MEMORANDUM

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

FROM: Alexis McKittrick and Ma rk de Figueiredo, EPA/CCD

DATE: January 21, 2016

SUBJECT: Greenhouse Gas Reporting Rule: Tec hnical Support for Leak Detection Methodology Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems

The U.S. Environmental Protection Agency (E PA) is proposing revisions to 40 CFR part 98, subpart W (hereafter referred to as “subpa rt W”). This memora ndum provides background information on certain revisions related to de veloping 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) Stor age and LNG Import and Export Equipment, are required to conduct fugitive monitoring and mu st report greenhouse gas (GHG) emissions from equipment leaks identified during monitoring surv eys 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 specif ically to the number of com ponents found to be leaking during the monitoring survey. The leaker emission fact or represents the average leak rate for components that are leaking above a given “l eak” 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 performan ce standards for natural gas processors) and effectively assumes that no emissions occur from components that were not found to be leaking. Leaker emission factors curren tly 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 se gments, 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 ga thering 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 se gments to count the pieces of major production equipment at the facility and mu ltiply 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 f actor to estimate total emissions at a facility. (This method is also required for specific sources in other industry segments, su ch as storage wellheads in gas service in the Underg round 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 cate gory on August 16, 2012 (77 FR 49542) (hereafter referred to as “NSPS subpart OOOO”), which requi re 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 im aging (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 compone nts are only subject to visual or olfactory leak identification. Historically, miscellaneous “other” fugitive emi ssion sources included components such as instruments (gauges), regulato rs, access doors, agitator seals, loading arms, dump lever arms, stuffing boxes, breather caps; these sources ma y 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 se veral emission sources not covered by NSPS subpart OOOO (80 FR 56593). Among other thi ngs, proposed NSPS subpart OOOOa would require routine fugitive emissions monitoring of fugitive emissions components at new and modified compressor stations thr oughout the oil and natural gas s ector and at new and modified well sites, defined as the area disturbed or a ffected by the drilling, subsequent operations, and production facilities directly associ ated with any oil, gas or inj ection well and its associated well pad. A fugitive emissions component is any com ponent 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, in struments, and meters. The proposed rule also specifies that fugitive emissions would be considered any visible emissions from fugitive emissions3 components observed using OGI. The proposed N SPS subpart OOOOa sta ndards would require replacement or repair of co mponents with fugitive emissions detected during a monitoring survey, which should result in re ductions of emissions from fug itive emissions components for those facilities.
To (a) limit burden for subpart W facilities with well sites and comp ressor 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 pr oposing to align the subpart W requirements with the fugitive emissions monitori ng requirements in proposed N SPS subpart OOOOa. Specifically, the EPA is proposing to add the OGI monitori ng method proposed in NSPS subpart OOOOa to subpart W. In addition, the EPA is proposing to a dd 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 a nd repair programs have used EPA Method 21 to identify leaks by manually monitoring for elevated hydrocarbon concen trations at specific individual equipment components, such as valves, pumps, open-ended lin es, connectors, flanges, and pressure relief valves (also referred to “traditional equipmen t components” within this document). These traditional equipment components ar e generally included in the ex isting 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 N SPS 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 com ponents 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 segm ent, equipment leak emissions are determined using a combination of leak surveys and component counts multip lied by population emission factors. However, NSPS subpart OOOOa as proposed would not cover facilities in th is industry segment; therefore, the subpart W Natural Gas Distribution industry segment is no t discussed further in this section.4  Subpart W does not currently include leak er emission factors for Onshore Petroleum and Natural Gas Production and the Onshor e 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 requirement s 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 corresp onding subpart W leaker emi ssion factor is a pump.

