Oil and Natural Gas Sector: Reconsideration of Additional Provisions of 

New Source Performance Standards

40 CFR Part 60 

Response to Public Comments on

Proposed Rule (79 FR 41752; July 17, 2014)

U.S. Environmental Protection Agency

Office of Air Quality Planning and Standards

Sector Policies and Programs Division

Research Triangle Park, NC 27711

December 19, 2014
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Table of Contents

1.0 Summary................................................................................................................................... 1

1.1 Background........................................................................................................................... 1

2.0 Response to Comments............................................................................................................. 9

2.1 Well Completions................................................................................................................. 9

2.1.1 Initial Flowback Stage ................................................................................................... 9

2.1.2 Production Stage ............................................................................................................ 9

2.1.3 Recordkeeping and Reporting Requirements .............................................................. 12

2.1.4 Use of Lower Explosive Limit (LEL) Meters.............................................................. 13

2.1.5 Definitions Associated with Well Completions........................................................... 15

2.2 Storage Vessels................................................................................................................... 17

2.2.1 Applicability and Compliance ..................................................................................... 17

2.2.2 Storage Vessels Removed from Service ...................................................................... 21

2.3 Vapor Recovery Unit (VRU) Provisions............................................................................ 21

2.4 Alternative Compliance Option for Reciprocating Compressors....................................... 22

2.5 Pneumatic Controllers......................................................................................................... 24

2.6 Control Device Operating Requirements............................................................................ 25

2.7 Exemptions to the Equipment Leak Standards................................................................... 25

2.8 Responsible Official............................................................................................................ 26

2.9 Technical Corrections......................................................................................................... 26
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Acronyms and Abbreviations

CAA Clean Air Act

CDPHE Colorado Department of Public Health and Environment

CFR Code of Federal Regulations

EPA Environmental Protection Agency

LEL Lower Explosive Limit

NESHAP National Emission Standards for Hazardous Air Pollutants

NSPS New Source Performance Standards

RTR Residual Risk and Technology Review

SCFH Standard Cubic Feet Per Hour

SO2 Sulfur Dioxide

SSM Startup, Shutdown and Malfunction

TPY Tons Per Year

VOC Volatile Organic Compounds

VRU Vapor Recovery Unit
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1.0 Summary

1.1 Background

On January 14, 2009, pursuant to section 304(a)(2) of the Clean Air Act (CAA), 

WildEarth Guardians and the San Juan Citizens Alliance filed a Complaint alleging that the U.S. 

Environmental Protection Agency (EPA) failed to meet its obligations under CAA sections 

111(b)(1)(B), 112(d)(6) and 112(f)(2) to take actions relative to the review/revision of the new 

source performance standards (NSPS) and the national emissions standards for hazardous air 

pollutants (NESHAP) with respect to the Oil and Natural Gas Production source category. On 

February 4, 2010, a consent decree was entered that, as modified, required the EPA to sign by 

July 28, 2011, proposed standards and/or determinations not to issue standards pursuant to CAA 

sections 111(b)(1)(B), 112(d)(6) and 112(f)(2) and to take final action by April 3, 2012.

On August 8, 2011, the EPA announced (76 FR 52738) how the Agency proposed to 

address the reviews of the new source performance standards (NSPS) for volatile organic 

compound (VOC) and sulfur dioxide (SO2) emissions from natural gas processing plants. The 

EPA proposed to add to the source category list any oil and gas operation not covered by the 

current listing. This action also included proposed amendments to the existing NSPS for VOCs 

from natural gas processing plants and proposed standards for operations not covered by the 

existing NSPS. In addition, this action proposed how the EPA would address the residual risk 

and technology review (RTR) conducted for the oil and natural gas production and natural gas 

transmission and storage national emission standards for hazardous air pollutants (NESHAP). 

The EPA further proposed standards for emission sources within these two source categories that 

were not then addressed, as well as amendments to improve aspects of these NESHAP related to 

applicability and implementation. Finally, the EPA addressed provisions in these NSPS and 

NESHAP related to emissions during periods of startup, shutdown and malfunction (SSM).

On August 16, 2012, the EPA published final NSPS and NESHAP for the oil and natural 

gas sector (77 FR49490). The Administrator received petitions for reconsideration of certain 

aspects for the standards.

On April 12, 2013, the EPA announced their proposed amendments to the oil and natural 

gas sector NSPS as a result of reconsideration of certain issues related to implementation of 

storage vessel provisions. On September 23, 2013, the EPA published final NSPS rule revisions 

for the oil and natural gas sector (78 FR 58416) for certain issues related to implementation of 

storage vessel provisions.

On July 17, 2014, the EPA proposed amendments to NSPS for the oil and natural gas 

sectors related to certain time-critical issues related to certain storage vessel provisions and well 

completion provisions. Over ninety comment letters were received on the proposed amendments 

and entered into the EPA’s Air and Radiation docket assigned for this rulemaking (docket 
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number EPA-HQ-OAR-2010-0505). The EPA reviewed all of the comment letters entered into 

the docket.

This document presents a summary of the public comments entered into docket EPA-HQOAR-2010-0505 regarding specific issues and topics related to the development of the proposed 

subpart OOOO NSPS (40 CFR part 60) amendments and the EPA’s responses to those 

comments. This document responds to comments not addressed in the preamble to the final rule 

action. The EPA assigned these comments to specific categories (see Table of Contents) based 

on an assessment of the principal subject of the comment; however, some comments inevitably 

overlap multiple subject areas. Table 1 provides the list of comments received by docket 

document ID, the commenter and their affiliation. The last 4 digits of the docket document ID 

are used to identify comments summarized and responded to in this document.
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Table 1. List of Commenters on the Oil and Natural Gas Sector: Reconsideration of Additional Provisions of 

New Source Performance Standards; Proposed Rule (79 FR 41752; July 17, 2014)

Document ID Name and Affiliation Date Received

EPA-HQ-OAR-2010-0505-4651 Tim Campbell August 14, 2014

EPA-HQ-OAR-2010-0505-4652 Jackie Raesly August 14, 2014

EPA-HQ-OAR-2010-0505-4653 Dan Boggs August 14, 2014

EPA-HQ-OAR-2010-0505-4654 Dr. Richard Guldi

Christine Guldi August 14, 2014

EPA-HQ-OAR-2010-0505-4655 Andrew Pearce, General Manager, 

ACL Manufacturing August 14, 2014

EPA-HQ-OAR-2010-0505-4656 John Robitalle, Vice President, 

Petroleum Association of Wyoming

August 14, 2014

EPA-HQ-OAR-2010-0505-4657 Anonymous Public Comment August 17, 2014

EPA-HQ-OAR-2010-0505-4658 Brian Jefferies, Executive Director, 

Wyoming Pipeline Authority August 17, 2014

EPA-HQ-OAR-2010-0505-4659

Douglas Jordan, Director Corporate 

Environmental Programs, V+ 

Resource Development Solutions, 

Southwestern Energy

August 18, 2014

EPA-HQ-OAR-2010-0505-4660 Duplicate of EPA-HQ-OAR-2010-

0505-4658 August 18, 2014

EPA-HQ-OAR-2010-0505-4661 Veronica Nasser, REM 

Technologies Inc. August 18, 2014

EPA-HQ-OAR-2010-0505-4662

William Addison, Director, Air 

Pollution Control Division, 

Colorado Department of Public 

Health and Environment

August 18, 2014
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Document ID Name and Affiliation Date Received

EPA-HQ-OAR-2010-0505-4663

Todd Parfitt, Director, Wyoming 

Department of Environmental 

Quality

August 18, 2014

EPA-HQ-OAR-2010-0505-4664

Jeff Applekamp, Vice President of 

Government Affairs, Gas Processors 

Association

August 18, 2014

EPA-HQ-OAR-2010-0505-4665

Nicholas DeMarco, President, West 

Virginia Oil and Natural Gas 

Association

August 18, 2014

EPA-HQ-OAR-2010-0505-4666

Gretchen Kern, Sr. Regulatory and 

Environmental Policy Advisor, 

Sustainable Development, Pioneer 

Natural Resources USA, Inc.

