1 

MEMORANDUM 

TO: Docket ID No. EPA-HQ-OAR-2014-0831 

FROM: Alexis McKittrick and Mark de Figueiredo, EPA/CCD

DATE: November 13, 2014 

SUBJECT: Greenhouse Gas Reporting Rule: Technical Support for 2015 Revisions and 

Confidentiality Determinations for Petroleum and Natural Gas Systems; Proposed 

Rule 

The U.S. Environmental Protection Agency (EPA) is proposing revisions to 40 CFR part 

98, subpart W (hereafter referred to as “subpart W”). This memorandum provides background 

information on proposed revisions relating to the following emission sources or specific 

provisions1

: 

1. Oil Well Completions and Workovers with Hydraulic Fracturing 

2. Onshore Petroleum and Natural Gas Gathering and Boosting Segment 

3. Natural Gas Transmission Lines Between Compressor Stations 

4. Well Identification Numbers 

1 OIL WELL COMPLETIONS AND WORKOVERS WITH HYDRAULIC

FRACTURING 

The EPA is proposing to amend subpart W to include provisions for the reporting of 

greenhouse gas (GHG) emissions from oil well completions and workovers with hydraulic 

fracturing in the Onshore Petroleum and Natural Gas Production segment. Consistent with the 

requirements for gas well completions and workovers with hydraulic fracturing, the proposed 

provisions include the reporting of activity data on the number of oil well completions and 

workovers with hydraulic fracturing and on the use of flaring and reduced emission completions. 

The EPA is also proposing to update calculation methods accordingly under 40 CFR 98.233(g) 

to reflect applicability to both gas well and oil well completions and workovers with hydraulic 

fracturing. 

 

1

 For background information related to other aspects of the proposed rule, please refer to documents contained in 

Docket ID No. EPA-HQ-OAR-2014-0831. 
2 

Calculation Method 

The EPA is proposing to require Calculation Method 1, currently specified in subpart W 

for gas wells, for calculating inputs to Equations W-12A and W-12B for oil wells, which relies 

on direct measurement of gas flow rate during flowback. In subpart W, Calculation Method 2 

uses the measured gas pressure differential across a well choke to estimate gas flow rate, but the 

EPA is not proposing to allow the use of Calculation Method 2 for oil wells. Calculation Method 

2 is based on the choke flow equation in Perry’s Chemical Engineering Handbook2, which is 

intended for use with compressible flows, particularly gases. In practice, this includes gases, 

supercritical fluids, and multiphase flows containing mostly gases. Based on the information 

available, the EPA concluded that this methodology may not be appropriate for estimating 

emissions from oil well completions because of the differences in operational conditions between 

oil and gas production. The EPA was unable to identify a methodology other than direct 

measurement, appropriate for calculating gas flow rate during flowback for oil well completions 

or workovers with hydraulic fracturing. 

The goal of the flowback process for oil well completions and workovers with hydraulic 

fracturing is to remove all the fracturing fluids from the formation so that the reservoir fluids (oil

and gas) can begin to flow. The duration of the flowback period is largely determined by 

reservoir characteristics. Operators are able to measure flowback gas when there is sufficient gas 

flow and a sufficient reduction in sand returns to route the flow to a separator. 

Calculation Method 1 requires two parameters, FRMs (Equation W-12A) and FRMi

(Equation W-12B), which are, respectively, the ratio of average gas flowback to 30-day gas 

production rate and the ratio of initial gas flowback to 30-day gas production rate. For oil wells 

where the gas production rate is not metered, the EPA is proposing a new Equation W-12C that 

allows reporters to use the average GOR during the first 30 days of production to estimate the 

average 30-day gas production flow rate following a completion or workover. 

Estimation of Emissions based on Published Literature 

Data from published literature were reviewed to estimate emissions that may be reported 

to the GHGRP from oil well completions or workovers with hydraulic fracturing if these 

proposed revisions are finalized3. One source estimated approximately 6,200 oil well

 

2 Perry’s Chemical Engineering Handbook. Seventh Edition. Ed. R.H. Perry and D.W. Green. Chapter 6: Fluid and 

Particle Dynamics, Fluid Dynamics: Compressible Flow, p. 6-22. 

3

 Subpart W does not currently cover emissions from oil well completions and workovers with hydraulic fracturing, 

except for associated flaring emissions that may be reported under the miscellaneous flare stacks category. The 

limited data available on oil well completions and workovers with hydraulic fracturing are summarized in the 

document, Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas during 

Ongoing Production. Some stakeholders have opined that some subpart W reporters have reported gas well 

completions and workovers data from oil formation sub-basins to the EPA through the Electronic Greenhouse Gas 
3 

completions with hydraulic fracturing in 20114. For purposes of the analysis in this 

memorandum, the EPA assumed the number of oil well completions and workovers with 

hydraulic fracturing located at facilities meeting the threshold for reporting under subpart W 

when the rule is proposed to take effect would be similar to the activity level in 2011. It is 

anticipated that the number of gas and oil wells has increased and will continue to increase 

substantially in the future because of the continued and expanding use of horizontal drilling 

combined with hydraulic fracturing. Therefore, this estimate may be an underrepresentation and 

the actual number of oil well completions or workovers with hydraulic fracturing may in fact be 

larger than 6,200. The Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012

published in 2014 (hereafter referred to as the “2014 U.S. GHG Inventory”) does not currently 

distinguish between oil wells with and without hydraulic fracturing, but estimates that over 

15,000 oil wells (both wells with and without hydraulic fracturing) were completed in 20125

. 

In published literature, estimates of potential methane emissions from oil well 

completions with hydraulic fracturing (i.e., emissions in the absence of controls) range from 7.7 

tons of methane (CH4) per completion6 to 32 tons of CH4 per completion7. Multiplying these 

values by the activity levels described above (i.e., 6,200 completions and workovers) gives a 

potential emissions range of 47,700 tons CH4 per year to 198,400 tons CH4 per year (43,300 to 

180,000 metric tons (MT) CH4 per year). 

 

Reporting Tool (e-GGRT). However, the EPA notes that subpart W does not currently specify an emissions

calculation or estimation method for oil well completions and workovers with hydraulic fracturing. Therefore, the 

EPA did not assess these data as part of our technical analysis for this proposed new emission source.

4

 Memorandum from Eastern Research Group, Inc. (ERG) to EC/R Incorporated. Hydraulically Fractured Oil Well 

Completions. October 24, 2013. 

5

 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012. EPA 

430-R-14-003. April 15, 2014. 

6

Ibid. 

7

 O’Sullivan, Francis and Sergey Paltsev, “Shale gas production: potential versus actual greenhouse gas emissions”, 

Environmental Research Letters, United Kingdom. November 26, 2012. 
4 

2 ONSHORE PETROLEUM AND NATURAL GAS GATHERING AND 

BOOSTING SEGMENT 

Overview of Gathering and Boosting Systems 

A gathering and boosting system is a single network of pipelines, compressors and 

process equipment, including equipment to perform natural gas compression, dehydration, and 

acid gas removal, that has one or more connection points to gas and oil production and a 

downstream endpoint. Gathering pipelines are used to transport petroleum and natural gas from 

the downstream exit points of onshore production facilities (e.g., wells) to one of the downstream 

endpoints, typically a gas processing plant, transmission pipeline, local distribution company 

(LDC) pipeline, or other gathering and boosting system. Compressors located along the 

gathering and boosting system are used to control or “boost” the pressure of the gas in the 

pipeline and keep the gas moving downstream. Acid gas removal units and dehydrators may be 

located on the gathering and boosting system to treat the collected natural gas to remove 

contaminants and prevent corrosion. 

Specifically, the emissions sources that may be present in a gathering and boosting 

system include: 

• Pneumatic devices 

• Acid gas removal units 

• Dehydrators 

• Blowdown vent stacks (including those on gathering pipelines) 

• Storage vessels and separators 

• Flares 

• Compressors 

• Equipment leaks from system components (e.g., valves, connectors, pressure relief 

valves) 

• Gathering pipelines (emissions from pipeline leaks)

• Combustion sources (e.g., engines, boilers, heaters) 

Subpart W currently does not specifically cover emissions from gathering and boosting 

systems. Some sources, such as boosting compressor stations, with combustion emissions that 

exceed the reporting threshold of 25,000 metric tons carbon dioxide equivalent (MT CO2e) 

report those emissions to the Greenhouse Gas Reporting Program (GHGRP) under 40 CFR part 
5 

98, subpart C (Stationary Combustion) (hereafter referred to as “subpart C”)8. Subpart W does 

cover emissions from sources such as compressors and dehydrators in other industry segments 

currently defined in subpart W, such as the Onshore Natural Gas Processing segment or Onshore 

Petroleum and Natural Gas Production (which includes sources located on a single well pad or 

associated with a single well pad). 

Estimates of Nationwide GHG Emissions for Gathering and Boosting Systems 

Two sources of GHG emissions data for gathering and boosting systems were used to 

estimate nationwide emissions. This section describes those sources of data and the methods 

used to estimate emissions. 

