1 

MEMORANDUM 

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

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

DATE: September 25, 2015 

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

Confidentiality Determinations for Petroleum and Natural Gas Systems 

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

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

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

provisions:1

1. Oil Well Completions and Workovers with Hydraulic Fracturing 

2. Onshore Petroleum and Natural Gas Gathering and Boosting Segment 

3. Onshore Natural Gas Transmission Pipeline Segment 

4. Well Identification Numbers 

1 OIL WELL COMPLETIONS AND WORKOVERS WITH HYDRAULIC 

FRACTURING 

The EPA is amending 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 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 updating 

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. 

Calculation Method 

The EPA is requiring Calculation Method 1, previously specified in subpart W for gas 

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

 

1

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

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

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 providing the use of Calculation Method 2 for oil wells. Calculation Method 2 is based on the 

choke flow equation in Perry’s Chemical Engineering Handbook,

2

 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 EPA sought comment on alternative methodologies in the proposed rule and none 

were identified by commenters. 

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

fracturing is to flow back the fracture fluids and reservoir gas at high volume and velocity 

necessary to lift excess proppant and fluids to the surface so that the reservoir fluids (oil and gas) 

can begin to flow. For oil wells, as the fracture fluids are depleted, the flowback contains an 

increasing volume of crude oil from the formation. The duration of the flowback period is largely 

determined by reservoir characteristics such as the number of zones, depth, reservoir pressure, 

and composition of the reservoir fluids. 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. 

The point at which a separator can function marks the beginning of the separation flowback 

stage. 

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 adding a new Equation W-12C that 

allows reporters to use the average gas to oil ratio (GOR) during the first 30 days of production 

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

Minimum GOR Threshold for Reporting 

The EPA recognizes that oil wells with low GOR values may not have sufficient gas to 

operate a separator. In some cases, the separators are operated by using pumps to move the fluid 

out of the vessels or by adding make-up gas to the system to ensure the necessary gas pressure. 

The EPA evaluated whether a specific GOR value could be added to subpart W to clarify the oil 

 

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 

wells for which owners and operators are expected to report emissions and solicited comments in 

the proposed rule on this issue. 

Energy Information Administration (EIA) data show that the proportion of “oil only” 

wells drilled from 2007-2012 was less than 20 percent of all new wells.3 Even in wells that 

produce primarily liquids at surface temperature and pressure conditions, there is often a volatile 

gaseous component. This associated gas is usually considered wet due to the high content of 

natural gas liquids (volatile components) included with the gaseous methane (CH4). The ratio of 

CH4 to volatile components increases as the GOR increases. One study that characterized the 

associated gas of conventional crudes stated that for a crude oil with a GOR of 1,000 standard 

cubic feet (scf) per barrel, the associated gas may be comprised of 46 mole percent CH4. For a 

crude oil with a GOR of 5,000 scf per barrel, the associated gas may be comprised of up to 78 

mole percent CH4.

4

 As the GOR increases, the API gravity of the crude tends to increase. 

The EPA agrees that including a minimum GOR threshold will help minimize reporting 

burden while still capturing most of the emissions from this source. The primary consideration 

when determining the level for a threshold is volatility; the threshold must be low enough that 

the oil produced is considered non-volatile. Non-volatile “black oils” (i.e., oil likely to not have 

gases or light hydrocarbons associated with it) are generally defined as having GOR values in the 

range of 200 to 900 standard cubic feet per stock tank barrel (scf/STB).5 Oil wells with a GOR 

less than 300 scf/STB are at the lower end of this range, and completions and workovers with 

hydraulic fracturing of these wells will not likely have enough gas associated that can be 

separated and routed to a flow meter. Given that the EPA is finalizing the proposed requirement 

that the oil well flow meter be located downstream of the separator, the separator must be 

operating for the owner or operator to be able to measure the flow rate and estimate emissions 

from completions and workovers of oil wells with hydraulic fracturing. Therefore, the final 

monitoring and reporting requirements do not apply to completions and workovers of oil wells 

with hydraulic fracturing that have a GOR of less than 300 scf/STB.6

 

3

 J. Lieskovsky and S. Gorgen. “Drilling often results in both oil and natural gas production.” Today in Energy, U.S. 

Energy Information Administration, October 29, 2013. http://www.eia.gov/todayinenergy/detail.cfm?id=13571. 

Accessed June 9, 2015. In this analysis, all hydrocarbon production in the liquid state at the wellhead was 

considered oil. 

4

 Laine, Pekka. “Gas Management Solutions in Oil Production: Compression In The Field.” In Pipeline & Gas 

Journal, September 2010, Vol. 237, No. 9. 5

 M.P. Walsh. “Oil Reservoir Primary Drive Mechanisms.” In Petroleum Engineering Handbook, Volume V: 

Reservoir Engineering and Petrophysics, E.D. Holstein (Ed.), L.W. Lake (Ed. In Chief), pp. V-895-980. Society of 

Petroleum Engineers, 2007. 

6

 A stock tank barrel is the volume of treated oil as stored in a stock tank (a storage tank specifically for treated oil). 

A stock tank barrel is the same quantity as a barrel at atmospheric temperature and pressure (i.e., surface conditions 

rather than reservoir conditions). 
4 

Estimation of Emissions based on Published Literature 

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

to the Greenhouse Gas Reporting Program (GHGRP) from oil well completions or workovers 

with hydraulic fracturing beginning in reporting year 2016.7

 One source estimated approximately 

15,600 oil well completions with hydraulic fracturing in 2012.8

 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 on 

the effective date of the rule will be similar to the activity level in 2012. The number of gas and 

oil wells has increased over the last few years and is anticipated to continue to increase 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 

15,600. 

In published literature, estimates of average potential CH4 emissions from oil well 

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

tons of CH4 per completion9

 to 32 tons of CH4 per completion.10 Multiplying these values by the 

activity levels described above (i.e., 15,600 completions and workovers, assuming all wells will 

be located at facilities reporting to the GHGRP) gives a potential emissions range of 120,000 

tons CH4 per year to 499,000 tons CH4 per year (109,000 to 453,000 metric tons (MT) CH4 per 

year). 

 

7

 Subpart W did not previously cover emissions from oil well completions and workovers with hydraulic fracturing, 

except for associated flaring emissions that may have been reported under the miscellaneous flare stacks category. 

