MEMORANDUM 

TO: Docket ID No. EPA-HQ-OAR-2015-0764 

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

DATE: January 21, 2016 

SUBJECT: Greenhouse Gas Reporting Rule: Technical Support for Leak Detection 

Methodology Revisions and Confidentiality Determinations for Petroleum and 

Natural Gas Systems 

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

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

information on certain revisions related to developing leaker emission factors for quantifying 

emissions from the proposed leak detection methodology amendments.1

Background 

Under subpart W, operators of facilities in certain industry segments, including Onshore 

Natural Gas Processing, Onshore Natural Gas Transmission Compression, Underground Natural 

Gas Storage, Liquefied Natural Gas (LNG) Storage and LNG Import and Export Equipment, are 

required to conduct fugitive monitoring and must report greenhouse gas (GHG) emissions from 

equipment leaks identified during monitoring surveys using component-specific “leaker emission 

factors” provided in the rule (e.g., Table W-2 for Onshore Natural Gas Processing). Leaker 

emission factors are applied specifically to the number of components found to be leaking during 

the monitoring survey. The leaker emission factor represents the average leak rate for 

components that are leaking above a given “leak” threshold (typically 10,000 parts per million 

by volume (ppmv) for the oil and natural gas sector when using EPA Method 21, such as the 

“leak” definition in the new source performance standards for natural gas processors) and 

effectively assumes that no emissions occur from components that were not found to be leaking. 

Leaker emission factors currently used in subpart W are available for component sources 

commonly monitored using EPA Method 21 such as valves, connectors, open-ended lines, 

pressure relief valves, flanges, and in some cases, “other” component sources. 

For the Onshore Petroleum and Natural Gas Production and the Onshore Petroleum and 

Natural Gas Gathering and Boosting industry segments, subpart W currently includes default 

whole gas “population emission factors” (Table W-1A) and default average component counts 

for natural gas and crude oil production and gathering and boosting major equipment such as 

 

1

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

Docket ID No. EPA-HQ-OAR-2015-0764. 
2 

wellheads, separators, meters/piping, heaters, dehydrators and compressors (Tables W-1B and 

W-1C). Subpart W requires reporters in these segments to count the pieces of major production 

equipment at the facility and multiply that count by the default average component counts, or to 

count each individual component at the facility, and then multiply the number of components by 

the applicable population emission factor to estimate total emissions at a facility. (This method is 

also required for specific sources in other industry segments, such as storage wellheads in gas 

service in the Underground Natural Gas Storage industry segment.) 

The EPA issued new source performance standards (NSPS) in 40 CFR part 60, subpart 

OOOO for the oil and natural gas source category on August 16, 2012 (77 FR 49542) (hereafter 

referred to as “NSPS subpart OOOO”), which require fugitive emission monitoring for onshore 

natural gas processing plants. NSPS subpart OOOO requires fugitive emission monitoring only 

for onshore natural gas processing plants. The leak detection methods specified in NSPS subpart 

OOOO generally require the use of EPA Method 21 to identify leaks (although there is an 

alternative work practice that allows use of optical gas imaging (OGI)). When EPA Method 21 is 

used, only specific components specified in the rule are actively monitored using EPA Method 

21 (for NSPS subpart OOOO, these equipment components are each pump, pressure relief 

device, open-ended valve or line, valve, and flange or other connector that is in volatile organic 

compound (VOC) or wet gas service); other components are only subject to visual or olfactory 

leak identification. Historically, miscellaneous “other” fugitive emission sources included 

components such as instruments (gauges), regulators, access doors, agitator seals, loading arms, 

dump lever arms, stuffing boxes, breather caps; these sources may not be subject to EPA Method 

21 monitoring, but they are subject to repair if found leaking via visual or olfactory inspections. 

On September 18, 2015, the EPA proposed another set of NSPS for the oil and natural 

gas source category, 40 CFR part 60, subpart OOOOa (hereafter referred to as “NSPS subpart 

OOOOa”), to reduce methane emissions for several emission sources not covered by NSPS 

subpart OOOO (80 FR 56593). Among other things, proposed NSPS subpart OOOOa would 

require routine fugitive emissions monitoring of fugitive emissions components at new and 

modified compressor stations throughout the oil and natural gas sector and at new and modified 

well sites, defined as the area disturbed or affected by the drilling, subsequent operations, and 

production facilities directly associated with any oil, gas or injection well and its associated well 

pad. A fugitive emissions component is any component that has the potential to emit fugitive 

emissions of methane or VOC at a well site or compressor station site, including but not limited 

to valves, connectors, pressure relief devices, open-ended lines, access doors, flanges, closed 

vent systems, thief hatches or other openings on a storage vessels, agitator seals, distance pieces, 

crankcase vents, blowdown vents, pump seals or diaphragms, compressors, separators, pressure 

vessels, dehydrators, heaters, instruments, and meters. The proposed rule also specifies that 

fugitive emissions would be considered any visible emissions from fugitive emissions 
3 

components observed using OGI. The proposed NSPS subpart OOOOa standards would require 

replacement or repair of components with fugitive emissions detected during a monitoring 

survey, which should result in reductions of emissions from fugitive emissions components for 

those facilities. 

To (a) limit burden for subpart W facilities with well sites and compressor stations also 

subject to the fugitive emissions monitoring requirements in proposed NSPS subpart OOOOa 

and (b) provide an equipment leak survey option for calculating GHG emissions for other 

facilities subject to subpart W, the EPA is proposing to align the subpart W requirements with 

the fugitive emissions monitoring requirements in proposed NSPS subpart OOOOa. Specifically, 

the EPA is proposing to add the OGI monitoring method proposed in NSPS subpart OOOOa to 

subpart W. In addition, the EPA is proposing to add new leaker emission factors in subpart W for 

industry segments and/or components that currently do not have leaker emission factors so that 

the new monitoring data can be used when estimating GHG emissions in subpart W. 

One of the key objectives of this proposed rulemaking is to ensure that GHG emissions 

from all fugitive emissions components at facilities subject to subpart W that are also required to 

be monitored under proposed NSPS subpart OOOOa are reported under subpart W without 

imposing additional leak detection monitoring on reporters subject to both EPA programs. 

Historically, leak detection and repair programs have used EPA Method 21 to identify leaks by 

manually monitoring for elevated hydrocarbon concentrations at specific individual equipment 

components, such as valves, pumps, open-ended lines, connectors, flanges, and pressure relief 

valves (also referred to “traditional equipment components” within this document). These 

traditional equipment components are generally included in the existing leaker emission factors 

in subpart W. Optical gas imaging can be used to scan for leaks at much greater distances from 

the equipment components than EPA Method 21, and it may identify fugitive emissions that 

occur from sources other than equipment components. Examples of other sources of fugitive 

emissions include components such as agitator seals, distance pieces, crankcase vents, 

instruments, and meters (also referred to as “non-traditional components” within this document). 

While visible emissions from all of these fugitive emissions components would require 

identification and repair under the proposed NSPS subpart OOOOa, not all of these components 

have corresponding leaker emission factors in subpart W. The EPA is therefore considering 

leaker emission factors for additional components as well as expanding the components 

considered under the “other” category as needed for various industry segments:2

 

2

 For the subpart W Natural Gas Distribution industry segment, equipment leak emissions are determined using a 

combination of leak surveys and component counts multiplied by population emission factors. However, NSPS 

subpart OOOOa as proposed would not cover facilities in this industry segment; therefore, the subpart W Natural 

Gas Distribution industry segment is not discussed further in this section. 
4 

 Subpart W does not currently include leaker emission factors for Onshore Petroleum 

and Natural Gas Production and the Onshore Petroleum and Natural Gas Gathering 

and Boosting industry segments, so the EPA is proposing leaker emission factors for 

those subpart W industry segments. 

 The proposed NSPS subpart OOOOa requirements for onshore natural gas processing 

plants are based on a more traditional EPA Method 21 leak detection and repair 

program, and the only Onshore Natural Gas Processing component type that does not 

currently have a corresponding subpart W leaker emission factor is a pump. 

 For the Onshore Natural Gas Transmission Compression, Underground Natural Gas 

Storage, LNG Storage and LNG Import and Export Equipment industry segments, 

Table 1 shows a comparison of the fugitive emissions components proposed to be 

included in the proposed NSPS subpart OOOOa alongside the subpart W leaker 

emission factors and requirements. 
5 

Table 1. Comparison of Proposed NSPS Subpart OOOOa Fugitive Emissions Components 

and Current Subpart W Leaker Emission Factors for Select Industry Segmentsa

Proposed NSPS subpart 

OOOOa Fugitive Emissions 

Component Typeb

Subpart W Industry Segment and Service Type 

Onshore Natural Gas Transmission 

Compression 

Underground 

Natural Gas 

Storagec

LNG Storage; 

LNG Import and 

Export 

Equipment 

Compressor 

Components, 

Gas Service 

Non-Compressor 

Components, 

Gas Service 

Storage Station, 

Gas Service 

Components, 

LNG Serviced,e

Valves    

Connectors    

Pressure relief devices   

Open-ended lines   

Pump seals or diaphragms 

Meters   

Thief hatches or other 

openings on storage vessels 

f 

Compressors g g g

Flanges h h h 

Separators, Access doors, 

Closed vent systems, 

Agitator seals, Distance 

pieces, Crankcase vents, 

Blowdown vents, Pressure 

vessels, Dehydrators, 

Heaters, and Instruments 

 

a

 A dot in a row means that component type is covered by the equipment leak requirements in subpart W for the 

industry segment and service type indicated in that column. 

b

 Fugitive emissions components include these listed components but are not limited to these components. c

 Subpart W also has population factors for connectors, valves, pressure relief valves, and open-ended lines for 

storage wellheads in gas service 

d

 Subpart W also includes a leaker emission factor for “other” components in LNG service to be applied for any 

component type other than connectors, pumps, or valves. 

e

 Subpart W also includes a population emission factor for vapor recovery compressors in gas service but does not 

include emission factors for non-compressor components in gas service. 

f

 Emissions for this sources are already included in the current subpart W calculation methodology for transmission 

storage tanks. 

g

 Some compressor fugitive emissions are already included in the current subpart W calculation methodologies for 

reciprocating compressors and centrifugal compressors. 

h

 The Greenhouse Gas Reporting Program considers flanges to be a connector for purposes of the subpart W 

calculation requirements for these industry segments. 
6 

The remainder of this section documents the development of new leaker emission factors 

for those components that are not already required to report emissions in subpart W but are 

expected to be monitored for fugitive emissions based on the proposed requirements in NSPS 

subpart OOOOa. 

