Mandatory Greenhouse Gas 

Reporting Rule: EPA's Response to 

Public Comments 

2011 Technical Revisions to the Petroleum and 

Natural Gas Systems Category of the 

Greenhouse Gas Reporting Rule 

 

   
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December 2011

2011 Technical Revisions to the Petroleum and Natural Gas Systems Category of the Greenhouse 

Gas Reporting Rule 
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U. S. Environmental Protection Agency

Office of Atmosphere Programs

Climate Change Division

Washington, D.C. 
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The primary contact regarding questions or comments on this document is: 

 Carole Cook (202) 343-9263 

U.S. Environmental Protection Agency 

 Office of Atmospheric Programs 

 Climate Change Division 

 Mail Code 6207-J 

 1200 Pennsylvania Avenue, NW 

 Washington, D.C. 20460 

For technical questions, please contact the Greenhouse Gas Reporting Rule Hotline at: 

http://www.epa.gov/climatechange/emissions/ghgrule_contactus.htm. 
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FOREWORD

This document provides EPA’s responses to public comments on EPA’s Proposed Technical Revisions to 

the Petroleum and Natural Gas Systems Category of the Greenhouse Gas Reporting Rule. EPA published 

a Notice of Proposed Rulemaking in the Federal Register on September 9, 2011 (76 FR 56010). In 

addition, this document contains EPA’s responses to public comments pertaining to Subpart W from the 

2011 Technical Corrections, Clarifying, Other Amendments to Certain Provisions published August 4, 

2011 (76 FR 47392). EPA received comments on these proposed rules via one or more of the following 

methods: regulations.gov, e-mail, fax, mail or courier. 

This Response to Comments document provides the verbatim text of comments extracted from the 

original comment letter. For each comment, the name and affiliation of the commenter, the document 

control number (DCN) assigned to the comment letter, and the number of the comment excerpt is 

provided. Note that footnote numbers in this Response to Comments document do not correspond to the 

exact footnote numbers in the commenter’s original submissions. 

While EPA has made every effort to ensure the accuracy of the discussion in the response to comment 

document, the obligations of the regulated community are determined by statutes, regulations or other 

legally binding requirements. In the event of a conflict between the discussion in these responses to 

comment and the Subpart W rule or any statute or regulation, the response to comment document would 

not be controlling. 

   
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Contents

Technical Revisions

Section 1 ‐ Field‐level to Sub‐Basin Discussion ............................................................................................. 1

Section 2 ‐ Purpose and Scope (98.1); Who must report? (98.2)................................................................. 8

Section 3 ‐ What are the general monitoring, reporting, recordkeeping and verification requirements of

this part? (98.3 )..........................................................................................................................................10

Section 4 ‐ Subpart A Definitions (98.6)...................................................................................................... 13

Section 4.1 ‐ Blowdown vent stack ......................................................................................................... 13

Section 4.2 ‐ Continuous bleed ............................................................................................................... 14

Section 4.3 ‐ Intermittent bleed pneumatic devices .............................................................................. 15

Section 5 ‐ Source Category Definitions (98.230) ....................................................................................... 20

Section 5.1 ‐ Onshore Petroleum and Natural Gas Production .............................................................. 20

Section 5.2 ‐ Onshore Natural Gas Processing........................................................................................ 22

Section 5.3 ‐ Onshore Natural Gas Transmission Compression.............................................................. 25

Section 6 ‐ Greenhouse Gases to Report (98.232)...................................................................................... 29

Section 7 ‐ Calculating GHG Emissions (98.233) and Data Reporting Requirement (98.236) ....................36

Section 7.1 ‐ Standard temperature and pressure ................................................................................. 38

Section 7.2 ‐ (t) (u) (v) Volumetric and mass conversion [W‐33 to W36]............................................... 40

Section 7.3 ‐ Emission factors tables ...................................................................................................... 46

Section 7.4 ‐ Calculating Greenhouse Gas Emissions ............................................................................. 51

Section 7.4.1 ‐ Calculating GHG Emissions (non equipment specific) ................................................ 52

Section 7.4.2 ‐ Data Reporting Requirements (non equipment specific) ........................................... 53

Section 7.5 ‐ Natural Gas Pneumatic Device Venting ............................................................................. 59

Section 7.5.1 ‐ Calculating GHG Emission [W‐1]................................................................................. 59

Section 7.5.2 ‐ Data Reporting Requirements .................................................................................... 65

Section 7.6 ‐ Natural Gas Driven Pneumatic Pump Venting ................................................................... 67

Section 7.6.1 ‐ Calculating GHG Emission [W‐2]................................................................................. 67

Section 7.7 ‐ Acid Gas Removal Vents..................................................................................................... 69

Section 7.7.1 ‐ Calculating GHG Emission [W‐3, W‐4] ........................................................................ 69

Section 7.8 ‐ Dehydrator Vents............................................................................................................... 72
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Section 7.8.1 ‐ Calculating GHG Emission [W‐5, W6].......................................................................... 72

Section 7.9 ‐ Well Venting for Liquids Unloading ................................................................................... 73

Section 7.9.2 ‐ Data Reporting Requirements .................................................................................... 75

Section 7.10 ‐ Gas Well Venting During Completions and Workovers from Hydraulic Fracturing.........77

Section 7.10.1 ‐ Calculating GHG Emission [W10 to W12] ................................................................. 78

Section 7.10.2 ‐ Data Reporting Requirements .................................................................................. 86

Section 7.11 ‐ Gas Well Venting During Completions and Workovers Without Hydraulic Fracturing ...86

Section 7.11.1 ‐ Calculating GHG Emission [W13] .............................................................................. 87

Section 7.12 ‐ Blowdown Vent Stack ...................................................................................................... 87

Section 7.12.1 ‐ Calculating GHG Emission [W14A, W‐14B]............................................................... 87

Section 7.12.2 ‐ Data Reporting Requirements .................................................................................. 96

Section 7.13 ‐ Onshore Production Storage Tanks ................................................................................. 99

Section 7.13.1 ‐ Calculating GHG Emission [W‐15, W‐16] .................................................................. 99

Section 7.13.2 ‐ Data Reporting Requirements ................................................................................ 102

Section7.14 ‐ Transmission Storage Tanks............................................................................................ 102

Section 7.14.1 ‐ Calculating GHG Emission ....................................................................................... 102

Section 7.14.2 ‐ Data Reporting Requirements ................................................................................ 106

Section 7.15 ‐ Well Testing Venting and Flaring ................................................................................... 107

Section 7.15.1 ‐ Calculating GHG Emission [W‐17]........................................................................... 107

Section 7.15.2 ‐ Data Reporting Requirements ................................................................................ 109

Section 7.16 ‐ Associated Gas Venting  and Flaring .............................................................................. 109

Section 7.16.1 ‐ Calculating GHG Emission [W‐18]........................................................................... 109

Section 7.16.2 ‐ Data Reporting Requirements ................................................................................ 110

Section 7.17 ‐ Flare Stack Emissions ..................................................................................................... 111

Section 7.17.1 ‐ Calculating GHG Emission [W‐19 to W‐21]............................................................. 111

Section 7.18 ‐ Leak Detection and Leaker Emission Factors................................................................. 114

Section 7.18.1 ‐ Calculating GHG Emission [W‐30]........................................................................... 114

Section 7.18.2 ‐ Data Reporting Requirements ................................................................................ 119

Section 7.19 ‐ Population Count and Emission Factors ........................................................................ 120

Section 7.19.1 ‐ Calculating GHG Emission [W‐31, W‐32] ................................................................ 120

Section 7.19.2 ‐ Data Reporting Requirements ................................................................................ 125

Section 7.2 ‐ EOR Injection Pump Blowdown ....................................................................................... 126
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Section 7.21.1 ‐ Calculating GHG Emission [W‐37]........................................................................... 126

Section 7.22 ‐ Onshore Petroleum and natural Gas Production and Natural Gas Distribution

Combustion Emissions.......................................................................................................................... 128

Section 7.22.1 ‐ Calculating GHG Emission [W‐39, W‐40] ................................................................ 129

Section 7.22.2 ‐ Data Reporting Requirements ................................................................................ 132

Section 7.22.3 ‐ Onshore Production and Distribution Equipment Threshold for Internal Combustion

Equipment.........................................................................................................................................133

Section 8 ‐ Monitoring and QA/QC Requirements (98.234)..................................................................... 138

Section 8.1 ‐ Methods........................................................................................................................... 138

Section 8.1.1 ‐ Optical Gas Imaging Instrument ............................................................................... 139

Section 8.1.2 ‐ Method 21................................................................................................................. 144

Section 8.1.5 ‐ Acoustic Leak Detection Device ................................................................................ 145

Section 8.2 ‐ Use Flow Meters .............................................................................................................. 146

Section 8.3 ‐ Use Calibrated Bags ......................................................................................................... 147

Section 8.4 ‐ Use High Volume Sampler................................................................................................ 148

Section 9 ‐ Records that must be retained (98.237)................................................................................. 150

Section 10 ‐ Definitions (98.238) .............................................................................................................. 152

Section 10.1 ‐ Associated With a Single Well‐Pad ................................................................................ 152

Section 10.3 ‐ Facility With Respect to Natural Gas Distribution ......................................................... 167

Section 10.4 ‐ Facility with Respect to Onshore Petroleum and Natural Gas Production....................168

Section 10.7 ‐ Forced extraction of natural gas liquids......................................................................... 169

Section 10.9 ‐ Horizontal well ............................................................................................................... 170

Section 10.10 ‐ Metering‐regulating station......................................................................................... 170

Section 10.11 ‐ Pressure grouping ........................................................................................................ 171

Section 10.12 ‐ Sub‐basin category....................................................................................................... 177

Section 10.13 ‐ Transmission‐distribution transfer station .................................................................. 179

Section 10.14 ‐ Transmission pipeline .................................................................................................. 190

Section 10.15 ‐ Tubing diameter groupings.......................................................................................... 194

Section 10.17 ‐ Vertical well.................................................................................................................. 195

Section 10.18 ‐ Well testing venting and flaring................................................................................... 195

Section 12 ‐ Outside Scope ....................................................................................................................... 197

Section 12.3 ‐ Other.............................................................................................................................. 197
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Section 7 ‐ Calculating Greenhouse Gas Emissions (non‐equipment specific).........................................222

Section 7.1 ‐ Standard temperature and pressure ............................................................................... 222

Section 7.2 ‐ (t) (u) (v) Volumetric and mass conversion [W‐33 to W36].............................................228

Section 7.3 ‐ Emission Factors Table..................................................................................................... 229

Section 7.5 ‐ Natural Gas Pneumatic Device Venting ........................................................................... 234

Section 7.5.1 ‐ Calculating GHG Emission [W‐1]............................................................................... 237

Section 7.7 ‐ Acid Gas Removal............................................................................................................. 239

Section 7.7.1 ‐ Calculating GHG Emission [W‐3, W‐4] ...................................................................... 239

Section 7.8 ‐ Dehydrator Vents............................................................................................................. 240

Section 7.8.1 ‐ Calculating GHG Emission [W‐5, W6]........................................................................ 240

Section 7.9 ‐ Well Venting for Liquids Unloading ................................................................................. 240

Section 7.9.1 ‐ Calculating GHG Emission [W‐7 to W9] .................................................................... 241

Section 7.10 ‐ Gas Well Venting During Completions and Workovers from Hydraulic Fracturing.......246

Section 7.10.1 ‐ Calculating GHG Emission [W10 to W12] ............................................................... 246

Section 7.10.2 ‐ Data Reporting Requirements ................................................................................ 247

Section 7.11 ‐ Gas Well Venting During Completions and Workovers Without Hydraulic Fracturing .248

Section 7.11.1 ‐ Calculating GHG Emission [W13] ............................................................................ 248

Section 7.12 ‐ Blowdown Vent Stack .................................................................................................... 249

Section 7.12.2 ‐ Data Reporting Requirements ................................................................................ 250

Section 7.13 ‐ Onshore Production Storage Tanks ............................................................................... 251

Section 7.13.1 ‐ Calculating GHG Emission [W‐15, W‐16] ................................................................ 251

Section 7.25 ‐ Onshore Petroleum and Natural Gas Production and Natural Gas Distribution

Combustion Emissions.......................................................................................................................... 253

Section 7.25.1 ‐ Calculating GHG Emission [W‐39, W‐40] ................................................................ 253
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Section 1 ­ Field­level to Sub­Basin Discussion

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 17 

Commenter Type: Industry - oil and gas 

Comment: However, we object to the imposition of a sub-basin reporting obligation for 

emissions from pneumatic devices. As noted above in Section A.8, EPA proposed defining 

GHGi in Eq. W-1 and Eq. W-2 by using a cross reference to 40 C.F.R. § 98.233(u)(2)(i). 

Reporting this information on a sub-basin basis will only serve to add an additional layer of 

complexity to an already onerous process of counting all of the devices – a process that EPA has 

already determined may take facilities up to three years to conduct. Additionally breaking this 

data down on a sub-basin level will provide few, if any, environmental or policy oriented 

benefits, but will impose a great burden on reporters. 

Response: EPA agrees with this comment. EPA does not require reporting of pneumatic 

devices at a sub-basin level. In this final rule, EPA has retained the reference to 98.233(u)(2)(i), 

however, has clarified that gas mole fractions can be determined either at a sub-basin or facility 

level as applicable to the emission source. Since the pneumatic devices’ emissions are reported at 

a facility level, 98.233(u)(2)(i) is also applicable at a facility level for pneumatic devices. EPA 

notes that companies must still report pneumatic device activity data at the facility level. 

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 9 

Commenter Type: Industry - oil and gas 

Comment: Sub-basin category – As Chesapeake and AXPC noted in our petition for 

reconsideration, Subpart W currently is unclear regarding how reporting entities are to map wells 

to a particular “field.” Section 98.238 defines a “field” as “oil and gas fields identified in the 

United States as defined by the Energy Information Administration Oil and Gas Field Code 

Master List 2008, DOE/EIA 0370(08).” No coordinates are provided in the EIA O&G Field 

Code Master List. There is no formal way to designate appropriate field names. Furthermore, 

Subpart W does not explain how to deal with wells that are not in a recognized field in the EIA 

Master List. 76 Fed. Reg. 56,025 (providing an explanation of why industry members petitioned 

EPA to review fieldlevel reporting). 

Mapping wells to the proper field is central to compliance with the rule because the rule as 

currently written requires aggregation of information by field for the following items: 
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1. Liquid unloading (75 Fed. Reg. 74,493) 

2. Completions and workovers with fracing (75 Fed. Reg. 74,494) 

3. Completions and workovers without fracing (75 Fed. Reg. 74,495) 

4. Storage tank venting (75 Fed. Reg. 74,496) 

5. Associated gas venting/flaring (75 Fed. Reg. 74,497) 

6. Major equipment counts (75 Fed. Reg. 74,510) 

7. Gas composition (75 Fed. Reg. 74,496, 74,498, 74,500, 74,503, 74,504) 

Recognizing that reporting on a field basis is problematic, EPA has proposed that entities report 

on a sub-basin basis for gas emitted from produced oil sent to atmospheric tanks, well venting 

for liquids unloading (for each tubing diameter and pressure grouping within the sub-basin 

category) and well completions and workovers (by sub-basin and well type combination). 

Chesapeake and AXPC support EPA’s proposal to delete all references in Subpart W to the EIA 

O&G Field Code Master List and field codes. We further support the agency’s sub-basin 

proposal as an improvement over field-level reporting for gas wells. However, we object to 

EPA’s expansion of the sub-basin reporting obligation to pneumatic devices and pumps. By 

defining GHGi in Eq. W-1 and Eq. W-2 of 40 C.F.R. § 98.233(a) through a cross reference to 40 

C.F.R. § 98.233(u)(2)(i), EPA has implied that pneumatic devices and pumps must report on a 

sub-basin basis. The final rule did not require sub-basin reporting for such emission sources and 

therefore, reporters do not have their calculations and reporting systems set up to comply with 

this obligation. This cross-reference should be removed from the rule. See also Section C.1 infra. 

For oil wells, the proposal still lacks the detail necessary for sources to comply with sub-basin 

reporting. EPA’s proposed rule does not provide a definition for sub-basin as applied to oil wells. 

Such a definition is necessary for reporters to meet the requirement that they report emissions 

from storage tank venting on a sub-basin level. See W.25 [EPA-HQ-OAR-2011-0512-0040, 

Excerpt 41] of Section 2 of API’s October 24, 2011 letter to EPA. AXPC and Chesapeake 

support API’s recommendation as a fundamental pre-requisite to compliance with that reporting 

obligation. 

Response: In this final rule, EPA has finalized the use of sub-basin category to monitor and 

report emissions from certain sources that earlier used the field designation. However, EPA is 

allowing the use of field designation for reporting year 2011 only for those reporters who have 

already conducted their monitoring using the field designation for reporting year 2011. 

Therefore, the reference to the field designation is being maintained in section 98.7. Please see 

response to EPA-HQ-OAR-2011-0512-0040, Excerpt 3 for further details. 

EPA agrees with the comment on pneumatic devices and pumps in Equation W-1 and Equation 

W-2; please see the response to comment EPA-HQ-OAR-2011-0512-0033, Excerpt 17 for 

further details. 
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EPA agrees with the comment regarding an oil sub-basin and has revised the definition for subbasin in 40 CFR 98.238 to include an oil formation within the sub-basin category. For further 

details, please see the preamble Section II.C. – Final Amendments to the Petroleum and Natural 

Gas Systems Source Category – Major Changes Since Proposal and Section II.D.9 - Responses 

to Major Comments on the Petroleum and Natural Gas Systems Source Category: Addition of oil 

formation type in the sub-basin category definition. 

Commenter Name: Jessica Stark 

Commenter Affiliation: SLR International Corp 

Document Control Number: EPA-HQ-OAR-2011-0512-0040

Comment Excerpt Number: 3 

Commenter Type: Industry - oil and gas 

Comment: 98.233(f) and other locations where ‘field’ was replaced by ‘sub-basin category’ 

I have clients who would prefer the rule continue to use field as a classification mechanism for 

groups of wells within each basin. Field names are more commonly known and are easier to 

identify than the parameters defining the sub basin categories. For this and other locations in the 

rule where the term ‘sub-basin category’ was used, we request retaining the term ‘field.’ For 

example: 

“For one well of each unique well tubing diameter grouping and pressure grouping in each gas 

producing field....” 

Response: EPA recognizes that this rule was finalized later in the 2011 reporting year and that 

some facilities may have been collecting data at the field level consistent with the 2010 final 

rule. Consistent with the ability to automatically use BAMM for the 2011 reporting year, 

facilities may use the data collected at the field level, apply these measurements to the equivalent 

sub-basins applicable to their facility using best available information. For further details, please 

see the preamble Section I.E – How Do These Amendments Apply to 2012 Reports?. EPA 

notes that for data collection in 2012 and beyond for the applicable emission sources, reporters 

must use the sub-basin level for data collection, unless a request for use of BAMM is submitted 

and approved by EPA according to the procedures and criteria outlined in 40 CFR 98.234. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 13 

Commenter Type: Industry - oil and gas 

Comment: Revision: In 98.7(q), EPA deleted the reference to EIA’s field code master list. 

Comment: API supports this revision. As stated in API’s letter to Bill Irving, dated April 19, 

2011, referencing the EIA field code master list presents significant issues: 

• Annual updates to the list, usually in March, typically result in combining, changing or 

otherwise modifying field names. With each annual update, EPA’s reference to the 2008 list will 
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become more and more outdated, and the old list will fail to include many wells and new areas 

developed after publication. 

• Revising the rule language to require use of the most current EIA field listing would place 

reporters in the impossible situation of collecting episodic data after the operation/event is 

concluded and/or trying to quickly assign and reassign wells to fit within a particular field. This 

work would have to be done quickly, since the updated field list is only available in March, 

shortly before the March 31 reporting deadline under Subpart W. Such an approach is plainly 

unworkable. 

• EIA has not mapped, furnished boundary descriptions for, or provided shape files for all of the 

fields that it lists. This makes assignment of a particular well or piece of equipment to a 

particular field extremely difficult. 

• Named fields may overlap, and a single well may be within the boundaries of more than one 

field. 

• Despite the immense number of fields in the EIA list, it is common for reporters to have wells 

which are not assigned to any named EIA field. 

Response: Please see response to EPA-HQ-OAR-2011-0512-0040, Excerpt 3. To provide the 

option for reporters to use the “field” designation as BAMM for 2011, in this final rule, reference 

to EIA’s field code master list is being retained in section 98.7(q). 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 6 

Commenter Type: Industry - oil and gas 

Comment: Alternative approach to field level reporting 

In page 56025 in the preamble EPA states, “In this action we are proposing an alternative 

approach to replace ‘‘field level’’ with ‘‘sub-basin categories”. EPA considered, but is not 

proposing at this time modifications to the current field level reporting method that would 

address the outstanding concerns raised by industry. Specifically, EPA considered an amendment 

that would allow reporters to use a temporary field name when submitting reports to EPA in 

instances where a well does not fall within a designated EIA field code.” 

API Response: 

API acknowledges and strongly supports the fact that among these technical corrections, EPA is 

proposing an alternative to field level reporting by using a sub-basin approach that is based on 

reporting at the county level and by formation type. 

API rejects the optional approach of patching-up the 2008 EIA FCML to try and “force” it to 
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work for GHG reporting. Such an approach is not warranted, does not provide the needed clarity 

and is unnecessarily burdensome. Although the ‘sub basin’ approach as proposed by EPA in the 

regulatory text, might still need some changes (see the technical comments in Section 2 below) it 

is a far superior approach and would provide EPA with quality representative data that EPA may 

need for future policy actions. 

However, if EPA chooses to reconsider its amendment to the rule and revert back to a field level 

approach API expects that it should be done by means of a full reproposal with an opportunity to 

provide specific comments on the alternative approach. 

Response: Please see response to EPA-HQ-OAR-2011-0512-0040, Excerpt 3. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 41 

Commenter Type: Industry - oil and gas 

Comment: Revision: For onshore production storage tanks, EPA has replaced field with subbasin category for determining the separator oil composition and Reid vapor pressure. 

Comment: EPA has not defined sub-basins for oil. This is needed since the sub-basin categories 

for gas wells are not applicable to the emissions from onshore production storage tanks. API 

proposes that a 5th sub-basin category - oil formations - be added for oil wells. Furthermore, API 

doesn’t believe that pressure groupings are necessary or useful for oil formations 

Response: EPA agrees with the comment regarding an oil sub-basin and has revised the 

definition for sub-basin in 40 CFR 98.238 to include an oil formation within the sub-basin 

category. For further details, please see the preamble Section II.C. – Final Amendments to the 

Petroleum and Natural Gas Systems Source Category – Major Changes Since Proposal and 

Section II.D.9 - Responses to Major Comments on the Petroleum and Natural Gas Systems 

Source Category: Addition of oil formation type in the sub-basin category definition. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 94 

Commenter Type: Industry - oil and gas 

Comment: Changes in Requirements for Field Level Reporting 

The September 9, 2011 preamble on page 56020 notes, “The one exception where both the 

underlying calculation requirements and reporting requirements in subpart W are proposed to be 

changed is related to the requirements for field level reporting for four emissions sources in the 
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onshore petroleum and natural gas production segment.” 

In the current proposed rule EPA specifies that it intends to implement the amended procedures 

for the four specified source categories starting with the 2011 reporting year. This amendment 

will require that for those four emission sources, calculations and reporting will be undertaken at 

the county level and by geologic formation starting with the 2011 reporting year. EPA further 

indicated that facilities concerned about their ability to implement those provisions for the 2011 

reporting year may use best available monitoring methods (BAMM) pursuant to 40 CFR 

98.234(f). 

API Response: 

API and its members have been working with EPA technical experts to develop a less 

burdensome approach for the calculation and reporting requirements for several source types to 

allow for the implementation of data collection, calculation and GHG emissions reporting at the 

county level and by geologic formation type. The proposed approach represents an improvement 

over the large burden and ambiguity associated with the previously promulgated requirements 

with using the EIA 2008 Field Code Master List (FCML). [Footnote 2: November 30, 2010, 

Final Rule at 75 FR 74458] 

Several API member facilities have, in fact, already designed their data collection systems and 

taken some measurements at the field level for 2011. API strongly supports EPA’s position that 

those facilities may “still use those same measurements for the 2011 reporting year, but apply 

them to the sub-basin categories based on BAMM.” [Footnote 3: 76 Federal Register at 56020] 

API requests that the flexibility for those facilities to use BAMM - as EPA has suggested - be 

expressly incorporated into the final rule. 

Response: EPA is allowing the use of "field" designation as a best available monitoring method 

for the purposes of taking measurement in calendar year 2011 as is noted in the preamble to this 

final rule. Please see the response to EPA-HQ-OAR-2011-0512-0040, Excerpt3. 

Commenter Name: William W. Grygar II 

Commenter Affiliation: Anadarko Petroleum Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0028

Comment Excerpt Number: 4 

Commenter Type: Industry - oil and gas 

Comment: Under §98.233(a) and (c), EPA requires for GHGi the concentration of GHGi, CH4, 

or CO2 as defined in paragraph (u)(2)(i) of this section. Reference to paragraph (u)(2)(i) requires 

reporters to use an annual average of gas compositions for individual sub-basin categories. 

Unexpected reference to paragraph (u)(2)(i) is also found for dehydrators under 

§98.233(e)(1)(xi)(A), (B), and §98.233(e)(6), and flares under §98.233(n)(2)(i). In order to 

categorize these sources at the sub-basin category level, a significant amount of work must be 

performed to associate specific wells and gas compositions to individual pieces of equipment. 

For Anadarko, this could mean that we would have up to 336 different sub-basin categories for 

which to calculate and assimilate emissions for these sources. We do not believe it was EPA's 
7

intent to increase the complexity and burden associated with reporting for these emission 

sources. Anadarko asks that these gas compositions be limited to annual average gas 

compositions based on available sample analysis of the facility or basin for the onshore 

production industry segment. 

Response: In this final rule, EPA has clarified in 40 CFR 98.233 (u)(2)(i) that gas mole 

fractions can be determined either at a sub-basin or facility level as applicable to the emission 

source. Therefore, reporters are not required to categorize pneumatic devices (40 CFR 

98.233(a)), pneumatic pumps (40 CFR 98.233(c)), dehydrators (40 CFR 98.233(e), and flares (40 

CFR 98.233(n)) in a sub-basin category to either determine or report emissions. 
8

Section 2 ­ Purpose and Scope (98.1); Who must report? (98.2)

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 7 

Commenter Type: Industry - oil and gas 

Comment: (6) “Owner and operator” – In our petition for reconsideration, we noted several 

problems with the certifications required for Designated Representatives under § 98.4(i). 40 

C.F.R. § 98.4(i) requires the Designated Representative, an individual, to make the following 

four Certifications: 

(i) "I was selected as the designated representative...by an agreement binding on the owners and 

operators of the facility. . . ." (Certification 1) 

(ii) "... each such owner and operator shall be fully bound by my representations, actions, 

inactions, or submissions." (Certification 2) 

(iii) "...the owners and operators of the facility...shall be bound by any order issued to me by the 

administrator or a court regarding the facility. . . ." (Certification 3) 

(iv) ". . . I have given a written notice of my selection as the ‘designated representative’ . . . and 

of the agreement by which I was selected to each owner and operator of the facility. . . .” 

(Certification 4) 

The oil and gas industry explores for, and develops hydrocarbons pursuant to a customary form 

of agreement, the joint operating agreement (JOA). There are thousands of JOAs outstanding, 

each with multiple parties. A JOA is an agreement between co-owners of the rights to explore for 

and develop the oil and gas in certain described property. The parties typically designate one of 

the co-owners as operator to manage property operations, subject to the terms of the JOA. The 

scope of an operator’s authority is derived from the terms and conditions of the JOA. Although 

multiple standard forms of JOAs are in use by industry, contracting parties amend the terms of 

the standard forms to achieve the desired contractual relationships among the parties. 

Before issuing the final Subpart W rule, EPA did not adequately evaluate whether these JOAs 

enable an operator to make Certifications 1 through 4 without obtaining the consent of other 

affected parties. The industry operates thousands of properties, each of which can have multiple 

interest owners of varying levels of sophistication and willingness to cooperate. Accordingly, 

obtaining consent could prove daunting and unsuccessful. Most JOAs give the operator some 

form of control or management of property operations and directly or indirectly contemplate 

compliance with applicable laws or filing of reports with government authorities. Typically, the 

operator certifies to the accuracy of the reports submitted, but is not required to additionally 

make other legally binding certifications that would necessitate the operator to act as a fiduciary 

or agent for the owners. 
9

Multiple provisions commonly included in JOAs raise the question of possible legal 

impediments to compliance with the Certification requirements if EPA did not modify the 

definition of “owner and operator” to account for the unique nature of the onshore production 

industry. For example, some form JOAs include provisions such as the following: 

· “The Operator is not the agent or fiduciary of the Non-Operating Parties.” 

· “It is not the intention of the parties to. . . render them liable as partners” (i.e., to make them 

jointly and severally liable). 

· “This agreement is not intended to. . . impose a partnership duty, obligation, or liability with 

regard to any one or more of the parties hereto. 

The inclusion of such provisions in executed JOAs may prohibit an operator from being able to 

make the Designated Representative Certifications required under Subpart A of the reporting 

rule. The specificity of the Certifications EPA requires – and the breadth of their legal 

implications – would require lawyers to review every JOA now in effect. While much of the 

industry tends to use form JOAs, not all the terms of those form JOAs are uniformly accepted 

and therefore each executed contract would need to be individually reviewed. 

To respond to these concerns, EPA has proposed adding a new provision to 40 C.F.R. § 98.1(c). 

This new provision clarifies that for Subpart W, the term "owner and operator" used in Subpart 

A would have the same meaning as "onshore petroleum and natural gas owner or operator" 

provided in 40 C.F.R. § 98.238. Section 98.238 defines "onshore owner or operator" as the entity 

that holds the permit to operate the wells. The effect of EPA’s proposal is that references to 

"owners and operators" in the 40 C.F.R. § 98.4(i) Designated Representative certification 

provisions would refer to the entity that holds the permit. Chesapeake and AXPC support this 

change because this proposal will resolve our concerns about JOAs and minority ownership 

interests that would have otherwise made the compliance with the Designated Representative 

certifications difficult. 

Response: EPA thanks the commenter for their remarks. 
10

Section 3 ­ What are the general monitoring, reporting, recordkeeping

and verification requirements of this part? (98.3 )

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 29 

Commenter Type: Trade Association

Comment: Comments solicited in the preamble: 

 The reporting deadline should be September 28, 2011, consistent with the August 4 proposed 

revisions to Subpart W. 

EPA requests comment on whether it is appropriate for Subpart W reporting to be delayed 

beyond March 31, 2012 to allow adequate time to adjust to the Proposed Rule [76 FR 56021]. 

This inquiry is puzzling, because the August 4 proposed revisions would change the reporting 

deadline to September 28, 2012, and INGAA anticipates that revision will be finalized. At any 

rate, a March 31, 2011 deadline is not appropriate, and INGAA supports delaying reporting until 

at least September 28, 2012. As INGAA indicated in its comments on the August 4 proposed 

revisions, INGAA supports the later deadline and recommends that reporting for all sources – 

including Subpart C and Subpart W emissions sources – should be deferred until the September 

deadline for facilities subject to Subpart W. Please refer to INGAA's comments on the August 4 

proposed revisions for additional details. 

Response: EPA agrees with the commenter that 2011 reporting for Subpart W sources – and for 

any other subpart for which those sources previously reported 2010 data for – should be deferred 

until September 28, 2012. Note that if the reporter provided 2010 data under any other subpart, 

they are to file a notification in eGGRT of the 2011 deferral by March 31, 2012. Please see the 

preamble for the Mandatory Reporting of Greenhouse Gases Rule 2011 Technical Corrections, 

Clarifying, Other Amendments to Certain Provisions, Section II.A.2, Subpart A – General 

Provisions: Summary of Comments and Responses, for further details on the 2012 reporting 

deadline for facilities and suppliers with a source category required to begin data collection in 

2011 and source categories that began data collection in 2010. 

Commenter Name: Jessica Stark 

Commenter Affiliation: SLR International Corp 

Document Control Number: EPA-HQ-OAR-2011-0512-0040

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas 

Comment: 40 CFR 98.3(b)(1)(iv) 

For facilities reporting under Subpart W that are not in the ‘Onshore Petroleum and Natural Gas 

Production’ industry sector, it is not clear whether the combustion emissions calculated under 
11

Subpart C would have to be reported by March 31, 2012 or whether the combustion emissions 

for those facilities would be included in the first Subpart W reports due by September 28, 2012. I 

have a client with facilities in the Underground Storage and Transmission Compression sectors 

that are not required to report under Subpart C alone. 

Response: Source categories considered new 2011 reporting year source categories are allowed 

to defer reporting of all their data until September 28, 2012. Please see the preamble for the 

Mandatory Reporting of Greenhouse Gases Rule 2011 Technical Corrections, Clarifying, Other 

Amendments to Certain Provisions, Section II.A.2, Subpart A – General Provisions: Summary of 

Comments and Responses, for further details on the 2012 reporting deadline for facilities and 

suppliers with a source category required to begin data collection in 2011 and source categories 

that began data collection in 2010. 

Commenter Name: Gregory L. Ryan 

Commenter Affiliation: DTE Energy 

Document Control Number: EPA-HQ-OAR-2011-0512-0041

Comment Excerpt Number: 5 

Commenter Type: Industry - oil and gas 

Comment: IV. Delay of Reporting Beyond March 31, 2012 for Subpart W Requirements 

DTE Energy supports moving the timeline for reporting of natural gas emissions under Subpart 

W by 6 months to the end of September 2012. Given that the final rule is not expected to be 

promulgated until December 2012, it is unreasonable to expect us to update the Greenhouse Gas 

Monitoring Plan and verify that all leak detection surveys, population counts, quality control and 

quality assurance requirements, emission calculations and other required elements of Subpart W 

have been completed in accordance with the GHG Monitoring Plan, and submit the 2012 data in 

the span of just 3 months. 

Response: EPA agrees with the commenter that new 2011 reporting year source categories are 

allowed to defer reporting of all their data until September 28, 2012. Please see the preamble for 

the Mandatory Reporting of Greenhouse Gases Rule 2011 Technical Corrections, Clarifying, 

Other Amendments to Certain Provisions, Section II.A.2, Subpart A – General Provisions: 

Summary of Comments and Responses, for further details on the 2012 reporting deadline for 

facilities and suppliers with a source category required to begin data collection in 2011. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 23 

Commenter Type: Trade Association 

Comment: 16. To address evolving requirements associated with Confidental Business 
12

Information, EPA needs to revise Subpart A, Table A-7 to address data elements where reporting 

should be deferred until 2015. 

INGAA provided a similar comment in response to the August 4 proposed revisions to Subpart 

W. To address ongoing concerns regarding Confidential Business Information (CBI), EPA 

published a rule in the August 25, 2011 Federal Register, "Change to the Reporting Date for 

Certain Data Elements Required Under the Mandatory Reporting of Greenhouse Gases Rule" (76 

FR 53057). That rule identifies data elements for Subpart W emission estimation calculations 

where reporting is deferred until March 31, 2015. Reporting criteria affected by the Proposed 

Rule have not been reconciled with the August 25 CBI Rule, and EPA will need to propose 

additional corrections to Subpart A to reconcile ongoing revisions in Subpart W with the recently 

adopted CBI rule. The technical revisions in the Proposed Rule will result in anomalies and 

additional data elements will need to be added to Subpart A, Table A-7. EPA should adopt 

changes expediently so that 2012 reporting obligations are clearly defined in Table A-7 and 

reflect the pending technical corrections to Subpart W. 

Response: With respect to revisions to Subpart A Table A-7 deferrals and additional corrections 

to Subpart A, please see the response to Mandatory Reporting of Greenhouse Gases Rule 2011 

Technical Corrections, Clarifying, Other Amendments to Certain Provisions EPA-HQ-OAR2011-0147-0029, Excerpt 8. 

Commenter Name: Curtis J. Winner 

Commenter Affiliation: New Mexico Gas Company (NMGC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0047

Comment Excerpt Number: 10 

Commenter Type: Industry - oil and gas 

Comment: CBI 

The August 25, 2011 CBI final rule lists SPW data in Table 7 that do not need to be reported 

until March 31, 2015. If the proposed technical revisions for the mandatory reporting rule for 

SPW are finalized, the data elements in the “Change to the reporting date for certain data 

elements” final rule from August 25, 2011 may need to be reviewed and updated.

Response: EPA is addressing changes to CBI and deferrals as a result of these technical 

corrections and revisions and will be publishing an updated list of data elements and their 

disposition in an upcoming rulemaking.

 
13

Section 4 ­ Subpart A Definitions (98.6)

Section 4.1 ­ Blowdown vent stack

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 14 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Blowdown vent 

stacks: 

7. EPA should clarify that emergency events are excluded from blowdown vent stack reporting. 

Revisions in the Proposed Rule conflict with the August 4 proposed revisions. Additional 

revisions are needed to clarify Subpart W requirements. 

As indicated in September 19, 2011 comments to EPA, INGAA supports the August 4 proposed 

revision that excludes emergency events from the definition of "blowdown vent stack ". 

However, the Proposed Rule confuses this issue in revisions to the introductory text of 

§98.233(i). The Proposed Rule should be revised to clearly indicate that emergency events are 

excluded from blowdown vent stack reporting. 

The August 4 proposed rule revisions [76 FR 47392] revised the definition of blowdown vent 

stack: 

"Blowdown vent stack emissions mean natural gas and/or CO2 released due to maintenance 

and/or blowdown operations including compressor blowdown and emergency shut-down (ESD) 

system testing. [add: Emissions from emergency events are not included]." 

The new closing sentence clearly indicates that emergency venting is excluded from blowdown 

vent stack reporting. INGAA supports this revision. However, the Proposed Rule introduction to 

§98.233(i) confuses issue. Revised text from EPA's redline version of the rule available in the 

docket is shown here, but the last sentence is not included in the published Proposed Rule: 

"Calculate CO2 and CH4 blowdown vent stack emissions from depressurizing equipment to 

[add: reduce system pressure for planned or emergency shutdowns or to take equipment out of 

service for maintenance] [delete: the atmosphere] (excluding depressurizing to a flare, overpressure relief, operating pressure control venting and blowdown of non-GHG gases; desiccant 

dehydrator blowdown venting before reloading is covered in paragraph (e)(5) of this section) as 

follows [add: (Emissions from emergency vents are not included.)]:" 

In this revised text, the text "or emergency" contradicts the revised §98.6 definition of blowdown 

vent stack and the text in the closing sentence of the EPA redline version. Both of these exclude 

emergency events and indicate EPA intended to exclude the reporting of emergency venting 

emissions. To clarify and avoid conflict with the §98.6 definition, the phrase “or emergency” 
14

should be deleted. INGAA also recommends including the closing sentence with the other list of 

excluded activities and referring to emergency events rather than emergency vents. The INGAA 

recommended revisions based on the EPA redlines above follows: 

"Calculate CO2 and CH4 blowdown vent stack emissions from depressurizing equipment to 

[add: reduce system pressure for planned or emergency shutdowns or to take equipment out of 

service for maintenance] [delete: the atmosphere] (excluding depressurizing to a flare, overpressure relief, operating pressure control venting and blowdown of non-GHG gases [add: , and 

emissions from emergency events]; desiccant dehydrator blowdown venting before reloading is 

covered in paragraph (e)(5) of this section) as follows [delete: (Emissions from emergency vents 

are not included)]:" 

Response: EPA disagrees with the commenter and requires reporting from certain types of 

emergency blowdowns. Please see preamble Section II.C – Final Amendments to the Petroleum 

and Natural Gas Systems Source Category, and Section II.D.8 – Responses to Major Comments 

on the Petroleum and Natural Gas Systems Source Category: Blowdown vent stacks: emergency 

blowdown. 

Section 4.2 ­ Continuous bleed

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 61 

Commenter Type: Trade Association

Comment: [Please refer to the original comment text posted in the docket] Definitions for 

Pneumatics in Subpart A 

§ 98.6 Definitions. 

Continuous bleed means a continuous flow of pneumatic supply gas to the process [add: control] 

[delete: measurement] device (e.g. level control, temperature control, pressure control) where the 

supply gas pressure is modulated by the process condition, and then flows to the valve controller 

where the signal is compared with the process set-point to adjust gas pressure in the valve 

actuator.

Response: EPA agrees with the commenter and is revising the definition in this final rule 

accordingly. Please see preamble Section II. A – Final Amendments to the General Provisions 

for the definition of continuous bleed. 

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 
15

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 3 

Commenter Type: Industry - oil and gas 

Comment: “Continuous bleed” – AXPC and Chesapeake support and incorporate here by 

reference the comments provided in A.1 [EPA-HQ-OAR-2011-0512-0033, Excerpt 11] of 

Section 2 of API’s comment letter to EPA regarding the definition “continuous bleed.” 

Response: EPA agrees with the commenter and is revising the definition in this final rule 

accordingly. Please see preamble Section II. A – Final Amendments to the General Provisions 

for the definition of continuous bleed. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 11 

Commenter Type: Industry - oil and gas

Comment: Revision: In the definition of “continuous bleed”, EPA replaced “process 

measurement device” with “process control device”. 

Comment: API supports the revised terminology, which is more correct. However, there is an 

inconsistency between the definitions of intermittent bleed pneumatic devices and continuous 

bleed pneumatic devices. The definition for intermittent bleed pneumatic devices indicates that 

these devices are powered by natural gas; while the definition for continuous bleed pneumatic 

devices only refers to “supply gas”. API requests that the definition for continuous bleed 

pneumatic be modified to be specific to the use of natural gas as the supply gas, so as not to 

inadvertently include pneumatic controllers powered by air. 

Response: EPA agrees with the commenter and is revising the definition in this final rule 

accordingly. Please see preamble Section II. A. – Final Amendments to the General Provisions – 

for the definition of continuous bleed. 

Section 4.3 ­ Intermittent bleed pneumatic devices

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 11 

Commenter Type: Trade Association 

Comment: Pneumatic controllers: 

Updated definitions for pneumatic controllers are generally consistent with previous INGAA 

recommendation, but additional clarification is needed. In addition, EPA should ensure that 
16

nomenclature for Subpart W sources are reconciled with similar sources included in the recently 

proposed NSPS for oil and natural gas operations (40 CFR, Part 60, Subpart OOOO). 

Definitions for pneumatic devices are generally consistent with previous INGAA comments and 

recommendations, including INGAA’s June 2011 redline recommendations. However, additional 

clarity on affected pneumatic devices is desired. In addition, the recently proposed New Source 

Performance Standard (NSPS), Part 60, Subpart OOOO, includes pneumatic controllers as an 

affected source. EPA should ensure similar nomenclature and definitions are used unless rule 

context requires differences. 

In recent meetings and in its June 2011 letter to EPA, INGAA noted that confusion remains 

regarding classification of pneumatic devices, especially the types of intermittent devices that are 

subject to the rule and the types that are excluded from Subpart W. Including this level of detail 

in the Subpart A definition is unwieldy, so INGAA recommended including preamble discussion 

that would add clarity. As rules are implemented, preamble text often addresses questions that 

arise. As Subpart W has been implemented in 2011, it is clear that questions remain regarding 

pneumatic devices. Thus, INGAA recommends that the Final Rule include discussion of this 

issue, and example preamble text previously provided is reiterated here: 

"The definition of "intermittent bleed pneumatic device" has been revised and examples of 

devices that are categorized as intermittent pneumatics, as well as devices that are excluded, are 

provided here. Examples of intermittent pneumatic or control loop devices include level 

switches, positioners, pressure switches, thermostats, flow integrators, controller-pilots, and 

volume boosters. Gas actuated isolation valves and recording or control measurement devices are 

not considered pneumatic devices under Subpart W. Manual assist devices and pneumatic 

controller devices that are infrequently actuated, sealed, or do not emit to atmosphere are not 

considered pneumatic devices under Subpart W, including transmitters, transducers, relays (also 

called a booster, transmitter, or amplifier), gauges, control valve operator/actuators, and selfcontained regulators. Subpart W intermittent bleed pneumatic device emissions are only 

associated with the pneumatic controller, and actuator venting is not counted as a device." 

In addition, when multiple EPA regulations affect the same equipment, it is desirable for similar 

nomenclature and definitions across rules, accepting that minor differences may be necessary to 

address different regulatory context. On August 23, 2011, an NSPS was proposed for oil and 

natural gas operations (40 CFR, Part 60, Subpart OOOO), and the rule includes pneumatic 

controllers as an affected source. Common nomenclature should be used for Part 98, Subpart W 

(and Subpart A) and Part 60, Subpart OOOO. For example, Subpart OOOO refers to pneumatic 

controllers, but also uses the term pneumatic devices. For consistency and to better describe the 

affected source, INGAA recommends consistently using the term "pneumatic controller" for both 

rules. 

Response: EPA disagrees with the commenter on changes to the intermittent bleed pneumatic 

device definition. For the response on the intermittent bleed pneumatic devices, please see 

preamble Section II.A – Final Amendments to the General Provisions. EPA has determined that 

certain clarifications of the definition of these devices were acceptable, in particular, the 

specification that they automatically maintain a process condition and discharge all or a portion 

of the full volume of the actuator intermittently. However, EPA has decided not to list examples 
17

of intermittent bleed pneumatic devices in the preamble as the definitions are considered 

sufficient for operators to determine whether any particular device meets the definitions provided 

in the final rule. 

Regarding coordination of Subpart W definitions with the proposed NSPS Part 60, Subpart 

OOOO definitions, EPA has maintained the definition "pneumatic device(s)" in this rulemaking. 

While EPA strives to maintain consistency in equipment nomenclature, EPA has determined that 

the term "pneumatic device" is necessary to meet the goals of this rulemaking. Furthermore, 

given this is a reporting rule and does not require reductions in air emissions, EPA has 

determined that it is appropriate to use potentially different nomenclature, as deemed necessary, 

from existing or contemplated regulatory air programs. 

The commenter’s recommendation for the use of the term “pneumatic controller” for Part 60, 

subpart OOOO is outside the scope of the part 98 rulemaking. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 25 

Commenter Type: Trade Association 

 Comment: Miscellaneous items: 

18. EPA should harmonize nomenclature and definitions in the Proposed Rule with similar 

elements in the recently proposed NSPS for oil and natural gas operations (40 CFR, Part 60, 

Subpart OOOO). 

EPA recently proposed a new NSPS for oil and natural gas operations, 40 CFR, Part 60, Subpart 

OOOO. That rule proposes to regulate VOCs from three natural gas transmission and storage 

sources that are also subject to Subpart W reporting. Since both rules address the same 

equipment and processes, EPA should strive to harmonize nomenclature and definitions between 

the GHG Reporting Rule and Subpart OOOO. INGAA understands that regulatory context may 

demand differences between the rules in some cases, but EPA should strive for consistency when 

possible. It is apparent that EPA has cross-checked definitions in some cases, but in other cases 

there are differences. EPA should search the rules and compare definitions and nomenclature for 

common processes and equipment, and propose similar text unless rule context demands a 

difference. 

This comment does not comprehensively address all relevant nomenclature and definitions, but 

several examples are provided. A similar comment will be included in INGAA's comments on 

Subpart OOOO, where EPA should consider adding several Subpart W definitions that are not in 

Subpart OOOO. 

Subpart W refers to "pneumatic devices" and Subpart OOOO typically refers to "pneumatic 

controllers". INGAA recommends that "pneumatic controller" be consistently used in both rules. 

Although the listed process streams are different for part 98 and part 60, the definition of 
18

"compressor" in §98.238 is preferrable to the §60.5430 definition. 

The definition of "controller" in §60.5430 should be added to §98.6, which contains related 

definitions for device types (e.g., high or low bleed) but not the general definition. Similarly, 

several definitions in §98.6 should be added to Subpart OOOO §60.5430, including "continuous 

bleed", "centrifugal compressor wet seal degassing vent emissions", and "centrifugal compressor 

dry seals". 

Response: No rule change has been made as a result of this comment. Please see the response 

to EPA-HQ-OAR-2011-0512-0029, Excerpt 11 for further details. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 62 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Intermittent bleed 

pneumatic devices mean automated flow control devices powered by pressurized natural gas and 

used for [add: automatically] maintaining a process condition such as liquid level, pressure, 

delta-pressure and temperature. These are snap-acting or throttling devices that discharge [add: a 

portion or] the full volume of the actuator intermittently when control action is necessary, but 

does not bleed continuously. 

[highlighted text: IN ADDITION – RECOMMEND EXPLANATORY PARAGRPAH FOR 

THE PREAMBLE TO PROVIDE EXAMPLES (PER DISCUSSION WITH EPA) OF 

DEVICES INCLUDED AND DEVICES EXCLUDED. Example text follows:] 

The [comment bubble JMc13: INGAA considered including “examples” in the definition on 

“intermittent” device, but the list may be too large and cumbersome. As an alternative, INGAA 

recommends including a paragraph in the preamble that lists examples.] definition of 

“intermittent bleed pneumatic device” was revised and examples of devices that are categorized 

as intermittent pneumatics, as well as devices that are excluded, are provided here. Examples of 

intermittent pneumatic or control loop devices include level switches, positioners, pressure 

switches, thermostats, flow integrators, controller-pilots, and volume boosters. Gas actuated 

isolation valves and recording or control measurement devices are not considered pneumatic 

devices under Subpart W. Manual assist devices and pneumatic controller devices that are 

infrequently actuated, sealed, or do not emit to atmosphere are not considered pneumatic devices 

under Subpart W, including transmitters, transducers, relays (also called a booster, transmitter, or 

amplifier), gauges, control valve operator/actuators, and self contained regulators. Subpart W 

intermittent bleed pneumatic device emissions are only associated with the pneumatic controller, 

and actuator venting is not counted as a device. 
19

Response: Please see response to EPA-HQ-OAR-2011-0512-0029, Excerpt 11. EPA has 

modified the definition as recommended, but is not providing examples in the preamble for 

reasons explained in the referenced response. 

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 4 

Commenter Type: Industry - oil and gas 

Comment: “Intermittent bleed pneumatic devices” - AXPC and Chesapeake support and 

incorporate by reference the comments provided in A.1 [EPA-HQ-OAR-2011-0512-0042, 

Excerpt 11] and A.2 [EPA-HQ-OAR-2011-0512-0042, Excerpt 12] of Section 2 of API’s 

comment letter to EPA regarding the definition “intermittent bleed pneumatic devices.” 

Response: Please see response to EPA-HQ-OAR-2011-0512-0029, Excerpt 11. EPA has 

modified the definition as recommended but is not providing examples in the preamble for 

reasons explained in the referenced response. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 12 

Commenter Type: Industry - oil and gas 

Comment: Revision: In the definition of “intermittent bleed pneumatic devices”, EPA clarified 

that the devices are used for “automatically” maintaining a process condition ..., and that these 

devices discharge “all or a portion of” the full volume of the actuator intermittently... 

Comment: API supports this revision. 

Response: Please see response to EPA-HQ-OAR-2011-0512-0029, Excerpt 11. EPA has 

finalized the definition as proposed.
20

Section 5 ­ Source Category Definitions (98.230)

Commenter Name: William W. Grygar II 

Commenter Affiliation: Anadarko Petroleum Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0028

Comment Excerpt Number: 3 

Commenter Type: Industry - oil and gas 

Comment: • Anadarko notes that under §98.230(a)(2), dehydrators are still referenced in the 

onshore petroleum and natural gas production industry segment and maintains that dehydrators 

owned and operated by a third party should be excluded from applicability. Anadarko supports 

both API and AXPC's position on this concern. 

• Anadarko supports EPA's proposed changes to the onshore natural gas transmission 

compression industry segment under §98.230(a)(4). 

Response: Regarding §98.230(a)(2), EPA notes that the reporter has to determine whether or 

not equipment within their facility is subject to reporting depending on whether the reporter has 

common ownership or common control over the equipment. Please see preamble Section II.D.10 

– Responses to Major Comments on the Petroleum and Natural Gas Systems Source Category: 

Dehydrators owned and operated by third parties. Regarding the onshore natural gas 

transmission compression industry segment under §98.230(a)(4), EPA agrees with the 

commenter and has finalized this amendment, as proposed. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 32 

Commenter Type: Trade Association

Comment: [Please refer to the original comment text posted in the docket] § 98.230 Definition 

of the source category. 

[highlighted text: NO CHANGES]

Response: EPA thanks the commenter for their remarks. 

Section 5.1 ­ Onshore Petroleum and Natural Gas Production

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 13 
21

Commenter Type: Industry - oil and gas 

Comment: B. § 98.230 - Definition of source categories 

“Onshore petroleum and natural gas production” - Chesapeake and AXPC support EPA’s 

proposal to use the term “single well-pad” in §§ 98.230, 98.232(c), and 98.238. However, this 

term should be used consistently throughout the rule. We note that the definition of “facility with 

respect to onshore petroleum and natural gas production” does not use the term “single wellpad.” This definition should be revised to include “single well-pad” for the purpose of 

consistency and clarity in order to avoid the implication that there is a difference between EPA’s 

use of well pad and “single well-pad.” Additionally, to clarify that “associated with a single wellpad” is a defined term, a cross-reference should be provided to 40 C.F.R. § 98.238 (“associated 

with a single well-pad”) in the definition of “onshore petroleum and natural gas production” in § 

98.230. 

Response: Please see preamble Section II.C – Summary of Final Amendments under the 

Petroleum and Natural Gas Systems Source Category, and Section II.D – Summary of 

Comments and Responses Submitted on the Petroleum and Natural Gas Systems Source 

Category for the response on the definition of “associated with a single well-pad.” EPA agrees 

with these clarifications and in this final rule, has made a change to § 98.238 to ensure that 

“associated with a single well-pad” is used consistently. Since the term is defined in 98.238, 

which is a section that applies to Subpart W only, EPA does not see a need for cross reference in 

98.230. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 15 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has modified the definition of Onshore Petroleum and Natural Gas 

Production. 

Comment: API agrees with the proposed revisions and suggests one additional change to the 

definition. API requests removing the phrase: “auxiliary non-transportation related equipment” 

from the parenthetical list of portable non-self-propelled equipment because there is no emission 

methodology or reporting requirement for this equipment. 

Response: EPA disagrees that auxiliary non-transportation related equipment should be 

removed from the list of portable non-self-propelled equipment, because this could be interpreted 

to include drilling rigs, workover rigs and hydraulic fracturing engine driven pumping units 

which are specifically required to report GHG emissions. EPA has provided methods for such 

equipment under 98.233(z), which reporters must comply with. 
22

Section 5.2 ­ Onshore Natural Gas Processing

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 14 

Commenter Type: Industry - oil and gas 

Comment: “Onshore natural gas processing” - EPA has proposed revising the definition of 

onshore natural gas processing in the final Subpart W rule because it currently fails to distinguish 

between a boosting station, which EPA intended to exempt, and an "onshore natural gas 

transmission compression facility," which must report under the rule. 76 Fed. Reg. 56,027. EPA 

proposed revisions to this definition to address this problem. Specifically, EPA states: "We are 

proposing to strike the term 'this industry segment does not include reporting of emissions from 

gathering lines and boosting stations' because the edits proposed above clarify what 'onshore 

natural gas processing' means, and therefore it is unnecessary to discuss that which is excluded. 

Further, if we had decided to maintain the 'gathering lines and boosting' stations in the rule, EPA 

would have to propose and finalize a definition of the term 'gathering line and boosting' station, 

which EPA has previously noted we intend to consider in a future rulemaking (75 FR 74468)." 

Id. 

AXPC and Chesapeake appreciate EPA’s clarification that onshore natural gas processing does 

not include emissions from gathering lines and boosting stations. However, some gathering line 

and boosting stations would still be required to report under this proposed definition. By 

including CO2 removal as an activity that must be reported by “processing” facilities, the 

proposed definition would include compressor stations with amine units. Under the proposed 

rule, these compressor stations would suddenly become subject to the Subpart W reporting 

obligations, whereas they are currently exempt from reporting given the express exemption for 

gathering lines and boosting stations provided in § 98.230(a)(3). 

It would be arbitrary and capricious for EPA require reporting from certain gathering and 

boosting stations while others remain exempt. The reporting obligations for all gathering and 

boosting stations should be handled together in a comprehensive, forthcoming rulemaking, as 

EPA clearly stated it would address this source category. 76 Fed. Reg. 56,027 (citing 75 Fed. 

Reg. 74,468 (Nov. 30, 2010) (“EPA has decided not to include gathering lines and boosting 

stations as an emissions source in subpart W at this time [because EPA must conduct] further 

analysis to ensure an effective coverage of emissions from this source in order to inform future 

policy decisions.”)). Therefore, EPA should modify the rule to clarify that onshore natural gas 

processing is not intended to apply to boosting stations with amine units. 

If EPA determines to arbitrarily impose a reporting requirement on boosting stations with amine 

units, it is not feasible for reporters to gather information for this equipment in 2011. Reporters 

were not aware of a potential reporting obligation for this equipment until this notice was 

published and will not have adequate time to install the necessary monitoring equipment and 

reporting systems to obtain this data in 2011. Therefore, if EPA does require boosting stations 
23

with amine units to report their emissions under Subpart W, such units should not be obligated to 

report data from 2011 and should begin collecting data in 2012. 

Response: Please see preamble Section II.C – Summary of Final Amendments under the 

Petroleum and Natural Gas Systems Source Category, for the response on the definition of 

natural gas processing. This definition has two parts which EPA is retaining in the final rule: 

“separation of non-methane gases from produced natural gas,” and “the threshold ... [of] 25 

million standard cubic feet ... annual average throughput.” First, EPA notes that separation of 

non-methane gases is processing of natural gas according to Subpart W requirements. There are 

processes that are common between facilities that gather and boost natural gas and facilities that 

process gas. Hence, EPA has provided a 25 mmscf average daily throughput facility threshold to 

exclude non-fractionation facilities below that level from the natural gas processing segment. 

EPA has also determined that a limited number of facilities are over this threshold. Please see the 

Minimum Gas Processing Throughput memorandum, Petroleum and Natural Gas Systems 

(Subpart W) of the Greenhouse Gas Reporting Rule, Docket: EPA-HQ-OAR-2009-0923. 

EPA disagrees that reporters were not aware of the reporting obligations. The November 2010 

final rule clearly states that sulfur and carbon dioxide removal are considered part of the onshore 

natural gas processing segment. In addition, the November 2010 final rule also clearly provided 

the non-fractionator facility throughput threshold. Hence, the reporter obligations were clearly 

stated in the November 2010 final rule. Also as regards reporting of emissions for year 2011, 

please see the preamble for the Mandatory Reporting of Greenhouse Gases Rule 2011 Technical 

Corrections, Clarifying, Other Amendments to Certain Provisions, Section II.A.2, Subpart A – 

General Provisions: Summary of Comments and Responses, and preamble Section II.F – 

Summary of Comments and Responses Submitted on the Petroleum and Natural Gas Systems 

Source Category, for the response on a source category required to begin data collection in 2011. 

EPA notes that the BAMM provision in the November 2011 final rule provide ample guidance 

on using data already available to report emissions for reporting year 2011. Hence, EPA does not 

deem the requirement for large (i.e. ≥25 million scf/day) gas plants with acid gas removal, as 

being an issue for reporting year 2011. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 16 

Commenter Type: Industry - oil and gas 

Comment: [Please refer to the original comment text posted in the docket] Revision: EPA has 

revised the definition of Onshore Natural Gas Processing. 

Comment: API requests the following revisions shown in green font. 

(3) Onshore natural gas processing. Natural gas processing [add (red): means the separation] 

[add (green): of] [delete (red): ofseparates and recovers] natural gas liquids (NGLs) [delete (red): 
24

and/] or [delete (red): other] [delete (green): non-methane gases] [add (green): CO2] [delete 

(red): and liquids] [add (red):from a stream of] produced natural gas[add (red): , or the separation 

of NGLs into one or more component mixtures. Separation includes] [delete (red): using 

equipment performing] one or more of the following [delete (red): processes]: [add (red): forced 

extraction of natural gas liquids,] [delete (green): sulfur and] [add (red): carbon dioxide 

removal,] [delete (red): oil and condensate removal, water removal, separation of natural gas 

liquids, sulfur and carbon dioxide removal,] fractionation of NGLs, or [delete (red): other 

processes, and also] the capture of CO2 separated from natural gas streams. This segment also 

includes all residue gas compression equipment owned or operated by the natural gas processing 

[add (green): facility as facility is defined in §98.6.] [delete (green): plant] [delete (red): .facility, 

whether inside or outside the processing facility fence.] This [add (red): industry segment 

includes processing facilities] [delete (red):plants] [add (red): that fractionate gas liquids, and 

processing plants that do not fractionate gas liquids but have an annual average throughput of 25 

MMscf per day or greater.] [delete (red): Source category does not include reporting of 

emissions from gathering lines and boosting stations. This source category includes: (i) All 

processing facilities that fractionate. (ii) All processing facilities that do not fractionate with 

annual average throughput of 25 MMscf per day or greater.] 

[See original comment for track changes in different colors] 

Replacing the reference to “non-methane gases” with “CO2” specifically addresses GHG 

emissions from removing CO2 from acid gas streams. Similarly, API requests removing the 

reference to sulfur removal, as sulfur is not a GHG nor does the removal of sulfur produce GHG 

emissions beyond what would occur from the removal of CO2 from the acid gas stream. 

API also requests that “natural gas processing plants” be revised back to “natural gas processing 

facilities” to maintain distinction between the Subpart W definition and the KKK definition. The 

definition of gas plant has specific meaning in other regulations that do not apply here. 

API does not see any difficulty in the application of the term “facility” in the source category 

definitions provided for gas processing. API does not believe that using the terminology 

“facility” in this definition changes the reporting of other source categories that are located 

within the boundaries of a gas processing facility. EPA has already provided a work-around 

under 98.236(c). 

The September 9, 2011 preamble indicates (page 56027) that EPA replaced “facility” with 

“plant” because “facility” has a specific meaning under 98.6 that is not intended here. However, 

the source category definition provided in 98.230 is broader than the “facility” definition in 98.6. 

In addition, the use of “facility” also takes on a specific meaning for onshore petroleum and 

natural gas production in Subpart W. Therefore, a specific meaning for “facility” with respect to 

onshore natural gas processing is not unique to gas processing under Subpart W. 

Response: Please see preamble Section II.C – Summary of Final Amendments under the 

Petroleum and Natural Gas Systems Source Category, for the response on the definition of 

natural gas processing. This definition does not delete the general reference to “non-methane 
25

gases,” does not delete the inclusion of sulfur as a non-methane gas to focus this aspect of the 

definition on only CO2 removal, and does not change the term “plant” to “facility.” For future 

policy considerations, EPA is seeking GHG emissions information on large (>25 million scf/day) 

gas plants that operate processes other than just CO2 removal, such as H2S removal, because 

these two acid gases are typically both present in produced natural gas in varying concentrations, 

and it would be impractical to specify minimum concentrations of one or the other in defining a 

gas processing plant. 

It is not appropriate to replace the term "plant" with "facility" as suggested by the commenter. 

Facility has a specific meaning in 40 CFR 98.6, and refers to "any physical property, plant, 

building, structure, source, or stationary equipment located on one or more contiguous or 

adjacent properties in actual physical contact or separated solely by a public roadway or other 

public right-of-way and under common ownership or common control, that emits or may emit 

any greenhouse gas...." The "facility" can include multiple source categories, covered by 

different subparts under part 98. For onshore natural gas processing specifically, the 

"facility" would likely include, at a minimum, subpart C (General Stationary Combustion) and 

subpart W (petroleum and natural gas systems). The gas processing "plant" is only one part of a 

larger "facility". 

Section 5.3 ­ Onshore Natural Gas Transmission Compression

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 15 

Commenter Type: Industry - oil and gas 

Comment: “Onshore natural gas transmission compression” - AXPC and Chesapeake support 

and incorporate by reference the comments provided in W.3 [EPA-HQ-OAR-2011-0512-0042, 

Excerpt 17] of Section 2 of API’s comment letter to EPA regarding the definition “onshore 

natural gas transmission compression.” 

Response: Please see response to EPA-HQ-OAR-2011-0512-0042, Excerpt 17. 

Commenter Name: Jessica Stark 

Commenter Affiliation: SLR International Corp 

Document Control Number: EPA-HQ-OAR-2011-0512-0040

Comment Excerpt Number: 5 

Commenter Type: Industry - oil and gas 

Comment: Definition of ‘Transmission Pipeline’ and Definition of ‘Onshore Natural Gas 

Transmission Compression’ Industry Sector in 98.230(a)(4) 
26

I would like to request that these two definitions be expanded to clarify the applicability to 

compressor stations. Many companies operate numerous compressor stations that range from one 

single compressor at a location on a pipeline to boost pressure up to larger stations with multiple 

compressors. The units operate to compress gas to serve different functions – from gas collection 

and field gathering to put gas into 6 to 8 inch pipelines, or to compress gas (their own produced 

gas as well as that of other companies) to transmit it through larger diameter 12 inch pipelines 

prior to sale to utilities or local distribution companies. 

As currently written, it could be interpreted that any compressor station operating on a FERClisted interstate or intrastate pipeline would be covered by the Transmission Compression 

industry sector. This is likely not EPA’s intention. I would like to request clarifying language to 

indicate exactly the types of stations that are considered ‘Transmission Compression.’ This could 

be accomplished by the addition of delineating parameters such as stations compressing gas for 

transmission in 12 (or 16) inch or greater pipelines, just prior to sale to a Local Distribution 

Company or other end user. This would only cover the final compressor stations in the process 

and not the gathering and boosting stations that are located everywhere along the lines between 

the wells and the point of transfer to regional gas companies. In locations where there is no gas 

processing plant, there is no clear delineation between field gathering and transmission 

compression. The same company can act as gas producer, gas collector, and gas transmitter, so 

using the list of FERC pipelines has too broad of a scope. The rule should have clearly 

identifying parameters such as pipeline diameter, operating pressure, or a minimum compression 

capacity. 

As an example, I am providing information on a representative compressor station operated by 

one of my clients. The station compresses gas collected by the company as well as other 

production companies in the region, and is one of their largest compressor stations. Many other 

stations have only one or two small compressors. At this station, the gas is dehydrated and 

compressed for transmission in a 12 inch diameter pipeline. Approximately 15 million cubic feet 

per day is compressed and transmitted. It is our opinion that the vent rates on the blowdown 

vents, isolation valves and rod packing vent lines on the compressors at this station would be so 

low they would be difficult to measure using the methods required by the rule. These are not 

very large units and the cost associated with performing these measurements does not seem to be 

worthwhile in terms of the accuracy of the magnitude of emissions measured. Emission factors 

(such as those presented for the individual vent types in the Technical Support Documents for 

Subpart W or those used for all compressor vents as allowed for Onshore Production 

compressors) would adequately represent emissions from smaller compressor units such as these. 

