Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources Reconsideration, 52056-52107 [2018-20961]
Download as PDF
<![CDATA[
52056
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:
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
khammond on DSK30JT082PROD with PROPOSAL10
SUMMARY:
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
is our preferred method of receiving
comments. However, other submission
methods are accepted:
• Email: a-and-r-docket@epa.gov.
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:
marsh.karen@epa.gov. 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: mia.marcia@epa.gov.
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
PO 00000
Frm 00002
Fmt 4701
Sfmt 4702
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
E:\FR\FM\15OCP2.SGM
15OCP2
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
khammond on DSK30JT082PROD with PROPOSAL10
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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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
PO 00000
Frm 00003
Fmt 4701
Sfmt 4702
52057
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.
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
1 Docket
ID No. EPA–HQ–OAR–2010–0505.
of the petitions are provided in Docket
ID No. EPA–HQ–OAR–2017–0483.
2 Copies
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52058
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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.
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
3 83
FR 10628.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 ongoing 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.
PO 00000
Frm 00004
Fmt 4701
Sfmt 4702
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
E:\FR\FM\15OCP2.SGM
15OCP2
52059
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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
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$]
7%
Present
value
Benefits (Total Cost Savings) ..........................................................................
Cost Savings ............................................................................................
Forgone Value of Product Recovery ........................................................
Costs (Forgone Domestic Climate Benefits) 1 .................................................
Net Benefits 2 ...................................................................................................
3%
Equivalent
annualized
value
$380
429
48
13.5
367
Present
value
$66
74
8.4
2.3
64
Emissions .........................................................................................................
$484
546
62
54
431
Equivalent
annualized
value
$75
85
9.6
8.3
67
Total Change
Methane (short tons) ................................................................................
VOC ..........................................................................................................
HAP ..........................................................................................................
Methane (million metric tons CO2E) ........................................................
380,000
100,000
3,800
8.5
khammond on DSK30JT082PROD with PROPOSAL10
1 The forgone benefits estimates are calculated using estimates of the social cost of methane (SC–CH ). SC–CH values represent only a par4
4
tial 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
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.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
PO 00000
Frm 00005
Fmt 4701
Sfmt 4702
E:\FR\FM\15OCP2.SGM
15OCP2
52060
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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 coproposed 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
Category
NAICS code 1
Industry .......................................................................................
211120
211130
221210
486110
486210
........................
........................
Federal government ....................................................................
State/local/tribal government ......................................................
1 North
Crude Petroleum Extraction.
Natural Gas Extraction.
Natural Gas Distribution.
Pipeline Distribution of Crude Oil.
Pipeline Transportation of Natural Gas.
Not affected.
Not affected.
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).
khammond on DSK30JT082PROD with PROPOSAL10
Examples of regulated entities
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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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-pollutionoil-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
PO 00000
Frm 00006
Fmt 4701
Sfmt 4702
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.
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
5 See Docket ID No. EPA–HQ–OAR–2010–0505–
7730.
6 82 FR 25730.
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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).
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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
PO 00000
Frm 00007
Fmt 4701
Sfmt 4702
52061
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
E:\FR\FM\15OCP2.SGM
15OCP2
52062
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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
khammond on DSK30JT082PROD with PROPOSAL10
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 (‘‘nonlow 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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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.
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
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.
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.
PO 00000
Frm 00008
Fmt 4701
Sfmt 4702
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.
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
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.
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
regards to controlled storage vessel
fugitive emissions.
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, helicopterbased 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.
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
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.
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.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
PO 00000
Frm 00009
Fmt 4701
Sfmt 4702
52063
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.
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
19 See TSD for additional information related to
OGI control effectiveness.
20 See ‘‘Methane Emissions from Natural Gas
Transmission and Storage Facilities: Review of
E:\FR\FM\15OCP2.SGM
Continued
15OCP2
52064
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
khammond on DSK30JT082PROD with PROPOSAL10
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.
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
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.
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.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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.
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
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.
27 U.S. Environmental Protection Agency,
Protocol for Equipment Leak Emission Estimates.
Appendix G. November 1995 (EPA–453/R–95–017).
PO 00000
Frm 00010
Fmt 4701
Sfmt 4702
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.
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
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.
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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.
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.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 costeffectiveness 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
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.
PO 00000
Frm 00011
Fmt 4701
Sfmt 4702
52065
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.
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 nonlow production well sites from
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).
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52066
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
semiannual monitoring to annual
monitoring.
We are soliciting comment on the
proposed annual monitoring for nonlow 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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 costeffectiveness of monitoring a wellhead
only well site and find it not to be costeffective. 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.