 For the Onshore Natural Gas Transmission Compression, Underground Natural Gas Storage, LNG Storage and LNG Import a nd 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 Subp art OOOOa Fugitive Emissions Components and Current Subpart W Leaker Emission Fa ctors for Select Industry Segments a

Proposed NSPS subpart OOOOa Fugitive Emissions Component Type b Subpart W Industry Segment and Service Type

Onshore Natural Gas Transmission Compression Underground Natural Gas

Storage c LNG Storage; LNG Import and Export Equipment Compressor Components, Gas Service Non-Compressor Components, Gas Service Storage Station, Gas Service Components, LNG Service d,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 ty pe 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, va lves, 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 co mpressors in gas service but does not

include emission factors for non-compressor components in gas service.
f Emissions for this sources are alread y 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 emissi ons 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 emissi on factors are based on the “1993 petroleum industry data” compiled by th e American Petroleum Institute and the Gas Research Institute (GRI), which includes fug itive hydrocarbon emissions data from onshore and offshore production sites (API, 1993b; API, 1995) , gas plants, refine ries (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 diffe rent 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 dete ctor were deployed for leak detection.

 All readings greater than 10 ppmv were recorded. Fi fteen percent of all components with fugitive emissions were bagged for measurement of mass emissions. All bagged samples were speciated into C1 throu gh 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 scr eening concentration value exceeded 10,000 ppmv.
The 1993 leak survey of production sites f ound that 90 percent of fugitive hydrocarbon emissions came from components with large le aks, which generally represented less than 1 percent of installe d components. The original survey found no evidence of statistical differences in emission fact ors 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 indus try data set were excluded due to large background concentrations or high sc reening value variability and th e statistical analyses of the original data were revised.
Emissions data used to develop leaker emi ssion factors are impacted by the sensitivity of the screening method and the emi ssions concentration threshold de fined for an equipment “leak.” In the 1995 EPA Protocol , petroleum industry equipment leak s are identified as exceeding a screening concentration threshold of 10,000 part s per million (ppm), which is generally the “pegged” concentration measurement of the sc reening instrument. Equipment with fugitive emissions that screened below 10,000 ppm were c onsidered “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 producti on sites, 70 to 98 pe rcent 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 fo r oil and gas production are summarized in Table 2. As seen in Table 2, leak er emission factors are available for different types of equipment that are typically include d 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 factor s 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 (N 2 ) and carbon dioxide (CO 2 ). Gas composition data are needed to translate total hydrocarbon leaker emission factor s to whole gas leaker emission factors or to methane leaker emission factors.

3 See Table 15, “Contribution of Each Screening Ra nge to Average Emission Factors” (API, 1995).8 Table 2. Existing Leaker Emission Factors A vailable 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 3.92 b 12 b Other c 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 Other c 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 Other c 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 fact ors 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 populatio n emission factors currently in subpart W for the Onshore Petroleum and Natural Gas Produc tion 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 ar e available from two studies by Clearstone Engineering Ltd.: Identification and Evaluation of Opportu nities to Reduce Methane Losses at Four Gas Processing Plants (Clearstone, 2002) and Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Ga s Processing Plants and Upstream Gathering Compressor Stations and Well Sites (NGML et al., 2006). Gas tran smission facility emissions data are available from the Handbook for Estimating Methane Em issions from Canadian Natural Gas Systems (Picard et al., 1998) and the Measurement of Natural Gas Emissions from the Canadian Natural Gas Transmissi on and Distribution Industry (Clearstone, 2007)