August 18, 2014

EPA-HQ-OAR-2010-0505-4667 Anonymous Public Comment August 18, 2014

EPA-HQ-OAR-2010-0505-4668 Darin Schroeder and David 

McCabe, Clean Air Task Force et al. August 18, 2014

EPA-HQ-OAR-2010-0505-4669

Alice Edwards, Director, Division of 

Air Quality, Alaska Department of 

Environmental Conservation

August 18, 2014

EPA-HQ-OAR-2010-0505-4670

Senator Eli Bebout and 

Representative Tim Stubson, Select 

Committee on Federal Natural 

Resource Management of the 

Wyoming Legislature

August 18, 2014

EPA-HQ-OAR-2010-0505-4671 Cory Pomeroy, General Counsel, 

Texas Oil & Gas Association August 18, 2014

EPA-HQ-OAR-2010-0505-4672

Andrew McNeill, Executive 

Director, Kentucky Oil & Gas 

Association, Inc.

August 18, 2014
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Document ID Name and Affiliation Date Received

EPA-HQ-OAR-2010-0505-4673

Jimmy Carlile, HSE and Regulatory 

Supervisor, Fasken Oil and Ranch, 

Ltd., on behalf of the Permian Basin 

Petroleum Association

August 18, 2014

EPA-HQ-OAR-2010-0505-4674 Ursula Rick, Manager of Regulatory 

Affairs, Western Energy Alliance August 18, 2014

EPA-HQ-OAR-2010-0505-4675 Duplicate of EPA-HQ-OAR-2010-

0505-4665

EPA-HQ-OAR-2010-0505-4676 Duplicate of EPA-HQ-OAR-2010-

0505-4669 August 18, 2014

EPA-HQ-OAR-2010-0505-4677

Matthew Todd, American Petroleum 

Association August 18, 2014

EPA-HQ-OAR-2010-0505-4678

V. Bruce Thompson, President, 

American Exploration and 

Production Council

August 18, 2014

EPA-HQ-OAR-2010-0505-4679

Jenny Yang, Director, 

Environmental Regulatory Issues, 

ConocoPhillips Company

August 18, 2014

EPA-HQ-OAR-2010-0505-4680 Duplicate of EPA-HQ-OAR-2010-

0505-4656

EPA-HQ-OAR-2010-0505-4681 Larry Schweiger August 17, 2014

EPA-HQ-OAR-2010-0505-4682 Bill Ferullo August 17, 2014

EPA-HQ-OAR-2010-0505-4683 Olivia Themudo August 17, 2014

EPA-HQ-OAR-2010-0505-4684 Daniel Chaplain August 17, 2014

EPA-HQ-OAR-2010-0505-4685 Dean Marshall August 17, 2014

EPA-HQ-OAR-2010-0505-4686 Tom Blackwell August 17, 2014

EPA-HQ-OAR-2010-0505-4687 Darryl Sullivan August 17, 2014
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Document ID Name and Affiliation Date Received

EPA-HQ-OAR-2010-0505-4688 Patti Rogers August 16, 2014

EPA-HQ-OAR-2010-0505-4689 Tom Damura August 15, 2014

EPA-HQ-OAR-2010-0505-4690 Anonymous Public Comment August 15, 2014

EPA-HQ-OAR-2010-0505-4691 Don Young August 15, 2014

EPA-HQ-OAR-2010-0505-4692 Laura Sessions August 15, 2014

EPA-HQ-OAR-2010-0505-4693 Benjamin Ketchum, Marketing 

Director, Greenbelt Events August 15, 2014

EPA-HQ-OAR-2010-0505-4694 Diane Hume August 15, 2014

EPA-HQ-OAR-2010-0505-4695 Brenda Allen August 15, 2014

EPA-HQ-OAR-2010-0505-4696 Robert West August 14, 2014

EPA-HQ-OAR-2010-0505-4697 Vera Scroggins August 14, 2014

EPA-HQ-OAR-2010-0505-4698 Fred Gustafson August 14, 2014

EPA-HQ-OAR-2010-0505-4699 Angela Spotts August 14, 2014

EPA-HQ-OAR-2010-0505-4700 Barbara VanHanken, Chair

Sierra Club Oklahoma Chapter August 14, 2014

EPA-HQ-OAR-2010-0505-4701 Anonymous Public Comment August 14, 2014

EPA-HQ-OAR-2010-0505-4702 Marisa Soliz August 14, 2014

EPA-HQ-OAR-2010-0505-4703 Anne White August 14, 2014

EPA-HQ-OAR-2010-0505-4704 Hobie Hukill August 14, 2014

EPA-HQ-OAR-2010-0505-4705 Lynne and Paul Binner August 13, 2014

EPA-HQ-OAR-2010-0505-4706 Susan Tyler August 13, 2014

EPA-HQ-OAR-2010-0505-4707 Renee Nielsen August 13, 2014
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Document ID Name and Affiliation Date Received

EPA-HQ-OAR-2010-0505-4708 Mike Dean August 13, 2014

EPA-HQ-OAR-2010-0505-4709 Duplicate of EPA-HQ-OAR-2010-

0505-4708

EPA-HQ-OAR-2010-0505-4710 Mary Cato August 13, 2014

EPA-HQ-OAR-2010-0505-4711 Rebecca Williams August 13, 2014

EPA-HQ-OAR-2010-0505-4712 Connie Triolo August 13, 2014

EPA-HQ-OAR-2010-0505-4713 Dick Schoech August 13, 2014

EPA-HQ-OAR-2010-0505-4714 Cindy Caudle-Dean August 13, 2014

EPA-HQ-OAR-2010-0505-4715 Eileen Barziloski August 13, 2014

EPA-HQ-OAR-2010-0505-4716 Kit Jones, Organizer

Fort Worth MoveOn Council August 13, 2014

EPA-HQ-OAR-2010-0505-4717 Audrey Gozdiskowski August 13, 2014

EPA-HQ-OAR-2010-0505-4718 Gail Neustadt August 13, 2014

EPA-HQ-OAR-2010-0505-4719 Christine Guldi August 12, 2014

EPA-HQ-OAR-2010-0505-4720 Sheila Purdy

Native American Industries, Inc. August 18, 2014

EPA-HQ-OAR-2010-0505-4721 Peter Smith July 9, 2014

EPA-HQ-OAR-2010-0505-4722 Alyssa Tharp August 18, 2014

EPA-HQ-OAR-2010-0505-4723 Chris Guldi August 18, 2014

EPA-HQ-OAR-2010-0505-4724 Tamera J. Bounds, President 

Woodland Estates HOA August 18, 2014

EPA-HQ-OAR-2010-0505-4725 Gary Hogan August 18, 2014

EPA-HQ-OAR-2010-0505-4726 Gerard Farias

Associate Professor of Management

August 18, 2014
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Document ID Name and Affiliation Date Received

