[Federal Register Volume 83, Number 199 (Monday, October 15, 2018)]
[Proposed Rules]
[Pages 52056-52107]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-20961]



[[Page 52055]]

Vol. 83

Monday,

No. 199

October 15, 2018

Part II





Environmental Protection Agency





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40 CFR Part 60





Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, 
and Modified Sources Reconsideration; Proposed Rule

  Federal Register / Vol. 83 , No. 199 / Monday, October 15, 2018 / 
Proposed Rules  

[[Page 52056]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2017-0483; FRL-9984-43-OAR]
RIN 2060-AT54


Oil and Natural Gas Sector: Emission Standards for New, 
Reconstructed, and Modified Sources Reconsideration

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: This action proposes reconsideration amendments to the new 
source performance standards (NSPS) at 40 Code of Federal Regulations 
(CFR) part 60, subpart OOOOa (2016 NSPS OOOOa). The Environmental 
Protection Agency (EPA) received petitions for reconsideration on the 
2016 NSPS OOOOa. In 2017, the EPA granted reconsideration on the 
fugitive emissions requirements, well site pneumatic pump standards, 
and the requirements for certification of closed vent systems by a 
professional engineer based on specific objections to these 
requirements. This action proposes amendments and clarifications as a 
result of reconsideration of these issues. The proposed amendments also 
address other issues raised for reconsideration and make technical 
corrections and amendments to further clarify the rule.

DATES: 
    Comments. Comments must be received on or before December 17, 2018. 
Under the Paperwork Reduction Act (PRA), comments on the information 
collection provisions are best assured of consideration if the Office 
of Management and Budget (OMB) receives a copy of your comments on or 
before December 17, 2018.
    Public Hearing. EPA is planning to hold at least one public hearing 
in response to this proposed action. Information about the hearing, 
including location, date, and time, along with instructions on how to 
register to speak at the hearing, will be published in a second Federal 
Register notice.

ADDRESSES: 
    Comments. Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2017-0483, at https://www.regulations.gov. Follow the online 
instructions for submitting comments. Once submitted, comments cannot 
be edited or removed from Regulations.gov. (See SUPPLEMENTARY 
INFORMATION for detail about how the EPA treats submitted comments.) 
Regulations.gov is our preferred method of receiving comments. However, 
other submission methods are accepted:
     Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2017-0483 in the subject line of the message.
     Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2017-0483.
     Mail: To ship or send mail via the United States Postal 
Service, use the following address: U.S. Environmental Protection 
Agency, EPA Docket Center, Docket ID No. EPA-HQ-OAR-2017-0483, Mail 
Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460.
     Hand/Courier Delivery: Use the following Docket Center 
address if you are using express mail, commercial delivery, hand 
delivery, or courier: EPA Docket Center, EPA WJC West Building, Room 
3334, 1301 Constitution Avenue NW, Washington, DC 20004. Delivery 
verification signatures will be available only during regular business 
hours.

FOR FURTHER INFORMATION CONTACT: For questions about this proposed 
action, contact Ms. Karen Marsh, Sector Policies and Programs Division 
(E143-05), Office of Air Quality Planning and Standards, U.S. 
Environmental Protection Agency, Research Triangle Park, North Carolina 
27711; telephone number: (919) 541-1065; fax number: (919) 541-0516; 
and email address: [email protected]. For information about the 
applicability of the new source performance standard (NSPS) to a 
particular entity, contact Ms. Marcia Mia, Office of Enforcement and 
Compliance Assurance, U.S. Environmental Protection Agency, EPA WJC 
South Building (Mail Code 2227A), 1200 Pennsylvania Avenue NW, 
Washington DC 20460; telephone number: (202) 564-7042; and email 
address: [email protected].

SUPPLEMENTARY INFORMATION: 
    Docket. The EPA has established a docket for this rulemaking under 
Docket ID No. EPA-HQ-OAR-2017-0483. All documents in the docket are 
listed in Regulations.gov. Although listed, some information is not 
publicly available, e.g., CBI or other information whose disclosure is 
restricted by statute. Certain other material, such as copyrighted 
material, is not placed on the internet and will be publicly available 
only in hard copy. Publicly available docket materials are available 
either electronically in Regulations.gov or in hard copy at the EPA 
Docket Center, Room 3334, EPA WJC West Building, 1301 Constitution 
Avenue NW, Washington, DC. The Public Reading Room 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 EPA Docket Center is (202) 566-1742.
    Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2017-0483. The EPA's policy is that all comments received will be 
included in the public docket without change and may be made available 
online at https://www.regulations.gov, including any personal 
information provided, unless the comment includes information claimed 
to be CBI or other information whose disclosure is restricted by 
statute. Do not submit information that you consider to be CBI or 
otherwise protected through https://www.regulations.gov or email. This 
type of information should be submitted by mail as discussed in the 
SUPPLEMENTARY INFORMATION section of this preamble..
    The EPA may publish any comment received to its public docket. 
Multimedia submissions (audio, video, etc.) must be accompanied by a 
written comment. The written comment is considered the official comment 
and should include discussion of all points you wish to make. The EPA 
will generally not consider comments or comment contents located 
outside of the primary submission (i.e., on the Web, cloud, or other 
file sharing system). For additional submission methods, the full EPA 
public comment policy, information about CBI or multimedia submissions, 
and general guidance on making effective comments, please visit https://www2.epa.gov/dockets/commenting-epa-dockets.
    The https://www.regulations.gov website allows you to submit your 
comments anonymously, which means the EPA will not know your identity 
or contact information unless you provide it in the body of your 
comment. If you send an email comment directly to the EPA without going 
through https://www.regulations.gov, your email address will be 
automatically captured and included as part of the comment that is 
placed in the public docket and made available on the internet. If you 
submit an electronic comment, the EPA recommends that you include your 
name and other contact information in the body of your comment and with 
any digital storage media you submit. If the EPA cannot read your 
comment due to technical difficulties and cannot contact you for 
clarification, the EPA may not be able to consider your comment. 
Electronic files should not include special characters or any form of 
encryption and be free of any defects or

[[Page 52057]]

viruses. For additional information about the EPA's public docket, 
visit the EPA Docket Center homepage at https://www.epa.gov/dockets.
    Submitting CBI. Do not submit information containing CBI to the EPA 
through https://www.regulations.gov or email. Clearly mark the part or 
all of the information that you claim to be CBI. For CBI information on 
any digital storage media that you mail to the EPA, mark the outside of 
the digital storage media as CBI and then identify electronically 
within the digital storage media the specific information that is 
claimed as CBI. In addition to one complete version of the comments 
that includes information claimed as CBI, you must submit a copy of the 
comments that does not contain the information claimed as CBI directly 
to the public docket through the procedures outlined in Instructions 
above. If you submit any digital storage media that does not contain 
CBI, mark the outside of the digital storage media clearly that it does 
not contain CBI. Information not marked as CBI will be included in the 
public docket and the EPA's electronic public docket without prior 
notice. Information marked as CBI will not be disclosed except in 
accordance with procedures set forth in 40 CFR part 2. Send or deliver 
information identified as CBI only to the following address: OAQPS 
Document Control Officer (C404-02), OAQPS, U.S. Environmental 
Protection Agency, Research Triangle Park, North Carolina 27711, 
Attention Docket ID No. EPA-HQ-OAR-2017-0483.
    Preamble Acronyms and Abbreviations. A number of acronyms and 
abbreviations are used 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:

AMEL Alternative Means of Emission Limitation
AVO Auditory, Visual, and Olfactory
BOE Barrels of Oil Equivalent
BSER Best System of Emissions Reduction
CAA Clean Air Act
CBI Confidential Business Information
CFR Code of Federal Regulations
CO2 Eq. Carbon dioxide equivalent
CVS Closed Vent System
EPA Environmental Protection Agency
FTE Full Time Equivalent
GHG Greenhouse Gases
GHGRP Greenhouse Gas Reporting Program
LDAR Leak Detection and Repair
NDE No Detectable Emissions
NEMS National Energy Modeling System
NSPS New Source Performance Standards
NTTAA National Technology Transfer and Advancement Act
OGI Optical Gas Imaging
OMB Office of Management and Budget
PE Professional Engineer
PRA Paperwork Reduction Act
PRV Pressure Relief Valve
REC Reduced Emissions Completion
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
TSD Technical Support Document
UMRA Unfunded Mandates Reform Act
VOC Volatile Organic Compounds
VRU Vapor Recovery Unit

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

I. Executive Summary
    A. Purpose of the Regulatory Action
    B. Summary of the Major Provisions of the Regulatory Action
    C. Costs and Benefits
II. General Information
    A. Does this action apply to me?
    B. What should I consider as I prepare my comments to the EPA?
    C. How do I obtain a copy of this document and other related 
information?
III. Background
IV. Legal Authority
V. The Proposed Action
VI. Discussion of Provisions Subject to Reconsideration
    A. Pneumatic Pumps
    B. Fugitive Emissions From Well Sites and Compressor Stations
    C. Professional Engineer Certifications
    D. Alternative Means of Emission Limitation (AMEL)
    E. Other Reconsideration Issues Being Addressed
VII. Implementation Improvements
    A. Reciprocating Compressors
    B. Storage Vessels
    C. Definition of Certifying Official
    D. Equipment in VOC Service Less Than 300 Hours/Year
    E. Reporting and Recordkeeping
    F. Technical Corrections and Clarifications
VIII. Impacts of This Proposed Rule
    A. What are the air impacts?
    B. What are the energy impacts?
    C. What are the compliance cost savings?
    D. What are the economic and employment impacts?
    E. What are the forgone benefits of the proposed standards?
IX. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Executive Order 13771: Reducing Regulations and Controlling 
Regulatory Costs
    C. Paperwork Reduction Act (PRA)
    D. Regulatory Flexibility Act (RFA)
    E. Unfunded Mandates Reform Act (UMRA)
    F. Executive Order 13132: Federalism
    G. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    H. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    I. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    J. National Technology Transfer and Advancement Act (NTTAA)
    K. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

I. Executive Summary

A. Purpose of the Regulatory Action

    The purpose of this action is to propose amendments to the NSPS for 
the oil and natural gas source category based on our reconsideration of 
those standards. On June 3, 2016, the EPA published a final rule titled 
``Oil and Natural Gas Sector: Emission Standards for New, 
Reconstructed, and Modified Sources; Final Rule,'' at 81 FR 35824 
(``2016 NSPS OOOOa''). The 2016 NSPS OOOOa established NSPS for 
emissions of greenhouse gases (GHG), in the form of limitations on 
methane, and volatile organic compounds (VOC) from the oil and natural 
gas sector.\1\ Following promulgation of the final rule, the 
Administrator received petitions for reconsideration of several 
provisions of the 2016 NSPS OOOOa.\2\ The EPA granted reconsideration 
on three issues: (1) Fugitive emissions requirements, (2) well site 
pneumatic pump standards, and (3) the requirements for certification of 
closed vent systems by a professional engineer based on specific 
objections to these requirements. This action addresses those specific 
issues raised for reconsideration, and addresses other implementation 
issues and technical corrections identified after promulgation of the 
rule.
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    \1\ Docket ID No. EPA-HQ-OAR-2010-0505.
    \2\ Copies of the petitions are provided in Docket ID No. EPA-
HQ-OAR-2017-0483.
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B. Summary of Major Provisions of the Regulatory Action

    The EPA proposes amendments and clarifications related to specific 
issues for which reconsideration was granted: Fugitive emissions 
requirements, well site pneumatic pump standards, the requirements for 
certification of closed vent systems, and the alternative means of 
emissions limitations (AMEL) provisions. The EPA also proposes 
additional amendments to clarify and streamline implementation of the 
rule. These proposed clarifications include the following provisions: 
Well completions (location of a separator during flowback, screenouts 
and coil tubing cleanouts), onshore natural gas processing plants 
(definition of capital expenditure and monitoring), storage vessels 
(maximum average daily throughput), and general clarifications 
(certifying official and recordkeeping

[[Page 52058]]

and reporting). Lastly, in addition to the proposed revisions 
addressing reconsideration and implementation issues, the EPA is 
proposing technical corrections of inadvertent errors in the final 
rule.
    Fugitive emissions requirements. The EPA is proposing several 
revisions to the requirements for the collection of fugitive emissions 
components located at well sites and the collection of fugitive 
emissions components located at compressor stations. First, the EPA is 
proposing to revise the monitoring frequencies: (1) Annual monitoring 
for non-low production well sites, (2) biennial (once every other year) 
monitoring for low production well sites, (3) co-proposing semiannual 
and annual monitoring for compressor stations, and (4) annual 
monitoring for compressor stations located on the Alaska North Slope. 
Additionally, the EPA is proposing that monitoring would no longer be 
required when all major production and processing equipment is removed 
from a well site such that it becomes a wellhead only well site. 
Consistent with the amendments promulgated on March 12, 2018,\3\ the 
EPA is proposing separate initial monitoring requirements for 
compressor stations located on the Alaska North Slope. These compressor 
stations would be required to conduct initial monitoring within 6 
months or by June 30, whichever is later, for compressor stations that 
startup between September and March or within 60 days for compressor 
stations that startup between April and August.
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    \3\ 83 FR 10628.
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    In addition to the proposed amendments related to the monitoring 
frequencies, the EPA is proposing various amendments to other 
requirements in the fugitive emissions monitoring program. The EPA is 
proposing to clarify that a modification has occurred at a well site 
that is a separate tank battery when a well that sends production to 
that tank battery has been modified. Given the proposed changes to 
monitoring frequencies, the EPA is proposing to remove the existing low 
temperature waiver for compressor stations.
    Several definitions related to fugitive emissions are included in 
this proposal. First, the EPA is proposing to add definitions for the 
terms ``first attempt at repair'' and ``repaired'' specific to the 
fugitive emissions requirements. Further, the EPA is proposing that a 
first attempt at repair must be completed within 30 days of identifying 
a component with fugitive emissions, with final repair completed within 
60 days. The proposed definition of ``repaired'' includes a requirement 
to verify the fugitive emissions are repaired before the repair is 
completed. We are also proposing revisions to the definition of ``well 
site'' to include exclusions for third party equipment located 
downstream of the custody meter assembly and saltwater disposal 
facilities. Finally, we are proposing specific changes to the fugitive 
emissions monitoring plan, including alternative requirements to the 
site plan and observation path.
    Pneumatic pumps. The EPA is proposing to expand the technical 
infeasibility provision to all well sites by eliminating the 
categorical distinction between greenfield sites and non-greenfield 
sites (and the categorical restriction of the technical infeasibility 
provision to existing sites) for the pneumatic pump requirements. The 
proposal would avoid the potential of requiring a greenfield site to 
control the pneumatic pump emissions should it be technically 
infeasible to do so, while having no impact on the compliance 
obligations of other greenfield sites that do not have this issue.
    Professional Engineer (PE) certifications. The EPA is proposing to 
amend the certification requirements for closed vent system (CVS) 
design and technical infeasibility for pneumatic pumps by allowing 
certification by either a PE or an in-house engineer with expertise on 
the design and operation of the CVS or pneumatic pump.
    Alternative means of emission limitation (AMEL). The 2016 NSPS 
OOOOa contains provisions for owners and operators to request an AMEL 
for specific work practice standards in the rule, covering well 
completions, reciprocating compressors, and the collection of fugitive 
emissions components located at well sites and compressor stations. An 
owner or operator can request an AMEL by submitting data that 
demonstrate the alternative will achieve at least equivalent emission 
reductions as the requirements in the rule, among other requirements 
such as initial and on-going compliance monitoring. The specific 
requirements for this request are outlined in 40 CFR 60.5398a. For the 
2016 NSPS OOOOa, these alternatives could be based on emerging 
technologies (e.g., for fugitive emissions, technologies other than OGI 
or Method 21) or requirements under state or local programs. The EPA is 
proposing to amend the language in 40 CFR 60.5398a for incorporation of 
emerging technologies, and to add a separate section at 40 CFR 60.5399a 
to take into account existing state programs.
    Location of a Separator During Flowback. The 2016 NSPS OOOOa 
requires the owner or operator to have a separator onsite during the 
entirety of the flowback period. The EPA is proposing to amend 40 CFR 
60.5375a(a)(1)(iii) to clarify that the separator may be located at the 
well site or near to the well site so that it is able to commence 
separation flowback, as required by the rule. This proposed revision is 
being made to alleviate the potential interpretation that the separator 
must be located on the well site, which was not the intent of the rule.
    Screenouts and Coil Tubing Cleanouts. Petitioners requested 
clarification as to whether screenouts and coil tubing cleanouts are 
regulated as part of flowback. Based on the EPA's reassessment of this 
issue, the EPA is correcting previous guidance on this issue to 
acknowledge that screenouts and coil tubing cleanouts are not a part of 
flowback; rather, they are functional processes that allow for flowback 
to begin. To clarify this point, the EPA is proposing to revise the 
definition of flowback to expressly exclude these processes to avoid 
any future confusion. In addition, the EPA is proposing definitions for 
these processes (i.e., plug drill-outs, flowback routed through 
permanent separators).
    Capital Expenditure. The EPA is proposing to correct the definition 
of ``capital expenditure'' promulgated at 40 CFR 60.5430a by replacing 
the reference to the year 2011 with the year 2015 in the formula in 
paragraph (2) of the definition. The promulgated definition is relevant 
to the equipment leaks standards for onshore natural gas processing 
plants that were originally promulgated in 1985 in 40 CFR part 60, 
subpart KKK, updated in 2012 in 40 CFR part 60, subpart OOOO, and 
carried over in 2016 in 40 CFR part 60, subpart OOOOa. The EPA is, 
therefore, amending the definition to address an inadvertent 
mathematical issue for affected facilities constructed in 2015 while 
leaving the calculation method intact for other affected facilities.
    Maximum Average Daily Throughput. Pursuant to 40 CFR 60.5365a(e), 
owners and operators must calculate potential emissions from storage 
vessels in order to determine if control requirements apply. This 
calculation is based on the ``maximum average daily throughput''. This 
value was intended to represent the maximum of the average daily 
production rates in the first 30-day period to each individual storage 
vessel. In order to address petitioner requests for clarification, the 
EPA is proposing to further clarify in this notice when and

[[Page 52059]]

how daily production may be averaged in determining daily throughput. 
The EPA is proposing to revise the definition to clarify that the 
maximum average daily throughput refers to the maximum average daily 
throughput for an individual storage vessel over the days that 
production is routed to that storage vessel during the 30-day 
evaluation period.
    Certifying Official. The EPA is proposing to amend this definition 
to remove the reference to permits to clarify that the requirements of 
the NSPS are not associated with a permitting program.
    Onshore Natural Gas Processing Plant Monitoring Exemption. The EPA 
is proposing to amend the requirements for equipment leaks at onshore 
natural gas processing plants. Specifically, the EPA is proposing to 
include an exemption from monitoring for certain equipment that an 
owner or operator designates as being in VOC service less than 300 hr/
yr.
    Recordkeeping and Reporting Requirements. The EPA is proposing to 
streamline certain reporting and recordkeeping requirements to reduce 
burden on the regulated industry. The proposed changes can be seen in 
section 60.5420a.

C. Costs and Benefits

    The EPA has projected the cost savings, emissions changes, and 
forgone benefits that may result from this proposed action. The 
projected cost savings and forgone benefits are presented in the RIA 
supporting this proposal. The RIA focuses on the elements of the 
proposal--the provisions related to fugitive emissions requirements and 
certification by a professional engineer--that are likely to result in 
quantifiable cost or emissions changes compared to a baseline that 
includes the 2016 NSPS OOOOa requirements.
    The effects of this proposed regulation are estimated for all 
sources that are projected to change compliance activities under this 
proposed rule for the analysis years 2019 through 2025. The RIA also 
presents the present value (PV) and equivalent annualized value (EAV) 
of costs, benefits and net benefits of the proposed action in 2016 
dollars. Cost savings include the forgone value associated with the 
decrease in natural gas recovery as a result of this proposed action.
    A summary of the key results of the co-proposed option under 
semiannual monitoring at compressor stations presented as shown in the 
RIA can be found in Table 1. Table 1 presents the PV and EAV, estimated 
using discount rates of 7 and 3 percent, of the changes in benefits, 
costs, and net benefits, as well as the change in emissions under the 
co-proposed option. In the following tables, the EPA refers to the cost 
savings as the ``benefits'' of this proposed action and the forgone 
benefits as the ``costs'' of this proposed action. The net benefits are 
the benefits (cost savings) minus the costs (forgone benefits).\4\
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    \4\ For information on the cost savings and forgone emission 
reductions associated with the co-proposed option assuming annual 
fugitives monitoring at compressor stations, see section 2 of the 
RIA.

    Table 1--Cost Savings, Forgone Benefits and Increase in Emissions of the Co-Proposed Option 3 (Semiannual
                          Monitoring) Compared to the 2018 Baseline, 2019 Through 2025
                                                [Millions 2016$]
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                                                                7%                              3%
                                                 ---------------------------------------------------------------
                                                                    Equivalent                      Equivalent
                                                   Present value    annualized     Present value    annualized
                                                                       value                           value
----------------------------------------------------------------------------------------------------------------
Benefits (Total Cost Savings)...................            $380             $66            $484             $75
    Cost Savings................................             429              74             546              85
    Forgone Value of Product Recovery...........              48             8.4              62             9.6
Costs (Forgone Domestic Climate Benefits) \1\...            13.5             2.3              54             8.3
Net Benefits \2\................................             367              64             431              67
                                                 ---------------------------------------------------------------
Emissions.......................................                           Total Change
                                                 ---------------------------------------------------------------
    Methane (short tons)........................                              380,000
    VOC.........................................                              100,000
    HAP.........................................                               3,800
    Methane (million metric tons CO2E)..........                                8.5
----------------------------------------------------------------------------------------------------------------
\1\ The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-CH4). SC-CH4
  values represent only a partial accounting of domestic climate impacts from methane emissions. See section 3.3
  of the RIA for more discussion.
\2\ Estimates may not sum due to independent rounding.

    The estimated costs (forgone benefits) include the monetized 
climate effects of the projected increase in methane emissions under 
the proposal. The EPA also expects there will be increases in VOC and 
HAP emissions under the proposal. While the EPA expects that the 
forgone VOC emission reductions may also degrade air quality and 
adversely affect health and welfare effects associated with exposure to 
ozone, PM2.5, and HAP, data limitations prevent the EPA from 
quantifying forgone VOC-related health benefits.
    Compared to the estimated cost savings of the co-proposed option 
under semiannual fugitive emissions monitoring at compressor stations, 
the co-proposed option assuming annual monitoring results in greater 
cost savings, as well as greater total emissions. Assuming a 7 percent 
discount rate, and including the forgone value of product recovery, the 
present value of the total cost savings from 2019 through 2025 are 
about $43 million greater under the co-proposed option assuming annual 
monitoring than under the co-proposed option assuming semiannual 
monitoring. This is associated with an increase in the equivalent 
annualized value of total cost savings of about $7.5 million per year 
in comparison to the co-proposed option under semiannual monitoring.
    Decreasing fugitive emissions monitoring frequency at compressor 
stations from semiannual to annual also

[[Page 52060]]

results in a greater increase in total emissions. Over 2019 through 
2025, the increase in fugitive emissions under the co-proposed option 
assuming annual monitoring are about 100,000 short tons greater for 
methane, 24,000 tons greater for VOC, and 890 tons greater for HAP than 
those under the co-proposed option assuming semiannual fugitive 
emissions monitoring. A summary of the cost savings and forgone 
emission reductions associated with the co-proposed option of annual 
fugitive emissions monitoring at compressor stations is located in 
section 2.5.2 of the RIA.

II. General Information

A. Does this action apply to me?

    Categories and entities potentially affected by this action 
include:

      Table 2--Industrial Source Categories Affected by This Action
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                                                  Examples of regulated
            Category             NAICS code \1\          entities
------------------------------------------------------------------------
Industry.......................          211120  Crude Petroleum
                                                  Extraction.
                                         211130  Natural Gas 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 provides a 
guide for readers regarding entities likely to be regulated by this 
action. This table lists the types of entities that the EPA is now 
aware could potentially be affected by this action. Other types of 
entities not listed in the table could also be regulated. To determine 
whether your entity is regulated by this action, you should carefully 
examine the applicability criteria found in the final rule. If you have 
questions regarding the applicability of this action to a particular 
entity, consult the person listed in the FOR FURTHER INFORMATION 
CONTACT section, your air permitting authority, or your EPA Regional 
representative listed in 40 CFR 60.4 (General Provisions).

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

    We seek comment only on the aspects of the proposed NSPS for the 
oil and natural gas sector specifically identified in this notice. We 
are not opening for reconsideration any other provisions of the NSPS at 
this time.
    Do not submit information containing CBI to the EPA through https://www.regulations.gov or email. Send or deliver information identified 
as CBI only to the following address: OAQPS Document Control Officer 
(C404-02), Office of Air Quality Planning and Standards, U.S. 
Environmental Protection Agency, Research Triangle Park, North Carolina 
27711, Attention: Docket ID Number EPA-HQ-OAR-2017-0483. Clearly mark 
the part or all of the information that you claim to be CBI. For CBI 
information in a disk or CD-ROM that you mail to the EPA, mark the 
outside of the disk or CD-ROM as CBI and then identify electronically 
within the disk or CD-ROM the specific information that is claimed as 
CBI. In addition to one complete version of the comment that includes 
information claimed as CBI, a copy of the comment that does not contain 
the information claimed as CBI must be submitted for inclusion in the 
public docket. Information so marked will not be disclosed except in 
accordance with procedures set forth in 40 CFR part 2.

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

    In addition to being available in the docket, an electronic copy of 
the proposed action is available on the internet. Following signature 
by the Administrator, the EPA will post a copy of this proposed action 
at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry. Additional information is also available at the same website.

III. Background

    On June 3, 2016, the EPA published a final rule titled ``Oil and 
Natural Gas Sector: Emission Standards for New, Reconstructed, and 
Modified Sources; Final Rule,'' at 81 FR 35824 (``2016 NSPS OOOOa''). 
The 2016 NSPS OOOOa established NSPS for greenhouse gas and volatile 
organic compound (VOC) emissions from the oil and natural gas sector. 
For further information on the 2016 NSPS OOOOa, see 81 FR 35824 (June 
3, 2016) and associated Docket ID No. EPA-HQ-OAR-2010-0505. Following 
promulgation of the final rule, the Administrator received petitions 
for reconsideration of several provisions of the 2016 NSPS OOOOa. 
Copies of the petitions are provided in rulemaking docket EPA-HQ-OAR-
2017-0483. A number of states and industry associations sought judicial 
review of the rule, and the litigation is currently being held in 
abeyance.
    In a letter to petitioners dated April 18, 2017, the EPA granted 
reconsideration of the fugitive emissions requirements at well sites 
and compressor stations.\5\ In a subsequent notice, the EPA granted 
reconsideration of two additional issues: Well site pneumatic pump 
standards and the requirements for certification of closed vent systems 
(CVS) by a professional engineer.\6\ This action proposes amendments 
and clarifications to address these issues, and grants reconsideration 
and proposes amendments to address several additional reconsideration 
issues, detailed in Section VII below. In addition, since the 
publication of the 2016 NSPS OOOOa, the EPA has received numerous 
questions relative to the implementation of the 2016 NSPS OOOOa 
requirements. This action also addresses these broad implementation 
issues that have been brought to the EPA's attention. The EPA is 
addressing these issues at the same time to provide clarity and 
certainty for the public and the regulated community with regard to 
these requirements.
---------------------------------------------------------------------------

    \5\ See Docket ID No. EPA-HQ-OAR-2010-0505-7730.
    \6\ 82 FR 25730.
---------------------------------------------------------------------------

IV. Legal Authority

    This action, which proposes certain amendments to the 2016 NSPS 
OOOOa, is based on the same legal authorities as those for the 
promulgation of that rule. The EPA promulgated the 2016 NSPS OOOOa 
pursuant to its standard setting authority under section 111(b)(1)(B) 
of the Clean Air Act (CAA) and in accordance with the rulemaking

[[Page 52061]]

procedures in section 307(d) of the CAA. Section 111(b)(1)(B) requires 
the EPA to issue ``standards of performance'' for new sources in a 
category listed by the Administrator based on a finding that this 
category of stationary sources causes or contributes significantly to 
air pollution which may reasonably be anticipated to endanger public 
health or welfare. CAA Section 111(a)(1) defines ``a standard of 
performance'' as ``a standard for emissions of air pollutants which 
reflects the degree of emission limitation achievable through the 
application of the best system of emission reduction which (taking into 
account the cost of achieving such reduction and any nonair quality 
health and environmental impact and energy requirement) the 
Administrator determines has been adequately demonstrated.'' This 
definition makes clear that the standard of performance must be based 
on controls that constitute ``the best system of emission reduction . . 
. adequately demonstrated.'' The standard that the EPA develops, based 
on the best system of emission reduction (BSER), is commonly a 
numerical emissions limit, expressed as a performance level (e.g., a 
rate-based standard). However, CAA section 111(h)(1) authorizes the 
Administrator to promulgate a work practice standard or other 
requirements, which reflects the best technological system of 
continuous emission reduction, if it is not feasible to prescribe or 
enforce an emissions standard. This action includes proposed amendments 
to the fugitive emissions standards for well sites and compressor 
stations, which are work practice standards promulgated pursuant to CAA 
section 111(h)(1)(A). 81 FR 35829.
    The proposed amendments in this notice result from the EPA's 
reconsideration of various aspects of the 2016 NSPS OOOOa. Agencies 
have inherent authority to reconsider past decisions and to revise, 
replace, or repeal a decision to the extent permitted by law and 
supported by a reasoned explanation. FCC v. Fox Television Stations, 
Inc., 556 U.S. 502, 515 (2009); Motor Vehicle Mfrs. Ass'n v. State Farm 
Mutual Auto. Ins. Co., 463 U.S. 29, 42 (1983) (``State Farm''). ``The 
power to decide in the first instance carries with it the power to 
reconsider.'' Trujillo v. Gen. Elec. Co., 621 F.2d 1084, 1086 (10th 
Cir. 1980); see also, United Gas Improvement Co. v. Callery Properties, 
Inc., 382 U.S. 223, 229 (1965); Mazaleski v. Treusdell, 562 F.2d 701, 
720 (D.C. Cir. 1977).

V. The Proposed Action

    In this action, we are proposing amendments and clarifications on 
the following set of issues as a result of reconsideration: (1) 
Pneumatic pump requirements; (2) fugitive emissions requirements at 
well sites and compressor stations; (3) professional engineering 
certification for CVS design and pneumatic pump technical 
infeasibility; and (4) alternative means of emissions limitations. In 
addition, we are proposing amendments to a number of other aspects of 
2016 NSPS OOOOa, including well completion requirements and 
requirements at onshore natural gas processing plants. This action also 
addresses broad implementation issues that have been brought to the 
EPA's attention. Finally, we are proposing to correct technical errors 
that were inadvertently included in the final rule.
    This document is limited to the specific issues identified in this 
notice. We will not respond to any comments addressing any other 
provisions of the 2016 NSPS OOOOa.

VI. Discussion of Provisions Subject to Reconsideration

    As summarized above, the EPA is proposing to address a number of 
issues that have been raised by different stakeholders through several 
administrative petitions for reconsideration of the 2016 NSPS OOOOa. 
The following sections present the issues raised by the petitioners 
that the EPA is addressing in this action and how the EPA proposes to 
resolve the issues.

A. Pneumatic Pumps

    The 2016 NSPS OOOOa includes a technical infeasibility provision 
from the well site pneumatic pump requirements for circumstances such 
as insufficient pressure or control device capacity. 81 FR 35850. This 
provision was categorically unavailable for pneumatic pumps at 
greenfield sites (defined as a site, other than a natural gas 
processing plant, which is entirely new construction). Id. Petitioners 
stated that the term greenfield site was inadequately defined. For 
example, one petitioner questioned whether the term ``new'' as used in 
this definition is synonymous to how that term is defined in section 
111 of the CAA. Additional questions included whether a greenfield 
remains forever a greenfield, considering that site designs may change 
by the time that a new control or pump is installed (which may be years 
later). Petitioners also objected to the EPA's assumption that the 
technical infeasibility encountered at existing well sites can be 
addressed when ``new'' sites are developed.
    We previously concluded that circumstances, such as insufficient 
pressure or control device capacity, that could otherwise make control 
of a pneumatic pump technically infeasible at an existing location 
could be addressed in the design and construction of a new site and 
therefore new sites were categorically ineligible for the technical 
feasibility provision. 81 FR 35850. However, petitioners have raised 
the concern that even at a greenfield site, there may be unique process 
or control design requirements that may not be compatible with 
controlling pneumatic pump emissions. Petitioners contend that such 
circumstances include the following:
     A new site design may require only a high-pressure flare 
to control emergency and maintenance blowdowns, and it is not feasible 
for a low pressure pneumatic pump discharge to be routed to such a 
flare; and
     A new site design may require only a small boiler or 
process heater, but such boiler or process heater could be insufficient 
to control pneumatic pumps emissions and routing pneumatic pump 
emissions to the boiler or process heater could result in safety trips 
and burner flame instability.
    The EPA solicits comment on whether the scenarios described above 
present circumstances where control of a pneumatic pump may be 
technically infeasible despite the site being newly designed and 
constructed, as well as other examples of technical infeasibility for a 
greenfield site. While the additional cost in the design and 
construction of a new site for selecting a control device that can 
control additional pneumatic pump emissions (e.g., selecting a flare or 
slightly larger boiler that can accommodate such flows) in many cases 
will not be high, the scenarios raised in petitions for reconsideration 
suggest that there might be cases of technical infeasibility at a 
greenfield site despite design and construction choices. We are 
therefore proposing to expand the technical infeasibility provision to 
all well sites by eliminating the categorical distinction between 
greenfield sites and non-greenfield sites (and the categorical 
restriction of the technical infeasibility provision to existing sites) 
for the pneumatic pump requirements. The proposal would avoid the 
potential of requiring a greenfield site to control the pneumatic pump 
emissions should it be technically infeasible to do so, while having no 
impact on the compliance obligations of other greenfield sites that

[[Page 52062]]

do not have this issue. We solicit comment on this proposal. In 
addition, we solicit comment on site and control configurations that 
could present technical infeasibility scenarios at a new construction 
site. We also solicit comment on cost information related to the 
additional costs related to selecting a control that can accommodate 
pneumatic pump emissions in addition to the control's primary purpose 
at a new construction site.

