[Federal Register Volume 79, Number 250 (Wednesday, December 31, 2014)]
[Rules and Regulations]
[Pages 79017-79041]
[FR Doc No: 2014-30630]

Vol. 79

Wednesday,

No. 250

December 31, 2014

Part III

 Environmental Protection Agency

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40 CFR Part 60

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

Federal Register / Vol. 79 , No. 250 / Wednesday, December 31, 2014 /
Rules and Regulations

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2010-0505; FRL-9921-03-OAR]
RIN 2060-AR75

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

AGENCY: Environmental Protection Agency.

ACTION: Final rule.

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SUMMARY: This action finalizes amendments to new source performance
standards (NSPS) for the oil and natural gas sector. On August 16,
2012, the Environmental Protection Agency (EPA) published final NSPS
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 July 17, 2014 (79 FR 41752), the EPA published proposed
amendments and clarifications as a result of reconsideration of certain
issues related to well completions, storage vessels and other issues
raised for reconsideration as well as technical corrections and
amendments to further clarify the rule. This action finalizes these
amendments and corrects technical errors that were inadvertently
included in the final standards.

DATES: This final rule is effective on December 31, 2014.

ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2010-0505. 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., confidential
business information (CBI) or other information whose disclosure is
restricted by statute. Certain other material, such as copyrighted
material, is not placed on the internet and 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<PHONE_NUMBER>.

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: Organization of This Document. The
information presented in this preamble is organized as follows:

I. Preamble Acronyms and Abbreviations
II. General Information
    A. Executive Summary
    B. Does this reconsideration action apply to me?
    C. How do I obtain a copy of this document and other related
information?
    D. Judicial Review
III. Summary of Final Amendments
    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
IV. Summary of Significant Changes since Proposal
    A. Well Completions
    B. Storage Vessels
    C. Definition of ``Responsible Official''
V. Summary of Significant Comments and Responses
    A. Well Completions
    B. Storage Vessels
    C. Routing of Reciprocating Compressor Rod Packing Emissions to
a Process
VI. Technical Corrections and Clarifications
VII. Impacts of These Final Amendments
    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 final standards?
VIII. 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 (PRA)
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act of 1995 (UMRA)
    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 (NTTAA)
    J. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations
    K. Congressional Review Act (CRA)

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:

CAA Clean Air Act
CFR Code of Federal Regulations
CO2 Carbon Dioxide
EPA Environmental Protection Agency
LEL Lower Explosive Limit
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
PTE Potential to Emit
psi Pounds per Square Inch
REC Reduced Emissions Completion
RFA Regulatory Flexibility Act
tpy Tons per Year
UMRA Unfunded Mandates Reform Act
VOC Volatile Organic Compounds
VRU Vapor Recovery Unit

II. General Information

A. Executive Summary

1. Purpose of This Regulatory Action
    The purpose of this action is to finalize amendments to the 40 CFR
part 60, subpart OOOO, Standards of Performance for Crude Oil and
Natural Gas Production, Transmission and Distribution final rule
promulgated under section 111(b) of the Clean Air Act (CAA), which was
published on August 16, 2012 (77 FR 49490). Specifically, this final
rule addresses certain issues 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 amending the NSPS to address these issues. Proposed amendments were
published on July 17, 2014. (79 FR 41752)
2. Summary of Major Amendments to the NSPS
    We are amending the standards for gas well affected facilities to
provide greater clarity concerning what owners and operators must do
during well completion operations with respect to the handling of gas
and liquids during the well completion operations. In this action, we
clarify that the flowback

period of a well completion following hydraulic fracturing consists of
two distinct stages, the ``initial flowback stage'' and the
``separation flowback stage.'' The initial flowback stage begins with
the onset of flowback and ends when the flow is routed to a separator.
During the initial flowback stage, any gas in the flowback is not
subject to control. However, the operator must route the flowback to a
separator unless it is technically infeasible for a separator to
function. The point at which the separator can function marks the
beginning of the separation flowback stage. During this stage, the
operator must route all salable quality gas from the separator to a
flow line or collection system, re-inject the gas into the well or
another well, use the gas as an on-site fuel source or use the gas for
another useful purpose. If it is infeasible to route the gas as
described above, or if the gas is not of salable quality, the operator
must combust the gas unless combustion creates a fire or safety hazard
or can damage tundra, permafrost or waterways. No direct venting of gas
is allowed during the separation flowback stage. The separation
flowback stage ends either when the well is shut in and the flowback
equipment is permanently disconnected from the well, or on startup of
production. This also marks the end of the flowback period. The
operator has a general duty to safely maximize resource recovery and
minimize releases to the atmosphere over the duration of the flowback
period. The operator is also required to document the stages of the
completion operation by maintaining records of (1) the date and time of
the onset of flowback; (2) the date and time of each attempt to route
flowback to the separator; (3) the date and time of each occurrence in
which the operator reverted to the initial flowback stage; (4) the date
and time of well shut in; and (5) date and time that temporary flowback
equipment is disconnected. The NSPS already requires that the operator
document the total duration of venting, combustion and flaring over the
flowback period. All flowback liquids during the initial flowback
period and the separation flowback period must be routed to a well
completion vessel, a storage vessel or a collection system. On startup
of production, the operator must begin the 30-day process of estimating
the volatile organic compound (VOC) potential to emit (PTE) for storage
vessels that will receive the liquids from the well. If the PTE is at
least 6 tons/yr (tpy), the operator must control emissions from the
storage vessel no later than 60 days after the startup of production
(for storage vessels used in applications other than production
following well completions, the term used to identify this point in
time is ``startup''). A well completion vessel to which liquids from
the well are routed after startup of production for a period in excess
of 60 days is considered a ``storage vessel'' subject to the storage
vessel PTE determination and, if determined to be a storage vessel
affected facility, would be subject to the control, cover and closed
vent system requirements of the NSPS.
    We are finalizing the definition of ``low pressure gas well,'' as
presented in the 2012 NSPS and re-proposed in the July 17, 2014,
proposed rule.
    We are finalizing several amendments related to the storage vessel
provisions of the NSPS. First, we are finalizing provisions for
determining VOC 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
tpy applicability threshold under a legally and practically enforceable
permit or other limitation under federal, state or tribal authority. We
are also amending the storage vessel closed vent system and cover
requirements to allow use of other mechanisms besides weighted lid
thief hatches to ensure that the thief hatch lid remains properly
seated. In addition, we are amending the requirements for storage
vessels to clarify notification and other requirements under the NSPS
for storage vessels affected facilities that are removed from service
for reasons other than maintenance. Further, we are clarifying that
Group 1 and Group 2 storage vessel affected facilities that are removed
from service are no longer affected facilities and therefore have no
requirements under the NSPS until they are returned to service. The
status of a Group 1 or Group 2 storage vessel that is later returned to
service depends on its new use, which can fall into three possible
scenarios. If the storage vessel is used to replace a storage vessel
affected facility, or is being connected in parallel with a storage
vessel affected facility, it is immediately subject to the same
requirements as the affected facility being replaced or with which it
is being connected in parallel. If the vessel is not used to replace or
connected in parallel with an affected facility but is being used to
contain crude oil, condensate, intermediate hydrocarbon liquids or
produced water, it is allowed 30 days to determine if its VOC PTE is at
least 6 tpy, and if so is subject to the requirements for Group 2
storage vessel affected facilities and would be required to control
emissions no later than 60 days after return to service. If the vessel
is being used in an application other than to contain crude oil,
condensate, intermediate hydrocarbon liquids or produced water, it does
not meet the definition of ``storage vessel'' and is not an affected
facility under the NSPS.
    We are amending 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 finalizing a
third alternative that would allow routing emissions from the rod
packing through a collection system under negative pressure via a
closed vent system to a process.
    We are finalizing 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 addition, we
are amending 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 amending the provisions related to ``responsible official''
to remove any confusion by the regulated community with respect to the
requirements for certifying under subpart OOOO and references to
``responsible official'' under the title V permitting program. To that
end, we are changing the term ``responsible official'' to ``certifying
official.'' We are also finalizing the proposed amendments to provide
for delegation of authority after advance notification for facilities
that employ 250 or fewer employees and have less than $25 million gross
annual sales or expenditures (in second quarter 1980 dollars).
    Finally, the EPA is removing a regulatory affirmative defense
provision from the rule. 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.
3. Cost and Benefits
    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 these amended

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
final rule that they would have for the original final rule, there
should not be any incremental costs related to this final revision.

B. Does this reconsideration action apply to me?

    Categories and entities potentially affected by today's action
include:

      Table 1--Industrial Source Categories Affected by This Action
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                                                  Examples of regulated
            Category             NAICS code \1\          entities
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Industry.......................          211111  Crude Petroleum and
                                                  Natural Gas
                                                  Extraction.
                                         211112  Natural Gas Liquid
                                                  Extraction.
                                         221210  Natural Gas
                                                  Distribution.
                                         486110  Pipeline Distribution
                                                  of Crude Oil.
                                         486210  Pipeline Transportation
                                                  of Natural Gas.
Federal government.............  ..............  Not affected.
State/local/tribal government..  ..............  Not affected.
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\1\ North American Industry Classification System.

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

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
the final and proposed rules will be available on the WorldWide Web.
Following signature, a copy of the rule will be posted at the following
address: http://www.epa.gov/airquality/oilandgas/actions.html.

D. Judicial Review

    Under section 307(b)(1) of the CAA, judicial review of this final
rule is available only by filing a petition for review in the United
States Court of Appeals for the District of Columbia Circuit by March
2, 2015. Under section 307(d)(7)(B) of the CAA, only an objection to
this final rule that was raised with reasonable specificity during the
period for public comment can be raised during judicial review.
Moreover, under section 307(b)(2) of the CAA, the requirements
established by this final rule may not be challenged separately in any
civil or criminal proceedings brought by the EPA to enforce these
requirements. Section 307(d)(7)(B) of the CAA further provides that
``[o]nly an objection to a rule or procedure which was raised with
reasonable specificity during the period for public comment (including
any public hearing) may be raised during judicial review.'' This
section also provides a mechanism for us to convene a proceeding for
reconsideration, ``[i]f the person raising an objection can demonstrate
to the EPA that it was impracticable to raise such objection within
[the period for public comment] or if the grounds for such objection
arose after the period for public comment (but within the time
specified for judicial review) and if such objection is of central
relevance to the outcome of the rule.'' Any person seeking to make such
a demonstration to us should submit a Petition for Reconsideration to
the Office of the Administrator, U.S. EPA, Room 3000, William Jefferson
Clinton West Building, 1200 Pennsylvania Ave. NW., Washington, DC
20460, with a copy to both the person(s) listed in the preceding FOR
FURTHER INFORMATION CONTACT section, and the Associate General Counsel
for the Air and Radiation Law Office, Office of General Counsel (Mail
Code 2344A), U.S. EPA, 1200 Pennsylvania Ave. NW., Washington, DC
20460.

