
[Federal Register Volume 80, Number 66 (Tuesday, April 7, 2015)]
[Proposed Rules]
[Pages 18557-18580]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2015-07819]


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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.

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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: OW-Docket@epa.gov, 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 202-566-2426.
    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,

[[Page 18558]]

and the telephone number for the Water Docket is 202-566-2426.
    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: biddle.lisa@epa.gov. For economic information, contact 
Karen Milam, Engineering and Analysis Division, Telephone: 202-566-
1915; email: milam.karen@epa.gov.

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:

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

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

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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.
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    \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)
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    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

[[Page 18561]]

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

[[Page 18562]]

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

[[Page 18563]]

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

[[Page 18564]]

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,

[[Page 18565]]

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

[[Page 18566]]

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.
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    \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

[[Page 18567]]

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.
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    \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.
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    \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,

[[Page 18568]]

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\
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    \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\
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    \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

[[Page 18569]]

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

[[Page 18570]]

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\
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    \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).

[[Page 18571]]

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

[[Page 18572]]

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

[[Page 18573]]

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

[[Page 18574]]

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 
increase pollutant discharges from current industry best practices. 
Such an option would not fulfill the CWA requirement to establish 
limitations based on ``Best Available Technology Economically 
Achievable'' (CWA section 301(b)(2)(A)), or the CWA goals of 
eliminating the discharge of pollutants into navigable waters (CWA 
section 101(a)(1)).
    Third, EPA does not have any data to demonstrate that UIC capacity 
nationwide will be expended and that this current management approach 
will not be available in the future (DCN SGE00613). In fact, industry 
has been managing oil and gas extraction wastewater through underground 
injection for decades. In recent years, industry has greatly expanded 
its knowledge about the ability to re-use UOG flowback and long-term 
produced water (the major contributors to UOG extraction wastewater by 
volume) in fracturing another well. Consequently, while the UOG 
industry continues to grow and new wells are being fractured, the need 
for UIC capacity for UOG extraction wastewater is decreasing, even in 
geographic locations with an abundance of UIC capacity (see TDD Chapter 
D.2).
    Fourth, EPA identified technologies that currently exist to treat 
dissolved pollutants in UOG extraction wastewater. Relative to 
underground injection and reuse/recycling to fracture another well (the 
basis for the preferred option EPA proposes), these technologies are 
costly, would result in more pollutant discharges, and are energy 
intensive. While EPA did not attempt to calculate a numerical standard 
for TDS, data collected for this proposed rulemaking demonstrate that 
the current technologies are capable of reducing TDS (and other 
dissolved pollutants) well below 500 mg/L. To the extent that these 
technologies or others are developed in the future to reduce pollutants 
in UOG extraction wastewater to enable them to be reused for purposes 
other than fracturing another well, these pre-treated wastewaters can 
be used directly for the other applications without going through a 
POTW.\23\
---------------------------------------------------------------------------

    \23\ As a point of clarification, except in certain geographic 
areas, these wastewaters would remain subject to the requirements in 
the Onshore Subcategory that require no discharge of pollutants to 
waters of the U.S. (40 CFR 435.30).
---------------------------------------------------------------------------

c. Conventional Oil and Gas Wastewater
    As explained in Section VIII., while the existing oil and gas 
regulation applies to both conventional and UOG extraction (except 
coalbed methane), the proposed rule would add pretreatment standards 
only for facilities engaged in oil and gas extraction from UOG sources 
that send their discharges to POTWs. EPA proposes to reserve standards 
for conventional oil and gas extraction for possible future rulemaking, 
if appropriate. This is consistent with EPA's stated scope throughout 
the development of this proposed rule. See specific comment 
solicitation on conventional oil and gas extraction wastewaters in 
Section VII.

B. Pollutants of Concern

    Since the effectiveness of the technology basis for the proposed 
standards results in zero discharge of all pollutants, it is not 
appropriate in this proposed rule to further specify the pollutants of 
concern. Rather, as is the case for the existing BPT requirements, the 
proposed PSES/PSNS apply to the discharge of all pollutants in UOG 
extraction wastewater.