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

document, Oil and Natural Gas Sector: Standards for Crude Oil and Natural Gas; Background Technical Support 

Document for the Proposed New Source Performance Standards (40 CFR Part 60, subpart OOOOa). August, 2015. 

See Docket ID No. EPA-HQ-OAR-2010-0505. 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 Reporting Tool (e-GGRT). However, the EPA notes that subpart W did not previously 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 new emission source. 

8

 U.S. EPA. Oil and Natural Gas Sector: Standards for Crude Oil and Natural Gas Facilities; Background 

Technical Support Document for the Proposed New Source Performance Standards (40 CFR Part 60, subpart 

OOOOa). August 2015. See Docket ID No. EPA-HQ-OAR-2010-0505. Oil wells were defined as those with a GOR 

greater than or equal to 300 scf per barrel but less than 100,000 scf per barrel. 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 O’Sullivan, Francis and Sergey Paltsev, “Shale gas production: potential versus actual greenhouse gas emissions,” 

Environmental Research Letters, United Kingdom. November 26, 2012. Docket Item No. EPA-HQ-OAR-2014-

0831-0025. 
5 

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 did not previously 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 MT carbon dioxide equivalent (CO2e) report those emissions to the 

GHGRP under 40 CFR part 98, subpart C (Stationary Combustion) (hereafter referred to as 
6 

“subpart C”).11 Subpart W did cover emissions from sources such as compressors and 

dehydrators in other industry segments already 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). 

As drilling of multiple horizontal wells from a single well pad has become a common 

industry practice, the complex infrastructure to produce, transport, and process hydrocarbons is 

no longer a simple linear train.12 This often makes the distinction between a production facility 

end point and the beginning of a gathering and boosting system difficult to assess. The Onshore 

Petroleum and Natural Gas Gathering and Boosting segment is intended to include upstream 

components that are not already included in the Onshore Petroleum and Natural Gas Production 

segment and may have fugitive emissions, including multiphase flow gathering pipelines as well 

as gas gathering pipelines. 

Multiphase Gathering Pipelines 

The inclusion of both “petroleum” and “natural gas” in the segment name is intended to 

reflect the complex nature of upstream operations where wells can produce oil, natural gas, or a 

mixture of both and to signify the inclusion of GHG emissions from gathering and boosting 

systems moving high volatility liquids in this new segment. According to the EIA, more than 50 

percent of new wells produced both oil and natural gas in 2011 and 2012.13 When wells go into 

production, either single phase or multiphase flow gathering pipelines transport the fluid to 

separation and processing facilities. 

It cannot be assumed that pipelines that carry “primarily liquids” will not have fugitive 

gas emissions. As noted in Section 1 of this document, even in wells that produce primarily 

liquids at surface temperature and pressure conditions, there is often a volatile gaseous 

component. For example, in the Bakken shale and similar tight oil reservoirs, the presence of 

associated gas is a necessary condition for high-volume production.14 A recent study of Bakken 

crude oils measured the flammable gas content of oil as high as 12 percent.15 A report prepared 

 

11 In 2013, 439 facilities with one or more of the North American Industry Classification System (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 will be part of the Onshore Petroleum and Natural Gas Gathering and Boosting segment. 12 Conder, Michael W. and Kevin A. Lawlor. “Production Characteristics Of Liquids-Rich Resource Plays 

Challenge Facility Design,” American Oil & Gas Reporter, May 2014. 13 J. Lieskovsky and S. Gorgen. “Drilling often results in both oil and natural gas production.” Today in Energy, 

U.S. Energy Information Administration, October 29, 2013. http://www.eia.gov/todayinenergy/detail.cfm?id=13571. 

Accessed June 9, 2015. 

14 U.S. Department of Energy Quadrennial Energy Review Task Force Secretariat and Energy Policy and Systems 

Analysis Staff. “QER Public Stakeholder Meeting: Infrastructure Constraints in the Bakken,” Memorandum to 

Members of the Public, August 8, 2014. 

15 Dangerous Goods Transport Consulting, Inc. A Survey of Bakken Crude Oil Characteristics Assembled for the 

U.S. Department of Transportation. Submitted by American Fuel & Petrochemical Manufacturers, May 14, 2014. 
7 

for the North Dakota Petroleum Council noted that volatile components of the oil could 

accumulate in atmospheric storage tanks.16 

The potential for leakage from a multiphase gathering pipeline can be determined by a 

number of factors, including vapor pressure, GOR, the flow regime, line pressure, and the 

volatility of the crude oil. The EPA considered several options to clarify the intent to exclude 

gathering pipelines containing essentially only oil. Some multiphase gathering pipelines carrying 

fluid through the gathering and boosting system will carry heavier crude with a very limited 

potential for fugitive emissions leaks. To distinguish from more volatile oil, some measure of the 

gaseous component of the oil can be used. The following are options considered to estimate the 

volatility of the oil and the likelihood of fugitive emissions: 

 Vapor pressure. Vapor pressure represents the liquid’s tendency to evaporate into its 

gaseous phase with rising temperature.17 Crude with higher volatility would produce 

high levels of gas during pipeline transportation. 

 API gravity. Use API gravity as a proxy to identify those light crudes likely to contain 

enough gas to create potential fugitive emissions. 

 GOR. The higher the GOR, the more likely that the pipeline will have the potential 

for fugitive emissions, because the gaseous content will be higher for higher GOR 

values. 

Vapor pressure is used to determine the volatility of crude oil. Typically, the Reid vapor 

pressure (RVP) test is used to measure vapor pressure of petroleum. As outlined in ASTM D 323 

– 99a, calculation of the RVP requires specialized equipment and controlled conditions.18

Conducting this test on a gathering and boosting system or, alternatively, collecting the 

necessary samples and sending them to a laboratory for testing would likely result in the highest 

burden to reporters of the three options considered. 

API gravity has the unit of degree, where a low value in degrees is heavy and high value 

is light. This makes API gravity the inverse of density, usually measured by specific gravity. 

Lighter crudes may contain more gaseous components that can create emissions. However, API 

gravity is not a direct measure of volatility or gas content and may not yield a consistent 

threshold for the purpose of GHG reporting. 