As explained above, we are proposing
that monitoring is no longer required
when all major production and
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 costeffective. Therefore, at more frequent monitoring
would also not be cost-effective because there are
higher costs compared to annual monitoring.
PO 00000
Frm 00012
Fmt 4701
Sfmt 4702
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
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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
39 See
Docket ID No. EPA–HQ–OAR–2010–0505–
7730.
40 See Docket ID No. EPA–HQ–OAR–2010–0505–
7685.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
change in component counts. The
petitioner then stated that:
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
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
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 ‘‘super41 See Docket ID No. EPA–HQ–OAR–2010–0505–
7685, p. 5.
42 See Docket ID No. EPA–HQ–OAR–2010–0505–
7682.
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.
PO 00000
Frm 00013
Fmt 4701
Sfmt 4702
52067
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.
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
46 See Docket ID No. EPA–HQ–OAR–2010–0505–
7685.
47 ‘‘The Natural Gas Air Quality Study (Final
Report),’’ prepared by Eastern Research Group, Inc.
E:\FR\FM\15OCP2.SGM
Continued
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52068
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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 nonlow production well sites in the study.
When fugitive emissions were
considered from non-tank and noncontroller 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
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
July 13, 2011, available at https://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.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 nonlow 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 costeffectiveness 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 nonlow 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 nonlow 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
PO 00000
Frm 00014
Fmt 4701
Sfmt 4702
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
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.
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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.
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
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.)
Similar to the information received
about fugitive monitoring at well sites,
the EPA received information from two
stakeholders regarding fugitive
emissions monitoring at compressor
50 See Docket ID Nos. EPA–HQ–OAR–2010–
0505–7682 and EPA–HQ–OAR–2010–0505–7685.
51 See the TSD for full comparison of cost.
52 See Docket ID Nos. EPA–HQ–OAR–2010–
0505–7682, EPA–HQ–OAR–2010–0505–7685 and
EPA–HQ–OAR–2010–0505–7686.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
PO 00000
Frm 00015
Fmt 4701
Sfmt 4702
52069
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.
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
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.
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.
E:\FR\FM\15OCP2.SGM
15OCP2
52070
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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.
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
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.
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 costeffectiveness 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.
TABLE 3—NATIONWIDE EMISSIONS REDUCTION AND COST IMPACTS OF CONTROL FOR FUGITIVE EMISSIONS COMPONENTS
LOCATED AT COMPRESSOR STATIONS
[Year 2015]
Frequency
khammond on DSK30JT082PROD with PROPOSAL10
Annual ...............
Semiannual .......
Quarterly ............
Capital cost
(million $)
Annualized
costs without
recovery
credits
(million $/yr)
0.42
0.42
0.42
2.05
3.6
6.7
57 Canadian Association of Petroleum Producers,
‘‘Best Management Practice. Management of
Fugitive Emissions at Upstream Oil and Gas
Facilities,’’ January 2007.
58 U.S. Environmental Protection Agency, ‘‘Leak
Detection and Repair: A Best Practices Guide,’’
EPA–305–D–07–001, October 2007.
59 Canadian Association of Petroleum Producers,
‘‘Best Management Practice. Management of
Fugitive Emissions at Upstream Oil and Gas
Facilities,’’ January 2007.
VerDate Sep<11>2014
19:11 Oct 12, 2018
Emissions
reduction,
methane
(tpy)
Jkt 247001
3,680
5,510
7,350
Total costeffectiveness
without
recovery credit
($/ton methane)
Emissions
reduction,
VOC
(tpy)
850
1,270
1,700
550
650
910
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.
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
PO 00000
Frm 00016
Fmt 4701
Sfmt 4702
Total costeffectiveness
without
recovery credit
($/ton VOC)
2,410
2,830
3,950
Incremental
cost-effectiveness
without
recovery credit
($/ton methane)
Incremental
cost-effectiveness without
recovery credit
($/ton VOC)
................................
840
1,690
........................
3,650
7,300
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).
E:\FR\FM\15OCP2.SGM
15OCP2
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
khammond on DSK30JT082PROD with PROPOSAL10
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
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.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 coproposing 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.
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
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.
65 83 FR 10628.
66 Startup of production is defined in 40 CFR
60.5430a.
PO 00000
Frm 00017
Fmt 4701
Sfmt 4702
52071
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.
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 °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 °F. 70 One
commenter provided data, and the EPA
confirmed with its own analysis, that
temperatures below 0°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
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 https://
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.
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52072
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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 °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.
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 60day 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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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.
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
72 See Docket ID No. EPA–HQ–OAR–2010–0505–
7682.
