[Federal Register Volume 79, Number 250 (Wednesday, December 31, 2014)]
[Rules and Regulations]
[Pages 79018-79041]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2014-30630]



[[Page 79017]]

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  

[[Page 79018]]


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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 (202) 566-1744, and the telephone number 
for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Mr. Bruce Moore, Sector Policies and 
Programs Division (E143-05), Office of Air Quality Planning and 
Standards, Environmental Protection Agency, Research Triangle Park, 
North Carolina 27711, telephone number: (919) 541-5460; facsimile 
number: (919) 685-3200; email address: [email protected].

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

[[Page 79019]]

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

[[Page 79020]]

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

[[Page 79021]]

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

[[Page 79022]]

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

[[Page 79023]]

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

[[Page 79024]]

``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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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

[[Page 79025]]

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

[[Page 79026]]

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

[[Page 79027]]

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

[[Page 79028]]

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

[[Page 79029]]

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

[[Page 79030]]

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

[[Page 79031]]

(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

[[Page 79032]]

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

[[Page 79033]]

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

[[Page 79034]]

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 
(b), which is unnecessary and inconsistent with Sec.  60.5385(a)(1) and 
(2). The commenter also believes it is inconsistent with the rule's 
structure for other affected facilities.
    Second, the commenter states that the EPA is not proposing to 
modify Sec.  60.5410(c)(1) (initial compliance requirements) which 
states ``[d]uring the initial compliance period, you must continuously 
monitor the number of hours of operation or track the number of months 
since the last rod packing replacement.'' The commenter contends that 
reciprocating compressor affected facilities complying with Sec.  
60.5385(a)(3) cannot comply with this requirement. Thus, the commenter 
believes that this requirement must be revised. Additionally, the 
commenter contends that there is not an initial compliance requirement 
here for compressors complying with Sec.  60.5385(a)(3); thus, it would 
be inappropriate to reference the Sec.  60.5411(a) and (b) 
requirements.
    Third, the commenter states that in the proposed continuous 
compliance requirements in Sec.  60.5415(c)(4), the EPA proposes to 
reference the initial compliance requirements in Sec.  60.5411(a) and 
(b). The commenter contends that this does not make sense and does not 
conform to the changes that the EPA is also proposing at Sec.  
60.5416(a) and (b) (continuous cover and closed vent system 
requirements).
    Fourth, the commenter states that the EPA is proposing to make 
Sec.  60.5416(a) and (b) (continuous cover and closed vent system 
requirements) applicable for reciprocating compressors; however, the 
recordkeeping requirements associated with Sec.  60.5416(a) and (b) 
have not been modified to conform to this proposed change. 
Additionally, the commenter believes Sec.  60.5420(c)(6) currently 
fails to reference Sec.  60.5416(a)(2). The commenter recommends that 
the EPA take this opportunity to resolve this oversight.
    One commenter does not believe that the proposed application of the 
closed vent system requirements to reciprocating compressors or the 
routing of the rod packing equipment through a closed vent system to a 
process in Sec.  60.5385(a)(3) are appropriate alternatives.

[[Page 79035]]

    Response: The EPA disagrees with several aspects of the comments 
but also agrees with certain suggestions. The commenter states that the 
reference in Sec.  60.5385(a)(3) to Sec.  60.5411(a) and (b) is not 
necessary. The EPA disagrees with this comment, because we consider it 
necessary to specify the standards to which a closed vent system and 
cover must be designed and operated to achieve the emission reductions 
sought by the rule.
    The EPA disagrees with the comment that the reference to Sec.  
60.5411(a) and (b) make it inconsistent with Sec.  60.5385(a)(1) and 
(2). Neither Sec.  60.5385(a)(1) nor (2) relies on additional equipment 
(e.g., covers and closed vent systems) to be operated properly to 
obtain the required emission reductions. Therefore, no such reference 
is needed in Sec.  60.5385(a)(1) or (2).
    The EPA agrees that compliance with 60.5410(c)(1) is intended for 
owners and operators that have not exercised their option to comply 
with 60.5385(a)(3), and has finalized language to that effect suggested 
by the commenter. The EPA has added a restrictive clause to Sec.  
60.5410(c) such that Sec.  60.5410(c)(1) through (4) apply only to 
sources electing to comply with Sec.  60.5385(a)(1) and (2). We made 
this change because several of the provisions of Sec.  60.5410(c)(1) 
through (4) are inappropriate for affected facilities that have chosen 
to comply with Sec.  60.5385(a)(3) rather than (a)(1) and (2).
    The EPA agrees that owners and operators that route rod packing 
emissions to a process under Sec.  60.5385(a)(3) are not subject to 
Sec.  60.5410(c)(1). We have amended Sec.  60.5410(c) to specify that 
owners and operators using closed vent systems and covers are not 
subject to Sec.  60.5410(c)(1).
    The commenter states that requirements in Sec.  60.5411(a) and (b) 
are initial compliance requirements and should not be referenced in the 
continuous compliance requirements of Sec.  60.5415(c)(4). The EPA 
disagrees with the commenter because there are requirements within 
Sec.  60.5411(a) and (b) that require compliance beyond initial 
compliance. Therefore, we believe it is necessary to specify continuous 
compliance with Sec.  60.5411(a) and (b).
    The commenter states that Sec.  60.5416(a) and (b) should be 
qualified so as to apply only the reciprocating compressors subject to 
Sec.  60.5385(a)(3). The EPA agrees with this comment and has added 
language to make this change.
    The EPA agrees that Sec.  60.5415(c)(4) is intended to describe the 
requirements applicable to reciprocating compressors operating under 
Sec.  60.5385(a)(3) and should refer to the continuous compliance 
requirements applicable to closed vent systems and covers specified in 
Sec.  60.5416(a) and (b).
    The EPA agrees with the suggested revision of 60.5420(c) (6) 
through (9), and has made the changes to the regulatory text.
    Comment: One commenter also expressed support for the proposed 
changes to Sec.  60.5385 to allow the emissions from reciprocating 
compressors to be routed to a process, but believes other revisions, 
similar to or the same as those suggested by the previous commenter, 
are needed in the rule to maintain consistency with the proposed 
changes. The commenter's suggestions are not repeated here but are 
detailed in their comments.
    Response: As discussed in the response to a previous comment, the 
EPA has made several amendments to the proposed rule language to 
clarify the requirements for reciprocating compressors.

