## GREENHOUSE GAS EMISSIONS REPORTING FROM THE

PETROLEUM AND NATURAL GAS INDUSTRY

BACKGROUND TECHNICAL SUPPORT DOCUMENT

U.S. ENVIRONMENTAL PROTECTION AGENCY

CLIMATE CHANGE DIVISION

WASHINGTON DCTABLE OF CONTENTS 1. Segments in the Petroleum and Natural Gas Industry ......................................................... 3 a. Petroleum Industry ............................................................................................................ 4 b. Natural Gas Industry ......................................................................................................... 5 2. Types of Emissions Sources and GHGs .............................................................................. 6

3. GHG Emissions from the Petr oleum and Natural Gas Industry .......................................... 7 4. Methodology for Selection of Industry Se gments and Emissions Sources Feasible for Inclusion in a Mandatory GHG Reporting Rule................................................................. 9 a. Review of Existing Regulations ...................................................................................... 10 b. Review of Existing Programs ......................................................................................... 12 c. Selection of Emissions Sources for Reporting ................................................................ 17 i. Facility Definition Characterization ............................................................................ 17

ii. Selection of Potential Em issions Sources for Reporting ............................................ 18 iii. Address Sources with Large Uncertainties ................................................................ 23 iv. Identify Sources to be Included ................................................................................. 23 5. Options for Reporting Threshold ....................................................................................... 30 a. Threshold Analysis .......................................................................................................... 30 6. Monitoring Method Options .............................................................................................. 34 a. Review of Existing Relevant Reporting Programs/ Methodologies ............................... 34 b. Potential Monitoring Methods ........................................................................................ 34 i. Fugitive Emissions Detection ...................................................................................... 34

ii. Emissions Measurement ............................................................................................ 36

A. Direct Measurement ............................................................................................... 36 B. Engineering Estimation .......................................................................................... 39

C. Emission Factors .................................................................................................... 45 D. Combination of Direct Measurement and Engineering Estimation ....................... 46

c. Leak detection and leaker emission factors .................................................................... 57 d. Population Count and Emission Factors. ........................................................................ 58

e. Method 21 ...................................................................................................................... 58

f. Portable VOC Detection In struments for Leak Measurement ........................................ 59 g. Mass Balance for Quantification ................................................................................... 60 h. Gulf Offshore Activity Data System program (GOADS) .............................................. 60 i. Additional Questions Regarding Potential Monitoring Methods .................................... 61 i. Source Level Fugitive Em issions Detection Threshold ........................................... 61 ii. Duration of Fugitive Emissions .............................................................................. 63 iii. Fugitive and Vented Emissions at Different Operational Modes .......................... 63 iv. Natural Gas Composition ....................................................................................... 64 v. Physical Access for Leak Measurement ................................................................. 65 7. Procedures for Estimating Missing Data ............................................................................ 65

a. Emissions Measurement Data ......................................................................................... 65 b. Engineering Estimation Data .......................................................................................... 66 c. Emissions Estimation Data for Storage Tanks and Flares .............................................. 66 d. Emissions Estimation Data Using Emissions Factors .................................................... 66 8. QA/QC Requirements ........................................................................................................ 67

Background Technical Support Document – Petroleum and Natural Gas Industry 2a. Equipment Maintenance .................................................................................................. 67 b. Data Management ........................................................................................................... 67

c. Calculation checks .......................................................................................................... 68 9. Reporting Procedure ........................................................................................................... 69 10. Verification of Reported Emissions .................................................................................. 70 Appendix A: Segregation of Emissions Sources using the Decision Process ........................ 71 Appendix B: Development of revised estimat es for four U.G. GHG Inventory emissions

sources ............................................................................................................................... 79 Appendix C: Development of threshold analysis ................................................................... 86 Appendix D: Analysis of potential facility de finitions for onshore petroleum and natural gas production ......................................................................................................................... 99 Appendix E: Analysis of potential facility definitions for local distribution companies ..... 103 Appendix F: Analysis of Definition Options for Natural Gas Production Gathering Pipelines for Emissions Reporting ................................................................................................. 106 Appendix G: Accounting for Inaccessible Emissions Sources ............................................. 109 Appendix H: Review and assessment of potential alternatives to monitoring methods for

emissions sources ............................................................................................................ 124 Appendix I: Flares ................................................................................................................. 130 Appendix J: Development of multipliers to scale emissions or miscellaneous sources connected to storage tanks .............................................................................................. 132 Appendix K: Development of Leaker Emission Factors ...................................................... 135 Appendix L: Development of Population emission factors .................................................. 144 Appendix M: Potential Solutions to Measur e Greenhouse Gas Emissions in Various Modes of Equipment Operation .................................................................................................. 159 Appendix N: Identifying gas com positions for emissions estimates .................................... 166 Appendix O: Development of performance criteria and monitoring protocol for fugitive measurement techniques ................................................................................................. 167 Appendix P: Discussion on Methodo logies in Emission References ................................... 181 Appendix Q: Glossary ........................................................................................................... 185 Appendix R: References ....................................................................................................... 191



### 1. Segments in the Petroleum and Natural Gas Industry

The U.S. petroleum and natural gas industr y encompasses the production of raw gas and

crude oil from wells to the deli very of processed gas and petr oleum products to consumers. These segments, and everything in between, use energy and emit greenhouse gases (GHG). It is convenient to view the industry in the following discrete segments:

• Petroleum Industry – petroleum production, petroleum transportation, petroleum refining, petroleum terminals, and

• Natural Gas Industry –natural gas productio n, natural gas processing (including gathering and boosting), natural gas transm ission and underground storage, liquefied natural gas (LNG) import and export term inals, and natural gas distribution.

Each industry segment uses common processes a nd equipment in its faci lities, all of which

emit GHG. Each of these i ndustry segments is described in further detail below.

Background Technical Support Document – Petroleum and Natural Gas Industry 3

### a. Petroleum Industry

Petroleum Production. Petroleum or crude oil is produ ced from underground formations. In some cases, natural gas is also produced fr om oil production wells; this gas is called associated natural gas. Production may require pumps or compressors for the injection of liquids or gas into the well to maintain pr oduction pressure. The produced crude oil is typically separated from water and gas, injected with chemic als, heated, and temporarily

stored. GHG emissions from cr ude oil production result from combustion-related activities, and fugitive and vented emissions. Equi pment counts and GHG-emitting practices are

related to the number of producing crude oil wells a nd their production rates.

As petroleum production matures in a field the natural reservoir pressure is not sufficient to bring the petroleum to the surf ace. In such cases, enhanced oil recovery (EOR) techniques

are used to extract oil that otherwise can not be produced using only re servoir pressure. In the United States, there are three predominan t types of EOR operations currently used; thermal EOR, gas injection EOR, and chemical injection EOR. Thermal EOR is carried out by injecting steam into the reservoir to reduce the viscosity of heavy petroleum to allow the flow of the petroleum in the reservoir a nd up the production well. Gas injection EOR involves injecting of gases, such as natural gas, n itrogen, or carbon dioxide (CO 2) , to improve the viscosity of the petroleum and push it to wards and up the producing well. Chemical injection EOR is carried out by injecting surf actants or polymers to improve the flow of petroleum and/or enhance a water flood in th e reservoir. Emissi ons sources from EOR operations are similar to those in conventio nal petroleum production fields. However,

additional emissions occur when carbon dioxide is used for recovery. This specific EOR operation requires pumps to inject supercritical CO 2 into the reservoir while compressors maintain the recycled CO 2 ’s supercritical state. Venting from these two sources is a major

source of emissions.

Petroleum Transportation

. The crude oil stored at production sites is either pumped into crude oil transportation pipeline s or loaded onto tankers and/or rail freight. Along the supply chain crude oil may be stored several times in tanks. Thes e practices and storage tanks release GHG emissions, as well as emissions fr om combustion. Emissions are related to the amount of crude oil transporte d and the transportation mode.

Petroleum Refining Crude oil is delivered to refineries where it is temporarily stored before being fractionated by distillation and treat ed. The fractions are reformed or cracked and then blended into consumer petroleum produc ts such as gasoline, diesel, aviation fuel, kerosene, fuel oil, and asphalt. These proce sses are energy intensive. Equipment counts and GHG gas emitting practices are rela ted to the number and comple xity of refineries. Subpart Y of the Final Mandatory Reporting Rule (M RR) published in the Federal Register on October 30, 2009, addresses refineries and hence is not discussed further in this document.

Petroleum products are then transported via tr ucks, rail cars, and barges across the supply chain network to terminals and finally to end users.

Background Technical Support Document – Petroleum and Natural Gas Industry 4

### b. Natural Gas Industry

Natural Gas Production In natural gas production, wells are used to withdraw raw gas from underground formations. Wells must be drilled to access the underground formations, and often require natural gas well completion procedures or other practices that vent gas from the well depending on the underground formation. The produced raw gas commonly requires treatment in the form of separation of ga s/liquids, heating, chemical injection, and dehydration before being compressed and inj ected into gathering lines. Combustion, fugitive, and vented emissions arise from the wells themselves, gathering pipelines, and all well-site natural gas treatment processes an d related equipment and control devices. Determining emissions, equipment counts, and frequency of GHG emitting practices is related to the number of producing wellheads and the amount of produced natural gas. Further details are provided on the individua l sources of GHG emissions in Appendix A.

Natural Gas Processing (includi ng Gathering/Boosting stations) In this segment of the supply chain, natural gas from the petrol eum and natural gas production segment is compressed and injected into gathering lines th at transport it to natural gas processing facilities. In the processing facility, natural gas liquids and various ot her constituents from the raw gas are separated, resulting in “pipeline quality” gas that is compressed and injected into the transmission pipelines. These sepa ration processes include acid gas removal, dehydration, and fractionation. All equipment and practices have associated GHG fugitive emissions, energy consumption-related combus tion GHG emissions, and/or process control related GHG vented emissions. Equipment c ounts and frequency of GHG emitting practices are related to the number and size of gas processi ng facilities. Further details are provided on the individual sources of GHG emissions in Appendix A.

Natural Gas Transmission and Storage Natural gas transmission involves high pressure, large diameter pipelines that transport natura l gas from petroleum and natural gas production sites and natural gas processing facilities to na tural gas distribution pipelines or large volume customers such as power plants or chemical plants. Compressor station facilities containing large reciprocating and turbine compressors, move the gas throughout the U.S. transmission pipeline system. Equipment counts and freque ncy of GHG emitting practices are related to the number and size of compressor stations and the length of transmission pipelines.

Natural gas is also injected and stored in unde rground formations, or stored as LNG in above ground storage tanks during periods of low dema nd (e.g., spring or fall), and then withdrawn, processed, and distributed during periods of high demand (e.g., winter and summer). Compressors and dehydrators are the primar y contributors to emissions from these underground and LNG storage facilities. E quipment counts and GHG emitting practices are

related to the number of storage stations.

Imported LNG also requires transportation and st orage. These processe s are similar to above ground LNG storage and require compression and c ooling processes. GHG emissions in this segment are related to the number of LNG import terminals and LNG storage facilities.

Background Technical Support Document – Petroleum and Natural Gas Industry 5Further details are provided on the individu al sources of GHG emissions for all of transmission and storage in Appendix A.

Natural Gas Distribution Natural gas distribution pipeline s take high-pressure gas from the transmission pipelines at “city gate” st ations, reduce and regulate the pressure, and distribute the gas through prim arily underground mains and service lines to individual end

users. Between the distribution mains an d many off-shooting services are underground regulating vaults. GHG emissions from distri bution systems are related to the pipelines, regulating stations and vaults , and customer/residential mete rs. Equipment counts and GHG emitting practices can be related to the number of regulating stations and the length of pipelines. Further details are provided on the individual sources of GHG emissions in Appendix A.



### 2. Types of Emissions Sources and GHGs

The three main GHGs that are relevant to the petroleum and natural gas industry are methane (CH 4 ), CO 2 , and nitrous oxide (N 2 O). This technical document will focus mainly on CH 4 and

CO 2 emissions from fugitive and vented emissions. However, all three gases are taken into account when developing the threshold analysis.

Emissions from sources in the petroleum and gas industry can be classified into one of two

types:

Combustion-related emissions

Combustion-related emissions result from the use of petroleum and natural gas as fuel in equipment (e.g., heaters, engines, furnaces etc) in the petroleum and gas industry. CO 2 is the predominant combustion-re lated emission; however, because combustion equipment is rarely 100 percent efficient, CH 4 and N 2 O may also be emitted. For methodologies to quantify GHG emissions from combustion, please refer to Subpart C of the MRR.

Fugitive emissions and vented emissions

The Intergovernmental Panel on Climate Change (IPCC) and the Inventory of U.S.

GHG Emissions and Sinks 1 (henceforth referred to as the U.S. GHG Inventory) define fugitive emissions to be both in tentional and unintentional emissions from systems that extract, process, and deliver fossil fuels. Intentional emissions are emissions designed into the equipment or system. For example, reciprocating compressor rod packing has a certain level of emissions by design, e.g., there is a clearance provided between the packing a nd the compressor rod for free movement

of the rod that results in emissions. Also, by design, ve nt stacks in petroleum and natural gas production, natural gas proces sing, and petroleum refining facilities release natural gas to the atmosphere. Unintentional emissions result from wear and

1 U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006, (April 2008), USEPA #430-R-08-005

Background Technical Support Document – Petroleum and Natural Gas Industry 6tear or damage to the equipment. For example, valves result in natural gas

emissions due to wear and tear from c ontinuous use over a period of time. Also, pipelines damaged during maintenance operations or corrosion result in

unintentional emissions.

However, defining fugitive emissions as un intentional and intentional led to a great deal of confusion in the initial rule proposal . Also, such a definition is not intuitive in that fugitive in itself means unintenti onal. Therefore, this document henceforth distinguishes fugitive emissions clearly from vented emissions.

Fugitive emissions are emissions which are uninten tional and could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening.

Vented emissions means intentional or designed releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not incl uding stationary combustion flue gas), including but not limited to process desi gned flow to the atmosphere through seals or vent pipes, equipment blowdown for main tenance, and direct venting of gas used to power equipment (such as pneumatic devices).

This document includes methodologies to quantify fugitive and vented emissions of

CO 2 and CH 4

.



### 3. GHG Emissions from the Petr oleum and Natural Gas Industry

The U.S. GHG Inventory provides estimates of fugitive and vented CH 4 and CO 2 emissions from all segments of the petroleum and natu ral gas industry. These estimates are based mostly on emissions factors available from two major studies conducted by EPA/Gas Research Institute (EPA/GRI) 2 for the natural gas segment and EPA/Radian 3 for the petroleum segment. These studies were conducted in the early and late 1990s respectively.

The EPA/GRI study used the best available da ta and somewhat restricted knowledge of industry practices at the time to provide estimates of emissions from each source in the various segments of the natural gas industry. In addition, this study wa s conducted at a time

when CH 4 emissions were not a significant concer n in the discussion about GHG emissions. Over the years, new data and increased knowle dge of industry operations and practices have highlighted the fact that emissions estim ates from the EPA/GRI study are outdated and potentially understated for some emissions s ources. The following emissions sources are believed to be significantly underestimated in the U.S. GHG Inventory: well venting for liquids unloading; gas well ve nting during well completions; ga s well venting during well workovers; crude oil and conde nsate storage tanks; centrifugal compressor wet seal degassing venting; and flaring.

2 EPA/GRI (1996) Methane Emissions from the Natural Gas Industry . Prepared by Harrison, M., T. Shires, J. Wessels, and R. Cowgill, eds., Radian International LLC for National Risk Management Research Laboratory, Air Pollution Prevention and Control Division, Research Triangle Park, NC. EPA-600/R-96-080a.

3 EPA (1996) Methane Emissions from the U.S. Petroleum Industry (Draft) . Prepared by Radian. U.S. Environmental Protection Agency. June 1996.

Background Technical Support Document – Petroleum and Natural Gas Industry 7The understatement of emissions in the U.S. GHG Inventory were re vised using publicly available information for all sources, excep t crude oil and condensate storage tanks and flares, where no new reliable data are available 4 . Appendix B provides a detailed discussion on how new estimates were developed for each of the four undere stimated sources. Table 1 provides a comparison of emissi ons factors as available fr om the EPA/GRI study and as

revised in this document. Table 2 provides a comparison of emissions from each segment of the natural gas industry as ava ilable in the U.S. GHG Inventor y and as calculated based on

the revised estimates for the four underestimated sources.

Table 1: Comparison of Emissions Factor s from Four Updated Emissions Sources

Emissions Source Name EPA/GRI

Emissions Factor (CH 4 – metric tons/year) Revised

Emissions Factor (CH 4 – metric tons/year)

1) Well venting for liquids unloading 1.02 11

2) Gas well venting during completions

Conventional well completions 0.02 0.71

Unconventional well completions 0.02 177

3) Gas well venting during well workovers

Conventional well workovers 0.05 0.05

Unconventional well workovers 0.05 177

4) Centrifugal compressor wet seal degassing venting 0 233

1. Conversion factor: 0.01926 metric tons = 1 Mcf

4 EPA did consider the data available from two new studies, TCEQ (2009) and TERC (2009). However, it was

found that the data available from the two studies rais e several questions regarding the magnitude of emissions from tanks and hence were not found appropriate for an y further analysis until the issues are satisfactorily understood and/ or resolved by the authors and covered parties.

Background Technical Support Document – Petroleum and Natural Gas Industry 8Table 2: Comparison of Process Emissions from each Segment of the Natural Gas and

Petroleum Industries

Segment Name U.S. GHG Inventory 1

Estimate for Year 2006 (MMTCO 2 e) Revised Estimate for

Year 2006 (MMTCO 2 e)

Production 2 90.2 186.4

Processing 33.1 31.7

Transmission and Storage 38.3 64.0

Distribution 24.7 25.3

1. U.S. EPA (2008) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006.

2.Production includes fugitive and vented emissions from both the natural gas and petroleum sectors’ onshore and offshore facil ities.

After revising the U.S. GHG Inventory for the four updated sources, fugitive CH 4 and CO 2 emissions from the petroleum and natural gas industry were 307.4 million metric tons of CO 2 equivalent (MMTCO 2 e) in 2006. Overall, the natura l gas industry emitted 257.2 of CH 4 and

23.6 MMTCO 2 e of CO 2 in 2006. Total CH 4 and CO 2 emissions from the petroleum industry

in 2006 were 26.3 MMTCO 2 e and 0.3 MMTCO 2 e respectively

.

Petroleum Segment Crude oil production operations account ed for over 97 percent of total CH 4 emissions from the petroleum industry. Crude oi l transportation activities account ed for less than one half of a percent of total CH 4 emissions from the oil industry. Cr ude oil refining pr ocesses accounted for slightly over two percent of total CH 4 emissions from the petroleum industry because

most of the CH 4 in crude oil is removed or escapes before the crude oil is delivered to the petroleum refineries. The United States currently estimates CO 2 emissions from crude oil production operations only in the U.S. GHG I nventory. Research is underway to include other larger sources of CO 2 emissions in future inventories.

Natural Gas Segment Emissions from natural gas production accounted for approximately 66 percent of CH 4 emissions and about 25 percent of non-energy CO 2 emissions from the natural gas industry in 2006. Processing facilities accounted for about 6 percent of CH 4 emissions and approximately 74 percent of non-energy CO 2 emissions from the na tural gas industry. CH 4 emissions from the natural gas transmission and storage segment accounted for approximately 17 percent of emissions, while CO 2 emissions from natural gas transmission and storage accounted for less than one percent of the non-energy CO 2 emissions from the natural gas industry. Natural gas distribu tion segment emissions, which account for approximately 10 percent of CH 4 emissions from natural gas systems and less than one percent of non-energy CO 2 emissions, result mainly from fugitive emissions from gate stations and pipelines.



### 4. Methodology for Selection of Indu stry Segments and Emissions Sources Feasible for Inclusion in a Mandatory GHG Reporting Rule

Background Technical Support Document – Petroleum and Natural Gas Industry 9It is important to develop criteria to help identify GHG emissions sources in the petroleum and natural gas industry most likely to be of in terest to policymakers. To identify sources for inclusion in a mandatory GHG reporting rule, two preliminary steps were taken; 1) review existing regulations to identify emissions s ources already being regul ated, and 2) review existing programs and guidance documents to identify a comprehensive list of emissions sources for potential inclus ion in the proposed rule.

The first step in determining emissions sources to be included in a mandatory GHG reporting rule was to review existing re gulations that the industry is subject to. Reviewing existing reporting requirements highlighted those sources that are currently subject to regulation for other pollutants and may be good candidates for addressing GHG emissions. The second step was to establish a comprehensive list of em issions sources from the various existing programs and guidance documents on GHG emissi ons reporting. This provided an exhaustive list of emissions sources for the purposes of this analysis and avoided the exclusion of any emissions sources already being monitored for reporting under other program(s). Both of these steps are described below.



### a. Review of Existing Regulations

The first step was to understand existing regula tions and consider adapting elements of the existing regulations to a mandatory reporting rule for GHG emissions. At this time, there are three emissions reporting regulations and six em issions reduction regula tions in place for the petroleum and natural gas industry, includi ng one voluntary reporting program included in the Code of Federal Regulations. This table also includes EPA’s Fi nal Mandatory Reporting Rule, which requires certain oi l and gas facilities to re port their combustion-related

emissions. Table 3 provides a summary of each of th ese nine reporting and reduction regulations.

Table 3: Summary of Regulations Related to the Petroleum and Natural Gas Industry

Regulation Type Point/ Area/ Major/ Mobile

Source Gases

Covered Segment and Sources

EPA 40 CFR Part 98 Final Mandatory Reporting of

Greenhouse Gases

Rule Mandatory

Emissions Reporting Point, Area, Biogenic CO 2 , CH 4 , N 2 O, HFCs, PFCs, , SF 6 , NF 3 , and HFE All facilities that emit 25,000 metric tons or more per year of GHG.

EPA 40 CFR Part 51 –

Consolidated Emissions Reporting Emissions Reporting Point, Area, Mobile, VOCs, NOx, CO, NH 3 , PM 10 , PM 2.5 All segments of the petroleum and natural gas industry

DOE 10 CFR Part 300 – Voluntary GHG Reporting Voluntary

GHG Reporting Point, Area,

Mobile CO 2 , CH 4 , N 2 O, HFCs, PFCs, , SF 6 , and CFCs All segments of the petroleum and natural gas industry

Background Technical Support Document – Petroleum and Natural Gas Industry 10EPA 40 CFR Part 60, Subpart KKK NSPS 2 Point VOCs Onshore processing plants; sources include compressor stations, dehydration units, sweetening units, underground storage tanks, field gas gathering systems, or liquefied natural gas units located in the plant
EPA 40 CFR Part 60, Subpart LLL NSPS 2 Point SO 2 Onshore processing plants; Sweetening units, and sweetening units followed by a sulfur recovery unit
EPA 40 CFR Part 63,,

NESHAP 1

, , Subpart

HHH MACT 3 Point (Glycol dehydrators, natural gas

transmission and storage facilities) HAPs Glycol dehydrators

EPA 40 CFR Part 63,

NESHAP 1 , Subpart

HH MACT 3 Major and Area (petroleum and natural gas production, up to and including processing plants) HAPs Point Source - Glycol dehydrators and tanks in petroleum and natural gas production; equipment leaks at gas processing plants Area Source - Triethylene glycol (TEG) dehydrators in petroleum and natural gas production
EPA 40 CFR Part 63,

NESHAP 1 , –Subpart

YYYY MACT 3 Major and Area (Stationary

Combustion Turbine) HAPs All segments of the petroleum and natural gas industry

EPA 40 CFR Part 63,

NESHAP 1 , Subpart

ZZZZ MACT 3 Major and Area (Reciprocating

Internal

Combustion Engines) HAPs All segments of the petroleum and natural gas industry

Notes:

1 National Emission Standards for Hazardous Air Pollutants

2 New Source Performance Standard

3 Maximum Allowable Control Technology

Table 3 , indicates that only DOE 10 CFR Part 300 includes the monitoring or reporting of

CH 4 emissions from the petroleum and natural gas industry. However, this program is a voluntary reporting program and is not expected to have a co mprehensive coverage of CH 4 emissions. Although some of the sources incl uded in the other regulations lead to CH 4 emissions, these emissions are not reported. The MACT regulated sources are subject to Part 70 permits which require the reporting of all major HAP emission sources, but not GHGs. GHG emissions from petroleum and natural gas operations are not systematically monitored and reported; therefore these regulations and programs can not serve as the foundation for a mandatory GHG emissions reporting rule.

Background Technical Support Document – Petroleum and Natural Gas Industry 11Background Technical Support Document – Petroleum and Natural Gas Industry 12 

### b. Review of Existing Programs

The second step was to review existing mon itoring and reporting programs to identify all emissions sources that are already monitored under these programs. Six reporting programs and six guidance documents were reviewed. Table 4 summarizes this review, highlighting monitoring points identified by the programs and guidance documents.

Table 4 shows that the different monitoring prog rams and guidance documents reflect the points of monitoring identified in the U.S. GH G Inventory, which are consistent with the range of sources covered in the 2006 IPCC Guidelines. Therefore, the U.S. GHG Inventory was used to provide the initial list of emissions sources for determining the emissions sources that can be potentially included in the proposed rule.

The preliminary review provided a potential list of sources, but did not yield any definitive indication on the emissions sources that were most suitable for potential inclusion in a reporting program. A systematic assessment of em issions sources in the oil and natural gas industry was then undertaken to identify the specific emissions sources (e.g., equipment or component for inclusion in a mandatory GHG reporting rule.Table 4: Summary of Program and Guidance Documents on GHG Emissions Monitoring and ReportingReportingProgram/GuidanceSource Category(or Fuel)Coverage (Gases orFuels)Points of MonitoringMonitoringMethods and/or GHG CalculationMethods*2006 IPCC Guidelines forNational GHG Inventory,Volume 2, Chapter 4Petroleum and Gas– all segmentsCH4, non-combustionCO2and other GHGgasesOil and natural gas systemsfugitive equipment leaks,evaporation losses, venting,flaring, and accidentalreleases; and all other fugitiveemissions at oil and naturalgas production, transportation,processing, refining, anddistribution facilities fromequipment leaks, storagelosses, pipeline breaks, wellblowouts, land farms,gas migration to the surfacearound the outside of wellheadcasing, surface casing ventbows, biogenic gas formationfrom tailings ponds and anyother gas or vapor releases notspecifically accounted for asventing or flaringAccounting/ reporting methodologies and guidelinesCompanies choose a base year for which verifiableemissions data are available. The base year emissionsare used as an historiccontrol against which thecompany's emissions are tracked over time. Thisensures data consistency over time. Directmeasurement of GHG emissions by monitoringconcentration and flow rate can also be conducted.IPCC methodologies are broken down into thefollowing categories:-Tier I calculation-based methodologies forestimating emissions involve the calculation ofemissions based on activity data and defaultindustry segment emission factors-Tier II calculation-based methodologies forestimating emissions involve the calculation ofemissions based on activity data and countryspecific industry segmentemission factors or byperforming a mass balance using countryspecific oil and/or gas production informationTier III calculation-based methodologies for estimatingemissions involve "rigorous bottom-up assessment byprimary type of source (e.g. evaporation losses,equipment leaks) at the individual facility level withappropriate accounting of contributions fromtemporary and minor field or well-site installations.The calculation of emissions is based on activity dataand facility-specific emission factorsAGA - Greenhouse GasEmissions EstimationMethodologies,Procedures, and GuidelinesGas – DistributionCH4, non-combustionCO2and other GHGgasesSegment-level counts,equipment discharges (i.e.valves, open-ended lines, ventstacks), and segmentEquipment or segment emissions rates and engineeringcalculationsTier I, II (IPCC) - facility level emissions ratesBackground Technical Support Document –Petroleum and Natural Gas Industry13for the Natural GasDistribution Sectorcapacities, facility counts andcapacitiesTier III (IPCC) - equipment emissions rates forintentional emissions, process level emissions rates,and process/equipment level emissions rateAPI - Compendium ofGHG Emissions EstimationMethodologies for the Oiland Gas IndustryGas and Petroleum– all segmentsCH4, non-combustionCO2Equipment discharges (e.g.valves, open-ended lines, ventstacks), vent stacks forequipment types, tankPRV/vents, and facility inputEquipment or segment emissions rates and engineeringcalculationsTier II (IPCC) - facility level emissions ratesTier III (IPCC) - equipment emissions rates forintentional emissions, process level emissions rates,tank level emissions rates, and process/equipment levelemissions rate (BY SEGMENT)California Climate ActionRegistry General ReportingProtocol, March 2007All legal entities(e.g. corporations,institutions, andorganizations)registered inCalifornia,includingpetroleum and gas– all segmentsCH4, non-combustionCO2and other GHGgasesAll activities resulting inindirect and direct emission ofGHG gases for the entityProvides references for use in making fugitivecalculationsThe CCAR does not specify methodology to calculatefugitive emissionsCalifornia Mandatory GHGReporting ProgramPetroleum –RefineriesCH4, non-combustionCO2and other GHGgasesAll activities resulting in CH4and CO2fugitive emissions forpetroleum refineriesContinuous monitoring methodologies and equipmentor process emissions ratesCO2process emissions can be determined bycontinuous emissions monitoring systems. Methods forcalculating fugitive emissions and emissions fromflares and other control devices are also availableDOE Voluntary Reportingof Greenhouse GasesProgram (1605(b))Petroleum andGas- All SegmentsCH4, non-combustionCO2and other GHGgasesAll activities resulting indirect and indirect emissionsof GHG gases for thecorporation or organizationDirect, site-specific measurements of emissions or allmass balance factorsMass-balance approach, using measured activity dataand emission factors that are publicly documented andwidely reviewed and adopted by a public agency, astandards-setting organization or an industry groupMass-balance approach, using measured activity dataand other emission factorsBackground Technical Support Document –Petroleum and Natural Gas Industry14Mass balance approach using estimated activity dataand default emissions factors.EU ETS 1stand 2ndReporting PeriodPetroleum –RefiningNon-combustion CO2Hydrogen productionEngineering calculationsOperators may calculate emissions using a massbalance approachINGAA - GHG EmissionsEstimation Guidelines forNatural Gas Transmissionand Storage, Volume 1Gas -Transmission/StorageCH4, non-combustionCO2Segment-level counts,equipment discharges (i.e.valves, open-ended lines, ventstacks), and segmentcapacities, facility counts andcapacitiesEquipment or segment emissions ratesTier I (IPCC)- segment level emissions rates fromintentional and unintentional releasesTier II - equipment level emissions rates for intentionalreleasesTier II (IPCC) – facility and equipment level emissionsrates for unintentional leaksEngineering calculation methodologies for:- Pig traps- Overhauls- FlaringIPIECA - PetroleumIndustry Guidelines forReporting GHG EmissionsPetroleum and Gas– all segmentsCH4, non-combustionCO2and other GHGgasesRefers to API Compendiumpoints of monitoring:Equipment discharges (e.g.valves, open-ended lines, ventstacks), vent stacks forequipment types, tankPRV/vents, and facility inputTiers I, II, and III (IPCC) definitions and reportingmethods for all fugitive and vented GHG emissions inthe oil and gas industryNew Mexico GHGMandatory EmissionsInventoryPetroleumrefineriesCO2reporting starts2008 , CH4reportingstarts 2010Equipment discharges (e.g.valves, pump seals,connectors, and flanges)-2009 reporting procedures will be made availablein 10/2008Background Technical Support Document –Petroleum and Natural Gas Industry15Background Technical Support Document –Petroleum and Natural Gas Industry16The Climate Registry(General ReportingProtocol for the VoluntaryReporting Program), 2007All legal entities(e.g.corporations,institutions, andorganizations)includingpetroleum andgas – allsegmentsCH4, non-combustionCO2and other GHGgasesAll activities resulting inemission of GHG gases for theentityContinuous monitoring methodologies and equipmentor process emissions ratesMeasurement-based methodology monitor gas flow(continuous, flow meter) and test methaneconcentration in the flue gas. Calculation-basedmethodologies involve the calculation of emissionsbased on activity data and emission factorsWestern Regional AirPartnership (WRAP)Petroleum andGas – allsegmentsCH4, non-combustionCO2and other GHGgasesAll activities resulting inemission of GHG gases for theentityProvides quantification methods for all sources from allsectors of the petroleum and gas industry considered inthe rule. Quantification methods are typicallyengineering equation; however, parameters for theequations in several cases require measurement of flowrates, such as from well ventingWorld Resources Institute/World Business Councilfor SustainableDevelopment GHGProtocol CorporateStandard, Revised Edition2003Organizationswith operationsthat result inGHG (GHG)emissions e.g.corporations(primarily),universities,NGOs, andgovernmentagencies. Thisincludes the oiland gas industryCH4, non-combustionCO2and other GHGgasesAll activities resulting indirect and indirect emission ofGHG gases for the corporationor organizationProvides continuous monitoring methodologies andequipment or process emissions ratesCompanies need to choose a base year for whichverifiable emissions data are available and specify theirreasons for choosing the year. "The base yearemissions are used as an historic datum against whichthe company's emissionsare tracked over time.Emissions in the base yearshould be recalculated toreflect a change in the structure of the company, or toreflect a change in the accounting methodology used.This ensures data consistency over time." Directmeasurement of GHG emissions by monitoringconcentration and flow rate can be conducted.Calculation-based methodologies for estimatingemissions involve the calculation of emissions basedon activity data and emission factors

### c. Selection of Emissions Sources for Reporting

When identifying emissions sources for in clusion in a mandatory reporting rule, two questions need addressing. The first is defini ng a facility. In other words, what physically constitutes a facility? The second is determinin g which sources of emissions should a facility report? Including or excludi ng sources from a mandatory reporting rule without knowing the definition of a facility is difficult. Ther efore, both the facility definition and emissions source inclusion (or exclusion) were studied independently and finally reviewed together to

arrive at a conclusion.



### i. Facility Definition Characterization

Typically, the various regulations under the Clea n Air Act (CAA) define a facility as a group of emissions sources all located in a contiguous area and under the control of the same person (or persons under common control) . This definition can be eas ily applied to onshore natural gas processing and petroleum re fining facilities since the operations are all located in a clearly defined boundary. Onshore natural gas tr ansmission compressor stations also can be clearly identified using this definition. However, this definition does not as directly lend itself to onshore petroleum a nd natural gas production, onshor e natural gas transmission pipelines and natural gas distribution, and petroleum trans portation sectors.

Petroleum and natural gas produ ction facilities can be very diverse in arrangement. Sometimes crude oil and natural gas produci ng wellheads are far ap art with individual equipment at each wellhead. At other times several wells in close proximity are connected to common pieces of equipment. The choice of whether multiple wells are connected to common equipment depends on factors such as distance between wells, production rate, and ownership and royalty payment. New well dr illing techniques such as horizontal and directional drilling allo w for multiple wellheads to be loca ted at a single location (or pad) from where they are drilled to connect to diffe rent zones in the same reservoir. Therefore, finding a single definition of a facility that can be applied to all of onshore petroleum and natural gas production can be challenging. In addition, there are several hydrocarbon resource ownership and operational equipment ownership issues relating to the onshore petroleum and natural gas production segment. In many cases, the mine ral rights are not necessarily owned by the land owner. This is pr evalent mostly in the western half of the United States where the Bureau of Land Manage ment owns major portions of the minerals rights whereas the lands are held by privat e owners. Also, multiple operators commonly operate in a single production operation. For example, in the onshore production segment, multiple operators are responsible for different equipment in the same field under different ownership.

An alternative to a physical facility defini tion is the use of a co rporate level reporter definition. In such a case the corporation that owns or operates petroleum and natural gas production operations could be re quired to report. Here the threshold for reporting could require that an individual corporation sum up GHG emissions from all the fields it is operating in and determine if its total emissions surpass the threshold. There is a precedent in subpart NN of the Final Mandatory Reporting Rule (MRR) for corporate reporting, where

Background Technical Support Document – Petroleum and Natural Gas Industry 17local distribution companies are required to report the volumes of natural gas that they sell to end customers. See Appendix E for fu rther discussion of this issue.