III. Summary of Final Amendments

    This section presents a summary of the provisions of the final
action with brief explanations where appropriate. In some cases
additional, detailed discussions are provided in sections IV or V. The
final amendments include revisions to certain reconsidered aspects of
the existing 2012 NSPS as follows: (1) Provisions for well completions
that clarify and amend existing requirements for handling of flowback
gases and liquids; (2) definition of ``low pressure gas well''; (3)
requirements pertaining to determining the potential emissions from
storage vessels; (4) requirements for thief hatches; (5) provisions for
storage vessels that are removed from service and for those that are
returned to service; (6) provisions for 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) clarification
of equipment subject to leak detection requirements under the NSPS; and
(9) revised definition of ``responsible official'' and revision of the
term to be ``certifying official'' for compliance certification
purposes. In addition, we are removing the affirmative defense
provisions from the startup, shutdown and malfunction provisions of the
2012 NSPS and are correcting technical errors in the 2012 NSPS. A
summary of the final amendments resulting from our reconsideration is
provided in the following paragraphs.

A. Well Completions

1. Handling of Flowback Gases and Liquids
    In today's action we are finalizing requirements in Sec.  60.5375
for handling of gases and liquids during flowback.
    The regulatory language in the well completion provisions of Sec.
60.5375 is amended to identify two distinct stages associated with well
completion, with each stage having specific requirements for handling
of gases and liquids. The final provisions are changed slightly from
the proposed amendments in response to public comments. Discussion of
our rationale for these changes since proposal are presented in section
IV.A.
    The flowback period consists of two stages, the ``initial flowback
stage'' and the ``separation flowback stage.'' The initial flowback
stage begins with the

first flowback from the well following hydraulic fracturing or
refracturing and is characterized by high volumetric flow water,
containing sand, fracturing fluids and debris from the formation with
very little gas being brought to the surface, usually in multiphase
slug flow. During this stage, the flowback must be routed to a
``storage vessel'' or to a ``well completion vessel'' that can be a
frac tank, a lined pit or any other vessel. Our reason for this
requirement is to avoid having operators route the flowback to an
unlined pit or onto the ground. During the initial flowback stage,
there is no requirement for controlling emissions from the vessel, and
any gas in the flowback during this stage may be vented. However, the
operator must route the flowback to a separator unless it is
technically infeasible for a separator to function. As a result, we
have changed ``as soon as sufficient gas is present in the flowback for
a separator to operate'' to ``unless it is technically infeasible for a
separator to function.'' We stress that operators have the
responsibility to direct the flowback to a separator as soon as
conditions allow a separator to function and in accordance with the
General Provision requirements to operate the affected facility in a
manner consistent with good air pollution control practices for
minimizing emissions.
    The second stage is defined as the ``separation flowback stage.''
The point at which the separator can function marks the beginning of
the separation flowback stage. This stage is characterized by the
separator operating with a gaseous phase and one or more liquid phases
in the separator. During this stage, the operator must route all
salable quality gas from the separator to a gas flow line or collection
system, re-inject the gas into the well or another well, use the gas as
an on-site fuel source or use the gas for another useful purpose that a
purchased fuel or raw material would serve. If, during the separation
flowback stage, it is infeasible to route the recovered gas to a flow
line or collection system, reinject the gas or use the gas as fuel or
for other useful purpose, the recovered gas must be combusted. No
direct venting of recovered gas is allowed during the separation
flowback stage except when combustion creates a fire or safety hazard
or can damage tundra, permafrost or waterways. With regard to
infeasibility of collecting the salable quality gas, we believe that
owners and operators plan their operations to extract a target product
and evaluate whether the appropriate infrastructure access is available
to ensure their product has a viable path to market before completing a
well. However, there may be isolated cases in which, for reason(s) not
within an operator's control, the well is completed and flowback occurs
without a suitable flow line available. In those isolated instances,
the NSPS provides a solution in Sec.  60.5375(a)(3), which requires
combustion of the gas unless combustion poses an unsafe condition as
described above. During the separation flowback stage, all liquids from
the separator must be directed to a storage vessel or to a well
completion vessel, routed to a collection system or be re-injected into
the well or another well.
    The end of the separation flowback stage marks the end of the
flowback period and is defined as the point at which the well is shut
in and the flowback equipment is permanently disconnected from the
well, or the startup of production. Identification of this point is
discussed in detail in section IV.A. As provided in the 2012 NSPS, the
operator has a general duty to safely maximize resource recovery and
minimize releases to the atmosphere over the duration of the flowback
period.
    At some point following the end of the flowback period, depending
on how long the well is shut in (if shut in), startup of production
will occur. Depending on the situation, the operator may choose to
startup production immediately following the end of flowback, once the
well is temporarily shut in to remove flowback equipment, may begin
production without shutting in and removing flowback equipment, or the
operator might delay startup for some period of time by leaving the
well shut in until permanent production equipment has been installed.
Startup of production, whenever that occurs, marks the beginning of the
30-day period for determining VOC PTE for purposes of making a storage
vessel affected facility determination in accordance with the procedure
in Sec.  60.5365(e). If the criteria in Sec.  60.5365(e) are met, the
operator would have to comply with the control requirements in Sec.
60.5395(d)(1) within 60 days after the startup of production. During
this period, any recovered liquids must be routed to well completion
vessels, storage vessels or a collection system. A well completion
vessel to which liquids are routed from the well for a period in excess
of 60 days after startup of production would be considered a ``storage
vessel'' under the NSPS and, depending on its VOC PTE, would be subject
to the control, cover and closed vent system requirements for storage
vessel affected facilities. We are finalizing amendments to Sec.
60.5365(e) to reflect that, for storage vessels associated with
production following completions, the 30-day period for the affected
facility determination required Sec.  60.5365(e) commences on startup
of production. We are also amending the requirements for storage vessel
affected facilities in Sec.  60.5395(d)(1)(i) to reflect that, for
purposes of the well completion provisions, control is required no
later than 60 days from startup of production.
    To accompany these changes, we are also amending the reporting and
recordkeeping requirements in Sec.  60.5420 to revise the terminology
used in that section relating to periods of gas recovery, combustion
and venting to be compatible with the terms used in the final
clarifying amendments to Sec.  60.5375, including addition of a
requirement to document the time of the beginning of flowback, the time
at which the operator directs the flowback to a separator (each time
this is done), the reason for reverting back to the initial flowback
stage (if this is done), the time of well shut in and removal of
flowback equipment (end of the flowback period) and time of startup of
production (beginning of the PTE determination period). We are also
revising the language used in requirements for exploratory, delineation
and low pressure wells in Sec.  60.5375(f) to be consistent with the
final amended terminology and requirements in Sec.  60.5375(a).
2. Definition of ``Low Pressure Gas Well''
    We are finalizing the re-proposed 2012 EPA definition of ``low
pressure gas well'' without change. This definition is used in
conjunction with Sec.  60.5375(f), which provides that those wells for
which a reduced emissions completion (REC) would not be feasible
because of a combination of well depth, reservoir pressure and flow
line pressure is not required to meet the requirements for recovery of
gases and liquids required under Sec.  60.5375(a). Instead of having to
perform an REC and recover gas during the separation flowback stage,
operators performing completions of low pressure gas wells (in addition
to wildcat wells and delineation wells) are required only to combust
the gas rather than capture it during flowback. The 2012 NSPS included
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 of ``low pressure gas well'' is found in Sec.  60.5430.
    Following publication of the final rule, several petitioners for
administrative reconsideration (hereinafter ``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. In the July 17, 2014, proposed
rule, we re-proposed the 2012 definition and solicited comment on an
alternative definition provided by these petitioners.\1\ For the
reasons discussed in detail in section V.A, we are retaining the 2012
definition without change.
---------------------------------------------------------------------------

    \1\ Email from James D. Elliott, Spilman, Thomas & Battle PLLC,
to Bruce Moore, EPA, March 24, 2014.
---------------------------------------------------------------------------

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 filed additional
administrative reconsideration petitions, in which they raised issues
with regard to various provisions of the 2013 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
    We are finalizing amendments to Sec.  60.5365(e) to allow the PTE
exclusion provision only in cases where a storage vessel is not subject
to any legally and practically enforceable limitation or other
requirement under a federal, state, local or tribal authority. An owner
or operator invoking this exclusion provision must comply with the
provisions of Sec.  60.5365(e)(1) through (4) in determining VOC PTE
for purposes of determining affected facility status.
2. Thief Hatch Properly Seated
    We are finalizing amendments to Sec.  60.5411(b)(3) to require that
thief hatches be equipped, maintained and operated with a weighted
mechanism or equivalent, to ensure that the lid remains properly
seated. This amendment provides for proper seating of thief hatch lids
while allowing innovation and flexibility in design not afforded by
requiring that thief hatch lids be weighted.
3. Storage Vessels Removed From Service
    As proposed, we are amending 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.
    For the reasons discussed in detail in section IV.B, we are also
amending the NSPS to clarify that a Group 1 and Group 2 storage vessel
affected facility that is removed from service, which is defined in
Sec.  60.5430 as physically isolated and disconnected from the process
for a purpose other than maintenance and, pursuant to Sec.
60.5395(f)(1), completely emptied and degassed and no longer used to
contain crude oil, condensate, produced water or intermediate
hydrocarbon liquids, would no longer meet the definition of ``storage
vessel'' in Sec.  60.5430 and, therefore, cease to be affected
facilities under the NSPS for the period they are out of service.
    We are also amending the NSPS to provide that a Group 1 or Group 2
storage vessel affected facility that is returned to service is subject
to the NSPS based on the use of the vessel in its new application.
There are three possible scenarios for vessels returned to service: (1)
The vessel is used to replace a storage vessel affected facility or is
connected in parallel with a storage vessel affected facility; (2) the
vessel is not used to replace an affected facility but is being used to
contain crude oil, condensate, intermediate hydrocarbon liquids or
produced water; or (3) the vessel is being used in an application other
than to contain crude oil, condensate, intermediate hydrocarbon liquids
or produced water. If the vessel is being used to replace a storage
vessel affected facility or is connected in parallel with a storage
vessel affected facility (i.e., the liquid contents and the VOC PTE are
already known), then it is a storage vessel affected facility and
immediately upon startup would be subject to the same requirements as
the storage vessel affected facility being replaced. If the vessel is
not being used to replace an affected facility but is being used to
contain crude oil, condensate, intermediate hydrocarbon liquids or
produced water (i.e., the VOC PTE is unknown), then, just as for any
new storage vessel, the operator would be afforded a 30-day period
after startup to determine the storage vessel's affected facility
status based on VOC PTE and, if VOC PTE were estimated to be at least 6
tpy, the storage vessel would be determined an affected facility and
would be subject to requirements for Group 2 storage vessels, and
controlled no later than 60 days after startup. If the vessel is not
being used to contain crude oil, condensate, intermediate hydrocarbon
liquids or produced water, it does not meet the definition of ``storage
vessel'' and would not be subject to the requirements of the NSPS.
    We are amending the definition of ``removed from service'' and
adding a definition of ``returned to service'' to clarify these
provisions. See section IV.B for a detailed discussion.

