of
a category by subcategories provides that each subcategory has a
uniform set of effluent limitations or pretreatment standards that take
into account technological achievability, economic impacts, and non-
water quality environmental impacts unique to that subcategory. In some
cases, effluent limitations or pretreatment standards within a
subcategory can be different based on consideration of these same
factors, which are identified in CWA section 304(b)(2)(B). The CWA
requires EPA, in developing effluent guidelines and pretreatment
standards, to consider a number of different factors, which are also
relevant for subcategorization. The CWA also authorizes EPA to take
into account other factors that the Administrator deems appropriate.
CWA section 304(b).
    Within the oil and gas extraction category, EPA has already
established subcategories. As explained in Section VIII.C., the
existing oil and gas extraction ELGs are divided into five
subcategories. The scope of the proposed rule is specific to subpart C:
onshore. The proposed rule is specific to pollutant discharges from UOG
extraction as defined in Section XI. EPA considered whether further
subcategorization of the UOG extraction industry was warranted. EPA
evaluated a number of factors including available data regarding
wastewater chemical constituents, generation volumes, and rates.
Although some differences can be observed among these characteristics
(between different types of unconventional resource and geologic
formations, and sometimes between wells within the same source), EPA
proposes that further subcategorization is not appropriate because EPA
has not identified any onshore UOG operations that currently discharge
to POTWs.

XIV. Proposed Regulation

A. Discussion of Options

1. PSES and PSNS Option Selection
    EPA proposes to establish PSES and PSNS that apply to wastewater
discharges from onshore UOG extraction facilities. Generally, EPA
designs PSES and PSNS to ensure that wastewaters from direct and
indirect industrial dischargers are subject to similar levels of
treatment prior to discharge to waters of the U.S. This means that,
typically, the requirements for indirect dischargers are analogous to
those for direct dischargers. As explained in Section VIII.C., the
existing requirements for BPT for the Onshore Subcategory are zero
discharge of wastewater pollutants into waters of the U.S. from any
source associated with production, field exploration, drilling, well
completion, or well treatment. As also explained in Section VIII.C.,
the existing BPT requirements do not apply to discharges to POTWs.
    Most POTWs are designed primarily to treat municipally generated
wastewater. POTWs typically provide at least secondary level treatment
and, thus, are designed to remove settleable solids, suspended solids
and organic material using biological treatment. EPA is not aware of
any POTWs that are designed to treat dissolved pollutants in UOG
extraction wastewater such as TDS (e.g., chlorides, sulfates, metals)
or radioactive elements. As a result, the mass of untreated pollutants
would be discharged from the POTW to the receiving water, could disrupt
the operation of the POTW (e.g., by inhibiting biological treatment) or
could facilitate the formation of harmful DBPs.
    As explained in Section XII.E., EPA evaluated the practices
currently used to manage UOG extraction wastewaters. Based on the
information reviewed as part of this proposed rulemaking, EPA
identified that current industry practice is not to discharge
pollutants from onshore UOG extraction to POTWs. Rather, the vast
majority of this wastewater is managed by disposal in underground
injection wells and/or re-use in fracturing another well.\22\ A small,
but in some geographic areas increasing, portion of the industry also
transfers its wastewater to privately owned wastewater treatment
facilities (also referred to as CWT facilities).
---------------------------------------------------------------------------

    \22\ While pollutant discharges from onshore oil and gas
extraction produced water are allowed under subpart E in certain
geographic locations for use in agriculture or wildlife propagation,
EPA has not found that these types of permits are typically written
for unconventional oil and gas extraction wastewater (as defined for
the proposed rule).
---------------------------------------------------------------------------