C. POTW Pass Through Analysis

    Sections 307(b) and (c) of the CWA authorize EPA to promulgate 
pretreatment standards for pollutants that are not susceptible to 
treatment by POTWs or which would interfere with the operation of 
POTWs. EPA looks at a number of factors in selecting the technology 
basis for pretreatment standards for existing and new sources. These 
factors are generally the same as those considered in establishing the 
direct discharge technology basis. However, unlike direct dischargers 
whose wastewater will receive no further treatment once it leaves the 
facility, indirect dischargers send their wastewater to POTWs for 
further treatment.
    Therefore, before establishing PSES/PSNS for a pollutant, EPA 
examines whether the pollutant ``passes through'' a POTW to waters of 
the U.S. or interferes with the POTW operation or biosolids disposal 
practices. In determining whether a pollutant would pass through POTWs 
for these purposes, EPA generally compares the percentage of a 
pollutant removed by well-operated POTWs performing secondary treatment 
to the percentage removed by a candidate technology basis. A pollutant 
is determined to pass through POTWs when the median percentage removed 
nationwide by well-operated POTWs is less than the median percentage 
removed by the candidate technology basis. Pretreatment standards are 
established for those pollutants regulated under the direct discharge 
level of control (typically BAT/NSPS) that passes through. In addition, 
EPA can regulate pollutants that do not pass through but otherwise 
interfere with POTW operations or biosolids disposal practices. This 
approach to the definition of pass through satisfies two competing 
objectives set by Congress: (1) That standards for indirect dischargers 
be equivalent to standards for direct dischargers, and (2) that the 
treatment capability and performance of POTWs be recognized and taken 
into account in regulating the discharge of pollutants from indirect 
dischargers.
    Historically, EPA's primary source of POTW removal data is its 1982 
``Fate of Priority Pollutants in Publicly Owned Treatment Works'' (also 
known as the 50 POTW Study) (see DCN SGE00765). The 50 POTW study 
presents data on the performance of 50 POTWs achieving secondary 
treatment in removing certain toxic pollutants. While the 50 POTW study 
demonstrates a wide variability in the effectiveness of POTWs in 
removing toxic pollutants, it demonstrates that POTWs remove these 
pollutants by less

[[Page 18575]]

than 100%. Although this study does not contain information on 
pollutant removals for TDS, as explained earlier, secondary treatment 
technologies are generally understood to be ineffective at removing TDS 
and as such little to no TDS removals are likely to occur at POTWs 
through secondary treatment (DCN SGE00011; DCN SGE00600). While the 
POTW study also does not contain information for other pollutants that 
may be present in UOG extraction wastewater, it is reasonable for EPA 
to conclude that removal of UOG extraction wastewater pollutants by a 
well-operated POTW would be less than 100%, the percentage removal by 
the candidate technology basis for the proposed rule, and therefore 
would if discharged to a POTW ``pass through'' the POTW, as the term 
applies under the CWA, into waters of the U.S.

XV. Environmental Impacts

    UOG production generates significant volumes of wastewater that 
need to be managed. As described in Section XII.C.2, wells can produce 
flowback volumes ranging between 210,000 and 2,100,000 gallons during 
the initial flowback process.\24\ During the production phase, wells 
typically produce smaller volumes of water (median flow rates range 
from 200-800 gallons per day) and continue producing wastewater 
throughout the life of the well.
---------------------------------------------------------------------------

    \24\ As explained in the TDD (Chapter B) the length of the 
flowback process is variable. Literature generally reports it as 30 
days or less (DCN SGE00532).
---------------------------------------------------------------------------

    In general, evidence of environmental impacts to surface waters 
from discharges of UOG extraction wastewater is sparsely documented. 
Some of the environmental impacts documented to date, such as increased 
DBP formation in downstream drinking water treatment plants, resulted 
from wastewater pollutants that passed untreated through POTWs in 
Pennsylvania (TDD, Chapter D.5).

A. Pollutants

    As described in Section XII.D., high concentrations of TDS are 
common in UOG extraction wastewater. As shown in Table XII-2. (in 
Section XII.D.), major inorganic constituents leaching from geologic 
formations such as sodium, potassium, bromide, calcium, fluoride, 
nitrate, phosphate, chloride, sulfate, and magnesium represent most of 
the TDS in UOG extraction wastewater. TDS in produced water can also 
include barium, radium, and strontium. Based on available data, TDS 
cations (positively charged ions) in UOG extraction wastewater are 
generally dominated by sodium and calcium, and the anions (negatively 
charged ions) are dominated by chloride (DCN SGE00284). TDS 
concentrations vary among the UOG formations. Table XII-1. (in Section 
XII.D.), presents the varying TDS concentrations in tight and shale oil 
and gas formations. The highest median TDS concentration (370,000 mg/L) 
is found in the Pearsall shale gas formation. For comparison, sea water 
contains approximately 35,000 mg/L TDS.