Data Sources Used Previously for Developing Leaker Emission Factors 

Onshore Petroleum and Natural Gas Production 

Subpart W does not currently include leaker emission factors for the Onshore Petroleum 

and Natural Gas Production segment, but the EPA previously developed leaker emission factors 

for equipment components in gas service and crude oil service in the production segment. In 

1995, the EPA published leaker emission factors for specific petroleum industry sectors, 

including oil and gas production, as well as a single set of leaker emission factors for equipment 

leaks for the entire petroleum industry in Protocol for Equipment Leak Emissions (EPA, 1995) 

(hereafter referred to as “the 1995 EPA Protocol”). These leaker emission factors are based on 

the “1993 petroleum industry data” compiled by the American Petroleum Institute and the Gas 

Research Institute (GRI), which includes fugitive hydrocarbon emissions data from onshore and 

offshore production sites (API, 1993b; API, 1995), gas plants, refineries (API, 1994), and 

marketing terminals (API, 1993a). Following is a summary of the methodology of the original 

1993 leak survey of production sites: 

 184,035 components were screened at 20 different production sites to develop new 

emission factors and correlation equations. 

 Productions sites included light crude production, heavy crude production, onshore 

gas production, and the Gulf of Mexico offshore. 

 Hydrocarbon vapor analyzers equipped with flame ionization detector were deployed 

for leak detection. 

 All readings greater than 10 ppmv were recorded. Fifteen percent of all components 

with fugitive emissions were bagged for measurement of mass emissions. All bagged 

samples were speciated into C1 through C6+ fractions and 25 percent of bagged 

samples were analyzed for aromatic air toxics. 

 For the purpose of developing “leak / no leak” emission factors, a “leaking” 

component was identified if the screening concentration value exceeded 10,000 

ppmv. 

The 1993 leak survey of production sites found that 90 percent of fugitive hydrocarbon 

emissions came from components with large leaks, which generally represented less than 

1 percent of installed components. The original survey found no evidence of statistical 

differences in emission factors among different regions of the country (API, 1993b). 
7 

The 1995 EPA Protocol published revised petroleum industry emission correlation 

equations and leaker emission factors, which are based on re-evaluation of the 1993 petroleum 

industry data plus additional leak survey data for gas production sites obtained by GRI. A few 

data pairs from the original 1993 petroleum industry data set were excluded due to large 

background concentrations or high screening value variability and the statistical analyses of the 

original data were revised. 

Emissions data used to develop leaker emission factors are impacted by the sensitivity of 

the screening method and the emissions concentration threshold defined for an equipment “leak.” 

In the 1995 EPA Protocol, petroleum industry equipment leaks are identified as exceeding a 

screening concentration threshold of 10,000 parts per million (ppm), which is generally the 

“pegged” concentration measurement of the screening instrument. Equipment with fugitive 

emissions that screened below 10,000 ppm were considered “non-leakers” for the purpose of 

determining leaker emission factors. For the Onshore Petroleum and Natural Gas Production 

segment, equipment components that screened at or above the 10,000 ppm threshold in the 

original 1993 petroleum industry data set were found to contribute 79 to 99 percent of mass 

emissions measured at gas production sites, 70 to 98 percent of mass emissions measured at oil 

productions sites; and 94 to 99 percent of mass emissions measured at gas plants (API, 1995).3

The 1995 EPA Protocol leaker emission factors for oil and gas production are 

summarized in Table 2. As seen in Table 2, leaker emission factors are available for different 

types of equipment that are typically included in an EPA Method 21-based leak detection 

program (“traditional equipment components”). While this includes an “other” category, this 

data set does not include as many “other” sources as can be seen leaking when using OGI. Note 

that the leaker emission factors provided in Table 2 are for total hydrocarbon emissions. The 

composition of whole gas at production sites would be expected to include non-hydrocarbon 

components, chiefly nitrogen (N2) and carbon dioxide (CO2). Gas composition data are needed to 

translate total hydrocarbon leaker emission factors to whole gas leaker emission factors or to 

methane leaker emission factors. 

 

3

 See Table 15, “Contribution of Each Screening Range to Average Emission Factors” (API, 1995). 
8 

Table 2. Existing Leaker Emission Factors Available for Onshore Oil and Gas Production 

from the 1995 EPA Protocol for Equipment Leak Emissions 

Service Equipment Type 

Leaker Emission Factors (Total Hydrocarbon)a

Oil & Gas Production 

≥10,000 ppm 

(kg/hr/source) 

≥10,000 ppm 

(lb/day/source) Sample Size 

Gas 

Valve 0.098 5.19 84 

Connector 0.026 1.38 24 

Flange 0.082 4.34 9 

Open-ended line 0.055 2.91 48 

Pump Seal 0.074 3.92b 12b

Otherc 0.089 4.71 11 

Light Oil 

Valve 0.087 4.60 51 

Connector 0.026 1.38 42 

Flange 0.073 3.86 13 

Open-ended line 0.044 2.33 39 

Pump Seal 0.100 5.29 1 

Otherc 0.083 4.39 19 

Heavy Oil 

Valve NA 1 

Connector NA 1 

Flange NA 1 

Open-ended line 0.030 1.59 13 

Pump Seal NA 0 

Otherc NA 11 

a

 Leaker emission factors in kilograms per hour per source (kg/hr/source) in as reported in Table 2-8 of the 1995 

EPA Protocol. Total hydrocarbon (or total organic compound) emissions include emissions of non-VOCs such as 

methane and ethane. Leaker emission factors in pounds per day per source (lb/day/source) are the factors in 

kg/hr/source multiplied by 2.20 pounds per kilogram and 24 hours per day. NA = not available. 

b

 No direct measurements for pumps in gas service were made. The 1995 EPA Protocol includes the overall leaker 

emission factor for petroleum industry pumps (including data from petroleum refineries and marketing terminals) 

from Table 2-14 of the 1995 EPA Protocol as the leaker emission factor for pumps in gas service for oil and gas 

production in Table 2-8 of the 1995 EPA Protocol. c

 “Other” equipment type were derived from compressors, diaphragms, drains, dump arms, hatches, instruments, 

meters, pressure relief valves, polished rods, relieve valves, and vents. The 1995 EPA Protocol indicates that the 

leaker emission factors for “other” should be used for any equipment type not otherwise listed. 

The 1993 fugitive emissions data and EPA’s 1995 analyses of leaker emission factors are 

the source for the average emission factors published in the 1996 EPA/GRI report, Methane 

Emissions from the Natural Gas Industry (EPA/GRI, 1996a; EPA/GRI, 1996b; EPA/GRI, 

1996c), as well as the default whole gas population emission factors currently in subpart W for 

the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas 

Gathering and Boosting industry segments. 
9 

Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, 

Underground Natural Gas Storage, LNG Storage and LNG Import and Export Equipment 

Leaker emission data for gas processing are available from two studies by Clearstone 

Engineering Ltd.: Identification and Evaluation of Opportunities to Reduce Methane Losses at 

Four Gas Processing Plants (Clearstone, 2002) and Cost-Effective Directed Inspection and 

Maintenance Control Opportunities at Five Gas Processing Plants and Upstream Gathering 

Compressor Stations and Well Sites (NGML et al., 2006). Gas transmission facility emissions 

data are available from the Handbook for Estimating Methane Emissions from Canadian Natural 

Gas Systems (Picard et al., 1998) and the Measurement of Natural Gas Emissions from the 

Canadian Natural Gas Transmission and Distribution Industry (Clearstone, 2007). Current

subpart W leaker emission factors for the Onshore Natural Gas Processing, Natural Gas 

Transmission Compression, and Underground Natural Gas Storage industry segments were 

derived from these four sources. Discussion of the leaker emission factor methodology and data 

sources are provided in the technical support document (EPA, 2010c) and supporting 

memoranda (EPA, 2010a; EPA, 2010b; EPA, 2010d) for the 2010 rule, Mandatory Reporting of 

Greenhouse Gases: Petroleum and Natural Gas Systems; Final Rule, November 2010. 

The primary leak detection and screening technique deployed for these studies was a 

modification of EPA Method 21. Bubble tests with soap solution were performed on the majority 

of traditional equipment components. Components found to be leaking by a soap bubble test 

were then screened using a portable hydrocarbon vapor analyzer. If the screening concentration 

was 10,000 ppm or greater, the component was identified as leaking. Acoustic and ultrasonic 

leak detectors were deployed at certain valves, flanged connections, and open-ended lines. A 

high-flow sampler was the primary method used to measure emissions from leaking equipment 

components; bagging and flow meters were used to measure emissions from most open-ended 

lines and vents. 

For the current subpart W leaker emission factors, equipment components were 

categorized as either compressor-related or non-compressor components. Once categorized, the 

sum of emission rates for the various leaking component types was divided by the total number 

of leaking components to obtain average leaker emission factors for each component type. 

Leaker emission factors from the transmission segment were combined with those from 

processing because the compressors used in both natural gas industry segments are comparable 

in size and discharge pressure. Applying the same rationale, leaker emission factors for 

compressor components in transmission and gas processing were also applied to compressorrelated components in underground natural gas storage. For LNG storage and LNG 

import/export terminals, current subpart W leaker emission factors are based on Table 2-7 of the 

1995 EPA Protocol, which presents leaker emission factors for petroleum marketing terminals. 
10 

New Fugitive Emissions Data Sources Available for Leaker Emission Factors 

Additional data from fugitive emissions surveys of equipment in the oil and gas industry 

have become available since 2010. These emissions data could potentially be used to derive new 

leaker emission factors for components not currently specified in subpart W. The emissions data 

from three studies listed below are available from public sources. These newer studies used OGI 

to identify leaking components and a high volume sampler to quantify mass emissions from the 

leaks.4

 City of Fort Worth Natural Gas Air Quality Study (ERG and Sage, 2011) (hereafter 

referred to as “the 2011 Fort Worth study”). This study measured fugitive gas 

emissions from 375 well pads, eight compressor stations, one gas processing plant, 

and one produced water treatment facility. Leak screening and measurement was 

performed using OGI and a high flow sampler. EPA Method 21 and bagging 

techniques were also performed on selected sources. All production facilities in the 

study are located in the Fort Worth Basin and are associated with gas production from 

the Barnett Shale. The source emissions calculation workbook (part of the study’s 

Appendix 3-B) was downloaded from the City of Fort Worth web site.5

 This data set 

contains a total of 91 methane emissions measurements from eight gathering and 

boosting compressor stations, including equipment components attached to 

compressors and components attached to other equipment associated with the facility. 