73 ‘‘Equipment Leaks of VOC in Natural Gas
Production Industry—Background Information for
Promulgated Standards,’’ EPA–450/3–82–024b, May
1985.
PO 00000
Frm 00018
Fmt 4701
Sfmt 4702
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.
2. Modification
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
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.
E:\FR\FM\15OCP2.SGM
15OCP2
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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:
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
khammond on DSK30JT082PROD with PROPOSAL10
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,
[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
75 See Docket ID No. EPA–HQ–OAR–2010–0505–
7730.
76 See Docket ID No. EPA–HQ–OAR–2010–0505–
7685.
77 See Docket ID No. EPA–HQ–OAR–2010–0505–
7685, page 6.
78 See Docket ID Nos. EPA–HQ–OAR–2010–
0505–7682, EPA–HQ–OAR–2010–0505–7685 and
EPA–HQ–OAR–2010–0505–7686.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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
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 reevaluated 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 crosssectional 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
79 Docket ID No. EPA–HQ–OAR–2010–0505–
7682, p. 16.
PO 00000
Frm 00019
Fmt 4701
Sfmt 4702
52073
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 otherwiseaccomplished 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
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52074
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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 § 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 offsite 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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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
PO 00000
Frm 00020
Fmt 4701
Sfmt 4702
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
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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 oneyear 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.
Between proposal and promulgation
of the 2016 NSPS OOOOa, several
industry comments recommended a 90day 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
80 See Docket ID Nos. EPA–HQ–OAR–2010–
0505–7682 and EPA–HQ–OAR–2010–0505–10791.
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.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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.
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° 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.
83 See Docket ID EPA–HQ–OAR–2010–0505–
6884.
PO 00000
Frm 00021
Fmt 4701
Sfmt 4702
52075
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° 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°. 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
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52076
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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
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.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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.
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.
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’
86 See
87 See
PO 00000
40 CFR 60.5397a(h)(2).
40 CFR 60.5420a(b)(7)(ii)(J).
Frm 00022
Fmt 4701
Sfmt 4702
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 § 60.5411a, thief hatches or
other openings on a controlled storage
vessel not subject to § 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 thirdparty.88
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
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
88 See Docket ID Nos. EPA–HQ–OAR–2010–
0505–7682 and EPA–HQ–OAR–2010–0505–7684.
89 See Docket ID No. EPA–HQ–OAR–2010–0505–
7684.
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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.
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.
90 See Docket ID No. EPA–HQ–OAR–2010–0505–
13436.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 https://www.tech-flo.net/salt-waterdisposal.html.
92 Barnett Shale Energy Education Council. What
are Saltwater Disposal Wells? Air and Water
Quality. https://www.bseec.org/what_are_saltwater_
disposal_wells.
PO 00000
Frm 00023
Fmt 4701
Sfmt 4702
52077
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 § 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 § 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
E:\FR\FM\15OCP2.SGM
15OCP2
52078
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
assembly and equipment, including fugitive
emissions components, located downstream
of this flange.
khammond on DSK30JT082PROD with PROPOSAL10
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.
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
93 See
40 CFR 60.5397a(d)(1) and (2).
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 timeconsuming 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.
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
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.
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.
PO 00000
Frm 00024
Fmt 4701
Sfmt 4702
these two items serve the same function,
i.e., to provide information on the
locations of equipment on site.
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.
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
97 See Docket ID No. EPA–HQ–OAR–2010–0505–
7632, Chapter 4, page 4–708.
E:\FR\FM\15OCP2.SGM
15OCP2
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
khammond on DSK30JT082PROD with PROPOSAL10
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.
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
98 See Docket ID Nos. EPA–HQ–OAR–2010–
0505–7682, EPA–HQ–OAR–2010–0505–7685 and
EPA–HQ–OAR–2010–0505–7686.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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
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
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.
102 See the TSD for additional discussion of
certification cost.
PO 00000
Frm 00025
Fmt 4701
Sfmt 4702
52079
is soliciting comment on this cost
estimate.
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 ongoing compliance monitoring. The
specific requirements for this request
are outlined in 40 CFR 60.5398a. For the
2016 NSPS OOOOa, these alternatives
E:\FR\FM\15OCP2.SGM
15OCP2
52080
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
khammond on DSK30JT082PROD with PROPOSAL10
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 sitespecific 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 sitespecific 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,
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
allowable emissions, or landscape).
Therefore, we expect that applications
for these AMEL will include sitespecific 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
103 See Docket ID Nos. EPA–HQ–OAR–2010–
0505–7682, EPA–HQ–OAR–2010–0505–7685 and
EPA–HQ–OAR–2010–0505–7686.