The first data source is the 2014 U.S. GHG Inventory

9

, which includes CH4 and CO2

emission factors and estimates of GHG emissions for some of the emission sources in gathering 

and boosting systems. In particular, the U.S. GHG Inventory includes fugitive and vented 

emission estimates for gathering reciprocating compressors and for gathering pipelines. In the 

U.S. GHG Inventory, gathering and boosting systems are included as part of the natural gas 

systems production segment. While some sources are considered to be specifically within 

gathering in the U.S. GHG Inventory (reciprocating compressors and pipelines in the production 

segment), vented and fugitive GHG emissions from equipment sources that are common to both 

well production sites and gathering systems, such as dehydrators, storage vessels and separators, 

and pneumatic devices, are not characterized in the U.S. GHG Inventory into further subsegments. 

Applying a global warming potential of CH4 of 25, the estimated emissions for gathering 

and boosting compressors and pipeline leaks in the 2014 U.S. GHG Inventory are approximately 

10 million metric tons (MMT) CO2e. This amount is likely lower than the total emissions from 

all emission sources in gathering and boosting, due to the 2014 U.S. GHG Inventory 

methodology which accounts for fossil fuel combustion elsewhere and includes other gathering 

and boosting emissions sources in the overall production segment number. 

An analysis conducted by the Interstate Natural Gas Association of America (INGAA) 

using data from the 2007 U.S. GHG Inventory estimated the “split” of GHG emissions from 

combustion versus fugitive and vented GHG emissions (i.e., process emissions) for natural gas 

systems10. The INGAA analysis, which was used as a rough estimate to assist in approximating 

combustion emissions from gathering and boosting systems, compared total combustion 

 

8

 In 2013, 439 facilities with one or more of the NAICS codes for a petroleum or natural gas facility reported to the 

GHGRP under subpart C but not subpart W. The EPA expects that some of these facilities would be part of the 

proposed Onshore Petroleum and Natural Gas Gathering and Boosting segment. 

9

 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012. EPA 

430-R-14-003. April 15, 2014. 

10 INGAA. “Emissions from the Natural Gas Industry.” Available at http://www.ingaa.org/cms/6435.aspx. 
6 

emissions and process emissions for natural gas production, natural gas processing and 

transportation and storage. The INGAA analysis found that of the 76.6 MMT CO2e emissions 

reported for natural gas production in the 2007 U.S. GHG Inventory, 41.4 MMT CO2e were 

combustion emissions (54 percent) and 35.2 MMT CO2e (46 percent) were “release of methane” 

(fugitive emissions and venting)11. Further, combustion emissions represented about 25% of the 

2013 subpart W CO2e emissions totals for the Onshore Petroleum and Natural Gas Production 

segment and approximately 65% of the Onshore Natural Gas Processing segment emissions 

totals. The EPA anticipates that the proposed Onshore Petroleum and Natural Gas Gathering and 

Boosting segment is expected to fall between these two segments in terms of percentage of total 

emissions related to combustion. 

Assuming that the ratio of process emissions and combustion emissions is consistent with 

the INGAA analysis between years and industry segments, then process emissions are 

approximately 46 percent of the total emissions associated with gathering and boosting. 

Conservatively assuming that the approximate value of 10 MMT CO2e is a low-bound estimate 

of total process emissions from the gathering and boosting segment, this would bring the total 

emissions from both process and combustion emissions in gathering and boosting to 

approximately 22 MMT CO2e. This is a low-bound estimate because the amount does not 

include the additional process equipment mentioned above. 

 The second data source is ICF International’s report from March 2014, titled Economic 

Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas 

Industries12, which developed a 2011 emissions baseline for the gathering and boosting segment. 

The emissions baseline developed for this analysis used the 2013 U.S. GHG Inventory13 as a 

starting point and supplemented the activity factors (equipment counts) and emissions factors 

data with data from several sources including GHGRP from reporting year 2012 and recent 

direct measurement studies of gathering and boosting sources14. 

 The ICF study includes the following equipment in its gathering and boosting analysis: 

• Reciprocating compressors; 

• Centrifugal compressors; 

• Compressor exhaust; 

 

11 Ibid.

12 ICF International. Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and 

Natural Gas Industries. March 2014. Available at 

http://www.edf.org/sites/default/files/methane_cost_curve_report.pdf. 

13 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990– 2011. 

EPA 430-R-13-001. April 12, 2013. 

14 For example, Allen, David, et. al., Measurements of Methane Emissions at Natural Gas Production Sites in the 

United States. Published in Proceedings of the National Academy of Sciences of the United States of America, 

110(44): 17768–17773, October 29, 2013. 
7 

• Gathering and boosting stations; 

• Pneumatic devices; 

• Pipeline leaks; 

• Dehydrators; 

• Kimray pumps; and 

• Condensate tanks. 

This study estimated emissions from Gathering and Boosting to be 0.8 MMT of CH4 or 

20 MMT CO2e. These estimates include process emissions but do not include combustion 

emissions. Using the INGAA analysis15 referenced above to assume that process emissions of 30 

MMT CO2e are approximately 46 percent of the total emissions associated with gathering and 

boosting, this would bring the total emissions from both process and combustion emissions in 

gathering and boosting to approximately 43.5 MMT CO2e. 

Based on the approaches discussed above, the estimated total emissions from the 

gathering and boosting segment of the petroleum and natural gas industry may range between 22 

MMT CO2e and 43.5 MMT CO2e, including both process and combustion emissions. For 

comparison, Table 2.1 shows the total emissions from both process and combustion emissions 

reported by facilities in other petroleum and natural gas industry segments. 

Table 2.1. Petroleum and Natural Gas Systems Sector — 

2013 Reported GHG Emissions by Industry Segment 

(Reported to the GHGRP as of August 18, 2014) 

Industry Segment 2013 Reported Emissions 

(MMT CO2e) 

Onshore Petroleum and Natural Gas Production 95 

Offshore Petroleum and Natural Gas Production 6 

Onshore Natural Gas Processing 59 

Onshore Natural Gas Transmission Compression 23 

Underground Natural Gas Storage 1 

Liquefied Natural Gas (LNG) Import and Export Equipment < 1 

LNG Storage < 1 

Natural Gas Distribution 15 

 

 

15 INGAA. “Emissions from the Natural Gas Industry.” Available at http://www.ingaa.org/cms/6435.aspx. 
8 

Definitions 

Gathering and Boosting System 

The term “gathering system” (including gathering pipeline system, gas gathering system 

and oil gathering system) is commonly used in the petroleum and natural gas industry, including 

by the American Gas Association, the EIA, and individual mid-stream companies, though the 

exact definition of this term is not always consistent between groups. The compressors used to 

“boost” the pressure of the petroleum or natural gas are generally referred to in the industry as 

compressor stations or boosting stations. Since there is some ambiguity in the definition of these 

sources by different groups, the EPA determined that a definition of “gathering and boosting 

system” would be the best way to clarify what is included in the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment. 

Two main sources were used to develop the definition of “gathering and boosting 

system.” The first is the definition of “gathering system” provided by Schlumberger in their 

Oilfield Glossary16

: 

The [pipeline] network and process facilities that transport and control the 

flow of oil or gas from the wells to a main storage facility, processing plant or 

shipping point. A gathering system includes pumps, headers, separators, 

emulsion treaters, tanks, regulators, compressors, dehydrators, valves and 

associated equipment. There are two types of gathering systems, radial and 

trunk line. The radial type brings all the (pipelines) to a central header, while 

the trunk-line type uses several remote headers to collect fluid. The latter is 

mainly used in large fields. The gathering system is also called the collecting 

system or gathering facility. 

The second is the definition of “gathering line” in 49 CFR 192.3 and the description of 

how to determine if a gathering line is a “regulated onshore gathering line” under 49 CFR 192.8. 

A “gathering line” is defined as “a pipeline that transports gas from a current production facility 

to a transmission line or main” (49 CFR 192.3). The regulations in 49 CFR 192.8 incorporate by 

reference the American Petroleum Institute Recommended Practice 80, Guidelines for the 

Definition of Onshore Gas Gathering Lines (API RP 80),17 which defines a “gathering line” as: 

 

16 Schlumberger Limited. The Oilfield Glossary. Available at http://www.glossary.oilfield.slb.com/. Last accessed 

September 30, 2014. 

17 API Recommended Practice 80, “Guidelines for the Definition of Onshore Gas Gathering Lines.” 1st edition, 

April 2000. 
9 

... any pipeline or part of a connected series of pipelines used to (1) transport 

gas from the furthermost downstream point in a production operation to the 

furthermost downstream of the following endpoints...: 

(A) the inlet of the furthermost downstream natural gas processing plant, other 

than a natural gas processing plant located on a transmission line, 

(B) the outlet of the furthermost downstream gathering line gas treatment 

facility, 

(C) the furthermost downstream point where gas produced in the same 

production field or separate production fields is commingled, 

(D) the outlet of the furthermost downstream compressor station used to lower 

gathering line operating pressure to facilitate deliveries into the pipeline from 

production operations or to increase gathering line pressure for delivery to 

another pipeline...; or 

(2) transport gas from a point other than in a production operation exclusively 

to points in or adjacent to one or more production operations or gathering 

facility sites for use as fuel, gas lift, or gas injection gas within those 

operations...” 

To fully address gathering and boosting within subpart W, the EPA needed to consider 

individual compressor stations / boosting stations that perform compression and processing for 

the gathering line systems. API RP 80 notes that “gas treatment often occurs in conjunction with 

gas processing or compression and in such cases is considered to be part of those operations.” In 

some cases, however, gas treatment operations involve significant stand-alone facilities (e.g., a 

sulfur recovery or large dehydration facility). 

