Vol. 79 Monday, 

No. 46 March 10, 2014 

Part II 

Environmental Protection Agency 

40 CFR Part 98 

Greenhouse Gas Reporting Rule: Revisions and Confidentiality 

Determinations for Petroleum and Natural Gas Systems; Proposed Rule 


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13394 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2011–0512; FRL–9906–85– 

OAR] 

RIN 2060–AR96 

Greenhouse Gas Reporting Rule: 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The EPA is proposing 

revisions and confidentiality 

determinations for the petroleum and 

natural gas systems source category and 

the general provisions of the 

Greenhouse Gas Reporting Rule. In 

particular, the EPA is proposing to 

revise certain calculation methods, 

amend certain monitoring and data 

reporting requirements, clarify certain 

terms and definitions, and correct 

certain technical and editorial errors 

that have been identified during the 

course of implementation. This action 

also proposes confidentiality 

determinations for new or substantially 

revised data elements contained in these 

proposed amendments, as well as 

proposes a revised confidentiality 

determination for one existing data 

element. 

DATES: Comments. Comments must be 

received on or before April 24, 2014. 

Public Hearing. The EPA does not 

plan to conduct a public hearing unless 

requested. To request a hearing, please 

contact the person listed in the 

following FOR FURTHER INFORMATION

CONTACT section by March 17, 2014. If 

requested, the hearing will be 

conducted on March 25, 2014, in the 

Washington, DC area. The EPA will 

provide further information about the 

hearing on the Greenhouse Gas 

Reporting Rule Web site, http://

www.epa.gov/ghgreporting/index.html if 

a hearing is requested. 

ADDRESSES: Submit your comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2011–0512 by any of the following 

methods: 

• Federal eRulemaking Portal: http:// 

www.regulations.gov. Follow the online 

instructions for submitting comments. 

• Email: GHG_Reporting_Rule_Oil_

And_Natural_Gas@epa.gov. Include 

Docket ID No. EPA–HQ–OAR–2011– 

0512 or RIN No. 2060–AR96 in the 

subject line of the message. 

• Fax: (202) 566–9744. 

• Mail: Environmental Protection 

Agency, EPA Docket Center (EPA/DC), 

Mailcode 28221T, Attention Docket ID 

No. OAR–2011–0512, 1200 

Pennsylvania Avenue NW., Washington, 

DC 20460. 

• Hand/Courier Delivery: EPA Docket 

Center, Public Reading Room, William 

Jefferson Clinton (WJC) West Building, 

Room 3334, 1301 Constitution Avenue 

NW., Washington, DC 20004. Such 

deliveries are accepted only during the 

normal hours of operation of the Docket 

Center, and special arrangements should 

be made for deliveries of boxed 

information. 

Additional Information on Submitting 

Comments: To expedite review of your 

comments by agency staff, you are 

encouraged to send a separate copy of 

your comments, in addition to the copy 

you submit to the official docket, to 

Carole Cook, U.S. EPA, Office of 

Atmospheric Programs, Climate Change 

Division, Mail Code 6207–J, 1200 

Pennsylvania Avenue NW., Washington, 

DC 20460, telephone (202) 343–9263, 

email address: GHGReportingRule@

epa.gov. 

Instructions: Direct your comments to 

Docket ID No. EPA–HQ–OAR–2011– 

0512, Greenhouse Gas Reporting Rule: 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Proposed Rule. 

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 http://

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. 

Should you choose to submit 

information that you claim to be CBI, 

clearly mark the part or all of the 

information that you claim to be CBI. 

For information that you claim to be CBI 

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 marked as 

CBI will not be disclosed except in 

accordance with procedures set forth in 

40 CFR part 2. Send or deliver 

information identified as CBI to only the 

mail or hand/courier delivery address 

listed above, attention: Docket ID No. 

EPA–HQ–OAR–2011–0512. If you have 

any questions about CBI or the 

procedures for claiming CBI, please 

consult the person identified in the FOR

FURTHER INFORMATION CONTACT section. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through http://

www.regulations.gov or email. The 

http://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 send an email 

comment directly to the EPA without 

going through http://

www.regulations.gov your email address 

will be automatically captured and 

included as part of the comment that is 

placed in the public docket and made 

available on the Internet. If you submit 

an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

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. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. 

Docket: All documents in the docket 

are listed in the http://

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., CBI or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http://

www.regulations.gov or in hard copy at 

the Air Docket, EPA/DC, WJC West 

Building, Room 3334, 1301 Constitution 

Ave. NW., Washington, DC. This Docket 

Facility is open from 8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: 

Carole Cook, Climate Change Division, 

Office of Atmospheric Programs (MC– 

6207J), Environmental Protection 

Agency, 1200 Pennsylvania Ave. NW., 

Washington, DC 20460; telephone 

number: (202) 343–9263; fax number: 

(202) 343–2342; email address: 

GHGReportingRule@epa.gov. For 

technical information, please go to the 

Greenhouse Gas Reporting Rule Web 

site, http://www.epa.gov/ghgreporting/


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index.html. To submit a question, select 

Help Center, followed by ‘‘Contact Us.’’ 

Worldwide Web (WWW). In addition 

to being available in the docket, an 

electronic copy of today’s proposal will 

also be available through the WWW. 

Following the Administrator’s signature, 

a copy of this action will be posted on 

EPA’s Greenhouse Gas Reporting Rule 

Web site at http://www.epa.gov/

ghgreporting/index.html. 

SUPPLEMENTARY INFORMATION: 

Regulated Entities. The Administrator 

determined that this action is subject to 

the provisions of Clean Air Act (CAA) 

section 307(d). See CAA section 

307(d)(1)(V) (the provisions of section 

307(d) apply to ‘‘such other actions as 

the Administrator may determine’’). 

These are proposed amendments to 

existing regulations. If finalized, these 

amended regulations would affect 

owners or operators of petroleum and 

natural gas systems that directly emit 

greenhouse gases (GHGs). Regulated 

categories and entities include those 

listed in Table 1 of this preamble: 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY

Category NAICS Examples of affected facilities 

Petroleum and Natural Gas Systems ......................................... 486210 Pipeline transportation of natural gas. 

221210 Natural gas distribution. 

211111 Crude petroleum and natural gas extraction. 

211112 Natural gas liquid extraction. 

Table 1 of this preamble is not 

intended to be exhaustive, but rather 

provides a guide for readers regarding 

facilities likely to be affected by this 

action. Other types of facilities than 

those listed in the table could also be 

subject to reporting requirements. To 

determine whether you are affected by 

this action, you should carefully 

examine the applicability criteria found 

in 40 CFR part 98, subpart A and 40 

CFR part 98, subpart W. If you have 

questions regarding the applicability of 

this action to a particular facility, 

consult the person listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

BAMM best available monitoring methods 

CAA Clean Air Act 

CBI confidential business information 

CFR Code of Federal Regulations 

CH4 methane 

CO2 carbon dioxide 

CO2e carbon dioxide equivalent 

EIA Energy Information Administration 

EOR enhanced oil recovery 

EPA U.S. Environmental Protection Agency 

FERC Federal Energy Regulatory 

Commission 

FR Federal Register 

GHG greenhouse gas 

GOR gas to oil ratio 

GWP global warming potential 

LNG liquefied natural gas 

MMscf million standard cubic feet per day 

N2O nitrous oxide 

NAICS North American Industry 

Classification System 

NGL natural gas liquids 

NTTAA National Technology Transfer and 

Advancement Act 

OMB Office of Management and Budget 

QA/QC quality assurance/quality control 

RFA Regulatory Flexibility Act 

scf standard cubic feet 

TSD Technical Support Document 

UIC underground injection control 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 

1995 

Organization of This Document. The 

following outline is provided to aid in 

locating information in this preamble. 

I. Background 

A. Organization of This Preamble 

B. Background on the Proposed Action 

C. Legal Authority 

D. How would these amendments apply to 

2014 and 2015 reports? 

II. Revisions and Other Amendments 

A. Proposed Revisions To Provide 

Consistency Throughout Subpart W 

B. Proposed Changes to Calculation 

Methods and Reporting Requirements 

C. Proposed Revisions to Missing Data 

Provisions 

D. Proposed Amendments to Best 

Available Monitoring Methods 

III. Proposed Confidentiality Determinations 

A. Overview and Background 

B. Approach to Proposed CBI 

Determinations for New or Revised 

Subpart W Data Elements 

C. Proposed Confidentiality 

Determinations for Data Elements 

Assigned to the ‘‘Unit/Process ‘Static’ 

Characteristics That Are Not Inputs to 

Emission Equations’’ and ‘‘Unit/Process 

Operating Characteristics That Are Not 

Inputs to Emission Equations’’ Data 

Categories 

D. Other Proposed or Re-Proposed Case-byCase Confidentiality Determinations for 

Subpart W 

E. Request for Comments on Proposed 

Confidentiality Determinations 

IV. Impacts of the Proposed Amendments to 

Subpart W 

V. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(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 That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. Background 

A. Organization of This Preamble 

The first section of this preamble 

provides background information 

regarding the origin of the proposed 

amendments. This section also 

discusses the EPA’s legal authority 

under the CAA to promulgate and 

amend 40 CFR part 98 of the 

Greenhouse Gas Reporting Rule 

(hereinafter referred to as ‘‘Part 98’’) as 

well as the legal authority for making 

confidentiality determinations for the 

data to be reported. Section II of this 

preamble contains information on the 

proposed revisions to 40 CFR part 98, 

subpart W (hereafter referred to as 

‘‘subpart W’’). Section III of this 

preamble discusses proposed 

confidentiality determinations for new 

or substantially revised (i.e., requiring 

additional or different data to be 

reported) data reporting elements, as 

well as a proposed revised 

confidentiality determination for one 

existing data element. Section IV of this 

preamble discusses the impacts of the 

proposed amendments to subpart W. 

Finally, Section V of this preamble 

describes the statutory and executive 

order requirements applicable to this 

action. 

B. Background on the Proposed Action 

On October 30, 2009, the EPA 

published Part 98 for collecting 

information regarding greenhouse gases 

(GHGs) from a broad range of industry 

sectors (74 FR 56260). The 2009 rule, 


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which finalized reporting requirements 

for 29 source categories, did not include 

the petroleum and natural gas systems 

source category. A subsequent rule was 

published on November 20, 2010 

finalizing the requirements for the 

petroleum and natural gas systems 

source category at 40 CFR part 98, 

subpart W (75 FR 74458) (hereafter 

referred to as ‘‘the final subpart W 

rule’’). Following promulgation, the 

EPA finalized actions revising subpart 

W (76 FR 22825, April 25, 2011; 76 FR 

59533, September 27, 2011; 76 FR 

80554, December 23, 2011; 77 FR 51477, 

August 24, 2012; 78 FR 25392, May 1, 

2013; 78 FR 71904, Nov. 29, 2013). 

In this action, the EPA is proposing to 

make certain revisions to the petroleum 

and natural gas systems source category 

GHG reporting requirements (Part 98, 

subpart W) and one clarifying edit to a 

definition in the general provisions 

source category (Part 98, subpart A). The 

proposed changes revise certain 

calculation methods, amend certain 

monitoring and data reporting 

requirements, clarify certain terms and 

definitions, and correct certain technical 

and editorial errors identified during the 

course of implementation. The proposed 

revisions were identified from the 

verification of annual reports, review of 

Best Available Monitoring Method 

(BAMM) request submittals, and 

questions raised by reporting entities. In 

conjunction with this action, we are 

proposing confidentiality 

determinations for the new and 

substantially revised (i.e., requiring 

additional or different data to be 

reported) data elements contained in 

these proposed amendments, as well as 

proposing a revised confidentiality 

determination for one existing data 

element. 

C. Legal Authority 

The EPA is proposing these rule 

amendments under its existing CAA 

authority provided in CAA section 114. 

As stated in the preamble to the 2009 

final GHG reporting rule (74 FR 56260, 

October 30, 2009), CAA section 

114(a)(1) provides the EPA broad 

authority to require the information 

proposed to be gathered by this rule 

because such data would inform and are 

relevant to the EPA’s carrying out a 

wide variety of CAA provisions. See the 

preambles to the proposed (74 FR 

16448, April 10, 2009) and final GHG 

reporting rule (74 FR 56260, October 30, 

2009) for further information. 

In addition, the EPA is proposing 

confidentiality determinations for 

proposed new or substantially revised 

data elements in subpart W, as well as 

proposing a revised confidentiality 

determination for one existing data 

element, under its authorities provided 

in sections 114, 301, and 307 of the 

CAA. Section 114(c) requires that the 

EPA make information obtained under 

section 114 available to the public, 

except where information qualifies for 

confidential treatment. The 

Administrator has determined that this 

action is subject to the provisions of 

section 307(d) of the CAA. 

D. How would these amendments apply 

to 2014 and 2015 reports? 

The EPA is planning to address the 

comments we receive on these proposed 

changes and publish the final 

amendments before the end of 2014. If 

finalized, these amendments would 

become effective on January 1, 2015. 

Facilities would therefore be required to 

follow the revised methods in subpart 

W, as amended, to calculate emissions 

beginning January 1, 2015 (i.e., 

beginning with the 2015 reporting year). 

The first annual reports of emissions 

calculated using the amended 

requirements would be those submitted 

by March 31, 2016, which would cover 

the 2015 reporting year. For the 2014 

reporting year, reporters would continue 

to calculate emissions and other 

relevant data for the reports that are 

submitted according to the requirements 

of 40 CFR part 98 that are applicable to 

the 2014 reporting year (i.e. those 

currently in effect). 

II. Revisions and Other Amendments 

The amendments to subpart W that 

the EPA is proposing include the 

following types of changes: 

• Changes to clarify or simplify 

calculation methods for certain sources 

at a facility, and reduce some of the 

burden associated with data collection 

and reporting. 

• Revisions to units of measure, 

terms, and definitions in certain 

equations to provide consistency 

throughout the rule, provide clarity, or 

better reflect facility operations. 

• Revisions to reporting requirements 

to clarify and align more closely with 

the calculation methods and to clearly 

identify the data that must be reported 

for each source type. 

• Other amendments and revisions 

identified as a result of working with 

the affected sources during rule 

implementation and outreach. 

In addition to the specific revisions or 

amendments discussed in this section of 

the preamble, the EPA is proposing 

several minor technical revisions to 

subpart W to improve readability, to 

create consistency in terminology, and/ 

or to correct typographical or other 

errors. These proposed revisions 

contained in the proposed regulatory 

text are further explained in the 

memorandum, ‘‘Proposed Minor 

Technical Corrections to Subpart W, 

Petroleum and Natural Gas Systems, in 

the Greenhouse Gas Reporting Program’’ 

in Docket ID No. EPA–HQ–OAR–2011– 

0512. The EPA invites public comment 

on the revisions identified in this 

memorandum, as well as those outlined 

in this preamble. 

A. Proposed Revisions To Provide 

Consistency Throughout Subpart W 

1. Consistency in Units of Measure for 

Emissions Reporting 

Currently, subpart W requires that 

reported GHG emissions be expressed in 

metric tons of CO2 equivalent (CO2e). 

The EPA is proposing to amend 40 CFR 

98.236 to revise the reporting of GHG 

emissions from units of metric tons of 

CO2e of each reported GHG to metric 

tons of each reported GHG. These 

proposed changes would increase 

consistency between the reporting 

requirements for subpart W and the rest 

of Part 98, because other subparts of Part 

98 generally require the reporting of 

metric tons of individual GHGs instead 

of metric tons of CO2e. Reporters would 

use the global warming potentials 

(GWPs) in Table A–1 of 40 CFR Part 98, 

subpart A, as required in 40 CFR 

98.2(b)(4), to calculate annual emissions 

aggregated for all GHGs from all 

applicable source categories in metric 

tons of CO2e for their annual reports. 

Specifically, we are proposing to 

revise the units of emissions reported in 

40 CFR 98.236 to require reporting in 

metric tons of methane (CH4), carbon 

dioxide (CO2), and nitrous oxide (N2O), 

as applicable, instead of reporting each 

gas in metric tons of CO2e. We are also 

proposing to revise certain calculation 

methods that require the calculation of 

emissions in CO2e. For example, subpart 

W total GHG emissions are calculated 

using equations that reference GWPs 

(Equations W–36 and W–40). We are 

proposing to amend each equation 

referencing GWPs separately to remove 

the conversion factors and GWPs that 

are built into the equations, and allow 

for calculation of individual GHG 

emissions in metric tons. 

The proposed revisions reduce the 

likelihood of errors and inconsistencies, 

because it reduces the number of 

calculations that need to be completed 

by reporters and removes some 

variability in how different reporters 

may complete these calculations (e.g., a 

reporter could inadvertently use the 

wrong GWP). The proposed changes 

would also simplify analysis of 

emissions on a GHG-specific basis, 


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which would facilitate the verification 

of reported data. In addition, this 

proposed change would align subpart W 

with the manner of reporting for most 

other subparts of Part 98. 

2. Onshore Production Source Category 

Definition 

We are proposing to revise the source 

category definition of onshore 

petroleum and natural gas production at 

40 CFR 98.230(a)(2) to clarify the 

emission sources covered for purposes 

of GHG reporting. The proposed 

amendments clarify the types of 

emission sources in the onshore 

petroleum and natural gas production 

source category to which the reporting 

requirements of subpart W apply. 

Specifically, we are proposing to add 

references to engines, boilers, heaters, 

flares, separation and processing 

equipment, and maintenance and repair 

equipment and to remove references to 

gravity separation equipment and 

auxiliary non-transportation-related 

equipment. Thus, the first sentence of 

40 CFR 98.230(a)(2) is proposed to read 

as follows: ‘‘Onshore petroleum and 

natural gas production means all 

equipment on a single well-pad or 

associated with a single well-pad 

(including but not limited to 

compressors, generators, dehydrators, 

storage vessels, engines, boilers, heaters, 

flares, separation and processing 

equipment, and portable non-selfpropelled equipment which includes 

well drilling and completion 

equipment, workover equipment, 

maintenance and repair equipment, and 

leased, rented or contracted equipment) 

used in the production, extraction, 

recovery, lifting, stabilization, 

separation or treating of petroleum and/ 

or natural gas (including condensate).’’ 

The references to gravity separation 

equipment and auxiliary nontransportation-related equipment in the 

current rule are redundant with other 

sources specified in the definition. The 

proposed amendments do not subject 

new emission sources to the reporting 

requirements and do not remove sources 

currently covered from the reporting 

requirements, but rather provide a more 

accurate description of the industry 

segment for purposes of GHG reporting. 

3. Definition of Sub-Basin Category 

The EPA is proposing to revise the 

definition of sub-basin category at 40 

CFR 98.238 to clarify coverage for 

purposes of GHG reporting due to issues 

identified during implementation. 

Specifically, we are proposing to define 

sub-basin category as ‘‘a subdivision of 

a basin into the unique combination of 

wells with the surface coordinates 

within the boundaries of an individual 

county and subsurface completion in 

one or more of each of the following five 

formation types: Oil, high permeability 

gas, shale gas, coal seam, or other tight 

gas reservoir rock. The distinction 

between high permeability gas and tight 

gas reservoirs shall be designated as 

follows: High permeability gas 

reservoirs with >0.1 millidarcy 

permeability, and tight gas reservoirs 

with ≤0.1 millidarcy permeability. 

Permeability for a reservoir type shall be 

determined by engineering estimate. 

Wells that produce only from high 

permeability gas, shale gas, coal seam, 

or other tight gas reservoir rock are 

considered gas wells; gas wells 

producing from more than one of these 

formation types shall be classified into 

only one type based on the formation 

with the most contribution to 

production as determined by 

engineering knowledge. All wells that 

produce hydrocarbon liquids (with or 

without gas) and do not meet the 

definition of a gas well in this sub-basin 

category definition are considered to be 

in the oil formation. All emission 

sources that handle condensate from gas 

wells in high permeability gas, shale 

gas, or tight gas reservoir rock 

formations are considered to be in the 

formation that the gas well belongs to 

and not in the oil formation.’’ The EPA 

is proposing these edits to clarify that 

‘‘tight gas reservoir rock’’ generally 

refers to tight reservoir rock formations 

that produce gas, and not tight reservoir 

rock formations that produce only oil, 

and that wells that produce liquids in a 

sub-basin from formations other than 

high permeability gas, shale gas, coal 

seam, or other tight gas reservoir rock 

are considered oil wells. 

B. Proposed Changes to Calculation 

Methods and Reporting Requirements 

This section describes proposed 

changes or corrections to calculation 

methods and reporting requirements. In 

general, the proposed revisions to 

calculation methods would provide 

greater flexibility and potentially reduce 

burden to facilities (e.g., by increasing 

options for calculating emissions from 

compressors), and increase clarity and 

congruency of calculation and reporting 

requirements (e.g., by clarifying which 

reporting requirements apply to which 

calculation methods). The EPA is also 

proposing minor technical revisions to 

the calculation methods of subpart W, 

such as making equation variables and 

definitions consistent across multiple 

equations that identify the same 

parameters, or clarifying requirements 

that have caused confusion. Please see 

the memo, ‘‘Proposed Minor Technical 

Corrections to Subpart W, Petroleum 

and Natural Gas Systems, in the 

Greenhouse Gas Reporting Program’’ in 

Docket ID No. EPA–HQ–OAR–2011– 

0512, for more information on the minor 

technical revisions included in this 

proposal. 

We are also proposing revisions to the 

reporting requirements in 40 CFR 

98.236. The proposed revisions would 

restructure the reporting requirements, 

make reporting requirements consistent 

with the calculation methods, clarify the 

data elements to be reported, and 

improve data utility. In the current 

subpart W rule, slight inconsistencies 

between the calculation and the 

reporting sections have caused 

confusion among some reporters. In 

order to improve the quality of the data 

reported, we are proposing to revise 

reporting requirements that more clearly 

align with the calculation methods for 

each source type. 

We are proposing to reorganize the 

reporting section by source type (e.g., 

natural gas pneumatic device venting, 

acid gas removal vents, etc.) and, for 

each industry segment, list which 

source types must be reported. These 

proposed changes would clarify the 

reporting requirements for each industry 

segment and streamline verification by 

reducing the amount of correspondence 

with facilities during verification 

regarding required data elements that 

were not reported. Although the 

proposed reporting requirements appear 

lengthier, the revisions separate the 

requirements into discrete reporting 

elements in order to facilitate reporting 

and improve data collection. The 

proposed revisions to the reporting 

requirements in 40 CFR 98.236 will 

clarify which data elements are required 

to be reported for which facilities. For 

example, in reviewing the current 

subpart W reporting forms, if a reporter 

left certain fields blank in the reporting 

form (e.g., emissions from flaring), the 

EPA has been unable to discern whether 

the field was left blank intentionally. 

Because the proposed 40 CFR 98.236 

would clearly define each data element 

for each emission source in each 

industry segment that must be reported, 

it would clarify which fields in the 

subpart W reporting form should be 

populated. In some cases, we are also 

proposing to add additional data 

elements to improve the quality of the 

data reported. The reporting of these 

proposed data elements would improve 

verification of reported emissions and 

reduce the amount of correspondence 

with reporters that is associated with 

follow-up and revision of annual 

reports. In nearly all cases, the new data 

elements are based on data that are 


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13398 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

already collected by the reporter or are 

readily available to the reporter, and 

would not require additional monitoring 

or data collection. For additional 

information on the proposed changes to 

the reporting section, see the memo, 

‘‘Proposed Revisions to the Subpart W 

Reporting Requirements’’ in Docket Id. 

No. EPA–HQ–OAR–2011–0512. 

1. Natural Gas Pneumatic Device 

Venting 

The EPA is proposing to revise the 

calculation method for natural gas 

pneumatic device venting to expand the 

use of site-specific data on gas 

compositions, if available, for facilities 

in the onshore natural gas transmission 

compression and underground natural 

gas storage industry segments. The final 

subpart W rule provides default natural 

gas compositions of 95 percent CH4 and 

1 percent CO2 for onshore natural gas 

transmission compression and 

underground natural gas storage, when 

calculating CH4 and CO2 volumetric 

emissions from transmission storage 

tanks (transmission compression), 

blowdown vent stacks (transmission 

compression), and compressor venting 

(40 CFR 98.233(u)(2)(iii) and (iv)). The 

provisions of 40 CFR 98.233(u)(2) only 

allow default gas compositions to be 

used, unless otherwise specified in 40 

CFR 98.233(u)(2) (i.e., for onshore 

production and natural gas processing). 

We are proposing to allow either the 

use of site-specific composition data for 

natural gas transmission compression 

and underground natural gas storage 

facilities or the use of a default gas 

composition (95 percent CH4 and 1 

percent CO2). Specifically, we are 

proposing to revise the parameter 

‘‘GHGi’’ in Equation W–1 to remove the 

default gas composition for CH4 and 

CO2 and to direct reporters to use the 

concentrations determined as specified 

in 40 CFR 98.233(u)(2)(i), (iii), and (iv). 

This amendment addresses reporter 

concerns and improves data quality for 

those using site-specific data. The 

proposed changes are consistent with 

provisions for other applicable emission 

sources at natural gas transmission 

compression and underground storage 

facilities and would allow a consistent 

gas composition to be used for all 

sources at a facility. The calculation still 

must be conducted in much the same 

way that is currently required; however, 

we are proposing that reporters be 

allowed to use site-specific data if they 

are available. Therefore, the EPA does 

not anticipate that this proposed change 

will significantly affect the reporting 

burden. The EPA requests comment on 

whether the use of site-specific 

composition data for calculating 

emissions should be required or 

optional. The EPA also requests 

comment and specific details on when, 

if ever, a facility would not have sitespecific gas composition data available. 

We are also proposing to revise the 

natural gas pneumatic device venting 

calculations (40 CFR 98.233(a)(1), (a)(2), 

and (a)(3)) to simplify how ‘‘Countt’’ of 

Equation W–1 (total number of natural 

gas pneumatic devices) must be 

calculated each year as new devices are 

added. The revisions clarify that for all 

industry segments, the reported number 

of devices must represent the total 

number of devices for the reporting 

year. For the onshore petroleum and 

natural gas production industry 

segment, reporters would continue to 

have the option in the first two 

reporting years to estimate ‘‘Countt’’ 

using engineering estimates. 

2. Acid Gas Removal Vents 

For acid gas removal vents, we are 

proposing minor clarifying edits to 40 

CFR 98.233(d) to clearly label each 

calculation method and to clarify 

provisions by providing references to 

equations where appropriate. We are 

also proposing to revise the parameters 

‘‘VolCO2’’ in Equation W–3 and 

parameters ‘‘VolI’’ and ‘‘VolO’’ in 

Equation W–4A and W–4B to clarify 

that the volumetric fraction used should 

be the annual average. We are also 

proposing to specify in 40 CFR 

98.233(d)(8) that reporters may use sales 

line quality specifications for CO2 in 

natural gas only if a continuous gas 

analyzer is not available. 

3. Dehydrators 

We are proposing to revise the 

dehydrator vents source by renumbering 

and revising the dehydrator calculation 

method for desiccant dehydrators in 

order to clarify the adjustment of 

emissions to account for venting to a 

vapor recovery system or to a flare (40 

CFR 98.233(e)). The proposed 

amendments provide for the adjustment 

of emissions vented to a vapor recovery 

system or flare (40 CFR 98.233(e)(5) and 

(e)(6)) for desiccant dehydrators because 

in the final subpart W rule, it was not 

clear how such an adjustment would be 

made. As such, we are clarifying the 

calculation methods for desiccant 

dehydrators that vent to a flare or vapor 

recovery device. 

4. Well Venting for Liquids Unloading 

The EPA is proposing to revise the 

calculation and reporting requirements 

for well venting from liquids unloading 

to allow for annualizing venting data for 

facilities that calculate emissions using 

a recording flow meter (Calculation 

Method 1). This proposed amendment 

would address reporter concerns and 

simplify reporting. Some reporters have 

expressed difficulty in collecting well 

venting data using a recording flow 

meter for the exact period of January 1 

to December 31, because they contend 

that it would require them to be 

physically present at each recording 

flow meter on December 31. The EPA is 

proposing to revise Calculation Method 

1 (40 CFR 98.233(f)(1)) such that 

reporters may use an annualized value 

to determine the cumulative amount of 

time of venting (‘‘Tp’’ in Equation W–7A 

and W–7B) if data are not available for 

the specific time period January 1 to 

December 31. We are specifying that if 

an annualized value is used, the 

monitoring period must begin before 

February 1 and must not end before 

December 1 of the reporting year, and 

that a minimum of 300 consecutive days 

must be used by reporters to determine 

the annualized vent time. The EPA is 

also proposing that the date of the end 

of one monitoring period must be the 

start of the next monitoring period for 

the next reporting year, and that all days 

must be monitored and all venting 

accounted for. We are proposing that if 

a reporter uses a monitoring period 

other than a full calendar year for any 

well, they must report the percentage of 

wells for which a monitoring period 

other than a full calendar year is used. 

Although the proposed change increases 

flexibility, the calculation still must be 

conducted in much the same way that 

is currently required. Therefore, the 

EPA does not anticipate that this 

proposed change will significantly affect 

reporting burden. 

We are proposing to change 

Calculation Method 1 at 40 CFR 

98.233(f)(1) to separate the calculation 

and reporting of emissions from wells 

that have plunger lifts and wells that do 

not have plunger lifts. This separation 

would allow the EPA and the public to 

more easily disaggregate emission data 

and activity data for wells that have 

plunger lifts and wells that do not have 

plunger lifts. We are proposing a 

clarification to Calculation Method 2 in 

40 CFR 98.233(f)(2) to clarify that this 

method is used for wells without 

plunger lifts. 

In a harmonizing change, the EPA is 

proposing to revise the reporting 

requirement for reporters using 

Calculation Method 1, under 40 CFR 

98.236 such that reporters would be 

required to report the cumulative 

amount of time of venting for each 

group of wells during the year. 

Calculation Method 1 uses the 

cumulative amount of time of venting 

and not the number of venting events, 


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to calculate emissions; therefore, this 

revision would align the reporting 

requirement with the calculation 

method. We are proposing harmonizing 

changes to 40 CFR 98.236 to separate 

the reporting of emissions from wells 

with and without plunger lifts when 

Calculation Method 1 is used. 

We are also proposing to amend the 

definition of the term ‘‘SPp’’ in Equation 

W–8 (40 CFR 98.233(f)(2)) to clarify that 

if casing pressure is not available for 

each well, reporters may determine the 

casing pressure using a ratio of the 

casing pressure to tubing pressure from 

a well in the same sub-basin where the 

casing pressure is known. This 

amendment would improve the 

consistency of the calculation method 

used to determine casing pressure 

across reporters. 

We are also proposing to revise 40 

CFR 98.236 to require that facilities 

using Calculation Methods 1, 2, and 3 

report a separate count of wells with 

plunger lifts and wells without plunger 

lifts, and to report annual emissions 

separately from each of those sources, 

respectively. We are also proposing to 

amend 40 CFR 98.236 to require the 

reporting of the cumulative number of 

unloadings from wells with plunger lifts 

and unloadings from wells without 

plunger lifts, the average flow rate of the 

measured well venting for wells with 

and without plunger lifts, and the 

internal casing or tubing diameters and 

pressures for wells with and without 

plunger lifts, as applicable. These 

proposed revisions break out the 

existing count and emissions reporting 

requirements to more clearly specify the 

sources of emissions at facilities. For 

further information on well venting for 

liquids unloading, see the Technical 

Support Document (TSD) ‘‘Greenhouse 

Gas Reporting Rule: Technical Support 

for Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Proposed Rule’’ in 

Docket ID No. EPA–HQ–OAR–2011– 

0512. 

5. Gas Well Completions And 

Workovers 

The EPA is proposing to amend 40 

CFR 98.238 to add definitions for 

‘‘reduced emissions completion’’ and 

‘‘reduced emissions workover’’. 

Currently, reduced emissions 

completions and reduced emission 

workovers are mentioned in the relevant 

calculation method as equipment that 

separates natural gas from the backflow 

and sends this natural gas to a flow-line. 

However, there are currently no defined 

terms for reduced emissions 

completions and reduced emissions 

workovers. The EPA notes that since the 

time that subpart W was promulgated, 

the EPA promulgated new source 

performance standards for the oil and 

natural gas sector under 40 CFR Part 60, 

subpart OOOO, that requires the use of 

a reduced emissions completion in 

specified circumstances. The EPA 

proposes to add a definition for 

‘‘reduced emissions completion’’ to 

subpart W that would be consistent with 

the description of that term in the new 

source performance standard 

rulemaking (see 76 FR 52757–8). 

Specifically, the EPA is proposing to 

amend 40 CFR 98.238 to define a 

‘‘reduced emissions completion’’ as a 

well completion following fracturing 

where gas flowback that is otherwise 

vented is captured, cleaned, and routed 

to the flow line or collection system, reinjected 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. We are proposing to amend 

40 CFR 98.238 to define a ‘‘reduced 

emissions workover’’ as a well workover 

with hydraulic fracturing (i.e., 

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. The EPA does not 

anticipate these definitional changes 

would impact current reporters under 

Part 98 because these changes are 

clarifying in nature and do not change 

any requirements of subpart W. 

The EPA is also proposing to amend 

the definition of ‘‘well completions’’ in 

40 CFR 98.6 to delete the term ‘‘refracture’’ as this term applies to an 

already producing well and is 

considered a well workover, not a well 

completion, for the purposes of part 98. 

This amendment is intended to avoid 

potential confusion concerning whether 

a re-fracture is a completion or 

workover in the context of subpart W. 

This change will also better align the 

existing definition of ‘‘well 

completions’’ with the new proposed 

definition of a ‘‘reduced emissions 

completion’’ by clarifying that a reduced 

emission completion only applies to 

new fractures and that re-fractures are 

potentially covered under the new 

definition of ‘‘reduced emission 

workover’’. The definition of ‘‘well 

workover’’ in 40 CFR 98.6 already refers 

to re-fractures, so no clarifying change is 

needed for that definition. 

We are also proposing to revise 

reporting requirements for completions 

and workovers to differentiate between 

completions and workovers with 

different well type combinations in each 

sub-basin category. A well type 

combination is a unique combination of 

the following factors: Vertical or 

horizontal, with flaring or without 

flaring, and reduced emission 

completion/workover or not reduced 

emission completion/workover. 

Specifically, for well completions and 

workovers with hydraulic fracturing, we 

are proposing to require separate counts 

and separate reporting of emissions for 

the different well type combinations. 

These revisions would improve data 

quality for emissions from wells with 

hydraulic fracturing. Because the EPA is 

proposing to expand the well type 

definition for completions and 

workovers with hydraulic fracturing to 

include whether the well completions/ 

workovers are flared or not, and 

whether it is a reduced or not reduced 

emission completion/workover, it is 

possible that reporters will have more 

than one reporting category (i.e., 

different well types in each sub-basin) 

for completions and workovers with 

hydraulic fracturing. Therefore, some 

reporters will be required to further 

categorize their calculated emissions 

from completions and workovers with 

hydraulic fracturing, which they did not 

have to do before. We anticipate that 

these proposed changes will increase 

burden to some reporters somewhat. 

Reporters will be required to separate 

and report their calculated emissions 

from completions and workovers 

without hydraulic fracturing by whether 

the emissions are related to completions 

or workovers, which they do not have 

to do under the current version of the 

rule. We anticipate that those proposed 

changes would only slightly increase 

burden to reporters. 

We are also proposing revisions to 

Equation W–10A that would add clarity 

and increase the accuracy of emissions 

calculations for gas well completions 

and workovers with hydraulic 

fracturing. In the final subpart W rule, 

the measurement or calculation for 

determining the ratio of flowback during 

well completions and workovers to 30- 

day production rate in Equation W–10A 

(40 CFR 98.233(g)) begins immediately 

upon initiating flowback of a well. Some 

reporters have asserted that the 

flowback characteristics of a well 

following hydraulic fracturing do not 

enable measurement or calculation to 

begin immediately upon initiating 

flowback due to a lack of sufficient gas 

being present, and the calculation needs 

to be revised to account for this fact. 

Therefore, the EPA is proposing to 


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modify the calculation to require the 

measurement of flow rate only when 

sufficient gas is present to enable flow 

rate measurement. In addition, some 

reporters have asserted that the accuracy 

of emissions calculations could be 

affected by the combined use of sales 

gas volume and approximations on flow 

rates for non-measured wells. To resolve 

this apparent issue, the time variable 

‘‘Tp’’ in Equation W–10A and W–10B is 

being modified. Time that the gas is 

routed to production would no longer 

be included, so it would no longer be 

necessary to subtract the volume of gas 

being sent to sales. This amendment 

would not significantly change the 

reporting burden. The proposed 

equations are similar in complexity as 

the previous equations and use 

measurements that are of similar 

complexity. This proposed revision 

would improve data quality and provide 

flexibility by providing an estimation 

method for data that could not likely be 

measured accurately. 

We are also proposing changes to the 

calculation section at 40 CFR 98.233(g) 

and (h) to support the separate 

calculation of emissions from 

completions and workovers that are 

vented, flared, or use equipment that 

separates natural gas from the backflow 

and sends this natural gas to a flow-line 

(e.g., reduced emissions completions or 

reduced emissions workovers). 

Reporters currently calculate emissions 

from all completion and workover 

activities, but the equations do not 

facilitate the classification of the activity 

needed for separate reporting. We are 

proposing to revise Equation W–13 in 

40 CFR 98.233(h) to separate the 

calculation of emissions from workovers 

from the calculation of completions into 

two equations. This amendment will 

improve data quality. We are also 

proposing to clarify that reporters must 

calculate the annual volumetric natural 

gas emissions from each gas well 

venting during workovers without 

hydraulic fracturing using Equation W– 

13A and from each gas well venting 

from completions without hydraulic 

fracturing using new Equation W–13B. 

We do not anticipate that this proposed 

change would significantly increase the 

reporting burden, because the proposed 

calculations are the same as the current 

calculation; we only propose to break it 

into two steps. The proposed 

methodology also requires the addition 

of parameter ‘‘Es,p’’ for Equation W–13B 

to specify the annual volumetric natural 

gas emissions in standard cubic feet 

from well completions. We are also 

proposing to revise 40 CFR 98.233(g)(1) 

to clarify the number of measurements 

or calculations that must be taken to 

estimate the average ratio of flowback 

rate (FRM). 

We are proposing to revise 40 CFR 

98.233(g)(2) to clarify that 

measurements from the well flowing 

pressure upstream of a well choke to 

calculate well backflow must be 

collected for each sub-basin and well 

type combination. We are also 

proposing to revise parameter ‘‘PRs,p’’ in 

Equations W–10A and W–10B and 

Equation W–12 to clarify that the first 

30 day average production flow rate is 

the average taken after completions of 

newly drilled gas wells or workovers. 

For further information on gas well 

venting during completions and 

workovers, see the TSD ‘‘Greenhouse 

Gas Reporting Rule: Technical Support 

for Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems; Proposed Rule’’ in 

Docket ID No. EPA–HQ–OAR–2011– 

0512. 

6. Blowdown Vents 

Based on questions received during 

implementation of the final subpart W 

rule and reporter concerns, the EPA is 

proposing to revise Equations W–14A 

and W–14B to include a compressibility 

term. Specifically, some reporters 

requested that the EPA allow the use of 

a factor to adjust for compressibility 

when calculating emissions from 

blowdown vents. The calculation 

method for blowdown vents included in 

the existing subpart W rule assumes 

natural gas is an ideal gas with a 

compressibility factor of 1, and does not 

include an adjustment for 

compressibility in the calculation. 

Although the EPA had previously 

considered including the 

compressibility term (76 FR 56010, 

September 9, 2011), the EPA ultimately 

did not propose including the factor, 

because we then concluded that 

including a compressibility adjustment 

could create a degree of uncertainty 

between reporters on how their reported 

blowdown values compared (on a 

volume basis). We noted at that time 

that although the compressibility of 

pure light hydrocarbon substances is 

well known, the compressibility of 

hydrocarbon mixtures is less well 

known and the composition of natural 

gas throughout the segments covered by 

subpart W can be variable. At that time, 

we determined that ideal gas law 

calculations were adequate for reporting 

purposes under Part 98. 

The EPA notes that the circumstances 

surrounding this issue are now different 

because, as discussed in Section III.B.1 

of this preamble, the EPA is proposing 

to require the use of site-specific data on 

gas compositions, if available. In 

addition, we have determined that at 

high pressures and low temperatures, 

the accuracy of the emission estimate 

would be improved if a compressibility 

factor were included in the calculation. 

The compressibility of methane at 

standard conditions is close to one. 

However, the compressibility of 

methane at low temperatures and high 

pressures is lower than one, which may 

affect the accuracy of the emission 

calculation if not included in that 

calculation. Therefore, the EPA 

proposes to revise Equations W–14A 

and W–14B in 40 CFR 98.233(i) to 

include the compressibility term ‘‘Za’’. 

A default compressibility term of 1 may 

be used at conditions where the 

pressure is below 5 atmospheres, and 

the temperature is above ¥10 degrees 

Fahrenheit, or if the compressibility 

factor at the actual temperature and 

pressure is 0.98 or greater. We are 

proposing harmonizing changes to 

Equations W–33 and W–34 in 40 CFR 

98.233(t) to include the compressibility 

term ‘‘Za’’ for conversion of volumetric 

emissions at actual conditions to 

standard conditions. Because it is likely 

that most facilities handle gas within 

the proposed compressibility factor 

default ranges, it is unlikely that adding 

this compressibility factor term into the 

blowdown vent stack calculations will 

significantly increase the reporting 

burden. 

The EPA is also proposing to simplify 

the reporting for blowdowns. In the 

final subpart W rule, reporters must 

calculate and record emissions for each 

blowdown event that is greater than or 

equal to 50 cubic feet of actual volume. 

Currently, for each piece of equipment 

(unique physical volume) that is blown 

down more than one time in a calendar 

year, reports are submitted for the total 

number of blowdowns, the emissions 

for each unique physical volume, and 

the name or ID number for the unique 

physical volume. For all equipment that 

is blown down only once during the 

calendar year, reports are submitted as 

an aggregate for all such equipment at 

each facility. Reports include the total 

number of blowdowns and the 

emissions from all equipment with 

unique physical volumes that are blown 

down only once. The volume of gas 

vented is calculated for each blowdown 

event using the conditions specific to 

the event. However, the reporting of 

each ‘‘unique physical volume’’ blown 

down more than once in a year may be 

an extensive list of unique equipment. 

A similar reporting approach was 

adopted by the EPA in the November 

2010 version of subpart W (75 FR 

74458). There, the reporting 


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requirement specified that emissions be 

reported collectively per equipment 

type. This approach caused some 

confusion because a list of equipment 

types was not provided. Therefore we 

are proposing to revise the current 

reporting requirements in 40 CFR 

98.236(c)(7) to simplify the reporting 

structure to report blowdown emissions 

aggregated by seven categories: station 

piping, pipeline venting, compressors, 

scrubbers/strainers, pig launchers and 

receivers, emergency shutdowns, and all 

other blowdowns greater than or equal 

to 50 cubic feet. Although facilities are 

no longer required to report blowdown 

vent stack emissions by each unique 

physical volume, facilities still have to 

calculate blowdown vent stack 

emissions from each unique physical 

volume and categorize the emissions by 

equipment. Therefore, the EPA has 

determined that this proposed change 

would not significantly impact burden 

to reporters. 

The EPA is also proposing an optional 

calculation method for blowdown 

emissions for situations where a flow 

meter is in place to measure the 

emissions directly. If a blowdown vent 

is equipped with a flow meter, there 

would not be an advantage to 

calculating the emissions using the 

unique volume, temperature, and 

pressure conditions of the equipment 

instead of the directly measured flow 

rate. We are proposing this alternative 

calculation method in 40 CFR 98.233(i), 

along with associated reporting 

requirements in 40 CFR 98.236. We are 

also proposing additional clarifying 

edits for both the blowdown calculation 

and reporting sections of the rule. If a 

flow meter is in place to measure 

emissions, the emissions would be 

reported on a facility basis, and would 

not be aggregated by emission type per 

40 CFR 98.236(i)(2). For further 

information on blowdown vents, see the 

TSD ‘‘Greenhouse Gas Reporting Rule: 

Technical Support for Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

Proposed Rule’’ in Docket ID No. EPA– 

HQ–OAR–2011–0512. 

7. Onshore Production Storage Tanks 

We are proposing to revise the 

method for estimating emissions from 

occurrences of well pad gas-liquid 

separator liquid dump valves that are 

not properly operating for onshore 

production storage tanks. The EPA 

initiated this revision to address 

reporter concerns and to improve data 

quality. Specifically, reporters 

expressed concern with the burden 

associated with quantifying and 

recording information for all properly 

functioning dump valves. The proposed 

revisions would require the detection of 

an anomaly and only then require 

quantification. Hence only those dump 

valves found to not be closing properly 

(i.e., stuck dump valves) would have to 

be quantified. Specifically, the EPA is 

proposing to simplify Equation W–16 to 

calculate emissions for only periods 

when the dump valve is not closing 

properly. 

The EPA is also proposing to revise 

the reporting section to make it clear 

that facilities are to separately report the 

emissions from onshore production 

storage tanks attributable to periods 

when dump valves are not closing 

properly, as opposed to emissions that 

occur when dump valves are closing 

properly. In the final subpart W rule, 40 

CFR 98.236(c)(8)(iv) requires that 

facilities report annual total volumetric 

GHG emissions that resulted from dump 

valves that are not closing properly. 

However, Equation W–16 in the final 

subpart W rule sums the total emissions 

for periods when the dump valve is 

closing properly and periods when the 

dump valve is not closing properly. The 

EPA is clarifying 40 CFR 98.236 to 

specify that facilities that use Equation 

W–16 should report only emissions that 

result from dump valves that are not 

closing properly. Note that emissions 

from atmospheric tanks that are not a 

result of dump valves not closing 

properly would continue to be reported 

in this proposed revision outside of 

Equation W–16. There is no significant 

additional burden to facilities, because 

reporters already use these data 

elements in Equation W–16: separate 

tank and dump valve emissions already 

need to be calculated separately, but 

would now also be reported separately. 

This revision would eliminate potential 

confusion for reporters, clarify 

recordkeeping requirements, and 

improve the ability to quantify 

emissions from stuck dump valves. For 

further information on emissions from 

improperly functioning dump valves, 

see the TSD ‘‘Greenhouse Gas Reporting 

Rule: Technical Support for Revisions 

and Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

Proposed Rule’’ in Docket ID No. EPA– 

HQ–OAR–2011–0512. These proposed 

revisions would improve the quality of 

data collected. 

