Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56593 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 60 

[EPA–HQ–OAR–2010–0505; FRL–9929–75– 

OAR] 

RIN 2060–AS30 

Oil and Natural Gas Sector: Emission 

Standards for New and Modified 

Sources 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: This action proposes to 

amend the new source performance 

standards (NSPS) for the oil and natural 

gas source category by setting standards 

for both methane and volatile organic 

compounds (VOC) for certain 

equipment, processes and activities 

across this source category. The 

Environmental Protection Agency (EPA) 

is including requirements for methane 

emissions in this proposal because 

methane is a greenhouse gas (GHG), and 

the oil and natural gas category is 

currently one of the country’s largest 

emitters of methane. In 2009, the EPA 

found that by causing or contributing to 

climate change, GHGs endanger both the 

public health and the public welfare of 

current and future generations. The EPA 

is proposing both methane and VOC 

standards for several emission sources 

not currently covered by the NSPS and 

proposing methane standards for certain 

emission sources that are currently 

regulated for VOC. The proposed 

amendents also extend the current VOC 

standards to the remaining unregulated 

equipment across the source category 

and additionally establish methane 

standards for this equipment. Lastly, 

amendments to improve 

implementation of the current NSPS are 

being proposed which result from 

reconsideration of certain issues raised 

in petitions for reconsideration that 

were received by the Administrator on 

the August 16, 2012, final NSPS for the 

oil and natural gas sector and related 

amendments. Except for the 

implementation improvements and the 

setting of standards for methane, these 

amendments do not change the 

requirements for operations already 

covered by the current standards. 

DATES: Comments. Comments must be 

received on or before November 17, 

2015. 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 November 17, 2015. The EPA 

will hold public hearings on the 

proposal. Details will be announced in 

a separate announcement. 

ADDRESSES: Submit your comments, 

identified by Docket ID Number EPA– 

HQ–OAR–2010–0505, to the Federal 

eRulemaking Portal: http://

www.regulations.gov. Follow the online 

instructions for submitting comments. 

Once submitted, comments cannot be 

edited or withdrawn. The EPA may 

publish any comment received to its 

public docket. Do not submit 

electronically any information you 

consider to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

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 

http://www2.epa.gov/dockets/

commenting-epa-dockets. 

Instructions: All submissions must 

include agency name and respective 

docket number or Regulatory 

Information Number (RIN) for this 

rulemaking. Direct your comments to 

Docket ID Number EPA–HQ–OAR– 

2010–0505. 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 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be confidential business 

information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through www.regulations.gov 

or email. (See section III.B below for 

instructions on submitting information 

claimed as CBI.) The 

www.regulations.gov Web site is an 

‘‘anonymous access’’ system, which 

means the EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you submit an electronic 

comment through www.regulations.gov, 

the EPA recommends that you include 

your name and other contact 

information in the body of your 

comment and with any disk or CD–ROM 

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. If you send an email 

comment directly to the EPA without 

going through 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. Electronic files should avoid 

the use of special characters, 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: 

www.epa.gov/epahome/dockets.htm. 

Docket: The EPA has established a 

docket for this rulemaking under Docket 

ID Number EPA–HQ–OAR–2010–0505. 

All documents in the docket are listed 

in the www.regulations.gov index. 

Although listed in the index, 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 

www.regulations.gov or in hard copy at 

the EPA Docket Center, EPA WJC West 

Building, Room Number 3334, 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. 

FOR FURTHER INFORMATION CONTACT: For 

information concerning this action, or 

for other information concerning the 

EPA’s Oil and Natural Gas Sector 

regulatory program, contact Mr. Bruce 

Moore, Sector Policies and Programs 

Division (E143–05), Office of Air 

Quality Planning and Standards, 

Environmental Protection Agency, 

Research Triangle Park, North Carolina 

27711, telephone number: (919) 541– 

5460; facsimile number: (919) 541–3470; 

email address: moore.bruce@epa.gov. 

SUPPLEMENTARY INFORMATION: Outline. 

The information presented in this 

preamble is organized as follows: 

I. Preamble Acronyms and Abbreviations 

II. Executive Summary 

A. Purpose of the Regulatory Action 

B. Summary of the Major Provisions of the 

Regulatory Action 

C. Costs and Benefits 

III. General Information 

A. Does this reconsideration notice apply 

to me? 

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56594 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

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? 

IV. Background 

A. Statutory Background 

B. What are the regulatory history and 

litigation background regarding 

performance standards for the oil and 

natural gas source category? 

C. Events Leading to This Action 

V. Why is the EPA Proposing to Establish 

Methane Standards in the Oil and 

Natural Gas NSPS? 

VI. The Oil and Natural Gas Source Category 

Listing Under Clean Air Act Section 

111(b)(1)(A) 

A. Impacts of GHG, VOC, and SO2

Emissions on Public Health and Welfare 

B. Stakeholder Input 

VII. Summary of Proposed Standards 

A. Control of Methane and VOC Emissions 

in the Oil and Natural Gas Source 

Category 

B. Centrifugal Compressors 

C. Reciprocating Compressors 

D. Pneumatic Controllers 

E. Pneumatic Pumps 

F. Well Completions 

G. Fugitive Emissions from Well Sites and 

Compressor Stations 

H. Equipment Leaks at Natural Gas 

Processing Plants 

I. Liquids Unloading Operations 

J. Recordkeeping and Reporting 

VIII. Rationale for Proposed Action for NSPS 

A. How does EPA evaluate control costs in 

this action? 

B. Proposed Standards for Centrifugal 

Compressors 

C. Proposed Standards for Reciprocating 

Compressors 

D. Proposed Standards for Pneumatic 

Controllers 

E. Proposed Standards for Pneumatic 

Pumps 

F. Proposed Standards for Well 

Completions 

G. Proposed Standards for Fugitive 

Emissions from Well Sites and 

Compressor Stations 

H. Proposed Standards for Equipment 

Leaks at Natural Gas Processing Plants 

I. Liquids Unloading Operations 

IX. Implementation Improvements 

A. Storage Vessel Control Device 

Monitoring and Testing Provisions 

B. Other Improvements 

X. Next Generation Compliance and Rule 

Effectiveness 

A. Independent Third-Party Verification 

B. Fugitives Emissions Verification 

C. Third-Party Information Reporting 

D. Electronic Reporting and Transparency 

XI. Impacts of This Proposed Rule 

A. What are the air impacts? 

B. What are the energy impacts? 

C. What are the compliance costs? 

D. What are the economic and employment 

impacts? 

E. What are the benefits of the proposed 

standards? 

XII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act (PRA) 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act of 1995 

(UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination with Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations that 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act (NTTAA) and 1 CFR 

part 51 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. Preamble Acronyms and 

Abbreviations 

Several acronyms and terms are 

included in this preamble. While this 

may not be an exhaustive list, to ease 

the reading of this preamble and for 

reference purposes, the following terms 

and acronyms are defined here: 

ANGA America’s Natural Gas Alliance 

API American Petroleum Institute 

bbl Barrel 

BID Background Information Document 

BOE Barrels of Oil Equivalent 

bpd Barrels Per Day 

BSER Best System of Emissions Reduction 

BTEX Benzene, Toluene, Ethylbenzene and 

Xylenes 

CAA Clean Air Act 

CFR Code of Federal Regulations 

CPMS Continuous Parametric Monitoring 

Systems 

EIA Energy Information Administration 

EPA Environmental Protection Agency 

GOR Gas to Oil Ratio 

HAP Hazardous Air Pollutants 

HPD HPDI, LLC 

LDAR Leak Detection and Repair 

Mcf Thousand Cubic Feet 

NEI National Emissions Inventory 

NEMS National Energy Modeling System 

NESHAP National Emissions Standards for 

Hazardous Air Pollutants 

NSPS New Source Performance Standards 

NTTAA National Technology Transfer and 

Advancement Act of 1995 

OAQPS Office of Air Quality Planning and 

Standards 

OGI Optical Gas Imaging 

OMB Office of Management and Budget 

OVA Olfactory, Visual and Auditory 

PRA Paperwork Reduction Act 

PTE Potential to Emit 

REC Reduced Emissions Completion 

RFA Regulatory Flexibility Act 

RIA Regulatory Impact Analysis 

scfh Standard Cubic Feet per Hour 

scfm Standard Cubic Feet per Minute 

SISNOSE Significant Economic Impact on a 

Substantial Number of Small Entities 

tpy Tons per Year 

TSD Technical Support Document 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act 

VCS Voluntary Consensus Standards 

VOC Volatile Organic Compounds 

VRU Vapor Recovery Unit 

II. 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. 

To date the EPA has established 

standards for emissions of VOC and 

sulfur dioxide (SO2) for several 

operations in the source category. In this 

action, the EPA is proposing to amend 

the NSPS to include standards for 

reducing methane as well as VOC 

emissions across the oil and natural gas 

source category (i.e., production, 

processing, transmission and storage). 

The EPA is including requirements for 

methane emissions in this proposal 

because methane is a GHG and the oil 

and natural gas category is currently one 

of the country’s largest emitters of 

methane. In 2009, the EPA found that by 

causing or contributing to climate 

change, GHGs endanger both the public 

health and the public welfare of current 

and future generations.1 The proposed 

amendments would require reduction of 

methane as well as VOC across the 

source category. 

In addition, the proposed 

amendments include improvements to 

several aspects of the existing standards 

related to implementation. These 

improvements and the setting of 

standards for methane are a result of 

reconsideration of certain issues raised 

in petitions for reconsideration that 

were received by the Administrator on 

the August 16, 2012, NSPS (77 FR 

49490) and on the September 13, 2013, 

amendments (78 FR 58416). Except for 

these implementation improvements, 

these proposed amendments do not 

change the requirements for operations 

and equipment already covered by the 

current standards. 

B. Summary of the Major Provisions of 

the Regulatory Action 

The proposed amendments include 

standards for methane and VOC for 

certain new, modified and reconstructed 

equipment, processes and activities 

across the oil and natural gas source 

category. These emission sources 

include those that are currently 

unregulated under the current NSPS 

(hydraulically fractured oil well 

completions, pneumatic pumps and 

fugitive emissions from well sites and 

compressor stations); those that are 

currently regulated for VOC but not for 

methane (hydraulically fractured gas 

well completions, equipment leaks at 

natural gas processing plants); and 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56595 

2 During the development of the 2012 NSPS, our 

data indicatedd that there were no centrifugal 

compressors located at well sites. Since the 2012 

NSPS, we have not received information that would 

change our understanding that there are no 

centrifugal compressors in use at well sites. 

certain equipment that are used across 

the source category, but which the 

current NSPS regulates VOC emissions 

from only a subset of these equipment 

(pneumatic controllers, centrifugal 

compressors, reciprocating 

compressors), with the exception of 

compressors located at well sites. 

Based on the EPA’s analysis (see 

section VIII), we believe it is important 

to regulate methane from the oil and gas 

sources already regulated for VOC 

emissions to provide more consistency 

across the category, and that the best 

system of emission reduction (BSER) for 

methane for all these sources is the 

same as the BSER for VOC. Accordingly, 

the current VOC standards also reflect 

the BSER for methane reduction for the 

same emission sources. In addition, 

with respect to equipment used 

category-wide of which only a subset of 

those equipment are covered under the 

NSPS VOC standards (i.e., pneumatic 

controllers, and compressors located 

other than at well sites), EPA’s analysis 

shows that the BSER for reducing VOC 

from the remaining unregulated 

equipment to be the same as the BSER 

for those currently regulated. The EPA 

is therefore proposing to extend the 

current VOC standards for these 

equipment to the remaining unregulated 

equipment. 

The additional sources for which we 

are proposing methane and VOC 

standards were evaluated in the 2014 

white papers (EPA Docket Number 

EPA–HQ–OAR–2014–0557). The papers 

summarized the EPA’s understanding of 

VOC and methane emissions from these 

sources and also presented the EPA’s 

understanding of mitigation techniques 

(practices and equipment) available to 

reduce these emissions, including the 

efficacy and cost of the technologies and 

the prevalence of use in the industry. 

The EPA received 26 submissions of 

peer review comments on these papers, 

and more than 43,000 comments from 

the public. The information gained 

through this process has improved the 

EPA’s understanding of the methane 

and VOC emissions from these sources 

and the mitigation techniques available 

to control them. 

The EPA has also received extensive 

and helpful input from state, local and 

tribal governments experienced in these 

operations, industry organizations, 

individual companies and others with 

data and experience. This information 

has been immensely helpful in 

determining appropriate standards for 

the various sources we are proposing to 

regulate. It has also helped the EPA 

design this proposal so as to 

complement, not complicate, existing 

state requirements. EPA acknowledges 

that a state may have more stringent 

state requirements (e.g., fugitives 

monitoring and repair program). We 

believe that affected sources already 

complying with more stringent state 

requirements may also be in compliance 

with this rule. We solicit comment on 

how to determine whether existing state 

requirements (i.e., monitoring, record 

keeping, and reporting) would 

demonstrate compliance with this 

federal rule. 

During development of these 

proposed requirements, we were 

mindful that some facilities that will be 

subject to the proposed EPA standards 

will also be subject to current or future 

requirements of the Department of 

Interior’s Bureau of Land Management 

(BLM) rules covering production of 

natural gas on Federal lands. We 

believe, to minimize confusion and 

unnecessary burden on the part of 

owners and operators, it is important 

that the EPA requirements not conflict 

with BLM requirements. As a result, 

EPA and BLM have maintained an 

ongoing dialogue during development of 

this action to identify opportunities for 

alignment and ways to minimize 

potential conflicting requirements and 

will continue to coordinate through the 

agencies’ respective proposals and final 

rulemakings. 

Following are brief summaries of 

these sources and the proposed 

standards. 

Compressors. The EPA is proposing a 

95 percent reduction of methane and 

VOC emissions from wet seal centrifugal 

compressors across the source category 

(except for those located at well sites).2

For reciprocating compressors across 

the source category (except for those 

located at well sites), the EPA is 

proposing to reduce methane and VOC 

emissions by requiring that owners and/ 

or operators of these compressors 

replace the rod packing based on 

specified hours of operation or elapsed 

calendar months or route emissions 

from the rod packing to a process 

through a closed vent system under 

negative pressure. See sections VIII.B 

and C of this preamble for further 

discussion. 

Pneumatic controllers. The EPA is 

proposing a natural gas bleed rate limit 

of 6 standard cubic feet per hour (scfh) 

to reduce methane and VOC emissions 

from individual, continuous bleed, 

natural gas-driven pneumatic 

controllers at locations across the source 

category other than natural gas 

processing plants. At natural gas 

processing plants, the proposed rule 

regulates methane and VOC emissions 

by requiring natural gas-operated 

pneumatic controllers to have a zero 

natural gas bleed rate, as in the current 

NSPS. See section VIII.D of this 

preamble for further discussion. 

Pneumatic pumps. The proposed 

standards for pneumatic pumps would 

apply to certain types of pneumatic 

pumps across the entire source category. 

At locations other than natural gas 

processing plants, we are proposing that 

the methane and VOC emissions from 

natural gas-driven chemical/methanol 

pumps and diaphragm pumps be 

reduced by 95 percent if a control 

device is already available on site. At 

natural gas processing plants, the 

proposed standards would require the 

methane and VOC emissions from 

natural gas-driven chemical/methanol 

pumps and diaphragm pumps to be 

zero. See section VIII.E of this preamble 

for further discussion. 

Hydraulically fractured oil well 

completions. For subcategory 1 wells 

(non-wildcat, non-delineation wells), 

we are proposing that for hydraulically 

fractured oil well completions, owners 

and/or operators use reduced emissions 

completions, also known as ‘‘RECs’’ or 

‘‘green completions,’’ to reduce methane 

and VOC emissions and maximize 

natural gas recovery from well 

completions. To achieve these 

reductions, owners and operators of 

hydraulically fractured oil wells must 

use RECs in combination with a 

completion combustion device. As is 

specified in the rule for hydraulically 

fractured gas well completions, the rule 

proposed here does not require RECs 

where their use is not feasible (e.g., if it 

technically infeasible for a separator to 

function). For subcategory 2 wells 

(wildcat and delineation wells), we are 

proposing that for hydraulically 

fractured oil well completions, owners 

and/or operators use a completion 

combustion device to reduce methane 

and VOC emissions. The proposed 

standards for hydraulically fractured oil 

well completions are the same as the 

requirements finalized for hydraulically 

fractured gas well completions in the 

2012 NSPS and as amended in 2014 (see 

79 FR 79018, December 31, 2014). See 

section VIII.F of this preamble for 

further discussion. 

Fugitive emissions from well sites and 

compressor stations. We are proposing 

that new and modified well sites and 

compressor stations (which include the 

transmission and storage segment and 

the gathering and boosting segment) 

conduct fugitive emissions surveys 

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56596 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

3We estimate methane benefits associated with 

four different values of a one ton CH4 reduction 

(model average at 2.5 percent discount rate, 3 

percent, and 5 percent; 95th percentile at 3 

percent). For the purposes of this summary, we 

present the benefits associated with the model 

average at 3 percent discount rate, however we 

emphasize the importance and value of considering 

the full range of social cost of methane values. We 

provide estimates based on additional discount 

rates in preamble section XI and in the RIA. 4Figures may not sum due to rounding. 

semiannually with optical gas imaging 

(OGI) technology and repair the sources 

of fugitive emissions within 15 days that 

are found during those surveys. We are 

also co-proposing OGI monitoring 

surveys on an annual basis for new and 

modified well sites, and requesting 

comment on OGI monitoring surveys on 

a quarterly basis for both well sites and 

compressor stations. Fugitive emissions 

can occur immediately on startup of a 

newly constructed facility as a result of 

improper makeup of connections and 

other installation issues. In addition, 

during ongoing operation and aging of 

the facility, fugitive emissions may 

occur. Under this proposal, the required 

survey frequency would decrease from 

semiannually to annually for sites that 

find fugitive emissions from fewer than 

one percent of their fugitive emission 

components during a survey, while the 

frequency would increase from 

semiannually to quarterly for sites that 

find fugitive emissions from three 

percent or more of their fugitive 

emission components during a survey. 

We recognize that subpart W already 

requires annual fugitives reporting for 

certain compressor stations that exceed 

the 25,000 Metric Ton CO2e threshold, 

and request comments on the overlap of 

these reporting requirements. 

Building on the 2012 NSPS, the EPA 

intends to continue to encourage 

corporate-wide voluntary efforts to 

achieve emission reductions through 

responsible, transparent and verifiable 

actions that would obviate the need to 

meet obligations associated with NSPS 

applicability, as well as avoid creating 

disruption for operators following 

advanced responsible corporate 

practices. Based on this concept, we 

solicit comment on criteria we can use 

to determine whether and under what 

conditions well sites and other emission 

sources operating under corporate 

fugitive monitoring plans can be 

deemed to be meeting the equivalent of 

the NSPS standards for well site fugitive 

emissions such that we can define those 

regimes as constituting alternative 

methods of compliance or otherwise 

provide appropriate regulatory 

streamlining. We also solicit comment 

on how to address enforceability of such 

alternative approaches (i.e., how to 

assure that these well sites are 

achieving, and will continue to achieve, 

equal or better emission reduction than 

our proposed standards). 

Other reconsideration issues being 

addressed. The EPA is granting 

reconsideration of a number of issues 

raised in the administrative 

reconsideration petitions and, where 

appropriate, is proposing amendments 

to address such issues. These issues are 

as follows: Storage vessel control device 

monitoring and testing provisions, 

initial compliance requirements in 

§ 60.5411(c)(3)(i)(A) for a bypass device 

that could divert an emission stream 

away from a control device, 

recordkeeping requirements of 

§ 60.5420(c) for repair logs for control 

devices failing a visible emissions test, 

clarification of the due date for the 

initial annual report under the 2012 

NSPS, flare design and operation 

standards, leak detection and repair 

(LDAR) for open-ended valves or lines, 

compliance period for LDAR for newly 

affected units, exemption to notification 

requirement for reconstruction, disposal 

of carbon from control devices, the 

definition of capital expenditure and 

initial compliance clarification. We are 

proposing to address these issues to 

clarify the rule, improve 

implementation and update procedures, 

as fully detailed in section IX. 

C. Costs and Benefits 

The EPA has estimated emissions 

reductions, costs and benefits for two 

years of analysis: 2020 and 2025. 

Actions taken to comply with the 

proposed NSPS are anticipated to 

prevent significant new emissions, 

including 170,000 to 180,000 tons of 

methane, 120,000 tons of VOC and 310 

to 400 tons of hazardous air pollutants 

(HAP) in 2020. The emission reductions 

are 340,000 to 400,000 tons of methane, 

170,000 to 180,000 tons of VOC, and 

1,900 to 2,500 tons of HAP in 2025. The 

methane-related monetized climate 

benefits are estimated to be $200 to $210 

million in 2020 and $460 to $550 

million in 2025 using a 3 percent 

discount rate (model average).3

In addition to the benefits of methane 

reductions, stakeholders and members 

of local communities across the country 

have reported to the EPA their 

significant concerns regarding potential 

adverse effects resulting from exposure 

to air toxics emitted from oil and natural 

gas operations. Importantly, this 

includes disadvantaged populations. 

The measures proposed in this action 

achieve methane and VOC reductions 

through direct regulation. The 

hazardous air pollutant (HAP) 

reductions from these proposed 

standards will be meaningful in local 

communities. In addition, reduction of 

VOC emissions will be very beneficial 

in areas where ozone levels approach or 

exceed the National Ambient Air 

Quality Standards for ozone. There have 

been measurements of increasing ozone 

levels in areas with concentrated oil and 

natural gas activity, including Wyoming 

and Utah. Several VOCs that commonly 

are emitted in the oil and natural gas 

source category are HAPs listed under 

Clean Air Act (CAA) section 112(b), 

including benzene, toluene, 

ethylbenzene and xylenes (this group is 

commonly referred to as ‘‘BTEX’’) and 

n-hexane. These pollutants and any 

other HAP included in the VOC 

emissions controlled under the NSPS, 

including requirements for additional 

sources being proposed in this action, 

are controlled to the same degree. The 

co-benefit HAP reductions for the 

measures being proposed are discussed 

in the Regulatory Impact Analysis (RIA) 

and in the Background Technical 

Support Document (TSD) which are 

included in the public docket for this 

action. 

The EPA estimates the total capital 

cost of the proposed NSPS will be $170 

to $180 million in 2020 and $280 to 

$330 million in 2025. The estimate of 

total annualized engineering costs of the 

proposed NSPS is $180 to $200 million 

in 2020 and $370 to $500 million in 

2025 when using a 7 percent discount 

rate. When estimated revenues from 

additional natural gas are included, the 

annualized engineering costs of the 

proposed NSPS are estimated to be $150 

to $170 million in 2020 and $320 to 

$420 million in 2025, assuming a 

wellhead natural gas price of $4/

thousand cubic feet (Mcf). These 

compliance cost estimates include 

revenues from recovered natural gas as 

the EPA estimates that about 8 billion 

cubic feet in 2020 and 16 to 19 billion 

cubic feet in 2025 of natural gas will be 

recovered by implementing the NSPS. 

Considering all the costs and benefits 

of this proposed rule, including the 

resources from recovered natural gas 

that would otherwise be vented, this 

rule results in a net benefit. The 

quantified net benefits (the difference 

between monetized benefits and 

compliance costs) are estimated to be 

$35 to $42 million in 2020 using a 3 

percent discount rate (model average) 

for climate benefits.4 The quantified net 

benefits are estimated to be $120 to $150 

million in 2025 using a 3 percent 

discount rate (model average) for 

climate benefits. All dollar amounts are 

in 2012 dollars. 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56597 

The EPA was unable to monetize all 

of the benefits anticipated to result from 

this proposal. The only benefits 

monetized for this rule are methanerelated climate benefits. However, there 

would be additional benefits from 

reducing VOC and HAP emissions, as 

well as additional benefits from 

reducing methane emissions because 

methane is a precursor to global 

background concentrations of ozone. A 

detailed discussion of these 

unquantified benefits are discussed in 

section XI of this document as well as 

in the RIA available in the docket. 

III. General Information 

A. Does this reconsideration notice 

apply to me? 

Categories and entities potentially 

affected by today’s notice include: 

TABLE 1—INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS ACTION

Category NAICS code 1 Examples of regulated entities 

Industry .................................................... 211111 Crude Petroleum and Natural Gas Extraction. 

211112 Natural Gas Liquid Extraction. 

221210 Natural Gas Distribution. 

486110 Pipeline Distribution of Crude Oil. 

486210 Pipeline Transportation of Natural Gas. 

Federal government ................................ .............................. Not affected. 

State/local/tribal government ................... .............................. Not affected. 

1 North American Industry Classification System. 

This table is not intended to be 

exhaustive, but rather is meant to 

provide a guide for readers regarding 

entities likely to be affected by this 

action. If you have any questions 

regarding the applicability of this action 

to a particular entity, consult either the 

air permitting authority for the entity or 

your EPA regional representative as 

listed in 40 CFR 60.4 or 40 CFR 63.13 

(General Provisions). 

B. What should I consider as I prepare 

my comments to the EPA? 

We seek comment only on the aspects 

of the new source performance 

standards for the oil and natural gas 

source category for the equipment, 

processes and activities specifically 

identified in this document. We are not 

opening for reconsideration any other 

provisions of the new source 

performance standards at this time. 

Do not submit information containing 

CBI to the EPA through 

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– 

2010–0505. 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, electronic copies of these 

proposed rules will be available on the 

Worldwide Web through the 

Technology Transfer Network (TTN). 

Following signature, a copy of each 

proposed rule will be posted on the 

TTN’s policy and guidance page for 

newly proposed or promulgated rules at 

the following address: http://

www.epa.gov/ttn/oarpg/. The TTN 

provides information and technology 

exchange in various areas of air 

pollution control. 

IV. Background 

A. Statutory Background 

Section 111 of the CAA requires the 

EPA Administrator to list categories of 

stationary sources that, in his or her 

judgment, cause or contribute 

significantly to air pollution which may 

reasonably be anticipated to endanger 

public health or welfare. The EPA must 

then issue ‘‘standards of performance’’ 

for new sources in such source 

categories. The EPA has the authority to 

define the source categories, determine 

the pollutants for which standards 

should be developed, and identify 

within each source category the 

facilities for which standards of 

performance would be established. 

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 BSER, is 

commonly a numerical emissions limit, 

expressed as a performance level (e.g., a 

rate-based standard). Generally, the EPA 

does not prescribe a particular 

technological system that must be used 

to comply with a standard of 

performance. Rather, sources generally 

can select any measure or combination 

of measures that will achieve the 

emissions level of the standard. 

Standards of performance under 

section 111 are issued for new, modified 

and reconstructed stationary sources. 

These standards are referred to as ‘‘new 

source performance standards.’’ The 

EPA has the authority to define the 

source categories, determine the 

pollutants for which standards should 

be developed, identify the facilities 

within each source category to be 

covered and set the emission level of the 

standards. 

CAA section 111(b)(1)(B) requires the 

EPA to ‘‘at least every 8 years review 

and, if appropriate, revise’’ performance 

standards unless the ‘‘Administrator 

determines that such review is not 

appropriate in light of readily available 

information on the efficacy’’ of the 

standard. When conducting a review of 

an existing performance standard, the 

EPA has discretion to revise that 

standard to add emission limits for 

pollutants or emission sources not 

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56598 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

5 IPCC, 2013: Climate Change 2013: The Physical 

Science Basis. Contribution of Working Group I to 

the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change 

[Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, 

S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex 

and P.M. Midgley (eds.)]. Cambridge University 

Press, Cambridge, United Kingdom and New York, 

NY, USA, 1535 pp. Note that for purposes of 

inventories and reporting, GWP values from the 4th 

Assessment Report may be used. 

currently regulated for that source 

category. 

B. What are the regulatory history and 

litigation background regarding 

performance standards for the oil and 

natural gas sector? 

In 1979, the EPA published a list of 

source categories, including ‘‘crude oil 

and natural gas production,’’ for which 

the EPA would promulgate standards of 

performance under section 111(b) of the 

CAA. See Priority List and Additions to 

the List of Categories of Stationary 

Sources, 44 FR 49222 (August 21, 1979) 

(‘‘1979 Priority List’’). That list 

included, in the order of priority for 

promulgating standards, source 

categories that the EPA Administrator 

had determined, pursuant to section 

111(b)(1)(A), contribute significantly to 

air pollution that may reasonably be 

anticipated to endanger public health or 

welfare. See 44 FR at 49223; see also, 49 

FR 2636, 2637. In 1979, the EPA listed 

crude oil and natural gas production on 

its priority list of source categories for 

promulgation of NSPS (44 FR 49222, 

August 21, 1979). 

On June 24, 1985 (50 FR 26122), the 

EPA promulgated an NSPS for the 

source category that addressed VOC 

emissions from leaking components at 

onshore natural gas processing plants 

(40 CFR part 60, subpart KKK). On 

October 1, 1985 (50 FR 40158), a second 

NSPS was promulgated for the source 

category that regulates sulfur dioxide 

(SO2) emissions from natural gas 

processing plants (40 CFR part 60, 

subpart LLL). In 2012, pursuant to its 

authority under section 111(b)(1)(B) to 

review and, if appropriate, revise NSPS, 

the EPA published the final rule, 

‘‘Standards of Performance for Crude 

Oil and Natural Gas Production, 

Transmission and Distribution’’ (40 CFR 

part 60, subpart OOOO)(‘‘2012 NSPS’’). 

The 2012 NSPS updated the VOC 

standards for equipment leaks at 

onshore natural gas processing plants. 

In addition, it established VOC 

standards for several oil and natural gasrelated operations not covered by 

subpart KKK, including gas well 

completions, centrifugal and 

reciprocating compressors, natural gasoperated pneumatic controllers and 

storage vessels. In 2013 and 2014, the 

EPA made certain amendments to the 

2012 NSPS in order to improve 

implementation of the standards (78 FR 

58416 and 79 FR 79018). The 2013 

amendments focused on storage vessel 

implementation issues; the 2014 

amendments provided clarification of 

well completion provisions which 

became fully effective on January 1, 

2015. The EPA received petitions for 

both judicial review and administrative 

reconsiderations for the 2012 NSPS as 

well as the subsequent amendments in 

2013 and 2014. The litigations are 

stayed pending the EPA’s 

reconsideration process. 

In this rulemaking, the EPA is 

granting reconsideration of a number of 

issues raised in the administrative 

reconsideration petitions and, where 

appropriate, is proposing amendments 

to address such issues. These issues, 

which mostly address implementation, 

are as follows: storage vessel control 

device monitoring and testing 

provisions, initial compliance 

requirements in § 60.5411(c)(3)(i)(A) for 

a bypass device that could divert an 

emission stream away from a control 

device, recordkeeping requirements of 

§ 60.5420(c) for repair logs for control 

devices failing a visible emissions test, 

clarification of the due date for the 

initial annual report under the 2012 

NSPS, emergency flare exemption from 

routine compliance tests, LDAR for 

open-ended valves or lines, compliance 

period for LDAR for newly affected 

process units, exemption to notification 

requirement for reconstruction of most 

types of facilities, and disposal of 

carbon from control devices. 

C. Events Leading to Today’s Action 

Several factors have led to today’s 

proposed action. First, the EPA in 2009 

found that six well-mixed GHGs— 

carbon dioxide, methane, nitrous oxide, 

hydrofluorocarbons, perfluorocarbons, 

and sulfur hexafluoride—endanger both 

the public health and the public welfare 

of current and future generations by 

causing or contributing to climate 

change. Oil and gas operations are 

significant emitters of methane. 

According to Greenhouse Gas Reporting 

Program (GHGRP) data, oil and gas 

operations are the second largest emitter 

of GHGs in the U.S. (when considering 

both methane emissions and 

combustion-related GHG emissions at 

oil and gas facilities), second only than 

fossil-fueled electricity generation. This 

endangerment finding is described in 

more detail in section VI. 

Second, on August 16, 2012, the EPA 

published the 2012 NSPS (77 FR 49490). 

The 2012 NSPS included VOC 

standards for a number of emission 

sources in the oil and natural gas source 

category. Based on information available 

at the time, the EPA also evaluated 

methane emissions and reductions 

during the 2012 NSPS rulemaking as a 

potential co-benefit from regulating 

VOC. Although information at the time 

indicated that methane emissions could 

be significant, the EPA did not take final 

action in the 2012 NSPS with respect to 

the regulation of methane; the EPA 

noted the impending collection of a 

large amount of GHG data for this 

industry through the GHGRP (40 CFR 

part 98) and expressed its intent to 

continue its evaluation of methane. As 

stated previously, the 2012 NSPS is the 

subject of a number of petitions for 

judicial review and administrative 

reconsideration. The litigation is 

currently stayed pending the EPA’s 

reconsideration process. Regulation of 

methane is an issue raised in several of 

the administrative petitions for the 

EPA’s reconsideration. 

Third, in June 2013, President Obama 

issued his Climate Action Plan which, 

among other actions, directed the EPA 

and five other federal agencies to 

develop a comprehensive interagency 

strategy to reduce methane emissions. 

The plan recognized that methane 

emissions constitute a significant 

percentage of domestic GHG emissions, 

highlighted reductions in methane 

emissions since 1990, and outlined 

specific actions that could be taken to 

achieve additional progress. 

Specifically, the federal agencies were 

instructed to focus on ‘‘assessing current 

emissions data, addressing data gaps, 

identifying technologies and best 

practices for reducing emissions and 

identifying existing authorities and 

incentive-based opportunities to reduce 

methane emissions.’’ 

Fourth, as a follow-up to the 2013 

Climate Action Plan, the Climate Action 

Plan: Strategy to Reduce Methane 

Emissions (the Methane Strategy) was 

released in March 2014. The focus on 

reducing methane emissions reflects the 

fact that methane is a potent GHG with 

a 100-year global warming potential 

(GWP) that is 28–36 times greater than 

that of carbon dioxide.5 Methane has an 

atmospheric life of about 12 years, and 

because of its potency as a GHG and its 

atmospheric life, reducing methane 

emissions is an important step that can 

be taken to achieve a near-term 

beneficial impact in mitigating global 

climate change. The Methane Strategy 

instructed the EPA to release a series of 

white papers on several potentially 

significant sources of methane in the oil 

and natural gas sector and to solicit 

input from independent experts. The 

papers were released in April 2014. 

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6Sierra Club et al., Petition for Reconsideration, 

In the Matter of: Final Rule Published at 77 FR 

49490 (Aug. 16, 2012), titled ‘‘Oil and Gas Sector: 

New Source Performance Standards and National 

Emission Standards for Hazardous Air Pollutants 

Reviews; Final Rule,’’ Docket No. EPA–HQ–OAR– 

2010–0505, RIN 2060–AP76 (2012). 

7See 42 U.S.C. § 7411(b) 

8The EPA often revises standards even where the 

revision will not lead to any additional reductions 

of a pollutant because another standard regulates a 

different pollutant using the same control 

equipment. For example, in 2014, the EPA revised 

the Kraft Pulp Mill NSPS in Part 60 Subpart BB 

(published at 70 FR 18952 (April 4, 2014) to align 

the NSPS standards with the NESHAP standards for 

those sources in Part 63 Subpart S. Although no 

previously unregulated sources were added to the 

Kraft Pulp Mill NSPS, several emission limits were 

adjusted downward. The revised NSPS did not 

achieve additional reductions beyond those 

achieved by the NESHAP, but eased compliance 

burden for the sources. 

They focused on technical issues, 

covering emissions and control 

technologies that reduce both VOC and 

methane, with particular focus on 

completions of hydraulically fractured 

oil wells, liquids unloading, leaks, 

pneumatic devices and compressors. 

The peer review process was completed 

on June 16, 2014. The EPA received 26 

submissions of peer review comments 

on these papers, and more than 43,000 

comments from the public. The 

comments received from the peer 

reviewers are available on EPA’s oil and 

natural gas white paper Web site (http:// 

www.epa.gov/airquality/oilandgas/

methane.html). Public comments on the 

white papers are available in EPA’s 

nonregulatory docket at 

www.regulations.gov, docket ID # EPA– 

HQ–OAR–2014–0557. The Methane 

Strategy also instructed the EPA to 

complete any new oil and natural gas 

regulations pertaining to the sources 

addressed in the white papers by the 

end of 2016. 

Finally, following the Climate Action 

Plan and Methane Strategy, in January 

2015, the Administration announced a 

new goal to cut methane emissions from 

the oil and gas sector (by 40–45 percent 

from 2012 levels by 2025) and steps to 

put the U.S. on a path to achieve this 

ambitious goal. These actions 

encompass both commonsense 

standards and cooperative engagement 

with states, tribes and industry. 

Building on prior actions by the 

Administration, and leadership in states 

and industry, the announcement laid 

out a plan for EPA to address, and if 

appropriate, propose and set 

commonsense standards for methane 

and ozone forming emissions from new 

and modified sources and issue Control 

Technique Guidelines (CTGs) to assist 

states in reducing ozone-forming 

pollutants from existing oil and gas 

systems in areas that do not meet the 

health-based standard for ozone. 

Building on the 2012 NSPS, the EPA 

intends to encourage corporate-wide 

efforts to achieve emission reductions 

through transparent and verifiable 

voluntary action that would obviate the 

burden associated with NSPS 

applicability. Throughout this proposal, 

we solicit comment on specific 

approaches that could provide incentive 

for owners and operators to design and 

implement programs to reduce fugitive 

emissions at their facilities. 

V. Why is the EPA Proposing to 

Establish Methane Standards in the Oil 

and Natural Gas NSPS? 

In a petition for reconsideration of the 

2012 NSPS, the petitioners urged that 

‘‘EPA must reconsider its failure adopt 

standards for the methane pollution 

released by the oil and gas sector.’’ 6

Upon reconsidering the issue, and on 

the basis of the wealth of additional 

information now available to us, the 

EPA is proposing to establish methane 

standards for facilities throughout the 

oil and natural gas source category. 

The EPA has discretion under CAA 

section 111(b) to determine which 

pollutants emitted from a listed source 

category warrant regulation.7 In making 

such determination, we have generally 

considered a number of factors to help 

inform our decision (We discuss 

considerations specific to individual 

emission source types in section VIII as 

part of the BSER analyses and rationale 

for regulating the sources). These factors 

include the amount such pollutant is 

being emitted from the source category, 

the availability of technically feasible 

control options and the costs of such 

control options. As we previously 

explained, ‘‘we have historically 

declined to propose standards for a 

pollutant where it is emitting (sic) in 

low amounts or where we determined 

that a [control analysis] would result in 

no control’’ device being used. 75 FR 

54970, 54997 (Sep. 9, 2010). Our 

consideration of these factors are 

provided below and in more detail in 

sections VI and VIII. 

The oil and natural gas industry is 

one of the largest emitters of methane, 

a GHG with a global warming potential 

more than 25 times greater than that of 

carbon dioxide. During the 2012 oil and 

natural gas NSPS rulemaking, while we 

had considerable amount of data and 

understanding on VOC emissions from 

the oil and natural gas industry and the 

available control options, data on 

methane emissions were just emerging. 

In light of the rapid expansion of this 

industry and the growing concern with 

the associated emissions, the EPA 

proceeded to establish a number of VOC 

standards in the 2012 NSPS but 

indicated in that rulemaking an intent to 

revisit methane at a later date when 

additional information was available 

from the GHGRP. We have since 

received and evaluated such data, 

which confirm that the oil and natural 

gas industry is one of the largest 

emitters of methane. As discussed in 

section VI, the current methane 

emissions from this industry contribute 

substantially to nationwide GHG 

emissions. These emissions are 

expected to increase as a result of the 

rapid growth of this industry. While the 

VOC standards in the 2012 NSPS also 

reduce methane emissions, in light of 

the current and projected future 

methane emissions from the oil and 

natural gas industry, reducing methane 

emissions from this source category 

cannot be treated simply as an 

incidental benefit to VOC reduction; 

rather, it is something that should be 

directly addressed through standards for 

methane under section 111(b) based on 

direct evaluation of the extent and 

impact of methane emissions from this 

source category and the best system for 

their reduction. Such standards, which 

would be reviewed and, if appropriate, 

revised at least every eight years, would 

achieve meaningful methane reductions 

and, as such, would be an important 

step towards mitigating the impact of 

GHG emissions on climate change. In 

addition, while many of the currently 

regulated emission sources are 

equipment used throughout the oil and 

natural gas industry (e.g., pneumatic 

controllers, compressors) and emit both 

VOC and methane, the current VOC 

standards apply only to a subset of these 

equipment based on VOC-only 

evaluation. However, as shown in 

section VIII, there are cost-effective 

controls that can simultaneously reduce 

both methane and VOC emissions from 

these equipment across the industry, 

which in some instances would not 

occur were we to focus solely on VOC 

reductions. Revising the NSPS to 

establish both methane and VOC 

standards for all such equipment across 

the industry would also promote 

consistency by providing the same 

regulatory regime for these equipment 

throughout the oil and natural gas 

source category, thereby facilitating 

implementation and enforcement.8

As mentioned above, we also we 

consider whether there are technically 

feasiable control options that can be 

applied nationally to sources to mitigate 

emissions of a pollutant and whether 

the costs of such controls are 

reasonable. As discussed in detail in 

section VIII, we have identified 

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9The process of producing natural gas for 

distribution involves operations in the various 

segments of the natural gas industry described 

above. In contrast, oil production involves drilling/ 

extracting oil, which is immediately followed by 

distribution offsite to be made into different 

products. 

10See Standards of Performance for New 

Stationary Sources, 43 FR 38872, August 31, 1978, 

and Priority List and Additions to the List of 

Categories of Stationary Sources, 44 FR 49222, 

August 21, 1979. 

11The crude oil production segment of the source 

category, which includes the well and extends to 

the point of custody transfer to the crude oil 

transmission pipeline, is more limited in scope than 

the segments of the natural gas value chain 

included in the source category. However, increases 

in production at the well and/or increases in the 

number of wells coming on line, in turn increase 

throughput and resultant emissions, similarly to the 

natural gas segments in the source category. 

technically feasible controls that can be 

applied nationally to reduce methane 

emissions and thus GHG emissions from 

the oil and natural gas source category. 

We consider whether the costs (e.g., 

capital costs, operating costs) are 

reasonable considering the emission 

reductions achieved through application 

of the controls that would be required 

by the proposed rule. As discussed in 

detail in section VIII, for the oil and 

natural gas source category, the 

available controls for reducing methane 

emissions simultaneously control VOC 

emissions and vice versa. Accordingly, 

the available controls are the same for 

reducing methane and VOC from the 

individual oil and natural gas emission 

sources. For a detailed discussion on 

how we evaluated control costs and our 

cost analysis for individual emission 

sources, please see section VIII. As 

shown in that section, there are costeffective controls for reducing methane 

emissions from the oil and natural gas 

source category. 

Based on our consideration of the 

three factors, the EPA is proposing to 

revise the NSPS to regulate directly 

GHG emissions in addition to VOC 

emissions across the oil and natural gas 

source category. The proposed 

standards include adding methane 

standards to certain sources currently 

regulated for VOC, as well as methane 

and VOC standards for additional 

emission sources. Specifically, 

• Well completions: We are 

proposing to revise the current NSPS to 

regulate both methane and VOC 

emissions from well completions of all 

hydraulically fractured wells (i.e., gas 

wells and oil wells); 

• Fugitive emissions: We are 

proposing standards to reduce methane 

and VOC emissions from fugitive 

emission components at well sites and 

compressor stations; 

• Pneumatic pumps: We are 

proposing methane and VOC standards; 

• Pneumatic controllers, centrifugal 

compressors, and reciprocating 

compressors (industry-wide, except for 

well site compressors, of which only a 

subset of those equipment are regulated 

currently): We are proposing to establish 

methane and VOC standards across the 

industry by adding methane standards 

to those currently subject to VOC 

standard and VOC and methane 

standards for all the others. 

• Equipment leaks at natural gas 

processing plants: We are proposing to 

add methane standards. 

For a detailed description of the 

proposed standards, please see section 

VII. For the BSER analyses that serve as 

the bases for the proposed standards, 

please see section VIII. 

VI. The Oil and Natural Gas Source 

Category Listing Under CAA Section 

111(b)(1)(A) 

Section 111(b)(1)(A) of the CAA, 

which Congress enacted as part of the 

1970 CAA Amendments, requires the 

EPA to promulgate a list of categories of 

stationary sources that the 

Administrator, in his or her judgment, 

finds ‘‘causes, or contributes 

significantly to, air pollution which may 

reasonably be anticipated to endanger 

public health or welfare.’’ In 1979, the 

EPA published a list of source 

categories, including ‘‘crude oil and 

natural gas production,’’ for which the 

EPA would promulgate standards of 

performance under section 111(b) of the 

CAA. Priority List and Additions to the 

List of Categories of Stationary Sources, 

44 FR 49222 (August 21, 1979) (‘‘1979 

Priority List’’). That list included, in the 

order of priority for promulgating 

standards, source categories that the 

EPA Administrator had determined, 

pursuant to section 111(b)(1)(A), to 

contribute significantly to air pollution 

that may reasonably be anticipated to 

endanger public health or welfare. See 

44 FR 49222; see also, 49 FR 2636, 2637. 

As mentioned above, one of the 

source categories listed in that 1979 

rulemaking related to the oil and natural 

gas industry. The EPA interprets the 

listing that resulted from that 

rulemaking as generally covering the oil 

and natural gas industry. Specifically, 

with respect to the natural gas industry, 

it includes production, processing, 

transmission, and storage. The EPA 

believes that the intent of the 1979 

listing was to broadly cover the natural 

gas industry.9 This intent was evident in 

the EPA’s analysis at the time of 

listing.10 For example, the priority list 

analysis indicated that the EPA 

evaluated emissions beyond the natural 

gas production segment to include 

emissions from natural gas processing 

plants. The analysis also showed that 

the EPA evaluated equipment, such as 

stationary pipeline compressor engines, 

that are used in various segments of the 

natural gas industry. The EPA’s 

interpretation of the 1979 listing is 

further supported by the Agency’s 

pronouncements during the NSPS 

rulemaking that followed the listing. 

Specifically, in its description of this 

listed source category in the 1984 

preamble to the proposed NSPS for 

equipment leaks at natural gas 

processing plants, the EPA described 

the major emission points of this source 

category to include process, storage and 

equipment leaks; these emissions can be 

found throughout the various segments 

of the natural gas industry. 49 FR at 

2637. There are also good reasons for 

treating various segments of the natural 

gas industry as one source category. 

Operations at production, processing, 

transmission and storage facilities are a 

sequence of functions that are 

interrelated and necessary for getting 

the recovered gas ready for 

distribution.11 Because they are 

interrelated, segments that follow others 

are faced with increases in throughput 

caused by growth in throughput of the 

segments preceding (i.e., feeding) them. 

For example, the relatively recent 

substantial increases in natural gas 

production brought about by hydraulic 

fracturing and horizontal drilling result 

in increases in the amount of natural gas 

needing to be processed and moved to 

market or stored. These increases in 

production and throughput can cause 

increases in emissions across the entire 

natural gas industry. We also note that 

some equipment (e.g., storage vessels, 

compressors) are used across the oil and 

natural gas industry, which further 

supports considering the industry as 

one source category. For the reasons 

stated above, the EPA interprets the 

1979 listing broadly to include the 

various segments of the natural gas 

industry (production, processing, 

transmission, and storage). 

Since the 1979 listing, EPA has 

promulgated performance standards to 

regulate SO2 emissions from natural gas 

processing and VOC emissions from the 

oil and natural gas industry. In this 

action, the EPA is proposing to further 

regulate VOC emissions as well as 

proposing performance standards for 

methane emissions from this industry. 

With respect to the latter, the EPA 

identifies the air pollutant that it 

proposes to regulate as the pollutant 

GHGs (which consist of the six wellmixed gases, consistent with other 

actions the EPA has taken under the 

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12See additional discussion at 79 FR 1430, 1452 

(Jan 8, 2014). 

13For the oil industry, the listing includes 

production, as explained above in footnote 10. 

CAA), although only methane will be 

reduced directly by the proposed 

standards. 

As mentioned above, in the 1979 

category listing, section 111(b)(1)(A) 

does not require another determination 

as a prerequisite for regulating a 

particular pollutant. Rather, once the 

EPA has determined that the source 

category causes, or contributes 

significantly to, air pollution that may 

reasonably be anticipated to endanger 

public health or welfare, and has listed 

the source category on that basis, the 

EPA interprets section 111(b)(1)(A) to 

provide authority to establish a standard 

for performance for any pollutant 

emitted by that source category as long 

as the EPA has a rational basis for 

setting a standard for the pollutant.12

The EPA believes that the information 

included below in this section provides 

a rational basis for the methane 

standards it is proposing in this action. 

First, because the EPA is not listing a 

new source category in this rule, the 

EPA is not required to make a new 

endangerment finding with regard to oil 

and natural gas source category in order 

to establish standards of performance 

for the methane from those sources. 

Under the plain language of CAA 

section 111(b)(1)(A), an endangerment 

finding is required only to list a source 

category. Further, though the 

endangerment finding is based on 

determinations as to the health or 

welfare impacts of the pollution to 

which the source category’s pollutants 

contribute, and as to the significance of 

the amount of such contribution, the 

statute is clear that the endangerment 

finding is made with respect to the 

source category; section 111(b)(1)(A) 

does not provide that an endangerment 

finding is made as to specific pollutants. 

This contrasts with other CAA 

provisions that do require the EPA to 

make endangerment findings for each 

particular pollutant that the EPA 

regulates under those provisions. E.g., 

CAA sections 202(a)(1), 211(c)(1), 

231(a)(2)(A). See American Electric 

Power v. Connecticut, 131 S. Ct. 2527, 

2539 (2011) (‘‘the Clean Air Act directs 

EPA to establish emissions standards for 

categories of stationary sources that, ‘in 

[the Administrator’s] judgment,’ 

‘caus[e], or contribut[e] significantly to, 

air pollution which may reasonably be 

anticipated to endanger public health or 

welfare.’ § 7411(b)(1)(A).’’) (emphasis 

added). 

Second, once a source category is 

listed, the CAA does not specify what 

pollutants should be the subject of 

standards from that source category. The 

statute, in section 111(b)(1)(B), simply 

directs the EPA to propose and then 

promulgate regulations ‘‘establishing 

Federal standards of performance for 

new sources within such category.’’ In 

the absence of specific direction or 

enumerated criteria in the statute 

concerning what pollutants from a given 

source category should be the subject of 

standard, it is appropriate for EPA to 

exercise its authority to adopt a 

reasonable interpretation of this 

provision. Chevron U.S.A. Inc. v. NRDC, 

467 U.S. 837, 843–44 (1984). 

The EPA has previously interpreted 

this provision as granting it the 

discretion to determine which 

pollutants should be regulated. See 

Standards of Performance for Petroleum 

Refineries, 73 FR 35838, 35858 (col. 3) 

(June 24, 2008) (concluding the statute 

provides ‘‘the Administrator with 

significant flexibility in determining 

which pollutants are appropriate for 

regulation under section 111(b)(1)(B)’’ 

and citing cases). Further, in directing 

the Administrator to propose and 

promulgate regulations under section 

111(b)(1)(B), Congress provided that the 

Administrator should take comment and 

then finalize the standards with such 

modifications ‘‘as he deems 

appropriate.’’ The DC Circuit has 

considered similar statutory phrasing 

from CAA section 231(a)(3) and 

concluded that ‘‘[t]his delegation of 

authority is both explicit and 

extraordinarily broad.’’ National Assoc. 

of Clean Air Agencies v. EPA, 489 F.3d 

1221, 1229 (D.C. Cir. 2007). 

In exercising its discretion with 

respect to which pollutants are 

appropriate for regulation under section 

111(b)(1)(B), the EPA has in the past 

provided a rational basis for its 

decisions. See National Lime Assoc. v. 

EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 

1980) (court discussed, but did not 

review, the EPA’s reasons for not 

promulgating standards for NOX, SO2

and CO from lime plants’’); Standards of 

Performance for Petroleum Refineries, 

73 FR at 35859–60 (June 24, 2008) 

(providing reasons why the EPA was not 

promulgating GHG standards for 

petroleum refineries as part of that rule). 

Though these previous examples 

involved the EPA providing a rational 

basis for not setting standards for a 

given pollutant, a similar approach is 

appropriate where the EPA determines 

that it should set a standard for an 

additional pollutant for a source 

category that was previously listed and 

regulated for other pollutants. 

While the EPA believes that the 1979 

listing of this source category provides 

sufficient authority for this action, to the 

extent that there is any ambiguity in the 

prior listing, the information provided 

here should be considered to constitute 

the requisite conclusions related to the 

category listing. Were EPA to formally 

seek to revise the category listing to 

broadly include the oil and natural gas 

industry (i.e., production, processing, 

transmission, and storage) 13, we believe 

this information discussed here fully 

suffices to support it as a source 

category that, in the Administrator’s 

judgment, contributes significantly to 

air pollution which may reasonably be 

anticipated to endanger public health or 

welfare. Furthermore, for the reason 

stated below, EPA’s previous 

determination under section 

111(b)(1)(A) is sufficient to support the 

proposed revision to the category listing 

as well as the proposed standards in this 

action. During the 1979 listing, EPA had 

determined that, at least a part of the oil 

and natural gas industry contributes 

significantly to air pollution which may 

reasonably be anticipated to endanger 

public health or welfare. Such health 

and welfare impacts could only increase 

when considering the broader industry 

(assuming it had not already been 

considered in the 1979 listing). To 

further support the conclusion related to 

this category listing, EPA has included 

below in this section information and 

analyses regarding the public health and 

welfare impacts from GHG, VOC and 

SO2 emissions, three of the primary 

pollutants emitted from the oil and 

natural gas industry, and the estimated 

emissions of these pollutants from the 

oil and natural gas source category. It is 

evident from this information and 

analyses that the oil and natural gas 

source category contributes significantly 

to air pollution which may reasonably 

be anticipated to endanger public health 

or welfare. 

Provided below are the supporting 

information and analyses. Specifically, 

section VI.A describes the public health 

and welfare impacts from GHG, VOC 

and SO2. Section VI.B analyzes the 

emission contribution of these three 

pollutants by the oil and natural gas 

industry. 

A. Impacts of GHG, VOC and SO2

Emissions on Public Health and Welfare 

The oil and natural gas industry emits 

a wide range of pollutants, including 

GHGs (such as methane and CO2), VOC, 

SO2, NOX, H2S, CS2 and COS. See 49 FR 

2636, at 2637 (Jan 20, 1984). Although 

all of these pollutants have significant 

impacts on public health and welfare, 

an analysis of every one of these 

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56602 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

14We note that EPA’s focus on GHG (in particular 

methane), VOC and SO2 in these analyses, does not 

in any way limit the EPA’s authority to promulgate 

standards that would apply to other pollutants 

emitted from the oil and natural gas source 

category, if the EPA determines that such action is 

appropriate. 

15 ‘‘Endangerment and Cause or Contribute 

Findings for Greenhouse Gases Under Section 

202(a) of the Clean Air Act,’’ 74 FR 66496 (Dec. 15, 

2009) (‘‘Endangerment Finding’’). 

pollutants is not necessary for the 

Administrator to make a determination 

under section 111(b)(1)(A); as shown 

below, the EPA’s analysis of GHG, VOC, 

and SO2, three of the primary emissions 

from the oil and natural gas source 

category, alone are sufficient for the 

Administrator to determine under 

section 111(b)(1)(A) that the oil and 

natural gas source category contributes 

significantly to air pollution which may 

reasonably be anticipated to endanger 

public health and welfare.14

1. Climate Change Impacts from GHG 

Emissions 

In 2009, based on a large body of 

robust and compelling scientific 

evidence, the EPA Administrator issued 

the Endangerment Finding under CAA 

section 202(a)(1).15 In the Endangerment 

Finding, the Administrator found that 

the current, elevated concentrations of 

GHGs in the atmosphere—already at 

levels unprecedented in human 

history—may reasonably be anticipated 

to endanger public health and welfare of 

current and future generations in the 

United States. We summarize these 

adverse effects on public health and 

welfare briefly here. 

a. Public Health Impacts Detailed in the 

2009 Endangerment Finding 

Climate change caused by human 

emissions of GHGs threatens the health 

of Americans in multiple ways. By 

raising average temperatures, climate 

change increases the likelihood of heat 

waves, which are associated with 

increased deaths and illnesses. While 

climate change also increases the 

likelihood of reductions in cold-related 

mortality, evidence indicates that the 

increases in heat mortality will be larger 

than the decreases in cold mortality in 

the United States. Compared to a future 

without climate change, climate change 

is expected to increase ozone pollution 

over broad areas of the U.S., especially 

on the highest ozone days and in the 

largest metropolitan areas with the 

worst ozone problems, and thereby 

increase the risk of morbidity and 

mortality. Climate change is also 

expected to cause more intense 

hurricanes and more frequent and 

intense storms and heavy precipitation, 

with impacts on other areas of public 

health, such as the potential for 

increased deaths, injuries, infectious 

and waterborne diseases, and stressrelated disorders. Children, the elderly, 

and the poor are among the most 

vulnerable to these climate-related 

health effects. 

b. Public Welfare Impacts Detailed in 

the 2009 Endangerment Finding 

Climate change impacts touch nearly 

every aspect of public welfare. Among 

the multiple threats caused by human 

emissions of GHGs, climate changes are 

expected to place large areas of the 

country at serious risk of reduced water 

supplies, increased water pollution, and 

increased occurrence of extreme events 

such as floods and droughts. Coastal 

areas are expected to face a multitude of 

increased risks, particularly from rising 

sea level and increases in the severity of 

storms. These communities face storm 

and flooding damage to property, or 

even loss of land due to inundation, 

erosion, wetland submergence and 

habitat loss. 

Impacts of climate change on public 

welfare also include threats to social 

and ecosystem services. Climate change 

is expected to result in an increase in 

peak electricity demand, Extreme 

weather from climate change threatens 

energy, transportation, and water 

resource infrastructure. Climate change 

may also exacerbate ongoing 

environmental pressures in certain 

settlements, particularly in Alaskan 

indigenous communities, and is very 

likely to fundamentally rearrange U.S. 

ecosystems over the 21st century. 

Though some benefits may balance 

adverse effects on agriculture and 

forestry in the next few decades, the 

body of evidence points towards 

increasing risks of net adverse impacts 

on U.S. food production, agriculture and 

forest productivity as temperature 

continues to rise. These impacts are 

global and may exacerbate problems 

outside the U.S. that raise humanitarian, 

trade, and national security issues for 

the U.S. 

c. New Scientific Assessments and 

Observations 

Since the administrative record 

concerning the Endangerment Finding 

closed following the EPA’s 2010 

Reconsideration Denial, the climate has 

continued to change, with new records 

being set for a number of climate 

indicators such as global average surface 

temperatures, Arctic sea ice retreat, CO2

concentrations, and sea level rise. 

Additionally, a number of major 

scientific assessments have been 

released that improve understanding of 

the climate system and strengthen the 

case that GHGs endanger public health 

and welfare both for current and future 

generations. These assessments, from 

the Intergovernmental Panel on Climate 

Change (IPCC), the U.S. Global Change 

Research Program (USGCRP), and the 

National Research Council of the 

National Academies (NRC), include: 

IPCC’s 2012 Special Report on 

Managing the Risks of Extreme Events 

and Disasters to Advance Climate 

Change Adaptation (SREX) and the 

2013–2014 Fifth Assessment Report 

(AR5), USGCRP’s 2014 National Climate 

Assessment, Climate Change Impacts in 

the United States (NCA3), and the 

NRC’s 2010 Ocean Acidification: A 

National Strategy to Meet the 

Challenges of a Changing Ocean (Ocean 

Acidification), 2011 Report on Climate 

Stabilization Targets: Emissions, 

Concentrations, and Impacts over 

Decades to Millennia (Climate 

Stabilization Targets), 2011 National 

Security Implications for U.S. Naval 

Forces (National Security Implications), 

2011 Understanding Earth’s Deep Past: 

Lessons for Our Climate Future 

(Understanding Earth’s Deep Past), 2012 

Sea Level Rise for the Coasts of 

California, Oregon, and Washington: 

Past, Present, and Future, 2012 Climate 

and Social Stress: Implications for 

Security Analysis (Climate and Social 

Stress), and 2013 Abrupt Impacts of 

Climate Change (Abrupt Impacts) 

assessments. 

The EPA has carefully reviewed these 

recent assessments in keeping with the 

same approach outlined in Section 

VIII.A. of the 2009 Endangerment 

Finding, which was to rely primarily 

upon the major assessments by the 

USGCRP, IPCC, and the NRC to provide 

the technical and scientific information 

to inform the Administrator’s judgment 

regarding the question of whether GHGs 

endanger public health and welfare. 

These assessments addressed the 

scientific issues that the EPA was 

required to examine were 

comprehensive in their coverage of the 

GHG and climate change issues, and 

underwent rigorous and exacting peer 

review by the expert community, as 

well as rigorous levels of U.S. 

government review. 

The findings of the recent scientific 

assessments confirm and strengthen the 

conclusion that GHGs endanger public 

health, now and in the future. The 

NCA3 indicates that human health in 

the United States will be impacted by 

‘‘increased extreme weather events, 

wildfire, decreased air quality, threats to 

mental health, and illnesses transmitted 

by food, water, and disease-carriers such 

as mosquitoes and ticks.’’ The most 

recent assessments now have greater 

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16 IPCC, 2014: Climate Change 2014: Impacts, 

Adaptation, and Vulnerability. Part B: Regional 

Aspects. Contribution of Working Group II to the 

Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change [Barros, V.R., C.B. Field, 

D.J. Dokken, M.D. Mastrandrea, K.J. Mach, T.E. 

Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. 

Genova, B. Girma, E.S. Kissel, A.N. Levy, S. 

MacCracken, P.R. Mastrandrea, and L.L. White 

(eds.)]. Cambridge University Press, Cambridge, p. 

1581. 

17National Research Council, Understanding 

Earth’s Deep Past, p. 1. 

18 Id., p. 138. 

confidence that climate change will 

influence production of pollen that 

exacerbates asthma and other allergic 

respiratory diseases such as allergic 

rhinitis, as well as effects on 

conjunctivitis and dermatitis. Both the 

NCA3 and the IPCC AR5 found that 

increasing temperature has lengthened 

the allergenic pollen season for 

ragweed, and that increased CO2 by 

itself can elevate production of plantbased allergens. 

The NCA3 also finds that climate 

change, in addition to chronic stresses 

such as extreme poverty, is negatively 

affecting indigenous peoples’ health in 

the United States through impacts such 

as reduced access to traditional foods, 

decreased water quality, and increasing 

exposure to health and safety hazards. 

The IPCC AR5 finds that climate 

change-induced warming in the Arctic 

and resultant changes in environment 

(e.g., permafrost thaw, effects on 

traditional food sources) have 

significant impacts, observed now and 

projected, on the health and well-being 

of Arctic residents, especially 

indigenous peoples. Small, remote, 

predominantly-indigenous communities 

are especially vulnerable given their 

‘‘strong dependence on the environment 

for food, culture, and way of life; their 

political and economic marginalization; 

existing social, health, and poverty 

disparities; as well as their frequent 

close proximity to exposed locations 

along ocean, lake, or river 

shorelines.’’ 16 In addition, increasing 

temperatures and loss of Arctic sea ice 

increases the risk of drowning for those 

engaged in traditional hunting and 

fishing. 

The NCA3 concludes that children’s 

unique physiology and developing 

bodies contribute to making them 

particularly vulnerable to climate 

change. Impacts on children are 

expected from heat waves, air pollution, 

infectious and waterborne illnesses, and 

mental health effects resulting from 

extreme weather events. The IPCC AR5 

indicates that children are among those 

especially susceptible to most allergic 

diseases, as well as health effects 

associated with heat waves, storms, and 

floods. The IPCC finds that additional 

health concerns may arise in low 

income households, especially those 

with children, if climate change reduces 

food availability and increases prices, 

leading to food insecurity within 

households. 

Both the NCA3 and IPCC AR5 

conclude that climate change will 

increase health risks facing the elderly. 

Older people are at much higher risk of 

mortality during extreme heat events. 

Pre-existing health conditions also make 

older adults susceptible to cardiac and 

respiratory impacts of air pollution and 

to more severe consequences from 

infectious and waterborne diseases. 

Limited mobility among older adults 

can also increase health risks associated 

with extreme weather and floods. 

The new assessments also confirm 

and strengthen the conclusion that 

GHGs endanger public welfare, and 

emphasize the urgency of reducing GHG 

emissions due to their projections that 

show GHG concentrations climbing to 

ever-increasing levels in the absence of 

mitigation. The NRC assessment 

Understanding Earth’s Deep Past 

projected that, without a reduction in 

emissions, CO2 concentrations by the 

end of the century would increase to 

levels that the Earth has not experienced 

for more than 30 million years.17 In fact, 

that assessment stated that ‘‘the 

magnitude and rate of the present GHG 

increase place the climate system in 

what could be one of the most severe 

increases in radiative forcing of the 

global climate system in Earth 

history.’’ 18 Because of these 

unprecedented changes, several 

assessments state that we may be 

approaching critical, poorly understood 

thresholds: As stated in the NRC 

assessment Understanding Earth’s Deep 

Past, ‘‘As Earth continues to warm, it 

may be approaching a critical climate 

threshold beyond which rapid and 

potentially permanent—at least on a 

human timescale—changes not 

anticipated by climate models tuned to 

modern conditions may occur.’’ The 

NRC Abrupt Impacts report analyzed 

abrupt climate change in the physical 

climate system and abrupt impacts of 

ongoing changes that, when thresholds 

are crossed, can cause abrupt impacts 

for society and ecosystems. The report 

considered destabilization of the West 

Antarctic Ice Sheet (which could cause 

3–4 m of potential sea level rise) as an 

abrupt climate impact with unknown 

but probably low probability of 

occurring this century. The report 

categorized a decrease in ocean oxygen 

content (with attendant threats to 

aerobic marine life); increase in 

intensity, frequency, and duration of 

heat waves; and increase in frequency 

and intensity of extreme precipitation 

events (droughts, floods, hurricanes, 

and major storms) as climate impacts 

with moderate risk of an abrupt change 

within this century. The NRC Abrupt 

Impacts report also analyzed the threat 

of rapid state changes in ecosystems and 

species extinctions as examples of an 

irreversible impact that is expected to be 

exacerbated by climate change. Species 

at most risk include those whose 

migration potential is limited, whether 

because they live on mountaintops or 

fragmented habitats with barriers to 

movement, or because climatic 

conditions are changing more rapidly 

than the species can move or adapt. 

While the NRC determined that it is not 

presently possible to place exact 

probabilities on the added contribution 

of climate change to extinction, they did 

find that there was substantial risk that 

impacts from climate change could, 

within a few decades, drop the 

populations in many species below 

sustainable levels thereby committing 

the species to extinction. Species within 

tropical and subtropical rainforests such 

as the Amazon and species living in 

coral reef ecosystems were identified by 

the NRC as being particularly vulnerable 

to extinction over the next 30 to 80 

years, as were species in high latitude 

and high elevation regions. Moreover, 

due to the time lags inherent in the 

Earth’s climate, the NRC Climate 

Stabilization Targets assessment notes 

that the full warming from increased 

GHG concentrations will not be fully 

realized for several centuries, 

underscoring that emission activities 

today carry with them climate 

commitments far into the future. 

Future temperature changes will 

depend on what emission path the 

world follows. In its high emission 

scenario, the IPCC AR5 projects that 

global temperatures by the end of the 

century will likely be 2.6 °C to 4.8 °C 

(4.7 to 8.6 °F) warmer than today. 

Temperatures on land and in northern 

latitudes will likely warm even faster 

than the global average. However, 

according to the NCA3, significant 

reductions in emissions would lead to 

noticeably less future warming beyond 

mid-century, and therefore less impact 

to public health and welfare. 

While rainfall may only see small 

globally and annually averaged changes, 

there are expected to be substantial 

shifts in where and when that 

precipitation falls. According to the 

NCA3, regions closer to the poles will 

see more precipitation, while the dry 

subtropics are expected to expand 

(colloquially, this has been summarized 

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19NRC, 2011: National Security Implications of 

Climate Change for U.S. Naval Forces. The National 

Academies Press, p. 28. 

20Melillo, Jerry M., Terese (T.C.) Richmond, and 

Gary W. Yohe, Eds., 2014: Climate Change Impacts 

in the United States: The Third National Climate 

Assessment. U.S. Global Change Research Program, 

p. 9. 

21 Melillo, Jerry M., Terese (T.C.) Richmond, and 

Gary W. Yohe, Eds., 2014: Climate Change Impacts 

in the United States: The Third National Climate 

Assessment. U.S. Global Change Research Program, 

p. 17. 

22 IPCC, 2014: Climate Change 2014: Impacts, 

Adaptation, and Vulnerability. Part A: Global and 

Sectoral Aspects. Contribution of Working Group II 

to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Field, 

C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. 

Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. 

Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 

Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, p. 796. 

as wet areas getting wetter and dry 

regions getting drier). In particular, the 

NCA3 notes that the western U.S., and 

especially the Southwest, is expected to 

become drier. This projection is 

consistent with the recent observed 

drought trend in the West. At the time 

of publication of the NCA, even before 

the last 2 years of extreme drought in 

California, tree ring data were already 

indicating that the region might be 

experiencing its driest period in 800 

years. Similarly, the NCA3 projects that 

heavy downpours are expected to 

increase in many regions, with 

precipitation events in general 

becoming less frequent but more 

intense. This trend has already been 

observed in regions such as the 

Midwest, Northeast, and upper Great 

Plains. Meanwhile, the NRC Climate 

Stabilization Targets assessment found 

that the area burned by wildfire is 

expected to grow by 2 to 4 times for 1 

°C (1.8 °F) of warming. For 3 °C of 

warming, the assessment found that 9 

out of 10 summers would be warmer 

than all but the 5 percent of warmest 

summers today, leading to increased 

frequency, duration, and intensity of 

heat waves. Extrapolations by the NCA 

also indicate that Arctic sea ice in 

summer may essentially disappear by 

mid-century. Retreating snow and ice, 

and emissions of carbon dioxide and 

methane released from thawing 

permafrost, will also amplify future 

warming. 

Since the 2009 Endangerment 

Finding, the USGCRP NCA3, and 

multiple NRC assessments have 

projected future rates of sea level rise 

that are 40 percent larger to more than 

twice as large as the previous estimates 

from the 2007 IPCC 4th Assessment 

Report due in part to improved 

understanding of the future rate of melt 

of the Antarctic and Greenland ice 

sheets. The NRC Sea Level Rise 

assessment projects a global sea level 

rise of 0.5 to 1.4 meters (1.6 to 4.6 feet) 

by 2100, the NRC National Security 

Implications assessment suggests that 

‘‘the Department of the Navy should 

expect roughly 0.4 to 2 meters (1.3 to 6.6 

feet) global average sea-level rise by 

2100,’’ 19 and the NRC Climate 

Stabilization Targets assessment states 

that an increase of 3 °C will lead to a sea 

level rise of 0.5 to 1 meter (1.6 to 3.3 

feet) by 2100. These assessments 

continue to recognize that there is 

uncertainty inherent in accounting for 

ice sheet processes. Additionally, local 

sea level rise can differ from the global 

total depending on various factors: The 

east coast of the U.S. in particular is 

expected to see higher rates of sea level 

rise than the global average. For 

comparison, the NCA3 states that ‘‘five 

million Americans and hundreds of 

billions of dollars of property are 

located in areas that are less than four 

feet above the local high-tide level,’’ and 

the NCA3 finds that ‘‘[c]oastal 

infrastructure, including roads, rail 

lines, energy infrastructure, airports, 

port facilities, and military bases, are 

increasingly at risk from sea level rise 

and damaging storm surges.’’ 20 Also, 

because of the inertia of the oceans, sea 

level rise will continue for centuries 

after GHG concentrations have 

stabilized (though more slowly than it 

would have otherwise). Additionally, 

there is a threshold temperature above 

which the Greenland ice sheet will be 

committed to inevitable melting: 

According to the NCA, some recent 

research has suggested that even present 

day carbon dioxide levels could be 

sufficient to exceed that threshold. 

In general, climate change impacts are 

expected to be unevenly distributed 

across different regions of the United 

States and have a greater impact on 

certain populations, such as indigenous 

peoples and the poor. The NCA3 finds 

climate change impacts such as the 

rapid pace of temperature rise, coastal 

erosion and inundation related to sea 

level rise and storms, ice and snow 

melt, and permafrost thaw are affecting 

indigenous people in the United States. 

Particularly in Alaska, critical 

infrastructure and traditional 

livelihoods are threatened by climate 

change and, ‘‘[i]n parts of Alaska, 

Louisiana, the Pacific Islands, and other 

coastal locations, climate change 

impacts (through erosion and 

inundation) are so severe that some 

communities are already relocating from 

historical homelands to which their 

traditions and cultural identities are 

tied.’’ 21 The IPCC AR5 notes, ‘‘Climaterelated hazards exacerbate other 

stressors, often with negative outcomes 

for livelihoods, especially for people 

living in poverty (high confidence). 

Climate-related hazards affect poor 

people’s lives directly through impacts 

on livelihoods, reductions in crop 

yields, or destruction of homes and 

indirectly through, for example, 

increased food prices and food 

insecurity.’’ 22

Events outside the United States, as 

also pointed out in the 2009 

Endangerment Finding, will also have 

relevant consequences. The NRC 

Climate and Social Stress assessment 

concluded that it is prudent to expect 

that some climate events ‘‘will produce 

consequences that exceed the capacity 

of the affected societies or global 

systems to manage and that have global 

security implications serious enough to 

compel international response.’’ The 

NRC National Security Implications 

assessment recommends preparing for 

increased needs for humanitarian aid; 

responding to the effects of climate 

change in geopolitical hotspots, 

including possible mass migrations; and 

addressing changing security needs in 

the Arctic as sea ice retreats. 

In addition to future impacts, the 

NCA3 emphasizes that climate change 

driven by human emissions of GHGs is 

already happening now and it is 

happening in the United States. 

According to the IPCC AR5 and the 

NCA3, there are a number of climaterelated changes that have been observed 

recently, and these changes are 

projected to accelerate in the future. The 

planet warmed about 0.85 °C (1.5 °F) 

from 1880 to 2012. It is extremely likely 

(>95% probability) that human 

influence was the dominant cause of the 

observed warming since the mid-20th 

century, and likely (>66% probability) 

that human influence has more than 

doubled the probability of occurrence of 

heat waves in some locations. In the 

Northern Hemisphere, the last 30 years 

were likely the warmest 30 year period 

of the last 1400 years. U.S. average 

temperatures have similarly increased 

by 1.3 to 1.9 degrees F since 1895, with 

most of that increase occurring since 

1970. Global sea levels rose 0.19 m (7.5 

inches) from 1901 to 2010. Contributing 

to this rise was the warming of the 

oceans and melting of land ice. It is 

likely that 275 gigatons per year of ice 

melted from land glaciers (not including 

ice sheets) since 1993, and that the rate 

of loss of ice from the Greenland and 

Antarctic ice sheets increased 

substantially in recent years, to 215 

gigatons per year and 147 gigatons per 

year respectively since 2002. For 

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23Blunden, J., and D.S. Arndt, Eds., 2014: State 

of the Climate in 2013. Bull. Amer. Meteor. Soc., 

95 (7), S1–S238. 

24http://www.ncdc.noaa.gov/sotc/global/2014/13. 

25NRC, 2011: America’s Climate Choices, The 

National Academies Press. 

26U.S. EPA. 2013. ‘‘Integrated Science 

Assessment for Ozone and Related Photochemical 

Oxidants (Final Report).’’ EPA–600–R–10–076F. 

National Center for Environmental Assessment— 

RTP Division. Available at http://www.epa.gov/

ncea/isa/. 

27Myhre, G., D. Shindell, F.-M. Bre ́on, W. Collins, 

J. Fuglestvedt, J. Huang, D. Koch, J.-F. Lamarque, D. 

Lee, B. Mendoza, T. Nakajima, A. Robock, G. 

Stephens, T. Takemura and H. Zhang, 2013: 

Anthropogenic and Natural Radiative Forcing. In: 

Climate Change 2013: The Physical Science Basis. 

Contribution of Working Group I to the Fifth 

Assessment Report of the Intergovernmental Panel 

on Climate Change [Stocker, T.F., D. Qin, G.-K. 

Plattner, M. Tignor, S.K. Allen, J. Boschung, A. 

Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. 

Cambridge University Press, Cambridge, United 

Kingdom and New York, NY, USA. Pg. 680. 

28 Ibid. 

29 Ibid. 

30West, J.J., Fiore, A.M. 2005. ‘‘Management of 

tropospheric ozone by reducing methane 

emissions.’’Environ. Sci. Technol. 39:4685–4691. 

31Anenberg, S.C., et al. 2009. ‘‘Intercontinental 

impacts of ozone pollution on human mortality,’’ 

Environ. Sci. & Technol. 43:6482–6487. 

32National Health Interview Survey (NHIS) Data, 

2011 http://www.cdc.gov/asthma/nhis/2011/

data.htm. 

context, 360 gigatons of ice melt is 

sufficient to cause global sea levels to 

rise 1 millimeter (mm). Annual mean 

Arctic sea ice has been declining at 3.5 

to 4.1 percent per decade, and Northern 

Hemisphere snow cover extent has 

decreased at about 1.6 percent per 

decade for March and 11.7 percent per 

decade for June. Permafrost 

temperatures have increased in most 

regions since the 1980s, by up to 3 °C 

(5.4 °F) in parts of Northern Alaska. 

Winter storm frequency and intensity 

have both increased in the Northern 

Hemisphere. The NCA3 states that the 

increases in the severity or frequency of 

some types of extreme weather and 

climate events in recent decades can 

affect energy production and delivery, 

causing supply disruptions, and 

compromise other essential 

infrastructure such as water and 

transportation systems. 

In addition to the changes 

documented in the assessment 

literature, there have been other climate 

milestones of note. According to the 

IPCC, methane concentrations in 2011 

were about 1803 parts per billion, 150 

percent higher than concentrations were 

in 1750. After a few years of nearly 

stable concentrations from 1999 to 2006, 

methane concentrations have resumed 

increasing at about 5 parts per billion 

per year. Concentrations today are likely 

higher than they have been for at least 

the past 800,000 years. Arctic sea ice 

has continued to decline, with 

September of 2012 marking a new 

record low in terms of Arctic sea ice 

extent, 40 percent below the 1979–2000 

median. Sea level has continued to rise 

at a rate of 3.2 mm per year (1.3 inches/ 

decade) since satellite observations 

started in 1993, more than twice the 

average rate of rise in the 20th century 

prior to 1993.23 And 2014 was the 

warmest year globally in the modern 

global surface temperature record, going 

back to 1880; this now means 19 of the 

20 warmest years have occurred in the 

past 20 years, and except for 1998, the 

ten warmest years on record have 

occurred since 2002.24 The first months 

of 2015 have also been some of the 

warmest on record. 

These assessments and observed 

changes make it clear that reducing 

emissions of GHGs across the globe is 

necessary in order to avoid the worst 

impacts of climate change, and 

underscore the urgency of reducing 

emissions now. The NRC Committee on 

America’s Climate Choices listed a 

number of reasons ‘‘why it is imprudent 

to delay actions that at least begin the 

process of substantially reducing 

emissions.’’ 25 For example: 

• The faster emissions are reduced, 

the lower the risks posed by climate 

change. Delays in reducing emissions 

could commit the planet to a wide range 

of adverse impacts, especially if the 

sensitivity of the climate to GHGs is on 

the higher end of the estimated range. 

• Waiting for unacceptable impacts to 

occur before taking action is imprudent 

because the effects of GHG emissions do 

not fully manifest themselves for 

decades and, once manifest, many of 

these changes will persist for hundreds 

or even thousands of years. 

• In the committee’s judgment, the 

risks associated with doing business as 

usual are a much greater concern than 

the risks associated with engaging in 

strong response efforts. 

Methane is also a precursor to groundlevel ozone, a health-harmful air 

pollutant. Additionally, ozone is a 

short-lived climate forcer that 

contributes to global warming. In remote 

areas, methane is a dominant precursor 

to tropospheric ozone formation.26

Approximately 50 percent of the global 

annual mean ozone increase since 

preindustrial times is believed to be due 

to anthropogenic methane.27 Projections 

of future emissions also indicate that 

methane is likely to be a key contributor 

to ozone concentrations in the future.28

Unlike nitrogen oxide (NOX) and VOC, 

which affect ozone concentrations 

regionally and at hourly time scales, 

methane emissions affect ozone 

concentrations globally and on decadal 

time scales given methane’s relatively 

long atmospheric lifetime compared to 

these other ozone precursors.29

Reducing methane emissions, therefore, 

may contribute to efforts to reduce 

global background ozone concentrations 

that contribute to the incidence of 

ozone-related health effects.30 31 These 

benefits are global and occur in both 

urban and rural areas. 

2. VOC 

Tropospheric, or ground-level, ozone 

is formed through reactions of VOC and 

NOX in the presence of sunlight. Ozone 

formation can be controlled to some 

extent through reductions in emissions 

of ozone precursor VOC and NOX. A 

significantly expanded body of 

scientific evidence shows that ozone 

can cause a number of harmful effects 

on health and the environment. 

Exposure to ozone can cause respiratory 

system effects such as difficulty 

breathing and airway inflammation. For 

people with lung diseases such as 

asthma and chronic obstructive 

pulmonary disease (COPD), these effects 

can lead to emergency room visits and 

hospital admissions. Studies have also 

found that ozone exposure is likely to 

cause premature death from lung or 

heart diseases. In addition, evidence 

indicates that long-term exposure to 

ozone is likely to result in harmful 

respiratory effects, including respiratory 

symptoms and the development of 

asthma. People most at risk from 

breathing air containing ozone include: 

Children; people with asthma and other 

respiratory diseases; older adults; and 

people who are active outdoors, 

especially outdoor workers. An 

estimated 25.9 million people have 

asthma in the U.S., including almost 7.1 

million children. Asthma 

disproportionately affects children, 

families with lower incomes, and 

minorities, including Puerto Ricans, 

Native Americans/Alaska Natives and 

African-Americans.32

Scientific evidence also shows that 

repeated exposure to ozone reduces 

growth and has other harmful effects on 

plants and trees. These types of effects 

have the potential to impact ecosystems 

and the benefits they provide. 

3. SO2

Current scientific evidence links 

short-term exposures to SO2, ranging 

from 5 minutes to 24 hours, with an 

array of adverse respiratory effects 

including bronchoconstriction and 

increased asthma symptoms. These 

effects are particularly important for 

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33U.S. EPA. Integrated Science Assessment (ISA) 

for Oxides of Nitrogen and Sulfur Ecological 

Criteria (2008 Final Report). U.S. Environmental 

Protection Agency, Washington, DC, EPA/600/R– 

08/082F, 2008. 34 IPCC, 2013: Summary for Policymakers. In: 

Climate Change 2013: The Physical Science Basis. 

Contribution of Working Group I to the Fifth 

Assessment Report of the Intergovernmental Panel 

on Climate Change [Stocker, T.F., D. Qin, G.-K. 

Plattner, M. Tignor, S.K. Allen, J. Boschung, A. 

Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. 

Cambridge University Press, p. 11. 

35One MMT = 1 million metric tons = 1 

megatonne (Mt). 1 metric ton = 1,000 kg = 1.102 

short tons = 2,205 lbs. 

36 IPCC, 2014: Climate Change 2014: Mitigation of 

Climate Change. Contribution of Working Group III 

to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change 

[Edenhofer, O., R. Pichs-Madruga, Y. Sokona, E. 

Farahani, S. Kadner, K. Seyboth, A. Adler, I. Baum, 

S. Brunner, P. Eickemeier, B. Kriemann, J. 

Savolainen, S. Schlo ̈mer, C. von Stechow, T. 

Zwickel and J.C. Minx (eds.)]. Cambridge University 

Press, 1435 pp. 

37U.S. EPA, 2014: Inventory of U.S. Greenhouse 

Gas Emissions and Sinks: 1990–2012. Available at 

http://www.epa.gov/climatechange/ghgemissions/

usinventoryreport.html#fullreport (Last accessed 

January 29, 2015). 