. Current subpart W leaker emission factors for the Onshore Natural Gas Processing, Natural Gas Transmission Compression, and Underground Natu ral Gas Storage industry segments were derived from these four sources. Discussion of the leaker emission fact or 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 Ga s 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. Component s 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 id entified as leaking. Acoustic and ultrasonic leak detectors were deployed at certain valves, flanged connec tions, 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 emissi on 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 leak er emission factors for each component type. Leaker emission factors from the transmissi on 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 forcompressor 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 A vailable for Leaker Emission Factors Additional data from fugitive emissions survey s of equipment in the oil and gas industry have become available since 2010. These emissions da ta 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 fr om 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 st udy”). This study measured fugitive gas emissions from 375 well pads, eight compre ssor stations, one gas processing plant, and one produced water treatment facil ity. Leak screening and measurement was performed using OGI and a high flow sampler. EPA Method 21 and bagging techniques were also perfor med on selected sources. All pr oduction facilities in the study are located in the Fort Worth Basin a nd 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 th e 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 othe r 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 fact ors for the Onshore Petroleu m and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting segments, taking into consideration the limited ge ographic 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 Coas t, Mid-Continent, and Rocky Mountains. Sites were screened with an infrared camer a 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 Ne w Kensington, Pennsylvania, is the sole manufacturer of a commercial high flow sampler, distributed as the Bacharach Hi-Flow Sampler TM ( http://www.mybacharach.com ). Concerns have been raised that methane emissions reported in recent stud ies, including Allen et al. (2013) and the 2011 Fort Worth study, may be underestimated due to systematic sensor failure of the Bacharach Hi-Flow Sampler TM when methane content in the gas stream is less than 91 percent, the instru ment 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 hou r (g/hr) (0.026 standard cubic feet per minute (scf/min)), consistent with the approved altern ative work practices in 40 CFR 60.18. In practice, the11 site of the Center for Energy and Envir onmental Resources at the University of Texas, Austin; the data include approxima tely 278 measurements of whole gas and methane emissions from leaks at production sites. 7

 Methane Emissions from Natural Gas Co mpressor 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 emi ssions 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 supplem ental information, which includes fugitiveemissions 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 segm ent, 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 usi ng EPA Method 21 may be different fr om 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 monitori ng requirements. The new leaker emission factors are intended to be used with the results of leak surveys to repo rt fugitive GHG emissions for equipment leaks under subpart W.

 Option 1: Use leak data developed using EP A Method 21 to develop new leaker emission factors for traditional equipm ent components and non-traditional components where they are not yet available in subpart W ( e.g. , the Onshore Petroleum and Natural Gas Production se gment, sources in the Natural Gas Transmission Compression segment that cu rrently 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 EP A Method 21 to develop new leaker emission factors for traditional equipment components and use leak data from OGIbased emissions surveys to develop new l eaker 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 th e 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/me thane/study/datasets1.cfm

.12 components only. As noted previously, examples of non-traditional components include instruments, heaters, agitator s eals, access doors, and blowdown vent fugitive emissions.

 Option 3: Use leak data from OGI-based emissi ons 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 Opti on 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 pr oposed NSPS subpart OOOOa.

 Option 4: Use aggregate leak data from EPA Method 21- and OGI-based emissions surveys to develop new leaker emission fact ors 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 l eaker emission factors would be derived from data for leaks identified using EPA Method 21. Under Opti on 2, some proposed leaker emission factors would be historical leaker emission factors based on an EP A Method 21 leak detection and monitoring program and some leaker emission f actors 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. Unde r Option 4, the proposed leaker emission factors would be derived from all available data, in cluding 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 emissi ons data available in the three recent studies cited above. The first two studies (the 2011 Fort Worth study and Alle n et al. (2013)) were specific to onshore natural ga s production (but appear to have also included equipment characterized as part of the Onshore Petroleu m and Natural Gas Gathering and Boosting segment in subpart W). We developed pot ential leaker emission factors fo r 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 methan e). In order to compare these values as directly as possible, we converted the reported emission factors from the 1995 EPA Protocol and13 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 Appendi x 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 Percent a Associated Gas (Oil Well) Volume Percent b Methane, C1 82.9 c 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 CO 2 3.9 c 1.4 N 2 2.77 d 4.0 H 2 S e 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 N 2 and assuming N 2 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 H 2 S = hydrogen sulfide.

Table 4 provides the comparis on of the existing to tal hydrocarbon leaker emission factors for equipment in gas service at onshore na tural gas production sites (from the 1995 EPA Protocol ) with potential leaker emission factors deri ved from two OGI-based emissions surveys at onshore natural gas production sites.14 Table 4. Comparison of Potential Leaker Emi ssion 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 Factor a (scf/hr/

component) Sample Size Whole Gas Leaker Emission Factor b (scf/hr/

component) Sample Size Methane (

&

Whole Gas)