C. Routing of Reciprocating Compressor Rod Packing Emissions to a
Process

    The 2012 final NSPS includes operational or ``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 that asserted that an alternative technology
exists that would reduce emissions commensurate with or better than the
reductions from the operational standard. This 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, or other process
that would burn the gas as fuel to augment the normal fuel supply.
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 and, therefore, it would be
within the operator's discretion to choose whichever option is most
appropriate for the application and situation at hand.
    Therefore, for the above reasons and as discussed in the proposed
rule, we are revising Sec.  60.5385(a) to include a third option for
routing the rod packing emissions to a process through a closed

vent system that meets the requirements of Sec.  60.5411(c).
    Also as proposed, we are amending 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). Similarly, we are
amending the continuous compliance requirements in Sec.  60.5415 and
inspection and monitoring requirements in Sec.  60.5416 to apply to
reciprocating compressors.
    The EPA received comments in support of the addition of the third
alternative in Sec.  60.5385(a). However, commenters identified several
inconsistencies that should be addressed with respect to other
provisions as they relate to the revised Sec.  60.5385(a). The EPA
agrees with the commenters' rationale and is amending Sec. Sec.
60.5410(c)(1), 60.5415(c)(4), 60.5416(a), and 60.5420(c)(6) through (9)
to be consistent with the intent of the third alternative provision in
Sec.  60.5385(a)(3). Specifically, we are revising the initial
compliance demonstration provisions in Sec.  60.5410(c)(1) by adding
language such that paragraphs (c)(1) through (4) would not apply to
sources electing to comply with Sec.  60.6385(a)(3). The EPA agrees
with commenters that these provisions would not apply to sources that
are operating a closed vent systems and complying with Sec.
60.5385(a)(3). We are revising the continuous compliance demonstration
provisions in Sec.  60.5415(c)(4) to reflect that the source must
comply with 60.5416(a) and (b) rather than Sec.  60.5411(a) and (b).
The EPA agrees that the provisions of Sec.  60.5416(a) and (b) are more
appropriate for a reciprocating compressor operating with a closed vent
and cover system. We are amending Sec.  60.5420(c)(6) through (9) to
add reciprocating compressors as sources subject to these recordkeeping
requirements.

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 of field gas per day) and at natural gas processing plants
located on the Alaskan North Slope. With the exception of the revision
to lower the leak definition for valves, we retained the other
provisions of subpart KKK by adopting the subpart KKK regulatory text,
including the above mentioned exemptions, in subpart OOOO. With this
complete adoption of subpart KKK regulatory text on the exemptions, we
inadvertently failed to update the equipment list to include
connectors, as pointed out by petitioners. 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
these requirements. As a result, as proposed, we are amending 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 natural gas processing plants, which was the scope of
subpart KKK. Except for lowering the leak definition for valves and
requiring monitoring of connectors, subpart OOOO retains the other
provisions of the subpart KKK by adopting those provisions, including
the definition of ``equipment.'' 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 amending the definition of ``equipment'' in
Sec.  60.5430 to read as set forth in the regulatory text of this rule.

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.
    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. Therefore, consistent with the proposed changes, we are also
amending the definition 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).
    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 the process of this evaluation, we also determined that the use
of ``permitting authority'' and the ``responsible official'' are
similar to terms used in the requirements of the Title V permitting
program. In order to remove potential confusion by the regulated
community and to clarify that this is a requirement of the NSPS and is
not associated with a permitting program, we are changing the term
``responsible official'' to ``certifying official'' and replacing the
term

``permitting authority'' used in the definition with ``Administrator.''

F. Affirmative Defense

    The EPA is removing a regulatory affirmative defense provision from
the rule, as proposed. For the reasons stated in the preamble to the
proposed amendments and below, we are finalizing the removal of the
affirmative defense provisions. In the 2012 rulemaking, the EPA had
included an affirmative defense to civil penalties for violations
caused by malfunctions in 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
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
EPA's regulatory 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 an affirmative
defense in one of the EPA's section 112 regulations. NRDC v. EPA, 749
F.3d 1055 (D.C. Cir., 2014) (vacating affirmative defense provisions in
section 112 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 in such cases
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, at 1063 (``[U]nder this statute, deciding
whether penalties are `appropriate' in a given private civil suit is a
job for the courts, not EPA.'').\2\ In light of NRDC, the EPA had
proposed and is finalizing in this action the removal of the regulatory
affirmative defense provisions in subpart OOOO. 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. 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, at 1064 (arguments that violation
were caused by unavoidable technology failure can be made to the courts
in future civil cases when the issue arises). The same is true for the
presiding officer in EPA administrative enforcement actions.\3\
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    \2\ 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.
    \3\ Although the NRDC case does not address the EPA's authority
to establish an affirmative defense to penalties that is available
in administrative enforcement actions, EPA had not included such an
affirmative defense in the 2012 NSPS. As explained above, such an
affirmative defense is not necessary. Moreover, assessment of
penalties for violations caused by malfunctions in administrative
proceedings and judicial proceedings should be consistent. Cf. CAA
section 113(e) (requiring both the Administrator and the court to
take specified criteria into account when assessing penalties).
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IV. Summary of Significant Changes Since Proposal

    Section III summarized the amendments to the 2012 NSPS that the EPA
is finalizing in this rule. This section discusses the key changes the
EPA has made since proposal. These changes are the result of the EPA's
consideration of the many substantive and thoughtful comments submitted
on the proposal and other information received since proposal. We
believe that the changes we have made sufficiently address concerns
expressed by commenters and improve the clarity of the rule while
improving or preserving public health and environmental protection
required under the CAA.

A. Well Completions

1. Handling of Flowback Gases and Liquids
    In today's action we are finalizing clarifications and amendments
to provisions for handling of gases and liquids during flowback at
Sec.  60.5375. Following publication of the 2012 final NSPS, we
received feedback from petitioners that the well completion provisions
were unclear and that operators were not sure of the requirements for
handling of gas and liquids during well completion operations.
Petitioners also asserted that, as written, compliance with the 2012
NSPS was impossible, since the rule appeared to prohibit venting of gas
at any time during the well completion. In our July 17, 2014, proposal,
we clarified it was not the EPA's intent to prohibit venting of
flowback gases throughout the entire flowback period and 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 after separation. We confirmed that
the initial flowback (prior to recovery of gas from the liquids through
separation) may be routed to storage vessels, temporary fracture tanks
(frac tanks) or to lined pits, as long as separation and recovery of
the gas 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).
    To clarify EPA's intent with regard to handling of gas and liquid
portions of flowback, we had proposed three distinct stages of the
completion operation, with each stage having specific requirements for
handling of gases and liquids.
    As proposed, the first stage would begin with the first flowback
from the well following hydraulic fracturing or refracturing, and would
be 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. Under the
proposed amendments, the first stage was defined as the ``initial
flowback stage.'' We had proposed that during this stage the flowback
would be required to be routed to a ``well completion vessel'' that
could be a frac tank, a lined pit or any other vessel. Our intention
was that the flowback could not be directed to an unlined pit or onto
the ground. During the initial flowback stage, there would be no
requirement for controlling emissions from the tank or other vessel,
and any gas in the flowback during this stage could be vented. We
proposed that, as soon as sufficient gas is present in the flowback for
a separator to operate, the flow would be required to be diverted to
the separator. We explained that ``for a separator to function enough
gas must be flowing [in the flowback] to maintain a gaseous phase and
one or more liquid phases in the separator.'' (79 FR 41755). In the
proposal preamble, we had