[See original comment for table: Representative Compressor Station in West Virginia] 

We request that the Transmission Compression category be defined using parameters that would 

clearly capture only the larger compressor stations in the industry due to the effort required to 

perform annual leak detection and vent measurement surveys, or that if the scope of the industry 

sector is so broad as to cover many small stations, that a size threshold be included to allow the 

use of emission factors to estimate compressor venting emissions. 
27

Response: EPA disagrees with the commenter and is retaining the proposed definition of 

transmission pipeline in this final rule. Please see preamble Section II.C – Summary of Final 

Amendments under the Petroleum and Natural Gas Systems Source Category, for the response 

on the definition of onshore natural gas transmission compression. EPA notes that there is no 

ambiguity in the definition of a transmission pipeline. It is EPA’s intent that any compression 

station located on a transmission pipeline be designated as transmission station. Also, no 

combination of compressor size, pressure rating, pipeline diameter and compression ratio will 

uniquely separate compressors in these five segments of the industry. Finally, EPA notes that 

since the facility in the natural gas transmission segment is an individual compressor station, the 

25,000 tonnes of CO2e emissions reporting threshold, will exempt small compressor stations. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 17 

Commenter Type: Industry - oil and gas 

Comment: [Please refer to the original comment text posted in the docket] Revision: EPA has 

revised the definition of Onshore Natural Gas Transmission Compression. 

Comment: API requests the following revisions shown in green font. 

Onshore natural gas transmission compression. Onshore natural gas transmission compression 

means any stationary combination of compressors that move natural gas [delete (red): at elevated 

pressure] from production fields[add (red): ,] [delete (red): or] natural gas processing [add 

(green): facilities] [delete (green): plants] [delete (red): ,facilities] [add (red): or] [delete (red): in] 

[add (red): other] transmission [add (red): compressors through transmission] pipelines to natural 

gas distribution pipelines [add (red):, LNG storage facilities,] or into [add (red): underground] 

storage. In addition, transmission compressor station [delete (red): may] include[add (red): s] 

equipment for liquids separation [delete (red):, natural gas dehydration,] and tanks for the storage 

of water and hydrocarbon liquids. Residue (sales) gas compression [add (red): that is part of] 

[add (green): an] [delete (red): operated by natural gas processing facilities are included in the] 

onshore natural gas processing [add (green): facility (as facility is defined in §98.6)] [delete 

(green): plant] [add (green): is] [delete (green): are] [add (red): included in the onshore natural 

gas processing] segment and are excluded from this segment. [delete (red): This source category 

also does not include reporting of emissions from gathering lines and boosting stations – these 

sources are currently not covered by subpart W.] 

[See original comment for track changes in different colors] 

As discussed in comment W.2 [EPA-HQ-OAR-2011-0512-0042, Excerpt 16] above, API 

requests that “natural gas processing plants” be revised back to “natural gas processing facilities” 

to maintain distinction between the Subpart W 

Response: Please see response to comment EPA-HQ-OAR-2011-0512-0040, Excerpt 5. In this 

final rule, EPA has adopted most of the text edits recommended here with exception of changing 
28

the term “process plant” back to “process facility.” EPA is not changing the term “plant” to 

“facility”; please see response to EPA-HQ-OAR-2011-0512-0042, Excerpt 16 for further details.
29

Section 6 ­ Greenhouse Gases to Report (98.232)

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 10 

Commenter Type: Trade Association 

Comment: Reporting N2O is inappropriate for vented emissions and equipment leaks unless the 

emissions are controlled with a combustion device. N2O reporting is required by §98.232(n) and 

adding N2O as a reportable GHG in §98.232(e) and (f) will cause confusion. This proposed 

revision should be deleted. 

§98.232(e) and (f) list the vent and equipment leak sources that must be reported for natural gas 

transmission compression and for underground storage, respectively. Subpart W currently 

indicates that CO2 and CH4 should be reported and both constituents are in natural gas. The 

Proposed Rule adds N2O to the list of GHGs to report. Adding this requirement preceding a list 

of vented sources and equipment leaks will cause unnecessary confusion. The proposed addition 

of N2O should be deleted in the Final Rule. 

Reporting N2O is appropriate for combustion, (e.g., when vented or fugitive sources are routed 

to a flare or other combustion device). §98.233(n) provides the GHG estimation methods for 

vented and fugitive sources that are controlled via combustion and includes N2O reporting. Since 

§98.232(n) addresses N2O reporting for Subpart W transmission compression and underground 

storage sources that are combusted, it is not necessary to add N2O to §98.232(e) or (f). 

Response: EPA’s intention in the November 2010 rule is that all industry segments that report 

flaring emissions include N2O emissions in their reporting. In this final rule, EPA has clarified 

the requirement to report N2O for all industry segments. Emissions sources with no N2O 

emissions would report zero emissions. Please see preamble Section II.C – Final Amendments 

to the Petroleum and Natural Gas Systems Source Category, for the response on the Greenhouse 

Gases to Report. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 28 

Commenter Type: Trade Association

Comment: Reference to §98.232(j) in §98.232(a) should be deleted because (j) has been 

deleted. 

The Proposed Rule deletes §98.232 (j), which referred to criteria for flaring, and "reserves" that 

section. Section §98.232(a) includes a reference to section (j), "...emissions from each flare as 

specified in paragraph (j) of this section, ...". To reconcile with other revisions, the reference to 

§98.232(j) should be deleted. 
30

Response: EPA agrees with the commenter. In this final rule, EPA has removed the reference to 

40 CFR 98.232(j) and has replaced it with 40 CFR 98.232 (b) through (i) in 40 CFR 98.232(a).

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 34 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] § 98.232 GHGs to 

report. 

[highlighted text: Add section (m) to clarify that operators can use DEFAULT values or 

company records for percent methane and CO2 for vented and fugitive emissions from 

transmission and storage segments 

Revise section (j) based on INGAA-EPA May 26 meeting discussion to clarify : (1) FLARE 

emissions are only reported if flares are listed for the segment in §98.232; (2) flare / vapor 

recovery efficiency should be applied when reporting emissions for ANY source that includes 

such control; and (3) if flares are not listed in §98.232 but flaring applies, the combustion 

emissions from the flare do NOT need to be reported] 

(j) [delete: All applicable i] [add: Industry] segments [add: in §98.232(b) through (d) include 

flares as a listed source and] must report the CO2, CH4, and N2O emissions from each flare. 

(i) [add: Other industry segments in §98.232(e) through (i) should not report flare emissions but 

should consider flaring, vapor recovery, or other control when reporting emissions of CH4 and 

CO2 under §98.236 based on calculations in §98.233 that estimate uncontrolled emissions. The 

emissions reported under §98.236 should consider the reduction efficiency (e.g., flare 

efficiency). Equation W-19 in §98.233(n) can be used to calculate CH4 emissions from a 

controlled emission source. Equation W-19 also applies for CO2 emissions for a vapor recovery 

system. Equation W-20 applies for CO2 emissions for combustion based control (flare, thermal 

oxidizer). The calculation approach should be documented under §98.3(g).] [comment bubble 

JMc1: Approach is to provide this “direction” once rather than in each 98.233 section, and 

reporting criteria based on May 26 INGAA meeting with EPA. With this addition, flare 

references in §98.233 sections for transmission are deleted (see below).] 

[add: (m) In [comment bubble JMc2: To simplify, intent is to allow operators in transmission, etc 

to apply either a default composition or to use company records / gas analysis. Alternate would 

be to add this criteria within §98.233(u)(2) and revise equation citations for gas composition 

throughout §98.233 source calculation sections.] lieu of the requirements for natural gas 

composition specified in §98.233, the operator may alternately apply a gas composition in (1) or 

(2) when calculating emissions in §98.233: 

(1) For sources in §98.232(e), (f), (g) and (i), default [comment bubble JMc3: Based on default 

assumed in DOE/EIA national inventory report – e.g., see “Documentation for Emissions of 
31

Greenhouse Gases in the United States 2008”, DOE/EIA-0638 (2008), January 2011 Default 

would apply for transmission, underground storage, LNG storage, and distribution.]natural gas 

composition of 95 percent CH4 and 1 percent CO2 (by volume). 

(2) For sources in §98.232(e) through (i), company gas records consistent with §98.233(u)(2).] 

Response: Regarding adding section (m), EPA disagrees with the commenter. Please see the 

response to EPA-HQ-OAR-2011-0512-0029, Excerpt 43. 

Regarding (j), EPA disagrees with the commenter, and in this final rule, EPA is removing the 

reference to 40 CFR 98.232(j) and has replaced it with 40 CFR 98.232 (b) through (i) in 40 CFR 

98.232(a). 

Regarding (i), emissions sources are to report the emissions sent to the flare under that emissions 

source type and not under the flares source. Please see section 98.233(n)(9) for further details. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 12 

Commenter Type: Trade Association 

Comment: Section 98.232(i): The proposed amendments to 98.232(i) would change the 

numbering of the distribution emission sources and inadvertently omit pipeline main equipment 

leaks from 98.232(i). In the November 2010 final rule, section 98.232.(i)(4) listed “pipeline main 

equipment leaks”. In the September 2011 Proposal, EPA proposes to revise section 98.232(i)(4) 

to include “equipment leaks from vaults at below grade metering-regulating stations” but the 

agency proposes no further edits to the list. There are no proposed revisions to the first paragraph 

in section 98.233(r), which references section 98.232(i). As a result, the list in 98.233(r) will 

need to be revised to reflect these proposed changes. 

Response: EPA thanks the commenter for pointing out this omission. This final rule includes a 

revision to 98.232(i) to restore the appropriate emissions sources. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 19 

Commenter Type: Industry - oil and gas 

Comment: Revision: 98.232(a) indicates “You must report CO2, CH4, and N2O emissions 

from each industry segment specified in paragraph (b) through (i) of this section, CO2, CH4, and 

N2O emissions from each flare as specified in paragraph (j) of this section, and stationary and 

portable combustion emissions as applicable as specified in paragraph (k) of this section” 

(emphasis added). 
32

Comment: Paragraph (j) language was deleted and paragraph (j) is now [Reserved]. The 

reference to paragraph (j) in this section should be deleted. [Flare emissions will be covered in 

paragraphs (b) through (i). 

Response: EPA agrees with the commenter. In this final rule, EPA has removed the reference to 

40 CFR 98.232(j) and has replaced it with 40 CFR 98.232 (b) through (i) in 40 CFR 98.232(a).

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 20 

Commenter Type: Industry - oil and gas

Comment: Revision: 98.232(c) EPA has added the word “single” prior to well-pad to designate 

the emission source types reported for onshore petroleum and natural gas production facilities. 

Comment: API supports this revision and interprets this to apply to single well bore and multiple 

well bore well-pads. 

Response: EPA agrees with the commenter. The well-pad can have a single wellhead or 

multiple wellheads on the same well-pad.

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 21 

Commenter Type: Industry - oil and gas

Comment: Revision: EPA has revised 98.232(c)(22) to specifically state that the methods in 

98.233(z) must be used for emissions from stationary or portable fuel combustion equipment that 

is “located at an onshore petroleum and natural gas production facility as defined in 98.238.” 

Comment: Previously this paragraph referenced combustion equipment at an onshore production 

well-pad. However, the reference for the definition of onshore petroleum and natural gas 

production facility in 98.238 is limited to “equipment on a well-pad or associated with a well-pad 

and CO2 EOR operations...” Therefore, this revision does not change the requirements of this 

paragraph. 

In addition, API interprets “well drilling and completion equipment” and “workover equipment” 

to refer specifically to equipment used on a well pad. This is consistent with the proposed 
33

definition of “associated with a single well pad” which links the emission sources associated 

with a single well-pad to the produced hydrocarbon stream from wells located on that well-pad. 

Response: Regarding combustion equipment, EPA has clarified the intention of the requirement 

by clarifying the definition of facility with respect to onshore petroleum and natural gas 

production in 98.238. The reporter has to make a determination on how the requirements of 

98.232(c)(22) and well drilling, completion and workover apply in the context of this 

clarification. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 22 

Commenter Type: Industry - oil and gas

Comment: Revision: EPA added that N2O emissions are required to be reported for the sources 

types under 98.232 (e), (f), (g), (h), and (i). 

Comment: 98.232(d) is excluded in the regulatory language. This appears to be an oversight in 

the Federal Register version. 

Response: EPA agrees with the commenter. In this final rule, EPA has updated the reference to 

40 CFR 98.232 (b) through (i), which includes 98.232(d). 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 4 

Commenter Type: Industry - oil and gas 

Comment: D. Onshore Production Flares 

In Table 2 of the preamble EPA recaps the status of its responses to issues raised in API’s 

petition for reconsideration, including, “Requirements for flare stack emission associated with 

onshore oil and gas production. API asserted that ‘‘[e]missions from flare stacks associated with 

onshore oil and gas production were not included in the Petroleum and Natural Gas production 

industry segment in the proposed rule * * * the inclusion of emissions from flare stacks 

associated with onshore oil and gas production is duplicative, burdensome, and a potential source 

of reporting inaccuracies’’. 

EPA contends that it has addressed this issue in Table 2 of the current proposal. 

API Response: 

EPA has not fully addressed this issue or the primary issue API stated in relation to this source 

type in the proposed technical corrections. 
34

EPA’s addition of Flare Stack Emissions as a discrete source type in 98.232 (c) (9) of the 

November 30, 2010 final rule represents a significant expansion of the rule requirements which 

was not included in the proposed rule and thus not able to be commented on prior to finalization. 

API understands and acknowledges that the proposed rule referred certain source types to 98.233 

(n) for calculation of emissions from gas sent to flares from these specific source types. This has 

been discussed with EPA and communicated in written form previously and API accepts this 

coverage of flared gas which was proposed and then finalized. 

The emissions calculation methodologies for dehydrator vents (233(e)), gas well venting during 

completions and workovers with and without hydraulic and non-hydraulic fracturing (98.233(g) 

and (h)), onshore production storage tanks (98.233(j)), well testing venting and flaring 

(98.233(l)), associated gas venting and flaring (98.233(m)), and centrifugal compressor venting 

(98.233(o)) each acknowledge that emissions may be sent to a flare. Each of these sections 

references the method in 98.233(n) as the means for calculating emissions from flares. However, 

nothing in the proposal indicated the potential inclusion of flare stacks as a discrete source type 

for onshore production in the final rule. In prior communications with EPA, API has noted the 

difficulties associated with coverage of “all flares” in the onshore production sector with no 

exclusions or de minimis levels or volumes. In these same communications API has noted that 

the specific source types which refer to the flaring methodology for calculation represent the vast 

majority of gas which is sent to flare in the onshore production sector and that including flare 

stacks as a discrete source type imposes significant burden without commensurate emissions 

coverage. 

Although there are some minor flaring types which are not covered in the specific source types, 

such as flaring of small amounts of gas entrained in the drilling fluid on those occasions where 

gas enters the drilling fluid, these are small, infrequent, and very difficult to adequately capture 

and estimate volume. API and its members are not aware of any significant flaring sources which 

are not specifically covered in the other specific source types in the rule. Inclusion of flare stacks 

as a discrete source type for onshore production in 40 CFR 98.232 (c) (9) requires that operators 

put systems in place to capture every flare event regardless of how small, estimate volume, 

calculate emissions, and then report the voluminous information required by the rule. Given the 

very minor volumes of flared gas that are not already captured under the other source types 

specified in 98.232, inclusion of flares as a discrete source type simply does not make sense from 

an emissions coverage vs. burden and cost perspective. 

Additionally, API has previously stated that it believes that the rule’s requirements for 

calculation and reporting of emissions from flares are duplicative for onshore oil and natural gas 

operations. The rule does acknowledge the possibility of double counting flare emissions, and 

98.233(n)(9) requires that “flare emissions determined under subparagraph (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 emission.” 

API requests that EPA remove flare stacks as a source type for onshore production at 

98.232(c)(9) since EPA has not properly proposed this addition and has not provided an 

explanation yet as to why flare stacks were added as a source type in the first place, except to 

state in a response to comments[Footnote 5: Comment Number: EPA-HQ-OAR-2009-0923-
35

1155-31; Response to Comments, Volume I, page 88] that “onshore production, offshore 

production and natural gas processing, must report the CO2, CH4, and N2O combustion 

emissions from each flare.” 

Response: 

EPA has reviewed your comment and is unable to respond at this time. Your question relates to 

an issue or issues currently the subject of ongoing litigation. Please monitor the website for any 

additional guidance that may be available in the future. 

_http://www.epa.gov/climatechange/emissions/subpart/w.html 

Commenter Name: Curtis J. Winner 

Commenter Affiliation: New Mexico Gas Company (NMGC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0047

Comment Excerpt Number: 3 

Commenter Type: Industry - oil and gas 

Comment: The proposed amendments to 98.232.(i) changes the numbering of the distribution 

emission sources and ends up omitting pipeline main equipment leaks from 98.232(i). In the 

November 2010 final rule 98.232.i.4 was “pipeline main equipment leaks”. In the September 

2011 revision, 98.232.i.4 is listed as “equipment leaks from vaults at below grade meteringregulating stations” with no further edits to the list. The first paragraph in section 98.233.r was 

not amended and references 98.232.(i) so the list in 98.233.r will need to be revised to reflect 

these proposed changes.

Response: EPA agrees with the commenter. In this final rule, EPA has revised the opening 

paragraph to 98.233(r) to include 98.232(i)(6) to reflect changes in the September 2011 proposal. 

 
36

Section 7 ­ Calculating GHG Emissions (98.233) and Data Reporting

Requirement (98.236)

Commenter Name: 

Commenter Affiliation: Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2011-0512-0026

Comment Excerpt Number: 7 

Commenter Type: Industry - other 

Comment: EPA should standardize the mol fraction of CH4 and CO2 used for underground 

storage of natural gas in the various emission equations that are required to be used. For 

Pneumatic Device Venting - Equation W-1 uses 0.95 for CH4 and 0.01 for CO2 – Also, should 

the footnote in Equation W-1 refer to paragraph (u)(2) instead of (u)(2)(i)? 

For Compressor Vents - Equation W-26 uses 0.95 for CH4 and 0.01 for CO2 

For Equipment Leaks - Equation W-30 uses 0.974 for CH4 and 0.01 for CO2 

For Population Count Fugitive Emissions - Equation W-31 uses 1 for CH4 and 0.011 for CO2 

EPA should standardize on one mole fraction for CH4 (0.95) and for CO2 (0.01) in all of these 

equations involving natural gas calculations. 

Response: EPA agrees with the commenter about standardizing the mole fraction of CH4 and 

CO2 for underground storage in Equations W-1, W-30, and W-31. In this final rule, for 

Equations W-1, W-30, and W-31, GHGi for CH4 = 0.975 and GHGi for CO2 = 1.1*10-2 which are 

the compositions of methane and carbon dioxide in total hydrocarbon for transmission pipeline 

quality natural gas. 

EPA is not accepting any comments on Equation W-26, because amendments to this equation 

were not proposed. Hence, this equation is outside the scope of this rule. EPA may consider 

your comment in future rulemakings. Additionally, your question relates to an issue or issues 

currently the subject of ongoing litigation. Please monitor the website for any additional 

guidance that may be available in the future. 

http://www.epa.gov/climatechange/emissions/subpart/w.html

EPA disagrees with the commenter in regard to the citation (u)(2)(i) in parameter GHGi in 

Equation W-1 being incorrect. For this equation, only onshore petroleum and natural gas 

production reporters are referred to paragraph (u) to determine the mole fractions of CH4 and 

CO2 in produced natural gas, and this is specifically addressed in (u)(2)(i). For reporters under 

other applicable industry segments, EPA is providing the mole fractions of CH4 and CO2 within 

the parameter definition. Hence, in this final rule, in Equation W-1, GHGi refers to (u)(2)(i). 

Commenter Name: Jeff Applekamp 

Commenter Affiliation: Gas Processors Association 
37

Document Control Number: EPA-HQ-OAR-2011-0512-0034

Comment Excerpt Number: 3 

Commenter Type: Trade Association 

Comment: On September 9, 2011, EPA proposed numerous technical amendments to Subpart 

W of the GHGRP for the following purposes: to respond to requests for reconsideration filed by 

industry groups, 76 Fed. Reg, 56012, “to ensure that the 2010 final rule is implemented as 

intended”, and “to address questions and issues raised by stakeholders since development of the 

proposal of the technical corrections rule.” 76 Fed. Reg. 56019. GPA strongly supports 

resolution of these technical matters, which will ensure consistency among GHGRP subparts and 

consistent application across reporting entities under the rule. GPA, through their members, has 

worked with API and API members on the development of comments on these proposed 

amendments and hereby incorporates by reference the comments filed by API on October 24, 

2011, including comments that address technical matters not addressed in the September 9, 2011 

proposal. 

Response: EPA has carefully reviewed GPA and API comments and has responded to every 

unique comment submitted. In regard to GPA’s incorporation by reference of API comments, 

for further information, please see EPA responses to API’s comments in this docket. 

Commenter Name: Richard Bye 

Commenter Affiliation: Centerpoint Energy, Inc. 

Document Control Number: EPA-HQ-OAR-2011-0512-0044

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas 

Comment: CenterPoint Energy, Inc. supports the detailed technical comments filed in this 

docket of the American Gas Association (AGA), and the Interstate Natural Gas Association of 

America (INGAA). Thank you for your consideration of these comments. 

Response: EPA has carefully reviewed INGAA’s and AGA’s comments and has responded to 

every unique comment submitted. In regard to Centerpoint Energy’s incorporation by reference 

of INGAA and AGA comments, for further information, please see EPA responses to INGAA’s 

and AGA’s comments in this docket.

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 53 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] § 98.236 Data 

reporting requirements. 
38

[highlighted text: CORRECTIONS ARE ADDED FOR CONSISTENCY WITH §98.233 

REVISIONS AND UNDERSTANDING OF EPA’S INTENT ON DESIRED INFO FOR 

REPORTING] 

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) Report annual emissions separately for each of the industry segments listed in paragraphs 

(a)(1) through (8) of this section in metric tons CO2e per year [delete: at standard conditions]. 

For each segment, report emissions from each source type §98.232(a) in the aggregate, unless 

specified otherwise. For example, an onshore natural gas production operation with multiple 

reciprocating compressors must report emissions from all reciprocating compressors as an 

aggregate number. 

(c) For each aggregated source, unless otherwise specified, report activity data and emissions (in 

metric tons CO2e per year [delete: at standard conditions]) for each aggregated source type as 

follows: 

Response: EPA agrees with the commenter on removing “at standard conditions” from 40 CFR 

98.236(a). However, in this final rule, EPA is making additional changes to this paragraph. 

Hence this issue does not arise anymore. 

EPA is also modifying 40 CFR 98.236(c) to clarify the reporting of emissions from equipment in 

co-located facilities and the reporting of vented and flared emissions from the same source type. 

With this change, the text that the commenter commented on is not part of this final rule and is 

therefore not an issue. 

Section 7.1 ­ Standard temperature and pressure

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 24 

Commenter Type: Industry - oil and gas 

Comment: Inconsistencies 

Chesapeake and AXPC have concerns about inconsistencies in the text of the Subpart W rule. 

(1) Standard Conditions 

EPA has proposed changes to several equations in Subpart W impacting whether emissions are 

calculated at standard conditions or atmospheric conditions. AXPC and Cheapeake support 
39

EPA’s efforts to achieve consistency in the rule because doing so will reduce the burden 

associated with calculating facility emissions. Therefore, we support and incorporate by 

reference API’s comments in W.8 [EPA-HQ-OAR-2011-0512-0042, Excerpt 24], W.10 [EPAHQ-OAR-2011-0512-0042, Excerpt 26], W.11[EPA-HQ-OAR-2011-0512-0042, Excerpt 27], 

W.14 [EPA-HQ-OAR-2011-0512-0042, Excerpt 30], W.15 [EPA-HQ-OAR-2011-0512-0042, 

Excerpt 31], W.20 [EPA-HQ-OAR-2011-0512-0042, Excerpt 36], W.24 [EPA-HQ-OAR-2011-

0512-0042, Excerpt 40], W.28 [EPA-HQ-OAR-2011-0512-0042, Excerpt 44], W.29 [EPA-HQOAR-2011-0512-0042, Excerpt 45], W.30 [EPA-HQ-OAR-2011-0512-0042, Excerpt 46], 

W.36[EPA-HQ-OAR-2011-0512-0042, Excerpt 52], and W.41 [EPA-HQ-OAR-2011-0512-

0042, Excerpt 58] of Section 2 of its letter regarding corrections to address reporting emissions at 

standard, atmospheric and actual conditions. 

Response: For the response to API’s comment in W.8 of Section 2, please see the response to 

EPA-HQ-OAR-2011-0512-0042, Excerpt 24. 

For the response to API’s comment in W.10 of Section 2, please see the response to EPA-HQOAR-2011-0512-0042, Excerpt 26. 

For the response to API’s comment in W.11 of Section 2, please see the response to EPA-HQOAR-2011-0512-0042, Excerpt 27. 

For the response to API’s comment in W.14 of Section 2, please see the response to EPA-HQOAR-2011-0512-0042, Excerpt 30. 

For the response to API’s comment in W.15 of Section 2, please see the response to EPA-HQOAR-2011-0512-0042, Excerpt 31. 

For the response to API’s comment in W.20 of Section 2, please see the response to EPA-HQOAR-2011-0512-0042, Excerpt 36.

For the response to API’s comment in W.24 of Section 2, please see the response to EPA-HQOAR-2011-0512-0042, Excerpt 40.

For the response to API’s comment in W.28 of Section 2, please see the response to EPA-HQOAR-2011-0512-0042, Excerpt 44.

For the response to API’s comment in W.29 of Section 2, please see the response to EPA-HQOAR-2011-0512-0042, Excerpt 45.

For the response to API’s comment in W.30 of Section 2, please see the response to EPA-HQOAR-2011-0512-0042, Excerpt 46. 

For the response to API’s comment in W.36 of Section 2, please see the response to EPA-HQOAR-2011-0512-0042, Excerpt 52.

For the response to API’s comment in W.41 of Section 2, please see the response to EPA-HQOAR-2011-0512-0042, Excerpt 58.
40

Section 7.2 ­ (t) (u) (v) Volumetric and mass conversion [W­33 to W36]

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 27 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] The rule 

inconsistently references and applies the gas volume and mass emission conversion calculations 

in §98.233(t) – (v) (e.g., see Comment 2 regarding natural gas composition). To clarify and 

standardize calculations and avoid unnecessary confusion and associated errors, the same GHG 

emissions calculation methodology and common engineering units should be used for all 

emission sources in §98.233(a) through (r). 

This is a broader comment regarding revisions associated with converting engineering units. 

Subpart W clarity and readability would be greatly improved if there was more commonality 

across emission estimate sections. §98.233(a) through (r) provide methods for source-specific 

emission estimates, and §98.233(t) through (v) provide calculations to convert engineering units 

from volumetric emissions to standard volumes and mass of CO2e emissions. Rule clarity would 

be greatly enhanced if the objective of calculations in sections (a) through (r) was to calcualte 

emissions with a common endpoint for engineering units (i.e., volumetric emissions at actual or 

standard conditions). Then, consistently refer to (t), (u) and (v) to convert natural gas volumetric 

emissions to CO2 and CH4 volumetric and mass emissions. The lack of a standard format 

hinders implementation clarity and also results in confusing or conflicting requirements. For 

example, Comment 2 discusses revisions where conflicts remain regarding natural gas 

composition assumptions. 

EPA may view this as a daunting task at this point in the process, but as Subpart W is 

incrementally (and repeatedly) revised, basic structural and organizational issues should be 

addressed. To implement this approach, only minor revisions would be needed in the equations 

and parameters in subsections (a) through (r) – and conflicting requirements such as natural gas 

composition assumptions would be clearly addressed. The revisions should follow several basic 

principles: 

§98.233(a) – (r) should not prescribe whether volumetric natural gas measurements are at actual 

or standard conditions (i.e., temperature and pressure). Rather, if volumetric gas measurements 

are at actual conditions, the rule should reference §98.233(t) and equation W-33 to convert the 

gas volumes to standard temperature and pressure. Volumetric conversions are not needed if 

volumetric gas measurements are reported at standard conditions. 

A specific natural gas composition (i.e., concentration of CH4 and CO2) should not be included 

in (a) – (r). Instead, §98.233(u) should always be referenced to determine the appropriate gas 

composition with equation W-35 referenced to calculate volumetric GHG emissions. An 

example of how this would be implemented is provided for reciprocating compressors based on 

suggested revisions to Equation W-26. (Note that this also relates to Comment 2 issues regarding 
41

conflicting natural gas composition assumptions). Equation W-26 should calculate natural gas 

volumetric emissions and then §98.233(u) and equation W-35 should be referenced to calculate 

volumetric GHG emissions. Equation W-26 revisions would include: 

“(6) Estimate annual emissions using the flow measurement and Equation W-26 of this section. 

[See original comment for Equation W-26] 

Where: 

Es,[delete: i,]m = Annual [delete: GHG i (either CH4or CO2)] volumetric emissions [add: of 

natural gas] [delete: at standard conditions], in [add: standard] cubic feet [add: for the unique 

mode and vent source combination]. 

MTm = Measured gas [add: volumetric] emissions in standard cubic feet per hour [add: for the 

unique mode and vent source combination]. 

Tm= Total time the compressor [add: package] is in the mode for which Es,[delete: i,]m is being 

calculated, in the calendar year in hours.” 

Calculations of mass emissions for each GHG should not be included in §98.233(a) – (r) 

equations and calculations. Instead, §98.233(v) and equation W-36 should be referenced to 

calculate GHG mass emissions. For example, for pneumatic devices Equation W-1 would not 

include "GHGi" or Convi" terms but rather reference §98.233(u) and Equation W-35 to address 

natural gas composition and §98.233(v) and Equation W-36 to calculate emissions on a mass 

basis. 

Response: EPA disagrees with the commenter. EPA acknowledges that some changes in the 

equations have resulted in incorrect references to 98.233(t), (u), and (v), which are fixed in this 

final rule. However, EPA notes that not all monitoring methods are similar in their calculation 

methods; some use emission factors, some actual measurements, some simulations, and others a 

blend of these methods. As a result the output from these calculations is a mix of emissions at 

actual and standard conditions. Therefore, the use of 98.233(t) is appropriate. Also, if the actual 

conditions for any of the equations are STP conditions then the use of 98.233(t) will not result in 

any error; please see response to EPA-HQ-OAR-2011-0512-0042, Excerpt 44 for further details. 

In this final rule, 40 CFR 98.233 (a) through (r) accurately reference either 40 CFR 98.233 (t), 

(u), and (v), to convert natural gas or GHG volumetric emissions at actual conditions to standard 

conditions, natural gas volumetric emissions at standard conditions to GHG volumetric 

emissions at standard conditions, and GHG volumetric emissions at standard conditions to GHG 

mass emissions in carbon dioxide equivalent, respectively. Thereby, regardless of the end result 

of the Equations W-1 through W-32, all emission estimates are converted to GHG mass 

emissions in carbon dioxide equivalent. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 
42

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 42 

Commenter Type: Trade Association

Comment: [Please refer to the original comment text posted in the docket] Volumetric 

emissions. Calculate volumetric emissions at standard conditions as specified in paragraphs (t)(1) 

or (2) of this section[add: , with actual pressure and temperature] determined by engineering 

estimate based on best available data unless otherwise specified. 

(1) Calculate natural gas volumetric emissions at standard conditions [delete: by converting 

actual temperature and pressure of natural gas emissions to standard temperature and pressure of 

natural gas] using [add: actual natural gas emissions temperature and pressure, and] Equation W–

33 [delete: of this section. 

[See original comment for Eq. W-33] 

Where: 

Es,n = Natural gas volumetric emissions at standard temperature and pressure (STP) conditions 

in cubic feet. 

Ea,n = Natural gas volumetric emissions at actual conditions in cubic feet. 

Ts = Temperature at standard conditions ( °F). 

Ta = Temperature at actual emission conditions ( °F). 

Ps = Absolute pressure at standard conditions (psia). 

Pa = Absolute pressure at actual conditions (psia). 

(2) Calculate GHG volumetric emissions at standard conditions [delete: by converting actual 

temperature and pressure of GHG emissions to standard temperature and pressure] using [add: 

actual GHG emissions temperature and pressure, and] Equation W–34 [delete: of this section]. 

[See original comment for Eq. W-34] 

Where: 

Es,i= GHG i volumetric emissions at standard temperature and pressure (STP) conditions in 

cubic feet. 

Ea,i= GHG i volumetric emissions at actual conditions in cubic feet. 

Ts= Temperature at standard conditions ( °F). 
43

Ta= Temperature at actual emission conditions ( °F). 

Ps= Absolute pressure at standard conditions (psia). 

Pa= Absolute pressure at actual conditions (psia). 

Response: EPA agrees with the commenter and is modifying 40 CFR 98.233 (t) accordingly, 

along with other amendments, in this final rule. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 43 

Commenter Type: Trade Association

Comment: [Please refer to the original comment text posted in the docket] GHG volumetric 

emissions. Calculate GHG volumetric emissions at standard conditions as specified in 

paragraphs (u)(1) and (2) of this section[add: , with mole fraction of GHGs in the natural gas] 

determined by engineering estimate based on best available data unless otherwise specified. 

(1) Estimate CH4and CO2emissions from natural gas emissions using Equation W–35 of this 

section. 

[See original comment for Eq. W-35] 

Where: 

Es,i= GHG i (either CH4or CO2) volumetric emissions at standard conditions in cubic feet. 

Es,n= Natural gas volumetric emissions at standard conditions in cubic feet. 

Mi= Mole fraction of GHGi in the natural gas. 

(2) For Equation W–35 of this section, the mole fraction, Mi, shall be the annual average mole 

fraction for each facility, as specified in paragraphs (u)(2)(i) through (vii) of this section. 

(i) GHG mole fraction in produced natural gas for onshore petroleum and natural gas production 

facilities. If you have a continuous gas composition analyzer for produced natural gas, you must 

use these values for determining the mole fraction. If you do not have a continuous gas 

composition analyzer, then you must use your most recent gas composition based on available 

sample analysis of the field. 

(ii) GHG mole fraction in feed natural gas for all emissions sources upstream of the demethanizer 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 
44

overhead or dew point control for onshore natural gas processing facilities. If you have a 

continuous gas composition analyzer on feed natural gas, you must use these values for 

determining the mole fraction. If you do not have a continuous gas composition analyzer, then 

annual samples must be taken according to methods set forth in §98.234(b). 

(iii) GHG mole fraction in transmission pipeline natural gas that passes through the facility for 

onshore natural gas transmission compression facilities [add: or the composition in 

§98.232(m)(1)]. 

(iv) GHG mole fraction in natural gas stored in underground natural gas storage facilities [add: 

or the composition in §98.232(m)(1)]. 

(v) GHG mole fraction in natural gas stored in LNG storage facilities [add: or the composition in 

§98.232(m)(1)]. 

(vi) GHG mole fraction in natural gas stored in LNG import and export facilities. 

(vii) GHG mole fraction in local distribution pipeline natural gas that passes through the facility 

for natural gas distribution facilities [add: or the composition in §98.232(m)(1)]. 

(v) GHG mass emissions. Calculate GHG mass emissions in carbon dioxide equivalent at 

standard conditions by converting the GHG volumetric emissions [add: at standard conditions] 

into mass emissions using Equation W–36 of this section. 

[See original comment for Eq. W-36] 

Where: 

Mass s,I = GHG i (either CH4[add: ,] [delete: or] CO2 [delete: or N2O]) mass emissions at 

standard conditions in metric tons CO2e. 

Es,i = GHG i (either CH4[add: ,] [delete: or] CO2 [delete: or N2O]) volumetric emissions at 

standard conditions, in cubic feet. 

? i = Density of GHG i. Use 0.0538 kg/ft3 for CO2and N2O, and 0.0196 kg/ft3 for CH4at 68 °F 

and 14.7 psia or 0.0530 kg/ft3 for CO2and N2O, and 0.0193 kg/ft3 for CH4at 60 °F and 14.7 

psia. 

GWP = Global warming potential, 1 for CO2, 21 for CH4, and 310 for N2O. 

Response: EPA agrees with the commenter, and in this final rule, along with other amendments, 

EPA has modified 40 CFR 98.233 (u) introductory text and (v) accordingly. 

In regard to the commenter’s suggested changes to 40 CFR 98.233 (u)(2), EPA agrees with the 

provision of default values for methane and carbon dioxide. In this final rule, EPA is allowing 

the use of 95% methane and 1% carbon dioxide as default GHG mole fractions in natural gas for 

facilities in transmission compression, underground natural gas storage, LNG storage, LNG 
45

import facilities, LNG export facilities if the export facility receives gas from transmission 

pipelines, and natural gas distribution. Please note that the use of 95% methane and 1% carbon 

dioxide as default GHG mole fractions only pertains to Subpart W and does not necessarily set 

agency precedent. 

EPA disagrees with the commenter in regard to the reference to 98.233(m)(1) where the 

commenter suggested allowing for the use of company records. The November 2010 Final Rule 

allows the use of engineering estimate based on best available data, which includes company 

records among many other options, to determine the GHG mole fractions. Hence, EPA deems it 

unnecessary to specifically mention “company records” as a provision to determine the GHG 

mole fractions. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 49 

Commenter Type: Industry - oil and gas 

Comment: Revision: Under 98.233(u), EPA replaced field with sub-basin category. EPA 

clarified that the mole fraction of GHGs in the natural gas is determined by engineering estimate 

based on best available data unless otherwise specified. EPA also clarified that if you have a 

continuous gas composition analyzer, you must use an annual average of the values for 

determining the mole fraction. Otherwise, an annual average of the available sample analyses for 

the sub-basin category is used. EPA has also clarified the CH4 and CO2 compositions that 

should be used for the other industry sectors. 

Comment: Several of the reporting categories that do not require reporting on a sub-basin basis 

direct you to 98.233(u)(2)(i) for GHGi compositional analysis. EPA revised 98.233(u) to address 

issues with determining the appropriate gas composition. For production operations, EPA 

addressed the gas composition in terms of the sub-basin approach, as shown below. However, 

there is an inconsistency between 98.233(u)(2) and 98.233(u)(2)(i). 98.233(u)(2) refers to the 

average mole fraction for each sub-basin category or facility; while 98.233(u)(2)(i) requires the 

use of available analyses in each sub-basin category. The regulatory text is shown below: 

(2) For Equation W–35 of this section, the mole fraction, Mi, shall be the annual average mole 

fraction for each sub-basin category or facility, as specified in paragraphs (u)(2)(i) through (vii) 

of this section. 

(i) GHG mole fraction in produced natural gas for onshore petroleum and natural gas production 

facilities. If you have a continuous gas composition analyzer for produced natural gas, you must 

use an annual average of these values for determining the mole fraction. If you do not have a 

continuous gas composition analyzer, then you must use an annual average gas composition 

based on available analyses in each of the sub-basin categories. 

API requests that 98.233(u)(2)(i) allow for determining average gas composition analysis on 
46

either a facility (basin) basis or sub-basin basis, whichever is more appropriate for the specific 

emission source category. 

Response: EPA agrees with the amendments suggested by the commenter in 98.233(u)(2). In 

this final rule, EPA has clarified in 40 CFR 98.233 (u)(2) that gas mole fractions can be 

determined either at a sub-basin or facility level, as applicable to the emission source. 

Section 7.3 ­ Emission factors tables

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 14 

Commenter Type: Trade Association 

Comment: Below Grade TD Stations: The proposed rule is not clear regarding how and 

whether to calculate emissions separately for below grade TD transfer stations and below grade 

metering-regulating stations. EPA does not provide an emission factor in Table W-7 for below 

grade TD transfer stations for calculating emissions in 98.233(r), although EPA does require 

emissions from below grade TD transfer stations to be reported separately under the proposed 

amendment to 98.236(c)(16)(.xvi). Conversely, in 98.233(r)(6)(i), below grade TD transfer 

stations are included with below grade metering-regulating stations suggesting they are to be 

calculated together and not separately. If EPA does want emissions from below grade TD 

transfer station to be calculated separately from metering-regulating stations, AGA suggests 

using the same emission factor for both below grade TD transfer stations and below grade 

metering-regulating stations. 

Response: In this final rule, EPA is clarifying that below grade T-D transfer stations use the 

same emission factor as below grade metering-regulating stations. EPA is also requiring 

emissions to be reported for below grade T-D transfer stations separately from meteringregulating stations. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 15 

Commenter Type: Trade Association 

Comment: Default Emission Factor for MR Stations at Companies with No TD Stations: A 

related question arises for a few companies that have no TD stations within the meaning of the 

Proposed Rule. Such companies will not have the option of leak surveying TD stations to 

develop a company-specific emission factor per metering-regulating run for their MR stations. 

The rule does not describe what these companies should do. A reasonable solution for this 

situation is to amend the rule to allow such companies to use the same default emission factor for 
47

both above-ground and below-ground MR stations, based on inlet pressure. The equipment is 

essentially the same. The only difference is whether it is situated above or below ground. 

Response: In this final rule, natural gas distribution reporters that do not own or operate T-D 

transfer stations must provide a count of above grade metering-regulating stations, but are not 

required to report emissions at these stations. EPA believes that the definition of T-D transfer 

station as finalized will capture almost all instances where a company transfers gas from a line at 

transmission pressure to a line operating at distribution pressure at an above ground facility.; 

please see response to EPA-HQ-OAR-2011-0512-0030, Excerpt 4 for further details. Hence, 

distribution companies that do not own or operate T-D transfer stations and only report activity 

data will not affect the overall quality of data used to inform future policy. If needed, EPA can 

use emission factors developed by other reporting entities in the region to estimate emissions 

from these metering-regulating stations. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 7 

Commenter Type: Trade Association 

Comment: Use of GTI or Other Emission Factors for Meter-Regulating Stations 

In AGA’s petition for reconsideration, we asked EPA to allow companies to use an updated 

emission factor for above ground metering and regulating stations based on the field testing 

performed recently by the Gas Technology Institute (GTI) at distribution facilities in the United 

States, rather than the default component leaker factors provided in Subpart W, which are based 

on data collected in Canada on facilities that are not subject to the same pipeline safety leak 

detection and repair requirements that apply to U.S. facilities. In the Proposal preamble, EPA 

states that 

“although we are not proposing changes to the approach for applying emission factors to above 

ground metering-regulating stations in this action, we are seeking comment on alternative 

approaches, or data that may be used, for determining emissions factors for above ground 

metering –regulating stations. Based on comments received, EPA may consider future 

amendments to the rule.” 

76 Fed. Reg. at 56,032. 

We appreciate the agency’s willingness to consider other approaches. In the months since we 

submitted our petition for reconsideration, our members have been performing numerous leak 

surveys at their larger custody transfer stations. Even at these large facilities, they are finding the 

leak rates are extremely low. As described above, one of our members computed a companyspecific, station-level emission factor of 0.64 metric tons (tonnes) per year per station, based on 

actual measured emissions. Using the default leaking component emission factors and adding 

these up for the average > 1 leaking component per station is likely to yield a somewhat 
48

overstated per station emission factor, but we believe it will be good enough for all reasonable 

efforts at policy analysis and regulatory program design. AGA urges EPA to evaluate the data 

submitted for 2011 and 2012 station emissions, and use this data to calculate a default stationlevel emission factor for reporting emissions from both TD Stations and other meteringregulating stations in subsequent years. This will be a more robust data set than used in either the 

GTI or Canadian studies, and it will be up to date. Further, by applying the emission factor 

approach to TD stations as well as other metering-regulating stations, EPA can eliminate the 

burden of annual leak surveys, which is not justified when compared to the minimal emissions 

being found and reported at these facilities. 

Response: EPA analyzed the report on field tests and measurements done by the Gas 

Technology Institute and determined that additional granularity in the data is required before any 

new distribution emission factors can be calculated. EPA found that although the GTI report 

collected a significant amount data on individual components and equipment, the data as 

presented, aggregated these sources together to create emissions factors by custody transfer, 

district regulator, or pressure limiting stations as a whole. In addition, the GTI sources do not 

map directly to the distribution segment sources as defined in Subpart W. To fully analyze the 

data, EPA determined it needs, amongst other details: 

(i) the descriptions of the stations where leak detection and measurement was conducted; 

(ii) the underlying data, including each emission measurement for each component; and

(iii) a full description of each component. 

Should this data become available, EPA may consider the information to develop new 

distribution emission factors. 

EPA has retained the requirement for natural gas distribution reporters to conduct leak detection 

at T-D transfer stations. EPA determined that the use of leaker emissions factors (i.e. emission 

factors applied to components that are found to be leaking during a leak survey) will be a closer 

representation of actual emissions than a facility-level population emission factors. At this time, 

EPA deems this level of detail necessary to track changes in emissions from T-D transfer station 

and effectively inform policy. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 8 

Commenter Type: Trade Association 

Comment: Emission Factors for Plastic Pipe 

AGA is also concerned that the emission factors for distribution pipe – particularly for plastic 

pipe – vastly overstate actual emissions rates. As we describe in our petition for reconsideration, 

these old emission factors were developed over a decade ago by the Gas Research Institute (GRI) 

using data from testing a limited sample of equipment in work performed nearly 20 years ago. 
49

GRI’s study only included six locations. Although the study was supposed to identify locations 

with low leak rates, one of the six locations included in GRI’s study was a faulty butt fusion on 

plastic pipe that was actively blowing gas and that had to be repaired immediately. This anomaly 

should have been omitted, but it was not. As a result, the GRI emission factor for plastic pipe – 

which EPA is using as the Subpart W default emission factor – overstates the actual emission 

rate for plastic pipe by over 300%. This is commonly known and understood, but the old plastic 

pipe emission factor is still being used because there is no updated emission factor available as 

yet. 

However, this will soon change. GTI is performing field testing in 2011 and 2012 that will 

provide the data needed for an updated, more accurate emission factor for plastic pipe, based on 

a far more robust data set. GTI has presented its methodology to EPA’s Natural Gas STAR staff 

along with the preliminary results of its study. We encourage EPA to evaluate the data when the 

study is complete, probably in fall 2012, and to initiate a proposed rule change to adopt the new, 

more accurate emission factor. 

Response: EPA used the best publicly available data to develop emission factors for plastic 

pipelines. EPA supports studies conducted by all stakeholders to improve emission factors. EPA 

will review any new data that is made available and consider updating emission factor for plastic 

pipe in a future rulemaking. 

Commenter Name: Ezra McCarthy 

Commenter Affiliation: National Grid 

Document Control Number: EPA-HQ-OAR-2011-0512-0046

Comment Excerpt Number: 3 

Commenter Type: Industry - oil and gas 

Comment: Emission Factors for Plastic Pipe 

National Grid believes that the emission factors for distribution pipe – particularly for plastic 

pipe – vastly overstates actual emissions rates using old emission factors that were developed 

over a decade ago by the Gas Research Institute (GRI) using data from testing a limited sample 

of equipment in work performed nearly 20 years ago. GRI was only able to include six locations 

in its study and one of the six locations included in GRI’s study was actively blowing gas, 

scenario not likely to exist without immediate attention in a distribution system. As a result, the 

GRI emission factor for plastic pipe – which EPA is using as the Subpart W default emission 

factor – overstates the actual emission rate for plastic pipe considerably. This is commonly 

known and understood, but it the old plastic pipe emission factor is still being used because there 

is no updated emission factor available as yet. 

GTI is performing field testing in 2011 and 2012 that will provide the data needed for an 

updated, more accurate emission factor for plastic pipe, based on a far more robust data set. We 

encourage EPA to evaluate the data when the study is complete, probably in fall 2012, and to 

initiate a proposed rule change to adopt the new, more accurate emission factor.
50

Response: Please see response to EPA-HQ-OAR-2011-0512-0032, Excerpt 8. 

Commenter Name: Curtis J. Winner 

Commenter Affiliation: New Mexico Gas Company (NMGC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0047

Comment Excerpt Number: 8 

Commenter Type: Industry - oil and gas 

Comment: In 98.236.c.15.ii.A EPA added 98.230(a)(8) to the list but did not include the 

appropriate Table, W-7, that goes with (a)(8). 

The rule is confusing about how and whether to calculate emissions separately for below grade 

T-D transfer stations and below grade metering-regulating stations. EPA does not provide an 

emission factor in Table W-7 for below grade T-D transfer stations for calculating emissions in 

98.233.r, although EPA does require emissions from below grade T-D transfer stations to be 

reported separately per the proposed amendment to 98.236.c.16.xvi. Conversely, in 98.233.r.6.i, 

below grade T-D transfer stations are included with below grade metering-regulating stations 

suggesting they are calculated together and not separately. If EPA does want emissions from 

below grade T-D transfer station to be calculated separately from metering-regulating stations, 

should the same emission factor be used for below grade T-D transfer stations and below grade 

metering-regulating stations? 

Response: In this final rule, EPA is clarifying that below grade T-D transfer stations use the 

same emission factor as below grade metering-regulating stations. Also, as proposed in the 

September 2011 Proposal, EPA is finalizing the requirement for emissions to be reported for 

below grade T-D transfer stations separately from below grade metering-regulating stations. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 60 

Commenter Type: Trade Association 

Comment: TABLES – APPARENT ERROR IN TABLE W-4 

There appears to be a heading in Table W-4 that is not appropriate. The third bold heading in the 

table states, “Leaker Emission Factors—Storage Station, Gas Service”. It appears that this 

heading should be deleted and the following line that present a component emission factor 

(“open ended line............ 0.03”) should be merged with the previous section under the second 

heading, “Population Emission Factors—Storage Wellheads, Gas Service”. 

Response: EPA is not clear on the issue that the commenter has stated. First, the third line in the 

Table W-4 is “Population Emission Factors-Other Component, Gas Service” and not “Leaker 

Emission Factors—Storage Station, Gas Service” as stated by the commenter. Second, EPA did 
51

not revise the emission factor for “open ended line”, hence, EPA has determined that no change 

is required for this comment. 

Section 7.4 ­ Calculating Greenhouse Gas Emissions

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 26 

Commenter Type: Trade Association 

Comment: Onshore production wells can use default component counts when estimating 

equipment leaks from wellheads. The underground storage sector should be afforded the same 

flexibility and be allowed to use default component counts for storage wells. 

Onshore production wells can use default component counts for wellheads based on information 

in Tables W-1B and W-1C. Default component counts are not allowed for storage wells. 

Similar to production wells, an underground storage field may include many wells dispersed over 

a broad area. In addition, these wells are often identically designed and constructed, and will 

typically be low emitters. The underground storage sector should be afforded the same flexibility 

as production and be should be allowed to use default component counts for storage well 

emission estimates. 

Rather than counting components at every wellhead, defaults based on engineering judgment 

should be allowed, with the methodology explained in the Monitoring Plan. For example, if a 

storage field contains many wells with similar design and construction, component counts from a 

subset of the wells could be used to define the default values for other wells. This methodology 

would be documented in the Monitoring Plan and would provide a reasonable estimate of storage 

well components and associated emissions. In fact, the component count uncertainty would be 

much lower than the emission factor uncertainty. 

Response: EPA disagrees that underground natural gas storage reporters should be allowed to 

use average component counts for wellheads or engineering estimates. EPA allowed the use of 

average component count in onshore petroleum and natural gas production because of the large 

number of wells that several reporters will have to visit to conduct a thorough component count. 

Underground natural gas storage reporters may have geographically dispersed wells, but do not 

have as many wells as onshore petroleum and natural gas production reporters. Therefore, the 

burden is not comparable, and reporters must comply with the requirements of 40 CFR 

98.233(q). Hence, this final rule has retained the monitoring requirements from the November 

2010 final rule for underground storage reporters. 
52

Section 7.4.1 ­ Calculating GHG Emissions (non equipment specific)

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 53 

Commenter Type: Industry - oil and gas 

Comment: These amendments include changes to many of the equations in Subpart W. For the 

equations that have been modified, EPA has added upper and lower bounds to most of the 

equations with a summation. However, Equation W-32 was modified in these amendments, but 

the summation limits are not defined. In addition, several other equations were not modified and 

do not include upper and lower limits on the summations: Equations W-7, W-13, W-23, W-24, 

W-27, W-28 and W-39. For clarification, API requests that EPA provide the proper notation for 

the summations in these equations. 

Response: EPA agrees with the commenter on issues with Equations W-32, W-7, W-13, and W39A (W-39 in The November 2010 Final Rule). In this final rule, EPA is removing the 

summation operator from Equation W-32 to make it mathematically accurate. Additionally, EPA 

is modifying Equations W-7, W-13, and W-39A to include upper and lower limits on the 

summations, among other amendments. 

Regarding Equations W-23, W-24, W-27, and W-28, amendments to these equations were not 

proposed and hence, these equations are outside the scope of this rule. EPA may consider your 

comment in future rulemakings. Additionally, your question relates to an issue or issues 

currently the subject of ongoing litigation. Please monitor the website for any additional 

guidance that may be available in the future. 

http://www.epa.gov/climatechange/emissions/subpart/w.html

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 9 

Commenter Type: Industry - oil and gas 

Comment: Gas Compressibility 

On page 56031 of the September 9, 2011 preamble, EPA raised the issue of factors, such as 

compressibility, which could impact emissions from blowdowns. EPA states, “We have 

considered accounting for gas compressibility but have not proposed this because we believe that 

the effort in adjusting for a compressibility factor outweighs the benefits in terms of increased 

accuracy.” 

EPA goes on to state, “EPA seeks comments on why such an allowance should be provided and 
53

how to standardize this option so that those who choose to use it all do so in the same way.” 

API Response: 

API supports EPA’s position that accounting for gas compressibility is not important under 

typical conditions and thus not warranted for GHG reporting. There are various industry 

methodologies for compressibility correction factors for mixed gases, and no simple (consensus) 

approaches exist to mathematically describe how it varies with gas composition and other 

deviations from ideal gas behavior. 

Response: EPA thanks the commenter for their remarks. 

Section 7.4.2 ­ Data Reporting Requirements (non equipment specific)

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas 

Comment: Unique name ID for specified units 

EPA added requirements to report a unique name or ID number for each AGR unit, each glycol 

dehydrator, each blowdown vent stack, each wellhead gas-liquid separator, each flare stack, EOR 

injection pump blowdowns, and each transmission storage tank. 

API Response: 

API’s member companies insist strongly that the requirements to develop and report certain 

Subpart W affected equipment through the use of unique identifier information at the individual 

equipment level: 

• were not contemplated or proposed in previous proposals, 

• have not been subject to comment previously, and are unnecessarily onerous, 

• add substantial costs that were not analyzed nor disclosed in the economic impact 

analysis, 

• do not deliver benefits commensurate with the costs, and 

• are contrary to the original scope and intent of the Greenhouse Gas Reporting Program 

(GHGRP) and its varying provisions for the different subparts as applicable to specific 

sectors. 

This is particularly an issue for wellhead gas-liquid separators with oil throughput greater than or 

equal to 10 bbls per day. For this source type, EPA has added the requirement to “report the 

following by sub-basin category, unless otherwise specified” (emphasis added). 98.236(c)(8) 
54

goes on to add reporting requirements under paragraphs (J), (K), (L), and (M) that are specified 

for each separator and not the aggregate of separators as in the existing rule language. These 

reporting requirements are contrary to EPA’s previously stated goal of their intent to “reduce 

reporting burden.” The introduction of these new reporting requirements for gas-liquid 

separators, which have no impact on the current emissions inputs or data quality, under the 

heading of “Technical Revisions” is clearly contradictory to industry’s efforts to work with EPA 

to complete an accurate GHG inventory within a manageable reporting burden and resources. 

The entire concept of basin level reporting for onshore petroleum and natural gas production was 

justified by EPA through its desire to achieve adequate coverage of the onshore production 

sector and its economic impact analysis and the concept of reducing burden by handling the vast 

number of sources as grouped source types rather than discrete emission sources. EPA should 

not include or imply individual tracking and reporting for separators that are currently reported 

as total counts or average emissions information. The requirement for creating unique identifiers 

for individual separators is inconsistent with aggregating equipment and emissions within a basin 

or sub-basin as currently required in the rule. This proposed change in effect eliminates the 

benefits from handling separators in the production sector at the sub-basin level, which API 

previously supported, and fundamentally changes API’s acceptance of this approach. 

For separators, the throughput, existence, and site-specific functionality (wells they service) can 

vary or change greatly depending on production scenarios throughout the year. Some sites have 

multiple separators that may change or be used differently throughout the year, so assigning a 

unique number on a specific separator and tracking for a whole year does not add clarity or 

value. API and its members strongly urge that EPA reconsider its proposal and remove this 

requirement upon promulgation. 

For the other equipment types that EPA is proposing to require assigning a unique name or ID 

number (AGR units, glycol dehydrator, blowdown vent stacks, flare stacks, EOR injection pump 

blowdowns, and transmission storage tanks), the current level of reporting already relies on 

individual component counts and equipment inventories that apply to EPA specified calculations. 

Creating unique equipment identifiers neither adds to the level of accuracy of calculated 

emissions, nor does it provide information that is not already available through the currently 

reported individual equipment counts and reported CO2 and CH4 emissions totals that are 

already part of the GHGRP. 

API further contends that the identifier data requested by EPA will not be usable at the individual 

equipment level due to the dynamic nature of the sector and the fact that the identifiers may be 

tied to well names or locations and hence be different every year due to frequent equipment 

movement, change-outs and replacements that routinely occur at Oil and Gas well sites. For 

example, flaring during drilling or completion operations uses either portable flares or openended pipe which is moved to new drilling/completion operations. A unique name or ID for the 

“flare” is meaningless in this situation. 

This requirement would lead to the expenditure of unnecessary time and resources to create 

identifiers, which serve no other purpose than to specifically identify equipment that is already 
55

called out and accounted for within the current GHGRP process. 

Response: Firstly, it is important to note that the reporting of unique ID does not impose a new 

requirement for unit-level reporting. The 2010 final rule required that emissions be reported for 

EACH [emphasis added] AGR (98.236(c)(3)), each glycol dehydrator (98.236(c)(4)), each 

blowdown vent stack (98.236(c)(7)), each transmission storage tank (98.236(c)(9)), each flare 

(98.236(c)(12)), and each EOR injection pump (98.236(c)(17)). Therefore, under the 2010 final 

rule, facilities in practice would have to collect emissions for each piece of equipment, and then 

report separately for each piece of equipment. The clarification made by EPA was just to 

generate a link between a specific piece of equipment and its emissions. 

Although EPA had intended for emissions be reported for each storage tank in the 2010 final 

rule, we can see how the lack of clarity in the reporting requirement for storage tank 

(98.236(c)(8)) which required emissions reporting for Calculation Methodology 1 and 

Calculation Methodology 2, could have been interpreted so as to not require separator specific 

reporting. In this final rule EPA is clarifying that all the reporting requirements for Calculation 

Methodologies 1 and 2 for onshore production storage tanks must be reported at a sub-basin 

category level, which is consistent with the sub-basin level change made to the onshore 

petroleum and natural gas production industry segment. 

Based on this, we are finalizing, as proposed, reporting of unique name or ID for all segments, 

except for onshore production. EPA agrees that for the onshore production segment, a unique 

name or ID number may be difficult to assign for portable equipment that may move from one 

location to another. In this final rule, EPA is not requiring unique name or ID number in onshore 

production. EPA recognizes that removing this requirement for onshore production could 

potentially result in the loss of equipment-specific information that could be useful for future 

policy analysis and we may continue to evaluate this for future rulemaking. For further details on 

the unique ID issue, please see preamble Section II.C.3 - Final Amendments to the Petroleum 

and Natural Gas Systems Source Category – Major Changes Since Proposal – 2. Data Reporting 

Requirements; and Section II.D.3 –Response to Major Comments on the Petroleum and Natural 

Gas Systems Source Category. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 5 

Commenter Type: Industry - oil and gas 

Comment: Feasibility of Reporting 2011 Data under Amended Rule 

On page 56020 of the preamble, EPA states, “for subpart W, reporters would be expected to 

calculate emissions and other relevant data for the reports that are submitted in 2012 using part 

98, as amended by this rule, as finalized. We have determined that it is feasible for the sources to 

implement these changes for the 2011 reporting year since the proposed revisions primarily 

provide additional clarifications or flexibility regarding the existing regulatory requirements, 

generally do not affect the type of information that must be collected, and do not substantially 
56

affect how emissions are calculated.” 

API Response: 

API and its members have been working with EPA staff over the past year to revise and correct a 

myriad of technical issues and mistakes that pervaded the Subpart W rule as promulgated on 

November 30, 2010. API and its members welcome most of the changes proposed by EPA and 

agree that the technical corrections in this proposed action are based to a large extent on 

technical issues raised by industry along with specific requests for reconsideration. API concurs 

that EPA’s final action on the ability to use best available monitoring methods (BAMM) for all 

of calendar year 2011 data [Footnote 6: On September 16, 2011, Administrator Jackson signed a 

rule that finalized amendments to the best available monitoring methods (BAMM) provisions in 

subpart W. http://www.epa.gov/climatechange/emissions/subpart/w.html] provides reporters the 

needed flexibility and time to implement these new requirements. However, there are still many 

issues in need of resolution, which is creating uncertainty for calendar year 2011 data collection 

and reporting. Some pertinent examples with specific comments and requests include: 

• Expanded reporting requirements for gas-liquids separators – As indicated in Comment A 

above, EPA has significantly expanded the reporting requirements for each gas-liquid 

separator with oil throughput greater than or equal to 10 bbls per day. 

• Completions and workovers with hydrofracing - For Methodology 1 data collection it 

would be best for EPA to specifically allow the use the data collected in 2012 for 

reporting for the 2-year period that includes the 2011 and 2012 calendar years. The rule 

allows the use of representative data for a period of 2-years, and this approach will be 

best for implementing the final sub-basin categories once promulgated. 

• Liquids Unloading – The same considerations would apply for implementing the subbasin categories for this source type. Here again API requests that EPA specifically allow 

the use of data collected in 2012 for the 2-year period of 2011 and 2012. 

• Oil Production – EPA is yet to propose and seek comment on a sub-basin category 

approach for oil production. As addressed in comments W.25 [EPA-HQ-OAR-2011-

0512-0042, Excerpt 41] and W.26 [EPA-HQ-OAR-2011-0512-0042, Excerpt 42] below, 

API proposes that oil production be classified as a fifth sub-basin category, in addition to 

the four sub-basins identified for gas production. Until this is incorporated into the rule, it 

remains another area of uncertainty that would require special considerations for 2011 

reporting. 

• Use of unique name or ID – This requirement has been introduced in this proposal under 

the banner of a technical revision, but as stated in Comment A above, it has far greater 

ramifications and potential burden for the regulated industry. If EPA were to finalize this 

requirement as proposed, it will be impossible in 2011 to: 

• implement a system of assigning unique names or IDs to the vast number of 

individual pieces of equipment; 

• implement a system to collect data for each piece of equipment; and 

• implement a system to track each piece of equipment. 

Moreover, EPA itself recognizes in Table 2 of the September 9, 2011 preamble that several 

issues from API’s (and other organization’s) Petitions for Reconsideration were not yet 

addressed. Likewise, additional technical errors and recommended corrections are provided in 
57

the Technical Comments Section below. 

Resolution of all of these pending issues is essential to allowing reporters to provide EPA with 

high quality GHG emissions data. API and its members request that EPA take into account the 

lateness in the calendar year of promulgating all of the referenced changes, and allow additional 

flexibility when approving BAMM requests beyond 2011. 

Response: EPA agrees with the commenter with regards to reporting requirements for wellhead 

gas-liquid separators and is modifying this final rule accordingly. Regarding the comment on the 

requirement for a unique name or ID, in this final rule, EPA is not requiring unique name or ID 

for the onshore production segment. For more details on these two issues, please see response to 

EPA-HQ-OAR-2011-0512-0042, Excerpt 2. 

EPA is allowing reporters to use 2012 data for reporting of emissions from well completions/ 

workovers and well liquids unloading for reporting year 2011. For further details, please see 

preamble Section II.D.7 – Response to Major Comments on the Petroleum and Natural Gas 

Systems Source Category. 

EPA added oil formations to the sub-basin category definition in 40 CFR 98.238 and clarified the 

reporting of sources under this formation for 2011. For the response on the Addition of Oil 

formation definition in the sub-basin category definition, please see preamble Section II.C - Final 

Amendments to the Petroleum and Natural Gas Systems Source Category - Major Changes 

Since Proposal – 3. Definitions; and Section II.D.9 – Response to Major Comments on the 

Petroleum and Natural Gas Systems Source Category. 

As indicated in its September 9, 2001 proposal, EPA has granted only limited reconsideration of 

specific issues contained in various Petitions for Reconsideration and will consider the remaining 

issues at a later point in time. EPA points out that we are allowing the use of BAMM as 

provided in the Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems: 

Revisions to Best Available Monitoring Method Provisions (76 FR 59533), where applicable. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 55 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA revised the reporting for offshore petroleum and natural gas to 

require reporting emissions individually for all source types listed in the most recent BOEMRE 

study. Previously, the rule required reporting as set forth by BOEMRE in 30 CFR 250.302 

through 304. 

Comment: For consistency with existing regulatory reporting requirements, API requests that 

EPA reverse the decision and reinstate reporting for offshore petroleum and natural gas 

production as set forth by BOEMRE in 30 CFR 250.302 through 304. 
58

Response: EPA disagrees with the commenter. The BOEMRE data reporting is for activity 

data by platforms, not emissions estimates. The emissions estimates are provided by BOEMRE 

in a report subsequent to data collection from platforms. Therefore, the November 2010 final 

rule was unclear on what information needs to be reported. Hence, we are finalizing, as 

proposed, reporting of emissions by gas type and emission source type, as listed in the most 

recent BOEMRE study. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 68 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has added a requirement to report average API gravity, average gas 

to oil ratio, and average low pressure separator pressure for each sub-basin category. On page 

56034 of the September 9, 2011 preamble EPA contends that this information is already known 

to reporters, and it plans to use these facility sub-basin characteristics to characterize other 

emissions sources across different sub basins. 

Comment: This information is not available or appropriate for broader applications to each of the 

sub-basin categories. For example, dry gas production areas, such as coal-bed methane, will not 

have API gravity or gas to oil ratios to report for a sub-basin. 

API interprets this reporting requirement as applicable only to the oil production sub-basin 

category proposed for addition by API. Only this sub-basin category is consistent with the 

preamble language, which indicates that this information is readily available. 

For the oil production sub-basin category, this requirement should only apply to separators with 

oil throughput greater than or equal to 10 barrels per day, as it is only for these operations where 

this information is available. API also interprets the requirement to report the low pressure 

separator pressure to refer only to the separator pressure in those instances where the separator 

oil composition is sampled and analyzed. 

Response: EPA agrees that reporting of average API gravity, average gas to oil ratio, and 

average low pressure separator pressure only applies to oil formation sub-basin categories. 

Please see preamble Section II.D.2 – Responses to Major Comments on the Petroleum and 

Natural Gas Systems Source Category, for the response on data reporting requirements of 

98.236(e). 

However, EPA disagrees that this requirement should only apply to separators with oil 

throughput greater than or equal to 10 barrels per day. As stated in this final rule, reporters must 

report average values for these requirements on a sub-basin category level, specifically oil 

formation sub-basin category, using best available estimates. These requirements are not to be 

reported on an equipment or emission source type level. 
59

Section 7.5 ­ Natural Gas Pneumatic Device Venting

Commenter Name: William W. Grygar II 

Commenter Affiliation: Anadarko Petroleum Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0028

Comment Excerpt Number: 5 

Commenter Type: Industry - oil and gas 

Comment: Under §98.233(a) and (c), EPA has allowed reporters to use the total number of 

hours that the devices/pumps were operational to estimate emissions, rather than the total hours 

in a year. Anadarko supports this change, but requests that a revision be made to clarify that the 

time used is an estimated average time for the basin; actual operating hours are extremely 

burdensome to collect and not readily tracked. An appropriate estimate of operating time of these 

devices and pumps is the well operating time, which is readily available. 