38World Resources Institute (WRI) Climate 

Analysis Indicators Tool (CAIT) Data Explorer 

(Version 2.0). Available at http://cait.wri.org. (Last 

accessed October 31, 2014.) 

39 IPCC, 2013: Climate Change 2013: The Physical 

Science Basis. Contribution of Working Group I to 

the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change 

[Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor, 

S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex 

and P.M. Midgley (eds.)]. Cambridge University 

Press, Cambridge, United Kingdom and New York, 

NY, USA, 1535 pp. Note that for purposes of 

inventories and reporting, GWP values from the 4th 

Assessment Report may be used. 

asthmatics at elevated ventilation rates 

(e.g., while exercising or playing). 

Studies also show an association 

between short-term exposure and 

increased visits to emergency 

departments and hospital admissions 

for respiratory illnesses, particularly in 

at-risk populations including children, 

the elderly, and asthmatics. 

SO2 in the air can also damage the 

leaves of plants, decrease their ability to 

produce food—photosynthesis—and 

decrease their growth. In addition to 

directly affecting plants, SO2 when 

deposited on land and in estuaries, 

lakes and streams, can acidify sensitive 

ecosystems resulting in a range of 

harmful indirect effects on plants, soils, 

water quality, and fish and wildlife (e.g., 

changes in biodiversity and loss of 

habitat, reduced tree growth, loss of fish 

species). Sulfur deposition to waterways 

also plays a causal role in the 

methylation of mercury.33

4. Emission Estimates 

Section VI.A above explains how 

GHGs, VOC, and SO2 emissions are ‘‘air 

pollution’’ that may reasonably be 

anticipated to endanger public health 

and welfare. This section provides 

estimated emissions that the oil and 

natural gas source category contributes 

to this air pollution. As shown below, 

the contribution from this industry is 

quite significant. 

a. GHG Emissions 

Atmospheric concentrations of GHGs 

are now at essentially unprecedented 

levels compared to the distant and 

recent past.34 This is the unambiguous 

result of emissions of these gases from 

human activities. Global emissions of 

well-mixed GHGs have been increasing, 

and are projected to continue increasing 

for the foreseeable future. According to 

IPCC AR5, total global emissions of 

GHGs in 2010 were about 49,000 

million metric tons 35 of CO2 equivalent 

(MMT CO2eq).36 This represents an 

increase in global GHG emissions of 

about 29 percent since 1990 and 23 

percent since 2000. In 2010, total U.S. 

GHG emissions were responsible for 

about 14 percent of global GHG 

emissions (and about 12 percent when 

factoring in the effect of carbon sinks 

from U.S. land use and forestry). 

Based on the Inventory of U.S. 

Greenhouse Gas Emissions and Sinks 

Report 37 (hereinafter ‘‘U.S. GHG 

Inventory’’), in 2013 total U.S. GHG 

emissions increased by 5.9 percent from 

1990 (or by about 4.8 percent when 

including the effects of carbon sinks), 

and increased from 2012 to 2013 by 2.0 

percent. This increase was attributable 

to multiple factors including increased 

carbon intensity of fuels consumed to 

generate electricity, a relatively cool 

winter leading to an increase in heating 

requirements, an increase in industrial 

production across multiple sectors and 

a small increase in vehicle miles 

traveled (VMT) and fuel use across onroad transportation modes. 

Because 2010 is the most recent year 

for which IPCC emissions data are 

available, we provide 2011 estimates 

from the World Resources Institute’s 

(WRI) Climate Analysis Indicators Tool 

(CAIT) 38 for comparison. According to 

WRI/CAIT, the total global GHG 

emissions in 2011 were 43,816 MMT of 

CO2 Eq., representing an increase in 

global GHG emissions of about 42 

percent since 1990 and 30 percent since 

2000 (excluding land use, land use 

change and forestry). These estimates 

are generally consistent with those of 

IPCC. In 2011, WRI/CAIT data indicate 

that total U.S. GHG emissions were 

responsible for almost 15.5 percent of 

global emissions, which is also 

generally in line with the percentages 

using IPCC’s 2010 estimate described 

above. According to WRI/CAIT, current 

U.S. GHG emissions rank only behind 

China’s, which was responsible for 24 

percent of total global GHG emissions. 

i. Methane Emissions in the United 

States and from the Oil and Natural Gas 

Industry 

The GHGs addressed by the 2009 

Endangerment Finding consist of six 

well-mixed gases, including methane. 

Methane is a potent GHG with a 100 

year GWP that is 28–36 times greater 

than that of carbon dioxide.39 Methane 

has an atmospheric life of about 12 

years. Official U.S. estimates of national 

level GHG emissions and sinks are 

developed by the EPA for the U.S. GHG 

Inventory to comply with commitments 

under the United Nations Framework 

Convention on Climate Change 

(UNFCCC). The U.S. inventory, which 

includes recent trends, is organized by 

industrial sectors. Natural gas and 

petroleum systems are the largest 

emitters of methane in the U.S. These 

systems emit 29 percent of U.S. 

anthropogenic methane. 

Table 2 below presents total U.S. 

anthropogenic methane emissions for 

the years 1990, 2005 and 2013. 

TABLE 2—U.S. METHANE EMISSIONS BY SECTOR

[Million metric ton carbon dioxide equivalent (MMT CO2 Eq.)] 

Sector 1990 2005 2013 

Oil and Natural Gas Production, and Natural Gas Processing and Transmission ... 170.0 163.5 148.3 

Enteric Fermentation ................................................................................................. 164.2 168.9 164.5 

Landfills ...................................................................................................................... 186.2 165.5 114.6 

Coal Mining ................................................................................................................ 96.5 64.1 64.6 

Manure Management ................................................................................................. 37.2 56.3 61.4 

Other Methane Sources 40 ......................................................................................... 91.4 89.5 82.9 

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40Other sources include remaining natural gas 

distribution, petroleum transport and petroleum 

refineries, forest land, wastewater treatment, rice 

cultivation, stationary combustion, abandoned coal 

mines, petrochemical production, mobile 

combustion, composting, and several sources 

emitting less than 1 MMT CO2¥e in 2013. 

TABLE 2—U.S. METHANE EMISSIONS BY SECTOR—Continued 

[Million metric ton carbon dioxide equivalent (MMT CO2 Eq.)] 

Sector 1990 2005 2013 

Total Methane Emissions ................................................................................... 745.5 707.8 636.3 

Emissions from the U.S. GHG Inventory, calculated using GWP of 25. 

Oil and natural gas production and 

natural gas processing and transmission 

systems encompass wells, natural gas 

gathering and processing facilities, 

storage, and transmission pipelines. 

These components are all important 

aspects of the natural gas cycle—the 

process of getting natural gas out of the 

ground and to the end user. In the oil 

industry, some underground crude oil 

contains natural gas that is entrained in 

the oil at high reservoir pressures. When 

oil is removed from the reservoir, 

associated natural gas is produced. 

Methane emissions occur throughout 

the natural gas industry. They primarily 

result from normal operations, routine 

maintenance, fugitive leaks and system 

upsets. As gas moves through the 

system, emissions occur through 

intentional venting and unintentional 

leaks. Venting can occur through 

equipment design or operational 

practices, such as the continuous bleed 

of gas from pneumatic controllers (that 

control gas flows, levels, temperatures, 

and pressures in the equipment), or 

venting from well completions during 

production. In addition to vented 

emissions, methane losses can occur 

from leaks (also referred to as fugitive 

emissions) in all parts of the 

infrastructure, from connections 

between pipes and vessels, to valves 

and equipment. 

In petroleum systems, methane 

emissions result primarily from field 

production operations, such as venting 

of associated gas from oil wells, oil 

storage tanks, and production-related 

equipment such as gas dehydrators, pig 

traps, and pneumatic devices. 

Table 3 (a and b) below present total 

methane emissions from natural gas and 

petroleum systems, and the associated 

segments of the sector, for years 1990, 

2005 and 2013, in million metric tons of 

carbon dioxide equivalent (Table 3(a)) 

and kilotons (or thousand metric tons) 

of methane (Table 3(b)). 

TABLE 3(a)—U.S. METHANE EMISSIONS FROM NATURAL GAS AND PETROLEUM SYSTEMS

[MMT CO2 Eq.] 

Sector 1990 2005 2013 

Oil and Natural Gas Production and Natural Gas Processing and Transmission 

(Total) ..................................................................................................................... 170 163 148 

Natural Gas Production ............................................................................................. 59 75 47 

Natural Gas Processing ............................................................................................. 21 16 23 

Natural Gas Transmission and Storage .................................................................... 59 49 54 

Petroleum Production ................................................................................................ 31 23 24 

Emissions from the 2015 U.S. GHG Inventory, calculated using GWP of 25. 

TABLE 3(b)—U.S. METHANE EMISSIONS FROM NATURAL GAS AND PETROLEUM SYSTEMS

[kt CH4] 

Sector 1990 2005 2013 

Oil and Natural Gas Production and Natural Gas Processing and Transmission 

(Total) ..................................................................................................................... 6,802 6,539 5,930 

Natural Gas Production ............................................................................................. 2,380 3,018 1,879 

Natural Gas Processing ............................................................................................. 852 655 906 

Natural Gas Transmission and Storage .................................................................... 2,343 1,963 2,176 

Petroleum Production ................................................................................................ 1,227 903 969 

Emissions from the 2015 U.S. GHG Inventory, in kt (1,000 tons) of CH4. 

ii. U.S. Oil and Natural Gas Production 

and Natural Gas Processing and 

Transmission GHG Emissions Relative 

to Total U.S. GHG Emissions 

Relying on data from the U.S. GHG 

Inventory, we compared U.S. oil and 

natural gas production and natural gas 

processing and transmission GHG 

emissions to total U.S. GHG emissions 

as an indication of the role this source 

plays in the total domestic contribution 

to the air pollution that is causing 

climate change. In 2013, total U.S. GHG 

emissions from all sources were 6,673 

MMT CO2 Eq. 

For purposes of the proposed revision 

to the category listing, the EPA is 

including oil and natural gas production 

sources, and natural gas processing 

transmission sources. In 2013, 

emissions from oil and natural gas 

production sources and natural gas 

processing and transmission sources 

accounted for 148 MMT CO2eq methane 

emissions and oil completions for 

another 3 MMT CO2eq (using a GWP of 

25 for methane). The sector also emitted 

44 MMT of CO2, mainly from acid gas 

removal during natural gas processing 

(22 MMT) and flaring in oil and natural 

gas production (16 MMT). In total, these 

emissions account for 3.0 percent of 

total U.S. domestic emissions. 

In regard to the six well-mixed GHGs 

(CO2, methane, nitrous oxide, 

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hydrofluorocarbons, perfluorocarbons, 

and sulfur hexafluoride), only two of 

these gases—CO2 and methane—are 

reported as non-zero emissions for the 

oil and natural gas production sources 

and natural gas processing and 

transmission sources that are being 

addressed within this rule. 

TABLE 4—COMPARISONS OF U.S. OIL AND NATURAL GAS PRODUCTION AND NATURAL GAS PROCESSING AND

TRANSMISSION GHG EMISSIONS TO TOTAL U.S. GHG EMISSIONS

2010 2011 2012 2013 

Total U.S. Oil & Gas Production and Natural Gas Processing 

& Transmission GHG Emissions (MMT CO2 Eq) ................ 147 147 146 148 

Share of Total U.S. GHG Inventory ........................................ 2.13% 2.18% 2.23% 2.22% 

Total U.S. GHG Emissions (MMT CO2 Eq) ............................ 6,899 6,777 6,545 6,673 

iii. U.S. Oil and Natural Gas Production 

and Natural Gas Processing and 

Transmission GHG Emissions Relative 

to Total Global GHG Emissions 

TABLE 5—COMPARISONS OF U.S. OIL AND NATURAL GAS PRODUCTION AND NATURAL GAS PROCESSING AND

TRANSMISSION GHG EMISSIONS TO TOTAL GLOBAL GREENHOUSE GAS EMISSIONS IN 2010 

2010 

(MMT CO2 eq) 

Total U.S. oil and 

natural gas 

production and 

natural gas 

processing and 

transmission 

share 

(%) 

Total Global GHG Emissions ...................................................................................................................... 49,000 0.3% 

For additional background 

information and context, we used 2011 

WRI/CAIT and IEA data to make 

comparisons between U.S. oil and 

natural gas production and natural gas 

processing and transmission emissions 

and the emissions inventories of entire 

countries and regions. Ranking U.S. 

emissions of GHGs from oil and natural 

gas production and natural gas 

processing and transmission against 

total GHG emissions for entire 

countries, show that these emissions 

would be more than the national-level 

emissions totals for all anthropogenic 

sources for Greece, the Czech Republic, 

Chile, Belgium, and about 140 other 

countries. 

As illustrated by the data summarized 

above, the collective GHG emissions 

from oil and natural gas production and 

natural gas processing and transmission 

sources are significant, whether the 

comparison is domestic (3.0 percent of 

total U.S. emissions) or global (0.3 

percent of all global GHG emissions). 

The EPA believes that consideration of 

the global context is important. GHG 

emissions from U.S. oil and natural gas 

production and natural gas processing 

and transmission will become globally 

well-mixed in the atmosphere, and thus 

will have an effect on the U.S. regional 

climate, as well as the global climate as 

a whole for years and indeed many 

decades to come. Based on the data 

above, GHG emissions from the oil and 

natural gas source category is 

significiant whether only the domestic 

context is considered, only the global 

context is considered, or both the 

domestic and global GHG emissions 

comparisons are viewed in combination. 

As was the case in 2009, no single 

GHG source category dominates on the 

global scale, and many (if not all) 

individual GHG source categories could 

appear small in comparison to the total, 

when, in fact, they could be very 

important contributors in terms of both 

absolute emissions or in comparison to 

other source categories, globally or 

within the U.S. Contributions of GHG to 

the global problem should not be 

compared to contributions associated 

with local air pollution problems. The 

EPA continues to believe that these 

unique, global aspects of the climate 

change problem—including that from a 

percentage perspective there are no 

dominating sources emitting GHGs and 

fewer sources that would even be 

considered to be close to dominating— 

tend to support consideration of 

contribution to the air pollution at lower 

percentage levels than the EPA typically 

encounters when analyzing contribution 

towards a more localized air pollution 

problem. Thus, the EPA, similar to the 

approach taken in the 2009 Finding, is 

placing significant weight on the fact 

that oil and natural gas production and 

natural gas processing and transmission 

sources contribute 3 percent of total 

U.S. GHG emissions for the contribution 

finding. 

b. VOC Emissions 

The EPA National Emissions 

Inventory (NEI) estimated total VOC 

emissions from the oil and natural gas 

sector to be 2,782,000 tons in 2011. This 

ranks second of all the sectors estimated 

by the NEI and first of all the 

anthropogenic sectors in the NEI. 

c. SO2 Emissions 

The NEI estimated total SO2

emissions from the oil and natural gas 

sector to be 74,000 tons in 2011. This 

ranks 13th of the sectors estimated by 

the NEI. 

5. Conclusion 

In summary, EPA interprets the 1979 

category listing to broadly cover the oil 

and natural gas industry, including all 

segments of the natural gas industry 

(production, processing, transmission, 

and storage). To the extent there is 

ambiguity to the prior listing, EPA is 

proposing to revise the category listing 

to include the various segments of the 

natural gas industry. In support, EPA 

notes its previous determination under 

section 111(b)(1)(A) for the oil and 

natural gas source category. In addition, 

EPA provides in this section 

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41Control techniques guidelines are not part of 

this action. 

information and analyses detailing the 

public health and welfare impacts of 

GHG, VOC and SO2 emissions and the 

amount of these emission from the oil 

and natural gas source category (in 

particular from the various segments of 

the natural gas industry). Although EPA 

does not believe the proposed revision 

to the category listing is required for the 

standards we are proposing in this 

action, even assuming it is, the proposal 

is well justified. 

B. Stakeholder Input 

1. White Papers 

As a follow up to the 2013 Climate 

Action Plan, the Climate Action Plan: 

Strategy to Reduce Methane Emissions 

(the Methane Strategy) was released in 

March 2014. The Methane Strategy 

instructed the EPA to release a series of 

white papers on several potentially 

significant sources of methane in the oil 

and natural gas sector and solicit input 

from independent experts. The papers 

were released in April 2014, and 

focused on technical issues, covering 

emissions and control technologies that 

target both VOC and methane with 

particular focus on completions of 

hydraulically fractured oil wells, liquids 

unloading, leaks, pneumatic devices 

and compressors. The peer review 

process was completed on June 16, 

2014. 

The peer review and public comments 

on the white papers included additional 

technical information that provided 

further clarification of our 

understanding of the emission sources 

and emission control options. The 

comments also provided additional data 

on emissions and number of sources, 

and pointed out newly published 

studies that further informed our 

emission rate estimates. Where 

appropriate, we used the information 

and data provided to adjust the control 

options considered and the impacts 

estimates presented in the 2015 TSD. 

The EPA used an ad hoc external peer 

review process, as outlined in the EPA’s 

Peer Review Handbook, 3rd Edition. 

Under that process, the Agency 

submitted names recommended by 

industry and environmental groups, 

along with state, tribal, and academic 

organizations to an outside contractor. 

To avoid any conflict of interest, the 

contractor did not work on the white 

papers and is not working on the EPA’s 

oil and natural gas regulations or 

voluntary programs. The contractor 

built a list of qualified reviewers from 

these names and their own research, 

reviewed appropriate credentials and 

selected reviewers from the list. A 

different set of reviewers was selected 

for each white paper, based on the 

reviewers’ expertise. A total of 26 sets 

of comments from peer reviewers were 

submitted to the EPA. Additionally, the 

EPA solicited technical information and 

data from the public. The EPA received 

over 43,000 submissions from the 

public. The comments received from the 

peer reviewers are available on EPA’s 

oil and natural gas white paper Web site 

(http://www.epa.gov/airquality/

oilandgas/methane.html). Public 

comments on the white papers are 

available in EPA’s nonregulatory docket 

at www.regulations.gov, docket ID # 

EPA–HQ–OAR–2014–0557. 

2. Outreach to State, Local and Tribal 

Governments 

The EPA spoke with state, local and 

tribal governments to hear how they 

have managed issues, and to get 

feedback that would help us as we 

develop the rule. In February 2015, the 

EPA asked states and tribes to nominate 

themselves to participate in discussions. 

Twelve states, three tribes and several 

local air districts participated. We 

conducted several teleconferences in 

March and April 2015 to discuss such 

questions as: 

• Whether these governments are, or 

have considered, regulating the 

sources identified in the white papers 

• Factors considered in determining 

whether to regulate them 

• Use of innovative compliance options 

• Experiences implementing control 

techniques guidelines (CTGs) 41

• Information and features that would 

be helpful to include in a CTG 

• Whether any sources of emissions are 

particularly suitable to voluntary 

rather than regulatory action 

In addition to the outreach described 

above, the EPA consulted with tribal 

officials under the ‘‘EPA Policy on 

Consultation and Coordination with 

Indian Tribes’’ early in the process of 

developing this regulation to provide 

them with the opportunity to have 

meaningful and timely input into its 

development. Additionally, the EPA has 

conducted meaningful involvement 

with tribal stakeholders throughout the 

rulemaking process and provided an 

update on the methane strategy to the 

National Tribal Air Association. 

Consistent with previous actions 

affecting the oil and natural gas sector, 

there is significant tribal interest 

because of the growth of the oil and 

natural gas production in Indian 

country. The EPA specifically solicits 

additional comment on this proposed 

action from tribal officials. 

VII. Summary of Proposed Standards 

A. Control of Methane and VOC 

Emissions in the Oil and Natural Gas 

Source Category 

In this action, we propose to set 

emission standards for methane and 

VOC for certain new, modified and 

reconstructed emission sources across 

the oil and natural gas source category. 

For some of these sources, there are 

VOC requirements currently in place 

that were established in the 2012 NSPS, 

that we are expanding to include 

methane. For others, for which there are 

no current requirements, we are 

proposing methane and VOC standards. 

We are also proposing improvements to 

enhance implementation of the current 

standards. For the reasons explained in 

section V, EPA believes that the 

proposed methane standards are 

warranted, even for those already 

subject to VOC standards under the 

2012 NSPS. Further, as shown in the 

analyses in section VIII, there are cost 

effective controls that achieve 

simultaneous reductions of methane 

and VOC emission. Some stakeholders 

have advocated that is appropriate to 

rely on VOC standards, as established in 

2012, for sources in the production and 

processing segment. For example, based 

on methane and VOC emissions from 

pneumatic controllers, this approach 

could result in just a VOC standard for 

pneumatic controllers in the production 

segment and a VOC and methane 

standard in the transmission and storage 

segment. Some stakeholders have also 

advocated for the importance of setting 

methane standards in the production 

segment that go beyond the 2012 NSPS 

standards. We anticipate that these 

stakeholders will express their views 

during the comment period. 

Pursuant to CAA section 111(b), we 

are proposing to amend subpart OOOO 

and to create a new subpart OOOOa 

which will include the standards and 

requirements summarized in this 

section. Subpart OOOO would be 

amended to apply to facilities 

constructed, modified or reconstructed 

after August 23, 2011, (i.e., the original 

proposal date of subpart OOOO) and 

before September 18, 2015 (i.e., the 

proposal date of the new subpart 

OOOOa) and would be amended only to 

include the revisions reflecting 

implementation improvements in 

response to issues raised in petitions for 

reconsideration. Subpart OOOOa would 

apply to facilities constructed, modified 

or reconstructed after September 18, 

2015 and would include current VOC 

requirements already provided in 

subpart OOOO as well as new 

provisions for methane and VOC across 

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42Bleed rate can be documented through 

information provided by the controller 

manufacturer. 

the oil and natural gas source category 

as highlighted below in this section. 

More details of the rationale for these 

proposed standards and requirements 

are provided in section VIII of this 

preamble. 

We note that the terms ‘‘emission 

source,’’ ‘‘source type’’ and ‘‘source,’’ as 

used in this preamble, refer to 

equipment, processes and activities that 

emit VOC and/or methane. This term 

does not refer to specific facilities, in 

contrast to usage of the term ‘‘source’’ in 

the contexts of permitting and section 

112 actions. As summarized below and 

discussed in more detail in section VIII, 

the BSER for methane is the same as 

that for VOC for all emission sources, 

including those currently subject to 

VOC standards and for which we are 

proposing to establish methane 

standards in this action. Accordingly, 

the current requirements reflect the 

BSER for both VOC and methane for 

these sources. We are, therefore, not 

proposing any change to the current 

requirements for emission sources 

addressed under the 2012 NSPS. 

Both VOC and methane are 

hydrocarbon compounds and behave 

essentially the same when emitted 

together or separately. Accordingly, the 

available controls for methane are the 

same as those for VOC and achieve the 

same levels of reduction for both VOC 

and methane. For example, combustionbased control technologies (e.g., flares 

and enclosed combustors) that reduce 

VOC emissions by 95 percent can be 

expected to also reduce methane 

emissions by 95 percent. Similarly, 

work practice and operational standards 

(e.g., leak detection and reduced 

emission completion of wells) that 

reduce emissions of VOC can be 

expected to have the same effect on 

methane emissions. Because VOC 

control technologies perform the same 

when used to control methane 

emissions, the BSER for methane is the 

same as the BSER for VOC. Therefore, 

we are proposing performance and 

operational standards to control 

methane and VOC emissions for certain 

emission sources across the source 

category. These proposed methane 

standards would require no change to 

the requirements for currently regulated 

affected facilities. 

Please note that there are minor 

differences in some values presented in 

various documents supporting this 

action. This is because some 

calculations have been performed 

independently (e.g., TSD calculations 

focused on unit-level cost-effectiveness 

and RIA calculations focused on 

national impacts) and include slightly 

different rounding of intermediate 

values. 

B. Centrifugal Compressors 

We are proposing standards to reduce 

methane and VOC emissions from new, 

modified or reconstructed centrifugal 

compressors located across the oil and 

natural gas source category, except those 

located at well sites. As discussed in 

detail in section VIII.B, the proposed 

standards are the same as those 

currently required to control VOC from 

centrifugal compressors in the 

production segment. Specifically, we 

are proposing to require 95 percent 

reduction of the emissions from each 

wet seal centrifugal compressor affected 

facility. The standard can be achieved 

by capturing and routing the emissions 

utilizing a cover and closed vent system 

to a control device that achieves an 

emission reduction of 95 percent, or 

routing the captured emissions to a 

process. Consistent with the current 

VOC provisions for centrifugal 

compressors in the production segment, 

dry seal centrifugal compressors are 

inherently low-emitting and would not 

be affected facilities. These proposed 

standards are the same as for centrifugal 

compressors regulated in the 2012 final 

rule. 

C. Reciprocating Compressors 

For the reasons discussed in section 

VIII.C, we are proposing an operational 

standard for affected reciprocating 

compressors across the oil and natural 

gas source category, except those 

located at well sites, that requires either 

replacement of the rod packing based on 

usage or routing of rod packing 

emissions to a process via a closed vent 

system under negative pressure. The 

owner or operator of a reciprocating 

compressor affected facility would be 

required to monitor the duration (in 

hours) that the compressor is operated, 

beginning on the date of initial startup 

of the reciprocating compressor affected 

facility. When the hours of operation 

reach 26,000 hours, the owner or 

operator would be required to 

immediately change the rod packing. 

Owners or operators can elect to change 

the rod packing every 36 months in lieu 

of monitoring compressor operating 

hours. As an alternative to rod packing 

replacement, owners and operators may 

route the rod packing emissions to a 

process via a closed vent system 

operated at negative pressure. These 

proposed standards are the same as for 

reciprocating compressors regulated in 

the 2012 rule. 

D. Pneumatic Controllers 

For the reasons presented in section 

VIII.D, consistent with VOC standards 

in the 2012 NSPS for pneumatic 

controllers in the production segment, 

we are proposing to control methane 

and VOC emissions by requiring use of 

low-bleed controllers in place of highbleed controllers (i.e., natural gas bleed 

rate not to exceed 6 scfh) 42 at locations 

within the source category except for 

natural gas processing plants. For 

natural gas processing plants, consistent 

with the VOC emission standards in the 

2012 NSPS, we are proposing to control 

methane and VOC emissions by 

requiring that pneumatic controllers 

have zero natural gas bleed rate (i.e., 

they are operated by means other than 

natural gas, such as being driven by 

compressed instrument air). We are 

proposing that these standards apply to 

each newly installed, modified or 

reconstructed pneumatic controller 

(including replacement of an existing 

controller). Consistent with the current 

requirements under the 2012 NSPS for 

control of VOC emissions from 

pneumatic controllers in the production 

segment and at natural gas processing 

plants, the proposed standards provide 

exemptions for certain critical 

applications based on functional 

considerations. These proposed 

standards are the same as for pneumatic 

controllers regulated in the 2012 rule. 

E. Pneumatic Pumps 

For the reasons detailed in section 

VIII.E, we are proposing standards for 

natural gas-driven chemical/methanol 

pumps and diaphragm pumps. The 

proposed standards would require the 

methane and VOC emissions from new, 

modified and reconstructed natural gasdriven chemical/methanol pumps and 

diaphragm pumps located at any 

location (except for natural gas 

processing plants) throughout the 

source category to be reduced by 95 

percent if a control device is already 

available on site. For pneumatic pumps 

located at a natural gas processing plant, 

the proposed standards would require 

the methane and VOC emissions from 

natural gas-driven chemical/methanol 

pumps and diaphragm pumps to be 

zero. 

F. Well Completions 

We are proposing operational 

standards for well completions at 

hydraulically fractured (or refractured) 

wells, including oil wells. The 2012 

NSPS regulated well completions to 

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control VOC emissions from 

hydraulically fractured or refractured 

gas wells. These proposed standards are 

the same as for natural gas wells 

regulated in the 2012 rule. We identified 

two subcategories of hydraulically 

fractured wells for which well 

completions are conducted: (1) Nonwildcat and non-delineation wells; and 

(2) wildcat and delineation wells. A 

wildcat well, also referred to as an 

exploratory well, is a well drilled 

outside known fields or are the first well 

drilled in an oil or gas field where no 

other oil and gas production exists. A 

delineation well is a well drilled to 

determine the boundary of a field or 

producing reservoir. 

As discussed in detail in section 

VIII.F, we are proposing operational 

standards for subcategory 1 (nonwildcat, non-delineation wells) 

requiring a combination of REC and 

combustion. Compared to combustion 

alone, we believe that the combination 

of REC and combustion will maximize 

gas recovery and minimize venting to 

the atmosphere. Furthermore, the use of 

traditional combustion control devices 

(i.e., flares and enclosed combustion 

control devices), present local emissions 

impacts. The proposed standards for 

subcategory 2 wells (wildcat and 

delineation wells) require only 

combustion. For subcategory 1 wells, we 

are proposing to define the flowback 

period of an oil well completion as 

consisting of two distinct stages, the 

‘‘initial flowback stage’’ and the 

‘‘separation flowback stage.’’ The initial 

flowback stage begins with the onset of 

flowback and ends when the flow is 

routed to a separator. During the initial 

flowback stage, any gas in the flowback 

is not subject to control. However, the 

operator must route the flowback to a 

separator unless it is technically 

infeasible for a separator to function. 

The point at which the separator can 

function marks the beginning of the 

separation flowback stage. During this 

stage, the operator must route all salable 

quality gas from the separator to a flow 

line or collection system, re-inject the 

gas into the well or another well, use the 

gas as an on-site fuel source or use the 

gas for another useful purpose. If it is 

technically infeasible to route the gas as 

described above, or if the gas is not of 

salable quality, the operator must 

combust the gas unless combustion 

creates a fire or safety hazard or can 

damage tundra, permafrost or 

waterways. No direct venting of gas is 

allowed during the separation flowback 

stage. The separation flowback stage 

ends either when the well is shut in and 

the flowback equipment is permanently 

disconnected from the well, or on 

startup of production. This also marks 

the end of the flowback period. The 

operator has a general duty to safely 

maximize resource recovery safely and 

minimize releases to the atmosphere 

over the duration of the flowback 

period. The operator is also required to 

document the stages of the completion 

operation by maintaining records of (1) 

the date and time of the onset of 

flowback; (2) the date and time of each 

attempt to route flowback to the 

separator; (3) the date and time of each 

occurrence in which the operator 

reverted to the initial flowback stage; (4) 

the date and time of well shut in; and 

(5) date and time that temporary 

flowback equipment is disconnected. In 

addition, the operator must document 

the total duration of venting, 

combustion and flaring over the 

flowback period. All flowback liquids 

during the initial flowback period and 

the separation flowback period must be 

routed to a well completion vessel, a 

storage vessel or a collection system. 

For subcategory 2 wells, we are 

proposing an operational standard that 

requires routing of the flowback into 

well completion vessels and 

commencing operation of a separator 

unless it is technically infeasible for the 

separator to function. Once the 

separator can function, recovered gas 

must be captured and directed to a 

completion combustion device unless 

combustion creates a fire or safety 

hazard or can damage tundra, 

permafrost or waterways. Operators 

would be required to maintain the same 

records described above for category 1 

wells. 

Consistent with the current VOC 

standards for hydraulically fractured gas 

wells, we are proposing that ‘‘low 

pressure’’ wells would remain affected 

facilities and would have the same 

requirements as subcategory 2 wells 

(wildcat and delineation wells). The 

term ‘‘low pressure gas well’’ is 

unchanged from the currently codified 

definition in the NSPS; however, we 

solicit comment on whether this 

definition appropriately indicates 

hydraulically fractured oil wells for 

which conducting an REC would be 

technologically infeasible and whether 

the term should be revised to address all 

wells rather than just gas wells. 

We are also retaining the provision 

from the 2012 NSPS, now at 

§ 60.5365a(a)(1), that a well that is 

refractured, and for which the well 

completion operation is conducted 

according to the requirements of 

§ 60.5375a(a)(1) through (4), is not 

considered a modified well and 

therefore does not become an affected 

facility under the NSPS. We point out 

that such an exclusion of a ‘‘well’’ from 

applicability under the NSPS has no 

effect on the affected facility status of 

the ‘‘well site’’ for purposes of the 

proposed fugitive emissions standards 

at § 60.5397a. 

Further, we are proposing that wells 

with a gas-to-oil ratio (GOR) of less than 

300 scf of gas per barrel of oil produced 

would not be affected facilities subject 

to the well completion provisions of the 

NSPS. We solicit comment on whether 

a GOR of 300 is the appropriate 

applicability threshold. Rationale for 

this threshold is discussed in detail in 

section VIII.F. 

G. Fugitive Emissions From Well Sites 

and Compressor Stations 

1. Fugitive Emissions From Oil and 

Natural Gas Production Well Sites 

We are proposing standards to reduce 

fugitive methane and VOC emissions 

from new and modified oil and natural 

gas production well sites. The proposed 

standards would require locating and 

repairing sources of fugitive emissions 

(e.g., visible emissions from fugitive 

emissions components observed using 

OGI) at well sites. Under the proposed 

standards, the affected facility would be 

‘‘the collection of fugitive emissions 

components at a well site’’; where ‘‘well 

site’’ is defined in subpart OOOO as 

‘‘one or more areas that are directly 

disturbed during the drilling and 

subsequent operation of, or affected by, 

production facilities directly associated 

with any oil well, gas well, or injection 

well and its associated well pad.’’ This 

definition is intended to include all 

ancillary equipment in the immediate 

vicinity of the well that are necessary 

for or used in production, and may 

include such items as separators, storage 

vessels, heaters, dehydrators, or other 

equipment at the site. 

Some well sites, especially in areas 

with very dry gas or where centralized 

gathering facilities are used, consist 

only of one or more wellheads, or 

‘‘Christmas trees,’’ and have no ancillary 

equipment such as storage vessels, 

closed vent systems, control devices, 

compressors, separators and pneumatic 

controllers. Because the magnitude of 

fugitive emissions depends on how 

many of each type of component (e.g., 

valves, connectors and pumps) are 

present, fugitive emissions from these 

well sites are extremely low. For that 

reason, we are proposing to exclude 

from the fugitive emissions 

requirements those well sites that 

contain only wellheads. Therefore, we 

are proposing to add the following 

sentence to the definition of ‘‘well site’’ 

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above: ‘‘For the purposes of the fugitive 

emissions standards at § 60.5397a, a 

well site that only contains one or more 

wellheads is not subject to these 

standards.’’ 

Also, we are proposing to exclude low 

production well sites (i.e., a low 

production site is defined by the average 

combined oil and natural gas 

production for the wells at the site being 

less than 15 barrels of oil equivalent 

(boe) per day averaged over the first 30 

days of production) from the standards 

for fugitives emissions from well sites. 

Please refer to section VIII.G. for further 

discussion. 

We are proposing that owners or 

operators of well site-affected facilities 

conduct an initial survey of ‘‘fugitive 

emissions components,’’ which we are 

proposing to define in § 60.5430a to 

include, among other things, valves, 

connectors, open-ended lines, pressure 

relief devices, closed vent systems and 

thief hatches on tanks using either OGI 

technology. For new well sites, the 

initial survey would have to be 

conducted within 30 days of the end of 

the first well completion or upon the 

date the site begins production, 

whichever is later. For modified well 

sites, the initial survey would be 

required to be conducted within 30 days 

of the site modification. We solicit 

comment on whether 30 days is an 

appropriate period for the first survey 

following startup or modification. For 

the purposes of these fugitive emissions 

standards, a modification would occur 

when a new well is added to a well site 

(regardless of whether the well is 

fractured) or an existing well on a well 

site is fractured or refractured. See 

section VII.G.3 below for a discussion of 

modifications in the context of fugitive 

emission requirements for well sites and 

compressor stations. After the initial 

monitoring survey, monitoring surveys 

would be required to be conducted 

semiannually for all new and modified 

well sites. We are also co-proposing 

monitoring surveys on an annual basis 

for new and modified well sites. 

The proposed standards would 

require replacement or repair of 

components if evidence of fugitive 

emissions is detected during the 

monitoring survey through visible 

confirmation from OGI. As discussed in 

section VIII.G, we solicit comment on 

whether to allow EPA Method 21 as an 

alternative to OGI for monitoring, 

including the appropriate EPA Method 

21 level repair threshold. 

We are proposing that the source of 

emissions be repaired or replaced, and 

resurveyed, as soon as practicable, but 

no later than 15 calendar days after 

detection of the fugitive emissions. We 

expect that the majority of the repairs 

can be made at the time the initial 

monitoring survey is conducted. 

However, we understand that more time 

may be necessary to repair more 

complex components. We have 

historically allowed 15 days for repair/ 

resurvey in the LDAR program, which 

has appeared to be sufficient time. We 

are proposing to allow the use of either 

Method 21 or OGI for resurveys that 

cannot be performed during the initial 

monitoring survey and repair. As 

explained above, there may be some 

components that cannot not be repaired 

right away and in some instances not 

until after the initial OGI personnel are 

no longer on site. In that event, resurvey 

with OGI would require rehiring OGI 

personnel, which would make the 

resurvey not cost effective. For those 

components that have been repaired, we 

believe that the no fugitive emissions 

would be detected above 500 ppm above 

background using Method 21. This has 

been historically used to ensure that 

there are no emissions from components 

that are required to operate with no 

detectable emissions. We solicit 

comments on whether either optical gas 

imaging or Method 21 should be 

allowed for the resurvey of the repaired 

components when fugitive emissions 

are detected with OGI. We estimate that 

the majority of operators will need to 

hire a contractor to come back to 

conduct the optical gas imaging 

resurvey. While there will also be costs 

associated with resurveying using 

Method 21, we estimate that many 

companies own Method 21 instruments 

(e.g., OVA/TVA) and would be able to 

perform the resurvey at a minimal cost. 

To verify that the repair has been made 

using OGI, no evidence of visible 

emissions must be seen during the 

survey. For Method 21, we are 

proposing that the instrument show a 

reading of less than 500 ppm above 

background from any of the repaired 

components. We solicit comment 

whether 500 ppm above background is 

the appropriate repair resurvey 

threshold when Method 21 instruments 

are used or if not, what the appropriate 

repair resurvey threshold is for Method 

21. 

If the repair or replacement is 

technically infeasible or unsafe during 

unit operations, the repair or 

replacement must be completed during 

the next scheduled shutdown or within 

six months, whichever is earlier. 

Equipment is unsafe to repair or replace 

if personnel would be exposed to an 

immediate danger in conducting the 

repair or replacement. All sources of 

fugitive emissions that are repaired 

must be resurveyed within 15 days of 

repair completion to ensure the repair 

has been successful (i.e., no fugitive 

emissions are imaged using OGI or less 

than 500 ppm above background when 

using Method 21). 

The EPA is proposing that these 

fugitive emission requirements be 

carried out through the development 

and implementation of a monitoring 

plan, which would specify the measures 

for locating sources of fugitive 

emissions and the detection technology 

to be used. A company would be able 

to develop a corporate-wide monitoring 

plan, although there may be specific 

information needed that pertains to a 

single site, such as number and 

identification of fugitive emission 

components. The monitoring plan must 

also include a description of how the 

OGI survey will be conducted that 

ensures that fugitive emissions can be 

imaged effectively. In addition, we 

solicit comment on whether other 

techniques could be required elements 

of the monitoring plan in conjunction 

with OGI, such as visual inspections, to 

help identify signs such as staining of 

storage vessels or other indicators of 

potential leaks or improper operation. 

If fugitive emissions are detected at 

less than one percent of the fugitive 

emission components at a well site 

during two consecutive semiannual 

monitoring surveys, then the monitoring 

survey frequency for that well site may 

be reduced to annually. If, during a 

subsequent monitoring survey, fugitive 

emissions are detected at between one 

percent and three percent of the fugitive 

emission components, then the 

monitoring survey frequency for that 

well site must be increased to 

semiannually. 

If fugitive emissions are detected from 

three percent or more of the fugitive 

emission components at a well site 

during two consecutive semiannual 

monitoring, then the monitoring survey 

frequency for that well site must be 

increased to quarterly. If, during a 

subsequent monitoring survey, fugitive 

emissions are detected from one to three 

percent of the fugitive emission 

components, then the monitoring survey 

frequency for that well site may be 

reduced to semiannually. If fugitive 

emissions are detected from less than 

one percent of the fugitive emission 

components, then the monitoring survey 

frequency for that well site may be 

reduced to annually. We solicit 

comment on the proposed metrics of 

one percent and three percent and 

whether these thresholds should be 

specific numbers of components rather 

than percentages of components for 

triggering change in survey frequency 

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discussed in this action. We also solicit 

comment on whether a performancebased frequency or a fixed frequency is 

more appropriate. 

As discussed in more detail in section 

VIII.G below and the TSD for this action 

available in the docket, we have 

identified OGI technology with 

semiannual survey monitoring as the 

BSER for detecting fugitive emissions 

from new and modified well sites. 

The proposed standards would apply 

to new well sites and to modified well 

sites. As explained in more detail in 

section VIII.B below, for purposes of 

this proposed standard, a well site is 

modified when a new well is completed 

(regardless of whether it is fractured) or 

an existing well is fractured or 

refractured after [effective date of final 

rule]. The standards would not apply to 

existing well sites where additional 

drilling activities were conducted on an 

existing well but those activities did not 

include fracturing or refracturing (e.g., 

well workovers that do not include 

fracturing or refracturing). 

2. Fugitive Emissions From Compressor 

Stations 

We are proposing standards to reduce 

fugitive methane and VOC emissions 

from new and modified natural gas 

compressor stations throughout the oil 

and natural gas source category. The 

proposed standards would require 

affected facilities to locate sources of 

fugitive emissions and to repair those 

sources. We are proposing that owners 

or operators of the affected facilities 

conduct an initial survey of the 

collection of fugitive emissions 

components (e.g., valves, connectors, 

open-ended lines, pressure relief 

devices, closed vent systems and thief 

hatches on tanks) using OGI technology. 

For new compressor stations, the initial 

survey would have to be conducted 

within 30 days of site startup. For 

modified compressor stations, the initial 

survey would be required within 30 

days of the site modification. After the 

initial survey, surveys would be 

required semiannually. We solicit 

comment on whether 30 days is an 

appropriate period for the first survey 

following startup. 

The proposed standards would 

require replacement or repair of any 

fugitive emissions component that has 

evidence of fugitive emissions detected 

during the survey through visible 

confirmation from OGI. As discussed in 

section VIII.G, we solicit comment on 

whether to allow EPA Method 21 as an 

alternative to OGI for monitoring, 

including the appropriate EPA Method 

21 level repair threshold. 

We are proposing that the source of 

emissions be repaired or replaced, and 

resurveyed, as soon as practicable, but 

no later than 15 calendar days after 

detection of the fugitive emissions. We 

expect that the majority of the repairs 

can be made at the time the initial 

monitoring survey is conducted. 

However, we understand that more time 

may be necessary to repair more 

complex components. We have 

historically allowed 15 days for repair/ 

resurvey in the LDAR program, which 

has appeared to be sufficient time. We 

are proposing to allow the use of either 

Method 21 or OGI for resurveys that 

cannot be performed during the initial 

monitoring survey and repair. As 

explained above, there may be some 

components that cannot not be repaired 

right away and in some instances not 

until after the initial OGI personnel are 

no longer on site. In that event, resurvey 

with OGI would require rehiring OGI 

personnel, which would make the 

resurvey not cost effective. For those 

components that have been repaired, we 

believe that the no fugitive emissions 

would be detected above 500 ppm above 

background using Method 21. This has 

been historically used to ensure that 

there are no emissions from components 

that are required to operate with no 

detectable emissions. We solicit 

comments on whether either optical gas 

imaging or Method 21 should be 

allowed for the resurvey of the repaired 

components when fugitive emissions 

are detected with OGI. We estimate that 

the majority of operators will need to 

hire a contractor to come back to 

conduct the optical gas imaging 

resurvey. While there will also be costs 

associated with resurveying using 

Method 21, we estimate that many 

companies own Method 21 instruments 

(e.g., OVA/TVA) and would be able to 

perform the resurvey at a minimal cost. 

To verify that the repair has been made 

using OGI, no evidence of visible 

emissions must be seen during the 

survey. For Method 21, we are 

proposing that the instrument show a 

reading of less than 500 ppm above 

background from any of the repaired 

components. We solicit comment 

whether 500 ppm above background is 

the appropriate repair resurvey 

threshold when Method 21 instruments 

are used or if not, what the appropriate 

repair resurvey threshold is for Method 

21. 

The source of emissions must be 

repaired or replaced as soon as 

practicable, but no later than 15 

calendar days after detection of the 

fugitive emissions. If the repair or 

replacement is technically infeasible or 

unsafe during unit operations, the repair 

or replacement must be completed 

during the next scheduled shutdown or 

within six months, whichever is earlier. 

Equipment is unsafe to repair or replace 

if personnel would be exposed to an 

immediate danger in conducting 

monitoring. All sources of fugitive 

emissions that are repaired must be 

resurveyed to ensure the repair has been 

successful (i.e., no fugitive emissions 

are imaged using OGI or less than 500 

ppm above background when using 

Method 21). 

The EPA is proposing that these 

fugitive emission requirements be 

carried out through the development 

and implementation of a monitoring 

plan, which would specify the measures 

for locating sources of fugitive 

emissions and the detection technology 

to be used. The monitoring plan must 

also include a description of how the 

OGI survey will be conducted that 

ensures that fugitive emissions can be 

imaged effectively. In addition, we 

solicit comment on whether other 

techniques could be required elements 

of the monitoring plan in conjunction 

with OGI, such as visual inspections, to 

help identify signs such as staining of 

storage vessels or other indicators of 

potential leaks or improper operation. 

If fugitive emissions are detected 

during two consecutive semi-annual 

monitoring surveys at less than one 

percent of the fugitive emission 

components, then the monitoring survey 

frequency for that compressor station 

may be reduced to annually. If, during 

a subsequent monitoring survey, visible 

fugitive emissions are detected using 

OGI from one to three percent of the 

fugitive emission components, then the 

monitoring survey frequency for that 

compressor station must be increased to 

semiannually. 

If fugitive emissions are detected from 

three percent or more of the fugitive 

emission components during two 

consecutive semiannual monitoring 

surveys with OGI technology, then the 

monitoring survey frequency for that 

compressor station must be increased to 

quarterly. If, during a subsequent 

monitoring survey, fugitive emissions 

are detected from one to three percent 

of the fugitive emission components 

using OGI technology, then the 

monitoring survey frequency for that 

compressor station may be reduced to 

semiannually. If fugitive emissions are 

detected from less than one percent of 

the fugitive emission components, then 

the monitoring survey frequency for that 

well site may be reduced to annually. 

We solicit comment on the proposed 

metrics of one percent and three percent 

and whether these thresholds should be 

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specific numbers of components rather 

than percentages of components for 

triggering change in survey frequency 

discussed in this action. We also solicit 

comment on whether a performancebased frequency or a fixed frequency is 

more appropriate. 

As discussed in more detail in section 

VIII.G below and the TSD for this action 

available in the docket, we have 

identified OGI technology as the BSER 

for detecting fugitive emissions from 

new and modified compressor stations. 

The proposed standards apply to new 

and modified compressor stations 

throughout the oil and natural gas 

source category. As explained in section 

VII.G.3 below, compressor stations are 

considered modified for the purposes of 

these fugitive emission standards when 

one or more compressors is added to the 

station after [effective date of final rule]. 

3. Modification of the Collection of 

Fugitive Emissions Components at Well 

Sites and Compressor Stations 

For the purposes of the fugitive 

emission standards at well sites and 

compressor stations, we are proposing 

definitions of ‘‘modification’’ for those 

facilities that are specific to these 

provisions and for this purpose only. As 

provided in section 60.14(f), such 

provisions in the specific subparts 

would supersede any conflicting 

provisions in § 60.14 of the General 

Provisions. This definition does not 

affect other standards under this subpart 

for wells, other equipment at well sites 

or compressors. 

For purposes of the proposed fugitive 

emissions standards at well sites, we 

propose that a modification to a well 

site occurs only when a new well is 

added to a well site (regardless of 

whether the well is fractured) or an 

existing well on a well site is fractured 

or refractured. When a new well is 

added or a well is fractured or 

refractured, there is an increase in 

emissions to the fugitive emissions 

components because of the addition of 

piping and ancillary equipment to 

support the well, along with potentially 

greater pressures and increased 

production brought about by the new or 

fractured well. Other than these events, 

we are not aware of any other physical 

change to a well site that would result 

in an increase in emissions from the 

collection of fugitive components at 

such well site. To clarify and ease 

implementation, we propose to define 

‘‘modification’’ to include only these 

two events for purposes of the fugitive 

emissions provisions at well sites. We 

note that under § 60.5365a(a)(1) a well 

that is refractured, and for which the 

well completion operation is conducted 

according to the requirements of 

§ 60.5375a(a)(1) through(4), is not 

considered a modified well and 

therefore does not become an affected 

facility under the NSPS. We would like 

to clarify that such an exclusion of a 

‘‘well’’ from applicability under the 

NSPS would have no effect on the 

affected facility status of the ‘‘well site’’ 

for purposes of the proposed fugitive 

emissions standards. Accordingly, a 

well at an existing well site that is 

refractured constitutes a modification of 

the well site, which then would be an 

affected facility for purposes of the 

fugitive emission standards at 

§ 60.5397a, regardless of whether the 

well itself is an affected facility. 

In the 2012 NSPS, we provided that 

completion requirements do not apply 

to refracturing of an existing well that is 

completed responsibly (i.e. green 

completions). Building on the 2012 

NSPS, the EPA intends to continue to 

encourage corporate-wide voluntary 

efforts to achieve emission reductions 

through responsible, transparent and 

verifiable actions that would obviate the 

need to meet obligations associated with 

NSPS applicability, as well as avoid 

creating disruption for operators 

following advanced responsible 

corporate practices. To encourage 

companies to continue such good 

corporate policies and encourage 

advancement in the technology and 

practices, we solicit comment on criteria 

we can use to determine whether and 

under what conditions well sites 

operating under corporate fugitive 

monitoring programs can be deemed to 

be meeting the equivalent of the NSPS 

standards for well site fugitive 

emissions such that we can define those 

regimes as constituting alternative 

methods of compliance or otherwise 

provide appropriate regulatory 

streamlining. We also solicit comment 

on how to address enforceability of such 

alternative approaches (i.e., how to 

assure that these well sites are 

achieving, and will continue to achieve, 

equal or better emission reduction than 

our proposed standards). 

For the reasons stated above, we are 

also soliciting comments on criteria we 

can use to determine whether and under 

what conditions all new or modified 

well sites or compressor stations 

operating under corporate fugitive 

monitoring programs can be deemed to 

be meeting the equivalent of the NSPS 

standards for well sites or compressor 

stations fugitive emissions such that we 

can define those regimes as constituting 

alternative methods of compliance or 

otherwise provide appropriate 

regulatory streamlining. We also solicit 

comment on how to address 

enforceability of such alternative 

approaches (i.e., how to assure that 

these well sites and compressor stations 

are achieving, and will continue to 

achieve, equal or better emission 

reduction than our proposed standards). 

For purposes of the proposed 

standards for fugitive emission at 

compressor stations, we propose that a 

modification occurs only when a 

compressor is added to the compressor 

station or when physical change is made 

to an existing compressor at a 

compressor station that increases the 

compression capacity of the compressor 

station. Since fugitive emissions at 

compressor stations are from 

compressors and their associated 

piping, connections and other ancillary 

equipment, expansion of compression 

capacity at a compressor station, either 

through addition of a compressor or 

physical change to the an existing 

compressor, would result in an increase 

in emissions to the fugitive emissions 

components. Other than these events, 

we are not aware of any other physical 

change to a compressor station that 

would result in an increase in emissions 

from the collection of fugitive 

components at such compressor station. 

To clarify and ease implementation, we 

define ‘‘modification’’ as the addition of 

a compressor for purposes of the 

fugitive emissions provisions at 

compressor stations. 

H. Equipment Leaks at Natural Gas 

Processing Plants 

We are proposing standards to control 

methane and VOC emissions from 

equipment leaks at natural gas 

processing plants. These requirements 

are the same as the VOC equipment leak 

requirements in the 2012 NSPS and 

would require NSPS part 60, subpart 

VVa level of control, including a 

detection level of 500 ppm as in the 

2012 NSPS. As discussed further in 

section VIII.H, we propose that the 

subpart VVa level of control applied 

plant-wide is the BSER for controlling 

methane emissions from equipment 

leaks at onshore natural gas processing 

plants. We believe it provides the 

greatest emission reductions of the 

options we considered in our analysis in 

Section VIII.H, and that the costs are 

reasonable. 

I. Liquids Unloading Operations 

For the reasons discussed in section 

VIII.I, at this time the EPA does not have 

sufficient information to propose a 

standard for liquids unloading. 

However, we are requesting comment 

on nationally applicable technologies 

and techniques that reduce methane and 

VOC emissions from these events. 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56615 

Specifically, we request comment on 

technologies and techniques that can be 

applied to new gas wells that can reduce 

emissions from liquids unloading in the 

future. 

J. Recordkeeping and Reporting 

We are proposing recordkeeping and 

reporting requirements that are 

consistent with those required in the 

current NSPS for natural gas well 

completions, compressors and 

pneumatic controllers. Owners or 

operators would be required to submit 

initial notifications (except for wells, 

pneumatic controllers, pneumatic 

pumps and compressors, as provided in 

§ 60.5420(a)(1)) and annual reports, and 

to retain records to assist in 

documenting that they are complying 

with the provisions of the NSPS. 

For new, modified or reconstructed 

pneumatic controllers, owners and 

operators would not be required to 

submit an initial notification; they 

would simply need to report the 

installation of these affected facilities in 

their facility’s first annual report 

following the compliance period during 

which they were installed. Owners or 

operators of well-affected facilities 

(consistent with current requirements 

for gas well affected facilities) would be 

required to submit an initial notification 

no later than two days prior to the 

commencement of each well completion 

operation. This notification would 

include contact information for the 

owner or operator, the American 

Petroleum Institute (API) well number, 

the latitude and longitude coordinates 

for each well, and the planned date of 

the beginning of flowback. 

In addition, an initial annual report 

would be due no later than 90 days after 

the end of the initial compliance period, 

which is established in the rule. 

Subsequent annual reports would be 

due no later than the same date each 

year as the initial annual report. The 

annual reports would include 

information on all affected facilities 

owned or operated of sources that were 

constructed, modified or reconstructed 

during the reporting period. A single 

report may be submitted covering 

multiple affected facilities, provided 

that the report contains all the 

information required by 40 CFR 

60.5420(b). This information would 

include general information on the 

facility (i.e., company name and 

address, etc.), as well as information 

specific to individual affected facilities. 

For well affected facilities, the 

information required in the annual 

report would include the location of the 

well, the API well number, the date and 

time of the onset of flowback following 

hydraulic fracturing or refracturing, the 

date and time of each attempt to direct 

flowback to a separator, the date and 

time of each occurrence of returning to 

the initial flowback stage, and the date 

and time that the well was shut in and 

the flowback equipment was 

permanently disconnected or the startup 

of production, the duration of flowback, 

the duration of recovery to the flow line, 

duration of combustion, duration of 

venting, and specific reasons for venting 

in lieu of capture or combustion. For 

each oil well for which an exemption is 

claimed for conditions in which 

combustion may result in a fire hazard 

or explosion or where high heat 

emissions from a completion 

combustion device may negatively 

impact tundra, permafrost or waterways, 

the report would include the location of 

the well, the API well number, the 

specific exception claimed, the starting 

date and ending date for the period the 

well operated under the exception, and 

an explanation of why the well meets 

the claimed exception. The annual 

report would also include records of 

deviations where well completions were 

not conducted according to the 

applicable standards. 

For centrifugal compressor affected 

facilities, information in the annual 

report would include an identification 

of each centrifugal compressor using a 

wet seal system constructed, modified 

or reconstructed during the reporting 

period, as well as records of deviations 

in cases where the centrifugal 

compressor was not operated in 

compliance with the applicable 

standards. 

For reciprocating compressors, 

information in the annual report would 

include the cumulative number of hours 

of operation or the number of months 

since initial startup or the previous 

reciprocating compressor rod packing 

replacement, whichever is later, or a 

statement that emissions from the rod 

packing are being routed to a process 

through a closed vent system under 

negative pressure. 

Information in the annual report for 

pneumatic controller affected facilities 

would include location and 

documentation of manufacturer 

specifications of the natural gas bleed 

rate of each pneumatic controller 

installed during the compliance period. 

For pneumatic controllers for which the 

owner is claiming an exemption to the 

standards, the annual report would 

include documentation that the use of a 

pneumatic controller with a natural gas 

bleed rate greater than 6 scfh is required 

and the reasons why. The annual report 

would also include records of 

deviations from the applicable 

standards. 

For pneumatic pump affected 

facilities, information in the annual 

report would include an identification 

of each pneumatic pump constructed, 

modified or reconstructed during the 

compliance period, as well as records of 

deviations in cases where the pneumatic 

pump was not operated in compliance 

with the applicable standards. 

The proposed rule includes new 

requirements for monitoring and 

repairing sources of fugitive emissions 

at well sites and compressor stations. 

The owner or operator would be 

required to keep one or more digital 

photographs of each affected well site or 

compressor station. A photograph of 

every component that is surveyed 

during the monitoring survey is not 

required. The photograph must include 

the date the photograph was taken and 

the latitude and longitude of the well 

site imbedded within or stored with the 

digital file and must identify the 

affected facility. This could include a 

‘‘still’’ image taken using OGI 

technology or a digital photograph taken 

of the survey being performed. As an 

alternative to imbedded latitude and 

longitude within the digital photograph, 

the digital photograph may consist of a 

photograph of the affected facility with 

a photograph of a separately operating 

Geographic Information Systems (GIS) 

device within the same digital picture, 

provided the latitude and longitude 

output of the GIS unit can be clearly 

read in the digital photograph. The 

owner or operator would also be 

required to keep a log for each affected 

facility. The log must include the date 

monitoring surveys were performed, the 

technology used to perform the survey, 

the monitoring frequency required at the 

time of the survey, the number and 

types of equipment found to have 

fugitive emissions, the date or dates of 

first attempt to repair the source of 

fugitive emissions, the final repair of 

each source of fugitive emissions, any 

source of fugitive emissions found to be 

technically infeasible or unsafe to repair 

during unit operation and the date that 

source is scheduled to be repaired. 

These digital photographs and logs must 

be available at the affected facility or the 

field office. We solicit comment on 

whether these records also should be 

sent directly to the permitting agency 

electronically to facilitate review 

remotely. The owner or operator would 

also be required to develop and 

maintain a corporate-wide and site 

specific monitoring plan enabling the 

fugitive emissions monitoring program. 

Annual reports for each fugitive 

emissions affected facility would have 

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56616 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

43The 1977 House Committee Report noted: In 

the [1970] Congress [sic: Congress’s] view, it was 

only right that the costs of applying best practicable 

control technology be considered by the owner of 

a large new source of pollution as a normal and 

proper expense of doing business. 1977 House 

Committee Report at 184. Similarly, the 1970 

Senate Committee Report stated: 

The implicit consideration of economic factors in 

determining whether technology is ‘‘available’’ 

should not affect the usefulness of this section. The 

overriding purpose of this section would be to 

prevent new air pollution problems, and toward 

that end, maximum feasible control of new sources 

at the time of their construction is seen by the 

committee as the most effective and, in the long 

run, the least expensive approach. S. Comm. Rep. 

No. 91–1196 at 16. 

to be submitted that include the date 

monitoring surveys were performed, the 

technology used to perform the survey, 

the monitoring frequency required at the 

time of the survey, the number and 

types of component found to have 

fugitive emissions, the date of first 

attempt to repair the source of fugitive 

emissions, the date of final repair of 

each source of fugitive emissions, any 

source of fugitive emissions found to be 

technically infeasible or unsafe to repair 

during unit operation and the date that 

source is scheduled to be repaired. 

Consistent with the current 

requirements of subpart OOOO, records 

must be retained for 5 years and 

generally consist of the same 

information required in the initial 

notification and annual reports. The 

records may be maintained either onsite 

or at the nearest field office. We solicit 

comment on whether these records also 

should be sent directly to the permitting 

agency electronically to facilitate review 

remotely. 

Lastly, the EPA realizes that 

duplicative recordkeeping and reporting 

requirements may exist between the 

NSPS, Subpart W, and other state and 

local rules, and is trying to minimize 

overlapping requirements on operators. 

We solicit comment on ways to 

minimize recordkeeping and reporting 

burden. 

VIII. Rationale for Proposed Action for 

NSPS 

The following sections provide our 

BSER analyses and the resulting 

proposed new source performance 

standards to reduce methane and VOC 

emissions from across the oil and 

natural gas source category. Our general 

process for evaluating BSER for the 

emission sources discussed below 

included: (1) Identification of available 

control measures; (2) evaluation of these 

measures to determine emission 

reductions achieved, associated costs, 

nonair environmental impacts, energy 

impacts and any limitations to their 

application; and (3) selection of the 

control techniques that represent BSER. 

As mentioned previously and 

discussed in more detail below, the 

control technologies available for 

reducing methane and VOC emissions 

are the same for the emissions sources 

in this source category. This observation 

was made in the 2014 white papers and 

confirmed by the comments received on 

the 2014 white papers, as well as state 

regulations, including those of 

Colorado, that require methane and 

VOC mitigation measures from these 

sources of emissions. 

CAA Section 111 also requires that 

EPA considers cost in determining 

BSER. Section VIII.A below describes 

how EPA evaluates the cost of control 

for purposes of this rulemaking. 

Sections VIII.B through VIII.I provide 

the BSER analysis and the resulting 

proposed standards for individual 

emission sources contemplated in this 

action. 

Please note that there are minor 

differences in some values presented in 

various documents supporting this 

action. This is because some 

calculations have been performed 

independently (e.g., TSD calculations 

focused on unit-level cost-effectiveness 

and RIA calculations focused on 

national impacts) and include slightly 

different rounding of intermediate 

values. 

A. How does EPA evaluate control costs 

in this action? 

Section 111 requires that EPA 

consider a number of factors, including 

cost, in determining ‘‘the best system of 

emission reduction . . . adequately 

demonstrated.’’ While section 111 

requires that EPA consider cost in 

determining such system (i.e., ‘‘BSER’’), 

it does not prescribe any criteria for 

such consideration. However, in several 

cases, the D.C. Circuit has shed light on 

how EPA is to consider cost under CAA 

section 111(a)(1). For example, in Essex 

Chemical Corp. v. Ruckelshaus, 486 

F.2d 427, 433 (D.C. Cir. 1973), the D.C. 

Circuit stated that to be ‘‘adequately 

demonstrated,’’ the system must be 

‘‘reasonably reliable, reasonably 

efficient, and . . . reasonably expected 

to serve the interests of pollution 

control without becoming exorbitantly 

costly in an economic or environmental 

way.’’ The Court has reiterated this limit 

in subsequent case law, including 

Lignite Energy Council v. EPA, 198 F.3d 

930, 933 (D.C. Cir. 1999), in which it 

stated: ‘‘EPA’s choice will be sustained 

unless the environmental or economic 

costs of using the technology are 

exorbitant.’’ In Portland Cement Ass’n v. 

EPA, 513 F.2d 506, 508 (D.C. Cir. 1975), 

the Court elaborated by explaining that 

the inquiry is whether the costs of the 

standard are ‘‘greater than the industry 

could bear and survive.’’43 In Sierra 

Club v. Costle, 657 F.2d 298, 343 (D.C. 

Cir. 1981), the Court provided a 

substantially similar formulation of the 

cost standard when it held: ‘‘EPA 

concluded that the Electric Utilities’ 

forecasted cost was not excessive and 

did not make the cost of compliance 

with the standard unreasonable. This is 

a judgment call with which we are not 

inclined to quarrel.’’ We believe that 

these various formulations of the cost 

standard—‘‘exorbitant,’’ ‘‘greater than 

the industry could bear and survive,’’ 

‘‘excessive,’’ and ‘‘unreasonable’’—are 

synonymous; the DC Circuit has made 

no attempt to distinguish among them. 

For convenience, in this rulemaking, we 

will use reasonable to describe our 

evaluation of costs well within the 

boundaries established by this case law. 

In evaluating whether the cost of a 

control is reasonable, EPA considers 

various costs associated with such 

control, including capital costs and 

operating costs, and the emission 

reductions that the control can achieve. 

A cost-effectiveness analysis is one 

means of evaluating whether a given 

control achieves emission reduction at a 

reasonable cost. Cost-effectiveness 

analysis also allows comparisons of 

relative costs and outcomes (effects) of 

two or more options. In general, costeffectiveness is a measure of the benefit 

produced by resources spent. In the 

context of air pollution control options, 

cost-effectiveness typically refers to the 

annualized cost of implementing an air 

pollution control option divided by the 

amount of pollutant reductions realized 

annually. A cost-effectiveness analysis 

is not intended to constitute or 

approximate a cost-benefits analysis but 

rather provides a metric of the relative 

cost to reduction ratios of various 

control options. 

The estimation and interpretation of 

cost-effectiveness values is relatively 

straightforward when an abatement 

measure controls a single pollutant. 

Increasingly, however, air pollution 

reduction programs require reductions 

in emissions of multiple pollutants, and 

in such programs multipollutant 

controls may be employed. 

Consequently, there is a need for 

determining cost-effectiveness for a 

control option across multiple 

pollutants (or classes of multiple 

pollutants). This is the case for this 

proposal where, for the reasons 

explained in section V, we are 

proposing to directly regulate both 

methane and VOC. Further, as discussed 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56617 

44See e.g. 73 FR 64079–64083 and EPA 

Document I.D. EPA–HQ–OAR–2004–0022–0622, 

EPA–HQ–OAR–2004–0022–0447, EPA–HQ–OAR– 

2004–0022–0448. 

45The Energy Information Administration’s 2014 

Annual Energy Outlook forecasted wellhead prices 

paid to lower 48 state producers to be $4.46/Mcf in 

2020 and $5.06/Mcf in 2025. The $4/Mcf price 

assumed in the RIA is intended to reflect the AEO 

estimate but simultaneously be conservatively low. 

46For example, see our compliance cost analysis 

in ‘‘Regulatory Impact Analysis (RIA) for 

Residential Wood Heaters NSPS Revision. Final 

Report.’’ U.S. Environmental Protection Agency, 

Office of Air Quality Planning and Standards. EPA– 

452/R–15–001, February 2015. 

in more detail below, both methane and 

VOC are simultaneously and equiproportionally reduced when 

controlled. 

We have evaluated a number of 

approaches for considering the costs of 

the available multipollutant controls for 

reducing both methane and VOC 

emissions. One approach is to assign the 

entire annualized cost to the reduction 

in emissions of a single pollutant 

reduced by the multipollutant control 

option and treat the simultaneous 

reductions of the other pollutants as 

incidental or co-benefits. This was the 

approach we took in the 2012 NSPS but 

no longer believe to be appropriate for 

the reasons explained in section V. 

Under the current proposal, methane 

and VOCs are both directly regulated; 

therefore, reductions of each pollutant 

must be properly considered benefits, 

not co-benefits, and consideration of 

only one of the regulated pollutants is 

not appropriate. 

Alternatively, all annualized costs can 

be allocated to each of the pollutant 

emission reductions addressed by the 

multipollutant control option. Unlike 

the approach above, no emission 

reduction is treated as co-benefit; each 

emission reduction is assessed based on 

the full cost of the control. However, 

this approach, which is often used for 

assessing single pollutant controls, 

evaluates emission reduction of each 

pollutant separately, assuming that each 

bears the entire cost, and thus inflates 

the control cost in the multiple of the 

number of additional pollutants being 

reduced. This type of approach 

therefore over-estimates the cost of 

obtaining emissions reductions with a 

multipollutant control as it does not 

recognize the simultaneity of the 

reductions achieved by the application 

of the control option. 

Another type of approach allocates 

the annualized cost to the sum of the 

individual pollutant emission 

reductions addressed by the 

multipollutant control option. The 

multipollutant cost-effectiveness 

approach may be appropriate when each 

of the pollutant reductions is similar in 

value or impact. However, methane and 

VOC have quite different health and 

environmental impacts. Summing the 

pollutants to derive the denominator of 

the cost-effectiveness equation is 

inappropriate for this reason. Similarly, 

if the multiple pollutants could be 

combined with like units—for example, 

via economic valuation—the pollutants 

could be summed. We also think that 

this approach would be inappropriate 

here. 

For purposes of this proposal, we 

have identified and are proposing to use 

two types of approaches for considering 

the cost of reducing emissions from 

multiple pollutants using one control. 

One approach assigns all costs to the 

emission reduction of one pollutant and 

zero to all other concurrent reductions; 

if the cost is reasonable for reducing any 

of the targeted emissions alone, the cost 

of such control is clearly reasonable for 

the concurrent emission reduction of all 

the other pollutants because they are 

being reduced at no additional cost. 

This approach acknowledges the 

reductions as intended as opposed to 

incidental or co-benefits. It also reflects 

the actual overall cost of the control. 

While this approach assigns all costs to 

only a portion of the emission reduction 

and thus may overstate the cost for that 

assigned portion, it does not overstate 

the overall cost. It also does not require 

evaluating in aggregate the benefits of 

methane and VOC emission reduction, 

which is not appropriate as discussed in 

the option immediately above. In 

addition, this approach is simple and 

straightforward in application. If the 

multipollutant control is cost-effective 

for reducing emissions of either of the 

targeted pollutant, it is clearly costeffective for reducing all other targeted 

emissions that are being achieved 

simultaneously. 

A second approach, which we term 

for the purpose of this rulemaking a 

‘‘multipollutant cost-effectiveness’’ 

approach, apportions the annualized 

cost across the pollutant reductions 

addressed by the control option in 

proportion to the relative percentage 

reduction of each pollutant controlled. 

For example, in this proposal both 

methane and VOC emissions are 

reduced in equal proportion by the 

multipollutant control option. As a 

result, half of the control costs are 

allocated to methane, the other half to 

VOC. This approach similarly does not 

inflate the control cost nor requires 

evaluating in aggregate the benefits of 

methane and VOC emission reduction. 

We believe that both approaches 

discussed above are appropriate for 

assessing the reasonableness of the 

multipollutant controls considered in 

this action. As such, in our analyses 

below, if a device is cost-effective under 

either of these two approaches, we find 

it to be cost-effective. EPA has 

considered similar approaches in the 

past when considering multiple 

pollutants that are controlled by a given 

control option.44 The EPA recognizes, 

however, not all situations where 

multipollutant controls are applied are 

the same, and that other types of 

approaches, including those described 

above as inappropriate for this action, 

might be appropriate in other instances. 

The EPA solicits comments on the 

approaches to estimate costeffectiveness for emissions reductions 

using multipollutant controls assessed 

in this action. 

In considering control costs, the EPA 

takes into account any expected 

revenues from the sale of natural gas 

product that would be realized as a 

result of avoided emissions. Although 

no D.C. Circuit case addresses how to 

account for revenue generated from the 

byproducts of pollution control, or 

product saved as a result of control, it 

is logical and a reasonable interpretation 

of the statute that any expected 

revenues from the sale of recovered 

product may be considered when 

determining the overall costs of 

implementation of the control 

technology. Clearly, such a sale would 

offset regulatory costs and so must be 

included to accurately assess the costs 

of the standard. In our analysis we 

consider any natural gas that is either 

recovered or that is not emitted as a 

result of a control option as being 

‘‘saved.’’ We estimate that one thousand 

standard cubic feet (Mcf) of natural gas 

is valued at $4.00.45 Our cost analysis 

then applies the monetary value of the 

saved natural gas as an offset to the 

control cost. This offset applies where, 

in our estimation, the monetary savings 

of the natural gas saved can be realized 

by the affected facility owner or 

operator and not where the owner or 

operator does not own the gas and 

would not likely realize the monetary 

value of the natural gas saved (e.g., 

transmission stations and storage 

facilities). Detailed discussions of these 

assumptions are presented in Chapter 3 

of the RIA associated with this action, 

which is in the Docket. 

We also completed two additional 

analyses to further inform our 

determination of whether the cost of 

control is reasonable, similar to 

compliance cost analyses we have 

completed for other NSPS. 46 First, we 

compared the capitals costs that would 

be incurred to comply with the 

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47http://www.census.gov/econ/aces/xls/2013/

full_report.html. 

48For information on confidentiality protection, 

sampling error, and nonsampling error, see http:// 

www.census.gov/econ/susb/methodology.html. For 

definitions of estimated receipts and other 

definitions, see http://www.census.gov/econ/susb/

definitions.html. 

49Since the 2012 NSPS, we have not received 

information that would change our understanding 

that there are no centrifugal compressors in use at 

well sites. 

50See previous footnote regarding centrifugal 

compressors at well sites. 

51Factors came from U.S. Environmental 

Protection Agency. Methodology for Estimating CH4

and CO2 Emissions from Natural Gas Systems. 

Greenhouse Gas Inventory: Emission and Sinks 

1990–2012. Washington, DC. Annex 3.5. Table A– 

129. 

proposed standards to the industry’s 

estimated new annual capital 

expenditures. This analysis allowed us 

to compare the capital costs that would 

be incurred to comply with the 

proposed standards to the level of new 

capital expenditures that the industry is 

incurring in the absence of the proposed 

standards. We then determined whether 

the capital costs appear reasonable in 

comparison to the industry’s current 

level of capital spending. Second, we 

compared the annualized costs that 

would be incurred to comply with the 

standards to the industry’s estimated 

annual revenues. This analysis allowed 

us to evaluate the annualized costs as a 

percentage of the revenues being 

generated by the industry. 

EPA evaluated incremental capital 

cost in prior new source performance 

standards, and its determinations that 

the costs were reasonable were upheld 

by the courts. For example, the EPA 

estimated that the costs for the 1971 

NSPS for coal-fired electric utility 

generating units were $19 million for a 

600 MW plant, consisting of $3.6 

million for particulate matter controls, 

$14.4 million for sulfur dioxide 

controls, and $1 million for nitrogen 

oxides controls, representing a 15.8 

percent increase in capital costs above 

the $120 million cost of the plant. See 

1972 Supplemental Statement, 37 FR 

5767, 5769 (March 21, 1972). The D.C. 

Circuit upheld the EPA’s determination 

that the costs associated with the final 

1971 standard were reasonable, 

concluding that the EPA had properly 

taken costs into consideration. Essex 

Cement v. EPA, 486 F. 2d at 440. 

Similarly, in Portland Cement 

Association, the D.C. Circuit upheld the 

EPA’s consideration of costs for a 

standard of performance that would 

increase capital costs by about 12 

percent, although the rule was 

remanded due to an unrelated 

procedural issue. 486 F.2d at 387–88. 

Reviewing the EPA’s final rule after 

remand, the court again upheld the 

standards and the EPA’s consideration 

of costs, noting that ‘‘[t]he industry has 

not shown inability to adjust itself in a 

healthy economic fashion to the end 

sought by the Act as represented by the 

standards prescribed.’’ Portland Cement 

v. Ruckelshaus, 513 F. 2d 506, 508 (D.C. 

Cir. 1975). As shown below in the BSER 

analysis for each of the proposed 

standards, the associated increase in 

capital cost is well below the percentage 

increase previously upheld by the 

Court, and the annualized cost is but 

less than 1 percent of the annual 

revenue. 

Capital expenditure data for relevant 

NAICS codes were obtained from the 

U.S. Census 2013 Annual Capital 

Expenditures Survey.47 Annual revenue 

data for relevant NAICS codes were 

obtained from the U.S. Census 2012 

County Business Patterns and 2012 

Economic Census.48 For both the capital 

expenditures and annual revenues, we 

obtained the Census data and performed 

the analyses on an affected facility basis 

rather than an industry-wide basis. We 

did this to better reflect the fact that 

different owners or operators are 

generally involved in the different 

industry segments. Thus, an industrywide analysis would likely not be 

representative of the cost impacts on 

owners and operators within each 

segment. Although there is not a one-toone correspondence between NAICS 

codes and the industry segments we 

used in the development of the cost 

impacts, we believe there is enough 

similarity to draw accurate conclusions 

from our analysis. 

For the capital expenditures analysis, 

we determined the estimated 

nationwide capital costs incurred by 

each type of affected facility to comply 

with the proposed standards, then 

divided the nationwide capital costs by 

the new capital expenditures (Census 

data) for the appropriate NAICS code(s) 

to determine the percentage that the 

nationwide capital costs represent of the 

capital expenditures. Similarly, for the 

annual revenues analysis, we 

determined the estimated nationwide 

annualize costs incurred by each type of 

affected facility to comply with the 

proposed standards, then divided the 

nationwide annualized costs by the 

annual revenues (Census data) for the 

appropriate NAICS code(s) to determine 

the percentage that the nationwide 

annualized costs represent of annual 

revenues. These percentages are 

presented below in this section for each 

affected facility. 

B. Proposed Standards for Centrifugal 

Compressors 

In the 2012 NSPS, we established 

VOC standards for wet seal centrifugal 

compressors in the production segment 

of the oil and natural gas source 

category. Specifically, the standards 

apply to centrifugal compressors located 

after the well site and before 

transmission and storage segments 

because our data indicate that there are 

no centrifugal compressors in use at 

well sites.49 In this action, we are 

proposing to extend these VOC 

standards to the remaining wet seal 

centrifugal compressors in the source 

category. We are also proposing 

methane standards for all wet seal 

centrifugal compressors in the oil and 

natural gas source category. Based on 

the analysis below, the proposed VOC 

and methane standards described above 

are the same as the wet seal centrifugal 

compressor standards currently in the 

NSPS. 

Centrifugal compressors are used 

throughout the natural gas industry 50 to 

move natural gas along the pipeline. 

They are a source of methane and VOC 

emissions. These compressors are 

powered by turbines. They use a small 

portion of the natural gas that they 

compress to fuel the turbine. Sometimes 

an electric motor is used to turn a 

centrifugal compressor. 

Centrifugal compressors require seals 

around the rotating shaft to minimize 

gas leakage from the point at which the 

shaft exits the compressor casing. There 

are two types of seal systems: Wet seal 

systems and mechanical dry seal 

systems. 

Wet seal systems use oil, which is 

circulated under high pressure between 

three or more rings around the 

compressor shaft, forming a barrier to 

minimize compressed gas leakage. Very 

little gas escapes through the oil barrier, 

but considerable gas is absorbed by the 

oil. The amount of gas absorbed and 

entrained by the oil barrier is affected by 

the operating pressure of the gas being 

handled; higher operating pressures 

result in higher absorption of gas into 

the oil. Seal oil is purged of the 

absorbed and entrained gas (using 

heaters, flash tanks and degassing 

techniques) and recirculated to the seal 

area for reuse. Gas that is purged from 

the seal oil is commonly vented to the 

atmosphere. Degassing of the seal oil 

emits an average of 47.7 standard cubic 

feet per minute (scfm) of methane,51

depending on the operating pressure of 

the compressor. Based on the average 

gas composition, which varies among 

segments of the natural gas industry, we 

estimate methane emission during the 

venting process of an uncontrolled wet 

seal system to be, on average, 228 tpy 

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52Estimated uncontrolled VOC emissions from a 

wet seal compressor in the processing segment is 

not included here because these emissions are 

already subject to subpart OOOO and are not 

included in this proposed rule. 

53 IBID. 

54Estimated VOC emissions reductions from a 

wet seal compressor in the processing segment is 

not included here because these emissions are 

already subject to the NSPS are not included in this 

proposed rule. 

55 In 2012, we already found that the cost of this 

control to be reasonable for reducing VOC 

emissions from wet seal centrifugal compressors in 

the production segment. We are not reopening that 

decision in this action. Therefore, this cost finding 

is relevant only to VOC reduction from wet seal 

centrifugal compressors in the transmission and 

storage segments. 

in the production segment, 157 tpy in 

the transmission segment and 117 tpy in 

the storage segment. We estimate the 

VOC emissions to be, on average, 

approximately 4.34 tpy VOC in the 

transmission segment and 3.24 tpy of 

VOC in the storage segment.52

Dry seal systems do not use any 

circulating seal oil. Dry seals operate 

mechanically under the opposing force 

created by hydrodynamic grooves and 

springs. Fugitive emissions occur from 

dry seals around the compressor shaft. 

Based on manufacturer studies and 

engineering design estimates, fugitive 

emissions from dry seal systems are 

approximately 6 scfm of gas, much 

lower than wet seal systems. A dry seal 

system can have fugitive methane 

emissions of, on average, approximately 

28.6 tpy in the processing segment, and 

19.7 tpy in the transmission segment 

and 14.7 tpy in the storage segment. 

Likewise, VOC emissions are estimated 

to be 0.5 tpy in the transmission 

segment and 0.4 tpy in the storage 

segment.53 In the 2012 NSPS, we did 

not regulate fugitive VOC emissions 

from dry seal compressors because we 

did not identify any control device 

suitable to capture and control such 

emissions. For the same reasons we 

explained in the 2012 NSPS, we are not 

proposing methane standards for dry 

seal compressors. 

The available control techniques for 

reducing methane and VOC emissions 

from degassing of wet seal systems are 

the same. These include routing the gas 

to a process and routing the gas to a 

combustion device. We also consider 

replacing wet seal system with a dry 

seal system due to its inherent low 

emissions. These are the same options 

we previously identified for controlling 

fugitive VOC emissions from degassing 

of wet seal compressors. We did not 

find other available control options from 

our white paper process or information 

review. 

During the rulemakings for the 2012 

NSPS and subsequent amendments, we 

found that the dry seal system had 

inherently low VOC emissions and the 

option of routing to a process had at 

least 95 percent control efficiency. 

However, the integration of a centrifugal 

compressor into an operation may 

require a certain compressor size or 

design that is not available in a dry seal 

model, or in the case of capture of 

emissions with routing to a process, 

there may not be down-stream 

equipment capable of handling a low 

pressure fuel source. As such, these two 

options not technically feasible in all 

instances and, therefore, neither was the 

BSER for reducing fugitive VOC 

emissions from wet seal centrifugal 

compressors. Available information 

since then continues to show that that 

these two options cannot be used in all 

circumstances. For the same reasons, 

these options do not qualify as BSER for 

reducing methane emissions from wet 

seal centrifugal compressors. 

In the 2012 NSPS rulemaking, we 

found that a capture and combustion 

device (option 3) had a 95 percent VOC 

emission reduction efficiency. Available 

information since then continues to 

support that such device can achieve 95 

percent control efficiency and for both 

methane and VOC emissions. Based on 

the average uncontrolled emissions of 

wet seal systems discussed above and a 

capture and combustion device system 

efficiency of 95 percent, we determined 

that methane emissions from a wet seal 

system in the processing segment would 

be reduced by 217 tpy, by 149 tpy in the 

transmission segment and by 111 tpy in 

the storage segment. The VOC emissions 

would be reduced by 4.12 tpy in the 

transmission segment and by 3 tpy in 

the storage segment.54

For purposes of this action, we have 

identified in section VIII.A two 

approaches for evaluating whether the 

cost of a multipollutant control, such as 

option 3 (routing to a combustion 

device), is reasonable. As explained in 

that section, we believe that both 

approaches are appropriate for assessing 

the reasonableness of the multipollutant 

controls considered in this action. 

Therefore, we propose to find the cost 

of control to be reasonable as long as it 

is such under either of these two 

approaches. 

Under the single pollutant approach, 

we assign all costs to the reduction of 

one pollutant and zero to all other 

pollutants simultaneously reduced. For 

this approach, we would find the cost 

of control reasonable if it is reasonable 

for reducing one pollutant alone. As 

shown in the evaluation below, which 

assigns all the costs to methane 

reduction alone, and based on an 

annualized cost per compressor of 

$114,146 to install and operate a new 

combustion device for the processing, 

transmission and storage segments, we 

estimate the cost of control for reducing 

methane emissions from a wet seal 

centrifugal compressor to be $478 per 

ton for the processing segment, $767 per 

ton in the transmission segment and 

$1,028 per ton in the storage segment. 

The cost of the simultaneous VOC 

reduction is zero because all the costs 

have been attributed to methane 

reduction.55 It is important to note that 

these costs are likely over-estimates for 

most because they assume that each 

compressor requires a new, individual 

control device, which is not the case in 

most instances. It is our general 

understanding that multiple 

compressors can and do get routed to 

one common control. The estimates also 

do not reflect situations where 

installation of a control is not required 

because one is already available for use 

on site. 