PO 00000
Frm 00026
Fmt 4701
Sfmt 4702
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.
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
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.
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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.
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
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.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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.
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
PO 00000
Frm 00027
Fmt 4701
Sfmt 4702
52081
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.
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
107 See Docket ID Nos. EPA–HQ–OAR–2010–
0505–7682 and EPA–HQ–OAR–2010–0505–7686.
108 See Docket ID No. EPA–HQ–OAR–2010–
0505–7682.
109 See Docket ID No. EPA–HQ–OAR–2010–
0505–7722.
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52082
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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.
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 drillouts 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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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
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.
PO 00000
Frm 00028
Fmt 4701
Sfmt 4702
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.
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
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.
E:\FR\FM\15OCP2.SGM
15OCP2
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
khammond on DSK30JT082PROD with PROPOSAL10
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’’.
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
113 See Docket ID Nos. EPA–HQ–OAR–2010–
0505–7682, EPA–HQ–OAR–2010–0505–7685 and
EPA–HQ–OAR–2010–0505–7686.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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.
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
PO 00000
Frm 00029
Fmt 4701
Sfmt 4702
52083
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.
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.
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.
E:\FR\FM\15OCP2.SGM
15OCP2
52084
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
khammond on DSK30JT082PROD with PROPOSAL10
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.
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
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.
117 See Docket ID No. EPA–HQ–OAR–2010–
0505–4639.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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.
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
PO 00000
Frm 00030
Fmt 4701
Sfmt 4702
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
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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.
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
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.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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
PO 00000
Frm 00031
Fmt 4701
Sfmt 4702
52085
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
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.
E:\FR\FM\15OCP2.SGM
15OCP2
52086
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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.
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.
khammond on DSK30JT082PROD with PROPOSAL10
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
123 See Docket ID No. EPA–HQ–OAR–2006–
0699–0094.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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
PO 00000
Frm 00032
Fmt 4701
Sfmt 4702
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
• 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.
124 See Docket ID No. EPA–HQ–OAR–2010–
0505–7632, Chapter 4, page 4–319.
E:\FR\FM\15OCP2.SGM
15OCP2
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
• 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.
khammond on DSK30JT082PROD with PROPOSAL10
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 coproposed option of annual fugitive
emissions monitoring results in greater
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
total emissions than those under the coproposed 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
PO 00000
Frm 00033
Fmt 4701
Sfmt 4702
52087
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
E:\FR\FM\15OCP2.SGM
15OCP2
52088
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
khammond on DSK30JT082PROD with PROPOSAL10
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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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.
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
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.
PO 00000
Frm 00034
Fmt 4701
Sfmt 4702
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 https://www2.epa.gov/lawsregulations/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).
E:\FR\FM\15OCP2.SGM
15OCP2
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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$]
Present value
Equivalent annualized value
Benefits (Total Cost Savings) .................................................................
Costs (Forgone Domestic Climate Benefits) ...........................................
$380 million ...................................
$13.5 million ..................................
$66 million.
$2.3 million.
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.
khammond on DSK30JT082PROD with PROPOSAL10
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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 RIA_
submissions@omb.eop.gov, 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.
PO 00000
Frm 00035
Fmt 4701
Sfmt 4702
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
E:\FR\FM\15OCP2.SGM
15OCP2
52090
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
significant economic costs on state or
local governments.
khammond on DSK30JT082PROD with PROPOSAL10
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
126 See Chapter 4, ‘‘Economic Impact Analysis
and Distributional Assessments,’’ of the RIA.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
continue to be achieved under the
amended 40 CFR part 60, subpart
OOOOa.
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.
Two VCS were identified as an
acceptable alternative to the EPA test
methods for the purpose of 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.
PO 00000
Frm 00036
Fmt 4701
Sfmt 4702
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, lowincome 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.
E:\FR\FM\15OCP2.SGM
15OCP2
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
khammond on DSK30JT082PROD with PROPOSAL10
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 nonlow 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:
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
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
2. Section 60.5365a is amended by
revising paragraph (e) introductory text
and adding paragraph (i)(4) to read as
follows:
■
§ 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 § 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 § 60.5397a, a
‘‘modification’’ to a separate tank
battery occurs when:
(i) Any of the actions in paragraphs
§ 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
§ 60.5365a(i)(3)(i) through (iii); or
(iii) A well site subject to the
requirements in § 60.5397a removes all
major production and processing
equipment, as defined in § 60.5430a,
such that it becomes a wellhead only
well site and sends production to an
existing separate tank battery.
*
*
*
*
*
■ 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:
§ 60.5375a What GHG and VOC standards
apply to well affected facilities?