Natural gas transmission and petroleum transp ortation pipelines run over several hundred

thousand miles in the United States. There are no id entifiers (or markers) that can be used to readily assign a portion of the pipelines as a si ngle facility. Moreover, emissions sources in pipelines are spread across large geographica l areas making it difficult to use the common

definition available from the CAA. The natural gas distribution segment has issues similar to the onshore natural gas transmission segment in defining facilities for the extensive pipeline network. The meters and regulators in the distribution segment are mainly in small underground vaults in urban areas . Individually defining each va ult as a facility is again impractical owing to the size a nd expected magnitude of emissi ons from a single vault. It may also not be immediately obvious to include multiple vaults to define a facility, as they are not in a contiguous area. However, similar to the onshore production segment, local distribution companies could poten tially report at a corporate level. The precedence for this type of reporting already ex ists under the Pipeline and Hazardous Materials Safety Administration (PHMSA) requirements under CFR Title 49 Section 191.11. See Appendix E

for further discussion of this issue.

Gathering pipelines collect produc ed natural gas from petroleu m and natural gas fields and direct it to either processing plants, transmission systems, or in some cases directly to end use customers via distribution system. The definitional issue with gathering pipelines is similar to transmission and distribution systems in that pi pelines cannot be physically demarcated into a facility. However, there is an additional issue in regard to gathering pipelines. Unlike other segments of the petroleum and natural gas industry, gathering systems may be owned by producers, processing plants, transmission comp anies, local distribution companies, or independent gathering companies. Therefore, it is difficult to assign this portion of onshore production to one particular segment. One opti on is to require gathering pipelines to be reported as an emissions source. The other opti on is to have a separate segment assigned to gathering pipelines. See Appendix F fo r further discussion on the options.



### ii. Selection of Potential Em issions Sources for Reporting

Given that there are over 160 emissions sources in the petroleum and natural gas industry, it is important to target sources which contribute significantly to the total national emissions for the industry. This avoids an excessive reporting burden on the i ndustry, but at the same time enables maximum coverage for emissions repor ting. The selection of emissions sources for potential inclusion in the proposed ru lemaking was conducted in three steps.

Step 1: Characterize Emissions Sources The U.S. GHG Inventory was used as the comp lete list of sources und er consideration for inclusion in a reporting rule. The U.S. GHG Inve ntory was also used to provide all relevant emissions source characteristics such as type, number of sources across industry segments, geographic location, emissions per unit of output, total national emissions from each emissions source, and frequency of emissions. Also, information included in the U.S. GHG Inventory and the Natural Gas STAR Program technical studies was used to identify the

Background Technical Support Document – Petroleum and Natural Gas Industry 18different monitoring methods that are considered the best for each emissions source. If there are several monitoring methods fo r the same source, with equiva lent capabilities, then the one with lower economic burden was considered in the analysis.

Step 2: Identify Selection Criteria a nd Develop Decision Tree for Selection There are several factors that impact the decision on whether an emissions source should be included for reporting. A discussion of the factors follows below.

• Significant Contributio n to U.S. GHG Inventory – Emissions sources that contribute significant emissions can be considered for po tential inclusion in the rule, since they increase the coverage of emissions reporting. Typically, in oil and natural gas facilities, 80 percent or more of the f acility emissions are reported to be from approximately 10 percent of the emissions sources. This is a good benchmark to ensure the adequate coverage of emissions while reducing the nu mber of emissions sources required for reporting thus, keeping the repo rting burden to a minimum. Emissions sources in each segment of the natural gas and petroleum industr y can be sorted into two main categories: (1) top sources contributing to 80 percent of the emissions from the segment, and (2) the remaining sources contributing to the remain ing 20 percent of the emissions from that particular segment. This can be easily achieved by determ ining the emissions

contribution of each emissions source to the segment it belongs t o, listing the emissions sources in a descending order, and identifying all the sources at the top that contribute to 80 percent of the emissions. Appendix A provide s a listing of all emissions sources in the U.S. GHG Inventory and a breakdown of the top emissions sources and their contributions to their respective segment emissions.

• Type of Emissions – The magnitude of emissions per unit or piece of equipment typically depends on the type of emissions. Vented emissions per unit source are usually much higher than fugitive emissions from a unit source. For example, emissions from compressor blowdown venting for one comp ressor are much higher than fugitive emissions from any one unit component so urce on the compressor. The burden from covering emissions reporting from each unit source (i.e. dollar per ton of emissions reported) is typically much lower in the case of venting sources in comparison to fugitive emissions sources when the same monitoring method is used. Therefore, vented sources could be treated separately from fugitiv e sources for assessment of monitoring requirements.

• Best Practice Monitoring Method(s) – Depending on the types of monitoring methods typically used, a source may or may not be a potential for emissions reporting. There are four types of monitoring methods as follows:

o Continuous monitoring – refe rs to cases where technologies are available that continuously monitor either the emissions fr om a source or a related parameter that can be used in estimating emissions. For example, continuous monitoring meters

can determine the flow rate and in line analyzers can determine the composition of emissions from a process vent.

Background Technical Support Document – Petroleum and Natural Gas Industry 19o Periodic monitoring – refers to monitori ng at periodic intervals to determine emissions from sources. For example, leak detection and measurement equipment can be used on a recurring basis to iden tify and measure an em issions rate from equipment.

o Engineering calculations – refers to es timation of emissions using engineering parameters. For example, emissions from a vessel emergency release can be estimated by calculating the volume of the emitting vessel.

o Emissions factors – refers to utilizing an existing emissions rate for a given source and multiplying it by the relevant activity data to estimate emissions. For example, emissions per equipment unit per year can be multiplied by the number of pieces of equipment in a facility to estimate annual emissions from that equipment for the facility.

• Accessibility of emissions sources – Not all emissions sources are directly accessible physically for emissions dete ction and/or measurement. For example, connectors on pipelines, pressure relief valves on equipmen t, and vents on storage tanks may be out of direct physical reach and could require the us e of bucket trucks or scaffolding to access them. In such cases requiring emissions de tection and measurement may not always be feasible. Also, such requirements could pose he alth and safety hazards or lead to large cost burden. The accessibility of emissions sour ces has to be considered when addressing monitoring requirements.

• Geographical dispersion of emissions sources – The cost burden for detecting and measuring emissions will largely depend on th e distance between various sources. For example, visiting individual onshore petroleum and natural gas production wells spread across large distances for emissions surveys wi ll require excessive travel time and result in a large cost burden. Compressors at compre ssor stations on the other hand are located in close proximity.

• Applicability of Population or Leaker Emission factors – When the total emissions from all leaking sources of th e same type are divided by the total count of that source type then

the resultant factor is referre d to as population emissions f actor. When the total emissions from all leaking sources of th e same type are divided by the total count of leaking sources for that source type then the resultant factor is referred to as leaker emissions factor. For example, in a emissions detection and measur ement study if 10 out of 100 valves in the facility are found leaking then:

o the total emissions from the 10 valves divided by 100 is referred to as population emissions factor

o the total emissions from the 10 valves di vided by 10 is referr ed to as leaker

emissions factor

The implication of these two types of emissi ons factor is as follows. The proposed rule could potentially ask for emissions detection only with the correspond ing application of a

leaker emissions factor. In such a case the burden for actual measurement is avoided. In addition, the use of leaker emissions fact ors will provide an estimate of “actual”

Background Technical Support Document – Petroleum and Natural Gas Industry 20emissions as opposed to the use of population emissions factor where the emissions from each facility can only be a "potential” of emissions. Based on the criteria outlined above, a decision process was developed to identify the potential sources that could be included in a reporting rule. Figure 1 shows the resulting decision tree that includes these criteria and supported the decision-making process. The cost for monitoring from each emissions source varies greatly for oil and gas production and

hence will have to be dealt with in addition to the deci sion tree. The decision process provided in Figure 1 was applied to each emissions source in the natural gas segment of the U.S. GHG Inventory. The petroleum onshore pr oduction segment has emissions sources that either are equivalent to their counterparts in the natural gas onshore segment or fall in the 20 percent exclusion category. Only CH 4 emissions were taken into consideration for this exercise given that, for most sources, fugitive CO 2 emissions are negligible in comparison to

CH 4 emissions from the same sources. Appendix A summarizes the results of this analysis and provides guidance on the feasibility of each of the monitoring options discussed previously.

Background Technical Support Document – Petroleum and Natural Gas Industry 21Is emissions source a fugitive?

Is source accessible for fugitive detection?

Use fugitive detection

and leaker emission

factor to estimate

emissions Use population

emissions factor

and source count

to estimate

emissions No No Yes No

Is vented emissions source geographically dispersed? Does credible

emission factor

exist? Yes

Use population

emissions factor and

source count to
estimate emissions Yes

Use Engineering

Estimation

method No Does engineering estimation methodology

exist? No

Use Engineering

Estimation

method Yes

Use continuous or period monitoring No Is source contributing to top 80% of emissions from each segment?

Yes No Potentially exclude

Is fugitive emissions

source geographically dispersed? Yes Yes

Figure 1: Decision Process for Emissions Source Selection

Background Technical Support Document – Petroleum and Natural Gas Industry 22

### iii. Address Sources with Large Uncertainties

The natural gas and petroleum industry inve ntories are based on a U.S. EPA and Gas Research Institute Study 5 published in 1996. There are several estimates of emissions factors for emissions sources that do not correctly reflec t the operational practices of today. Hence in

some cases the estimates either under or over count volume of emissions from these sources. From anecdotal evidence from the industry, it is believed that emissions from some sources may be much higher than currently reported in the U.S. GHG Inventory. In most cases sufficient information is not publicly availabl e to make changes to the national Inventory estimates. In other cases where public data are available, it is often incomplete and does not represent the industry at a national level. Th e decision tree was not necessarily ideal for

sources known to be over- or underestimated in current inventories, which use existing emission factors. Therefore, the decision tree was overridden for these sources. The sources for consideration under this exception are:

o Condensate and oil storage tanks

o Natural gas well workovers

o Natural gas well completions

o Natural gas well blowdowns

o Centrifugal compressor wet seals

o Flares

In addition, the U.S. GHG Inventory includes CH 4 and CO 2 emissions from natural gas engines and turbines, as well as petroleum refine ries. Emissions from these sources were not

considered further here because methods for calculating and reporting emissions from these sources are addressed in the background t echnical support documents for Stationary Combustion described in Subpa rt C of the Final Mandator y Reporting Rule (MRR) and

Petroleum Refineries described in Subpart Y of the Final Mandatory Reporting Rule (MRR) respectively.



### iv. Identify Sources to be Included

Based on the understanding of facility definiti ons for each segment of the oil and gas industry and the identification of potential sources for incl usion in a mandatory reporting rule, the potential segments and sources to be included were identified. A brief analysis for each segment is as follows;

 Onshore Petroleum and Natural Gas Production Segment

– Onshore petroleum and natural gas production is an important segment for inclusion in a GHG reporting program, due to its relatively large share of emissions. Ho wever, in order to include this segment, it is important to clearly artic ulate how to define th e facility and identify who is the reporter. For some segments of the industry, identi fying a facility is straightforward since there are clear physical boundaries and owne rship structures

5 U.S. Environmental Protection Agency/ Gas Research Institute, Methane Emissions from the Natural Gas Industry, June 1996.

Background Technical Support Document – Petroleum and Natural Gas Industry 23Onshore production operations are a challe nge for emissions reporting using the conventional facility definition of a “c ontiguous area” under a common owner/ operator. EPA proposes to define a hydrocar bon producing basin as a facility and all operators report their emissions on a basin level. In such a case, the company (or corporation) operating in multiple fields in the same basin can report at the basin level. The operator could be the company or corporation holding the required state or federal permit for drilling or ope rating. Reporting emissions from all potential

emissions sources at a basi n level would substantially increase reporting burden but the complexity of reporting requirements would be substantia lly reduced. Another possible alternative is to define a producti on field as a facility. In such cases, the company (or corporation) operating in the fi eld can report emissi ons. However, such

field level definition can result in lower c overage than basin level reporting, since fields are typically a segment of a basin.

In addition to basin and field level repor ting, one alternative op tion is identifying a facility as an individual well pad, including all stati onary and portable equipment operating in conjunction with that well, in cluding drilling rigs w ith their ancillary equipment, gas/liquid separators, compre ssors, gas dehydrators, crude oil heatertreaters, gas powered pneumatic instruments and pumps, electrical generators, steam boilers and crude oil and gas liquids stock tanks. This definition was analyzed with available data including four cases to represent the full ra nge of petroleum and natural gas well pad operations:

• Case 1 (highest well pad emissions ): Drilling and completion of an unconventional gas well early in the year with the well produci ng the remainder of the year with a full complement of comm on, higher process emissions equipment on the well pad including a compressor, glycol dehydrator, gas pneumatic controllers, and condensate tank without vapor recove ry. We assumed that unconventional well completion does not employ "Reduced Emissions Completion" practices.

• Case 2 (second highest well pad emissi ons): Drilling and completion of a conventional gas well early in the year w ith the well producing th e remainder of the year with a full complement of common, higher process emissions equipment on the well pad including a compressor, glycol dehydrator, gas pneumatic controllers, and condensate tank without vapor recovery.

• Case 3 (third highest well pad emissi ons): Drilling and completion of a conventional oil well early in the year w ith the well producing the remainder of the year with a full complement of common, higher process emissions equipment on the well pad including an associated gas compre ssor, glycol dehydrator, gas pneumatic

Background Technical Support Document – Petroleum and Natural Gas Industry 24controllers, chemical injection pump, an oil heater-treater, and a crude oil stock tank without vapor recovery.

• Case 4 (fourth highest well pad emissions ): Production at an associate gas and oil well (no drilling) with a compressor, dehydrator, gas pneumatics, oil heater/treater and oil stock tank without vapor recovery.

Facility definitions identif ying a single wellhead as a f acility could significantly increase the number of reporters to a pr ogram, and potentially raise implementation

issues.

One way to reduce the reporting burden, due to the large numb er of sources, would be to focus on the largest c ontributors to GHG emissions. From the EPA Natural Gas STAR experience in mitigating methane emissions in the onshore petroleum and natural gas production segment, the major c ontributors to emissions from the onshore production segment are easily identifiable. Th ese emissions sources are not reflected as major sources in the U.S. GHG Inventory as the inventory estimates are based on a 1992 measurement study 5 that, in the case of these sources, was based on limited

data. Based on current know ledge of the petroleum and natural gas industry, the following seven emissions sources are known to be the major contributors to the total petroleum and natural gas production segment emissions: natural gas driven pneumatic valve and pump devices, well completion releases and flaring, well blowdowns, well workovers, crude oil and c ondensate storage tanks, dehydrator vent stacks, and reciprocating compressor rod packi ng. With a basin level, field level, or well-head level facility definition, onshore production segment operators or companies could report emissions from th e seven major emissi ons sources listed

above.

 Offshore Petroleum and Natural Gas Production Segment – All of the production activities offshore take place on platforms. These platforms can be grouped into two main categories; wellhead platforms and processing platforms. Wellhead platforms consist of crude oil and/ or natural gas producing wellheads that are connected to processing platforms or send the hydrocar bons onshore. Processing platforms consist of wellheads as well as pro cessing equipment such as sepa rators and deh ydrators, in addition to compressors. All platforms ar e within a confined area and can be distinctly identified as a facility. Since all sources are within a small area on and around the platform, all sources of emissions on or associated with offshore platforms could be monitored and reported.

 Onshore Natural Gas Processing Segment – There are two types of operations in the processing segment of the natural gas i ndustry; gathering/ boosting stations and processing facilities. Gathering/ boosting st ations typically collect gas from several producing zones, dehydrate the natural ga s and compress it fo r transportation to onshore natural gas processing plants. Processing facilities further process the gas to remove hydrogen sulfide (H 2 S) and/ or CO 2 in the natural gas, if any, separate the higher hydrocarbons (ethane, propane, butane, pentanes, etc.) from the natural gas

Background Technical Support Document – Petroleum and Natural Gas Industry 25and compress the natural gas to be injected into the onshore natu ral gas transmission segment. Both gathering/ boosting stations a nd natural gas processi ng facilities have a well defined boundary within which all proce sses take place. All emissions sources in a processing plant could be monitored and included in a mandatory GHG reporting rule, including associated ga thering and boosting stations.

 Onshore Natural Gas Transmission Segment – Transmission compressor stations are the largest source of emissi ons on transmission pipelines and meet the conventional definition of a facility. Given the relatively large share of emissions from the compressor station, as compared to the pipeline segments between transmission compressor stations, the station may be the most logical place to capture emissions from this segment. Natural gas transm ission also involves high pressure, large diameter pipelines that transport gas long distances from field production and natural gas processing facilities to natural ga s distribution pipelines or large volume customers such as power plants or chemi cal plants. The magnitude of transmission pipeline emissions in the U.S. Inventor y is 0.07% of the total national emissions. Also, the Department of Transportation in Title 49 CFR Part 192 Section 706 requires that all natural gas transmission lines perform leakage surveys at least two to four times every calendar year. S ection 711 of the same regulat ion requires operators to make permanent repairs to discovered leak s when feasible. Therefore, EPA is not proposing to include reporting of fugitive emissions from natural gas pipeline segments between compressor stations, or crude oil pipelines and tank terminals in the supplemental rulemaking can potentiall y be excluded becaus e of the dispersed nature of the fugitive emissions, and the fact that once fugitives are found, they are generally fixed quickly. One possible option is that each segment facility that operates gathering pipelines report em issions from their gathering lines.

 Underground Natural Gas Storage, LN G Storage, and LNG Import and Export Segments – All operations in an underground na tural gas storage facility (except wellheads), LNG storage facility, and LNG import and export faci lities are confined

within defined boundaries. In the case of underground natural gas storage facilities,

the wellheads are within short distances of th e main compressor station such that it is

feasible to monitor them al ong with the stations themselves. All three segments could be included in a mandatory reporting rule.

 Natural Gas Distribution Segment – The distribution segmen t meter and regulation vaults are identifiable as a facility. Howe ver, the magnitude of emissions from a single vault is not sign ificant. Although vaults collec tively contribute to a significant share of emissions from the natural gas i ndustry nationally, it ma y not be possible to group multiple vaults as a single facility as they are not in a contiguous area. Also, emissions from vaults and pipelines are us ually quickly dealt with given the safety concerns in a gas distribution segment. This might not allow any time for monitoring

of leaks.

Another option for including distribution sector is adapting the facility definition from the fuels reporting regulation for natural gas reporting from distribution

Background Technical Support Document – Petroleum and Natural Gas Industry 26companies. This subpart of the MRR define s a local distribution company (LDC) as a facility and the threshold is applied at th e company level. Using this definition will avoid all the issues discussed earlier since geographical demarcation of the facility

will no more be an issue.

 Petroleum Transportation Segment – All the sources in th e petroleum transportation segment were excluded as a result of the decision process. Hence, this segment may

not be amenable to inclusi on in a reporting program.

Table 5 provides a list of each segment and a corresponding facility definition. It also provides a listing of all sources that can be monitored and could be reported as part of a mandatory GHG reporting rule.

Table 5: Segment Specifi c Facility Definition

Segment Facility Definition Potential Emission

Sources for Inclusion

Onshore Petroleum

and Natural Gas Onshore petroleum and natural gas production facility means all petroleum or natural gas equipment associated with all petroleum or natural gas production wells under common ownership or common control by an onshore petroleum and natural gas production owner or operator located in a single hydrocarbon basin as defined by the American Association of Petroleum Geologists which is assigned a three digit Geologic Province Code. Where an operating entity holds more than one permit in a basin, then all onshore petroleum and natural gas production equipment relating to all permits in their name in the basin is one onshore petroleum and natural gas production facility. Acid gas removal (AGR) vent stacks, centrifugal compressor dry seals, centrifugal compressor wet seals, compressor fugitive emissions, dehydrator vent stacks, flare stacks, natural gas driven pneumatic pumps, non-pneumatic pumps, open-ended lines (OELs), pump seals, pipeline fugitive emissions, natural gas driven pneumatic manual valve actuator devices, natural gas driven pneumatic valve bleed devices, reciprocating compressor rod packing, storage tanks, separators, well clean-ups/blowdowns, vessel blowdowns/venting, meters/piping, pipeline leaks, pipeline venting, wellhead fugitives, well completions, coal bed methane fugitives, heaters, separators.

Offshore Petroleum

and Natural Gas

Production Offshore petroleum and natural gas production facility means any platform structure, either floating in the ocean or lake, or fixed on the ocean or lake bed, that houses equipment to extract hydrocarbons from the ocean or lake floor and transports it to storage or transport vessels or transports onshore. In addition, offshore production facilities include secondary platform structures and floating storage tanks connected to the platform structure by a pipeline. Production facilities connected to each other via causeways are one Acid gas removal (AGR) vent stacks, centrifugal compressor dry seals, centrifugal compressor wet seals, compressor fugitive emissions, dehydrator vent stacks, flare stacks, natural gas driven pneumatic pumps, non-pneumatic pumps, open-ended lines (OELs), pump seals, offshore platform pipeline fugitive emissions, platform fugitive emissions, natural gas driven pneumatic

Background Technical Support Document – Petroleum and Natural Gas Industry 27facility. manual valve actuator devices, natural gas driven pneumatic valve bleed devices, reciprocating compressor rod packing, storagetanks, separators, well cleanups/blowdowns, vessel blowdowns/venting, meters/piping, pipeline leaks, pipeline venting.

Onshore Natural Gas Processing Natural gas processing facilities are plants designed to separate and recover natural gas liquids (NGLs)or other non-methane gases and liquids from a stream of produced natural gas to meet onshore natural gas transmission pipeline quality specifications through equipment performing one or more of the following processes: oil and condensate removal, water removal, separation of natural gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or other processes, and also the capture of CO2 separated from natural gas streams for Enhanced Oil Recovery (EOR), carbon sequestration projects or other commercial applications. In addition, field gathering and/or boosting stations that gather and process natural gas from multiple wellheads, and compress and transport natural gas (including but not limited to flow lines or intra-facility gathering lines or compressors) as feed to the natural gas processing facilities are considered a part of the processing facility. Gathering and boosting stations that send the natural gas to an onshore natural gas transmission facility, or natural gas distribution facility, or to an end user are

considered stand alone natural gas processing facilities. All residue gas compression equipment operated by a processing plant, whether inside or outside the processing plant fence, are considered part of the natural gas processing facility. All petroleum and natural gas equipment associated with petroleum and natural gas wells are not considered a part of the natural gas processing AGR vent stacks, blowdown vent stacks, centrifugal compressor dry seals, centrifugal compressor wet seals, compressor fugitive emissions, dehydrator vent stacks, open-ended lines (OELs), natural gas driven pneumatic manual valve actuator devices, natural gas driven pneumatic valve bleed devices, processing facility fugitive emissions, reciprocating compressor rod packing, storage tanks, non-pneumatic pumps, meters/piping, pipeline leaks, station venting and M&R

Onshore Natural Gas

Transmission Onshore natural gas transmission compression facility means any permanent combination of compressors that move natural gas at elevated pressure from production fields or natural gas processing facilities, in transmission pipelines, to natural gas distribution pipelines, or into storage facilities. In addition, transmission compressor station includes equipment for liquids separation, natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids. Each owner or operator Centrifugal compressor dry seals, centrifugal compressor wet seals, compressor fugitive emissions, dehydrator vent stacks, OELs, natural gas driven pneumatic manual valve actuator devices, natural gas driven pneumatic valve bleed devices, reciprocating compressor rod packing, storage tanks, transmission station fugitive emissions, meters/piping, pipeline

Background Technical Support Document – Petroleum and Natural Gas Industry 28engaged in gas transmission compression, who also operates gas gathering pipelines, shall report emissions for these pipelines. leaks, CBM Powder River, AGR vent stacks, vessel blowdown, station venting, and M&R.

Underground Natural Gas Storage Underground natural gas storage facility

means a subsurface fac ility, including but not limited to; depleted gas or oil reservoirs and salt dome caverns, utilized for storing natural gas that has been transferred from its original location for the primary purpose of load balancing, which is the process of equalizing the receipt and delivery of natural gas; processes and operations that may be located at a natural gas underground storage facility (including, but are not limited to, compression, dehydration and flow measurement); and all the wellheads connected to the compre ssion units located at the facility. Centrifugal compressor dry seals, centrifugal compressor wet seals, compressor fugitive emissions, dehydrator vent stacks, OELs, pump seals, natural gas driven pneumatic manual valve actuator devices, natural gas driven pneumatic valve bleed devices, reciprocating compressor rod packing, storage tanks, storage station fugitive emissions, storage wellhead fugitive emissions, meters/piping, pipeline leaks, vessel blowdowns/venting, pipeline venting, station venting,

and M&R.

LNG Storage LNG storage facilities means an onshore facility that stores LNG in above ground storage vessels, equipment for liquefyingnatural gas, compressors to capture and reliquefy boil-off-gas, re-condensers, and vaporization units for re-gasification of the liquefied natural gas. Centrifugal compressor dry seals, centrifugal compressor wet seals, compressor fugitive emissions, OELs, LNG storage station fugitive emissions, reciprocating compressor rod packing, meters/piping, pipeline leaks, pneumatic device vents, vessel blowdowns/venting, pipeline venting, station venting, and

M&R.

LNG Import and Export LNG import facility means onshore or offshore facilities that receive imported LNG via ocean transport, store it in storage tanks, re-gasify it, and deliver re-gasified natural gas to a natural gas transmission or distribution system. LNG export fac ility means onshore or offshore facilities that receive natural gas, liquefy it, store it in storage tanks, and send out the LNG via ocean transportation, including to import facilities in the United

States. Centrifugal compressor dry seals, centrifugal compressor wet seals, compressor fugitive emissions, OELs, LNG storage station fugitive emissions, reciprocating compressor rod packing, meters/piping, pipeline leaks, pneumatic device vents, vessel blowdowns/venting, pipeline venting, station venting, and

M&R.

Natural Gas

Distribution A natural gas distribution facility is a Local Distribution Company (LDC) that owns or operates distribution pipelines, not interstate pipelines or intrastate pipelines, and metering and regulating stations, that physically deliver natural gas to end users and that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution

systems. Main cast iron pipeline fugitives, main unprotected steel pipeline fugitives, main protected steel pipeline fugitives, main plastic protected steel pipeline fugitives, service unprotected steel pipeline fugitives, service protected steel pipeline fugitives, service plastic pipeline fugitives, service copper pipeline fugitive, city gate station fugitives, customer meter fugitives, pressure relief valves, pipeline blowdowns, mishaps.

Background Technical Support Document – Petroleum and Natural Gas Industry 29

### 5. Options for Reporting Threshold
For each segment in the petroleum and natural ga s industry identified above as amenable to a reporting program, four thresholds were consider ed for emissions reporting as applicable to an individual facility ; 1,000 metric tons of CO 2 equivalent (mtCO 2 e) per year, 10,000

mtCO 2 e, 25,000 mtCO 2 e, and 100,000 mtCO 2 e. A threshold analysis was then conducted on each segment to determine which level of th reshold was most suitable for each industry segment. CH 4 , CO 2 , and N 2 O emissions from each segment were included in the threshold analysis.



### a. Threshold Analysis

For each segment, a threshold analysis wa s conducted to determ ine how many of the facilities in the segment exceed the various repo rting thresholds, and the total emissions from these impacted facilities. This analysis wa s conducted considering fugitive and vented CH 4 and CO 2 emissions, and incremental combustion CH 4 , CO 2 , and N 2 O emissions. Incremental

combustion emissions are those combustion em issions not already re ported under Subpart C of the MRR, but are required to be reported because their pro cess emissions. The fugitive and

vented emissions estimates available from the U.S. GHG Inventory were used in the analysis. However, the emissions estimates for four s ources, well venting for liquids unloading, gas well venting during well completions, gas well venting during well workovers, and centrifugal compressor wet seal degassing ven ting from the U.S. GHG Inventory were replaced with revised estimates developed as described in Appendix B. Incremental combustion emissions were estimated using gas engine methane emissions factors available from the GRI study, back calculating the natural gas consumptions in engines, and finally applying a CO 2 emissions factor to the natu ral gas consumed as fuel. N 2 O emissions were also calculated similarly. In the case of offshore petrol eum and natural gas production platforms combustion emissions are already available from the GOADS 2000 study analysis and hence were directly used fo r the threshold analysis. It must be noted that the threshold analysis for the rule includes all fugitive and vented emissions but only incremental

combustion emissions. Due to these reasons the total emissions from the threshold analysis does not necessarily match the U.S. GHG Inventory for all segm ents of the petroleum and natural gas industry. A detailed discussion on the threshold analysis is available in Appendix

C.

The general rationale for selecting a reporting th reshold is to identify a level at which the incremental emissions reporting between thresholds is the highest for the lowest incremental

increase in number of faciliti es reporting between the same thresholds. This would ensure maximum emissions reporting coverage with minimal burden on the industry. For example, for onshore production the emissions reporting c overage is 67 percen t and the corresponding reporting facilities coverage is 2 percent for a threshold of 100,000 mtCO 2 e per year. The incremental emissions and facilities coverage is 14 and 2 percent (81 percent minus 67 percent and 4 percent minus 2 per cent), respectivel y, for a 25,000 mtCO 2 e per year threshold. However, at the next reportin g threshold level of 10,000 mtCO 2 e per year the incremental

Background Technical Support Document – Petroleum and Natural Gas Industry 30Background Technical Support Document – Petroleum and Natural Gas Industry 31 emissions and entities coverage is 6 and 5 percent, respectively. It can be seen that the incremental coverage of emissions decreases but the coverage of facilities increases.

Table 6 provides the details of the threshold analys is at all threshold levels for the different segments in the oil and gas industry.Table 6: Threshold Analysis for the Oil and Gas Industry SegmentsEmissions CoveredFacilities CoveredSource CategoryThresholdLevelTotalNationalEmissionsNumber ofFacilitiesProcessEmissions(mtCO2e/year)CombustionCO2Emissions(mt/year)Total Emissions(tonsmtCO2e/yr)PercentNumberPercent100,000277,798,73727,993131,978,11255,197,177187,175,28967%4662%25,000277,798,73727,993154,932,64169,294,918224,227,55981%1,2324%10,000277,798,73727,993164,072,92278,317,926242,390,84987%2,4139%Onshore Natural Gas ProductionFacilities (Basin)1,000277,798,73727,993174,457,30994,391,220268,848,52997%10,60438%100,00011,261,30532353,217,22825,1613,242,38929%40.1%25,00011,261,30532354,619,175500,2295,119,40545%582%10,00011,261,30532355,515,4191,596,1447,111,56363%1846%Offshore Petroleum and Natural GasProduction Facilities100011,261,30532356,907,8123,646,07610,553,88994%119237%100,00033,984,01556624,846,99227,79224,874,78373%13023%25,00033,984,01556629,551,6891,677,38231,229,07192%28951%10,00033,984,01556630,725,5322,257,44332,982,97597%39670%Onshore Natural Gas ProcessingFacilities100033,984,01556631,652,4842,331,53133,984,015100%566100%100,00064,059,1251,94434,511,0947,83434,518,92754%43322%25,00064,059,1251,94451,527,8326,155,31357,683,14490%1,14559%10,00064,059,1251,94453,554,3029,118,60362,672,90598%1,44374%Onshore Natural Gas TransmissionFacilities1,00064,059,1251,94454,117,1879,934,47464,051,661100%1,69587%100,0009,713,0293973,548,98803,548,98837%369%25,0009,713,0293976,570,3691,276,2397,846,60981%13334%10,0009,713,0293977,283,0581,685,9368,968,99492%20050%Underground Natural Gas StorageFacilities1,0009,713,0293977,745,0281,951,5059,696,532100%34787%100,0002,113,601157669,50325,956695,45933%43%25,0002,113,6011571,712,240188,5521,900,79390%3321%10,0002,113,6011571,826,546204,2972,030,84296%4126%LNG Storage Facilities1,0002,113,6011571,859,880237,0942,096,97499%5434%100,000315,8885314,8030314,803100%480%25,000315,8885314,8030314,803100%480%10,000315,8885314,8030314,803100%480%LNG Import Facilities11,000315,8885315,048840315,888100%5100%100,00025,258,3471,42718,470,457018,470,45773%665%25,00025,258,3471,42722,741,042022,741,04290%14310%10,00025,258,3471,42723,733,488023,733,48894%20314%Natural Gas Distribution Facilities1,00025,258,3471,42724,983,115024,983,11599%59442%1. The only LNG export facility in Alaskahas not been included in this analysis.Background Technical Support Document –Petroleum and Natural Gas Industry32Note: Totals may not add exactly due to rounding. Fugitiv e and vented emissions in the threshold analysis are a sum of facility level emissions for each segment. Hence the total fugitive and vented emissions from each segment may not match the U.S. GHG Inventory.

As discussed above, alternative definitions of facility for onshore petroleum and natural gas production could be considered. One alternative option is a pplying the threshold at the facility level. Table 7 provides the results of the threshold analysis for a field level facility

definition.

Table 7. Emissions coverage and entities repo rting for field level facility definition

Emissions Covered Facilities Covered Threshold

Level 2 Metric tons

CO 2 e/year Percent Number Percent

100,000 99,776,033 38% 305 0%

25,000 144,547,282 55% 1,253 2%

10,000 169,160,462 64% 2,846 3%

1,000 242,621,431 92% 39,652 48%

Four different scenarios were also considered above for applying thresholds at individual well pads. Table 8 below illustrates the averag e emissions for each scenario and the number of facilities that have emissions equal to or greater than that average. So, for example, in case 1, average emissions are 4,927 tons CO 2 e/well pad. A threshold would have to be set as low as appropriately 5,000 tons CO 2 e/well pad to capture even 6% of emissions from onshore oil and gas production. Fo r the other cases, the threshold would have to be set lower

than the thresholds considered for other se ctors of the mandatory GHG reporting rule to capture even relatively small percentages of total emissions. In all cases, the number of reporters is higher than woul d be affected under the fiel d or basin level options.

Table 8: Alternate Well-head Facility Definitions

Case 1 Case 2 Case 3 Case 4

Average emissions (tons CO 2 e / well pad) 4,927 700 700 370

Number of Reporters 3,349 38,949 66,762 166,690

Covered Emissions (metric tons CO2e) 16,498,228 40,943,092 50,572,248 87,516,080

Percent Coverage 6% 16% 19% 33%

Background Technical Support Document – Petroleum and Natural Gas Industry 33The petroleum and natural gas industry may be somewhat unique when calculating facility emissions to be applied against a threshold for reporting. Finalized s ource categories in the MRR excluded the calculation and reporting of emissions from portable equipment. This was one option considered for the petroleum a nd natural gas industry. However, given that portable equipment is so central to many of th e operations in the oil and natural gas industry and such a large contributor to emissions for the industry, particularly for onshore petroleum and natural gas production, one might consider requiring reporting and calculation of portable equipment emissions from this source category. If these emissions were excluded from the threshold calculation, a large numbe r of facilities may fa ll below the threshold, preventing the collection of significant data from the industry that would be beneficial to the development of future climate policies and programs. Although loweri ng the threshold, but excluding portable equipment emissions could addr ess this issue, data are not available to disaggregate stationary and por table combustion emissions from total combustion emissions in order to support an analys is to lower the threshold.



### 6. Monitoring Method Options

a. Review of Existing Relevant Reporting Programs/ Methodologies

To determine applicability of the different m onitoring methods available, existing programs and guidance documents were reviewed. All of the program and guidance documents provide direction on estimating CH 4 and/ or CO 2 emissions. All documents in general provide emissions rate (emissions factors) that can be used to estimate emissions and in some cases refer to continuous emissions monitoring. Table 4 provided a summary of the programs and guidance documents reviewed.



### b. Potential Monitoring Methods

Depending on the particular source to be monito red in a facility, seve ral of the currently available monitoring methods for es timating emissions could be used.