For the reasons stated above, we 

believe that these estimates represent a 

conservative scenario and that the cost 

of this control (routing to a combustion 

control device) is lower in most 

instances. 

We also evaluate the cost of methane 

reduction by assigning all costs to VOC 

and zero to methane reduction. In the 

2012 NSPS rulemaking we already 

found the cost of this control to be 

reasonable for reducing VOC emissions 

from wet seal centrifugal compressors in 

the production segment. Therefore, the 

cost of methane reduction is reasonable 

for centrifugal compressors in the 

production segment if we assign all 

costs to VOC under the single pollutant 

approach. 

Although we propose to find the cost 

of control to be reasonable because it is 

reasonable under the above approach, 

we also evaluate the cost of this control 

under the multipollutant approach. 

Under the multipollutant approach, 

the costs are allocated based on the 

percentage reduction expected for each 

pollutant. Because option 3 reduces 

both methane and VOC by 95 percent, 

we attribute 50 percent of the costs to 

methane reduction and 50 percent of the 

cost to VOC reduction. Based on this 

formulation, the costs for methane 

reduction are half of the estimated costs 

under the first approach above and 

therefore we believe these costs are 

reasonable for the same reasons 

discussed above. For VOC, we estimate 

the multipollutant approach costs to be 

$13,853 per ton in the transmission 

segment and $18,553 per ton in the 

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56620 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

56 In the 2012 rulemaking, we already concluded 

that the cost of this control to be reasonable for 

reducing VOC emissions from wet seal centrifugal 

compressors in the production segment and set 

standards for such reduction. We are not reopening 

that decision here. Accordingly, we are not 

addressing VOC reduction in the production 

segment here. 

57As discussed later in this section, the control 

cost for reciprocating compressors at well site is not 

reasonable. 

storage segment.56 While these costs 

may seem high, as explained above, 

they are based on the assumption that 

a control device is required for each 

compressor, which is not the case in 

most instances. The estimates also do 

not reflect situations where installation 

of a control is not required because one 

is already available for use on site. For 

the reasons stated above, we believe the 

cost of VOC reduction with this control 

to be to lower than the above estimates 

in most instances. Because the operators 

of facilities in the transmission and 

storage segment typically do not own 

the gas they are handling, these costs do 

not account for gas savings in those 

segments. Although these reductions 

may not result in a direct financial 

benefit to the operator, we believe it is 

worthwhile to note that overall these 

standards save a non-renewable 

resource. 

As discussed above in section VIII.A 

two additional approaches, based on 

new capital expenditures and annual 

revenues, for evaluating whether the 

costs are reasonable. For the capital 

expenditure analysis, we used the 

capital expenditures for 2012 for NAICS 

4862 as reported in the U.S. Census 

data, which we believe is representative 

of the transmission and storage segment. 

The total capital costs for complying 

with the proposed standards for 

centrifugal compressors is 0.011 percent 

of the total capital expenditures, which 

we believe is reasonable. For the total 

revenue analysis, we used the revenues 

for 2012 for NAICS 486210, which we 

believe is representative of the 

transmission and storage segment. The 

total annualized costs for complying 

with the proposed standards is 0.001 

percent of the total revenues, which we 

believe is reasonable. 

For all types of affected facilities in 

the transmission and storage segment, 

the total capital costs for complying 

with the proposed standards is 0.24 

percent of the total capital expenditures, 

which is well below the percentage 

capital increase that courts have 

previously upheld as reasonable as 

discussed in Section VIII.A.. Similarly, 

the total annualized costs for complying 

with the proposed standards is also very 

low, at 0.11 percent of the total 

revenues. 

With this control option, there would 

be secondary air impacts from 

combustion. However we did not 

identify any nonair quality or energy 

impacts associated with this control 

technique. 

In light of the above, we find that the 

BSER for reducing VOC emissions from 

wet seal centrifugal compressors in the 

transmission and storage segment and 

for reducing methane emissions from all 

wet seal centrifugal compressors in the 

oil and natural gas source category are 

the same, i.e., to capture and route the 

emissions to a combustion control 

device. As discussed above, this option 

results in a 95 percent reduction of 

emissions for both methane and VOC. 

The 2012 NSPS requires that VOC 

emissions from wet seal centrifugal 

compressors in the natural gas 

production segment be reduced by 95 

percent, which similarly reflects the 

reduction that can be achieved by 

capturing and routing to a combustion 

control device. We are, therefore, 

proposing to extend the existing 95 

percent VOC reduction standard to all 

other wet seal centrifugal compressors 

in the oil and natural gas source 

category (i.e., natural gas transmission 

and storage segments). We are also 

proposing to require 95 percent 

reduction of methane emissions from all 

wet seal centrifugal compressors in the 

oil and natural gas source category. As 

in the 2012 NSPS, our proposal would 

allow dry seal systems and routing 

emissions to a process as alternatives to 

routing to a combustion device to meet 

the proposed 95 percent emission 

reduction standards. We hope that by 

such provisions, owners and operators 

would be encouraged to employ these 

effective emission control options where 

feasible. As described above, the 

proposed VOC and methane standards 

would be the same as the current VOC 

standards for wet seal centrifugal 

compressors in the NSPS. 

C. Proposed Standards for Reciprocating 

Compressors 

In the 2012 NSPS, we established 

VOC standards for reciprocating 

compressors in the production (located 

other than at well sites) and processing 

segments of the oil and natural gas 

source category. In this action, we are 

proposing VOC standards for the 

remaining reciprocating compressors in 

the source category that are not located 

at a well site. We are also proposing 

methane standards for all reciprocating 

compressors in the oil and natural gas 

source category except for those that are 

located at well sites.57 Based on the 

analysis below, the proposed VOC and 

methane standards described above are 

the same as the reciprocating 

compressor standards currently in the 

NSPS. 

Reciprocating compressors are used 

throughout the oil and natural gas 

industry and are a source of methane 

and VOC emissions. Emissions occur 

when natural gas leaks around the 

piston rod when pressurized natural gas 

is in the cylinder. The most significant 

volumes of gas loss and resulting 

fugitive methane and VOC emissions are 

associated with piston rod packing 

systems. Rod packing systems are used 

to maintain a tight seal around the 

piston rod, preventing the high pressure 

gas in the compressor cylinder from 

leaking, while allowing the rod to move 

freely. This leakage rate is dependent on 

a variety of factors, including physical 

size of the compressor piston rod, 

operating speed and operating pressure. 

Higher leak rates are a consequence of 

improper fit, misalignment of the 

packing parts and wear. We estimate 

that reciprocating compressors have 

emissions of 0.198 tpy methane and 

0.055 tpy VOC in the production 

segment (well sites), 12.3 tpy methane 

and 3.42 tpy VOC in the production 

segment (other than located at well site), 

23.3 tpy methane and 6.48 tpy VOC in 

the processing segment, 27.1 tpy 

methane and 0.75 tpy VOC in 

transmission segment, and 28.2 tpy 

methane and 0.78 tpy VOC in the 

storage segment. 

In developing the 2012 NSPS, we 

examined two options to reduce VOC 

emissions from reciprocating 

compressors. One approach was based 

on routing emission to a combustion 

device, as is used with wet seal 

centrifugal compressors. The other 

option was based on regular 

replacement of piston rod packing. 

Upon reconsideration of the standards 

in 2014, we evaluated a third option, 

routing of emissions to a process 

through a closed vent system under 

negative pressure. Information since the 

2012 NSPS development have not 

identified other control options for 

reciprocating compressors. 

We rejected combustion as the BSER 

because, as detailed in the 2011 TSD, 

routing of emissions to a control device 

can cause positive back pressure on the 

packing, which can cause safety issues 

due to gas backing up in the distance 

piece area and engine crankcase in some 

designs. While considering the option of 

routing of emissions to a process 

through a closed vent system under 

negative pressure, we determined that 

the negative pressure requirement not 

only ensures that all the emissions are 

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58Estimated VOC emissions reductions from 

reciprocating compressors in the production 

segment (at well sites and other than well sites) and 

the processing segment are not included here 

because these emissions are already subject to the 

NSPS are not included in this proposed rule. Under 

the 2012 NSPS we found the cost of control for VOC 

emissions from reciprocating compressors at well 

sites to be unreasonable and final rule did not set 

standards for reciprocating compressors located at 

well sites. 

59 VOC emissions reductions from reciprocating 

compressors in the production segment (at well 

sites and other than well sites) and the processing 

segment are already subject to the 2012 NSPS. We 

are not reopening those standards in this action. 60See footnote 56. 

conveyed to the process, it also avoids 

the issue of inducing back pressure on 

the rod packing and the resultant safety 

concerns. Although this option can be 

used in some circumstances, it cannot 

be applied in every installation. As a 

result, this option was not further 

considered for the determination of the 

BSER. 

As noted above, the most significant 

volumes of gas loss are associated with 

piston rod packing systems. We found 

that under the best conditions, new 

packing systems properly installed on a 

smooth, well-aligned shaft can be 

expected to leak a minimum of 11.5 scfh 

of natural gas. We determined that 

regular rod packing replacement, when 

carried out approximately every three 

years, effectively controls emissions and 

helps prevent excessive rod wear and 

determined that the BSER is regular 

replacement of rod packing. The control 

measures discussed above also reduce 

methane emissions. 

We are not aware of any other 

methods for controlling methane and 

VOC emissions from the rod packing of 

reciprocating compressors. We estimate 

that replacement of the compressor rod 

packing every 26,000 hours reduces 

methane emissions by 0.16 tpy in the 

production segment (well site) 6.84 tpy 

in the production segment (excluding 

the well site), 18.6 tpy in the processing 

segment, 21.7 tpy in the transmission 

segment, and 21.8 tpy in the storage 

segment. Likewise, replacement of rod 

packing is estimated to reduce VOC 

emissions by 0.6 tpy in the transmission 

and storage segments.58 See the 2011 

TSD and 2015 TSD for details of these 

calculations. 

For the 2012 NSPS, we estimated the 

annual costs of replacing the rod 

packing to be $2,493 for the production 

segment (well sites), $1,669 for the 

production segment (excluding well 

sites), $1,413 for processing plants, 

$1,748 for transmission stations, and 

$2,077 for storage facilities without 

considering the cost savings realized 

from the recovered gas. Considering gas 

savings, the annual cost of replacing the 

rod packing was $2,457 for the 

production segment (well sites), $83 for 

the production segment and a net 

savings for the processing segment. We 

did not consider gas savings for 

transmission and storage segments 

because owners and operators of these 

facilities do not necessarily own the gas 

they are handling and therefore would 

not realize gas savings. 

As explained in section VIII.A, for 

purposes of this action, we have 

identified two approaches for evaluating 

whether the cost of a multipollutant 

control, such as rod packing 

replacement described above, is 

reasonable. As explained in that section, 

we believe that both approaches are 

appropriate for assessing the 

reasonableness of the multipollutant 

controls considered in this action. 

Therefore, we propose to find the cost 

of control to be reasonable as long as it 

is such under either of these two 

approaches. 

Under the single pollutant approach, 

which attributes all cost to one pollutant 

and zero to the other pollutant, we 

would find the cost of control 

reasonable if it is reasonable for 

reducing one pollutant alone. When 

assigning all costs to methane alone and 

zero to the simultaneous VOC 

reduction, the cost of control is $15,802 

per ton for the production segment (well 

sites), $244 per ton of methane for the 

production segment (excluding well 

sites), $76 per ton of methane for the 

processing segment, $81 per ton of 

methane in the transmission segment 

and $95 per ton of methane in the 

storage segment. When assigning all 

costs to VOC alone and zero to the 

simultaneous methane reduction, the 

cost of control under this approach is 

$2,910 per ton of VOC reduced in the 

transmission segment, and $3,434 per 

ton of VOC reduced in the storage 

segment.59 In light of the above, we find 

the costs of rod-packing replacement are 

reasonable for reducing methane and 

VOC emissions across the industry 

(except at well sites) under the single 

pollutant approach irrespective of 

which pollutant bears all of the costs. 

Under the multipollutant approach, 

because the control achieves the same 

reduction for both methane and VOC, 

we would apportion the cost equally 

between methane and VOC. Rod 

Packing replacement reduces the 

amount of natural gas emitted by the 

compressor. This natural gas contains 

both methane and VOC; therefore, 

reducing the amount of natural gas 

emitted will reduce methane and VOC 

in equal proportion. Using the 

multipollutant approach, the cost of 

control for methane is $7,901 per ton for 

the production segment (well sites), 

$122 per ton for the production segment 

(excluding well sites), $38 per ton for 

the processing segment, $40 per ton for 

the transmission segment, and $48 per 

ton for the storage segment. The cost of 

control for VOC under the 

multipollutant approach is $1,455 per 

ton for the transmission segment and 

$1,717 per ton for the storage segment.60

In light of the above, with the exception 

of compressors located at well sites, we 

consider the costs to be reasonable for 

the estimated methane reductions across 

the source category and the estimated 

VOC reductions for the currently 

unregulated compressors under both 

approaches. In the 2012 NSPS 

rulemaking, we found the cost of rod 

packing not reasonable for reducing 

VOC emissions from reciprocating 

compressors at well sites. This finding 

remains unchanged under the two cost 

approaches discussed in section VIII.A. 

We also found the cost of control for 

methane emissions to not be reasonable 

for the amount of methane emissions 

achieved under either approach. 

As discussed in section VIII.A, we 

also identified two additional 

approaches, based on new capital 

expenditures and annual revenues, for 

evaluating whether the costs are 

reasonable. For the capital expenditure 

analysis, we used the capital 

expenditures for 2012 for NAICS 4862 

as reported in the U.S. Census data, 

which we believe is representative of 

the transmission and storage segment. 

The total capital costs for complying 

with the proposed standards for 

reciprocating compressors is 0.022 

percent of the capital expenditures, 

which is well below the percentage 

capital increase that courts have 

previously upheld as reasonable as 

discussed in Section VIII.A.. For the 

total revenue analysis, we used the 

revenues for 2012 for NAICS 486210, 

which we believe is representative of 

the transmission and storage segment. 

The total annualized cost for complying 

with the proposed standards is 0.003 

percent of the total revenues, which is 

also very low. 

For all types of affected facilities in 

the transmission and storage segment, 

the total capital cost for complying with 

the proposed standards is 0.24 percent 

of the capital expenditures, and the total 

annualized cost for complying with the 

proposed standards is also very low, at 

0.11 percent of the total revenues. 

We did not identify any nonair 

quality health or environmental impacts 

or energy impacts associated with 

replacement of rod packing and 

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56622 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

61Letter from John P. Miguez, Founder and Sr. 

Partner, M-Squared Products & Services, Inc., to 

Gina McCarthy, EPA Administrator, Petition for 

Reconsideration, January 20, 2015. 

62We did not address intermittent controllers in 

the 2012 NSPS, and we are not addressing them in 

this action. Intermittent controllers are inherently 

low emitting sources because they vent only when 

actuating and the total emissions are dependent on 

the applications in which they are used. 

63Emission factors and emissions data for 

production and processing segments are from TSD 

for the 2011 proposed rule, available in the docket. 

Emission factors for transmission and storage are 

from Subpart W Continuous Bleed Controller 

Emission Factors (Table W-1A of 40 CFR Part 98, 

Subpart W). Available at http://www.ecfr.gov/cgibin/text-idx?SID=dda4d1715e9926ee3517ac08e

6258817&node=40:21.0.1.1.3.23&rgn=div6

#ap40.21.98_1238.1. 

therefore, no analyses was conducted. In 

light of the above, we propose that rod 

packing replacement is the BSER for 

reducing methane and VOC emissions 

from compressors in the oil and natural 

gas sector, with the exception of 

reciprocating compressors located at 

well sites. See the 2011 and 2015 TSDs, 

available in the docket, for detail on 

methodology used for emissions and 

cost of control estimation. 

Because the VOC and methane 

emissions from reciprocating 

compressors are fugitive emissions that 

occur when natural gas leaks around the 

piston rod when pressurized natural gas 

is in the cylinder, it is technically 

infeasible capturing and routing 

emissions to a control device. Therefore, 

we are unable to set a numerical 

emission limit for reciprocating 

compressors. Pursuant to section 111(h), 

we are proposing an operation standard 

based on rod packing replacement. The 

proposed standards are the same as the 

current VOC standard in the NSPS for 

reciprocating compressors, which was 

also based on rod packing replacement. 

Specifically we propose to replace rod 

packing every 3 years of operation. 

However, to account for segments of the 

industry in which reciprocating 

compressors operate in pressurized 

mode for a fraction of the calendar year 

(ranging from approximately 68 percent 

up to approximately 90 percent), we 

determined that 26,000 hours of 

operation would be, on average, 

comparable to 3 years of continuous 

operation. As a result, we are proposing 

a work practice standard based on our 

determination that replacement of rod 

packing no later than after 26,000 hours 

of operation or after 36 calendar months 

represents the BSER. The owner or 

operator would be required to monitor 

the hours of operation beginning with 

the installation of the reciprocating 

compressor affected facility. Cumulative 

hours of operation would be reported 

each year in the facility’s annual report. 

Once the hours of operation reached 

26,000 hours, the owner or operator 

would be required to change the rod 

packing immediately, although 

unexpected shutdowns could be 

avoided by tracking hours of operation 

and planning for packing replacement at 

scheduled maintenance shutdowns 

before the hours of operation reached 

26,000. Alternatively, owners and 

operators may replace rod packing every 

36 months and would not be required to 

track operating hours of the compressor. 

As with the current requirement for 

controlling VOC from these 

reciprocating compressors, we are 

allowing routing of emissions from the 

rod packing to a process through a 

closed vent system under negative 

pressure as an alternative to rod packing 

replacement. As mentioned above, it is 

our understanding that this technology 

can capture all emissions; however, it 

may not be applicable to every 

compressor installation and situation 

and, therefore, it would be within the 

operator’s discretion to choose 

whichever option is most appropriate 

for the application and situation at 

hand. 

Following the December 31, 2014, 

amendments to the NSPS, which added 

the alternative of routing of emissions 

from the rod packing to a process 

through a closed vent system under 

negative pressure, we received a 

petition for administrative 

reconsideration of the standard for 

reciprocating compressors.61 The 

petitioner requested that EPA provide 

an additional alternative to the rod 

packing replacement intervals of 26,000 

hours or 36 months. The alternative 

suggested by the petitioner would 

consist of monitoring of rod packing 

leakage to identify when the rate of rod 

packing leakage indicates that packing 

replacement is needed. We have 

requested additional information from 

the petitioner on the technical details of 

the petitioner’s concept. As a result, we 

are unable at this time to evaluate the 

alternative suggested by the petitioner. 

D. Proposed Standards for Pneumatic 

Controllers 

In the 2012 NSPS, we established 

VOC standards for pneumatic 

controllers in the production and 

processing segments of the oil and 

natural gas source category. In this 

action, we are proposing VOC standards 

for the remaining pneumatic controllers 

in the source category. We are also 

proposing methane standards for all 

pneumatic controllers in the oil and 

natural gas source category. Based on 

the analysis below, the BSER for 

reducing the methane and VOC 

emissions from the pneumatic 

controllers described above are the same 

as the BSER for those that are currently 

subject to the VOC standards. 

Accordingly, the proposed VOC and 

methane standards described above are 

the same as the pneumatic controller 

standards currently in the NSPS. 

Pneumatic controllers are automated 

instruments used for maintaining a 

process condition, such as liquid level, 

pressure, pressure differential and 

temperature that typically operate by 

using available high-pressure natural 

gas. 

In these ‘‘gas-driven’’ pneumatic 

controllers, natural gas may be released 

with every valve movement or 

continuously from the valve control 

pilot. The rate at which this release 

occurs is referred to as the device bleed 

rate. Bleed rates are dependent on the 

design of the device. Similar designs 

will have similar steady-state rates 

when operated under similar 

conditions. Gas-driven pneumatic 

controllers are typically characterized as 

‘‘high-bleed’’ or ‘‘low-bleed,’’ where a 

high-bleed device releases more than 6 

scfh of gas. There are two basic designs: 

(1) continuous bleed devices (high or 

low-bleed) are used to modulate flow, 

liquid level or pressure, and gas is 

vented at a steady-state rate; and (2) 

intermittent devices perform quick 

control movements and only release gas 

when they open or close a valve or as 

they throttle the gas flow.62

Not all pneumatic controllers are gas 

driven. These ‘‘non-gas driven’’ 

pneumatic controllers use sources of 

power other than pressurized natural 

gas, such as compressed ‘‘instrument’’ 

air. Because these devices are not gas 

driven, they do not release natural gas 

(or methane or VOC emissions), but they 

do have energy impacts because 

electrical power is required to drive the 

instrument air compressor system. 

As we explained for the 2012 NSPS, 

because manufacturers’ technical 

specifications for pneumatic controllers 

are stated in terms of natural gas bleed 

rate rather than methane or VOC, we 

used natural gas as a surrogate for VOC. 

We evaluated the impact of a high-bleed 

pneumatic controller emission rate (37 

scfh of natural gas for the production 

and processing segments and 18 scfh of 

natural gas for the transmission and 

storage segments) contrasted with the 

emission rate of a low-bleed unit (1.39 

scfh of natural gas for the production 

and processing segments and 1.37 scfh 

of natural gas for the transmission and 

storage segment).63 We determined percontroller high-bleed pneumatic 

controller methane emissions to be 6.91 

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64Estimated VOC emissions from pneumatic 

controllers in the production and processing 

segments are not included here because these 

emissions are already subject to the NSPS are not 

included in this proposed rule. 

65We note that VOC emissions from pneumatic 

controllers in the production and processing 

segments are already subject to subpart 0000. We 

are not reopening those standards in this 

rulemaking. 

66We note that during the 2012 NSPS 

rulemaking, we already determined the costs of 

VOC reduction from pneumatic controllers at the 

production and processing segments to be 

reasonable. Accordingly, under the single-pollutant 

approach, the costs would also be reasonable for 

methane reduction as well for those pneumatic 

controllers. 

tpy in the production segment, 1 tpy in 

the processing segment and 3.01 tpy in 

the transmission and storage segment. 

We estimate high-bleed pneumatic 

controller emissions to be 0.08 tpy VOC 

in the transmission and storage 

segments.64 In contrast, we estimate the 

per-controller low-bleed pneumatic 

controller methane emissions to be 0.26 

tpy in the production segment, 1 tpy in 

the processing segment, and 0.23 tpy in 

the transmission and storage segments. 

We estimate the low-bleed pneumatic 

controller VOC emissions to be 0.006 

tpy in the transmission and storage 

segment. 

We are not aware of any add-on 

controls that are or can be used to 

reduce methane or VOC emissions from 

gas-driven pneumatic controllers. 

Therefore, the available control 

techniques for reducing methane and 

VOC emissions from pneumatic 

controllers are the same, which are: (1) 

use of a low-bleed controllers; or (2) use 

of non-gas driven controllers (i.e., 

instrument air systems). These are the 

same control options we previously 

identified in the 2012 NSPS for 

controlling VOC emissions from 

pneumatic controllers. We did not find 

other available control options from our 

white paper process or information 

review. 

As in the 2012 NSPS, our current 

analysis indicates that in order to use an 

instrument air system, a constant 

reliable electrical supply would be 

required to run the compressors for the 

system. At sites without available 

electrical service sufficient to power an 

instrument air compressor, only gas 

driven pneumatic devices are 

technically feasible in all situations. 

Therefore, for the production and 

transmission and storage segments, 

where electrical service sufficient to 

power an instrument air system is likely 

unavailable, we evaluated only the 

option to use low-bleed controllers in 

place of high-bleed controllers. 

During the development of the 2012 

NSPS, we estimated methane emissions 

along with VOC emissions from 

pneumatic controllers. We estimated 

that for an average high-bleed 

pneumatic controller located in the 

production segment, the difference in 

emissions between a high-bleed 

controller and a low-bleed controller is 

6.65 tpy methane.65 We also estimated 

that replacing a natural gas-driven 

pneumatic controller in the processing 

segment with an instrument air system 

would reduce methane emissions by 1 

tpy. Further, we estimate that the 

emission reductions of replacing a highbleed with a low-bleed pneumatic 

controller in the transmission and 

storage segment would be 2.79 tpy of 

methane and 0.077 tpy of VOC per 

controller. 

For purposes of this action, we have 

identified in section VIII.A two 

approaches for evaluating whether the 

cost of a multipollutant control, such as 

replacing a high-bleed controller with a 

low-bleed controller, is reasonable. As 

explained in that section, we believe 

that both the single and multipollutant 

approaches are appropriate for assessing 

the reasonableness of the multipollutant 

controls considered in this action. 

Therefore, we find the cost of control to 

be reasonable as long as it is such under 

either of these two approaches. 

Under the single pollutant approach, 

we assign all costs to the reduction of 

one pollutant and zero to all other 

pollutants simultaneously reduced. For 

this approach, we would find the cost 

of control reasonable if it is reasonable 

for reducing one pollutant alone. The 

evaluation below for pneumatic 

controllers in the production, 

transmission and storage segments first 

assigns all the costs to methane 

reduction alone, and uses an 

incremental capital cost difference 

between a new high-bleed controller 

and a new low-bleed controller of $165 

for the production segment and $227 for 

the transmission and storage segment, 

which results in cost of control of $24 

for the production segment and $25 for 

the transmission and storage segment. 

We estimate the cost of replacing 

high-bleed controllers with low-bleed 

controllers to be $4 per ton of methane 

reduced in the production segment and 

$9 per ton of methane reduced in the 

transmission and storage segment. We 

find these costs to be reasonable for the 

amount of methane reduction it can 

achieve. Also, because all the costs have 

been attributed to methane reduction, 

the cost of simultaneous VOC reduction 

is zero and therefore reasonable. We 

also evaluated the cost by attributing all 

the costs to VOC reduction and 

estimated the cost to be $13 per ton of 

VOC reduction in the production 

segment and $323 per ton of VOC 

reduction in the transmission and 

storage segment.66 We also find these 

costs to be reasonable. 

Although we propose to find the cost 

of control to be reasonable because it is 

reasonable under the above approach, 

we also evaluated the cost on this 

control under the multipollutant 

approach. Under this approach, the 

costs are allocated based on the 

percentage reduction expected for each 

pollutant. Because replacing a highbleed controller with a low-bleed 

controller reduces the natural gas 

emitted by the controller, both methane 

and VOC are reduced equally, we 

attribute 50 percent of the costs to 

methane reduction and 50 percent of the 

costs to VOC reduction. Based on this 

formulation, the costs for methane and 

VOC reduction are half of the estimated 

costs under the first approach and are 

therefore reasonable. 

We also identified in section VIII.A 

two additional approaches, based on 

new capital expenditures and annual 

revenues, for evaluating whether the 

costs are reasonable. For the capital 

expenditure analysis, we used the 

capital expenditures for 2012 for NAICS 

4862 as reported in the U.S. Census 

data, which we believe is representative 

of the transmission and storage segment. 

The total capital cost for complying 

with the proposed standards for 

pneumatic controllers is 0.0022 percent 

of the total capital expenditures, which 

is well below the percentage capital 

increase that courts have previously 

upheld as reasonable as discussed in 

Section VIII.A.. For the total revenue 

analysis, we used the revenues for 2012 

for NAICS 486210, which we believe is 

representative of the transmission and 

storage segment. The total annualized 

cost for complying with the proposed 

standards is 0.0001 percent of the total 

revenues, which is also very low. 

For all types of affected facilities in 

the transmission and storage segment, 

the total capital costs for complying 

with the proposed standards is 0.24 

percent of the total capital expenditures, 

and the total annualized costs for 

complying with the proposed standards 

is 0.11 percent of the total revenues, 

which is also very low. 

With this option, we do not anticipate 

any secondary air impacts. We also did 

not identify any nonair quality or energy 

impacts associated with this control 

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56624 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

67 In the 2012 NSPS, EPA established VOC 

standards for pneumatic controllers at natural gas 

processing plants. We are not reopening up those 

standards in this proposed rule. 

68Oil and Natural Gas Section: Standards of 

Performance for Crude Oil and Natural Gas 

Production, Transmission, and Distribution— 

Background Supplemental Technical Support 

Document for the Final New Source Performance 

Standards, USEPA, Office of Air Quality Planning 

and Standards, April 2012. 

technique, therefore, these impacts were 

not analyzed. 

In light of the above, we find that the 

BSER for reducing methane emissions 

from continuous bleed natural gasdriven pneumatic controllers in the 

production and transmission and 

storage segment and VOC emissions 

from the remaining unregulated 

pneumatic controllers (i.e., those in the 

transmission and storage segment) 

would be the installation of low-bleed 

pneumatic controllers. This is the same 

BSER we identified in the 2012 final 

rule for reducing VOC emissions from 

pneumatic controllers in the production 

and processing segments. 

Accordingly, we are proposing a 

methane emission standard for 

continuous-bleed, natural gas-driven 

pneumatic controllers in the production 

and transmission and storage segment to 

be a natural gas bleed rate of less than 

or equal to 6 scfh. We are also proposing 

a VOC emissions standard for 

continuous-bleed, natural gas-driven 

pneumatic controllers in the 

transmission and storage segment to be 

a natural gas bleed rate of less than or 

equal to 6 scfh. As described above, the 

proposed methane and VOC standards 

would be the same as the current VOC 

standards for pneumatic controllers in 

the production segment in the NSPS. 

It is important to note that these costs 

are most likely over-estimates because 

they do not take into account the cost 

savings that would result based on the 

value of natural gas saved. Therefore, 

the above cost estimated, which we 

have already found to be reasonable, 

represent a conservative scenario and 

that the cost of these controls are lower 

in most instances. 

For the processing segment, which 

comprises pneumatic controllers at 

natural gas processing plants, we 

identified instrument air systems and 

replacement of high-bleed controllers 

with low-bleed controllers as control 

options for reducing methane emissions 

from pneumatic controllers.67 These are 

the same options we identified for the 

2012 rule to reduce VOC emissions from 

these pneumatic controllers. As 

described below, we first evaluated the 

cost of an instrument air system to 

reduce methane emissions. Since we 

found these costs to be reasonable (as 

discussed below), we did not evaluate 

the costs of replacing the high-bleed 

pneumatic controllers with low-bleed 

controllers because the replacement 

option would result in less methane 

emission reduction than the instrument 

air option. 

The annual costs of the instrument air 

system per gas processing plant without 

considering the cost savings realized 

from the recovered gas are $11,090, and 

$7,676 when considering these savings. 

See the 2012 Supplemental TSD 68 for 

details of these calculations. 

We evaluate the cost of using an 

instrument air system to reduce 

methane emissions from the pneumatic 

controllers at gas processing plants 

based on the two approaches identified 

earlier in this section for considering the 

cost of a multipollutant control (in this 

case the instrument air system). Under 

the single pollutant approach, which 

assigns all costs to the reduction of one 

pollutant and zero to all other pollutants 

simultaneously reduced, we would find 

the cost of control reasonable if it is 

reasonable for reducing one pollutant 

alone. In the 2012 NSPS rulemaking, we 

already determined that the cost of this 

control for reducing VOC emissions 

alone is reasonable for pneumatic 

controllers at gas processing plants (76 

FR 52760). Having assigned all the cost 

to VOC, the cost of methane reduction 

would be zero and therefore clearly 

reasonable. If we assign all the cost to 

methane instead, it is $738 per ton 

without considering cost savings and 

$506 per ton considering cost savings. 

These costs do not appear excessive, nor 

do we have reason to believe that they 

are beyond what the industry can bear. 

In light of the above, we find the cost 

of reducing methane emissions from the 

pneumatic controllers at gas processing 

plants to be reasonable under the single 

pollutant approach. 

The second approach is to evaluate 

the cost on a multipollutant basis, based 

on the percentage reduction expected of 

VOC and methane. We estimate that 

replacing high-bleed pneumatic 

controllers with a non-natural gas 

driven pneumatic controller (i.e., 

instrument air-powered) reduces 

methane emissions by 15 tpy and VOC 

emissions by 4.2 tpy at gas processing 

plants. Refer to the 2012 TSD for details 

of these calculations. Because the 

control achieves the same reduction for 

both methane and VOC, under this 

approach, we apportion the cost 

equally, resulting in a cost of control of 

$369 per ton of methane reduced 

without considering gas savings. 

Considering gas savings, the cost of 

control is $253 per ton of methane. 

These costs do not appear excessive, nor 

do we have reason to believe that they 

are beyond what the industry can bear. 

With respect to the VOC control cost 

under this approach, as mentioned 

above, in the 2012 NSPS rulemaking, we 

already determined that the cost of this 

control for reducing VOC emissions 

alone is reasonable for pneumatic 

controllers at gas processing plants (76 

FR 52760). The cost of VOC reduction 

under the multiple pollutant approach 

would be half of that cost and therefore 

clearly reasonable. In light of the above, 

we find the cost of reducing methane 

emissions from pneumatic controllers at 

gas processing plants to be reasonable as 

well under the multi-pollutant 

approach. As mentioned above, we did 

not identify any nonair quality or energy 

impacts associated with this control 

option, therefore no impacts were 

analyzed. 

Based on the above considerations, 

we propose that pneumatic controllers 

powered by an instrument air system 

are the BSER for reducing methane 

emission from pneumatic controllers at 

gas processing plants. This is the same 

BSER we identified for reducing VOC 

emissions from pneumatic controllers at 

gas processing plants in the 2012 final 

rule. 

For the reasons discussed above and 

in the TSD, we have determined that 

BSER for reducing methane emissions 

from pneumatic controllers in the 

processing segment to be instrument airactivated controllers which represent an 

emission rate of zero for methane. 

Accordingly, we are proposing a 

methane standard for pneumatic 

controllers in the processing segment to 

be a natural gas bleed rate of zero. This 

is the same as the VOC standard for 

these pneumatic controllers in the 2012 

NSPS. 

We have identified situations where 

high-bleed controllers are necessary due 

to functional requirements, such as 

positive actuation or rapid actuation. An 

example would be controllers used on 

large emergency shutdown valves on 

pipelines entering or exiting 

compression stations. The current NSPS 

takes this into account by exempting 

pneumatic controllers from meeting the 

applicable emission standards if 

compliance would pose a functional 

limitation due to their actuation 

response time or other operating 

characteristics. We propose to similarly 

exempt pneumatic controllers from 

meeting the proposed methane standard 

if compliance would pose a functional 

limitation due to their actuation 

response time or other operating 

characteristics. 

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69 GRI/EPA, 1996d. 

70EPA/GRI. Methane Emissions from the Natural 

Gas Industry, Volume 13: Chemical Injection 

Pumps. June 1996 (EPA–60/R –96– 80m), Sections 

5.1—Diaphragm Pumps and 5.2—Piston Pumps. 

71U.S. EPA, 2011b. 

72Subpart OOOOa defines ‘‘route to a process’’ to 

mean that ‘‘the emissions are conveyed via a closed 

vent system to any enclosed portion of a process 

where the emissions are predominantly recycled 

and/or consumed in the same manner as a material 

that fulfills the same function in the process and/ 

or transformed by chemical reaction into materials 

that are not regulated materials and/or incorporated 

into a product; and/or recovered.’’ 

E. Proposed Standards for Pneumatic 

Pumps 

In the 2012 NSPS, we did not 

establish standards for pneumatic 

pumps. Pneumatic pumps are devices 

that use gas pressure to drive a fluid by 

raising or reducing the pressure of the 

fluid by means of a positive 

displacement, a piston or set of rotating 

impellers. Gas powered pneumatic 

pumps are generally used at oil and 

natural gas production sites where 

electricity is not readily available and 

can be a significant source of methane 

and VOC emissions.69 As discussed 

previously, in April 2014, the EPA 

published a white paper titled ‘‘Oil and 

Natural Gas Sector Pneumatic Devices.’’ 

The paper summarized the EPA’s 

understanding of methane and VOC 

emissions from pneumatic pumps and 

also presented the EPA’s understanding 

of mitigation techniques (practices and 

equipment) available to reduce these 

emissions, including the efficacy and 

cost of the technologies and the 

prevalence of use in the industry. 

During our review of the public and 

peer review comments on the white 

paper and the Wyoming state rules, we 

identified different types of pneumatic 

pumps that are commonly used in the 

oil and natural gas sector. Wyoming is 

the only state of which we are aware 

that has air emission standards for 

pneumatic pumps. Pneumatic chemical 

and methanol injection pumps are 

generally used to pump fairly small 

volumes of chemicals or methanol into 

well-bores, surface equipment, and 

pipelines. Typically, these pumps 

include plunger pumps with a 

diaphragm or large piston on the gas 

end and a smaller piston on the liquid 

end to enable a high discharge pressure 

with a varied but much lower 

pneumatic supply gas pressure. They 

are typically used semi-continuously 

with some seasonal variation. 

Pneumatic diaphragm pumps are 

another type used widely in the oil and 

natural gas sector to move larger 

volumes of liquids per unit of time at 

lower discharge pressures than chemical 

and methanol injection pumps. The 

usage of these pumps is episodic 

including transferring bulk liquids such 

as motor oil, pumping out sumps, and 

circulation of heat trace medium at well 

sites in cold climates during winter 

months. 

Emissions from pneumatic pumps 

occur when the gas used in the pump 

stroke is exhausted to enable liquid 

filling of the liquid chamber side of the 

diaphragm. Emissions are a function of 

the amount of fluid pumped, the 

pressure of the pneumatic supply gas, 

the number of pressure ratios between 

the pneumatic supply gas pressure and 

the fluid discharge pressure, and the 

mechanical inefficiency of the pump. 

Based on emission factors obtained 

from an EPA/GRI report 70 we estimate 

emissions from natural gas-driven 

piston pumps (i.e., pneumatic chemical 

and methanol injection pumps) and 

diaphragm pumps in both the 

production and processing segments to 

be 2.48 scf natural gas per hour and 

22.45 scf natural gas per hour 

respectively. Based on these emission 

rates, and using the gas composition 

developed during the 2012 NSPS for the 

production and processing segments 

(i.e., natural gas is 82.9 percent methane 

and VOC constitutes 0.27797 pounds of 

VOC per pound of methane), we 

estimate the baseline emissions from a 

natural gas-driven piston pump in either 

the production or processing segment to 

be 0.38 tpy of methane and 0.11 tpy of 

VOC, and a gas-driven diaphragm pump 

to be 3.46 tpy of methane and 0.96 tpy 

of VOC. 

We estimate that emissions in the 

transmission and storage segment are 

2.21 scf natural gas per hour for a 

pneumatic piston pump and 20.05 scf 

natural gas per hour for a diaphragm 

pump. Based on these emissions rates, 

and using the gas composition 

developed during the 2012 NSPS for the 

transmission and storage segment (i.e., 

natural gas is 92.8 percent methane and 

VOC constitutes 0.0277 pounds of VOC 

per pound of methane), we estimate the 

baseline emissions from a natural gasdriven piston pump to be 0.38 tpy of 

methane and 0.01 tpy of VOC, and a gasdriven diaphragm pump to be 3.46 tpy 

of methane and 0.10 tpy of VOC in the 

transmission and storage segment. 

These emission estimates are explained 

in detail in the TSD for this action 

available in the docket. 

As discussed in the white paper, we 

identified several options for reducing 

methane and VOC emissions from 

natural gas-driven pumps: replace 

natural gas-driven pumps with 

instrument air pumps, replace natural 

gas-driven pumps with solar-powered 

direct current pumps (solar pumps), 

replace natural gas-driven pumps with 

electric pumps, and route natural gasdriven pump emissions to a control 

device. In some applications, chemical 

injection pumps can be retrofitted with 

instrument air to drive the pumps.71

During our review of the Wyoming state 

rule covering pneumatic pumps, we 

identified an additional mitigation 

option for reducing emission from 

piston and diaphragm natural gasdriven pumps, which involves routing 

the gas to a process 72 or routing the gas 

to a combustor (often done as part of the 

storage vessel control system). As with 

the BSER for wet seal centrifugal 

compressors discussed earlier in this 

section, the emission reduction 

potential for this option is estimated at 

95 percent based on the efficiencies of 

the capture system and the combustion 

device. No further control options were 

identified from our white paper process 

or information review. 

Instrument air systems and electric 

pumps require a reliable, constant 

supply of electrical power. Because of 

their remote locations, well sites, 

gathering and boosting stations and 

potentially transmission stations and 

storage facilities may not necessarily 

have a constant, reliable electrical 

power supply. Therefore, we do not 

believe the use of instrument air 

systems and electric pumps are feasible 

at all facilities in the production and 

transmission and storage segments. 

However, we take comment on is the 

availability of a constant, reliable source 

of electrical power at facilities 

throughout the oil and natural gas 

source category. 

Natural gas processing plants are 

known to have a constant and reliable 

source of electrical power. Therefore, 

instrument air systems are technically 

feasible at natural gas processing plants. 

Because pumps powered by instrument 

air systems release no natural gas, the 

methane and VOC emissions are 

reduced by 100 percent under this 

control option. 

For natural gas processing plants, the 

potential emission reduction for the 

instrument air option is 3.46 tpy of 

methane and 0.96 tpy of VOC for each 

diaphragm pump, and 0.38 tpy of 

methane and 0.11 tpy of VOC for each 

piston pump replaced. 

While solar pumps can be installed in 

certain situations, these pumps are not 

technically feasible in all situations for 

which piston pumps and diaphragm 

pumps are needed. Specifically, weather 

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56626 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

73This is well below the amount we find 

reasonable for reducing fugitive methane emissions 

at well site (see Section VIII.G.1 below). 74This is well below the amount we find 

reasonable for reducing fugitive methane emissions 

at well site (see Section VIII.G.1 below). 

conditions in certain areas can limit the 

effectiveness of solar pumps and the 

capacity of solar pumps is also limited, 

so they cannot be used in all situations 

where larger pumps are needed. 

Therefore, solar pumps are not 

universally feasible control option for 

the production and transmission and 

storage segments. 

As a result, we further analyzed the 

remaining potential control option for 

the production and transmission and 

storage segments, which is routing of 

natural gas-driven pump emissions to a 

process (e.g., used as fuel for a 

combustion source) or control device. 

Assuming that emissions are routed 

through a closed vent system to a 

control device or process, we believe 

these control options achieve a 95 

percent reduction in emissions of 

methane and VOC. 

Based on a 95 percent reduction, we 

estimate the reduction in emissions in 

the production segment to be 0.36 tpy 

methane and 0.10 tpy VOC per piston 

pump and 3.29 tpy of methane and 0.91 

tpy of VOC per diaphragm pump. In the 

transmission and storage segment, we 

estimate the reduction in emissions to 

be 0.36 tpy of methane and 0.01 tpy 

VOC per piston pump and 3.29 tpy of 

methane and 0.09 tpy of VOC per 

diaphragm pump. 

For purposes of this action, we have 

identified in section VIII.A two 

approaches for evaluating whether the 

cost of a multipollutant control, such as 

routing emissions to a combustion 

device, is reasonable. As explained in 

that section, we believe that both 

approaches are appropriate for assessing 

the reasonableness of the multipollutant 

controls considered in this action. 

Therefore, we find the cost of control to 

be reasonable as long as it is such under 

either of these two approaches. 

Under the single pollutant approach, 

we assign all costs to the reduction of 

one pollutant and zero to all other 

pollutants simultaneously reduced. For 

this approach, we would find the cost 

of control reasonable if it is reasonable 

for reducing one pollutant alone. In the 

evaluation below, we assign all the costs 

to methane reduction alone and then to 

VOC reduction alone. For installing a 

new control device in the production 

segment we estimate the cost of control 

for reducing methane emissions using a 

combustion device to be $60,602 per ton 

for piston pumps and $6,656 per ton for 

diaphragm pumps. The cost of control 

for reducing VOC emissions for the 

production segment is $218,017 per ton 

for piston pumps and $23,944 for 

diaphragm pumps. For both the 

transmission and storage segment we 

estimate the cost of control for reducing 

methane emissions using a new 

combustion device to be $60,602 per ton 

for piston pumps and $6,656 per ton for 

diaphragm pumps. The cost of control 

for reducing VOC emissions for both the 

transmission and storage segment is 

$2,187,805 per ton for piston pumps 

and $240,279 for diaphragm pumps. We 

do not consider these cost to be 

reasonable. 

Under the multipollutant approach 

we attributed half the cost to the 

methane reduction and half to the VOC 

reduction. For the production segment, 

we estimate the cost of reducing 

methane emissions using a new 

combustion device for piston pumps to 

be $30,301 per ton and the cost of 

reducing VOC emissions to be $109,009 

per ton. For diaphragm pumps, the cost 

of reducing methane emissions is $3,328 

per ton and the cost of reducing VOC 

emissions is $11,972 per ton. For both 

the transmission and storage segment, 

we estimate the cost of reducing 

methane emissions for piston pumps to 

be $30,301 per ton and the cost of 

reducing VOC emissions to be 

$1,093,903 per ton. For diaphragm 

pumps, the cost of reducing methane 

emissions is $3,328 per ton and the cost 

of reducing VOC emissions is $120,140 

per ton. We also do not consider these 

cost to be reasonable. 

While the use of a new combustion 

device is not cost-effective, the costs 

appear reasonable when using an 

existing combustion control device that 

is already on site. For routing the 

emissions in the production segment to 

an existing combustion control device, 

under the single pollutant approach, if 

we assign all costs to reducing methane 

emissions and zero to VOC reduction, 

the cost is $789 per ton of methane 

reduced for piston pumps and $87 per 

ton of methane reduced for diaphragm 

pumps.73 If we assign all costs to VOC 

reduction and zero to methane 

reduction, the cost of reducing VOC 

emissions using an existing combustion 

control device in the production 

segment is $2,840 for piston pumps and 

$312 for diaphragm pumps. For both the 

transmission and storage segment, if we 

assign all costs to methane reduction 

and zero to VOC reduction, the cost of 

reducing methane emissions is $789 per 

ton for piston pumps and $87 per ton 

for diaphragm pumps.74 If we assign all 

costs to VOC reduction and zero to 

methane reduction, the cost of reducing 

VOC emissions in the transmission and 

storage segment is $28,501 for piston 

pumps and $3,130 for diaphragm 

pumps. As shown above, under the 

single pollutant approach (i.e., all costs 

are assigned to one pollutant and zero 

to the other), the costs are reasonable 

regardless of which pollutant bears all 

the costs, except for the piston pump at 

the transmission and storage segment if 

all costs are assigned to VOC. In that 

case, while the cost is high if it is all 

assigned to VOC reduction, the cost is 

reasonable when assigned to methane 

reduction. 

We also evaluated the cost of control 

for routing emissions to an existing 

control device under the multipollutant 

approach. For the production segment, 

we estimate the cost of reducing 

methane emissions for piston pumps to 

be $395 per ton and the cost of reducing 

VOC emissions to be $1,420 per ton. For 

diaphragm pumps, the cost of reducing 

methane emissions is $43 per ton and 

the cost of reducing VOC emissions is 

$156 per ton. For both the transmission 

and storage segment, we estimate the 

cost of reducing methane emissions for 

piston pumps to be $395 per ton and the 

cost of reducing VOC emissions to be 

$14,250 per ton. For diaphragm pumps, 

the cost of reducing methane emissions 

is $43 per ton and the cost of reducing 

VOC emissions is $1,565 per ton. With 

respect to piston pumps at transmission 

and storage segments, we note that the 

control is cost-effective under the single 

pollutant approach. 

We further evaluated the cost of 

control for routing the emissions to a 

process by installing a new VRU or 

utilizing an existing VRU and found 

these costs to be similar to the costs 

presented above for new and existing 

combustion devices, respectively. We 

determined that the cost of control for 

routing to a process is similar to the 

costs presented above for an existing 

combustion device (see the TSD for this 

action for details of this analysis). 

The option of routing emissions to a 

control device would result in 

secondary impacts from combustion. 

However, we did not identify any 

nonair quality or energy impacts 

associated with this option. 

For natural gas processing plants, we 

evaluated instrument air systems based 

on a 100 percent emissions reduction 

potential resulting in a natural gas 

emission rate of zero standard cubic feet 

per hour. We estimated the potential 

reduction in emissions to be 0.38 tpy of 

methane and 0.11 tpy of VOCs per 

piston pump and 3.46 tpy of methane 

and 0.96 tpy of VOC per diaphragm 

pump. 

Because instrument air systems are 

known to be used at natural gas 

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75 June 13, 2014, API comments on EPA’s white 

paper on oil and natural gas sector pneumatic 

devices. 

processing plants, we evaluated this 

option based on the incremental 

additional cost of routing the natural 

gas-driven pumps to an existing 

instrument air system, assuming all 

natural gas processing plants currently 

use instrument air systems. We 

determined that the incremental cost 

would be the cost of aligning the 

capacity of the existing instrument air 

system to that needed after the addition 

of the pumps. We determined that the 

facility would likely either replace an 

existing compressor or add a 

compressor to address any needed 

additional capacity. Because we do not 

have data on the number and 

distribution of types of natural gasdriven pumps at a typical natural gas 

processing plant, we developed several 

model plant scenarios. We varied the 

size of the plant (i.e., the total number 

of natural gas-driven pumps) from 

small, consisting of 4 natural gas-driven 

pumps per plant to large, consisting of 

100 natural gas-driven pumps per plant. 

We also, within the size of the plant, 

varied the distribution of the type of 

pumps using three distribution 

scenarios (i.e., 50 percent diaphragm 

and 50 percent piston, 25 percent 

diaphragm and 75 percent piston, and 

75 percent diaphragm and 25 percent 

piston). For each model plant, we 

evaluated the cost of an appropriately 

sized compressor based on the required 

additional capacity needed by number 

and types of pumps. Details of this 

analysis are included in the TSD for this 

action. 

Under the single pollutant approach, 

which assigns all costs to the reduction 

of one pollutant and zero to all other 

pollutants, the cost of control for the 

model plants ranges from $374 to $2,185 

per ton of methane reduced when 

assigning all costs to alone to methane 

reduction, and ranges from $1,344 to 

$7,861 per ton of VOC reduced when 

assigning all the costs alone to VOC 

reduction. 

Under the multipollutant approach, 

we assigned half the cost of control to 

the methane reduction and half the cost 

to the VOC reduction. The cost of 

control under the second approach for 

the model plants ranges from $187 to 

$1,093 per ton of methane reduced and 

$672 and $3,930 per ton of VOC 

reduced. We find the control to be costeffective under either approach. 

We also identified in section VIII.A 

two additional approaches, based on 

new capital expenditures and annual 

revenues, for evaluating whether the 

costs are reasonable. For the capital 

expenditure analysis, we used the 

capital expenditures for 2012 for NAICS 

2111, 213111 and 213112 as reported in 

the U.S. Census data, which we believe 

are representative of the production 

segment. The total capital cost for 

complying with the proposed standards 

for pneumatic pumps is 0.02 percent of 

the total capital expenditures, which is 

well below the percentage capital 

increase that courts have previously 

upheld as reasonable as discussed in 

Section VIII. A.. For the total revenue 

analysis, we used the revenues for 2012 

for NAICS 211111, 211112 and 213112, 

which we believe are representative of 

the production segment. The total 

annualized costs for complying with the 

proposed standards is 0.001 percent of 

the total revenues, which is also very 

low. 

For all types of affected facilities in 

the production segment, the total capital 

costs for complying with the proposed 

standards is 0.16 percent of the capital 

expenditures, and the total annualized 

costs for complying with the proposed 

standards is 0.13 percent of the total 

revenues, which is also very low. 

In light of the above, we find that the 

BSER for reducing methane and VOC 

emissions from natural gas-driven 

piston and diaphragm pumps in the 

production and transmission and 

storage segments to be the same, which 

is to route the emissions to an existing 

control device or route the emissions to 

a process. As discussed above, this 

option results in a 95 percent reduction 

of emissions for both methane and VOC. 

We find that the BSER for reducing 

methane and VOC emissions from 

natural gas-driven piston and 

diaphragm pumps at gas processing 

plants is to use an instrument air system 

in place of natural gas to drive the 

pumps. This option results in a 100 

percent reduction of emissions for both 

methane and VOC. 

We are, therefore, proposing to 

require 95 percent methane and VOC 

control from all natural gas-driven 

pneumatic pumps in the production and 

transmission and storage segments. For 

gas processing plants, we are proposing 

to require 100 percent methane and 

VOC control from all pneumatic pumps. 

As discussed above in this section, 

solar-powered, electrically-powered and 

air-driven pumps cannot be employed 

in all applications. However, we 

encourage operators to use other than 

natural gas-driven pneumatic pumps 

where their use is technically feasible. 

To incentivize the use of such 

alternatives, we propose that 

‘‘pneumatic pump affected facility’’ be 

defined in § 60.5365(h) to include only 

natural gas-driven pumps. As a result, 

pumps which are driven by means other 

than natural gas would not be affected 

facilities subject to the pneumatic pump 

provisions of the proposed NSPS. 

Public and peer review comments on 

the white paper noted that, in addition 

to piston injection pumps and 

diaphragm pumps, gas assist glycol 

dehydrator pumps are used to pump 

lean glycol through glycol dehydrator 

systems. The glycol dehydrator pumps 

tend to be more complex because they 

‘‘scavenge’’ energy from the high 

pressure (rich) glycol flowing from the 

contactor to the regenerator to provide 

the bulk of the energy needed to pump 

the lean glycol into the contactor. These 

types of pumps are used continuously 

when the glycol dehydrator is in use. 

Emissions from gas assist pumps are a 

function of the lean glycol circulation 

rate, the pressure of the contactor, and 

the model of the pump. Commenters of 

the white paper indicate that the 

emissions profile of all three types of 

pumps are very different. Commenters 

note that data for the EPA/GRI report for 

gas assisted glycol pumps is calculated 

based on two assumptions of process 

conditions, water removal, and 

information from the pump 

manufacturer which result in significant 

limitations for the calculated emission 

factor derived in the report. 

Furthermore, commenters discuss the 

NEI have activity factors and emissions 

separated from the glycol process 

emissions for gas assist lean glycol 

pumps, however commenters believe 

that it is not clear whether the estimate 

is valid.75 Our understanding is that 

emissions from glycol dehydrator 

pumps are not separately quantified 

because these emissions are released 

from the same stack as the rest of the 

emissions from the dehydrator system, 

which are regulated under the NESHAP 

at 40 CFR part 63 HH and HHH. It is 

also our understanding from 

commenters that replacing the natural 

gas in gas-assisted lean glycol pumps 

with instrument air is not feasible and 

would create significant safety concerns. 

Commenters state that the only option 

for these types of pumps are to replace 

them with electric motor driven pumps 

however, solar and battery systems large 

enough to power these types of pumps 

are not feasible. The EPA is requesting 

comment and additional information on 

the level of uncontrolled emissions from 

these pumps, how these pumps are 

vented through the dehydrator system, 

and the amount and characteristics of 

VOC and methane emissions from 

uncontrolled glycol dehydrators. 

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56628 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

76Available at http://www.epa.gov/airquality/

oilandgas/2014papers/20140415completions.pdf. 

77Colorado Oil and Gas Conservation 

Commission (COGCC) 805 Series Rules (805.b.(3)A) 

at: http://cogcc.state.co.us/ and the Colorado Code 

of Regulations at: http://www.sos.state.co.us/CCR/

Welcome.do. 

78WY BACT permitting guidance available at 

http://deq.state.wy.us/aqd/Oil%20and%20Gas/

September%202013%20FINAL_

Oil%20and%20Gas%20Revision_UGRB.pdf. 

F. Proposed Standards for Well 

Completions 

For the 2012 NSPS and this action, we 

have identified two subcategories of 

hydraulically fractured wells: (1) Nonexploratory and non-delineation wells, 

also known as development wells; and 

(2) exploratory (also known as wildcat 

wells) and delineation wells. An 

exploratory well is the first well drilled 

to determine the presence of a 

producing reservoir and the well’s 

commercial viability. A delineation well 

is a well drilled to determine the 

boundary of a field or producing 

reservoir. In the 2012 NSPS analysis, we 

determined that the emissions profile 

for subcategory 2 wells is the same as 

subcategory 1 wells as described above. 

In our review of white paper comments 

and other information for this action, we 

found no information that would 

indicate this conclusion is not still 

valid. 

1. Proposed Standards for Hydraulically 

Fractured Non-Wildcat and NonDelineation Wells (Subcategory 1 Wells) 

In the 2012 NSPS, we established 

VOC standards for subcategory 1 

hydraulically fractured gas well 

completions and recompletions in the 

oil and natural gas source category. In 

this action, we are proposing VOC 

standards for subcategory 1 oil well 

completions and recompletions and 

methane standards for all subcategory 1 

well completions and recompletions in 

the oil and natural gas source category. 

Based on the analysis below, the 

proposed VOC and methane standards 

are the same as the gas well completion 

standards currently in the NSPS. 

As explained in the 2012 NSPS, well 

completions with hydraulic fracturing 

are a significant source of VOC and 

methane emissions, which occur when 

natural gas and non-methane 

hydrocarbons are vented to the 

atmosphere during flowback of a 

hydraulically fractured well. Flowback 

emissions are short-term in nature and 

occur over a period of several days 

following fracturing or refracturing of a 

well. Well completions include multiple 

steps after the well bore hole has 

reached the target depth. These steps 

include inserting and cementing-in well 

casing, perforating the casing at one or 

more producing horizons, and often 

hydraulically fracturing one or more 

zones in the reservoir to stimulate 

production. Hydraulic fracturing is one 

technique for improving oil or gas 

production where the reservoir rock is 

fractured with very high pressure fluid, 

typically water emulsion with a 

proppant (generally sand) that ‘‘props 

open’’ the fractures after fluid pressure 

is reduced. Emissions are a result of the 

flowback of the fracture fluids and 

reservoir gas at high volume and 

velocity necessary to lift excess 

proppant and fluids to the surface. This 

multi-phase mixture is often directed to 

a surface impoundment or to vented 

tanks (‘‘frac tanks’’), where methane and 

VOC vapors escape to the atmosphere 

during the collection of water, sand and 

hydrocarbon liquids. For oil wells, as 

the fracture fluids are depleted, the 

flowback eventually contains more 

volume of crude oil from the formation. 

Wells that are fractured generally 

have greater amounts of VOC and 

methane emissions than conventional 

wells because of the extended length of 

the flowback period required to purge 

the well of the fluids and sand that are 

associated with the fracturing operation. 

Along with the fluids and sand from the 

fracturing operation, the flowback 

period may also result in emissions of 

methane and VOC that would not occur 

in large quantities at wells that are not 

fractured. 

There are a variety of factors that will 

determine the length of the flowback 

period and actual volume of emissions 

from a well completion such as the 

number of zones, depth, pressure of the 

reservoir, gas composition, etc. This 

variability means there will be 

variability in the emissions from well 

completions. 

For the 2012 NSPS, we estimated that 

the emissions from an uncontrolled gas 

well completion were 155.5 ton of 

methane and 22.7 tons of VOC per 

completion event. We also evaluated oil 

well completions emissions for the 2012 

NSPS; however, based on that 

evaluation, we found oil well 

completion emissions to be very low 

and, therefore, no standard was set for 

oil well completions. 

For this action, we reviewed new 

emissions studies and information for 

oil well completions, as described in the 

2014 white paper titled ‘‘Oil and 

Natural Gas Sector Hydraulically 

Fractured Oil Well Completions and 

Associated Gas during Ongoing 

Production.’’ 76 While there was a wide 

variation in the results of these studies 

and analyses, even in the lowest 

estimates the potential methane and 

VOC emissions from hydraulically 

fractured oil well completions were 

significant. This conclusion is 

consistent with the Federal 

Implementation Plan (FIP) for the Fort 

Berthold Indian Reservation (FBIR) (78 

FR 17836), in which the EPA found that 

the emissions from oil well completions 

are significant. One difference identified 

in our review of comments from the 

2014 white paper process was that the 

average duration of an oil well 

completion is on the lower end of the 

duration identified in our 2012 analysis, 

or 3 days. Therefore, for this action, 

based on our review of these estimates 

and the methodologies used and in 

consideration of these comments, we 

estimate the potential emissions from 

hydraulically fractured oil well 

completions to be 9.72 tons methane 

and 8.14 tons VOC per 3-day 

completion event. These estimates are 

explained in detail in the 2012 TSD and 

the TSD for this action which are both 

available in the docket. 

For the 2012 NSPS, we evaluated 

three options for reducing methane and 

VOC emissions from hydraulically 

fractured well completions: RECs, 

combustion (e.g., flaring), and the 

combination of REC with combustion. 

For this action, we reviewed public and 

peer comments on the white paper as 

well as state (i.e., Colorado 77 and 

Wyoming 78) and other federal 

regulations (i.e., FBIR FIP). We found 

that the available control techniques for 

reducing methane and VOC emissions 

from well completion are the same, and 

they were the same as the control 

options we previously identified for 

controlling VOC emissions: use of a 

REC, combustion, and the combination 

of REC with combustion. We did not 

find any other available control options 

from our white paper process or 

information review. 

RECs are performed by separating the 

flowback water, sand, hydrocarbon 

condensate and natural gas to reduce 

the portion of natural gas and VOC 

vented to the atmosphere, while 

maximizing recovery of salable natural 

gas and condensate and routing the 

salable gas to a sales line and routing 

the recovered condensate to a 

completion or storage vessel for 

collection. Equipment required to 

conduct RECs may include tankage (e.g., 

‘‘frac tanks’’), special gas-liquid-sand 

separator traps and gas dehydration. 

Control by combustion is achieved 

through the use of a completion 

combustion device. Based on our 

review, we believe that traditional 

combustion control devices, (i.e., flares 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56629 

79Emissions of VOC from hydraulically fractured 

subcategory 1 gas wells are subject to the current 

NSPS and are not included in this action. 

80As was determined for the 2012 NSPS. 

81 In 2012 we already found that the cost of this 

control to be reasonable for reducing VOC 

emissions from subcategory 1 gas well completions 

and recompletions. We are not reopening that 

decision in this action. Therefore, this cost finding 

is relevant only to methane reduction from 

subcategory 1 hydraulically fractured gas well 

completions. 

or enclosed combustion control 

devices), are infeasible for use on 

completion emissions because the 

flowback following hydraulic fracturing 

consists of liquids, gases and sand in a 

high-volume, multiphase slug flow. 

We evaluated RECs, completion 

combustion devices and the 

combination of RECs with completion 

combustion devices in order to 

determine the BSER for subcategory 1 

wells. See the 2012 TSD and the TSD for 

this action, available in the docket, for 

further details on this evaluation. Our 

evaluation indicates that REC alone 

provides for a 90 percent control of 

emissions where gas emitted from the 

well is of suitable quality to be routed 

to a gathering line. However, in some 

cases, the initial gas produced from the 

well does not meet quality 

specifications for entering gathering 

lines, and as a result, the gas must be 

either vented or combusted. Due to the 

potential for gas to be emitted, even 

during the use of a REC, we determined 

that the use of a REC alone, would not 

be the BSER for control of emissions 

from well completions. Our evaluation 

of REC combined with a completion 

combustion device indicated that this 

option resulted in a 95 percent control 

of both methane and VOC emissions. 

We believe this option maximizes gas 

recovery and minimizes venting to the 

atmosphere. 

Under the last option, combustion, we 

determined that a completion 

combustion device would achieve a 95 

percent reduction in both methane and 

VOC emissions. However, we 

determined that combustion alone 

would not represent the BSER for well 

completions because, although the 

emissions reduction would be equal to 

the REC and completion combustion 

device combination (i.e., 95 percent 

control), the opportunity to realize gas 

recovery would be minimized and the 

generation of secondary combustionrelated emissions would be increased. 

Based on the 95 percent emission 

reduction of a REC combined with a 

combustion device, in the 2012 NSPS, 

the emission reductions for a 

hydraulically fractured gas well 

completion event were estimated to be 

147.4 tons of methane per completion.79

In this analysis, we estimate the 

emission reductions for a hydraulically 

fractured oil well completion event to 

be 9.23 tons of methane and 7.73 tons 

of VOC per completion based on a 3-day 

completion event. 

Equipment costs associated with RECs 

will vary from well to well. Costs of 

performing REC are projected to be 

between $700 and $6,500 per day, 

varying based on if key pieces of 

equipment are readily available on site 

or temporarily brought on site. Based on 

the 2012 NSPS evaluation, the average 

cost of a REC combined with 

completion combustion device for a 7- 

day completion event was $33,327. 

Under our evaluation in this action, we 

estimate the cost for a REC combined 

with a completion combustion device 

for a 3-day completion event to be 

$17,183. However, in both cases, there 

are savings associated with the use of 

RECs because the gas recovered can be 

incorporated into the production stream 

and sold. With the consideration of gas 

savings, the cost of a REC combined 

with a completion combustion device 

for a 7-day completions event for a gas 

well was estimated to have a net 

savings. With the consideration of gas 

savings, the cost of a REC combined 

with a completion combustion device 

for a 3-day completions event for an oil 

well was estimated to be $13,586. 

We determined that the completion 

combustion device option for well 

completions also reduces both methane 

and VOC emissions by 95 percent. 

Therefore, the emissions reductions 

would be the same as those cited above 

for the REC combined with a 

completion combustion device. The 

annual cost for a completion 

combustion device alone was estimated 

be $3,523 for the 2012 NSPS for gas 

wells and $3,723 under this action for 

oil wells. 

For purposes of this action, we have 

identified in section VIII.A two 

approaches (single pollutant approach 

and multipollutant approach) for 

evaluating whether the cost of a 

multipollutant control is reasonable. As 

explained in that section, we believe 

that both approaches are appropriate for 

assessing the reasonableness of the 

multipollutant controls considered in 

this action. Therefore, we find the cost 

of control to be reasonable as long as it 

is such under either of these two 

approaches. 

Under the single pollutant approach, 

we assign all costs to the reduction of 

one pollutant and zero to all other 

pollutants simultaneously reduced. For 

this approach, we would find the cost 

of control reasonable if it is reasonable 

for reducing one pollutant alone. As 

shown in the evaluation below, which 

assigns all the costs to methane 

reduction alone, and based on an 

average cost of $33,327 per completion 

event for a gas well,80 a REC combined 

with a completion combustion device, 

would cost $226 per ton of methane 

reduced per gas well completion 

without cost savings.81 As noted above, 

this option maximizes gas recovery and 

minimizes venting to the atmosphere. 

Thus, when the value of the natural gas 

recovered (approximately 1,609 Mcf of 

natural gas) is considered, there is a net 

savings realized for this option for a 

subcategory 1 gas well completion or 

recompletion. We find these costs to be 

reasonable for the amount of methane 

reduction it can achieve. Also, because 

all the costs have been attributed to 

methane reduction, the cost of the 

simultaneous VOC reduction is zero and 

therefore reasonable. Based on the 

$17,183 annual cost of a REC combined 

with a completion combustion device 

for a 3-day completion event for an oil 

well completion, with the cost 

attributed only to methane and zero cost 

attributed to VOC, the cost of control 

would be $1,861 per ton of methane 

reduced per oil well completion without 

considering cost savings attributable to 

recovery of natural gas. As noted above, 

this option maximizes gas recovery and 

minimizes venting to the atmosphere. 

Thus, when the value of the natural gas 

recovered (approximately 999 Mcf of 

natural gas) is considered, the cost of 

control would be $1,471 per ton of 

methane reduced. Under this approach, 

the cost of control with all cost 

attributed to VOC would be $2,222 per 

ton of VOC reduced without considering 

natural gas savings and $1,757 with 

savings realized from natural gas 

recovery. Although the cost of control 

for a 3-day completion event at an oil 

well is higher than the cost at a gas well, 

we believe that the emissions reductions 

collectively are significant to justify the 

cost. Furthermore, we believe that the 

industry can bear the cost and survive. 

Under the multipollutant approach, 

we assign 50 percent of the cost to 

methane and 50 percent to VOC. The 

cost of a REC with completion 

combustion for a gas well under this 

approach would be $930 per ton of 

methane and $1,111 per ton of VOC 

reduced without considering natural gas 

savings. With consideration of natural 

gas savings, the cost of control is $736 

per ton of methane and $879 per ton of 

VOC reduced. Based on this 

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56630 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

82Because the current NSPS requires control of 

gas well completions using this option, we do not 

include the secondary emissions for control of 

methane from gas well completions. 

formulation, the costs for pollutant 

reduction are half of the estimated costs 

under the single pollutant approach 

above and therefore we believe these 

costs are not excessive for the same 

reasons discussed above. 

Under the single pollutant approach, 

based on the $3,723 annual cost of a 

completion combustion device alone, 

with the cost attributed only to methane 

and zero attributed to VOC, the cost of 

control would be $403 per ton of 

methane reduced per oil well 

completion. Under this approach, the 

cost of control with cost attributed to 

VOC would be $481 per ton of VOC 

reduced. Under the multipollutant 

approach, we assign 50 percent of the 

cost to methane and 50 percent to VOC. 

The cost of control under this approach 

would be $202 per ton of methane and 

$241 per ton of VOC reduced. We think 

that these costs are reasonable. 

See the TSD, available in the docket 

for this action, for a detailed description 

of the cost of control analysis. 

We believe that the cost for both 

options, a REC combined with 

combustion and combustion alone, are 

reasonable, given the emission 

reduction that would be achieved. 

However, given that the reductions in 

emissions are equal between the two 

control options, the REC combined with 

combustion option provides a better 

environmental benefit with the recovery 

of natural gas and reduced secondary 

combustion-related emissions. Aside 

from the potential hazards (in some 

cases) associated with combustion 

devices, we did not identify any nonair 

environmental impacts, health or energy 

impacts associated with REC combined 

with combustion, therefore these 

impacts were not analyzed. 

The use of a completion combustion 

device with this option would produce 

secondary impacts in the form of 

combustion-related emissions. We 

estimate that, for subcategory 1 oil wells 

completed using a combination of REC 

and combustion for the year 2020, the 

combustion control-related emissions 

would be approximately 26 tons of total 

hydrocarbons, 69 tons of carbon 

monoxide, 24,846 tons of carbon 

dioxide, and 13 tons of nitrogen 

oxides.82 This is based on the 

assumption that 5 percent of the 

flowback gas is combusted for 

subcategory 1 oil wells (controlled with 

a REC combined with a completion 

combustion device). 

We estimate that this option of control 

for subcategory 1 oil well completions, 

for the projected year 2020, will result 

in estimated emission reductions of 

127,478 tons of methane and 106,750 

tons of VOC. Thus, we believe that the 

benefit of the methane and VOC 

reductions far outweigh the secondary 

impacts of combustion emissions 

formation during use of the completion 

combustion operation. Further, should 

only combustion be considered for all 

oil well completions, including the 

subcategory 1 wells, the secondary 

impacts would be far greater than those 

shown above. Secondary impacts of 

combustion alone are presented in the 

discussion of subcategory 2 wells below 

in this section. 

We also identified in section VIII.A 

two additional approaches, based on 

new capital expenditures and annual 

revenues, for evaluating whether the 

costs are reasonable. For the capital 

expenditure analysis, we used the 

capital expenditures for 2012 for NAICS 

2111, 213111 and 213112 as reported in 

the U.S. Census data, which we believe 

are representative of the production 

segment. The total capital costs for 

complying with the proposed standards 

for subcategory 1 wells is 0.081 percent 

of the total capital expenditures, which 

is well below the percentage capital 

increase that courts have previously 

upheld as reasonable as discussed in 

Section VIII.A.. For the total revenue 

analysis, we used the revenues for 2012 

for NAICS 211111, 211112 and 213112, 

which we believe are representative of 

the production segment. The total 

annualized costs for complying with the 

proposed standards is 0.033 percent of 

the total revenues, which is also very 

low. 

For all types of affected facilities in 

the production segment, the total capital 

costs for complying with the proposed 

standards is 0.16 percent of the total 

capital expenditures, and the total 

annualized costs for complying with the 

proposed standards is 0.13 percent of 

the total revenues, which is also very 

low. 

For the reasons stated above, we 

determine the BSER for subcategory 1 

(developmental wells) is the 

combination of REC and the use of a 

completion combustion device. We 

considered setting a numerical 

performance standard; however, we 

determined that it is not feasible to 

prescribe or enforce a numerical 

performance standard in this case 

because the gas can be discharged at 

multiple locations along with water and 

sand in a multiphase slug flow during 

the flowback process and, therefore, 

may not always be emitted at the same 

specific location in the process or 

through one conveyance designed and 

constructed to emit or capture such 

pollutant. Therefore, pursuant to section 

111(h)(2) of the CAA, we are proposing 

an operational standard for subcategory 

1 wells that would require a 

combination of gas capture and recovery 

and completion combustion devices to 

minimize venting of gas and condensate 

vapors to the atmosphere, with 

provisions for venting in lieu of 

combustion for situations in which 

combustion would present safety 

hazards or for periods when the 

flowback gas is noncombustible. 

For the purposes of these standards 

we have separated the flowback period 

into two stages, the ‘‘initial flowback 

stage’’ and the ‘‘separation flowback 

stage.’’ The initial flowback stage begins 

with the first flowback from the well 

following hydraulic fracturing or 

refracturing and is characterized by high 

volumetric flow water, containing sand, 

fracturing fluids and debris from the 

formation with very little gas being 

brought to the surface, usually in 

multiphase slug flow. Due to the high 

volume of the flowback and the small 

amounts of gas in the initial flowback, 

operation of a separator may be initially 

technically infeasible, and there may 

not be sufficient gas for combustion. 

During these conditions, the emissions 

cannot be controlled from the flowback. 

During this stage, liquids are collected 

and routed to completion vessels. 

For the reasons explained above, 

during the initial flowback stage, we 

propose that the flowback be routed to 

a storage vessel or to a well completion 

vessel that can be a frac tank, a lined pit 

or any other vessel. The purpose of this 

requirement is to avoid having operators 

route the flowback to an unlined pit or 

onto the ground. During the initial 

flowback stage, there is no requirement 

for controlling emissions from the 

vessel, and any gas in the flowback 

during this stage may be vented. 

However, the operator must route the 

flowback to a separator unless it is 

technically infeasible for a separator to 

function. Conditions that could prevent 

proper operation of the separator 

include insufficient gas concentration, 

low pressure gas, and multiphase slug 

flow containing solids that could clog 

the separator. We stress that operators 

have the responsibility to direct the 

flowback to a separator as soon as 

conditions allow a separator to function 

and in accordance with the General 

Provision requirements to operate the 

affected facility in a manner consistent 

with good air pollution control practices 

for minimizing emissions. 

The second stage is defined as the 

‘‘separation flowback stage.’’ The point 

at which the separator can function 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56631 

83Emissions of VOC from hydraulically fractured 

subcategory 2 gas wells are subject to the current 

NSPS and are not included in this action. 

84Emissions of VOC from hydraulically fractured 

subcategory 2 gas wells are subject to the current 

NSPS and are not included in this action. 

marks the beginning of the separation 

flowback stage. This stage is 

characterized by the separator operating 

with a gaseous phase and one or more 

liquid phases in the separator. The end 

of the separation flowback stage marks 

the end of the flowback period and is 

defined as the point at which the well 

is shut in and the flowback equipment 

is permanently disconnected from the 

well, or the startup of production. The 

end of the separation flowback stage 

(i.e., the end of flowback) is 

characterized by certain indicators. 

Permanent disconnection of the 

temporary equipment used during 

flowback can be an indicator of 

flowback having ended. For example, 

during flowback, skid-mounted choke 

manifolds are used to limit flowback 

and assist in directing the flow. 

Temporary lines laid on the ground 

from the wellhead to the choke 

manifold and to the flowback separators 

and frac tanks are connected with 

‘‘hammer unions’’ which are pipe 

unions that are designed for ease of 

making temporary connections and are 

characterized by ‘‘ears’’ that allow the 

joint to be made up quickly by striking 

with a hammer. After flowback has 

subsided and the well has cleaned up 

sufficiently, the well is temporarily shut 

in to disconnect the temporary flowback 

equipment. We believe that when the 

operator permanently disconnects choke 

manifolds, temporary separators, sand 

traps and other equipment connected 

with temporary lines and hammer 

unions, it is a reliable indicator that 

flowback has ended and the well is 

ready for production. At that point, we 

believe that operators will remove these 

temporary equipment used during 

flowback to avoid incurring unnecessary 

charges for additional days the 

equipment remains onsite. The well 

could start production immediately or it 

could remain shut in until permanent 

equipment is installed. 

During the separation flowback stage, 

the operator must route all salable 

quality natural gas from the separator to 

a gas flow line or collection system, reinject the gas into the well or another 

well, use the gas as an on-site fuel 

source or use the gas for another useful 

purpose that a purchased fuel or raw 

material would serve. If, during the 

separation flowback stage, it is 

technically infeasible to route the 

recovered gas to a flow line or collection 

system, re-inject the gas or use the gas 

as fuel or for other useful purpose, the 

recovered gas must be combusted. No 

direct venting of recovered gas is 

allowed during the separation flowback 

stage except when combustion creates a 

fire or safety hazard or can damage 

tundra, permafrost or waterways. With 

regard to infeasibility of collecting the 

salable quality gas, we believe that 

owners and operators plan their 

operations to extract a target product 

and evaluate whether the appropriate 

infrastructure access is available to 

ensure their product has a viable path 

to market before completing a well. 

However, there may be cases in which, 

for reason(s) not within an operator’s 

control, the well is completed and 

flowback occurs without a suitable flow 

line available. We are aware that this 

situation may be more common for 

wells that are primarily drilled to 

produce oil. In those instances, 

§ 60.5375(a)(3) requires the combustion 

of the gas unless combustion poses an 

unsafe condition as described above. 

During the separation flowback stage, all 

liquids from the separator must be 

directed to a storage vessel or to a well 

completion vessel, routed to a collection 

system or be re-injected into the well or 

another well. 

The proposed operational standard 

would be accompanied by requirements 

for documentation of the overall 

duration of the completion event, 

duration of recovery using REC, 

duration of combustion, duration of 

venting, and specific reasons for venting 

in lieu of combustion. 

2. Proposed Standards for Hydraulically 

Fractured Exploratory and Delineation 

Wells (Subcategory 2 Wells) 

In the 2012 NSPS, we established 

VOC standards for subcategory 2 

hydraulically fractured exploratory and 

delineation gas well completions. In this 

action, we are proposing VOC standards 

for the hydraulically fractured 

exploratory and delineation oil well 

completions and we are also proposing 

methane standards for all hydraulically 

fractured exploratory and delineation 

well completions in the oil and natural 

gas source category. Based on the 

analysis below, the proposed VOC and 

methane standards described above are 

the same as the current standards for 

hydraulically fractured exploratory and 

delineation gas well completion 

standards currently in the NSPS. 

As noted above, for the 2012 NSPS 

analysis, we determined that the 

emissions profile for subcategory 2 

wells is the same as subcategory 1 wells 

as described above. In our review of 

white paper comment and other 

information for this action, we found no 

information that would indicated this 

conclusion is not still valid. 

Specifically, we determined the 

emissions from a hydraulically fractured 

oil well were 9.72 tons of methane and 

8.14 tons of VOC per 3-day completion 

event.83

In our analysis for the 2012 NSPS, we 

determined that a REC is not an option 

for subcategory 2 wells because there is 

no infrastructure in place to get the 

recovered gas to market or further 

processing. Typically, these types of 

wells generally are not in proximity to 

existing gathering lines at the time the 

well is completed. Therefore, for these 

wells, the only potential control option 

identified (both under the 2012 NSPS 

and under this action) is combustion of 

gases using a completion combustion 

device, as described above. Also as 

explained above, because of the highvolume, multiphase slug flow nature of 

the flowback gas, water and sand, 

control by a traditional flare or other 

control devices, such as vapor recovery 

units, is infeasible, since these devices 

would be overcome by the erratic highvolume flow of liquids, which leaves 

combustion as the only available control 

system for subcategory 2 wells. As also 

discussed above, combustion can 

present a fire hazard or other 

undesirable impacts in some situations. 

In our review of white paper comment 

and other information for this action, we 

found no information that would 

indicate this conclusion is not still 

valid. 

Based on the 95 percent emission 

reduction of a completion combustion 

device, the emission reductions for a 

subcategory 2 hydraulically fractured 

gas well completion or recompletion are 

estimated to be 147.4 tons of methane 

per completion event.84 The emission 

reductions for a subcategory 2 

hydraulically fractured oil well 

completion or recompletion event are 

estimated to be around 9.23 tons of 

methane and 7.73 tons of VOC per 3-day 

completion. 

As noted above, for purposes of this 

action, we have identified in section 

VIII.A two approaches (single pollutant 

and multipollutant approaches) for 

evaluating whether the cost of a 

multipollutant control is reasonable. As 

explained in that section, we believe 

that both approaches are appropriate for 

assessing the reasonableness of the 

multipollutant controls considered in 

this action. Therefore, we find the cost 

of control to be reasonable as long as it 

is such under either of these two 

approaches. 

Under the single pollutant approach, 

we assign all costs to the reduction of 

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56632 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

85 In 2012 we already found that the cost of this 

control to be reasonable for reducing VOC 

emissions from hydraulically fractured subcategory 

2 gas well completions. We are not reopening that 

decision in this action. Therefore, this cost finding 

is relevant only to methane from hydraulically 

fractured subcategory 2 gas well completions. 

86Because subcategory 2 hydraulically fractured 

gas well completions are subject to the current 

NSPS, we do not consider secondary impacts for 

the destruction of methane under this action. 

one pollutant and zero to all other 

pollutants simultaneously reduced. For 

this approach, we would find the cost 

of control reasonable if it is reasonable 

for reducing one pollutant alone. As 

shown in the evaluation below, which 

assigns all the costs to methane 

reduction alone, based on an average 

annual cost of $3,723 per completion, 

the cost of control for a completion 

combustion device is estimated to be 

$24 per ton of methane for subcategory 

2 gas well completion event. We find 

these costs to be reasonable for the 

amount of methane reduction it can 

achieve. Also, because all the costs have 

been attributed to methane reduction, 

the cost of the simultaneous VOC 

reduction is zero and therefore 

reasonable.85 We estimate the cost of 

control for subcategory 2 oil wells to be 

$403 per ton of methane and $481 per 

ton of VOC per oil well completion. We 

consider these costs to be reasonable 

considering the level of emissions 

reductions. 

We also evaluated the cost of this 

control under the multipollutant 

approach. Under this approach, the 

costs would be allocated based on the 

estimated percentage reduction 

expected for each pollutant. Because 

completion combustion devices reduces 

both methane and VOC by 95 percent, 

we attributed 50 percent of the costs to 

methane reduction and 50 percent of the 

cost to VOC reduction. The costs for 

methane reduction would be half of the 

estimated costs under the first approach 

above, for both gas and oil wells, which 

we have found to be reasonable. See the 

TSD, available in the docket for this 

action, for a detailed description of the 

cost of control analysis. 

Aside from the potential hazards 

associated with use of a completion 

combustion device in some cases, we 

did not identify any nonair 

environmental impacts, health or energy 

impacts associated with completion 

combustion devices, therefore no 

analysis was completed. However, 

completion combustion devices would 

produce combustion-related air 

pollutants. For 870 subcategory 2 oil 

well completion86 for the projected year 

2020, we estimated that 66 tons of total 

hydrocarbons, 175 tons of carbon 

monoxide, 62,628 tons of carbon 

dioxide, 32 tons of nitrogen oxides and 

1 ton of particulate matter would be 

produced as secondary emissions. This 

is based on the assumption that 95 

percent of flowback gas is combusted by 

the combustion device. This control 

option is estimated to reduce emissions 

for the projected year 2020 by 135,516 

tons of methane and 113,481 tons of 

VOC. Thus, we believe that the benefit 

of the methane and VOC reduction far 

outweighs the secondary impact of 

combustion-related pollutants as a 

result of completion combustion 

control. 

We also identified in section VIII.A 

two additional approaches, based on 

new capital expenditures and annual 

revenues, for evaluating whether the 

costs are reasonable. For the capital 

expenditure analysis, we used the 

capital expenditures for 2012 for NAICS 

2111, 213111 and 213112 as reported in 

the U.S. Census data, which we believe 

are representative of the production 

segment. The total capital cost for 

complying with the proposed standards 

for subcategory 2 wells is 0.002 percent 

of the capital expenditures, which is 

well below the percentage capital 

increase that courts have previously 

upheld as reasonable as discussed in 

Section VIII.A.. For the total revenue 

analysis, we used the revenues for 2012 

for NAICS 211111, 211112 and 213112, 

which we believe are representative of 

the production segment. The total 

annualized cost for complying with the 

proposed standards is 0.001 percent of 

the total revenues, which is also very 

low. 

