[Federal Register Volume 79, Number 137 (Thursday, July 17, 2014)]
[Proposed Rules]
[Pages 41751-41769]
[FR Doc No: 2014-16576]

Vol. 79

Thursday,

No. 137

July 17, 2014

Part II

Environmental Protection Agency

-----------------------------------------------------------------------

40 CFR Part 60

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

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

-----------------------------------------------------------------------

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2010-0505, FRL-9913-40-OAR]
RIN 2060-AS01

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

AGENCY: Environmental Protection Agency.

ACTION: Proposed rule; Notice of Public Hearing.

-----------------------------------------------------------------------

SUMMARY: On August 16, 2012, the Environmental Protection Agency (EPA)
published final new source performance standards for the oil and
natural gas sector. The Administrator received petitions for
administrative reconsideration of certain aspects of the standards.
Among issues raised in the petitions were time-critical issues related
to certain storage vessel provisions and well completion provisions. On
September 23, 2013, the EPA published final amendments as a result of
reconsideration of issues related to implementation of the storage
vessel provisions. Following that action, the Administrator again
received petitions for administrative reconsideration pertaining to the
storage vessel provisions. In this notice, the EPA is announcing
proposed amendments and clarifications as a result of reconsideration
of certain issues related to well completions and additional issues
pertaining to storage vessels. The proposed amendments also address
other issues raised for reconsideration and make technical corrections
and amendments to further clarify the rule.

DATES: Comments. Comments must be received on or before August 18,
2014, unless a public hearing is requested by July 22, 2014. If a
hearing is requested on this proposed rule, written comments must be
received by September 2, 2014.
    Public Hearing. If anyone contacts the EPA requesting a public
hearing by July 22, 2014 we will hold a public hearing on August 1,
2014.
    If a public hearing is requested by July 22, 2014, it will be held
on August 1, 2014 at the EPA's Research Triangle Park Campus, 109 T.W.
Alexander Drive, Research Triangle Park, NC 27711. The hearing will
convene at 10:00 a.m. (Eastern Standard Time) and end at 5:00 p.m.
(Eastern Standard Time). A lunch break will be held from 12:00 p.m.
(Eastern Standard Time) until 1:00 p.m. (Eastern Standard Time). Please
contact Virginia Hunt at<PHONE_NUMBER>, or at<EMAIL_ADDRESS>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<EMAIL_ADDRESS>Include Docket ID No. EPA-
HQ-OAR-2010-0505 in the subject line of the message.
     Fax:<PHONE_NUMBER>, 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

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<PHONE_NUMBER>, 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:<PHONE_NUMBER>; facsimile
number:<PHONE_NUMBER>; email address<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Outline. The information presented in this
preamble is organized as follows:

I. Preamble Acronyms and Abbreviations
II. General Information
    A. Does this proposed rule apply to me?
    B. What should I consider as I prepare my comments to the EPA?
    C. How do I obtain a copy of this document and other related
information?
III. Background
IV. Today's Action
V. Executive Summary
VI. Discussion of Provisions Subject to Reconsideration
    A. Well Completions
    B. Storage Vessels
    C. Routing of Reciprocating Compressor Rod Packing Emissions to
a Process
    D. Equipment Leaks at Gas Processing Plants
    E. Definition of ``Responsible Official''
    F. Affirmative Defense
VII. Technical Corrections and Clarifications
VIII. Impacts of This Proposed Rule
    A. What are the air impacts?
    B. What are the energy impacts?
    C. What are the compliance costs?
    D. What are the economic and employment impacts?
    E. What are the benefits of the proposed standards?
IX. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations

I. Preamble Acronyms and Abbreviations

    Several acronyms and terms are included in this preamble. While
this may not be an exhaustive list, to ease the reading of this
preamble and for reference purposes, the following terms and acronyms
are defined here:

API American Petroleum Institute
BSER Best System of Emissions Reduction
CAA Clean Air Act
CFR Code of Federal Regulations
EPA Environmental Protection Agency
Mcf Thousand Cubic Feet
NESHAP National Emissions Standards for Hazardous Air Pollutants
NSPS New Source Performance Standards
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality Planning and Standards
OMB Office of Management and Budget
OVA Olfactory, Visual and Auditory
PTE Potential to Emit
RFA Regulatory Flexibility Act
tpy Tons per Year
TTN Technology Transfer Network
UMRA Unfunded Mandates Reform Act
VCS Voluntary Consensus Standards
VOC Volatile Organic Compounds
VRU Vapor Recovery Unit

II. General Information

A. Does this proposed rule apply to me?

    Categories and entities potentially affected by today's proposed
rule include:

                          TABLE 1--Industrial Source Categories Affected by This Action
----------------------------------------------------------------------------------------------------------------
              Category                NAICS code \1\                Examples of regulated entities
----------------------------------------------------------------------------------------------------------------
Industry............................          211111  Crude Petroleum and Natural Gas Extraction.
                                              211112  Natural Gas Liquid Extraction.
                                              221210  Natural Gas Distribution.
                                              486110  Pipeline Distribution of Crude Oil.
                                              486210  Pipeline Transportation of Natural Gas.
Federal government..................  ..............  Not affected.