### i. Fugitive Emissions Detection

Traditional fugitive emission detection techno logies like the Toxic Vapor Analyzer (TVA) and the Organic Vapor Analyzer (OVA) are appropriate for use in small facilities with few pieces of equipment. However, comprehensive leak detection in larg e facilities can be cumbersome, time consuming, and in many cases costly. But new infrared remote fugitive emissions detection technologies are currently being used in the United States and internationally to efficiently detect leaks across large facilities. Considering these factors, one of the following two technologies can be used to detect leaks in facilities depending on suitability;

Infrared Remote Fugitive Emissions Detectors Hydrocarbons in natural gas emissions absorb infrared light. The infrared remote fugitive emissions detectors use this prope rty to detect leakages in syst ems. There are two main types of detectors; a) those that scan the an area to produce images of fugitive emissions from a source, and b) those that point or aim an IR beam towards a potential source to indicate presence of fugitive emissions.

Background Technical Support Document – Petroleum and Natural Gas Industry 34An IR camera scans a given area and conve rts it into a moving im age of the area while distinctly identifying the location where infrared light has been absorbed, i.e. the fugitive emissions source. The camera can actually “see” fugitive emissions. The advantages of IR cameras are that they are easy to use, very effi cient in that they can detect multiple leaks at the same time, and can be used to do a comp rehensive survey of a facility. The main disadvantage of an IR camera is that it invo lves substantial upfront capital investment depending on the features that are made ava ilable. Therefore, these cameras are most applicable in facilities with large number of equipment and multiple potential leak sources or when purchased at the corporate level, and then shared among the facilities, thereby lowering

costs.

Aiming devices are based on infrared laser reflection, which is tuned to detect the interaction

of CH 4 and other organic compounds with infrar ed light in a wavelength range where CH 4 has strong absorption bands but do not visually display an image of the fugitive emissions.

Such devices do not have screens to view the fugitive emissions, but pin point the location of the emissions with a visual guide (such as a vi sible pointer laser) combined with an audible

alarm when CH 4 is detected. These devices are consid erably less expensive than the camera and also can detect fugitive emissions from a distance (i.e. the instrument need not be in close proximity to the emissions). More time is required for screening, however, since each equipment (or component) has to be pointed at to determine if it is leak ing. Also, if there are multiple leaks in the pathway of the IR beam then it may not accurately detect the right

source of emissions.

Method For IR instruments that visually display an image of fugitive emissions, the background of the emissions has to be appropriate for emissions to be detectable. Therefore, the operator should inspect the emissions source from multiple angles or locations until the

entire source has been viewed without visual obstructions to identify al l emissions. For other IR detection instruments, such as those base d on IR laser reflection, instruments would have to monitor potential emissions sources along all joints and connection points where a potential path to the atmosphere exists. For example, a flange can potentially have fugitive emissions along its circumference and such surfaces will have to be monitored completely by tracing the instrument along each surface.

Calibration The minimum detectable quantity of fugitive emissions depends on a number of factors including manufacturer , viewing distance, wind sp eed, gas composition, ambient temperature, gas temperature, and type of background behind the fugitive emissions. For best survey results, fugitive emissions detecti on can be performed under favorable conditions, such as during daylight hours, in the absence of pr ecipitation, in the absence of high wind, and, for active laser devices, in front of a ppropriate reflective b ackgrounds within the detection range of the instrument. Fugitive em issions detection and measurement instrument manuals can be used to determine optimal operati ng conditions to help ensure best results.

Toxic Vapor Analyzer (or Organic Vapor Analyzer)

TVAs and OVAs consist of a flame ionization detector that is us ed to detect the presence of hydrocarbon and measure the concentration of th e fugitive emissions. It consists of a probe

Background Technical Support Document – Petroleum and Natural Gas Industry 35that is moved close to and around the potential emissions source and an emissions detection results in a positive reading on the instrument monitoring scale. The concentration can be used in conjunction with correlation equations to determine the leak rate. However,

concentration is not a true measure of an em ission’s magnitude. Therefore concentration data from TVAs and OVAs, for the purposes of th e rule, may be best suited for screening purposes only. The advantage of these instrument s is that they have lower costs than IR cameras and several facilities conducting Leak Detection and Repair (LDAR) programs might already have these instruments, thereby reducing capital investme nt burden. But these instruments screen very slowly given that each potential emission s source has to be individually and thoroug hly circumscribed less than 1 centimeter from the potentially leaking joints or seals.

Method TVAs and OVAs can be used for all fugitive emissions detection that is safely accessible at close-range. For each potential emissions sour ce, all joints, connections, and other potential paths to the at mosphere would be monitored for emissions. Due to residence time of a sample in the probe, there is a lag between when an emission is captured and the operator is alerted. To pinpoint the source of the fugitive emission, upon alert the instrument can be slowly retraced over the sour ce until the exact location is found.

Calibration Method 21 guidance can be used to ca librate the TVA or OVA using guidelines

from Determination of Volatile Organic Compound Leaks Sections 3, 6, and 7.



### ii. Emissions Measurement



### A. Direct Measurement

Three types of technologies can be used where appropriate to measure or quantify the magnitude of emissions.

High Volume Sampler A high volume sampler consists of a simple fi xed rate induced flow sampling system to capture the emissions and measure its volume. The emissions and the air surrounding the

emissions source are drawn into the instrume nt using a sampling hose. The instrument measures the flow rate of the captured volum e of air and emissions mixture. A separate sample of the ambient air is taken by the inst rument to correct for the volume of ambient air that is captured along with the emissions.

High volume samplers have moderate costs a nd have a maximum capacity for measuring up to 30 leaking components per hour with high precision at 0.02 per cent methane. This allows for reduced labor costs and survey times while maintaining precise results. For this reason, high volume samplers are considered the preferred and most cost-effective measurement option for emissions within their maximum rang e. However, large component emissions and many vent emissions are above the high volum e sampler capacity and therefore warrant the

use of other measurement instruments.

Method A high volume sampler is typically used to measure only emissions for which the

instrument can intake the entire emissions from a single source. To ensure proper use of the

Background Technical Support Document – Petroleum and Natural Gas Industry 36instrument, a trained technician can conduct the measurements. The technician will have to be conversant with all operating procedures and measurement method ologies relevant to using a high volume sampler, such as positioni ng the instrument for complete capture of the emissions without creating bac kpressure on the sour ce. If the high volume sampler, along

with all attachments available from the manufactur er, is not able to capture all the emissions from the source then anti-static wraps or other aids can to be used to capture all emissions without violating operating requirements as provided in the instrument manufacturer’s manual. The attachments help capture the em issions from different points on the source allowing the measurement of the emission by the high volume sampler.

Calibration The instrument can be calibrated at 2.5% and 100% CH 4 by using calibrated gas samples and by following the manufact urer’s instructi ons for calibration.

Meters Several types of meters measure natural gas flows and can be used for measurement of

emissions from sources where the volume of emissions are large li ke in vent stacks.

Rotameter

–A rotameter consists of a tapered calibrated transparent tube and a floating bob inside to measure emissions. To measure emissions a rotameter is placed over an emissions source (typically vents and open ended lines) and the emissions pass through the tube. As the emissions move through the tube it raises the floating bob to indicate the magnitude of emissions on the calibrated scale. Rotameters are most advantageous to use in cases where the emissions are very large. The disadvantage though is that it can only be used on leaks where the entire emissions can be captured and directed through the rotameter.

Turbine Meter –To measure emissions a turbine meter is placed over an emissions source and the emissions pass through the tube. As the emissions move through the tube it spins the turbine; the rate at which the turbine spins indicates the magnitude of emissions. Like rotameters, turbine meters are most advantageous to use in cases where emissions are very large. The disadv antage is that it can only be used on emissions that can be entirely captu red and directed through the meter.

Hotwire Anemometer – Hotwire anemometers measur e emissions velocity by noting the heat connected away by the emissions. Th e core of the anemometer is an exposed hot wire either heated up by a constant current or maintained at a constant temperature. In either case, the heat lost to emissions by convection is a function of the emissions velocity. Hotwire anemomet ers are best for measuring vents and open

ended lines of known cross-s ectional area and do not requi re complete capture of

emissions. Hot wire anemometers have low levels of accuracy since they measure velocity that is converted into mass emissions rate.

Pitot Tube Flow Meter – A simple pitot tube is a right angled tube open at one end

and closed at the other. The closed end is connected to a transducer to measure pressure of the inflowing emissions. The open end is aligned parall el to the direction

of emissions flow. Emissions are directed into the tube so that the pressure required to

Background Technical Support Document – Petroleum and Natural Gas Industry 37bring the air inside the tube to stagnati on is measured. The difference in pressure between the interior of the pitot tube and the surrounding air is measured and

converted to an emissions ra te. Pitot tube flow meters can be used when the crosssectional area of an emitting vent or open ended line is known, or when the entire

emission can be directed into the tube. The pitot tube flow meter measures pressure

differential that is converted to mass emissions rate.

Vane Anemometer – A vane anemometer channels the emissions over a rotating vane

that in turn rotates a fan to measure the velocity of emissions. The number of

revolutions of the fan are de tected and measured and conv erted to a flow velocity. Using the cross section of flow of the emissions, the volumetric flow rate of

emissions can be estimated. A vane anemometer is best used for lines that have known cross-sectional areas. The disadvantag e is if the flow direction of the emissions changes with respect to the axis of rotation of the vanes, it can result in errors in velocity and flow rate estimation.

Method To ensure accurate measurements when using metering (e.g. rotameters, turbine meters, and others), all emissions from a singl e source will have to be channeled directly through the meter. An appropriately sized me ter can be used to prevent the flow from exceeding the full range of the meter and conver sely to have sufficient momentum for the meter to register continuously in the course of measurement.

Calibration The meters can be calibrated using e ither one of the two methods provided

below:

(A) Develop calibration curves by following the manufacturer’s instruction.

(B) Weigh the amount of gas that flows through the meter into or out of a container during the calibration procedure using a master weigh scale (approved by the

National Institute of Standards and T echnology (NIST) or calibrated using standards traceable by NIST) that has a very high degree of accuracy. Determine

correction factors for the flow meter accord ing to the manufacturer’s instructions,

record deviations from the correct readi ng at several flow rates, plot the data points, compare the flow meter output to th e actual flow rate as determined by the master weigh scale and use the di fference as a correction factor.

Calibrated Bagging A calibrated bag made of anti-static material is used to enclose an emissions source to completely capture all the leaking gas. The ti me required to fill the bag with emissions is measured using a stop watch. The volume of the ba g and time required to fill it is used to

determine the mass rate of emissions. Calibrated bags have a very high accuracy, since all the emissions are captured in the measurement.

Calibrated bags are the lowest cost meas urement technique, and can measure up to 30 leaking components in an hour, but may require two operators (one to deploy the bag, the other to measure time inflation). It is a su itable technique for emission sources that are

Background Technical Support Document – Petroleum and Natural Gas Industry 38within a safe temperature range and can be sa fely accessed. The speed of measurement is highly dependent on the emissions rate and the results are susceptible to human error in enclosing the emission source and taking the m easurement data, leading to lower precision and accuracy. For those sources outside the capa city of high volume samplers and within the limitations of bagging, this would be a s econd best choice for quantification.

Method Calibrated bags (also known as vent bags ) can be used only where the emissions are at near-atmospheric pressures and the enti re emissions volume can be captured for measurement. Using these bags on high pres sure vent stacks can be dangerous. For conducting measurement the bag is physically held in place by a trained technician, enclosing the emissions source, to capture the entire emissions and record the time required to completely fill the bag. Three measurements of the time required to fill the bag can be

conducted to estimate the emissions rates. The av erage of the three rate s will provide a more accurate measurement than a single measurement.

Calibration To ensure accurate results, a technician can be trained to obtain consistent results when measuring the time it take s to fill the bag with emissions.

All of the emissions measurement instruments di scussed above measure the flow rate of the natural gas emissions. In order to conv ert the natural gas emissions into CO 2 and CH 4 emissions, speciation factors de termined from natural gas co mposition analysis must be applied. Another key issue is that all measurement technologi es discussed require physical access to the emissions source in order to quantify emissions.



### B. Engineering Estimation

Several emissions sources do not require physi cal measurement of the emissions using a measurement instrument. For example, emissions to the atmosphere due to emergency conditions from vessels or other equipment a nd engineered emissions from equipment like pneumatic devices can be estimated or quantif ied using engineering calculations. This is referred to as engineering estimation. These sources are outlined belo w along with relevant engineering estimation methods that can be us ed to estimate GHG gas emissions from each

source.

1. Natural Gas Driven Pneumatic Pumps

Fugitive emissions from natural gas driven pneumatic pumps can be calculated using data obtained from the manufacturer for natural ga s emissions per unit volume of liquid pumped at operating pressures. This information is available from the pump manufacturer in their manuals. Operators can maintain a log of the amount of liquids pumped annually for individual pneumatic pumps and use the fo llowing equation for calculating emissions:

VFE

sns *

, = Equation 1

Background Technical Support Document – Petroleum and Natural Gas Industry 39where,

E s,n = Annual natural gas emissions at standard conditions in cubic feet

per year

F

s = Natural gas driven pneumatic pump gas emission in “emission per volume of liquid pumped at operati ng pressure” in scf/gallon at standard conditions, as pr ovided by the manufacturer

V

= Volume of liquid pumped annually in gallons/year

If manufacturer data for a specific pump is not available, then data for a similar pump model of the same size and operational characteristic s can be used to estimate emissions. As an

alternative to manufacturer da ta on pneumatic pump natural ga s emissions, the operator can

conduct a one-time measurement to determin e natural gas emissions per unit volume of liquid pumped using a calibrated bag for each pneumatic pump, when it is pumping liquids.

2. Natural Gas Driven Pneumatic Manual Valve Actuators

Emissions from natural gas driven pneumatic ma nual valve actuators ca n be calculated using

data obtained from the manufacturer for natu ral gas emissions per act uation. Operators can maintain a log of the number of manual actuations annually for individual pneumatic devices and use the following equation:

NAE

sns *

, = Equation 2

where,

E s,n = natural gas emissions at standard conditions

A

s = natural gas driven pneumatic valve actuator natural gas emissions in “emissions per actuation” uni ts at standard conditions, as provided by the manufacturer.

N

= Number of times the pneumatic device was actuated through the reporting period

As an alternative to manufacturer data, the operator could conduct a one-time measurement to determine natural gas emissions per actua tion using a calibrated bag for each pneumatic

device.

3. Natural Gas Driven Pneumatic Bleed Devices

Pneumatic devices typically fall in two categor ies; low bleed devices and high bleed devices.

Low bleed devices are devices th at bleed less than 6 scf of natural gas per hour. Given the vast difference in bleed rates, low bleed devi ces contribute to a small portion of the total emissions from pneumatic devices nationally. Ther efore, it may be feasible to provide an

Background Technical Support Document – Petroleum and Natural Gas Industry 40emissions factor approach for low bleed pneum atic devices to reduce burden. Following are two different options for high and low bleed pneumatic devices.

Emissions from a natural gas pneumatic high blee d device venting can be calculated using a specific pneumatic device model natural gas bl eed rate during normal operation as available

from the manufacturer. If manufacturer data for a specific device is not available then data for a similar size and operation device can pote ntially be used to estimate emissions. The natural gas emissions for each bleed device can be calculated as follows;

TBE

sns *

, = Equation 3

where,

E s,n = Annual natural gas emissions at standard conditions, in cubic feet

B

s = Natural gas driven pneumatic device bleed rate vol ume at standard conditions in cubic feet per minute, as provided by the manufacturer

T

= Amount of time in minutes that the pneumatic device has been operational through the reporting period

Emissions from natural gas pneumatic low bl eed device venting can be calculated using emissions factor as follows;

365*24****

, i i is Conv GHGEFCount Mass = Equation 4

where,

Mass s,i = Annual total mass GHG emissions in metric tons per year at standard conditions from all natural gas pneumatic low bleed device venting at the facility, for GHG i

Count = Total number of natural gas pneuma tic low bleed devices at the facility

EF = Population emission factors for na tural gas pneumatic low bleed device venting listed in Appendix K for onshore petroleum and natural gas production, onshore natural gas tran smission, and underground natural gas storage facilities, respectively

GHG i = for onshore petroleum and natural gas production facilities,

concentration of GHG i , CH 4 or CO 2 , in produced natural gas; for other

facilities GHG i equals 1

Conv i = conversion from standard cubic feet to metric tons CO 2 e; 0.000404 for

CH 4 , and 0.00005189 for CO 2 24 * 365 = conversion to yearly emissions estimate

Background Technical Support Document – Petroleum and Natural Gas Industry 414. Acid Gas Removal (AGR) Vent Stacks

AGR vents consist of both CO 2 and CH 4 emissions. CO 2 emissions from AGR units can be reliably estimated using mass balance approach or one of the standard simulation software packages. CH 4 emissions can only be estimated using simulation software packages. It must be noted, however, that CH 4 emissions from AGR vents are in significant, 0.06 percent of the

total volume of CO 2 and CH 4 emissions. The mass balance approach has the advantage of being usable in systems that use membrane, molecular sieves, or absorbents other than amines; simulation software packages currently do not provide an option for these types of technologies.

Operators can calculate emissions from aci d gas removal vent stacks using simulation software packages, such as ASPENTM or AMIN ECalcTM. Different software packages might use different calculations and input parameters to determine emissions from an acid gas removal units. However, there are some parame ters that directly im pact the accuracy of

emissions calculation. Therefor e, any standard simulation soft ware could be used assuming it accounts for the following operational parameters:

• Natural gas feed temperature, pressure, and flow rate;

• Acid gas content of feed natural gas;

• Acid gas content of outlet natural gas;

• Unit operating hours, excluding downtim e for maintenance or standby;

• Emissions control method(s), if any, and associated reduction of emissions;

• Exit temperature of natural gas; and

• Solvent pressure, temperature, circulation rate, and weight.

CO 2 emissions from AGR unit vent stac ks can be calculated as follows;

E

a,CO2 = (V 1 * %Vol 1 ) - (V 2 * %Vol 2 ) Equation 5

where,

E a,CO2 = Annual volumetric CO 2 emissions at ambient condition, in cubic feet per

year

V

1 = Metered total annual volume of natural gas flow into AGR unit in cubic feet per year at ambient condition

%Vol 1 = Volume weighted CO 2 content of natural gas into the AGR unit

V

2 = Metered total annual volume of natural gas flow out of the AGR unit in cubic feet per year at ambient condition

%Vol 2 = Volume weighted CO 2 content of natural ga s out of the AGR unit

Background Technical Support Document – Petroleum and Natural Gas Industry 42Sometimes AGR units have a continuous gas analyzer in which case they can be used to

determine %Vol 1 and %Vol 2 . In addition, there are gas pr ocessing plants that capture CO 2 for EOR or carbon sequestration projects. In such cases, the emissions E CO2 can be adjusted downward to account for the percentage of total emissions captured.

5. Blowdown Vent Stacks

Emissions from blowdown vent stacks can be calculated using the total volume between isolation valves (including all natural gas-cont aining pipelines and vessels) and logs of the number of blowdowns for each piece of equipment using the following equation:

v na VNE *

, = Equation 6

where,

E a,n = Annual natural gas venting emissions at ambient conditions from

blowdowns in cubic feet

N

= Number of blowdowns for the equipment in reporting year

V

v = Total volume of blowdown equi pment chambers (including, but not limited to, pipelines, compressors and vessels) between isolation valves in

cubic feet

6. Dehydrator Vent Stacks

There are two predominant types of technologies that are used to dehydrate natural gas. The first type is the most prevalent and uses liqui d tri-ethylene glycol fo r dehydration, typically referred to as glycol dehydrators. The second type of dehydrators use solid desiccants to extract water from natural gas. For glycol dehy drators, when contacted with natural gas for dehydration, the glycol absorbs some amount of natural gas, which is released as emissions during its regeneration. Standa rd simulation software packages that use some form of equilibrium analysis can estimate emissions from such liquid glycol t ype dehydrators. On the other hand, in desiccant dehydrators the solid de siccant itself does not absorb any significant quantities of natural gas. But emissions result when the desiccant dehydrator is opened to the atmosphere for the regeneration of the desiccant, which results in the release of natural gas trapped in the desiccant dehydrator vessel. Hence, for desiccant dehydrators standard simulation software packages cannot be used. However, calculative methods can be used to determine emissions from solid desiccant type dehydrators. The two monitoring methods for the two different types for dehydrators are as below.

Emissions from a dehydrator vent stack can be calcu lated using a simulation software package, such as GLYCalcTM. There may be several other simulation packages, such as Aspen HYSYS, that can also estimate emis sions from glycol dehydrators. However, GLYCalcTM is the most widely used software and referenced by several State and Federal agencies in their programs and regulations; se e Appendix H for furthe r details. Different software packages might use different calcu lations and input parameters to determine

Background Technical Support Document – Petroleum and Natural Gas Industry 43emissions from dehydration syst ems. However, there are some parameters that directly impact the accuracy of emissions calculation. Therefore, any standard simulation software could be used provided it accounts for the following operational parameters:

• Feed natural gas flow rate;

• Feed natural gas water content;

• Outlet natural gas water content;

• Absorbent circulation pump type(natural gas pneumatic/ air pneumatic/ electric);

• Absorbent circulation rate;

• Absorbent type: including, but not limited to , triethylene glycol (TEG), diethylene glycol (DEG) or et hylene glycol (EG);

• Use of stripping natural gas;

• Use of flash tank separator (and disposition of re covered gas);

• Hours operated; and

• Wet natural gas temperature, pressure, and composition.

For dehydrators that use desiccant emissions can be calculated from the amount of gas vented from the vessel every time it is depressurized for the desiccant refilling process using the following equation:

)/000,1***4( )/365*%****(

1 2 2

, McfcfTP yrdaysGPPDH E

ns = Equation 7

where,

E s,n = Annual natural gas emissions at standard conditions

H

= Height of the dehydrator vessel (ft)

D

v = Inside diameter of the vessel (ft)

P 1 = Atmospheric pressure (psia)

P

2 = Pressure of the gas (psia)

P = pi (3.14)

G % = Percent of packed vessel volume that is gas

T

= Time between refilling (days)

Some dehydrator vented emissions are sent to a flare. Annual emissions from dehydrator vent

stacks to flares can be calculated usi ng the methodology under section 8 for flares. Alternatively, a simple combustion efficiency f actors, such as 98 perc ent, can be used in conjunction with a CO 2 emissions factor for natural gas to estimate emissions from glycol dehydrator vents to flare stack.

7. EOR injection pump blowdown.

Background Technical Support Document – Petroleum and Natural Gas Industry 44EOR operations use pumps to in ject supercritical phase CO 2 into reservoirs. For maintenance, these pumps may be blown down to release all the supercritical phase CO 2 . The

volume of CO2 released to duri ng such blow down practices can be calculated using the total volume between isolation valves (including, but not limited to, pipelines, compressors and vessels).The emissions can be calcu lated using the following equation.

3

, 10****

−

= i cv ic GHGRVNMass Equation 8

where,

Mass c,i = Annual EOR injection gas venting emissi ons in metric tons at critical

conditions “c” from blowdowns.

N

= Number of blowdowns for the equipment in reporting year.

V

v = Total volume in cubic meters of blowdown equipment chambers (including, but not limited to, pi pelines, compressors and vessels

between isolation valves.

R

c = Density of critical pha se EOR injection gas in kg/m 3 . Use an appropriate standard method published by a consen sus-based standards organization to determine density of super critical EOR injection gas.

GHG i = mass fraction of GHG i in critical phase injection gas



### C. Emission Factors

The EPA/ GRI and EPA/Radian studies provi de emissions factors for almost all the emissions sources in the petroleum and natural ga s industry. These can potentially be used to estimate emissions for reporting under the rule . However, the emissions factors are not necessarily reliable for all the emissions sources . The emissions factors were developed more than a decade ago when the industry practices were much different from now. In many cases the emissions factors were developed using limited sample data and knowledge about the industry’s operations. Also, th e introduction of many emissions reduction technologies are

not reflected in the emissions factor estimates. However, the two studies provide a wealth of raw data that can be potentially used to revi se the estimate in conjunc tion with any new data that is now publicly available.

Background Technical Support Document – Petroleum and Natural Gas Industry 45

### D. Combination of Dire ct Measurement and Engineering Estimation

Emissions from several sources can be estimate d using a combination of direct measurement and engineering estimation. Direct measurem ent can provide either a snapshot of the emissions in time or information on parameters that can be used fo r using a calculative method to estimate emissions. Following are options for using such a combination of monitoring methods to estimate emissions.

8. Flare stacks

Flares typically burn two types of hydro carbon streams; continuous and intermittent.

Continuous streams result from vented emissions from equipment such as glycol dehydrators and storage tanks. Intermittent streams result fr om such sources as emergency releases from equipment blowdown. It must be noted that most of these streams, continuous or intermittent, can be covered using monitoring methods alre ady provided on an i ndividual emissions

source level.

Flare emissions in general can be monitored using one of the following monitoring methods

Method 1:

Many facilities, such as in the processing sect or, may already have a continuous flow monitor on the flare. In such cases, the measured fl ow rates can be used when the monitor is operational, to calculate the total flare volumes for the reporting year.

Method 2:

One option is to require the estimation of all streams of hydrocarbons going to the flare at an

individual emissions source leve l. Here engineering calculati on and other methods described

for different sources in this Section can be used to estimates of volume flare gas

Method 3:

When the flare stream is mostly continuous, a flow velocity measuring device (such as hot wire anemometer, pitot tube, or vane anemomet er) can be inserted di rectly upstream of the

flare stack to determine the velocity of natural gas sent to flare. The GHG volumetric

emissions at actual conditions can then be calculated as follows.

i a ia X V combusted unE *)1(*) (

, η

− =

− Equation 9 

# ∑

=

j jja COa RYV combusted E ***) ( 2, η Equation 10

) () (

, ,, combusted unE combusted EE
ia

iaia − + = Equation 11

Background Technical Support Document – Petroleum and Natural Gas Industry 46where,

E a,i (un-combusted) = Contribution of annual un-combusted emissions from flare stack in cubic feet, under ambient conditions

E

a,CO2 (combusted) = Contribution of annual emissi ons from combustion from flare stack in cubic feet, under ambient conditions

E

a,i (total) = Total annual emissions from flare stack in cubic feet,

under ambient conditions

V

a = Volume of natural gas sent to flare in cubic feet, during the year

η = Percent of natural gas co mbusted by flare (default is 98 percent)

X

i = Concentration of GHG i in gas to the flare

Y

j = Concentration of natural gas hydrocarbon constituents j (such as methane, ethane, pr opane, butane, and pentanes plus).

R

j = Number of carbon atoms in the natural gas hydrocarbon

constituent j ; 1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for pentanes plus)

In some cases the facility may have a conti nuous gas composition analyzer on the flare. Here the compositions from the analyzer can be used in calculating emissions. If an analyzer is not present then a sample of the gas to the flare st ack can be taken every quarter to evaluate the composition of GHGs present in the stream. The natural gas composition analyses can be conducted using ASTM D1945-03. It must be noted that for processing plants there are two distinct streams of natural gas with significa nt differences in composition. The natural gas stream upstream of the de-methanizer can be expected to have higher C2+ components as opposed to the stream downs tream of the de-methanizer. In addition, the CO 2 content in natural gas can change significantly after acid gas removal. Finally, processing plants may send pure streams of separated hydrocarbons such as ethane, propane, butane, iso-butane, or pentanes plus to the flare during an emergenc y shutdown of any partic ular equipment. Such variations in hydrocarbon streams being sent to the flare would have to be accounted for in the monitoring methodology.

9. Compressor wet seal degassing vents

In several compressors, the wet seal degassing ve nts emit flash gas from degassed oil straight into or close to the compressor engine exhaust vent stack. The temperatures at the degassing vent exit are very high due to the proximity to the engine exhaust vent stack. In such cases, emissions can be estimated using a flow ve locity measuring device (such as hot wire anemometer, pitot tube) or a flow rate measur ement device such as vane anemometer, which can be inserted directly upstream of the degassing unit vent exit to determine the velocity or flow rate of gas sent to the ve nt. If a velocity measuring devi ce is used then the volume of natural gas sent to vent can be calculated from the velocity measurement using the

Background Technical Support Document – Petroleum and Natural Gas Industry 47manufacturer manual for conversion. Annual em issions can be estimated using meter flow

measurement as follows:

)1(***

, BMTMTE
i ia − = Equation 12

where,

E a,i = Annual GHG i (either CH 4 or CO 2 ) volumetric emissions at ambient

conditions

MT = Meter reading of gas emissions per unit time

T

= Total time the compressor associated with the wet seal(s) is operational in the reporting year

M i = Mole percent of GHG i in the degassing vent gas

B = percentage of centrifugal compressor we t seal degassing vent gas sent to vapor recovery or fuel gas or other be neficial use as determined by keeping logs of the number of operating hours for the vapor recovery system or recycle to fuel gas system

A sample representative of the gas to the degassing vent can be taken every quarter to evaluate the composition of GHGs present in the stream using ASTM D1945-03. Some facilities may send their degassing vent vapors to a flare or to fuel use. The monitoring

method will have to account for this.

10. Reciprocating compressor rod packing venting

There are three primary considerations for emissions from rod packing on reciprocating compressors. First, the rod packing case may or may not be connected to an open ended line or vent. Second, the rod packing may leak through the nose gasket in addition to the emissions directed to the vent. And third, the emissions from rod packing will vary depending on the mode of operation of the r eciprocating compressor – running, standby and pressurized, or standby and de-pressurized.

If the rod packing case is connected to an ope n ended line or vent then emissions from the rod packing case can be estimated using baggi ng or high volume sampler. Alternatively, a temporary meter such as vane anemometer or permanent meter such as orifice meter can be used to measure emissions from rod packing vents.

If the rod packing case is open to the atmosphere then the emissions from the rod packing case will be mingled with the emissions from the nose gasket. The emissions from an open rod packing case usually will migrate to the distance piece (dog house), and if the distance piece is enclosed then this emissions will migr ate to the engine crank case, before being emitted to the atmosphere. There are two possi ble options to monitor these emissions. The

Background Technical Support Document – Petroleum and Natural Gas Industry 48first option is to use an emi ssions factor for rod packing al ong with a popul ation count. The second option is to require fugitive emissions detection and measurem ent to determine the

exact location and volume of emission.

Typically, rod packing emissions vary with th e mode of operation of the compressor. The emissions are highest when the compressor is operating and lower when they are in standby pressurized mode. When the compressor is standby de-pressurized there might be some migration of natural gas from the unit isolation valve through the rod packing. But this is for the most part, negligible. Hence to correctly characterize annual emissions from rod packing, estimation of emissions at two compressor m odes, operating and standby pressurized, may be required.

11. Storage tanks

Emissions from storage tanks can be estimat ed using one of the following three methods.

Method 1:

In the case of storage tanks, emissions ra tes are not constant; and thus, a one-time measurement may not provide accurate emissions rates for the entire reporting period. To accurately estimate emissions from storage ta nks, it is necessary to conduct a one-time measurement during a cycle of ope ration that is representative of the tank operations through the year. The following equation can be used to calculate GHG emissions:

ERQE

ha ×=

, Equation 13

where,

E a,h = hydrocarbon vapor emissions at ambient conditions, in cubic meters

Q = storage tank total annual throughput, in barrels

ER = measured hydrocarbon vapor em issions rate per throughput (e.g. meter/barrel)

ER can be estimating using the following procedure:

• The hydrocarbon vapor emissions from stor age tanks can be measured using a flow meter for a test period that is representative of the normal operating conditions of the storage tank throughout the year and which includes a complete cycle of accumulation of hydrocarbon li quids and pumping out of hydrocarbon liquids from the storage tank.

• The throughput of the storage tank duri ng the test period can be recorded.

• The temperature and pressure of hydro carbon vapors emitted during the test period can be recorded.

• A sample of hydrocarbon vapors can be collected for composition analysis.

Background Technical Support Document – Petroleum and Natural Gas Industry 49Method 2:

A second method is to use simulation software such as E&P Tank (GEO-RVP) to estimate vented emissions from storage tanks. Therefor e, any standard simulation software could be used assuming it accounts for the following operational parameters:

• Feed liquid flow rate to tank;

• Feed liquid API gravity;

• Feed liquid composition or characteristics;

• Upstream (typically a separator) pressure;

• Upstream (typically a separator) temperature;

• Tank or ambient pressure; and

• Tank or ambient temperature;

• Sales oil API gravity;

• Sales oil production rate;

• Sales oil Reid vapor pressure;

Method 3:

A third method for storage tank vented emission s quantification is use of the Vasquez-Beggs equation. This correlation equation provides an estimate of the gas-to-oil ratio for flashing tank vapors; however, it does not provide the GHG of the vapors, so composition analysis of tank vapors is still required. Equation 14 demonstrates the use of this correlation equation:



# ( ) ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

+ × ×+××= 460 exp7.14

sep oil

sep fg T GC PGAGOR Equation 14

where,

GOR = ratio of flash gas production to stan dard stock tank barrels of oil produced,

in standard cubic feet/barrel (barrels corrected to 60°F)

G

fg

= Specific gravity of the tank flash gas, where air = 1. A suggested default

value for G fg

is 1.22

G oil = API gravity of stock tank oil at 60°F

P

sep = Pressure in separator (or other ve ssel directly upstream), in pounds per square inch gauge

T

sep = Temperature in separator (or other vess el directly upstream of the tank), °F

A = 0.0362 for G oil </= 30°API, or 0.0178 for G oil > 30°API

B = 1.0937 for G oil </= 30°API, or 1.187 for G oil > 30°API

C

= 25.724 for G oil </= 30°API, or 23.931 for G oil > 30°API

Sometimes one or more emissions source vents ma y be connected to the storage tank. In such cases the emissions from these sources will be commingled with the emissions from the storage tank. In addition, two phase separators directly upstr eam of the storage tank may not

have a vortex breaker. This can lead to channe ling of natural gas from the separator to the storage tank. All these multiple scenarios mean that only Method 1 could potentially capture

Background Technical Support Document – Petroleum and Natural Gas Industry 50such miscellaneous sources connected to th e storage tank. If, however, Method 1 is performed at a time when say the separator is not vortexing then even Method 1 may not capture the emissions from the miscellaneous emissions sources conn ected to the storage tank. Hence there is no single method that can identify these variations in storage tank emissions that represent multiple sources. Thes e data are available from two recent studies provided by the Texas Commission on Environmental Quality (2009) and the Texas Environment Research Consortium (2009) that highlight this fact. A potential option to

correct such scenarios where other emissions s ources are connected to the storage tank or if the separator is vortexing is to use multiplier s on emissions estimated from Methods 1 and 2 above. Two such potential multipliers are as below,

(i) The emissions for sales oil less than 45 API gravity can be multiplied by 3.87

(ii) The emissions for sales oil equal to or greater than 45 API gravity can be multiplied by 5.37

Details on the development of these mu ltipliers are available in Appendix J.

Storage tanks in the onshore natural gas transm ission segment typically store the condensate from the scrubbing of pipeline quality gas. Th e volume of condensate is typically low in comparison to the volumes of hydrocarbon liquid s stored in the upstream segments of the industry. Hence the emissions from condens ate itself in the transmission segment are insignificant. However, scrubber dump valves ofte n get stuck due to debris in the condensate and can remain open resulting in natural gas loss via the open dump valve. This natural gas then flows through the storage tank. The only po tential option to meas uring emissions from scrubber dump valves is to monitor storage tank emissions to determine if the emissions do not subside and become negligib le. If the scrubber dump valve is stuck and leaking natural gas to the tank then the emissions will be visibly significant and will not subside to inconspicuous volumes. If the scrubber dump va lve functions normally and shuts completely after the condensate has been dumped then the storage tank emission s should subside and taper off to insignificant quantities; this will happen because once the condensate has flashed the dissolved natural gas there will not be si gnificant emissions from the storage tank. If persistent and significant emissions are detected then a measurement may be required using a

temporary meter.

Storage tank vapors captured using vapor recovery systems or sent to flares will have to be

accounted for in the above method.