Given this information, the EPA is proposing to define a “gathering and boosting system” 

as “a single network of pipelines, compressors and process equipment, including equipment to 

perform natural gas compression, dehydration, and acid gas removal, that has one or more 

connection points to gas and oil production and a downstream endpoint, typically a gas 

processing plant, transmission pipeline, LDC pipeline, or other gathering and boosting system.” 

Owner/Operator 

Petroleum and natural gas gathering and boosting and natural gas processing are 

operations often considered to be in the “midstream” sector of the petroleum and natural gas 

industry. While some midstream operations are owned by companies that also have upstream and 
10 

downstream operations, many of the gathering and boosting systems are constructed, owned and 

operated by midstream specialists. In addition, there are midstream contractors who operate 

gathering systems that are owned by another firm18. 

One of the issues identified by commenters with the EPA’s original proposal to include 

gathering and boosting operations in the 2010 rule was that the EPA did not adequately address 

the multiple ownership scenarios for gathering and boosting systems. Several ownership and 

operating scenarios for gathering pipeline systems were identified through preliminary research 

and review of publically available information for some gathering pipeline systems and 

midstream sector companies. Some examples are provided in the following list, which is 

intended for illustration, not as a comprehensive characterization of the midstream sector. 

• The gathering and boosting system is owned by a vertically integrated oil and gas 

company. The company owns the production wells, the gathering and boosting 

system, and the gas processing plant. The gathering and boosting system may be 

operated by a contractor; some equipment may be leased. 

• The gathering and boosting system is owned by an oil and gas exploration and 

production company. The company may own the production wells, but does not own 

downstream gas processing. The gathering system may be operated by a contractor 

and some equipment may be leased. 

• The gathering and boosting system is owned and operated by a single company 

specializing in the oil and gas mid-stream sector, which may include gathering and 

boosting and gas processing. 

• The gathering and boosting system is owned and operated in partnership by multiple 

entities. Such entities could include midstream companies, limited partnerships, 

investors, and midstream subsidiaries of oil and gas production companies. Shared or 

split management may be evident. Under a shared management arrangement, the 

gathering and boosting system may be managed by committee of stakeholder 

representatives. Operation of the gathering and boosting system may be designated to 

one of the owners or contracted. Under a split management arrangement, one of the 

owners may provide administrative management, one may provide operating 

management, and one may provide general management.

Under any of the scenarios above, all or portions of the operation of the gathering system 

may be contracted. However, the contractor typically is not considered the party responsible for 

the gathering system. That responsibility lies with the owners. In addition, a gathering and 

boosting system owner or partial owner may have full or partial ownership of multiple gathering 

 

18 See 2014 Midstream Directory published by Hart Energy, www.hartenergy.com. See also, Midstream Business,

published by Hart Energy and MidstreamBusiness.com 
11 

and boosting systems within a basin and/or full or partial ownership of gathering and boosting 

systems in other basins. 

As part of the reporting process under the GHGRP, reporters must select a designated 

representative (DR) who is responsible for certifying, signing, and submitting all submissions to 

the EPA. While the DR may need to acquire necessary reporting information from a third party, 

the Part 98 certification provisions in 40 CFR 98.4(e)(1) simply require the DR to make 

“appropriate inquiry” and certify to the best of his or her knowledge when reporting; ultimate 

responsibility rests and must necessarily rest on him or her. The DR may provide in contracts, 

leases, or other agreements with third parties that true, accurate, and correct reporting 

information must be provided to the DR in a timely fashion. If the third party fails to provide 

timely, true, accurate, or correct information to the DR, then the DR has recourse contractually, 

or otherwise, on the third party19

. 

Another consideration when determining the definition of owner or operator is the 

responsibility for reporting emissions. For example, it may be necessary to consider scenarios 

such as who would have reporting responsibility if two companies own a 50 percent stake in a 

gathering and boosting system, (each individual company or the joint venture), and whether the 

reporting responsibility would change if one of the individual companies also owns another 

nearby gathering and boosting system. 

The EPA has previously promulgated language in 40 CFR 98.4 to address emissions 

reporting responsibility for facilities with multiple owners/operators through a designated 

representative. Under this provision, gathering and boosting facilities with multiple owners 

would identify and authorize a designated representative who would be responsible (on behalf of 

the multiple owners) for identifying and reporting emissions for the gathering pipelines and all 

gathering and boosting equipment, regardless of whether the associated equipment is leased, 

rented, or owned and regardless of whether the gathering and boosting facility is operated by a 

contractor, one of the owners, or an owner committee. 

Given all the ownership possibilities and the need to understand who is responsible for 

appointing the designated representative, it is important to include a clear definition of owner or 

operator for the Onshore Petroleum and Natural Gas Gathering and Boosting segment that is 

inclusive of the multiple possible ownership scenarios. The definition proposed in this action is: 

Gathering and boosting system owner or operator means any person that holds 

a contract in which they agree to transport petroleum or natural gas from one 

or more onshore petroleum and natural gas production wells to a natural gas 

processing facility, another gathering and boosting system, a natural gas 

 

19 75 FR 74474 
12 

transmission pipeline, or a distribution pipeline, or any person responsible for 

custody of the gas transported. 

In the Clean Air Act, “person” is defined as “an individual, corporation, partnership, 

association, State, municipality, political subdivision of a State, and any agency, department, or 

instrumentality of the United States and any officer, agent, or employee thereof” (42 

U.S.C. 7602). Therefore, use of the term “person” in this definition should include all possible 

ownership scenarios. In addition, the final clause of the definition that refers to the “person 

responsible for custody of the gas transported” is primarily intended to cover the larger vertically 

integrated companies that transfer petroleum or natural gas from the production wells to points 

further downstream within the same company (i.e., without a contract). 

Facility 

In determining the best definition for a facility within the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment, there were a few important considerations. First, the EPA 

decided not to propose any changes to the facility definitions or segment descriptions for the 

Onshore Petroleum and Natural Gas Production and Onshore Natural Gas Processing segments 

to provide consistency for reporters in those segments. Different portions of gathering and 

boosting systems were considered part of the Onshore Petroleum and Natural Gas Production 

and Onshore Natural Gas Processing segments in the original subpart W proposal (75 FR 18608, 

April 12, 2010), and many of the public commenters provided comments disagreeing with the 

inclusion of gathering and boosting operations in those segments, mostly because it created 

complex reporting situations20. Therefore, the EPA determined that the definition of gathering 

and boosting facility and the description of the Onshore Petroleum and Natural Gas Gathering 

and Boosting segment should include natural gas and petroleum operations that exist between the 

current Onshore Petroleum and Natural Gas Production and Onshore Gas Processing segments. 

This approach ensures that the current data gap in subpart W related to gathering and boosting 

systems may be addressed while minimizing confusion with other existing segments. 

As a result, the EPA decided to define the Onshore Petroleum and Natural Gas Gathering 

and Boosting segment as the gathering pipelines and other equipment used to collect petroleum 

and/or natural gas from onshore production gas or oil wells and used to compress, dehydrate, 

sweeten, or transport the gas to a natural gas processing facility, a natural gas transmission 

pipeline, or a natural gas distribution pipeline. Gathering and boosting equipment would include, 

but would not be limited to, gathering pipelines, separators, compressors, acid gas removal units, 

dehydrators, pneumatic devices/pumps, storage vessels, engines, boilers, heaters, and flares. The 

 

20 U.S. Environmental Protection Agency. Mandatory Greenhouse Gas Reporting Rule Subpart W – Petroleum and 

Natural Gas: EPA's Response to Public Comments, November 2010. Docket Item No. EPA-HQ-OAR-2009-0923-

3608. 
13 

segment description also specifies that the Onshore Petroleum and Natural Gas Gathering and 

Boosting segment does not include equipment and pipelines that are reported under any other 

industry segment defined in subpart W. The intent with this definition is that if the upstream 

boundary of a gathering and boosting system is the Onshore Petroleum and Natural Gas 

Production segment, then the gathering and boosting system would include equipment that may 

functionally be close to onshore production operations but not located on a single well pad or be 

associated with multiple well pads. For example, if multiple wells are located in close proximity, 

the output may be routed to a single “production battery” for efficiency of further processing21, 

and those batteries would be considered part of the gathering and boosting system. 

Second, there are multiple options for defining a gathering and boosting facility, each 

imposing a different potential burden to reporters. The ideal definition of a gathering and 

boosting facility would balance addressing the data gap for the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment within subpart W while minimizing the burden to potential 

reporters. 

The EPA decided to apply a 25,000 MT CO2e reporting threshold to facilities in the 

Onshore Petroleum and Natural Gas Gathering and Boosting segment. All other subpart W 

industry segments have a reporting threshold of 25,000 MT CO2e, and the EPA did not have any 

data for gathering and boosting systems to suggest that the reporting threshold should be higher 

or lower for a gathering and boosting facility than other subpart W industry segments. 

The remainder of this section describes three potential approaches that the EPA 

considered when developing the proposed definition for a gathering and boosting facility. 

Table 2.2 includes a summary of the potential approaches and the EPA’s analysis of their 

potential advantages and disadvantages. Note that, while all three of these options are mentioned 

in the preamble to the proposed amendments, Option 2 is the proposed option. 