8. Associated Gas Venting and Flaring 

The EPA is proposing to add a term 

to Equation W–18 (40 CFR 98.233(m)(3)) 

to account for situations where part of 

the associated gas from a well goes to a 

sales line while another part of the gas 

is flared or vented. These amendments 

improve data quality by eliminating 

duplicate reporting. Emissions are 

currently calculated based on the gas-tooil ratio (GOR) and volume of oil 

produced during the flaring period. The 

GOR is based on total gas from the well, 

which means all the gas would 

currently be reported as flared even 

though a portion of the gas goes to a 

sales line. The proposed revision to 

Equation W–18 subtracts the volume of 

associated gas sent to sales from the 

annual volumetric natural gas emissions 

from associated gas venting. The EPA 

has also included in the equation a term 

(EREp,q) for emissions reported under 

other sources included in this subpart 

(i.e., tank venting) to avoid double 

counting of these emissions. The EPA 

also proposes updating the definition of 

the term GORp,q and the emission result 

Ea,n in Equation W–18 to specify that the 

gas to oil ratio and the result of the 

calculation are calculated at standard 

conditions rather than actual 

conditions. Because the GOR is 

measured in standard cubic feet, this 

change would harmonize the equation 

terms and the result of the emission 

calculation equation would be at 

standard conditions. Although the 

proposed calculation method modifies 

the current equation to include two new 

terms, these terms are already being 

calculated elsewhere and/or can be 

estimated. Therefore, the EPA does not 

anticipate that this proposed change 

will significantly affect the reporting 

burden. 

The EPA is also proposing to add a 

definition for the term ‘‘Associated gas 

venting or flaring’’ to clarify what is 

included in this source. The EPA is 

proposing to define ‘‘Associated gas 

venting or flaring’’ as ‘‘the venting or 

flaring of natural gas which originates at 

wellheads that also produce 

hydrocarbon liquids and occurs either 

in a discrete gaseous phase at the 

wellhead or is released from the liquid 

hydrocarbon phase by separation. This 

definition does not include venting or 

flaring resulting from activities that are 

reported elsewhere, including tank 

venting, well completions, and well 

workovers.’’ The proposed definition 

allows for greater consistency with the 

changes made to the calculation 

method. This is a clarifying proposed 

change that improves data quality and 

should not significantly affect the 

burden to current reporters. For further 

information on emissions from 

associated gas, see the TSD 

‘‘Greenhouse Gas Reporting Rule: 

Technical Support for Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 


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13402 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

Proposed Rule’’ in Docket ID No. EPA– 

HQ–OAR–2011–0512. 

9. Flare Stack Emissions 

The EPA is proposing to amend the 

calculation method for emissions from a 

flare stack to simplify the calculation to 

standard conditions and to account for 

gas that is sent to an unlit flare. 

Specifically, we are proposing to revise 

Equation W–19 and combine Equations 

W–20, and W–21. The EPA also 

proposes to revise the equations such 

that the emissions of CH4 and CO2 are 

calculated in standard conditions. We 

propose to remove paragraph 40 CFR 

98.233(n)(11), which specifies 

estimating emissions for the volume of 

gas flared under actual conditions. We 

also propose to add the terms ‘‘ZU’’ and 

‘‘ZL’’ to Equation W–19 and the terms 

‘‘ZU’’ and ‘‘ZL’’ to Equation W–20 to 

account for the fraction of gas sent to an 

unlit flare and the fraction of gas sent to 

a burning flare. The fraction of feed gas 

sent to an unlit flare would be 

determined by using engineering 

estimates and process knowledge. The 

proposed changes simplify and clarify 

the calculation requirements and would 

improve the accuracy of the collected 

data by accounting for the fraction of 

emissions that are not combusted when 

sent to an unlit flare. 

The EPA is also proposing a revision 

to the onshore natural gas transmission 

compression, underground natural gas 

storage, liquefied natural gas (LNG) 

storage, LNG import and export 

equipment industry segments to clarify 

that emissions from any flares in these 

segments must be reported using the 

calculation method for emissions from a 

flare stack. This clarifying revision is 

consistent with the treatment of flares in 

other parts of subpart W and is 

necessary to calculate emissions for 

compressors routed to flares under the 

proposed compressor calculation 

requirement modifications. We 

anticipate that this proposed change 

may slightly increase burden for select 

reporters and will not significantly 

affect burden for most reporters; 

however, this clarifying revision is 

consistent with the treatment of flares in 

other parts of subpart W and is 

necessary to calculate emissions for 

compressors routed to flares under the 

proposed compressor calculation 

requirement modifications. 

10. Centrifugal and Reciprocating 

Compressors 

Some reporters have contended that 

the current monitoring requirements for 

compressor venting are overly 

burdensome and present safety and 

operational process concerns. These 

reporters asserted that it is not practical 

to require a measurement from each 

individual compressor for groups of 

compressors that are routed to a 

common vent manifold (or flare header), 

because this would require the entire 

group of compressors that are connected 

to the common manifold (or flare 

header) to be shutdown, blown down, 

and purged in order to safely install 

meters (or ports for temporary meters) 

and enable individual measurements. 

The reporters stated that it is extremely 

rare that entire groups of compressors 

are shutdown at the same time. In the 

November 2010 response to public 

comments on the subpart W final rule 

(Docket ID No. EPA–HQ–OAR–2009– 

0923), the EPA noted that commenters 

requested that the EPA allow direct 

measurements of common manifolded 

vent lines on compressors. At least one 

commenter stated that if continuous 

measurement of manifolded vent lines 

and aggregate annual emissions 

reporting were allowed as an option for 

measuring compressors, they would be 

able to safely collect and report to the 

EPA continuously measured data. The 

EPA did not include this option in the 

2010 final subpart W rule because it was 

not clear whether measurements at a 

common vent outlet could be used to 

correctly characterize annual emissions 

from individual compressors. 

In today’s action, we are proposing 

changes to the centrifugal and 

reciprocating compressor calculation 

sections (see 40 CFR 98.233(o) and (p)) 

in order to address reporter concerns 

related to measuring centrifugal and 

reciprocating compressor emissions that 

are routed to a common vent manifold 

(or flare header). For those compressors, 

the EPA is proposing an option where 

reporters would take at least three 

measurements per year and report the 

average of the measurements. These 

measurements would need to be taken 

before emissions are comingled with 

other non-compressor emission sources. 

This option would address reporter’s 

safety concerns for facilities that need to 

shut down equipment to install 

individual meters and maintain accurate 

characterization of annual emissions 

from compressors at the facility. Annual 

volumetric emissions would be 

determined for each manifolded group 

of compressors combined for all 

operating conditions (mode-source 

combinations). Reporters would still be 

required to report activity data for any 

individually measured sources (i.e., 

non-manifolded sources) at the 

compressor level. Activity data reported 

would include information about the 

individual compressors included in the 

manifolded vent. This proposed 

measurement option would allow the 

EPA to correctly characterize and 

analyze GHG emissions from all 

compressors at individual facilities in 

the petroleum and natural gas systems 

source category while potentially 

reducing burden to the industry. 

Although reporting elements include 

new activity data, reporters would no 

longer be required to sample manifolded 

compressor sources individually, thus 

decreasing overall burden and providing 

flexibility. For example, if a reporter 

operates seven compressors that have 

their blowdown vent stacks manifolded, 

the reporter would no longer have to 

conduct seven measurements every year 

(one for each blowdown vent stack) as 

required by the current rule. Instead, for 

this example, the reporter would be 

required to only conduct a measurement 

three times per year on the common 

vent stack that is associated with the 

manifolded group of seven compressor 

sources, which would decrease burden 

for the reporter compared to the seven 

measurements currently required. 

The EPA considered requiring only 

one or two measurements per year for 

these manifolded sources (as opposed to 

the EPA proposal above for the average 

of three measurements). The EPA 

concluded that the annual process 

variability for these sources was high 

enough to warrant more than one or two 

measurements per year. Please see the 

TSD ‘‘Greenhouse Gas Reporting Rule: 

Technical Support for Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

Proposed Rule’’ in Docket ID No. EPA– 

HQ–OAR–2011–0512, for more 

background and information on the 

options considered. In addition to 

seeking comment on our proposed 

option, the EPA is specifically seeking 

comment on the two other options that 

were considered and other derivations 

of these options (i.e., four measurements 

per year instead of three). Comments 

should include justification why the 

specific option receiving comment does 

not negatively impact safety, is 

technical and economically feasible, 

does not impose undue burden on 

reporters, and how the option is 

sufficiently accurate given the annual 

process variability for these sources. 

We are also proposing to include four 

definitions in 40 CFR 98.238 to support 

the addition of the calculation method 

for manifolded vents. We are proposing 

a definition for ‘‘compressor’’ to mean 

‘‘any type of vent or valve (i.e., wet seal, 

blowdown valve, isolation valve, or rod 

packing) on a centrifugal or 

reciprocating compressor.’’ We are 

proposing a definition for ‘‘compressor 


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mode’’ to mean ‘‘means the operational 

and pressurized status of a compressor. 

For a centrifugal compressor, ‘‘mode’’ 

refers to either operating-mode or notoperating-depressurized-mode. For a 

reciprocating compressor, ‘‘mode’’ refers 

to either: Operating-mode, standbypressurized-mode, or not-operatingdepressurized-mode.’’ We are proposing 

a definition for ‘‘manifolded compressor 

source’’ to mean ‘‘a compressor source 

that is manifolded to a common vent 

that routes gas from multiple 

compressors.’’ We are also proposing a 

definition of ‘‘manifolded group of 

compressor sources’’ to mean ‘‘a 

collection of any combination of 

compressor sources that are manifolded 

to a common vent.’’ 

In addition, for compressors that are 

routed to an operational flare, we are 

proposing to allow operators to 

calculate and report emissions with 

other flare emissions (in lieu of 

estimating compressor emissions based 

on knowledge of the total flare 

emissions and the portion of those flare 

emissions that can be attributed to 

compressors). This proposed change 

addresses reporter concerns, provides 

flexibility, and potentially decreases 

burden without affecting data quality. 

Although operators would still be 

required to report certain compressorrelated activity data for each compressor 

that is routed to an operational flare (as 

provided for in 40 CFR 98.236(o)(1) and 

(p)(1)), reporting emissions from 

compressors (that are routed to an 

operational flare) with other flare 

emissions would reduce burden, 

because reporters would not be required 

to sample compressors individually or 

be required to portion flare emissions 

attributed to compressors. 

It was brought to the EPA’s attention 

that the 3-year cycle requirement for 

measuring compressors in the notoperating-depressurized-mode could 

present a compliance challenge for some 

facilities, because not every facility 

schedules routine shutdowns for 

maintenance within 3 years. The EPA 

did not intend for reporters to perform 

an unscheduled shutdown of a facility 

for the sole purpose of taking a 

measurement of the compressor in the 

not-operating-depressurized-mode. 

Therefore, we are proposing to revise 

the requirement to measure each 

compressor in the not-operatingdepressurized-mode at least once in any 

3 consecutive calendar years, provided 

the measurement can be taken during a 

scheduled shutdown. If there is no 

scheduled shutdown within three 

consecutive calendar years, the EPA 

proposes that a measurement must be 

made at the next scheduled 

depressurized compressor shutdown 

(for reciprocating compressors, this 

measurement can be taken during the 

next scheduled shutdown when the 

compressor rod packing is replaced). By 

allowing the measurement to be taken at 

these specified scheduled shutdowns, 

operators would not have to plan a 

shutdown of their equipment to take a 

measurement of their compressor in the 

not-operating-depressurized-mode. This 

proposed amendment addresses 

reporters’ concerns and potentially 

decreases burden without affecting data 

quality. Even though the ‘‘not-operatingdepressurized-mode’’ is measured only 

at scheduled shutdowns (which might 

be every 3 years or greater), the reporter 

is still required to conduct an annual 

measurement in whatever mode the 

compressor is found. Therefore, the 

frequency in measurements is 

unchanged. The EPA also considered 

modifying the existing requirement to 

measure each compressor in the notoperating-depressurized-mode at least 

once every 3 years to correspond to a 

longer term, such as every 5 years. 

However, such an extension might not 

resolve the issue for all reporters. The 

EPA is specifically seeking comment on 

our proposed option as well as the 

additional option that was considered. 

The EPA is also clarifying that for 

reporters that elect to conduct as found 

leak measurements for individual 

compressor sources, all measurements 

from a single owner or operator may be 

used when developing an emission 

factor (using Equation W–24 or W–28 of 

40 CFR 98.233) for each compressor 

mode-source combination. If the 

reporter elects to use this option, the 

reporter emission factor must be applied 

to all reporting facilities for the owner 

or operator. Although this option may 

make it easier for some reporters to keep 

track of their calculated reporter 

emission factors, all reporters are still 

required to calculate reporter emission 

factors if they use the as found leak 

measurement option. Therefore, the 

EPA does not anticipate that this 

clarifying edit will significantly affect 

the reporting burden. 

We are also proposing to restructure 

and revise the centrifugal and 

reciprocating compressor sections (see 

40 CFR 98.233(o) and 40 CFR 98.233(p)) 

in order to improve clarity for reporters. 

Because the restructuring was extensive, 

entirely new text appears for 40 CFR 

98.233(o) and 40 CFR 98.233(p). 

Although the proposed restructuring 

changes would not significantly change 

any of the requirements or burden, the 

proposed restructuring and revisions 

would clarify current requirements that 

are vague or confusing. For example, we 

are proposing to retain the current 

equations for determining emissions 

from each compressor’s measured 

mode-source combination and 

unmeasured mode-source combination; 

however, we are proposing language 

that would explain when to use the 

equation(s). We are also proposing 

revisions to improve consistency 

between the centrifugal and 

reciprocating compressor sections (see 

40 CFR 98.233(o) and 40 CFR 

98.233(p)). For example, we are 

proposing to revise the equation 

variables to bring consistency between 

the two sections. It is our view that the 

restructuring and clarification revisions 

that we are proposing in this action for 

the centrifugal and reciprocating 

compressor sections would improve 

readability and usability for both 

industry and government regulators. For 

further information on measuring 

emissions from compressors, see the 

TSD ‘‘Greenhouse Gas Reporting Rule: 

Technical Support for Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

Proposed Rule’’ in Docket ID No. EPA– 

HQ–OAR–2011–0512. 

11. Natural Gas Distribution: Leak 

Detection Equipment and Emissions 

From Components 

For natural gas distribution, the final 

subpart W rule requires reporters to 

calculate a facility emission factor for a 

meter/regulator run per component type 

at above grade metering-regulating (M– 

R) stations. The calculation of the 

emission factor using Equation W–32 in 

40 CFR 98.233(r) based on the results of 

equipment leak surveys that are 

required under 40 CFR 98.233(q) at 

above grade transmission-distribution 

(T–D) stations and the subsequent 

annual emissions calculated for those 

stations using Equations W–30B. 

Reporters have pointed out that the 

nomenclature and inter-related 

calculations between 40 CFR 98.233(q) 

and (r) has caused confusion. Therefore, 

the EPA is proposing to revise the 

calculation requirements for natural gas 

distribution facilities and associated 

terminology in 40 CFR 98.233(q) and (r). 

Specifically, the EPA is proposing to 

place the facility meter/regulator run 

emission factor calculation in 40 CFR 

98.233(q) instead of 40 CFR 98.233(r) 

and clarify that the emission factor is 

calculated separately for CO2 and CH4

and is on a meter/regulator run 

operational hour basis, instead of on a 

meter/regulator run component basis. 

Facilities calculate annual emissions 

from above grade transmissiondistribution transfer stations using 

Equation W–30 of 40 CFR 98.233(q). 


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The emissions are calculated in 

Equation W–30 on a per component 

basis based on equipment leak survey 

results and leaker emission factors for 

transmission-distribution transfer 

station components listed in Table W– 

7. The results of the component level 

annual emissions calculations using 

Equation W–30 are then summed for all 

component types in Equation W–31 to 

develop the annual facility meter/

regulator run emission factors for CO2

and CH4. Those facility emission factors 

must be recalculated annually as 

additional equipment leak survey data 

becomes available from above grade 

transmission-distribution transfer 

stations. To calculate annual emissions 

from above grade metering-regulating 

stations that are not above grade 

transmission-distribution transfer 

stations, facilities must use the emission 

factors (calculated in Equation W–31) in 

the annual emissions calculation of 

Equation W–32B in 40 CFR 98.233(r). 

Emissions from below grade meteringregulating stations, below grade 

transmission-distribution transfer 

stations, distribution mains, and 

distribution services are calculated 

using Equation W–32A of 40 CFR 

98.233(r) using population emission 

factors listed in Table W–7. These 

proposed revisions will alleviate the 

current confusion with the calculation 

and reporting requirements for natural 

gas distribution facilities while 

capturing the same emissions sources 

from this industry segment and 

maintaining the same level of data 

accuracy. Data are generally reported at 

a less detailed level, but there is no 

change in emissions coverage. 

12. Onshore Petroleum and Natural Gas 

Production and Natural Gas Distribution 

Combustion Emissions 

The EPA is proposing to clarify that 

emissions and volume of fuel 

combusted must be reported for all 

compressor driven internal combustion 

units in 40 CFR 98.236. The EPA is 

proposing to revise this reporting 

requirement to be consistent with the 

emission estimation methods in 40 CFR 

98.233(z)(4) that specify the exemption 

from reporting emissions for internal 

combustion units with a rated heat 

input capacity less than or equal to 1 

MMBtu/hr (130 horsepower) does not 

apply to internal fuel combustion 

sources that are compressor drivers. 

C. Proposed Revisions to Missing Data 

Provisions 

We are proposing to revise 40 CFR 

98.235 to clarify the procedures for 

estimating missing data. We are 

proposing to increase the specificity 

regarding how to use, treat, and report 

missing data for each calculation 

specified in 40 CFR 98.233.These 

proposed revisions would increase 

clarity for reporters and improve the 

accuracy of the data reported by 

ensuring that the data substituted for 

missing values is limited in use, and, 

where necessary, well-documented and 

quality-assured or based on the best 

available estimates. To address newly 

acquired wells, the EPA is also 

proposing missing data procedures 

specific to facilities that are newly 

subject to subpart W and to existing 

onshore petroleum and natural gas 

production facilities that acquire wells 

that were not subject to subpart W prior 

to the acquisition. In these specific 

cases, the EPA is proposing to allow 

best engineering estimates for any 

parameter that cannot be reasonably 

measured or obtained according to the 

requirements in subpart W for up to six 

months from the first date of subpart W 

applicability. Where facilities acquired 

additional wells, only data and 

calculations associated with those 

newly acquired wells would fall within 

this proposed provision. This proposed 

revision provides flexibility for newly 

acquired facilities or wells. Missing data 

procedures were previously not allowed 

for many areas of subpart W; however, 

with the proposed removal of BAMM, 

the missing data procedures provide 

clarity for reporters who may have 

unintentionally missed required data. 

D. Proposed Amendments to Best 

Available Monitoring Methods 

In order to provide facilities with time 

to adjust to the requirements of the rule, 

subpart W has provisions allowing the 

optional use of best available 

monitoring methods (BAMM) for unique 

or unusual circumstances. Where a 

facility uses BAMM, it is required to 

follow emission calculations specified 

by the EPA, but is allowed to use 

alternative methods for determining 

inputs to calculate emissions. Inputs are 

the values used by facilities to calculate 

equation outputs. Examples of BAMM 

include: Monitoring methods used by 

the facility that do not meet the 

specifications of subpart W, supplier 

data, engineering calculations, and other 

company records. Facilities are required 

to receive approval from the EPA prior 

to using BAMM and these facilities are 

required to specify in their GHG annual 

reports when BAMM is used for an 

emission source. The EPA has 

previously noted that the Agency 

intended to ‘‘approve the use of BAMM 

beyond 2011 only in cases that are 

unique or unusual’’ (76 FR 59538). 

Furthermore, the EPA limited the 

approvals of BAMM to one reporting 

year in keeping with the intent to allow 

use of BAMM as a transitional provision 

until facilities come into compliance 

with the final rule. While the EPA 

occasionally uses BAMM for targeted, 

short-term monitoring flexibilities (i.e., 

provision for reporters who become 

subject to Part 98 from the recent GWP 

changes to subpart A to have automatic 

BAMM for the first three months of 

reporting), no industry-specific subpart 

within Part 98 continues to use the 

BAMM flexibility except subpart W. 

In this action, the EPA is proposing to 

remove all provisions in 40 CFR 

98.234(f) for BAMM. We are also 

proposing to remove and reserve 40 CFR 

98.234(g), which is a provision specific 

to the 2011 and 2012 reporting years. 

The removal of BAMM will improve 

data quality by requiring consistent 

reporting for each segment in subpart 

W. We are proposing these amendments 

because we expect facilities would be 

able to comply with the monitoring and 

QA/QC methods required under subpart 

W after this proposed rule is finalized 

and effective. Reporters with issues that 

were unidentified at the time of the final 

rule will, by January 1, 2015, have had 

adequate time to resolve these issues. It 

has been the EPA’s intent throughout 

implementation of subpart W that 

BAMM be available as a limited, 

transitional program to serve as a bridge 

to full compliance with the rule for 

cases where reporters faced reasonable 

impediments to compliance. The EPA 

never intended to extend BAMM 

requirements indefinitely. The proposed 

amendments are therefore in keeping 

with the EPA’s stated intent to 

transition to reporting without BAMM. 

We also believe, based on several years 

of experience with the industry and 

these reporting requirements, that 

facilities have successfully transitioned 

so that they either no longer need to use 

BAMM or will not need to use BAMM 

if these proposed revisions are finalized. 

In a review of BAMM request 

submittals for the 2014 reporting year, 

the EPA found that the sources with the 

most frequent BAMM requests included 

centrifugal compressors, reciprocating 

compressors, blowdown vent stacks, 

and combustion emissions, which are 

addressed in this rulemaking. The 

proposed revisions would also resolve 

the need for BAMM for certain facilities 

for which the final subpart W 

monitoring requirements were 

technically infeasible. For example, the 

most common concerns raised in 

BAMM requests associated with 

technical infeasibility included 

concerns related to having to shut down 

a facility to install access ports to 


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1 Direct emitter data categories that meet the 

definition of ‘‘emission data’’ in 40 CFR 2.301(a) are 

Facility and Unit Identifier Information, Emissions, 

Calculation Methodology and Methodological Tier, 

Data Elements Reported for Periods of Missing Data 

that are not Inputs to Emission Equations, and 

Inputs to Emission Equations. 

conduct compressor measurements. As 

discussed in Section II.B.10 of this 

preamble, we are making revisions that 

allow the testing of a common vent and 

that clarify that operators do not have to 

shut a facility down for the sole purpose 

to test a compressor in its non-operating 

mode, but that the measurement must 

be made at the next scheduled 

shutdown. 

In light of the extended time period in 

which the EPA has granted BAMM to 

allow facilities to come into compliance 

with subpart W requirements, the 

revisions that the EPA is proposing to 

make to the final rule, and the fact that 

all other industry-specific subparts in 

Part 98 no longer have continual 

BAMM, we expect that facilities would 

be in compliance with the monitoring 

and QA/QC methods required under 

subpart W for the 2015 calendar year. 

The EPA requests comment and 

strong technical evidence for sitespecific unique or unusual 

circumstances that would require the 

use of BAMM after January 1, 2015. 

These comments should include the 

details of how and why the special 

circumstances exist, why the data 

collection methods in subpart W 

(including those in this proposal) are 

not feasible, the data that could not be 

monitored in order to comply with 

subpart W, and how specifically the 

data could otherwise be collected. For 

further information on BAMM, see the 

TSD ‘‘Greenhouse Gas Reporting Rule: 

Technical Support for Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems; 

Proposed Rule’’ in Docket ID No. EPA– 

HQ–OAR–2011–0512. 

III. Proposed Confidentiality 

Determinations 

A. Overview and Background 

In this proposed rule we are 

proposing confidentiality 

determinations for new and subtantially 

revised reporting data elements in the 

proposed amendments, with certain 

exceptions as discussed in more detail 

below. These new and substantially 

revised data elements would result from 

the proposed corrections, clarifying, and 

other amendments that are described in 

Section II of this preamble, which 

would also result in substantial changes 

to the data elements that are reported. 

We are also proposing to revise the 

confidentiality determination for one 

existing data element that is not being 

amended, as discussed in Section III.B 

of this preamble. The final 

confidentiality determinations the EPA 

has previously made for the remainder 

of the subpart W data elements are 

unaffected by the proposed amendments 

and continue to apply. For information 

on confidentiality determinations for 

the GHGRP and subpart W data 

elements, see: 75 FR 39094, July 7, 2010; 

76 FR 30782, May 26, 2011; 77 FR 

48072, August 13, 2012; and 78 FR 

55994, September 11, 2013. These 

proposed confidentiality determinations 

would be finalized after considering 

public comment. The EPA plans to 

finalize these determinations at the 

same time the proposed rule 

amendments described in this action are 

finalized. 

B. Approach to Proposed CBI 

Determinations for New or Revised 

Subpart W Data Elements 

For the proposed new and 

substantially revised data elements, 

except for the specific data elements 

separately addressed below, we are 

applying the same approach as 

previously used for making 

confidentiality determinations for data 

elements reported under the GHGRP. In 

the ‘‘Confidentiality Determinations for 

Data Required Under the Mandatory 

Greenhouse Gas Reporting Rule and 

Amendments to Special Rules 

Governing Certain Information Obtained 

Under the Clean Air Act’’ (hereinafter 

referred to as ‘‘2011 Final CBI Rule’’) (76 

FR 30782, May 26, 2011), the EPA 

grouped Part 98 data elements into 22 

data categories (11 direct emitter data 

categories and 11 supplier data 

categories) with each of the 22 data 

categories containing data elements that 

are similar in type or characteristics. 

The EPA then made categorical 

confidentiality determinations for eight 

direct emitter data categories and eight 

supplier data categories and applied the 

categorical confidentiality 

determination to all data elements 

assigned to the category. Of these data 

categories with categorical 

determinations, the EPA determined 

that four direct emitter data categories 

are comprised of those data elements 

that meet the definition of ‘‘emissions 

data,’’ as defined at 40 CFR 2.301(a), 

and that, therefore, are not entitled to 

confidential treatment under section 

114(c) of the CAA.1 The EPA 

determined that the other four direct 

emitter data categories and the eight 

supplier data categories do not meet the 

definition of ‘‘emission data.’’ For these 

data categories that are determined not 

to be emission data, the EPA determined 

categorically that data in three direct 

emitter data categories and five supplier 

data categories are eligible for 

confidential treatment as CBI, and that 

the data in one direct emitter data 

category and three supplier data 

categories are ineligible for confidential 

treatment as CBI. For two direct emitter 

data categories, ‘‘Unit/Process ‘Static’ 

Characteristics that Are Not Inputs to 

Emission Equations’’ and ‘‘Unit/Process 

Operating Characteristics that Are Not 

Inputs to Emission Equations,’’ and 

three supplier data categories, ‘‘GHGs 

Reported,’’ ‘‘Production/Throughput 

Quantities and Composition,’’ and 

‘‘Unit/Process Operating 

Characteristics,’’ the EPA determined in 

the 2011 Final CBI Rule that the data 

elements assigned to those categories 

are not emission data, but the EPA did 

not make categorical CBI determinations 

for them. Rather, the EPA made CBI 

determinations for each individual data 

element included in those categories on 

a case-by-case basis taking into 

consideration the criteria in 40 CFR 

2.208. No final confidentiality 

determination was made for the inputs 

to emission equation data category (a 

direct emitter data category). 

For this rulemaking, we are proposing 

to assign 243 new or revised data 

elements to the appropriate direct 

emitter data categories created in the 

2011 Final CBI Rule based on the type 

and characteristics of each data element. 

Note that subpart W is a direct emitter 

source category, thus, no data are 

assigned to any supplier data categories. 

For data elements the EPA has 

assigned in this proposed action to a 

direct emitter category with a 

categorical determination, the EPA is 

proposing that the categorical 

determination for the category be 

applied to the proposed new or revised 

data element. For the proposed 

categorical assignment of the data 

elements in these eight categories with 

categorical determinations, see 

Memorandum Data Category 

Assignments and Confidentiality 

Determinations for all Data Elements 

(excluding inputs to emission 

equations) in the Proposed ‘‘Technical 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’’ in Docket ID No. 

EPA–HQ–OAR–2011–0512. 

For data elements assigned to the 

‘‘Unit/Process ‘Static’ Characteristics 

that Are Not Inputs to Emission 

Equations’’ and ‘‘Unit/Process Operating 

Characteristics that Are Not Inputs to 

Emission Equations,’’ we are proposing 

confidentiality determinations on a 

case-by-case basis taking into 


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2 In the 2011 Final CBI rule, several data 

categories include both CBI and non-CBI data 

elements. See 76 FR 30786. 

3See the ‘‘Change to the Reporting Date for 

Certain Data Elements Required Under the 

Mandatory Reporting of Greenhouse Gases Rule’’ 

(hereinafter referred to as the ‘‘Final Deferral 

Notice’’) (76 FR 53057, August 25, 2011) and the 

accompanying memorandum entitled ‘‘Process for 

Evaluating and Potentially Amending Part 98 Inputs 

to Emission Equations’’ (Docket ID EPA–HQ–OAR– 

2010–0929). 

4See the memoranda titled ‘‘Summary of Data 

Collected to Support Determination of Public 

Availability of Inputs to Emission Equations for 

which Reporting was Deferred to March 31, 2015’’ 

and ‘‘Evaluation of Competitive Harm from 

Disclosure of Inputs to Equations Data Elements 

Deferred to March 31, 2015.’’ (Docket ID EPA–HQ– 

OAR–2010–0929). 

consideration the criteria in 40 CFR 

2.208, consistent with the approach 

used for data elements previously 

assigned to these two data categories. 

For the proposed categorical assignment 

of these data elements, see 

Memorandum Data Category 

Assignments and Confidentiality 

Determinations for all Data Elements 

(excluding inputs to emission 

equations) in the Proposed ‘‘Technical 

Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’’ in Docket ID No. 

EPA–HQ–OAR–2011–0512. For the 

results of our case-by-case evaluation of 

these data elements, see Sections III.C 

and III.D of this preamble. 

For the reasons stated below, we are 

proposing individual confidentiality 

deteminations for 11 new or 

substantially revised data elements 

without making a data category 

assignment. In the 2011 Final CBI rule, 

although the EPA grouped similar data 

into categories and made categorical 

confidentiality determinations for a 

number of data categories, the EPA also 

recognized that similar data elements 

may not always have the same 

confidentiality status, in which case the 

EPA made individual instead of 

categorical determinations for the data 

elements within such data categories.2

Similarly, while the 11 proposed new or 

substantially revised data elements are 

similar in type or certain characteristics 

to data elements previously assigned to 

the ‘‘Production/Throughput Data Not 

Used as Input’’ and ‘‘Raw Materials 

Consumed that are Not Inputs to 

Emission Equations’’ data categories, we 

do not believe that they share the same 

confidentiality status as the non-subpart 

W data elements already assigned to 

those two data categories, which the 

EPA has determined categorically to be 

CBI based on the data elements assigned 

to those categories at the time of the 

2011 Final CBI Rule. As discussed in 

more detail below, our review showed 

that these 11 subpart W production and 

throughput-related data elements fail to 

qualify for confidential treatment. 

Therefore, we do not believe that the 

categorical determinations for the 

‘‘Production/Throughput Data Not Used 

as Input’’ and ‘‘Raw Materials 

Consumed that are Not Inputs to 

Emission Equations’’ data categories are 

appropriate for these 11 data elements; 

accordingly, these data elements should 

not be assigned to these data categories. 

Not assigning these 11 data elements to 

these two data categories would also 

leave unaffected the existing categorical 

determinations for these data categories, 

which remain valid and applicable to 

the data elements assigned to those data 

categories. For the reasons stated above, 

we are proposing individual 

confidentiality determinations for these 

11 data elements without making 

categorical assignment. 

Our proposed individual 

determinations follow the same twostep evaluation process as set forth in 

the 2011 Final CBI Rule and subsequent 

confidentiality determinations for Part 

98 data. Specifically, we first 

determined whether the data element 

meets the definition of emission data in 

40 CFR 2.301(a). Data elements that 

meet the definition of emission data are 

required to be released under section 

114 of the Clean Air Act. For data 

elements found to not meet the 

definition of emission data, we 

evaluated whether a data element meets 

the criteria in 40 CFR 2.208 for 

confidential treatment. In particular, we 

focus on: (1) Whether the data are 

already public; and (2) whether ‘‘. . . 

disclosure of the information is likely to 

cause substantial harm to the business’s 

competitive position.’’ For the results of 

our case-by-case evaluation of these 

proposed new subpart W data elements, 

see Section III.D of this preamble. 

We are also proposing to revise the 

confidentiality determinations for one 

existing subpart W data element. Our 

review of the 11 proposed data elements 

discussed above led us to re-examine 

our previous determination for this data 

element, which is similar in type or 

characteristics to the 11 proposed data 

elements for which the EPA is choosing 

to make case-by-case determinations. 

This one data element is the only 

subpart W data element currently 

assigned to ‘‘Production/Throughput 

Data Not Used as Input’’ data category. 

As discussed in more detail in Section 

III.D of this preamble, our review 

showed that this data element fails to 

qualify for confidential treatment. For 

the same reasons set forth above for not 

proposing categorical assignments for 

the 11 data elements, we are proposing 

to remove this data element’s current 

category assignment, as well as the 

application of the categorical CBI 

determination to this data element. 

Instead, we are re-proposing a 

confidentiality determination based on 

the two-step process discussed above for 

the proposed 11 new data elements. For 

the results of our case-by-case 

evaluation of the proposed subpart W 

data elements, see Section III.D of this 

preamble. 

We are proposing to assign 40 new or 

substantially revised data elements used 

to calculate GHG emissions in subpart 

W to the ‘‘Input to Emission Equation’’ 

data category. To date, the EPA has not 

made confidentiality determinations for 

any data element, including any subpart 

W data element, assigned to the ‘‘Inputs 

to Emission Equation’’ data category. 

We are therefore not proposing 

confidentiality determinations for the 40 

proposed new or substantially revised 

inputs to emission equations data 

elements. However, due to concerns 

expressed by reporters with the 

potential release of inputs to emission 

equations, we previously established a 

process for evaluating ‘‘inputs to 

emission equation’’ data elements to 

identify potential disclosure concerns 

and actions to address such concerns if 

appropriate.3 The EPA has used this 

process to evaluate inputs to emission 

equations, including the subpart W data 

elements that are already assigned to the 

inputs to emission equations data 

category.4 We performed a similar 

evaluation for the 40 proposed new and 

substantially revised subpart W inputs 

to emission equations and did not 

identify any potential disclosure 

concerns. Accordingly, the proposal 

would require reporting of these data 

elements by March 31, 2016, which is 

the reporting deadline for the 2015 

reporting year. For the list of new and 

revised subpart W inputs to emission 

equations and the results of our 

evaluation, see memorandum titled 

‘‘Review of Public Availability and 

Harm Evaluation for Proposed New 

Inputs to Emission Equations in the 

Proposed ‘Revisions and Confidentiality 

Determinations for Petroleum and 

Natural Gas Systems’ ’’ in Docket ID No. 

EPA–HQ–OAR–2011–0512. 

The proposed amendments include 

revisions a number of subpart W data 

reporting elements for which 

confidentiality determinations were 

previously finalized in the August 13, 

2012 ‘‘Final Confidentiality 

Determinations for Regulations Under 

the Mandatory Reporting of Greenhouse 

Gases Rule’’ (77 FR 48072). The 

proposed revisions relative to some of 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13407 

these data reporting elements would not 

require different or additional data to be 

reported under these data elements. The 

proposed revisions include a 

reorganization of the reporting 

requirements so that the data elements 

more close align with the calculation 

methodologies. This reorganization of 

the reporting section would result in 

changes to many of the rule citations for 

data elements. In addition to restructuring the reporting section, the 

EPA has proposed other minor revisions 

designed to clarify the existing reporting 

requirements. For example, some of the 

proposed changes would clarify the 

source type (e.g., natural gas pneumatic 

device venting, acid gas removal vents, 

etc.) and industry segment that is 

required to report the data element. The 

proposed revisions also include 

corrections of typographical and other 

clerical errors. These corrections would 

not change the data to be reported. 

Although the proposed revisions would 

separate the requirements into a larger 

number of discrete reporting elements 

and would clarify and correct 

typographical errors, they would not 

change the underlying data elements to 

be reported for many data elements. 

Therefore, the confidentiality 

determinations finalized in the August 

13, 2012 rule continue to apply. We are 

therefore not proposing revisions to the 

existing confidentially determinations 

for the data reporting elements that 

either would not require different or 

additional data to be reported under the 

proposed revisions or the proposed 

revisions would not change the 

underlying data elements to be reported. 

For a summary of the proposed 

reporting requirements for subpart W 

that incorporate these changes to data 

organization and descriptions, see the 

memo, ‘‘Proposed Revisions to the 

Subpart W Reporting Requirements’’ in 

Docket ID No. EPA–HQ–OAR–2011– 

0512. 

C. Proposed Confidentiality 

Determinations for Data Elements 

Assigned to the ‘‘Unit/Process ‘Static’ 

Characteristics That Are Not Inputs to 

Emission Equations’’ and ‘‘Unit/Process 

Operating Characteristics That Are Not 

Inputs to Emission Equations’’ Data 

Categories 

The EPA is proposing to assign 101 

proposed new or substantially revised 

data elements for subpart W to the 

‘‘Unit/Process ‘Operating’ 

Characteristics That Are Not Inputs to 

Emission Equations’’ data category or 

the ‘‘Unit/Process ‘Static’ Characteristics 

That Are Not Inputs to Emission 

Equations’’ data category, because the 

proposed new or substantially revised 

data elements share the same 

characteristics as the other data 

elements previously assigned to the 

category. We are proposing 

confidentiality determinations for these 

proposed new or substantially revised 

data elements based on the approach set 

forth in the 2011 Final CBI Rule for data 

elements assigned to these two data 

categories. In that rule, the EPA 

determined categorically that data 

elements assigned to these two data 

categories do not meet the definition of 

emission data in 40 CFR 2.301(a); the 

EPA then made individual, instead of 

categorical, confidentiality 

determinations for these data elements. 

As with all other data elements 

assigned to these two categories, the 

proposed new or substantially revised 

data elements do not meet the definition 

of emissions data in 40 CFR 2.301(a). 

The EPA then considered the 

confidentiality criteria at 40 CFR 2.208 

in making our proposed confidentiality 

determinations. Specifically, we focused 

on whether the data are already publicly 

available from other sources and, if not, 

whether disclosure of the data is likely 

to cause substantial harm to the 

business’ competitive position. Table 2 

of this preamble lists the data elements 

the EPA proposes to assign to the ‘‘Unit/ 

Process ‘Operating’ Characteristics That 

Are Not Inputs to Emission Equations’’ 

and ‘‘Unit/Process ‘Static’ 

Characteristics That Are Not Inputs to 

Emission Equations’’ data categories, the 

proposed confidentiality determination 

for each data element, and our rationale 

for each determination. 

TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT

ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS

TO EMISSION EQUATIONS’’ DATA CATEGORIES

Citation Data element Proposed confidentiality determination and rationale 

‘‘Unit/Process ‘Operating’ Characteristics That Are Not Inputs to Emission Equations’’ Data Category 

98.236(d)(1)(iv) ......................... Whether any CO2 emissions are recovered 

and transferred outside the facility.

This proposed data element would be reported by onshore 

petroleum and natural gas production facilities and by onshore natural gas processing plants. This data element indicates that a facility is operating an acid gas removal unit 

and indicates how the facility handles the CO2 emissions it 

generates. Acid gas removal units are used to remove carbon dioxide and hydrogen sulfide from raw natural gas 

streams and are commonly found at gas processing facilities. These units are listed in a facility’s construction and 

operating permits, which are publicly available. Because 

this information is routinely available through required permits, we propose these data elements be designated as 

‘‘not CBI.’’ 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13408 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT

ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS

TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued 

Citation Data element Proposed confidentiality determination and rationale 

98.236(e)(1)(xvii) .......................

98.236(e)(2)(i) ...........................

98.236(e)(2)(ii) ..........................

98.236(e)(2)(iii) ..........................

For each absorbent dehydrator, whether any 

dehydrator emissions are vented to the atmosphere without being routed to a flare or 

regenerator firebox.

For glycol dehydrators with an annual average 

daily natural gas throughput less than 0.4 

MMscfd, the total number of dehydrators at 

the facility. 

For glycol dehydrators with an annual average 

daily natural gas throughput less than 0.4 

MMscfd, the total number of dehydrators 

venting to a vapor recovery device. 

For glycol dehydrators with an annual average 

daily natural gas throughput less than 0.4 

MMscfd, the number of dehydrators venting 

to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes. 

These proposed data elements would be reported by onshore 

petroleum and natural gas production facilities and by onshore natural gas processing plants. These data elements 

indicate that a facility is equipped with dehydration units, 

the number of dehydrators used, the design of dehydrator 

used (glycol or desiccant), and how emissions from dehydration units are handled by the facility. Dehydration units 

are used to remove water from natural gas streams. Most 

natural gas processing facilities are equipped with these 

units and because they are a source of hazardous air pollutants, these units are subject to rigorous emissions control requirements (e.g., 40 CFR part 63, subpart HH). Dehydration units and their associated control devices are listed in a facility’s construction and operating permits, which 

are publicly available. For this reason, we propose these 

data elements be designated as ‘‘not CBI’’ for both onshore 

production and natural gas processing plants. 

98.236(e)(2)(iv) ......................... For glycol dehydrators with an annual average 

daily natural gas throughput less than 0.4 

MMscfd, whether any glycol dehydrator 

emissions are vented to a flare or regenerator firebox/fire tubes.

98.236(e)(2)(iv)(A) ..................... For glycol dehydrators with an annual average 

daily natural gas throughput less than 0.4 

MMscfd and vented to a flare or regenerator firebox, the total number of 

dehydrators.

98.236(e)(3)(i) ........................... For dehydrators that use desiccant, the total 

number of dehydrators at the facility.

98.236(e)(3)(i) ........................... For dehydrators that use desiccant, whether 

any dehydrator emissions are vented to a 

vapor recovery device.

98.236(e)(3)(i) ........................... For dehydrators that use desiccant, the total 

number of dehydrators venting to a vapor 

recovery device.

98.236(e)(3)(i) ........................... For dehydrators that use desiccant, whether 

any dehydrator emissions are vented to a 

control device other than a vapor recovery 

device or a flare or regenerator firebox/fire 

tubes, and the control device type.

98.236(e)(3)(i) ........................... For dehydrators that use desiccant, whether 

any dehydrator emissions are vented to a 

control device other than a vapor recovery 

device or a flare or regenerator firebox/fire 

tubes.

98.236(e)(3)(i) ........................... For dehydrators that use desiccant, the number of dehydrators venting to a control device other than a vapor recovery device or 

a flare or regenerator firebox/fire tubes.

98.236(e)(3)(i) ........................... For dehydrators that use desiccant, whether 

any glycol dehydrator emissions are vented 

to a flare or regenerator firebox/fire tubes.

98.236(e)(3)(i) ........................... For dehydrators that use desiccant and vent 

to a flare or regenerator firebox, the total 

number of dehydrators.


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13409 

TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT

ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS

TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued 

Citation Data element Proposed confidentiality determination and rationale 

98.236(f) ....................................

98.236(f)(1)(iv) ..........................

Liquids unloading. You must indicate whether 

well venting for liquids unloading occurs at 

your facility.

For each Sub-basin and well tubing diameter 

and pressure group for which you used Calculation Method 1 (reported separately for 

wells with plunger lifts and wells without 

plunger lifts), the count of wells vented to 

the atmosphere for this grouping. 

These proposed data element would be reported by onshore 

petroleum and natural gas production facilities. Liquid unloading is conducted in mature gas wells that have an accumulation of liquids which impede the steady flow of natural gas. This is a common occurrence in reservoirs where 

the pressure is depleted and liquids enter the well bore. 

The fact that liquids unloading occurs and the number of 

unloading wells with and without plungers vented to the atmosphere indicate that the wells in a basin are older and 

may indicate changes in production rates. However, the 

age and production rates for wells are information that can 

be derived from or are already available to the public 

through state oil and gas commissions. Hence, this information is routinely publicly available, so we propose these 

data elements be designated as ‘‘not CBI.’’ 

98.236(g) ...................................

98.236(g)(3) ..............................

Whether the facility had any gas well completions or workovers with hydraulic fracturing 

in the calendar year.

For each completion or workover and well 

type combination, the total number of completions or workovers. 

These proposed data elements would be reported by onshore 

petroleum and natural gas production facilities and provide 

information on whether the facility conducted any well completions or workovers during the reporting year, and for 

those facilities that had well completions and/or workovers, 

the number of completions and workovers that were completed. Information on the number of completions and 

workovers performed by an oil and gas operator in a given 

year and the age and production rates for wells can be derived from or is available publicly on state oil and gas commission Web sites. Because disclosure of these data elements would not be likely to cause substantial competitive 

harm, we propose these data elements be designated as 

‘‘not CBI.’’ 

98.236(h)(1) .............................. You must indicate whether the facility had any 

gas well completions without hydraulic fracturing or any gas well workovers without hydraulic fracturing, and if the activities occurred with or without flaring.

This proposed data element would be reported by onshore 

petroleum and natural gas production facilities and provides 

information on whether the facility conducted any well completions or workovers during the reporting year and whether the emissions were flared. Information on completions 

and workovers performed in a given year and the age and 

production rates for wells can be derived from or is available publicly on state oil and gas commission Web sites 

and from the Energy Information Administration (EIA). 

Whether the emissions from well completions and 

workovers are sent to a flare provides only information 

about how the emissions are handled by the facility, which 

is not considered to be sensitive information by the industry. Because disclosure of these data elements would not 

be likely to cause substantial competitive harm, we propose 

these data elements be designated as ‘‘not CBI.’’ 

98.236(h)(1)(ii) ..........................

98.236(h)(2)(ii) ..........................

For each sub-basin with gas well completions 

without hydraulic fracturing and without flaring, the number of completions that vented 

gas to the atmosphere.

For each sub-basin with gas well completions 

without hydraulic fracturing with flaring, the 

number of well completions that flared gas. 

These proposed data elements would be reported by onshore 

petroleum and natural gas production facilities and provide 

information on the number of completions where gas is 

vented to the atmosphere and the number of completions 

where the gas is vented to a flare. The number of completions that vent gas directly to the atmosphere and the number of completions that send the gas to a flare provides 

only information about the number of well completions that 

were performed in a sub-basin during a reporting year and 

how the emissions are handled by the facility. The number 

of completions performed each year is available publicly on 

state oil and gas commission Web sites and from the EIA. 

Thus, disclosure of these data elements would not be likely 

to cause substantial competitive harm and we propose 

these data elements be designated as ‘‘not CBI.’’ 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13410 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT

ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS

TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued 

Citation Data element Proposed confidentiality determination and rationale 

98.236(h)(1)(iv) ......................... Average daily gas production rate for all completions without hydraulic fracturing in the 

sub-basin without flaring, in standard cubic 

feet per hour (average of all ‘‘Vp’’ as used 

in Equation W–13B).