B. Fugitive Emissions From Well Sites and Compressor Stations

1. Monitoring Frequency
    Monitoring Frequency for Well Sites. The 2016 NSPS OOOOa requires 
initial monitoring within 60 days of the startup of production and 
subsequent semiannual monitoring of the collection of fugitive 
emissions components located at all well sites. We received petitions 
requesting changes to several aspects of fugitive monitoring 
frequencies to provide: (1) A pathway to less frequent monitoring, (2) 
an exemption for low production well sites, and (3) an exemption for 
well sites located on the Alaskan North Slope. As discussed in detail 
in the following subsections, the EPA is proposing the following 
amendments to the fugitive emissions monitoring frequency for the 
collection of fugitive emissions components located at well sites:
     Annual monitoring would be required at well sites with 
average combined oil and natural gas production for the wells at the 
site greater than or equal to 15 barrels of oil equivalent (boe) per 
day averaged over the first 30 days of production (``non-low production 
well sites'');
     Biennial monitoring (once every other year) would be 
required for well sites with average combined oil and natural gas 
production for the wells at the site less than 15 boe per day averaged 
over the first 30 days of production (``low production well sites''); 
and
     Monitoring may be stopped once all major production and 
processing equipment is removed from a well site such that it contains 
only one or more wellheads.
    Non-low Production Well Sites. The 2016 NSPS OOOOa requires initial 
and semiannual fugitive emissions monitoring using optical gas imaging 
(OGI) for the collection of fugitive emissions components located at 
well sites. In the 2016 NSPS OOOOa preamble, the EPA stated that ``both 
semiannual and annual monitoring remain cost-effective for reducing GHG 
(in the form of methane) and VOC emissions.'' 81 FR 35855. Several 
petitioners requested that the EPA reconsider the frequency of 
monitoring,\7\ with one petitioner asserting that the EPA's cost-
effectiveness analysis is not accurate and should be revised.\8\ In 
response, the EPA has reviewed the data provided by the petitioner, as 
well as other data that have become available since promulgation of the 
2016 NSPS OOOOa. Based on this review, we have updated our model plant 
analysis. Although under the updated analysis, semiannual monitoring 
may appear to be cost-effective, we have identified several areas of 
our analysis that indicate we may have overestimated the emission 
reductions and, therefore, the cost effectiveness, due to gaps in 
available data and factors that may bias the analysis towards 
overestimation of reductions. Therefore, the semiannual monitoring may 
not be as cost-effective as presented, and the EPA is proposing to 
revise the monitoring frequency to require annual fugitive emissions 
monitoring at non-low production well sites. Provided below is a 
detailed discussion of (1) how we revised the model plant analysis 
based on our review of the data; and (2) areas of our analysis that 
indicate we may have overestimated the emission reductions and in turn 
the cost effectiveness of the monitoring frequencies analyzed.
---------------------------------------------------------------------------

    \7\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.
    \8\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682.
---------------------------------------------------------------------------

    First, the EPA reviewed the available information and determined 
several updates were necessary to the non-low production well site 
model plants. As described in the TSD, the EPA evaluated the cost-
effectiveness of the fugitive emissions monitoring program using model 
plants that represent average equipment and fugitive emissions 
component counts per well site.\9\ We updated the model plants based on 
updates in the Greenhouse Gas Inventory (GHGI) program for major 
equipment counts at well sites. Specifically, the number of meters/
piping decreased from 3 to 2 for the gas well site and oil with 
associated gas well site model plants. No changes were made to the oil 
well site model plant as a result of updates in the GHGI. The 
petitioner provided information that included counts for major 
production and processing equipment located at well sites.\10\ For 
example, the data included the count of separators per well site and 
demonstrated that, on average, there are 3 separators per natural gas 
well site and oil well site. In comparison, the EPA model plants 
include 2 separators per natural gas well site and 1 separator per oil 
well site. While similar differences were observed for other types of 
major production and processing equipment, we maintained the estimates 
derived from the GHGI because the data included in the GHGI is the most 
up-to-date information available and the petitioner was not able to 
provide information on when the fugitive emissions monitoring occurred 
at the well sites presented in their data set.
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    \9\ See TSD for additional information.
    \10\ See memorandum EPA Analysis of Well Site Fugitive Emissions 
Monitoring Data Provided by API located at Docket ID No. EPA-HQ-OAR-
2017-0483. April 17, 2018.
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    In addition to updates made based on updates to the GHGI, we also 
added one controlled storage vessel per model plant and an emissions 
factor for pressure relief devices (PRDs), such as thief hatches and 
pressure relief valves (PRVs) from these controlled storage vessels 
because controlled storage vessels that are not affected facilities 
subject to the requirements in 40 CFR 60.5395a are considered fugitive 
emissions components. In evaluating the quantity of fugitive emissions 
from storage vessels, we considered data indicating that the frequency 
of fugitive emissions from controlled storage vessels may be much 
higher than that for other fugitive emissions components.\11\ For 
purposes of the model plant, we are adding one controlled storage 
vessel with one PRD. We recognize that many well sites may have more 
controlled storage vessels, suggesting that we should add more than one 
controlled storage vessel to the model plant, while other well sites 
may not have any controlled storage vessels that are subject to 
fugitive emissions monitoring. The data provided by the petitioner \12\ 
did not include the number of storage vessels at natural gas well 
sites, but included an estimated average of 7 storage vessels per oil 
well site. However, the data was not provided in a form sufficient to 
indicate whether these storage vessels are controlled or subject to 
fugitive emissions monitoring. Therefore, we did not incorporate any 
information from the petitioner related to storage vessel counts at 
well sites. We are soliciting comment on our assumption of one 
controlled storage vessel per well site subject to fugitive emissions 
requirements and data to further refine the model plant with

[[Page 52063]]

regards to controlled storage vessel fugitive emissions.
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    \11\ See the TSD for additional information on the fugitive 
emissions from storage vessels.
    \12\ See memorandum EPA Analysis of Well Site Fugitive Emissions 
Monitoring Data Provided by API located at Docket ID No. EPA-HQ-OAR-
2017-0483. April 17, 2018.
---------------------------------------------------------------------------

    The emissions factor used for PRDs on controlled storage vessels 
was derived from a study that conducted aerial surveys for emissions at 
oil and gas production sites located in seven basins across the United 
States.\13\ We did not update the average emissions factors for other 
fugitive emissions components based on information in this study 
because the study stated that emissions from individual components, 
such as valves, could not be identified during the surveys. In this 
study, helicopter-based OGI monitoring was performed at 8,220 well 
sites. A total of 494 fugitive emission sources were identified at 327 
sites, averaging approximately 1.5 fugitive sources per site. Fugitive 
emissions \14\ from storage vessels accounted for 92 percent of the 
total fugitive sources, with 198 fugitive sources associated with 
storage vessel PRVs and 257 fugitive sources associated with thief 
hatches, though it was unclear from the study if all of these storage 
vessels were equipped with a CVS that routes emissions to a control 
device. The estimated detection limit for the OGI instrument observed 
by this study was 1 gram per second (g/s) for heavier hydrocarbons and 
3 g/s for methane.\15\ Based on this information, we used the 1 g/s 
estimated emission rate in combination with the frequency of storage 
vessel emissions identified in the study to estimate emissions from 
thief hatches for purposes of the model plants. However, we acknowledge 
that the emissions are likely underestimated when using this 
information because small or medium sized emissions would not be 
visible during an aerial OGI survey. Additional information about the 
model plants and analysis is included in the Background Technical 
Support Document (TSD) located at Docket ID No. EPA-HQ-OAR-2017-0483.
---------------------------------------------------------------------------

    \13\ Lyon, David R., et al., Aerial Surveys of Elevated 
Hydrocarbon Emissions from Oil and Gas Production Sites. 
Environmental Science and Technology 2016, 50, 4877-4886.
    \14\ It was difficult for the Lyon, David R., et al., study to 
attribute emissions from storage vessels to specific malfunctions or 
normal operations. The study predicted liquid unloading events and 
stuck open separator dump valves would contribute less than 0.1% of 
the emissions detected for each event. The other 99.8% of the 
storage vessel emissions were not characterized by the study. See 
Id. at pages 4882-4883.
    \15\ Id.
---------------------------------------------------------------------------

    Baseline emissions (uncontrolled) for the other fugitive emissions 
components were estimated using average emissions factors for oil and 
gas production operations, found in Table 2-4 of the Protocol for 
Equipment Leak Emission Estimates (1995 Protocol).\16\ These average 
emissions factors are used when screening data are not available, as is 
the case when OGI is used as the monitoring instrument,\17\ and provide 
an average emission rate for the collection of fugitive emissions 
components at the site. For example, the average emissions factors can 
be used to estimate emissions from the collection of all valves at the 
site, instead of needing to estimate emissions from each individual 
valve and averaging the emissions across the collection of valves. The 
petitioner presented updated emissions factors for these fugitive 
emissions components.\18\ The petitioner attempted to create new 
average emissions factors by using the newly presented 0.4 percent for 
identified fugitive emissions and scaling the average emissions factors 
documented in the 1995 Protocol. However, in creating these new average 
emissions factors, the petitioner used correlation equations in the 
1995 Protocol. These correlation equations were derived from leak 
studies using Method 21 of Appendix A-7 to Part 60 (``Method 21'') and 
are based on specific leak definitions when using Method 21. The 
correlation equations do not apply to monitoring using OGI, as it is 
not possible to correlate OGI detection capabilities with a Method 21 
instrument reading provided in parts per million (ppm). Correlation 
equations for OGI do not currently exist and would be difficult to 
develop because OGI either sees fugitive emissions or it does not; 
there is no emissions scale as there is with Method 21. As such, at 
best, only average factors for visualized emissions and no visualized 
emissions would be possible (similar to the ``leak'' and ``no leak'' 
factors in the 1995 Protocol specific to Method 21). In order to 
develop such factors, an extensive dataset of OGI data and bagging 
studies, similar to the studies used to develop the factors presented 
in the 1995 Protocol would be needed. Therefore, the approach of 
scaling emissions factors as presented by the petitioner for the non-
storage vessel PRD fugitive emissions components does not adequately 
address the differences in emissions correlations when using Method 21 
and OGI, and therefore we have not evaluated the cost of control using 
the scaled factors presented by the petitioner. Additional information 
on our evaluation of the scaled emissions factors is included in the 
memorandum EPA Analysis of Well Site Fugitive Emissions Monitoring Data 
Provided by API, located at Docket ID No. EPA-HQ-OAR-2017-0483. Thus, 
we continue to use the average emissions factors in the 1995 Protocol 
to calculate emissions in the model plants for the fugitive emissions 
components, excluding controlled storage vessel PRDs. We are soliciting 
comment on the use of the average emissions factors and additional 
information or alternative methodologies that should be considered to 
refine our estimates of fugitive emissions.
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    \16\ U.S. Environmental Protection Agency, Protocol for 
Equipment Leak Emission Estimates. Table 2-4. November 1995 (EPA-
453/R-95-017).
    \17\ OGI instruments that are currently widely available provide 
a qualitative indication of emissions and do not provide an 
indication of the concentration levels of fugitive emissions. 
However, we recognize that quantitative OGI is a new technological 
development that may allow estimations of mass emission rates in the 
future.
    \18\ See memorandum EPA Analysis of Well Site Fugitive Emissions 
Monitoring Data Provided by API located at Docket ID No. EPA-HQ-OAR-
2017-0483. April 17, 2018.
---------------------------------------------------------------------------

    While updating the model plants, the EPA identified three areas of 
the analysis that raise concerns regarding the emissions reductions: 
(1) The percent emission reduction achieved by OGI, (2) the occurrence 
rate of fugitive emissions at different monitoring frequencies, and (3) 
the initial percentage of fugitive emissions components identified with 
fugitive emissions. As described in detail below, the EPA acknowledges 
that emission reductions may have been overestimated, even in our 
updated model plants.
    First, several stakeholders have raised concerns regarding the 
percent emission reductions (i.e., control effectiveness) of OGI 
monitoring at the various monitoring frequencies. In the analysis 
described in the TSD, the EPA estimates emission reductions of 30 
percent for biennial monitoring, 40 percent for annual monitoring, 45 
percent for stepped monitoring, 60 percent for semiannual monitoring, 
and 80 percent for quarterly monitoring.\19\ The estimates for annual, 
semiannual, and quarterly monitoring frequencies are the same as those 
during used for the 2016 NSPS OOOOa. Stakeholders have raised specific 
concerns regarding the control effectiveness values for semiannual and 
quarterly monitoring. One stakeholder asserts that the ``EPA's leak 
emission reduction estimates are based on a LDAR control efficiency 
model with high uncertainty and biased by flawed and unrepresentative 
data and assumptions.'' \20\ Specific concerns

[[Page 52064]]

raised by this stakeholder include the comparison of OGI control 
effectiveness to Method 21 control effectiveness. The stakeholder noted 
that the EPA based the Method 21 control effectiveness evaluation on 
information from the Synthetic Organic Chemical Manufacturing Industry 
(SOCMI) which the stakeholder suggests overestimates fugitive emissions 
because this data is not representative of the oil and natural gas 
sector. We are soliciting comment and information that would support a 
revision of the evaluation of the Method 21 alternative that is more 
representative of the oil and natural gas industry.
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    \19\ See TSD for additional information related to OGI control 
effectiveness.
    \20\ See ``Methane Emissions from Natural Gas Transmission and 
Storage Facilities: Review of Available Data on Leak Emission 
Estimates and Mitigation Using Leak Detection and Repair,'' prepared 
for INGAA by Innovative Environmental Solutions, Inc., June 8, 2018, 
located at Docket ID No. EPA-HQ-OAR-2017-0473.
---------------------------------------------------------------------------

    This stakeholder also raised concerns that the estimated control 
efficiency of 80 percent for quarterly monitoring is too low, 
suggesting 90 percent would be more appropriate for quarterly 
monitoring and 80 percent for annual monitoring.\21\ The stakeholder 
references a report by the Canadian Association of Petroleum Producers 
(CAPP) that estimated a net-weighted decrease of component-specific 
emissions factors following the implementation of best management 
practices, also published by CAPP.22 23 The EPA has reviewed 
this report from CAPP and the associated best management practices to 
determine if updates to our estimated control efficiencies for OGI are 
appropriate. In our analysis \24\ of the information presented by CAPP, 
we are unable to conclude that annual monitoring with OGI will achieve 
80 percent emission reductions because there is no information 
regarding the type of detection method used or repair requirement 
related to the facilities that provided data for the CAPP emissions 
factor update study. The related Best Management Practices document 
provides some information about the recommended frequency of 
monitoring; \25\ however, the information provided for the CAPP study 
does not specify what monitoring frequencies were implemented at the 
facilities. Therefore, the TSD continues to use 80 percent as the best 
estimated control effectiveness for quarterly monitoring.\26\ While the 
EPA's estimated emission reductions are based on the best currently 
available information, there are considerable uncertainties associated 
with that information and the consequent reductions, and the EPA is 
aware there may be studies that may provide additional analysis on the 
effectiveness of OGI monitoring that can further refine our estimates. 
The EPA is requesting information on any analyses performed on the 
emission reductions achieved with OGI monitoring at different 
monitoring frequencies and the data underlying these analyses, 
including information on how the data was gathered, what the data 
represents, and how the analysis was performed.
---------------------------------------------------------------------------

    \21\ See memorandum EPA Analysis of Fugitive Emissions Data 
Provided by INGAA located at Docket ID No. EPA-HQ-OAR-2017-0483. 
August 21, 2018.
    \22\ See ``Update of Fugitive Equipment Leak Emission Factors'', 
prepared for Canadian Association of Petroleum Producers by 
Clearstone Engineering, Ltd., February 2014, located at Docket ID 
No. EPA-HQ-OAR-2017-0483.
    \23\ Canadian Association of Petroleum Producers, ``Best 
Management Practice. Management of Fugitive Emissions at Upstream 
Oil and Gas Facilities'', January 2007.
    \24\ See memorandum EPA Analysis of Fugitive Emissions Data 
Provided by INGAA located at Docket ID No. EPA-HQ-OAR-2017-0483. 
August 21, 2018.
    \25\ Canadian Association of Petroleum Producers, ``Best 
Management Practice. Management of Fugitive Emissions at Upstream 
Oil and Gas Facilities'', January 2007.
    \26\ See TSD for more information related to OGI control 
effectiveness.
---------------------------------------------------------------------------

    Second, because the model plants assume that the percentage of 
components found with fugitive emissions is the same regardless of the 
monitoring frequency, we acknowledge that we may have overestimated the 
total number of fugitive emissions components identified during each of 
the more frequent monitoring cycles. The percentage of components found 
with fugitive emissions is similar to the occurrence rate (i.e., the 
percentage of components not ``leaking'' that start to ``leak'' between 
monitoring cycles) of leak detection and repair (LDAR) programs. 
Appendix G of the 1995 Protocol describes how to calculate the 
occurrence rate.\27\ When we have evaluated the use of Method 21 as an 
alternative for OGI in the fugitive emissions requirements of the 2016 
NSPS OOOOa, we assumed occurrence rates that decrease with increasing 
monitoring frequencies, consistent with the 1995 Protocol. However, 
when evaluating the use of OGI, we assumed a constant percent of 
fugitive emissions components will be identified with fugitive 
emissions at each monitoring event, regardless of the number of 
monitoring events each year, which is counter to the 1995 Protocol and 
our evaluation of the Method 21 alternative. That is, the model plant 
analysis assumes that the same number of components will be identified 
with fugitive emissions during each monitoring event, regardless of how 
frequently monitoring occurs. Specifically, we currently assume that 4 
components will have fugitive emissions during a single annual period 
if monitored annually, while 8 components will have fugitive emissions 
during a single annual period if monitored semiannually. While there is 
uncertainty regarding the number of components identified with fugitive 
emissions, as described below, the use of a single percentage for all 
monitoring frequencies may overestimate the number of fugitive 
emissions identified during more frequent monitoring events, such as 
semiannual monitoring. We are soliciting information to evaluate how 
the percentage of fugitive emissions identified changes with frequency 
to revise the model plant analysis.
---------------------------------------------------------------------------

    \27\ U.S. Environmental Protection Agency, Protocol for 
Equipment Leak Emission Estimates. Appendix G. November 1995 (EPA-
453/R-95-017).
---------------------------------------------------------------------------

    Finally, in addition to the uncertainty described above regarding 
the percentage of fugitive emissions at the various monitoring 
frequencies, there is concern regarding the value that the EPA uses as 
an initial percentage in the model plant analysis. In the analysis for 
the 2016 NSPS OOOOa, we assumed a value of 1.18 percent based on 
information used in previous rulemakings for the SOCMI.\28\ One 
petitioner provided data to demonstrate lower percentages of fugitive 
emissions than used in our analysis. One data set included information 
from well sites in Colorado and the Barnett Shale region of Texas.\29\ 
This information included the number of components with fugitive 
emissions by component type, an estimate of the total number of each 
component type, and an estimated percentage of fugitive emissions 
components identified with fugitive emissions using both OGI and Method 
21. Subsequent to the submission of their petition, this petitioner 
also provided additional data on the initial

[[Page 52065]]

fugitive emissions percentages for well sites located in 14 states.\30\ 
While the letter from the petitioner stated that on average 0.4 percent 
of fugitive emissions components were identified with fugitive 
emissions, this percentage was based on the aggregation of fugitive 
emissions by dividing the total number of fugitive emissions components 
identified with fugitive emissions by the total estimated number of 
fugitive emissions components monitored within the entire dataset; 
therefore, the 0.4 percent does not represent the average percentage of 
fugitive emissions components found with fugitive emissions at 
individual well sites, which is the information needed to evaluate 
fugitive emissions requirements at an individual well site. The EPA, 
therefore, has evaluated the data provided to determine the average 
percentage of fugitive emissions components identified with fugitive 
emissions at the individual well site level, consistent with our model 
plant approach and the standards for fugitive emissions in the 2016 
NSPS OOOOa. Based on the EPA's analysis of the petitioner's data, the 
data result in an average percentage of 0.54 percent or an average of 2 
components per well site with fugitive emissions during the initial 
monitoring survey.\31\ This contrasts with the EPA's estimate of 4 
components per well site with fugitive emissions during the initial 
monitoring survey, or 1.18 percent, used in the 2016 NSPS OOOOa. 
Additional information on our evaluation of this data is included in 
the memorandum EPA Analysis of Well Site Fugitive Emissions Monitoring 
Data Provided by API, located at Docket ID No. EPA-HQ-OAR-2017-0483. 
Based on this information, we are concerned that 1.18 percent is too 
high and not representative of the oil and gas sector. However, as 
discussed in the memorandum, the EPA has insufficient information, 
based on what was provided by the petitioner, to determine if the 
information is representative of fugitive emissions monitoring 
consistent with the requirements of the 2016 NSPS OOOOa. Therefore, we 
have not incorporated a change in the percentage value used in the 
model plant analysis and are soliciting more information as described 
later in this subsection.
---------------------------------------------------------------------------

    \28\ The assumption of 1.18% leak rate for OGI monitoring was 
obtained from Table 5 of the Uniform Standards memorandum. The 1.18% 
value is the baseline leak frequency for valves in gas/vapor 
service. None of the other baseline frequencies in this table were 
used because the equipment is in liquid service (e.g., pumps LL, 
valve LL, agitators LL). There is no information on the number of 
leaks located at uncontrolled facilities, only average percentages 
of the total number of components at a facility. Therefore, our 
methodology was to use the 1.18% leak frequency value from the 
Uniform Standards memorandum and apply that value to the total 
number of components at the oil and natural gas model plant. 
(Uniform Standards Memorandum to Jodi Howard, EPA/OAQPS from Cindy 
Hancy, RTI International, Analysis of Emission Reduction Techniques 
for Equipment Leaks, December 21, 2011. EPA-HQ-OAR-2002-0037-0180).
    \29\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682.
    \30\ Alaska, Arkansas, Colorado, Louisiana, Montana, New Mexico, 
North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, Utah, West 
Virginia, and Wyoming.
    \31\ See memorandum EPA Analysis of Well Site Fugitive Emissions 
Monitoring Data Provided by API located at Docket ID No. EPA-HQ-OAR-
2017-0483. April 17, 2018.
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    In summary, although the EPA has incorporated several updates into 
the model plant analysis, the three areas described above cause concern 
that our analysis may still overestimate emission reductions. Based on 
the model plant analysis, we estimated the cost of control for each of 
the monitoring frequencies to determine how the changes to the model 
plants would affect the determination of cost-effectiveness presented 
in the 2016 NSPS OOOOa, noting that the revised analysis, 
notwithstanding its incorporation of additional information, does not 
address the three areas of concern described above. We applied the two 
approaches used in the 2016 NSPS OOOOa (single and multipollutant 
approaches) \32\ for evaluating cost-effectiveness of the semiannual 
and annual monitoring frequencies for the fugitive emissions program 
for reducing both methane and VOC emissions from non-low production 
well sites.\33\ For purposes of this reconsideration, we examined the 
emission reductions and costs for the fugitive emissions monitoring 
requirements at non-low production well sites at semiannual, annual, 
and stepped (semiannual for 2 years followed by annual monitoring 
thereafter) monitoring frequencies. This stepped monitoring frequency 
was based on a suggestion from one petitioner that, at a minimum, the 
EPA should require semiannual monitoring at well sites for an initial 
period of 2 years followed by less frequent monitoring frequencies such 
as annual monitoring for sites that do not have a significant number of 
``leaking'' \34\ components.\35\ While we have not established what 
would constitute an insignificant number of leaking components and the 
period of time before that number is reached, we have historically 
recognized that initial percentages of leaks are generally higher than 
subsequent leak percentages for the non-storage vessel PRD fugitive 
emissions components.\36\ As a fugitive emissions program is 
implemented, leak percentages decline until they reach a ``steady 
state.'' As illustrated in Figure 5-35 of the 1995 Protocol,\37\ the 
highest leak percentage is identified during the first monitoring 
event. The leak percentage then declines over time and reaches a point 
of steady state where the leak percentage is lower than that identified 
in the first monitoring event. We therefore evaluated a stepped 
approach, using 2 years as the initial period (as suggested by the 
petitioner) before reaching the steady state. Additional information 
regarding the cost of control and emission reductions is available in 
section 2.5 of the TSD located at Docket ID No. EPA-HQ-OAR-2017-0483.
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    \32\ See 81 FR 56616. Under the single pollutant approach, we 
assign all costs to the reduction of one pollutant and zero costs 
for all other pollutants simultaneously reduced. Under the 
multipollutant approach, we allocate the annualized costs across the 
pollutant reductions addressed by the control option in proportion 
to the relative percentage reduction of each pollutant controlled. 
For purposes of the multipollutant approach, we assume that 
emissions of methane and VOC are equally controlled, therefore half 
of the cost is apportioned to the methane emission reductions and 
half of the cost is apportioned to the VOC emission reductions. In 
this evaluation, we examined both approaches across the range of 
identified monitoring frequencies: Semiannual, annual, and 
semiannual for 2 years followed by annual.
    \33\ The TSD also include an analysis of the cost of control for 
the stepped monitoring frequency; however, we are not considering 
this for proposal in this action because we do not currently have 
information to understand how fugitive emission percentage change 
over time or how long it takes to achieve the steady state 
percentage at non-low production well sites.
    \34\ While the petitioner used the term leaking, EPA is 
clarifying they were referring to fugitive emissions, and not 
equipment leaks such as those subject to a leak detection and repair 
(LDAR) program at onshore natural gas processing plants.
    \35\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682.
    \36\ See Final Impacts Analysis for Regulatory Options for 
Equipment Leaks of VOC in the SOCMI, located at Docket ID. EPA-HQ-
OAR-2006-0699-0090 at p. 8.
    \37\ U.S. Environmental Protection Agency, Protocol for 
Equipment Leak Emission Estimates. Section 5.3 and Figure 5-35. 
November 1995 (EPA-453/R-95-017).
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    These costs of control for both the semiannual and annual 
monitoring frequencies may appear to be reasonable for non-low 
production well sites. However, as explained above regarding the three 
areas of concern, we acknowledge that our updated analysis may 
overestimate the emission reductions achieved under semiannual 
monitoring and the number of fugitive emissions components identified 
during semiannual monitoring. Therefore, we are unable to conclude that 
semiannual monitoring is cost effective. While we have also 
overestimated the cost effectiveness of the stepped approach and annual 
monitoring for the same reasons discussed above, the overestimate would 
be less compared to that for semiannual monitoring. As mentioned 
earlier, petitioners have requested that we consider annual monitoring, 
which suggests that they are able to bear such costs. In light of all 
these considerations, we are therefore proposing to revise the 
monitoring frequency for the collection of fugitive emissions 
components located at non-low production well sites from

[[Page 52066]]

semiannual monitoring to annual monitoring.
    We are soliciting comment on the proposed annual monitoring for 
non-low production well sites and additional information to address the 
uncertainties described previously. There are several well sites that 
have incorporated fugitive monitoring programs prior to the 2016 NSPS 
OOOOa for various purposes, including compliance with state or local 
requirements. Data from these programs could provide the information 
necessary to refine our model plant analysis. We are soliciting data 
regarding the percentage of fugitive emissions components identified 
with fugitive emissions at these well sites for each survey performed 
to understand how this percentage may change over time or based on 
monitoring frequency; the data should include information on when the 
well site began producing, the start date of the fugitive program at 
the well site, the frequency of monitoring, an indication of the 
location of the well site (e.g., basin name or state), and how the 
surveys are performed, including the monitoring instrument used and the 
regulatory program followed. We are also soliciting comment and 
supporting data on the stepped monitoring frequency for non-low 
production well sites, including information to determine the 
appropriate period for more frequent monitoring prior to stepping down 
to less frequent monitoring. We further solicit comment whether, should 
we still lack information of the type solicited in this paragraph, the 
existing uncertainties and absences of information described in this 
notice support the monitoring frequencies proposed in this notice, the 
monitoring frequencies in the 2016 NSPS OOOOa, or some other result.
    The EPA is soliciting information that can be used to evaluate if 
additional changes are necessary to the model plants. Specifically, the 
EPA requests information that has been collected from implementing 
fugitive monitoring programs, including information on leak 
concentrations where Method 21 has been used for monitoring. This 
information could also demonstrate the actual equipment counts or 
fugitive emissions component counts at the well site, in relation to 
the number of fugitive emissions identified during each monitoring 
survey.
    Further, we are proposing that fugitive monitoring may stop when an 
owner or operator removes all major production and processing equipment 
from the well site, such that it contains only one or more wellheads. 
The 2016 NSPS OOOOa excludes well sites that contain only one or more 
wellheads from the fugitive emissions requirements because fugitive 
emissions at such well sites are extremely low. 80 FR 56611. In the 
preamble to the 2015 NSPS OOOOa proposal, we noted that wellhead only 
well sites do not have ancillary equipment (such as storage vessels, 
closed vent systems, control devices, compressors, separators, and 
pneumatic controllers), thus resulting in low emissions. For the same 
reason, we anticipate that, when a well site becomes a wellhead only 
well site due to the removal of all ancillary equipment, its fugitive 
emissions would also be extremely low because the number of fugitive 
emissions components is low. This proposal uses the term ``major 
production and processing equipment'' to refer to ancillary equipment 
without which the fugitive emissions would be extremely low. We are, 
therefore, proposing to define ``major production and processing 
equipment'' as including separators, heater treaters, storage vessels, 
glycol dehydrators, pneumatic pumps, or pneumatic controllers. We have 
also evaluated the cost-effectiveness of monitoring a wellhead only 
well site and find it not to be cost-effective. For that analysis, we 
developed a model plant that contains only 2 wellheads and no major 
production and processing equipment. For the annual monitoring 
frequency, we found the cost for control was greater than $5,000 per 
ton of methane reduced and greater than $20,000 per ton of VOC 
reduced.\38\ Additional discussion about this model plant and the cost 
of control is included in the TSD. In light of the above, because 
fugitive emissions are anticipated to be extremely low and control 
costs are estimated to be elevated, we are proposing that monitoring 
may discontinue when all major production and processing equipment at a 
well site has been removed, resulting in a wellhead only well site. We 
are soliciting comment on the proposed exemption and definition of 
major production and processing equipment for purposes of this specific 
proposal, including whether additional equipment should be included in 
this list, such as compressors and engines.
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    \38\ We did not perform an analysis for the cost of control at a 
semiannual monitoring frequency for these wellhead only well sites 
because we determined that annual monitoring was not cost-effective. 
Therefore, at more frequent monitoring would also not be cost-
effective because there are higher costs compared to annual 
monitoring.
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    As explained above, we are proposing that monitoring is no longer 
required when all major production and processing equipment at a well 
site has been removed, resulting in a wellhead only well site. We note 
that if the production from this well site (with all major production 
and processing equipment removed), is sent to a separate tank battery 
for processing, that separate tank battery (which itself is a well site 
as defined in 40 CFR 60.5430a) is considered modified and subject to 
the fugitive emissions requirements. Additional discussion on this 
topic is included in section VI.B.2 of this preamble. We further note 
that the proposed monitoring exemption would not change the affected 
facility status of the collection of fugitive emissions components 
located at a well site that removes equipment to become a wellhead only 
well site; it would remain an affected facility. We are proposing to 
require that owners or operators report the following information in 
the next annual report following the change to a wellhead only well 
site: (1) A statement that the well site has removed all major 
production and processing equipment, (2) the final date that equipment 
was removed, (i.e., the date that the well site began meeting the 
definition of a wellhead only well site), and (3) the location 
receiving the production from the well site. Provided the well site 
remains a wellhead only well site, no additional reporting related to 
fugitive emissions would be required. If in the future production 
equipment is reintroduced to the well site, the fugitive emissions 
requirements would restart with initial monitoring followed by the 
subsequent monitoring, the frequency of which would be based on the 
subcategory (non-low production or low production) that the well site 
was classified as when it first became an affected facility for 
fugitive emissions requirements (e.g. not the subcategory that the well 
site is classified when production equipment is reintroduced). We are 
soliciting comment on this proposed exemption from monitoring for well 
sites that become wellhead only sites, including the proposed reporting 
requirements and subsequent monitoring requirements should the wellhead 
only status of the well site later change.
    Low Production Well Sites. The 2016 NSPS OOOOa requires semiannual 
monitoring for all well sites, regardless of the production levels for 
the well site. In 2015, the EPA proposed to exclude low production well 
sites (i.e., well sites where the average combined oil and natural gas 
production is less than 15 boe per day averaged over the first 30 days 
of production) from fugitive emissions requirements. 80 FR 56639. It

[[Page 52067]]

was our understanding in 2015 that fugitive emissions were low at low 
production well sites and that these well sites were mostly owned and 
operated by small businesses. We were concerned about the burden on 
small businesses, especially with relatively low emission reduction 
potential. Id. However, in the preamble to the final 2016 NSPS OOOOa, 
the EPA stated that we ``believe that low production well sites have 
the same type of equipment (e.g., separators, storage vessels) and 
components (e.g., valves, flanges) as well sites with production 
greater than 15 boe per day. Because we did not receive additional data 
on equipment or component counts for low production wells, we believe 
that a low production well model plant would have the same equipment 
and component counts as a non-low production well site.'' 81 FR 35856. 
We based this conclusion on the fact that we had no data to indicate 
that the number and types of equipment were different at low production 
well sites than at non-low production well sites. Additionally, 
comments received on the 2015 proposal indicated that small businesses 
would not benefit from the proposed exemption because these types of 
wells would not be economical to operate and few operators, if any, 
would operate new low production well sites. Id.
    In a letter dated April 18, 2017, the Administrator granted 
reconsideration of several aspects of the 2016 NSPS OOOOa, including 
applying the fugitive emissions requirements at 40 CFR 60.5397a to low 
production well sites.\39\ The petitioner who raised this issue for 
reconsideration identified in its petition what they classified as an 
inconsistency between the EPA's justification for not exempting low 
production well sites from the fugitive emissions requirements and the 
EPA's rationale for the definition of modification for purposes of 
those same requirements.\40\ This petitioner observed that it appeared 
the EPA relied on data indicating the same equipment counts were 
present at all well sites regardless of production levels to justify 
regulating fugitive emissions at low production well sites, while 
defining modification by events that increase production (i.e., 
drilling a new well, hydraulic fracturing a well, or hydraulic 
refracturing a well), which the EPA concludes will increase emissions 
whether or not there is change in component counts. The petitioner then 
stated that:
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    \39\ See Docket ID No. EPA-HQ-OAR-2010-0505-7730.
    \40\ See Docket ID No. EPA-HQ-OAR-2010-0505-7685.

    EPA's rationale, that fugitive emissions are a function of the 
number and types of equipment, and not operating parameters such as 
pressure and volume, is inconsistent with EPA's justification for 
what constitutes a `modification' for an existing well site. EPA 
assumes that fracturing or refracturing an existing well will 
increase emissions because of the additional production, i.e., the 
additional pressure and volume. EPA cannot ignore the laws of 
physics to the detriment of low production wells in one instance and 
then `honor' them in another context to eliminate an `emissions 
increase' requirement in the traditional definition of 
`modification.' \41\
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    \41\ See Docket ID No. EPA-HQ-OAR-2010-0505-7685, p. 5.

    As we explain in detail in section VI.B.2 related to modifications, 
operating pressures and volumes are one set of factors that can cause 
changes in the fugitive emissions at a well site. However, as described 
below, there is support for the petitioners' assertion that equipment 
counts can vary based on the amount of production at a well site.\42\
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    \42\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682.
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    The petitioners noted that as production increases it is possible 
that additional major production and processing equipment is added to 
the well site to handle this increase. The inverse impact was also 
presented by petitioners, in that as production declines, major 
production and processing equipment is either disconnected or removed 
from the well site so it can be used somewhere else.\43\ Additionally, 
the petitioners noted that operating pressures for the well site are 
generally affected by production, and depleted wells may not be able to 
provide enough pressure to meet the pressure requirements of the gas 
gathering system.\44\ In comments submitted on the November 2017 Notice 
of Data Availability (``2017 NODA''), one commenter noted that the 
information used as the basis for the EPA's decision to treat low 
production well sites the same as non-low production well sites was 
based on a flawed analysis of the data.\45\ This commenter noted that 
emissions were presented in such a way as to compare the total well 
site emissions as a percentage of production. As noted by the 
commenter, this type of analysis unfairly makes it appear that low 
production well sites are ``super-emitters'' because when emissions are 
compared based on a percentage of production, even small emissions can 
appear to be upwards of 50 percent or more of the total production for 
the well site. Further, one petitioner reiterated concerns about the 
impacts of fugitive emissions requirements on small businesses, 
including stating that the ``marginal profitability will mean that many 
wells will be shut in instead of making the investment to conduct LDAR 
surveys.'' \46\ We solicit information confirming or refuting this 
concern including analyses of the number of wells that may be shut in 
as a result of requiring fugitive emissions monitoring and how these 
concerns may vary based on production level (presumably wells with 
higher production would be better able to adsorb more frequent 
monitoring). At a minimum, any information provided should include the 
costs of implementing the fugitive emissions requirements compared to 
the profitability of the well site over the life of the well site from 
first production through shut in. Further, any information provided 
should include information as to the length of the life of the well 
site, beginning at first production, and by how much that total 
duration would be shortened by the shut in, as well as information as 
to total production over the life of the well site, beginning at first 
production, and the amount of production that would be reduced by the 
shut in. If information received supports the allegation that fugitive 
emissions monitoring would lead to a significant number of shut-ins at 
a significantly earlier point in the life of the well site and with a 
significant loss of overall production volume, that would further 
support our proposals regarding monitoring frequency. However, 
assertions presented without supporting information will be of limited 
or no utility in this analysis.
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    \43\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682, p. 12.
    \44\ Id.
    \45\ See Docket ID No. EPA-HQ-OAR-2010-0505-12454.
    \46\ See Docket ID No. EPA-HQ-OAR-2010-0505-7685.
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    In light of the comments, the petitions, and data made available 
after promulgation of the 2016 NSPS OOOOa, the EPA has re-examined 
whether fugitive emissions are different for low production well sites. 
Following promulgation of the 2016 NSPS OOOOa, the EPA received 
information from one stakeholder which contained component level 
emissions information for well sites in the Dallas/Fort Worth area 
(herein referred to as the ``Fort Worth Study'').\47\ The EPA evaluated

[[Page 52068]]

the emissions calculation workbook included in Appendix 3-B of the Fort 
Worth Study and was able to identify 27 well sites with throughput less 
than 90 thousand cubic feet per day (Mcfd), or 15 boe per day. While 
this throughput was the throughput reported for the prior day and not 
the average over the first 30 days as we are defining low production 
well sites in this proposed reconsideration, this information was 
relevant to understanding both component counts and emissions for the 
well sites in the study as compared to production values. As explained 
in the memorandum Analysis of Low Production Well Site Fugitive 
Emissions from the Fort Worth Air Quality Study (``Fort Worth Study 
Memo''), located at Docket ID No. EPA-HQ-OAR-2017-0483, the EPA was 
able to directly compare fugitive component emissions from these 27 low 
production well sites to the fugitive component emissions from the 
other approximately 300 well sites in the study. This evaluation 
demonstrated that average emissions across the low production well 
sites were lower than those at the non-low production well sites in the 
study. Additionally, the average equipment counts were also lower for 
the low production well sites than those at non-low production well 
sites in the study. When fugitive emissions were considered from non-
tank and non-controller fugitive sources, the average methane emissions 
were approximately 2.5 tpy for low production well sites, and 24 tpy 
for non-low production well sites. When storage vessel fugitives (e.g., 
thief hatches) were considered, average methane emissions were 13 tpy 
for low production well sites and 33 tpy for non-low production well 
sites.\48\
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    \47\ ``The Natural Gas Air Quality Study (Final Report),'' 
prepared by Eastern Research Group, Inc. July 13, 2011, available at 
http://fortworthtexas.gov/gaswells/air-quality-study/final/.
    \48\ See the memorandum Analysis of Low Production Well Site 
Fugitive Emissions from the Fort Worth Air Quality Study, located at 
Docket ID No. EPA-HQ-OAR-2017-0483.
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    Given this information, the EPA for this proposal has evaluated 
fugitive emissions from well sites by subcategorizing well sites based 
on production: (1) Non-low production and (2) low production. Within 
each of these subcategories, the EPA has modified the three model 
plants used in the 2016 NSPS OOOOa: Gas well site, oil well site 
(defined as GOR <300), and oil with associated gas well site (defined 
as GOR >=300). A discussion of the non-low production well site model 
plants is included in the discussion above on the pathway to less 
frequent monitoring.
    The EPA created new model plants using the component count 
information obtained for the low production well sites in the Fort 
Worth Study in order to compare the emissions using the emissions 
factors used by the EPA for model plant calculations to the measured 
emissions from the study. For the low production gas well site model 
plant, we used the average equipment counts for the low production well 
sites in the Fort Worth Study. We then compared the corresponding 
average component counts (e.g., valves, connectors) for this equipment 
in the low production gas well site to the non-low production gas well 
site to determine a scaling factor. This scaling factor was applied to 
the non-low production component counts for the oil well site and oil 
with associated gas well site model plants in order to evaluate these 
types of well sites for the low production subcategory. Additional 
information about the low production well site model plants and 
analysis is included in the TSD.
    As mentioned previously, in the 2016 NSPS OOOOa the EPA did not 
expect production levels to affect the amount of major production and 
processing equipment at well sites. However, as discussed above, we 
have since evaluated data showing that low production wells have fewer 
equipment components, and therefore fewer fugitive emissions. 
Therefore, in this proposal, we have incorporated the new data and 
developed model plants for low production well sites. The estimated 
emissions and cost-effectiveness are different between the low 
production and non-low production well site model plants. For example, 
the estimated baseline methane emissions are 5.91 and 4.80 tpy for non-
low production and low production gas well site model plants, 
respectively. We performed additional analysis on the emissions data 
presented in the Fort Worth Study to determine if there was a 
statistical difference between the low production and non-low 
production methane emissions. This analysis determined the mean methane 
emissions were 157 and 116 tpy for non-low production and low 
production well sites, respectively. Additional information on this 
analysis is included in the Fort Worth Study Memo located at Docket ID 
No. EPA-HQ-OAR-2017-0483.
    In addition to the Fort Worth Study, the EPA evaluated other 
available information for comparing low and non-low production well 
sites. While we did not find the same level of detail regarding 
component counts to allow us to further refine the low production well 
site model plants, several of the studies indicated that there is a 
general correlation between production and fugitive emissions, where 
fugitive emissions increase as production increases at the well site. 
Further, some studies indicated that while the number of fugitive 
emissions components was lower for low production well sites (contrary 
to our assumption in the 2016 NSPS OOOOa), a few outliers were 
identified suggesting that low production well sites may have the 
potential for fugitive emissions greater than the estimates in the 
model plants. Finally, the studies also indicated that storage vessel 
thief hatches were a large source of fugitive emissions when compared 
to other fugitive emissions components, such as valves and connectors. 
Additional information about these studies is presented in the 
memorandum Low Production Well Site Fugitive Emissions (``Low 
Production Memo''), located at Docket ID No. EPA-HQ-OAR-2017-0483.
    In addition to the potential overestimates of emissions discussed 
related to non-low production well sites, our re-assessment of our 2016 
analysis indicates that we may have overestimated emissions and the 
potential for emission reductions from low production well sites. As we 
have described previously, the number of each type of major production 
and processing equipment located at low production well sites may 
differ from that at non-low production well sites, and we are not 
certain this has been adequately taken into account with the limited 
data available \49\ from the Fort Worth Study. The equipment that is 
present at a low production well site is typically designed for lower 
operating conditions, such as volume and pressure, therefore, the 
equipment may be smaller and composed of fewer fugitive emission 
components than those estimated in the model plants. As discussed in 
further detail in the TSD, we used the average major production and 
processing equipment counts from the Fort Worth Study as the basis for 
the low production model plants; however, because the Fort Worth Study 
does not provide component count data by equipment, we assigned the 
same average component counts per major equipment (i.e., the same 
number of valves per separator as the number of valves per separator at 
non-low