Response: EPA agrees with the commenter. In this final rule, EPA is modifying the parameter 

Tt and T in Equations W-1 and W-2 respectively, to allow reporters to estimate the average 

number of hours in the operating year the devices (of type t)/pumps are operational. 

Additionally, EPA is providing 8760 hours as a default values for these parameters. 

Commenter Name: William W. Grygar II 

Commenter Affiliation: Anadarko Petroleum Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0028

Comment Excerpt Number: 6 

Commenter Type: Industry - oil and gas 

Comment: Anadarko supports the proposed addition under §98.233(a)(2) that the type of 

pneumatic device be determined using engineering estimates based on best available 

information. 

Response: EPA thanks the commenter for their remarks.

Section 7.5.1 ­ Calculating GHG Emission [W­1]

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 12 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Pneumatic 

controller operating hours: The Proposed Rule adds annual operating hours as a parameter in 
60

Equation W-1. Operators should be allowed to assume 8760 operating hours, with actual hours 

used at the operator's discretion. 

Equation W-1 in §98.233(a) calculates emissions from pneumatic controllers. The Proposed Rule 

revises the equation to add a new parameter "T", which is defined as, "The total number of hours 

in the operating year that the devices were operational." Previously, Equation W-1 assumed 

continuous operation for the entire year – i.e., 8760 annual operating hours. In addition to 

substituting "controllers" for "devices" per the previous comment, INGAA strongly recommends 

that Subpart W clearly indicate that 8760 hours can be assumed as a default value for "T". The 

proposed revision will have a minimal impact on inventory estimate accuracy, and in many cases 

operators have already set up reporting programs based on the 8760 operating hour assumption. 

EPA should not add unnecessary costs and complications by mandating that annual operating 

hours is defined for pneumatic controllers. INGAA recommends that Subpart W include the 

following revisions for the description of "T" in the list of variable that follows Equation W-1: 

"T = Total [delete: number of] [add: annual operating] hours for [delete: in the operating year] 

the [add: controllers] [delete: devices were operational]. [add: 8760 annual operating hours can 

be used as a default assumption."] 

 

Response: EPA agrees with the commenter with regards to providing a default value of 8760 

hours for parameter “T” in equation W-1 of 40 CFR 98.233(a). For additional changes to 

parameter “Tt” and “T” in Equations W-1 and W-2, please see the response to EPA-HQ-OAR2011-0512-0028, Excerpt 5. 

EPA disagrees with the commenter with regards to substituting “controllers” for “devices” in 

parameter “T”. Please see the response to EPA-HQ-OAR-2011-0512-0029, Excerpt 11. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 3 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] INGAA supports 

Proposed Rule revisions that allow default or standard facility-wide concentrations for natural 

gas composition for the transmission compression and underground storage segments. However, 

the Proposed Rule still contains conflicts and inconsistencies that need to be resolved. 

In Table 2 of the preamble, EPA indicates that the Proposed Rule addresses INGAA's request to 

allow operators in natural gas transmission and storage to use a default gas composition and 

consisently apply the assumed gas composition for all emission estimates. INGAA supports this 

objective, but conflicting requirements remain, and additional revisions are needed. In addition, 

refer to Comment 20 regarding general issues associated with emission estimates and the lack of 

clarity that results form inconsistent approaches for converting from volumetric emissions (i.e., 

volume of natural gas) to volume and mass of CH4, CO2 and CO2e emissions. 
61

INGAA requested that transmission, storage, and distribution operations be allowed to use either 

a default natural gas CH4 and CO2 composition, or a single assumption based on a facility gas 

analysis. Subpart W currently stipulates different assumptions for different sources within a 

facility. Proposed Rule revisions in §98.233(u)(2) address the intent of INGAA's request. 

However, §98.233 individual source sections still contain conflicts. To enhance rule clarity and 

simplicity, EPA should address this issue throughout Subpart W as recommended in Comment 

20. INGAA's recommendations to address the issue for the natural gas transmission compression 

and underground storage segments within the applicable §98.233 subsections follow: 

In §98.233(a), parameter GHGi inappropriately references §98.233(u)(2)(i), which is for 

production. The parameter should be revised to reference the general section as follows (or 

alternatively, to reference (u)(2)(iii) and (iv) for transmission and storage, respectively): 

"GHGi = [delete: For onshore petroleum and natural gas production facilities, onshore natural 

gas transmission compression, and underground natural gas storage, c] [add: C]oncentration of 

GHGi, CH4, or CO2, in natural gas as defined in paragraph (u)(2) [delete: (i)] of this section. 

Response: EPA disagrees with the commenter with regards to the citation (u)(2)(i) in parameter 

GHGi in Equation W-1 being incorrect. The emission factors for pneumatic devices for segments 

other than onshore production are in total hydrocarbon units. Hence, the blanket allowance of 

applying 95% methane and 1% carbon dioxide to a facility will be incorrect. In this final rule, 

for onshore production facilities, GHGi refers to (u)(2)(i) and for onshore natural gas 

transmission compression and underground natural gas storage, GHGi for CH4 = 0.975 and 

GHGi for CO2 = 1.1*10-2. 

EPA disagrees with standardizing calculations as suggested in Comment 20 submitted by the 

commenter. Please see the response to EPA-HQ-OAR-2011-0512-0029, Excerpt 27. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 35 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] 

§ 98.233 Calculating GHG emissions. 

[highlighted text: Clarifications in 98.33(a), (e), (i), (k), (o) and (p); minor changes to (q), (r), (t), 

(u), (v) for consistency] 

... 

(a) Natural gas pneumatic device venting. 

[highlighted text: Clarify that best available information and engineering judgment can be used 
62

to define high vs low bleed; also address definition (and provide examples) for intermittent 

devices [see revision to 98.6 and recommended paragraph for preamble with examples].] 

Calculate CH4 and CO2 emissions from continuous high bleed, continuous low bleed, and 

intermittent bleed natural gas pneumatic devices using Equation W–1 of this section. 

[See original comment for Eq. W-1] 

Where: 

Mass s,i = Annual total mass GHG emissions in metric tons CO2e per year at standard 

conditions from a natural gas pneumatic device vent, for GHG i. 

Count = Total number of continuous high bleed, continuous low bleed, or intermittent bleed 

natural gas pneumatic devices of each type as determined in paragraph (a)(1) of this section. 

[add: The count shall be based on best available information or engineering judgment with the 

approach described in the monitoring plan required under §98.3(g)(5) and does not require bleed 

rate measurement to define device type.] 

EF = Population emission factors for natural gas pneumatic device venting 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, concentration of GHG i, 

CH4or CO2, in produced natural gas; for facilities listed in §98.230(a)(3) through (a)(8), GHGi 

equals 1 [add: or the gas composition allowed per §98.232(m).] 

Convi = Conversion from standard cubic feet to metric tons CO2e; 0.000410 for CH4, and 

0.00005357 for CO2. 

24 * 365 = Conversion to yearly emissions estimate. 

... 

Response: EPA agrees with the commenter with regards to clarifying the use of an engineering 

estimate based on best available data to determine the type of pneumatic device. In this final 

rule, EPA is adding clarification language in section 40 CFR 98.233(a)(3) and not in the 

definition of the parameter “Count” as suggested by the commenter. 

EPA disagrees with the commenter with regards to changes in definition of parameter “GHGi”. 

Please see response to EPA-HQ-OAR-2011-0512-0029, Excerpt 3 for further details. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 
63

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 9 

Commenter Type: Trade Association 

Comment: As discussed below in Comment 20, if common approaches are implemented for 

converting from natural gas volumetric emission estimates in §98.233(a) – (r) to CO2 and CH4 

voumetric and mass emissions, these conflicts can be avoided. §98.233(i) and (k) provide 

examples of this approach. 

 

Response: EPA disagrees with standardizing calculations as suggested in Comment 20 

submitted by the commenter. Please see the response to EPA-HQ-OAR-2011-0512-0029, 

Excerpt 27. 

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 16 

Commenter Type: Industry - oil and gas 

Comment: C. § 98.233 Calculating GHG Emissions 

(1) Natural gas pneumatic device venting, § 98.233(a). The requirement to report emissions from 

pneumatic devices, 40 C.F.R. § 98.233(a), is vague in the final rule. Subpart W requires 

conducting a total count of pneumatic devices within three calendar years and classifying each 

device according to its bleed rate. EPA required conducting a count of pneumatic devices in 

order to reduce the burden on reporters, while still meeting the necessary data quality to inform 

EPA’s policies. 75 Fed. Reg. 74,470 (Nov. 30, 2010). 

Subpart W states that high-bleed pneumatic devices are those that vent continuously to the 

atmosphere at a rate in excess of 6 scf/hr, whereas low-bleed pneumatic devices are those that 

bleed at rates equal to or less than 6 scf/hr. However, the final rule does not clarify how industry 

must determine whether a device’s bleed rate exceeds 6 scf/hr or not. Without explaining how to 

determine a device’s bleed rate, it is unclear whether a reporter must rely on the manufacturer's 

bleed rate data, whether direct measurements are required at each individual pneumatic device, 

or if some other method should be used. 

To rectify this problem, the proposed rule directs that all industry segments must “determine the 

type of pneumatic device using engineering estimates based on best available information.” 76 

Fed. Reg. 56,040. Chesapeake and AXPC support this proposed clarification because it provides 

the necessary explanation of how to reporters are expected to determine what devices have high 

bleed rates versus low bleed rates, as is needed to comply with the rule. 

Separately, EPA has proposed modifying Eq. W-1 and Eq. W-2 “to include a parameter ‘T’ that 
64

estimates the total number of hours [pneumatic] devices were operational.” 76 Fed. Reg. 56,029. 

We support this proposal because it will increase accuracy in the emissions reported from 

leaking pneumatic devices and pumps. 

Response: EPA thanks the commenter for their remarks. For additional changes to parameter 

“Tt” and “T” in Equations W-1 and W-2, please see the response to EPA-HQ-OAR-2011-0512-

0028, Excerpt 5. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 24 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added a time term to equation W-1 to account for the duration the 

device is operational for the reporting year. T is defined as “Total number of hours in the 

operating year the devices were operational.” 

Comment: The term “T” should refer to an estimated average annual time for all the devices or 

allow the use of 8760 hours. An estimate of the time is consistent with the preamble language 

stating “EPA is also proposing to amend Equation W-1 to include a parameter ‘T’ that estimates 

the total number of hours the devices were operational” (emphasis added). 

Further for this equation, the term “Masss,i”, does not need the subscript “s”, and the definition 

does not need “at standard conditions” as mass does not change based on temperature and 

pressure. API also requests the term Masss,i be revised to “mass per type of device” for the 

different pneumatic device types. 

The term GHGi refers to “onshore petroleum and natural gas production facilities” and 

references paragraph (u)(2)(i), which is defined as “sub-basin”. However, to be consistent with 

this equation and the methodology for compiling pneumatic device counts, GHGi should be 

representative of all the wells in the basin with a particular device type and not aligned with a 

sub-basin. Revisions to 98.233(u)(2)(i) to address this are provided in comment W.33 [EPA-HQOAR-2011-0512-0042, Excerpt 49]. 

Response: EPA agrees with the commenter with regards to parameters “Tt” and “Massi”. In this 

final rule, these parameters are being modified accordingly. 

EPA agrees with the commenter with regards to parameter “GHGi”. For the response about 

clarifying the use of 98.233(u)(2)(i) on either a facility (basin) basis or sub-basin basis, as per the 

specific emission source type, please see the response to EPA-HQ-OAR-2011-0512-0033, 

Excerpt 17. 

 
65

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 25 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added 98.233(a)(3), which states: “For all industry segments, 

determine the type of pneumatic device using engineering estimates based on best available 

information. 

Comment: API supports this revision. 

Response: EPA thanks the commenter for their remarks. 

Commenter Name: Curtis J. Winner 

Commenter Affiliation: New Mexico Gas Company (NMGC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0047

Comment Excerpt Number: 4 

Commenter Type: Industry - oil and gas 

Comment: Pneumatic Device Venting 

NMGC supports EPA’s amendment to 98.233.a to allow the type of pneumatic devices to be 

determined using engineering estimation based on best available information. 

Response: EPA thanks the commenter for their remarks. 

Section 7.5.2 ­ Data Reporting Requirements

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 13 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Pneumatic 

controller reporting in §98.236(c)(1) for transmission and storage sectors should simply require 

the pneumatic controller type by count. INGAA recommended rule text is provided. 

In its June 2011 letter, INGAA recommended revisions to §98.237(c)(1) reporting requirements. 

It appears that EPA is trying to differentiate reporting obligations for other sectors where 

different options are available for obtaining pneumatic controller counts. If so, that delineation 
66

should be defined in a separate subsection for the sector of interest. For natural gas transmission 

compression and underground storage, controller count by type and emissions reporting are all 

that is warranted. INGAA reiterates recommended rule text for §98.236(c)(1) provided in June 

2011: 

"(1) For natural gas pneumatic controllers devices (refer to Equation W–1 of §98.233), report the 

following: 

(i) [delete: Actual c] [add: C]ount [delete: and estimated count separately] of natural gas 

pneumatic high bleed [add: controllers] [delete: devices as applicable]. 

(ii) [delete: Actual c] [add: C]ount [delete: and estimated count separately] of natural gas 

pneumatic low bleed [add: controllers] [delete: devices as applicable]. 

(iii) [delete: Actual c] [add: C]ount [delete: and estimated count separately] of natural gas 

pneumatic intermittent bleed [add: controllers] [delete: devices as applicable]. 

(iv) Report emissions collectively [add: for all pneumatic controllers]." 

It appears that reference to "actual" or "estimated" counts is intended for the onshore production 

segment where requirements are phased in over multiple years. More straightforward criteria 

apply to transmission and storage, and reporting based on production criteria could cause 

confusion. If necessary, EPA should provide separate subsections in §98.236(c)(1) to clearly 

identify segment-specific criteria. 

Response: EPA disagrees with the commenter with regards to changes to the data reporting 

requirements for natural gas pneumatic devices. Please see the response to EPA-HQ-OAR-2011-

0512-0029, Excerpt 63 for further details. 

EPA disagrees with the commenter on replacing “devices” with “controllers”. Please see the 

response to EPA-HQ-OAR-2011-0512-0029, Excerpt 11 for further details.

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 63 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] § 98.236 Data 

reporting requirements. 

(1) For natural gas pneumatic devices (refer to Equation W–1 of §98.233), report the following: 

(i) [delete: Actual c] [comment bubble JMc11: Reference to “actual” deleted for consistency 

with language added in 98.233(a) regarding “best available info” for defining device type. In 
67

addition, §98.233(a) criteria clearly identify differences allowed for device counts for different 

segments.] [add: C]ount [delete: and estimated count separately] of natural gas pneumatic high 

bleed devices [delete: as applicable]. 

(ii) [delete: Actual c] [add: C]ount [delete: and estimated count separately] of natural gas 

pneumatic low bleed devices [delete: as applicable]. 

 (iii) [delete: Actual c] [add: C]ount [delete: and estimated count separately] of natural gas 

pneumatic intermittent bleed devices [delete: as applicable]. 

(iv) Report emissions collectively [add: for all pneumatic devices]. 

Response: EPA does not agree with the commenter with regards to changes to the data 

reporting requirements for natural gas pneumatic devices. In this final rule, EPA is finalizing the 

reporting of “actual” and “estimated” counts separately for different types of natural gas 

pneumatic devices, as applicable. The text “as applicable” implies that reporters must follow the 

requirement of “actual” versus “estimated” only if it is applicable to their facility, i.e., if they 

report under onshore petroleum and natural gas production consistent with 40 CFR 98.233(a)(1). 

Onshore production facilities are allowed to count their pneumatic devices over a three year 

period. Hence, for each year they may have an actual count and an estimated count, where an 

actual count is not available. For reporters with facilities where it is not applicable, i.e., if they 

report under onshore transmission compression and underground natural gas storage, reporters 

must report the actual count of each type of pneumatic device, consistent with 40 CFR 

98.233(a)(2) and (a)(3). “Actual” count does not refer to the engineering estimate based on best 

available information. 

EPA disagrees with the commenter with regards to reporting the emissions from all pneumatic 

devices collectively. The Calculation Methodology in 40 CFR 98.233(a) calculates CO2 and CH4 

emissions from each type of pneumatic device at a facility level. Consistent with this Calculation 

Methodology, EPA is finalizing the reporting of CO2 and CH4 emissions from each type of 

pneumatic device at a facility level. 

Section 7.6 ­ Natural Gas Driven Pneumatic Pump Venting

Section 7.6.1 ­ Calculating GHG Emission [W­2]

Commenter Name: Vince Alaimo 

Commenter Affiliation: Marshall Miller & Associates Inc. on behalf of Consol Energy Inc. 

Document Control Number: EPA-HQ-OAR-2011-0512-0036

Comment Excerpt Number: 4 

Commenter Type: Trade Association 

Comment: Natural Gas Driven Pneumatic Pump 
68

•EPA is also proposing to amend Equation W–2, to include a parameter ‘‘T’’ that estimates the 

total number of hours the devices were operational. Previously, this equation assumed that all 

natural gas pneumatic devices were operational all year, which would overestimate the emissions 

where the pneumatic devices operate less than a full year. These amendments to Equation W–2 

will more accurately reflect operating conditions for natural gas pneumatic device venting 

Comment 3 

In many cases the time the devices are operational is not recorded in which Consol Energy 

proposes a default value be allowed of 8260 hours. 

Response: EPA disagrees with the commenter as no justification for the value of “8260 hours” 

is given. However, EPA assumes that the commenter intended for the default hours to be “8760” 

and not “8260” and is providing the option to use 8760 default hours of operation in Equation 

W-2. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 26 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added a time term to equation W-2 to account for the duration the 

pneumatic pump is operational for the reporting year. 

Comment: The terms defined for Equation W-2 include “24 * 365 = Conversion to yearly 

emissions estimate”. This term is no longer used in the equation and should be deleted from the 

list of terms. 

The term “T” should refer to an estimated average annual time for all the pumps or allow the use 

of 8760 hours. An estimate of the time is consistent with the preamble language stating “We are 

proposing to amend Equation W–2 in 40 CFR 98.233(c), which is used for calculating GHG 

emissions from natural gas pneumatic pump venting, to include a parameter ‘‘T’’ that estimates 

the total amount of hours the pumps were operational” (emphasis added). 

Further for this equation, the term “Masss,i”, does not need the subscript “s”, and the definition 

does not need “at standard conditions” as mass does not change based on temperature and 

pressure. 

The term GHGi refers to “onshore petroleum and natural gas production facilities” and 

references paragraph (u)(2)(i), which is defined as “sub-basin”. However, to be consistent with 

this equation, GHGi should be representative of all the wells in the basin with a pneumatic pump 

and not aligned with a sub-basin. Revisions to 98.233(u)(2)(i) to address this are provided in 
69

comment W.33 [EPA-HQ-OAR-2011-0512-0042, Excerpt 49]. 

Response: EPA agrees that the “24*365” conversion in equation W-2 is no longer used or 

needed and is removing it from the list of terms. EPA also agrees that “Massi” does not need the 

subscript “s,” and it is removing it from the equation. Furthermore, EPA agrees that “T” in 

Equation W-2 should be an estimated average annual time, and the definition will be changed to 

reflect this. Finally, EPA agrees that pneumatic device emissions are to be estimated and 

reported at a facility level. Paragraph 98.233(u)(2)(i) is being revised to reflect the use of either 

the basin or sub-basin as applicable to the emissions source. 

Section 7.7 ­ Acid Gas Removal Vents

Section 7.7.1 ­ Calculating GHG Emission [W­3, W­4]

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 27 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has modified Equation W-4 for calculating CO2 emissions from acid 

gas removal units. EPA notes in the preamble that the correction was needed because the original 

equation introduces an error that increases significantly when the amount of CO2 in the gas 

increases. 

Comment: The previous (original) equation contained a variable, alpha, to adjust the calculation 

based on whether the inlet gas or outlet gas flow rate was applied. Note, the definition of terms 

still lists the term alpha, although alpha is not used in the revised equation. 

The proposed correction seems to introduce a larger error than the original equation if the inlet 

gas volume is applied. Testing the equations using the onshore production example facility from 

the Compendium (Section 8.1.1), results in the following: 

Compendium Method 1,190 scf CO2/yr 

Original EPA Method: Applying inlet gas flow 1,183 scf CO2/yr 

Original EPA Method: Applying outlet gas flow 1,154 scf CO2/yr 

Revised EPA Method: Applying inlet gas flow 1,337 scf CO2/yr 

Revised EPA Method: Applying outlet gas flow 1,169 scf CO2/yr 
70

[The Compendium example is based on the following conditions: AGR inlet gas flow = 10,290 

scf/yr, inlet gas CO2 composition is 12%, AGR outlet gas flow rate = 8,997 scf/yr, outlet gas 

CO2 composition is 0.5%.] 

When the inlet volume of gas is used, the proposed corrected equation over estimates emissions 

by incorrectly increasing the volume of inlet gas. Based on API’s analysis, it does not appear that 

the revision improves the quality of data when the inlet gas flow rate is applied. 

API requests that EPA retain the previous equation, using the alpha term. As demonstrated in the 

table above, the revised equation actually introduces a larger error, particularly when the inlet 

gas flow rate is applied. 

API also requests that the flow rate term “V” be defined in terms of standard conditions (60oF 

and 14.7 psia), consistent with the flow measurements available for amine units. In addition, the 

term Ea,CO2.should be revised to Es,CO2 and be expressed in volumetric emissions at standard 

conditions (60oF and 14.7 psia). With this revision, paragraph (9) is no longer needed. 

Response: EPA agrees that equation W-4, as published, is incorrect. EPA is proposing two new 

equations, W-4A and W-4B, to replace the current equation. These two new equations, used 

separately if either inlet or outlet gas flow is known, give the highest accuracy of any of the 

equations considered thus far. For further explanation, please see docket memo “Acid Gas 

Removal Vents – Engineering Calculation Revisions” located in the docket: EPA-HQ-OAR2011-0512. 

Commenter Name: Mike Hampton 

Commenter Affiliation: SandRidge Midstream, Inc. 

Document Control Number: EPA-HQ-OAR-2011-0512-0045

Comment Excerpt Number: 3 

Commenter Type: Industry - oil and gas 

Comment: Problems with the September 9, 2011 Proposed Rule Changes 

The proposed changes to 40 CFR 98.233(d)(1) in the September 9, 2011 Federal Register 

require, for AGR vents with both continuous gas analyzer and continuous flow monitor, to 

calculate C02 emissions "by following the Tier 4 Calculation Methodology and all associated 

calculation, quality assurance, reporting, and recordkeeping requirements for Tier 4 in subpart C 

of this part (General Stationary Fuel Combustion Sources)." 

SandRidge believes this requirement to use 40 CFR Part 98 Subpart C Tier 4 methodology and 

all associated calculation, quality assurance, reporting, and recordkeeping requirements is 

inappropriate for several reasons, as discussed below. 

1. AGR vents are not combustion sources. Subpart C was drafted and promulgated for 

combustion sources, and AGR vents exhausted to atmosphere are not combustion sources. The 

requirements for Tier 4 specifically address combustion sources and fuels, and as such, direct 
71

application to cold, dry, non-combustion vents is not appropriate. Rather, development of Tier 4 

type requirements should be proposed, reviewed, and finalized specifically for AGR vents, if 

needed, at a future date if an applicable rule requires specific AGR units to demonstrate 

compliance with a limit or an allowance. 

2. QA/QC requirements in 40 CFR Part 60 apply to new or modified sources, not to existing 

sources. It is not appropriate to retroactively apply the stringent Part 60 QA/QC requirements 

(which include initial certification, annual relative accuracy test audits [RATA], quarterly 

cylinder gas audits, daily calibrations, and associated recordkeeping/reporting requirements) to 

existing monitoring equipment that was not designed or installed to meet such requirements. An 

owner or operator who becomes subject to 40 CFR Part 60 QA/QC requirements will design, 

purchase, and install such equipment specifically with the intent of meeting such requirements. It 

is not reasonable for the retroactive application of such stringent QA/QC requirements to apply 

simply because an owner or operator has existing monitoring equipment. 

3. 40 CFR Part 98 Subpart C itself does not mandate Tier 4 methodology unless the stationary 

source is already subject to the QA/QC requirements of 40 CFR Part 75 or Part 60 [ref 

§98.33(b)(4)(ii)(F) and §98.33(b)(4)(iii)(C)]. Therefore, it is unreasonable and far-reaching for 

EPA to require these QA/QC requirements for AGR vents that are not already subject to the 

stringent QA/QC requirements of 40 CFR Part 75 or Part 60, simply because the vents have 

continuous monitoring equipment. 

4. The proposed QA/QC requirements for AGR vents with monitoring equipment cause 

unreasonable and excessive expense applied unevenly across AGR vent owners. The fact that 

some AGR vent owners have monitoring equipment should not subject them to excessive burden 

and expense when there are other acceptable methods in 40 CFR Part 98 Subpart W that other 

AGR vent owners are allowed to use, even though the data quality of the other methods is less 

certain than with continuous gas analyzers/continuous flow monitors. In fact, if existing 

monitoring equipment that currently meets existing QA/QC requirements is unable to satisfy the 

stringent Part 60 requirements, the owner/operator would be forced to spend additional resources 

to replace the existing system, simply because they had an existing system. Operators that do not 

currently have continuous monitoring equipment would not be exposed to this requirement. 

5. AGR vent owners and operators have no opportunity to comment on Tier 4 methodology in 

Subpart C. By proposing a reference to 40 CFR Part 98 Subpart C Tier 4 methodology that 

imposes significant new burdens on some AGR vent owners and operators, EPA has initiated 

rulemaking without the opportunity for stakeholder comments, because Subpart C is not open for 

comment. At the time Subpart C was open to comment, AGR owner/operators would not have 

had any need to comment on the rule. 

Additionally, SandRidge believes that the proposed language in the September 9, 2011 federal 

register should be clarified to specify that Tier 4 methodology would only apply if the 

continuous gas analyzer and continuous flow monitor are sampling and recording data from the 

exhaust stack. Monitoring equipment on the feed to a combustion or process device (such as 

flare, engine, sulfur recovery unit, etc.) could not be appropriately subjected to RATA-type 

QA/QC for C02 emissions, because it is not a direct measurement of emissions. 
72

Proposed Solution 

Therefore, SandRidge proposes that 98.233(d) be changed as shown below, with proposed 

changes to the September 9, 2011 federal register shown in redline format. 

“(d) Acid gas removal (AGR) vents. For AGR vent (including processes such as amine, 

membrane, molecular sieve or other absorbents and adsorbents), calculate emissions for C02 

only (not CH4) vented directly to the atmosphere or through a flare, engine (e.g., permeate from 

a membrane or de-adsorbed gas from a pressure swing adsorber used as fuel supplement), or 

sulfur recovery plant using any of the calculation methodologies described in paragraph (d) of 

this section, as applicable. 

(1) Calculation Methodology 1. If you operate and maintain a CEMS [add: on an AGR exhaust 

Stack] that has both a C02 concentration monitor and volumetric flow rate monitor, you must 

calculate C02 emissions under this subpart by following the Tier 4 Calculation Methodology and 

all associated calculation, quality assurance, reporting, and recordkeeping requirements for Tier 

4 in subpart C of this part (General Stationary Fuel Combustion Sources). [add: For existing 

continuous monitoring equipment on AGR vents, and for continuous monitoring equipment on 

non-combustion AGR vents, the calculation, quality assurance, reporting, and recordkeeping 

requirements of 98.33(a)(4) and 98.34(c) may alternatively be satisfied by following the 

calculation, quality assurance, reporting, and recordkeeping requirements in a permit or the 

recommendations of the manufacturer of the monitoring equipment or general industry practice.] 

If a C02 concentration monitor and volumetric flow rate monitor are not available, you may elect 

to install a C02 concentration monitor and a volumetric flow rate monitor that comply with all of 

the requirements specified for the Tier 4 Calculation Methodology in subpart C of this part 

(General Stationary Fuel Combustion). The calculation and reporting of CH4 and N20 emissions 

is not required as part of the Tier 4 requirements for AGRs." 

Response: EPA notes that CEMS stands for continuous emissions monitoring systems and hence 

cannot be confused for monitoring of feed gas to equipment. Therefore, EPA disagrees with the 

commenter on adding “on an AGR exhaust stack” to Calculation methodology 1. EPA agrees 

with the commenter that the stringent calibration and quality assurance required for combustion 

stack CEMS are not required for AGR vent stack CEMS. Hence, EPA is allowing reporters the 

use of “manufacturer’s instructions or industry standard practice” for calculations, quality 

assurance, reporting, and recordkeeping for CEMS as stated in 98.233(d)(1). 

Section 7.8 ­ Dehydrator Vents

Section 7.8.1 ­ Calculating GHG Emission [W­5, W6]

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 
73

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 28 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added a definition for the “1000” term used in Equation W-5. 

Comment: API requests the following revision to this definition: “1000 = Conversion of EFi in 

thousand standard cubic feet to [add (red): standard] cubic feet.” 

Response: EPA agrees that the word “standard” should be added to the conversion factor 

definition in Equation W-5. Accordingly, this change has been made in this final rule. 

Section 7.9 ­ Well Venting for Liquids Unloading

Section 7.9.1 ­ Calculating GHG Emission [W­7 to W9]

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 18 

Commenter Type: Industry - oil and gas 

Comment: Well venting for liquids unloading, § 98.233(f). EPA has proposed revising the 

calculation methodologies for well venting for liquids unloading, § 98.233(f). We support and 

incorporate by reference the comments regarding Eq. W-8 and Eq. W-9 that were submitted by 

API on October 24, 2011 in Section 2 - W.14 [EPA-HQ-OAR-2011-0512-0042, Excerpt 30] and 

W.15 [EPA-HQ-OAR-2011-0512-0042, Excerpt 31] of its letter. See also Section A.7 supra. 

Response: EPA thanks Chesapeake Energy Corporation and American Exploration & 

Production Council for their comments. Please refer to responses to EPA-HQ-OAR-2011-0512-

0042, Excerpt 30, and EPA-HQ-OAR-2011-0512-0042, Excerpt 31. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 30 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has modified the summation terms in Equation W-8 to account for 

the pressure and tubing diameter groupings. 
74

Comments: 

• API appreciates that EPA has corrected Es,n and SFRq to be stated in standard conditions, 

not actual conditions. 

• For clarity, the term CDp in Equation W-8 should indicate that this is the internal 

diameter, which is consistent with the calculation approach. 

• On page 54 of Appendix D in the Technical Support Document associated with these 

proposed amendment, EPA indicates that the pressure in Equation W-8 is the reservoir 

shut-in pressure. EPA comments that this information is not reliably available in public 

literature. API agrees with this assessment, but further would like to point out that 

reservoir shut-in pressure is not reliably available in operations either. The term SPp

should represent the surface pressure prior to venting, in pounds per square inch absolute

(not atmosphere). 

• In the list of defined terms for Equation W-8, the term HRQ,PW should be HRq,p. 

• EPA has clarified that the term WDp is the distance between the lowest packer to the 

bottom of the well. It is unclear what value should be applied for WDp for wells without 

packers. 

• The amendments did not change 98.233(f)(2)(i) which references 98.233(t) to adjust the 

natural gas volumetric emissions at standard conditions. This adjustment double corrects 

the gas volume for pressure, which is already included in the 0.37×10-3 constant. API 

recommends removing the reference to §98.233(t) since SFRq and Es,n are defined in 

terms of gas volumes at standard conditions (60 oF and 14.7 psia). 

Response: EPA agrees that the term CDp should be the “internal diameter” of the casing, the 

parameter HRq,p was listed incorrectly, and the reference to paragraph §98.233(t) should be 

removed. EPA agrees with API’s definition change to SPw and in this final rule has updated 

Equation W-8 to reflect “pounds per square inch absolute” instead of “pounds per square inch 

atmosphere”. 

In this final rule, EPA is allowing the use of surface pressure in Equation W-8 with certain 

stipulations; please see preamble section II.C. - Final Amendments to the Petroleum and Natural 

Gas Systems Source Category: Well Venting for Liquids Unloading for further details. Also, 

agrees that the definition for WDp does not address wells without packers, and in this final rule, 

has revised the definition to make provision for wells without packers by restating the definition 

as “Well depth from either the top of the well or the lowest packer to the bottom of the well”. 

Finally, EPA agrees that shut-in pressure may not be known for all wells. Therefore, EPA is 

allowing the use of surface pressure or casing pressure either when the well is shut-in or just 

before liquids unloading. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 31 

Commenter Type: Industry - oil and gas 
75

Comment: Revision: EPA revised Equation W-9. 

Comments: 

• API appreciates that EPA has corrected Es,n and SFRq to be stated in standard conditions, 

not actual conditions. 

• For clarity, the term TDp in Equation W-9 should indicate that this is the internal 

diameter, which is consistent with the calculation approach. 

• The term SPp should be the flowing wellhead pressure, not the sales line pressure which 

has no bearing for wells on compression. Using the sales line pressure in this situation 

will over-estimate emissions. SPp should also be expressed as pounds per square inch 

absolute, (not atmosphere) which is gauge pressure + 14.7 psi and is consistent with the 

pressure adjustment included in the 0.37×10-3 constant. 

• The amendments did not change 98.233(f)(3)(i) which references §8.233(t) to adjust the 

natural gas volumetric emissions at standard conditions. This adjustment double corrects 

the gas volume for pressure, which is already included in the 0.37×10-3 constant. API 

recommends removing the reference to §98.233(t) since SFRq and Es,n are defined in 

terms of gas volumes at standard conditions (60 oF and 14.7 psia). 

• API requests the use of Methodology 3 for wells without plunger lifts. 

Response: EPA agrees that the term TDp should be for “internal diameter” and that the reference 

to paragraph §98.233(t) should be removed; EPA is making these changes to this final rule. 

EPA disagrees that the sales line pressure should not be used; please see the response to EPAHQ-OAR-2011-0147-0007, Excerpt 3. EPA is also clarifying that sales line pressure may be 

estimated using best available data; please see preamble section II.C. - Final Amendments to the 

Petroleum and Natural Gas Systems Source Category: Well Venting for Liquids Unloading for 

further discussion on this issue. EPA disagrees that Methodology 3 should be used for wells 

without plunger lifts. Equation W-8 and W-9 were specifically derived for wells without plunger 

lifts and wells with plunger lifts, respectively; please see docket memo “Change to Equation W-7 

Well Liquids Unloading” located in the docket: EPA-HQ-OAR-2009-0923. 

Section 7.9.2 ­ Data Reporting Requirements

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 29 

Commenter Type: Industry - oil and gas 

Comment: Revision: For Well Venting for Liquids Unloading, EPA is proposing a vent 

measurement for each unique well tubing diameter grouping and pressure grouping in each subbasin category. Pressure groupings are defined in 98.238 as: = 25 psig; 25-60 psig; 60-110 psig, 

110-200 psig; and > 200 psig. Tubing diameter groupings are defined in 98.238 as = 1 inch; 1-2 

inches; and = 2 inches. The average flow rate is calculated for each unique tubing diameter 
76

grouping and pressure grouping in each sub-basin category by dividing the recorded total flow 

by the recorded time for a single liquid unloading with venting to the atmosphere. The revisions 

also state that for a new producing sub-basin category, an average flow rate is calculated 

beginning in the first year of production. 

Comment: EPA has modified the terms used in Equation W-7 to address the groupings by tubing 

diameter and pressure. However, the emissions resulting from Equation W-7 are inconsistent 

with the reporting requirements under 98.236(c)(5). It appears, though it is not explicitly stated, 

that Equation W-7 is intended to result in emissions summed for the sub-basin, while the 

reporting requirements are for each well tubing diameter and pressure grouping. API interprets 

Equation W-7 to result in emissions aggregated for the sub-basin and requests that the reporting 

requirements be modified to be consistent. 

The reporting requirements are further confused by combining the requirements for 

Methodologies 1, 2, and 3 all under the same paragraph of 98.236(c)(5). API requests that EPA 

specify separate reporting requirements for Methodology 1. 

Methodology 1 indicates that the pressure groupings apply across each of the sub-basin category 

(conventional and unconventional) and tubing grouping. API has provided separate comments 

specifically addressing the pressure groupings under comment W.56 [EPA-HQ-OAR-2011-

0512-0042, Excerpt 74]. 

As indicated in comment W.58 [EPA-HQ-OAR-2011-0512-0042, Excerpt 76], API proposes the 

use of two tubing diameter groupings, rather than the three proposed by EPA. In addition, while 

the pressure and tubing groupings only apply to Methodology 1, the reporting requirements 

under 98.236(c)(5) require reporting emissions for each tubing diameter and pressure grouping 

for Methodologies 2 and 3 as well. API requests that EPA remove the reporting requirements by 

pressure grouping for Methodologies 2 and 3 since these groupings do not apply to calculation 

Methodologies 2 and 3. 

Response: EPA disagrees with the commenter that reporting for Methodology 1 should be only 

at a sub-basin level. The methodology requires estimation of emissions at a pressure grouping 

and sub-basin level. Hence, reporting at the same level of granularity is not an issue. 

EPA agrees that the pressure groupings should not apply to Methodologies 2 and 3 and is 

revising the data reporting section accordingly to require reporting only at a sub-basin category 

level for these two methodologies. EPA disagrees that only two pressure groupings should be 

used. Please see response to EPA-HQ-OAR-2011-0512-0042, Excerpt 74, for further 

explanation. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 57 

Commenter Type: Industry - oil and gas 
77

Comment: Revision: For well venting for liquids unloading, EPA requires reporting for each 

well tubing diameter grouping and pressure grouping. For Methodology 1, EPA also requires 

reporting the casing diameter, depth, and pressure of each well selected to represent emissions in 

that tubing size and pressure combination. 

Comment: 98.236(c)(5) requires reporting the casing diameter for Equations W-7, 8, and 9, 

although casing diameter is not used for Equations W-7 or W-9. Also, where Methodologies 2 

and 3 are applied, tubing and pressure groupings are not used, so the reporting requirements for 

these methodologies should not reference the tubing and pressure groupings. API requests that 

these inconsistencies between the reporting requirements and calculation methodologies be 

removed. 

Response: EPA agrees that pressure groupings and tubing diameter groupings combinations are 

not used in Calculation Methodology 2 or 3 under paragraph 98.233(f), and in this final rule has 

modified the data reporting requirements to not require this data when methodologies 2 and 3 are 

used. EPA agrees that the pressure groupings should not apply to Calculation Methodology 2 

and 3, and in this final rule, has revised the data reporting section accordingly to require 

reporting only at a sub-basin category level for these two methodologies. 

Section 7.10 ­ Gas Well Venting During Completions and Workovers from

Hydraulic Fracturing

Commenter Name: William W. Grygar II 

Commenter Affiliation: Anadarko Petroleum Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0028

Comment Excerpt Number: 7 

Commenter Type: Industry - oil and gas 

Comment: 

• Under §98.233(g), reporters should have the option of using measured data on gas vented 

and/or flared, if available, for all wells hydraulically fractured during completions and 

workovers. 

• Under §98.233(g)(1), the clarification should be made that the number of measurements 

are per each sub-basin category. Similarly, under §98.233(g)(1)(i), the regulatory text 

should read, "For well completion(s) and well workover(s) in each producing sub-basin 

category ... " 

Response: EPA agrees with the commenter’s recommendation to allow reporters to calculate 

emissions using metered volumes of the backflow subsequent to the hydraulic fracture; please 

see the response to EPA-HQ-OAR-2011-0512-0042, Excerpt 32, for further details. 
78

EPA has clarified in the introductory text of 40 CFR 98.233 (g)(1) that the number of required 

measurements are the specified number of completions and workovers for either vertical or 

horizontal wells are performed in a sub-basin category. 

Section 7.10.1 ­ Calculating GHG Emission [W10 to W12]

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 32 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA revised Equation W-10, but not as API had requested in our July 29, 

2011 correspondence to EPA. 

Comment: In an e-mail provided to EPA on July 29, 2011, API provided regulatory revisions to 

Equation W-10. API proposed to remove the subtraction of the SG term and define the “flowback volume” term in Equation W-10 by limiting it only to the time span during which gas is 

actually vented to the atmosphere or flared. The SGp term should be removed and FRM should 

be revised to reflect venting to the atmosphere. SGp is not needed since T is defined as the hours 

vented. If a well is venting, then it is not recovering to sales. 

These proposed revisions add clarity, simplify the calculation, and reflect the emissions 

characteristics of flow-back operations. Without the removal of the SG term, Equation W-10 has 

the potential to either lead to the calculation of a negative emissions value, or compare emissions 

values vented to the atmosphere to sales values that are produced against the back-pressure of a 

gathering or sales pipeline; these are two completely different operating scenarios. API’s 

proposed mark-ups to incorporate the changes for 98.233(g) are provided in Section 4 of these 

comments. 

EPA has added language defining the number of measurements required based on the number of 

workovers/completions. API interprets this requirement to apply to the sub-basin. Clarification is 

needed that the number of measurements required is relative to a sub-basin or basin (facility) and 

well type combination and not total number of completions/workovers. 

In addition, API requests the addition of a new equation that sums available measurements and 

eliminates the need for normalizing and tracking cumulative venting time. Some companies are 

planning to measure the venting associated with gas well completion and workovers with 

hydraulic fracturing. Equation W-10 does not allow the use the actual measurements. API has 

included this new equation in the proposed revisions provided in Section 4 below. 

Response: EPA disagrees that the term SGp should be removed from Equation W-10A. The 

parameter “FRM”, which is calculated using Equation W-12, has been amended to the ratio of 

backflow during well completions and workovers from hydraulic fracturing to the 30-day 
79

production rate. Therefore, the backflow measurement is not only limited to the time the gas is 

vented to the atmosphere or flared, but also includes the time the gas is recovered for beneficial 

use. Consequently, subtracting “SGp” in Equation W-10A, will not result in negative emissions. 

Instead, it will only take out the amount of gas that is recovered for beneficial use from the total 

amount of backflow for a specific well in a sub-basin and well-type combination. 

EPA agrees with the commenter’s recommendation to allow reporters to calculate emissions 

using metered volumes of the backflow subsequent to the hydraulic fracture; therefore, in this 

final rule, EPA has added Equation W-10B. This equation can only be used if vented or flared 

backflow volumes for all well are measured in a sub-basin category and well-type combination. 

In this final rule, EPA has clarified in the introductory text of 40 CFR 98.233 (g)(1) that the 

number of required measurements are if the specified number of completions and workovers for 

either vertical or horizontal wells are performed in a sub-basin category. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 33 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has modified the definitions of terms associated with Equations W11A and W-11B. 

Comment: In Equations W-11A and W-11B. “A” is defined as m2 instead of m2, which API 

interprets to mean “meters squared”. However, cross sectional area of an orifice is usually 

reported in inches squared. API would prefer to define the term “A” as inches squared (in2) and 

the other terms in these equations in English units, consistent with industry practices. 

Response: EPA agrees that the unit for “A” should be defined as “m2

” and has changed it 

accordingly in this final rule. Equations W-11A and W-11B have been subjected to peer review 

and validation and can be found in engineering handbooks and textbooks. These equations, as 

they stand, require the use of metric units. Converting the units of parameters from English units 

to metric units for use in Equation W-11A and Equation W-11B does not place undue burden on 

reporters. Therefore, the units of Equations W-11A and W-11B have been retained in this final 

rule. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 34 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has added Equation W-11C to determine whether the flow rate is 

sonic or subsonic. Flow is sonic if the value of R is greater than 2. 
80

Comment: API appreciates the clarity provided by documenting the equation determining if the 

flow rate is sonic or sub-sonic. However, Methodology 2 does not acknowledge that a single 

completion or workover can alternate between sonic and sub-sonic flows. As API pointed out in 

a letter to EPA on May 13, 2011, flowback on any single completion will be partially supersonic 

and partially subsonic. Reporters cannot discern exactly when flowback falls into either category 

during a completion. Additionally, liquids and gases flow at different rates. As a completion 

progresses, the amount of liquids decreases and the amount of gases increases, which makes 

performing the calculations more difficult. EPA should replace this methodology with a single 

calculation for tracking pressure drop across the choke, with assumptions for choke flow and gas 

gravity. Such a calculation will be technically feasible and sufficient for policy purposes. 

Response: EPA agrees that it is difficult to track flow that alternates between sonic or subsonic. 

In this final rule, EPA has allowed operators to use best engineering estimate based on best 

available data and Equation W-11C to determine whether the flow is predominantly sonic or subsonic. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 35 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has added Equation W-12 to quantify a ratio of emissions to 30-days 

production 

Comment: As provided to EPA in an e-mail on July 29. 2011 and also included is Appendix A to 

these comments, API had proposed the use of the first calendar month for developing a 

normalized production rate. API would agree to use 30-days of production as well. However, as 

noted in comment W-16 above, the key issue is that the time used in Equation W-10 should only 

reflect flowback time and should not include time when gas is sent to sales. 

Response: EPA does not agree that gas sent to the flow line should not be included in the ratio 

calculated in Equation W-12; please see the response to EPA-HQ-OAR-2011-0512-0042, 

Excerpt 32. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 91 

Commenter Type: Industry - oil and gas 

Comment: [Please refer to the original comment text posted in the docket] The follow 

reiterates suggested regulatory revisions provided to EPA on July 29, 2011 addressing workover 
81

and completions. The mark-ups shown are incorporated into the September 9, 2011 proposed 

regulatory amendments. 

During a meeting with API on May 26, 2011, EPA had outlined an approach to extrapolate 

measured or quantified flow-back volumes for gas well completions and workovers across all 

workovers and completions in the sub-basin category. The following provides API’s mark-ups to 

the September 9, 2011 proposed regulatory language to incorporate this approach. API’s 

revisions for the flow-back volume normalization approach are indicated in blue text. 

API’s revisions include a modification to Equation W-10 that consists of removing the 

subtraction of the SG term. API is proposing to define the “FRM” term in Equation W-10 by 

limiting it only to the time span during which gas is actually vented to the atmosphere or flared. 

These proposed revisions add clarity, simplify the calculation, and reflect the emissions 

characteristics of flow-back operations. Without the removal of the SG term, Equation W-10 has 

the potential to either lead to the calculation of a negative emissions value, or compare emissions 

values vented to the atmosphere to sales values that are produced against the back-pressure of a 

gathering or sales pipeline; these are two completely different operating scenarios. 

Please note that these proposed regulatory revisions do not yet address changes to Methodology 

2 under §98.233(g). API is working to develop an alternative approach to Equations W-11 and 

W-12, but this is a difficult technical challenge. API intends to address this separately with EPA. 

(g) Gas well venting during completions and workovers from hydraulic fracturing. Calculate 

CH4, CO2 and N2O (when flared) annual emissions from gas well venting during completions 

involving hydraulic fracturing in wells and well workovers using Equation W-10[add (blue): A 

or W-10B] of this section. Both CH4 and CO2 volumetric and mass emissions shall be calculated 

from volumetric total gas emissions using calculations in paragraphs (u) and (v) of this section. 

[See original comment for Eq. W-10A] (Eq. W-10A) 

Where: 

Es,n = Annual volumetric total gas emissions in cubic feet at standard conditions from gas well 

venting [add (blue): to the atmosphere or a flare] during completions or workovers following 

hydraulic fracturing for each sub-basin [add (blue): category] and well type combination [add 

(blue): (vertical or horizontal).] 

Tp = Cumulative amount of time [add (blue): venting to the atmosphere or a flare post fracture 

stimulation before being routed to production. Reported] in hours of each well(p) completion or 

workover [delete (blue): venting] in a sub-basin and well type combination during the reporting 

year. 

[add (blue): FRM = Ratio of venting to the atmosphere or flare to 30-day production rate] [delete 

(blue): Venting to 30-day production ratio] [add (blue): from Equation W-12.] 

PRp = First 30-day average production flow rate [add (blue): after well completion or well 

workover operations have ended and the well has been routed to normal production ]in standard 
82

cubic feet per hour of each well (p), [delete (blue): under actual conditions, converted to standard 

conditions,] as required in paragraph (g)(1) of this section. 

EnF = Volume of CO2 or N2 injected gas in cubic feet at standard conditions that was injected 

into the reservoir [add (blue): during the completion or workover] [delete (blue): an energized 

fracture job] for each well (p). If the fracture process did not inject gas into the reservoir, then 

EnF is 0. If injected gas is CO2 then EnF is 0. 

[delete (blue): SGp = Volume of natural gas in cubic feet at standard conditions that was 

recovered into a sales pipeline for well p as per paragraph (g)(3) of this section. If no gas was 

recovered for sales, SG is 0.] 

[add (blue) or 

[See original comment for Eq. W-10B] (Eq. W-10B) 

Where 

Es,n = Annual volumetric total gas emissions in cubic 

feet at standard conditions from gas well venting to the atmosphere or a flare during completions 

or workovers following hydraulic fracturing for each sub-basin category and well type 

combination (vertical or horizontal). 

EnF = Volume of CO2 or N2 injected gas in cubic feet at 

standard conditions that was injected into the reservoir during an energized fracture job for each 

well (p). If the fracture process did not inject gas into the reservoir, then EnF is 0. If injected gas 

is CO2 then EnF is 0. 

FRM = Measured Volume of flow-back gas from completions or workovers for the time that gas 

is vented to the atmosphere or a flare, in cubic feet at standard conditions. 

W = Number of wells completed or worked over using Hydraulic fracturing in a sub-basin.] 

(1) The average flow rate for gas well venting to the atmosphere or to a flare during well 

completions and workovers from hydraulic fracturing shall be determined using either of the 

calculation methodologies described in this paragraph (g)(1) of this section. The number of 

measurements shall be determined as follows: One measurement for less than or equal to 25 

completions/workovers; two measurements for 26 to 50 completions/workovers; three 

measurements for 51 to 100 completions/workovers; four measurements for 101 to 250 

completions/workovers; and five measurements for greater than 250 completions/workovers. 

(i) Calculation Methodology 1. For one well completion(s) in each gas producing sub-basin 

category and well type (horizontal or vertical)combination and for one well workover(s) in each 

gas producing sub-basin category and well type (horizontal or vertical) combination, a recording 
83

flow meter (digital or analog) shall be installed on the vent line, ahead of a flare if used, to 

measure the backflow venting event according to methods set forth in §98.234(b). 

(ii) Calculation Methodology 2. For one horizontal gas well completion and one vertical gas well 

completion in each gas producing sub-basin category and for one horizontal well workover and 

one vertical well workover in each gas producing sub-basin category, record the well flowing 

pressure upstream (and downstream in subsonic flow) of a well choke according to methods set 

forth in §98.234(b) to calculate intermittent well flow rate of gas during venting to the 

atmosphere or a flare. Calculate emissions using Equation W-11A of this section for subsonic 

flow or Equation W-11B of this section for sonic flow. Use equation W-11C of this section to 

determine whether flow is sonic or subsonic. If the value of R in Equation W-11C is greater than 

or equal to 2, then flow is sonic; otherwise, flow is subsonic: 

[See original comment for Eq. W-11A] (Eq. W-11A) 

Where: 

FR = Average flow rate in cubic feet per hour, under subsonic flow conditions. 

A = Cross sectional area of orifice ( [add (blue): 2]). 

P1 = Upstream pressure (psia). 

Tu = Upstream temperature (degrees Kelvin). 

P2 = Downstream pressure (psia). 

3430 = Constant with units of m[add (blue): 2] /(sec[add (blue): 2] * K). 

1.27*105 = Conversion from m[add (blue): 3] /second to ft[add (blue): 3] /hour. 

[See original comment for Eq. W-11B] (Eq. W-11B) 

Where: 

FR = Average flow rate in cubic feet per hour, under sonic flow conditions. 

A = Cross sectional area of orifice (m[add (blue): 2]). 

Tu = Upstream temperature (degrees Kelvin). 

187.08 = Constant with units of m[add (blue): 2]/(sec[add (blue): 2] * K). 

1.27*105 = Conversion from m[add (blue): 3] /second to ft[add (blue): 3] /hour. 

[See original comment for Eq. W-11C] (Eq. W-11C) 
84

Where: 

R = Pressure ratio 

P1 = Pressure upstream of the restriction orifice in pounds per square inch absolute. 

P2 = Pressure downstream of the restriction orifice in pounds per square inch absolute. 

(iii) The emissions to 30-day production ratio is calculated using Equation W-12 of this section. 

[See original comment for Eq. W-12] (Eq. W-12) 

Where: 

FRM = [add (blue): Ratio of venting to the atmosphere or flare] [delete (blue): Emissions] to 30-

day production rat[delete (blue) eio]. 

FRp = Measured flow rate from Calculation Methodology 1 or estimated flow rate from 

Calculation Methodology 2 in standard cubic feet per hour [add (blue): of venting to the 

atmosphere or flaring] for well(s) p for each sub-basin and well type [add (blue): (horizontal or 

vertical) combination.] 

PRp = First 30-day production rate in standard cubic feet per hour [add (blue): after well 

completion or well workover operations have ended and the well has been routed to normal 

production] for each well p that was measured in the sub-basin and well type combination 

(horizontal or vertical). 

W = Number of wells [add (blue): sampled per the requirements of paragraph 98.233(g)(1)] 

[delete (blue): completed or worked over using hydraulic fracturing in a sub-basin and well type 

formation.] 

(iv) The [add (blue): average] flow rates 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 

sub-basin and well type combination for the total number of hours of venting [add (blue): to the 

atmosphere or a flare] of each of these wells. 

(v) New [add (blue): average] flow rates for horizontal and vertical gas well completions and 

horizontal and vertical gas well workovers in each sub-basin category shall be calculated once 

every two years starting in the first calendar year of data collection. 

(2) The volume of CO2 or N2 injected into the well reservoir during [add (blue): completion or 

workover] [delete (blue): energized hydraulic fractures] will be measured using an appropriate 

meter as described in 98.234(b) or using receipts of gas purchases that are used for the energized 

fracture job. 
85

(i) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section. 

(ii) [Reserved] 

[delete (blue): (3) The volume of recovered completion or workover gas sent to a sales line will 

be measured using existing company records. If data does not exist on sales gas, then an 

appropriate meter as described in 98.234(b) may be used. 

(i) Calculate gas volume at standard conditions using calculations in paragraph (t) of this section. 

(ii) [Reserved]] 

(3[delete (blue):4]) Both CH4 and CO2 volumetric and mass emissions shall be calculated from 

volumetric total emissions using calculations in paragraphs (u) and (v) of this section. 

[delete (blue): (5) Determine if the well completion or workover from hydraulic fracturing 

recovered gas with purpose designed equipment that separates saleable gas from the backflow, 

and sent this gas to a sales line (e.g. reduced emissions completion). 

(i) Use the factor SG in Equation W-10 of this 

section, to adjust the emissions estimated in paragraphs (g)(1) through (g)(4) of this section by 

the magnitude of emissions captured using reduced emission completions as determined by 

engineering estimate based on best available data. 

(ii) [Reserved]] 

(4[delete (blue): 6]) Calculate annual emissions from gas well venting during well completions 

and workovers from hydraulic fracturing to flares as follows: 

(i) Use the total gas well venting volume during well completions and workovers as determined 

in paragraph (g) of this section. 

(ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine 

gas well venting during well completions and workovers using hydraulic fracturing emissions 

from the flare. This adjustment to emissions from completions using flaring versus completions 

without flaring accounts for the conversion of CH4 to CO2 in the flare. 

Response: EPA agrees with the commenter’s recommendation to allow reporters to calculate 

emissions using metered volumes of the backflow subsequent to the hydraulic fracture; please 

see the response to EPA-HQ-OAR-2011-0512-0042, Excerpt 32 for further details. 

EPA has combined the requirements of 40 CFR 98.233 (g)(3) and 40 CFR 98.233 (g)(5), because 

the requirements in both were duplicative. The requirements in 40 CFR 98.233 (g)(5) has been 
86

deleted and paragraph 40 CFR 98.233 (g)(6), (g)(6)(i), and (g)(6)(ii) has been re-designated as 

40 CFR 98.233 (g)(5), (g)(5)(i), and (g)(5)(ii). 

EPA disagrees with the commenter’s stance that the normalized backflow volumes (i.e. “FRM”) 

multiplied by the 30-day production only accounts for the amount of gas that is vented to the 

atmosphere or flared. EPA disagrees with any rule text edits associated with the commenter’s 

suggestion, including the deletion of SGp. Please see the response to EPA-HQ-OAR-2011-0512-

0042, Excerpt 32 for further details. 

Section 7.10.2 ­ Data Reporting Requirements

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 58 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA requires reporting emissions by sub-basin and well type for well 

completions and workovers with hydraulic fracturing. EPA also requires reporting annual CO2 

and CH4 emissions that resulted from gas venting directly to the atmosphere and that annual 

CO2, N2O, and CH4 emissions resulted from flares, 

Comment: For 98.236 (c)(6)(i)(B)&(D) API suggests that the average flow rate should be 

reported in “standard” cubic feet instead of cubic feet. 

Response: EPA agrees that the average flow rates reported in 40 CFR 98.236 (c)(6)(i)(B) and 

40 CFR 98.236 (c)(6)(i)(D) are at standard cubic feet. EPA in this final rule has amended these 

reporting requirements accordingly.

Section 7.11 ­ Gas Well Venting During Completions and Workovers Without

Hydraulic Fracturing

Commenter Name: William W. Grygar II 

Commenter Affiliation: Anadarko Petroleum Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0028

Comment Excerpt Number: 8 

Commenter Type: Industry - oil and gas 

Comment: Under §98.233(h), term Now should read "Number of workovers per sub-basin 

category not involving ... " 
87

Response: EPA agrees with the commenter and in this final rule has revised the term Nwo to 

reflect accounting at a sub-basin level. 

Section 7.11.1 ­ Calculating GHG Emission [W13]

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 36 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has addressed gas volumes at standard conditions and the sub-basin 

category approach in revisions to the definition of terms for Equation W-13. 

Comment: EPA has changed Vf and Tf to Vp and Tp, respectively in the definitions, but did not 

change the variable subscripts in the equation. Also, the term “Vv” is defined in terms of each 

blowdown “i”. However, the subscript “i” is not used in either Equation W-14A or W-14B. API 

believes “i” should be replaced with “p”. 

Response: EPA agrees that the subscript “p” did not get updated in the parameter definitions for 

Equation W-13. 

Parameter “Vv” has been redefined to “V” in Equation W-14A and W-14B. In Equation W-14B, 

all references to subscript “i” have been removed and replaced with subscript “p”. A definition 

for subscript “p” has been added.

Section 7.12 ­ Blowdown Vent Stack

Section 7.12.1 ­ Calculating GHG Emission [W14A, W­14B]

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 15 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] INGAA supports 

the addition of Equation W-14B, which estimates blowdown vent stack emissions by summing 

venting events for the year. However, minor errors need to be corrected. 

INGAA requested that an additional calculation method be included in §98.233(i), and INGAA 

supports the addition of Equation W-14B. Minor errors in the new text need to be revised. For 

example, the reference to a "purge factor" should be deleted. 
88

Methods prescribed in §98.233(i) are used to estimate natural gas emissions from blowdown 

events. Equation W-14A and associated reporting requirements apply to equipment where every 

blowdown event has the same physical volume, gas temperature, starting and ending pressure, 

and blowdown vent stack. The methods associated with this equation do not apply to normal 

operating practices at transmission and storage facilities. The physical volume of vented 

equipment depends on the locations of operational isolation valves and blowdown events do not 

typically have the same physical volume. Similarly, starting and ending pressures and 

temperatures typically vary for blowdown events. In addition, operations often dictate use of 

more than one vent stack (i.e., there is not a unique vent stack for each piece of equipment). 

INGAA's June 2011 letter recommended the approach reflected in Equation W-14B to address 

these real-world considerations for estimating blowdown event emissions and to be consistent 

with typical blowdown data collection practices that are already in place. Equation W-14B 

accomplishes this by estimating annual facility blowdown emissions by summing emissions 

from individual events, with event emissions calculated from event-specific physical volume, 

temperature, and pressures. INGAA supports adding this equation to Subpart W, but there are 

minor corrections needed to the equation and description of Equation W-14B parameters. For 

example, although subtle, in the equation the subscript for "start" (i.e., pressure at start of event) 

should be a capital "S" rather than lower case "s" because the latter is used in the equation and 

throughout Subpart W to denote standard conditions. (In June 2011, INGAA recommended time 

zero and time final ("0" and "f" subscripts) in the equation and this avoids using a duplicative 

subscript). Based on EPA's subscripts, Equation W-14B should be revised (edits are not shown 

within the equation) and parameter definitions in Equation W-14B should be revised as follows: 

[See original comment for Eq. W-14B] 

Where: 

Es,n = Annual natural gas venting emissions at standard conditions from blowdowns in cubic 

feet. 

N = Number of repetitive blowdowns [delete: for each unique volume] in [add: the] calendar 

year. 

Vv [add: ,i] = Total [add: physical] volume of blowdown equipment chamber (including 

pipelines, compressors and vessels) between isolation valves in cubic feet for each blowdown 

“i.” 

[delete: C = Purge factor that is 1 if the equipment is not purged or zero if the equipment is 

purged using non-GHG gases. ] 

Ts = Temperature at standard conditions (°F). 

Ta [add: ,i] = Temperature at actual conditions in the blowdown equipment chamber (°F) for 

each blowdown “i”. 
89

Ps = Absolute pressure at standard conditions (psia). 

Pa,[delete: s] [add: S], [delete: p] [add: i] = Absolute pressure at actual conditions in the 

blowdown equipment chamber (psia) at the start of the blowdown “[delete: p] [add: i]”. 

Pa,[delete: e] [add: E], [delete: p] [add: i] = Absolute pressure at actual conditions in the 

blowdown equipment chamber (psia) at the end of the blowdown “[delete: p] [add: i]”; 0 if 

blowdown volume is purged using non-GHG gases. 

Response: EPA disagrees to the changes in definition of parameter N. EPA requires calculation 

and reporting of blowdown emissions by each unique physical volume; please see response to 

EPA-HQ-OAR-2011-0512-0029, Excerpt 16 for further details. In this final rule, all references 

to subscript “i” have been removed and replaced with subscript “p”. A definition for subscript 

“p” has also been added. EPA agrees to the clarification on subscripts designating the beginning 

and end of a blowdown and also agrees on the deletion of the purge factor. In this final rule, 

EPA has deleted the purge factor definition and has represented the pressure at the start of the 

blowdown as “Pa,b,p,” standing for pressure at the beginning of the blowdown event. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 30 

Commenter Type: Trade Association 

Comment: Compressibility should be allowed in blowdown vent stack calculations at the 

operator's discretion. 

EPA requests comment [76 FR 56031] on whether an allowance should be provided for 

considering compressibility in blowdown calculations. When calculating blowdown emissions 

for current operations, some natural gas operators include compressibility in calculations that 

generally follow Equation W-14B. This approach should be allowed, at the operators discretion, 

since it is an existing practice based on engineering principles and provides a more accurate 

estimate. This can be readily addressed in Subpart W by including compressibility as a parameter 

in equations W-14A and W-14B, and clearly indicating that the compressibility factor is assumed 

to be one unless the operator chooses to apply a compressibility factor. 

Response: EPA does not consider the complexities in mandating a compressibility factor to be 

warranted for the purposes of informing future policy. EPA believes that the variability of 

allowing voluntary use of a compressibility factor, with a default value of 1 (one), would 

unnecessarily complicate comparison of reported blowdown data. Please see response to 

comment number EPA-HQ-OAR-2011-0512-0041, Excerpt 3. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 
90

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 36 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] 

[highlighted text: Clarify ?exempt volumes; events to include (i.e., “significant” blowdowns for 

maintenance or safety), and add another calc (operator selects calc to use) where events are 

calculated and summed.] 

Calculate CO2 and CH4 blowdown vent stack emissions from depressurizing equipment to the 

atmosphere [ add: to reduce [comment bubble JMc4: Intent is to include “significant” blowdown 

events associated with shutdowns and maintenance activity.] system pressure for planned or 

emergency shutdowns or to take equipment out of service for maintenance] (excluding 

depressurizing to a flare, over-pressure relief, [delete: operating pressure control venting and] 

blowdown of non-GHG gases; desiccant dehydrator blowdown venting before reloading is 

covered in paragraph (e)(5) of this section) as follows: 

(1) Calculate the total volume (including pipelines, compressor case or cylinders, manifolds, 

suction bottles, discharge bottles, and vessels) between isolation valves determined by 

engineering estimate based on best available data. 

(2) If the total [add: physical] volume between isolation valves is greater than or equal to 50 

[delete: standard] cubic feet, retain logs of the number of blowdowns [delete: for each equipment 

type] (including but not limited to compressors, vessels, pipelines, headers, fractionators, and 

tanks). [delete: Blowdown] [add: Physical] volumes smaller than 50 [delete: standard] cubic feet 

are exempt from reporting under paragraph (i) of this section. 

(3) [add: The operator can elect to use either Equation W-14a or W-14b.] [comment bubble 

JMc5: Additional description can be included in the preamble: Equation W-14a (former Equation 

W-14) applies to an equipment type (i.e., group of equipment) where the estimate is based on the 

following physical and operating properties: the same unique blowdown chamber volume; the 

same blowdown chamber pressure and temperature; and, the same equipment purging practices 

(i.e., C = 0 or 1). Equation W-14b is appropriate if the blowdown pressure differential (start and 

end pressures) vary for different events and calculations for annual emissions are based on 

summing the calculated volume for events that occur throughout the year. For the latter, each 

event can be unique, so reporting requirements include total annual emissions and number of 

annual events.] Calculate [delete: the] total annual venting emissions for each equipment type 

using Equation W–14a [delete: of this section:] [add: or calculate total annual venting emissions 

using Equation W–14b. The operator can include corrections that address factors such as gas 

compressibility when completing the calculation.][comment bubble JMc6: This sentence is 

needed to allow operators to use existing vent records – e.g., similar equation used but 

longstanding calculation includes minor adjustments for factors such as compressibility. Without 

this sentence, some operators will have “two sets of books” for calculating vented emissions.] 

[See original comment for equation (Eq. W-14a)] 

Where: 
91

Es,n = Annual natural gas venting emissions at standard conditions from blowdowns in cubic 

feet. 

N = Number of repetitive blowdowns for each equipment type of a unique volume in calendar 

year. 

Vv = Total volume of blowdown equipment chambers (including pipelines, compressors and 

vessels) between isolation valves in cubic feet. 

C = Purge factor that is 1 if the equipment is not purged or zero if the equipment is purged using 

non-GHG gases. 

Ts = Temperature at standard conditions ( °F). 

Ta = Temperature at actual conditions in the blowdown equipment chamber ( °F). 

Ps = Absolute pressure at standard conditions (psia). 

Pa = Absolute pressure at actual conditions in the blowdown equipment chamber (psia). 

[See original comment for Eq.-W-14b] 

[add: Where: 

Es,n= Annual natural gas venting emissions at standard conditions from blowdowns in cubic 

feet. 

N = Number of blowdowns in the calendar year. 

Vv,i = Total volume of blowdown equipment chambers (including pipelines, compressors and 

vessels) in cubic feet. 

Ts = Temperature at standard conditions ( °F). 

Ta,i = Temperature at actual conditions (estimated) for event ?i? in the blowdown chamber (°F). 

Ps = Absolute pressure at standard conditions (psia). 