Silberman College of Business

EPA-HQ-OAR-2010-0505-4727 Ramona Saldana-Flores August 18, 2014

EPA-HQ-OAR-2010-0505-4728 Daniel Tartaglia August 18, 2014

EPA-HQ-OAR-2010-0505-4729 Sandra DenBraber August 18, 2014

EPA-HQ-OAR-2010-0505-4730 Becky Bornhorst August 18, 2014

EPA-HQ-OAR-2010-0505-4731 Todd Harshman August 18, 2014

EPA-HQ-OAR-2010-0505-4732 Leonard Seiler August 18, 2014

EPA-HQ-OAR-2010-0505-4733 Sinikka Dickerson August 18, 2014

EPA-HQ-OAR-2010-0505-4734 Jerry Lobdill August 18, 2014

EPA-HQ-OAR-2010-0505-4735 Jenny Lisak August 18, 2014

EPA-HQ-OAR-2010-0505-4736 Ann Mai August 18, 2014

EPA-HQ-OAR-2010-0505-4737 Jacqueline Lansford August 18, 2014

EPA-HQ-OAR-2010-0505-4738 John Fischer October 15, 2014

EPA-HQ-OAR-2010-0505-4739 Anonymous Public Comment August 18, 2014

EPA-HQ-OAR-2010-0505-4740 Susan Waskey August 18, 2014

EPA-HQ-OAR-2010-0505-4741 Tim Campbell August 18, 2014

EPA-HQ-OAR-2010-0505-4742 Shelly McAllister August 17, 2014

EPA-HQ-OAR-2010-0505-4743 Martha Hand August 17, 2014

EPA-HQ-OAR-2010-0505-4744 Dan Ferrell August 17, 2014
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2.0 Response to Comments 

2.1 Well Completions

2.1.1 Initial Flowback Stage

Comment: Several commenters (4651, 4652, 4653, 4654, 4657, and 4667) contend that a 

mix of fracking water, fracking chemicals, heavy metals, naturally occurring radioactive 

materials, and hydrocarbon compounds such as BTEX are directed into open tanks during the 

initial flowback stage. The commenters believe the best system of emission reduction for 

flowback liquids is to direct the liquids into closed, ventless, pressurized tanks and urge the EPA 

to amend the proposed rule to require these tanks during flowback.

Response: Pressurized tanks perform best where conditions are constant and predictable 

such that operating parameters for the tanks can be set and maintained. Several characteristics of 

the liquid stream during flowback are highly variable (e.g., pressure, flow rate, solids content, or 

slug flow) and render the use of pressurized storage vessels technologically infeasible under 

most circumstances. Therefore, the EPA does not believe specifying the use of closed, ventless, 

pressurized tanks as a method to control emissions from these operations is warranted. 

2.1.2 Production Stage

2.1.2.1 Applicability

Comment: One commenter (4662) contends that the proposed rule does not distinguish 

what type of equipment is excluded from venting or combusting gas during the production stage, 

which results in confusion as to whether the temporary flowback separator or the permanent 

production separator is prohibited from using combustion as a control.

Response: In the final rule, we have amended the regulatory language in the well 

completions provisions of §60.5375 to identify two distinct stages associated with well 

completion, with each stage having specific requirements for handling of gases and liquids. As 

amended, the flowback stage consists of two stages, the “initial flowback stage” and the 

“separation flowback stage.” As such, the requirements do not apply to a production separator. 

Comment: Two commenters (4663, 4670) point out that the title of §60.5375 refers only 

to gas wells. However, the proposed language regarding the different stages utilizes industry 

terminology ordinarily associated with oil wells. For example, §60.5375(a)(1)(ii) uses the term 

“crude oil” whereas gas well operators would normally use “hydrocarbon liquid” or “liquid 

condensate.” The commenter recommends replacing “crude oil” with one of these alternate terms 

and to specifically clarify that §60.5375 applies only to gas wells. Another commenter (4670) 
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also states that §60.5375 should apply only to wells drilled principally for the production of gas, 

and no other type of well.

Response: We are unsure as to which proposed language the commenter is referring. The 

language we proposed for §60.5375, including §60.5375(a)(1)(ii) referred to by the commenter, 

uses the term “liquids” or “recovered liquids.” We did not use the term “crude oil” in the 

proposed regulatory text for this section. The only instance where we used the term “crude oil” 

in the proposed regulatory text is in the definition of “production stage” in §60.5430. We note 

that the final rule no longer includes this definition. We did, however, repeatedly use the phrase 

“crude oil, condensate and produced water” in the preamble to the proposed rule in the context of 

storage vessels and liquids in general, regardless of whether a particular well would involve all 

these liquids. Although we appreciate the commenters’ concerns on the use of proper 

terminology, we do not believe any confusion will result from the terminology we used in the 

preamble or the proposed rule language.

Concerning the comment on the applicability of §60.5375, we point out that §60.5430 

defines a gas well as “an onshore well drilled principally for production of natural gas.”

2.1.2.2 Prohibition on Venting or Routing Emissions to a Combustion Device

Comment: One commenter (4671) claims that the prohibition is in conflict with the 

storage vessel control requirements. Proposed §60.5375(a)(1)(iii) states that during the 

production stage, “recovered gas may not be vented or controlled by any combustion device.” 

Subpart OOOO requires operators to reduce VOC emissions from storage vessels (which are 

primarily used in production operations) by 95 percent. Control of storage vessel emissions is 

typically achieved through a combustion device. According to the commenter, combusting the 

gas emitted from storage vessels during production would be in apparent conflict with the 

prohibition on combustion in the proposed rule, and controlling only 95 percent of emissions 

from the storage vessel would be in conflict with the proposed prohibition on venting gas.

Response: In the final rule, we have amended the regulatory language in the well 

completions provisions of §60.5375 to identify two distinct stages associated with well 

completion, with each stage having specific requirements for handling of gases and liquids. As 

amended, the flowback stage consists of two stages, the “initial flowback stage” and the 

“separation flowback stage.” Provisions relating to the production stage, including 

§60.5375(a)(1)(iii), are not included in the final rule. Thus, the issue raised by the commenter is 

now resolved.

Comment: Two commenters (4665, 4677), believe the EPA’s prohibition on venting and 

combusting emissions during the production stage is related to the concern about possible use of 

portable frac tanks as substitutes for storage vessels after production has begun, thus delaying the 
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time the 60-day emissions and control evaluation would begin. The commenters contend that is 

could be avoided, and the need to regulate production activities eliminated, by revising the 

definition of "well completion vessel" to add as the third sentence of the definition the following: 

A vessel that is skid-mounted or portable that continues to receive well flow from a 

hydraulically fractured well after startup of production of the well shall be deemed a new 

storage vessel for only as long as it continues to receive well flow from that well. 

The commenters contend that this would treat portable frac tanks as storage vessels if 

they were used to support production activities, but only as long as they were used in that 

capacity.

Response: As discussed in the previous comment response, the final rule no longer 

includes provisions relating to the production stage. Therefore, the commenters’ concern about 

the prohibition on venting and combusting emissions during the production stage is now moot. 

We point out, however, that we have amended the definition of “storage vessel” in the final rule 

to include the provision that “a well completion vessel that receives recovered liquids from a 

well after startup of production following flowback for a period which exceeds 60 days is 

considered a storage vessel under this subpart” The commenters are referred to sections III.A and 

IV.A of the preamble to the final rule for further discussion of these changes. 