This proposed data element would be reported by onshore 

petroleum and natural gas production facilities. This data 

element potentially provides information about the productivity of wells where hydraulic fracturing is not conducted 

and the emissions are not flared. Because production data 

for individual production wells are publicly available, the average daily production for all wells in a basin presents no 

information that is not already publicly available. Because 

disclosure of this data element would not be likely to cause 

substantial competitive harm, we propose this data element 

be designated as ‘‘not CBI.’’ 

98.236(h)(2)(iii) .......................... Total number of hours that gas vented to a 

flare during backflow for all completions in 

the sub-basin category (sum of all ‘‘Tp’’ for 

completions that vented to a flare as used 

in Equation W–13B).

This proposed data element would be reported by onshore 

petroleum and natural gas production facilities and potentially provides information on the time spent on well completions. Information specific to exploratory wells is generally considered proprietary information by the industry. 

However, by reporting this data as the total for all completed wells in a sub-basin category, data for individual 

wells would not be disclosed because of the large number 

of wells per sub-basin category. Because disclosure of this 

data element would not be likely to cause substantial competitive harm, we propose this data element be designated 

as ‘‘not CBI.’’ 

98.236(h)(2)(iv) ......................... Average daily gas production rate for all completions without hydraulic fracturing in the 

sub-basin with flaring, in standard cubic feet 

per hour (the average of all ‘‘Vp’’ from 

Equation W–13B).

This proposed data element would be reported by onshore 

petroleum and natural gas production facilities. This data 

element potentially provides information about the productivity of wells where hydraulic fracturing is not conducted 

and the emissions are flared. Because production data for 

individual production wells are publicly available, the average daily production for all wells in a basin presents no information that is not already publicly available. Because 

disclosure of this data element would not be likely to cause 

substantial competitive harm, we propose this data element 

be designated as ‘‘not CBI.’’ 

98.236(i)(1)(i) ............................ Total number of blowdowns in the calendar 

year for the equipment type (sum equation 

variable ‘‘N’’ from Equation W–14A or 

Equation W–14B of this subpart for all 

unique physical volumes for the equipment 

type).

This proposed data element would be reported by the onshore petroleum and natural gas production, onshore natural gas processing, onshore natural gas transmission 

compression, and LNG import and export facilities. 

Blowdowns occur when equipment is taken out of service, 

either to be placed on standby or for maintenance purposes, and the natural gas in the equipment is typically released to the atmosphere. This practice may occur as part 

of a routine scheduled maintenance or as the result of an 

un-planned event (e.g., equipment breakdown). Although 

blowdown events may be associated with periods of reduced production or throughput, natural gas processing 

plants and LNG import/export facilities typically have 

backup units that can be used to avoid production shutdowns. Hence, the number of blowdown events that occur 

during a reporting year does not indicate a plant was shut 

down and would not provide any potentially sensitive information on the impact of such events on a facility’s production or throughput. Hence, the disclosure of the number of 

blowdowns occurring during a reporting year is not likely to 

cause substantial competitive harm. For this reason, we 

propose that this data element be designated ‘‘not CBI’’ 

when reported by onshore natural gas processing plants 

and LNG import/export facilities. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13411 

TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT

ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS

TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued 

Citation Data element Proposed confidentiality determination and rationale 

These proposed data elements would also be reported by the 

natural gas transmission compression sector. Companies 

operating in this sector are subject to regulatory oversight 

by the Federal Energy Regulatory Commission (FERC), 

state utility commissions, and other federal agencies because they operate in an industry that is inherently uncompetitive. FERC controls pricing, sets rules for business 

practices, has the power to impose conditions on mergers 

and acquisitions, and has the sole responsibility for authorizing the location, construction and operations of companies operating in this sector. The rate charged for transporting gas is regulated. Hence the tightly regulated natural 

gas transmission sector is inherently less competitive than 

other industries. Because disclosure of the number of 

blowdowns occurring during a reporting year would not be 

likely to cause substantive competitive harm, we propose 

this data element be designated as ‘‘not CBI’’ when reported by the natural gas transmission sector. 

98.236(j) .................................... You must indicate whether your facility sends 

produced oil to atmospheric tanks.

This proposed data element would be reported by onshore 

petroleum and natural gas production facilities and indicates only that a facility is equipped with atmospheric storage tanks. Atmospheric storage tanks are used to store hydrocarbon liquids from separators or production wells. Atmospheric tanks are a typical part of onshore production 

facilities and are listed in each facility’s construction and 

operating permits, which have to be reissued when modifications are made to the facility. Hence, disclosure of this 

data element would not be likely to cause substantial competitive harm and we propose that this data element be 

designated as ‘‘not CBI.’’ 

98.236(j) ....................................

98.236(j)(3)(ii) ............................

If any of the atmospheric tanks are observed 

to have malfunctioning dump valves, indicate that dump valves were malfunctioning.

If any of the gas-liquid separator liquid dump 

valves did not close properly during the reporting year, the total time, in hours, the 

dump valves on gas-liquid separators did 

not close properly (‘‘Tn’’ in equation W–16). 

These proposed data elements would be reported by onshore 

petroleum and natural gas production facilities and provide 

information on malfunctioning of dump valves on gas-liquid 

separators. Separators are used to separate hydrocarbons 

into liquid and gas phases and are typically connected to 

atmospheric storage tanks where the hydrocarbon liquids 

are stored. Dump valves on separators periodically release 

liquids from the separator. The time period during which a 

dump valve is malfunctioning provides little insight into 

maintenance practices or the nature or cost of repairs that 

are needed. Therefore, this information would not be likely 

to cause substantial competitive harm to reporters. For this 

reason, we are proposing these data elements be designated as ‘‘not CBI.’’ 

98.236(k)(1)(iii) ..........................

98.236(k)(1)(iv) ..........................

For each transmission storage tank vent 

stack, indicate whether scrubber dump 

valve leakage is occurring for the underground storage vent.

For each transmission storage tank vent 

stack, indicate if there is a flare attached to 

the vent stack. 

These proposed data elements would be reported by the onshore natural gas transmission compression sector. Companies operating in this sector are subject to regulatory 

oversight by FERC, state utility commissions, and other 

federal agencies because they operate in an industry that 

is inherently uncompetitive. FERC controls pricing, sets 

rules for business practices, has the power to impose conditions on mergers and acquisitions, and has the sole responsibility for authorizing the location, construction and 

operations of companies operating in this sector. The rate 

charged for transporting gas is regulated. Hence the natural gas transmission sector is inherently less competitive 

than other industries and there is little incentive to build additional pipelines and compressor stations within the same 

corridors as existing transmission lines. Because disclosure 

of these data elements would not be likely to cause substantive competitive harm, we propose these data elements 

be designated as ‘‘not CBI.’’ 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13412 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT

ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS

TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued 

Citation Data element Proposed confidentiality determination and rationale 

98.236(l)(1)(iv) ...........................

98.236(l)(2)(iv) ...........................

98.236(l)(3)(iii) ...........................

If oil well testing is performed where emissions are not vented to a flare, the average 

flow rate in barrels of oil per day for well(s) 

tested.

If oil well testing is performed where emissions are vented to a flare, the average flow 

rate in barrels of oil per day for well(s) tested. 

If gas well testing is performed where emissions are not vented to a flare, the average 

annual production rate in actual cubic feet 

per day for well(s) tested. 

This proposed data element would be reported by onshore 

petroleum and natural gas production facilities. These data 

elements provide information on the oil flow and gas production rates of wells. Oil and gas production data for individual wells are publicly available. Because production data 

for individual production wells are publicly available, the average of all wells tested presents no information that is not 

already publicly available. Because disclosure of these data 

elements would not be likely to cause substantial competitive harm, we propose these data elements be designated 

as ‘‘not CBI.’’ 

98.236(l)(4)(iii) ........................... If gas well testing is performed where emissions are vented to a flare, the average annual production rate in actual cubic feet per 

day for well(s) tested.

98.236(m) ..................................

98.236(m)(2) .............................

98.236(m)(3) .............................

You must indicate whether any associated 

gas was vented or flared during the reporting year.

For each sub-basin, indicate whether any associated gas was vented without flaring. 

For each sub-basin, indicate whether any associated gas was flared. 

These proposed data elements would be reported by onshore 

petroleum and natural gas production facilities and indicate 

whether associated gas is flared or vented directly to the 

atmosphere. Information on how emissions are handled 

does not provide any insight into the operation of the emission source. Therefore, disclosure of these data elements 

would be unlikely to cause competitive harm. For this reason, we are proposing these data elements be designated 

as ‘‘not CBI.’’ 

98.236(m)(5) .............................

98.236(m)(6) .............................

For each sub-basin, the volume of oil produced during time periods in which associated gas was vented or flared (barrels).

For each sub-basin, the total volume of associated gas sent to sales during time periods 

in which associated gas was vented or 

flared (scf). 

These proposed data elements would be reported by onshore 

petroleum and natural gas production facilities and provide 

production related information during periods when associated gas is vented or flared. Associated gas is vented or 

flared when it is not being captured for sales. Oil and gas 

production data for individual production wells are publicly 

available, By reporting this data as total for all production 

wells in a sub-basin category, no data for individual wells is 

disclosed that is not already publicly available. Because 

disclosure of these data elements would not be likely to 

cause substantial competitive harm, we propose they be 

designated as ‘‘not CBI.’’ 

98.236(o)(1)(xvi) ........................

98.236(o)(2)(viii) ........................

Date of last maintenance shutdown that the 

compressor was depressurized.

If the emission vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device 

was operational. 

These proposed data elements would be reported by onshore 

petroleum and natural gas production facilities, onshore 

natural gas processing plants, LNG import/export terminals, 

natural gas transmission compression, underground natural 

gas storage facilities, and LNG storage facilities. These 

data elements provide information about the operation and 

maintenance of centrifugal compressors. Centrifugal compressors are used to move gas at high pressure through 

pipelines and are standard equipment found at all types of 

natural gas facilities. Facilities typically have backup compressors to allow operations to continue without interruption 

during periods of maintenance and repair. Hence, the percentage of time a compressor was operational and the date 

of last maintenance shutdown would be not likely to cause 

substantial competitive harm to any type of natural gas facility. For these reasons, we propose these data elements 

be designated as ‘‘not CBI.’’ 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13413 

TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT

ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS

TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued 

Citation Data element Proposed confidentiality determination and rationale 

98.236(p)(1)(xvi) ........................

98.236(p)(2)(viii) ........................

Date of last maintenance shutdown for rod 

packing replacement.

If the emission vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device 

was operational. 

These proposed data elements would be reported by onshore 

petroleum and natural gas production facilities, onshore 

natural gas processing plants, LNG import/export terminals, 

natural gas transmission compression, underground natural 

gas storage facilities, and LNG storage facilities. These 

data elements provide information about the operation and 

maintenance of reciprocating compressors. Reciprocating 

compressors are used to move gas at high pressure 

through pipelines and are standard equipment found at all 

types of natural gas facilities. Facilities typically have 

backup compressors to allow operations to continue without interruption during periods of compressor maintenance 

and repair. Hence, the percentage of time a compressor is 

operational and date of last maintenance shutdown would 

be not likely to cause substantial competitive harm to any 

type of natural gas facility. For these reasons, we propose 

these data elements be designated as ‘‘not CBI.’’ 

98.236(q)(2)(iii) .......................... Average time the surveyed components were 

found leaking and operational, in hours (average of Tp,z in Equation W–30 of this subpart).

This proposed data element would provide information on the 

amount of time operational components were found to be 

leaking. This information would provide little insight into 

maintenance practices at a facility because it would not 

identify the cause of the leaks or the nature and cost of repairs. Therefore, this information would not be likely to 

cause substantial competitive harm to reporters. For this 

reason, we are proposing the average time operational 

components were found leaking be designated as ‘‘not 

CBI.’’ 

98.236(q)(3)(ii) ..........................

98.236(q)(3)(iii) ..........................

98.236(q)(3)(v) ..........................

98.236(q)(3)(vi) .........................

Number of meter/regulator runs at above 

grade transmission-distribution transfer stations surveyed in the calendar year.

Average time that meter/regulator runs surveyed in the calendar year were operational, in hours (average of Tw,y in Equation W–31 of this subpart, for the current 

calendar year). 

Number of meter/regulator runs at above 

grade transmission-distribution transfer stations surveyed in current leak survey cycle. 

Average time that meter/regulator runs surveyed in the current leak survey cycle were 

operational, in hours. 

These proposed data elements would be reported by natural 

gas distribution facilities. Natural gas distribution companies 

are subject to regulatory oversight by state utility commissions because they operate in an industry that is inherently 

not competitive. The state utility commission controls pricing, sets rules for business practices, has the power to impose conditions on mergers and acquisitions, and has the 

sole responsibility for authorizing the location, construction 

and operations of companies operating in this sector. Because disclosure of these data elements would not be likely 

to cause substantive competitive harm, we propose these 

data elements be designated as ‘‘not CBI’’ when reported 

by natural gas distributors. 

98.236(w) .................................. Whether CO2 enhanced oil recovery (EOR) injection was used at the facility.This proposed data element would be reported by onshore 

petroleum and natural gas production facilities. This data 

element indicates whether EOR is performed. However, underground injection of CO2 is regulated under 40 CFR parts 

124, 144 and 146. Facilities that inject CO2 underground 

are required to have an Underground Injection Control 

(UIC) permit, which is a public document issued by the 

EPA or by states that have primary enforcement authority 

for permitting injection wells. Since this information is already available through other public documents, we propose this data be designated as ‘‘not CBI.’’ 

98.236(w) .................................. You must indicate whether any EOR injection 

pump blowdowns occurred during the year.

This proposed data element would be reported by the onshore petroleum and natural gas production facilities using 

EOR. Blowdowns are a typical operation undertaken by 

EOR operators and occur when equipment is taken out of 

service either to be placed on standby or for maintenance 

purposes. This practice may occur as part of a routine 

scheduled maintenance or be the result of an un-planned 

event (e.g., equipment breakdown). Although blowdown 

events may be associated with periods of reduced production, facilities typically have backup pumps that can be 

used to avoid production shutdowns. Hence, the disclosure 

of the number of blowdowns occurring during a reporting 

year is not likely to cause substantial competitive harm. For 

this reason, we propose that this data element be designated ‘‘not CBI.’’ 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13414 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT

ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS

TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued 

Citation Data element Proposed confidentiality determination and rationale 

98.236(x) ................................... Whether hydrocarbon liquids were produced 

through EOR operations.

This proposed data element would be reported by onshore 

petroleum and natural gas production facilities using EOR 

and provides production related information about EOR operations. However, production data for wells is available to 

the public through state oil and gas commissions. Since 

this information is already available through other public 

documents, we propose this data be designated as ‘‘not 

CBI.’’ 

98.236(z)(2)(i) ........................... The type of combustion unit ............................ This data element would be reported by onshore petroleum 

and gas production facilities and natural gas distribution. 

This data element would provide information on the types 

of combustion units. Information on the types of combustion units located at a facility is often available in a facility’s 

construction and operating permits. For these reasons, we 

consider information on the types of combustion units in 

production and distribution facilities would not be likely to 

cause substantive competitive harm and propose this data 

element be designated as ‘‘not CBI’’ for both industry sectors. 

98.236(z)(2)(ii) ........................... Type of fuel combusted ................................... This data element would be reported by onshore petroleum 

and gas production facilities and natural gas distribution. 

This data element would provide information on the types 

of fuel burned. However, facilities in both these sectors 

generally burn fuels that are readily available to them as 

part of their operations. Information on the types of fuels 

burned by a facility is often available in a facility’s construction and operating permits. For these reasons, we consider 

information on the types of fuels burned by production and 

distribution facilities would not be likely to cause substantive competitive harm and propose this data element 

be designated as ‘‘not CBI’’ for both industry sectors. 

98.236(aa)(1)(ii)(I) .....................

98.236(aa)(1)(ii)(J) ....................

For each sub-basin category, the average 

mole fraction CH4 in produced gas.

For each sub-basin category, the average 

mole fraction CO2 in produced gas. 

This proposed data element would be reported by onshore 

petroleum and natural gas production facilities. The typical 

composition of produced gas is available through the Gas 

Technology Institute and the Department of Energy, Gas 

Information System (GASIS) Database.5 Both of these 

sources are made available to the public. Since these data 

are publicly available we are proposing these data elements be designated as ‘‘not CBI.’’ 

98.236(aa)(4)(i) .........................

98.236(aa)(4)(iv) .......................

98.236(aa)(4)(v) ........................

The quantity of gas transported through the 

compressor station in the calendar year, in 

thousand standard cubic feet.

The average upstream pipeline pressure in 

pounds per square inch gauge. 

The average downstream pipeline pressure in 

pounds per square inch gauge. 

These proposed data elements would be reported by the onshore natural gas transmission compression sector. Companies operating in this sector are subject to regulatory 

oversight by FERC, state utility commissions, and other 

federal agencies because they operate in an industry that 

is inherently uncompetitive. FERC controls pricing, sets 

rules for business practices, has the power to impose conditions on mergers and acquisitions, and has the sole responsibility for authorizing the location, construction and 

operations of companies operating in this sector. The rate 

charged for transporting gas is regulated. Hence the natural gas transmission sector is inherently less competitive 

than other industries and there is little incentive to build additional pipelines and compressor stations within the same 

corridors as existing transmission lines. Because disclosure 

of pipeline pressures and the quantity of gas transported 

through the compressor would not be likely to cause substantive competitive harm, we propose these data elements 

be designated as ‘‘not CBI.’’ 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13415 

TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT

ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS

TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued 

Citation Data element Proposed confidentiality determination and rationale 

98.236(aa)(5)(i) .........................

98.236(aa)(5)(ii) ........................

The quantity of gas injected into storage in 

the calendar year, in thousand standard 

cubic feet.

The quantity of gas withdrawn from storage in 

the calendar year, in thousand standard 

cubic feet. 

These proposed data elements would be reported by underground natural gas storage facilities. Underground storage 

facilities are closely associated with and are part of the utilities’ integrated distribution systems. Some are owned by 

natural gas distribution companies. Distribution companies 

are regulated by state commissions, because they operate 

in an industry that is inherently not competitive. Underground storage facilities are constrained by geographical 

and geological requirements. These facilities must be located in areas where appropriate geologic conditions exist 

for gas storage, while also located near regions of the 

country where gas usage fluctuates during the year. Typically, gas is injected into underground storage during the 

summer months, when consumer demand is low, and withdrawn during the winter months, when demand peaks. 

These factors provide significant barriers to new companies 

moving into the underground storage sector or existing 

companies increasing their market share. Because disclosure of these proposed new data elements would not be 

likely to cause substantive competitive harm to underground storage facilities, we propose these data elements 

be designated as ‘‘not CBI.’’ 

98.236(aa)(6) ............................ For LNG import equipment, the quantity of 

LNG imported in the calendar year, in thousand standard cubic feet.

Quantities of LNG imported to the U.S. together with the 

name of the importer are published by EIA in quarterly reports. Because disclosure of this proposed new data element would not be likely to cause substantive competitive 

harm, we propose this data element be designated as ‘‘not 

CBI.’’ 

98.236(aa)(7) ............................ For LNG export equipment, the quantity of 

LNG exported in the calendar year, in thousand standard cubic feet.

Quantities of natural gas exported from the U.S. are published by EIA in quarterly reports. Because disclosure of 

this proposed new data element would not be likely to 

cause substantive competitive harm, we propose this data 

element be designated as ‘‘not CBI.’’ 

98.236(aa)(8)(i) .........................

98.236(aa)(8)(ii) ........................

The quantity of LNG added into storage in the 

calendar year, in thousand standard cubic 

feet.

The quantity of LNG withdrawn from storage 

in the calendar year, in thousand standard 

cubic feet. 

These proposed data elements would be reported by LNG 

storage facilities. Most LNG storage facilities are owned by 

distributors whose operations are regulated by FERC and 

state commissions, because they operate in an industry 

that is inherently not competitive. FERC controls pricing, 

sets rules for business practices, has the power to impose 

conditions on mergers and acquisitions, and has the sole 

responsibility for authorizing the location, construction and 

operations of companies operating in this sector. Because 

disclosure of these proposed new data elements would not 

be likely to cause substantive competitive harm, we propose these data elements be designated as ‘‘not CBI.’’ 

98.236(aa)(9)(i) .........................

98.236(aa)(9)(ii) ........................

98.236(aa)(9)(iii) ........................

98.236(aa)(9)(iv) .......................

The quantity of natural gas received at all 

custody transfer stations in the calendar 

year in thousand standard cubic feet.

The quantity of natural gas withdrawn from insystem storage in the calendar year in thousand cubic feet. 

The quantity of natural gas added to in-system storage in the calendar year in thousand cubic feet. 

The quantity of natural gas delivered to end 

users in thousand cubic feet. This value 

does not include stolen gas, or gas that is 

otherwise unaccounted for 

Natural gas distribution companies are subject to regulatory 

oversight by state utility commissions, because they operate in an industry that is inherently not competitive. Many 

of these data elements are also reported to EIA on a 

monthly basis (e.g., natural gas withdrawn from storage, 

natural gas stored, gas received at city gate). EIA publishes the data on their Web site on an annual basis. Because disclosure of these proposed new data elements 

would not be likely to cause substantive competitive harm, 

we propose these data elements be designated as ‘‘not 

CBI.’’ 

98.236(aa)(9)(v) ........................ The quantity of natural gas transferred to third 

parties such as other LDCs or pipelines in 

thousand cubic feet. This value does not include stolen gas, or gas that is otherwise 

unaccounted for.

98.236(aa)(9)(vi) ....................... The quantity of natural gas consumed by the 

LDC for operational purposes in thousand 

cubic feet.

98.236(aa)(9)(vii) ....................... The estimated quantity of gas stolen in the 

calendar year in thousand cubic feet.


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13416 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT

ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS

TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued 

Citation Data element Proposed confidentiality determination and rationale 

‘‘Unit/Process ‘Static’ Characteristics That Are Not Inputs to Emission Equations’’ Data Category 

98.236(o)(1)(iv) operating mode 

(v) not operating mode.

98.236(o)(1)(vii) .........................

98.236(o)(1)(viii) ........................

98.236(o)(1)(ix) .........................

98.236(o)(1)(x) ..........................

98.236(o)(1)(xi) .........................

98.236(o)(1)(xiii) ........................

98.236(o)(1)(xiv) ........................

98.236(o)(1)(xv) ........................

For non-manifolded compressors, whether the 

compressor was measured in the operatingmode or the not-operating-depressurized– 

mode.

Indicate whether any compressor sources are 

routed to a flare. 

Indicate whether any compressor sources 

have vapor recovery. 

Indicate whether emissions from any compressor sources are captured for fuel use or 

are routed to a thermal oxidizer. 

Indicate whether the compressor has blind 

flanges installed. 

Indicate whether the compressor has wet or 

dry seals. 

Compressor power rating (hp). 

Year compressor was installed. 

Compressor model name and description. 

These proposed data elements would be reported by onshore 

petroleum and natural gas production facilities, onshore 

natural gas processing plants, LNG import/export terminals, 

natural gas transmission compression, underground natural 

gas storage facilities, and LNG storage facilities. These 

data elements indicate whether a facility has centrifugal 

compressors, how emissions from each unit are handled, 

and specific information about the design and age of each 

centrifugal compressor. Centrifugal compressors are used 

to move gas at high pressure through pipelines and are 

standard equipment found at all types of natural gas facilities. Centrifugal compressors are also listed in each facility’s construction and operating permits, which must be updated and reissued when modifications are made. Hence, 

the fact that a facility has a centrifugal compressor, its age 

and design, and emissions handling reveals no sensitive information that would be likely to cause substantial competitive harm to any type of natural gas facility. For these reasons, we propose these data elements be designated as 

‘‘not CBI.’’ 

98.236(p)(1)(viii) ........................

98.236(p)(1)(ix) .........................

98.236(p)(1)(x) ..........................

98.236(p)(1)(xi) .........................

98.236(p)(1)(xii) .........................

98.236(p)(1)(xiii) ........................

98.236(p)(1)(xiv) ........................

98.236(p)(1)(xv) ........................

Indicate whether any compressor sources are 

part of a manifolded group of compressor 

sources.

Indicate whether any compressor sources are 

routed to a flare. 

Indicate whether any compressor sources 

have vapor recovery. 

Indicate whether emissions from any compressor sources are captured for fuel use or 

are routed to a thermal oxidizer. 

Indicate whether the compressor has blind 

flanges installed. 

Compressor power rating (hp). 

Year compressor was installed. 

Compressor model name and description. 

These proposed data elements would be reported by onshore 

petroleum and natural gas production facilities, onshore 

natural gas processing plants, LNG import/export terminals, 

natural gas transmission compression, underground natural 

gas storage facilities, and LNG storage facilities. These 

data elements indicate whether a facility has reciprocating 

compressors, how emissions from each unit are handled, 

and specific information about the design and age of each 

reciprocating compressor. Reciprocating compressors are 

used to move gas at high pressure through pipelines and 

are standard equipment found at all types of natural gas facilities. Reciprocating compressors are also listed in each 

facility’s construction and operating permit, which must be 

updated and reissued when modifications are made. Because disclosure of these data elements would be not likely 

to cause substantial competitive harm to any type of natural gas facility, we propose these data elements be designated as ‘‘not CBI.’’ 

98.236(z)(1)(ii) ........................... The total number of combustion units ............. This data element would be reported by onshore petroleum 

and gas production facilities and natural gas distribution. 

This data element provides information on the number of internal and external combustion units located at onshore petroleum and natural gas production facilities. However, this 

information would not be likely to cause substantial competitive harm if released to the public, since internal and 

external combustion units are typical parts of an onshore 

petroleum and natural gas production facility and the total 

number of such units is not considered to be competitively 

sensitive information by this industry sector. Because disclosure of the number of combustion units would not be 

likely to cause substantive competitive harm to this sector, 

we propose this data element be designated as ‘‘not CBI’’ 

when reported by onshore petroleum and natural gas production facilities. 

Natural gas distribution companies are subject to regulatory 

oversight by state utility commissions, because they operate in an industry that is inherently not competitive. Because disclosure of the number combustion units would not 

be likely to cause substantive competitive harm, we propose this data element be designated as ‘‘not CBI’’ when 

reported by natural gas distributors. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13417 

TABLE 2—PROPOSED NEW DATA ELEMENTS ASSIGNED TO THE ‘‘UNIT/PROCESS ‘OPERATING’ CHARACTERISTICS THAT

ARE NOT INPUTS TO EMISSION EQUATIONS’’ AND ‘‘UNIT/PROCESS ‘STATIC’ CHARACTERISTICS THAT ARE NOT INPUTS

TO EMISSION EQUATIONS’’ DATA CATEGORIES—Continued 

Citation Data element Proposed confidentiality determination and rationale 

98.236(aa)(1)(ii)(C) ................... For each sub-basin category, the formation 

type.

The formation type refers to the following types of formations: 

Oil, high permeability gas, shale gas, coal seam, or other 

tight gas reservoir rock. The location of these formations is 

general information that is publicly available from EIA. Because disclosure of the formation would not be likely to 

cause substantive competitive harm, we propose this data 

element be designated as ‘‘not CBI.’’ 

98.236(aa)(1)(ii)(D) ...................

98.236(aa)(1)(ii)(E) ....................

98.236(aa)(1)(ii)(F) ....................

98.236(aa)(1)(ii)(G) ...................

98.236(aa)(1)(ii)(H) ...................

For each sub-basin category, the number of 

producing wells at the end of the calendar 

year.

For each sub-basin category, the number of 

producing wells acquired during the calendar year. 

For each sub-basin category, the number of 

producing wells divested during the calendar year. 

For each sub-basin category, the number of 

wells completed during the calendar year. 

For each sub-basin category, the number of 

wells taken out of production during the calendar year. 

We are proposing that each of these proposed new data elements be assigned to the Unit/Process Static Characteristics That Are Not Inputs to Emission Equations’’ because 

each data element provides descriptive information about 

units at the facility and does not meet the definition of 

emission data. We propose that each new data element be 

designated as ‘‘not CBI’’ because detailed information regarding wells is available from state databases and permits. Because disclosure of the formation would not be 

likely to cause substantive competitive harm, we propose 

this data element be designated as ‘‘not CBI.’’ 

98.236(aa)(3)(vii) ....................... Whether the onshore natural gas processing 

facility fractionates natural gas liquids 

(NGLs).

Whether a natural gas processing facility fractionates NGLs is 

information that is readily available from other public 

sources, such as the LPG Almanac (updated annually) and 

other trade journals. For this reason, disclosure of this information would not be likely to cause substantial competitive harm and we propose that this data element be designated as ‘‘not CBI.’’ 

98.236(aa)(4)(ii) ........................

98.236(aa)(4)(iii) ........................

Number of compressors ...................................

The total compressor power rating for all compressors combined, in horsepower. 

These data elements would be reported by the onshore natural gas transmission compression sector. Companies operating in this sector are subject to regulatory oversight by 

FERC, state utility commissions, and other federal agencies because they operate in an industry that is inherently 

uncompetitive. FERC controls pricing, sets rules for business practices, has the power to impose conditions on 

mergers and acquisitions, and has the sole responsibility 

for authorizing the location, construction and operations of 

companies operating in this sector. Because disclosure of 

the number and power rating for compressors would not be 

likely to cause substantive competitive harm, we propose 

these data elements be designated as ‘‘not CBI.’’ 

98.236(aa)(5)(iii) ........................ The total storage capacity for underground 

natural gas storage facilities.

Companies operating underground gas storage facilities are 

required to report their storage capacity to the EIA by company on a monthly basis. EIA publishes the data on their 

Web site on an annual basis. Because disclosure of underground storage capacity would not be likely to cause substantial competitive harm, we propose these data elements 

be designated as ‘‘not CBI.’’ 

98.236(aa)(8)(iii) ........................ The total LNG storage capacity in the calendar year, in thousand standard cubic feet.Most LNG storage facilities are regulated by FERC and state 

commissions, because they operate in an industry that is 

inherently not competitive. FERC controls pricing, sets 

rules for business practices, has the power to impose conditions on mergers and acquisitions, and has the sole responsibility for authorizing the location, construction and 

operations of companies operating in this sector. Because 

disclosure of LNG storage capacity would not be likely to 

cause substantial competitive harm, we propose these data 

elements be designated as ‘‘not CBI.’’ 

D. Other Proposed or Re-Proposed Caseby-Case Confidentiality Determinations 

for Subpart W 

The proposed revision includes 11 

new or substantially revised data 

elements relative to production and/or 

throughput data from subpart W 

facilities from the onshore petroleum 

and natural gas production, offshore 

petroleum and natural gas production, 

and onshore natural gas processing 

industry sectors. Although these data 

elements are similar in certain types or 

characteristics to the data elements in 

‘‘Production/Throughput Data that are 

Not Inputs to Emissions Equations’’ or 

‘‘Raw Materials Consumed that are Not 

Inputs to Emissions Equations’’ data 

categories, for the reasons provided 

above in Section III.B of this preamble, 

we are not proposing to assign these 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13418 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

data elements to a data category. 

Instead, we are proceeding to make 

individual confidentiality 

determinations for these data elements. 

As further explained in Section III.B of 

this preamble, we are also proposing to 

remove one existing data element, 40 

CFR 98.236(j)(2)(i)(A), from 

‘‘Production/Throughput Data Not Used 

as Input,’’ thereby removing the 

application of the categorical 

confidentiality determination for this 

data category to this data element. We 

are re-proposing the confidentiality 

determination for this data element. 

Table 3 of this preamble lists the 11 new 

or substantially revised data elements 

and one existing data element and 

provides the rationale and proposed 

confidentiality determination for each 

data element. 

As described above in Section III.B of 

this preamble, our proposed 

determinations for these data elements 

were based on a two-step process in 

which we first evaluated whether the 

data element met the definition of 

emission data. This first step in the 

evaluation is important because 

emission data are not eligible for 

confidential treatment pursuant to 

section 114(c) of the CAA, which 

precludes emissions data from being 

considered confidential and requires 

that such data be made available to the 

public. The term ‘‘emission data’’ is 

defined in 40 CFR 2.301(a). 

We propose to determine that none of 

these 12 data elements are emission data 

under 40 CFR 2.301(a)(2)(i), because 

they do not provide any information 

characterizing actual GHG emissions or 

descriptive information about the 

location or nature of the emissions 

source. However, we note that this 

determination is made strictly in the 

context of the GHGRP and may not 

apply to other regulatory programs. 

In the second step, we evaluate 

whether the data element is entitled to 

confidentiality treatment, based on the 

criteria for confidential treatment 

specified in 40 CFR 2.208. In particular, 

the EPA focused on the following two 

factors: (1) Whether the data was 

already publicly available; and (2) 

whether ‘‘ . . . disclosure of the 

information is likely to cause significant 

harm to the business’ competitive 

position.’’ See 40 CFR 2.208(e)(1). For 

each of these 12 data elements, we 

determined whether the information is 

already available in the public domain. 

For those data elements for which no 

published data could be found, we 

evaluated whether the publication 

would be likely to cause competitive 

harm. Many of the new data elements 

proposed to be reported by the onshore 

oil and gas production sector would be 

reported at an aggregated-level (i.e., subbasin level) that would mask any 

underlying information for individual 

production wells. These data elements 

involve reporting aggregated data 

covering all individual wells, 

exploratory wells, and production 

equipment in a sub-basin, rather than 

information specific to an individual 

well or other production unit. Reporting 

at a sub-basin level is at a large enough 

scale that disclosure of the collected 

data would not reveal any proprietary 

information, such as the sensitive 

operational information or the cost to do 

business. Because the proposed new 

data elements would also be collected at 

a sub-basin level, they would not 

disclose production data for individual 

wells, reveal information about 

individual exploratory wells, or provide 

insight into production costs. Therefore, 

we propose that the new production 

data proposed to be reported by the 

onshore oil and gas production sector be 

designated as non-CBI because its 

disclosure would not be likely to cause 

competitive harm. 

For offshore oil and gas production, 

the EPA is proposing that the quantity 

of gas produced for sales, quantity of oil 

produced for sales, and quantity of 

condensate produced for sales be 

reported. These data elements do not 

provide any competitively sensitive 

information on the costs of doing 

business. We note that similar data on 

throughputs for individual platforms are 

published annually by the Bureau of 

Ocean Energy Management. Therefore, 

we propose that these new production 

data proposed to be reported by offshore 

oil and gas platforms be designated as 

non-CBI because its disclosure would 

not be likely to cause competitive harm. 

For natural gas processing, the EPA is 

proposing that the total quantity of 

NGLs (bulk and fractionated) received at 

and leaving the processing plant be 

reported on an annual basis. Because 

the reported value would be the annual 

sum of bulk and fractionated NGLs 

received and the annual sum of bulk 

and fractionated NGLs leaving the plant, 

the data collected would provide very 

limited information on facility 

operations and would not disclose any 

detailed information about the facility’s 

day-to-day operations, such as the 

amount, contents, and price of each 

shipment of bulk material received, the 

amount, contents, and price of each 

shipment of NGL product received, the 

amount of bulk materials fractionated 

and costs of fractionation, or the type 

and amounts of each individual NGL 

product produced. Because these data 

are to be reported at an aggregated level, 

these proposed two new data elements 

would not provide insight on operating 

costs, or other highly sensitive aspects 

of operation the disclosure of which 

would be likely to cause competitive 

harm. Therefore, we propose that the 

total quantity of NGLs (bulk and 

fractionated) received at and leaving the 

natural gas processing plant be 

designated as not CBI. In addition, many 

facilities in this sector already 

voluntarily report these data to the 

Worldwide Gas Processing survey and 

the data at the plant level are published 

annually in the Oil and Gas Journal. 

Similar data are also mandatorily 

reported monthly to the EIA. Although 

the EIA aggregates the data before 

publishing data, the EIA also 

acknowledges that some statistics may 

be based on data from fewer than three 

respondents, or that are dominated by 

data from one or two large respondents, 

and in these cases, it may be possible for 

a the information reported by a specific 

respondent to be accurately estimated. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13419 

TABLE 3—PROPOSED INDIVIDUAL CONFIDENTIALITY DETERMINATION FOR 13 NEW OR SUBSTANTIALLY REVISED DATA

ELEMENTS AND RE-PROPOSAL FOR ONE EXISTING DATA ELEMENTS

Citation Data element Proposed confidentiality determination and rationale 

Onshore petroleum and natural gas production 

98.236(aa)(1)(i)(A) ....................

98.236(aa)(1)(i)(B) ....................

98.236(aa)(1)(i)(C) ....................

98.236(aa)(1)(i)(D) ....................

98.236(j)(2)(i)(A) ........................

The quantity of gas produced in the calendar 

year from wells, in thousand standard cubic 

feet. This includes gas that is routed to a 

pipeline, vented or flared, or used in field 

operations. This does not include gas injected back into reservoirs or shrinkage resulting from lease condensate production.

The quantity of gas produced in the calendar 

year for sales in thousand standard cubic 

feet. 

For each basin, the quantity of crude oil produced in the calendar year for sales, not including lease condensates, in barrels. 

For each basin, the quantity of lease condensate produced in the calendar year for sales 

(in barrels). 

The total annual oil throughput that is sent to 

all atmospheric tanks in the basin, in barrels. 

We propose that each of these data elements be designated 

as ‘‘not CBI.’’ The onshore petroleum production sector is a 

regionally concentrated sector, with wells located in fixed 

geological formations and a large number of operators 

within each formation. Information that is typically considered sensitive to this industry includes data related to production costs for developed fields and information on individual exploratory wells. Information on exploratory wells is 

sensitive during the time period when a new formation is 

being developed because lease prices are not stabilized 

until wells have proven production records. Once the formation has been developed and several wells have been 

drilled in a basin, production decisions are based on market prices and the ability to control flow from the well. The 

production data that will be reported at the basin or subbasin level are already publicly available through the Department of Energy. Reporting at the basin or sub-basin 

level includes data aggregated to a scale large enough that 

it does not disclose production data for individual wells, reveal sensitive information about individual exploratory wells, 

or provide insight into production costs. 

Offshore petroleum and natural gas production 

98.236(aa)(2)(i) .........................

98.236(aa)(2)(ii) ........................

The quantity of gas produced for sales from 

the offshore platform in the calendar year 

for sales, in thousand standard cubic feet.

The quantity of oil produced for sales from the 

offshore platform in the calendar year for 

sales (in barrels). 

We propose that each of these new data elements be designated as ‘‘not CBI’’ because the production throughput 

data are published annually on the Bureau of Ocean Energy Management’s Web site. 

98.236(aa)(2)(iii) ........................ The quantity of condensate produced for 

sales from the offshore platform in the calendar year for sales (in barrels).

Onshore natural gas processing 

98.236(aa)(3)(i) .........................

98.236(aa)(3)(ii) ........................

The quantity of produced gas received at the 

gas processing plant in thousand standard 

cubic feet.

The quantity of processed (residue) gas leaving the gas processing plant in thousand 

standard cubic feet. 

We propose that each of these new data elements be designated as ‘‘not CBI’’ because the average annual flow and 

plant utilization rates are published quarterly on EIA’s Web 

site and are already in the public domain. 

98.236(aa)(3)(iii) ........................

98.236(aa)(3)(iv) .......................

The quantity of NGLs (bulk and fractionated) 

received at the gas processing plant in the 

calendar year, in barrels.

The quantity of NGLs (bulk and fractionated) 

leaving the gas processing plant in the calendar year, in barrels. 

We propose that each of these new data elements be designated as ‘‘not CBI’’ because they are already publicly 

available. Many facilities in this sector already voluntarily 

report these data to the Worldwide Gas Processing survey 

and the data at the plant level are published annually in the 

Oil and Gas Journal. Similar data are also mandatorily reported monthly to the EIA. Although the EIA aggregates the 

data before publishing data, the EIA also acknowledges 

that, ‘‘Disclosure limitation procedures are not applied to 

the statistical data published from this survey’s information. 

Thus, there may be some statistics that are based on data 

from fewer than three respondents, or that are dominated 

by data from one or two large respondents. In these cases, 

it may be possible for a knowledgeable person to estimate 

the information reported by a specific respondent.’’ 6

The list of data elements, their data 

category assignments, and proposed 

confidentiality determinations can be 

found in the memorandum titled ‘‘Data 

Category Assignments and 

Confidentiality Determinations for all 

Data Elements (excluding inputs to 

emission equations) in the Proposed 

‘Technical Revisions and 

Confidentiality Determinations for 

Petroleum and Natural Gas Systems’’’ in 

Docket ID No. EPA–HQ–OAR–2011– 

0512. 

E. Request for Comments on Proposed 

Confidentiality Determinations 

For the CBI component of this 

rulemaking, we are specifically 

soliciting comment on the following 

issues. First, we specifically seek 

comment on the proposed data category 


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assignments, and application of the 

established categorical confidentiality 

determinations to data elements 

assigned to categories with such 

determinations. If a commenter believes 

that the EPA has improperly assigned 

certain new or substantially revised data 

elements to any of the data categories 

established in the 2011 Final CBI Rule, 

please provide specific comments 

identifying which of these data elements 

may be mis-assigned along with a 

detailed explanation of why you believe 

them to be incorrectly assigned and in 

which data category you believe they 

belong. In addition, if you believe that 

a data element should be assigned to 

one of the two direct emitter data 

categories that do not have a categorical 

confidentiality determination, please 

also provide specific comment along 

with detailed rationale and supporting 

information on whether such data 

element does or does not qualify as CBI. 

We also seek comment on the 

proposed individual confidentiality 

determinations for the following data 

elements: 72 new or substantially 

revised data elements assigned to the 

‘‘Unit/Process ‘Operating’ 

Characteristics That Are Not Inputs to 

Emission Equations’’ data category; 29 

new or substantially revised data 

elements assigned to the ‘‘Unit/Process 

‘Static’ Characteristics That Are Not 

Inputs to Emission Equations’’ category; 

11 new data elements for which no data 

category assignment was proposed; and 

one existing data element for which we 

are proposing to remove the data 

category assignment and make a new 

confidentiality determination. 

By proposing confidentiality 

determinations prior to data reporting 

through this proposal and rulemaking 

process, we provide reporters an 

opportunity to submit comments, in 

particular comments identifying data 

they consider sensitive and their 

rationales and supporting 

documentation; this opportunity is the 

same opportunity that is afforded to 

submitters of information in case-bycase confidentiality determinations 

made in response to individual claims 

for confidential treatment not made 

through rulemaking. It provides an 

opportunity to rebut the Agency’s 

proposed determinations prior to 

finalization. We will evaluate the 

comments on our proposed 

determinations, including claims of 

confidentiality and information 

substantiating such claims, before 

finalizing the confidentiality 

determinations. Please note that this 

will be a reporter’s only opportunity to 

substantiate a confidentiality claim for 

these proposed new data elements. 

Upon finalizing the confidentiality 

determinations of the data elements 

identified in this rule, the EPA will 

release or withhold these data in 

accordance with 40 CFR 2.301, which 

contains special provisions governing 

the treatment of Part 98 data for which 

confidentiality determinations have 

been made through rulemaking. 

When submitting comments regarding 

the confidentiality determinations we 

are proposing in this action, please 

identify each individual data element 

you do or do not consider to be CBI or 

emission data in your comments. Please 

explain specifically how the public 

release of that particular data element 

would or would not cause a competitive 

disadvantage to a facility. Discuss how 

this data element may be different from 

or similar to data that are already 

publicly available. Please submit 

information identifying any publicly 

available sources of information 

containing the specific data elements in 

question. Data that are already available 

through other sources would likely be 

found not to qualify for CBI protection. 

In your comments, please identify the 

manner and location in which each 

specific data element you identify is 

publicly available, including a citation. 

If the data are physically published, 

such as in a book, industry trade 

publication, or federal agency 

publication, provide the title, volume 

number (if applicable), author(s), 

publisher, publication date, and 

International Standard Book Number 

(ISBN) or other identifier. For data 

published on a Web site, provide the 

address of the Web site and the date you 

last visited the Web site and identify the 

Web site publisher and content author. 

If your concern is that competitors 

could use a particular data element to 

discern sensitive information, 

specifically describe the pathway by 

which this could occur and explain how 

the discerned information would 

negatively affect your competitive 

position. Describe any unique process or 

aspect of your facility that would be 

revealed if the particular data element 

you consider sensitive were made 

publicly available. If the data element 

you identify would cause harm only 

when used in combination with other 

publicly available data, then describe 

the other data, identify the public 

source(s) of these data, and explain how 

the combination of data could be used 

to cause competitive harm. Describe the 

measures currently taken to keep the 

data confidential. Avoid conclusory and 

unsubstantiated statements, or general 

assertions regarding potential harm. 

Please be as specific as possible in your 

comments and include all information 

necessary for the EPA to evaluate your 

comments. 

IV. Impacts of the Proposed 

Amendments to Subpart W 

The proposed amendments to subpart 

W are based on identified improvements 

in the regulatory language and revisions 

to calculation methods that do not 

significantly increase the burden of data 

collection and reporting, improve the 

accuracy of the data reported, and 

provide clarity. The proposed 

amendments do not impart significant 

additional burden to reporters and many 

reduce burden to reporters and 

regulators in some cases. 

As discussed in Section II of this 

preamble, the EPA is proposing to revise 

the reporting elements that must be 

reported. Any elements that were not 

previously required to be reported 

identify the equipment to be reported 

for the industry segment or are inputs to 

an emission equation. These data 

elements are typically already collected 

by reporters. These proposed revisions 

would remove ambiguity for the 

reporter and would not increase burden 

significantly, since the reporting 

elements are already available. 

As discussed in Section II.D of this 

preamble, the EPA is proposing to 

remove the best available monitoring 

method (BAMM) provisions in 40 CFR 

98.234(f). Removing these provisions 

would not add to previous burden 

estimates for subpart W reporters; 

previous burden estimates were 

prepared based on all reporters 

complying with the monitoring methods 

in 40 CFR 98.234 without BAMM. 

The additional proposed amendments 

to subpart W are not expected to 

significantly increase burden. See the 

memorandum, ‘‘Assessment of Impacts 

of the 2014 Proposed Revisions to 

Subpart W’’ in Docket Id. No. EPA–HQ– 

OAR–2011–0512 for additional 

information. 

V. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). 

In addition, the EPA prepared an 

analysis of the potential costs and 

benefits associated with the proposed 

amendments to subpart W. This analysis 


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is contained in ‘‘Assessment of Impacts 

of the 2014 Proposed Revisions to 

Subpart W.’’ A copy of the analysis is 

available in the docket for this action 

(see Docket Id. No. EPA–HQ–OAR– 

2011–0512) and the analysis is briefly 

summarized in Section IV of this 

preamble. 

