Vol. 79 Thursday, 

No. 137 July 17, 2014 

Part II 

Environmental Protection Agency 

40 CFR Part 60 

Oil and Natural Gas Sector: Reconsideration of Additional Provisions of 

New Source Performance Standards; Proposed Rule 


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ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2010–0505, FRL–9913–40– 

OAR] 

RIN 2060–AS01 

Oil and Natural Gas Sector: 

Reconsideration of Additional 

Provisions of New Source 

Performance Standards 

AGENCY: Environmental Protection 

Agency. 

ACTION: Proposed rule; Notice of Public 

Hearing. 

SUMMARY: On August 16, 2012, the 

Environmental Protection Agency (EPA) 

published final new source performance 

standards for the oil and natural gas 

sector. The Administrator received 

petitions for administrative 

reconsideration of certain aspects of the 

standards. Among issues raised in the 

petitions were time-critical issues 

related to certain storage vessel 

provisions and well completion 

provisions. On September 23, 2013, the 

EPA published final amendments as a 

result of reconsideration of issues 

related to implementation of the storage 

vessel provisions. Following that action, 

the Administrator again received 

petitions for administrative 

reconsideration pertaining to the storage 

vessel provisions. In this notice, the 

EPA is announcing proposed 

amendments and clarifications as a 

result of reconsideration of certain 

issues related to well completions and 

additional issues pertaining to storage 

vessels. The proposed amendments also 

address other issues raised for 

reconsideration and make technical 

corrections and amendments to further 

clarify the rule. 

DATES: Comments. Comments must be 

received on or before August 18, 2014, 

unless a public hearing is requested by 

July 22, 2014. If a hearing is requested 

on this proposed rule, written 

comments must be received by 

September 2, 2014. 

Public Hearing. If anyone contacts the 

EPA requesting a public hearing by July 

22, 2014 we will hold a public hearing 

on August 1, 2014. 

If a public hearing is requested by July 

22, 2014, it will be held on August 1, 

2014 at the EPA’s Research Triangle 

Park Campus, 109 T.W. Alexander 

Drive, Research Triangle Park, NC 

27711. The hearing will convene at 

10:00 a.m. (Eastern Standard Time) and 

end at 5:00 p.m. (Eastern Standard 

Time). A lunch break will be held from 

12:00 p.m. (Eastern Standard Time) 

until 1:00 p.m. (Eastern Standard Time). 

Please contact Virginia Hunt at (919) 

541–0832, or at hunt.virginia@epa.gov 

to request a hearing, to determine if a 

hearing will be held and to register to 

speak at the hearing, if one is held. If a 

hearing is requested, the last day to preregister in advance to speak at the 

hearing will be July 30, 2014. 

Additionally, requests to speak will be 

taken the day of the hearing at the 

hearing registration desk, although 

preferences on speaking times may not 

be able to be fulfilled. If you require the 

service of a translator or special 

accommodations such as audio 

description, please let us know at the 

time of registration. If no one contacts 

the EPA requesting a public hearing to 

be held concerning this proposed rule 

by July 22, 2014, a public hearing will 

not take place. 

If a hearing is held, it will provide 

interested parties the opportunity to 

present data, views or arguments 

concerning the proposed action. The 

EPA will make every effort to 

accommodate all speakers who arrive 

and register. Because these hearings are 

being held at U.S. government facilities, 

individuals planning to attend the 

hearing should be prepared to show 

valid picture identification (e.g., driver’s 

license or government-issued ID) to the 

security staff in order to gain access to 

the meeting room. Please note that the 

REAL ID Act, passed by Congress in 

2005, established new requirements for 

entering federal facilities. These 

requirements will take effect July 21, 

2014. If your driver’s license is issued 

by Alaska, American Samoa, Arizona, 

Kentucky, Louisiana, Maine, 

Massachusetts, Minnesota, Montana, 

New York, Oklahoma or Washington 

State, you must present an additional 

form of identification to enter the 

federal buildings where the public 

hearings will be held. Acceptable 

alternative forms of identification 

include: Federal employee badges, 

passports, enhanced driver’s licenses 

and military identification cards. In 

addition, you will need to obtain a 

property pass for any personal 

belongings you bring with you. Upon 

leaving the building, you will be 

required to return this property pass to 

the security desk. No large signs will be 

allowed in the building, cameras may 

only be used outside of the building and 

demonstrations will not be allowed on 

federal property for security reasons. 

The EPA may ask clarifying questions 

during the oral presentations, but will 

not respond to the presentations at that 

time. Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as oral comments 

and supporting information presented at 

the public hearing. If a hearing is held 

on August 1, 2014, written comments on 

the proposed rule must be postmarked 

by September 2, 2014. Commenters 

should notify Ms. Hunt if they will need 

specific equipment, or if there are other 

special needs related to providing 

comments at the hearing. The EPA will 

provide equipment for commenters to 

show overhead slides or make 

computerized slide presentations if we 

receive special requests in advance. Oral 

testimony will be limited to 5 minutes 

for each commenter. Verbatim 

transcripts of the hearings and written 

statements will be included in the 

docket for the rulemaking. The EPA will 

make every effort to follow the schedule 

as closely as possible on the day of the 

hearing; however, please plan for the 

hearing to run either ahead of schedule 

or behind schedule. Information 

regarding the hearing (including 

information as to whether or not one 

will be held) will be available at: http:// 

www.epa.gov/airquality/oilandgas/

actions.html. Again, all requests for a 

public hearing to be held must be 

received by July 22, 2014. 

ADDRESSES: Submit your comments, 

identified by Docket ID Number EPA– 

HQ–OAR–2010–0505, by one of the 

following methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the online 

instructions for submitting comments. 

• Email: A-and-R-Docket@epa.gov. 

Include Docket ID No. EPA–HQ–OAR– 

2010–0505 in the subject line of the 

message. 

• Fax: (202) 566–9744, Attention 

Docket ID No. EPA–HQ–OAR–2010– 

0505. 

• Mail: Environmental Protection 

Agency, EPA Docket Center (EPA/DC), 

Mail Code 28221T, Attention Docket ID 

No. EPA–HQ–OAR–2010–0505, 1200 

Pennsylvania Avenue NW., Washington, 

DC 20460. Please include a total of two 

copies. In addition, please mail a copy 

of your comments on the information 

collection provisions to the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget 

(OMB), Attn: Desk Officer for EPA, 725 

17th Street NW., Washington, DC 20503 

• Hand/Courier Delivery: EPA Docket 

Center, Room 3334, EPA WJC West 

Building, 1301 Constitution Avenue 

NW., Washington, DC 20004, Attention 

Docket ID No. EPA–HQ–OAR–2010– 

0505. Such deliveries are only accepted 

during the Docket’s normal hours of 

operation, and special arrangements 


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should be made for deliveries of boxed 

information. 

Instructions: All submissions must 

include agency name and respective 

docket number or Regulatory 

Information Number (RIN) for this 

rulemaking. All comments will be 

posted without change and may 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 the 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 the 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, the 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 the EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may 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. 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 through http://

www.regulations.gov or in hard copy at 

the EPA’s Docket Center, Public Reading 

Room, EPA WJC West Building, Room 

Number 3334, 1301 Constitution 

Avenue NW., Washington, DC 20004. 

This docket facility is open from 8:30 

a.m. to 4:30 p.m., Monday through 

Friday, excluding legal holidays. The 

telephone number for the Public 

Reading Room is (202) 566–1744, and 

the telephone number for the Air Docket 

is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: Mr. 

Bruce Moore, Sector Policies and 

Programs Division (E143–05), Office of 

Air Quality Planning and Standards, 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, telephone number: (919) 541– 

5460; facsimile number: (919) 541–3470; 

email address: moore.bruce@epa.gov. 

SUPPLEMENTARY INFORMATION: Outline. 

The information presented in this 

preamble is organized as follows: 

I. Preamble Acronyms and Abbreviations 

II. General Information 

A. Does this proposed rule apply to me? 

B. What should I consider as I prepare my 

comments to the EPA? 

C. How do I obtain a copy of this document 

and other related information? 

III. Background 

IV. Today’s Action 

V. Executive Summary 

VI. Discussion of Provisions Subject to 

Reconsideration 

A. Well Completions 

B. Storage Vessels 

C. Routing of Reciprocating Compressor 

Rod Packing Emissions to a Process 

D. Equipment Leaks at Gas Processing 

Plants 

E. Definition of ‘‘Responsible Official’’ 

F. Affirmative Defense 

VII. Technical Corrections and Clarifications 

VIII. Impacts of This Proposed Rule 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. What are the economic and employment 

impacts? 

E. What are the benefits of the proposed 

standards? 

IX. 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 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. Preamble Acronyms and 

Abbreviations 

Several acronyms and terms are 

included in this preamble. While this 

may not be an exhaustive list, to ease 

the reading of this preamble and for 

reference purposes, the following terms 

and acronyms are defined here: 

API American Petroleum Institute 

BSER Best System of Emissions Reduction 

CAA Clean Air Act 

CFR Code of Federal Regulations 

EPA Environmental Protection Agency 

Mcf Thousand Cubic Feet 

NESHAP National Emissions Standards for 

Hazardous Air Pollutants 

NSPS New Source Performance Standards 

NTTAA National Technology Transfer and 

Advancement Act 

OAQPS Office of Air Quality Planning and 

Standards 

OMB Office of Management and Budget 

OVA Olfactory, Visual and Auditory 

PTE Potential to Emit 

RFA Regulatory Flexibility Act 

tpy Tons per Year 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act 

VCS Voluntary Consensus Standards 

VOC Volatile Organic Compounds 

VRU Vapor Recovery Unit 

II. General Information 

A. Does this proposed rule apply to me? 

Categories and entities potentially 

affected by today’s proposed rule 

include: 

TABLE 1—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS ACTION

Category NAICS code 1 Examples of regulated entities 

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

211112 Natural Gas Liquid Extraction. 

221210 Natural Gas Distribution. 

486110 Pipeline Distribution of Crude Oil. 

486210 Pipeline Transportation of Natural Gas. 

Federal government ..................................................................................................... ........................ Not affected. 


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TABLE 1—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS ACTION—Continued 

Category NAICS code 1 Examples of regulated entities 

State/local/tribal government ........................................................................................ ........................ Not affected. 

1 North American Industry Classification System. 

This table is not intended to be 

exhaustive, but rather is meant to 

provide a guide for readers regarding 

entities likely to be affected by this 

action. If you have any questions 

regarding the applicability of this action 

to a particular entity, consult either the 

air permitting authority for the entity or 

your EPA regional representative as 

listed in 40 CFR 60.4 or 40 CFR 63.13 

(General Provisions). 

B. What should I consider as I prepare 

my comments to the EPA? 

We seek comment only on the aspects 

of the final new source performance 

standards for the oil and natural gas 

sector specifically identified in this 

notice. We are not opening for 

reconsideration any other provisions of 

the new source performance standards 

(NSPS) at this time. 

Do not submit information containing 

CBI to the EPA through http://

www.regulations.gov or email. Send or 

deliver information identified as CBI 

only to the following address: Roberto 

Morales, OAQPS Document Control 

Officer (C404–02), Office of Air Quality 

Planning and Standards, U.S. 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, Attention: Docket ID Number 

EPA–HQ–OAR–2010–0505. Clearly 

mark the part or all of the information 

that you claim to be CBI. For CBI 

information in a disk or CD–ROM that 

you mail to the EPA, mark the outside 

of the disk or CD–ROM as CBI and then 

identify electronically within the disk or 

CD–ROM the specific information that 

is claimed as CBI. In addition to one 

complete version of the comment that 

includes information claimed as CBI, a 

copy of the comment that does not 

contain the information claimed as CBI 

must be submitted for inclusion in the 

public docket. Information so marked 

will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. 

C. How do I obtain a copy of this 

document and other related 

information? 

In addition to being available in the 

docket, electronic copies of these 

proposed rules will be available on the 

World Wide Web through the TTN. 

Following signature, a copy of this 

proposed rule will be posted on the 

TTN’s policy and guidance page for 

newly proposed or promulgated rules at 

the following address: http://

www.epa.gov/airquality/oilandgas/

actions.html. 

III. Background 

On August 16, 2012, the EPA 

published the Oil and Natural Gas 

Sector NSPS (40 CFR part 60 subpart 

OOOO) in the Federal Register at 77 FR 

49490. Following promulgation of the 

final rule, the Administrator received 

petitions for administrative 

reconsideration of several provisions of 

the NSPS pursuant to Clean Air Act 

(CAA) section 307(d)(7)(B). Copies of 

the petitions are provided in rulemaking 

docket EPA–HQ–OAR–2010–0505. On 

September 23, 2013, the EPA published 

final amendments primarily related to 

implementation of the storage vessel 

provisions. In the petitions for 

reconsideration of the 2012 final rule, 

petitioners raised several issues 

regarding clarification of the well 

completion provisions, some of which 

have a compliance deadline of January 

1, 2015. In addition, the Administrator 

received petitions for reconsideration of 

several provisions of the 2013 storage 

vessel implementation amendments. 

IV. Today’s Action 

Today, we are granting 

reconsideration of, proposing and 

requesting comment on the following 

limited set of issues raised in the 

petitions described above: (1) Provisions 

for well completions that clarify existing 

requirements for handling of flowback 

gases and liquids; (2) definition of ‘‘low 

pressure gas well’’ ; (3) requirements 

pertaining to determining the potential 

emission of storage vessels that employ 

vapor recovery; (4) requirements for 

thief hatches; (5) provisions for storage 

vessels that are removed from service; 

(6) routing of emissions from 

reciprocating compressor rod packing to 

a process; (7) leak detection 

requirements at small natural gas 

processing plants and natural gas 

processing plants located on the 

Alaskan North Slope; (8) equipment 

subject to leak detection requirements 

under the NSPS; and (9) definition of 

‘‘responsible official’’ for compliance 

certification purposes. In addition, we 

are proposing to remove the affirmative 

defense provisions from the startup, 

shutdown and malfunction provisions 

of the 2012 NSPS. Finally, we are 

proposing to correct technical errors in 

the 2012 NSPS. 