2.1.2.3 Consideration of Costs

Comment: One commenter (4663) contends that the EPA failed to consider costs 

associated with the prohibition on venting and flaring, which the commenter believes is required 

by the CAA when determining the best system of emission reduction. Specifically, the 

commenter stated that the EPA failed to consider the costs associated with the prohibition for oil 

wells. The EPA stated that “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.” The commenter contends that the EPA’s statement is 

only applicable to gas wells, which by virtue of their purpose are already connected to sales lines 

for natural gas. However, there would be substantial compliance costs for oil wells due to a lack 

of natural gas pipeline infrastructure in areas dominated by oil wells.

The commenter adds that if the proposed rule bans all venting and flaring from oil wells 

during the production stage, then oil well operators would be faced with the choice of installing 

pipelines to connect to sales lines, utilizing recovered gas as fuel on site or shutting the wells in 

until they could perform one of these options. The commenter urges the EPA to allow venting 

and flaring during all stages of well completion and production.
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Response: We believe the commenter is referring to the prohibition in §60.5375(a)(1)(iii) 

of the proposed rule on venting and flaring during the production stage. First, we point out that 

§60.5375 applies only to gas wells. Insomuch as the commenter is concerned about the effect on 

oil wells, these concerns are not relevant because §60.5375 does not apply to oil wells. Second, 

we have amended the regulatory language in the well completions provisions of §60.5375 to 

identify two distinct stages associated with well completion, with each stage having specific 

requirements for handling of gases and liquids. As amended, the flowback stage consists of two 

stages, the “initial flowback stage” and the “separation flowback stage.” Provisions relating to 

the production stage, including §60.5375(a)(1)(iii), are not included in the final rule. 

2.1.3 Recordkeeping and Reporting Requirements

Comment: One commenter (4668) urges the EPA to require that producers document

each instance in which the infeasibility exception in proposed §60.5375(a)(1)(ii) is invoked, to 

include the reasons for using this exception in annual reports to the EPA in light of the operative 

regulatory criteria, and to ensure these reports are publicly available. The commenter believes 

the omission of this recordkeeping and reporting requirement in the current language of subpart 

OOOO is a serious compliance and enforcement deficiency, and correcting this deficiency will 

help ensure basic transparency and accountability in the use of this exception.

Response: The EPA agrees with the commenter with respect to the need for operators to

document exceptions to the requirements for handling gases from the separator during flowback,

which consists of the initial flowback stage and the separation flowback stage. The NSPS, at 

§60.5420(c)(1)(iii), requires records of the date and time of the onset of flowback following 

hydraulic fracturing or refracturing; the date and time of each attempt to direct flowback to a 

separator as required in §60.5375(a)(1)(i); the date and time of each occurrence of returning to 

the initial flowback stage under §60.5375(a)(1)(i); and the date and time that either the well was 

shut in and the flowback equipment was permanently disconnected, or production commenced 

(i.e., the “startup of production”). The EPA considers these recordkeeping requirements to be 

necessary for enforcement personnel to clearly understand the duration of flowback and how the 

well completion was conducted, including how long after the onset of flowback that attempts 

were made to route flowback to a separator and how many times the operator reverted to the 

initial flowback stage.

Comment: One commenter (4679) points out that the recordkeeping requirements for 

gas well affected facilities in §60.5420(c)(1)(iii)(A) requires records of the duration of venting. 

According to the commenter, during the initial flowback stage, the well is not routed to any 

phase separation equipment capable of determining the presence of gas. As indicated by the 

EPA, any gas generated during the initial flowback stage will be negligible and does not warrant 
13

applicability under the subpart OOOO green completion work practice standards. Accordingly, 

the commenter states that no gas volumes may be measured and it would not be possible to make 

accurate representations of “venting” during the initial flowback stage to satisfy the 

recordkeeping requirement for logging the duration of venting. The commenter requests that the 

EPA clarify that these recordkeeping requirements apply only during the separation flowback 

stage.

Response: We point out that the proposed language in §60.5375(a)(1)(i) states that “any 

gas present in flowback prior to the separation flowback stage is not subject to control under this 

section.” That means that operators are not required to “control” these emissions or capture them. 

However, any gas in the flowback that is routed to an uncontrolled well completion vessel or 

storage vessel during the initial flowback stage in accordance with the requirements of 

§60.5375(a)(1)(i) is considered to be “vented,” and the recordkeeping requirements of 

§60.5420(c)(1)(iii) to document the duration of venting would apply to the initial flowback stage, 

since that stage is a part of the flowback period. As a result the initial flowback stage (including 

any occurrences of reverting to that stage) would be considered a period of venting to be 

included in the total duration of venting required to be recorded in accordance with §60.5375(b)

and as specified in §60.5420(c)(1)(iii). The periods of venting, combustion and collection would 

account for the entire flowback period, minus any time the well was shut in.

2.1.4 Use of Lower Explosive Limit (LEL) Meters

Comment: Three commenters (4668, 4674, and 4678) support the use of an LEL meter 

to determine when flowback gas can be diverted to a separator. One commenter (4668) states 

that a recent study indicates that the methane LEL is a conservative indicator of the feasibility of 

separating and controlling emissions during a completion, and recommends that the EPA 

explicitly define the methane concentration that signifies the end of the initial flowback period. 

The commenter also urges the EPA to provide clear parameters regarding acceptable 

technologies for methane monitoring as well as the installation and calibration of such monitors.

Two commenters (4674, 4678) stated that the EPA is correct that some operators use 

LEL meter results as one piece of data to determine when fluids can be routed to a separator 

during flowback, but this practice is not universal throughout the oil and natural gas industry. 

According to the commenters, LEL meters can be used as an indication that gas is present but are 

not used as the sole determinant that a separator could operate. The commenter suggests the EPA 

allow flowback crews and operators the flexibility in the methods used to determine when it is 

safe to route fluids to a separator.

Several commenters (4656, 4659, 4671, 4673, 4677, and 4679) oppose the use of an LEL 

meter. As described by one commenter (4656), LEL meters offer no empirical means from which 

to make the determination of when gas can be routed to a separator. A separator requires both 
14

sufficient gas pressure and volume to operate. An LEL meter provides information on neither. 

Making the determination that the separation stage can begin is an experience-based decision and 

flowback characteristics are variable from well to well. Two commenters (4677, 4679) add that 

the sand and water content are important factors in this experience-based decision. Requiring an 

LEL to make this determination could force the separation stage to occur prematurely which 

risks flooding the separator and lines with fluids that need to be cleaned out. This would 

necessitate shutting in the well and restarting flowback which is not desirable.

One commenter (4671) adds that LEL measurements are used by some operators to 

determine if any gas is present in the flowback, but the measurements do not inform an operator 

whether sufficient pressure and quantity of gas to operate a separator is present. Further, the gas 

content in flowback is highly variable over time, and an LEL measurement by itself is not a 

conclusive indicator of a steady and sufficient gas concentration and pressure. In addition, for 

certain well site configurations, such as those discharging to a lined earthen pit during initial 

flowback, the flowback is not contained in a manner where it is practical to collect a 

representative LEL measurement. Another commenter (4679) adds that LEL meter readings can 

vary depending on location and external influences such as wind. Due to the high variability of 

well behavior during flowback, including fluctuations in gas concentration and pressure, the 

commenter states that there is no single objective criterion relied upon by operators to signal 

when to begin separation. The well completion process is dependent on experienced operators to 

gauge when sufficient gas is present to operate a separator. The commenter does not believe it is 

realistic for the EPA to proscribe objective criteria for this determination when none exist in the 

field.