12. Well testing venting and flaring

During well testing the well usually is flow ing freely and the produced hydrocarbons are typically vented and/ or flared. A gas to oil ratio is often determined when conducting well testing. This information can be reliably used to estimate emissions from well testing venting using the equation below:

DFRGORE

ns **

, = Equation 15

Background Technical Support Document – Petroleum and Natural Gas Industry 51where,

E s,n = Annual volumetric natural gas emissions from well testing in cubic feet

under ambient conditions

GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities

FR = Flow rate in barrels of oil per day for the well being tested

D = Number of days during th e year, the well is tested

When well testing emissions are sent to a flare then the emissions es timated above should be adjusted to reflect the combustion emissions.

13. Associated gas venting and flaring

Often times when onshore petroleum production fiel ds are located in a remote location, the associated gas produced is sent to a vent or flare. This is beca use the associated natural gas is stranded gas, meaning that it is not economical to send the usually low volumes to the market via a pipeline system. In such cases the emissions can be estimated using the volume of oil produced and the corresponding gas to oil ratio as following;

Vented associated natural gas emissions can be estimated using the following equation,

VGORE

na *

, = Equation 16

where,

E a,n = Annual volumetric natural gas emi ssions from associated gas venting under ambient conditions, in cubic feet

GOR = Gas to oil ratio in cubic feet of gas per barrel of oil; oil here refers to hydrocarbon liquids produced of all API gravities

V

= Total volume of oil produced in barrels in the reporting year

When well testing emissions are sent to a flar e then the emissions estimated above will have to be adjusted to reflect the combustion emissions.

14. Hydrocarbon liquids dissolved CO 2 Onshore petroleum production that uses EOR with CO 2 injection results in the production of petroleum that has significant amounts of CO 2 dissolved in it. This CO 2 is usually separated from the liquid petroleum component, and re-inj ected in a closed loop system (although this

CO 2 might be eventually recovered when the EOR operation at the site is closed). However, the liquid portion of petroleum still contains dissolved CO 2 , since separation usually takes place at higher than ambient pressure. Most of this CO 2 is then released in a storage tank

where the CO 2 flashes out of the liquid hydrocarbons. Bu t even after this stage some amount

of CO 2 remains entrapped in the liquid hydrocarbons and is lost to the atmosphere during the transportation and processing phases.

Background Technical Support Document – Petroleum and Natural Gas Industry 52The amount of CO 2 retained in hydrocarbon liquids after flashing in tanks can be determined by taking quarterly samples to account for retention of CO 2 in hydrocarbon liquids immediately downstream of the storage tank. The emissions from this hydrocarbon dissolved CO2 can be estimated using the following equation,

Mass s, CO2 = S hl

* V hl Equation 17

where,

Mass s, CO2 = Annual CO 2 emissions from CO 2 retained in hydrocarbon liquids beyond tankage, in metric tons.

S

hl

= Amount of CO 2 retained in hydrocarbon liquids in metric tons per barrel, under standard conditions.

V

hl

= Total volume of hydrocarbon liq uids produced in barrels in the reporting year.

15. Produced water dissolved CO 2 EOR operations often use water inje ction techniques to push the CO 2 soaked petroleum through the reservoir and up the production well. This water, like the liquid petroleum,

contains dissolved CO 2 , since CO 2 readily dissolves in water. This produced water is recirculated for injection into th e reservoir. However, often it may be sent through tankage to avoid a two phase flow of CO 2 and water through the injection pumps. In such cases the CO 2 dissolved in the water is flashed to the atmosphere in the storage tank.

These emissions can be determined similar to hydrocarbon dissolved CO 2 by sampling the water on a periodic basis. To determine retention of CO 2 in produced water immediately downstream of the separator where hydrocarbon liquids and produced water are separated the following equation can be used.

Mass s, CO2 = S pw * V pw Equation 18

where,

Mass s, CO2 = Annual CO 2 emissions from CO 2 retained in produced water beyond tankage, metric tons.

S

pw = Amount of CO 2 retained in produced water in metric tons per barrel, under

standard conditions.

V

pw = Total volume of produced water produ ced in barrels in the reporting year.

Background Technical Support Document – Petroleum and Natural Gas Industry 53EOR operations that route produced water from separation directly to re-injection into the hydrocarbon reservoir in a closed loop system without any leakage to the atmosphere could be exempted from reporting.

16. Well venting for liquids unloading

There are three potential methods to estimate well venting emissions from liquids unloading. Method 1 requires installation of a flow mete r temporarily for developing an emissions factor. Method 2 requires a transient pressure sp ike engineering analysis across the vent pipe during one well unloading event. Method 3 uses an engineering calcula tion method that uses the well’s physical parameters to estimate emissions. Each of the three options is discussed

below.

Method 1: For each unique well tubing diameter and pr oducing horizon/formation combination in each gas producing field where gas wells are vented to the at mosphere to expel liquids accumulated in the tubing, a recording flow meter can be installed on the vent line used to vent gas from the well (e.g. on the vent line off the separator or a storage tank). An emissions factor can be estimated as an averag e flow rate per minute of venting calculated for each unique tubing diameter and produc ing horizon/formation combination in each producing field. The emission factor can be applied to all wells in the field that have the same tubing diameter and producing horizon/formati on combination, multiplied by the number of minutes of venting of all wells of the same tubing diameter and producing horizon/formation combination in that field. A new factor can be determined periodically to track field declining formation pressu re and flow potential.

Method 2:

For each unique well tubing diameter and pr oducing horizon/formation combination in each gas producing field where gas wells are vented to the at mosphere to expel liquids accumulated in the tubing, an engineering analys is of the transient pressure spike across the vent line for well unloading events can be conducte d. An emissions factor as an average flow rate per minute of venting can then be calcu lated through such an analysis. This emissions factor can be applied to all wells in the fi eld that have the same tubing diameter and producing horizon/formation combination, multip lied by the number of minutes of venting all wells of the same tubing diameter and pr oducing horizon/formation combination in that

field. A new emission factor can be determined periodically to track field declining formation pressure and flow potential. Emissions from well venting for liquids unloading can be calculated using the following equation,

E

s,n = T * X * EF Equation 19

where,

E s,n = Annual natural gas emissions at standard conditions

T

= Amount of time of well venting

Background Technical Support Document – Petroleum and Natural Gas Industry 54X = Concentration of GHG i in gas vented.

EF = Emission factor developed usi ng the transient pressure spike

For wells that have a plunger lif t installed on a timer or progra mmable logic controller that vent to the atmosphere and automatically closes the vent valve when the plunger is received at the well head, an equation calculating the volum e of gas in the tubing string calculated at sales pipeline pressure can be used. This equa tion is unique for each category of wells with the same well depth and tubing size. The emissions factor can be estimated by multiplying the tubing cross-sectional area by the tubing string length from wellhead to the bottom resting location of the plunger, corrected for sales line pressure a nd average gas flowing

temperature.

Method 3:

The Natural Gas STAR Lessons Learned – Inst alling Plunger Lift Systems in Gas Wells (available at < http://epa.gov/gasstar/ documents/ll_plungerlift.pdf >) provides an engineering estimation method in its Appendix. This method us es physical characteristics of the well that are usually well known. Usi ng this method, emissions from well venting for liquids unloading can be calculated us ing the following equation:

E

s,n = {(0.37×10 -3 ) * CD 2 * WD * SP * V} + {SFR*HR} Equation 20

where,

E s,n = Annual natural gas emissions at standard conditions, in cubic feet/year

0.37×10 -3 = {pi(3.14)/4}/{(14.7*144) psia c onverted to pounds per square feet}

CD = Casing diameter (inches)

WD = Well depth (feet)

SP = Shut-in pressure (psig)

V

= Number of vents per year

SFR = Sales flow rate of gas well in cubic feet per hour

HR = Hours that the well was le ft open to the atmosphere during unloading

17. Gas well venting during well completions and workovers

There are two methods to estimate emissions from gas well venting during well completions and workovers. Method 1 requires the installation of a recording flow meter on the vent line to the atmosphere or to a flare. Method 2 is an engineering calculation based on the pressure drop flow across the well choke. Method 3 uses the production of the well to determine

emissions.

Background Technical Support Document – Petroleum and Natural Gas Industry 55Method 1:

A recording flow meter can be in stalled on the vent line to the atmosphere or to a flare during each well unloading event. This one time read ing can be extrapolated to yearly emissions based on the time taken for completion or wo rkover and the number of times the well is worked over (if more than once per year). Su ch emissions factors can be developed for representative wells in a field on a yearly basis. During periods when gas is combusted in a flare, the carbon dioxide quantity can be de termined from the gas composition with an adjustment for combustion efficiency. This me thod can also be used when phase separation equipment is used and requires th e installation of a recording fl ow meter on the vent line to the atmosphere or to a flare.

Emissions from gas well venting during well completions and workovers from hydraulic fracturing can be calculate d using equation 21 below;

E

s,n = T * FR Equation 21

where,

E s,n = Annual natural gas vented emissions at ambient conditions in cubic feet

T

= Cumulative amount of time in hour s of well venting during the year

FR = Flow rate in cubic feet per hour, under ambient conditions

Method 2:

Using pressures measured before and after th e well choke, an engineering calculation of the average flow rate across the choke can be done. Using engineering judgment and the total

time that flow across the choke is occurring, the tota l volume to the atmosphere or a flare during the back-flow period can be estimated. This one time reading can be extrapolated to yearly emissions based on the time taken fo r completion or workover and the number of times the well is worked over (if more than on ce per year). Such emissions factors can be developed for representative wells in a field on a yearly basis.

Method 3:

A quick and least burdensome method to dete rmine emissions from well venting during completions and workovers is to use the daily gas production rate to es timate emissions using the following equation,

i is GHGTVE **

, = Equation 22

where,

E s,i = Annual GHG emissions in cubic fe et at standard conditions from gas well venting during conventional well completions or workovers

Background Technical Support Document – Petroleum and Natural Gas Industry 56V = Daily gas production rate, in cubic feet per minute

T

= Cumulative amount of time of we ll venting in minutes during the year

GHG i = for onshore petroleum and natural ga s production facilities, fraction of

GHG i , CH 4 or CO 2 , in produced natural gas



### c. Leak detection and leaker emission factors

For fugitive emissions sources that are standa rd components such as connectors, valves, meters, etc. emissions can be estimated by c onducting a fugitive emissions detection program and applying a leaker emissions factor to t hose sources found to be emitting. The following Equation 23 can be used for this purpose.

TGHGEFCount E
i

is ***

, = Equation 23

where,

E s,j = Annual total volumetric GHG emissions at standard conditions from a fugitive source

Count = Total number of this type of emission source found to be leaking

EF = Leaker emission factor for specific sources listed in Appendix J.

GHG i = for onshore natural gas processing facilities, conc entration of GHG i , CH 4 or CO 2 , in feed natural gas; for other facilities GHG i equals 1

T = Total time the specific source associated with the fugitive emission was operational in the reporting year, in hours

Leaker emissions factors are available for specific sources for onshore natural gas processing facilities, onshore natural ga s transmission compression facilities, underground natural gas storag e facilities, liquefied natural gas storage facilities, liquefied natural gas import and export facilities, and natu ral gas distribution

facilities. These leaker emissions factor s and a discussion on their development are available in Appendix K.

Background Technical Support Document – Petroleum and Natural Gas Industry 57

### d. Population Count and Emission Factors.

For fugitive emissions that are geographically di spersed or where the cost burden is an issue emissions can be estimated using the popu lation count of emi ssions sources and a corresponding population emissions factor. Such an option may be most feasible for emissions sources with gas content greater than 10 percent CH 4 plus CO 2 by weight since otherwise the emissions factors may overest imate overall GHG emissions. Emissions from all sources listed in this paragraph of this section can be calcula ted using the following equation.

TGHGEFCountE
i is ***

, = Equation 24

where,

E s,i = Annual total volumetric GHG emissi ons at standard conditions from each fugitive source

Count = Total number of this type of emission source at the facility

EF = Population emission factor for sp ecific sources listed in Appendix K.

GHG i = for onshore petroleum and natural gas production facilities and onshore natural gas processing faciliti es, concentration of GHG i, CH 4 or CO 2 , in produced natural gas or feed natu ral gas; for other facilities GHG i equals

1

T = Total time the specific source associated with the fugitive emission was operational in the reporting year, in hours

Population emissions factors ar e available for specific sour ces for onshore petroleum and natural gas production facilities, onshore natura l gas processing facilities, onshore natural gas transmission compression facilities, unde rground natural gas st orage facilities, liquefied natural gas storage f acilities, liquefied natural ga s import and export facilities, and natural gas distribution f acilities. These population emissi ons factors and a discussion on their references are available in Appendix L.



### e. Method 21

This is the authorized met hod for detecting volatile orga nic carbon (VOC) emissions under Title 40 CFR The method specifies the performance of a portable VOC emission detection instrument with a probe not exceeding one four th inch outside diameter, used to slowly circumscribe the entire component interface where fugitive emissions could occur. The probe must be maintained in close proximity to th e interface; otherwise it could be damaged by rotating shafts or plugged with ingested lubric ants or greases. In most cases, it can be no more than 1 centimeter away from the leak interface. Method 21 does not specify leak

Background Technical Support Document – Petroleum and Natural Gas Industry 58definitions; they are defined within specific subparts of the Title 40 CFR. Method 21 also allows certain alternative fugitive emissions detection methods, such as soap solutions (where the fugitive emissions source is below the boiling point and above the freezing point of the soap solution, does not have areas open to the atmosphere that the soap solution cannot bridge, and does not have signs of liquid leak age). Method 21 does not specify any emissions mass or volumetric quantification methods, but only specifies an emissions concentration expressed in parts per million of combustible hydrocarbons in the air stream of the instrument probe. This leak detection data has been used by state em ission inventories with “leaker” factors developed by the Syntheti c Organic Chemicals Manufacturing Industry (SOCMI) 6 to estimate the quantity of VOC emissi ons. SOCMI factors were developed from petroleum refinery and petrochemical plant da ta using Method 21. SOCMI factors adjusted for methane content are considerably lower than the methane factors proposed in this rule, which were developed from more recent studies of gas processing plants and compressor

stations.

Performance standards for remote leak sensing devices, such as those based on infrared (IR) light imaging, or laser beams in a narrow wavelength absorbed by hydrocarbon gases, were promulgated in the general provisions of EPA 40 CFR Part 60. This alternate work practice (AWP) permits leak detection using an instru ment which can image both the equipment and leaking gas for all 40 CFR 60 subparts that require monitoring under Method 21.

Although leak detection with Method 21 or the AWP in their current form in conjunction with leaking component emission factors may not be the best suited for all mandatory reporting, the principle could potentially be adopted for estimating emissions from minor sources such as fugitive emissi ons from components. Emissions can be detected from sources (including those not required under Method 21, i.e. not within arm’s reach) using AWP procedures for the optical ga s imaging instrument, and appl ying leaker emissions factors available from studies conducted specifically wi th methane emissions in its scope. This will be easier for industry to adapt to and also avoid the use of Synthe tic Organic Chemical Manufacturing Industry correlation equations or leak factor s developed specifically for different industry segments (i.e. petroleum refi neries and chemical plants). This method will

also result in the estimation of real emissions, as opposed to potential emissions from population emissions factor calculations.



### f. Portable VOC Detection In struments for Leak Measurement

As discussed above under Method 21, portable VOC detection instruments do not quantify the volumetric or mass emissions. They qua ntify the concentration of combustible hydrocarbon in the air stream induced thr ough the maximum one fourth inch outside diameter probe. Since these small size probes rare ly ingest all of the fugitive emissions from a component leak, they are used primarily fo r fugitive emissions detection. EPA provides emissions quantification guidelines, derived from emissions detection data, for using portable

VOC detection devices. One choice of instrument emissions detection data is referred to as

6 EPA (1995). Protocol for Equipment Leak Emission Estimates. Research Triangle Park, NC. Publication No. EPA-453/R-95-017. Online at: http://www .epa.gov/ttnchie1/efdocs/equiplks.pdf

Background Technical Support Document – Petroleum and Natural Gas Industry 59“leak/no-leak”, where equipment is determined to be leaking when the portable instrument indicates the provided leak defi nition. Different leak definitions are specified within the subparts of the Clean Air Act. Subpart KKK of 40 CFR Part 60 defines “leakers” for natural gas processing facilities as components with a concentration of 10,000 ppm or more when measured by a portable leak detection instrume nt. Components that are measured to be less than 10,000 ppm are considered “not leaking.” He nce, these quantificatio n tables have a “noleak” emission factor for all components foun d to have emissions rates below the leak definition, and “pegged” emission factors fo r all components above the leak definition. Alternatively, the “stratified” method has em ission factors based on ranges of actual leak concentrations below, at and above the leak de finition. Portable leak detection instruments normally peg at 10,000 ppm, and so are unsuitable for use with the “stra tified” quantification factors. For the proposed rule, fugitive emissions detection by more cost-effective screening technologies in conjunction with leaker emission factors are considered a better approach to emissions quantification than the labor intensive Method 21.



### g. Mass Balance for Quantification

There are mass balance methods that could be considered to calculate emissions from a reporting program. This approach would take into account the volume of gas entering a facility and the amount exiting the facility, with the difference assumed to be emitted to the atmosphere. This is most often discussed fo r emissions estimation from the transportation segment of the industry. For transportation, the mass balance is often not recommended because of the uncertainties surrounding meter readings and the large volumes of throughput relative to fugitive emissions. The mass balance approach may, however, be feasible in cases where the volume of emissions is significantl y large and recognizable as meter readings. One such source is an acid gas reco very unit where the volume of CO 2 extracted from natural gas is significant enough to be registered in a compositional difference of the natural gas and can be determined using mass balance.



### h. Gulf Offshore Activity Data System program (GOADS)

The Mineral Management Service conducts a co mprehensive activity data collection effort under its Gulf Offshore Activity Data Syst em program (GOADS). This requires all petroleum and natural gas production platforms lo cated in the Federal Gulf of Mexico (GoM) to report their activities to MMS once in every fo ur years. The activity data reported includes counts of emissions sources, volumes of throughput s from several pieces of equipment, fuel consumption by combustion devices, and parametric data related to certain emissions sources such as glycol dehydrators. This activity data is then converted into emissions estimates by MMS and reported subsequently by MMS. The MMS summary report provides estimates of

GHG emissions in the GoM as well as a detailed database of emissions from each source on platform in the GoM. The EPA could potentia lly use this data reported by the GOADS program. However, since the data are only co llected once every four years, EPA will not receive new emissions information for every reporting period. This means that between MMS reporting periods if a new platform is commissioned, an old platform is decommissioned, new equipment is installed on existing platforms, or operating levels of

Background Technical Support Document – Petroleum and Natural Gas Industry 60platforms change then this information will no t get recorded and reported for periods when MMS GOADS is not being conducted. Finally, the MMS GOADS program does not collect information from platforms in the GoM under Stat e jurisdiction, as well as platform in the Pacific and Alaskan coasts. These platform s not under GOADS pur view will not have existing data to report if GOADS re porting were to be adopted by EPA.



### i. Additional Questions Regardi ng Potential Monitoring Methods

There are several additional issu es regarding the potential m onitoring methods relevant to estimating fugitive and vented emissions from the petroleum and natural gas industry.



### i. Source Level Fugitive Em issions Detection Threshold

This document does not indicate a particular fugitive emissions definition or detection threshold requiring emissions measurement. Th is is because different fugitive emissions

detection instruments have diffe rent levels and types of detection capabilities, i.e. some instruments provide a visual image while othe rs provide a digital value on a scale (not necessarily directly related to mass emissions). Hence the magnitude of actual emissions can only be determined after measurement. This , however, may not serve the purpose of a reporting rule, which is to limit the burden by focusing only on significant sources of emissions. A facility can have hundreds of sma ll emissions (as low as 3 grams per hour) and it might not be practical to meas ure all of them for reporting.

There are, however, two possible approaches to overcome this issue, as follows; provide an instrument performance standard such that any source determined to be emitting per the instrument is considered an emissions source, or provide a threshold value for the emitter such that any source below the threshold magnitude is not considered an emitter.

Instrument Performance Standards Performance standards can be provided for fugitive emissions detection instruments and usage such that all instruments follow a minimum common detection threshold. Alternatively, the AWP to Detect Leaks from Equipment standards for optical gas imaging instruments recently adopted by EPA can potentially be proposed. In such a case, all detected emissions from components subject to the proposed rule may require measurement and reporting. This avoids the necessity of specifying performance standards.

Method 21 instrumentation technolo gy has been used for over 30 years to detect leaks. The approach uses gas concentration measurement of air and combustible gas drawn into the tip of a probe manually circumscribed on or within one centimeter along th e entire potential seal surface or center of a vent to detect fugitive em issions. This original practice is required for certain regulated components that are reachable with the hand-h eld leak detection instrument used while standing on the ground or fixed platfo rm accessible by stairs (i.e. does not require climbing ladders, standing on stools or use of bucket-lift trucks to access components). In a

Background Technical Support Document – Petroleum and Natural Gas Industry 61study conducted by API at se ven California refineries 7 with over five years of measured data (11.5 million data points), it was found that 0.13 percent of the components contributed over 90 percent of the controllable emissions (i.e. fugitive or vented emissions that can be mitigated once detected). Given the fact that only a small number of sources contribute to the majority of emissions, it is important for this proposed supplemental rule to detect and quantify leaking sources beyond the scope of Method 21.

In a typical Method 21 program the costs of co nducting emissions detection remain the same during each recurring study period. This is beca use the determination of whether a potential source is emitting or not is made only after ev ery regulated source is screened for emissions as described above. The OVA/TVA requires the operator to physically access the emissions source with the probe and thus is much more time intensive than using the optical gas imaging instrument. Optical gas imaging instru ments were found to be more cost effective for leak detection for the proposed supplemental rule as these instruments are able to scan hundreds of source components quickly, incl uding components out of reach for an

OVA/TVA.

The EPA Alternative Work Pr actice (AWP) promulgated the use of optical gas imaging

instruments that can detect in some cases em issions as small as 1 gram per hour. The AWP requires technology effectiveness of emissions statistically e quivalent to 60 grams/hour on a bi-monthly screening frequency, i.e. the techno logy should be able to routinely detect all emissions equal to or greater than 60 grams/hour. EPA determined by Monte Carlo simulation that 60 grams/hour leak rate thres hold and bi-monthly monitoring are equivalent to existing work practices (Method 21). To implement the technology effectiveness, the AWP requires that the detection instrument m eet a minimum detection sensitivity mass flow rate. For the purposes of the proposed supplemen tal rule, such a performance standard could be adapted for the detection of natural gas emissions with methane as the predominant component (it should be noted that Method 21 is specifically meant for VOCs and HAPs and not for methane). A detailed discussion on th e available instruments and standards for methane emission detection and quantific ation are presented in Appendix O.

Fugitive Emissions Threshold One alternative to determining an emission source is to provide a mass emissions threshold for the emitter. In such a case, any source that emits above the th reshold value would be considered an emitter. For portable VOC monitoring instruments that measure emission concentrations a concentration threshold equi valent to a mass thresh old can be provided. However, the concentration measurement is c onverted to an equivalent mass value using SOCMI correlation equations, which were de veloped from petroleum refinery and petrochemical plant data. As discussed above, these SOCMI factors are not proposed for this supplemental rule. In the case of an optical imaging instrument , which does not provide the magnitude of emissions, either concentrati on or mass emissions, qua ntification would be required using a separate measurement instru ment to determine whether a source is an emitter or not. This could be very cost prohibitive for the purposes of this rule.

7 Hal Taback Company Analysis of Refinery Screening Data , American Petroleum Institute, Publication Number 310, November 1997.

Background Technical Support Document – Petroleum and Natural Gas Industry 62

### ii. Duration of Fugitive Emissions

Fugitive emissions by nature occur randomly within the facility. Therefore, there is no way of knowing when a partic ular source started emitting. If the potential monitoring method requires a one time fugitive emissions detection and measurement, then assumptions will have to be made regarding the duration of the emissions. There are several potential options for calculating the duration of emis sions. If a component fugitive emission is detected, total emissions from each source co uld be quantified under one of the following three scenarios: 1) if a facility conducts one comprehensive leak survey each reporting period, applicable component leaker emission s factors could be ap plied to all specific component emissions sources and emissions qua ntified based on emissions occurring for an entire reporting period; 2) if a facility condu cts two comprehensive leak surveys during a single reporting period, a pplicable component leaker emission s factors could be applied to all component emissions sources. If a specific emis sion source is found not leaking in the first survey but leaking in the sec ond survey, emissions could be qua ntified from the date of the first leak survey conducted in the same reportin g period forward through the remainder of the reporting period. If a specific emissions source is found leaking in the first survey but is repaired and found not leaking in the second su rvey, emissions could be quantified from the first day of the reportin g period to the date of the second survey. If a component is found leaking in both surveys, emissions could be quantified based on an emission occurring for an entire reporting period; 3) if a facility conducts multiple comprehensive leak surveys during the same reporting period, applicable component leaker emissions factors could be applied to component emissions sources. Each specific so urce found leaking in one or more surveys is quantified for the period from a prior finding of no leak (or beginning of the reporting period) to a subsequent finding of no leak (or end of the reporting period). If a component is found leaking in all surveys, emissions could be qua ntified based on an emi ssions occurring for an entire reporting period.



### iii. Fugitive and Vented Emissions at Different Operational Modes

If a reporting program relies on a one time or periodic measurement, the measured emissions may not account for the different modes in wh ich a particular tec hnology operates throughout the reporting period. This may be particularly true for measurements taken at compressors. Fugitive emissions from a compressor are a function of the mode in which the compressor is operating: i.e. offline pressurized, or offline de-pressurized. Typically, a compressor station consists of several compressors with one (or more) of them on standby based on system redundancy requirements and peak delivery capacity. When a comp ressor is taken offline it may be kept pressurized with natural gas or de-pressurized. When the compressor is offline and kept pressurized, fugitive and vented emissions result from closed blowdown valves and reciprocating compressor rod packing leaks, re spectively. When the compressor is offline and depressurized, fugitive emissions result fr om leaking isolation valves. When operating, compressor vented emissions result from co mpressor seals or rod packing and other components in the compressor system. In each of the compressor modes the resultant fugitive and vented emissions are signifi cantly different. One potential approach to address this issue is that operators measure emissions for each mode the compressor is operated in and the period of time during the reporting period at whic h the compressor is in the different modes

Background Technical Support Document – Petroleum and Natural Gas Industry 63to account for the varying levels of fugitive and vented emissions. However, this will increase the reporting burden. Measurements will have to be taken at each mode of compressor operation and the time that the equi pment is in various operational modes would

also have to be tracked.

A similar issue exists with ta nks where the operati onal parameters change more dynamically than compressors. The amount of throughput th rough tanks varies continuously as new hydrocarbon liquids are introduced and stored liquids are w ithdrawn for transportation. Unlike other equipment, the opera tional level of tanks cannot be categorized into a fixed and

limited number of modes. This makes it all th e more challenging to characterize emissions from storage tanks. One option is to require operators to use best judgment and characterize a few different modes for the storage tanks and make adjustments to the monitored emissions accordingly. A detailed discussion on the issue of operational modes, their impact on emissions monitoring, and potential options for monitoring emissions from emissions sources with varying modes of operation are can be found in Appendix M.



### iv. Natural Gas Composition

When measuring fugitive and vented emissions using the various measurement instruments (high volume sampler, calibrated bags, and me ters measure natural gas emissions) or using engineering estimation for vented emissions, only flow rate is m easured or calculated and the

individual CH 4 and CO 2 emissions are estimated from the natural gas mass emissions using natural gas composition appropriate for each facility. For this purpose, the monitoring methodologies discussed above would require th at facilities use existing gas composition

estimates to determine CH 4 and CO 2 components of the natural ga s emissions (flare stack and storage tank vented emissions are an exception to this general rule). These gas composition

estimates are assumed to be available at facili ties. But this may or may not be a practical assumption. In the absence of gas composition, periodic measurement of the required gas composition for speciation of the natural gas mass emissions into CH 4 and CO 2 mass emissions could be a potential option.

In addition, GHG components of natural gas may change significantly in the facilities during the reporting period and different sources in the same facility may be emitting different compositions of natural gas. This is mo st prevalent in onshore production, offshore production and natural gas processing facilities . One potential option is to apply an average composition across all emissions sources for the re porting facility. Anothe r option is to apply specific composition estimates across similar str eams in the same facility. For example, in processing, the natural gas composition is si milar for all streams upstream of the demethanizer. The same is true of all equipmen t downstream of the de-methanizer overhead. For onshore production and offshor e production monthly or quarter ly samples can be taken

to account for the vari ation in natural gas be ing produced from differe nt combinations of production wells throughout the reporting period . See Appendix N for a detailed discussion

on this issue.

Background Technical Support Document – Petroleum and Natural Gas Industry 64

### v. Physical Access for Leak Measurement

All emissions measurement techniques require physical access to the leaking source. The

introduction of remote leak detection technol ogies based on infrared (IR) light absorption by hydrocarbon gas clouds from atmospheric leaks makes leak detection quicker and possible

for sources outside of arms reach from the ground or fixed platforms. Fugitive emissions from flanges, valve stems, equipment covers, et c. are generally smaller than emissions from vents. Fugitive emissions are expensive to measure where they are not accessible within arms reach from the ground or a fixed platform. For these inaccessible sources, the use of emission factors for emissions quantification may be appropriate. Ve nt stacks are often located out of access by operators for safety purposes, but may represent large emission sources. Where emissions are detected by op tical gas imaging instruments, emissions measurement may be cost-effective using the following source access techniques:

 Short length ladders positioned on the ground or a fixed platform where OSHA regulations do not require pe rsonnel enclosure and the measurement technique can be performed with one hand;

 Bucket trucks can safely position an ope rator within a full surround basket allowing both hands to be used above the range of ladders or for measurement techniques requiring both hands;

 Relatively flat, sturdy roofs of equipment buildings and some tanks allow safe access to roof vents that are not normally accessibl e from fixed platforms or bucket trucks;

 Scaffolding is sometimes installed for operational or maintenance purposes that allow access to emission sources not normally accessible from the ground, fixed platforms

and out of reach of bucket trucks.

Accessibility issues and these potential solutions are discussed in more detail in Appendix G.



### 7. Procedures for Esti mating Missing Data

It is possible that some companies would be missing data necessary to quantify annual emissions. In the event that data are missing, potential procedures to fill the data gap are outlined below and are organized by data type.

In general, although there is alwa ys the possibility of using a pr evious years’ data point to replace missing data in the current reporting year , this is not ideal since varying operating conditions can dramatically impact emissions es timates. Where using previous years’ data are not desirable, then a reporti ng rule might require 100% data av ailability. In other words, there would be no missing data procedures provid ed. If any data were identified as missing, then there would be an opportunity to recollec t the emissions data over the course of the current reporting period.



### a. Emissions Measurement Data

Measured data can be collected by trained engineers using a high volume sampler, meter, or calibrated bag. Over the course of the data collection effort, so me of the measured emissions rates could get lost temporarily or permanently due to human error, or storage errors such as

Background Technical Support Document – Petroleum and Natural Gas Industry 65lost hard-drives and records. If measured da ta is missing then the field measurement process may have to be repeated within the reporting pe riod. If this proves to be impossible and the company clearly certifies that they lost the da ta and can justify not repeating the survey within the given reporting period, then the previous reporting pe riod’s data could be used to estimate fugitive emissions from the current reporting period.



### b. Engineering Estimation Data

Engineering estimations rely on the collection of input data to the simulation software or calculations. A potential procedure for missing i nput data is outlined below for each type of input parameter.

• Operations logs. If operating logs are lost or damaged for a current reporting period, previous reporting period’s data could be used to estimate emissions. Again, using previous years’ data are not as desirable as there could be significant differences from year to year based on operating conditions.

• Process conditions data. Estimating vented emissions from acid gas removal vent stacks, blowdown vent stacks, dehydrator ve nt stacks, natural ga s driven pneumatic valve bleed devices, natural gas driven pne umatic pumps, and storage tanks requires data on the process conditions (e.g., pro cess temperature, pres sure, throughputs, and vessel volumes). If, for any r eason, these data are incomplete or not available for the current reporting period, field operators or engineers could recollect data wherever possible. If this data cannot be collected, then relevant parameters for estimation of emissions can be used from previous reporting period. However, where possible current reporting period parameters should be used for emissions estimation due to

the reasons listed above.



### c. Emissions Estimation Data for Storage Tanks and Flares

Emissions from storage tanks and flares mi ght require a combination of both direct measurement and engineering estimation to qua ntify emissions. In such cases the storage tank emissions calculation requires the measurement of “emissions per throughput” data. If this data is missing then the previous year’s estimate of “em issions per throughput” measured data could be used with current period throughp ut of the storage tank to calculate emissions.

Calculating emissions from flares requires the volume of flare gas measured using a meter. If these data are missing then the flare gas in the current reporting period could be estimated by scaling the flare gas volume fr om previous reporting period by adjusting it for current period throughput of the facility.



### d. Emissions Estimation Data Using Emissions Factors

If population emissions factors are used then the only data required is activity data. In such a case missing data should be easily replaceable by undertaking a counting exercise for locations from which the data is missing. Alte rnatively, previous reporting period activity data can be used to fill in missing data. However, if facility and/ or equipment modifications

Background Technical Support Document – Petroleum and Natural Gas Industry 66have resulted in increase or decrease in activity data count then this may not be a feasible approach.

If leaker emissions factors are used then activity data will have to be collected using some form of fugitive emissions detection. In such case, missing data may not be easily replaceable. Previous period reported activit y data may be used but it may not be representative of current period emissions. A de tection survey to replace missing data may be

warranted.



### 8. QA/QC Requirements

a. Equipment Maintenance

Equipment used for monitoring, both emissi ons detection and measurement, should be

calibrated on a scheduled basis in accordance w ith equipment manufact urer specifications and standards. Generally, such calibration is require d prior to each monitoring cycle for each facility. A written record of procedures needed to maintain the monitoring equipment in proper operating condition and a schedule for thos e procedures could be part of the QA/QC plan for the facility.

An equipment maintenance plan could be developed as part of the QA/QC plan. Elements of a maintenance plan for equipment could include the following:

• Conduct regular maintenance of monitoring equipment.

o Keep a written record of procedures n eeded to maintain the monitoring system in proper operating condition and a schedule for those procedures;

o Keep a record of all testing, maintena nce, or repair activities performed on any monitoring instrument in a location and format suitable for inspection. A maintenance log may be used for this purpose. The following records should be maintained: date, time, and descripti on of any testing, adjustment, repair, replacement, or preventive maintenance action performed on any monitoring instrument and records of any correctiv e actions associated with a monitor’s outage period.



### b. Data Management

Data management procedures could be included in the QA/QC Plan. Elements of the data management procedures plan are as follows:

• Check for temporal consistency in production data and emission estimate. If outliers exist, can they be explained by change s in the facility’s operations, etc.?

o A monitoring error is probable if diff erences between annual data cannot be explained by:

 Changes in activity levels,

 Changes concerning monitoring methodology,

 Changes concerning change in equipment,

Background Technical Support Document – Petroleum and Natural Gas Industry 67 Changes concerning the emitting process (e.g. energy efficiency improvements). 8

• Determine the “reasonableness” of the em ission estimate by comparing it to previous year’s estimates and relative to nation al emission estimate for the industry:

o Comparison of emissions by specific s ources with correct ion for throughput, if required,

o Comparison of emissions at facility le vel with correction for throughput, if required,

o Comparison of emissions at source leve l or facility level to national or

international reference emissions from co mparable source or facility, adjusted for size and throughput,

o Comparison of measured and calculated emissions. 9

• Maintain data documentation, including comprehensive documentation of data received through personal communication:

o Check that changes in data or methodology are documented



### c. Calculation checks

Calculation checks could be performed for all re ported calculations. Elements of calculation

checks could include:

• Perform calculation checks by reproducing a representative sample of emissions calculations or building in automated checks such as computational checks for

calculations:

o Check whether emission units, parame ters, and conversion factors are appropriately labeled,

o Check if units are properly labeled and correctly carried through from beginning to end of calculations,

o Check that conversion factors are correct,

o Check the data processing steps (e.g., equations) in the spreadsheets,

o Check that spreadsheet input data and cal culated data are clearly differentiated

o Check a representative sample of cal culations, by hand or electronically,

o Check some calculations with abbrevia ted calculations (i.e., back of the envelope checks),

o Check the aggregation of data across source categories, business units, etc.,

8 Official Journal of the European Union, August 31, 2007. Commission Decision of 18 July 2007, “Establishing guidelines for the monitoring and reporting of GHG emissions pursuant to Directive 2003/87/ECof the European Parliament and of the Council. Available at http://eurlex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2007:229:0001:0085:EN:PDF.