    Because of this information, EPA identified one candidate PSES/PSNS
option; that is, zero discharge of wastewater pollutants to POTWs. UOG
extraction wastewater is discussed in Section XII.C.
    The technology basis for the proposed PSES is disposal in UIC wells
and/or wastewater reuse/recycling to fracture another well. Because
existing UOG extraction facilities currently employ alternative
wastewater management practices, the technology basis for meeting a
zero discharge requirement is widely available. While EPA estimates
that there will be no incremental pollutant reductions associated with
the proposed PSES, the technology basis is best performing in that it
achieves zero discharges of pollutants in UOG extraction wastewater.
Additionally, because this technology represents current industry
practice nationwide, no facilities will incur incremental costs for
compliance with the proposed PSES and, therefore, the proposed PSES is
economically achievable. For the same reasons, the proposed PSES will
result in no incremental non-water quality environmental impacts.
Finally, because the proposal represents current industry practice, EPA
proposes that PSES requiring zero discharge of wastewater pollutants be
effective as of the effective date of this rule.
    As previously noted, under section 307(c) of the CWA, new sources
of pollutants into POTWs must comply with standards which reflect the
greatest degree of effluent reduction achievable through application of
the best available demonstrated control technologies. Congress
envisioned that new treatment systems could meet tighter controls than
existing sources because of the opportunity to incorporate the most
efficient processes and treatment systems into the facility design. EPA
proposes PSNS that would control the same pollutants using the same
technologies proposed for control by PSES. The technologies used to
control

pollutants at existing sources, disposal in UIC wells and/or wastewater
reuse/recycling to fracture another well, are fully available to new
sources. They achieve the greatest degree of effluent reduction
available: zero discharge of pollutants in UOG extraction wastewater.
Furthermore, EPA has not identified any technologies that are
demonstrated to be available for new sources that are different from
those identified for existing sources. Finally, EPA determined that the
proposed PSNS present no barrier to entry into the market for new
sources. While EPA cannot say with certainty exactly how new sources
will manage their UOG extraction wastewater, information in the record
indicates that new sources would manage their UOG extraction wastewater
following current industry practice. EPA has found that overall impacts
from the proposed standards on new sources would be minimal, as is the
case for existing sources, since the costs faced by new sources
generally will be the same as those faced by existing sources. EPA
projects no (and, therefore, acceptable) incremental non-water quality
environmental impacts. Therefore, EPA proposes to establish PSNS that
are the same as the proposed PSES.
2. Other Options Considered
a. ``No Rule''
    In addition to the PSES/PSNS option of zero discharge of wastewater
pollutants, EPA also considered the option of no proposed PSES or PSNS,
a ``no rule'' option. Based on the discussion above that no UOG
facilities are currently transferring wastewater to POTWs, and given
available alternative management options such as disposal in UIC wells
and reuse/recycling, EPA considered the option of no proposed rule. A
``no rule'' option would impose no change to the existing pretreatment
regulatory regime, or industry practice, and would, therefore, be a
``no incremental cost and pollutant reduction'' option.
    EPA, however, did not select this ``no rule'' option for several
reasons. First, there is no national federal regulation that would
prevent or require pretreatment of such discharges--and, as mentioned
above, EPA is not aware of any POTWs that are designed to treat
dissolved pollutants common in UOG extraction wastewater. This means
that constituents of such wastewater could be discharged to receiving
waters when other [available] options such as reuse and proper disposal
in a Class II UIC well better protect water quality and aquatic
communities and help further the zero discharge goal of the CWA. CWA
section 101(a)(1). Second, as detailed in Chapter A.2 of the TDD, few
states have regulations or policies that prevent discharges of
pollutants in UOG extraction wastewater to POTWs or that mandate pre-
treatment prior to discharge to a POTW. In the absence of such
regulations or policies, resource-constrained control authorities and/
or POTWs who receive requests to accept UOG extraction wastewater would
be in the position of having to evaluate whether to accept transfers of
wastewater on a case-by-case basis. Third, history demonstrates that
absent controls preventing the transfer of or requiring pretreatment of
such wastewater, POTWs can accept it, as occurred in Pennsylvania (see
TDD Chapters A.2 and D.5), where POTWs were used to manage UOG
extraction wastewater until the state took action, including
promulgating new regulations requiring pretreatment. Among the drivers
behind these actions taken by Pennsylvania was that some waters were
impaired by TDS. (DCN SGE00187).