 

16 Auers, John R., Ryan M. Couture, and Dennis L. Sutton. The North Dakota Petroleum Council Study on Bakken 

Crude Properties, report prepared for the North Dakota Petroleum Council, August 4, 2014. 17 Pharris, T.C. and R.L. Kolpa. Overview of the Design, Construction, and Operation of Interstate Liquid 

Petroleum Pipelines, Argonne National Laboratory, ANL/EVS/TM/08-1, November 2007. 18 ASTM International. Standard Test Method for Vapor Pressure of Petroleum Products (Reid Method). ASTM D 

323 – 99a. Approved April 10, 1999; published June 1999. 
8 

The GOR is the measure of gaseous components of crude oil to the liquid components. 

The higher the GOR, the higher the volatility and thus the potential for emissions. Operators 

regularly calculate GOR in the field as part of assessing the likely sales volume of gas and/or oil. 

Therefore, completing a GOR measurement is not anticipated to be an additional burden to 

reporters. For these reasons, GOR was determined to be the best mechanism for assessing the 

volatility of the gaseous phase in a multiphase gathering pipeline. 

As with oil well completions, the selection of a GOR threshold should consider 

minimizing reporting burden while still capturing most of the emissions from this source. A 

primary consideration when setting a threshold is volatility; the threshold must be low enough 

that the oil produced is considered non-volatile. Non-volatile “black oils” (i.e., oil likely to not 

have gases or light hydrocarbons associated with it) are generally defined as having GOR values 

in the range of 200 to 900 scf/STB.19 Because the considerations for gathering pipelines are 

similar to those for oil well completions and workovers with hydraulic fracturing, the EPA 

evaluated applying the same GOR threshold of 300 scf/STB to multiphase gathering pipelines. 

Oil transported in gathering pipeline segments with a GOR less than 300 scf/STB are at the 

lower end of the range for “black oils,” and oil transported in these pipelines will not likely have 

significant amounts of associated gas. Therefore, the EPA selected a GOR of 300 scf/STB as the 

threshold between multiphase gathering pipelines and oil pipelines, and oil pipelines (those with 

a GOR less than 300 scf/STB) are not considered part of the Onshore Petroleum and Natural Gas 

Gathering and Boosting segment. 

Estimates of Nationwide GHG Emissions for Gathering and Boosting Systems 

Several 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 for estimating gathering and boosting emissions is 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”),20 which includes CH4 and carbon dioxide (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 reciprocating compressors in the natural gas production segment and for gas 

gathering pipelines. In the U.S. GHG Inventory, gathering and boosting systems are included as 

part of the natural gas systems production segment. Vented and fugitive GHG emissions from 

 

19 M.P. Walsh. “Oil Reservoir Primary Drive Mechanisms.” In Petroleum Engineering Handbook, Volume V: 

Reservoir Engineering and Petrophysics, E.D. Holstein (Ed.), L.W. Lake (Ed. In Chief), pp. V-895-980. Society of 

Petroleum Engineers, 2007. 

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

430-R-14-003. April 15, 2014. Docket Item No. EPA-HQ-OAR-2014-0831-0008. 
9 

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 assigned in the U.S. 

GHG Inventory to further sub-segments. 

Applying a global warming potential for 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. 

To estimate the combustion emissions associated with gathering and boosting, the EPA 

reviewed an analysis conducted by the Interstate Natural Gas Association of America (INGAA). 

INGAA used data from the 2007 U.S. GHG Inventory and estimated the “split” of GHG 

emissions from combustion versus fugitive and vented GHG emissions (i.e., process emissions) 

for natural gas systems.21 The INGAA analysis compared total combustion emissions and 

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

storage. The INGAA analysis found that of the 83.0 MMT CO2e emissions reported for natural 

gas production in the 2007 U.S. GHG Inventory, 47.8 MMT CO2e were combustion and flaring 

emissions (58 percent) and 35.2 MMT CO2e (42 percent) were “release of methane” (fugitive 

emissions and venting).22,23

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 42 percent of the total emissions associated with gathering and boosting. 

Conservatively assuming that the approximate value of 10 MMT CO2e from the 2014 U.S. GHG 

Inventory is a low-bound estimate of total process emissions from the gathering and boosting 

segment, this brings the total emissions from both process and combustion emissions in 

gathering and boosting to approximately 24 MMT CO2e. This is a low-bound estimate because 

the amount does not include the additional process equipment mentioned above. 

Another 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 

 

21 INGAA. “Emissions from the Natural Gas Industry.” Available at http://www.ingaa.org/cms/6435.aspx. 22 Ibid. 23 Using data gathered through the GHGRP for subpart W in RY2013, combustion emissions represented about 25 

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

segment and approximately 65 percent of the Onshore Natural Gas Processing segment emissions totals. The EPA 

anticipates that the 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, which is consistent with the 58 

percent estimate calculated using the INGAA analysis. 
10 

Industries,

24 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 Inventory25 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 sources.26

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

 Reciprocating compressors; 

 Centrifugal compressors; 

 Compressor exhaust; 

 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 analysis27 referenced above to assume that process emissions of 

20 MMT CO2e are approximately 42 percent of the total emissions associated with gathering and 

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

gathering and boosting to approximately 47 MMT CO2e. 

A recent study published in Environmental Science and Technology estimated national 

emissions of methane from gathering and boosting to be 47 MMT CO2e. The study used 

measured emissions data from a sample of gathering plants, a Monte Carlo approach to estimate 

 

24 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. Docket Item No. EPA-HQ-OAR-2014-0831-

0028. 

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

EPA 430-R-13-001. April 12, 2013. Docket Item No. EPA-HQ-OAR-2014-0831-0026. 

26 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. 

27 INGAA. “Emissions from the Natural Gas Industry.” Available at http://www.ingaa.org/cms/6435.aspx. 
11 

emissions from gathering plants, and the GHG inventory estimate for pipeline emissions.28 Using 

the INGAA analysis29 referenced above to assume that process emissions of 47 MMT CO2e are 

approximately 42 percent of the total emissions associated with gathering and boosting, this 

brings the total emissions from both process and combustion emissions in gathering and boosting 

to approximately 111 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 

24 MMT CO2e and 111 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 

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 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” is the 

 

28 Marchese et al., Methane Emissions from United States Natural Gas Gathering and Processing, Published in 

Environmental Science and Technology, 2015, 49, 10718-10727, available at 

http://pubs.acs.org/doi/pdf/10.1021/acs.est.5b02275. 29 INGAA. “Emissions from the Natural Gas Industry.” Available at http://www.ingaa.org/cms/6435.aspx. 
12 

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 Glossary:30

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),31 which defines a “gathering line” as: 

... 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, 

 

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

September 30, 2014. 