VI. Technical Corrections and Clarifications

    The EPA is finalizing corrections and clarifications to the 2012 
NSPS and the 2013 storage vessel amendments including typographical and 
grammatical errors, as well as incorrect dates and cross-references. 
Details of the specific changes we are finalizing to the regulatory 
text may be found in the docket for this action.\4\
---------------------------------------------------------------------------

    \4\ Memorandum from Moore, Bruce, U.S. EPA, to Docket ID No. 
EPA-HQ-OAR-2010-0505, Technical Corrections to the Oil and Natural 
Gas Sector New Source Performance Standards. June 30, 2014.
---------------------------------------------------------------------------

VII. Impacts of These Final Amendments

    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 this action as would have been necessary to 
meet the previously finalized standards. We project that these 
amendments will result in no significant change in costs, emission 
reductions, or benefits. Even if there were changes in costs for the 
affected facilities, 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 controls for this revised final rule 
that they would have for the original final rule, there should not be 
any incremental costs related to this final revision.

A. What are the air impacts?

    We believe that owners and operators of affected facilities will 
install the same or similar control technologies to comply with the 
revised standards finalized in this action as they would have installed 
to comply with the previously finalized standards. Accordingly, we 
believe that this final rule will not result in significant changes in 
emissions of any of the regulated pollutants.

B. What are the energy impacts?

    This final rule is not anticipated to have an effect on the supply, 
distribution, or use of energy. As previously stated, we believe that 
owners and operators of affected facilities would install the same or 
similar control technologies as they would have installed to comply 
with the previously finalized standards.

C. What are the compliance costs?

    We believe there will be no significant change in compliance costs 
as a result of this final rule because owners and operators of affected 
facilities would install the same or similar control technologies as 
they would have installed to comply with the previously finalized 
standards.

D. What are the economic and employment impacts?

    Because we expect that owners and operators of affected facilities 
would install the same or similar control technologies to meet the 
standards finalized in this action as they would have chosen to comply 
with the previously finalized standards, we do not anticipate that this 
final rule will result in significant changes in emissions, energy 
impacts, costs, benefits, or economic impacts. Likewise, we believe 
this rule will not have any impacts on the price of electricity, 
employment or labor markets, or the U.S. economy.

E. What are the benefits of the final standards?

    As previously stated, the EPA anticipates the oil and natural gas 
sector will not incur significant compliance costs or savings as a 
result of this action and we do not anticipate any significant emission 
changes resulting from these amendments to the rule. Therefore, there 
are no direct monetized benefits or disbenefits associated with this 
final rule.

VIII. Statutory and Executive Order Reviews

    Additional information about these statutes and Executive Orders 
can be

[[Page 79036]]

found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 13563: Improving Regulation and Regulatory Review

    This action is not a significant regulatory action and was 
therefore not submitted to the Office of Management and Budget (OMB) 
for review.

B. Paperwork Reduction Act (PRA)

    This action does not impose any new information collection burden 
under the PRA. OMB has previously approved the information collection 
activities contained in the existing regulations and has assigned OMB 
control number 2060-0673. Today's action does not change the 
information collection requirements previously finalized and, as a 
result, does not impose any additional information collection burden on 
industry.

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic 
impact on a substantial number of small entities under the RFA. In 
making this determination, the impact of concern is any significant 
adverse economic impact on small entities. An agency may certify that a 
rule will not have a significant economic impact on a substantial 
number of small entities if the rule relieves regulatory burden, has no 
net burden or otherwise has a positive economic effect on the small 
entities subject to the rule. The EPA has determined that none of the 
small entities subject to this rule will experience a significant 
impact because today's action imposes no additional compliance costs on 
owners or operators of affected sources. We have therefore concluded 
that this action will have no net regulatory burden for all directly 
regulated small entities.

