Federal Register / Vol. 80, No. 66 / Tuesday, April 7, 2015 / Proposed Rules 18557 

identifiers, contact information, or other 

personal information provided, to: 

http://www.regulations.gov. Do not 

submit confidential business 

information, trade secret information, or 

other sensitive or protected information 

electronically. Such information should 

be submitted in writing. 

Docket: For access to the docket to 

read background documents or 

comments received, go to: http://

www.regulations.gov and insert the 

Docket No. CPSC–2009–0087 into the 

‘‘Search’’ box and follow the prompts. 

SUPPLEMENTARY INFORMATION: On 

November 19, 2014, the Commission 

published an NPR in the Federal 

Register proposing standards that would 

apply to ROVs. (79 FR 68964). The 

Commission issued the proposed rule 

under the authority of the Consumer 

Product Safety Act (CPSA). In response 

to requests for an extension of the 

comment period by the Recreational 

Off-Highway Vehicle Association 

(ROHVA) and the Outdoor Power 

Equipment Institute (OPEI), the 

Commission extended the comment 

period to April 8, 2015. (80 FR 3535 

(January 23, 2015)). ROHVA and OPEI 

have each requested another extension 

to the comment period. ROHVA asked 

for additional time to review documents 

provided by the Commission. OPEI 

noted a need for additional time for 

OPEI to complete and review ‘‘round 

robin’’ testing that OPEI is conducting to 

gauge the reproducibility and 

repeatability of tests the Commission 

proposed in the NPR. The Commission 

has considered the requests and is 

extending the comment period until 

June 19, 2015. 

Alberta E. Mills, 

Acting Secretary, U.S. Consumer Product 

Safety Commission. 

[FR Doc. 2015–07910 Filed 4–6–15; 8:45 am] 

BILLING CODE 6355–01–P 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 435 

[EPA–HQ–OW–2014–0598; FRL–9917–78– 

OW] 

RIN 2040–AF35 

Effluent Limitations Guidelines and 

Standards for the Oil and Gas 

Extraction Point Source Category 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: EPA proposes a Clean Water 

Act (CWA) regulation that would better 

protect human health and the 

environment and protect the operational 

integrity of publicly owned treatment 

works (POTWs) by establishing 

pretreatment standards that would 

prevent the discharge of pollutants in 

wastewater from onshore 

unconventional oil and gas extraction 

facilities to POTWs. Unconventional oil 

and gas (UOG) extraction wastewater 

can be generated in large quantities and 

contains constituents that are 

potentially harmful to human health 

and the environment. Because they are 

not typical of POTW influent 

wastewater, some UOG extraction 

wastewater constituents can be 

discharged, untreated, from the POTW 

to the receiving stream; can disrupt the 

operation of the POTW (e.g., by 

inhibiting biological treatment); can 

accumulate in biosolids (sewage 

sludge), limiting their use; and can 

facilitate the formation of harmful 

disinfection by-products (DBPs). Based 

on the information collected by EPA, 

the requirements in this proposal reflect 

current industry practices for 

unconventional oil and gas extraction 

facilities, therefore, EPA does not 

project the proposed rule will impose 

any costs or lead to pollutant removals, 

but will ensure that such current 

industry best practice is maintained 

over time. 

DATES: Comments on this proposed rule 

must be received on or before June 8, 

2015. EPA will conduct a public hearing 

on the proposed pretreatment standards 

on May 29, 2015 at 1:00 p.m. in the EPA 

East Building, Room 1153, 1201 

Constitution Avenue NW., Washington, 

DC. 

ADDRESSES: Submit your comments on 

the proposed rule, identified by Docket 

No. EPA–HQ–OW–2014–0598 by one of 

the following methods: 

• http://www.regulations.gov: Follow 

the on-line instructions for submitting 

comments. 

• Email: 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, 


rljohnson on DSK3VPTVN1PROD with PROPOSALS
18558 Federal Register / Vol. 80, No. 66 / Tuesday, April 7, 2015 / Proposed Rules 

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® 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 TDSContributing 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: 

Category Examples of regulated entities 

North American Industry Classification 

System (NAICS) 

Code 

Industry ................................................... Crude Petroleum and Natural Gas Extraction ........................................................ 211111 

Natural Gas Liquid Extraction ................................................................................. 211112 

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 


rljohnson on DSK3VPTVN1PROD with PROPOSALS
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1For more information on EPA’s continued 

engagement with states and other stakeholders, see: 

http://www2.epa.gov/hydraulicfracturing. 

2Naturally 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) 

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 hardcopy 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). 

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 


rljohnson on DSK3VPTVN1PROD with PROPOSALS
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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. 

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 technologybased 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 


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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 


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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., ammoniaN, 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 


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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 


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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® Data Set 

EPA used a propriety database of all 

oil and gas wells in the U.S., called DI 

Desktop®, 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 Congressionallymandated study and attended meetings, 

workshops, and roundtable discussions 

pertaining to water and wastewater 

management and treatment in the UOG 

extraction industry. See DCN SGE00063, 


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3Natural 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. 