discussed how some operators monitor the gas concentration at the
vessel receiving the flowback both for safety reasons and to determine
that sufficient gas is present in the flowback for the separator to
function. We understood that when the gas concentration approaches the
lower explosive limit (LEL) (i.e., approaches flammability), these
operators direct the flowback to a separator. We were uncertain whether
this method could be used effectively in all applications and whether
there were other techniques used by operators to make this
determination. We solicited comment on the suitability of the ``LEL
method'' when used for this purpose and asked for information on other
techniques or indicators that could be used to determine when
sufficient gas is present for a separator to function.
    Commenters responded that the EPA apparently had misunderstood
earlier discussions regarding use of the LEL detector. They asserted
that the detector is used for safety reasons and that although the LEL
detector indicates that there may be potential flammability, it does
not necessarily indicate that sufficient gas is present for the
separator to function. Commenters also asserted that monitoring the gas
concentration does not reflect other conditions such as sand and water
content and well characteristics that have a bearing on the point where
the separator will operate. We also learned that some operators begin
to direct the flowback to the separator immediately upon initial
flowback, even though it may not maintain a gaseous phase and one or
more liquid phases in the separator. Other operators may not have an
initial flowback stage and may go directly to the separation flowback
stage.
    Because whether a separator can operate may depend on site specific
factors other than the amount of gas present in the flowback, we are
not finalizing the proposed requirement to commence operation of a
separator as soon as sufficient gas is present in the flowback for a
separator to operate. However, the public comments did not provide
sufficient information regarding other indicators as to when a
separator can operate. We therefore are unable to establish specific
criteria for determining the point at which operators are required to
route the flowback to the separator. For the reasons stated above, we
require in the final amendments that flowback must be routed to a
separator unless it is technically infeasible. This has always been our
intent. Although we learned that technical infeasibility is not
strictly limited to the amount of gas present, we believe that if this
infeasibility is not predicated solely on the amount of gas present,
then there must be some other site-specific technical issues that
prevent a separator from functioning. Such technical infeasibility
might include the separator being overwhelmed by the flowback, such
that the vapor space in the separator is not maintained, or the liquid
drain is unable to handle the volume of liquid flowing through. We
further note that the general duty to maximize resource recovery and
minimize releases to the atmosphere required in Sec.  60.5375(a)(4)
applies during the entire flowback period, including the initial
flowback stage.
    As proposed, the second stage, defined as the ``separation flowback
stage,'' begins when the flowback gases and liquids are routed to 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 infeasible to
route the recovered gas to a flow line or collection system, 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, as required in the 2012 NSPS at
Sec.  60.5375(a)(3). No direct venting of recovered gas would be
allowed during the separation flowback stage. We also proposed that, at
any time during the separation flowback stage, if the gas present in
the flowback becomes insufficient to maintain operation of the
separator, the operator would revert to the initial flowback stage
until the separator could again function to allow continuous recovery
of the gas and to allow separation and recovery of the liquids. 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. We are finalizing the
provisions relative to the separation flowback stage as proposed,
except that the operator can revert to the initial flowback stage if it
is technically infeasible to maintain function of the separator
(consistent with our discussion above on requiring the operation of a
separator unless it is technically infeasible). We also have added
requirements for recordkeeping to document each occurrence of reverting
back to the initial flowback stage and the reason for the reversion.
    We had proposed that the end of the separation flowback stage was
the point where separation flowback would have declined and stabilized
enough to allow continuous recovery of the gas and where separation and
recovery of any crude oil, condensate and produced water were possible.
We had proposed that the flowback period of a well completion operation
included only the initial flowback stage and the separation flowback
stage, as flowback ended and ongoing production began at that point.
Further, we had identified that point as the beginning of the
``production stage'' of the well completion. We had also explained at
proposal that we were seeking to identify objective criteria for making
a determination that flowback had subsided and that the well had
reached the point where production could begin, marking the end of the
separation flowback stage and the beginning of the production stage. We
solicited comment on the characteristics of the flow or other
conditions that could be used to establish such criteria.
    In addition, we proposed that, for storage vessels receiving
liquids following the flowback period of a well completion, the
beginning of the production stage would also begin the 30-day period
for determining VOC PTE 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 had also proposed amendments to Sec.  60.5365(e) to reflect
that, for purposes of the well completion provisions, the 30-day period
for the affected facility determination required in Sec.  60.5365(e)
would commence at the beginning of the production stage. During the
production stage, any venting or flaring of the recovered gas would be
prohibited.
    Several commenters took issue with the inclusion of the production
stage as part of the overall well completion operation. The commenters
contended that this extension confuses or contradicts other provisions
that explicitly are applicable to well completion operations and should
not be applicable over the lifetime of a well in production. The
commenters asserted that it is critical that the rule identify when the
flowback period ends and clarify that the requirements for well
completions do not extend beyond the end of the flowback period. The

commenters explained that, because the production stage could
conceivably continue for decades, it was clearly not a stage of well
completion and was beyond the intended scope of Sec.  60.5375.
Commenters also gave examples of the ramifications of this concept.
They asserted that prohibition of venting and flaring for the lifetime
of the well would preclude planned maintenance workovers, flaring of
amine system overhead gas and venting of carbon dioxide.
    We agree with the commenters that the production stage should not
be a stage of well completion and understand that compliance with the
well completion provisions (which were intended only for the flowback
period) would be impossible were these provisions applicable throughout
the life of the well. As a result, we are finalizing requirements for
well completions that identify two stages of well completion, the
initial flowback stage and the separation flowback stage.
    As discussed above, we had proposed that the point where separation
flowback would have declined and stabilized enough to allow continuous
recovery of the gas and where separation and recovery of any crude oil,
condensate and produced water were possible would be the end of the
separation flowback stage and the beginning of the production stage. We
solicited information that could identify criteria for defining this
point. Commenters explained that removal of flowback equipment and
absence of well completion personnel were two indicators that flowback
had subsided and the well had cleaned up sufficiently to allow
production to begin.
    In addition to the information provided by commenters, it is our
observation that the permanent disconnection of the temporary equipment
used during flowback can be an indicator of flowback having ended. For
example, during flowback, skid-mounted choke manifolds are used to
limit flowback and assist in directing the flow. Temporary lines laid
on the ground from the wellhead to the choke manifold and to the
flowback separators and frac tanks are connected with ``hammer unions''
which are pipe unions that are designed for ease of making temporary
connections and are characterized by ``ears'' that allow the joint to
be made up quickly by striking with a hammer. After flowback has
subsided and the well has cleaned up sufficiently, the well is
temporarily shut in to disconnect the temporary flowback equipment. We
believe that when the operator permanently disconnects choke manifolds,
temporary separators, sand traps and other equipment connected with
temporary lines and hammer unions, it is a reliable indicator that
flowback has ended and the well is ready for production. At that point,
we believe that operators will remove these temporary equipment used
during flowback to avoid incurring unnecessary charges for additional
days the equipment remains onsite. The well could start production
immediately or it could remain shut in until permanent equipment is
installed some time later.
    In light of the above considerations, we are amending the NSPS such
that the end of the separation flowback stage is defined as the startup
of production, or when the well is shut in and the temporary flowback
equipment has been permanently disconnected from the well. We are also
finalizing amendments that identify the startup of production, rather
than the beginning of the production stage, as the beginning of the 30-
day period for determining storage vessel PTE according to the
requirements of Sec.  60.5365(e).
    As discussed in section V.A, we had received comment that some
operators route gas and liquids from the well site to other facilities
for collection and suggested we specify ``collection system'' as one of
the options for disposition of flowback liquids and recovered gas. We
agree with the commenter and have included ``collection system'' in the
provisions for gas and liquids handling during well completions. To
provide clarity, we also have added a definition in Sec.  60.5430 for
``collection system'' which is presented in section V.A.
    We are finalizing the liquids handling requirements during the
flowback period as proposed, with the slight revision to the definition
of the separation flowback stage as described above. During the
flowback period, which includes the initial flowback stage and the
separation flowback stage, the liquid portion of the flowback must be
directed to storage vessels, well completion vessels, injected into the
well or another well or routed to a collection system.
    In the proposed rule, we had provided that the 30-day period for
estimating the VOC PTE of a storage vessel receiving recovered liquids
would begin at the beginning of the production stage. With the revision
to the stages of completion discussed above, ``startup of production''
would replace ``beginning of the production stage.'' Because we believe
it is important to achieve control of storage vessel affected
facilities as soon as practicable, we believe it is important to begin
the 30-day period for estimating storage vessel VOC PTE as soon as this
estimation can be achieved and will provide a representative estimate
of the storage vessel's PTE during production. As a result, we believe
it is necessary to begin the estimation period after flowback ends,
immediately after the end of the separation flowback stage, since the
flowback period is not representative of liquids flow and composition
during production. Estimation during the flowback period could result
in PTE estimates being either abnormally low or abnormally high, since
very early in flowback the liquid is predominantly water flowing at a
high rate, while immediately after flowback, the volume has subsided
but VOC content of the liquid may be much higher. Tank emission
estimation methods generally require information on both the
composition of the liquid entering a storage vessel (generally obtained
through analysis of a pressurized sample of the liquid obtained from
the separator) and the volumetric rate of the liquid (often in barrels
per day). Because the analytical samples are taken from the separator
and the volume is calculated by recording the liquid collection from
the receiving vessel, it is not necessary to have a permanent storage
vessel installed in order to perform this estimation, and the sampling
and volume tracking can begin at any time after the end of flowback,
while the liquids are being collected in a well completion vessel or a
storage vessel. Based on these considerations, we are finalizing the
requirement that liquid during flowback may be routed to a well
completion vessel or storage vessel. Also, based on these
considerations, we are clarifying that recovered liquids may continue
to be routed to a well completion vessel or a storage vessel after the
startup of production, but that a well completion vessel to which
recovered liquids are routed for a period in excess of 60 days after
startup of production is considered a storage vessel subject, depending
on its PTE, to control under Sec.  60.5395, as with any other storage
vessel affected facility. In addition, we are amending the definitions
of ``storage vessel'' and ``well completion vessel'' to be consistent
with this requirement. We are amending 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 startup of production.
Consistent with these changes we are amending Sec.  60.5395(d)(1)(i) to
read as set forth in the regulatory text of this rule.
    We note that we have received requests for clarification of the
meaning

of ``maximum average daily throughput'' as used in the VOC PTE
determination language in Sec.  60.5365(e). The 2013 final rule that
promulgated storage vessel implementation amendments in which this term
first appeared in the NSPS provided limited guidance on how operators
should determine ``maximum average daily throughput,'' and no
definition of this term was included in the July 2014 proposed rule.
The discussion above explains that PTE determination methods generally
are based on modeling performed using results of analysis of
pressurized samples from the separator combined with liquid throughput
over some period that corresponds with the separator sample. We believe
that the ``maximum average daily throughput'' is determined by the
earliest calculation of daily average throughput during the 30-day
evaluation period employing generally accepted methods. Based on the
performance of wells over time, this initial calculation would
represent the maximum average daily throughput that could be expected
for the storage vessel. To provide more clarity in the rule, we have
added a definition of ``maximum average daily throughput'' in Sec.
60.5430. We are aware that issues remain concerning this term and
continue to consider how to resolve them.