State/local/tribal government.......  ..............  Not affected.
----------------------------------------------------------------------------------------------------------------
\1\ North American Industry Classification System.

    This table is not intended to be exhaustive, but rather is meant to
provide a guide for readers regarding entities likely to be affected by
this action. If you have any questions regarding the applicability of
this action to a particular entity, consult either the air permitting
authority for the entity or your EPA regional representative as listed
in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions).

B. What should I consider as I prepare my comments to the EPA?

    We seek comment only on the aspects of the final new source
performance standards for the oil and natural gas sector specifically
identified in this notice. We are not opening for reconsideration any
other provisions of the new source performance standards (NSPS) at this
time.
    Do not submit information containing CBI to the EPA through http://www.regulations.gov or email. Send or deliver information identified as
CBI only to the following address: Roberto Morales, OAQPS Document
Control Officer (C404-02), Office of Air Quality Planning and
Standards, U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina 27711, Attention: Docket ID Number EPA-HQ-OAR-
2010-0505. Clearly mark the part or all of the information that you
claim to be CBI. For CBI information in a disk or CD-ROM that you mail
to the EPA, mark the outside of the disk or CD-ROM as CBI and then
identify electronically within the disk or CD-ROM the specific
information that is claimed as CBI. In addition to one complete version
of the comment that includes information claimed as CBI, a copy of the
comment that does not contain the information claimed as CBI must be
submitted for inclusion in the public docket. Information so marked
will not be disclosed except in accordance with procedures set forth in
40 CFR part 2.

C. How do I obtain a copy of this document and other related
information?

    In addition to being available in the docket, electronic copies of
these proposed rules will be available on the World Wide Web through
the TTN. Following signature, a copy of this proposed rule will be
posted on the TTN's policy and guidance page for newly proposed or
promulgated rules at the following address: http://www.epa.gov/airquality/oilandgas/actions.html.

III. Background

    On August 16, 2012, the EPA published the Oil and Natural Gas
Sector NSPS (40 CFR part 60 subpart OOOO) in the Federal Register at 77
FR 49490. Following promulgation of the final rule, the Administrator
received petitions for administrative reconsideration of several
provisions of the NSPS pursuant to Clean Air Act (CAA) section
307(d)(7)(B). Copies of the petitions are provided in rulemaking docket
EPA-HQ-OAR-2010-0505. On September 23, 2013, the EPA published final
amendments primarily related to implementation of the storage vessel
provisions. In the petitions for reconsideration of the 2012 final
rule, petitioners raised several issues regarding clarification of the
well completion provisions, some of which have a compliance deadline of
January 1, 2015. In addition, the Administrator received petitions for
reconsideration of several provisions of the 2013 storage vessel
implementation amendments.

IV. Today's Action

    Today, we are granting reconsideration of, proposing and requesting
comment on the following limited set of issues raised in the petitions
described above: (1) Provisions for well completions that clarify
existing requirements for handling of flowback gases and liquids; (2)
definition of ``low pressure gas well'' ; (3) requirements pertaining
to determining the potential emission of storage vessels that employ
vapor recovery; (4) requirements for thief hatches; (5) provisions for
storage vessels that are removed from service; (6) routing of emissions
from reciprocating compressor rod packing to a process; (7) leak
detection requirements at small natural gas processing plants and
natural gas processing plants located on the Alaskan North Slope; (8)
equipment subject to leak detection requirements under the NSPS; and
(9) definition of ``responsible official'' for compliance certification
purposes. In addition, we are proposing to remove the affirmative
defense provisions from the startup, shutdown and malfunction
provisions of the 2012 NSPS. Finally, we are proposing to correct
technical errors in the 2012 NSPS.
    This notice is limited to the specific issues identified in this
notice. We will not respond to any comments addressing any other
provisions of the Oil and Natural Gas Sector NSPS. We will address any
other issues for which we intend to grant reconsideration at a later
time.
    The impacts of today's proposed revisions on the costs and the
benefits of the final rule are minor, but 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

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''

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).
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

    \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.
---------------------------------------------------------------------------

    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

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

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

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

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

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

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

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.

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.

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

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

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.
* * * * *

    (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