Pa,0,i = Absolute pressure at actual conditions at the start of event ?i" in the blowdown chamber 

(psia). 

Pa,f,i = Absolute pressure of natural gas at actual conditions at the end of event ?i" in the 

blowdown chamber (psia) ((if the equipment is purged using non-GHG gases then Pa,f,i = 0).] 

(4) Calculate both CH4 and CO2 volumetric and mass emissions from volumetric natural gas 
92

emissions using calculations in paragraph (u) and (v) of this section. [add: This calculation can 

use the gas composition per §98.232(m).] 

(5) Calculate total annual venting emissions for all blowdown vent stacks by adding all standard 

volumetric and mass emissions determined [delete: in] [add: from] Equation[add: s] W–14[add: a 

or W-14b] and paragraph (i)(4) of this section. 

Response: EPA disagrees with the commenter. Exempt volumes already have enough clarity, 

and adding the word “significant” will not improve the clarity. Also, both equations result in a 

summed total of emissions for each unique physical volume. Please see response to EPA-HQOAR-2011-0512-0029, Excerpt 16 for further details. EPA agrees with the commenter on 

adding the word “physical” and removing “standard” where appropriate to the unique volume. 

EPA also agrees with the commenter and is removing any references to the words “equipment 

type”. A unique physical volume is a reference to one or more equipment collectively blowdown 

to the atmosphere and hence the term “equipment type” is unnecessary. EPA has made these 

changes in this final rule. EPA does not agree with the commenter on the issue of 

compressibility; please see response to comment number EPA-HQ-OAR-2011-0512-0041, 

Excerpt 3. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 4

Commenter Type: Trade Association

Comment: §98.233(i) appropriately refers to §98.233(u) and (v). This is the general 

methodology that INGAA recommends for all §98.233(a) – (r) subsections in Comment 20. 

Response: EPA agrees with the commenter. 

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033 

Comment Excerpt Number: 19 

Commenter Type: Industry - oil and gas 

Comment: (3) Blowdown vent stacks – § 98.233(i). We support and incorporate by reference 

the comments regarding reporting emissions from blowdown vent stacks submitted by API 

October 24, 2011 (Section 2 - W.21 [EPA-HQ-OAR-2011-0512-0042, Excerpt 37], W.22 [EPAHQ-OAR-2011-0512-0042, Excerpt 38], W.23 [EPA-HQ-OAR-2011-0512-0042, Excerpt 39], 

and W.24 [EPA-HQ-OAR-2011-0512-0042, Excerpt 40]). 

Response: Please see responses to EPA-HQ-OAR-2011-0512-0042, Excerpt 37, EPA-HQOAR-2011-0512-0042, Excerpt 38, EPA-HQ-OAR-2011-0512-0042, Excerpt 39, and EPA-HQ-
93

OAR-2011-0512-0042, Excerpt 40. 

Commenter Name: Gregory L. Ryan 

Commenter Affiliation: DTE Energy 

Document Control Number: EPA-HQ-OAR-2011-0512-0041 

Comment Excerpt Number: 3 

Commenter Type: Industry - oil and gas 

Comment: Calculating Natural Gas Venting Emissions from Blowdown Events 

DTE Energy appreciates that the EPA is seeking comments on why a compressibility allowance 

should be provided in the equations used for calculating natural gas emissions from blowdowns 

[Equations W-14(a) & (b)]. We support the utilization of a compressibility correction factor in 

the calculation of blowdown volumes using AGA Report No. 8 to compute gas compressibility. 

Utilizing compressibility factors in the blowdown volume equation is consistent with required 

reporting of blowdown volumes to the Michigan Department of Environmental Quality as well 

as for financial and system balancing (Lost and Unaccounted For gas) purposes . Computing 

blowdown volumes using Equations W-14(a) or (b) in the proposed rule would add additional 

burden by requiring calculation and reporting of blowdown emissions in two separate ways to 

two separate environmental agencies. 

A complete calculation of the quantity of gas to be blown down to atmosphere would include the 

internal volume of the chamber to be evacuated along with the pressure, temperature, and 

compressibility of the gas just prior to the blowdown event. The largest quantities of gas that are 

blown down are from long sections of pipelines that are taken out of service. Since pipelines are 

generally buried below the frost line in a given area, the coldest that the gas temperature would 

equilibrate to in the pipe is 32 degrees F. The impact that the temperature would have on the 

calculated blowdown quantity would be as large as 6% at 32 degrees F. Since most planned 

blowdown events occur during warmer seasons, the typical impact on the calculated quantity 

would likely be between 0% and 4%. Transmission system blowdowns could happen between 

300 psig and 1,000 psig which correlate to compressibilities between 4% and 15 %. 

EPA’s equations W-14(a) and (b) require LDC’s to monitor gas temperature in the blowdown 

equipment chamber, which is difficult to perform (See DTE Energy’s Best Available Monitoring 

Method request, dated July 28, 2011). However, the equations completely disregard the likely 

more substantial impact of compressibility. It is DTE Energy’s recommendation that EPA 

require compressibility to be included in the calculation of gas blowdowns. As an alternative, 

DTE Energy is recommending that each company be allowed the option to include 

compressibility in the blowdown volume calculation, and to identify if the company is reporting 

the numbers utilizing compressibility to eliminate the inconsistent reporting as described 

previously. 

Response: EPA has considered the refinement of the blowdown equations with a 

compressibility factor, either voluntary with a default factor of 1 (one) or mandatory based on 

public literature, and decided that this improvement in accuracy does not warrant the extra 
94

burden and creates a degree of uncertainty between reporters on how their reported blowdown 

values compare. Compressibility of pure light hydrocarbon substances is well known, but 

compressibility of mixtures is less well known and the composition of natural gas throughout the 

segments covered by Subpart W is highly variable. For the purposes of informing future policy, 

ideal gas law calculations are considered adequate. Hence, EPA is not requiring compressibility 

adjustment in this final rule. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042 

Commenter Excerpt Number: 37

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has clarified that emissions are to be calculated for blowdown vent 

stacks from depressurizing equipment to reduce system pressure for planned or emergency 

shutdowns or to take equipment out of service. EPA is proposing to delete “to atmosphere” 

because not every blowdown will result in the blowdown chamber being brought to atmospheric 

pressure. In addition, the preamble indicates that EPA is proposing to remove the exclusion of 

emergency events from blowdown vent stack emissions. 

Comment: The preamble (page 56020) indicates that EPA intends to only “cover the type of 

blowdowns typically tracked by operators for planned maintenance or emergency situations.” 

The preamble goes on to state that these amendments propose to overturn the exclusion of 

emergency events proposed in the August 4, 2011 amendments because EPA has since learned 

that operators track emergency shutdowns. 

API disagrees with this assessment. While it is true that emergency blowdowns at gas plants may 

be tracked, such releases are not tracked with the specificity required under 98.233(i). In 

addition, many of the emergency events are routed to a flare, in which case they would not be 

reportable under 98.233(i). Due to the unexpected occurrence of such events, it may not be 

possible to determine the actual volume of gas released. 

Response: EPA disagrees with the commenter. First, EPA requires only emergency blowdowns 

with human or manned intervention to be tracked. Please see response to EPA-HQ-OAR-2011-

0512-0029, Excerpt 14. Second, blowdowns of GHG emissions are to be reported under 

98.233(i) and not 98.233(n). See 40 CFR 98.233(n)(10) for further details. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042 

Comment Excerpt Number: 38 

Commenter Type: Industry - oil and gas 

Comment: [Please refer to the original comment text posted in the docket] Revision: The 
95

preamble (page 56020) indicates that EPA is providing reporters the option of tracking 

blowdowns by each occurrence for the same blowdown volume: “To enable facilities to retain 

their current tracking system, we are proposing to add an option for calculating emission by 

equipment type” (emphasis added). However, the regulatory language does not provide an 

option, but rather blends the two approaches. 98.233(i)(3) requires calculating the total emissions 

for each equipment type using either Equation W-14A or W-14B. While, the term “N” used in 

these equations is defined as the number of repetitive blowdowns for each unique volume in the 

calendar year. 

Comment: 

API suggests that EPA revise the definition of term “N” to present the option of using unique 

volume or equipment: “N= number of repetitive blowdowns for each unique [add (red): volume 

or equipment type] in calendar year.” 

EPA should similarly revise the text under 98.233(i)(3): “Calculate the total annual venting 

emissions for each [add (red): unique volume or] equipment type ...”. 

API also requests that EPA delete the words “and mass” under 98.233(i)(5). This correction is 

consistent with the calculation approach for blowdown vent stacks which result in volumetric 

emissions, not mass. 

Response: In this final rule EPA has clarified 98.233(i) by using unique physical volume only 

to avoid any confusion; please see response to EPA-HQ-OAR-2011-0512-0029, Excerpt 36 for 

further details. In this final rule, EPA has deleted the paragraph under 98.233(i)(5), and hence 

the issue of “and mass” is no longer relevant. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042 

Comment Excerpt Number: 39 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has added Equation W-14B, which appears to apply where 

equipment is only partially blown down. 

Comment: API suggests that a statement be added to 98.233(i)(3) to indicate when Equation W14B should be applied. In addition, the equation should include the same adjustment for purging 

the equipment as is used in Equation W-14A. The modified equation is provided below. 

[See original comment for equation] 

Response: EPA disagrees with the commenter. Equation W-14B can be used, as proposed and 

now finalized, regardless to which pressure the equipment is blown down. If the equipment is 

purged, an adjustment is provided in the definition of variable “Pa,e,p” where the final pressure is 
96

taken to be zero. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042 

Comment Excerpt Number: 40

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA revised 98.233(i)(5) to reference emissions determined under 

Equations W-14A and W-14B. 

Comment: 98.233(i)(5) requires calculating the total annual venting emissions for all blowdown 

vent stacks “by adding all standard volumetric and mass emissions determined using 

Equations W-14A and W-14B.” API requests the phrase “and mass” be deleted from this 

statement as neither Equations W-14A nor B result in mass emissions. Paragraph (5) should be 

placed before paragraph (4), which references 98.233(v) for the conversion of volumetric 

emissions to mass emissions. 

Response: Please see responses to EPA-HQ-OAR-2011-0512-0042, excerpt 38. 

Section 7.12.2 ­ Data Reporting Requirements

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 16 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Reporting 

requirements for blowdown vent stacks must be revised to be consistent with emission estimates 

calculated using Equation W-14A and Equation W-14B of §98.233(i). 

The reporting criteria in §98.236(c)(7) should be revised to reflect different requirements 

depending on whether Equation W-14A or W-14B is used. For example, a "unique volume" 

attribute may be considered a reportable data element when using Equation W-14A, but it is not 

applicable for Equation W-14B. 

Reporting of blowdown events could be based on one of three approaches: (1) use equation W14A for calculating all facility emissions if all blowdown events can be categorized by unique 

physical volume with invariant blowdown gas parameters, and events are always associated with 

a unique blowdown stack; (2) use equation W-14B to sum the emissions for all facility 

blowdown events; or (3) use Equation W-14A for calculating emissions from equipment that 

have a unique physical volume, invariant blowdown gas parameters, and are associated with a 

unique blowdown stack, and use equation W-14B to sum the emissions the remaining facility 

blowdown events (i.e., both equations are used during a year, depending on the type of event). 
97

For natural gas transmission and storage operations, it is anticipated that option (2) will be 

commonly used based on Equation W-14B. 

The Proposed Rule revision that requires reporting of a unique name or ID for each blowdown 

stack does not apply for emissions calculated using equation W-14B. During real-world 

operations, equipment gas releases are not always associated with a specific or unique stack. In 

addition, multiple equipment groupings could be vented through a single stack. Thus, unique 

blowdown vent stack reporting is not appropriate when using Equation W-14B. 

Reporting requirements need to be revised to address the different methods for estimating 

blowdown vent stack emissions. INGAA recommends the following revisions to §98.236(c)(7): 

“(7) For [delete: each] blowdown vent stack[add: s] [delete: (refer to Equation W‐14 of §98.233)], report

the following:  

(i) [delete: Total number of blowdowns per unique volume type in calendar year.] [add: For blowdown

vent stack emissions calculated using Equation W‐14A, report the following for each blowdown vent

stack:  

(A) Total number of blowdowns per unique volume type in calendar year.  

(B) Annual CO2 and CH4 emissions, expressed in metric tons CO2e for each gas, for each unique volume

type, at each blowdown stack. 

(C) A unique name or ID number for the blowdown vent stack.] 

(ii) [delete: Annual CO2 and CH4 emissions, expressed in metric tons CO2e for each gas, for 

each unique volume type, at each blowdown stack.] [add: For blowdown vent stack emissions 

calculated using Equation W-14B, report the following: 

(A) Total number of blowdowns in calendar year. 

(B) Total annual CO2 and CH4 emissions, expressed in metric tons CO2e for each gas.] 

[delete: (iii) A unique name or ID number for the blowdown vent stack.”] 

Response: EPA is clarifying that Equations W-14A and W-14B are equivalent, except that W14B allows for accounting of variations in emission volume from multiple occurrences of 

blowdown from the same unique physical volume. EPA disagrees with the commenter in item 

(1) above that W-14A is used when “events are always associated with a unique blowdown 

stack”. Furthermore, EPA is allowing Equation W-14A or W-14B to be used for either multiple 

blowdowns of the same unique physical volume or one-time blowdowns of unique physical 

volumes. 

Therefore, the summation in W-14B is over multiple occurrences of the same unique physical 

volume and not a summation over the entire facility (which was never stated in the September 

2011 proposal). Therefore, EPA disagrees with items (2) and (3) in the comment. The “unique 
98

physical volume” applies to a set of equipment, not different sets of equipment that may have the 

same calculated volume. In other words, if two or three compressors are virtually identical 

design and construction, and have the same unique physical volume between isolation valves 

within the accuracy of engineering estimation, and each is blown down multiple times per year, 

they are reported individually using either Equation W-14A if the actual volume of gas vented is 

approximately the same in starting and ending temperature and pressure, or Equation W-14B if 

the starting temperature and pressure change from blowdown to blowdown. 

EPA agrees with the comments to exclude assigning a unique name or ID number for blowdown 

vent stacks, given there may be multiple choices and different amounts blowndown through 

different vents. Instead, EPA is taking the emphasis in this reporting requirement off the stack 

and applying it to the unique physical volume. In addition, EPA agrees that there are many 

unique physical volumes that are blowndown only once a year and is allowing for reporting of 

emissions from them as an aggregate at the facility level. Therefore, the unique name or ID 

should be associated with the unique physical volumes that are blown down multiple times in a 

reporting year, not the blowdown stack or vent, and not one-time blowdown unique physical 

volumes. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 54 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] (7) For [delete: 

each] blowdown vent stack[add: s] (refer to Equation W–14[add: a or W-14b] of §98.233), report 

the following: 

(i) Total number of blowdowns per equipment type in calendar year [add: for Equation W-14a]. 

(ii) [add: Total number of blowdowns in calendar year for Equation W-14b.] [comment bubble 

JMc12: As noted in section 98.233(i), for facility blowdowns calculated using Eq W-14b, most 

or all events will include a unique volume, so tracking counts “per equipment type” is not 

appropriate] 

[add: (iii)] Report emissions collectively [delete: per equipment type]. 

Response: EPA agrees with the text in the opening paragraph allowing for either use of 

Equation W-14A or Equation W-14B and in this final rule is clarifying the text accordingly. 

EPA agrees that reporting by “equipment type” is irrelevant in the context of “unique physical 

volume”. However, EPA disagrees with the commenter that the total number of occurrences 

should be reported only in the case of Equation W-14B. In this final rule, the number of 

occurrences for each unique physical volume that is blown down more than once a year must be 

reported. 
99

For further details on reporting blowdown emissions, please see response to EPA-HQ-OAR2011-0512-0029, Excerpt 16. 

Section 7.13 ­ Onshore Production Storage Tanks

Commenter Name: William W. Grygar II 

Commenter Affiliation: Anadarko Petroleum Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0028

Comment Excerpt Number: 9 

Commenter Type: Industry - oil and gas 

Comment: Under §98.233(j)(1)(Vii)(B) and (C), the sub-basin category definition is referenced 

in regards to separator oil composition. Oil sub-basin categories are also required under 

§98.233(m). The current definition of sub-basin category does not have any reference to oil 

wells. Anadarko supports API's recommendations on how best to define oil well sub-basin 

categories. 

Response: EPA agrees with the commenter and in this final rule has added an oil formation to 

the sub-basin category definition. Please see preamble Section II.C – Final Amendments to the 

Petroleum and Natural Gas Systems Source Category – Major Changes Since Proposal and 

Section II.D.9 - Responses to Major Comments on the Petroleum and Natural Gas Systems 

Source Category: Addition of oil formation type in the sub-basin category definition for further 

details. 

Section 7.13.1 ­ Calculating GHG Emission [W­15, W­16]

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 20 

Commenter Type: Industry - oil and gas 

Comment: Onshore production tanks – § 98.233(j). EPA has proposed that reporters provide 

the annual total volumetric GHG emissions for storage tanks based on a representative sample 

for the sub-basin. Chesapeake and AXPC support this change, but EPA must also provide a 

definition for sub-basin as applied to oil wells. See Section A.8 supra. 

Notably, the proposed revision to the rule does not remedy the primary problem with § 98.233(j) 

– knowing how long a dump valve has been stuck open. Subpart W states that the number of 

hours a dump valve is stuck open may be established through "maintenance or operations 

records." 75 Fed. Reg. at 74,497 (Nov. 30, 2010). If a company has no records to establish how 
100

long a valve was open, it must assume it was open for the entire portion of the calendar year until 

the open valve was discovered and repaired. Id. However, doing so would grossly overstate the 

emissions from dump valves. 

Onshore production companies typically have thousands of dump valves per reporting facility or 

basin that would require frequent monitoring and recordkeeping. One AXPC company alone has 

determined that it has over 6,700 separators. Another company has reported that it has 

approximately 8,000 separators. Each separator has one or two dump valves. Even if a field 

technician were obligated to begin recording the position of every dump valve during each visit 

to a site, not every dump valve can feasibly be checked on a daily basis. Many field technicians 

are assigned to routes that cover 30 to 100 different sites. The frequency that a field technician 

visits each site varies according to the extent of his or her route. Some field technicians whose 

routes don't cover as much territory are able to visit each site every few days, while those with 

larger routes are only able to visit each site around every two weeks. Therefore, even relying on 

records from scheduled site visits would likely overestimate the duration that a valve was stuck 

open, as it may be several days or weeks between scheduled site visits. 

The assumption that dump valves stay stuck open for long periods of time disregards the reality 

that onshore production companies have an economic interest in minimizing losses of natural 

gas. As a result, most large companies closely monitor process data, typically on a daily basis 

from a remote location. If data shows conditions such as a sudden pressure drop, a low level in 

the separator, or an increase in the amount of fluid in the tank, a field technician will typically be 

sent to the site to investigate whether a dump valve was stuck open or if there is another 

operational problem. Such non-routine site visits are typically conducted within about 24-hours 

of the onset of irregular operational conditions. Furthermore, if companies detect that a certain 

valve model has a higher occurrence of sticking open, they will usually stop purchasing those 

types of valves in favor of those that malfunction less frequently. 

However, it is not industry practice to require field technicians to maintain checklists indicating 

whether every dump valve at every site was operating properly. Rather, as operational problems 

arise, corrections are made in the field as a matter of routine business practices. Therefore, the 

present text imposes a very large manual recordkeeping obligation for a problem that rarely 

occurs and for which a timely response is triggered by ongoing monitoring. 

One AXPC member has reviewed data for several of its fields and estimates that dump valves get 

stuck open approximately 1% of the time in a given year. Despite the infrequency of its dump 

valves getting stuck open, this operator would still need to develop a system to manage a 

massive number of forms documenting that dump valves are operating properly 99% of the time. 

A system would need to be developed to retain thousands of forms, which would be filled out at 

varying frequencies – every few days for wells that are visited regularly and up to every few 

weeks for others. All of these forms would need to be reviewed on a regular basis (at least 

weekly or monthly) by the appropriate personnel to: 

· assess whether any valves had been stuck open, 

· if so, review operational records/maintenance records/production data preceding the discovery 

of the stuck valve, 
101

· calculate the emissions associated with the stuck valve, and document the emissions in a format 

that will facilitate annual reporting. 

AXPC and Chesapeake object to this requirement because it imposes an unreasonable burden on 

reporters for no environmental benefit and because assuming a valve was stuck open for an 

extended period of time would create large inaccuracies in emission reporting. Furthermore, 

reporters were not provided with an opportunity to comment on this reporting obligation during 

the notice and comment period. EPA alleges that onshore production was provided notice of the 

dump valve monitoring requirement by the inclusion of a statement regarding tank emissions not 

being "represented by the equilibrium conditions of the liquid in a gas-liquid separator and 

calculated by E&P Tank. . . ." 75 Fed. Reg. at 18,640 (Apr. 12, 2010). This alleged notice did not 

refer to "dump valves" and was interpreted as referring to problems other than a stuck dump 

valve, such as a separator that is too small. For these reasons, we believe the requirement should 

be removed from the rule. 

Response: EPA agrees with the comment regarding an oil sub-basin and has revised the 

definition for sub-basin in 40 CFR 98.238 to include an oil formation within the sub-basin 

category; please see the preamble Section II.C. -– Final Amendments to the Petroleum and 

Natural Gas Systems Source Category – Major Changes Since Proposal and Section II.D.9 - 

Responses to Major Comments on the Petroleum and Natural Gas Systems Source Category: 

Addition of oil formation type in the sub-basin category definition for further details. 

EPA disagrees with the commenter on the accounting of emissions from leaky dump valves. 

EPA has provided the simplest monitoring method to account for these emissions. The 

commenter states that “As a result, most large companies closely monitor process data, typically 

on a daily basis from a remote location.” Hence, EPA believes that this monitoring can be used 

to maintain a simple log of disruptions in dump valve functioning. Finally, the information that 

AXPC member collected is what EPA expects to account for malfunctioning dump valves. 

Therefore, EPA has retained the requirement to account for malfunctioning dump valves. 

Commenter Name: Jessica Stark 

Commenter Affiliation: SLR International Corp 

Document Control Number: EPA-HQ-OAR-2011-0512-0040

Comment Excerpt Number: 4 

Commenter Type: Industry - oil and gas 

Comment: 98.233(j) Onshore Production Storage Tanks 

I would like to request that Calculation Methodology 2 be modified to allow a representative 

sample of separator oil composition at separator temperature and pressure to be used to estimate 

dissolved gas concentrations for all wells in the same field (or sub-basin category if that is 

retained). The only alternative calculation method for oil or condensate flowing through a 

separator on the same well-pad as the producing well (with a throughput greater than 10 barrels 

per day) is Calculation Methodology 1, requiring modeling of each tank. One of my clients owns 

thousands of tanks located on well pads and would prefer the flexibility to calculate dissolved 
102

gas emissions. The modeling exercise is too onerous. Requiring an oil sample from each on-pad 

separator with a throughput greater than 10 barrels per day is going to be very expensive and is 

not consistent with the other calculation methods in Subpart W allowing use of representative 

sample data under reasonably similar conditions. My client does not currently have any separator 

oil sample results. Separator sample results are not going to vary greatly within the same 

reservoir. 

Response: EPA has considered this comment and concludes it is out of scope with the 

Technical Revisions to the Petroleum and Natural Gas Systems Category of the GHG Reporting 

Rule. The only proposed change made to Methodology 2 under 98.233(j) was the replacement 

of the term “field” with “sub-basin,” and therefore the commenter’s suggested alteration is out of 

scope. 

Section 7.13.2 ­ Data Reporting Requirements

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 59 

Commenter Type: Industry - oil and gas 

Comment: Revision: 98.236(c)(8)(i)(J) requires reporting emissions for each wellhead gasliquid separator or storage tank. 

Comment: Previously, the rule required separate reporting for Methodologies 1 and 2, which did 

not imply separate reporting for each separator or tank. A basin can have well over 1000 

separators. This is a significant expansion of the regulatory requirements introduced through 

these rule amendments as discussed in Section 1, Comment A [EPA-HQ-OAR-2011-0512-0042, 

Excerpt 2], above. 

Response: In this final rule, EPA has amended the requirement to report emissions at a subbasin level; please see the response to EPA-HQ-OAR-2011-0512-0042, Excerpt 2 for further 

details. 

Section7.14 ­ Transmission Storage Tanks

Section 7.14.1 ­ Calculating GHG Emission

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 5 
103

Commenter Type: Trade Association 

Comment: §98.233(k) appropriately refers to §98.233(u)(2)(iii). 

Response: EPA thanks the commenter for their remarks. 

Commenter Name: Curtis J. Winner 

Commenter Affiliation: New Mexico Gas Company (NMGC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0047

Comment Excerpt Number: 5 

Commenter Type: Industry - oil and gas 

Comment: Transmission Storage Tanks 

NMGC supports EPA’s proposed revision of 98.233(k) to include the option of directly 

measuring the transmission storage tanks. This allows NMGC to measure emissions from storage 

tanks at compressor stations using equipment NMGC currently owns without purchasing 

additional equipment. This option is more cost effective for NMGC and obtains the same data as 

the current rule. 

Response: EPA thanks the commenter for their remarks and is finalizing the requirements in 

this final rule. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 17 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Transmission tanks: 

10. INGAA supports Proposed Rule revisions in §98.233(k)(1) that add flexibility for 

transmission tank vent measurement. However, the proposed text requires minor revisions to 

improve clarity and consistency with the measurement methods. 

INGAA supports options added to §98.233(k)(1) for detecting and measuring leaks. The 

revisions are based on INGAA recommendations, and the following revision is from the EPA 

redline version of the rule: 

“(1) Monitor the tank vapor vent stack annually for emissions using an optical gas imaging 

instrument according to methods set forth in §98.234(a)(1) [ add: or by directly measuring the 

tank vent using a flow meter, calibrated bag, or high volume sampler according to methods in 

§98.234(b) through (d) for a duration of 5 minutes.] [delete: for a duration of 5 minutes.] Or you 
104

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)." 

This text and associated text in (k)(2) requires a minor revision because a five minute sampling 

duration may not be appropriate for all methods. For example, a calibrated bag, which is a 

reasonable method, may fill in less than five minutes, so the specified duration is not appropriate. 

The five minute duration was originally included for optical imaging to ensure a sample time that 

captures a leaky dump valve rather than a release associated with a dump cycle, and five minutes 

is essentially an arbitrary choice. The other measurement approaches added to (k)(1) can identify 

the appropriate source (i.e., a leaky dump valve), but may accomplish this in a shorter time 

period. The text in (k)(1) that refers to "a 5 minute duration" should be revised to indicate, "a 

duration of 5 minutes or a duration adequate to demonstrate continuous leakage rather than a 

dump cycle release." In addition, related text in (k)(2)(i) appropriately refers to "continuous 

leakage" and the text, "...for five minutes..." is not necessary and should be deleted. 

Response: EPA thanks the commenter for their remarks on flow meter, calibrated bag, and high 

volume sampler options. EPA agrees that the five minute measurement duration should not 

apply to measurements carried out by calibrated bags. Therefore, in this action EPA has 

modified the associated rule provisions accordingly. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 37 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Transmission 

storage tanks. 

[highlighted text: Correct reference to flaring in intro, add monitoring method flexibility, and 

delete reference to flaring calculation (broadly addressed in §98.232(j) and not needed in this 

section)] 

For condensate storage tanks, either water or hydrocarbon, [delete: without vapor recovery or 

thermal control devices] in onshore natural gas transmission compression facilities calculate 

CH4[delete: ,] [add: and] CO2 [delete: and N2O (when flared)] annual emissions from 

compressor scrubber dump valve leakage as follows: 

(1) Monitor the tank vapor vent stack annually for emissions using an optical gas imaging 

instrument according to methods [delete: set forth] in §98.234(a)(1) [add: or by directly 

measuring the tank vent using a flow meter, calibrated bag, or high volume sampler according to 

methods in §98.234(b) through (d)] for a duration of 5 minutes. Or you may annually monitor 

leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak 

detection device according to methods [delete: set forth] in §98.234(a)(5). 
105

(2) If the tank vapors are continuous for 5 minutes, or the acoustic leak detection device detects a 

leak, then use one of the following two methods in paragraph (k)(2) of this section to [add: 

estimate] [delete: quantify] emissions: 

(i) Use a meter, such as a turbine meter, [add: calibrated bag, or high flow sampler] to estimate 

tank vapor volumes according to methods [delete: set forth] in §98.234(b) [add: 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. [add: If the vent is directly measured for five minutes under section 

(1) to detect continuous leakage, this serves as the measurement. If a leak of 3.1 SCF per hour or 

greater is measured, a leak is detected and must be reported.] 

(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). 

(3) [delete: (iii)] [add: Calculate both CH4 and CO2 volumetric and mass emissions using 

calculations in (u) and (v) of this section, and using] [delete: Use] the appropriate gas 

composition in paragraph (u)(2)(iii) of this section [add: or the gas composition allowed in 

§98.232(m).] 

(4) [delete: (3)] If the leaking dump valve(s) is repaired following leak detection, the annual 

emissions shall be calculated from the beginning of the calendar year to the time the valve(s) is 

repaired. 

[delete: (4) Calculate emissions from storage tanks to flares as follows: 

(i) Use the storage tank emissions volume and gas composition as determined in either paragraph 

(j)(1)of this section or with an acoustic leak detection device in paragraphs (k)(1) through (k)(3) 

of this section. 

(ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine 

storage tank emissions from the flare.] 

Response: EPA disagrees with the deletion of reference to 98.233(n) when emissions are sent to 

a flare. The reporter must either meter or use an acoustic device to estimate emissions that are 

going to a flare and report the emissions under 98.233(k). 

EPA agrees with the commenter on the deletion of “thermal control devices” in the opening 

paragraph to 98.233(k) and has amended this final rule accordingly. EPA has reviewed the 

comment about the deletion of “without vapor recovery units” and disagrees with the deletion of 

this term. EPA’s intent is to cover transmission storage tanks without vapor recovery, as is 

stated in 98.233(k). EPA disagrees with the deletion of N2O emissions. When emissions are sent 

to a flare, EPA requires reporters to use 98.233(n) to determine CH4, CO2 and N2O emissions. 

EPA thanks the commenter for their remarks on flow meter, calibrated bag, and high volume 

sampler options. For additional changes to measurement options, please see response to EPAHQ-OAR-2011-0512-0029, Excerpt 17. 
106

EPA disagrees with the commenter on the change suggested to 98.233(k)(2). Reporters are 

required to physically quantify leaks using methods in 98.233(k)(2), not estimate them. 

Reporters are required to measure and quantify leaks, if detected, using 98.233 (k)(2). 98.233 

(k)(2) refers the reporter to 98.233 (k)(1) and appropriate sections in 98.234 to explain how they 

should estimate the emissions. Therefore it is not appropriate to use the term “estimate” in the 

rule language for 98.233 (k)(2). 

EPA agrees with the commenter on allowing the 5 minute measurement in 98.233(k)(1) to be the 

necessary measurement in 98.233(k)(2)(i). However, EPA disagrees with the 3.1 scf per hour 

limit other than for acoustic leak detection devices; any leak measured must be reported. 

EPA agrees with the commenter on adding references to (u) and (v) to 98.233(k)(2). EPA 

disagrees with the reference to 98.232(m); please see response EPA-HQ-OAR-2011-0512-0029, 

Excerpt 3 for further details. 

EPA agrees that multiple transmission storage tanks may be connected to the same vent; 

therefore the tank may not be the monitored source. In this final rule, EPA is requiring the 

venting emissions from transmission storage tanks be monitored and reported per vent stack. 

Section 7.14.2 ­ Data Reporting Requirements

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 18 

Commenter Type: Trade Association 

Comment: Reporting a unique name or ID for each transmission tank does not provide relevant 

information. EPA should eliminate the revision that adds this reporting requirement. 

As noted in Comment 13, INGAA supports method and monitoring flexibility in the Proposed 

Rule. INGAA does not support a new reporting requirement proposed for transmission tanks. 

§98.236(c)(9)(iii) adds a requirement to report "a unique name or ID for the transmission storage 

tank." INGAA does not agree with this revision because it does not provide meaningful 

information. The tank is not the emission source or the monitored source. For example, multiple 

tanks are often tied into a single vent, and the vent, not the tank, will be monitored. In addition, 

providing a unique name or ID for the transmission storage tank may cause confusion with the 

tank ID under an existing SPCC plan. EPA should eliminate this requirement from the Final 

Rule. 

Response: EPA agrees that there may be cases where multiple transmission storage tanks may 

be connected to the same vent. In this final action, EPA has amended the provisions in 40 CFR 

98.233(k) and 98.236(c)(9) accordingly. Also finalized in this action is the requirement for 

reporters to assign a unique name or ID to for the vent stack that is being monitored according to 
107

40 CFR 98.233(k). Please see preamble Section II.D.3 - Responses to Major Comments on the 

Petroleum and Natural Gas Systems Source Category: Unique name or ID reporting 

requirements for further details. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 55 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] For transmission 

tank [delete: emissions identified using optical gas imaging instrument per §98.234(a) (refer to 

§98.233(k)), or acoustic leak detectionof] scrubber dump valves, report the following for each 

tank: 

(i) Report emissions individually [add: for each tank]. 

(ii) [Reserved] 

Response: EPA does not agree with the commenter. EPA agrees that additional clarification is 

needed when asking operators to “report emissions individually”, however, EPA is amending the 

requirement 40 CFR 98.234(c)(9)(i) and 40 CFR 98.234(c)(9)(iii) to have emissions reported per 

vent stack, please see EPA-HQ-OAR-2011-0512-0029, Excerpt 37 and preamble Section II.D.3 - 

Responses to Major Comments on the Petroleum and Natural Gas Systems Source Category: 

Unique name or ID reporting requirements for further details. EPA disagrees with modifying 

paragraph 98.236(c)(9) since commenter’s suggestion of removing text adds no additional clarity 

to the data reporting requirements. 

Section 7.15 ­ Well Testing Venting and Flaring

Section 7.15.1 ­ Calculating GHG Emission [W­17]

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 12 

Commenter Type: Industry - oil and gas 

Comment: EPA has requested comments regarding how to reduce the burden where companies 

verify that zero emissions are associated with this well testing venting and flaring, such as when 

a closed loop system is employed. Where a reporter deems that there are zero emissions to report 

under well testing venting and flaring, EPA should require no additional reporting under § 
108

98.233(l) aside from indicating the source has zero emissions from well testing venting and 

flaring. 

Response: EPA would like to clarify that the data reporting section (98.236) applies to emission 

sources that need to be monitored as per requirements in 98.233. If a well is tested using a closed 

loop system that does not result in either venting or flaring, then the reporter would report zero 

emissions. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 7 

Commenter Type: Industry - oil and gas 

Comment: Well testing venting and flaring 

On page 56031 of the September 9, 2011 preamble, EPA is addressing well testing and venting 

and flaring. Among other things, EPA is considering, but has not yet proposed, using the 

production rate to estimate the volume of emissions from venting and testing gas wells that 

produce dry gas. EPA is soliciting comments on this suggested provision for gas wells. 

API Response: 

API agrees that production rate could be used as an estimate of gas flow rate. 

Response: EPA agrees with the commenter and in this final rule has added a new equation (W17B) to provide for testing on dry gas producing wells. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 8 

Commenter Type: Industry - oil and gas 

Comment: Emissions associated with well testing 

On page 56031 of the September 9, 2011 preamble EPA states, “EPA has determined that during 

well testing, some states allow companies to flare sour gas for a maximum of 72 or 144 hours. 

EPA has concluded that this approach would result in emissions from this source that should be 

reported under this rule. If, however, for some reason reporters do not have any emissions from 

this source (e.g., states do not allow venting or flaring from well testing), they would report zero 

emissions. Thus, EPA is retaining well testing venting and flaring in the rule. 
109

EPA is seeking comment on how to reduce or eliminate burden in cases where companies verify 

that zero emissions are associated with this potential source, such as when a closed loop system 

is employed. 

API Response: 

Many of the source types specified for reporting under Subpart W may have zero emissions for 

reporting facilities, including no venting during well testing. These zero emissions should be 

reported consistently with zero emissions from other affected sources. 

Response: Please see response to EPA-HQ-OAR-2011-0512-0033, Excerpt 12 for requirements 

on data reporting. 

Section 7.15.2 ­ Data Reporting Requirements

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 60 

Commenter Type: Industry - oil and gas 

Comment: Revision: For well testing venting and flaring, EPA has added the requirements to 

report CO2 and CH4 emissions at the facility level, and CO2, CH4 and N2O emissions at the 

facility level from flaring. 

Comment: API supports this reporting at the facility level. 

Response: EPA thanks the commenter for their remarks. 

Section 7.16 ­ Associated Gas Venting  and Flaring

Section 7.16.1 ­ Calculating GHG Emission [W­18]

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 42 

Commenter Type: Industry - oil and gas 

Comment: [Please refer to the original comment text posted in the docket] Revision: For 

associated gas venting and flaring, EPA has replaced field with sub-basin category for 

determining the separator oil composition and Reid vapor pressure. 
110

Comment: API supports the revision for sub-basin. However, sub-basin here should apply to oil 

wells based on the “oil formation” sub-basin category proposed by API above. In addition, API 

interprets “associated gas” to mean natural gas produced with crude oil that is not recovered for 

sales due to the lack of infrastructure. This is consistent with a response EPA posted to the list of 

Frequently Asked Questions on Subpart W, which indicated “Section 98.233(m) only covers 

natural gas that is not recovered from the production operation.” 

With the introduction of the sub-basin concept, it is now unclear what the geographic boundaries 

are for the volume term used in Equation W-18. The objective of the sub-basin approach is to 

reduce sampling burden. API requests that EPA clarify that the volume used in Equation W-18, 

and the resulting emissions from Equation W-18, represent the oil formation at the entire basin 

level. Paragraph (1) should be modified to state “If GOR from each well is not available, the 

GOR from a cluster of wells in the [add (red): basin] shall be used.” With these changes, the 

terms in Equation W-18 will be consistent with the reporting requirements under 

98.236(c)(11)(iii) and (iv). 

Response: EPA agrees that an oil well sub-basin category is needed and in this final rule, has 

made included the oil-formation type in the sub-basin category definition. Please see preamble 

Section II.C. – Final Amendments to the Petroleum and Natural Gas Systems Source Category – 

Major Changes Since Proposal and Section II.D.9 - Responses to Major Comments on the 

Petroleum and Natural Gas Systems Source Category: Addition of oil formation type in the subbasin category definition for further details. 

EPA agrees with the FAQ response as it relates to “associated gas venting and flaring”. 

EPA agrees conditionally that equation W-18 and the associated parameters need clarification. 

EPA agrees that the data reporting requirements ask for emissions summed on a facility level, 

and EPA has modified the equation accordingly. However, EPA disagrees that both GOR and 

volume should be used on a facility level to calculate emissions. GOR can vary widely within a 

basin, and therefore individual well GOR should be used. If this data isn’t available, paragraph 

98.233(m)(1) provides an alternative method to determine GOR. This method allows the 

reporter to use the average GOR from a cluster of wells in the same sub-basin as a surrogate data 

for wells for which the GOR is unknown. 

Section 7.16.2 ­ Data Reporting Requirements

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 61 

Commenter Type: Industry - oil and gas 

Comment: Revision: For associated gas venting, EPA has added the requirements to report 

CO2 and CH4 emissions at the facility level, and CO2, CH4 and N2O emissions at the facility 

level from flaring. 
111

Comment: API supports this reporting at the facility level. 

Response: EPA thanks the commenter for their remarks. 

Section 7.17 ­ Flare Stack Emissions

Section 7.17.1 ­ Calculating GHG Emission [W­19 to W­21]

Commenter Name: 

Commenter Affiliation: Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2011-0512-0026

Comment Excerpt Number: 4 

Commenter Type: Industry - other 

Comment: EPA should clarify whether or not emissions from flares should be reported for 

sources in the underground storage of natural gas category. 

Section 98.232(f) requires that the owner/operator calculate CO2, CH4, and N2O emissions from 

the following sources: 

1. Reciprocating compressor rod packing; 

2. Centrifugal compressor venting;. 

3. Natural gas pneumatic device venting; and 

4. Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters. 

Thus, section 98.232(f) does not require reporting emissions from flares. However, the 

introductory sentence to 98.232(f) does require reporting of N2O emissions. Furthermore, Page 

56028 of the Federal Register preamble contains a statement which says: “we are proposing to 

revise the introductory sentences to 40 CFR 98.232(e), (f), (g), (h), and (i) to clarify that N20 

emissions, which are the primary GHG emissions from flaring, are also required to be reported 

under these industry segments. Thus, the preamble and the introductory sentence suggest that 

emissions from an associated flare must be included in the calculations for underground natural 

gas storage. 

Thus, it is unclear whether or not the flare emissions must be calculated for this source category, 

and if so, should the provisions contained in 98.233(n) for flares be followed? 

Response: In this action, EPA has clarified that any emission source types for which there are 

methods in 98.233 where emissions are being sent to a flare, reporters must use provisions in 

98.233(n) to estimate flare emissions and report the emissions under the same emission source, 

and not under flare category. For example, the centrifugal compressor emission source type 
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listed for Underground Storage of Natural Gas has a reference to paragraph 98.233(n) for 

emissions routed to a flare. The emissions from the centrifugal compressor venting routed to a 

flare must be calculated as outlined in 98.233(n), however, the emissions must be attributed to 

the source type where the gas originated (i.e. centrifugal compressor venting). EPA requires 

monitoring of emissions from the four sources listed under 98.232(f), but any emissions from 

those sources sent to a flare must be calculated as outlined in 98.233(n). 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 38 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] [highlighted text: 

§98.233(n) PROVIDED HERE FOR REFERENCE ONLY – NO CHANGES... “Efficiency” 

calcs in Equations W-19 and W-20 are shown here because these are referenced in proposed new 

section §98.232(j)(1) [see above] for calculating “reduction efficiency” from §98.233 sources.] 

(n) Flare stack emissions. Calculate CO2, CH4, and N2O emissions from a flare stack as follows: 

(4) Calculate GHG volumetric emissions at actual conditions using Equations W–19, W–20, and 

W–21 of this section. 

[See original comment for Eq. W-19, W-20, and W-21] 

Where: 

Ea,CH4(un-combusted) = Contribution of annual un-combusted CH4 emissions from flare stack 

in cubic feet, under actual conditions. 

Ea,CO2(un-combusted) = Contribution of annual un-combusted CO2 emissions from flare stack 

in cubic feet, under actual conditions. 

Ea,CO2(combusted) = Contribution of annual combusted CO2 emissions from flare stack in 

cubic feet, under actual conditions. 

Va= Volume of gas sent to flare in cubic feet, during the year. 

η = Fraction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, η

is zero. 

XCH4= Mole fraction of CH4 in gas to the flare. 

XCO2= Mole fraction of CO2 in gas to the flare. 
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Yj= Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, 

and pentanes-plus). 

Rj= Number of carbon atoms in the gas hydrocarbon constituent j: 1 for methane, 2 for ethane, 3 

for propane, 4 for butane, and 5 for pentanes-plus). 

Response: EPA thanks the commenter for their remarks. 

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 21 

Commenter Type: Industry - oil and gas 

Comment: Flare stack emissions – § 98.233(n). EPA has proposed a new equation to calculate 

combusted emissions, clarified that if a facility has CEMS the Tier 4 calculation methodology 

must be used, and verified that flare emissions reported in this part must be corrected for flare 

emissions calculated and reported under other paragraphs to avoid double counting. We support 

and incorporate by reference API’s comments W.27 [EPA-HQ-OAR-2011-0512-0042, Excerpt 

43] and W.28 [EPA-HQ-OAR-2011-0512-0042, Excerpt 44] in Section 2 of its October 24, 2011 

letter to EPA. 

Response: Please see responses to EPA-HQ-OAR-2011-0512-0042, Excerpt 43 and EPA-HQOAR-2011-0512-0042, Excerpt 44. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 43 

Commenter Type: Industry - oil and gas 

Comment: Revision: For flare stack emissions, EPA added a provision for natural gas 

processing plants that solely fractionate a liquid stream. In this situation, the GHG mole percent 

in feed natural gas liquids is applied for all streams. 

Comment: API’s understanding of the phrase “fractionating a liquids stream” means that the 

input to the plant is solely NGL. 

Response: EPA agrees that fractionating a liquids stream means that the input to the plant is 

solely a hydrocarbon liquid stream. 
114

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 44 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added clarification that for source types in 98.233 that use Equations 

W-19 through W-21 for flare emissions, an estimate of emissions under actual conditions are to 

be used for the parameter Va. The preamble (page 56032) states that “this is consistent with 

other proposed changes throughout this revision that clarify the use of actual versus standard 

conditions. 

Comment: Industry’s common practice is to track all gas flow rates in standard cubic feet at 60 

oF and 14.7 psia. The parameters Va and Ea in Equations W-19 through W-21 should be defined 

in terms of standard cubic feet and use the subscript “s” to indicated standard conditions. 

Response: EPA disagrees with the commenter. EPA’s understanding from this comment is that 

flow rate readout from the meter is for standard conditions of 60oF and 14.7 psia. As long as this 

flow rate readout has been appropriately converted to standard conditions, then this flow rate 

may be used in Equations W-19, W-20, and W-21. Currently paragraph 98.233(n)(5) refers 

reporters to paragraph 98.233(t) to convert emissions at actual conditions to standard conditions. 

Assuming the flow rate reading from the meter is at standard conditions of 60oF and 14.7 psia, 

then in that case when the emissions calculated by Equations W-19, W-20, or W-21 are 

converted to standard conditions by using paragraph 98.233(t) (either equation W-33 or W-34), 

then the actual condition emissions would essentially be multiplied by 1 (since the reporting 

conditions are standard conditions), and the standard condition emissions would be the same as 

the actual condition emissions. However, not all meters may measure at STP or at the same STP 

as required in the rule. Hence the change suggested by the commenter is unnecessary. Therefore, 

EPA is retaining the definition of Va and Ea in equations W-19, W-20, and W-21 and the 

reference to paragraph 98.233(t). 

Section 7.18 ­ Leak Detection and Leaker Emission Factors

Section 7.18.1 ­ Calculating GHG Emission [W­30]

Commenter Name: 

Commenter Affiliation: Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2011-0512-0026

Comment Excerpt Number: 3 

Commenter Type: Industry - other 

Comment: EPA should provide an option for the owner/operator to take credit in the equipment 

leak calculations if the owner/operator fixes a leaking component before the end of the year. 

Equation W-30 requires the input of the total time (T) that a component was found leaking and 
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operational. If one leak detection survey is conducted, the owner/operator must assume the 

component was leaking for the entire calendar year. Dow’s practice is generally to repair leaking 

components. Thus, Dow suggests that the owner/operator be provided an option to determine the 

number of hours that a component is leaking by taking the hours between January 1st and the 

time that a leaking component has been repaired. Such a change to the rule will allow for 

increased accuracy in the GHG emissions reporting, and will allow the owner/operator the ability 

to use the population emission factors for the period of time that a component is not leaking. 

Response: In the November 2010 rule EPA did provide an option for reporters to conduct more 

than the one mandatory leak detection survey and account for leaks that are fixed. Hence, EPA 

disagrees with the commenter that there is no option in the rule to account for leaking 

components that have been repaired. To verify that leaking components have been repaired and 

are no longer leaking, a second, subsequent leak detection survey must be performed on the 

entire facility. For further details, please see response to EPA-HQ-OAR-2009-0923-1014, 

Excerpt 9 for further details, which we have below: 

Comment Number: EPA-HQ-OAR-2009-0923-1014-9 

Organization: Independent Oil and Gas Association of West Virginia Commenter: Charlie 

Burd 

Comment Excerpt Text: 

Fugitive Emissions Sources 

Finally, Subpart W requires all covered facilities to perform comprehensive emissions surveys of 

their entire population of fugitive emissions on an annual basis. Should a leak be detected during 

this survey, the current calculation methodologies specified in the proposal require operators to 

assume that these fugitive emissions occur for the entire 365 days in the year. 75 Fed. Reg. at 

18623. Those facilities required to estimate fugitive emissions based on population count (e.g., 

onshore production facilities) generally must make similar assumptions (i.e., that the emissions 

occurred for the total time that the specific source associated with the fugitive emissions was 

operating). See 40 C.F.R. § 98.233(r), 75 Fed. Reg. at 18643. Because this is not the case with 

regard to most fugitive emissions at most operations, these assumptions will result in a 

significant overestimation of actual emissions that will artificially inflate the inventory. Indeed, 

as USEPA acknowledges in the Preamble for Subpart W, "the petroleum and natural gas industry 

is already implementing voluntary fugitive emissions and repair programs" for detected fugitive 

emissions that will result in correction of leaks. Id. at 18623. Nevertheless, IOGA-WV shares 

USEPA's view that requiring more frequent emissions surveys would be both unduly 

burdensome and impractical in light of the marginal levels of emissions that would be captured 

in the inventory in light of the leak reductions and repairs that are undertaken pursuant to these 

programs. If anything, IOGA-WV believes that the burdens associated with undertaking a 

comprehensive annual emissions survey of these sources outweigh the benefits of including these 

comparatively de minimis emissions in the inventory. 

Response: EPA disagrees that equipment leaks are a small portion of emissions from the 

petroleum and natural gas industry. Equipment leaks are a substantial percentage of emissions 

from upstream production; EPA conducted detailed analysis in order to determine sources to 

report in each segment of the industry. EPA does not agree that the burden associated with leak 

detection is not justified by the benefits. Please see Section III.E of the preamble to this final rule 

for a description of the benefits of the rule. EPA recognizes the commenter’s concern that 
116

assuming a leak duration of 365 days may overestimate emissions. Conversely, there will be 

leaks that start after a leak survey is conducted and therefore an underestimation may occur as 

well. Regardless, in this final rule, EPA allows reporters the option to perform subsequent 

facility-wide leak detection surveys and to adjust their emissions to account for components that 

are subsequently found to be leaking or not leaking, respectively. EPA emphasizes that 

adjustment of emissions is not allowed based on repair records alone. Reporters must assume 

that a leaking component has been leaking starting from the beginning of the calendar year. In 

addition, if only one leak detection survey is conducted during the calendar year, the reporter 

must assume that the duration of the leak is 365 days unless the leak is fixed and a subsequent 

official leak detection survey is conducted for an entire facility proving that the leak and others 

were repaired. A goal with leak detection is to get a facility wide snapshot of equipment leak 

emissions. If a reporter finds certain components leaking during a specific survey they are 

usually not addressed immediately. During the time leaks are being addressed, other leaks will 

appear which only subsequent facility wide leak detection surveys will ascertain. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 40 

Commenter Type: Trade Association 

Comment: [highlighted text: In (q) and (r), add references to gas composition; minor 

clarifications and corrections to (t) though (v)] 

(q) Leak detection and leaker emission factors. 

GHGi = For onshore natural gas processing facilities, concentration of GHGi, CH4 or CO2, in 

the total hydrocarbon of the feed natural gas; for other facilities listed in § 98.230(a)(4) through 

(a)(8), GHGi equals 1 for CH4 and 1.1 × 10-2 for CO2[add: , or use the gas composition allowed 

in §98.232(m)]. 

Response: [Please refer to the original comment text posted in the docket.] EPA disagrees with 

the commenter. The emission factors in Table W-7 are in methane only and the reporter cannot 

use a 1% CO2 composition on this emission factor as suggested by the commenter. Please see 

response to EPA-HQ-OAR-2011-0512-0029, Excerpt 3 and EPA-HQ-OAR-2011-0512-0029, 

Excerpt 43 for further details. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 7 

Commenter Type: Trade Association 
117

Comment: §98.233(q) includes different default values in the definition of GHGi that follows 

Equation W-30. Section (u)(2) should be referenced rather than introducing different defaults. 

Response: EPA disagrees that a reference to 98.233(u)(2) should be provided instead of the 

default compositions listed in the definition for GHGi. Paragraph 98.233(u)(2) is for determining 

greenhouse gas compositions in whole gas streams. The emissions factors used in paragraph 

98.233(q) are not whole gas emission factors, and are instead total hydrocarbon (THC) emission 

factors or methane emission factors. Hence, EPA is retaining the requirements in 98.233(q) as 

relates to composition in this final rule. Please see response to EPA-HQ-OAR-2011-0512-0029, 

Excerpt 3 for further details. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 11 

Commenter Type: Trade Association 

Comment: AGA Supports Proposed Revisions to Equations W-30 and W-31, and W-32, but 

Seeks Additional Corrections 

Equation W-30: As AGA and others have requested, EPA has proposed to clarify the summation 

operator in Equation W-30 to make it mathematically correct, and we appreciate this correction. 

76 Fed. Reg. at 56,032. The agency has also proposed several revisions to use the new terms 

“transmission-distribution transfer stations” and “metering-regulating stations.” AGA supports 

these revisions. However, Equation W-30 is still confusing and requires additional revisions. 

First, there appears to be a conflicting provisions in the definition of Tp in W-30. 

The last two sentences are confusing. We suggest revising the text to say: 

“If multiple leak detection surveys are conducted at a facility or TD station, assume that the 

component found to be leaking has been leaking since the previous survey (if not found in the 

previous survey) or the beginning of the entire calendar year (if it was found in the previous 

survey). 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.” 

Second, a typographical error appears in the proposed revision to Equation W-30, where the 

subscript “s” was omitted from EF. The definition for EF was not amended in the proposed rule, 

so the definition for EF is found in the November 2010 final rule version of Equation W-30 – 

where the term is listed as EFs. This should be corrected to avoid confusion. 

Third, Equation W-30 is also confusing because the definition of Es,i in Equation W-30 is 

different from the definition for Es,i in W-32 even though they represent the same thing. To 

make it less confusing, the definition of Es,i in Equation W-30 should be changed to match the 
118

definition in Equation W-32 which says “Annual volumetric GHG i emissions, CO2 or CH4 at 

standard conditions from all equipment leak sources at all above grade T-D transfer stations”. 

Response: In regard to the definition of parameter “Tp” in Equation W-30, EPA agrees with the 

commenter and in this final rule, has made necessary clarifications to the text. In regard to the 

subscript “s” in parameter “EF”, EPA agrees with the commenter and in this final rule, has 

removed the subscript throughout the Equations W-30A and W-30B. In regard to parameter 

“Es,i”, EPA disagrees with the commenter. The parameter “Es,i” in Equation W-30 does not 

represent the same definition as parameter “Es,i” in Equation W-32. Please see response to EPAHQ-OAR-2011-0512-0047, Excerpt 9 for further details. 

Commenter Name: Curtis J. Winner 

Commenter Affiliation: New Mexico Gas Company (NMGC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0047

Comment Excerpt Number: 6 

Commenter Type: Industry - oil and gas 

Comment: Leak Detection and Leaker Emission Factors 

Although EPA has proposed revisions to Equation W-30 in 98.233.q, NMGC still feels it is 

difficult to determine what is being calculated in W-30. Is equation W-30, the sum of emissions 

from each component type (ie Es,i is emissions from just connectors) from all stations? Or is it 

the sum of emissions from all components (ie the sum of emissions from connectors, block 

valves, control valves, pressure relief valves, orifice meters, regulators AND open-ended lines) 

from all transmission-distribution stations? It is confusing because of the use of the terms 

component and equipment leak source. Component is defined in the rule, but equipment leak 

source is not. EPA seems to be using these terms interchangeably and they seem to mean the 

same thing. For example, the term component is used both in Tp and in equation W-31 definition 

of Counts whereas equipment leak source is used in the definition of x and Es,i in equation W30. In addition, although EPA amended the definition of x in equation W-30, it is still confusing. 

The definition of x in Equation W-30 should more closely match the language for Es,i in 

equation W-32. Some confusion could be eliminated if the definition of x was changed to “total 

number of equipment leak sources, at all above ground stations”. Or the definition of x in W-30 

could be changed to say “total number of each component type”, not equipment leak source, 

since the term component is used in Tables W-2 through W-7. 

When EPA revised Equation W-30 the subscript “s” was omitted from EF. The definition for EF 

was not amended in the proposed rule, so the definition for EF is found in the final rule and it is 

listed as EFs. 

Response: EPA agrees with the commenter that the terms “component” and “emission source” 

were being interchangeably used that caused some confusion. In this final rule, EPA has 

clarified that the Equation W-30 (A and B) sums up at a facility level per “component type.” 

EPA has also clarified that the term “x” is the total count of each “component type”. Finally, 
119

EPA has consistently removed the subscript from EF throughout Equations W-30 (A and B) and 

W-31. 

Section 7.18.2 ­ Data Reporting Requirements

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 57 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] For each equipment 

leak sources that uses emission factors for estimating emissions (refer to §98.233(q) and (r)[add: 

)]. 

(i) For equipment leaks found in each leak survey (refer to §98.233(q)), report the following: 

(A) Total count of leaks found in each complete survey listed by date of survey and each type of 

leak source for which there is a leaker emission factor in Tables W–2, W–3, W–4, W–5, W–6, 

and W–7 of this subpart. 

(B) [delete: Concentration of CH4 and CO2 as described in Equation W–30 of §98.233.] 

[delete: (C) Report] [add: Annual] CH4 and CO2 emissions (refer to Equation W–30 [delete: of 

§98.233]) collectively by equipment type. 

(ii) For equipment leaks calculated using population counts and [add: emission] factors (refer to 

§98.233(r)), report the following: 

(A) For source categories §98.230(a)(3), (a)(4), (a)(5), (a)(6), and (a)(7), total count for each type 

of leak source in Tables W–2, W–3, W–4, W–5, and W–6 of this subpart for which there is a 

population emission factor, listed by major heading and component type. 

(B) For onshore production (refer to §98.230 paragraph (a)(2)), total count for each type of major 

equipment in Table W–1B and Table W–1C of this subpart, by field. 

(C) [delete: Report] [add: Annual] CH4 and CO2 emissions (refer to Equation W–31 [delete: of 

§98.233]) collectively by equipment type. 

Response: EPA agrees with the commenter in part. In this final rule, in paragraphs 

98.236(c)(15)(i)(C) and (ii)(C), the word “annual” has been added. EPA disagrees with deleting 

paragraph 98.236(c)(15)(i)(B) and in this rule has instead clarified to read that only onshore 

natural gas processing facilities must report their CH4 and CO2 concentration ranges in the total 

hydrocarbon feed of natural gas. EPA also disagrees with deleting the reference to 98.233 in 
120

paragraphs 98.236(c)(15)(i)(C) and (ii)(C), since it adds no additional clarity to what is 

requested. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 62 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has added a reporting requirement for the range of CH4 and CO2 

concentrations associated with equipment leaks in gas processing leak surveys. The rule cites 

Equation W-30. EPA also requires reporting CO2 and CH4 emissions by equipment type. 

Comment: It is not clear what “range” of concentrations EPA is referring to. The concentrations 

of CH4 and CO2 are defined for each segment under Equation W-30; there are no ranges in 

concentration. 

Response: EPA disagrees with the commenter that it is not clear what range of concentrations is 

asked for in 98.236(c)(15)(i)(B). First, that paragraph only applies to onshore natural gas 

processing facilities. All other facilities have default concentrations listed in the definition of 

GHGi in paragraph 98.233(q). The only segment that doesn’t have a default composition is 

onshore natural gas processing, and instead instructs reporters to use the actual concentration of 

CH4 and CO2 in the total hydrocarbon of the feed natural gas. Therefore, this range in CH4 and 

CO2 concentrations for onshore natural gas processing is what is asked for in 

98.236(c)(15)(i)(B). 

Section 7.19 ­ Population Count and Emission Factors

Section 7.19.1 ­ Calculating GHG Emission [W­31, W­32]

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 41 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Population count 

and emission factors. 

GHGi = For onshore petroleum and natural gas production facilities and onshore natural gas 

processing facilities, concentration of GHG i, CH4 or CO2, in produced natural gas or feed 

natural gas; for other facilities listed in § 98.230(a)(4) through (a)(8), GHGi equals 1 for CH4 

and 1.1 × 10-2 for CO2[add: , or use the gas composition allowed in §98.232(m)]. 
121

Response: EPA disagrees with the commenter. The default gas compositions for facilities listed 

in 98.230(a)(4) through (a)(8) are standard default ratios of CH4 and CO2 to total hydrocarbon 

content (THC) in pipeline quality gas. Since the emission factors used in Equation W-31 are on 

a THC or methane basis, these default CH4 and CO2 are sufficient for estimating GHG 

emissions. Hence, in this final rule, EPA has retained the requirements in 98.233(r) as relates to 

composition. Please see response to EPA-HQ-OAR-2011-0512-0029, Excerpt 3 for further 

details. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 8 

Commenter Type: Trade Association 

Comment: §98.233(r) includes different default values in the definition of GHGi that follows 

Equation W-31. Section (u)(2) should be referenced rather than introducing different defaults. 

Response: EPA disagrees that a reference to 98.233(u)(2) should be provided instead of the 

default compositions listed in the definition for GHGi. Paragraph 98.233(u)(2) is for determining 

greenhouse gas compositions in whole gas streams. The emissions factors used in paragraph 

98.233(r) are not whole gas emission factors, and are instead total hydrocarbon (THC) or 

methane emission factors. Therefore, a reference to 98.233(u)(2) would be inappropriate. The 

compositions provided in the definition of GHGi for the facilities listed in 98.230(a)(4) through 

(a)(8) are standard default ratios of CH4 and CO2 to THC or methane for pipeline quality gas in 

the various sectors. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 13 

Commenter Type: Trade Association 

Comment: Equation W-32 and §98.233(r)(2)(ii): 

The preamble incorrectly states that the agency is proposing to amend Equation W-32 to yield an 

emission factor in cubic feet “per meter to be used in Equation W-31 for above ground meteringregulating stations.” See 76 Fed. Reg. at 56,033. We think you meant to say “per meteringregulating station.” If the emission factor in the Proposal is to apply to a count of meters, we 

would have a problem, because the emission factor is supposed to apply to some stations where 

there are no meters. Recall that the proposed term “metering-regulating station” is defined to 

include stations that have (1) a pressure regulator but not a meter; or (2) a meter but not a 

pressure regulator; or (3) both a meter and a regulator. See 76 Fed. Reg. at 56,050. Fortunately, 

the actual proposed rule language in Equation W-32 correctly directs LDCs to count the “[t]otal 

number of meter/regulator runs at all TD transfer stations.” 76 Fed. Reg. at 56,045. Proposed 
122

section 98.233(e(6)(ii) also correctly uses the term “meter/regulator runs.” 

Define Meter/Regulator Run: AGA supports changing the emission factor so that it is based on a 

count of meter/regulator runs rather than a count of “meters.” However, we urge EPA to define 

this new term “meter/regulator run.” There is no definition in the proposed rule. We suggest the 

following definition: 

“Meter/ regulator run means a series of components used in regulating pressure or metering 

natural gas or both.” 

Response: EPA disagrees with the commenter that W-32 yields emission factors at a meteringregulating station. The September 2011 proposal rule text stating that the emission factor is at a 

meter/regulator run is correct and in this final rule, EPA has finalized the requirements. EPA has 

also added the definition for meter/regulator run. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 17 

Commenter Type: Trade Association 

Comment: Additional Corrections for W-32 and Section 98.233(r): 

EPA states in the preamble that the agency is proposing to eliminate the summation operator 

from Equation W-32. See 76 Fed. Reg. at 56.033. AGA supports this change. However, it 

appears that the agency inadvertently failed to remove this summation operator from Equation 

W-32 in the proposed rule. See 76 Fed. Reg. at 56,045. In this case, it appears the preamble is 

correct but the proposed rule is not. AGA requests that EPA remove the summation operator 

from Equation W-32 in section 98.,233(r), as the agency apparently intended. Our members have 

attempted to run calculations using the revised equations in the proposed rule, and they have 

found this equation is still confusing. Eliminating the summation operator will help remove that 

confusion. 

Further, in the proposed amendments, EF from the equation is listed as EFi when it is defined. 

The subscript i is either omitted from the equation or added unnecessarily in the definition for 

EF. 

Response: EPA agrees with the commenter and has removed the summation operator from 

Equation W-32. Additionally, EPA has removed the subscript “i” from parameter EF under 

Equation W-32. 

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 
123

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 22 

Commenter Type: Industry - oil and gas 

Comment: Population count and emission factors – § 98.233(r). The preamble discussion of Eq. 

W-31 is inconsistent with the proposed caption to this equation. In the preamble, EPA stated that 

it was proposing to modify Eq. W-31 by including a reference to 40 C.F.R. § 98.233(u) and 

deleting the specified compositions for each industry segment. 76 Fed. Reg. 56,033. The caption 

provided to Eq. W-31 in the proposed regulatory text does not include this cross-reference. 

Rather, it lists specific compositions for each industry segment. Chesapeake and AXPC support 

the caption provided in the proposed regulatory text. We object to inserting a cross reference to 

40 C.F.R. § 98.233(u)(2)(i) because doing so would impose a requirement for reporters to 

provide population count and emission factor information on a sub-basin basis. Gathering subbasin level data for fugitive sources would provide little environmental benefit. We support and 

incorporate by reference API’s comments in W.31 [EPA-HQ-OAR-2011-0512-0042, Excerpt 

47] of Section 2 in its October 24, 2011 letter to EPA. 

Response: EPA agrees with the commenter that a reference to paragraph 98.233(u) is 

unnecessary and is retaining the compositions for each industry segment in the parameter GHGi. 

Please see response to EPA-HQ-OAR-2011-0512-0042, Excerpt 48 for more information. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 47 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added guidance on how to determine the number of fugitive 

component sources in Equation W-31 for the different industry sectors. EPA provided CH4 and 

CO2 concentrations for GHGi for some industry sectors. 

Comment: The preamble on page 56033 states “In that same equation [Eq. W-31], we are 

proposing to revise the definition for GHGi by referring to 40 CFR 98.233(u) and deleting the 

composition specified for each industry segment.” However, the regulatory text on page 56045 

and the redline version for the definition of GHGi in Eq. W-31 were not revised to reference 

98.233(u) and still specify the composition for each industry segment. Also the compositions 

specified in the GHGi definition were revised in the regulatory text. 

Response: EPA agrees with the commenter that the rule and the preamble in the September 

2011 proposal do not match for 98.233(r). EPA’s intent was to specify the default compositions 

in W-31 for the parameter GHGi. Accordingly in this final rule, EPA has listed the composition 

of GHGs in the THC or methane emission factors in the definition of GHGi for Equation W-31. 
124

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 48 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA clarified for component count Methodology 1 that the count of 

meters/piping is 1 per well pad. 

Comment: API supports this revision. 

Response: EPA agrees with the commenter and thanks them for their remarks. 

Commenter Name: Curtis J. Winner 

Commenter Affiliation: New Mexico Gas Company (NMGC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0047

Comment Excerpt Number: 7 

Commenter Type: Industry - oil and gas 

Comment: Population Count and Emission Factors 

In Equation W-31, the revised definition for EFs in the proposed rule refers to an “EF for 

meter/regulating runs at above grade metering-regulating stations”. Did EPA intend for the 

emission factor to be for meter/regulator runs? NMGC’s understanding is we are using W-31 to 

calculate emissions from all above grade metering-regulating stations (including above grade TD 

transfer stations) using an EF generated from Equation W-32. 