*
PO 00000
*
*
Frm 00037
*
Fmt 4701
*
Sfmt 4702
52091
(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 § 60.5420a(a)(2), submit
annual reports as specified in
§ 60.5420a(b)(1) and (2) and maintain
records specified in § 60.5420a(c)(1)(iii)
for each wildcat and delineation well.
You must submit the notification as
specified in § 60.5420a(a)(2), submit
annual reports as specified in
§ 60.5420a(b)(1) and (2), and maintain
records as specified in
§ 60.5420a(c)(1)(iii) and (vii) for each
low pressure well.
*
*
*
*
*
■ 4. Section 60.5385a is amended by
revising paragraph (a)(1) to read as
follows:
§ 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.
*
*
*
*
*
■ 5. Section 60.5393a is amended by:
E:\FR\FM\15OCP2.SGM
15OCP2
52092
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
a. Revising paragraph (b) introductory
text and paragraphs (b)(3), (b)(5), (b)(6)
and (c);
■ b. Removing and reserving paragraphs
(b)(1), (b)(2), and (f).
The revisions read as follows:
■
§ 60.5393a What GHG and VOC standards
apply to pneumatic pump affected
facilities?
khammond on DSK30JT082PROD with PROPOSAL10
*
*
*
*
*
(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 § 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 § 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 § 60.5420a(b)(8)(ii) in
your next annual report and maintain
the records in § 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 inhouse 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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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
§ 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
§ 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 § 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
§ 60.5411a(c) and (d).
*
*
*
*
*
(f) [Reserved]
■ 6. Section 60.5397a is amended by:
■ a. Revising paragraph (a);
■ b. Revising paragraphs (c)(2);
■ c. Revising paragraph (c)(8)
introductory text;
■ d. Adding paragraph (c)(8)(iii);
■ e. Revising paragraph (d);
■ f. Revising paragraph (f)(2);
■ g. Revising paragraph (g) introductory
text;
■ h. Revising paragraphs (g)(1) and (2);
■ i. Removing and reserving paragraph
(g)(5);
■ j. Adding paragraph (g)(6); and
■ k. Revising paragraph (h).
PO 00000
Frm 00038
Fmt 4701
Sfmt 4702
The revisions and additions read as
follows:
§ 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
§ 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,
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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 remonitored.
(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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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
PO 00000
Frm 00039
Fmt 4701
Sfmt 4702
52093
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 companydefined 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 § 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 § 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
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52094
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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.
*
*
*
*
*
■ 7. Section 60.5398a is amended by
revising paragraphs (a), (c), (d) and (f) to
read as follows:
§ 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 § 60.5375a, § 60.5385a,
and § 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 § 60.5375a, § 60.5385a,
and § 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
PO 00000
Frm 00040
Fmt 4701
Sfmt 4702
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
§ 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
§ 60.5397a.
(xiii) Initial and continuous
compliance procedures, including
recordkeeping and reporting, if the
compliance procedures are different
than those specified in § 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
E:\FR\FM\15OCP2.SGM
15OCP2
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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.
■ 8. Subpart OOOOa is amended by
adding section 60.5399a to read as
follows:
khammond on DSK30JT082PROD with PROPOSAL10
§ 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 § 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 § 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 § 60.5397a
will be evaluated by the following
guidelines:
(1) The monitoring instrument,
including the monitoring procedure;
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
(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 § 60.5397a.
(f)(1) An owner or operator must
notify the Administrator before
implementing one of the alternative
fugitive emissions standards, as
specified in § 60.5420a(a)(3).
(2) An owner or operator
implementing one of the alternative
fugitive emissions standards must
include the information specified in
§ 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 § 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
PO 00000
Frm 00041
Fmt 4701
Sfmt 4702
52095
recordkeeping requirements in the
California Code of Regulations, title 17,
§§ 95665–95667, effective January 1,
2020, as an alternative to complying
with the requirements in
§§ 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 § 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, §§ 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 §§ 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 § 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
§§ 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 § 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
§§ 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
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52096
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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
§ 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 §§ 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
§ 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 §§ 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 § 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
§ 116.620, effective September 4, 2000,
as an alternative to complying with the
requirements in §§ 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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
defined in § 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 §§ 60.5397a(f)(2), (g)(2)
through (4), (h), and (i) of this subpart.
■ 9. Section 60.5400a is amended by
revising paragraph (a) to read as follows:
§ 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 §§ 60.482–1a(a), (b), (d),
and (e), 60.482–2a, and 60.482–4a
through 60.482–11a, except as provided
in § 60.5401a.