9 Official Journal of the European Union, August 31, 2007. Commission Decision of 18 July 2007, “Establishing guidelines for the monitoring and reporting of GHG emissions pursuant to Directive 2003/87/ECof the European Parliament and of the Council. Available at http://eurlex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2007:229:0001:0085:EN:PDF.

Background Technical Support Document – Petroleum and Natural Gas Industry 68o When methods or data have changed, check consistency of time series inputs

and calculations. 10



### 9. Reporting Procedure

The following reporting requirements could be considered for a mandatory reporting rule;

a) Some fugitive emissions by nature occur randomly within the facility, therefore, where emissions are reported on an annual basis, it may not be possible to determine when the fugitive emissions began. As discussed in more detail in Section I ii, under these circumstances, annual emissions could be dete rmined assuming that the fugitive emissions were continuous from the beginn ing of the reporting period or from the last recorded not leaking in the current reporting period and until the fugitive emissions is repaired or the end of the reporting period.

(b) There are potentially hundreds (and in some cases) thousa nds of emissions sources in a facility. Typically, from practic al experience in the Natural Ga s STAR Program 10 percent of the potential emissions sources have been f ound to be emitting the large majority of the emissions. Reporting of such large numbers of emissions estimates may not be practical. One way to minimize the reporting burden would be to have facilities report emissions at the individual source type level, i.e. emissions from each source type can be reported in the aggregate. For example, a facility with multiple reciprocating compressors may report emissions from all reciprocating compressors as an aggregate number. The disadvantage to this approach would be that there would not be a distinction in the reported data between vented emissions and fugitive emissions. Although such distinctions may be of interest to the reporter, as different mitigation opportunitie s may exist for intentional and unintentional releases, it may not be necessary for the inte grity of a reporting program, and therefore aggregate reporting may be sufficient.

(c) Due to the point-in-time nature of direct m easurements, reports of annual emissions levels should take into account equipment operati ng hours according to standard operating conditions and any significant operational interrup tions and shutdowns, to convert direct measurement to an annual figure.

(d) The facilities that cross the potential thre shold for reporting coul d report the following information to EPA;

(1) Emissions monitored at an aggregate source level for each facility, separately identifying those emissions that are from standby sources. In several onshore na tural gas processing plants CO 2 is being capture for Enha nced Oil Recovery operations. Therefore, these CO 2 emissions may have to be separate ly accounted for in the reporting.

10 U.S. EPA 2007. Climate Leaders, Inventory Guidance, Design Principles Guidance, Chapter 7 “Managing Inventory Quality”. Available at http://www.epa.gov/climateleaders/documents/resources/design_princ_ch7.pdf.

Background Technical Support Document – Petroleum and Natural Gas Industry 69Background Technical Support Document – Petroleum and Natural Gas Industry 70 (2) Activity data, such as the number of sources monitored, for each aggregated source type level for which emissions will be reported.

(3) The parameters required for calculati ng emissions when using engineering estimation

methods.



### 10. Verification of Reported Emissions

As part of the data verification requirements , the owner or operator could submit a detailed explanation of how company records of measurements are used to quantify fugitive and vented emissions measurement within 7 days of receipt of a written request from EPA or from the applicable State or local air pollution control agency (the use of electronic mail can be made acceptable).

### Appendix A: Segregation of Emissions Sources using the Decision Process
The tables provided in this appendix repr esent the outcome of the decision process used to identify a starting lis t of potential sources that can be included in the proposed rule. The decision process was applied to each emission source in the natural gas segment of the U.S. GHG Inventory. The petroleum onshore production segment has emission sources that either are equivalent to their counter-parts in the natural gas onshore production segment or fall in th e exclusion category. Petroleum transportation was not analyzed further due to the level of emissions and refineries are treated separately in Subpart Y.

Sources Contributing to 80% of Fugitive and Vented Emissions from Each Sector

Source Offshore

Production Onshore Production Processing Transmission Storage LNG Storage LNG Import and Export Distribution
Separators 4% Meters/Piping 4% Small Gathering Reciprocating Comp. 2% Pipeline Leaks 7%

CBM Powder River 2%

Pneumatic Device Vents 43% 0.26% 12% 13%

Gas Pneumatic Pumps 9% 0.49%

Dehydrator Vents 2% 3% 3% Well Clean Ups (LP Gas Wells)/ Blowdowns 7%

Plant/Station/ Platform Fugitives 4% 5% 16% 14% 3%

Reciprocating Compressors 48% 40% 45% 54% 14%

Centrifugal Compressors 22% 16% 8% 6% 19% 4%

Acid Gas Removal Vents 2%

Vessel Blowdowns/Venting 6% Routine Maintenance/Upsets - Pipeline venting 10% Station venting 8% 2% M&R (Trans. Co. Interconnect) 4% Pipeline Leaks Mains 36%

Services 16% Meter/Regulator (City Gates) 37%

Residential Customer Meters

Flare stacks 1%

Non-pneumatic pumps 0.03%

Open ended lines 0.005%

Pump seals 0.41%

Storage tanks 50%

Wellhead fugitive emissions 4% Well completions 0.0004%

Well workovers 0.04%

NOTE: Pink cells represent sources that were included over riding the decision tree process. Blue cells represent sources that are not present in the respective segments. Green cells represent sour ces that are not explicitly identified in the U.S. GHG Inventory; however, these sour ces may potentially be found in the respective segments.

Blank cells are sources in the U

Background Technical Support Document – Petroleum and Natural Gas Industry 71Inventory of Methane Emissions from Natural Gas SystemsPRODUCTION OFFSHORETotal EmissionsNationally(MMcf/year)TonnesCO2e/ Year% of SectorEmissions% of totalInventoryEmissionsActivityFactorsLeakDetectionDirectMeasurementEngineeringEstimateAccesibleSourceAmine gas sweetening unit0.2 80 0.01% 0.0001% NE ccanBoiler/heater/burner0.8 332 0.05% 0.0002%cdanDiesel or gasoline engine0.016 0.001% 0.000004%cdanDrilling rig3 1,1340.17% 0.001%cdanFlare24 9,583 1.47% 0.01%ccbnCentrifugal Seals358 144,547 22% 0.10%aaabConnectors0.8 309 0.05% 0.0002%bbbbFlanges2.38 960 0.15% 0.001%bbbbOEL0.1 32 0.005% 0.00002%bbbbOther44 17,576 2.70% 0.01%bbbbPump Fugitive0.5 191 0.03% 0.0001%bbabValves19 7,758 1% 0.01%bbbbGlycol dehydrator25 9,914 2% 0.01%ccbnLoading operation0.1 51 0.01% 0.00004%cdanSeparator796 321,566 49% 0.23%ccbbMud degassing8 3,071 0.47% 0.002%cdanNatural gas engines191 77,000 12% 0.05%Natural gas turbines3 1,399 0.22% 0.001%Pneumatic pumps7 2,682 0.41% 0.002%cbabPressure/level controllers2 636 0.10% 0.0005%cbabStorage tanks7 2,933 0.45% 0.002%ccanVEN exhaust gas121 48,814 8% 0.03%ccbnNOTES:Leak Detection: a – Yes and cost effective; b – Yes but cost burden c- No. Cost effectiveness based on expert judgment.Direct Measurement: a – Accurate and cost effective; b – Accurate but costburden; c – Questionable; d –No direct measurement.Engineering Estimate: a – Exists; b – does not exist.Accessible Source: y – Yes; n – No; b – Both.Background Technical Support Document –Petroleum and Natural Gas Industry72PRODUCTION ONSHORETotal EmissionsNationally(MMcf/year)TonnesCO2e/ Year% of SectorEmissions% of totalInventoryEmissionsActivityFactorsLeakDetectionDirectMeasurementEngineeringEstimateAccesibleSourceNormal FugitivesGas WellsNon-associated Gas Wells (less Unconventional)2,682 1,083,539 2% 0.77% 376784 bbbbUnconventional Gas Wells69 27,690 0.06% 0.02% 35440 abbbField Separation Equipment0Heaters1,463 591,023 1% 0.42% 89720 abbbSeparators4,718 1,906,206 4%1% 247919 bbbbDehydrators1,297 524,154 1% 0.37% 37925 abbbMeters/Piping4,556 1,840,683 4%1% 315487 bbbbGathering Compressors0Small Reciprocating Comp.2,926 1,182,062 2%1% 28490 aabbLarge Reciprocating Comp.664 268,133 0.54% 0.19% 112 aabbLarge Reciprocating Stations45 18,178 0.04% 0.01% 14 aabbPipeline Leaks8,087 3,267,306 7%2% 392624 bbbnVented and CombustedDrilling and Well CompletionCompletion Flaring0188 0.00% 0.00% 597 cccnWell Drilling96 38,946 0.08% 0.03% 35600 ccayCoal Bed MethanePowder River2,924 1,181,246 2%1% 396920 ccanBlack Warrior543 219,249 0.44% 0.16%ccanNormal OperationsPneumatic Device Vents52,421 21,178,268 43% 15%cbabChemical Injection Pumps2,814 1,136,867 2% 0.81%cbabKimray Pumps11,572 4,674,913 9%3%cbanDehydrator Vents3,608 1,457,684 3%1%ccanCondensate Tank VentsCondensate Tanks without Control Devices1,225 494,787 1% 0.35%ccabCondensate Tanks with Control Devices245 98,957 0.20% 0.07%cdabCompressor Exhaust VentedGas Engines11,680 4,718,728 9%3%Well WorkoversGas Wells47 18,930 0.04% 0.01%cdbyWell Clean Ups (LP Gas Wells)9,008 3,639,271 7%3%cdanBlowdownsVessel BD31 12,563 0.03% 0.01%cdanPipeline BD129 52,040 0.10% 0.04%cdabCompressor BD113 45,648 0.09% 0.03%cdanCompressor Starts253 102,121 0.20% 0.07%cdanUpsetsPressure Relief Valves29 11,566 0.02% 0.01%cdbnMishaps70 28,168 0.06% 0.02%cdbnNotes:Leak Detection: a – Yes and cost effective; b – Yes but cost burden;c - No. Cost effectiveness based on expert judgment.Direct Measurement: a – Accurate and cost effective; b – Accurate but costburden; c – Questionable; d –No direct measurement.Engineering Estimate: a – Exists; b – does not exist.Accessible Source: y – Yes; n – No; b – Both.Background Technical Support Document –Petroleum and Natural Gas Industry73GAS PROCESSING PLANTSTotal EmissionsNationally(MMcf/year)TonnesCO2e/ Year% of SectorEmissions% of totalInventoryEmissionsActivityFactorsLeakDetectionDirectMeasurementEngineeringEstimateAccesibleSourceNormal FugitivesPlants1,634 660,226 5% 0.47%aabbRecip. Compressors17,351 7,009,755 48%5%aabbCentrifugal Compressors5,837 2,358,256 16%2%aabbVented and CombustedNormal OperationsCompressor ExhaustGas Engines6,913 2,792,815 19%2%Gas Turbines195 78,635 1% 0.06%AGR Vents643 259,592 2% 0.18%ccanKimray Pumps177 71,374 0.49% 0.05%cbabDehydrator Vents1,088 439,721 3% 0.31%ccanPneumatic Devices93 37,687 0.3% 0.03%cbabRoutine MaintenanceBlowdowns/Venting2,299 928,900 6%1%cdanNotes:Leak Detection: a – Yes and cost effective; b – Yes but cost burden;c - No. Cost effectiveness based on expert judgment.Direct Measurement: a – Accurate and cost effective; b – Accurate but costburden; c – Questionable; d –No direct measurement.Engineering Estimate: a – Exists; b – does not exist.Accessible Source: y – Yes; n – No; b – Both.Background Technical Support Document –Petroleum and Natural Gas Industry74TRANSMISSIONTotal EmissionsNationally(MMcf/year)TonnesCO2e/ Year% of SectorEmissions% of totalInventoryEmissionsActivityFactorsLeakDetectionDirectMeasurementEngineeringEstimateAccesibleSourceFugitivesPipeline Leaks166 67,238 0.17% 0.05%acanCompressor Stations (Transmission)Station5,619 2,270,177 6%2%aabbRecip Compressor38,918 15,722,907 40% 11%aabbCentrifugal Compressor7,769 3,138,795 8%2%aabbM&R (Trans. Co. Interconnect)3,798 1,534,238 4%1%aabbM&R (Farm Taps + Direct Sales)853 344,646 1% 0.25%bbbbVented and CombustedNormal OperationDehydrator vents (Transmission)105 42,329 0.11% 0.03%ccanCompressor ExhaustEngines (Transmission)10,820 4,371,314 11%3%Turbines (Transmission)61 24,772 0.06% 0.02%Generators (Engines)529 213,911 0.55% 0.15%Generators (Turbines)060 0.0002% 0.00004%Pneumatic Devices Trans + StorPneumatic Devices Trans11,393 4,602,742 12%3%cbabRoutine Maintenance/UpsetsPipeline venting9,287 3,752,013 10%3%cdabStation venting Trans + StorageStation Venting Transmission7,645 3,088,575 8%2%cdanNotes:Leak Detection: a – Yes and cost effective; b – Yes but cost burden;c - No. Cost effectiveness based on expert judgment.Direct Measurement: a – Accurate and cost effective; b – Accurate but costburden; c – Questionable; d –No direct measurement.Engineering Estimate: a – Exists; b – does not exist.Accessible Source: y – Yes; n – No; b – Both.Background Technical Support Document –Petroleum and Natural Gas Industry75STORAGETotal EmissionsNationally(MMcf/year)TonnesCO2e/ Year% of SectorEmissions% of totalInventoryEmissionsActivityFactorsLeakDetectionDirectMeasurementEngineeringEstimateAccesibleSourceFugitivesCompressor Stations (Storage)Station2,801 1,131,492 16%1%aabbRecip Compressor8,093 3,269,454 45%2%aabnCentrifugal Compressor1,149 464,354 6% 0.33%aabnWells (Storage)695 280,891 4% 0.20%aabyVented and CombustedNormal OperationDehydrator vents (Storage)217 87,514 1% 0.06%ccanCompressor ExhaustEngines (Storage)1,092 441,108 6% 0.31%Turbines (Storage)9 3,680 0.05% 0.003%Pneumatic Devices Trans + StorPneumatic Devices Storage2,318 936,324 13%1%cbabStation venting Trans + StorageStation Venting Storage1,555 628,298 9% 0.45%cdanNotes:Leak Detection: a – Yes and cost effective; b – Yes but cost burden;c - No. Cost effectiveness based on expert judgment.Direct Measurement: a – Accurate and cost effective; b – Accurate but costburden; c – Questionable; d –No direct measurement.Engineering Estimate: a – Exists; b – does not exist.Accessible Source: y – Yes; n – No; b – Both.Background Technical Support Document –Petroleum and Natural Gas Industry76LNG STORAGETotal EmissionsNationally(MMcf/year)TonnesCO2e/ Year% of SectorEmissions% of totalInventoryEmissionsActivityFactorsLeakDetectionDirectMeasurementEngineeringEstimateAccesibleSourceLNG StorageLNG Stations552 222,824 14% 0.16%bbbbLNG Reciprocating Compressors2,084 842,118 54%1%bbbbLNG Centrifugal Compressors715 288,756 19% 0.21%bbbbLNG Compressor ExhaustLNG Engines172 69,632 5% 0.05%LNG Turbines1261 0.02% 0.0002%LNG Station venting306 123,730 8% 0.09%cdanTotal EmissionsNationally(MMcf/year)TonnesCO2e/ Year% of SectorEmissions% of totalInventoryEmissionsActivityFactorsLeakDetectionDirectMeasurementEngineeringEstimateAccesibleSourceLNG Import TerminalsLNG Stations22 8,880 3% 0.01%bbbbLNG Reciprocating Compressors105 42,347 14% 0.03%bbabLNG Centrifugal Compressors27 10,820 4% 0.01%bbabLNG Compressor ExhaustLNG Engines586 236,647 78% 0.17%LNG Turbines3 1,370 0.45% 0.001%LNG Station venting12 4,931 2% 0.004%cdanLNG IMPORT AND EXPORTTERMINALSNotes:Leak Detection: a – Yes and cost effective; b – Yes but cost burden; c - No.Direct Measurement: a – Accurate and cost effective; b – Accurate but costburden; c – Questionable; d –No direct measurement.Engineering Estimate: a – Exists; b – does not exist.Accessible Source: y – Yes; n – No; b – Both.Export Terminals are not currently included in the U.S. GHG Inventory, therefore they were not included inthis analysis. There is currently only one exportterminal, located in Alaska.Background Technical Support Document –Petroleum and Natural Gas Industry77Background Technical Support Document –Petroleum and Natural Gas Industry78DISTRIBUTIONTotal EmissionsNationally(MMcf/year)TonnesCO2e/Year% of SectorEmissions% of totalInventoryEmissionsActivityFactorsLeakDetectionDirectMeasurementEngineeringEstimateAccesibleSourceNormal FugitivesPipeline LeaksMains - Cast Iron9,222 3,725,675 14%3%abbnMains - Unprotected steel6,515 2,632,209 10%2%abbnMains - Protected steel1,422 574,529 2% 0.41%abbnMains - Plastic6,871 2,775,759 10%2%abbnTotal Pipeline Miles36%7%Services - Unprotected steel7,322 2,957,970 11%2%abbnServices Protected steel2,863 1,156,473 4%1%abbnServices - Plastic315 127,210 0.47% 0.09%abbnServices - Copper47 19,076 0.07% 0.01%abanTotal Services16%3%Meter/Regulator (City Gates)37%7%M&R >3005,037 2,034,986 7%1% 3,198aabbM&R 100-30010,322 4,170,101 15%3% 12,325bbbbM&R <100249 100,480 0.37% 0.07% 6,587acbbReg >3005,237 2,115,726 8%2% 3,693aabbR-Vault >30025 9,976 0.04% 0.01% 2,168aabbReg 100-3004,025 1,625,929 6%1% 11,344bbbbR-Vault 100-3008 3,247 0.01% 0.002% 5,097acbbReg 40-100306 123,586 0.45% 0.09% 33,578bbbbR-Vault 40-10023 9,115 0.03% 0.01% 29,776bbbbReg <4017 6,690 0.02% 0.005% 14,213bbbbCustomer MetersResidential5,304 2,142,615 8%2% 37017342 bbayCommercial/Industry203 81,880 0.30% 0.06% 4231191 bbayVentedRountine MaintenancePressure Relief Valve Releases63 25,346 0.09% 0.02%cdbnPipeline Blowdown122 49,422 0.18% 0.04%cdanUpsetsMishaps (Dig-ins)1,907 770,405 3%1%cdbnNOTES:Leak Detection: a – Yes and cost effective; b – Yes but cost burden;c - No. Cost effectiveness based on expert judgment.Direct Measurement: a – Accurate and cost effective; b – Accurate but costburden; c – Questionable; d –No direct measurement.Engineering Estimate: a – Exists; b – does not exist.Accessible Source: y – Yes; n – No; b – Both.

### Appendix B: Development of revis ed estimates for four U.G. GHG Inventory emissions sources

Well Completion and Workover Venting

This discussion describes the methods used to estimate total U.S. methane emissions from well completion and workover venting. For the pur poses of this estimate, it is assumed that all unconventional wells are comple ted with hydraulic fracturing of tight sand, shale or coal bed methane formations (i.e. completions i nvolving high rate, extended back-flow to expel fracture fluids and sand proppant, which also lead s to greater gas venti ng or flaring emissions than conventional well completions). It is un derstood that not all unconventional wells involve hydraulic fracturing, but some convent ional wells are hydraulically fractured, which

is assumed to balance the over-estimate.

► Estimate the Number of Gas Wells Completed

The data in Exhibit B-1 wa s extracted from EPA (2008) 11

.

Exhibit B-1. 2007 Natural Gas Wells

Year Approximate Number of

Onshore Unconventional

Gas Wells Approximate Number of

Onshore Conventional Gas

Wells Total Number of Gas Wells (both conventional and unconventional)

2006 35,440 375,601 411,041

2007 41,790 389,245 431,035

Exhibit B-1 was used to calc ulate that there was a net increase of 19,994 wells (both conventional and unconventional) between 2006 and 2007. Each of these wells is assumed to have been completed over the course of 2006 . EPA (2008) also estimates that 35,600 gas

wells were drilled in 2006. Th is includes exploratory wells, dr y holes, and completed wells. EPA (2008) also indicates that 19,994 of those natural gas wells were drilled and completed. The difference between the 35,600 drilled a nd 19,994 new wells is 15,606 wells, which we assume are replaced for shut-in or dry holes. This analysis assumed that 50% of those remaining 15,606 wells were completed. Thus, the total number of gas well completions, both conventional and unconventional, was estimated to be 27,797 wells in 2006.



## ( ) ( ) wells wells wells wells 797,27 994,19 600,35%50 994,19 =

− × +

That is 78% of the total gas wells drilled in 2006. We assu med this same percentage of completed wells applies to the year 2007. EPA (2008) estimates 37,196 gas wells were drilled in 2007, so applying this completi on factor, 78% of 37,196 wells equals 29,043 gas wells completed in 2007.

► Estimate the Number of Conventional and Unconventional Well Completions

11 EPA. U.S. Inventory of Greenhouse Gas Emissions and Sinks: 1990 – 2007 . Available online at: <http://epa.gov/climatechange/emissions/usgginv_archive.html>.

79Exhibit B-1 shows a net increase of 6,350 unconve ntional wells from 2006 to 2007. This is 32% of the 19,994 net increase in all wells over that period. It was assumed that 32% of the estimated 29,043 well completions in 2007 (see previous section) were unconventional wells. The remaining gas well completions were assumed to be conventional wells. These results are summarized in Exhibit B-2. This analysis also assumed that all unconventional wells require hydraulic fracture upon completion.

Exhibit B-2. 2007 Completions Activity Factors

2007 Conventional Well Completions 19,819

2007 Unconventional Well Completions 9,224

► Estimate the Number of Conventional and Unconventional Well Workovers GRI (1996) 12 provides activity data for 1992 on conven tional workovers. It reported that 9,324 workovers were performed with 276,014 pr oducing gas wells. This activity data was projected to 2007 using the ratio of 2007 producing gas wells to 1992 producing gas wells; as

shown in Exhibit 3:

Exhibit B-3. Calculation of 2007 Conv entional Workover Activity Factor

GasWells GasWells

s alWorkover Convention s alWorkover Convention 1992 2007 1992 2007 × =

wells wells workovers s alWorkover Convention 014,276 035,431 324,9 2007 × =

Unconventional gas wells were assumed to be re-fractured once every 10 years. Thus, the number of unconventional gas well workovers was 10% of the existing unconventional well

count in 2007.

The resulting activity factor s for conventional and unconvent ional gas well workovers are

summarized in Exhibit B-4.

Exhibit B-4. Summary of 2007 Workover Activity Factors

2007 Conventional

Well Workovers = × wells wells workovers 014,276 035,431 324,9 14,569

2007 Unconventional

Well Workovers = × wells 790,41%10 4,179

► Estimate the Emission Factor for Conventional Well Completions

12 GRI. Methane Emissions from the Natural Gas Industry . 1996. Available online at: <http://epa.gov/gasstar/tools/related.html>.

80GRI (1996) estimated that conventional well completions emit 0.733 Mcf of methane each. GRI (1996) assumed that all completion flowback was flared at 98% combustion efficiency and the produced gas was 78.8% methane by volum e. This analysis estimated the amount of gas sent to the flare by dividi ng the reported GRI factor by th e 2% un-combusted gas. The resulting emission factor for c onventional well completions was 36.65 Mcf of methane/completion

.

► Estimate the Emission Factor fo r Conventional Well Workovers The GRI (1996) emission factor for well comple tions was accepted for this analysis. That

emission factor is 2.454 Mcf of methane/workover for conventional wells.

► Estimate the Emission Factor for Unconventional Well Completions

The emission factor for unconventional well completions was derived using several experiences presented at Natural Gas STAR technology transfer workshops.

One presentation 13 reported that the emissions from all unconventional well completions were approximately 45 Bcf usi ng 2002 data. The emission rate per completion can be backcalculated using 2002 activity data. API Basic Petroleum Handbook 14 lists that there were 25,520 wells completed in 2002. Assuming Illinoi s, Indiana, Kansas, Kentucky, Michigan, Missouri, Nebraska, New York, Ohio, Pennsylvania, Virginia, and West Virginia producedfrom low-pressure wells that year, 17,769 of those wells can be attributed to onshore, nonlow-pressure formations. The Handbook also estimated that 73% (or 12,971 of the 17,769 drilled wells) were gas wells, but are still from regions that are not entirely low-pressure formations. The analysis assumed that 60% of those wells are high pressure, tight formations (and 40% were low-pressure wells). Therefore, by applying the inventor y emission factor for low-pressure well cleanups (49,570 scf/well-year 11 )approximately 5,188 low-pressure wells

emitted 0.3 Bcf .

Bcf scf Bcf

well scf wells 3.0 10 1570,49 971,12%40

9 ≈× × ×

The remaining high pressure, tight-formation wells emitted 45 Bcf less the low-pressure 0.3 Bcf, which equals 44.7 Bcf. Since there is grea t variability in the natural gas sector and the resulting emission rates have high uncertainty ; the emission rate per unconventional (highpressure tight formation) wells were rounded to the nearest thousand Mcf.

completion Mcf Bcf

Mcf

wells Bcf /000,6 10

971,12%60 7.44 6

≈×

×

The same Natural Gas STAR presentation 12 provides a Partner expe rience which shares its recovered volume of methane per well. This an alysis assumes that the Partner recovers 90% of the flowback. Again, because of the high variability and uncertainty associated with

13 EPA. Green Completions . Natural Gas STAR Producer’s Technology Transfer Workshop. September 21, 2004. Available online at: <http://epa.gov/gasstar/workshops/techtransfer/2004/houston-02.html>.

14 API. Basic Petroleum Data Handbook . Volume XXIV, Number 1. February, 2004.

81different completion flowbacks in the gas indu stry, this was estimated only to the nearest thousand Mcf – 10,000 Mcf/completion.

A vendor/service provider of “reduced emission completions” shared it s experience later in that same presentation 12 for the total recovered volume of gas for 3 completions. Assuming that 90% of the gas was recovered, the total otherwise-emitted gas was back-calculated. Again, because of the high variability and uncer tainty associated with different completion flowbacks in the gas industry, this was rounded to the neares t hundred Mcf – 700 Mcf/completion.

The final Natural Gas STAR presentation 15 with adequate data to determine an average emission rate also presented the total flowback and total completions and re-completions. Because of the high variability and uncertainty associated with different completion flowbacks in the gas industry, this wa s rounded to the n earest 10,000 Mcf – 20,000 Mcf/completion.

This analysis takes the simple average of these completion flowbacks for the unconventional well completion emission factor: 9,175 Mcf/completion

.

► Estimate the Emission Factor for Unconventi onal Well Workovers (“re-completions”)

The emission factor for unconventional well wo rkovers involving hydraulic re-fracture (“recompletions”) was assumed to be the same as unconventional well completions; calculated in the previous section.

► Estimate the Total National Emis sions (disregarding reductions) The estimated activity factors were multiplied by the associated emission factors to estimate the total emissions from well completions and wo rkovers in the U.S. for 2007. This does not

reflect reductions due to contro l technologies such as flares or bringing portable treatment units onsite to perform a practi ce called “reduced emission completions”. The results are displayed in Exhibit B-5 below.

Exhibit B-5. Summary of Results: U. S. Completion and Workover Venting 2007

Activity Activity Factor Emission Factor Total U.S. Emissions

Conventional Gas Well Completions 19,819 completions 36.65 Mcf/completion ~0.7 Bcf

Conventional Gas Well

Workovers 14,569 workovers 2.454 Mcf/workover << 1 Bcf

Unconventional Gas Well Completions 9,224 completions 9,175 Mcf/completion ~85 Bcf

Unconventional Gas

Well Workovers 4,179 workovers 9,175 Mcf/workover ~38. Bcf

Note: The emission factors and calculated emissions as presented in this table were rounded independently. TOTAL: ~120 Bcf

15 EPA. Reducing Methane Emissions During Completion Operations . Natural Gas STAR Producer’s Technology Transfer Workshop. September 11, 2007. Available online at: <http://epa.gov/gasstar/documents/works hops/glenwood-2007/04_recs.pdf>.

82The final U.S. emissions were rounded to 120 Bcf

.



## Well Blowdown Venting for Liquid Unloading

This discussion describes the methods used to estimate total U.S. methane emissions from low-pressure well blowdowns for liquid unloading.

► Estimate the Fraction of Conventional Wells that Require Liquid Unloading This analysis assumed that the survey of 25 well sites conducted by GRI (1996) for the base year 1992 provides representative data for th e fraction of conventional wells requiring unloading. That is, 41.3% of conven tional wells required liquid unloading.

► Calculate Emissions per Blowdown This analysis used a fluid equilibrium calculation to determine the volume of gas necessary to blow out a column of liquid for a given we ll pressure, depth, a nd casing diameter. The equation for this calculation is available in an EPA, Natural Gas STAR technical study 16

. The equation is displa yed in Exhibit B-6.

Exhibit B-6. Well Blowdown Em issions for Liquid Unloading

V

v = 

# ( ) PhD ×××× − 26 1037. 0

where,

V

v = Vent volume (Mcf/blowdown)

D = casing diameter (inches)

h = well depth (feet)

P

= shut-in pressure (psig)

A combination of GASIS 17 and LASSER 18 databases provided well depth and shut-in pressures for a sample of 35 natural gas basi ns. The analysis assumed an average casing

diameter of 10-inches for al l wells in all basins.

► Estimate the Annual Number of Blowdowns per Well that Require Unloading For wells that require liquid unloading, multiple blowdowns per year are typically necessary. A calibration using the equation in the previous section was pe rformed using public data for the shared experiences of two Natural Gas STAR Partners.

16 EPA. Installing Plunger Lift Systems in Gas Wells: Lessons Learned from Natural Gas STAR Partners

. October, 2003. Available online at: <http://e pa.gov/gasstar/documents/ll_plungerlift.pdf>.

17 DOE. GASIS, Gas Information System . Release 2 – June 1999.

18 LASSERTM database.

83One Partner reported that it r ecovered 4 Bcf of emissions usi ng plunger lifts with “smart” automation (to optimize plunger cycles) on 2,200 wells in the San Juan basin 19 . Using the data for San Juan basin in the equation in E xhibit B-6 required appr oximately 51 blowdowns per well to match the 4 Bcf of emissions.

Another Partner reported that it recovered 12 MMcf of emi ssions using plunger lifts on 19 wells in Big Piney 16 . Using information for the nearest basin in the equation in Exhibit B-6 required approximately 11 blowdowns per well to match the 12 MMcf of emission.

The simple average of 31 blowdowns per we ll requiring liquid unloading was used in the analysis to determine the number of well blowdowns per year by basin.

► Estimate the Percentage of Wells in Each Basin that are Conventional GASIS and LASSER provided approximate well counts for each basin and GRI provided the percentage of conventional well s requiring liquid unloa ding for 35 sample basins. However, many of those basins contain unconventional we lls which will not require liquid unloading. EIA posts maps that display the concentra tion of conventional gas wells in each basin 20 , the concentration of gas wells in tight formations by basin 21 , and the concentration of coal bed methane gas wells by basin 22 . These maps were used to esti mate the approximate percentage

of wells that are conventional in each basin. These percentages ranged from 50% to 100%.

► Estimate Emissions fr om 35 Sample Basins The total well counts for each basin were multip lied by the percentage of wells estimated to

be conventional for that basin to estimate the approximate nu mber of conventional wells in each of the basins. The resulting conventional well counts were multiplied by the percentage of wells requiring liquid unloading, as estimated by the GRI survey (41.3%). The number of wells in each basin that require liquid unloa ding were multiplied by an average of 31

blowdowns/well to determine the number of we ll blowdowns for each basin. The emissions per blowdown, as calculated using the equation in Exhibit B-6, were then multiplied by the number of blowdowns for each basin to estimate the total well venting emissions from each of the 35 sample basins due to liquid unloadi ng. Using the GRI estimate that the average methane content of production segment gas is 78.8% methane by volume, the total methane emissions from the sample of 35 basins were calculated to be 149 Bcf.

► Extrapolate Sample Data to Entire U.S. The sample of 35 gas well basins represente d only 260,694 conventional gas wells. EPA’s national inventory 23 . estimated that there were 389,245 conventional gas wells in 2007. The

19 EPA. Natural Gas STAR Partner Update: Spring 2004 . Available online at: <http://epa.gov/gasstar/documents/par tner-updates/spring2004.pdf>.

20 EIA. Gas Production in Conventional Fields, Lower 48 States . Available online at: <http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm>.

21 EIA. Major Tight Gas Plays, Lower 48 States . Available online at: <http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm>.

22 EIA. Coal Bed Methane Fields, Lower 48 States . Available online at: <http://www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/maps/maps.htm>.

23 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2006 . Available online at http://www.epa.gov/climatechange/emissions/usinventoryreport.html

.

84emission estimates were extrapolated to the en tire nation by the ratio of the conventional gas wells. The final resulting emissions from gas well venting due to liquid unloading were

estimated to be 223 Bcf

.

This estimate does not include emission reduc tions from control methods such as plunger lifts, plunger lifts with “smart” automation, or other artificial lift techniques.

85

### Appendix C: Development of threshold analysis

As the main text has pointed out the oil an d natural gas sector includes hundreds, and in some cases thousands, of play ers, many of them with few emission sources as well as ones with over 160 emission sources. Requiring all participants to report would impose a large burden on the industry and also on EPA. A rule-of-thumb, substantiated by survey work, is that 80 percent of the emissions come from 10 percent of the analysis. Therefore, a threshold analysis was perfor med so that the large emitters would be identified and small insignificant emitters could be excluded from the reporting requirement.

Threshold Analysis for Onshore Production The following points lay out the methodology for the threshold analysis for the onshore oil and natural gas production segment

• Threshold analysis for onshore (including EOR) production sector was estimated per unique operator per basin.

• The oil and gas production volumes per opera tor per basin were obtained from the

LASSERTM database 2006. The total onsho re oil and gas production process and combustion (CH 4 and CO 2 ) emissions estimated in the U.S. GHG Inventory 2006 were apportioned to each operator based on the oil or gas production volumes.

• The U.S. GHG Inventory emissions estimates for the following sources were revised: well completions, well unloading, and we ll clean-ups. Natural Gas STAR emission reductions reported by partners from th ese sources are higher than the current inventory emission estimates. As a result emissions from these sources are currently under-estimated in the inventory. The met hodology used to revise these emissions estimates can be found in Appendix B. In addition, emissions from storage tanks and

flares as estimated in the U.S. GHG I nventory were included for the threshold analysis. These sources also have Natural Gas STAR reductions th at are higher than the emissions estimates in the inventory. However, though these source emissions estimates were included, no new estimates were developed for lack of publicly

available data.