This notice is limited to the specific 

issues identified in this notice. We will 

not respond to any comments 

addressing any other provisions of the 

Oil and Natural Gas Sector NSPS. We 

will address any other issues for which 

we intend to grant reconsideration at a 

later time. 

The impacts of today’s proposed 

revisions on the costs and the benefits 

of the final rule are minor, but costsaving. We expect that affected facility 

owners and operators will install and 

operate the same or similar control 

technologies to meet the proposed 

revised standards in this notice as they 

would have chosen to comply with the 

standards in the August 2012 final rule, 

and revisions to the rule will not 

significantly impact emission 

reductions. 

V. Executive Summary 

The purpose of this action is to 

propose amendments to 40 CFR part 60, 

subpart OOOO, Standards of 

Performance for Crude Oil and Natural 

Gas Production, Transmission and 

Distribution. This proposal was 

developed to address certain issues 

primarily related to well completion 

and storage vessel provisions that have 

been raised by different stakeholders 

through several administrative petitions 

for reconsideration of the 2012 NSPS 

and the 2013 storage vessel amendments 

to the NSPS. The EPA is proposing to 

amend the NSPS to address these issues. 

We are proposing to amend the 

standards for gas well affected facilities 

to provide greater clarity concerning 

what owners and operators must do 

during well completion operations, 

especially the provisions for reduced 

emissions completions which have a 

compliance date of January 1, 2015. 

While the 2012 NSPS focused mainly on 

handling of flowback emissions, we did 

not provide extensive detail concerning 

requirements for handling of liquids 

during the well completion operation. 

In this action, we are proposing to 

identify three distinct stages of a well 

completion operation and specific 

requirements for handling of gases and 

liquids for each stage. The ‘‘initial 

flowback stage’’ begins with the onset of 


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flowback following hydraulic fracturing 

or refracturing and ends when there is 

sufficient gas present in the flowback for 

a separator to operate. At that time, the 

operator must direct the flowback to the 

separator, and the ‘‘separation flowback 

stage’’ begins. It is at this stage where 

recovery of the gas begins, unless the 

gas is unsuitable for entering the flow 

line, or infrastructure to convey the gas 

to market is not available, in which case 

the gas is required to be combusted 

unless combustion poses a safety 

hazard. Once the flowback volume has 

subsided and stabilized such that the 

well is producing gas continuously to 

the flow line or is shut in, and any crude 

oil, condensate and produced water in 

the flowback can be separated, the 

‘‘production stage’’ begins and 

continues as ongoing production of the 

well. At that time, the separated and 

recovered crude oil, condensate and 

produced water must be routed to 

storage vessels. At the beginning of the 

production stage, the operator must 

begin the 30-day process of estimating 

storage vessel volatile organic 

compound (VOC) potential to emit 

(PTE) and must control emissions no 

later than 60 days after the beginning of 

the production stage. Beginning with 

the production stage, the rule prohibits 

venting or flaring of gas. 

We are re-proposing for comment the 

definition of ‘‘low pressure gas well,’’ as 

related to the well completion 

provisions. We added this definition in 

the 2012 NSPS in response to public 

comments. Petitioners asserted that the 

definition is unnecessarily complicated 

and would pose difficulty for smaller 

operators. The petitioners provided a 

very straightforward alternative on 

which we are also soliciting comment. 

We are proposing several 

amendments related to the storage 

vessel provisions of the NSPS. First, we 

are proposing to amend the provisions 

for determining PTE for storage vessels 

with vapor recovery to clarify that the 

provisions allowing sources to exclude 

emissions captured through vapor 

recovery if certain specified control 

requirements are met do not apply to 

storage vessels whose PTE is limited to 

below the 6 tons per year (tpy) 

applicability threshold under a legally 

and practically enforceable permit or 

other limitation under federal, state or 

tribal authority. We are also proposing 

to amend the storage vessel closed cover 

requirements to allow other 

mechanisms besides weighted lid thief 

hatches to ensure that the thief hatch lid 

remains properly seated. In addition, we 

are proposing to amend slightly the 

requirements for storage vessels to 

clarify notification and other 

requirements under the NSPS for 

storage vessels that are removed from 

service. 

We are proposing to amend the 

requirements for reciprocating 

compressors to add a third alternative to 

the two existing work practice options 

for controlling emissions from rod 

packing venting. We are proposing a 

third alternative that would be to route 

emissions from the rod packing through 

a closed vent system to a process. 

We are proposing two amendments to 

the equipment leaks requirements for 

natural gas processing plants. One is to 

correct an inadvertent omission we 

made in the 2012 NSPS concerning an 

exemption from routine leak detection 

in small gas processing plants and gas 

processing plants located on the 

Alaskan North Slope. In the 2012 NSPS, 

we inadvertently failed to include 

connectors in the list of equipment 

under this exemption. In addition, we 

are proposing to amend the definition of 

‘‘equipment’’ to clarify that the term, as 

used in relation to the equipment leaks 

requirements under the NSPS, refers 

only to equipment at onshore natural 

gas processing plants. 

We are proposing to amend the 

definition of ‘‘responsible official’’ that 

is used in conjunction with the 

compliance certification provisions of 

the 2012 NSPS. We are proposing to 

amend the definition of ‘‘responsible 

official’’ to provide for delegation of 

authority after advance notification 

rather than after approval, which is 

currently required for delegation to 

authorities responsible for facilities that 

employ 250 or fewer employees and 

have less than $25 million gross annual 

sales or expenditures (in second quarter 

1980 dollars). Requirements for 

delegation to representatives 

responsible for one or more facilities 

that employ more than 250 persons or 

have gross annual sales or expenditures 

exceeding $25 million (in second 

quarter 1980 dollars) are unchanged 

from the 2012 NSPS (i.e., there is no 

advance notification or approval 

required for such delegations). 

Finally, we are proposing to remove 

the ‘‘affirmative defense’’ provisions 

from the startup, shutdown and 

malfunction provisions of the 2012 

NSPS. We are also proposing to correct 

technical errors in the 2012 NSPS. 

Details and rationale for all the above 

proposed amendments are presented in 

section VI below. 

VI. Discussion of Provisions Subject to 

Reconsideration 

As summarized above, the EPA is 

proposing to address a number of issues 

that have been raised by different 

stakeholders through several 

administrative petitions for 

reconsideration of the 2012 NSPS final 

action and 2013 storage vessel 

amendments. The following sections 

discuss the issues that the EPA is 

addressing in this action and how the 

EPA proposes to resolve the issues. 

A. Well Completions 

Several petitioners raised issues with 

regard to the well completion provisions 

in the 2012 NSPS, including handling of 

flowback gases and liquids and 

definition of ‘‘low pressure well.’’ While 

the 2012 NSPS focused mainly on 

handling of flowback gases, we did not 

provide extensive detail concerning 

requirements for handling of liquids 

during the various stages of well 

completion. The proposed amendments 

to the regulatory text discussed below 

provide clarity concerning what owners 

and operators must do during 

completion operations, and the 

proposed amendments to the 

requirements would maintain the same 

level of reduction as the 2012 NSPS. 

1. Handling of Flowback Gases and 

Liquids 

The petitioners asserted that the rule 

is unclear with regard to requirements 

in § 60.5375 for handling of gases and 

liquids during flowback and that, as 

written, compliance with the existing 

language cannot be achieved. 

Specifically, petitioners asserted that 

§ 60.5375(a)(1) which states ‘‘(F)or the 

duration of flowback, route the 

recovered liquids into one or more 

storage vessels . . . and route the 

recovered gas into a gas flow line or 

collection system . . . with no direct 

release to the atmosphere’’ could be 

interpreted to prohibit venting of gases 

at any time during the flowback period. 

According to petitioners, at the 

beginning of the flowback period, the 

flowback consists initially of water, 

fracturing fluids and proppant (sand) 

with no gas present. At some point, 

sporadic slugs of gas begin to appear in 

the flowback in increasing amounts 

until enough gas is present to approach 

flammability and to enable a separator 

to function. Petitioners explained that 

operators usually locate a monitor on 

the vessel receiving the initial flowback 

to sense the gas concentration. When 

the gas concentration approaches 

flammability, the flowback is then 

directed to a separator. For a separator 

to function, enough gas must be flowing 

to maintain a gaseous phase and one or 

more liquid phases within the separator. 

In addition, petitioners explained that 

the requirement to ‘‘route the recovered 

liquids into one or more storage vessels’’ 


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1Letter from Matt Todd, American Petroleum 

Institute, to Bruce Moore, EPA Office of Air Quality 

Planning and Standards, July 25, 2012. 

2Letter from Peter Tsirigotis, EPA Office of Air 

Quality Planning and Standards, to Matt Todd, 

American Petroleum Institute, September 28, 2012. 

3Recent studies have shown that air emissions 

from open top tanks used during initial flowback 

are very low. Allen, David, T., et al. 2013. 

Measurements of methane emissions at natural gas 

production sites in the United States. Proceedings 

of the National Academy of Sciences (PNAS) 500 

Fifth Street NW., NAS 340 Washington, DC 20001 

USA. October 29, 2013. 

is not feasible because of the 

composition and high volumetric flow 

of the initial flowback that necessitate 

using open top tanks or a pit for this 

purpose. As explained by the 

petitioners, this initial high volume 

liquid flowback carries with it sand and 

debris that can be removed relatively 

easily from open top tanks or that can 

settle to the bottom of lined pits. The 

petitioners also explained that removal 

of sand and debris from a closed top 

tank is extremely difficult and must be 

performed manually. Petitioners further 

noted that, because temporary tanks are 

excluded from the definition of ‘‘storage 

vessel,’’ such temporary tanks as 

fracture tanks (frac tanks) cannot be 

used to comply with requirements of the 

2012 NSPS. 

In the EPA’s clarification letter to the 

American Petroleum Institute (API),1 2

we explained that it was not the EPA’s 

intent to prohibit venting of flowback 

gases throughout the entire flowback 

period and that we understood that 

there were periods during which gas 

may be present in the flowback but with 

insufficient volume and consistency of 

flow to enable either combustion or 

recovery of the gas through separation. 

Our clarification letter further 

responded to the issue of routing of all 

recovered liquids to storage vessels. We 

explained that the term ‘‘recovered 

liquids’’ refers to condensate, crude oil 

and produced water recovered through 

the separation process. Although the 

2012 NSPS does not define ‘‘recovered 

liquids,’’ the discussion of the proposed 

NSPS for storage vessels describes the 

storage of ‘‘crude oil, condensate and 

produced water.’’ (see 76 FR 72763, 

August 23, 2011). In our clarification 

letter to API, we stated that the 2012 

final rule accurately reflected our intent 

to require these liquids to be routed to 

‘‘storage vessels,’’ which may be subject 

to control in the rule depending on their 

potential to emit VOC and their affected 

facility status. We confirmed that the 

initial flowback (prior to recovery of 

these liquids through separation) may 

be routed to temporary fracture tanks 

(frac tanks) or other portable tanks (i.e., 

tanks that do not meet the definition of 

‘‘storage vessel’’) as long as separation 

occurs as soon as practicable, consistent 

with the general duty to maximize 

resource recovery and minimize releases 

to the atmosphere as required in 

§ 60.5375(a)(4). 

In light of petitioners’ assertions and 

the confusion caused by the current 

regulatory language in the well 

completion provisions, we reexamined 

the regulatory text in § 60.5375 and 

concluded that more clarity is needed 

such that owners, operators, regulatory 

agencies and the public could readily 

understand what was required at 

various stages of a hydraulically 

fractured well completion operation. 

We believe that the requirements of 

the rule would be easier to understand 

if the rule identified distinct stages 

associated with well completion, with 

each stage having specific requirements 

for handling of gases and liquids. To 

that end, we are proposing that each 

well completion subject to § 60.5375 

consists of three distinct stages. 

The first stage begins with the first 

flowback from the well following 

hydraulic fracturing or refracturing, and 

is characterized by high volumetric flow 

water, with sand, fracturing fluids and 

debris from the formation with very 

little gas being brought to the surface, 

usually in multiphase slug flow. As the 

flowback proceeds, the amount of gas 

appearing in the flowback increases to 

the point where there is enough gas 

present for a separator to function, at 

which time the well completion would 

enter the second stage. We are 

proposing that the first stage be defined 

as the ‘‘initial flowback stage,’’ during 

which the flowback must be routed to 

a ‘‘well completion vessel’’ that can be 

an open top frac tank, a lined pit or any 

other vessel. During the initial flowback 

stage, there would be no requirement for 

controlling emissions from the tank, and 

any gas in the flowback during this stage 

could be vented.3 We propose that the 

flow must be diverted to a separator as 

soon as a sufficient amount of gas is 

present in the flowback to operate the 

separator. The EPA is seeking to 

establish, if possible, objective criteria 

for determining when there is sufficient 

gas in the flowback for the separator to 

function and is therefore soliciting 

comment on one potential approach. It 

is our understanding that some 

operators monitor the gas concentration 

at the vessel receiving the flowback for 

safety reasons and to determine that 

sufficient gas is present in the flowback. 

When the gas concentration approaches 

the lower explosive limit (LEL) (i.e., 

approaches flammability), these 

operators direct the flowback to a 

separator. While we are aware that some 

operators employ this technique, we are 

uncertain whether it can be used 

effectively in all applications and 

whether there are other techniques used 

by operators to make this determination. 