Response: We appreciate all of the informative comments on the use and function of

LEL meters. As discussed in section IV.A of the preamble to the final rule, we believed that 

some operators used LEL meters to determine when sufficient gas is present in the flowback for 

the separator to function. However, we were uncertain whether this method could be used 

effectively in all applications and whether there were other techniques used by operators to make 

this determination. Based on the comments received, it is apparent that some owners and 

operators use LEL meters at least as an indicator that the separator can function, but other 

owners and operators strongly contend that LEL meters do not necessarily indicate in all 

situations that sufficient gas is present for the separator to function. Because whether a separator 

can operate may depend on site specific factors other than the amount of gas present in the 

flowback, we are not finalizing requirements to use a LEL meter to determine when the separator 

can function. 
15

2.1.5 Definitions Associated with Well Completions

Comment: One commenter (4677) provides the following explanations for 

recommended amendments to the proposed definitions. In addition, the commenter provides

revised wording for each of these definitions in their comments.

Flowback. The definition of flowback should be revised to clarify the conditions 

indicating the end of the flowback period. The EPA proposed a revision to this definition 

stating that one condition for the end of flowback is when “the production stage begins,” 

which is defined as 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 is a rather subjective threshold, and should be 

replaced with more determinative criteria. The other condition for the end of flowback in 

the EPA’s proposed definition is when “the well is shut in.” However, there are 

circumstances that require a well to be temporarily shut-in before flowback is complete, 

and thus we suggest clarifying language be added to explain the intent of this condition. 

Recovered gas. While the EPA has attempted to clarify the distinction between gas 

recovered from the separator and gas flashed from a storage vessel or well completion 

vessel, there is still room for this distinction to be misconstrued. It should be clarified that 

recovered gas is gas recovered from the gas outlet of the separator during flowback. 

Reduced emissions completion. This definition should be deleted as the term is not used 

in the rule. 

Salable quality gas. Certain of the requirements in §60.5375 hinge on the definition of 

salable quality gas. This term as defined requires that gas meet “composition, moisture, 

or other limits set by the purchaser of the natural gas.” This could be construed as 

exempting gas that is suitable for routing to a flow line at the well site if the gas does not 

meet pipeline specifications, in that the processing to meet composition and moisture 

limits is often done at a central facility rather than at the individual well site. The 

commenter suggests this definition should be expanded so as to include all gas suitable 

for routing to a flow line or a collection system (i.e., meeting the flow line operator 

specifications and having sufficient pressure), and not to limit it to only the gas that meets 

gas pipeline specifications. 

Separation flowback stage. The revisions suggested above to clarify the end of flowback 

in the definition of flowback should be mirrored in the definition of separation flowback 

stage. 
16

Well completion vessel. The EPA has expressed a concern that liquids from a well which 

has been hydraulically fractured may continue to be routed to a well completion vessel

after startup of production. The most direct and effective way to address this concern may 

be to declare a well completion vessel to be a storage vessel if it continues to receive well 

flow from a hydraulically fractured well after startup of production of the well, regardless 

of the characteristics of the vessel. This would effectively subject the vessel to the 

applicability determination of §60.5365(e) within 30 days after startup of production, and 

if determined to be an affected facility, the control requirements of §60.5395(d) within 60 

days after startup of production.

Response: In the final rule, we have amended the definition of flowback to include the 

following provision: “The flowback period ends when either the well is shut in and permanently 

disconnected from the flowback equipment or at the startup of production.” We believe this 

provision provides the clarity sought by the commenter. Similar changes are also included in the 

definition of “separation flowback stage.”

We agree with the commenter’s suggestion concerning the definition of “recovered gas” 

and have made the suggested amendment in the final rule, as follows: “Recovered gas means gas 

recovered through the separation process during flowback.”

As suggested by the commenter, we have removed the definition of “reduced emissions 

completion” from the final rule because that term is not used in the rule.

We agree that the proposed definition of “salable quality gas” was overly restrictive, and 

the changes suggested by the commenter would allow more gas to be routed to a flowline, which 

is a beneficial result. Therefore the definition of “salable quality gas” in the final rule 

incorporates the commenter’s suggestions as follows: “Salable quality gas means natural gas that 

meets the flow line or collection system operator specifications, regardless of whether such gas is 

sold.”

We agree with the commenter’s suggestion concerning the treatment of well completion 

vessels after startup of production. See sections IV.A and V.A of the preamble to the final rule 

for further discussion of this topic.
17

2.2 Storage Vessels

2.2.1 Applicability and Compliance 

2.2.1.1 Initial Compliance Period for Modified or Reconstructed Storage Vessels

Comment: One commenter (4664) states that if a storage vessel is not an affected source 

due to emissions of less than 6 tpy of VOC emissions as defined and calculated under 

§60.5365(e), but then is modified or reconstructed such that emissions increase to 6 tpy or 

greater, it is unclear when the storage vessel must comply with the §60.5395 standards. 

Currently, §60.5395(d)(1)(i) allows 60 days from startup to achieve the required emissions 

reductions. As such, the rule should also allow 60 days from the date on which a storage vessel 

becomes an affected facility since there may be some situations where a source becomes an 

affected facility long after startup occurs. The commenter suggests adding “or within 60 days of 

the date on which a storage vessel becomes an affected facility” to §60.5395(d)(1)(i).

Response: While the comment is somewhat unclear, we read the comment as requesting 

that we provide that a tank that is initially determined under § 60.5365(e) to have less than 6 tpy 

of potential VOC emissions not be given less time than other tanks to come into compliance if 

circumstances change. We are not adopting the requested language both because (1) the rule 

already provides for equivalent treatment in these circumstances; and (2) the requested addition 

would actually provide 90 days for a tank to come into compliance. To the extent that the 

commenter is requesting this longer timeframe, they have not provided information to support 

such a deviation.

Comment: Several commenters (4665, 4666, 4671, 4677, 4679) express concern that 

§60.5365(e) requires a redetermination of VOC emissions each time a well is connected to a 

given storage vessel after production has commenced. The commenters state that the VOC 

emissions analysis should only be required for new, modified or reconstructed storage vessels. 

The commenters request that the EPA modify §§60.5365(e) and 60.5395(d)(1)(i) accordingly. 

One commenter adds that in order to avoid inadvertent application of the rule to tanks that 

receive liquids pursuant to §60.5375 but which are not new, modified or reconstructed, 

§60.5365(e) should be revised to clarify that applicability is triggered by construction, 

modification or reconstruction of the storage vessel.

Response: In response to these and other comments on §60.5365(e), the EPA has made 

several amendments to this paragraph (see sections III and IV of the preamble to the final rule 

for further discussion of these changes). In particular with regards to these comments, we agree 

that the language suggested by the commenters would add clarity and have incorporated the 

commenters’ suggestion by adding §60.5365(e)(1) as follows: “For each new, modified or 
18

reconstructed storage vessel 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 startup of production.”

2.2.1.2 What Constitutes a Modification or Reconstruction for Storage Vessels

Comment: Two commenters (4666, 4671) express concern that the proposed rule is 

unclear as what constitutes a modification or reconstruction for a storage vessel. The commenters

believe that it was the EPA’s intent to require evaluation of a storage vessel’s emissions only if it 

is an affected facility. The rule specifies that a storage vessel affected facility is a storage vessel 

with the potential for VOC emissions greater than 6 tpy and for which construction, modification 

or reconstruction commenced after August 23, 2011. Thus, according to the commenters, the 

NSPS General Provisions dictate the type of change (i.e., modification) that would subject a 

storage vessel to subpart OOOO because subpart OOOO does not contain a subpart-specific 

definition of modification. The General Provisions define modification as “any physical change 

or change in the method of operation of an existing facility which increases the amount of any air 

pollutant...or which results in the emissions of any air pollutant...not previously emitted.” The 

commenters point out that the General Provisions requires both a physical change and an 

increase in emissions for the change to be considered a modification. Also, the General 

Provisions provide that an increase in production rate is not a modification if it can be 

accomplished without a capital expenditure. The commenters contend that existing storage 

vessels may experience an emissions increase from increased throughput due to fracturing, 

refracturing, addition of new wells or rerouting of existing wells; however, none of these actions 

will change the affected facility status of the storage vessel because of the increased production 

rate exemption of the General Provisions.