*
*
*
*
*
■ 10. Section 60.5401a is amended by
revising paragraph (e) to read as follows:
§ 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
§§ 60.482–2a(a)(1), 60.482–7a(a),
60.482–11a(a), and paragraph (b)(1) of
this section.
*
*
*
*
*
■ 11. Section 60.5410a is amended by:
■ a. Revising paragraph (c)(1);
■ b. Revising paragraphs (e)(2) through
(5); and
■ c. Removing and reserving paragraph
(e)(8).
The revisions read as follows:
§ 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 § 60.5385a(a)(1)
or (2), during the initial compliance
period, you must continuously monitor
the number of hours of operation or
PO 00000
Frm 00042
Fmt 4701
Sfmt 4702
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 § 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 § 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
§ 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
§ 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 § 60.5393a(b)(4), you
must collect the pneumatic pump
emissions through a closed vent system
that meets the requirements of
§ 60.5411a(c) and (d).
*
*
*
*
*
(8) [Reserved]
*
*
*
*
*
■ 12. Section 60.5411a is amended by:
■ a. Revising the introductory text;
■ b. Revising paragraph (a) introductory
text;
■ c. Revising paragraph (a)(1);
■ d. Revising paragraph (c) introductory
text;
■ e. Revising paragraph (c)(1);
■ f. Revising paragraph (d)(1); and
■ g. Removing and reserving paragraph
(e).
The revisions read as follows:
§ 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.
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
(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 § 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 § 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 inhouse 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]
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
13. Section 60.5412a is amended by
a. Revising paragraph (a)(1)
introductory text;
■ b. Revising paragraph (a)(1)(iv);
■ c. Revising paragraph (c) introductory
text;
■ d. Revising paragraph (d)(1)(iv)
introductory text; and paragraph
(d)(1)(iv)(D).
The revisions read as follows:
■
■
§ 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.
*
*
*
*
*
■ 14. Section 60.5413a is amended by
revising paragraph (d)(5)(i) introductory
text and paragraphs (d)(9)(iii) and
PO 00000
Frm 00043
Fmt 4701
Sfmt 4702
52097
(d)(12) introductory text to read as
follows.
§ 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
§ 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 Oil_and_
Gas_PT@EPA.GOV.
*
*
*
*
*
■ 15. Section 60.5415a is amended by:
■ a. Revising paragraph (b) introductory
text;
■ b. Revising paragraph (b)(3);
■ c. Removing and reserving paragraph
(b)(4);
■ d. Revising paragraph (c)(1); and
■ e. Revising paragraph (h)(2).
The revisions read as follows:
E:\FR\FM\15OCP2.SGM
15OCP2
52098
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
§ 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 § 60.5420a(b)(1), (3),
and (8) and maintain the records as
specified in § 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 § 60.5397a(h).
*
*
*
*
*
■ 16. Section 60.5416a is amended by:
■ a. Revising the introductory text;
■ b. Revising paragraph (a) introductory
text;
■ c. Revising paragraph (a)(4)
introductory text;
■ d. Revising paragraph (c) introductory
text; and
■ e. Removing and reserving paragraph
(d).
The revisions read as follows:
khammond on DSK30JT082PROD with PROPOSAL10
§ 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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 § 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]
■ 17. Section 60.5417a is amended by
revising paragraph (a) to read as follows:
§ 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 § 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 § 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.