We therefore solicit comment on the 

suitability of the ‘‘LEL method’’ when 

used for this purpose and seek 

information on other techniques or 

indicators that may be used to 

determine when sufficient gas is present 

for a separator to function. 

The second stage would begin when 

the flowback gases and liquids are 

routed to the separator, which would be 

required as soon as sufficient gas is 

present for the separator to function. 

This stage, which we propose to define 

as the ‘‘separation flowback stage,’’ is 

characterized by the separator operating 

(i.e., there is sufficient gas in the 

flowback to maintain a gaseous phase 

and one or more liquid phases in the 

separator). During the separation 

flowback stage, the operator would be 

required to route the recovered gas into 

a gas flow line or collection system, reinject the recovered gas into the well or 

another well, use the recovered gas as 

an on-site fuel source or use the 

recovered gas for another useful purpose 

that a purchased fuel or raw material 

would serve. If, during the separation 

flowback stage, it was technically 

infeasible to route the recovered gas to 

a flow line or collection system (e.g., if 

there was no flow line or other 

infrastructure available at the site for 

collection of the gas), reinject the gas or 

use the gas as fuel or for other useful 

purpose, the recovered gas (i.e., 

‘‘flowback emissions’’) would have to be 

combusted using a completion 

combustion device. No direct venting of 

recovered gas would be allowed during 

the separation flowback stage. If, at any 

time during the separation flowback 

stage, the recoverable gas present in the 

flowback becomes insufficient to 

maintain operation of the separator, the 

operation would revert to the initial 

flowback stage until the gas was again 

present in sufficient volume to operate 

the separator. During the separation 

flowback stage, all liquids from a 

separator could be directed to one or 

more well completion vessels or storage 

vessels, or be re-injected into the well or 

another well (i.e., during this stage, 

operators would not be required to route 

flowback liquids to ‘‘storage vessels’’ as 

defined in the NSPS). During this stage 

of a completion, the flowback continues 

to have a very high volumetric flow rate, 

with the hydrocarbon content (and 

potential to emit VOC) often increasing 


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4 In the 2012 NSPS, § 60.5375(a)(2) and (3) require 

that ‘‘flowback emissions’’ be either routed to a flow 

line or to a completion combustion device. In our 

clarification letter to API, we clarified that 

‘‘flowback emissions’’ refers to the recovered gas 

and vapor after separation. 

5Oil and Natural Gas Sector: Standards of 

Performance for Crude Oil and Natural Gas 

Production, Transmission, and Distribution— 

Background Supplemental Technical Support 

Document for the Final New Source Performance 

Standards, USEPA, Office of Air Quality Planning 

and Standards, April 2012. 

with time and being dependent on the 

characteristics of the gas (e.g., to what 

degree the gas is ‘‘wet’’ or ‘‘dry’’). It is 

our understanding that the initially high 

volume and inconsistent character of 

the flowback will gradually subside and 

stabilize. At some point, the flowback 

will have declined and stabilized 

enough to allow continuous recovery of 

the gas. It would also allow separation 

and recovery of any crude oil, 

condensate and produced water. We 

propose to define this point as the end 

of the separation flowback stage and the 

beginning of the ‘‘production stage.’’ We 

seek to establish, if possible, objective 

criteria on which to base a 

determination that the well has reached 

that point, and we therefore solicit 

comment on the characteristics of the 

flow or other conditions that could be 

used to establish such criteria. During 

the production stage, we propose to 

prohibit gas from the separator being 

vented or controlled by combustion, and 

require that all recovered liquids be 

routed to storage vessels. 

We are proposing that the beginning 

of the production stage would also begin 

the 30-day period for determining VOC 

potential to emit for purposes of making 

a storage vessel affected facility 

determination in accordance with the 

procedure in § 60.5365(e). If the criteria 

under § 60.5365(e) were met, the 

operator would have to comply with the 

control requirements in § 60.5395(d)(1) 

within 60 days after the beginning of the 

production stage. We are proposing to 

amend § 60.5365(e) to reflect that, for 

purposes of the well completion 

provisions, the 30-day period for the 

affected facility determination required 

§ 60.5365(e) would commence at the 

beginning of the production stage. We 

are proposing to amend 

§ 60.5395(d)(1)(i) to reflect that, for 

purposes of the well completion 

provisions, control would be required 

no later than 60 days from the beginning 

of the production stage. We propose 

revising § 60.5395(d)(1)(i) to read: 

(i) Except as otherwise provided in this 

paragraph, for each Group 2 storage vessel 

affected facility, you must achieve the 

required emissions reductions by April 15, 

2014, or within 60 days after startup, 

whichever is later. For storage vessels 

receiving liquids pursuant to the standards 

for gas well affected facilities in § 60.5375, 

you must achieve the required emissions 

reductions within 60 days after the beginning 

of the production stage as defined in 

§ 60.5430. 

In addition, we are proposing 

amendments to the reporting and 

recordkeeping requirements in 

§ 60.5420 to revise the terminology used 

in that section relating to periods of 

recovery, combustion and venting to be 

compatible with the terms identified in 

the proposed clarifying amendments to 

§ 60.5375. 

Similarly, we are proposing revisions 

to the terms used in the regulatory text 

for exploratory, delineation and low 

pressure wells at § 60.5375(f) to be 

consistent with the proposed amended 

terminology and requirements in 

§ 60.5375(a). 

Petitioners also raised the issue of 

‘‘screenouts’’ and ‘‘coil tubing 

cleanouts,’’ which are remedial 

operations sometimes required during 

flowback when flow is impeded or 

blocked by packed proppant (sand) and 

must be restored to prevent permanent 

damage to the well. As related in 

petitions, a screenout is the first attempt 

to clear the proppant that can plug the 

wellbore. A screenout involves flowing 

the well to a frac tank in a manner to 

achieve maximum velocity to carry the 

sand out of the well. If a screenout is 

unsuccessful in clearing the packed 

sand from the wellbore, then the well 

typically is ‘‘jetted’’ using a string of coil 

tubing and nitrogen gas to dislodge the 

sand and provide sufficient lift energy 

to flow it to surface. Small amounts of 

gas and condensate may be part of the 

flowback fluids during screenouts and 

coil tubing cleanouts. In our 

clarification letter to API, we explained 

that any gas or vapor liberated during 

screenouts and coil tubing cleanouts, 

both of which are operations prior to the 

point of separation, were not ‘‘flowback 

emissions’’ 4 and, as a result, were not 

subject to the work practice standards 

for gas well affected facilities. 

2. Definition of ‘‘Low Pressure Gas 

Well’’ 

In the August 23, 2011, proposed rule, 

the EPA solicited comments on 

situations where reduced emission 

completion (REC) would be infeasible 

(see 76 FR 52758, August 23, 2011). 

Several commenters highlighted 

technical issues that prevent the 

implementation of a REC on what they 

referred to as ‘‘low pressure’’ gas wells 

because of the lack of the necessary 

reservoir pressure to flow at rates 

appropriate for the transportation of 

solids and liquids from a hydraulically 

fractured gas well completion against an 

imposed back-pressure. Based on our 

analysis of the public comments 

received, we learned that there are 

certain wells where a REC is infeasible 

because of the characteristics of the 

reservoir and the well depth that will 

not allow the flowback to overcome the 

gathering system pressure due to the 

back pressure imposed by the REC 

surface equipment. Accordingly, in 

response to those comments, we 

provided in the 2012 final NSPS at 

§ 60.5375(f) that ‘‘low pressure’’ gas 

wells (i.e., those wells for which a REC 

would not be feasible because of a 

combination of well depth, reservoir 

pressure and flow line pressure) would 

not be required to meet the 

requirements for recovery of gases and 

liquids required under § 60.5375(a), 

except as provided in § 60.5375(f)(2) 

which subjects wildcat, delineation and 

low pressure gas wells to requirements 

for combustion of flowback emissions 

and to the general duty to safely 

maximize resource recovery and 

minimize releases to the atmosphere 

required under § 60.5375(a)(4). Under 

the 2012 final NSPS, low pressure wells 

are treated the same as exploratory and 

delineation wells (i.e., they are not 

required to perform a REC). We also 

added a definition of ‘‘low pressure gas 

well’’ in the final rule that is based on 

a mathematical formula that takes into 

account a well’s depth, reservoir 

pressure and flow line pressure. The 

definition at § 60.5430 is as follows: 

Low pressure gas well means a well with 

reservoir pressure and vertical well depth 

such that 0.445 times the reservoir pressure 

(in psia) minus 0.038 times the vertical well 

depth (in feet) minus 67.578 psia is less than 

the flow line pressure at the sales meter. 

A detailed discussion of development 

of the definition and derivation of the 

formula was provided in the 

Supplemental Technical Support 

Document for the 2012 final rule.5

Following publication of the final 

rule, a group of petitioners representing 

independent oil and natural gas owners 

and operators submitted a joint petition 

for administrative reconsideration of the 

2012 NSPS. The petitioners questioned 

the technical merits of the low pressure 

well definition and asserted that the 

public had not had an opportunity to 

comment on the definition because it 

was added in the final rule. The 

petitioners expressed concern that the 

formula adopted in the 2012 NSPS was 

based on ‘‘questionable assumptions’’ 

and ‘‘sparse data’’ and will ‘‘exclude 

from its scope many gas wells drilled in 

formations that historically have been 


pmangrum on DSK3VPTVN1PROD with PROPOSALS2
41758 Federal Register / Vol. 79, No. 137 / Thursday, July 17, 2014 / Proposed Rules 

6Letter from James D. Elliott, Spilman, Thomas 

& Battle PLLC, to Lisa P. Jackson, EPA 

Administrator, October 15, 2012; Petition for 

Administrative Reconsideration of Final Rule ‘‘Oil 

and Gas Sector: New Source Performance Standards 

and National Emission Standards for Hazardous Air 

Pollutants Reviews,’’ 77 FR 49490 (August 16, 

2012). 

7Email from James D. Elliott, Spilman, Thomas 

& Battle PLLC, to Bruce Moore, EPA, March 24, 

2014. 

recognized as ‘low pressure.’ 

Accordingly, in the view of the 

petitioners, this exclusion—or lack 

thereof—has the potential to directly 

affect many smaller producers, who are 

less likely to be able to bear the costs of 

implementing costly RECs.’’ 6 However, 

the administrative petition did not 

include any details on which of EPA’s 

assumptions is questionable and why, 

or what additional data the petitioners 

consider necessary to support EPA’s 

‘‘low pressure gas well’’ definition. We 

were therefore unable to assess 

petitioners’ assertions regarding the 

‘‘low pressure gas well’’ definition in 

the 2012 final NSPS. 

On March 24, 2014, the petitioners 

submitted to the EPA a suggested 

alternative definition 7 for 

consideration. The petitioners’ 

definition is based on the fresh water 

hydrostatic gradient of 0.433 pounds per 

square inch per foot (psi/ft). The 

petitioners assert that this approach is 

straightforward and has been recognized 

for many years in the oil and natural gas 

industry and by governmental agencies 

and professional organizations. As 

expressed in the paper submitted by the 

petitioners, the alternative definition for 

consideration by the EPA, as stated by 

the petitioners, would be: 

A well where the field pressure is less than 

0.433 times the vertical depth of the deepest 

target reservoir and the flow-back period will 

be less than three days in duration 

We agree with the petitioners that this 

alternative definition is straightforward 

and easy to use. However, we are 

concerned that it may be too simplistic 

and may not adequately account for the 

parameters that must be taken into 

account when determining whether a 

REC would be feasible for a given 

hydraulically fractured gas well. 

Further, we question how an operator 

would know before flowback begins that 

the flowback period would be less than 

3 days in duration. 

We believe that, to determine whether 

the flowback gas has sufficient pressure 

to flow into a flow line, it is necessary 

to account for reservoir pressure, well 

depth and flow line pressure. In 

addition, it is important for any such 

determination to take into account 

pressure losses in the surface equipment 

used to perform the REC. The EPA’s 

proposed definition was developed to 

account for these factors. 

We further disagree with the 

petitioners’ assertion that the EPA 

definition is too complicated. We 

believe that values for each of the three 

parameters discussed above and used in 

the EPA definition are known by 

operators in advance of flowback and 

that the relatively simple calculation 

called for in the EPA definition could be 

performed with a basic hand-held 

calculator and should not pose 

difficulty or hardship for smaller 

operators. 

However, we agree with the 

petitioners that the public should be 

provided an opportunity to comment on 

the 2012 definition of ‘‘low pressure gas 

well.’’ We are therefore re-proposing 

that definition for notice and comment. 

In addition, we solicit comment on the 

definition suggested by the petitioners. 

The petitioners’ background paper and 

supporting documents for the 

alternative definition have been placed 

in the public docket for this action. We 

believe that soliciting comments on both 

definitions would help us better 

understand and characterize the term 

‘‘low pressure gas well’’ for which REC 

is not feasible. 

B. Storage Vessels 

On September 23, 2013, the EPA 

published amendments primarily 

focused on storage vessel 

implementation issues raised by 

petitioners following publication of the 

2012 final NSPS. Following publication 

of the 2013 storage vessel amendments, 

three petitioners raised issues with 

regard to various provisions of the 

amendments. Among these issues are 

requirements for determining PTE for 

storage vessels employing vapor 

recovery under a legal and practically 

enforceable limitation, requirement for 

thief hatches being properly seated and 

clarification of the term ‘‘storage vessels 

removed from service.’’ 