• The combustion emissions from the following sources were estimated separately as they are not included in the U.S GHG Invent ory: heater-treater, well drilling (oil and gas), dehydrator reboiler, and acid gas removal (AGR) units.

o Heater-Treaters Combustion: The total national combustion emissions from heater-treaters were calculated by estimating the total fuel required to increase the temperature by 10 o F of total oil produced in 2006. CO 2 and N 2 O

combustion emission factor for natura l gas from the API compendium 2004

was used to estimate the total national CO 2 and N 2 O emissions. The total emissions were apportioned to the ope rators based on their oil production

volumes.

o Dehydrator and AGR Combustion: The total national combustion emissions from dehydrators and AGR units were estimated by applying the fuel consumption factor of 17 Mcf of natural gas/ MMcf of gas throughput,

86obtained from the EPA’s Lesson Learned 2006, Replacing Gycol Dehydrators with Desiccant Dehydrator . The total national thr oughput was assumed to be equal to the total na tional gas produced obtained from the EIA. CO 2 and N 2 O

combustion emission factor for natura l gas from the API compendium 2004

was used to estimate the total national CO 2 and N 2 O emissions. The total emissions were apportioned to the operators based on their gas production

volumes.

o Well Drilling Combustion: The total national com bustion emissions from well drilling was estimated by multiplying the emissions per well drilled with the national number of oil and gas wells drilled in the year 2006. The emissions per well was estimated by a ssuming the use of two 1500 hp diesel engines over a period of 90 days to drill each well. CO 2 and N 2 O combustion emission factor for diesel from the API compendium 2004 was used to

estimate the total national CO 2 and N 2 O emissions. The total emissions were apportioned to different states based on th e percentage of rigs present in the state. The number of rigs per state was obtained from Baker Hughes. The total oil and gas well drilling combustion em issions per state was apportioned to each operator in the state based on their oil and gas volumes respectively.

• The total barrels of oil pr oduced per field and operator using EOR operations was obtained from the OGJ (2006) EOR/Heavy Oil Survey

.

• The total make-up CO 2 volume required for EOR operations was estimated using

0.29 metric tons CO 2 / bbl oil produced from EOR ope rations obtained from DOE, Storing CO 2 with Enhanced Oil Recovery . The total recycled CO 2 volumes per operator was estimated using a f actor of 0.39 metric tons CO 2 /bbl estimated from DOE, Storing CO 2 with Enhanced Oil Recovery.

• The equipment count for EOR operations was estimated by apportioning the U.S. GHG Inventory activity factors for onshore petroleum production to each field using the producing well count or throughput (bbl ) based on judgment. E.g. the total number of compressors in the US used in EOR onshore production operations per field was estimated by using the ratio of the throughput per fi eld to the national throughput and multiplying it by the total number of nationa l compressors in onshore operations.

• The emission factors in the U.S. GHG Invent ory and the re-estimated activity factors for EOR operations were used to estimat e total methane emissions by volume for EOR operations. This volume was adjusted for methane composition (assumed to be 78.8% from GRI) to estimate the natura l gas emissions from EOR operations. The composition of 97% CO 2 and 1.7% CH 4 was applied to the total natural gas emissions

to estimate CO 2 and CH 4 emissions from vented, fugitive and combustion sources covered in the U.S. GHG Inventory . 97% CO 2 and 1.7% CH 4 composition was

obtained from Summary of Carbon Dioxide Enhanced Oil Recovery (CO 2 EOR) Injection Well Technology.

• The following EOR emissions sources are not covered in the U. S. GHG Inventory and therefore were estimated sepa rately:

o Recycled injection CO 2 dehydrator vented emissions

o Recycled injection CO 2 compressor - vented and combustion emissions

o CO 2 injection pumps - combustion and vented emissions

87o Water injection pumps – combustion emissions

o Orifice meter - vented emissions from calibration Emissions from the above mentioned sources were calculated in the following manner:

• Recycled CO 2 Dehydrator : The number of dehydrators per EOR field was estimated by using the ratio of gas throughput to th e number of dehydrator s indicated in the GRI report and multiplying it by the recycled CO 2 volumes. The recycled dehydrator vented emissions were estimated using readjusted U.S. GHG Inventory emission

factor. The GRI methane emission factor was divided by 78.8% methane composition to calculate the natural gas emission factor. The natural gas emission factor was adjusted to EOR operation using the critical density of CO2. 97% CO 2 and 1.7% CH 4 composition obtained from Summary of Carbon Dioxide Enhanced Oil Recovery (CO 2 EOR) Injection Well Technology was used to estimate emissions.

• Recycled CO 2 Injection compressor : The recycled CO 2 injection compressor fuel gas requirement was estimated using an assumed value of 65 kWhr/metric ton CO2 injected. The assumption was based on the DOE study, Electricity use of EOR with

Carbon dioxide . It is assumed that only 50% of the injected CO2 re quires natural gas powered compressors. CH 4 and CO 2 combustion emissions were estimated by applying API compendium relevant combusti on emission factors to the fuel gas used by each operator. The fuel gas consump tion was estimated using the horsepower requirements of engines per operator. N 2 O (CO 2 e) combustion emissions were estimated by applying API compendium N 2 O combustion emission factors to the fuel gas used by each plant. The number of compressor per field was estimated using an assumed number of 12 hp/ bbl of EOR produ ced oil. This number was obtained from Enhanced Recovery Scoping Study conducted by the state of Ca lifornia. It is assumed that a typical compressor used in EOR operations is 3000 hp. This number is obtained from DOE study, Electricity use of EOR with Carbon dioxide . The compressor

blowdown emissions was estimated assumi ng one blowdown event per year, the estimated number of compressors per fi eld, and compressor blowdown emission

factor obtained from the U.S GHG invent ory. The compressor blowdown emission factor was adjusted for critical CO 2 density, CO 2 and CH 4 gas composition. 97% CO 2 and 1.7% CH 4 composition obtained from Summary of Carbon Dioxide Enhanced Oil Recovery (CO2EOR) Injection Well Technology was used to estimate emissions. .

• CO2 Injection pumps : The supercritical CO 2 injection pumps are assumed to be electrically driven and therefore have no combustion emissions. 97% CO 2 and 1.7%

CH 4 composition obtained from Summary of Carbon Dioxide Enhanced Oil Recovery ( CO 2 EOR) Injection Well Technology was used to estimate emissions. The pump blowdown emissions were estimated assuming an internal diameter of 12 inches and length of 30 feet with a 50% void volum e. The pipe length between the blowdown

valve and unit valve was assumed to be 10 feet with a diameter of 5.38 inches. It is assumed that the pump and pipeline vent gas equivalent to their volume once a year during blowdown operations. The number of supercritical pumps required per field was estimated by assuming that the EOR operations use pumps with 600 hp with a throughput of 40 Mcf/day. These pump sp ecifications were obtained from an

unnamed Natural Gas STAR Partner.

• Water injection pumps : The injection pump fuel gas requirement was estimated using an assumed value of 6 kWhr/bbl of oil produced. The assumption was based on

88the DOE study, Electricity use of EOR with Carbon dioxide . It is assumed that only 50% of the injection pumps are natural gas powered. CH 4 and CO 2 combustion emissions were estimated by applying API compendium (2004) relevant combustion emission factors to the fuel gas used by each operator. The fuel gas consumption was estimated using the horsepower requir ements of engines per operator. N 2 O (CO 2 e) combustion emissions were estimated by applying API compendium N 2 O combustion emission factors to the fuel gas used by each plant.

• Orifice Meter Vented Emissions : It is assumed that there are 5 orifice meters for each field based on data provided by an unnamed Natural Gas STAR Partner. The

orifice meters are assumed to be calibrated once per year during which the volume of meter is vented to the atmosphere. The orifice meters are assumed to be 8 inches in

diameter and 12 feet in length. 97% CO 2 and 1.7% CH 4 composition obt ained from Summary of Carbon Dioxide Enhanced Oi l Recovery (CO2EOR) Injection Well Technology was used to estimate emissions.

• The total emissions per operator were calc ulated by summing up all the process and combustion emissions for EOR opera tions and onshore production.

• Each operators was assigned a “1” or “0” ba sed on if it crossed a threshold by running the following logic checks:

o IF(operator total emission s > 1000) then reporting

o IF(operator total emission s > 10000) then reporting

o IF(operator total emission s > 25000) then reporting

o IF(operator total emission s >100000) then reporting

Threshold Analysis for Offshore Production

• Federal GOM offshore platforms, by their complex ID, and their corresponding CO 2 combustion and fugitive emissions (CO 2 e), CH 4 fugitive emissions (CO 2 e), CH 4 vented emissions (CO 2 e), and N 2 O combusted emissions (CO 2 e) for the year 2000

was obtained from the MMS Goads Summar y Access File "Final GOADS Emissions

Summaries”

• The ratio of 2006 to 2000 Gulf of Mexico offshore productions was calculated and applied to the emissions from each platform to estimate emissions for the year 2006.

• The total number of GOM offshore production platforms was obtained from the

MMS website.

• Each platform was assigned a “1” or “0” base d on if it crossed an emissions threshold by running the following logic checks:

o IF(operator total emission s > 1000) then reporting

o IF(operator total emission s > 10000) then reporting

o IF(operator total emission s > 25000) then reporting

o IF(operator total emission s >100000) then reporting

• The total number of state platforms (Ala ska and Pacific) was obtained from the

Alaska Division of Oil and Gas and Emery et al 24 respectively. The number of state and federal offshore oil and gas wells fo r GOM, Pacific, and Alaska was obtained

from the LASSERTM database. The ratio of federal GOM oil and gas wells to federal

24 http://www.icess.ucsb.edu/iog/pubs /DrifterSimulationsFinal_v5.pdf

89platforms and the number of state offshore oi l and gas wells were used to estimate the state GOM platform count.

• The ratio of gas to oil platforms was obt ained from the U.S GHG Inventory 2006. All the state offshore platforms were assu med to be shallow water platforms.

• The state offshore fugitive, vented and combustion emissions were estimated by applying the ratio of state to federal platforms and multiplying it by the federal offshore fugitive, vented, and combustion emissions.

• The percentage of platforms that fall within each emissions threshold (1000, 10,000, 25,000 and 100,000 metric tons CO 2 e) for the federal GOM offshore was calculated and applied to the estimated state fugitiv e, vented, and combustion emissions to

calculate the volume of state offshore emi ssions that fall within each threshold.

• The number of state platforms that fall w ithin each category was estimated by taking the ratio of federal emissions to platform count within each threshold and multiplying it by the state emissions covered by each threshold.

• The emissions from state and federal offshore platforms were summed up to estimate the total emissions from offshore operations

Threshold Analysis for Processing

• US gas processing plants, plant throughputs, and equipm ent count per plant were obtained from the OGJ (2006). 2005 and 2006 emissions are assumed to be the same on a plant basis as the total national throughput from 2005 to 2006 did not change significantly and were 45,685 MMcf/d and 45,537.4 MMcf/d respectively as indicated by the U.S. GHG Inventory

• CH 4 and CO 2 process emissions (CO 2 e) per facility were estimated by multiplying the equipment count per plant (activity factor ) obtained from the Gas Processing Survey with their corresponding em ission factors obtained from GRI/ EPA 1996 reports. The national processing sector average composition (CH 4 and CO 2 content) of natural gas was obtained from GTI and applied to the GRI emission factors. Emission factor for centrifugal compressor degassing seal s was obtained from Bylin et al 25

.

• CH 4 , CO 2 and N 2 O combustion emissions (CO 2 e) were estimated by applying

CH 4 ,CO 2 and N 2 O API compendium relevant combus tion emission factors to the fuel gas used by each plant. The fuel gas consumption was estimated using the horsepower requirements of engine s and turbines per plant.

• N 2 O combustion emissions (CO 2 e) were estimated by applying API compendium

N 2 O combustion emission factors to th e fuel gas used by each plant.

• The different emissions per plant was summed up to provide total emissions (CO 2 e)

• Each facility was assigned a “1” or “0” based on if it crossed a threshold by running the following logic checks:

o IF(operator total emission s > 1000) then reporting

o IF(operator total emission s > 10000) then reporting

o IF(operator total emission s > 25000) then reporting

25 Bylin, Carey (EPA), et. al (2009) Methane’s Role in Promoting Sustai nable Development in Oil and Natural Gas Industry . <presented at 24th World Gas Conference>

90o IF(operator total emission s >100000) then reporting

• Summing the results of the above logic checks for each threshold provided the number of facilities exceeding that threshold.

• Multiplying the logic checks above by the total emissions for each facility, then summing the results yielded the total em issions covered at each threshold.

• The resulting O&M and capital costs from th e cost burden analyses were entered for each facility in the spreadsheet. The sum of the product of O&M or capital costs and the logic checks described above provides th e total cost burdens for each reporting threshold. Dividing the total cost burde ns by the number of reporting facilities (calculated above) provides the average fa cility cost burdens at each reporting

threshold.

Threshold Analysis for Transmission

• “Facility” in the natural gas transmission segm ent is defined as a compressor station. Data for individual compressor stations on interstate transmission pipelines are reported to FERC Form 2 26 , and data for compressor stat ions on intrastate pipelines were obtained from EIA through personal cont act. However, the data collected for intrastate pipelines were incomplete.

• For intrastate pipeline facilities that did not have the number of compressor stations listed, it was assumed that each facility has one compressor. The compressor horsepower per intrastate pipeline was estimated by multiplying design throughput per intrastate pipeline with the ratio of total interstate pipeline compressor horsepower (engine and turbine) to the total interstate design throughput.

• The FERC data, supplemented with intrastate data and assumptions, list pipeline states, names, designed throughput capac ity, and in some cases the type of compressor (centrifugal, reciprocating, and/ or electric), and the installed horsepower

for each station.

• In cases where the installed reciprocating horsepower is provided, it was used for installed engine capacity (H p). In cases where the inst alled capacity was provided, but the type of compressor was not specified , the analysis assumes that 81% of the installed capacity is reciprocating. In cases where the provided installed capacity is both centrifugal and reciprocating, it is a ssumed that 81% is for engines. The 81% assumption is the ratio of reciprocat ing compressor engine capacity in the transmission sector to centrifugal turbin e drivers for 2006 taken from the U.S. GHG Inventory

• The ratio of reciprocating compressor engine driver energy use (MMHphr, EPA 28 ) to interstate station design th roughput capacity (MMcfd, FERC 27 ) was calculated. Then, the reciprocating compressor energy use for each station was assigned by multiplying the installed station throughput capacity by th e ratio calculated pr eviously in this

bullet.

• In cases where the installed centrifugal horse power is provided, it was used directly for installed turbine capacity (Hp). In cases where the installed capacity was

26 FERC. Form 2 Major and Non-major Natural Gas Pipeline Annual Report. Available online at: <http://www.ferc.gov/docs-filing/eforms/form-2/data.asp#skipnavsub>.

91provided, but the type of compressor was not specified, the analysis assumes that 19% of the installed capacity is centrifugal. In cases where the provided installed capacity is both centrifugal and re ciprocating, it is assumed that 19% is for turbines. The 19% assumption is the ratio of centrifugal compressor turbine capacity in the transmission sector to reciprocating e ngine drivers taken from the U.S. GHG Inventory.

• The ratio of centrifugal compressor e ngine driver energy use (MMHphr, EPA 28 ) to interstate station design th roughput capacity (MMcfd, FERC 27 ) was calculated. Then, the reciprocating compressor energy use for each station was assigned by multiplying the installed station throughput capacity by th e ratio calculated pr eviously in this

bullet.

• The total emissions for 2006, both vented and fugitive methane and non-energy CO 2 , were estimated in the U.S. GHG Inventory. These total fugitive and vented emissions were allocated to each facility based on its portion of the segment’s total station throughput capacity, as shown in the following equation:

Station “ i ” process emissions = ons toryEmissi TotalInven acity StationCap acity StationCap

i i × 

## ∑

• Combustion CO 2 and N 2 O emissions were estimated for each facility by applying the following emission factors:

EF CO2 = 719 metric tons CO 2 e/MMHphr

EF N20 = 5.81 metric tons CO 2 e/MMHphr

Emissions CO2 or N20 = EF CO2 or N20 × Compressor energy i (MMHphr)

• The total emissions for each facility were calculated by summing the calculated process and the combustion emissions.

• Each facility was assigned a “1” or “0” based on if it crossed a threshold by running the following logic checks:

o IF(operator total emission s > 1000) then reporting

o IF(operator total emission s > 10000) then reporting

o IF(operator total emission s > 25000) then reporting

o IF(operator total emission s >100000) then reporting

• Summing the results of the above logic checks for each threshold provided the number of facilities exceeding that threshold.

• Multiplying the logic checks above by the total emissions for each facility, then summing the results yielded the total em issions covered at each threshold.

Threshold Analysis for Underground Storage

• “Facility” in the underground natural gas st orage segment is defined as storage stations and the connected storage wellhea ds. Underground storage data by operator

are collected in form EIA-176 27

.

27 EIA. EIA-176 Query System . Available online at: <http://www.eia.doe.gov/oil_gas/natural_gas/applications/eia176query_historical.html>.

92• The data collected in EIA-176 contained each underground storage operator, field, and location as well as the storage cap acity and maximum daily delivery.

• The total compressor energy use in 2006 fo r the underground storage segment was estimated in the U.S. GHG Inventory. This total energy us e, in millions of horsepower hours (MMHphr), is allocated to each facility based on its portion of the segment’s total maximum daily delivery ca pacity; as described in the following equation:

Compressor energy i (MMHphr) = ntMMHphr TotalSegme lyDelivery MaximumDai lyDelivery MaximumDai

i i × 

## ∑

Where, index “ i ” denotes an individual facility

• The total process emissions for 2006, both vented and fugitive methane and nonenergy CO 2 , were estimated in the U.S. GHG Inventory. These total process

emissions were allocated to each facility based on its portion of the segment’s total maximum daily delivery capacity, using the same methods as compressor energy use.

• Combustion CO 2 and N 2 O emissions were estimated for each facility by applying the following emission factors:

EF CO2 = 719 metric tons CO 2 e/MMHphr

EF N20 = 5.81 metric tons CO 2 e/MMHphr

Emissions CO2 or N20 = EF CO2 or N20 × Compressor energy i (MMHphr)

• The total emissions for each facility were calculated by summing the calculated process and the combustion emissions.

• Each facility was assigned a “1” or “0” based on if it crossed a threshold by running the following logic checks:

o IF(operator total emission s > 1000) then reporting

o IF(operator total emission s > 10000) then reporting

o IF(operator total emission s > 25000) then reporting

o IF(operator total emission s >100000) then reporting

• Summing the results of the above logic checks for each threshold provided the number of facilities exceeding that threshold.

• Multiplying the logic checks above by the total emissions for each facility, then summing the results yielded the total em issions covered at each threshold.

93Threshold Analysis for LNG Storage

• “Facility” in LNG storage segment is define d as LNG storage plants (peak shaving or satellite). Data for each peak shaving facility is provided in The World LNG Source Book – An Encyclopedia of the World LNG Industry . Summary data for all satellite

facilities is estimated in ICF Additional Changes to Activity Factors for Portions of the Gas Industry background memo for EPA’ s U.S. GHG Inventory.

• The data reported in The World LNG Source Book – An Encyclopedia of the World LNG Industry includes the operator, liquefaction capacity, storage capacity, vaporization design capacity for each individual peak shaving plant.

• U.S GHG Inventory reports th at in addition to peak shaving plants there are approximately 100 satellite faci lities with a to tal storage capacity of 8.7 Bcf. The ICF memo also provides several ke y assumptions that will be discussed at the appropriate

locations below.

• The total liquefaction compressor energy use for the segment was estimated using the methods and assumptions detailed in the ICF background memo for EPA’s U.S. GHG Inventory. LNG company contacts pr ovided the memo’s assumption that 750 MMHphr are required for liquefaction for each million cubic feet per day of liquefaction capacity. It assumes the lique faction takes place over a 200-day “fill” season. It assumes that approximately 50% of compressors are driven by gas-fired engines or turbines. EIA provides the L NG storage additions for 2006 on its website, totaling 38,706 MMcf. Thus, the total lique faction energy use for the segment was calculated using the following formula:

LEU = Hphr MMHphr days day hours

MMcfd Hp
days MMcf

000,000,1 1 %50 200 24

1 750

200 706,38

×××××

where, LEU = total liquefaction energy use for the segment, gas fired (MMHphr)

• The total calculated liquefaction compresso r energy use was apportioned to individual facilities based on their share of the total liquefaction capacity for the segment, as shown in the following equation:

Facility “i” liquefaction MMHphr = ntMMHphr TotalSegme LC LC

i i × 

## ∑

Where “i” indexes facilities and LC = liquefaction capacity.

• Storage capacity, provided in gallons by The World LNG Source Book – An Encyclopedia of the World LNG Industry , was converted to milli on cubic feet with a conversion factor of 1 gallon of LNG = 81.5 standard cubic feet of natural gas.

• Boil-off liquefaction compressor energy use was calculated using assumptions outlined in the U.S GHG Inventory. Th e memo assumes that 0.05% of storage capacity boils off and is recovered by vapor recovery compresso rs and liquefied. These compressors must operate all year and require the same 750 Hp per 1 MMcfd liquefied. The boil-off liquefaction compressor energy use was thus estimated for each facility using the following equation:

94FBEU i = Hphr MMHphr

day hours days MMcfd Hp
days SC
i 000,000,1 24 365 750

365 %05.0

× ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× ×× ×

where,

FBEU i = Facility “i” boil-off liquefaction compressor energy use (MMHphr) SC = Facility “i” storage capacity (MMcf)

• Vaporization and send-out compressor energy use was also calculated based on assumptions from the U.S GHG Inventory. It estimates that with an average send-out pressure of 300 psia and inlet pressure of 15 psia, using 2- stage compression, a satellite facility requires 1.86 MMHphr for each MMcfd of send-out. The send-out period lasts all year, unlike the “fill” season. The memo also estimates that 75 Bcf of gas were sent out from peak shaving facilities compared to 8.7 Bcf from satellite facilities in 2003. This equates to 89.6% of send-out coming from peak shaving plants in 2003; the analysis assume s the same is true for 2006. EIA 28 provides that in 2006, total LNG withdrawals were 33,743 MMcf. The send-out compressor energy use by all peak shaving plants in the se gment was calculated using the following equation:

Total send-out energy use = %6.89 86.1

365 743,33

× × MMcfd MMHphr

days MMcf

• Send-out compressor energy use was apportioned to each peak shaving facility by its share of the total peak shaving segment’ s send-out capacity; using the same method as apportioning liquefaction energy use. (See liquefaction bullet).

• The 100 satellite facilities were assumed to be equal size and capacity. That is, 8.7 Bcf storage capacity, all of which is sent out each year. It was assumed that satellite facilities have no liquefaction, except for that which is necessary for boil-off. We performed the above analysis on the “average” satellite facility to estimate its energy use and emissions. The only difference was that 10.4% of EIA reported LNG

withdrawals was attributed to the satellite facilities.

• The total process emissions for 2006, both vented and fugitive methane and nonenergy CO 2 , were estimated in the U.S. GHG Inve ntory. These total emissions were allocated to each facility based on its porti on of the segment’s total storage capacity, using the same methods as apportioning liquefaction and send-out compressor energy

use.

• Combustion CO 2 and N 2 O emissions were estimated for each facility by applying the following emission factors:

EF CO2 = 719 metric tons CO 2 e/MMHphr

EF N20 = 5.81 metric tons CO 2 e/MMHphr

Emissions CO2 or N20 = EF CO2 or N20 × Compressor energy i (MMHphr)

28 EIA. Liquefied Natural Gas Additions to and Withdrawals from Storage . Available online at: <http://tonto.eia.doe.gov/dnav/ng/ng_stor_lng_dcu_nus_a.htm>.

95• The total emissions for each facility were calculated by summing the calculated fugitive, vented, and combustion emissions.

• Each facility was assigned a “1” or “0” based on if it crossed a threshold by running the following logic checks:

o IF(operator total emission s > 1000) then reporting

o IF(operator total emission s > 10000) then reporting

o IF(operator total emission s > 25000) then reporting

o IF(operator total emission s >100000) then reporting

• Summing the results of the above logic checks for each threshold provided the number of facilities exceeding that threshold.

• Multiplying the logic checks above by the total emissions for each facility, then summing the results yielded the total em issions covered by each threshold.

• Satellite facilities crossed the 1,000 and 10,000-metric ton reporting threshold, but fell well short of the 25,000-metric ton threshold.

Threshold Analysis for LNG Import Terminals

• “Facility” in the LNG import segment is defined as the import terminals. Data is

available for this on the FERC website 29 . It provides the owner, location, capacity, and 2006 import volumes for each LNG terminal.

• ICF Additional Changes to Activity Factors for Portions of the Gas Industry background memo for EPA’s U.S. Inventor y assumptions were used to estimate liquefaction, boil-off liquefaction, and se nd-out compressor energy use for each of the LNG import terminals.

• It was assumed that import terminals do not have liquefaction capacity.

• Boil-off liquefaction compressor energy use was calculated using assumptions

outlined in ICF Additional Changes to Activity Factors for Portions of the Gas Industry background memo for EPA’s U.S. Inventory. The memo assumes that 0.05% of capacity boils off and is reco vered by vapor recovery compressors and liquefied. These compressors must operate all year and require the same 750 Hp per 1 MMcfd liquefied. The boil-off liquef action compressor energy use was thus estimated for each facility using the following equation:

FBEU i = Hphr MMHphr

day hours days MMcfd Hp
days IV
i 000,000,1 24 365 750

365 %05.0

× ⎟ ⎟ ⎠ ⎞ ⎜ ⎜ ⎝ ⎛

× ×× ×

where,

FBEU i = Facility “i” boil-off liquefaction compressor energy use (MMHphr)

IV i = Facility “i” import volume (MMcf)

• Vaporization and send-out compressor energy use was also calculated based on assumptions from ICF Additional Changes to Activity Fa ctors for Portions of the Gas Industry background memo for EPA’s U.S. GHG Inve ntory. It estimates that with an average send-out pressure of 300 psia and inlet pressure of 15 psia, using 2-stage

29 FERC. Import Terminals . Available online at: <http://www.ferc.gov/industries/lng.asp>.

96compression, satellite facilities require 1.86 MMHphr for each MMcfd of send-out. The following equation estimates the energy use at each facility:

Facility “i” send-out energy use = MMcfd MMHphr

days IV
i 86.1

365 ×

• The total process emissions for 2006, both vented and fugitive methane and nonenergy CO 2 , were estimated in the U.S. GHG Inventory. These total process

emissions were allocated to each facility based on its portion of the segment’s total import volume, using the following equation:

Facility “i” process emissions = sions egmentEmis InventoryS IV IV

i i × 

## ∑

where,

IV i = import volume and “i” re presents individual facilities

• Combustion CO 2 and N 2 O emissions were estimated for each facility by applying the following emission factors:

EF CO2 = 719 metric tons CO 2 e/MMHphr

EF N20 = 5.81 metric tons CO 2 e/MMHphr

Emissions CO2 or N20 = EF CO2 or N20 × Compressor energy i (MMHphr)

• The total emissions for each facility were calculated by summing the calculated process and the combustion emissions.

• Since there were only 5 active import terminal s, all were assumed to be “medium” in

size.

• Each facility was assigned a “1” or “0” based on if it crossed a threshold by running the following logic checks:

o IF(operator total emission s > 1000) then reporting

o IF(operator total emission s > 10000) then reporting

o IF(operator total emission s > 25000) then reporting

o IF(operator total emission s >100000) then reporting

• Summing the results of the above logic checks for each threshold provided the number of facilities exceeding that threshold.

• Multiplying the logic checks above by the total emissions for each facility, then summing the results yielded the total em issions covered by each threshold.

Threshold Analysis for Distribution

• “Facility” in the natural gas distribution se gment is defined as the local distribution company (LDC). The Departme nt of Transportation (DOT) 30 provides a set of data

that contains distribution ma in pipelines miles by pipeline materials and distribution service counts by pipeline material for each LDC.

• Fugitive CO 2 and CH 4 emissions from distribution mains were evaluated for each facility by multiplying its pipeline data by the appropriate emission factor, summarized in the table below, from the U.S GHG Inventory

.

30 DOT. 2006 Distribution Annuals Data . Available online at: <http://www.phmsa.dot.gov/pipeline/library/data-stats>.

97Exhibit C-8: LDC’s Fugitive Emissions Emission Factor

Pipeline Type/Material Fugitive GHG Emission Factor

Mains – Unprotected Steel 110 Mcf/mile/year

Mains – Protected Steel 3.07 Mcf/mile/year

Mains – Plastic 9.91 Mcf/mile/year

Mains – Cast Iron 239 Mcf/mile/year Services – Unprotected

Steel 1.70 Mcf/service/year

Services – Protected Steel 0.18 Mcf/service/year

Services – Plastic 0.01 Mcf/service/year Services – Copper 0.25 Mcf/service/year

• The total miles of mains pipelines of a ll materials were summed for each LDC.

• The total emissions from metering and regulating (M&R) stations for 2006, both vented and fugitive methane and non-energy CO 2 , were estimated by EPA U.S GHG Inventory. These total emissions were allo cated to each facility based on its portion of the segment’s total import volume, using the following equation:

Facility “i” M&R emissions = sions egmentEmis InventoryS MM MM

i i × 

## ∑

where,

MM = total miles of mains pipeline, and “i” represents individual

facilities

• There are no combustion emissions from the LDCs covered in the rule.

• The total emissions for each facility were calculated by summing the calculated pipeline fugitives and M&R station emissions.

• Each facility was assigned a “1” or “0” based on if it crossed a threshold by running the following logic checks:

o IF(operator total emission s > 1000) then reporting

o IF(operator total emission s > 10000) then reporting

o IF(operator total emission s > 25000) then reporting

o IF(operator total emission s >100000) then reporting

• Summing the results of the above logic checks for each threshold provided the number of facilities exceeding that threshold.

• Multiplying the logic checks above by the total emissions for each facility, then summing the results yielded the total em issions covered at each threshold.

98

### Appendix D: Analysis of potential facility definitions for onshore petroleum and natural gas production

The purpose of this appendix is to determine th e barriers in using a physical definition of a facility for the onshore petroleum and natu ral gas production segment. The paper also discusses a potential alternative to a physical definition by using a corporate level reporter

definition.

A. Facility Definition: Any production sector reporting co nfiguration will need specific definitions on what constitutes a facility. There are no definitions currently for the production sector in the initial rule proposal.

i. Field level – A field may be defined by either physically aggregating certain surface equipment, referred to as physical field definition. Or the field may be defined by demarcation of geographical boundaries, referred to as Geographic

field definition.

Physical field definition: The challenge in defining a field as a facility is to recognize a common structure through the oil and gas production operations. Such a definition can be achieved by identifying a point in the system ups tream of which all equipment can be collectively referred to as a field le vel facility. All oil and gas production operators are required by law to meter their oil and gas production for paying royalties to the owner of the gas and taxe s to the state, referred to as the lease meter. All equipment upstream of this meter can be collectively referred to as a facility.

There is no precedence for such a defi nition in the CAA. It must be noted, however, that the facility definitions commonly used in the CAA pertain specifically to pollutants whose concentra tion in the ambient atmosphere is the deciding factor on its imp act. This is not ne cessarily true of GHGs that have the same overall impact on climate forcing irre spective of how and where they occur.

Geographic field definition:

An alternative to the lease meter field le vel definition is to use the EIA Oil and

Gas Field Code Master 31 to identify each geological field as a facility. This definition is structurally similar to the corp orate basin level definition, i.e. it uses geological demarcations to identify a facility rather th an the above ground operational demarcation.

ii. Basin level – The American Associa tion of Petroleum Geologists (AAPG) provides a geologic defin ition of hydrocarbon producti on basins which are

31 EIA Oil and Gas Field Master – 2007, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_pub lications/field_code_master_list/current/pdf/fcml_all. pdf

99referenced to County boundaries. The Unite d States Geological Survey (USGS) also provides such a definition, which is different than the AAPG definition. The AAPG definition identified by the “geol ogic province code” is most commonly used by the industry and can be used to report emissions from each basin. The

individual counties in each state are allocated to diffe rent geologic province codes and therefore there is no ambiguity in a ssociating an operation with the relevant basin (geologic province c ode). An operation physically located on a basin as defined by the AAPG can be identified with that particular basi n, irrespective of which basins the wells are producing from. (Well pads may have multiple wells producing from different fields and zones in a reservoir, and possibly different basins as well).

B. Level of Reporting: It is important to clearly distingui sh the level of reporting- i.e., the facility level or the corporate level. The leve l of reporting is where the threshold level is applied and thus determination on whether re porting is required. In some cases, the owner or operator of the facility itself is the reporter and in other cases it is the overall company that is the reporter. For exampl e, in subpart NN of the MRR published on September 22, 2009, reporting for natural gas sent to the end use custom ers is at the local distribution company, and not th e individual physical locations (or facilities) that send the natural gas into the economy. Alternatively, in subpart MM of the initial rule proposal, the owner or operator of the in dividual refinery is the repor ter as opposed to the company owning multiple refineries.

For the purposes of onshore petroleum and natural gas production reporting can be at either the facility level or the corporate level. If the level of reporting is at the corporate level, it could still be required that data be reported for indivi dual facilities.

Petroleum and natural gas production companie s are identified unique ly by the Internal Revenue System (IRS). Also, the CAA define s the ‘‘owner or operator’’ as meaning any person who owns, leases, ope rates, controls, or supervises a stationary source. In general, operational control for a facility means th e authority to introduce and implement operating, environmental, health and safety policies, and therefore would be the entity who potentially reports under th e rule. In circumstances where this authority is shared among multiple entities, the en tity holding the pe rmit to operate from the local air pollution control district or air quality mana gement district is considered to have operational control.

C. Qualitative Analysis of Facility Options

The following qualitative evaluation provi des a discussion on the advantages and disadvantages of using any of th e three reporting level definiti ons, based on expert opinion.

i. Ease of practical application of reporter and facility definitions

1001) Field level facility definition – In this case the physical demarcation of field level by aggregating field equipment is difficult to implement. On the other hand, field level definition based on bounda ries identified by the EIA Oil and Gas Field Code Master should be easy to implement, since the classification if widely used in the industry.

Physical Field Definition: There are no standard guidelines or operational practices on how many wells can be connected to one lease meter. The choice of whether multiple wells are

connected to the same lease meter de pends on; the well spacing, number of owners of leases, volume of hydro carbons produced per well, geographical boundaries, and ease of operati on. Therefore, such a de finition will lead to facilities of all kinds of sizes; at one extreme several well pads with multiple wells could be connected to one lease meter, while at the other extreme where situation demands only one well with no equipment could directly be

connected to a lease meter. In addition th ere will be thousands of facilities that will be under purview.

Any lease meters located upstr eam of a compression system will exclude compressors from the facility definition. This means that the required threshold for emissions reporting may not be reached due to exclusion of the fugitive emissions as well as the combustion emissions from compressors.

Geographic field definition: The EIA publishes its Fiel d Code Master on a yearly basis. Also, the classification system is widely used in the industry. Hence such a definition should be easy to implement.

2) Basin level facility definition - Basin level definition is more practical to implement given that operational bounda ries and basin demarcations are clearly defined. Furthermore, more em issions will be captured under this facility definition than the field level or well level definitions.

3) Corporate reporting - It can be difficult to identify who the co rporation is that would be responsible for reporting. If the corporation can be readily identified and defined then applying a field level facil ity definition using the EI A field classification or basin level facility definition using AAPG classification becomes practical.

ii. Coverage that can be expected from each definition type 1) Field level facility definition – This definition (both physical and geographical) provides the highest le vel of detail possible on emissions sources. However, any field level defi nition along with a 25,000 metric tons

CO 2 e/year threshold for reporting could potentially exclude a large portion of the U.S. oil and gas operations. Hence only a portion of the entire emissions from the U.S. oil and gas operations will get reported.

1012) Basin level facility definition - Basin le vel information will throw light on the difference in patterns of emissions fr om sources both as a result of being

located in different basins and as a re sult of different opera tional practices in different companies. This definition will result in the reporting of a significant portion of the emissions for the identifi ed sources from the entire U.S. onshore oil and gas operations.

3) Corporate reporting - This definition will result in reporting of a significant portion of the emissions for the identified sources from the entire US onshore oil and gas operations. Since the reporting will be at a company level,

variations in emissions from sources due to location on different basins may not be evident. However, if corporate national level reporter definition is used

in addition to field and/or basin level reporting then all possible patterns in

emissions will be evident.