D. Unfunded Mandates Reform Act of 1995 (UMRA)

    This action does not contain any unfunded mandate as described in 
UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect 
small governments. This action imposes no enforceable duty on any 
state, local or tribal governments or the private sector.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government.

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications as specified in 
Executive Order 13175. It will not have substantial direct effect on 
tribal governments, on the relationship between the federal government 
and Indian tribes or on the distribution of power and responsibilities 
between the federal government and Indian tribes, as specified in 
Executive Order 13175. Thus, Executive Order 13175 does not apply to 
this action.
    Although at proposal the EPA noted that Executive Order 13175 did 
not apply, the EPA solicited comment from tribes inclined to comment on 
the proposed action. The EPA did not receive substantive comments from 
tribes on our proposal.

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    This action is not subject to Executive Order 13045 because it is 
not economically significant as defined in Executive Order 12866, and 
because the EPA does not believe the environmental health or safety 
risks addressed by this action present a disproportionate risk to 
children.
    This action does not add to or relieve affected sources from any 
requirements, and therefore has no impacts; thus, health and risk 
assessments were not conducted. The public was invited to submit 
comments or identify peer-reviewed studies and data that assess effects 
of early life exposure to HAP from oil and natural gas sector 
activities. The EPA received no substantive information on these risks.

H. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 because it is 
not a significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act (NTTAA)

    This rulemaking does not involve technical standards.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    The EPA believes the human health or environmental risk addressed 
by this action will not have potential disproportionately high and 
adverse human health or environmental effects on minority, low-income 
or indigenous populations because it does not affect the level of 
protection provided to human health or the environment. The basis for 
this determination is that this action is a reconsideration of existing 
requirements and imposes no new impacts or costs.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule 
report to each House of the Congress and to the Comptroller General of 
the United States. This action is not a ``major rule'' as defined by 5 
U.S.C. 804(2).

List of Subjects in 40 CFR Part 60

    Administrative practice and procedure, Air pollution control, 
Environmental protection, Intergovernmental relations, Reporting and 
recordkeeping.

    Dated: December 19, 2014.
Gina McCarthy,
Administrator.

    For the reasons set out in the preamble, title 40, chapter I of the 
Code of Federal Regulations is amended as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

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

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

Subpart OOOO--[Amended]

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


Sec.  60.5365  Am I subject to this subpart?

* * * * *
    (e) Each storage vessel affected facility, which is a single 
storage vessel located in the oil and natural gas production segment, 
natural gas processing segment or natural gas transmission and storage 
segment, and has the potential for VOC emissions equal to or greater 
than 6 tpy as determined according to this section by October 15, 2013 
for Group 1 storage vessels and by April 15, 2014, or 30 days after 
startup (whichever is later) for Group 2 storage vessels, except as 
provided in paragraphs (e)(1) through (4) of this section. The 
potential for VOC emissions must be calculated using a generally 
accepted model or calculation methodology, based on the maximum average 
daily throughput determined for a 30-day period of production prior to

[[Page 79037]]

the applicable emission determination deadline specified in this 
section. The determination may take into account requirements under a 
legally and practically enforceable limit in an operating permit or 
other requirement established under a Federal, State, local or tribal 
authority.
    (1) For each new, modified or reconstructed storage vessel 
receiving liquids pursuant to the standards for gas well affected 
facilities in Sec.  60.5375, including wells subject to Sec.  
60.5375(f), you must determine the potential for VOC emissions within 
30 days after startup of production.
    (2) A storage vessel affected facility that subsequently has its 
potential for VOC emissions decrease to less than 6 tpy shall remain an 
affected facility under this subpart.
    (3) For storage vessels not subject to a legally and practically 
enforceable limit in an operating permit or other requirement 
established under Federal, state, local or tribal authority, any vapor 
from the storage vessel that is recovered and routed to a process 
through a VRU designed and operated as specified in this section is not 
required to be included in the determination of VOC potential to emit 
for purposes of determining affected facility status, provided you 
comply with the requirements in paragraphs (e)(3)(i) through (iv) of 
this section.
    (i) You meet the cover requirements specified in Sec.  60.5411(b).
    (ii) You meet the closed vent system requirements specified in 
Sec.  60.5411(c).
    (iii) You maintain records that document compliance with paragraphs 
(e)(3)(i) and (ii) of this section.
    (iv) In the event of removal of apparatus that recovers and routes 
vapor to a process, or operation that is inconsistent with the 
conditions specified in paragraphs (e)(3)(i) and (ii) of this section, 
you must determine the storage vessel's potential for VOC emissions 
according to this section within 30 days of such removal or operation.
    (4) For each new, reconstructed, or modified storage vessel with 
startup, startup of production, or which is returned to service, 
affected facility status is determined as follows: If a storage vessel 
is reconnected to the original source of liquids; used to replace any 
storage vessel affected facility; or is installed in parallel with any 
storage vessel affected facility, it is a storage vessel affected 
facility subject to the same requirements as before being removed from 
service, or applicable to the storage vessel affected facility being 
replaced, or with which it is installed in parallel immediately upon 
startup, startup of production, or return to service.
* * * * *