The proposed rule revises 98.233.r.6.ii, to calculate emissions from all above grade meteringregulating stations (including above grade T-D transfer stations) by applying the EF calculated in 

W-32 and the total count of meter/regulator runs at all above grade metering-regulating stations 

(inclusive of T-D transfer stations) to Equation W-31. Does this mean we need to count all 

meter/regulator runs at all metering-regulating stations and use this count as the Counts for 

equation W-31? A count of meter/regulator runs at all metering-regulating stations would be 

very time consuming and costly to do. NMGC would have to visit close to 1,000 stations to 

obtain this count and it would negate the reduced burden EPA included in the final rule of 

applying a company specific emission factor to a larger set of stations that do not need to be 

surveyed for leaks. Instead, Counts for calculating emission from all above grade meteringregulating stations (including above grade T-D transfer stations) should be the total count of 

metering-regulating stations (including T-D transfer stations). 

In the proposed rule EPA uses a new term, meter/regulator run which is not defined. Does this 

mean all meter runs and all regulator runs need to be counted at each transmission-distribution 

transfer station where a leak survey is conducted? It should mean count meter and/or regulators 

since a meter can be on a regulator run. A meter on a regulator is just one run not two. 
125

Response: EPA is clarifying in this final rule (as proposed in the September 2011 rule) that 

Equation W-32 should be used to develop a meter-regulator run emission factor using leak 

detection data from above grade T-D transfer stations as summed in Equation W-30B. This 

factor per meter/regulator run should then be used to estimate emissions from above grade 

metering-regulating stations in Equation W-31. EPA disagrees with the commenter that 

counting meter/regulator runs is burdensome. Natural gas distribution facilities can collect this 

information when such stations are visited by personnel for routine visits. EPA cannot require 

the use of metering-regulating stations, as the size of stations varies considerably and will 

introduce errors in emissions estimates. In this final rule, EPA has clarified that a meter on a 

regulator run is considered one run. 

Commenter Name: Curtis J. Winner 

Commenter Affiliation: New Mexico Gas Company (NMGC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0047

Comment Excerpt Number: 9 

Commenter Type: Industry - oil and gas 

Comment: NMGC appreciates that EPA corrected Equation W-32 to calculate hourly 

emissions. However, there are still errors with Equation W-32. In the proposed amendments, EF 

from the equation is listed as EFi when it is defined. The subscript i is either omitted from the 

equation or added unnecessarily in the definition for EF. In addition, in the preamble to the 

proposed rule, page 56033, it says that the summation operator is removed in Equation W-32. 

This change is not reflected in the rule revisions to Equation W-32. Although the preamble states 

that the summation operator is removed because Es,i represents annual volumetric GHGi 

emissions at all T-D transfer stations, and its removal would clear up some of the confusion 

stated above for Leak Detection and Leaker Emission Factors, Equation W-30 is still confusing. 

It is confusing because the definition of Es,i in Equation W-30 is different from the definition for 

Es,i in W-32 even though they represent the same thing. To make it a little less confusing, the 

definition of Es,i in Equation W-30 should be changed to match the definition in Equation W-32 

which says “Annual volumetric GHGi emissions, CO2 or CH4 at standard conditions from all 

equipment leak sources at all above grade T-D transfer stations”. 

Response: EPA agrees with the commenter and in this final rule, has removed the summation 

from Equation W-32 to match the text provided in the preamble. Additionally, EPA has removed 

the subscript “i” from parameter “EF” under Equation W-32. 

EPA does not agree with changing the definition of the parameter “Es,i” in Equation W-30 to 

match the definition of the parameter “Es,i” in Equation W-32. Equation W-30, and therefore the 

parameter “Es,i”, is applicable to other industrial segments as well. Changing it to be applicable 

to natural gas distribution only would make the parameter invalid for other industry segments. 

Section 7.19.2 ­ Data Reporting Requirements

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 
126

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 63 

Commenter Type: Industry - oil and gas 

Comment: Revision: For equipment leaks using population counts, EPA has replaced the field 

level reporting requirement with reporting at the sub-basin. EPA also requires reporting CO2 and 

CH4 emissions by equipment type. 

Comment: API supports reporting for the sub-basin level. Although we recognize that reporting 

emissions by equipment type is consistent with the calculation methodologies, this reporting 

requirement adds burden without value. The requirements under 98.236(c)(15)(ii)(A) already 

requires the count of each type of leak source. Since emissions are based on this count and the 

emission factors provided in Tables W-2 through W-6, EPA already has the information required 

to determine the emissions for each equipment type. Therefore the request for this information 

from the reporters is redundant with information already available to EPA. 

Response: EPA notes that the commenter has misread the requirements for reporting of 

equipment leaks from onshore production. 98.236(c)(15)(ii)(A) applies to non-onshore 

production industry segments only. For onshore production, only 98.236(c)(15)(ii)(B) applies, 

where reporters are required to report the count of major equipment, not the count of component. 

In this final rule, EPA has provided further clarifying language to this paragraph. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 64 

Commenter Type: Industry - oil and gas 

Comment: Revision: 98.236(c)(15)(ii)(A) – EPA is proposing a correction to not include 

onshore gas processing as this source category is not required to use population emission factors. 

Comment: API supports this revision. 

Response: EPA agrees with the commenter and thanks them for their remarks. 

Section 7.2 ­ EOR Injection Pump Blowdown

Section 7.21.1 ­ Calculating GHG Emission [W­37]

Commenter Name: Darrell Shier 

Commenter Affiliation: SCANA Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0030 

Comment Excerpt Number: 3 

Commenter Type: Industry - oil and gas 
127

Comment: M&R Station Emission Calculations 

We find the emission calculations in the Proposed Rule remain confusing, particularly for M&R 

stations. We offer two suggestions. First, Equations W-30 and W-32 both use a variable named 

"EF" but the definitions for EF are different in the two equations. One of these variables should 

be renamed. 

Second, we find that the sequence in which the equations must be used (W-30 to W-32 to W-31) 

is confusing. The changes in the variable definitions for W-31 that are contained in paragraph 

98.233(r)(6)(ii) are also confusing. We suggest that a new equation W-32b be created to solve 

this second concern. 

Response: In this final rule, EPA is amending Equations W-30A (designated as Equation W-30 

in the November 2010 Final rule), adding Equations W-30B, and revising the associated data 

reporting requirements. For further details on these changes, please see preamble Section II.C. – 

Final Amendments to the Petroleum and Natural Gas Systems Source Category – Major Changes 

Since Proposal. 

EPA disagrees with the commenter’s suggestion of renaming one the variable “EF” for one of 

the equations. For each equation, the definitions of the relevant parameters are stated below the 

equation and must only be used for that particular equation. Hence, the “EF” for EquationW-30 

is different from the “EF” in Equation W-32. 

The commenter does not provide any reasoning to explain why the sequence in which Equations 

W-30 (now W-30A) through W-32 and the changes in variable definitions for Equation W-31 are 

confusing. In this final rule, EPA clearly states that reporter must calculate emissions per 

component type per reporting facility using Equation W-30A (for industry segments 98.230(a)(3) 

to (a)(7)) and Equation W-30 B (for industry segment (a)(8)) if equipment leaks are detected for 

the applicable sources as listed in 98.233(q). Additionally, reporters must calculate the facility 

wide emission factor per meter/regulator run and component type in Equation W-32 using the 

total volumetric GHG emissions at standard conditions for all leaking components calculated in 

Equation W-30B and the count of meter/regulator runs located at above grade transmissiondistribution transfer stations that were monitored over the years that constitute one complete 

cycle as per 98.233(q)(8)(i). Lastly, reporters must calculate emissions from all above grade 

metering-regulating stations (including above grade T-D transfer stations) by applying the 

emission factor calculated in Equation W-32 and the total count of meter/regulator runs at all 

above grade metering-regulating stations (inclusive of T-D transfer stations) to Equation W-31. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 65 

Commenter Type: Industry - oil and gas 
128

Comment: Revision: 98.236(c)(15)(ii)(b) requires reporting fugitive emissions for each type of 

major equipment by sub-basin category. However, Equation W-31, which is the calculation 

approach applied for fugitive emissions by population counts is applied at the facility (i.e. basin) 

level. Comment: The reporting requirements should align with the calculation method. The 

definitions for “Count” and “GHGi” Equation W-31 clearly refer to the facility. API requests 

that the reporting requirements be revised accordingly. 

Response: EPA agrees with the commenter. EPA has amended this final rule to require 

reporting of major equipment type by facility for onshore production. 

Section 7.22 ­ Onshore Petroleum and natural Gas Production and Natural Gas

Distribution Combustion Emissions

Commenter Name: William W. Grygar II 

Commenter Affiliation: Anadarko Petroleum Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0028

Comment Excerpt Number: 12 

Commenter Type: Industry - oil and gas 

Comment: Furthermore, Anadarko supports additional comments submitted by API, 

particularly regarding reporting requirements under §98.236. Anadarko also supports the 

recommendations made by AXPC, particularly regarding stationary and portable combustion 

requirements for the onshore production sector under §98.233(z). 

Response: For the response to API’s comments regarding §98.236, please see the responses to 

EPA-HQ-OAR-2011-0512-0042, Excerpt 29; EPA-HQ-OAR-2011-0512-0042, Excerpt 57; 

EPA-HQ-OAR-2011-0512-0042, Excerpt 58; EPA-HQ-OAR-2011-0512-0042, Excerpt 59; 

EPA-HQ-OAR-2011-0512-0042, Excerpt 64; and EPA-HQ-OAR-2011-0512-0042, Excerpt 65. 

For the response to AXPC’s comments regarding §98.233(z), please see the response to 

comment EPA-HQ-OAR-2011-0512-0033, Excerpt 23. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 10 

Commenter Type: Trade Association 

Comment: EPA Should Exclude Distribution Combustion from Subpart W 

In addition to the exclusion for small IC engines, AGA urges EPA to exclude LDC combustion 

emissions entirely from Subpart W, because this needlessly duplicates the emissions already 
129

reported by LDC’s for their system operations under Subpart NN. 

LDCs report the CO2e emissions that result from their own combustion in distribution operations 

through Subpart NN. Meters feeding LDC buildings and combustion units are included in the gas 

sendout volumes reported under NN along with the associated combustion emissions. 

In Subpart NN, section 98.406(b)(1) specifically prompts the LDC to report the “Annual volume 

in Mscf of natural gas received by the LDC at its city gate stations for redelivery on the LDC’s 

distribution system, including for use by the LDC.” Reporting these emissions twice – under 

both Subpart NN and W results in an overstatement of the carbon footprint for the natural gas 

value chain. Accordingly, we urge EPA to exclude natural gas distribution combustion emissions 

from Subpart W. 

Response: EPA disagrees with the commenter that LDCs should be excluded from reporting 

combustion emissions. EPA notes that the Subpart NN requires the reporting of total natural gas 

delivered among other activity data; it does not collect information on natural gas consumed 

internally as fuel separately from the total sendout for the facility. Secondly, Subpart NN does 

not track the specific combustion equipment type in which natural gas is being consumed. EPA 

understands that the combustion volume of natural gas is being reported twice, and will ensure 

appropriate adjustments in the national mass balance of emissions. Hence, EPA has retained the 

requirement for LDCs to report combustion emissions. However, EPA has provided relief in 

terms of an equipment threshold for internal combustion emissions that are not compressor 

drivers; please see preamble Section II.C –Final Amendments to the Petroleum and Natural Gas 

Systems Source Category, and Section II.D.6 – Responses to Major Comments Submitted on the 

Petroleum and Natural Gas Systems Source Category for onshore production and distribution 

combustion emissions and equipment threshold for internal combustion engines. 

Section 7.22.1 ­ Calculating GHG Emission [W­39, W­40]

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 23 

Commenter Type: Industry - oil and gas 

Comment: Onshore petroleum & natural gas production combustion emissions – § 98.233(z). 

In its December 17, 2010 amendments to the MRR, EPA modified the definition of "natural gas" 

provided in 40 C.F.R. § 98.6. Natural gas is now defined as: "a naturally occurring mixture of 

hydrocarbon and non-hydrocarbon gases found in geologic formations beneath the earth’s 

surface, of which the principal constituent is methane. Natural gas may be field quality or 

pipeline quality." 40 C.F.R. § 98.6. The December 17 technical amendments also modified Table 

C-1, which provides default CO2 emission factors and high heat values for various types of fuel. 

Specifically, EPA removed the modifier "pipeline" from the description of "natural gas." 75 Fed. 

Reg. 79113, 79154 (Dec. 17, 2010). By making this change in Table C-1, EPA provided a 
130

default high heat value and CO2 emission factor for the general term "natural gas" which 

includes both field gas and pipeline quality gas. Prior to this amendment, the CO2 emission 

factor and high heat value in Table C-1 could not be used for field gas. These changes impact the 

calculations required for the combustion emissions from onshore petroleum and natural gas 

production and natural gas distribution. 

40 C.F.R. § 98.233(z) created different calculation methodologies for pipeline quality natural gas 

and field gas. To determine the emissions from combusting pipeline quality natural gas, Subpart 

W currently allows reporters to use the Tier 1 methodologies provided in Subpart C, which are 

based on the emission factors found in Table C-1. In contrast, to determine the emissions from 

combusting natural gas that is not of pipeline quality or that has a higher heating value of less 

than 950 Btu/scf, Subpart W does not allow reporters to use the Tier 1 methodologies and 

emission factors from Table C-1. 

The rule creates an arbitrary distinction between pipeline quality gas and field gas, in addition to 

an inconsistency between the way terms are used in Subpart W and in Subpart C, resulting in 

different reporting obligations. Table C-1 lists the high heat value and CO2 emission factor for 

“natural gas,” which is defined to include both pipeline quality and field quality natural gas. 

Therefore, Subpart W reporters should be directed to use the default emission factors in Table C1 for both pipeline quality and field gas quality natural gas, regardless of the higher heating 

value, to ensure consistency in reporting emissions relating to natural gas combustion. This 

modification to Subpart W would be consistent with EPA’s decision to remove the modifier 

"pipeline" from the description of "natural gas" in Table C-1. 75 Fed. Reg. 79113, 79154 (Dec. 

17, 2010); see also 75 Fed. Reg. 79,106 (“we have decided to finalize the definition of natural 

gas without any specifications regarding minimum or maximum Btu values or a minimum 

methane content.”). 

AXPC and Chesapeake also restate our objection to the requirement to report emissions from the 

combustion of diesel fuels under § 98.233(z). Requiring the reporting of these diesel combustion 

emissions contradicts EPA’s oft-stated need for accurate emission data from all sectors covered 

in the Reporting Rule. See, e.g., 75 Fed. Reg. 74,474 (“[T]he high level of public interest in the 

data collected, as well as its importance to future policy, warrants establishment of a high 

standard for data quality and consistency. . . .” ); 75 Fed. Reg. 74,484 (“EPA plans to collect 

complete and accurate facility-level GHG emissions from the petroleum and natural gas industry. 

Accurate and timely information on GHG emissions is essential for informing future climate 

change policy decisions); 75 Fed. Reg. 74,467 (“facility” definition selected in part to avoid 

double-counting ); 75 Fed. Reg. 74,498 (flare emissions “must be corrected for flare emissions 

calculated and reported under other paragraphs of this section to avoid double counting”). In its 

Response to Comments to the final Subpart W rule, EPA acknowledged that these same 

emissions are already reported under Subpart MM and double counting will result. RTC at 955- 

56. EPA accepts double counting in this instance, because “[a]lthough refineries will report total 

fuel supplied under Subpart MM, EPA will not know where the fuels are being combusted to 

inform any combustion equipment specific policy. . . .” RTC at 1600. 

EPA’s determination to require that such diesel emissions be reported under Subpart W is 

completely arbitrary; in the same rule, EPA demands exact measurement of very de minimis 
131

emissions, while inviting inaccuracy by expressly requiring double-counting of emissions from 

the same sources. This irrational outcome should be addressed during this rulemaking process. 

Section 98.233(z) should not require the reporting of emissions from diesel-fired equipment. 

To address both of these issues (the definition of natural gas and the double-counting of diesel 

combustion emissions), §§ 98.233(z)(1) and (2) should be rewritten as follows: 

§ 98.233(z) Onshore petroleum and natural gas production and natural gas distribution 

combustion emissions. Calculate CO2, CH4, and N2O combustion related emissions from 

stationary or portable equipment as follows: 

(1) If the fuel combusted in the stationary or portable equipment is: 

(i) Diesel fuel (i.e., distillate fuel oil No. 1, 2 or 4 or other diesel fuel), the emissions from the 

combustion of such fuel in stationary or portable equipment used for onshore petroleum and 

natural gas production are excluded from 40 CFR 98, subpart W; 

(ii) listed in Table C–1 of subpart C of this part, except for diesel fuel, or is a blend of fuels listed 

in Table C–1, use the Tier 1 methodology described in subpart C of this part (General Stationary 

Fuel Combustion Sources). 

(2) [Reserved] 

* * * 

Response: EPA disagrees with the reporter on the use of Subpart C methods for fuel that is field 

gas, process vent gas, a blend of field gas and process vent gas, or natural gas less than 950 Btu 

per scf. EPA did not change this method as finalized in the November 2010 final rule. In the 

September 2011 proposal, EPA simplified the determination of fuel consumption and allowed 

for the use of company records. EPA also proposed a calculation method for CH4 emissions and 

allowed the use of CEMS for combustion emissions monitoring. The change in the definition of 

natural gas for Subpart W has no bearing on the reporting of combustion emissions for onshore 

production and natural gas distribution. In this final rule, the requirement for the determination of 

composition of non-pipeline quality gas remains unchanged from the November 2010 rule. 

EPA disagrees with the commenter on the reporting of diesel fuel combustion. Please see 

response to EPA-HQ-OAR-2009-0923-1042, Excerpt 26 for further details. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 50 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA has added clarifications on the requirements for combustion 
132

emissions under 98.233(z). Natural gas that does not meet the definition of “pipeline quality” is 

required to use the same approach as used for the combustion of process vent gas or field gas. 

EPA has removed the requirement that a flow meter must be used if available. 

Comments: 

• A conversion term in Eq. W-40 is 1×103, but the term in the definition is 1×10-3. 

• In 98.233(z)(1)(i), the first sentence should be corrected to read “...or a blend containing one or 

more fuels...” instead of “...or a blend containing one more fuels...”. 

• 98.233(z)(2)(ii) is an example of a non-sub-basin reporting category directing you to 

98.233(u)(2)(i) which requires sub-basin composition analysis. (See comment W.34 [EPA-HQOAR-2011-0512-0042, Excerpt 50]). 

• In 98.233(z)(2)(i), EPA has added that you may use company records to determine the volume 

of fuel combusted in the unit during the reporting year. API fully supports this revision. 

Response: EPA agrees with the commenter on Equation W-40 and has modified the conversion 

term appropriately in this final rule. 

EPA agrees with the commenter on 98.233(z)(1)(i) and has added the “or” to the sentence as 

necessary in this final rule. 

EPA agrees with the commenter on 98.233(z)(2)(ii). In this final rule, EPA has clarified that 

98.233(u)(2)(i) is applicable at a facility or sub-basin level as per the requirements in the 

monitoring method for the particular emission source. 

EPA agrees and thanks the commenter for the comment on 98.233(z)(2)(i) and has finalized the 

requirements in this final rule. 

Section 7.22.2 ­ Data Reporting Requirements

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 66 

Commenter Type: Industry - oil and gas 

Comment: Revision: API interprets the type of units for external combustion sources >5 

MMBtu/hr to refer to those listed under 98.30: boilers, incinerators, and process heaters. 

Comment: EPA has revised the reporting requirements for external combustion sources >5 

MMBtu/hr to require annual CO2, CH4 and N2O emissions by type of unit. 
133

Response: EPA notes that the reporters for onshore production combustion equipment must 

determine the type of equipment using 98.232(c)(22). 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 67 

Commenter Type: Industry - oil and gas 

Comment: Revision: API interprets the type of units for internal combustion sources to refer to 

those listed under 98.30: simple and combined-cycle combustion turbines, and engines. 

Comment: EPA has revised the reporting requirements for internal combustion sources to require 

annual CO2, CH4 and N2O emissions by type of unit. 

Response: EPA notes that the reporters for onshore production combustion equipment must 

determine the type of equipment using 98.232(c)(22). 

Section 7.22.3 ­ Onshore Production and Distribution Equipment Threshold for Internal

Combustion Equipment

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 9 

Commenter Type: Trade Association

Comment: AGA Supports a 1 million Btu/hour or 130 HP Threshold for Exempting Internal 

Combustion Engines 

EPA, citing a lack of data, declined to include a 5 million Btu/hour threshold for exempting 

internal combustion (IC) engines even though the Agency had established a similar exemption 

level for external combustion engines, and even though both API and AGA had requested such 

an exemption in their respective petitions for reconsideration. However, the agency indicates that 

it collected data on IC engines used in production, and determined that a 130 horsepower level 

(double the largest size found) would exclude virtually all small IC engines, and would equate to 

about 1 million Btu/hour. EPA states in the preamble that it “is seeking comment on whether a 1 

mm Btu/hour equipment threshold for IC engines that are not driven by natural gas is 

reasonable.” 76 Fed. Reg. at 56034. AGA supports exempting small stationary IC engines less 

than 1 million Btu/hour from the reporting requirements. This exemption threshold would work 

for the small IC engines used by our members in natural gas distribution systems, but only if the 

exemption also applies to IC engines that are driven by natural gas. 
134

Attached are three pictures of a typical natural gas-powered generator set at a regulator station. 

(See Exhibits 1-3). [See original comment for Exhibits 1, 2, and 3]. LDCs typically place these at 

their larger regulator stations (including custody transfer stations, and T-D or Transmission to 

Transmission stations) for backup power in the event of a power outage. At stations where large 

pressure drops are occurring, the natural gas must be heated ahead of the pressure cut to keep the 

gas above freezing temperature downstream of the pressure cut. The boilers that preheat the gas 

actually burn natural gas but they need electricity to operate the controls and the pumps. In the 

event of a prolonged outage the IC engine generator sets are run to keep the heaters in operation. 

Two specification sheets are also attached in Exhibit 4 for a typical 20 kW generator set and a 

larger 35 kW generator set. [See original comment for Exhibit 4]. As shown on the sheets the full 

load input of the 35 kW generator is 494 scf/hour or approximately 0.496 mmBtu/hour. 

The IC engine generators are used for backup generation so they rarely run. Typically they are 

test fired once a year for 10 minutes to make sure they operate. For example, one of our members 

reported that they have three IC engines of this type that are all relatively new & have operated 

for the following number of hours during the years after installation: (1) their 35 kW unit is 4 

years old and has operated 36.2 total hours; (2) a 20 kW unit is less than 2 yrs old and has 

operated for 9.3 hrs over that time; and (3) another 20 kW unit is new and has operated 5 hrs 

during its first year (all for testing). The member estimates that the engines operate about 6 hours 

per year on average, most of which occurs during quarterly test runs to make sure they work. 

Subpart W calculations would yield estimated emissions of only 0.357 tonnes CO2e per year 

from the three engines [Footnote 3: 35 kW IC engine @ 6 hrs = 2,964 scf/hour; 20 kW IC engine 

@ 6hrs = 1,790 scf/hour each X two engines; Total = 6,544 scf/hour of gas; Total CO2e GHG = 

0.357 metric tons]. And this overstates actual emissions, because the gas is not metered, so the 

member assumed for purposes of this calculation that the engines were operated under full load 

consumption, which was obviously not the case. For most of the hours of operation, the back-up 

engines were being tested and were operating at minimal load or no load at all. Exempting such 

engines from the reporting requirement would reduce burdens while maintaining a robust and 

accurate estimate of the greenhouse gas emissions from the distribution sector. 

Response: EPA agrees with the commenter on adopting a 1 mmBtu/hr threshold for internal 

combustion equipment. However, this equipment threshold does not apply to compressor 

drivers. Please see preamble Section II.C – Final Amendments to the Petroleum and Natural Gas 

Systems Source Category, and Section II.D.6 – Responses to Major Comments on the Petroleum 

and Natural Gas Systems Source Category for onshore production and distribution combustion 

emissions and equipment threshold for internal combustion engines. Given the requirements in 

this final rule, gas fired electricity generator sets with a rated heat capacity under 1 mmBtu/hour 

do not have to report emissions; however a count of such equipment, by type, has to be reported. 

Commenter Name: Vince Alaimo 

Commenter Affiliation: Marshall Miller & Associates Inc. on behalf of Consol Energy Inc. 

Document Control Number: EPA-HQ-OAR-2011-0512-0036

Comment Excerpt Number: 9 
135

Commenter Type: Industry - oil and gas 

Comment: Onshore Production and Distribution Equipment Threshold for Internal Combustion 

Equipment 

•EPA is proposing to use a 1mBtu threshold for the small internal combustion engines used for 

periodic maintenance and construction. This would remove all but the largest generator (130HP) 

from the reporting requirement. 

In some cases the deck engine used for the drill is powered using the engine that propels the drill 

rig on the road. Consol Energy Inc. would like clarification if the GHG emissions from this 

engine are to be considered? 

Response: In the scenario that the engine used to propel the rig is used to run the drill, the 

emissions do not have to be reported under Subpart W. Generally, if the power take-off for 

operating the truck mounted workover rig is the truck wheel drive engine (i.e. a transmission 

option to transfer the truck wheel drive shaft to powering the rig generator or wench or other rig 

equipment), this workover rig arrangement is “self propelled.” However, if the truck has a 

separate engine not connected to the drive wheels that powers the workover rig equipment, then 

it is a “non-self propelled equipment” and therefore you must report emissions from this 

equipment. 

If the equipment is on a trailer where the trailer can technically be detached from the truck 

tractor, this equipment is considered portable equipment and required for reporting. Regardless 

of whether the trailered equipment is detached from a tractor or not, the equipment is considered 

portable and required for reporting, if the equipment itself is considered non-self propelled. 

Commenter Name: Gregory L. Ryan 

Commenter Affiliation: DTE Energy 

Document Control Number: EPA-HQ-OAR-2011-0512-0041

Comment Excerpt Number: 4 

Commenter Type: Industry - oil and gas

Comment: Threshold for internal combustion equipment in natural gas distribution 

DTE Energy supports a 1 million BTU/hr or 130 HP threshold for exempting internal 

combustion engines in service in natural gas distribution systems. We support this exemption for 

all internal combustion engines, including those that combust natural gas. 

Response: EPA agrees with the commenter on adopting a 1 mmBtu/hr threshold for internal 

combustion equipment. However, this equipment threshold does not apply to compressor 

drivers. For further details, please see response to EPA-HQ-OAR-2011-0512-0032, Excerpt 9. 
136

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 3 

Commenter Type: Industry - oil and gas 

Comment: Threshold for Internal Combustion Engines 

On page 56034 of the preamble EPA solicits comments as to why emissions from specific 

internal combustion related equipment should not be reported, including the size of the 

equipment that should be excluded along with supporting data. 

Specifically, EPA is seeking comments on the following: 

- “...whether a 1 MMBtu/hr equipment threshold for internal combustion engines that are not 

driven by natural gas is reasonable.” 

- “...combustion-related emissions at compressors should not be excluded from reporting, 

regardless of size, and where EPA can find reliable estimates of natural gas consumption.” 

- “... why emissions from specific internal combustion related equipment should not be reported, 

including the size of the equipment that should be excluded along with supporting data.” 

API Response: 

For the onshore petroleum and natural gas production segment, the current rule exempts external 

combustion equipment with a rated heat capacity < 5 MMBtu/hr from reporting GHG emissions 

regardless of fuel type.[Footnote 4: See 40 C.F.R. § 98.233(z)(3)] The rule simply requires 

reporters to report the type and number of each external fuel combustion unit. API has welcomed 

this exemption in the final rule as a means to reducing the reporting burden associated with the 

small quantity of emissions associated with these sources. 

API has noted further that internal combustion equipment with a similar capacity of < 5 

MMBtu/hr, regardless of fuel type, should be likewise exempted. The magnitude of emissions 

from the combustion of internal combustion devices of similar capacity would be no different 

than for the exempted external combustion devices. 

Although API appreciates EPA’s consideration of providing a limited exemption for reporting 

GHG emissions from small internal combustion engines not fueled with natural gas, API 

continues to insist that there is no justification for separate exemption thresholds for internal and 

external combustion equipment, no justification for limiting such an exemption to engines not 

fueled by natural gas, and that all combustion equipment, both internal and external, integral to 

production operations with a rated capacity of < 5 MMBtu/hr should be uniformly exempted 

from emissions reporting regardless of fuel type. 

The reporting burden that EPA found not to be justified for small external combustion devices 
137

remains unjustified for small internal combustion devices. API recommends that along with such 

an exemption, reporters would simply report the type and number of internal combustion units, 

regardless of fuel type, which are integral to production operations, in each of the following 

specified size categories: (a) those that are less than or equal to 125hp (<1MMBtu/hr); (b) those 

that are over 125hp but less than or equal to 375hp (1-3MMBtu/hr); and (c) those that are over 

375hp but less than or equal to 625hp (3-5 MMBtu/hr). This is consistent with and provides 

more detailed information than the approach for the excluded external combustion devices, and 

would contribute to reducing the reporting burden. This information will enable EPA to estimate 

the natural gas consumption by these internal combustion engines and thus provide EPA with 

needed data for future policy development. 

At the same time, API wants to reiterate here that the internal combustion engines addressed by 

this rule should be limited to those that are “integral to the extraction, processing, or movement 

of oil or natural gas”, including compressors. This would not include some of the types of 

engines referenced in the first paragraph on Page 56034 of the preamble to the September 9, 

2011 proposed rule, and which are already exempt from emissions reporting based on the 

promulgated Subpart W requirements. 

Response: EPA disagrees with the commenter on providing a 5 mmBtu per hour threshold for 

internal combustion equipment and also disagrees on applying an equipment threshold for 

natural gas driven internal combustion equipment, especially compressor drivers. Please see 

response to comment EPA-HQ-OAR-2011-0512-0032, Excerpt 9 for further details. To inform 

future policy, EPA requires the number of wellhead compressors, generally fueled with produced 

natural gas, in the size categories between 1 and 5 mmBtu/hour. EPA believes that most of the 

wellhead compressors in onshore production will fall under 5 mmBtu/hour, so extending the 

threshold would exempt virtually all such compressors from reporting. No commenter has 

provided EPA with data on the numbers and horsepower ranges of such internal combustion 

engines, as commenters did for external combustion devices. In addition, no reporter has 

provided any reference(s) to reliable source of data for natural gas consumption by such 

compressors. Finally, EPA cannot estimate natural gas consumption simply by using a count of 

equipment by heat rate, since the hours of operation are needed to perform such a calculation; 

and the ranges specified by the commenter are too large and will potentially result in estimates 

with large uncertainty. 

 
138

Section 8 ­ Monitoring and QA/QC Requirements (98.234)

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029 

Comment Excerpt Number: 20 

Commenter Type: Trade Association 

Comment: INGAA supports revisions that provide additional clarity and flexibility for 

monitoring and measurement methods. 

EPA has added monitoring and monitoring measurement flexibility in response to INGAA 

recommendations. INGAA supports revisions that provide additional flexibility for monitoring 

and measurement methods and associated recordkeeping. For example, the Proposed Rule 

indicates in §98.234(a) that video records are not required for optical imaging; and, provides 

additional flexibility in §98.233(k)(1) for measuring vented emissions from transmission tanks. 

Similarly, under §98.234(a)(5), INGAA supports the addition of acoustic stethoscope type 

devices to detect through valve leakage and recommends that the use of similar and commonly 

used devices such as open air attachments also be allowed. 

The flexibility from these changes provides reasonable options that reduce burden while ensuring 

data quality objective are met. As discussed in Comment 12, an important monitoring option is 

not included in the Proposed Rule. Flexible approaches to acquire the necessary data should be 

consistently implemented throughout Subpart W, and this philosophy should be applied when 

addressing Comment 12 and Comment 14. 

Response: EPA thanks the commenter for their remarks. EPA is unclear on what an “open air 

attachment” is, and therefore has no comment in that regard. For further details on the 

monitoring options suggested by the commenter in comments 12 and 14, please see the response 

to EPA-HQ-OAR-2011-0512-0029, Excerpt 19 and EPA-HQ-OAR-2011-0512-0029, Excerpt 

21. 

Section 8.1 ­ Methods

Commenter Name:

Commenter Affiliation: Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2011-0512-0026 

Comment Excerpt Number: 5 

Commenter Type: Industry - other 

Comment: Dow supports EPA’s proposed rule that clarifies that video recordings for leak 

inspections are not required under Subpart W. 

Proposed changes to Section 98.34(a)(1) clarify that video recordings of the fugitive emission 
139

monitoring scans with the IR camera are not required under subpart W. Dow supports this 

clarification and believes that the proposal will increase the ability of the owner/operator to use 

the camera for the required annual check. 

Response: EPA agrees and thanks the commenter for their remarks. 

Commenter Name: 

Commenter Affiliation: Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2011-0512-0026 

Comment Excerpt Number: 6 

Commenter Type: Industry - other 

Comment: Dow seeks clarification on whether any of the options contained in 98.234(a) can be 

used to detect valve leak through or whether an acoustic device must be used for these 

determinations. 

Dow’s interpretation of the Monitoring and QA/QC requirements in 98.234(a) is that any of the 

options noted in Section 98.234(a)(1) through (5) can be used to detect through-valve leakage. If 

correct, Dow comments that EPA should slightly modify the beginning of section 98.234(a) to 

read as follows: 

You may use one or more 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 ....... 

Response: EPA has reviewed your comment and may consider it in future rulemakings. EPA 

notes that for monitoring transmission storage tanks as under 98.233(k), reporters must use the 

equipment listed in 98.233(k). 

Section 8.1.1 ­ Optical Gas Imaging Instrument

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029 

Comment Excerpt Number: 19 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Monitoring and 

measurement methods: 

In a May 2011 meeting, EPA was receptive to an INGAA request to allow optical imaging to 

screen compressor vents subject to §98.233(o) and (p) to determine whether measurement is 

warranted. The Proposed Rule does not include this important revision. 

As EPA has developed necessary revisions to Subpart W, INGAA has strived to provide input 
140

and recommendations on rule content. To increase the flexibility of compressor vent 

measurement required under §98.233(o) and (p), INGAA has requested that Subpart W allow 

optical imaging as a method to pre-screen affected vents. With this approach, if emissions are not 

seen using optical imaging, the vent line would not require measurement. This issue was 

discussed at a May 2011 meeting and EPA was receptive. In response to EPA's request at the 

meeting, INGAA provided recommended rule redlines, including the following addition to 

§98.234(a): 

[add: "An operator can elect to conduct annual optical gas imaging according to paragraph (i) or 

(ii) of this section to screen vents that require measurement under §98.233(o) and (p). Vent rate 

measurement is not required and the vent rate is recorded as zero if optical gas imaging does not 

detect vented gas."] 

Unfortunately, EPA has not addressed this issue in the Proposed Rule. As discussed in Comment 

1, this omission may be due to EPA's failure to address revisions to §98.233(o) and (p) in either 

the Proposed Rule or August 4 proposed revisions. Adding this flexibility can be easily 

accomplished through an addition to the monitoring section, §98.234(a), and appropriate 

reference to the new provisions in §98.233(o) and (p). INGAA's June 2011 recommended 

redlines provide example text. 

Availability of this option should not be delayed as EPA considers other revisions to §98.233(o) 

and (p). INGAA hopes that this omission from the Proposed Rule is an oversight, and 

recommends that EPA incorporate the text above, or similar text, in the Final Rule so this option 

is available for use as soon as possible. 

Response: EPA is not accepting any comments on 40 CFR 98.233 (o) and (p), because 

amendments to these sections were not proposed in this proposed rule or the August 4 proposed 

revisions and hence, these equations are outside the scope of this rule. EPA may consider your 

comment in future rulemakings. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029 

Comment Excerpt Number: 21 

Commenter Type: Trade Association 

Comment: For optical imaging, methods other than the EPA Alternative Work Practice (AWP) 

should be allowed. 

INGAA reiterates previous comments and concerns expressed to EPA. For optical imaging, 

methods other than the EPA Alternative Work Practice (AWP) are necessary and should be 

allowed. EPA's attempt to apply select sections of the AWP is resulting in a derivative method 

that is untested and has not been validated. The derivative AWP in the Proposed Rule should not 

be mandated as the only method allowed. 
141

§98.234(a)(1) specifies the use of an optical gas imaging instrument for fugitive emissions 

detection in accordance with 40 CFR part 60, Subpart A, §§ 60.18(i)(1) and (2) of the AWP for 

monitoring equipment leaks. This AWP was not developed for methane or GHG leaks and 

contains provisions and requirements that are inappropriate or too restrictive for natural gas 

transmission and storage component leak screening. The Proposed Rule adds criteria and 

revisions to the AWP, and INGAA reiterates that this should not be the only method allowed. 

§98.234(a)(1) should be revised to include additional flexibility and allow use of other methods 

such as manufacturer procedures or industry standards which are more appropriate for methane 

detection from transmission and storage sources. 

The Proposed Rule attempts to rely on select provisions from an AWP that was developed for the 

refining sector as a Method 21 alternative work practice. Since its adoption, the AWP has not 

been widely adopted by that industry. It is inappropriate to assume that an AWP that is not 

generally accepted in its intended sector provides the only viable method for methane detection 

from a different sector. It is also inappropriate to unilaterally mandate a derivative method that 

has not been peer-reviewed or validated for this application. 

A basic tenet of test method development is that the component parts collectively comprise 

procedures that result in a method that has been evaluated, peer-reviewed, and validated. For the 

GHG reporting rule, methodology guidelines are marginally less rigorous in most cases, with 

industry practices and manufacturer procedures commonly allowed. This is appropriate for 

measurement associated with data gathering for a reporting rule that includes inherent 

uncertainties in the estimation methods. Yet, EPA is mandating a single method for optical 

imaging – but revising the published method without adequately supporting the premise that this 

is the only solution. The unilateral imposition of untested criteria is contrary to the process for 

developing acceptable methods. In a case where a single method is mandated and EPA dictates 

only one solution, it is imperative that the procedures have been validated and scrutinized, rather 

than unilaterally imposed without testing, evaluation, and validation. Rule flexibility is needed to 

accommodate manufacturer recommendations, future test methods and method enhancement, 

and possible adoption of AWP revisions to address method inadequacies, shortcomings, and 

criteria to adapt the method to other applications (i.e., other industrial sources, gases, etc.). 

In the Proposed Rule, rather than addressing comments requesting flexibility for other methods, 

EPA unilaterally revises the AWP, and maintains that this is the only viable method. The AWP 

revisions have not been subjected to peer review or validation. INGAA is troubled by the 

precedent established by unilaterally implementing untested procedural changes to a method that 

has not been validated. Mandating selected provisions and revisions to an AWP that has not been 

successfully integrated into the mainstream practices for optical imaging is inappropriate. The 

failure to provide alternative options is remiss. In addition, mandating a single method for optical 

imaging is contrary to the general tenor of Subpart W, which commonly allows manufacturer 

procedures and industry standard procedures for measurements. EPA has not adequately justified 

or supported this position. 

INGAA opposes the Proposed Rule mandate that identifies the "derivative" AWP as the only 

allowed method. EPA has not provided documentation that supports the efficacy of the proposed 
142

AWP deviations, or assessed (and discounted) whether other viable alternatives are available. At 

a minimum, EPA should allow operators flexibility to document the procedures relied upon 

within site Monitoring Plans to ensure optical imaging performance. 

INGAA refers EPA to previous INGAA comments submitted in response to Subpart W rule 

proposals and our June 2011 letter that provided recommended redlines. In addition, INGAA 

understands that optical camera vendors and users of the technology – i.e., the best experts 

available – are more than willing to provide alternative procedures and standards for optical 

imaging. If EPA retains a single method mandate, it should be subject to appropriate peer review 

and a refereed method validation process. INGAA strongly recommends revising §98.234(a)(1) 

to add flexibility. In addition to the AWP, manufacturer procedures and industry standard 

practices should be allowed. 

Response: EPA disagrees with the commenter. First, EPA is not mandating the use of optical 

imaging cameras and the associated AWP requirements. EPA has provided reporters the option 

to use Method 21 compliant leak detection equipment. Reporters may, therefore, choose to use 

this option instead of using the optical imaging camera. 

Second, the commenter is objecting to the “derivative” AWP without specifically identifying 

what feature(s) of the leak imaging cameras are not acceptable. EPA excluded from the AWP 

those features that are necessary in an enforceable leak repair program but are unnecessary for 

Subpart W purposes (e.g. the requirement to retain a video recording of all detected leaks). 

Because the LDAR regulation requires detection and repair of only components that are 

accessible to an operator standing on the ground or fixed platform using hand held instruments 

such as an organic vapor analyzer (OVA), the IR camera is not a necessary instrument. Operators 

decide which instrument is most cost effective for the regulatory requirement and IR camera with 

video recording of all detected leaks may not be more cost effective than OVA with no 

requirement of video recording. This choice by refinery and chemical plant operators complying 

with the LDAR regulation has no bearing on the collection of leak data to inform future policy in 

Subpart W. EPA notes that allowing manufacturer’s standards does not establish the sensitivity 

of the instrument the way AWP does for the detection of hydrocarbons, i.e. nothing precludes the 

optical imaging camera from being less sensitive than as needed by the AWP to detect 

hydrocarbon emissions. If the detection sensitivity 60 grams per hour is acceptable to the 

commenter, then this final rule clearly specifies this requirement in which there is no issue with 

the AWP requirements in Subpart W. Please see preamble Section II.C. –Final Amendments to 

the Petroleum and Natural Gas Systems Source Category, Monitoring and QA/QC Requirements 

for further details. Although AWP was developed for VOCs, EPA notes that the limited use of 

AWP, which is an established standard whether widely used or not, is sufficient for the purposes 

of Subpart W, as the detection of methane using an IR camera is indeed well tested and 

documented in the Journal of Air and Waste Management (paper 6560-50-P), in EPA’s Natural 

Gas STAR Program presentations by FLIR 

(http://www.epa.gov/gasstar/documents/workshops/okcity2009/chk_flir.pdf) showing the 

methane absorption spectrum overlapping the IR camera detection range, and the EPA ETV 

(Environmental Technology Verification) program which used methane for the IR camera 

calibration for detecting other chemicals 

(http://www.epa.gov/nrmrl/std/etv/pubs/600r10160/600r10160vr.pdf).” Finally, EPA notes that 
143

the AWP requirements for Subpart W have been greatly simplified; please see preamble Section 

II.C. - Final Amendments to the Petroleum and Natural Gas Systems Source Category, 

Monitoring and QA/QC Requirements for further details. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029 

Comment Excerpt Number: 44 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] § 98.234 

Monitoring and QA/QC requirements. 

[highlighted text: REVISIONS TO ADD METHOD FLEXIBILITY AND TO ALLOW AN 

ALTERNATIVE TO AWP IN 60.18(i) THAT CAPTURES THE RELEVANT 

PERFORMANCE SPECS FOR DAILY QA/QC] 

The GHG emissions data for petroleum and natural gas emissions sources must be quality 

assured as applicable as specified in this section. Offshore petroleum and natural gas production 

facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 250. 

(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, except as provided in paragraph 

(a)(4) of this section. 

(1) Optical gas imaging instrument. Use an optical gas imaging instrument for equipment leak 

detection in accordance with [add: (i) or (ii).] 

[add: (i)] 40 CFR part 60, subpart A, §60.18(i)(1)[add: (i)] and (2) of the Alternative work 

practice for monitoring equipment leaks [add: with a detection sensitivity of 60 grams per hour]. 

Any emissions detected by the optical gas imaging instrument is a leak unless screened with 

Method 21 (40 CFR part 60, appendix A–7) monitoring, in which case 10,000 ppm or greater is 

designated a leak. [add: Video records per §60.18(i)(1)(ii) are not required.] [delete: In addition, 

you must operate the optical gas imaging instrument to image the source types required by this 

subpart in accordance with the instrument manufacturer's operating parameters.] 

[add: (ii) Operate the optical gas imaging instrument consistent with manufacturer operating 

procedures. The instrument must meet the specification in §60.18(i)(1)(i) and manufacturer 

procedures must include daily instrument check procedures similar to those in §60.18(i)(2) based 

on a detection sensitivity level of 60 grams methane per hour (equivalent to 3.1 SCFH) with a 

purity of no less than 98 percent by volume. Video records per §60.18(i)(1)(ii) are not required. 

(iii) An operator can elect to conduct annual optical gas imaging according to paragraph (i) or (ii) 

of this section to screen vents that require measurement under §98.233(o) and (p). Vent rate 
144

measurement is not required and the vent rate is recorded as zero if optical gas imaging does not 

detect vented gas.] 

Response: EPA agrees with the commenter that a 60 grams per hour detection sensitivity be 

stated in the rule and that no video recording be required. Please see preamble section II.C. –

Final Amendments to the Petroleum and Natural Gas Systems Source Category, Monitoring and 

QA/QC Requirements and the response to EPA-HQ-OAR-2011-0512-0029, Excerpt 21 for 

further details. Hence, in this final rule, EPA is finalizing these amendments in §98.234 (a)(1), 

and EPA does not consider it necessary to add separate items (i) and (ii), as suggested by the 

commenter. Additionally, EPA disagrees with the rule text amendments recommended by the 

commenter in (iii); please see the response to EPA-HQ-OAR-2011-0512-0029, Excerpt 19 for 

further details. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029 

Comment Excerpt Number: 47 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Optical gas imaging 

instrument. An optical gas imaging instrument must be used for [delete: all source types] [add: 

components requiring a leak survey] that are inaccessible and cannot be monitored without 

elevating the monitoring personnel more than 2 meters above a support surface. 

Response: In this final rule, EPA combined 40 CFR 98.234 (a)(4) with 40 CFR 98.234(a)(1) 

because both of these are applicable to optical gas imaging instruments. EPA is not 

implementing the change suggested by the commenter because it adds no additional clarity to the 

statement given the amendments in this final rule. 

Section 8.1.2 ­ Method 21

Commenter Name: 

Commenter Affiliation: Dow Chemical Company 

Document Control Number: EPA-HQ-OAR-2011-0512-0026 

Comment Excerpt Number: 2 

Commenter Type: Industry - other 

Comment: EPA should clarify the rule text to clarify that Method 21 compliant instruments 

may be used to monitor inaccessible fugitive emission sources. 

On Page 56034 of the Federal Register preamble, EPA explains that the language in 98.234(a)(2) 

is being amended to state that Method 21 compliant instruments may be used to monitor 

inaccessible emission sources. Dow supports this change as it does increase the flexibility in 

monitoring requirements and reduces the burden on industry without compromising data quality. 
145

However, the proposed rule text in 98.234(a)(1) and (2) is confusing. For example, the last 

sentence in 98.234(a)(1) states that: “An optical gas imaging instrument must be used for all 

sources types that are inaccessible and cannot be monitored without elevating the monitoring 

personnel more than 2 meters above a support surface.” Then, the last sentence of 98.234(a)(2) 

seems to allow the owner/operator to use the alternative leak detection devices as described in 

paragraph (a)(1) or (a)(2) of this section, which includes Method 21. 

Assuming the intent discussed in the preamble is correctly understood, Dow suggests that EPA 

clarify in both 98.234(a)(1) and (a)(2) that a Method 21 compliant instrument may be used to 

monitor inaccessible emission sources that are subject to the monitoring requirements. 

Response: EPA agrees with your comment, and in this final rule is adding language indicating 

that an optical gas imaging instrument must be used for all source types that are inaccessible and 

cannot be safely monitored using Method 21 compliant leak detection equipment. Please see 

preamble section II.C. –Final Amendments to the Petroleum and Natural Gas Systems Source 

Category, Monitoring and QA/QC Requirements for further details. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029 

Comment Excerpt Number: 45 

Commenter Type: Trade Association 

Comment: Method 21. Use the equipment leak detection methods in 40 CFR part 60, appendix 

A–7, Method 21. If using Method 21 monitoring, if an instrument reading of 10,000 ppm or 

greater is measured, a leak is detected. Inaccessible emissions sources, as defined in 40 CFR part 

60, are not exempt from this subpart. Owners or operators must use alternative leak detection 

devices as described in paragraph(a)(1) of this section to monitor inaccessible equipment leaks or 

vented emissions. 

Response: EPA thanks the commenter for their remarks and notes that this rule text has been 

amended to allow for alternative leak detection devices as described in paragraph (a)(2) in 

addition to (a)(1). Please see response to EPA-HQ-OAR-2011-0512-0026, Excerpt 2 for further 

details. 

Section 8.1.5 ­ Acoustic Leak Detection Device

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029 

Comment Excerpt Number: 48 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Acoustic leak 

detection device. Use the acoustic leak detection device to detect through-valve leakage. When 

using the acoustic leak detection device to quantify the through-valve leakage, you must use the 
146

instrument manufacturer's calculation methods to quantify the through-valve leak. When using 

the acoustic leak detection device, if a leak of 3.1 scf per hour or greater is calculated, a leak is 

detected. In addition, you must operate the acoustic leak detection device to monitor the source 

valves required by this subpart in accordance with the instrument manufacturer's operating 

parameters. [add: Acoustic devices that provide an audible leak signal but do not calculate a leak 

rate can be used to identify non-leakers with subsequent measurement required to calculate the 

rate if through-valve leakage is identified. Leaks are reported if a leak rate of 3.1 scf per hour or 

greater is measured.] 

Response: EPA agrees with the commenter. However, EPA disagrees that the September 2011 

proposal language needs to be revised, because the meaning of the proposed text is the same as 

the revised text provided by the commenter. 

Section 8.2 ­ Use Flow Meters

Commenter Name: Mike Hampton 

Commenter Affiliation: SandRidge Midstream, Inc. 

Document Control Number: EPA-HQ-OAR-2011-0512-0045 

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas 

Comment: Operations Overview 

One of the plants operated by SandRidge captures C02 for sale from an AGR vent stream 

composed of 95%+ C02, up to 5% methane and hydrocarbons, and trace nitrogen. If it cannot be 

sold, the stream is incinerated for VOC control, and as a last resort, if the incinerator (thermal 

oxidizer) is not available, the stream is vented to atmosphere. 

The AGR vent stream to atmosphere has a continuous flow monitor and a separate continuous 

gas analyzer, which are quality assured per the air permit requirement and manufacturer 

recommendations or industry standard methods. The exhaust gas is predominantly dry C02, and 

the stack gas temperature is typically 10-20 degrees F. 

SandRidge believes that the data generated from the existing monitoring equipment provides 

quality assured information that is the best data available for calculating emissions. 

Response: EPA has described all the Calculation Methodologies under AGRs sufficiently. The 

commenter may use the data generated from its existing monitoring equipment as long as this 

data follows one of the methodologies accurately, keeping in mind the hierarchy of the 

Calculation Methodologies. From the information provided by the commenter, EPA believes that 

the reporter must use methodology 1 or 2 in 98.233(d) to estimate emissions from their AGR 

units. EPA has relaxed the calibration criteria for methodologies 1 and 2; please see response to 

EPA-HQ-OAR-2011-0512-0045, Excerpt 3 for further details. 
147

Section 8.3 ­ Use Calibrated Bags

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA)

Document Control Number: EPA-HQ-OAR-2011-0512-0029 

Comment Excerpt Number: 50 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Use calibrated bags 

(also known as vent bags) only where the emissions are at near-atmospheric pressures [add: and 

below the maximum temperature specified by the vent bag manufacturer] such that [delete: it] 

[add: the bag] is safe to handle[add: .] [delete: and can capture all the emissions, below the 

maximum temperature specified by the vent bag manufacturer, and] [add: The bag must be of 

sufficient size that] the entire emissions volume can be encompassed for measurement. 

(1) Hold the bag in place enclosing the emissions source to capture the entire emissions and 

record the time required for completely filling the bag. If the bag inflates in less than one second, 

assume one second inflation time. 

(2) Perform three measurements of the time required to fill the bag, report the emissions as the 

average of the three readings. 

(3) Estimate natural gas volumetric emissions at standard conditions using calculations in 

§98.233(t). 

(4) Estimate CH4and CO2volumetric and mass emissions from volumetric natural gas emissions 

using the calculations in §98.233(u) and (v). 

Response: EPA agrees with the commenter and EPA is modifying this final rule accordingly. 

EPA notes that the bag opening, and not the bag, must be of sufficient size such that the entire 

emissions volume can be encompassed for measurement till the calibrated bag is completely 

filled. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042 

Comment Excerpt Number: 51 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added clarification to the requirements for using a calibrated bag that 

the temperature of the source to be measured must be below the maximum temperature specified 

by the manufacturer and that the bag must be of sufficient size that the entire volume can be 

encompassed for measurement. 
148

Comment: API requests clarification on EPA’s intent in stating “the bag must be of sufficient 

size that the entire volume can be encompassed for measurement.” This could be interpreted to 

mean that the bag must fit over the entire source being measured. Alternatively, this could be 

interpreted to mean that the bag must be sized to capture the venting volume within a specific 

time, recognizing, however, that the calibrated bag cannot measure the entire volume. 

Response: EPA is clarifying in this final rule that the entire volume of emissions must be tightly 

encompassed till the calibrated bag is filled. 

Section 8.4 ­ Use High Volume Sampler

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029 

Comment Excerpt Number: 51 

Commenter Type: Trade Association 

Comment: [Please refer to the original comment text posted in the docket] Use a high volume 

sampler to measure emissions within the capacity of the instrument. 

(1) A technician following manufacturer instructions shall conduct measurements, including 

equipment manufacturer operating procedures and measurement methodologies relevant to using 

a high volume sampler, including positioning the instrument for complete capture of the 

equipment leak without creating backpressure on the source. 

(2) If the high volume sampler, along with all attachments available from the manufacturer, is 

not able to capture all the emissions from the source then use anti-static wraps or other aids to 

capture all emissions without violating operating requirements as provided in the instrument 

manufacturer's manual. 

[add: (3) Estimate natural gas volumetric emissions at standard conditions using calculations in 

§98.233(t).] 

([delete: 3][add: 4]) Estimate CH4 and CO2 volumetric and mass emissions from volumetric 

natural gas emissions using the calculations in §98.233(u) and (v). 

([delete: 4][add: 5]) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 

100 percent CH4 by using calibrated gas samples and by following manufacturer's instructions 

for calibration. 

Response: EPA agrees with the commenter in regard to adding a reference to 40 CFR 98.233(t) 

for monitoring and QA/QC requirements for high volume samplers. However, in this final rule, 
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EPA is adding this reference in 40 CFR 98.234(d)(3) and hence, a change to the designation of 

40 CFR 98.234(d)(4) is not necessary. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042 

Comment Excerpt Number: 52 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA clarified that volumetric emissions from the high flow sampler must 

be at standard conditions using 98.233(t). 

Comment: API supports this revision with standard conditions defined as 60 oF and 14.7 psia. 

Response: EPA thanks the commenter for their remarks. EPA agrees with the commenter in 

regard to revising standard conditions as 60 oF and 14.7 psia. EPA is making the necessary 

changes in this final rule. Additionally, EPA is providing a ratio in 40 CFR 98.233(t)(3) for 

reporters who use 68°F for standard temperature to convert volumetric emissions from 68°F to 

60°F. 
150

Section 9 ­ Records that must be retained (98.237)

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 24 

Commenter Type: Trade Association

Comment: 17. The proposed new recordkeeping requirement in §98.237(e) should be deleted 

because the Monitoring Plan addresses similar requirements and this revision adds unnecessary 

burden. 

The Monitoring Plan required under Subpart A requires operators to document how data is 

collected and emission calculations are completed. The Proposed Rule adds new recordkeeping 

in §98.237(e), "The records required under §98.3(g)(2)(i) shall include an explanation of how 

company records, engineering estimation, or best available information are used to calculate each 

applicable parameter under this subpart." 

This new requirement is duplicative, may cause confusion, and adds unnecessary recordkeeping 

burden. Since the Monitoring Plan addresses similar criteria, this addition to Subpart W is not 

needed and §98.237(e) should be deleted. 

Response: EPA disagrees with the commenter that the recordkeeping requirements are 

duplicative and add unnecessary burden. The requirements in §98.3(g)(2)(i) were written to be 

generally applicable to all facilities. The recordkeeping requirement in §98.237(e) further 

clarifies this general requirement as it applies to subpart W, particularly with respect to the use of 

company records, engineering estimation or best available information. If this detailed 

information is already captured under a Monitoring Plan then it does not add burden to the 

reporter. It is important to note that, in §98.3(g)(2), EPA states only that records must be kept in 

an electronic or hard-copy format and recorded in a format that is suitable for expeditious 

inspection and review. If the Monitoring Plan meets all the requirements of 98.3(g) and 98.237, 

then this information may only have to be retained in one location. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 54 

Commenter Type: Trade 

Comment: [Please refer to the original comment text posted in the docket] § 98.237 Records 

that must be retained. 

Monitoring Plans, as described in §98.3(g)(5), must be completed by April 1, 2011. In addition 

to the information required by §98.3(g), you must retain the following records: 

(a) Dates on which measurements were conducted. 
151

(b) Results of all emissions detected and measurements [add: except video records from optical 

imaging conducted according to §98.234(a)(1) or (4) are not required]. 

Response: EPA agrees with the commenter and has addressed the exclusion for keeping video 

records within §98.234(a)(1). Please see the response to EPA-HQ-OAR-2011-0512-0029, 

Excerpt 21 and Section II.C. - Final Amendments to the Petroleum and Natural Gas Systems 

Source Category: Monitoring and QA/QC Requirements of the Preamble for further details. 
152

Section 10 ­ Definitions (98.238)

Section 10.1 ­ Associated With a Single Well­Pad

Commenter Name: William W. Grygar II 

Commenter Affiliation: Anadarko Petroleum Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0028

Comment Excerpt Number: 10 

Commenter Type: Industry - oil and gas 

Comment: [Please refer to the original comment text posted in the docket] The definition for 

"associated with a single well-pad" provides confusion in the last sentence, "this does not include 

storage and condensate tanks that are located downstream of the point of combination." This 

sentence could be interpreted either to imply that storage and condensate tanks downstream of 

the point of combination are included or are not included. Anadarko believes EPA's intent is to 

include these sources, and recommends that the regulatory text be revised to state the following: 

o With the exception of storage and condensate tanks, [add: t][delete: T]he association ends 

where the stream from a single well-pad is combined with streams from one or more additional 

single well-pads, where the point of combination is located off that single well-pad. [delete: This 

does not include storage and condensate tanks that are located downstream of the point of 

combination.] 

Response: In this final rule, EPA is amending the proposed definition of associated with a 

single well-pad in 40 CFR 98.238 and deleting the text “[t]his does not include storage and 

condensate tanks that are located downstream of the point of combination.” This revision 

clarifies that onshore production reporters do not report emissions from equipment that are not 

either on a single well-pad or associated with a single well-pad (as defined in 98.238). This same 

condition applies to storage and condensate tanks. However, under 98.233(j) onshore production 

reporters must report emissions from separators or tanks that are either on a single well-pad or 

associated with a single well-pad. EPA is making additional clarifications about reporting 

emissions under onshore production. For more details, please see preamble Section II.D.5 - 

Responses to Major Comments on the Petroleum and Natural Gas Systems Source Category: 

Associated with a single well-pad.   

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas 

Comment: [Please refer to the original comment text posted in the docket] A. Definitions – § 

98.238 

(1) “Associated with a single well-pad” – EPA has proposed a new term to clarify what 
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equipment is associated with a single well-pad. The inclusion of this term is fundamental to 

enabling reporters to determine what equipment must report under Subpart W. The proposed 

definition is not entirely clear and must be further modified as follows: 

Associated with a single well-pad means associated with the hydrocarbon stream as produced 

from one or more wells located on that single well-pad. [Add: With the exception of storage and 

condensate tanks,] [Delete: T] [Add: t] he association ends where the stream from a single wellpad is combined with streams from one or more additional single well-pads, where the point of 

combination is located off that single well-pad. [Delete: This does not include storage and 

condensate tanks that are located downstream of the point of combination.] 

As proposed, the last sentence is ambiguous because “this” could either be interpreted as 

clarifying that tanks downstream of the combination point are or are not associated with a single 

well-pad. We believe that EPA meant the former. This definition must be modified to remedy 

this ambiguity. 

Response: Please see response to EPA-HQ-OAR-2011-0512-0028, Excerpt 10. 

Commenter Name: Vince Alaimo 

Commenter Affiliation: Marshall Miller & Associates Inc. on behalf of Consol Energy Inc. 

Document Control Number: EPA-HQ-OAR-2011-0512-0036

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas 

Comment: Associated With a Single Well-Pad 

EPA is proposing to add a definition for ‘‘associated with a single well-pad’’ to clearly 

demarcate the boundary of onshore production. EPA proposes that the association be defined by 

the hydrocarbon stream from a single wellpad. The association with a single wellpad ends where 

the stream from a single well-pad is combined with streams from one or more additional single 

well-pads, where the point of combination is located off that single well-pad. In addition, EPA is 

stating that this definition does not include storage and condensate tanks that are located 

downstream of the point of combination. For gas contained in crude oil or condensate flowing 

under pressure off a single well-pad to a gas liquid separator or tank, or comingled with flow 

from other well-pads, 40 CFR 98.233(j) requires reporting of the gas content that may be 

released from the oil or condensate in an atmospheric pressure fixed roof storage tank. EPA has 

determined that the conditions of the pressurized oil or condensate (i.e., gravity, pressure, 

temperature, flow rate) are commonly known by the well owner/operator, and the amount of gas 

that may be released from the oil or condensate with a pressure reduction. 

In some remote areas the tie in with other wells may be miles from the well pad. As such Consol 

Energy Inc. proposes to limit the distance “associated with a well pad” to a maximum of 1⁄4 mile 

from the actual wellpad. 

Response: EPA disagrees with the commenter with regards to defining “associated with a single 

well-pad” with a distance limit of a maximum of 1⁄4 mile from the actual wellpad, because 

distance is neither a reliable or consistent indicator of what is “associated with”. Instead, EPA is 
154

finalizing, as proposed, that the association ends where the stream from a single well-pad is 

combined with streams from one or more additional single well-pads, where the point of 

combination is located off that single well-pad. This physical demarcation ensures more 

comparable treatment across reporters for the type of equipment and processes included in the 

onshore oil and gas production segment. For further information, please see response to EPAHQ-OAR-2011-0512-0028, Excerpt 10. 

Commenter Name: Yasmeen Sultana 

Commenter Affiliation: ERM 

Document Control Number: EPA-HQ-OAR-2011-0512-0039

Comment Excerpt Number: 1 

Commenter Type: Other 

Comment: Existing and proposed changes to Subpart W of the EPA GHG Reporting Rule do 

not adequately address typical onshore oil and gas production facilities in California. Much of 

California produces heavy oil, with many more shallow wells (most reservoirs are < 4,000 ft 

deep) in close proximity to each other. Most of the oil is produced with the aid of steam 

injection. It is not uncommon for an operator to have several thousand wells with associated, 

shared process equipment that is located where space is available. Please see Attachment 1. [See 

original comment for attachment]. 

From the initial introduction of the facility definition in the Subpart W Pre-publication Rule of 

10 March 2010, EPA has proposed language changes several times that have impacted the 

applicability of equipment source types for onshore petroleum and natural gas facilities. EPA 

states that, “...the proposed amendments would not change the overall requirements, but 

improve clarity and consistency across the calculation, monitoring and data reporting 

requirements.” However, it appears that EPA is trying to clarify applicability of certain 

equipment types based on both their geographical location (on a well pad) within an oil field and 

their location within a process (associated with a single well pad). 

The latest proposed changes to the Subpart W regulation (8/19/2011) implies that only 

equipment used at onshore oil and gas production facilities that is on a single well pad, or 

associated with a single well pad is included in the reported calculated emissions under Subpart 

W. Depending on the interpreted definition, not all equipment types (for which a GHG 

calculation method has been provided) have the potential to be “associated with a single well 

pad” (i.e., hydrocarbon stream dependent): storage tanks; however, every equipment type has the 

potential to be on a single well pad. 

Although EPA has clarified “associated with a single well pad,” a clear definition of well pad 

does not exist in the current Subpart W regulation or any proposed revisions. This creates 

ambiguity in applicability of Subpart W to equipment in California’s oil field operations where 

the process equipment (including combustion) is in close proximity to several wells but typically 

serves entire oil field’s (and sometimes several fields’) operations. Using the latest proposed 

language, the same type of equipment can be included into the facility at some locations and 

excluded at others, solely based on the physical location or location within the process stream; 

exclusive of the emissions potential. 
155

This lack of clear definition has a big impact on stationary combustion emission sources. Except 

for some process heaters, none of the stationary combustion emission sources are “associated 

with a single well pad”; therefore, their inclusion and exclusion will depend solely on their 

geographical location, and if that location is interpreted as being on a well pad. 

Stationary combustion emission sources that are determined to be on a well pad are part of the 

Subpart W Onshore petroleum and natural gas production Industrial Segment. Within Subpart 

W, combustion emission sources are required to be grouped by type of unit (assumed well 

drilling and completion equipment, workover equipment, natural gas dehydrators, natural gas 

compressors, electrical generators, steam boilers, and process heaters). Combustion emission 

sources that are determined to be not on a well pad, are not part of the Subpart W Onshore 

petroleum and natural gas production Industrial Segment. Therefore, it is assumed that these 

sources, excluding portable equipment, would fall within the applicability of Subpart C, much 

like they were for 2010 calendar year emissions. Within Subpart C, combustion emissions are 

essentially grouped by fuel type. Fuel meters selected (often common pipe meters with several 

unit types), and in some cases installed, to measure shared fuel by fuel type for Subpart C 

reporting will not be adequate to measure fuel by type of unit. Stationary combustion emission 

sources that are interpreted to be on a well pad will require the purchase and installation of 

additional fuel meters to enable quantification and reporting by unit type as required by Subpart 

W. Operators drill several hundreds to thousands of wells every year and established down hole 

well patterns create congested surface locations. As a result, the applicability of Subpart W or C 

to existing combustion equipment depends on their location with respect to the newly drilled 

wells. Applicability and reporting “bucket” (Subpart C or Subpart W) has to be determined every 

time a new well is drilled. This requires rigorous additional monitoring of existing equipment 

and exhaustive applicability determinations creating unnecessary burden on operators with 

several thousand wells without increasing the amount or quality of reported emissions (emissions 

are reported either under Subpart C or Subpart W). 

Recommendation: At this point there is no clear direction on how to identify equipment that is 

located on a single well pad. However, actions associated with these decisions needs to happen 

fast (especially for stationary combustion emissions report due for Subpart C reporting in March 

2012) to ensure compliance with the EPA GHG reporting requirements. With this letter, we are 

requesting further clarification on the definition of a single well pad to enable applicability 

determinations for stationary combustion equipment. Operators would prefer a definition that 

does not change applicability of Subpart C versus Subpart W to combustion equipment every 

year. We have provided Attachment 1 to depict actual well sites and equipment configurations. 

[See original comment for attachment]. 

Given the timing of the initial data gathering and reporting activities, your prompt attention to 

this matter would be appreciated. The issues addressed above apply to many California oil and 

gas sources and therefore, publication of a clarification in the Federal Register is probably 

appropriate. However, any near term information you could provide would be greatly 

appreciated. 

Response: EPA acknowledges the variations in well and equipment arrangements within 

onshore production. Although some equipment may be perceived as being in either the 
156

production or gathering segment, it might be challenging to develop a demarcation that can 

capture all such nuances. Hence, the physical demarcation point is the most optimal method for 

the purposes of reporting GHG emissions. Therefore, EPA has chosen a physical point of 

demarcation, i.e. on a single well-pad or associated with a single well-pad, to separate the 

onshore production segment from the gathering and boosting segment of the oil and gas industry. 