B. Paperwork Reduction Act 

The information collection 

requirements in this proposed rule have 

been submitted for approval to the 

Office of Management and Budget 

(OMB) under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. The 

Information Collection Request (ICR) 

document prepared by the EPA has been 

assigned EPA ICR number 2300.15. 

This action proposes to simplify the 

existing reporting methods in subpart W 

and clarify monitoring methods and 

data reporting requirements, and 

proposes confidentiality determinations 

for reported data elements. The EPA is 

proposing to restructure the reporting 

requirements for clarity and align them 

with the calculation requirements. OMB 

has previously approved the 

information collection requirements for 

40 CFR part 98 under the provisions of 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq., and has assigned OMB 

control number 2060–0629. The OMB 

control numbers for the EPA’s 

regulations in 40 CFR are listed in 40 

CFR part 9. 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. 

The estimated total projected cost and 

hour burden associated with reporting 

for subpart W are $21,964,000 and 

244,000 hours, respectively. For the 

hour burden, the estimated average 

burden hours per response is 54 hours, 

the proposed frequency of response is 

once annually, and the estimated 

number of likely respondents is 2,885. 

For the cost burden to respondents or 

record keepers resulting from the 

collection of information, the estimated 

total capital and start-up cost 

component annualized over its expected 

useful life is $796,000 per year, the total 

operation and maintenance component 

is $1,690,000 per year, and the total 

labor cost is $19,478,000 per year for all 

of subpart W. 

To comment on the Agency’s need for 

this information, the accuracy of the 

provided burden estimates, and any 

suggested methods for minimizing 

respondent burden, the EPA has 

established a public docket for this rule, 

which includes this ICR, under Docket 

ID number EPA–HQ–OAR–2011–0512. 

Submit any comments related to the ICR 

to the EPA and OMB. See ADDRESSES 

section at the beginning of this proposed 

rule for where to submit comments to 

the EPA. Send comments to OMB at the 

Office of Information and Regulatory 

Affairs, Office of Management and 

Budget, 725 17th Street NW., 

Washington, DC 20503, Attention: Desk 

Office for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

March 10, 2014, a comment to OMB is 

best assured of having its full effect if 

OMB receives it by April 9, 2014. The 

final rule will respond to any OMB or 

public comments on the information 

collection requirements contained in 

this proposal. We continue to be 

interested in the potential impacts of 

this proposed action on the burden 

associated with the proposed 

amendments and welcome comments 

on issues related to such impacts. 

C. Regulatory Flexibility Act (RFA) 

The Regulatory Flexibility Act (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 today’s proposed rule on small 

entities, small entity is defined as: (1) A 

small business as defined by the Small 

Business Administration’s regulations at 

13 CFR 121.201; (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. 

This action proposes to (1) amend 

monitoring and calculation 

methodologies in subpart W; (2) assign 

subpart W data reporting elements into 

CBI data categories; and (3) amend a 

definition in subpart A. After 

considering the economic impacts of 

these proposed rule amendments on 

small entities, I certify that this action 

would not have a significant economic 

impact on a substantial number of small 

entities. 

The small entities directly regulated 

by this proposed rule include small 

businesses in the petroleum and gas 

industry, small governmental 

jurisdictions and small non-profits. The 

EPA has determined that some small 

businesses would be affected because 

their production processes emit GHGs 

exceeding the reporting threshold. 

This action includes proposed 

amendments that do not result in a 

significant burden increase on subpart 

W reporters. In some cases, the EPA is 

proposing to increase flexibility in the 

selection of methods used for 

calculating GHGs, and is also proposing 

to revise certain methods that may 

result in greater conformance to current 

industry practices. In addition, the EPA 

is proposing to revise specific 

provisions to provide clarity on what 

information is being reported. These 

proposed revisions would not 

significantly increase the burden on 

reporters while maintaining the data 

quality of the information being 

reported to the EPA. 

As part of the process of finalization 

of the final subpart W rule, the EPA took 

several steps to evaluate the effect of the 

rule on small entities. For example, the 

EPA determined appropriate thresholds 

that reduced the number of small 

businesses reporting. In addition, the 

EPA conducted several meetings with 

industry associations to discuss 

regulatory options and the 

corresponding burden on industry, such 

as recordkeeping and reporting. Finally, 

the EPA continues to conduct 

significant outreach on the GHG 

reporting rule and maintains an ‘‘open 

door’’ policy for stakeholders to help 

inform the EPA’s understanding of key 

issues for the industries. 

The EPA continues to be interested in 

the potential impacts of the proposed 

rule amendments on small entities and 

welcomes comments on issues related to 

such impacts. 

D. Unfunded Mandates Reform Act 

(UMRA) 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), 2 U.S.C. 

1531–1538, requires federal agencies, 

unless otherwise prohibited by law, to 

assess the effects of their regulatory 

actions on state, local, and tribal 

governments and the private sector. 

Federal agencies must also develop a 

plan to provide notice to small 

governments that might be significantly 

or uniquely affected by any regulatory 

requirements. The plan must enable 

officials of affected small governments 

to have meaningful and timely input in 

the development of the EPA regulatory 

proposals with significant federal 


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intergovernmental mandates and must 

inform, educate, and advise small 

governments on compliance with the 

regulatory requirements. 

This action proposes to (1) amend 

monitoring and calculation 

methodologies in subpart W; (2) assign 

subpart W data reporting elements into 

CBI data categories; and (3) amend a 

definition in subpart A. This proposed 

rule does not contain a federal mandate 

that may result in expenditures of $100 

million or more for state, local, and 

tribal governments, in the aggregate, or 

the private sector in any one year. Thus, 

this proposed rule is not subject to the 

requirements of section 202 and 205 of 

the UMRA. This rule is also not subject 

to the requirements of section 203 of 

UMRA because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. The 

proposed amendments would not 

impose any new requirements that are 

not currently required for 40 CFR part 

98, and the rule amendments would not 

uniquely apply to small governments. 

Therefore, this action is not subject to 

the requirements of section 203 of the 

UMRA. 

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, as specified in 

Executive Order 13132. However, for a 

more detailed discussion about how 

Part 98 relates to existing state 

programs, please see Section II of the 

preamble to the final Part 98 rule (74 FR 

56266, October 30, 2009). 

This action proposes to (1) amend 

monitoring and calculation 

methodologies in subpart W; (2) assign 

subpart W data reporting elements into 

CBI data categories; and (3) amend a 

definition in subpart A. Few, if any, 

state or local government facilities 

would be affected by the provisions in 

this proposed rule. This regulation also 

does not limit the power of States or 

localities to collect GHG data and/or 

regulate GHG emissions. Thus, 

Executive Order 13132 does not apply 

to this action. 

In the spirit of Executive Order 13132, 

and consistent with the EPA policy to 

promote communications between the 

EPA and state and local governments, 

the EPA specifically solicits comment 

on this proposed action from state and 

local officials. For a summary of the 

EPA’s consultation with state and local 

organizations and representatives in 

developing Part 98, see Section VIII.E of 

the preamble to the final rule (74 FR 

56371, October 30, 2009). 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Subject to the Executive Order 13175 

(65 FR 67249, November 9, 2000) the 

EPA may not issue a regulation that has 

tribal implications, that imposes 

substantial direct compliance costs, and 

that is not required by statute, unless 

the federal government provides the 

funds necessary to pay the direct 

compliance costs incurred by tribal 

governments, or the EPA consults with 

tribal officials early in the process of 

developing the proposed regulation and 

develops a tribal summary impact 

statement. 

The EPA has concluded that this 

action may have tribal implications. 

This action proposes to (1) Amend 

monitoring and calculation 

methodologies in subpart W; (2) assign 

subpart W data reporting elements into 

CBI data categories; and (3) amend a 

definition in subpart A. However, it will 

neither impose substantial direct 

compliance costs on tribal governments, 

nor preempt Tribal law. This regulation 

would apply directly to petroleum and 

natural gas facilities that emit 

greenhouses gases. Although few 

facilities that would be subject to the 

rule are likely to be owned by tribal 

governments, the EPA has sought 

opportunities to provide information to 

tribal governments and representatives 

during the development of the proposed 

and final subpart W that was 

promulgated on November 30, 2010 (75 

FR 74458). The EPA consulted with 

tribal officials early in the process of 

developing subpart W to permit them to 

have meaningful and timely input into 

its development. 

For additional information about the 

EPA’s interactions with tribal 

governments, see section IV.F of the 

preamble to the re-proposal of subpart 

W published on April 12, 2010 (75 FR 

18608), and section IV.F of the preamble 

to the final subpart W published on 

November 30, 2010 (75 FR 74458). 

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 

The EPA interprets Executive Order 

13045 (62 FR 19885, April 23, 1997) as 

applying only to those regulatory 

actions that concern health or safety 

risks, such that the analysis required 

under section 5–501 of the Executive 

Order has the potential to influence the 

regulation. This action proposes to (1) 

Amend monitoring and calculation 

methodologies in subpart W; (2) assign 

subpart W data reporting elements into 

CBI data categories; and (3) amend a 

definition in subpart A. This action is 

not subject to Executive Order 13045 

because it does not establish an 

environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action proposes to (1) amend 

monitoring and calculation 

methodologies in subpart W; (2) assign 

subpart W data reporting elements into 

CBI data categories; and (3) amend a 

definition in subpart A. This action is 

not subject to Executive Order 13211 (66 

FR 28355 (May 22, 2001)), because it is 

not a significant regulatory action under 

Executive Order 12866. 

I. National Technology Transfer and 

Advancement Act 

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 in 

its regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. NTTAA directs EPA 

to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

This action proposes to (1) Amend 

monitoring and calculation 

methodologies in subpart W; (2) assign 

subpart W data reporting elements into 

CBI data categories; and (3) amend a 

definition in subpart A. This proposed 

rulemaking does not involve the use of 

any technical standards. No changes are 

being proposed that affect the test 

methods currently in use for subpart W. 

Therefore, the EPA is not considering 

the use of any voluntary consensus 

standards. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

(February 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 


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practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

This action proposes to (1) amend 

monitoring and calculation 

methodologies in subpart W; (2) assign 

subpart W data reporting elements into 

CBI data categories; and (3) amend a 

definition in subpart A. The EPA has 

determined that this proposed rule will 

not have disproportionately high and 

adverse human health or environmental 

effects on minority or low-income 

populations because it does not affect 

the level of protection provided to 

human health or the environment. 

Instead, this proposed rule addresses 

information collection and reporting 

procedures. 

List of Subjects in 40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Incorporation by 

reference, Reporting and recordkeeping 

requirements. 

Dated: February 20, 2014. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, of the Code 

of Federal Regulations is proposed to be 

amended as follows: 

PART 98—MANDATORY 

GREENHOUSE GAS REPORTING 

■ 1. The authority citation for part 98 

continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[AMENDED] 

■ 2. Section 98.6 is amended by revising 

the definition of ‘‘Well completions’’ to 

read as follows: 

§ 98.6 Definitions. 

* * * * * 

Well completions means the process 

that allows for the flow of petroleum or 

natural gas from newly drilled wells to 

expel drilling and reservoir fluids and 

test the reservoir flow characteristics, 

steps which may vent produced gas to 

the atmosphere via an open pit or tank. 

Well completion also involves 

connecting the well bore to the 

reservoir, which may include treating 

the formation or installing tubing, 

packer(s), or lifting equipment, steps 

that do not significantly vent natural gas 

to the atmosphere. This process may 

also include high-rate flowback of 

injected gas, water, oil, and proppant 

used to fracture and prop open new 

fractures in existing lower permeability 

gas reservoirs, steps that may vent large 

quantities of produced gas to the 

atmosphere. 

* * * * * 

Subpart W—[AMENDED] 

■ 3. Section 98.230 is amended by 

revising paragraph (a)(2) to read as 

follows: 

§ 98.230 Definition of the source category. 

(a) * * * 

(2) Onshore petroleum and natural 

gas production. Onshore petroleum and 

natural gas production means all 

equipment on a single well-pad or 

associated with a single well-pad 

(including but not limited to 

compressors, generators, dehydrators, 

storage vessels, engines, boilers, heaters, 

flares, separation and processing 

equipment, and portable non-selfpropelled equipment, which includes 

well drilling and completion 

equipment, workover equipment, 

maintenance and repair equipment, and 

leased, rented or contracted equipment) 

used in the production, extraction, 

recovery, lifting, stabilization, 

separation or treating of petroleum and/ 

or natural gas (including condensate). 

This equipment also includes associated 

storage or measurement vessels all 

petroleum and natural gas production 

equipment located on islands, artificial 

islands, or structures connected by a 

causeway to land, an island, or an 

artificial island. Onshore petroleum and 

natural gas production also means all 

equipment on or associated with a 

single enhanced oil recovery (EOR) well 

pad using CO2 or natural gas injection. 

* * * * * 

■ 4. Section 98.232 is amended by: 

■ a. Revising paragraph (c)(11); 

■ b. Revising paragraph (d)(1); 

■ c. Revising paragraph (e)(1); 

■ d. Adding paragraph (e)(6); 

■ e. Revising paragraph (f)(1); 

■ f. Adding paragraph (f)(4); 

■ g. Revising paragraph (g)(1); 

■ h. Adding paragraph (g)(4); 

■ i. Revising paragraph (h)(1); 

■ j. Adding paragraph (h)(5); and 

■ k. Revising paragraphs (i)(1) through 

(i)(7). 

The revisions and additions read as 

follows: 

§ 98.232 GHGs to report. 

* * * * * 

(c) * * * 

(11) Reciprocating compressor 

venting. 

* * * * * 

(d) * * * 

(1) Reciprocating compressor venting. 

* * * * * 

(e) * * * 

(1) Reciprocating compressor venting. 

* * * * * 

(6) Flare stack emissions. 

(f) * * * 

(1) Reciprocating compressor venting. 

* * * * * 

(4) Flare stack emissions. 

* * * * * 

(g) * * * 

(1) Reciprocating compressor venting. 

* * * * * 

(4) Flare stack emissions. 

(h) * * * 

(1) Reciprocating compressor venting. 

* * * * * 

(5) Flare stack emissions. 

(i) * * * 

(1) Equipment leaks from connectors, 

block valves, control valves, pressure 

relief valves, orifice meters, regulators, 

and open-ended lines at above grade 

transmission-distribution transfer 

stations. 

(2) Equipment leaks at below grade 

transmission-distribution transfer 

stations. 

(3) Equipment leaks at above grade 

metering-regulating stations that are not 

above grade transmission-distribution 

transfer stations. 

(4) Equipment leaks at below grade 

metering-regulating stations. 

(5) Distribution main equipment 

leaks. 

(6) Distribution services equipment 

leaks. 

(7) Report under subpart W of this 

part the emissions of CO2, CH4, and N2O 

emissions from stationary fuel 

combustion sources following the 

methods in § 98.233(z). 

* * * * * 

■ 5. Section 98.233 is amended by: 

■ a. Revising paragraphs (a) 

introductory text, (a)(1), and (a)(2); 

■ b. Adding paragraph (a)(4); 

■ c. Revising paragraphs (c), (d), (e), (f), 

(g), (h), and (i); 

■ d. Revising paragraphs (j) introductory 

text, (j)(1) introductory text, (j)(1)(vii) 

introductory text, and (j)(2); 

■ e. Removing paragraphs (j)(3) and 

(j)(4). 

■ f. Redesignating paragraph (j)(5) as 

paragraph (j)(3) and revising newly 

redesignated paragraph (j)(3); 

■ g. Redesignating paragraph (j)(6) as 

paragraph (j)(4) and revising newly 

redesignated paragraph (j)(4); 

■ h. Redesignating paragraph (j)(7) as 

paragraph (j)(5) and revising newly 

redesignated paragraph (j)(5); 

■ i. Redesignating paragraph (j)(8) as 

paragraph (j)(6) and revising newly 

redesignated paragraph (j)(6); 


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13424 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

■ j. Redesignating paragraph (j)(9) as 

paragraph (j)(7) and revising newly 

redesignated paragraph (j)(7); 

■ k. Revising paragraph (k); 

■ l. Revising paragraphs (l) introductory 

text, (l)(2) introductory text, and 

(l)(2)(ii); 

■ m. Revising paragraphs (l)(3) 

introductory text and the parameters 

‘‘FR’’ and ‘‘D’’ of Equation W–17B in 

paragraph (l)(3); 

■ n. Revising paragraphs (l)(5) and (l)(6); 

■ o. Revising paragraphs (m), (n), (o), 

(p), (q), and (r); 

■ p. Revising paragraphs (s)(2) 

introductory text, (s)(2)(i), (s)(3), (s)(4), 

and (t) introductory text. 

■ q. Revising Equation W–33 of 

paragraph (t)(1) and adding the 

parameter ‘‘Za’’ to Equation W–33 in 

paragraph (t)(1); 

■ r. Revising Equation W–34 of 

paragraph (t)(2) and adding the 

parameter ‘‘Za’’ to Equation W–34 in 

paragraph (t)(2); 

■ s. Revising paragraphs (u) 

introductory text, (u)(2)(iii), and 

(u)(2)(v) through (vii); 

■ t. Revising paragraphs (v), (w) 

introductory text, (w)(1), and (w)(3) 

introductory text; 

■ u. Revising the parameters ‘‘MassCO2’’, 

‘‘N’’, and ‘‘Vv’’ to Equation W–37 in 

paragraph (w)(3); 

■ v. Revising paragraphs (x) 

introductory text and (x)(1); 

■ w. Revising the parameter ‘‘Shl’’ to 

Equation W–38 in paragraph (x)(2); 

■ x. Revising paragraph (z)(1); 

■ y. Revising the parameters ‘‘Va’’, 

‘‘YCO2’’, ‘‘Yj’’, and ‘‘YCH4’’ to Equations 

W–39A and W–39B in paragraph 

(z)(2)(iii); 

■ z. Revising Equation W–40 in 

paragraph (z)(2)(vi) and the parameters 

‘‘MassN2O’’, ‘‘Fuel’’, and ‘‘HHV’’ to 

Equation W–40 in paragraph (z)(2)(vi); 

and 

■ aa. Removing the parameter ‘‘GWP’’ of 

Equation W–40 in paragraph (z)(2)(vi). 

The revisions and additions read as 

follows: 

§ 98.233 Calculating GHG emissions. 

* * * * * 

(a) Natural gas pneumatic device 

venting. Calculate CH4 and CO2

volumetric emissions from continuous 

high bleed, continuous low bleed, and 

intermittent bleed natural gas 

pneumatic devices using Equation W–1 

of this section. 

Where: 

Es,i = Annual total volumetric GHG emissions 

at standard conditions in standard cubic 

feet per year from natural gas pneumatic 

device vents, of types ‘‘t’’ (continuous 

high bleed, continuous low bleed, 

intermittent bleed), for GHGi. 

Countt = Total number of natural gas 

pneumatic devices of type ‘‘t’’ 

(continuous high bleed, continuous low 

bleed, intermittent bleed) as determined 

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

section. 

EFt = Population emission factors for natural 

gas pneumatic device vents (in standard 

cubic feet per hour per device) of each 

type ‘‘t’’ listed in Tables W–1A, W–3, 

and W–4 of this subpart for onshore 

petroleum and natural gas production, 

onshore natural gas transmission 

compression, and underground natural 

gas storage facilities, respectively. 

GHGi = For onshore petroleum and natural 

gas production facilities, onshore natural 

gas transmission compression facilities, 

and underground natural gas storage 

facilities, concentration of GHGi, CH4 or 

CO2, in produced natural gas or 

processed natural gas for each facility as 

specified in paragraphs (u)(2)(i), (iii), and 

(iv) of this section. 

Tt = Average estimated number of hours in 

the operating year the devices, of each 

type ‘‘t’’, were operational using 

engineering estimates based on best 

available data. Default is 8760 hours. 

(1) For all industry segments, 

determine ‘‘Countt’’ for Equation W–1 of 

this subpart for each type of natural gas 

pneumatic device (continuous high 

bleed, continuous low bleed, and 

intermittent bleed) by counting the 

devices, except as specified in 

paragraph (a)(2) of this section. The 

reported number of devices must 

represent the total number of devices for 

the reporting year. 

(2) For the onshore petroleum and 

natural gas production industry 

segment, you have the option in the first 

two consecutive calendar years to 

determine ‘‘Countt’’ for Equation W–1 of 

this subpart for each type of natural gas 

pneumatic device (continuous high 

bleed, continuous low bleed, and 

intermittent bleed) using engineering 

estimates based on best available data. 

* * * * * 

(4) Calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

using calculations in paragraph (v) of 

this section. 

* * * * * 

(c) Natural gas driven pneumatic 

pump venting. (1) Calculate CH4 and 

CO2 volumetric emissions from natural 

gas driven pneumatic pump venting 

using Equation W–2 of this section. 

Natural gas driven pneumatic pumps 

covered in paragraph (e) of this section 

do not have to report emissions under 

this paragraph (c). 

Where: 

Es,i = Annual total volumetric GHG emissions 

at standard conditions in standard cubic 

feet per year from all natural gas driven 

pneumatic pump venting, for GHGi. 

Count = Total number of natural gas driven 

pneumatic pumps. 

EF = Population emissions factors for natural 

gas driven pneumatic pumps (in 

standard cubic feet per hour per pump) 

listed in Table W–1A of this subpart for 

onshore petroleum and natural gas 

production. 

GHGi = Concentration of GHGi, CH4, or CO2, 

in produced natural gas as defined in 

paragraph (u)(2)(i) of this section. 

T = Average estimated number of hours in 

the operating year the pumps were 

operational using engineering estimates 

based on best available data. Default is 

8760 hours. 

(2) Calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

using calculations in paragraph (v) of 

this section. 

(d) Acid gas removal (AGR) vents. For 

AGR vents (including processes such as 

amine, membrane, molecular sieve or 

other absorbents and adsorbents), 

calculate emissions for CO2 only (not 

CH4) vented directly to the atmosphere 

or emitted through a flare, engine (e.g., 

permeate from a membrane or deadsorbed gas from a pressure swing 

adsorber used as fuel supplement), or 

sulfur recovery plant, using any of the 


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Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13425 

calculation methods described in this 

paragraph (d), as applicable. 

(1) Calculation Method 1. If you 

operate and maintain a continuous 

emissions monitoring system (CEMS) 

that has both a CO2 concentration 

monitor and volumetric flow rate 

monitor, you must calculate CO2

emissions under this subpart by 

following the Tier 4 Calculation Method 

and all associated calculation, quality 

assurance, reporting, and recordkeeping 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). Alternatively, you 

may follow the manufacturer’s 

instructions or industry standard 

practice. If a CO2 concentration monitor 

and volumetric flow rate monitor are 

not available, you may elect to install a 

CO2 concentration monitor and a 

volumetric flow rate monitor that 

comply with all of the requirements 

specified for the Tier 4 Calculation 

Method in subpart C of this part 

(General Stationary Fuel Combustion 

Sources). The calculation and reporting 

of CH4 and N2O emissions is not 

required as part of the Tier 4 

requirements for AGR units. 

(2) Calculation Method 2. If a CEMS 

is not available but a vent meter is 

installed, use the CO2 composition and 

annual volume of vent gas to calculate 

emissions using Equation W–3 of this 

section. 

Where: 

Ea,CO2 = Annual volumetric CO2 emissions at 

actual conditions, in cubic feet per year. 

VS = Total annual volume of vent gas flowing 

out of the AGR unit in cubic feet per year 

at actual conditions as determined by 

flow meter using methods set forth in 

§ 98.234(b). Alternatively, you may 

follow the manufacturer’s instructions or 

industry standard practice for calibration 

of the vent meter. 

VolCO2 = Annual average volumetric fraction 

of CO2 content in vent gas flowing out 

of the AGR unit as determined in 

paragraph (d)(6) of this section. 

(3) Calculation Method 3. If a CEMS 

or a vent meter is not installed, you may 

use the inlet or outlet gas flow rate of 

the acid gas removal unit to calculate 

emissions for CO2 using Equations W– 

4A or W–4B of this section. If inlet gas 

flow rate is known, use Equation W–4A. 

If outlet gas flow rate is known, use 

Equation W–4B. 

Where: 

Ea, CO2 = Annual volumetric CO2 emissions 

at actual conditions, in cubic feet per 

year. 

Vin = Total annual volume of natural gas flow 

into the AGR unit in cubic feet per year 

at actual conditions as determined using 

methods specified in paragraph (d)(5) of 

this section. 

Vout = Total annual volume of natural gas 

flow out of the AGR unit in cubic feet 

per year at actual conditions as 

determined using methods specified in 

paragraph (d)(5) of this section. 

VolI = Annual average volumetric fraction of 

CO2 content in natural gas flowing into 

the AGR unit as determined in paragraph 

(d)(7) of this section. 

Volo = Annual average volumetric fraction of 

CO2 content in natural gas flowing out 

of the AGR unit as determined in 

paragraph (d)(8) of this section. 

(4) Calculation Method 4. If CEMS or 

a vent meter is not installed, you may 

calculate emissions using any standard 

simulation software package, such as 

AspenTech HYSYS®, or API 4679 

AMINECalc, that uses the PengRobinson equation of state and speciates 

CO2 emissions. A minimum of the 

following, determined for typical 

operating conditions over the calendar 

year by engineering estimate and 

process knowledge based on best 

available data, must be used to 

characterize emissions: 

(i) Natural gas feed temperature, 

pressure, and flow rate. 

(ii) Acid gas content of feed natural 

gas. 

(iii) Acid gas content of outlet natural 

gas. 

(iv) Unit operating hours, excluding 

downtime for maintenance or standby. 

(v) Exit temperature of natural gas. 

(vi) Solvent pressure, temperature, 

circulation rate, and weight. 

(5) For Calculation Method 3, 

determine the gas flow rate of the inlet 

when using Equation W–4A of this 

section or the gas flow rate of the outlet 

when using Equation W–4B of this 

section for the natural gas stream of an 

AGR unit using a meter according to 

methods set forth in § 98.234(b). If you 

do not have a continuous flow meter, 

either install a continuous flow meter or 

use an engineering calculation to 

determine the flow rate. 

(6) For Calculation Method 2, if a 

continuous gas analyzer is not available 

on the vent stack, either install a 

continuous gas analyzer or take 

quarterly gas samples from the vent gas 

stream to determine VolCO2 in Equation 

W–3 of this section according to 

methods set forth in § 98.234(b). 

(7) For Calculation Method 3, if a 

continuous gas analyzer is installed on 

the inlet gas stream, then the continuous 

gas analyzer results must be used. If a 

continuous gas analyzer is not available, 

either install a continuous gas analyzer 

or take quarterly gas samples from the 

inlet gas stream to determine VolI in 

Equation W–4A or W–4B of this section 

according to methods set forth in 

§ 98.234(b). 

(8) For Calculation Method 3, 

determine annual average volumetric 

fraction of CO2 content in natural gas 

flowing out of the AGR unit using one 

of the methods specified in paragraphs 

(d)(8)(i) through (d)(8)(iii) of this 

section. 

(i) If a continuous gas analyzer is 

installed on the outlet gas stream, then 

the continuous gas analyzer results must 

be used. If a continuous gas analyzer is 

not available, you may install a 

continuous gas analyzer. 

(ii) If a continuous gas analyzer is not 

available or installed, quarterly gas 

samples may be taken from the outlet 

gas stream to determine VolO in 

Equation W–4A or W–4B of this section 


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13426 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

according to methods set forth in 

§ 98.234(b). 

(iii) If a continuous gas analyzer is not 

available or installed, you may use sales 

line quality specification for CO2 in 

natural gas. 

(9) Calculate annual volumetric CO2

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(10) Calculate annual mass CO2

emissions at standard conditions using 

calculations in paragraph (v) of this 

section. 

(11) Determine if CO2 emissions from 

the AGR unit are recovered and 

transferred outside the facility. Adjust 

the CO2 emissions estimated in 

paragraphs (d)(1) through (d)(10) of this 

section downward by the magnitude of 

CO2 emissions recovered and 

transferred outside the facility. 

(e) Dehydrator vents. For dehydrator 

vents, calculate annual CH4 and CO2

emissions using the applicable 

calculation methods described in 

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

section. If emissions from dehydrator 

vents are routed to a vapor recovery 

system, you must adjust the emissions 

downward according to paragraph (e)(5) 

of this section. If emissions from 

dehydrator vents are routed to a flare or 

regenerator fire-box/fire tubes, you must 

calculate CH4, CO2, and N2O annual 

emissions as specified in paragraph 

(e)(6) of this section. 

(1) Calculation Method 1. Calculate 

annual mass emissions from absorbent 

dehydrators that have an annual average 

of daily natural gas throughput that is 

greater than or equal to 0.4 million 

standard cubic feet per day by using a 

software program, such as AspenTech 

HYSYS® or GRI–GLYCalcTM, that uses 

the Peng-Robinson equation of state to 

calculate the equilibrium coefficient, 

speciates CH4 and CO2 emissions from 

dehydrators, and has provisions to 

include regenerator control devices, a 

separator flash tank, stripping gas and a 

gas injection pump or gas assist pump. 

The following parameters must be 

determined by engineering estimate 

based on best available data and must be 

used at a minimum to characterize 

emissions from dehydrators: 

(i) Feed natural gas flow rate. 

(ii) Feed natural gas water content. 

(iii) Outlet natural gas water content. 

(iv) Absorbent circulation pump type 

(e.g., natural gas pneumatic/air 

pneumatic/electric). 

(v) Absorbent circulation rate. 

(vi) Absorbent type (e.g., triethylene 

glycol (TEG), diethylene glycol (DEG) or 

ethylene glycol (EG)). 

(vii) Use of stripping gas. 

(viii) Use of flash tank separator (and 

disposition of recovered gas). 

(ix) Hours operated. 

(x) Wet natural gas temperature and 

pressure. 

(xi) Wet natural gas composition. 

Determine this parameter using one of 

the methods described in paragraphs 

(e)(1)(xi)(A) through (e)(1)(xi)(D) of this 

section. 

(A) Use the GHG mole fraction as 

defined in paragraph (u)(2)(i) or 

(u)(2)(ii) of this section. 

(B) If the GHG mole fraction cannot be 

determined using paragraph (u)(2)(i) or 

(u)(2)(ii) of this section, select a 

representative analysis. 

(C) You may use an appropriate 

standard method published by a 

consensus-based standards organization 

if such a method exists or you may use 

an industry standard practice as 

specified in § 98.234(b) to sample and 

analyze wet natural gas composition. 

(D) If only composition data for dry 

natural gas is available, assume the wet 

natural gas is saturated. 

(2) Calculation Method 2. Calculate 

annual volumetric emissions from 

glycol dehydrators that have an annual 

average of daily natural gas throughput 

that is less than 0.4 million standard 

cubic feet per day using Equation W–5 

of this section: 

Where: 

Es,i = Annual total volumetric GHG emissions 

(either CO2 or CH4) at standard 

conditions in cubic feet. 

EFi = Population emission factors for glycol 

dehydrators in thousand standard cubic 

feet per dehydrator per year. Use 73.4 for 

CH4 and 3.21 for CO2 at 60 °F and 14.7 

psia. 

Count = Total number of glycol dehydrators 

that have an annual average of daily 

natural gas throughput that is less than 

0.4 million standard cubic feet per day. 

1000 = Conversion of EFi in thousand 

standard cubic feet to standard cubic 

feet. 

(3) Calculation Method 3. Dehydrators 

that use desiccant must calculate 

emissions from the amount of gas 

vented from the vessel when it is 

depressurized for the desiccant refilling 

process using Equation W–6 of this 

section. Desiccant dehydrator emissions 

covered in this paragraph do not have 

to be calculated separately using the 

method specified in paragraph (i) of this 

section for blowdown vent stacks. 

Where: 

Es,n = Annual natural gas emissions at 

standard conditions in cubic feet. 

H = Height of the dehydrator vessel (ft). 

D = Inside diameter of the vessel (ft). 

P1 = Atmospheric pressure (psia). 

P2 = Pressure of the gas (psia). 

p = pi (3.14). 

%G = Percent of packed vessel volume that 

is gas. 

N = Number of dehydrator openings in the 

calendar year. 

100 = Conversion of %G to fraction. 

(4) For glycol dehydrators that use the 

calculation method in paragraph (e)(2) 

of this section, calculate both CH4 and 

CO2 mass emissions from volumetric 

GHGi emissions using calculations in 

paragraph (v) of this section. For 

desiccant dehydrators that use the 

calculation method in paragraph (e)(3) 

of this section, calculate both CH4 and 

CO2 volumetric and mass emissions 

from volumetric natural gas emissions 

using calculations in paragraphs (u) and 

(v) of this section. 

(5) Determine if the dehydrator unit 

has vapor recovery. Adjust the 

emissions estimated in paragraphs 

(e)(1), (e)(2), and (e)(3) of this section 

downward by the magnitude of 

emissions recovered using a vapor 

recovery system as determined by 

engineering estimate based on best 

available data. 

(6) Calculate annual emissions from 

dehydrator vents to flares or regenerator 

fire-box/fire tubes as follows: 


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Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13427 

(i) Use the dehydrator vent volume 

and gas composition as determined in 

paragraphs (e)(1) or (e)(2) of this section 

for absorbent dehydrators. Use the 

dehydrator vent volume and gas 

composition as determined in 

paragraphs (e)(3) and (e)(4) of this 

section for dehydrators that use 

desiccant. 

(ii) Use the calculation method of 

flare stacks in paragraph (n) of this 

section to determine dehydrator vent 

emissions from the flare or regenerator 

combustion gas vent. 

(f) Well venting for liquids 

unloadings. Calculate annual volumetric 

natural gas emissions from well venting 

for liquids unloading using one of the 

calculation methods described in 

paragraphs (f)(1), (f)(2), or (f)(3) of this 

section. Calculate annual CH4 and CO2

volumetric and mass emissions using 

the method described in paragraph (f)(4) 

of this section. 

(1) Calculation Method 1. Calculate 

emissions from wells with plunger lifts 

and wells without plunger lifts 

separately. For at least one well of each 

unique well tubing diameter group and 

pressure group combination in each 

sub-basin category (see § 98.238 for the 

definitions of tubing diameter group, 

pressure group, and sub-basin category), 

where gas wells are vented to the 

atmosphere to expel liquids 

accumulated in the tubing, install a 

recording flow meter on the vent line 

used to vent gas from the well (e.g., on 

the vent line off the wellhead separator 

or atmospheric storage tank) according 

to methods set forth in § 98.234(b). 

Calculate the total emissions from well 

venting to the atmosphere for liquids 

unloading using Equation W–7A of this 

section. For any tubing diameter group 

and pressure group combination in a 

sub-basin where liquids unloading 

occurs both with and without plunger 

lifts, Equation W–7A will be used twice, 

once for wells with plunger lifts and 

once for wells without plunger lifts. 

Where: 

Ea = Annual natural gas emissions for all 

wells of the same tubing diameter group 

and pressure group combination in a 

sub-basin at actual conditions, a, in 

cubic feet. Calculate emission from wells 

with plunger lifts and wells without 

plunger lifts separately. 

h = Total number of wells of the same tubing 

diameter group and pressure group 

combination in a sub-basin either with or 

without plunger lifts. 

p = Wells 1 through h of the same tubing 

diameter group and pressure group 

combination in a sub-basin. 

Tp = Cumulative amount of time in hours of 

venting for each well, p, of the same 

tubing diameter group and pressure 

group combination in a sub-basin during 

the year. If the available venting data do 

not contain a record of the date of the 

venting events and data are not available 

to provide the venting hours for the 

specific time period of January 1 to 

December 31, you may calculate an 

annualized vent time, Tp, using Equation 

W–7B of this section. 

FR = Average flow rate in cubic feet per hour 

for all measured wells of the same tubing 

diameter group and pressure group 

combination in a sub-basin, over the 

duration of the liquids unloading, under 

actual conditions as determined in 

paragraph (f)(1)(i) of this section. 

Where: 

HRp = Cumulative amount of time in hours 

of venting for each well, p, during the 

monitoring period. 

MPp = Time period, in days, of the 

monitoring period for each well, p. A 

minimum of 300 days in a calendar year 

are required. The next period of data 

collection must start immediately 

following the end of data collection for 

the previous reporting year. 

Dp = Time period, in days during which the 

well, p, was in production (365 if the 

well was in production for the entire 

year). 

(i) Determine the well vent average 

flow rate (‘‘FR’’ in Equation W–7A of 

this section) as specified in paragraphs 

(f)(1)(i)(A) through (f)(1)(i)(C) of this 

section for at least one well in a unique 

well tubing diameter group and pressure 

group combination in each sub-basin 

category. Calculate emissions from wells 

with plunger lifts and wells without 

plunger lifts separately. 

(A) Calculate the average flow rate per 

hour of venting for each unique tubing 

diameter group and pressure group 

combination in each sub-basin category 

by dividing the recorded total annual 

flow by the recorded time (in hours) for 

all measured liquid unloading events 

with venting to the atmosphere. 

(B) Apply the average hourly flow rate 

calculated under paragraph (f)(1)(i)(A) 

of this section to all wells in the same 

pressure group that have the same 

tubing diameter group, for the number 

of hours of venting these wells. 

(C) Calculate a new average flow rate 

every other calendar year starting with 

the first calendar year of data collection. 

For a new producing sub-basin category, 

calculate an average flow rate beginning 

in the first year of production. 

(ii) Calculate natural gas volumetric 

emissions at standard conditions using 

calculations in paragraph (t) of this 

section. 

(2) Calculation Method 2. Calculate 

the total emissions for each sub-basin 

from well venting to the atmosphere for 

liquids unloading without plunger lift 

assist using Equation W–8 of this 

section. 


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13428 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

Where: 

Es = Annual natural gas emissions for each 

sub-basin at standard conditions, s, in 

cubic feet per year. 

W = Total number of wells with well venting 

for liquids unloading for each sub-basin. 

p = Wells 1 through W with well venting for 

liquids unloading for each sub-basin. 

Vp = Total number of unloading events in the 

monitoring period per well, p. 

0.37 ×10¥3 = {3.14 (pi)/4}/{14.7*144} (psia 

converted to pounds per square feet). 

CDp = Casing internal diameter for each well, 

p, in inches. 

WDp = Well depth from either the top of the 

well or the lowest packer to the bottom 

of the well, for each well, p, in feet. 

SPp = For each well, p, shut-in pressure or 

surface pressure for wells with tubing 

production, or casing pressure for each 

well with no packers, in pounds per 

square inch absolute (psia). If casing 

pressure is not available for each well, 

you may determine the casing pressure 

by multiplying the tubing pressure of 

each well with a ratio of casing pressure 

to tubing pressure from a well in the 

same sub-basin for which the casing 

pressure is known. The tubing pressure 

must be measured during gas flow to a 

flow-line. The shut-in pressure, surface 

pressure, or casing pressure must be 

determined just prior to liquids 

unloading when the well production is 

impeded by liquids loading or closed to 

the flow-line by surface valves. 

SFRp = Average flow-line rate of gas for well, 

p, at standard conditions in cubic feet 

per hour. Use Equation W–33 of this 

section to calculate the average flow-line 

rate at standard conditions. 

HRp,q = Hours that each well, p, was left open 

to the atmosphere during each unloading 

event, q. 

1.0 = Hours for average well to blowdown 

casing volume at shut-in pressure. 

q = Unloading event. 

Zp,q = If HRp,q is less than 1.0 then Zp,q is 

equal to 0. If HRp,q is greater than or 

equal to 1.0 then Zp,q is equal to 1. 

(3) Calculation Method 3. Calculate 

the total emissions for each sub-basin 

from well venting to the atmosphere for 

liquids unloading with plunger lift 

assist using Equation W–9 of this 

section. 

Where: 

Es = Annual natural gas emissions for each 

sub-basin at standard conditions, s, in 

cubic feet per year. 

W = Total number of wells with plunger lift 

assist and well venting for liquids 

unloading for each sub-basin. 

p = Wells 1 through W with well venting for 

liquids unloading for each sub-basin. 

Vp = Total number of unloading events in the 

monitoring period for each well, p. 

0.37 ×10¥3 = {3.14 (pi)/4}/{14.7*144} (psia 

converted to pounds per square feet). 

TDp = Tubing internal diameter for each well, 

p, in inches. 

WDp = Tubing depth to plunger bumper for 

each well, p, in feet. 

SPp = Flow-line pressure for each well, p, in 

pounds per square inch absolute (psia), 

using engineering estimate based on best 

available data. 

SFRp = Average flow-line rate of gas for well, 

p, at standard conditions in cubic feet 

per hour. Use Equation W–33 of this 

section to calculate the average flow-line 

rate at standard conditions. 

HRp,q = Hours that each well, p, was left open 

to the atmosphere during each unloading 

event, q. 

0.5 = Hours for average well to blowdown 

tubing volume at flow-line pressure. 

q = Unloading event. 

Zp,q = If HRp,q is less than 0.5 then Zp,q is 

equal to 0. If HRp,q is greater than or 

equal to 0.5 then Zp,q is equal to 1. 

(4) Calculate CH4 and CO2 volumetric 

and mass emissions from volumetric 

natural gas emissions using calculations 

in paragraphs (u) and (v) of this section. 

(g) Gas well venting during 

completions and workovers with 

hydraulic fracturing. Calculate annual 

volumetric natural gas emissions from 

gas well venting during completions 

and workovers involving hydraulic 

fracturing using Equation W–10A or 

Equation W–10B of this section. 

Equation W–10A applies to well venting 

when the flowback rate is measured 

from a specified number of example 

completions or workovers and Equation 

W–10B applies when the flowback vent 

or flare volume is measured for each 

completion or workover. Completion 

and workover activities are separated 

into two periods, an initial period when 

flowback is routed to open pits or tanks 

and a subsequent period when gas 

content is sufficient to route the 

flowback to a separator or when the gas 

content is sufficient to allow 

measurement by the devices specified in 

paragraph (g)(1) of this section, 

regardless of whether a separator is 

actually utilized. If you elect to use 

Equation W–10A of this section, you 

must follow the procedures specified in 

paragraph (g)(1) of this section. 

Emissions must be calculated separately 

for completions and workovers, for each 

sub-basin, and for each well type 

combination identified in paragraph 

(g)(2) of this section. You must calculate 

CH4 and CO2 volumetric and mass 

emissions as specified in paragraph 

(g)(3) of this section. If emissions from 

gas well venting during completions 

and workovers with hydraulic fracturing 

are routed to a flare, you must calculate 

CH4, CO2, and N2O annual emissions as 

specified in paragraph (g)(4) of this 

section. 

Where: 

Es,n = Annual volumetric natural gas 

emissions in standard cubic feet from gas 

well venting during completions or 

workovers following hydraulic fracturing 

for each sub-basin and well type 

combination. 

W = Total number of wells completed or 

worked over using hydraulic fracturing 

in a sub-basin and well type 

combination. 

Tp,s = Cumulative amount of time of 

flowback, after sufficient quantities of 

gas are present to enable separation, 

where gas is vented or flared for the 

completion or workover, in hours, for 

each well, p, in a sub-basin and well 

type combination during the reporting 


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year. This may include non-contiguous 

periods of venting or flaring. 

Tp,i = Cumulative amount of time of flowback 

to open tanks/pits, from when gas is first 

detected until sufficient quantities of gas 

are present to enable separation, for the 

completion or workover, in hours, for 

each well, p, in a sub-basin and well 

type combination during the reporting 

year. This may include non-contiguous 

periods of routing to open tanks/pits. 

FRMs = Ratio of average flowback, during the 

period when sufficient quantities of gas 

are present to enable separation, of well 

completions and workovers from 

hydraulic fracturing to 30-day 

production rate for the sub-basin and 

well type combination, calculated using 

procedures specified in paragraph 

(g)(1)(iii) of this section, expressed in 

standard cubic feet per hour. 

FRMi = Ratio of initial flowback rate during 

well completions and workovers from 

hydraulic fracturing to 30-day 

production rate for the sub-basin and 

well type combination, calculated using 

procedures specified in paragraph 

(g)(1)(iv) of this section, expressed in 

standard cubic feet per hour, for the 

period of flow to open tanks/pits. 

PRs,p = Average production flow rate during 

the first 30 days of production after 

completions of newly drilled gas wells or 

gas well workovers using hydraulic 

fracturing in standard cubic feet per hour 

of each well p, that was measured in the 

sub-basin and well type combination. 

EnFs,p = Volume of N2 injected gas in cubic 

feet at standard conditions that was 

injected into the reservoir during an 

energized fracture job for each well, p, as 

determined by using an appropriate 

meter according to methods described in 

§ 98.234(b), or by using receipts of gas 

purchases that are used for the energized 

fracture job. Convert to standard 

conditions using paragraph (t) of this 

section. If the fracture process did not 

inject gas into the reservoir or if the 

injected gas is CO2 then EnFs,p is 0. 

FVs,p = Flow volume vented or flared of each 

well, p, in standard cubic feet measured 

using a recording flow meter (digital or 

analog) on the vent line to measure 

flowback during the separation period of 

the completion or workover according to 

methods set forth in § 98.234(b). 

FRp,i = Flow rate vented or flared of each 

well, p, in standard cubic feet measured 

using a recording flow meter (digital or 

analog) on the vent line to measure the 

flowback, at the beginning of the period 

of time when sufficient quantities of gas 

are present to enable separation, of the 

completion or workover according to 

methods set forth in § 98.234(b). 

(1) If you elect to use Equation W– 

10A of this section, you must use 

Calculation Method 1 as specified in 

paragraph (g)(1)(i) of this section, or 

Calculation Method 2 as specified in 

paragraph (g)(1)(ii) of this section, to 

determine the value of FRMs and FRMi. 

These values must be based on the flow 

rate for flowback, once sufficient gas is 

present to enable separation. The 

number of measurements or calculations 

required to estimate FRMs and FRMi

must be determined individually for 

completions and workovers per subbasin and well type as follows: complete 

measurements or calculations for at 

least one completion or workover for 

less than or equal to 25 completions or 

workovers for each well type within a 

sub-basin; complete measurements or 

calculations for at least two completions 

or workovers for 26 to 50 completions 

or workovers for each sub-basin and 

well type combination; complete 

measurements or calculations for at 

least three completions or workovers for 

51 to 100 completions or workovers for 

each sub-basin and well type 

combination; complete measurements or 

calculations for at least four 

completions or workovers for 101 to 250 

completions or workovers for each subbasin and well type combination; and 

complete measurements or calculations 

for at least five completions or 

workovers for greater than 250 

completions or workovers for each subbasin and well type combination. 

(i) Calculation Method 1. You must 

use Equation W–12A as specified in 

paragraph (g)(1)(iii) of this section to 

determine the value of FRMs. You must 

use Equation W–12B as specified in 

paragraph (g)(1)(iv) of this section to 

determine the value of FRMi. The 

procedures specified in paragraphs 

(g)(1)(v) and (g)(1)(vi) also apply. When 

making flowback measurements for use 

in Equations W–12A and W–12B of this 

section, you must use a recording flow 

meter (digital or analog) installed on the 

vent line, ahead of a flare or vent, to 

measure the flowback rates in units of 

standard cubic feet per hour according 

to methods set forth in § 98.234(b). 