For all types of affected facilities in 

the production segment, the total capital 

costs for complying with the proposed 

standards is 0.16 percent of the total 

capital expenditures, and the total 

annualized costs for complying with the 

proposed standards is 0.13 percent of 

the total revenues, which is also very 

low. 

In light of the above, we propose to 

determine that the BSER for subcategory 

2 wells would be use of a completion 

combustion device. As we explained 

above, the gas is discharged at multiple 

locations during flowback and is mixed 

with water and sand in multiphase slug 

flow and therefore we determined that 

it is not feasible to set a numerical 

performance standard. 

Pursuant to CAA section 111(h)(2), we 

are proposing an operational standard 

for subcategory 2 well completions that 

would require minimization of venting 

of gas and hydrocarbon vapors during 

the completion operation through the 

use of a completion combustion device, 

with provisions for venting in lieu of 

combustion for situations in which 

combustion would present safety 

hazards or for periods when the 

flowback gas is noncombustible. The 

owners and operators of these wells also 

have a general duty to safely maximize 

resource recovery and minimize releases 

to the atmosphere during flowback and 

subsequent recovery. 

As with subcategory 1 wells, for the 

purposes of these standards we have 

separated the flowback period into two 

stages, the ‘‘initial flowback stage’’ and 

the ‘‘separation flowback stage.’’ During 

the initial flowback stage, the 

requirements for the subcategory 2 wells 

would be the same as the subcategory 1 

wells. The flowback must be routed to 

a storage vessel or to a well completion 

vessel that can be a frac tank, a lined pit 

or any other vessel. During the initial 

flowback stage, there is no requirement 

for controlling emissions from the 

vessel, and any gas in the flowback 

during this stage may be vented. 

During the separation flowback stage, 

the operator must route all salable 

quality gas from the separator to a gas 

flow line or collection system, combust 

the gas, re-inject the gas into the well or 

another well, use the gas as an on-site 

fuel source or use the gas for another 

useful purpose that a purchased fuel or 

raw material would serve. No direct 

venting of recovered gas is allowed 

during the separation flowback stage 

except when combustion creates a fire 

or safety hazard or can damage tundra, 

permafrost or waterways. During the 

separation flowback stage, all liquids 

from the separator must be directed to 

a storage vessel or to a well completion 

vessel, routed to a collection system or 

re-injected into the well or another well. 

Consistent with requirements for 

subcategory 1 wells, owners or operators 

of subcategory 2 wells would be 

required to document completions and 

provide justification for periods when 

gas was vented in lieu of combustion. 

We estimate that these control options 

for these sources would reduce the total 

emissions from all hydraulically 

fractured and refractured oil well 

completions for the projected year 2020 

by 135,516 tons of methane and 113,481 

tons of VOC. Thus, we believe that the 

benefit of the methane and VOC 

reductions far outweigh the secondary 

impact of combustion emissions 

formation during use of the completion 

combustion operation. 

Several public and peer reviewer 

comments on the white paper noted that 

these technologies are currently in 

regular use by industry to control oil 

well completion and recompletion 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56633 

87The EPA received six peer review comments 

and several submissions of technical information 

and data on this paper, available for review at 

http://www.epa.gov/airquality/oilandgas/

whitepapers.html. 

88Following publication of the 2012 NSPS, EPA 

received a joint petition for administrative 

reconsideration of the rule. The petitioners 

questioned the technical merits of the low pressure 

well definition and asserted that the public had not 

had an opportunity to comment on the definition. 

EPA re-proposed the definition of ’’low pressure gas 

well,’’ on March 23, 2015 (80 FR 15180), and took 

comment on IPAA’s alternative definition. EPA has 

finalized this definition in a separate action. 

89Many of these data are available in the 

DrillingInfo database. More information is available 

at: http://info.drillinginfo.com. 

90For the purposes of this discussion, we define 

‘low production well’ as a well with an average 

daily production of 15 barrel equivalents or less. 

This reflects the definition of a stripper well 

property in IRC 613A(c)(6)(E). 

91On February 24, 2015, API submitted a 

comment to EPA stating that oil wells with GOR 

values less than 300 do not have sufficient gas to 

operate a separator. http://www.regulations.gov/

#!documentDetail;D=EPA-HQ-OAR-2014-0831- 

0137. 

92http://www.eia.gov/todayinenergy/

detail.cfm?id=13571#. 

93http://petrowiki.org/Oil_fluid_characteristics. 

emissions.87 In addition, these control 

technologies are the same as those 

required in the 2012 NSPS to control 

completion emissions from 

hydraulically fractured gas well 

completions. 

The EPA is aware that oil wells 

cannot perform a REC if there is not 

sufficient well pressure or gas content 

during the well completion to operate 

the surface equipment required for a 

REC. In the 2012 NSPS the EPA did not 

require low pressure gas wells to 

perform REC, but operators were 

required to control those well 

completions using combustion.88 We 

solicit comment on the types of oil wells 

that will not be capable of performing a 

REC or combusting completion 

emissions due to technical 

considerations such as low pressure or 

low gas content, or other physical 

characteristics such as location, well 

depth, length of hydraulic fracturing, or 

drilling direction (e.g., horizontal, 

vertical, directional).89 Additionally, we 

solicit comment on all aspects of our 

proposal to regulate methane and VOC 

emissions from hydraulically fractured 

oil well completions. 

As shown in the analyses presented 

above, the BSER for hydraulically 

fractured oil wells is the same as that for 

gas wells. Accordingly, we are 

proposing to apply the current 

requirements for hydraulically fractured 

gas well completions to hydraulically 

fractured oil well completions. It is 

logical that the BSER analyses would 

result in the same BSER determinations 

for hydraulically fractured gas and oil 

wells, because the available options for 

controlling emissions and their current 

use in the field are the same. Several 

public and peer reviewer comments on 

the white paper noted that the control 

technologies used for controlling 

emissions from hydraulically fractured 

oil well completions are the same as 

those used for completions of 

hydraulically fractured gas wells. The 

commenters further noted that in many 

cases it is difficult to distinguish gas 

wells from oil wells, because many 

wells produce both gas and oil. 

Consistent standards for completions of 

hydraulically fractured gas wells and 

completions of hydraulically fractured 

oil wells will remove the need for 

operators to distinguish a gas well 

completion from an oil well completion 

for the purposes of complying with 

subpart OOOO. This change will 

improve the implementation of the 

standards by providing greater certainty 

as to which well completions must 

comply with the standards. 

We are requesting comment on 

excluding low production wells (i.e., 

those with an average daily production 

of 15 barrel equivalents or less) 90 from 

the standards for well completions. It is 

our understanding that low production 

wells have inherently low emissions 

from well completions and many are 

owned and operated by small 

businesses. We are concerned about the 

burden of the well completion 

requirement on small businesses, in 

particular where there is little emission 

reduction to be achieved. We recognize 

that identification of these wells prior to 

completion events is difficult. We 

believe that drilling of a low production 

well may be unintentional and may be 

infrequent, but production may 

nevertheless proceed due to economic 

reasons. We solicit comment and 

information on emissions associated 

with low production wells, 

characteristics of these wells and 

supporting information that would help 

owners/operators and enforcement 

personnel identify these wells prior to 

completion. In addition, we understand 

that a daily average of 15 barrel 

equivalents is representative of low 

production wells for some purposes, we 

solicit comment on the appropriateness 

of this threshold for applying the 

standards for well completions. 

Further, we are proposing that wells 

with a gas-to-oil ratio (GOR) of less than 

300 scf of gas per barrel of oil produced 

would not be affected facilities subject 

to the well completion provisions of the 

NSPS.91 We solicit comment on 

whether a GOR of 300 is the appropriate 

applicability threshold, and if the GOR 

of nearby wells would be a reliable 

indicator in determining the GOR of a 

new or modified well. The reason for 

the proposed threshold GOR of 300 is 

that separators typically do not operate 

at a GOR less than 300, which is based 

on industry experience rather than a 

vetted technical specification for 

separator performance. Though, in 

theory, any amount of free gas could be 

separated from the liquid, the reality is 

that this is not practical given the design 

and operating parameters of separation 

units operating in the field. 

We believe that having no threshold 

may create a significant burden for 

operators to control emissions for these 

wells with just a trace of gas. EIA data 

show that the number of ‘‘oil only’’ 

wells drilled from 2007–2012 was less 

than 20 percent.92 The potential 

emission characteristic of oils with a 

GOR of 300 is relevant when deciding 

whether this is a reasonable threshold. 

Primarily, the concern is volatility. The 

threshold must be low enough that the 

oil produced is considered non-volatile. 

Non-volatile ‘‘black oils’’ (oil likely to 

not have gases or light hydrocarbons 

associated with it) are generally defined 

as having GOR values in the range of 

200 to 900.93 Therefore, oil wells with 

GORs less than 300 are at the lower end 

of this range, and will not likely have 

enough gas associated that it can be 

separated. Therefore, the EPA is 

proposing that the NSPS requirements 

for well completions do not apply to 

completions wells with hydraulic 

fracturing that have a GOR of less than 

300 scf/barrel. 

We are soliciting comment on 

whether the well completion provisions 

of the proposed rule can be 

implemented on the effective date of the 

rule in the event of potential shortage of 

REC equipment and, if not, how a phase 

in could be structured. We believe that 

there will be a sufficient supply of REC 

equipment available by the time the 

NSPS becomes effective. However, we 

request comment on whether sufficient 

supply of this equipment and personnel 

to operate it will be available to 

accommodate the increased number of 

RECs by the effective date of the NSPS. 

We also request specific estimates of 

how much time would be required to 

get enough equipment in operation to 

accommodate the full number of RECs 

performed annually. In the event that 

public comments indicate that available 

equipment would likely be insufficient 

to accommodate the increase in number 

of REC performed, we are considering 

phasing in requirements for well 

completions in the final rule. Such a 

phased in approach could be structured 

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56634 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

94Administrative Rules of Montana (ARM) Title 

17 Chapter 8 Air Quality Subchapter 16—Emission 

Control Requirements for Oil and Gas Well 

Facilities Operating Prior to Issuance of a Montana 

Air Quality Permit. Emission Control Requirements, 

17.8.1603 Available at: http://www.deq.mt.gov/dir/ 

legal/Chapters/Ch08-toc.mcpx. 

95Available at http://www.epa.gov/airquality/

oilandgas/2014papers/20140415leaks.pdf. 

to provide for control of the highest 

emitting wells first, with other wells 

being included at a later date. We solicit 

comment on whether GOR of the well 

and production level of the well should 

be bases for the phasing of requirements 

for RECs. We also solicit suggestions for 

other ways to address a potential shortterm REC equipment shortage that may 

hinder operators’ compliance with the 

proposed NSPS. Additionally, we solicit 

comment on what an appropriate 

threshold should be for low production 

wells. 

Finally, we solicit comment on 

criteria that could help clarify 

availability of gathering lines. 

Availability of a gathering line is one 

consideration affecting feasibility of 

recovery of natural gas during 

completion of hydraulically fractured 

wells. There are several factors that can 

affect availability of a gathering line 

including, but not limited to, the 

capacity of an existing gathering line to 

accept additional throughput, the ability 

of owners and operators to obtain rights 

of way to cross properties, and the 

distance from the well to an existing 

gathering line. We are aware that some 

states require collection of gas if a 

gathering line is present within a 

specific distance from the well. For 

example, Montana allows gas from wells 

to be flared only in cases where the well 

is farther than one-half mile from a gas 

pipeline.94 We solicit comment on 

whether distance from a gathering line 

is a valid criterion on which to base 

requirements for gas recovery and, if so, 

what would an appropriate distance for 

such a threshold. In addition, we solicit 

comment on any other factors that could 

be specified in the NSPS for requiring 

recovery of gas from well completions. 

3. Use of a Separator During Flowback 

For subcategory 1, subcategory 2 and 

low pressure gas wells, the current 

NSPS at § 60.5375(a) and (f) requires 

routing of flowback to a separator unless 

it is technically infeasible for a separator 

to function. The NSPS also provides in 

§ 60.5375(f) that subcategory 2 and low 

pressure wells are required to control 

emissions through combustion using a 

completion combustion device (which 

can include a pit flare) rather than being 

required to perform a REC. It was our 

understanding that a separator could be 

used at some point during the flowback 

period of every well completion. Recent 

information indicates that some wells, 

because of certain characteristics of the 

reservoir, do not need to employ a 

separator. In those cases, we understand 

that operators direct the flowback to a 

pit and can combust gas contained in 

the flowback as it emerges from the 

pipe. At some point, after the well has 

flowed sufficiently to clean up the 

wellbore and the gas is of salable 

quality, production begins or the well is 

temporarily shut in. As a result of this 

new information, our initial 

understanding may not apply. 

We solicit comment on (1) the role of 

the separator in well completions and 

whether a separator can be employed for 

every well completion; and (2) the 

appropriate relationship of the separator 

in the context of our requirements that 

cover a very broad spectrum of wells. 

We solicit further information that 

would help inform our consideration of 

this issue as we seek to ensure we have 

adequately established appropriate 

requirements for all well completions 

subject to the NSPS. 

G. Proposed Standards for Fugitive 

Emissions From Well Sites and 

Compressor Stations 

In April 2014, the EPA published the 

white paper titled ‘‘Oil and Natural Gas 

Sector Leaks’’ 95 which summarized the 

EPA’s current understanding of fugitive 

emissions of methane and VOC at 

onshore oil and natural gas production, 

processing, and transmission and 

storage facilities. The white paper also 

outlined our understanding of the 

mitigation techniques (practices and 

technology) available to reduce these 

emissions along with the cost and 

effectiveness of these practices and 

technologies. 

The detection of fugitive emissions 

from oil and natural gas well sites and 

compressor stations, which are 

comprised of compressors at natural gas 

transmission, storage, gathering and 

boosting stations, can be determined 

using several technologies. Historically, 

fugitive emissions were detected using 

sensory monitoring (e.g., visual, 

olfactory or sound) or EPA Method 21 

to determine if a leak exceeded a set 

threshold (e.g., the leak concentration 

was greater than the leak definition for 

the component). As described in the 

white paper, we found that many 

fugitive emission surveys are now 

conducted using OGI in the oil and 

natural gas source category, a 

technology that provides a visible image 

of gas emissions or leaks to the 

atmosphere. The OGI instrument works 

by using spectral wavelength filtering 

and an array of infrared detectors to 

visualize the infrared absorption of 

hydrocarbons and other gaseous 

compounds. As the gas absorbs radiant 

energy at the same waveband that the 

filter transmits to the detector, the gas 

and motion of the gas is imaged. The 

OGI instrument can be used for 

monitoring a large array of components 

at a facility and is an effective means of 

detecting fugitive emissions when the 

technology is used appropriately. 

Several studies in the white paper 

estimated that OGI can monitor 1,875– 

2,100 components per hour. In 

comparison, the average screening rate 

using a Method 21 instrument (e.g., 

organic vapor analyzer, flame ionization 

detector, flow measurement devices) is 

roughly 700 components per day. 

However, the EPA’s recent work with 

OGI instruments suggests these studies 

underestimate the amount of time 

necessary to thoroughly monitor 

components for fugitive emissions using 

OGI instruments. Even though the 

amount of time may be underestimated, 

we believe the use of OGI can reduce 

the amount of time necessary to conduct 

fugitive emissions monitoring since 

multiple fugitive emissions components 

can be surveyed simultaneously, thus 

reducing the cost of identifying fugitive 

emissions in upstream oil and natural 

gas facilities when compared to using a 

handheld TVA or OVA, which requires 

a manual screening of each fugitive 

emissions component. 

1. Fugitive Emissions From Well Sites 

Fugitive emissions may occur for 

many reasons at well sites such as when 

connection points are not fitted 

properly, thief hatches are not properly 

weighted or sealed or when seals and 

gaskets start to deteriorate. Changes in 

pressure or mechanical stresses can also 

cause fugitive emissions. Potential 

sources of fugitive emissions, fugitive 

emissions components, include agitator 

seals, connectors, pump diaphragms, 

flanges, instruments, meters, openended lines, pressure relief devices, 

pump seals, valves or open thief hatches 

or holes in storage vessels, pressure 

vessels, separators, heaters and meters. 

For purposes of this proposed rule, 

fugitive emissions do not include 

venting emissions from devices that 

vent as part of normal operations, such 

as gas-driven pneumatic controllers or 

gas-driven pneumatic pumps. 

Based on our review of the public and 

peer review comments on the white 

paper and the Colorado and Wyoming 

state rules, we believe that there are two 

options for reducing methane and VOC 

fugitive emissions at well sites: (1) A 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56635 

96 Draft Technical Support Document 

Appendices, Optical Gas Imaging Protocol (40 CFR 

part 60, Appendix K), August 11, 2015. 

97 Gas Research Institute/U.S. Environmental 

Protection Agency, Research and Development, 

Methane Emission Factors from the Natural Gas 

Industry, Volume 8, Equipment Leaks, June 1996 

(EPA–600/R–96–080h). 

98API Workbook 4638, 1996. 

99U.S. Environmental Protection Agency, 

Protocol for Equipment Leak Emission Estimates, 

Table 2–4, November 1995 (EPA–453/R–95–017). 

100Memorandum 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. 

fugitive emissions monitoring program 

based on individual component 

monitoring using EPA Method 21 for 

detection combined with repairs, or (2) 

a fugitive emissions monitoring program 

based on the use of OGI detection 

combined with repairs. Several public 

and peer reviewer comments on the 

white paper noted that these 

technologies are currently used by 

industry to reduce fugitive emissions 

from the production segment in the oil 

and natural gas industry. 

Each of these control options are 

evaluated below based on varying the 

frequency of conducting the survey and 

fugitive emissions repair threshold (e.g., 

the specified concentration when using 

Method 21 or visible identification of 

methane or VOC when an OGI 

instrument is used). For our analysis, 

we considered quarterly, semiannual 

and annual survey frequency. For 

Method 21 monitoring and repair, we 

considered 10,000 ppm, 2,500 ppm and 

500 ppm fugitive repair thresholds. The 

leak definition concentrations for other 

NSPS referencing Method 21 range from 

500–10,000 ppm. Therefore, we selected 

500 ppm, 2,500 ppm and 10,000 ppm. 

For OGI, we considered visible 

emissions as the fugitive repair 

threshold (i.e., emissions that can be 

seen using OGI instrumentation). EPA’s 

recent work with OGI indicates that 

fugitive emissions at a concentration of 

10,000 ppm are generally detectable 

using OGI instrumentation provided 

that the right operating conditions (e.g., 

wind speed and background 

temperature) are present. Work is 

ongoing to determine the lowest 

concentration that can be reliably 

detected using OGI.96

In order to estimate fugitive methane 

and VOC emissions from well sites, we 

used fugitive emissions component 

counts from the GRI/EPA report 97 for 

natural gas production well sites, and 

fugitive emissions component counts 

from the GHG inventory and API for oil 

production well sites. The types of 

production equipment located at natural 

gas production well pads include: Gas 

wellheads, separators, meters/piping, 

heaters, and dehydrators. The types of 

oil well production equipment include: 

Oil well heads, separators, headers and 

heater/treaters. The types of fugitive 

emissions components that are 

associated with both oil and natural gas 

wells include but are not limited to: 

Valves, connectors, open-ended lines 

and valves (OEL), and pressure relief 

device (PRD). Fugitive emissions 

component counts for each piece of 

equipment in the gas production 

segment were calculated using the 

average fugitive emissions component 

counts in the Eastern U.S. and the 

Western U.S. from the EPA/GRI report. 

These data were used to develop a 

natural gas well site model plant. 

Fugitive emissions components counts 

for these equipment types in the oil 

production segment were obtained from 

an American Petroleum Institute (API) 

workbook.98 These data were used to 

develop an oil production well site 

model plant. 

Since we have emission factors for 

only a subset of the components which 

are possible sources for fugitive 

emissions, our emission estimates are 

believed to be lower than the emissions 

profile for the entire set of fugitive 

emissions components that would 

typically be found at a well site. 

The fugitive emission factors from 

AP–42,99 which provided a single 

source of total organic compounds 

(TOC) emission factors that include 

non-VOCs, such as methane and ethane, 

were used to estimate emissions and 

evaluate the cost of control of a fugitive 

emissions program for oil and natural 

gas production well sites. Using the AP– 

42 factors, the methane and VOC 

fugitive emissions from a natural gas 

well site are estimated to be 4.5 tpy and 

1.3 tpy, respectively. For an oil 

production well site, the estimated 

fugitive methane and VOC emissions are 

1.1 tpy and 0.3 tpy, respectively. The 

calculation of these emission estimates 

are explained in detail in the 

background TSD for this proposal 

available in the docket. 

Information in the white paper related 

to the potential emission reductions 

from the implementation of an OGI 

monitoring program varied from 40 to 

99 percent. The causes for this range in 

reduction efficiency were the frequency 

of monitoring surveys performed and 

different assumptions made by the 

study authors. According to the 

calculations, which are based on 

uncontrolled emission factors for well 

pads contained within the EPA Oil and 

Natural Gas Sector Technical Support 

Document (2011), the Colorado Air 

Quality Control Commission, Initial 

Economic Impact Analysis for Proposed 

Revisions to Regulation Number 7 (5 

CCR 1001–9) and the FINAL ECONOMIC 

IMPACT ANALYSIS For Industry’s 

Proposed Revisions to Colorado Air 

Quality Control Commission Regulation 

Number 3, 6, and 7 (5 CCR 1001–9) 

(January 30, 2014), a quarterly 

monitoring program in combination 

with a repair program can reasonably be 

expected to reduce fugitive methane and 

VOC emissions at well sites by 80 

percent. Although information in the 

white paper indicated emission 

reductions as high as 99 percent may be 

achievable with OGI, we do not believe 

such levels can be consistently achieved 

for all of types of components that may 

be subject to a fugitive emissions 

monitoring program. Therefore, using 

engineering judgement and experience 

obtained through our existing programs 

for finding and repairing leaking 

components, we selected 80 percent as 

an emission reduction level that can 

reasonably be expected to be achieved 

with a quarterly monitoring program. 

Due to the increased amount of time 

between each monitoring survey and 

subsequent repair, we believe that the 

level of emissions reduction achieved 

by less frequent monitoring surveys will 

be reduced from this level. Therefore, 

we assigned an emission reduction of 60 

percent to semiannual monitoring 

survey and repair frequency and 40 

percent to annual frequency, consistent 

with the reduction levels used by the 

Colorado Air Quality Control 

Commission in their initial and final 

economic impacts analyses. We solicit 

comment on the appropriateness of the 

percentage of emission reduction level 

that can be reasonably expected to be 

achieved with quarterly, semiannual, 

and annual monitoring program 

frequencies. 

For Method 21, we estimated 

emissions reductions using The EPA 

Equipment Leaks Protocol document, 

which provides emissions factor data 

based on leak definition and monitoring 

frequencies primarily for the Synthetic 

Organic Chemical Manufacturing 

Industry (SOCMI) and Petroleum 

Refining Industry along with the 

emissions rates contained within the 

Technology Review for Equipment 

Leaks document.100 We used these data 

along with the monitoring frequency 

(e.g., annual, semiannual, and quarterly) 

at fugitive repair thresholds at 500, 

2,500 and 10,000 ppm to determine 

uncontrolled emissions. Using this 

information we calculated an expected 

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101See pages 68–69 of the TSD. 102See the 2015 TSD for full comparison. 

emissions reduction percentage for each 

of the combinations of monitoring 

frequency and repair threshold. 

We also looked at the costs of a 

monitoring and repair program under 

various monitoring frequencies and 

repair thresholds (for Method 21), 

including the cost of OGI monitoring 

survey, repair, monitoring plan 

development, and the cost-effectiveness 

of the various options.101 For purposes 

of this action, we have identified in 

section VIII.A two approaches (single 

and multipollutant approaches) for 

evaluating the cost-effectiveness of a 

multipollutant control, such as the 

fugitive emissions monitoring and 

repair programs identified above for 

reducing both methane and VOC 

emissions. As explained in that section, 

we believe that both the single and 

multipollutant approaches are 

appropriate for assessing the 

reasonableness of the multipollutant 

controls considered in this action. 

Therefore, we find the cost of control to 

be warranted as long as it is such under 

either of these two approaches. 

Under the first approach (single 

pollutant approach), we assign all costs 

to the reduction of one pollutant and 

zero to all other pollutants 

simultaneously reduced. Under the 

second approach (multipollutant 

approach), we allocate the annualized 

cost across the pollutant reductions 

addressed by the control option in 

proportion to the relative percentage 

reduction of each pollutant controlled. 

In the multipollutant approach, since 

methane and VOC emissions are 

controlled proportionally equal, half the 

cost is apportioned to the methane 

emission reductions and half the cost is 

apportioned to the VOC emission 

reductions. In this evaluation, we 

evaluated both approaches across the 

range of identified monitoring survey 

options: OGI monitoring and repair 

performed quarterly, semiannually and 

annually; and Method 21 performed 

quarterly, semiannually and annually, 

with a fugitive emissions repair 

threshold of 500, 2,500 and 10,000 ppm 

at each frequency. The calculation of the 

costs, emission reductions, and cost of 

control for each option are explained in 

detail in the TSD. As shown in the TSD, 

while the costs for repairing 

components that are found to have 

fugitive emissions during a fugitive 

monitoring survey remain the same, the 

annual repair costs will differ based on 

monitoring frequency. 

As shown in our TSD, both OGI and 

Method 21 monitoring survey 

methodologies costs generally increase 

with increasing monitoring frequency 

(i.e., quarterly monitoring has a higher 

cost of control than annual monitoring). 

For EPA Method 21 specifically, the 

cost also increases with decreasing 

fugitive emissions repair threshold (i.e., 

500 ppm results in a higher cost of 

control than 10,000 ppm). However, as 

shown in the TSD, the cost of control 

based on the OGI methodology for 

annual, semiannual, and quarterly 

monitoring frequencies for a model well 

site are estimated to be more costeffective than Method 21 for those same 

monitoring frequencies.102 We therefore 

focus our BSER analysis based on the 

use of OGI. 

For the reasons stated below, we find 

that the control cost based on quarterly 

monitoring using OGI may not be costeffective based on the information 

available. As shown in the TSD, under 

the single pollutant approach, if all 

costs are assigned to methane and zero 

to VOC reduction, the cost is $3,753 per 

ton of methane reduced, and $3,521 per 

ton if savings of the natural gas 

recovered is taken into account. If all 

costs are assigned to VOC and zero to 

methane reduction, the cost is $13,502 

per ton of VOC reduced, and $12,668 

per ton if savings of the natural gas 

recovered is taken into account. Under 

the multipollutant approach, the cost of 

control for VOC based on quarterly 

monitoring is $6,751 per ton, and $6,334 

per ton of VOC reduced if savings are 

considered. In a previous NSPS 

rulemaking [72 FR 64864 (November 16, 

2007)], we had concluded that a VOC 

control option was not cost-effective at 

a cost of $5,700 per ton. In light of the 

above, we find that the cost of 

monitoring/repair based on quarterly 

monitoring at well sites using OGI is not 

cost-effective for reducing VOC and 

methane emissions under either 

approach. Having found the control cost 

using OGI based on quarterly 

monitoring not to be cost-effective, we 

now evaluate the control cost based on 

annual and semi-annual monitoring 

using OGI. As shown in the TSD, the 

costs between annual and semi-annual 

monitoring are comparable. Because 

semi-annual monitoring achieves greater 

emissions reduction, we focus our 

analysis on the cost based on semiannual monitoring. 

While the cost appears high under the 

single pollutant approach, we find the 

costs to be reasonable under the 

multipollutant approach for the 

following reasons. As shown in the 

TSD, for VOC reduction, the cost is 

$4,979 per ton; when savings of the 

natural gas recovered are taken into 

account, the cost is reduced to $4,562 

per ton. For methane reduction, the 

control cost is $1,384 per ton; when cost 

savings of the natural gas recovered is 

taken into account, the cost is reduced 

to $1,268 per ton. As explained above, 

we believe that we have underestimated 

the emissions from these well sites; 

therefore, we believe the use of OGI is 

more cost-effective than the amount 

presented here. Furthermore, while 

being used to survey fugitive 

components at a well site, the OGI may 

potentially help an owner and operator 

detect and repair other sources of visible 

emissions not covered by the NSPS. One 

example would be an intermittently 

acting pneumatic controller that is stuck 

open. The OGI could help the owner 

and operator detect and address and 

reduce such inadvertent emissions, 

resulting in more cost saving from more 

natural gas recovered. 

We also identified in section VIII.A 

two additional approaches, based on 

new capital expenditures and annual 

revenues, for evaluating whether the 

costs are reasonable. For monitoring and 

repair of fugitive emissions at well sites, 

we believe that the total revenue 

analysis is more appropriate than the 

capital expenditure analysis and 

therefore we did not perform the capital 

expenditure analysis. For the total 

revenue analysis, we used the revenues 

for 2012 for NAICS 211111, 211112 and 

213112, which we believe are 

representative of the production 

segment. The total annualized costs for 

complying with the proposed standards 

is 0.085 percent of the total revenues, 

which is very low. 

For all types of affected facilities in 

the production, the total annualized 

costs for complying with the proposed 

standards is 0.13 percent of the total 

revenues, which is also very low. 

For the reasons stated above, we find 

the cost of monitoring and repairing 

fugitive emissions at well sites based on 

semi-annual monitoring using OGI to be 

reasonable. To ensure that no fugitive 

emissions remain, a resurvey of the 

repaired components is necessary. We 

expect that most of the repair and 

resurveys are conducted at the same 

time as the initial monitoring survey 

while OGI personnel are still on-site. 

However, there may be some 

components that cannot not be repaired 

right away and in some instances not 

until after the initial OGI personnel are 

no longer on site. In that event, resurvey 

with OGI would require rehiring OGI 

personnel, which would make the 

resurvey not cost effective. On the other 

hand, as shown in TSD, the cost of 

conducting resurvey using Method 21 is 

$2 per component, which is reasonable. 

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103 In our TSD we estimate the number of fugitive 

emissions components to be around 700 and of 

those components we estimate that about 1 percent 

would need to be repaired. 

104This timelines is consistent with the timeline 

originally established in 1983 under 40 CFR part 60 

subpart VV. 105

We did not find any nonair quality 

health and environmental impacts, or 

energy requirements associated with the 

use of OGI or Method 21 for monitoring, 

repairing and resurvey fugitive 

components at well sites. Based on the 

above analysis, we believe that the 

BSER for reducing fugitive methane and 

VOC emissions at well sites is a 

monitoring and repair standard based 

on semi-annual monitoring using OGI 

and resurvey using Method 21. 

As mentioned above, OGI monitoring 

requires trained OGI personnel and OGI 

instruments. Many owners and 

operators, in particular small 

businesses, may not own OGI 

instruments or have staff who are 

trained and qualified to use such 

instruments; some may not have the 

capital to acquire the OGI instrument or 

provide training to their staff. While our 

cost analysis takes into account that 

owners and operators may need to hire 

contractors to perform the monitoring 

survey using OGI, we do not have 

information on the number of available 

contractors and OGI instruments. In 

light of our estimated 20,000 active 

wells in 2012 and that the number will 

increase annually, we are concerned 

that some owners and operators, in 

particular small businesses, may have 

difficulty securing the requisite OGI 

contractors and/or OGI instrumentation 

to perform monitoring surveys on a 

semi-annual basis. Larger companies, 

due to the economic clout they have by 

offering the contractors more work due 

to the higher number of wells they own, 

may preferentially retain the services of 

a large portion of the available 

contractors. This may result in small 

businesses experiencing a longer wait 

time to obtain contractor services. In 

light of the potential concern above, we 

are co-proposing monitoring survey on 

an annual basis at the same time 

soliciting comment and supporting 

information on the availability of 

trained OGI contractors and OGI 

instrumentation to help us evaluate 

whether owners and operators would 

have difficulty acquiring the necessary 

equipment and personnel to perform a 

semi-annual monitoring and, if so, 

whether annual monitoring would 

alleviate such problems. 

Recognizing that additional data may 

be available, such as emissions from 

super emitters that may have higher 

emission factors than those considered 

in this analysis, we are also taking 

comment on requiring monitoring 

survey on a quarterly basis. 

CAA section 111(h)(1) states that the 

Administrator may promulgate a work 

practice standard or other requirements, 

which reflects the best technological 

system of continuous emission 

reduction when it is not feasible to 

enforce an emission standard. CAA 

section 111(h)(2) defines the phrase 

‘‘not feasible to prescribe or enforce an 

emission standard’’ as follows: 

[A]ny situation in which the Administrator 

determines that (A) a hazardous air pollutant 

or pollutants cannot be emitted through a 

conveyance designed and constructed to emit 

or capture such pollutant, or that any 

requirement for, or use of, such a conveyance 

would be inconsistent with any Federal, 

State, or local law, or (B) the application of 

measurement methodology to a particular 

class of sources is not practicable due to 

technological and economic limitations. 

The work practice standards for 

fugitive emissions from well sites are 

consistent with CAA section 

111(h)(1)(A), because no conveyance to 

capture fugitive emissions exist for 

fugitive emissions components at a well 

site. In addition, OGI does not measure 

the extent the fugitive emissions from 

fugitive emissions components. For the 

reasons stated above, pursuant to CAA 

section 111(h)(1)(b), we are proposing 

work practice standards for fugitive 

emissions from the collection of fugitive 

emission components at well sites. 

The proposed work practice standards 

include details for development of a 

fugitive emissions monitoring plan, 

repair requirements and recordkeeping 

and reporting requirements. The fugitive 

emissions monitoring plan includes 

operating parameters to ensure 

consistent and effective operation for 

OGI such as procedures for determining 

the maximum viewing distance and 

wind speed during monitoring. The 

proposed standards would require a 

source of fugitive emissions to be 

repaired or replaced as soon as 

practicable, but no later than 15 

calendar days after detection of the 

fugitive emissions. We have historically 

allowed 15 days for repair/resurvey in 

LDAR programs, which appears to be 

sufficient time. Further, in light of the 

number of components at a well site and 

the number that would need to be 

repaired, we believe that 15 days is also 

sufficient for conducting the required 

repairs under the proposed fugitive 

emission standards.103 That said, we are 

also soliciting comment on whether 15 

days is an appropriate amount of time 

for repair of sources of fugitive 

emissions at well sites.104

Many recent studies have shown a 

skewed distribution for emissions 

related to leaks, where a majority of 

emissions come from a minority of 

sources.105 Commenters on the white 

papers agreed that emissions from 

equipment leaks exhibit a skewed 

distribution, and pointed to other 

examples of data sets in which the 

majority of fugitive methane and VOC 

emissions come from a minority of 

components (e.g., gross emitters). Based 

on this information, we solicit comment 

on whether the fugitive emissions 

monitoring program should be limited 

to ‘‘gross emitters.’’ 

We believe that a properly maintained 

facility would likely detect very little to 

no fugitive emissions at each monitoring 

survey, while a poorly maintained 

facility would continue to detect 

fugitive emissions. As shown in our 

TSD, we estimate the number of fugitive 

emission components at a well site to be 

around 700. We believe that a facility 

with proper operation would likely find 

one to three percent of components to 

have fugitive emissions. To encourage 

proper maintenance, we are proposing 

that the owner or operator may go to 

annual monitoring if the initial two 

consecutive semiannual monitoring 

surveys show that less than one percent 

of the collection of fugitive emissions 

components at the well site has fugitive 

emissions. For the same reason, we are 

proposing that the owner or operator 

conduct quarterly monitoring if the 

initial two semi-annual monitoring 

surveys show that more than three 

percent of the collection of fugitive 

emissions components at the well site 

has fugitive emissions. We believe the 

first year to be the tune-up year to allow 

owners and operators the opportunity to 

refine the requirements of their 

monitoring/repair plan. After that initial 

year, the required monitoring frequency 

would be annual if a monitoring survey 

shows less than one percent of 

components to have fugitive emissions; 

semi-annual if one to three percent of 

total components have fugitive 

emissions; and quarterly if over three 

percent of total components have 

fugitive emissions. We solicit comment 

on this approach, including the 

percentage used to adjust the 

monitoring frequency. We also solicit 

comment on the appropriateness of 

performance based monitoring 

frequencies. We also solicit comment on 

the appropriateness of triggering 

different monitoring frequencies based 

on the percentage of components with 

fugitive emissions. Under the proposed 

standards, the affected facility would be 

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56638 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

defined as the collection of fugitive 

emissions components at a well site. To 

clarify which components are subject to 

the fugitive emissions monitoring 

provisions, we propose to add a 

definition to § 60.5430 for ‘‘fugitive 

emissions component’’ as follows: 

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 site, including 

but not limited to valves, connectors, 

pressure relief devices, open-ended lines, 

access doors, flanges, closed vent systems, 

thief hatches or other openings on a storage 

vessels, agitator seals, distance pieces, 

crankcase vents, blowdown vents, pump 

seals or diaphragms, compressors, separators, 

pressure vessels, dehydrators, heaters, 

instruments, and meters. Devices that vent as 

part of normal operations, such as a natural 

gas-driven pneumatic controllers or natural 

gas-driven pumps, are not fugitive emissions 

components, insofar as the natural gas 

discharged from the device’s vent is not 

considered a fugitive emission. Emissions 

originating from other than the vent, such as 

the seals around the bellows of a diaphragm 

pump would be considered fugitive 

emissions. 

Thus, all fugitive emissions components 

at the affected facility would be 

monitored for fugitive emissions of 

methane and VOC. 

For the reasons stated in section 

VII.G.1, for purposes of the proposed 

standards for fugitive emissions at well 

sites, modification of a well site is 

defined as when a new well is drilled 

or a well at the well site (where 

collection of fugitive emissions 

components are located) is 

hydraulically fractured or refractured. 

As explained in that section, other than 

these events, we are not aware of any 

other physical change to a well site that 

would result in an increase in emissions 

from the collection of fugitive 

components at such well site. To clarify 

and ease implementation, we propose to 

define ‘‘modification’’ to include only 

these two events for purposes of the 

fugitive emissions provisions at well 

sites. 

In the 2012 NSPS, we provided that 

completion requirements do not apply 

to refracturing of an existing well that is 

completed responsibly (i.e. green 

completions). Building on the 2012 

NSPS, the EPA intends to continue to 

encourage corporate-wide voluntary 

efforts to achieve emission reductions 

through responsible, transparent and 

verifiable actions that would obviate the 

need to meet obligations associated with 

NSPS applicability, as well as avoid 

creating disruption for operators 

following advanced responsible 

corporate practices. It has come to our 

attention that some owners and 

operators may already have in place, 

and are implementing, corporate-wide 

fugitive emissions monitoring and 

repair programs at their well sites that 

are equivalent to, or more stringent than 

our proposed standards. Such corporate 

efforts present the potential to further 

the development of LDAR technologies. 

To encourage companies to continue 

such good corporate policies and 

encourage advancement in the 

technology and practices, we solicit 

comment on criteria we can use to 

determine whether and under what 

conditions well sites operating under 

corporate fugitive monitoring programs 

can be deemed to be meeting the 

equivalent of the NSPS standards for 

well site fugitive emissions such that we 

can define those regimes as constituting 

alternative methods of compliance or 

otherwise provide appropriate 

regulatory streamlining. We also solicit 

comment on how to address 

enforceability of such alternative 

approaches (i.e., how to assure that 

these well sites are achieving, and will 

continue to achieve, equal or better 

emission reduction than our proposed 

standards). We recognize that meeting 

an NSPS performance level should not, 

standing alone, be a basis for a source 

not becoming an affected facility. 

For the reasons stated above, we are 

also soliciting comments on criteria we 

can use to determine whether and under 

what conditions all new or modified 

well sites operating under corporate 

fugitive monitoring programs can be 

deemed to be meeting the equivalent of 

the NSPS standards for well sites 

fugitive emissions such that we can 

define those regimes as constituting 

alternative methods of compliance or 

otherwise provide appropriate 

regulatory streamlining. We also solicit 

comment on how to address 

enforceability of such alternative 

approaches (i.e., how to assure that 

these well sites are achieving, and will 

continue to achieve, equal or better 

emission reduction than our proposed 

standards). 

We are requesting comment on 

whether the fugitive emissions 

requirements should apply to all 

fugitive emissions components at 

modified well sites or just to those 

components that are connected to the 

fractured, refractured or added well. For 

some modified well sites, the fractured 

or refractured or added well may only 

be connected to a subset of the fugitive 

emissions components on site. We are 

soliciting comment on whether the 

fugitive emission requirements should 

only apply to that subset. However, we 

are aware that the added complexity of 

distinguishing covered and non-covered 

sources may create difficulty in 

implementing these requirements. 

However, we note that it may be 

advantageous to the operator from an 

operational perspective to monitor all 

the components at a well site since the 

monitoring equipment is already onsite. 

As explained above, Method 21 is not 

as cost-effective as OGI for monitoring. 

That said, there may be reasons why 

and owner and operator may prefer to 

use Method 21 over OGI. While we are 

confident with the ability of Method 21 

to detect fugitive emissions and 

therefore consider it a viable alternative 

to OGI, we solicit comment on the 

appropriate fugitive emissions repair 

threshold for Method 21 monitoring 

surveys. As mentioned above, EPA’s 

recent work with OGI indicates that 

fugitive emissions at a concentration of 

10,000 ppm is generally detectable 

using OGI instrumentation provided 

that the right operating conditions (e.g., 

wind speed and background 

temperature) are present. Work is 

ongoing to determine the lowest 

concentration that can be reliably 

detected using OGI As mentioned 

above, we believe that OGI. In light of 

the above, we solicit comment on 

whether the fugitive emissions repair 

threshold for Method 21 monitoring 

surveys should be set at 10,000 ppm or 

whether a different threshold is more 

appropriate (including information to 

support such threshold). 

While we did not identify OGI as the 

BSER for resurvey because of the 

potential cost associated with rehiring 

OGI personnel, there is no such 

additional cost for those who either own 

the OGI instrument or can perform 

repair/resurvey at the same time. 

Therefore, the proposed rule would 

allow the use either OGI or Method 21 

for resurvey. When Method 21 is used 

to resurvey components, we are 

proposing that the component is 

repaired if the Method 21 instrument 

indicates a concentration less than 500 

ppm above background. This has been 

historically used in other LDAR 

programs as an indicator of no 

detectable emissions. 

The proposed standards would 

require that operators begin monitoring 

fugitive emissions components at a well 

site within 30 days of the initial startup 

of the first well completion for a new 

well or within 30 days of well site 

modification. We are proposing a 30 day 

period to allow owners and operators 

the opportunity to secure qualified 

contractors and equipment necessary for 

the initial monitoring survey. We are 

requesting comment on whether 30 days 

is an appropriate amount of time to 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56639 

106For the purposes of this discussion, we define 

‘low production well’ as a well with an average 

daily production of 15 barrel equivalents or less. 

This reflects the definition of a stripper well 

property in IRC 613A(c)(6)(E). 

107 Draft Technical Support Document 

Appendices, Optical Gas Imaging Protocol (40 CFR 

part 60, Appendix K), August 11, 2015. 108 Gas Research Institute/U.S. Environmental 

Protection Agency, Research and Development, 

Methane Emission Factors from the Natural Gas 

Industry, Volume 8, Equipment Leaks, June 1996 

(EPA–600/R–96–080h). 

109Environmental Protection Agency, Protocol for 

Equipment Leak Emission Estimates, Table 2–4, 

November 1995 (EPA–453/R–95–017). 

begin conducting fugitive emissions 

monitoring. 

We received new information 

indicating that some companies could 

experience logistical challenges with the 

availability of OGI instrumentation and 

qualified OGI technicians and operators 

to perform monitoring surveys and in 

some instances repairs. We solicit 

comment on both the availability of OGI 

instruments and the availability of 

qualified OGI technicians and operators 

to perform surveys and repairs. 

We are proposing to exclude low 

production well sites (i.e., a low 

production site is defined by the average 

combined oil and natural gas 

production for the wells at the site being 

less than 15 barrels of oil equivalent 

(boe) per day averaged over the first 30 

days of production) 106 from the 

standards for fugitives emissions from 

well sites. We believe the lower 

production associated with these wells 

would generally result in lower fugitive 

emissions. It is our understanding that 

fugitive emissions at low production 

well sites are inherently low and that 

such well sites are mostly owned and 

operated by small businesses. We are 

concerned about the burden of the 

fugitive emission requirement on small 

businesses, in particular where there is 

little emission reduction to be achieved. 

To more fully evaluate the exclusion, 

we solicit comment on the air emissions 

associated with low production wells, 

and the relationship between 

production and fugitive emissions. 

Specifically, we solicit comment on the 

relationship between production and 

fugitive emissions over time. While we 

have learned that a daily average of 15 

barrel per day is representative of low 

production wells, we solicit comment 

on the appropriateness of this threshold 

for applying the standards for fugitive 

emission at well sites. Further, we 

solicit comment on whether EPA should 

include low production well sites for 

fugitive emissions and if these types of 

well sites are not excluded, should they 

have a less frequent monitoring 

requirement. 

We are also requesting comment on 

whether there are well sites that have 

inherently low fugitive emissions, even 

when a new well is drilled or a well site 

is fractured or refractured and, if so, 

descriptions of such type(s) of well 

sites. The proposed standards are not 

intended to cover well sites with no 

fugitive emissions of methane or VOC. 

We are aware that some sites may have 

inherently low fugitive emissions due to 

the characteristics of the site, such as 

the gas to oil ratio of the wells or the 

specific types of equipment located on 

the well site. We solicit comment on 

these characteristics and data that 

would demonstrate that these sites have 

low methane and VOC fugitive 

emissions. 

We are requesting comment on 

whether there are other fugitive 

emission detection technologies for 

fugitive emissions monitoring, since this 

is a field of emerging technology and 

major advances are expected in the near 

future. We are aware of several types of 

technologies that may be appropriate for 

fugitive emissions monitoring such as 

Geospatial Measurement of Air 

Pollutants using OTM–33 approaches 

(e.g., Picarro Surveyor), passive sorbent 

tubes using EPA Methods 325A and B, 

active sensors, gas cloud imaging (e.g., 

Rebellion photonics), and Airborne 

Differential Absorption Lidar (DIAL). 

Therefore, we are specifically requesting 

comments on details related to these 

and other technologies such as the 

detection capability; an equivalent 

fugitive emission repair threshold to 

what is required in the proposed rule for 

OGI; the frequency at which the fugitive 

emissions monitoring surveys should be 

performed and how this frequency 

ensures appropriate levels of fugitive 

emissions detection; whether the 

technology can be used as a stand-alone 

technique or whether it must be used in 

conjunction with a less frequent (and 

how frequent) OGI monitoring survey; 

the type of restrictions necessary for 

optimal use; and the information that is 

important for inclusion in a monitoring 

plan for these technologies. 

2. Fugitive Emissions From Compressor 

Stations 

Fugitive emissions at compressor 

stations in the oil and natural gas source 

category may occur for many reasons 

(e.g., when connection points are not 

fitted properly, or when seals and 

gaskets start to deteriorate). Changes in 

pressure and mechanical stresses can 

also cause fugitive emissions. Potential 

sources of fugitive emissions include 

agitator seals, distance pieces, crank 

case vents, blowdown vents, connectors, 

pump seals or diaphragms, flanges, 

instruments, meters, open-ended lines, 

pressure relief devices, valves, open 

thief hatches or holes in storage vessels, 

and similar items on glycol dehydrators 

(e.g., pumps, valves, and pressure relief 

devices). Equipment that vents as part of 

normal operations, such as gas driven 

pneumatic controllers, gas driven 

pneumatic pumps or the normal 

operation of blowdown vents are not 

considered to be sources of fugitive 

emissions. 

Based on our review of the public and 

peer review comments on the white 

paper and the Colorado and Wyoming 

state rules, we believe that there are two 

options for reducing methane and VOC 

fugitive emissions at compressor 

stations: (1) A fugitive emissions 

monitoring program based on individual 

component monitoring using EPA 

Method 21 for detection combined with 

repairs, or (2) a fugitive emissions 

monitoring program based on the use of 

OGI detection combined with repairs. 

Several public and peer reviewer 

comments on the white paper noted that 

these technologies are currently used by 

industry to reduce fugitive emissions 

from the production segment in the oil 

and natural gas industry. 

Each of these control options are 

evaluated below based on varying the 

frequency of conducting the monitoring 

survey and fugitive emissions repair 

threshold (e.g., the specified 

concentration when using Method 21 or 

visible identification of methane or VOC 

when an OGI instrument is used). For 

our analysis, we considered quarterly, 

semiannual and annual monitoring 

frequencies. For Method 21, we 

considered 10,000 ppm, 2,500 ppm and 

500 ppm fugitive repair thresholds. The 

leak definitions for other NSPS 

referencing Method 21 range from 500– 

10,000 ppm. Therefore, we selected 500 

ppm, 2,500 ppm and 10,000 ppm. For 

OGI, we considered visible emissions as 

the fugitive repair threshold (i.e., 

emissions that can be seen using OGI). 

EPA’s recent work with OGI indicate 

that fugitive emissions at a 

concentration of 10,000 ppm are 

generally detectable using OGI 

instrumentation, provided that the right 

operating conditions (e.g., wind speed 

and background temperature) are 

present. Work is ongoing to determine 

the lowest concentration that can be 

reliably detected using OGI.107

In order to estimate fugitive emissions 

from compressor stations, we used 

component counts from the GRI/EPA 

report 108 for each of the compressor 

station segments. Fugitive emission 

factors from AP–42 109 were used to 

estimate emissions from gathering and 

boosting stations in the production 

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56640 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

110U.S. Environmental Protection Agency, 

Protocol for Equipment Leak Emission Estimates, 

Table 2–4, November 1995 (EPA–453/R–95–017). 

111Memorandum 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 

112See pages 68–69 of the TSD. 

segment and emission factors from the 

GRI/EPA report were used to estimate 

fugitive emission from transmission and 

storage compressor stations and 

evaluate the cost of control for these 

segments. 

Since we have emission factors for 

only a subset of the components which 

are possible sources for fugitive 

emissions, our emission estimates are 

believed to be lower than the emissions 

profile for the entire set of components 

that would typically be found at a 

compressor station. 

The fugitive emission factors from 

AP–42,110 which provided a single 

source of TOC emission factors that 

include non-VOCs, such as methane and 

ethane, were used to estimate emissions 

and evaluate the cost of control of a 

fugitive emissions program for 

compressor stations. Using the GRI/EPA 

and AP–42 data, fugitive emissions from 

gathering and boosting stations were 

estimated to be 35.1 tpy of methane and 

9.8 tpy of VOC. Fugitive emissions from 

natural gas transmission stations were 

estimated to be 62.4 tpy of methane and 

1.7 tpy of VOC. Fugitive emissions from 

natural gas storage facilities were 

estimated to be 164.4 tpy of methane 

and 4.6 tpy of VOC. The calculation of 

these emission estimates are explained 

in detail in the TSD available in the 

docket. 

Information in the white paper related 

to the potential emission reductions 

from the implementation of an OGI 

monitoring program varied from 40 to 

99 percent. The causes for this range in 

reduction efficiency were the frequency 

of monitoring surveys performed and 

different assumptions made by the 

study authors. According to the 

calculations, which are based on 

uncontrolled emission factors for well 

pads contained within the EPA Oil and 

Natural Gas Sector Technical Support 

Document (2011), the Colorado Air 

Quality Control Commission, Initial 

Economic Impact Analysis for Proposed 

Revisions to Regulation Number 7 (5 

CCR 1001–9) and the FINAL 

ECONOMIC IMPACT ANALYSIS For 

Industry’s Proposed Revisions to 

Colorado Air Quality Control 

Commission Regulation Number 3, 6, 

and 7 (5 CCR 1001–9) (January 30, 

2014), a -quarterly monitoring program 

in combination with a repair program 

can reasonably be expected to reduce 

fugitive methane and VOC emissions at 

well sites by 80 percent. Although 

information in the white paper 

indicated emission reductions as high as 

99 percent may be achievable with OGI, 

we do not believe such levels can be 

consistently achieved for all of types of 

components that may be subject to a 

fugitive emissions monitoring program. 

Therefore, using engineering judgement 

and experience obtained through our 

existing programs for finding and 

repairing leaking components, we 

selected 80 percent as an emission 

reduction level that can reasonably be 

expected to be achieved with a quarterly 

monitoring program. Due to the 

increased amount of time between each 

monitoring survey and subsequent 

repair, we believe that the level of 

emissions reduction achieved by less 

frequent monitoring surveys will be 

reduced from this level. Therefore, we 

assigned an emission reduction of 60 

percent to semiannual monitoring 

survey and repair frequency and 40 

percent to annual frequency, consistent 

with the reduction levels used by the 

Colorado Air Quality Control 

Commission in their initial and final 

economic impacts analyses. We solicit 

comment on the appropriateness of the 

percentage of emission reduction level 

that can be reasonably expected to be 

achieved with quarterly, semiannual, 

and annual monitoring program 

frequencies. 

For Method 21, we estimated 

emissions reductions using The EPA 

Equipment Leaks Protocol document, 

which provides emissions factor data 

based on leak definition and monitoring 

frequencies primarily for the Synthetic 

Organic Chemical Manufacturing 

Industry (SOCMI) and Petroleum 

Refining Industry along with the 

emissions rates contained within the 

Technology Review for Equipment 

Leaks document.111 We used these data 

along with the monitoring frequency 

(e.g., annual, semiannual, and quarterly) 

at fugitive repair thresholds at 500, 

2,500 and 10,000 ppm to determine 

uncontrolled emissions. Using this 

information we calculated an expected 

emissions reduction percentage for each 

of the combinations of monitoring 

frequency and repair threshold which 

range from. 

We also looked at the costs of a 

monitoring and repair program under 

various monitoring frequencies and 

repair thresholds (for Method 21), 

including the cost of OGI monitoring 

survey, repair, monitoring plan 

development, and the cost-effectiveness 

of the various options.112 For purposes 

of this action, we have identified in 

section VIII.A two approaches (single 

pollutant and multipollutant 

approaches) for evaluating whether the 

cost of a multipollutant control, such as 

the fugitive emissions monitoring and 

repair programs identified above, is 

reasonable. As explained in that section, 

we believe that both approaches are 

appropriate for assessing the 

reasonableness of the multipollutant 

controls considered in this action. 

Therefore, we find the cost of control to 

be reasonable as long as it is such under 

either of these two approaches. 

Under the first approach (single 

pollutant approach), we assign all costs 

to the reduction of one pollutant and 

zero to all other pollutants 

simultaneously reduced. Under the 

second approach (multipollutant 

approach), we apportion the annualized 

cost across the pollutant reductions 

addressed by the control option in 

proportion to the relative percentage 

reduction of each pollutant controlled. 

In the multipollutant approach, since 

methane and VOC are controlled 

equally, half the cost is apportioned to 

the methane emission reductions and 

half the cost is apportioned to the VOC 

emission reductions. In this evaluation, 

we evaluated both approaches across 

the range of identified monitoring 

survey options: OGI monitoring and 

repair performed quarterly, 

semiannually and annually; and Method 

21 monitoring performed quarterly, 

semiannually and annually, with a 

fugitive emissions repair threshold of 

500, 2,500 and 10,000 ppm at each 

frequency. The calculation of the costs, 

emission reductions, and cost of control 

for each option are explained in detail 

in the TSD. As shown in the TSD, while 

the costs for repairing components that 

are found to have fugitive emissions 

during a fugitive monitoring survey 

remain the same, the annual repair costs 

will differ based on monitoring 

frequency. 

As shown in our TSD, both OGI and 

Method 21 monitoring survey 

methodologies costs generally increase 

with increasing monitoring frequency 

(i.e., quarterly monitoring has a higher 

cost of control than annual monitoring). 

For EPA Method 21 specifically, the 

cost also increases with decreasing 

fugitive emissions repair threshold (i.e., 

500 ppm results in a higher cost of 

control than 10,000 ppm). However, as 

shown in the TSD, the cost of control 

based on the OGI methodology for 

annual, semiannual, and quarterly 

monitoring frequencies are estimated to 

be more cost-effective than Method 21 

for those same monitoring 

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113See the 2015 TSD for full comparison. 

frequencies.113 We therefore focus our 

BSER analysis based on the use of OGI. 

As shown in the TSD, the costs are 

comparable for all three monitoring 

frequencies using OGI. For the reasons 

explained below, we find the 

monitoring/repair program using OGI at 

compressor stations to be cost-effective 

for all three monitoring frequencies. 

Under the single pollutant approach, if 

we assign all control costs to VOC and 

zero to methane reduction, the costs 

range from $3,110 to $4,273 per ton of 

VOC reduced ($2,338 to $3,502 with gas 

saving) and zero for methane, which 

indicate that the control is costeffective. Even if we assign all of the 

costs to methane and zero to VOC 

reduction, the costs, which range from 

$686 to $930 per ton of methane 

reduced ($471 to $715 per ton with gas 

savings), are well below our costeffectiveness estimates for the semiannual monitoring and repair option for 

reducing fugitive emissions at 

compressor stations, which we find to 

be reasonable for the reasons stated 

above. Under the multipollutant 

approach, the costs for VOC reduction 

range from $1,555 to $2,136 ($1,169 to 

$1,751 with gas saving). The costs for 

methane reduction range from $343 to 

$465 per ton ($236 to $358 per ton with 

gas savings). Again these cost estimates 

for methane reductions are well below 

our estimates for the monitoring/repair 

program at compressor stations using 

OGI based on semiannual monitoring, 

which we find to be reasonable for the 

reasons stated above. Further, as 

previously explained, we believe the 

emission reduction values used in these 

calculations underestimate the actual 

emission reductions that would be 

achieved by a fugitives monitoring and 

repair program, so these cost of control 

values likely represent a high end cost 

assumption. Therefore, we believe the 

use of OGI is more cost-effective than 

the amounts presented here. The 

calculation of the costs, emission 

reductions, and cost of control 

calculations for each option are 

explained in detail in the TSD for this 

action available in the docket. 

While the costs are comparable for all 

three monitoring frequencies using OGI, 

for the reasons stated below, we have 

concerns with the potential compliance 

burdens, in particular on small 

businesses, associated with quarterly 

monitoring, and we believe that semiannual monitoring could achieve 

meaningful reduction without such 

potential issues. 

Further practical aspects we 

considered for the methodology of each 

monitoring survey include the likeliness 

that many owners and operators will 

hire a contractor to conduct the 

monitoring survey due to the cost of the 

specialized equipment needed to 

perform the monitoring survey and the 

training necessary to properly operate 

the OGI equipment. We also believe that 

small businesses are most likely to hire 

such contractors because they are less 

likely to have excess capital to purchase 

monitoring equipment and train 

operators. We are concerned that the 

limited supply of qualified contractors 

to perform monitoring surveys may lead 

to disadvantages for small businesses. 

Larger businesses, due to the economic 

clout they have by offering the 

contractors more work due to the higher 

number of compressor stations they 

own, may preferentially retain the 

services of a large portion of the 

available contractors. This may result in 

small businesses experiencing a longer 

wait time to obtain contractor services. 

Specifically for conducting OGI 

monitoring surveys, we believe that 

many operators will hire OGI 

contractors to conduct the OGI surveys. 

The proposed fugitive emissions 

monitoring plan requires that operators 

verify the capability of OGI 

instrumentation, determine viewing 

distance, and determine the maximum 

wind speed. Additionally, there are 

specific requirements for conducting the 

survey such as how to operate OGI in 

adverse monitoring conditions or how 

to deal with interferences such as steam. 

Each corporate-wide plan will need to 

include these requirements and will 

require OGI contractors and operators to 

be trained to meet these requirement. 

The monitoring plan requirements will 

also cause the surveys to take more 

time, thus affecting the availability of 

OGI equipment and contractors. 

Therefore, if we specify quarterly 

monitoring surveys, we are concerned 

that the available supply of qualified 

contractors and OGI instruments may 

not be sufficient for small businesses to 

obtain timely monitoring surveys. For 

the reasons stated above, we have 

concerns with the potential compliance 

burdens, in particular on small 

businesses, associated with quarterly 

monitoring, and we believe that semiannual monitoring could achieve 

meaningful reduction without such 

potential issues. 

We also identified in section VIII.A 

two additional approaches, based on 

new capital expenditures and annual 

revenues, for evaluating whether the 

costs are reasonable. For monitoring and 

repair of fugitive emissions at 

compressor stations, we believe that the 

total revenue analysis is more 

appropriate than the capital expenditure 

analysis and therefore we did not 

perform the capital expenditure 

analysis. For the total revenue analysis, 

we used the revenues for 2012 for 

NAICS 486210, which we believe is 

representative of the production 

segment. The total annualized costs for 

complying with the proposed standards 

is 0.103 percent of the total revenues, 

which is very low. 

For all types of affected facilities in 

the transmission and storage segment, 

the total annualized costs for complying 

with the proposed standards is 0.13 

percent of the total revenues, which is 

also very low. 

For the reasons stated above, we find 

the cost of monitoring and repairing 

fugitive emissions at compressor 

stations based on semi-annual 

monitoring using OGI to be reasonable. 

To ensure that no fugitive emissions 

remain, a resurvey of the repaired 

components is necessary. We expect 

that most of the repair and resurveys are 

conducted at the same time as the initial 

monitoring survey while OGI personnel 

are still on-site. However, there may be 

some components that cannot be 

repaired right away and in some 

instances not until after the initial OGI 

personnel are no longer on site. In that 

event, resurvey with OGI would require 

rehiring OGI personnel, which would 

make the resurvey not cost effective. On 

the other hand, as shown in the TSD, 

the cost of conducting a resurvey using 

Method 21 is $2 per component, which 

is reasonable. 

We did not find any nonair quality 

health and environmental impacts, or 

energy requirements associated with the 

use of OGI or Method 21 for monitoring, 

repairing and resurveying fugitive 

emissions components at compressor 

stations. Based on the above analysis, 

we believe that the BSER for reducing 

fugitive methane and VOC emissions at 

compressor stations is a monitoring and 

repair standard based on semi-annual 

monitoring using OGI and resurvey 

using Method 21. 

Although we identified OGI with 

semiannual monitoring as the BSER, we 

acknowledge that some states have 

promulgated rules that allow for annual 

monitoring of fugitive emission sources. 

In addition, EPA regulates GHGs in 40 

CFR part 98 subpart W and requires 

annual fugitive emissions surveys for 

emissions reporting. As previously 

discussed we believe that we have 

underestimated our baseline fugitive 

emissions estimate for well sites and 

compressors and the emission 

reductions may be greater than we have 

estimated. However, because we 

continue to support efforts by states to 

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56642 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

114This timeline is consistent with the timeline 

originally established in 1983 under 40 CFR part 60 

subpart VV. 

115See 2015 TSD. 

establish fugitive emissions monitoring 

programs and to establish efficiencies 

across programs, we solicit comment on 

an alternate option for the fugitive 

emission monitoring program based on 

setting the initial monitoring frequency 

to an annual or quarterly frequency. 

CAA section 111(h)(1) states that the 

Administrator may promulgate a work 

practice standard or other requirements, 

which reflects the best technological 

system of continuous emission 

reduction when it is not feasible to 

enforce an emission standard. CAA 

section 111(h)(2) defines the phrase 

‘‘not feasible to prescribe or enforce an 

emission standard’’ as follows: 

[A]ny situation in which the Administrator 

determines that (A) a hazardous air pollutant 

or pollutants cannot be emitted through a 

conveyance designed and constructed to emit 

or capture such pollutant, or that any 

requirement for, or use of, such a conveyance 

would be inconsistent with any Federal, 

State, or local law, or (B) the application of 

measurement methodology to a particular 

class of sources is not practicable due to 

technological and economic limitations. 

The work practice standards for fugitive 

emissions from compressor stations are 

consistent with CAA section 

111(h)(1)(A), because no conveyance to 

capture fugitive emissions exist for 

fugitive emissions components. In 

addition, OGI does not measure the 

extent the fugitive emissions from 

fugitive emissions components. For the 

reasons stated above, pursuant to CAA 

section 111(h)(1)(b), we are proposing 

work practice standards for fugitive 

emissions from compressor stations. 

The proposed work practice standards 

include details for development of a 

fugitive emissions monitoring plan, 

repair requirements and recordkeeping 

and reporting requirements. The fugitive 

emissions monitoring plan includes 

operating parameters to ensure 

consistent and effective operation for 

OGI such as procedures for determining 

the maximum viewing distance and 

wind speed during monitoring. The 

proposed standards would require a 

source of fugitive emissions to be 

repaired or replaced as soon as 

practicable, but no later than 15 

calendar days after detection of the 

fugitive emissions. We have historically 

allowed 15 days for repair/resurvey in 

LDAR programs, which appears to be 

sufficient time. Further, in light of the 

number of components at a compressor 

station and the number that would need 

to be repaired, we believe that 15 days 

is also sufficient for conducting the 

required repairs under the proposed 

fugitive emission standards. That said, 

we are also soliciting comment on 

whether 15 days is an appropriate 

amount of time for repair of sources of 

fugitive emissions at compressor 

stations.114

Many recent studies have shown a 

skewed distribution for emissions 

related to leaks, where a majority of 

emissions come from a minority of 

sources.115 Commenters on the white 

papers agreed that emissions from 

equipment leaks exhibit a skewed 

distribution, and pointed to other 

examples of data sets in which the 

majority of methane and VOC fugitive 

emissions come from a minority of 

components (e.g., gross emitters). Based 

on this information, we solicit comment 

on whether the fugitive emissions 

monitoring program should be limited 

to ‘‘gross emitters.’’ 

We believe that a properly maintained 

facility would likely detect very little to 

no fugitive emissions at each monitoring 

survey, while a poorly maintained 

facility would continue to detect 

fugitive emissions. We believe that a 

facility with proper operation would 

likely find one to three percent of 

components to have fugitive emissions. 

To encourage proper maintenance, we 

are proposing that the owner or operator 

may go to annual monitoring if the 

initial two consecutive semiannual 

monitoring surveys show that less than 

one percent of the collection of fugitive 

emissions components at the 

compressor station has fugitive 

emissions. For the same reason, we are 

proposing that the owner or operator 

conduct quarterly monitoring if the 

initial two semi-annual monitoring 

surveys show that more than three 

percent of the collection of fugitive 

emissions components at the 

compressor station has fugitive 

emissions. We believe the first year to 

be the tune-up year to allow owners and 

operators the opportunity to refine the 

requirements of their monitoring/repair 

plan. After that initial year, the required 

monitoring frequency would be annual 

if a monitoring survey shows less than 

one percent of components to have 

fugitive emissions; semi-annual if one to 

three percent of total components have 

fugitive emissions; and quarterly if over 

three percent of total components have 

fugitive emissions. We solicit comment 

on this approach, including the 

percentage used to adjust the 

monitoring frequency. We also solicit 

comment on the appropriateness of 

performance based monitoring 

frequencies. We also solicit comment on 

the appropriateness of triggering 

different monitoring frequencies based 

on the percentage of components with 

fugitive emissions. 

Under the proposed standards, the 

affected facility would be defined as the 

collection of fugitive emissions 

components at a compressor station. To 

clarify which components are subject to 

the fugitive emissions monitoring 

provisions, we propose to add a 

definition to § 60.5430 for ‘‘fugitive 

emissions component’’ as follows: 

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 site, including 

but not limited to valves, connectors, 

pressure relief devices, open-ended lines, 

access doors, flanges, closed vent systems, 

thief hatches or other openings on a storage 

vessels, agitator seals, distance pieces, 

crankcase vents, blowdown vents, pump 

seals or diaphragms, compressors, separators, 

pressure vessels, dehydrators, heaters, 

instruments, and meters. Devices that vent as 

part of normal operations, such as a natural 

gas-driven pneumatic controller or a natural 

gas-driven pump, are not fugitive emissions 

components, insofar as the natural gas 

discharged from the device’s vent is not 

considered a fugitive emission. Emissions 

originating from other than the vent, such as 

the seals around the bellows of a diaphragm 

pump, would be considered fugitive 

emissions. 

Thus, all fugitive emissions 

components at the affected facility 

would be monitored for fugitive 

emissions of methane and VOC. 

For the reasons stated in section 

VII.G.2, for purposes of the proposed 

standards for fugitive emission at 

compressor stations, we propose that a 

modification occurs only when a 

compressor is added to the compressor 

station or when physical change is made 

to an existing compressor at a 

compressor station that increases the 

compression capacity of the compressor 

station. As explained in that section, 

since fugitive emissions at compressor 

stations are from compressors and their 

associated piping, connections and 

other ancillary equipment, expansion of 

compression capacity at a compressor 

station, either through addition of a 

compressor or physical change to the an 

existing compressor, would result in an 

increase in emissions to the fugitive 

emissions components. Other than these 

events, we are not aware of any other 

physical change to a compressor station 

that would result in an increase in 

emissions from the collection of fugitive 

components at such compressor station. 

To provide clarity and ease of 

implementation, for the purposes of the 

proposed standards for fugitive 

emissions at compressor stations, we are 

proposing to define modification as the 

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addition of a compressor at an existing 

compressor station or when a physical 

change is made to an existing 

compressor at a compressor station that 

increases the compression capacity of 

the compressor station. 

To encourage broadly applied fugitive 

emissions monitoring, we are also 

soliciting comments on criteria we can 

use to determine whether and under 

what conditions all new or modified 

compressor stations operating under 

corporate fugitive monitoring programs 

can be deemed to be meeting the 

equivalent of the NSPS standards for 

compressor stations fugitive emissions 

such that we can define those regimes 

as constituting alternative methods of 

compliance or otherwise provide 

appropriate regulatory streamlining. We 

also solicit comment on how to address 

enforceability of such alternative 

approaches (i.e., how to assure that 

these compressor stations are achieving, 

and will continue to achieve, equal or 

better emission reduction than our 

proposed standards). 

We are requesting comment on 

whether the fugitive emissions 

requirements should apply to all of the 

fugitive emissions sources at the 

compressor station for modified 

compressor stations or just to fugitive 

sources that are connected to the added 

compressor. For some modified 

compressor stations, the added 

compressor may only be connected to a 

subset of the fugitive emissions sources 

on site. We are soliciting comment on 

whether the fugitive emission 

requirements should only apply to that 

subset. However, we are aware that the 

added complexity of distinguishing 

covered and non-covered sources may 

create difficulty in implementing these 

requirements. However, we note that it 

may be advantageous to the operator 

from an operational perspective to 

monitor all the components at a 

compressor station since the monitoring 

equipment is already onsite. 

As explained above, Method 21 is not 

as cost-effective as OGI for monitoring. 

That said, there may be reasons why 

and owner and operator may prefer to 

use Method 21 over OGI. While we are 

confident with the ability of Method 21 

to detect fugitive emissions and 

therefore consider it a viable alternative 

to OGI, we solicit comment on the 

appropriate fugitive emissions repair 

threshold for Method 21 monitoring 

surveys. As mentioned above, EPA’s 

recent work with OGI indicates that 

fugitive emissions at a concentration of 

10,000 ppm is generally detectable 

using OGI instrumentation provided 

that the right operating conditions (e.g., 

wind speed and background 

temperature) are present. Work is 

ongoing to determine the lowest 

concentration that can be reliably 

detected using OGI As mentioned 

above, we believe that OGI. In light of 

the above, we solicit comment on 

whether the fugitive emissions repair 

threshold for Method 21 surveys should 

be set at 10,000 ppm or whether a 

different threshold is more appropriate 

(including information to support such 

threshold). 

While we did not identify OGI as the 

BSER for resurvey because of the 

potential cost associated with rehiring 

OGI personnel, there is no such 

additional cost for those who either own 

the OGI instrument or can perform 

repair/resurvey at the same time. 

Therefore, the proposed rule would 

allow the use either OGI or Method 21 

for resurvey. When Method 21 is used 

to resurvey components, we are 

proposing that the component is 

repaired if the Method 21 instrument 

indicates a concentration of less than 

500 ppm above background. This has 

been historically used in other LDAR 

programs as an indicator of no 

detectable emissions. 

The proposed standards would 

require that operators begin monitoring 

fugitive emissions components at 

compressor stations with 30 days of the 

initial startup of a new compressor 

station or within 30 days of a 

modification of a compressor station. 

We are proposing 30 day period to allow 

owners and operators the opportunity to 

secure qualified contractors and 

equipment necessary for the initial 

monitoring survey. We are requesting 

comment on whether 30 days is an 

appropriate amount of time to begin 

conducting fugitive emissions 

monitoring. 

We received new information 

indicating that some companies could 

experience logistical challenges with the 

availability of OGI instrumentation and 

qualified OGI personnel to perform 

monitoring surveys and in some 

instances repairs. We solicit comment 

on both the availability of OGI 

instruments and the availability of 

qualified OGI personnel to perform 

monitoring surveys and repairs. 

We are requesting comment on 

whether there are other fugitive 

emission detection technologies for 

fugitive emissions monitoring, since this 

is a field of emerging technology and 

major advances are expected in the near 

future. We are aware of several types of 

technologies that may be appropriate for 

fugitive emissions monitoring such as 

Geospatial Measurement of Air 

Pollutants using OTM–33 approaches 

(e.g., Picarro Surveyor), passive sorbent 

tubes using EPA Methods 325A and B, 

active sensors, gas cloud imaging (e.g., 

Rebellion photonics), and Airborne 

Differential Absorption Lidar (DIAL). 

Therefore, we are specifically requesting 

comments on details related to these 

and other technologies such as the 

detection capability; an equivalent 

fugitive emission repair threshold to 

what is required in the proposed rule for 

OGI; the frequency at which the fugitive 

emissions monitoring survey should be 

performed and how this frequency 

ensures appropriate levels of fugitive 

emissions detection; whether the 

technology can be used as a stand-alone 

technique or whether it must be used in 

conjunction with a less frequent (and 

how frequent) OGI monitoring survey; 

the type of restrictions necessary for 

optimal use; and the information that is 

important for inclusion in a monitoring 

plan for these technologies. 

H. Proposed Standards for Equipment 

Leaks at Natural Gas Processing Plants 

In the 2012 NSPS, we established 

VOC standards for equipment leaks at 

onshore natural gas processing plants in 

the oil and natural gas source category. 

In this action, we are proposing 

methane standards for onshore natural 

gas processing plants. Based on the 

analysis below, the proposed methane 

standards are the same as the VOC 

standards currently in the NSPS. 

Natural gas is primarily made up of 

methane. However, whether natural gas 

is associated gas from oil wells or nonassociated gas from gas or condensate 

wells, it commonly exists in mixtures 

with other hydrocarbons. These 

hydrocarbons are often referred to as 

natural gas liquids (NGL). They are sold 

separately and have a variety of 

different uses. The raw natural gas often 

contains water vapor, H2S, CO2, helium, 

nitrogen and other compounds. Natural 

gas processing consists of separating 

certain hydrocarbons and fluids from 

the natural gas to produced ‘‘pipeline 

quality’’ dry natural gas. While some of 

the processing can be accomplished in 

the production segment, the complete 

processing of natural gas takes place in 

the natural gas processing segment. 

Natural gas processing operations 

separate and recover NGL or other 

nonmethane gases and liquids from a 

stream of produced natural gas through 

components performing one or more of 

the following processes: Oil and 

condensate separation, water removal, 

separation of NGL, sulfur and CO2

removal, fractionation of natural gas 

liquid and other processes, such as the 

capture of CO2 separated from natural 

gas streams for delivery outside the 

facility. 

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116Available athttp://www.epa.gov/airquality/

oilandgas/2014papers/20140415leaks.pdf. 

117 In 2012 we already found that the cost of this 

control to be reasonable for reducing VOC 

emissions from natural gas processing plants. We 

are not reopening that decision in this action. 

In the analysis for the 2012 NSPS, we 

estimated nationwide methane 

emissions from equipment leaks at 

onshore natural gas processing plants to 

be 51.4 tpy. We identified four control 

options for reducing methane emissions 

from these equipment leaks in the 2012 

TSD: (1) Subpart VVa level of control; 

(2) monthly survey using optical gas 

imaging (OGI) and an annual Method 21 

survey; (3) monthly OGI survey without 

the annual Method 21 survey; and (4) 

annual OGI survey. 

In April 2014, the EPA published the 

white paper titled ‘‘Oil and Natural Gas 

Sector Leaks’’116 which summarized the 

EPA’s current understanding of fugitive 

emissions of methane and VOC at 

onshore oil and natural gas production, 

processing, and transmission and 

storage facilities. The white paper also 

outlined our understanding of the 

available mitigation techniques 

(practices and equipment) available to 

reduce these emissions along with the 

cost and effectiveness of these practices 

and technologies. Based on our review 

of the public and peer review comments 

on the white paper and our additional 

research, we did not identify any 

additional control options beyond those 

that we identified for the 2012 NSPS. 

For purposes of this action, we have 

identified two approaches in section 

VIII.A for evaluating whether the cost of 

a multipollutant control, such as the 

leak detection and repair programs 

described above, is reasonable. As 

explained in that section above, we 

believe that both approaches are 

appropriate for assessing the 

reasonableness of the multipollutant 

controls considered in this action. 

Therefore, we find the cost of control to 

be reasonable as long as it is such under 

either of these two approaches. 

Under the first approach (single 

pollutant approach), which assigns all 

costs to the reduction of one pollutant 

and zero to all other pollutants 

simultaneously reduced, we find the 

cost of control reasonable if it is 

reasonable for reducing one pollutant 

alone. The annualized costs for option 

1 (subpart VVa level of control) is 

$45,160 without considering the cost 

savings of the recovered natural gas, and 

$33,915 considering the cost savings. 

We estimate the cost of reducing 

methane emissions from equipment 

leaks at natural gas processing plants 

under this option to be $931 per ton. 

The annualized costs for option 2 

(monthly survey using OGI and annual 

Method 21 survey) is $87,059 without 

considering the cost savings of the 

recovered natural gas, and $75,813 

considering the cost savings. We 

estimate the cost of reducing methane 

emissions from equipment leaks at 

natural gas processing plants under this 

option to be $1,795 per ton. At the time 

of the analysis for the 2012 NSPS, we 

were unable to estimate the methane 

emission reduction of options 3 

(monthly OGI survey) and 4 (annual 

OGI survey-only programs) since OGI 

currently does not have the capability to 

quantify emissions. 

We find the costs for methane 

emission reductions for option 1 

(subpart VVa level of control) to be 

reasonable for the amount of methane 

emissions it can achieve. Also, because 

all of the costs have been attributed to 

methane reduction, the cost of 

simultaneous VOC reduction is zero and 

therefore reasonable.117

Although we propose to find the cost 

of control to be reasonable because it is 

reasonable under the above approach, 

we also evaluated the cost of option 1 

(subpart VVa level of control) under the 

second approach (multipollutant 

approach). Under the second approach, 

we apportion the annualized cost across 

the pollutant reductions addressed by 

the control option in proportion to the 

relative percentage reduction of each 

pollutant controlled. In this case, since 

methane and VOC are controlled 

equally, half the cost is apportioned to 

the methane emission reductions and 

half the cost is apportioned to the VOC 

emission reductions. Under this 

approach, the costs are allocated based 

on the percentage reduction expected 

for each pollutant. Because option 1 

(subpart VVa level of control) reduces 

the fugitive emission of natural gas from 

equipment components, emissions of 

methane and VOC will be reduced 

equally. Therefore, we attribute 50 

percent of the costs to methane 

reduction and 50 percent to VOC 

reduction. Based on this formulation, 

the costs for methane reduction are half 

of the estimated costs under the first 

approach above and are therefore 

reasonable. 

With option 1 (subpart VVa level of 

control) there would be no secondary air 

impacts, therefore no impacts were 

assessed. Also, we did not identify any 

nonair quality or energy impacts 

associated with this control technique, 

therefore no impacts were assessed. 

In light of the above, we find that the 

BSER for reducing methane emissions 

from equipment leaks at natural gas 

processing plants is a leak detection and 

repair program at the subpart VVa level 

of control, and we are proposing to 

require such a program at natural gas 

processing plants. As described above, 

the proposed methane standard would 

be the same as the current VOC standard 

for natural gas processing plants in the 

NSPS. 

I. Liquids Unloading Operations 

Liquids unloading is an operation that 

is conducted at natural gas wells to 

remove accumulated liquids that can 

impede or even halt production of 

natural gas due to insufficient gas flow 

within the wellbore. Fluid accumulation 

is a common problem in both aging and 

newer natural gas wells. The typical 

industry practices used to accomplish 

liquids unloading include using plunger 

lifts, beam pumps, remedial treatments, 

or venting the well to atmosphere (also 

referred to as blowing down the well). 

The emissions from liquids unloading 

result from the intentional venting of 

gas from the wellbore during activities 

conducted on or near equipment 

associated with the removal of 

accumulated fluids. The volume of gas 

vented is presumed to be the total 

volume of gas in the casing and tubing 

minus the volume of water accumulated 

in the well. Wells can require multiple 

unloading events per year; however, the 

number and frequency of unloading 

events and volume of emissions 

generated vary widely. Some wells 

conduct liquids unloading without 

venting, through use of closed-loop 

systems and other technologies. 

Based on the information and data 

available to the EPA during 

development of the 2012 NSPS, the EPA 

conducted a preliminary screening of 

emissions sources with the goal of 

maximizing emission reductions for 

new sources. At the time, there was not 

sufficient data available to determine 

whether liquids unloading was an issue 

for hydraulically fractured wells, which 

represent the majority of projected 

future production and new sources. In 

petitions on the 2012 NSPS, some 

petitioners asserted that the EPA should 

have regulated the methane and VOC 

emissions from liquids unloading 

operations because these emissions are 

significant and there are data that 

demonstrate that cost-effective 

mitigation technologies are available to 

address the emissions. 

Data on liquids unloading operations 

supplied to the EPA subsequent to the 

2012 rule finalization provided 

significantly better insight into 

emissions from liquids unloading. Data 

were provided in a study conducted by 

members of the American Petroleum 

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Institute (API) and America’s Natural 

Gas Alliance (ANGA) and published in 

a report titled ‘‘Characterizing Pivotal 

Sources of Methane Emissions from 

Natural Gas Production, Summary and 

Analysis of API and ANGA Survey 

Responses’’, hereafter referred to the 

API/ANGA study, available in the 

docket. These data demonstrate that 

venting for liquids unloading can and 

does result in significant increases in 

emissions for the well in comparison to 

wells that do not vent for liquids 

unloading operations. In addition, data 

reported to the GHGRP show emissions 

from venting for liquids unloading 

similar in magnitude to those calculated 

using API/ANGA study data. 

The 2014 white paper on liquids 

unloading discussed the most recent 

information and data available for the 

analysis of emissions (including the 

API/ANGA survey and GHGRP data) 

and industry practices or control 

technologies available to address these 

emissions. Commenters on the white 

paper noted that venting for liquids 

unloading is a significant source of 

emissions and that these emissions are 

highly skewed, with a minority of 

sources being responsible for a large 

fraction of total emissions. As a result, 

commenters urged the EPA to further 

study these operations and that 

regulation of those operations at this 

time would be premature. 

Since publication of the white paper, 

additional data have become available 

on liquids unloading emissions from 

Allen et al., 2014. The Allen et al. data 

confirm the findings of previous studies, 

that venting for liquids unloading is a 

significant source of emissions and that 

emissions are highly skewed. Data 

reviewed also show that liquids 

unloading events are highly variable 

and often well-specific. Furthermore, 

questions remain concerning the 

difficulty of effective control for these 

high-emitting events in many cases and 

the applicability and limitations of 

specific control technologies such as 

plunger lift systems for supporting a 

new source performance standard. For 

analysis conducted in the development 

of this proposal, we revised our estimate 

of methane and VOC emissions from 

liquids unloading based on the API/

ANGA study data and Allen et al. Based 

on the emissions data discussed in the 

white paper, and on new data available 

from Allen et al., we believe that the 

emissions from liquids unloading 

operations are significant. However, as 

noted in section VII.I, the EPA does not 

have sufficient information to propose 

standards for liquids unloading. The 

EPA is continuing to study this issue 

and is soliciting information and data 

on control technologies or practices for 

reducing these emissions. 