The reference to “on a single well pad, or associated with a single well pad” was in the 2010 

final rule and was not changed further in the proposed amendments. The proposal merely 

defined this term to provide the clarity that the commenter is seeking. Please see preamble 

Section II.D.5 - Responses to Major Comments on the Petroleum and Natural Gas Systems 

Source Category: Associated with a single well-pad. 

EPA disagrees with the comment on the definition of a “well-pad”. EPA defined a well-pad in 

the November 2010 final rule; please see the definition for “wellhead” in 40 CFR 98.6. Also 

note that EPA is amending the proposed definition of associated with a single well-pad in 40 

CFR 98.238 to clarify the application to storage tanks; please see response to EPA-HQ-OAR2011-0512-0028, Excerpt 10. 

EPA disagrees with the comment that combustion sources on a well-pad will require the 

purchase and installation of fuel meters, as 40 CFR 98.233(z) allows the use of company records 

to determine the volume of fuel combusted. EPA disagrees with the comment that it is onerous 

to determine if combustion equipment is on a single well-pad or associated with a single wellpad. Further, if a piece of equipment is not on a well pad or associated with a well pad, and 

covered under subpart C, it is unlikely to trigger the threshold for reporting under subpart C 

alone. Hence, EPA has not changed the requirements for combustion equipment reporting for 

onshore production. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 70 

Commenter Type: Industry - oil and gas

Comment: [Please refer to the original comment text posted in the docket] Revision: EPA 

added a new definition for “associated with a single well-pad”. 

Comments: EPA needs to clarify what the word “This” is referring to in the beginning of the last 

sentence. API suggests the following revisions to the definition as shown in green font: 

Associated with a single well-pad means associated with the hydrocarbon stream as produced 

from one or more wells located on that single well-pad. [add (green): For all equipment with the 

exception of storage and condensate tanks], the[add (green): exclusion for the] association ends 

where the stream from a single well-pad is combined with streams from one or more additional 

single wellpads, where the point of combination is located off that single well-pad. [delete 

(green): This does not includes storage and condensate tanks that are located downstream of the 

point of combination.] 

API offers the diagrams provided in Section 3, which illustrate API’s understanding of the 
157

proposed definition for “associated with a well-pad” and the proposed revised source category 

definition for onshore petroleum and natural gas production. API is providing this information to 

companies as a tool to guide industry to classify their emission sources for data collection and 

reporting, although we realize that it is too cumbersome to include in regulatory language. 

Response: Please see response to EPA-HQ-OAR-2011-0512-0028, Excerpt 10. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 80 

Commenter Type: Industry - oil and gas 

Comment: Scenario 1 – Central Tank Battery with Heater Treater 

Response: In the commenter’s example Scenario 1, EPA agrees with the classifications, with 

the exception that “condensate storage” is not part of onshore production, because the input 

stream to the condensate storage tank is a combination of multiple streams from equipment 

associated with one or more additional single well-pads. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 81 

Commenter Type: Industry - oil and gas 
158

Comment: Scenario 2 – Central Tank Battery or Booster Station

Response: In the commenter’s example Scenario 2, EPA agrees with the classifications, with 

the exception that “condensate storage” is not part of onshore production, because the input 

stream to the condensate storage tank is a combination of multiple streams from equipment 

associated with one or more additional single well-pads. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 82 

Commenter Type: Industry - oil and gas 
159

Comment: Scenario 3 – Central Tank Battery or Booster Station 

Response: In the commenter’s example Scenario 3, EPA agrees with the classifications, with 

the exception that “condensate storage” is not part of onshore production, because the input 

stream to the condensate storage tank is a combination of multiple streams from equipment 

associated with one or more additional single well-pads. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 83 

Commenter Type: Industry - oil and gas 
160

Comment: Scenario 4 – Central Tank Battery or Booster Station 

Response: In the commenter’s example Scenario 4, EPA agrees with the classifications, with 

the exception that “condensate storage” is not part of onshore production, because the input 

stream to the condensate storage tank is a combination of multiple streams from equipment 

associated with one or more additional single well-pads. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 84 

Commenter Type: Industry - oil and gas
161

Comment: Scenario 5 – Multi-Well Pad 

Response: In the commenter’s example Scenario 5, EPA conditionally agrees with the 

classifications. If the dry gas leaving the well-pad in Scenario 5 does not enter equipment(s) that 

is under common-control or common ownership of the reporter, then Scenario 5 is correct. 

However, if there is equipment(s) that is associated with a single well-pad in Scenario 5 and is 

under common-control or common ownership of the reporter, then that equipment(s) is a part of 

onshore production and the reporter must monitor and report emissions from such equipment(s). 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 85 

Commenter Type: Industry - oil and gas 
162

Comment: Scenario 6 – Remote Well Pad to Satellite Well Pad 

Response: In the commenter’s example Scenario 6, EPA conditionally agrees with the 

classifications. If the dry gas leaving the well-pad in Scenario 6 does not enter equipment(s) that 

is under common-control or common ownership of the reporter, then Scenario 6 is correct. 

However, if there is equipment(s) that is associated with a single well-pad in Scenario 6 and is 

under common-control or common ownership of the reporter, then that equipment(s) is a part of 

onshore production and the reporter must monitor and report emissions from such equipment(s). 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 86 

Commenter Type: Industry - oil and gas 
163

Comment: Scenario 7 – Condensate Stabilization Plant 

Response: In the commenter’s example Scenario 7, EPA disagrees that the “stabilization plant” 

is not natural gas processing, because of the fractionation of hydrocarbon liquids into component 

mixtures. EPA also disagrees that “condensate storage” is part of onshore production. If the dry 

gas leaving the well-pad in Scenario 7 does not enter equipment(s) that is under common-control 

or common ownership of the reporter, then the designation of onshore production equipment in 

Scenario 7 is correct. However, if there is equipment(s) that is associated with a single well-pad 

in Scenario 7 and is under common-control or common ownership of the reporter then that 

equipment(s) is a part of onshore production and the reporter must monitor and report emissions 

from such equipment(s). 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 87 

Commenter Type: Industry - oil and gas
164

Comment: Scenario 8 – Central Produced Water Injection Facility 

Response: In the commenter’s example Scenario 8, EPA conditionally agrees with the 

classifications. If the dry gas leaving the well-pad in Scenario 8 does not enter equipment(s) that 

is under common-control or common ownership of the reporter, then Scenario 8 is correct. 

However, if there is equipment(s) that is associated with a single well-pad in Scenario 8 and is 

under common-control or common ownership of the reporter, then that equipment(s) is a part of 

onshore production and the reporter must monitor and report emissions from such equipment(s). 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 88 

Commenter Type: Industry - oil and gas
165

Comment: Scenario 9 – Central Tank Battery with Independent Separators 

Response: In the commenter’s example Scenario 9, EPA disagrees that “separators” are not part 

of onshore production, because each separator is associated with a single well-pad. EPA also 

disagrees that “condensate storage” is part of onshore production, because the input stream to the 

condensate storage tank is a combination of multiple streams from equipment associated with 

one or more additional single well-pads. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 89 

Commenter Type: Industry - oil and gas
166

Comment: Scenario 10 – Remote Well Pad to Satellite Well Pad with Compression 

Response: In the commenter’s example Scenario 10, EPA conditionally agrees with the 

classifications. If the dry gas leaving the well-pad in Scenario 10 does not enter equipment(s) 

that is under common-control or common ownership of the reporter, then Scenario 10 is correct. 

However, if there is equipment(s) that is associated with a single well-pad in Scenario 10 and is 

under common-control or common ownership of the reporter, then that equipment(s) is a part of 

onshore production and the reporter must monitor and report emissions from such equipment(s). 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 79 

Commenter Type: Industry - oil and gas

 Comment: Section 3: Production Configuration Diagrams 

As referenced in Comment W.52 [EPA-HQ-OAR-2011-0512-0042, Excerpt 70], the following 
167

diagrams illustrate API’s understanding of the proposed definition for “associated with a wellpad” and the proposed revised source category definition for onshore petroleum and natural gas 

production. In these diagrams, blue shading indicates equipment “associated with a well-pad”, 

and red shading indicates equipment that is not part of the onshore petroleum and natural gas 

source category nor part of the onshore natural gas processing source category. These diagrams 

were distributed to the API member companies as a tool to guide industry in classifying their 

emission sources for data collection and reporting. 

[See original comment for Scenario, Well Pad Equipment, Facility Processes Table] 

Response: For EPA’s agreements and disagreements with the Production Configuration 

Diagrams submitted by the commenter, please see the responses to EPA-HQ-OAR-2011-0512-

0042, Excerpt 80 through EPA-HQ-OAR-2011-0512-0042, Excerpt 89. 

Section 10.3 ­ Facility With Respect to Natural Gas Distribution  

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 56 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added the following to the reporting requirements: “Report the 

information listed in this paragraph for each applicable source type. If a facility operates under 

more than one industry segment, each piece of equipment should be reported under its respective 

majority use segment...” 

Comment: The use of “facility” here is confusing. It is not clear how a “facility” in the context of 

Subpart W can operate under more than one industry segment. Is this statement meant to address 

equipment rather than facilities? For example, a well located within a gas plant or residue 

compression adjacent to a gas plant, are two examples where specific equipment might be 

operated under more than one industry segment. API requests clarification on EPA’s intention 

with this statement and guidance on how these two examples should be reported. 

Response: There are situations in which more than one industry segment could be located in 

one facility. Where there is co-located or dual use equipment, reporters should consider the 

following when evaluating applicability: 

1) As a first step the reporter must determine the emissions from all equipment listed in 

98.232(c) for onshore petroleum and production. Per section 98.231(a) only sources listed 

in 98.232(c) need to be considered for threshold determination for onshore petroleum and 

natural gas production. 98.238 defines “facility” for the purposes of onshore petroleum 

and natural gas systems. Per the requirements of 98.3 each “facility” must submit a GHG 

report for all source categories at that “facility”. 

2) Note that while identifying onshore production emissions sources reporters have to 

determine whether the source is “on the well pad or associated with a well pad”. The 

location of production wells within other facilities is inconsequential to this 
168

determination. Sources on a single well pad or associated with a single well pad across 

the entire reporting basin have to be taken into consideration. If your emissions from 

onshore petroleum and natural gas production are equal to or greater than 25,000mtCO2e, 

then onshore petroleum and natural gas production facilities report as a separate facility 

and include all emissions sources listed in 98.232(c). 

3) Except for onshore petroleum and natural gas production and natural gas distribution, 

which have unique facility definitions, all other segments subject to subpart W are 

considered in the threshold determination for a single facility. You would also include 

emissions from other source categories at your facility (e.g., stationary combustion). If 

there are emissions sources that are dual purpose then the rule requires this piece of 

equipment to be reported under the majority use industry segment based on guidance 

provided in EPA-HQ-OAR-2009-0923-1024, Excerpt 14 of the Reporting Rule Subpart 

W – Petroleum and Natural Gas: EPA's Response to Public Comments. 

4) For collocated industry segments, which cannot occur in the case of onshore petroleum 

and natural gas production and natural gas distribution due to the requirements in 

98.231(a), EPA has provided guidance on emissions reporting in EPA-HQ-OAR-2009-

0923-1024, Excerpt 14 of the Reporting Rule Subpart W – Petroleum and Natural Gas: 

EPA's Response to Public Comments. 

Section 10.4 ­ Facility with Respect to Onshore Petroleum and Natural Gas

Production

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 5 

Commenter Type: Industry - oil and gas 

Comment: “Facility with respect to onshore petroleum and natural gas production” – We 

generally support the modifications made to this definition; however, EPA should exclude from 

this definition dehydrators that are located on or associated with a single well-pad if the 

dehydrator is owned and operated by a third-party. In such cases, these dehydrators are owned 

and operated by a third-party company contracted by the well operator. The well operator does 

not control the dehydrator, may not handle it, and cannot conduct maintenance on the dehydrator 

even if it is located at the well site. In some cases, the well operator no longer owns the gas going 

through this equipment as there has already been a transfer of custody of the gas to the thirdparty. Therefore, such third-party owned and operated dehydrators are better classified as 

gathering and boosting equipment. Hence, third-party owned and operated dehydrators should be 

required to report under forthcoming regulations that will cover these activities. EPA should 

clarify that emissions from dehydrators owned and operated by third parties should not be 

reported under § 98.232(c)(1), (14), (22). 
169

Response: The reporter has to determine whether or not equipment within their facility has to 

report depending on whether the reporter has common ownership or common control over the 

equipment. Please see preamble Section II.D.10 – Responses to Major Comments on the 

Petroleum and Natural Gas Systems Source Category: Dehydrators owned and operated by third 

parties. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 71 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA modified the definition for “facility” as shown: 

Facility with respect to onshore petroleum and natural gas production for purposes of [add (red): 

reporting under] this subpart and for [add (red): the corresponding] subpart A [add (red): 

requirements] means all petroleum or natural gas equipment on a well- pad or associated with a 

wel[add (red): -] pad and CO2 EOR operations that are under common ownership or common 

control including leased, rented, or contracted activities by an onshore petroleum and natural gas 

production owner or operator and that are located in a single hydrocarbon basin as defined in 

§98.238. Where a person or entity owns or operates more than one well in a basin, then all 

onshore petroleum and natural gas production equipment associated with all wells that the person 

or entity owns or operates in the basin would be considered one facility. 

Comments: API supports this revision. 

Response: EPA thanks the commenter for their remarks. Additionally, in this final rule, EPA is 

adding the word “single” to the first sentence of this definition to clarify that the petroleum or 

natural gas equipment must be on a “single” well-pad or associated with a “single” well-pad. 

Section 10.7 ­ Forced extraction of natural gas liquids

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 6 

Commenter Type: Industry - oil and gas 

Comment “Forced extraction of natural gas liquids” – Chesapeake and AXPC support EPA’s 

proposed definition for this term. 

Response: EPA thanks the commenter for their remarks. 
170

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 72 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added a new definition for “forced extraction”. 

Forced extraction of natural gas liquids means removal of ethane or higher carbon number 

hydrocarbons existing in the vapor phase in natural gas, by removing ethane or heavier 

hydrocarbons derived from natural gas into natural gas liquids by means of a forced extraction 

process. Forced extraction processes include but are not limited to refrigeration, absorption (lean 

oil), cryogenic expander, and combinations of these processes. Forced extraction does not 

include in and of itself; natural gas dehydration, or the collection or gravity separation of water 

or hydrocarbon liquids from natural gas at ambient temperature or heated above ambient 

temperatures, or the condensation of water or hydrocarbon liquids through passive reduction in 

pressure or temperature, or portable dewpoint suppression skids. 

Comment: API supports the addition of this definition 

Response: EPA thanks the commenter for their remarks. 

Section 10.9 ­ Horizontal well

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 73 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added a new definition for “horizontal well”: 

Horizontal well means a well bore that has a planned deviation from primarily vertical to a 

primarily horizontal inclination or declination tracking in parallel with and through the target 

formation. 

Comment: API supports the addition of this definition. 

Response: EPA thanks the commenter for their remarks. 

Section 10.10 ­ Metering­regulating station

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 
171

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 4 

Commenter Type: Trade Association 

Comment: The term “metering-regulating station” is also defined in revised §98.238. We 

believe this is the clearer term and should be used consistently instead of “meter-regulating 

station" as used in the TD station definition above. The Proposal defines the term meteringregulating station to mean: 

“A station that meters the flowrate, regulates the pressure, or both, of natural gas in a natural gas 

distribution facility. This does not include customer meters, customer regulators, or farm taps.” 

Exclusion of Farm Taps and Customer Meters and Regulators: AGA very much appreciates the 

exclusion of customer meters, regulators and farm taps. This will avoid sweeping millions of 

customer facilities into the reporting rule, thereby avoiding an untenable burden on LDC 

resources. We also appreciate the clarity of the definition. However, we believe the definition is 

unduly broad. We understand that the term Metering-regulating station includes stations that 

have just a meter but no regulator, stations that have just a pressure regulator but no meter, and 

stations that have both a meter and a regulator. It is still our understanding however, that 

equipment that the LDC does not own or operate would not be included because this equipment 

is not part of the LDC distribution “facility.” 

Response: In this final rule, EPA is amending the term “meter-regulating station” to “meteringregulating station” to make it consistent with the definition. The commenter has not provided any 

technical reason as to why the definition for metering-regulating station is broad and how this 

places undue burden on reporters. The commenter’s understanding that stations with only meters, 

only regulators, or both meters and regulators are considered metering-regulating stations is 

correct as per the requirements of this final rule. EPA notes that the reporters only have to 

conduct leak detection at T-D transfer stations and apply a meter/regulator run factor to 

metering-regulating stations. Hence, there is no burden to monitor metering-regulating stations 

other than to determine a count of such facilities. 

Natural gas distribution reporters must determine whether equipment, which is not owned or 

operated, is under common ownership or common control. Emissions from sources that are 

under common ownership or common control of the reporter must be reported. 

Section 10.11 ­ Pressure grouping

Commenter Name: William W. Grygar II 

Commenter Affiliation: Anadarko Petroleum Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0028

Comment Excerpt Number: 11 

Commenter Type: Industry - oil and gas 
172

Comment: For the liquids unloading emissions calculations EPA provides a definition of 

pressure groupings. The exact pressure to use; however, is not defined. Downhole pressure is not 

available; however tubing and gas-line pressure are readily available data sets that may be used 

for this calculation. 

Response: In this final rule, EPA is clarifying that reporters may use shut-in pressure, surface 

pressure, or casing pressure. If casing pressure is not available for each well then the operator 

may determine the casing pressure by multiplying the tubing pressure of each with a ratio of 

casing pressure to tubing pressure from a well in the same sub-basin where 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. 

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 8 

Commenter Type: Industry - oil and gas 

Comment: Pressure groupings – The proposed definition for pressure groupings is silent 

regarding where reporters must measure the pressure. This definition must clarify whether 

reporters must use the surface pressure or the reservoir shut-in pressure. See also API’s comment 

W.56 [EPA-HQ-OAR-2011-0512-0042, Excerpt 74] in Section 2 of its October 24, 2011 letter to 

EPA. 

Response: In this final rule, EPA is clarifying that shut-in pressure, surface pressure, or casing 

pressure may be used in estimating emissions from well liquids unloading. Please see response 

to EPA-HQ-OAR-2011-0512-0028, Excerpt 11. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 74 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added a new definition for “pressure groupings”: 

Pressure groupings are defined as follows: less than or equal to 25 psig; greater than 25 psig and 

less than or equal to 60 psig; greater than 60 psig and less than or equal to 110 psig; greater than 

110 psig and less than or equal to 200 psig; and greater than 200 psig. 

Comments: 

• As noted in comment (EPA-HQ-OAR-2011-0512-0042, Excerpt 74), the pressure groupings 

only apply to Methodology 1 for the liquids unloading emission source. 
173

• Also as noted in comment (EPA-HQ-OAR-2011-0512-0042, Excerpt 74), above, Methodology 

1 indicates that the pressure groupings apply across each of the sub-basin category (conventional 

and unconventional) and tubing grouping. This is inconsistent with previous discussions with 

EPA, where pressure grouping were discussed only in the context of conventional wells. API 

requests that the regulatory language clarify that pressure groupings are only applicable to 

conventional wells. 

• In discussions with EPA and an e-mail sent on June 22, 2011, API proposed two pressure 

groupings for Conventional formations based on flowing wellhead pressure. API requests that 

the pressure groupings be limited to two pressure groupings as originally proposed by the API. 

Based on the pressure regimes EPA included in this amendment, the two recommended pressure 

groupings would be < 110 psig and > 110 psig. Requiring five pressure groupings for three 

tubing diameter groupings and four formation types per county is excessive considering the 

logistics involved with capturing calibrated metered vent rates. Two pressure groupings will still 

provide EPA with the desired representative data and sufficient data granularity for future policy 

development. API recognizes that there may be some concerns regarding the range of the two 

proposed pressure groupings and would propose that the pressure of the representative metered 

vent rates be within ±10% of the average pressure of the range (S P / well count) to address this 

issue. 

• EPA does not define what pressure is to be used for the pressure groupings. API interprets the 

pressure groupings to be based on the surface pressure. As EPA indicated in Appendix D of the 

Technical Support Document associated with these proposed amendments, reservoir shut-in 

pressure is not available in the public domain. API agrees with this assessment, and as indicated 

in Comment W.14 reservoir shut-in pressure is not reliably available in operations either. 

Response: EPA notes that the language in the rule sufficiently indicates that the pressure 

grouping applies only to the gas well liquids unloading monitoring method. Hence, EPA is not 

making any changes to this effect in final rule. EPA agrees that the pressure grouping and subbasin category should apply only to Method 1. However, for methods 2 and 3, the data reporting 

is required at a sub-basin level. For further details, please see the preamble Section II.D.1 – 

Responses to Major Comments on the Petroleum and Natural Gas Systems Source Category: 

Pressure groupings. 

EPA has deleted the term conventional and unconventional from the definition of sub-basin 

category, since it has different connotations in the industry. As regards the pressure grouping, 

since they apply to only one emission source, i.e. gas well liquids unloading, reporters have to 

apply the pressure grouping to any sub-basin category where gas well liquid unloading occurs, if 

they are using Calculation Methodology 1 in 40 CFR 98.233(f). 

Regarding the suggestion to limit the number of pressure groupings to two; as discussed in the 

proposed rule, EPA analyzed different numbers of pressure groupings and selected the optimal 

number of pressure groupings that resulted in minimal error while managing burden. The EPA 

error estimates were developed using the mean pressure value within each range. EPA estimates 

that using five pressure groupings would result in a possible national average error of 

approximately 30% from all wells that report for the well liquids unloading emissions source. 
174

The API suggestion to decrease the pressure groupings to two would result in a possible national 

average error increase to approximately 65%. For background on the analysis, please see “2011 

Technical Revisions to the Petroleum and Natural Gas Systems Category of the GHG Reporting 

Rule: Summary of questions raised on Subpart W” docket number EPA-HQ-OAR-2011-0512-

0015 and “Sub-Basin Entity Pressure Range Analysis” docket number EPA-HQ-OAR-2011-

0016, and preamble Section II.C – Final Amendments to the Petroleum and Natural Gas Systems 

Source Category – Well Venting for Liquids Unloading and Section II.D.1 – Responses to Major 

Comments on the Petroleum and Natural Gas Systems Source Category: Pressure groupings. 

Hence, EPA has retained the five pressure ranges for Monitoring method 1 for well venting from 

liquids unloading in this final rule. Reporters are to estimate emissions from one well with a 

unique tubing diameter grouping and pressure grouping combination in a sub-basin, and apply 

that value to all wells with that tubing diameter grouping and pressure grouping in that same subbasin. Additionally, EPA has provided alternative calculation methodologies that do not require 

any measurement to calculate the total emissions for well venting for liquids unloading with or 

without plunger lifts in Equations W-9 and W-8. 

In this final rule, EPA is clarifying that shut-in pressure, surface pressure, or casing pressure may 

be used in estimating emissions from well liquids unloading. Please see response to EPA-HQOAR-2011-0512-0028, Excerpt 11. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 95 

Commenter Type: Industry - oil and gas 

Comment: National Gas Well Counts 

EPA posted several supporting documents to Docket EPA–HQ–OAR–2011–0512 on August 18, 

2011. The file, “Sub-basin Well Counts by Group Type 2010”, includes a listing of gas wells by 

state, county, formation type, pressure grouping, and reservoir name from the 2010 HPDI© data 

listing. API has reviewed this information and found that the gas well counts from this file 

(355,082 gas wells for 2010) are significantly less than the 2009 gas well counts available from 

EIA (493,100 from http://www.eia.gov/dnav/ng/ng_prod_wells_s1_a.htm). 

In addition, API found that all of Southwest Wyoming wells are listed as Conventional <25 psi 

when these are actually almost 100% tight sand and run with surface pressures of between 200 

and 600 psi. This raises concerns with the HPDI data posted by EPA. 

API therefore questions whether these discrepancies are: 

• artifacts of the query used to pull the data; 

• indications that the HPDI database does not have the proper data in their database and EPA 

assumed blank is zero (<25) for pressure and blank is conventional/other for formation type; or 
175

• indications that data are simply not available in any of the databases. 

API requests additional information on the well counts contained in the HPDI data listing, 

including an explanation of any algorithms and assumptions used in classifying wells, as well as 

an explanation for the differences between the HPDI gas well totals and gas well counts reported 

by EIA. 

Response: EPA provided the mapping of sub-basin categories in the docket as guidance to 

reporters. The sub-basin categories were developed using the HPDI© database, which is a 

commercially available data base that is compiled of specific data on onshore producers. The 

data within the HPDI © database is developed using data gathered from States by oil and gas 

operators. EPA in developing the sub-basin categories has made best engineering judgment on 

certain data elements where data were not available in HPDI©. However, EPA reiterates that the 

listing which maps sub-basin categories that was provided in the docket has been provided as 

guidance only. The responsibility for determining the correct sub-basin category listing using 

the criteria outlined in 40 CFR part 98, Subpart W ultimately lies with the Subpart W reporter. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 74 

Commenter Type: Industry - oil and gas 

Comment: Revision: EPA added a new definition for “pressure groupings”: 

Pressure groupings are defined as follows: less than or equal to 25 psig; greater than 25 psig and 

less than or equal to 60 psig; greater than 60 psig and less than or equal to 110 psig; greater than 

110 psig and less than or equal to 200 psig; and greater than 200 psig. 

Comments: 

• As noted in comment W.13 [EPA-HQ-OAR-2011-0512-0042, Excerpt 29], the pressure 

groupings only apply to Methodology 1 for the liquids unloading emission source. 

• Also as noted in comment W.13 [EPA-HQ-OAR-2011-0512-0042, Excerpt 29], above, 

Methodology 1 indicates that the pressure groupings apply across each of the sub-basin category 

(conventional and unconventional) and tubing grouping. This is inconsistent with previous 

discussions with EPA, where pressure grouping were discussed only in the context of 

conventional wells. API requests that the regulatory language clarify that pressure groupings are 

only applicable to conventional wells. 

• In discussions with EPA and an e-mail sent on June 22, 2011, API proposed two pressure 

groupings for Conventional formations based on flowing wellhead pressure. API requests that 

the pressure groupings be limited to two pressure groupings as originally proposed by the API. 

Based on the pressure regimes EPA included in this amendment, the two recommended pressure 
176

groupings would be < 110 psig and > 110 psig. Requiring five pressure groupings for three 

tubing diameter groupings and four formation types per county is excessive considering the 

logistics involved with capturing calibrated metered vent rates. Two pressure groupings will still 

provide EPA with the desired representative data and sufficient data granularity for future policy 

development. API recognizes that there may be some concerns regarding the range of the two 

proposed pressure groupings and would propose that the pressure of the representative metered 

vent rates be within ±10% of the average pressure of the range (S P / well count) to address this 

issue. 

• EPA does not define what pressure is to be used for the pressure groupings. API interprets the 

pressure groupings to be based on the surface pressure. As EPA indicated in Appendix D of the 

Technical Support Document associated with these proposed amendments, reservoir shut-in 

pressure is not available in the public domain. API agrees with this assessment, and as indicated 

in Comment W.14 [EPA-HQ-OAR-2011-0512-0042, Excerpt 30] reservoir shut-in pressure is 

not reliably available in operations either. 

Response: EPA notes that the language in the rule sufficiently indicates that the pressure 

grouping applies only to the gas well liquids unloading monitoring method. Hence, EPA is not 

making any changes to this effect in final rule. EPA agrees that the pressure grouping and subbasin category should apply only to Method 1. However, for methods 2 and 3, the data reporting 

is required at a sub-basin level. For further details, please see the preamble Section II.D.1 – 

Responses to Major Comments on the Petroleum and Natural Gas Systems Source Category: 

Pressure groupings. 

EPA has deleted the term conventional and unconventional from the definition of sub-basin 

category, since it has different connotations in the industry. As regards the pressure grouping, 

since they apply to only one emission source, i.e. gas well liquids unloading, reporters have to 

apply the pressure grouping to any sub-basin category where gas well liquid unloading occurs, if 

they are using Calculation Methodology 1 in 40 CFR 98.233(f). 

Regarding the suggestion to limit the number of pressure groupings to two; as discussed in the 

proposed rule, EPA analyzed different numbers of pressure groupings and selected the optimal 

number of pressure groupings that resulted in minimal error while managing burden. The EPA 

error estimates were developed using the mean pressure value within each range. EPA estimates 

that using five pressure groupings would result in a possible national average error of 

approximately 30% from all wells that report for the well liquids unloading emissions source. 

The API suggestion to decrease the pressure groupings to two would result in a possible national 

average error increase to approximately 65%. For background on the analysis, please see “2011 

Technical Revisions to the Petroleum and Natural Gas Systems Category of the GHG Reporting 

Rule: Summary of questions raised on Subpart W” docket number EPA-HQ-OAR-2011-0512, 

Excerpt15 and “Sub-Basin Entity Pressure Range Analysis” docket number EPA-HQ-OAR2011-0016, and preamble Section II.C – Final Amendments to the Petroleum and Natural Gas 

Systems Source Category – Well Venting for Liquids Unloading and Section II.D.1 – Responses 

to Major Comments on the Petroleum and Natural Gas Systems Source Category: Pressure 

groupings. Hence, EPA has retained the five pressure ranges for Monitoring method 1 for well 

venting from liquids unloading in this final rule. Reporters are to estimate emissions from one 

well with a unique tubing diameter grouping and pressure grouping combination in a sub-basin, 
177

and apply that value to all wells with that tubing diameter grouping and pressure grouping in that 

same sub-basin. Additionally, EPA has provided alternative calculation methodologies that do 

not require any measurement to calculate the total emissions for well venting for liquids 

unloading with or without plunger lifts in Equations W-9 and W-8. 

In this final rule, EPA is clarifying that shut-in pressure, surface pressure, or casing pressure may 

be used in estimating emissions from well liquids unloading. Please see response to EPA-HQOAR-2011-0512-0028, Excerpt 11. 

Section 10.12 ­ Sub­basin category

Commenter Name: Vince Alaimo 

Commenter Affiliation: Marshall Miller & Associates Inc. on behalf of Consol Energy Inc. 

Document Control Number: EPA-HQ-OAR-2011-0512-0036

Comment Excerpt Number: 3 

Commenter Type: Industry - oil and gas 

Comment: Sub-Basin Field designation 

EPA still believes they are correct by using EIA Field Code Master List for field designation; 

however, they are proposing an alternative method using the County and the distinction of the 

type of hydrocarbon formation. The various hydrocarbon formations can be grouped into four 

categories: conventional, coal bed methane, tight formations, and shale. BUT for liquid 

unloading EPA is also proposing a measurement plan that uses some operational criteria to 

generate more than one sample per sub-basin category for specific emissions sources. EPA is 

proposing the use of pressure ranges for liquids unloading measurements, because the volume of 

gas released during an unloading is related to the wellhead pressure. For example, reporters 

would take one measurement per pressure range within a sub-basin category. An example of 

pressure ranges is 0–25 psig, > 25–60 psig, > 60–110 psig, > 110–200 psig, and 200 psig and 

above. 

COMMENT 2 

Consol Energy Inc. would like to see this category reduced to two or three pressure ranges per 

sub-basin. Companies with thousands of wells could have a very large number of wells per subbasin. Two categories would reduce the burden of additional measurements required. Consol 

Energy Inc. proposes reporting wells above 110 psig and below. 

Response: EPA disagrees with reducing the number of pressure groups to two or three; please 

see the response to EPA-HQ-OAR-2011-0512-0042, Excerpt 74 for further details. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API)

Document Control Number: EPA-HQ-OAR-2011-0512-0042 

Comment Excerpt Number: 75 
178

Commenter Type: Industry - oil and gas

Comment:[Please refer to the original comment text posted in the docket] 

Revision: EPA added a new definition for “sub-basin category”. 

Comments: API requests the following revisions, shown in green font: 

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 [add (green): five] 

[delete (green): four] formation types: [add (green): oil, conventional gas, shale gas, coal seam, 

or other tight reservoir rock. The distinction between conventional gas and tight gas reservoirs 

shall be [delete (green): as] [add (green): designated as:] [delete (green): by 18 C.F.R. 270.305:] 

conventional with >0.1 millidarcy permeability, and unconventional tight with =0.1 millidarcy 

permeability. [add (green): Permeability for a reservoir type shall be determined by engineering 

estimate.] [delete (green): Unconventional formation types are either shale, coal seam, or other 

tight reservoir rock.] Wells producing from more than one [delete (green): unconventional] 

formation type shall be classified into only one type based on the formation with the most 

contribution to production as determined by engineering knowledge. [delete (green): 

Unconventional wells producing in two or more formation types of “shale and coal seam”, “shale 

and other tight”, or “shale, coal seam, and other tight”; are considered shale. In addition, 

unconventional wells producing in “coal seam and other tight” formations are considered coal.] 

• API requests the revisions noted above. Deleting “unconventional” in the third sentence 

clarifies how to distinguish between wells that produce from co-mingled conventional and 

unconventional formations (the previous language did not address this situation). In addition, the 

last two sentences appear contradictory. API prefers to assign formation types by the highest 

contribution to production based on engineering knowledge. 

• In the preamble (page 56026 middle column), EPA indicates “In the event that there is more 

than one formation, then the reporters would use the most specific designation.” This seems to 

imply that only one formation type is assigned per county. Whereas the rule language assigns the 

formation type by well, with only one designation to each well. API prefers the approach 

described in the preamble and requests additional clarification in the rule language if EPA’s 

intent is for reporters to assign only one formation type per county. If the intent is for reporters to 

assign only one formation type per county, then EPA would need to clarify what is meant by 

“most specific designation”. 

• The revisions above address API’s concern that a sub-basin category for oil production was not 

previously defined. 

Response: In this final rule, EPA has deleted the term conventional and unconventional from 

the definition of sub-basin category, since it has different connotations in the industry. EPA is 

allowing engineering estimate to determine the permeability of the reservoir type in this final 
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rule. It was not EPA’s intent to place additional burden on reporters by having them measure 

formation permeability. 

EPA does not agree with assigning one formation type to each county. The statement cited by the 

commenter is not referring to assigning a formation type to each county. Instead, the intent of 

the preamble text was that wells, which are producing from more than one formation type, must 

be associated with the formation that contributes most to its production. This is clearly stated in 

the definition of sub-basin category in 98.238. EPA is not changing the sub-basin category 

definition to have reporters assign a single formation type to a county and this was never the 

intent. A single county can have multiple different types of formations each with its own 

characteristic. Assigning a single formation to a count would not provide the level of data clarity and 

formation differentiation necessary for future policy considerations.

EPA agrees with the comment regarding an oil sub-basin and in this final rule has revised the 

definition for sub-basin in 40 CFR 98.238 to include an oil formation within the sub-basin 

category; please see the preamble Section II.C. – Final Amendments to the Petroleum and 

Natural Gas Systems Source Category – Major Changes Since Proposal and Section II.D.9 - 

Responses to Major Comments on the Petroleum and Natural Gas Systems Source Category: 

Addition of oil formation type in the sub-basin category definition, for further details. 

Section 10.13 ­ Transmission­distribution transfer station

Commenter Name: Darrell Shier 

Commenter Affiliation: SCANA Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0030

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas 

Comment: Metering-Regulating Station Sampling 

The Final Rule requires that leak surveys be conducted at all metering-regulating (M&R) stations 

classified as "custody transfer city gate stations." We agree that this definition has problems, 

because it attempts to capture ownership change (custody transfer) and pressure change (city 

gate) within the same definition. Those two classes of stations do not necessarily overlap. 

The Proposed Rule discards those qualifying terms and instead requires surveys at all 

transmission distribution stations. While this definition is perhaps more clear, the number of 

stations that must be surveyed is greatly increased, thus putting an undue burden on LDCs. We 

respectfully disagree with the EPA's statement that "the proposed revisions primarily provide 

additional clarifications or flexibility regarding the existing regulatory requirements, [and] 

generally do not affect the type of information that must be collected ...." For example, under the 

Final Rule, PSNC would be required to leak survey 18 M&R stations in its entire system. This is 

the number of "custody transfer" M&R stations within the PSNC system. Under the Proposed 

Rule, the number of transmission-distribution stations that must be surveyed increases to more 
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than 450. Our SCE&G subsidiary would experience a similarly impossible number to survey in 

2011. A survey of this magnitude cannot possibly be conducted with but a few months remaining 

in the year. 

Furthermore, we believe that a survey of this size will not yield significantly better information 

than a smaller survey. If it is EPA's goal to have a statistically sound number of M&R stations 

surveyed, then it is appropriate to use other factors to reduce the number of stations surveyed. 

We suggest two possible ways to limit the surveyed subset of stations: 

1. Survey only those stations that flow a significant amount of gas at any point during the year. 

This flow range could be based on actual gas measurements or determined by flow models based 

on actual system conditions. This method is attractive because it would remove from the subset 

all M&R stations that serve only handfuls of customers. For example, if only stations that had 

modeled flows of 200 cubic feet per hour (cfh) or more were included in the PSNC survey, the 

surveyed subset would be cut to 68 stations from 450 stations. 

2. Survey a defined percentage of M&R stations. For example, 10% of all M&R stations might 

be included in the survey, perhaps subject to a minimum and maximum number of stations. This 

method might be attractive because the 10% of surveyed stations could include stations of all 

sizes and types, thus creating a more representative emission factor to apply to the whole 

universe of stations. 

We suggest that the inlet pressure to the M&R station not be used as a threshold for subset 

selection. A large number of PSNC's and SCE&G's M&R stations serve a small number of 

customers -as few as three per station. Some of those small stations have inlet pressures as high 

as 800 psi and would be included any subset based on inlet pressure. 

Response: In this final rule, EPA is finalizing the definition of transmission-distribution (T-D) 

transfer station, as proposed. EPA has determined that custody of gas is not necessarily 

transferred from a transmission company to a distribution company through a pressure drop (i.e. 

custody may be transferred through a transmission pipeline owned by a transmission company to 

a transmission pipeline owned by a natural gas distribution company). In this final rule, EPA 

requires reporters to conduct leak detection at specific stations where gas is regulated and not 

necessarily where custody is transferred. EPA understands that pressure drops occur in several 

locations throughout a distribution system, but only requires reporters to do leak detection at 

stations where gas is taken from the transmission pipeline and put into a distribution pipeline at a 

lower pressure. Therefore, EPA is finalizing the definition of T-D transfer station to more 

clearly distinguish the stations where reporters must do leak detection. 

Regarding the commenter suggestion (1) of excluding some smaller stations from leak detection 

requirements, EPA disagrees with the commenter that surveying only large stations will 

represent the entire population and that size of the station should impact whether leaks are 

surveyed or not. Hence, EPA requires monitoring of all T-D transfer stations. However, EPA is 

providing the option for natural gas distribution companies to conduct leak detection at their T-D 

transfer stations over multiple years, not exceeding five years. This is similar to option 2 

suggested by the commenter, however, the reporter has to monitor a minimum of 20% as 

opposed to the commenter suggested 10% of the T-D transfer stations each year. For further 
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details on why EPA is not including a threshold (below which reporter do not have to conduct 

leak detection) for T-D transfer stations, and how EPA is reducing burden on natural gas 

distribution reporters that must conduct leak detection at T-D transfer stations, please see 

preamble Section II.D.4 – Responses to Major Comments on the Petroleum and Natural Gas 

Systems Source Category: Transmission-distribution transfer station reporting.

Commenter Name: Paul Pike 

Commenter Affiliation: Ameren Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0031

Comment Excerpt Number: 2 

Commenter Type: Industry - other

Comment: Ameren appreciates EPA's effort to propose revisions to what is subject to the 

annual component leak surveys, the Proposal increases the type and number of stations that 

would be subject to the annual leak survey requirement under, and that this would apply 

retroactively to the beginning of 2011, even though the Technical Revisions are not expected to 

be issued in final form until December 2011. We made a determination regarding which stations 

we would leak survey under the existing Subpart W rule, and by December 2011 it will be to late 

re-do the Subpart W leak survey program. It will be important that the agency make clear in the 

final rule and preamble that it is allowing local distribution companies to deal with this situation 

by submitting the leak surveys we have conducted and/or apply an emission factor to a count of 

stations under the Best Available Monitoring Methods provisions. 

Response: In this final rule, EPA is providing the option for natural gas distribution companies 

to conduct leak detection at their T-D transfer stations over multiple years, not exceeding five 

years. Please see preamble Section II.D.4 – Responses to Major Comments on the Petroleum and 

Natural Gas Systems Source Category: Transmission-distribution transfer station reporting and 

the response to EPA-HQ-OAR-2011-0512-0030, Excerpt 2. 

With regards to reporting of emissions for year 2011, EPA notes that the BAMM provisions in 

the Mandatory Reporting of Greenhouse Gases: Petroleum and Natural Gas Systems: Revisions 

to Best Available Monitoring Method Provisions (76 FR 59533) and the November 2011 final 

rule provide ample guidance on using data already available to report emissions for reporting 

year 2011. If you already made a determination regarding which stations to leak survey under 

the 2010 final Subpart W rule, you can use those measurements as your best available 

monitoring method for the 2011 reporting year. Hence, EPA does not deem the requirement for 

T-D transfer stations as being an issue for reporting year 2011. 

Commenter Name: Paul Pike 

Commenter Affiliation: Ameren Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0031

Comment Excerpt Number: 3

Commenter Type: Industry - other
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Comment: Under the Proposal, EPA is replacing the term "custody transfer city gate station" 

with the term Transmission-distribution (TD) transfer station". This replacement will sweep in 

many more stations into the resource-intensive on site leak survey requirement than appear to be 

covered under the current rule. Survey data from larger stations should be sufficient to develop 

an emission factor that can be applied to smaller stations. We urge EPA to impose the leak 

survey requirement only on TD Stations with a design rate of 4 million standard cubic feet per 

hour (scf/hr). This level will focus the leak surveys on a manageable number of stations. 

Response: In this final rule, EPA is finalizing the definition of T-D stations and associated 

monitoring and reporting requirements and providing the option for natural gas distribution 

companies to conduct leak detection at their T-D transfer stations over multiple years, not 

exceeding five years. Please see preamble Section II.D.4 – Responses to Major Comments on the 

Petroleum and Natural Gas Systems Source Category: Transmission-distribution transfer station 

reporting and the response to EPA-HQ-OAR-2011-0512-0030, Excerpt 2. Please see response 

to EPA-HQ-OAR-2011-0512-0031, Excerpt 2 about the ability to use BAMM for the 2011 

reporting year.

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 2 

Commenter Type: Trade Association

Comment: I. New Definition of Stations Subject to Annual Leak Surveys: BAMM 

Essential to Deal with Retroactive Application to 2011 

While AGA appreciates EPA’s effort to provide clear definitions of what is or is not subject to 

the annual component leak surveys, we are very concerned about the dramatic shift in the type 

and number of stations that would be subject to the annual leak survey requirement under the 

Proposal. We are further concerned that these new requirements would apply retroactively to the 

beginning of 2011, even though the Technical Revisions are not expected to be issued in final 

form until December 2011. Obviously, natural gas local distribution companies (LDCs) have had 

to make their best guess this year regarding which stations they should leak survey under the 

existing Subpart W rule, and in December 2011 they will not be able to turn the clock back to 

January 2011 and re-do their Subpart W leak survey program. We understand that the agency is 

suggesting that LDCs will be allowed to deal with this dilemma by submitting the leak surveys 

they have conducted and/or apply an emission factor to a count of stations under the Best 

Available Monitoring Methods (BAMM) provisions. See 76 Fed. Reg. at 56,032. It will be 

important to make this clear in the final rule and preamble.

Response: In this final rule, EPA is finalizing, as proposed, the definition of T-D stations and 

associated monitoring and reporting requirements and providing the option for natural gas 

distribution companies to conduct leak detection at their T-D transfer stations over multiple 

years, not exceeding five years. Please see preamble Section II.D.4 – Responses to Major 

Comments on the Petroleum and Natural Gas Systems Source Category: Transmission-
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distribution transfer station reporting and response to comments EPA-HQ-OAR-2011-0512-30, 

Excerpt 2 and EPA-HQ-OAR-2011-0512-0031, Excerpt 2. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 3 

Commenter Type: Trade Association 

Comment: AGA Appreciates Clear Definition of TD Stations, But Urges EPA to Exclude 

Stations Below 4.0 Million SCF/hr From Annual On-Site Surveys 

Aside from the retroactive timing, we are also concerned about the overly broad scope of the 

new leak survey requirement in the Proposal. The current rule requires annual on-site surveys of 

components at “custody transfer city gate stations.” As explained in our March 2, 2011 petition 

for reconsideration, this term has proved subject to conflicting interpretations, especially when 

combined with other provisions of the rule that focus on components in meter runs, and the 

provision in the rule stating that the LDC’s distribution “facility” include only equipment 

operated by the LDC. Our members were confused as to which stations would be subject to the 

survey requirement. The best consensus guess was to leak survey meter run components at 

stations where an upstream pipeline or local producer transfers custody of natural gas to the 

LDC, and where the LDC operates a meter. 

EPA is now proposing to replace the term “custody transfer city gate station” with the term 

Transmission-distribution (TD) transfer station” defined in proposed revised section 98.238 to 

mean: 

“a meter-regulating station where a local distribution company takes part or all of the natural gas 

from a transmission pipeline and puts it into a distribution pipeline. 

Response: In this final rule, EPA is finalizing, as proposed, the definition of T-D stations and 

associated monitoring and reporting requirements and providing the option for natural gas 

distribution companies to conduct leak detection at their T-D transfer stations over multiple 

years, not exceeding five years. Additionally, EPA disagrees with the commenter with regards to 

including a threshold for the T-D transfer stations. Please see preamble Section II.D.4 – 

Responses to Major Comments on the Petroleum and Natural Gas Systems Source Category: 

Transmission-distribution transfer station reporting and response to comments EPA-HQ-OAR2011-0512-30, Excerpt 2 and EPA-HQ-OAR-2011-0512-0031, Excerpt 2.

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 6 

Commenter Type: Trade Association 
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Comment: It is Essential to Reduce the Number of TD Stations Requiring On-Site Surveys: 

AGA appreciates EPA’s request for comment on whether the agency should establish a threshold 

for imposing the annual leak survey requirement that would exclude smaller stations. See 76 Fed. 

Reg. at 56036. It will be very important to establish a workable exemption threshold to avoid 

sweeping in many more stations into the resource-intensive on site leak survey requirement than 

appear to be covered under the current rule. There is no environmental reason not to set such 

reasonable requirements. Survey data from larger stations will be sufficient to develop an 

emission factor that can be applied to smaller stations. Our members have found in their Subpart 

W work this year that even their large custody transfer stations have less than one leaking 

component per station on average. Surveying smaller stations is a waste of resources that could 

be better used elsewhere. 

AGA surveyed its members in October 2011 regarding the number of TD stations they have that 

would be affected by the Proposal. We received responses from 42 of our larger member LDCs. 

The 42 responding companies reported they have a total of 20,781 stations that appear to fall 

within the Proposal’s definition of TD Station. If no threshold were established, an average of 

483 TD stations per company would have to be visited each year by a trained crew of utility 

employees or consultants for an annual Subpart W survey. The burden is uneven, and would fall 

much more heavily on some companies than on others simply based on their configuration. 

Several companies reported they have between 1,000 and 4,770 TD stations that would have to 

be surveyed every year under the Proposal. This could easily impose a cost burden of several 

million dollars per company each year. 

This burden is completely out of proportion to the quantity of CO2e that would be estimated and 

reported from these stations. One of our member companies hired a consultant this year to 

perform leak surveys using a FLIR GasFind IR camera and a Bacharach HiFlow Sampler to 

measure the actual volume of any leaks found. 

The company surveyed 162 custody transfer stations in 2011. Out of 32,400 components 

measured, they found only 18 leaking components for an average of 0.1 leaking components per 

custody transfer station. The total component leak rate was 0.06%, and the total amount of 

greenhouse gas emissions actually measured from those leaking components amounted to 104 

tonnes CO2e per year from all the 162 stations – assuming the components leaked at this rate for 

the entire year. 

In fact, this is an overestimate, because most of the leaking components were tightened with a 

wrench and fixed on the spot. 

The resulting emission factor for the company’s custody transfer stations is 0.64 tonnes per year 

per station. 

The company estimates over 2,700 TD stations would be subject to the annual survey 

requirement under the Proposal. Leak surveying those 2,700 TD stations would cost around $3 

million. Using the above emission factor, one can estimate the total emissions from the 2,700 

stations would equal 1,728 tonnes per year. So in effect, the Proposal would require this 

company – and many others – to expend about $1,736 per tonne of CO2e just to estimate and 

report – not to reduce emissions. This is about fifty times the level of control costs that would be 
185

imposed on those same emissions by a comprehensive and aggressive GHG control program 

[Footnote 1: Many analysts project that $30 per tonne CO2e would be enough to stabilize 

climate change in the long run.]. 

Another way to look at this requirement is to compare the minimal cost and effort to estimate 

and report emissions from miles of pipeline – which just requires multiplying the miles of pipe 

times an emission factor. And yet pipeline emissions contribute the largest percentage of 

emissions from distribution systems, simply because there are so many miles of pipe. For 

example, the same company calculates emissions from its distribution pipelines by multiplying 

its 71,000 miles of distribution mains and 3.5 million miles of service lines by the appropriate 

default emission factor (for plastic pipe, cast iron, and steel). This simple spreadsheet calculation 

yields an estimate of 431,153 tonnes per year (tpy) CO2e. This effort costs about $2,000 at most, 

including the time to build the spreadsheet, collect the mileage data, and have a supervising 

engineer review the result [Footnote 2: This conservatively assumes using the services of a junior 

engineer for 24 hours at $75/hour, and two hours of review by a senior engineer at $100/hour, 

which is probably a lot more time than it actually took to calculate. The going rates for engineers 

may vary somewhat in different parts of the country.]. Thus, the cost to estimate and report the 

431,153 tpy CO2e from distribution pipelines is approximately $0.005/Tonne CO2e calculated. 

This is a far cry from the $1,736 per tonne of CO2e for surveying TD Station components. 

Given what we have learned this year about the extremely low incidence of leaking components 

and the cost for conducting component leak surveys, it would make far more sense to impose the 

annual survey requirement on the largest stations and allow an emissions estimate for other TD 

stations using a station-level emission factor and population count. 

Based on AGA’s survey, we urge EPA to impose the leak survey requirement only on TD 

Stations with a design rate of 4 million standard cubic feet per hour (scf/hr). 

This level would focus the leak surveys on a manageable number of stations. Most of our 

members have surveyed about 10 - 50 custody transfer stations this year. A threshold of 4 

million scf/hr would capture about six TD stations on average per company. For the 42 members 

responding to the survey, this threshold would include 270 TD stations in the survey requirement 

and exclude 16,524 TD stations. In the alternative, at a 2.5 million scf/hr level, the survey 

requirement would apply to about 13 TD stations per company on average. For the 42 members 

responding to the survey, a threshold of 2.5 million scf/hr would include 568 TD stations and 

exclude 16,226 TD stations. AGA would prefer the 4 million scf/hr threshold, as this would yield 

more than enough data to develop an emission factor for other TD stations, and the effort 

involved would be more in line with the truly minimal emissions from this type of source. 

Response: In this final rule, EPA is finalizing, as proposed, the definition of T-D stations and 

associated monitoring and reporting requirements and providing the option for natural gas 

distribution companies to conduct leak detection at their T-D transfer stations over multiple 

years, not exceeding five years. Additionally, EPA disagrees with the commenter with regards to 

including a threshold for the T-D transfer stations. Please see preamble Section II.D.4 – 

Responses to Major Comments on the Petroleum and Natural Gas Systems Source Category: 
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Transmission-distribution transfer station reporting and response to comments EPA-HQ-OAR2011-0512-30, Excerpt 2 and EPA-HQ-OAR-2011-0512-0031, Excerpt 2. 

EPA does not have sufficient information to comment on the low leak rates found at the stations 

monitored by the company that conducted a survey at 162 stations. However, EPA does not 

expect to find significant leaks at custody transfer stations where gas is transferred from a 

transmission pipeline owned by a transmission company to a transmission pipeline owned by a 

natural gas distribution company. Typically, such stations are equipped with only a meter 

without any gas regulation. The leaks that are of interest to EPA are at T-D transfer stations 

where pressure is stepped down from a transmission pipeline to a distribution pipeline. 

EPA disagrees with the cost estimate provided by the commenter. First, EPA does not require 

leak measurement to estimate emissions in Subpart W. Reporters need only conduct leak 

detection and use an emission factor to estimate emissions. Second, EPA has determined 

through experience in the Natural Gas Star Program that leak detection at a typical T-D transfer 

station takes about 15-30 minutes using a camera and 30-60 minutes using an OVA/ TVA. Third, 

commenters to the August 2011 rule proposal indicated that natural gas distribution companies 

already own and operate leak detection equipment. Finally, the Department of Transportation 

requires periodic inspection of certain stations, potentially providing reporters with an 

opportunity to align their survey schedules to meet both requirements on the same trip, although 

the DOT regulations are not duplicative of the Greenhouse Gas Reporting program. For further 

details, please see Preamble Section II.D.4 - Responses to Major Comments on the Petroleum 

and Natural Gas Systems Source Category: Transmission-distribution transfer station reporting. 

Hence, EPA does not agree that it will cost reporters approximately $1,100 per T-D transfer 

station for leak detection only. For further details on EPAs cost estimates, please see Technical 

Support Document to the November 2010 final rule and Volume 10 of the Mandatory 

Greenhouse Gas Reporting Rule Subpart W – Petroleum and Natural Gas: EPA’s Response to 

Public Comments. 

EPA does not have, nor has the commenter provided, sufficient information on emissions from 

T-D transfer stations. Further, it is not clear that the estimates provided by the commenter are 

from T-D transfer stations. EPA does not agree with the costs to monitor these stations. Hence, 

EPA disagrees with the cost effectiveness estimate developed by the commenter. 

Commenter Name: Eldon Lindt 

Commenter Affiliation: Xcel Energy, Inc. 

Document Control Number: EPA-HQ-OAR-2011-0512-0035

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas 

Comment: Xcel Energy's operating companies provide gas to 1.9 million natural gas customer 

and is therefore required to report under EPA's Subpart W. Xcel Energy is in agreement with the 

American Gas Association's (AGA) comments submitted on October 24, 2011 , related to 

exclusion of leak surveying for transmission-distribution (TD) stations below 4.0 million 

standard cubic feet/hour. Imposing a threshold for leak surveying allows local distribution 
187

companies to focus efforts on the larger TD stations. The threshold also ensures that reporting is 

not unduly burdensome on industry. 

Response: Please see response to comment EPA-HQ-OAR-2011-0512-32, Excerpt 6. 

Commenter Name: Gregory L. Ryan 

Commenter Affiliation: DTE Energy 

Document Control Number: EPA-HQ-OAR-2011-0512-0041

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas 

Comment: DTE Energy is a member of the American Gas Association (AGA) and Interstate 

Natural Gas Association of America (INGAA) and endorses the comments filed by each in this 

docket. 

II. Definition of Transfer-Distribution Stations and Threshold for Excluding T-D Stations from 

Annual On-Site Surveys 

DTE Energy supports AGA’s comments regarding the replacement of the term “custody transfer 

city gate station” with “transmission-distribution (T-D) station”. While EPA’s proposed 

definition for T-D stations is clear, we would prefer that EPA utilize the Department of 

Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) definition 

of a “transmission line” in Section 98.238 of the proposed rule in order to be consistent with 

EPA’s use of the PHMSA definition of “distribution line” in the proposed rule. 

We also support AGA’s request for a natural gas design flow rate threshold that would exempt 

smaller T-D stations from the requirements to perform annual leak surveys. If the EPA rule 

required leak surveys at T-D stations with a design flow rate of 4 million standard cubic feet per 

hour (scf/hr), as recommended by AGA, MichCon would be required to conduct leak surveys at 

11 T-D stations, and use these results to develop an emission factor to apply to 222 T-D stations 

with design flow rates less than 4 million scf/hr. Applying this threshold would greatly reduce 

the burden of conducting leak surveys at these facilities that account for a very small component 

of the GHG leaks from the natural gas distribution sector. 

In addition, we support AGA’s understanding that equipment that the Local Distribution 

Company (LDC) does not own or operate (e.g. a transmission company’s meter) at a T-D station 

would not be included in the leak survey. In other words, only equipment owned by the LDC 

would be used to calculate the emission factor for metering-regulating (M-R) stations and T-D 

stations below the design flow rate threshold, if a threshold is included in the final rule. The final 

rule should clarify this assumption that T-D station components not owned by an LDC should 

not be included in the leak survey. 

Response: EPA disagrees with the commenter’s suggestion to use the PHMSA definition of a 

transmission pipeline. The commenter has not provided any technical reasons on why PHMSA 

is better suited for the transmission pipeline definition. EPA has determined that transmission 

companies best understand the definition of transmission pipeline as aligned to the FERC 
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designation. Hence, EPA has retained the definition of a transmission pipeline as proposed in 

the September 2011 proposal. In this final rule, EPA is finalizing the definition of transmissiondistribution transfer station and associated monitoring and reporting requirements and providing 

the option for natural gas distribution companies to conduct leak detection at their T-D transfer 

stations over multiple years, not exceeding five years. Please see response to comment EPA-HQOAR-2011-0512-32, Excerpt 6. 

Emissions from sources at T-D transfer stations that are under common ownership or common 

control of the reporter must be reported by the reporter. For further discussion on common 

ownership and common control issues, please see preamble Section II.D.10 – Summary of 

Comments and Responses Submitted on the Petroleum and Natural Gas Systems Source 

Category: Dehydrators owned and operated by third parties. 

Commenter Name: Ezra McCarthy

Commenter Affiliation: National Grid 

Document Control Number: EPA-HQ-OAR-2011-0512-0046

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas 

Comment: New Definition of Stations Subject to Annual Leak Surveys 

National Grid notes that EPA, in the preamble, believes it is feasible to implement the technical 

changes to the 2011 reporting year. National Grid is very concerned about the dramatic shift in 

the type and number of stations that would be subject to the annual leak survey requirement 

under the Proposal, and that this would apply retroactively to the beginning of 2011, even though 

the Technical Revisions are not expected to be issued in final form until December 2011. The 

new T-D Station definition changes the stations to be surveyed significantly from the existing 

rule where only custody transfer stations are to be surveyed. National Grid has had to make its 

own determination of applicable survey locations and has conducted many surveys as part of our 

plan, based on our interpretation of the existing rule (published November 30, 2010). In 

December 2011 we will not be able to redo surveys at other locations. We understand that the 

agency is suggesting that LDCs will be allowed to deal with this dilemma by submitting the leak 

surveys they have conducted and/or apply an emission factor to a count of stations under the Best 

Available Monitoring Methods (BAMM) provisions. We would appreciate this emphasized in 

the final rule in December 2011. 

Definition of T-D Stations 

Under the proposed technical revisions, EPA is now replacing the term “custody transfer city 

gate station” with the term Transmission-Distribution (TD) transfer station” defined in proposed 

revised section §98.238 to mean 

“a meter-regulating station where a local distribution company takes part or all of the natural gas 

from a transmission pipeline and puts it into a distribution pipeline. 

This definition changes the stations National Grid would survey considerably. Using the existing 
189

rule we are surveying only our equipment at 102 Custody Transfer Stations, where we take 

custody of gas from transmission companies and they own the meters. Generally at these stations 

both inlet and outlet pipelines are at transmission pipeline pressures and the gas pressure is 

regulated down to distribution pressure further down the system chain. Using the new definition 

National Grid would now have to survey roughly 300 stations where the transmission pipeline 

pressure at the inlet to distribution pipeline pressure at the outlet scenario exists. Given the small 

amount of emissions we are finding at Custody Transfer Stations, expanding the number of 

survey locations seems an unnecessary cost burden that does not improve the robustness of GHG 

data. Please refer to the example provided in the AGA comments to see an example how few 

emissions are being observed at Custody Transfer Stations and how small those are in 

comparison to fugitive emissions from distribution mains and services 

Establishing a TD Stations Survey Threshold: 

National Grid appreciates EPA’s request for comment on whether the agency should establish a 

threshold for imposing the annual leak survey requirement that would exclude smaller stations. It 

will be very important to establish a workable exemption threshold to avoid surveying more TD 

stations than what is necessary to estimate emission in a statistically significant manner. Survey 

data from larger stations will be sufficient to develop an emission factor that can be applied to 

smaller stations. Surveying smaller stations is a waste of resources that could be better used 

elsewhere. 

Based on an AGA’s survey and National Grid’s own station characteristics, we urge EPA to 

impose the leak survey requirement only on TD Stations with a design rate of 4 million standard 

cubic feet per hour (scf/hr). This level will focus the leak surveys on a manageable number of 

stations. A threshold of 4 million scf/hr would capture about 15 TD stations from our company. 

In the alternative, at a 2.5 million scf/hr level, the survey requirement would apply to about 36 

TD stations. National Grid would prefer the 4 million scf/hr threshold, as this would yield more 

than enough data to develop an emission factor for other TD stations, and the effort involved 

would be more in line with the truly minimal emissions from this type of source. 

Response: Please see response to comment EPA-HQ-OAR-2011-0512-0032, Excerpt 6. 

Commenter Name: Curtis J. Winner 

Commenter Affiliation: New Mexico Gas Company (NMGC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0047

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas 

Comment: Source Category Definitions 

The proposed amendments to the natural gas distribution industry segment definition changes the 

locations that NMGC will conduct leak surveys in 2012 compared with 2011. The current rule 

requires leak surveys at above ground custody transfer city gate stations which mean only 

locations where there is custody transfer of natural gas. EPA’s new definitions of meter-
190

regulating and transmission-distribution transfer stations, do not depend on custody transfer. This 

means that the stations that NMGC surveyed in 2011 will be totally different from those that 

must be surveyed in 2012. Per EPA’s proposed new definition NMGC will be required to survey 

approximately 600 more stations in 2012 compared with 2011. In 2011 NMGC will survey 

approximately 50 stations. This will substantially increase our burden and costs to comply with 

SP W of the mandatory reporting rule in 2012. NMGC suggests adding a threshold which would 

exempt some T-D transfer stations from requiring a leak survey. NMGC supports AGA’s 

proposed threshold of 4 million scf per hour. 

Response: The amendments in this final rule apply to the 2011 reporting years. Regarding 

reporting of emissions for reporting year 2011, EPA does require reporters to re-conduct leak 

detection at stations for reporting year 2011. Please see response to comment EPA-HQ-OAR2011-0512-0032, Excerpt 6. 

Section 10.14 ­ Transmission pipeline

Commenter Name: Darrell Shier 

Commenter Affiliation: SCANA Corporation 

Document Control Number: EPA-HQ-OAR-2011-0512-0030

Comment Excerpt Number: 4 

Commenter Type: Industry - oil and gas

Comment: Definition of a Transmission Pipeline 

The Proposed Rule defines a transmission-distribution transfer station as a "a meter regulating 

station where a local distribution company takes part or all of the natural gas from a transmission 

pipeline and puts it into a distribution pipeline," see 76 Fed. Reg. at 56,050 (to be codified at 40 

C.F.R. 98.238), and imposes certain requirements on transmission distribution transfer stations, 

see 76 Fed. Reg. at 56,039 (to be codified at 40 C.F.R. 98.232(i)(1)) (emphasis added) (reporting 

requirement) and 76 Fed. Reg. at 56,045 (to be codified at 40 C.F.R. 98.233(0)(8))(leak 

detection). The Proposed Rule defines "distribution pipeline" as "a pipeline that is designated as 

such by the Pipeline and Hazardous Material Safety Administration (PHMSA) 49 C.F.R. 192.3," 

and it defines "transmission pipeline" as "a Federal Energy Regulatory Commission rateregulated Interstate pipeline, a state rate-regulated Intrastate pipeline, or a pipeline that falls 

under the 'Hinshaw Exemption' ...." Id. 

Attachment 1 presents a hypothetical for which we are requesting guidance on how to apply the 

Proposed Rule's definition of a transmission-distribution transfer station. In the attached 

hypothetical, an LDC takes natural gas from a FERC rate-regulated Interstate pipeline (the red 

"Line A" in Attachment 1) at Points 1 and 2. Point 1 is a meter regulating station where the LDC 

takes the natural gas from the transmission pipeline and puts the natural gas into the LDC's own 

pipeline (the blue "Line B") which is designated as a distribution line under 49 C.F.R. 192.3. As 
191

such, it appears that, under the Proposed Rule's definition of "transmission distribution transfer 

station" in 40 C.F.R. 98.238, the LDC would be subject to any requirements applicable to 

transmission-distribution transfer stations at Point 1. 

Point 2 is a meter regulating station where the LDC takes natural gas from the transmission line 

(Line A) and puts it into its own pipeline ("Line C"). However, Part 1 of Line C (the orange 

portion in Attachment 1) is not considered to be a distribution line under 49 CFR 192.3. Thus, 

under the Proposed Rule's definition of "transmission distribution transfer station" of 40 C.F.R. 

98.238, it appears that the LDC would not be subject to any requirements applicable to 

transmission-distribution transfer stations at Point 2 because the LDC is not putting the natural 

gas into a distribution line (as defined by the Proposed Rule) at this point. 

At Point 3, however, the application of the Proposed Rule is less clear. Point 3 is a meter 

regulating station where the LDC takes natural gas from Part 1 of its own Line C (the orange 

portion in Attachment 1) and puts it into Part 2 of its own Line C (the green portion in 

Attachment 1). Part 2 of Line C is designated as a distribution line under 49 C.F.R. 192.3. 

However, to determine whether Point 3 is a transmission-distribution transfer station, one must 

determine whether Part 1 of Line C (the orange portion) is a transmission line under the 

Proposed Rule. Part 1 of Line C is classified as a transmission line by PHMSA under 49 CFR 

192.3 because it operates at a hoop stress of 20 percent or more of SMYS, but the Proposed Rule 

does not incorporate the PHMSA definition of transmission line into the Proposed Rule's 

definition of "transmission pipeline." Rather, the Proposed Rule attempts to "define transmission 

pipeline using a widely accepted designation for what is a transmission pipeline," 76 Fed. Reg. at 

56,027, i.e., "a Federal Energy Regulatory Commission rate-regulated Interstate pipeline, a state 

rate-regulated Intrastate pipeline, or a pipeline that falls under the 'Hinshaw Exemption' ...." See 

76 Fed. Reg. at 56,039 (to be codified at 40 C.F.R. 98.238); see also id. at 56,036 (discussing 

"interstate transmission pipelines" and "intrastate transmission pipelines."). 

