[Federal Register Volume 79, Number 137 (Thursday, July 17, 2014)]
[Proposed Rules]
[Pages 41751-41769]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2014-16576]



[[Page 41751]]

Vol. 79

Thursday,

No. 137

July 17, 2014

Part II





Environmental Protection Agency





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40 CFR Part 60





Oil and Natural Gas Sector: Reconsideration of Additional Provisions of 
New Source Performance Standards; Proposed Rule

Federal Register / Vol. 79 , No. 137 / Thursday, July 17, 2014 / 
Proposed Rules

[[Page 41752]]


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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.

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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 pre-register 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

[[Page 41753]]

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
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              Category                NAICS code \1\                Examples of regulated entities
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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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State/local/tribal government.......  ..............  Not affected.
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\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 cost-saving. 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 Sec.  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 Sec.  
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''

[[Page 41756]]

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 Sec.  60.5375(a)(4).
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    \1\ Letter from Matt Todd, American Petroleum Institute, to 
Bruce Moore, EPA Office of Air Quality Planning and Standards, July 
25, 2012.
    \2\ Letter from Peter Tsirigotis, EPA Office of Air Quality 
Planning and Standards, to Matt Todd, American Petroleum Institute, 
September 28, 2012.
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    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 Sec.  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 Sec.  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.
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    \3\ Recent 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.
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    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, 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, 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

[[Page 41757]]

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 Sec.  60.5365(e). If the criteria 
under Sec.  60.5365(e) were met, the operator would have to comply with 
the control requirements in Sec.  60.5395(d)(1) within 60 days after 
the beginning of the production stage. We are proposing to amend Sec.  
60.5365(e) to reflect that, for purposes of the well completion 
provisions, the 30-day period for the affected facility determination 
required Sec.  60.5365(e) would commence at the beginning of the 
production stage. We are proposing to amend Sec.  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 Sec.  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 Sec.  
60.5375, you must achieve the required emissions reductions within 
60 days after the beginning of the production stage as defined in 
Sec.  60.5430.

    In addition, we are proposing amendments to the reporting and 
recordkeeping requirements in Sec.  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 Sec.  60.5375.
    Similarly, we are proposing revisions to the terms used in the 
regulatory text for exploratory, delineation and low pressure wells at 
Sec.  60.5375(f) to be consistent with the proposed amended terminology 
and requirements in Sec.  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.
---------------------------------------------------------------------------

    \4\ In the 2012 NSPS, Sec.  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.
---------------------------------------------------------------------------

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 Sec.  
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 
Sec.  60.5375(a), except as provided in Sec.  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 Sec.  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 Sec.  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\
---------------------------------------------------------------------------

    \5\ Oil 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.
---------------------------------------------------------------------------

    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

[[Page 41758]]

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.
---------------------------------------------------------------------------

    \6\ Letter 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).
---------------------------------------------------------------------------

    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:
---------------------------------------------------------------------------

    \7\ Email from James D. Elliott, Spilman, Thomas & Battle PLLC, 
to Bruce Moore, EPA, March 24, 2014.

    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 Sec.  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 Sec.  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 Sec.  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 Sec.  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.
    Sec.  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 Sec.  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 Sec.  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 Sec.  60.5365(e) 
to allow the PTE exclusion provision only in cases where

[[Page 41759]]

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 Sec.  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 Sec.  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 
Sec.  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 Sec.  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 Sec.  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 Sec.  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 Sec.  
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 Sec.  60.5395(f)(1) and (2), and 
Sec.  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 
spark-ignited 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 Sec. Sec.  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

[[Page 41760]]

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.
---------------------------------------------------------------------------

    \8\ U.S. Environmental Protection Agency, Natural Gas STAR 
Program. Partner Reported Opportunities--Install Electronic Flare 
Ignition Devices, PRO Fact Sheet No. 903, 2011.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \9\ Letter from Veronica Nasser, REM Technologies, Inc., to Lisa 
P. Jackson, EPA Administrator, Petition for Reconsideration.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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 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

[[Page 41761]]

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 
Sec.  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 Sec.  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 Sec.  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 Sec.  60.5411(c) to a process.

    We are also proposing to amend the closed vent system requirements 
in Sec.  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 Sec.  60.5415 and 
inspection and monitoring requirements in Sec.  60.5416 to apply to 
reciprocating compressors.
---------------------------------------------------------------------------

    \11\ Sec.  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.
---------------------------------------------------------------------------

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 Sec.  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 
Sec.  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 
Sec.  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 Sec.  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

[[Page 41762]]

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 Sec.  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\
---------------------------------------------------------------------------

    \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 Sec.  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.
---------------------------------------------------------------------------

    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 Sec.  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

[[Page 41763]]

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 data-gathering 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-by-case 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 non-malfunctioning 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 case-by-
case enforcement discretion to provide flexibility, as appropriate.
---------------------------------------------------------------------------

    \13\ The 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.
---------------------------------------------------------------------------

    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 
cross-references. Details of the specific changes we are proposing to 
the regulatory text may be found in the docket for this action.\14\
---------------------------------------------------------------------------

    \14\ Memorandum 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
---------------------------------------------------------------------------

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.