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

April 2000. 
13 

(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 defining 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 

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 firm.32

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

gathering and boosting operations in the 2010 rule (75 FR 18608, April 12, 2010) 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 

 

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

published by Hart Energy and MidstreamBusiness.com 
14 

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 

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 
15 

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

or otherwise, on the third party.33

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 has 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 changes 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 DR. Under this 

provision, gathering and boosting facilities with multiple owners will identify and authorize a 

DR who will 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 DR, 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 final definition 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 

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

custody of the petroleum or natural 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 

 

33 75 FR 74474 
16 

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 make 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 situations.34 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 

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 segments already defined in 

subpart W. 

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 petroleum and/or natural gas to a natural gas processing facility, a 

natural gas transmission pipeline, or a natural gas distribution pipeline. Gathering and boosting 

equipment includes, but is not limited to, gathering pipelines, separators, compressors, acid gas 

removal units, dehydrators, pneumatic devices/pumps, storage vessels, engines, boilers, heaters, 

and flares. The 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 includes 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, 

 

34 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. 
17 

the output may be routed to a single “production battery” for efficiency of further processing,35

and those batteries are 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 balances 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 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 basis of the proposed and final definition. 

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 

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 

 

35 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. 
18 

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 subpart W 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). 

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.
19 

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 repo

Emissions coverage eonly largest facilities reporting threshold. Nfacilities that exceed tcombustion sources aunder subpart C. Option provides potenmore geographically soverall coverage may No reporting thresholwould be comprehens

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 threshold option is used, so the burden to evaluate whether a facility exceeds the reporting threshold would be lower than Option 1. Reporting burden would likely be higher than Option 1, if the threshold option is used, 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 used; most facilities winclude more emissionumber of emission sthan Option 1 if no thOption provides potengeographically specif
20 

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 similar to or slightly less than Option 2, depending on the number 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 Oplower. Separation of gcompressor stations wconsists of fewer emiparticularly for gatherthe number of emissioOption provides potengeographically specifstations. Gathering pibe reported at the natia geographic basis. 
21 

Options 1 and 3 would provide limited data on the 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 final 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. 

If a gathering and boosting system spans multiple basins, the owner or operator reporter 

should submit one report per basin (i.e., per “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” as it is defined in subpart W at 40 CFR 98.238) if the portion of the 

gathering and boosting system in that basin exceeds the 25,000 MT CO2e per year reporting 

threshold (as defined at 40 CFR 98.2). In other words, the reporter would determine the 

emissions from the portion of gathering and boosting system associated with each basin. If the 

total emissions in each basin exceed the 25,000 MT CO2e per year reporting threshold, then the 

reporter would submit two reports. If the total emissions in one basin exceed the 25,000 MT 

CO2e threshold, but the emissions in the other basin are below the threshold, then the reporter 
22 

would submit one report for the basin that exceeds the threshold. For reference, the EPA is 

including a map of the U.S. geologic basins in Docket ID No. EPA-HQ-OAR-2014-0831.36

Emission Sources 

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

are 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 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 

Subpart W requires reporting of emissions from “blowdown vent stacks,” defined in 

subpart A of Part 98 as “natural gas and/or CO2 released due to maintenance and/or blowdown 

operations including compressor blowdown and emergency shut-down (ESD) system testing,” 

for several segments. For the most part, the blowdown vent stacks in these segments are located 

at consolidated facility sites, and for the blowdown vent stacks in the Onshore Petroleum and 

Natural Gas Gathering and Boosting segment that are similar to those other industry segments, 

the calculation methodologies in subpart W are appropriate. The EPA then evaluated the 

applicability of the same subpart W calculation methodologies for blowdown vent stacks on 

gathering pipelines in the Onshore Petroleum and Natural Gas Gathering and Boosting segment. 

Both of these types of blowdown vent stacks were included in the proposed rule. 

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

 

36 R.F. Meyer, L.G. Wallace, and F.J. Wagner, Jr., Editors. Contiguous United States AAPG-CSD Geologic 

Provinces Code Map. Revised edition: 1991.
23 

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 is appropriate for the Onshore Petroleum and Natural 

Gas Gathering and Boosting segment. 

The EPA does recognize that blowdown vent stacks not located at consolidated facility 

sites are not always manned. As noted in the previous paragraph, pipeline owners and operators 

know when maintenance activities are going to occur, and they know the parameters needed to 

calculate emissions. However, emergency blowdowns may occur without personnel on-site or 

nearby, making it difficult to determine emissions from a blowdown event. Therefore, for 

emergency blowdowns, reporters may use engineering estimates based on the most recently 

available information to determine the temperature and pressure used in Equation W-14A. 

Compressors and Equipment Leaks 

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

sufficient pressure so natural gas will continue flowing. The two 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 (“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 typical.37

 

37 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

(Docket Item No. EPA-HQ-OAR-2014-0831-0041) 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. 
24 

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 British thermal units (Btu) per cubic foot, produced gas is less 

suitable for use as a fuel gas.38 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 a 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 requiring gathering and 

boosting reporters to 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. The 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 this approach, a reporter needs 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. 

Gathering Pipelines 

Prior to the addition of the Onshore Petroleum and Natural Gas Gathering and Boosting 

segment, the only other segment in subpart W that included emissions from pipelines was the 

Natural Gas Distribution segment. For that industry segment, subpart W requires that emission 

leaks from distribution mains be estimated using an emission factor approach. To assess whether 

a similar 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. 

 

38 Lawlor and Conder, op. cit. 
25 

The pipeline characteristics include typical material, pipe size, maximum operating pressure, and 

burial depth. 

The results are summarized in Table 2.3. 
26 

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

Characteristic 

Type of Pipeline 

Gathering Pipelines39

Distribution 

Mains40

Transmission 

Pipelines41

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 norms.42

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 endpoint.43 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 cover.44

Minimum 

depth is 30” 

from top of 

pipe 

 

39 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, Docket Item No. EPA-HQ-OAR-2014-0831-

0020. 