Part 1 of Line C does not fit into any of the definitions of "transmission pipeline" in the Proposed 

Rule. It is not a FERC rate-regulated Interstate Pipeline; it is not a Hinshaw Pipeline; and it is not 

considered to be an Intrastate pipeline in the natural gas industry because the term "Intrastate 

pipeiine" refers to a transmission pipeline, see 76 Fed. Reg. at 56,036 (stating that "transmission 

pipelines are clearly designated as such by ... individual States for intrastate transmission 

pipelines"). Because Part 1 of Line C is owned and operated by a state rate-regulated LDC and is 

used to deliver natural gas to end users, the natural gas industry and the State would not consider 

Part 1 of Line C to be a transmission pipeline but rather would consider it to be a distribution 

pipeline. As we have already noted, however, Part 1 of Line C does not meet the Proposed Rule's 

definition of a distribution pipeline because PHMSA classifies it as a transmission line for 

purposes of its safety regulations. In short Part 1 of Line C does not appear to fit the Proposed 

Rule's definitions for either a distribution pipeline or a transmission pipeline. 
192

As such, we believe the Proposed Rule does not address whether lines which are owned and 

operated by an LDC in the delivery of natural gas to end users and which do not meet PHMSA's 

definition of a "distribution line" should be classified as "distribution pipelines" or "transmission 

pipelines" for purposes of the Proposed Rule. However, we also do not believe that it was EPA's 

intent for neither Point 2 nor Point 3 to be considered a transmission-distribution transfer station. 

We would appreciate clarification in the Final Rule on which point--Point 2 or Point 3--should 

be considered a transmission-distribution transfer station in the above-described hypothetical. 

Response: Based on the definition of T-D transfer station in this final rule, EPA agrees with the 

commenter’s classification of Point 1 as T-D transfer station, because gas is taken from a 

transmission pipeline and put into a distribution pipeline. 

EPA disagrees with the commenter that Part 1 of Line C in the hypothetical example is not 

subject to requirements of Subpart W. While the complete “fact pattern” in the hypothetical is 

not fully defined, we submit that the segment between Point 2 and Point 3 falls within the 

transmission pipeline definition in the September 2011 proposal, and as finalized in this final 

rule includes the “Hinshaw Exemption.” Line C is not an interstate transmission pipeline 

regulated by FERC. However, Part 1 of Line C as defined in the hypothetical conforms to the 

definition of a transmission pipeline under the rule since it is consistent with the Hinshaw 

Exemption as described by the United States Court of Appeals of the Sixth Circuit (226 F.3d 777 

(6th Cir. 2000); 

A Hinshaw pipeline is a natural gas pipeline that receives all of its out-of-state gas 

from persons "within or at the boundary of a [s]tate if all the natural gas so received is 

ultimately consumed" within the state in which it is received. 15 U.S.C. § 717(c).

Since Part 1 of Line C is a transmission pipeline according to Subpart W, Point 3 is the T-D 

transfer station that the facility has to monitor by conducting leak detection. In addition, EPA 

notes that since Line C is a transmission pipeline according to Subpart W, all requirements 

associated with facilities in 98.230(a)(4) apply to Line C. 

Commenter Name: Pamela A. Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0032

Comment Excerpt Number: 5 

Commenter Type: Trade Association

Comment: Transmission vs. Distribution Pipelines: The TD station definition depends on a clear 

understanding of what is a “transmission pipeline” vs. what is a “distribution pipeline.” We 

appreciate EPA’s willingness to define “distribution pipeline” by reference to the definition of 

“distribution line” used in 49 C.F.R. Part 192, the regulations for natural gas pipeline safety 
193

promulgated by the Department of Transportation (DOT) Pipeline and Hazardous Materials 

Safety Administration (PHMSA). Our members can clearly identify what is a distribution main 

using this definition. PHMSA defines a distribution line as a pipeline that is not a “transmission 

line” or a “gathering line” – as defined by the PHMSA regulations. See 49 C.F.R. §192.3. The 

EPA Proposal refers to the definition of transmission pipeline used by the Federal Energy 

Regulatory Commission (FERC) and state utility commission regulations rather than PHMSA’s 

definition. 

We understand that this definition of “transmission pipeline” will be easier for producers and 

processors to use in order to determine what is a gathering line and not a “transmission pipeline” 

for purposes of Subpart W. They are more familiar with the FERC or state rate regulation 

definition. In response to their concerns, the Proposal would define “transmission pipeline” as: 

A Federal Energy Regulatory Commission rate-regulated Interstate pipeline, a state rateregulated Intrastate pipeline, or a pipeline that falls under the “Hinshaw Exemption” as 

referenced in ...the Natural Gas Act...” 

AGA supports EPA’s proposed definitions of “distribution pipeline” and “transmission pipeline” 

as these definitions will help companies clearly and easily determine whether equipment falls 

within the production, processing, transmission or distribution sectors.

Response: EPA thanks the commenter for their remarks. 

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 10 

Commenter Type: Industry - oil and gas

Comment:

[Please refer to the original comment text posted in the docket] (9) “Transmission pipeline” – 

Chesapeake and AXPC support EPA’s modified definition for transmission pipeline but EPA 

should further modify the definition as follows: 

Transmission pipeline means a Federal Energy Regulatory Commission rate-regulated Interstate 

pipeline, a state rate regulated Intrastate pipeline, or a pipeline that falls under the “Hinshaw 

Exemption” as referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717(w)(1994) 

[Add:, except that a pipeline is not a transmission pipeline if it moves natural gas to a natural gas 

processing facility. All pipelines upstream of FERC regulated, state regulated, or Hinshaw 

pipelines are considered gathering pipelines.] 
194

The definition as proposed is overbroad and will cover pipelines that are not “transmission 

pipelines.” Precision is needed in this definition in order to clearly draw the distinction between 

pipelines that are covered by Subpart W and those that are part of gathering systems, which EPA 

has indicated will be covered in a future rulemaking. 

Response: EPA disagrees that further clarification is required to segregate gathering lines in the 

definition for transmission pipelines. The Subpart W definition of transmission pipeline includes 

only pipelines that are rate-regulated by FERC or the State, or are considered transmission 

pipeline according to the “Hinshaw Exemption”. In this final rule, pipelines, such as gathering 

facilities that are exempt from rate regulation under the Natural Gas Act, do not fall in any one of 

three categories are not covered as transmission pipelines. Finally, the amendments 

recommended by the commenter attempts to define a gathering pipeline. EPA will consider this 

definition in a possible future rulemaking, but does not consider it necessary at this time. 

Commenter Name: Eldon Lindt 

Commenter Affiliation: Xcel Energy, Inc. 

Document Control Number: EPA-HQ-OAR-2011-0512-0035

Comment Excerpt Number: 3 

Commenter Type: Industry - oil and gas 

Comment: In addition, Xcel Energy supports AGA's discussion on the conflicting definitions of 

pipelines that are neither transmission nor distribution as proposed in the rule. To completely 

avoid uncertainty and confusion surrounding the definition of transmission and distribution 

pipelines, Xcel Energy urges EPA to adopt the Pipeline and Hazardous Material Safety 

Administration (PHMSA) definition for distribution pipeline and the PHMSA definition for 

transmission pipeline. At the very least, Xcel Energy echoes AGA's request for clarification on 

how to report pipelines that are neither PHMSA distribution pipelines nor FERC transmission 

pipeline.

Response: EPA disagrees with the commenter’s suggestion to use the PHMSA definition of a 

transmission pipeline; please see the response to EPA-HQ-OAR-2011-0512-0041, Excerpt2. 

Section 10.15 ­ Tubing diameter groupings

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 76 

Commenter Type: Industry - oil and gas

Comment:

Revision: EPA added a new definition for “tubing diameter groupings”: Tubing diameter 

groupings are defined as follows: less than or equal to 1 inch; greater than 1 inch and less than 2 

inch; and greater than or equal to 2 inch. 
195

Comment: API supports this grouping concept. However, tubing diameters for completions are 

not commonly less than 1 inch. API suggests that two categories of tubing diameter be used 

based on the most common tubing sizes used in completions: = 2 3/8” nominal diameter and > 2 

3/8” nominal diameter.

Response: EPA thanks the commenter for their remarks on the grouping concept. EPA does not 

agree with changing the number of tubing diameter ranges to only 2. EPA is retaining the lowest 

tubing diameter range (less than or equal to 1 inch) to characterize emissions from wells 

employing smaller tubing diameters that avoid liquid buildup by increasing the velocity of flow 

through a smaller cross-sectional area. EPA agrees with the commenter’s suggestion to change 

the upper and lower limit of the remaining two ranges to 2.375 inches. EPA has also clarified in 

the definition that the ranges apply specifically to the outer diameter of the well tubing. In this 

final rule, both of these changes have been made. 

Section 10.17 ­ Vertical well

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 77 

Commenter Type: Industry - oil and gas

Comment:

Revision: EPA added a new definition for “vertical well”: 

Vertical well means a well bore that is primarily vertical but has some unintentional deviation or 

one or more intentional deviations to enter one or more subsurface targets that are off-set 

horizontally from the surface location, intercepting the targets either vertically or at an angle. 

Comment: API supports the addition of this definition 

Response: EPA thanks the commenter for their remarks. 

Section 10.18 ­ Well testing venting and flaring

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 11 

Commenter Type: Industry - oil and gas
196

Comment: “Well testing venting and flaring” – The current regulatory text in § 98.233(l) is 

unclear regarding what activities constitute "well testing." To address this problem, EPA has 

proposed a new definition in § 98.238 for “well testing venting and flaring.” Chesapeake and 

AXPC support this new definition. 

Response: In this final rule, EPA has clarified the definition of well testing venting and flaring 

by deleting the text “(i.e., the well testing) through a choke (an orifice restriction)” and adding 

the phrase “for regulatory, commercial, or technical purposes”; please see the response to EPAHQ-OAR-2011-0512-0042, Excerpt78 for further details. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 78 

Commenter Type: Industry - oil and gas

 Comment: [Please refer to the original comment text posted in the docket] Revision: EPA 

added a new definition for “well testing venting and flaring”: 

Well testing venting and flaring means venting and/or flaring of natural gas at the time the 

production rate of a well is determined [add (green): for regulatory purposes] [delete (green): 

(i.e., the well testing) through a choke (an orifice restriction).] If well testing is conducted 

immediately after well completion or workover, then it is considered part of well completion or 

workover. 

Comment: API suggests the revisions shown above in green font to make the definition 

technically correct. API supports the clarification that well testing conducted after a well 

completion or workover, is considered part of the completion or workover. 

Response: EPA does not agree with the commenter’s addition of “for regulatory purposes” to 

the definition of well testing venting and flaring. EPA requires reporters to determine emissions 

from all well testing activities, which result in vented or flared emissions, regardless of the 

purpose of the activity. The only exception is well tests conducted after completions and 

workovers, which are part of well completions or workover completions with or without 

hydraulic fracturing. Thus, in this final rule, EPA has clarified the definition by adding “for 

regulatory, commercial, or technical purposes.” 

EPA agrees with the deletion of “(i.e., the well testing) through a choke (an orifice restriction)” 

from the definition of well testing venting and flaring. Not all well testing activities are 

conducted through a choke. For example, depleted gas wells with liquids loading problems are 

not tested through a choke. Hence, in this final rule, EPA has clarified the definition by deleting 

“(i.e., the well testing) through a choke (an orifice restriction).” 
197

Section 12 ­ Outside Scope

Section 12.3 ­ Other

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 46 

Commenter Type: Trade Association 

Comment: (3) Infrared laser beam illuminated instrument. Use an infrared laser beam 

illuminated instrument for equipment leak detection. Any emissions detected by the infrared 

laser beam illuminated instrument is a leak unless screened with Method 21 monitoring, in which 

case 10,000 ppm or greater is designated a leak. In addition, you must operate the infrared laser 

beam illuminated instrument to detect the source types required by this subpart in accordance 

with the instrument manufacturer's operating parameters.

Response: EPA thanks the commenter for their remarks. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 49 

Commenter Type: Trade Association 

Comment: (b) You must operate and calibrate all flow meters, composition analyzers and 

pressure gauges used to measure quantities reported in §98.233 according to the procedures in 

§98.3(i) and the procedures in paragraph (b) 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. Consensus-based standards organizations include, but are 

not limited to, the following: ASTM International, the American National Standards Institute 

(ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers 

(ASME), the American Petroleum Institute (API), and the North American Energy Standards 

Board (NAESB). 

Response: EPA thanks the commenter for their remarks. 

Commenter Name: T. Cook 

Commenter Affiliation: 

Document Control Number: EPA-HQ-OAR-2011-0512-0027

Comment Excerpt Number: 1 

Commenter Type: Private Citizen
198

Comment: Environmental Protection Agency (EPA), 

I am writing this letter in regards to the proposed Greenhouse Gas Emissions Regulation. We all 

realize the importance to protect and preserve our environment, however, at this time; it would 

be counterproductive to enforce this regulation due to the negative impact it would have on the 

United States economy. It is estimated that while over 1.4 Million jobs (daily caller) would be 

lost from this regulation’s enactment, at the same time, an outrageous 21 Billion dollars 

(nwdailymarker) of taxpayer money would be needed to fund the manpower additions to the 

EPA. Not only are American’s losing 1.4 million fellow taxpayer that could help us pay your 

salaries, but now we are wasting 21 billion that could go to our nation’s debt. 

This is not the right time for this proposed regulation. Let’s get out of debt before we continue 

spending on things that are not absolute necessities. 

Thank you for your time, 

Toby Cook 

References: 

http://www.nwdailymarker.com/2011/09/goplabs-obama%E2%80%99s-proposedenvironmental-regs-mean-millions-more-u-s-jobs-lost/ 

http://dailycaller.com/2011/09/26/epa-regulations-would-require-230000-new-employees-21-

billion/ 

http://www.citizen.org/Page.aspx?pid=2628 

http://www.epa.gov/compliance/civil/index.html 

Response: The subject of national debt is outside of the scope of the specific amendments 

proposed for public comment in the Federal Register notice of September 9, 2011, therefore no 

rule changes were made as a result of this comment. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 2 

Commenter Type: Trade Association

Comment: 1. EPA has not addressed previous INGAA comments and recommendations, 

especially clarifications and revisions for compressor venting emission estimates. In addition, 

some proposed revisions intended to address INGAA comments are insufficient and additional 

revisions are needed. 

As discussed in INGAA's comments below, and, more importantly, as reflected in ongoing 

discussions with EPA regarding Subpart W, there are significant Subpart W implementation 
199

concerns due to unclear or conflicting requirements. 

Previous INGAA comments (e.g., comments on the 2009 and 2010 proposed rules; comments on 

the August 4 proposed revisions) discuss these issues. In addition, following a May 26, 2011 

meeting with EPA and at EPA’s request, on June 6, 2011 INGAA provided a document to EPA 

with recommended redlines to Subpart W. The proposed redlines addressed items discussed with 

EPA regarding rule clarity (e.g., estimation methods and associated reporting in §98.233 and 

§98.237) and conflicts (e.g., conflicting requirements for CO2 and CH4 content of natural gas 

and use of a default assumption for pipeline quality natural gas). 

Neither the Proposed Rule nor the August 4 proposed revisions address these key issues. As 

indicated in Table 2 of the Proposed Rule preamble and discussed in comments below, it appears 

that EPA intended to address some INGAA recommendations. However, in some cases the 

proposed revisions do not effectively address INGAA recommendations or additional revisions 

are needed to improve rule clarity. For example, Comment 2 discusses additional revisions that 

are needed to eliminate conflicting requirements when implementing a default natural gas 

composition for calculating emissions from the transmission and storage sectors. 

As INGAA members implement Subpart W, many questions remain about reporting 

requirements and regulatory intent. INGAA has voiced these concerns on the record through its 

comments and letters to EPA. It is imperative that Subpart W is revised and clarified in response 

to INGAA recommendations so operators can effectively and efficiently address rule 

requirements and ensure compliance. The INGAA recommended Subpart W redlines provided in 

June 2011 are provided as Attachment 2. In addition, INGAA plans to revisit these redlines to 

assess whether additional comments are warranted. This effort is needed because INGAA 

developed the recommended redlines over approximately one week in response to EPA's request 

and deadline. As indicated in ongoing communications with EPA, INGAA looks forward to 

continued engagement until these items are resolved. Recent Subpart W revisions that provide 

reporting flexibility for 2011 expire at the end of the year. Thus, it is imperative that remaining 

issues are expeditiously resolved so the reporting requirements are clear at the start of the 2012 

reporting year. 

Response: The subject of compressor emissions estimates is outside of the scope of the specific 

amendments proposed for public comment in the Federal Register notice of September 9, 2011, 

therefore no rule changes were made as a result of this comment. EPA may consider these issues 

at a later date. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 22 

Commenter Type: Trade Association

Comment: [Please refer to the original comment text posted in the docket] Missing data 
200

provisions in §98.235 should be revised to provide more flexibility. 

In meetings with INGAA, EPA has indicated that §98.235 missing data provisions may provide 

an avenue to address reporting issues that arise in future years that may otherwise require 

resolution through a request for Best Available Monitoring Methods (BAMM). Despite EPA's 

claims, INGAA believes that §98.235 is far too restrictive to serve as a means to address out-year 

issues that hinder an operator's ability to fulfill Subpart W obligations. One scenario discussed 

with EPA is the case where a facility is not subject to Subpart W, but becomes subject late in a 

future year due to an unexpected event at the facility that increases emissions above the reporting 

threshold. If this occurs late in the calendar year, the company may not be able to acquire 

necessary data or complete required measurements. INGAA believes that the BAMM process 

would be needed in this situation. EPA indicated that missing data provisions may provide 

another option. However, §98.235 very narrowly defines where missing data provisions apply 

and INGAA does not believe it serves the purpose intimated by EPA unless revised. 

For example, §98.235 limits missing data provisions to instances where, "...data are lost or an 

error occurs during annual emissions estimation or measurements...". The scenario described, 

where facility status changes late in the year, does not meet the common meaning of "lost data" 

or an "error during estimation or measurement." Revisions are needed to improve the utility of 

the missing data provisions. 

To provide the additional flexibility necessary to serve scenarios such as those discussed with 

EPA, INGAA recommends revising §98.235 as follows: 

"A complete record of all estimated and/or measured parameters used in the GHG emissions 

calculations is required. If data are lost, or an error occurs during annual emissions estimation or 

measurements, [ add: or an unanticipated circumstance precludes data collection or 

measurement,] you must repeat [ add: or conduct] the estimation or measurement activity for 

those sources as soon as possible, including in the subsequent calendar year if missing data are 

not discovered until after December 31 of the year in which data are collected, until valid data 

for reporting is obtained. [delete: Data developed and/or collected in a subsequent calendar year 

to substitute for missing data cannot be used for that subsequent year’s emissions estimation.] 

Where missing data procedures are used for the previous year, at least 30 days must separate 

emissions estimation or measurements for the previous year and emissions estimation or 

measurements for the current year of data collection[ add: , with the exception of cases where a 

facility becomes newly affected under this subpart in a particular year and it is not reasonably 

feasible to collect information or conduct measurements until the subsequent year. In this case, 

the first year reporting can be based on data collected in the subsequent year. ..."] 

If EPA is concerned that these revisions may be abused or misused, recordkeeping and/or 

reporting criteria could be added that require documenting the basis for using the missing data 

provisions in response to unanticipated circumstances. 

Response: The subject of compressor emissions estimates is outside of the scope of the specific 

amendments proposed for public comment in the Federal Register notice of September 9, 2011, 
201

therefore no rule changes were made as a result of this comment. EPA may consider these issues 

at a later date. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 39 

Commenter Type: Trade Association

 Comment:[Please refer to the original comment text posted in the docket] 

[highlighted text: Sections (o) and (p) for compressor emissions include significant revisions 

based on recent discussions with EPA on intended requirements for calculating and reporting 

compressor vent emissions. In addition, revisions were completed so that the format / structure of 

the two sections is analogous.] 

(o) Centrifugal compressor venting. Calculate CH4[delete: ,] [add: and] CO2 [add: and N2O 

(when flared)] emissions from both wet seal and dry seal centrifugal compressor vents as 

follows: 

(1) [add: Centrifugal compressor package operating status includes two reportable modes: 

operating and not operating de-pressurized. Centrifugal compressor package vent sources are wet 

seal oil degassing vents, unit isolation valve vents, and blowdown valve vents.] For each 

centrifugal compressor [add: package] covered by §98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) 

you must conduct an annual measurement in the [delete: operating] mode in which it is found 

[add: during the annual measurement]. Measure emissions from [add: each unique mode and 

vent source combination in (i) through (iii) of this section applicable to the as-found mode.] 

[delete: all vents (including emissions manifolded to common vents) including wet seal oil 

degassing vents, unit isolation valve vents, and blowdown valve vents).] [add: Measurement 

from a single compressor package can] [delete: (]include[add: e] [delete: ing] emissions [add: 

from unique vent sources] manifolded to common vent[delete: s)]. Record emissions from the 

following vent [add: sources] [delete: types] in the specified [delete: compressor] mode[delete: s] 

during the annual measurement. 

(i) Operating mode, blowdown valve leakage through the blowdown vent, [add: for both] wet 

seal and dry seal compressors. 

(ii) Operating mode, wet seal oil degassing vents. 

(iii) Not operating depressurized mode, unit isolation valve leakage through open blowdown 

vent, without blind flanges, [add: for both] wet seal and dry seal compressors. 

(A) For the not operating depressurized mode, each compressor [add: package] must be 

measured at least once in any three consecutive calendar years. If a compressor [add: package] is 

not operated and has blind flanges in place throughout the 3 year period, measurement is not 
202

required in this mode. [delete: If [comment bubble JMc7: Sentence is redundant and not 

needed.]the compressor is in standby depressurized mode without blind flanges in place and is 

not operated throughout the 3 year period, it must be measured in the standby depressurized 

mode.] 

(2) [add: Measure emissions from each vent including emissions manifolded to a common vents 

from a single vent source (] [delete: For] wet seal oil degassing vents, [delete: determine vapor 

volumes sent to an atmospheric vent or flare], [add: unit isolation valves, or blowdown valve 

vents) for a single compressor package] using [add: any of the methods in (o)(2)(i) though (iv) of 

this section. Vents may be screened annually using an optical imaging instrument according to 

methods in §98.234(a)(1) and if emissions are not present, then measurement per §98.234(b) is 

not required and emissions are estimated as zero.] 

[add: (i) A] [delete: a] temporary meter such as a vane anemometer or permanent flow meter 

[add: such as an orifice meter] according to 98.234(b) [delete: of this section. If [comment 

bubble JMc8: Sentence is not needed because operator clearly has the option to use a temporary 

or permanent meter.] you do not have a permanent flow meter, you may install a permanent flow 

meter on the wet seal oil degassing tank vent.] 

[delete: (3) For blowdown valve leakage and unit isolation valve leakage to open ended vents, 

you can use one of the following methods:] 

[add: (ii)] Calibrated bagging [delete: or high volume sampler] according to methods set forth in 

§98.234(c) [delete: and §98.234(d), respectively]. 

[add: (iii) High volume sampler according to methods set forth in §98.234(d),] 

[add: (iv)] For through valve leakage, such as isolation valves [add: on not operating 

depressurized compressor packages and blowdown valves on pressurized compressor packages,] 

you may use an acoustic leak detection device according to methods set forth in §98.234(a). 

[delete: If you do not have a flow meter, you may install a port for insertion of a temporary 

meter, or a permanent flow meter, on the vents.] 

([delete: 4][add: 3]) [comment bubble JMc9: NOTE: Calculation and reporting requirements 

would likely be clearer to reader if Eqn W-24 (i.e., Section 5) was introduced first, which would 

then provide a more logical flow through the estimates. INGAA did not make this change to 

avoid section “restructuring” in these edits, but recommends that EPA re-order the sections] 

[add: For each unique mode and vent source combination for which vent gas emission 

measurements were conducted during the reporting year, e] [delete: E]stimate annual emissions 

[add: for each centrifugal compressor package] using the flow measurement and Equation W–22 

of this section. 

[See original comment for Eq. W-22] 

Where: 
203

Es,i,m = Annual GHGi (either CH4 or CO2) volumetric emissions [delete: at standard 

conditions], in [add: standard] cubic feet [add: for the unique mode and vent source 

combination]. 

MTm = Measured gas [add: volumetric] emissions in standard cubic feet per hour [add: for the 

unique mode and vent source combination]. 

Tm = Total time the compressor [add: package] is in the mode for which Es[add: i,m] is being 

calculated, in the calendar year in hours. 

M[delete: i,m] = Mole fraction of GHGi in the vent gas; use the appropriate gas compositions in 

paragraph (u)(2) of this section [add: or according to §98.232(m)]. 

[delete: Bm = Fraction of operating time that the vent gas is sent to vapor recovery or fuel gas as 

determined by keeping logs of the number of operating hours for the vapor recovery system and 

the time that vent gas is directed to the fuel gas system or sales.] 

([delete: 5][add: 4]) [add: For each unique mode and vent source combination for which vent gas 

emission measurements were not conducted during the reporting year, c] [delete: C]alculate 

annual emissions from each centrifugal compressor package using Equation W–23 of this 

section. 

[See original comment for Eq. W-23] 

Where: 

Es,i,[add: m] = Annual [add: GHGi (either CH4 or CO2)] [delete: total] volumetric [delete: 

GHG] emissions [delete: at standard conditions] from each centrifugal compressor [add: 

package] in [add: standard] cubic feet [add: for the unique mode and vent source combination]. 

EFm = [add: For each unique mode and vent source combination,] [delete: R][add: r]eporter 

emission factor [delete: for each mode m], in [add: standard] cubic feet per hour, from Equation 

W–24 [delete: of this section] as calculated in paragraph [add: 5][delete: 6]. 

Tm = Total time [add: the compressor package is in the mode for which Esi,m is being 

calculated, in the calendar year] [delete: in hours per year the compressor was in each mode, as 

listed in paragraph (o)(1)(i) through (o)(1)(iii)]. 

GHGi = For onshore natural gas processing facilities, concentration of GHGi, CH4 or CO2, in 

produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through 

(a)(8),GHGi equals 1 [add: or use the gas composition allowed in §98.232(m). 

[add: (5)] You shall use [add: all of] the [add: volumetric gas] flow measurements [add: (MTm) 

for each unique mode and vent source combination (] [delete: of] operating mode wet seal oil 

degassing vent, operating mode blowdown valve vent[add: ,] and not operating depressurized 

mode isolation valve vent[add: ) to develop] [delete: for all the] reporter[delete: 's] [add: 
204

emission factors that are mode and vent source-specific. Use Equation W-24] to develop the 

[delete: following] emission factors [delete: using Equation W–24 of this section] for each 

emission source and mode as listed in paragraph (o)(1)(i) through (o)(1)(iii). 

[See original comment for Eq. W-24] 

Where: 

EFm = Reporter emission factors for [add: centrifugal] compressor [add: packages] [delete: in 

the] [add: for a unique] [delete: three] modes [delete: m] [add: and vent source combination] as 

listed in paragraph[add: s] (o)(1)(i) through (o)(1)(iii) ) [add: of this section,] in [add: standard] 

cubic feet [add: of natural gas] per hour. 

MTm = [add: All] [delete: F][add: f]low [delete: M] [add: m]easurements from [delete: all] 

centrifugal compressor [add: packages for a unique mode and vent source combination as listed] 

in [add: paragraphs] (o)(1)(i) through (o)(1)(iii) of this section[add: ,] in [add: standard] cubic 

feet [add: of natural gas] per hour. 

Countm = Total number of [add: centrifugal] compressors [add: packages] measured [add: in the 

respective unique mode and vent source combination]. 

m = [add: Three unique] [delete: Compressor] mode [add: and vent source combinations] as 

listed in paragraph (o)(1)(i) through (o)(1)(iii). 

(i) [add: For each of the unique mode and vent source combinations in §98.233(o)(1)(i) through 

(iii),] [delete: The] emission factors must be calculated annually. You must use all measurements 

from the current calendar year and the preceding [add: one (after the second annual 

measurement) or] two calendar years, totaling three consecutive calendar years of measurements 

in paragraph (o)([add: 5] [delete: 6]) of this section [add: for year three and beyond. The 

emission factor is used for calculating compressor package emissions from the unique mode and 

vent source combinations not measured in a particular year.] 

(ii) [Reserved] 

([add: 6] [delete: 7]) Onshore petroleum and natural gas production shall calculate emissions 

from [add: wet seal] centrifugal compressor [add: packages] [delete: wet seal oil degassing 

vents] as follows: 

[See original comment for Eq. W-25] 

Where: 

Es,i = Annual total volumetric GHG emissions [add: at standard conditions] from [add: wet seal] 

centrifugal compressor [add: packages] [delete: wet seals] in [add: standard] cubic feet. 

Count = Total number of [add: wet seal] centrifugal compressors [add: packages] for the 
205

reporter. 

EFi = Emission factor for GHGi. Use 12.2 million standard cubic feet per year per compressor 

[add: package] for CH4 and 538 thousand standard cubic feet per year per compressor [add: 

package] for CO2 at 68 °F and 14.7 psia or 12 million standard cubic feet per year per 

compressor [add: package] for CH4 and 530 thousand standard cubic feet per year per 

compressor [add: package] for CO2 at 60 °F and 14.7 psia. 

([add: 7][delete: 8]) [add: Estimate] [delete: Calculate both] CH4 and CO2 mass emissions from 

volumetric emissions using [add: the] calculations in paragraph (v) of this section. 

[delete: (9) Calculate emissions from seal oil degassing vent vapors to flares as follows: 

(i) Use the seal oil degassing vent vapor volume and gas composition as determined in 

paragraphs (o)(5) of this section. 

(ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine 

degassing vent vapor emissions from the flare.] 

(p) Reciprocating compressor venting. Calculate CH4 and CO2 emissions from all reciprocating 

compressor vents as follows. 

[add: (1) Reciprocating compressor package operating status includes three modes: operating, 

standby pressurized, and not operating de-pressurized. Reciprocating compressor package vent 

sources are] reciprocating rod packing vents, unit isolation valve vents, and blowdown valve 

vents. For each reciprocating compressor [add: package] covered in §98.232(d)(1), (e)(1), (f)(1), 

(g)(1), and (h)(1) you must conduct an annual measurement [delete: for each compressor] in the 

mode in which it is found during the annual measurement, except as specified in paragraph 

(p)([add: 7] [delete: 9]) of this section. Measure emissions from [add: each unique mode and vent 

source combination in (i) through (iv) of this section applicable to the as-found mode.] [delete: 

(including emissions manifolded to common vents) reciprocating rod packing vents, unit 

isolation valve vents, and blowdown valve vents).] [add: Measurement from a single compressor 

package can include emissions from unique vent sources manifolded to common vents.] Record 

emissions from the following vent [add: sources][delete: types] in the specified [delete: 

compressor] modes during the annual measurement [delete: as follows]: 

[add: (i)][delete: (1)] Operating [delete: or standby pressurized] mode[delete: ,] blowdown vent 

leakage through the blowdown vent stack. 

[add: (ii) ] Operating mode, reciprocating rod packing emissions. 

[add: (iii)] [delete: (2)] [add: Standby pressurized mode blowdown vent leakage through the 

blowdown vent stack.] 

[add: (iv)] [delete: (3)] Not operating depressurized mode, unit isolation valve leakage through 

the blowdown vent stack, without blind flanges. 
206

[add: (A)] [delete: (i)] For the not operating depressurized mode, each compressor [add: 

package] must be measured at least once in any three consecutive calendar years [delete: if this 

mode is not found in the annual measurement]. If a compressor [add: package] is not operated 

and has blind flanges in place throughout the 3 year period, measurement is not required in this 

mode. [delete: If the compressor is in standby depressurized mode without blind flanges in place 

and is not operated throughout the 3 year period, it must be measured in the standby 

depressurized mode.] 

[add: (B)] [delete: (ii)] [Reserved] 

[add: (2)] [delete: (4)] If reciprocating rod packing and blowdown vent are connected to an openended vent line[add: ,] [delete: use one of the following two methods to calculate 

emissions][add: . ] [delete: (i) M] [add: m]easure emissions from [add: each] [delete: all] vents 

[delete: (]including emissions manifolded to [add: a] common vents [add: from a single vent 

source (] [delete: including] rod packing, unit isolation valves, [delete: and] [add: or] blowdown 

[add: valve] vents[add: ) for a single compressor package][delete: )] using [delete: either] [add: 

any of the methods in (p)(2)(i) though (iv) of this section. Vents may be screened annually using 

an optical imaging instrument according to methods in §98.234(a)(1) and if emissions are not 

present, then measurement per §98.234(b) is not required and emissions are estimated as zero.] 

[delete: calibrated bagging or high volume sampler according to methods set forth in §98.234(c) 

and §98.234(d), respectively. 

(ii) Use a temporary meter such as a vane anemometer or a permanent meter such as an orifice 

meter to measure emissions from all vents (including emissions manifolded to a common vent 

including rod packing vents, unit isolation valve leakage through blowdown vents according to 

methods set forth in §98.234(b). If you do not have a permanent flow meter, you may install a 

port for insertion of a temporary meter or a permanent flow meter on the vents.] 

[add: (i) A temporary meter such as a vane anemometer or a permanent meter such as an orifice 

meter according to methods set forth in §98.234(b). 

(ii) Calibrated bagging according to methods set forth in §98.234(c). 

(iii) High volume sampler according to methods set forth in §98.234(d).] 

[add: (iv)] For through-valve leakage [delete: to open ended vents], such as unit isolation valves 

on not operating depressurized compressors [add: packages] and blowdown valves on 

pressurized compressors [add: packages], you may use an acoustic detection device according to 

methods set forth in §98.234(a). 

[add: (3)][delete: (5)] If reciprocating rod packing is not equipped with a vent line use the 

following method to calculate emissions: 

(i) 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 
207

case breather cap or other vent with a closed distance piece. 

(ii) Measure emissions found in paragraph (p)[add: (3)][delete: (5)](i) of this section using an 

appropriate meter, or calibrated bag, or high volume sampler according to methods set forth in 

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

[add: (4)][delete: (6)] [comment bubble JMc10: NOTE: Calculation and reporting requirements 

would likely be clearer to reader if Eqn W-28 (i.e., Section 6) was introduced first, which would 

then provide a more logical flow through the estimates. INGAA did not make this change to 

avoid section “restructuring” in these edits, but recommends that EPA re-order the sections.] 

[add: For each unique mode and vent source combination for which vent gas emission 

measurements were conducted during the reporting year,] [delete: E]estimate annual emissions 

[add: for each reciprocating compressor package] using the flow measurement and Equation W–

26 of this section. 

[See original comment for Eq. W-26] 

Where: 

Es,i,m = Annual GHG i (either CH4or CO2) volumetric emissions [delete: at standard 

conditions], in [add: standard] cubic feet [add: for the unique mode and vent source 

combination]. 

MTm = Measured gas [add: volumetric] emissions in standard cubic feet per hour [add: for the 

unique mode and vent source combination]. 

Tm= Total time the compressor [add: package] is in the mode for which Es,i,m is being 

calculated, in the calendar year in hours. 

Mi,m = Mole fraction of GHGi in [add: the vent] gas; use the appropriate gas compositions in 

paragraph (u)(2) of this section [add: or according to §98.232(m)]. 

[add: (5)][delete: (7)] [add: For each unique mode and vent source combination for which vent 

gas emission measurements were not conducted during the reporting year,] [delete: C][add: 

c]alculate annual emissions from each reciprocating compressor [add: package] using Equation 

W–27 of this section. 

[See original comment for Eq. W-27] 

Where: 

Es,i,[add: m] = Annual [add: GHGi (either CH4 or CO2)] [delete: total] volumetric [delete: 

GHG] emissions [delete: at standard conditions] from each reciprocating compressor [add: 

package] in [add: standard] cubic feet [add: for the unique mode and vent source combination]. 

EFm = [add: For each unique mode and vent source combination,] [delete: R][add: r]eporter 
208

emission factor [delete: for each mode, m,] in [add: standard] cubic feet per hour, from Equation 

W–28 [delete: of this section] as calculated in paragraph (p)([delete: 7][add: 6])[delete: (i)] of 

this section. 

Tm = Total time [add: the compressor package is in the mode for which Esi,m is being 

calculated, in the calendar year] [delete: in hours per year the compressor was in mode, m, as 

listed in paragraph (p)(1) through (p)(3)]. 

GHGi = For onshore natural gas processing facilities, concentration of GHG i, CH4or CO2, in 

produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through 

(a)(8), GHGi equals 1[delete: .] [add: or gas composition allowed per §98.232(m)]. 

[delete: m = Compressor mode as listed in paragraph (p)(1) through (p)(3).] 

([add: 6][delete: i]) You shall use [add: all of] the [add: volumetric gas] flow [delete: meter 

readings from] measurements [add: (MTm) for each unique mode and vent source combination 

(][delete: of] operating [add: mode] [delete: and standby pressurized] blowdown vent, [add: 

operating mode reciprocating rod packing] vents, [add: standby pressurized mode blowdown 

vent, and] not operating depressurized isolation valve vent[add: )] [delete: for all the reporter's 

compressor modes not measured in the calendar year] to develop [delete: the following] [add: 

reporter] emission factors [add: that are mode and vent source-specific]. [delete: u][add: U]s[add: 

e]ing Equation W–28 [delete: of this section for] [add: to develop the emission factors] for each 

[add: emission source and] mode as listed in paragraph (p)(1)[add: (i)] through (p)([delete: 

3][add:1)(iv)]. 

[See original comment for Eq. W-28] 

Where: 

EFm= Reporter emission factors for [add: reciprocating] compressor [add: packages] [delete: in 

the] [add: for a unique] [delete: three] mode[delete: s, m,] [add: and vent source combination as 

listed in paragraphs (p)(1)(i) through (p)(1)(iv) of this section,] in [add: standard] cubic feet [add: 

of natural gas] per hour. 

MTm= [add: All flow measurements] [delete: Meter readings] from [delete: all] reciprocating 

compressor [add: packages for a unique] [delete: vents in each and mode, m,] [add: and vent 

source combination as] [delete: identified] [add: listed] in [add: paragraphs (p)(1)(i) through 

(p)(1)(iv) of this section], in [add: standard] cubic feet [add: of natural gas] per hour. 

Countm = Total number of [add: reciprocating] compressors [add: packages] measured [delete: 

in each mode, m] [add: in the respective unique mode and vent source combination]. 

m = [add: Four unique] [delete: Compressor] mode [add: and vent source combinations] as listed 

in paragraphs (p)(1)(i) through (p)([add: 1][delete: 3])(iv). 

[delete: (A) You must combine emissions for blowndown vents, measured in the operating and 
209

standby pressurized modes.] 

([add: i][delete: B]) [add: For each of the unique mode and vent source combinations in 

§98.233(p)(1)(i) through (iv),] [delete: The] emission factors must be calculated annually. You 

must use all measurements from the current calendar year and the preceding [add: one (after the 

second annual measurement) or] two calendar years, totaling three consecutive calendar years of 

measurements [add: in paragraph (p)(6) of this section for year three and beyond. The emission 

factor is used for calculating compressor package emissions from the unique mode and vent 

source combinations not measured in a particular year]. 

(ii) [Reserved] 

[delete: (8) Determine if the reciprocating compressor vent vapors are sent to a vapor recovery 

system. 

(i) Adjust the emissions estimated in paragraphs (p)(7) 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]] 

[add: (7)][delete: (9)] Onshore petroleum and natural gas production shall calculate emissions 

from reciprocating compressors [add: packages] as follows: 

[See original comment for Eq. W-29] 

Where: 

Es,i= Annual total volumetric GHG emissions at standard conditions from reciprocating 

compressors in [add: standard] cubic feet. 

Count = Total number of reciprocating compressors [add: packages] for the reporter. 

EFi= Emission factor for GHG i. Use 9.63 thousand standard cubic feet per year per compressor 

[add: package] for CH4and 0.535 thousand standard cubic feet per year per compressor [add: 

package] for CO2at 68 °F and 14.7 psia or 9.48 thousand standard cubic feet per year per 

compressor [add: package] for CH4and 0.527 thousand standard cubic feet per year per 

compressor [add: package] for CO2at 60 °F and 14.7 psia. 

[add: (8)][delete: (10)] Estimate CH4 and CO2 [delete: volumetric and] mass emissions from 

volumetric [delete: natural gas] emissions using the calculations in paragraph[delete: s (u) and] 

(v) of this section. 

Response: No rule change has been made as a result of this comment. The subject of 

compressor emissions estimates is outside of the scope of the specific amendments proposed for 
210

public comment in the Federal Register notice of September 9, 2011. EPA may consider these 

issues at a later date. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 52 

Commenter Type: Trade Association

Comment: [Please refer to the original comment text posted in the docket]

§ 98.235 Procedures for estimating missing data. 

[highlighted text: [ INITIAL SUGGESTION OF TEXT TO BROADEN ?ACCESS? TO 

MISSING DATA PROVISIONS]] 

A complete record of all estimated and/or measured parameters used in the GHG emissions 

calculations is required. If data are lost or an error occurs during annual emissions estimation or 

measurements, [add: or an unanticipated circumstance prevents a measurement or leak survey,] 

you must repeat [add: or conduct] the estimation or measurement activity for those sources as 

soon as possible, including in the subsequent calendar year if missing data are not discovered 

until after December 31 of the year in which data are collected, until valid data for reporting is 

obtained. Data developed and/or collected in a subsequent calendar year to substitute for missing 

data cannot be used for that subsequent year’s emissions estimation. Where missing data 

procedures are used for the previous year, at least 30 days must separate emissions estimation or 

measurements for the previous year and emissions estimation or measurements for the current 

year of data collection. For missing data which are continuously monitored or measured, (for 

example flow meters), or for missing temperature or pressure data that are required under § 

98.236, the reporter may use best available data for use in emissions determinations. The reporter 

must record and report the basis for the best available data in these cases. 

Response: No rule change has been made as a result of this comment. The subject of missing 

data provisions is outside of the scope of the specific amendments proposed for public comment 

in the Federal Register notice of September 9, 2011. EPA may consider this issue at a later date. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 56 

Commenter Type: Trade Association

Comment:

[Please refer to the original comment text posted in the docket] 

(13) For each centrifugal compressor [add: packages]: 

(i) For [add: each wet seal centrifugal] compressors [add: package] [delete: with wet seals ]in 

operati[add: ng][delete: onal] mode [delete: (refer to Equations W–22 through W–24 of 

§98.233)], report the following [delete: for each degassing vent]: 
211

(A) Number of wet seals connected to the degassing vent. 

(B) Fraction of [add: wet seal oil degassing] vent gas recovered for fuel or sales or flared. 

(C) [delete: Annual throughput in million scf, use an engineering calculation based on best 

available data. 

(D) Type of meters used for making measurements. 

(E) Reporter emission factor for wet seal oil degassing vents in cubic feet per hour (refer to 

Equation W–24 of §98.233). 

(F) Total time the compressor driver is operating in hours.] 

[delete: (G ) Report] [add: Annual wet] seal oil degassing vent emissions [add: in metric tons of 

CH4 and metric tons of CO2] [delete: Report seal oil degassing vent emissions for compressors 

measured (refer to Equation W–22 of §98.233) and for compressors not measured (refer to 

Equation W–23 and Equation W–24 of §98.233)]. 

(ii) For [add: each] wet [delete: and] [add: or] dry seal centrifugal compressors [add: package] in 

operating mode[delete: , (refer to Equations W–22 through W–24 of §98.233),] report the 

following: 

(A) Total time in hours the compressor [add: package] is in operating mode. 

(B) [delete: Reporter emission factor for blowdown vents in cubic feet per hour (refer to 

Equation W–24 of §98.233).] 

[delete: (C) Report] [add: B][delete: b]lowdown vent emissions [add: in metric tons of CH4 and 

metric tons of CO2] [delete: when in operating mode (refer to Equation W–23 and Equation W–

24 of §98.233)]. 

[add: (C) Annual throughput in million scf, use an engineering calculation based on best 

available data.] 

(iii) For [add: each] wet [delete: and] [add: or] dry seal centrifugal compressors [add: package] in 

not operating depressurized mode [delete: (refer to Equations W–22 through W–24 of §98.233)], 

report the following: 

(A) Total time in hours the compressor [add: package] is in [delete: shutdown,] [add: not 

operating] depressurized mode. 

(B) [delete: Reporter emission factor for isolation valve emissions in shutdown, depressurized 

mode in cubic feet per hour (refer to Equation W–24 of §98.233).] 
212

[delete: (C) Report the i][add: I]solation valve leakage emissions in not operating depressurized 

mode in [delete: cubic feet] [add: metric tons of CH4] [delete: per hour] [add: and metric tons of 

CO2] [delete: (refer to Equation W–23 and Equation W–24 of §98.233)]. 

(iv) For each [add: centrifugal] compressor [add: package,] [delete: R][add: r]eport total annual 

compressor emissions from all modes of operation [delete: (refer to Equation W–24 of 

§98.233)]. 

(v) [add: Report the following: 

(A) Reporter emission factor for wet seal oil degassing vents in operating mode in standard cubic 

feet of natural gas per hour (refer to Equation W–24 of §98.233).] 

(B) Reporter emission factor for blowdown vents in operating mode in standard cubic feet of 

natural gas per hour (refer to Equation W–24 of §98.233). 

[add: (C) Reporter emission factor for isolation valve emissions in not operating depressurized 

mode in cubic feet of natural gas per hour (refer to Equation W–24 of §98.233).] 

(v[add: i]) For centrifugal compressors in onshore petroleum and natural gas production (refer to 

Equation W–25 of 

§ 98.233), report the following: 

(A) Count of compressors [add: packages]. 

(B) Report emissions (refer to Equation W–25 of § 98.233) collectively. 

(14) For reciprocating compressor [add: packages]: 

(i) For [add: each] reciprocating compressors [add: package] [delete: rod packing emissions with 

or without a vent] in operating mode, report the following: 

(A) Annual throughput in million scf, use an engineering calculation based on best available 

data. 

(B) Total time in hours the reciprocating compressor [add: package] is in operating mode. 

(C) [delete: Report] [add: Annual] rod packing emissions [add: in metric tons of CH4 and metric 

tons of CO2] [delete: for compressors measured (refer to Equation W–26 of §98.233) and for 

compressors not measured (refer to Equation W–27 and Equation W–28 of §98.233)]. 

[add: (D) Annual blowdown vent emissions in metric tons of CH4 and metric tons of CO2.] 

(ii) For [add: each] reciprocating compressors [add: package] [delete: blowdown vents not 

manifold to rod packing vents], in [delete: operating and] standby pressurized mode [delete: 
213

(refer to Equations W–26 through W–28 of §98.233)], report the following: 

(A) Total time in hours the compressor is in standby, pressurized mode. 

(B) [delete: Reporter emission factor for blowdown vents in cubic feet per hour (refer to 

§98.233, Equation W–28).] 

[delete: (C) Report] [add: Annual] blowdown vent emissions [add: in metric tons of CH4 and 

metric tons of CO2] [delete: when in operating and standby pressurized modes (refer to Equation 

W–27 and Equation W–28 of §98.233)]. 

(iii) For [add: each] reciprocating compressors [add: package] in not operating depressurized 

mode [delete: (refer to Equations W–26 through W–28 of §98.233)], report the following: 

(A) Total time the compressor [add: package] is in not operating depressurized mode. 

(B) [delete: Reporter emission factor for isolation valve emissions in not operating depressurized 

mode in cubic feet per hour (refer to Equation W–28 of §98.233).] 

[delete: (C) Report the] [add: Annual] isolation valve leakage emissions [add: in metric tons of 

CH4 and metric tons of CO2] [delete: in not operating depressurized mode.] 

(iv) For each reciprocating compressor [add: package], [delete: R][add: r]eport total annual 

[delete: compressor] emissions from all modes of operation [delete: (refer to Equation W–27 and 

Equation W–28 of §98.233)]. 

(vi) [add: Report the following: 

(A) Reporter emission factor for rod packing vents in operating mode in standard cubic feet of 

natural gas per hour (refer to Equation W–28 of §98.233). 

(B) Reporter emission factor for blowdown vents in operating mode in standard cubic feet of 

natural gas per hour (refer to Equation W–28 of §98.233). 

(C) Reporter emission factor for blowdown vents in standby pressurized mode in standard cubic 

feet of natural gas per hour (refer to Equation W–28 of §98.233). 

(D) Reporter emission factor for isolation valve emissions in not operating depressurized mode 

in cubic feet of natural gas per hour (refer to Equation W–28 of §98.233).] 

(v[add: ii]) For reciprocating compressors in onshore petroleum and natural gas production (refer 

to Equation W–29 of §98.233), report the following: 

(A) Count of compressor[delete: s] [add: packages.] 

(B) Report emissions collectively. 
214

Response: No rule change has been made as a result of this comment. The subject of 

compressor emissions estimates is outside of the scope of the specific amendments proposed for 

public comment in the Federal Register notice of September 9, 2011. EPA may consider this 

issue at a later date. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 59 

Commenter Type: Trade Association

Comment: [Please refer to the original comment text posted in the docket] 

§ 98.238 Definitions. 

Except as provided in this section, all terms used in this subpart have the same meaning given in 

the Clean Air Act and subpart A of this part. 

Compressor means any machine for raising the pressure of a natural gas or CO2 by drawing in 

low pressure natural gas or CO2and discharging significantly higher pressure natural gas or CO2. 

[add: Compressor package means one or more compressors with a single drive, including 

separable, integral, and multi-stage compressor designs.] 

Response: No rule change has been made as a result of this comment. The subject of 

compressor definitions is outside of the scope of the specific amendments proposed for public 

comment in the Federal Register notice of September 9, 2011. EPA may consider this issue at a 

later date. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0029

Comment Excerpt Number: 6 

Commenter Type: Trade Association

Comment:

[Please refer to the original comment text posted in the docket]§98.233(o) and (p) include 

conflicts. For centrifugal compressors, §98.233(u) is referenced following Equation W-22, but 

following Equation W-23 GHGi is defined as "1". The reference to "1" should be deleted and 

§98.232(u)(2) should be referenced. The analogous conflict occurs for reciprocating compressors 

following equations W-26 and W-27. §98.233(p)(10) also includes another reference to 

subsection (u). Consistent regulatory text referencing (u)(2) should be used in §98.233(o) and 

(p). 

Response: No rule change has been made as a result of this comment. The subject of 

compressor emissions estimates is outside of the scope of the specific amendments proposed for 
215

public comment in the Federal Register notice of September 9, 2011. EPA may consider this 

issue at a later date. 

Commenter Name: Grover R. Campbell and V. Bruce Thompson 

Commenter Affiliation: Chesapeake Energy Corporation and American Exploration & 

Production Council (AXPC) 

Document Control Number: EPA-HQ-OAR-2011-0512-0033

Comment Excerpt Number: 25 

Commenter Type: Industry - oil and gas

Comment: (2) Approval Criteria 

Chesapeake and AXPC would like to note an inconsistency in the recently finalized Subpart W 

Best Available Monitoring Methods (BAMM) approval criteria. 76 Fed. Reg. 59533 (Sept. 27, 

2011). The final rule states the following regarding BAMM: 

· “Owners and operators that submit both a timely notice of intent and extension request 

consistent with 98.234(f)(8)(ii) can automatically use BAMM through June 30, 2012. . . 

regardless of whether the best available monitoring methods request is ultimately approved.” 40 

C.F.R. § 98.234(f)(8)(i): 

· “To obtain approval to use best available monitoring methods after December 31, 2011” a 

BAMM extension request must demonstrate “to the Administrator’s satisfaction that the owner 

or operator faces unique or unusual circumstances . . . .” 40 C.F.R. § 98.234(f)(8)(iii). 

These two statements are at best confusing and perhaps inconsistent. On the one hand, the rule 

indicates that BAMM is available automatically after 2011 based on the timely submission of 

both a notice of intent and an extension request. 40 C.F.R. § 98.234(f)(8)(i). But on the other 

hand, the rule indicates EPA approval under the unique or unusual circumstance criteria is 

required for all BAMM after December 31, 2011. 40 C.F.R. § 98.234(f)(8)(iii). 

During the BAMM comment period, Chesapeake and AXPC suggested that 40 C.F.R. § 

98.234(f)(8)(iii) be modified to state that the approval criteria applies to BAMM “other than 

BAMM that is allowed automatically through” June 30, 2012. This modification would have 

made it clear that there are two methods to obtain BAMM for January – June 2012: automatic 

BAMM is available to reporters that submit both a timely notice of intent and a BAMM 

extension request and EPA-approved BAMM is available to reporters that do not submit both a 

timely notice of intent and BAMM extension request. 

Unfortunately, the final BAMM rule now expressly links the EPA approval requirement to the 

period when automatic BAMM is available. The now-modified 40 C.F.R. § 98.234(f)(8)(iii) 

requires EPA approval “to use best available monitoring methods after December 31, 2011.” So 

rather than exclude reporters from obtaining EPA approval to receive automatic BAMM from 

January – June 2012, the final BAMM rule expressly requires this approval. Chesapeake and 

AXPC recommend that EPA modify this language to clarify that EPA approval is not necessary 

where a reporter fulfills the criteria to obtain automatic BAMM. 
216

Response: No rule change has been made as a result of this comment. The subject of Best 

Available Monitoring Methods (BAMM) approval criteria was addressed in the rulemaking 

finalizes Sept. 27, 2011 and is outside of the scope of the specific amendments proposed for 

public comment in the Federal Register notice of September 9, 2011. 

Commenter Name: Rachel Buckbee 

Commenter Affiliation: BP Exploration Alaska Inc. (BPXA) 

Document Control Number: EPA-HQ-OAR-2011-0512-0037

Comment Excerpt Number: 2 

Commenter Type: Industry - oil and gas

Comment:[Please refer to the original comment text posted in the docket]Centrifugal 

Compressor Venting - Paragraph (o) and Reciprocating Compressor Venting - Paragraph (p) 

Although changes were not proposed to these paragraphs, BPXA believes that EPA should allow 

companied to petition EPA directly via a specific exemption process where direct measurement 

of a vent is deemed unsafe and unable to be completed. Where there is other data on similar 

machines in a grouping, substitution of test data should be able to be approved by EPA on a case 

by case basis. 

Centrifugal Compressor Venting - Paragraph (o) 

BPXA requests an alternative flow rate estimation methodology for measuring wet seal oil 

degassing vents to flare. This proposed methodology would greatly reduce the burden to report 

these emissions while maintaining the level of accuracy the EPA desires. BPXA has a unique 

wet seal oil system design for their compressors (diagram below). [See original comment for 

Typical BPXA North Slope Wet Seal Oil System diagram]. 

Most wet seal degassing systems send the sour seal oil (with process gas entrained) to the 

degassing tank which may vent to flare or atmosphere. BPXA has a modified system, where the 

sour seal oil goes into an intermediate stage of separation (a sour seal oil trap) before it goes to 

the degassing tank. This is where the majority (estimated >98%) of the gas is knocked out of the 

seal oil and the degassing tank removes the remaining entrained gas with an electric heater. The 

gas outlet of the sour seal oil trap has a restriction orifice which provides backpressure on the 

system to keep the sour seal oil trap operating near the sour seal oil feed pressure. Some facilities 

recover the gas off of the sour seal oil trap while others vent it to the flare system. Where this gas 

goes to flare, BPXA interprets that this flow rate to flare must be measured and reported. As this 

flare system typically operates at very low pressures (5-10 psig) and the sour seal oil traps 

operate at significantly higher pressures (ranging from 100-1000 psig), this causes the flow 

through the restriction orifice to be choked. (Note: choked flow typically occurs when the 

downstream pressure is less than half the upstream pressure). As the flow through the restriction 

orifice is choked, it can be easily estimated using standard industry calculations. These 

calculations will be as accurate as installing a meter. 
217

BPXA proposes the following language (in green) be considered for addition to Subpart W to 

clarify the applicability of compliance requirements for compressors with sour seal oil trap 

systems: 

98.233(o)(2) For wet seal oil degassing vents determine the vapor volumes sent to an 

atmospheric vent of flare, using a temporary meter such as a vane anemometer or permanent 

flow meter according to 98.234(b) of this section. If you do not have a permanent flow meter, 

you may install a permanent flow meter on the wet seal oil degassing tank vent. [highlighted text 

in green: If the sour seal oil system has an intermediate stage of separation before the degassing 

tank, a choked flow orifice gas flow engineering calculation may be used to estimate the flow 

rate to the flare under the following conditions: (1) A restriction orifice is installed on the gas 

outlet of the intermediate separator gas outlet, (2) the operating pressure of the intermediate stage 

of separation is two times the operating pressure of the flare system.] 

Response: No rule change has been made as a result of this comment. The subject of 

compressor emissions estimates is outside of the scope of the specific amendments proposed for 

public comment in the Federal Register notice of September 9, 2011. Please see the Revisions to 

Best Available Monitoring Method Provisions for further details 

http://www.gpo.gov/fdsys/pkg/FR-2011-09-27/pdf/2011-24362.pdf. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 45 

Commenter Type: Industry - oil and gas

Comment: Revision: For centrifugal compressor venting, EPA modified the definition of the 

term MTm in Equation W-24 to clarify that the flow measurements are in standard cubic feet per 

hour. 

Comment: API supports the use of flowrate in standard cubic feet at industry’s standard 

conditions of 60 oF and 14.7 psia. 

Response: No rule change has been made as a result of this comment. The subject of 

compressor emissions estimates is outside of the scope of the specific amendments proposed for 

public comment in the Federal Register notice of September 9, 2011. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0512-0042

Comment Excerpt Number: 46 

Commenter Type: Industry - oil and gas

Comment: Revision: For reciprocating compressor venting, EPA modified the definition of the 
218

term MTm in Equation W-28 to clarify that the flow measurements are in standard cubic feet per 

hour. 

Comment: API supports the use of flowrate in standard cubic feet at industry’s standard 

conditions of 60 oF and14.7 psia. 

Response: No rule change has been made as a result of this comment. The subject of 

compressor emissions estimates is outside of the scope of the specific amendments proposed for 

public comment in the Federal Register notice of September 9, 2011. 

Commenter Name: J. Dillard 

Commenter Affiliation: City of Los Angeles 

Document Control Number: EPA-HQ-OAR-2011-0512-0043

Comment Excerpt Number: 1 

Commenter Type: Private Citizen

Comment: See Attachment 

ATTACHMENT: 

Comments to EPA-HQ-OAR-2011-0512 Mandatory Reporting of Greenhouse Gases: 

Petroleum and Natural Gas Systems due 10.24.2011 

Joyce Dillard 

to: 

GHG Reporting Rule Oil and Natural Gas 

10/24/2011 08:00 PM 

Hide Details 

From: Joyce Dillard <dillardjoyce@yahoo.com> 

To: GHG Reporting Rule Oil and Natural Gas@EPA 

Please respond to Joyce Dillard <dillardjoyce@yahoo.com> 

Comments to EPA-HQ-OAR-2011-0512 Mandatory Reporting of Greenhouse Gases: Petroleum 

and Natural Gas Systems due 10.24.2011 
219

To comment generally on the proposed amendments which include calculation methods, 

amending data reporting requirements clarifying terms and definitions, and technical corrections 

in Petroleum and Natural Gas Systems and are concerned “only on the issues specifically 

identified in this proposal for the identified subparts,” we ask that you consider that these 

systems are not necessarily in remote areas but in the context of densely populated areas. 

We, in the City of Los Angeles, parts of Los Angeles County and parts of Orange County have 

these systems in our backyards. The City of Los Angeles is so densely populated and has 

diminished and non-reliable Fire and Emergency Services due to budget cuts. 

Not all wells are mapped since records were destroyed in those early boom years in Los Angeles 

were wells were prolific everywhere. We do have leakage and we do have subsidence. 

Even if oil was found, say when constructing a building, it may be that there are no records of 

this find. We have found this out from conversations former construction employees who 

remember finds, but we can find no records of a well-current or abandoned. 

The emissions problem from methane and affiliated gases are part of our air quality problem and 

water quality problem. 

Also, because of earthquake faults, we may be subject to more carbon sequestration projects. We 

have a Class V Experimental Project in the Terminal Annex Renewable Energy Project now. 

Specific identification is important to us. We are home to many Petroleum Production Facilities. 

There is leakage of Natural Gas Systems in densely populated areas. Those who are watchdogs 

are having extreme difficulty in obtaining cooperation and compliance from the parties who own 

this Natural Gas Systems and the governing bodies over the situation. 

We ask that identification used we aid us in identifying vent wells, as they are part of the 

pollution problems. We are trying to avoid explosions and the loss of life. 

So, in essence, we ask that you consider the Public Health and Safety as you review these 

amended rules. 

Thank you for your consideration. 

Joyce Dillard 

P.O. Box 31377 

Los Angeles, CA 90031 

Response: EPA thanks the commenter for their remarks. EPA will make emissions data 

collected under the Mandatory Greenhouse Gas reporting rule available to the public. 
220

 December 2011
221

Responses to Public Comments Pertaining to Subpart W from the 2011 Technical 

Corrections, Clarifying, Other Amendments to Certain Provisions of the Greenhouse Gas 

Reporting Rule 

   

   
222

Section 7 ­ Calculating Greenhouse Gas Emissions (non­equipment

specific)

Section 7.1 ­ Standard temperature and pressure

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 18 

Commenter Type: Industry – oil and gas 

Comment: Revisions: EPA added a conversion factor multiplier of 1000 to Equation W-15. 

Comment: API supports this correction. However, API requests that the emission factors be 

replaced with the following, derived for industry standard conditions of 60 oF and 14.7 psia 

- Crude EF for CH4 at 60 oF = 4.2 Mscf CH4/separator 

- Crude EF for CO2 at 60 oF = 2.9 Mscf CO2/separator 

- Condensate EF for CH4 at 60 oF = 17.2 Mscf CH4/separator 

- Condensate EF for CO2 at 60 oF = 2.9 Mscf CO2/separator 

Response: EPA agrees with the commenter’s request to provide the emission factors in 

Equation W-10 at 60°F and 14.7 psi; for further details, please see the response to EPA-HQOAR-2011-0147-0016, Excerpt 1. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 1 

Commenter Type: Industry – oil and gas 

Comment: Technical Corrections, Clarifying and Other Amendments to Certain Provisions of 

the Mandatory Reporting of Greenhouse Gases Rule 

Inconsistent Use of Standard Conditions 

No revisions were made in Subparts A or W to allow for the consistent use of industry standard 

conditions (60 oF and 14.7 psia). Even with the August 4, 2011 proposed technical amendments, 

there are numerous inconsistencies in the standard conditions applied in Subpart W. The 

following table summarizes the different temperatures used for standard conditions in Subpart 

W. 

Table 1. Summary of Standard Conditions Used in Subpart W. 

Equations W-1 and W-2 

Standard Conditions: 50.6 oF and 14.7 psia (derivation is provided in comment W.1 [EPA-HQOAR-2011-0147-0016, Excerpt 9], below) 
223

Equation W-3 

Standard Conditions: Equation indicates that the resulting volumetric emissions are at actual 

conditions, though the metered vent rate is likely to be at standard conditions , which for industry 

would correspond to 60 oF and 14.7 psia 

§98.233(d)(4) 

Standard Conditions: AmineCalc uses industry standard conditions of 60 oF and 14.7 psia 

Equation W-4 

Standard Conditions: Equation indicates that the resulting volumetric emissions are at actual 

conditions, though inlet and outlet flow rate are likely tracked at standard conditions, which for 

industry would correspond to 60 oF and 14.7 psia 

§98.233(e)(1) 

Standard Conditions: GlyCalc uses industry standard conditions of 60 oF and 14.7 psia 

Equation W-5 

Standard Conditions: Provides emission factors for both standard temperatures of 60 oF and 68 

oF 

Equation W-6 

Standard Conditions: Equation indicates that the resulting volumetric emissions are at standard 

conditions, which for industry would correspond to 60 oF and 14.7 psia 

Equation W-7 

Standard Conditions: Equation indicates that the resulting volumetric emissions are at actual 

conditions, though flow rates are likely tracked at standard conditions, which for industry would 

correspond to 60 oF and 14.7 psia 

Equations W-8 and W-9 

Standard Conditions: Equation indicates that the resulting volumetric emissions are at actual 

conditions, though the pressure correction results in standard conditions of 14.7 psia. The 

equations do not include a temperature correction. 

Equation W-10 

Standard Conditions: Equation indicates that the resulting volumetric emissions are at standard 

conditions, which for industry would correspond to 60 oF and 14.7 psia 

Equations W-11 and W-12 

Standard Conditions: Equation results in volumetric emissions at actual conditions 

Equation W-13 

Standard Conditions: Equation indicates that the resulting volumetric emissions are at actual 

conditions. (API recognizes the equation is corrected to standard conditions in the September 9, 

2011 amendments.) The emission factor is based on standard conditions at 60 oF and 14.7 psia 
224

Equation W-14 

Standard Conditions: Equation indicates that the resulting volumetric emissions are at standard 

conditions, which for industry would correspond to 60 oF and 14.7 psia 

§98.233(j)(1) 

Standard Conditions: E&P Tanks uses the standard conditions associated with the input gas 

analysis, which for industry would correspond to 60 oF and 14.7 psia 

§98.233(j)(2)-(4) 

Standard Conditions: Calculation methodologies will result in volumetric emissions at standard 

conditions, which for industry would correspond to 60 oF and 14.7 psia 

Equation W-15 

Standard Conditions: Calculation methodologies will result in volumetric emissions at standard 

conditions. Emission factors are based on standard conditions at 68 oF and 14.7 psia. Comment 

W.10 [EPA-HQ-OAR-2011-0147-0016, Excerpt 18] below provides the emission factors for 

industry standard conditions of 60 oF and 14.7 psia 

Equation W-16 

Standard Conditions: Calculation methodologies will result in volumetric emissions at standard 

conditions, which for industry would correspond to 60 oF and 14.7 psia 

Equations W-17 and W-18 

Standard Conditions: Equations indicate that the resulting volumetric emissions are at actual 

conditions, however the GOR is typically reported at industry standard conditions of 60 oF and 

14.7 psia 

Equations W-19 and W-20 

Standard Conditions: Equations indicate that the resulting volumetric emissions are at actual 

conditions 

Equations W-22 through W-24 

Standard Conditions: Equations indicate that the resulting volumetric emissions are at standard 

conditions, which for industry would correspond to 60 oF and 14.7 psia 

Equation W-25 

Standard Conditions: Calculation methodologies will result in volumetric emissions at standard 

conditions. Emission factors are provided for both standard temperatures of 68 oF and 60 oF 

Equations W-26 and W-27 

Standard Conditions: Equations indicate that the resulting volumetric emissions are at standard 

conditions, which for industry would correspond to 60 oF and 14.7 psia 

Equation W-29 

Standard Conditions: Calculation will result in volumetric emissions at standard conditions. 
225

Emission factors are provided for both standard temperatures of 68 oF and 60 oF 

Equations W-30 and W-31 

Standard Conditions: Calculations will result in volumetric emissions at standard conditions. 

Some of the emission factors in Table W-2, W¬3, W-4, W-5, W-6 and W-7 are provided for 

standard conditions of 68 oF and 14.7 psia. Table 2 at the end of this document provides the 

emission factors for 60 oF and 14.7 psia based on a correction factor of 519.67/527.67. 

Equation W-32 

Standard Conditions: Equations indicate that the resulting volumetric emissions are at standard 

conditions, which for industry would correspond to 60 oF and 14.7 psia 

Equations W-33 and W-34 

Standard Conditions: Converts actual volumetric emissions to standard conditions, which for 

industry would correspond to 60 oF and 14.7 psia 

Equation W-35 

Standard Conditions: Equation indicates that the resulting volumetric emissions are at standard 

conditions, which for industry would correspond to 60 oF and 14.7 psia 

Equation W-36 

Standard Conditions: Calculation will result in volumetric emissions at standard conditions. 