B. Storage Vessels

1. Storage Vessels Removed From Service and PTE Determination
    As proposed, we are amending Sec.  60.5395(f) 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.
    For the reasons discussed below, we are also amending the NSPS to
clarify that storage vessel affected facilities removed from service
(which is defined as when they are physically disconnected from their
source of liquids for reasons other than maintenance and are emptied
and degassed) cease to be storage vessel affected facilities under the
NSPS. We received comment, with which we agree, that storage vessel
emissions are a function of the specific use of the vessel as
installed--determined by factors such as the type of liquid it is used
to contain, the liquid throughput of the vessel, and the pressure drop
of the liquid entering the vessel causing flash emissions. As a result,
removing a storage vessel from service in one use and moving it to a
new use could drastically change its emissions characteristics. To be
classified a ``storage vessel'' as defined in Sec.  60.5430, a tank or
other vessel must be used to contain crude oil, condensate,
intermediate hydrocarbon liquids or produced water. Should the tank or
other vessel cease being used to contain any of these liquids, it would
no longer meet the definition of ``storage vessel.'' In light of these
considerations, we believe that a storage vessel affected facility that
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 should not be
subject to requirements under the NSPS for the period of time it is
removed from service.
    A vessel, whether it is in service for the first time or after
being removed from service, falls into one of three categories: (1) It
is installed to replace a storage vessel affected facility or is
connected in parallel with a storage vessel affected facility, where
liquids to be contained and VOC PTE for the application are already
known; (2) the vessel does not replace a storage vessel affected
facility but is being returned to service to contain crude oil,
condensate, intermediate hydrocarbon liquids or produced water with
unknown PTE; or (3) the vessel is being used in an application other
than to contain crude oil, condensate, intermediate hydrocarbon liquids
or produced water.
    A vessel falling under the first category, that is replacing or is
being connected in parallel with a vessel that has already been
determined to be a ``storage vessel affected facility'' based on a
known PTE, in effect takes the place of the affected facility being
replaced or with which it is being connected in parallel and, as such,
should be immediately subject to the same requirements as the storage
vessel affected facility being replaced. There is no need for the 30-
day period after startup allowed under Sec.  60.5365(e) for determining
its VOC PTE and the 60-day period after startup allowed under Sec.
60.5395(c) for applying control. In short, a vessel in this category
should be subject immediately upon startup to the same requirements as
the storage vessel affected facility it is replacing. For example, a
vessel that is replacing a storage vessel affected facility subject to
the 95.0 percent control requirement in Sec.  60.5395(d)(1) would be
subject to Sec.  60.5395(d)(1), whereas a vessel that is replacing a
storage vessel affected facility subject to the 4 tpy alternative
uncontrolled emission standard in Sec.  60.5395(d)(2) would be subject
to Sec.  60.5395(d)(2).
    For vessels in the second category, i.e., the vessel does not
replace a storage vessel affected facility but is being returned to
service to contain crude oil, condensate, intermediate hydrocarbon
liquids or produced water with unknown PTE, the 30-day period for
determining the VOC PTE and the 30-day period for installation of
control if the PTE is 6 tpy or above would apply.
    For vessels in the third category, i.e., the vessel is being used
in an application other than to contain crude oil, condensate,
intermediate hydrocarbon liquids or produced water, the vessel
continues to not meet the definition of ``storage vessel'' for this
rule and has no requirements while in this service.
    Although we believe it is an unlikely occurrence, we note that,
when two or more storage vessels receive liquids in parallel, the total
throughput is shared between or among the parallel vessels and, in
turn, this causes the PTE of each vessel to be a fraction of the total
PTE. In these cases, the EPA would consider the parallel storage
vessels equivalent to a single vessel with PTE equal to the sum of the
PTE of the individual vessels. As a result, the parallel storage
vessels would be considered storage vessel affected facilities and
subject to control if the total PTE was at least 6 tpy. If one of the
parallel storage vessels has already been determined to be an affected
facility and is subject to storage vessel requirements, no PTE
calculation is necessary for the other parallel storage vessels because
the PTE is already known to be at least 6 tpy. In that event, all
storage vessels receiving liquids in parallel to the storage vessel
affected facility are subject to the same requirements immediately upon
startup. As a result of the above considerations, we are amending the
current definition of ``removed from service'' and adding a definition
of ``returned to service'' to clarify these provisions. The definitions
read as set forth in the regulatory text of this rule.
    We are also amending Sec.  60.5395(f) to include requirements for
storage vessels removed from service and returned to read as set forth
in the regulatory text of this rule.

C. Definition of ``Responsible Official''

    In our proposed action, the EPA proposed to amend the definition of
``responsible official'' to address several concerns identified by
petitioners as discussed above in section III.E. In our evaluation of
comments received from regulatory authorities and industry, we
determined that the terminology used for the definition of
``responsible official'' too closely mirrored

terminology used in the Title V permitting program. As the requirements
of subpart OOOO are separate and distinct from those of any permitting
program, we found that the use of those terms was inappropriate for
subpart OOOO and could potentially cause confusion of regulated
entities. Therefore, in addition to the proposed change to the
definition to reduce the burden of the advance delegation requirements
on the oil and gas industry, we are changing the term ``responsible
official'' to ``certifying official'' and changing the term
``permitting authority'' used in the definition to ``Administrator.''

V. Summary of Significant Comments and Responses

    This section summarizes the significant comments on our proposed
amendments and our response thereto.

A. Well Completions

1. Handling of Gases and Liquids
    Comment: One commenter concurs that many wells undergo the three
stages of well completion as defined in the preamble to the proposed
rule, but not all wells. The commenter points to the Fayetteville Shale
where the flowback from many of their wells are routed directly to a
separator with gas recovered into gathering lines and produced water
sent to frac tanks and then to lined earthen retention ponds. The
commenter asserts that these wells do not undergo the initial flowback
stage nor the separation flowback stage and instead go directly into
production stage as defined in the proposed rule.
    Response: The EPA acknowledges that there are differences in
reservoir characteristics and the resultant variations in composition
of the flowback between shale plays and even within a given shale play.
These differences affect how the well completion process is conducted.
As we discussed in section IV.A, we are aware that some operators are
able to route the flowback directly to a separator, essentially
bypassing the initial flowback stage. We agree with the commenter that
this is possible in some cases; however, that may not be true for all
situations. The final rule requires operators to direct the flow to the
separator unless it is technically infeasible for the separator to
function (which we explain in further detail in section IV.A) and
minimize releases to the atmosphere as required by Sec.  60.5375(a)(4).
We disagree with the commenter that their operation bypasses both
stages of flowback, if the operations the commenter described used a
temporary separator or other temporary flowback equipment. If a
temporary separator or other temporary flowback equipment were used,
then the operation would bypass the initial flowback stage but enter
the separation flowback stage and would be subject to the requirements
of Sec.  60.5375(a)(1)(ii). If such temporary flowback equipment is not
used, then the completion operation is indeed considered to enter
directly into production at the beginning of flowback, which in this
case would be considered ``startup of production,'' that begins the 30-
day period for determining VOC PTE for purposes of making a storage
vessel affected facility determination in accordance with the procedure
in Sec.  60.5365(e). However, should the well completions described by
the commenter involve the use of temporary flowback equipment, then the
onset of flowback would begin the separation flowback stage, which
would continue until the well was shut in and the temporary flowback
equipment was removed. There would be no initial flowback stage in
either case described above.
    Comment: One commenter supports the EPA's proposed definition of
initial flowback stage because they have received information in the
subpart OOOO annual reports that control was not possible or necessary
because there was insufficient gas to route to a control device.
Further, to ensure that emissions are not unnecessarily vented, the
commenter supports the EPA's establishment of clear criteria for
determining when there is sufficient gas to operate the separator, as
well as the delineation between the initial and separation flowback
stages. The commenter is concerned that without additional, clear
criteria, operators will unnecessarily vent rather than control
emissions. The commenter, therefore, requests that the EPA clarify the
criteria for reversion to initial flowback stage from separation
flowback stage when the recoverable gas present in the flowback becomes
insufficient to maintain operation of the separator.
    Response: As stated above, under the final rule, the second stage,
defined as the ``separation flowback stage,'' begins when the flowback
is routed to the separator, which is required unless it is technically
infeasible. The issues raised by the commenter are discussed in depth
in sections III.A and IV.A.
    Comment: One commenter expressed concern with the proposed
definition of the separation flowback stage which states that ``the
separation flowback stage ends when the production stage begins or when
the well is shut in, whichever is first.'' The commenter contends that
the well shut in provision should be removed. The commenter states that
in a typical well completion operation, prior to commencing production,
the well may be shut in to remove the flowback equipment and install
production equipment. In some instances, the well may be temporarily
shut in for other purposes such as making adjustments or performing
unexpected maintenance on the flowback equipment. Following these
activities, the well is re-opened and separation flowback may resume.
According to the commenter, the proposed rule would consider the well
in the ``production stage'' when the well is shut in regardless of
whether it actually enters into production or returns to the flowback
process after temporary shut in. The commenter believes it is more
accurate for the rule to state that the end of the separation flowback
stage occurs when production (not the ``production stage'') begins. The
commenter provides suggested revisions to the definition for separation
flowback stage.
    Response: The EPA agrees with the commenter that a well may be shut
in for various reasons and that shut in alone does not necessarily
depict the point of transition into production. As described in detail
in section IV.A, there are other conditions such as having the
temporary flowback equipment disconnected that indicate the end of
flowback that should be taken into account in combination with well
shut in. Further, although this commenter did not raise this issue, as
discussed in an earlier response, sometimes operators can startup
production without shutting in the well by running the temporary
flowback equipment in parallel with the permanent flow line such that
they can open the valve from the wellhead to the flow line and close
the valve from the wellhead to the temporary flowback equipment, and
isolate the temporary equipment for removal. As a result, the well is
not shut in, but the temporary flowback equipment would be removed. In
such cases, production had started without well shut in. In light of
the above, in the final rule, we have defined the ``separation flowback
stage'' to include two sets of criteria which identify the end of the
separation flowback stage. The new definition indicates that the end of
the separation flowback stage ends at the startup of production, or
when the well is shut in and permanently disconnected from the flowback
equipment. Therefore, a shut in condition of the well alone will not be
considered the end of the separation flowback stage so long as flowback