0
3. Section 60.5375 is amended by:
0
a. Revising paragraphs (a) introductory text and (a)(1) through (3);
0
b. Revising paragraph (b);
0
c. Revising paragraphs (f)(1)(i) and (ii); and
0
d. Revising paragraph (f)(2).
    The revisions read as follows:


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

* * * * *
    (a) Except as provided in paragraph (f) of this section, for each 
well completion operation with hydraulic fracturing begun prior to 
January 1, 2015, you must comply with the requirements of paragraphs 
(a)(3) and (4) of this section unless a more stringent state or local 
emission control requirement is applicable; optionally, you may comply 
with the requirements of paragraphs (a)(1) through (4) of this section. 
For each new well completion operation with hydraulic fracturing begun 
on or after January 1, 2015, you must comply with the requirements in 
paragraphs (a)(1) through (4) of this section. You must maintain a log 
as specified in paragraph (b).
    (1) For each stage of the well completion operation, as defined in 
Sec.  60.5430, follow the requirements specified in paragraph (a)(1)(i) 
and (ii) of this section.
    (i) During the initial flowback stage, route the flowback into one 
or more well completion vessels or storage vessels and commence 
operation of a separator unless it is technically infeasible for a 
separator to function. Any gas present in the initial flowback stage is 
not subject to control under this section.
    (ii) During the separation flowback stage, route all recovered 
liquids from the separator to one or more well completion vessels or 
storage vessels, re-inject the liquids into the well or another well or 
route the recovered liquids to a collection system. Route the recovered 
gas from the separator into a gas flow line or collection system, re-
inject the recovered gas into the well or another well, use the 
recovered gas as an on-site fuel source, or use the recovered gas for 
another useful purpose that a purchased fuel or raw material would 
serve. If it is infeasible to route the recovered gas as required 
above, follow the requirements in paragraph (a)(3) of this section. If, 
at any time during the separation flowback stage, it is not technically 
feasible for a separator to function, you must comply with (a)(1)(i) of 
this section.
    (2) All salable quality recovered gas must be routed to the gas 
flow line as soon as practicable. In cases where salable quality gas 
cannot be directed to the flow line, you must follow the requirements 
in paragraph (a)(3) of this section.
    (3) You must capture and direct recovered gas to a completion 
combustion device, except in conditions that may result in a fire 
hazard or explosion, or where high heat emissions from a completion 
combustion device may negatively impact tundra, permafrost or 
waterways. Completion combustion devices must be equipped with a 
reliable continuous ignition source.
* * * * *
    (b) You must maintain a log for each well completion operation at 
each gas well affected facility. The log must be completed on a daily 
basis for the duration of the well completion operation and must 
contain the records specified in Sec.  60.5420(c)(1)(iii).
* * * * *
    (f) * * *
    (1) * * *
    (i) Each well completion operation with hydraulic fracturing at a 
wildcat or delineation well.
    (ii) Each well completion operation with hydraulic fracturing at a 
non-wildcat low pressure gas well or non-delineation low pressure gas 
well.
    (2) Route the flowback into one or more well completion vessels and 
commence operation of a separator unless it is technically infeasible 
for a separator to function. Any gas present in the flowback before the 
separator can function is not subject to control under this section. 
You must capture and direct recovered gas to a completion combustion 
device, except in conditions that may result in a fire hazard or 
explosion, or where high heat emissions from a completion combustion 
device may negatively impact tundra, permafrost or waterways. 
Completion combustion devices must be equipped with a reliable 
continuous ignition source. You must also comply with paragraphs (a)(4) 
and (b) through (e) of this section.
* * * * *

0
4. Section 60.5385 is amended by:
0
a. Revising paragraph (a) introductory text; and
0
b. Adding paragraph (a)(3).
    The revision and addition read as follows:


Sec.  60.5385  What standards apply to reciprocating compressor 
affected facilities?

* * * * *

[[Page 79038]]

    (a) You must replace the reciprocating compressor rod packing 
according to either paragraph (a)(1) or (2) of this section or you must 
comply with paragraph (a)(3) of this section.
* * * * *
    (3) Collect the emissions from the rod packing using a rod packing 
emissions collection system which operates under negative pressure and 
route the rod packing emissions to a process through a closed vent 
system that meets the requirements of Sec.  60.5411(a).
* * * * *

0
5. Section 60.5390 is amended by revising paragraph (c)(2) to read as 
follows:


Sec.  60.5390  What standards apply to pneumatic controller affected 
facilities?

* * * * *
    (c) * * *
    (2) Each pneumatic controller affected facility constructed, 
modified or reconstructed on or after October 15, 2013, at a location 
between the wellhead and a natural gas processing plant or the point of 
custody transfer to an oil pipeline must be tagged with the month and 
year of installation, reconstruction or modification, and 
identification information that allows traceability to the records for 
that controller as required in Sec.  60.5420(c)(4)(iii).
* * * * *

0
6. Section 60.5395 is amended by:
0
a. Revising paragraph (d)(1)(i); and
0
b. Revising paragraph (f).
    The revisions read as follows:


Sec.  60.5395  What standards apply to storage vessel affected 
facilities?