1. PTE Determination for Storage 

Vessels Employing Vapor Recovery 

Under a Legally and Practically 

Enforceable Limitation 

In the 2013 final storage vessel 

amendments to the NSPS, we provided 

at § 60.5365(e) that the determination of 

a storage vessel’s VOC PTE may take 

into account requirements under a 

legally and practically enforceable limit 

in an operating permit or other 

requirement established under a federal, 

state, local or tribal authority. We 

further provided that any vapor from the 

storage vessel that is recovered and 

routed to a process through a vapor 

recovery unit (VRU) designed and 

operated as specified in § 60.5365(e) is 

not required to be included in the 

determination of VOC PTE. 

In petitions for reconsideration of the 

storage vessel amendments, petitioners 

pointed out that, if a VRU is required by 

a legally and practically enforceable 

limitation under which the storage 

vessel is operating, then § 60.5365(e)(1) 

through (4) should not apply. The 

petitioners explained that, in such 

cases, removal of the VRU would violate 

the enforceable limitation, thereby 

making the prior affected facility 

determination of VOC PTE invalid. 

They further assert their understanding 

that the EPA intended that 

§ 60.5365(e)(1) through (4) should apply 

only to storage vessels which are not 

under a legal and practically enforceable 

limit but which are employing vapor 

recovery to lower the VOC PTE. 

§ 60.5365(e) allows an owner or 

operator of a storage vessel to exclude 

from its PTE determination any vapor 

routed to a process through a VRU 

provided that conditions in 

§ 60.5365(e)(1) through (4), which relate 

to the design and operation of cover and 

closed vent system associated with the 

VRU, are met (hereinafter referred to as 

the ‘‘PTE exclusion provision’’). 

However, this is not the only way for a 

storage vessel to demonstrate that its 

PTE is below the 6 tpy threshold. As 

stated in the 2013 amendment and 

reiterated above, a storage vessel’s PTE 

determination can take into account 

requirements under a legally and 

practically enforceable limit in an 

operating permit or other requirement 

established under a federal, state, local 

or tribal authority. However, it appears 

that there may be misinterpretation of 

the PTE exclusion provision as 

requiring compliance with 

§ 60.5365(e)(1) through (4) in all cases, 

even where a storage vessel has VOC 

PTE less than 6 tpy under a legally and 

practically enforceable limit in an 

operating permit or other requirement 

established under a Federal, state, local 

or tribal authority. Under such a permit 

or limitation, an operator therefore does 

not need to invoke the NSPS PTE 

exclusion provision. Further, we 

conclude that the PTE exclusion 

provision would only be invoked by a 

storage vessel absent any legally and 

practically enforceable limit under 

which the storage vessel was being 

operated to maintain its VOC PTE less 

than 6 tpy. 

In light of the points raised by the 

petitioners and considering the EPA’s 

original intent, we are proposing to 

amend § 60.5365(e) to allow the PTE 

exclusion provision only in cases where 


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a storage vessel is not subject to any 

legal and practically enforceable 

limitation or other requirement under a 

Federal, state, local or tribal authority. 

Accordingly, we propose to revise the 

last full paragraph of § 60.5365(e) as 

follows: 

For storage vessels not subject to a legally 

and practically enforceable limit in an 

operating permit or other requirement 

established under a federal, state, local or 

tribal authority, any vapor from the storage 

vessel that is recovered and routed to a 

process through a VRU designed and 

operated as specified in this section is not 

required to be included in the determination 

of VOC potential to emit for purposes of 

determining affected facility status, provided 

you comply with the requirements in 

paragraphs (e)(1) through (4) of this section. 

2. Thief Hatch Properly Seated 

Thief hatches are generally hinged 

access openings in the roof of storage 

vessels that serve as emergency 

overpressure relief devices and a point 

of access for obtaining a sample of the 

material stored or for gauging the liquid 

level. To be functional, the thief hatch 

must be able to open when access is 

needed, yet close and seal properly to 

prevent vapor at very low pressure from 

escaping. The hatch must be able to 

open readily during overpressure events 

to prevent damage to the storage vessel. 

Storage vessels used in this industry 

sector are generally designed to operate 

at atmospheric pressure. The 2012 final 

NSPS requires at § 60.5411(b)(3) that 

thief hatches be ‘‘weighted and properly 

seated.’’ 

Petitioners asserted that the 

requirement for the thief hatch lid to be 

‘‘weighted’’ is too restrictive, since there 

are other types and mechanisms that 

provide the same functionality (i.e., the 

lid presses on the seating surface with 

sufficient force to ensure proper seating 

while allowing opening manually for 

personnel access or automatically 

during overpressure events) as a 

weighted lid thief hatch. The petitioners 

requested that the NSPS be revised to 

allow the use of other types (e.g., 

hatches with spring-loaded lids) besides 

weighted-lid hatches. 

We agree with the petitioners that 

other mechanisms that would provide 

equivalent function to that provided by 

a weight should be allowed for thief 

hatch lid control, since the important 

factor here is to ensure that the hatch lid 

remains properly closed, whether with 

a weight or another mechanism, at all 

times except during personnel access 

and overpressure events. As a result, we 

are proposing to amend § 60.5411(b)(3) 

to require that the thief hatch be 

equipped with a mechanism or be of 

such design and properly maintained 

and operated to ensure that the lid 

remains properly seated. 

3. Storage Vessels Removed From 

Service 

The 2013 final storage vessel 

amendments to the NSPS added 

provisions at § 60.5395(f) that apply to 

storage vessel affected facilities that are 

removed from service. Provisions are 

also included for storage vessel affected 

facilities that are later returned to 

service. 

Petitioners assert that the provisions 

for storage vessel affected facilities that 

are removed from service need 

clarification to avoid misinterpretation 

that the NSPS requires reporting of 

every instance of a storage vessel being 

temporarily shut down for maintenance. 

In addition, petitioners requested that 

the EPA provide clarity by adding a 

definition of ‘‘removed from service.’’ 

Petitioners also requested that 

§ 60.5395(f) state explicitly that a 

storage vessel affected facility that is 

removed from service is no longer 

subject to the control, reporting or 

recordkeeping requirements of the 

NSPS, other than reporting that it has 

been removed from service, until such 

time as it is subsequently returned to 

service. Petitioners also suggested that 

the required notifications include the 

date that the storage vessel-affected 

facility is removed from service or 

restored to service to assist in 

documenting the period of time for 

which the NSPS did not apply to a 

given storage vessel-affected facility. 

We reexamined § 60.5395(f) and 

propose to clarify the requirements 

regarding storage vessel affected 

facilities removed from service to avoid 

potential misinterpretation of these 

requirements. Our intent in including 

such provisions in the 2013 storage 

vessel amendments was to ensure that 

unnecessary burden was not imposed by 

the NSPS by requiring emission control, 

compliance monitoring, reporting and 

recordkeeping activities for storage 

vessels that were removed from service 

for reasons other than maintenance. 

Based on our review, we are proposing 

to add a definition of ‘‘removed from 

service’’ to § 60.5430 as follows: 

Removed from service means that a storage 

vessel affected facility has been physically 

isolated and disconnected from the process 

for a purpose other than maintenance and is 

no longer used to contain crude oil, 

condensate, produced water or intermediate 

hydrocarbon liquids. If the storage vessel 

affected facility is reconnected to the process, 

or introduced with crude oil, condensate, 

produced water or intermediate hydrocarbon 

liquids at the same location, or relocated to 

another location and utilized as a storage 

vessel for crude oil, condensate, produced 

water or intermediate hydrocarbon liquids, it 

will be deemed to no longer be ‘‘removed 

from service’’ and at that time will be 

deemed ‘‘returned to service’’ and subject to 

the provisions of this subpart applicable to 

such vessel. 

We are also proposing to amend 

§ 60.5395(f)(1) and (2), and 

§ 60.5420(b)(6) to require that the dates 

that storage vessel-affected facilities are 

removed from service and returned to 

service be included when reporting 

those actions. 

4. Electronic Spark Ignition for 

Combustion Devices for Well 

Completions, Storage Vessels and Wet 

Seal Centrifugal Compressors 

The 2012 final NSPS requires a 

continuous pilot flame for well 

completion combustion devices and for 

combustors used to control emissions 

from storage vessels and wet seal 

centrifugal compressors. Commenters 

on the 2011 proposed NSPS and 

NESHAP had asserted that these rules 

should allow the use of automatic 

electronic spark ignition as an 

alternative to a continuous pilot flame 

for these control devices. In our 

response to public comments, we had 

clarified that the rule does not allow 

electronic ignition devices as surrogates 

for a continuous ignition source. The 

continuous ignition source is designed 

to combust the flammable portion of the 

flowback gas from a well completion, 

even if the flowback gas has a low BTU 

content. We further explained that an 

electronic ignition device designed for 

ignition of a combustible stream would 

not be successful at combusting VOC 

portions of low BTU flowback gas. With 

regard to storage vessels, we 

acknowledged the growing use of 

electronic spark ignition systems for 

flares. We explained that, however, 

given the intermittent and inconsistent 

nature of emissions from tanks in this 

industry combined with the highly 

variable VOC concentration in the 

emissions, we did not believe a sparkignited flare would achieve the same 

level of emission reduction as a flare 

with a continuous flame present. We 

also noted that there were not sufficient 

data at this time to suggest that 

electronic ignition systems on 

combustion devices are capable of 

continuously supplying a constant 

source of ignition to keep a flame 

present on a continuous basis. In 

addition, for flares, test data for which 

the current standards in §§ 63.11(b) and 

60.18 were written show that operating 

a flare with a continuously lit pilot adds 

an additional degree of flame stability to 


pmangrum on DSK3VPTVN1PROD with PROPOSALS2
41760 Federal Register / Vol. 79, No. 137 / Thursday, July 17, 2014 / Proposed Rules 

8U.S. Environmental Protection Agency, Natural 

Gas STAR Program. Partner Reported 

Opportunities—Install Electronic Flare Ignition 

Devices, PRO Fact Sheet No. 903, 2011. 

9Letter from Veronica Nasser, REM Technologies, 

Inc., to Lisa P. Jackson, EPA Administrator, Petition 

for Reconsideration. 

10 Docket document number EPA–HQ–OAR– 

2010–0505–4546, ‘‘Oil and Natural Gas Sector: New 

Source Performance Standards and National 

Emission Standards for Hazardous Air Pollutants 

Reviews, 40 CFR Parts 60 and 63, Response to 

Public Comments on Proposed Rule August 23, 

2011 (76 FR 52738),’’ Section 2.7.3, (U.S. EPA, 

April 2012). 

the flare itself. Therefore, we did not 

allow electronic spark ignition as an 

alternative to a continuous pilot flame 

in the final rule. 

The issue was raised by petitioners in 

response to the 2012 final NSPS in the 

context of completion combustion 

devices, but petitioners did not provide 

additional data or information to refute 

EPA’s rationales for not allowing 

electronic spark ignition in the 2012 

Final NSPS, as described above. The 

issue was raised again in public 

comments received on the 2013 

proposed storage vessel amendments 

without additional data or information. 

However, the commenters asserted that 

the EPA’s own Natural Gas Star program 

encourages the use of electronic ignition 

instead of a continuous pilot flame.8 In 

our response to public comments, we 

maintained our previous position and 

rationales and declined to provide in 

the final NSPS storage vessel 

amendments that electronic spark 

ignition would be an acceptable 

alternative to continuous pilot flame for 

storage vessel control devices. 

The EPA encourages innovation and 

also believes that resource conservation 

should be encouraged where possible. 

We believe electronic spark ignition is 

a promising technology, and for that 

reason highlighted it in the Natural Gas 

STAR publication cited by the 

petitioners. However, we still have 

concerns about the dependability of 

these devices and control efficiency 

afforded by this technology and would 

like to have more information that could 

inform further consideration of the 

petitioners’ assertions. 

We solicit information that would 

inform our evaluation of this technology 

as an alternative to a continuous pilot 

flame used with combustion devices for 

control of emissions from well 

completions, storage vessels and 

centrifugal compressor wet seal 

degassing systems. Specifically we 

solicit information, including any test 

data or other documentation, that may 

help address the following topics 

relative to the operation of an electronic 

spark ignition: (1) Appropriate design, 

operation and maintenance procedures 

to ensure proper combustion of the 

waste stream; (2) use of safety valves to 

ensure that no gas is available for 

combustion if the ignition system is not 

functional; (3) measures that could be 

taken to avoid vapor venting upstream 

of the control device in cases where the 

safety valve remains closed; (4) 

frequency of monitoring for proper 

operation; (5) specific checks to be made 

to ensure proper operation; (6) operating 

parameters that affect pilot-less flare 

performance and flare flame stability; 

(7) effects of gas with low BTU content 

or gas of variable VOC content; and (8) 

how often these systems need to be 

replaced. 

In addition, we are interested in 

learning more about the use of this 

technology as a means of ensuring that 

continuous flame pilots remain 

functional at all times. Therefore, we 

also solicit comment, including any 

supporting data or information, on 

whether automatic spark ignition 

relighting systems should be required as 

a means of ensuring that continuous 

flame pilots remain functional at all 

times. 

Based on our evaluation of the data 

and comments received, we may 

provide language in the final rule that 

would allow electronic spark ignition as 

an alternative to a continuous pilot 

flame. We may also provide language in 

the final rule that would require 

automatic electronic spark ignition 

relighting systems. 

C. Routing of Reciprocating Compressor 

Rod Packing Emissions to a Process 

The 2012 final NSPS includes 

operational (i.e., ‘‘work practice’’) 

standards for reciprocating compressors 

to reduce emissions from gas vented 

from the piston rod packing as the rod 

moves during operation. The rule 

requires regular rod packing 

replacement every 26,000 hours of 

operation or, if the owner and operator 

elect, every 36 months. 