Option 1 – Site-Based Facility 

In Option 1, the EPA considered applying the GHGRP definition of a facility as a single 

site to gathering and boosting systems (i.e., the definition of “facility” found in 40 CFR 98.6), 

which is “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 GHG. Operators of military installations may 

 

21 See the Global Methane Initiative website for diagrams showing the location of these production/gas batteries 

(https://www.globalmethane.org/m2mtool/gas.html). Note that these batteries may be used for single wells as well 

as for situations with multiple wells in close proximity, but if a production battery is on or associated with a single 

well pad, then it is by definition part of the Onshore Petroleum and Natural Gas Production facility and segment. 
14 

classify such installations as more than a single facility based on distinct and independent 

functional groupings within contiguous military properties.” 

The advantage of this approach is that it uses the definition for facility that is already 

used in the GHGRP. It would also provide granular, site-specific data for each 

compressor/boosting station. On the other hand, the EPA would likely still have to provide 

guidance related to the inclusion of gathering pipelines within a facility, and it is likely that 

companies would have multiple facilities within each basin. In addition, this definition may not 

address the current data gap, because of the geographic dispersion of these operations. Although 

one possible way to address this issue would be to make this an “all in” segment (i.e. all facilities 

would be required to report regardless of their annual emissions), an “all in” approach has not 

been applied to any of the segments within subpart W to date. 

Option 2 – Basin-Based Facility 

In Option 2, the EPA considered defining the facility as all the gathering and boosting 

systems owned by a gathering and boosting owner or operator in a single hydrocarbon basin. 

This definition would be similar to the current definition of “facility with respect to onshore 

petroleum and natural gas production for purposes of reporting under this subpart and for the 

corresponding subpart A requirements” for the Onshore Petroleum and Natural Gas Production 

segment. Since this option would use a definition of facility similar to the definition for the 

Onshore Petroleum and Natural Gas Production segment, it would likely not cause unnecessary 

confusion among reporters. This definition recognizes the fact that gathering and boosting 

facilities are more dispersed than processing facilities and are geographically similar to the 

Onshore Petroleum and Natural Gas Production segment in size and number of sources. This 

definition is also expected to require fewer reports for a given owner or operator than the 

definition in Option 1, because owners and operators would be able to report all of their 

operators within a basin as one facility (instead of many). 

 
15 

Option 3 – Basin-Based Facility for Boosting Stations and Nationally-Based Facility for 

Gathering Pipelines 

In Option 3, the EPA considered using a basin-based definition of facility as in Option 2 

for the portion of the gathering and boosting system that is consolidated (i.e., the boosting or 

compressor station), and setting a separate facility definition for gathering pipelines. The 

gathering pipeline facility would be all gathering pipelines owned by a gathering and boosting 

owner or operator in the United States. 

Under this option, the definition of a boosting station facility would recognize the fact 

that gathering and boosting facilities are more dispersed than processing facilities and are 

geographically similar to the Onshore Petroleum and Natural Gas Production segment in size and 

number of sources, as in Option 2. In addition, the pipeline facility boundaries would be easy to 

understand, and the EPA would not need to define how much of the gathering pipeline should be 

included in the facility definition as would be needed in Option 1. However, dividing gathering 

and boosting systems into two different types of facilities may increase reporter burden, 

particularly for owners and operators with both types of facilities.
16 

Table 2.2. Options for Facility Definition in the Onshore Petroleum and Natural Gas Gathering and B

Facility 

Definition 

Option Approach/Considerations Burden to Reporters Coverage 

1. SiteBased Facility 

Definition of facility consistent with definition in 40 CFR 98.6, which is used by subparts in the GHGRP that do not have geographically dispersed sources. Would need to determine the facility boundaries for gathering lines (i.e. what length of pipeline upstream or downstream from the main site would be considered part of the facility). 

25,000 MT CO2e reporting threshold: Each 

individual site would have to be evaluated to determine if it would exceed the reporting threshold. Reporting burden is expected to be relatively low because it is expected that only the largest sites would exceed the reporting threshold, but if an owner/operator has many sites, each would have to be reported separately. No reporting threshold: There would be no burden related to applicability because all facilities would be required to report regardless of emissions. However, if a company owns a large number of facilities, total reporting burden would be relatively high because a separate report would be required for each facility. This option would likely place reporting burden on small entities as well. 

25,000 MT CO2e repor

coverage expected to bfacilities would exceed Note that emissions frothe threshold based on already reporting undeOption provides potentgeographically specific coverage may offset thNo reporting thresholdwould be comprehensi

2. BasinBased Facility 

Definition of facility is all the gathering and boosting systems owned by a gathering and boosting owner or operator in a single hydrocarbon basin. Basinbased facility consistent with Onshore Petroleum and Natural Gas Production segment. Recognizes the fact that these sites are more dispersed than processing facilities, and geographically similar to the production sector in size and number of sources. 

Fewer facilities than in Option 1, if the thresholdoption is used, so the burden to evaluate whether afacility exceeds the reporting threshold would be lower than Option 1. Reporting burden would likely be higher than Option 1, if the threshold option isused, because more emission sources would be reported. If no reporting threshold is used for Option 1, then Option 1 would likely have more facilities and higher reporting burden than Option 2. 

Higher than Option 1 iused; most facilities womore emission sourcesemission sources reporif no threshold is used. Option provides potentgeographically specific 
17 

Facility 

Definition 

Option Approach/Considerations Burden to Reporters Coverage 

3. BasinBased Facility for Boosting Stations and NationallyBased Facility for Gathering Pipelines 

Two definitions of facility; Definition of facility consistent with definition in Option 2 for the boosting or compressor stations and national-level facility for gathering pipelines. Having two different definitions of facility could be confusing. 

Each collection of boosting stations in a basin would have to be evaluated to determine if it would exceed the reporting threshold of 25,000 MT CO2e, and 

owners/operators would have to aggregate and evaluate all gathering pipelines at the national level, which would be slightly more burdensome than Option 2. Overall reporting burden would be similarto or slightly less than Option 2, depending on thenumber of boosting station facilities that would exceed the reporting threshold without the gathering pipelines and the number of national gathering pipeline facilities that would have to report. Burden for an individual owner or operator would increase from Option 2, as separate reports would be required for boosting station facilities and national gathering pipeline facilities. 

May be similar to Optilower. Separation of gacompressor stations woconsists of fewer emissfor gathering pipelinesemission sources reporOption provides potentgeographically specific stations. Gathering pipreported at the national geographic basis. 
18 

Options 1 and 3 would provide limited data on the proposed Onshore Petroleum and 

Natural Gas Gathering and Boosting segment (with the exception of the Option 1 case where no 

reporting threshold is used) as a whole due to decreased coverage compared to other options and 

would likely be more burdensome overall to reporters, because a larger number of “facility” 

reports would be required for each owner or operator. Therefore, the EPA concluded that these 

options would not achieve the goals of having a thorough data set and transparent, complete 

information for this sector while minimizing burden to reporters. 

Option 2 was selected as the best option for the definition of facility for the gathering and 

boosting segment because it provides the best balance of minimizing burden to reporters and 

coverage of emissions from sources in the segment. Therefore, the proposed rule includes the 

following definition: 

Facility with respect to petroleum and natural gas gathering and boosting for 

purposes of reporting under this subpart and for the corresponding subpart A 

requirements means all gathering pipelines and other equipment located along 

those pipelines that are under common ownership or common control by a 

gathering and boosting system owner or operator and that are located in a 

single hydrocarbon basin as defined in this section. Where a person owns or 

operates more than one gathering and boosting system in a basin (for example, 

separate gathering lines that are not connected), then all gathering and 

boosting equipment that the person owns or operates in the basin would be 

considered one facility. Any gathering and boosting equipment that is 

associated with a single gathering and boosting system, including leased, 

rented, or contracted activities, is considered to be under common control of 

the owner or operator of the gathering and boosting system that contains the 

pipeline. The facility does not include equipment and pipelines that are part of 

any other industry segment defined in this subpart.

Emission Sources 

Subpart W already contains monitoring and calculation methods for emission sources that 

would be included in the Onshore Petroleum and Natural Gas Gathering and Boosting segment, 

with the exception of gathering pipelines, in either the Onshore Petroleum and Natural Gas 

Production segment or the Onshore Natural Gas Processing segment. After reviewing the 

emission source types and the calculation methods already included in subpart W, the EPA 

determined that because most processing of the gas and oil extracted from wells will be 

processed downstream of the gathering and boosting facility, the equipment/activities in the 

Onshore Petroleum and Natural Gas Production segment will be designed to handle gas and oil 
19 

of composition similar to the gas and oil in the Onshore Petroleum and Natural Gas Gathering 

and Boosting segment, so the same methods are applicable. 

This section discusses emission sources for which the EPA considered calculation 

methods other than those in the Onshore Petroleum and Natural Gas Production segment, or 

conducted additional research to confirm that the Onshore Petroleum and Natural Gas Production 

segment method was the best method. 

Blowdown Vent Stacks 

Emissions from blowdown vent stacks are addressed in subpart W for several segments, 

but for the most part, the blowdown vent stacks in these segments are located at consolidated 

facility sites. Therefore, the EPA evaluated the applicability of the method for blowdowns of 

emissions from gathering pipelines. 