Specifically, we are soliciting 

comment on the level of methane and 

VOC emissions per unloading event, the 

number of unloading events per year, 

and the number of wells that perform 

liquids unloading. In addition, we 

solicit comment on (1) characteristics of 

the well that play a role in the frequency 

of liquids unloading events and the 

level of emissions, (2) demonstrated 

techniques to reduce the emissions from 

liquids unloading events, including the 

use of smart automation, and the 

effectiveness and cost of these 

techniques, (3) whether there are 

demonstrated techniques that can be 

employed on new wells that will reduce 

the emissions from liquids unloading 

events in the future, and (4) whether 

emissions from liquids unloading can be 

captured and routed to a control device 

and whether this has been demonstrated 

in practice. 

IX. Implementation Improvements 

A. Storage Vessel Control Device 

Monitoring and Testing Provisions 

We are proposing regulatory text 

changes that address performance 

testing and monitoring of control 

devices used for new storage vessel 

installations and centrifugal compressor 

emissions, specifically relating to infield performance testing of enclosed 

combustors. Industry reconsideration 

petitioners assert that the compliance 

demonstration and monitoring 

requirements finalized in the 2012 

NSPS were overly complex and 

stringent given the large number of 

affected storage vessels each year and 

the remoteness of the well sites at which 

they are installed. The petitioners argue 

that the well sites are unmanned for 

periods of time up to a month. The 

additional information provided by 

petitioners raised significant concerns 

that the compliance monitoring 

provisions and field testing provisions 

of the 2012 NSPS may not have been 

appropriate for the large number of 

affected storage vessels, which was 

much greater than we had expected, and 

of which many are in remote locations. 

In the reconsideration of the NSPS 

that was finalized in 2013, we 

streamlined certain monitoring and 

continuous compliance demonstration 

requirements, while we more fully 

evaluated the proper requirements. 

Instead of the detailed Method 21 

monitoring requirements, the revised 

requirements included monthly sensory 

(i.e., OVA) inspections of: (1) Closedvent system joints, seams and other 

sealed connections (e.g., welded joints); 

(2) other closed-vent system 

components such as peak pressure and 

vacuum valves; and (3) the physical 

integrity of tank thief hatches, covers, 

seals and pressure relief devices. Instead 

of the continuous parameter monitoring 

system (CPMS) requirements, the 

revised requirements included the 

following inspection requirements: (1) 

Monthly observation for visible smoke 

emissions employing section 11 of EPA 

Method 22 for a 15 minute period; (2) 

monthly visual inspection of the 

physical integrity of the control device; 

and (3) monthly check of the pilot flame 

and signs of improper operations. 

Lastly, instead of the field performance 

testing requirements in § 60.5413, we 

required that, where controls are used to 

reduce emissions, sources use control 

devices that by design can achieve 95 

percent or more emission reduction and 

operate such devices according to the 

manufacturer’s instructions, procedures 

and maintenance schedule, including 

appropriate sizing of the combustor for 

the application. 

After evaluating these streamlined 

requirements and other potential 

options, we believe that performance 

testing of enclosed combustors is 

necessary to assure that they are 

achieving the required 95 percent 

control. However, petitioners also assert 

that the previous performance testing 

requirements were unreasonably 

strenuous for a control device needing 

to demonstrate 95 percent control 

efficiency. They assert that in order for 

an enclosed combustor to meet a 

requirement of 20 parts per million 

volume (ppmv) it would have to be 

achieving greater than the required 95 

percent control. After an evaluation of 

the requirement we agree with the 

comment and are proposing to revise 

this requirement from 20 ppmv to 600 

ppmv; a value that more appropriately 

reflects 95 percent control of VOC 

inflow to these control devices. The 

EPA solicits comment on the 

appropriateness of this level of control 

and invites commenters to provide data 

that demonstrates the VOC composition 

of field gas from a variety of oil and gas 

field well sites across the nation. 

As proposed, initial and ongoing 

performance testing will be required for 

any enclosed combustors used to 

comply with the emissions standard for 

an affected facility and whose make and 

model are not listed on the EPA Oil and 

Natural Gas Web site (http://

www.epa.gov/airquality/oilandgas/

implement.html) as those having 

already met a Manufacturer’s 

Performance Test demonstration. 

Performance testing of combustors not 

listed at the above site would also be 

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conducted on an ongoing basis, every 60 

months of service, and monthly 

monitoring of visible emissions from 

each unit is also required. 

We are proposing amendments to 

make the requirements for monitoring of 

visible emissions consistent for all 

enclosed combustion units. Currently 

enclosed combustors that have met the 

Manufacturer’s Performance Test 

requirement must conduct quarterly 

observation for visible smoke emissions 

employing section 11 of EPA Method 22 

for a 60 minute period. 40 CFR 

60.5413(e)(3). Certain petitioners have 

suggested it may ease implementation to 

adjust the frequency and duration to 

monthly 15 minute EPA Method 22 

tests, which is currently required for 

continuous monitoring of enclosed 

combustors that are not manufacturer 

tested. 40 CFR 60.5417(h)(1). If this 

change were made then all enclosed 

combustors would have the same 

monitoring requirements which could 

potentially make compliance easier for 

owners and operators. Because both 

monitoring requirements assure 

compliance of the enclosed combustors, 

and having the same requirement would 

ease implementation burden, we 

propose to amend 40 CFR 60.5413(e)(3) 

to require monthly 15 minute-period 

observation using EPA Method 22 Test, 

as suggested by the petitioner. 

B. Other Improvements 

Following publication of the 2012 

NSPS and the 2013 storage vessel 

amendments, we subsequently 

determined, following review of 

reconsideration petitions and 

discussions with affected parties, that 

the final rule warrants correction and 

clarification in certain areas. Each of 

these areas is discussed below. 

1. Initial Compliance Requirements for 

Bypass Devices 

Initial compliance requirements in 

§ 60.5411(c)(3)(i)(A) for a bypass device 

that could divert an emission stream 

away from a control device were 

previously amended to allow for 

initiating a notification via remote alarm 

to the nearest field office indicating that 

the bypass device was activated. 

However, the previous amendments did 

not address parallel requirements for 

continuous compliance in § 60.5416. In 

order to maintain consistency with the 

previously amended § 60.5411, we are 

proposing to amend § 60.5416(c)(3)(i) to 

include notification via remote alarm to 

the nearest field office. We are 

proposing to require both an alarm at 

the bypass device and a remote alarm. 

This is important in this source category 

due to the great number of unmanned 

sites, especially well sites. Previously, 

the only option was an alarm at the 

device location. We believe this change 

will ensure that personnel will be 

alerted to a potential uncontrolled 

emissions release whether they are in 

the vicinity of the bypass device when 

it is activated or at a remote monitoring 

location. Finally, we are proposing 

similar amendments to parallel 

requirements at § 60.5411(a)(3)(i)(A) for 

closed vent systems used with 

reciprocating compressors and 

centrifugal compressor wet seal 

degassing systems. 

2. Recordkeeping Requirements 

Petitioners noted that the 

recordkeeping requirements of 

§ 60.5420(c) do not include the repair 

logs for control devices failing a visible 

emissions test required by § 60.5413(c). 

We agree that these recordkeeping 

requirements should be listed and are 

proposing to add them at 

§ 60.5420(c)(14). 

3. Due Date for Initial Annual Report 

Petitioners pointed out that the 

preamble to the 2013 final rule stated 

that the initial annual report is due on 

January 15, 2014; however, § 60.5420(b) 

states that initial annual report is due 90 

days after the end of the initial 

compliance period. The petitioners 

correctly contend that this equates to a 

due date of January 13, 2014. Although 

we inadvertently stated a date three 

months after the end of the initial 

compliance period (rather than 90 days 

after) in the preamble, we are not 

proposing to amend the rule at this 

time. Rather, we will consider any 

initial annual report submitted no later 

than January 15, 2014 to be a timely 

submission. All subsequent annual 

reports must be submitted by the correct 

date of January 13 of the year. 

4. Flare Design and Operation Standards 

The petitioners requested that the 

EPA clarify the regulatory compliance 

requirements for storage vessel affected 

facilities with respect to flares. 

Currently subpart OOOO contains 

conflicting references to the NSPS 

general provisions that obscures the 

EPA’s intent to require compliance with 

the requirements for the design and 

operation of flares under § 60.18 of the 

General Provisions. To clarify EPA’s 

intent, the EPA is proposing to remove 

the provision of Table 3 in subpart 

OOOO that exempts flares from 

complying with the requirements for the 

design and operation of flares under 40 

CFR 60.18 of the General Provisions. By 

removing the exemption from the 

General Provisions from subpart OOOO, 

this clarifies that flares used to comply 

with subpart OOOO are subject to the 

design and operation requirements in 

the general provisions. 

It has recently come to EPA’s 

attention that that there may be affected 

facilities which use pressure assistedflares (e.g., sonic flares) to control 

emissions during periods of startup, 

shutdown, emergency and/or 

maintenance activities. While 

compliance with the NSPS emission 

limits can be achieved using such flares, 

when designed and operated properly, it 

is EPA’s understanding that pressureassisted flares cannot meet the 

maximum exit velocity of 400 feet per 

second as required by 40 CFR 60.18(b). 

Pressure-assisted flares are designed to 

operate with a high velocities up to 

sonic velocity conditions (e.g., 700 to 

1,400 feet per second) for common 

hydrocarbon gases. 

In order to evaluate the use of 

pressure-assisted flares by the oil and 

natural gas industry and determine 

whether to develop operating 

parameters for pressure-assisted flares 

for purposes of subparts OOOO (and 

subpart OOOOa should it be finalized), 

the EPA is soliciting comment on where 

in the source category, under what 

conditions (e.g., maintenance), and how 

frequently pressure-assisted flares are 

used to control emissions from an 

affected facility, as defined within this 

subpart. In addition, we request 

information on: (1) The importance of, 

and assessment of flame stability; (2) the 

importance of, and ranges of the heat 

content of flared gas; (3) the importance 

and ranges of gas pressure and flare tip 

pressure; (4) the importance of and 

examples of appropriate flare head 

design; (5) a cross-country review of 

waste gas composition; (6) and 

appropriate methodology to measure the 

resultant flare destruction efficiency. 

The EPA also requests comment on the 

appropriate parameters to monitor to 

ensure continuous compliance. This 

information is critical for the potential 

development of operating parameters for 

pressure-assisted flares given the 

limited to no information currently 

available for this type of flare in the oil 

and natural gas industry. 

5. Exemption to Notification 

Requirement for Reconstruction 

The petitioners asked for the EPA to 

consider whether a single remaining 

notification of reconstruction required 

under § 60.15(d) of the General 

Provisions was necessary, given that the 

EPA had already provided an exemption 

to parallel requirements for 

construction, startup, and modification. 

The EPA agrees with the petitioner that 

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118The proposed definition does not include B 

values listed in subpart VV for other subparts 

because those values are irrelevant to subpart 

OOOO. 

119 Comments of the Gas Processors Association 

Regarding the Proposed Rule, Oil and Natural Gas 

Sector: New Source Performance Standards and 

National Emission Standards for Hazardous Air 

Continued 

the notification of reconstruction 

requirements under § 60.15(d) is 

unnecessary. The EPA considers it 

unnecessary because subpart OOOO 

specifies notification of reconstruction 

for affected unit pneumatic controllers, 

centrifugal compressors, and storage 

vessels under § 60.5410 and § 60.5420 in 

lieu of the general notification 

requirement in § 60.15(d). The EPA, 

therefore, proposes to add in Table 3 

that § 60.15(d) does not apply to affected 

facility pneumatic controllers, 

centrifugal compressors, and storage 

vessels subject to subpart OOOO. 

6. Disposal of Carbon From Control 

Devices 

We are re-proposing the provisions for 

management of waste from spent carbon 

canisters that were finalized in 

§ 60.5412(c)(2) of the 2012 NSPS to 

allow for comment. Petitioners assert 

that the requirements for RCRA-level 

management of waste from spent carbon 

canisters are unnecessary and overly 

burdensome. Further, they assert that 

those provisions were not in the 

proposal which excluded them from 

review and comment. We do not agree 

that these provisions are overly 

burdensome because RCRA hazardous 

waste units are not the only options 

made available to manage the spent 

carbon. In the scenario where the carbon 

is to be burned, the EPA sought a means 

to assure that sufficient precaution was 

taken to assure complete destruction of 

the carbon and adsorbed compounds. 

These same requirements apply to spent 

carbon from units subject to NESHAP 

subpart HH in oil and natural gas 

production, further supporting our 

decision to seek consistent and 

appropriate levels of control for burning 

spent carbon from an adsorption system. 

We are re-proposing the provisions here 

to allow for review and comment. 

Petitioners may submit alternatives that 

would allow for consistent treatment of 

spent carbon from the oil and natural 

gas sector, and that assure destruction of 

the compounds adsorbed in carbon 

adsorption control units. 

7. Definition of Capital Expenditure 

Petitioners requested that the EPA 

clarify the definition of ‘‘capital 

expenditure’’ in subpart OOOO. The 

term is used in section § 60.5365(f), 

which describes the applicability of the 

equipment leaks provisions for onshore 

natural gas processing plants. 

Specifically, 40 CFR 60.5365(f)(1) states 

that ‘‘addition or replacement of 

equipment for the purpose of process 

improvement that is accomplished 

without a capital expenditure shall not 

by itself be considered a modification 

under this subpart.’’ Subpart OOOO 

does not define ‘‘capital expenditure’’ 

but states in 40 CFR 60.5430 (definition 

section) that ‘‘all terms not defined 

herein shall have the meaning given 

them in the Act, in subpart A or subpart 

VVa of part 60.’’ The term ‘‘capital 

expenditure’’ is defined in the General 

Provisions subpart A, as well as in 

subpart VVa. However, this definition in 

subpart VVa is currently stayed. The 

EPA agrees with the commenter that 

this capital expenditure approach 

applies to onshore natural gas 

processing plants that are subject to 

subpart OOOO. The EPA had previously 

adopted this method for determining 

modification in subpart KKK. In fact, 

the capital expenditure provision in 

subpart OOOO, 40 CFR 60.5365(f)(1) 

was carried over from subpart KKK 40 

CFR 60.630(c). Subpart KKK does not 

specifically define ‘‘capital 

expenditure;’’ it states in 40 CFR 60.631 

that ‘‘as used in this subpart, all terms 

not defined herein shall have the 

meaning given them in the Act, in 

subpart A or subpart VV of part 60. . .’’ 

This means that the definition of capital 

expenditure in subpart KKK is the 

current definition in VV. 

In conducting the EPA’s 8-year review 

of subpart KKK, the EPA promulgated 

subpart OOOO, which includes certain 

revisions to subpart KKK. The EPA 

revised the existing NSPS requirements 

for LDAR to reflect the procedures and 

leak definition established by 40 CFR 

part 60, subpart VVa (77 FR 49498). 

Specifically, the revision to subpart 

KKK, which is codified in subpart 

OOOO, includes a lower leak 

definitions for valves and pumps and 

requires monitoring of connectors. 

The EPA’s 8-year review and revision 

of subpart KKK did not include any 

change to the capital expenditure 

provision as it applies to oil and natural 

gas processing plants. This means that 

the technique used to determine 

whether there is a modification based 

on capital expenditure under OOOO 

remains the same technique as in 

subpart KKK (i.e., based on the 

definition of ‘‘capital expenditure’’ in 

subpart VV). 

However, as the petitioner correctly 

noted, the year that is the basis for 

calculating Y (the percent of 

replacement cost) is designed to reflect 

the year of the proposed standards for 

the relevant subpart at issue; as such, 

the definition of ‘‘capital expenditure’’ 

in subpart VV does not reflect the year 

subpart OOOO was proposed (i.e., 2011) 

and is therefore inaccurate for 

application to subpart OOOO as is. To 

address this issue, the EPA is proposing 

to provide in subpart OOOO a definition 

for ‘‘capital expenditure’’ that 

essentially mirrors 118 the definition in 

subpart VV but with the year revised to 

reflect the year subpart OOOO was 

proposed (i.e., 2011). 

The EPA disagrees with the petitioner 

that the appropriate applicable basic 

annual asset guideline repair allowance, 

designated ‘‘B’’ in the formula, is 12.5, 

which is the B value for Subpart VVa. 

Since ‘‘capital expenditure’’ method 

was not among the updates the EPA 

made in its review of the subpart KKK 

(and subpart OOOO is the updated 

version of KKK), the allowance in KKK 

(i.e., 4.5 according to subpart VV) 

remains applicable to onshore gas 

affected facilities. Further, B values are 

based on the annual asset guideline 

repair allowance specified in IRS 

Revenue Procedure 83–35. The 

specified allowance value is 4.5 for 

exploration and production of 

petroleum and natural gas deposits. 

Also, as evident from the ‘‘capital 

expenditure’’ definitions in both 

subparts VV and VVa, the B values are 

subpart-specific and therefore the EPA 

has promulgated specific B values for 

different subparts. Whereas subpart VV 

includes a specific B value for natural 

gas processing plants covered by 

subpart KKK (natural gas processing 

plants), there is no such value in 

subpart VVa referencing subpart KKK. 

For the reasons stated above, the EPA 

clarifies that the B value for purposes of 

subpart OOOO is 4.5; it is not 12.5, as 

the petitioner suggests. 

In sum, to provide clarity the EPA is 

proposing to specifically define the term 

‘‘capital expenditure’’ in subpart OOOO. 

In this proposed definition, EPA is 

updating the formula to reflect the 

calendar year that subpart OOOO was 

proposed, as well as specifying that the 

B value for subpart OOOO is 4.5. These 

updates are necessary for proper 

calculation of capital expenditure under 

subpart OOOO. 

8. Initial Compliance Clarification 

An issue was raised in an 

administrative petition that EPA did not 

adequately respond to a comment on the 

2011 proposed NSPS regarding 

compliance period for the LDAR 

requirements for On-Shore Natural Gas 

Processing Plants. The comment at 

issue 119 requested that EPA include in 

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56648 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

Pollutants Reviews, 76 FR 52738 (Aug. 23, 2011). 

Pp. 3, 32–33. 

120Comments of the Gas Processors Association 

Regarding the Proposed Rule, Oil and Natural Gas 

Sector: New Source Performance Standards and 

National Emission Standards for Hazardous Air 

Pollutants Reviews, 76 FR 52738 (Aug. 23, 2011). 

Pp. 33. 

121Letter from Obie O’Brien, Vice President— 

Government Affairs/Corporate Outreach, Apache 

Corporation, to EPA Docket, Docket ID Number 

EPA–HQ–OAR–2010–4755, April 20, 2015. Similar 

letters from Rockwater Energy Solutions (EPA–HQ– 

OAR–2010–4756) and Permian Basin Petroleum 

Association (EPA–HQ–OAR–2010–4757). 

122EPA, Renewable Fuel Standards (RFS), http:// 

www.epa.gov/OTAQ/fuels/renewablefuels/. 

123MassDEP, Third-Party Underground Storage 

Tank (UST) Inspection Program, http://

subpart OOOO a provision similar to 

subpart KKK, 40 CFR 60.632(a), which 

allows a compliance period of up to 180 

days after initial start-up. The 

commenter was ‘‘concerned that a 

modification at an existing facility or a 

subpart KKK regulated facility could 

subject the facility to Subpart OOOO 

LDAR requirements without adequate 

time to bring the whole process unit 

into compliance with the new 

regulation.’’ 120

We clarify that subpart OOOO, as 

promulgated in 2012, already includes a 

provision similar to subpart KKK, 

§ 60.632(a), as requested in the 

comment. Specifically, § 60.5400(a) 

requires compliance with 40 CFR 

60.482–1a(a), which provides that 

‘‘[e]ach owner or operator subject to the 

provisions of this subpart shall 

demonstrate compliance . . . within 

180 days of initial startup.’’ This 

provision applies to all new, modified, 

and reconstructed sources. With respect 

to modification, which was of specific 

concern to the commenter, a change to 

a unit sufficient to trigger a modification 

and thus application of the subpart 

OOOO LDAR requirements for on-shore 

natural gas processing plants would be 

followed by startup, which would mark 

the beginning of the 180 day compliance 

period provided in 40 CFR 60.482–1a(a) 

(incorporated by reference in subpart 

OOOO § 60.5400(a)). 

9. Tanks Associated With Water 

Recycling Operations 

In many cases, flowback water from 

well completions and water produced 

during ongoing production is collected, 

treated and recycled to reduce the 

volume of potable water withdrawn 

from wells or other sources. Large, nonearthen tanks are used to collect the 

water for recycling following separation 

to remove crude oil, condensate, 

intermediate hydrocarbon liquids and 

natural gas. These collection tanks used 

for water recycling are very large vessels 

having capacities of 25,000 barrels or 

more, with annual throughput of 

millions of barrels of water. In contrast, 

industry standard storage vessels 

commonly found in well site tank 

batteries and used to contain crude oil, 

condensate, intermediate hydrocarbon 

liquids and produced water typically 

have capacities in the 500 barrel range. 

In the 2012 NSPS, we had envisioned 

the storage vessel provisions as 

regulating the vessels in well site tank 

batteries and not these large tanks 

primarily used for water recycling. It 

was never our intent to cover these large 

water recycling tanks. It recently came 

to our attention that these water 

recycling tanks could be inadvertently 

subject to the NSPS due to the 

extremely low VOC content combined 

with the millions of barrels of 

throughput each year, which could 

result in a potential to emit VOC 

exceeding the NSPS storage vessel 

threshold of 6 tpy.121 The EPA 

encourages efforts on the part of owners 

and operators to maximize recycling of 

flowback and produced water. We are 

concerned that the inadvertent coverage 

of these tanks under the NSPS could 

discourage recycling. It is our 

understanding that, due to the size and 

throughput of these tanks, combined 

with the trace amounts of VOC 

emissions that are difficult to control, 

that operators may choose to 

discontinue recycling to avoid 

noncompliance with the NSPS. 

As a result, we are considering 

changes in the final rule to remove tanks 

that are used for water recycling from 

potential NSPS applicability. We solicit 

comment on approaches that could be 

taken to amend the definition of 

‘‘storage vessel’’ or other changes to the 

NSPS that would resolve this issue 

without excluding storage vessels 

appropriately covered by the NSPS. In 

addition, we solicit comment on 

location, capacity or other criteria that 

would be appropriate for such purpose. 

X. Next Generation Compliance and 

Rule Effectiveness 

A. Independent Third-Party Verification 

The EPA is taking comment on 

establishing a third-party verification 

program as discussed below. Thirdparty verification is when an 

independent third-party verifies to a 

regulator that a regulated entity is 

meeting one or more of its compliance 

obligations. The regulator retains the 

ultimate responsibility to monitor and 

enforce compliance but, as a practical 

matter, gives significant weight to the 

third-party verification provided in the 

context of a regulatory program with 

effective standards, procedures, 

transparency and oversight. While 

requiring regulated entities to monitor 

and report should improve compliance 

by establishing minimum requirements 

for a regulated entity’s employees and 

managers, well-structured third-party 

compliance monitoring and reporting 

may further improve compliance. 

The third-party verification program 

would be designed to ensure that the 

third-party reviewers are competent, 

independent, and accredited, apply 

clear and objective criteria to their 

design plan reviews, and report 

appropriate information to regulators. 

Additionally, there would need to be 

mechanisms to ensure regular and 

effective oversight of third-party 

reviewers by the EPA and/or states 

which may include public disclosure of 

information concerning the third parties 

and their performance and 

determinations, such as licensing or 

registration. 

The EPA is considering a broad range 

of possible design features for such a 

program under the following two 

scenarios: (A) Third-Party Verification 

of Closed Vent System Design and (B) 

Third-Party Verification of IR Camera 

Fugitives Monitoring Program. These 

include those discussed or included in 

the following articles, rules, and 

programs: 

(1) Lesley K. McAllister, Regulation by 

Third-Party Verification, 53 B.C. L. REV. 1, 

22–23 (2012); 

(2) Lesley K. McAllister, THIRD–PARTY 

PROGRAMS FINAL REPORT (2012) 

(prepared for the Administrative Conference 

of the United States), available at http://

www.acus.gov/report/third-party-programsfinal-report; 

(3) Esther Duflo et al., Truth-Telling By 

Third-Party Auditors and the Response of 

Polluting Firms: Experimental Evidence 

From India, 128 Q. J. OF ECON. 4 at 1499– 

1545 (2013); 

(4) EPA CAA Renewable Fuel Standard 

(RFS) program: The RFS regulations include 

requirements for obligated parties to, in 

relevant part, submit independent third-party 

engineering reviews to the EPA before 

generating Renewable Identification Numbers 

(RINs).122

(5) Massachusetts Underground Storage 

Tank (UST) third-party inspection program: 

The owners/operators of most underground 

storage tanks in Massachusetts are required 

to have their USTs inspected by third-party 

inspectors every three years. While the thirdparty inspectors are hired directly by the tank 

owners and operators, they report to the 

Massachusetts Department of Environmental 

Protection (MassDEP). The third parties 

conduct and document detailed inspections 

of USTs and piping systems, review facility 

recordkeeping to ensure it meets UST 

program requirements, and submit reports on 

their findings electronically to MassDEP.123

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www.mass.gov/eea/agencies/massdep/toxics/ust/

third-party-ust-inspection-program.html. 

124http://www.mass.gov/eea/agencies/massdep/

cleanup/licensed-site-professionals.html. 

(6) Massachusetts licensed Hazardous 

Waste Site Cleanup Professional program: 

Private parties who are financially 

responsible under Massachusetts law for 

assessing and cleaning up confirmed and 

suspected hazardous waste sites must retain 

a licensed Hazardous Waste Site Cleanup 

Professional (commonly called a ‘‘Licensed 

Site Professional’’ or simply an ‘‘LSP’’) to 

oversee the assessment and cleanup work.124

We have identified one potential area 

for third-party verification under this 

rule. 

Professional Engineer Certification of 

Closed Vent System and Control Device 

Design and Installation 

When produced liquids from oil and 

natural gas operations are routed from 

the separator to the condensate storage 

tank, a drop in pressure from operating 

pressure to atmospheric pressure 

occurs. This results in ‘‘flash emissions’’ 

as gases are liberated from the 

condensate stream due to the change in 

pressure. The magnitude of flash 

emissions can dwarf normal working 

and breathing losses of a storage tank. If 

the control system (closed vent system 

and control device, including pressure 

relief devices and thief hatches on 

storage vessels) cannot accommodate 

the peak instantaneous flow rate of flash 

emissions, working losses, breathing 

losses and any other additional vapors, 

this may cause pressure relief devices 

and thief hatches to ‘‘pop’’ and they 

may not properly reseat, resulting in 

immediate and potentially continuing 

excess emissions. Through our energy 

extraction enforcement initiative, we 

have seen this to be the case, due in 

large part to undersized control systems 

that may have been inadequately 

designed to accommodate only working 

and breathing losses of a storage tank. 

We have worked in conjunction with 

states, including Colorado, in 

conducting inspection campaigns 

associated with storage vessels. In two 

inspection campaigns, in two different 

regions, we recorded venting from thief 

hatches or other parts of the control 

system at over 60 percent of the tank 

batteries inspected. Another inspection 

campaign resulted in a much higher 

leak rate, with 23 of 25 tank batteries 

experiencing fugitive emissions. 

One potential remedy for the 

inadequate design and sizing of the 

closed vent system would be to require 

an independent third-party 

(independent of the well site owner/

operator and control device 

manufacturer), such as a professional 

engineer, to review the design and 

verify that it is designed to 

accommodate all emissions scenarios, 

including flash emissions episodes. 

Another element of the professional 

engineer verification could be that the 

professional engineer verifies that the 

control system is installed correctly and 

that the design criteria is properly 

utilized in the field. 

Another approach to detecting 

overpressure in a closed vent system 

would be to require a continuous 

pressure monitoring device or system, 

located on the thief hatches, pressure 

relief devices and other bypasses from 

the closed vent system. Through our 

inspections, we have seen thief hatch 

pressure settings below the pressure 

settings of the storage tanks to which 

they are affixed. This results in 

emissions escaping from the thief hatch 

and not making it to the control device. 

The EPA requests comment on these 

approaches. Specifically, we request 

comment as to whether we should 

specify criteria by which the PE verifies 

that the closed vent system is designed 

to accommodate all streams routed to 

the facility’s control system, or whether 

we might cite to current engineering 

codes that produce the same outcome. 

We also request comment as to what 

types of cost-effective pressure 

monitoring systems can be utilized to 

ensure that the pressure settings on 

relief devices is not lower than the 

operating pressure in the closed vent to 

the control device and what types of 

reporting from such systems should be 

required, such as through a supervisory 

control and data acquisition (SCADA) 

system. 

B. Fugitives Emissions Verification 

As discussed in sections VII.G and 

VIII.G, the EPA is proposing the use of 

OGI as a low cost way to find leaks. 

While we believe we are proposing a 

robust method to ensure that OGI 

surveys are done correctly, we have 

ample experience from our enhanced 

leak detection and repair (LDAR) efforts 

under our Air Toxics Enforcement 

Initiative, that even when methods are 

in place, routine monitoring for 

fugitives may not be as effective in 

practice as in design. Similar to the 

audits included as part of consent 

decrees under the Initiative (See U.S. et. 

Al. v. BP Products North America Inc.), 

we are soliciting comment on an audit 

program of the collection of fugitive 

emissions components at well sites and 

compressor stations. 

For this rule, we are anticipating a 

structure in which the facilities 

themselves are responsible for 

determining and documenting that their 

auditors are competent and independent 

pursuant to specified criteria. The 

Agency seeks comment as to whether 

this approach is appropriate for the type 

of auditing we describe below, or 

whether an alternative approach, such 

as requiring auditors to have 

accreditation from a recognized auditing 

body or EPA, or other potentially 

relevant and applicable consensus 

standards and protocols (e.g., American 

National Standards Institute (ANSI), 

ASTM International (ASTM), European 

Committee for Standardization (CEM), 

International Organization for 

Standardization (ISO), and National 

Institute of Standards and Technology 

(NIST) standards), would be preferable. 

In order to ensure the competence and 

independence of the auditor, certain 

criteria should be met. Competence of 

the auditor can include safeguards such 

as licensing as a Professional Engineer 

(PE), knowledge with the requirements 

of rule and the operation of monitoring 

equipment (e.g., optical gas imaging), 

experience with the facility type and 

processes being audited and the 

applicable recognized and generally 

accepted good engineering practices, 

and training or certification in auditing 

techniques. 

Independence of the auditor can be 

ensured by provisions and safeguards in 

the contracts and relationships between 

the owner and operator of the affected 

facility with auditors. These can 

include: The auditor and its personnel 

must not have conducted past research, 

development, design, construction 

services, or consulting for the owner or 

operator within the last 3 years; the 

auditor and its personnel must not 

provide other business or consulting 

services to the owner or operator, 

including advice or assistance to 

implement the findings or 

recommendations in the Audit report, 

for a period of at least 3 years following 

the Auditor’s submittal of the final 

Audit report; and all auditor personnel 

who conduct or otherwise participate in 

the audit must sign and date a conflict 

of interest statement attesting the 

personnel have met and followed the 

auditors’ policies and procedures for 

competence, impartiality, judgment, and 

operational integrity when auditing 

under this section; and must receive no 

financial benefit from the outcome of 

the Audit, apart from payment for the 

auditing services themselves. In 

addition, owners or operators cannot 

provide future employment to any of the 

auditor’s personnel who conducted or 

otherwise participated in the Audit for 

a period of at least 3 years following the 

Auditor’s submittal of its final Audit 

report and must be empowered to direct 

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their auditors to produce copies of any 

of the audit-related reports and records 

specified in those sections. Both the 

owners and operators and their auditors 

should sign supporting certifications 

statements. To further minimize audit 

bias, an audit structure might require 

that audit report drafts and final audit 

reports be submitted to EPA at the same 

time, or before, they are provided to the 

owners and operators. Furthermore, the 

audits conducted by the auditors under 

this rule should not be claimed as a 

confidential attorney work products 

even if the auditors are themselves, or 

managed by or report to, attorneys. 

There may be other options, in 

addition to the approaches above, that 

may increase owner or operator 

flexibility, but these options also 

present risks of introducing bias into the 

program, resulting in less robust and 

effective audit reports. EPA invites 

comment on the structure above as well 

as alternative auditor/auditing 

approaches with less rigorous 

independence criteria. For example, 

EPA could, in the final rule, allow for 

audits to be performed by auditors with 

some potential conflicts of interest (e.g., 

employees of parent company, affiliates, 

vendors/contractors that participated in 

developing source master plan(s) and/or 

site-specific plan(s), etc.) and/or allow a 

person at the facility itself who is a 

registered PE or who has the requisite 

training in conducting optical gas 

imaging monitoring to conduct the 

audit. If such approaches are adopted in 

the final rule, the Agency could seek to 

place appropriate restrictions on 

auditors and auditing with less than full 

independence from their client facilities 

in an effort to increase confidence that 

the auditors will act accurately when 

performing their activities under the 

rule. Such provisions could include 

ones addressed to ensuring that auditor 

personnel who assess a facility’s 

compliance with the fugitives 

monitoring requirements do not receive 

any financial benefit from the outcome 

of their auditing decisions, apart from 

their basic salaries or remuneration for 

having conducted the audits. 

Additional examples of the types of 

restrictions that could be placed on such 

self-auditing to potentially improve 

auditor impartiality and auditing 

outcomes appear in the U.S. and CARB 

v. Hyundai Motor Company, et al. 

Consent Decree (CD). Until the CDs 

corrective measures are fully 

implemented, the defendants must audit 

their fleets to ensure that vehicles sold 

to the public conform to the vehicles’ 

certification. The CD provides that the 

audit team will be in the United States, 

will be independent from the group that 

performed the original certification 

work, and must perform their audits 

without access to or knowledge of the 

defendants’ original certification test 

data which the CD-required audits are 

intended to backcheck. EPA seeks 

comment as to whether similar 

restrictions could be effective for any 

potential enhanced self-auditing 

conducted under the rule. 

Finally, EPA seeks comment on 

whether, and to what extent, the public 

should have access to the compliance 

reports, portions or summaries of them 

and/or any other information or 

documentation produced pursuant to 

the auditing provisions. EPA is also 

considering the approach it should take 

to balance public access to the audits 

and the need to protect Confidential 

Business Information (CBI). To balance 

these potentially competing interests, 

EPA is reviewing a variety of 

approaches that may include limiting 

public access to portions of the audits 

and/or posting public audit grades or 

scores to inform the public of the 

auditing outcomes without 

compromising confidential or sensitive 

information. EPA seeks comment on 

these transparency and public access to 

information issues in the context of the 

proposed auditing provisions. 

A suggested structure which 

incorporates concepts from the 

discussion above, and relevant to an 

audit of the fugitives monitoring 

program of the collection of fugitive 

emissions components at well sites and 

compressor stations could include the 

following structure: 

Within the first year of applicability 

to the rule, an OGI trained auditor, 

experienced with the facility type and 

processes being audited and the 

applicable recognized and generally 

accepted good engineering practices, 

and trained or certified in auditing 

techniques, and who has not: 

a. served as a fugitive emissions 

monitoring technician at the source, 

b. conducted past research, development, 

design, construction services, or consulting 

for the owner or operator within the last 3 

years or; 

c. provided other business or consulting 

services to the owner or operator, including 

advice or assistance to implement the 

findings or recommendations in the Audit 

report, for a period of at least 3 years 

following the Auditor’s submittal of the final 

Audit report; 

shall: 

a. Verify that the source has established a 

master and site specific monitoring plan; 

b. Verify that the master and site specific 

monitoring plan includes the elements 

described in the rule; 

c. Verify that the fugitive components were 

monitored in accordance with the master and 

site specific monitoring plan and at the 

appropriate frequency under the plan(s) and 

the rule; 

d. Verify that proper documentation and 

sign offs have been recorded for all fugitive 

components placed on the delay of repair 

list; 

e. Ensure that repairs have been performed 

in the required periods under the rule; 

f. Review monitoring data for feasibility 

(e.g., do the survey results reflect a feasible 

timeframe in which to conduct the 

monitoring survey) and unusual trends; 

g. Verify that proper calibration records 

and monitoring instrument maintenance 

information are maintained; 

h. Verify that other fugitives emissions 

monitoring records are maintained as 

required; and 

i. Observe in the field each technician who 

is conducting fugitive emissions monitoring 

to ensure that monitoring is being conducted 

as described in the rule and the master and 

site specific plan; 

j. Submit a report to the EPA and the 

facility outlining the findings of the audit 

with deficiencies and corrective actions 

provided. 

k. Sign a certification statement that the 

report was prepared by the auditor 

conducting the audit (or under his/her 

direction or supervision), that the report is 

true, accurate, and complete, that the Audit 

was prepared pursuant to, and meets the 

requirements of, 40 CFR part 60 subpart 

OOOOa, and any other applicable auditing, 

competency, and independence/impartiality/ 

conflict of interest standards and protocols. 

Upon the receipt of the auditor’s 

report, the source should correct any 

deficiencies detected or observed within 

four months. The source would be 

required to maintain a record that: (i) 

Records the auditor’s report; and (ii) 

describes the nature and timing of any 

corrective actions taken. The source 

would be required to submit in their 

periodic compliance report, a summary 

of the findings of the auditor’s report 

and a description and timing of any 

corrective actions taken. EPA envisions 

that the audit would be repeated with 

some frequency and requests comment 

on the appropriate frequency, and any 

actions, trends or compliance triggers 

which might require or allow deviation 

from the frequency. 

C. Third-Party Information Reporting 

Third-party information reporting 

occurs when a third-party reports 

information on a regulated source’s 

performance, directly to the regulator. 

To promote improved compliance, 

third-party information reporting 

reduces information asymmetries 

between what the regulated entities 

know about themselves and the 

regulators’ knowledge about the entities. 

An example of third-party 

information reporting involves federal 

income tax law where certain income 

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125See www.epa.gov/oilandgas. 

126EPA, Policy Statement on E-Reporting in EPA 

Regulations (September 30, 2013). 

must be independently reported to the 

Internal Revenue Service (IRS) by 

payers of the income. Because the 

information is required to be identical to 

that reported by taxpayers, the 

government can compare the dual 

disclosures for consistency. Taxpayers 

know this and are deterred from failing 

to report or underreporting. 

We outlined a potential third-party 

information reporting structure for oil 

and natural gas in our 2013 proposed 

amendments. We continue to believe 

that application of such a reporting 

structure is a natural outgrowth for 

implementation of the manufacturer 

performance testing requirements under 

subpart OOOO and subparts HH/HHH. 

As previously discussed in the 2013 

proposal, an owner or operator that 

purchases a specific model of control 

device that the manufacturer has 

demonstrated achieves the combustion 

control device performance 

requirements in NSPS subpart OOOO (a 

‘‘listed device’’) is exempt from 

conducting their own performance test 

and submitting performance test results. 

To provide further incentive to use such 

a listed device, the EPA can ‘‘level the 

playing field’’ by ensuring that 

exemption claims are valid. Using the 

framework of third-party information 

reporting, the owner or operator would 

demonstrate initial compliance by 

providing proof of purchase of the listed 

device, reporting certain information, 

such as device model, serial number, 

geospatial coordinates and date of 

installation in their annual report 

following the end of the compliance 

period during which the device was 

installed. In the final rule, the EPA 

could conceivably supplement the 

owner/operator reporting requirement 

with a manufacturer reporting 

requirement providing the names of 

entities that had purchased the listed 

device. The manufacturer report to the 

EPA could be very simple, such as a 

‘‘notice and go’’ or ‘‘post card’’ type 

report. This could allow a simple cross 

check of the owner’s or operator’s report 

with the manufacturer’s sales 

confirmation, making compliance 

checks easy and provide assurance to 

the Agency that the source has in fact 

purchased and installed a manufacturer 

performance tested device, improving 

compliance with the rule. 

As noted above, we have currently 

evaluated and posted 15 enclosed 

combustor models, allaying concerns 

that it would take ‘‘years of work’’ to 

avoid compliance complications with 

the process. The EPA continues to 

encourage the option to use listed 

devices and believe that operators have 

an incentive to do so, in lessened initial 

and on-going compliance demonstration 

costs. Third-party information reporting 

could lessen any lingering concerns 

with implementation and potential 

compliance complications. However, we 

understand the issues for this sector, 

with making the ‘‘postcard’’ model work 

as we envisioned. One of the issues is 

related to the granularity of the 

reporting by the manufacturer as 

compared to the reporting by the source 

to the EPA or delegated authority. For 

example, the manufacturer may only 

know that they sold 500 units of a 

particular control device, but may not 

know where it is actually installed. Lack 

of a unique ‘‘user ID’’ being reported by 

both sides can limit the utility of the 

postcard model in this instance. We 

solicit comment on potential third-party 

approaches such as the ‘‘post card’’ 

reporting described above that could be 

implemented to streamline and enhance 

compliance. 

As stated above, a primary concern is 

that an owner or operator would install 

a control device, and not conduct a 

performance test, claiming that they 

installed a device listed on the Oil and 

Gas page. We believe that we can build 

on the success of GIS imbedded digital 

photos for green completions (‘‘REC 

PIX’’), already in the rule, by developing 

a similar requirement for installed 

manufacturer tested control devices. 

Enhancing the records and reports by 

requiring specifics of the control device 

(make, model and serial number) and 

requiring the digital picture, will allow 

us to match a particular control device 

at a specific location with control device 

models listed on the Oil and Gas 

page.125 Having this information 

electronically reported to CEDRI will 

further enhance our ability to evaluate 

compliance with the rule. 

While we are soliciting comment on 

third-party reporting by combustor 

vendors directly to the EPA, we propose 

to require that owners or operators 

include information regarding purchase 

of a pre-tested combustor model in their 

Notice of Compliance Status as part of 

the first annual report following the 

compliance period in which the 

combustor commences operation. The 

information would include (1) make, 

model and serial number of the 

purchased device; (2) date of purchase; 

(3) inlet gas flow rate; (4) latitude and 

longitude of the emission source being 

controlled by the combustor; (5) digital 

GIS and date stamp-imbedded photo of 

the combustor once it is installed; and 

(6) certification of continuous 

compliance. The owner or operator 

would be required to submit 

information to CEDRI in lieu of a field 

performance test. 

D. Electronic Reporting and 

Transparency 

1. Include Robust Federal Reporting 

With Easy Access to Information 

We have the opportunity to expand 

transparency by making the information 

we have today more accessible, and 

making new information, obtained from 

advanced emissions monitoring and 

electronic reporting, publicly available. 

This approach will empower 

communities to play an active role in 

compliance oversight and improve the 

performance of both the government 

and regulated entities. On September 

30, 2013, the EPA established that the 

default assumption for all new EPA 

rules is to use e-reporting, absent a 

compelling reason to use paper 

reporting.126 Current reporting 

requirements in most rules and permits 

direct regulated entities to submit paper 

reports and forms to the EPA, states, and 

tribes. Under electronic, or e-reporting, 

paper reporting is replaced by 

standardized, Internet-based, electronic 

reporting to a central repository using 

specifically developed forms, templates 

and tools. E-reporting is not simply a 

regulated entity emailing an electronic 

copy of a document (e.g., a PDF file) to 

the government, but also a means to 

make collected information easily 

accessible to the public and other 

stakeholders. 

On March 20, 2015, the EPA proposed 

the ‘‘Electronic Reporting and 

Recordkeeping Requirements for New 

Source Performance Standards’’ (80 FR 

15099, March 20, 2015). If adopted, the 

rule would revise the part 60 General 

Provisions and various NSPS subparts 

in part 60 of title 40 of the Code of 

Federal Regulations (CFR) to require 

affected facilities to submit specified air 

emissions data reports to the EPA 

electronically and to allow affected 

facilities to maintain electronic records 

of these reports. This proposed rule 

focuses on the submission of electronic 

reports to the EPA that provide direct 

measures of air emissions data such as 

summary reports, excess emission 

reports, performance test reports and 

performance evaluation reports. 

Subpart OOOO is one of the rules 

potentially affected by this rulemaking. 

When promulgated, § 60.5420(c)(9) 

would be amended to require the 

submittal of reports to the EPA via the 

CEDRI. (CEDRI can be accessed through 

the EPA’s CDX (https://cdx.epa.gov/).) 

The owner or operator would be 

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56652 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

127Lori S. Bennear and Sheila M. Olmstead, 

Impacts of the ‘‘Right to Know’’: Information 

Disclosure and the Violation of Drinking Water 

Standards, 56 J. ENVT’L ECON. & MGMT. 117 

(2008) (finding that when larger utilities were 

required to mail annual Consumer Confidence 

Reports on water-supplier compliance pursuant to 

the 1998 Safe Drinking Water Act amendments, 

those utilities’ total violations were reduced by 30– 

44% and more severe health violations by 40–57%). 

128Using a micro-level data set linking Toxic 

Release Inventory (TRI) releases to plant-level 

Census data, one researcher found, among other 

things, that state and local government use of TRI 

disclosures helped induce firms to become cleaner. 

Linda T.M. Bui, Public Disclosure of Private 

Information as a Tool for Regulating Environmental 

Emissions: Firm-Level Responses by Petroleum 

Refineries to the Toxics Release Inventory (Brandeis 

Univ. Working Paper Series, Working Paper No. 05– 

13, 2005), available at ftp://ftp2.census.gov/ces/wp/ 

2005/CES-WP-05-13.pdf. See also, Shameek Komar 

& Mark A. Cohen, Information As Regulation: The 

Effect of Community Right to Know Laws on Toxic 

Emissions, 32 J. ENVT’L ECON. & MGMT. 109 

(1997), available at http://www.sciencedirect.com/

science/article/pii/S0095069696909559 (finding 

that the top 40 firms with the largest drop in stock 

price following their disclosure of TRI emissions 

subsequently reduced their average emissions more 

than other firms in their industry, including the top 

40 firms with the largest TRI emissions per 

thousand dollars in revenue [TRI/$]; these firms 

both significantly reduced their average emissions 

and made significant attempts to improve their 

environmental performance by reducing the 

frequency and severity of chemical and oil spills). 129 DAVID WHEELER, WORLD BANK REPORT 

NO. 16513–BR, INFORMATION IN POLLUTION 

MANAGEMENT: THE NEW MODEL 14 (1997), 

available at http://web.worldbank.org/archive/

website01004/WEB/IMAGES/BRAZILIN.PDF 

(finding that Indonesia’s Program for Pollution 

Control, Evaluation and Rating improved the 

studied facilities’ ratings pursuant to a color-coded 

scheme). 

130 In 1990, the Ministry of Environment, Lands 

and Parks of British Columbia, Canada (MOE) 

employed a public disclosure strategy releasing a 

list of industrial operations that were not in 

compliance with their waste management permits 

or were deemed to be a potential pollution concern. 

Simultaneously, the Government of British 

Columbia introduced revised regulations to its pulp 

and paper regulations setting stricter standards and 

also increasing the maximum amount of fines under 

the Waste Management Act. Results indicated that 

the public disclosure strategy had a larger impact 

on both emissions levels and compliance status 

than traditional enforcement strategies, including 

fines, orders, and penalties. The results also 

indicated that the adoption of stricter standards and 

higher penalties also had a significant impact on 

decreasing emissions levels. Je ́roˆme Foulon et al., 

Incentives for Pollution Control: Regulation and 

Public Disclosure 5 (World Bank Pol’y Res., 

Working Paper No. 2291, 2000), available at http:// 

papers.ssrn.com/sol3/papers.cfm?abstract_

id=629138. 

131Richard Liroff, D. F. (2014). Disclosing the 

Facts: Transparency and Risk in Hydraulic 

Fracturing. 

required to use the appropriate 

electronic report in CEDRI for this 

subpart or an alternate electronic file 

format consistent with the extensible 

markup language (XML) schema listed 

on the CEDRI Web site (http://

www.epa.gov/ttn/chief/cedri/

index.html). If the reporting form 

specific to this subpart is not available 

in CEDRI at the time that the report is 

due, the owner or operator would 

submit the report to the Administrator 

at the appropriate address listed in 

§ 60.4 of the General Provisions. The 

owner or operator must begin 

submitting reports via CEDRI no later 

than 90 days after the form becomes 

available in CEDRI. The EPA is 

currently working to develop the form 

for subpart OOOO. 

2. Potential To Enhance Public 

Transparency Through Web Site Posting 

on Company Maintained Web Site 

The public disclosure of compliance 

information by regulated entities to 

customers, ratepayers, or stakeholders 

has been shown to reduce pollution and 

improve compliance. This disclosure 

will empower communities and other 

stakeholders to play an active role in 

compliance oversight and improve the 

performance of both the government 

and regulated entities. A study of the 

Safe Drinking Water Act’s (SDWA) 

Consumer Confidence Reports (CCR) 

requirements linked direct disclosures 

of compliance information to drinking 

water customers to statistically 

significant compliance improvements 

and reduced pollution.127 Additional 

studies have linked public information 

disclosure to pollution reductions,128

improved water pollution control 

practices,129 reduced air emissions and 

improved environmental regulatory 

compliance,130 and health and safety 

improvements in the automobile and 

restaurant markets. 

A 2014 study specific to the oil and 

natural gas industry 131 relied solely on 

publicly available information that 

companies provide on their Web sites, 

or in publicly released financial 

statements or other reports linked from 

their Web sites. The report focused on 

promoting improved operational 

practices among oil and natural gas 

companies engaged in horizontal 

drilling and hydraulic fracturing. 

According to the report, ‘‘[f]ollowing the 

maxim of what gets measured, gets 

managed,’’ this report encourages oil 

and natural gas companies to increase 

disclosures about their use of current 

best practices to minimize the 

environmental risks and community 

impacts of their ‘‘fracking’’ activities. A 

key finding of the report was that across 

the industry, ‘‘companies are failing to 

provide investors and other key 

stakeholders with quantitative, play-byplay disclosure of operational impacts 

and best management practices’’ (while 

noting an increase in any level of 

reporting over 2013). 

The EPA solicits comment on 

requiring owners and operators of 

affected facilities to report quantitative 

environmental results on their corporate 

maintained Web sites. Such results 

might include monitoring data 

(including fugitives), quantification of 

excess emissions and corrective actions, 

results of performance tests, affected 

facility status with respect to a standard 

contained in a rule, and third-party 

certifications. The EPA requests 

comment on whether all owner and 

operators should be required to do this, 

or only a subset (e.g., based on size of 

entity, complexity or number of 

operations, web presence, etc.) and what 

data we should require them to report; 

keeping in mind that monitoring and 

reporting requirements that may be 

sufficient for government regulators may 

be insufficient for the public. 

Government regulators may be satisfied 

with a regulation that requires a facility 

to monitor specified parameters (e.g., 

operating temperature) to generally 

assure that the facility is operating 

properly, and to perform a formal 

compliance test (e.g., measuring actual 

smokestack emissions) only upon the 

government’s request. 

3. Potential to Promote Advances in 

Data Capture (e.g., ‘‘Check-In App’’ 

With Location and Photos) 

One of the advances of the digital age 

is the ability to ‘‘check-in’’ with 

geospatial accuracy at any location. For 

example, in the 2012 NSPS, we 

provided a mechanism by which owners 

and operators could streamline annual 

reporting of well completions by using 

a digital camera to document that a well 

completion was performed in 

compliance with the NSPS. In lieu of 

submitting voluminous hard copies of 

well completion records in their annual 

report, the owner or operator could 

document the completions with a digital 

photograph of the REC equipment in 

use, with the date and geospatial 

coordinates shown on the photographs. 

These photographs would be submitted 

digitally or in hard copy form with the 

next annual report, along with a list of 

well completions performed with 

identifying information for each well 

completed. This option has been 

referred to as ‘‘REC PIX.’’ Building on 

the success of REC PIX, the EPA would 

like to explore this opportunity as it 

relates to advances in data capture to 

ensure that other compliant practices 

are in effect. For example, pictures of 

storage vessels could provide visual 

evidence of staining related to excess 

emissions events. As discussed 

previously, digital pictures and frame 

captures can help ensure that optical gas 

imaging for fugitive emissions is being 

performed properly. The EPA requests 

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comments on viability and benefits of 

this approach, and to which areas it 

might be expanded. 

XI. Impacts of This Proposed Rule 

A. What are the air impacts? 

For this action, the EPA estimated the 

emission reductions that will occur due 

to the implementation of the proposed 

emission limits. The EPA estimated 

emission reductions based on the 

control technologies proposed as the 

BSER. This analysis estimates regulatory 

impacts for the analysis years of 2020 

and 2025. The analysis of 2020 is 

assumed to represent the first year the 

full suite of proposed standards is in 

effect and thus represents a single year 

of potential impacts. We estimate 

impacts in 2025 to illustrate how new 

and modified sources accumulate over 

time under the proposed NSPS. The 

regulatory impact estimates for 2025 

include sources newly affected in 2025 

as well as the accumulation of affected 

sources from 2020 to 2024 that are also 

assumed to be in continued operation in 

2025, thus incurring compliance costs 

and emissions reductions in 2025. 

While the EPA is proposing an 

exclusion from fugitive emission 

requirements for low production well 

sites, there is uncertainty in how many 

well sites this exclusion might affect in 

the future. As a result, the analysis in 

this RIA presents a ‘‘low’’ impact case 

and ‘‘high’’ impact case for fugitive 

emissions requirements at well sites. 

The low impact case excludes from 

analysis an estimate of low production 

sites, based on the first month of 

production data from wells newly 

completed or modified in 2012. The 

high impact case includes these well 

sites. National-level results for the 

proposed NSPS, then, are presented as 

ranges. 

In 2020, we have estimated that the 

proposed NSPS would reduce about 

170,000 to 180,000 tons of methane 

emissions and 120,000 tons of VOC 

emissions from affected facilities. In 

2025, we have estimated that the 

proposed NSPS would reduce about 

340,000 to 400,000 tons of methane 

emissions and 170,000 to 180,000 tons 

of VOC emissions from affected 

facilities. The NSPS is also expected to 

concurrently reduce about 310 to 400 

tons HAP in 2020 and 1,900 to 2,500 

tons HAP in 2025. 

As described in the TSD and RIA for 

this proposal, the EPA projected 

affected facilities using a combination of 

historical data from the U.S. GHG 

Inventory, and projected activity levels, 

taken from the Energy Information 

Administration (EIA’s) Annual Energy 

Outlook (AEO). The EPA also 

considered state regulations with 

similar requirements to the proposed 

NSPS in projecting affected sources for 

impacts analyses supporting this 

proposed rule. The EPA solicits 

comments on these projection methods 

as well as solicits information that 

would improve our estimate of the 

turnover rates and rates of modification 

of relevant sources and the number of 

wells on multi-well well sites. 

B. What are the energy impacts? 

Energy impacts in this section are 

those energy requirements associated 

with the operation of emission control 

devices. Potential impacts on the 

national energy economy from the rule 

are discussed in the economic impacts 

section. There would be little national 

energy demand increase from the 

operation of any of the environmental 

controls proposed in this action. 

The proposed NSPS encourages the 

use of emission controls that recover 

hydrocarbon products, such as methane 

that can be used on-site as fuel or 

reprocessed within the production 

process for sale. We estimated that the 

proposed standards will result in a total 

cost of about $150 to $170 million in 

2020 and $320 to $420 million in 2025 

(in 2012 dollars). 

C. What are the compliance costs? 

The EPA estimates the total capital 

cost of the proposed NSPS will be $170 

to $180 million in 2020 and $280 to 

$330 million in 2025. The estimate of 

total annualized engineering costs of the 

proposed NSPS is $180 to $200 million 

in 2020 and $370 to $500 million in 

2025. This annual cost estimate 

includes the cost of capital, operating 

and maintenance costs, and monitoring, 

reporting, and recordkeeping costs. This 

estimated annual cost does not take into 

account any producer revenues 

associated with the recovery of salable 

natural gas. The EPA estimates that 

about 8 million Mcf in 2020 and 16 to 

19 million Mcf of natural gas in 2025 

will be recovered by implementing the 

proposed NSPS. In the engineering cost 

analysis, we assume that producers are 

paid $4 per thousand cubic feet (Mcf) 

for the recovered gas at the wellhead. 

After accounting for these revenues, the 

estimate of total annualized engineering 

costs of the proposed NSPS are 

estimated to be $150 to $170 million in 

2020 and $320 to $420 million in 2025. 

The price assumption is influential on 

estimated annualized engineering costs. 

A simple sensitivity analysis indicates 

$1/Mcf change in the wellhead price 

causes a change in estimated 

engineering compliance costs of about 

$8 million in 2020 and $16 to $19 

million in 2025. 

D. What are the economic and 

employment impacts? 

The EPA used the National Energy 

Modeling System (NEMS) to estimate 

the impacts of the proposed rule on the 

United States energy system. The NEMS 

is a publically-available model of the 

United States energy economy 

developed and maintained by the 

Energy Information Administration of 

the DOE and is used to produce the 

Annual Energy Outlook, a reference 

publication that provides detailed 

forecasts of the United States energy 

economy. 

The EPA modeled the high impact 

case of the proposed NSPS with respect 

the low production exemption from the 

well site fugitive emissions 

requirements. As such the NEMS-based 

estimates of energy system impacts are 

likely high end estimates. 

The NEMS-based analysis estimates 

natural gas and crude oil production 

levels remain essentially unchanged 

under the proposed rule in 2020, while 

slight declines are estimated for 2025 for 

both natural gas (about 4 billion cubic 

feet (bcf) or about 0.01 percent) and 

crude oil production (about 2,000 

barrels per day or 0.03 percent). 

Wellhead natural gas prices for onshore 

lower 48 production are not estimated 

to change in 2020 under the proposed 

rule, but are estimated to increase about 

$0.007 per Mcf or 0.14 percent in 2025. 

Meanwhile, well crude oil prices for 

onshore lower 48 production are not 

estimated to change, despite the 

incidence of new compliance costs from 

the proposed NSPS. Meanwhile, net 

imports of natural gas are estimated to 

decline slightly in 2020 (by about 1 bcf 

or 0.05 percent) and in 2025 (by about 

3 bcf or 0.09 percent). Crude oil imports 

are estimated to not change in 2020 and 

increase by about 1,000 barrels per day 

(or 0.02 percent) in 2025. 

Executive Order 13563 directs federal 

agencies to consider the effect of 

regulations on job creation and 

employment. According to the 

Executive Order, ‘‘our regulatory system 

must protect public health, welfare, 

safety, and our environment while 

promoting economic growth, 

innovation, competitiveness, and job 

creation. It must be based on the best 

available science.’’ (Executive Order 

13563, 2011) Although standard benefitcost analyses have not typically 

included a separate analysis of 

regulation-induced employment 

impacts, we typically conduct 

employment analyses. During the 

current economic recovery, employment 

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132Previous analyses have commonly referred to 

the social cost of carbon dioxide emissions as the 

social cost of carbon or SCC. To more easily 

facilitate the inclusion of non-CO2 GHGs in the 

discussion and analysis the more specific SC-CO2

nomenclature is used to refer to the social cost of 

CO2 emissions. 

133Both the 2010 SC-CO2 TSD and the current 

TSD are available at: https://www.whitehouse.gov/ 

omb/oira/social-cost-of-carbon. 

impacts are of particular concern and 

questions may arise about their 

existence and magnitude. 

EPA estimated the labor impacts due 

to the installation, operation, and 

maintenance of control equipment, 

control activities, and labor associated 

with new reporting and recordkeeping 

requirements. We estimated up-front 

and continual, annual labor 

requirements by estimating hours of 

labor required for compliance and 

converting this number to full-time 

equivalents (FTEs) by dividing by 2,080 

(40 hours per week multiplied by 52 

weeks). The up-front labor requirement 

to comply with the proposed NSPS is 

estimated at about 50 to 70 FTEs in 2020 

and 50 to 70 FTEs in 2025. The annual 

labor requirement to comply with 

proposed NSPS is estimated at about 

470 to 530 FTEs in 2020 and 1,100 to 

1,400 FTEs in 2025. 

We note that this type of FTE estimate 

cannot be used to identify the specific 

number of people involved or whether 

new jobs are created for new employees, 

versus displacing jobs from other sectors 

of the economy. 

E. What are the benefits of the proposed 

standards? 

The proposed rule is expected to 

result in significant reductions in 

emissions. In 2020, the proposed rule is 

anticipated to reduce 170,000 to 180,000 

tons of methane (a GHG and a precursor 

to global ozone formation), 120,000 tons 

of VOC (a precursor to both PM (2.5 

microns and less) (PM2.5) and ozone 

formation), and 310 to 400 tons of HAP. 

In 2025, the proposed rule is anticipated 

to reduce 340,000 to 400,000 tons of 

methane, 170,000 to 180,000 tons of 

VOC, and 1,900 to 2,500 tons of HAP. 

These pollutants are associated with 

substantial health effects, climate 

effects, and other welfare effects. 

The proposed standards are expected 

to reduce methane emissions annually 

by about 3.8 to 4.0 million metric tons 

CO2 Eq. in 2020 and by about 7.7 to 9.0 

million metric tons CO2 Eq. in 2025. 

The methane reductions represent about 

2 percent in 2020 and 4 to 5 percent in 

2025 of the baseline methane emissions 

for this sector reported in the U.S. GHG 

Inventory for 2013 (about 182 million 

metric tons CO2 Eq. when petroleum 

refineries and petroleum transportation 

are excluded because these sources are 

not examined in this proposal). 

However, it is important to note that the 

emission reductions are based upon 

predicted activities in 2020 and 2025; 

the EPA did not forecast sector-level 

emissions in 2020 and 2025 for this 

rulemaking. 

Methane is a potent GHG that, once 

emitted into the atmosphere, absorbs 

terrestrial infrared radiation that 

contributes to increased global warming 

and continuing climate change. 

Methane reacts in the atmosphere to 

form tropospheric ozone and 

stratospheric water vapor, both of which 

also contribute to global warming. When 

accounting for the impacts changing 

methane, tropospheric ozone, and 

stratospheric water vapor 

concentrations, the Intergovernmental 

Panel on Climate Change (IPCC) 5th 

Assessment Report (2013) found that 

historical emissions of methane 

accounted for about 30 percent of the 

total current warming influence 

(radiative forcing) due to historical 

emissions of GHGs. Methane is therefore 

a major contributor to the climate 

change impacts described previously. In 

2013, total methane emissions from the 

oil and natural gas industry represented 

nearly 29 percent of the total methane 

emissions from all sources and account 

for about 3 percent of all CO2-equivalent 

emissions in the United States, with the 

combined petroleum and natural gas 

systems being the largest contributor to 

U.S. anthropogenic methane emissions. 

We calculated the global social 

benefits of methane emission reductions 

expected from the proposed NSPS 

standards for oil and natural gas sites 

using estimates of the social cost of 

methane (SC-CH4), a metric that 

estimates the monetary value of impacts 

associated with marginal changes in 

methane emissions in a given year. The 

SC-CH4 estimates applied in this 

analysis were developed by Marten et 

al. (2014) and are discussed in greater 

detail below. 

A similar metric, the social cost of 

CO2 (SC-CO2), provides important 

context for understanding the Marten et 

al. SC-CH4 estimates.132 The SC-CO2 is 

a metric that estimates the monetary 

value of impacts associated with 

marginal changes in CO2 emissions in a 

given year. Similar to the SC-CH4, it 

includes a wide range of anticipated 

climate impacts, such as net changes in 

agricultural productivity, property 

damage from increased flood risk, and 

changes in energy system costs, such as 

reduced costs for heating and increased 

costs for air conditioning. Estimates of 

the SC-CO2 have been used by the EPA 

and other federal agencies to value the 

impacts of CO2 emissions changes in 

benefit cost analysis for GHG-related 

rulemakings since 2008. 

The SC-CO2 estimates were developed 

over many years, using the best science 

available, and with input from the 

public. Specifically, an interagency 

working group (IWG) that included EPA 

and other executive branch agencies and 

offices used three integrated assessment 

models (IAMs) to develop the SC-CO2

estimates and recommended four global 

values for use in regulatory analyses. 

The SC-CO2 estimates were first 

released in February 2010 and updated 

in 2013 using new versions of each 

IAM. The 2010 SC-CO2 Technical 

Support Document (2010 TSD) provides 

a complete discussion of the methods 

used to develop these estimates and the 

current SC-CO2 TSD presents and 

discusses the 2013 update (including 

recent minor technical corrections to the 

estimates).133

The SC-CO2 TSDs discuss a number of 

limitations to the SC-CO2 analysis, 

including the incomplete way in which 

the IAMs capture catastrophic and noncatastrophic impacts, their incomplete 

treatment of adaptation and 

technological change, uncertainty in the 

extrapolation of damages to high 

temperatures, and assumptions 

regarding risk aversion. Currently, IAMs 

do not assign value to all of the 

important physical, ecological, and 

economic impacts of climate change 

recognized in the climate change 

literature due to a lack of precise 

information on the nature of damages 

and because the science incorporated 

into these models understandably lags 

behind the most recent research. 

Nonetheless, these estimates and the 

discussion of their limitations represent 

the best available information about the 

social benefits of CO2 reductions to 

inform benefit-cost analysis. EPA and 

other agencies continue to engage in 

research on modeling and valuation of 

climate impacts with the goal to 

improve these estimates, and continue 

to consider feedback on the SC-CO2

estimates from stakeholders through a 

range of channels, including public 

comments on Agency rulemakings a 

separate recent OMB public comment 

solicitation, and through regular 

interactions with stakeholders and 

research analysts implementing the SCCO2 methodology. See the RIA of this 

rule for additional details. 

A challenge particularly relevant to 

this proposal is that the IWG did not 

estimate the social costs of non-CO2

GHG emissions at the time the SC-CO2

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134U.S. EPA. 2012. Regulatory Impact Analysis 

Final New Source Performance Standards and 

Amendments to the National Emissions Standards 

for Hazardous Air Pollutants for the Oil and Natural 

Gas Industry. Office of Air Quality Planning and 

Standards, Health and Environmental Impacts 

Division. April. http://www.epa.gov/ttn/ecas/

regdata/RIAs/oil_natural_gas_final_neshap_nsps_

ria.pdf. Accessed March 30, 2015. 

135For example, see (1) U.S. EPA. (2012). 

‘‘Regulatory impact analysis supporting the 2012 

U.S. Environmental Protection Agency final new 

source performance standards and amendments to 

the national emission standards for hazardous air 

pollutants for the oil and natural gas industry.’’ 

Retrieved from http://www.epa.gov/ttn/ecas/

regdata/RIAs/oil_natural_gas_final_neshap_nsps_

ria.pdf and (2) U.S. EPA. (2012). ‘‘Regulatory 

impact analysis: Final rulemaking for 2017-2025 

light-duty vehicle greenhouse gas emission 

standards and corporate average fuel economy 

standards.’’ Retrieved from http://www.epa.gov/

otaq/climate/documents/420r12016.pdf. 

136See Waldhoff et al. (2011); Marten and 

Newbold (2012); and Marten et al. (2014). 

137Marten et al. (2014) also provided the first set 

of SC-N2O estimates that are consistent with the 

assumptions underlying the IWG SC-CO2 estimates. 

138Marten, A.L., E.A. Kopits, C.W. Griffiths, S.C. 

Newbold & A. Wolverton (2014, online publication; 

2015, print publication). Incremental CH4 and N2O 

mitigation benefits consistent with the U.S. 

Government’s SC-CO2 estimates, Climate Policy, 

DOI: 10.1080/14693062.2014.912981. 

estimates were developed. In addition, 

the directly modeled estimates of the 

social costs of non-CO2 GHG emissions 

previously found in the published 

literature were few in number and 

varied considerably in terms of the 

models and input assumptions they 

employed 134 (EPA 2012). As a result, 

benefit-cost analyses informing U.S. 

federal rulemakings to date have not 

fully considered the monetized benefits 

associated with CH4 emissions 

mitigation. To understand the potential 

importance of monetizing non-CO2 GHG 

emissions changes, EPA has conducted 

sensitivity analysis in some of its past 

regulatory analyses using an estimate of 

the GWP of CH4 to convert emission 

impacts to CO2 equivalents, which can 

then be valued using the SC-CO2

estimates. This approach approximates 

the social cost of methane (SC-CH4) 

using estimates of the SC-CO2 and the 

GWP of CH4.135

The published literature documents a 

variety of reasons that directly modeled 

estimates of SC-CH4 are an analytical 

improvement over the estimates from 

the GWP approximation approach. 

Specifically, several recent studies 

found that GWP-weighted benefit 

estimates for methane are likely to be 

lower than the estimates derived using 

directly modeled social cost estimates 

for these gases.136 The GWP reflects 

only the relative integrated radiative 

forcing of a gas over 100 years in 

comparison to CO2. The directly 

modeled social cost estimates differ 

from the GWP-scaled SC-CO2 because 

the relative differences in timing and 

magnitude of the warming between 

gases are explicitly modeled, the nonlinear effects of temperature change on 

economic damages are included, and 

rather than treating all impacts over a 

hundred years equally, the modeled 

damages over the time horizon 

considered (2300 in this case) are 

discounted to present value terms. A 

detailed discussion of the limitations of 

the GWP approach can be found in the 

RIA. 

In general, the commenters on 

previous rulemakings strongly 

encouraged the EPA to incorporate the 

monetized value of non-CO2 GHG 

impacts into the benefit cost analysis. 

However they noted the challenges 

associated with the GWP approach, as 

discussed above, and encouraged the 

use of directly modeled estimates of the 

SC-CH4 to overcome those challenges. 

Since then, a paper by Marten et al. 

(2014) has provided the first set of 

published SC-CH4 estimates in the peerreviewed literature that are consistent 

with the modeling assumptions 

underlying the SC-CO2 estimates.137 138

Specifically, the estimation approach of 

Marten et al. used the same set of three 

IAMs, five socioeconomic and 

emissions scenarios, equilibrium 

climate sensitivity distribution, three 

constant discount rates, and aggregation 

approach used by the IWG to develop 

the SC-CO2 estimates. 

The SC-CH4 estimates from Marten et 

al. (2014) are presented below in Table 

6. More detailed discussion of the SCCH4 estimation methodology, results 

and a comparison to other published 

estimates can be found in the RIA and 

in Marten et al. 

TABLE 6—SOCIAL COST OF CH4, 2012–2050 a

[In 2012$ per metric ton] (Source: Marten et al., 2014 b) 

Year 

SC-CH4

5% 

Average 

3% 

Average 

2.5% 

Average 

3% 

95th Percentile 

2012 ......................................................................................................... $430 $1000 $1400 $2800 

2015 ......................................................................................................... 490 1100 1500 3000

2020 ......................................................................................................... 580 1300 1700 3500

2025 ......................................................................................................... 700 1500 1900 4000

2030 ......................................................................................................... 820 1700 2200 4500

2035 ......................................................................................................... 970 1900 2500 5300

2040 ......................................................................................................... 1100 2200 2800 5900 

2045 ......................................................................................................... 1300 2500 3000 6600 

2050 ......................................................................................................... 1400 2700 3300 7200 

Notes: 

aThere are four different estimates of the SC-CH4, each one emissions-year specific. The first three shown in the table are based on the average SC-CH4 from three integrated assessment models at discount rates of 5, 3, and 2.5 percent. The fourth estimate is the 95th percentile of the 

SC-CH4 across all three models at a 3 percent discount rate. See RIA for details. bThe estimates in this table have been adjusted to reflect the minor technical corrections to the SC-CO2 estimates described above. See the 

Corrigendum to Marten et al. (2014), http://www.tandfonline.com/doi/abs/10.1080/14693062.2015.1070550. 

The application of these directly 

modeled SC-CH4 estimates from Marten 

et al. (2014) in a benefit-cost analysis of 

a regulatory action is analogous to the 

use of the SC-CO2 estimates. In addition, 

the limitations for the SC-CO2 estimates 

discussed above likewise apply to the 

SC-CH4 estimates, given the consistency 

in the methodology. 

The EPA recently conducted a peer 

review of the application of the Marten 

et al. (2014) non-CO2 social cost 

estimates in regulatory analysis and 

received responses that supported this 

application. See the RIA for a detailed 

discussion. 

In light of the favorable peer review 

and past comments urging the EPA to 

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139Previous studies have estimated the monetized 

benefits-per-ton of reducing VOC emissions 

associated with the effect that those emissions have 

on ambient PM2.5 levels and the health effects 

associated with PM2.5 exposure (Fann, Fulcher, and 

Hubbell, 2009). While these ranges of benefit-perton estimates can provide useful context, the 

geographic distribution of VOC emissions from the 

oil and gas sector are not consistent with emissions 

modeled in Fann, Fulcher, and Hubbell (2009). In 

addition, the benefit-per-ton estimates for VOC 

emission reductions in that study are derived from 

total VOC emissions across all sectors. Coupled 

with the larger uncertainties about the relationship 

between VOC emissions and PM2.5 and the highly 

localized nature of air quality responses associated 

with HAP and VOC reductions, these factors lead 

us to conclude that the available VOC benefit-perton estimates are not appropriate to calculate 

monetized benefits of these rules, even as a 

bounding exercise. 

140U.S. EPA. RIA. National Ambient Air Quality 

Standards for Particulate Matter, Chapter 5. Office 

of Air Quality Planning and Standards, Research 

Triangle Park, NC. October 2006. Available on the 

Internet at http://www.epa.gov/ttn/ecas/regdata/

RIAs/Chapter%205-Benefits.pdf. 

141U.S. EPA. RIA. National Ambient Air Quality 

Standards for Ozone. Office of Air Quality Planning 

and Standards, Research Triangle Park, NC. January 

2010. Available on the Internet at http://

www.epa.gov/ttn/ecas/regdata/RIAs/s1- 

supplemental_analysis_full.pdf. 

142U.S. EPA. RIA. National Ambient Air Quality 

Standards for Ozone. Office of Air Quality Planning 

and Standards, Research Triangle Park, NC. 

December 2014. Available on the Internet at 

http://www.epa.gov/ttnecas1/regdata/RIAs/

20141125ria.pdf. 

143U.S. EPA. Integrated Science Assessment for 

Particulate Matter (Final Report). EPA–600–R–08– 

139F. National Center for Environmental 

Assessment—RTP Division. December 2009. 

Available at http://cfpub.epa.gov/ncea/cfm/

recordisplay.cfm?deid=216546. 

144U.S. EPA. Air Quality Criteria for Ozone and 

Related Photochemical Oxidants (Final). EPA/600/ 

R–05/004aF–cF. Washington, DC: U.S. EPA. 

February 2006. Available on the Internet at 

http://cfpub.epa.gov/ncea/CFM/

recordisplay.cfm?deid=149923. 

value non-CO2 GHG impacts in its 

rulemakings, the Agency has used the 

Marten et al. (2014) SC-CH4 estimates to 

value methane impacts expected from 

this proposed rulemaking and has 

included those benefits in the main 

benefits analysis. The EPA seeks 

comments on the use of these directly 

modeled estimates, from the peerreviewed literature, for the social cost of 

non-CO2 GHGs in today’s rulemaking. 

The methane benefits calculated using 

Marten et al. (2014) are presented for 

years 2020 and 2025. Applying this 

approach to the methane reductions 

estimated for the NSPS proposal, the 

2020 methane benefits vary by discount 

rate and range from about $88 million 

to approximately $550 million; the 

mean SC-CH4 at the 3-percent discount 

rate results in an estimate of about $200 

to $210 million in 2020. The methane 

benefits increase in the 2025, ranging 

from $220 million to $1.4 billion, 

depending on discount rate used; the 

mean SC-CH4 at the 3-percent discount 

rate results in an estimate of about $460 

to $550 million in 2025. 

TABLE 7—ESTIMATED GLOBAL BENEFITS OF METHANE REDUCTIONS

[In millions, 2012$] 

Discount rate and statistic 

Year 

2020 2025 

Million metric tonnes of methane reduced ...................................................................................... 0.15 to 0.16 ............... 0.31 to 0.36. 

Million metric tonnes of CO2 Eq. ..................................................................................................... 3.8 to 4.0 ................... 7.7 to 9.0. 

5% (average) ............................................................................................................................ $88 to $93 ................. $220 to $250. 

3% (average) ............................................................................................................................ $200 to $210 ............. $460 to $550. 

2.5% (average) ......................................................................................................................... $260 to $280 ............. $600 to $700. 

3% (95th percentile) ................................................................................................................. $520 to $550 ............. $1,200 to $1,400. 

In addition to the limitation discussed 

above, and the referenced documents, 

there are additional impacts of 

individual GHGs that are not currently 

captured in the IAMs used in the 

directly modeled approach of Marten et 

al. (2014), and therefore not quantified 

for the rule. For example, in addition to 

being a GHG, methane is a precursor to 

ozone. The ozone generated by methane 

has important non-climate impacts on 

agriculture, ecosystems, and human 

health. The RIA describes the specific 

impacts of methane as an ozone 

precursor in more detail and discusses 

studies that have estimated monetized 

benefits of these methane generated 

ozone effects. The EPA continues to 

monitor developments in this area of 

research and seeks comment on the 

potential inclusion of health impacts of 

ozone generated by methane in future 

regulatory analysis. 

With the data available, we are not 

able to provide credible health benefit 

estimates for the reduction in exposure 

to HAP, ozone and PM2.5 for these rules, 

due to the differences in the locations of 

oil and natural gas emission points 

relative to existing information and the 

highly localized nature of air quality 

responses associated with HAP and 

VOC reductions. This is not to imply 

that there are no benefits of the rules; 

rather, it is a reflection of the difficulties 

in modeling the direct and indirect 

impacts of the reductions in emissions 

for this industrial sector with the data 

currently available.139 In addition to 

health improvements, there will be 

improvements in visibility effects, 

ecosystem effects and climate effects, as 

well as additional product recovery. 

Although we do not have sufficient 

information or modeling available to 

provide quantitative estimates for this 

rulemaking, we include a qualitative 

assessment of the health effects 

associated with exposure to HAP, ozone 

and PM2.5 in the RIA for this rule. These 

qualitative effects are briefly 

summarized below, but for more 

detailed information, please refer to the 

RIA, which is available in the docket. 

One of the HAPs of concern from the oil 

and natural gas sector is benzene, which 

is a known human carcinogen. VOC 

emissions are precursors to both PM2.5

and ozone formation. As documented in 

previous analyses (U.S. EPA, 2006,140

U.S. EPA, 2010,141 and U.S. EPA, 

2014 142), exposure to PM2.5 and ozone 

is associated with significant public 

health effects. PM2.5 is associated with 

health effects, including premature 

mortality for adults and infants, 

cardiovascular morbidity such as heart 

attacks, and respiratory morbidity such 

as asthma attacks, acute bronchitis, 

hospital admissions and emergency 

room visits, work loss days, restricted 

activity days and respiratory symptoms, 

as well as visibility impairment.143

Ozone is associated with health effects, 

including hospital and emergency 

department visits, school loss days and 

premature mortality, as well as injury to 

vegetation and climate effects.144

Finally, the control techniques to 

meet the standards are anticipated to 

have minor secondary emissions 

impacts, which may partially offset the 

direct benefits of this rule. The 

magnitude of these secondary air 

pollutant impacts is small relative to the 

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direct emission reductions anticipated 

from this rule. 

In particular, EPA has estimated that 

an increase in flaring of methane in 

response to this rule will produce a 

variety of emissions, including 610,000 

tons of CO2 in 2020 and 750,000 tons of 

CO2 in 2025. EPA has not estimated the 

monetized value of the secondary 

emissions of CO2 because much of the 

methane that would have been released 

in the absence of the flare would have 

eventually oxidized into CO2 in the 

atmosphere. Note that the CO2 produced 

from the methane oxidizing in the 

atmosphere is not included in the 

calculation of the SC-CH4. However, 

EPA recognizes that because the growth 

rate of the SC-CO2 estimates are lower 

than their associated discount rates, the 

estimated impact of CO2 produced in 

the future from oxidized methane would 

be less than the estimated impact of CO2

released immediately from flaring, 

which would imply a small disbenefit 

associated with flaring. Assuming an 

average methane oxidation period of 8.7 

years, consistent with the lifetime used 

in IPCC AR4, the disbenefits associated 

with destroying one ton of methane and 

releasing the CO2 emissions in 2020 

instead of being released in the future 

via the methane oxidation process is 

estimated to be $6 to $25, depending on 

the SC-CO2 value or 0.7 percent to 1.0 

percent of the SC-CH4 estimates for 

2020. The analogous estimates for 2025 

are $7 to $34 or 0.8 percent to 1.0 

percent of the SC-CH4 estimates for 

2025. While EPA is not accounting for 

the CO2 disbenefits at this time, we 

request comment on the appropriateness 

of the monetization of such impacts 

using the SC-CO2 and aspects of the 

calculation. See RIA for further details 

about the calculation. 

XII. Statutory and Executive Order 

Reviews 

Additional information about these 

statutes and Executive Orders can be 

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

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is an economically 

significant regulatory action that was 

submitted to the OMB for review. Any 

changes made in response to OMB 

recommendations have been 

documented in the docket. The EPA 

prepared an analysis of the potential 

costs and benefits associated with this 

action. 

In addition, the EPA prepared a 

Regulatory Impact Analysis (RIA) of the 

potential costs and benefits associated 

with this action. The RIA available in 

the docket describes in detail the 

empirical basis for the EPA’s 

assumptions and characterizes the 

various sources of uncertainties 

affecting the estimates below. Table 8 

shows the results of the cost and 

benefits analysis for these proposed 

rules. 

TABLE 8—SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET BENEFITS FOR THE PROPOSED OIL AND

NATURAL GAS NSPS IN 2020 AND 2025 

[Millions of 2012$] 

2020 2025 

Total Monetized Benefits 1 ................................. $200 to $210 million ......................................... $460 to $550 million. 

Total Costs 2 ...................................................... $150 to $170 million ......................................... $320 to $420 million. 

Net Benefits 3 ..................................................... $35 to $42 million ............................................. $120 to $150 million. 

Non-monetized Benefits .................................... Non-monetized climate benefits. 

Health effects of PM2.5 and ozone exposure from 120,000 tons of VOC in 2020 and 170,000 to 

180,000 tons of VOC in 2025. 

Health effects of HAP exposure from 310 to 400 tons of HAP in 2020 and 1,900 to 2,500 tons 

of HAP in 2025. 

Health effects of ozone exposure from 170,000 to 180,000 tons of methane in 2020 and 

340,000 to 400,000 tons methane in 2025. 

Visibility impairment. 

Vegetation effects. 

1We estimate methane benefits associated with four different values of a one ton CH4 reduction (model average at 2.5 percent discount rate, 

3 percent, and 5 percent; 95th percentile at 3 percent). For the purposes of this table, we show the benefits associated with the model average 

at 3 percent discount rate, however we emphasize the importance and value of considering the full range of social cost of methane values. We 

provide estimates based on additional discount rates in preamble section XI and in the RIA. Also, the specific control technologies for the proposed NSPS are anticipated to have minor secondary disbenefits. The net CO2-equivalent (CO2 Eq.) methane emission reductions are 3.8 to 4.0 

million metric tons in 2020 and 7.7 to 9.0 million metric tons in 2025. 2The engineering compliance costs are annualized using a 7 percent discount rate and include estimated revenue from additional natural gas 

recovery as a result of the NSPS. When rounded, the cost estimates are the same for the 3 percent discount rate as they are for the 7 percent 

discount rate cost estimates, so rounded net benefits do not change when using a 3 percent discount rate. 3Figures may not sum due to rounding. 

B. Paperwork Reduction Act (PRA) 

The Office of Management and Budget 

(OMB) has previously approved the 

information collection activities 

contained in 40 CFR part 60, subpart 

OOOO under the PRA and has assigned 

OMB control number 2060–0673 and 

ICR number 2437.01; a summary can be 

found at 77 FR 49537. The information 

collection requirements in today’s 

proposed rule titled, Standards of 

Performance for Crude Oil and Natural 

Gas Facilities for Construction, 

Modification, or Reconstruction (40 CFR 

part 60 subpart OOOOa) have been 

submitted for approval to the OMB 

under the PRA. The ICR document 

prepared by the EPA has been assigned 

EPA ICR Number 2523.01. You can find 

a copy of the ICR in the docket for this 

rule, and is briefly summarized below. 