On October 15, 2012, the 

Administrator received a petition for 

administrative reconsideration of the 

performance standards for reciprocating 

compressors. The petitioners asserted 

that an available alternative would 

reduce reciprocating compressor 

emissions to levels equivalent to, or 

better than, the emission levels achieved 

by the operational standard.9 The 

alternative technology consists of 

recovering vented emissions from the 

rod packing under negative pressure 

and routing these emissions of 

otherwise vented gas to the air intake of 

a reciprocating internal combustion 

engine that would burn the gas as fuel 

to augment the normal fuel supply. The 

system’s computerized air/fuel control 

system would then adjust the normal 

fuel supply to accommodate the 

increased fuel made available from the 

recovered emissions and thereby take 

advantage of the recovered emissions 

while avoiding an overly rich fuel 

mixture. 

The petitioner requested that the EPA 

consider this alternative technology and 

that the EPA revise the provisions of 

Subpart OOOO to allow for this 

alternative to the operational standard. 

The petitioner pointed out that subpart 

OOOO already includes similar options 

for handling of vented emissions from 

centrifugal compressors and storage 

vessels and that similar alternatives 

could apply for reciprocating 

compressors as well. Access to similar 

technologically valid approaches should 

be an option for reciprocating 

compressors. The petitioner reasoned 

that such an option would provide 

emission reductions in excess of 99.5 

percent attributed to the efficiency of 

the computer-controlled combustion of 

the engine and the recovery of the 

emissions under negative pressure 

produced by the engine air intake. The 

petitioner reasoned that emission 

reductions would be commensurate 

with or better than the reductions from 

the operational standard. 

Finally, the petitioner asserted that 

alternatives to the reciprocating 

compressor operational standard were 

not adequately reviewed by the EPA 

and, in its response to comments 

document, the EPA addressed 

comments from the petitioner and 

others with little more than a passive 

response.10

The EPA values innovation on the 

part of owners, operators and equipment 

vendors serving the Oil and Natural Gas 

Sector. We also believe that resource 

conservation should be encouraged 

where possible and that alternatives 

should be flexible enough, within the 

law, to provide opportunities for 

innovation and resource recovery. 

Under the 2012 final NSPS for 

reciprocating compressors, an owner or 

operator must either (1) replace the rod 

packing every 26,000 hours of 

operation; or (2) replace the rod packing 

every 36 months. Any other options 

considered would need to provide at 

least the level of emission control that 

the existing options provide. Based on 

our review of the information submitted 

by the petitioner, we conclude that the 

technology has merit and would provide 

equivalent or better emissions reduction 


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11 § 60.5411(a) and (b) are the closed vent system 

and cover requirements that are meant to ensure 

that all emissions from the compressor rod packing 

will reach a process. 

since the emissions would be captured 

under negative pressure, allowing all 

emissions to be routed to the engine. It 

is our understanding that this 

technology may not be applicable to 

every compressor installation and 

situation. However, we are proposing 

this as an alternative to the current work 

practice standards and, therefore, it 

would be within the operator’s 

discretion to choose whichever option is 

most appropriate for the application and 

situation at hand. Based on these 

considerations and on the information 

submitted by the public and the 

petitioner, we are proposing to include 

in the NSPS a third option for 

controlling emissions from reciprocating 

compressor rod packing as described 

above. 

In light of the above considerations, 

we are proposing to revise § 60.5385(a) 

to reflect that a third option for 

controlling VOC emissions from the 

reciprocating compressor rod packing 

would be to capture the emissions and 

route them to a process. ‘‘Route to a 

process’’ was defined in the 2012 NSPS 

at § 60.5430 to work in conjunction with 

the standards for storage vessels and wet 

seal centrifugal compressors. By using 

the same term in the proposed third 

option, emissions captured from the rod 

packing would be treated the same as 

emissions recovered from a storage 

vessel or from a wet seal centrifugal 

compressor. Specifically, for example, 

in the petitioner’s case, the compressor 

engine would be the ‘‘process’’ to which 

the emissions would be routed. 

Although we have used the petitioner’s 

application as an example, we want to 

be clear that the third option would not 

be limited to use of the captured 

emissions as on site fuel. Similar to 

vapor recovery applied to storage 

vessels and wet seal centrifugal 

compressors, routing the emissions to a 

process would also include routing of 

the emissions to a flow line or other 

beneficial use. 

As a result, we propose to amend 

§ 60.5385(a) to read as follows: 

(a) You must follow the requirements of 

paragraph (a)(1), (2) or (3) of this section. 

(1) Replace the reciprocating compressor 

rod packing before the compressor has 

operated for 26,000 hours. The number of 

hours of operation must be continuously 

monitored beginning upon initial startup of 

your reciprocating compressor-affected 

facility, or October 15, 2012, or the date of 

the most recent reciprocating compressor rod 

packing replacement, whichever is later. 

(2) Replace the reciprocating compressor 

rod packing prior to 36 months from the date 

of the most recent rod packing replacement, 

or 36 months from the date of startup for a 

new reciprocating compressor for which the 

rod packing has not yet been replaced. 

(3) Route the rod packing emissions 

through a closed vent system that meets the 

requirements of § 60.5411(c) to a process. 

We are also proposing to amend the 

closed vent system requirements in 

§ 60.5411(a) and (b) to apply to 

reciprocating compressors in addition to 

centrifugal compressor wet seal 

degassing systems, to which those 

sections already apply.11 Similar 

amendments are being proposed to the 

continuous compliance requirements in 

§ 60.5415 and inspection and 

monitoring requirements in § 60.5416 to 

apply to reciprocating compressors. 

D. Equipment Leaks at Gas Processing 

Plants 

1. Small Gas Processing Plants and Gas 

Processing Plants Located on the 

Alaskan North Slope 

The equipment leaks standards in the 

1985 NSPS subpart KKK requires 

routine leak detection at natural gas 

processing plants for certain equipment, 

specifically pumps in light liquid 

service, valves in gas/vapor and light 

liquid service, and pressure relief valves 

from gas/vapor service. Subpart KKK 

provides for exemptions for pumps in 

light liquid service, valves in gas/vapor 

and light liquid service, and pressure 

relief valves in gas/vapor service from 

routine monitoring requirements at 

small natural gas processing plants (i.e., 

plants that do not have the design 

capacity to process at least 10 million 

standard cubic feet (scf) of field gas per 

day) and at natural gas processing plants 

located on the Alaskan North Slope. In 

the 2012 NSPS, we updated the subpart 

KKK standards by lowering the leak 

definition for valves from 10,000 parts 

per million (ppm) to 500 ppm and 

adding connectors to the list of 

equipment to be monitored. The revised 

standards, which are codified in subpart 

OOOO, apply to affected facilities at 

onshore natural gas processing plants 

that commence construction, 

modification or reconstruction after 

August 23, 2011. Except for the 

revisions described above, we retained 

the other provisions of subpart KKK by 

adopting the subpart KKK regulatory 

text, including the above mentioned 

exemptions, in the new subpart OOOO. 

However, in adopting the subpart KKK 

regulatory text on the exemptions, we 

inadvertently failed to update the 

equipment list to include connectors. As 

a result, connectors were not listed in 

§ 60.5401(d) and (e) as exempt from the 

routine leak detection requirements at 

small gas processing plants and gas 

processing plants located on the 

Alaskan North Slope. 

Petitioners pointed out that 

connectors had been added to the list of 

equipment for routine leak detection in 

subpart OOOO but had not been 

similarly added to the list of equipment 

exempted from routine leak detection at 

small gas processing plants and at gas 

processing plants located on the 

Alaskan North Slope. The petitioners 

requested that we amend the NSPS to 

correct this apparent oversight. We 

agree that this omission was an 

oversight and that it was not our intent 

for the 2012 NSPS to single out 

connectors at small gas processing 

plants and at gas processing plants 

located on the Alaska North Slope for 

routine leak detection while exempting 

the other equipment at these plants from 

such requirement. As a result, we are 

proposing to amend § 60.5401(d) and (e) 

to add connectors to the list of 

equipment exempt from routine leak 

detection at these plants. 

2. Equipment Under Subpart OOOO 

Subject to Leak Detection Requirements 

Petitioners pointed out that the 

definition of ‘‘equipment’’ in § 60.5430 

of the 2012 final NSPS could be 

misinterpreted to expand the scope of 

the equipment leaks program under 

subpart OOOO to cover beyond 

onshore-gas processing plants, which 

was the scope of subpart KKK. The term 

‘‘equipment’’ is currently defined in 

§ 60.5430 as follows: 

Equipment means each pump, pressure relief 

device, open-ended valve or line, valve, and 

flange or other connector that is in VOC 

service or in wet gas service, and any device 

or system required by this subpart. 

As discussed above, the 2012 final 

NSPS subpart OOOO updated the 1985 

NSPS subpart KKK by lowering the leak 

definition for valves from 10,000 ppm to 

500 ppm and requiring monitoring of 

connectors. Otherwise, subpart OOOO 

retains the other provisions of the 

subpart KKK by adopting those 

provisions, including the definition of 

‘‘equipment.’’ As mentioned above, the 

definition of ‘‘equipment’’ includes 

‘‘any device or system required by this 

subpart.’’ [Emphasis added]. Because 

subpart KKK pertained only to onshore 

natural gas processing plants, the phrase 

‘‘any device or system required by this 

subpart’’ refers to only devices and 

systems at onshore natural gas 

processing plants. However, since 

subpart OOOO also covers affected 

facilities not located at onshore natural 

gas processing plants, the phrase could 

be misinterpreted to apply to every 


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12 During consideration of this issue, we realized 

that the definition of ‘‘responsible official’’ in the 

2012 NSPS refers to ‘‘permitting authority’’ in error. 

This occurred when we took language from the 

Title V definition which uses ‘‘permitting 

authority’’ appropriately. However, in the case of 

the NSPS, we are proposing to change the definition 

in § 60.5430 to replace ‘‘permitting authority’’ with 

‘‘Administrator’’ which is appropriate for the NSPS. 

For purposes of the discussion in this preamble, we 

continue to refer to ‘‘permitting authority,’’ since 

the current definition still uses that term until such 

an amendment would be effective. 

affected facility under the entire subpart 

OOOO, including those not located at 

onshore natural gas processing plants. 

To avoid any such misinterpretation, we 

are proposing to amend the definition of 

‘‘equipment’’ in § 60.5430 to clarify as 

follows: 

Equipment, as used in the standards and 

requirements in this subpart relative to the 

equipment leaks of VOC from onshore 

natural gas processing plants, means each 

pump, pressure relief device, open-ended 

valve or line, valve, and flange or other 

connector that is in VOC service or in wet gas 

service, and any device or system required by 

those same standards and requirements in 

this subpart. 

E. Definition of ‘‘Responsible Official’’ 

The 2012 final rule requires 

certification by a responsible official of 

the truth, accuracy and completeness of 

the annual report. Petitioners pointed 

out that the definition of ‘‘responsible 

official’’ is not appropriate for the oil 

and natural gas sector due to the large 

number and wide geographic 

distribution of the small sources 

involved. Petitioners suggested that the 

EPA should develop a certification 

requirement specific to the Oil and 

Natural Gas Sector NSPS that would 

allow delegation of the authority of a 

responsible official to someone, such as 

a field or production supervisor, who 

has direct knowledge of the day to day 

operation of the facilities being certified, 

without requiring that such delegation 

be pre-approved by the permitting 

authority.12

We reexamined the definition of 

‘‘responsible official’’ and agree with 

petitioners that the current language in 

the NSPS, specifically the requirement 

to seek advance approval by the 

permitting authority of the delegation of 

authority to a representative if the 

facility employs 250 or fewer persons, is 

too burdensome for the oil and natural 

gas sector. The oil and natural gas 

sector, especially the production (i.e., 

‘‘upstream’’) segment, is characterized 

by many individually small facilities 

(e.g., well sites) with oversight typically 

by a production field office serving a 

large geographic area such as a basin. 

We believe a production supervisor or 

field supervisor who is in charge of a 

field office would be analogous to a 

‘‘plant manager’’ in other sectors, 

because he or she is ‘‘responsible for the 

overall operation of one or more 

manufacturing, production, or operating 

facilities’’ (from § 60.5430, definition of 

‘‘responsible official’’). We believe 

positions such as these are much closer 

to the day to day operations in this 

sector and would be appropriate to 

certify as to the truth, accuracy and 

completeness of annual reports and 

compliance certifications. However, 

because most oil and gas production 

facilities are small and therefore 

unlikely to have more than 250 persons, 

delegating the authority of responsible 

official to an oil and gas production 

supervisor or field supervisor would 

almost always require the permitting 

authority’s approval. 

We believe that the oil and natural gas 

sector is unique in that the ones with 

most knowledge of the facilities being 

certified are field or production 

supervisors overseeing such facilities, 

which are numerous across country but 

generally with few employees in each 

facility. As a result, requiring prior 

approval of a delegation of the authority 

of a responsible official because most of 

these facilities employ 250 persons or 

less is unnecessarily burdensome and 

may potentially affect the facilities’ 

ability to comply with the certification 

requirement in the event there are 

delays in approvals of delegation. We 

therefore propose requiring advance 

notification instead of advance approval 

before such delegation becomes 

effective. 

Petitioners also noted that the current 

definition does not adequately address 

the complex ownership arrangements of 

limited partnerships. We agree with the 

petitioners and believe limited 

partnerships should be reflected in the 

definition along with sole 

proprietorships and partnerships which 

are currently addressed. 

In light of the considerations 

discussed above, we are proposing to 

amend the definition of ‘‘responsible 

official’’ to make such delegation 

effective after advance notification 

rather than after approval. Requirements 

for delegation to representatives 

responsible for one or more facilities 

that employ more than 250 persons or 

have gross annual sales or expenditures 

exceeding $25 million (in second 

quarter 1980 dollars) are unchanged 

from the 2012 NSPS (i.e., there is no 

advance notification or approval 

required for such delegations). 