[[Page 52069]]

production well sites). Therefore, there is evidence to suggest that we 
may have overestimated the fugitive emissions component counts for low 
production well sites. Additionally, the petitioners assert that the 
operating pressures are much lower for low production well sites than 
for non-low production well sites, and we do not have a mechanism to 
account for operating pressure changes in our model plants.\50\ 
However, in section VI.B.2 of this preamble, we discuss comments from 
petitioners stating that operating pressures may be driven, in part, by 
sales line pressures such that decreased production levels may not 
allow for operations below the gas sales line pressures. In such 
circumstances, the low production well site would need to produce at or 
above the relevant gas sales line pressure. This may result in 
decreased dump frequency or duration, and therefore, reduced periods of 
fugitive emissions during operation. While lower operating pressure and 
decreased dump frequency or duration would result in lower fugitive 
emissions, we do not have enough information to determine the 
likelihood of decreased operating pressure or decreased dump frequency 
or duration in order to account for them in our model plant analysis.
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    \49\ The site-specific data available in the Fort Worth Study is 
limited to approximately 300 natural gas well sites located near the 
City of Fort Worth, Texas. Most of the well sites consisted of dry 
gas, with no information available on oil well sites. We are 
uncertain the major production and processing equipment counts 
presented in this study are representative of well sites located in 
other areas of the country, and solicit information regarding 
operations in other areas.
    \50\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-7685.
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    Despite the potential overestimation of emissions and emission 
reductions for low production well sites, we examined the costs and 
emission reductions for several monitoring frequencies to determine the 
cost of control for the newly created low production well site model 
plant. As a result of this review, there is evidence to support the 
petitioners' assertion that low production well sites are different 
than non-low production well sites. The TSD presents the cost of 
control for semiannual, stepped, annual and biennial monitoring 
frequencies.\51\
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    \51\ See the TSD for full comparison of cost.
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    After considering the differences in emissions between non-low 
production and low production well sites, and the reasons to believe 
that we have overestimated emission reductions and percentage of 
fugitive emissions, we are proposing to change the current monitoring 
frequency for low production well sites from semiannual monitoring to 
biennial monitoring, or monitoring every other year. We are soliciting 
comment on the biennial monitoring requirement for low production well 
sites. Additionally, we are soliciting data on the number of major 
production and processing equipment (e.g., separators, heater treaters, 
glycol dehydrators, and storage vessels) and the number of fugitive 
emissions components (e.g., valves, open-ended lines, and connectors) 
located at these well sites, as well as the operating pressures of 
these well sites considering gas sales line pressures and the number of 
major production and processing equipment located at the well site 
(e.g., separators and heater treaters). Further, the EPA is proposing 
that low production well sites are defined as those well sites where 
the average combined oil and natural gas production is less than 15 boe 
per day averaged over the first 30 days of production. We are 
soliciting comment on the definition of a low production well site, 
including those where all the wells located on the well site have 
production below 15 boe per day. We are proposing specific 
recordkeeping and reporting requirements in 40 CFR 60.5420a, including 
a requirement to describe how the well site determined it is a low 
production well site. We are soliciting comment on the recordkeeping 
and reporting requirements, including alternative information that 
would provide the combined production of oil and natural gas for the 
well site. In addition to soliciting comment on the biennial monitoring 
frequency, we are also soliciting comment and supporting data on an 
exemption from fugitive emissions requirements at low production well 
sites, for well sites both with and without controlled storage vessels.
    Monitoring Frequency for Compressor Stations. The 2016 NSPS OOOOa 
requires initial and quarterly monitoring of the collection of fugitive 
emissions components located at compressor stations. As noted in 
section VI.B.1 of this preamble, we received petitions requesting less 
frequent monitoring, specifically semiannual monitoring for compressor 
stations.\52\ In this action, we are co-proposing semiannual and annual 
monitoring of the collection of fugitive emissions components located 
at compressor stations not located on the Alaskan North Slope. (See 
``Well Sites and Compressor Stations Located on the Alaskan North 
Slope'' for the proposed actions related to those sites.)
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    \52\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.
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    Similar to the information received about fugitive monitoring at 
well sites, the EPA received information from two stakeholders 
regarding fugitive emissions monitoring at compressor 
stations.53 54 Some of the information provided the number 
of fugitive emission components monitored and the number and 
percentages of fugitive emissions components identified with fugitive 
emissions for 110 gathering and boosting compressor stations.\55\ One 
of these stakeholders asserted the data provided regarding gathering 
and boosting stations would support changing the monitoring frequency 
for compressor stations to annual monitoring. Some of this data was 
specific to the required monitoring of the 2016 NSPS OOOOa, while other 
information was specific to monitoring requirements for various state 
programs or consent decrees. One company provided the number of 
fugitive emissions identified during initial monitoring at 17 stations, 
and subsequent fugitive emissions counts for up to 6 total surveys, 
however, not all stations are represented in subsequent surveys. While 
fugitive emissions counts were included in this submission, no other 
information was provided about the number of components monitored. It 
was difficult for us to make any conclusions from the information, but 
we were able to recognize that for at least one company, the average 
reported initial percentage of identified fugitive emissions is almost 
1.5 percent, which is higher than the 1.18 percent used for our model 
plant calculations. However, no conclusions can be drawn from this 
single data point and we did not make updates to the model plants as a 
result of this information. The EPA performed a sensitivity analysis 
using this data to understand how the cost of control would change if 
we applied the data provided to compressor stations and included this 
analysis in the TSD. This analysis did not alter the conclusions that 
we had reached using the 1.18 percent value.
---------------------------------------------------------------------------

    \53\ See letter from GPA Midstream Association Re: GPA Midstream 
OOOOa White Paper Supplemental Information, March 5, 2018, located 
at Docket ID No. EPA-HQ-OAR-2017-0483.
    \54\ See memorandum NSPS OOOOa Monitoring Case Study 
Presentation by Terence Trefiak with Target Emission Services 
located at Docket ID No. EPA-HQ-OAR-2017-0483. March 13, 2018.
    \55\ See memorandum EPA Analysis of Compressor Station Fugitive 
Emissions Monitoring Data Provided by GPA Midstream located at 
Docket ID No. EPA-HQ-OAR-2017-0483. April 17, 2018.
---------------------------------------------------------------------------

    We are soliciting comment on our analysis of the information 
provided by this stakeholder,\56\ including additional data that will 
allow for further analysis of fugitive emissions monitoring at

[[Page 52070]]

compressor stations. The EPA is also soliciting information that can be 
used to evaluate if changes are necessary to the model plants. 
Specifically, the EPA requests information that has been collected from 
implementing fugitive monitoring programs. This information could 
demonstrate the actual equipment counts or fugitive emissions component 
counts at the compressor station, in relation to the number of fugitive 
emissions identified during each monitoring survey. Finally, the EPA 
solicits comment and information on costs associated with implementing 
a fugitive emissions monitoring program.
---------------------------------------------------------------------------

    \56\ See memorandum EPA Analysis of Compressor Station Fugitive 
Emissions Monitoring Data Provided by GPA Midstream located at 
Docket ID No. EPA-HQ-OAR-2017-0483. April 17, 2018.
---------------------------------------------------------------------------

    The unique operating characteristics of compressor stations may 
support more frequent monitoring of compressor stations as compared to 
well sites. The collection of fugitive emissions components located at 
compressor stations are subject to vibration and temperature cycling. 
Some studies indicate that components subject to vibration, high use, 
or temperature cycling are the most leak-prone.\57\ The EPA best 
practices guide for LDAR states that more frequent monitoring should be 
implemented for components that contribute most to emissions.\58\ 
Similarly, the Canadian Association of Petroleum Producers issued a 
best management practice for the management of fugitive emissions at 
upstream oil and gas facilities in 2007. That document states, ``the 
equipment components most likely to leak should be screened most 
frequently.'' \59\
---------------------------------------------------------------------------

    \57\ Canadian Association of Petroleum Producers, ``Best 
Management Practice. Management of Fugitive Emissions at Upstream 
Oil and Gas Facilities,'' January 2007.
    \58\ U.S. Environmental Protection Agency, ``Leak Detection and 
Repair: A Best Practices Guide,'' EPA-305-D-07-001, October 2007.
    \59\ Canadian Association of Petroleum Producers, ``Best 
Management Practice. Management of Fugitive Emissions at Upstream 
Oil and Gas Facilities,'' January 2007.
---------------------------------------------------------------------------

    Additionally, information was also provided by one stakeholder that 
indicates the operating mode of the compressor(s) located at the 
station was a key piece of information when detecting fugitive 
emissions.\60\ For instance, the stakeholder stated that when 
compressors were in standby mode, the detected fugitive emissions were 
lower. We had not previously considered that compressors may not be 
operating during the fugitive emissions survey, therefore, we are 
proposing that owners or operators keep a record of the operating mode 
of each compressor at the time of the monitoring survey, and a 
requirement that each compressor must be monitored at least once per 
calendar year when it is operating. If the operating mode of individual 
compressors has an impact on the occurrence of fugitive emissions, it 
may provide support for more frequent monitoring, or, alternatively, a 
requirement to monitor when compressors are operating reflective of 
normal operating conditions. For example, if the EPA were to move to an 
annual monitoring frequency, owners and operators might conduct 
fugitive emissions monitoring during scheduled maintenance periods such 
as times when there is less demand on the station. This might present 
the appearance of lower fugitive emissions than if the monitoring 
occurred during peak seasons, thus decreasing the effectiveness of the 
program for controlling fugitive emissions, unless the monitoring 
procedure can assure that does not occur. The EPA is soliciting comment 
related to the effect the compressor operating mode has on fugitive 
emissions and comment on a requirement to conduct monitoring only 
during times that are representative of operating conditions for the 
compressor station.
---------------------------------------------------------------------------

    \60\ See memorandum NSPS OOOOa Monitoring Case Study 
Presentation by Terence Trefiak with Target Emission Services 
located at Docket ID No. EPA-HQ-OAR-2017-0483. March 13, 2018.
---------------------------------------------------------------------------

    There are a number of important factors to consider when selecting 
the appropriate monitoring frequency for fugitive emissions components 
located at compressor stations such as the operating modes that likely 
affect the number and magnitude of fugitive emissions and costs. In 
light of the concerns from the petitioners that less frequent 
monitoring than the current requirement of quarterly monitoring would 
be appropriate, the EPA performed a sensitivity analysis to understand 
how the monitoring frequencies would affect emission reductions and 
costs. We examined the costs and emission reductions for the compressor 
station model plant at quarterly, semiannual, and annual monitoring 
frequencies. We applied the two approaches used in the 2016 NSPS OOOOa 
(single and multipollutant approaches) \61\ for evaluating cost-
effectiveness of these three monitoring frequencies for the fugitive 
emissions program for reducing both methane and VOC emissions from non-
low production well sites. In addition to evaluating the total cost-
effectiveness of the different monitoring frequencies, the EPA also 
estimated the incremental costs of going from the baseline of no 
monitoring to annual, from annual to semiannual, and from semiannual to 
quarterly. The incremental cost of control provides insight into how 
much it costs to achieve the next increment of emission reductions 
going from one stringency level to the next, more stringent level, and 
thus is an appropriate tool for distinguishing among the effects of 
different stringency levels. Table 3 summarizes the total and 
incremental costs of control for each of the monitoring frequencies 
evaluated at compressor stations. Additional information regarding the 
cost of control and emission reductions is available in section 2.5 of 
the TSD located at Docket ID No. EPA-HQ-OAR-2017-0483.
---------------------------------------------------------------------------

    \61\ See 81 FR 56616. Under the single pollutant approach, we 
assign all costs to the reduction of one pollutant and zero costs 
for all other pollutants simultaneously reduced. Under the 
multipollutant approach, we allocate the annualized costs across the 
pollutant reductions addressed by the control option in proportion 
to the relative percentage reduction of each pollutant controlled. 
For purposes of the multipollutant approach, we assume that 
emissions of methane and VOC are equally controlled, therefore half 
of the cost is apportioned to the methane emission reductions and 
half of the cost if apportioned to the VOC emission reductions. In 
this evaluation, we examined both approaches across the range of 
identified monitoring frequencies: Semiannual, annual, and stepped 
(semiannual for 2 years followed by annual).

                              Table 3--Nationwide Emissions Reduction and Cost Impacts of Control for Fugitive Emissions Components Located at Compressor Stations
                                                                                           [Year 2015]
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                                                                    Incremental
                                                                            Annualized                                        Total cost-       Total cost-    Incremental cost-       cost-
                                                                           costs without     Emissions       Emissions       effectiveness     effectiveness     effectiveness     effectiveness
                        Frequency                          Capital cost      recovery       reduction,    reduction, VOC   without recovery       without      without recovery       without
                                                            (million $)       credits      methane (tpy)       (tpy)         credit ($/ton       recovery        credit ($/ton       recovery
                                                                          (million $/yr)                                       methane)        credit ($/ton       methane)        credit ($/ton
                                                                                                                                                   VOC)                                VOC)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Annual..................................................            0.42            2.05           3,680             850                 550           2,410  ..................  ..............
Semiannual..............................................            0.42             3.6           5,510           1,270                 650           2,830                 840           3,650
Quarterly...............................................            0.42             6.7           7,350           1,700                 910           3,950               1,690           7,300
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 52071]]

    We continue to recognize the limitations in our emissions 
estimation method, as described for non-low production well sites. As 
mentioned above, we recognize the distinct operational characteristics 
of compressor stations that may cause increased fugitive emissions may 
support more frequent monitoring than proposed for well sites. At this 
time, we recognize that our analysis likely overestimates the emission 
reduction and therefore, the cost-effectiveness of each of the three 
monitoring frequencies for compressor stations due to the same 
uncertainties described previously for non-low production well sites 
(e.g., assumed constant percentage of fugitive emissions, uncertainties 
regarding emission reductions achieved, etc.). Due to these 
uncertainties, we are unable to conclude that quarterly monitoring is 
cost-effective for compressor stations, thus we are co-proposing 
semiannual monitoring for compressor stations. The EPA is soliciting 
comment and information that will allow us to further refine our model 
plant analysis, including information regarding emission reductions and 
the relationship to monitoring frequencies. We are soliciting comment 
on quarterly monitoring, and our analysis of the factors that may 
contribute to increased fugitive emissions at compressor stations. 
Additionally, we are soliciting data in order to understand how the 
percentage of identified fugitive emissions may change over time; the 
data should include the date of construction of the compressor station, 
information on when the compressor station began its fugitive program, 
the frequency of monitoring, an indication of the location of the 
compressor station, and how the surveys are performed, including the 
monitoring instrument used and the regulatory program followed.
    Finally, the EPA is also noting that another stakeholder presented 
an analysis of third party studies and reports as justification for 
annual monitoring at compressor stations.\62\ In their analysis, the 
stakeholder states that the EPA has underestimated the control 
effectiveness of annual OGI monitoring and overestimated emissions from 
fugitive emissions components at compressor stations. For example, the 
stakeholder states that annual OGI monitoring at compressor stations 
can achieve 80 percent emissions reductions, compared to the EPA's 
estimate of 40 percent emissions reductions. Additionally, the 
stakeholder compares the EPA model plant emission estimates to 
measurement data reported under the requirements of 40 CFR part 98, 
subpart W--Petroleum and Natural Gas Systems (``Subpart W'') as 
compiled and described in the Pipeline Research Council International, 
Inc. (PRCI) study report.\63\ The EPA has reviewed the information and 
analyzed the referenced third-party reports to determine if the 
information would support annual monitoring. The EPA has several 
concerns with the analysis and conclusions presented by the 
stakeholder, as discussed in the memorandum describing our 
analysis,\64\ therefore, the EPA is unable at this point to conclude 
that this information supports annual monitoring for compressor 
stations. We are co-proposing semiannual and annual monitoring for 
compressor stations, and soliciting comment and supporting information 
related to our analysis of the information, including data that sheds 
further light on which monitoring frequency (annual, semiannual, or 
quarterly) is most appropriate.
---------------------------------------------------------------------------

    \62\ See ``Methane Emissions from Natural Gas Transmission and 
Storage Facilities: Review of Available Data on Leak Emission 
Estimates and Mitigation Using Leak Detection and Repair'', prepared 
for INGAA by Innovative Environmental Solutions, Inc., June 8, 2018 
and ``Supplement to INGAA White Paper on Subpart OOOOa TSD Estimates 
of Leak Emissions and LDAR Performance'', from Jim McCarthy and Tom 
McGrath, Innovative Environmental Solutions, Inc., June 20, 2018 
located at Docket ID No. EPA-HQ-OAR-2017-0473.
    \63\ GHG Emission Factor Development for Natural Gas 
Compressors, PRCI Catalog No. PR-312-1602-R02, April 18, 2018.
    \64\ See memorandum EPA Analysis of Fugitive Emissions Data 
Provided by INGAA located at Docket ID No. EPA-HQ-OAR-2017-0483. 
August 21, 2018.
---------------------------------------------------------------------------

    Well Sites and Compressor Stations Located on the Alaskan North 
Slope. On March 12, 2018, the EPA amended the 2016 NSPS OOOOa to 
include separate monitoring requirements for the collection of fugitive 
emissions components located at well sites located on the Alaskan North 
Slope.\65\ As explained in that action, such separate requirements were 
warranted due to the area's extreme cold temperature, which is below 
the temperatures at which the monitoring instruments are designed to 
operate for approximately half of a year. The amended requirements for 
the collection of fugitive emissions components located at well sites 
located on the Alaskan North Slope specify that new well sites that 
startup production between September and March must conduct initial 
monitoring within 6 months of the startup of production \66\ or by June 
30, whichever is later, while well sites that startup production 
between April and August must comply with the 60-day initial monitoring 
requirement in the 2016 NSPS OOOOa. Similarly, well sites that are 
modified between September and March must conduct initial monitoring 
within 6 months of the first day of production for each collection of 
fugitive emissions components or by June 30, whichever is later. 
Further, all well sites located on the Alaskan North Slope that are 
subject to the fugitive emissions requirements must conduct annual 
monitoring, instead of the semiannual monitoring required for other 
well sites. Subsequent annual monitoring must be conducted at least 9 
months apart.
---------------------------------------------------------------------------

    \65\ 83 FR 10628.
    \66\ Startup of production is defined in 40 CFR 60.5430a.
---------------------------------------------------------------------------

    Compressor stations located on the Alaskan North Slope experience 
the same extreme cold temperatures as the well sites located on the 
Alaskan North Slope. One petitioner \67\ cautioned that the monitoring 
technology specified in the 2016 NSPS OOOOa (i.e., optical gas imaging 
(OGI) and the instruments for Method 21) cannot reliably operate at 
well sites on the Alaskan North Slope for a significant portion of the 
year due to the lengthy period of extreme cold temperatures.\68\ 
According to manufacturer specifications, OGI cameras, which the EPA 
identified in the 2016 NSPS OOOOa as the BSER for monitoring fugitive 
emissions at well sites, are not designed to operate at temperatures 
below -4 [deg]F, \69\ and the monitoring instruments for Method 21, 
which the 2016 NSPS OOOOa provides as an alternative to OGI, are not 
designed to operate below +14 [deg]F. \70\ One commenter provided data, 
and the EPA confirmed with its own analysis, that temperatures below 
0[deg]F are a common occurrence on the Alaskan North Slope between 
November and April.\71\ In light of the above, there is no assurance 
that the initial and quarterly monitoring that must occur during that 
period of time are technically feasible for compressor stations located 
on the Alaskan North

[[Page 52072]]

Slope. Additionally, while the 2016 NSPS OOOOa provides a waiver from 
one quarterly monitoring event when the average temperature is below 0F 
for two consecutive months, this waiver would not fully address the 
issues for compressor stations located on the Alaskan North Slope. As 
discussed above, temperatures are below 0 [deg]F between November and 
April, which spans across two quarters. The low temperature wavier, 
only allows missing one quarterly monitoring event. Based on available 
information, we have concluded that semiannual monitoring is not 
feasible for well sites located on the Alaskan North Slope, therefore, 
conducting three quarterly monitoring events is likewise not feasible 
for compressor stations. Therefore, we are proposing amendments to the 
fugitive emissions requirements in the 2016 NSPS OOOOa as they apply to 
compressor stations located on the Alaskan North Slope.
---------------------------------------------------------------------------

    \67\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682.
    \68\ See Docket ID No. EPA-HQ-OAR-2010-0505-12434.
    \69\ See FLIR Systems, Inc. product specifications for GF300/320 
model OGI cameras at http://www.flir.com/ogi/display/?id=55671.
    \70\ See Thermo Fisher Scientific product specification for TVA-
2020 at https://assets.thermofisher.com/TFS-Assets/LSG/Specification-Sheets/EPM-TVA2020.pdf.
    \71\ See information on average hourly temperatures from January 
2010 to January 2018 at the weather station located at Deadhorse 
Alpine Airstrip, Alaska. Obtained from the National Oceanic and 
Atmospheric Administration (NOAA)'s National Centers for 
Environmental Information and summarized in Docket ID No. EPA-HQ-
OAR-2010-0505-12505.
---------------------------------------------------------------------------

    We are proposing to establish separate fugitive monitoring 
requirements for compressor stations located on the Alaskan North Slope 
because of the technical infeasibility issues with the operations of 
the monitoring instruments discussed above. Similar to well sites 
located on the Alaskan North Slope, we are proposing that new 
compressor stations that startup between September and March must 
conduct initial monitoring within 6 months of startup, or by June 30, 
whichever is later. Similarly, we are proposing that modified 
compressor stations located on the Alaskan North Slope that become 
modified between September and March must conduct initial monitoring 
within 6 months of the modification, or by June 30, whichever is later. 
Compressor stations that startup or are modified between April and 
August would meet the 60-day initial monitoring requirement in the 2016 
NSPS OOOOa. However, as discussed in section VI.B.3, we are soliciting 
comment on extending the time frame for conducting the initial 
monitoring for all well site and compressor station fugitive emissions 
components subject to the 2016 NSPS OOOOa, including those located on 
the Alaskan North Slope. Further, we are proposing that all compressor 
stations located on the Alaskan North Slope that are subject to the 
fugitive emissions requirements must conduct annual monitoring. 
Subsequent annual monitoring must be conducted at least 9 months apart, 
but no more than 13 months apart.
    As discussed in section VI.B.3 of this preamble (Initial Monitoring 
for Well Sites and Compressor Stations), the EPA is soliciting comment 
on whether to extend the period for conducting initial monitoring for 
well sites and compressor stations because additional time is needed to 
complete installation of equipment. For the same reason, the EPA is 
soliciting comment on whether to extend the time frame for initial 
monitoring for well sites that start up production and compressor 
stations that start up between April and August, and for those that are 
modified during this period. Further discussion on this topic is 
included in section VI.B.3 of this preamble, which describes the 
concerns raised and the timeframes suggested by petitioners (180 days) 
and the EPA (90 days) to address such concerns. In addition to the 
information specified in that subsection, we are soliciting comments 
and information specific to the well sites and compressor stations 
located on the Alaskan North Slope regarding allowing additional time 
for the initial monitoring. Upon receiving and reviewing the relevant 
information, the EPA may conclude that amendment to extend the 
timeframe for conducting the initial monitoring is necessary for all or 
some well site and compressor station fugitive emissions components 
subject to the 2016 NSPS OOOOa, including those located on the Alaskan 
North Slope.
    One petitioner \72\ requested that the EPA exempt well sites and 
compressor stations located on the Alaskan North Slope from fugitive 
emissions monitoring, similar to the exemptions from LDAR at natural 
gas processing plants provided in the 2012 NSPS OOOO and the 2016 NSPS 
OOOOa. The petitioner stated the reasons for applying an exemption to 
natural gas processing plants are also valid for well sites and 
compressor stations.
---------------------------------------------------------------------------

    \72\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682.
---------------------------------------------------------------------------

    The EPA exempted natural gas processing plants from LDAR 
requirements when issuing 40 CFR part 60, subpart KKK, in 1985 (1985 
NSPS KKK). At that time, we acknowledged ``that there are several 
unique aspects to the operation of natural gas processing plants north 
of the Arctic Circle. Because of the unique aspects of natural gas 
processing plants north of the Arctic Circle, the increased costs to 
perform routine leak detection and repair may result in an unreasonable 
cost effectiveness.'' \73\ We currently do not have sufficient 
information to suggest that the cost-effectiveness of the fugitive 
emissions requirements specific to well sites and compressor stations 
located on the Alaskan North Slope differ from the cost-effectiveness 
of the program generally. The information we do have related to the 
initial monitoring suggests that the average initial percentage of 
identified fugitive emissions for a well site located on the Alaskan 
North Slope is 2.38 percent.\74\ Additionally, this information 
represents some of the highest reported percentages of identified 
fugitive emissions from the data set are from well sites located on the 
Alaskan North Slope. Therefore, we are not proposing to exempt well 
sites located on the Alaskan North Slope from the fugitive emissions 
requirements. However, we are soliciting data to support an analysis of 
the cost-effectiveness of fugitive emissions monitoring programs for 
well sites and compressor stations located on the Alaskan North Slope, 
including the cost associated with performing annual fugitive emissions 
monitoring and repairs. Specific information that distinguishes 
differences in cost realized by sites located on the Alaskan North 
Slope from our model plant estimates would be useful.
---------------------------------------------------------------------------

    \73\ ``Equipment Leaks of VOC in Natural Gas Production 
Industry--Background Information for Promulgated Standards,'' EPA-
450/3-82-024b, May 1985.
    \74\ See memorandum EPA Analysis of Well Site Fugitive Emissions 
Monitoring Data Provided by API located at Docket ID No. EPA-HQ-OAR-
2017-0483. April 17, 2018.
---------------------------------------------------------------------------

2. Modification -Name: pb -Payroll No: 09854 -Folios: 66-69 -Date: 10/
10/18[FEDREG][VOL]*[/VOL][NO]*[/NO][DATE]*[/
DATE][PRORULES][PRORULE][PREAMB][AGENCY]*[/AGENCY][SUBJECT]*[/
SUBJECT][/PREAMB][SUPLINF][HED]*[/HED]?>
    Modification of Well Sites. For the purposes of fugitive emissions 
components at a well site, a modification is defined in 40 CFR 
60.5365a(i)(3) as (i) drilling a new well at an existing well site, 
(ii) hydraulically fracturing a well at an existing well site, or (iii) 
hydraulically refracturing a well at an existing well site. As the EPA 
explained in that rulemaking, these three activities, which are 
conducted to increase production, increase fugitive emissions at well 
sites in two ways. First, increased production will ``generate 
additional emissions at the well sites. Some of these additional 
emissions will pass through leaking fugitive emission components at the 
well sites (in addition to the emissions already leaking from those 
components).'' 81 FR 35881. Second, additional fugitive emissions can 
also result from installation of additional equipment. As the EPA 
observed, ``it is not uncommon that an increase in production would 
require additional equipment and, therefore, additional fugitive 
emission components at the well sites.'' Id.
    As previously mentioned, in a letter dated April 18, 2017, the 
Administrator granted reconsideration of several

[[Page 52073]]

aspects of the 2016 NSPS OOOOa, including its application of the 
fugitive emissions requirements at 40 CFR 60.5397a to low production 
well sites.\75\ The petitioner who raised this issue for 
reconsideration identified in its petition a perceived inconsistency 
between the EPA's justification for not exempting low production well 
sites from the fugitive emissions requirements and the EPA's rationale 
for the definition of modification for purposes of those same 
requirements.\76\ This petitioner observed that it appeared the EPA 
relied on data indicating the same equipment counts are present at all 
well sites, regardless of production levels, to justify regulating 
fugitive emissions at low production well sites, while defining 
modification by events that increase production (i.e., drilling a new 
well, hydraulic fracturing, or hydraulic refracturing), which the EPA 
concludes will increase emissions whether or not there is change in 
component counts. The petitioner then stated that:
---------------------------------------------------------------------------

    \75\ See Docket ID No. EPA-HQ-OAR-2010-0505-7730.
    \76\ See Docket ID No. EPA-HQ-OAR-2010-0505-7685.

    EPA's rationale, that fugitive emissions are a function of the 
number and types of equipment, and not operating parameters such as 
pressure and volume, is inconsistent with EPA's justification for 
what constitutes a `modification' for an existing well site. EPA 
assumes that fracturing or refracturing an existing well will 
increase emissions because of the additional production, i.e., the 
additional pressure and volume. EPA cannot ignore the laws of 
physics to the detriment of low production wells in one instance and 
then `honor' them in another context to eliminate an `emissions 
increase' requirement in the traditional definition of 
`modification.' \77\
---------------------------------------------------------------------------

    \77\ See Docket ID No. EPA-HQ-OAR-2010-0505-7685, page 6.

    In addition to the issues raised regarding an inconsistency with 
our treatment of fugitive emissions from low production well sites and 
what constitutes a modification (as discussed in section VI.B.1), 
several petitioners stated that hydraulically refracturing a well alone 
would not increase emissions from the fugitive emissions components and 
suggested that emissions would increase from a refractured well only if 
additional permanent equipment is also installed.\78\ According to one 
petitioner,
---------------------------------------------------------------------------

    \78\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.

[a] well that is refractured typically does not require additional 
production equipment and does not typically operate at a pressure 
higher than before the refracturing since that pressure is set by 
the gas gathering system pressure. Therefore, as long as a 
significant piece of process equipment is not constructed along with 
the refracture, there is no emissions increase and there is no 
`modification' as defined in CFR part 60.2. \79\
---------------------------------------------------------------------------

    \79\ Docket ID No. EPA-HQ-OAR-2010-0505-7682, p. 16.

    In light of the above, the EPA has provided a more detailed 
explanation below for the definition of modification of fugitive 
emissions components at well sites, including how an increase in 
production can increase fugitive emissions at well sites even without 
the addition of equipment, and therefore no addition of fugitive 
emissions components. The EPA has also re-evaluated its treatment of 
low production well sites, which is discussed in section VI.B.1 of this 
preamble.
    There is no dispute that an addition of processing equipment, and 
attendant fugitive emissions components, in conjunction with 
refracturing a well will result in a modification. Further, as 
explained in the 2016 NSPS OOOOa and in more detail below, an increase 
in the number of components is not the sole reason for an increase in 
fugitive emissions when there is an increase in production.
    A well is refractured for the purpose of increasing production 
rates. An increase in the production rate necessitates, by definition, 
an increase in the molar flow rate. An increase in molar flow rate can 
be accomplished through an increase in operating pressure (and 
attendant mass per unit of volume) and/or volumetric flow rate. An 
increase in volumetric flow rate can be accomplished through an 
increase to the velocity of flow, an increase to cross-sectional area 
of the flow path, or, if flow is intermittent, an increase to the time 
duration of flow (e.g., duration of flow events or frequency of flow 
events). Increasing velocity of flow of production fluids through 
process equipment can only be accomplished through an increase in the 
pressure drop across the system. Where increased production throughput 
is routed through a system of production equipment that is not 
physically changed, the cross-sectional area of the flow path through 
the equipment does not change. Therefore, the increase in production 
rate requires an increase to either the operating pressure and/or the 
duration or frequency of flow events. Where operating pressure is 
increased, the pressure increase will increase the molar flow rate of 
fugitive emissions from leaking fugitive emission components. These 
increased emissions on components with existing fugitive emissions will 
occur even if the increased operating pressure does not result in 
additional components with fugitive emissions at existing design stress 
points, which is an additional source of potential fugitive emissions 
increases. Increasing duration or frequency of flow events will not be 
an option unless flow is intermittent. Where flow is intermittent in 
the process and flow event duration or frequency is increased (e.g., 
through longer dump events or more frequent dump events), additional 
molar flow rate will pass through components with fugitive emissions 
due to increased periods of flow through that component at the same 
pressure. Therefore, as was stated in the 2016 NSPS OOOOa preamble 
language, increased production will result in ``[s]ome of these 
additional emissions [passing] through leaking fugitive emission 
components at the well sites (in addition to the emissions already 
leaking from those components).'' 81 FR 35881.
    There is also a third instance in which increased production from 
modification of a well site could cause an increase in emissions from 
fugitive emissions components without additional equipment, and 
therefore, without additional fugitive emissions components. Absent 
additional stages of separation or an otherwise-accomplished decrease 
in the pressure at the final stage of separation prior to the storage 
vessels, increased production throughput to storage vessels increases 
the flash emissions at those storage vessels. Where storage vessels are 
affected facilities for purposes of this rule, the rule contains 
separate requirements for storage vessel covers and CVS to be designed 
and operated to route all emissions to a control device. However, where 
controlled storage vessels are not affected facilities because legally 
and practically enforceable permits limit the potential VOC emissions 
to below 6 tpy, the covers and CVS are included in the fugitives 
monitoring program for the well site as a fugitive emissions component. 
In either scenario, it is possible for increased throughput to these 
controlled storage vessels at a well site to exceed the design capacity 
of the vapor control system, which may result in additional emissions 
from storage vessel thief hatches or other openings.
    For the reasons stated above, we propose to maintain our conclusion 
that refracturing of an existing well will increase fugitive emissions. 
We solicit comments on our rationale described above. Specifically, we 
solicit comments and data on whether emissions from fugitive emissions 
components will

[[Page 52074]]

increase following a refracture even if the equipment counts and 
operating pressures remain the same. Further, we are soliciting 
comments and data about how changes in production may influence the 
operating pressures of the well site. Additionally, we are soliciting 
comment and data on whether an increase in pressure alone (without 
additional equipment) would result in more fugitive emissions (e.g., 
cause new fugitive emissions that were not otherwise present or would 
result in an increase in the fugitive emissions from an already leaking 
fugitive emissions component). Finally, we are soliciting comment and 
information on other factors, such as changes in the gas gathering 
system, that may influence the operating pressures of the well site.
    During the implementation of the 2016 NSPS OOOOa, several questions 
were raised regarding the modification of a separate tank battery for 
the purposes of fugitive emissions monitoring. The definition of well 
site in 40 CFR 60.5430a states, ``For purposes of the fugitive 
emissions standards at Sec.  60.5397a, well site also means a separate 
tank battery surface site collecting crude oil, condensate, 
intermediate hydrocarbon liquids, or produced water from wells not 
located at the well site (e.g., centralized tank batteries).'' 
Stakeholders have commented to the EPA that there is confusion 
regarding when a modification of fugitive emissions components has 
occurred at a separate tank battery. Similar to the information from 
petitioners regarding modifications without a change in equipment or 
component counts at a well site, stakeholders have also claimed that 
sending process fluids from a new well or existing hydraulically 
fractured or refractured well that is not located at the separate tank 
battery will not necessarily increase the emissions from the fugitive 
emissions components at the separate tank battery. Instead, 
stakeholders have suggested that emissions increase only when 
additional processing equipment, such as storage vessels, separators, 
or compressors, is installed in conjunction with the introduction of 
additional process fluids received from these off-site wells.
    The EPA is proposing a clarification to address modifications of 
the collection of fugitive emissions components at well sites when the 
well site is a separate tank battery with no wells located at the tank 
battery. While the regulatory text is clear about what constitutes a 
modification when a well is located at the separate tank battery, the 
regulatory text is less clear when there are no wells at the tank 
battery. To clarify the definition of modifications for separate tank 
batteries, we are proposing specific amendments to clarify when a 
modification occurs at a well site, including a well site that is a 
separate tank battery. We are proposing to amend the language in 40 CFR 
60.5365a(i) to add two additional instances to clarify when there is a 
modification to the collection of fugitive emissions components located 
at a separate tank battery, such as a centralized tank battery (which 
itself is a well site as defined in 40 CFR 60.5430a). First, when 
production from a new, hydraulically fractured, or hydraulically 
refractured well is sent to an existing separate tank battery, the 
collection of fugitive emissions components at the separate tank 
battery has been modified. Second, when a well site that is subject to 
fugitive emissions requirements removes the major production and 
processing equipment, such that it becomes a well head only well site, 
and sends the production to an existing separate tank battery, the 
collection of fugitive components at that separate tank battery has 
modified. In both instances, a physical or operational change occurs at 
an existing separate tank battery because additional production from a 
well site is sent to that separate tank battery, and this change 
results in an increase in fugitive emissions at that tank battery. We 
are soliciting comment on these proposed amendments to the definition 
of modification of the collection of fugitive emissions components 
located at a well site, including the treatment of separate tank 
batteries as well sites for the purposes of fugitive emissions 
requirements. Additionally, we are soliciting comment on other options 
for modifications of a separate tank battery for purposes of fugitive 
emissions monitoring. For example, we are soliciting comment on whether 
we should define a separate tank battery as a separate affected 
facility, instead of defining this source as a well site. Further, we 
are soliciting comment on what would constitute a modification of a 
separate tank battery affected facility, or other options for a 
modification if the definition remains as currently proposed. Finally, 
the EPA is soliciting information related to the permitting of such 
separate tank batteries and information related to how states have 
regulated these sources when a well is not located at the site.
    Modification of Compressor Stations. For the purposes of fugitive 
emissions components at a compressor station, a modification is defined 
in 40 CFR 60.5365a(j) as (1) the installation of an additional 
compressor at an existing compressor station or (2) the replacement of 
one or more compressors at an existing compressor station that results 
in a net increase in the total horsepower to drive the compressor(s) 
that are replaced at the compressor station. We are not proposing any 
changes to this definition; however, we are soliciting comment on 
whether the engine horsepower is the correct measure of increased 
emissions from the collection of fugitive emissions components.
    Further, the EPA is clarifying the type of compressors that would 
trigger a modification for the purposes of fugitive emissions at a 
compressor station. In the preamble to the 2016 NSPS OOOOa, the EPA 
clarified that this definition refers to instances where ``the design 
capacity and potential emissions of the compressor station would 
increase.'' 81 FR 35864. Therefore, it is possible that the addition of 
a compressor would not be considered a modification where the overall 
design capacity of the compressor station is not increased. For 
example, the addition of a vapor recovery unit (VRU) compressor, such 
as a screw or vane compressor, would not be a modification for purposes 
of the compressor station fugitive emissions standards. Adding a VRU 
compressor does not increase the overall design capacity of the 
compressor station for the following reasons. VRU compressors are 
installed to recover methane and VOC emissions; they are not designed 
to ``move natural gas at increased pressure through gathering or 
transmission pipelines, or into or out of storage.'' Therefore, the 
addition of a VRU compressor does not increase the overall design 
capacity of a compressor station, and does not result in a modification 
of the compressor station for the purposes of fugitive emissions 
monitoring. The EPA is not proposing a definition for compressor in 
this action because the explanation provided above related to the 
definition of compressor station does not support the need for a 
definition, and because the 2016 NSPS OOOOa already contains 
definitions of centrifugal and reciprocating compressors, which are the 
only compressor affected facilities.
3. Initial Monitoring for Well Sites and Compressor Stations
    The 2016 NSPS OOOOa requires completion of initial monitoring for 
well sites and compressor stations by June 3, 2017, or 60 days after 
startup, whichever is later. For well sites, the startup of production 
marks the beginning of the initial monitoring