B. Impacts From the Discharge of Pollutants Found in UOG Extraction 
Wastewater

    Conventional POTW treatment operations are designed primarily to 
treat organic waste and remove total suspended solids and constituents 
responsible for biochemical oxygen demand, not to treat waters with 
high TDS. When transfers of UOG extraction wastewater to POTWs were 
occurring in Pennsylvania, these POTWs, lacking adequate TDS removal 
processes, diluted UOG extraction wastewaters with other sewage flows 
and discharged TDS-laden effluent into local streams and rivers. POTWs 
not sufficiently treating TDS in UOG extraction wastewater were a 
suspected source of elevated TDS levels in the Monongahela River in 
2009 (DCN SGE00525). Also see TDD, Chapter D.5 for additional examples.
    In addition to UOG wastewater pollutants passing through POTWs, 
other industrial discharges of inadequately treated UOG extraction 
wastewater pollutants have also been associated with in-stream impacts. 
One study reviewed by EPA of discharges from a CWT facility in western 
Pennsylvania that treats UOG extraction wastewater examined the water 
quality and isotopic compositions of discharged effluents, surface 
waters, and stream sediments (DCN SGE00629).\25\ The study found that 
the discharge of the effluent from the CWT facility increased 
downstream concentrations of chloride and bromide above background 
levels. The chloride concentrations 1.7 kilometers downstream of the 
treatment facility were two to ten times higher than chloride 
concentrations found in similar reference streams in western 
Pennsylvania. Radium 226 levels in stream sediments at the point of 
discharge were approximately 200 times greater than upstream and 
background sediments. EPA intends to further study the frequency and 
magnitude of such impacts from CWTs.
---------------------------------------------------------------------------

    \25\ Discharges from CWT facilities are subject to ELGs in 40 
CFR part 437 and would not be subject to the proposed rule. However, 
the effect of discharges of treated oil and gas wastewaters from CWT 
facilities that lack high level treatment is similarly 
representative of POTWs.
---------------------------------------------------------------------------

C. Impact on Surface Water Designated Uses

    UOG extraction wastewater TDS levels are high enough, if discharged 
untreated to surface water, to affect adversely a number of designated 
uses of surface water, including drinking water, aquatic life support, 
livestock watering, irrigation, and industrial use.
1. Drinking Water Uses
    Available data indicate the levels of TDS in UOG extraction 
wastewaters can often significantly exceed recommended drinking water 
concentrations. Because TDS concentrations in drinking water sources 
are typically well below the recommended drinking water levels, few 
drinking water treatment facilities have technologies to remove TDS. 
Two published standards for TDS in drinking water include the U.S. 
Public Health Service recommendation and EPA's secondary maximum 
contaminant level recommendation that TDS in drinking water should not 
exceed 500 mg/L. High concentrations of TDS in drinking water primarily 
degrade its taste rather than pose a human health risk. Taste surveys 
found that water with less than 300 mg/L TDS is considered excellent, 
and water with TDS above 1,100 mg/L is unacceptable (DCN SGE00939). The 
World Health Organization dropped its health-based recommendations for 
TDS in 1993, instead retaining 1,000 mg/L as a secondary standard for 
taste (DCN SGE00947).
    EPA also reviewed a study concerning unintentional creation of 
harmful DBPs due to insufficient removal of bromide and other UOG 
wastewater constituents by POTWs accepting UOG extraction wastewaters 
(DCN SGE00535; DCN SGE00587). DBPs have been shown to have both adverse 
human health and ecological affects. The study found that UOG 
extraction wastewaters contain various inorganic and organic DBP 
precursors that can react with disinfectants used by POTWs to promote 
the formation of DBPs, or alter speciation of DBPs, particularly 
brominated-DBPs, which are suspected to be among the more toxic DBPs 
(DCN SGE00535; DCN SGE00985). These precursors are a concern for 
drinking water managers wherever they can enter raw water intakes. See 
TDD, Chapter D.5 for further discussion of DBP formation associated 
with UOG extraction wastewaters.