This data set also includes more than 1,200 methane emission measurements from 

equipment components associated with well pads. These data could be applied to 

derive leaker emission factors for the Onshore Petroleum and Natural Gas Production 

and Onshore Petroleum and Natural Gas Gathering and Boosting segments, taking 

into consideration the limited geographic scope of the data set. 

 Measurements of Methane Emissions at Natural Gas Production Sites in the United 

States, Supporting Information (Allen et al., 2013). For this study, 150 natural gas 

production sites were surveyed and leaks were detected at 97 sites. Equipment leaks 

were assessed at compressors, well heads, and equipment in four producing regions of 

the United States: Appalachia, Gulf Coast, Mid-Continent, and Rocky Mountains. 

Sites were screened with an infrared camera to identify leaks, and all observed leaks 

were measured with a high-flow sampler.6

 Emissions data are available from the web 

 

4

 Bacharach, Inc., headquartered in New Kensington, Pennsylvania, is the sole manufacturer of a commercial high 

flow sampler, distributed as the Bacharach Hi-Flow SamplerTM (http://www.mybacharach.com). Concerns have 

been raised that methane emissions reported in recent studies, including Allen et al. (2013) and the 2011 Fort Worth 

study, may be underestimated due to systematic sensor failure of the Bacharach Hi-Flow SamplerTM when methane 

content in the gas stream is less than 91 percent, the instrument is not sufficiently calibrated, and/or the instrument 

firmware is out dated (see Howard, 2015a; Howard, 2015b; and Howard, Ferrara, and Townsend-Small, 2015). 

Members of the research team that developed Allen et al. (2013) published a response to the concerns raised 

regarding some of their previous work (see Allen, Sullivan, and Harrison, 2015). 5

 Available at http://fortworthtexas.gov/gaswells/air-quality-study/final/. 6

 The threshold for detecting a leak with an infrared camera was 30 grams per hour (g/hr) (0.026 standard cubic feet 

per minute (scf/min)), consistent with the approved alternative work practices in 40 CFR 60.18. In practice, the 
11 

site of the Center for Energy and Environmental Resources at the University of 

Texas, Austin; the data include approximately 278 measurements of whole gas and 

methane emissions from leaks at production sites.7

 Methane Emissions from Natural Gas Compressor Stations in the Transmission and 

Storage Sector: Measurements and Comparisons with the EPA Greenhouse Gas 

Reporting Program Protocol (Subramanian et al., 2015). This study obtained 

equipment-level and site-level methane emissions from 47 compressor station sites in 

the transmission and storage segment, including direct measurements of fugitive and 

vented emissions. Leak detection was performed with OGI. The published study 

report provides an Excel file with supplemental information, which includes fugitive 

emissions for compressor components (attached to a compressor) and noncompressor components associated with other equipment at compressor stations. This 

data set provides 468 fugitive methane emissions measurements from 10 compressor 

station sites in the gas storage segment, and 898 fugitive methane emissions 

measurements from 37 transmission compressor stations. 

Leaker Emission Factor Options for Subpart W 

Due to differences in the monitoring methods, it is possible that the average emissions 

rate of a leak identified using EPA Method 21 may be different from the average emissions rate 

of a leak/fugitive emissions identified using OGI. Consequently, the EPA considered several 

options for providing leaker emission factors in subpart W for components subject to proposed 

NSPS subpart OOOOa fugitive emissions monitoring requirements. The new leaker emission 

factors are intended to be used with the results of leak surveys to report fugitive GHG emissions 

for equipment leaks under subpart W. 

 Option 1: Use leak data developed using EPA Method 21 to develop new leaker 

emission factors for traditional equipment components and non-traditional 

components where they are not yet available in subpart W (e.g., the Onshore 

Petroleum and Natural Gas Production segment, sources in the Natural Gas 

Transmission Compression segment that currently do not have subpart W leaker 

emission factors). The new leaker emission factors would be based on data sources 

that were used previously to develop the existing population emission factors in 

subpart W. 

 Option 2: Use leak data developed using EPA Method 21 to develop new leaker 

emission factors for traditional equipment components and use leak data from OGIbased emissions surveys to develop new leaker emission factors for non-traditional 

 

threshold for leak detection depends upon operator experience and skill in interpretation of the visual images, as 

well as site-specific parameters such as the visual background for the leak image. 7

 See Project Data sets for Allen (2013), available for download from Center for Energy and Environmental 

Resources, University of Texas, Austin. http://dept.ceer.utexas.edu/methane/study/datasets1.cfm. 
12 

components only. As noted previously, examples of non-traditional components 

include instruments, heaters, agitator seals, access doors, and blowdown vent fugitive 

emissions. 

 Option 3: Use leak data from OGI-based emissions surveys to develop new leaker 

emission factors in subpart W for all components (both traditional equipment 

components and non-traditional components) and for all industry segments covered in 

proposed NSPS subpart OOOOa. Under Option 3, new OGI-based emissions data 

from three recent fugitive emissions studies (i.e., the 2011 Fort Worth study, Allen et 

al. (2013), and Subramanian et al. (2015)) would be used to develop new leaker 

emission factors (consistent with OGI monitoring) for all fugitive emissions 

components covered in proposed NSPS subpart OOOOa. 

 Option 4: Use aggregate leak data from EPA Method 21- and OGI-based emissions 

surveys to develop new leaker emission factors in subpart W for all components (both 

traditional equipment components and non-traditional components) and for all 

industry segments covered in proposed NSPS subpart OOOOa. Under Option 4, the 

old EPA Method 21 leaker data would be combined with the new OGI-based 

emissions data for the appropriate industry segments to develop new leaker emission 

factors (using all available data) for all fugitive emissions components covered in 

proposed NSPS subpart OOOOa. 

Under Option 1, the proposed leaker emission factors would be derived from data for 

leaks identified using EPA Method 21. Under Option 2, some proposed leaker emission factors 

would be historical leaker emission factors based on an EPA Method 21 leak detection and 

monitoring program and some leaker emission factors would be derived from an OGI leak 

monitoring program. Under Option 3, the proposed leaker emission factors would be derived 

from data for leaks identified using OGI. Under Option 4, the proposed leaker emission factors 

would be derived from all available data, including leaks identified using EPA Method 21 and 

leaks identified using OGI. 

As part of the decision process to select one of the four leaker emission factor options, 

the EPA reviewed and evaluated the fugitive emissions data available in the three recent studies 

cited above. The first two studies (the 2011 Fort Worth study and Allen et al. (2013)) were 

specific to onshore natural gas production (but appear to have also included equipment 

characterized as part of the Onshore Petroleum and Natural Gas Gathering and Boosting segment 

in subpart W). We developed potential leaker emission factors for as many relevant components 

as possible. The potential “new” leaker emission factors (which are based on leak screening with 

OGI) were compared to the existing leaker emission factors available in the 1995 EPA Protocol. 

The emission rates measured for the three studies were each reported on a different basis (mass 

hydrocarbon, volume whole gas, and volume methane). In order to compare these values as 

directly as possible, we converted the reported emission factors from the 1995 EPA Protocol and 
13 

the 2011 Fort Worth study to whole gas emission factors. Default gas and oil compositions 

provided in Table 3 were used to perform this conversion (see Appendix A for more detail on 

default compositions). 

Table 3. Default Gas Composition from Oil and Natural Gas Production Wells 

Constituent 

Produced Gas (Gas Well) 

Volume Percenta

Associated Gas (Oil Well) 

Volume Percentb

Methane, C1 82.9c 63.4 

Ethane, C2 4.92 13.8 

Propane, C3 2.14 8.98 

Butanes, C4 0.99 4.35 

Pentanes, C5 0.22 1.45 

Hexanes+, C6+ 0.16 0.99 

CO2 3.9c 1.4 

N2 2.77d 4.0 

H2Se 2.0 1.0 

a

 From Table 8 of Composition of Natural Gas for Use in the Oil and Natural Gas Sector Rulemaking (Brown, 

2011) unless otherwise noted. 

b

 Estimated from the relative concentration in Table 8 of Brown (2011) excluding N2 and assuming N2 concentration 

in producing wells is 4 volume percent. 

c

 Average composition for lower 48 states from Inventory of U.S. GHG Emissions and Sinks: 1990-2013, Annex 3 

(EPA, 2015).

d

 Calculated by difference from the other concentrations used for produced gas. 

e

 H2S = hydrogen sulfide. 