equipment is still connected and production has not begun.
    Comment: One commenter points out that there is a point at which
gas can be separated from fluids, but the gas is not yet of salable
quality. The commenter recommends that the EPA allow flaring of non-
sales quality gas because it cannot be recovered and sold, and
recommends that Sec.  60.5375 be amended to refer to ``salable
quality'' gas from the gas outlet of the separator and similar changes
to the definitions of ``production stage,'' ``recovered gas'' and
``reduced emissions completion'' in Sec.  60.5430.
    Another commenter states that Sec.  60.5375(a)(2) specifies only
one of the suitable options for salable quality recovered gas. The
commenter suggests that this section be modified to say ``all salable
quality recovered gas must be routed to a gas flow line or collection
system, re-injected into the well or another well, used as an onsite
fuel source, or used for another useful purpose that a purchased fuel
or raw material would serve.'' Alternatively, this paragraph could be
deleted in that it is redundant given Sec.  60.5375(a)(1)(ii).
    Response: The EPA agrees with the commenter's assertion that some
gas recovered during the separation flowback stage may not be of
salable quality. The NSPS defines ``salable quality gas'' as ``natural
gas that meets the flow line or collection system operator
specifications, regardless of whether such gas is sold.'' It is our
intent to prohibit the direct venting of any gas during the separation
flowback stage. However, because we are aware that not all recovered
gas is of salable quality, the final rule requires an operator to route
all salable quality recovered gas from the separator to 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. However, if, during the separation flowback
stage, it is infeasible to route the recovered gas to a flow line or
collection system, reinject the gas or use the gas as fuel or for other
useful purpose, the recovered gas must be combusted. No direct venting
of recovered gas is allowed during the separation flowback stage.
    We believe these options effectively address all gas conditions
(salable or non-salable) encountered during the separation flowback
stage. For example, should the gas not meet minimum quality standards
for entering the gathering system, we believe that would render
collection ``infeasible'' until such time that the quality of the gas
had improved and was acceptable. As a result, the non-salable quality
gas would be combusted.
    Comment: Several commenters point out that Sec.  60.5375(a)(1)(ii)
allows limited options on how liquids from the separator must be
handled. According to the commenters, condensate is not always sent to
a storage vessel at the well site during production, but rather is
routed to a condensate or mixed well stream line and piped to another
location. Sometimes the condensate is piped to a central processing
facility or tank battery, and sometimes it is piped to a condensate
stabilization facility where the condensate is heated and stabilized at
a lower vapor pressure prior to going to a condensate tank so as to
avoid flashing in the tank. One commenter states that in the Eagle Ford
shale play they often elect to install blowcase units to maximize
condensate recovery and to enable the direct routing of recovered
liquids from the separator to a condensate collection system. This
design and practice would, according to the commenter, eliminate or
reduce the need for atmospheric storage vessels. According to the
commenters, the proposed rule's requirement that recovered liquids must
be routed to a storage vessel could be misinterpreted by regulatory
agencies to not allow for companies to pipe the condensate to another
location. For the separation flowback stage, paragraph Sec.
60.5375(a)(1)(ii) should be revised to clarify that liquids may be
routed to a collection system.
    Response: It is the EPA's intention to allow any innovative
management practice for these materials that encourages resource
conservation, gas recovery and emissions reductions. We agree that
routing liquids to centralized collection systems mentioned by the
commenter is an innovative approach that results in reduced emissions,
since the liquids are conveyed to the central facility through closed
pipes, reducing emissions. The commenter mentioned production, and also
cited the provisions for the separation flowback stage at Sec.
60.5375(a)(1)(ii). We believe that collection systems should be allowed
as one of the options for handling liquids during flowback and during
production. In light of the comments received and our belief that
centralized collection systems are protective of the environment, the
final rule requires that during the separation flowback stage, all
liquids from the separator must be directed to one or more well
completion vessels or storage vessels, routed to a collection system or
be re-injected into the well or another well. To further clarify this
requirement, we have added a definition for ``collection system'' in
Sec.  60.5375 as set forth in the regulatory text of this rule.
    Comment: One commenter expresses concern that allowing liquids from
the separator to be routed to a well completion vessel, which as
defined in the proposed rule includes lined earthen pits and as
described in the proposal preamble includes open top frac tanks, may
allow the release of emissions from recovered gas and other
hydrocarbons. The commenter requests that the EPA clarify that the use
of ``well completion vessels,'' like the use of ``storage vessels,''
during the separation flowback stage, will not result in emissions from
recovered gas or other hydrocarbons.
    Response: Because of the high volumes of liquids encountered during
flowback, both in the initial flowback stage and in the separation
flowback stage, we believe it is appropriate to route flowback liquids
to a well completion vessel. Flowback consists largely of water both
from the fracturing operation and water produced from the formation. In
addition, such high volumes potentially could cause damage to sealed
and controlled storage vessels which operate essentially at atmospheric
pressure and are not designed to handle elevated pressures that could
be caused by surges. Although we understand that there may be some
emissions from these vessels, our intent in the well completion
requirements of the NSPS is to require practices that will minimize
releases to the atmosphere and maximize resource recovery, such as
separation and collection of gas from the flowback unless it is
technically infeasible for the separator to function and requiring gas
that cannot be routed to the flow line to be combusted.
    Comment: One commenter contends that limiting exceptions to the REC
requirement is important, given that flaring of completion emissions
represents a waste of natural resources and results in emissions of
nitrogen oxides (NOX) and carbon dioxide (CO2)
that offset the benefits of methane and VOC reduction. In this regard,
the commenter is concerned that the proposed amendments continue to
allow for excessive combustion of completion emissions, instead of the
use of REC, when the producer deems it ``infeasible'' to capture
completion emissions for sale or beneficial use.
    The commenter believes that the proposed amendments would not only
preserve this vague exception, but also problematically include
preamble text suggesting that a producer can invoke

the exception in circumstances that are contrary to the original intent
of subpart OOOO. The commenter contends that in the preamble to the
final rule promulgating subpart OOOO, the EPA explained its
``understanding'' that producers ordinarily ``plan their operations . .
. to ensure their product has a viable path to market before completing
a well,'' and that combustion in lieu of a REC would only be necessary
in ``isolated cases.'' However, the preamble to the current proposed
rule indicates that a REC could be deemed ``infeasible'' merely because
``there [is] no flow line or other infrastructure available at the site
for collection of the gas.'' This preamble text implies that the
``infeasibility'' exception could be used for logistical reasons or for
the convenience of the producer, rather than in ``isolated'' cases
where inherent characteristics of the completion prevent the capture of
emissions for sale or beneficial use.
    Accordingly, the commenter urges the EPA to either eliminate or
expressly limit the scope of the infeasibility exception in the final
rule to ensure that it is consistent with the original structure and
intent of subpart OOOO and is not used inappropriately. Specifically,
the commenter recommends that the EPA include regulatory text
clarifying that collection of completion emissions in the separation
flowback stage is required unless it is technically infeasible due to
inherent characteristics of the flowback or unexpected conditions, not
for logistical reasons that are within the control of the operator. The
commenter believes this clarification would provide operators the
flexibility to use combustion instead of REC when necessary, while
ensuring that combustion is an option of last resort.
    Response: We agree with the commenter that the intent of the rule
is to minimize completion emissions during the separation flowback
stage and to maximize recovery of the gas to the flow line. The final
rule requires the operator to route the recovered salable gas to 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 is infeasible to route the recovered gas to a flow line or
collection system, reinject the gas or use the gas as fuel or for other
useful purpose, the recovered gas must be combusted. No direct venting
of recovered gas is allowed during the separation flowback stage.
    While we understand the commenters concern about using the
infeasibility provision to combust recovered gas when a flow line is
not available, we point out that these are gas wells drilled for the
production of gas; therefore the operator will have planned to be able
to produce the well commercially by having the infrastructure in place
and will generally avoid completing wells when it is known that the
infrastructure to collect the gas and route it to market will not yet
be available. However, there will be cases, though we believe to be
rare, in which the operator, for reasons not within his or her control,
is unable to acquire access to a flow line in time for the well
completion due to unforeseen circumstances.
    Comment: Several commenters took issue with the inclusion of the
production stage as part of the overall well completion operation. The
commenters contend that inclusion confuses or contradicts other
provisions that explicitly are applicable to well completion operations
and not to a well in production. The commenter believes it is critical
that the rule identify when the flowback period ends and clarify that
the requirements for well completions do not extend beyond the end of
the flowback period.
    For the commenter, the problems arise in the provisions of Sec.
60.5375(a)(1)(iii) and in the definition of ``production stage.''
Paragraph 60.5375(a)(1)(iii) specifies requirements for the production
stage, yet this paragraph is a subparagraph of Sec.  60.5375(a), which
is expressly applicable to well completion operations. Further, the
commenter states that, in the proposed rule, while the beginning of the
production stage marks the end of well completion operations, Sec.
60.5365(e) indicates that the beginning of the production stage also
marks the commencement of the period for determining storage vessel
applicability. The commenter believes that there should be no
requirements applicable to production following the end of flowback in
this paragraph. One of the commenters believes that the EPA's intent of
including the production stage is to ensure a storage vessel emissions
evaluation occurs immediately upon the start of production. However,
the commenter points out that storage vessel requirements in Sec.
60.5365(e) already dictate that an emissions evaluation must begin at
startup. Any such requirements for storage vessels should be specified
in applicable portions of Sec.  60.5365 and Sec.  60.5395.
    The commenter believes the definition of production stage requires
some editing in order to be consistent with the intent that
requirements for well completion operations end when production begins.
The commenters make several recommendations to the change of the terms
``production stage'', and editing of other provisions to minimize any
misinterpretation of the term ``production'' in well completion
operations requirements. The commenter also recommends that the last
sentence of Sec.  60.5375(a)(1)(ii) be deleted and replaced with
language indicating to the effect that ``the separation flowback stage
ends and production begins when flow resumes after flowback equipment
is removed from the well and flowback crews are released.'' See the
Response to Comments Document for a full discussion of these comments.
    Response: The EPA agrees with the arguments presented by the
commenter regarding confusion and opportunity for misinterpretation of
well completion requirements to be applicable during production. It is
not the intent that rule provisions for well completions and the
flowback period be applicable to the well during production over the
lifetime of the well. As such, the final amendments do not include the
term ``production stage'' or its definition. All references to
``production stage'' in the proposed amendments have been removed or
changed to ``startup of production'' in the final amendments.
Accordingly, the well completion requirements do not carry over beyond
the end of the flowback period.
    Comment: One commenter notes that they have many wells that go
straight to the production stage, as defined in the proposed rule. The
gas is recovered to a gathering line, but the liquids (produced water)
are routed to a portable frac tank and then to either additional frac
tanks or a lined earthen retention pond for storage. In some cases, the
commenter states that the produced water is routed to the frac tanks
because state regulations do not allow produced water to be routed
directly to lined earthen retention ponds. The commenter also contends
that routing the produced water to the frac tank also provides for
better flow measurement and better control of flow into the retention
pond, as well as allowing for additional sediment deposition and
recovery within the frac tank. The produced water is then reused/
recycled in subsequent well completions, reducing fresh water demands.
    The commenter is concerned that if the proposed rule is finalized,
they would be prohibited from using frac tanks and lined earthen
retention ponds