[[Page 18576]]

2. Aquatic Life Support Uses
    TDS and its accompanying salinity play a primary role in the 
distribution and abundance of aquatic animal and plant communities. 
High levels of TDS can impact aquatic biota through increases in 
salinity, loss of osmotic balance in tissues, and toxicity of 
individual ions. Increases in salinity have been shown to cause shifts 
in biotic communities, limit biodiversity, exclude less-tolerant 
species and cause acute or chronic effects at specific life stages (DCN 
SGE00946). A detailed study of plant communities associated with 
irrigation drains, reported substantial changes in marsh communities in 
part because of an increase in dissolved solids (DCN SGE00941). 
Observations over time indicate a shift in plant community coinciding 
with increases in dissolved solids from estimated historic levels of 
270 to 1170 mg/L, as species that are less salt tolerant such as 
coontail (Ceratophyllus demersum) and cattail (Typha sp.) were nearly 
eliminated. A related study found that lakes with higher salinity 
exhibit lower aquatic biodiversity, with species distribution also 
affected by ion composition (DCN SGE00940).
    It is often a specific ion concentration in TDS that is responsible 
for adverse effects to aquatic ecosystems. For example, a TDS 
concentration of 2,000 mg/L with chloride as the primary anionic 
constituent is acutely toxic to aquatic life, but the same TDS 
concentration composed primarily of sulfate is nontoxic. Sodium 
chloride accounts for about 50 percent of the TDS typically found in 
UOG extraction wastewater. As reported in Table XII-2 (in Section 
XII.D.), chloride has been measured at concentrations up to 230,000 mg/
L. Macroinvertebrates, such as fresh water shrimp and aquatic insects 
that are a primary prey of many fish species, have open circulatory 
systems that are especially sensitive to pollutants like chloride. 
Based on laboratory toxicity data from EPA's 1988 chloride criteria 
document and more recent studies, invertebrate sensitivity to chloride 
acute effect concentrations ranged from 953 mg/L to 13,691 mg/L. 
Chronic effect concentrations of chloride ranged from 489 mg/L to 556 
mg/L. In addition to the laboratory data, EPA also reviewed data from a 
2009 Pennsylvania Department of Environmental Protection violation 
report documenting a fish kill attributed to a spill of diluted 
produced water in Hopewell Township, PA. TDS at the location of the 
fish kill was as high as 7,000 mg/L. While not related to UOG 
extraction wastewater, negative impacts of high TDS, including fish 
kills, were documented during 2009 at Dunkard Creek located in 
Monongalia County, Pennsylvania. (DCN SGE00001 and DCN SGE00001.A01)
    EPA has published chemical-specific national recommended water 
quality criteria for some of the TDS constituents in UOG extraction 
wastewater, such as barium, chloride, manganese, and iron, based on a 
variety of human health or ecological benchmarks. A review of state and 
tribal water quality standards in 2012 indicated that 26 states had 
adopted a numeric or narrative criterion for TDS, either for state-wide 
or site-specific application (DCN SGE00945). The TDS criteria levels 
and the designated uses they are intended to protect vary greatly from 
state to state. For example, Alaska has a criterion of 1,500 mg/L TDS 
to protect aquatic life; Mississippi has a criterion of 750 mg/L 
monthly average for protection of fish, wildlife and recreation 
criteria, and Illinois has a statewide 1,000 mg/L TDS criterion for 
aquatic life and a 1,500 mg/L TDS criterion for secondary contact 
recreation and indigenous aquatic life. TDS criteria adopted 
specifically for the protection of aquatic life have been developed for 
at least 16 of the 26 states, with some criteria applying only to 
specific waterbodies. Oregon has the most stringent TDS criterion using 
a standard of 100 mg/L for all freshwater streams and tributaries in 
order to protect aquatic life, public water use, agriculture, and 
recreation.
3. Livestock Watering Uses
    POTW discharges to surface waters containing high concentrations of 
TDS can impact downstream uses for livestock watering. High TDS 
concentrations in water sources for livestock watering can adversely 
affect animal health by disrupting cellular osmotic and metabolic 
processes (DCN SGE01053). Domestic livestock, such as cattle, sheep, 
goats, horses, and pigs have varying degrees of sensitivity to TDS in 
drinking water as shown in Table XV-1. Sheep seem to be more tolerant 
of saline water than most domestic species, but will only drink it if 
introduced to the saline water over a period of several weeks (DCN 
SGE00937).