Table 4 provides the comparison of the existing total hydrocarbon leaker emission factors 

for equipment in gas service at onshore natural gas production sites (from the 1995 EPA 

Protocol) with potential leaker emission factors derived from two OGI-based emissions surveys 

at onshore natural gas production sites. 
14 

Table 4. Comparison of Potential Leaker Emission Factors for Natural Gas Production 

Equipment 

Component 

1995 EPA Protocol: 

Table 2-8 & C-1 

Allen et al. (2013): Methane 

Emissions at Natural Gas 

Production Sites 

2011 Fort Worth Air 

Quality Study: 

Production Well Pads 

Total 

Hydrocarbon 

(&Whole Gas) 

Leaker Emission 

Factora (scf/hr/ 

component) 

Sample 

Size 

Whole Gas 

Leaker Emission 

Factorb (scf/hr/ 

component) 

Sample 

Size 

Methane 

(&Whole Gas)

Leaker 

Emission 

Factorb (scf/hr/ 

component) 

Sample 

Size 

Valve 4.5 (4.9) 84 7.6 32 10.1 (12.2) 87 

Connector 1.2 (1.3) 24 3.3 40 5.4 (6.5) 371 

Flange 3.8 (4.1) 9 9.6 11 11.9 (14.4) 8 

Open-ended Line 2.5 (2.8) 48 21.8 13 8.8 (10.6) 22 

Pressure Relief 

Valve 4.1 (4.5) 6 9.8 2 

Pump Seal 3.4 (3.7) 

Otherc 4.1 (4.5) 11 

Proposed NSPS Subpart OOOOa Components Not Specified in Subpart W Table W-1E: 

Blowdown Vent 4.1 (4.5) As “other” 7.8 3 

Crankcase Vent 4.1 (4.5) As “other” 8.3 2 

Heater 4.1 (4.5) As “other” 6.2 3 

Holes (Corrosion) 4.1 (4.5) As “other” 8.2 2 19.3 (23.3) 37 

Instrument (Gauges) 4.1 (4.5) As “other” 1.5 27 2.1 (2.5) 15 

Meter 4.1 (4.5) As “other” 1.6 2 9.4 (11.3) 14 

Plug 4.1 (4.5) As “other” 3.2 (3.9) 19 

Regulator 4.1 (4.5) As “other” 4.5 48 7.8 (9.4) 77 

a

 Leaker emission factor units converted from kilograms per hour (kg/hr) total hydrocarbon to standard cubic feet 

per hour (scf/hr) of total hydrocarbon and scf/hr of whole gas, in parentheses. Assumes an average composition 

for produced natural gas (see Table 3 and Appendix A of this memorandum). 

b

 Leaker emission factor applies to components not located on compressors or storage tanks. 

c

 “Other” equipment type is derived from compressors, diaphragms, drains, dump arms, hatches, instruments, 

meters, pressure relief valves, polished rods, relief valves and vents and should be applied to any equipment type 

other than connectors, flanges, open-ended lines, pumps or valves. 

As illustrated by the data in Table 4, Allen et al. (2013) and the 2011 Fort Worth study, 

which are recent OGI-based fugitive emissions studies, appear to yield higher leaker emission 

factors than the EPA Method 21-based data presented in the 1995 EPA Protocol. Note also that 

there are significant differences in the leaker emission factors developed from the two OGIbased studies. Except for open-ended lines, the 2011 Fort Worth study consistently yielded 

higher emission factors than Allen et al. (2013). In comparing the leaker emission factors in 

Table 4, it is important to note that there is significant variability in the mass emission rate from 
15 

individual leaks. Figure 1 shows a plot of the mass emissions rate as a function of the EPA 

Method 21 screening value. 

Figure 1. Emissions plot for valves in gas service for oil and gas production facilities 

(includes data from Table C-1-1 and C-2-1 of Appendix C in the 1995 EPA Protocol). 

As seen in Figure 1, the emissions from any one leaking component via EPA Method 21 

monitoring (i.e., points with a log screening value of 4 or more, or points to the right of the line 

marked “10,000 ppmv”) can differ by over a range of 3 to 4 orders of magnitude from another 

leaking component measured via EPA Method 21. The EPA conducted Monte Carlo analyses to 

‐7

‐6

‐5

‐4

‐3

‐2

‐1

0

1

0123456

Log10(Mass Emissions Rate, kg/hr)

Log10(Method 21 Screening Value)

Correlation Eqn Data

Pegged Data

Linear (Correlation Eqn Data)

10,000 ppmv leak

10 g/hr leak
16 

assess the impacts of this variability (see Appendix B of this memorandum for more 

information). Based on these analyses, random samples of 30 leaking components can expected 

to yield average leaker emission factors that vary by a factor of 2 to 3 and samples of 100 leaking 

components can expected to yield average leaker emission factors that vary by a factor 1.5 to 2. 

Therefore, even with a large number of measurements, there can still be significant uncertainty in 

the leaker emission factors developed from different data sets. 

While the precise level of fugitive emissions that can be identified using OGI is difficult 

to assess, as it may vary with both concentration and mass emissions rate, the proposed NSPS 

subpart OOOOa would require that the OGI instrument used must be able to detect fugitive 

emissions at 10,000 ppmv of half methane and half propane at a mass emissions rate of 60 grams 

per hour (g/hr) from a quarter-inch diameter orifice. A 60 g/hr leak rate is the maximum 

allowable detection level, so we assume that most OGI systems will have somewhat lower mass 

detection limits. Included in Figure 1 is a line showing leaks that are 10 g/hr. If OGI monitoring 

is only able to detect fugitive emissions (or leaks, for purposes of subpart W) with a mass 

emission rate of 10 g/hr or greater, regardless of concentration, it is evident that the average size 

of leaks above the red “10 g/hr leak” line will be larger than the average size of leaks to the right 

of the orange “10,000 ppmv leak” line. Thus, we expect that there may be differences in the 

average “leaker rate” due to the differences in the monitoring methods used to detect fugitive 

emissions, but we cannot necessarily conclude that the average leaker rates are different when 

the leaker rates are within the range of expected values, considering the variability in the mass 

emissions rate from individual leaking components. 

With this understanding, some specific points of comparison between the three studies by 

component type are provided below: 

 Valves. The number of measurements for all studies is reasonable. The variability in 

the derived leaker emission factors appears consistent with expectations for this 

sample size based on the Monte Carlo analysis. 

 Connectors. The number of measurements available from the 2011 Fort Worth study 

is far greater than the number of measurements available from the other two studies. 

The 2011 Fort Worth study and Allen et al. (2013) suggest a higher leaker emission 

rate than the 1995 EPA Protocol. 

 Flanges. The number of measurements is limited for all studies. The variability in the 

derived leaker emission factors appears consistent with expectations based on the 

Monte Carlo analysis. 

 Open-Ended Lines. The number of measurements available from the 1995 EPA 

Protocol is 2 to 4 times greater than for the 2011 Fort Worth study and Allen et al. 

(2013) study. The variability in the derived leaker emission factors appears consistent 

with expectations for these sample sizes based on the Monte Carlo analysis. 
17 

 Pressure Relief Valves. The number of measurements is limited for all studies. The 

variability in the derived leaker emission factors appears consistent with expectations 

for these sample sizes based on the Monte Carlo analysis. 

 Pump Seals. The number of measurements is limited or non-existent for all studies. 

The leaker emission factor for pump seals is based on all petroleum sources 

considered in the 1995 EPA Protocol. 

 Other. The average “other” emission factor from Allen et al. (2013) is 3.8 kg whole 

gas/hr/component. The average “other” emission factor from the 2011 Fort Worth 

study is higher at 11.5 kg whole gas/hr/component. The number of measurements for 

“other” components is much larger for the OGI-based studies than in the 1995 EPA 

Protocol and includes non-traditional components such as holes from corrosion that 

would not be included or identified when monitoring using EPA Method 21. The 

variability between the average mass leaker emission factor for all “other” 

components between the two OGI-based studies is larger than expected based on the 

sample size, but OGI-based study average values compare reasonably well with the 

1995 EPA Protocol leaker emission factor for “other” components considering the 

limited number of “other” components for which measurements were made in the 

1995 EPA Protocol. 

Subramanian et al. (2015) provided a graphical comparison of the average leak size 

measured using OGI compared to the Onshore Natural Gas Transmission Compression leaker 

emission factors in Table W-3 of subpart W. This comparison is provided in Figure 2. Figure 2 

includes the number of leaking components measured by Subramanian et al. (2015); Table 5 

provides a comparison of the number of leaks measured for the current subpart W leaker 

emission factors (Clearstone, 2002 and 2007) and the number measured by Subramanian et al. 

(2015). 

Table 5. Comparison of Number of Leaks Measured at Natural Gas Processing and 

Transmission Compression Facilities 

Equipment in Gas 

Service 

Number Compressor Components 

Measured 

Number of Non-Compressor 

Components Measured 

Clearstone 

(2002, 2007) 

Subramanian et al. 

(2015)

Clearstone 

(2002, 2007) 

Subramanian et 

al. (2015) 

Valve 1,499 252 1,364 135 

Connector 1,862 290 1,004 219 

Open-ended Line 166 97 192 38 

Pressure Relief Valve 60 5 9 8 

Meter 14 2 18 1 
18 

Figure 2. Comparison of leaker emission factors from Subramanian et al. (2015) and 

Table W-3 of subpart W for the Onshore Natural Gas Transmission Compression industry 

segment (figure taken from Subramanian et al. (2015)). 

Some specific points of comparison between the OGI-based study (Subramanian et al., 

2015) and the EPA Method 21-based study (Clearstone, 2002; Clearstone 2007) by component 

type are provided below: 

 Valves. Over 1,000 measurements were made for the current subpart W leaker 

emission factors for valves, while the number of measurements made for the OGI 

study is in the low hundreds. There is good agreement for valves on compressor 

components, but less agreement for non-compressor valves. The OGI-based study 

does not show a significant difference in the valve leak rates between compressor and 

non-compressor components as seen in the subpart W leaker emission factors from 

the EPA Method 21-based study. The variability in the derived leaker emission 

factors for valves appears consistent with expectations for compressor valves but is 

slightly larger than expected for non-compressor valves based on the sample size and 

the Monte Carlo analysis (see Appendix B of this memorandum). 
19 

 Connectors. The number of measurements is large for the current subpart W leaker 

emission factor and significant for the OGI study. As with the Onshore Petroleum and 

Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and 

Boosting segments, connectors is one component where the data available from 

Subramanian et al. (2015) suggest a higher leaker emission rate than Clearstone 

(2002) and Clearstone (2007). 

 Open-Ended Lines. The number of measurements is reasonable for both the current 

subpart W leaker emission factor and the OGI study. The resulting leaker emission 

factors from the OGI-based study are higher than the EPA Method 21-based study. 

The variability in the derived leaker emission factors for the non-compressor openended lines appears consistent with expectations based on the Monte Carlo analysis 

considering that there are only 38 OGI-based measurements; however, the OGI-based 

leaker emission factor from Subramanian et al. (2015) for compressor open-ended 

lines appears to be larger than the subpart W leaker emission factor considering the 

sample size and the Monte Carlo analysis. 

 Pressure Relief Valves. The number of measurements is less than 10 for Subramanian 

et al. (2015). The number of measurements of non-compressor pressure relief valves 

in the Clearstone studies (2002 and 2007) is also less than 10, but 60 measurements 

are available for compressor component pressure relief valves. The variability in the 

derived leaker emission factors appears consistent with expectations for the small 

sample size based on the Monte Carlo analysis. 