Blowdown vent stacks are located at various points along a gathering pipeline at some 

distance in between the connection points for the various production fields and the compression 

boosting stations. A blowdown vent stack is one component of an isolation-blowdown assembly 

that would include isolation or “block” valves that would be closed to shut-off flow to a segment 

of pipeline and a blowdown valve that would be opened to evacuate gas from the isolated 

segment of pipeline. All blowdown valve assemblies will have a vent stack, which is simply a 

pipe through which the blowdown gas is released to the atmosphere or is routed to a combustion 

device (flare) or other equipment to capture the gas. The length and diameter of isolated pipeline 

section and the pressure of the gas in the pipeline will determine the volume of gas that will be 

emitted during a gathering line blowdown. If the pipeline blowdown is for scheduled 

maintenance and repair, pipeline operators generally prepare by reducing the volume of gas in 

the pipeline segment prior to isolation and blowdown, or by temporarily routing the gas flow 

around the isolated pipeline segment. Although the distance between blowdown vent stacks may 

be greater for gathering pipelines than for blowdown vent stacks at more consolidated facility 

sites, the general isolation-blowdown configuration is similar to those other facilities, so the 

emissions calculation method in subpart W would be appropriate for the Onshore Petroleum and 

Natural Gas Gathering and Boosting segment. 

Compressors and Equipment Leaks 

Compressors are used in gathering and boosting systems to keep pipelines at a high 

enough pressure so natural gas will continue flowing through the pipelines. The two primary 

types of compressors in use in gathering and boosting systems are reciprocating compressors and 

centrifugal compressors. Reciprocating compressors used in gathering and boosting systems 

typically have two to six cylinders, which can be configured to operate in parallel or in series 
20 

(“stages”). Most gathering and boosting compressors are configured in two or three stages. 

Compressors used in gathering and boosting may range in size from 1,000 horsepower (hp) to 

4,500 hp. Gathering and boosting compressors may be located out in the open or housed in 

compressor stations. The compressors operate for long periods of time; 8,400 hours of operating 

time per year is typical22. 

Centrifugal compressors are best suited to handle large volumes of gas at high pressure 

and stable flow rates that require a moderate pressure boost. Some gathering and boosting 

systems, particularly the newer, large gathering systems handling shale gas production, use 

centrifugal compressors.

Compressor drivers in gathering and boosting systems include gas engines, electric 

motors, propane and diesel engines. Spark ignition natural gas engines are the most common, but 

if gas richness exceeds 1,200 Btu per cubic foot, produced gas is less suitable for use as a fuel 

gas

23. Gathering and boosting system design is driven by well head pressure, gas composition, 

production volumes, and well spacing. The configuration and operating design of a gathering and 

boosting system may change over the lifetime of producing field, and a balance must be struck 

between pipeline size and compression cost. 

For compressors and equipment leaks, subpart W contains one method in the Onshore 

Petroleum and Natural Gas Production segment and a different method for the same emission 

source in the Onshore Natural Gas Processing segment. The EPA is proposing that gathering and 

boosting reporters use the same method as in the Onshore Petroleum and Natural Gas Production 

segment, which relies on the reporter counting the number of compressors or components (e.g., 

population counts) and then applying emission factors per compressor or component for that 

population. Alternatively, for equipment leaks, the reporter may count the number of pieces of 

major equipment, assume the default component counts in Table W-1B, and then apply emission 

factors per component. This proposed population count approach is appropriate for the Onshore 

Petroleum and Natural Gas Gathering and Boosting segment because, as in the Onshore 

Petroleum and Natural Gas Production segment, the equipment is often geographically dispersed 

and may be visited only intermittently. Under the proposed approach, a reporter would need to 

establish an inventory of the components or equipment subject to the population counts, apply 

the emission factors, and then update the inventory each year to account for new or retired 

components or equipment. 

 

22 For more information, see “Compressors are heart of Natural Gas Production” by Norm Shade in Gas & Oil 

Magazine on-line publication, August 6, 

2014,http://www.gasandoilmag.com/gas%20&%20oil/2013/07/02/compressors-are-heart-of-natural-gas-production

and “Gathering and Processing Design Options for Unconventional Gas” by K.A. Lawlor and M. Conder in Hart 

Energy Midstream Business, Vol. 3, No. 4, April 2013. 

23 Lawlor and Conder, op. cit. 
21 

Gathering Pipelines 

The only other segment in subpart W that currently includes pipelines is the Natural Gas 

Distribution segment. Currently, subpart W requires that emission leaks from distribution mains 

be estimated using an emission factor approach. To assess whether an emission factor approach 

would be appropriate for gathering pipelines, the EPA compared the characteristics of three types 

of pipeline, including gathering pipelines, distribution mains (used in the Natural Gas 

Distribution segment), and natural gas transmission pipelines. The pipeline characteristics 

include typical material, pipe size, maximum operating pressure, and burial depth. 

The results are summarized in Table 2.3. 
22 

Table 2.3. Comparison of Types of Petroleum and Natural Gas Systems Pipelines 

Characteristic 

Type of Pipeline 

Gathering Pipelines24

Distribution 

Mains25

Transmission 

Pipelines26

Material Varies, but usually polyethylene for low pressure 

pipelines; coated steel for high pressure pipelines

Flexible plastic and 

corrugated steel are 

rapidly replacing 

rigid steel pipe 

High strength 

steel 

Size 2–36 inches (”) in diameter. The common size range of 

gathering pipeline for conventional gas plays and older 

gathering systems is 2–12”. For unconventional gas 

developments, the gathering lines are generally much 

larger, ranging from 12–36”, and have much higher 

maximum allowable operating pressures than historical 

norms27. 

2–24” diameter 20–42” 

diameter 

(transmission 

laterals 6–16”) 

Maximum 

Operating 

Pressure 

During operation, pressure in a gathering system will 

fluctuate depending on whether the gas is moving to or 

from a compression point. The gathering system is most 

likely to approach the maximum allowable operating 

pressure when it is departing the downstream outlet of a 

compressor. After it leaves the compressor, pressure 

decreases uniformly along the gathering system to the 

next compression point or the gathering system 

endpoint28. Operating pressure can range from less than 

100 pounds per square inch (psi) to more than 700 psi. 

Less than 150 psi. 

Regulators step the 

pressure down for 

distribution mains 

from city gates to 

the service lines. 

Distribution mains 

and service lines 

typically operate at 

less than 20 percent 

of design pressure; 

60 psi is typical for 

distribution and 3 

psi – 0.25 psi is 

typical for services. 

200 – 1,500 

psi; 700 psi is 

typical 

Burial Depth Some low pressure, smaller diameter gathering lines are 

not buried. Some are buried to very shallow depths of 

approximately 4– 6”. Large gathering pipelines are 

typically buried to depths of up to 36”. 

Each main must be 

installed with at 

least 24” of 

cover29. 

Minimum 

depth is 30” 

from top of 

pipe 

 

24 Sources: Corken Inc., “What is a gas gathering system” www.corken.com/gas_gathering; Bullin, K.A. and 

Chipps, J., Bryan Research and Engineering, 2005, Optimization of natural gas gathering systems and gas plants, 

presented at the 84th GPA Annual Convention, San Antonio, TX, March 13-16, 2005, 

www.bre.com/portals/0/technicalarticles/GPA05.Chipps.Jason.pdf. 

25 Bruno, M. and Moe, J., Xcel Energy Accelerated Main Renewal Program, Natural Gas STAR Annual 

Implementation Workshop, April 11, 2012; and Natural Gas Supply Association. 

26 American Gas Association, www.aga.org/KC/AboutNaturalGas; Natural Gas Supply Association, 

www.Naturalgas.org. 

27 Burdeaux, D. Briefing Paper: Onshore Gas Gathering, Advisory Committee Action – Information. March 24, 

2011. Available at 

http://www.phmsa.dot.gov/pv_obj_cache/pv_obj_id_8D4A289CD397250DA8D8ED1115A1CEA03E8A0000/filen

ame/Tab%207b%20-%20Briefing%20-%20TPSSC%20Gas%20Gathering%20Lines%20-%20Dewitt.pdf. 

28 Williams Company, www.williamsinthenortheast.com/projects/landowner-faq. 

29 49 CFR 192.327. 
23 

The 2014 U.S. GHG Inventory lists more than 1.24 million miles of distribution mains. 

Emission factors for distribution mains vary depending upon the pipe material. In terms of 

pipeline composition, distribution mains constructed from plastic or from protected steel are 

comparable to gathering pipelines, but the emission factors are significantly lower for 

distribution mains. The emission factors for these two types of distribution pipelines are 0.35 

standard cubic feet (scf)/hour/mile (protected steel) and 1.13 scf/hour/mile (plastic)30,31. 

The 2014 U.S. GHG Inventory lists 445,135 miles of gathering pipelines32,33. The 

emission factor for gathering pipeline leaks in the 2014 U.S. GHG Inventory varies slightly by 

National Energy Modeling System (NEMS) region, from 19.1 thousand cubic feet (Mcf)/mileyear (2.18 scf/hour/mile) to 22.6 Mcf/mile-year (2.58 scf/hour/mile). For transmission pipelines, 

the 2014 U.S. GHG Inventory emission factor is 1.55 standard cubic feet per day (scfd) per mile 

or approximately 0.57 Mcf/mile-year (0.065 scf/hour/mile). These emission factors are derived 

from the 1996 GRI/EPA study. No other published emission factors for pipeline leaks were 

identified for gathering pipelines. 