                          Table XV-1--Tolerances of Livestock to TDS in Drinking Water
----------------------------------------------------------------------------------------------------------------
                                                                  Total Dissolved Solids (TDS) (mg/L)
                                                     -----------------------------------------------------------
                                                                                              Loss of production
                                                                           Animals can have    and a decline in
                                                                                initial        animal condition
                                                                             reluctance to     and health would
                      Livestock                           No adverse      drink or there can  be expected. Stock
                                                          effects on       be some scouring,  can tolerate these
                                                       animals  expected   but stock should    levels for short
                                                                          adapt without loss      periods if
                                                                            of  production        introduced
                                                                                                   gradually
----------------------------------------------------------------------------------------------------------------
Beef cattle.........................................             0-4,000         4,000-5,000        5,000-10,000
Dairy cattle........................................             0-2,400         2,400-4,000         4,000-7,000
Sheep...............................................             0-4,000        4,000-10,000       10,000-13,000
Horses..............................................             0-4,000         4,000-6,000         6,000-7,000
Pigs................................................             0-4,000         4,000-6,000         6,000-8,000
Poultry.............................................             0-2,000         2,000-3,000         3,000-4,000
----------------------------------------------------------------------------------------------------------------
Source: Australia and New Zealand Water Quality Guidelines 2000. Chapter 3 Primary Industries--9.3 Livestock
  drinking water guidelines (DCN SGE00937).


[[Page 18577]]

4. Irrigation Uses
    If UOG extraction wastewater discharges to POTWs increase TDS 
concentrations in receiving streams, downstream irrigation uses of that 
surface water can be negatively affected. Elevated TDS levels can limit 
the usefulness of water for irrigation. Excessive salts affect crop 
yield in the short term, and the soil structure in the long term. 
Primary direct impacts of high salinity water on plant crops include 
physiological drought, increased osmotic potential of soil, specific 
ion toxicity, leaf burn, and nutrient uptake interferences (DCN 
SGE00938). In general, for various classes of crops the salinity 
tolerance decreases in the following order: forage crops, field crops, 
vegetables, fruits.
    The suitability of water for irrigation is classified using several 
different measurements, including TDS and electrical conductivity (EC). 
Table XV-2. shows a classification of TDS concentrations for irrigation 
suitability.

     Table XV-2--Permissible Limits for Classes of Irrigation Water
------------------------------------------------------------------------
                                           Concentrations of TDS
                                 ---------------------------------------
         Class of water               Electrical
                                   conductivity \a\   TDS by gravimetric
                                        (dS/m)               (mg/L)
------------------------------------------------------------------------
Class 1. Excellent..............               0.250                 175
Class 2. Good...................         0.250-0.750             175-275
Class 3. Permissible \b\........           0.750-2.0           525-1,400
Class 4. Doubtful \c\...........             2.0-3.0         1.400-2,100
Class 5. Unsuitable \c\.........                 3.0              >2,100
------------------------------------------------------------------------
a = TDS (mg/L) [ap] Electrical Conductivity (EC) (deci-Siemen/meter (dS/
  m)) x 640 for EC < 5 dS/m.
b = leaching needed if used.
c = good drainage needed and sensitive plants will have difficulty
  obtaining stands.
Source: Fipps (2003) (DCN SGE00936).

    In addition to short-term impacts to crop plants, irrigating with 
high TDS water can result in gradual accumulation of salts or sodium in 
soil layers and eventual decrease in soil productivity. The 
susceptibility of soils to degradation is dependent on the soil type 
and structure. Sandy soils are less likely than finely textured soils 
to accumulate salts or sodium. Soils with a high water table or poor 
drainage are more susceptible to salt or sodium accumulation. The most 
common method of estimating the suitability of a soil for crop 
production is through calculation of its sodicity as estimated by the 
soil's sodium absorption ratio (SAR). The SAR value is calculated by 
the equation: \26\
[GRAPHIC] [TIFF OMITTED] TP07AP15.012

The impact of irrigation water salinity on crop productivity is a 
function of both the SAR value and the electrical conductivity. The 
actual field-observed impacts are very site-specific depending on soil 
and crop system. (DCN SGE00938)
---------------------------------------------------------------------------

    \26\ The variables in the equation are defined as follows: 
[Na\+\]-Sodium concentration (mg/L); [Ca\2+\]-Calcium concentration 
(mg/L); [Mg\2+\]-Magnesium concentration (mg/L).
---------------------------------------------------------------------------

5. Industrial Uses
    POTW discharges to surface waters are often upstream of industrial 
facilities that withdraw surface waters for various cooling and process 
uses. High levels of TDS can adversely affect industrial applications 
requiring the use of water in cooling tower operations, boiler feed 
water, food processing, and electronics manufacturing. Concentrations 
of TDS above 500 mg/L result in excessive corrosivity, scaling, and 
sedimentation in water pipes, water heaters, boilers and household 
appliances. Depending on the industry, TDS in intake water can 
interfere with chemical processes within the plant. Some industries 
requiring ultrapure water, such as semi-conductor manufacturing 
facilities, are particularly sensitive to high TDS levels due to the 
treatment cost for the removal of TDS.