[[Page 52075]]

survey period for the collection of fugitive emissions components at a 
well site. Similarly, for compressor stations, the startup of the 
compressor station marks the beginning of the initial monitoring survey 
period.
    Petitioners on the 2016 NSPS OOOOa have requested that the timing 
of fugitive emissions initial monitoring surveys be revised to allow 
for integration into existing monitoring programs.\80\ One petitioner 
asserted that there are numerous challenges to setting up and 
implementing a fugitive monitoring program. The petitioner reported 
that even with the EPA's one-year phase-in allowance, there are initial 
inspection timing challenges (e.g., because of the significant 
distances between oil and gas sites). Petitioners requested that the 
EPA consider allowing 180 days for the initial survey. According to the 
petitioners, allowing for 180 days would not result in significantly 
more emissions and that, on average, half of the sites would likely 
conduct their initial survey in less than 90 days and half would likely 
conduct their initial survey between 90 and 180 days.
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    \80\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-10791.
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    Between proposal and promulgation of the 2016 NSPS OOOOa, several 
industry comments recommended a 90-day time period (in lieu of the 30-
day time period we initially proposed) to complete the initial survey 
to (1) address time and logistical capacities of oil and gas field 
crews and potential limited availability of monitoring contractors, (2) 
be consistent with the Ohio Environmental Protection Agency's General 
Air Permit for Oil and Gas Well Site Production Operations (General 
Permit 12.2), and (3) provide a more realistic time frame to perform an 
initial survey without potentially resulting in safety issues while 
initial oil and gas production and completion activities are taking 
place on the well pad.\81\ Other industry comments were received 
requesting that the EPA allow the initial fugitive survey to occur 
within 180 days from startup of a new well site or compressor station 
to (1) be consistent with similar LDAR programs, such as NSPS KKK and 
NSPS OOOO (where leak detection is currently imposed at natural gas 
processing plants), and (2) allow owners or operators time to do a 
thorough check of all new equipment installations before the 
survey.\82\ One of the commenters (also a petitioner) reported that 180 
days is needed to prepare for monitoring of the new or modified well 
site and ensure that such monitoring is conducted during the next 
scheduled monitoring period that would include all the well sites in 
the area.\83\ They asserted that hiring third-party contractors to 
monitor one remote well site is inefficient and costly.
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    \81\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-6808, EPA-HQ-OAR-
2010-0505-6935 and EPA-HQ-OAR-2010-0505-6960.
    \82\ See Docket ID EPA-HQ-OAR-2010-0505-6857.
    \83\ See Docket ID EPA-HQ-OAR-2010-0505-6884.
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    We have not received data indicating that initial monitoring cannot 
be completed within the currently required 60-day timeframe. We propose 
to maintain our conclusion that, in light of the need to complete 
initial monitoring in a timely manner after startup of production for 
well sites and the startup or modification for compressor stations to 
verify the proper installation of equipment, waiting 180 days for 
initial monitoring is too long after the installation of equipment to 
verify its proper installation. However, we are soliciting data that 
supports or refutes the claims by the petitioner that 180 days are 
necessary for proper installation of equipment before conducting 
initial monitoring would not result in significantly more emissions. 
Assuming we receive information that supports extending the initial 
monitoring deadline to give more time for installing equipment, we 
think it is possible these tasks may be nevertheless completed in a 
shorter time frame than the suggested 180 days discussed above. We are, 
therefore, soliciting comment and supporting data for changing the 
initial monitoring deadline to 90 days from 60 days after the startup 
of production for well sites and the startup or modification for 
compressor stations. Specific data would need to outline the 
difficulties with completing initial monitoring within the 60 days 
required in the 2016 NSPS OOOOa. In summary, while we are proposing to 
maintain the 60-day requirement, we solicit comment and information 
regarding the request to extend to 180 days, as well as an intermediate 
90-day requirement.
    We recognize that the 2016 NSPS OOOOa includes a waiver from 
quarterly monitoring at compressor stations after recognizing there are 
areas of the country that may experience temperatures below 0[deg] for 
a period of 60 days. However, as discussed in detail in section VI.B.4, 
we are not sure where any areas of the country would utilize this 
waiver. The EPA is soliciting comment on how cold weather may impact 
the ability to comply with the 60-day initial monitoring deadline for 
well sites and compressor stations.
4. Low Temperature Waivers
    In the 2016 NSPS OOOOa, owners and operators are granted a waiver 
from one quarterly monitoring event at compressor stations if the 
average temperature is below 0[deg] for two consecutive quarters. 40 
CFR 60.5397a(g)(5). In the preamble to the 2016 NSPS OOOOa we stated 
that the waiver was included for two reasons: (1) There were concerns 
raised by commenters that extreme winter weather created risk for the 
safety of monitoring survey personnel and (2) the manufacturer 
specifications indicate that OGI cameras may not reliably operate at 
temperatures below 0[deg]. 80 FR 56668. In light of the proposed 
changes to monitoring frequencies discussed in section VI.B.1 of this 
preamble, we are proposing to remove the low temperature waiver because 
it is no longer relevant. The EPA is soliciting comment and supporting 
data that would indicate a need to maintain the waiver.
5. Repair Requirements
    Repair. After detection of fugitive emissions, the 2016 NSPS OOOOa 
requires repair of these components within 30 days of detection of the 
fugitive emissions. Further, the owner or operator must resurvey the 
component within 30 days of the repair in order to verify successful 
repair. 40 CFR 60.5397a(h)(1) and (3).
    Several questions were raised during implementation that required 
reconsideration of the repair requirements. Specifically, stakeholders 
asked about the situation where repairs were completed during the 30-
day required timeframe but the resurvey identified the presence of 
fugitive emissions, indicating unsuccessful repair.
    The EPA recognizes the requirements in the 2016 NSPS OOOOa may 
create an unintended noncompliance issue with the repair requirements. 
Therefore, we are proposing to amend the repair requirements to require 
a ``first attempt at repair'' within 30 days of detection of fugitive 
emissions, followed by a requirement that identified fugitive emissions 
be ``repaired'' within 60 days of detection. We are proposing 
definitions for ``repaired'' and ``first attempt at repair'' as related 
to the fugitive emissions requirements. The EPA is proposing to define 
``repaired,'' for purposes of fugitive emissions monitoring, as 
``fugitive emissions components are adjusted, replaced, or otherwise 
altered, in order to eliminate fugitive emissions as defined in 40 CFR 
60.5397a of this subpart and is

[[Page 52076]]

resurveyed as specified in 40 CFR 60.5397a(h)(4) and it is verified 
that emissions from the fugitive emissions components are below the 
applicable fugitive emissions definition.'' Additionally, we are 
proposing the definition for ``first attempt at repair'' for the 
purposes of fugitive emissions monitoring as ``an action taken for the 
purpose of stopping or reducing fugitive emissions of methane or VOC to 
the atmosphere. First attempts at repair include, but are not limited 
to, the following practices where practicable and appropriate: 
Tightening bonnet bolts; replacing bonnet bolts; tightening packing 
gland nuts; ensuring the thief hatch is properly seated or injecting 
lubricant into lubricated packing.'' These proposed definitions for 
``repaired'' and ``first attempt at repair'' are specific to the 
fugitive emissions requirements and would not replace the definitions 
for ``repaired'' or ``first attempt at repair'' within the requirements 
for equipment leaks at onshore natural gas processing plants referenced 
in 40 CFR part 60, subpart VVa. We are soliciting comment on these 
proposed repair requirements and definitions.
    Delay of Repair. As amended on March 12, 2018, the 2016 NSPS OOOOa 
allows for delay of repair if the repair is technically infeasible; 
requires a vent blowdown, a compressor station shutdown, a well 
shutdown, or well shut-in; or would be unsafe to repair during 
operation of the unit. Repairs meeting one of these criteria must be 
completed during the next scheduled compressor station shutdown, well 
shutdown, or well shut-in; after a planned vent blowdown; or within 2 
years, whichever is earlier. The amendment addressed the concerns 
associated with requiring repair during unscheduled or emergency events 
by removing such a requirement.
    In addition to concerns with requiring repair during unscheduled or 
emergency events, several petitioners raised additional concerns with 
the provisions regarding the delay of repair for fugitive emissions 
components at well sites and compressor stations.\84\ One petitioner 
stated that the 2-year delay should be reevaluated because no specific 
data was provided to support that deadline.\85\ Further, other 
petitioners stated that blowdowns, shutdowns, and well shut-ins might 
not always involve depressurizing the specific equipment that needs 
repair. The EPA is soliciting comment on instances when equipment 
cannot be isolated during vent blowdowns, compressor station shutdowns, 
well shutdowns, and well shut-ins to allow for repair of components 
with fugitive emissions. Further, the EPA is soliciting comment and 
supporting information on the instances where delayed repairs cannot be 
conducted during any of the events listed in the rule and under what 
event or time frame delayed repairs can be conducted for those 
instances.
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    \84\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7683, and EPA-HQ-OAR-2010-0505-7686.
    \85\ See Docket ID No. EPA-HQ-OAR-2010-0505-7683.
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    Finally, we are clarifying when a repair can be delayed. There are 
three circumstances when repair can be delayed: (1) When the repair is 
technically infeasible, (2) when the repair requires a vent blowdown, a 
compressor station shutdown, a well shut-in, or a well shutdown, and 
(3) when the repair is unsafe during operation of the unit.\86\ The 
2016 NSPS OOOOa requires an explanation of each repair that is delayed 
as well.\87\ As discussed in section VI.B.1, we have added 1 controlled 
storage vessel per model plant because when the controlled storage 
vessel is not subject to the control requirements in 40 CFR 60.5395a, 
the thief hatch and other openings are subject to fugitive emissions 
requirements, per the definition of fugitive emissions components in 40 
CFR 60.5430a. The EPA believes that thief hatches on controlled storage 
vessels which are part of the fugitive emissions program would not be 
subject to delay of repair under any of these circumstances; however, 
we are soliciting comment for any instance when delaying repair on a 
thief hatch may be necessary. The EPA acknowledges that questions may 
arise as to whether opening a thief hatch is considered a vent 
blowdown. While we do not consider this to constitute a vent blowdown, 
we are soliciting comment on whether clarification within the 
regulatory text is necessary for this point. We are also soliciting 
comment on the 2-year deadline for completion of delayed repairs.
---------------------------------------------------------------------------

    \86\ See 40 CFR 60.5397a(h)(2).
    \87\ See 40 CFR 60.5420a(b)(7)(ii)(J).
---------------------------------------------------------------------------

6. Definitions Related to Fugitive Emissions at Well Sites and 
Compressor Stations
    Third-party equipment. In the 2016 NSPS OOOOa, all fugitive 
emissions components located at a well site, regardless of ownership, 
are subject to the monitoring and repair requirements for fugitive 
emissions in the 2016 NSPS OOOOa. As defined in 40 CFR 60.5430a, the 
term `fugitive emissions component' means ``any component that has the 
potential to emit fugitive emissions of methane or VOC at a well site 
or compressor station, including, but not limited to valves, 
connectors, pressure relief devices, open-ended lines, flanges, covers 
and closed vent systems not subject to Sec.  60.5411a, thief hatches or 
other openings on a controlled storage vessel not subject to Sec.  
60.5395a, compressors, instruments, and meters'' and the term `well 
site' means ``one or more surface sites that are constructed for the 
drilling and subsequent operation of any oil well, natural gas well, or 
injection well.'' Several petitioners raised concerns that these 
definitions are too broad and requested that the EPA should exclude 
equipment that is owned and operated by a third-party.\88\
---------------------------------------------------------------------------

    \88\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-7684.
---------------------------------------------------------------------------

    First, petitioners requested an exemption for equipment owned and 
operated by midstream companies because that equipment is owned by 
legally distinct entities, and applicability of the standards to 
midstream assets would be based solely on the actions of the upstream 
producers. Second, petitioners stated that the EPA is incorrect in 
suggesting that contractual agreements between upstream producers and 
midstream owners and operators would be appropriate for managing 
fugitive emissions monitoring and repair(s) at the well site. The 
petitioners stated that, due to the complexity of contractual 
agreements between different owners and operators at a well site, each 
individual owner or operator may need to develop and implement separate 
fugitive emissions monitoring programs. The petitioner further stated 
that doing so would add significant and unnecessary costs that the EPA 
did not consider.\89\
---------------------------------------------------------------------------

    \89\ See Docket ID No. EPA-HQ-OAR-2010-0505-7684.
---------------------------------------------------------------------------

    In the response to comment document for the 2016 NSPS OOOOa we 
stated that cooperative agreements could be used to resolve any 
fugitive emissions identified during surveys, but we acknowledged in 
the 2017 NODA that confusion remained over the applicability of the 
fugitive emissions requirements as they relate to ancillary midstream 
assets that are owned by companies that are legally distinct from the 
well site owner and operator and that could have limited emissions. 82 
FR 51798. In their comments on the 2017 NODA, one petitioner noted that 
since the components associated with the gas gathering and metering 
systems

[[Page 52077]]

serve the ``crucial commercial purpose in calculating gas accepted by 
the gathering company and the related revenue accounting,'' the 
midstream operators could not allow the production operators to access 
this equipment.\90\ This petitioner further clarified that due to this 
limitation, the midstream operator would need to implement a separate 
fugitive emissions program for a limited number of components. 
Additionally, the petitioner stated there are significant practical 
issues with renegotiating contracts, especially as well sites are 
modified over time. We did not consider this issue during development 
of the 2016 NSPS OOOOa.
---------------------------------------------------------------------------

    \90\ See Docket ID No. EPA-HQ-OAR-2010-0505-13436.
---------------------------------------------------------------------------

    In light of the concerns raised by the petitioners, the EPA is 
proposing to amend the definition of ``well site,'' for the purposes of 
fugitive emissions monitoring, to exclude the flange upstream of the 
custody meter assembly, and fugitive emissions components located 
downstream of this flange. The EPA understands this custody meter is 
used effectively as the cash register for the well site and provides a 
clear separation for the equipment associated with production of the 
well site, and the equipment associated with putting the gas into the 
gas gathering system. Additionally, the proposed definition would 
exclude only a small number of fugitive emissions components, and we do 
not believe it would be cost-effective to require a separate fugitive 
emissions program for these components. We are also proposing a 
definition for the custody meter as ``the meter where natural gas or 
hydrocarbon liquids are measured for sales, transfers, and/or royalty 
determination,'' and the custody meter assembly as ``an assembly of 
fugitive emissions components, including the custody meter, valves, 
flanges, and connectors necessary for the proper operation of the 
custody meter.'' We are limiting the exemption within the definition of 
a well site to the flange upstream of the custody meter because we are 
not aware of similar issues with monitoring other third-party equipment 
at a well site. The EPA is soliciting comment on this proposed change 
to the ``well site'' definition, the proposed definition of ``custody 
meter,'' the proposed definition of ``custody meter assembly,'' and 
suggestions for other ways which provide a clear separation to 
distinguish the third-party equipment described above at a well site, 
for the purposes of fugitive emissions monitoring.
    Applicability to Saltwater Disposal Wells. In addition to concerns 
about the definition of a ``well site'' as it relates to third party 
equipment, the EPA received feedback from industry seeking confirmation 
that a saltwater disposal well is not an injection well as the term is 
used in the definition for well site and, therefore, not subject to the 
fugitive emission standards at 40 CFR 60.5397a. They asserted that 
disposal wells are not injection wells and that the disposed liquid 
consists of water with insignificant amounts of stabilized skim oil 
that is never in vapor state at normal or elevated conditions. The 
commenters were concerned that, although they did not believe it was 
the EPA's intent to require fugitive emissions monitoring of saltwater 
disposal wells, they will nevertheless have to comply with those 
requirements because, as written, the definition of ``well site'' is 
ambiguous with respect to the status of saltwater disposal wells.
    Deposits of oil and natural gas can be found in porous rocks and 
shale, where saltwater is also found. Oil and gas pumped out of the 
earth that is not pure enough for distribution because of saltwater and 
other chemicals/impurities go through a separation phase or are treated 
with chemicals that extract the impurities. After the oil or gas is 
treated, the water that remains (referred to as ``saltwater'') is 
subject to handling requirements.\91\ Saltwater, or produced water, 
that results from bringing the oil and gas up to the surface (ejected 
from the well) during production operations is generally (1) recycled, 
(2) returned to the reservoir for fluid reinjection or (3) injected 
into underground porous rock formations not productive of oil or gas, 
and sealed above and below by unbroken, impermeable strata.\92\ The 
third option is considered saltwater disposal (or oilfield wastewater 
disposal). Regulations for the disposal of this water vary from state 
to state, but the EPA monitors disposal to ensure ground water is not 
contaminated through Underground Injection Control (UIC) programs under 
the federal Safe Drinking Water Act for surface and groundwater 
protection. The EPA had not considered these UIC Class II oilfield 
wastewater disposal wells during the development of the fugitive 
emissions standards in the 2016 NSPS OOOOa.
---------------------------------------------------------------------------

    \91\ http://www.tech-flo.net/salt-water-disposal.html.
    \92\ Barnett Shale Energy Education Council. What are Saltwater 
Disposal Wells? Air and Water Quality. http://www.bseec.org/what_are_saltwater_disposal_wells.
---------------------------------------------------------------------------

    For the reasons stated below, we are proposing to exclude UIC Class 
II oilfield wastewater disposal wells from the well site definition and 
are proposing a definition for a UIC Class II oilfield wastewater 
disposal well to distinguish them from injection wells subject to the 
rule. It is our understanding that the storage vessels located at these 
disposal facilities have low methane and VOC emissions, and thus are 
not subject to the control requirements for storage vessels found in 40 
CFR 60.5395a, do not require controls for permitting purposes, and 
would not be subject to fugitive emissions monitoring because they are 
uncontrolled. Further, it is our understanding that the number of 
fugitive emissions components at these facilities are typically low, 
including water pumps and a limited number of valves or connectors, 
which are expected to have negligible if any fugitive emissions. These 
proposed changes clarify the universe of well sites subject to the 
fugitive emissions standards. Our proposed definition for a ``UIC Class 
II oilfield disposal well'' is ``a well with a UIC Class II permit 
where wastewater resulting from oil and natural gas production 
operations is injected into underground porous rock formations not 
productive of oil or gas, and sealed above and below by unbroken, 
impermeable strata.'' Further, we are proposing that UIC Class II 
disposal facilities without wells that produce oil or natural gas are 
not considered well sites for the purposes of fugitive emissions 
requirements. We are soliciting comment on this proposed definition and 
on the proposed exemption for UIC Class II wastewater disposal wells 
and disposal facilities from fugitive emissions monitoring and repair, 
including data to support or refute our understanding that these sites 
have limited fugitive emissions components.
    Definition of well site. As discussed in the sections regarding 
third-party equipment and saltwater disposal wells, the EPA is 
proposing to amend the definition of well site as follows:

    Well site means one or more surface sites that are constructed 
for the drilling and subsequent operation of any oil well, natural 
gas well, or injection well. For purposes of fugitive emission 
standards at Sec.  60.5397a, a well site also means a separate tank 
battery surface site collection crude oil, condensate, intermediate 
hydrocarbon liquids, or produced water from wells not located at the 
well site (e.g., centralized tank batteries). Also for the purposes 
of the fugitive emissions standards at Sec.  60.5397a, a well site 
does not include (1) UIC Class II oilfield disposal wells and 
disposal facilities and (2) the flange upstream of the custody meter

[[Page 52078]]

assembly and equipment, including fugitive emissions components, 
located downstream of this flange.

    Startup of Production. The EPA defines the ``startup of 
production'' in the 2016 NSPS OOOOa as 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.'' 40 CFR 60.5430a. For purposes of the 
fugitive emissions requirements in 40 CFR 60.5397a, the initial 
monitoring survey follows the startup of production. We received 
questions from stakeholders that suggested this definition would limit 
the fugitive emissions requirements to well sites with hydraulically 
fractured wells and not those with conventional wells. While the first 
trigger for modification is based on the drilling of a new well, 
regardless if it is hydraulically fractured or not, the definition of 
startup of production is linked to flowback, which is inherently an 
effect following hydraulic fracturing.
    We are proposing to amend the definition of ``startup of 
production'' in this proposal to address how it relates to the fugitive 
emissions requirements. Specifically, we are proposing that, for the 
purposes of the fugitive monitoring requirements, startup of production 
means ``the beginning of the continuous recovery of salable quality gas 
and separation and recovery of any crude oil, condensate or produced 
water.'' We are soliciting comment on this proposed definition change 
as it relates to wells that are not hydraulically fractured.
7. Fugitive Emissions Monitoring Plan
    The 2016 NSPS OOOOa requires that each fugitive emissions 
monitoring plan include a sitemap and a defined observation path.\93\ 
As we are clarifying in this proposed action, these requirements were 
meant to apply only to owners and operators using OGI for monitoring 
surveys, not to owners and operators using Method 21. In addition to 
clarifying this intent, we are also proposing options that owners and 
operators using OGI for monitoring surveys can comply with in lieu of 
the observation path requirement.
---------------------------------------------------------------------------

    \93\ See 40 CFR 60.5397a(d)(1) and (2).
---------------------------------------------------------------------------

    As we discussed in the preamble to the 2016 NSPS OOOOa, the purpose 
of the observation path is to ensure that the OGI operator visualizes 
all of the components that must be monitored. In a traditional 
monitoring scenario using Method 21, the owner or operator tags all of 
the equipment that must be monitored, and when the operator 
subsequently inspects the affected facility, the operator scans each 
component's tag and notes the component's instrument reading. The EPA 
realizes that this is a time-consuming practice that requires close 
contact with each component, whereas with OGI, the operator can be away 
from the components and still monitor several components 
simultaneously. The observation path \94\ was intended to offer owners 
and operators an alternative to the traditional tagging approach while 
still providing assurance that the owner or operator has met the 
obligation to monitor all components. 81 FR 35860.
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    \94\ In the preamble to the 2016 NSPS OOOOa, we also noted that 
the purpose of using the term ``observation path'' was to clarify 
that the emphasis is on the field of view of the OGI instrument, not 
the physical location of the OGI operator. 81 FR 35860.
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    Petitions received on the 2016 NSPS OOOOa assert that there is no 
added benefit to including the sitemap and defined observation path in 
the fugitive emissions monitoring plan and that they should be 
removed.\95\ Industry representatives report that, in many cases, 
sitemaps do not exist. They further report that there are significant 
added costs associated with the requirement to develop site-specific 
details for a sitemap and a defined observation path for each site and 
that there may be hundreds to thousands of different sites. These 
representatives express concern that sitemaps could also change, 
subjecting them to additional costs associated with revising the 
fugitive emissions monitoring plan without any added benefit. While we 
do think that it is necessary to revise monitoring plans when equipment 
at the site changes,\96\ we generally expected these to be one-time 
requirements, unless additional equipment is added to the site. 81 FR 
35860. The EPA is specifically seeking comment on whether this 
assumption is incorrect and, if not, we solicit information on the cost 
to develop and revise the sitemap, including the cost to document an 
observation path, the cost to revise a sitemap and observation path, 
and the frequency with which the sitemap and observation path need to 
be updated. We are also clarifying that plot plans can be substituted 
for sitemaps, as these two items serve the same function, i.e., to 
provide information on the locations of equipment on site.
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    \95\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7686 and EPA-HQ-
OAR-2010-0505-10791.
    \96\ As we stated in the preamble to the 2016 NSPS OOOOa, we do 
not expect facilities to create overly detailed process and 
instrumentation diagrams to describe the observation path. The 
observation path description could be a simple schematic diagram of 
the facility site or an aerial photograph of the facility site, as 
long as such a photograph clearly shows locations of the components 
and the OGI operator's walking path. 81 FR 35860.
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    Industry representatives have also expressed concern that the 
fugitive emissions monitoring plan as written in 40 CFR 60.5397a(d) may 
cause enforcement issues in cases where the fugitive emissions 
monitoring plan is not followed exactly (specifically related to the 
defined observation path), even when the deviation is not critical and 
the monitoring plan is still effective. In response to public comments 
on the 2016 NSPS OOOOa, we stated that the elements required in the 
monitoring plan are necessary to judge the quality of the fugitive 
emissions survey, in light of the fact that the EPA does not have a 
standard method for use of OGI, but that we fully expected a trained 
and experienced camera operator to know when deviations from the 
standard monitoring plan are necessary and to make these 
deviations.\97\ However, while deviations may not impact the camera's 
detection ability and can actually improve the detection ability, this 
does not mean that deviations from the monitoring plan should not be 
noted because this record provides valuable information to air agency 
reviewers on how surveys are conducted and whether the deviations from 
the monitoring plan are adequate and warranted. We note that deviations 
from the monitoring plan are not necessarily deviations from the 
requirements of the rule.
---------------------------------------------------------------------------

    \97\ See Docket ID No. EPA-HQ-OAR-2010-0505-7632, Chapter 4, 
page 4-708.
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    While we are not proposing to remove the sitemap and observation 
path elements from the fugitive emissions monitoring plan, we are 
proposing two alternatives to address petitioner/industry 
representative concerns. First, in lieu of the defined observation 
path, we are proposing to add language to 40 CFR 60.5397a(d) that 
allows an owner or operator to describe how each type of equipment will 
be effectively monitored, including a description and location of the 
fugitive emissions components located on the equipment. The sitemap 
would include the locations of the pieces of equipment when complying 
with this option. Second, in lieu of meeting the sitemap and defined 
observation path requirements, we are proposing to add language to 40 
CFR 60.5397a(d) to extend the inventory requirement that is currently 
in 40 CFR 60.5397a(d)(3) for when an owner or operator chooses to 
perform a survey with Method 21 as an option for owners and operators 
who perform surveys with OGI. We believe

[[Page 52079]]

that both of these options provide assurances similar to the 
observation path that the owner or operator meets the requirement to 
visualize all components.
    In summary, the EPA is retaining the requirements for the sitemap 
and observation path in the fugitive monitoring plan, but is also 
proposing two alternatives to these requirements. The EPA is soliciting 
comment on these proposed alternatives. Additionally, we are soliciting 
comment on other potential options that would serve the same functions 
as an observation path and sitemap. We are particularly interested in 
potential options that provide assurance that all regulated components 
have been monitored, how this information can be documented, and the 
costs of such alternative approaches.

C. Professional Engineer Certifications

    The 2016 NSPS OOOOa requires that CVS used for routing emissions 
from centrifugal compressor wet seal fluid degassing systems, 
reciprocating compressors, pneumatic pumps, and storage vessels must 
have sufficient design and capacity to ensure that all emissions are 
routed to the control device. 40 CFR 60.5411a(d). This is accomplished 
through a design evaluation that must be certified by a ``qualified 
professional engineer'' (PE). Several petitioners requested 
reconsideration of the PE certification requirement because the EPA did 
not provide an evaluation of the costs associated with the 
certification.\98\ Additionally, petitioners requested that the EPA 
allow alternatives to PE certification, such as engineering design 
reviews not necessarily conducted by a licensed PE.
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    \98\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.
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    The 2016 NSPS OOOOa also includes a technical infeasibility 
provision allowing an exemption from the well site pneumatic pump 
requirements. However, the rule requires that such technical 
infeasibility be determined and certified by a ``qualified professional 
engineer.'' 40 CFR 60.5393a(b)(5)(i). Petitioners objected to this 
additional certification, stating it results in additional costs and 
project delays, with no environmental benefits. Additionally, 
petitioners questioned the value of this requirement, claiming it is 
duplicative with the existing general duty obligations and requirement 
to provide a certifying official's acknowledgment. Petitioners also 
stated that few companies have a sufficient number of in-house PEs, and 
requested that this requirement be broadened to allow alternatives to 
PE certification, including requiring engineering review and approval 
of all designs.
    In the 2017 NODA, we requested information related to the 
availability of PEs to provide these certifications. Seven commenters 
provided information. Three commenters stated that there should be no 
limitation related to the availability of licensed PEs because in 2016 
over 400,000 resident licenses were issued, and over 400,000 non-
resident licenses were issued (a PE can hold both types of 
licenses).\99\ One commenter cited a similar requirement in Colorado's 
regulation and stated that in response to the same concerns from the 
industry, Colorado found there was no basis for the claims about a lack 
of availability of PEs.\100\ In contrast, four commenters stated 
difficulties with locating a PE willing to provide the certification, 
citing multiple concerns, including the certification statement 
included in the 2016 NSPS OOOOa and the certification of a portion of a 
system when the PE did not design the entire system.\101\
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    \99\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-12386, EPA-HQ-OAR-
2010-0505-12441, and EPA-HQ-OAR-2010-0505-12469.
    \100\ See Docket ID No. EPA-HQ-OAR-2010-0505-12469.
    \101\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-12422, EPA-HQ-OAR-
2010-0505-12424, EPA-HQ-OAR-2010-0505-12437, and EPA-HQ-OAR-2010-
0505-12446.
---------------------------------------------------------------------------

    We have evaluated the concerns raised by petitioners regarding the 
additional burden of the PE certification for CVS design and pneumatic 
pump technical infeasibility. Further, the EPA agrees with commenters 
that in-house engineers may be more knowledgeable about site design and 
operation for both CVS and pneumatic pumps. In addition, the EPA 
acknowledges that, in the 2016 NSPS OOOOa, we did not analyze the costs 
associated with the PE certification requirement or evaluate whether 
the improved environmental performance this requirement may achieve 
justifies the associated costs and other compliance burden. In this 
action, the EPA evaluated the costs associated with PE certification 
and certification by an in-house engineer. We estimated costs based on 
two scenarios: (1) Requiring a PE certify the design and (2) allowing 
either a PE or an in-house engineer certify the design. We estimate 
that each PE certification would cost $547, while allowing use of in-
house engineers would cost $358.\102\ The EPA is soliciting comment on 
this cost estimate.
---------------------------------------------------------------------------

    \102\ See the TSD for additional discussion of certification 
cost.
---------------------------------------------------------------------------

    After reconsideration of these costs, the EPA is proposing to amend 
the certification requirements for CVS design and technical 
infeasibility for pneumatic pumps. Specifically, we are proposing to 
allow certification by either a PE or an in-house engineer with 
expertise on the design and operation of the CVS or pneumatic pump. We 
believe that an in-house engineer with knowledge of the design and 
operation of the CVS is capable of performing these certifications, 
regardless of licensure; however, we are soliciting comment on the use 
of other engineers with knowledge of the design and operation of the 
CVS that may be appropriate for this certification, such as third-party 
or other qualified engineers. We continue to have a concern regarding 
the use of undersized or under designed CVS, which can result in 
pressure relief events from thief hatches and PRVs on the controlled 
storage vessels or CVS, thus allowing emissions to escape to the 
atmosphere uncontrolled. As stated in the 2013 NSPS OOOO Oil and 
Natural Gas Sector: Reconsideration of Certain Provisions of New Source 
Performance Standards, ``Improper design or operation of the storage 
vessel and its control system can result in occurrences where peak flow 
overwhelms the storage vessel and its capture systems, resulting in 
emissions that do not reach the control device, effectively reducing 
the control efficiency. We believe that it is essential that operators 
employ properly designed, sized, and operated storage vessels to 
achieve effective emissions control.'' 78 FR 22136. This proposed 
amendment will still ensure these systems are evaluated and certified 
by engineers with expert knowledge of their operation.

D. Alternative Means of Emission Limitation (AMEL)

    The 2016 NSPS OOOOa contains provisions for owners and operators to 
request an AMEL for specific work practice standards in the rule, 
covering well completions, reciprocating compressors, and the 
collection of fugitive emissions components at well sites and 
compressor stations. An owner or operator can request an AMEL by 
submitting data that demonstrate the alternative will achieve at least 
equivalent emission reductions as the requirements in the rule, among 
other requirements such as initial and on-going compliance monitoring. 
The specific requirements for this request are outlined in 40 CFR 
60.5398a. For the 2016 NSPS OOOOa, these alternatives

[[Page 52080]]

could be based on emerging technologies (e.g., for fugitive emissions, 
technologies other than OGI or Method 21) or requirements under state 
or local programs.
    We are proposing to amend the language in 40 CFR 60.5398a for 
incorporation of emerging technologies, and to add a separate section 
at 40 CFR 60.5399a to take into account existing state programs as 
discussed in further detail in the sections below.
1. Incorporating Emerging Technologies
    As discussed in the 2016 NSPS OOOOa, the EPA recognizes that new 
technologies are expected to enter the market in the near future that 
will locate the source of emissions sooner and at lower levels than 
current technology. While the EPA established a foundation for 
approving the use of emerging technologies in the final rule, several 
stakeholders have identified a need to streamline the process for 
requesting and approving an AMEL for individual affected sources, such 
as well completions, compressors, and the collection of fugitive 
emissions components located at a well site or at a compressor station. 
As promulgated in the 2016 NSPS OOOOa, each AMEL request must be 
submitted using site-specific information, which could result in the 
same owner or operator submitting identical requests for multiple 
affected facilities. We are clarifying that an individual application 
may include the same technology for multiple sites, provided the 
required information is provided for each site and any site-specific 
variations to the procedures are addressed in the application. The 
application must provide a demonstration of equivalency and the 
emission reductions achieved for each site included in the application. 
The EPA is also proposing specific changes to the AMEL process as it 
relates to emerging technologies to address this issue. Specifically, 
we are proposing to allow owners or operators to apply for an AMEL, on 
their own or in conjunction with manufacturers or vendors, and trade 
associations, that incorporates the use of alternative technologies, 
techniques, or processes, along with compliance monitoring provisions 
to ensure continuous compliance other than those identified in the 2016 
NSPS OOOOa work practice standards. We are not changing the requirement 
that AMELs must be site-specific because we are aware of the 
variability of this sector and are concerned that the procedures for a 
specific technology may need to be adjusted based on site-specific 
conditions (e.g., gas compositions, allowable emissions, or landscape). 
Therefore, we expect that applications for these AMEL will include 
site-specific procedures for ensuring continuous compliance of the 
emission reductions to be demonstrated as equivalent. For this reason, 
we are not proposing to allow a manufacturer, vendor, or trade 
association to apply for an AMEL without an owner or operator. However, 
we are soliciting comment on whether groups of sites within a specific 
area (e.g., basin-specific) that are operated by the same operator 
could be grouped under a single AMEL. Additionally, we are proposing 
that field data can be supplemented with test data, modeling analyses 
and other documentation, provided the field data still provides 
information related to seasonal variations. For the purposes of 
fugitive emissions requirements, the application must demonstrate that 
the technology is able to detect emissions beyond those allowed, such 
as pneumatic controllers. We are soliciting comment on the proposed 
revisions to the application requirements for technology-based AMEL.
2. Incorporating State Programs
    In addition to recognizing potential emerging technologies, the EPA 
evaluated existing state and local fugitive emissions programs during 
the development of the 2016 NSPS OOOOa for purposes of establishing 
AMEL. The EPA was unable to conclude that any state program as a whole 
would reflect what we identified as BSER in the 2016 NSPS OOOOa due to 
the differences in the sources covered and the specific requirements. 
However, the 2016 NSPS OOOOa allowed owners and operators to use the 
AMEL process to allow use of existing state or local programs. 81 FR 
35871. Petitioners and states have raised specific questions about the 
practicality of the AMEL process as it relates to the incorporation of 
state programs.\103\ For instance, one state has notified the EPA that 
since the ability to make an AMEL request is limited to owners and 
operators at the individual site level, it is possible that the EPA 
would have over 300 identical applications from various owners and 
operators wanting to use the same state program at their affected 
facilities. Believing that there may be opportunities to streamline the 
process, ensure compliance, and reduce regulatory burdens, the EPA 
continued its evaluation of existing state fugitive emissions programs 
after promulgating the 2016 NSPS OOOOa. Based on this evaluation, the 
EPA is proposing certain existing state requirements as alternatives to 
specified aspects (e.g., monitoring, repair, and recordkeeping) of the 
fugitive emissions requirements for well sites and compressor stations.
---------------------------------------------------------------------------

    \103\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.
---------------------------------------------------------------------------

    To date, the EPA has evaluated 14 existing state programs for 
comparable or equivalent standards related to the fugitive emissions 
requirements in 40 CFR 60.5397a and the specific amendments in this 
proposal. For this evaluation, we compared the fugitive emissions 
components covered by the state programs, monitoring instruments, leak 
or fugitive emissions definitions, monitoring frequencies, repair 
requirements, and recordkeeping to the fugitive emissions requirements 
proposed in this action.\104\ We did not include an evaluation of 
monitoring plans or reporting requirements because we are not proposing 
any alternative standards for these aspects of the fugitive emissions 
requirements. Through this evaluation, we have identified aspects of 
certain existing state fugitive emissions programs that we propose to 
find to be at least equivalent to the proposed amendments in this 
action.\105\ For instance, we have evaluated the lists of affected 
fugitive components, monitoring instrument(s), fugitive definition(s), 
monitoring frequency, repair deadlines, delay of repair provisions, and 
recordkeeping of the programs reviewed. In most of the programs, the 
affected fugitive components were different than our definition of 
fugitive emissions component. Therefore, we are proposing alternative 
standards that also require the owner or operator to survey our entire 
list of fugitive emissions components, regardless of whether they are 
affected components in the state program. Additionally, we evaluated 
monitoring instruments, frequencies, and fugitive definitions in 
conjunction with each other. Where monitoring is more frequent, we are 
proposing that a different fugitive definition could be appropriate. 
For instance, the standards in the California Code of Regulations, 
title 17, sections 95665-95667 require quarterly monitoring using 
Method 21 with a fugitive definition of 1,000 ppm while this proposal 
requires annual or stepped monitoring with a fugitive definition of 500 
ppm if Method 21 is the chosen monitoring instrument. The

[[Page 52081]]

EPA believes that more frequent monitoring warrants allowance of a 
higher fugitive definition because larger fugitive emissions will be 
found faster and repaired sooner, thus reducing the overall length of 
the emission event. Additional information related to the specific 
evaluation of programs is available in the memorandum Equivalency of 
State Fugitive Emissions Programs for Well Sites and Compressor 
Stations to Proposed Standards at 40 CFR part 60, subpart OOOOa, 
located at Docket ID No. EPA-HQ-OAR-2017-0483.
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    \104\ See memorandum Equivalency of State Fugitive Emissions 
Programs for Well Sites and Compressor Stations to Proposed 
Standards at 40 CFR part 60, subpart OOOOa located at Docket ID No. 
EPA-HQ-OAR-2017-0483. April 12, 2018.
    \105\ Specifically, we propose to make this finding with respect 
to state programs in California, Colorado, Ohio, Pennsylvania, 
Texas, and Utah.
---------------------------------------------------------------------------

    Based on this evaluation, we are proposing combining those aspects 
of the state requirements to formulate alternatives to the relevant 
portions of the fugitive emissions standards for the collection of 
fugitive emissions components located at either well sites or 
compressor stations. The specific states for which we are proposing 
alternative standards are California, Colorado, Ohio, and Pennsylvania 
for both well sites and compressor stations, and Texas and Utah for 
well sites only. We have not determined whether Pennsylvania's 
Exemption No. 38 for well sites should be included in the alternative 
standards. While we evaluated the current consent decree \106\ that the 
state of North Dakota has developed for well sites, we are not 
proposing alternative standards related to those requirements because 
by their nature, consent decrees are negotiated terms for non-
compliance and contain an expiration date, after which sources return 
to compliance with the underlying regulatory provisions, permit terms, 
etc. Further, inclusion of settlement terms from a consent decree as an 
alternative standard would essentially endorse regulation through 
enforcement as a pathway to establishment of alternative standards. For 
all of these reasons, the EPA believes that evaluation of settlement 
agreement terms reached through negotiated resolution to an enforcement 
action would be an inappropriate basis from which to establish 
alternative standards for regulations promulgated through notice and 
comment rulemaking. Additionally, we are identifying the specific 
effective date of the individual state programs to specify which 
version of the state programs is being proposed as alternative 
standards because the state programs may change over time, and our 
evaluation is only valid for the current version of these programs. If 
in the future any of these programs are amended, the states can utilize 
the proposed application procedure discussed below.
---------------------------------------------------------------------------

    \106\ See North Dakota Consent Decree 10.19.16, attachment to 
the memorandum Equivalency of State Fugitive Emissions Programs for 
Well Sites and Compressor Stations to Proposed Standards at 40 CFR 
part 60, subpart OOOOa. April 12, 2018, in Docket ID No. EPA-HQ-OAR-
2017-0483.
---------------------------------------------------------------------------

    The proposed alternative fugitive emissions standards include 
alternatives for monitoring frequencies, repair deadlines, and 
recordkeeping. The requirements for the monitoring plan found in 40 CFR 
60.5397a(c) and (d) would still apply. In fact, the owner or operator 
would indicate through this monitoring plan that they have elected the 
alternative and would base the monitoring plan on the specific 
requirements from the state, local, or tribal program that is being 
adopted. Compliance would be evaluated against the specified 
requirements in the alternative fugitive emissions standards as 
incorporated in the monitoring plan. Further, we are proposing to 
require notification that the owner or operator has elected to comply 
with the applicable alternative fugitive emissions standards for the 
state in which the well site or compressor station is located. We are 
proposing that this notification is made at least 90 days prior to 
adopting an alternative fugitive emissions standard. We are soliciting 
comment on the requirements necessary to document that an owner or 
operator is following an alternative state, local or tribal program and 
on the notification requirement, including the appropriateness of the 
use of the requirement of 90 days' notice prior to adoption of the 
alternative standards.
    In this action we are proposing a new section, in proposed 40 CFR 
60.5399a, to include these state requirements that qualify as 
alternative fugitive emissions standards. The proposed section also 
includes a framework for the application and inclusion of additional 
existing state fugitive emissions standards as alternatives to the 
fugitive emissions requirements or future revisions to programs already 
proposed as alternative standards. Under our proposal, such applicants 
would include, but not be limited to, individuals, corporations, 
partnerships, associations, states, or municipalities. The proposed 
requirements for the application include specific information about the 
monitoring instrument (including monitoring procedures), monitoring 
frequency, leak or fugitive emissions definition, and repair 
requirements. We are soliciting comment on the proposed application 
requirements, the proposed alternative fugitive emissions standards 
(including compliance monitoring), and information to support the 
inclusion of additional alternative fugitive emissions standards.