(ii) Calculation Method 2. You must 

use Equation W–12A as specified in 

paragraph (g)(1)(iii) of this section to 

determine the value of FRMs. You must 

use Equation W–12B as specified in 

paragraph (g)(1)(iv) of this section to 

determine the value of FRMi. The 

procedures specified in paragraphs 

(g)(1)(v) and (g)(1)(vi) also apply. When 

calculating the flowback rates for use in 

Equations W–12A and W–12B of this 

section based on well parameters, you 

must record the well flowing pressure 

immediately upstream (and 

immediately downstream in subsonic 

flow) of a well choke according to 

methods set forth in § 98.234(b) to 

calculate the well flowback. The 

upstream pressure must be surface 

pressure and reservoir pressure cannot 

be assumed. The downstream pressure 

must be measured after the choke and 

atmospheric pressure cannot be 

assumed. Calculate flowback rate using 

Equation W–11A of this section for 

subsonic flow or Equation W–11B of 

this section for sonic flow. You must 

use best engineering estimates based on 

best available data along with Equation 

W–11C of this section to determine 

whether the predominant flow is sonic 

or subsonic. If the value of R in 

Equation W–11C of this section is 

greater than or equal to 2, then flow is 

sonic; otherwise, flow is subsonic. 

Convert calculated FRa values shall be 

converted from actual conditions 

upstream of the restriction orifice to 

standard conditions (FRs,p and FRi,p) for 

use in Equations W–12A and W–12B of 

this section using Equation W–33 in 

paragraph (t) of this section. 

Where: 

FRa = Flowback rate in actual cubic feet per 

hour, under actual subsonic flow 

conditions. 

A = Cross sectional open area of the 

restriction orifice (m2). 

P1 = Pressure immediately upstream of the 

choke (psia). 

Tu = Temperature immediately upstream of 

the choke (degrees Kelvin). 

P2 = Pressure immediately downstream of the 

choke (psia). 

3430 = Constant with units of m2/(sec2 * K). 

1.27*105 = Conversion from m3/second to ft3/ 

hour. 


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Where: 

FRa = Flowback rate in actual cubic feet per 

hour, under actual sonic flow conditions. 

A = Cross sectional open area of the 

restriction orifice (m2). 

Tu = Temperature immediately upstream of 

the choke (degrees Kelvin). 

187.08 = Constant with units of m2/(sec2 * K). 

1.27*105 = Conversion from m3/second to ft3/ 

hour. 

Where: 

R = Pressure ratio. 

P1 = Pressure immediately upstream of the 

choke (psia). 

P2 = Pressure immediately downstream of the 

choke (psia). 

(iii) For Equation W–10A of this 

section, calculate FRMs using Equation 

W–12A of this section. 

Where: 

FRMs = Ratio of average flowback rate, during 

the period of time when sufficient 

quantities of gas are present to enable 

separation, of well completions and 

workovers from hydraulic fracturing to 

30-day production rate for each subbasin and well type combination. 

FRs,p = Measured average flowback rate from 

Calculation Method 1 described in 

paragraph (g)(1)(i) of this section or 

calculated average flowback rate from 

Calculation Method 2 described in 

paragraph (g)(1)(ii) of this section, during 

the separation period in standard cubic 

feet per hour for well(s) p for each subbasin and well type combination. 

Convert measured and calculated FRa

values shall be converted from actual 

conditions upstream of the restriction 

orifice (FRa) to standard conditions 

(FRs,p) for each well p using Equation W– 

33 in paragraph (t) of this section. You 

may not use flow volume as used in 

Equation W–10B converted to a flow rate 

for this parameter. 

PRs,p = Average production flow rate during 

the first 30 days of production after 

completions of newly drilled gas wells or 

gas well workovers using hydraulic 

fracturing, in standard cubic feet per 

hour for each well, p, that was measured 

in the sub-basin and well type 

combination. 

N = Number of measured or calculated well 

completions or workovers using 

hydraulic fracturing in a sub-basin and 

well type combination. 

(iv) For Equation W–10A of this 

section, calculate FRMi using Equation 

W–12B of this section. 

Where: 

FRMi = Ratio of flowback gas rate while 

flowing to open tanks/pits during well 

completions and workovers from 

hydraulic fracturing to 30-day 

production rate. 

FRi,p = Initial measured gas flowback rate 

from Calculation Method 1 described in 

paragraph (g)(1)(i) of this section or 

initial calculated flow rate from 

Calculation Method 2 described in 

paragraph (g)(1)(ii) of this section in 

standard cubic feet per hour for well(s), 

p, for each sub-basin and well type 

combination. Measured and calculated 

FRi,p values must be based on flow 

conditions at the beginning of the 

separation period and must be expressed 

at standard conditions. 

PRs,p = Average production flow rate during 

the first 30-days of production after 

completions of newly drilled gas wells or 

gas well workovers using hydraulic 

fracturing, in standard cubic feet per 

hour of each well, p, that was measured 

in the sub-basin and well type 

combination. 

N = Number of measured or calculated well 

completions or workovers using 

hydraulic fracturing in a sub-basin and 

well type combination. 

(v) For Equation W–10A of this 

section, the ratio of flowback rate during 

well completions and workovers from 

hydraulic fracturing to 30-day 

production rate for horizontal and 

vertical wells are applied to all 

horizontal and vertical well completions 

in the gas producing sub-basin and well 

type combination and to all horizontal 

and vertical well workovers, 

respectively, in the gas producing subbasin and well type combination for the 

total number of hours of flowback and 

for the first 30 day average production 

rate for each of these wells. 

(vi) For Equation W–12A and W–12B 

of this section, calculate new flowback 

rates for horizontal and vertical gas well 

completions and horizontal and vertical 

gas well workovers in each sub-basin 

category once every two years starting in 

the first calendar year of data collection. 

(2) For paragraphs (g) introductory 

text and (g)(1) of this section, 

measurements and calculations are 

completed separately for workovers and 

completions per sub-basin and well type 

combination. A well type combination 

is a unique combination of the 


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Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13431 

parameters listed in paragraphs (g)(2)(i) 

through (g)(2)(iii) of this section. 

(i) Vertical or horizontal (directional 

drilling). 

(ii) With flaring or without flaring. 

(iii) Reduced emission completion/

workover or not reduced emission 

completion/workover. 

(3) Calculate both CH4 and CO2

volumetric and mass emissions from 

total natural gas volumetric emissions 

using calculations in paragraphs (u) and 

(v) of this section. 

(4) Calculate annual emissions from 

gas well venting during well 

completions and workovers from 

hydraulic fracturing where all or a 

portion of the gas is flared as specified 

in paragraphs (g)(4)(i) and (g)(4)(ii) of 

this section. 

(i) Use the volumetric total natural gas 

emissions vented to the atmosphere 

during well completions and workovers 

as determined in paragraph (g) of this 

section to calculate volumetric and mass 

emissions using paragraphs (u) and (v) 

of this section. 

(ii) Use the calculation method of 

flare stacks in paragraph (n) of this 

section to adjust emissions for the 

portion of gas flared during well 

completions and workovers using 

hydraulic fracturing. This adjustment to 

emissions from completions using 

flaring, versus completions without 

flaring, accounts for the conversion of 

CH4 to CO2 in the flare and for the 

formation on N2O during flaring. 

(h) Gas well venting during 

completions and workovers without 

hydraulic fracturing. Calculate annual 

volumetric natural gas emissions from 

each gas well venting during workovers 

without hydraulic fracturing using 

Equation W–13A of this section. 

Calculate annual volumetric natural gas 

emissions from each gas well venting 

during completions without hydraulic 

fracturing using Equation W–13B of this 

section. You must convert annual 

volumetric natural gas emissions to CH4

and CO2 volumetric and mass emissions 

as specified in paragraph (h)(1) of this 

section. If emissions from gas well 

venting during completions and 

workovers without hydraulic fracturing 

are routed to a flare, you must calculate 

CH4, CO2, and N2O annual emissions as 

specified in paragraph (h)(2) of this 

section. 

Where: 

Es,wo = Annual volumetric natural gas 

emissions in standard cubic feet from gas 

well venting during well workovers 

without hydraulic fracturing. 

Nwo = Number of workovers per sub-basin 

category that do not involve hydraulic 

fracturing in the reporting year. 

EFwo = Emission factor for non-hydraulic 

fracture well workover venting in 

standard cubic feet per workover. Use 

3,114 standard cubic feet natural gas per 

well workover without hydraulic 

fracturing. 

Es,p = Annual volumetric natural gas 

emissions in standard cubic feet from gas 

well venting during well completions 

without hydraulic fracturing. 

p = Well completions 1 through f in a subbasin. 

f = Total number of well completions without 

hydraulic fracturing in a sub-basin 

category. 

Vp = Average daily gas production rate in 

standard cubic feet per hour for each 

well, p, undergoing completion without 

hydraulic fracturing. This is the total 

annual gas production volume divided 

by total number of hours the wells 

produced to the flow-line. For completed 

wells that have not established a 

production rate, you may use the average 

flow rate from the first 30 days of 

production. In the event that the well is 

completed less than 30 days from the 

end of the calendar year, the first 30 days 

of the production straddling the current 

and following calendar years shall be 

used. 

Tp = Time that gas is vented to either the 

atmosphere or a flare for each well, p, 

undergoing completion without 

hydraulic fracturing, in hours during the 

year. 

(1) Calculate both CH4 and CO2

volumetric emissions from natural gas 

volumetric emissions using calculations 

in paragraph (u) of this section. 

Calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

vented to atmosphere using calculations 

in paragraph (v) of this section. 

(2) Calculate annual emissions of CH4, 

CO2, and N2O from gas well venting to 

flares during well completions and 

workovers not involving hydraulic 

fracturing as specified in paragraphs 

(h)(2)(i) and (h)(2)(ii) of this section. 

(i) Use the gas well venting volume 

and gas composition during well 

completions and workovers that are 

flared as determined using the methods 

specified in paragraphs (h) and (h)(1) of 

this section. 

(ii) Use the calculation method of 

flare stacks in paragraph (n) of this 

section to determine emissions from the 

flare for gas well venting to a flare 

during completions and workovers 

without hydraulic fracturing. 

(i) Blowdown vent stacks. Calculate 

CO2 and CH4 blowdown vent stack 

emissions from the depressurization of 

equipment to reduce system pressure for 

planned or emergency shutdowns 

resulting from human intervention or to 

take equipment out of service for 

maintenance as specified in either 

paragraph (i)(2) or (i)(3) of this section. 

Equipment with a unique physical 

volume of less than 50 cubic feet as 

determined in paragraph (i)(1) of this 

section are not subject to the 

requirements in paragraphs (i)(2) 

through (i)(4) this section. The 

requirements in this paragraph (i) do not 

apply to blowdown vent stack emissions 

from depressurizing to a flare, overpressure relief, operating pressure 

control venting, blowdown of non-GHG 

gases, and desiccant dehydrator 

blowdown venting before reloading. 

(1) Method for calculating unique 

physical volumes. You must calculate 

each unique physical volume (including 

pipelines, compressor case or cylinders, 

manifolds, suction bottles, discharge 

bottles, and vessels) between isolation 

valves, in cubic feet, by using 

engineering estimates based on best 

available data. 

(2) Method for determining emissions 

from blowdown vent stacks according to 

equipment type. If you elect to 

determine emissions according to each 

equipment type, using unique physical 

volumes as calculated in paragraph 

(i)(1) of this section, you must calculate 

emissions as specified in paragraphs 

(i)(2)(i) through (i)(2)(iii) of this section 

for each equipment type. Equipment 

types must be grouped into the 

following seven categories: station 

piping, pipeline venting, compressors, 

scrubbers/strainers, pig launchers and 

receivers, emergency shutdowns, and all 

other blowdowns greater than or equal 

to 50 cubic feet. 

(i) Calculate the total annual natural 

gas emissions from each unique 

physical volume that is blown down 


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using either Equation W–14A or W–14B 

of this section. 

Where: 

Es,n = Annual natural gas emissions at 

standard conditions from each unique 

physical volume that is blown down, in 

cubic feet. 

N = Number of occurrences of blowdowns for 

each unique physical volume in the 

calendar year. You must retain logs 

documenting the number of occurrences 

of blowdowns for each unique physical 

volume in the calendar year. 

V = Unique physical volume between 

isolation valves, in cubic feet, as 

calculated in paragraph (i)(1) of this 

section. 

C = Purge factor is 1 if the unique physical 

volume is not purged, or 0 if the unique 

physical volume is purged using nonGHG gases. 

Ts = Temperature at standard conditions 

(60 °F). 

Ta = Temperature at actual conditions in the 

unique physical volume (°F). 

Ps = Absolute pressure at standard conditions 

(14.7 psia). 

Pa = Absolute pressure at actual conditions 

in the unique physical volume (psia). 

Za = Compressibility factor at actual 

conditions for natural gas. You may use 

1 if the temperature is above ¥10 

degrees Fahrenheit and pressure is below 

5 atmospheres, or if the compressibility 

factor at the actual temperature and 

pressure is 0.98 or greater. 

Where: 

Es,n = Annual natural gas emissions at 

standard conditions from each unique 

physical volume that is blown down, in 

cubic feet. 

p = Individual occurrence of blowdown for 

the same unique physical volume. 

N = Number of occurrences of blowdowns for 

each unique physical volume in the 

calendar year. You must retain logs 

documenting the number of occurrences 

of blowdowns for each unique physical 

volume in the calendar year. 

Vp = Unique physical volume between 

isolation valves, in cubic feet, for each 

blowdown ‘‘p.’’ 

Ts = Temperature at standard conditions 

(60 °F). 

Ta,p = Temperature at actual conditions in the 

unique physical volume (°F) for each 

blowdown ‘‘p’’. 

Ps = Absolute pressure at standard conditions 

(14.7 psia). 

Pa,b,p = Absolute pressure at actual conditions 

in the unique physical volume (psia) at 

the beginning of the blowdown ‘‘p’’. 

Pa,e,p = Absolute pressure at actual conditions 

in the unique physical volume (psia) at 

the end of the blowdown ‘‘p’’; 0 if 

blowdown volume is purged using nonGHG gases. 

Za = Compressibility factor at actual 

conditions for natural gas. You may use 

1 if the temperature is above ¥10 

degrees Fahrenheit and pressure is below 

5 atmospheres, or if the compressibility 

factor at the actual temperature and 

pressure is 0.98 or greater. 

(ii) Calculate the annual natural gas 

emissions, in cubic feet, from each 

equipment type by summing Es,n, as 

calculated in either Equation W–14A or 

Equation W–14B of this subpart, for all 

unique physical volumes associated 

with the equipment type. 

(iii) Calculate total annual CH4 and 

CO2 volumetric and mass emissions 

from each equipment type by using the 

annual natural gas emission value 

calculated in paragraph (i)(2)(ii) of this 

section for the equipment type and the 

calculation method specified in 

paragraph (i)(4) of this section. 

(3) Method for determining emissions 

from blowdown vent stacks using a flow 

meter. In lieu of determining emissions 

from blowdown vent stacks using 

unique physical volumes as specified in 

paragraphs (i)(1) and (i)(2) of this 

section, you may use a flow meter and 

measure blowdown vent stack 

emissions. If you choose to use this 

method, you must measure the natural 

gas emissions from the blowdown(s) at 

the facility using a flow meter according 

to methods in § 98.234(b), and calculate 

annual CH4 and CO2 volumetric and 

mass emissions measured by the meters 

according to paragraph (i)(4) of this 

section. 

(4) Method for converting from 

natural gas emissions to GHG 

volumetric and mass emissions. 

Calculate both CH4 and CO2 volumetric 

and mass emissions using the methods 

specified in paragraphs (u) and (v) of 

this section. 

(j) Onshore production storage tanks. 

Calculate CH4, CO2, and N2O (when 

flared) emissions from atmospheric 

pressure fixed roof storage tanks 

receiving hydrocarbon produced liquids 

from onshore petroleum and natural gas 

production facilities (including 

stationary liquid storage not owned or 

operated by the reporter), as specified in 

this paragraph (j). For wells flowing to 

gas-liquid separators with annual 

average daily throughput of oil greater 

than or equal to 10 barrels per day, 

calculate annual CH4 and CO2 using 

Calculation Method 1 or 2 as specified 

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

section. For wells flowing directly to 

atmospheric storage tanks without 

passing through a wellhead separator 

with throughput greater than 10 barrels 

per day, calculate annual CH4 and CO2

emissions using Calculation Method 2 

as specified in paragraph (j)(2) of this 

section. For wells flowing to gas-liquid 

separators or directly to atmospheric 

storage tanks with throughput less than 

10 barrels per day, use Calculation 

Method 3 as specified in paragraphs 

(j)(3) of this section. You must also 

calculate emissions that may have 

occurred due to dump valves not 

closing properly using the method 

specified in paragraph (j)(6) of this 

section. If emissions from atmospheric 

pressure fixed roof storage tanks are 

routed to a vapor recovery system, you 

must adjust the emissions downward 

according to paragraph (j)(4) of this 

section. If emissions from atmospheric 

pressure fixed roof storage tanks are 

routed to a flare, you must calculate 

CH4, CO2, and N2O annual emissions as 

specified in paragraph (j)(5) of this 

section. 

(1) Calculation Method 1. Calculate 

annual CH4 and CO2 emissions from 

onshore production storage tanks using 

operating conditions in the last 


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wellhead gas-liquid separator before 

liquid transfer to storage tanks. 

Calculate flashing emissions with a 

software program, such as AspenTech 

HYSYS® or API 4697 E&P Tank, that 

uses the Peng-Robinson equation of 

state, models flashing emissions, and 

speciates CH4 and CO2 emissions that 

will result when the oil from the 

separator enters an atmospheric 

pressure storage tank. The following 

parameters must be determined for 

typical operating conditions over the 

year by engineering estimate and 

process knowledge based on best 

available data, and must be used at a 

minimum to characterize emissions 

from liquid transferred to tanks: 

* * * * * 

(vii) Separator oil composition and 

Reid vapor pressure. If this data is not 

available, determine these parameters 

by using one of the methods described 

in paragraphs (j)(1)(vii)(A) through 

(j)(1)(vii)(C) of this section. 

* * * * * 

(2) Calculation Method 2. Calculate 

annual CH4 and CO2 emissions by 

assuming that all of the CH4 and CO2 in 

solution at separator temperature and 

pressure is emitted from oil sent to 

storage tanks, using either of the 

methods in paragraphs (j)(2)(i) or 

(j)(2)(ii) of this section. You may use an 

appropriate standard method published 

by a consensus-based standards 

organization if such a method exists or 

you may use an industry standard 

practice as described in § 98.234(b) to 

sample and analyze separator oil 

composition at separator pressure and 

temperature. 

* * * * * 

(3) Calculation Method 3. Calculate 

CH4 and CO2 emissions using Equation 

W–15 of this section: 

Where: 

Es,i = Annual total volumetric GHG emissions 

(either CO2 or CH4) at standard 

conditions in cubic feet. 

EFi = Population emission factor for 

separators or wells in thousand standard 

cubic feet per separator or well per year, 

for crude oil use 4.2 for CH4 and 2.8 for 

CO2 at 60 °F and 14.7 psia, and for gas 

condensate use 17.6 for CH4 and 2.8 for 

CO2 at 60 °F and 14.7 psia. 

Count = Total number of separators or wells 

with annual average daily throughput 

less than 10 barrels per day. Count only 

separators or wells that feed oil directly 

to the storage tank. 

1,000 = Conversion from thousand standard 

cubic feet to standard cubic feet. 

(4) Determine if the storage tank 

receiving your separator oil has a vapor 

recovery system. 

(i) Adjust the emissions estimated in 

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

section downward by the magnitude of 

emissions recovered using a vapor 

recovery system as determined by 

engineering estimate based on best 

available data. 

(ii) [Reserved] 

(5) Determine if the storage tank 

receiving your separator oil is sent to 

flare(s). 

(i) Use your separator flash gas 

volume and gas composition as 

determined in this section. 

(ii) Use the calculation method of 

flare stacks in paragraph (n) of this 

section to determine storage tank 

emissions from the flare. 

(6) Calculate emissions from 

occurrences of well pad gas-liquid 

separator liquid dump valves not 

closing during the calendar year by 

using Equation W–16 of this section. 

Where: 

Es,i,o = Annual volumetric GHG emissions at 

standard conditions from each storage 

tank in cubic feet that resulted from the 

dump valve on the gas-liquid separator 

not closing properly. 

En = Storage tank emissions as determined in 

Calculation Methods 1, 2, or 3 in 

paragraphs (j)(1), (j)(2), and (j)(3) of this 

section (with wellhead separators) in 

standard cubic feet per year. 

Tn = Total time a dump valve is not closing 

properly in the calendar year in hours. 

Estimate Tn based on maintenance, 

operations, or routine well pad 

inspections that indicate the period of 

time when the valve was malfunctioning 

in open or partially open position. 

CFn = Correction factor for tank emissions for 

time period Tn is 2.87 for crude oil 

production. Correction factor for tank 

emissions for time period Tn is 4.37 for 

gas condensate production. 

8,760 = Conversion to hourly emissions. 

(7) Calculate both CH4 and CO2 mass 

emissions from natural gas volumetric 

emissions using calculations in 

paragraph (v) of this section. 

(k) Transmission storage tanks. For 

vent stacks connected to one or more 

transmission condensate storage tanks, 

either water or hydrocarbon, without 

vapor recovery, in onshore natural gas 

transmission compression, calculate 

CH4 and CO2 annual emissions from 

compressor scrubber dump valve 

leakage as specified in paragraphs (k)(1) 

through (k)(3) of this section. If 

emissions from compressor scrubber 

dump valve leakage are routed to a flare, 

you must calculate CH4, CO2, and N2O 

annual emissions as specified in 

paragraph (k)(4) of this section. 

(1) Except as specified in paragraph 

(k)(1)(iv) of this section, you must 

monitor the tank vapor vent stack 

annually for emissions using one of the 

methods specified in paragraphs (k)(1)(i) 

through (k)(1)(iii) of this section. 

(i) Use an optical gas imaging 

instrument according to methods set 

forth in § 98.234(a)(1). 

(ii) Measure the tank vent directly 

using a flow meter or high volume 

sampler according to methods in 

§ 98.234(b) or (d) for a duration of 5 

minutes. 

(iii) Measure the tank vent using a 

calibrated bag according to methods in 

§ 98.234(c) for a duration of 5 minutes 

or until the bag is full, whichever is 

shorter. 

(iv) You may annually monitor 

leakage through compressor scrubber 

dump valve(s) into the tank using an 

acoustic leak detection device according 

to methods set forth in § 98.234(a)(5). 

(2) If the tank vapors from the vent 

stack are continuous for 5 minutes, or 

the acoustic leak detection device 

detects a leak, then you must use one of 

the methods in either paragraph (k)(2)(i) 

or (k)(2)(ii) of this section and the 

requirements specified in paragraphs 

(k)(2)(iii) and (k)(2)(iv) of this section to 

quantify annual emissions. 

(i) Use a flow meter, such as a turbine 

meter, calibrated bag, or high volume 

sampler to estimate tank vapor volumes 

from the vent stack according to 


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methods set forth in § 98.234(b) through 

(d). If you do not have a continuous 

flow measurement device, you may 

install a flow measuring device on the 

tank vapor vent stack. If the vent is 

directly measured for five minutes 

under paragraph (k)(1)(ii) or (k)(1)(iii) of 

this section to detect continuous 

leakage, this serves as the measurement. 

(ii) Use an acoustic leak detection 

device on each scrubber dump valve 

connected to the tank according to the 

method set forth in § 98.234(a)(5). 

(iii) Use the appropriate gas 

composition in paragraph (u)(2)(iii) of 

this section. 

(iv) Calculate CH4 and CO2 volumetric 

and mass emissions at standard 

conditions using calculations in 

paragraphs (t), (u), and (v) of this 

section, as applicable to the monitoring 

equipment used. 

(3) If a leaking dump valve is 

identified, the leak must be counted as 

having occurred since the beginning of 

the calendar year, or from the previous 

test that did not detect leaking in the 

same calendar year. If the leaking dump 

valve is fixed following leak detection, 

the leak duration will end upon being 

repaired. If a leaking dump valve is 

identified and not repaired, the leak 

must be counted as having occurred 

through the rest of the calendar year. 

(4) Calculate annual emissions from 

storage tanks to flares as specified in 

paragraphs (k)(4)(i) and (k)(4)(ii) of this 

section. 

(i) Use the storage tank emissions 

volume and gas composition as 

determined in paragraphs (k)(1) through 

(k)(3) of this section. 

(ii) Use the calculation method of 

flare stacks in paragraph (n) of this 

section to determine storage tank 

emissions sent to a flare. 

(l) Well testing venting and flaring. 

Calculate CH4 and CO2 annual 

emissions from well testing venting as 

specified in paragraphs (l)(1) through 

(l)(5) of this section. If emissions from 

well testing venting are routed to a flare, 

you must calculate CH4, CO2, and N2O 

annual emissions as specified in 

paragraph (l)(6) of this section. 

* * * * * 

(2) If GOR cannot be determined from 

your available data, then you must 

measure quantities reported in this 

section according to one of the 

procedures specified in paragraph 

(l)(2)(i) or (l)(2)(ii) of this section to 

determine GOR. 

* * * * * 

(ii) You may use an industry standard 

practice as described in § 98.234(b). 

(3) Estimate venting emissions using 

Equation W–17A (for oil wells) or 

Equation W–17B (for gas wells) of this 

section. 

* * * * * 

FR = Average annual flow rate in barrels of 

oil per day for the oil well(s) being 

tested. 

* * * * * 

D = Number of days during the calendar year 

that the well(s) is tested. 

* * * * * 

(5) Calculate both CH4 and CO2

volumetric and mass emissions from 

natural gas volumetric emissions using 

calculations in paragraphs (u) and (v) of 

this section. 

(6) Calculate emissions from well 

testing if emissions are routed to a flare 

as specified in paragraphs (l)(6)(i) and 

(l)(6)(ii) of this section. 

(i) Use the well testing emissions 

volume and gas composition as 

determined in paragraphs (l)(1) through 

(4) of this section. 

(ii) Use the calculation method of 

flare stacks in paragraph (n) of this 

section to determine well testing 

emissions from the flare. 

(m) Associated gas venting and 

flaring. Calculate CH4 and CO2 annual 

emissions from associated gas venting 

not in conjunction with well testing 

(refer to paragraph (l): Well testing 

venting and flaring of this section) as 

specified in paragraphs (m)(1) through 

(m)(4) of this section. If emissions from 

associated gas venting are routed to a 

flare, you must calculate CH4, CO2, and 

N2O annual emissions as specified in 

paragraph (m)(5) of this section. 

(1) Determine the GOR of the 

hydrocarbon production from each well 

whose associated natural gas is vented 

or flared. If GOR from each well is not 

available, use the GOR from a cluster of 

wells in the same sub-basin category. 

(2) If GOR cannot be determined from 

your available data, then you must use 

one of the procedures specified in 

paragraphs (m)(2)(i) or (m)(2)(ii) of this 

section to determine GOR. 

(i) You may use an appropriate 

standard method published by a 

consensus-based standards organization 

if such a method exists. 

(ii) You may use an industry standard 

practice as described in § 98.234(b). 

(3) Estimate venting emissions using 

Equation W–18 of this section. 

Where: 

Es,n = Annual volumetric natural gas 

emissions, at the facility level, from 

associated gas venting at standard 

conditions, in cubic feet. 

GORp,q = Gas to oil ratio, for well p in subbasin q, in standard cubic feet of gas per 

barrel of oil; oil here refers to 

hydrocarbon liquids produced of all API 

gravities. 

Vp,q = Volume of oil produced, for well p in 

sub-basin q, in barrels in the calendar 

year during time periods in which 

associated gas was vented or flared. 

SGp,q = Volume of associated gas sent to 

sales, for well p in sub-basin q, in 

standard cubic feet of gas in the calendar 

year during time periods in which 

associated gas was vented or flared. 

EREp,q = Emissions reported elsewhere, 

volume of associated gas for well p in 

sub-basin q, in standard cubic feet, 

during time periods in which associated 

gas was vented or flared and for which 

emission source types of this section 

calculate and report emissions from the 

associated gas stream prior to venting or 

flaring of the associated gas (i.e., 

§ 98.233(j) for onshore production 

storage tanks). 

x = Total number of wells in sub-basin that 

vent or flare associated gas. 

y = Total number of sub-basins in a basin that 

contain wells that vent or flare 

associated gas. 

(4) Calculate both CH4 and CO2

volumetric and mass emissions from 

volumetric natural gas emissions using 

calculations in paragraphs (u) and (v) of 

this section. 

(5) Calculate emissions from 

associated natural gas if emissions are 

routed to a flare as specified in 

paragraphs (m)(5)(i) and (m)(5)(ii) of this 

section. 

(i) Use the associated natural gas 

volume and gas composition as 

determined in paragraph (m)(1) through 

(m)(4) of this section. 

(ii) Use the calculation method of 

flare stacks in paragraph (n) of this 

section to determine associated gas 

emissions from the flare. 

(n) Flare stack emissions. Calculate 

CO2, CH4, and N2O emissions from a 

flare stack as specified in paragraphs 

(n)(1) through (n)(9) of this section. 

(1) If you have a continuous flow 

measurement device on the flare, you 


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must use the measured flow volumes to 

calculate the flare gas emissions. If all 

of the flare gas is not measured by the 

existing flow measurement device, then 

the flow not measured can be estimated 

using engineering calculations based on 

best available data or company records. 

If you do not have a continuous flow 

measurement device on the flare, you 

can use engineering calculations based 

on process knowledge, company 

records, and best available data. 

(2) If you have a continuous gas 

composition analyzer on gas to the flare, 

you must use these compositions in 

calculating emissions. If you do not 

have a continuous gas composition 

analyzer on gas to the flare, you must 

use the appropriate gas compositions for 

each stream of hydrocarbons going to 

the flare as specified in paragraphs 

(n)(2)(i) through (n)(2)(iii) of this 

section. 

(i) For onshore natural gas 

production, determine the GHG mole 

fraction using paragraph (u)(2)(i) of this 

section. 

(ii) For onshore natural gas 

processing, when the stream going to 

flare is natural gas, use the GHG mole 

fraction in feed natural gas for all 

streams upstream of the de-methanizer 

or dew point control, and GHG mole 

fraction in facility specific residue gas to 

transmission pipeline systems for all 

emissions sources downstream of the 

de-methanizer overhead or dew point 

control for onshore natural gas 

processing facilities. For onshore 

natural gas processing plants that solely 

fractionate a liquid stream, use the GHG 

mole fraction in feed natural gas liquid 

for all streams. 

(iii) For any applicable industry 

segment, when the stream going to the 

flare is a hydrocarbon product stream, 

such as methane, ethane, propane, 

butane, pentane-plus and mixed light 

hydrocarbons, then you may use a 

representative composition from the 

source for the stream determined by 

engineering calculation based on 

process knowledge and best available 

data. 

(3) Determine flare combustion 

efficiency from manufacturer. If not 

available, assume that flare combustion 

efficiency is 98 percent. 

(4) Convert GHG volumetric 

emissions to standard conditions using 

calculations in paragraph (t) of this 

section. 

(5) Calculate GHG volumetric 

emissions from flaring at standard 

conditions using Equations W–19 and 

W–20 of this section. 

Where: 

Es,CH4 = Annual CH4 emissions from flare 

stack in cubic feet, at standard 

conditions. 

Es,CO2 = Annual CO2 emissions from flare 

stack in cubic feet, at standard 

conditions. 

Vs = Volume of gas sent to flare in standard 

cubic feet, during the year as determined 

in paragraph (n)(1) of this section. 

h = Flare combustion efficiency, expressed as 

fraction of gas combusted by a burning 

flare (default is 0.98). 

XCH4 = Mole fraction of CH4 in the feed gas 

to the flare as determined in paragraph 

(n)(2) of this section. 

XCO2 = Mole fraction of CO2 in the feed gas 

to the flare as determined in paragraph 

(n)(2) of this section. 

ZU = Fraction of the feed gas sent to an unlit flare determined by engineering 

estimate and process knowledge based 

on best available data and operating 

records. 

ZL = Fraction of the feed gas sent to a burning 

flare (equal to 1- ZU). 

Yj = Mole fraction of hydrocarbon 

constituents j (such as methane, ethane, 

propane, butane, and pentanes-plus) in 

the feed gas to the flare as determined in 

paragraph (n)(1) of this section. 

Rj = Number of carbon atoms in the 

hydrocarbon constituent j in the feed gas 

to the flare: 1 for methane, 2 for ethane, 

3 for propane, 4 for butane, and 5 for 

pentanes-plus). 

(6) Calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

using calculation in paragraph (v) of this 

section. 

(7) Calculate N2O emissions from flare 

stacks using Equation W–40 in 

paragraph (z) of this section. 

(8) If you operate and maintain a 

CEMS that has both a CO2 concentration 

monitor and volumetric flow rate 

monitor for the combustion gases from 

the flare, you must calculate only CO2

emissions for the flare. You must follow 

the Tier 4 Calculation Method and all 

associated calculation, quality 

assurance, reporting, and recordkeeping 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). If a CEMS is used 

to calculate flare stack emissions, the 

requirements specified in paragraphs 

(n)(1) through (n)(7) are not required. 

(9) The flare emissions determined 

under paragraph (n) of this section must 

be corrected for flare emissions 

calculated and reported under other 

paragraphs of this section to avoid 

double counting of these emissions. 

(o) Centrifugal compressor venting. If 

you are required to report emissions 

from centrifugal compressor venting as 

specified in § 98.232(d)(2), (e)(2), (f)(2), 

(g)(2), and (h)(2), you must conduct 

volumetric emission measurements 

specified in paragraph (o)(1) of this 

section using methods specified in 

paragraphs (o)(2) through (o)(5) of this 

section; perform calculations specified 

in paragraphs (o)(6) through (o)(9) of 

this section; and calculate CH4 and CO2

mass emissions as specified in 

paragraph (o)(11) of this section. If 

emissions from a compressor source are 

routed to a flare, paragraphs (o)(1) 

through (o)(11) of this section do not 

apply and instead you must calculate 

CH4, CO2, and N2O emissions as 

specified in paragraph (o)(12) of this 

section. If emissions from a compressor 

source are captured for fuel use or are 

routed to a thermal oxidizer, paragraphs 

(o)(1) through (o)(12) of this section do 

not apply and instead you must 

calculate and report emissions as 

specified in subpart C of this part. If 

emissions from a compressor source are 

routed to vapor recovery, the 

calculations specified in paragraphs 

(o)(1) through (o)(12) of this section do 

not apply. If you are required to report 

emissions from centrifugal compressor 

venting at an onshore petroleum and 

natural gas production facility as 

specified in § 98.232(c)(19), you must 

calculate volumetric emissions as 

specified in paragraph (o)(10) of this 

section; and calculate CH4 and CO2

mass emissions as specified in 

paragraph (o)(11) of this section. 

(1) General requirements for 

conducting volumetric emission 

measurements. You must conduct 

volumetric emission measurements on 

each centrifugal compressor as specified 

in this paragraph. Compressor sources 

(as defined in § 98.238) without 

manifolded vents must use a 


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measurement method specified in 

paragraph (o)(1)(i) or (o)(1)(ii) of this 

section. Manifolded compressor sources 

(as defined in § 98.238) must use a 

measurement method specified in 

paragraph (o)(1)(i), (o)(1)(ii), (o)(1)(iii), 

or (o)(1)(iv) of this section. 

(i) Centrifugal compressor source as 

found leak measurements. Measure 

venting from each compressor according 

to either paragraph (o)(1)(i)(A) or 

(o)(1)(i)(B) of this section at least once 

annually, based on the compressor 

mode (as defined in § 98.238) in which 

the compressor was found at the time of 

measurement, except as specified in 

paragraphs (o)(1)(i)(C) and (o)(1)(i)(D) of 

this section. If additional measurements 

beyond the required annual testing are 

performed (including duplicate 

measurements or measurement of 

additional operating modes), then all 

measurements satisfying the applicable 

monitoring and QA/QC that is required 

by this paragraph (o) must be used in 

the calculations specified in this 

section. 

(A) For a compressor measured in 

operating-mode, you must measure 

volumetric emissions from blowdown 

valve leakage through the blowdown 

vent as specified in either paragraph 

(o)(2)(i)(A) or (o)(2)(i)(B) of this section 

and, if the compressor has wet seal oil 

degassing vents, measure volumetric 

emissions from wet seal oil degassing 

vents as specified in paragraph (o)(2)(ii) 

of this section. If a compressor has a 

continuously operating vapor recovery 

system for the wet seal degassing, then 

measurement of wet seal degassing is 

not required. 

(B) For a compressor measured in notoperating-depressurized-mode, you 

must measure volumetric emissions 

from isolation valve leakage as specified 

in either paragraph (o)(2)(i)(A), 

(o)(2)(i)(B), or (o)(2)(i)(C) of this section. 

If a compressor is not operated and has 

blind flanges in place throughout the 

reporting period, measurement is not 

required in this compressor mode. 

(C) You must measure the compressor 

as specified in paragraph (o)(1)(i)(B) of 

this section at least once in any three 

consecutive calendar years, provided 

the measurement can be taken during a 

scheduled shutdown. If three 

consecutive calendar years occur 

without measuring the compressor in 

not-operating-depressurized-mode, you 

must measure the compressor as 

specified in paragraph (o)(1)(i)(B) of this 

section at the next scheduled 

depressurized shutdown. The 

requirement specified in this paragraph 

does not apply if the compressor has 

blind flanges in place throughout the 

reporting year. 

(D) You must measure the compressor 

as specified in paragraph (o)(1)(i)(A) of 

this section at least once in any three 

consecutive calendar years, provided 

that the measurement can be taken 

when the compressor is in operatingmode. If three consecutive calendar 

years occur without measuring the 

compressor in operating-mode, you 

must measure the compressor as 

specified in paragraph (o)(1)(i)(A) of this 

section in the next calendar year that 

the compressor is in operating-mode for 

more than 2,000 hours. 

(ii) Centrifugal compressor source 

continuous monitoring. Instead of 

measuring the compressor source 

according to paragraph (o)(1)(i) of this 

section for a given compressor, you may 

elect to continuously measure 

volumetric emissions from a compressor 

source as specified in paragraph (o)(3) of 

this section. 

(iii) Manifolded centrifugal 

compressor source as found leak 

measurements. For a compressor source 

that is part of a manifolded group of 

compressor sources (as defined in 

§ 98.238), instead of measuring the 

compressor source according to 

paragraph (o)(1)(i), (o)(1)(ii), or (o)(1)(iv) 

of this section, you may elect to measure 

combined volumetric emissions from 

the manifolded group of compressor 

sources by conducting leak 

measurements at the common vent stack 

as specified in paragraph (o)(4) of this 

section. The leak measurements must be 

conducted at the frequency specified in 

paragraphs (o)(1)(iii)(A) through 

(o)(1)(iii)(C) of this section. 

(A) A minimum of three leak 

measurements must be taken for each 

manifolded group of compressor sources 

in a calendar year. 

(B) The leak measurements may be 

performed while the compressors are in 

any compressor mode. 

(C) The three required leak 

measurements must be separated by a 

minimum of 60 days. If more than two 

leak measurements are performed, the 

first and last measurements in a 

calendar year must be separated by a 

minimum of 120 days. 

(iv) Manifolded centrifugal 

compressor source continuous 

monitoring. For a compressor source 

that is part of a manifolded group of 

compressor sources, instead of 

measuring the compressor source 

according to paragraph (o)(1)(i), 

(o)(1)(ii), or (o)(1)(iii) of this section, you 

may elect to continuously measure 

combined volumetric emissions from 

the manifolded group of compressor 

sources as specified in paragraph (o)(5) 

of this section. 

(2) Methods for performing as found 

leak measurements from individual 

centrifugal compressor sources. If 

conducting leak measurements for each 

compressor source, you must determine 

the volumetric emissions of leaks from 

blowdown valves and isolation valves 

as specified in paragraph (o)(2)(i) of this 

section, and the volumetric emissions of 

leaks from wet seal oil degassing vents 

as specified in paragraph (o)(2)(ii) of 

this section. 

(i) For blowdown valves on 

compressors in operating-mode and for 

isolation valves on compressors in notoperating-depressurized-mode, 

determine the volumetric emissions of 

leaks using one of the methods specified 

in paragraphs (o)(2)(i)(A) through 

(o)(2)(i)(C) of this section. 

(A) Measure the volumetric flow at 

standard conditions from the blowdown 

vent using calibrated bagging or high 

volume sampler according to methods 

set forth in § 98.234(c) and § 98.234(d), 

respectively. 

(B) Measure the volumetric flow at 

standard conditions from the blowdown 

vent using a temporary meter such as a 

vane anemometer according to methods 

set forth in § 98.234(b). 

(C) For isolation valves, you may use 

an acoustic leak detection device 

according to methods set forth in 

§ 98.234(a) instead of measuring the 

isolation valve leakage through the 

blowdown vent as provided for in 

paragraphs (o)(2)(i)(A) or (o)(2)(i)(B) of 

this section. 

(ii) For wet seal oil degassing vents in 

operating-mode, determine vapor 

volumes at standard conditions, using a 

temporary meter such as a vane 

anemometer or permanent flow meter 

according to methods set forth in 

§ 98.234(b). 

(3) Methods for continuous leak 

measurement from individual 

centrifugal compressor sources. If you 

elect to conduct continuous volumetric 

emission measurements for an 

individual compressor source as 

specified in paragraph (o)(1)(ii) of this 

section, you must measure volumetric 

emissions as specified in paragraphs 

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

(i) Continuously measure the 

volumetric flow for the individual 

compressor source at standard 

conditions using a permanent meter 

according to methods set forth in 

§ 98.234(b). 

(ii) If compressor blowdown 

emissions are included in the metered 

emissions specified in paragraph 

(o)(3)(i) of this section, the compressor 

blowdown emissions may be included 

with the reported emissions for the 

compressor source and do not need to 


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be calculated separately using the 

method specified in paragraph (i) of this 

section for blowdown vent stacks. 

(4) Methods for performing as found 

leak measurements from manifolded 

groups of centrifugal compressor 

sources. If conducting leak 

measurements for a manifolded group of 

compressor sources, you must measure 

volumetric emissions of leaks as 

specified in paragraphs (o)(4)(i) and 

(o)(4)(ii) of this section. 

(i) Measure at a single point in the 

manifold downstream of all compressor 

inputs and where emissions cannot be 

comingled with other non-compressor 

emission sources. 

(ii) Determine the volumetric flow at 

standard conditions from the common 

stack using one of the methods specified 

in paragraphs (o)(4)(ii)(A) through 

(o)(4)(ii)(C) of this section. 

(A) A temporary meter such as a vane 

anemometer according the methods set 

forth in § 98.234(b). 

(B) Calibrated bagging according to 

methods set forth in § 98.234(c). 

(C) A high volume sampler according 

to methods set forth § 98.234(d). 

(5) Methods for continuous leak 

measurement from manifolded groups 

of centrifugal compressor sources. If you 

elect to conduct continuous volumetric 

emission measurements for a 

manifolded group of compressor sources 

as specified in paragraph (o)(1)(iv) of 

this section, you must measure 

volumetric emissions as specified in 

paragraphs (o)(5)(i) through (o)(5)(iii) of 

this section. 

(i) Measure at a single point in the 

manifold downstream of all compressor 

inputs and where emissions cannot be 

comingled with other non-compressor 

emission sources. 

(ii) Continuously measure the 

volumetric flow for the manifolded 

group of compressor sources at standard 

conditions using a permanent meter 

according to methods set forth in 

§ 98.234(b). 

(iii) If compressor blowdown 

emissions are included in the metered 

emissions specified in paragraph 

(o)(5)(ii) of this section, the compressor 

blowdown emissions may be included 

with the reported emissions for the 

manifolded group of compressor sources 

and do not need to be calculated 

separately using the method specified in 

paragraph (i) of this section for 

blowdown vent stacks. 

(6) Method for calculating volumetric 

GHG emissions from as found leak 

measurements for individual centrifugal 

compressor sources. For compressor 

sources measured according to 

paragraph (o)(1)(i) of this section, you 

must calculate annual GHG emissions 

from the compressor sources as 

specified in paragraphs (o)(6)(i) through 

(o)(6)(iv) of this section. 

(i) Using Equation W–21 of this 

section, calculate the annual volumetric 

GHG emissions for each centrifugal 

compressor mode-source combination 

specified in paragraphs (o)(1)(i)(A) and 

(o)(1)(i)(B) of this section that was 

measured during the reporting year. 

Where: 

Es,i,m = Annual volumetric GHGi (either CH4

or CO2) emissions for measured 

compressor mode-source combination m, 

at standard conditions, in cubic feet. 

MTs,m = Volumetric gas emissions for 

measured compressor mode-source 

combination m, in standard cubic feet 

per hour, measured according to 

paragraph (o)(2) of this section. If 

multiple measurements are performed 

for a given mode-source combination m, 

use the average of all measurements. 

Tm = Total time the compressor is in the 

mode-source combination for which 

Es,i,m is being calculated in the reporting 

year, in hours. 

GHGi,m = Mole fraction of GHGi in the vent 

gas for measured compressor modesource combination m; use the 

appropriate gas compositions in 

paragraph (u)(2) of this section. 

m = Compressor mode-source combination 

specified in paragraph (o)(1)(i)(A) or 

(o)(1)(i)(B) of this section that was 

measured for the reporting year. 

(ii) Using Equation W–22 of this 

section, calculate the annual volumetric 

GHG emissions from each centrifugal 

compressor mode-source combination 

specified in paragraph (o)(1)(i)(A) and 

(o)(1)(i)(B) of this section that was not 

measured during the reporting year. 

Where: 

Es,i,m = Annual volumetric GHGi (either CH4

or CO2) emissions for unmeasured 

compressor mode-source combination m, 

at standard conditions, in cubic feet. 

EFm,s = Reporter emission factor for 

compressor mode-source combination m, 

in standard cubic feet per hour, as 

calculated in paragraph (o)(6)(iii) of this 

section. 

Tm = Total time the compressor was in the 

unmeasured mode-source combination 

m, for which Es,i,m is being calculated in 

the reporting year, in hours. 

GHGi,m = Mole fraction of GHGi in the vent 

gas for unmeasured compressor modesource combination m; use the 

appropriate gas compositions in 

paragraph (u)(2) of this section. 

m = Compressor mode-source combination 

specified in paragraph (o)(1)(i)(A) or 

(o)(1)(i)(B) of this section that was not 

measured in the reporting year. 