XVI. Non-Water Quality Environmental Impacts Associated With the 
Proposed Rule

    Because the elimination or reduction of one form of pollution can 
create or aggravate other environmental problems, EPA considers non-
water quality environmental impacts (including energy impacts) that can 
result from the implementation of proposed regulations. EPA evaluated 
the potential impact of the proposed pretreatment standards on air 
emissions, solid waste generation, and energy consumption.
    The proposed PSES/PSNS would prohibit the discharge to POTWs of 
wastewater pollutants associated with UOG extraction. Because EPA knows 
of no POTWs that are currently accepting UOG extraction wastewater, the 
proposed PSES will require no changes in current industry wastewater 
management practices and, consequently, will have no incremental 
impacts on air emissions, solid waste generation, or energy 
consumption. Based on the reasoning that new sources will follow 
current industry practice, EPA projects no incremental non-water 
quality environmental impacts associated with PSNS.

XVII. Implementation

A. Implementation Deadline

    Because the requirements of the proposed rule are based on current 
practice, EPA proposes that the PSES/NSPS standards based on the 
regulatory options being proposed apply on the effective date of the 
final rule.

B. Upset and Bypass Provisions

    A ``bypass'' is an intentional diversion of waste streams from any 
portion of a treatment facility. An ``upset'' is an exceptional 
incident in which there is unintentional and temporary noncompliance 
with technology-based permit effluent limitations because of factors 
beyond the reasonable control of the permittee. EPA's regulations for 
indirect dischargers concerning bypasses and upsets are set forth at 40 
CFR 403.16 and 403.17.

C. Variances and Modifications

    The CWA requires application of effluent limitations established 
pursuant to section 304 for direct dischargers and section 307 for all 
indirect dischargers. However, the statute provides for the 
modification of these national requirements in a limited number of 
circumstances. Moreover, the Agency

[[Page 18578]]

has established administrative mechanisms to provide an opportunity for 
relief from the application of the national pretreatment standards for 
categories of existing sources.
    EPA can develop pretreatment standards different from the otherwise 
applicable requirements for an individual existing discharger if it is 
fundamentally different with respect to factors considered in 
establishing the standards applicable to the individual discharger. 
Such a modification is known as a ``fundamentally different factors'' 
(FDF) variance. See 40 CFR 403.13. EPA, in its initial implementation 
of the effluent guidelines program, provided for the FDF modifications 
in regulations. These were variances from the BCT effluent limitations, 
BAT limitations for toxic and nonconventional pollutants, and BPT 
limitations for conventional pollutants for direct dischargers. FDF 
variances for toxic pollutants were challenged judicially and 
ultimately sustained by the Supreme Court in Chemical Manufacturers 
Association v. Natural Resources Defense Council, 479 U.S. 116, 124 
(U.S. 1985). FDF variances, however, are not available for new sources. 
E.I. Dupont v. Train, 430 U.S. 112, 138 (U.S. 1977).
    Subsequently, in the Water Quality Act of 1987, Congress added new 
CWA section 301(n). This provision explicitly authorizes modifications 
of the otherwise applicable BAT effluent limitations or categorical 
pretreatment standards if a discharger is fundamentally different with 
respect to the factors specified in CWA section 304 or 403 (other than 
costs) from those considered by EPA in establishing the effluent 
limitations or pretreatment standards. CWA section 301(n) also defined 
the conditions under which EPA can establish alternative requirements. 
Under section 301(n), an application for approval of a FDF variance 
must be based solely on (1) information submitted during rulemaking 
raising the factors that are fundamentally different or (2) information 
the applicant did not have an opportunity to submit. The alternate 
limitation must be no less stringent than justified by the difference 
and must not result in markedly more adverse non-water quality 
environmental impacts than the national limitation or standard.
    The legislative history of section 301(n) underscores the necessity 
for the FDF variance applicant to establish eligibility for the 
variance. EPA's regulations at 40 CFR 403.13 are explicit in imposing 
this burden upon the applicant. The applicant must show that the 
factors relating to the discharge controlled by the applicant's permit 
that are claimed to be fundamentally different are, in fact, 
fundamentally different from those factors considered by EPA in 
establishing the applicable pretreatment standards. In practice, very 
few FDF variances have been granted for past ELGs. An FDF variance may 
be available to an existing source subject to the proposed PSES, but an 
FDF variance is not available to a new source that would be subject to 
PSNS.

XVIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action is a ``significant regulatory action'' under the terms 
of Executive Order 12866 (58 FR 51735, October 4, 1993). Accordingly, 
EPA submitted this action to the Office of Management and Budget (OMB) 
for review under Executive Orders 12866 and 13563 (76 FR 3821, January 
21, 2011) and any changes made in response to OMB recommendations have 
been documented in the docket for this action.

B. Paperwork Reduction Act

    This action does not impose an information collection burden under 
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 
Burden is defined at 5 CFR 1320.3(b). This proposal would codify 
current industry practice and would not impose any additional reporting 
requirements.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any proposed rule that 
would be subject to notice and comment rulemaking requirements under 
the Administrative Procedure Act or any other statute unless the agency 
certifies that the rule will not have a significant economic impact on 
a substantial number of small entities. Small entities include small 
businesses, small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of the proposed rule on small 
entities, small entity is defined as: (1) a small business that is 
primarily engaged in Crude Petroleum and Natural Gas Extraction and 
Natural Gas Liquid Extraction by NAICS code 211111 and 211112 with 
fewer than 500 employees (based on Small Business Administration size 
standards).
    After considering the economic impacts of the proposed rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. The small 
entities that would be subject to the requirements of this proposed 
rule are small businesses that engage in UOG extraction as defined in 
Section XI. No small businesses will experience an impact because the 
proposed rulemaking does not impose any new requirement that is not 
already being met by the industry.

D. Unfunded Mandates Reform Act

    This proposed rule does not contain a Federal mandate that can 
result in expenditures of $100 million or more for state, local, and 
tribal governments, in the aggregate, or the private sector in any one 
year. As explained in Section VI.C., this proposed rule has no costs. 
Thus, this proposed rule would not be subject to the requirements of 
sections 202 or 205 of the Unfunded Mandates Reform Act (UMRA).
    This proposed rule also would not be subject to the requirements of 
section 203 of UMRA because it contains no regulatory requirements that 
might significantly or uniquely affect small governments. EPA has not 
identified any oil and gas facilities that are owned by small 
governments.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. The proposed rule would not alter 
the basic state-federal scheme established in the CWA under which EPA 
authorizes states to carry out the NPDES permit program. EPA expects 
the proposed rule would have little effect on the relationship between, 
or the distribution of power and responsibilities among, the federal 
and state governments. Thus, Executive Order 13132 does not apply to 
this action. Although this order does not apply to this action, as 
explained in Section IX., EPA coordinated closely with states through a 
workgroup, as well as outreach efforts to pretreatment coordinators and 
pretreatment authorities.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have 
substantial direct

[[Page 18579]]

effects on tribal governments, on the relationship between the Federal 
government and Indian tribes, or on the distribution of power and 
responsibilities between the Federal government and Indian tribes. The 
proposed rule contains no Federal mandates for tribal governments and 
does not impose any enforceable duties on tribal governments. Thus, 
Executive Order 13175 does not apply to this action.
    Although Executive Order 13175 does not apply to this action, EPA 
coordinated with tribal officials in developing this action. EPA 
coordinated with federally recognized tribal governments in May and 
June of 2014, sharing information about the UOG pretreatment standards 
proposed rulemaking with the National Tribal Caucus and the National 
Tribal Water Council. As part of this outreach effort, EPA collected 
data about UOG operations on tribal reservations, UOG operators that 
are affiliated with Indian tribes, and POTWs owned or operated by 
tribes that can accept industrial wastewaters (see DCN SGE00785). Based 
on this information, there are no tribes operating UOG wells that 
discharge wastewater to POTWs nor are there any tribes that own or 
operate POTWs that accept industrial wastewater from UOG facilities; 
therefore, this proposed rule will not impose any costs on tribes.

G. Executive Order 13045: Protection of Children From Environmental 
Health and Safety Risks

    E.O. 13045 (62 FR 19885, April 23, 1997) applies to rules that are 
economically significant according to E.O. 12866 and involve a health 
or safety risk that can disproportionately affect children. This 
proposed action would not be subject to E.O. 13045 because it is 
estimated to cost less than $100 million and does not involve a safety 
or health risk that can have disproportionately negative effects on 
children.