40 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. Docket Item No. EPA-HQ-OAR2014-0831-0045. 

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

www.Naturalgas.org. 42 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. 43 Williams Company, www.williamsinthenortheast.com/projects/landowner-faq. Docket Item No. EPA-HQ-OAR2014-0831-0036. 
27 

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 than the average factor for gathering pipelines. The emission factors for these 

two types of distribution pipelines are 0.35 standard cubic feet per hour per mile (scf/hour/mile) 

(protected steel) and 1.13 scf/hour/mile (plastic).45,46

The 2014 U.S. GHG Inventory lists 445,135 miles of gathering pipelines.47,48 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)/mile/year (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 per mile (scfd/mile) or approximately 0.57 Mcf/mile/year (0.065 scf/hour/mile). These 

emission factors are derived from the 1996 Gas Research Institute (GRI)/EPA foundational study 

(hereafter referred to as “the 1996 GRI/EPA study”).49 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. 

 

44 49 CFR 192.327. 

45 2014 U.S. GHG Inventory. 

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

47 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. 48 ICF (1996), Estimation of Activity Factors for the Natural Gas Exploration and Production Industry in the U.S. 

49 M. Harrison, T. Shires, J. Wessels, and R. Cowgill, eds. Methane Emissions from the Natural Gas Industry. 

Prepared by Radian International LLC for National Risk Management Research Laboratory, Air Pollution 

Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a. 
28 

 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. 

 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. 

 Using the information from the original 1996 GRI/EPA study to develop emission 

factors by pipeline material on a nationwide basis. 

The proposed emission factor for gathering and boosting pipelines was based on an 

average emission factor for gathering and boosting pipelines from the 2014 U.S. GHG Inventory 

(the first option in the list above). Although the emission factors for gathering and boosting 

pipelines in the 2014 U.S. GHG Inventory were initially based on the 1996 GRI/EPA emission 

factors for gathering pipeline material type, different activity factors have been applied to derive 

average gathering pipeline emission factors for six different U.S. onshore production regions. In 

response to comments received on the proposed emission factors, which recommended using 

characteristics of currently operating gathering pipelines rather than distribution pipelines or 

older data on gathering pipelines, the EPA re-evaluated the development of the emission factors 

for gathering pipelines. 

The EPA reviewed the documentation in the 1996 GRI/EPA study 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). 

The 1996 GRI/EPA study presents emission factors for gathering pipelines based on 

pipeline material.50 As shown in Table 2.4, the 1996 GRI/EPA study emission factors are 

presented in units of standard cubic feet of CH4 per leak per year (scf CH4/leak/yr) by pipe 

material, except for the cast iron pipe emission factor, which is presented in units of scf 

CH4/mile/year. The activity factors presented in 1996 GRI/EPA study are “number of leaks per 

year” and the “miles of gathering pipeline” for each pipe material type. If the average leaks per 

year are known and miles of gathering pipeline are known for each pipe material type, emission 

factors in units of scf/mile can be derived from the 1996 GRI/EPA study for each category of 

 

50 M. Harrison, H.J. Williamson, and L.M. Campbell. Methane Emissions from the Natural Gas Industry, Volume 3: 

General Methodology. Prepared by Radian International LLC for National Risk Management Research Laboratory, 

Air Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080c. Pages A-17 – A21.
29 

pipe material. These emission factors are derived in Table 2.4; Column D shows CH4 emission 

factors in units of scf/mile/year, Column E shows emission factors in units of scfd/mile and 

Column F shows emission factors in units of scf/hour/mile. 

Table 2.4. Methane Emission Factors for Gathering Pipelines (1996 GRI/EPA Study) 

Column A Column B Column C Column D Column E Column F 

Pipe 

Material 

Average 

Emission 

Factor, 

scf/leak/yr 

Activity 

Factor: 

Average 

Leaks per 

Year 

Activity 

Factor: 

Miles of 

Gathering 

Pipeline 

Derived 

Emission 

Factor 

(scf/mile/year) 

Derived 

Emission 

Factor 

(scfd/mile)

Derived 

Emission 

Factor 

(scf/hour/mile) 

Protected 

Steel 17,102 53,657 268,802 3,414 9.35 0.39 

Unprotect

ed Steel 43,705 114,6555 41,400 121,039 331.61 13.82 

Plastic 84,237 6,467 29,862 18,243 49.98 2.08 

Cast Iron 201,418 

(scf/mile/year) 856 201,418 551.83 22.99 

The U.S. GHG Inventory provides potential CH4 emission factors for gathering pipelines 

in units of scfd/mile by NEMS region. These are derived emission factors; the underlying 

average emission factors in units of scf/leak/yr are from the 1996 GRI/EPA study, but different 

assumptions are made about gathering pipeline activity factors for each NEMS region to derive 

an emission factor in units of scfd/mile for each region. These activity factor assumptions 

include average leaks per year by pipeline material type and the miles of gathering pipeline in 

each NEMS region by material type. 

To develop a single emission factor per mile of gathering pipeline for subpart W, the 

miles of gathering pipeline by material type is needed. For example, the original 1996 GRI/EPA 

study found that 79 percent of gathering pipelines were protected steel, 12 percent were 

unprotected steel, 9 percent were plastic, and 0.3 percent of gathering pipelines were iron. These 

percentages could be applied to the 1996 GRI/EPA study emission factors, resulting in a derived 

factor of 2.23 scf/hour/mile, regardless of pipeline type. However, as noted earlier in this section, 

there is significant variability in gathering pipelines and gathering system configurations, and the 

configuration and operating design of a gathering and boosting system may change over the 

lifetime of a producing field, so these percentages are not expected to have remained the same 

over the last 20 years. Therefore, rather than calculate a single emission factor for gathering 

pipelines based on a distribution of gathering pipeline materials, the EPA determined that the 

most appropriate approach is to include gathering pipeline emission factors for four pipeline 

material types – protected steel, unprotected steel, plastic, and cast iron – in subpart W. 
30 

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

should develop CO2 emission estimates for gathering pipelines in addition to CH4, as the CH4

content of materials transported in gathering pipelines may vary from facility to facility. 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. 