One commenter (4671) adds that §60.14(e) of the General Provisions provides that an 

existing facility is not modified by the use of an alternative fuel or raw material if the facility was 

designed to accommodate the alternative fuel or raw material prior to the effective date of the 

rule. Existing storage vessels, the commenter contends, are designed to accommodate recovered 

liquids of varying compositions. Thus, even when the liquids from new or re-routed wells are of 

a different composition than what is currently routed to an existing storage vessel, this would not 

constitute a physical change or change in the method of operation. The commenter provides 

further support for this view by referencing a general guidance letter from OECA dated August 

19, 2003 stating that a change in the liquids stored in a storage vessel does not constitute a 

modification (in reference to 40 CFR part 60, subparts Ka and Kb).

Response: The General Provisions to 40 CFR part 60 govern what constitutes a 

modification or reconstruction since subpart OOOO does not override the General Provisions in 

this regard. Thus, section 60.14(a) of the General Provisions states that:
19

Except as provided under paragraphs (e) and (f) of this section, any physical or 

operational change to an existing facility which results in an increase in the emission rate 

to the atmosphere of any pollutant to which a standard applies shall be considered a 

modification within the meaning of section 111 of the Act.

Similarly, §60.15(b) of the General Provisions states that:

Reconstruction means the replacement of components of an existing facility to such an 

extent that:

(1) The fixed capital cost of the new components exceeds 50 percent of the fixed capital 

cost that would be required to construct a comparable entirely new facility, and

(2) It is technologically and economically feasible to meet the applicable standards set 

forth in this part.

It is beyond the scope of this document to address whether a specific situation may 

constitute modification or reconstruction.

Comment: One commenter (4671) states that if the intent of the emissions determination 

requirement of §60.5365(e) is to regulate existing storage vessels when a fractured well is 

connected, this significant new requirement is beyond the scope of the proposed rule. The 

existing regulation regulates storage vessels that are constructed, modified, or reconstructed after 

August 23, 2011. In the proposed rule, the commenter points out that the EPA lists four issues 

related to storage vessels that the Agency is addressing – PTE determinations, thief hatches, 

storage vessels removed from service, and electronic spark ignition – but does not provide notice 

that it is changing the rule to regulate existing storage vessels when a new well is connected.

Thus, the commenter contends that regulation of existing storage vessels, under any 

circumstances, is beyond the scope of this rulemaking because the EPA did not provide adequate 

notice to the public of this proposed significant change. In addition, the costs and economic 

impacts of installing control devices on existing storage vessels, if the rule was changed to 

regulate these facilities, were not considered.

Response: The introductory text to §60.5365 reads "You are subject to the applicable 

provisions of this subpart if you are the owner or operator of one or more of the onshore affected 

facilities listed in paragraphs (a) through (g) of this section for which you commence 

construction, modification or reconstruction after August 23, 2011." Section 60.5365(e) applies 

only to facilities constructed, modified or reconstructed after August 23, 2011. Therefore, the 

commenter has misinterpreted the applicability requirements and the EPA is not expanding 

coverage of the rule requirements to existing storage vessels.
20

2.2.1.3 Compliance Period for Storage Vessels

Comment: One commenter (4668) states that the proposed amendments allow storage 

vessels that receive liquids from gas well affected facilities pursuant to §60.5375(a) 60 days after 

the beginning of the production stage to comply with the 95 percent emissions reduction 

requirement. The commenter finds this to be particularly troubling because the emissions from 

these storage vessels are likely to be highest during the beginning of the production stage.

The commenter points out that recent state-level precedent on this issue shows it is 

possible to require controls during the period that the EPA proposes to exempt. The Colorado 

Department of Public Health and Environment’s (CDPHE) recent revisions to Regulation 7 

require controls on all storage vessels that have a PTE of 1.5 tons or more during the first 90 

days of production (roughly the equivalent of 6 tpy). The CDPHE recognized that “[b]ecause

production is typically at its highest during this initial period, significant emissions [occurred]

before controls [were] installed.” According to the CDPHE, the tanks that would have a PTE of

less than 6 tpy would still be able to control VOC emissions at a very reasonable rate of $176 per

ton of VOC reduction. The regulations further allow the control to be removed at any time after

the first 90 days of production if the source demonstrates that the uncontrolled actual emissions

are below 6 tpy.

Based on Colorado’s precedent, the commenter requests that the EPA remove the 60-day 

post production phase exclusion period for compliance with the storage vessel emission 

reduction requirements and require all storage vessels, including those that receive liquids from 

gas well affected facilities, to comply with the 95% VOC reduction requirement during the first 

60 days of the production stage. After that time, the commenter recommends that the source 

could be allowed to remove the pollution control only if it is able to show that its uncontrolled 

actual emissions would fall below the affected source threshold.

Response: As explained in the 2012 NSPS rulemaking, a 30-day period is provided to 

allow the throughput to stabilize and determine a storage vessel’s potential emissions. 77 FR 

49526. For storage vessels that require control, because time is needed to acquire and install 

control, an additional 30 days is provided for these storage vessels to come in compliance. Id. 

The commenter did not dispute or otherwise comment on the EPA’s rationales for the 60-day 

period but requested that the EPA eliminated this period because it is not provided in CDPHE’s 

regulation. While the CDPHE regulation strives to quickly implement control on larger sources 

of emissions, there may be conditions and factors that may not be an issue in Colorado but are 

encountered in other states, which we need to consider in establishing the NSPS. For example, 

Wyoming requires that storage vessels be controlled within 30-90 days (depending on the area of 

the state) to allow owners and operators time to procure and installing controls. In light of the 

above, we reject the commenter’s request to eliminate the 60 day period.
21

2.2.2 Storage Vessels Removed from Service

Comment: One commenter (4665) requests that the EPA provide clarification as to what 

is meant by “physically isolated” as that term is used in the definition of removed from service. 

In particular, the commenter requests clarification on whether the term is intended to differ from 

“disconnected.”

Response: The definition of “removed from service” includes both “physically isolated” 

and “disconnected.” Therefore, the two terms were meant to convey two different criteria 

otherwise one of the terms would have been redundant. As used in the definition of “removed 

from service,” the term “disconnected” means that piping used to direct fluid into and out of the 

storage vessel has been physically detached from the storage vessel. The term “physically 

isolated” means that the storage vessel has been moved from its former location and placed 

where it cannot be readily reconnected for use as a storage vessel. Further, as provided in 

§60.5395(f)(1) of the final rule, for a storage vessel affected facility to be considered “removed 

from service,” the owner or operator must empty and degas the storage vessel and include a 

notification of the date of its removal from service in the next annual report. 