H. Executive Order 13211: Energy Effects

    This proposed action is not subject to Executive Order 13211, 
because it not a ``significant energy action'' as defined in Executive 
Order 13211, ``Actions Concerning Regulations That Significantly Affect 
Energy Supply, Distribution, or Use'' (66 FR 28355, May 22, 2001). This 
action will not have a significant adverse effect on the supply, 
distribution, or use of energy, as described in Section XVI. of the 
proposed rule.

I. National Technology Transfer Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards.
    This proposed rulemaking does not involve technical standards. 
Therefore, EPA is not considering the use of any voluntary consensus 
standards.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629 (Feb. 16, 1994)) establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the U.S.
    EPA determined that this proposed rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it does not 
affect the level of protection provided to human health or the 
environment. The proposed rule changes the control technology required 
but will neither increase nor decrease environmental protection (as 
described in Section VII.C.).
    EPA welcomes comments on this aspect of the proposed rulemaking 
and, specifically, invites the public to identify potential 
environmental justice considerations associated with this proposed 
regulation.

List of Subjects in 40 CFR Part 435

    Environmental protection, Pretreatment, Waste treatment and 
disposal, Water pollution control, Unconventional oil and gas 
extraction.

    Dated: March 31, 2015.
Gina McCarthy,
Administrator.

    Therefore, it is proposed that 40 CFR part 435 be amended as 
follows:

PART 435--OIL AND GAS EXTRACTION POINT SOURCE CATEGORY

0
1. The authority citation for part 435 continues to read as follows:

    Authority:  33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342 and 
1361.

0
2. Add Sec.  435.33 to read as follows:


Sec.  435.33  Pretreatment standards of performance for existing 
sources (PSES).

    (a) PSES for Wastewater from Conventional Oil and Gas Extraction. 
[Reserved]
    (b) PSES for Wastewater from Unconventional Oil and Gas Extraction. 
Except as provided in 40 CFR 403.7 and 403.13, any existing source 
subject to this section, must achieve the following pretreatment 
standards for existing sources (PSES).
    (1) There shall be no discharge of wastewater pollutants associated 
with production, field exploration, drilling, well completion, or well 
treatment for unconventional oil and gas extraction (e.g., drilling 
muds, drill cuttings, produced sand, produced water) into publicly 
owned treatment works.
    (2) For the purposes of this section,
    (i) Unconventional oil and gas means crude oil and natural gas 
produced by a well drilled into a low porosity, low permeability 
formation (including, but not limited to, shale gas, shale oil, tight 
gas, tight oil).
    (ii) Drill cuttings means the particles generated by drilling into 
subsurface geologic formations and carried out from the wellbore with 
the drilling fluid.
    (iii) Drilling muds means the circulating fluid (mud) used in the 
rotary drilling of wells to clean and condition the hole and to 
counterbalance formation pressure.
    (iv) Produced sand means 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.
    (v) Produced water means the water (brine) brought up from the 
hydrocarbon-bearing strata during the extraction of oil and gas, and 
can include formation water, injection water, and any chemicals added

[[Page 18580]]

downhole or during the oil/water separation process.
0
3. Add Sec.  435.34 to read as follows:


Sec.  435.34  Pretreatment standards of performance for new sources 
(PSNS).

    (a) PSNS for Wastewater from Conventional Oil and Gas Extraction. 
[Reserved]
    (b) PSNS for Wastewater from Unconventional Oil and Gas Extraction. 
Except as provided in 40 CFR 403.7 and 403.13, any new source with 
discharges subject to this section must achieve the following 
pretreatment standards for new sources (PSNS).
    (1) There shall be no discharge of wastewater pollutants associated 
with production, field exploration, drilling, well completion, or well 
treatment for unconventional oil and gas extraction (e.g., drilling 
muds, drill cuttings, produced sand, produced water) into publicly 
owned treatment works.
    (2) For the purposes of this section, the definitions of 
unconventional oil and gas, drill cuttings, drilling muds, produced 
sand, and produced water are as specified in Sec.  435.33(b)(2)(i) 
through (v).
0
4. Add subpart H to read as follows:

Subpart H--Coalbed Methane Subcategory [Reserved]

[FR Doc. 2015-07819 Filed 4-6-15; 8:45 a.m.]
 BILLING CODE 6560-50-P