Table 2.5 summarizes the CH4 and whole gas emission factors for gathering pipelines by 

pipeline material type. The CH4 emission factors were converted to whole gas emission factors 

using the average CH4 content of natural gas in the U.S. production sector of 83.3 percent.51

These whole gas emission factors are included in Table W-1A of the final rule. 

Table 2.5. Emission Factors for Gas Gathering Pipelines by Pipeline Material Type 

Pipeline Material Derived CH4 Emission Factor 

(scf/hour/mile) 

Derived Whole Gas Emission Factor 

(scf/hour/mile) 

Protected Steel 0.39 0.47 

Unprotected Steel 13.82 16.59 

Plastic 2.08 2.50 

Cast Iron 22.99 27.60 

These emission factors allow 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. 

 

 

51 2014 U.S. GHG Inventory, Annex 3, Table A-131, U.S. Production Sector CH4 Content in Natural Gas by NEMS 

Region (General Sources); value from “Lower 48 States” column.
31 

3 ONSHORE NATURAL GAS TRANSMISSION PIPELINE SEGMENT 

Background 

Natural gas transmission compressor stations are 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 

stations.52 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 for CH4 of 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/year,53 which is equivalent to 

6.0 MMT CO2e per year in 2012, or 19.6 MT CO2e/mile/year (applying the global warming 

potential for CH4 of 25). 

Definition of Owner/Operator 

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

ownership scenarios. For example a master limited partnership (MLP) is a unique structure of 

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

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 

 

52 2014 U.S. GHG Inventory, Annex 3, Table A-129: 2012 Data and CH4 Emissions (Mg) for the Natural Gas 

Transmission Stage. 

53 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. 
32 

was necessary. The Pipeline and Hazardous Materials Safety Administration (PHMSA) already 

includes a specific description 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 LDC 

without prior FERC approval. 

This description 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. However, upon review of the existing 

definition of “transmission pipeline” in subpart W, the EPA recognized that the PHMSA 

description of “operator” is not inclusive enough to cover all subpart W transmission pipelines. 

Specifically, subpart W defines a “transmission pipeline” as a “FERC 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.” This definition was 

proposed in September 2011 “to clearly demarcate transmission pipelines from distribution and 

gathering pipelines” because transmission pipelines are clearly designated as such by FERC for 

interstate pipelines, individual States for intrastate pipelines, and the Hinshaw exemption under 

the Natural Gas Act for Hinshaw transmission pipelines.”54 During the public comment period 

for the 2011 amendments, one commenter expressed concern that the proposed definition would 

cover parts of gathering systems and submitted additional language for the definition that would 

describe what is not covered. In the response, the EPA noted that “pipelines, such as gathering 

facilities that are exempt from rate regulation under the Natural Gas Act, do not fall in any one of 

[the] three categories [and] are not covered as transmission pipelines.”55

 

54 76 FR 56010; September 9, 2011 

55 U.S. EPA. 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. December 

2011. Docket Item No. EPA-HQ-OAR-2011-0512-0054. 
33 

Therefore, intrastate pipelines were to be considered a transmission pipeline for the 

purposes of subpart W if they are “state rate-regulated.” It is clear that some states regulate rates, 

but it appears that others do not. Thus, the PHMSA definition above would not cover all 

intrastate pipelines. Even within those states that do regulate rates, not all intrastate pipelines 

would be covered because only some intrastate pipelines are subject to section 311 of the NGPA. 

Specifically, they are subject to the NGPA only if they transport natural gas on behalf of an 

interstate pipeline (or LDC served by an intrastate pipeline), or if they sell natural gas to an 

interstate pipeline. For those intrastate pipelines that are not subject to section 311 of the NGPA, 

the owner or operator would be the person identified as the owner or operator on reports to the 

regulatory body of the state or municipality having jurisdiction to regulate rates and charges for 

the sale of natural gas to consumers within the State or municipality. 

In addition, it appears that pipelines that fall under the “Hinshaw Exemption” also would 

not be covered by the PHMSA definition because they are not required to obtain a Certificate of 

Public Convenience and Necessity, and they are not intrastate pipelines (or subject to section 311 

of the NGPA). However, in order to transport on behalf of interstate pipelines (just like an 

intrastate pipeline) they must apply for a “blanket certificate” under section 284.224 of CFR title 

18. Thus, Hinshaw pipelines would be covered as transmission pipeline facilities under subpart 

W if the definition of owner or operator indicates that the owner or operator is the person 

identified as the owner or operator on blanket certificates issued under 18 CFR 284.224. 

As a result of this research, the final definition of “Onshore natural gas transmission 

pipeline owner or operator” has been added to 40 CFR 98.238 to read as follows: 

Onshore natural gas transmission pipeline owner or operator means, for 

interstate pipelines, the person identified as the transmission pipeline owner or 

operator on the Certificate of Public Convenience and Necessity issued under 

15 U.S.C. 717f, or, for intrastate pipelines, the person identified as the owner 

or operator on the transmission pipeline’s Statement of Operating Conditions 

under section 311 of the Natural Gas Policy Act, or for pipelines that fall 

under the “Hinshaw Exemption” as referenced in section 1(c) of the Natural 

Gas Act, 15 U.S.C. 717-717 (w)(1994), the person identified as the owner or 

operator on blanket certificates issued under 18 CFR 284.224. If an intrastate 

pipeline is not subject to section 311 of the NGPA, the onshore natural gas 

transmission pipeline owner or operator is the person identified as the owner 

or operator on reports to the state regulatory body regulating rates and charges 

for the sale of natural gas to consumers. 
34 

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 

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. 
35 

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. 

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 United States to another. 

The EPA also took into account the fact that many entities own and operate pipeline segments 
36 

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 is 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 PHMSA 

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

unintentional (with targeted exceptions) must be reported to PHMSA, per 49 CFR part 191. 

Specifically, PHMSA collects data on transmission pipeline incidents.56 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. 

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 

 

56 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. 
37 

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

on any resulting shutdowns, explosions, evacuations.57

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 U.S. Department of Energy (DOE) 

Many of the data elements required 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-17658 and EIA-19159

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 site60 and in EIA publications such as Natural Gas Monthly.

61 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. 