Density factors are provided for both standard temperatures of 68 oF and 60 oF 

Equations W-37, W-38, and W-40 

Standard Conditions: Equations result in mass emissions 

Equation W-39 

Standard Conditions: Equation indicates the resulting volumetric emissions are at actual 

conditions, though gas volumes are likely tracked at standard conditions, which for industry 

would correspond to 60 oF and 14.7 psia 

API strongly insists that EPA should allow the use of industry standard conditions of 60 oF and 

14.7 psia for all Subpart W equations used to quantify and report volumetric emissions for 

individual sources. This would reduce the potential for error in tracking standard volumes for the 

regulatory program that differ from those usually tracked for industry operations. If EPA needs 

the volumetric data at 68 oF for EPA’s purposes, API requests that reporters should be allowed to 

make a single final conversion (under §98.233(t)) in which they would convert volumetric 

emissions from 60 oF to 68 oF by using the ratio of 527.67/519.67 as the applicable temperature 

correction. Providing consistency in the application of industry standard conditions for the 

source-specific calculations will reduce burden, increase consistency, and improve data quality 

while ultimately once the emissions are converted to a metric tons basis, the mass emissions 

reported to EPA would be identical. 

Response: EPA agrees with commenter’s request to change standard conditions to 60°F and 

14.7 psi, which conforms to industry standard conditions. EPA has determined that changing the 
226

standard condition will reduce the burden of reporting but will not affect the quality of data 

received through this program. Emission factors, throughput thresholds, and conversion factors 

currently in Subpart W have been changed to 60°F and 14.7 psi in this final rule. EPA has also 

modified 98.233 (t) by fixing the standard conditions at 60°F and 14.7 psi in Equation W-33 or 

Equation W-34. Finally, reporters that are already complying with standard conditions as 

provided in Subpart A (68°F and 14.7 psi), can use a final conversion of 519.67/527.67 to 

convert emissions from 68°F to 60°F. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 20 

Commenter Type: Industry – oil and gas 

Comment: Revision: EPA revised the density factors for CO2 and CH4 used in Equation W-36. 

Comment: API supports this revision. However, based on our general comment on standard 

conditions, API suggests that the density factors are only needed for standard conditions of 60 oF 

and 14.7 psia if all emission source calculations are carried out at industry standard conditions. 

Response: EPA agrees with commenter’s request to change the density factors to 60°F and 14.7 

psi and has revised this final rule accordingly; for further details please see the response to EPAHQ-OAR-2011-0147-0016, Excerpt 1. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 23 

Commenter Type: Industry – oil and gas 

Comment: Also, Equations 39 A&B are shown in actual volume terms in both the August 4 and 

the September 9 amendments. As discussed above, API requests restating these equations in 

terms of industry standard conditions (60 oF and 14.7 psia). 

Response: EPA agrees with the commenter’s request to change Equation 39 A and B standard 

conditions to 60°F and 14.7 psi and has revised this final rule accordingly; for further details 

please see the response to EPA-HQ-OAR-2011-0147-0016, Excerpt 1. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 31 

Commenter Type: Industry – oil and gas 
227

Comment: Table 2. Revised Fugitive Emission Factors 

The emission factors provided below are corrected to standard conditions of 60 °F and 14.7 psia. 

Note, the table below only corrects those emission factors which were provided at 68 °F and 14.7 

psia in the reporting rule. Factors not listed below or not addressed in the comments above are 

believed to be provided at standard conditions of 60 °F and 14.7 psia in the reporting rule. 

Table W-1. Onshore Petroleum and Natural Gas Production – Eastern U.S. 

Component: Connector; Scf/hour/component: 0.003 

Component: Open-ended Line; Scf/hour/component: 0.061 

Component: Pressure Relief Valve; Scf/hour/component: 0.040 

Table W-1. Onshore Petroleum and Natural Gas Production – Western U.S. 

Component: Connector; Scf/hour/component: 0.121 

Component: Open-ended Line; Scf/hour/component: 0.031 

Component: Pressure Relief Valve; Scf/hour/component: 0.193 

Table W-2. Onshore Natural Gas Processing and Table W-3. Onshore Natural Gas Transmission 

Leaker Emission Factors – Compressor Components, Gas Service 

Component: Valve; Scf/hour/component: 14.84 

Component: Connector; Scf/hour/component: 5.59 

Component: Open-ended Line; Scf/hour/component: 17.27 

Component: Pressure Relief Valve; Scf/hour/component: 39.66 

Component: Meter; Scf/hour/component: 19.33 

Table W-2. Onshore Natural Gas Processing and Table W-3. Onshore Natural Gas Transmission 

Leaker Emission Factors – Non-Compressor Components, Gas Service 

Component: Valve; Scf/hour/component: 6.42 

Component: Connector; Scf/hour/component: 5.71 

Component: Open-ended Line; Scf/hour/component: 11.27 

Component: Pressure Relief Valve; Scf/hour/component: 2.01 

Component: Meter; Scf/hour/component: 2.93 

Table W-4. Underground Natural Gas Storage Leaker Emission Factors – Storage Station, Gas 

Service 

Component: Valve; Scf/hour/component: 14.84 

Component: Connector; Scf/hour/component: 5.59 

Component: Open-ended Line; Scf/hour/component: 17.27 

Component: Pressure Relief Valve; Scf/hour/component: 39.66 

Component: Meter; Scf/hour/component: 19.33 

Table W-5. LNG Storage and Table W-6. LNG Import and Export Equipment Leaker Emission 

Factors – LNG Storage Components and LNG Terminals Components, LNG Service 

Component: Valve; Scf/hour/component: 1.19 

Component: Pump Seal; Scf/hour/component: 4.00 

Component: Connector; Scf/hour/component: 0.34 
228

Component: Other; Scf/hour/component: 1.77 

Table W-5. LNG Storage and Table W-6. LNG Import and Export Equipment Leaker Emission 

Factors – LNG Storage and LNG Terminals Compressors, Gas Service 

Component: Vapor Recovery Compressor; Scf/hour/component: 4.16 

Table W-7. Natural Gas Distribution Leaker Emission Factors – Above Grade M&R at City Gate 

Stations Components, Gas Service 

Component: Block Valve; Scf/hour/component: 0.557 

Component: Control Valve; Scf/hour/component: 9.34 

Component: Pressure Relief Valve; Scf/hour/component: 0.270 

Component: Orifice Meter; Scf/hour/component: 0.212 

Component: Regulator; Scf/hour/component: 0.772 

Component: Open-ended Line; Scf/hour/component: 26.13 

Response: EPA agrees with the commenter’s request to provide the emission factors at 60°F 

and 14.7 psi and has revised this final rule accordingly; for further details please see the response 

to EPA-HQ-OAR-2011-0147-0016, Excerpt 1. 

Section 7.2 ­ (t) (u) (v) Volumetric and mass conversion [W­33 to W36]

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0147-0029

Comment Excerpt Number: 5 

Commenter Type: Trade Association 

Comment: INGAA supports revisions that allow use of default natural gas CO2 and CH4 

compositions for T&S pneumatic device emission estimates. Additional rule revisions are 

necessary to allow a consistent default gas composition for all T&S source estimates. 

In previous communications and comments, INGAA has requested that a single gas composition 

for natural gas CH4 and CO2 content should be allowed for estimating emissions from all 

sources at a T&S facility. In addition, default compositions should be allowed for T&S. The 

Proposed Rule revises §98.233(a) to require natural gas composition of 95.2% CH4 and 1% CO2 

for calculating vented emissions from T&S pneumatic devices. This is an improvement over the 

current version of Subpart W which requires that 100% is assumed for both constituents. 

However, the Proposed Rule (and September 9 proposed revisions) does not achieve the 

objective of allowing a common standard assumption for all sources and a common default 

composition of 95% and 1%. The September 9 proposed revisions offer additional changes that 

improve the rule, but the desired outcome is still not achieved because references to gas quality 

remain within source-specific subsections and introduce conflicts. 

Rather than requiring different assumptions for gas composition, a single value should be 

allowed for all sources. This results in a logical approach where ALL sources at a facility assume 
229

the same gas composition rather than using different assumptions for different sources. In 

addition, for T&S sources, operators should be allowed to use a default of 95% CH4 and 1% 

CO2 or a common value for the facility based on a gas analysis. To best achieve this outcome, it 

appears that §98.233 should be revised so that individual subsections (e.g., §§98.233(a), (i), (k), 

(o), (p), and (q) for the transmission compression segment) do not specify gas quality within the 

section. Instead, all of the subsections should consistently refer to §98.233(u). Then, §98.233(u) 

can identify the appropriate criteria for each segment. For T&S segments, §98.233(u) should 

indicate that operators can apply a default of 95% CH4 and 1% CO2 or use a value based on 

facility measured data (i.e., best available data). The September 9 proposed revisions provide 

appropriate §98.233(u) revisions but conflicts still exist within source-specific estimation 

methods in other §98.233 subsections. Additional details can be found in previous INGAA 

communications with EPA regarding inconsistent and conflicting Subpart W gas composition 

requirements which are incorporated herein by reference. 

Response: It is EPA’s intention that any facility that handles transmission quality gas may use a 

default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in 

natural gas. This may include the following industry segments: Onshore natural gas processing, 

Onshore natural gas transmission compression, Underground natural gas storage, Liquefied 

Natural Gas (LNG) storage, and LNG import and export equipment, and Natural gas distribution 

To make this clear, in this final rule, EPA has updated the following two sections to refer to the 

applicable sections within §98.233(u)(2) that refer to these default values: §98.233(a) Natural 

Gas Pneumatic Device Venting and §98.233(i) Blowdown Vent Stacks. 

EPA has not updated the following two sections to refer to 98.233(u)(2): (k) Transmission 

Storage Tanks and (q) Leak Detection and Leaker Emissions. Further clarification of §98.233(k) 

Transmission Storage Tanks is not necessary as the applicable section within §98.233(u)(2) that 

refers to the default values is already appropriately referenced in the November 30, 2010 final 

rule in §98.233 (k)(2)(iii). §98.233(q) Leak Detection and Leaker Emission Factors does use the 

above-mentioned default factors, however, while 98.233 (a) and (i) and (k) refer to total gas, 

98.233 (q) refers to total hydrocarbons. The above-mentioned default factors of 95% and 1% 

were used to back-calculate to get the correct percentages for total hydrocarbons, and these 

percentages are correctly referenced in the September 9, 2011 Proposal. 

EPA has also not updated the following two sections 98.233(o) Centrifugal Compressor Venting 

and (p) Reciprocating Compressors. The September 9, 2011 Proposed Rule did not propose 

changes to either of these sections. At this time EPA is not granting reconsideration of other 

issues raised, but will consider those issues at a later time. 

Section 7.3 ­ Emission Factors Table  

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 28 
230

Commenter Type: Industry – oil and gas 

Comment: Revision: EPA has revised the pneumatic device emission factors for transmission 

compression and natural gas storage. 

Comment: Based on API’s Compendium and a review of the TSD for Subpart W, EPA is 

applying the “low-bleed” pneumatic device emission factor from production to a “low 

continuous bleed” device category in the transmission and storage sectors. EPA’s revision to the 

emission factor is correcting an error in converting the factor from a CH4 basis to a natural gas 

basis. EPA’s revised emission factor is correct for standard conditions of 68 oF. However, as 

stated above, API requests that EPA provide the emission factor of 1.39 scf/pneumatic controller 

for industry standard conditions of 60 oF. 

Similarly, API reviewed EPA’s proposed correction to the “intermittent bleed” and “high 

continuous bleed” pneumatic devices in the transmission sector. The basis for EPA’s 

emission factor is an average value provided in the API Compendium for pneumatic devices in 

the transmission and storage sectors. EPA’s revision to the emission factor is correcting an error 

in converting the factor from a CH4 basis to a natural gas basis. EPA’s revised emission factor is 

correct for standard conditions of 68 oF. However, as stated above, API requests that EPA 

provide the emission factor of 19.8 scf/pneumatic controller for industry standard conditions of 

60 oF. 

Response: EPA agrees with the commenter’s request to provide the emission factors for 

pneumatic devices at 60°F and 14.7 psi and has revised this final rule accordingly; for further 

details please see the response to EPA-HQ-OAR-2011-0147-0016, Excerpt 1. In this final rule, 

EPA has updated the pneumatic device emission factor in Table W-3 and Table W-4; please see 

the response to EPA-HQ-OAR-2011-0147-0029, Excerpt 7. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 29 

Commenter Type: Industry – oil and gas 

Comment: API notes that EPA has not proposed revisions to the pneumatic emission factors for 

the production sector. API had previously pointed out an error in the emission factors provided in 

Table W-1A. Below, API provides a corrected derivation for these emission factors: 

Pneumatic Device Emission Factor Correction

API Question (Response Tracker 4844-40) 

The derivation provided in the Technical Support Document (TSD) for the high bleed, low bleed, 

and intermittent bleed pneumatic device emission factors provided in Table W-1A introduces an 

error. Footnote 3. U.S. Environmental Protection Agency (EPA). Greenhouse Gas Emissions 

Reporting from the Petroleum and Natural Gas Indistry, Background Technical Support 

Document, U.S. EPA, Climate Change Division, Washington, DC. 

<http://www.epa.gov/climatechange/emissions/downloads10/Subpart-W_TSD.pdf>] The 
231

derivation incorrectly divides by the CH4 weight fraction (e.g. D=0.788). The correct values are 

provided in the API Compendium (Table 5-15; based on scf/day of natural gas at 60 °F). 

EPA Response (January 28, 2011): The emission factors in Table W-1A are correct. The 

emission factors in Table 5-15 of the API compendium are Methane (CH4) emission factors, 

where as the emission factors in Table W-1A are Whole Gas emission factors. 

API Follow-up: 

It appears EPA misunderstood the emission factors they have cited from the API Compendium. 

Table 5-15 of the 2009 API Compendium provides emission factors for pneumatic devices in 

two sets of units. The first column cites emission factors from the original reference in the same 

units as the original reference. The original reference for the emission factors of interest is the 

data set used to develop the emission estimates provided in Volume 12 of the GRI/EPA 1996 

study and the derivation provided in Table B-14 of the API Compendium. [Footnote 4 Shires, 

T.M. and M.R. Harrison. Methane Emissions from the Natural Gas Industry, Volume 12: 

Pneumatic Devices, Final Report, GRI-94/0257.29 and EPA-600/R-96-080l, Gas Research 

Institute and U.S. Environmental Protection Agency, June 1996. 

http://www.epa.gov/gasstar/documents/emissions_report/12_pneumatic.pdf] As shown in both 

Compendium Tables 5-15 (Column labeled “Emission Factor, Original Units) and B-14 (Column 

labeled “Bleed Rate (scf/day)), the units are in scf of gas per device. The emission factors are 

then converted to tonnes CH4/device-yr in the far right-hand column of Table 5-15 and the 

bottom row of Table B-14. 

The TSD incorrectly labels the emission factor units as scfd CH4/device and then divides by the 

CH4 mole% in an attempt to convert the emission factor to a total gas basis. This erroneously 

increases the emission factors. The TSD calculations should be corrected to show the following: 

"High Continuous Bleed Pneumatic Device Vents" Methodology 

37.9 scf/hour/component EF = (705.7 From Compendium Table B-14 [scfd CH4/pneumatic 

devises, high bleed]) * (B) / (D) / (E) 

OR

37.9 scf/hour/component EF = (896 [scfd gasCH4/pneumatic devises, high bleed]) * (B) / (D) / 

(E) 

At industry standard conditions of 60 oF, the emission factor is 37.3 scfh/device

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F [API suggests removing 

this conversion and requests that the emission factors be provided at industry standard conditions 

of 60 oF.] 

D: 78.8% – production quality of natural gas (% methane), taken from Table B-14 of the 2009 

API Compendium [This should be shown as 0.788, as used in the equation.] 

E: 24 hours/day 

Low Continuous Bleed Pneumatic Device Vents” Methodology 

1.41 scf/hour/component EF = (26.3 From Compendium Table B-14 [scfd CH4/pneumatic 

devises, low bleed]) * (B) / (D) / (E) 

OR
232

1.41 scf/hour/component EF = (33.4 [scfd gasCH4/pneumatic devises, low bleed]) * (B) / (D) / 

(E) 

At industry standard conditions of 60 oF, the emission factor is 1.39 scfh/device

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F [API suggests removing 

this conversion and requests that the emission factors be provided at industry standard conditions 

of 60 oF.] 

D: 78.8% – production quality of natural gas (% methane) [This should be shown as 0.788, as 

used in the equation.] 

E: 24 hours/day 

“Intermittent Bleed Pneumatic Device Vents” Methodology 

13.7 scf/hour/component EF = (323 From GRI/EPA CH4 Study, Vol. 12, Table 4-6[scfd 

gasCH4/pneumatic devises, low bleed]) * (B) / (D)/ (E) 

At industry standard conditions of 60 oF, the emission factor is 13.5 scfh/device

Conversions: 

B: 1.015 = (68+459.67)/(60+459.67) = conversion from 60°F to 68°F [API suggests removing 

this conversion and requests that the emission factors be provided at industry standard conditions 

of 60 oF.] 

D: 78.8% – production quality of natural gas (% methane)44

E: 24 hours/day 

The corrected emission factors, derived above for industry standard conditions of 60 

oF and 14.7 psia, are summarized below. 

- High Continuous Bleed Pneumatic Device Vents= 37.3 scfh/device 

- Low Continuous Bleed Pneumatic Device Vents= 1.39 scfh/device 

- Intermittent Bleed Pneumatic Device Vents = 13.5 scfh/device 

Response: EPA agrees with the commenter’s correction of the emission factors for high 

continuous bleed, low continuous bleed, and intermittent bleed pneumatic device vents in Table 

W-1A. In this final rule, EPA has appropriately updated the factors as recommended by the 

commenter. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 30 

Commenter Type: Industry – oil and gas 

Comment: API had also noted in previous correspondence to EPA an error in the CH4 emission 

factors applied to fugitive population counts in heavy crude service. API requests that these 

revision be included in amendments to Subpart W. 

CH4 Composition for Heavy Crude Service Emission Factors 
233

API Question (Response Tracker 4844-41) 

The derivation provided in the Technical Support Document (TSD) for heavy crude service 

population emission factors applies the wrong composition. API 4615, Table 16 indicates the 

vapor phase CH4 composition associated with heavy crude is 0.942 weight fraction, not the 

0.612 weight fraction that the TSD uses for the density conversion. 

EPA Response: EPA used the averaged methane gas composition from produced gas based on 

API collected data, as noted on p. 12 of the document Estimates of Methane Emission from US 

Oil Industry (which further references API Publication No. 4638). This is the data that EPA uses 

in their standard calculations and is used as the basis for the National Inventory. 

API Follow-up: 

EPA’s response above conflicts with the TSD. Based on API Publication 4615 (also cited in 

Compendium Table C-6), the vapor phase CH4 content of light crude is 61.3 wt%, while for 

heavy crude it is 94.2 wt%. 

In the TSD (page 125), under “Population Emission Factors – All Components, Heavy Crude 

Service Methodology”, EPA indicates “Average emissions factors by facility type were taken 

from API’s Emission Factors for Oil and Gas Production Operations. [Footnote 5 API. Emission 

Factors for Oil and Gas Production Operations. API Publication Number 4615. page ES-3, 

Table ES-4, January 1995.] Hydrocarbon liquids less than 20°API are considered “heavy 

crude.” The methane content of associated natural gas with onshore light (sic) crude is 94.2%

from the same study.” (emphasis added). The statement above uses the term “light crude” when 

it should be “heavy crude” which corresponds to the methane weight percent shown. 

As detailed above, the TSD references the correct methane content for heavy crude; however, the 

composition used for the density calculations, shown on page 126 of the TSD, does not 

correspond with that of heavy crude methane composition. 

F: 0.072 gas density lb/scf – assumes a gas composition of 61.2% methane, 20% ethane, 10% 

propane, 5% butane, and 3.8% pentanes+

Notably, the term “F” used for the density of heavy crude in the emission factor derivation is the 

identical to that used for the density of light crude in the derivation of the population emission 

factors. Since the vapor phase compositions are different for light crude and heavy crude, the 

density values should not be the same. EPA should calculate separate densities corresponding to 

light crude and heavy crude, based on the weight percent methane contents cited by EPA in the 

TSD. These densities should be applied as the “F” terms for the emission factors shown on pages 

125 and 126 of the TSD. 

The correct density calculation for the vapor phase associated with light crude service is 

provided below using the composition from the TSD. 

Compound: Methane ;Weight %: 61.2; Molecular Weight: 16.04 

Compound: Ethane ;Weight %: 20; Molecular Weight: 30.07 

Compound: Propane ;Weight %: 10; Molecular Weight: 44.10 
234

Compound: Butanes ;Weight %: 5; Molecular Weight: 58.12 

Compound: Pentanes ;Weight %: 3.8; Molecular Weight: 72.15 

Applying Compendium Equation 3-9, the molecular weight of the gas is calculated as shown: 

[See original comment for equation 3-9 on page 19] 

The gas density is calculated by dividing the molecular weight of the vapor by the ideal gas 

molar volume. Compendium Table 3-3 provides commonly used molar volume conversion 

factors: 379.3 scf/lb-mole at 60°F and 385.3 scf/lb-mole at 68°F. 

Using these values results in the following light crude vapor phase density 

[See original comment for light crude vapor phase density (a) and (b) on page 19] 

The density for heavy crude vapor phase, when accounting for its higher CH4 content, would be 

somewhat lower than the density for light crude vapor phase. The TSD (page 113) provides a 

CH4 density of 0.04246 lb/scf for leakers emission factors in heavy crude service. This value 

should be applied to the population-based fugitive emission factors for heavy crude service. The 

use of the incorrect density reduces the population emission factors by 25% for components in 

light crude service and by 40% for components in heavy crude service. 

The corrected population emission factors for components in heavy crude service are provided 

below. Note, the emission factors are shown for standard conditions of 60 °F and 14.7 psia. 

Component: Valve; Scf/hour/component: 0.00064 

Component: Flange; Scf/hour/component: 0.0011 

Component: Connector (other) ; Scf/hour/component: 0.00039 

Component: Open-ended line; Scf/hour/component: 0.0076 

Component: Other; Scf/hour/component: 0.0034 

Response: EPA has reviewed your comment and may consider it in future rulemakings. 

Section 7.5 ­ Natural Gas Pneumatic Device Venting

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0147-0029

Comment Excerpt Number: 6 

Commenter Type: Trade Association 

Comment: The T&S emission factors for natural gas pneumatic device venting are 

inappropriate and emission factors more representative of current equipment and operations 

should be determined. 
235

The Proposed Rule updates emission factors for T&S pneumatic devices, and there are several 

issues that will affect emission estimate accuracy. Emission factors based on more recent and 

representative emissions data should be used for Subpart W estimates of emission from natural 

gas pneumatic devices. At a minimum and as detailed below, the Tier 2 emission factor in Tables 

W-3 and W-4 (i.e., 20.1 scf THC/device-hr) should be replaced by the Tier 3 emission factors for 

high continuous bleed pneumatic devices (i.e., 57.7 scf NG/device-hr) and intermittent bleed 

pneumatic devices (i.e., 2.51 scf NG/device-hr). In addition, these emission factors are based on 

very limited data that is approximately 20 years old. Assessing more recent data to arrive at 

emission factors more indicative of current operations is appropriate. Additional discussion 

follows on three topics. 

Response: EPA does agree with the use of “tier 3” emission factor for intermittent bleed devices 

but does not agree with the use of “tier 3” emission factors for continuous bleed devices. EPA 

used best available public data to develop the pneumatic device emission factors in this final 

rule. For further details on these issues please see the response to EPA-HQ-OAR-2011-0147-

0029, Excerpt 7. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0147-0029

Comment Excerpt Number: 7 

Commenter Type: Trade Association 

Comment: Separate emission factors are warranted for high-bleed and intermittent-bleed 

devices. In Table W-3 and Table W-4 of Subpart W, the same emission factor is applied to high 

continuous bleed pneumatic device vents and intermittent bleed pneumatic device vents. The 

Subpart W Technical Support Document (TSD) indicates the emission factor is from the GRI 

Methane Emissions from the Natural Gas Industry” study. This study and other reference 

documents provide different emission factor "tiers". The Subpart W factor is a “Tier 2” emission 

factor derived from the “Tier 3” continuous and intermittent bleed emission factors (shown in 

Table 1 below), and the estimated relative populations of each device type. Tier 2 emission 

factors are appropriate when pneumatic device counts do not distinguish between continuous 

bleed and intermittent bleed devices, but Subpart W requires separate counts of continuous bleed 

and intermittent bleed devices (i.e., Tier 3 activity data). Thus, Tier 3 intermittent device 

emission factors from the GRI study would appear more appropriate. 

Table 1 lists the Tier 3 and Tier 2 emission factors from the GRI study. For intermittent bleed 

devices, separate Tier 3 emission factors for turbine valve operators and pneumatic/hydraulic 

valve operators could be used or a weighted average Tier 3 intermittent bleed emission factor 

(i.e., 2.51 scf NG/hr) could be used as shown in Table 1. 

Table 1. Pneumatic Device Emission Factors for Transmission and Storage 

Emission Source: Gas-driven continuous bleed pneumatic devices 
236

Emission Factor* Tier: 3 

Emission Factor* scf NGA/ device-yr: 505,000 

Emission Factor* scf NGA/ device-hr : 57.7 

Reference Tier D 

Emission Source: Turbine valve operator (Intermittent bleed) 

Emission Factor* Tier: 3 

Emission Factor* scf NGA/ device-yr: 68,600 

Emission Factor* scf NGA/ device-hr : 7.84 

Reference Tier D 

Emission Source: Pneumatic/hydraulic valve operator (Intermittent) 

Emission Factor* Tier: 3 

Emission Factor* scf NGA/ device-yr: 5,710 

Emission Factor* scf NGA/ device-hr : 0.652 

Reference Tier D 

Emission Source: Intermittent bleed pneumatic device 

Emission Factor* Tier: 3B 

Emission Factor* scf NGA/ device-yr: 22,000 

Emission Factor* scf NGA/ device-hr : 2.51 

Reference Tier D 

Emission Source: Gas-operated pneumatic devices 

Emission Factor* Tier: 2C 

Emission Factor* scf NGA/ device-yr: 176,000 

Emission Factor* scf NGA/ device-hr : 20.1 

Reference Tier D 

* Emission factors reported to three significant figures for consistency with Subpart W. 

A. Based on standard temperature of 68°F and standard pressure of 14.73 psi 

B. Weighted average of Tier 3 emission factors for intermittent bleed devices 

C. Weighted average of Tier 3 emission factors for continuous bleed and intermittent bleed 

devices 

D. Emission factors based on data collected for the 1996 GRI/EPA Study. These emission factors 

are also included in the INGAA GHG Guidelines, API Compendium, GRI GHGCalcTM, and the 

U.S. Inventory of Greenhouse Gas Emissions and Sinks. 

In addition, these emission factors are based on a small emissions data set that was collected in 

the early 1990’s. Thus, these emission factors may not be representative of pneumatic devices 

currently used in the natural gas T&S segments and of questionable accuracy when developing 

emission estimates. This issue is of particular concern for the intermittent bleed device emission 

factors, which may not reflect integration of current generation “no bleed or low bleed” devices. 

The emission factor engineering units should be revised. The Proposed Rule units for the 

emission factors are “scf THC/device-hr.” The emission factor units should be “scf 
237

NG/devicehr” based on the data used to develop the emission factors. NG (natural gas) is the 

appropriate basis for the engineering units and THC (total hydrocarbons) is not appropriate or 

equivalent nomenclature. For example, analysis on a THC basis would typically be expressed as 

methane equivalents for natural gas and provides a different result unless the gas is 100% 

methane. 

The low bleed emission factor is based on data from a different industry segment. The Subpart 

W emission factor for continuous low-bleed pneumatic devices is from Table 5-15 from the API 

Compendium. The data used to develop this emission factor are included in Appendix B.5 of the 

API Compendium, and these data originate from the 1996 GRI/EPA Study. A review of these 

data shows: (1) the emission factor is based on a total of seven devices. Six of the devices are 

from a single Oil Battery measured for a 1992 Canadian Petroleum Association (CPA) study; 

and (2) the devices are from the production segment rather than natural gas transmission or 

storage operations. The very limited data set, age of the data (20 years), and production segment 

operations suggest this emission factor may not represent emissions from low-bleed pneumatic 

devices currently in use for natural gas transmission and storage operations. 

Response: Regarding the suggestion to include “tier 3” emission factor for intermittent bleed 

device EPA agrees with commenter’s suggestion; therefore, EPA has provided separate emission 

factors for turbine valve operators and pneumatic/hydraulic valve operators. The weighted 

average intermittent bleed device emission factor can be used in cases where the pneumatic 

device does not fall under either of the new intermittent pneumatic device categories. 

Regarding the suggestion to provide a single “tier 3” emission factor for both continuous highbleed and low-bleed emission factors, EPA does not agree. EPA requires data that segregates 

continuous high-bleed devices from continuous low-bleed devices. This level of detail is 

required to inform future policy. 

Regarding the commenter’s conversion of the factors to standard cubic feet of natural gas, EPA 

does not agree. Reporters are to use the total hydrocarbon emission factors and convert these to 

CH4 and CO2 (default values as listed under 98.233(u)(2)(i) may be used for the conversion). 

EPA used best available public data to develop the pneumatic device emission factors in this 

final rule. All other alternatives considered were either less recent or more prone to erroneous 

calculations than the data EPA used. If and when new data become available, EPA will consider 

the need to update the emissions factors. Moreover, EPA developed the emission factors with 

the intent of minimizing the reporting burden on reporters. Where used in this final rule, 

population emission factors are the least burdensome method for reporters, while sustaining the 

necessary quality of data. 

Section 7.5.1 ­ Calculating GHG Emission [W­1]

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 9 
238

Commenter Type: Industry – oil and gas 

Comment: Revision: EPA revised the GHGi definition for Equation W-1. 

Comment: API supports the clarification provided for GHGi in Equation W-1. However, EPA 

did not correct the constant in this equation and Equation W-2. As API commented in December 

2010, the conversion from standard cubic feet to metric tons used in Equations W-1 and W-2 is 

based on 50.6 oF. Applying the Ideal Gas Law, the correct conversion factors at industry standard 

conditions should be: 

- CH4 at 60 oF = 4.03E-4 

- CO2 at 60 oF = 5.26E-5 

In Subpart Y, EPA provides molar volume conversion factors for two set of standard conditions: 

“MVC = Molar volume conversion factor at standard conditions, as defined in §98.6. Use 849.5 

scf per kg mole if you select 68 °F as standard temperature and 836.6 scf per kg mole if you 

select 60 °F as standard temperature”. Based on the MVC for 60 °F, the conversion factor for 

CH4 should be: 

(kg mol/836.6 sfc) x (16.04 kg CH4/kg mo) x (tonne CH4/1000 kg CH4) x (21 tonne 

CO2e/tonne CH4) = 0.000403 tonne CO2e/scf 

Using the conversion factor provided for Equation W-1, we were able to back-calculate the 

molar volume conversion factor associated with the value, as shown: 

(0.000410 tonne CO2e/scf) x ( tonne CH4/21 tonne CO2e) x (1000 kg CH4/tonne CH4) x 

kgmole HC4/16.04 kg CH4) = 0.0012172 kgmole CH4/scf 

The inverse of this value = 821.56 scf/kgmole CH4. The temperature associated with this 

conversion factor can be calculated using the Ideal Gas Law: 

MVC1/MVC2 – T1/T2 

821.56/849.5 = (T1 + 459.7)/(69 + 459.7) 

T1 = 50.6° F 

This clearly demonstrates an error in the derivation of the conversion factors provided for both 

CH4 and CO2. API requests that EPA correct the conversion factor to correspond to industry 

standard conditions of 60 oF and 14.7 psia. Based on the general comment above on standard 

conditions, a conversion factor for 68 oF and 14.7 psia is not needed. This conversion would take 

place under §98.233(t), based on API’s recommendations. 

Response: EPA agrees that the factor should be determined at industry standard conditions; 

please see the response to EPA-HQ-OAR-2011-0147-0016, Excerpt 1. EPA also agrees that 

factor Convi in Equation W-1 and W-2 was not calculated at standard condition and has updated 

factor Convi in Equation W-1 and W-2 in this final rule. 

 
239

Commenter Name: Pamela Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0147-0028

Comment Excerpt Number: 3 

Commenter Type: Industry – oil and gas 

Comment: Clarification that Pneumatic Device Venting in W-1 Does not Apply to Natural Gas 

Distribution: AGA appreciates the proposed clarification that the definition of GHG1 in section 

98.233(a), Equation W-1, are to be reported only for certain listed sectors of the natural gas 

industry, and that natural gas distribution is not on the list. We thought this was your intent, but it 

was not clear from the existing rule. See 76 Fed. Reg. at 47,398. 

Response: EPA agrees that this was our intent. 

Section 7.7 ­ Acid Gas Removal

Section 7.7.1 ­ Calculating GHG Emission [W­3, W­4]

Commenter Name: William Grygar 

Commenter Affiliation: Anadarko Petroleum Corporation 

Document Control Number: EPA-HQ-OAR-2011-0147-0014

Comment Excerpt Number: 4 

Commenter Type: Industry – oil and gas 

Comment: Under Subpart W EPA proposes to require the use of Methodology 2 for acid gas 

removal units if the owner or operator has a meter installed on the vent, allowing the use of 

Methodologies 3 and 4 only when there is no vent meter. This revision requires the calibration 

requirements under §98.3(i) if a meter is present. In some instances an operational meter may be 

installed on a vent for basic process and safety information, and requiring a facility to maintain 

these meters under the requirements of §98.3(i) is overly arduous. Anadarko supports the 

continued use of Methodologies 3 and 4 where a previously quality-assured meter meeting the 

requirements of the GHGR is not already in place. 

Response: EPA has finalized, as proposed, the requirement that if CEMS is not available, but a 

vent meter is installed, it must be used to quantify GHG emissions from acid gas removal vents. 

If the meter cannot provide the required quality expectation in 98.3(i) despite calibration, the 

operator may calibrate the meter according to manufacturer’s instructions and use this 

measurement for determining vent emissions. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 10 
240

Commenter Type: Industry – oil and gas 

Comment: Revision: For Acid Gas Unit Methodology 2, EPA proposes to require the use of 

Methodology 2 if you have a meter. If a facility has a vent meter but no CEMS available for 

determining the CO2 emissions from AGR units, then they would use Calculation Methodology 

2; and if a facility has neither a CEMS nor a vent meter, they have the option of using either 

Calculation Methodology 3 or 4. 

Comment: This revision poses a problem. A company may have a meter installed on the acid gas 

unit for process information or flow indication. Such meters were not intended to provide the 

level of quality required by §98.3(i). API requests the continued use of Methodologies 3 or 4 

even where a flow meter is installed and there is no CEMS. 

Response: EPA agrees with the commenter regarding the use of available vent meters on AGR 

vents; please see the response to EPA-HQ-OAR-2011-0147-0014, Excerpt 4.

Section 7.8 ­ Dehydrator Vents

Section 7.8.1 ­ Calculating GHG Emission [W­5, W6]

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 11 

Commenter Type: Industry – oil and gas 

Comment: Revisions: EPA revised several references for dehydrator emissions under 

§98.233(e) and clarified that the annual average daily throughput is used to assess if the flow is 

less than 0.4 million cubic feet per day. 

Comment: API supports the corrected references. API requests one additional revision to the 

clarification of the annual average daily throughput. The flow rate should be examined based on 

0.4 million standard (at 60 oF and 14.7 psia) cubic feet of gas per day. This is consistent with 

the terms defined in Equation W-5. 

Response: EPA has taken into consideration the suggestion to change STP conditions and has 

revised this final rule to this STP condition of 60oF. Hence dehydrator daily throughput threshold 

should be determined at STP conditions to 60oF and 14.7 psia. 

Section 7.9 ­ Well Venting for Liquids Unloading

Commenter Name: Amy Hendershot 

Commenter Affiliation: Marshall Miller & Associates, Inc 

Document Control Number: EPA-HQ-OAR-2011-0147-0007

Comment Excerpt Number: 3 
241

Commenter Type: Industry – oil and gas 

Comment: Discussion on plunger lift – 

“Plunger travel is normally provided by formation gas stored in the casing annulus during a shutin period. As the well is opened and the tubing pressure allowed to decrease, the stored casing 

gas moves around the end of the tubing and pushes the plunger to the surface. This intermittent 

operation is repeated several times per day.” 

In essence, the well shuts itself in and the casing pressure builds to a pre-set point. At that time, 

the valve that shut in the gas flow from the tubing re-opens. The casing pressure pushes the 

plunger up the tubing string to unload the liquids that accumulated. The EPA uses sales line 

pressure. In some cases, the pressures may be the same, however, not always. 

Response: EPA does not agree with the suggestion to change sales line pressure (SPw, now 

renamed SPp defined as “flow-line” pressure) to casing pressure. If a well venting to the 

atmosphere with the aid of a plunger lift is operated properly, either manually or with automated 

controls, a small amount of high pressure casing gas may slip past the plunger and through the 

liquids load being pushed up the tubing, so the gas being vented at the surface is the gas in the 

tubing string above the liquid load and plunger. This gas begins at flow-line pressure just before 

opening the surface vent, and quickly reduces to atmospheric pressure allowing the higher 

pressure gas in the casing to push the plunger and liquids up the tubing. EPA’s method for 

calculating well venting for liquids unloading with plunger lifts is not attempting to quantify the 

casing gas at all. The liquid accumulation in the tubing string suppresses gas flow to the sales 

line, which gradually shuts in the well causing gas in the formation to replenish the “cone” of 

low pressure gas surrounding the well perforations, raising the casing gas pressure to near shut-in 

pressure. Thus, EPA agrees with the commenter that the casing pressure is what pushes the 

plunger up the tubing string. In the first term of Equation W-9, EPA is attempting to quantify the 

gas in the tubing, above the liquid column, and released when the plunger lift travels up the 

tubing string. This gas is not at the same pressure as the casing pressure, which the commenter 

noted. Thus, EPA does not agree that casing pressure should be used instead of sales line 

pressure when a plunger lift is employed. 

Section 7.9.1 ­ Calculating GHG Emission [W­7 to W9]

Commenter Name: Amy Hendershot 

Commenter Affiliation: Marshall Miller & Associates, Inc 

Document Control Number: EPA-HQ-OAR-2011-0147-0007

Comment Excerpt Number: 2 

Commenter Type: Industry – oil and gas 

 Comment: § 98.233 Calculating GHG emissions. 

(f) * * * 

(3) Calculation Methodology 3. 
242

The proposed correction to equation W-9 appears to have been just a copy of the revised 

equation W- 8. TDw is outlined in the details of this revised equation but is not included. 

Also in this same equation, the pressure requirement is for sales line pressure (SPw). We believe 

this should instead be using casing pressure. 

Response: Regarding the comment about the missing term TDw in Equation W-9, first in the 

September 9, 2011 proposal and subsequently finalized in this final rule, EPA has corrected 

equation W-9 to include the TDw term, now renamed TDp. Regarding the comment that sales line 

pressure (SPw) should be replaced by casing pressure, EPA does not agree. Please see EPA’s 

response to comment number EPA-HQ-OAR-2011-0147-0007, Excerpt 3. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 19 

Commenter Type: Industry – oil and gas 

Comment: Revision: EPA has proposed corrections to Equation W-8. 

Comment: The revisions do not fully correct Equation W-8. API provides the following 

corrections for both the terminology associated with Equation W-7 and for Equation W-8. 

For Equation W-7: 

- Ea,n should be defined in terms of standard conditions: Eas,n = Annual natural gas emissions at 

actual conditions in standard cubic feet. 

- Similarly, FRh,t should be defined in terms of standard conditions: FRh,t = Average flow rate 

in standard cubic feet per hour of the measured well venting for the duration of the liquids 

unloading, under actual conditions as determined in paragraph (f)(1)(i) of this section. 

- §98.233(f)(1)(ii) should be deleted. 

Equation W-8 should be replaced with the following: 

[See original comment for revised equation W-8 on page 11] 

Where: Esa,n = Annual natural gas emissions at actual conditions in standard cubic feet/year. 

W = Number of wells with well venting for liquids unloading at the facility. 

0.37×10-3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet). 

CDW = Casing diameter for each well, in inches. 

WDW = Well depth to first producing horizon for each well, in feet. 

SPW = Shut-in Surface pressure prior to venting for each well, in pounds square inch 

atmosphereabsolute (psia). 

VW = Number of vents per year per well. (Note, the second summation was changed from V to 

VW in the revised equation above to reflect this term.) 

SFRW = Average sales flow rate of each gas well in cubic feet per hour. 

HRV,W = Hours that each well was left open to the atmosphere during each unloading event. 
243

1.0 = Hours for average well to blowdown casing volume at shut-in pressure. 

ZV,W = If HRV,W is less than 1.0 then 

ZV,W is equal to0. If HRV,W is greater than or equal to 1.0 then ZV,W is equal to 1. 

- In the equation above, API requests that the SPp term represent surface pressure prior to 

venting, in pounds per square inch absolute. As EPA had defined SPp, the shut-in pressure is 

interpreted to refer to the bottom-hole or casing pressure, which is not readily available. 

- EPA uses “pounds per square inch atmosphere”, while the correct terminology is “pounds per 

square inch absolute” which is gauge pressure + 14.7 psi and is consistent with the pressure 

adjustment included in the 0.37×10-3 constant. 

- §98.233(f)(2)(i) references §98.233(t) to adjust the natural gas volumetric emissions at standard 

conditions. This adjustment double corrects the gas volume for pressure, which is already 

included in the 0.37×10-3 constant. API notes that the August 19 amendments remove the 

reference to §98.233(t) and define SFRW in terms of gas volumes at standard conditions (60 oF 

and 14.7 psia). As indicated above, the term Ea,n should also be defined in terms of gas volumes 

at standard conditions (60 oF and 14.7 psia). 

Response: In this final rule, EPA has implemented industry’s request to change standard 

conditions to 60°F and 14.7 psi, which conforms to industry standard conditions. Please see 

EPA response to comment number EPA-HQ-OAR-2011-0147-0016, Excerpt 1. Regarding the 

two comments about equation W-7: 1) that meter reading FRh,t in most cases could be under the 

new STP condition at 60oF and 14.7 psia, and 2) that Ea,n should be defined in terms of standard 

conditions, EPA notes that a reporter could be using meters set at STP at 68oF, in which case the 

emissions would have to be converted to the new STP standard. Therefore, instead of making 

changes to equation W-7, in §98.233(t), EPA has provided STP conversion from actual to 

standard (60oF). 

Regarding the five suggested changes to equation W-8, EPA’s responses are below: 

Regarding the first suggestion to make the following replacements: “Esa,n = Annual natural gas 

emissions at actual conditions in standard cubic feet/year”, as stated in the response above 

regarding a similar comment about equation W-7, in this rule EPA has implemented industry’s 

request to change standard conditions to 60°F and 14.7 psi, which conforms to industry standard 

conditions. Again, please see EPA response to comment number EPA-HQ-OAR-2011-0147-

0016, Excerpt 1. However, EPA notes that a reporter could be using meters set at STP at 68oF, 

in which case the emissions would have to be converted to the new STP standard. Therefore, 

instead of making changes to equation W-8, in §98.233(t), EPA has provided conversion from 

68oF to 60oF. 

Regarding the following three comments and suggestions: 1) to make the following Equation W8 replacements: “SPW = Shut-in Surface pressure prior to venting for each well, in pounds 

square inch atmosphereabsolute (psia)”; 2) “EPA uses “pounds per square inch atmosphere”; 

and 3) In the equation above, API requests that the SPp term represent surface pressure prior to 

venting, in pounds per square inch absolute. As EPA had defined SPp, the shut-in pressure is 
244

interpreted to refer to the bottom-hole or casing pressure, which is not readily available, while 

the correct terminology is “pounds per square inch absolute,” which is gauge pressure plus 14.7 

psi and is consistent with the pressure adjustment included in the 0.37×10-3 constant”; EPA 

agrees with API’s definition change to SPw and in this final rule has updated Equation 8 to reflect 

“pounds per square inch absolute” instead of “pounds per square inch atmosphere”. Also, in the 

final rule, EPA is allowing the use of surface pressure in Equation W-8 with certain stipulations; 

please see preamble section II.C. - Final Amendments to the Petroleum and Natural Gas Systems 

Source Category: Well Venting for Liquids Unloading for further details. 

Regarding the comment: “§98.233(f)(2)(i) references §98.233(t) to adjust the natural gas 

volumetric emissions at standard conditions. This adjustment double corrects the gas volume for 

pressure, which is already included in the 0.37×10-3 constant. API notes that the August 19 

amendments remove the reference to §98.233(t) and define SFRw in terms of gas volumes at 

standard conditions (60oF and 14.7 psia). As indicated above, the term Ea,n should also be defined 

in terms of gas volumes at standard conditions (60oF and 14.7 psia).”, EPA has eliminated the 

double correction for pressure in the 98.233 (f)(2) by eliminating the reference to 98.233 (t) in 

98.233(f)(2)(i) in this final rule. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 14 

Commenter Type: Industry – oil and gas 

Comment: Revision: EPA has proposed corrections to Equation W-9. 

Comment API recognizes that EPA has inadvertently replicated Equation W-8 as Equation W-9 

in the August 4, 2011 revisions, but has updated the equation in the September 9, 2011 revisions. 

API will comment on the September 9 amendment separately. 

API provides the following corrected version of Equation W-9: 

[See original comment for corrected version of equation W-9 on page 12] 

Where: Esa,n = Annual natural gas emissions in standard cubic feet/year. 

W = Number of wells with well venting for liquids unloading at the facility. 

0.37×10-3 = {3.14 (pi)/4}/{14.7*144} (psia converted to pounds per square feet). 

TDW = Tubing diameter for each well, in inches. 

WDW = Tubing depth to plunger bumper for each well, in feet. 

SPW = Sales line Surface pressure for each well, in pounds per square inch 

atmosphericabsolute (psia). 

NVVW = Number of vents per year per well. 

SFRW = Average sales flow rate of each gas well in standard cubic feet per hour. 

HRV,W = Hours that each well was left open to the atmosphere during each unloading 

event. 

0.5 = Hours for average well to blowdown tubing volume at sales line pressure. 
245

ZV,W = If HRV,W is less than 0.5 then ZV,W is equal to 0. If HRV,W is greater than or equal to 

0.5 then ZV,W is equal to 1. 

- API requests that EPA modify the equation to apply the surface pressure. The use of the sales 

line pressure has no bearing for wells on compression. Using the sales line pressure in this 

situation will over-estimate emissions. 

- EPA uses “pounds per square inch atmosphere”, while the correct terminology is “pounds per 

square inch absolute” which is gauge pressure + 14.7 psi and is consistent with the pressure 

adjustment included in the 0.37×10-3 constant. 

- §98.233(f)(3)(i) references §8.233(t) to adjust the natural gas volumetric emissions at standard 

conditions. This adjustment double corrects the gas volume for pressure, which is already 

included in the 0.37×10-3 constant. API recommends removing the reference to §98.233(t) and 

defining SFRW and Ea,n in terms of gas volumes at standard conditions (60 oF and 14.7 psia),as 

shown above. 

- API requests the use of Methodology 3 for wells without plunger lifts. Methodology 3 specifies 

that it can be used only for tubing wells with plunger lifts. However, there are several instances 

in the field where one would have tubing wells without plunger lifts. In those instances there is 

no other methodology provided to calculate emissions. 

Response: Regarding the comment: “EPA uses “pounds per square inch atmosphere”, while the 

correct terminology is “pounds per square inch absolute” which is gauge pressure + 14.7 psi and 

is consistent with the pressure adjustment included in the 0.37×10-3 constant.” And the request 

to change the definition to SPw, in this final rule, EPA has changed the definition of SPw from 

“pounds per square inch atmosphere” to “pounds per square inch absolute”. 

 

Regarding the request and comment: “EPA modify the equation to apply the surface pressure. 

The use of the sales line pressure has no bearing for wells on compression. Using the sales line 

pressure in this situation will over-estimate emissions.” EPA is not allowing reporters to use 

surface pressure in Equation W-9 but is allowing the use of engineering estimate to determine 

sales line pressure when not known; please see preamble section II.C. - Final Amendments to the 

Petroleum and Natural Gas Systems Source Category: Well Venting for Liquids Unloading for 

further discussion on this issue. 

Regarding the comment: “§98.233(f)(3)(i) references §8.233(t) to adjust the natural gas 

volumetric emissions at standard conditions. This adjustment double corrects the gas volume for 

pressure, which is already included in the 0.37×10-3 constant. API recommends removing the 

reference to §98.233(t) and defining SFRW and Ea,n in terms of gas volumes at standard 

conditions (60oF and 14.7 psia),as shown above.”, EPA has eliminated the double correction for 

pressure in the 98.233(f)(3) by eliminating the reference to 98.233(t) in 98.233(f)(3)(i). 

Regarding the comment: “API requests the use of Methodology 3 for wells without plunger lifts. 

Methodology 3 specifies that it can be used only for tubing wells with plunger lifts. However, 

there are several instances in the field where one would have tubing wells without plunger lifts. 
246

In those instances there is no other methodology provided to calculate emissions.”, EPA has 

provided a detailed explanation for the use of casing diameter instead of tubing diameter in 

Calculation Methodology 2, even if the well has a tubing string and does not have a plunger lift. 

Please refer to the technical memo titled, “Change to Equation W-7: Time to Vent Gas” located 

in the Petroleum and Natural Gas Systems (Subpart W) of the Greenhouse Gas Reporting Rule 

docket (EPA-HQ-OAR-2009-0923). 

Section 7.10 ­ Gas Well Venting During Completions and Workovers from

Hydraulic Fracturing

Commenter Name: Amy Hendershot 

Commenter Affiliation: Marshall Miller & Associates, Inc 

Document Control Number: EPA-HQ-OAR-2011-0147-0015

Comment Excerpt Number: 2 

Commenter Type: Industry – oil and gas 

Comment: Field Code and Producing Horizon 

The field code where each well is located is required for several of the sections of Subpart W to 

determine representative emissions from representative fields and producing horizons, 

specifically Section (g) Gas well venting during completions and workovers with hydraulic 

fracturing. In everyday practice, this field name is not typically referenced and it would be very 

difficult to identify for each well. In an attempt to comply with the rule, a map of several wells 

was overlaid with the EIA Field Code Master List GIS layer. It became abundantly clear that this 

requirement will be very burdensome with which to comply: there is no vertical vector (depth) 

within the EIA Field Codes and, as such, there is no way to determine from the EIA Master List 

which producing horizon each field references and thus to which field a well (or portions of a 

well if it has multiple horizons) belongs. Also, the current EIA Field Code List does not include 

fields for approximately 10% of the wells that were reviewed because of the relative age of the 

some of the fields. 

Response: EPA addressed the concern with EIA field designation by proposing the use of subbasin category in the September 9, 2011 rule proposal. In this final rule, EPA has retained the 

sub-basin category designation to monitor and report emissions from specific source types. 

Please see section 98.238 for a definition of sub-basin category and preamble section I.E. – How 

Do These Amendments Apply to 2012 Reports? for further details. 

Section 7.10.1 ­ Calculating GHG Emission [W10 to W12]

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 
247

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 24 

Commenter Type: Industry – oil and gas 

Comment: Revision: Under §98.236(c)(6)(ii)(B), EPA clarified that the total count of 

workovers in the calendar year should be reported for those that flare gas or vent to the 

atmosphere. 

Comment: API supports this revision. However, API requests similar clarification be added to 

the definition of the term “N” in Equation W-13 to reflect that the number of workovers in the 

equation reflect those that flare gas or vent gas to the atmosphere. 

Response: EPA thanks the commenter for their remarks. EPA agrees with the change to the 

definition of “N” (now defined as “Nwo”) and EPA has modified this final rule accordingly. 

Section 7.10.2 ­ Data Reporting Requirements

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 25 

Commenter Type: Industry – oil and gas 

Comment: API also notes that there is an inconsistency between the preamble and the revised 

regulatory text. The preamble (page 47400, 1st column, under “Other Technical Corrections”) 

states: “EPA is proposing to clarify in 40 CFR §98.236(c)(6)(ii)(B) that only the number of 

workovers with hydraulic fracturing that vent gas to the atmosphere or flare gas needs to be 

reported . The current rule language could suggest you must report on the total number of 

workovers per year, including those that don’t involve hydraulic fracture and those that do not 

vent gas to the atmosphere.” 

The text in the preamble is inconsistent with the regulatory text since §98.236(c)(6)(i)(A-H) are 

the reporting requirements for completions/workovers with hydraulic fracturing; and 

§98.236(c)(6)(ii)(A-D) are the reporting requirements for completions/workovers without 

hydraulic fracturing. Despite the text in the preamble the revisions in the regulatory text were 

made under §98.236(c)(6)(ii)(B), where for workover and completions without hydraulic 

fracturing EPA has changed from “Total count of workover in calendar year” to “Total count of 

workovers in calendar year that flare gas or vent gas to the atmosphere”. 

API requests EPA to clarify this inconsistency, and as noted above, it supports the revision as 

reflected in the regulatory language. However, we wanted to point out this inconsistency and 

confirm that EPA’s intent is reflected in the revision to the regulatory language under 

§98.236(c)(6)(ii). 
248

Response: EPA agrees and therefore EPA has finalized this requirement in §98.236(c)(6)(ii)(B). 

Section 7.11 ­ Gas Well Venting During Completions and Workovers Without

Hydraulic Fracturing

Section 7.11.1 ­ Calculating GHG Emission [W13]

Commenter Name: Amy Hendershot 

Commenter Affiliation: Marshall Miller & Associates, Inc 

Document Control Number: EPA-HQ-OAR-2011-0147-0008

Comment Excerpt Number: 2 

Commenter Type: Industry – oil and gas 

 Comment: § 98.233 Calculating GHG emissions. 

(h) * * * 

The definitions of the variables within Equation W-13 in section (h) has been revised. The 

original rule indicated we were solving for Ea,n but the revised definition (the equation was not 

revised) indicates “Es,n = Annual natural gas emissions in standard cubic feet from a gas well...” 

Which should it be? Ea,n or Es,n? 

Response: In this final rule EPA has revised the output of equation W-13 to Es,n, which is 

emissions in standard cubic feet. This follows the clarification of the input terms EFwo and Vp as 

being in standard cubic feet. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 15 

Commenter Type: Industry – oil and gas 

Comment: Revision: EPA has revised the emission factor for non-hydraulic fracture well 

workover venting from 2,454 scf CH4/workover to 3,114 scf gas/workover. 

Comment: API has reviewed this correction and confirmed that EPA is adjusting the emission 

factor of 2,454 scf CH4/workover to a natural gas basis, based on 78.8 mol% CH4. This 

conversion does result in 3,114 scf natural gas/workover, as shown below, where standard 

conditions are 60 oF and 14.7 psia. 

[See original comment for equation on page 13] 

Response: In this final rule, at the suggestion of industry, EPA has adopted consistent use of 

industry standard conditions (60°F and 14.7 psia). Please see comment number EPA-HQ-OAR2011-0147-0016, Excerpt 1. Accordingly, EPA has updated the final rule, including revising the 
249

emission factor for non-hydraulic fracture well workover venting from 2,454 scf CH4/workover 

to 3,114 scf natural gas/workover. 

Section 7.12 ­ Blowdown Vent Stack

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0147-0029

Comment Excerpt Number: 3 

Commenter Type: Trade Association 

Comment: INGAA supports the proposed revision to the definition of "blowdown vent stack" 

in §98.6 but additional clarification is required regarding blowdown vent reporting. 

The definition of "blowdown vent stack" is revised to clarify that emissions from emergency 

events are not included. INGAA supports this revision. However, when considered along with 

§98.233(i), additional clarification on blowdown vent emissions reporting is required, especially 

when considering additional revisions proposed by EPA in the September 9 proposed revisions. 

INGAA will provide additional comment when responding to the September 9 proposal, but the 

issue relates to clearly indicating which type of blowdown events are to be reported under 

§98.233(i). This requires a clear definition in §98.6, as well as consistent and clear text in 

§98.233(i), including introductory text explaining which types of blowdowns are included and 

excluded. Currently, and based on revisions proposed in the September 9 proposed revisions, 

§98.233(i) is not clear. 

Response: EPA acknowledges that the provision regarding emergency equipment blowdown is 

different between the August 4, 2011 and September 9, 2011 proposals. The proposed technical 

corrections published on August 4, 2011 (76 FR 47392) reflected clarifications determined to be 

necessary based on questions and issues raised on the GHG Reporting Program hotline in the 

first half of 2011. Subsequent to development of the August “2011 Technical Corrections, 

Clarifying and Other Amendments” proposed rule, EPA learned that some of the technical 

amendments proposed there did not fully correct the technical errors or were not fully reflective 

of industry practice, as understood by EPA at the time of that proposal. Therefore, EPA further 

clarified the proposed requirements in its September 9, 2011 proposal. Because of the close 

relationship between the August 4, 2011 and September 9, 2011 proposals, and the need to 

consider the comments in total before finalizing the respective requirements, EPA decided not to 

finalize the technical corrections to subpart W when finalizing the August “2011 Technical 

Corrections, Clarifying and Other Amendments” final rule. 

As suggested, in this final rule, EPA has added additional clarification on blowdown vent stacks 

reporting. Please see preamble section II.C. - Final Amendments to the Petroleum and Natural 

Gas Systems Source Category: Blowdown Vent Stacks, which clarifies that the following 

blowdowns are covered: the types of blowdowns typically tracked by operators for emergency 

shutdowns resulting from human intervention or when taking equipment out of service for 

maintenance; and not automated releases that do not require human intervention, such as valve 
250

releases designed to keep equipment under safe operating mode. Please see section 98.233(i), 

which has been amended to clarify the types of blowdowns that must be reported and the types 

of blowdowns that are not required to be reported. 

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0147-0029

Comment Excerpt Number: 4 

Commenter Type: Trade Association 

Comment: INGAA supports §98.233(i) revisions clarifying that physical volumes less than 50 

cubic feet are exempt from reporting, but additional revisions are needed to consistently apply 

appropriate terminology. 

§98.233(i) revisions clarify that the exempt volume is a "physical" volume of 50 cubic feet 

(rather than a volume of 50 standard cubic feet). INGAA supports this revision. However, the 

term “physical volume” needs to be consistently used and terminology related to "standard" 

conditions should not be used when referring to physical volumes. The Proposed Rule still uses 

the term standard cubic feet when identifying volumes exempt from blowdown reporting. In 

§98.233(i), the term "physical" should be consistently used and "standard" should be deleted. 

The Proposed Rule revisions along with additional recommendations are provided here: 

“If the total physical [EPA proposed revision] volume between isolation valves is greater than or 

equal to 50 standard [EPA proposed revision]cubic feet, retain logs of the number of blowdowns 

for each equipment type (including but not limited to compressors, vessels, pipelines, headers, 

fractionators, and tanks). Physical Blowdown [ADDITIONAL REVISION RECOMMENDED] 

volumes smaller than 50 standard [ADDITIONAL REVISION RECOMMENDED]cubic feet are 

exempt from reporting under paragraph (i) of this section.” 

Response: EPA thanks the commenter for pointing out the inconsistency and has clarified 40 CFR 

98.233(i) to remove the term “standard”. 

Section 7.12.2 ­ Data Reporting Requirements

Commenter Name: Lisa Beal 

Commenter Affiliation: Interstate Natural Gas Association of America (INGAA) 

Document Control Number: EPA-HQ-OAR-2011-0147-0029

Comment Excerpt Number: 8 

Commenter Type: Trade Association 

Comment: Reporting Requirements: §98.236(c)(7)(i) reporting for blowdown vents should be 

revised. In addition, to complement the Proposed Rule and the September 9 proposed revisions, 

EPA will need to revise the recently adopted criteria in Subpart A Table A-7 regarding data 

elements where reporting is deferred until 2015. 
251

§98.236(c)(7)(i) reporting for blowdowns includes the number of blowdowns "per unique 

volume type". As indicated by INGAA recommendations (see EPA-HQ-OAR-2011-0512-0013), 

an alternative equation is needed (i.e., summing the annual blowdown volumes by event). With 

that approach, only the total volume should be reported. “Unique volume type” is a misnomer for 

determining compressor station blowdown emissions because most events will be associated 

with a unique circumstance and repetitive blowdown of the same volume is not the norm. The 

reporting section for blowdown vents should be revised to include reporting associated with the 

current equation (which is revised to Equation W-14A in the September 9 proposed revisions) 

and separate criteria for blowdown emissions calculated by summing individual events (i.e., see 

approach associated with Equation W-14B in the September 9 proposed technical corrections). 

INGAA will provide additional details in October comments on the second proposal. 

In addition, EPA will need to propose additional corrections to Subpart A to reconcile ongoing 

revisions in Subpart W with the recently adopted, "Change to the Reporting Date for Certain 

Data Elements Required Under the Mandatory Reporting of Greenhouse Gases Rule" (see 76 FR 

53057 to 53071). That rule was published in the Federal Register on August 25, 2011 and 

identifies data elements used for Subpart W emission estimation calculations where reporting is 

deferred until March 31, 2015. The pending technical revisions to Subpart W will result in 

anomalies and additional data elements for Subpart A, Table A-7. EPA needs to adopt changes 

expediently so that 2012 reporting obligations are clearly defined in Table A-7 and reflect the 

pending technical corrections to Subpart W. 

Response: With respect to revisions to Subpart A Table A-7 deferrals and additional corrections 

to Subpart A, EPA is addressing these changes, and will be publishing an updated list of data 

elements in an upcoming rulemaking. 

In regard to the first comment about the need to revise the reporting section to include separate 

criteria for blowdown emissions calculated by summing individual events, EPA agrees that the 

data reporting requirements for blowdown vent stacks should accurately represent the calculation 

methodologies in 98.233(i). In this final rule, EPA is amending Equations W-14A and W-14B 

and the associated data reporting requirements for blowdown vent stacks. For further details, 

please see the response to EPA-HQ-OAR-2011-0512-0029, Excerpt 16. 

Section 7.13 ­ Onshore Production Storage Tanks

Section 7.13.1 ­ Calculating GHG Emission [W­15, W­16]

Commenter Name: Amy Hendershot 

Commenter Affiliation: Marshall Miller & Associates, Inc 

Document Control Number: EPA-HQ-OAR-2011-0147-0007

Comment Excerpt Number: 4 

Commenter Type: Industry – oil and gas 

Comment: § 98.233 Calculating GHG emissions. 
252

(j) * * * 

(8) * * * 

MM&A has found issues with the original as well as the revised equation W-16. The units do not 

work out properly, and there seems to be a flaw in the logic. Please see attached PDF for details. 

Response: EPA agrees with the commenter. Please see the response to EPA-HQ-OAR-2011-

0147-0007, Excerpt 6 for further information. 

Commenter Name: Amy Hendershot 

Commenter Affiliation: Marshall Miller & Associates, Inc 

Document Control Number: EPA-HQ-OAR-2011-0147-0007

Comment Excerpt Number: 6 

Commenter Type: Industry – oil and gas 

Comment: W-16 (j)(8) onshore production storage tanks and occurrences of well pad gas-liquid 

separator liquid dump valves not closing during calendar year 

[See original comment for handwritten equations] 

Es1i = (CFN * EN/8760 * TN) + (EN * (8760 – TN)) 

ft3/hr = (No unites * ft3/year / 8760 hr/year * hr/hr) + (ft3/year * (8760 hrs/year – hrs/hr) 

= ft3/yr + (ft3 * hr/yr2) units not the same cannot sum here => something off with eq. W-16. 

Es1i – Total volumetric GHG emissions @ STP from each storage tank 

CFN = Correction Factor: 3.87 => crude oil production for time period TN 

5.37 => gas condensate production for the period TN 

1.0 = periods when dump value is closed 

TN = Total time dump valve is not closing properly during calendar year (hrs/yr) 

Estimate by Maintenance/Ops records 

When record shows open, it is assumed open since last record. If next record shows closed, it is 

assumed closed from that time forward until next reading or, if no reading, through the end of 

calendar year. 

EN = storage tank emissions as calculated in j(1), j(2) and j(4) => all having well head separators 

(ft3/year) 

Assume closed all year => TN = 0 hrs/year and that units aren’t as issue 

Es1i = (1 EN/8760 0 + (EN (8760 - 0) 

= 0 + [EN – 8760] 

= 8760 EN =>But if closed all year there should be no emissions 

This again seems to show something is off with the Eq. W-16 
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Response: EPA agrees with the issue in Equation W-16 and has corrected the problem in this 

final rule. The units of En are standard cubic feet per year; therefore the conversion from hours to 

year is necessary in the second part of Equation W-16. EPA has included a divisor of 8760 to the 

part of the Equation after the summation point (En(8760-Tn)), which will resolve the issue 

highlighted in the equation. 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 17 

Commenter Type: Industry – oil and gas 

Comment: Revision: Under §98.233(j), EPA has clarified that the annual average daily 

throughput is used to assess if the separator oil flow is less or more than 10 barrels per day. 

Comment: API supports this clarification. 

Response: EPA has finalized, as proposed, the clarification to §98.233(j). 

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 19 

Commenter Type: Industry – oil and gas 

Comment: Revision: In Equation W-16, EPA added a correction to the first part of the equation 

to convert the time aspect of the emission factor from an annual basis to an hourly basis. 

Comment: The proposed revisions did not correct the units in the second part of the equation. 

The correct equation should be: 

[See original comment for equation on page 14] 

Response: EPA agrees with the correction presented in the comment and made the necessary 

correction in this final rule; please see response to EPA-HQ-OAR-2011-0147-0007, Excerpt 6 

for further details. 

Section 7.25 ­ Onshore Petroleum and Natural Gas Production and Natural Gas

Distribution Combustion Emissions

Section 7.25.1 ­ Calculating GHG Emission [W­39, W­40]
254

Commenter Name: Karin Ritter 

Commenter Affiliation: American Petroleum Institute (API) 

Document Control Number: EPA-HQ-OAR-2011-0147-0016

Comment Excerpt Number: 21 

Commenter Type: Industry – oil and gas 

Comment: Revision: EPA revised Equation W-39 to account for CO2 present in the combusted 

gas, to apply a combustion efficiency, and to separately quantify CH4 emissions from 

combustion. 

Comment: For determining the combustion efficiency, ?, API supports the use of engineering 

estimate. In addition, API requests the option of using a combustion efficiency of 99.5%, as 

referenced in the footnotes of AP-42 Tables 3.2-1, 3.2-1, and 3.2-2. 

Response: EPA agrees with the commenter’s suggestion to use a default combustion efficiency 

of 99.5% in Equation W-39A and Equation W-39B for internal combustion devices only and has 

made appropriate changes in this final rule. This default combustion efficiency will not apply to 

external combustion devices that must report under 98.233(z). 

Commenter Name: Pamela Lacey 

Commenter Affiliation: American Gas Association (AGA) 

Document Control Number: EPA-HQ-OAR-2011-0147-0028

Comment Excerpt Number: 4 

Commenter Type: Industry – oil and gas 

Comment: Combustion Emissions from Natural Gas Distribution Operations: It will be helpful 

to have additional clarification regarding how to calculate combustion emissions for natural gas 

distribution facilities, particularly methane combustion emissions. Our members were confused 

by the existing rule that did not describe how to determine methane emissions form fuel 

combustion. See 76 Fed. Reg. at 47,399. 

Response: In the September 9, 2011 proposal, EPA proposed adding Equation W-39B to 

calculate methane emissions from combustion equipment. EPA has finalized this equation in this 

final rule. 

 
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