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). 

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-tonatural 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 


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4Natural gas can include ‘‘natural gas liquids,’’ 

components that are liquid at ambient temperature 

and pressure. 

5Natural gas can include ‘‘natural gas liquids,’’ 

components that are liquid at ambient temperature 

and pressure. 

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. 

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. 

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 


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6Shale oil and gas wells, are primarily drilled 

directionally (and specifically horizontally), while 

tight oil and gas wells are drilled vertically and 

directionally. 

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. 

8Hydraulic 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. 

9The 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. 

10The hours per day depends on the operator, 

local ordinances, and weather. 

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. 

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. 

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. 

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). 

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, 


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11Formation water is naturally occurring water 

contained in the reservoir rock pores. 

12Fracturing 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). 

13On 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). 

14Stormwater 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. 

15Synthetic fluids, which are more expensive 

than water-based drilling fluid, are almost always 

reused/recycled in drilling additional wells. 

16Burial 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). 

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

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

• Produced water—the water (brine) 

brought up from the hydrocarbonbearing 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: 

Æ 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.’’ 

Æ 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: 

Æ Drill cuttings—The particles 

generated by drilling into subsurface 

geologic formations and carried out 

from the wellbore with the drilling 

fluid. 

Æ 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

• Disposal via landfill 16

• 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 


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17As explained above, produced water includes 

both flowback and long-term produced water. 

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

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 (mm) 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

Shale/tight oil and gas formation 

TDS concentration 

range 

(mg/L) 

TDS median 

concentration 

(mg/L) 

Number of data 

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 


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18A 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. 

19Occasionally, UOG operators in the western 

U.S. may use evaporation as a means of wastewater 

management. 

20Operators 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. 

not found in high concentrations in 

UOG produced water. Table XII–2. 

presents ranges and median 

concentrations of TDS and TDScontributing ions in UOG produced 

water. Based on available data, 

concentrations of TDS and TDScontributing 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

Constituent 

Concentration 

range 

(mg/L) 

Median 

concentration 

(mg/L) 

Number of data 

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 welldocumented 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) 

E. Wastewater Management and 

Disposal Practices 

Historically, UOG operators primarily 

managed their wastewater using the 

following four methods: 19

• 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

(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). 


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21Source waters may include freshwater, ground 

water, treated municipal wastewater, and other 

industrial wastewater. 

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). 

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 


rljohnson on DSK3VPTVN1PROD with PROPOSALS
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22While 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). 

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 reuse 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). 

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 


rljohnson on DSK3VPTVN1PROD with PROPOSALS
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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, resourceconstrained 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 caseby-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 


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23As 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). 

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

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 


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24As 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). 

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. 

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. 

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. 

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. 


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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 sitespecific 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

Livestock 

Total Dissolved Solids (TDS) (mg/L) 

No adverse 

effects on 

animals 

expected 

Animals can 

have initial 

reluctance to drink 

or there can be 

some scouring, but 

stock should adapt 

without loss of 

production 

Loss of production 

and a decline in 

animal condition 

and health would 

be expected. Stock 

can tolerate these 

levels for short 

periods if 

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). 


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26The variables in the equation are defined as 

follows: [Na+]¥Sodium concentration (mg/L); 

[Ca2+]¥Calcium concentration (mg/L); 

[Mg2+]¥Magnesium concentration (mg/L). 

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

Class of water 

Concentrations of TDS 

Electrical 

conductivity a

(dS/m) 

TDS by gravimetric 

(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) ≈ Electrical Conductivity (EC) (deci-Siemen/meter (dS/m)) × 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

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) 

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 


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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 nonwater 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 statefederal 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 


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Federal Register / Vol. 80, No. 66 / Tuesday, April 7, 2015 / Proposed Rules 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 

■ 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. 

■ 2. Add § 435.33 to read as follows: 

§ 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 


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downhole or during the oil/water 

separation process. 

■ 3. Add § 435.34 to read as follows: 

§ 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 § 435.33(b)(2)(i) through 

(v). 

■ 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 

NATIONAL AERONAUTICS AND 

SPACE ADMINISTRATION 

48 CFR Parts 1801, 1802, 1805, 1807, 

1812, 1813, 1823, 1833, 1836, 1847, 

1850, and 1852 

RIN 2700–AE19 

NASA FAR Supplement Regulatory 

Review No. 3 

AGENCY: National Aeronautics and 

Space Administration. 

ACTION: Proposed rule. 

SUMMARY: NASA is updating the NASA 

FAR Supplement (NFS) with the goal of 

eliminating unnecessary regulation, 

streamlining overly-burdensome 

regulation, clarifying language, and 

simplifying processes where possible. 