(iii) Using Equation W–23 of this 

section, develop an emission factor for 

each compressor mode-source 

combination specified in paragraph 

(o)(1)(i)(A) and (o)(1)(i)(B) of this 

section. These emission factors must be 

used in Equation W–22 of this section 

to determine volumetric emissions from 

a centrifugal compressor in the modesource combinations that were not 

measured in the reporting year. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2EP10MR14.024</GPH> EP10MR14.025</GPH> EP10MR14.026</GPH>
13438 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

Where: 

EFm,s = Reporter emission factor to be used 

in Equation W–22 of this section for 

compressor mode-source combination m, 

in standard cubic feet per hour. The 

reporter emission factor must be based 

on all compressors measured in 

compressor mode-source combination m 

in the current reporting year and the 

preceding two reporting years. 

MTm,p,s = Average volumetric gas emission 

measurement for compressor modesource combination m, for compressor p, 

in standard cubic feet per hour, 

calculated using all volumetric gas 

emission measurements (MTm in 

Equation W–21 of this section) for 

compressor mode-source combination m 

for compressor p in the current reporting 

year and the preceding two reporting 

years. 

Countm = Total number of compressors 

measured in compressor mode-source 

combination m in the current reporting 

year and the preceding two reporting 

years. 

m = Compressor mode-source combination 

specified in paragraph (o)(1)(i)(A) or 

(o)(1)(i)(B) of this section. 

(iv) The reporter emission factor in 

Equation W–23 of this section may be 

calculated by using all measurements 

from a single owner or operator instead 

of only using measurements from a 

single facility. If you elect to use this 

option, the reporter emission factor 

must be applied to all reporting 

facilities for the owner or operator. 

(7) Method for calculating volumetric 

GHG emissions from continuous 

monitoring of individual centrifugal 

compressor sources. For compressor 

sources measured according to 

paragraph (o)(1)(ii) of this section, you 

must use the continuous volumetric 

emission measurements taken as 

specified in paragraph (o)(3) of this 

section and calculate annual volumetric 

GHG emissions associated with the 

compressor source using Equation W– 

24A of this section. 

Where: 

Es,i,v = Annual volumetric GHGi (either CH4

or CO2) emissions from compressor 

source v, at standard conditions, in cubic 

feet. 

Qs,v = Volumetric gas emissions from 

compressor source v, for reporting year, 

in standard cubic feet. 

GHGi,v = Mole fraction of GHGi in the vent 

gas for compressor source v; use the 

appropriate gas compositions in 

paragraph (u)(2) of this section. 

(8) Method for calculating volumetric 

GHG emissions from as found leak 

measurements of manifolded groups of 

centrifugal compressor sources. For 

manifolded groups of compressor 

sources measured according to 

paragraph (o)(1)(iii) of this section, you 

must calculate annual volumetric GHG 

emissions using Equation W–24B of this 

section. 

Where: 

Es,i,g = Annual volumetric GHGi (either CH4

or CO2) emissions for manifolded group 

of compressor sources g, at standard 

conditions, in cubic feet. 

MTg,avg = Average volumetric gas emissions 

of all measurements performed in the 

reporting year according to paragraph 

(o)(4) of this section for the manifolded 

group of compressor sources g, in 

standard cubic feet per hour. 

GHGi,g = Mole fraction of GHGi in the vent 

gas for manifolded group of compressor 

sources g; use the appropriate gas 

compositions in paragraph (u)(2) of this 

section. 

(9) Method for calculating volumetric 

GHG emissions from continuous 

monitoring of manifolded group of 

centrifugal compressor sources. For a 

manifolded group of compressor sources 

measured according to paragraph 

(o)(1)(iv) of this section, you must use 

the continuous volumetric emission 

measurements taken as specified in 

paragraph (o)(5) of this section and 

calculate annual volumetric GHG 

emissions associated with each 

manifolded group of compressor sources 

using Equation W–24C of this section. If 

the centrifugal compressors included in 

the manifolded group of compressor 

sources share the manifold with 

reciprocating compressors, you must 

follow the procedures in either this 

paragraph (o)(9) or paragraph (p)(9) of 

this section to calculate emissions from 

the manifolded group of compressor 

sources. 

Where: 

Es,i,g = Annual volumetric GHGi (either CH4

or CO2) emissions from manifolded 

group of compressor sources g, at 

standard conditions, in cubic feet. 

Qs,g = Volumetric gas emissions from 

manifolded group of compressor sources 

g, for reporting year, in standard cubic 

feet. 

GHGi,g = Mole fraction of GHGi in the vent 

gas for measured manifolded group of 

compressor sources g; use the 

appropriate gas compositions in 

paragraph (u)(2) of this section. 

(10) Method for calculating 

volumetric GHG emissions from wet seal 

oil degassing vents at an onshore 

petroleum and natural gas production 

facility. You must calculate emissions 

from centrifugal compressor wet seal oil 

degassing vents at an onshore petroleum 

and natural gas production facility using 

Equation W–25 of this section. 

Where: 

Es,i = Annual volumetric GHGi (either CH4 or 

CO2) emissions from centrifugal 

compressor wet seals, at standard 

conditions, in cubic feet. 

Count = Total number of centrifugal 

compressors that have wet seal oil 

degassing vents. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2EP10MR14.027</GPH> EP10MR14.028</GPH> EP10MR14.029</GPH> EP10MR14.030</GPH>
Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13439 

EFi,s = Emission factor for GHGi. Use 1.2 × 

107 standard cubic feet per year per 

compressor for CH4 and 5.30 × 105 

standard cubic feet per year per 

compressor for CO2 at 60 °F and 14.7 

psia. 

(11) Method for converting from 

volumetric to mass emissions. You must 

calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

using calculations in paragraph (v) of 

this section. 

(12) General requirements for 

calculating volumetric GHG emissions 

from centrifugal compressors routed to 

flares. You must calculate and report 

emissions from all centrifugal 

compressor sources that are routed to a 

flare as specified in paragraphs (o)(12)(i) 

through (o)(12)(iii) of this section. 

(i) Emissions calculations under this 

paragraph (o) of this section are not 

required for compressor sources that are 

routed to a flare. 

(ii) If any compressor sources are 

routed to a flare, calculate the emissions 

for the flare stack as specified in 

paragraph (n) of this section and report 

emissions from the flare as specified in 

§ 98.236(n), without subtracting 

emissions attributable to compressor 

sources from the flare. 

(iii) Report all applicable activity data 

for compressors with compressor 

sources routed to flares as specified in 

§ 98.236(o). 

(p) Reciprocating compressor venting. 

If you are required to report emissions 

from reciprocating compressor venting 

as specified in § 98.232(d)(1), (e)(1), 

(f)(1), (g)(1), and (h)(1), you must 

conduct volumetric emission 

measurements specified in paragraph 

(p)(1) of this section using methods 

specified in paragraphs (p)(2) through 

(p)(5) of this section; perform 

calculations specified in paragraphs 

(p)(6) through (p)(9) of this section; and 

calculate CH4 and CO2 mass emissions 

as specified in paragraph (p)(11) of this 

section. If emissions from a compressor 

source are routed to a flare, paragraphs 

(p)(1) through (p)(11) of this section do 

not apply and instead you must 

calculate CH4, CO2, and N2O emissions 

as specified in paragraph (p)(12) of this 

section. If emissions from a compressor 

source are captured for fuel use or are 

routed to a thermal oxidizer, paragraphs 

(p)(1) through (p)(12) of this section do 

not apply and instead you must 

calculate and report emissions as 

specified in subpart C of this part. If 

emissions from a compressor source are 

routed to vapor recovery, the 

calculations specified in paragraphs 

(p)(1) through (p)(12) of this section do 

not apply. If you are required to report 

emissions from reciprocating 

compressor venting at an onshore 

petroleum and natural gas production 

facility as specified in § 98.232(c)(11), 

you must calculate volumetric 

emissions as specified in paragraph 

(p)(10) of this section; and calculate CH4

and CO2 mass emissions as specified in 

paragraph (p)(11) of this section. 

(1) General requirements for 

conducting volumetric emission 

measurements. You must conduct 

volumetric emission measurements on 

each reciprocating compressor as 

specified in this paragraph. Compressor 

sources (as defined in § 98.238) without 

manifolded vents must use a 

measurement method specified in 

paragraph (p)(1)(i) or (p)(1)(ii) of this 

section. Manifolded compressor sources 

(as defined in § 98.238) must use a 

measurement method specified in 

paragraph (p)(1)(i), (p)(1)(ii), (p)(1)(iii), 

or (p)(1)(iv) of this section. 

(i) Reciprocating compressor source as 

found leak measurements. Measure 

venting from each compressor according 

to either paragraph (p)(1)(i)(A), 

(p)(1)(i)(B), or (p)(1)(i)(C) of this section 

at least once annually, based on the 

compressor mode (as defined in 

§ 98.238) in which the compressor was 

found at the time of measurement, 

except as specified in paragraph 

(p)(1)(i)(D) of this section. If additional 

measurements beyond the required 

annual testing are performed (including 

duplicate measurements or 

measurement of additional operating 

modes), then all measurements 

satisfying the applicable monitoring and 

QA/QC that is required by this 

paragraph (o) must be used in the 

calculations specified in this section. 

(A) For a compressor measured in 

operating-mode, you must measure 

volumetric emissions from blowdown 

valve leakage through the blowdown 

vent as specified in either paragraph 

(p)(2)(i)(A) or (p)(2)(i)(B) of this section, 

and measure volumetric emissions from 

reciprocating rod packing as specified in 

paragraph (p)(2)(ii) of this section. 

(B) For a compressor measured in 

standby-pressurized-mode, you must 

measure volumetric emissions from 

blowdown valve leakage through the 

blowdown vent as specified in either 

paragraph (p)(2)(i)(A) or (p)(2)(i)(B) of 

this section. 

(C) For a compressor measured in notoperating-depressurized-mode, you 

must measure volumetric emissions 

from isolation valve leakage as specified 

in either paragraph (p)(2)(i)(A), 

(p)(2)(i)(B), or (p)(2)(i)(C) of this section. 

If a compressor is not operated and has 

blind flanges in place throughout the 

reporting period, measurement is not 

required in this compressor mode. 

(D) You must measure the compressor 

as specified in paragraph (p)(1)(i)(C) of 

this section at least once in any three 

consecutive calendar years, provided 

the measurement can be taken during a 

scheduled shutdown. If there is no 

scheduled shutdown within three 

consecutive calendar years, you must 

measure the compressor as specified in 

paragraph (p)(1)(i)(C) of this section 

either prior to or during the next 

compressor shutdown when the 

replacement of the compressor rod 

packing occurs. 

(ii) Reciprocating compressor source 

continuous monitoring. Instead of 

measuring the compressor source 

according to paragraph (p)(1)(i) of this 

section for a given compressor, you may 

elect to continuously measure 

volumetric emissions from a compressor 

source as specified in paragraph (p)(3) 

of this section. 

(iii) Manifolded reciprocating 

compressor source as found leak 

measurements. For a compressor source 

that is part of a manifolded group of 

compressor sources (as defined in 

§ 98.238), instead of measuring the 

compressor source according to 

paragraph (p)(1)(i), (p)(1)(ii), or (p)(1)(iv) 

of this section, you may elect to measure 

combined volumetric emissions from 

the manifolded group of compressor 

sources by conducting leak 

measurements at the common vent stack 

as specified in paragraph (p)(4) of this 

section. The leak measurements must be 

conducted at the frequency specified in 

paragraphs (p)(1)(iii)(A) through 

(p)(1)(iii)(C) of this section. 

(A) A minimum of three leak 

measurements must be taken for each 

manifolded group of compressor sources 

in a calendar year. 

(B) The leak measurements may be 

performed while the compressors are in 

any compressor mode. 

(C) The three required leak 

measurements must be separated by a 

minimum of 60 days. If more than three 

leak measurements are performed, the 

first and last measurements in a 

calendar year must be separated by a 

minimum of 120 days. 

(iv) Manifolded reciprocating 

compressor source continuous 

monitoring. For a compressor source 

that is part of a manifolded group of 

compressor sources, instead of 

measuring the compressor source 

according to paragraph (p)(1)(i), 

(p)(1)(ii), or (p)(1)(iii) of this section, 

you may elect to continuously measure 

combined volumetric emissions from 

the manifolded group of compressors 

sources as specified in paragraph (p)(5) 

of this section. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13440 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

(2) Methods for performing as found 

leak measurements from individual 

reciprocating compressor sources. If 

conducting leak measurements for each 

compressor source, you must determine 

the volumetric emissions of leaks from 

blowdown valves and isolation valves 

as specified in paragraph (p)(2)(i) of this 

section. You must determine the 

volumetric emissions of leaks from 

reciprocating rod packing as specified in 

paragraph (p)(2)(ii) or (p)(2)(iii) of this 

section. 

(i) For blowdown valves on 

compressors in operating-mode or 

standby-pressurized-mode, and for 

isolation valves on compressors in notoperating-depressurized-mode, 

determine the volumetric emissions of 

leaks using one of the methods specified 

in paragraphs (p)(2)(i)(A) through 

(p)(2)(i)(C) of this section. 

(A) Measure the volumetric flow at 

standard conditions from the blowdown 

vent using calibrated bagging or high 

volume sampler according to methods 

set forth in § 98.234(c) and § 98.234(d), 

respectively. 

(B) Measure the volumetric flow at 

standard conditions from the blowdown 

vent using a temporary meter such as a 

vane anemometer, according to methods 

set forth in § 98.234(b). 

(C) For isolation valves, you may use 

an acoustic leak detection device 

according to methods set forth in 

§ 98.234(a) instead of measuring the 

isolation valve leakage through the 

blowdown vent as provided for in 

paragraphs (p)(2)(i)(A) or (p)(2)(i)(B) of 

this section. 

(ii) For reciprocating rod packing 

equipped with an open-ended vent line 

on compressors in operating-mode, 

determine the volumetric emissions of 

leaks using one of the methods specified 

in paragraphs (p)(2)(ii)(A) and 

(p)(2)(ii)(B) of this section. 

(A) Measure the volumetric flow at 

standard conditions from the openended vent line using calibrated bagging 

or high volume sampler according to 

methods set forth in § 98.234(c) and 

§ 98.234(d), respectively. 

(B) Measure the volumetric flow at 

standard conditions from the openended vent line using a temporary meter 

such as a vane anemometer, according 

to methods set forth in § 98.234(b). 

(iii) For reciprocating rod packing not 

equipped with an open-ended vent line 

on compressors in operating-mode, you 

must determine the volumetric 

emissions of leaks using the method 

specified in paragraphs (p)(2)(iii)(A) and 

(p)(2)(iii)(B) of this section. 

(A) You must use the methods 

described in § 98.234(a) to conduct 

annual leak detection of equipment 

leaks from the packing case into an open 

distance piece, or from the compressor 

crank case breather cap or other vent 

with a closed distance piece. 

(B) You must measure emissions 

found in paragraph (p)(2)(iii)(A) of this 

section using an appropriate meter, 

calibrated bag, or high volume sampler 

according to methods set forth in 

§ 98.234(b), (c), and (d), respectively. 

(3) Methods for continuous leak 

measurement from individual 

reciprocating compressor sources. If you 

elect to conduct continuous volumetric 

emission measurements for an 

individual compressor source as 

specified in paragraph (p)(1)(ii) of this 

section, you must measure volumetric 

emissions as specified in paragraphs 

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

(i) Continuously measure the 

volumetric flow for the individual 

compressor sources at standard 

conditions using a permanent meter 

according to methods set forth in 

§ 98.234(b). 

(ii) If compressor blowdown 

emissions are included in the metered 

emissions specified in paragraph 

(p)(3)(i) of this section, the compressor 

blowdown emissions may be included 

with the reported emissions for the 

compressor source and do not need to 

be calculated separately using the 

method specified in paragraph (i) of this 

section for blowdown vent stacks. 

(4) Methods for performing as found 

leak measurements from manifolded 

groups of reciprocating compressor 

sources. If conducting leak 

measurements for a manifolded group of 

compressor sources, you must measure 

volumetric emissions of leaks as 

specified in paragraphs (p)(4)(i) and 

(p)(4)(ii) of this section. 

(i) Measure at a single point in the 

manifold downstream of all compressor 

inputs and where emissions cannot be 

comingled with other non-compressor 

emission sources. 

(ii) Determine the volumetric flow at 

standard conditions from the common 

stack using one of the methods specified 

in paragraph (p)(4)(ii)(A) through 

(p)(4)(ii)(C). 

(A) A temporary meter such as a vane 

anemometer according the methods set 

forth in § 98.234(b). 

(B) Calibrated bagging according to 

methods set forth in § 98.234(c). 

(C) A high volume sampler according 

to methods set forth § 98.234(d). 

(5) Methods for continuous leak 

measurement from manifolded groups 

of reciprocating compressor sources. If 

you elect to conduct continuous 

volumetric emission measurements for a 

manifolded group of compressor sources 

as specified in paragraph (p)(1)(iv) of 

this section, you must measure 

volumetric emissions as specified in 

paragraphs (p)(5)(i) through (p)(5)(iii) of 

this section. 

(i) Measure at a single point in the 

manifold downstream of all compressor 

inputs and where emissions cannot be 

comingled with other non-compressor 

emission sources. 

(ii) Continuously measure the 

volumetric flow for the manifolded 

group of compressor sources at standard 

conditions using a permanent meter 

according to methods set forth in 

§ 98.234(b). 

(iii) If compressor blowdown 

emissions are included in the metered 

emissions specified in paragraph 

(p)(5)(ii) of this section, the compressor 

blowdown emissions may be included 

with the reported emissions for the 

manifolded group of compressor sources 

and do not need to be calculated 

separately using the method specified in 

paragraph (i) of this section for 

blowdown vent stacks. 

(6) Method for calculating volumetric 

GHG emissions from as found leak 

measurements for individual 

reciprocating compressor sources. For 

compressor sources measured according 

to paragraph (p)(1)(i) of this section, you 

must calculate GHG emissions from the 

compressor sources as specified in 

paragraphs (p)(6)(i) through (p)(6)(iv) of 

this section. 

(i) Using Equation W–26 of this 

section, calculate the annual volumetric 

GHG emissions for each reciprocating 

compressor mode-source combination 

specified in paragraphs (p)(1)(i)(A) 

through (p)(1)(i)(C) of this section that 

was measured during the reporting year. 

Where: 

Es,i,m = Annual volumetric GHGi (either CH4

or CO2) emissions for measured 

compressor mode-source combination m, 

at standard conditions, in cubic feet. 

MTs,m = Volumetric gas emissions for 

measured compressor mode-source 

combination m, in standard cubic feet 


emcdonald on DSK67QTVN1PROD with PROPOSALS2EP10MR14.031</GPH>
Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13441 

per hour, measured according to 

paragraph (p)(2) of this section. If 

multiple measurements are performed 

for a given mode-source combination m, 

use the average of all measurements. 

Tm = Total time the compressor is in the 

mode-source combination m, for which 

Es,i,m is being calculated in the reporting 

year, in hours. 

GHGi,m = Mole fraction of GHGi in the vent 

gas for measured compressor modesource combination m; use the 

appropriate gas compositions in 

paragraph (u)(2) of this section. 

m = Compressor mode-source combination 

specified in paragraph (p)(1)(i)(A), 

(p)(1)(i)(B), or (p)(1)(i)(C) of this section 

that was measured for the reporting year. 

(ii) Using Equation W–27 of this 

section, calculate the annual volumetric 

GHG emissions from each reciprocating 

compressor mode-source combination 

specified in paragraph (p)(1)(i)(A), 

(p)(1)(i)(B), and (p)(1)(i)(C) of this 

section that was not measured during 

the reporting year. 

Where: 

Es,i,m = Annual volumetric GHGi (either CH4

or CO2) emissions for unmeasured 

compressor mode-source combination m, 

at standard conditions, in cubic feet. 

EFm,s = Reporter emission factor for 

compressor mode-source combination m, 

in standard cubic feet per hour, as 

calculated in paragraph (p)(6)(iii) of this 

section. 

Tm = Total time the compressor was in the 

unmeasured mode-source combination 

m, for which Es,i,m is being calculated in 

the reporting year, in hours. 

GHGi,m = Mole fraction of GHGi in the vent 

gas for unmeasured compressor modesource combination m; use the 

appropriate gas compositions in 

paragraph (u)(2) of this section. 

m = Compressor mode-source combination 

specified in paragraph (p)(1)(i)(A), 

(p)(1)(i)(B), or (p)(1)(i)(C) of this section 

that was not measured in the reporting 

year. 

(iii) Using Equation W–28 of this 

section, develop an emission factor for 

each compressor mode-source 

combination specified in paragraph 

(p)(1)(i)(A), (p)(1)(i)(B), and (p)(1)(i)(C) 

of this section. These emission factors 

must be used in Equation W–27 of this 

section to determine volumetric 

emissions from a reciprocating 

compressor in the mode-source 

combinations that were not measured in 

the reporting year. 

Where: 

EFm,s = Reporter emission factor to be used 

in Equation W–27 of this section for 

compressor mode-source combination m, 

in standard cubic feet per hour. The 

reporter emission factor must be based 

on all compressors measured in 

compressor mode-source combination m 

in the current reporting year and the 

preceding two reporting years. 

MTm,p,s = Average volumetric gas emission 

measurement for compressor modesource combination m, for compressor p, 

in standard cubic feet per hour, 

calculated using all volumetric gas 

emission measurements (MTm in 

Equation W–26 of this section) for 

compressor mode-source combination m 

for compressor p in the current reporting 

year and the preceding two reporting 

years. 

Countm = Total number of compressors 

measured in compressor mode-source 

combination m in the current reporting 

year and the preceding two reporting 

years. 

m = Compressor mode-source combination 

specified in paragraph (p)(1)(i)(A), 

(p)(1)(i)(B), or (p)(1)(i)(C) of this section. 

(A) Emission factors must be 

calculated annually for each compressor 

mode-source combination specified in 

paragraph ((p)(1)(i)(A), (p)(1)(i)(B), and 

(p)(1)(i)(C) of this section. 

(B) You must combine emissions for 

blowndown vents, measured in the 

operating and standby-pressurized 

modes. 

(iv) The reporter emission factor in 

Equation W–28 of this section may be 

calculated by using all measurements 

from a single owner or operator instead 

of only using measurements from a 

single facility. If you elect to use this 

option, the reporter emission factor 

must be applied to all reporting 

facilities for the owner or operator. 

(7) Method for calculating volumetric 

GHG emissions from continuous 

monitoring of individual reciprocating 

compressor sources. For compressor 

sources measured according to 

paragraph (p)(1)(ii) of this section, you 

must use the continuous volumetric 

emission measurements taken as 

specified in paragraph (p)(3) of this 

section and calculate annual volumetric 

GHG emissions associated with the 

compressor source using Equation W– 

29A of this section. 

Where: 

Es,i,v = Annual volumetric GHGi (either CH4

or CO2) emissions from compressor 

source v, at standard conditions, in cubic 

feet. 

Qs,v = Volumetric gas emissions from 

compressor source v, for reporting year, 

in standard cubic feet. 

GHGi,v = Mole fraction of GHGi in the vent 

gas for compressor source v; use the 

appropriate gas compositions in 

paragraph (u)(2) of this section. 

(8) Method for calculating volumetric 

GHG emissions from as found leak 

measurements of manifolded groups of 

reciprocating compressor sources. For 

manifolded groups of compressor 

sources measured according to 

paragraph (p)(1)(iii) of this section, you 

must calculate annual GHG emissions 

using Equation W–29B of this section. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2EP10MR14.032</GPH> EP10MR14.033</GPH> EP10MR14.034</GPH>
13442 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

Where: 

Es,i,g = Annual volumetric GHGi (either CH4

or CO2) emissions for manifolded group 

of compressor sources g, at standard 

conditions, in cubic feet. 

MTg,avg = Average volumetric gas emissions 

of all measurements performed in the 

reporting year according to paragraph 

(p)(4) of this section for the manifolded 

group of compressor sources g, in 

standard cubic feet per hour. 

GHGi,g = Mole fraction of GHGi in the vent 

gas for manifolded group of compressor 

sources g; use the appropriate gas 

compositions in paragraph (u)(2) of this 

section. 

(9) Method for calculating volumetric 

GHG emissions from continuous 

monitoring of manifolded group of 

reciprocating compressor sources. For a 

manifolded group of compressor sources 

measured according to paragraph 

(p)(1)(iv) of this section, you must use 

the continuous volumetric emission 

measurements taken as specified in 

paragraph (p)(5) of this section and 

calculate annual volumetric GHG 

emissions associated with each 

manifolded group of compressor sources 

using Equation W–29C of this section. If 

the reciprocating compressors included 

in the manifolded group of compressor 

sources share the manifold with 

centrifugal compressors, you must 

follow the procedures in either this 

paragraph (p)(9) or paragraph (o)(9) of 

this section to calculate emissions from 

the manifolded group of compressor 

sources. 

Where: 

Es,i,g = Annual volumetric GHGi (either CH4

or CO2) emissions from manifolded 

group of compressor sources g, at 

standard conditions, in cubic feet. 

Qs,g = Volumetric gas emissions from 

manifolded group of compressor sources 

g, for reporting year, in standard cubic 

feet. 

GHGi,g = Mole fraction of GHGi in the vent 

gas for measured manifolded group of 

compressor sources g; use the 

appropriate gas compositions in 

paragraph (u)(2) of this section. 

(10) Method for calculating 

volumetric GHG emissions from 

reciprocating compressor venting at an 

onshore petroleum and natural gas 

production facility. You must calculate 

emissions from reciprocating 

compressor venting at an onshore 

petroleum and natural gas production 

facility using Equation W–29D of this 

section. 

Where: 

Es,i = Annual volumetric GHGi (either CH4 or 

CO2) emissions from reciprocating 

compressors, at standard conditions, in 

cubic feet. 

Count = Total number of reciprocating 

compressors. 

EFi,s = Emission factor for GHGi. Use 9.48 × 

103 standard cubic feet per year per 

compressor for CH4 and 5.27 × 102

standard cubic feet per year per 

compressor for CO2 at 60 °F and 14.7 

psia. 

(11) Method for converting from 

volumetric to mass emissions. You must 

calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

using calculations in paragraph (v) of 

this section. 

(12) General requirements for 

calculating volumetric GHG emissions 

from reciprocating compressors routed 

to flares. You must calculate and report 

emissions from all reciprocating 

compressor sources that are routed to a 

flare as specified in paragraphs (p)(12)(i) 

through (p)(12)(iii) of this section. 

(i) Emissions calculations under this 

paragraph (p) of this section are not 

required for compressor sources that are 

routed to a flare. 

(ii) If any compressor sources are 

routed to a flare, calculate the emissions 

for the flare stack as specified in 

paragraph (n) of this section and report 

emissions from the flare as specified in 

§ 98.236(n), without subtracting 

emissions attributable to compressor 

sources from the flare. 

(iii) Report all applicable activity data 

for compressors with compressor 

sources routed to flares as specified in 

§ 98.236(p). 

(q) Equipment leak surveys. You must 

use the methods described in § 98.234(a) 

to conduct leak detection(s) of 

equipment leaks from all component 

types listed in § 98.232(d)(7), (e)(7), 

(f)(5), (g)(3), (h)(4), and (i)(1). This 

paragraph (q) applies to component 

types in streams with gas content greater 

than 10 percent CH4 plus CO2 by 

weight. Component types in streams 

with gas content less than or equal to 10 

percent CH4 plus CO2 by weight are 

exempt from the requirements of this 

paragraph (q) and do not need to be 

reported. Tubing systems equal to or 

less than one half inch diameter are 

exempt from the requirements of this 

paragraph (q) and do not need to be 

reported. For industry segments listed 

in § 98.230(a)(3) through (a)(8), if 

equipment leaks are detected for 

component types listed in this 

paragraph (q), then you must calculate 

equipment leak emissions per 

component type per reporting facility 

using Equations W–30 of this section. 

For the industry segment listed in 

§ 98.230(a)(8), the results from Equation 

W–30 are used to calculate population 

emission factors on a meter/regulator 

run basis using Equation W–31 of this 

section. 

Where: Es,p,i = Annual total volumetric emissions of 

GHGi from specific component type ‘‘p’’ 

(listed in § 98.232(d)(7), (e)(7), (f)(5), 

(g)(3), (h)(4), and (i)(1)) in standard (‘‘s’’) 


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cubic feet, as specified in paragraphs 

(q)(1) through (q)(8) of this section. 

xp = Total number of specific component 

type ‘‘p’’ detected as leaking during 

annual leak surveys. 

EFs,p = Leaker emission factor for specific 

component types listed in Table W–2 

through Table W–7 of this subpart. 

GHGi = For onshore natural gas processing 

facilities, concentration of GHGi, CH4 or 

CO2, in the total hydrocarbon of the feed 

natural gas; for onshore natural gas 

transmission compression and 

underground natural gas storage, GHGi

equals 0.975 for CH4 and 1.1 × 10¥2 for 

CO2 ; for LNG storage and LNG import 

and export equipment, GHGi equals 1 for 

CH4 and 0 for CO2 ; and for natural gas 

distribution, GHGi equals 1 for CH4 and 

1.1 × 10¥2 CO2. 

Tp,z = The total time the surveyed component 

‘‘z’’, component type ‘‘p’’, was found 

leaking and operational, in hours. If one 

leak detection survey is conducted in the 

calendar year, assume the component 

was leaking for the entire calendar year, 

accounting for time the component was 

not operational (i.e. not operating under 

pressure) using engineering estimate 

based on best available data. If multiple 

leak detection surveys are conducted in 

the calendar year, assume that the 

component found to be leaking has been 

leaking since the previous survey (if not 

found leaking in the previous survey) or 

the beginning of the calendar year (if it 

was found leaking in the previous 

survey), accounting for time the 

component was not operational using 

engineering estimate based on best 

available data. For the last leak detection 

survey in the calendar year, assume that 

all leaking components continue to leak 

until the end of the calendar year, 

accounting for time the component was 

not operational using engineering 

estimate based on best available data. 

(1) You must conduct either one leak 

detection survey in a calendar year or 

multiple complete leak detection 

surveys in a calendar year. The leak 

detection surveys selected must be 

conducted during the calendar year. 

(2) Calculate both CO2 and CH4 mass 

emissions using calculations in 

paragraph (v) of this section. 

(3) Onshore natural gas processing 

facilities must use the appropriate 

default total hydrocarbon leaker 

emission factors for compressor 

components in gas service and noncompressor components in gas service 

listed in Table W–2 of this subpart. 

(4) Onshore natural gas transmission 

compression facilities must use the 

appropriate default total hydrocarbon 

leaker emission factors for compressor 

components in gas service and noncompressor components in gas service 

listed in Table W–3 of this subpart. 

(5) Underground natural gas storage 

facilities must use the appropriate 

default total hydrocarbon leaker 

emission factors for storage stations in 

gas service listed in Table W–4 of this 

subpart. 

(6) LNG storage facilities must use the 

appropriate default methane leaker 

emission factors for LNG storage 

components in gas service listed in 

Table W–5 of this subpart. 

(7) LNG import and export facilities 

must use the appropriate default 

methane leaker emission factors for LNG 

terminals components in LNG service 

listed in Table W–6 of this subpart. 

(8) Natural gas distribution facilities 

must use Equation W–30 of this section 

and the default methane leaker emission 

factors for transmission-distribution 

transfer station components in gas 

service listed in Table W–7 of this 

subpart to calculate component 

emissions from annual equipment leak 

surveys conducted at above grade 

transmission-distribution transfer 

stations. Natural gas distribution 

facilities are required to perform 

equipment leak surveys only at above 

grade stations that qualify as 

transmission-distribution transfer 

stations. Below grade transmissiondistribution transfer stations and all 

metering-regulating stations that do not 

meet the definition of transmissiondistribution transfer stations are not 

required to perform equipment leak 

surveys under this section. 

(i) Natural gas distribution facilities 

may choose to conduct equipment leak 

surveys at all above grade transmissiondistribution transfer stations over 

multiple years, not exceeding a five year 

period to cover all above grade 

transmission-distribution transfer 

stations. If the facility chooses to use the 

multiple year option, then the number 

of transmission-distribution transfer 

stations that are monitored in each year 

should be approximately equal across 

all years in the cycle. 

(ii) Use Equation W–31 to determine 

the meter/regulator run population 

emission factors for each GHGi. The 

meter/regulator run population 

emission factors calculated using 

Equation W–31 must be used in 

Equation W–32B of this section to 

estimate emissions from above grade 

metering-regulating stations that are not 

transmission-distribution transfer 

stations. As additional survey data 

become available, you must recalculate 

the meter/regulator run population 

emission factors for each GHGi annually 

according to paragraph (q)(8)(iii) of this 

section. 

Where: 

EFs,MR,i = Meter/regulator run population 

emission factor for GHGi based on all 

surveyed above grade transmissiondistribution transfer stations over ‘‘n’’ 

years, in standard cubic feet of GHGi per 

operational hour of all meter/regulator 

runs. 

Es,p,i,y = Annual total volumetric emissions at 

standard conditions of GHGi from 

component type ‘‘p’’ during year ‘‘y’’ in 

standard (‘‘s’’) cubic feet, as calculated 

using Equation W–30 of this section. 

p = Seven component types listed in Table 

W–7 of this subpart for transmissiondistribution transfer stations. 

Tw,y = The total time the surveyed meter/

regulator run ‘‘w’’ was operational, in 

hours during survey year ‘‘y’’ using 

engineering estimate based on best 

available data. 

CountMR,y = Count of meter/regulator runs 

surveyed at above grade transmissiondistribution transfer stations in year ‘‘y’’. 

y = Year of data included in emission factor 

‘‘EFs,MR,i’’ according to paragraph 

(q)(8)(iii) of this section. 

n = Number of years of data used to calculate 

emission factor ‘‘EFs,MR,i’’ according to 

paragraph (q)(8)(iii) of this section. 

(iii) The emission factor ‘‘EFs,MR,i’’, 

based on annual equipment leak surveys 

at above grade transmission-distribution 

transfer stations, must be calculated 

annually. If the facility has submitted a 

smaller number of annual reports than 

the duration of the selected cycle period 

(up to 5 years), then all available data 

from the current year and previous years 

must be used in the emission 


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calculation. After the first cycle is 

completed, the survey will continue on 

a rolling basis by including the 

measurements from the current calendar 

year and as many of the previous 

calendar years as are needed to 

complete the survey cycle. 

(r) Equipment leaks by population 

count. This paragraph applies to 

emissions sources listed in § 98.232 

(c)(21), (f)(5), (g)(3), (h)(4), (i)(2), (i)(3), 

(i)(4), (i)(5), and (i)(6) on streams with 

gas content greater than 10 percent CH4

plus CO2 by weight. Emissions sources 

in streams with gas content less than or 

equal to 10 percent CH4 plus CO2 by 

weight are exempt from the 

requirements of this paragraph (q) do 

not need to be reported. Tubing systems 

equal to or less than one half inch 

diameter are exempt from the 

requirements of paragraph (r) of this 

section and do not need to be reported. 

You must calculate emissions from all 

emission sources listed in this 

paragraph using Equation W–32A of this 

section, except for natural gas 

distribution facility emission sources 

listed in § 98.232(i)(3). Natural gas 

distribution facility emission sources 

listed in § 98.232(i)(3) must calculate 

emissions using Equation W–32B and 

according to paragraph (r)(6) of this 

section. 

Where: 

Es,e,i = Annual volumetric emissions of GHGi

from the emission source type in 

standard cubic feet. The emission source 

type may be a component (e.g. 

connector, open-ended line, etc.), below 

grade metering-regulating station, below 

grade transmission-distribution transfer 

station, distribution main, or distribution 

service. 

Es,MR,i = Annual volumetric emissions of 

GHGi from all meter/regulator runs at 

above grade metering regulating stations 

that are not above grade transmission 

distribution transfer stations, in standard 

cubic feet. 

Counte = Total number of the emission 

source type at the facility. For onshore 

petroleum and natural gas production 

facilities, average component counts are 

provided by major equipment piece in 

Tables W–1B and Table W–1C of this 

subpart. Use average component counts 

as appropriate for operations in Eastern 

and Western U.S., according to Table W– 

1D of this subpart. Underground natural 

gas storage facilities must count each 

component listed in Table W–4 of this 

subpart. LNG storage facilities must 

count the number of vapor recovery 

compressors. LNG import and export 

facilities must count the number of vapor 

recovery compressors. Natural gas 

distribution facilities must count: (1) The 

number of distribution services by 

material type; (2) miles of distribution 

mains by material type; and (3) number 

of below grade metering-regulating 

stations, by pressure type; as listed in 

Table W–7 of this subpart. 

CountMR = Total number of meter/regulator 

runs at above grade metering-regulating 

stations that are not above grade 

transmission-distribution transfer 

stations. 

EFs,e = Population emission factor for the 

specific emission source type, as listed 

in Tables W–1A and W–4 through W–7 

of this subpart. Use appropriate 

population emission factor for operations 

in Eastern and Western U.S., according 

to Table W–1D of this subpart. 

EFs,MR,i = Meter/regulator run population 

emission factor for GHGi based on all 

surveyed above grade transmissiondistribution transfer stations over ‘‘n’’ 

years, in standard cubic feet of GHGi per 

operational hour of all meter/regulator 

runs., as determined in Equation W–31. 

GHGi = For onshore petroleum and natural 

gas production facilities, concentration 

of GHGi, CH4, or CO2, in produced 

natural gas as defined in paragraph (u)(2) 

of this section; for onshore natural gas 

transmission compression and 

underground natural gas storage, GHGi

equals 0.975 for CH4 and 1.1 × 10¥2 for 

CO2; for LNG storage and LNG import 

and export equipment, GHGi equals 1 for 

CH4 and 0 for CO2; and for natural gas 

distribution, GHGi equals 1 for CH4 and 

1.1 × 10¥2CO2. 

Te = Average estimated time that each 

emission source type associated with the 

equipment leak emission was 

operational in the calendar year, in 

hours, using engineering estimate based 

on best available data. 

Tw,avg = Average estimated time that each 

meter/regulator run was operational in 

the calendar year, in hours per meter/

regulator run, using engineering estimate 

based on best available data. 

(1) Calculate both CH4 and CO2 mass 

emissions from volumetric emissions 

using calculations in paragraph (v) of 

this section. 

(2) Onshore petroleum and natural gas 

production facilities must use the 

appropriate default whole gas 

population emission factors listed in 

Table W–1A of this subpart. Major 

equipment and components associated 

with gas wells are considered gas 

service components in reference to 

Table W–1A of this subpart and major 

natural gas equipment in reference to 

Table W–1B of this subpart. Major 

equipment and components associated 

with crude oil wells are considered 

crude service components in reference 

to Table W–1A of this subpart and major 

crude oil equipment in reference to 

Table W–1C of this subpart. Where 

facilities conduct EOR operations the 

emissions factor listed in Table W–1A of 

this subpart shall be used to estimate all 

streams of gases, including recycle CO2

stream. The component count can be 

determined using either of the 

calculation methods described in this 

paragraph (r)(2). The same calculation 

method must be used for the entire 

calendar year. 

(i) Component Count Method 1. For 

all onshore petroleum and natural gas 

production operations in the facility 

perform the following activities: 

(A) Count all major equipment listed 

in Table W–1B and Table W–1C of this 

subpart. For meters/piping, use one 

meters/piping per well-pad. 

(B) Multiply major equipment counts 

by the average component counts listed 

in Table W–1B and W–1C of this 

subpart for onshore natural gas 

production and onshore oil production, 

respectively. Use the appropriate factor 

in Table W–1A of this subpart for 

operations in Eastern and Western U.S. 

according to the mapping in Table W– 

1D of this subpart. 

(ii) Component Count Method 2. 

Count each component individually for 

the facility. Use the appropriate factor in 

Table W–1A of this subpart for 

operations in Eastern and Western U.S. 

according to the mapping in Table W– 

1D of this subpart. 

(3) Underground natural gas storage 

facilities must use the appropriate 

default total hydrocarbon population 

emission factors for storage wellheads in 

gas service listed in Table W–4 of this 

subpart. 

(4) LNG storage facilities must use the 

appropriate default methane population 

emission factor for LNG storage 

compressors in gas service listed in 

Table W–5 of this subpart. 

(5) LNG import and export facilities 

must use the appropriate default 

methane population emission factor for 

LNG terminal compressors in gas 

service listed in Table W–6 of this 

subpart. 


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(6) Natural gas distribution facilities 

must use the appropriate methane 

emission factors as described in 

paragraph (r)(6) of this section. 

(i) Below grade metering-regulating 

stations, distribution mains, and 

distribution services must use the 

appropriate default methane population 

emission factors listed in Table W–7 of 

this subpart. Below grade transmissiondistribution transfer stations must use 

the emission factor for below grade 

metering-regulating stations. 

(ii) Above grade metering-regulating 

stations (that are not above grade 

transmission-distribution transfer 

stations) must use the meter/regulator 

run population emission factor 

calculated in Equation W–31. Natural 

gas distribution facilities that do not 

have above grade transmissiondistribution transfer stations are not 

required to calculate emissions for 

above grade metering-regulating 

stations. 

(s) * * * 

(2) Offshore production facilities that 

are not under BOEMRE jurisdiction 

must use the most recent monitoring 

methods and calculation methods 

published by BOEMRE referenced in 30 

CFR 250.302 through 304 to calculate 

and report annual emissions (GOADS). 

(i) For any calendar year that does not 

overlap with the most recent BOEMRE 

emissions study publication, you may 

report the most recently reported 

emissions data submitted to 

demonstrate compliance with this 

subpart of part 98, with emissions 

adjusted based on the operating time for 

the facility relative to operating time in 

the previous reporting period. 

* * * * * 

(3) If BOEMRE discontinues or delays 

their data collection effort by more than 

4 years, then offshore reporters shall 

once in every 4 years use the most 

recent BOEMRE data collection and 

emissions estimation methods to 

estimate emissions. These emission 

estimates would be used to report 

emissions from the facility sources as 

required in paragraph (s)(1)(i) of this 

section. 

(4) For either first or subsequent year 

reporting, offshore facilities either 

within or outside of BOEMRE 

jurisdiction that were not covered in the 

previous BOEMRE data collection cycle 

must use the most recent BOEMRE data 

collection and emissions estimation 

methods published by BOEMRE 

referenced in 30 CFR 250.302 through 

304 to calculate and report emissions. 

(t) GHG volumetric emissions using 

actual conditions. If equation 

parameters in § 98.233 are already at 

standard conditions, which results in 

volumetric emissions at standard 

conditions, then this paragraph does not 

apply. Calculate volumetric emissions at 

standard conditions as specified in 

paragraphs (t)(1) or (2) of this section, 

with actual pressure and temperature 

determined by engineering estimates 

based on best available data unless 

otherwise specified. 

(1) * * * 

* * * * * 

Za = Compressibility factor at actual 

conditions for natural gas. You may use 

1 if the temperature is above -10 degrees 

Fahrenheit and pressure is below 5 

atmospheres, or if the compressibility 

factor at the actual temperature and 

pressure is 0.98 or greater. 

(2) * * * 

* * * * * 

Za = Compressibility factor at actual 

conditions for GHG i. You may use 1 if 

the compressibility factor at the actual 

temperature and pressure is 0.98 or 

greater. 

* * * * * 

(u) GHG volumetric emissions at 

standard conditions. Calculate GHG 

volumetric emissions at standard 

conditions as specified in paragraphs 

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

(2) * * * 

(iii) GHG mole fraction in 

transmission pipeline natural gas that 

passes through the facility for the 

onshore natural gas transmission 

compression industry segment. You may 

use either a default 95 percent methane 

and 1 percent carbon dioxide fraction 

for GHG mole fraction in natural gas or 

site specific engineering estimates based 

on best available data. 

* * * * * 

(v) GHG mole fraction in natural gas 

stored in the LNG storage industry 

segment. You may use either a default 

95 percent methane and 1 percent 

carbon dioxide fraction for GHG mole 

fraction in natural gas or site specific 

engineering estimates based on best 

available data. 

(vi) GHG mole fraction in natural gas 

stored in the LNG import and export 

industry segment. For export facilities 

that receive gas from transmission 

pipelines, you may use either a default 

95 percent methane and 1 percent 

carbon dioxide fraction for GHG mole 

fraction in natural gas or site specific 

engineering estimates based on best 

available data. 

(vii) GHG mole fraction in local 

distribution pipeline natural gas that 

passes through the facility for natural 

gas distribution facilities. You may use 

a default 95 percent methane and 1 

percent carbon dioxide fraction for GHG 

mole fraction in natural gas or site 

specific engineering estimates based on 

best available data. 

(v) GHG mass emissions. Calculate 

GHG mass emissions in metric tons by 

converting the GHG volumetric 

emissions at standard conditions into 

mass emissions using Equation W–36 of 

this section. 


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Where: 

Massi = GHGi (either CH4, CO2, or N2O) mass 

emissions in metric tons. 

Es,i = GHGi (either CH4, CO2, or N2O) 

volumetric emissions at standard 

conditions, in cubic feet. 

Pi = Density of GHGi. Use 0.0526 kg/ft3 for 

CO2 and N2O, and 0.0192 kg/ft3 for CH4

at 60 °F and 14.7 psia. 

(w) EOR injection pump blowdown. 

Calculate CO2 pump blowdown 

emissions from each EOR injection 

pump system as follows: 

(1) Calculate the total injection pump 

system volume in cubic feet (including 

pipelines, manifolds and vessels) 

between isolation valves. 

* * * * * 

(3) Calculate the total annual CO2

emissions from each EOR injection 

pump system using Equation W–37 of 

this section: 

* * * * * 

MassCO2 = Annual EOR injection pump 

system emissions in metric tons from 

blowdowns. 

N = Number of blowdowns for the EOR 

injection pump system in the calendar 

year. 

Vv = Total volume in cubic feet of EOR 

injection pump system chambers 

(including pipelines, manifolds and 

vessels) between isolation valves. 

* * * * * 

(x) EOR hydrocarbon liquids 

dissolved CO2. Calculate CO2 emissions 

downstream of the storage tank from 

dissolved CO2 in hydrocarbon liquids 

produced through EOR operations as 

follows: 

(1) Determine the amount of CO2

retained in hydrocarbon liquids after 

flashing in tankage at STP conditions. 

Annual samples of hydrocarbon liquids 

downstream of the storage tank must be 

taken according to methods set forth in 

§ 98.234(b) to determine retention of 

CO2 in hydrocarbon liquids 

immediately downstream of the storage 

tank. Use the annual analysis for the 

calendar year. 

(2) * * * 

* * * * * 

Shl = Amount of CO2 retained in 

hydrocarbon liquids downstream of the 

storage tank, in metric tons per barrel, under 

standard conditions. 