The information to be collected for 

the proposed NSPS is based on 

notification, performance tests, 

recordkeeping and reporting 

requirements which will be mandatory 

for all operators subject to the final 

standards. Recordkeeping and reporting 

requirements are specifically authorized 

by section 114 of the CAA (42 U.S.C. 

7414). The information will be used by 

the delegated authority (state agency, or 

Regional Administrator if there is no 

delegated state agency) to ensure that 

the standards and other requirements 

are being achieved. Based on review of 

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the recorded information at the site and 

the reported information, the delegated 

permitting authority can identify 

facilities that may not be in compliance 

and decide which facilities, records, or 

processes may need inspection. All 

information submitted to the EPA 

pursuant to the recordkeeping and 

reporting requirements for which a 

claim of confidentiality is made is 

safeguarded according to Agency 

policies set forth in 40 CFR part 2, 

subpart B. 

Potential respondents under subpart 

OOOOa are owners or operators of new, 

modified or reconstructed oil and 

natural gas affected facilities as defined 

under the rule. None of the facilities in 

the United States are owned or operated 

by state, local, tribal or the Federal 

government. All facilities are privately 

owned for-profit businesses. The 

requirements in this action result in 

industry recording keeping and 

reporting burden associated with review 

of the requirements for all affected 

entities, gathering relevant information, 

performing initial performance tests and 

repeat performance tests if necessary, 

writing and submitting the notifications 

and reports, developing systems for the 

purpose of processing and maintaining 

information, and train personnel to be 

able to respond to the collection of 

information. 

The estimated average annual burden 

(averaged over the first 3 years after the 

effective date of the standards) for the 

recordkeeping and reporting 

requirements in subpart OOOOa for the 

2,552 owners and operators that are 

subject to the rule is 92,658 labor hours, 

with an annual average cost of 

$3,163,699. The annual public reporting 

and recordkeeping burden for this 

collection of information is estimated to 

average 3.9 hours per response. 

Respondents must monitor all specified 

criteria at each affected facility and 

maintain these records for 5 years. 

Burden is defined at 5 CFR 1320.3(b). 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for the EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

Submit your comments on the 

Agency’s need for this information, the 

accuracy of the provided burden 

estimates and any suggested methods 

for minimizing respondent burden to 

the EPA using the docket identified at 

the beginning of this rule. You may also 

send your ICR-related comments to 

OMB’s Office of Information and 

Regulatory Affairs via email to RIA_

submissions@omb.eop.gov, Attention: 

Desk Officer for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

receipt, OMB must receive comments no 

later than November 17, 2015. The EPA 

will respond to any ICR-related 

comments in the final rule. 

C. Regulatory Flexibility Act (RFA) 

The RFA generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the agency 

certifies that the rule will not have a 

significant economic impact on a 

substantial number of small entities. 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts 

of this rule on small entities, a small 

entity is defined as: (1) A small business 

in the oil or natural gas industry whose 

parent company has no more than 500 

employees (or revenues of less than $7 

million for firms that transport natural 

gas via pipeline); (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district, or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-forprofit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

Pursuant to section 603 of the RFA, 

the EPA prepared an initial regulatory 

flexibility analysis (IRFA) that examines 

the impact of the proposed rule on small 

entities along with regulatory 

alternatives that could minimize that 

impact. The complete IRFA is available 

for review in the docket and is 

summarized here. 

The IRFA describes the reason why 

the proposed rule is being considered 

and describes the objectives and legal 

basis of the proposed rule, as well as 

discusses related rules affecting the oil 

and natural gas sector. The IRFA 

describes the EPA’s examination of 

small entity effects prior to proposing a 

regulatory option and provides 

information about steps taken to 

minimize significant impacts on small 

entities while achieving the objectives 

of the rule. 

The EPA also summarized the 

potential regulatory cost impacts of the 

proposed rule and alternatives in 

Section 3 of the RIA. The analysis in the 

IRFA drew upon the same analysis and 

assumptions as the analyses presented 

in the RIA. The IRFA analysis is 

presented in its entirely in Section 7.3 

of the RIA. 

Identifying impacts on specific 

entities is challenging because of the 

difficulty of predicting potentially 

affected new or modified sources at the 

firm level. To identify potentially 

affected entities under the proposed 

NSPS, the EPA combined information 

from industry databases to identify 

firms drilling and completing wells in 

2012, as well as identified their oil and 

natural gas production levels for that 

year. 

The EPA based the analysis in the 

IRFA on impacts estimates for the 

proposed requirements for hydraulically 

fractured and re-fractured oil well 

completions and well site fugitive 

emissions. While the IRFA does not 

incorporate potential impacts from other 

provisions of the proposed NSPS, the 

completions and fugitive emissions 

provisions represent a large majority of 

the estimated compliance costs of the 

proposed NSPS in 2020 and 2025. Note 

incorporating impacts from other 

provisions in this analysis is a 

limitation and underestimates impacts, 

but the EPA believes that detailed 

analysis of the two provisions impacts 

on small entities is illustrative of 

impacts on small entities from the 

proposed rule in its entirety. 

We projected the 2012 base year 

estimates of incrementally affected 

facilities to 2020 and 2025 levels based 

on the same growth rates used to project 

future activities as described in the TSD 

and consistent with other analyses in 

the RIA. This approach assumes that no 

other firms perform potentially affected 

activities and firms performing oil and 

natural gas activities in 2012 will 

continue to do so in 2020 and 2025. 

While likely true for many firms, this 

will not be the case for all firms. 

For some firms, we estimated their 

2012 sales levels by multiplying 2012 

oil and natural gas production levels 

reported in an industry database by 

assumed oil and natural gas prices at the 

wellhead. For natural gas, we assumed 

the $4/Mcf for natural gas. For oil 

prices, we estimated revenues using two 

alternative prices, $70/bbl and $50/bbl. 

In the results, we call the case using 

$70/bbl the ‘‘primary scenario’’ and the 

case using the $50/bbl as the ‘‘low oil 

price scenario’’. 

For projected 2020 and 2025 

potentially affected activities, we 

allocated compliance costs across 

entities based upon the costs estimated 

in the TSD and used in the RIA. The 

RIA and IRFA also estimates the 

potential implications of the proposed 

exclusion for low producing sites from 

the fugitive emission requirements. 

Fewer sites in the program due to this 

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exclusion will likely lead to lower costs 

and emissions. 

The analysis indicates about 1,200 to 

2,100 small entities may be subject to 

the requirements for hydraulically 

fractured and re-fractured oil well 

completions and fugitive emissions 

requirements at well sites. The low end 

of this range reflects an estimate of how 

many entities might be excluded as a 

result of the low production fugitive 

emissions exemption. Also the cost-tosales ratios with ratios greater than 1 

percent and 3 percent increase from 

2020 to 2025 as affected sources 

accumulate under the proposed NSPS. 

Cost-to-sales ratios exceeding 1 percent 

and 3 percent are also reduced from the 

case without the entities that might be 

excluded from fugitive emissions 

requirements as a result of the low 

production exemption. 

The analysis above is subject to a 

number of caveats and limitations. 

These are discussed in detail in the 

IRFA, as well as in Section 3 of the RIA. 

As required by section 609(b) of the 

RFA, the EPA also convened a Small 

Business Advocacy Review (SBAR) 

Panel to obtain advice and 

recommendations from small entity 

representatives that potentially would 

be subject to the rule’s requirements. 

The SBAR Panel evaluated the 

assembled materials and small-entity 

comments on issues related to elements 

of an IRFA. A copy of the full SBAR 

Panel Report is available in the 

rulemaking docket. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This action does not contain any 

unfunded mandate as described in 

UMRA, 2 U.S.C. 1531–1538, and does 

not significantly or uniquely affect small 

governments. The action imposes no 

enforceable duty on any state, local or 

tribal governments or the private sector. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. These final rules 

primarily affect private industry and 

would not impose significant economic 

costs on state or local governments. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action has tribal implications. 

However, it will neither impose 

substantial direct compliance costs on 

federally recognized tribal governments, 

nor preempt tribal law. The majority of 

the units impacted by this rulemaking 

on tribal lands are owned by private 

entities, and tribes will not be directly 

impacted by the compliance costs 

associated with this rulemaking. There 

would only be tribal implications 

associated with this rulemaking in the 

case where a unit is owned by a tribal 

government or a tribal government is 

given delegated authority to enforce the 

rulemaking. 

The EPA consulted with tribal 

officials under the ‘‘EPA Policy on 

Consultation and Coordination with 

Indian Tribes’’ early in the process of 

developing this regulation to permit 

them to have meaningful and timely 

input into its development. 

Additionally, the EPA has conducted 

meaningful involvement with tribal 

stakeholders throughout the rulemaking 

process. We provided an update on the 

methane strategy on the January 29, 

2015, NTAA and EPA Air Policy call. 

As required by section 7(a), the EPA’s 

Tribal Consultation Official has certified 

that the requirements of the Executive 

Order have been met in a meaningful 

and timely manner. A copy of the 

certification is included in the docket 

for this action. 

Consistent with previous actions 

affecting the oil and natural gas sector, 

there is significant tribal interest 

because of the growth of the oil and 

natural gas production in Indian 

country. The EPA specifically solicits 

additional comment on this proposed 

action from tribal officials. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This action is subject to Executive 

Order 13045 (62 FR 19885, April 23, 

1997) because it is an economically 

significant regulatory action as defined 

by Executive Order 12866, and the EPA 

believes that the environmental health 

or safety risk addressed by this action 

has a disproportionate effect on 

children. Accordingly, the agency has 

evaluated the environmental health and 

welfare effects of climate change on 

children. 

GHGs including methane contribute 

to climate change and are emitted in 

significant quantities by the oil and gas 

sector. The EPA believes that the GHG 

emission reductions resulting from 

implementation of these final guidelines 

will further improve children’s health. 

The assessment literature cited in the 

EPA’s 2009 Endangerment Finding 

concluded that certain populations and 

life stages, including children, the 

elderly, and the poor, are most 

vulnerable to climate-related health 

effects. The assessment literature since 

2009 strengthens these conclusions by 

providing more detailed findings 

regarding these groups’ vulnerabilities 

and the projected impacts they may 

experience. 

These assessments describe how 

children’s unique physiological and 

developmental factors contribute to 

making them particularly vulnerable to 

climate change. Impacts to children are 

expected from heat waves, air pollution, 

infectious and waterborne illnesses, and 

mental health effects resulting from 

extreme weather events. In addition, 

children are among those especially 

susceptible to most allergic diseases, as 

well as health effects associated with 

heat waves, storms, and floods. 

Additional health concerns may arise in 

low income households, especially 

those with children, if climate change 

reduces food availability and increases 

prices, leading to food insecurity within 

households. 

More detailed information on the 

impacts of climate change to human 

health and welfare is provided in 

Section V of this preamble. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

Executive Order 13211 (66 FR 28355, 

May 22, 2001) provides that agencies 

will prepare and submit to the 

Administrator of the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, a 

Statement of Energy Effects for certain 

actions identified as ‘‘significant energy 

actions.’’ Section 4(b) of Executive 

Order 13211 defines ‘‘significant energy 

actions’’ as any action by an agency 

(normally published in the Federal 

Register) that promulgates or is 

expected to lead to the promulgation of 

a final rule or regulation, including 

notices of inquiry, advance notices of 

proposed rulemaking, and notices of 

proposed rulemaking: (1)(i) That is a 

significant regulatory action under 

Executive Order 12866 or any successor 

order, and (ii) is likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy; or (2) that 

is designated by the Administrator of 

the Office of Information and Regulatory 

Affairs as a significant energy action. 

This action is not a ‘‘significant 

energy action’’ as defined in Executive 

Order 13211 (66 FR 28355, May 22, 

2001), because it is not likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy. The basis 

for these determinations follows. 

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56660 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

The EPA used the National Energy 

Modeling System (NEMS) to estimate 

the impacts of the proposed rule on the 

United States energy system. The NEMS 

is a publically-available model of the 

United States energy economy 

developed and maintained by the 

Energy Information Administration of 

the DOE and is used to produce the 

Annual Energy Outlook, a reference 

publication that provides detailed 

forecasts of the United States energy 

economy. 

The EPA modeled the high impact 

case of the proposed NSPS with respect 

the low production exemption from the 

well site fugitive emissions 

requirements. As such the NEMS-based 

estimates of energy system impacts are 

likely high end estimates. 

The NEMS-based analysis estimates 

natural gas and crude oil production 

levels remain essentially unchanged 

under the proposed rule in 2020, while 

slight declines are estimated for 2020 for 

both natural gas (about 4 billion cubic 

feet (bcf) or about 0.01 percent) and 

crude oil production (about 2,000 

barrels per day or 0.03 percent). 

Wellhead natural gas prices for onshore 

lower 48 production are not estimated 

to change in 2020 under the proposed 

rule, but are estimated to increase about 

$0.007 per Mcf or 0.14 percent in 2025. 

Meanwhile, well crude oil prices for 

onshore lower 48 production are not 

estimated to change, despite the 

incidence of new compliance costs from 

the proposed NSPS. Meanwhile, net 

imports of natural gas are estimated to 

decline slightly in 2020 (by about 1 bcf 

or 0.05 percent) and in 2025 (by about 

3 bcf or 0.09 percent). Crude oil imports 

are estimated to not change in 2020 and 

increase by about 1,000 barrels per day 

(or 0.02 percent) in 2025. 

Additionally, the NSPS establishes 

several performance standards that give 

regulated entities flexibility in 

determining how to best comply with 

the regulation. In an industry that is 

geographically and economically 

heterogeneous, this flexibility is an 

important factor in reducing regulatory 

burden. For more information on the 

estimated energy effects of this 

proposed rule, please see the Regulatory 

Impact Analysis which is in the docket 

for this proposal. 

I. National Technology Transfer and 

Advancement Act (NTTAA) and 1 CFR 

Part 51 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113 (15 U.S.C. 272 note) directs the EPA 

to use voluntary consensus standards 

(VCS) in its regulatory activities unless 

to do so would be inconsistent with 

applicable law or otherwise impractical. 

VCS are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by VCS bodies. NTTAA directs the EPA 

to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable VCS. 

The proposed rule involves technical 

standards. Therefore, the EPA 

conducted searches for the Oil and 

Natural Gas Sector: Emission Standards 

for New and Modified Sources through 

the Enhanced National Standards 

Systems Network (NSSN) Database 

managed by the American National 

Standards Institute (ANSI). Searches 

were conducted for EPA Methods 1, 1A, 

2, 2A, 2C, 2D, 3A, 3B, 3C, 4, 6, 10, 15, 

16, 16A, 21, 22, and 25A of 40 CFR part 

60 Appendix A. No applicable 

voluntary consensus standards were 

identified for EPA Methods 1A, 2A, 2D, 

21, and 22. All potential standards were 

reviewed to determine the practicality 

of the VCS for this rule. In this rule, the 

EPA is proposing to include in a final 

EPA rule regulatory text for 40 CFR part 

60, subpart OOOOa that includes 

incorporation by reference. In 

accordance with requirements of 1 CFR 

51.5, the EPA is proposing to 

incorporate by reference ASME/ANSI 

PTC 19–10–1981 Part 10 (2010), ‘‘Flue 

and Exhaust Gas Analyses’’ to be used 

in lieu of EPA Methods 3B, 6, 6A, 6B, 

15A and 16A manual portions only and 

not the instrumental portion. This 

standard includes manual and 

instructional methods of analysis for 

carbon dioxide, carbon monoxide, 

hydrogen sulfide, nitrogen oxides, 

oxygen, and sulfur dioxide. This 

standard is available from the American 

Society of Mechanical Engineers 

(ASME), Three Park Avenue, New York, 

NY 10016–5990. 

The EPA welcomes comments on this 

aspect of the proposed rulemaking and, 

specifically, invites the public to 

identify potentially-applicable VCS and 

to explain why such standards should 

be used in this regulation. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

The EPA believes the human health or 

environmental risk addressed by this 

action will not have potential 

disproportionately high and adverse 

human health or environmental effects 

on minority, low-income or indigenous 

populations. The EPA has determined 

this because the rulemaking increases 

the level of environmental protection for 

all affected populations without having 

any disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority, low-income or indigenous 

populations. The EPA has provided 

meaningful participation opportunities 

for minority, low-income, indigenous 

populations and tribes during the preproposal period by conducting 

community calls and webinars. 

Additionally, the EPA will conduct 

outreach for communities after the 

rulemaking is finalized. 

List of Subjects in 40 CFR Part 60 

Administrative practice and 

procedure, Air pollution control, 

Incorporation by reference, 

Intergovernmental relations, Reporting 

and recordkeeping. 

Dated: August 18, 2015. 

Gina McCarthy, 

Administrator. 

For the reasons set out in the 

preamble, title 40, chapter I of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 60—STANDARDS OF 

PERFORMANCE FOR NEW 

STATIONARY SOURCES 

■ 1. The authority citation for part 60 

continues to read as follows: 

AUTHORITY: 42 U.S.C. 4701, et seq. 

Subpart A—[Amended] 

■ 2. Section 60.17 is amended by 

revising paragraph (f)(14) 

§ 60.17 Incorporations by reference. 

* * * * * 

(f) * * * 

(14) ASME/ANSI PTC 19.10–1981, 

Flue and Exhaust Gas Analyses [Part 10, 

Instruments and Apparatus], (Issued 

August 31, 1981), IBR approved for 

§§ 60.56c(b), 60.63(f), 60.106(e), 

60.104a(d), (h), (i), and (j), 60.105a(d), 

(f), and (g), § 60.106a(a), § 60.107a(a), 

(c), and (d), tables 1 and 3 to subpart 

EEEE, tables 2 and 4 to subpart FFFF, 

table 2 to subpart JJJJ, § 60.285a(f), 

§§ 60.4415(a), 60.2145(s) and (t), 

60.2710(s) (t), and (w), 60.2730(q), 

60.4900(b), 60.5220(b), tables 1 and 2 to 

subpart LLLL, tables 2 and 3 to subpart 

MMMM, §§ 60.5406(c) and 60.5413(b), 

§ 60.5406a(c), § 60.5407a(g), 

§§ 60.5413a(b) and 60.5413a(d). 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56661 

Subpart OOOO—Standards of 

Performance for Crude Oil and Natural 

Gas Production, Transmission and 

Distribution for which Construction, 

Modification or Reconstruction 

Commenced after August 23, 2011, and 

on or before September 18, 2015 

■ 3. The heading for Subpart OOOO is 

revised to read as set forth above. 

■ 4. Section 60.5360 is revised to read 

as follows: 

§ 60.5360 What is the purpose of this 

subpart? 

This subpart establishes emission 

standards and compliance schedules for 

the control of volatile organic 

compounds (VOC) and sulfur dioxide 

(SO2) emissions from affected facilities 

that commence construction, 

modification or reconstruction after 

August 23, 2011, and on or before 

September 18, 2015. 

■ 5. Section 60.5365 is amended by: 

■ a. Revising the introductory text; and 

■ b. Revising paragraph (h)(4). 

The revisions read as follows: 

§ 60.5365 Am I subject to this subpart? 

You are subject to the applicable 

provisions of this subpart if you are the 

owner or operator of one or more of the 

onshore affected facilities listed in 

paragraphs (a) through (g) of this section 

for which you commence construction, 

modification or reconstruction after 

August 23, 2011, and on or before 

September 18, 2015. 

* * * * * 

(h)* * * 

(4) A gas well facility initially 

constructed after August 23, 2011, and 

on or before September 18, 2015 is 

considered an affected facility 

regardless of this provision. 

■ 6. Section 60.5370 is amended by 

adding paragraph (d) to read as follows: 

§ 60.5370 When must I comply with this 

subpart? 

* * * * * 

(d) You are deemed to be in 

compliance with this subpart if you are 

in compliance with all applicable 

provisions of subpart OOOOa of this 

part. 

■ 7. Section 60.5411 is amended by: 

revising paragraphs (a)(3)(i)(A) and 

(c)(3)(i)(A) to read as follows: 

§ 60.5411 What additional requirements 

must I meet to determine initial compliance 

for my covers and closed vent systems 

routing materials from storage vessels and 

centrifugal compressor wet seal degassing 

systems? 

* * * * * 

(a) * * * 

(3) * * * 

(i) * * * 

(A) You must properly install, 

calibrate, maintain, and operate a flow 

indicator at the inlet to the bypass 

device that could divert the stream away 

from the control device or process to the 

atmosphere. Set the flow indicator to 

trigger an audible alarm, and initiate 

notification via remote alarm to the 

nearest field office, when the bypass 

device is open such that the stream is 

being, or could be, diverted away from 

the control device or process to the 

atmosphere. You must maintain records 

of each time the alarm is activated 

according to § 60.5420(c)(8). 

* * * * * 

(c)* * * 

(3)* * * 

(i) * * * 

(A) You must properly install, 

calibrate, maintain, and operate a flow 

indicator at the inlet to the bypass 

device that could divert the stream away 

from the control device or process to the 

atmosphere. Set the flow indicator to 

trigger an audible alarm and initiate 

notification via remote alarm to the 

nearest field office, when the bypass 

device is open such that the stream is 

being, or could be, diverted away from 

the control device or process to the 

atmosphere. You must maintain records 

of each time the alarm is activated 

according to § 60.5420(c)(8). 

* * * * * 

■ 8. Section 60.5412 is amended by: 

■ a. Revising paragraphs (a)(1)(ii) and 

(d)(1) introductory text; and 

■ b. Adding paragraph (d)(1)(iv). 

The revisions and addition read as 

follows: 

§ 60.5412 What additional requirements 

must I meet for determining initial 

compliance with control devices used to 

comply with the emission standards for my 

storage vessel or centrifugal compressor 

affected facility? 

* * * * * 

(a) * * * 

(1) * * * 

(ii) You must reduce the 

concentration of TOC in the exhaust 

gases at the outlet to the device to a 

level equal to or less than 600 parts per 

million by volume as propane on a dry 

basis corrected to 3 percent oxygen as 

determined in accordance with the 

requirements of § 60.5413. 

* * * * * 

(d) * * * 

(1) Each enclosed combustion device 

(e.g., thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) must be designed to reduce the 

mass content of VOC emissions by 95.0 

percent or greater. You must follow the 

requirements in paragraphs (d)(1)(i) 

through (iv) of this section. 

* * * * * 

(iv) Each combustion control device 

(e.g., thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) must be designed and operated 

in accordance with one of the 

performance requirements specified in 

paragraphs (A) through (D) of this 

section. 

(A) You must reduce the mass content 

of methane and VOC in the gases vented 

to the device by 95.0 percent by weight 

or greater as determined in accordance 

with the requirements of § 60.5413. 

(B) You must reduce the 

concentration of TOC in the exhaust 

gases at the outlet to the device to a 

level equal to or less than 600 parts per 

million by volume as propane on a dry 

basis corrected to 3 percent oxygen as 

determined in accordance with the 

requirements of § 60.5413. 

(C) You must operate at a minimum 

temperature of 760°C for a control 

device that can demonstrate a uniform 

combustion zone temperature during 

the performance test conducted under 

§ 60.5413. 

(D) If a boiler or process heater is used 

as the control device, then you must 

introduce the vent stream into the flame 

zone of the boiler or process heater. 

* * * * * 

■ 9. Section 60.5413 is amended by 

revising paragraph (e)(3) to read as 

follows: 

§ 60.5413 What are the performance 

testing procedures for control devices used 

to demonstrate compliance at my storage 

vessel or centrifugal compressor affected 

facility? 

* * * * * 

(e) * * * 

(3) Devices must be operated with no 

visible emissions, except for periods not 

to exceed a total of 1 minute during any 

15-minute period. A visible emissions 

test conducted according to section 11 

of EPA Method 22, 40 CFR part 60, 

appendix A, must be performed at least 

once every calendar month, separated 

by at least 15 days between each test. 

The observation period shall be 15 

minutes. 

* * * * * 

■ 10. Section 60.5415 is amended by 

revising paragraph (b)(2)(vii)(B) to read 

as follows: 

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56662 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

§ 60.5415 How do I demonstrate 

continuous compliance with the standards 

for my gas well affected facility, my 

centrifugal compressor affected facility, my 

stationary reciprocating compressor 

affected facility, my pneumatic controller 

affected facility, my storage vessel affected 

facility, and my affected facilities at onshore 

natural gas processing plants? 

* * * * * 

(b) * * * 

(2) * * * 

(vii) * * * 

(B) Devices must be operated with no 

visible emissions, except for periods not 

to exceed a total of 1 minute during any 

15-minute period. A visible emissions 

test conducted according to section 11 

of Method 22, 40 CFR part 60, appendix 

A, must be performed at least once 

every calendar month, separated by at 

least 15 days between each test. The 

observation period shall be 15 minutes. 

* * * * * 

■ 11. Section 60.5416 is amended by 

revising paragraph (c)(3)(i) to read as 

follows: 

§ 60.5416 What are the initial and 

continuous cover and closed vent system 

inspection and monitoring requirements for 

my storage vessel and centrifugal 

compressor affected facility? 

* * * * * 

(c) * * * 

(3) * * * 

(i) You must properly install, calibrate 

and maintain a flow indicator at the 

inlet to the bypass device that could 

divert the stream away from the control 

device or process to the atmosphere. Set 

the flow indicator to trigger an audible 

alarm, and initiate notification via 

remote alarm to the nearest field office, 

when the bypass device is open such 

that the stream is being, or could be, 

diverted away from the control device 

or process to the atmosphere. You must 

maintain records of each time the alarm 

is activated according to § 60.5420(c)(8). 

* * * * * 

■ 12. Section 60.5417 is amended by 

adding paragraph (h)(4) to read as 

follows: 

§ 60.5417 What are the continuous control 

device monitoring requirements for my 

storage vessel or centrifugal compressor 

affected facility? 

* * * * * 

(h) * * * 

(4) Conduct a periodic performance 

test no later than 60 months after the 

initial performance test as specified in 

§ 60.5413(b)(5)(ii) and conduct 

subsequent periodic performance tests 

at intervals no longer than 60 months 

following the previous periodic 

performance test. 

■ 13. Section 60.5420 is amended by: 

■ a. Revising paragraph (c) introductory 

text; and 

■ b. Adding paragraph (c)(14). 

The revision and addition reads as 

follows: 

§ 60.5420 What are my notification, 

reporting, and recordkeeping 

requirements? 

* * * * * 

(c) Recordkeeping requirements. You 

must maintain the records identified as 

specified in § 60.7(f) and in paragraphs 

(c)(1) through (14) of this section. All 

records required by this subpart must be 

maintained either onsite or at the 

nearest local field office for at least 5 

years. 

* * * * * 

(14) A log of records as specified in 

§§ 60.5412(d)(1)(iii) and 60.5413(e)(4) 

for all inspection, repair and 

maintenance activities for each control 

devices failing the visible emissions 

test. 

■ 14. Section 60.5430 is revised by: 

■ a. Adding, in alphabetical order, a 

definition for the term ‘‘capital 

expenditure;’’ and 

■ b. Revising the definition for ‘‘group 2 

storage vessel.’’ 

The addition and revision read as 

follows: 

§ 60.5430 What definitions apply to this 

subpart? 

* * * * * 

Capital expenditure means, in 

addition to the definition in 40 CFR 

60.2, an expenditure for a physical or 

operational change to an existing facility 

that: 

(1) Exceeds P, the product of the 

facility’s replacement cost, R, and an 

adjusted annual asset guideline repair 

allowance, A, as reflected by the 

following equation: P = R × A, where 

(i) The adjusted annual asset 

guideline repair allowance, A, is the 

product of the percent of the 

replacement cost, Y, and the applicable 

basic annual asset guideline repair 

allowance, B, divided by 100 as 

reflected by the following equation: 

A = Y × (B ÷ 100); 

(ii) The percent Y is determined from 

the following equation: Y = 1.0 ¥ 0.575 

log X, where X is 2011 minus the year 

of construction; and 

(iii) The applicable basic annual asset 

guideline repair allowance, B, is 4.5. 

* * * * * 

Group 2 storage vessel means a 

storage vessel, as defined in this section, 

for which construction, modification or 

reconstruction has commenced after 

April 12, 2013, and on or before 

September 18, 2015. 

* * * * * 

■ 15. Amend Table 3 to Subpart OOOO 

by revising entries ‘‘§ 60.15’’ and 

‘‘§ 60.18’’ to read as follows: 

TABLE 3 TO SUBPART OOOO OF PART 60—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART OOOO 

General 

provisions 

citation 

Subject of citation Applies to 

subpart? Explanation 

*******

§ 60.15 .............. Reconstruction ............................... Yes ................... Except that § 60.15(d) does not apply to pneumatic controllers, centrifugal compressors or storage vessels. 

*******

§ 60.18 .............. General control device requirements.Yes ...................

* * * * * * * 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56663 

■ 16. Add subpart OOOOa, consisting of 

sections 60.5360a through 60.5430a, to 

part 60 to read as follows: 

Subpart OOOOa—Standards of 

Performance for Crude Oil and Natural Gas 

Facilities for which Construction, 

Modification, or Reconstruction 

Commenced after September 18, 2015 

Sec. 

60.5360a What is the purpose of this 

subpart? 

60.5365a Am I subject to this subpart? 

60.5370a When must I comply with this 

subpart? 

60.5375a What methane and VOC standards 

apply to well affected facilities? 

60.5380a What methane and VOC standards 

apply to centrifugal compressor affected 

facilities? 

60.5385a What methane and VOC standards 

apply to reciprocating compressor 

affected facilities? 

60.5390a What methane and VOC standards 

apply to pneumatic controller affected 

facilities? 

60.5393a What methane and VOC standards 

apply to pneumatic pump affected 

facilities? 

60.5395a What VOC standards apply to 

storage vessel affected facilities? 

60.5397a What fugitive emissions methane 

and VOC standards apply to the 

collection of fugitive emissions 

components at a well site and the 

collection of fugitive emissions 

components at a compressor station? 

60.5400a What equipment leak methane 

and VOC standards apply to affected 

facilities at an onshore natural gas 

processing plant? 

60.5401a What are the exceptions to the 

equipment leak methane and VOC 

standards for affected facilities at 

onshore natural gas processing plants? 

60.5402a What are the alternative emission 

limitations for equipment leaks from 

onshore natural gas processing plants? 

60.5405a What standards apply to 

sweetening unit affected facilities at 

onshore natural gas processing plants? 

60.5406a What test methods and 

procedures must I use for my sweetening 

unit affected facilities at onshore natural 

gas processing plants? 

60.5407a What are the requirements for 

monitoring of emissions and operations 

from my sweetening unit affected 

facilities at onshore natural gas 

processing plants? 

60.5408a What is an optional procedure for 

measuring hydrogen sulfide in acid gas— 

Tutwiler Procedure? 

60.5410a How do I demonstrate initial 

compliance with the standards for my 

well, centrifugal compressor, 

reciprocating compressor, pneumatic 

controller, pneumatic pump, storage 

vessel, collection of fugitive emissions 

components at a well site, and collection 

of fugitive emissions components at a 

compressor station, and equipment leaks 

and sweetening unit affected facilities at 

onshore natural gas processing plants? 

60.5411a What additional requirements 

must I meet to determine initial 

compliance for my covers and closed 

vent systems routing emissions from 

centrifugal compressor wet seal fluid 

degassing systems, reciprocating 

compressors, pneumatic pump and 

storage vessels? 

60.5412a What additional requirements 

must I meet for determining initial 

compliance with control devices used to 

comply with the emission standards for 

my centrifugal compressor, pneumatic 

pump and storage vessel affected 

facilities? 

60.5413a What are the performance testing 

procedures for control devices used to 

demonstrate compliance at my 

centrifugal compressor, pneumatic pump 

and storage vessel affected facilities? 

60.5415a How do I demonstrate continuous 

compliance with the standards for my 

well, centrifugal compressor, 

reciprocating compressor, pneumatic 

controller, pneumatic pump, storage 

vessel, collection of fugitive emissions 

components at a well site, and collection 

of fugitive emissions components at a 

compressor station affected facilities, 

and affected facilities at onshore natural 

gas processing plants? 

60.5416a What are the initial and 

continuous cover and closed vent system 

inspection and monitoring requirements 

for my centrifugal compressor, 

reciprocating compressor, pneumatic 

pump, and storage vessel affected 

facilities? 

60.5417a What are the continuous control 

device monitoring requirements for my 

centrifugal compressor, pneumatic 

pump, and storage vessel affected 

facilities? 

60.5420a What are my notification, 

reporting, and recordkeeping 

requirements? 

60.5421a What are my additional 

recordkeeping requirements for my 

affected facility subject to methane and 

VOC requirements for onshore natural 

gas processing plants? 

60.5422a What are my additional reporting 

requirements for my affected facility 

subject to methane and VOC 

requirements for onshore natural gas 

processing plants? 

60.5423a What additional recordkeeping 

and reporting requirements apply to my 

sweetening unit affected facilities at 

onshore natural gas processing plants? 

60.5425a What parts of the General 

Provisions apply to me? 

60.5430a What definitions apply to this 

subpart? 

60.5431a–60.5499a [Reserved] 

Table 1 to Subpart OOOOa of Part 60— 

Required Minimum Initial SO2 Emission 

Reduction Efficiency (Zi) 

Table 2 to Subpart OOOOa of Part 60— 

Required Minimum SO2Emission 

Reduction Efficiency (Zc) 

Table 3 to Subpart OOOOa of Part 60— 

Applicability of General Provisions to 

Subpart OOOOa 

Subpart OOOOa—Standards of 

Performance for Crude Oil and Natural 

Gas Facilities for which Construction, 

Modification or Reconstruction 

Commenced After September 18, 2015 

§ 60.5360a What is the purpose of this 

subpart? 

This subpart establishes emission 

standards and compliance schedules for 

the control of methane, volatile organic 

compounds (VOC) and sulfur dioxide 

(SO2) emissions from affected facilities 

in the crude oil and natural gas source 

category that commence construction, 

modification or reconstruction after 

September 18, 2015. The effective date 

of the rule is [date 60 days after 

publication of final rule in the Federal 

Register]. 

§ 60.5365a Am I subject to this subpart? 

You are subject to the applicable 

provisions of this subpart if you are the 

owner or operator of one or more of the 

onshore affected facilities listed in 

paragraphs (a) through (j) of this section 

for which you commence construction, 

modification or reconstruction after 

September 18, 2015. 

(a) Each well affected facility, which 

is a single well that conducts a well 

completion operation following 

hydraulic fracturing or refracturing and 

has a gas-to-oil ratio of greater than 300 

scf of gas per barrel of oil produced. The 

provisions of this paragraph do not 

affect the affected facility status of well 

sites for the purposes of § 60.5397a. The 

provisions of paragraphs (a)(1) through 

(4) of this section apply to wells that are 

hydraulically refractured: 

(1) A well that conducts a well 

completion operation following 

hydraulic refracturing is not an affected 

facility, provided that the requirements 

of § 60.5375a(a)(1) through (4) are met. 

However, hydraulic refracturing of a 

well constitutes a modification of the 

well site for purposes of § 60.5397a, 

regardless of affected facility status of 

the well itself. 

(2) A well completion operation 

following hydraulic refracturing not 

conducted pursuant to § 60.5375a(a)(1) 

through (4) is a modification to the well. 

(3) Refracturing of a well does not 

affect the modification status of other 

equipment, process units, storage 

vessels, compressors, pneumatic pumps, 

or pneumatic controllers. 

(4) A well initially constructed after 

September 18, 2015, that conducts a 

well completion operation following 

hydraulic refracturing is considered an 

affected facility regardless of this 

provision. 

(b) Each centrifugal compressor 

affected facility, which is a single 

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centrifugal compressor using wet seals. 

A centrifugal compressor located at a 

well site, or an adjacent well site and 

servicing more than one well site, is not 

an affected facility under this subpart. 

(c) Each reciprocating compressor 

affected facility, which is a single 

reciprocating compressor. A 

reciprocating compressor located at a 

well site, or an adjacent well site and 

servicing more than one well site, is not 

an affected facility under this subpart. 

(d)(1) Each pneumatic controller 

affected facility not located at a natural 

gas processing plant, which is a single 

continuous bleed natural gas-driven 

pneumatic controller operating at a 

natural gas bleed rate greater than 6 

scfh. 

(2) Each pneumatic controller affected 

facility located at a natural gas 

processing plant, which is a single 

continuous bleed natural gas-driven 

pneumatic controller. 

(e) Each storage vessel affected 

facility, which is a single storage vessel 

with the potential for VOC emissions 

equal to or greater than 6 tpy as 

determined according to this section, 

except as provided in paragraphs (e)(1) 

through (4) of this section. The potential 

for VOC emissions must be calculated 

using a generally accepted model or 

calculation methodology, based on the 

maximum average daily throughput 

determined for a 30-day period of 

production prior to the applicable 

emission determination deadline 

specified in this section. The 

determination may take into account 

requirements under a legally and 

practically enforceable limit in an 

operating permit or other requirement 

established under a Federal, State, local 

or tribal authority. 

(1) For each new, modified or 

reconstructed storage vessel receiving 

liquids pursuant to the standards for 

well affected facilities in § 60.5375a, 

including wells subject to § 60.5375a(f), 

you must determine the potential for 

VOC emissions within 30 days after 

startup of production. 

(2) A storage vessel affected facility 

that subsequently has its potential for 

VOC emissions decrease to less than 6 

tpy shall remain an affected facility 

under this subpart. 

(3) For storage vessels not subject to 

a legally and practically enforceable 

limit in an operating permit or other 

requirement established under Federal, 

state, local or tribal authority, any vapor 

from the storage vessel that is recovered 

and routed to a process through a VRU 

designed and operated as specified in 

this section is not required to be 

included in the determination of VOC 

potential to emit for purposes of 

determining affected facility status, 

provided you comply with the 

requirements in paragraphs (e)(3)(i) 

through (iv) of this section. 

(i) You meet the cover requirements 

specified in § 60.5411a(b). 

(ii) You meet the closed vent system 

requirements specified in § 60.5411a(c). 

(iii) You maintain records that 

document compliance with paragraphs 

(e)(3)(i) and (ii) of this section. 

(iv) In the event of removal of 

apparatus that recovers and routes vapor 

to a process, or operation that is 

inconsistent with the conditions 

specified in paragraphs (e)(3)(i) and (ii) 

of this section, you must determine the 

storage vessel’s potential for VOC 

emissions according to this section 

within 30 days of such removal or 

operation. 

(4) For each new, reconstructed, or 

modified storage vessel with startup, 

startup of production, or which is 

returned to service, affected facility 

status is determined as follows: If a 

storage vessel is reconnected to the 

original source of liquids or is used to 

replace any storage vessel affected 

facility, it is a storage vessel affected 

facility subject to the same requirements 

as before being removed from service, or 

applicable to the storage vessel affected 

facility being replaced, immediately 

upon startup, startup of production, or 

return to service. 

(f) The group of all equipment, except 

compressors, within a process unit is an 

affected facility. 

(1) Addition or replacement of 

equipment for the purpose of process 

improvement that is accomplished 

without a capital expenditure shall not 

by itself be considered a modification 

under this subpart. 

(2) Equipment associated with a 

compressor station, dehydration unit, 

sweetening unit, underground storage 

vessel, field gas gathering system, or 

liquefied natural gas unit is covered by 

§§ 60.5400a, 60.5401a, 60.5402a, 

60.5421a, and 60.5422a of this subpart 

if it is located at an onshore natural gas 

processing plant. Equipment not located 

at the onshore natural gas processing 

plant site is exempt from the provisions 

of §§ 60.5400a, 60.5401a, 60.5402a, 

60.5421a, and 60.5422a of this subpart. 

(3) The equipment within a process 

unit of an affected facility located at 

onshore natural gas processing plants 

and described in paragraph (f) of this 

section are exempt from this subpart if 

they are subject to and controlled 

according to subparts VVa, GGG or 

GGGa of this part. 

(g) Sweetening units located at 

onshore natural gas processing plants 

that process natural gas produced from 

either onshore or offshore wells. 

(1) Each sweetening unit that 

processes natural gas is an affected 

facility; and 

(2) Each sweetening unit that 

processes natural gas followed by a 

sulfur recovery unit is an affected 

facility. 

(3) Facilities that have a design 

capacity less than 2 long tons per day 

(LT/D) of hydrogen sulfide (H2S) in the 

acid gas (expressed as sulfur) are 

required to comply with recordkeeping 

and reporting requirements specified in 

§ 60.5423a(c) but are not required to 

comply with §§ 60.5405a through 

60.5407a and §§ 60.5410a(g) and 

60.5415a(g) of this subpart. 

(4) Sweetening facilities producing 

acid gas that is completely reinjected 

into oil-or-gas-bearing geologic strata or 

that is otherwise not released to the 

atmosphere are not subject to 

§§ 60.5405a through 60.5407a, 

60.5410a(g), 60.5415a(g), and 60.5423a 

of this subpart. 

(h)(1) For natural gas processing 

plants, each pneumatic pump affected 

facility, which is a single natural gasdriven chemical/methanol pump or 

natural gas-driven diaphragm pump. 

(2) For locations other than natural 

gas processing plants, each pneumatic 

pump affected facility, which is a single 

natural gas-driven chemical/methanol 

pump or natural gas-driven diaphragm 

pump for which a control device is 

located on site. 

(i) Except as provided in 

§ 60.5365a(i)(1) through (i)(2), the 

collection of fugitive emissions 

components at a well site, as defined in 

§ 60.5430a, is an affected facility. 

(1) A well site with average combined 

oil and natural gas production for the 

wells at the site being less than 15 

barrels of oil equivalent (boe) per day 

averaged over the first 30 days of 

production, is not an affected facility 

under this subpart. 

(2) A well site that only contains one 

or more wellheads is not an affected 

facility under this subpart. 

(3) For purposes of § 60.5397a, a 

‘‘modification’’ to a well site occurs 

when: 

(i) A new well is drilled at an existing 

well site; 

(ii) A well at an existing well site is 

hydraulically fractured; or 

(iii) A well at an existing well site is 

hydraulically refractured. 

(j) The collection of fugitive emissions 

components at a compressor station, as 

defined in § 60.5430a, is an affected 

facility. For purposes of § 60.5397a, a 

‘‘modification’’ to a compressor station 

occurs when: 

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(1) A new compressor is constructed 

at an existing compressor station; or 

(2) A physical change is made to an 

existing compressor at a compressor 

station that increases the compression 

capacity of the compressor station. 

(3) Reserved 

§ 60.5370a When must I comply with this 

subpart? 

(a) You must be in compliance with 

the standards of this subpart no later 

than [date 60 days after publication of 

final rule in the Federal Register] or 

upon startup, whichever is later. 

(b) The provisions for exemption from 

compliance during periods of startup, 

shutdown and malfunctions provided 

for in 40 CFR 60.8(c) do not apply to 

this subpart. 

(c) You are exempt from the 

obligation to obtain a permit under 40 

CFR part 70 or 40 CFR part 71, provided 

you are not otherwise required by law 

to obtain a permit under 40 CFR 70.3(a) 

or 40 CFR 71.3(a). Notwithstanding the 

previous sentence, you must continue to 

comply with the provisions of this 

subpart. 

§ 60.5375a What methane and VOC 

standards apply to well affected facilities? 

If you are the owner or operator of a 

well affected facility, you must reduce 

methane and VOC emissions by 

complying with paragraphs (a) through 

(f) of this section. 

(a) Except as provided in paragraph (f) 

of this section, for each well completion 

operation with hydraulic fracturing you 

must comply with the requirements in 

paragraphs (a)(1) through (4) of this 

section. You must maintain a log as 

specified in paragraph (b) of this 

section. 

(1) For each stage of the well 

completion operation, as defined in 

§ 60.5430a, follow the requirements 

specified in paragraphs (a)(1)(i) and (ii) 

of this section. 

(i) During the initial flowback stage, 

route the flowback into one or more 

well completion vessels or storage 

vessels and commence operation of a 

separator unless it is technically 

infeasible for a separator to function. 

Any gas present in the initial flowback 

stage is not subject to control under this 

section. 

(ii) During the separation flowback 

stage, route all recovered liquids from 

the separator to one or more well 

completion vessels or storage vessels, 

re-inject the recovered liquids into the 

well or another well or route the 

recovered liquids to a collection system. 

Route the recovered gas from the 

separator into a gas flow line or 

collection system, re-inject the 

recovered gas into the well or another 

well, use the recovered gas as an on-site 

fuel source, or use the recovered gas for 

another useful purpose that a purchased 

fuel or raw material would serve. If it is 

technically infeasible to route the 

recovered gas as required above, follow 

the requirements in paragraph (a)(3) of 

this section. If, at any time during the 

separation flowback stage, it is not 

technically feasible for a separator to 

function, you must comply with (a)(1)(i) 

of this section. 

(2) All salable quality recovered gas 

must be routed to the gas flow line as 

soon as practicable. In cases where 

salable quality gas cannot be directed to 

the flow line due to technical 

infeasibility, you must follow the 

requirements in paragraph (a)(3) of this 

section. 

(3) You must capture and direct 

recovered gas to a completion 

combustion device, except in conditions 

that may result in a fire hazard or 

explosion, or where high heat emissions 

from a completion combustion device 

may negatively impact tundra, 

permafrost or waterways. Completion 

combustion devices must be equipped 

with a reliable continuous ignition 

source. 

(4) You have a general duty to safely 

maximize resource recovery and 

minimize releases to the atmosphere 

during flowback and subsequent 

recovery. 

(b) You must maintain a log for each 

well completion operation at each well 

affected facility. The log must be 

completed on a daily basis for the 

duration of the well completion 

operation and must contain the records 

specified in § 60.5420a(c)(1)(iii). 

(c) You must demonstrate initial 

compliance with the standards that 

apply to well affected facilities as 

required by § 60.5410a. 

(d) You must demonstrate continuous 

compliance with the standards that 

apply to well affected facilities as 

required by § 60.5415a. 

(e) You must perform the required 

notification, recordkeeping and 

reporting as required by § 60.5420a. 

(f)(1) For each well affected facility 

specified in paragraphs (f)(1)(i) and (ii) 

of this section, you must comply with 

the requirements of paragraphs (f)(2) 

and (3) of this section. 

(i) Each well completion operation 

with hydraulic fracturing at a wildcat or 

delineation well. 

(ii) Each well completion operation 

with hydraulic fracturing at a nonwildcat low pressure well or nondelineation low pressure well. 

(2) Route the flowback into one or 

more well completion vessels and 

commence operation of a separator 

unless it is technically infeasible for a 

separator to function. Any gas present in 

the flowback before the separator can 

function is not subject to control under 

this section. You must capture and 

direct recovered gas to a completion 

combustion device, except in conditions 

that may result in a fire hazard or 

explosion, or where high heat emissions 

from a completion combustion device 

may negatively impact tundra, 

permafrost or waterways. Completion 

combustion devices must be equipped 

with a reliable continuous ignition 

source. You must also comply with 

paragraphs (a)(4) and (b) through (e) of 

this section. 

(3) You must maintain records 

specified in § 60.5420a(c)(1)(iii) for 

wildcat, delineation and low pressure 

wells. 

§ 60.5380a What methane and VOC 

standards apply to centrifugal compressor 

affected facilities? 

You must comply with the methane 

and VOC standards in paragraphs (a) 

through (d) of this section for each 

centrifugal compressor affected facility. 

(a)(1) You must reduce methane and 

VOC emissions from each centrifugal 

compressor wet seal fluid degassing 

system by 95.0 percent or greater. 

(2) If you use a control device to 

reduce emissions, you must equip the 

wet seal fluid degassing system with a 

cover that meets the requirements of 

§ 60.5411a(b). The cover must be 

connected through a closed vent system 

that meets the requirements of 

§ 60.5411a(a) and the closed vent system 

must be routed to a control device that 

meets the conditions specified in 

§ 60.5412a(a), (b) and (c). As an 

alternative to routing the closed vent 

system to a control device, you may 

route the closed vent system to a 

process. 

(b) You must demonstrate initial 

compliance with the standards that 

apply to centrifugal compressor affected 

facilities as required by § 60.5410a(b). 

(c) You must demonstrate continuous 

compliance with the standards that 

apply to centrifugal compressor affected 

facilities as required by § 60.5415a(b). 

(d) You must perform the required 

notification, recordkeeping, and 

reporting as required by § 60.5420a. 

§ 60.5385a What methane and VOC 

standards apply to reciprocating 

compressor affected facilities? 

You must reduce methane and VOC 

emissions by complying with the 

standards in paragraphs (a) through (d) 

of this section for each reciprocating 

compressor affected facility. 

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(a) You must replace the reciprocating 

compressor rod packing according to 

either paragraph (a)(1) or (2) of this 

section or you must comply with 

paragraph (a)(3) of this section. 

(1) Before the compressor has 

operated for 26,000 hours. The number 

of hours of operation must be 

continuously monitored beginning upon 

initial startup of your reciprocating 

compressor affected facility, or the date 

of the most recent reciprocating 

compressor rod packing replacement, 

whichever is later. 

(2) Prior to 36 months from the date 

of the most recent rod packing 

replacement, or 36 months from the date 

of startup for a new reciprocating 

compressor for which the rod packing 

has not yet been replaced. 

(3) Collect the methane and VOC 

emissions from the rod packing using a 

rod packing emissions collection system 

which operates under negative pressure 

and route the rod packing emissions to 

a process through a closed vent system 

that meets the requirements of 

§ 60.5411a(a). 

(b) You must demonstrate initial 

compliance with standards that apply to 

reciprocating compressor affected 

facilities as required by § 60.5410a. 

(c) You must demonstrate continuous 

compliance with standards that apply to 

reciprocating compressor affected 

facilities as required by § 60.5415a. 

(d) You must perform the required 

notification, recordkeeping, and 

reporting as required by § 60.5420a. 

§ 60.5390a What methane and VOC 

standards apply to pneumatic controller 

affected facilities? 

For each pneumatic controller 

affected facility you must comply with 

the methane and VOC standards, based 

on natural gas as a surrogate for 

methane and VOC, in either paragraph 

(b)(1) or (c)(1) of this section, as 

applicable. Pneumatic controllers 

meeting the conditions in paragraph (a) 

of this section are exempt from this 

requirement. 

(a) The requirements of paragraph 

(b)(1) or (c)(1) of this section are not 

required if you determine that the use 

of a pneumatic controller affected 

facility with a bleed rate greater than the 

applicable standard is required based on 

functional needs, including but not 

limited to response time, safety and 

positive actuation. However, you must 

tag such pneumatic controller with the 

month and year of installation, 

reconstruction or modification, and 

identification information that allows 

traceability to the records for that 

pneumatic controller, as required in 

§ 60.5420a(c)(4)(ii). 

(b)(1) Each pneumatic controller 

affected facility at a natural gas 

processing plant must have a bleed rate 

of zero. 

(2) Each pneumatic controller affected 

facility at a natural gas processing plant 

must be tagged with the month and year 

of installation, reconstruction or 

modification, and identification 

information that allows traceability to 

the records for that pneumatic controller 

as required in § 60.5420a(c)(4)(iv). 

(c)(1) Each pneumatic controller 

affected facility at a location other than 

at a natural gas processing plant must 

have a bleed rate less than or equal to 

6 standard cubic feet per hour. 

(2) Each pneumatic controller affected 

facility constructed, modified or 

reconstructed on or after October 15, 

2013, at a location other than at a 

natural gas processing plant must be 

tagged with the month and year of 

installation, reconstruction or 

modification, and identification 

information that allows traceability to 

the records for that controller as 

required in § 60.5420a(c)(4)(iii). 

(d) You must demonstrate initial 

compliance with standards that apply to 

pneumatic controller affected facilities 

as required by § 60.5410a. 

(e) You must demonstrate continuous 

compliance with standards that apply to 

pneumatic controller affected facilities 

as required by § 60.5415a. 

(f) You must perform the required 

notification, recordkeeping, and 

reporting as required by § 60.5420a, 

except that you are not required to 

submit the notifications specified in 

§ 60.5420a(a). 

§ 60.5393a What methane and VOC 

standards apply to pneumatic pump 

affected facilities? 

For each pneumatic pump affected 

facility you must comply with the 

methane and VOC standards, based on 

natural gas as a surrogate for methane 

and VOC, in either paragraph (a)(1) or 

(b)(1) of this section, as applicable. 

(a)(1) Each pneumatic pump affected 

facility at a natural gas processing plant 

must have a natural gas emission rate of 

zero. 

(2) Each pneumatic pump affected 

facility at a natural gas processing plant 

must be tagged with the month and year 

of installation, reconstruction or 

modification, and identification 

information that allows traceability to 

the records for that pneumatic pump as 

required in § 60.5420a(c)(16)(i). 

(b)(1) Each pneumatic pump affected 

facility at a location other than a natural 

gas processing plant must reduce 

natural gas emissions by 95.0 percent, 

except as provided in paragraph (b)(2) of 

this section. 

(2) You are not required to install a 

control device solely for the purposes of 

complying with the 95.0 percent 

reduction of paragraph (b)(1) of this 

section. If you do not have a control 

device installed on-site by the 

compliance date, then you must comply 

instead with the provisions of 

paragraphs (b)(2)(i) and (ii) of this 

section. 

(i) Submit a certification in 

accordance with § 60.5420(b)(8)(i). 

(ii) If you subsequently install a 

control device, you are no longer 

required to submit the certification in 

§ 60.5420(b)(8)(i) and must be in 

compliance with the requirements of 

paragraph (b)(1) of this section within 

30 days of installation of the control 

device. Compliance with this 

requirement should be reported in the 

next annual report in accordance with 

§ 60.5420(b)(8)(iii). 

(3) Each pneumatic pump affected 

facility at a location other than a natural 

gas processing plant must be tagged 

with the month and year of installation, 

reconstruction or modification, and 

identification information that allows 

traceability to the records for that pump 

as required in § 60.5420a(c)(16)(i). 

(4) If you use a control device to 

reduce emissions, you must connect the 

pneumatic pump affected facility 

through a closed vent system that meets 

the requirements of § 60.5411a(a) and 

route emissions to a control device that 

meets the conditions specified in 

§ 60.5412a(a), (b) and (c) and 

performance tested in accordance with 

§ 60.5413a. As an alternative to routing 

the closed vent system to a control 

device, you may route the closed vent 

system to a process. 

(c) You must demonstrate initial 

compliance with standards that apply to 

pneumatic pump affected facilities as 

required by § 60.5410a. 

(d) You must demonstrate continuous 

compliance with standards that apply to 

pneumatic pump affected facilities as 

required by § 60.5415a. 

(e) You must perform the required 

notification, recordkeeping, and 

reporting as required by § 60.5420a, 

except that you are not required to 

submit the notifications specified in 

§ 60.5420a(a). 

§ 60.5395a What VOC standards apply to 

storage vessel affected facilities? 

Except as provided in paragraph (e) of 

this section, you must comply with the 

VOC standards in this section for each 

storage vessel affected facility. 

(a) You must comply with either the 

requirements of paragraphs (a)(1) and 

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(a)(2) or the requirements of paragraph 

(a)(3) of this section. If you choose to 

meet the requirements in paragraph 

(a)(3) of this section, you are not 

required to comply with the 

requirements of paragraph (a)(2) of this 

section except as provided in 

paragraphs (a)(3)(i) and (ii) of this 

section. 

(1) Determine potential for VOC 

emissions in accordance with 

§ 60.5365a(e). 

(2) Reduce VOC emissions by 95.0 

percent within 60 days after startup. For 

storage vessel affected facilities 

receiving liquids pursuant to the 

standards for well affected facilities in 

§ 60.5375a, you must achieve the 

required emissions reductions within 60 

days after startup of production as 

defined in § 60.5430a. 

(3) Maintain the uncontrolled actual 

VOC emissions from the storage vessel 

affected facility at less than 4 tpy 

without considering control. Prior to 

using the uncontrolled actual VOC 

emission rate for compliance purposes, 

you must demonstrate that the 

uncontrolled actual VOC emissions 

have remained less than 4 tpy as 

determined monthly for 12 consecutive 

months. After such demonstration, you 

must determine the uncontrolled actual 

VOC emission rate each month. The 

uncontrolled actual VOC emissions 

must be calculated using a generally 

accepted model or calculation 

methodology, and the calculations must 

be based on the average throughput for 

the month. You must comply with 

paragraph (a)(2) of this section if your 

storage vessel affected facility meets the 

conditions specified in paragraphs 

(a)(3)(i) or (ii) of this section. 

(i) If a well feeding the storage vessel 

affected facility undergoes fracturing or 

refracturing, you must comply with 

paragraph (a)(2) of this section as soon 

as liquids from the well following 

fracturing or refracturing are routed to 

the storage vessel affected facility. 

(ii) If the monthly emissions 

determination required in this section 

indicates that VOC emissions from your 

storage vessel affected facility increase 

to 4 tpy or greater and the increase is 

not associated with fracturing or 

refracturing of a well feeding the storage 

vessel affected facility, you must 

comply with paragraph (a)(2) of this 

section within 30 days of the monthly 

determination. 

(b) Control requirements. (1) Except as 

required in paragraph (b)(2) of this 

section, if you use a control device to 

reduce VOC emissions from your 

storage vessel affected facility, you must 

equip the storage vessel with a cover 

that meets the requirements of 

§ 60.5411a(b) and is connected through 

a closed vent system that meets the 

requirements of § 60.5411a(c), and you 

must route emissions to a control device 

that meets the conditions specified in 

§ 60.5412a(c) and (d). As an alternative 

to routing the closed vent system to a 

control device, you may route the closed 

vent system to a process that reduces 

VOC emissions by at least 95.0 percent. 

(2) If you use a floating roof to reduce 

emissions, you must meet the 

requirements of § 60.112b(a)(1) or (2) 

and the relevant monitoring, inspection, 

recordkeeping, and reporting 

requirements in 40 CFR part 60, subpart 

Kb. 

(c) Requirements for storage vessel 

affected facilities that are removed from 

service or returned to service. If you 

remove a storage vessel affected facility 

from service, you must comply with 

paragraphs (c)(1) through (3) of this 

section. A storage vessel is not an 

affected facility under this subpart for 

the period that it is removed from 

service. 

(1) For a storage vessel affected 

facility to be removed from service, you 

must comply with the requirements of 

paragraph (c)(1)(i) and (ii) of this 

section. 

(i) You must completely empty and 

degas the storage vessel, such that the 

storage vessel no longer contains crude 

oil, condensate, produced water or 

intermediate hydrocarbon liquids. A 

storage vessel where liquid is left on 

walls, as bottom clingage or in pools 

due to floor irregularity is considered to 

be completely empty. 

(ii) You must submit a notification as 

required in § 60.5420a(b)(6)(v) in your 

next annual report, identifying each 

storage vessel affected facility removed 

from service during the reporting period 

and the date of its removal from service. 

(2) If a storage vessel identified in 

paragraph (c)(1)(ii) of this section is 

returned to service, you must determine 

its affected facility status as provided in 

§ 60.5365a(e). 

(3) For each storage vessel affected 

facility returned to service during the 

reporting period, you must submit a 

notification in your next annual report 

as required in § 60.5420a(b)(6)(vi), 

identifying each storage vessel affected 

facility and the date of its return to 

service. 

(d) Compliance, notification, 

recordkeeping, and reporting. You must 

comply with paragraphs (d)(1) through 

(3) of this section. 

(1) You must demonstrate initial 

compliance with standards as required 

by § 60.5410a(h) and (i). 

(2) You must demonstrate continuous 

compliance with standards as required 

by § 60.5415a(e)(3). 

(3) You must perform the required 

notification, recordkeeping and 

reporting as required by § 60.5420a. 

(e) Exemptions. This subpart does not 

apply to storage vessels subject to and 

controlled in accordance with the 

requirements for storage vessels in 40 

CFR part 60, subpart Kb, 40 CFR part 63, 

subparts G, CC, HH, or WW. 

§ 60.5397a What fugitive emissions 

methane and VOC standards apply to the 

affected facility which is the collection of 

fugitive emissions components at a well 

site and the affected facility which is the 

collection of fugitive emissions 

components at a compressor station? 

For each affected facility under 

§ 60.5365a(i) and (j), you must reduce 

methane and VOC emissions by 

complying with the requirements of 

paragraphs (a) through (l) of this section. 

These requirements are independent of 

the closed vent system and cover 

requirements in § 60.5411a. 

(a) You must monitor all fugitive 

emission components, as defined in 

60.5430a, in accordance with 

paragraphs (b) through (i) of this 

section. You must repair all sources of 

fugitive emissions in accordance with 

paragraph (j) of this section. You must 

keep records in accordance with 

paragraph (k) and report in accordance 

with paragraph (l) of this section. For 

purposes of this section, fugitive 

emissions are defined as: Any visible 

emission from a fugitive emissions 

component observed using optical gas 

imaging. 

(b) You must develop a corporatewide fugitive emissions monitoring plan 

that covers the collection of fugitive 

emissions components at well sites and 

compressor stations in accordance with 

paragraph (c) of this section, and you 

must develop a site-specific fugitive 

emissions monitoring plan specific to 

each collection of fugitive emissions 

components at a well site and each 

collection of fugitive emissions 

components at a compressor station in 

accordance with paragraph (d) of this 

section. Alternatively, you may develop 

a site-specific plan for each collection of 

fugitive emissions components at a well 

site and each collection of fugitive 

emissions components at a compressor 

station that covers the elements of both 

the corporate-wide and site-specific 

plans. 

(c) Your corporate-wide monitoring 

plan must include the elements 

specified in paragraphs (c)(1) through 

(8) of this section, as a minimum. 

(1) Frequency for conducting surveys. 

Surveys must be conducted at least as 

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frequently as required by paragraphs (f) 

through (i) of this section. 

(2) Technique for determining fugitive 

emissions. 

(3) Manufacturer and model number 

of fugitive emissions detection 

equipment to be used. 

(4) Procedures and timeframes for 

identifying and repairing fugitive 

emissions components from which 

fugitive emissions are detected, 

including timeframes for fugitive 

emission components that are unsafe to 

repair. Your repair schedule must meet 

the requirements of paragraph (j) of this 

section at a minimum. 

(5) Procedures and timeframes for 

verifying fugitive emission component 

repairs. 

(6) Records that will be kept and the 

length of time records will be kept. 

(7) Your plan must also include the 

elements specified in paragraphs 

(c)(7)(i) through (vii) of this section. 

(i) Verification that your optical gas 

imaging equipment meets the 

specifications of paragraphs (c)(7)(i)(A) 

and (B) of this section. This verification 

is an initial verification and may either 

be performed by the facility, by the 

manufacturer, or by a third-party. For 

the purposes of complying with the 

fugitives emissions monitoring program 

with optical gas imaging, a fugitive 

emission is defined as any visible 

emissions observed using optical gas 

imaging. 

(A) Your optical gas imaging 

equipment must be capable of imaging 

gases in the spectral range for the 

compound of highest concentration in 

the potential fugitive emissions. 

(B) Your optical gas imaging 

equipment must be capable of imaging 

a gas that is half methane, half propane 

at a concentration of ≤10,000 ppm at a 

flow rate of ≥60 g/hr from a quarter inch 

diameter orifice. 

(ii) Procedure for a daily verification 

check. 

(iii) Procedure for determining the 

operator’s maximum viewing distance 

from the equipment and how the 

operator will ensure that this distance is 

maintained. 

(iv) Procedure for determining 

maximum wind speed during which 

monitoring can be performed and how 

the operator will ensure monitoring 

occurs only at wind speeds below this 

threshold. 

(v) Procedures for conducting surveys, 

including the items specified in 

paragraphs (c)(7)(v)(A) through (C) of 

this section. 

(A) How the operator will ensure an 

adequate thermal background is present 

in order to view potential fugitive 

emissions. 

(B) How the operator will deal with 

adverse monitoring conditions, such as 

wind. 

(C) How the operator will deal with 

interferences (e.g., steam). 

(vi) Training and experience needed 

prior to performing surveys. 

(vii) Procedures for calibration and 

maintenance. Procedures must comply 

with those recommended by the 

manufacturer. 

(d) Your site-specific monitoring plan 

must include the elements specified in 

paragraphs (d)(1) through (3) of this 

section, as a minimum. 

(1) Deviations from your master plan. 

(2) Sitemap. 

(3) Your plan must also include your 

defined walking path. The walking path 

must ensure that all fugitive emissions 

components are within sight of the path 

and must account for interferences. 

(e) Each monitoring survey shall 

observe each fugitive emissions 

component for fugitive emissions. 

(f)(1) You must conduct an initial 

monitoring survey within 30 days of the 

first well completion for each collection 

of fugitive emissions components at a 

new well site or upon the date the well 

site begins the production phase for 

other wells. For a modified collection of 

fugitive emissions components at a well 

site, the initial monitoring survey must 

be conducted within 30 days of the well 

site modification. 

(2) You must conduct an initial 

monitoring survey within 30 days of the 

startup of a new compressor station for 

each new collection of fugitive 

emissions components at the new 

compressor station. For modified 

compressor stations, the initial 

monitoring survey of the collection of 

fugitive emissions components at a 

modified compressor station must be 

conducted within 30 days of the 

modification. 

(g) A monitoring survey of each 

collection of fugitive emissions 

components at a well site and collection 

of fugitive emissions components at a 

compressor station shall be conducted 

at least semiannually after the initial 

survey. Consecutive semiannual 

monitoring surveys shall be conducted 

at least 4 months apart. 

(h) The monitoring frequency 

specified in paragraph (g) of this section 

shall be increased to quarterly in the 

event that two consecutive semiannual 

monitoring surveys detect fugitive 

emissions at greater than 3.0 percent of 

the fugitive emissions components at a 

well site or at greater than 3.0 percent 

of the fugitive emissions components at 

a compressor station. 

(i) The monitoring frequency 

specified in paragraph (g) of this section 

may be decreased to annual in the event 

that two consecutive semiannual 

surveys detect fugitive emissions at less 

than 1.0 percent of the fugitive 

emissions components at a well site, or 

at less than 1.0 percent of the fugitive 

emissions components at a compressor 

station. The monitoring frequency shall 

return to semiannual if a survey detects 

fugitive emissions between 1.0 percent 

and 3.0 percent of the fugitive emissions 

components at the well site, or between 

1.0 percent and 3.0 percent of the 

fugitive emissions components at the 

compressor station. 

(j) For fugitive emissions components 

also subject to the repair provisions of 

§§ 60.5416a(b)(9) through (12) and (c)(4) 

through (7), those provisions apply 

instead to those closed vent system and 

covers, and the repair provisions of 

paragraphs (j)(1) and (2) of this section 

do not apply to those closed vent 

systems and covers. 

(1) Each identified source of fugitive 

emissions shall be repaired or replaced 

as soon as practicable, but no later than 

15 calendar days after detection of the 

fugitive emissions. If the repair or 

replacement is technically infeasible or 

unsafe to repair during operation of the 

unit, the repair or replacement must be 

completed during the next scheduled 

shutdown or within 6 months, 

whichever is earlier. 

(2) Each repaired or replaced fugitive 

emissions component must be 

resurveyed as soon as practicable, but 

no later than 15 days of finding such 

fugitive emissions, to ensure that there 

is no leak. 

(i) For repairs that cannot be made 

during the monitoring survey when the 

fugitive emissions are initially found, 

the operator may resurvey the repaired 

fugitive emissions components using 

either Method 21 or optical gas imaging 

within 15 days of finding such fugitive 

emissions. 

(ii) Operators that use Method 21 to 

resurvey the repaired fugitive emissions 

components, are subject to the resurvey 

provisions specified in paragraphs 

(j)(2)(ii)(A) and (B). 

(A) A fugitive emissions component is 

repaired when the Method 21 

instrument indicates a concentration of 

less than 500 ppm above background. 

(B) Operators must use the Method 21 

monitoring requirements specified in 

paragraph § 60.5401a(g). 

(iii) Operators that use optical gas 

imaging to resurvey the repaired fugitive 

emissions components, are subject to 

the resurvey provisions specified in 

paragraphs (j)(2)(iii)(A) and (B). 

(A) A fugitive emissions component is 

repaired when the optical gas imaging 

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instrument shows no indication of 

visible emissions. 

(B) Operators must use the optical gas 

imaging monitoring requirements 

specified in paragraph (a). 

(k) Records for each monitoring 

survey shall be maintained as specified 

§ 60.5420a(c)(15) and must contain, at a 

minimum, the information specified in 

paragraphs (k)(1) through (6) of this 

section. 

(1) Date of the survey. 

(2) Beginning and end time of the 

survey. 

(3) Name of operator(s) performing 

survey. You must note the training and 

experience of the operator. 

(4) Ambient temperature, sky 

conditions, and maximum wind speed 

at the time of the survey. 

(5) Any deviations from the 

monitoring plan or a statement that 

there were no deviations from the 

monitoring plan. 

(6) Documentation of each source of 

fugitive emissions (e.g., fugitive 

emissions components), including the 

information specified in paragraphs 

(k)(6)(i) through (ii) of this section. 

(i) Location. 

(ii) One or more digital photographs 

of each required monitoring survey 

being performed. The digital photograph 

must include the date the photograph 

was taken and the latitude and 

longitude of the well site or compressor 

station imbedded within or stored with 

the digital file. As an alternative to 

imbedded latitude and longitude within 

the digital photograph, the digital 

photograph may consist of a photograph 

of the monitoring survey being 

performed with a photograph of a 

separately operating GIS device within 

the same digital picture, provided the 

latitude and longitude output of the GIS 

unit can be clearly read in the digital 

photograph. 

(iii) The date of successful repair of 

the fugitive emissions component. 

(iv) The instrument used to resurvey 

a repaired fugitive emissions component 

that could not be repaired during the 

initial fugitive emissions finding. 

(l) Annual reports shall be submitted 

for each collection of fugitive emissions 

components at a well site and each 

collection of fugitive emissions 

components at a compressor station that 

include the information specified in 

§ 60.5420a(b)(7). Multiple collection of 

fugitive emissions components at a well 

site or collection of fugitive emissions at 

a compressor station may be included in 

a single annual report. 

§ 60.5400a What equipment leak methane 

and VOC standards apply to affected 

facilities at an onshore natural gas 

processing plant? 

This section applies to the group of all 

equipment, except compressors, within 

a process unit. 

(a) You must comply with the 

requirements of §§ 60.482–1a(a), (b), and 

(d), 60.482–2a, and 60.482–4a through 

60.482–11a, except as provided in 

§ 60.5401a. 

(b) You may elect to comply with the 

requirements of §§ 60.483–1a and 

60.483–2a, as an alternative. 

(c) You may apply to the 

Administrator for permission to use an 

alternative means of emission limitation 

that achieves a reduction in emissions 

of methane and VOC at least equivalent 

to that achieved by the controls required 

in this subpart according to the 

requirements of § 60.5402a. 

(d) You must comply with the 

provisions of § 60.485a except as 

provided in paragraph (f) of this section. 

(e) You must comply with the 

provisions of §§ 60.486a and 60.487a of 

this part except as provided in 

§§ 60.5401a, 60.5421a, and 60.5422a. 

(f) You must use the following 

provision instead of § 60.485a(d)(1): 

Each piece of equipment is presumed to 

be in VOC service or in wet gas service 

unless an owner or operator 

demonstrates that the piece of 

equipment is not in VOC service or in 

wet gas service. For a piece of 

equipment to be considered not in VOC 

service, it must be determined that the 

VOC content can be reasonably 

expected never to exceed 10.0 percent 

by weight. For a piece of equipment to 

be considered in wet gas service, it must 

be determined that it contains or 

contacts the field gas before the 

extraction step in the process. For 

purposes of determining the percent 

VOC content of the process fluid that is 

contained in or contacts a piece of 

equipment, procedures that conform to 

the methods described in ASTM E169– 

93, E168–92, or E260–96 (incorporated 

by reference as specified in § 60.17) 

must be used. 

§ 60.5401a What are the exceptions to the 

methane and VOC equipment leak 

standards for affected facilities at onshore 

natural gas processing plants? 

(a) You may comply with the 

following exceptions to the provisions 

of § 60.5400a(a) and (b). 

(b)(1) Each pressure relief device in 

gas/vapor service may be monitored 

quarterly and within 5 days after each 

pressure release to detect leaks by the 

methods specified in § 60.485a(b) except 

as provided in § 60.5400a(c) and in 

paragraph (b)(4) of this section, and 

§ 60.482–4a(a) through (c) of subpart 

VVa of this part. 

(2) If an instrument reading of 500 

ppm or greater is measured, a leak is 

detected. 

(3)(i) When a leak is detected, it must 

be repaired as soon as practicable, but 

no later than 15 calendar days after it is 

detected, except as provided in 

§ 60.482–9a. 

(ii) A first attempt at repair must be 

made no later than 5 calendar days after 

each leak is detected. 

(4)(i) Any pressure relief device that 

is located in a nonfractionating plant 

that is monitored only by non-plant 

personnel may be monitored after a 

pressure release the next time the 

monitoring personnel are on-site, 

instead of within 5 days as specified in 

paragraph (b)(1) of this section and 

§ 60.482–4a(b)(1) of subpart VVa of this 

part. 

(ii) No pressure relief device 

described in paragraph (b)(4)(i) of this 

section may be allowed to operate for 

more than 30 days after a pressure 

release without monitoring. 

(c) Sampling connection systems are 

exempt from the requirements of 

§ 60.482–5a. 

(d) Pumps in light liquid service, 

valves in gas/vapor and light liquid 

service, pressure relief devices in gas/

vapor service, and connectors in gas/

vapor service and in light liquid service 

that are located at a nonfractionating 

plant that does not have the design 

capacity to process 283,200 standard 

cubic meters per day (scmd) (10 million 

standard cubic feet per day) or more of 

field gas are exempt from the routine 

monitoring requirements of §§ 60.482– 

2a(a)(1), 60.482–7a(a), 60.482–11a(a), 

and paragraph (b)(1) of this section. 

(e) Pumps in light liquid service, 

valves in gas/vapor and light liquid 

service, pressure relief devices in gas/

vapor service, and connectors in gas/

vapor service and in light liquid service 

within a process unit that is located in 

the Alaskan North Slope are exempt 

from the routine monitoring 

requirements of §§ 60.482–2a(a)(1), 

60.482–7a(a), 60.482–11a(a), and 

paragraph (b)(1) of this section. 

(f) An owner or operator may use the 

following provisions instead of 

§ 60.485a(e): 

(1) Equipment is in heavy liquid 

service if the weight percent evaporated 

is 10 percent or less at 150 °C (302 °F) 

as determined by ASTM Method D86– 

96 (incorporated by reference as 

specified in § 60.17). 

(2) Equipment is in light liquid 

service if the weight percent evaporated 

is greater than 10 percent at 150 °C (302 

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°F) as determined by ASTM Method 

D86–96 (incorporated by reference as 

specified in § 60.17). 

(g) An owner or operator may use the 

following provisions instead of 

§ 60.485a(b)(2): A calibration drift 

assessment shall be performed, at a 

minimum, at the end of each monitoring 

day. Check the instrument using the 

same calibration gas(es) that were used 

to calibrate the instrument before use. 

Follow the procedures specified in 

Method 21 of appendix A–7 of this part, 

Section 10.1, except do not adjust the 

meter readout to correspond to the 

calibration gas value. Record the 

instrument reading for each scale used 

as specified in § 60.486a(e)(8). Divide 

these readings by the initial calibration 

values for each scale and multiply by 

100 to express the calibration drift as a 

percentage. If any calibration drift 

assessment shows a negative drift of 

more than 10 percent from the initial 

calibration value, then all equipment 

monitored since the last calibration with 

instrument readings below the 

appropriate leak definition and above 

the leak definition multiplied by (100 

minus the percent of negative drift/

divided by 100) must be re-monitored. 

If any calibration drift assessment shows 

a positive drift of more than 10 percent 

from the initial calibration value, then, 

at the owner/operator’s discretion, all 

equipment since the last calibration 

with instrument readings above the 

appropriate leak definition and below 

the leak definition multiplied by (100 

plus the percent of positive drift/

divided by 100) may be re-monitored. 

§ 60.5402a What are the alternative 

emission limitations for methane and VOC 

equipment leaks from onshore natural gas 

processing plants? 

(a) If, in the Administrator’s 

judgment, an alternative means of 

emission limitation will achieve a 

reduction in methane and VOC 

emissions at least equivalent to the 

reduction in methane and VOC 

emissions achieved under any design, 

equipment, work practice or operational 

standard, the Administrator will 

publish, in the Federal Register, a 

notice permitting the use of that 

alternative means for the purpose of 

compliance with that standard. The 

notice may condition permission on 

requirements related to the operation 

and maintenance of the alternative 

means. 

(b) Any notice under paragraph (a) of 

this section must be published only 

after notice and an opportunity for a 

public hearing. 

(c) The Administrator will consider 

applications under this section from 

either owners or operators of affected 

facilities, or manufacturers of control 

equipment. 

(d) The Administrator will treat 

applications under this section 

according to the following criteria, 

except in cases where the Administrator 

concludes that other criteria are 

appropriate: 

(1) The applicant must collect, verify 

and submit test data, covering a period 

of at least 12 months, necessary to 

support the finding in paragraph (a) of 

this section. 

(2) If the applicant is an owner or 

operator of an affected facility, the 

applicant must commit in writing to 

operate and maintain the alternative 

means so as to achieve a reduction in 

methane and VOC emissions at least 

equivalent to the reduction in methane 

and VOC emissions achieved under the 

design, equipment, work practice or 

operational standard. 

§ 60.5405a What standards apply to 

sweetening units at onshore natural gas 

processing plants? 

(a) During the initial performance test 

required by § 60.8(b), you must achieve 

at a minimum, an SO2 emission 

reduction efficiency (Zi) to be 

determined from Table 1 of this subpart 

based on the sulfur feed rate (X) and the 

sulfur content of the acid gas (Y) of the 

affected facility. 

(b) After demonstrating compliance 

with the provisions of paragraph (a) of 

this section, you must achieve at a 

minimum, an SO2 emission reduction 

efficiency (Zc) to be determined from 

Table 2 of this subpart based on the 

sulfur feed rate (X) and the sulfur 

content of the acid gas (Y) of the 

affected facility. 

§ 60.5406a What test methods and 

procedures must I use for my sweetening 

units affected facilities at onshore natural 

gas processing plants? 

(a) In conducting the performance 

tests required in § 60.8, you must use 

the test methods in appendix A of this 

part or other methods and procedures as 

specified in this section, except as 

provided in paragraph § 60.8(b). 

(b) During a performance test required 

by § 60.8, you must determine the 

minimum required reduction 

efficiencies (Z) of SO2 emissions as 

required in § 60.5405a(a) and (b) as 

follows: 

(1) The average sulfur feed rate (X) 

must be computed as follows: 

X = KQaY 

Where: 

X = average sulfur feed rate, Mg/D (LT/D). 

Qa = average volumetric flow rate of acid gas 

from sweetening unit, dscm/day (dscf/

day). 

Y = average H2S concentration in acid gas 

feed from sweetening unit, percent by 

volume, expressed as a decimal. 

K = (32 kg S/kg-mole)/((24.04 dscm/kg-mole) 

(1000 kg S/Mg)). 

= 1.331 × 10¥3Mg/dscm, for metric units. 

= (32 lb S/lb-mole)/((385.36 dscf/lb-mole) 

(2240 lb S/long ton)). 

= 3.707 × 10¥5 long ton/dscf, for English 

units. 

(2) You must use the continuous 

readings from the process flowmeter to 

determine the average volumetric flow 

rate (Qa) in dscm/day (dscf/day) of the 

acid gas from the sweetening unit for 

each run. 

(3) You must use the Tutwiler 

procedure in § 60.5408a or a 

chromatographic procedure following 

ASTM E260–96 (incorporated by 

reference as specified in § 60.17) to 

determine the H2S concentration in the 

acid gas feed from the sweetening unit 

(Y). At least one sample per hour (at 

equally spaced intervals) must be taken 

during each 4-hour run. The arithmetic 

mean of all samples must be the average 

H2S concentration (Y) on a dry basis for 

the run. By multiplying the result from 

the Tutwiler procedure by 1.62 × 10¥3, 

the units gr/100 scf are converted to 

volume percent. 

(4) Using the information from 

paragraphs (b)(1) and (b)(3) of this 

section, Tables 1 and 2 of this subpart 

must be used to determine the required 

initial (Zi) and continuous (Zc) 

reduction efficiencies of SO2 emissions. 

(c) You must determine compliance 

with the SO2 standards in § 60.5405a(a) 

or (b) as follows: 

(1) You must compute the emission 

reduction efficiency (R) achieved by the 

sulfur recovery technology for each run 

using the following equation: 

R = (100S)/(S + E) 

(2) You must use the level indicators 

or manual soundings to measure the 

liquid sulfur accumulation rate in the 

product storage vessels. You must use 

readings taken at the beginning and end 

of each run, the tank geometry, sulfur 

density at the storage temperature, and 

sample duration to determine the sulfur 

production rate (S) in kg/hr (lb/hr) for 

each run. 

(3) You must compute the emission 

rate of sulfur for each run as follows: 

E = CeQsd/K 1 

Where: 

E = emission rate of sulfur per run, kg/hr. 

Ce = concentration of sulfur equivalent (SO2+

reduced sulfur), g/dscm (lb/dscf). 

Qsd = volumetric flow rate of effluent gas, 

dscm/hr (dscf/hr). 

K1 = conversion factor, 1000 g/kg (7000 gr/ 

lb). 

(4) The concentration (Ce) of sulfur 

equivalent must be the sum of the SO2

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and TRS concentrations, after being 

converted to sulfur equivalents. For 

each run and each of the test methods 

specified in this paragraph (c) of this 

section, you must use a sampling time 

of at least 4 hours. You must use 

Method 1 of appendix A–1 of this part 

to select the sampling site. The 

sampling point in the duct must be at 

the centroid of the cross-section if the 

area is less than 5 m2 (54 ft2) or at a 

point no closer to the walls than 1 m (39 

in) if the cross-sectional area is 5 m2 or 

more, and the centroid is more than 1 

m (39 in) from the wall. 

(i) You must use Method 6 of 

appendix A–4 of this part to determine 

the SO2 concentration. You must take 

eight samples of 20 minutes each at 30- 

minute intervals. The arithmetic average 

must be the concentration for the run. 

The concentration must be multiplied 

by 0.5 × 10¥3 to convert the results to 

sulfur equivalent. In place of Method 6 

of Appendix A of this part, you may use 

ASME/ANSI PTC 19.10–1981, Part 10 

(manual portion only) (incorporated by 

reference as specified in § 60.17) 

(ii) You must use Method 15 of 

appendix A–5 of this part to determine 

the TRS concentration from reductiontype devices or where the oxygen 

content of the effluent gas is less than 

1.0 percent by volume. The sampling 

rate must be at least 3 liters/min (0.1 ft3/ 

min) to insure minimum residence time 

in the sample line. You must take 

sixteen samples at 15-minute intervals. 

The arithmetic average of all the 

samples must be the concentration for 

the run. The concentration in ppm 

reduced sulfur as sulfur must be 

multiplied by 1.333 × 10¥3 to convert 

the results to sulfur equivalent. 

(iii) You must use Method 16A of 

appendix A–6 of this part or Method 15 

of appendix A–5 of this part or ASME/ 

ANSI PTC 19.10–1981, Part 10 (manual 

portion only) (incorporated by reference 

as specified in § 60.17) to determine the 

reduced sulfur concentration from 

oxidation-type devices or where the 

oxygen content of the effluent gas is 

greater than 1.0 percent by volume. You 

must take eight samples of 20 minutes 

each at 30-minute intervals. The 

arithmetic average must be the 

concentration for the run. The 

concentration in ppm reduced sulfur as 

sulfur must be multiplied by 1.333 × 

10¥3 to convert the results to sulfur 

equivalent. 

(iv) You must use Method 2 of 

appendix A–1 of this part to determine 

the volumetric flow rate of the effluent 

gas. A velocity traverse must be 

conducted at the beginning and end of 

each run. The arithmetic average of the 

two measurements must be used to 

calculate the volumetric flow rate (Qsd) 

for the run. For the determination of the 

effluent gas molecular weight, a single 

integrated sample over the 4-hour 

period may be taken and analyzed or 

grab samples at 1-hour intervals may be 

taken, analyzed, and averaged. For the 

moisture content, you must take two 

samples of at least 0.10 dscm (3.5 dscf) 

and 10 minutes at the beginning of the 

4-hour run and near the end of the time 

period. The arithmetic average of the 

two runs must be the moisture content 

for the run. 