    To avoid future scenarios where POTWs receive UOG extraction
wastewater, it is reasonable to codify the good practice already
adopted by the industry that is technologically and economically
viable. Moreover, it is beneficial to the states as a practical matter
to establish federal regulations that mandate this existing practice,
in order to avoid the burden for each state to potentially repeat the
effort of promulgating state-level regulations. EPA has discussed this
proposed rule with several states, who have indicated that a federal
pretreatment standard would reduce their administrative burden (DCN
SGE00762; DCN SGE00762; DCN SGE00743).
    EPA also considered the future burden that continued lack of
pretreatment standards can impose on POTWs. The UOG extraction industry
is predicted to continue to grow in the future, resulting in the
installation, fracturing, and possible refracturing of hundreds of
thousands of wells. Well operators will continue to generate UOG
extraction wastewater and could request local POTWs to accept their
wastewater for discharge. In the absence of federal pretreatment
standards, POTWs can legally accept UOG extraction wastewater to the
extent that such wastewater transfers are in compliance with state and
local requirements. Evaluating each potential customer (industrial
user), developing a determination for each new UOG extraction
wastewater source on a case-by-case basis could be burdensome for
POTWs. In addition, where a POTW determines it can accept this
wastewater, complying with applicable reporting requirements could be a
significant burden to some POTWs. EPA concluded that a national-level
determination that UOG extraction wastewater contains pollutant
concentrations that could pass through POTWs, and development of
categorical pretreatment standards, will avoid burdening individual
POTWs with evaluating each individual request. Thus, the national
categorical pretreatment standards will reduce the process burden on
pretreatment Control Authorities (e.g., POTWs). While EPA does not have
the information to quantify the reductions in administrative burden
that will likely result from the proposed rule, states generally
support EPA's position that such reductions will be realized (DCN
SGE00762; DCN SGE00762; DCN SGE00743).
    Moreover, as explained above, because some pollutants of concern in
UOG extraction wastewater will not be physically, chemically, or
biologically reduced by the treatment processes typically used at
POTWs, these pollutants are expected to be discharged from the POTW
into receiving waters. In addition, these pollutants can cause
operational problems for the POTW's biological treatment processes and
alter the POTW's ability to adequately remove BOD, TSS, and other
pollutants for which it is regulated. For some UOG pollutants, such as
radionuclides, the data indicate POTWs will remove some portion while
discharging the remainder (DCN SGE00136). In these cases, some portion
of the radionuclides will partition to the POTW biosolids, which can
cause the POTW to incur increased costs to change its selected method
of biosolids management (DCN SGE00615). See also TDD Chapter D.5.
    Finally, EPA did not select the ``no rule'' option because it
concluded that national pretreatment standards provide clear direction
and certainty to industry, POTWs, states, and the public that UOG
extraction wastewaters are not treated by POTWs and should not be
transferred to them. Categorical pretreatment standards support the CWA
goal that the discharge of pollutants into the nation's navigable
waters be eliminated. CWA section 101(a).
b. Non-Zero Numeric Discharge Pretreatment Requirements
    EPA considered an option that would have included non-zero
numerical discharge pre-treatment requirements prior to discharge to a
POTW. Such an

option could be similar to the one adopted in Pennsylvania in 2010 that
requires pretreatment of oil and gas wastewaters before discharge to a
POTW to meet a maximum TDS concentration of 500 mg/L as well as
specific numerical concentrations for other pollutants. Some have
suggested this would provide an ``escape-valve'' for the future in the
event that UIC disposal well capacity is exhausted. Others have
suggested this would allow the water to be available for re-use (other
than in fracturing another well) if technologies become available to
pre-treat it to remove dissolved pollutants in a cost effective manner.
    EPA does not propose an option with numerical discharge
pretreatment requirements prior to discharge to a POTW for the
following reasons. First, the existing requirements for direct
discharges of UOG extraction wastewater in the Onshore Subcategory
require no discharge of pollutants. As explained above, EPA generally
establishes requirements for direct and indirect discharges so that the
wastewater receives comparable treatment prior to discharge to waters
of the U.S.
    Second, the option EPA proposes, zero discharge of pollutants in
UOG extraction wastewater to POTWs, is widely available, economically
achievable and has no incremental (and, therefore, acceptable) non-
water quality environmental impacts. Because the proposed zero
pollutant discharge requirement is current practice and, therefore,
clearly both available and achievable, any option that includes non-
zero discharge requirements for any pollutants would potentially