* * * * *
    (d) * * *
    (1) * * *
    (i) For each Group 2 storage vessel affected facility, you must 
achieve the required emissions reductions by April 15, 2014, or within 
60 days after startup, whichever is later, except as otherwise provided 
below in paragraph (f) of this section. For storage vessel affected 
facilities receiving liquids pursuant to the standards for gas well 
affected facilities in Sec.  60.5375, you must achieve the required 
emissions reductions within 60 days after startup of production as 
defined in Sec.  60.5430.
* * * * *
    (f) Requirements for Group 1 and Group 2 storage vessel affected 
facilities that are removed from service or returned to service. If you 
remove a Group 1 or Group 2 storage vessel affected facility from 
service, you must comply with paragraphs (f)(1) through (3) of this 
section. A Group 1 or Group 2 storage vessel is not an affected 
facility under this subpart for the period that it is removed from 
service.
    (1) For a storage vessel affected facility to be removed from 
service, you must comply with the requirements of paragraph (f)(1)(i) 
and (ii) of this section.
    (i) You must completely empty and degas the storage vessel, such 
that the storage vessel no longer contains crude oil, condensate, 
produced water or intermediate hydrocarbon liquids. A storage vessel 
where liquid is left on walls, as bottom clingage or in pools due to 
floor irregularity is considered to be completely empty.
    (ii) You must submit a notification as required in Sec.  
60.5420(b)(6)(vi) in your next annual report, identifying each storage 
vessel affected facility removed from service during the reporting 
period and the date of its removal from service.
    (2) If a storage vessel identified in paragraph (f)(1)(ii) of this 
section is returned to service, you must determine its affected 
facility status as provided in Sec.  60.5365(e).
    (3) For each storage vessel affected facility returned to service 
during the reporting period, you must submit a notification in your 
next annual report as required in Sec.  60.5420(b)(6)(vii), identifying 
each storage vessel affected facility and the date of its return to 
service.
* * * * *

0
7. Section 60.5401 is amended by revising paragraphs (d) and (e) to 
read as follows:


Sec.  60.5401  What are the exceptions to the equipment leak standards 
for affected facilities at onshore natural gas processing plants?

* * * * *
    (d) Pumps in light liquid service, valves in gas/vapor and light 
liquid service, pressure relief devices in gas/vapor service, and 
connectors in gas/vapor service and in light liquid service that are 
located at a nonfractionating plant that does not have the design 
capacity to process 283,200 standard cubic meters per day (scmd) (10 
million standard cubic feet per day) or more of field gas are exempt 
from the routine monitoring requirements of Sec. Sec.  60.482-2a(a)(1), 
60.482-7a(a), 60.482-11a(a), and paragraph (b)(1) of this section.
    (e) Pumps in light liquid service, valves in gas/vapor and light 
liquid service, pressure relief devices in gas/vapor service, and 
connectors in gas/vapor service and in light liquid service within a 
process unit that is located in the Alaskan North Slope are exempt from 
the routine monitoring requirements of Sec. Sec.  60.482-2a(a)(1), 
60.482-7a(a), 60.482-11a(a), and paragraph (b)(1) of this section.
* * * * *

0
8. Section 60.5410 is amended by:
0
a. Revising paragraph (c)(1);
0
b. Adding a new paragraph (c)(2); and
0
c. Revising paragraph (d)(2) to read as follows:


Sec.  60.5410  How do I demonstrate initial compliance with the 
standards for my gas well affected facility, my centrifugal compressor 
affected facility, my reciprocating compressor affected facility, my 
pneumatic controller affected facility, my storage vessel affected 
facility, and my equipment leaks and sweetening unit affected 
facilities at onshore natural gas processing plants?

* * * * *
    (c) * * *
    (1) If complying with Sec.  60.5385(a)(1) or (2), during the 
initial compliance period, you must continuously monitor the number of 
hours of operation or track the number of months since the last rod 
packing replacement.
    (2) If complying with Sec.  60.5385(a)(3), you must operate the rod 
packing emissions collection system under negative pressure and route 
emissions to a process through a closed vent system that meets the 
requirements of Sec.  60.5411(a).
* * * * *
    (d) * * *
    (2) You own or operate a pneumatic controller affected facility 
located at a natural gas processing plant and your pneumatic controller 
is driven by a gas other than natural gas and therefore emits zero 
natural gas.
* * * * *

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


Sec.  60.5411  What additional requirements must I meet to determine 
initial compliance for my covers and closed vent systems routing 
materials from storage vessels, reciprocating compressors and 
centrifugal compressor wet seal degassing systems?

    You must meet the applicable requirements of this section for each 
cover and closed vent system used to comply with the emission standards 
for your storage vessel, reciprocating compressor or centrifugal 
compressor affected facility.
    (a) Closed vent system requirements for reciprocating compressors 
and for

[[Page 79039]]

centrifugal compressor wet seal degassing systems. (1) You must design 
the closed vent system to route all gases, vapors, and fumes emitted 
from the material in the reciprocating compressor rod packing emissions 
collection system or the wet seal fluid degassing system to a control 
device or to a process that meets the requirements specified in Sec.  
60.5412(a) through (c).
* * * * *
    (b) * * *
    (3) Each storage vessel thief hatch shall be equipped, maintained 
and operated with a weighted mechanism or equivalent, to ensure that 
the lid remains properly seated. You must select gasket material for 
the hatch based on composition of the fluid in the storage vessel and 
weather conditions.
    (c) Closed vent system requirements for storage vessel affected 
facilities using a control device or routing emissions to a process.
* * * * *

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


Sec.  60.5412  What additional requirements must I meet for determining 
initial compliance with control devices used to comply with the 
emission standards for my storage vessel or centrifugal compressor 
affected facility?