Leaker Emission Factor b (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) Other c 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 whol e 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, Alle n et al. (2013) and the 2011 Fort Worth study, which are recent OGI-based fugitive emissions st udies, appear to yield higher leaker emission factors than the EPA Method 21-base d data presented in the 1995 EPA Protocol . Note also that there are significant differences in the leakeremission factors developed from the two OGIbased studies. Except for open-ended lines, th e 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 th at there is significant variability in the mass emission rate from15 individual leaks. Figure 1 show s 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 se rvice for oil and gas production facilities (includes data from Table C-1-1 a nd 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

0123456Log10(MassEmissionsRate,kg/hr)

Log10(Method 21 Screening Value) Correlation Eqn Data Pegged Data

Linear (Correlation Eqn Data) 10,000 ppmv leak

10 g/hr leak16 assess the impacts of this variability (see Appendix B of this memorandum for more information). Based on these analyses, random sa mples 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 measurem ents, there can still be significant uncertainty in the leaker emission factors develo ped 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 concentr ation 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 or ifice. 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 greate r, regardless of concentration, it is evident that the average size of leaks above the red “10 g/hr leak” line will be la rger 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 me thods 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 point s 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 measurem ents available from the other two studies. The 2011 Fort Worth study and Allen et al. (2013) suggest a hi gher leaker emission rate than the 1995 EPA Protocol

.

 Flanges. The number of measurements is lim ited for all studies. The variability in the derived leaker emission factors appears c onsistent with expectations based on the Monte Carlo analysis.

 Open-Ended Lines. The number of meas urements available from the 1995 EPA Protocol is 2 to 4 times greater than for th e 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 si zes based on the Monte Carlo analysis.17  Pressure Relief Valves. The number of m easurements is limited for all studies. The variability in the derived leaker emission f actors 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 s eals 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/c omponent. The number of measurements for “other” components is much larger for th e OGI-based studies than in the 1995 EPA Protocol and includes non-tr aditional 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 l eaker 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 reas onably well with the 1995 EPA Protocol leaker emission factor for “oth er” components considering the limited number of “other” components for wh ich measurements were made in the 1995 EPA Protocol

. Subramanian et al. (2015) provided a graphi cal comparison of the average leak size measured using OGI compared to the Onshor e Natural Gas Transmission Compression leaker emission factors in Table W-3 of subpart W. Th is comparison is provided in Figure 2. Figure 2 includes the number of leaking components m easured 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 18 118 Figure 2. Comparison of leaker emission fa ctors from Subramanian et al. (2015) and Table W-3 of subpart W for the Onshore Natu ral 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 (Cle arstone, 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 numb er 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 th e 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 variab ility in the derived leaker emission factors for valves appears consistent with expectations for compressor valves but is slightly larger than expect ed for non-compressor valves based on the sample size and the Monte Carlo analysis (see A ppendix 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 Petr oleum and Natural Gas Gathering and Boosting segments, connectors is one com ponent where the data available from Subramanian et al. (2015) suggest a higher leaker emi ssion rate than Clearstone (2002) and Clearstone (2007).

 Open-Ended Lines. The number of measurem ents is reasonable for both the current subpart W leaker emission factor and th e OGI study. The resulting leaker emission factors from the OGI-based study are hi gher than the EPA Method 21-based study. The variability in the derived leaker em ission factors for the non-compressor openended lines appears consistent with expect ations based on the Monte Carlo analysis considering that there are only 38 OGI-bas ed 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 meas urements 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 pressu re relief valves. The variability in the derived leaker emission factor s appears consistent with expectations for the small sample size based on the Monte Carlo analysis.

 Meters. The number of measurements is lim ited for all studies. The variability in the derived leaker emission factor s appears consistent with e xpectations for this sample size based on the Monte Carlo analysis.