2.3 Vapor Recovery Unit (VRU) Provisions

Comment: Two commenters (4673, 4678) believe that the proposed language in 

§60.5365(e) is not clear and could be interpreted to state that only vessels that do not have 

legally and practically enforceable limitations can take into account emission reductions from the 

VRU when determining applicability. The commenters request confirmation that, as stated in the 

preamble, it was the EPA’s intent that storage vessels with a legally and practically enforceable 

limitation incorporating a VRU may take the reductions into account when determining 

applicability, and also need only comply with the existing enforceable limitation and not the 

requirements in 60.5365(e).

Response: We disagree that our intent was not clearly stated in the proposed language of 

§60.5365(e). In the proposal, the EPA clarified the language to indicate that the potential to emit 

determination may exclude emissions that are controlled under a legally and practically 

enforceable limit in an operating permit or other requirement established under a federal, state, 

local or tribal authority. The proposed rule also states that 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 §60.5365(e)(3) (i) 

through (iv) is not required to be included in the determination of VOC potential to emit. In 

other words, potentially affected facilities have two ways to exclude potential emissions from the 

PTE calculation: by having a legally and practically enforceable limit in an operating permit or 
22

other requirement established under a federal, state, local or tribal authority; or by using a VRU 

operated according to the criteria in 60.5365(e)(3) (i) through (iv). The EPA has made both 

these alternatives available in order to maximize incentives to capture emissions that would 

otherwise be emitted and use those captured emissions for a useful purpose.

2.4 Alternative Compliance Option for Reciprocating Compressors

Comment: One commenter (4668) states that while the EPA apparently intends this 

alternative compliance option to require beneficial use of gas escaping from rod packing, the 

commenter is concerned that the text of the proposed rule text is confusing or perhaps ambiguous 

and may be read to allow the emissions from rod packing to be sent to a combustion device, 

instead of “to a process” (i.e., to be used beneficially).

The commenter points out that the proposed regulation would require operators to 

“[r]oute the rod packing emissions to a process through a closed vent system and cover that meet 

the requirements of § 60.5411(a) and (b)”, and includes a definition for “route to process.”

However, the commenter believes that the proposed language is general and some may not 

realize that the specific definition of “route to process” applies, and does not allow routing to a 

flare. As currently worded, the proposed definition of “route to a process” includes a broadly 

stated provision that the commenter contends can be misinterpreted to include combustion in a 

flare. This confusion is more likely, according to the commenter, because the proposed rule 

would require operators to “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).” The commenter points out that a control device can refer to a combustion device or flare.

The commenter adds that since the alternative that the EPA proposes would not require 

regular rod packing replacement, the volume of gas escaping through the rod packing may 

become quite large if operators choose not to replace the rod packing for several years past the 

26,000 hour working period required by §60.5385(a)(1). If all of these emissions are sent to a 

combustor or flare instead of used in a beneficial manner, the commenter believes that 

significant unnecessary emissions of CO2 and combustion pollutants could result.

The commenter urges the EPA to modify the text of §60.5411 to clarify the definition of 

“route to a process” and provide appropriate preamble language so that it is clear that emissions 

must be routed to a process that involves beneficial use. The commenter suggests separate 

paragraphs for reciprocating compressor closed vent systems.

Response: The EPA disagrees that this is a possible interpretation of §§60.5385(a)(3) 

and 60.5411(a)(1). While §60.5411(a)(1) is more general with respect to closed vent systems 
23

and does describe requirements for closed vent systems that route to a control device, the specific 

standard applicable to closed vent systems routing rod packing emissions from reciprocating 

compressors precludes routing to a flare, because the language directly says “to a process” 

without further options. The EPA considers the current definition of “route to a process” to be 

sufficient as well.

Comment: One commenter (4668) states that inspecting closed vent systems to ensure 

that emissions are contained within the closed vent system is critical. While the specific system 

that the EPA describes for routing rod packing emissions to process is designed to put suction on 

the closed vent system, the commenter contends that the proposed rule language does not require 

that the system operate under negative pressure, and conceivably other systems will be invented

which operate under positive pressure. If operators choose not to replace rod packing under the 

alternative compliance option, the commenter contends that the quantity of gas passing through 

the closed vent system could become large, making it essential that operators ensure it does not 

leak. The commenter urges the EPA to require instrument-based inspections at intervals more 

often than annually (quarterly or monthly, for example) for all systems subject to §60.5416

(closed vent systems for wet seal centrifugal compressors, reciprocating compressors, and

storage tanks) and to allow operators to perform such inspections using optical gas imaging

technology.

Response: The commenter is correct that the decision to add a third alternative for 

controlling emissions from reciprocating compressor rod packing was based, in part, on the 

concept of having the rod packing emissions routed to a process under negative pressure. 

Although the proposed rule did not include requirements for negative pressure, we agree with the 

commenter and have included language that requires that the emissions must be conveyed from 

the rod packing to the process under negative pressure. However, we disagree that more 

frequent monitoring is required. Closed vent systems are subject to the closed vent system 

inspection and monitoring requirements and the no detectable emissions test methods and 

procedures. The potential examples cited by the commenter are not compelling, given that the 

owner or operator must continuously comply with the negative pressure and no detectable 

emissions requirements. With regard to the other emission sources the commenter mentioned,

such as wet seal centrifugal compressors and storage vessels, we discussed in detail the 

monitoring provisions for those units in the September 23, 2013, storage vessel implementation 

amendments final rule.

Comment: Several commenters (4673, 4674, and 4678) expressed support for the 

provisions in the proposed rule that allow for control of rod packing vents through the use of 

combustion devices. However, the commenters do not support the provisions requiring the same 

testing and monitoring of these control devices as that required for centrifugal wet seal control 

devices. The commenters contend that reciprocating compressors have far less emissions than 
24

centrifugal compressors, and the testing and monitoring requirements are quite onerous for such 

a small amount of VOC emissions, which could discourage the use of control devices to reduce 

these emissions. The commenters suggest the EPA allow the use of the same streamlined 

monitoring required for storage vessels for reciprocating compressors.

Response: The EPA points out that the proposed requirements for routing rod packing 

emissions do not allow these emissions to be routed to a control device. Rather, the allowable 

route for a closed vent system under §60.5385(a)(3) is to a process, with “route to a process”

defined under §60.5430. While closed vent systems in general may be routed to combustion 

devices, this specifically is not the case for reciprocating compressors under §60.5385(a)(3). We 

note that, in the final rule, such closed vent system for routing rod packing emissions to a process 

must operate under negative pressure.

2.5 Pneumatic Controllers

Comment: One commenter (4664) appreciates the EPA’s modification to §60.5390(c)(2) 

which corrects one contradictory requirement. However, the commenter believes there are still 

significant issues with consistency between the pneumatic controller affected facility 

descriptions in §60.5365(d) and the rule requirements. As written, the commenter contends that 

the proposed rule contains requirements for a pneumatic controller whose bleed rate is below 6 

scfh. However, if the pneumatic controller bleed rate is below 6 scfh, then it is not an affected 

facility, and is not subject to this rule. For example, §60.5390(c)(2) references a requirement in 

§60.5420(c)(4)(iii) to maintain records of the manufacturer's specifications indicating that the 

controller is designed such that natural gas bleed rate is less than or equal to 6 scfh. There is no 

circumstance under which §60.5420(c)(4)(iii) will be an applicable requirement, and it should be 

deleted. Also, the commenter states that there does not appear to be a scenario under which 

§60.5390(c)(2) would be an applicable requirement, and it should be deleted as well. The 

commenter also contends that §60.5390(c)(2) still contains language that is not consistent with 

the affected facility descriptions provided in §60.5365(d)(1) and (2). 