This proposed rule is the third and final 

in a series and includes updates and 

revisions to 10 parts of the NFS. On 

January 18, 2011, President Obama 

signed Executive Order (E.O.) 13563, 

Improving Regulations and Regulatory 

Review, directing agencies to develop a 

plan for a retrospective analysis of 

existing regulations. The revisions to 

this proposed rule are part of NASA’s 

retrospective plan under E.O. 13563 

completed in August 2011. 

DATES: Interested parties should submit 

comments to NASA at the address 

below on or before June 8, 2015 to be 

considered in formulation of the final 

rule. 

ADDRESSES: Interested parties may 

submit comments, identified by RIN 

number 2700–AE19 via the Federal 

eRulemaking Portal: http://

www.regulations.gov. Follow the 

instructions for submitting comments. 

Comments may also be submitted to 

Cynthia Boots via email at 

cynthia.d.boots@nasa.gov. 

FOR FURTHER INFORMATION CONTACT: 

Cynthia Boots, NASA, Office of 

Procurement, email: cynthia.d.boots@

nasa.gov. 

SUPPLEMENTARY INFORMATION: 

A. Background 

The NASA FAR Supplement (NFS) is 

codified at 48 CFR part 1800. 

Periodically, NASA performs a 

comprehensive review and analysis of 

the regulation, makes updates and 

corrections, and reissues the NASA FAR 

Supplement. The last reissue was in 

2004. The goal of the review and 

analysis is to reduce regulatory burden 

where justified and appropriate and 

make the NFS content and processes 

more efficient and effective, faster and 

simpler, in support of NASA’s mission. 

Consistent with Executive Order (E.O.) 

13563, Improving Regulations and 

Regulatory Review, NASA is currently 

reviewing and revising the NFS with an 

emphasis on streamlining it and 

reducing associated burdens. Due to the 

volume of the NFS, these revisions are 

being made in increments. This 

proposed rule is the third and final rule. 

The three rules together will constitute 

the NFS update and reissue. This 

proposed rule includes regulatory 

revisions to the following ten parts of 

the NFS: 

1801—Federal Acquisition Regulations 

Systems 

1802—Definitions 

1805—Publicizing Contract Actions 

1807—Acquisition Planning 

1812—Acquisition of Commercial Items 

1813—Simplified Acquisition Procedures 

1823—Environment, Energy and Water 

Efficiency, Renewable Energy 

Technologies, Occupational Safety, and 

Drug-Free Workplace 

1833—Protests, Disputes and Appeals 

1836—Construction and Architect-Engineer 

Contracts 

1847—Transportation 

1850—Extraordinary Contractual Actions and 

the Safety Act 

1852—Solicitation Provisions and Contract 

Clauses 

Further, this proposed rule provides 

notice that no regulatory changes will be 

made to the following ten parts of the 

NFS: 

1803—Improper Business Practices and 

Personal Conflicts of Interest 

1804—Administrative Matters 

1808—Required Sources of Supplies and 

Services 

1811—Describing Agency Needs 

1825—Foreign Acquisition 

1839—Acquisition of Information 

Technology 

1835—Research and Development 

Contracting 

1845—Government Property 

1848—Value Engineering 

1872—Acquisition of Investigations 

NASA analyzed the existing 

regulation to determine whether any 

portions should be modified, 

streamlined, expanded, or repealed in 

order to make the regulation more 

efficient and effective. Special emphasis 

was placed on identifying and 

eliminating or simplifying overly 

burdensome processes that could be 

streamlined without jeopardizing 

Agency mission effectiveness. 

Additionally, NASA sought to identify 

current regulatory coverage that is not 

regulatory in nature, and to remove or 

relocate such coverage to internal 

guidance. In addition to substantive 

changes, this proposed rule includes 

administrative changes necessary to 

make minor corrections and updates. 

Specifically, the changes in this 

proposed rule are summarized as 

follows: 

1801.106 is revised to reflect currently 

approved OMB Information Collection 

Requests 

1802.101 is revised to update the 

definition of Head of Contracting 

Activity to reflect internal 

organizational changes. 

1805.303(a)(i) is revised to delete the 

dollar figure of $3.5 million but retain 

the reference to the threshold at FAR 

5.303(a). Consequently, if the threshold 

at FAR 5.303(a) changes at any time, 

NFS 1805.303(a)(i) will continue to be 

correct and will not require rule-making 

to reflect the FAR change. 

1807.107 and 1807.107–70 are deleted 

from the regulation. These sections 

provide NASA-internal direction to 

contracting officers and are not 

regulatory in nature. These sections, 

with minor edits, will remain noncodified internal guidance. 

1807.7200 is revised to reflect a 

change to a Web site address. 

1807.7201, the definition of ‘‘contract 

opportunity’’ is revised to delete 

‘‘$25,000’’ and replace it with ‘‘the 

simplified acquisition threshold’’. 

1812.301, the list of NFS clauses 

authorized for use in acquisition of 


rljohnson on DSK3VPTVN1PROD with PROPOSALS