The discussion above illustrates consideratio ns 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 hydr ocarbon 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 asp ects as equipment component categories, equipment descriptions, and mass emissions measurement methodology. Such differences introduce uncertainty in accurate ly 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 differe nt 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 si gnificant 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 cognizan t of the variability in the mass emissions from individual leaks and to ensure that there are a su fficient number of measurements for any given fugitive emi ssions component in order to develop a robust and accurate leaker emi ssion 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 descri bed 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 emi ssions detected from com ponents that are not uniquely specified are simply assigned the l eaker emission factor for “other” equipment components. There is uncertainty in applying th e “other” leaker emissi on factors developed in the 1995 EPA Protocol to the larger array of “other” fugi tive emissions components that can be identified using OGI leak detection and monito ring, 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” component s 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 propos ed for the Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natura l 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 em ission factors in the 1995 EPA Protocol are kilograms per hour (kg/hr) of tota l 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 differ ent 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 em ission factors were presented previously in Table 3 of this memorandum. A ppendix A provides additional detail regarding the source of these default compositi ons 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 hydrocar bon leaker emission factor from the 1995 EPA Protocol in units of kg/hr and the leaker emissi on 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 (CO 2 , N 2 & hydrogen sulfide (H 2 S)) = 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 comp onents 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 se rvice that do exceed the 10,000 pp mv leak threshold would have emissions similar to those in gas or light liqui d 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 hydro carbon leaker emission factors in units of kg/hr total hydrocarbon and the leaker factors converted to units of scf/hr total hydr ocarbon, methane, and whole gas.22 Table 7. Total Hydrocarbon, Methane, and Whole Gas Leaker Emission Factors for Equipment in Crude Oil Service for the Onsh ore 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 (CO 2 , N 2 & H 2 S = hydrogen sulfide (H 2 S)) = 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 prov ides leaker emission factors for additional components and expands the components consider ed under the “other” ca tegory 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 st udies 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 connector s would also appl y to flanges).
For the LNG Storage and LNG Import and Export Equipment industry segments, the source for current leaker emission factor s 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 a nd 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 Import23 Terminals, 9 suggesting that the equipment and emissions are expected to be similar for these three sources. We also note that the leaker em ission factors in subpart W for equipment in gas service at Underground Natural Gas Storage stations are identical to the le aker emission factors for compressor components in gas service fo r 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 tota l hydrocarbon leaker emission fact ors are equal to the methane emission factors.
Similarly, based on our analys es and consistent with the conclusion for the Onshore Petroleum and Natural Gas Production and Onshor e Petroleum and Natural Gas Gathering and Boosting industry segments to use the leaker emission factors devel oped from EPA Method 21- based studies for the “other” category where OGI-bas ed study data were av ailable, 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 partic ular industry segment, average leaker emission factors for the category of “other” components in that industr y 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 Natu ral 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 summar izes the whole gas leaker emission factors for Onshore Petroleum and Natural Gas Producti on and Onshore Petroleum and Natural Gas Gathering and Boosting. Table 10 summarizes the new total hydro carbon leaker emission factors for the Onshore Natural Gas Processing, Ons hore Natural Gas Transmission Compression, and Underground Natural Gas Storage industry segm ents. 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 CH 4 Emissions (Mg) for the Natura l Gas Transmission Stage” (EPA, 2015)

.24 Table 8. Summary of Development of Ne w 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 memorandum25 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 Ga s 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 3.126 Table 10. Summary of New Total Hydrocarbo n 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 Em ission 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 4.127 References
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Metropolis, N. 1987. “The Beginning of the Monte Carlo Method.” Los Alamos Science , Number 15, Special Issue. pp. 125-130. Available at http://la-science.lanl .gov/lascience15.shtml

. NGML (National Gas Machinery Laboratory, An Institute of Kansas State University), Clearstone Engineering Ltd and Innova tive Environmental Solutions, Inc. 2006. CostEffective Directed Inspection and Maintenanc e Control Opportuniti es at Five Gas Processing Plants and Upstream Gatheri ng Compressor Stations and Well Sites

. Prepared for Roger Fernandez, U.S. Environmental Protection Agency Natural Gas30 STAR Program. March 2006. Available at http://www3.epa.gov/gasstar/doc uments/clearstone_II_03_2006.pdf

