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

Federal RegisterOct 15, 2018

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

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

RIN 2060-AT54

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

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

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: 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 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

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.

Following promulgation of the final rule, the Administrator received petitions for reconsideration of several provisions of the 2016 NSPS OOOOa.

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.

Docket ID No. EPA-HQ-OAR-2010-0505.

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

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,

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.

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

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).

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$]

Present

value

Equivalent

annualized

value

Present

value

Equivalent

annualized

value

Benefits (Total Cost Savings)

$380

$66

$484

$75

Cost Savings

429

546

Forgone Value of Product Recovery

8.4

9.6

Costs (Forgone Domestic Climate Benefits)

13.5

2.3

8.3

Net Benefits

367

431

Emissions

Total Change

Methane (short tons)

380,000

VOC

100,000

HAP

3,800

Methane (million metric tons CO2E)

8.5

The forgone benefits estimates are calculated using estimates of the social cost of methane (SC-CH

). SC-CH

values represent only a partial accounting of domestic climate impacts from methane emissions. See section 3.3 of the RIA for more discussion.

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, PM

2.5

, 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

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

Category

NAICS code

Examples of regulated 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.

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.

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.

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.

See Docket ID No. EPA-HQ-OAR-2010-0505-7730.

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

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

Fox Television Stations, Inc.,

556 U.S. 502, 515 (2009);

Motor Vehicle Mfrs. Ass'n

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

Gen. Elec. Co.,

621 F.2d 1084, 1086 (10th Cir. 1980); see also,

United Gas Improvement Co.

Callery Properties, Inc.,

382 U.S. 223, 229 (1965);

Mazaleski

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

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,

with one petitioner asserting that the EPA's cost-effectiveness analysis is not accurate and should be revised.

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.

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

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.

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.

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.

See TSD for additional information.

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.

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

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

regards to controlled storage vessel fugitive emissions.

See the TSD for additional information on the fugitive emissions from storage vessels.

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.

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

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.

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.

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.

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.

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).

These average emissions factors are used when screening data are not available, as is the case when OGI is used as the monitoring instrument,

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.

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.

U.S. Environmental Protection Agency, Protocol for Equipment Leak Emission Estimates. Table 2-4. November 1995 (EPA-453/R-95-017).

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.

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.

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.”

Specific concerns

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.

See TSD for additional information related to OGI control effectiveness.

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.

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

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;

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.

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.

See memorandum

EPA Analysis of Fugitive Emissions Data Provided by INGAA

located at Docket ID No. EPA-HQ-OAR-2017-0483. August 21, 2018.

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.

Canadian Association of Petroleum Producers, “Best Management Practice. Management of Fugitive Emissions at Upstream Oil and Gas Facilities”, January 2007.

See memorandum

EPA Analysis of Fugitive Emissions Data Provided by INGAA

located at Docket ID No. EPA-HQ-OAR-2017-0483. August 21, 2018.

Canadian Association of Petroleum Producers, “Best Management Practice. Management of Fugitive Emissions at Upstream Oil and Gas Facilities”, January 2007.

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.

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.

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.

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.

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

fugitive emissions percentages for well sites located in 14 states.

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.

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.

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).

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

Alaska, Arkansas, Colorado, Louisiana, Montana, New Mexico, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, Utah, West Virginia, and Wyoming.

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)

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.

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”

components.

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.

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,

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.

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.

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.

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.

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

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.

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

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.

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.

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

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.

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.

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:

See Docket ID No. EPA-HQ-OAR-2010-0505-7730.

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.'

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.

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.

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.

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.

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.”

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.

See Docket ID No. EPA-HQ-OAR-2010-0505-7682, p. 12.

Id.

See Docket ID No. EPA-HQ-OAR-2010-0505-12454.

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”).

The EPA evaluated

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.

“The Natural Gas Air Quality Study (Final Report),” prepared by Eastern Research Group, Inc.

July 13, 2011,

available at http://fortworthtexas.gov/gaswells/air-quality-study/final/.

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

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

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.

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.

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.

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.

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.

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.)

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.

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.

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.

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.

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,

including additional data that will allow for further analysis of fugitive emissions monitoring at

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.

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.

The EPA best practices guide for LDAR states that more frequent monitoring should be implemented for components that contribute most to emissions.

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.”

Canadian Association of Petroleum Producers, “Best Management Practice. Management of Fugitive Emissions at Upstream Oil and Gas Facilities,” January 2007.

U.S. Environmental Protection Agency, “Leak Detection and Repair: A Best Practices Guide,” EPA-305-D-07-001, October 2007.

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.

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.

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)

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.

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]

Frequency

Capital cost (million $)

Annualized costs without recovery

credits

(million $/yr)

Emissions

reduction, methane

(tpy)

Emissions

reduction,

VOC

(tpy)

Total cost-

effectiveness

without

recovery credit

($/ton methane)

Total cost-

effectiveness without

recovery credit

($/ton VOC)

Incremental

cost-effectiveness

without

recovery credit

($/ton methane)

Incremental

cost-effectiveness without recovery credit

($/ton 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

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.

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.

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,

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.

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.

GHG Emission Factor Development for Natural Gas Compressors, PRCI Catalog No. PR-312-1602-R02, April 18, 2018.

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.

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

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.

83 FR 10628.

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

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.

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,

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.

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.

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

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.

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

See Docket ID No. EPA-HQ-OAR-2010-0505-12434.

See FLIR Systems, Inc. product specifications for GF300/320 model OGI cameras at

http://www.flir.com/ogi/display/?id=55671.

See Thermo Fisher Scientific product specification for TVA-2020 at

https://assets.thermofisher.com/TFS-Assets/LSG/Specification-Sheets/EPM-TVA2020.pdf.

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

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.

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.”

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.

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.

“Equipment Leaks of VOC in Natural Gas Production Industry—Background Information for Promulgated Standards,” EPA-450/3-82-024b, May 1985.

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

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

aspects of the 2016 NSPS OOOOa, including its application of the fugitive emissions requirements at 40 CFR 60.5397a to low production well sites.

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.

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:

See Docket ID No. EPA-HQ-OAR-2010-0505-7730.

See Docket ID No. EPA-HQ-OAR-2010-0505-7685.

i.e.,

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.

According to one petitioner,

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.

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

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 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

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.

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.

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.

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.

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.

They asserted that hiring third-party contractors to monitor one remote well site is inefficient and costly.

See Docket ID Nos. EPA-HQ-OAR-2010-0505-6808, EPA-HQ-OAR-2010-0505-6935 and EPA-HQ-OAR-2010-0505-6960.

See Docket ID EPA-HQ-OAR-2010-0505-6857.

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° 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° 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

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.

One petitioner stated that the 2-year delay should be reevaluated because no specific data was provided to support that deadline.

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.

See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-2010-0505-7683, and EPA-HQ-OAR-2010-0505-7686.

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.

The 2016 NSPS OOOOa requires an explanation of each repair that is delayed as well.

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.

See 40 CFR 60.5397a(h)(2).

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 § 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 third-party.

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.

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

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.

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.

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 chemical

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