 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 

 

57 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. Docket Item No. EPA-HQ-OAR-2014-0831-0044. 58 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. Docket Item No. EPA-HQ-OAR-2014-

0831-0048. 

59 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. Docket Item No. EPA-HQ-OAR-2014-0831-0047. 60 EIA Natural Gas Annual Respondent Query System. Last release: April 2014. Available at 

http://www.eia.gov/cfapps/ngqs/ngqs.cfm?f_report=RP1. 61 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/. 
38 

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 required to be reported under 40 CFR 98.236(aa)(11), the miles of 

transmission pipeline for each state in the facility, is reported through FERC Form No. 262 and is 

available on the FERC and individual company Web sites. 

Subpart W Reporting 

At proposal, there were seven blowdown equipment and event type categories applicable 

to all blowdowns in 40 CFR 98.233(i)(2), including blowdowns within the Onshore Natural Gas 

Transmission Pipeline segment. The EPA originally developed these categories based on 

compressor station blowdowns. During the public comment period, multiple commenters noted 

that the blowdown equipment and event type categories that were proposed were developed for 

compressor station blowdowns do not provide meaningful information for pipeline blowdowns. 

The EPA agrees that the rule should include blowdown categories specific to pipeline 

blowdowns in the Onshore Natural Gas Transmission Pipeline segment. Therefore, the final rule 

at 40 CFR 98.233(i)(2) specifies that the Onshore Natural Gas Transmission Pipeline segment 

blowdowns must be grouped into one of the following eight categories: 

 pipeline integrity work (e.g., the preparation work of modifying facilities, ongoing 

assessments, maintenance or mitigation), 

 traditional operations or pipeline maintenance, 

 equipment replacement or repair (e.g., valves), 

 pipe abandonment, 

 

62 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. Docket Item No. EPA-HQ-OAR-2014-0831-0029. 
39 

 new construction or modification of pipelines including commissioning and change of 

service, 

 operational precaution during activities (e.g. excavation near pipelines), 

 emergency shutdowns including pipeline incidents as defined by PHMSA, and 

 all other pipeline segments with a physical volume greater than or equal to 50 cubic 

feet. 

 
40 

4 WELL IDENTIFICATION NUMBERS 

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

wells in the United States must apply for a permit from the relevant permitting authority, or the 

entity that issues permits for drilling of oil and gas wells.63 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 D12A.64 API 

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

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

and then renamed the identifier as the “US Well Number” in June 2014.65 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.

 

63 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). 

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

Offshore Waters. API Bulletin D12A, January 1979. Available at https://dl.ppdm.org/dl/62. 65 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/1209. 
41 

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 
42 

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 United States, 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 tools.66

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. 

 

66 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. Docket Item No. EPA-HQOAR-2014-0831-0024.) 
43 

The final revisions to subpart W include well identification reporting requirements for 

individual oil and gas wells covered by the Onshore Petroleum and Natural Gas Production 

segment and equipment or operations associated with those individual wells. In addition, the 

EPA is finalizing the requirements in 40 CFR 98.236(aa)(1)(ii)(D) through (H) to include a list 

of the well identification numbers by sub-basin for the producing wells at the end of the calendar 

year and lists of the well identification numbers for the wells acquired, divested, completed, and 

permanently taken out of production during the calendar year. These requirements will improve 

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

The EPA also considered including well identification reporting requirements for 

equipment other than wells. As part of this consideration, the EPA reviewed the well and 

emission-source equipment reporting practices used by a number of producing states to assess 

the current status of reporting of well identification numbers associated with each emission 

source. Seven states were surveyed to see how the issue of linking well identification numbers to 

the various emission-source equipment is handled at the state level. Although most of the states 

assign unique identifiers to each emission source, the EPA found that only two of the seven 

states have a tracking system that links individual emission sources to specific wells and well 

identification numbers, and these two states approach the linking of well identification numbers 

to equipment differently. See Appendix A of this document for details of the state analysis. 

The EPA’s review of state requirements shows that there may be multiple scenarios in 

which a reporter does not know which well or wells are associated with a particular emission 

source. Therefore, the EPA is not requiring facilities in this rulemaking to report well 

identification numbers for every emission source in a facility in the Onshore Petroleum and 

Natural Gas Production segment. Instead, the EPA is requiring the reporting of well 

identification numbers for the Onshore Petroleum and Natural Gas Production segment only for 

information related specifically to wells. 
Appendix A 

Use of Well Identification Numbers in State Programs 

 
A-1 

APPENDIX A 

Use of Well Identification Numbers in State Programs 

The EPA reviewed the well and emission-source equipment reporting practices used by a 

number of producing states to assess the current status of reporting of well identification 

numbers associated with each emission source. Seven states were surveyed to see how the issue 

of linking well identification numbers to the various emission-source equipment is handled at the 

state level. 

All seven state exploration and production regulatory agencies require that individual 

wells be given a unique identifier as current practice. Without an identifier, each state’s ability to 

permit wells, track production and levy severance would be impossible. Most of these regulatory 

programs are based on well-level data identified by a unique number. Each state requires a 

drilling and operations permit for well sites that includes a description of the well and a 

schematic of the site. Because the primary purpose of these drilling permits is to manage oil and 

gas production, there is limited information on emissions-source equipment provided therein. 

Additionally, many of these states report air emissions through different bureaus, departments 

and, in a few cases, different regulatory entities. 

In the seven-state sample, two states specifically created a tracking system that linked 

individual emission-source equipment to well identification numbers for at least one emissions 

reporting program. The other states surveyed either did not attempt to link individual emissionsource equipment to well identification numbers or did not assign any identification numbers to 

emission-source equipment that would allow a link with well identification numbers to be 

established. 