(well completion vessels) to recover and reuse produced water upon
entering the production stage for those wells that go directly to the
production stage (for these wells, upon commencing flowback). The
commenter does not believe it was the EPA's intent to adversely impact
water reuse and recycling practices and requests that in the final
rule, ``well completion vessel'' should be included in the standards
for the production stage.
    The commenter understands that the EPA may have concerns over
allowing the use of well completion vessels during the production stage
due to the potential for VOC emissions. However, according to the
commenter in the shale gas plays where the gas composition contains
either no or negligible amounts of hydrocarbons, the resultant VOC
emissions would be negligible as well. The commenter suggests that the
EPA consider exempting shale gas flowback liquids from being required
to be routed to a storage vessel on the basis of hydrocarbon gas
composition and negligible VOC emissions.
    Response: As stated previously, the final amendments do not include
the term ``production stage'' or the associated well completions
requirements that were in the proposed amendments. The final rule, as
amended, states that flowback period ends when either the well is shut
in and well completion equipment is removed from the well, or that
production has started. With respect to the types of wells identified
by the commenter, these wells would be subject to the same requirements
as other wells. However, we disagree with the commenter that these
wells enter directly into production, since apparently there is water
from the flowback that is separated from the gas and routed to frac
tanks. As a result, such wells may not go through the initial flowback
stage but would enter the separation flowback stage. We remind the
commenter that, even if there is no initial flowback stage or
separation flowback stage as defined by the rule, then the requirements
of Sec.  60.5375(a)(2) through (4) still apply. It should be noted that
there is nothing in the rule that prohibits the use of the types of
structures which would be well completion vessels during the initial
and separation flowback stage for the life of the well; however, once
the well has begun production, the vessels then become ``storage
vessels'' under the rule if they continue receiving liquids from the
well for a period exceeding 60 days from startup of production.
Accordingly, they would be subject to the same VOC PTE determination
and, if PTE was at least 6 tpy, would be subject to the cover, closed
vent system and control requirements.
2. Definition of Low Pressure Gas Well
    In the 2012 final rule, we had included a definition of ``low
pressure gas well.'' This was added as a logical outgrowth of the
public comments received on the August 23, 2011 proposed rule (76 FR
52738) that asserted that due to the reservoir pressure, well depth and
gathering line pressure, it was infeasible to perform an REC for some
wells. We developed a definition based on well parameters taking into
account fluid mechanics and other engineering principles. Development
of the definition was described in detail in the Technical Support
Document for the final rule which is in the docket. Following
publication of the final rule, we received petitions that asserted that
we had not provided the public an opportunity to comment on the
definition. We proposed the definition in our July 2014 proposed
amendments to provide the public an opportunity to comment. We also
presented and solicited comment on an alternative definition provided
by the petitioners.
    Comment: Two commenters appreciate the EPA's willingness to propose
for further comment the definition of ``low pressure gas well'' found
at Sec.  60.5430. The EPA noted that an alternative definition that was
submitted for its consideration by industry petitioners was ``a well
where the field pressure is less than 0.433 times the vertical depth of
the deepest target reservoir and the flowback period will be less than
3 days in duration.'' The commenters support the alternative
definition, although one of the commenters suggests that the word
``initial'' should be placed before the word ``flowback'' so that it is
clear that the three-day period in the definition refers to the initial
flowback period, and does not include the separation flowback. This
commenter adds that this definition is one that is consistent with the
manner in which low pressure wells are generally described in the
Appalachian Basin, is easier to use and is not as susceptible to
misunderstanding.
    Response: In the proposed rule we solicited comment on the
alternative definition suggested by the petitioners and on specific
concerns or questions we have with respect to the alternative
definition. We received no comments that provided any data or other
information that would lead us to conclude that the alternative
definition is sufficient to predict whether an REC would be infeasible
for wells meeting the alternative definition.
    As explained in the proposal, 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 definition in the rule 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. For these reasons, we are finalizing
the definition of ``low pressure gas well'' as proposed.
    Comment: A commenter concurs with the industry's alternate
definition presented in the previous comment. The commenter explains
that typical gas wells in Kentucky are produced from low pressure
reservoirs with low permeability. In order to make them economically
productive, they are stimulated with treatments that contain very
little fluid. According to the commenter, all Devonian Shale wells--the
largest producing reservoir in eastern Kentucky--are currently treated
using straight nitrogen. Most nitrogen flowbacks require a minimum of 3
days before there is a sufficient volume of natural gas to route and
flare with a combustion device. Fluid treatments or ``foamed'' fluid
are almost certain to damage the formation's permeability, negating the
opportunity for Kentucky's producers to continue developing that
region's significant resources.
    The commenter states that the current EPA definition of a ``low
pressure well'' is based upon the physical characteristics of a
reservoir, which is

then compared to the poorly defined ``flow line pressure at the sales
meter.'' Typical gathering systems in eastern Kentucky are low
pressure--typically below 100 psi with the overwhelming majority below
50 psi. This makes qualifying as a ``low pressure well'' under the
current definition almost impossible in Kentucky.
    According to the commenter, if a Devonian Shale well cannot be
qualified as ``low pressure'' after January 1, 2015, Kentucky operators
will be denied the option of stimulating gas wells with an ``inert''
gas such as nitrogen. Without the ``low pressure'' qualification, the
requirement of a green completion eliminates the ability to flow the
wells back to the atmosphere to remove the nitrogen used in the
stimulation. The commenter predicts that drilling in Kentucky's
Appalachian region will cease unless the EPA adopts the proposed
alternative ``low pressure well'' definition.
    Response: We believe the commenter may be misinterpreting the
proposed rule. The commenter appears to interpret the rule language as
requiring liquids to be used for stimulating the well. This is not the
case. The owner or operator is free to use any stimulation procedure so
long as the handling of the liquids and gases released from the well
follows the rule's provisions.
    Based on the comment, it appears that there will be essentially
little or no liquids discharged from these wells during the completion
process, and that the initial flowback period would consist of the
period of nitrogen flowback that precedes the production of natural
gas. There is nothing in the NSPS that prohibits venting of nitrogen.
However, any liquids that are discharged would have to be handled as
specified in the rule. The commenter does not appear to be concerned
about these rule provisions.
    The problem appears to be related to the rule provisions that
require the operator to route the recovered gas to 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. As explained above, the final amendments clarify
that during the initial flowback stage, gas may be vented. It appears
that the types of completions discussed by the commenter do not have a
separation flowback stage (based on the limited recovered liquids), and
once the nitrogen stimulation gas is off-gassed, the well goes directly
to production. If this is the case, there should not be excessive back
pressure introduced by the separator and other flowback equipment that
would overly impede gas flow, which was the situation the EPA was
intending to avoid by providing exemptions for low pressure gas wells.
As a result, as described by the commenter, we believe that such wells
do not need a low pressure well exemption to enable them to be
completed and to startup production. We note that, even if there is no
initial flowback stage or separation flowback stage as defined by the
rule, then the completion is still subject to the requirements of Sec.
60.5375(a)(2) through (4).
    If completion operations on these wells do in fact involve a
separation flowback stage, then Sec.  60.5375(a)(1)(ii) would apply,
meaning that during the separation flowback stage, all salable gas must
be routed to the flow line and that, if it is infeasible to route the
recovered gas to a flow line or collection system, reinject the gas or
use the gas as fuel or for other useful purpose, the recovered gas must
be combusted. No direct venting of recovered gas is allowed during the
separation flowback stage.
    In the case of the Devonian shale wells, we understand that the
initial gas flow is predominantly nitrogen which is not combustible.
However, based on the initial flowback provisions under the final rule,
these gases would be allowed to be vented during initial flowback. It
is assumed that as the nitrogen stimulant gas is released from the
well, the hydrocarbon proportion of recovered gas will continually
increase and eventually become combustible. Therefore, based on the
above rationale, we do not agree that these wells should be
specifically exempted as low pressure wells.