After considering existing calculation methodologies, the EPA determined that an 

emission factor approach would still be the most appropriate for gathering pipelines. However, 

considering the variability in the gathering pipelines and gathering system configurations, the 

EPA determined that specific emission factors for gathering pipelines should be added to subpart 

W. 

Options for these emission factors include: 

• Using CH4 emission factors for gathering lines in the 2014 U.S. GHG Inventory, 

which range by NEMS region but average around 20 Mcf/mile-year (2.28 

scf/hour/mile). 

• Using CH4 emission factors for distribution pipelines in the 2014 U.S. GHG 

Inventory made of protected steel (0.35 scf/hour/mile) or plastic (1.13 scf/hour/mile). 

These can be adjusted to account for the generally higher pressure of gathering lines 

relative to distribution lines. 

• Developing a new set of emission factors based on a function of pipeline material 

(e.g., protected steel, plastic composite), pipe diameter, and throughput pressure to 

account for the variation in the different characteristics of gathering pipelines. 

 

30 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2012. EPA 

430-R-14-003. April 15, 2014. 

31 Table W-7 of Subpart W of Part 98. 

32 This is the sum of the mileage reported by NEMS Region in the 2014 U.S. GHG Inventory, Table A-125: 2012 

Data and Calculated CH4 Potential Emissions (Mg) for the Natural Gas Production Stage, by NEMS Region. 

33 ICF (1996), Estimation of Activity Factors for the Natural Gas Exploration and Production Industry in the U.S. 
24 

• Allowing reporters to use their own site-specific emission factors, subject to EPA 

approval as another way to account for the variation in the different characteristics of 

gathering pipelines. 

The EPA reviewed the documentation in the original 1996 GRI/EPA report for the 

gathering line emission factors in the 2014 U.S. GHG Inventory and found that the gathering line 

emission factors are based on measured data obtained from distribution mains. Measured leak 

data for distribution mains from 10 participating distribution companies were adapted to 

gathering lines (and to transmission pipelines, as well) to account for differences between typical 

distribution mains and typical gathering lines in terms of pipe diameter, operating pressure, 

burial depth and oxidation of CH4 in soil, and pipe material (mostly coated steel or plastic for 

gathering lines). From this review, the EPA concluded that the CH4 emission factors for 

gathering lines that are already in the 2014 U.S. GHG Inventory are the best available, meaning 

that they are based on actual leak measurements that have been explicitly adapted to the unique 

characteristics of gathering pipelines. 

The EPA determined that gathering and boosting system owners and operators should 

develop CO2 emission estimates for gathering pipelines in addition to CH4. The next step was to 

determine whether to develop a specific CO2 emission factor or a “whole gas” emission factor 

(total hydrocarbon emission factor, similar to the emission factors for equipment leaks in Table 

W-1A of subpart W) for gathering pipelines. Use of whole gas emission factors would require 

reporters to determine CH4 and CO2 emissions based on CH4 and CO2 content of the gas in the 

pipeline, which is slightly more burdensome than nationwide (or Eastern U.S. and Western U.S.) 

CH4 and CO2 emission factors. However, use of whole gas emission factors would also provide 

the advantage of more accurate emissions reporting because they would allow for differences in 

the type of production field as well as the amount of processing the company chooses to conduct 

near the production well instead of at the gas processing facility. 

To develop these options for proposed emission factors for gathering pipelines, the EPA 

used data for the average CH4 content of the gas in the Onshore Petroleum and Natural Gas 

Production segment, available in the 2014 U.S. GHG Inventory (Annex 3, Table 131). The data 

for the average CH4 content of natural gas in the Onshore Petroleum and Natural Gas Production 

segment in the 2014 U.S. GHG Inventory are provided by NEMS region; these data are shown in 

Table 2.4. The data for the average CH4 content of natural gas in the Onshore Petroleum and 

Natural Gas Production segment in the 2014 U.S. GHG Inventory are provided by NEMS region; 

these data are shown in Table 2.4. 
25 

Table 2.4. Emission Factors for Leaks from Gathering Pipelines by NEMS Region 

NEMS Region 

CH4 Emission Factor

(scf CH4/hour/mile)a

Production Sector CH4 in Natural 

Gas (General Sources) for 2012b

Whole Gas Emission 

Factor (scf /hour/mile)c

Northeast 2.39 85.2 % 2.81 

Mid-Continent 2.32 82.6 % 2.81 

Rocky Mountain 2.18 77.5 % 2.81 

Southwest 2.26 80.5 % 2.81 

West Coast 2.58 91.9 % 2.81 

Gulf Coast 2.48 88.2 % 2.81 

a

 2014 U.S. GHG Inventory, Annex 3, Table A-125. 

b

 2014 U.S. GHG Inventory, Annex 3, Table A-131. 

c

 Derived from 2014 U.S. GHG Inventory data shown in first two columns of this table. 

Using these data, the EPA determined a “whole gas” or total hydrocarbon emission factor 

of 2.81 scf/hour/mile for gathering pipelines. This emission factor allows gathering pipeline 

owners/operators flexibility to account for variation in CO2 content at the points where natural 

gas enters the gathering pipeline system, as well as at acid gas removal points. The burden to 

reporters to calculate CH4 and CO2 content will be minimal because they will already be 

conducting these calculations to estimate emissions from components such as valves and 

connectors. 
26 

3 NATURAL GAS TRANSMISSION LINES BETWEEN COMPRESSOR

STATIONS 

Background 

Natural gas transmission compressor stations are currently covered in subpart W as part 

of the Natural Gas Transmission Compression segment, and the natural gas transmission 

pipelines between those compressor stations are not. The 2014 U.S. GHG Inventory estimated 

that the total transmission pipelines in 2012 were 303,126 miles and that there were 1,799 

compression stations34. Emissions from blowdowns of transmission pipelines between 

compressor stations represent a gap in the data collected by the GHGRP. 

The main source of emissions for natural gas transmission pipelines is venting through a 

blowdown vent stack (other emissions sources are considered to be part of the compressor 

stations and are, therefore, already covered under subpart W, as noted above). Transmission 

pipeline blowdowns occur when a segment of pipeline is isolated from the rest of the line and the 

natural gas inside is purged through a blowdown vent stack. These blowdowns are needed to 

safely inspect and maintain the pipelines. Using the information in the 2014 U.S. GHG 

Inventory, net emissions from pipeline venting are estimated to be 2.12 MMT CO2e per year in 

2012, or 7.0 MT CO2e/mile-year (applying the global warming potential of CH4 is 25). Using the 

emissions information in the Compendium of Greenhouse Gas Emissions Methodologies for the 

Oil and Natural Gas Industry published by API in August 2009 (hereafter referred to as the “API 

Compendium”) and the pipeline mileage from the 2014 U.S. GHG Inventory, emissions from gas 

transmission pipeline venting and blowdowns are estimated to be 40.95 thousand standard cubic 

feet (Mscf) CH4/mile-year, or 0.7855 MT CH4/mile-year35, which is equivalent to 6.0 MMT 

CO2e per year in 2012, or 19.6 MT CO2e/mile-year (applying the global warming potential of 

CH4 is 25). 

Definition of Owner/Operator 

Similar to gathering and boosting systems, transmission pipelines can have complex 

ownership scenarios. For example, master limited partnerships (MLPs) are a unique structure of 

ownership which is common in midstream sector corporations and in transmission companies. 

 

34 U.S. Environmental Protection Agency. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990– 2012. 

EPA 430-R-14-003. April 15, 2014. Annex 3, Table A-129: 2012 Data and CH4 Emissions (Mg) for the Natural Gas 

Transmission Stage. 

35 American Petroleum Institute (API). Compendium of Greenhouse Gas Emissions Methodologies for the Oil and 

Natural Gas Industry. Prepared by T.M. Shires, C.J. Loughran, S. Jones, E. Hopkins, URS Corporation, for API. 

August 2009. Table 5-26. Table B-21 of this document shows that the emission factor is based on a combination of 

data used in the 1996 GRI/EPA study and additional data from seven Canadian facilities. 
27 

The EPA evaluated the subpart A definitions of “owner” and “operator” and determined 

that they could not be easily applied to natural gas transmission pipelines. Therefore, the EPA 

concluded that a definition of owner or operator specific to natural gas transmission pipelines 

was necessary. The PHMSA already includes a specific definition of “operator” that entities are 

to use for the purpose of submitting reports: 

• For interstate pipelines, the operator is the holder of the Certificate of Public 

Convenience and Necessity issued under 15 U.S.C. 717f by the Federal Energy 

Regulatory Commission (FERC). This is the certificate issued by FERC that allows 

the pipeline company to engage in the transportation and/or sale for resale of natural 

gas in interstate commerce or to acquire and operate facilities needed to accomplish 

this. They are issued by FERC after FERC has approved the construction of a 

pipeline, and they allow the holder to build and operate the pipeline. 