* * * * * 

(z) * * * 

(1) If a fuel combusted in the 

stationary or portable equipment is 

listed in Table C–1 of subpart C of this 

part, or is a blend containing one or 

more fuels listed in Table C–1, calculate 

emissions according to paragraph 

(z)(1)(i) of this section. If the fuel 

combusted is natural gas and is of 

pipeline quality specification and has a 

minimum high heat value of 950 Btu per 

standard cubic foot, use the calculation 

method described in paragraph (z)(1)(i) 

of this section and you may use the 

emission factor provided for natural gas 

as listed in Table C–1. If the fuel is 

natural gas, and is not pipeline quality 

or has a high heat value of less than 950 

Btu per standard cubic feet, calculate 

emissions according to paragraph (z)(2) 

of this section. If the fuel is field gas, 

process vent gas, or a blend containing 

field gas or process vent gas, calculate 

emissions according to paragraph (z)(2) 

of this section. 

(i) For fuels listed in Table C–1 or a 

blend containing one or more fuels 

listed in Table C–1, calculate CO2, CH4, 

and N2O emissions according to any 

Tier listed in subpart C of this part. You 

must follow all applicable calculation 

requirements for that tier listed in 

§ 98.33, any monitoring or QA/QC 

requirements listed for that tier in 

§ 98.34, any missing data procedures 

specified in § 98.35, and any 

recordkeeping requirements specified in 

§ 98.37. 

(ii) Emissions from fuel combusted in 

stationary or portable equipment at 

onshore natural gas and petroleum 

production facilities and at natural gas 

distribution facilities will be reported 

according to the requirements specified 

in § 98.236(c)(19) and not according to 

the reporting requirements specified in 

subpart C of this part. 

(2) * * * 

(iii) * * * 

* * * * * 

Va = Volume of gas sent to combustion unit 

in actual cubic feet, during the year. 

YCO2 = Mole fraction of CO2 constituent in 

gas sent to combustion unit. 

* * * * * 

Yj = Mole fraction of gas hydrocarbon 

constituents j (such as methane, ethane, 

propane, butane, and pentanes plus) in 

gas sent to combustion unit. 

* * * * * 

YCH4 = Mole fraction of methane constituent 

in gas sent to combustion unit. 

* * * * * 

(vi) * * * 

* * * * * 

MassN2O = Annual N2O emissions from the 

combustion of a particular type of fuel 

(metric tons). 

Fuel = Annual mass or volume of the fuel 

combusted (mass or volume per year, 

choose appropriately to be consistent 

with the units of HHV). 

HHV = Higher heating value of fuel, mmBtu/ 

unit of fuel (in units consistent with the 

fuel quantity combusted). For the higher 

heating value for field gas or process 

vent gas, use 1.235 × 10¥3 mmBtu/scf for 

HHV. 

■ 6. Section 98.234 is amended by: 

■ a. Revising paragraphs (a) 

introductory text and (d)(1); 

■ b. Removing and reserving paragraph 

(f); and 

■ c. Adding paragraph (h). 

The revisions read as follows: 

§ 98.234 Monitoring and QA/QC 

requirements. 

* * * * * 

(a) You must use any of the methods 

described as follows in this paragraph to 

conduct leak detection(s) of equipment 

leaks and through-valve leakage from all 

source types listed in § 98.233(k), (o), (p) 

and (q) that occur during a calendar 

year. 

(d) * * * 

(1) A technician following 

manufacturer instructions shall conduct 

measurements, including equipment 

manufacturer operating procedures and 

measurement methods relevant to using 

a high volume sampler, including 

positioning the instrument for complete 

capture of the equipment leak without 

creating backpressure on the source. 

* * * * * 

(h) For well venting for liquids 

unloading, if a monitoring period other 

than the full calendar year is used to 

determine the cumulative amount of 

time in hours of venting for each well 

(the term ‘‘Tp’’ in Equation W–7A and 

W–7B of § 98.233) or the number of 

unloading events per well (the term 

‘‘Vp’’ in Equations W–8 and W–9 of 

§ 98.233), then the monitoring period 

must begin before February 1 of the 

reporting year and must not end before 

December 1 of the reporting year. The 

end of one monitoring period must 

immediately precede the start of the 

next monitoring period for the next 

reporting year. All production days 

must be monitored and all venting 

accounted for. 

■ 7. Section 98.235 is revised to read as 

follows: 


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§ 98.235 Procedures for estimating 

missing data. 

Except as specified in § 98.233, 

whenever a value of a parameter is 

unavailable for a GHG emission 

calculation required by this subpart 

(including, but not limited to, if a 

measuring device malfunctions during 

unit operation, a required gas sample is 

not taken, or activity data are not 

collected), you must follow the 

procedures specified in paragraphs (a) 

through (h) of this section, as 

applicable. 

(a) If you choose to take quarterly gas 

samples as allowed in § 98.233(d) in 

lieu of using a continuous gas analyzer, 

and there is a missing sample, you must 

substitute the average value of the last 

four samples for which data are 

available. 

(b) If you did not conduct monitoring 

as specified in § 98.233(k) for a 

transmission storage tank(s), you must 

assume the vent stack(s) connected to 

the transmission storage tank(s) was 

leaking for the entire calendar year. 

(c) For stationary and portable 

combustion sources that use the 

calculation methods of subpart C of this 

part, you must use the missing data 

procedures in subpart C of this part. 

(d) For each missing value of a 

parameter that should have been 

measured using a continuous flow 

meter, composition analyzer, 

thermocouple, or pressure gauge, you 

must substitute the arithmetic average of 

the quality-assured values of that 

parameter immediately preceding and 

immediately following the missing data 

incident. If the ‘‘after’’ value is not 

obtained by the end of the reporting 

year, you may use the ‘‘before’’ value for 

the missing data substitution. If, for a 

particular parameter, no quality-assured 

data are available prior to the missing 

data incident, you must use the first 

quality-assured value obtained after the 

missing data period as the substitute 

data value. A value is quality-assured 

according to the procedures specified in 

§ 98.234. 

(e) For the first six months of required 

data collection, facilities that become 

newly subject to this subpart W may use 

best engineering estimates for any data 

that cannot reasonably be measured or 

obtained according to the requirements 

of this subpart. 

(f) For the first six months of required 

data collection, facilities that are 

currently subject to this subpart W and 

that acquire new wells that were not 

previously subject to this subpart W 

may use best engineering estimates for 

any data related to those newly acquired 

wells that cannot reasonably be 

measured or obtained according to the 

requirements of this subpart. 

(g) For each missing value of any 

activity data not described in this 

section, you must substitute data 

value(s) using the best available 

estimate(s) of the parameter(s), based on 

all available process data (including, but 

not limited to, processing rates, 

operating hours). 

(h) You must report information for 

all measured and substitute values of a 

parameter, and the procedures used to 

substitute an unavailable value of a 

parameter per the requirements in 

§ 98.236(bb). 

■ 8. Section 98.236 is revised to read as 

follows: 

§ 98.236 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain reported emissions and 

related information as specified in this 

section. 

(a) The annual report must include 

the information specified in paragraphs 

(a)(1) through (8) of this section for each 

applicable industry segment. The 

annual report must also include annual 

emissions totals, in metric tons of CO2e 

of each GHG, for each applicable 

industry segment listed in paragraphs 

(a)(1) through (a)(8) of this section, and 

each applicable emission source listed 

in paragraphs (b) through (z) of this 

section. 

(1) Onshore petroleum and natural gas 

production. For the equipment/

activities specified in paragraphs 

(a)(1)(i) through (a)(1)(xvii) of this 

section, report the information specified 

in the applicable paragraphs of this 

section. 

(i) Natural gas pneumatic devices. 

Report the information specified in 

paragraph (b) of this section. 

(ii) Natural gas driven pneumatic 

pumps. Report the information specified 

in paragraph (c) of this section. 

(iii) Acid gas removal units. Report 

the information specified in paragraph 

(d) of this section. 

(iv) Dehydrators. Report the 

information specified in paragraph (e) of 

this section. 

(v) Liquids unloading. Report the 

information specified in paragraph (f) of 

this section. 

(vi) Completions and workovers with 

hydraulic fracturing. Report the 

information specified in paragraph (g) of 

this section. 

(vii) Completions and workovers 

without hydraulic fracturing. Report the 

information specified in paragraph (h) 

of this section. 

(viii) Onshore production storage 

tanks. Report the information specified 

in paragraph (j) of this section. 

(ix) Well testing. Report the 

information specified in paragraph (l) of 

this section. 

(x) Associated natural gas. Report the 

information specified in paragraph (m) 

of this section. 

(xi) Flare stacks. Report the 

information specified in paragraph (n) 

of this section. 

(xii) Centrifugal compressors. Report 

the information specified in paragraph 

(o) of this section. 

(xiii) Reciprocating compressors. 

Report the information specified in 

paragraph (p) of this section. 

(xiv) Equipment leaks by population 

count. Report the information specified 

in paragraph (r) of this section. 

(xv) EOR injection pumps. Report the 

information specified in paragraph (w) 

of this section. 

(xvi) EOR hydrocarbon liquids. Report 

the information specified in paragraph 

(x) of this section. 

(xvii) Combustion equipment. Report 

the information specified in paragraph 

(z) of this section. 

(2) Offshore petroleum and natural 

gas production. Report the information 

specified in paragraph (s) of this section. 

(3) Onshore natural gas processing. 

For the equipment/activities specified 

in paragraphs (a)(3)(i) through (a)(3)(vii) 

of this section, report the information 

specified in the applicable paragraphs of 

this section. 

(i) Acid gas removal units. Report the 

information specified in paragraph (d) 

of this section. 

(ii) Dehydrators. Report the 

information specified in paragraph (e) of 

this section. 

(iii) Blowdown vent stacks. Report the 

information specified in paragraph (i) of 

this section. 

(iv) Flare stacks. Report the 

information specified in paragraph (n) 

of this section. 

(v) Centrifugal compressors. Report 

the information specified in paragraph 

(o) of this section. 

(vi) Reciprocating compressors. 

Report the information specified in 

paragraph (p) of this section. 

(vii) Equipment leak surveys. Report 

the information specified in paragraph 

(q) of this section. 

(4) Onshore natural gas transmission 

compression. For the equipment/

activities specified in paragraphs 

(a)(4)(i) through (a)(4)(vii) of this 

section, report the information specified 

in the applicable paragraphs of this 

section. 

(i) Natural gas pneumatic devices. 

Report the information specified in 

paragraph (b) of this section. 

(ii) Blowdown vent stacks. Report the 

information specified in paragraph (i) of 

this section. 


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(iii) Transmission storage tanks. 

Report the information specified in 

paragraph (k) of this section. 

(iv) Flare stacks. Report the 

information specified in paragraph (n) 

of this section. 

(v) Centrifugal compressors. Report 

the information specified in paragraph 

(o) of this section. 

(vi) Reciprocating compressors. 

Report the information specified in 

paragraph (p) of this section. 

(vii) Equipment leak surveys. Report 

the information specified in paragraph 

(q) of this section. 

(5) Underground natural gas storage. 

For the equipment/activities specified 

in paragraphs (a)(5)(i) through (a)(5)(vi) 

of this section, report the information 

specified in the applicable paragraphs of 

this section. 

(i) Natural gas pneumatic devices. 

Report the information specified in 

paragraph (b) of this section. 

(ii) Flare stacks. Report the 

information specified in paragraph (n) 

of this section. 

(iii) Centrifugal compressors. Report 

the information specified in paragraph 

(o) of this section. 

(iv) Reciprocating compressors. 

Report the information specified in 

paragraph (p) of this section. 

(v) Equipment leak surveys. Report 

the information specified in paragraph 

(q) of this section. 

(vi) Equipment leaks by population 

count. Report the information specified 

in paragraph (r) of this section. 

(6) LNG storage. For the equipment/

activities specified in paragraphs 

(a)(6)(i) through (a)(6)(v) of this section, 

report the information specified in the 

applicable paragraphs of this section. 

(i) Flare stacks. Report the 

information specified in paragraph (n) 

of this section. 

(ii) Centrifugal compressors. Report 

the information specified in paragraph 

(o) of this section. 

(iii) Reciprocating compressors. 

Report the information specified in 

paragraph (p) of this section. 

(iv) Equipment leak surveys. Report 

the information specified in paragraph 

(q) of this section. 

(v) Equipment leaks by population 

count. Report the information specified 

in paragraph (r) of this section. 

(7) LNG import and export 

equipment. For the equipment/activities 

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

(a)(7)(vi) of this section, report the 

information specified in the applicable 

paragraphs of this section. 

(i) Blowdown vent stacks. Report the 

information specified in paragraph (i) of 

this section. 

(ii) Flare stacks. Report the 

information specified in paragraph (n) 

of this section. 

(iii) Centrifugal compressors. Report 

the information specified in paragraph 

(o) of this section. 

(iv) Reciprocating compressors. 

Report the information specified in 

paragraph (p) of this section. 

(v) Equipment leak surveys. Report 

the information specified in paragraph 

(q) of this section. 

(vi) Equipment leaks by population 

count. Report the information specified 

in paragraph (r) of this section. 

(8) Natural gas distribution. For the 

equipment/activities specified in 

paragraphs (a)(8)(i) through (a)(8)(iii) of 

this section, report the information 

specified in the applicable paragraphs of 

this section. 

(i) Combustion equipment. Report the 

information specified in paragraph (z) of 

this section. 

(ii) Equipment leak surveys. Report 

the information specified in paragraph 

(q) of this section. 

(iii) Equipment leaks by population 

count. Report the information specified 

in paragraph (r) of this section. 

(b) Natural gas pneumatic devices. 

You must indicate whether the facility 

contains the following types of 

equipment: continuous high bleed 

natural gas pneumatic devices, 

continuous low bleed natural gas 

pneumatic devices, and intermittent 

bleed natural gas pneumatic devices. If 

the facility contains any continuous 

high bleed natural gas pneumatic 

devices, continuous low bleed natural 

gas pneumatic devices, or intermittent 

bleed natural gas pneumatic devices, 

then you must report the information 

specified in paragraphs (b)(1) through 

(b)(4) of this section. 

(1) The number of natural gas 

pneumatic devices as specified in 

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

section. 

(i) The total number of devices, 

determined according to § 98.233(a)(1) 

and (a)(2). 

(ii) If the reported value in paragraph 

(b)(1)(i) of this section is an estimated 

value determined according to 

§ 98.233(a)(2), then you must report the 

information specified in paragraphs 

(b)(1)(ii)(A) through (b)(1)(ii)(C) of this 

section. 

(A) The number of devices reported in 

paragraph (b)(1)(i) of this section that 

are counted. 

(B) The number of devices reported in 

paragraph (b)(1)(i) of this section that 

are estimated (not counted). 

(C) Whether the calendar year is the 

first calendar year of reporting or the 

second calendar year of reporting. 

(2) Estimated average number of hours 

in the calendar year that the natural gas 

pneumatic devices reported in 

paragraph (b)(1)(i) of this section were 

operating in the calendar year (‘‘Tt’’ in 

Equation W–1 of this subpart). 

(3) Annual CO2 emissions, in metric 

tons CO2, for the natural gas pneumatic 

devices combined, calculated using 

Equation W–1 of this subpart and 

§ 98.233(a)(4), and reported in 

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

(4) Annual CH4 emissions, in metric 

tons CH4, for the natural gas pneumatic 

devices combined, calculated using 

Equation W–1 of this subpart and 

§ 98.233(a)(4), and reported in 

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

(c) Natural gas driven pneumatic 

pumps. You must indicate whether the 

facility has any natural gas driven 

pneumatic pumps. If the facility 

contains any natural gas driven 

pneumatic pumps, then you must report 

the information specified in paragraphs 

(c)(1) through (c)(4) of this section. 

(1) Count of natural gas driven 

pneumatic pumps. 

(2) Average estimated number of 

hours in the calendar year the pumps 

were operational (‘‘T’’ in Equation W–2 

of this subpart). 

(3) Annual CO2 emissions, in metric 

tons CO2, for all natural gas driven 

pneumatic pumps combined, calculated 

according to § 98.233(c)(1) and (c)(2). 

(4) Annual CH4 emissions, in metric 

tons CH4, for all natural gas driven 

pneumatic pumps combined, calculated 

according to § 98.233(c)(1) and (c)(2). 

(d) Acid gas removal units. You must 

indicate whether your facility has any 

acid gas removal units that vent directly 

to the atmosphere, to a flare or engine, 

or to a sulfur recovery plant. If your 

facility contains any acid gas removal 

units that vent directly to the 

atmosphere, to a flare or engine, or to a 

sulfur recovery plant, then you must 

report the information specified in 

paragraphs (d)(1) and (d)(2) of this 

section. 

(1) You must report the information 

specified in paragraphs (d)(1)(i) through 

(d)(1)(vi) of this section for each acid gas 

removal unit. 

(i) A unique name or ID number for 

the acid gas removal unit. For the 

onshore petroleum and natural gas 

production industry segment, a different 

name or ID may be used for a single acid 

gas removal unit for each location it 

operates at in a given year. 

(ii) Total feed rate entering the acid 

gas removal unit, using a meter or 

engineering estimate based on process 

knowledge or best available data, in 

million cubic feet per year. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
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(iii) The calculation method used to 

calculate CO2 emissions from the acid 

gas removal unit, as specified in 

§ 98.233(d). 

(iv) Whether any CO2 emissions from 

the acid gas removal unit are recovered 

and transferred outside the facility, as 

specified in § 98.233(d)(11). If any CO2

emissions from the acid gas removal 

unit were recovered and transferred 

outside the facility, then you must 

report the annual quantity of CO2, in 

metric tons CO2, that was recovered and 

transferred outside the facility. 

(v) Annual CO2 emissions, in metric 

tons CO2, from the acid gas removal 

unit, calculated using any one of the 

calculation methods specified in 

§ 98.233(d) and as specified in 

§ 98.233(d)(10) and (11). 

(vi) Sub-basin ID (for the onshore 

petroleum and natural gas production 

industry segment only). 

(2) You must report information 

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

(d)(2)(iii) of this section, applicable to 

the calculation method reported in 

paragraph (d)(1)(iii) of this section, for 

each acid gas removal unit. 

(i) If you used Calculation Method 1 

or Calculation Method 2 as specified in 

§ 98.233(d) to calculate CO2 emissions 

from the acid gas removal unit, then you 

must report the information specified in 

paragraphs (d)(2)(i)(A) and (d)(2)(i)(B) of 

this section. 

(A) Annual average volumetric 

fraction of CO2 in the vent gas exiting 

the acid gas removal unit. 

(B) Annual volume of gas vented from 

the acid gas removal unit, in cubic feet. 

(ii) If you used Calculation Method 3 

as specified in § 98.233(d) to calculate 

CO2 emissions from the acid gas 

removal unit, then you must report the 

information specified in paragraphs 

(d)(2)(ii)(A) through (d)(2)(ii)(D) of this 

section. 

(A) Which equation was used; 

Equation W–4A or W–4B. 

(B) Annual average volumetric 

fraction of CO2 in the natural gas 

flowing out of the acid gas removal unit, 

as specified in Equation W–4A or 

Equation W–4B of this subpart. 

(C) Annual average volumetric 

fraction of CO2 content in natural gas 

flowing into the acid gas removal unit, 

as specified in Equation W–4A or 

Equation W–4B of this subpart. 

(D) The natural gas flow rate used, as 

specified in Equation W–4A of this 

subpart, reported as either total annual 

volume of natural gas flow into the acid 

gas removal unit in cubic feet at actual 

conditions; or total annual volume of 

natural gas flow out of the acid gas 

removal unit, as specified in Equation 

W–4B of this subpart, in cubic feet at 

actual conditions,. 

(iii) If you used Calculation Method 4 

as specified in § 98.233(d) to calculate 

CO2 emissions from the acid gas 

removal unit, then you must report the 

information specified in paragraphs 

(d)(2)(iii)(A) through (d)(2)(iii)(L) of this 

section, as applicable to the simulation 

software package used. 

(A) The name of the simulation 

software package used. 

(B) Natural gas feed temperature, in 

degrees Fahrenheit. 

(C) Natural gas feed pressure, in 

pounds per square inch. 

(D) Natural gas flow rate, in standard 

cubic feet per minute. 

(E) Acid gas content of the feed 

natural gas, in mole percent. 

(F) Acid gas content of the outlet 

natural gas, in mole percent. 

(G) Unit operating hours, excluding 

downtime for maintenance or standby, 

in hours per year. 

(H) Exit temperature of the natural 

gas, in degrees Fahrenheit. 

(I) Solvent pressure, in pounds per 

square inch. 

(J) Solvent temperature, in degrees 

Fahrenheit. 

(K) Solvent circulation rate, in gallons 

per minute. 

(L) Solvent weight, in pounds per 

gallon. 

(e) Dehydrators. You must indicate 

whether your facility contains any of the 

following equipment: absorbent 

dehydrators with an annual average 

daily natural gas throughput greater 

than or equal to 0.4 million standard 

cubic feet per day, glycol dehydrators 

with an annual average daily natural gas 

throughput less than 0.4 million 

standard cubic feet per day, and 

dehydrators that use desiccant. If your 

facility contains any of the equipment 

listed in this paragraph (e), then you 

must report the applicable information 

in paragraphs (e)(1) through (e)(3). 

(1) For each absorbent dehydrator that 

has an annual average daily natural gas 

throughput greater than or equal to 0.4 

million standard cubic feet per day (as 

specified in § 98.233(e)(1)), you must 

report the information specified in 

paragraphs (e)(1)(i) through (e)(1)(xviii) 

of this section for the dehydrator. 

(i) A unique name or ID number for 

the dehydrator. For the onshore 

petroleum and natural gas production 

industry segment, a different name or ID 

may be used for a single dehydrator for 

each location it operates at in a given 

year. 

(ii) Dehydrator feed natural gas flow 

rate, in million standard cubic feet per 

day, determined by engineering estimate 

based on best available data. 

(iii) Dehydrator feed natural gas water 

content, in pounds per million standard 

cubic feet. 

(iv) Dehydrator outlet natural gas 

water content, in pounds per million 

standard cubic feet. 

(v) Dehydrator absorbent circulation 

pump type (e.g., natural gas pneumatic, 

air pneumatic, or electric). 

(vi) Dehydrator absorbent circulation 

rate, in gallons per minute. 

(vii) Type of absorbent (e.g., 

triethylene glycol (TEG), diethylene 

glycol (DEG), or ethylene glycol (EG)). 

(viii) Whether stripper gas is used in 

dehydrator. 

(ix) Whether a flash tank separator is 

used in dehydrator. 

(x) Total time the dehydrator is 

operating, in hours. 

(xi) Temperature of the wet natural 

gas, in degrees Fahrenheit. 

(xii) Pressure of the wet natural gas, 

in pounds per square inch gauge. 

(xiii) Mole fraction of CH4 in wet 

natural gas. 

(xiv) Mole fraction of CO2 in wet 

natural gas. 

(xv) Whether any dehydrator 

emissions are vented to a vapor recovery 

device. 

(xvi) Whether any dehydrator 

emissions are vented to a flare or 

regenerator firebox/fire tubes. If any 

emissions are vented to a flare or 

regenerator firebox/fire tubes, report the 

information specified in paragraphs 

(e)(1)(xvi)(A) through (e)(1)(xvi)(C) of 

this section for these emissions from the 

dehydrator. 

(A) Annual CO2 emissions, in metric 

tons CO2, for the dehydrator, calculated 

according to § 98.233(e)(6). 

(B) Annual CH4 emissions, in metric 

tons CH4, for the dehydrator, calculated 

according to § 98.233(e)(6). 

(C) Annual N2O emissions, in metric 

tons N2O, for the dehydrator, calculated 

according to § 98.233(e)(6). 

(xvii) Whether any dehydrator 

emissions are vented to the atmosphere 

without being routed to a flare or 

regenerator firebox/fire tubes. If any 

emissions are not routed to a flare or 

regenerator firebox/fire tubes, then you 

must report the information specified in 

paragraphs (e)(1)(xvii)(A) and 

(e)(1)(xvii)(B) of this section for those 

emissions from the dehydrator. 

(A) Annual CO2 emissions, in metric 

tons CO2, for the dehydrator when not 

venting to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(1) and (e)(5). 

(B) Annual CH4 emissions, in metric 

tons CH4, for the dehydrator when not 

venting to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(1) and (e)(5). 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13450 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

(xviii) Sub-basin ID (for the onshore 

petroleum and natural gas production 

industry segment only). 

(2) For glycol dehydrators with an 

annual average daily natural gas 

throughput less than 0.4 million 

standard cubic feet per day (as specified 

in § 98.233(e)(2)), you must report the 

information specified in paragraphs 

(e)(2)(i) through (e)(2)(v) of this section 

for the entire facility. 

(i) The total number of dehydrators at 

the facility. 

(ii) Whether any dehydrators reported 

in paragraph (e)(2)(i) of this section 

were vented to a vapor recovery device. 

If any dehydrators reported in paragraph 

(e)(2)(i) of this section were vented to a 

vapor recovery device, then you must 

report the total number of dehydrators 

at the facility that vented to a vapor 

recovery device. 

(iii) Whether any dehydrators 

reported in paragraph (e)(2)(i) of this 

section were vented to a control device 

other than a vapor recovery device or a 

flare or regenerator firebox/fire tubes. If 

any dehydrators reported in paragraph 

(e)(2)(i) of this section were vented to a 

control device other than a vapor 

recovery device or a flare or regenerator 

firebox/fire tubes, then you must specify 

the type of control device and the 

number of dehydrators at the facility 

that were vented to each type of control 

device. 

(iv) Whether any dehydrators reported 

in paragraph (e)(2)(i) of this section 

were vented to a flare or regenerator 

firebox/fire tubes. If any dehydrators 

reported in paragraph (e)(2)(i) of this 

section were vented to a flare or 

regenerator firebox/fire tubes, then you 

must report the information specified in 

paragraphs (e)(2)(iv)(A) through 

(e)(2)(iv)(D) of this section. 

(A) The total number of dehydrators 

venting to a flare or regenerator firebox/ 

fire tubes. 

(B) Annual CO2 emissions, in metric 

tons CO2, for the dehydrators reported 

in paragraph (e)(2)(iv)(A) of this section, 

calculated according to § 98.233(e)(6). 

(C) Annual CH4 emissions, in metric 

tons CH4, for the dehydrators reported 

in paragraph (e)(2)(iv)(A) of this section, 

calculated according to § 98.233(e)(6). 

(D) Annual N2O emissions, in metric 

tons N2O, for the dehydrators reported 

in paragraph (e)(2)(iv)(A) of this section, 

calculated according to § 98.233(e)(6). 

(v) For dehydrators reported in 

paragraph (e)(2)(i) of this section that 

were not vented to a flare or regenerator 

firebox/fire tubes, report the information 

specified in paragraphs (e)(2)(v)(A) and 

(e)(2)(v)(B) of this section. 

(A) Annual CO2 emissions in metric 

tons CO2, for emissions from all 

dehydrators reported in paragraph 

(e)(2)(i) of this section that were not 

vented to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(2), (e)(4), and (e)(5), where 

emissions are added together for all 

such dehydrators. 

(B) Annual CH4 emissions in metric 

tons CO2, for emissions from all 

dehydrators reported in paragraph 

(e)(2)(i) of this section that were not 

vented to a flare or regenerator firebox/ 

fire tubes, calculated according to 

§ 98.233(e)(2), (e)(4), and (e)(5), where 

emissions are added together for all 

such dehydrators. 

(3) For dehydrators that use desiccant 

(as specified in § 98.233(e)(3)), you must 

report the information specified in 

paragraphs (e)(3)(i) through (e)(3)(iii) of 

this section for the entire facility. 

(i) The same information specified in 

paragraphs (e)(2)(i) through (e)(2)(iv) of 

this section for glycol dehydrators, and 

report the information under this 

paragraph for dehydrators that use 

desiccant. 

(ii) Annual CO2 emissions, in metric 

tons CO2, for emissions from all 

desiccant dehydrators reported under 

paragraph (e)(3)(i) of this section that 

are not venting to a flare or regenerator 

firebox/fire tubes, calculated according 

to § 98.233(e)(3), (e)(4), and (e)(5), and 

summing for all such dehydrators. 

(iii) Annual CH4 emissions, in metric 

tons CH4, for emissions from all 

desiccant dehydrators reported in 

paragraph (e)(3)(i) of this section that 

are not venting to a flare or regenerator 

firebox/fire tubes, calculated according 

to § 98.233(e)(3), (e)(4), and (e)(5), and 

summing for all such dehydrators. 

(f) Liquids unloading. You must 

indicate whether well venting for 

liquids unloading occurs at your 

facility, and if so, which methods (as 

specified in § 98.233(f)) were used to 

calculate emissions. If your facility 

performs well venting for liquids 

unloading and uses Calculation Method 

1, then you must report the information 

specified in paragraph (f)(1) of this 

section. If the facility performs liquids 

unloading and uses Calculation Method 

2 or 3, then you must report the 

information specified in paragraph (f)(2) 

of this section. 

(1) For each sub-basin and well tubing 

diameter and pressure grouping for 

which you used Calculation Method 1 

to calculate natural gas emissions from 

well venting for liquids unloading, 

report the information specified in 

paragraphs (f)(1)(i) through (f)(1)(xii) of 

this section. Report information 

separately for wells with plunger lifts 

and wells without plunger lifts. 

(i) Sub-basin ID. 

(ii) Well tubing diameter and pressure 

group ID. 

(iii) Plunger lift indicator. 

(iv) Count of wells vented to the 

atmosphere for the sub-basin/well 

tubing diameter and pressure grouping. 

(v) Percentage of wells for which the 

monitoring period used to determine the 

cumulative amount of time venting was 

not the full calendar year. 

(vi) Cumulative amount of time wells 

were vented (sum of ‘‘Tp’’ from Equation 

W–7A or W–7B of this subpart), in 

hours. 

(vii) Cumulative number of 

unloadings vented to the atmosphere for 

each well, aggregated across all wells in 

the sub-basin/well tubing diameter and 

pressure grouping. 

(viii) Annual natural gas emissions, in 

standard cubic feet, from well venting 

for liquids unloading, calculated 

according to § 98.233(f)(1). 

(ix) Annual CO2 emissions, in metric 

tons CO2, from well venting for liquids 

unloading, calculated according to 

§ 98.233(f)(1) and § 98.233(f)(4). 

(x) Annual CH4 emissions, in metric 

tons CH4, from well venting for liquids 

unloading, calculated according to 

§ 98.233(f)(1) and § 98.233(f)(4). 

(xi) For each well tubing diameter 

group and pressure group combination, 

you must report the information 

specified in paragraphs (f)(1)(xi)(A) 

through (f)(1)(xi)(E) of this section for 

each individual well not using a plunger 

lift that was tested during the year. 

(A) API number of tested well. 

(B) Casing pressure, in pounds per 

square inch absolute. 

(C) Internal casing diameter, in 

inches. 

(D) Measured depth of the well, in 

feet. 

(E) Average flow rate of the well 

venting over the duration of the liquids 

unloading, in standard cubic feet per 

hour. 

(xii) For each well tubing diameter 

group and pressure group combination, 

you must report the information 

specified in paragraphs (f)(1)(xii)(A) 

through (f)(1)(xii)(E) of this section for 

each individual well using a plunger lift 

that was tested during the year. 

(A) The API well number. 

(B) The tubing pressure, in pounds 

per square inch absolute. 

(C) The internal tubing diameter, in 

inches. 

(D) Measured depth of the well, in 

feet. 

(E) Average flow rate of the well 

venting over the duration of the liquids 

unloading, in standard cubic feet per 

hour. 

(2) For each sub-basin for which you 

used Calculation Method 2 or 3 (as 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13451 

specified in § 93.233(f)) to calculate 

natural gas emissions from well venting 

for liquids unloading, you must report 

the information in (f)(2)(i) through 

(f)(2)(x) of this section. Report 

information separately for each 

calculation method. 

(i) Sub-basin ID. 

(ii) Calculation method. 

(iii) Plunger lift indicator. 

(iv) Number of wells vented to the 

atmosphere. 

(v) Cumulative number of unloadings 

vented to the atmosphere for each well, 

aggregated across all wells. 

(vi) Annual natural gas emissions, in 

standard cubic feet, from well venting 

for liquids unloading, calculated 

according to § 98.233(f)(2) or 

§ 98.233(f)(3), as applicable. 

(vii) Annual CO2 emissions, in metric 

tons CO2, from well venting for liquids 

unloading, calculated according to 

§ 98.233(f)(2) or § 98.233(f)(3), as 

applicable, and § 98.233(f)(4). 

(viii) Annual CH4 emissions, in metric 

tons CH4, from well venting for liquids 

unloading, calculated according to 

§ 98.233(f) (2) or § 98.233(f)(3), as 

applicable, and § 98.233(f)(4). 

(ix) For wells without plunger lifts, 

the average internal casing diameter, in 

inches. 

(x) For wells with plunger lifts, the 

average internal tubing diameter, in 

inches. 

(g) Completions and workovers with 

hydraulic fracturing. You must indicate 

whether your facility had any gas well 

completions or workovers with 

hydraulic fracturing during the calendar 

year. If your facility had gas well 

completions or workovers with 

hydraulic fracturing during the calendar 

year, then you must report information 

specified in paragraphs (g)(1) through 

(g)(10) of this section, for each sub-basin 

and well type combination. Report 

information separately for completions 

and workovers. 

(1) Sub-basin ID. 

(2) Well type. 

(3) Number of completions or 

workovers in the category. 

(4) Calculation method used. 

(5) If you used Equation W–10A to 

calculate annual volumetric total gas 

emissions, then you must report the 

information specified in paragraphs 

(g)(5)(i) and (g)(5)(ii) of this section. 

(i) Cumulative backflow time, in 

hours, for each sub-basin (‘‘Tp’’ in 

Equation W–10A). 

(ii) Measured flowback rate, in 

standard cubic feet per hour, for each 

sub-basin (‘‘FRs,p’’ in Equation W–12A). 

(6) If you used Equation W–10B to 

calculate annual volumetric total gas 

emissions for completions that vent gas 

to the atmosphere, then you must report 

the vented natural gas volume, in 

standard cubic feet, for each well in the 

sub-basin (‘‘FVs,p’’ in Equation W–10B). 

(7) Annual gas emissions, in standard 

cubic feet (‘‘Es,n’’ in Equation W–10A or 

W–10B). 

(8) Annual CO2 emissions, in metric 

tons CO2. 

(9) Annual CH4 emissions, in metric 

tons CH4. 

(10) If the well emissions were vented 

to a flare, then you must report the total 

N2O emissions, in metric tons N2O. 

(h) Completions and workovers 

without hydraulic fracturing. You must 

indicate whether the facility had any gas 

well completions without hydraulic 

fracturing or any gas well workovers 

without hydraulic fracturing, and if the 

activities occurred with or without 

flaring. If the facility had gas well 

completions or workovers without 

hydraulic fracturing, then you must 

report the information specified in 

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

section, as applicable. 

(1) For each sub-basin with gas well 

completions without hydraulic 

fracturing and without flaring, report 

the information specified in paragraphs 

(h)(1)(i) through (h)(1)(vi) of this 

section. 

(i) Sub-basin ID. 

(ii) Number of well completions that 

vented gas directly to the atmosphere 

without flaring. 

(iii) Total number of hours that gas 

vented directly to the atmosphere 

during backflow for all completions in 

the sub-basin category (the sum of all 

‘‘Tp’’ for completions that vented to the 

atmosphere as used in Equation W– 

13B). 

(iv) Average daily gas production rate 

for all completions without hydraulic 

fracturing in the sub-basin without 

flaring, in standard cubic feet per hour 

(average of all ‘‘Vp’’ used in Equation 

W–13B). 

(v) Annual CO2 emissions, in metric 

tons CO2, that resulted from 

completions venting gas directly to the 

atmosphere (‘‘Es,p’’ from Equation W– 

13B for completions that vented directly 

to the atmosphere, converted to mass 

emissions according to § 98.233(h)(1)). 

(vi) Annual CH4 emissions, in metric 

tons CH4, that resulted from 

completions venting gas directly to the 

atmosphere (Es,p from Equation W–13B 

for completions that vented directly to 

the atmosphere, converted to mass 

emissions according to § 98.233(h)(1)). 

(2) For each sub-basin with gas well 

completions without hydraulic 

fracturing and with flaring, report the 

information specified in paragraphs 

(h)(2)(i) through (h)(2)(vii) of this 

section. 

(i) Sub-basin ID. 

(ii) Number of well completions that 

flared gas. 

(iii) Total number of hours that gas 

vented to a flare during backflow for all 

completions in the sub-basin category 

(the sum of all ‘‘Tp’’ for completions that 

vented to a flare from Equation W–13B). 

(iv) Average daily gas production rate 

for all completions without hydraulic 

fracturing in the sub-basin with flaring, 

in standard cubic feet per hour (the 

average of all ‘‘Vp’’ from Equation W– 

13B). 

(v) Annual CO2 emissions, in metric 

tons CO2, that resulted from 

completions that flared gas calculated 

according to § 98.233(h)(2). 

(vi) Annual CH4 emissions, in metric 

tons CH4, that resulted from 

completions that flared gas calculated 

according to § 98.233(h)(2). 

(vii) Annual N2O emissions, in metric 

tons N2O, that resulted from 

completions that flared gas calculated 

according to § 98.233(h)(2). 

(3) For each sub-basin with gas well 

workovers without hydraulic fracturing 

and without flaring, report the 

information specified in paragraphs 

(h)(3)(i) through (h)(3)(iv) of this 

section. 

(i) Sub-basin ID. 

(ii) Number of workovers that vented 

gas to the atmosphere without flaring. 

(iii) Annual CO2 emissions, in metric 

tons CO2 per year, that resulted from 

workovers venting gas directly to the 

atmosphere (‘‘Es,wo’’ in Equation W–13A 

for workovers that vented directly to the 

atmosphere, converted to mass 

emissions as specified in § 98.233(h)(1)). 

(iv) Annual CH4 emissions, in metric 

tons CH4 per year, that resulted from 

workovers venting gas directly to the 

atmosphere (‘‘Es,wo’’ in Equation W–13A 

for workovers that vented directly to the 

atmosphere, converted to mass 

emissions as specified in § 98.233(h)(1)). 

(4) For each sub-basin with gas well 

workovers without hydraulic fracturing 

and with flaring, report the information 

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

(h)(4)(v) of this section. 

(i) Sub-basin ID. 

(ii) Number of workovers that flared 

gas. 

(iii) Annual CO2 emissions, in metric 

tons CO2 per year, that resulted from 

workovers that flared gas calculated as 

specified in § 98.233(h)(2). 

(iv) Annual CH4 emissions, in metric 

tons CH4 per year, that resulted from 

workovers that flared gas, calculated as 

specified in § 98.233(h)(2). 

(v) Annual N2O emissions, in metric 

tons N2O per year, that resulted from 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13452 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

workovers that flared gas calculated as 

specified in § 98.233(h)(2). 

(i) Blowdown vent stacks. You must 

indicate whether your facility has 

blowdown vent stacks. If your facility 

has blowdown vent stacks, then you 

must report whether emissions were 

calculated by equipment type or by 

using flow meters. If you calculated 

emissions by equipment type, then you 

must report the information specified in 

paragraph (i)(1) of this section. If you 

calculated emissions using flow meters, 

then you must report the information 

specified in paragraph (i)(2) of this 

section. 

(1) Report by equipment type. If you 

calculated emissions from blowdown 

vent stacks by equipment type, then you 

must report the equipment types and 

the information specified in paragraphs 

(i)(1)(i) through (i)(1)(iii) of this section 

for each equipment type. If a blowdown 

event resulted in emissions from 

multiple equipment types, then you 

must report the information in 

paragraphs (i)(1)(i) through (i)(1)(iii) of 

this section for the equipment type that 

represented the largest portion of the 

emissions for the blowdown event. 

(i) Total number of blowdowns in the 

calendar year for the equipment type 

(the sum of equation variable ‘‘N’’ from 

Equation W–14A or Equation W–14B of 

this subpart, for all unique physical 

volumes for the equipment type). 

(ii) Annual CO2 emissions for the 

equipment type, in metric tons CO2, 

calculated according to 

§ 98.233(i)(2)(iii). 

(iii) Annual CH4 emissions for the 

equipment type, in metric tons CH4, 

calculated according to 

§ 98.233(i)(2)(iii). 

(2) Report by flow meter. If you elect 

to calculate emissions from blowdown 

vent stacks by using a flow meter 

according to § 98.233(i)(3), then you 

must report the information specified in 

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

section for the facility. 

(i) Annual CO2 emissions from all 

blowdown vent stacks at the facility, in 

metric tons CO2 (the sum of all CO2

mass emission values calculated 

according to § 98.233(i)(3), for all flow 

meters). 

(ii) Annual CH4 emissions from all 

blowdown vent stacks at the facility, in 

metric tons CH4, (the sum of all CH4

mass emission values calculated 

according to § 98.233(i)(3), for all flow 

meters). 

(j) Onshore production storage tanks. 

You must indicate whether your facility 

sends produced oil to atmospheric 

tanks. If your facility sends produced oil 

to atmospheric tanks, then you must 

indicate which Calculation Method(s) 

you used to calculate GHG emissions, 

and you must report the information 

specified in paragraphs (j)(1) and (j)(2) 

of this section as applicable. If any 

atmospheric tanks were observed to 

have malfunctioning dump valves 

during the calendar year, then you must 

indicate that dump valves were 

malfunctioning and you must report the 

information specified in paragraph (j)(3) 

of this section. 

(1) If you used Calculation Method 1 

or Calculation Method 2 to calculate 

GHG emissions, then you must report 

the information specified in paragraphs 

(j)(1)(i) through (j)(1)(xiv) of this section 

for each sub-basin and by calculation 

method. 

(i) Sub-basin ID. 

(ii) Calculation method used, and 

name of the software package used if 

using Calculation Method 1. 

(iii) The total annual gas-liquid 

separator oil volume that is sent to 

applicable onshore production storage 

tanks, in barrels. 

(iv) The average gas-liquid separator 

temperature, in degrees. 

(v) The average gas-liquid separator 

pressure, in pounds per square inch 

gauge. 

(vi) The average sales oil or stabilized 

oil API gravity, in degrees. 

(vii) The minimum and maximum 

concentration (mole fraction) of CO2 in 

flash gas from onshore production 

storage tanks. 

(viii) The minimum and maximum 

concentration (mole fraction) of CH4 in 

flash gas from onshore production 

storage tanks. 

(ix) The number of wells sending oil 

to gas-liquid separators or directly to 

atmospheric tanks. 

(x) The number of atmospheric tanks. 

(xi) An estimate of the number of 

atmospheric tanks, not on well-pads, 

receiving your oil. 

(xii) If any emissions from the 

atmospheric tanks at your facility were 

controlled with vapor recovery systems, 

then you must report the information 

specified in paragraphs (j)(1)(xii)(A) 

through (j)(1)(xii)(E) of this section. 

(A) The number of atmospheric tanks 

that control emissions with vapor 

recovery systems. 

(B) Total CO2 mass, in metric tons 

CO2, that was recovered during the 

calendar year using a vapor recovery 

system. 

(C) Total CH4 mass, in metric tons 

CH4, that was recovered during the 

calendar year using a vapor recovery 

system. 

(D) Annual CO2 emissions, in metric 

tons CO2, from atmospheric tanks 

equipped with vapor recovery systems. 

(E) Annual CH4 emissions, in metric 

tons CH4, from atmospheric tanks 

equipped with vapor recovery systems. 

(xiii) If any atmospheric tanks at your 

facility vented gas directly to the 

atmosphere without using a vapor 

recovery system or without flaring, then 

you must report the information 

specified in paragraphs (j)(1)(xiii)(A) 

through (j)(1)(xiii)(C) of this section. 

(A) The number of atmospheric tanks 

that vented gas directly to the 

atmosphere without using a vapor 

recovery system or without flaring. 

(B) Annual CO2 emissions, in metric 

tons CO2, that resulted from venting gas 

directly to the atmosphere. 

(C) Annual CH4 emissions, in metric 

tons CH4, that resulted from venting gas 

directly to the atmosphere. 

(xiv) If you controlled emissions from 

any atmospheric tanks at your facility 

with one or more flares, then you must 

report the information specified in 

paragraphs (j)(1)(xiv)(A) through 

(j)(1)(xiv)(D) of this section. 

(A) The number of atmospheric tanks 

that controlled emissions with flares. 

(B) Annual CO2 emissions, in metric 

tons CO2, from atmospheric tanks that 

controlled emissions with one or more 

flares. 

(C) Annual CH4 emissions, in metric 

tons CH4, from atmospheric tanks that 

controlled emissions with one or more 

flares. 

(D) Annual N2O emissions, in metric 

tons N2O, from atmospheric tanks that 

controlled emissions with one or more 

flares. 

(2) If you used Calculation Method 3 

to calculate GHG emissions, then you 

must report the information specified in 

paragraph (j)(2)(i) through (j)(2)(iii) of 

this paragraph. 

(i) Report the information specified in 

paragraphs (j)(2)(i)(A) through (j)(2)(i)(F) 

of this section, at the basin level, for 

atmospheric tanks where emissions 

were calculated using Calculation 

Method 3. 

(A) The total annual oil throughput 

that is sent to all atmospheric tanks in 

the basin, in barrels. 

(B) An estimate of the fraction of oil 

throughput reported in paragraph 

(j)(2)(i)(A) sent to atmospheric tanks in 

the basin that controlled emissions with 

flares. 

(C) An estimate of the fraction of oil 

throughput reported in paragraph 

(j)(2)(i)(A) sent to atmospheric tanks in 

the basin that controlled emissions with 

vapor recovery systems. 

(D) The number of atmospheric tanks 

in the basin. 

(E) The number of wells with gasliquid separators (‘‘Count’’ from 

Equation W–15 of this subpart) in the 

basin. 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13453 

(F) The number of wells without gasliquid separators (‘‘Count’’ from 

Equation W–15 of this subpart) in the 

basin. 

(ii) Report the information specified 

in paragraphs (j)(2)(ii)(A) through 

(j)(2)(ii)(D) of this section for each subbasin with atmospheric tanks whose 

emissions were calculated using 

Calculation Method 3 and that did not 

control emissions with flares. 

(A) Sub-basin ID. 

(B) The number of atmospheric tanks 

in the sub-basin that did not control 

emissions with flares. 

(C) Annual CO2 emissions, in metric 

tons CO2, from atmospheric tanks in the 

sub-basin that did not control emissions 

with flares, calculated using Equation 

W–15 of this subpart. 

(D) Annual CH4 emissions, in metric 

tons CH4, from atmospheric tanks in the 

sub-basin that vented gas directly to the 

atmosphere, calculated using Equation 

W–15 of this subpart. 