E. Other Reconsideration Issues Being Addressed

1. Well Completions
    Location of a Separator During Flowback. The 2016 NSPS OOOOa 
requires the owner or operator to have a separator onsite during the 
entirety of the flowback period. 40 CFR 60.5375a(a)(1)(iii). However, 
several petitioners indicated that it is not clear whether the term 
``onsite'' refers to the specific well site where the well completion 
is taking place.\107\ Our intent was that the separator be located in 
close enough proximity to the well that it could be utilized as soon as 
sufficient flowback is present for the separator to function. Close 
proximity could be either onsite or nearby, as we explained in the 
preamble to the 2016 NSPS OOOOa, ``We anticipate a subcategory 1 well 
to be producing or near other producing wells. We therefore anticipate 
REC equipment (including separators) to be onsite or nearby, or that 
any separator brought onsite or nearby can be put to use.'' 81 FR 
35852. Thus, our intent was that the separator may be located at the 
well site or near to the well site so that it is able to commence 
separation flowback, as required by the rule. Locations ``near'' or 
``nearby'' may include a centralized facility or well pad that services 
the well which is used to conduct the completion of the well affected 
facility. In order to alleviate concerns that the separator must be 
located on the well site, we are proposing to amend 40 CFR 
60.5375a(a)(1)(iii) to clarify the location of the separator.
---------------------------------------------------------------------------

    \107\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-7686.
---------------------------------------------------------------------------

    Screenouts and Coil Tubing Cleanouts. Petitioners requested 
clarification as to whether screenouts and coil tubing cleanouts are 
regulated as part of flowback. Petitioners asserted that these are 
necessary processes performed during hydraulic fracturing that are not 
associated with flowback.\108\ In November 2016, the EPA responded to a 
letter from API seeking clarification on this issue, stating, ``any 
releases of gas or vapor during `screenouts' and `coil tubing 
cleanouts,' which occur during the initial flowback stage are not 
subject to control under section 60.5375a.\109\ However, we have 
further assessed this topic and believe that the guidance we issued was 
incorrect. In the

[[Page 52082]]

preamble to the final 2014 amendments, we stated regarding flowback: 
``. . . 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 . . .'' 79 FR 79024. In some 
situations, screenouts or coil tubing cleanouts may be necessary in 
order to remove proppant (sand) from the well so that high volumetric 
flow can occur, marking the beginning of the initial flowback stage. 
Therefore, screenouts and coil tubing cleanouts are not a part of 
flowback; rather, they are functional processes that allow for flowback 
to begin. It should be noted that this is consistent with the 
definition of hydraulic fracturing, which we stated requires high rate, 
extended flowback to expel fracture fluids and solids during 
completions. 40 CFR 60.5430a. For the reasons stated above, the 
November 2016 letter incorrectly states that screenouts and coil tubing 
cleanouts occur during the initial flowback stage. To clarify this 
point, we are proposing to revise the definition of flowback to 
expressly exclude these processes to avoid any future confusion. In 
addition, we are proposing definitions for these processes. A screenout 
is the first attempt to clear proppant from the wellbore. It involves 
flowing the well to a fracture tank in order to achieve maximum 
velocity and carry the proppant out of the well. If a screenout is 
unsuccessful in clearing the proppant from the wellbore, then a coil 
tubing cleanout is conducted. This involves running a string of coil 
tubing to the packed proppant and jetting the well to dislodge the 
proppant and provide sufficient lift energy to flow it to the surface. 
It is after these processes that flowback begins and, subsequently, 
production. The EPA solicits comment on the proposed definitions for 
these processes.
---------------------------------------------------------------------------

    \108\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682.
    \109\ See Docket ID No. EPA-HQ-OAR-2010-0505-7722.
---------------------------------------------------------------------------

    Plug Drill-Outs. A plug drill-out is the removal of a plug (or 
plugs) that was used to conduct hydraulic fracturing in different 
sections of the well. Plug drill-outs are also functional processes 
that are necessary in order for flowback to begin. Therefore, the EPA 
is similarly proposing to exclude these processes from the definition 
of flowback.
    Flowback Routed Through Permanent Separators. The EPA is proposing 
to streamline reporting and recordkeeping requirements for flowback 
routed through permanent separators to reduce burden on the regulated 
community. We consider a permanent separator to be one that handles 
flowback from a well or wells beginning when the flowback period begins 
and continuing to the startup of production. When routing flowback 
through permanent separators, some reporting and recordkeeping elements 
associated with well completions (e.g., information about when a 
separator is hooked up or disconnected) become unnecessary because the 
separator is already connected to the well at the onset of flowback. In 
these situations, there is no initial flowback stage, and the 
separation flowback stage begins. Therefore, the EPA is proposing that 
operators do not need to record or report the date and time of each 
attempt to direct flowback to a separator for these situations. 
However, these streamlined recordkeeping and reporting requirements 
would not apply in situations where flowback is not routed through a 
permanent separator; in those cases, operators would be required to 
report the date and time of each attempt to direct flowback to a 
separator. The EPA is soliciting comments on these proposed revisions 
and additional ways to streamline reporting and recordkeeping.
2. Onshore Natural Gas Processing Plants
    Capital Expenditure. We are proposing to correct the definition of 
``capital expenditure'' promulgated at 40 CFR 60.5430a by replacing the 
reference to the year 2011 with the year 2015 in the formula in 
paragraph (2) of the definition. The definition of ``capital 
expenditure'' was among the issues related to 40 CFR part 60, subpart 
OOOO that the EPA reconsidered and addressed in the 2016 NSPS OOOOa. 
That definition is relevant to the equipment leaks standards for 
onshore natural gas processing plants that were originally promulgated 
in 1985 in 40 CFR part 60, subpart KKK, updated in 2012 in 40 CFR part 
60, subpart OOOO, and carried over in 2016 in 40 CFR part 60, subpart 
OOOOa. As explained in the memorandum Alternative Method for 
Determining Capital Expenditures (Thomas W. Rhoads to Docket A-80-44, 
July 21, 1983), located at Docket ID No. EPA-HQ-OAR-2017-0483, this 
method was developed to allow a facility to approximate the original 
costs of the facility using the replacement costs and the inflation 
index and therefore, providing an alternative method to the definition 
of ``capital expenditure'' in 40 CFR part 60, subpart A (``General 
Provisions'').\110\ The value for ``Y'' (the percent of replacement 
cost) is designed to take into account the age of the facility. 
Therefore, the replacement cost for a new facility should be the same 
as the original cost, or the value of ``Y'' should be closer to 1 for 
new facilities. Because the 2016 NSPS OOOOa applies to new sources 
constructed, reconstructed, or modified after September 18, 2015, the 
base year of 2015 is the correct year to reflect the age of the 
facility in this calculation.
---------------------------------------------------------------------------

    \110\ See also Equipment Leaks of VOC in Natural Gas Production 
Industry--Background for Promulgated Standards, EPA-450/3-82-024b, 
May 1985, at 9-1.
---------------------------------------------------------------------------

    However, for sources that commenced construction between January 1, 
2015, and September 18, 2015, when the value of ``2015'' is used it 
results in a ``zero'' value for ``X'' for which there is no logarithmic 
solution. This is a result that the EPA did not intend in its revision 
of the calculation in the 2016 rulemaking. The EPA is, therefore, 
amending the definition so that the value of ``Y'' equals 1 if the 
affected process unit was constructed in 2015. The proposed amendment 
would address the mathematical issue for affected sources constructed 
in 2015 whiling leaving the calculation method intact for other 
affected sources. We are soliciting comment on the proposed amendment 
to the equation.
    Notwithstanding this proposed amendment, as indicated above, the 
equation was developed as an alternative to the General Provisions 
definition of ``capital expenditure.'' Since the General Provisions 
definition also applies, if calculation issues arise when applying the 
2016 NSPS OOOOa equation, facilities should use the General Provisions 
to calculate capital expenditure. Facilities can also contact the EPA 
for guidance on how to apply the General Provisions definition for 
``capital expenditure'' evaluations if necessary by utilizing 40 CFR 
60.5 (Determination of construction or modification).
    In addition, the EPA is soliciting comment and information to help 
inform us whether the current capital expenditure definition should be 
revised based on a ratio of consumer price indices (CPI), as requested 
by two petitioners.\111\ Petitioners indicated that calculation of 
``capital expenditure'' was designed to account for inflation. In 
supporting documentation provided from one petitioner \112\ a plot of 
values prior to 1982 demonstrates a logarithmic function, which 
directly correlates to the CPI for the years 1950 through 1982. This 
was the information on which the ``capital expenditure'' equation was 
based. However, as described by the

[[Page 52083]]

petitioners, the CPI takes a more linear function post-1982, while the 
``capital expenditure'' equation remains with a logarithmic function. 
In practice, this could mean that the ``P'' value would be lower using 
the ``capital expenditure'' equation, thus resulting in modifications 
at lower expenditures than if the CPI were used. While we are proposing 
to update the existing equation with the corrected base year date of 
2015, we are also soliciting comment on changing the calculation for 
the value of ``Y'' using the CPI. Specifically, we are soliciting 
comment on the petitioner's suggestion that the value for ``Y'' should 
be calculated using the CPI of the date of construction or 
reconstruction divided by the CPI of the date of component price data, 
or ``CPIN/CPIPD''.
---------------------------------------------------------------------------

    \111\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-7684.
    \112\ See GPA Midstream New Source Performance Standards 
(``NSPS'') Subpart OOOOa Petition for Review Technical Issues 
located at Docket ID No. EPA-HQ-OAR-2010-0505-12361. March 1, 2017.
---------------------------------------------------------------------------

3. Closed Vent Systems (CVS) and Storage Vessel Thief Hatches
    The requirements for CVS are specific to the type of affected 
facility that is associated with the CVS (i.e., ``routes to'' the CVS). 
CVS receiving emissions from centrifugal compressor, reciprocating 
compressor, and pneumatic pump affected facilities must be (a) 
initially and annually inspected visually for defects and (b) initially 
and annually monitored using Method 21 to verify operation at no 
detectable emissions (i.e., an instrument reading less than 500 ppm 
above background concentration). In contrast, no instrument monitoring 
is required for CVS receiving emissions from storage vessel affected 
facilities and monthly auditory, visual, and olfactory (AVO) 
inspections must be performed. 40 CFR 60.5416a. Several petitioners 
have stated that the requirements for CVS associated with pneumatic 
pumps should be aligned with the requirements for CVS associated with 
storage vessels instead of the CVS requirements for centrifugal or 
reciprocating compressors.\113\ In addition, these petitioners stated, 
though incorrectly, that pneumatic pumps are subject to OGI monitoring 
under the fugitive emissions requirements as well as the annual Method 
21 requirement; the petitioners, therefore, assert that the Method 21 
requirement is duplicative and burdensome. Pneumatic pumps are not 
fugitive emissions components because they vent as part of normal 
operation. Finally, stakeholders have requested streamlined and 
standardized requirements for all CVS, in place of equipment-specific 
requirements currently in the 2016 NSPS OOOOa. Specifically, the 
requirements are spread over multiple sections of the rule and vary 
based on the affected facility associated with the CVS as stated above, 
which the stakeholders have indicated creates confusion regarding 
compliance.
---------------------------------------------------------------------------

    \113\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.
---------------------------------------------------------------------------

    The EPA has received information from various stakeholders that 
overlapping requirements for these CVS and openings on controlled 
storage vessels may still exist due to state program requirements. 
Specifically, two stakeholders have informed us they are required to 
perform quarterly OGI monitoring on the CVS located at well sites under 
their state program in addition to the annual Method 21 requirement on 
the same CVS for their affected facility pneumatic pumps as required by 
the 2016 NSPS OOOOa. We agree with the stakeholders that amendments are 
appropriate for the CVS requirements for pneumatic pumps.
    We are proposing to align the CVS monitoring requirements for 
affected facility pneumatic pumps with the CVS monitoring requirements 
for affected facility storage vessels. As stated by the petitioners, we 
agree that pneumatic pumps and storage vessels are commonly located at 
well sites and agree that having separate monitoring requirements for 
potentially shared CVS is overly burdensome and duplicative. This 
proposed amendment effectively requires monthly AVO monitoring for the 
CVS located at well sites because there are no affected facility 
reciprocating or centrifugal compressors located at well sites. We are 
soliciting comment on this proposed amendment for CVS on affected 
facility pneumatic pumps. Additionally, we are soliciting comment on 
other methods that could be employed as an alternative to the monthly 
AVO monitoring to ensure the CVS is operated with no detectable 
emissions.
    Further, we are soliciting comment regarding the requirements for 
covers, thief hatches and other openings on storage vessel affected 
facilities. As specified in 40 CFR 60.5411a(b)(2), each opening on the 
storage vessel cover should be secured in a closed and sealed position 
except during periods where opening the cover is necessary (e.g., to 
inspect or sample material in the storage vessel). Under 40 CFR 
60.5416a(c)(2), each cover is also subject to monthly AVO monitoring 
for defects that could result in air emissions. It has come to our 
attention, however, that there may be confusion related to how the 
cover and openings on the cover relate to the CVS and the no detectable 
emissions requirement. We have observed fugitive emissions using OGI on 
thief hatches, even where the CVS has been properly designed and 
certified, and the thief hatch is properly weighted and closed.\114\ 
Given this information, we acknowledge there are concerns about an 
interpretation of 40 CFR 60.5411a(c)(2) under which thief hatches are 
subject to the no detectable emissions limit. We recognize that this 
limit is traditionally required for components that we do not expect to 
leak (e.g., valves with no external actuating shaft in contact with 
process fluid). However, as noted here, we continue to observe fugitive 
emissions from thief hatches that are properly weighted and closed. 
Root cause analysis has demonstrated that deteriorated gaskets are one 
cause of such emissions. While these sources might still be able to 
meet the sensory monitoring limit, we are soliciting comment on whether 
covers and openings on the cover should be viewed as part of the CVS 
and thus subject to the no detectable emissions limit. In addition, we 
are soliciting comment on whether other methods are available to more 
reliably identify fugitive emissions from the CVS and thief hatches or 
other openings on storage vessel affected facilities than the currently 
required monthly AVO and to better assure compliance with the 95% VOC 
emissions control requirement for storage vessel affected facilities. 
We are also soliciting comment on whether a work practice standard 
would be more effective at assuring compliance than subjecting thief 
hatches to a no detectable emissions standard as determined through 
monthly AVO. Finally, we are not proposing any changes to the CVS 
requirements for affected facility centrifugal compressors or 
reciprocating compressors.
---------------------------------------------------------------------------

    \114\ Analysis of Consent Decree Reports from Noble Energy, Inc. 
as to Emissions Observations from Thief Hatches or Other Openings on 
Controlled Storage Vessels; Oil and Natural Gas Sector: Emission 
Standards for New, Reconstructed and Modified Sources 
Reconsideration--SAN 5719.8 located at Docket ID No. EPA-HQ-OAR-
2017-0483.
---------------------------------------------------------------------------

VII. Implementation Improvements

    Following publication of the 2016 NSPS OOOOa, we subsequently 
determined, following review of petitions and discussions with affected 
parties, that the final rule warrants correction and clarification in 
certain areas in addition to those discussed above. Each of these areas 
is discussed below.

[[Page 52084]]

A. Reciprocating Compressors

    The 2016 NSPS OOOOa includes an alternative to the work practice 
standards for reciprocating compressors. Operators may choose to gather 
rod packing emissions using a collection system that operates under 
negative pressure and then route emissions to a process via a CVS, as 
opposed to replacing the rod packing every 26,000 hours or 36 months. 
During the comment period for the proposal for the 2016 NSPS OOOOa, the 
EPA received feedback from various stakeholders, who noted that there 
were safety concerns with requiring the rod packing emissions to be 
collected under negative pressure. Specifically, commenters stated that 
operating the collection system under negative pressure may 
inadvertently introduce oxygen into the system.\115\ In response to 
comments, the EPA stated that operation of the collection system under 
negative pressure was necessary in order to appropriately capture 
emissions.\116\ The EPA is soliciting comment and supporting data on 
capture systems which are at least equivalent to the current systems 
and which could negate the necessity to capture emissions under 
negative pressure.
---------------------------------------------------------------------------

    \115\ See Docket ID No. EPA-HQ-OAR-2010-0505-6884.
    \116\ See Docket ID No. EPA-HQ-OAR-2010-0505-7632, Chapter 7, 
page 7-37.
---------------------------------------------------------------------------

B. Storage Vessels

    Pursuant to 40 CFR 60.5365a(e), owners and operators must calculate 
potential emissions from storage vessels in order to determine if 
control requirements apply. This calculation is based on the ``maximum 
average daily throughput.'' During implementation of the 2016 NSPS 
OOOOa, several stakeholders requested clarification regarding this 
calculation. Specifically, the stakeholders have expressed confusion 
about what value constitutes the ``maximum average daily throughput.'' 
This value was intended to represent the maximum of the average daily 
production rates in the first 30-day period to each individual storage 
vessel. The EPA stated in its Response to Comments on the 2013 
amendments to the 2012 NSPS OOOO, ``we believe that the estimate of 
potential VOC emissions should be determined based on maximum emissions 
during the 30-day period rather than average emissions over that 
period''.\117\ While the EPA was clear that emissions are not to be 
averaged over the 30-day period, we were less clear at the time as to 
what averaging was allowed when we used the term ``maximum average 
daily throughput.'' Therefore, we propose to further clarify in this 
notice when and how daily production may be averaged in determining 
daily throughput.
---------------------------------------------------------------------------

    \117\ See Docket ID No. EPA-HQ-OAR-2010-0505-4639.
---------------------------------------------------------------------------

    We are proposing to revise the definition to clarify that the 
maximum average daily throughput refers to the maximum average daily 
throughput for an individual storage vessel over the days that 
production is routed to that storage vessel during the 30-day 
evaluation period. This average over the days that production is routed 
to a storage vessel represents the maximum average daily throughput for 
that single storage vessel because the determination takes place during 
the first 30-day evaluation period when production throughput will be 
the greatest due to the decline curve for production from oil and 
natural gas wells. Further, by clarifying that production to a single 
storage vessel must be averaged over the number of days production was 
actually sent to that storage vessel, rather than over the entire 30 
days (where the storage vessel receives no production on some days), we 
are ensuring that the determination of potential for VOC emissions to 
that individual storage vessel does not presume that production will be 
split evenly across storage vessels where there is no legally and 
practically enforceable limit requiring operation in that manner. A 
more detailed discussion regarding the issue of averaging across a tank 
battery is provided below. We are soliciting comment on this 
clarification. Additionally, we are soliciting comment on whether a 
different term would better describe this value than the currently used 
``maximum average daily throughput.''
    Where a storage vessel has automated gauging, the operator may 
directly determine the average daily throughput for each day that 
production is routed to that storage vessel. The average daily 
throughput for each day of production to that storage vessel would then 
be averaged to determine the maximum average daily throughput for the 
30-day evaluation period. For example, if a storage vessel receives 
production on 22 of the 30 days in the evaluation period, then the 
maximum average daily throughput is calculated by averaging the daily 
throughput that was calculated for each of those 22 days. We recognize 
that this approach averages the daily throughputs for the days that a 
storage vessel receives production; however, recognizing that 
production declines, we are clarifying that this calculation, based on 
the days of production to the storage vessel during the first 30-days 
of production, represents the potential emissions. We are soliciting 
comment on this clarification.
    We understand that some storage vessels may not have daily 
throughput measurements because they are not equipped with automated 
level gauging and do not have daily manually gauged readings. In such 
circumstances, we believe that the liquid height, and therefore volume, 
in the storage vessel would be measured at a minimum at the start and 
completion of loadout of liquids from the storage vessel. Frequency of 
loadout from each storage vessel (i.e., ``turnover rate'') will vary 
depending on company or site-specific operations. Therefore, it is 
possible that a storage vessel could have multiple turnovers during the 
first 30-days of production, and therefore multiple production periods. 
Where this occurs, you must determine the average daily throughput for 
each of those production periods, which can be done by dividing the 
volumetric throughput calculated from the change in liquid height for 
that production period over the number of days in the production 
period, and use the maximum of those production period average daily 
throughput values to calculate the potential emissions from the 
individual storage vessel. A production period begins when production 
begins to be routed to a storage vessel and ends either when throughput 
is routed away from that storage vessel or when a loadout occurs from 
that storage vessel, whichever happens first. We recognize that 
calculating daily throughput based on liquid level measurements at the 
beginning and end of a production period will necessarily average 
production throughput to the individual storage vessel over the number 
of days it was receiving production in the turnover period. However, 
recognizing that production declines, we are clarifying that this 
calculation, based on the first 30-days of production, represents the 
potential emissions. We are soliciting comment on this clarification.
    Finally, inspection data and compliance reports for the 2016 NSPS 
OOOOa indicate that many operators determined that few or no storage 
vessels are affected facilities under the 2016 NSPS OOOOa. For example, 
review of the 2016 NSPS OOOOa compliance reports and the fewer than 
expected number of reported storage vessel affected facilities 
indicates that some operators may be incorrectly averaging emissions 
across storage tanks in tank batteries when determining the potential 
for VOC emissions. Both the

[[Page 52085]]

2012 NSPS OOOO and 2016 NSPS OOOOa specify that a storage vessel 
affected facility is ``a single storage vessel'' that ``has the 
potential for VOC emissions equal to or greater than 6 tpy.'' 40 CFR 
60.5365(e) and 60.5365a(e). In prior rulemakings, the EPA explained 
that storage vessel emission estimation methods for the potential for 
VOC emissions generally require information on both the composition and 
volumetric rate of the liquid entering the storage vessel, where the 
volumetric throughput is frequently calculated by recording the volume 
of liquid collected from the receiving vessel(s) over time. 79 FR 
79026. Because the 2012 NSPS OOOO and 2016 NSPS OOOOa define the 
affected facility as ``a single storage vessel,'' the determination of 
the potential for VOC emissions must be based on the liquid throughput 
of each ``single storage vessel,'' even where the storage vessel is 
part of a tank battery. Operators should ensure that the determination 
of the potential for VOC emissions reflects each storage vessel's 
actual configuration and operational characteristics. Similarly, the 
EPA notes that affected facility determinations are allowed to account 
for legally and practically enforceable limits in determining the 
potential for VOC emissions for a storage vessel. However, only limits 
that meet certain enforceability criteria may be used to restrict a 
source's potential to emit, and the permit or requirement must include 
sufficient compliance assurance terms and conditions such that the 
source cannot lawfully exceed the limit. Given the potential for 
recurring emissions from controlled storage vessel thief hatches or 
other opening owing to operation and maintenance performance even where 
adequate design has been verified,\118\ any limit on capture and 
control efficiency from storage vessels must include sufficient 
monitoring to timely identify and repair emissions from storage vessels 
to ensure the limit on capture and control efficiency is consistently 
achieved.
---------------------------------------------------------------------------

    \118\ Analysis of Consent Decree Reports from Noble Energy, Inc. 
as to Emissions Observations from Thief Hatches or Other Openings on 
Controlled Storage Vessels; Oil and Natural Gas Sector: Emission 
Standards for New, Reconstructed and Modified Sources 
Reconsideration--SAN 5719.8 located at Docket ID No. EPA-HQ-OAR-
2017-0483.
---------------------------------------------------------------------------

    Where a storage vessel is part of a tank battery, some operators 
appear to derive the maximum average daily throughput of a storage 
vessel in a battery by using the throughput to the entire battery (by 
using records of liquids collected from the battery over time) and 
dividing that figure by the number of storage vessels in the battery. 
This approach for determining a storage vessel's maximum average daily 
throughput is incorrect for certain operational configurations. For 
instance, where a tank battery is operated such that all pressurized 
liquids from the separator initially flow to only one storage vessel, 
and then overflow to the next, and so on (i.e., in series or series 
flow), the first individual storage vessel's throughput would be the 
entire battery's throughput, not the entire battery's throughput 
apportioned evenly among the storage vessels. Dividing an entire 
battery's throughput by the number of storage vessels in the battery 
would greatly underestimate flash emissions from the first storage 
vessel connected in series, which is where liquid pressure drops from 
separator pressure to atmospheric pressure. However, such division 
could be appropriate where all liquids flow through a splitter system 
in a common header that ensures that all liquids initially flow in 
equal amounts to all storage vessels in a tank battery at all times 
since the liquid pressure drop would occur equally in each storage 
vessel in the battery. The EPA is soliciting comment and suggestions 
for how to clarify or simplify the calculation for application by 
stakeholders such that the potential emissions from storage vessels may 
be determined.
    Finally, records of each VOC emissions determination for each 
storage vessel affected facility are required in 40 CFR 
60.5420a(c)(5)(ii). Given the proposed clarification discussed above, 
we are soliciting comment on specific recordkeeping requirements that 
would support the applicability determination for each individual 
storage vessel regardless of whether that storage vessel is determined 
to be an affected facility. This is because recordkeeping is necessary 
to be able to verify that rule applicability was appropriately 
determined in accordance with the regulatory requirements. We are 
soliciting comment on the type of records that would be maintained to 
demonstrate how the calculations of the maximum average daily 
throughput and the potential for VOC emissions were performed. For 
example, information related to how the throughput to the individual 
storage vessel was determined (i.e., daily measurements or liquid 
height measurements at the start and end of a production period) and 
the start and end dates for each production period, along with the 
number of days production was routed to that storage vessel, are key 
elements that we would expect to have recorded. Where automated 
readings from gauges or meters are available, we expect that a data 
historian could automatically record and store some or all of this 
information. Where automated readings are not available, load slips may 
be able to provide some or all of this information (i.e., liquid height 
in a storage vessel at the beginning and end of each load out and the 
date of the load out, traceable to the storage vessel). We are also 
soliciting comment on records that would be available to document the 
operational configuration of a tank battery, where applicable, 
including to which storage vessel(s) production was routed for each day 
in the 30-day evaluation period. For calculation of potential for VOC 
emissions, we expect that identification of the model or calculation 
methodology used would be documented with the calculation itself. In 
addition to the type of information that should be recorded, we are 
also soliciting comment on the associated recordkeeping burden.

C. Definition of Certifying Official

    In response to petitions on NSPS OOOO, the EPA amended the 
definition of `responsible official' in order to remove potential 
confusion in the regulated community and to clarify that the 
requirements of the NSPS were not associated with a permitting 
program.\119\ Because the terms `responsible official' and `permitting 
authority' were similar to terms used in the Title V permitting 
program, the EPA changed the term `responsible official' to `certifying 
official' and replaced the term `permitting authority' used in the 
definition with `Administrator.' '' \120\ This amended definition of 
`certifying official' was carried forward into the 2015 NSPS OOOOa 
proposal. 80 FR 56694. The EPA received comments that the term 
`certifying official' still includes references to permitting programs 
and is inconsistent with way the NSPS program operates.\121\ In 
response to this comment, the EPA stated that the change made in the 
2014 amendments ``remove[d] any confusion.'' \122\ Upon further 
evaluation of this issue, the EPA recognizes that continuing to include 
the language ``facilities applying for or subject to a permit'' in the 
definition of `certifying

[[Page 52086]]

official' is inappropriate for the NSPS program. Therefore, the EPA is 
proposing to amend this definition to remove the reference to permits. 
The EPA solicits comment on this proposed change.
---------------------------------------------------------------------------

    \119\ 79 FR 79023-4.
    \120\ Id.
    \121\ See Docket ID No. EPA-HQ-OAR-2010-0505-6881.
    \122\ See Docket ID No. EPA-HQ-OAR-2010-0505-7632, Chapter 15, 
page 15-284.
---------------------------------------------------------------------------

D. Equipment in VOC Service Less Than 300 Hours/Year

    In this action, the EPA is proposing to amend the requirements for 
equipment leaks at onshore natural gas processing plants. Specifically, 
we are proposing to include an exemption from monitoring for certain 
equipment that an owner or operator designates as being in VOC service 
less than 300 hr/yr.
    When the 2007 requirements were promulgated, the EPA concluded that 
an exemption for certain equipment that is in VOC service less than 300 
hr/yr was appropriate. In response to public comments on the 2006 NSPS 
VV/VVa proposal, we stated that such exemption was appropriate for 
equipment that is used only during emergencies, used as a backup, or 
that is in service only during startup and shutdown.\123\ In these 
situations, the operating schedule of the equipment is unpredictable 
and likely at widely spaced and varying intervals. Planning for 
monitoring is more challenging and the effort outweighs the limited 
potential gain in emissions. The EPA is proposing to include this same 
exemption for equipment at onshore natural gas processing plants that 
is used only during emergencies, used as a backup, or that is in 
service only during startup and shutdown.
---------------------------------------------------------------------------

    \123\ See Docket ID No. EPA-HQ-OAR-2006-0699-0094.
---------------------------------------------------------------------------

E. Reporting and Recordkeeping

    The EPA is proposing to streamline certain reporting and 
recordkeeping requirements to reduce burden on the regulated industry. 
The proposed changes can be seen in section 60.5420a. Additionally, the 
proposed reporting elements can be seen in the draft electronic 
reporting template, located at Docket ID No. EPA-HQ-OAR-2017-0483. We 
solicit comment on these proposed revisions; the content, layout, and 
overall design of the reporting template; and additional ways to 
streamline reporting and recordkeeping.
    We are also proposing revisions to accommodate the submittal of CBI 
data in annual reports, as well as additional clarifications for 
reporting requirements during outages of the Compliance and Emissions 
Data Reporting Interface (CEDRI) or the EPA's Central Data Exchange 
(CDX) systems, or during a force majeure event. These proposed changes 
can be seen in section 60.5420a.

F. Technical Corrections and Clarifications

    We are proposing to revise the 2016 NSPS OOOOa to include the 
following technical corrections and clarifications.
     Revise paragraphs 60.5385a(a)(1), 60.5410a(c)(1), 
60.5415a(c)(1), 60.5420a(b)(4)(i), and 60.5420a(c)(3)(i) to clarify 
that hours or months of operation at reciprocating compressor 
facilities should be measured beginning with the later of initial 
startup, the effective date of the requirement (August 2, 2016), or the 
last rod packing replacement.
     Revise paragraph 60.5393a(b)(3)(ii) to correctly cross-
reference to paragraph (b)(3)(i) of that section.
     Revise paragraph 60.5397a(c)(8) to clarify the calibration 
requirements when Method 21 of Appendix A-7 to Part 60 is used for 
fugitive emission monitoring.
     Revise paragraph 60.5397a(d)(3) to correctly cross-
reference paragraphs (g)(3) and (g)(4) of that section.
     Revise paragraph 60.5401a(e) to remove the word 
``routine'' to clarify that pumps in light liquid service, valves in 
gas/vapor service and light liquid service, and pressure relief devices 
in gas/vapor service within a process unit at an onshore natural gas 
processing plant located on the Alaskan North Slope are not subject to 
any monitoring requirements.
     Revise paragraph 60.5410a(e) to correctly reference 
pneumatic pump affected facilities located at a well site as opposed to 
pneumatic pump affected facilities not located at a natural gas 
processing plant. This proposed revision reflects that the 2016 NSPS 
OOOOa did not finalize requirements for pneumatic pumps in the 
gathering and boosting and transmission and storage segments. 81 FR 
35850.
     Revise paragraph 60.5411a(a)(1) to remove the reference to 
paragraphs 60.5412a(a) and (c) for reciprocating compressor affected 
facilities.
     Revise paragraph 60.5411a(d)(1) to remove the reference to 
storage vessels, as this paragraph applies to all the sources lists in 
paragraph 60.5411a(d), not only storage vessels.
     Revise paragraphs 60.5412a(a)(1), 60.5412a(a)(1)(iv), 
60.5412a(d)(1)(iv), and 60.5412a(d)(1)(iv)(D) to clarify that all 
boilers and process heaters must introduce the vent stream into the 
flame zone and that the performance requirement option for combustion 
control devices on centrifugal compressors and storage vessels is to 
introduce the vent stream with the primary fuel or as the primary fuel. 
This is consistent with the performance testing exemption in section 
60.5413a and continuous monitoring exemption in section 60.5417a for 
boilers and process heaters that introduce the vent stream with the 
primary fuel or as the primary fuel.
     Revise paragraph 60.5412a(c) to correctly reference both 
paragraphs (c)(1) and (c)(2) of that section, for managing carbon in a 
carbon adsorption system.
     Revise paragraph 60.5413a(d)(5)(i) to reference fused 
silica-coated stainless steel evacuated canisters instead a specific 
name brand product.
     Revise paragraph 60.5413a(d)(9)(iii) to clarify the basis 
for the total hydrocarbon span for the alternative range is propane, 
just as the basis for the recommended total hydrocarbon span is 
propane.
     Revise paragraph 60.5413a(d)(12) to clarify that all data 
elements must be submitted for each test run.
     Revise paragraph 60.5415a(b)(3) to reference all the 
applicable reporting and recordkeeping requirements.
     Revise paragraph 60.5416a(a)(4) to correctly cross-
reference paragraph 60.5411a(a)(3)(ii).
     Revise paragraph 60.5417a(a) to clarify requirements for 
controls not specifically listed in paragraph (d) of that section.
     Revise paragraph 60.5422a(b) to correctly cross-reference 
paragraphs 60.487a(b)(1) through (3) and (b)(5).
     Revise paragraph 60.5422a(c) to correctly cross-reference 
paragraph 60.487a(c)(2)(i) through (iv) and (c)(2)(vii) through (viii).
     Revise paragraph 60.5423a(b) to simplify the reporting 
language and clarify what data is required in the report of excess 
emissions for sweetening unit affected facilities.
     Revise paragraph 60.5430a to remove the phrase ``including 
but not limited to'' from the ``fugitive emissions component'' 
definition. This proposed revision reflects that in the response to 
comments document for the 2016 NSPS OOOOa we stated we were removing 
this phrase.\124\
---------------------------------------------------------------------------

    \124\ See Docket ID No. EPA-HQ-OAR-2010-0505-7632, Chapter 4, 
page 4-319.
---------------------------------------------------------------------------

     Revise paragraph 60.5430a to remove the phrase ``at the 
sales meter'' from the ``low pressure well'' definition. When 
determining the low pressure status of a well, pressure is measured 
within the flow line, rather than at the sales meter.
     Revise Table 3 to correctly indicate that the performance 
tests in section 60.8 do not apply to pneumatic pump affected 
facilities.