 Meters. The number of measurements is limited for all studies. The variability in the 

derived leaker emission factors appears consistent with expectations for this sample 

size based on the Monte Carlo analysis. 

The discussion above illustrates considerations for implementing leaker emission factors 

in subpart W that are derived from recent OGI-based emissions surveys. These include: 

 Converting between total hydrocarbon, methane, and whole gas. Whole gas 

composition and speciation of total hydrocarbon must be known or estimated to 

convert between total hydrocarbon, whole gas, and methane leaker emission factors. 

When study data report emissions in different units of measure, additional uncertainty 

is added when assumptions are needed to convert the reported emissions to 

comparable units of measure. 

 Differences between studies in such aspects as equipment component categories, 

equipment descriptions, and mass emissions measurement methodology. Such 

differences introduce uncertainty in accurately grouping emissions data according to 

equipment or component categories to derive emission factors and comparing 

component-specific average emission factors between studies. 
20 

 EPA Method 21 and OGI methods have different threshold criteria for identifying 

leaking equipment. For the 1995 EPA Protocol, leaker emission factors were 

developed based on equipment components surveyed with a hand-held hydrocarbon 

analyzer and those with screening values of 10,000 ppmv or greater were identified as 

“leaking.” For OGI methods, a leaking component (or a component with fugitive 

emissions) is identified by a visible gas plume using the gas imaging instrument. The 

typical minimum detection limit requirement for OGI is about 60 g/hr.8 While OGI 

visualization is not solely a function of mass emissions rate, mass emissions rate is 

nonetheless expected to be a significant factor in OGI leak visualization, and as seen 

in Figure 1, it is possible that the leaks detected by the two methods could have 

different distributions. 

 Sample size. It is important to be cognizant of the variability in the mass emissions 

from individual leaks and to ensure that there are a sufficient number of 

measurements for any given fugitive emissions component in order to develop a 

robust and accurate leaker emission factor for that component. 

Leaker Emission Factors Proposed for Subpart W 

Upon consideration of the comparisons and issues noted above, the EPA decided to 

implement Option 1 described above for the reasons described in the preamble to the proposed 

rule. The leaker emission factors from the 1995 EPA Protocol are straightforward to apply 

because the component categories are well-defined and readily identified across the full range of 

oil and gas operations. Leaks or fugitive emissions detected from components that are not 

uniquely specified are simply assigned the leaker emission factor for “other” equipment 

components. There is uncertainty in applying the “other” leaker emission factors developed in 

the 1995 EPA Protocol to the larger array of “other” fugitive emissions components that can be 

identified using OGI leak detection and monitoring, but the average leaker emission factor for 

“other” components in the 1995 EPA Protocol compares well with the aggregated average leaker 

emission factor for “other” components measured in Allen et al. (2013). 

Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas 

Gathering and Boosting 

Whole gas leaker emission factors are proposed for the Onshore Petroleum and Natural 

Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting segments based 

on the existing total hydrocarbon leaker emission factors for oil and gas production from the 

1995 EPA Protocol. The units of the leaker emission factors in the 1995 EPA Protocol are 

kilograms per hour (kg/hr) of total hydrocarbon per source. Two key pieces of data are needed to 

 

8

 The EPA’s alternative work practice at 40 CFR 60.18(g) and 63.11(c) specifies different monitoring frequencies 

for leak detection levels between 60 and 100 g/hr. The proposed minimum detection limit for the OGI-based survey 

in proposed NSPS subpart OOOOa is 60 g/hr. 
21 

convert total hydrocarbon leaker emission factors to whole gas leaker emission factors: the 

speciation of total hydrocarbon emissions and the composition of whole gas. The default 

compositions used to convert the total hydrocarbon leaker emission factors were presented 

previously in Table 3 of this memorandum. Appendix A provides additional detail regarding the 

source of these default compositions and the calculations used to convert the total hydrocarbon 

emission factors to whole gas and methane emission factors. 

Table 6 summarizes the leaker emission factors proposed for equipment components in 

gas service. Table 6 shows the original total hydrocarbon leaker emission factor from the 1995 

EPA Protocol in units of kg/hr and the leaker emission factor converted to units of standard 

cubic feet per hour (scf/hr) total hydrocarbon, methane, and whole gas. 

Table 6. Total Hydrocarbon, Methane, and Whole Gas Leaker Emission Factors for 

Equipment in Gas Service for the Onshore Petroleum and Natural Gas Production and 

Onshore Petroleum and Natural Gas Gathering and Boosting Segments 

Leaker Emission 

Factors – 

Equipment in 

Gas Service 

Total 

Hydrocarbon,a

kg/hr 

Total 

Hydrocarbon, 

scf/hr

Methane, 

kg/hr 

Methane,b

scf/hr 

Whole Gas,b

scf/hr 

Valve 0.098 4.5 0.079 4.1 4.9 

Connector 0.026 1.2 0.021 1.1 1.3 

Flange 0.082 3.8 0.066 3.4 4.1 

Open-ended Line 0.055 2.5 0.044 2.3 2.8 

Pump Seal 0.074 3.4 0.059 3.1 3.7 

Other 0.089 4.1 0.071 3.7 4.5 

a Source is the 1995 EPA Protocol. b

 Assumes methane weight fraction in total hydrocarbon = 0.801; assumes methane volume fraction in whole gas = 

0.829; total volume fraction of non-hydrocarbons in whole gas (CO2, N2 & hydrogen sulfide (H2S)) = 0.087. 

Table 7 summarizes leaker emission factors proposed for equipment components in light 

crude oil service and heavy crude oil service. As reported in the 1995 EPA Protocol and shown 

in Table 2, open-ended lines were the only components in heavy liquid service found to have 

leaks greater than 10,000 ppmv as measured using EPA Method 21. Given the similarities in the 

leaker emission factors between gas and light oil service, it is reasonable to expect that leaks 

from components in heavy oil service that do exceed the 10,000 ppmv leak threshold would have 

emissions similar to those in gas or light liquid service. Therefore, whole gas leaker emission 

factors developed from the 1995 EPA Protocol for components in light oil service are also 

proposed as whole gas leaker emission factors for components in heavy oil service. Table 7 

shows the original total hydrocarbon leaker emission factors in units of kg/hr total hydrocarbon 

and the leaker factors converted to units of scf/hr total hydrocarbon, methane, and whole gas. 
22 

Table 7. Total Hydrocarbon, Methane, and Whole Gas Leaker Emission Factors for 

Equipment in Crude Oil Service for the Onshore Production and Gathering and Boosting 

Segments 

Leaker Emission Factors – 

Equipment in Light Crude 

& Heavy Crude Oil Service 

Total 

Hydrocarbon,a

kg/hr 

Total 

Hydrocarbon, 

scf/hr 

Methane, 

kg/hr 

Methane,b

scf/hr 

Whole 

Gas,b scf/hr 

Valve 0.087 3.0 0.039 2.0 3.2 

Connector 0.026 0.9 0.012 0.6 1.0 

Flange 0.073 2.5 0.033 1.7 2.7 

Open-ended Line 0.044 1.5 0.020 1.0 1.6 

Pump Seal 0.10 3.4 0.045 2.3 3.7 

Other 0.083 2.8 0.037 1.9 3.1 

a Source is the 1995 EPA Protocol. 

b

 Assumes methane weight fraction in total hydrocarbon = 0.448; assumes methane volume fraction in whole gas = 

0.634; total volume fraction of non-hydrocarbons in whole gas (CO2, N2 & H2S = hydrogen sulfide (H2S)) = 

0.063. 

Other Industry Segments 

For the Onshore Natural Gas Processing, Onshore Natural Gas Transmission 

Compression, Underground Natural Gas Storage, LNG Storage and LNG Import and Export 

Equipment industry segments, subpart W currently includes leaker emission factors for selected 

equipment components. The proposed rule provides leaker emission factors for additional 

components and expands the components considered under the “other” category to include the 

additional equipment components specified in the proposed NSPS subpart OOOOa definition of 

“fugitive emissions component.” 

Based on our analyses and comparisons of EPA Method 21-based studies to OGI-based 

study data, where available, we concluded that it was reasonable to use EPA Method 21-based 

leaker emission factors for specific additional equipment components, such as pumps and 

flanges. In most cases, this conclusion led us to expand the applicability of an existing leaker 

emission factor in subpart W (e.g., for Onshore Natural Gas Transmission Compression, the 

leaker emission factor for connectors would also apply to flanges). 

For the LNG Storage and LNG Import and Export Equipment industry segments, the 

source for current leaker emission factors in Tables W-5 and W-6 is the 1995 EPA Protocol, 

Table 2-7 (screening range ≥ 10,000 ppmv). However, the 1995 EPA Protocol only includes 

emission factors for connectors and flanges in gas service. The Inventory of U.S. Greenhouse 

Gas Emissions and Sinks: 1990 – 2013 (EPA, 2015) uses identical population emission factors 

for natural gas storage compressor stations as for LNG stations at LNG Storage and LNG Import 
23 

Terminals,9 suggesting that the equipment and emissions are expected to be similar for these 

three sources. We also note that the leaker emission factors in subpart W for equipment in gas 

service at Underground Natural Gas Storage stations are identical to the leaker emission factors 

for compressor components in gas service for Onshore Natural Gas Processing plants and 

Onshore Natural Gas Transmission Compression facilities, suggesting that leaks from 

compressor components in gas service in the Onshore Natural Gas Processing segment and 

segments downstream are similar in magnitude. Therefore, the leaker emission factors for 

storage station components in gas service in Table W-4 (for the Underground Natural Gas 

Storage industry segment) were applied to the LNG Storage and LNG Import and Export 

Equipment industry segments. For these segments, the gas and LNG streams are considered to be 

100 percent methane, so the total hydrocarbon leaker emission factors are equal to the methane 

emission factors. 

Similarly, based on our analyses and consistent with the conclusion for the Onshore 

Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and 

Boosting industry segments to use the leaker emission factors developed from EPA Method 21-

based studies for the “other” category where OGI-based study data were available, we concluded 

that it was reasonable to use the EPA Method 21-based leaker emission factors from the 1995 

EPA Protocol for all fugitive emission components that would be classified in the “other” 

category for these industry segments. Given the uncertainty around leaker emission factors, we 

concluded that even if parameters such as gas composition and total hydrocarbon speciation are 

not readily available for a particular industry segment, average leaker emission factors for the 

category of “other” components in that industry segment can be approximated by the leaker 

emission factor for “other” components in gas service for the Onshore Petroleum and Natural 

Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting segments. 