(iii) Report the information specified 

in paragraphs (j)(2)(iii)(A) through 

(j)(2)(iii)(E) of this section for each subbasin with atmospheric tanks whose 

emissions were calculated using 

Calculation Method 3 and that 

controlled emissions with flares. 

(A) Sub-basin ID. 

(B) The number of atmospheric tanks 

in the sub-basin that controlled 

emissions with flares. 

(C) Annual CO2 emissions, in metric 

tons CO2, from atmospheric tanks that 

controlled emissions with flares. 

(D) Annual CH4 emissions, in metric 

tons CH4, from atmospheric tanks that 

controlled emissions with flares. 

(E) Annual N2O emissions, in metric 

tons N2O, from atmospheric tanks that 

controlled emissions with flares. 

(3) If any gas-liquid separator liquid 

dump values did not close properly 

during the calendar year, then you must 

report the information specified in 

paragraphs (j)(3)(i) through (j)(3)(iv) of 

this section. 

(i) The total number of gas-liquid 

separators whose liquid dump valves 

did not close properly during the 

calendar year. 

(ii) The total time the dump valves on 

gas-liquid separators did not close 

properly in the calendar year, in hours 

(‘‘Tn’’ in Equation W–16 of this subpart). 

(iii) Annual CO2 emissions, in metric 

tons CO2, that resulted from dump 

valves on gas-liquid separators not 

closing properly during the calendar 

year, calculated using Equation W–16 of 

this subpart. 

(iv) Annual CH4 emissions, in metric 

tons CH4, that resulted from the dump 

valves on gas-liquid separators not 

closing properly during the calendar 

year, calculated using Equation W–16 of 

this subpart. 

(k) Transmission storage tanks. You 

must indicate whether your facility 

contains any transmission storage tanks. 

If your facility contains at least one 

transmission storage tank, then you 

must report the information specified in 

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

section for each transmission storage 

tank vent stack. 

(1) For each transmission storage tank 

vent stack, report the information 

specified in (k)(1)(i) through (k)(1)(iv) of 

this section. 

(i) The unique name or ID number for 

the transmission storage tank vent stack. 

(ii) Method used to determine if dump 

valve leakage occurred. 

(iii) Indicator whether scrubber dump 

valve leakage occurred for the 

transmission storage tank vent. 

(iv) Indicator if there is a flare 

attached to the transmission storage 

tank vent stack. 

(2) If scrubber dump valve leakage 

occurred for a transmission storage tank 

vent stack, as reported in paragraph 

(k)(1)(iii), and the vent stack vented 

directly to the atmosphere during the 

calendar year, then you must report the 

information specified in paragraphs 

(k)(2)(i) through (k)(2)(v) of this section 

for each transmission storage vent stack 

where scrubber dump valve leakage 

occurred. 

(i) Method used to measure the leak 

rate. 

(ii) Measured leak rate (average leak 

rate from a continuous flow 

measurement device), in standard cubic 

feet per hour. 

(iii) Duration of time that venting 

occurred, in hours (may use best 

available data if a continuous flow 

measurement device was used). 

(iv) Annual CO2 emissions, in metric 

tons CO2, that resulted from venting gas 

directly to the atmosphere, calculated 

according to § 98.233(k)(1) through 

(k)(3). 

(v) Annual CH4 emissions, in metric 

tons CH4, that resulted from venting gas 

directly to the atmosphere, calculated 

according to § 98.233(k)(1) through 

(k)(3). 

(3) If scrubber dump valve leakage 

occurred for a transmission storage tank 

vent stack, as reported in paragraph 

(k)(1)(iii), and the vent stack vented to 

a flare during the calendar year, then 

you must report the information 

specified in paragraphs (k)(3)(i) through 

(k)(3)(vi) of this section. 

(i) Method used to measure the leak 

rate. 

(ii) Measured leakage rate (average 

leak rate from a continuous flow 

measurement device) in standard cubic 

feet per hour. 

(iii) Duration of time that flaring 

occurred in hours (may use best 

available data if a continuous flow 

measurement device was used). 

(iv) Annual CO2 emissions, in metric 

tons CO2, that resulted from flaring gas, 

calculated according to § 98.233(k)(4). 

(v) Annual CH4 emissions, in metric 

tons CH4, that resulted from flaring gas, 

calculated according to § 98.233(k)(4). 

(vi) Annual N2O emissions, in metric 

tons N2O, that resulted from flaring gas, 

calculated according to § 98.233(k)(4). 

(l) Well testing. You must indicate 

whether you performed gas well or oil 

well testing, and if the testing of gas 

wells or oil wells resulted in vented or 

flared emissions during the calendar 

year. If you performed well testing that 

resulted in vented or flared emissions 

during the calendar year, then you must 

report the information specified in 

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

section, as applicable. 

(1) If you used Equation W–17A to 

calculate annual volumetric natural gas 

emissions at actual conditions from oil 

wells and the emissions are not vented 

to a flare, then you must report the 

information specified in paragraphs 

(l)(1)(i) through (l)(1)(vi) of this section. 

(i) Number of wells tested in the 

calendar year. 

(ii) Average number of well testing 

days in the calendar year. 

(iii) Average gas to oil ratio for well(s) 

tested, in cubic feet of gas per barrel of 

oil. 

(iv) Average flow rate for well(s) 

tested, in barrels of oil per day. 

(v) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(l). 

(vi) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(l). 

(2) If you used Equation W–17A to 

calculate annual volumetric natural gas 

emissions at actual conditions from oil 

wells and the emissions are vented to a 

flare, then you must report the 

information specified in paragraphs 

(l)(2)(i) through (l)(2)(vii) of this section. 

(i) Number of wells tested in the 

calendar year. 

(ii) Average number of well testing 

days in the calendar year. 

(iii) Average gas to oil ratio for well(s) 

tested, in cubic feet of gas per barrel of 

oil. 

(iv) Average flow rate for well(s) 

tested, in barrels of oil per day. 

(v) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(l). 

(vi) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(l). 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13454 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

(vii) Annual N2O emissions, in metric 

tons N2O, calculated according to 

§ 98.233(l). 

(3) If you used Equation W–17B to 

calculate annual volumetric natural gas 

emissions at actual conditions from gas 

wells and the emissions were not vented 

to a flare, then you must report the 

information specified in paragraphs 

(l)(3)(i) through (l)(3)(v) of this section. 

(i) Number of wells tested in the 

calendar year. 

(ii) Average number of well testing 

days in the calendar year. 

(iii) Average annual production rate 

for well(s) tested, in actual cubic feet 

per day. 

(iv) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(l). 

(v) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(l). 

(4) If you used Equation W–17B to 

calculate annual volumetric natural gas 

emissions at actual conditions from gas 

wells and the emissions were vented to 

a flare, then you must report the 

information specified in paragraphs 

(l)(4)(i) through (l)(4)(vi) of this section. 

(i) Number of wells tested in calendar 

year. 

(ii) Average number of well testing 

days in the calendar year. 

(iii) Average annual production rate 

for well(s) tested, in actual cubic feet 

per day. 

(iv) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(l). 

(v) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(l). 

(vi) Annual N2O emissions, in metric 

tons N2O, calculated according to 

§ 98.233(l). 

(m) Associated natural gas. You must 

indicate whether any associated gas was 

vented or flared during the calendar 

year. If associated gas was vented or 

flared during the calendar year, then 

you must report the information 

specified in paragraphs (m)(1) through 

(m)(9) of this section for each sub-basin. 

(1) Sub-basin ID. 

(2) Indicator whether any associated 

gas was vented directly to the 

atmosphere without flaring. 

(3) Indicator whether any associated 

gas was flared. 

(4) Average gas to oil ratio, in 

standard cubic feet of gas per barrel of 

oil (average of the ‘‘GOR’’ values used 

in Equation W–18 of this subpart). 

(5) Volume of oil produced, in barrels, 

in the calendar year during the time 

periods in which associated gas was 

vented or flared (the sum of ‘‘Vp,q’’ used 

in Equation W–18 of this subpart). 

(6) Total volume of associated gas sent 

to sales, in standard cubic feet, in the 

calendar year during time periods in 

which associated gas was vented or 

flared (the sum of ‘‘SG’’ values used in 

Equation W–18 of this subpart). 

(7) Total volume of emissions 

reported elsewhere, in standard cubic 

feet, during time periods in which 

associated gas was vented or flared and 

which are calculated and reported 

under other paragraphs of this section, 

in standard cubic feet (the sum of 

‘‘EREp,q’’ values used in Equation W–18 

of this subpart). 

(8) If you had associated gas 

emissions directly to the atmosphere 

without flaring, then you must report 

the information specified in paragraphs 

(m)(8)(i) through (m)(8)(iii) of this 

section for each sub-basin. 

(i) Total number of wells for which 

associated gas was vented directly to the 

atmosphere without flaring. 

(ii) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(m)(3) and (m)(4). 

(iii) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(m)(3) and (m)(4). 

(9) If you had associated gas 

emissions that were flared, then you 

must report the information specified in 

paragraphs (m)(9)(i) through (m)(9)(iv) 

of this section for each sub-basin. 

(i) Total number of wells for which 

associated gas was flared. 

(ii) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(m)(5). 

(iii) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(m)(5). 

(iv) Annual N2O emissions, in metric 

tons N2O, calculated according to 

§ 98.233(m)(5). 

(n) Flare stacks. You must indicate if 

your facility contains any flare stacks. 

You must report the information 

specified in paragraphs (n)(1) through 

(n)(12) of this section for each flare stack 

at your facility, and for each industry 

segment applicable to your facility. 

(1) Unique name or ID for the flare 

stack. For the onshore petroleum and 

natural gas production industry 

segment, a different name or ID may be 

used for a single flare stack for each 

location where it operates at in a given 

calendar year. 

(2) Indicate whether the flare stack 

has a continuous flow measurement 

device. 

(3) Indicate whether the flare stack 

has a continuous gas composition 

analyzer on feed gas to the flare. 

(4) Volume of gas sent to the flare, in 

standard cubic feet (‘‘Va’’ in Equation 

W–19 of this subpart). 

(5) Fraction of the feed gas sent to an 

un-lit flare (‘‘Zu’’ in Equation W–19 of 

this subpart). 

(6) Flare combustion efficiency, 

expressed as the fraction of gas 

combusted by a burning flare. 

(7) Mole fraction of CH4 in the feed 

gas to the flare (‘‘XCH4’’ in Equation W– 

19 of this subpart). 

(8) Mole fraction of CO2 in the feed 

gas to the flare (‘‘XCO2’’ in Equation W– 

20 of this subpart). 

(9) Annual CO2 emissions, in metric 

tons CO2 (refer to Equation W–20 of this 

subpart). 

(10) Annual CH4 emissions, in metric 

tons CH4 (refer to Equation W–19 of this 

subpart). 

(11) Annual N2O emissions, in metric 

tons N2O (refer to Equation W–40 of this 

subpart). 

(12) Indicate whether a CEMS was 

used to measure emissions from the 

flare. If a CEMS was used to measure 

emissions from the flare, then you are 

not required to report N2O and CH4

emissions for the flare stack. 

(o) Centrifugal compressors. You must 

indicate whether your facility has 

centrifugal compressors. You must 

report the information specified in 

paragraphs (o)(1) and (o)(2) of this 

section for all centrifugal compressors at 

your facility. For each compressor 

source or manifolded group of 

compressor sources that you conduct as 

found leak measurements as specified in 

§ 98.233(o)(2) or (o)(4), you must report 

the information specified in paragraph 

(o)(3) of this section. For each 

compressor source or manifolded group 

of compressor sources that you conduct 

continuous monitoring as specified in 

§ 98.233(o)(3) or (o)(5), you must report 

the information specified in paragraph 

(o)(4) of this section. Centrifugal 

compressors in onshore petroleum and 

natural gas production are not required 

to report information in paragraphs 

(o)(1) through (o)(4) of this section and 

instead must report the information 

specified in paragraph (o)(5) of this 

section. 

(1) Compressor activity data. Report 

the information specified in paragraphs 

(o)(1)(i) through (o)(1)(xvi) of this 

section for each compressor located at 

your facility. 

(i) Unique name or ID for the 

centrifugal compressor. 

(ii) Hours in operating-mode. 

(iii) Hours in not-operatingdepressurized-mode. 

(iv) Indicate whether the compressor 

was measured in operating-mode. 

(v) Indicate whether the compressor 

was measured in not-operatingdepressurized-mode. 


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(vi) Indicate whether any compressor 

sources are part of a manifolded group 

of compressor sources. 

(vii) Indicate whether any compressor 

sources are routed to a flare. 

(viii) Indicate whether any 

compressor sources have vapor 

recovery. 

(ix) Indicate whether emissions from 

any compressor sources are captured for 

fuel use or are routed to a thermal 

oxidizer. 

(x) Indicate whether the compressor 

has blind flanges installed. 

(xi) Indicate whether the compressor 

has wet or dry seals. 

(xii) If the compressor has wet seals, 

the number of wet seals. 

(xiii) Compressor power rating (hp). 

(xiv) Year compressor was installed. 

(xv) Compressor model name and 

description. 

(xvi) Date of last maintenance 

shutdown that compressor was 

depressurized. 

(2) Compressor source emission vent. 

For each compressor source at each 

compressor, report the information 

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

(o)(2)(viii) of this section. 

(i) Centrifugal compressor name or ID. 

Use the same ID as in paragraph (o)(1)(i) 

of this section. 

(ii) Centrifugal compressor source 

(wet seal, isolation valve, or blowdown 

valve). 

(iii) Unique name or ID for the 

emission vent. If the emission vent is 

connected to a manifolded group of 

compressor sources, use the same 

emission vent ID for each compressor 

source. 

(iv) Emission vent type. Indicate 

whether the emission vent is for a single 

compressor source or manifolded group 

of compressor sources and whether the 

emissions from the emission vent are 

released to the atmosphere, routed to a 

flare, combustion (fuel or thermal 

oxidizer), or vapor recovery. 

(v) Indicate whether an as found leak 

measurement(s) as identified in 

§ 98.233(o)(2) or (o)(4) was conducted 

on the emission vent. 

(vi) Indicate whether continuous leak 

measurements as identified in 

§ 98.233(o)(3) or (o)(5) were conducted 

on the emission vent. 

(vii) Report emissions as specified in 

paragraphs (o)(2)(vii)(A) and 

(o)(2)(vii)(B) of this section for the 

emission vent. For emission vents 

associated with individual compressor 

sources that use an as found leak 

measurement(s), calculate emissions by 

summing all emissions from all 

compressor mode-source combinations 

for the emission vent. 

(A) Annual CO2 emissions, in metric 

tons CO2. 

(B) Annual CH4 emissions, in metric 

tons CH4. 

(viii) If the emission vent is routed to 

flare, combustion, or vapor recovery, 

report the percentage of time that the 

respective device was operational. 

(3) As found leak measurement 

sample data. If the measurement 

methods specified in paragraphs 

§ 98.233(o)(2) or (o)(4) are conducted, 

report the information specified in 

paragraph (o)(3)(i) of this section. If the 

measurement method specified in 

paragraph § 98.233(o)(2) is performed, 

report the information specified in 

paragraph (o)(3)(ii) of this section. 

(i) For each as found leak 

measurement performed on an emission 

vent, report the information specified in 

paragraphs (o)(3)(i)(A) through 

(o)(3)(i)(E) of this section. 

(A) Name or ID of emission vent. Use 

same emission vent ID as in paragraph 

(o)(2)(iii) of this section. 

(B) Sample date. 

(C) Leak measurement method. 

(D) Measured flow rate, in standard 

cubic feet per hour. 

(E) For each compressor attached to 

the emission vent, report the mode of 

operation the compressor was in when 

the sample was taken. 

(ii) For each compressor mode-source 

combination where a reporter emission 

factor as calculated in equation W–24 

was used to calculate emissions in 

Equation W–23, report the information 

specified in paragraphs (o)(3)(ii)(A) 

through (o)(3)(ii)(D) of this section 

(A) The compressor mode-source 

combination. 

(B) The compressor mode-source 

combination reporter emission factor, in 

standard cubic feet per hour (EFm,s in 

Equation W–24). 

(C) The total number of compressors 

measured in the compressor modesource combination in the current 

reporting year and the preceding two 

reporting years (Countm in Equation W– 

24). 

(D) Indicate whether the compressor 

mode-source combination reporter 

emission factor is facility-specific or 

corporate. 

(4) Continuous leak measurement 

data. If the measurement methods 

specified in paragraphs § 98.233(o)(3) or 

(o)(5) are conducted, report the 

information specified in paragraphs 

(o)(4)(i) and (o)(4)(ii) of this section for 

each continuous measurement 

conducted on each emission vent 

associated with each compressor source 

or manifolded group of compressor 

sources. 

(i) Name or ID of emission vent. Use 

same emission vent ID as in paragraph 

(o)(2)(iii) of this section. 

(ii) Measured volume of flow during 

the reporting year, in million standard 

cubic feet. 

(5) Centrifugal compressors with wet 

seal degassing vents in onshore 

petroleum and natural gas production 

must report the information specified in 

paragraphs (o)(5)(i) through (o)(5)(iii) of 

this section. 

(i) Number of centrifugal compressors 

that have wet seal oil degassing vents. 

(ii) Annual CO2 emissions, in metric 

tons CO2, from centrifugal compressors 

with wet seal oil degassing vents. 

(iii) Annual CH4 emissions, in metric 

tons CH4, from centrifugal compressors 

with wet seal oil degassing vents. 

(p) Reciprocating compressors. You 

must indicate whether your facility has 

reciprocating compressors. You must 

report the information specified in 

paragraphs (p)(1) and (p)(2) of this 

section for all reciprocating compressors 

at your facility. For each compressor 

source or manifolded group of 

compressor sources that you conduct as 

found leak measurements as specified in 

§ 98.233(p)(2) or (p)(4), you must report 

the information specified in paragraph 

(p)(3) of this section. For each 

compressor source or manifolded group 

of compressor sources that you conduct 

continuous monitoring as specified in 

§ 98.233(p)(3) or (p)(5), you must report 

the information specified in paragraph 

(p)(4) of this section. Reciprocating 

compressors in onshore petroleum and 

natural gas production are not required 

to report information in paragraphs 

(p)(1) through (p)(4) of this section and 

instead must report the information 

specified in paragraph (p)(5) of this 

section. 

(1) Compressor activity data. Report 

the information specified in paragraphs 

(p)(1)(i) through (p)(1)(xvi) of this 

section for each compressor located at 

your facility. 

(i) Unique name or ID for the 

reciprocating compressor. 

(ii) Hours in operating-mode. 

(iii) Hours in standby-depressurizedmode. 

(iv) Hours in not-operatingdepressurized-mode. 

(v) Indicate whether the compressor 

was measured in operating-mode. 

(vi) Indicate whether the compressor 

was measured in standbydepressurized-mode. 

(vii) Indicate whether the compressor 

was measured in not-operatingdepressurized-mode. 

(viii) Indicate whether any 

compressor sources are part of a 

manifolded group of compressor 

sources. 

(ix) Indicate whether any compressor 

sources are routed to a flare. 


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13456 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

(x) Indicate whether any compressor 

sources have vapor recovery. 

(xi) Indicate whether emissions from 

any compressor sources are captured for 

fuel use or are routed to a thermal 

oxidizer. 

(xii) Indicate whether the compressor 

has blind flanges installed. 

(xiii) Compressor power rating (hp). 

(xiv) Year compressor was installed. 

(xv) Compressor model name and 

description. 

(xvi) Date of last maintenance 

shutdown for rod packing replacement. 

(2) Compressor source emission vent. 

For each compressor source at each 

compressor, report the information 

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

(p)(2)(viii) of this section. 

(i) Reciprocating compressor name or 

ID. Use the same ID as in paragraph 

(p)(1)(i) of this section. 

(ii) Reciprocating compressor source 

(isolation valve, blowdown valve, or rod 

packing). 

(iii) Unique name or ID for the 

emission vent. If the emission vent is 

connected to a manifolded group of 

compressor sources, use the same 

emission vent ID for each compressor 

source. 

(iv) Emission vent type. Indicate 

whether the emission vent is for a single 

compressor source or manifolded group 

of compressor sources and whether the 

emissions from the emission vent are 

released to the atmosphere, routed to a 

flare, combustion (fuel or thermal 

oxidizer), or vapor recovery. 

(v) Indicate whether an as found leak 

measurement(s) as identified in 

§ 98.233(p)(2) or (p)(4) was conducted 

on the emission vent. 

(vi) Indicate whether continuous leak 

measurements as identified in 

§ 98.233(p)(3) or (p)(5) were conducted 

on the emission vent. 

(vii) Report emissions as specified in 

paragraphs (p)(2)(vii)(A) and 

(p)(2)(vii)(B) of this section for the 

emission vent. For emission vents 

associated with individual compressor 

sources that use an as found leak 

measurement(s), calculate emissions by 

summing all emissions from all 

compressor mode-source combinations 

for the emission vent. 

(A) Annual CO2 emissions, in metric 

tons CO2. 

(B) Annual CH4 emissions, in metric 

tons CH4. 

(viii) If the emission vent is routed to 

flare, combustion, or vapor recovery, 

report the percentage of time that the 

respective device was operational. 

(3) As found leak measurement 

sample data. If the measurement 

methods specified in paragraphs 

§ 98.233(p)(2) or (p)(4) are conducted, 

report the information specified in 

paragraph (p)(3)(i) of this section. If the 

measurement method specified in 

paragraph § 98.233(p)(2) is performed, 

report the information specified in 

paragraph (p)(3)(ii) of this section. 

(i) For each as found leak 

measurement performed on an emission 

vent, report the information specified in 

paragraphs (p)(3)(i)(A) through 

(p)(3)(i)(E) of this section. 

(A) Name or ID of emission vent. Use 

same emission vent ID as in paragraph 

(p)(2)(iii) of this section. 

(B) Sample date. 

(C) Leak measurement method. 

(D) Measured flow rate, in standard 

cubic feet per hour. 

(E) For each compressor attached to 

the emission vent, report the mode of 

operation the compressor was in when 

the sample was taken. 

(ii) For each compressor mode-source 

combination where a reporter emission 

factor as calculated in equation W–28 

was used to calculate emissions in 

Equation W–27, report the information 

specified in paragraphs (p)(3)(ii)(A) 

through (p)(3)(ii)(D) of this section 

(A) The compressor mode-source 

combination. 

(B) The compressor mode-source 

combination reporter emission factor, in 

standard cubic feet per hour (EFm,s in 

Equation W–28). 

(C) The total number of compressors 

measured in the compressor modesource combination in the current 

reporting year and the preceding two 

reporting years (Countm in Equation W– 

28). 

(D) Indicate whether the compressor 

mode-source combination reporter 

emission factor is facility-specific or 

corporate. 

(4) Continuous leak measurement 

data. If the measurement methods 

specified in paragraphs § 98.233(p)(3) or 

(p)(5) are conducted, report the 

information specified in paragraphs 

(p)(4)(i) and (p)(4)(ii) of this section for 

each continuous measurement 

conducted on each emission vent 

associated with each compressor source 

or manifolded group of compressor 

sources. 

(i) Name or ID of emission vent. Use 

same emission vent ID as in paragraph 

(p)(2)(iii) of this section. 

(ii) Measured volume of flow during 

the reporting year, in million standard 

cubic feet. 

(5) Reciprocating compressors in 

onshore petroleum and natural gas 

production must report the information 

specified in paragraphs (p)(5)(i) through 

(p)(5)(iii) of this section. 

(i) Number of reciprocating 

compressors. 

(ii) Annual CO2 emissions, in metric 

tons CO2, from reciprocating 

compressors. 

(iii) Annual CH4 emissions, in metric 

tons CH4, from reciprocating 

compressors. 

(q) Equipment leak surveys. If your 

facility is subject to the requirements of 

§ 98.233(q), then you must report the 

information specified in paragraphs 

(q)(1) and (q)(2) of this section. Natural 

gas distribution facilities must also 

report the information specified in 

paragraph (q)(3) of this section. 

(1) You must report the information 

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

of this section. 

(i) The number of complete 

equipment leak surveys performed 

during the calendar year. 

(ii) Natural gas distribution facilities 

performing equipment leak surveys 

across a multiple year leak survey cycle 

must report the number of years in the 

leak survey cycle. 

(2) You must indicate whether your 

facility contains any of the component 

types listed in § 98.232(d)(7), (e)(7), 

(f)(5), (g)(3), (h)(4), or (i)(1), for your 

facility’s industry segment. For each 

component type that is located at your 

facility, you must report the information 

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

(q)(2)(v) of this section. If a component 

type is located at your facility and no 

leaks were identified from that 

component, then you must report the 

information in paragraphs (q)(2)(i) 

through (q)(2)(v) of this section but 

report a zero (‘‘0’’) for the information 

required according to paragraphs 

(q)(2)(iii), (q)(2)(iv), and (q)(2)(v) of this 

section. 

(i) Component type. 

(ii) Total number of the surveyed 

component type that were identified as 

leaking in the calendar year (‘‘xp’’ in 

Equation W–30 of this subpart for the 

component type). 

(iii) Average time the surveyed 

components were found leaking and 

operational, in hours (average of ‘‘Tp,z’’ 

from Equation W–30 of this subpart for 

the component type). 

(iv) Annual CO2 emissions, in metric 

tons CO2, for the component type. 

(v) Annual CH4 emissions, in metric 

tons CH4, for the component type. 

(3) Natural gas distribution facilities 

must report the information specified in 

paragraphs (q)(3)(i) through (q)(3)(viii) 

of this section. 

(i) Number of above grade 

transmission-distribution transfer 

stations surveyed in the calendar year. 

(ii) Number of meter/regulator runs at 

above grade transmission-distribution 

transfer stations surveyed in the 

calendar year (‘‘CountMR,y’’ from 


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Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13457 

Equation W–31 of this subpart, for the 

current calendar year). 

(iii) Average time that meter/regulator 

runs surveyed in the calendar year were 

operational, in hours (average of ‘‘Tw,y’’ 

from Equation W–31 of this subpart, for 

the current calendar year). 

(iv) Number of above grade 

transmission-distribution transfer 

stations surveyed in the current leak 

survey cycle. 

(v) Number of meter/regulator runs at 

above grade transmission-distribution 

transfer stations surveyed in current 

leak survey cycle (sum of ‘‘CountMR,y’’ 

from Equation W–31 of this subpart, for 

all calendar years in the current leak 

survey cycle). 

(vi) Average time that meter/regulator 

runs surveyed in the current leak survey 

cycle were operational, in hours 

(average of ‘‘Tw,y’’ from Equation W–31 

of this subpart, for all years included in 

the leak survey cycle). 

(vii) Meter/regulator run CO2

emission factor based on all surveyed 

transmission-distribution transfer 

stations in the current leak survey cycle, 

in standard cubic feet of CO2 per meter/ 

regulator run operating hour (‘‘EFs,MR,i’’ 

for CO2 calculated using Equation W–31 

of this subpart). 

(viii) Meter/regulator run CH4

emission factor based on all surveyed 

transmission-distribution transfer 

stations in the current leak survey cycle, 

in standard cubic feet of CH4 per meter/ 

regulator run operating hour (‘‘EFs,MR,i’’ 

for CH4 calculated using Equation W–31 

of this subpart). 

(r) Equipment leaks by population 

count. If your facility is subject to the 

requirements of § 98.233(r), then you 

must report the information specified in 

paragraph (r)(1) of this section. Natural 

gas distribution facilities must also 

report the information specified in 

paragraph (r)(2) of this section. Onshore 

petroleum and natural gas production 

facilities must also report the 

information specified in paragraph (r)(3) 

of this section. 

(1) You must indicate whether your 

facility contains any of the emission 

source types covered by § 98.233(r), for 

the applicable industry segment. You 

must report the information specified in 

paragraphs (r)(1)(i) through (r)(1)(v) of 

this section separately for each emission 

source type that is located at your 

facility. Onshore petroleum and natural 

gas production facilities must report the 

information specified in paragraphs 

(r)(1)(i) through (r)(1)(v) of this section 

separately by component type, service 

type, and geographic location (i.e., 

Eastern U.S or Western U.S.). 

(i) Emission source type. Onshore 

petroleum and natural gas production 

facilities must report the component 

type, service type and geographic 

location. 

(ii) Total number of the emission 

source type at the facility (‘‘Counte’’ in 

Equation W–32A of this subpart). 

(iii) Average estimated time that the 

emission source type was operational in 

the calendar year, in hours (‘‘Te’’ in 

Equation W–32A of this subpart). 

(iv) Annual CO2 emissions, in metric 

tons CO2, for the emission source type. 

(v) Annual CH4 emissions, in metric 

tons CH4, for the emission source type. 

(2) Natural gas distribution facilities 

must also report the information 

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

(q)(2)(viii) of this of this section. 

(i) Number of above grade 

transmission-distribution transfer 

stations at the facility. 

(ii) Number of above grade meteringregulating stations that are not 

transmission-distribution transfer 

stations at the facility. 

(iii) Number of below grade 

transmission-distribution transfer 

stations at the facility. 

(iv) Number of below grade meteringregulating stations that are not 

transmission-distribution transfer 

stations at the facility. 

(v) Total number of meter/regulator 

runs at above grade metering-regulating 

stations that are not above grade 

transmission-distribution transfer 

stations (‘‘CountMR’’ in Equation W–32B 

of this subpart). 

(vi) Average estimated time that each 

meter/regulator run was operational in 

the calendar year, in hours per meter/

regulator run (‘‘Tw,avg’’ in Equation W– 

32B of this subpart). 

(vii) Annual CO2 emissions, in metric 

tons CO2, from above grade metering 

regulating stations that are not above 

grade transmission-distribution transfer 

stations. 

(viii) Annual CH4 emissions, in metric 

tons CH4, from above grade metering 

regulating stations that are not above 

grade transmission-distribution transfer 

stations. 

(3) Onshore petroleum and natural gas 

production facilities must also report 

the information specified in paragraphs 

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

(i) Calculation method used. 

(ii) Onshore petroleum and natural 

gas production facilities must report the 

information specified in paragraphs 

(r)(3)(ii)(A) and (r)(3)(ii)(B) of this 

section, for each major equipment type, 

production type (i.e., natural gas or 

crude oil), and geographic location 

combination in Tables W–1B and W–1C 

of this subpart. 

(A) An indication of whether the 

facility contains the major equipment 

type. 

(B) If the facility does contain the 

equipment type, the count of the major 

equipment type. 

(s) Offshore petroleum and natural 

gas production. You must report the 

information specified in paragraphs 

(s)(1) through (s)(3) of this section for 

each emission source type listed in the 

most recent BOEMRE study. 

(1) Annual CO2 emissions, in metric 

tons CO2. 

(2) Annual CH4 emissions, in metric 

tons CH4. 

(3) Annual N2O emissions, in metric 

tons N2O. 

(t) [Reserved] 

(u) [Reserved] 

(v) [Reserved] 

(w) EOR injection pumps. You must 

indicate whether CO2 EOR injection was 

used at your facility during the calendar 

year and if any EOR injection pump 

blowdowns occurred during the year. If 

any EOR injection pump blowdowns 

occurred during the calendar year, then 

you must report the information 

specified in paragraphs (w)(1) through 

(w)(8) of this section for each EOR 

injection pump system. 

(1) Sub-basin ID. 

(2) EOR injection pump system 

identifier. 

(3) Pump capacity, in barrels per day. 

(4) Total volume of EOR injection 

pump system equipment chambers, in 

cubic feet (‘‘Vv’’ in Equation W–37 of 

this subpart). 

(5) Number of blowdowns for the EOR 

injection pump system in the calendar 

year. 

(6) Density of critical phase EOR 

injection gas, in kilograms per cubic foot 

(‘‘Rc’’ in Equation W–37 of this subpart). 

(7) Mass fraction of CO2 in critical 

phase EOR injection gas (‘‘GHGCO2’’ in 

Equation W–37 of this subpart). 

(8) Annual CO2 emissions, in metric 

tons CO2, from EOR injection pump 

system blowdowns. 

(x) EOR hydrocarbon liquids. You 

must indicate whether hydrocarbon 

liquids were produced through EOR 

operations. If hydrocarbon liquids were 

produced through EOR operations, you 

must report the information specified in 

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

section for each sub-basin category with 

EOR operations. 

(1) Sub-basin ID. 

(2) Total volume of hydrocarbon 

liquids produced through EOR 

operations in the calendar year, in 

barrels (‘‘Vhl’’ in Equation W–38 of this 

subpart). 

(3) Average CO2 retained in 

hydrocarbon liquids downstream of the 

storage tank, in metric tons per barrel 

under standard conditions (‘‘Shl’’ in 

Equation W–38 of this subpart). 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13458 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

(4) Annual CO2 emissions, in metric 

tons CO2, from CO2 retained in 

hydrocarbon liquids produced through 

EOR operations downstream of the 

storage tank (‘‘MassCO2’’ in Equation W– 

38 of this subpart). 

(y) [Reserved] 

(z) Combustion equipment at onshore 

petroleum and natural gas production 

facilities and natural gas distribution 

facilities. If your facility is required by 

§ 98.232(c)(22) or (i)(7) to report 

emissions from combustion equipment, 

then you must indicate whether your 

facility has any combustion units 

subject to reporting according to 

paragraphs (a)(1)(xvii) or (a)(8)(i) of this 

section. If your facility contains any 

combustion units subject to reporting 

according to paragraphs (a)(1)(xvii) or 

(a)(8)(i) of this section, then you must 

report the information specified in 

paragraphs (z)(1) and (z)(2) of this 

section, as applicable. 

(1) Indicate whether the combustion 

units include: external fuel combustion 

units with a rated heat capacity less 

than or equal to 5 million Btu per hour; 

or, internal fuel combustion units that 

are not compressor-drivers, with a rated 

heat capacity less than or equal to 1 

mmBtu/hr (or the equivalent of 130 

horsepower). If the facility contains 

external fuel combustion units with a 

rated heat capacity less than or equal to 

5 million Btu per hour or internal fuel 

combustion units that are not 

compressor-drivers, with a rated heat 

capacity less than or equal to 1 million 

Btu per hour (or the equivalent of 130 

horsepower), then you must report the 

information specified in paragraphs 

(z)(1)(i) and (z)(1)(ii) of this section for 

each unit type. 

(i) The type of combustion unit. 

(ii) The total number of combustion 

units. 

(2) Indicate whether the combustion 

units include: external fuel combustion 

units with a rated heat capacity greater 

than 5 million Btu per hour; internal 

fuel combustion units that are not 

compressor-drivers, with a rated heat 

capacity greater than 1 million Btu per 

hour (or the equivalent of 130 

horsepower); or, internal fuel 

combustion units of any heat capacity 

that are compressor-drivers. If your 

facility contains: external fuel 

combustion units with a rated heat 

capacity greater than 5 mmBtu/hr; 

internal fuel combustion units that are 

not compressor-drivers, with a rated 

heat capacity greater than 1 million Btu 

per hour (or the equivalent of 130 

horsepower); or internal fuel 

combustion units of any heat capacity 

that are compressor-drivers, then you 

must report the information specified in 

paragraphs (z)(2)(i) through (z)(2)(vi) for 

each combustion unit type and fuel type 

combination. 

(i) The type of combustion unit. 

(ii) The type of fuel combusted. 

(iii) The quantity of fuel combusted in 

the calendar year, in thousand standard 

cubic feet, gallons, or tons. 

(iv) Annual CO2 emissions, in metric 

tons CO2, calculated according to 

§ 98.233(z)(1) and (z)(2). 

(v) Annual CH4 emissions, in metric 

tons CH4, calculated according to 

§ 98.233(z)(1) and (z)(2). 

(vi) Annual N2O emissions, in metric 

tons N2O, calculated according to 

§ 98.233(z)(1) and (z)(2). 

(aa) Each facility must report the 

information specified in paragraphs 

(aa)(1) through (aa)(9) of this section, for 

each applicable industry segment, by 

using best available data. If a quantity 

required to be reported is zero, you must 

report zero as the value. 

(1) For onshore petroleum and natural 

gas production, report the data specified 

in paragraphs (aa)(1)(i) and (aa)(1)(ii) of 

this section. 

(i) Report the information specified in 

paragraphs (aa)(1)(i)(A) through 

(aa)(1)(i)(D) of this section for the basin 

as a whole. 

(A) The quantity of gas produced in 

the calendar year from wells, in 

thousand standard cubic feet. This 

includes gas that is routed to a pipeline, 

vented or flared, or used in field 

operations. This does not include gas 

injected back into reservoirs or 

shrinkage resulting from lease 

condensate production. 

(B) The quantity of gas produced in 

the calendar year for sales, in thousand 

standard cubic feet. 

(C) The quantity of crude oil 

produced in the calendar year for sales, 

not including lease condensates, in 

barrels. 

(D) The quantity of lease condensate 

produced in the calendar year for sales, 

in barrels. 

(ii) Report the information specified 

in paragraphs (aa)(1)(ii)(A) through 

(aa)(1)(ii)(M) of this section for each 

unique sub-basin category. 

(A) State. 

(B) County. 

(C) Formation type. 

(D) The number of producing wells at 

the end of the calendar year. 

(E) The number of producing wells 

acquired during the calendar year. 

(F) The number of producing wells 

divested during the calendar year. 

(G) The number of wells completed 

during the calendar year. 

(H) The number of wells taken out of 

production during the calendar year. 

(I) Average mole fraction of CH4 in 

produced gas. 

(J) Average mole fraction of CO2 in 

produced gas. 

(K) If an oil sub-basin, report the 

average GOR of all wells, in thousand 

standard cubic feet per barrel. 

(L) If an oil sub-basin, report the 

average API gravity of all wells. 

(M) If an oil sub-basin, report average 

low pressure separator pressure, in 

pounds per square inch gauge. 

(2) For offshore production, report the 

quantities specified in paragraphs 

(aa)(2)(i) through (aa)(2)(iii) of this 

section. 

(i) The quantity of gas produced from 

the offshore platform in the calendar 

year for sales, in thousand standard 

cubic feet. 

(ii) The quantity of oil produced from 

the offshore platform in the calendar 

year for sales, in barrels. 

(iii) The quantity of condensate 

produced from the offshore platform in 

the calendar year for sales, in barrels. 

(3) For natural gas processing, report 

the quantities specified in paragraphs 

(aa)(3)(i) through (aa)(3)(vii) of this 

section. 

(i) The quantity of produced gas 

received at the gas processing plant in 

the calendar year, in thousand standard 

cubic feet. 

(ii) The quantity of processed 

(residue) gas leaving the gas processing 

plant in the calendar year, in thousand 

standard cubic feet. 

(iii) The quantity of NGLs (bulk and 

fractionated) received at the gas 

processing plant in the calendar year, in 

barrels. 

(iv) The quantity of NGLs (bulk and 

fractionated) leaving the gas processing 

plant in the calendar year, in barrels. 

(v) Average mole fraction of CH4 in 

produced gas received. 

(vi) Average mole fraction of CO2 in 

produced gas received. 

(vii) Indicate whether the facility 

fractionates NGLs. 

(4) For natural gas transmission 

compression, report the quantity 

specified in paragraphs (aa)(4)(i) 

through (aa)(4)(v) of this section. 

(i) The quantity of gas transported 

through the compressor station in the 

calendar year, in thousand standard 

cubic feet. 

(ii) Number of compressors. 

(iii) Total compressor power rating of 

all compressors combined, in 

horsepower. 

(iv) Average upstream pipeline 

pressure, in pounds per square inch 

gauge. 

(v) Average downstream pipeline 

pressure, in pounds per square inch 

gauge. 

(5) For underground natural gas 

storage, report the quantities specified 


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Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 13459 

in paragraphs (aa)(5)(i) through 

(aa)(5)(iii) of this section. 

(i) The quantity of gas injected into 

storage in the calendar year, in thousand 

standard cubic feet. 

(ii) The quantity of gas withdrawn 

from storage in the calendar year, in 

thousand standard cubic feet. 

(iii) Total storage capacity, in 

thousand standard cubic feet. 

(6) For LNG import equipment, report 

the quantity of LNG imported in the 

calendar year, in thousand standard 

cubic feet. 

(7) For LNG export equipment, report 

the quantity of LNG exported in the 

calendar year, in thousand standard 

cubic feet. 

(8) For LNG storage, report the 

quantities specified in paragraphs 

(aa)(8)(i) through (aa)(8)(iii) of this 

section. 

(i) The quantity of LNG added into 

storage in the calendar year, in thousand 

standard cubic feet. 

(ii) The quantity of LNG withdrawn 

from storage in the calendar year, in 

thousand standard cubic feet. 

(iii) Total storage capacity, in 

thousand standard cubic feet. 

(9) For natural gas distribution, report 

the quantities specified in paragraphs 

(aa)(9)(i) through (aa)(9)(vii) of this 

section. 

(i) The quantity of natural gas 

received at all custody transfer stations 

in the calendar year, in thousand 

standard cubic feet. This value may 

include meter corrections, but only for 

the calendar year covered by the annual 

report. 

(ii) The quantity of natural gas 

withdrawn from in-system storage in the 

calendar year, in thousand standard 

cubic feet. 

(iii) The quantity of natural gas added 

to in-system storage in the calendar 

year, in thousand standard cubic feet. 

(iv) The quantity of natural gas 

delivered to end users, in thousand 

standard cubic feet. This value does not 

include stolen gas, or gas that is 

otherwise unaccounted for. 

(v) The quantity of natural gas 

transferred to third parties such as other 

LDCs or pipelines, in thousand standard 

cubic feet. This value does not include 

stolen gas, or gas that is otherwise 

unaccounted for. 

(vi) The quantity of natural gas 

consumed by the LDC for operational 

purposes, in thousand standard cubic 

feet. 

(vii) The estimated quantity of gas 

stolen in the calendar year, in thousand 

standard cubic feet. 

(bb) For any missing data procedures 

used, report the information in 

paragraphs (bb)(1) through (bb)(5) in 

this section for each individual missing 

data value used in a calculation. 

Aggregation of missing data values 

within a component, well, sub-basin, or 

basin is not acceptable. If missing data 

is substituted for the same parameter in 

non-consecutive periods during the 

calendar year, the information in 

paragraphs (bb)(1) through (bb)(5) in 

this section should be reported for each 

period separately. 

(1) The date(s) the missing data is 

used. 

(2) The equation(s) in which the 

missing data is used. 

(3) The description of the unique or 

unusual circumstance that led to 

missing data use, including information 

on any equipment or components 

involved and any procedures that were 

not followed. 

(4) The description of the procedures 

used to substitute an unavailable value 

of a parameter. 

(5) The description of how the owner 

or operator will avoid the use of missing 

data in the future, such as mitigation 

strategies or changes to standard 

operating procedures. 

■ 9. Section 98.238 is amended by: 

■ a. Adding a definition for ‘‘Associated 

gas venting or flaring’’ in alphabetical 

order; 

■ b. Removing the definition for 

‘‘Component’’; 

■ c. Adding definitions for ‘‘Compressor 

mode’’ and ‘‘Compressor source’’ in 

alphabetical order; 

■ d. Removing the definitions for 

‘‘Equipment leak’’ and ‘‘Equipment leak 

detection’’; 

■ e. Adding definitions for ‘‘Manifolded 

compressor source’’ and ‘‘Manifolded 

group of compressor sources’’ in 

alphabetical order; 

■ f. Revising the definition for ‘‘Meter/ 

regulator run’’; 

■ g. Adding definitions for ‘‘Reduced 

emissions completion’’ and ‘‘Reduced 

emissions workover’’ in alphabetical 

order; and 

■ h. Revising the definition for ‘‘Subbasin category, for onshore natural gas 

production’’. 

The revisions and additions read as 

follows: 

§ 98.238 Definitions. 

* * * * * 

Associated gas venting or flaring 

means the venting or flaring of natural 

gas which originates at wellheads that 

also produce hydrocarbon liquids and 

occurs either in a discrete gaseous phase 

at the wellhead or is released from the 

liquid hydrocarbon phase by separation. 

This does not include venting or flaring 

resulting from activities that are 

reported elsewhere, including tank 

venting, well completions, and well 

workovers. 

* * * * * 

Compressor mode means the 

operational and pressurized status of a 

compressor. For a centrifugal 

compressor, ‘‘mode’’ refers to either 

operating -mode or not-operatingdepressurized -mode. For a 

reciprocating compressor, ‘‘mode’’ refers 

to either: operating -mode, standbypressurized -mode, or not-operatingdepressurized -mode. 

Compressor source means any type of 

vent or valve (i.e., wet seal, blowdown 

valve, isolation valve, or rod packing) 

on a centrifugal or reciprocating 

compressor. 

* * * * * 

Manifolded compressor source means 

a compressor source (as defined in this 

section) that is manifolded to a common 

vent that routes gas from multiple 

compressors. 

Manifolded group of compressor 

sources means a collection of any 

combination of manifolded compressor 

sources (as defined in this section) that 

are manifolded to a common vent. 

Meter/regulator run means a series of 

components used in regulating pressure 

or metering natural gas flow or both. At 

least one meter, at least on regulator, or 

any combination of both on a single run 

of piping is considered one meter/

regulator run. 

* * * * * 

Reduced emissions completion means 

a well completion following hydraulic 

fracturing 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 emissions workover means a 

well workover with hydraulic fracturing 

(i.e., 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. 

* * * * * 

Sub-basin category, for onshore 

natural gas production, means a 

subdivision of a basin into the unique 

combination of wells with the surface 

coordinates within the boundaries of an 

individual county and subsurface 

completion in one or more of each of the 

following five formation types: Oil, high 


emcdonald on DSK67QTVN1PROD with PROPOSALS2
13460 Federal Register / Vol. 79, No. 46 / Monday, March 10, 2014 / Proposed Rules 

permeability gas, shale gas, coal seam, 

or other tight gas reservoir rock. The 

distinction between high permeability 

gas and tight gas reservoirs shall be 

designated as follows: High 

permeability gas reservoirs with >0.1 

millidarcy permeability, and tight gas 

reservoirs with ≤0.1 millidarcy 

permeability. Permeability for a 

reservoir type shall be determined by 

engineering estimate. Wells that 

produce only from high permeability 

gas, shale gas, coal seam, or other tight 

gas reservoir rock are considered gas 

wells; gas wells producing from more 

than one of these formation types shall 

be classified into only one type based on 

the formation with the most 

contribution to production as 

determined by engineering knowledge. 

All wells that produce hydrocarbon 

liquids (with or without gas) and do not 

meet the definition of a gas well in this 

sub-basin category definition are 

considered to be in the oil formation. 

All emission sources that handle 

condensate from gas wells in high 

permeability gas, shale gas, or tight gas 

reservoir rock formations are considered 

to be in the formation that the gas well 

belongs to and not in the oil formation. 

* * * * * 

[FR Doc. 2014–04408 Filed 3–7–14; 8:45 am] 

BILLING CODE 6560–50–P 


emcdonald on DSK67QTVN1PROD with PROPOSALS2