B. Storage Vessels

    Comment: One commenter believes the proposed definition of
``removed from service'' is too narrow. The commenter suggests that a
storage vessel affected facility should be considered removed from
service if it no longer meets the definition of a storage vessel,
regardless of whether it is physically isolated and disconnected from
the process. As proposed, the commenter contends that the rule
addresses only a single scenario when a storage vessel is no longer
used to store any materials. However, there are many other scenarios
where a storage vessel affected facility may still be used for storage
but no longer meets the definition of storage vessel and would thus no
longer be subject to the rule requirements. Examples of such scenarios
provided by the commenter include an atmospheric condensate tank
converted to methanol storage or non-VOC storage which may need to be
connected to the process; a bullet tank previously operated as an
atmospheric condensate tank for which its service is subsequently
changed to pressurized storage of butane and is connected to the
process; and a bullet tank previously operated as an atmospheric
produced water tank and which its service is subsequently changed to a
surge control process vessel and is connected to the process.
    For the scenario where a storage vessel is no longer used to store
anything, the commenter contends that the language regarding physical
isolation and disconnection is not necessary because the definition of
storage vessel states, ``vessel that contains an accumulation of crude
oil, condensate, intermediate hydrocarbon liquids, or produced water .
. .'' Thus, if those materials were to again enter the storage vessel,
the vessel would be ``returned to service'' and subject to the
applicable requirements. The commenter points out that in the unique
scenario where a storage vessel is no longer used to store anything,
physical isolation is sufficient; disconnection should not be required
if, for example, blind flanges are installed. The commenter suggests
several changes to the definition of removed from service to cover all
scenarios where a storage vessel may no longer meet the definition of
storage vessel for purposes of subpart OOOO, but is still used for
storage of liquids not included in the definition of ``storage
vessel.''
    Another commenters recommends that the EPA separate the definition
of returned to service from the definition of removed from service and
provided suggested language.
    Response: We agree that the proposed definition of ``removed from
service'' did not sufficiently address the many scenarios identified by
the commenters. In particular, the scenario where a storage vessel
affected facility is removed from service for a period of time and then
returned to service for some purpose was not clearly addressed under
the proposed rule. As discussed further in section IV.B of this
preamble, we have revised the definition of ``removed from service''
and added a definition for ``returned to service.''
    Comment: Several commenters do not support the concept of a storage
vessel maintaining its subpart OOOO applicability status when that
storage vessel is relocated to a different well site. One commenter
stated that storage vessel PTE at a previous location is irrelevant to
the new location and is entirely dependent on the particular

type of service for which the vessel is being used at the new location.
The commenters point out that the emissions from storage vessels are
not related to the equipment itself, but rather the characteristics and
volume of the fluids being sent to and stored in the storage vessel.
    As proposed, the commenters believe that the rule could require an
operator to control a storage vessel with little actual emissions and
could discourage the replacement of older damaged storage vessels with
newer vessels that may have come from a location that had emissions
above the 6 tpy threshold. One commenter concurred that applicability
should be based on the type of liquids introduced into the relocated
storage vessel and the emissions, not just the type of liquids. The
commenters seek confirmation that applicability of storage vessels is
triggered by the addition of crude oil, condensate, produced water or
intermediate hydrocarbon liquids to the vessel and the unique
production of the new location, rather than by simply moving the vessel
to a new location.
    The commenters believe the proposed rule requirements are further
complicated if the out-of-service storage vessel is sold to another
owner or operator as part of the relocation. ``Tank pedigree'' tracking
would quickly become unduly burdensome. The commenter agrees that if
the vessel's emissions are above 6 tpy at the new location, it should
be fully subject to the rule. The commenters believe that the tracking
and recordkeeping burden of having to assess different emissions
thresholds on different affected facility storage vessels based solely
on their movement within the company is an excessive and unrealistic
burden, particularly where the storage vessel emissions are less than 6
tpy at the new location. At this point, according to the commenters,
the tank is no longer a storage vessel affected facility and should not
be subject to the rule's requirements, including annual reporting,
regardless of whether the storage vessel's previous owner/operator used
the vessel in a service at a different location and facility, which
resulted in emissions sufficient to trigger rule applicability. Unless
the storage vessel's emissions are above 6 tpy at the new location, the
commenters contend that subpart OOOO requirements should not be imposed
on a relocated storage vessel.
    One commenter requests that controls only be required when that
relocated tank's emissions exceed 6 tpy, and not merely 4 tpy as
required in Sec.  60.5395(f)(2)(ii)(B). The commenter does not
understand why the initial emissions assessment should be different for
a relocated storage vessel compared to a newly constructed storage
vessel. The commenter states that the hydrocarbon composition flowing
through the relocated storage vessel may be significantly different at
the new location, and the owner or operator of the storage vessel
should not be penalized with a lower emissions threshold. The commenter
points out that a storage vessel affected facility is defined as ``a
single storage vessel . . . that has the potential for VOC emissions
equal to or greater than 6 tpy . . . [taking] into account requirements
under a legally and practically enforceable limit . . .'' The commenter
contends that by requiring a 4 tpy threshold for relocated affected
facility storage vessels, the EPA is effectively requiring control
devices on storage vessels that have emissions below the threshold that
is cost effective to control. Therefore, the commenter contends that a
4 tpy threshold for relocated affected facility storage vessels is
legally unsupportable.
    Finally, another commenter seeks clarification on the requirements
for storage vessels that are returned to service at the same location.
In the September 23, 2013 final rule amendments, the EPA added
requirements at Sec.  60.5395(f)(2)(ii)(B), which states that ``[i]f
the uncontrolled VOC emissions without considering control from your
storage vessel affected facility are 4 tpy or greater, you must comply
with paragraph (d) of this section within 60 days of returning to
service.'' However, the commenter points out that storage vessel
affected facilities returned to service with uncontrolled emissions
less than 4 tpy are not addressed and the commenter seeks clarification
of this issue.
    Response: We agree with the commenters' assertion that the
emissions from a storage vessel are not intrinsic to the vessel but are
a result of the operation and service to which the storage vessel is
connected. We have provided a detailed discussion of this issue and the
final amendments for storage vessels that are removed from service and
returned from service in section IV.B.
    Comment: Several commenters expressed general support for allowing
the use of electronic spark ignition systems on combustion control
devices, although many of the commenters also suggested modifications
to the proposed requirements.
    One commenter notes that Colorado's Regulation Number 7 requires
all combustion devices used to control hydrocarbon emissions utilize an
auto-igniter to ensure the operation of the continuous flame pilot.
During the adoption of this requirement, the Colorado Air Quality
Control Commission determined that auto-igniters were a cost-effective
method to reduce hydrocarbon emissions. Another commenter notes that
the Fort Berthold Indian Reservation Federal Implementation Plan allows
for the use of continuous pilots or automatic spark igniters.
    Three commenters note that in the Natural Gas STAR program, the EPA
published a Partner Recognized Opportunity (PRO) in PRO Fact Sheet No.
903 that discusses the operation and benefits of electronic spark
ignition systems. The commenter contends that the EPA should not lose
the benefits of this control technology enhancement by disallowing its
use in this rule. With this being an established technology in Natural
Gas STAR, the commenters do not believe operators should have to
petition the EPA for approval under its new control technology
provision. The commenters request that the rule be modified to
explicitly allow the use of electronic spark ignition systems as an
alternative to a continuous pilot flame.
    The commenters add that in the arctic environment in Alaska,
operators have often encountered situations where, following
maintenance on a flare, a new spark igniter with frost buildup cannot
re-light the flare pilot. Continuous pilot flames are required for
safety and certainty of combustion in arctic Alaska. Therefore, the
commenters contend that if an electronic spark ignition system is
allowed, it needs to be an option, rather than a requirement. Two other
commenters agree that it should only be an option.
    One commenter believes that spark ignition systems may be most
appropriate for flares which only occasionally operate (such as flares
to handle mishap/safety shutdowns, maintenance blowdowns, etc.) and
flares that operate more or less continuously, such as a flare for a
wet seal compressor seal-degassing unit. In both cases they may be more
reliable than a pilot light, since spark ignition systems cannot be
blown out and do not consume fuel and increase emissions, as a pilot
light does. However, the commenter contends that a spark ignition
system should not be the sole ignition mechanism for flares with highly
variable flow, such as flares associated with well completion flowback
or storage tank control systems. The commenter states that variable
flow can lead to sputtering flames, and a failure to burn all the gas

directed to the flare, leading to large emissions of VOC and methane
from the flare. The commenter is concerned that a spark ignition device
may not restart the flare as rapidly as a pilot light in such
situations, which could lead to higher emissions for flares on variable
flow sources such as wells and storage tanks. Given the high rate of
emissions of VOC and methane during flowback flaring, it would be
appropriate to require both pilot lights and spark ignition devices.
    One commenter adds that although they believe electronic spark
ignition systems should be allowed as an option, the EPA has not
provided any evidence or data to suggest that pilots do not remain
continuously lit during operation in the applications used for
compliance with this rule. Nor has the EPA provided any data on
potential environmental benefit of such technology. The commenter also
contends that safety implications must be seriously considered when
using auto-igniters. When use is appropriate, operators must be able to
tailor the auto-igniter configuration and operation to the combustion
device, the facility design, the flammability of the waste stream,
facility operations and applicable industry standards. The commenter
states that the EPA should not attempt to create a blanket mandate for
the application or operation of auto-igniters since safety risks must
be evaluated, often on a case-by-case basis. Auto-igniters may not be
appropriate or allowed in current industry standards for all
applications (such as heaters, boilers, and enclosed combustors). The
commenter provides details of safety concerns related to electronic
spark ignition systems in their comments.
    Two commenters recommend that electronic spark ignition systems
have fail safe systems such as temperature and pressure monitoring to
prevent any venting during periods when vapors are flowing to the
device.
    One commenter points out that electronic spark ignition systems
have been available for over twenty years and have a proven track
record of successfully and safely lighting and maintaining flares and
fuel burning equipment.
    Response: In our response to comments on the 2011 proposed rule, we
stated that given the intermittent and inconsistent nature of emissions
from storage vessels in this industry combined with the highly variable
VOC concentration in the emissions, we did not believe at that time
that a spark-ignited flare would achieve the same level of emission
reduction as a flare with a continuous flame present.
    In the July 17, 2014, proposed rule, we solicited 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 were interested in information on the use of this
technology as a means of ensuring that continuous flame pilots remain
functional at all times. Therefore, we also solicited 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.
    Although we received some information, we received no data in
response to most of the questions we asked that would help us determine
that electronic spark ignition should be allowed as an alternative to a
continuous pilot flame.
    Accordingly, issues and concerns related to intermittent and
inconsistent flow still remain. Specifically, we remain concerned with
how quickly an electronic spark ignition system will ignite an emission
stream from an intermittent and inconsistent emission source. We also
remain to have concerns about flame stability.
    In light of the comments received and the lack of information
received in response to our solicitation, we are not satisfied at this
time that we have sufficient information on which to base a decision to
allow electronic spark ignition as an alternative to a continuous pilot
flame.

C. Routing of Reciprocating Compressor Rod Packing Emissions to a
Process

    Comment: One commenter expressed support for the EPA's proposal to
allow reciprocating compressor rod packing emissions to be routed to a
process. However, the commenter claims that they cannot comply with the
structure of the requirements as proposed. Also, the commenter contends
that the proposed requirements do not conform to the current structure
of the rule. The commenter recommends several changes:
    First, the commenter states that proposed Sec.  60.5385(a)(3)
references initial compliance requirements with Sec.  60.5411(a) and