[[Page 41764]]

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-for-profit 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.

[[Page 41765]]

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

0
1. The authority citation for part 60 continues to read as follows:

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

Subpart OOOO--[Amended]

0
2. Section 60.5365 is amended by revising paragraph (e) introductory 
text to read as follows:


Sec.  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 Sec.  60.5375, including wells subject to Sec.  
60.5375(f), you must determine the potential for VOC emissions within 
30 days after the beginning of the production stage as defined in Sec.  
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

[[Page 41766]]

facility status, provided you comply with the requirements in 
paragraphs (e)(1) through (4) of this section.
* * * * *
0
3. Section 60.5375 is amended by:
0
a. Revising paragraphs (a)(1) through (a)(3);
0
b. Revising paragraph (b);
0
c. Revising paragraphs (f)(1)(i), (ii) and (f)(2).
    The revisions read as follows:


Sec.  60.5375  What standards apply to gas well affected facilities?

* * * * *
    (a) * * *
    (1) For each stage of the well completion operation, as defined in 
Sec.  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 Sec.  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 
non-wildcat low pressure gas well or non-delineation 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.
* * * * *
0
4. Section 60.5385 is amended by:
0
a. Revising paragraph (a) introductory text; and
0
b. Adding paragraph (a)(3).
    The revision and addition read as follows:


Sec.  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 Sec.  60.5411(a) 
and (b).
* * * * *
0
5. Section 60.5390 is amended by revising paragraph (c)(2) to read as 
follows:


Sec.  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 Sec.  60.5420(c)(4)(iii).
* * * * *
0
6. Section 60.5395 is amended by:
0
a. Revising paragraph (d)(1)(i); and
0
b. Revising paragraph (f) introductory text.
    The revisions read as follows:


Sec.  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 Sec.  60.5375, you 
must achieve the required emissions reductions within 60 days after the 
beginning of the production stage as defined in Sec.  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

[[Page 41767]]

subpart applies to a storage vessel affected facility while that 
storage vessel affected facility is removed from service.
* * * * *
0
7. Section 60.5401 is amended by revising paragraphs (d) and (e) to 
read as follows:


Sec.  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 Sec. Sec.  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 Sec. Sec.  60.482-2a(a)(1), 
60.482-7a(a), and paragraph (b)(1) of this section.
* * * * *
0
8. Section 60.5410 is amended by revising paragraph (d)(2) to read as 
follows:


Sec.  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.
* * * * *
0
9. Section 60.5411 is amended by:
0
a. Revising the section heading;
0
b. Revising paragraph (a) introductory text;
0
c. Revising paragraph (a)(1);
0
d. Revising paragraph (b) introductory text;
0
e. Revising paragraph (b)(3); and
0
f. Revising paragraph (c) introductory text.
    The revisions read as follows:


Sec.  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 Sec.  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.
* * * * *
0
10. Section 60.5412 is amended by revising paragraph (d) introductory 
text to read as follows:


Sec.  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 Sec.  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 Sec.  
60.5413(d), which meets the criteria in Sec.  60.5413(d)(11) and Sec.  
60.5413(e).
* * * * *
0
11. Section 60.5413 is amended by:
0
a. Revising paragraph (e) introductory text; and
0
b. Adding paragraph (e)(7).
    The revisions and additions read as follows:


Sec.  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.
* * * * *
0
12. Section 60.5415 is amended by:
0
a. Revising paragraph (a)(2);
0
b. Revising paragraph (c) introductory text;
0
c. Adding paragraph (c)(4); and
0
d. Removing paragraph (h).
    The revisions and additions read as follows:


Sec.  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 
Sec.  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 Sec.  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 Sec.  60.5420(b), following the change.
* * * * *

[[Page 41768]]

    (c) For each reciprocating compressor affected facility complying 
with Sec.  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 
Sec.  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 Sec.  60.5411(a) and (b).
* * * * *
0
13. Section 60.5416 is amended by:
0
a. Revising the section heading;
0
b. Revising the introductory text;
0
c. Revising paragraph (a) introductory text; and
0
d. Revising paragraph (b) introductory text.
    The revisions read as follows:


Sec.  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.
* * * * *
0
14. Section 60.5420 is amended by:
0
a. Revising paragraphs (b)(6)(ii), (vi) and (vii); and
0
b. Revising paragraph (c)(3)(ii).
    The revisions read as follows:


Sec.  60.5420  What are my notification, reporting, and recordkeeping 
requirements?

* * * * *
    (b) * * *
    (6) * * *
    (ii) Documentation of the VOC emission rate determination according 
to Sec.  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 
Sec.  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 
Sec.  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 Sec.  60.5385(a)(3).
* * * * *
0
15. Section 60.5430 is amended by:
0
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;''
0
b. Removing the definition of ``Affirmative defense;'' and
0
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:


Sec.  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 Sec.  60.5375(f) for purposes of determining a storage vessel's 
potential to emit VOC under Sec.  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

[[Page 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 Sec.  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