Summary of all Proposed Leaker Emission Factors 

Table 8 summarizes the data sources and assumptions for the new proposed leaker 

emission factors for all segments. Table 9 summarizes the whole gas leaker emission factors for 

Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas 

Gathering and Boosting. Table 10 summarizes the new total hydrocarbon leaker emission factors 

for the Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression, and 

Underground Natural Gas Storage industry segments. Table 11 summarizes the new methane 

leaker emission factors for the LNG Storage, and LNG Import and Export Equipment industry 

segments. 

 

9 See Annex 3, Table A-137: “2013 Data and CH4 Emissions (Mg) for the Natural Gas Transmission Stage” (EPA, 

2015).
24 

Table 8. Summary of Development of New Leaker Emission Factors for Subpart W 

Industry Segment(s) New Leaker Emission Factor(s) Leaker Emission Factor(s) Source 

Onshore Petroleum 

and Natural Gas 

Production and 

Onshore Petroleum 

and Natural Gas 

Gathering and 

Boosting 

(Table W-1E) 

 “Valve,” “flange,” “connector,” 

“open-ended line,” “pressure relief 

valve,” “pump seal,” and “other” 

components in gas service 

 “Valve,” “flange,” “connector,” 

“open-ended line,” “pump,” 

“agitator seal,” and “other” 

components in light crude service 

 “Valve,” “flange,” “connector,” 

“open-ended line,” “pump,” 

“agitator seal,” and “other” 

components in heavy crude service 

Converted 1995 EPA Protocol, Table 2-8, Oil 

and Gas Production Operations Screening 

Ranges Emission Factors, for equipment in gas 

service and light liquid service for screening 

range ≥ 10,000 ppmv from kg/hr total 

hydrocarbon to scf/hr whole gas factors using 

default compositions in Table 3 of this 

memorandum. See also Table 6, Table 7, and 

Appendix A of this memorandum 

Onshore Natural Gas 

Processing 

(Table W-2) 

“Pump” in gas service Assumed to be the same as the total hydrocarbon 

factor for pumps in gas service developed for 

Onshore Petroleum and Natural Gas Production; 

see Table 6 and Appendix A of this 

memorandum

Natural Gas 

Transmission 

Compression 

(Table W-3) 

“Flange” in gas service Assumed to equal the factor for “connector” in 

gas service in Table W-3 

“Instrument” in gas service Assumed to equal the factor for “meter” in gas 

service in Table W-3 

“Other” components in gas service Assumed to be the same as the total hydrocarbon 

factor for “other” components in gas service 

developed for Onshore Petroleum and Natural 

Gas Production; see Table 6 and Appendix A of 

this memorandum 

Underground Natural 

Gas: Storage Stations 

(Table W-4) 

“Flange” in gas service Assumed to equal the factor for “connector” in 

gas service in Table W-4 

“Instrument” in gas service Assumed to equal the factor for “meter” in gas 

service in Table W-4 

“Other” components in gas service Assumed to be the same as the total hydrocarbon 

factor for “other” components in gas service 

developed for Onshore Petroleum and Natural 

Gas Production; see Table 6 and Appendix A of 

this memorandum 

Underground Natural 

Gas Storage 

Wellheads 

(Table W-4) 

“Valve,” “connector,” “flange,” and 

“open-ended line” in gas service 

Assumed to be the same as the total hydrocarbon 

factors for these specific equipment types in gas 

service developed for Onshore Petroleum and 

Natural Gas Production; see Table 6 and 

Appendix A of this memorandum

“Pressure relief valve” and “other” 

components in gas service 

Assumed to be the same as the total hydrocarbon 

factor for “other” components in gas service 

developed for Onshore Petroleum and Natural 

Gas Production; see Table 6 and Appendix A of 

this memorandum 
25 

Industry Segment(s) New Leaker Emission Factor(s) Leaker Emission Factor(s) Source 

LNG Storage and 

LNG Import and 

Export Equipment 

Terminals 

(Tables W-5 and W-6) 

“Valve,” “connector,” “flange,” 

“open-ended line,” “pressure relief 

valve,” “meter and instrument” and 

“other” components in gas service 

Assumed to be the same as the total hydrocarbon 

factors for storage station components in gas 

service in Table W-4 (For these segments, the 

gas and LNG streams are considered to be 100 

percent methane, so the total hydrocarbon leaker 

emission factors are equal to the methane 

emission factors.) 

Table 9. Summary of Methane and Whole Gas Leaker Emission Factors for Onshore 

Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas 

Gathering and Boosting 

Service Equipment Component 

Methane Leaker Emission 

Factor (scf/hour/component) 

Whole Gas Leaker Emission 

Factor (scf/hour/component) 

Gas Valve 4.1 4.9 

Flange 3.4 4.1 

Connector 1.1 1.3 

Open-Ended Line 2.3 2.8 

Pressure Relief Valve 3.7 4.5 

Pump seal 3.1 3.7 

Other 3.7 4.5 

Light Crude Valve 2.0 3.2 

Flange 1.7 2.7 

Connector 0.61 1.0 

Open-Ended Line 1.0 1.6 

Pump 2.3 3.7 

Agitator Seal 2.3 3.7 

Other 1.9 3.1 

Heavy Crude Valve 2.0 3.2 

Flange 1.7 2.7 

Connector 0.61 1.0 

Open-Ended Line 1.0 1.6 

Pump 2.3 3.7 

Agitator Seal 2.3 3.7 

Other 1.9 3.1 
26 

Table 10. Summary of New Total Hydrocarbon Leaker Emission Factors for Various 

Subpart W Industry Segments 

Industry Segment Service Equipment Component 

Leaker Emission Factor 

(scf/hour/component) 

Onshore Natural Gas 

Processing 

Gas; Non-compressor 

components 

Pump 3.4 

Natural Gas Transmission 

Compression 

Gas; Compressor 

components 

Flange 5.59 

Meter or Instrument 19.33 

Other 4.1 

Gas; Non-compressor 

components 

Flange 5.71 

Meter or Instrument 2.93 

Other 4.1 

Underground Natural Gas 

Storage 

Gas; Storage stations Flange 5.59 

Meter or Instrument 19.33 

Other 4.1 

Gas; Storage Wellheads Valve 4.5 

Connector 1.2 

Flange 3.8 

Open-ended Line 2.5 

Pressure Relief Valve 4.1 

Other 4.1 

Table 11. Summary of New Methane Leaker Emission Factors for LNG Storage and LNG 

Import and Export Equipment 

Service Equipment Component 

Leaker Emission Factor 

(scf/hour/component) 

Gas Valve 14.84 

Connector 5.59 

Flange 5.59 

Open-Ended Line 17.27 

Pressure Relief Valve 39.66 

Meter or Instrument 19.33 

Other 4.1 

 
27 

References 

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Emissions from Process Equipment at Natural Gas Production Sites in the United States: 

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3984. March 3, 2015. 

Allen, D.T., V.M. Torres, J. Thomas, D.W. Sullivan, M. Harrison, A. Hendler, S.C. Herndon, 

C.E. Kolb, M.P. Fraser, A.D. Hill, B.K. Lamb, J. Miskimins, R.F. Sawyer, and J.H. 

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0006. 

API (American Petroleum Institute). 1993a. Development of Fugitive Emission Factors and 

Emission Profiles for Petroleum Marketing Terminals. Publications 4588 (Vol. 1: Text) 

and 45881 (Vol. 2: Appendices). Prepared by Radian Corporation. May 1993. 

API (American Petroleum Institute). 1993b. Fugitive Hydrocarbon Emissions from Oil and Gas 

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API (American Petroleum Institute). 1994. Study of Refinery Fugitive Emissions from Equipment 

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by Radian Corporation. April 1994. 

API (American Petroleum Institute). 1995. Emission Factors for Oil and Gas Production 

Operations. Publication 4615. January 1995. 

Brown, H.P. 2011. Composition of Natural Gas for use in the Oil and Natural Gas Sector 

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28 

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0923-3588. 

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Production Sites in the United States: Pneumatic Controllers.’” Environmental Science & 

Technology, Vol. 49, No. 6, pp. 3981-3982. March 3, 2015. 

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Vol. 49, no. 5, pp. 3252-3261. http://pubs.acs.org/doi/abs/10.1021/es5060258. 
A-1 

Appendix A 

Whole Gas Leaker Emission Factors for Onshore Production and Gathering 

and Boosting – Methodology and Assumptions 

Whole gas leaker emission factors for the onshore production and gathering and boosting 

segments were derived from the total hydrocarbon leaker emission factors for oil and gas 

production published in the 1995 EPA Protocol. The original leaker emission factors are for 

mass emissions of total hydrocarbon expressed in units of kg/hr. The proposed whole gas leaker 

emission factors are expressed in volume units of scf/hr. This appendix describes the method 

used to convert leaker emission factors for mass emissions of total hydrocarbon to leaker 

emission factors for volumetric emissions of total hydrocarbon. This appendix also describes the 

method used to calculate leaker emission factors for volumetric emissions of whole gas and 

methane from the leaker emission factors for mass emissions of total hydrocarbon. 

Step 1. Assume gas compositions for produced gas from gas wells and associated gas 

from oil wells, which include speciation of total hydrocarbons in the gas. Table A-1 shows the 

gas compositions assumed for produced gas and associated gas (natural gas co-produced with 

oil). Gas composition expressed as mole percent (volume percent) was converted to gas 

composition by weight by multiplying the mole percent of each gas constituent by its molecular 

weight. 
A-2 

Table A-1. Average Gas Composition from Producing Gas Wells and Oil Wells 

Completions for Onshore, L-48 States (Mole Percent)a

Average Gas Composition Produced Gas from Gas Wells Associated Gas from Oil Wells 

Constituent 

Molecular Wt. 