• For intrastate pipelines, the operator is the operator identified on the pipeline’s 

Statement of Operating Conditions that is prepared for compliance under section 311 

of the Natural Gas Policy Act (NGPA). Section 311 of the NGPA allows an interstate 

pipeline company to sell or transport gas on behalf of any intrastate pipeline or local 

distribution company without prior FERC approval. 

This definition is straightforward and already understood by the industry through 

PHMSA reporting and through the requirements of FERC. It also avoids the need to address each 

possible ownership scenario to identify the owner. Therefore, the EPA determined that this 

definition would be the most appropriate definition for natural gas transmission pipeline facilities 

in subpart W. 

Definition of Facility 

In defining the facility, the EPA considered several options, including: 

• the segment of transmission pipeline between two compressor stations, or between a 

compressor station and a distribution system 

• total mileage of natural gas transmission pipelines owned and operated by an entity 

within a state 

• total mileage of natural gas transmission pipelines owned and operated by an entity 

within a basin 

• total U.S. mileage of natural gas transmission pipelines owned and operated by an 

entity 
28 

For each option, the EPA considered the amount of burden to the owner or operator 

compared to the amount of data that could be collected. Table 3.1 summarizes the analysis that 

was performed. 

Table 3.1. Options for Definition of Natural Gas Transmission Pipeline Facility 

Facility Definition 

Option Approach/Considerations Burden to Reporters 

Coverage of 

Emissions

Segment of 

transmission 

pipeline between 

two compressor 

stations, or between 

a compressor 

station and a 

distribution system 

Owners/operators would 

determine the number of miles 

of a transmission pipeline 

segment. 

Dividing the total miles of 

pipeline (303,126 miles) by the 

number of compressor stations 

estimated by the 2014 U.S. 

GHG Inventory (1,799 

stations), the estimated average 

distance between compressor 

stations is 168 miles. 

Each pipeline segment would have to 

be evaluated to determine if it would 

exceed the reporting threshold of 

25,000 MT CO2e, which could be 

burdensome. Reporting burden is 

expected to be relatively low because 

it is unlikely that any individual 

pipeline segment would exceed the 

reporting threshold, but if an 

owner/operator has several such 

pipeline segments, each would have 

to be reported separately.

Extremely limited, 

as it is unlikely 

that many 

individual pipeline 

segments would 

exceed the 

reporting 

threshold of 

25,000 MT CO2e.

Total mileage of 

natural gas 

transmission 

pipelines owned 

and operated by an 

entity within a state 

Owners/operators would 

determine the number of miles 

of transmission pipeline in a 

state. 

Data reported to EIA and 

PHMSA are by state. 

Fewer facilities would have to be 

evaluated and compared to the 

reporting threshold of 25,000 MT 

CO2e than segment-based facility. 

Reporting burden would be higher 

than segment-based facility because 

more facilities expected to exceed 

the threshold, and because the 

owner/operator would have to track 

data elements within each state 

separately. 

Higher coverage 

than segmentbased option, as 

more facilities 

would be expected 

to report 

emissions. 

Total mileage of 

natural gas 

transmission 

pipelines owned 

and operated by an 

entity within a 

basin 

Owners/operators would 

determine the number of miles 

of transmission pipeline in a 

basin. 

Slightly higher than a state-based 

facility, as some states contain 

multiple basins. Additional burden 

may be incurred due to reporting data 

by basin rather than by state, which 

is already required by EIA and 

PHMSA. 

Likely slightly 

less than a statebased facility, 

since facility. 

Total U.S. mileage 

of natural gas 

transmission 

pipelines owned 

and operated by an 

entity 

Owners/operators would 

determine the total number of 

miles of transmission pipeline 

in the United States. 

This option would require the least 

evaluation and comparison to the 

reporting threshold of 25,000 MT 

CO2e, as there would be a maximum 

of one facility per owner/operator. 

More facilities would likely exceed 

the reporting threshold than any 

other option, but reporting burden for 

each owner/operator would be 

minimized as much as possible by 

the requirement to file only one 

report. 

The highest of any 

other option 

considered. 

 
29 

In considering these options, the EPA took into account the fact that many major pipeline 

systems are essentially linear systems to move gas from one part of the U.S. to another. The EPA 

also took into account the fact that many entities own and operate pipeline segments that may not 

be directly interconnected, but are connected with pipelines owned and operated by other entities 

as part of the national network of natural gas transmission pipelines. 

After comparing the options, the EPA concluded that requiring reporters to file separate 

reports for each portion of the system in any one segment, state, or basin would impose higher 

evaluation and reporting burden on owners and operators without providing the EPA with 

additional useful emissions information and activity data. Defining the facility on the national 

level limits the burden on reporters to correlate the pipeline ownership transfer points with 

specific geographical segments. Instead, the reporters can track the required information for their 

various pipelines, regardless of location, and submit data associated with all of them in one 

report. 

The reporting threshold for facilities in this segment would be 25,000 MT CO2e/year, the 

same as all other facilities in industry segments of subpart W. This means that a facility required 

to report blowdown emissions under subpart W is estimated to need a minimum of between 

1,273 and 1,640 miles of pipeline (based on the API Compendium and the 2014 U.S. GHG 

Inventory data, respectively). 

Data Reported to the PHMSA 

Data for incidents from transmission pipelines that exceed a defined threshold and are 

unintentional (with targeted exceptions) must be reported to the Pipeline and Hazardous 

Materials Safety Administration (PHMSA), per 49 CFR part 191. Specifically, PHMSA collects 

data on transmission pipeline incidents36. As defined in 49 CFR 191.3, an incident includes any 

of the following events: 

• An event that involves a release of gas from a pipeline and that results in one or more 

of the following consequences: 

o A death, or personal injury necessitating in-patient hospitalization; 

o Estimated property damage of $50,000 or more; 

o Unintentional estimated gas loss of 3 million cubic feet or more. 

• An event that results in an emergency shutdown of an LNG facility (unless the 

emergency shutdown system is activated for reasons other than an actual emergency). 

• Any other event that is significant in the judgment of the operator. 

 

36 See the link for “Incident/Accident Data from Gas Distribution, Gas Gathering, Gas Transmission, and Hazardous 

Liquids and LNG Operators Accident and Incident Data” at http://www.phmsa.dot.gov/pipeline/library/data-stats. 
30 

For each incident, the owner or operator must complete and submit a report within 

30 days of the incident, per 49 CFR 191.15. Reports typically include: (1) location/ facility/ 

operator information; (2) estimated volume of gas and/or liquid released; (3) cause of the 

incident/ release; (4) information on any injuries, fatalities, or property damage; and (5) details 

on any resulting shutdowns, explosions, evacuations37. 

Natural gas transmission pipeline blowdowns for repairs and maintenance are not 

required to be reported to PHMSA, unless the blowdown otherwise fits the definition of a 

transmission pipeline “incident” or a “safety-related condition” under 49 CFR 191. 

Data Reported to the Department of Energy (DOE) 

Many of the data elements proposed to be reported under 40 CFR 98.236(aa)(11) are also 

reported to the DOE and two of its associated agencies, EIA and FERC. 

Most of the data elements are reported to EIA through Forms EIA-17638 and EIA-19139

by each company that meets the description of a required reporter, for each state in which that 

company is conducting one of the listed activities. The data from these forms are made available 

on the EIA Web site40 and in EIA publications such as Natural Gas Monthly41. The specific 

reporting elements are discussed below. 

• The quantity of natural gas received at all custody transfer stations in the calendar 

year: The instructions for Form EIA-176 indicate that reporters must provide “the 

name of the company, the adjacent State or Country from which the gas was received, 

and the volume of gas received at the State line or U.S. border” and “the volume of 

other receipts within the report State if the gas was delivered to a point on your 

company’s system and not previously reported.” 

• The quantity of natural gas withdrawn from in-system storage in the calendar year: 

The instructions for Form EIA-191 indicate that reporters “must provide net 

withdrawals from storage reservoirs,” and the data are available in Table 8 of the 

Natural Gas Monthly. 

 

37 Instructions (rev 12-2012) for Form PHMSA F 7100.2 (rev 12-2012) Incident Report – Natural and Other Gas 

Transmission and Gathering Pipeline Systems. December 2012. Available at 

http://phmsa.dot.gov/pipeline/library/forms. 

38 EIA Form EIA-176: Annual Report of Natural and Supplemental Gas Supply and Disposition. OMB No. 1905-

0175, Version 2012.01. Available at http://www.eia.gov/survey/#eia-176. 

39 EIA Form EIA-191: Monthly Underground Gas Storage Report. OMB No. 1905-0175, Version 2012.01. 

Available at: http://www.eia.gov/survey/#eia-191. 

40 EIA Natural Gas Annual Respondent Query System. Last release: April 2014. Available at 

http://www.eia.gov/cfapps/ngqs/ngqs.cfm?f_report=RP1. 

41 U.S. Department of Energy, U.S. Energy Information Administration, Office of Oil, Gas, and Coal Supply 

Statistics. Natural Gas Monthly. Released monthly; most recent version available at 

http://www.eia.gov/naturalgas/monthly/. 
31 

• The quantity of natural gas added to in-system storage in the calendar year: The 

instructions for Form EIA-176 indicate that reporters must provide the “total volumes 

of natural and supplemental gas stored in company-operated facilities,” and the 

instructions for Form EIA-191 indicate that reporters “must provide net injections 

into storage reservoirs.” The data are available in Table 8 of the Natural Gas 

Monthly. 