* * * * *
    (d) Each control device used to meet the emission reduction 
standard in Sec.  60.5395(d) for your storage vessel affected facility 
must be installed according to paragraphs (d)(1) through (3) of this 
section, as applicable. As an alternative to paragraph (d)(1) of this 
section, you may install a control device model tested under Sec.  
60.5413(d), which meets the criteria in Sec.  60.5413(d)(11) and Sec.  
60.5413(e).
* * * * *

0
11. Section 60.5413 is amended by:
0
a. Revising the introductory text of paragraph (e); and
0
b. Adding paragraph (e)(7).
    The revision and addition read as follows:


Sec.  60.5413  What are the performance testing procedures for control 
devices used to demonstrate compliance at my storage vessel or 
centrifugal compressor affected facility?

* * * * *
    (e) Continuous compliance for combustion control devices tested by 
the manufacturer in accordance with paragraph (d) of this section. This 
paragraph applies to the demonstration of compliance for a combustion 
control device tested under the provisions in paragraph (d) of this 
section. Owners or operators must demonstrate that a control device 
achieves the performance requirements in (d)(11) of this section by 
installing a device tested under paragraph (d) of this section and 
complying with the criteria specified in paragraphs (e)(1) through (7) 
of this section.
* * * * *
    (7) Ensure that each enclosed combustion device is maintained in a 
leak free condition.

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


Sec.  60.5415  How do I demonstrate continuous compliance with the 
standards for my gas well affected facility, my centrifugal compressor 
affected facility, my stationary reciprocating compressor affected 
facility, my pneumatic controller affected facility, my storage vessel 
affected facility, and my affected facilities at onshore natural gas 
processing plants?

    (b) * * *
    (2) For each control device used to reduce emissions, you must 
demonstrate continuous compliance with the performance requirements of 
Sec.  60.5412(a) using the procedures specified in paragraphs (b)(2)(i) 
through (vii) of this section. If you use a condenser as the control 
device to achieve the requirements specified in Sec.  60.5412(a)(2), 
you must demonstrate compliance according to paragraph (b)(2)(viii) of 
this section. You may switch between compliance with paragraphs 
(b)(2)(i) through (vii) of this section and compliance with paragraph 
(b)(2)(viii) of this section only after at least 1 year of operation in 
compliance with the selected approach. You must provide notification of 
such a change in the compliance method in the next annual report, as 
required in Sec.  60.5420(b), following the change.
* * * * *
    (c) For each reciprocating compressor affected facility complying 
with Sec.  60.5385(a)(1) or (2), you must demonstrate continuous 
compliance according to paragraphs (c)(1) through (3) of this section. 
For each reciprocating compressor affected facility complying with 
Sec.  60.5385(a)(3), you must demonstrate continuous compliance 
according to paragraph (c)(4) of this section.
* * * * *
    (4) You must operate the rod packing emissions collection system 
under negative pressure and continuously comply with the closed vent 
requirements in Sec.  60.5411(a).
* * * * *

0
13. Section 60.5416 is amended by:
0
a. Revising the section heading;
0
b. Revising the introductory text;
0
c. Revising paragraph (a) introductory text; and
0
d. Revising paragraph (b) introductory text.
    The revisions read as follows:


Sec.  60.5416  What are the initial and continuous cover and closed 
vent system inspection and monitoring requirements for my storage 
vessel, centrifugal compressor and reciprocating compressor affected 
facilities?

    For each closed vent system or cover at your storage vessel, 
centrifugal compressor and reciprocating compressor affected facility, 
you must comply with the applicable requirements of paragraphs (a) 
through (c) of this section.
    (a) Inspections for closed vent systems and covers installed on 
each centrifugal compressor or reciprocating compressor affected 
facility. Except as provided in paragraphs (b)(11) and (12) of this 
section, you must inspect each closed vent system according to the 
procedures and schedule specified in paragraphs (a)(1) and (2) of this 
section, inspect each cover according to the procedures and schedule 
specified in paragraph (a)(3) of this section, and inspect each bypass 
device according to the procedures of paragraph (a)(4) of this section.
* * * * *
    (b) No detectable emissions test methods and procedures. If you are 
required to conduct an inspection of a closed vent system or cover at 
your centrifugal compressor or reciprocating compressor affected 
facility as specified in paragraphs (a)(1), (2), or (3) of this 
section, you must meet the requirements of paragraphs (b)(1) through 
(13) of this section.
* * * * *
0
14. Section 60.5420 is amended by:
0
a. Revising paragraph (b)(1)(iv);
0
b. Revising paragraph (b)(6)(ii);
0
c. Revising paragraphs (b)(6)(vi) and (vii);
0
d. Revising paragraphs (c)(1)(iii)(A) and (B);
0
e. Revising paragraph (c)(3)(ii); and
0
f. Revising paragraphs (c)(7), (8) and (9).
    The revisions read as follows:


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

* * * * *

[[Page 79040]]

    (b) * * *
    (1) * * *
    (iv) A certification by a certifying official of truth, accuracy, 
and completeness. This certification shall state that, based on 
information and belief formed after reasonable inquiry, the statements 
and information in the document are true, accurate, and complete.
* * * * *
    (6) * * *
    (ii) Documentation of the VOC emission rate determination according 
to Sec.  60.5365(e) for each storage vessel that became an affected 
facility during the reporting period or is returned to service during 
the reporting period.
* * * * *
    (vi) You must identify each storage vessel affected facility that 
is removed from service during the reporting period as specified in 
Sec.  60.5395(f)(1)(ii), including the date the storage vessel affected 
facility was removed from service.
    (vii) You must identify each storage vessel affected facility 
returned to service during the reporting period as specified in Sec.  
60.5395(f)(3), including the date the storage vessel affected facility 
was returned to service.
* * * * *
    (c) * * *
    (1) * * *
    (iii) * * *
    (A) For each gas well affected facility required to comply with the 
requirements of Sec.  60.5375(a), you must record: The location of the 
well; the API well number; the date and time of the onset of flowback 
following hydraulic fracturing or refracturing; the date and time of 
each attempt to direct flowback to a separator as required in Sec.  
60.5375(a)(1)(i); the date and time of each occurrence of returning to 
the initial flowback stage under Sec.  60.5375(a)(1)(i); and the date 
and time that the well was shut in and the flowback equipment was 
permanently disconnected, or the startup of production; the duration of 
flowback; duration of recovery to the flow line; duration of 
combustion; duration of venting; and specific reasons for venting in 
lieu of capture or combustion. The duration must be specified in hours 
of time.
    (B) For each gas well affected facility required to comply with the 
requirements of Sec.  60.5375(f), you must maintain the records 
specified in paragraph (c)(1)(iii)(A) of this section except that you 
do not have to record the duration of recovery to the flow line.
* * * * *
    (3) * * *
    (ii) Records of the date and time of each reciprocating compressor 
rod packing replacement, or date of installation of a rod packing 
emissions collection system and closed vent system as specified in 
Sec.  60.5385(a)(3).
* * * * *
    (7) A record of each cover inspection required under Sec.  
60.5416(a)(3) for centrifugal or reciprocating compressors or Sec.  
60.5416(c)(2) for storage vessels.
    (8) If you are subject to the bypass requirements of Sec.  
60.5416(a)(4) for centrifugal or reciprocating compressors or Sec.  
60.5416(c)(3) for storage vessels, a record of each inspection or a 
record each time the key is checked out or a record of each time the 
alarm is sounded.
    (9) If you are subject to the closed vent system no detectable 
emissions requirements of Sec.  60.5416(b) for centrifugal or 
reciprocating compressors, a record of the monitoring conducted in 
accordance with Sec.  60.5416(b).
* * * * *

0
15. Section 60.5430 is amended by:
0
a. Adding, in alphabetical order, definitions for the terms 
``Certifying official,'' ``Collection system,'' ``Initial flowback 
stage,'' ``Maximum average daily throughput,'' ``Recovered gas,'' 
``Recovered liquids,'' ``Removed from service,'' ``Returned to 
service,'' ``Separation flowback stage,'' ``Startup of production,'' 
and ``Well completion vessel;''
0
b. Removing the definition of ``Affirmative defense;'' and
0
c. Revising the definitions for ``Equipment'', ``Flowback,'' ``Routed 
to a process or route to a process,'' ``Salable quality gas,'' and 
``Storage vessel.''
    The revisions read as follows:


Sec.  60.5430  What definitions apply to this subpart?

* * * * *
    Certifying official means one of the following:
    (1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business 
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized 
representative of such person if the representative is responsible for 
the overall operation of one or more manufacturing, production, or 
operating facilities applying for or subject to a permit and either:
    (i) The facilities employ more than 250 persons or have gross 
annual sales or expenditures exceeding $25 million (in second quarter 
1980 dollars); or
    (ii) The Administrator is notified of such delegation of authority 
prior to the exercise of that authority. The Administrator reserves the 
right to evaluate such delegation;
    (2) For a partnership (including but not limited to general 
partnerships, limited partnerships, and limited liability partnerships) 
or sole proprietorship: A general partner or the proprietor, 
respectively. If a general partner is a corporation, the provisions of 
paragraph (1) of this definition apply;
    (3) For a municipality, State, Federal, or other public agency: 
Either a principal executive officer or ranking elected official. For 
the purposes of this part, a principal executive officer of a Federal 
agency includes the chief executive officer having responsibility for 
the overall operations of a principal geographic unit of the agency 
(e.g., a Regional Administrator of EPA); or
    (4) For affected facilities:
    (i) The designated representative in so far as actions, standards, 
requirements, or prohibitions under title IV of the Clean Air Act or 
the regulations promulgated thereunder are concerned; or
    (ii) The designated representative for any other purposes under 
part 60.
* * * * *
    Collection system means any infrastructure that conveys gas or 
liquids from the well site to another location for treatment, storage, 
processing, recycling, disposal or other handling.
* * * * *
    Equipment, as used in the standards and requirements in this 
subpart relative to the equipment leaks of VOC from onshore natural gas 
processing plants, means each pump, pressure relief device, open-ended 
valve or line, valve, and flange or other connector that is in VOC 
service or in wet gas service, and any device or system required by 
those same standards and requirements in this subpart.
* * * * *
    Flowback means the process of allowing fluids and entrained solids 
to flow from a natural gas well following a treatment, either in 
preparation for a subsequent phase of treatment or in preparation for 
cleanup and returning the well to production. The term flowback also 
means the fluids and entrained solids that emerge from a natural gas 
well during the flowback process. The flowback period begins when 
material introduced into the well during the treatment returns to the 
surface following hydraulic fracturing or refracturing. The flowback 
period ends when either the well is shut in and