Response: In this case, an affected facility is defined by a threshold (i.e., 6 scfh). In order 

for both the owner/operator and the regulatory agency to determine whether the facility is an 

affected facility, the bleed rate of each pneumatic controller must be determined. In the case of 

pneumatic controllers, the NSPS provides that manufacturer documentation presenting the 

controller’s bleed rate is an acceptable basis for this determination. Records of these 

determinations must be maintained in order for the regulatory agency to know which pneumatic 

controllers are affected facilities. The affected facility determination, in this case, for the nonaffected pneumatic controller is the manufacturer's specification indicating that the pneumatic 

controller emission rate is less than the threshold. Therefore, the recordkeeping requirement in 

§60.5390(c)(2) would be an applicable and appropriate requirement.
25

2.6 Control Device Operating Requirements

Comment: Two commenters (4665, 4677) request clarification of the proposed 

requirements for control devices to be operated at all times that vapors are routed from the 

storage vessel to the control device. The commenters note that §§60.5412(d)(3) and 

60.5417(h)(1)(i) might be interpreted to require operation of control devices at all times, even 

when the control devices are not needed. The commenters request that the EPA clarify that this 

requirement applies to all times that vapors are being pushed from the storage vessel by flow 

from a well, and does not apply to periods when the well is shut in and the only emissions from 

the storage vessel are breathing losses.

Response: We do not agree with the commenters that emissions should be controlled 

only when flow is occurring from the well. There may be periods when liquids containing VOC 

are present in the storage vessel when there is no flow from the well. There will likely be 

emissions from these liquids that will be emitted from the tank. These emissions should be 

controlled to the same extent as emissions that occur while liquids are flowing into the storage 

vessel. Therefore, the requirement to operate the combustion device at all times is appropriate. 

Comment: One commenter (4664) refers to the proposed new requirement in 

§60.5413(e)(7), which states, “[e]nsure that each enclosed combustion device is maintained in a 

leak free condition.” The commenter states that similar language currently exists at 

§60.5412(d)(1)(i), and seeks clarification on what this requirement means. According to the 

commenter, the terms “ensure” and “leak free” are not described or defined, and specific 

compliance requirements, if any, are unclear. The commenter also points out that a combustion 

device must have a vent to atmosphere through which the combustion products are vented to 

prevent over-pressurization; therefore, it is unclear how such a device can be “leak free.” 

Response: This requirement was added to the ongoing compliance demonstration 

requirements of §60.5413(e)(7) to be consistent with the initial compliance demonstration 

requirements of §60.5412. The EPA does not believe that these provisions are ambiguous and 

that venting of a combustion device for its normal operation and safety concerns is not 

considered a leak.

2.7 Exemptions to the Equipment Leak Standards

Comment: One commenter (4677) points out that the revised wording of §60.5401 

appropriately adds connectors to the description of equipment components that are exempt from 

the standard if located at a small non-fractionating plant or within a process unit in the Alaskan 

North Slope, but the language should also include the provision for connectors in the citations at 

paragraphs §60.5401(d) and (e) to 40 CFR part 60, subpart VVa. That is, in specifying that there 
26

is an exemption for connectors, the commenter contends that the language should also cite the 

provision from which the connectors are exempt.

Response: The EPA agrees that the suggested change is appropriate and will add further

clarity to the final rule. Therefore, we have added §60.482-11a(a) to the list of exempted 

equipment in both §60.5401(d) and (e).

2.8 Responsible Official

Comment: One commenter (4677) expresses concern with the statement that “the 

Administrator reserves the right to evaluate such delegation.” The commenter is unsure about 

what this means in practice and how one would know whether or not their delegation is 

immediately effective. The commenter would also like clarification on how the EPA will ensure 

that this “evaluation” does not “affect the facilities’ ability to comply with the certification 

requirement in the event there are delays in approvals of delegation” as stated in the preamble.

The commenter recommends that this sentence be removed or some qualifying language added 

that allows for use/application of the delegation for certification during evaluation in the event 

than an agency elects to exercise their right to evaluate the delegation. Another option suggested 

by the commenter might be to establish a period of time within which the evaluation must be 

completed to allow for unconditional use/application of the delegation in the absence of any

agency correspondence to the contrary.

Response: In response to the commenter, we note that the final rule does not require the 

Administrator’s approval for delegation. Thus, the delegation is effective upon notification of the 

delegation as specified in the definition of “certifying official” in §60.5430. Since approval is not 

required for delegation, there cannot be a delay of approval, whether by the Administrator’s 

evaluation or anything else, that would affect a facility’s ability to comply with the certification 

requirement.

2.9 Technical Corrections

Comment: Two commenters (4664, 4677) note that there are several places in the 

amendatory regulatory text that appear to exactly match the previous rule language. The 

amendatory items are numbers 8, 9.f, 12.a, and 15.c.

Response: The corrections to which the commenters refer were changes to spacing and 

line returns that would not be readily perceivable in comparison but were deemed important to 

address clarity.
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Comment: One commenter (4664) points out that in the preamble, the EPA notes, “[w]e 

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.” (79 Fed. Reg. 41759). However, no changes are 

proposed to sections §60.5395(f)(1) or (2).

Response: The EPA erroneously noted that changes were made to sections 

§60.5395(f)(1) or (2). The only proposed changes were to the introductory text of paragraph 

§60.5395(f).

Comment: One commenter (4664) suggests the follow changes:

 To improve clarity and consistency in §60.5416(b): §60.5416(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 compressor 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.

 §60.5420(c)(8) now applies to reciprocating compressors, so the language that 

appears in that section should be modified to reflect that (citation path is 

§60.5385(a)(3) to §60.5411(a)(3)(i)(A) to §60.5416(a)(4)(ii) to §60.5420(c)(8)):

§60.5420(c)(8) If you are subject to the bypass requirements of §60.5416(a)(4) 

for centrifugal compressors or reciprocating compressors or §60.5416(c)(3) for 

storage vessels, a record of each inspection or a record each time the key is 

checked out or a record of each time the alarm is sounded.

 The title for §60.5415 includes the word “stationary.” This is the only place the 

phrase “stationary reciprocating compressor affected facility” is used in subpart 

OOOO. The commenter suggests deleting the word “stationary” to avoid 

unnecessary confusion.

 The EPA is proposing to modify §60.5420(c)(3)(ii). The commenter requests that 

the requirement to maintain “[r]ecords of the date and time of each reciprocating 

compressor rod packing replacement” should be eliminated. Section 

60.5420(c)(3)(i) already requires records of cumulative number of hours of 

operation or number of months since startup, rule publication, or previous 

replacement. Thus, recording the date and time of replacement is duplicative at 

best but is mostly unnecessary to ensure compliance with the emission reduction 
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requirements. The “time,” at minimum, should be eliminated to reduce 

recordkeeping burden.

Response: The EPA appreciates the detailed analysis provided by the commenter. In 

response to the comments, we agree that the suggested changes to §§60.5416(b) and 

60.5420(c)(8) are appropriate and add clarity to the rule. Thus, we have incorporated these 

changes in the final rule.

Concerning the use of “stationary” in the title of §60.5415, we do not believe this 

wording causes any confusion and have made no changes as a result of the comment.

We also disagree that the recordkeeping requirement of §60.5420(c)(3)(ii) are duplicative 

or unnecessary. The other records referred to by the commenter track the amount of time or 

operating hours since the last replacement. Such records would not necessarily indicate when the 

next replacement occurred. It is important to provide the regulatory authority clear records of 

when compliance events occurred so that the authority can verify compliance. We do not believe 

the records of §60.5420(c)(3)(i) are adequate to demonstrate compliance.