States Not Tracking Equipment by Well Identification Number 

In North Dakota, the Department of Health regulates air emissions while the North 

Dakota Industrial Commission regulates sites and production. The Department of Health requires 

well identification numbers (NDIC Permit Number) on the Registration for Oil/Gas Production 

Facility SFN 14334 form if the permit includes a well but assigns no identification number to 

specific equipment. For multiple well pads, the SFN 14334 form also requires listing other 

existing wells at the site by NDIC Permit Number. For equipment with emissions, there is no 

identification system or assignment to a particular well. Location data for a piece of equipment is 

done only at the township and section level. Emissions by equipment category are aggregated 

and then entered into the workbook provided.i

 

The Pennsylvania Department of Environmental Protection regulates all aspects of oil 

and gas development. The Bureau of Air Quality regulates air emissions and the Bureau of Oil 
A-2 

and Gas Management regulates sites and production. For the Bureau of Air Quality GP-05 

Permit Application Form 2700-PM-BAQ0205 for Natural Gas Compression Facilities and/or 

Processing Facilities, the facility is not tied to a particular well identification number, though 

there are identification numbers for the specific pieces of equipment (such as internal 

combustion engines, turbines, dehydrators, fractionators, tanks, and pumps). Permit site diagrams 

do require the location of nearby equipment and facilities including “well(s), compressor 

stations(s), processing plant(s), natural gas wastewater storage and treatment facilities, 

interconnect/metering stations and transmission stations etc. within a five (5) miles radius, which 

are under common control.”ii However, there is no specific requirement to add identification 

numbers to the plot. 

Ohio regulates oil and gas operations through the Department of Natural Resources and 

air emissions through the Ohio Environmental Protection Agency. The Ohio EPA has developed 

General Permit 12 for air emissions reporting from oil and gas operations. There is one form for 

facilities with large flares and another for facilities with small flares. This facility permit process 

includes an emissions activity category (EAC) form along with the application for Permit to 

Install (PTI) and Permit to Install/Operate (PTIO). Though the EAC form is industry-specific, 

the actual permit application is not specific to the oil and gas industry. It follows the facility and 

equipment identification approach. Therefore, emission-source equipment is given a unique 

identification but is not linked to a particular well identification number anywhere on the form.iii 

In California, emissions reporting for wells and related facilities is managed by each air 

quality district rather than by the California Environmental Protection Agency - Air Resources 

Board while production and other well site regulation is managed by the Division of Oil, Gas, 

and Geothermal Resources.iv As an example, the South Coast Air Quality Management District 

(AQMD) Rule 222 Registration Form assigns an AQMD facility identification for permitting and 

a facility can have up to four wells associated in a well production group. Equipment is assigned 

a number that relates to the facility rather than the individual well.v

 Other air quality districts 

have different procedures. 

Air emission regulation in Oklahoma is managed by the Department of Environmental 

Quality (DEQ) while site and production are regulated by the Oklahoma Corporation 

Commission. The DEQ requires a Minor Source General Permit for Oil & Gas Facilities (GPOGF) form from operators in the state. The form does assign identifications for emission-source 

equipment but does not require a specific well identification number.vi 

States Tracking Equipment by Well Identification Number 

Some states have created an approach that links unique emission-source equipment to 

well identification numbers for at least one regulatory program. However, each follows a slightly 
A-3 

different approach. For Wyoming, the approach is to link each piece of emission-source 

equipment to the nearest well identification number. Texas created a facility identification 

numbering system that includes wells and emission-source equipment. 

For Wyoming, Wyoming Department of Environmental Quality monitors air quality 

while the Wyoming Oil and Gas Conservation Commission regulates sites and production. As 

regulated by Wyoming DEQ, the State of Wyoming Production Site Emissions Inventory 

requires that emissions from production facilities be identified by API number for its Triennial 

Minor Source Emissions program: 

Facilities with associated American Petroleum Institute (API) number (i.e.

production sites, water injection wells, tank batteries, etc.) should be reported 

using one of three excel “Production Equipment Inventory” forms available 

below. These forms are identical in nature except that they allow the user to 

report more or less facilities. 

The spreadsheets require the well name and API number for each particular piece of 

emission-source equipment. This data is required to help crosscheck the inventory data with 

information collected by the Wyoming Oil and Gas Conservation Commission.vii

For Texas, the regulation of sites and production is handled by the Texas viiiRailroad 

Commission while the Texas Commission of Environmental Quality (TCEQ) manages air 

emissions. Under Title 30 Texas Administrative Code (TAC), Chapter 116, Subchapter B, TCEQ 

“requires facilities that may emit air contaminants to obtain authorization prior to construction” 

including reporting emissions by site/location when point source reporting is required. If 

emissions are estimated to be above a certain level, the site/location is assigned a Regulated 

Entity Reference Number (RN), and the individual facility, be it a flare, vapor recovery unit or 

component, is assigned an individual Facility Identification Number (FIN). TCEQ uses a tiered 

approach to permitting and, unless a facility is designated as De Minimis, the information is 

submitted to the agency. This system allows very detailed analysis of emissions data by location, 

equipment type, field, and, in certain cases, producing formation.ix 
A-4 

i

 North Dakota Department of Health. Oil & Gas Upstream programs. Accessed May 15, 2015, at 

http://www.ndhealth.gov/aq/oilgaswell.aspx. ii Pennsylvania Department of Environmental Protection. General Permits: GP-05, Natural Gas Compression and/or 

Processing Facilities. Accessed May 15, 2015, at http://www.elibrary.dep.state.pa.us/dsweb/View/Collection-9747. iii Ohio Environmental Protection Agency, General Permits – Oil and Gas Well-Site Production Operations. 

Accessed May 15, 2015, at http://epa.ohio.gov/dapc/genpermit/oilandgaswellsiteproduction.aspx. iv California Environmental Protection Agency - Air Resources Board, Oil and Natural Gas Production, Processing, 

and Storage. Accessed May 15, 2015, at http://www.arb.ca.gov/cc/oil-gas/oil-gas.htm. v

 South Coast AQMD. Rule 222 Filing Program. Accessed May 15, 2015, at 

http://www.aqmd.gov/home/permits/equipment-registration/rule-222-filing-program. vi Oklahoma Department of Environmental Quality. General Permits & Permits by Rule for Oil and Gas Facilities. 

Accessed May 15, 2015, at http://www.deq.state.ok.us/aqdnew/permitting/genperm.htm. vii Wyoming Department of Environmental Quality. Triennial Minor Source Emissions. Accessed May 15, 2015, at 

http://deq.wyoming.gov/aqd/emission-inventories/resources/triennial-minor-source-emissions/. viii ix Texas Commission on Environmental Quality. Oil and Gas Facilities: Air Compliance Information. Accessed May 

15, 2015, at https://www.tceq.texas.gov/assistance/industry/oil-and-gas/oilgas_air.html.