In addition, the 2012 NSPS uses the 

term ‘‘permitting authority’’ in the 

definition of ‘‘responsible official.’’ The 

NSPS is not a permitting program, and 

the annual compliance certification that 

requires signature of the ‘‘responsible 

official’’ is a requirement of the NSPS 

and is not associated with a permitting 

program. As a result, we are proposing 

to replace the term ‘‘permitting 

authority’’ with ‘‘Administrator’’ in the 

definition of ‘‘responsible official’’ to be 

consistent with other notification and 

reporting requirements of the NSPS. 

F. Affirmative Defense 

In the 2012 NSPS subpart OOOO, the 

EPA had included an affirmative 

defense to civil penalties for violations 

caused by malfunctions. For the reasons 

provided below, we are proposing to 

remove the affirmative defense 

provisions in the 2012 NSPS subpart 

OOOO. 

Periods of startup, normal operations, 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

However, by contrast, malfunction is 

defined as ‘‘any sudden, infrequent, and 

not reasonably preventable failure of air 

pollution control equipment, process 

equipment, or a process to operate in a 

normal or usual manner. Failures that 

are caused in part by poor maintenance 

or careless operation are not 

malfunctions.’’ (40 CFR 60.2). The EPA 

has determined that CAA section 111 

does not require that emissions that 

occur during periods of malfunction be 

factored into development of CAA 

section 111 standards. Nothing in CAA 

section 111 or in case law requires that 

the EPA anticipate and account for the 

innumerable types of potential 

malfunction events in setting emission 

standards. CAA section 111 provides 

that the EPA set standards of 

performance which reflect the degree of 

emission limitation achievable through 

‘‘the application of the best system of 

emission reduction’’ that the EPA 

determines is adequately demonstrated. 

A malfunction is a failure of the source 

to perform in a ‘‘normal or usual 

manner’’ and no statutory language 

compels the EPA to consider such 

events in setting standards based on the 

‘‘best system of emission reduction.’’ 

The ‘‘application of the best system of 

emission reduction’’ is more 

appropriately understood to include 

operating units in such a way as to 

avoid malfunctions. 

Further, accounting for malfunctions 

in setting emission standards would be 

difficult, if not impossible, given the 

myriad different types of malfunctions 

that can occur across all sources in the 

category and given the difficulties 

associated with predicting or accounting 

for the frequency, degree, and duration 

of various malfunctions that might 

occur. The performance of units that are 


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13The court’s reasoning in NRDC focuses on civil 

judicial actions. The court noted that ‘‘EPA’s ability 

to determine whether penalties should be assessed 

for Clean Air Act violations extends only to 

administrative penalties, not to civil penalties 

imposed by a court.’’ Id. 

14Memorandum from Moore, Bruce, U.S. EPA, to 

Docket No. EPA–HQ–OAR–2010–0505, ‘‘Technical 

Corrections to the Oil and Natural Gas Sector New 

Source Performance Standards.’’ June 30, 2014 

malfunctioning is not ‘‘reasonably’’ 

foreseeable. See, e.g., Sierra Club v. 

EPA, 167 F.3d 658, 662 (D.C. Cir. 1999) 

(‘‘The EPA typically has wide latitude 

in determining the extent of datagathering necessary to solve a problem. 

We generally defer to an agency’s 

decision to proceed on the basis of 

imperfect scientific information, rather 

than to ‘invest the resources to conduct 

the perfect study.’ ’’) See also, 

Weyerhaeuser v. Costle, 590 F.2d 1011, 

1058 (D.C. Cir. 1978) (‘‘In the nature of 

things, no general limit, individual 

permit, or even any upset provision can 

anticipate all upset situations. After a 

certain point, the transgression of 

regulatory limits caused by 

‘uncontrollable acts of third parties,’ 

such as strikes, sabotage, operator 

intoxication or insanity, and a variety of 

other eventualities, must be a matter for 

the administrative exercise of case-bycase enforcement discretion, not for 

specification in advance by 

regulation.’’). In addition, emissions 

during a malfunction event can be 

significantly higher than emissions at 

any other time of source operation and 

thus accounting for malfunctions could 

lead to standards that are significantly 

less stringent than levels that are 

achieved by a well-performing nonmalfunctioning source. It is reasonable 

to interpret CAA section 111 to avoid 

such a result. The EPA’s approach to 

malfunctions is consistent with CAA 

section 111 and is a reasonable 

interpretation of the statute. 

In the event that a source fails to 

comply with the applicable CAA section 

111 standards as a result of a 

malfunction event, the EPA would 

determine an appropriate response 

based on, among other things, the good 

faith efforts of the source to minimize 

emissions during malfunction periods, 

including preventative and corrective 

actions, as well as root cause analyses 

to ascertain and rectify excess 

emissions. The EPA would also 

consider whether the source’s failure to 

comply with the CAA section 111 

standard was, in fact, ‘‘sudden, 

infrequent, not reasonably preventable’’ 

and was not instead ‘‘caused in part by 

poor maintenance or careless 

operation.’’ 40 CFR 60.2 (definition of 

malfunction). 

Further, to the extent the EPA files an 

enforcement action against a source for 

violation of an emission standard, the 

source can raise any and all defenses in 

that enforcement action and the federal 

district court will determine what, if 

any, relief is appropriate. The same is 

true for citizen enforcement actions. 

Similarly, the presiding officer in an 

administrative proceeding can consider 

any defense raised and determine 

whether administrative penalties are 

appropriate. 

In the 2012 NSPS, 40 CFR 60, subpart 

OOOO, the EPA included an affirmative 

defense as an effort to create a system 

that incorporates some flexibility, 

recognizing that there is a tension, 

inherent in many types of air regulation, 

to ensure adequate compliance while 

simultaneously recognizing that despite 

the most diligent of efforts, emission 

standards may be violated under 

circumstances entirely beyond the 

control of the source. Although the EPA 

recognized that its case-by-case 

enforcement discretion provides 

sufficient flexibility in these 

circumstances, it included the 

affirmative defense in the 2012 NSPS 

subpart OOOO to provide a more 

formalized approach and more 

regulatory clarity. See Weyerhaeuser Co. 

v. Costle, 590 F.2d 1011, 1057–58 (D.C. 

Cir. 1978) (holding that an informal 

case-by-case enforcement discretion 

approach is adequate); but see Marathon 

Oil Co. v. EPA, 564 F.2d 1253, 1272–73 

(9th Cir. 1977) (requiring a more 

formalized approach to consideration of 

‘‘upsets beyond the control of the permit 

holder.’’). Under the 2012 NSPS subpart 

OOOO affirmative defense provisions, if 

a source could demonstrate in a judicial 

or administrative proceeding that it had 

met the requirements of the affirmative 

defense in the regulation, civil penalties 

would not be assessed. Recently, the 

United States Court of Appeals for the 

District of Columbia Circuit vacated 

such an affirmative defense in one of the 

EPA’s section 112(d) regulations. NRDC 

v. EPA, No. 10–1371 (D.C. Cir. April 18, 

2014) 2014 U.S. App. LEXIS 7281 

(vacating affirmative defense provisions 

in CAA section 112(d) rule establishing 

emission standards for Portland cement 

kilns). The court found that the EPA 

lacked authority to establish an 

affirmative defense for private civil suits 

and held that under the CAA, the 

authority to determine civil penalty 

amounts lies exclusively with the 

courts, not the EPA. Specifically, the 

court found: ‘‘As the language of the 

statute makes clear, the courts 

determine, on a case-by-case basis, 

whether civil penalties are 

‘appropriate.’ ’’ See NRDC, 2014 U.S. 

App. LEXIS 7281 at *21 (‘‘[U]nder this 

statute, deciding whether penalties are 

‘appropriate’ in a given private civil suit 

is a job for the courts, not EPA.’’).13 In 

light of NRDC, the EPA is proposing to 

remove the affirmative defense 

provisions from the 2012 NSPS subpart 

OOOO in this rulemaking. As explained 

above, if a source is unable to comply 

with emissions standards as a result of 

a malfunction, the EPA may use its caseby-case enforcement discretion to 

provide flexibility, as appropriate. 

Further, as the D.C. Circuit 

recognized, in an EPA or citizen 

enforcement action, the court has the 

discretion to consider any defense 

raised and determine whether penalties 

are appropriate. Cf. NRDC, 2014 U.S. 

App. LEXIS 7281 at *24. (arguments 

that violation was caused by 

unavoidable technology failure can be 

made to the courts in future civil cases 

when the issue arises). The same logic 

applies to EPA administrative 

enforcement actions. 

VII. Technical Corrections and 

Clarifications 

Following publication of the 2012 

NSPS and the 2013 storage vessel 

amendments, we subsequently 

determined, following review of the 

petitions and discussions with affected 

parties, that the final rule warrants 

correction clarification in certain areas. 

The EPA is proposing corrections that 

are editorial in nature, including 

typographical and grammatical errors, 

as well as incorrect dates and crossreferences. Details of the specific 

changes we are proposing to the 

regulatory text may be found in the 

docket for this action.14

VIII. Impacts of This Proposed Rule 

Our analysis shows that owners and 

operators of affected facilities would 

choose to install and operate the same 

or similar air pollution control 

technologies under the proposed 

standards as would have been necessary 

to meet the previously finalized 

standards. We project that this rule will 

result in no significant change in costs, 

emission reductions or benefits. Even if 

there were changes in costs for these 

units, such changes would likely be 

small relative to both the overall costs 

of the individual projects and the 

overall costs and benefits of the final 

rule. Since we believe that owners and 

operators would put on the same or 

similar controls for this proposed rule 

that they would have for the original 

final rule, there should not be any 

incremental costs related to this 

proposed revision. 


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A. What are the air impacts? 

We believe that owners and operators 

of affected facilities will install the same 

or similar control technologies to 

comply with the revised standards 

proposed in this action as they would 

have installed to comply with the 

previously finalized standards. 

Accordingly, we believe that this 

proposed rule will not result in 

significant changes in emissions of any 

of the regulated pollutants. 

B. What are the energy impacts? 

This proposed rule is not anticipated 

to have an effect on the supply, 

distribution or use of energy. As 

previously stated, we believe that 

owners and operators of affected 

facilities would install the same or 

similar control technologies as they 

would have installed to comply with the 

previously finalized standards. 

C. What are the compliance costs? 

We believe there will be no significant 

change in compliance costs as a result 

of this proposed rule because our 

analysis shows that owners and 

operators of affected facilities would 

install the same or similar control 

technologies as they would have 

installed to comply with the previously 

finalized standards. 

D. What are the economic and 

employment impacts? 

Because we expect that owners and 

operators of affected facilities would 

install the same or similar control 

technologies to meet the standards 

proposed in this action as they would 

have chosen to comply with the 

previously finalized standards, we do 

not anticipate that this proposed rule 

will result in significant changes in 

emissions, energy impacts, costs, 

benefits or economic impacts. Likewise, 

we believe this rule will not have any 

impacts on the price of electricity, 

employment or labor markets or the U.S. 

economy. 

E. What are the benefits of the proposed 

standards? 

As previously stated, the EPA 

anticipates the oil and natural gas sector 

will not incur significant compliance 

costs or savings as a result of this 

proposal and we do not anticipate any 

significant emission changes resulting 

from this rule. Therefore, there are no 

direct monetized benefits or disbenefits 

associated with this proposed rule. 

IX. 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 not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). 

A regulatory impacts analysis (RIA) 

was prepared for the April 2012 final 

rule and can be found at: http://

www.epa.gov/ttn/ecas/regdata/RIAs/oil_

natural_gas_final_neshap_nsps_ria.pdf. 

Because this action does not impose 

new compliance costs on affected 

sources, we project that this rule will 

result in no significant change in costs, 

emission reductions or benefits in 2015, 

the year of full implementation of the 

NSPS. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden. Today’s 

proposed rule does not change the 

information collection requirements 

previously finalized and, as a result, 

does not impose any additional burden 

on industry. However, OMB has 

previously approved the information 

collection requirements contained in the 

existing regulations (see 77 FR 49490) 

under the provisions of the Paperwork 

Reduction Act (PRA), 44 U.S.C. 3501, et 

seq., and has assigned OMB control 

number 2060–0673. The OMB control 

numbers for the EPA’s regulations are 

listed in 40 CFR part 9 and 48 CFR 

chapter 15. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule 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 this rule on small entities, a small 

entity is defined as: (1) A small business 

in the oil or natural gas industry whose 

parent company has no more than 500 

employees (or revenues of less than $7 

million for firms that transport natural 

gas via pipeline); (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this proposed rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

In determining whether a rule has a 

significant economic impact on a 

substantial number of small entities, the 

impact of concern is any significant 

adverse economic impact on small 

entities, since the primary purpose of 

the regulatory flexibility analyses is to 

identify and address regulatory 

alternatives ‘‘which minimize any 

significant economic impact of the rule 

on small entities.’’ 5 U.S.C. 603 and 604. 

Thus, an agency may certify that a rule 

will not have a significant economic 

impact on a substantial number of small 

entities if the rule relieves regulatory 

burden, or otherwise has a positive 

economic effect on all of the small 

entities subject to the rule. 

The EPA has determined that none of 

the small entities subject to this rule 

will experience a significant impact 

because the notice of reconsideration 

imposes no additional compliance costs 

on owners or operators of affected 

sources. We have therefore concluded 

that today’s proposed rule will not 

result in a significant economic impact 

on a substantial number of small 

entities. We continue to be interested in 

the potential impacts of the proposed 

rule on small entities and welcome 

comments on issues related to such 

impacts. 