[[Page 79041]]

permanently disconnected from the flowback equipment or at the startup 
of production. The flowback period includes the initial flowback stage 
and the separation flowback stage.
* * * * *
    Initial flowback stage means the period during a well completion 
operation which begins at the onset of flowback and ends at the 
separation flowback stage.
* * * * *
    Maximum average daily throughput means the earliest calculation of 
daily average throughput during the 30-day PTE evaluation period 
employing generally accepted methods.
* * * * *
    Recovered gas means gas recovered through the separation process 
during flowback.
    Recovered liquids means any crude oil, condensate or produced water 
recovered through the separation process during flowback.
* * * * *
    Removed from service means that a storage vessel affected facility 
has been physically isolated and disconnected from the process for a 
purpose other than maintenance in accordance with Sec.  60.5395(f)(1).
    Returned to service means that a Group 1 or Group 2 storage vessel 
affected facility that was removed from service has been:
    (1) Reconnected to the original source of liquids, connected in 
parallel to any storage vessel affected facility or has been used to 
replace any storage vessel affected facility; or
    (2) Installed in any location covered by this subpart and 
introduced with crude oil, condensate, intermediate hydrocarbon liquids 
or produced water.
    Routed to a process or route to a process means the emissions are 
conveyed via a closed vent system to any enclosed portion of a process 
where the emissions are predominantly recycled and/or consumed in the 
same manner as a material that fulfills the same function in the 
process and/or transformed by chemical reaction into materials that are 
not regulated materials and/or incorporated into a product; and/or 
recovered.
    Salable quality gas means natural gas that meets the flow line or 
collection system operator specifications, regardless of whether such 
gas is sold.
    Separation flowback stage means the period during a well completion 
operation when it is technically feasible for a separator to function. 
The separation flowback stage ends either at the startup of production, 
or when the well is shut in and permanently disconnected from the 
flowback equipment.
    Startup of production means the beginning of initial flow following 
the end of flowback when there is continuous recovery of salable 
quality gas and separation and recovery of any crude oil, condensate or 
produced water.
    Storage vessel means a tank or other vessel that contains an 
accumulation of crude oil, condensate, intermediate hydrocarbon 
liquids, or produced water, and that is constructed primarily of 
nonearthen materials (such as wood, concrete, steel, fiberglass, or 
plastic) which provide structural support. Two or more storage vessels 
connected in parallel are considered equivalent to a single storage 
vessel with throughput equal to the total throughput of the storage 
vessels connected in parallel. A well completion vessel that receives 
recovered liquids from a well after startup of production following 
flowback for a period which exceeds 60 days is considered a storage 
vessel under this subpart. A tank or other vessel shall not be 
considered a storage vessel if it has been removed from service in 
accordance with the requirements of Sec.  60.5395(f) until such time as 
such tank or other vessel has been returned to service. For the 
purposes of this subpart, the following are not considered storage 
vessels:
    (1) Vessels that are skid-mounted or permanently attached to 
something that is mobile (such as trucks, railcars, barges or ships), 
and are intended to be located at a site for less than 180 consecutive 
days. If you do not keep or are not able to produce records, as 
required by Sec.  60.5420(c)(5)(iv), showing that the vessel has been 
located at a site for less than 180 consecutive days, the vessel 
described herein is considered to be a storage vessel from the date the 
original vessel was first located at the site. This exclusion does not 
apply to a well completion vessel as described above.
    (2) Process vessels such as surge control vessels, bottoms 
receivers or knockout vessels.
    (3) Pressure vessels designed to operate in excess of 204.9 
kilopascals and without emissions to the atmosphere.
* * * * *
    Well completion vessel means a vessel that contains flowback during 
a well completion operation following hydraulic fracturing or 
refracturing. A well completion vessel may be a lined earthen pit, a 
tank or other vessel that is skid-mounted or portable. A well 
completion vessel that receives recovered liquids from a well after 
startup of production following flowback for a period which exceeds 60 
days is considered a storage vessel under this subpart.
* * * * *
[FR Doc. 2014-30630 Filed 12-30-14; 8:45 am]
BILLING CODE 6560-50-P