D. Data Sources for Research and Analysis

i. Clean Air Act

ii. United States Geological Survey

iii. Natural Gas STAR Technical Documents

iv. EPA National GHG Inventory

v. DOE GASIS database

vi. Lasser® database

vii. Energy Information Administration

viii. Oil & Gas Journal

ix. HARC - VOC Emissions from Oil and Condensate Storage Tanks

x. State Oil and Gas Commissions

102

### Appendix E: Analysis of potential facili ty definitions for local distribution companies

The purpose of this appendix is to investigate options for defi ning reporting facilities within

the local distribution sector as well as disc uss emissions sources to be reported and the associated coverage.

A. Issue Identification and Clarification

i. LDC Facility Definition: A potential parallel for defining the distribution sector for the GHG Reporting rule is adapting th e definition available from Section NN of the Final Mandatory Reporting Rule (MRR) published on September 22, 2009.

The Clean Air Act (CAA) does not put fort h any definition for a facility in the natural gas distribution sector . This is to be expected as there are few sources of hazardous air pollutants in the natural gas distribution sector; the primary stationary emissions from this sector are fugitive and vented methane emissions. Only Section 112 (n) (4) (A) mentions natu ral gas pipeline f acilities within the

CAA and it states that emissions from co mpressor or pump sta tions shall not be aggregated with other units to determine whether they are major sources. As there are no compressor stations or pump stations within local natural gas distribution systems, this would potentially not effect any facility definition.

In developing an appropriate definition for a reporting entity within the local natural gas distribution sector , a number of sources were examined to determine if there are any existing faci lity definitions in use. The Pipeline and Hazardous Materials Safety Administration (PHMSA) in the Department of Transportation

collects data from the dist ribution sector on pipeline in cidents and mileage. CFR

Title 49 Section 191.11 32 requires that “each operator of a distribution pipeline system shall submit an annual report fo r that system”. Section 191.3 defines a pipeline system as:

Pipeline or Pipeline System means all parts of those physical facilities through which gas moves in transportation, including, but not limited to, pipe, valves, and other appurtenance attached to pipe, compressor uni ts, metering stations, regulator stations, delivery stations, holde rs, and fabricated assemblies.

Data on pipeline mileage, number of serv ices, leaks, and other incidents is reported to the PHMSA by individual LD Cs. Larger holding companies that operate distribution systems in different areas do not report as one large entity; each system reports separate data to the PHMSA.

32 Code of Federal Regulations Title 49. “Transportation of Natural and Other Gas By Pipeline; Annual Reports, Incident Reports, and Safety-Related Condition Reports.” Available online at http://www.access.gpo.gov/nara/cfr/waisidx_02/49cfr191_02.html

103The Climate Registry supports a volunt ary GHG emissions reporting system in North America. The Climate Registry pr oposes that “For purposes of reporting, each pipeline, pipeline system, or electrici ty T&D system should be treated as a single facility” 33 . This definition indicates that an entire distribution system operated by an LDC would report GHG emissi ons as one entity to The Climate Registry.

The final MRR requires that all LDCs report CO 2 emissions which would result from the complete combustion of natural gas delivered to end users. The rule

defines LDCs as:

Local Distribution Companies are companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, that physica lly deliver natural gas to end users and that are regulated as separate operating companies by State public utility commi ssions or that operate as independent municipally-own ed distribution systems.

These various sources imply that LDCs ar e accustomed to reporting data from the pipeline systems that they operate. If GHG emissions from the natural gas distribution sector are requ ired to be reported, it would be easiest to have emissions reported at the LDC level as this is consistent with the final MRR as well as other data reporting mechanisms. It is important to note that often one company may own several LDCs under differe nt names. In such a case, it is important to determine at what level the company has to report.

B. Evaluation Criteria and Approach

i. Qualitative Analysis

A qualitative evaluation below provides a discussion on the advantages and disadvantages of using a LDC reporting level definition, using the following criteria;

1) Boundary limitations.

As some holding companies operate multiple LDCs, often in close proximity, it may be difficult to define distinct boundaries between the systems that do

not double-count or under-count GHG emi ssions. The data collected by the PHMSA appears to have addressed bounda ry issues for these large holding companies. The boundary specifications used by LDCs to report to the PHMSA can be potentially used to e liminate any confusion in the boundaries between LDCs owned by the same holding company.

33 The Climate Registry. “General Reporting Protocol”. Page 38. Available online at http://www.theclimateregistr y.org/downloads/GRP.pdf

104Another issue that needs to be addressed for the boundary definition is DOT’s definition of distribution pipelines versus transmission pipelines. In some cases, pipelines operated by LDCs are considered transmission pipelines rather than distribution pipelines. CF R Title 49 §192.5 provides the definition

of a transmission line which can cover ce rtain pipelines that are operated by an LDC. For example, a large company may operate a length of pipeline that delivers natural gas from an interstate transmission line to their distribution center. Along that length of pipeline there may be individual farm taps or industrial customers that pull gas directly from the transmission line with their own regulator to step down pressure. B ecause these end-users are not part of the distribution system, the initial rule propos al would need to clarify if any emissions from the equipment used to step down pressure and meter gas going

to these customers would fall under the distribution sector or transmission

sector.

2) Ease of practical application of definition.

Annual reports collected by the Pipe line and Hazardous Materials Safety Administration (PHMSA) demonstrate that the definition of a distribution pipeline system can be applied to th e industry to achieve nationwide data reporting.

3) Coverage that can be expected fr om LDC facility definition type.

Defining a distribution pipeline system as a reporting entity in an equivalent

fashion as in CFR Title 49 191.3 should include all distribution operations as tracked in the U.S. GHG Inventory. The number of entities that trigger the reporting threshold will depend largel y upon the size of the system. A topdown estimate of fugitive emissions from LDCs based on both LDC data tracked by the PHMSA, as well as on emission factors from the Inventory of

US Greenhouse Gas Emissions and Sinks 34 , indicates that 11% of LDCs would emit fugitive emissions in excess of the 25,000 metric tons CO 2 e threshold. Emissions from these LDCs would make up over 90% of fugitive emissions from all sources in the natural gas distribution sector.

C. Data Sources for Research

i. US Methane Emissions Inventory

ii. CAA

iii. NAICS definitions - 221210 Natural Gas Distribution

iv. Office of Pipeline Safety

v. Pipeline and Gas Journal

34 EPA. Inventory of US Greenhouse Gas Emissions and Sinks: 1990-2006 . Available online at http://www.epa.gov/climatechange/emissions/usinventoryreport.html

.

105

### Appendix F: Analysis of Definition Options for Natural Gas Production Gathering Pipelines for Emissions Reporting

The purpose of this appendix is to identify issu es resulting from defining gathering pipelines as an independent reporting segment for the rule.

A. Issue Identification and Clarification

The initial rule proposal did not require emissions from natural gas production gathering pipelines to be reported. Natural gas pr oduction gathering pipelin es cannot easily be

classified into facilities as they are made up of a network of pipelines. The options for gathering pipelines are to incl ude these facilities in either the Onshore Production sector, the Gas Processing sector, a new segment, or exclude them from reporting.

i. Natural Gas Gathering Pipeline Facility Definition:

From the wellhead, natural gas is transpor ted to processing plants or natural gas transmission pipelines th rough a network of small-diameter, low-pressure gathering pipelines. A complex gatheri ng system can consist of thousands of miles of pipes, interconnecting the proce ssing plant to upwards of 100 wells in the area. The Department of Transportation (DOT), Pipeline and Hazardous Materials Safety Administration (PHMSA ) statistics show that there were approximately 12,477 miles of onshore a nd 7095 miles of offshore gas gathering pipeline in the U. S. in 2007. This is a fraction of the total gathering pipeline mileage because only the mileage closes t to human habitation that can pose a safety risk is reported to and regulated by PHMSA. Gathering pipelines may be owned by the producer or the processing plant, or the affiliate of a pipeline company or an independent gathering busin ess. A fee is charged for the service and the fees are negotiated between the producer and the gath ering pipeline.

Gathering systems may report to federal la nd management agencies and state land use agencies primarily for safety and permitting purposes. They must file reports with the PHMSA, Office of Pipeline Safety (OPS). These reports are relative to silting, routing, and safety issues.

The PHMSA collects data from the gather ing pipeline sector on pipeline incidents and mileage under CFR Title 49 Section 191.17 1 which requires each operator of a gathering pipeline system to submit an annual report:

(a) Except as provided in paragraph (b) of this section, each operator of a transmission or a gathering pipeline system shall submit an annual report for that system on Department of

1 Code of Federal Regulations Title 49. “Transportation of Natural and Other Gas By Pipeline; Annual Reports, Incident Reports, and Safety-Related Condition Reports.” Available online at http://www.access.gpo.gov/nara/cfr/waisidx_02/49cfr191_02.html

106Transportation Form RSPA 7100.2–1. This report must be submitted each year, not later than March 15, for the preceding calendar year.

Title 49CFR Part 192.3 defines a gathering pipeline as follows:

Gathering line means a pipeline t hat transports gas from a current production facility to a transmission line or main.

The PHMSA regulations for gas gatheri ng pipelines incorporate an industry standard prepared by the American Petroleum Institute (API RP 80) to better define which portions of the natural gas pipeline network are considered “gathering” pipelines. This includes how a pipeline operator must determine which of its gas gathering pipelines are subject to regulation, i.e., which are “regulated gathering lines.” This is done using criteria that determine when a gas gathering pipeline is close enough to a numb er of homes, or to areas/buildings where people congregate, that an accide nt on the pipeline could impact them. Offshore gas gathering pipelines and hi gh-pressure onshore lines meeting these criteria must meet all requirements of 49 CFR Part 192 applicable to gas transmission pipelines. Onshore gas gath ering pipelines that operate at lower pressures must comply with a subset of these requirements specified in 49 CFR

192.9.

Title 49CFR Part 191.15 for transmission and gathering systems incident reports

states:

(a) Except as provided in paragraph (c) of this section, each operator of a transmission or a gathering pipeline system shall submit Department of Transportation Form RSPA F 7100.2 as soon as practicable but not more than 30 days after detection of an incident required to be reported under §191.5.

Title 49CFR Part 191.3 defines an incident as follows:

Incident means any of the following events:(1) An event that involves a release of gas from a pipeline or of liquefied natural gas or gas from an LNG facility and (i ) A death, or personal injury necessitating in-patient hospitalization; or (ii) Estimated property damage, including cost of gas lost, of the operator or others, or both, of $50,000 or more.

Under section 7 of the Natural Gas Act, FERC reviews applications for the construction and operation of natural gas pipelines. In its a pplication review, FERC ensures that the applicant has certified that it will comply with Department of Transportation safety standards. FE RC has no jurisdiction over pipeline safety or security, but actively wo rks with other agencies with safety and security responsibilities.

107The Clean Air Act (CAA) does not put fort h any definition for a facility in the natural gas gathering pipelin e sector. This is to be expected as there are few sources of hazardous air pollutants in the na tural gas gathering pipeline sector; the primary stationary emissions from this sector are fugitive and vented methane emissions. Only Section 112 (4) (A) mentions natural gas pipeline facilities within

the CAA

(4) OIL AND GAS WELLS; PIPELINE FACILITIES.— (A) Notwithstanding the provisions of subsection (a), emissions from any oil or gas exploration or production well (with its associated equipment) and emissions from any pipeline compressor or pump station shall not be aggregated with emissions from other similar units, whether or not such units are in a contiguous area or under common control, to determine

whether such units or stations are ma jor sources, and in the case of any oil or gas exploration or production well (with its associated equipment), such emissions shall not be agg regated for any purpose under this

section.

The Climate Registry supports a volunt ary GHG emissions reporting system in North America. The Climate Registry pr oposes that “For purposes of reporting, each pipeline, pipeline system, or electrici ty T&D system should be treated as a single facility” 35 . This definition indicates that an entire gathering pipeline system operated by a company would report GHG emissions as one entity to The Climate Registry.

These various sources imply that comp anies are accustomed to reporting data from the gathering pipeline systems that they operate. If GHG emissions from the natural gas gathering pipeline segmen t were included, it could be most straightforward to have emi ssions reported at the pipeline company level as this is consistent with the PHMSA reporting.

B. Data Sources Referenced

i. US Methane Emissions Inventory

ii. CAA

iii. Office of Pipeline Safety

iv. Energy Information Administration

v. Gas Research Institute (GRI) Well workover assumptions in the study Methane Emissions from the Natural Gas Industry

.

35 The Climate Registry. “General Reporting Protocol”. Page 38. Available online at http://www.theclimateregistr y.org/downloads/GRP.pdf

108

### Appendix G: Accounting for Inaccessible Emissions Sources

The purpose of this appendix is to evaluate options for ensuring comprehensive fugitive and

vented emissions detection and measuremen t of all potential sources, focusing on accessibility issues of potential sources of fugitive methane emissions. Part 1 identifies and discusses comprehensiveness issues. Part 2 disc usses how to evaluate those issues. Part 3 identifies other resources pertaining to the issue, and part 4 provides a summary.

Inaccessible emission sources includes thos e potentially emitting components which are either unsafe to monitor, or physically out of reach, or visually hidden. Physically out of reach emission sources means those components wh ich are not within arms reach when using a portable VOC detection instrument. Visually hidden emission sources are those that cannot be viewed with a optical imag ing instrument due to blockage from other equipment or components. Unsafe-to-monitor emission source s are those described in the regulations

discussed below.

A. Review of Current Provisions Pe rtaining to Inaccessibility

Inaccessible components and comprehensiveness of leak surveys are addressed in current EPA volatile organic compound (VOC) regul ations. Method 21 provides general language about adhering to safety practices.

i. 40 CFR 60 Appendices: Method 21

5.0 Safety 5.1 Disclaimer. This method may involve hazardous materials, operations, and equipment. This te st method may not address all of the safety problems associated with its use. It is the responsibility of the user of this test method to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to perfor ming this test method.

40 CFR 60 Subpart VV covers leak inspecti ons of components and is referenced by subpart KKK for onshore natural gas pr ocessing plants. Subpart VV does notdiscuss equipment as inaccessible but as difficult or unsafe-to-monitor. Unsafe-tomonitor equipment means that the equi pment must expose monitoring personnel to immediate danger as a consequence of complying with performance standards. For equipment deemed as such, an expl anation is required by the operator and a plan must be developed for future mon itoring when the equipment is safe to monitor. Inaccessible equipment include s those that are unsafe-to-monitor; however, the provisions me ntioned above only apply to pumps, valves, and

connectors.

ii. 40 CFR 63 Subpart UU

109(e) Special provisions for connectors —( 1) Unsafe-to-monitor connectors. Any connector that is designated, as desc ribed in §63.1022(c)(1), as an unsafe-tomonitor connector is exempt from the re quirements of paragr aphs (a) and (b) of this section and the owner or operator sha ll monitor according to the written plan specified in §63.1022(c)(4).

2) Inaccessible, ceramic, or ceramic-lined connectors. (i) Any connector that is

inaccessible or that is ceramic or cerami c-lined (e.g., porcelain, glass, or glasslined), is exempt from the monitoring re quirements of paragr aphs (a) and (b) of this section, from the leak repair requirements of paragr aph (d) of this section, and from the recordkeeping and repor ting requirements of §§63.1038 and

63.1039. An inaccessible connector is one that meets any of the provisions specified in paragraphs (e)(2)(i)(A) through (e)(2)(i)(F) of th is section, as applicable.

(A) Buried;

(B) Insulated in a manner that prevents access to the connector by a monitor probe;

(C) Obstructed by equipment or piping that prevents access to the connector by a monitor probe;

(D) Unable to be reached from a wheeled scissor-lift or hydraulic-type scaffold that would allow access to connectors up to 7.6 meters (25 feet) above the ground.

(E) Inaccessible because it would requi re elevating the monitoring personnel more than 2 meters (7 feet) above a perm anent support surface or would require the erection of scaffold;

(F) Not able to be accessed at any time in a safe manner to perform monitoring. Unsafe access includes, but is not limited to, the use of a wheeled scissor-lift on unstable or uneven terrain, the use of a motorized man-lift basket in areas where an ignition potential exists, or access w ould require near proximity to hazards
such as electrical lines, or w ould risk damage to equipment.

(ii) If any inaccessible, ceramic or cera mic-lined connector is observed by visual, audible, olfactory, or other means to be le aking, the visual, audible, olfactory, or other indications of a leak to the atmo sphere shall be eliminated as soon as practical.

Based on a review of this existing HAP LDAR regulatory la nguage, from 40 CFR Part 63 Subpart UU, many accessibility issues are addressed. Inaccessible

connectors are described above as either buried, insulated in a manner that prevents access to the connector by a m onitor probe, obstructed by equipment or

110piping that prevents access to the connector by a monitor probe, or unable to be reached from an permanent support surface. This definition of inaccessible can potentially be applied to all components for leak detection.

The safety conditions outlined in the Clean Air Act and Method 21 may result in a portion of fugitive methane emissions to be excluded from required monitoring, due to safety and physical inaccessibility concerns in measurement. However,

these conditions are most common within processing facilities where there are a large number of equipment in close proxim ity, as well as equipment that deal with hot and cold process streams that may be a safety concern. This is not necessarily the case for the other sectors in the oil and natural gas industry such as onshore production, transmission, and dist ribution where methane streams are not necessarily a safety concern. The number of emission sources excluded for safety reasons in the other oil and natural gas sectors are most likely less than that from processing because of the relative simplic ity of their operations. Since the entire natural gas industry is within the scope of the rule, those leaks or measurements unaccounted for due to safety coul d be insignificant.

B. Potential methods to account for inaccessible components

i. Remote detection applicability – Dist ance, field of view, wind speed, and subjectivity of individual instrument tech nicians are among several factors that affect applicability to inaccessible compone nts. A remote detection instrument is

a device that can detect emissions without using a probe at a component’s surface.

1) Distance. Fugitive methane emissions detection instruments of the remote sensing type can accommodate screening of many components that are inaccessible. Components must first be within the working distance of the remote sensing instrument. One study 36 found that handheld remote sensing instruments can detect fugitive emissions from a 30-foot distance or closer. The study reports that the act ual distance will depend, in part, on the specific instrument model: for example, a passive optical imaging instrument will have

a maximum stated distance of “hundreds of feet”, while an active remote leak

detection instrument will indicate a maximum distance of about 100 feet. The effective distance of a remote sensing instrument will vary depending on a number of parameters, many of which will be specific to the individual facility or even the individual component being surveyed. The parameters that affect leak detection pe rformance include minimum detection limit, type of lens, wind speed, field of view, and th e ambient and gas temperatures. For example, an instrument may detect a leak of a certain magnitude from a certain vantage point but not detect the same leak from a different vantage point where the view is obstructed or if sustained wind speeds increase.

36 Implementing Directed Inspection & Maintenance with a Focus on Infrared Re mote Screening. Draft

document. EPA Natural Gas STAR

111The Alternative Work Pr actice (AWP) to Method 21 monitoring for 40 CFR Parts 60, 61, 63, and 65 in a VOC leak detection and repair program developed regulations to help ensure su ch standardization. Under the AWP, each monitoring session must begin w ith a “Daily Instrument Check”–a calibration test by releasing the know n hydrocarbon of interest at the

calculated mass flow rate and confir ming detection is possible at the maximum distance from the component to th e instrument that is to be tested during the monitoring session.

40 CFR 60 Subpart A [60.18(i)(2)] ( B) Set up the optical gas imaging instrument at a recorded distance from the outlet or leak orif ice of the flow meter that will not be exceeded in the actual pe rformance of the leak survey.

(v) Repeat the procedures sp ecified in paragraphs (i)(2)(ii) through (i)(2)(iv) of this secti on for each configuration of the optical gas imaging instrument used during the leak survey.

This calibration test aims to control the parameters of performance and ensures that an inaccessible componen t can be screened successfully at a distance—except if the hydrocarbon cannot be detected during the calibration test. The practical effect of this test is that facil ities with great distances between the feasible inspection point and the component may be at a disadvantage to those facilities with smaller distances for implementing remote sensing inspections if the great er distance is sufficiently large to prevent leak detection by the instrume nt. The AWP has provisions that can reduce this potential adva ntage/disadvantage scenario. The AWP reinforces the idea that monitoring ha s two components, 1) detection to determine mass flow rates that can be imaged, and 2) survey frequency. More frequent surveys could result in more opportuni ties to identify ne w occurrences of fugitives. Less frequent surveys could re sult in fewer opportunities to identify new occurring fugitives. Therefore, if a remote sensing instrument cannot

detect emissions at a certai n flow rate because of a large distance, there is the potential to increase the monitoring fr equency and then m onitor for a smaller size leak more frequently.

2) Field of View. Another performance factor for remote sensing instruments that specifically affects monitoring of inaccessible co mponents is the field of view. Either the background behind a co mponent or any obstructions to view in front of the component can prohibit successful monitoring. The background is important for active remote sensing instruments that operate by generating a signal and then detecting emissions base d on the reflected signal strength to determine if a hydrocarbon ga s is within the signal path. These

active instruments theref ore require a suitable reflective background for any component being monitored. Facilitie s with inaccessible components already situated with such backgrounds may have a monitoring advantage with active

112instruments over facilities with elevated components and no such backgrounds. For a voluntary effort to detect, measure, and repair methane leaks, one natural gas transmission ope rator has affixed metal plates behind elevated open-ended lines (a minima l facility modification) to allow inspection from the ground with activ e remote sensing instruments.

For the passive type of remote sensing instruments, background is a contrast issue to ensure that a gas plume can be detected by the instrument operator. A wall, vessel, or collection of piping of ten provides the necessary contrast. Inspecting the component against the sky may result in the ability to detect larger leaks. For this reason, the calibration test required by the AWP could be more prescriptive in matching the background requirements to the conditions to be encountered during monitoring to ensure consistent monitoring practices from facility to facility.

Obstructions between the remote sensing instrument and the component will prevent leak inspection. For some components this may be remedied by inspecting the elevated component from a different vantage point, but for other components the obstru ction of view may preven t an operator from using remote sensing for that component. Ot her components such as flanges on top of large vertical vessels may not offer a clear field of view for remote sensing, requiring a lift or other equipment to achieve a suitable viewing location for remote sensing. Applicability of re mote sensing for inaccessible component inspection can therefore vary from facility to facility depending on the field of

view.

Use of an optical imaging instrument is also a field of view issue, and specific issues to consider are viewing for a sufficient length of time and ambient lighting conditions. Use of a camera by quickly panning through a large number of components is not sufficient to identify leak s or attribut e leaks to a specific component. Sin ce optical imaging instruments depend on the

ambient IR radiation or IR radiation produced by indoor lighting, monitoring may not be possible during the night or without a light source, and the video image produced by a camera can be bla nk or difficult to interpret. The Method 21 AWP language appears to cove r reasonable use of an IR camera by requiring video recordings and wi th instruments use specifications.

The AWP requires that video recordings of monitoring be kept and that the video must clearly show the regulated components, which can help determine

reasonable camera use.

40 CFR 60 Subpart A [60.18(h)(3)] (vi) Recordkeeping requirements in the applicable subpart. A video

record must be used to document the leak survey results. The video record must include a time and date stamp for each monitoring event. A video record can be used to meet the recordkeeping

113requirements of the applicable subparts if each piece of regulated equipment selected for this work practice can be identified in the video record. The video record must be kept for 5 years.

The AWP also specifies that the instrument must give the operator a clear view of each component, though the AWP does not otherwise specific a sufficient length of viewing time.

40 CFR 63 Subpart A [60.18(i)] (1) Instrument Specifications. The optical gas imaging instrument must comply with the require ments specified in paragraphs (e)(1)(i) and (e)(1)(ii) of this section. (i) Provide the operator with an im age of the potential leak points for each piece of equipment at bot h the detection sensitivity level

and within the distance used in the daily instrument check described in paragraph (e)(2) of this section.

3) Wind Speed. Wind speed also affects applicability of remote sensing devices to inspecting inaccessible components. Increased wind speed will disperse a leak plume more quickly and make a leak more difficult to detect. Sustained wind speeds further decrease detection ability since intermittent wind allows leaks to accumulate before being di spersed by wind. Components at ground level or that are otherwise accessible may be shielded from components that are elevated above surrounding buildings or equipment. Remote sensing instruments may still be applicable in cases where components are subject to higher wind speeds, but this applicabil ity may be incorporated into a more prescriptive calibration test for the instrument. Given the inaccessible nature of the elevated components, it may be difficult to ascertain or measure the wind conditions at the component, though measuring wind speed or conducting the calibration test in an open, nearby area may be a reasonable surrogate for wind conditi ons at the component.

4) Subjectivity of Individual Instrument Technicians. Some remote sensing devices display a numerical value or audible alarm upon detection of fugitive emissions, while others display a video re presentation of the field of view and rely on the instrument t echnician to make the determination for if a component is leaking. The visual inte rpretation and judgment of an individual therefore introduces some subjectivity into monitoring elevated components with remote sensing. This subjectivity is an issue at the minimum detection level rather than for large leaks wh ich are obvious due to plume size and motion of the plume. Subjectivity is also minimized with an AWP calibration test ensuring the technician can iden tify a specified minimum flow rate. A disadvantage of this calibration test is th at in the test an individual would be viewing a specific component at a large distance to discern the presence of a leak, however, discerning leaks in th e field amongst many components in the same frame of reference could be challeng ing. As a result, the individual may

114be able to discern a very small leak during the calibration test but not discern as small a leak during the actual survey. Though this subjectivity affects comprehensiveness of leak detection for elevated/inaccessible components, this is primarily a performance standard issue. If however, the survey was

conducted in the same manner as Me thod 21 specifies for portable VOC monitoring devices, surveying each co mponent individually, the subjectivity

can be minimized.

ii. Non-optical detection applicability – Leak detection instruments that require close proximity or contact with components (s uch as electronic screening, flame ionization detectors, toxic vapor analyzers, and organic vapor analyzers) are applicable to components that are inaccessible if resources are spent to gain access. Methods to gain access include: 1) temporary use of a portable ladder, 2) wearing harnesses or other applicable fall protection equipment to comply with safety regulations, 3) temporary use of a bucket truck or other lift, 4) facility modification to either create access to the component or relocate the component to an accessible area 5) use of a self contained breathing apparatus, and 6) excavation of buried components.

A comprehensive leak survey coveri ng all inaccessible components therefore would require additional la bor costs and potentially ad ditional capital or lease costs for specialized equipment.

Hot-wire anemometers may be a niche solution for some inaccessible OELs. These quantification instruments operate by inserting a probe into a hole bored into a vent stack. Using such a device for leak inspections could eliminate the need for lifts to reach the top of some OELs.

iii. Measurement applicability – all measurem ent instruments appropriate for a leak

detection and measurement re porting rule requir e contact with or close proximity to the leaking component.

1) High Volume Samplers capture a l eak for measurement using a hose, requiring the hose to be in contact with or within several inches of the component. The instrument can typically be mounted on a backpack for use when standing on a ladder or other positions where the technician has limited mobility or requires the use of hands and arms for balance and for directing the leak into the instrument using the hose attachments.

2) The enclosure method involves c onstructing a tent around a leaking component, passing a known volume of inert gas through the tent, and collecting the flow out to determine mass emissions. This method is timeconsuming, requiring about 30 minute s per enclosure and requiring ample

115access to the area surrounding the component to construct the enclosure. Inaccessible components such as elevated OELs are not suitable candidates for the enclosure method given that no other components are typically near the OEL which can support the enclosure. This method is time-consuming on the ground and will encounter construction difficulties when in an elevated, inaccessible position, and for these reasons it is unlikely that the enclosure method is practical for a large-scale monitoring program or applicable to inaccessible elevated components.

3) The calibrated bag method uses a bag ofa known volume constructed of antistatic materials plus a stopwatch to measure emissions. This measurement method involved some technique and traini ng so that a technician places the bag over a leak source to capture all of the flow, ensures the bag unfurls correctly, and ensure that full inflation is achieved rather than bursting the bag or under-inflating it. The technique just described means that a technician requires both hands and arms to be free for the measurement rather than in use holding onto a ladder or railing. Calibrated bags are a measurement method applicable to inaccessibly high components, but additional resources such as a lift may be necessary.

4) Correlation equations to estimate mass emissions based on parts per million readings taken from gas detectors ar e also applicable to an elevated component again but may require extra co sts to gain access to that component.

5) Turbine meters and rotameters are applicable to OELs and require access to

and direct contact with the end of the stack.

6) Hot wire anemometers operate by insert ing a probe into a hole bored into a vent stack. Using such a device for leak inspections could eliminate the need for lifts to reach the top of some OELs but are not su itable for other types of component leaks.

Emission factors or other cal culation methods to quan tify emissions volumes can

limit or overcome the need to access com ponents but sacrifice reporting accuracy.

C. Evaluation Criteria and Approach Because each industry facility is constructed differently, each facility contains a different number of occurrences of these issues, result ing in different facility cost burdens. The exhibits below are examples of best case, lo w cost scenarios and a worst case, high cost scenarios as regards cost burdens. A key message for each accessibility issue is that remote sensing instruments requir e a higher initial capital cost.

i. Elevated Components: Components may be installe d out of reach above ground level, above walkways, or beyond fixed platforms for a number of reasons. Pressure relief valves on large separators or other equipment divert the flow from overpressure situations in a safe manner which can warrant high elevations away

116from the walkways, ladders, and other access points. Similarly, open-ended lines may be elevated for safe venting. Pipe racks in larger facilities that may contain streams with a methane component may also be elevated beyond reach given the clearances needed for heavy maintenance vehicles. Stacks within buildings are typically routed beyond the roof which ma y be difficult to access since the stacks themselves require little maintenance and th erefore do not need to be accessible..

The existing VOC LDAR rule states that pumps, valves, and connectors that cannot be monitored due to safety reasons are to be omitted from the survey work, meaning that a comprehensive report may not include those components. Those components deemed unsafe-to-monitor requi re an explanation as to why and a plan for future monitoring. Therefore, the inspection of some elevated components using the techniques that requi re close proximity such as portable

VOC detection devices are excl uded from the survey.

Exhibit G-1: Survey and measurement of inaccessibly elevated components

ii. Slanted Roofs: Emission sources may on roofs which are often not physically accessible. Vent stacks in particular ar e designed for safe venting and typically lead to rooftops away from personnel acce ss points. A vent stack outlet above the roofline requires no routine maintenance, so access may not have been a facility design concern. The type of roof therefore affects accessibility of components on or above the roofline. Accessibility issues include:

• whether the roof is flat or slanted;

• whether the roof is acce ssible by a fixed ladder, by a portable ladder, by fixed stairs, or by portable lifts;

117• whether the roof can safely support the weight of a survey/measurement technician; and

• component proximity to the edge of the roof which may require additional fall protection measures. These factors will vary for each buildi ng and for each facility, meaning that slanted roofs and other roof accessibility issues will be more burdensome to some

facilities and less bur densome to others.

Exhibit G-2: Survey and me asurement of slanted roofs

iii. Confined Spaces: Confined spaces require added sa fety measures such as use of a self contained breathing apparatus, so inclusion of com ponents in confined spaces requires additional measures to access them.

118Exhibit G-3: Survey and measurement of confined spaces

iv. Buried Components: The typical buried component is piping, ranging from small diameter flow lines to large diamet er transmission lines. Fugitive emissions from such buried components can be detected by various means ranging from spotting dead vegetation above the lines to traversing the lines with various types of methane detection instruments. Quantification is more closely tied to the accessibility issue with buried component s. Quantification may be possible without excavating the leaking component, and such quantificat ion would require encasing the surrounding area with a tarp to capture all the methane flux from the ground and also accounting for the soil oxidizing rate. This method does not provide assurance that the entire magn itude is quantified since some of the methane may travel along the buried pipe corridor before moving towards the surface or may otherwise be dispersed over a larger ground area than the surface immediately above the component.

Excavation is another quantification option, and it is labor intensive and has safety issues. Excavation of a line still in se rvice around a leak is a safety issue, especially for high pressure lines. Excavation of the soil supporting the line may also risk a blowout. Quantification of an excavated line that is still in service poses additional safety and measurement issues such as approaching the leak source and routing all emissions into the measurement instrument. Lines can be

taken out of service for safe excav ation (and replacement), though this complicates the ability to quan tify accurately the leak rate.

119Exhibit G-4: Survey and measurement of buried components

v. Limited Accessibility Because of Safety: High flow rate fugitives or fugitives with high velocity or high pressure drop can be a safety issue. For example, compressor unit valves, when closed, isolate the compressor from the high pressure main line, and leaks across this valve can be large in magnitude and high in velocity. Another example is compresso r or pump seal oil degassing vents that carry methane which has entrained oil mist or other liquids whic h may not be safe to approach for quantification or me asurement without breathing protection.

120Exhibit G-5: Survey and measurement of no or limited accessibility due to safety

vi. Scheduling Shutdowns, Startups, or Maintenance to Not Interfere with

Measurement: Fugitive emission can vary depe nding on operating mode, and the availability of each operating mode fo r leak inspection a nd quantification is another accessibility issue. Compressors have a number of operating modes and

best illustrate this accessibi lity issue. Some operators have compressors with high operating factors which limits the leak inspection and quantif ication of those compressors in the standby or shutdown mode. Conversely, compressors with a standby or peak loading role will ha ve limited availability in the running operating mode for leak in spection and quantification.

vii. Internal Leaks through Open-Ended Lines: OELs can be manifolded into a single stack that leads to the atmosphere . A common example of this is valves around a compressor: two unit valves isolate the compre ssor from the main line,

and a blowdown valve allows the volum e of the compressor between the unit valves to be depressurized. All three of these valves typically lead to a single stack, and attributing leaks to a specific valve to target for quantification (or repair) can be difficult. In the case of the three compressor valves, a compressor can be cycled through different operating modes to isolate leak rate of the

121blowdown valve and leak rate of the two un it valves, but attributing leak rates to

individual unit valves is difficult. If multiple compressors are connected to the

same vent stack then it is difficult to identify the leak with a particular compressor. Hence, though a cumulative emissions reporting is possible in such cases, determining the number of l eaking valves may not be possible.

A single fugitive emissions source can also reach the atmosphere through more than one path. An example of this is fugitives from pig trap valve which may reach the atmosphere either through the ve nt atop a pig trap or through the gasket on the pig trap hatch: both paths to the atmosphere must be measured and totaled to estimate the entire leak rate from the pig trap.

D. Data Sources for Research Resources related to component accessibility are listed below.

• Clean Air Act

o 40 CFR 60 Appendices: EPA Method 21

o 40 CFR 60 Subpart KKK: Standards of Performance of Performance for Equipment Leaks of VOC from Ons hore Natural Gas Processing Plants.

o AWP in 40 CFR General Provisions

• OSHA Standards

o The need to carry flammable gas dete ctor (OSHA requires that the employer must provide personal protective e quipment (PPE) for employees in a dangerous environment. If it is determined that a flammable gas detector is necessary PPE, then one mu st be provided and used.) 1910.132 - General requirements.

o The need to be aware of surroundings and watch where you walking (Requires employer to develop safe work pract ices and train employees on them) 1910.119 - Process safety management of highly hazardous chemicals.

o Fall protection 1926.502 - Fall protection systems criteria and practices

o Confined spaces 1910.146 Confined Spaces - Amended Final Rule (1998)

• Industry published standard operating procedures

o API Leak Detection Standards API publis hes many of these; each costs about
$150.

E. Summary

• If the inaccessibility prov isions for monitoring under th e VOC LDAR regulation also apply to this reporting rule, the reporting rule ma y be able to require optical leak detection for components that are inaccessible, but may not be able to require direct

emission measurement.

• The enclosure method requires that a tech nician must first gain access to the component and remain in the inaccessible location for a relatively long period of time relative to other quantific ation methods to perform the measurement.

• For vented methane emissions, significant em issions sources are often routed through OELs which are inaccessible, and exclusion of these OELs in particular would affect

122the comprehensiveness of a facility’s em issions reporting. Buried components are also potentially large fugitive emissions sources.