[[Page 52087]]

     Revise Table 3 to include the collection of fugitive 
emissions components at a well site and the collection of fugitive 
emissions components at a compressor station in the list of exclusions 
for notification of reconstruction.
     Revise paragraphs 60.5393a(f), 60.5410a(e)(8), 
60.5411a(e), 60.5415a(b), 60.5415a(b)(4), 60.5416a(d), 60.5420a(b), 
60.5420a(b)(13), and introductory text in 60.5411a and 60.5416a to 
remove the language added in the ``Oil and Natural Gas Sector: Emission 
Standards for New, Reconstructed, and Modified Sources; Grant of 
Reconsideration and Partial Stay'' (June 5, 2017), which was vacated by 
the U.S. Court of Appeals for the D.C. Circuit on July 3, 2017.

VIII. Impacts of This Proposed Rule

A. What are the air impacts?

    For this action, the EPA estimated the change in emissions that 
will occur due to the implementation of the proposed NSPS 
reconsideration for the analysis years of 2019 through 2025. We 
estimate impacts beginning in 2019 to reflect the year implementation 
of this reconsideration will begin, assuming it is finalized within the 
next year. We estimate impacts through 2025 to illustrate the continued 
compound effect of this rule over a longer period. We do not estimate 
impacts after 2025 for reasons including limited information, as 
explained in the RIA (Regulatory Impact Analysis). The regulatory 
impact estimates for 2025 include sources newly affected in 2025 as 
well as the accumulation of affected sources from 2016 to 2024 that are 
also assumed to be in continued operation in 2025, thus incurring 
compliance costs and emissions reductions in 2025.
    We have estimated that, over the 2019 through 2025 timeframe, 
assuming semiannual monitoring at compressor stations, the proposed 
NSPS reconsideration would increase methane emissions by about 380,000 
short tons, and VOC emissions by about 100,000 tons from facilities 
affected by this reconsideration compared to emissions under the 2018 
updated baseline, as described in the RIA. The proposed reconsideration 
is also expected to concurrently increase hazardous air pollutant (HAP) 
emissions by about 3,800 tons from 2019 through 2025. Section 2 of the 
RIA contains an analysis of the increase in emissions as a result of 
this proposed reconsideration under the co-proposed option of annual 
monitoring at compressor stations. As seen in section 2.5.2 of the RIA, 
the co-proposed option of annual fugitive emissions monitoring results 
in greater total emissions than those under the co-proposed option of 
semiannual fugitive emissions monitoring at compressor stations outside 
of the Alaskan North Slope. Over 2019 through 2025, fugitive emissions 
under the co-proposed option assuming annual monitoring are about 
100,000 short tons greater for methane, 24,000 tons greater for VOC, 
and 890 tons greater for HAP than those under the co-proposed option 
assuming semiannual fugitive emissions monitoring.
    As described in the TSD and RIA for this rule, the EPA projected 
affected facilities using a combination of historical data from the 
United States GHG Inventory, projected activity levels taken from the 
Energy Information Administration (EIA's) Annual Energy Outlook (AEO), 
and oil and natural gas production information from DrillingInfo, a 
private company that provides information and analysis to the energy 
sector. The EPA also considered state regulations with similar 
requirements to the proposed NSPS in projecting affected sources for 
impacts analyses supporting this rule.

B. What are the energy impacts?

    Energy impacts in this section are those energy requirements 
associated with the operation of emission control devices. Potential 
impacts on the national energy economy from the rule are discussed in 
the economic impacts section. There would be little change in the 
national energy demand from the operation of any of the environmental 
controls proposed in this action. The proposed NSPS reconsideration 
continues to encourage the use of emission controls that recover 
hydrocarbon products that can be used on-site as fuel or reprocessed 
within the production process for sale.

C. What are the compliance cost savings?

    Assuming the co-proposed option of semiannual monitoring at 
compressor stations, the EPA estimates the PV of compliance cost 
savings of the proposed reconsideration over 2019-2025, discounted back 
to 2016, will be $429 million (in 2016 dollars) under a 7 percent 
discount rate, and $546 million under a 3 percent discount rate, not 
including the forgone producer revenues associated with the decrease in 
the recovery of saleable natural gas. The EAV of these cost savings are 
$74 million per year using a 7 percent discount rate and $85 million 
per year using a 3 percent discount rate. In this analysis, we use the 
2018 AEO projection of natural gas prices to estimate the value of the 
change in the recovered gas at the wellhead. After accounting for the 
change in these revenues, the estimate of the PV of compliance cost 
savings of the proposed reconsideration over 2019-2025, discounted back 
to 2016, are estimated to be $380 million under a 7 percent discount 
rate, and $484 million under a 3 percent discount rate; the 
corresponding estimates of the EAV of cost savings after accounting for 
the forgone revenues are $66 million per year under a 7 percent 
discount rate, and $75 million per year under a 3 percent discount 
rate.
    Compared to the estimated cost savings of the co-proposed option 
under semiannual fugitive emissions monitoring at compressor stations, 
the co-proposed option assuming annual monitoring results in greater 
cost savings. Assuming a 7 percent discount rate, and including the 
forgone value of product recovery, the PV of the total cost savings 
from 2019 through 2025 are about $43 million greater under annual 
monitoring than under semiannual monitoring. This is associated with an 
increase in the EAV of total cost savings of about $7.5 million per 
year in comparison to the co-proposed option under semiannual 
monitoring. A summary of the cost savings and forgone emission 
reductions associated with the co-proposed option of annual fugitive 
emissions monitoring at compressor stations is located in section 2.5.2 
of the RIA.

D. What are the economic and employment impacts?

    The EPA used the National Energy Modeling System (NEMS) to estimate 
the impacts of the 2016 NSPS OOOOa on the United States energy system. 
The NEMS is a publicly-available model of the United States energy 
economy developed and maintained by the EIA and is used to produce the 
AEO, a reference publication that provides detailed forecasts of the 
United States energy economy.
    The EPA estimated small impacts of that rule over the 2020 to 2025 
period relative to the baseline for that rule. The proposed 
reconsideration is estimated to result in a decrease in total costs 
compared to the updated 2018 baseline, and the 2016 NSPS OOOOa, with 
the change in costs affecting a subset of the total costs estimated for 
the 2016 NSPS OOOOa. Therefore, the EPA expects that this deregulatory 
action, if finalized, would partially ameliorate the impacts estimated 
for the final NSPS in the 2016 RIA.
    Executive Order 13563 directs federal agencies to consider the 
effect of regulations on job creation and

[[Page 52088]]

employment. According to the Executive Order, ``our regulatory system 
must protect public health, welfare, safety, and our environment while 
promoting economic growth, innovation, competitiveness, and job 
creation. It must be based on the best available science.'' (Executive 
Order 13563, 2011.) While a standalone analysis of employment impacts 
is not included in a standard benefit-cost analysis, such an analysis 
is of particular concern in the current economic climate given 
continued interest in the employment impact of regulations such as this 
proposed rule.
    The EPA estimated the labor impacts due to the installation, 
operation, and maintenance of control equipment, control activities, 
and labor associated with new reporting and recordkeeping requirements 
in the 2016 NSPS OOOOa RIA. For the proposed reconsideration, the EPA 
expects there will be slight reductions in the labor required for 
compliance-related activities associated with the 2016 NSPS OOOOa 
requirements relating to fugitive emissions and inspections of closed 
vent systems. However, due to uncertainties associated with how the 
proposed reconsideration will influence the portfolio of activities 
associated with fugitive emissions-related requirements, the EPA is 
unable to provide quantitative estimates of compliance-related labor 
changes.

E. What are the forgone benefits of the proposed standards?

    The EPA estimated the forgone domestic climate benefits from the 
methane emissions associated with this reconsideration using an interim 
measure of the domestic social cost of methane (SC-CH4). The 
SC-CH4 estimates used here were developed under E.O. 13783 
for use in regulatory analyses until an improved estimate of the 
impacts of climate change to the U.S. can be developed based on the 
best available science and economics. E.O. 13783 directed agencies to 
ensure that estimates of the social cost of greenhouse gases used in 
regulatory analyses ``are based on the best available science and 
economics'' and are consistent with the guidance contained in OMB 
Circular A-4, ``including with respect to the consideration of domestic 
versus international impacts and the consideration of appropriate 
discount rates'' (E.O. 13783, Section 5(c)). In addition, E.O. 13783 
withdrew the technical support documents (TSDs) and the August 2016 
Addendum to these TSDs describing the global social cost of greenhouse 
gas estimates developed under the prior Administration as no longer 
representative of government policy. The withdrawn TSDs and Addendum 
were developed by an interagency working group (IWG) that included the 
EPA and other executive branch entities and were used in the 2016 NSPS 
RIA.
    The forgone benefits of the proposed reconsideration are estimated 
based on semiannual monitoring at compressor stations and are in 
comparison to an updated baseline with the 2016 NSPS OOOOa and the 
March 12, 2018 amendments with respect to the Alaskan North Slope in 
place.\125\ The EPA estimates the PV of the forgone domestic climate 
benefits over 2019-2025, discounted back to 2016, will be $13.5 million 
under a 7 percent discount rate and $54 million under a 3 percent 
discount rate. The EAV of these forgone benefits is $2.3 million per 
year under a 7 percent discount rate and $8.3 million per year under a 
3 percent discount rate. These values represent only a partial 
accounting of domestic climate impacts from methane emissions, and do 
not account for health effects of ozone exposure from the increase in 
methane emissions.
---------------------------------------------------------------------------

    \125\ While the EPA is co-proposing annual monitoring for 
compressor stations, this discussion of forgone benefits is limited 
to the proposal of semiannual monitoring for compressor stations. 
For additional information regarding the cost savings and forgone 
emission reductions, see section 2 of the RIA.
---------------------------------------------------------------------------

    The EPA expects that the forgone VOC emission reductions may 
degrade air quality and adversely affect health and welfare effects 
associated with exposure to ozone, PM2.5, and HAP, however 
data limitations prevent us from quantifying forgone VOC-related health 
benefits. This omission should not imply that these forgone benefits 
may not exist; rather, it reflects the difficulties in modeling the 
direct and indirect impacts of the reductions in emissions for this 
industrial sector with the data currently available. As described in 
the RIA, with these data currently unavailable, we are unable to 
estimate forgone health benefits estimates for this rule due to the 
differences in the locations of oil and natural gas emission points 
relative to existing information and the highly localized nature of air 
quality responses associated with HAP and VOC reductions.

IX. Statutory and Executive Order Reviews

    Additional information about these statutes and Executive Orders 
can be 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 an economically significant regulatory action that 
was submitted to the OMB for review. Any changes made in response to 
OMB recommendations have been documented in the docket. The EPA 
prepared an analysis of the potential costs and benefits associated 
with this action. This Regulatory Impact Analysis (RIA) is available in 
the docket. The RIA describes in detail the empirical basis for the 
EPA's assumptions and characterizes the various sources of 
uncertainties affecting the estimates below. Table 4 shows the present 
value and equivalent annualized value results of the cost and benefits 
analysis for the proposed rule, assuming semiannual monitoring at 
compressor stations, for 2019 through 2025, discounted back to 2016 
using a discount rate of 7 percent. The table also shows the total 
increase in emissions from 2019 through 2025 from this proposed 
reconsideration. When discussing net benefits, we modify the relevant 
terminology to be more consistent with traditional net benefits 
analysis. In the following table, we refer to the cost savings as 
presented in section 2 of the RIA, and in section VIII.C, above, as the 
``benefits'' of this proposed action and the forgone benefits as 
presented in section 3 of the RIA, and in section VIII.E, above, as the 
``costs'' of this proposed action. The net benefits are the benefits 
(cost savings) minus the costs (forgone benefits).

[[Page 52089]]



Table 4--Summary of the Present Value and Equivalent Annualized Value of
  the Monetized Forgone Benefits, Cost Savings and Net Benefits of the
   Proposed Oil and Natural Gas Reconsideration From 2019 Through 2025
                           [Millions of 2016$]
------------------------------------------------------------------------
                                                          Equivalent
                                     Present value     annualized value
------------------------------------------------------------------------
Benefits (Total Cost Savings)...  $380 million......  $66 million.
Costs (Forgone Domestic Climate   $13.5 million.....  $2.3 million.
 Benefits).
                                 ---------------------------------------
    Net Benefits................  $367 million......  $64 million.
------------------------------------------------------------------------
Non-monetized Forgone Benefits..  Non-monetized climate impacts from
                                   increases in methane emissions.
                                  Health effects of PM2.5 and ozone
                                   exposure from an increase of 100,000
                                   tons of VOC from 2019 through 2025.
                                  Health effects of HAP exposure from an
                                   increase of 3,800 tons of HAP from
                                   2019 through 2025.
                                  Health effects of ozone exposure from
                                   an increase of 380,000 short tons of
                                   methane from 2019 through 2025.
                                  Visibility impairment.
                                  Vegetation effects.
------------------------------------------------------------------------
Estimates may not sum due to independent rounding.

B. Executive Order 13771: Reducing Regulations and Controlling 
Regulatory Costs

    This action is expected to be an Executive Order 13771 deregulatory 
action. Details on the estimated cost savings of this proposed rule can 
be found in the EPA's analysis of the potential costs and benefits 
associated with this action.

C. Paperwork Reduction Act (PRA)

    A summary of the information collection activities submitted to the 
OMB for the final action titled, ``Standards of Performance for Crude 
Oil and Natural Gas Facilities for Construction, Modification, or 
Reconstruction'' (2016 NSPS OOOOa) under the PRA, and assigned EPA ICR 
Number 2523.02, can be found at 81 FR 35890. You can find a copy of the 
ICR in the 2016 NSPS OOOOa docket (EPA-HQ-OAR-2010-0505-7626). This 
proposed reconsideration revises the information collection activities 
of 2016 NSPS OOOOa. The revised information collection activities in 
this proposed rule have been submitted for approval to OMB under the 
PRA. The revised ICR document that the EPA prepared has been assigned 
EPA ICR number 2523.03. You can find a copy of the revised ICR in the 
docket for this rule.
    The proposed changes to the 2016 NSPS OOOOa information collection 
activities would reduce the burden on the regulated industry associated 
with reporting and recordkeeping requirements. Proposed amendments to 
the reporting and recordkeeping requirements are presented in section 
60.5420a. Other information collection activity reductions would result 
from proposed amendments that streamline and align monitoring 
requirements (and associated recordkeeping) in the rule.
    The estimated average annual burden (averaged over the first 3 
years after the effective date of the standards) for the recordkeeping 
and reporting requirements associated with the proposed amendments to 
subpart OOOOa for the estimated 2,893 owners and operators subject to 
the rule is 156,188 labor hours, with an average annual cost of 
$9,615,691 (2016$) over the three-year period. The information 
collection activities associated with the proposed amendments would 
result in an estimated average annual burden reduction of 8 percent 
compared to the previously-submitted 2016 NSPS OOOOa ICR (2016$).
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on the Agency's need for this information, the 
accuracy of the provided revised burden estimates and any suggested 
methods for minimizing respondent burden to the EPA using the docket 
identified at the beginning of this rule. You may also send your ICR-
related comments to OMB's Office of Information and Regulatory Affairs 
via email to [email protected], Attention: Desk Officer for 
the EPA. Since OMB is required to make a decision concerning the ICR 
between 30 and 60 days after receipt, OMB must receive comments no 
later than November 14, 2018. The EPA will respond to any ICR-related 
comments in the final rule.

D. 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. This is a deregulatory action, and the 
burden on all entities affected by this proposed rule, including small 
entities, is reduced compared to the 2016 NSPS OOOOa. See the RIA for 
details. We have therefore concluded that this action will relieve 
regulatory burden for all directly regulated small entities.

E. 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. The action imposes no enforceable duty on any state, 
local or tribal governments or the private sector.

F. 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. This rule, 
if finalized, would primarily affect private industry and would not 
impose

[[Page 52090]]

significant economic costs on state or local governments.

G. 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 effects 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.

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

    This action is not subject to Executive Order 13045 because the EPA 
does not believe the environmental health risks or safety risks 
addressed by this action present a disproportionate risk to children. 
The 2016 NSPS OOOOa, as discussed in the RIA,\126\ was anticipated to 
reduce emissions of methane, VOC, and HAPs, and some of the benefits of 
reducing these pollutants would have accrued to children. However, new 
data and analysis have affected expectations about the extent of the 
impact of the fugitive emissions program in the 2016 NSPS OOOOa on 
these benefits. For example, as previously discussed above in section 
VI.B.1. of this preamble, the EPA reviewed data provided by the 
petitioners, as well as other data that have become available since 
promulgation of the 2016 NSPS OOOOa. The EPA identified several areas 
of our analysis that raise concerns we have overestimated the emission 
reductions and, therefore, the cost effectiveness of the 2016 NSPS 
OOOOa fugitive emissions program. Based on this review, the EPA updated 
the model plants for non-low production well sites, re-examined the 
fugitive emissions estimation method for non-low production well sites 
and compressor stations, and recognized distinct operational 
characteristics of compressor stations. Furthermore, while the proposed 
amendment is expected to decrease the impact of the fugitive emissions 
program in the 2016 NSPS OOOOa on these benefits, as discussed in 
Chapter 1 of the RIA, the potential decrease in emission reduction (and 
thus the benefit) from the proposed amendment is minimal compared to 
the overall emission reduction that would continue to be achieved under 
the amended 40 CFR part 60, subpart OOOOa.
---------------------------------------------------------------------------

    \126\ See Chapter 4, ``Economic Impact Analysis and 
Distributional Assessments,'' of the RIA.
---------------------------------------------------------------------------

    Moreover, the proposed action does not affect the level of public 
health and environmental protection already being provided by existing 
NAAQS and other mechanisms in the CAA. This proposed action does not 
affect applicable local, state, or federal permitting or air quality 
management programs that will continue to address areas with degraded 
air quality and maintain the air quality in areas meeting current 
standards. Areas that need to reduce criteria air pollution to meet the 
NAAQS will still need to rely on control strategies to reduce 
emissions. For the reasons stated above, we do not believe this small 
decrease in emission reduction from this action will have a 
disproportionate adverse effect on children's health.

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

    This action is not a ``significant energy action'' because it is 
not likely to have a significant adverse effect on the supply, 
distribution, or use of energy. The basis for this determination can be 
found in the 2016 NSPS OOOOa (81 FR 35894).

J. National Technology Transfer and Advancement Act (NTTAA)

    This action involves technical standards.\127\ Therefore, the EPA 
conducted searches for the Oil and Natural Gas Sector: Emission 
Standards for New, Reconstructed, and Modified Sources Reconsideration 
through the Enhanced National Standards Systems Network (NSSN) Database 
managed by the American National Standards Institute (ANSI). Searches 
were conducted for EPA Methods 1, 1A, 2, 2A, 2C, 2D, 3A, 3B, 3C, 4, 6, 
10, 15, 16, 16A, 18, 21, 22, and 25A of 40 CFR part 60 Appendix A. No 
applicable voluntary consensus standards were identified for EPA 
Methods 1A, 2A, 2D, 21, and 22 and none were brought to its attention 
in comments. All potential standards were reviewed to determine the 
practicality of the voluntary consensus standards (VCS) for this rule.
---------------------------------------------------------------------------

    \127\ These proposed technical standards are the same as those 
previously finalized at 40 CFR part 60, subpart OOOOa (81 FR 35824). 
2016 NSPS OOOOa also previously incorporated by reference 10 
technical standards. The incorporation by reference remains 
unchanged in this proposed action. See Docket ID Nos. EPA-HQ-OAR-
2010-0505-7657 and EPA-HQ-OAR-2010-0505-7658.
---------------------------------------------------------------------------

    Two VCS were identified as an acceptable alternative to the EPA 
test methods for the purpose of this rule. First, ANSI/ASME PTC 19-10-
1981, Flue and Exhaust Gas Analyses (Part 10) was identified to be used 
in lieu of EPA Methods 3B, 6, 6A, 6B, 15A, and 16A manual portions only 
and not the instrumental portion. This standard includes manual and 
instructional methods of analysis for carbon dioxide, carbon monoxide, 
hydrogen sulfide, nitrogen oxides, oxygen, and sulfur dioxide. Second, 
ASTM D6420-99 (2010), ``Test Method for Determination of Gaseous 
Organic Compounds by Direct Interface Gas Chromatography/Mass 
Spectrometry,'' is an acceptable alternative to EPA Method 18 with the 
following caveats; only use when the target compounds are all known and 
the target compounds are all listed in ASTM D6420 as measurable. ASTM 
D6420 should never be specified as a total VOC Method. (ASTM D6420-99 
(2010) is not incorporated by reference in 40 CFR part 60.) The search 
identified 19 VCS that were potentially applicable for this rule in 
lieu of the EPA reference methods. However, these have been determined 
to not be practical due to lack of equivalency, documentation, 
validation of data, and other important technical and policy 
considerations. For additional information, please see the memorandum 
Voluntary Consensus Standard Results for Oil and Natural Gas Sector: 
Emission Standards for New, Reconstructed, and Modified Sources 
Reconsideration, located at Docket ID No. EPA-HQ-OAR-2017-0483.

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

    The EPA believes that this proposed action is unlikely to have 
disproportionately high and adverse human health or environmental 
effects on minority populations, low-income populations and/or 
indigenous peoples as specified in Executive Order 12898 (59 FR 7629, 
February 16, 1994). The 2016 NSPS OOOOa was anticipated to reduce 
emissions of methane, VOC, and HAPs, and some of the benefits of 
reducing these pollutants would have accrued to minority populations, 
low-income populations and/or indigenous peoples. However, new data and 
analysis have affected expectations about the extent of the impact of 
the fugitive emissions program in the 2016 NSPS OOOOa on these 
benefits. For example, as previously discussed above in section VI.B.1. 
of this preamble, the EPA reviewed data provided by the petitioners, as 
well as other data that have become available since promulgation of the 
2016 NSPS OOOOa.

[[Page 52091]]

The EPA identified several areas of our analysis that raise concerns we 
have overestimated the emission reductions and, therefore, the cost 
effectiveness of the 2016 NSPS OOOOa fugitive emissions program. Based 
on this review, the EPA updated the model plants for non-low production 
well sites, re-examined fugitive emissions from low production well 
sites, recognized the limitations in our emissions estimation method 
for non-low production well sites and compressor stations, and 
recognized distinct operational characteristics of compressor stations. 
Furthermore, while these communities may experience forgone benefits as 
a result of this action, as discussed in Chapter 1 of the RIA, the 
potential foregone emission reductions (and related benefits) from the 
proposed amendments is minimal compared to the overall emission 
reductions (and related benefits) from the 2016 NSPS.
    Moreover, the proposed action does not affect the level of public 
health and environmental protection already being provided by existing 
NAAQS and other mechanisms in the CAA. This proposed action does not 
affect applicable local, state, or federal permitting or air quality 
management programs that will continue to address areas with degraded 
air quality and maintain the air quality in areas meeting current 
standards. Areas that need to reduce criteria air pollution to meet the 
NAAQS will still need to rely on control strategies to reduce 
emissions.
    For the reasons stated above, the EPA believes that this proposed 
action is unlikely to have disproportionately high and adverse human 
health or environmental effects on minority populations, low-income 
populations and/or indigenous peoples. We note that the potential 
impacts of this proposed action are not expected to be experienced 
uniformly, and the distribution of avoided compliance costs associated 
with this action depends on the degree to which costs would have been 
passed through to consumers.

List of Subjects in 40 CFR Part 60

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

    Dated: September 11, 2018.
Andrew R. Wheeler,
Acting Administrator.

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

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

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

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

Subpart OOOOa--Standards of Performance for Crude Oil and Natural 
Gas Facilities for Which Construction, Modification or 
Reconstruction Commenced After September 18, 2015

0
2. Section 60.5365a is amended by revising paragraph (e) introductory 
text and adding paragraph (i)(4) to read as follows:


Sec.  60.5365a  Am I subject to this subpart?

* * * * *
    (e) Each storage vessel affected facility, which is a single 
storage vessel with the potential for VOC emissions equal to or greater 
than 6 tpy as determined according to 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, 
as defined in Sec.  60.5430a, determined for a 30-day period of 
production prior to the applicable emission determination deadline 
specified in this subsection. 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.
* * * * *
    (i) * * *
    (4) For purposes of Sec.  60.5397a, a ``modification'' to a 
separate tank battery occurs when:
    (i) Any of the actions in paragraphs Sec.  60.5365a(i)(3)(i) 
through (iii) occurs at an existing separate tank battery;
    (ii) A well sending production to an existing separate tank battery 
is modified, as defined in Sec.  60.5365a(i)(3)(i) through (iii); or
    (iii) A well site subject to the requirements in Sec.  60.5397a 
removes all major production and processing equipment, as defined in 
Sec.  60.5430a, such that it becomes a wellhead only well site and 
sends production to an existing separate tank battery.
* * * * *
0
3. Section 60.5375a is amended by revising paragraph (a)(1)(iii) 
introductory text and paragraph (f)(3)(ii) and adding paragraph (f)(4) 
to read as follows:


Sec.  60.5375a  What GHG and VOC standards apply to well affected 
facilities?

* * * * *
    (a) * * *
    (1) * * *
    (iii) You must have a separator onsite or otherwise available for 
use at a centralized facility or well pad that services the well 
affected facility which is used to conduct the completion of the well 
affected facility. The separator must be available and ready to be used 
to comply with paragraph (a)(1)(ii) of this section during the entirety 
of the flowback period, except as provided in paragraphs (a)(1)(iii)(A) 
through (C) of this section.
* * * * *
    (f) * * *
    (3) * * *
    (ii) Route all 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. 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 pilot flame.
    (4) You must submit the notification as specified in Sec.  
60.5420a(a)(2), submit annual reports as specified in Sec.  
60.5420a(b)(1) and (2) and maintain records specified in Sec.  
60.5420a(c)(1)(iii) for each wildcat and delineation well. You must 
submit the notification as specified in Sec.  60.5420a(a)(2), submit 
annual reports as specified in Sec.  60.5420a(b)(1) and (2), and 
maintain records as specified in Sec.  60.5420a(c)(1)(iii) and (vii) 
for each low pressure well.
* * * * *
0
4. Section 60.5385a is amended by revising paragraph (a)(1) to read as 
follows:


Sec.  60.5385a  What GHG and VOC standards apply to reciprocating 
compressor affected facilities?

* * * * *
    (a) * * *
    (1) On or before the compressor has operated for 26,000 hours. The 
number of hours of operation must be continuously monitored beginning 
upon initial startup of your reciprocating compressor affected 
facility, August 2, 2016, or the date of the most recent reciprocating 
compressor rod packing replacement, whichever is later.
* * * * *
0
5. Section 60.5393a is amended by:

[[Page 52092]]

0
a. Revising paragraph (b) introductory text and paragraphs (b)(3), 
(b)(5), (b)(6) and (c);
0
b. Removing and reserving paragraphs (b)(1), (b)(2), and (f).
    The revisions read as follows:


Sec.  60.5393a  What GHG and VOC standards apply to pneumatic pump 
affected facilities?

* * * * *
    (b) For each pneumatic pump affected facility at a well site you 
must reduce natural gas emissions by 95.0 percent, except as provided 
in paragraphs (b)(3), (4) and (5) of this section.
    (1) [Reserved]
    (2) [Reserved]
    (3) You are not required to install a control device solely for the 
purpose of complying with the 95.0 percent reduction requirement of 
paragraph (b) of this section. If you do not have a control device 
installed on site by the compliance date and you do not have the 
ability to route to a process, then you must comply instead with the 
provisions of paragraphs (b)(3)(i) and (ii) of this section.
    (i) Submit a certification in accordance with Sec.  
60.5420a(b)(8)(i)(A) in your next annual report, certifying that there 
is no available control device or process on site and maintain the 
records in Sec.  60.5420a(c)(16)(i) and (ii).
    (ii) If you subsequently install a control device or have the 
ability to route to a process, you are no longer required to comply 
with paragraph (b)(3)(i) of this section and must submit the 
information in Sec.  60.5420a(b)(8)(ii) in your next annual report and 
maintain the records in Sec.  60.5420a(c)(16)(i), (ii), and (iii). You 
must be in compliance with the requirements of paragraph (b)(2) of this 
section within 30 days of startup of the control device or within 30 
days of the ability to route to a process.
* * * * *
    (5) If an owner or operator determines, through an engineering 
assessment, that routing a pneumatic pump to a control device or a 
process is technically infeasible, the requirements specified in 
paragraph (b)(5)(i) through (iv) of this section must be met.
    (i) The owner or operator shall conduct the assessment of technical 
infeasibility in accordance with the criteria in paragraph (b)(5)(iii) 
of this section and have it certified by an in-house engineer or a 
qualified professional engineer in accordance with paragraph (b)(5)(ii) 
of this section.
    (ii) The following certification, signed and dated by the in-house 
engineer or qualified professional engineer shall state: ``I certify 
that the assessment of technical infeasibility was prepared under my 
direction or supervision. I further certify that the assessment was 
conducted and this report was prepared pursuant to the requirements of 
Sec.  60.5393a(b)(5)(iii). Based on my professional knowledge and 
experience, and inquiry of personnel involved in the assessment, the 
certification submitted herein is true, accurate, and complete. I am 
aware that there are penalties for knowingly submitting false 
information.''
    (iii) The assessment of technical feasibility to route emissions 
from the pneumatic pump to an existing control device onsite or to a 
process shall include, but is not limited to, safety considerations, 
distance from the control device, pressure losses and differentials in 
the closed vent system and the ability of the control device to handle 
the pneumatic pump emissions which are routed to them. The assessment 
of technical infeasibility shall be prepared under the direction or 
supervision of the in-house engineer or qualified professional engineer 
who signs the certification in accordance with paragraph (b)(2)(ii) of 
this section.
    (iv) The owner or operator shall maintain the records Sec.  
60.5420a(c)(16)(iv).
    (6) If the pneumatic pump is routed to a control device or a 
process and the control device or process is subsequently removed from 
the location or is no longer available, you are no longer required to 
be in compliance with the requirements of paragraph (b) of this 
section, and instead must comply with paragraph (b)(3) of this section 
and report the change in next annual report in accordance with Sec.  
60.5420a(b)(8)(ii).
    (c) If you use a control device or route to a process to reduce 
emissions, you must connect the pneumatic pump affected facility 
through a closed vent system that meets the requirements of Sec.  
60.5411a(c) and (d).
* * * * *
    (f) [Reserved]
0
6. Section 60.5397a is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraphs (c)(2);
0
c. Revising paragraph (c)(8) introductory text;
0
d. Adding paragraph (c)(8)(iii);
0
e. Revising paragraph (d);
0
f. Revising paragraph (f)(2);
0
g. Revising paragraph (g) introductory text;
0
h. Revising paragraphs (g)(1) and (2);
0
i. Removing and reserving paragraph (g)(5);
0
j. Adding paragraph (g)(6); and
0
k. Revising paragraph (h).
    The revisions and additions read as follows:


Sec.  60.5397a  What fugitive emissions GHG and VOC standards apply to 
the affected facility which is the collection of fugitive emissions 
components at a well site and the affected facility which is the 
collection of fugitive emissions components at a compressor station?

* * * * *
    (a) You must monitor all fugitive emission components, as defined 
in Sec.  60.5430a, in accordance with paragraphs (b) through (g) of 
this section. You must repair all sources of fugitive emissions in 
accordance with paragraph (h) of this section. You must keep records in 
accordance with paragraph (i) of this section and report in accordance 
with paragraph (j) of this section. For purposes of this section, 
fugitive emissions are defined as: Any visible emission from a fugitive 
emissions component observed using optical gas imaging or an instrument 
reading of 500 ppm or greater using Method 21 of Appendix A-7 to this 
part.
* * * * *
    (c) * * *
    (2) Technique for determining fugitive emissions (i.e., Method 21 
of Appendix A-7 to this part or optical gas imaging meeting the 
requirements in paragraphs (c)(7)(i) through (vii) of this section).
* * * * *
    (8) If you are using Method 21 of appendix A-7 of this part, your 
plan must also include the elements specified in paragraphs (c)(8)(i) 
through (iii) of this section. For purposes of complying with the 
fugitive emissions monitoring program using Method 21 a fugitive 
emission is defined as an instrument reading of 500 ppm or greater.
* * * * *
    (iii) Procedures for calibration. The instrument must be calibrated 
before use each day of its use by the procedures specified in Method 21 
of appendix A-7 of this part. At a minimum, you must also conduct 
precision tests at the interval specified in Method 21 of appendix A-7 
of this part, Section 8.1.2, and a calibration drift assessment at the 
end of each monitoring day. The calibration drift assessment must be 
conducted as specified in paragraph (c)(8)(iii)(A) of this section. 
Corrective action for drift assessments is specified in paragraphs 
(c)(8)(iii)(B) and (C) of this section.
    (A) Check the instrument using the same calibration gas that was 
used to calibrate the instrument before use. Follow the procedures 
specified in Method 21 of appendix A-7 of this part,

[[Page 52093]]

Section 10.1, except do not adjust the meter readout to correspond to 
the calibration gas value. If multiple scales are used, record the 
instrument reading for each scale used. Divide these readings by the 
initial calibration values for each scale and multiply by 100 to 
express the calibration drift as a percentage.
    (B) If a calibration drift assessment shows a negative drift of 
more than 10 percent, then all equipment with instrument readings 
between the fugitive emission definition multiplied by (100 minus the 
percent of negative drift/divided by 100) and the fugitive emission 
definition that was monitored since the last calibration must be re-
monitored.
    (C) If any calibration drift assessment shows a positive drift of 
more than 10 percent from the initial calibration value, then, at the 
owner/operator's discretion, all equipment with instrument readings 
above the fugitive emission definition and below the fugitive emission 
definition multiplied by (100 plus the percent of positive drift/
divided by 100) monitored since the last calibration may be re-
monitored.
    (d) Each fugitive emissions monitoring plan must include the 
elements specified in paragraphs (d)(1) through (3) of this section, at 
a minimum, as applicable.
    (1) If you are using optical gas imaging, your plan must include a 
sitemap or plot plan and the information in paragraph (d)(1)(i) or 
paragraphs (d)(1)(ii) through (iv):
    (i) A defined observation path that ensures that all fugitive 
emissions components are within sight of the path. The observation path 
must account for interferences.
    (ii) For closed vent systems regulated under this section, a 
narrative description of how the closed vent system will be monitored, 
including a description and the location of all fugitive emissions 
components located on the closed vent system. The sitemap or plot plan 
must include the location of each closed vent system.
    (iii) For controlled storage vessels regulated under this section, 
a narrative description of how the storage vessel will be monitored 
including a description and location of all fugitive emissions 
components located on the controlled storage vessel. The sitemap or 
plot plan must include the location of each controlled storage vessel.
    (iv) For all other fugitive emissions components not associated 
with a closed vent system or controlled storage vessel regulated under 
this section, a narrative description of how the fugitive emissions 
components will be monitored, including a description and location of 
all fugitive emissions components. The description and location of 
fugitive emissions components may be grouped by unit operations (e.g., 
separator, heater/treater, glycol dehydrator). The sitemap or plot plan 
must include the location of each unit operation.
    (2) If you are using Method 21, your plan must include a list of 
fugitive emissions components to be monitored and method for 
determining location of fugitive emissions components to be monitored 
in the field (e.g., tagging, identification on a process and 
instrumentation diagram, etc.). If you are using optical gas imaging, 
you may comply with this requirement in lieu of paragraph (d)(1) of 
this section.
    (3) Your fugitive emissions monitoring plan must include the 
written plan developed for all of the fugitive emission components 
designated as difficult-to-monitor in accordance with paragraph (g)(3) 
of this section, and the written plan for fugitive emission components 
designated as unsafe-to-monitor in accordance with paragraph (g)(4) of 
this section.
* * * * *
    (f) * * *
    (2) You must conduct an initial monitoring survey within 60 days of 
the startup of a new compressor station for each new collection of 
fugitive emissions components at the new compressor station or by June 
3, 2017, whichever is later. For a modified collection of fugitive 
components at a compressor station, the initial monitoring survey must 
be conducted within 60 days of the modification or by June 3, 2017, 
whichever is later. Notwithstanding the preceding deadlines, for each 
collection of fugitive emissions components at a new compressor station 
located on the Alaskan North Slope that starts up between September and 
March, you must conduct an initial monitoring survey within 6 months of 
the startup date for new compressor stations, within 6 months of the 
modification, or by the following June 30, whichever is later.
    (g) A monitoring survey of each collection of fugitive emissions 
components at a well site or at a compressor station must be performed 
at the frequencies specified in paragraphs (g)(1) and (2) of this 
section, with the exceptions noted in paragraphs (g)(3), (4), and (6) 
of this section.
    (1) A monitoring survey of each collection of fugitive emissions 
components at a well site within a company-defined area must be 
conducted at the frequencies specified in paragraphs (g)(1)(i) or (ii) 
of this section.
    (i) At least annually for each collection of fugitive emissions 
components located at a well site with average combined oil and natural 
gas production for the wells at the site being greater than or equal to 
15 barrels of oil equivalent (boe) per day averaged over the first 30 
days of production, where boe equals cubic feet gas/5658.53. 
Consecutive annual monitoring surveys must be conducted at least 9 
months apart and no more than 13 months apart.
    (ii) At least once every other year (i.e., biennial) for each 
collection of fugitive emissions components located at a well site with 
average combined oil and natural gas production for the wells at the 
site being less than 15 boe per day averaged over the first 30 days of 
production, where boe equals cubic feet gas/5658.53. Consecutive 
biennial monitoring surveys must be conducted no more than 25 months 
apart.
    (2) Except as provided herein, a monitoring survey of the 
collection of fugitive emissions components at a compressor station 
within a company-defined area must be conducted at least semiannually 
after the initial survey. Consecutive semiannual monitoring surveys 
must be conducted at least 4 months apart and no more than 6 months 
apart. Each compressor must be monitored while in operation (i.e., not 
in stand-by mode) at least annually. A monitoring survey of the 
collection of fugitive emissions components at a compressor station 
located on the Alaskan North Slope must be conducted at least annually. 
Consecutive annual monitoring surveys must be conducted at least 9 
months apart and no more than 13 months apart.
* * * * *
    (5) [Reserved]
    (6) You are no longer required to comply with the requirements of 
paragraph (g)(1) of this section when the owner or operator removes all 
major production and processing equipment, as defined in Sec.  
60.5430a, such that the well site becomes a wellhead only well site. If 
any major production and processing equipment is subsequently added to 
the well site, then the owner or operator must comply with the 
requirements in paragraphs (f)(1) and (g)(1) of this section.
    (h) Each identified source of fugitive emissions shall be repaired, 
as defined in Sec.  60.5430a, in accordance with paragraphs (h)(1) and 
(2) of this section.
    (1) Each identified source of fugitive emissions shall be repaired 
as soon as

[[Page 52094]]

practicable, but no later than 60 calendar days after detection of the 
fugitive emissions.
    (2) A first attempt at repair shall be made no later than 30 
calendar days after detection of the fugitive emissions.
    (3) If the repair is technically infeasible, would require a vent 
blowdown, a compressor station shutdown, a well shutdown or well shut-
in, or would be unsafe to repair during operation of the unit, the 
repair must be completed during the next scheduled compressor station 
shutdown, well shutdown, well shut-in, after a scheduled vent blowdown 
or within 2 years, whichever is earlier. For purposes of this 
requirement, a vent blowdown is the opening of one or more blowdown 
valves to depressurize major production and processing equipment, other 
than a storage vessel.
    (4) Each repaired fugitive emissions component must be resurveyed 
according to the requirements in paragraphs (h)(4)(i) through (iv) of 
this section, to ensure that there are no fugitive emissions.
    (i) The operator may resurvey the fugitive emissions components to 
verify repair using either Method 21 of appendix A-7 of this part or 
optical gas imaging.
    (ii) For each repair that cannot be made during the monitoring 
survey when the fugitive emissions are initially found, a digital 
photograph must be taken of that component or the component must be 
tagged during the monitoring survey when the fugitives were initially 
found for identification purposes and subsequent repair. The digital 
photograph must include the date that the photograph was taken and must 
clearly identify the component by location within the site (e.g., the 
latitude and longitude of the component or by other descriptive 
landmarks visible in the picture).
    (iii) Operators that use Method 21 of appendix A-7 of this part to 
resurvey the repaired fugitive emissions components are subject to the 
resurvey provisions specified in paragraphs (h)(4)(iii)(A) and (B) of 
this section.
    (A) A fugitive emissions component is repaired when the Method 21 
instrument indicates a concentration of less than 500 ppm above 
background or when no soap bubbles are observed when the alternative 
screening procedures specified in section 8.3.3 of Method 21 of 
appendix A-7 of this part are used.
    (B) Operators must use the Method 21 monitoring requirements 
specified in paragraph (c)(8)(ii) of this section or the alternative 
screening procedures specified in section 8.3.3 of Method 21 of 
appendix A-7 of this part.
    (iv) Operators that use optical gas imaging to resurvey the 
repaired fugitive emissions components, are subject to the resurvey 
provisions specified in paragraphs (h)(4)(iv)(A) and (B) of this 
section.
    (A) A fugitive emissions component is repaired when the optical gas 
imaging instrument shows no indication of visible emissions.
    (B) Operators must use the optical gas imaging monitoring 
requirements specified in paragraph (c)(7) of this section.
* * * * *
0
7. Section 60.5398a is amended by revising paragraphs (a), (c), (d) and 
(f) to read as follows:


Sec.  60.5398a  What are the alternative means of emission limitations 
for GHG and VOC from well completions, reciprocating compressors, the 
collection of fugitive emissions components at a well site and the 
collection of fugitive emissions components at a compressor station?