(kg/kg-mol) Mole Percentb

Relative Mass 

Contribution (kg 

for 100 kg-mol) 

Mole 

Percentc

Relative Mass 

Contribution (kg 

for 100 kg-mol) 

Methane, C1 16.043 82.9c 1329.96 63.4 1016.96 

Ethane, C2 30.070 4.92 147.94 13.8 414.84 

Propane, C3 44.097 2.14 94.37 8.98 396.00 

Butanes, C4 58.124 0.99 57.54 4.35 252.57 

Pentanes, C5 72.000 0.22 15.84 1.45 104.28 

Hexanes+, C6+ 86.000 0.16 13.76 0.99 84.85 

CO2 44.010 3.9d 171.64 1.4 61.61 

N2 28.013 2.77e 77.6 4.0 112.05 

H2Sf 34.081 2.0 68.16 1.0 34.08 

Total Hydrocarbon 1659.42 2477.25 

Whole Gas 1976.82 2269.50 

a

 kg/kg-mol = kilogram per kilogram-mole. 

b

 From Table 8 of Composition of Natural Gas for Use in the Oil and Natural Gas Sector Rulemaking (Brown, 

2011) unless otherwise noted. 

c

 Estimated from the relative concentration in Table 8 of Brown (2011) excluding N2 and assuming N2 concentration 

in producing wells is 4 volume percent. 

d

 Average composition for lower 48 states from Inventory of U.S. GHG Emissions and Sinks: 1990-2013, Annex 3 

(EPA, 2015). 

e

 Calculated by difference from the other concentrations used for produced gas. 

f

 H2S = hydrogen sulfide. 

The starting point for estimating average gas compositions is the memorandum 

Composition of Natural Gas for use in the Oil and Natural Gas Sector Rulemaking (Brown, 

2011). Table 8 of this document provides useful speciation of total hydrocarbon for gas and oil 

well completions. For the present leaker emission factor analysis, the non-hydrocarbon 

components of whole gas shown in Table 8 of Brown (2011) were adjusted so that the average 

gas compositions assumed in Table A-1 correspond more closely to other data sources for 

national average gas composition. Examples of other sources for average gas composition 

include the Natural Gas Supply Association and the Oil and Gas Journal, which provide typical 

compositions of natural gas before processing, as shown in Table A-2. Other analyses of the 

composition of associated gas indicate that N2 content may range between 2.0 and 4.5 mole 

percent (Burruss and Ryder, 2004). In addition, the Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2013 assumes a methane content of natural gas in the production sector of 
A-3 

82.9 percent (for general sources, Lower-48 states)10 and an average CO2 content of produced 

natural gas of 3.5 percent (EPA, 2015).11

Table A-2. Typical Composition of Natural Gas before Processing 

Constituent Produced Gas, Volume Percenta Associated Gas, Volume Percentb

Methane 70 – 90 68 

Ethane 

0 – 20 

15 

Propane 9 

Butane 5 

CO2 0 – 8 1 

O2 0 – 0.2 1 

N2 0 – 5 

H2Sc 0 – 5 

Rare Gas Trace 

a

 Source: NGSA, 2013. NaturalGas.org is presented by the Natural Gas Supply Association to provide a 

comprehensive information source for topics related to natural gas. 

b

 Source: Table 2, “Typical Natural Gas Compositions, Mole %” (Farry, 1998). 

c

 H2S = hydrogen sulfide. 

Step 2. Compute the weight fraction of total hydrocarbon for each gas constituent and 

the weight fraction of whole gas for each gas constituent. The molecular weights of gas 

constituents in Table A-1 were divided by the molecular weight of total hydrocarbon emissions 

(provided in Table A-1), or by the total molecular weight of whole gas (provided in Table A-1). 

The computed weight fractions of gas constituents are shown in Table A-3. 

 

10 See Annex 3, Table A-139: “Production Sector Methane Content in Natural Gas by NEMS Region” (EPA, 2015). 11 See Annex 3, Table A-150: “Production Sector CO2 Content in Natural Gas by NEMS Region” (EPA, 2015). 
A-4 

Table A-3. Computed Weight Percent of Gas Constituents in Total Hydrocarbon and 

Whole Gas 

Constituenta

Produced Gas - Gas Wells Associated Gas – Oil Wells 

Whole Gas, Weight 

Percent 

Total Hydrocarbon, 

Weight Percent 

Whole Gas, Weight 

Percent 

Total Hydrocarbon, 

Weight Percent 

Methane, C1 67.3 80.1 41.0 44.8 

Ethane, C2 7.5 8.9 16.8 18.3 

Propane, C3 4.8 5.7 16.0 17.4 

Butanes, C4 2.9 3.5 10.2 11.1 

Pentanes, C5 0.8 1.0 4.2 4.6 

Hexanes+, C6+ 0.7 0.8 3.4 3.7 

CO2 8.7 2.5 

N2 3.9 4.5 

H2S 3.4 1.4 

a

 H2S = hydrogen sulfide. 

Step 3. Compute molecular weight of total hydrocarbon emissions and leaker emission

factor conversion from kg/hr to scf/hr total hydrocarbon. The molecular weight of total 

hydrocarbon emissions was computed from the speciation of total hydrocarbon emissions, now 

expressed as weight percent of total hydrocarbon in Table A-3. This was done by dividing the 

weight fraction of each total hydrocarbon constituent by its molecular weight. The resulting 

values (in units of kilogram-moles per kilogram (kg-mol/kg) total hydrocarbon) were summed. 

The reciprocal is the molecular weight of the total hydrocarbon emissions in units of kilograms 

per kilogram-mole (kg/kg-mol). This value was divided by the molar volume conversion factor 

of 836.6 standard cubic feet per kilogram mole (scf/kg-mol) at standard conditions of 60 

°Fahrenheit and 1 atmosphere to produce a total hydrocarbon conversion factor in units of 

kilograms per standard cubic foot (kg/scf). The total hydrocarbon conversion factor can also be 

expressed as standard cubic feet per kilogram (scf/kg) total hydrocarbon. The computation of the 

leaker emission factor conversion for produced gas from gas wells and associated gas from oil 

wells is summarized in Table A-4. The leaker emission factors in units of scf/hr total 

hydrocarbon are summarized in Table A-5. 
A-5 

Table A-4. Molecular Weight of Total Hydrocarbon Emissions and Leaker Emission 

Factor Conversion to scf/hr of Total Hydrocarbon 

Total Hydrocarbon Composition Produced Gas - Gas Wells Associated Gas – Oil Wells 

Constituent 

Molecular Wt. 

(kg/kg-mol) 

Wt. Fraction 

of Total 

Hydrocarbon 

Moles per 1 kg 

of Total 

Hydrocarbon 

(kg-mol/kg) 

Wt. Fraction 

of Total 

Hydrocarbon 

Moles per 1 kg 

of Total 

Hydrocarbon 

(kg-mol/kg) 

Methane, C1 16.043 0.801 4.993 E-2 0.448 2.792 E-2 

Ethane, C2 30.070 0.089 2.960 E-3 0.183 6.086 E-3 

Propane, C3 44.097 0.057 1.293 E-3 0.174 3.946 E-3 

Butanes, C4 58.124 0.035 6.022 E-4 0.111 1.910 E-3 

Pentanes, C5 72.000 0.010 1.389 E-4 0.046 6.389 E-4 

Hexanes+, C6+ 86.000 0.008 9.302 E-5 0.037 4.302 E-4 

Cumulative mole per 1 kg Total Hydrocarbon (kg-mol/kg) 5.501 E-2 4.094 E-2 

Average Molecular Weight of Total Hydrocarbon (kg/kg-mol) 18.177 24.429 

Molar Volume Conversion (scf/kg-mol) 836.6 836.6 

Total Hydrocarbon Conversion Factor (kg/scf) 0.0217 0.0292 

Total Hydrocarbon Conversion Factor (scf/kg) 46.02 34.25 

Table A-5. Total Hydrocarbon Leaker Emission Factors for Onshore Petroleum and 

Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting 

Components 

Equipment in Gas Service 

Equipment in Light and Heavy Crude 

Oil Service 

Total 

Hydrocarbon,a

kg/hr 

Total 

Hydrocarbon, 

scf/hr

Total 

Hydrocarbon,a

kg/hr 

Total 

Hydrocarbon, 

scf/hr 

Valve 0.098 4.5 0.087 3.0 

Connector 0.026 1.2 0.026 0.9 

Flange 0.082 3.8 0.073 2.5 

Open-ended Line 0.055 2.5 0.044 1.5 

Pump Seal 0.074 3.4 0.100 3.4 

Other 0.089 4.1 0.083 2.8 

a

 Source is the 1995 EPA Protocol. 

Step 4. Apply gas composition data to convert total hydrocarbon leaker emission

factors in kg/hr to volumetric leaker emission factors for methane and for whole gas. Methane 

leaker emission factors were computed from total hydrocarbon leaker emission factors using the 

assumed speciation of total hydrocarbon emissions for produced gas from gas wells and for 

associated gas from oil wells. This is a necessary intermediate step to calculate volumetric whole 

gas leaker emission factors. The mass total hydrocarbon leaker emission factors were multiplied 
A-6 

by the assumed weight percent of methane in total hydrocarbon (shown in Table A-3). Then, 

mass emissions of methane in total hydrocarbon were converted to volumetric leaker emission 

factors by applying the molar volume conversion factor of 836.6 scf/kg-mol, as previously 

described in Step 3, to determine a mass to volume conversion factor for methane emissions. For 

pure methane, the resulting conversion factor is 0.01918 kg/scf, which can also be expressed as 

52.13764 scf/kg. The resulting volumetric methane leaker emission factors are summarized in 

Table A-6. 

Whole gas leaker emission factors were calculated from the volumetric methane leaker 

emission factors in Table A-6 by dividing the volumetric methane leaker emission factor by the 

volume fraction of methane in whole gas based on the assumed average gas compositions shown 

in Table A-1. For example, the average volume fraction of methane is 0.829 in whole gas 

produced from gas wells. The other hydrocarbon and non-hydrocarbon constituents comprise the 

remaining 0.171 volumetric fraction of gas emissions. The resulting whole gas leaker emission 

factors are also summarized in Table A-6. 