• The quantity of natural gas transferred to third parties such as LDCs or other 

transmission pipelines: The instructions for Form EIA-176 indicate that reporters 

must provide “the total volumes of... natural and supplemental gas delivered to 

others” 

• The quantity of natural gas consumed by the transmission pipeline facility for 

operational purposes: The instructions for Form EIA-176 indicate that reporters must 

provide “the volume of gas consumed as fuel in [the] company’s operations” 

including space heating, “new pipeline fill, pipeline distribution or storage 

compressor use, and other (specify type) within the report State.” The data are 

available in Table 2 of the Natural Gas Monthly.

The last data element proposed to be reported under 40 CFR 98.236(aa)(11), the miles of 

transmission pipeline in the facility, is reported through FERC Form No. 242 and is available on 

the FERC and individual company Web sites. 

 

 

42 FERC FORM No. 2: Annual Report of Major Natural Gas Companies and Supplemental Form 3-Q: Quarterly 

Financial Report. OMB Nos. 1902-0028 and 1902-0205.
32 

4 WELL IDENTIFICATION NUMBERS 

Owners and operators of all onshore and offshore petroleum or natural gas production 

wells in the U.S. must apply for a permit from the relevant permitting authority, or the entity that 

issues permits for drilling of oil and gas wells43. Typically, a single drilling permit is issued to an 

onshore well, which spells out, or incorporates by reference, a range of requirements for the 

operator. These include requirements for well construction, geophysical well logs, and protection 

of sensitive areas, as well as requirements to notify the state or other relevant agency at various 

points in the development of the well. For example, there may be notification requirements 

before well tests, before and after hydraulic fracturing, after well completion and before and after 

a well is plugged and abandoned. In addition, a well identification number is issued for the 

proposed well at the time of the initial permit application, which must be granted prior to the 

start of drilling operations, so that each well can be uniquely identified. 

In 1962, the API subcommittee on Well Data Retrieval Systems was formed to make 

recommendations for a system that would allow regulators to track drilling permits, collect 

royalties, and optimize field conservation. The subcommittee’s first recommendations on the 

API Well Number system were published as Appendix A of API Bulletin D12 (Well Data 

Glossary) in 1966; this appendix was superseded in 1968 by API Bulletin D12A44. API 

transferred ownership of the well numbering specification to the Professional Petroleum Data 

Management (PPDM) Association in 2010. PDDM issued an updated specification in May 2013 

and then renamed the identifier as the “US Well Number” in June 201445. The PDDM is working 

with state regulatory agencies to implement the 2013 updates, but adoption is currently at the 

discretion of the agency. State agencies that elect not to use the US Well Number assign unique 

well identification numbers to the gas and oil wells in that state for tracking in their regulatory 

databases. 

 

 

43 For wells drilled on private land, state lands and state waters, the permitting authorities are the individual state 

regulatory agencies, departments, boards, or commissions tasked with regulating the oil and gas industry in that 

state. Each state has only one entity that issues oil and gas well drilling permits. For wells drilled onshore on federal 

land, the permitting authority is the Bureau of Land Management (BLM). For wells drilled offshore in federal water, 

the permitting authority is the Bureau of Ocean Energy Management (BOEM). 

44 American Petroleum Institute. The API Well Number and Standard State And County Numeric Codes Including 

Offshore Waters. API Bulletin D12A, January 1979. Available at 

http://wellidentification.org/dl/US_API_Bulliten_1979.pdf.

45 The Professional Petroleum Data Management Association. The US Well Number Standard: An Identifier for 

Petroleum Industry Wells in the USA. Version 2013 rev 1, published June 19, 2014. Available at 

http://dl.ppdm.org/dl/1147. 
33 

The US Well Number Standard provides instruction for assigning each well a 12-digit 

unique identifier, with some wells having more than 12 digits if an optional extension is used. 

The assignment of each digit is explained below: 

• State Code (digits 1 and 2): The state code represents a state (including off-shore state 

waters) or other location (e.g., Offshore Federal Waters). A list of state codes is 

provided in The US Well Number Standard. 

• County Code (digits 3 through 5): The county code represents an onshore county, 

parish (Louisiana), U.S. Geological Survey (USGS) quadrangle (Alaska), or a 

pseudo-county for offshore state and federal waters. A list of county codes is 

provided in The US Well Number Standard. 

• Well Code (digits 6 through 10): The well code is assigned to each well as 

determined by a unique well origin and must be unique within a county code. The 

well code must be numeric, but according to The US Well Number Standard, there is 

no sequence or order significance implied by the code applied. 

• Wellbore Code (also referred to as the directional sidetrack code in the API Well 

Number) (digits 11 and 12): The wellbore code may be assigned to the original 

wellbore (typically “00”), directional sidetracks, or deepening. It must be unique 

within the well code for the well. Some regulating agencies do not assign the 

wellbore code. The wellbore code must be numeric, but according to The US Well 

Number Standard, there is no sequence or order significance implied by the code 

applied. 

• Extension (also referred to as the event sequence code in the API Well Number) (any 

digits beyond 12): The extension may be assigned based on regulatory agency 

requirements and may include alphanumeric or special characters. The only 

requirement for the extension provided in The US Well Number Standard is that it 

may not be used to identify wellbores (the wellbore code must be used for that 

purpose). (This is a change from the previous API Well Number standard.) The 

standard suggests that the extension may be used to describe events such as 

completions, plugbacks, and recompletions, and that it should not be used for 

administrative events such as regulatory filings and permit numbers. 

The US Well Number Standard requires the state code, county code, well code, and the 

wellbore code; the extension is optional and is not further defined by the standard. US Well 

Numbers are publically available, but the accessibility of the data varies from state to state. The 

US Well Number Standard specifies that historical API Well Numbers should be included in the 

state’s master list of US Well Numbers without being revised unless there are concerns that the 

number is not or will not be unique. However, previous versions of the standard have not always 

included the wellbore code, so some historical API Well Numbers may be only 10 digits long. 

For these numbers, The US Well Number Standard specifies that a wellbore code should be 
34 

added but leaves the ultimate decision of whether to do so up to the regulatory agency with 

primary jurisdiction over the drilling of oil and gas wells (given that retroactive assignment of 

wellbore codes may take years to complete). 

The US Well Number Standard provides a protocol for assigning unique and permanent 

US Well Numbers to each well in the U.S., and nearly all states follow this protocol. However, 

there is no national authority that requires or assigns US Well Numbers. Therefore, as noted 

above, there are a few states that, historically, have not assigned US Well Numbers to wells. The 

reasons some states may have not adopted the US Well Number standard vary: (1) the level of 

oil and gas exploration and development activity in the state may be low; (2) conversely, the 

state may have a very large number of old wells and historical well records; (3) regulatory 

agency staff resources may be limited; or (4) the state has a previously established system for 

identifying wells and maintaining well records that already meets its need. Although some states 

do not use US Well Numbers, such states do assign a unique number to every well according to 

their own system, so all wells are uniquely identified. In addition, some operators in these states 

may request or otherwise acquire US Well Numbers (in addition to the state-assigned identifiers) 

for ease of use in specialized mapping programs and other analytical software tools46

. 

Well identification numbers have long been used in the oil and gas exploration and 

production industry as the primary means of integrating all forms of well data and linking the 

data to specific wells and boreholes (in the case of wells with multiple sidetrack or lateral 

boreholes). For example, basic well information (such as location, depth, well status), 

geophysical well log data, reservoir and rock sample data, pressure test and production data are 

all linked to specific wells and boreholes via a unique identification number. Unique well 

identification numbers are used in regulatory filings by operators, and in various transactions 

pertaining to working interest, production and royalties, well ownership and operating 

agreements. Unique well identification numbers are more accurate for such purposes than well 

names, hence the practice of using well identification numbers for data integration is long 

established and universally accepted in the oil and gas industry. For this reason, the US Well 

Number, or the predecessor API Well Number, is intended to be a straightforward way for 

operators to link emissions reporting to specific production facilities. 

 

46 For example, the Indiana Division of Oil and Gas (DOG) assigned API well numbers to newly permitted wells 

between 1967 and 1990. In 1994, the need for a unique well identifier was recognized, but it was determined that the 

API well number would not be suitable because there were inconsistencies in the existing API well numbers and the 

historical numbers could not be verified. Instead, wells in Indiana are issued a six-digit number known as the 

Indiana Geological Survey (IGS) Petroleum Well Identification Number (IGS ID). The Petroleum Information 

Corporation (now IHS, Inc.) began issuing API well numbers to Indiana wells in 1994, but they hold the cross 

referenced list of assigned numbers proprietary, so this list of API well numbers is not used by the public or the 

permitting authority. (See “API Well Numbers in Indiana (Draft 1)” by Charles W. Zuppann, Indiana Geological 

Survey, July 2011, http://igs.indiana.edu/pdms/help/API_Numbers_in_Indiana.htm.) 
35 

As part of this proposal, the EPA has included well identification reporting requirements 

to improve the EPA’s ability to verify reported data and enhance transparency. Adding well 

identification numbers to the required reporting for oil and gas wells covered by the Onshore 

Petroleum and Natural Gas Production segment will enable the EPA and other stakeholders to 

directly match data for reported wells with other local, state, and federal permitting and other 

reported information.