D. Unfunded Mandates Reform Act 

This action contains no federal 

mandates under the provisions of Title 

II of the Unfunded Mandates Reform 

Act of 1995 (UMRA), 2 U.S.C. 1531– 

1538, for state, local or tribal 

governments or the private sector. The 

action imposes no enforceable duty on 

any state, local or tribal governments or 

the private sector. Therefore, this action 

is not subject to the requirements of 

sections 202 or 205 of the UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. This 

action contains no requirements that 

apply to such governments nor does it 

impose obligations upon them. 


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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. This proposal is 

a reconsideration of an existing rule and 

imposes no new impacts or costs. Thus, 

Executive Order 13132 does not apply 

to this action. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between the 

EPA and state and local governments, 

the EPA specifically solicits comment 

on this proposed action from state and 

local officials. 

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 

effect 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, as 

specified in Executive Order 13175. 

Thus, Executive Order 13175 does not 

apply to this action. 

The EPA specifically solicits 

additional comment on this proposed 

action from tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This action is not subject to Executive 

Order 13045 (62 FR 19885, April 23, 

1997) because it is not economically 

significant as defined in Executive 

Order 12866, and because the agency 

does not believe the environmental 

health risks or safety risks addressed by 

this action present a disproportionate 

risk to children. This action has no 

impacts; thus, health and risk 

assessments were not conducted. 

The public is invited to submit 

comments or identify peer-reviewed 

studies and data that assess effects of 

early life exposure to HAP from oil and 

natural gas sector activities. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law No. 

104–113, 12(d) (15 U.S.C. 272 note), 

directs the EPA to use voluntary 

consensus standards (VCS) in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. VCS are 

technical standards (e.g., materials 

specifications, test methods, sampling 

procedures and business practices) that 

are developed or adopted by VCS 

bodies. The NTTAA directs the EPA to 

provide Congress, through OMB, 

explanations when the agency decides 

not to use available and applicable VCS. 

This proposed rulemaking does not 

involve technical standards. Therefore, 

the EPA is not considering the use of 

any VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 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 United States. 

The EPA has 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. This proposal is a 

reconsideration of an existing rule and 

imposes no new impacts or costs. 

List of Subjects in 40 CFR Part 60 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Incorporation by 

reference, Intergovernmental relations, 

Reporting and recordkeeping. 

Dated: July 1, 2014. 

Gina McCarthy, 

Administrator. 

For the reasons set out in the 

preamble, title 40, chapter I of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for part 60 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart OOOO—[Amended] 

■ 2. Section 60.5365 is amended by 

revising paragraph (e) introductory text 

to read as follows: 

§ 60.5365 Am I subject to this subpart? 

* * * * * 

(e) Each storage vessel affected 

facility, which is a single storage vessel 

located in the oil and natural gas 

production segment, natural gas 

processing segment or natural gas 

transmission and storage segment, and 

has the potential for VOC emissions 

equal to or greater than 6 tpy as 

determined according to this section by 

October 15, 2013 for Group 1 storage 

vessels and by April 15, 2014, or 30 

days after startup (whichever is later) for 

Group 2 storage vessels, except as 

otherwise provided in this paragraph 

below. For storage vessels receiving 

liquids pursuant to the standards for gas 

well affected facilities in § 60.5375, 

including wells subject to § 60.5375(f), 

you must determine the potential for 

VOC emissions within 30 days after the 

beginning of the production stage as 

defined in § 60.5430. A storage vessel 

affected facility that subsequently has 

its potential for VOC emissions decrease 

to less than 6 tpy shall remain an 

affected facility under this subpart. The 

potential for VOC emissions must be 

calculated using a generally accepted 

model or calculation methodology, 

based on the maximum average daily 

throughput determined for a 30-day 

period of production prior to the 

applicable emission determination 

deadline specified in this section. The 

determination may take into account 

requirements under a legally and 

practically enforceable limit in an 

operating permit or other requirement 

established under a Federal, State, local 

or tribal authority. For storage vessels 

not subject to a legally and practically 

enforceable limit in an operating permit 

or other requirement established under 

Federal, state, local or tribal authority, 

any vapor from the storage vessel that is 

recovered and routed to a process 

through a VRU designed and operated 

as specified in this section is not 

required to be included in the 

determination of VOC potential to emit 

for purposes of determining affected 


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facility status, provided you comply 

with the requirements in paragraphs 

(e)(1) through (4) of this section. 

* * * * * 

■ 3. Section 60.5375 is amended by: 

■ a. Revising paragraphs (a)(1) through 

(a)(3); 

■ b. Revising paragraph (b); 

■ c. Revising paragraphs (f)(1)(i), (ii) and 

(f)(2). 

The revisions read as follows: 

§ 60.5375 What standards apply to gas 

well affected facilities? 

* * * * * 

(a) * * * 

(1) For each stage of the well 

completion operation, as defined in 

§ 60.5430, follow the requirements 

specified in paragraph (a)(1)(i), (ii) or 

(iii) of this section as applicable. 

(i) During the initial flowback stage, 

route the flowback into one or more 

well completion vessels and commence 

operation of a separator as soon as 

sufficient gas is present in the flowback 

for a separator to operate. Any gas 

present in the flowback prior to the 

separation flowback stage is not subject 

to control under this section. 

(ii) During the separation flowback 

stage, route all liquids from the 

separator to one or more well 

completion vessels or storage vessels, or 

re-inject the liquids into the well or 

another well. Route the recovered gas 

from the separator into a gas flow line 

or collection system, re-inject the 

recovered gas into the well or another 

well, use the recovered gas as an on-site 

fuel source, or use the recovered gas for 

another useful purpose that a purchased 

fuel or raw material would serve. If it is 

infeasible to route the recovered gas as 

required above, follow the requirements 

in paragraph (a)(3) of this section. If, at 

any time during the separation flowback 

stage, the gas present in the flowback 

becomes insufficient to maintain 

operation of the separator, you must 

comply with (a)(1)(i) of this section. As 

soon as the rate of flowback has 

declined and stabilized enough to allow 

continuous recovery of the gas and to 

allow separation and recovery of any 

crude oil, condensate or produced 

water, you must comply with 

requirements for the production stage as 

provided in (a)(1)(iii) of this section. 

(iii) During the production stage, 

separate and route recovered liquids to 

storage vessels. Route the recovered gas 

into a gas flow line or collection system, 

re-inject the recovered gas into the well 

or another well, use the recovered gas as 

an on-site fuel source, or use the 

recovered gas for another useful purpose 

that a purchased fuel or raw material 

would serve. During the production 

stage, recovered gas may not be vented 

or controlled by any combustion device. 

(2) All salable quality gas must be 

routed to the gas flow line as soon as 

practicable. In cases where recovered 

gas cannot be directed to the flow line, 

you must follow the requirements in 

paragraph (a)(3) of this section. 

(3) You must capture and direct 

recovered gas to a completion 

combustion device, except in conditions 

that may result in a fire hazard or 

explosion, or where high heat emissions 

from a completion combustion device 

may negatively impact tundra, 

permafrost or waterways. Completion 

combustion devices must be equipped 

with a reliable continuous ignition 

source. 

* * * * * 

(b) You must maintain a log for each 

well completion operation at each gas 

well affected facility. The log must be 

completed on a daily basis for the 

duration of the flowback period and 

must contain the records specified in 

§ 60.5420(c)(1)(iii). 

* * * * * 

(f) * * * 

(1) * * * 

(i) Each well completion operation 

with hydraulic fracturing at a wildcat or 

delineation well. 

(ii) Each well completion operation 

with hydraulic fracturing at a nonwildcat low pressure gas well or nondelineation low pressure gas well. 

(2) Route the flowback into one or 

more well completion vessels and 

commence operation of a separator as 

soon as sufficient gas is present in the 

flowback for a separator to operate. Any 

gas present in the flowback before the 

separator can operate is not subject to 

control under this section. You must 

capture and direct recovered gas to a 

completion combustion device, except 

in conditions that may result in a fire 

hazard or explosion, or where high heat 

emissions from a completion 

combustion device may negatively 

impact tundra, permafrost or waterways. 

Completion combustion devices must be 

equipped with a reliable continuous 

ignition source. As soon as the rate of 

flowback has declined and stabilized 

enough to allow separation and recovery 

of any crude oil, condensate or 

produced water, route the recovered 

liquids to storage vessels. You must also 

comply with paragraphs (a)(4) and (b) 

through (e) of this section. 

* * * * * 

■ 4. Section 60.5385 is amended by: 

■ a. Revising paragraph (a) introductory 

text; and 

■ b. Adding paragraph (a)(3). 

The revision and addition read as 

follows: 

§ 60.5385 What standards apply to 

reciprocating compressor affected 

facilities? 

* * * * * 

(a) You must replace the reciprocating 

compressor rod packing according to 

either paragraph (a)(1) or (2) of this 

section or you must comply with 

paragraph (a)(3). 

* * * * * 

(3) Route the rod packing emissions to 

a process through a closed vent system 

and cover that meet the requirements of 

§ 60.5411(a) and (b). 

* * * * * 

■ 5. Section 60.5390 is amended by 

revising paragraph (c)(2) to read as 

follows: 

§ 60.5390 What standards apply to 

pneumatic controller affected facilities? 

* * * * * 

(c) * * * 

(2) Each pneumatic controller affected 

facility constructed, modified or 

reconstructed on or after October 15, 

2013, at a location between the 

wellhead and a natural gas processing 

plant or the point of custody transfer to 

an oil pipeline must be tagged with the 

month and year of installation, 

reconstruction or modification, and 

identification information that allows 

traceability to the records for that 

controller as required in 

§ 60.5420(c)(4)(iii). 

* * * * * 

■ 6. Section 60.5395 is amended by: 

■ a. Revising paragraph (d)(1)(i); and 

■ b. Revising paragraph (f) introductory 

text. 

The revisions read as follows: 

§ 60.5395 What standards apply to storage 

vessel affected facilities? 

* * * * * 

(d) * * * 

(1) * * * 

(i) For each Group 2 storage vessel 

affected facility, you must achieve the 

required emissions reductions by April 

15, 2014, or within 60 days after startup, 

whichever is later, except as otherwise 

provided below in this paragraph. For 

storage vessels receiving liquids 

pursuant to the standards for gas well 

affected facilities in § 60.5375, you must 

achieve the required emissions 

reductions within 60 days after the 

beginning of the production stage as 

defined in § 60.5430. 

* * * * * 

(f) Requirements for storage vessel 

affected facilities that are removed from 

service. If you are the owner or operator 

of a storage vessel affected facility that 

is removed from service, you must 

comply with paragraphs (f)(1) and (2) of 

this section. No other provision of this 


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subpart applies to a storage vessel 

affected facility while that storage vessel 

affected facility is removed from service. 

* * * * * 

■ 7. Section 60.5401 is amended by 

revising paragraphs (d) and (e) to read 

as follows: 

§ 60.5401 What are the exceptions to the 

equipment leak standards for affected 

facilities at onshore natural gas processing 

plants? 

* * * * * 

(d) Pumps in light liquid service, 

valves in gas/vapor and light liquid 

service, pressure relief devices in gas/ 

vapor service, and connectors in gas/ 

vapor service and in light liquid service 

that are located at a nonfractionating 

plant that does not have the design 

capacity to process 283,200 standard 

cubic meters per day (scmd) (10 million 

standard cubic feet per day) or more of 

field gas are exempt from the routine 

monitoring requirements of §§ 60.482– 

2a(a)(1) and 60.482–7a(a), and 

paragraph (b)(1) of this section. 

(e) Pumps in light liquid service, 

valves in gas/vapor and light liquid 

service, pressure relief devices in gas/

vapor service, and connectors in gas/ 

vapor service and in light liquid service 

within a process unit that is located in 

the Alaskan North Slope are exempt 

from the routine monitoring 

requirements of §§ 60.482–2a(a)(1), 

60.482–7a(a), and paragraph (b)(1) of 

this section. 

* * * * * 

■ 8. Section 60.5410 is amended by 

revising paragraph (d)(2) to read as 

follows: 

§ 60.5410 How do I demonstrate initial 

compliance with the standards for my gas 

well affected facility, my centrifugal 

compressor affected facility, my 

reciprocating compressor affected facility, 

my pneumatic controller affected facility, 

my storage vessel affected facility, and my 

equipment leaks and sweetening unit 

affected facilities at onshore natural gas 

processing plants? 

* * * * * 

(d) * * * 

(2) You own or operate a pneumatic 

controller affected facility located at a 

natural gas processing plant and your 

pneumatic controller is driven by a gas 

other than natural gas and therefore 

emits zero natural gas. 

* * * * * 

■ 9. Section 60.5411 is amended by: 

■ a. Revising the section heading; 

■ b. Revising paragraph (a) introductory 

text; 

■ c. Revising paragraph (a)(1); 

■ d. Revising paragraph (b) introductory 

text; 

■ e. Revising paragraph (b)(3); and 

■ f. Revising paragraph (c) introductory 

text. 

The revisions read as follows: 

§ 60.5411 What additional requirements 

must I meet to determine initial compliance 

for my covers and closed vent systems 

routing materials from storage vessels, 

reciprocating compressors and centrifugal 

compressor wet seal degassing systems? 

* * * * * 

(a) Closed vent system requirements 

for reciprocating compressors and for 

centrifugal compressor wet seal 

degassing systems. (1) You must design 

the closed vent system to route all gases, 

vapors, and fumes emitted from the 

material in the reciprocating compressor 

or the wet seal fluid degassing system to 

a control device or to a process that 

meets the requirements specified in 

§ 60.5412(a) through (c). 