Table A-6. Methane and Whole Gas Leaker Emission Factors for Onshore Production and 

Gathering and Boosting 

Equipment in Gas Service 

Components 

Methane, weight fraction in total hydrocarbon 

= 0.801

Methane, volume fraction in whole gas 

= 0.829

Total Hydrocarbon,a

kg/hr Methane, kg/hr 

Methane,a

scf/hr Whole Gas, scf/hr 

Valve 0.098 0.079 4.1 4.9 

Connector 0.026 0.021 1.1 1.3 

Flange 0.082 0.066 3.4 4.1 

Open-ended line 0.055 0.044 2.3 2.8 

Pump Seal 0.074 0.059 3.1 3.7 

Other 0.089 0.071 3.7 4.5 

Equipment in Light and Heavy Crude Oil Service 

Components 

Methane, weight fraction in total hydrocarbon 

= 0.448

Methane, volume fraction in whole gas 

= 0.634

Total Hydrocarbon,a

kg/hr Methane, kg/hr 

Methane,a

scf/hr Whole Gas, scf/hr 

Valve 0.087 0.039 2.0 3.2 

Connector 0.026 0.012 0.6 1.0 

Flange 0.073 0.033 1.7 2.7 

Open-ended line 0.044 0.020 1.0 1.6 

Pump Seal 0.100 0.045 2.3 3.7 

Other 0.083 0.037 1.9 3.1 

a

 mass to volume conversion for pure methane = 0.01918 kg/scf. 
A-7 

Following is an example of how the whole gas leaker emission factors were derived from 

the total hydrocarbon leaker emission factors in the 1995 EPA Protocol. Because the original 

leaker emission factors are provided in units of kg/hr total hydrocarbon, the first step was to use 

the hydrocarbon speciation data to determine the weight fraction of methane. For example, the 

total hydrocarbon leaker emission factor for valves in gas service is 0.098 kg/hour/source (from 

Table 2 of this memorandum). Assuming the weight fraction of methane in total hydrocarbon is 

80.1 percent (from Table A-3), the methane leaker emission factor becomes: 

0.098 kg/hr total hydrocarbon × 0.801 = 0.079 kg/hr methane 

The next step was to convert the methane kg/hr leaker emission factor to a methane 

scf/hour leaker emission factor using the molecular weight of methane and the molar volume 

conversion factor: 

[0.079 kg/hr methane ÷ 16.043 kg/kg-mol] × 836.6 scf/kg-mol = 4.1 scf/hr methane 

The final step was to convert the methane scf/hour leaker emission factor to a whole gas 

scf/hr leaker emission factor using the assumed volumetric content of methane in whole gas 

presented above (for gas wells, methane is assumed to be 82.9 volume percent of the gas): 

4.1 scf/hr methane ÷ 0.829 = 4.9 scf/hr whole gas 

This process was repeated for each of the fugitive emissions component types in each 

type of service to calculate the whole gas leaker emission factors shown in Table 9 of this 

memorandum. 
B-1 

Appendix B 

Monte Carlo Analyses 

As part of our analysis comparing the leaker emission factors from different studies, it 

was necessary to understand how the variability in the mass emissions of individual “leaks” 

identified during any one study may impact the average leaker emission factor determined for 

that study. That is, in order to assess whether the differences in leaker emission factors 

determined from two separate studies are due to differences in the underlying leaker distribution 

(i.e., if OGI-identified leaks are larger or smaller in magnitude than EPA Method 21-identified 

leaks or if leaks that were measured in the early 1980s are different in magnitude from leaks 

today due to changes in equipment or operational parameters) or whether the variability observed 

may be explained by the range of mass emissions of individual “leakers” within the same 

underlying leaker distribution. To better understand how variability of mass emissions from 

individual leaks may impact the average leaker emission factor, a limited (1,000 run) Monte 

Carlo analysis was conducted.12

First, we evaluated the “leaker” data from the 1995 EPA Protocol (EPA, 1995) for valves 

in gas service at oil and gas production facilities to determine if the data were normally or lognormally distributed using ProUCL v5.0.13 Figure B-1 shows the histogram of the mass emission 

rate data; Figure B-2 shows the histogram of the log (base 10) of the mass emissions data. It is 

evident from these figures that the data are not normally distributed but appear to be lognormally distributed. A kurtosis test suggests the data are log-normally distributed; however, the 

data appear to be skewed and fail the normality test based on skewness. When the five smallest 

measured mass emission rates are excluded from the analysis, the remaining data meet the 

normality test for both kurtosis and skewness for log-normal distribution. 

Based on this analysis of the leaker emissions data, we concluded that it was reasonable 

to perform the Monte Carlo analysis assuming a log-normal distribution. We assumed that the 

central tendency mass emission rate was 0.01 kg/hr (or -2.0 log base10). While the data set for 

valves in gas service encompasses 5 orders of magnitude, it appears skewed at the lower 

emissions rates (as noted above, the data were normally distributed when the smallest mass 

emissions rates were removed from the data set). Consequently, we first conducted the Monte 

Carlo analysis assuming the data span 4 orders of magnitude (± a factor of 100) considering a 99 

percent 2-sided confidence interval (z-statistic =2.576). We also ran the Monte Carlo analysis 

 

12 The Monte Carlo method refers to using repeated random sampling to obtain numerical results. For further 

reading on the historical development of the Monte Carlo method, see “The Beginning of the Monte Carlo Method” 

(Metropolis, 1987). 

13 EPA statistical software package available at: http://www.epa.gov/land-research/proucl-software. 
B-2 

assuming the data span approximately 3 orders of magnitude (± a factor of 30) to develop an 

expected range of uncertainties in the resulting average leaker emission factors. 

Figure B-1. Histogram of leaker mass emission rate data (designated by ProUCL as 

dataset C0). 
B-3 

Figure B-2. Histogram of logarithm (base 10) of the leaker mass emission rate data 

(designated by ProUCL as dataset C1). 

Random mass emission rates were generated from the assumed log-normal distribution 

function. Groups of 30, 100, and 200 of these mass emission rates were then used to determine 

an average leaker emission factor from that pool of data, representing an average leaker emission 

factor from a given study. The analysis was repeated to generate 1,000 separate “average” leaker 

emission factors (effectively 1,000 different study results for studies with either 30, 100, or 200 

measurement values). A 95 percent confidence interval was then determined based on the 1,000 

separate “average” leaker emission factors from the Monte Carlo analysis. The results of this 

analysis are presented in Table B-1. 
B-4 

Table B-1. Uncertainty in Average Leaker Emission Factor Based on Sample Variability of 

Leak Size and Number of Leak Measurements 

Assumed Data Range 

Sample 

Size 

2.5 

Percentile Average 

97.5 

Percentile 

Variation from 

Averagea

0.01 ± a factor of 100 200 0.031 0.050 0.089 ± a factor of 1.7 

0.01 ± a factor of 100 100 0.025 0.050 0.105 ± a factor of 2.0 

0.01 ± a factor of 100 30 0.016 0.050 0.140 ± a factor of 3.0 

0.01 ± a factor of 30 200 0.018 0.024 0.032 ± a factor of 1.3 

0.01 ± a factor of 30 100 0.016 0.024 0.036 ± a factor of 1.5 

0.01 ± a factor of 30 30 0.012 0.024 0.048 ± a factor of 2.0 

a

 Calculated as the average of (1) the ratio of the “Average” column to the “2.5 Percentile” column” and (2) the ratio 

of the “97.5 Percentile” column to the “Average” column. 

The “variation from average” in Table B-1 was assessed as the factor by which the 95th

percentile confidence range value differed from the average value. This factor was used to 

determine if the values of two different measurement averages were likely to be different and 

was generally used to assess differences on average emission factors from the data set with the 

fewest measurements. That is, even if one data set had 1,000 measurements and presumably had 

a good assessment of the true average of the data set, if a second measurement study only had 30 

measurements and was a factor of 2 from the value determined from the larger study, this was 

deemed to be within the expected range of values. Or, more precisely, we were not 95 percent 

confident that the average determined from the 30 measurement data set was different because 

the underlying distribution of mass emission rates was different. 

It is possible that one study would yield an average leaker emission factor that is higher 

than the “true” average and another yield an average leaker emission factor that is lower than the 

“true” average, but it is unlikely that the two or three studies that we are comparing from 

literature reviews would yield averages on extreme tails on opposite sides of the overall 

distribution. Another method to assess the expected variation from one test result to another test 

result is to look at the difference between two separate averages. Specifically, we compared 

sequential average leaker emission factors and calculated the ratio factor (largest/smallest) for 

each of the 1,000 “study averages” determined in the Monte Carlo analysis. We conducted this 

analysis using the leaker distribution spanning 4 orders of magnitude (± a factor of 100 range 

assumption). We also compared this ratio factor using a 100 measurement study average 

compared with a 30 measurement study average and a 200 measurement study average compared 

to a 30 measurement study average. The results of this analysis are provided in Table B-2. The 

average ratio factor did decrease slightly when one of the measurement studies included more 

samples. The average ratio factor was slightly lower than the “variation from average,” but this 
B-5 

assessment shows that the 95th percent confidence interval for the ratio of any two runs is 

somewhat greater than the “variation from average” factor that was presented in Table B-1. 

Table B-2. Comparison of Ratio of Consecutive Average Leaker Emission Factors from 

Different Monte Carlo Runs 

Assumed Data Range Sample Size 

Average Ratio 

Factor 

95th Percentile 

Ratio Factor 

Variation from Average 

(Table B-1) 

0.01 ± a factor of 100 200/200 1.4 2.1 1.7 

0.01 ± a factor of 100 100/100 1.6 2.7 2.0 

0.01 ± a factor of 100 30/30 2.2 4.8 3.0 

0.01 ± a factor of 100 100/30 1.9 3.8 NA 

0.01 ± a factor of 100 200/30 1.8 3.4 NA 

Considering this analysis, we concluded that comparisons of data from different studies 

where the study with the fewest number of measurements had approximately 30 measurements 

could be expected to yield average leaker emission factors that are different by a factor of 2 to 3 

even though they are sampling from the same overall distribution of mass leak rates. We also 

concluded that comparisons of data from different studies where the study with the fewest 

number of measurements had approximately 100 measurements could be expected to yield 

average leaker emission factors that are different by a factor of 1.5 to 2. 

Thus, given the large variability in the mass emission rate of individual “leakers” 

(spanning orders of magnitude), there is large uncertainty in the calculated average leaker 

emission factor, even when measurement studies include 30 to 100 measurements. We also 

determined that one needs approximately 1,000 measurements to determine an average leaker 

emission factor with uncertainties less than 30 to 40 percent if the distribution of leaks is lognormally distributed spanning 4 orders of magnitude.