§ 60.5407a What are the requirements for 

monitoring of emissions and operations 

from my sweetening unit affected facilities 

at onshore natural gas processing plants? 

(a) If your sweetening unit affected 

facility is located at an onshore natural 

gas processing plant and is subject to 

the provisions of § 60.5405a(a) or (b) 

you must install, calibrate, maintain, 

and operate monitoring devices or 

perform measurements to determine the 

following operations information on a 

daily basis: 

(1) The accumulation of sulfur 

product over each 24-hour period. The 

monitoring method may incorporate the 

use of an instrument to measure and 

record the liquid sulfur production rate, 

or may be a procedure for measuring 

and recording the sulfur liquid levels in 

the storage vessels with a level indicator 

or by manual soundings, with 

subsequent calculation of the sulfur 

production rate based on the tank 

geometry, stored sulfur density, and 

elapsed time between readings. The 

method must be designed to be accurate 

within ±2 percent of the 24-hour sulfur 

accumulation. 

(2) The H2S concentration in the acid 

gas from the sweetening unit for each 

24-hour period. At least one sample per 

24-hour period must be collected and 

analyzed using the equation specified in 

§ 60.5406a(b)(1). The Administrator may 

require you to demonstrate that the H2S 

concentration obtained from one or 

more samples over a 24-hour period is 

within ±20 percent of the average of 12 

samples collected at equally spaced 

intervals during the 24-hour period. In 

instances where the H2S concentration 

of a single sample is not within ±20 

percent of the average of the 12 equally 

spaced samples, the Administrator may 

require a more frequent sampling 

schedule. 

(3) The average acid gas flow rate 

from the sweetening unit. You must 

install and operate a monitoring device 

to continuously measure the flow rate of 

acid gas. The monitoring device reading 

must be recorded at least once per hour 

during each 24-hour period. The average 

acid gas flow rate must be computed 

from the individual readings. 

(4) The sulfur feed rate (X). For each 

24-hour period, you must compute X 

using the equation specified in 

§ 60.5406a(b)(1). 

(5) The required sulfur dioxide 

emission reduction efficiency for the 24- 

hour period.You must use the sulfur 

feed rate and the H2S concentration in 

the acid gas for the 24-hour period, as 

applicable, to determine the required 

reduction efficiency in accordance with 

the provisions of § 60.5405a(b). 

(b) Where compliance is achieved 

through the use of an oxidation control 

system or a reduction control system 

followed by a continually operated 

incineration device, you must install, 

calibrate, maintain, and operate 

monitoring devices and continuous 

emission monitors as follows: 

(1) A continuous monitoring system 

to measure the total sulfur emission rate 

(E) of SO2 in the gases discharged to the 

atmosphere. The SO2 emission rate must 

be expressed in terms of equivalent 

sulfur mass flow rates (kg/hr (lb/hr)). 

The span of this monitoring system 

must be set so that the equivalent 

emission limit of § 60.5405a(b) will be 

between 30 percent and 70 percent of 

the measurement range of the 

instrument system. 

(2) Except as provided in paragraph 

(b)(3) of this section: A monitoring 

device to measure the temperature of 

the gas leaving the combustion zone of 

the incinerator, if compliance with 

§ 60.5405a(a) is achieved through the 

use of an oxidation control system or a 

reduction control system followed by a 

continually operated incineration 

device. The monitoring device must be 

certified by the manufacturer to be 

accurate to within ±1 percent of the 

temperature being measured. 

(3) When performance tests are 

conducted under the provision of § 60.8 

to demonstrate compliance with the 

standards under § 60.5405a, the 

temperature of the gas leaving the 

incinerator combustion zone must be 

determined using the monitoring 

device. If the volumetric ratio of sulfur 

dioxide to sulfur dioxide plus total 

reduced sulfur (expressed as SO2) in the 

gas leaving the incinerator is equal to or 

less than 0.98, then temperature 

monitoring may be used to demonstrate 

that sulfur dioxide emission monitoring 

is sufficient to determine total sulfur 

emissions. At all times during the 

operation of the facility, you must 

maintain the average temperature of the 

gas leaving the combustion zone of the 

incinerator at or above the appropriate 

level determined during the most recent 

performance test to ensure the sulfur 

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56672 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

compound oxidation criteria are met. 

Operation at lower average temperatures 

may be considered by the Administrator 

to be unacceptable operation and 

maintenance of the affected facility. You 

may request that the minimum 

incinerator temperature be reestablished 

by conducting new performance tests 

under § 60.8. 

(4) Upon promulgation of a 

performance specification of continuous 

monitoring systems for total reduced 

sulfur compounds at sulfur recovery 

plants, you may, as an alternative to 

paragraph (b)(2) of this section, install, 

calibrate, maintain, and operate a 

continuous emission monitoring system 

for total reduced sulfur compounds as 

required in paragraph (d) of this section 

in addition to a sulfur dioxide emission 

monitoring system. The sum of the 

equivalent sulfur mass emission rates 

from the two monitoring systems must 

be used to compute the total sulfur 

emission rate (E). 

(c) Where compliance is achieved 

through the use of a reduction control 

system not followed by a continually 

operated incineration device, you must 

install, calibrate, maintain, and operate 

a continuous monitoring system to 

measure the emission rate of reduced 

sulfur compounds as SO2 equivalent in 

the gases discharged to the atmosphere. 

The SO2 equivalent compound emission 

rate must be expressed in terms of 

equivalent sulfur mass flow rates (kg/hr 

(lb/hr)). The span of this monitoring 

system must be set so that the 

equivalent emission limit of 

§ 60.5405a(b) will be between 30 and 70 

percent of the measurement range of the 

system. This requirement becomes 

effective upon promulgation of a 

performance specification for 

continuous monitoring systems for total 

reduced sulfur compounds at sulfur 

recovery plants. 

(d) For those sources required to 

comply with paragraph (b) or (c) of this 

section, you must calculate the average 

sulfur emission reduction efficiency 

achieved (R) for each 24-hour clock 

interval. The 24-hour interval may begin 

and end at any selected clock time, but 

must be consistent. You must compute 

the 24-hour average reduction efficiency 

(R) based on the 24-hour average sulfur 

production rate (S) and sulfur emission 

rate (E), using the equation in 

§ 60.5406a(c)(1). 

(1) You must use data obtained from 

the sulfur production rate monitoring 

device specified in paragraph (a) of this 

section to determine S. 

(2) You must use data obtained from 

the sulfur emission rate monitoring 

systems specified in paragraphs (b) or 

(c) of this section to calculate a 24-hour 

average for the sulfur emission rate (E). 

The monitoring system must provide at 

least one data point in each successive 

15-minute interval. You must use at 

least two data points to calculate each 

1-hour average. You must use a 

minimum of 18 1-hour averages to 

compute each 24-hour average. 

(e) In lieu of complying with 

paragraphs (b) or (c) of this section, 

those sources with a design capacity of 

less than 152 Mg/D (150 LT/D) of H2S 

expressed as sulfur may calculate the 

sulfur emission reduction efficiency 

achieved for each 24-hour period by: 

Where: 

R = The sulfur dioxide removal efficiency 

achieved during the 24-hour period, 

percent. 

K2 = Conversion factor, 0.02400 Mg/D per kg/ 

hr (0.01071 LT/D per lb/hr). 

S = The sulfur production rate during the 24- 

hour period, kg/hr (lb/hr). 

X = The sulfur feed rate in the acid gas, Mg/ 

D (LT/D). 

(f) The monitoring devices required in 

paragraphs (b)(1), (b)(3) and (c) of this 

section must be calibrated at least 

annually according to the 

manufacturer’s specifications, as 

required by § 60.13(b). 

(g) The continuous emission 

monitoring systems required in 

paragraphs (b)(1), (b)(3), and (c) of this 

section must be subject to the emission 

monitoring requirements of § 60.13 of 

the General Provisions. For conducting 

the continuous emission monitoring 

system performance evaluation required 

by § 60.13(c), Performance Specification 

2 of appendix B of this part must apply, 

and Method 6 of appendix A–4 of this 

part must be used for systems required 

by paragraph (b) of this section. In place 

of Method 6 of appendix A–4 of this 

part, ASME PTC 19.10–1981 

(incorporated by reference—see § 60.17) 

may be used. 

§ 60.5408a What is an optional procedure 

for measuring hydrogen sulfide in acid 

gas—Tutwiler Procedure? 

The Tutwiler procedure may be found 

in the Gas Engineers Handbook, Fuel 

Gas Engineering practices, The 

Industrial Press, 93 Worth Street, New 

York, NY, 1966, First Edition, Second 

Printing, page 6/25 (Docket A–80–20–A, 

Entry II–I–67). 

(a) When an instantaneous sample is 

desired and H2S concentration is 10 

grains per 1000 cubic foot or more, a 

100 ml Tutwiler burette is used. For 

concentrations less than 10 grains, a 500 

ml Tutwiler burette and more dilute 

solutions are used. In principle, this 

method consists of titrating hydrogen 

sulfide in a gas sample directly with a 

standard solution of iodine. 

(b) Apparatus. (See Figure 1 of this 

subpart) A 100 or 500 ml capacity 

Tutwiler burette, with two-way glass 

stopcock at bottom and three-way 

stopcock at top which connect either 

with inlet tubulature or glass-stoppered 

cylinder, 10 ml capacity, graduated in 

0.1 ml subdivision; rubber tubing 

connecting burette with leveling bottle. 

(c) Reagents. (1) Iodine stock solution, 

0.1N. Weight 12.7 g iodine, and 20 to 25 

g cp potassium iodide (KI) for each liter 

of solution. Dissolve KI in as little water 

as necessary; dissolve iodine in 

concentrated KI solution, make up to 

proper volume, and store in glassstoppered brown glass bottle. 

(2) Standard iodine solution, 1 ml = 

0.001771 g I. Transfer 33.7 ml of above 

0.1N stock solution into a 250 ml 

volumetric flask; add water to mark and 

mix well. Then, for 100 ml sample of 

gas, 1 ml of standard iodine solution is 

equivalent to 100 grains H2S per cubic 

feet of gas. 

(3) Starch solution. Rub into a thin 

paste about one teaspoonful of wheat 

starch with a little water; pour into 

about a pint of boiling water; stir; let 

cool and decant off clear solution. Make 

fresh solution every few days. 

(d) Procedure. Fill leveling bulb with 

starch solution. Raise (L), open cock (G), 

open (F) to (A), and close (F) when 

solutions starts to run out of gas inlet. 

Close (G). Purge gas sampling line and 

connect with (A). Lower (L) and open 

(F) and (G). When liquid level is several 

ml past the 100 ml mark, close (G) and 

(F), and disconnect sampling tube. Open 

(G) and bring starch solution to 100 ml 

mark by raising (L); then close (G). Open 

(F) momentarily, to bring gas in burette 

to atmospheric pressure, and close (F). 

Open (G), bring liquid level down to 10 

ml mark by lowering (L). Close (G), 

clamp rubber tubing near (E) and 

disconnect it from burette. Rinse 

graduated cylinder with a standard 

iodine solution (0.00171 g I per ml); fill 

cylinder and record reading. Introduce 

successive small amounts of iodine 

through (F); shake well after each 

addition; continue until a faint 

permanent blue color is obtained. 

Record reading; subtract from previous 

reading, and call difference D. 

(e) With every fresh stock of starch 

solution perform a blank test as follows: 

Introduce fresh starch solution into 

burette up to 100 ml mark. Close (F) and 

(G). Lower (L) and open (G). When 

liquid level reaches the 10 ml mark, 

close (G). With air in burette, titrate as 

during a test and up to same end point. 

Call ml of iodine used C. Then, 


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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56673 

Grains H2S per 100 cubic foot of gas = 

100 (D–C) 

(f) Greater sensitivity can be attained 

if a 500 ml capacity Tutwiler burette is 

used with a more dilute (0.001N) iodine 

solution. Concentrations less than 1.0 

grains per 100 cubic foot can be 

determined in this way. Usually, the 

starch-iodine end point is much less 

distinct, and a blank determination of 

end point, with H2S-free gas or air, is 

required. 


mstockstill on DSK4VPTVN1PROD with PROPOSALS4EP18SE15.001</GPH>

F 

IUIIII:TTt 

LtVIt.LING IU&.I 

Figure 1. Tutwiler burette (lettered items mentioned in text). 
56674 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

§ 60.5410a How do I demonstrate initial 

compliance with the standards for my well, 

centrifugal compressor, reciprocating 

compressor, pneumatic controller, 

pneumatic pump, storage vessel, collection 

of fugitive emissions components at a well 

site, collection of fugitive emissions 

components at a compressor station, and 

equipment leaks and sweetening unit 

affected facilities at onshore natural gas 

processing plants? 

You must determine initial 

compliance with the standards for each 

affected facility using the requirements 

in paragraphs (a) through (j) of this 

section. The initial compliance period 

begins on [date 60 days after publication 

of final rule in the Federal Register], or 

upon initial startup, whichever is later, 

and ends no later than 1 year after the 

initial startup date for your affected 

facility or no later than 1 year after [date 

60 days after publication of final rule in 

the Federal Register]. The initial 

compliance period may be less than one 

full year. 

(a) To achieve initial compliance with 

the methane and VOC standards for 

each well completion operation 

conducted at your well affected facility 

you must comply with paragraphs (a)(1) 

through (a)(4) of this section. 

(1) You must submit the notification 

required in § 60.5420a(a)(2). 

(2) You must submit the initial annual 

report for your well affected facility as 

required in § 60.5420a(b). 

(3) You must maintain a log of records 

as specified in § 60.5420a(c)(1)(i) 

through (iv) for each well completion 

operation conducted during the initial 

compliance period. 

(4) For each well affected facility 

subject to both § 60.5375a(a)(1) and (3), 

as an alternative to retaining the records 

specified in § 60.5420a(c)(1)(i) through 

(iv), you may maintain records of one or 

more digital photographs with the date 

the photograph was taken and the 

latitude and longitude of the well site 

imbedded within or stored with the 

digital file showing the equipment for 

storing or re-injecting recovered liquid, 

equipment for routing recovered gas to 

the gas flow line and the completion 

combustion device (if applicable) 

connected to and operating at each well 

completion operation that occurred 

during the initial compliance period. As 

an alternative to imbedded latitude and 

longitude within the digital photograph, 

the digital photograph may consist of a 

photograph of the equipment connected 

and operating at each well completion 

operation with a photograph of a 

separately operating GIS device within 

the same digital picture, provided the 

latitude and longitude output of the GIS 

unit can be clearly read in the digital 

photograph. 

(b)(1) To achieve initial compliance 

with standards for your centrifugal 

compressor affected facility you must 

reduce methane and VOC emissions 

from each centrifugal compressor wet 

seal fluid degassing system by 95.0 

percent or greater as required by 

§ 60.5380a and as demonstrated by the 

requirements of § 60.5413a. 

(2) If you use a control device to 

reduce emissions, you must equip the 

wet seal fluid degassing system with a 

cover that meets the requirements of 

§ 60.5411a(b) that is connected through 

a closed vent system that meets the 

requirements of § 60.5411a(a) and is 

routed to a control device that meets the 

conditions specified in § 60.5412a(a), (b) 

and (c). As an alternative to routing the 

closed vent system to a control device, 

you may route the closed vent system to 

a process that reduces VOC emissions 

by at least 95.0 percent. 

(3) You must conduct an initial 

performance test as required in 

§ 60.5413a within 180 days after initial 

startup or by [date 60 days after 

publication of final rule in the Federal 

Register], whichever is later, and you 

must comply with the continuous 

compliance requirements in 

§ 60.5415a(b)(1) through (3). 

(4) You must conduct the initial 

inspections required in § 60.5416a(a) 

and (b). 

(5) You must install and operate the 

continuous parameter monitoring 

systems in accordance with 

§ 60.5417a(a) through (g), as applicable. 

(6) You must submit the notifications 

required in 60.7(a)(1), (3), and (4). 

(7) You must submit the initial annual 

report for your centrifugal compressor 

affected facility as required in 

§ 60.5420a(b) for each centrifugal 

compressor affected facility. 

(8) You must maintain the records as 

specified in § 60.5420a(c). 

(c) To achieve initial compliance with 

the standards for each reciprocating 

compressor affected facility you must 

comply with paragraphs (c)(1) through 

(4) of this section. 

(1) If complying with § 60.5385a(a)(1) 

or (2), during the initial compliance 

period, you must continuously monitor 

the number of hours of operation or 

track the number of months since the 

last rod packing replacement. 

(2) If complying with § 60.5385a(a)(3), 

you must operate the rod packing 

emissions collection system under 

negative pressure and route emissions to 

a process through a closed vent system 

that meets the requirements of 

§ 60.5411a(a). 

(3) You must submit the initial annual 

report for your reciprocating compressor 

as required in § 60.5420a(b). 

(4) You must maintain the records as 

specified in § 60.5420a(c) for each 

reciprocating compressor affected 

facility. 

(d) To achieve initial compliance with 

methane and VOC emission standards 

for your pneumatic controller affected 

facility you must comply with the 

requirements specified in paragraphs 

(d)(1) through (6) of this section, as 

applicable. 

(1) You must demonstrate initial 

compliance by maintaining records as 

specified in § 60.5420a(c)(4)(ii) of your 

determination that the use of a 

pneumatic controller affected facility 

with a bleed rate greater than the 

applicable standard is required as 

specified in § 60.5390a(a). 

(2) You own or operate a pneumatic 

controller affected facility located at a 

natural gas processing plant and your 

pneumatic controller is driven by a gas 

other than natural gas and therefore 

emits zero natural gas. 

(3) You own or operate a pneumatic 

controller affected facility located other 

than at a natural gas processing plant 

and the manufacturer’s design 

specifications indicate that the 

controller emits less than or equal to 6 

standard cubic feet of gas per hour. 

(4) You must tag each new pneumatic 

controller affected facility according to 

the requirements of § 60.5390a(b)(2) or 

(c)(2). 

(5) You must include the information 

in paragraph (d)(1) of this section and a 

listing of the pneumatic controller 

affected facilities specified in 

paragraphs (d)(2) and (3) of this section 

in the initial annual report submitted for 

your pneumatic controller affected 

facilities constructed, modified or 

reconstructed during the period covered 

by the annual report according to the 

requirements of § 60.5420a(b). 

(6) You must maintain the records as 

specified in § 60.5420a(c) for each 

pneumatic controller affected facility. 

(e) To achieve initial compliance with 

emission standards for your pneumatic 

pump affected facility you must comply 

with the requirements specified in 

paragraphs (e)(1) through (6) of this 

section, as applicable. 

(1) You own or operate a pneumatic 

pump affected facility located at a 

natural gas processing plant and your 

pneumatic pump is driven by a gas 

other than natural gas and therefore 

emits zero natural gas. 

(2) You own or operate a pneumatic 

pump affected facility located other 

than at a natural gas processing plant 

and your pneumatic pump is controlled 

by at least 95 percent. 

(3) You own or operate a pneumatic 

pump affected facility located other 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56675 

than at a natural gas processing plant 

and your pneumatic pump is not 

controlled by at least 95 percent because 

a control device is not available at the 

site, you must submit the certification in 

60.5420a(b)(8)(i). 

(4) You must tag each new pneumatic 

pump affected facility according to the 

requirements of § 60.5393a(a)(2) or 

(b)(3). 

(5) You must include a listing of the 

pneumatic pump affected facilities 

specified in paragraphs (e)(1) through 

(3) of this section in the initial annual 

report submitted for your pneumatic 

pump affected facilities constructed, 

modified or reconstructed during the 

period covered by the annual report 

according to the requirements of 

§ 60.5420a(b). 

(6) You must maintain the records as 

specified in § 60.5420a(c) for each 

pneumatic pump affected facility. 

(f) For affected facilities at onshore 

natural gas processing plants, initial 

compliance with the methane and VOC 

requirements is demonstrated if you are 

in compliance with the requirements of 

§ 60.5400a. 

(g) For sweetening unit affected 

facilities at onshore natural gas 

processing plants, initial compliance is 

demonstrated according to paragraphs 

(g)(1) through (3) of this section. 

(1) To determine compliance with the 

standards for SO2 specified in 

§ 60.5405a(a), during the initial 

performance test as required by § 60.8, 

the minimum required sulfur dioxide 

emission reduction efficiency (Zi) is 

compared to the emission reduction 

efficiency (R) achieved by the sulfur 

recovery technology as specified in 

paragraphs (g)(1)(i) and (ii) of this 

section. 

(i) If R ≥ Zi, your affected facility is 

in compliance. 

(ii) If R < Zi, your affected facility is 

not in compliance. 

(2) The emission reduction efficiency 

(R) achieved by the sulfur reduction 

technology must be determined using 

the procedures in § 60.5406a(c)(1). 

(3) You have submitted the results of 

paragraphs (g)(1) and (2) of this section 

in the initial annual report submitted for 

your sweetening unit affected facilities 

at onshore natural gas processing plants. 

(h) For each storage vessel affected 

facility, you must comply with 

paragraphs (h)(1) through (6) of this 

section. You must demonstrate initial 

compliance by [date 60 days after 

publication of final rule in the Federal 

Register], or within 60 days after 

startup, whichever is later. 

(1) You must determine the potential 

VOC emission rate as specified in 

§ 60.5365a(e). 

(2) You must reduce VOC emissions 

in accordance with § 60.5395a(a). 

(3) If you use a control device to 

reduce emissions, you must equip the 

storage vessel with a cover that meets 

the requirements of § 60.5411a(b) and is 

connected through a closed vent system 

that meets the requirements of 

§ 60.5411a(c) to a control device that 

meets the conditions specified in 

§ 60.5412a(d) within 60 days after 

startup for storage vessels constructed, 

modified or reconstructed at well sites 

with no other wells in production, or 

upon startup for storage vessels 

constructed, modified or reconstructed 

at well sites with one or more wells 

already in production. 

(4) You must conduct an initial 

performance test as required in 

§ 60.5413a within 180 days after initial 

startup or within 180 days of [date 60 

days after publication of final rule in the 

Federal Register], whichever is later, 

and you must comply with the 

continuous compliance requirements in 

§ 60.5415a(e). 

(5) You must submit the information 

required for your storage vessel affected 

facility as specified in § 60.5420a(b). 

(6) You must maintain the records 

required for your storage vessel affected 

facility, as specified in § 60.5420a(c) for 

each storage vessel affected facility. 

(i) For each storage vessel affected 

facility, you must submit the 

notification specified in § 60.5395a(b)(2) 

with the initial annual report specified 

in § 60.5420a(b). 

(j) To achieve initial compliance with 

the fugitive emission standards for each 

collection of fugitive emissions 

components at a well site and each 

collection of fugitive emissions 

components at a compressor station, 

you must comply with paragraphs (j)(1) 

through (5) of this section. 

(1) You must develop a fugitive 

emissions monitoring plan for each 

collection of fugitive emissions 

components at a well site and each 

collection of fugitive emissions 

components at a compressor station as 

required in § 60.5397a(a). 

(2) You must conduct an initial 

monitoring survey as required in 

§ 60.5397a(f). 

(3) You must maintain the records 

specified in § 60.5420a(c). 

(4) You must repair each identified 

source of fugitive emissions for each 

affected facility as required in 

§ 60.5397a(j). 

(5) You must submit the initial annual 

report for each collection of fugitive 

emissions components at a well site and 

each collection of fugitive emissions 

components at a compressor station 

compressor station as required in 

§ 60.5420a(b). 

§ 60.5411a What additional requirements 

must I meet to determine initial compliance 

for my covers and closed vent systems 

routing emissions from centrifugal 

compressor wet seal fluid degassing 

systems, reciprocating compressors, 

pneumatic pumps and storage vessels? 

You must meet the applicable 

requirements of this section for each 

cover and closed vent system used to 

comply with the emission standards for 

your centrifugal compressor wet seal 

degassing systems, reciprocating 

compressors, pneumatic pumps and 

storage vessels. 

(a) Closed vent system requirements 

for reciprocating compressors, 

centrifugal compressor wet seal 

degassing systems and pneumatic 

pumps. (1) You must design the closed 

vent system to route all gases, vapors, 

and fumes emitted from the 

reciprocating compressor rod packing 

emissions collection system, the wet 

seal fluid degassing system or 

pneumatic pump to a control device or 

to a process that meets the requirements 

specified in § 60.5412a(a) through (c). 

(2) You must design and operate the 

closed vent system with no detectable 

emissions as demonstrated by 

§ 60.5416a(b). 

(3) You must meet the requirements 

specified in paragraphs (a)(3)(i) and (ii) 

of this section if the closed vent system 

contains one or more bypass devices 

that could be used to divert all or a 

portion of the gases, vapors, or fumes 

from entering the control device. 

(i) Except as provided in paragraph 

(a)(3)(ii) of this section, you must 

comply with either paragraph 

(a)(3)(i)(A) or (B) of this section for each 

bypass device. 

(A) You must properly install, 

calibrate, maintain, and operate a flow 

indicator at the inlet to the bypass 

device that could divert the stream away 

from the control device or process to the 

atmosphere. Set the flow indicator to 

trigger an audible and visible alarm, and 

initiate notification via remote alarm to 

the nearest field office, when the bypass 

device is open such that the stream is 

being, or could be, diverted away from 

the control device or process to the 

atmosphere. You must maintain records 

of each time the alarm is activated 

according to § 60.5420a(c)(8). 

(B) You must secure the bypass device 

valve installed at the inlet to the bypass 

device in the non-diverting position 

using a car-seal or a lock-and-key type 

configuration. 

(ii) Low leg drains, high point bleeds, 

analyzer vents, open-ended valves or 

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56676 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

lines, and safety devices are not subject 

to the requirements of paragraph (a)(3)(i) 

of this section. 

(b) Cover requirements for storage 

vessels and centrifugal compressor wet 

seal fluid degassing systems. (1) The 

cover and all openings on the cover 

(e.g., access hatches, sampling ports, 

pressure relief devices and gauge wells) 

shall form a continuous impermeable 

barrier over the entire surface area of the 

liquid in the storage vessel or wet seal 

fluid degassing system. 

(2) Each cover opening shall be 

secured in a closed, sealed position 

(e.g., covered by a gasketed lid or cap) 

whenever material is in the unit on 

which the cover is installed except 

during those times when it is necessary 

to use an opening as follows: 

(i) To add material to, or remove 

material from the unit (this includes 

openings necessary to equalize or 

balance the internal pressure of the unit 

following changes in the level of the 

material in the unit); 

(ii) To inspect or sample the material 

in the unit; 

(iii) To inspect, maintain, repair, or 

replace equipment located inside the 

unit; or 

(iv) To vent liquids, gases, or fumes 

from the unit through a closed-vent 

system designed and operated in 

accordance with the requirements of 

paragraph (a) or (c) of this section to a 

control device or to a process. 

(3) Each storage vessel thief hatch 

shall be equipped, maintained and 

operated with a weighted mechanism or 

equivalent, to ensure that the lid 

remains properly seated and sealed 

under normal operating conditions, 

including such times when working, 

standing/breathing, and flash emissions 

may be generated. You must select 

gasket material for the hatch based on 

composition of the fluid in the storage 

vessel and weather conditions. 

(c) Closed vent system requirements 

for storage vessel affected facilities 

using a control device or routing 

emissions to a process. (1) You must 

design the closed vent system to route 

all gases, vapors, and fumes emitted 

from the material in the storage vessel 

to a control device that meets the 

requirements specified in § 60.5412a(c) 

and (d), or to a process. 

(2) You must design and operate a 

closed vent system with no detectable 

emissions, as determined using 

olfactory, visual and auditory 

inspections. Each closed vent system 

that routes emissions to a process must 

be operational 95 percent of the year or 

greater. 

(3) You must meet the requirements 

specified in paragraphs (c)(3)(i) and (ii) 

of this section if the closed vent system 

contains one or more bypass devices 

that could be used to divert all or a 

portion of the gases, vapors, or fumes 

from entering the control device or to a 

process. 

(i) Except as provided in paragraph 

(c)(3)(ii) of this section, you must 

comply with either paragraph 

(c)(3)(i)(A) or (B) of this section for each 

bypass device. 

(A) You must properly install, 

calibrate, maintain, and operate a flow 

indicator at the inlet to the bypass 

device that could divert the stream away 

from the control device or process to the 

atmosphere. Set the flow indicator to 

trigger and audible and visible alarm, 

and initiate notification via remote 

alarm to the nearest field office, when 

the bypass device is open such that the 

stream is being, or could be, diverted 

away from the control device or process 

to the atmosphere. You must maintain 

records of each time the alarm is 

sounded according to § 60.5420a(c)(8). 

(B) You must secure the bypass device 

valve installed at the inlet to the bypass 

device in the non-diverting position 

using a car-seal or a lock-and-key type 

configuration. 

(ii) Low leg drains, high point bleeds, 

analyzer vents, open-ended valves or 

lines, and safety devices are not subject 

to the requirements of paragraph (c)(3)(i) 

of this section. 

§ 60.5412a What additional requirements 

must I meet for determining initial 

compliance with control devices used to 

comply with the emission standards for my 

centrifugal compressor, pneumatic pump 

and storage vessel affected facilities? 

You must meet the applicable 

requirements of this section for each 

control device used to comply with the 

emission standards for your centrifugal 

compressor affected facility, pneumatic 

pump affected facility, or storage vessel 

affected facility. 

(a) Each control device used to meet 

the emission reduction standard in 

§ 60.5380a(a)(1) for your centrifugal 

compressor affected facility or 

§ 60.5393a(b)(1) for your pneumatic 

pump must be installed according to 

paragraphs (a)(1) through (3) of this 

section. As an alternative, you may 

install a control device model tested 

under § 60.5413a(d), which meets the 

criteria in § 60.5413a(d)(11) and 

§ 60.5413a(e). 

(1) Each combustion device (e.g., 

thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) must be designed and operated 

in accordance with one of the 

performance requirements specified in 

paragraphs (a)(1)(i) through (iv) of this 

section. 

(i) You must reduce the mass content 

of methane and VOC in the gases vented 

to the device by 95.0 percent by weight 

or greater as determined in accordance 

with the requirements of § 60.5413a. 

(ii) You must reduce the 

concentration of TOC in the exhaust 

gases at the outlet to the device to a 

level equal to or less than 600 parts per 

million by volume as propane on a dry 

basis corrected to 3 percent oxygen as 

determined in accordance with the 

requirements of § 60.5413a. 

(iii) You must operate at a minimum 

temperature of 760 °C for a control 

device that can demonstrate a uniform 

combustion zone temperature during 

the performance test conducted under 

§ 60.5413a. 

(iv) If a boiler or process heater is 

used as the control device, then you 

must introduce the vent stream into the 

flame zone of the boiler or process 

heater. 

(2) Each vapor recovery device (e.g., 

carbon adsorption system or condenser) 

or other non-destructive control device 

must be designed and operated to 

reduce the mass content of methane and 

VOC in the gases vented to the device 

by 95.0 percent by weight or greater as 

determined in accordance with the 

requirements of § 60.5413a. As an 

alternative to the performance testing 

requirements, you may demonstrate 

initial compliance by conducting a 

design analysis for vapor recovery 

devices according to the requirements of 

§ 60.5413a(c). 

(3) You must design and operate a 

flare in accordance with the 

requirements of § 60.5413a(a)(1). 

(b) You must operate each control 

device installed on your centrifugal 

compressor or pneumatic pump affected 

facility in accordance with the 

requirements specified in paragraphs 

(b)(1) and (2) of this section. 

(1) You must operate each control 

device used to comply with this subpart 

at all times when gases, vapors, and 

fumes are vented from the wet seal fluid 

degassing system affected facility as 

required under § 60.5380a(a), or from 

the pneumatic pump as required under 

§ 60.5393a(b)(1), through the closed vent 

system to the control device. You may 

vent more than one affected facility to 

a control device used to comply with 

this subpart. 

(2) For each control device monitored 

in accordance with the requirements of 

§ 60.5417a(a) through (g), you must 

demonstrate compliance according to 

the requirements of § 60.5415a(b)(2), as 

applicable. 

(c) For each carbon adsorption system 

used as a control device to meet the 

requirements of paragraph (a)(2) or 

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(d)(2) of this section, you must manage 

the carbon in accordance with the 

requirements specified in paragraphs 

(c)(1) or (2) of this section. 

(1) Following the initial startup of the 

control device, you must replace all 

carbon in the control device with fresh 

carbon on a regular, predetermined time 

interval that is no longer than the 

carbon service life established according 

to § 60.5413a(c)(2) or (3) or according to 

the design required in paragraph (d)(2) 

of this section, for the carbon adsorption 

system. You must maintain records 

identifying the schedule for replacement 

and records of each carbon replacement 

as required in § 60.5420a(c)(10) and 

(12). 

(2) You must either regenerate, 

reactivate, or burn the spent carbon 

removed from the carbon adsorption 

system in one of the units specified in 

paragraphs (c)(2)(i) through (vii) of this 

section. 

(i) Regenerate or reactivate the spent 

carbon in a thermal treatment unit for 

which you have been issued a final 

permit under 40 CFR part 270 that 

implements the requirements of 40 CFR 

part 264, subpart X. 

(ii) Regenerate or reactivate the spent 

carbon in a thermal treatment unit 

equipped with and operating air 

emission controls in accordance with 

this section. 

(iii) Regenerate or reactivate the spent 

carbon in a thermal treatment unit 

equipped with and operating organic air 

emission controls in accordance with an 

emissions standard for VOC under 

another subpart in 40 CFR part 60 or 

this part. 

(iv) Burn the spent carbon in a 

hazardous waste incinerator for which 

the owner or operator has been issued 

a final permit under 40 CFR part 270 

that implements the requirements of 40 

CFR part 264, subpart O. 

(v) Burn the spent carbon in a 

hazardous waste incinerator which you 

have designed and operated in 

accordance with the requirements of 40 

CFR part 265, subpart O. 

(vi) Burn the spent carbon in a boiler 

or industrial furnace for which you have 

been issued a final permit under 40 CFR 

part 270 that implements the 

requirements of 40 CFR part 266, 

subpart H. 

(vii) Burn the spent carbon in a boiler 

or industrial furnace that you have 

designed and operated in accordance 

with the interim status requirements of 

40 CFR part 266, subpart H. 

(d) Each control device used to meet 

the emission reduction standard in 

§ 60.5395a(a) for your storage vessel 

affected facility must be installed 

according to paragraphs (d)(1) through 

(3) of this section, as applicable. As an 

alternative to paragraph (d)(1) of this 

section, you may install a control device 

model tested under § 60.5413a(d), 

which meets the criteria in 

§ 60.5413a(d)(11) and § 60.5413a(e). 

(1) For each enclosed combustion 

control device (e.g., thermal vapor 

incinerator, catalytic vapor incinerator, 

boiler, or process heater) you must meet 

the requirements in paragraphs (d)(1)(i) 

through (iv) of this section. 

(i) Ensure that each enclosed 

combustion control device is 

maintained in a leak free condition. 

(ii) Install and operate a continuous 

burning pilot flame. 

(iii) Operate the combustion control 

device with no visible emissions, except 

for periods not to exceed a total of 1 

minute during any 15 minute period. A 

visible emissions test using section 11 of 

EPA Method 22 of appendix A–7 of this 

part must be performed at least once 

every calendar month, separated by at 

least 15 days between each test. The 

observation period shall be 15 minutes. 

Devices failing the visible emissions test 

must follow manufacturer’s repair 

instructions, if available, or best 

combustion engineering practice as 

outlined in the unit inspection and 

maintenance plan, to return the unit to 

compliant operation. All inspection, 

repair and maintenance activities for 

each unit must be recorded in a 

maintenance and repair log and must be 

available for inspection. Following 

return to operation from maintenance or 

repair activity, each device must pass a 

Method 22 of appendix A–7 of this part 

visual observation as described in this 

paragraph. 

(iv) Each combustion control device 

(e.g., thermal vapor incinerator, catalytic 

vapor incinerator, boiler, or process 

heater) must be designed and operated 

in accordance with one of the 

performance requirements specified in 

paragraphs (A) through (D) of this 

section. 

(A) You must reduce the mass content 

of methane and VOC in the gases vented 

to the device by 95.0 percent by weight 

or greater as determined in accordance 

with the requirements of § 60.5413a. 

(B) You must reduce the 

concentration of TOC in the exhaust 

gases at the outlet to the device to a 

level equal to or less than 600 parts per 

million by volume as propane on a dry 

basis corrected to 3 percent oxygen as 

determined in accordance with the 

requirements of § 60.5413a. 

(C) You must operate at a minimum 

temperature of 760 °C for a control 

device that can demonstrate a uniform 

combustion zone temperature during 

the performance test conducted under 

§ 60.5413a. 

(D) If a boiler or process heater is used 

as the control device, then you must 

introduce the vent stream into the flame 

zone of the boiler or process heater. 

(2) Each vapor recovery device (e.g., 

carbon adsorption system or condenser) 

or other non-destructive control device 

must be designed and operated to 

reduce the mass content of methane and 

VOC in the gases vented to the device 

by 95.0 percent by weight or greater. A 

carbon replacement schedule must be 

included in the design of the carbon 

adsorption system. 

(3) You must operate each control 

device used to comply with this subpart 

at all times when gases, vapors, and 

fumes are vented from the storage vessel 

affected facility through the closed vent 

system to the control device. You may 

vent more than one affected facility to 

a control device used to comply with 

this subpart. 

§ 60.5413a What are the performance 

testing procedures for control devices used 

to demonstrate compliance at my 

centrifugal compressor, pneumatic pump 

and storage vessel affected facilities? 

This section applies to the 

performance testing of control devices 

used to demonstrate compliance with 

the emissions standards for your 

centrifugal compressor affected facility, 

pneumatic pump affected facility, or 

storage vessel affected facility. You must 

demonstrate that a control device 

achieves the performance requirements 

of § 60.5412a(a) or (d) using the 

performance test methods and 

procedures specified in this section. For 

condensers and carbon adsorbers, you 

may use a design analysis as specified 

in paragraph (c) of this section in lieu 

of complying with paragraph (b) of this 

section. In addition, this section 

contains the requirements for enclosed 

combustion control device performance 

tests conducted by the manufacturer 

applicable to storage vessel, centrifugal 

compressor and pneumatic pump 

affected facilities. 

(a) Performance test exemptions. You 

are exempt from the requirements to 

conduct performance tests and design 

analyses if you use any of the control 

devices described in paragraphs (a)(1) 

through (7) of this section. 

(1) A flare that is designed and 

operated in accordance with § 60.18(b). 

You must conduct the compliance 

determination using Method 22 of 

appendix A–7 of this part to determine 

visible emissions. 

(2) A boiler or process heater with a 

design heat input capacity of 44 

megawatts or greater. 

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(3) A boiler or process heater into 

which the vent stream is introduced 

with the primary fuel or is used as the 

primary fuel. 

(4) A boiler or process heater burning 

hazardous waste for which you have 

either been issued a final permit under 

40 CFR part 270 and comply with the 

requirements of 40 CFR part 266, 

subpart H; or you have certified 

compliance with the interim status 

requirements of 40 CFR part 266, 

subpart H. 

(5) A hazardous waste incinerator for 

which you have been issued a final 

permit under 40 CFR part 270 and 

comply with the requirements of 40 CFR 

part 264, subpart O; or you have 

certified compliance with the interim 

status requirements of 40 CFR part 265, 

subpart O. 

(6) A performance test is waived in 

accordance with § 60.8(b). 

(7) A control device whose model can 

be demonstrated to meet the 

performance requirements of 

§ 60.5412a(a) or (d) through a 

performance test conducted by the 

manufacturer, as specified in paragraph 

(d) of this section. 

(b) Test methods and procedures. You 

must use the test methods and 

procedures specified in paragraphs 

(b)(1) through (5) of this section, as 

applicable, for each performance test 

conducted to demonstrate that a control 

device meets the requirements of 

§ 60.5412a(a) or (d). You must conduct 

the initial and periodic performance 

tests according to the schedule specified 

in paragraph (b)(5) of this section. 

(1) You must use Method 1 or 1A of 

appendix A–1 of this part, as 

appropriate, to select the sampling sites 

specified in paragraphs (b)(1)(i) and (ii) 

of this section. Any references to 

particulate mentioned in Methods 1 and 

1A do not apply to this section. 

(i) Sampling sites must be located at 

the inlet of the first control device, and 

at the outlet of the final control device, 

to determine compliance with the 

control device percent reduction 

requirement specified in 

§ 60.5412a(a)(1)(i) or (a)(2). 

(ii) The sampling site must be located 

at the outlet of the combustion device to 

determine compliance with the 

enclosed combustion control device 

total TOC concentration limit specified 

in § 60.5412a(a)(1)(ii). 

(2) You must determine the gas 

volumetric flowrate using Method 2, 2A, 

2C, or 2D of appendix A–2 of this part, 

as appropriate. 

(3) To determine compliance with the 

control device percent reduction 

performance requirement in 

§ 60.5412a(a)(1)(i), (a)(2) or (d)(1)(i)(A), 

you must use Method 25A of appendix 

A–7 of this part. You must use the 

procedures in paragraphs (b)(3)(i) 

through (iv) of this section to calculate 

percent reduction efficiency. 

(i) For each run, you must take either 

an integrated sample or a minimum of 

four grab samples per hour. If grab 

sampling is used, then the samples must 

be taken at approximately equal 

intervals in time, such as 15-minute 

intervals during the run. 

(ii) You must compute the mass rate 

of TOC (minus methane and ethane) 

using the equations and procedures 

specified in paragraphs (b)(3)(ii)(A) and 

(B) of this section. 

(A) You must use the following 

equations: 

Where: 

Ei, Eo = Mass rate of TOC (minus methane 

and ethane) at the inlet and outlet of the 

control device, respectively, dry basis, 

kilogram per hour. 

K2 = Constant, 2.494 × 10¥6 (parts per 

million) (gram-mole per standard cubic 

meter) (kilogram/gram) (minute/hour), 

where standard temperature (gram-mole 

per standard cubic meter) is 20 °C. 

Cij, Coj = Concentration of sample component 

j of the gas stream at the inlet and outlet 

of the control device, respectively, dry 

basis, parts per million by volume. 

Mij, Moj = Molecular weight of sample 

component j of the gas stream at the inlet 

and outlet of the control device, 

respectively, gram/gram-mole. 

Qi, Qo = Flowrate of gas stream at the inlet 

and outlet of the control device, 

respectively, dry standard cubic meter 

per minute. 

n = Number of components in sample. 

(B) When calculating the TOC mass 

rate, you must sum all organic 

compounds (minus methane and 

ethane) measured by Method 25A of 

appendix A–7 of this part using the 

equations in paragraph (b)(3)(ii)(A) of 

this section. 

(iii) You must calculate the percent 

reduction in TOC (minus methane and 

ethane) as follows: 

Where: 

Rcd = Control efficiency of control device, 

percent. 

Ei = Mass rate of TOC (minus methane and 

ethane) at the inlet to the control device 

as calculated under paragraph (b)(3)(ii) 

of this section, kilograms TOC per hour 

or kilograms HAP per hour. 

Eo = Mass rate of TOC (minus methane and 

ethane) at the outlet of the control 

device, as calculated under paragraph 

(b)(3)(ii) of this section, kilograms TOC 

per hour per hour. 

(iv) If the vent stream entering a boiler 

or process heater with a design capacity 

less than 44 megawatts is introduced 

with the combustion air or as a 

secondary fuel, you must determine the 

weight-percent reduction of total TOC 

(minus methane and ethane) across the 

device by comparing the TOC (minus 

methane and ethane) in all combusted 

vent streams and primary and secondary 

fuels with the TOC (minus methane and 

ethane) exiting the device, respectively. 

(4) You must use Method 25A of 

appendix A–7 of this part to measure 

TOC (minus methane and ethane) to 

determine compliance with the 

enclosed combustion control device 

total VOC concentration limit specified 

in § 60.5412a(a)(1)(ii) or (d)(1)(iv)(B). 

You must calculate parts per million by 

volume concentration and correct to 3 

percent oxygen, using the procedures in 

paragraphs (b)(4)(i) through (iii) of this 

section. 

(i) For each run, you must take either 

an integrated sample or a minimum of 

four grab samples per hour. If grab 

sampling is used, then the samples must 

be taken at approximately equal 

intervals in time, such as 15-minute 

intervals during the run. 

(ii) You must calculate the TOC 

concentration for each run as follows: 

Where: 

CTOC = Concentration of total organic 

compounds minus methane and ethane, 

dry basis, parts per million by volume. 

Cji = Concentration of sample component j of 

sample i, dry basis, parts per million by 

volume. 

n = Number of components in the sample. 

x = Number of samples in the sample run. 

(iii) You must correct the TOC 

concentration to 3 percent oxygen as 

specified in paragraphs (b)(4)(iii)(A) and 

(B) of this section. 

(A) You must use the emission rate 

correction factor for excess air, 

integrated sampling and analysis 

procedures of Method 3A or 3B of 

appendix A–2 of this part, ASTM 

D6522–00 (Reapproved 2005), or ASME/ 


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ANSI PTC 19.10–1981, Part 10 (manual 

portion only) (incorporated by reference 

as specified in § 60.17) to determine the 

oxygen concentration. The samples 

must be taken during the same time that 

the samples are taken for determining 

TOC concentration. 

(B) You must correct the TOC 

concentration for percent oxygen as 

follows: 

Where: 

Cc = TOC concentration corrected to 3 

percent oxygen, dry basis, parts per 

million by volume. 

Cm = TOC concentration, dry basis, parts per 

million by volume. 

%O2d = Concentration of oxygen, dry basis, 

percent by volume. 

(5) You must conduct performance 

tests according to the schedule specified 

in paragraphs (b)(5)(i) and (ii) of this 

section. 

(i) You must conduct an initial 

performance test within 180 days after 

initial startup for your affected facility. 

You must submit the performance test 

results as required in § 60.5420a(b)(9). 

(ii) You must conduct periodic 

performance tests for all control devices 

required to conduct initial performance 

tests except as specified in paragraphs 

(b)(5)(ii)(A) and (B) of this section. You 

must conduct the first periodic 

performance test no later than 60 

months after the initial performance test 

required in paragraph (b)(5)(i) of this 

section. You must conduct subsequent 

periodic performance tests at intervals 

no longer than 60 months following the 

previous periodic performance test or 

whenever you desire to establish a new 

operating limit. You must submit the 

periodic performance test results as 

specified in § 60.5420a(b)(9). 

Combustion control devices meeting the 

criteria in either paragraph (b)(5)(ii)(A) 

or (B) of this section are not required to 

conduct periodic performance tests. 

(A) A control device whose model is 

tested under, and meets the criteria of 

paragraph (d) of this section. 

(B) A combustion control device 

tested under paragraph (b) of this 

section that meets the outlet TOC 

performance level specified in 

§ 60.5412a(a)(1)(ii) or (d)(1)(iv)(B) and 

that establishes a correlation between 

firebox or combustion chamber 

temperature and the TOC performance 

level. 

(c) Control device design analysis to 

meet the requirements of 

§ 60.5412a(a)(2) or (d)(2). (1) For a 

condenser, the design analysis must 

include an analysis of the vent stream 

composition, constituent 

concentrations, flowrate, relative 

humidity, and temperature, and must 

establish the design outlet organic 

compound concentration level, design 

average temperature of the condenser 

exhaust vent stream, and the design 

average temperatures of the coolant 

fluid at the condenser inlet and outlet. 

(2) For a regenerable carbon 

adsorption system, the design analysis 

shall include the vent stream 

composition, constituent 

concentrations, flowrate, relative 

humidity, and temperature, and shall 

establish the design exhaust vent stream 

organic compound concentration level, 

adsorption cycle time, number and 

capacity of carbon beds, type and 

working capacity of activated carbon 

used for the carbon beds, design total 

regeneration stream flow over the period 

of each complete carbon bed 

regeneration cycle, design carbon bed 

temperature after regeneration, design 

carbon bed regeneration time, and 

design service life of the carbon. 

(3) For a nonregenerable carbon 

adsorption system, such as a carbon 

canister, the design analysis shall 

include the vent stream composition, 

constituent concentrations, flowrate, 

relative humidity, and temperature, and 

shall establish the design exhaust vent 

stream organic compound concentration 

level, capacity of the carbon bed, type 

and working capacity of activated 

carbon used for the carbon bed, and 

design carbon replacement interval 

based on the total carbon working 

capacity of the control device and 

source operating schedule. In addition, 

these systems shall incorporate dual 

carbon canisters in case of emission 

breakthrough occurring in one canister. 

(4) If you and the Administrator do 

not agree on a demonstration of control 

device performance using a design 

analysis, then you must perform a 

performance test in accordance with the 

requirements of paragraph (b) of this 

section to resolve the disagreement. The 

Administrator may choose to have an 

authorized representative observe the 

performance test. 

(d) Performance testing for 

combustion control devices— 

manufacturers’ performance test. (1) 

This paragraph applies to the 

performance testing of a combustion 

control device conducted by the device 

manufacturer. The manufacturer must 

demonstrate that a specific model of 

control device achieves the performance 

requirements in paragraph (d)(11) of this 

section by conducting a performance 

test as specified in paragraphs (d)(2) 

through (10) of this section. You must 

submit a test report for each combustion 

control device in accordance with the 

requirements in paragraph (d)(12) of this 

section. 

(2) Performance testing must consist 

of three 1-hour (or longer) test runs for 

each of the four firing rate settings 

specified in paragraphs (d)(2)(i) through 

(iv) of this section, making a total of 12 

test runs per test. Propene (propylene) 

gas must be used for the testing fuel. All 

fuel analyses must be performed by an 

independent third-party laboratory (not 

affiliated with the control device 

manufacturer or fuel supplier). 

(i) 90–100 percent of maximum 

design rate (fixed rate). 

(ii) 70–100–70 percent (ramp up, 

ramp down). Begin the test at 70 percent 

of the maximum design rate. During the 

first 5 minutes, incrementally ramp the 

firing rate to 100 percent of the 

maximum design rate. Hold at 100 

percent for 5 minutes. In the 10–15 

minute time range, incrementally ramp 

back down to 70 percent of the 

maximum design rate. Repeat three 

more times for a total of 60 minutes of 

sampling. 

(iii) 30–70–30 percent (ramp up, ramp 

down). Begin the test at 30 percent of 

the maximum design rate. During the 

first 5 minutes, incrementally ramp the 

firing rate to 70 percent of the maximum 

design rate. Hold at 70 percent for 5 

minutes. In the 10–15 minute time 

range, incrementally ramp back down to 

30 percent of the maximum design rate. 

Repeat three more times for a total of 60 

minutes of sampling. 

(iv) 0–30–0 percent (ramp up, ramp 

down). Begin the test at the minimum 

firing rate. During the first 5 minutes, 

incrementally ramp the firing rate to 30 

percent of the maximum design rate. 

Hold at 30 percent for 5 minutes. In the 

10–15 minute time range, incrementally 

ramp back down to the minimum firing 

rate. Repeat three more times for a total 

of 60 minutes of sampling. 

(3) All models employing multiple 

enclosures must be tested 

simultaneously and with all burners 

operational. Results must be reported 

for each enclosure individually and for 

the average of the emissions from all 

interconnected combustion enclosures/

chambers. Control device operating data 

must be collected continuously 

throughout the performance test using 

an electronic Data Acquisition System. 

A graphic presentation or strip chart of 

the control device operating data and 

emissions test data must be included in 

the test report in accordance with 

paragraph (d)(12) of this section. Inlet 

fuel meter data may be manually 

recorded provided that all inlet fuel data 

readings are included in the final report. 


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(4) Inlet testing must be conducted as 

specified in paragraphs (d)(4)(i) through 

(ii) of this section. 

(i) The inlet gas flow metering system 

must be located in accordance with 

Method 2A of appendix A–1 of this part 

(or other approved procedure) to 

measure inlet gas flow rate at the control 

device inlet location. You must position 

the fitting for filling fuel sample 

containers a minimum of eight pipe 

diameters upstream of any inlet gas flow 

monitoring meter. 

(ii) Inlet flow rate must be determined 

using Method 2A of appendix A–1 of 

this part. Record the start and stop 

reading for each 60-minute THC test. 

Record the gas pressure and temperature 

at 5-minute intervals throughout each 

60-minute test. 

(5) Inlet gas sampling must be 

conducted as specified in paragraphs 

(d)(5)(i) through (ii) of this section. 

(i) At the inlet gas sampling location, 

securely connect a Silonite-coated 

stainless steel evacuated canister fitted 

with a flow controller sufficient to fill 

the canister over a 3-hour period. Filling 

must be conducted as specified in 

paragraphs (d)(5)(i)(A) through (C) of 

this section. 

(A) Open the canister sampling valve 

at the beginning of each test run, and 

close the canister at the end of each test 

run. 

(B) Fill one canister across the three 

test runs such that one composite fuel 

sample exists for each test condition. 

(C) Label the canisters individually 

and record sample information on a 

chain of custody form. 

(ii) Analyze each inlet gas sample 

using the methods in paragraphs 

(d)(5)(ii)(A) through (C) of this section. 

You must include the results in the test 

report required by paragraph (d)(12) of 

this section. 

(A) Hydrocarbon compounds 

containing between one and five atoms 

of carbon plus benzene using ASTM 

D1945–03. 

(B) Hydrogen (H2), carbon monoxide 

(CO), carbon dioxide (CO2), nitrogen 

(N2), oxygen (O2) using ASTM D1945– 

03. 

(C) Higher heating value using ASTM 

D3588–98 or ASTM D4891–89. 

(6) Outlet testing must be conducted 

in accordance with the criteria in 

paragraphs (d)(6)(i) through (v) of this 

section. 

(i) Sample and flow rate must be 

measured in accordance with 

paragraphs (d)(6)(i)(A) through (B) of 

this section. 

(A) The outlet sampling location must 

be a minimum of four equivalent stack 

diameters downstream from the highest 

peak flame or any other flow 

disturbance, and a minimum of one 

equivalent stack diameter upstream of 

the exit or any other flow disturbance. 

A minimum of two sample ports must 

be used. 

(B) Flow rate must be measured using 

Method 1 of appendix A–1 of this part 

for determining flow measurement 

traverse point location, and Method 2 of 

appendix A–1 of this part for measuring 

duct velocity. If low flow conditions are 

encountered (i.e., velocity pressure 

differentials less than 0.05 inches of 

water) during the performance test, a 

more sensitive manometer must be used 

to obtain an accurate flow profile. 

(ii) Molecular weight and excess air 

must be determined as specified in 

paragraph (d)(7) of this section. 

(iii) Carbon monoxide must be 

determined as specified in paragraph 

(d)(8) of this section. 

(iv) THC must be determined as 

specified in paragraph (d)(9) of this 

section. 

(v) Visible emissions must be 

determined as specified in paragraph 

(d)(10) of this section. 

(7) Molecular weight and excess air 

determination must be performed as 

specified in paragraphs (d)(7)(i) through 

(iii) of this section. 

(i) An integrated bag sample must be 

collected during the moisture test 

required by Method 4 of appendix A–3 

of this part following the procedure 

specified in (d)(7)(i)(A) and (B) of this 

section. Analyze the bag sample using a 

gas chromatograph-thermal conductivity 

detector (GC–TCD) analysis meeting the 

criteria in paragraphs (d)(7)(i)(C) and (D) 

of this section. 

(A) Collect the integrated sample 

throughout the entire test, and collect 

representative volumes from each 

traverse location. 

(B) Purge the sampling line with stack 

gas before opening the valve and 

beginning to fill the bag. Clearly label 

each bag and record sample information 

on a chain of custody form. 

(C) The bag contents must be 

vigorously mixed prior to the gas 

chromatograph analysis. 

(D) The GC–TCD calibration 

procedure in Method 3C of appendix A– 

2 of this part must be modified by using 

EPA Alt-045 as follows: For the initial 

calibration, triplicate injections of any 

single concentration must agree within 

5 percent of their mean to be valid. The 

calibration response factor for a single 

concentration re-check must be within 

10 percent of the original calibration 

response factor for that concentration. If 

this criterion is not met, repeat the 

initial calibration using at least three 

concentration levels. 

(ii) Calculate and report the molecular 

weight of oxygen, carbon dioxide, 

methane, and nitrogen in the integrated 

bag sample and include in the test 

report specified in paragraph (d)(12) of 

this section. Moisture must be 

determined using Method 4 of appendix 

A–3 of this part. Traverse both ports 

with the sampling train required by 

Method 4 of appendix A–3 of this part 

during each test run. Ambient air must 

not be introduced into the integrated 

bag sample required by Method 3C of 

appendix A–2 of this part during the 

port change. 

(iii) Excess air must be determined 

using resultant data from the EPA 

Method 3C tests and EPA Method 3B of 

appendix A–2 of this part, equation 3B– 

1, or ASME/ANSI PTC 19.10–1981, Part 

10 (manual portion only) (incorporated 

by reference as specified in § 60.17). 

(8) Carbon monoxide must be 

determined using Method 10 of 

appendix A–4 of this part. Run the test 

simultaneously with Method 25A of 

appendix A–7 of this part using the 

same sampling points. An instrument 

range of 0–10 parts per million by 

volume-dry (ppmvd) is recommended. 

(9) Total hydrocarbon determination 

must be performed as specified by in 

paragraphs (d)(9)(i) through (vii) of this 

section. 

(i) Conduct THC sampling using 

Method 25A of appendix A–7 of this 

part, except that the option for locating 

the probe in the center 10 percent of the 

stack is not allowed. The THC probe 

must be traversed to 16.7 percent, 50 

percent, and 83.3 percent of the stack 

diameter during each test run. 

(ii) A valid test must consist of three 

Method 25A tests, each no less than 60 

minutes in duration. 

(iii) A 0–10 parts per million by 

volume-wet (ppmvw) (as propane) 

measurement range is preferred; as an 

alternative a 0–30 ppmvw (as carbon) 

measurement range may be used. 

(iv) Calibration gases must be propane 

in air and be certified through EPA 

Protocol 1—‘‘EPA Traceability Protocol 

for Assay and Certification of Gaseous 

Calibration Standards,’’ September 

1997, as amended August 25, 1999, 

EPA–600/R–97/121 (or more recent if 

updated since 1999). 

(v) THC measurements must be 

reported in terms of ppmvw as propane. 

(vi) THC results must be corrected to 

3 percent CO2, as measured by Method 

3C of appendix A–2 of this part. You 

must use the following equation for this 

diluent concentration correction: 


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Where: 

Cmeas = The measured concentration of the 

pollutant. 

CO2meas = The measured concentration of the 

CO2 diluent. 

3 = The corrected reference concentration of 

CO2 diluent. 

Ccorr = The corrected concentration of the 

pollutant. 

(vii) Subtraction of methane or ethane 

from the THC data is not allowed in 

determining results. 

(10) Visible emissions must be 

determined using Method 22 of 

appendix A–7 of this part. The test must 

be performed continuously during each 

test run. A digital color photograph of 

the exhaust point, taken from the 

position of the observer and annotated 

with date and time, must be taken once 

per test run and the 12 photos included 

in the test report specified in paragraph 

(d)(12) of this section. 

(11) Performance test criteria. (i) The 

control device model tested must meet 

the criteria in paragraphs (d)(11)(i)(A) 

through (D) of this section. These 

criteria must be reported in the test 

report required by paragraph (d)(12) of 

this section. 

(A) Results from Method 22 of 

appendix A–7 of this part determined 

under paragraph (d)(10) of this section 

with no indication of visible emissions. 

(B) Average results from Method 25A 

of appendix A–7 of this part determined 

under paragraph (d)(9) of this section 

equal to or less than 10.0 ppmvw THC 

as propane corrected to 3.0 percent CO2. 

(C) Average CO emissions determined 

under paragraph (d)(8) of this section 

equal to or less than 10 parts ppmvd, 

corrected to 3.0 percent CO2. 

(D) Excess air determined under 

paragraph (d)(7) of this section equal to 

or greater than 150 percent. 

(ii) The manufacturer must determine 

a maximum inlet gas flow rate which 

must not be exceeded for each control 

device model to achieve the criteria in 

paragraph (d)(11)(iii) of this section. The 

maximum inlet gas flow rate must be 

included in the test report required by 

paragraph (d)(12) of this section. 

(iii) A control device meeting the 

criteria in paragraphs (d)(11)(i)(A) 

through (D) of this section must 

demonstrate a destruction efficiency of 

95 percent for methane, if applicable, 

and VOC regulated under this subpart. 

(12) The owner or operator of a 

combustion control device model tested 

under this paragraph must submit the 

information listed in paragraphs 

(d)(12)(i) through (vi) in the test report 

required by this section in accordance 

with § 60.5420a(b). Owners or operators 

who claim that any of the performance 

test information being submitted is 

confidential business information (CBI) 

must submit a complete file including 

information claimed to be CBI, on a 

compact disc, flash drive, or other 

commonly used electronic storage 

media to the EPA. The electronic media 

must be clearly marked as CBI and 

mailed to Attn: CBI Officer; OAQPS 

CBIO Room 521; 109 T.W. Alexander 

Drive; RTP, NC 27711. The same file 

with the CBI omitted must be submitted 

to Oil_and_Gas_PT@EPA.GOV. 

(i) A full schematic of the control 

device and dimensions of the device 

components. 

(ii) The maximum net heating value of 

the device. 

(iii) The test fuel gas flow range (in 

both mass and volume). Include the 

maximum allowable inlet gas flow rate. 

(iv) The air/stream injection/assist 

ranges, if used. 

(v) The test conditions listed in 

paragraphs (d)(12)(v)(A) through (O) of 

this section, as applicable for the tested 

model. 

(A) Fuel gas delivery pressure and 

temperature. 

(B) Fuel gas moisture range. 

(C) Purge gas usage range. 

(D) Condensate (liquid fuel) 

separation range. 

(E) Combustion zone temperature 

range. This is required for all devices 

that measure this parameter. 

(F) Excess air range. 

(G) Flame arrestor(s). 

(H) Burner manifold. 

(I) Pilot flame indicator. 

(J) Pilot flame design fuel and 

calculated or measured fuel usage. 

(K) Tip velocity range. 

(L) Momentum flux ratio. 

(M) Exit temperature range. 

(N) Exit flow rate. 

(O) Wind velocity and direction. 

(vi) The test report must include all 

calibration quality assurance/quality 

control data, calibration gas values, gas 

cylinder certification, strip charts, or 

other graphic presentations of the data 

annotated with test times and 

calibration values. 

(e) Continuous compliance for 

combustion control devices tested by the 

manufacturer in accordance with 

paragraph (d) of this section. This 

paragraph applies to the demonstration 

of compliance for a combustion control 

device tested under the provisions in 

paragraph (d) of this section. Owners or 

operators must demonstrate that a 

control device achieves the performance 

criteria in paragraph (d)(11) of this 

section by installing a device tested 

under paragraph (d) of this section, 

complying with the criteria specified in 

paragraphs (e)(1) through (7) of this 

section, maintaining the records 

specified in 60.5420a(b) and submitting 

the reports specified in 60.5420a(c). 

(1) The inlet gas flow rate must be 

equal to or less than the maximum 

specified by the manufacturer. 

(2) A pilot flame must be present at 

all times of operation. 

(3) Devices must be operated with no 

visible emissions, except for periods not 

to exceed a total of 1 minute during any 

15-minute period. A visible emissions 

test conducted according to section 11 

of EPA Method 22 of appendix A–7 of 

this part must be performed at least 

once every calendar month, separated 

by at least 15 days between each test. 

The observation period shall be 15 

minutes. 

(4) Devices failing the visible 

emissions test must follow 

manufacturer’s repair instructions, if 

available, or best combustion 

engineering practice as outlined in the 

unit inspection and maintenance plan, 

to return the unit to compliant 

operation. All repairs and maintenance 

activities for each unit must be recorded 

in a maintenance and repair log and 

must be available for inspection. 

(5) Following return to operation from 

maintenance or repair activity, each 

device must pass a visual observation 

according to EPA Method 22 of 

appendix A–7 of this part as described 

in paragraph (e)(3) of this section. 

(6) If the owner or operator operates 

a combustion control device model 

tested under this section, an electronic 

copy of the performance test results 

required by this section shall be 

submitted via email to Oil_and_Gas_

PT@EPA.GOV unless the test results for 

that model of combustion control device 

are posted at the following Web site: 

epa.gov/airquality/oilandgas/. 

(7) Ensure that each enclosed 

combustion control device is 

maintained in a leak free condition. 

§ 60.5415a How do I demonstrate 

continuous compliance with the standards 

for my well, centrifugal compressor, 

reciprocating compressor, pneumatic 

controller, pneumatic pump, storage vessel, 

collection of fugitive emissions 

components at a well site, and collection of 

fugitive emissions components at a 

compressor station, and affected facilities 

at onshore natural gas processing plants? 

(a) For each well affected facility, you 

must demonstrate continuous 

compliance by submitting the reports 

required by § 60.5420a(b) and 

maintaining the records for each 

completion operation specified in 

§ 60.5420a(c)(1). 

(b) For each centrifugal compressor 

affected facility and each pneumatic 

pump affected facility at a location with 

a control device on site, you must 

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demonstrate continuous compliance 

according to paragraphs (b)(1) through 

(3) of this section. 

(1) You must reduce methane and 

VOC emissions from the wet seal fluid 

degassing system and from the 

pneumatic pump by 95.0 percent or 

greater. 

(2) For each control device used to 

reduce emissions, you must 

demonstrate continuous compliance 

with the performance requirements of 

§ 60.5412a(a) using the procedures 

specified in paragraphs (b)(2)(i) through 

(vii) of this section. If you use a 

condenser as the control device to 

achieve the requirements specified in 

§ 60.5412a(a)(2), you must demonstrate 

compliance according to paragraph 

(b)(2)(viii) of this section. You may 

switch between compliance with 

paragraphs (b)(2)(i) through (vii) of this 

section and compliance with paragraph 

(b)(2)(viii) of this section only after at 

least 1 year of operation in compliance 

with the selected approach. You must 

provide notification of such a change in 

the compliance method in the next 

annual report, as required in 

§ 60.5420a(b), following the change. 

(i) You must operate below (or above) 

the site specific maximum (or 

minimum) parameter value established 

according to the requirements of 

§ 60.5417a(f)(1). 

(ii) You must calculate the daily 

average of the applicable monitored 

parameter in accordance with 

§ 60.5417a(e) except that the inlet gas 

flow rate to the control device must not 

be averaged. 

(iii) Compliance with the operating 

parameter limit is achieved when the 

daily average of the monitoring 

parameter value calculated under 

paragraph (b)(2)(ii) of this section is 

either equal to or greater than the 

minimum monitoring value or equal to 

or less than the maximum monitoring 

value established under paragraph 

(b)(2)(i) of this section. When 

performance testing of a combustion 

control device is conducted by the 

device manufacturer as specified in 

§ 60.5413a(d), compliance with the 

operating parameter limit is achieved 

when the criteria in § 60.5413a(e) are 

met. 

(iv) You must operate the continuous 

monitoring system required in 

§ 60.5417a at all times the affected 

source is operating, except for periods of 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, and required monitoring 

system quality assurance or quality 

control activities (including, as 

applicable, system accuracy audits and 

required zero and span adjustments). A 

monitoring system malfunction is any 

sudden, infrequent, not reasonably 

preventable failure of the monitoring 

system to provide valid data. 

Monitoring system failures that are 

caused in part by poor maintenance or 

careless operation are not malfunctions. 

You are required to complete 

monitoring system repairs in response 

to monitoring system malfunctions and 

to return the monitoring system to 

operation as expeditiously as 

practicable. 

(v) You may not use data recorded 

during monitoring system malfunctions, 

repairs associated with monitoring 

system malfunctions, or required 

monitoring system quality assurance or 

control activities in calculations used to 

report emissions or operating levels. 

You must use all the data collected 

during all other required data collection 

periods to assess the operation of the 

control device and associated control 

system. 

(vi) Failure to collect required data is 

a deviation of the monitoring 

requirements, except for periods of 

monitoring system malfunctions, repairs 

associated with monitoring system 

malfunctions, and required quality 

monitoring system quality assurance or 

quality control activities (including, as 

applicable, system accuracy audits and 

required zero and span adjustments). 

(vii) If you use a combustion control 

device to meet the requirements of 

§ 60.5412a(a) and you demonstrate 

compliance using the test procedures 

specified in § 60.5413a(b), you must 

comply with paragraphs (b)(2)(vii)(A) 

through (D) of this section. 

(A) A pilot flame must be present at 

all times of operation. 

(B) Devices must be operated with no 

visible emissions, except for periods not 

to exceed a total of 1 minute during any 

15-minute period. A visible emissions 

test conducted according to section 11 

of EPA Method 22, 40 CFR part 60, 

appendix A, must be performed at least 

once every calendar month, separated 

by at least 15 days between each test. 

The observation period shall be 15 

minutes. 

(C) Devices failing the visible 

emissions test must follow 

manufacturer’s repair instructions, if 

available, or best combustion 

engineering practice as outlined in the 

unit inspection and maintenance plan, 

to return the unit to compliant 

operation. All repairs and maintenance 

activities for each unit must be recorded 

in a maintenance and repair log and 

must be available for inspection. 

(D) Following return to operation 

from maintenance or repair activity, 

each device must pass a Method 22 of 

appendix A–7 of this part visual 

observation as described in paragraph 

(b)(2)(vii)(B) of this section. 

(viii) If you use a condenser as the 

control device to achieve the percent 

reduction performance requirements 

specified in § 60.5412a(a)(2), you must 

demonstrate compliance using the 

procedures in paragraphs (b)(2)(viii)(A) 

through (E) of this section. 

(A) You must establish a site-specific 

condenser performance curve according 

to § 60.5417a(f)(2). 

(B) You must calculate the daily 

average condenser outlet temperature in 

accordance with § 60.5417a(e). 

(C) You must determine the 

condenser efficiency for the current 

operating day using the daily average 

condenser outlet temperature calculated 

under paragraph (b)(2)(viii)(B) of this 

section and the condenser performance 

curve established under paragraph 

(b)(2)(viii)(A) of this section. 

(D) Except as provided in paragraphs 

(b)(2)(viii)(D)(1) and (2) of this section, 

at the end of each operating day, you 

must calculate the 365-day rolling 

average TOC emission reduction, as 

appropriate, from the condenser 

efficiencies as determined in paragraph 

(b)(2)(viii)(C) of this section. 

(1) After the compliance dates 

specified in § 60.5370a, if you have less 

than 120 days of data for determining 

average TOC emission reduction, you 

must calculate the average TOC 

emission reduction for the first 120 days 

of operation after the compliance date. 

You have demonstrated compliance 

with the overall 95.0 percent reduction 

requirement if the 120-day average TOC 

emission reduction is equal to or greater 

than 95.0 percent. 

(2) After 120 days and no more than 

364 days of operation after the 

compliance date specified in § 60.5370a, 

you must calculate the average TOC 

emission reduction as the TOC emission 

reduction averaged over the number of 

days between the current day and the 

applicable compliance date. You have 

demonstrated compliance with the 

overall 95.0 percent reduction 

requirement if the average TOC 

emission reduction is equal to or greater 

than 95.0 percent. 

(E) If you have data for 365 days or 

more of operation, you have 

demonstrated compliance with the TOC 

emission reduction if the rolling 365- 

day average TOC emission reduction 

calculated in paragraph (b)(2)(viii)(D) of 

this section is equal to or greater than 

95.0 percent. 

(3) You must submit the annual report 

required by 60.5420a(b) and maintain 

the records as specified in 

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§ 60.5420a(c)(2), (6) through (11), and 

(16), as applicable. 

(c) For each reciprocating compressor 

affected facility complying with 

§ 60.5385a(a)(1) or (2), you must 

demonstrate continuous compliance 

according to paragraphs (c)(1) through 

(3) of this section. For each 

reciprocating compressor affected 

facility complying with § 60.5385a(a)(3), 

you must demonstrate continuous 

compliance according to paragraph 

(c)(4) of this section. 

(1) You must continuously monitor 

the number of hours of operation for 

each reciprocating compressor affected 

facility or track the number of months 

since initial startup, or [date 60 days 

after publication of final rule in Federal 

Register], or the date of the most recent 

reciprocating compressor rod packing 

replacement, whichever is later. 

(2) You must submit the annual report 

as required in § 60.5420a(b) and 

maintain records as required in 

§ 60.5420a(c)(3). 

(3) You must replace the reciprocating 

compressor rod packing before the total 

number of hours of operation reaches 

26,000 hours or the number of months 

since the most recent rod packing 

replacement reaches 36 months. 

(4) You must operate the rod packing 

emissions collection system under 

negative pressure and continuously 

comply with the closed vent 

requirements in § 60.5411a(a). 

(d) For each pneumatic controller 

affected facility, you must demonstrate 

continuous compliance according to 

paragraphs (d)(1) through (3) of this 

section. 

(1) You must continuously operate the 

pneumatic controllers as required in 

§ 60.5390a(a), (b), or (c). 

(2) You must submit the annual report 

as required in § 60.5420a(b). 

(3) You must maintain records as 

required in § 60.5420a(c)(4). 

(e) You must demonstrate continuous 

compliance according to paragraph 

(e)(3) of this section for each storage 

vessel affected facility, for which you 

are using a control device or routing 

emissions to a process to meet the 

requirement of § 60.5395a(a)(2). 

(1)–(2) [Reserved] 

(3) For each storage vessel affected 

facility, you must comply with 

paragraphs (e)(3)(i) and (ii) of this 

section. 

(i) You must reduce methane and 

VOC emissions as specified in 

§ 60.5395a(a). 

(ii) For each control device installed 

to meet the requirements of 

§ 60.5395a(a), you must demonstrate 

continuous compliance with the 

performance requirements of 

§ 60.5412a(d) for each storage vessel 

affected facility using the procedure 

specified in paragraph (e)(3)(ii)(A) and 

either (e)(3)(ii)(B) or (e)(3)(ii)(C) of this 

section. 

(A) You must comply with 

§ 60.5416a(c) for each cover and closed 

vent system. 

(B) You must comply with 

§ 60.5417a(h) for each control device. 

(C) Each closed vent system that 

routes emissions to a process must be 

operated as specified in § 60.5411a(c)(2). 

(f) For affected facilities at onshore 

natural gas processing plants, 

continuous compliance with methane 

and VOC requirements is demonstrated 

if you are in compliance with the 

requirements of § 60.5400a. 

(g) For each sweetening unit affected 

facility at onshore natural gas 

processing plants, you must 

demonstrate continuous compliance 

with the standards for SO2 specified in 

§ 60.5405a(b) according to paragraphs 

(g)(1) and (2) of this section. 

(1) The minimum required SO2

emission reduction efficiency (Zc) is 

compared to the emission reduction 

efficiency (R) achieved by the sulfur 

recovery technology. 

(i) If R ≥ Zc, your affected facility is 

in compliance. 

(ii) If R < Zc, your affected facility is 

not in compliance. 

(2) The emission reduction efficiency 

(R) achieved by the sulfur reduction 

technology must be determined using 

the procedures in § 60.5406a(c)(1). 

(h) For each collection of fugitive 

emissions components at a well site and 

each collection of fugitive emissions 

components at a compressor station, 

you must demonstrate continuous 

compliance with the fugitive emission 

standards specified in § 60.5397a 

according to paragraphs (h)(1) through 

(4) of this section. 

(1) You must conduct periodic 

monitoring surveys as required in 

§ 60.5397a(f) through (i). 

(2) You must repair or replace each 

identified source of fugitive emissions 

as required in § 60.5397a(j). 

(3) You must maintain records as 

specified in § 60.5420a(c)(15). 

(4) You must submit annual reports 

for collection of fugitive emissions 

components at a well site and each 

collection of fugitive emissions 

components at a compressor station as 

required in § 60.5420a(b). 

§ 60.5416a What are the initial and 

continuous cover and closed vent system 

inspection and monitoring requirements for 

my centrifugal compressor, reciprocating 

compressor, pneumatic pump and storage 

vessel affected facilities? 

For each closed vent system or cover 

at your storage vessel, centrifugal 

compressor, reciprocating compressor 

and pneumatic pump affected facilities, 

you must comply with the applicable 

requirements of paragraphs (a) through 

(c) of this section. 

(a) Inspections for closed vent systems 

and covers installed on each centrifugal 

compressor, reciprocating compressor 

or pneumatic pump affected facility. 

Except as provided in paragraphs (b)(11) 

and (12) of this section, you must 

inspect each closed vent system 

according to the procedures and 

schedule specified in paragraphs (a)(1) 

and (2) of this section, inspect each 

cover according to the procedures and 

schedule specified in paragraph (a)(3) of 

this section, and inspect each bypass 

device according to the procedures of 

paragraph (a)(4) of this section. 

(1) For each closed vent system joint, 

seam, or other connection that is 

permanently or semi-permanently 

sealed (e.g., a welded joint between two 

sections of hard piping or a bolted and 

gasketed ducting flange), you must meet 

the requirements specified in 

paragraphs (a)(1)(i) and (ii) of this 

section. 

(i) Conduct an initial inspection 

according to the test methods and 

procedures specified in paragraph (b) of 

this section to demonstrate that the 

closed vent system operates with no 

detectable emissions. You must 

maintain records of the inspection 

results as specified in § 60.5420a(c)(6). 

(ii) Conduct annual visual inspections 

for defects that could result in air 

emissions. Defects include, but are not 

limited to, visible cracks, holes, or gaps 

in piping; loose connections; liquid 

leaks; or broken or missing caps or other 

closure devices. You must monitor a 

component or connection using the test 

methods and procedures in paragraph 

(b) of this section to demonstrate that it 

operates with no detectable emissions 

following any time the component is 

repaired or replaced or the connection 

is unsealed. You must maintain records 

of the inspection results as specified in 

§ 60.5420a(c)(6). 

(2) For closed vent system 

components other than those specified 

in paragraph (a)(1) of this section, you 

must meet the requirements of 

paragraphs (a)(2)(i) through (iii) of this 

section. 

(i) Conduct an initial inspection 

according to the test methods and 

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procedures specified in paragraph (b) of 

this section to demonstrate that the 

closed vent system operates with no 

detectable emissions. You must 

maintain records of the inspection 

results as specified in § 60.5420a(c)(6). 

(ii) Conduct annual inspections 

according to the test methods and 

procedures specified in paragraph (b) of 

this section to demonstrate that the 

components or connections operate 

with no detectable emissions. You must 

maintain records of the inspection 

results as specified in § 60.5420a(c)(6). 

(iii) Conduct annual visual 

inspections for defects that could result 

in air emissions. Defects include, but are 

not limited to, visible cracks, holes, or 

gaps in ductwork; loose connections; 

liquid leaks; or broken or missing caps 

or other closure devices. You must 

maintain records of the inspection 

results as specified in § 60.5420a(c)(6). 

(3) For each cover, you must meet the 

requirements in paragraphs (a)(3)(i) and 

(ii) of this section. 

(i) Conduct visual inspections for 

defects that could result in air 

emissions. Defects include, but are not 

limited to, visible cracks, holes, or gaps 

in the cover, or between the cover and 

the separator wall; broken, cracked, or 

otherwise damaged seals or gaskets on 

closure devices; and broken or missing 

hatches, access covers, caps, or other 

closure devices. In the case where the 

storage vessel is buried partially or 

entirely underground, you must inspect 

only those portions of the cover that 

extend to or above the ground surface, 

and those connections that are on such 

portions of the cover (e.g., fill ports, 

access hatches, gauge wells, etc.) and 

can be opened to the atmosphere. 

(ii) You must initially conduct the 

inspections specified in paragraph 

(a)(3)(i) of this section following the 

installation of the cover. Thereafter, you 

must perform the inspection at least 

once every calendar year, except as 

provided in paragraphs (b)(11) and (12) 

of this section. You must maintain 

records of the inspection results as 

specified in § 60.5420a(c)(7). 

(4) For each bypass device, except as 

provided for in § 60.5411a, you must 

meet the requirements of paragraphs 

(a)(4)(i) or (ii) of this section. 

(i) Set the flow indicator to take a 

reading at least once every 15 minutes 

at the inlet to the bypass device that 

could divert the steam away from the 

control device to the atmosphere. 

(ii) If the bypass device valve installed 

at the inlet to the bypass device is 

secured in the non-diverting position 

using a car-seal or a lock-and-key type 

configuration, visually inspect the seal 

or closure mechanism at least once 

every month to verify that the valve is 

maintained in the non-diverting 

position and the vent stream is not 

diverted through the bypass device. You 

must maintain records of the 

inspections according to 

§ 60.5420a(c)(8). 

(b) No detectable emissions test 

methods and procedures. If you are 

required to conduct an inspection of a 

closed vent system or cover at your 

centrifugal compressor, reciprocating 

compressor, or pneumatic pump 

affected facility as specified in 

paragraphs (a)(1), (2), or (3) of this 

section, you must meet the requirements 

of paragraphs (b)(1) through (13) of this 

section. 

(1) You must conduct the no 

detectable emissions test procedure in 

accordance with Method 21 of appendix 

A–7 of this part. 

(2) The detection instrument must 

meet the performance criteria of Method 

21 of appendix A–7 of this part, except 

that the instrument response factor 

criteria in section 8.1.1 of Method 21 

must be for the average composition of 

the fluid and not for each individual 

organic compound in the stream. 

(3) You must calibrate the detection 

instrument before use on each day of its 

use by the procedures specified in 

Method 21 of appendix A–7 of this part. 

(4) Calibration gases must be as 

specified in paragraphs (b)(4)(i) and (ii) 

of this section. 

(i) Zero air (less than 10 parts per 

million by volume hydrocarbon in air). 

(ii) A mixture of methane in air at a 

concentration less than 10,000 parts per 

million by volume. 

(5) You may choose to adjust or not 

adjust the detection instrument readings 

to account for the background organic 

concentration level. If you choose to 

adjust the instrument readings for the 

background level, you must determine 

the background level value according to 

the procedures in Method 21 of 

appendix A–7 of this part. 

(6) Your detection instrument must 

meet the performance criteria specified 

in paragraphs (b)(6)(i) and (ii) of this 

section. 

(i) Except as provided in paragraph 

(b)(6)(ii) of this section, the detection 

instrument must meet the performance 

criteria of Method 21 of appendix A–7 

of this part, except the instrument 

response factor criteria in section 8.1.1 

of Method 21 must be for the average 

composition of the process fluid, not 

each individual volatile organic 

compound in the stream. For process 

streams that contain nitrogen, air, or 

other inerts that are not organic 

hazardous air pollutants or volatile 

organic compounds, you must calculate 

the average stream response factor on an 

inert-free basis. 

(ii) If no instrument is available that 

will meet the performance criteria 

specified in paragraph (b)(6)(i) of this 

section, you may adjust the instrument 

readings by multiplying by the average 

response factor of the process fluid, 

calculated on an inert-free basis, as 

described in paragraph (b)(6)(i) of this 

section. 

(7) You must determine if a potential 

leak interface operates with no 

detectable emissions using the 

applicable procedure specified in 

paragraph (b)(7)(i) or (ii) of this section. 

(i) If you choose not to adjust the 

detection instrument readings for the 

background organic concentration level, 

then you must directly compare the 

maximum organic concentration value 

measured by the detection instrument to 

the applicable value for the potential 

leak interface as specified in paragraph 

(b)(8) of this section. 

(ii) If you choose to adjust the 

detection instrument readings for the 

background organic concentration level, 

you must compare the value of the 

arithmetic difference between the 

maximum organic concentration value 

measured by the instrument and the 

background organic concentration value 

as determined in paragraph (b)(5) of this 

section with the applicable value for the 

potential leak interface as specified in 

paragraph (b)(8) of this section. 

(8) A potential leak interface is 

determined to operate with no 

detectable organic emissions if the 

organic concentration value determined 

in paragraph (b)(7) of this section is less 

than 500 parts per million by volume. 

(9) Repairs. In the event that a leak or 

defect is detected, you must repair the 

leak or defect as soon as practicable 

according to the requirements of 

paragraphs (b)(9)(i) and (ii) of this 

section, except as provided in paragraph 

(b)(10) of this section. 

(i) A first attempt at repair must be 

made no later than 5 calendar days after 

the leak is detected. 

(ii) Repair must be completed no later 

than 15 calendar days after the leak is 

detected. 