. NGSA (Natural Gas Supply Association). 2013. “Overview of Natural Gas: Background.” Available at http://naturalgas.org/overview/background . September 20, 2013. Accessed December 1, 2015.
Picard, D.J., M. Stribrny, and M.R. Harrison. 1998. Handbook for Estimating Methane Emissions from Canadian Natural Gas Systems . Prepared for GRI Canada by D.J. Picard, M. Stribrny, and M.R. Harrison of Clearston e Engineering Ltd., Enerco Engineering Ltd., and Radian International. May 25, 1998.
Subramanian, R., L.L. Williams, T.L. Vaughn, D. Zimmerle, J.R. Roscioli, S.C. Herndon, T.I. Yacovitch, C. Floerchinger, D.S. Tkacik, A. L. Mitchell, M.R. Sullivan, T.R. Dallmann, and A.L. Robinson. 2015. “Methane emissions from natural gas compressor stations in the transmission and storage sector: meas urements and comparisons with the EPA Greenhouse Gas Reporting Program protocol.” Environmental Scie nce and Technology

. 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 fo r 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 hydrocar bon 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 appendi x describes the method used to convert leaker emission factors for mass emissions of total hydrocarbon to leaker emission factors for volumetric emissions of tota l hydrocarbon. This appendix also describes the method used to calculate leaker emission fact ors 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 a ssociated gas (natural gas co-produced with oil). Gas composition expressed as mole per cent (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 Percent b Relative Mass Contribution (kg for 100 kg-mol) Mole Percent c Relative Mass Contribution (kg for 100 kg-mol) Methane, C1 16.043 82.9 c 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 CO 2 44.010 3.9 d 171.64 1.4 61.61 N 2 28.013 2.77 e 77.6 4.0 112.05 H 2 S f 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 N 2 and assuming N 2 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 H 2 S = hydrogen sulfide.

The starting point for estimating averag e gas compositions is the memorandum Composition of Natural Gas for use in th e 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 emi ssion factor analysis , the non-hydrocarbon components of whole gas shown in Table 8 of Br own (2011) were adjusted so that the average gas compositions assumed in Table A-1 corresp ond 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 N 2 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 natura l gas in the production sector ofA-3 82.9 percent (for general sources, Lower-48 states) 10 and an average CO 2 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 Percent a Associated Gas, Volume Percent b

Methane 70 – 90 68 Ethane 0 – 20 15 Propane 9 Butane 5

CO 2 0 – 8 1 O 2 0 – 0.2 1 N 2 0 – 5 H 2 S c 0 – 5 Rare Gas Trace

a Source: NGSA, 2013. Natu ralGas.org is presented by the Natura l Gas Supply Association to provide a

comprehensive information source for topics related to natural gas.
b Source: Table 2, “Typical Natural Ga s Compositions, Mole %” (Farry, 1998).

c H 2 S = hydrogen sulfide.

Step 2. Compute the weight fraction of to tal 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 th e total molecular weight of whol e 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 Na tural Gas by NEMS Region” (EPA, 2015)

. 11 See Annex 3, Table A-150: “ Production Sector CO 2 Content in Natural Gas by NEMS Region ” (EPA, 2015).A-4 Table A-3. Computed Weight Percent of Ga s Constituents in Total Hydrocarbon and Whole Gas

Constituent a 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 CO 2 8.7 2.5 N 2 3.9 4.5 H 2 S 3.4 1.4

a H 2 S = hydrogen sulfide.

Step 3. Compute molecular weight of tota l 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 cons tituent by its molecular weight. The resulting values (in units of kilogram-moles per kil ogram (kg-mol/kg) total hydrocarbon) were summed. The reciprocal is the molecular weight of the total hydrocarbon em issions 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 to tal hydrocarbon conversion factor in units of kilograms per standard cubic foot (kg/scf). The total hydrocarbon conversi on factor can also be expressed as standard cubic feet per kilogram (scf/kg) total h ydrocarbon. The computation of the leaker emission factor conversion for produced ga s 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 Hydr ocarbon 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 Emissi on 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 to tal hydrocarbon leaker em ission factors using the assumed speciation of total hydrocarbon emissi ons 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 multipliedA-6 by the assumed weight percent of methane in total hydrocarb on (shown in Table A-3). Then, mass emissions of methane in to tal 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 vol ume conversion factor for methane emissions. For pure methane, the resulting conversion factor is 0.01918 kg/scf, which can al so be expressed as 52.13764 scf/kg. The resulting volumetric methane l eaker emission factors are summarized in Table A-6.
Whole gas leaker emission factors were calc ulated from the volumetric methane leaker emission factors in Table A-6 by dividing the volu metric 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 emissi ons. The resulting whole gas leaker emission factors are also summarized in Table A-6.