    (a) If, in the Administrator's judgment, an alternative means of 
emission limitation will achieve a reduction in GHG (in the form of a 
limitation on emission of methane) and VOC emissions at least 
equivalent to the reduction in GHG and VOC emissions achieved under 
Sec.  60.5375a, Sec.  60.5385a, and Sec.  60.5397a, the Administrator 
will publish, in the Federal Register, a notice permitting the use of 
that alternative means for the purpose of compliance with Sec.  
60.5375a, Sec.  60.5385a, and Sec.  60.5397a. The notice may condition 
permission on requirements related to the operation and maintenance of 
the alternative means.
* * * * *
    (c) The Administrator will consider applications under this section 
from owners or operators of affected facilities, and manufacturers or 
vendors of leak detection technologies, or trade associations provided 
they are submitted in conjunction with an owner or operator.
    (d) Determination of equivalence to the design, equipment, work 
practice or operational requirements of this section will be evaluated 
by the following guidelines:
    (1) The applicant must provide information that is sufficient for 
demonstrating the alternative means of emission limitation is at least 
as equivalent as the relevant standards. At a minimum, the applicant 
must collect, verify, and submit field data to demonstrate the 
equivalence of the alternative means of emission limitation; the field 
data must encompass seasonal variations over the year to ensure that 
the technique works appropriately in different conditions that will be 
encountered during monitoring surveys. The field data may be 
supplemented with modeling analyses, test data, or other documentation. 
The application must include the following information:
    (i) A description of the technology, technique, or process.
    (ii) A description of the monitoring instrument or measurement 
technology used in the technology, technique, or process.
    (iii) A description of performance based procedures (i.e., method) 
and data quality indicators for precision and bias; the method 
detection limit of the technology, technique, or process.
    (iv) For affected facilities under Sec.  60.5397a, the action 
criteria and level at which a fugitive emission exists.
    (v) Any initial and ongoing quality assurance/quality control 
measures necessary for maintaining the technology, technique, or 
process.
    (vi) Timeframes for conducting ongoing quality assurance/quality 
control.
    (vii) Field data verifying viability and detection capabilities of 
the technology, technique, or process. Test data, modeling analyses, or 
other documentation may be used to supplement field data.
    (viii) Frequency of measurements and surveys conducted with the 
technology, technique, or process.
    (ix) For continuous monitoring techniques, the minimum data 
availability.
    (x) Sufficient data and other supporting documentation for 
determining the emissions reductions achieved or avoided by the 
technology, technique, or process.
    (xi) Any restrictions for using the technology, technique, or 
process.
    (xii) Operation and maintenance procedures and other provisions 
necessary to ensure reduction in methane and VOC emissions at least 
equivalent to the reduction in methane and VOC emissions achieved under 
Sec.  60.5397a.
    (xiii) Initial and continuous compliance procedures, including 
recordkeeping and reporting, if the compliance procedures are different 
than those specified in Sec.  60.5397a(d).
    (2) For each determination of equivalency requested, the emission 
reduction achieved by the design, equipment, work practice or 
operational requirements shall be demonstrated by field data, which can 
be supplemented with modeling analyses at an active

[[Page 52095]]

production site or test data at a controlled test environment or 
facility.
    (3) For each technology, technique, or process for which a 
determination of equivalency is requested, the emission reduction 
achieved by the alternative means of emission limitation shall be 
demonstrated.
* * * * *
    (f)(1) An application submitted under this section will be 
evaluated based on the field data, modeling analyses, and other 
documentation that was provided to demonstrate the equivalence of the 
alternative means of emission limitation under this section.
    (2) The Administrator may condition the approval of the alternative 
means of emission limitation on requirements that may be necessary to 
ensure that the alternative will achieve at least equivalent emission 
reduction(s) as the reduction(s) achieved under the requirement(s) for 
which the alternative is being requested.
0
8. Subpart OOOOa is amended by adding section 60.5399a to read as 
follows:


Sec.  60.5399a  What alternative fugitive emissions standards apply to 
the affected facility which is the collection of fugitive emissions 
components at a well site and the affected facility which is the 
collection of fugitive emissions components at a compressor station: 
Equivalency with state, local, and tribal programs?

    This section provides alternative fugitive emissions standards for 
the collection of fugitive emissions components, as defined in Sec.  
60.5430a, located at well sites and compressor stations. Paragraphs (a) 
through (e) of this section outline the procedure for submittal and 
approval of alternative fugitive emissions standards. Paragraphs (g) 
through (n) of this section provide approved alternative fugitive 
emissions standards. The terms ``fugitive emissions components'' and 
``repaired'' are defined in Sec.  60.5430a and must be applied to the 
alternative fugitive emissions standards in this section.
    (a) The Administrator will consider applications for alternative 
fugitive emissions standards under this section based on state, local, 
or tribal programs that are currently in effect from any interested 
person, which includes, but is not limited to individuals, 
corporations, partnerships, associations, state, or municipalities.
    (b) Determination of alternative fugitive emissions standards to 
the design, equipment, work practice, or operational requirements of 
Sec.  60.5397a will be evaluated by the following guidelines:
    (1) The monitoring instrument, including the monitoring procedure;
    (2) The monitoring frequency;
    (3) The fugitive emissions definition;
    (4) The repair requirements; and
    (5) The recordkeeping and reporting requirements.
    (c) After notice and opportunity for public comment, the 
Administrator will determine whether the requested alternative fugitive 
emissions standard will achieve at least equivalent emission 
reduction(s) in VOC and methane emissions as the reduction(s) achieved 
under the applicable requirement(s) for which an alternative is being 
requested, and will publish the determination in the Federal Register.
    (d)(1) An application submitted under this section will be 
evaluated based on the documentation that was provided to demonstrate 
the equivalence of the alternative fugitive emissions standards under 
this section.
    (2) The Administrator may condition the approval of the alternative 
fugitive emissions standards on requirements that may be necessary to 
ensure that the alternative will achieve at least equivalent emissions 
reduction(s) as the reduction(s) achieved under the requirements for 
which the alternative is being requested.
    (e) Any alternative fugitive emissions standard approved under this 
section shall:
    (1) Constitute a required design, equipment, work practice, or 
operational standard within the meaning of section 111(h)(1) of the 
CAA; and
    (2) May be used by any owner or operator in meeting the relevant 
standards and requirements established for affected facilities under 
Sec.  60.5397a.
    (f)(1) An owner or operator must notify the Administrator before 
implementing one of the alternative fugitive emissions standards, as 
specified in Sec.  60.5420a(a)(3).
    (2) An owner or operator implementing one of the alternative 
fugitive emissions standards must include the information specified in 
Sec.  60.5420a(b)(7) in the annual report and maintain the records 
specified by the specific alternative fugitive emissions standard for a 
period of at least 5 years.
    (g) Alternative fugitive emissions requirements for the collection 
of fugitive emissions components located at a well site or a compressor 
station in the state of California. An affected facility, which is the 
collection of fugitive emissions components, as defined in Sec.  
60.5430a, located at a well site or a compressor station in the state 
of California may elect to reduce VOC and GHG emissions through 
compliance with the monitoring, repair, and recordkeeping requirements 
in the California Code of Regulations, title 17, Sec. Sec.  95665-
95667, effective January 1, 2020, as an alternative to complying with 
the requirements in Sec. Sec.  60.5397a(f)(1) and (2), (g)(1) through 
(4), (h), and (i) of this subpart.
    (h) Alternative fugitive emissions requirements for the collection 
of fugitive emissions components located at a well site or a compressor 
station in the state of Colorado. An affected facility, which is the 
collection of fugitive emissions components, as defined in Sec.  
60.5430a, located at a well site or a compressor station in the state 
of Colorado may elect to comply with the monitoring, repair, and 
recordkeeping requirements in Colorado Regulation 7, Sec. Sec.  XII.L, 
effective June 30, 2018, or XVII.F, effective October 15, 2014 for well 
sites and January 1, 2015 for compressor stations, as an alternative to 
complying with the requirements in Sec. Sec.  60.5397a(f)(1) and (2), 
(g)(1) through (4), (h), and (i) of this subpart, provided the 
monitoring instrument used is an optical gas imaging or a Method 21 
instrument.
    (i) Alternative fugitive emissions requirements for the collection 
of fugitive emissions components located at a well site in the state of 
Ohio. An affected facility, which is the collection of fugitive 
emissions components, as defined in Sec.  60.5430a, located at a well 
site in the state of Ohio may elect to comply with the monitoring, 
repair, and recordkeeping requirements in Ohio General Permits 12.1, 
Section C.5 and 12.2, Section C.5, effective April 14, 2014, as an 
alternative to complying with the requirements in Sec. Sec.  
60.5397a(f)(1), (g)(1), (3), and (4), (h), and (i) of this subpart, 
provided the monitoring instrument used is a Method 21 instrument and 
that the leak definition used for Method 21 monitoring is an instrument 
reading of 500 ppm or greater.
    (j) Alternative fugitive emissions requirements for the collection 
of fugitive emissions components located at a compressor station in the 
state of Ohio. An affected facility, which is the collection of 
fugitive emissions components, as defined in Sec.  60.5430a, located at 
a compressor station in the state of Ohio may elect to comply with the 
monitoring, repair, and recordkeeping requirements in Ohio General 
Permit 18.1, effective February 7, 2017, as an alternative to complying 
with the requirements in Sec. Sec.  60.5397a(f)(2), (g)(2) through (4), 
(h), and (i) of this subpart, provided the monitoring instrument used 
is a Method 21 instrument and that the leak definition used for Method 
21

[[Page 52096]]

monitoring is an instrument reading of 500 ppm or greater.
    (k) Alternative fugitive emissions requirements for the collection 
of fugitive emissions components located at a well site in the state of 
Pennsylvania. An affected facility, which is the collection of fugitive 
emissions components, as defined in Sec.  60.5430a, located at a well 
site in the state of Pennsylvania may elect to comply with the 
monitoring, repair, and recordkeeping requirements in Pennsylvania 
General Permit 5, section G, effective August 8, 2018, as an 
alternative to complying with the requirements in Sec. Sec.  
60.5397a(f)(2), (g)(2) through (4), (h), and (i) of this subpart, 
provided the monitoring instrument used is an optical gas imaging or a 
Method 21 instrument.
    (l) Alternative fugitive emissions requirements for the collection 
of fugitive emissions components located at a compressor station in the 
state of Pennsylvania. An affected facility, which is the collection of 
fugitive emissions components, as defined in Sec.  60.5430a, located at 
a compressor station in the state of Pennsylvania may elect to comply 
with the monitoring, repair, and recordkeeping requirements in 
Pennsylvania General Permit 5, section G, effective August 8, 2018, as 
an alternative to complying with the requirements in Sec. Sec.  
60.5397a(f)(2), (g)(2) through (4), (h), and (i) of this subpart, 
provided the monitoring instrument used is an optical gas imaging or a 
Method 21 instrument.
    (m) Alternative fugitive emissions requirements for the collection 
of fugitive emissions components located at a well site in the state of 
Texas. An affected facility, which is the collection of fugitive 
emissions components, as defined in Sec.  60.5430a, located at a well 
site in the state of Texas may elect to comply with the monitoring, 
repair, and recordkeeping requirements in the Air Quality Standard 
Permit for Oil and Gas Handling and Production Facilities, section 
(e)(6), effective November 8, 2012, or at 30 Tex. Admin. Code Sec.  
116.620, effective September 4, 2000, as an alternative to complying 
with the requirements in Sec. Sec.  60.5397a(f)(2), (g)(2) through (4), 
(h), and (i) of this subpart, provided the monitoring instrument used 
is a Method 21 instrument and that the leak definition used for Method 
21 monitoring is an instrument reading of 2,000 ppm or greater.
    (n) Alternative fugitive emissions requirements for the collection 
of fugitive emissions components located at a well site in the state of 
Utah. An affected facility, which is the collection of fugitive 
emissions components, as defined in Sec.  60.5430a, and is required to 
control emissions in accordance with Utah Administrative Code R307-506 
and R307-507, located at a well site in the state of Utah may elect to 
comply with the monitoring, repair, and recordkeeping requirements in 
the Utah Administrative Code R307-509, effective March 2, 2018, as an 
alternative to complying with the requirements in Sec. Sec.  
60.5397a(f)(2), (g)(2) through (4), (h), and (i) of this subpart.
0
9. Section 60.5400a is amended by revising paragraph (a) to read as 
follows:


Sec.  60.5400a  What equipment leak GHG and VOC standards apply to 
affected facilities at an onshore natural gas processing plant?

* * * * *
    (a) You must comply with the requirements of Sec. Sec.  60.482-
1a(a), (b), (d), and (e), 60.482-2a, and 60.482-4a through 60.482-11a, 
except as provided in Sec.  60.5401a.
* * * * *
0
10. Section 60.5401a is amended by revising paragraph (e) to read as 
follows:


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

* * * * *
    (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 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
11. Section 60.5410a is amended by:
0
a. Revising paragraph (c)(1);
0
b. Revising paragraphs (e)(2) through (5); and
0
c. Removing and reserving paragraph (e)(8).
    The revisions read as follows:


Sec.  60.5410a  How do I demonstrate initial compliance with the 
standards for my well, centrifugal compressor, reciprocating 
compressor, pneumatic controller, pneumatic pump, storage vessel, 
collection of fugitive emissions components at a well site, collection 
of fugitive emissions components at a compressor station, and equipment 
leaks and sweetening unit affected facilities at onshore natural gas 
processing plants?

* * * * *
    (c) * * *
    (1) If complying with Sec.  60.5385a(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 initial startup, 
since August 2, 2016, or since the last rod packing replacement, 
whichever is later.
* * * * *
    (e) * * *
    (2) If you own or operate a pneumatic pump affected facility 
located at a well site, you must reduce emissions in accordance with 
Sec.  60.5393a(b)(1) or (b)(2), and you must collect the pneumatic pump 
emissions through a closed vent system that meets the requirements of 
Sec.  60.5411a(c) and (d).
    (3) If you own or operate a pneumatic pump affected facility 
located at a well site and there is no control device or process 
available on site, you must submit the certification in Sec.  
60.5420a(b)(8)(i)(A).
    (4) If you own or operate a pneumatic pump affected facility 
located at a well site, and you are unable to route to an existing 
control device or to a process due to technical infeasibility, you must 
submit the certification in Sec.  60.5420a(b)(8)(i)(B).
    (5) If you own or operate a pneumatic pump affected facility 
located at a well site and you reduce emissions in accordance with 
Sec.  60.5393a(b)(4), you must collect the pneumatic pump emissions 
through a closed vent system that meets the requirements of Sec.  
60.5411a(c) and (d).
* * * * *
    (8) [Reserved]
* * * * *
0
12. Section 60.5411a is amended by:
0
a. Revising the introductory text;
0
b. Revising paragraph (a) introductory text;
0
c. Revising paragraph (a)(1);
0
d. Revising paragraph (c) introductory text;
0
e. Revising paragraph (c)(1);
0
f. Revising paragraph (d)(1); and
0
g. Removing and reserving paragraph (e).
    The revisions read as follows:


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

    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 centrifugal compressor wet seal degassing systems, 
reciprocating compressors, pneumatic pumps and storage vessels.
    (a) Closed vent system requirements for reciprocating compressors 
and centrifugal compressor wet seal degassing systems.

[[Page 52097]]

    (1) You must design the closed vent system to route all gases, 
vapors, and fumes emitted from the reciprocating compressor rod packing 
emissions collection system to a process. You must design the closed 
vent system to route all gases, vapors, and fumes emitted from the 
centrifugal compressor wet seal fluid degassing system to a process or 
a control device that meets the requirements specified in Sec.  
60.5412a(a) through (c).
* * * * *
    (c) Closed vent system requirements for storage vessel and 
pneumatic pump affected facilities using a control device or routing 
emissions to a process.
    (1) You must design the closed vent system to route all gases, 
vapors, and fumes emitted from the material in the storage vessel or 
pneumatic pump to a control device or to a process. For storage 
vessels, the closed vent system must route all gases, vapors, and fumes 
to a control device that meets the requirements specified in Sec.  
60.5412a(c) and (d).
* * * * *
    (d) * * *
    (1) You must conduct an assessment that the closed vent system is 
of sufficient design and capacity to ensure that all emissions from the 
affected facility are routed to the control device and that the control 
device is of sufficient design and capacity to accommodate all 
emissions from the affected facility, and have it certified by an in-
house engineer or a qualified professional engineer in accordance with 
paragraphs (d)(1)(i) and (ii) of this section.
    (i) You must provide the following certification, signed and dated 
by an in-house engineer or a qualified professional engineer: ``I 
certify that the closed vent system design and capacity assessment was 
prepared under my direction or supervision. I further certify that the 
closed vent system design and capacity assessment was conducted and 
this report was prepared pursuant to the requirements of subpart OOOOa 
of 40 CFR part 60. Based on my professional knowledge and experience, 
and inquiry of personnel involved in the assessment, the certification 
submitted herein is true, accurate, and complete. I am aware that there 
are penalties for knowingly submitting false information.''
    (ii) The assessment shall be prepared under the direction or 
supervision of an in-house engineer or a qualified professional 
engineer who signs the certification in paragraph (d)(1)(i) of this 
section.
* * * * *
    (e) [Reserved]
0
13. Section 60.5412a is amended by
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(1)(iv);
0
c. Revising paragraph (c) introductory text;
0
d. Revising paragraph (d)(1)(iv) introductory text; and paragraph 
(d)(1)(iv)(D).
    The revisions read as follows:


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

* * * * *
    (a) * * *
    (1) Each combustion device (e.g., thermal vapor incinerator, 
catalytic vapor incinerator, boiler, or process heater) must be 
designed and operated in accordance with one of the performance 
requirements specified in paragraphs (a)(1)(i) through (iv) of this 
section. If a boiler or process heater is used as the control device, 
then you must introduce the vent stream into the flame zone of the 
boiler or process heater.
* * * * *
    (iv) You must introduce the vent stream with the primary fuel or 
use the vent stream as the primary fuel in a boiler or process heater.
* * * * *
    (c) For each carbon adsorption system used as a control device to 
meet the requirements of paragraph (a)(2) or (d)(2) of this section, 
you must manage the carbon in accordance with the requirements 
specified in paragraphs (c)(1) and (2) of this section.
* * * * *
    (d) * * *
    (1) * * *
    (iv) Each enclosed combustion control device (e.g., thermal vapor 
incinerator, catalytic vapor incinerator, boiler, or process heater) 
must be designed and operated in accordance with one of the performance 
requirements specified in paragraphs (A) through (D) of this section. 
If a boiler or process heater is used as the control device, then you 
must introduce the vent stream into the flame zone of the boiler or 
process heater.
* * * * *
    (D) You must introduce the vent stream with the primary fuel or use 
the vent stream as the primary fuel in a boiler or process heater.
* * * * *
0
14. Section 60.5413a is amended by revising paragraph (d)(5)(i) 
introductory text and paragraphs (d)(9)(iii) and (d)(12) introductory 
text to read as follows.


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

* * * * *
    (d) * * *
    (5) * * *
    (i) At the inlet gas sampling location, securely connect a fused 
silica-coated stainless steel evacuated canister fitted with a flow 
controller sufficient to fill the canister over a 3-hour period. 
Filling must be conducted as specified in paragraphs (d)(5)(i)(A) 
through (C) of this section.
* * * * *
    (9) * * *
    (iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane) 
measurement range is preferred; as an alternative a 0-30 ppmvw (as 
propane) measurement range may be used.
* * * * *
    (12) The owner or operator of a combustion control device model 
tested under this paragraph must submit the information listed in 
paragraphs (d)(12)(i) through (vi) of this section for each test run in 
the test report required by this section in accordance with Sec.  
60.5420a(b)(10). Owners or operators who claim that any of the 
performance test information being submitted is confidential business 
information (CBI) must submit a complete file including information 
claimed to be CBI, on a compact disc, flash drive, or other commonly 
used electronic storage media to the EPA. The electronic media must be 
clearly marked as CBI and mailed to Attn: CBI Document Control Officer; 
Office of Air Quality Planning and Standards (OAQPS) CBIO Room 521; 109 
T.W. Alexander Drive; RTP, NC 27711. The same file with the CBI omitted 
must be submitted to [email protected].
* * * * *
0
15. Section 60.5415a is amended by:
0
a. Revising paragraph (b) introductory text;
0
b. Revising paragraph (b)(3);
0
c. Removing and reserving paragraph (b)(4);
0
d. Revising paragraph (c)(1); and
0
e. Revising paragraph (h)(2).
    The revisions read as follows:

[[Page 52098]]

Sec.  60.5415a  How do I demonstrate continuous compliance with the 
standards for my well, centrifugal compressor, reciprocating 
compressor, pneumatic controller, pneumatic pump, storage vessel, 
collection of fugitive emissions components at a well site, and 
collection of fugitive emissions components at a compressor station 
affected facilities, and affected facilities at onshore natural gas 
processing plants?

* * * * *
    (b) For each centrifugal compressor affected facility and each 
pneumatic pump affected facility, you must demonstrate continuous 
compliance according to paragraph (b)(3) of this section. For each 
centrifugal compressor affected facility, you also must demonstrate 
continuous compliance according to paragraphs (b)(1) and (2) of this 
section.
* * * * *
    (3) You must submit the annual reports required by Sec.  
60.5420a(b)(1), (3), and (8) and maintain the records as specified in 
Sec.  60.5420a(c)(2), (6) through (11), (16), and (17), as applicable.
    (4) [Reserved]
    (c) * * *
    (1) You must continuously monitor the number of hours of operation 
for each reciprocating compressor affected facility or track the number 
of months since initial startup, since August 2, 2016, or since the 
date of the most recent reciprocating compressor rod packing 
replacement, whichever is later.
* * * * *
    (h) * * *
    (2) You must repair each identified source of fugitive emissions as 
required in Sec.  60.5397a(h).
* * * * *
0
16. Section 60.5416a is amended by:
0
a. Revising the introductory text;
0
b. Revising paragraph (a) introductory text;
0
c. Revising paragraph (a)(4) introductory text;
0
d. Revising paragraph (c) introductory text; and
0
e. Removing and reserving paragraph (d).
    The revisions read as follows:


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

    For each closed vent system or cover at your centrifugal 
compressor, reciprocating compressor, pneumatic pump, and storage 
vessel affected facilities, 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.
* * * * *
    (4) For each bypass device, except as provided for in Sec.  
60.5411a(a)(3)(ii), you must meet the requirements of paragraphs 
(a)(4)(i) or (ii) of this section.
* * * * *
    (c) Cover and closed vent system inspections for pneumatic pump or 
storage vessel affected facilities. If you install a control device or 
route emissions to a process, you must comply with the inspection and 
recordkeeping requirements for each closed vent system and cover as 
specified in paragraphs (c)(1) and (c)(2) of this section. You must 
also comply with the requirements of (c)(3) through (7) of this 
section.
* * * * *
    (d) [Reserved]
0
17. Section 60.5417a is amended by revising paragraph (a) to read as 
follows:


Sec.  60.5417a  What are the continuous control device monitoring 
requirements for my centrifugal compressor and storage vessel affected 
facilities?

* * * * *
    (a) For each control device used to comply with the emission 
reduction standard for centrifugal compressor affected facilities in 
Sec.  60.5380a(a)(1), you must install and operate a continuous 
parameter monitoring system for each control device as specified in 
paragraphs (c) through (g) of this section, except as provided for in 
paragraph (b) of this section. If you install and operate a flare in 
accordance with Sec.  60.5412a(a)(3), you are exempt from the 
requirements of paragraphs (e) and (f) of this section. If you install 
and operate an enclosed combustion device or control device which is 
not specifically listed in paragraph (d) of this section, you must 
demonstrate continuous compliance according to paragraphs (h)(1) 
through (h)(4) of this section.
* * * * *
0
18. Section 60.5420a is amended by:
0
a. Revising paragraph (a)(1);
0
b. Adding paragraph (a)(3);
0
c. Revising paragraph (b) introductory text;
0
d. Revising paragraph (b)(2);
0
e. Revising paragraph (b)(3) introductory paragraph;
0
f. Revising paragraphs (b)(3)(ii) through (iv);
0
g. Adding paragraph (b)(3)(v);
0
h. Revising paragraph (b)(4);
0
i. Revising paragraphs (b)(5)(i) through (iii);
0
j. Revising paragraph (b)(6) introductory text;
0
k. Revising paragraphs (b)(6)(iii) and (vii);
0
l. Adding paragraphs (b)(6)(viii) and (ix);
0
m. Revising paragraph (b)(7);
0
n. Revising paragraph (b)(8) introductory text;
0
o. Revising paragraph (b)(8)(iii);
0
p. Adding paragraph (b)(8)(iv);
0
q. Revising paragraph (b)(9)(i);
0
r. Revising paragraphs (b)(11) through (13);
0
s. Adding paragraph (b)(14);
0
t. Revising paragraph (c) introductory text;
0
u. Revising paragraph (c)(1) introductory text;
0
v. Revising paragraph (c)(1)(ii);
0
w. Revising paragraph (c)(1)(iii) introductory text;
0
x. Revising paragraphs (c)(1)(iii)(A) and (B);
0
y. Revising paragraph (c)(1)(iii)(C)(1);
0
z. Revising paragraphs (c)(1)(iv), (c)(1)(vi)(B), and (c)(1)(vii);
0
aa. Revising paragraph (c)(2) introductory text;
0
bb. Revising paragraphs (c)(2)(vi)(D) and (E);
0
cc. Revising paragraph (c)(2)(vii);
0
dd. Adding paragraph (c)(2)(viii);
0
ee. Revising paragraphs (c)(3)(i) and (iii);
0
ff. Revising paragraphs (c)(4)(i) and (v);
0
gg. Revising paragraph (c)(5) introductory text;
0
hh. Revising paragraphs (c)(5)(iii) and (v);
0
ii. Revising paragraph (c)(5)(vi) introductory text;
0
jj. Revising paragraphs (c)(5)(vi)(F)(4) and (c)(5)(vi)(G);
0
kk. Adding paragraphs (c)(5)(vi)(H) and (c)(5)(vii);
0
ll. Revising paragraphs (c)(6) through (9);
0
mm. Revising paragraph (c)(15);
0
nn. Revising paragraphs (c)(16)(ii) and (iv); and
0
oo. Adding paragraph (c)(18)
    The revisions and additions read as follows:


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

    (a) * * *

[[Page 52099]]

    (1) If you own or operate an affected facility that is the group of 
all equipment within a process unit at an onshore natural gas 
processing plant, or a sweetening unit at an onshore natural gas 
processing plant, you must submit the notifications required in Sec.  
60.7(a)(1), (3), and (4) and Sec.  60.15(d). If you own or operate a 
well, centrifugal compressor, reciprocating compressor, pneumatic 
controller, pneumatic pump, storage vessel, or collection of fugitive 
emissions components at a well site or collection of fugitive emissions 
components at a compressor station, you are not required to submit the 
notifications required in Sec.  60.7(a)(1), (3), and (4) and Sec.  
60.15(d).
* * * * *
    (3) An owner or operator electing to comply with the provisions of 
Sec.  60.5399a shall notify the Administrator of the alternative 
standard selected 90 days before implementing any of the provisions.
    (b) Reporting requirements. You must submit annual reports 
containing the information specified in paragraphs (b)(1) through (8) 
and (12) of this section and performance test reports as specified in 
paragraph (b)(9) or (10) of this section, if applicable. You must 
submit annual reports following the procedure specified in paragraph 
(b)(11) of this section. The initial annual report is due no later than 
90 days after the end of the initial compliance period as determined 
according to Sec.  60.5410a. Subsequent annual reports are due no later 
than same date each year as the initial annual report. If you own or 
operate more than one affected facility, you may submit one report for 
multiple affected facilities provided the report contains all of the 
information required as specified in paragraphs (b)(1) through (8) and 
(12) of this section. Annual reports may coincide with title V reports 
as long as all the required elements of the annual report are included. 
You may arrange with the Administrator a common schedule on which 
reports required by this part may be submitted as long as the schedule 
does not extend the reporting period.
* * * * *
    (2) For each well affected facility that is subject to Sec.  
60.5375a(a) or (f), the records of each well completion operation 
conducted during the reporting period, including the information 
specified in paragraphs (b)(2)(i) through (b)(2)(xiv) of this section, 
if applicable. In lieu of submitting the records specified in paragraph 
(b)(2)(i) through (b)(2)(xiv) of this section, the owner or operator 
may submit a list of each well completion with hydraulic fracturing 
completed during the reporting period, and the digital photograph 
required by paragraph (c)(1)(v) of this section for each well 
completion. For each well affected facility that routes flowback 
entirely through permanent separators, the records specified in 
paragraphs (b)(2)(i) through (b)(2)(iv) and (b)(2)(vi) through 
(b)(2)(xiv) of this section. For each well affected facility that is 
subject to Sec.  60.5375a(g), the record specified in paragraph 
(b)(2)(xv) of this section.
    (i) Well Completion ID.
    (ii) Latitude and longitude of the well in decimal degrees to an 
accuracy and precision of five (5) decimals of a degree using North 
American Datum of 1983.
    (iii) US Well ID.
    (iv) The date and time of the onset of flowback following hydraulic 
fracturing or refracturing.
    (v) The date and time of each attempt to direct flowback to a 
separator as required in Sec.  60.5375a(a)(1)(ii).
    (vi) The date and time that the well was shut in and the flowback 
equipment was permanently disconnected, or the startup of production.
    (vii) The duration (in hours) of flowback.
    (viii) The duration (in hours) of recovery and disposition of 
recovery (i.e., routed to the 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).
    (ix) The duration (in hours) of combustion.
    (x) The duration (in hours) of venting.
    (xi) The specific reasons for venting in lieu of capture or 
combustion.
    (xii) For any deviations recorded as specified in paragraph 
(c)(1)(ii) of this section, the date and time the deviation began, the 
duration of the deviation, and a description of the deviation.
    (xiii) For each well affected facility subject to Sec.  
60.5375a(f), a record of the well type (i.e., wildcat well, delineation 
well, or low pressure well (as defined Sec.  60.5430a)) and supporting 
inputs and calculations, if applicable.
    (xiv) For each well affected facility for which you claim an 
exception under Sec.  60.5375a(a)(3), the specific exception claimed 
and reasons why the well meets the claimed exception.
    (xv) For each well affected facility with less than 300 scf of gas 
per stock tank barrel of oil produced, the supporting analysis that was 
performed in order the make that claim, including but not limited to, 
GOR values for established leases and data from wells in the same basin 
and field.
    (3) For each centrifugal compressor affected facility, the 
information specified in paragraphs (b)(3)(i) through (v) of this 
section.
* * * * *
    (ii) For each deviation that occurred during the reporting period 
and recorded as specified in paragraph (c)(2) of this section, the date 
and time the deviation began, the duration of the deviation, and a 
description of the deviation.
    (iii) If required to comply with Sec.  60.5380a(a)(2), the 
information in paragraphs (b)(3)(iii)(A) through (C) of this section.
    (A) Dates of each inspection required under Sec.  60.5416a(a) and 
(b);
    (B) Each defect or leak identified during each inspection, how the 
defect or leak was repaired and date of repair or the date of 
anticipated repair if the repair is delayed; and
    (C) Date and time of each bypass alarm or each instance the key is 
checked out if you are subject to the bypass requirements of Sec.  
60.5416a(a)(4).
    (iv) If complying with Sec.  60.5380a(a)(1) with a control device 
tested under Sec.  60.5413a(d) which meets the criteria in Sec.  
60.5413a(d)(11) and Sec.  60.5413a(e), the information in paragraphs 
(b)(3)(iv)(A) through (D) of this section.
    (A) Identification of the compressor with the control device.
    (B) Make, model, and date of purchase of the control device.
    (C) For each instance where the inlet gas flow rate exceeds the 
manufacturer's listed maximum gas flow rate, where there is no 
indication of the presence of a pilot flame, or where visible emissions 
exceeded 1 minute in any 15-minute period, include the date and time 
the deviation began, the duration of the deviation, and a description 
of the deviation.
    (D) For each visible emissions test following return to operation 
from a maintenance or repair activity, the date of the visible 
emissions test, the length of the test, and the amount of time for 
which visible emissions were present.
    (v) If complying with Sec.  60.5380a(a)(1) with a control device 
not tested under Sec.  60.5413a(d), identification of the compressor 
with the tested control device, the date the performance test was 
conducted, and pollutant(s) tested. Submit the performance test report 
following the procedures specified in paragraph (b)(9) of this section.
    (4) For each reciprocating compressor affected facility, the 
information specified in paragraphs (b)(4)(i) through (iii) of this 
section.
    (i) The cumulative number of hours of operation or the number of 
months since initial startup, since August 2, 2016, or since the 
previous

[[Page 52100]]

reciprocating compressor rod packing replacement, whichever is later. 
Alternatively, a statement that emissions from the rod packing are 
being routed to a process through a closed vent system under negative 
pressure.
    (ii) If applicable, for each deviation that occurred during the 
reporting period and recorded as specified in paragraph (c)(3)(iii) of 
this section, the date and time the deviation began, duration of the 
deviation and a description of the deviation.
    (iii) If required to comply with Sec.  60.5385a(a)(3), the 
information in paragraphs (b)(4)(iii)(A) through (C) of this section.
    (A) Dates of each inspection required under Sec.  60.5416a(a) and 
(b);
    (B) Each defect or leak identified during each inspection, how the 
defect or leak was repaired and date of repair or date of anticipated 
repair if repair is delayed; and
    (C) Date and time of each bypass alarm or each instance the key is 
checked out if you are subject to the bypass requirements of Sec.  
60.5416a(a)(4).
    (5) * * *
    (i) An identification of each pneumatic controller constructed, 
modified or reconstructed during the reporting period, including the 
month and year of installation, reconstruction or modification and 
identification information that allows traceability to the records 
required in paragraph (c)(4)(iii) or (iv) of this section.
    (ii) If applicable, reason why the use of pneumatic controller 
affected facilities with a natural gas bleed rate greater than the 
applicable standard are required.
    (iii) For each instance where the pneumatic controller was not 
operated in compliance with the requirements specified in Sec.  
60.5390a, a description of the deviation, the date and time the 
deviation began, and the duration of the deviation.
    (6) For each storage vessel affected facility, the information in 
paragraphs (b)(6)(i) through (ix) of this section.
* * * * *
    (iii) For each deviation that occurred during the reporting period 
and recorded as specified in paragraph (c)(5)(iii) of this section, the 
date and time the deviation began, duration of the deviation and a 
description of the deviation.
* * * * *
    (vii) For each storage vessel constructed, modified, reconstructed 
or returned to service during the reporting period complying with Sec.  
60.5395a(a)(2) with a control device tested under Sec.  60.5413a(d) 
which meets the criteria in Sec.  60.5413a(d)(11) and Sec.  
60.5413a(e), the information in paragraphs (b)(6)(vii)(A) through (D) 
of this section.
    (A) Identification of the storage vessel with the control device.
    (B) Make, model, and date of purchase of the control device.
    (C) For each instance where the inlet gas flow rate exceeds the 
manufacturer's listed maximum gas flow rate, where there is no 
indication of the presence of a pilot flame, or where visible emissions 
exceeded 1 minute in any 15-minute period, include the date and time 
the deviation began, the duration of the deviation, and a description 
of the deviation.
    (D) For each visible emissions test following return to operation 
from a maintenance or repair activity, the date of the visible 
emissions test, the length of the test, and the amount of time for 
which visible emissions were present.
    (viii) If complying with Sec.  60.5395a(a)(2) with a control device 
not tested under Sec.  60.5413a(d), identification of the storage 
vessel with the tested control device, the date the performance test 
was conducted, and pollutant(s) tested. Submit the performance test 
report following the procedures specified in paragraph (b)(9) of this 
section.
    (ix) If required to comply with Sec.  60.5395a(b)(1), the 
information in paragraphs (b)(6)(ix)(A) through (C) of this section.
    (A) Dates of each inspection required under Sec.  60.5416a(c);
    (B) Each defect or leak identified during each inspection, how the 
defect or leak was repaired and date of repair or date of anticipated 
repair if repair is delayed; and
    (C) Date and time of each bypass alarm or each instance the key is 
checked out if you are subject to the bypass requirements of Sec.  
60.5416a(c)(3).
    (7) For the collection of fugitive emissions components at each 
well site and the collection of fugitive emissions components at each 
compressor station within the company-defined area, the information 
specified in paragraphs (b)(7)(i) and (ii) of this section.
    (i)(A) For each collection of fugitive emissions components at a 
well site that became an affected facility during the reporting period, 
you must include the date of the startup of production or the date of 
the first day of production after modification.
    (B) For each collection of fugitive emissions components at a 
compressor station that became an affected facility during the 
reporting period, you must include the date of startup or the date of 
modification.
    (C) For each collection of fugitive emissions components at a well 
site where during the reporting period you complete the removal of all 
major production and processing equipment such that the well site 
contains only one or more wellheads, you must include a statement that 
all major production and processing equipment has been removed from the 
well site, the date of the removal of the last piece of major 
production and processing equipment, and if the well site is still 
producing to another site, the well ID or separate tank battery ID 
receiving the production.
    (D) For each collection of fugitive emissions components at a well 
site where you previously reported under paragraph (b)(7)(i)(C) the 
removal of all major production and processing equipment and during the 
reporting period major production and processing equipment is added 
back to the well site, the date that the first piece of major 
production and processing equipment is added back to the well site.
    (E) For each new collection of fugitive emissions components at a 
well site where the average combined oil and natural gas production for 
the wells at the site is less than 15 boe per day, you must submit the 
combined oil and natural gas production in boe for the wells at the 
site, averaged over the first 30 days of production.
    (ii) For each fugitive emissions monitoring survey performed during 
the annual reporting period, the information specified in paragraphs 
(b)(7)(ii)(A) through (L) of this section.
    (A) Date of the survey.
    (B) Name or unique ID of operator(s) performing survey.
    (C) Ambient temperature, sky conditions, and maximum wind speed at 
the time of the survey.
    (D) Monitoring instrument used.
    (E) Any deviations from the monitoring plan elements under Sec.  
60.5397a(c)(1), (2), (7), and (8)(i) or a statement that there were no 
deviations from these elements of the monitoring plan.
    (F) Number and type of components for which fugitive emissions were 
detected.
    (G) Number and type of fugitive emissions components that were not 
repaired as required in Sec.  60.5397a(h).
    (H) Number and type of difficult-to-monitor and unsafe-to-monitor 
fugitive emission components monitored.
    (I) The date of successful repair of the fugitive emissions 
component.
    (J) Number and type of fugitive emission components currently on 
delay of repair and explanation for each delay of repair.