* * * * * 

(b) Cover requirements for storage 

vessels, reciprocating compressors and 

centrifugal compressor wet seal 

degassing systems. 

* * * * * 

(3) Each storage vessel thief hatch 

shall be equipped with a mechanism or 

be of such design, and properly 

maintained and operated, to ensure that 

the lid remains properly seated. You 

must select gasket material for the hatch 

based on composition of the fluid in the 

storage vessel and weather conditions. 

(c) Closed vent system requirements 

for storage vessel affected facilities 

using a control device or routing 

emissions to a process. 

* * * * * 

■ 10. Section 60.5412 is amended by 

revising paragraph (d) introductory text 

to read as follows: 

§ 60.5412 What additional requirements 

must I meet for determining initial 

compliance with control devices used to 

comply with the emission standards for my 

storage vessel or centrifugal compressor 

affected facility? 

* * * * * 

(d) Each control device used to meet 

the emission reduction standard in 

§ 60.5395(d) for your storage vessel 

affected facility must be installed 

according to paragraphs (d)(1) through 

(3) of this section, as applicable. As an 

alternative to paragraph (d)(1) of this 

section, you may install a control device 

model tested under § 60.5413(d), which 

meets the criteria in § 60.5413(d)(11) 

and § 60.5413(e). 

* * * * * 

■ 11. Section 60.5413 is amended by: 

■ a. Revising paragraph (e) introductory 

text; and 

■ b. Adding paragraph (e)(7). 

The revisions and additions read as 

follows: 

§ 60.5413 What are the performance 

testing procedures for control devices used 

to demonstrate compliance at my storage 

vessel or centrifugal compressor affected 

facility? 

* * * * * 

(e) Continuous compliance for 

combustion control devices tested by the 

manufacturer in accordance with 

paragraph (d) of this section. This 

paragraph applies to the demonstration 

of compliance for a combustion control 

device tested under the provisions in 

paragraph (d) of this section. Owners or 

operators must demonstrate that a 

control device achieves the performance 

requirements in (d)(11) of this section 

by installing a device tested under 

paragraph (d) of this section and 

complying with the criteria specified in 

paragraphs (e)(1) through (7) of this 

section. 

* * * * * 

(7) Ensure that each enclosed 

combustion device is maintained in a 

leak free condition. 

* * * * * 

■ 12. Section 60.5415 is amended by: 

■ a. Revising paragraph (a)(2); 

■ b. Revising paragraph (c) introductory 

text; 

■ c. Adding paragraph (c)(4); and 

■ d. Removing paragraph (h). 

The revisions and additions read as 

follows: 

§ 60.5415 How do I demonstrate 

continuous compliance with the standards 

for my gas well affected facility, my 

centrifugal compressor affected facility, my 

stationary reciprocating compressor 

affected facility, my pneumatic controller 

affected facility, my storage vessel affected 

facility, and my affected facilities at onshore 

natural gas processing plants? 

* * * * * 

(a) * * * 

(2) For each control device used to 

reduce emissions, you must 

demonstrate continuous compliance 

with the performance requirements of 

§ 60.5412(a) using the procedures 

specified in paragraphs (b)(2)(i) through 

(vii) of this section. If you use a 

condenser as the control device to 

achieve the requirements specified in 

§ 60.5412(a)(2), you must demonstrate 

compliance according to paragraph 

(b)(2)(viii) of this section. You may 

switch between compliance with 

paragraphs (b)(2)(i) through (vii) of this 

section and compliance with paragraph 

(b)(2)(viii) of this section only after at 

least 1 year of operation in compliance 

with the selected approach. You must 

provide notification of such a change in 

the compliance method in the next 

annual report, as required in 

§ 60.5420(b), following the change. 

* * * * * 


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(c) For each reciprocating compressor 

affected facility complying with 

§ 60.5385(a)(1) or (2), you must 

demonstrate continuous compliance 

according to paragraphs (c)(1) through 

(3) of this section. For each 

reciprocating compressor affected 

facility complying with § 60.5385(a)(3), 

you must demonstrate continuous 

compliance according to paragraph 

(c)(4). 

* * * * * 

(4) You must continuously comply 

with the closed vent and cover 

requirements in § 60.5411(a) and (b). 

* * * * * 

■ 13. Section 60.5416 is amended by: 

■ a. Revising the section heading; 

■ b. Revising the introductory text; 

■ c. Revising paragraph (a) introductory 

text; and 

■ d. Revising paragraph (b) introductory 

text. 

The revisions read as follows: 

§ 60.5416 What are the initial and 

continuous cover and closed vent system 

inspection and monitoring requirements for 

my storage vessel, centrifugal compressor 

and reciprocating compressor affected 

facilities? 

For each closed vent system or cover 

at your storage vessel, centrifugal 

compressor and reciprocating 

compressor affected facility, you must 

comply with the applicable 

requirements of paragraphs (a) 

through(c) of this section. 

* * * * * 

(a) Inspections for closed vent systems 

and covers installed on each centrifugal 

compressor or reciprocating compressor 

affected facility. Except as provided in 

paragraphs (b)(11) and (12) of this 

section, you must inspect each closed 

vent system according to the procedures 

and schedule specified in paragraphs 

(a)(1) and (2) of this section, inspect 

each cover according to the procedures 

and schedule specified in paragraph 

(a)(3) of this section, and inspect each 

bypass device according to the 

procedures of paragraph (a)(4) of this 

section. 

* * * * * 

(b) No detectable emissions test 

methods and procedures. If you are 

required to conduct an inspection of a 

closed vent system or cover at your 

centrifugal compressor or reciprocating 

affected facility as specified in 

paragraphs (a)(1), (2), or (3) of this 

section, you must meet the requirements 

of paragraphs (b)(1) through (13) of this 

section. 

* * * * * 

■ 14. Section 60.5420 is amended by: 

■ a. Revising paragraphs (b)(6)(ii), (vi) 

and (vii); and 

■ b. Revising paragraph (c)(3)(ii). 

The revisions read as follows: 

§ 60.5420 What are my notification, 

reporting, and recordkeeping 

requirements? 

* * * * * 

(b) * * * 

(6) * * * 

(ii) Documentation of the VOC 

emission rate determination according 

to § 60.5365(e) for each storage vessel 

that became an affected facility during 

the reporting period. 

* * * * * 

(vi) You must identify each storage 

vessel affected facility that is removed 

from service during the reporting period 

as specified in § 60.5395(f)(1), including 

the date the storage vessel affected 

facility was removed from service. 

(vii) You must identify each storage 

vessel affected facility for which 

operation resumes during the reporting 

period as specified in § 60.5395(f)(2)(iii), 

including the date the storage vessel 

affected facility was returned to service. 

* * * * * 

(c) * * * 

(3) * * * 

(ii) Records of the date and time of 

each reciprocating compressor rod 

packing replacement, or the date of 

installation of a closed vent system as 

specified in § 60.5385(a)(3). 

* * * * * 

■ 15. Section 60.5430 is amended by: 

■ a. Adding, in alphabetical order, 

definitions for the terms ‘‘Initial 

flowback stage,’’ ‘‘Production stage,’’ 

‘‘Recovered gas,’’ ‘‘Recovered liquids,’’ 

‘‘Removed from service,’’ ‘‘Separation 

flowback stage,’’ and ‘‘Well completion 

vessel;’’ 

■ b. Removing the definition of 

‘‘Affirmative defense;’’ and 

■ c. Revising the definition for 

‘‘Equipment’’, ‘‘Flowback’’ ‘‘Responsible 

official,’’ ‘‘Routed to a process or route 

to a process,’’ and ‘‘Storage vessel’’ to 

read as follows: 

§ 60.5430 What definitions apply to this 

subpart? 

* * * * * 

Equipment, as used in the standards 

and requirements in this subpart 

relative to the equipment leaks of VOC 

from onshore natural gas processing 

plants, means each pump, pressure 

relief device, open-ended valve or line, 

valve, and flange or other connector that 

is in VOC service or in wet gas service, 

and any device or system required by 

those same standards and requirements 

in this subpart. 

* * * * * 

Flowback means the process of 

allowing fluids and entrained solids to 

flow from a natural gas well following 

a treatment, either in preparation for a 

subsequent phase of treatment or in 

preparation for cleanup and returning 

the well to production. The term 

flowback also means the fluids and 

entrained solids that emerge from a 

natural gas well during the flowback 

process. The flowback period begins 

when material introduced into the well 

during the treatment returns to the 

surface following hydraulic fracturing or 

refracturing. The flowback period ends 

when either the production stage begins 

or the well is shut in, whichever occurs 

first. Flowback includes the initial 

flowback stage and the separation 

flowback stage. 

* * * * * 

Initial flowback stage means the 

period during a well completion 

operation when there is insufficient gas 

in the flowback to operate a separator. 

* * * * * 

Production stage means the period 

during a well completion operation that 

follows the separation flowback stage 

when flowback has declined and 

stabilized sufficiently to allow 

continuous recovery of the gas and to 

allow separation and recovery of any 

crude oil, condensate and produced 

water. This definition applies to wells 

subject to § 60.5375(f) for purposes of 

determining a storage vessel’s potential 

to emit VOC under § 60.5365(e). 

* * * * * 

Recovered gas means gas recovered 

through the separation process. 

Recovered liquids means any crude 

oil, condensate or produced water 

recovered through the separation 

process. 

* * * * * 

Removed from service means that a 

storage vessel affected facility has been 

physically isolated and disconnected 

from the process for a purpose other 

than maintenance, has been completely 

emptied and degassed and is no longer 

used to contain crude oil, condensate, 

produced water or intermediate 

hydrocarbon liquids. A storage vessel 

where liquid is left on walls, as bottom 

clingage or in pools due to floor 

irregularity is considered to be 

completely empty. If the storage vessel 

affected facility is reconnected to the 

process, or introduced with crude oil, 

condensate, produced water or 

intermediate hydrocarbon liquids at the 

same location, or relocated to another 

location and utilized as a storage vessel 

for crude oil, condensate, produced 

water or intermediate hydrocarbon 

liquids, it will be deemed to no longer 

be ‘‘removed from service’’ and at that 

time will be deemed ‘‘returned to 


pmangrum on DSK3VPTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 137 / Thursday, July 17, 2014 / Proposed Rules 41769 

service’’ and subject to the provisions of 

this subpart applicable to such vessel. 

Responsible official means one of the 

following: 

(1) For a corporation: A president, 

secretary, treasurer, or vice-president of 

the corporation in charge of a principal 

business function, or any other person 

who performs similar policy or 

decision-making functions for the 

corporation, or a duly authorized 

representative of such person if the 

representative is responsible for the 

overall operation of one or more 

manufacturing, production, or operating 

facilities applying for or subject to a 

permit and either: 

(i) The facilities have gross annual 

sales or expenditures exceeding $25 

million (in second quarter 1980 dollars); 

or 

(ii) The Administrator is notified in 

advance of delegation of authority to 

such representatives. The Administrator 

reserves the right to evaluate such 

delegation; 

(2) For a partnership or sole 

proprietorship: A general partner or the 

proprietor, respectively. If a general 

partner is a corporation, the provisions 

of paragraph (1) of this definition apply; 

(3) For a municipality, State, Federal, 

or other public agency: Either a 

principal executive officer or ranking 

elected official. For the purposes of this 

part, a principal executive officer of a 

Federal agency includes the chief 

executive officer having responsibility 

for the overall operations of a principal 

geographic unit of the agency (e.g., a 

Regional Administrator of EPA); or 

(4) For affected facilities: 

(i) The designated representative in so 

far as actions, standards, requirements, 

or prohibitions under title IV of the 

Clean Air Act or the regulations 

promulgated thereunder are concerned; 

or 

(ii) The designated representative for 

any other purposes under part 60. 

Routed to a process or route to a 

process means the emissions are 

conveyed via a closed vent system to 

any enclosed portion of a process where 

the emissions are predominantly 

recycled and/or consumed in the same 

manner as a material that fulfills the 

same function in the process and/or 

transformed by chemical reaction into 

materials that are not regulated 

materials and/or incorporated into a 

product; and/or recovered. 

* * * * * 

Separation flowback stage means the 

period during a well completion 

operation when a sufficient volume of 

gas is present in the flowback to operate 

a separator. The separation flowback 

stage ends when the production stage 

begins or when the well is shut in, 

whichever is first. 

Storage vessel means a tank or other 

vessel that contains an accumulation of 

crude oil, condensate, intermediate 

hydrocarbon liquids, or produced water, 

and that is constructed primarily of 

nonearthen materials (such as wood, 

concrete, steel, fiberglass, or plastic) 

which provide structural support. For 

the purposes of this subpart, the 

following are not considered storage 

vessels: 

(1) Vessels that are skid-mounted or 

permanently attached to something that 

is mobile (such as trucks, railcars, 

barges or ships), and are intended to be 

located at a site for less than 180 

consecutive days. If you do not keep or 

are not able to produce records, as 

required by § 60.5420(c)(5)(iv), showing 

that the vessel has been located at a site 

for less than 180 consecutive days, the 

vessel described herein is considered to 

be a storage vessel since the original 

vessel was first located at the site. 

(2) Process vessels such as surge 

control vessels, bottoms receivers or 

knockout vessels. 

(3) Pressure vessels designed to 

operate in excess of 204.9 kilopascals 

and without emissions to the 

atmosphere. 

* * * * * 

Well completion vessel means a vessel 

that contains flowback during a well 

completion operation following 

hydraulic fracturing or refracturing. A 

well completion vessel may be a lined 

earthen pit, a storage vessel, or a vessel 

that is skid-mounted or portable. 

* * * * * 

[FR Doc. 2014–16576 Filed 7–16–14; 8:45 am] 

BILLING CODE 6560–50–P 


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