Table A-6. Methane and Whole Gas Leaker Emis sion 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 emi ssion factors in the 1995 EPA Protocol . Because the original leaker emission factors are provide d in units of kg/hr total hydro carbon, the first step was to use the hydrocarbon speciation data to determine the we ight fraction of methane. For example, the total hydrocarbon leaker emission f actor for valves in gas serv ice is 0.098 kg/hour/source (from Table 2 of this memorandum). Assuming the wei ght fraction of methane in total hydrocarbon is 80.1 percent (from Table A-3), the methan e 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 mol ecular 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 sc f/hour leaker emission f actor to a whole gas scf/hr leaker emission factor using the assumed volumetric co ntent of methane in whole gas presented above (for gas wells, methane is a ssumed 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 leak er 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 av erage leaker emission factor determined for that study. That is, in order to assess whethe r the differences in leaker emission factors determined from two separate studies are due to differences in the underl ying leaker distribution ( i.e. , if OGI-identified leak s are larger or smaller in magn itude than EPA Method 21-identified leaks or if leaks that were measured in the ea rly 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 “leake rs” within the same underlying leaker distribution. To better understa nd how variability of mass emissions from individual leaks may impact the average leak er 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 pr oduction facilities to de termine if the data were normally or lognormally distributed using ProUCL v5.0. 13 Figure B-1 shows the hist ogram of the mass emission rate data; Figure B-2 shows the hi stogram 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). Wh ile 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 se t). 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 interv al (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 re sulting average leaker emission factors.

Figure B-1. Histogram of leak er 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 em ission 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 an alysis was repeated to generate 1,000 separate “average” leaker emission factors (effectively 1,000 di fferent study results for studi es with either 30, 100, or 200 measurement values). A 95 percent confidence in terval 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 Average a 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 “Avera ge” 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 95 th 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 averag e emission factors from the data set with the fewest measurements. That is, even if one da ta set had 1,000 measurements and presumably had a good assessment of the true average of the da ta set, if a second measurement study only had 30 measurements and was a factor of 2 from the va lue determined from the larger study, this was deemed to be within the expect ed range of values. Or, more pr ecisely, we were not 95 percent confident that the average determined from th e 30 measurement data set was different because the underlying distribution of ma ss emission rates was different.
It is possible that one study w ould yield an average leaker em ission factor that is higher than the “true” average and another yield an averag e leaker emission factor that is lower than the “true” average, but it is unlikely that the tw o 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 tw o separate averages. Specifically, we compared sequential average leaker emission factors and calc ulated 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 distri bution spanning 4 orders of magn itude (± a factor of 100 range assumption). We also compared this ratio factor using a 100 meas urement study average compared with a 30 measurement study averag e 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 lo wer than the “variation from average,” but thisB-5 assessment shows that the 95 th percent confidence interval for the ratio of any two runs is somewhat greater than the “variation from av erage” factor that was presented in Table B-1.

Table B-2. Comparison of Ratio of Consecuti ve Average Leaker Emi ssion 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 m easurements 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 overa ll distribution of mass leak rates. We also concluded that comparisons of data from diff erent studies where the study with the fewest number of measurements had approximately 100 measurements could be expected to yield average leaker emission f actors 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 studi es include 30 to 100 measurements. We also determined that one needs approximately 1,000 m easurements to determine an average leaker emission factor with uncertainties less than 30 to 40 percent if the distri bution of leaks is lognormally distributed spanni ng 4 orders of magnitude.