[[Page 52101]]

    (K) Type of instrument used to resurvey a repaired fugitive 
emissions component that could not be repaired during the initial 
fugitive emissions finding, if the type of instrument is different from 
the type used during the initial fugitive emissions finding.
    (L) Date of planned shutdown(s) that occurred during the reporting 
period if there are any components that have been placed on delay of 
repair.
    (8) For each pneumatic pump affected facility, the information 
specified in paragraphs (b)(8)(i) through (iv) of this section.
* * * * *
    (iii) For each deviation that occurred during the reporting period 
and recorded as specified in paragraph (c)(16)(ii) of this section, the 
date and time the deviation began, duration of the deviation and a 
description of the deviation.
    (iv) If required to comply with Sec.  60.5393a(b), the information 
in paragraphs (b)(8)(iv)(A) through (C) of this section.
    (A) Dates of each inspection required under Sec.  60.5416a(c);
    (B) Each defect or leak identified during each inspection, how the 
defect or leak was repaired and date of repair or date of anticipated 
repair if repair is delayed; and
    (C) Date and time of each bypass alarm or each instance the key is 
checked out if you are subject to the bypass requirements of Sec.  
60.5416a(c)(3).
    (9) * * *
    (i) For data collected using test methods supported by the EPA's 
Electronic Reporting Tool (ERT) as listed on the EPA's ERT website 
(https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of the test, you must submit the 
results of the performance test to the EPA via the Compliance and 
Emissions Data Reporting Interface (CEDRI). (CEDRI can be accessed 
through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/).) 
Performance test data must be submitted in a file format generated 
through the use of the EPA's ERT or an alternate electronic file format 
consistent with the extensible markup language (XML) schema listed on 
the EPA's ERT website. If you claim that some of the performance test 
information being submitted is confidential business information (CBI), 
you must submit a complete file generated through the use of the EPA's 
ERT or an alternate electronic file consistent with the XML schema 
listed on the EPA's ERT website, including information claimed to be 
CBI, on a compact disc, flash drive, or other commonly used electronic 
storage media to the EPA. The electronic media must be clearly marked 
as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group 
Leader, Measurement Policy Group, MD C404-02, 4930 Old Page Rd., 
Durham, NC 27703. The same ERT or alternate file with the CBI omitted 
must be submitted to the EPA via the EPA's CDX as described earlier in 
this paragraph.
* * * * *
    (11) You must submit reports to the EPA via the CEDRI. (CEDRI can 
be accessed through the EPA's CDX (https://cdx.epa.gov/).) You must use 
the appropriate electronic report in CEDRI for this subpart or an 
alternate electronic file format consistent with the extensible markup 
language (XML) schema listed on the CEDRI website (https://www3.epa.gov/ttn/chief/cedri/). If the reporting form specific to this 
subpart is not available in CEDRI at the time that the report is due, 
you must submit the report to the Administrator at the appropriate 
address listed in Sec.  60.4. Once the form has been available in CEDRI 
for at least 90 calendar days, you must begin submitting all subsequent 
reports via CEDRI. The reports must be submitted by the deadlines 
specified in this subpart, regardless of the method in which the 
reports are submitted. If you claim that some of the information 
required to be submitted via CEDRI is CBI, submit a complete report 
generated using the appropriate form in CEDRI or an alternate 
electronic file consistent with the XML schema listed on the EPA's 
CEDRI website, including information claimed to be CBI, on a compact 
disc, flash drive, or other commonly used electronic storage medium to 
the EPA. The electronic medium shall be clearly marked as CBI and 
mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, 
Measurement Policy Group, MD C404-02, 4930 Old Page Rd., Durham, NC 
27703. The same file with the CBI omitted shall be submitted to the EPA 
via CEDRI.
    (12) You must submit the certification signed by the in-house 
engineer or qualified professional engineer according to Sec.  
60.5411a(d) for each closed vent system routing to a control device or 
process.
    (13) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX, and due to a planned or actual outage of either 
the EPA's CEDRI or CDX systems within the period of time beginning 5 
business days prior to the date that the submission is due, you will be 
or are precluded from accessing CEDRI or CDX and submitting a required 
report within the time prescribed, you may assert a claim of EPA system 
outage for failure to timely comply with the reporting requirement. You 
must submit notification to the Administrator in writing as soon as 
possible following the date you first knew, or through due diligence 
should have known, that the event may cause or caused a delay in 
reporting. You must provide to the Administrator a written description 
identifying the date, time and length of the outage; a rationale for 
attributing the delay in reporting beyond the regulatory deadline to 
the EPA system outage; describe the measures taken or to be taken to 
minimize the delay in reporting; and identify a date by which you 
propose to report, or if you have already met the reporting requirement 
at the time of the notification, the date you reported. In any 
circumstance, the report must be submitted electronically as soon as 
possible after the outage is resolved. The decision to accept the claim 
of EPA system outage and allow an extension to the reporting deadline 
is solely within the discretion of the Administrator.
    (14) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX and a force majeure event is about to occur, 
occurs, or has occurred within the period of time beginning 5 business 
days prior to the date the submission is due, the owner or operator may 
assert a claim of force majeure for failure to timely comply with the 
reporting requirement. For the purposes of this section, a force 
majeure event is defined as an event that will be or has been caused by 
circumstances beyond the control of the affected facility, its 
contractors, or any entity controlled by the affected facility that 
prevents you from complying with the requirement to submit a report 
electronically within the time period prescribed. Examples of such 
events are acts of nature (e.g., hurricanes, earthquakes, or floods), 
acts of war or terrorism, or equipment failure or safety hazard beyond 
the control of the affected facility (e.g., large scale power outage). 
If you intend to assert a claim of force majeure, you must submit 
notification to the Administrator in writing as soon as possible 
following the date you first knew, or through due diligence should have 
known, that the event may cause or caused a delay in reporting. You 
must provide to the Administrator a written description of the force 
majeure event and a rationale for attributing the delay in reporting 
beyond the regulatory deadline to the

[[Page 52102]]

force majeure event; describe the measures taken or to be taken to 
minimize the delay in reporting; and identify a date by which you 
propose to report, or if you have already met the reporting requirement 
at the time of the notification, the date you reported. In any 
circumstance, the reporting must occur as soon as possible after the 
force majeure event occurs. The decision to accept the claim of force 
majeure and allow an extension to the reporting deadline is solely 
within the discretion of the Administrator.
    (c) Recordkeeping requirements. You must maintain the records 
identified as specified in Sec.  60.7(f) and in paragraphs (c)(1) 
through (18) of this section. All records required by this subpart must 
be maintained either onsite or at the nearest local field office for at 
least 5 years. Any records required to be maintained by this subpart 
that are submitted electronically via the EPA's CDX may be maintained 
in electronic format.
    (1) The records for each well affected facility as specified in 
paragraphs (c)(1)(i) through (vii) of this section, as applicable. For 
each well affected facility for which you make a claim that the well 
affected facility is not subject to the requirements for well 
completions pursuant to 60.5375a(g), you must maintain the record in 
paragraph (c)(1)(vi) of this section, only. For each well affected 
facility that routes flowback entirely through permanent separators the 
date and time of each attempt to direct flowback to a separator is not 
required.
* * * * *
    (ii) Records of deviations in cases where well completion 
operations with hydraulic fracturing were not performed in compliance 
with the requirements specified in Sec.  60.5375a, including the date 
and time the deviation began, the duration of the deviation, and a 
description of the deviation.
    (iii) You must maintain the records specified in paragraphs 
(c)(1)(iii)(A) through (C) of this section.
    (A) For each well affected facility required to comply with the 
requirements of Sec.  60.5375a(a), you must record: The latitude and 
longitude of the well in decimal degrees to an accuracy and precision 
of five (5) decimals of a degree using North American Datum of 1983; 
the United States 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.  60.5375a(a)(1)(ii); the date and time of each occurrence of 
returning to the initial flowback stage under Sec.  60.5375a(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 and disposition of 
recovery (i.e., routed to the 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); duration of combustion; duration of venting; and 
specific reasons for venting in lieu of capture or combustion. The 
duration must be specified in hours. In addition, for wells where it is 
technically infeasible to route the recovered gas as specified in Sec.  
60.5375a(a)(1)(ii), you must record the reasons for the claim of 
technical infeasibility with respect to all four options provided in 
that subparagraph.
    (B) For each well affected facility required to comply with the 
requirements of Sec.  60.5375a(f), you must record: Latitude and 
longitude of the well in decimal degrees to an accuracy and precision 
of five (5) decimals of a degree using North American Datum of 1983; 
the United States Well Number; the date and time of the onset of 
flowback following hydraulic fracturing or refracturing; 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 and disposition of recovery (i.e., 
routed to the 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); duration of combustion; duration of venting; and specific 
reasons for venting in lieu of capture or combustion. The duration must 
be specified in hours.
    (C) * * *
    (1) The latitude and longitude of the well in decimal degrees to an 
accuracy and precision of five (5) decimals of a degree using North 
American Datum of 1983; the United States Well Number; the date and 
time of the onset of flowback following hydraulic fracturing or 
refracturing; 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 and 
disposition of recovery (i.e., routed to the 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); duration of combustion; 
duration of venting; and specific reasons for venting in lieu of 
capture or combustion. The duration must be specified in hours.
* * * * *
    (iv) For each well affected facility for which you claim an 
exception under Sec.  60.5375a(a)(3), you must record: The latitude and 
longitude of the well in decimal degrees to an accuracy and precision 
of five (5) decimals of a degree using North American Datum of 1983; 
the United States Well Number; the specific exception claimed; the 
starting date and ending date for the period the well operated under 
the exception; and an explanation of why the well meets the claimed 
exception.
* * * * *
    (vi) * * *
    (B) The latitude and longitude of the well in decimal degrees to an 
accuracy and precision of five (5) decimals of a degree using North 
American Datum of 1983; the United States Well Number;
* * * * *
    (vii) For each well affected facility subject to Sec.  60.5375a(f), 
a record of the well type (i.e., wildcat well, delineation well, or low 
pressure well (as defined Sec.  60.5430a)) and supporting inputs and 
calculations, if applicable.
    (2) For each centrifugal compressor affected facility, you must 
maintain records of deviations in cases where the centrifugal 
compressor was not operated in compliance with the requirements 
specified in Sec.  60.5380a, including a description of each deviation, 
the date and time each deviation began and the duration of each 
deviation. Except as specified in paragraph (c)(2)(viii) of this 
section, you must maintain the records in paragraphs (c)(2)(i) through 
(vii) of this section for each control device tested under Sec.  
60.5413a(d) which meets the criteria in Sec.  60.5413a(d)(11) and Sec.  
60.5413a(e) and used to comply with Sec.  60.5380a(a)(1) for each 
centrifugal compressor.
* * * * *
    (vi) * * *
    (D) Records of the visible emissions test following return to 
operation from a maintenance or repair activity, including the date of 
the visible emissions test, the length of the test, and the amount of 
time for which visible emissions were present.
    (E) Records of the manufacturer's written operating instructions, 
procedures and maintenance schedule to ensure good air pollution 
control practices for minimizing emissions.
    (vii) Records of deviations for instances where the inlet gas flow 
rate exceeds the manufacturer's listed

[[Page 52103]]

maximum gas flow rate, where there is no indication of the presence of 
a pilot flame, or where visible emissions exceeded 1 minute in any 15-
minute period, including a description of the deviation, the date and 
time the deviation began, and the duration of the deviation.
    (viii) As an alternative to the requirements of paragraph 
(c)(2)(iv) of this section, you may maintain records of one or more 
digital photographs with the date the photograph was taken and the 
latitude and longitude of the centrifugal compressor and control device 
imbedded within or stored with the digital file. As an alternative to 
imbedded latitude and longitude within the digital photograph, the 
digital photograph may consist of a photograph of the centrifugal 
compressor and control device with a photograph of a separately 
operating GPS device within the same digital picture, provided the 
latitude and longitude output of the GPS unit can be clearly read in 
the digital photograph.
    (3) * * *
    (i) Records of the cumulative number of hours of operation or 
number of months since initial startup, since August 2, 2016, or since 
the previous replacement of the reciprocating compressor rod packing, 
whichever is later. Alternatively, a statement that emissions from the 
rod packing are being routed to a process through a closed vent system 
under negative pressure.
* * * * *
    (iii) Records of deviations in cases where the reciprocating 
compressor was not operated in compliance with the requirements 
specified in Sec.  60.5385a, including the date and time the deviation 
began, duration of the deviation and a description of the deviation.
    (4) * * *
    (i) Records of the month and year of installation, reconstruction 
or modification, location in latitude and longitude coordinates in 
decimal degrees to an accuracy and precision of five (5) decimals of a 
degree using the North American Datum of 1983, identification 
information that allows traceability to the records required in 
paragraph (c)(4)(iii) or (iv) of this section and manufacturer 
specifications for each pneumatic controller constructed, modified or 
reconstructed.
* * * * *
    (v) For each instance where the pneumatic controller was not 
operated in compliance with the requirements specified in Sec.  
60.5390a, a description of the deviation, the date and time the 
deviation began, and the duration of the deviation.
    (5) For each storage vessel affected facility, you must maintain 
the records identified in paragraphs (c)(5)(i) through (vii) of this 
section.
* * * * *
    (iii) For each instance where the storage vessel was not operated 
in compliance with the requirements specified in Sec. Sec.  60.5395a, 
60.5411a, 60.5412a, and 60.5413a, as applicable, a description of the 
deviation, the date and time each deviation began, and the duration of 
the deviation.
* * * * *
    (v) You must maintain records of the identification and location in 
latitude and longitude coordinates in decimal degrees to an accuracy 
and precision of five (5) decimals of a degree using the North American 
Datum of 1983 of each storage vessel affected facility.
    (vi) Except as specified in paragraph (c)(5)(vi)(G) of this 
section, you must maintain the records specified in paragraphs 
(c)(5)(vi)(A) through (H) of this section for each control device 
tested under Sec.  60.5413a(d) which meets the criteria in Sec.  
60.5413a(d)(11) and Sec.  60.5413a(e) and used to comply with Sec.  
60.5395a(a)(2) for each storage vessel.
* * * * *
    (F) * * *
    (4) Records of the visible emissions test following return to 
operation from a maintenance or repair activity, including the date of 
the visible emissions test, the length of the test, and the amount of 
time for which visible emissions were present.
* * * * *
    (G) Records of deviations for instances where the inlet gas flow 
rate exceeds the manufacturer's listed maximum gas flow rate, where 
there is no indication of the presence of a pilot flame, or where 
visible emissions exceeded 1 minute in any 15-minute period, including 
a description of the deviation, the date and time the deviation began, 
and the duration of the deviation.
    (H) As an alternative to the requirements of paragraph 
(c)(5)(vi)(D) of this section, you may maintain records of one or more 
digital photographs with the date the photograph was taken and the 
latitude and longitude of the storage vessel and control device 
imbedded within or stored with the digital file. As an alternative to 
imbedded latitude and longitude within the digital photograph, the 
digital photograph may consist of a photograph of the storage vessel 
and control device with a photograph of a separately operating GPS 
device within the same digital picture, provided the latitude and 
longitude output of the GPS unit can be clearly read in the digital 
photograph.
    (vii) Records of the date that each storage vessel affected 
facility is removed from service and returned to service, as 
applicable.
    (6) Records of each closed vent system inspection required under 
Sec.  60.5416a(a)(1) and (2) for centrifugal compressors and 
reciprocating compressors, or Sec.  60.5416a(c)(1) for storage vessels 
and pneumatic pumps as required in paragraphs (c)(6)(i) through (iii) 
of this section.
    (i) A record of each closed vent system inspection. You must 
include an identification number for each closed vent system (or other 
unique identification description selected by you) and the date of the 
inspection.
    (ii) For each defect detected during inspections required by Sec.  
60.5416a(a)(1) and (2) or Sec.  60.5416a(c)(1), you must record the 
location of the defect, a description of the defect, the date of 
detection, the corrective action taken the repair the defect, and the 
date the repair to correct the defect is completed.
    (iii) If repair of the defect is delayed as described in Sec.  
60.5416a(b)(10), you must record the reason for the delay and the date 
you expect to complete the repair.
    (7) A record of each cover inspection required under Sec.  
60.5416a(a)(3) for centrifugal or reciprocating compressors or Sec.  
60.5416a(c)(2) for storage vessels or pneumatic pumps as required in 
paragraphs (c)(7)(i) through (iii) of this section.
    (i) A record of each cover inspection. You must include an 
identification number for each cover (or other unique identification 
description selected by you) and the date of the inspection.
    (ii) For each defect detected during inspections required by Sec.  
60.5416a(a)(3) or Sec.  60.5416a(c)(2), you must record the location of 
the defect, a description of the defect, the date of detection, the 
corrective action taken the repair the defect, and the date the repair 
to correct the defect is completed.
    (iii) If repair of the defect is delayed as described in Sec.  
60.5416a(b)(10), you must record the reason for the delay and the date 
you expect to complete the repair.
    (8) If you are subject to the bypass requirements of Sec.  
60.5416a(a)(4) for centrifugal compressors or reciprocating 
compressors, or Sec.  60.5416a(c)(3) for storage vessels or pneumatic 
pumps, you must prepare and maintain a record of each inspection or a 
record of each time the key is checked out or a record of each time the 
alarm is sounded.

[[Page 52104]]

    (9) If you are subject to the closed vent system no detectable 
emissions requirements of Sec.  60.5416a(b) for centrifugal compressors 
or reciprocating compressors, you must prepare and maintain the records 
required in paragraphs (c)(9)(i) through (iii) of this section.
    (i) A record of each closed vent system no detectable emissions 
monitoring survey. You must include an identification number for each 
closed vent system (or other unique identification description selected 
by you) and the date of the monitoring survey.
    (ii) For each leak detected during inspections required by Sec.  
60.5416a(b), you must record the location of the leak, the maximum 
concentration reading obtained using Method 21, the date of detection, 
the corrective action taken the repair the leak, and the date the 
repair to correct the leak is completed.
    (iii) If repair of the leak is delayed as described in Sec.  
60.5416a(b)(10), you must record the reason for the delay and the date 
you expect to complete the repair.
* * * * *
    (15) For each collection of fugitive emissions components at a well 
site and each collection of fugitive emissions components at a 
compressor station, the records identified in paragraphs (c)(15)(i) 
through (vii) of this section.
    (i) The date of the startup of production or the date of the first 
day of production after modification for each collection of fugitive 
emissions components at a well site and the date of startup or the date 
of modification for each collection of fugitive emissions components 
compressor station.
    (ii) For each collection of fugitive emissions components at a well 
site where you complete the removal of all major production and 
processing equipment such that the well site contains only one or more 
wellheads, the date the well site completes the removal of all major 
production and processing equipment from the well site, and, if the 
well site is still producing, the well ID or separate tank battery ID 
receiving the production from the well site. If major production and 
processing equipment is subsequently added back to the well site, the 
date that the first piece of major production and processing equipment 
is added back to the well site.
    (iii) For each collection of fugitive emissions components at a 
well site that is monitored annually under (g)(1)(ii)(B), the records 
identified in paragraphs (c)(15)(iii)(A) and (B) of this section.
    (A) The average daily combined oil and natural gas production for 
the well site during the first 30 days of production; and
    (B) A description of the methodology used to calculate the daily 
average production for the well site.
    (iv) The fugitive emissions monitoring plan as required in Sec.  
60.5397a(b), (c), and (d).
    (v) The records of each monitoring survey as specified in 
paragraphs (c)(15)(v)(A) through (L) of this section.
    (A) Date of the survey.
    (B) Beginning and end time of the survey.
    (C) Name of operator(s) performing survey. If you choose to report 
the unique ID of the operator(s) performing the survey in lieu of the 
operator(s) name, you must keep a record linking the unique ID to the 
operator(s) name. You must note the training and experience of the 
operator(s).
    (D) Monitoring instrument used.
    (E) When optical gas imaging is used to perform the survey, one or 
more digital photographs or videos, captured from the optical gas 
imaging instrument used for monitoring, of each required monitoring 
survey being performed. The digital photograph must include the date 
the photograph was taken and the latitude and longitude of the 
collection of fugitive emissions components at a well site or 
collection of fugitive emissions components at a compressor station 
imbedded within or stored with the digital file. As an alternative to 
imbedded latitude and longitude within the digital file, the digital 
photograph or video may consist of an image of the monitoring survey 
being performed with a separately operating GPS device within the same 
digital picture or video, provided the latitude and longitude output of 
the GPS unit can be clearly read in the digital image. Digital 
photographs or video recorded under paragraph (c)(15)(v)(K)(1) of this 
section can be used to meet this requirement, as long as the photograph 
or video is taken with the optical gas imaging instrument, includes the 
date and the latitude and longitude are either imbedded or visible in 
the picture.
    (F) Fugitive emissions component identification when Method 21 of 
appendix A-7 of this part is used to perform the monitoring survey or 
when optical gas imaging is used to perform the monitoring survey and 
the owner or operator chooses to comply with Sec.  60.5397a(d)(2) in 
lieu of Sec.  60.5397a (d)(1).
    (G) Ambient temperature, sky conditions, and maximum wind speed at 
the time of the survey.
    (H) Any deviations from the monitoring plan or a statement that 
there were no deviations from the monitoring plan.
    (I) Documentation of each fugitive emission, including the 
information specified in paragraphs (c)(15)(v)(I)(1) through (3) of 
this section.
    (1) Location.
    (2) Component ID and type of fugitive emissions component.
    (3) Instrument reading of each fugitive emissions component that 
requires repair when Method 21 is used for monitoring.
    (J) Number and type of fugitive emissions components that were not 
repaired as required in Sec.  60.5397a(h).
    (K) For each component that cannot be repaired during the 
monitoring survey when the fugitive emissions were initially found:
    (1) Number and type of components that were tagged or a digital 
photograph or video of each fugitive emissions component. The digital 
photograph or video must clearly identify the location of the component 
that must be repaired. Any digital photograph or video required under 
this paragraph can also be used to meet the requirements under 
paragraph (c)(15)(ii)(E) of this section, as long as the photograph or 
video is taken with the optical gas imaging instrument, includes the 
date and the latitude and longitude are either imbedded or visible in 
the picture.
    (2) The date and repair methods applied in each attempt to repair 
the fugitive emissions components.
    (3) The date of successful repair of the fugitive emissions 
component.
    (4) The date of each resurvey and instrumentation used to resurvey 
a repaired fugitive emissions component that could not be repaired 
during the initial fugitive emissions finding.
    (5) Identification of each fugitive emission component placed on 
delay of repair and explanation for each delay of repair.
    (L) Records of calibrations for the instrument used during the 
monitoring survey.
    (vi) Date of planned shutdowns that occur while there are any 
components that have been placed on delay of repair.
    (16) * * *
    (ii) Records of deviations in cases where the pneumatic pump was 
not operated in compliance with the requirements specified in Sec.  
60.5393a, including the date and time the deviation began, duration of 
the deviation and a description of the deviation.
* * * * *
    (iv) Records substantiating a claim according to Sec.  
60.5393a(b)(5) that it is technically infeasible to capture and

[[Page 52105]]

route emissions from a pneumatic pump to a control device or process; 
including the certification according to Sec.  60.5393a(b)(5)(ii) and 
the records of the engineering assessment of technical infeasibility 
performed according to Sec.  60.5393a(b)(5)(iii).
* * * * *
    (18) A copy of each performance test submitted under paragraph 
(b)(9) of this section.
0
19. Section 60.5422a is amended by revising paragraphs (a) and (b), and 
paragraph (c) introductory text to read as follows:


Sec.  60.5422a  What are my additional reporting requirements for my 
affected facility subject to GHG and VOC requirements for onshore 
natural gas processing plants?

    (a) You must comply with the requirements of paragraphs (b) and (c) 
of this section in addition to the requirements of Sec.  60.487a(a), 
(b)(1) through (3), (b)(5), (c)(2)(i) through (iv), and (c)(2)(vii) 
through (viii). You must submit semiannual reports to the EPA via the 
Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can 
be accessed through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/).) Use the appropriate electronic report in CEDRI for this 
subpart or an alternate electronic file format consistent with the 
extensible markup language (XML) schema listed on the CEDRI website 
(https://www3.epa.gov/ttn/chief/cedri/). If the reporting form specific 
to this subpart is not available in CEDRI at the time that the report 
is due, submit the report to the Administrator at the appropriate 
address listed in Sec.  60.4. Once the form has been available in CEDRI 
for at least 90 days, you must begin submitting all subsequent reports 
via CEDRI. The report must be submitted by the deadline specified in 
this subpart, regardless of the method in which the report is 
submitted.
    (b) An owner or operator must include the following information in 
the initial semiannual report in addition to the information required 
in Sec.  60.487a(b)(1) through (3) and (b)(5): Number of pressure 
relief devices subject to the requirements of Sec.  60.5401a(b) except 
for those pressure relief devices designated for no detectable 
emissions under the provisions of Sec.  60.482-4a(a) and those pressure 
relief devices complying with Sec.  60.482-4a(c).
    (c) An owner or operator must include the information specified in 
paragraphs (c)(1) and (2) of this section in all semiannual reports in 
addition to the information required in Sec.  60.487a(c)(2)(i) through 
(iv) and (c)(2)(vii) through (viii):
* * * * *
0
20. Section 60.5423a is amended by revising paragraph (b) introductory 
text and adding paragraph (b)(3) to read as follows:


Sec.  60.5423a  What additional recordkeeping and reporting 
requirements apply to my sweetening unit affected facilities at onshore 
natural gas processing plants?

* * * * *
    (b) You must submit a report of excess emissions to the 
Administrator in your annual report if you had excess emissions during 
the reporting period. The procedures for submitting annual reports are 
located in Sec.  60.5420a(b). For the purpose of these reports, excess 
emissions are defined as specified in paragraphs (b)(1) and (2) of this 
section. The report must contain the information specified in paragraph 
(b)(3) of this section.
* * * * *
    (3) For each period of excess emissions during the reporting 
period, include the following information in your report:
    (i) The date and time of commencement and completion of each period 
of excess emissions;
    (ii) The required minimum efficiency (Z) and the actual average 
sulfur emissions reduction (R) for periods defined in paragraph (b)(1) 
of this section; and
    (iii) The appropriate operating temperature and the actual average 
temperature of the gases leaving the combustion zone for periods 
defined in paragraph (b)(2) of this section.
* * * * *
0
21. Section 60.5430a is amended by:
0
a. Revising the definitions for ``capital expenditure'', ``certifying 
official'', ``flowback'', ``fugitive emissions component'', ``low 
pressure well'', ``maximum average daily throughput'', ``startup of 
production'', and ``well site'';
0
b. Adding in alphabetical order the definitions for ``coil tubing 
cleanout'', ``custody meter'', ``custody meter assembly'', ``first 
attempt at repair'', ``major production and processing equipment'', 
``permanent separator'', ``plug drill-out'', ``repaired'', 
``screenout'', ``UIC Class II oilfield disposal well'', and ``wellhead 
only well site''; and
0
c. Removing the definition for ``greenfield site''.
    The revisions and additions read as follows:


Sec.  60.5430a  What definitions apply to this subpart?

* * * * *
    Capital expenditure means, in addition to the definition in 40 CFR 
60.2, an expenditure for a physical or operational change to an 
existing facility that:
    (1) Exceeds P, the product of the facility's replacement cost, R, 
and an adjusted annual asset guideline repair allowance, A, as 
reflected by the following equation: P = R x A, where:
    (i) The adjusted annual asset guideline repair allowance, A, is the 
product of the percent of the replacement cost, Y, and the applicable 
basic annual asset guideline repair allowance, B, divided by 100 as 
reflected by the following equation: A = Y x (B / 100);
    (ii) The percent Y is determined from the following equations: Y = 
1.0 - 0.575 log X, where X is 2015 minus the year of construction, and 
Y = 1.0 when the year of construction is 2015; and
    (iii) The applicable basic annual asset guideline repair allowance, 
B, is 4.5.
* * * * *
    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 with an affected facility subject to this subpart 
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

[[Page 52106]]

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.
    Coil tubing cleanout means the process where an operator runs a 
string of coil tubing to the packed proppant within a well and jets the 
well to dislodge the proppant and provide sufficient lift energy to 
flow it to the surface.
* * * * *
    Custody meter means the meter where natural gas or hydrocarbon 
liquids are measured for sales, transfers, and/or royalty 
determination.
    Custody meter assembly means an assembly of fugitive emissions 
components, including the custody meter, valves, flanges, and 
connectors necessary for the proper operation of the custody meter.
* * * * *
    First attempt at repair means, for the purposes of fugitive 
emissions components, an action taken for the purpose of stopping or 
reducing fugitive emissions of methane or VOC to the atmosphere. First 
attempts at repair include, but are not limited to, the following 
practices where practicable and appropriate: Tightening bonnet bolts; 
replacing bonnet bolts; tightening packing gland nuts; or injecting 
lubricant into lubricated packing.
* * * * *
    Flowback means the process of allowing fluids and entrained solids 
to flow from a 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 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 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. 
Screenouts, coil tubing cleanouts, and plug drill-outs are not 
considered part of the flowback process.
    Fugitive emissions component means any component that has the 
potential to emit fugitive emissions of methane or VOC at a well site 
or compressor station, including valves, connectors, pressure relief 
devices, open-ended lines, flanges, covers and closed vent systems not 
subject to Sec. Sec.  60.5411 or 60.5411a, thief hatches or other 
openings on a controlled storage vessel not subject to Sec. Sec.  
60.5395 or 60.5395a, compressors, instruments, and meters. Devices that 
vent as part of normal operations, such as natural gas-driven pneumatic 
controllers or natural gas-driven pumps, are not fugitive emissions 
components, insofar as the natural gas discharged from the device's 
vent is not considered a fugitive emission. Emissions originating from 
other than the device's vent, such as the thief hatch on a controlled 
storage vessel, would be considered fugitive emissions.
* * * * *
    Low pressure well means a well that satisfies at least one of the 
following conditions:
    (1) The static pressure at the wellhead following fracturing but 
prior to the onset of flowback is less than the flow line pressure;
    (2) The pressure of flowback fluid immediately before it enters the 
flow line, as determined under Sec.  60.5432a, is less than the flow 
line pressure; or
    (3) Flowback of the fracture fluids will not occur without the use 
of artificial lift equipment.
    Major production and processing equipment means compressors, glycol 
dehydrators, heater/treaters, pneumatic pumps, pneumatic controllers, 
separators, and storage vessels collecting crude oil, condensate, 
intermediate hydrocarbon liquids, or produced water, for the purpose of 
determining whether a well site is a wellhead only well site.
    Maximum average daily throughput means the throughput, determined 
as described in (1) or (2), to an individual storage vessel over the 
days that production is routed to that storage vessel during the 30-day 
evaluation period specified in Sec.  60.5365a(e)(1).
    (1) If throughput to the individual storage vessel is measured on a 
daily basis (e.g., via level gauge automation or daily manual gauging), 
the maximum average daily throughput is the average of all daily 
throughputs for days on which throughput was routed to that storage 
vessel during the 30-day evaluation period; or
    (2) If throughput to the individual storage vessel is not measured 
on a daily basis (e.g., via manual gauging at the start and end of 
loadouts), the maximum average daily throughput is the highest, of the 
average daily throughputs, determined for any production period to that 
storage vessel during the 30-day evaluation period, as determined by 
averaging total throughput to that storage vessel over each production 
period. A production period begins when production begins to be routed 
to a storage vessel and ends either when throughput is routed away from 
that storage vessel or when a loadout occurs from that storage vessel, 
whichever happens first.
    Regardless of the determination methodology, operators must not 
include days during which throughput is not routed to an individual 
storage vessel when calculating maximum average daily throughput for 
that storage vessel.
* * * * *
    Permanent separator means a separator that handles flowback from a 
well or wells beginning when the flowback period begins and continuing 
to the startup of production.
    Plug drill-out means the removal of a plug (or plugs) that was used 
to conducted hydraulic fracturing in different sections of the well.
* * * * *
    Repaired means, for the purposes of fugitive emissions components, 
that fugitive emissions components are adjusted, replaced, or otherwise 
altered, in order to eliminate fugitive emissions as defined in Sec.  
60.5397a of this subpart and is resurveyed as specified in Sec.  
60.5397a(h)(4) and it is verified that emissions from the fugitive 
emissions components are below the applicable fugitive emissions 
definition.
* * * * *
    Screenout means the first attempt to clear proppant from the 
wellbore through flowing the well to a fracture tank in order to 
achieve maximum velocity and carry the proppant out of the well.
* * * * *
    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, except as otherwise provided herein. For the purposes 
of the fugitive monitoring requirements of Sec.  60.5397a, startup of 
production means the beginning of the continuous recovery of salable 
quality gas and separation and recovery of any crude oil, condensate or 
produced water.
* * * * *
    UIC Class II oilfield disposal well means a well with a UIC Class 
II permit

[[Page 52107]]

where wastewater resulting from oil and natural gas production 
operations is injected into underground porous rock formations not 
productive of oil or gas, and sealed above and below by unbroken, 
impermeable strata.
* * * * *
    Well site means one or more surface sites that are constructed for 
the drilling and subsequent operation of any oil well, natural gas 
well, or injection well. For purposes of the fugitive emissions 
standards at Sec.  60.5397a, well site also means a separate tank 
battery surface site collecting crude oil, condensate, intermediate 
hydrocarbon liquids, or produced water from wells not located at the 
well site (e.g., centralized tank batteries). Also, for the purposes of 
the fugitive emissions standards at Sec.  60.5397a, a well site does 
not include (1) UIC Class II oilfield disposal wells and disposal 
facilities and (2) the flange upstream of the custody meter assembly 
and equipment, including fugitive emissions components, located 
downstream of this flange.
* * * * *
    Wellhead only well site means, for the purposes of the fugitive 
emissions standards at Sec.  60.5397a, a well site that contains one or 
more wellheads and no major production and processing equipment.
* * * * *
0
22. Table 3 to Subpart OOOOa of Part 60 is amended to revise the 
explanations for sections 60.8 and 60.15 general provisions citation 
entries to read as follows:

            Table 3 to Subpart OOOOa of Part 60--Applicability of General Provisions to Subpart OOOOa
----------------------------------------------------------------------------------------------------------------
   General provisions citation      Subject of citation  Applies to subpart?              Explanation
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
Sec.   60.8......................  Performance tests...  Yes................  Performance testing is required
                                                                               for control devices used on
                                                                               storage vessels, centrifugal
                                                                               compressors, and pneumatic pumps,
                                                                               except that performance testing
                                                                               is not required for a control
                                                                               device used solely on pneumatic
                                                                               pump(s).
 
                                                  * * * * * * *
Sec.   60.15.....................  Reconstruction......  Yes................  Except that Sec.   60.15(d) does
                                                                               not apply to wells, pneumatic
                                                                               controllers, pneumatic pumps,
                                                                               centrifugal compressors,
                                                                               reciprocating compressors,
                                                                               storage vessels, or the
                                                                               collection of fugitive emissions
                                                                               components at a well site or the
                                                                               collection of fugitive emissions
                                                                               components at a compressor
                                                                               station.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2018-20961 Filed 10-12-18; 8:45 am]
 BILLING CODE 6560-50-P