*
*
*
*
*
■ 18. Section 60.5420a is amended by:
■ a. Revising paragraph (a)(1);
■ b. Adding paragraph (a)(3);
■ c. Revising paragraph (b) introductory
text;
PO 00000
Frm 00044
Fmt 4701
Sfmt 4702
d. Revising paragraph (b)(2);
e. Revising paragraph (b)(3)
introductory paragraph;
■ f. Revising paragraphs (b)(3)(ii)
through (iv);
■ g. Adding paragraph (b)(3)(v);
■ h. Revising paragraph (b)(4);
■ i. Revising paragraphs (b)(5)(i)
through (iii);
■ j. Revising paragraph (b)(6)
introductory text;
■ k. Revising paragraphs (b)(6)(iii) and
(vii);
■ l. Adding paragraphs (b)(6)(viii) and
(ix);
■ m. Revising paragraph (b)(7);
■ n. Revising paragraph (b)(8)
introductory text;
■ o. Revising paragraph (b)(8)(iii);
■ p. Adding paragraph (b)(8)(iv);
■ q. Revising paragraph (b)(9)(i);
■ r. Revising paragraphs (b)(11) through
(13);
■ s. Adding paragraph (b)(14);
■ t. Revising paragraph (c) introductory
text;
■ u. Revising paragraph (c)(1)
introductory text;
■ v. Revising paragraph (c)(1)(ii);
■ w. Revising paragraph (c)(1)(iii)
introductory text;
■ x. Revising paragraphs (c)(1)(iii)(A)
and (B);
■ y. Revising paragraph (c)(1)(iii)(C)(1);
■ z. Revising paragraphs (c)(1)(iv),
(c)(1)(vi)(B), and (c)(1)(vii);
■ aa. Revising paragraph (c)(2)
introductory text;
■ bb. Revising paragraphs (c)(2)(vi)(D)
and (E);
■ cc. Revising paragraph (c)(2)(vii);
■ dd. Adding paragraph (c)(2)(viii);
■ ee. Revising paragraphs (c)(3)(i) and
(iii);
■ ff. Revising paragraphs (c)(4)(i) and
(v);
■ gg. Revising paragraph (c)(5)
introductory text;
■ hh. Revising paragraphs (c)(5)(iii) and
(v);
■ ii. Revising paragraph (c)(5)(vi)
introductory text;
■ jj. Revising paragraphs (c)(5)(vi)(F)(4)
and (c)(5)(vi)(G);
■ kk. Adding paragraphs (c)(5)(vi)(H)
and (c)(5)(vii);
■ ll. Revising paragraphs (c)(6) through
(9);
■ mm. Revising paragraph (c)(15);
■ nn. Revising paragraphs (c)(16)(ii) and
(iv); and
■ oo. Adding paragraph (c)(18)
The revisions and additions read as
follows:
■
■
§ 60.5420a What are my notification,
reporting, and recordkeeping
requirements?
(a) * * *
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
(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 § 60.7(a)(1),
(3), and (4) and § 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 § 60.7(a)(1), (3),
and (4) and § 60.15(d).
*
*
*
*
*
(3) An owner or operator electing to
comply with the provisions of
§ 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 § 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 § 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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 § 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 § 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 § 60.5375a(f), a record of the
well type (i.e., wildcat well, delineation
well, or low pressure well (as defined
§ 60.5430a)) and supporting inputs and
calculations, if applicable.
(xiv) For each well affected facility for
which you claim an exception under
§ 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
PO 00000
Frm 00045
Fmt 4701
Sfmt 4702
52099
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
§ 60.5380a(a)(2), the information in
paragraphs (b)(3)(iii)(A) through (C) of
this section.
(A) Dates of each inspection required
under § 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 § 60.5416a(a)(4).
(iv) If complying with § 60.5380a(a)(1)
with a control device tested under
§ 60.5413a(d) which meets the criteria
in § 60.5413a(d)(11) and § 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 § 60.5380a(a)(1)
with a control device not tested under
§ 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
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52100
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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
§ 60.5385a(a)(3), the information in
paragraphs (b)(4)(iii)(A) through (C) of
this section.
(A) Dates of each inspection required
under § 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 § 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 § 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 § 60.5395a(a)(2)
with a control device tested under
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
§ 60.5413a(d) which meets the criteria
in § 60.5413a(d)(11) and § 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
§ 60.5395a(a)(2) with a control device
not tested under § 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
§ 60.5395a(b)(1), the information in
paragraphs (b)(6)(ix)(A) through (C) of
this section.
(A) Dates of each inspection required
under § 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 § 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.
PO 00000
Frm 00046
Fmt 4701
Sfmt 4702
(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
§ 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 § 60.5397a(h).
(H) Number and type of difficult-tomonitor 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.
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
(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
§ 60.5393a(b), the information in
paragraphs (b)(8)(iv)(A) through (C) of
this section.
(A) Dates of each inspection required
under § 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 § 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/electronicreporting-air-emissions/electronicreporting-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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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
§ 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 § 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
PO 00000
Frm 00047
Fmt 4701
Sfmt 4702
52101
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
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52102
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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 § 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 § 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 § 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
§ 60.5375a(a)(1)(ii); the date and time of
each occurrence of returning to the
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
initial flowback stage under
§ 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 § 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 § 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
PO 00000
Frm 00048
Fmt 4701
Sfmt 4702
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
§ 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 § 60.5375a(f), a record of the
well type (i.e., wildcat well, delineation
well, or low pressure well (as defined
§ 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 § 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 § 60.5413a(d) which meets
the criteria in § 60.5413a(d)(11) and
§ 60.5413a(e) and used to comply with
§ 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
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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 § 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 § 60.5390a, a description of
the deviation, the date and time the
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 §§ 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 § 60.5413a(d) which meets
the criteria in § 60.5413a(d)(11) and
§ 60.5413a(e) and used to comply with
§ 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
PO 00000
Frm 00049
Fmt 4701
Sfmt 4702
52103
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
§ 60.5416a(a)(1) and (2) for centrifugal
compressors and reciprocating
compressors, or § 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 § 60.5416a(a)(1)
and (2) or § 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 § 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 § 60.5416a(a)(3) for
centrifugal or reciprocating compressors
or § 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 § 60.5416a(a)(3)
or § 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 § 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 § 60.5416a(a)(4) for
centrifugal compressors or reciprocating
compressors, or § 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.