(10) Delay of repair. Delay of repair of 

a closed vent system or cover for which 

leaks or defects have been detected is 

allowed if the repair is technically 

infeasible without a shutdown, or if you 

determine that emissions resulting from 

immediate repair would be greater than 

the fugitive emissions likely to result 

from delay of repair. You must complete 

repair of such equipment by the end of 

the next shutdown. 

(11) Unsafe to inspect requirements. 

You may designate any parts of the 

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closed vent system or cover as unsafe to 

inspect if the requirements in 

paragraphs (b)(11)(i) and (ii) of this 

section are met. Unsafe to inspect parts 

are exempt from the inspection 

requirements of paragraphs (a)(1) 

through (3) of this section. 

(i) You determine that the equipment 

is unsafe to inspect because inspecting 

personnel would be exposed to an 

imminent or potential danger as a 

consequence of complying with 

paragraphs (a)(1), (2), or (3) of this 

section. 

(ii) You have a written plan that 

requires inspection of the equipment as 

frequently as practicable during safe-toinspect times. 

(12) Difficult to inspect requirements. 

You may designate any parts of the 

closed vent system or cover as difficult 

to inspect, if the requirements in 

paragraphs (b)(12)(i) and (ii) of this 

section are met. Difficult to inspect parts 

are exempt from the inspection 

requirements of paragraphs (a)(1) 

through (3) of this section. 

(i) You determine that the equipment 

cannot be inspected without elevating 

the inspecting personnel more than 2 

meters above a support surface. 

(ii) You have a written plan that 

requires inspection of the equipment at 

least once every 5 years. 

(13) Records. Records shall be 

maintained as specified in this section 

and in § 60.5420a(c)(9). 

(c) Cover and closed vent system 

inspections for storage vessel affected 

facilities. If you install a control device 

or route emissions to a process, you 

must inspect each closed vent system 

according to the procedures and 

schedule specified in paragraphs (c)(1) 

of this section, inspect each cover 

according to the procedures and 

schedule specified in paragraph (c)(2) of 

this section, and inspect each bypass 

device according to the procedures of 

paragraph (c)(3) of this section. You 

must also comply with the requirements 

of (c)(4) through (7) of this section. 

(1) For each closed vent system, you 

must conduct an inspection at least 

once every calendar month as specified 

in paragraphs (c)(1)(i) through (iii) of 

this section. 

(i) You must maintain records of the 

inspection results as specified in 

§ 60.5420a(c)(6). 

(ii) Conduct olfactory, visual and 

auditory inspections for defects that 

could result in air emissions. Defects 

include, but are not limited to, visible 

cracks, holes, or gaps in piping; loose 

connections; liquid leaks; or broken or 

missing caps or other closure devices. 

(iii) Monthly inspections must be 

separated by at least 14 calendar days. 

(2) For each cover, you must conduct 

inspections at least once every calendar 

month as specified in paragraphs 

(c)(2)(i) through (iii) of this section. 

(i) You must maintain records of the 

inspection results as specified in 

§ 60.5420a(c)(7). 

(ii) Conduct olfactory, visual and 

auditory inspections for defects that 

could result in air emissions. Defects 

include, but are not limited to, visible 

cracks, holes, or gaps in the cover, or 

between the cover and the separator 

wall; broken, cracked, or otherwise 

damaged seals or gaskets on closure 

devices; and broken or missing hatches, 

access covers, caps, or other closure 

devices. In the case where the storage 

vessel is buried partially or entirely 

underground, you must inspect only 

those portions of the cover that extend 

to or above the ground surface, and 

those connections that are on such 

portions of the cover (e.g., fill ports, 

access hatches, gauge wells, etc.) and 

can be opened to the atmosphere. 

(iii) Monthly inspections must be 

separated by at least 14 calendar days. 

(3) For each bypass device, except as 

provided for in § 60.5411a(c)(3)(ii), you 

must meet the requirements of 

paragraphs (c)(3)(i) or (ii) of this section. 

(i) You must properly install, calibrate 

and maintain a flow indicator at the 

inlet to the bypass device that could 

divert the stream away from the control 

device or process to the atmosphere. Set 

the flow indicator to trigger an audible 

and visible alarm, and initiate 

notification via remote alarm to the 

nearest field office, when the bypass 

device is open such that the stream is 

being, or could be, diverted away from 

the control device or process to the 

atmosphere. You must maintain records 

of each time the alarm is sounded 

according to § 60.5420a(c)(8). 

(ii) If the bypass device valve installed 

at the inlet to the bypass device is 

secured in the non-diverting position 

using a car-seal or a lock-and-key type 

configuration, visually inspect the seal 

or closure mechanism at least once 

every month to verify that the valve is 

maintained in the non-diverting 

position and the vent stream is not 

diverted through the bypass device. You 

must maintain records of the 

inspections and records of each time the 

key is checked out, if applicable, 

according to § 60.5420a(c)(8). 

(4) Repairs. In the event that a leak or 

defect is detected, you must repair the 

leak or defect as soon as practicable 

according to the requirements of 

paragraphs (c)(4)(i) through (iii) of this 

section, except as provided in paragraph 

(c)(5) of this section. 

(i) A first attempt at repair must be 

made no later than 5 calendar days after 

the leak is detected. 

(ii) Repair must be completed no later 

than 30 calendar days after the leak is 

detected. 

(iii) Grease or another applicable 

substance must be applied to 

deteriorating or cracked gaskets to 

improve the seal while awaiting repair. 

(5) Delay of repair. Delay of repair of 

a closed vent system or cover for which 

leaks or defects have been detected is 

allowed if the repair is technically 

infeasible without a shutdown, or if you 

determine that emissions resulting from 

immediate repair would be greater than 

the fugitive emissions likely to result 

from delay of repair. You must complete 

repair of such equipment by the end of 

the next shutdown. 

(6) Unsafe to inspect requirements. 

You may designate any parts of the 

closed vent system or cover as unsafe to 

inspect if the requirements in 

paragraphs (c)(6)(i) and (ii) of this 

section are met. Unsafe to inspect parts 

are exempt from the inspection 

requirements of paragraphs (c)(1) and 

(2) of this section. 

(i) You determine that the equipment 

is unsafe to inspect because inspecting 

personnel would be exposed to an 

imminent or potential danger as a 

consequence of complying with 

paragraphs (c)(1) or (2) of this section. 

(ii) You have a written plan that 

requires inspection of the equipment as 

frequently as practicable during safe-toinspect times. 

(7) Difficult to inspect requirements. 

You may designate any parts of the 

closed vent system or cover as difficult 

to inspect, if the requirements in 

paragraphs (c)(7)(i) and (ii) of this 

section are met. Difficult to inspect parts 

are exempt from the inspection 

requirements of paragraphs (c)(1) and 

(2) of this section. 

(i) You determine that the equipment 

cannot be inspected without elevating 

the inspecting personnel more than 2 

meters above a support surface. 

(ii) You have a written plan that 

requires inspection of the equipment at 

least once every 5 years. 

§ 60.5417a What are the continuous 

control device monitoring requirements for 

my centrifugal compressor, pneumatic 

pump, and storage vessel affected 

facilities? 

You must meet the applicable 

requirements of this section to 

demonstrate continuous compliance for 

each control device used to meet 

emission standards for your storage 

vessel, centrifugal compressor or 

pneumatic pump affected facility. 

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(a) For each control device used to 

comply with the emission reduction 

standard for centrifugal compressor 

affected facilities in § 60.5380a(a)(1) or 

the emission reduction standard for 

pneumatic pumps affected facilities in 

§ 60.5393a(b)(1), you must install and 

operate a continuous parameter 

monitoring system for each control 

device as specified in paragraphs (c) 

through (g) of this section, except as 

provided for in paragraph (b) of this 

section. If you install and operate a flare 

in accordance with § 60.5412a(a)(3), you 

are exempt from the requirements of 

paragraphs (e) and (f) of this section. 

(b) You are exempt from the 

monitoring requirements specified in 

paragraphs (c) through (g) of this section 

for the control devices listed in 

paragraphs (b)(1) and (2) of this section. 

(1) A boiler or process heater in which 

all vent streams are introduced with the 

primary fuel or are used as the primary 

fuel. 

(2) A boiler or process heater with a 

design heat input capacity equal to or 

greater than 44 megawatts. 

(c) If you are required to install a 

continuous parameter monitoring 

system, you must meet the 

specifications and requirements in 

paragraphs (c)(1) through (4) of this 

section. 

(1) Each continuous parameter 

monitoring system must measure data 

values at least once every hour and 

record the parameters in paragraphs 

(c)(1)(i) or (ii) of this section. 

(i) Each measured data value. 

(ii) Each block average value for each 

1-hour period or shorter periods 

calculated from all measured data 

values during each period. If values are 

measured more frequently than once per 

minute, a single value for each minute 

may be used to calculate the hourly (or 

shorter period) block average instead of 

all measured values. 

(2) You must prepare a site-specific 

monitoring plan that addresses the 

monitoring system design, data 

collection, and the quality assurance 

and quality control elements outlined in 

paragraphs (c)(2)(i) through (v) of this 

section. You must install, calibrate, 

operate, and maintain each continuous 

parameter monitoring system in 

accordance with the procedures in your 

approved site-specific monitoring plan. 

(i) The performance criteria and 

design specifications for the monitoring 

system equipment, including the sample 

interface, detector signal analyzer, and 

data acquisition and calculations. 

(ii) Sampling interface (e.g., 

thermocouple) location such that the 

monitoring system will provide 

representative measurements. 

(iii) Equipment performance checks, 

system accuracy audits, or other audit 

procedures. 

(iv) Ongoing operation and 

maintenance procedures in accordance 

with provisions in § 60.13(b). 

(v) Ongoing reporting and 

recordkeeping procedures in accordance 

with provisions in § 60.7(c), (d), and (f). 

(3) You must conduct the continuous 

parameter monitoring system equipment 

performance checks, system accuracy 

audits, or other audit procedures 

specified in the site-specific monitoring 

plan at least once every 12 months. 

(4) You must conduct a performance 

evaluation of each continuous 

parameter monitoring system in 

accordance with the site-specific 

monitoring plan. 

(d) You must install, calibrate, 

operate, and maintain a device 

equipped with a continuous recorder to 

measure the values of operating 

parameters appropriate for the control 

device as specified in paragraph (d)(1), 

(2), or (3) of this section. 

(1) A continuous monitoring system 

that measures the operating parameters 

in paragraphs (d)(1)(i) through (viii) of 

this section, as applicable. 

(i) For a thermal vapor incinerator 

that demonstrates during the 

performance test conducted under 

§ 60.5413a that combustion zone 

temperature is an accurate indicator of 

performance, a temperature monitoring 

device equipped with a continuous 

recorder. The monitoring device must 

have a minimum accuracy of ±1 percent 

of the temperature being monitored in 

°C, or ±2.5 °C, whichever value is 

greater. You must install the 

temperature sensor at a location 

representative of the combustion zone 

temperature. 

(ii) For a catalytic vapor incinerator, 

a temperature monitoring device 

equipped with a continuous recorder. 

The device must be capable of 

monitoring temperature at two locations 

and have a minimum accuracy of ±1 

percent of the temperature being 

monitored in °C, or ±2.5 °C, whichever 

value is greater. You must install one 

temperature sensor in the vent stream at 

the nearest feasible point to the catalyst 

bed inlet, and you must install a second 

temperature sensor in the vent stream at 

the nearest feasible point to the catalyst 

bed outlet. 

(iii) For a flare, a heat sensing 

monitoring device equipped with a 

continuous recorder that indicates the 

continuous ignition of the pilot flame. 

(iv) For a boiler or process heater, a 

temperature monitoring device 

equipped with a continuous recorder. 

The temperature monitoring device 

must have a minimum accuracy of ±1 

percent of the temperature being 

monitored in °C, or ±2.5 °C, whichever 

value is greater. You must install the 

temperature sensor at a location 

representative of the combustion zone 

temperature. 

(v) For a condenser, a temperature 

monitoring device equipped with a 

continuous recorder. The temperature 

monitoring device must have a 

minimum accuracy of ±1 percent of the 

temperature being monitored in °C, or 

±2.5 °C, whichever value is greater. You 

must install the temperature sensor at a 

location in the exhaust vent stream from 

the condenser. 

(vi) For a regenerative-type carbon 

adsorption system, a continuous 

monitoring system that meets the 

specifications in paragraphs (d)(1)(vi)(A) 

and (B) of this section. 

(A) The continuous parameter 

monitoring system must measure and 

record the average total regeneration 

stream mass flow or volumetric flow 

during each carbon bed regeneration 

cycle. The flow sensor must have a 

measurement sensitivity of 5 percent of 

the flow rate or 10 cubic feet per 

minute, whichever is greater. You must 

check the mechanical connections for 

leakage at least every month, and you 

must perform a visual inspection at least 

every 3 months of all components of the 

flow continuous parameter monitoring 

system for physical and operational 

integrity and all electrical connections 

for oxidation and galvanic corrosion if 

your flow continuous parameter 

monitoring system is not equipped with 

a redundant flow sensor; and 

(B) The continuous parameter 

monitoring system must measure and 

record the average carbon bed 

temperature for the duration of the 

carbon bed steaming cycle and measure 

the actual carbon bed temperature after 

regeneration and within 15 minutes of 

completing the cooling cycle. The 

temperature monitoring device must 

have a minimum accuracy of ±1 percent 

of the temperature being monitored in 

°C, or ±2.5 °C, whichever value is 

greater. 

(vii) For a nonregenerative-type 

carbon adsorption system, you must 

monitor the design carbon replacement 

interval established using a design 

analysis performed as specified in 

§ 60.5413a(c)(3). The design carbon 

replacement interval must be based on 

the total carbon working capacity of the 

control device and source operating 

schedule. 

(viii) For a combustion control device 

whose model is tested under 

§ 60.5413a(d), a continuous monitoring 

system meeting the requirements of 

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paragraphs (d)(1)(viii)(A) and (B) of this 

section. 

(A) The continuous monitoring 

system must measure gas flow rate at 

the inlet to the control device. The 

monitoring instrument must have an 

accuracy of ±2 percent or better. The 

flow rate at the inlet to the combustion 

device must not exceed the maximum or 

be less than the minimum flow rate 

determined by the manufacturer. 

(B) A monitoring device that 

continuously indicates the presence of 

the pilot flame while emissions are 

routed to the control device. 

(2) An organic monitoring device 

equipped with a continuous recorder 

that measures the concentration level of 

organic compounds in the exhaust vent 

stream from the control device. The 

monitor must meet the requirements of 

Performance Specification 8 or 9 of 

appendix B of this part. You must 

install, calibrate, and maintain the 

monitor according to the manufacturer’s 

specifications. 

(3) A continuous monitoring system 

that measures operating parameters 

other than those specified in paragraph 

(d)(1) or (2) of this section, upon 

approval of the Administrator as 

specified in § 60.13(i). 

(e) You must calculate the daily 

average value for each monitored 

operating parameter for each operating 

day, using the data recorded by the 

monitoring system, except for inlet gas 

flow rate. If the emissions unit operation 

is continuous, the operating day is a 24- 

hour period. If the emissions unit 

operation is not continuous, the 

operating day is the total number of 

hours of control device operation per 

24-hour period. Valid data points must 

be available for 75 percent of the 

operating hours in an operating day to 

compute the daily average. 

(f) For each operating parameter 

monitor installed in accordance with 

the requirements of paragraph (d) of this 

section, you must comply with 

paragraph (f)(1) of this section for all 

control devices. When condensers are 

installed, you must also comply with 

paragraph (f)(2) of this section. 

(1) You must establish a minimum 

operating parameter value or a 

maximum operating parameter value, as 

appropriate for the control device, to 

define the conditions at which the 

control device must be operated to 

continuously achieve the applicable 

performance requirements of 

§ 60.5412a(a). You must establish each 

minimum or maximum operating 

parameter value as specified in 

paragraphs (f)(1)(i) through (iii) of this 

section. 

(i) If you conduct performance tests in 

accordance with the requirements of 

§ 60.5413a(b) to demonstrate that the 

control device achieves the applicable 

performance requirements specified in 

§ 60.5412a(a), then you must establish 

the minimum operating parameter value 

or the maximum operating parameter 

value based on values measured during 

the performance test and supplemented, 

as necessary, by a condenser design 

analysis or control device manufacturer 

recommendations or a combination of 

both. 

(ii) If you use a condenser design 

analysis in accordance with the 

requirements of § 60.5413a(c) to 

demonstrate that the control device 

achieves the applicable performance 

requirements specified in § 60.5412a(a), 

then you must establish the minimum 

operating parameter value or the 

maximum operating parameter value 

based on the condenser design analysis 

and supplemented, as necessary, by the 

condenser manufacturer’s 

recommendations. 

(iii) If you operate a control device 

where the performance test requirement 

was met under § 60.5413a(d) to 

demonstrate that the control device 

achieves the applicable performance 

requirements specified in § 60.5412a(a), 

then your control device inlet gas flow 

rate must not exceed the maximum or 

be less than the minimum inlet gas flow 

rate determined by the manufacturer. 

(2) If you use a condenser as specified 

in paragraph (d)(1)(v) of this section, 

you must establish a condenser 

performance curve showing the 

relationship between condenser outlet 

temperature and condenser control 

efficiency, according to the 

requirements of paragraphs (f)(2)(i) and 

(ii) of this section. 

(i) If you conduct a performance test 

in accordance with the requirements of 

§ 60.5413a(b) to demonstrate that the 

condenser achieves the applicable 

performance requirements in 

§ 60.5412a(a), then the condenser 

performance curve must be based on 

values measured during the 

performance test and supplemented as 

necessary by control device design 

analysis, or control device 

manufacturer’s recommendations, or a 

combination or both. 

(ii) If you use a control device design 

analysis in accordance with the 

requirements of § 60.5413a(c)(1) to 

demonstrate that the condenser achieves 

the applicable performance 

requirements specified in § 60.5412a(a), 

then the condenser performance curve 

must be based on the condenser design 

analysis and supplemented, as 

necessary, by the control device 

manufacturer’s recommendations. 

(g) A deviation for a given control 

device is determined to have occurred 

when the monitoring data or lack of 

monitoring data result in any one of the 

criteria specified in paragraphs (g)(1) 

through (g)(6) of this section being met. 

If you monitor multiple operating 

parameters for the same control device 

during the same operating day and more 

than one of these operating parameters 

meets a deviation criterion specified in 

paragraphs (g)(1) through (6) of this 

section, then a single excursion is 

determined to have occurred for the 

control device for that operating day. 

(1) A deviation occurs when the daily 

average value of a monitored operating 

parameter is less than the minimum 

operating parameter limit (or, if 

applicable, greater than the maximum 

operating parameter limit) established 

in paragraph (f)(1) of this section. 

(2) If you are subject to 

§ 60.5412a(a)(2), a deviation occurs 

when the 365-day average condenser 

efficiency calculated according to the 

requirements specified in 

§ 60.5415a(b)(2)(viii)(D) is less than 95.0 

percent. 

(3) If you are subject to 

§ 60.5412a(a)(2) and you have less than 

365 days of data, a deviation occurs 

when the average condenser efficiency 

calculated according to the procedures 

specified in § 60.5415a(b)(2)(viii)(D)(1) 

or (2) is less than 95.0 percent. 

(4) A deviation occurs when the 

monitoring data are not available for at 

least 75 percent of the operating hours 

in a day. 

(5) If the closed vent system contains 

one or more bypass devices that could 

be used to divert all or a portion of the 

gases, vapors, or fumes from entering 

the control device, a deviation occurs 

when the requirements of paragraph 

(g)(5)(i) or (ii) of this section are met. 

(i) For each bypass line subject to 

§ 60.5411a(a)(3)(i)(A), the flow indicator 

indicates that flow has been detected 

and that the stream has been diverted 

away from the control device to the 

atmosphere. 

(ii) For each bypass line subject to 

§ 60.5411a(a)(3)(i)(B), if the seal or 

closure mechanism has been broken, the 

bypass line valve position has changed, 

the key for the lock-and-key type lock 

has been checked out, or the car-seal has 

broken. 

(6) For a combustion control device 

whose model is tested under 

§ 60.5413a(d), a deviation occurs when 

the conditions of paragraphs (g)(6)(i) or 

(ii) are met. 

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(i) The inlet gas flow rate exceeds the 

maximum established during the test 

conducted under § 60.5413a(d). 

(ii) Failure of the monthly visible 

emissions test conducted under 

§ 60.5413a(e)(3) occurs. 

(h) For each control device used to 

comply with the emission reduction 

standard in § 60.5395a(a)(2) for your 

storage vessel affected facility, you must 

demonstrate continuous compliance 

according to paragraphs (h)(1) through 

(h)(4) of this section. You are exempt 

from the requirements of this paragraph 

if you install a control device model 

tested in accordance with 

§ 60.5413a(d)(2) through (10), which 

meets the criteria in § 60.5413a(d)(11), 

the reporting requirement in 

§ 60.5413a(d)(12), and meet the 

continuous compliance requirement in 

§ 60.5413a(e). 

(1) For each combustion device you 

must conduct inspections at least once 

every calendar month according to 

paragraphs (h)(1)(i) through (iv) of this 

section. Monthly inspections must be 

separated by at least 14 calendar days. 

(i) Conduct visual inspections to 

confirm that the pilot is lit when vapors 

are being routed to the combustion 

device and that the continuous burning 

pilot flame is operating properly. 

(ii) Conduct inspections to monitor 

for visible emissions from the 

combustion device using section 11 of 

EPA Method 22 of appendix A of this 

part. The observation period shall be 15 

minutes. Devices must be operated with 

no visible emissions, except for periods 

not to exceed a total of 1 minute during 

any 15 minute period. 

(iii) Conduct olfactory, visual and 

auditory inspections of all equipment 

associated with the combustion device 

to ensure system integrity. 

(iv) For any absence of the pilot flame, 

or other indication of smoking or 

improper equipment operation (e.g., 

visual, audible, or olfactory), you must 

ensure the equipment is returned to 

proper operation as soon as practicable 

after the event occurs. At a minimum, 

you must perform the procedures 

specified in paragraphs (h)(1)(iv)(A) and 

(B) of this section. 

(A) You must check the air vent for 

obstruction. If an obstruction is 

observed, you must clear the obstruction 

as soon as practicable. 

(B) You must check for liquid 

reaching the combustor. 

(2) For each vapor recovery device, 

you must conduct inspections at least 

once every calendar month to ensure 

physical integrity of the control device 

according to the manufacturer’s 

instructions. Monthly inspections must 

be separated by at least 14 calendar 

days. 

(3) Each control device must be 

operated following the manufacturer’s 

written operating instructions, 

procedures and maintenance schedule 

to ensure good air pollution control 

practices for minimizing emissions. 

Records of the manufacturer’s written 

operating instructions, procedures, and 

maintenance schedule must be available 

for inspection as specified in 

§ 60.5420a(c)(13). 

(4) Conduct a periodic performance 

test no later than 60 months after the 

initial performance test as specified in 

§ 60.5413a(b)(5)(ii) and conduct 

subsequent periodic performance tests 

at intervals no longer than 60 months 

following the previous periodic 

performance test. 

§ 60.5420a What are my notification, 

reporting, and recordkeeping 

requirements? 

(a) You must submit the notifications 

according to paragraphs (a)(1) and (2) of 

this section if you own or operate one 

or more of the affected facilities 

specified in § 60.5365a that was 

constructed, modified, or reconstructed 

during the reporting period. 

(1) If you own or operate a well, 

centrifugal compressor, reciprocating 

compressor, pneumatic controller, 

pneumatic pump, storage vessel, or 

collection of fugitive emissions 

components at a well site or collection 

of fugitive emissions components at a 

compressor station you are not required 

to submit the notifications required in 

§ 60.7(a)(1), (3), and (4). 

(2)(i) If you own or operate a well 

affected facility, you must submit a 

notification to the Administrator no 

later than 2 days prior to the 

commencement of each well completion 

operation listing the anticipated date of 

the well completion operation. The 

notification shall include contact 

information for the owner or operator; 

the API well number; the latitude and 

longitude coordinates for each well in 

decimal degrees to an accuracy and 

precision of five (5) decimals of a degree 

using the North American Datum of 

1983; and the planned date of the 

beginning of flowback. You may submit 

the notification in writing or in 

electronic format. 

(ii) If you are subject to state 

regulations that require advance 

notification of well completions and 

you have met those notification 

requirements, then you are considered 

to have met the advance notification 

requirements of paragraph (a)(2)(i) of 

this section. 

(b) Reporting requirements. You must 

submit annual reports containing the 

information specified in paragraphs 

(b)(1) through (8) of this section and 

performance test reports as specified in 

paragraph (b)(9) or (10) of this section. 

You must submit annual reports 

following the procedure specified in 

paragraph (b)(11). The initial annual 

report is due no later than 90 days after 

the end of the initial compliance period 

as determined according to § 60.5410a. 

Subsequent annual reports are due no 

later than same date each year as the 

initial annual report. If you own or 

operate more than one affected facility, 

you may submit one report for multiple 

affected facilities provided the report 

contains all of the information required 

as specified in paragraphs (b)(1) through 

(10) of this section. Annual reports may 

coincide with title V reports as long as 

all the required elements of the annual 

report are included. You may arrange 

with the Administrator a common 

schedule on which reports required by 

this part may be submitted as long as 

the schedule does not extend the 

reporting period. 

(1) The general information specified 

in paragraphs (b)(1)(i) through (iv) of 

this section for all reports. 

(i) The company name and address of 

the affected facility. 

(ii) An identification of each affected 

facility being included in the annual 

report. 

(iii) Beginning and ending dates of the 

reporting period. 

(iv) A certification by a certifying 

official of truth, accuracy, and 

completeness. This certification shall 

state that, based on information and 

belief formed after reasonable inquiry, 

the statements and information in the 

document are true, accurate, and 

complete. 

(2) For each well affected facility, the 

information in paragraphs (b)(2)(i) and 

(ii) of this section. 

(i) Records of each well completion 

operation as specified in paragraph 

(c)(1)(i) through (iv) of this section for 

each well affected facility conducted 

during the reporting period. In lieu of 

submitting the records specified in 

paragraph (c)(1)(i) through (iv), the 

owner or operator may submit a list of 

the well completions with hydraulic 

fracturing completed during the 

reporting period and the records 

required by paragraph (c)(1)(v) of this 

section for each well completion. 

(ii) Records of deviations specified in 

paragraph (c)(1)(ii) of this section that 

occurred during the reporting period. 

(3) For each centrifugal compressor 

affected facility, the information 

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specified in paragraphs (b)(3)(i) through 

(iv) of this section. 

(i) An identification of each 

centrifugal compressor using a wet seal 

system constructed, modified or 

reconstructed during the reporting 

period. 

(ii) Records of deviations specified in 

paragraph (c)(2) of this section that 

occurred during the reporting period. 

(iii) If required to comply with 

§ 60.5380a(a)(2), the records specified in 

paragraphs (c)(6) through (11) of this 

section. 

(iv) If complying with § 60.5380a(a)(1) 

with a control device tested under 

§ 60.5413a(d) which meets the criteria 

in § 60.5413a(d)(11) and § 60.5413a(e), 

records specified in paragraph (c)(2)(i) 

through (c)(2)(vii) of this section for 

each centrifugal compressor using a wet 

seal system constructed, modified or 

reconstructed during the reporting 

period. 

(4) For each reciprocating compressor 

affected facility, the information 

specified in paragraphs (b)(4)(i) and (ii) 

of this section. 

(i) The cumulative number of hours of 

operation or the number of months 

since initial startup, since [date 60 days 

after publication of final rule in the 

Federal Register], or since the previous 

reciprocating compressor rod packing 

replacement, whichever is later. 

(ii) Records of deviations specified in 

paragraph (c)(3)(iii) of this section that 

occurred during the reporting period. 

(5) For each pneumatic controller 

affected facility, the information 

specified in paragraphs (b)(5)(i) through 

(iii) of this section. 

(i) An identification of each 

pneumatic controller constructed, 

modified or reconstructed during the 

reporting period, including the 

identification information specified in 

§ 60.5390a(b)(2) or (c)(2). 

(ii) If applicable, documentation that 

the use of pneumatic controller affected 

facilities with a natural gas bleed rate 

greater than 6 standard cubic feet per 

hour are required and the reasons why. 

(iii) Records of deviations specified in 

paragraph (c)(4)(v) of this section that 

occurred during the reporting period. 

(6) For each storage vessel affected 

facility, the information in paragraphs 

(b)(6)(i) through (vii) of this section. 

(i) An identification, including the 

location, of each storage vessel affected 

facility for which construction, 

modification or reconstruction 

commenced during the reporting period. 

The location of the storage vessel shall 

be in latitude and longitude coordinates 

in decimal degrees to an accuracy and 

precision of five (5) decimals of a degree 

using the North American Datum of 

1983. 

(ii) Documentation of the VOC 

emission rate determination according 

to § 60.5365a(e) for each storage vessel 

that became an affected facility during 

the reporting period or is returned to 

service during the reporting period. 

(iii) Records of deviations specified in 

paragraph (c)(5)(iii) of this section that 

occurred during the reporting period. 

(iv) A statement that you have met the 

requirements specified in 

§ 60.5410a(h)(2) and (3). 

(v) You must identify each storage 

vessel affected facility that is removed 

from service during the reporting period 

as specified in § 60.5395a(c)(1)(ii), 

including the date the storage vessel 

affected facility was removed from 

service. 

(vi) You must identify each storage 

vessel affected facility returned to 

service during the reporting period as 

specified in § 60.5395a(c)(3), including 

the date the storage vessel affected 

facility was returned to service. 

(vii) If complying with 

§ 60.5395a(a)(2) with a control device 

tested under § 60.5413a(d) which meets 

the criteria in § 60.5413a(d)(11) and 

§ 60.5413a(e), records specified in 

paragraphs (c)(5)(vi)(A) through (G) of 

this section for each storage vessel 

constructed, modified, reconstructed or 

returned to service during the reporting 

period. 

(7) For the collection of fugitive 

emissions components at a well site and 

the collection of fugitive emissions 

components at a compressor station, the 

records of each monitoring survey 

conducted during the year: 

(i) Date of the survey. 

(ii) Beginning and end time of the 

survey. 

(iii) Name of operator(s) performing 

survey. If the survey is performed by 

optical gas imaging, you must note the 

training and experience of the operator. 

(iv) Ambient temperature, sky 

conditions, and maximum wind speed 

at the time of the survey. 

(v) Any deviations from the 

monitoring plan or a statement that 

there were no deviations from the 

monitoring plan. 

(vi) Documentation of each fugitive 

emission, including the information 

specified in paragraphs (b)(7)(vi)(A) 

through (C) of this section 

(A) Location. 

(B) One or more digital photographs 

of each required monitoring survey 

being performed. The digital photograph 

must include the date the photograph 

was taken and the latitude and 

longitude of the collection of fugitive 

emissions components at a well site or 

collection of fugitive emissions 

components at a compressor station 

imbedded within or stored with the 

digital file. As an alternative to 

imbedded latitude and longitude within 

the digital photograph, the digital 

photograph may consist of a photograph 

of the monitoring survey being 

performed with a photograph of a 

separately operating GIS device within 

the same digital picture, provided the 

latitude and longitude output of the GIS 

unit can be clearly read in the digital 

photograph. 

(C) The date of successful repair of the 

fugitive emissions component. 

(D) Type of instrument used to 

resurvey a repaired fugitive emissions 

component that could not be repaired 

during the initial fugitive emissions 

finding. 

(8) For each pneumatic pump affected 

facility, the information specified in 

paragraphs (b)(8)(i) through (v) of this 

section. 

(i) In the initial annual report, a 

certification that there is no control 

device on site, if applicable. 

(ii) An identification of each 

pneumatic pump constructed, modified 

or reconstructed during the reporting 

period, including the identification 

information specified in § 60.5393a(a)(2) 

or (b)(2). 

(iii) An identification of any sites 

which contain natural pneumatic 

pumps and which installed a control 

device during the reporting period, 

where there was no control device 

previously at the site. 

(iv) Records of deviations specified in 

paragraph (c)(16)(ii) of this section that 

occurred during the reporting period. 

(v) If complying with § 60.5393a(b)(1) 

with a control device tested under 

§ 60.5413(d), which meets the criteria in 

§ 60.5413(d)(11) and § 60.5413(e), 

records specified in paragraphs 

(c)(16)(iv)(A) through (G) of this section 

for each pneumatic pump constructed, 

modified or reconstructed during the 

reporting period. 

(9) Within 60 days after the date of 

completing each performance test (see 

§ 60.8) required by this subpart, except 

testing conducted by the manufacturer 

as specified in § 60.5413a(d), you must 

submit the results of the performance 

test following the procedure specified in 

either paragraph (b)(9)(i) or (ii) of this 

section. 

(i) For data collected using test 

methods supported by the EPA’s 

Electronic Reporting Tool (ERT) as 

listed on the EPA’s ERT Web site 

(http://www.epa.gov/ttn/chief/ert/

index.html) at the time of the test, you 

must submit the results of the 

performance test to the EPA via the 

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Compliance and Emissions Data 

Reporting Interface (CEDRI). (CEDRI can 

be accessed through the EPA’s Central 

Data Exchange (CDX) (https://

cdx.epa.gov/).) Performance test data 

must be submitted in a file format 

generated through the use of the EPA’s 

ERT or an alternate electronic file 

format consistent with the extensible 

markup language (XML) schema listed 

on the EPA’s ERT Web site. If you claim 

that some of the performance test 

information being submitted is 

confidential business information (CBI), 

you must submit a complete file 

generated through the use of the EPA’s 

ERT or an alternate electronic file 

consistent with the XML schema listed 

on the EPA’s ERT Web site, including 

information claimed to be CBI, on a 

compact disc, flash drive, or other 

commonly used electronic storage 

media to the EPA. The electronic media 

must be clearly marked as CBI and 

mailed to U.S. EPA/OAQPS/CORE CBI 

Office, Attention: Group Leader, 

Measurement Policy Group, MD C404– 

02, 4930 Old Page Rd., Durham, NC 

27703. The same ERT or alternate file 

with the CBI omitted must be submitted 

to the EPA via the EPA’s CDX as 

described earlier in this paragraph. 

(ii) For data collected using test 

methods that are not supported by the 

EPA’s ERT as listed on the EPA’s ERT 

Web site at the time of the test, you must 

submit the results of the performance 

test to the Administrator at the 

appropriate address listed in § 60.4. 

(10) For combustion control devices 

tested by the manufacturer in 

accordance with § 60.5413a(d), an 

electronic copy of the performance test 

results required by § 60.5413a(d) shall 

be submitted via email to Oil_and_Gas_

PT@EPA.GOV unless the test results for 

that model of combustion control device 

are posted at the following Web site: 

epa.gov/airquality/oilandgas/. 

(11) You must submit reports to the 

EPA via the CEDRI. (CEDRI can be 

accessed through the EPA’s CDX 

(https://cdx.epa.gov/).) You must use 

the appropriate electronic report in 

CEDRI for this subpart or an alternate 

electronic file format consistent with the 

extensible markup language (XML) 

schema listed on the CEDRI Web site 

(http://www.epa.gov/ttn/chief/cedri/

index.html). If the reporting form 

specific to this subpart is not available 

in CEDRI at the time that the report is 

due, you must submit the report to the 

Administrator at the appropriate 

address listed in § 60.4. You must begin 

submitting reports via CEDRI no later 

than 90 days after the form becomes 

available in CEDRI. The reports must be 

submitted by the deadlines specified in 

this subpart, regardless of the method in 

which the reports are submitted. 

(c) Recordkeeping requirements. You 

must maintain the records identified as 

specified in § 60.7(f) and in paragraphs 

(c)(1) through (16) of this section. All 

records required by this subpart must be 

maintained either onsite or at the 

nearest local field office for at least 5 

years. Any records required to be 

maintained by this subpart that are 

submitted electronically via the EPA’s 

CDX may be maintained in electronic 

format. 

(1) The records for each well affected 

facility as specified in paragraphs 

(c)(1)(i) through (v) of this section. 

(i) Records identifying each well 

completion operation for each well 

affected facility; 

(ii) Records of deviations in cases 

where well completion operations with 

hydraulic fracturing were not performed 

in compliance with the requirements 

specified in § 60.5375a. 

(iii) Records required in § 60.5375a(b) 

or (f) for each well completion operation 

conducted for each well affected facility 

that occurred during the reporting 

period. You must maintain the records 

specified in paragraphs (c)(1)(iii)(A) and 

(B) of this section. 

(A) For each well affected facility 

required to comply with the 

requirements of § 60.5375a(a), you must 

record: The location of the well; the API 

well number; the date and time of the 

onset of flowback following hydraulic 

fracturing or refracturing; the date and 

time of each attempt to direct flowback 

to a separator as required in 

§ 60.5375a(a)(1)(ii); the date and time of 

each occurrence of returning to the 

initial flowback stage under 

§ 60.5375a(a)(1)(i); and the date and 

time that the well was shut in and the 

flowback equipment was permanently 

disconnected, or the startup of 

production; the duration of flowback; 

duration of recovery to the flow line; 

duration of combustion; duration of 

venting; and specific reasons for venting 

in lieu of capture or combustion. The 

duration must be specified in hours. 

(B) For each well affected facility 

required to comply with the 

requirements of § 60.5375a(f), you must 

maintain the records specified in 

paragraph (c)(1)(iii)(A) of this section 

except that you do not have to record 

the duration of recovery to the flow line. 

(iv) For each well affected facility for 

which you claim an exception under 

§ 60.5375a(a)(3), you must record: The 

location of the well; the API well 

number; the specific exception claimed; 

the starting date and ending date for the 

period the well operated under the 

exception; and an explanation of why 

the well meets the claimed exception. 

(v) For each well affected facility 

required to comply with both 

§ 60.5375a(a)(1) and (3), if you are using 

a digital photograph in lieu of the 

records required in paragraphs (c)(1)(i) 

through (iv) of this section, you must 

retain the records of the digital 

photograph as specified in 

§ 60.5410a(a)(4). 

(2) For each centrifugal compressor 

affected facility, you must maintain 

records of deviations in cases where the 

centrifugal compressor was not operated 

in compliance with the requirements 

specified in § 60.5380a. Except as 

specified in paragraph (c)(2)(vii) of this 

section, you must maintain the records 

in paragraphs (c)(2)(i) through (vi) of 

this section for each control device 

tested under § 60.5413a(d) which meets 

the criteria in § 60.5413a(d)(11) and 

§ 60.5413a(e) and used to comply with 

§ 60.5380a(a)(1) for each centrifugal 

compressor. 

(i) Make, model and serial number of 

purchased device. 

(ii) Date of purchase. 

(iii) Copy of purchase order. 

(iv) Location of the centrifugal 

compressor and control device in 

latitude and longitude coordinates in 

decimal degrees to an accuracy and 

precision of five (5) decimals of a degree 

using the North American Datum of 

1983. 

(v) Inlet gas flow rate. 

(vi) Records of continuous 

compliance requirements in 

§ 60.5413a(e) as specified in paragraphs 

(c)(2)(vi)(A) through (D) of this section. 

(A) Records that the pilot flame is 

present at all times of operation. 

(B) Records that the device was 

operated with no visible emissions 

except for periods not to exceed a total 

of 2 minutes during any hour. 

(C) Records of the maintenance and 

repair log. 

(D) Records of the visible emissions 

test following return to operation from 

a maintenance or repair activity. 

(vii) As an alternative to the 

requirements of paragraph (c)(2)(iv) of 

this section, you may maintain records 

of one or more digital photographs with 

the date the photograph was taken and 

the latitude and longitude of the 

centrifugal compressor and control 

device imbedded within or stored with 

the digital file. As an alternative to 

imbedded latitude and longitude within 

the digital photograph, the digital 

photograph may consist of a photograph 

of the centrifugal compressor and 

control device with a photograph of a 

separately operating GIS device within 

the same digital picture, provided the 

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latitude and longitude output of the GIS 

unit can be clearly read in the digital 

photograph. 

(3) For each reciprocating compressor 

affected facility, you must maintain the 

records in paragraphs (c)(3)(i) through 

(iii) of this section. 

(i) Records of the cumulative number 

of hours of operation or number of 

months since initial startup or [date 60 

days after publication of final rule in the 

Federal Register], or the previous 

replacement of the reciprocating 

compressor rod packing, whichever is 

later. 

(ii) Records of the date and time of 

each reciprocating compressor rod 

packing replacement, or date of 

installation of a rod packing emissions 

collection system and closed vent 

system as specified in § 60.5385a(a)(3). 

(iii) Records of deviations in cases 

where the reciprocating compressor was 

not operated in compliance with the 

requirements specified in § 60.5385a. 

(4) For each pneumatic controller 

affected facility, you must maintain the 

records identified in paragraphs (c)(4)(i) 

through (v) of this section, as applicable. 

(i) Records of the date, location and 

manufacturer specifications for each 

pneumatic controller constructed, 

modified or reconstructed. 

(ii) Records of the demonstration that 

the use of pneumatic controller affected 

facilities with a natural gas bleed rate 

greater than the applicable standard are 

required and the reasons why. 

(iii) If the pneumatic controller is not 

located at a natural gas processing plant, 

records of the manufacturer’s 

specifications indicating that the 

controller is designed such that natural 

gas bleed rate is less than or equal to 6 

standard cubic feet per hour. 

(iv) If the pneumatic controller is 

located at a natural gas processing plant, 

records of the documentation that the 

natural gas bleed rate is zero. 

(v) Records of deviations in cases 

where the pneumatic controller was not 

operated in compliance with the 

requirements specified in § 60.5390a. 

(5) For each storage vessel affected 

facility, you must maintain the records 

identified in paragraphs (c)(5)(i) through 

(vi) of this section. 

(i) If required to reduce emissions by 

complying with § 60.5395a(a)(2), the 

records specified in §§ 60.5420a(c)(6) 

through (8), 60.5416a(c)(6)(ii), and 

60.5416a(c)(7)(ii). You must maintain 

the records in paragraph (c)(5)(vi) of this 

part for each control device tested under 

§ 60.5413a(d) which meets the criteria 

in § 60.5413a(d)(11) and § 60.5413a(e) 

and used to comply with 

§ 60.5395a(a)(2) for each storage vessel. 

(ii) Records of each VOC emissions 

determination for each storage vessel 

affected facility made under 

§ 60.5365a(e) including identification of 

the model or calculation methodology 

used to calculate the VOC emission rate. 

(iii) Records of deviations in cases 

where the storage vessel was not 

operated in compliance with the 

requirements specified in §§ 60.5395a, 

60.5411a, 60.5412a, and 60.5413a, as 

applicable. 

(iv) For storage vessels that are skidmounted or permanently attached to 

something that is mobile (such as 

trucks, railcars, barges or ships), records 

indicating the number of consecutive 

days that the vessel is located at a site 

in the oil and natural gas production 

segment, natural gas processing segment 

or natural gas transmission and storage 

segment. If a storage vessel is removed 

from a site and, within 30 days, is either 

returned to the site or replaced by 

another storage vessel at the site to serve 

the same or similar function, then the 

entire period since the original storage 

vessel was first located at the site, 

including the days when the storage 

vessel was removed, will be added to 

the count towards the number of 

consecutive days. 

(v) You must maintain records of the 

identification and location of each 

storage vessel affected facility. 

(vi) Except as specified in paragraph 

(c)(5)(vi)(G) of this section, you must 

maintain the records specified in 

paragraphs (c)(5)(vi)(A) through (F) of 

this section for each control device 

tested under § 60.5413a(d) which meets 

the criteria in § 60.5413a(d)(11) and 

§ 60.5413a(e) and used to comply with 

§ 60.5395a(a)(2) for each storage vessel. 

(A) Make, model and serial number of 

purchased device. 

(B) Date of purchase. 

(C) Copy of purchase order. 

(D) Location of the control device in 

latitude and longitude coordinates in 

decimal degrees to an accuracy and 

precision of five (5) decimals of a degree 

using the North American Datum of 

1983. 

(E) Inlet gas flow rate. 

(F) Records of continuous compliance 

requirements in § 60.5413a(e) as 

specified in paragraphs (c)(5)(vi)(F)(1) 

through (4). 

(1) Records that the pilot flame is 

present at all times of operation. 

(2) Records that the device was 

operated with no visible emissions 

except for periods not to exceed a total 

of 2 minutes during any hour. 

(3) Records of the maintenance and 

repair log. 

(4) Records of the visible emissions 

test following return to operation from 

a maintenance or repair activity. 

(G) As an alternative to the 

requirements of paragraph (c)(5)(vi)(D) 

of this section, you may maintain 

records of one or more digital 

photographs with the date the 

photograph was taken and the latitude 

and longitude of the storage vessel and 

control device imbedded within or 

stored with the digital file. As an 

alternative to imbedded latitude and 

longitude within the digital photograph, 

the digital photograph may consist of a 

photograph of the storage vessel and 

control device with a photograph of a 

separately operating GIS device within 

the same digital picture, provided the 

latitude and longitude output of the GIS 

unit can be clearly read in the digital 

photograph. 

(6) Records of each closed vent system 

inspection required under 

§ 60.5416a(a)(1) and (a)(2) for centrifugal 

compressors, reciprocating compressors 

and pneumatic pumps, or 

§ 60.5416a(c)(1) for storage vessels. 

(7) A record of each cover inspection 

required under § 60.5416a(a)(3) for 

centrifugal or reciprocating compressors 

or § 60.5416a(c)(2) for storage vessels. 

(8) If you are subject to the bypass 

requirements of § 60.5416a(a)(4) for 

centrifugal compressors, reciprocating 

compressors or pneumatic pumps, or 

§ 60.5416a(c)(3) for storage vessels, a 

record of each inspection or a record of 

each time the key is checked out or a 

record of each time the alarm is 

sounded. 

(9) If you are subject to the closed 

vent system no detectable emissions 

requirements of § 60.5416a(b) for 

centrifugal compressors, reciprocating 

compressors or pneumatic pumps, a 

record of the monitoring conducted in 

accordance with § 60.5416a(b). 

(10) For each centrifugal compressor 

or pneumatic pump affected facility, 

records of the schedule for carbon 

replacement (as determined by the 

design analysis requirements of 

§ 60.5413a(c)(2) or (3)) and records of 

each carbon replacement as specified in 

§ 60.5412a(c)(1). 

(11) For each centrifugal compressor 

or pneumatic pump affected facility 

subject to the control device 

requirements of § 60.5412a(a), (b), and 

(c), records of minimum and maximum 

operating parameter values, continuous 

parameter monitoring system data, 

calculated averages of continuous 

parameter monitoring system data, 

results of all compliance calculations, 

and results of all inspections. 

(12) For each carbon adsorber 

installed on storage vessel affected 

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facilities, records of the schedule for 

carbon replacement (as determined by 

the design analysis requirements of 

§ 60.5412a(d)(2)) and records of each 

carbon replacement as specified in 

§ 60.5412a(c)(1). 

(13) For each storage vessel affected 

facility subject to the control device 

requirements of § 60.5412a(c) and (d), 

you must maintain records of the 

inspections, including any corrective 

actions taken, the manufacturers’ 

operating instructions, procedures and 

maintenance schedule as specified in 

§ 60.5417a(h)(3). You must maintain 

records of EPA Method 22 of appendix 

A–7 of this part, section 11 results, 

which include: Company, location, 

company representative (name of the 

person performing the observation), sky 

conditions, process unit (type of control 

device), clock start time, observation 

period duration (in minutes and 

seconds), accumulated emission time 

(in minutes and seconds), and clock end 

time. You may create your own form 

including the above information or use 

Figure 22–1 in EPA Method 22 of 

appendix A–7 of this part. 

Manufacturer’s operating instructions, 

procedures and maintenance schedule 

must be available for inspection. 

(14) A log of records as specified in 

§§ 60.5412a(d)(1)(iii), for all inspection, 

repair and maintenance activities for 

each control device failing the visible 

emissions test. 

(15) For each collection of fugitive 

emissions components at a well site and 

each collection of fugitive emissions 

components at a compressor station, the 

records identified in paragraphs 

(c)(15)(i) and (ii) of this section. 

(i) The fugitive emissions monitoring 

plan for each collection of fugitive 

emissions components at a well site and 

each collection of fugitive emissions 

components at a compressor station as 

required in § 60.5397a(a). 

(ii) The records of each monitoring 

survey as specified in paragraphs 

(c)(15)(ii)(A) through (F) of this section. 

(A) Date of the survey. 

(B) Beginning and end time of the 

survey. 

(C) Name of operator(s) performing 

survey. You must note the training and 

experience of the operator. 

(D) Ambient temperature, sky 

conditions, and maximum wind speed 

at the time of the survey. 

(E) Any deviations from the 

monitoring plan or a statement that 

there were no deviations from the 

monitoring plan. 

(F) Documentation of each fugitive 

emission, including the information 

specified in paragraphs (c)(15)(ii)(F)(1) 

through (2) of this section. 

(1) Location. 

(2) One or more digital photographs of 

each required monitoring survey being 

performed. The digital photograph must 

include the date the photograph was 

taken and the latitude and longitude of 

the collection of fugitive emissions 

components at a well site or collection 

of fugitive emissions components at a 

compressor station imbedded within or 

stored with the digital file. As an 

alternative to imbedded latitude and 

longitude within the digital photograph, 

the digital photograph may consist of a 

photograph of the monitoring survey 

being performed with a photograph of a 

separately operating GIS device within 

the same digital picture, provided the 

latitude and longitude output of the GIS 

unit can be clearly read in the digital 

photograph. 

(3) The date of successful repair of the 

fugitive emissions component. 

(4) Instrumentation used to resurvey a 

repaired fugitive emissions component 

that could not be repaired during the 

initial fugitive emissions finding. 

(16) For each pneumatic pump 

affected facility, you must maintain the 

records identified in paragraphs 

(c)(16)(i) through (iv) of this section. 

(i) Records of the date, location and 

manufacturer specifications for each 

pneumatic pump constructed, modified 

or reconstructed. 

(ii) Records of deviations in cases 

where the pneumatic pump was not 

operated in compliance with the 

requirements specified in § 60.5393a. 

(iii) Records of the control device 

installation date and the location of sites 

containing pneumatic pumps at which a 

control device was installed, where 

previously there was no control device 

at the site. 

(iv) Except as specified in paragraph 

(c)(16)(iv)(G) of this section, records for 

each control device tested under 

§ 60.5413a(d) which meets the criteria 

in § 60.5413a(d)(11) and § 60.5413a(e) 

and used to comply with 

§ 60.5393a(b)(1) for each pneumatic 

pump. 

(A) Make, model and serial number of 

purchased device. 

(B) Date of purchase. 

(C) Copy of purchase order. 

(D) Location of the pneumatic pump 

and control device in latitude and 

longitude coordinates in decimal 

degrees to an accuracy and precision of 

five (5) decimals of a degree using the 

North American Datum of 1983. 

(E) Inlet gas flow rate. 

(F) Records of continuous compliance 

requirements in § 60.5413a(e) as 

specified in paragraphs (c)(16)(iv)(F)(1) 

through (4) of this section. 

(1) Records that the pilot flame is 

present at all times of operation. 

(2) Records that the device was 

operated with no visible emissions 

except for periods not to exceed a total 

of 2 minutes during any hour. 

(3) Records of the maintenance and 

repair log. 

(4) Records of the visible emissions 

test following return to operation from 

a maintenance or repair activity. 

(G) As an alternative to the 

requirements of paragraph (c)(16)(iv)(D) 

of this part, you may maintain records 

of one or more digital photographs with 

the date the photograph was taken and 

the latitude and longitude of the 

pneumatic pump and control device 

imbedded within or stored with the 

digital file. As an alternative to 

imbedded latitude and longitude within 

the digital photograph, the digital 

photograph may consist of a photograph 

of the pneumatic pump and control 

device with a photograph of a separately 

operating GIS device within the same 

digital picture, provided the latitude 

and longitude output of the GIS unit can 

be clearly read in the digital 

photograph. 

§ 60.5421a What are my additional 

recordkeeping requirements for my affected 

facility subject to methane and VOC 

requirements for onshore natural gas 

processing plants? 

(a) You must comply with the 

requirements of paragraph (b) of this 

section in addition to the requirements 

of § 60.486a. 

(b) The following recordkeeping 

requirements apply to pressure relief 

devices subject to the requirements of 

§ 60.5401a(b)(1) of this subpart. 

(1) When each leak is detected as 

specified in § 60.5401a(b)(2), a 

weatherproof and readily visible 

identification, marked with the 

equipment identification number, must 

be attached to the leaking equipment. 

The identification on the pressure relief 

device may be removed after it has been 

repaired. 

(2) When each leak is detected as 

specified in § 60.5401a(b)(2), the 

information specified in paragraphs 

(b)(2)(i) through (x) of this section must 

be recorded in a log and shall be kept 

for 2 years in a readily accessible 

location: 

(i) The instrument and operator 

identification numbers and the 

equipment identification number. 

(ii) The date the leak was detected 

and the dates of each attempt to repair 

the leak. 

(iii) Repair methods applied in each 

attempt to repair the leak. 

(iv) ‘‘Above 500 ppm’’ if the 

maximum instrument reading measured 

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by the methods specified in 

§ 60.5400a(d) after each repair attempt is 

500 ppm or greater. 

(v) ‘‘Repair delayed’’ and the reason 

for the delay if a leak is not repaired 

within 15 calendar days after discovery 

of the leak. 

(vi) The signature of the owner or 

operator (or designate) whose decision it 

was that repair could not be effected 

without a process shutdown. 

(vii) The expected date of successful 

repair of the leak if a leak is not repaired 

within 15 days. 

(viii) Dates of process unit shutdowns 

that occur while the equipment is 

unrepaired. 

(ix) The date of successful repair of 

the leak. 

(x) A list of identification numbers for 

equipment that are designated for no 

detectable emissions under the 

provisions of § 60.482–4a(a). The 

designation of equipment subject to the 

provisions of § 60.482–4a(a) must be 

signed by the owner or operator. 

§ 60.5422a What are my additional 

reporting requirements for my affected 

facility subject to methane and VOC 

requirements for onshore natural gas 

processing plants? 

(a) You must comply with the 

requirements of paragraphs (b) and (c) of 

this section in addition to the 

requirements of § 60.487a(a), (b), (c)(2)(i) 

through (iv), and (c)(2)(vii) through 

(viii). You must submit semiannual 

reports to the EPA via the Compliance 

and Emissions Data Reporting Interface 

(CEDRI). (CEDRI can be accessed 

through the EPA’s Central Data 

Exchange (CDX) (https://cdx.epa.gov/).) 

Use the appropriate electronic report in 

CEDRI for this subpart or an alternate 

electronic file format consistent with the 

extensible markup language (XML) 

schema listed on the CEDRI Web site 

(http://www.epa.gov/ttn/chief/cedri/

index.html). If the reporting form 

specific to this subpart is not available 

in CEDRI at the time that the report is 

due, submit the report to the 

Administrator at the appropriate 

address listed in § 60.4. You must begin 

submitting reports via CEDRI no later 

than 90 days after the form becomes 

available in CEDRI. The report must be 

submitted by the deadline specified in 

this subpart, regardless of the method in 

which the report is submitted. 

(b) An owner or operator must 

include the following information in the 

initial semiannual report in addition to 

the information required in 

§ 60.487a(b)(1) through (4): Number of 

pressure relief devices subject to the 

requirements of § 60.5401a(b) except for 

those pressure relief devices designated 

for no detectable emissions under the 

provisions of § 60.482–4a(a) and those 

pressure relief devices complying with 

§ 60.482–4a(c). 

(c) An owner or operator must include 

the information specified in paragraphs 

(c)(1) and (2) of this section in all 

semiannual reports in addition to the 

information required in 

§ 60.487a(c)(2)(i) through (vi): 

(1) Number of pressure relief devices 

for which leaks were detected as 

required in § 60.5401a(b)(2); and 

(2) Number of pressure relief devices 

for which leaks were not repaired as 

required in § 60.5401a(b)(3). 

§ 60.5423a What additional recordkeeping 

and reporting requirements apply to my 

sweetening unit affected facilities at 

onshore natural gas processing plants? 

(a) You must retain records of the 

calculations and measurements required 

in § 60.5405a(a) and (b) and 

§ 60.5407a(a) through (g) for at least 2 

years following the date of the 

measurements. This requirement is 

included under § 60.7(f) of the General 

Provisions. 

(b) You must submit a report of excess 

emissions to the Administrator in your 

annual report if you had excess 

emissions during the reporting period. 

The excess emissions report must be 

submitted to the EPA via the 

Compliance and Emissions Data 

Reporting Interface (CEDRI). (CEDRI can 

be accessed through the EPA’s Central 

Data Exchange (CDX) (https://

cdx.epa.gov/).) You must use the 

appropriate electronic report in CEDRI 

for this subpart or an alternate 

electronic file format consistent with the 

extensible markup language (XML) 

schema listed on the CEDRI Web site 

(http://www.epa.gov/ttn/chief/cedri/

index.html). If the reporting form 

specific to this subpart is not available 

in CEDRI at the time that the report is 

due, you must submit the report to the 

Administrator at the appropriate 

address listed in § 60.4. You must begin 

submitting reports via CEDRI no later 

than 90 days after the form becomes 

available in CEDRI. The report must be 

submitted by the deadline specified in 

this subpart, regardless of the method in 

which the report is submitted. For the 

purpose of these reports, excess 

emissions are defined as specified in 

paragraphs (b)(1) and (2) of this section. 

(1) Any 24-hour period (at consistent 

intervals) during which the average 

sulfur emission reduction efficiency (R) 

is less than the minimum required 

efficiency (Z). 

(2) For any affected facility electing to 

comply with the provisions of 

§ 60.5407a(b)(2), any 24-hour period 

during which the average temperature of 

the gases leaving the combustion zone 

of an incinerator is less than the 

appropriate operating temperature as 

determined during the most recent 

performance test in accordance with the 

provisions of § 60.5407a(b)(3). Each 24- 

hour period must consist of at least 96 

temperature measurements equally 

spaced over the 24 hours. 

(c) To certify that a facility is exempt 

from the control requirements of these 

standards, for each facility with a design 

capacity less than 2 LT/D of H2S in the 

acid gas (expressed as sulfur) you must 

keep, for the life of the facility, an 

analysis demonstrating that the facility’s 

design capacity is less than 2 LT/D of 

H2S expressed as sulfur. 

(d) If you elect to comply with 

§ 60.5407a(e) you must keep, for the life 

of the facility, a record demonstrating 

that the facility’s design capacity is less 

than 150 LT/D of H2S expressed as 

sulfur. 

(e) The requirements of paragraph (b) 

of this section remain in force until and 

unless the EPA, in delegating 

enforcement authority to a state under 

section 111(c) of the Act, approves 

reporting requirements or an alternative 

means of compliance surveillance 

adopted by such state. In that event, 

affected sources within the state will be 

relieved of obligation to comply with 

paragraph (b) of this section, provided 

that they comply with the requirements 

established by the state. Electronic 

reporting to the EPA cannot be waived, 

and as such, the provisions of this 

paragraph do not relieve owners or 

operators of affected facilities of the 

requirement to submit the electronic 

reports required in this section to the 

EPA. 

§ 60.5425a What parts of the General 

Provisions apply to me? 

Table 3 to this subpart shows which 

parts of the General Provisions in 

§§ 60.1 through 60.19 apply to you. 

§ 60.5430a What definitions apply to this 

subpart? 

As used in this subpart, all terms not 

defined herein shall have the meaning 

given them in the Act, in subpart A or 

subpart VVa of part 60; and the 

following terms shall have the specific 

meanings given them. 

Acid gas means a gas stream of 

hydrogen sulfide (H2S) and carbon 

dioxide (CO2) that has been separated 

from sour natural gas by a sweetening 

unit. 

Alaskan North Slope means the 

approximately 69,000 square-mile area 

extending from the Brooks Range to the 

Arctic Ocean. 

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API Gravity means the weight per unit 

volume of hydrocarbon liquids as 

measured by a system recommended by 

the American Petroleum Institute (API) 

and is expressed in degrees. 

Bleed rate means the rate in standard 

cubic feet per hour at which natural gas 

is continuously vented (bleeds) from a 

pneumatic controller. 

Capital expenditure means, in 

addition to the definition in 40 CFR 

60.2, an expenditure for a physical or 

operational change to an existing facility 

that exceeds P, the product of the 

facility’s replacement cost, R, and an 

adjusted annual asset guideline repair 

allowance, A, as reflected by the 

following equation: P = R × A, where: 

(1) The adjusted annual asset 

guideline repair allowance, A, is the 

product of the percent of the 

replacement cost, Y, and the applicable 

basic annual asset guideline repair 

allowance, B, divided by 100 as 

reflected by the following equation: 

A = Y × (B ÷ 100); 

(2) The percent Y is determined from 

the following equation: Y = 1.0 ¥ 0.575 

log X, where X is 2011 minus the year 

of construction; and 

(3) The applicable basic annual asset 

guideline repair allowance, B, is 4.5. 

Centrifugal compressor means any 

machine for raising the pressure of a 

natural gas by drawing in low pressure 

natural gas and discharging significantly 

higher pressure natural gas by means of 

mechanical rotating vanes or impellers. 

Screw, sliding vane, and liquid ring 

compressors are not centrifugal 

compressors for the purposes of this 

subpart. 

Certifying official means one of the 

following: 

(1) For a corporation: A president, 

secretary, treasurer, or vice-president of 

the corporation in charge of a principal 

business function, or any other person 

who performs similar policy or 

decision-making functions for the 

corporation, or a duly authorized 

representative of such person if the 

representative is responsible for the 

overall operation of one or more 

manufacturing, production, or operating 

facilities applying for or subject to a 

permit and either: 

(i) The facilities employ more than 

250 persons or have gross annual sales 

or expenditures exceeding $25 million 

(in second quarter 1980 dollars); or 

(ii) The Administrator is notified of 

such delegation of authority prior to the 

exercise of that authority. The 

Administrator reserves the right to 

evaluate such delegation; 

(2) For a partnership (including but 

not limited to general partnerships, 

limited partnerships, and limited 

liability partnerships) or sole 

proprietorship: A general partner or the 

proprietor, respectively. If a general 

partner is a corporation, the provisions 

of paragraph (1) of this definition apply; 

(3) For a municipality, State, Federal, 

or other public agency: Either a 

principal executive officer or ranking 

elected official. For the purposes of this 

part, a principal executive officer of a 

Federal agency includes the chief 

executive officer having responsibility 

for the overall operations of a principal 

geographic unit of the agency (e.g., a 

Regional Administrator of EPA); or 

(4) For affected facilities: 

(i) The designated representative in so 

far as actions, standards, requirements, 

or prohibitions under title IV of the 

Clean Air Act or the regulations 

promulgated thereunder are concerned; 

or 

(ii) The designated representative for 

any other purposes under part 60. 

Chemical/methanol or diaphragm 

pump means a gas-driven positive 

displacement pump typically used to 

inject precise amounts of chemicals into 

process streams or circulate glycol 

compounds for freeze protection. 

City gate means the delivery point at 

which natural gas is transferred from a 

transmission pipeline to the local gas 

utility. 

Collection system means any 

infrastructure that conveys gas or 

liquids from the well site to another 

location for treatment, storage, 

processing, recycling, disposal or other 

handling. 

Completion combustion device means 

any ignition device, installed 

horizontally or vertically, used in 

exploration and production operations 

to combust otherwise vented emissions 

from completions. 

Compressor station site means any 

permanent combination of one or more 

compressors that move natural gas at 

increased pressure through gathering or 

transmission pipelines, or into or out of 

storage. This includes, but is not limited 

to, gathering and boosting stations and 

transmission compressor stations. 

Condensate means hydrocarbon 

liquid separated from natural gas that 

condenses due to changes in the 

temperature, pressure, or both, and 

remains liquid at standard conditions. 

Continuous bleed means a continuous 

flow of pneumatic supply natural gas to 

a pneumatic controller. 

Crude oil and natural gas source 

category means: 

(1) Crude oil production, which 

includes the well and extends to the 

point of custody transfer to the crude oil 

transmission pipeline; and 

(2) Natural gas production, 

processing, transmission, and storage, 

which include the well and extend to, 

but do not include, the city gate. 

Custody transfer means the transfer of 

natural gas after processing and/or 

treatment in the producing operations, 

or from storage vessels or automatic 

transfer facilities or other such 

equipment, including product loading 

racks, to pipelines or any other forms of 

transportation. 

Dehydrator means a device in which 

an absorbent directly contacts a natural 

gas stream and absorbs water in a 

contact tower or absorption column 

(absorber). 

Deviation means any instance in 

which an affected source subject to this 

subpart, or an owner or operator of such 

a source: 

(1) Fails to meet any requirement or 

obligation established by this subpart 

including, but not limited to, any 

emission limit, operating limit, or work 

practice standard; 

(2) Fails to meet any term or condition 

that is adopted to implement an 

applicable requirement in this subpart 

and that is included in the operating 

permit for any affected source required 

to obtain such a permit; or 

(3) Fails to meet any emission limit, 

operating limit, or work practice 

standard in this subpart during startup, 

shutdown, or malfunction, regardless of 

whether or not such failure is permitted 

by this subpart. 

Delineation well means a well drilled 

in order to determine the boundary of a 

field or producing reservoir. 

Equipment, as used in the standards 

and requirements in this subpart 

relative to the equipment leaks of 

methane and VOC from onshore natural 

gas processing plants, means each 

pump, pressure relief device, openended valve or line, valve, and flange or 

other connector that is in VOC service 

or in wet gas service, and any device or 

system required by those same 

standards and requirements in this 

subpart. 

Field gas means feedstock gas 

entering the natural gas processing 

plant. 

Field gas gathering means the system 

used transport field gas from a field to 

the main pipeline in the area. 

Flare means a thermal oxidation 

system using an open (without 

enclosure) flame. Completion 

combustion devices as defined in this 

section are not considered flares. 

Flow line means a pipeline used to 

transport oil and/or gas to a processing 

facility, a mainline pipeline, reinjection, or routed to a process or other 

useful purpose. 

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Flowback means the process of 

allowing fluids and entrained solids to 

flow from a well following a treatment, 

either in preparation for a subsequent 

phase of treatment or in preparation for 

cleanup and returning the well to 

production. The term flowback also 

means the fluids and entrained solids 

that emerge from a well during the 

flowback process. The flowback period 

begins when material introduced into 

the well during the treatment returns to 

the surface following hydraulic 

fracturing or refracturing. The flowback 

period ends when either the well is shut 

in and permanently disconnected from 

the flowback equipment or at the startup 

of production. The flowback period 

includes the initial flowback stage and 

the separation flowback stage. 

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 

site, including but not limited to valves, 

connectors, pressure relief devices, 

open-ended lines, access doors, flanges, 

closed vent systems, thief hatches or 

other openings on a storage vessels, 

agitator seals, distance pieces, crankcase 

vents, blowdown vents, pump seals or 

diaphragms, compressors, separators, 

pressure vessels, dehydrators, heaters, 

instruments, and meters. Devices that 

vent as part of normal operations, such 

as natural gas-driven pneumatic 

controllers or natural gas-driven pumps, 

are not fugitive emissions components, 

insofar as the natural gas discharged 

from the device’s vent is not considered 

a fugitive emission. Emissions 

originating from other than the vent, 

such as the seals around the bellows of 

a diaphragm pump, would be 

considered fugitive emissions. 

Gas processing plant process unit 

means equipment assembled for the 

extraction of natural gas liquids from 

field gas, the fractionation of the liquids 

into natural gas products, or other 

operations associated with the 

processing of natural gas products. A 

process unit can operate independently 

if supplied with sufficient feed or raw 

materials and sufficient storage facilities 

for the products. 

Hydraulic fracturing means the 

process of directing pressurized fluids 

containing any combination of water, 

proppant, and any added chemicals to 

penetrate tight formations, such as shale 

or coal formations, that subsequently 

require high rate, extended flowback to 

expel fracture fluids and solids during 

completions. 

Hydraulic refracturing means 

conducting a subsequent hydraulic 

fracturing operation at a well that has 

previously undergone a hydraulic 

fracturing operation. 

In light liquid service means that the 

piece of equipment contains a liquid 

that meets the conditions specified in 

§ 60.485a(e) or § 60.5401a(f)(2) of this 

part. 

In wet gas service means that a 

compressor or piece of equipment 

contains or contacts the field gas before 

the extraction step at a gas processing 

plant process unit. 

Initial flowback stage means the 

period during a well completion 

operation which begins at the onset of 

flowback and ends at the separation 

flowback stage. 

Intermediate hydrocarbon liquid 

means any naturally occurring, 

unrefined petroleum liquid. 

Intermittent/snap-action pneumatic 

controller means a pneumatic controller 

that is designed to vent noncontinuously. 

Liquefied natural gas unit means a 

unit used to cool natural gas to the point 

at which it is condensed into a liquid 

which is colorless, odorless, noncorrosive and non-toxic. 

Low pressure well means a well with 

reservoir pressure and vertical well 

depth such that 0.445 times the 

reservoir pressure (in psia) minus 0.038 

times the vertical well depth (in feet) 

minus 67.578 psia is less than the flow 

line pressure at the sales meter. 

Maximum average daily throughput 

means the earliest calculation of daily 

average throughput during the 30-day 

PTE evaluation period employing 

generally accepted methods. 

Natural gas-driven pneumatic 

controller means a pneumatic controller 

powered by pressurized natural gas. 

Natural gas-driven chemical/

methanol or diaphragm pump means a 

chemical or methanol injection or 

circulation pump or a diaphragm pump 

powered by pressurized natural gas. 

Natural gas liquids means the 

hydrocarbons, such as ethane, propane, 

butane, and pentane that are extracted 

from field gas. 

Natural gas processing plant (gas 

plant) means any processing site 

engaged in the extraction of natural gas 

liquids from field gas, fractionation of 

mixed natural gas liquids to natural gas 

products, or both. A Joule-Thompson 

valve, a dew point depression valve, or 

an isolated or standalone JouleThompson skid is not a natural gas 

processing plant. 

Natural gas transmission means the 

pipelines used for the long distance 

transport of natural gas (excluding 

processing). Specific equipment used in 

natural gas transmission includes the 

land, mains, valves, meters, boosters, 

regulators, storage vessels, dehydrators, 

compressors, and their driving units and 

appurtenances, and equipment used for 

transporting gas from a production 

plant, delivery point of purchased gas, 

gathering system, storage area, or other 

wholesale source of gas to one or more 

distribution area(s). 

Nonfractionating plant means any gas 

plant that does not fractionate mixed 

natural gas liquids into natural gas 

products. 

Non-natural gas-driven pneumatic 

controller means an instrument that is 

actuated using other sources of power 

than pressurized natural gas; examples 

include solar, electric, and instrument 

air. 

Onshore means all facilities except 

those that are located in the territorial 

seas or on the outer continental shelf. 

Pneumatic controller means an 

automated instrument used for 

maintaining a process condition such as 

liquid level, pressure, delta-pressure 

and temperature. 

Pressure vessel means a storage vessel 

that is used to store liquids or gases and 

is designed not to vent to the 

atmosphere as a result of compression of 

the vapor headspace in the pressure 

vessel during filling of the pressure 

vessel to its design capacity. 

Process unit means components 

assembled for the extraction of natural 

gas liquids from field gas, the 

fractionation of the liquids into natural 

gas products, or other operations 

associated with the processing of 

natural gas products. A process unit can 

operate independently if supplied with 

sufficient feed or raw materials and 

sufficient storage facilities for the 

products. 

Produced water means water that is 

extracted from the earth from an oil or 

natural gas production well, or that is 

separated from crude oil, condensate, or 

natural gas after extraction. 

Reciprocating compressor means a 

piece of equipment that increases the 

pressure of a process gas by positive 

displacement, employing linear 

movement of the driveshaft. 

Reciprocating compressor rod packing 

means a series of flexible rings in 

machined metal cups that fit around the 

reciprocating compressor piston rod to 

create a seal limiting the amount of 

compressed natural gas that escapes to 

the atmosphere. 

Recovered gas means gas recovered 

through the separation process during 

flowback. 

Recovered liquids means any crude 

oil, condensate or produced water 

recovered through the separation 

process during flowback. 

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Reduced emissions completion means 

a well completion following fracturing 

or refracturing where gas flowback that 

is otherwise vented is captured, 

cleaned, and routed to the flow line or 

collection system, re-injected into the 

well or another well, used as an on-site 

fuel source, or used for other useful 

purpose that a purchased fuel or raw 

material would serve, with no direct 

release to the atmosphere. 

Reduced sulfur compounds means 

H2S, carbonyl sulfide (COS), and carbon 

disulfide (CS2). 

Removed from service means that a 

storage vessel affected facility has been 

physically isolated and disconnected 

from the process for a purpose other 

than maintenance in accordance with 

§ 60.5395a(c)(1). 

Responsible official means one of the 

following: 

(1) For a corporation: A president, 

secretary, treasurer, or vice-president of 

the corporation in charge of a principal 

business function, or any other person 

who performs similar policy or 

decision-making functions for the 

corporation, or a duly authorized 

representative of such person if the 

representative is responsible for the 

overall operation of one or more 

manufacturing, production, or operating 

facilities applying for or subject to a 

permit and either: 

(i) The facilities employ more than 

250 persons or have gross annual sales 

or expenditures exceeding $25 million 

(in second quarter 1980 dollars); or 

(ii) The delegation of authority to 

such representatives is approved in 

advance by the permitting authority; 

(2) For a partnership or sole 

proprietorship: A general partner or the 

proprietor, respectively; 

(3) For a municipality, State, Federal, 

or other public agency: Either a 

principal executive officer or ranking 

elected official. For the purposes of this 

part, a principal executive officer of a 

Federal agency includes the chief 

executive officer having responsibility 

for the overall operations of a principal 

geographic unit of the agency (e.g., a 

Regional Administrator of EPA); or 

(4) For affected facilities: 

(i) The designated representative in so 

far as actions, standards, requirements, 

or prohibitions under title IV of the 

Clean Air Act or the regulations 

promulgated thereunder are concerned; 

or 

(ii) The designated representative for 

any other purposes under part 60. 

Returned to service means that a 

storage vessel affected facility that was 

removed from service has been: 

(1) Reconnected to the original source 

of liquids or has been used to replace 

any storage vessel affected facility; or 

(2) Installed in any location covered 

by this subpart and introduced with 

crude oil, condensate, intermediate 

hydrocarbon liquids or produced water. 

Routed to a process or route to a 

process means the emissions are 

conveyed via a closed vent system to 

any enclosed portion of a process where 

the emissions are predominantly 

recycled and/or consumed in the same 

manner as a material that fulfills the 

same function in the process and/or 

transformed by chemical reaction into 

materials that are not regulated 

materials and/or incorporated into a 

product; and/or recovered. 

Salable quality gas means natural gas 

that meets the flow line or collection 

system operator specifications, 

regardless of whether such gas is sold. 

Separation flowback stage means the 

period during a well completion 

operation when it is technically feasible 

for a separator to function. The 

separation flowback stage ends either at 

the startup of production, or when the 

well is shut in and permanently 

disconnected from the flowback 

equipment. 

Startup of production means the 

beginning of initial flow following the 

end of flowback when there is 

continuous recovery of salable quality 

gas and separation and recovery of any 

crude oil, condensate or produced 

water. 

Storage vessel means a tank or other 

vessel that contains an accumulation of 

crude oil, condensate, intermediate 

hydrocarbon liquids, or produced water, 

and that is constructed primarily of 

nonearthen materials (such as wood, 

concrete, steel, fiberglass, or plastic) 

which provide structural support. A 

well completion vessel that receives 

recovered liquids from a well after 

startup of production following 

flowback for a period which exceeds 60 

days is considered a storage vessel 

under this subpart. A tank or other 

vessel shall not be considered a storage 

vessel if it has been removed from 

service in accordance with the 

requirements of § 60.5395a(c) until such 

time as such tank or other vessel has 

been returned to service. For the 

purposes of this subpart, the following 

are not considered storage vessels: 

(1) Vessels that are skid-mounted or 

permanently attached to something that 

is mobile (such as trucks, railcars, 

barges or ships), and are intended to be 

located at a site for less than 180 

consecutive days. If you do not keep or 

are not able to produce records, as 

required by § 60.5420a(c)(5)(iv), 

showing that the vessel has been located 

at a site for less than 180 consecutive 

days, the vessel described herein is 

considered to be a storage vessel from 

the date the original vessel was first 

located at the site. This exclusion does 

not apply to a well completion vessel as 

described above. 

(2) Process vessels such as surge 

control vessels, bottoms receivers or 

knockout vessels. 

(3) Pressure vessels designed to 

operate in excess of 204.9 kilopascals 

and without emissions to the 

atmosphere. 

Sulfur production rate means the rate 

of liquid sulfur accumulation from the 

sulfur recovery unit. 

Sulfur recovery unit means a process 

device that recovers element sulfur from 

acid gas. 

Surface site means any combination 

of one or more graded pad sites, gravel 

pad sites, foundations, platforms, or the 

immediate physical location upon 

which equipment is physically affixed. 

Sweetening unit means a process 

device that removes hydrogen sulfide 

and/or carbon dioxide from the sour 

natural gas stream. 

Total Reduced Sulfur (TRS) means the 

sum of the sulfur compounds hydrogen 

sulfide, methyl mercaptan, dimethyl 

sulfide, and dimethyl disulfide as 

measured by Method 16 of appendix A– 

6 of this part. 

Total SO2 equivalents means the sum 

of volumetric or mass concentrations of 

the sulfur compounds obtained by 

adding the quantity existing as SO2 to 

the quantity of SO2 that would be 

obtained if all reduced sulfur 

compounds were converted to SO2

(ppmv or kg/dscm (lb/dscf)). 

Underground storage vessel means a 

storage vessel stored below ground. 

Well means a hole drilled for the 

purpose of producing oil or natural gas, 

or a well into which fluids are injected. 

Well completion means the process 

that allows for the flowback of 

petroleum or natural gas from newly 

drilled wells to expel drilling and 

reservoir fluids and tests the reservoir 

flow characteristics, which may vent 

produced hydrocarbons to the 

atmosphere via an open pit or tank. 

Well completion operation means any 

well completion with hydraulic 

fracturing or refracturing occurring at a 

well affected facility. 

Well completion vessel means a vessel 

that contains flowback during a well 

completion operation following 

hydraulic fracturing or refracturing. A 

well completion vessel may be a lined 

earthen pit, a tank or other vessel that 

is skid-mounted or portable. A well 

completion vessel that receives 

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Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 56697 

recovered liquids from a well after 

startup of production following 

flowback for a period which exceeds 60 

days is considered a storage vessel 

under this subpart. 

Well site means one or more areas that 

are directly disturbed during the drilling 

and subsequent operation of, or affected 

by, production facilities directly 

associated with any oil well, natural gas 

well, or injection well and its associated 

well pad. For the purposes of the 

fugitive emissions standards at 

§ 60.5397a, well site also includes tank 

batteries collecting crude oil, 

condensate, intermediate hydrocarbon 

liquids, or produced water from wells 

not located at the well site (e.g., 

centralized tank batteries). 

Wellhead means the piping, casing, 

tubing and connected valves protruding 

above the earth’s surface for an oil and/ 

or natural gas well. The wellhead ends 

where the flow line connects to a 

wellhead valve. The wellhead does not 

include other equipment at the well site 

except for any conveyance through 

which gas is vented to the atmosphere. 

Wildcat well means a well outside 

known fields or the first well drilled in 

an oil or gas field where no other oil and 

gas production exists. 

§§ 60.5431a–60.5499a [Reserved] 

TABLE 1 TO SUBPART OOOOa OF PART 60—REQUIRED MINIMUM INITIAL SO2 EMISSION REDUCTION EFFICIENCY (Zi) 

H2S content of acid gas (Y), % 

Sulfur feed rate (X), LT/D 

2.0<X<5.0 5.0<X<15.0 15.0<X<300.0 X>300.0 

Y>50 ............................................ 79.0 88.51X0.0101Y0.0125 or 99.9, whichever is smaller. 

20<Y<50 ..................................... 79.0 88.51X0.0101Y0.0125 or 97.9, whichever is smaller. 97.9 

10<Y<20 ..................................... 79.0 88.51X0.0101Y0.0125 or 93.5, 

whichever is smaller.

93.5 93.5 

Y<10 ............................................ 79.0 79.0 ............................................. 79.0 79.0 

TABLE 2—TO SUBPART OOOOa OF PART 60—REQUIRED MINIMUM SO2 EMISSION REDUCTION EFFICIENCY (Zc) 

H2S content of acid gas (Y), % 

Sulfur feed rate (X), LT/D 

2.0<X<5.0 5.0<X<15.0 15.0<X<300.0 X>300.0 

Y>50 ............................................ 74.0 85.35X0.0144Y0.0128 or 99.9, whichever is smaller. 

20<Y<50 ..................................... 74.0 85.35X0.0144Y0.0128 or 97.5, whichever is smaller. 97.5 

10<Y<20 ..................................... 74.0 85.35X0.0144Y0.0128 or 90.8, 

whichever is smaller.

90.8 90.8 

Y<10 ............................................ 74.0 74.0 ............................................. 74.0 74.0 

X = The sulfur feed rate from the sweetening unit (i.e., the H2S in the acid gas), expressed as sulfur, Mg/D(LT/D), rounded to one decimal 

place. 

Y = The sulfur content of the acid gas from the sweetening unit, expressed as mole percent H2S (dry basis) rounded to one decimal place. 

Z = The minimum required sulfur dioxide (SO2) emission reduction efficiency, expressed as percent carried to one decimal place. Zi refers to 

the reduction efficiency required at the initial performance test. Zc refers to the reduction efficiency required on a continuous basis after compliance with Zi has been demonstrated. 

TABLE 3 TO SUBPART OOOOa OF PART 60—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART OOOOa 

[As stated in § 60.5425a, you must comply with the following applicable General Provisions] 

General 

provisions 

citation 

Subject of citation Applies to 

subpart? Explanation 

§ 60.1 ................ General applicability of the General Provisions ........ Yes ...................

§ 60.2 ................ Definitions .................................................................. Yes ................... Additional terms defined in § 60.5430a. 

§ 60.3 ................ Units and abbreviations ............................................. Yes ...................

§ 60.4 ................ Address ..................................................................... Yes ...................

§ 60.5 ................ Determination of construction or modification ........... Yes ...................

§ 60.6 ................ Review of plans ......................................................... Yes ...................

§ 60.7 ................ Notification and record keeping ................................ Yes ................... Except that § 60.7 only applies as specified in 

§ 60.5420a(a). 

§ 60.8 ................ Performance tests ..................................................... Yes ................... Performance testing is required for control devices 

used on storage vessels, centrifugal compressors 

and pneumatic pumps. 

§ 60.9 ................ Availability of information .......................................... Yes ...................

§ 60.10 .............. State authority ........................................................... Yes ...................

§ 60.11 .............. Compliance with standards and maintenance requirements.No ..................... Requirements are specified in subpart OOOOa. 

§ 60.12 .............. Circumvention ............................................................ Yes ...................

§ 60.13 .............. Monitoring requirements ............................................ Yes ................... Continuous monitors are required for storage vessels. 

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56698 Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / Proposed Rules 

TABLE 3 TO SUBPART OOOOa OF PART 60—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART OOOOa—Continued 

[As stated in § 60.5425a, you must comply with the following applicable General Provisions] 

General 

provisions 

citation 

Subject of citation Applies to 

subpart? Explanation 

§ 60.14 .............. Modification ............................................................... Yes ................... To the extent any provision in § 60.14 conflicts with 

specific provisions in subpart OOOOa, it is superseded by subpart OOOOa provisions. 

§ 60.15 .............. Reconstruction ........................................................... Yes ................... Except that § 60.15(d) does not apply to pneumatic 

controllers, pneumatic pumps, centrifugal compressors or storage vessels. 

§ 60.16 .............. Priority list .................................................................. Yes ...................

§ 60.17 .............. Incorporations by reference ...................................... Yes ...................

§ 60.18 .............. General control device and work practice requirements.Yes ...................

§ 60.19 .............. General notification and reporting requirement ........ Yes ...................

[FR Doc. 2015–21023 Filed 9–17–15; 8:45 am] 

BILLING CODE 6560–50–P 

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