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52104
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
(9) If you are subject to the closed
vent system no detectable emissions
requirements of § 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 § 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 § 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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 § 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
§ 60.5397a(d)(2) in lieu of § 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
PO 00000
Frm 00050
Fmt 4701
Sfmt 4702
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 § 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 § 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 § 60.5393a(b)(5) that it is
technically infeasible to capture and
E:\FR\FM\15OCP2.SGM
15OCP2
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
route emissions from a pneumatic pump
to a control device or process; including
the certification according to
§ 60.5393a(b)(5)(ii) and the records of
the engineering assessment of technical
infeasibility performed according to
§ 60.5393a(b)(5)(iii).
*
*
*
*
*
(18) A copy of each performance test
submitted under paragraph (b)(9) of this
section.
■ 19. Section 60.5422a is amended by
revising paragraphs (a) and (b), and
paragraph (c) introductory text to read
as follows:
khammond on DSK30JT082PROD with PROPOSAL10
§ 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 § 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 § 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
§ 60.487a(b)(1) through (3) and (b)(5):
Number of pressure relief devices
subject to the requirements of
§ 60.5401a(b) except for those pressure
relief devices designated for no
detectable emissions under the
provisions of § 60.482–4a(a) and those
pressure relief devices complying with
§ 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
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
§ 60.487a(c)(2)(i) through (iv) and
(c)(2)(vii) through (viii):
*
*
*
*
*
■ 20. Section 60.5423a is amended by
revising paragraph (b) introductory text
and adding paragraph (b)(3) to read as
follows:
§ 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 § 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.
*
*
*
*
*
■ 21. Section 60.5430a is amended by:
■ 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’’;
■ 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
■ c. Removing the definition for
‘‘greenfield site’’.
The revisions and additions read as
follows:
PO 00000
Frm 00051
Fmt 4701
Sfmt 4702
§ 60.5430a
subpart?
52105
What definitions apply to this
*
*
*
*
*
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 × 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 × (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
E:\FR\FM\15OCP2.SGM
15OCP2
khammond on DSK30JT082PROD with PROPOSAL10
52106
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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.
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
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 §§ 60.5411 or 60.5411a, thief
hatches or other openings on a
controlled storage vessel not subject to
§§ 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 § 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 § 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
PO 00000
Frm 00052
Fmt 4701
Sfmt 4702
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 § 60.5397a of this subpart
and is resurveyed as specified in
§ 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 § 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
E:\FR\FM\15OCP2.SGM
15OCP2
52107
Federal Register / Vol. 83, No. 199 / Monday, October 15, 2018 / Proposed Rules
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 § 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
§ 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 § 60.5397a, a well site that
contains one or more wellheads and no
major production and processing
equipment.
*
*
*
*
*
■ 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
*
§ 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).
*
§ 60.15 ........
*
Reconstruction .............
*
Yes ...........
*
*
*
*
Except that § 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]
khammond on DSK30JT082PROD with PROPOSAL10
BILLING CODE 6560–50–P
VerDate Sep<11>2014
18:26 Oct 12, 2018
Jkt 247001
PO 00000
Frm 00053
Fmt 4701
Sfmt 9990
E:\FR\FM\15OCP2.SGM
15OCP2
*
]]>Agencies
[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
-----------------------------------------------------------------------
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]]
-----------------------------------------------------------------------
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.
-----------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\3\ 83 FR 10628.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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$]
----------------------------------------------------------------------------------------------------------------
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
------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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:
---------------------------------------------------------------------------
\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\
---------------------------------------------------------------------------
\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\
---------------------------------------------------------------------------
\42\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\47\ ``The Natural Gas Air Quality Study (Final Report),''
prepared by Eastern Research Group, Inc. July 13, 2011, available at
https://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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\51\ See the TSD for full comparison of cost.
---------------------------------------------------------------------------
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.)
---------------------------------------------------------------------------
\52\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.
---------------------------------------------------------------------------
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 https://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.
---------------------------------------------------------------------------
\80\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-10791.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\ https://www.tech-flo.net/salt-water-disposal.html.
\92\ Barnett Shale Energy Education Council. What are Saltwater
Disposal Wells? Air and Water Quality. https://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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\98\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
\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 https://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