• Remote sensing requires a) a capital inve stment by operators who lack suitable instruments already and b) rule language that ensures cons istent and reasonable use of

the instrument to detect methane leaks successfully. Met hod 21 monitoring of inaccessible components requires a capital investment by operators to obtain accessibility equipment such as lifts to ga in physical proximity to each inaccessible component. Estimated cost impacts for eith er type of monitori ng have been provided

in the exhibits above for various types of inaccessible components.

123

### Appendix H: Review and a ssessment of potential alternatives to monitoring

methods for emissions sources

Pneumatic Pumps

This appendix provides a brief overview of sel ected key comments (not all) representing initial thoughts to show why changes in the proposed s upplemental rule were made. These are not meant to show every comment on an is sue, or a response on every issue. First, it summarizes the comment(s) and then it summari zes research on pump curves, in this case, from pump vendors and how it can be used to estimate emissions from pumps.

Comments A commenter proposes an alternate engine ering emissions estimation methodology that employs the ideal gas law, differe nt from direct measurement of emissions or using data from pump manufacturers and emission factors. The data required for this estimation methodology is provided by manufacturers in the form of “pump curves”.

The volume of natural gas emissions from a pneumatic pump is a function of the amount of liquid pumped (displacement volume), the liquid outlet pressure from the pump, the gas pressure and temperature used as the pneumatic power gas, and the “mechanical efficiency loss” across the pump. In manufacturers’ information, this relationship is typically described using a set of “pump curves.” It can be described mathematically as follows: 37

Gas volume = [{(outlet pressure from the pump psig) + (atmospheric pressure psia)}/14.7 psia] * (atmospheric temperature R/(460 R + gas temperature F ) * (volume of liquid pumped in cubic feet) * (1+pump inefficiency)

Volume of liquid: Measured volume or calculated volume: (gals/ stroke of pump/7.48 gal/scf * number of strokes/min)

Pump inefficiency: Expressed as a fractional decimal (e.g. 0.30) provided by the manufact urer or an assumed default of 30% mechanical efficiency loss

The gas temperature and pressure is assumed to be at atmospheric conditions in the equation above. To estimate the GHG emissions from the above equations:

CO 2 = (Volume of gas above) * (CO 2 content of pneumatic power gas)

CH 4 = (Volume of gas above) * (CH 4 content of pneumatic power gas)

Comments

37 The use of “fugitive” in quoted text from the initial proposed rule implies both fugitive and vented emissions

as defined in this document.

124A commenter recommends using emission factor s for pneumatic pumps provided in the API Compendium where emissions from pneumatic pumps are considered to be a small

contributor to total facility emissions.

Exhibit H-1 provides emission fa ctors from API Compendium 2004

Exhibit H-1: Emission factor for pneumatic pump seals.

Component – Service a Emission Factor

original units b

(lb gas/day/component) Emission Factor

converted to

(tonne gas/hr/component)

Pump Seals – gas 0.609 1.15E-05

The engineering estimation method proposed by th e first commenter is also supported by the

second commenter.

Measurement Methods A commenter lists the following methods as potential emissions measurement methods:

• Direct measurement of gas consumption rate by pneumatic pump type using gas flow meters, and the measured or estimated CH 4 content of gas.

• Measured gas consumption rates by pneuma tic pump type from vendor data, and the

measured or estimated CH 4 content of gas.

• Emissions factor by pneumatic pump type (p iston, diaphragm or average), and the

measured or estimated CH 4 content of gas.

• Vented CH 4 emissions from pneumatic pumps are estimated using the bleed rates of gas from the pumps, and the methane fracti on of the vented gas, according to the following equation:

2200 **** 3.379 1

4 4

4 bleed annual CH

CH QtfCH MW scf molelb

E −

=

where,

E CH4 = total pneumatic pump CH 4 venting emissions for a basin or region [tonne/yr] Q bleed = bleed rate of gas from a pneumatic pump [scf/hr]

MW CH4 = molecular weight of methane (16 lb/lb-mole) [lb/lb-mole] f

CH 4 = molar fraction of methane in the gas

t annual = annual usage of the pneumatic devices [hr/yr]

Manufacturer’s Pump Curves: Pneumatic pump manufacturer Kimray was c ontacted regarding their manufacturer “pump curves”. Kimray provides pump curves for all it s pneumatic pumps. Pump curves graphically represent the relationship between gas pump spee d strokes per minute and gallons per hour of liquid pumped. Manufacturers also provide tabl es indicating the gas consumption or usage

125per gallon of liquid pumped at different operating pressures. This information can be used to estimate emissions from pneumatic pumps. Sample Kimray pump curve and gas consumption tables can be found at Kimray’s website. 38

Summary Measurement of natural gas fugitive emissions either by direct measurement or using data provided by the pump manufacturer, along with a ppropriate emission factors may be used to estimate total emissions. The application of pump curves provided by manufacturers also seems feasible and a potentially cost-effectiv e method to estimate emissions from pumps. If pump curves are not provided by the manufact urer, then the pump curves for pumps with similar operational capacity and manufacturer ca n be used for emissions estimation.



### Acid Gas Removal (AGR) Vents

This appendix provides a brief overview of sel ected key comments (not all) representing initial thoughts to show why changes in the proposed s upplemental rule were made. These are not meant to show every comment on an is sue, or a response on every issue. First, it summarizes the comments, and th en it provides quantification methods opted or reported by Natural Gas STAR partners, the API Compe ndium, and the EPA National GHG Inventory.

Comments A commenter proposes the use of the following methods to estimate emissions from AGR

vents:

• Mass balance

• Emission factor

Comments Another commenter proposes the use of mass balance methods to estimate emissions from AGR vents. In cases where acid gas flow and composition are measured, this commenter

recommends mass balance and in other cas es proposes the following equation:

)**21*(* 4 4 2 2 CH CH CO CO ag ag y yQE ρ ρ + =

where,

E ag

= Mass of acid gas removed (tonnes CO 2 e) Q ag = Volume of acid gas (1000 m 3 )

y CO2 = Mole fraction of CO 2 in the acid gas

y CH4 = Mole fraction CH 4 in the acid gas

ρ CO2 = Density of CO 2 (1.87 kg/m 3 )

ρ CH4 = Density of CH 4 (0.717 kg/m 3 ) 21 = Global warming potential for CH 4

38 Kimray. Available online at: <www.kimray.com.cn/pdf/G_10.17.pdf>

126API Compendium Measurement Method

The AP I compendium lists the following methods to estimate methane emissions from amine

ed on the methane composition in the u nits:

• API’s AMINECalc is a software that provi des a mass emission rate for VOCs that can

be converted into methane emission rates bas gas. Details on this software are available at: engineers.ihs.com/documen t/abstract/CKFJDBAAAAAAAAAA

• For uncontrolled AGR units, two CH 4 emission factors for AGR vents were developed as part of the 1996 GRI/EPA CH 4 emissions study (Volume 14, page A13) based on process simulation results for typical unit operati ons of a diet

39 hanol amine (DEA) unit (Myers, 1996). The fact ors are listed in Exhibit H-2 below :

Exhibit H-2: Process Simulation Re sults for a Diethanol Amine Unit

Metha actor ne Emission F Me r thane Emission Facto Un certainty Source original units converted to tonnes (+/- %)

AGR vent 965 scf/10 6 scf treated gas 0

0.654 tonnes/10 6 m 3 treated gas 119 .0185 tonnes/10 6 scf treated gas

6,083 scfd/AGR unit 0.1167 tonnes/day-AGR unit 126

EPA National GHG Inventory: The U.S. GHG Inventory employs a mass balan ce approach to estimate methane emission

from AGRs. The CO 2 content acceptable in natural gas transmission pipelines varies from 1% to 3% depending on the pipeline co mpany. The national average of CO 2 content in pipeline gas is 1%. As a result, natural gas processing companies are most likely aware of their outgoing natural gas CO 2 composition. If the CO 2 composition of the incoming natural gas can be identified, then esti mation of em issions from AGR units is feasible using simple

nd cost effective mass balance approach.

other approach is using mulation software packages to estimate emissions CO 2 emissions.

s they are very small and would be difficult to assess via the mass balance pproach. a

Summary If processing plants know the composition of their incoming and outgoing gas, the mass balance approach is reasonable for estimating CO 2 emissions. An

si

The mass balance approach may not be reliable for methane emissions since feed gas and residue gas methane content are two very larg e numbers while the amo unt of methane going up the AGR vent is a very small number. For this source, methane losses may not be

estimated a

a

39 API Compendium 2004, Appendix B-Additional Calculation Approaches, Page B-39.

127

## Glycol Dehydrator

This appendix summarizes the input parameters to GTI’s GLYCalcTM software and how it is typically used. Below are 1) key GLYCalcTM inputs, 2) precedents for mandated use of GLYCalcTM specifically, and 3) a Summa ry of a quantific ation method.

Required GLYCalcTM inputs include:

Volume percent of the following components in the gas at the dehydrator inlet:

CO2

H2S

N2

C1 C2

C3

C4s

C5s n-C6

other C6

C7s 2,2,4 Trimethylpentane Benzene

Toluene Xylenes

C8+.

Other required information:

o Is gas saturated (y/n)

o Lean glycol

recirculation ratio

o Type of stripping gas (dry/wet)

o Stripping gas flow rate

o Is gas saturated (y/n)

o Lean glycol

recirculation ratio o Type of stripping gas (dry/wet)

o Stripping gas flow

rate

o Dry gas dewpoint

o Lean glycol

concentration (%)

o Flash tank

temperature and

pressure

o Throughput o Operating hours per year

o Glycol pump type

o What controls are on the

reboiler vent and flash gas vent? (i.e. is it vented, routed to fuel gas, etc).

Precedents for GLYCalcTM use

EPA AP-42 is the set of air emissions rate quantification methods for various pollutants (VOC, BTEX, HAPs). AP-42 gives GLYCalcTM as the only option for gl ycol dehydrators in gas processing 40 . The section on natural gas proce ssing discusses gl ycol dehydration indicating that glycol dehydrator emissions are important from an air emissions standpoint and recommends using GLYCalcTM.

MMS GOADS also uses GLYCalcTM to estimate all air emissions from glycol dehydrators 41

.

State guidance documents for permitting show that GLYCalcTM is also specified by name and required for estimating air emissions rates. At least one state has specif ied an alternative if the operator does not wi sh to use GLYCALCTM 42 . The alternative is a mass balance calculation which requires taking samples of th e rich glycol and th e lean glycol and

40 EPA. AP-42 . Section 5.3. January 1995. <www.e pa.gov/ttn/chief/ap42/ch05/index.html>

41 Mineral Management Service (MMS). Gulfwide Emission Inventory Study for the Regional Haze and Ozone Modeling Effort. October 2004. MMS 2004-072. pg. 5-17 <www.gomr.mms.gov/PI/PDFImages/ESPIS/2/3010.pdf >

42 Oklahoma Department of Environmental Quality. Fact Sheet: Title V Oil & Gas Facilities. February 6, 1997. pg. 7 <www.deq.state.ok.us/f actsheets/air/o&gfctst.pdf>

128calculating the difference for each pollutant species. This me thod is also applicable for

methane and carbon dioxide.

Summary Given that GLYCalcTM is ubiquito us in industry and in regulator y entities both at the national and the state levels, GLYCalcTM could be used in the mandatory reporting rule: it is an industry standard and is not a co st burden at $140.00 per license 43 . Allowing for alternative estimation methods, either competing models, calculations, or measurement methods, would require additional resources for an EPA validatio n program since not all alternatives may be as rigorous or correct. Use of the same or similar inputs as GLYC alcTM does not guarantee

an accurate emissions rate result as shown by the following two examples.

1. The well-known 1996 EPA-GRI study in volume 14 44 developed glycol dehydrator process simulations using ASPEN/SP ® software that had relevant inputs as the basis for its results; however, the results have since been proven to have the unrealistic assumption of holding the glycol circulation rate constant for different runs. As a result, the results were developed assuming that reboiler stack methane emissions rate corresponds to the inlet gas flow rate (stack emissions actually correspond to glycol circulation rate). Though this study is an authority on methane emissions, and ASPEN is an established process simu lator, the applied methodology for this particular source has become outdated as understanding of methane emissions has increased. This is an example of how a pplication of different models for dehydrator emissions may cause inconsistent results from reporting entity to reporting entity and one advantage of stipulating a st andardized software package.

2. The 1996 EPA-GRI study also uses process si mulation to estimate methane emissions from amine units which operate similar to glycol dehydrators in that they have a contactor and regenerator. The study used a process simulator, ASPEN PLUS TM , to model methane emissions by using 100 percent water as the solvent as a surrogate for aqueous amine solutions 45 . This may or may not be a valid assumption when using a process simulator for an individual unit, depending on the desired accuracy, and would require further resources to assess how this assumption compares to actual emission rates for specific units. Similar i ssues would arise for assessing assumptions when allowing other process simulation methods for glycol dehydrator methane

emissions.

Thus other glycol dehydrator emission modeli ng approaches are available but are primarily

found in literature before GLYCalcTM became the norm and their use alongside GLYCalcTM may result in non-standard results across reporting entities.

43 GTI. GRI-GLYCalc. Version 4.0. [CD-ROM]. GRI-00/0102. <www.gastechnology.org/webroot/app/xn/xd.aspx?it=enweb&xd=10abstractpage\12352.xml>

44 GRI. Methane Emissions from the Natural Gas Industry . Volume 14. June 1996. <www.epa.gov/gasstar/documents/emissions_report/14_glycol.pdf>

45 GRI. Methane Emissions from the Natural Gas Industry . Volume 6. June 1996. <www.epa.gov/gasstar/documents/emissions_report/6_vented.pdf>

129

### Appendix I: 

## Flares

This appendix provides results of additiona l research and general consensus on flare reporting that was conducted to support development of the supplemental proposed rulemaking.

No data source was found that comprehensively reports data on vented and flared emissions from the production and processing sector of th e oil and gas industry. The EIA does collect information from states on a voluntary basis. However, this data is not complete and moreover does not distinguish flare data from vent data.

In 2004, the U.S. Government Accountability Office raised concerns on the lack of

information on vented and flared data. EIA responded to this, but did not propose any concrete steps to collect accurate information. In summary, EIA proposed to rely on states, the Bureau of Land Management (BLM), and the Mineral Management Services to report, as best as possible, data on vented and flared emissions. In addition, EIA noted that BLM

estimated the cost of meter vents and fl ares to be around $32 million in 2004 dollars. 46

Flares in general can be categorized into two main types; continuous and intermittent. Continuous flares combust casing head gas, asso ciated gas, well testin g gas, and gas from equipment that generate a continuous waste gas stream (such as glycol dehydrators, storage tanks, and pneumatic devices). Intermittent flares combust releases that are not continuous in nature such as streams from equipment/ vessel / site blowdowns and pressure relief valves.

The emissions from continuous flares can be monitored using predominantly two techniques that are practical for the rule; (1) measurements using either a conti nuous flow meter or one time measurement meters, and (2) engineering me thods. If most of the equipment emissions going to a flare get included in the rule, only associated gas and casing head gas flaring will

have to be accounted for in this rule.

Intermittent flare emissions can be measured only using continuous flow meters or engineering estimation methods. The volume of intermittent emi ssions is lower in magnitude in comparison to continuous emissions. Hence us ing continuous flow meters could be cost prohibitive for the purposes of the Rule.

Summary Considering the various options and the magnitude of emissions from each type of flare (continuous and intermittent), the following monitoring options could be adopted for the Rule;

Onshore and Offshore Production 1) Continuous flaring: All major continuous e quipment vents are covered in the initial rule proposal as individual sources. The only three major co ntinuous sources not

46 GAO. Natural Gas Flaring and Venting: Opportunities to Improve Data and Reduce Emissions. July 14,

2004. GAO-04-809. <www.gao.gov/products/GAO-04-809>

130covered are casing head gas, associated gas, and well testing gas. Engineering

estimation methods can be used for these so urces. Companies can easily measure the gas-to-oil ratio for each of the sources and estimate emissions using calculation

methods. 2) Intermittent flaring: All equipment sending gas to the flare on an intermittent basis

are covered as individual s ources in the proposed rule.

Onshore Processing There are potentially many sources that send thei r gas to a flare and are not covered in the proposed rule. For example, molecular sieves se nd gas to the flare intermittently and are not covered in the Rule. In addition, gas plants may send pure hydrocarbon products such as propane and butane to a flare when equipment s huts down (they may prefer to keep the plant running and losing some product as opposed to shutting down the plant). However, the possibility of using continuous meters on flares in processing plants can be cost prohibitive. One option is to provide fo r calculative methods based on the volume of pure hydrocarbons sent to flares during a disruption.

131

### Appendix J: Development of multipliers to scale emissions or miscellaneous sources connected to storage tanks

This method of quantifying tank emissions as sumes that thermodynamically based models such as E&P Tank can accurately predict the effect of flashing emissions from hydrocarbons in fixed roof storage; but are unable to pred ict or account for emissions from vortexing or dump valves. Either direct measurement or a correction factor is required to represent the total emissions from hydrocarbon storage tanks.

This appendix compares two methods of co rrecting E&P Tank (GEO-RVP) data to account for non-flashing emission effects on tanks. Actual measurement data from a Texas Commission on Environmental Quality (TCEQ) report 47 were compared to E&P Tank (GEO-RVP) data runs on the same tanks to develop a correction factor which can be applied to E&P Tank (GEO-RVP) results in which addi tional non-flashing emissions or vortexing are

detected.

Selected Data All data considered were presented in a TCEQ-funded report that compared tank emission predicting equations, charts, and models to actu al measured data. Data from the E&P Tank 2.0 GEO-RVP setting were compared against to direct measurement results. The TCEQ study focused on comparing the various methods of predicting VOC portion of emissions; however, for the purposes of this analysis, the total gas-oil ratios were compared.

Where direct measurement results were w ithin ±100% of E&P Ta nk (GEO-RVP) results, those tanks were assumed to be exhibiting typical flashing emissions only. Direct measurement results greater or less than ±100% of E&P Tank (GEO-RVP ) results were used to develop a correction factor for no n-flashing effects on tank emissions.

The data were separated into two regimes:

• Hydrocarbon liquids with API gravities less than 45  ̊ API were considered “oil”

• Hydrocarbon liquids with AP I gravities greater than 45  ̊ API were considered

“condensate”

Correction factors were de veloped for both ranges.

Method 1 – Least Squares Analys is of Emission Difference The first method sorts qualifying tanks in ascen ding order of emission rates estimated by the E&P Tank (GEO-RVP) runs. The difference be tween the measured emission rate and E&P Tank (GEO-RVP) emission rates was plotted against the E&P Tank (GEO-RVP) emission rates and a trend line was fitted to the equa tion, as shown in Exhibits J-1 and J-2.

Exhibit J-1. Oil Tank Correction Factors

47 Texas Commission on Environmental Quality (TCEQ). Upstream Oil and Gas Storage Tank Project Flash

Emissions Models Evaluation . July 16, 2009.

132y = -1.5592x + 139.23

R 2 = 0.0719

(100) - 100 200 300 400 500

10 20 30 40 50 60 70 80 90 100 E&P Tank Estimate (scf/bbl)[Measurement] - [E&P Tank estimates](scf/bbl)

Measurement - E&P Tank Linear (Measurement - E&P Tank) Oil Tanks (  ̊ API<45)

Exhibit J-2. Condensate Tank Correction Factors

y = -0.6673x + 248.34

R 2 = 0.0045

- 100 200 300 400 500 600

20 30 40 50 60 70 80 E&P Tank Estimate (scf/bbl)[Measurement] - [E&P Tank estimates](scf/bbl)

Measurement - E&P Tank Linear (Measurement - E&P Tank) Condensate Tanks (  ̊ API>45)

The equation for the line of best fit can be used on E&P Tank (GEO-RVP) results where non-flashing emission affects are de tected to estimate the true ta nk emissions. The data used to derive this relationship range fr om oil gravities from 29.1 to 44.8  ̊ API and separator pressures from 15 to 70 psig; and for condensate gravities from 45.3 to 82.2  ̊ API and separator pressures from 30 to 231 psig.

The E&P Tank (GEO-RVP) emission estimates can be corrected with the following equations:

• For oil: CE = (-0.5592 × EE) + 139.23

• For condensate: CE = (0.3327 × EE) + 248.34 Where “EE” is the E&P Tank (GEO-RVP) emi ssion estimate and “CE” is the corrected

emission estimate.

As demonstrated in Exhibits J-1 and J-2, the correlations for the correction factor are very weak, with R 2 values of 0.0719 for oil and 0.0045 for condensate.

133Method 2 – Average Emissions Ratio Analysis This method takes the simple average of the ra tio of qualifying measured emission rates to simulated emission rates gene rated by E&P Tank (GEO-RVP) for the oil and condensate

ranges.

Using this method, E&P Tank (GEO-RVP) emi ssion estimates can be corrected with the following equations:

• For oil: CE = 3.87 × EE

• For condensate: CE = 5.37 × EE Where “EE” is the E&P Tank (GEO-RVP) emi ssion estimate and “CE” is the corrected

emission estimate.

Summary Predicting and evaluating non-fl ashing effects on emissions (such as dump valves or vortexing) has not yet been t horoughly studied or quantified. The methods above have significant weaknesses as:

1. The sample data set is limited

2. Only weak correlations were observed for the available data.

Method 1 naturally suggests that very low estim ates are underestimating the tank emissions and very high estimates (over 89 scf/bbl for o il) are overestimating the emissions. This will

tend to “even out” estimates so that none are extremely high or extrem ely low. It also suggests that if E&P Tank (GEO-RVP) estimates 0 scf/bbl flashing emissions, the emission rates are actually higher than if E&P Tank (G EO-RVP) estimates large (near 89 scf/bbl for oil) emission rates.

Method 2 does not “even out” emission rates, and assumes that in all cases where nonflashing effects are present, each case is uniformly underestimated.

134

### Appendix K: Development of Leaker Emission Factors

Natural Gas Emission Factors for Onshore Production

Leaker Emission Factors – All Co mponents, Light Crude Service

Methodology Average emission factors by facility type are taken from API’s Emission Factors for Oil and Gas Production Operations 48 . (A discussion on how this API study was conducted is provided in Appendix P.) Hydrocarbon liquids greater than or equal to 20°API are considered “light crude.” The methane content of associated natural gas with onshore light

crude is 61.3% is taken from the same API publication, Table ES-4, page ES-3.

Component EF, scf/hour/component = ((Component EF, lb/day THC) * ( A )) / (( B ) * ( C ))

Component Name Component EF, scf/hour/comp Component EF, lb/day THC

Valve 2.03 3.381

Connector 0.90 1.497
Open-Ended Line 0.96 1.6 Pump 2.35 3.905

Other 2.31 3.846

EF: Emission Factor THC: Total Hydrocarbons Conversions:

A: 0.613 – CH 4 content of onshore light crude associated natural gas

B: 0.04246 CH 4 density lb/scf

C: 24 hours/day

Leaker Emission Factors – All Components, Heavy Crude Service

Methodology Average emission factors by facili ty type are taken from API’s Emission Factors for Oil and Gas Production Operations 48

. (A discussion on how this API study was conducted is provided in Appendix P.) Hydr ocarbon liquids less than 20°API are considered “heavy

crude.” The methane content of associated na tural gas with onshore heavy crude is 94.2% taken from the same API publication, Table ES-4, page ES-3.

Component EF, scf/hour/component = ((Component EF, lb/day THC) * ( D )) / (( B ) * ( C ))

Component Name Component EF, scf/hour/component Component EF, lb/day THC

Valve 3.13 3.381
Flange 4.15 4.49

48 API. Emission Factors for Oil and Gas Production Operations . Table 10, page 16. API Publication Number 4615. January 1995.

135Connector (other) 1.38 1.497
Open-Ended Line 1.48 1.6

Other 3.56 3.846

EF: Emission Factor THC: Total Hydrocarbons Conversions:

B: 0.04246 CH 4 density lb/scf

C: 24 hours/day

D: 0.942 – CH 4 content of onshore heavy crude associated natural gas



### Total Hydrocarbon Emission Factors for Processing

Leaker Emissions Factors – Reciprocating Compressor Components, Centrifugal Compressor Components, and Ot her Components, Gas Service

Methodology

The leaker emissions factors ar e from Clearstone Engineering’s Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas Processing Plants 49 and

Clearstone’s Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing Plants and Upstream Gath ering Compressor Stations and Well Sites 50

. (A discussion on how these studies were conducted is provided in Appendix P.) The components were categorized in to three groups: reci procating compressor related, centrifugal compressor related and all other components. Furthermore, the components related to reciprocating and centrifugal compressor were se gregated into components before and after the de-methanizer. Once categorized, the sum of the leak rates from components known to be leaking was divided by the sum of number of leaking components.

Component EF, scf/hour/component = (Leak rate

, Mscf/day/component) * ( E ) / ( C )

Reciprocating Compressor Component, (scf/hour/comp) Centrifugal Compressor Component, (scf/hour/comp) Component

Name Before DeMethanizer After DeMethanizer Before DeMethanizer After DeMethanizer Other Components, (scf/hour/comp)

Valve 15.88 18.09 0.67 2.51 6.42

Connector 4.31 9.10 2.33 3.14 5.71
Open-Ended

Line 17.90 10.29 17.90 16.17 11.27

Pressure

Relief Valve 2.01 30.46

- - 2.01

Meter 0.02 48.29

- - 2.93

49 EPA

. Identification and Evaluation of Opportunities to Reduce Methane Losses at Four Gas Processing

Plants . Clearstone Engineering Ltd. June 20, 2002. <www.epa.gov/gasstar/documents/four_plants.pdf>

50 National Gas Machinery Laboratory, Kansas State Un iversity; Clearstone Engineering, Ltd; Innovative Environmental Solutions, Inc. Cost-Effective Directed Inspection and Maintenance Control Opportunities at Five Gas Processing Plants and Upstream Ga thering Compressor Stations and Well Sites . For EPA Natural Gas STAR Program. March 2006.

136

### Total Hydrocarbon Emission Factors for Transmission

Leaker Emission Factors – All Components, Gas Service

Methodology Gas transmission facility emissions are drawn from the Handbook for Estimating Methane Emissions from Canadian Natural Gas Systems 51 and the Measurement of Natural Gas Emissions from the Canadian Natural Ga s Transmission and Distribution Industry 52

. . (A

discussion on how these studies were conducte d is provided in Appendix P.) All compressor related components were separated from the raw data and categorized into the component types. Once categorized, the sum of the leak rates from components known to be leaking was divided by the sum of number of leaking components.

Component EF, scf/hour/component = (Gas Transmission Facility Emissions, kg/h/src) * ( F ) / ( B )

Component Name Component EF, (scf/hour/comp)

Connector 2.7

Block Valve 10.4

Control Valve 3.4 Compressor Blowdown Valve 543.5

Pressure Relief Valve 37.2

Orifice Meter 14.3

Other Meter 0.1 Regulator 9.8
Open-Ended Line 21.5

Conversions:

B: 0.04246 CH 4 density lb/scf

F: 2.20462262 lb/kg

51 Clearstone. Handbook for Estimating Methane Emissions from Canadian Natural Gas Systems . Clearstone Engineering Ltd., Enerco Engineering Ltd, and Radian International. May 25, 1998.

52 Clearstone. Measurement of Natural Gas Emissions from the Canadian Natural Gas Transmission and Distribution Industry . Clearstone Engineering Ltd., Canadian Energy Partnership for Environmental Innovation (CEPEI). April 16, 2007.

137

### Methane Emission Factors for LNG Storage

Leaker Emission Factors – LNG Storage Components, LNG Service

Methodology The light liquid emission factors with leak concentrations grea ter than or equal to 10,000 ppmv were taken from Protocol for Equipment Leak Emission Estimates 53 . The emissions

are assumed to be 100% methane

.

Component EF, scf/hour/component = (Light Li quid >= 10,000 ppmv Emission Factor) * ( F ) / ( B )

Component Name Component EF, scf/hour/comp † Light Liquid EF, kg/hr THC

Valve 1.19 2.30E-02

Pump Seal 4.00 7.70E-02

Connector 0.34 6.50E-03

Other 1.77 3.40E-02

† Greater or equal to 10,000 ppmv Conversions:

B: 0.04246 CH 4 density lb/scf

F: 2.20462262 lb/kg



### Methane Emission Factors for LNG Terminals

Leaker Emission Factors – LNG T erminals Components, LNG Service

Methodology See methodology for Leaker Emission Factors – LNG Storage Components, LNG Service for LNG Storage 53

.



### Methane Emission Factors for Distribution

Leaker Emission Factors – Above Grade M&R Stations Components, Gas Service

Methodology Gas distribution meter/regulator st ation emissions are drawn from: Handbook for Estimating Methane Emissions from C anadian Natural Gas Systems 51 and Measurement of Natural Gas Emissions from the Canadian Natural Ga s Transmission and Distribution Industry 52 . (A

discussion on how these studies were conducted is provided in Appendix P.)

53 EPA. Protocol for Equipment Leak Emission Estimates . Emission Standards Division. U.S. EPA. SOCMI

Table 2-7. November 1995.

138Component EF, scf/hour/component = (Gas Dist ribution Meter/Regulator Station Emissions, kg/h/src) * ( F ) / ( B )

Component Name Component EF, scf/hour/comp Gas Distribution Meter/Regulator Station Emissions, kg/h/src

Connector 0.67 0.01292

Block Valve 1.49 0.02872

Control Valve 3.94 0.07581

Pressure Relief Valve 5.24 0.1009

Orifice Meter 0.46 0.0088

Other Meter 0.01 0.0002064
Regulator 2.14 0.04129 Open-Ended Line 6.01 0.1158

Conversions:

B: 0.04246 CH 4 density lb/scf

F: 2.20462262 lb/kg

Leaker Emission Factors – Distribution Mains and Services, Gas Service

Methodology Emission factors for pipeline leaks (mains and services) are drawn from GRI’s Methane Emissions from the Natural Gas Industry 54

.

Component EF, scf/hour/leak = (Pip eline Leak, scf/leak-year) / ( G )

Component Name Component EF (Mains),

scf/hour/leak Pipeline Leak EF (Mains), scf/leak-yr Component EF, (Services)

scf/hour/leak Pipeline Leak EF (Services), scf/leak-yr
Unprotected Steel 6.02 52748 2.33 20433

Protected Steel 2.38 20891 1.08 9438

Plastic 11.63 101897 0.35 3026

Copper 0.88 7684

Conversions: G: 8,760 hours/year

N ATURAL G AS E MISSION F ACTORS FOR O NSHORE P RODUCTION

Onshore production Emission Factor (scf/hour/component)

Leaker Emission Factors - All Components, Gas Service

54 GRI. Methane Emissions from the Natural Gas Industry . Volume 9. Tables 8-9 and 9-4. June 1996. <www.epa.gov/gasstar/documents/emissions_report/9_underground.pdf>

139Valve NA

Connector NA Open-ended Line NA

Pressure Relief Valve NA

Low-Bleed Pneumatic Device Vents NA
Gathering Pipelines NA

CBM Well Water Production NA Compressor Starter Gas Vent NA
Conventional Gas Well Completion NA

Conventional Gas Well Workover NA
Leaker Emission Factors - All Components, Light Crude Service 1

Valve 2.03

Connector 0.90 Open-ended Line 0.96 Pump 2.35

Other 2.31
Leaker Emission Factors - All Components, Heavy Crude Service 2

Valve 3.13 Flange 4.15 Connector (other) 1.38 Open-ended Line 1.48

Other 3.56

1 Hydrocarbon liquids greater than or equal to 20  ̊ API are considered "light crude"

2 Hydrocarbon liquids less than 20  ̊ API are considered "heavy crude"

TOTAL H YDROCARBON E MISSION F ACTORS FOR P ROCESSING

Processing 1 Before De-Methanizer

Emission Factor (scf/hour/component) After De-Methanizer

Emission Factor (scf/hour/component)

Leaker Emission Factors - Reciprocating Compressor Components, Gas Service

Valve 15.88 18.09

Connector 4.31 9.10 Open-ended Line 17.90 10.29

Pressure Relief Valve 2.01 30.46

Meter 0.02 48.29 Leaker Emission Factors - Centrifugal Compressor Components, Gas Service

Valve 0.67 2.51

Connector 2.33 3.14 Open-ended Line 17.90 16.17
Leaker Emission Factors - Other Components, Gas Service 2

Valve 6.42

Connector 5.71 Open-ended Line 11.27

Pressure Relief Valve 2.01

Meter 2.93 Population Emission Factors - Other Components, Gas
Service

140Gathering Pipelines 3 2.81

METHANE E MISSION F ACTORS FOR T RANSMISSION

Transmission Emission Factor (scf/hour/component)

Leaker Emission Factors - All Components, Gas Service

Connector 2.7

Block Valve 10.4

Control Valve 3.4 Compressor Blowdown Valve 543.5

Pressure Relief Valve 37.2

Orifice Meter 14.3

Other Meter 0.1 Regulator 9.8 Open-ended Line 21.5 Leaker Emission Factors - Other Components, Gas Service

Low-Bleed Pneumatic Device Vents NA
Gathering Pipelines 1 NA

1 Emission Factor is in units of "scf/hour/mile"

M ETHANE E MISSION F ACTORS FOR U NDERGROUND S TORAGE

Underground Storage Emission Fa ctor (scf/hour/component)

Leaker Emission Factors - Stor age Station, Gas Service

Connector 0.96

Block Valve 2.02

Control Valve 3.94 Compressor Blowdown Valve 66.15

Pressure Relief Valve 19.80

Orifice Meter 0.46

Other Meter 0.01 Regulator 1.03 Open-ended Line 6.01 Leaker Emission Factors - Storage Wellheads, Gas Service

Connector NA

Valve NA

Pressure Relief Valve NA Open-ended Line NA Leaker Emission Factors - Other Components, Gas Service

Low-Bleed Pneumatic Device Vents NA

M ETHANE E MISSION F ACTORS FOR LNG S TORAGE

LNG Storage Emission Factor (scf/hour/component)
Leaker Emission Factors - LNG Storage Components, LNG Service

141Valve 1.19 Pump Seal 4.00

Connector 0.34

Other 1.77 Leaker Emission Factors - LNG Storage Compressor, Gas Service Vapor Recovery Compressor NA

M ETHANE E MISSION F ACTORS FOR LNG T ERMINALS

LNG Terminals Emission Factor (scf/hour/component)

Leaker Emission Factors - LNG Terminals Components, LNG Service

Valve 1.19 Pump Seal 4.00

Connector 0.34

Other 1.77 Leaker Emission Factors - LNG Terminals Compressor, Gas Service Vapor Recovery Compressor NA

M ETHANE E MISSION F ACTORS FOR D ISTRIBUTION

Distribution Emission Factor (scf/hour/component)

Leaker Emission Factors - Above Grade M&R Stations Components, Gas Service

Connector 1.69

Block Valve 0.557

Control Valve 9.34

Pressure Relief Valve 0.270

Orifice Meter 0.212 Regulator 26.131 Open-ended Line 1.69
Leaker Emission Factors - Below Grade M&R Stations Components, Gas Service Below Grade M&R Station, Inlet Pressure > 300 psig NA Below Grade M&R Station, Inlet Pressure 100 to 300 psig NA Below Grade M&R Station, Inlet Pressure < 100 psig NA Leaker Emission Factors - Gathering Pipelines, Gas Service

Gathering Pipelines NA

Leaker Emission Factors - Distribution Mains, Gas Service 1

Unprotected Steel 6.02

Protected Steel 2.38

Plastic 11.63

Cast Iron NA

Leaker Emission Factors - Distri bution Services, Gas Service 1

Unprotected Steel 2.33

Protected Steel 1.08

Plastic 0.35 Copper 0.88

1 Emission Factor is in units of "scf/hour/leak"

142Summary This Appendix provides leaker emissions fact ors that can be applied to any individual

emissions source which meets the leak detection definition in a leak de tection survey. These emissions factors provide an estimate of real emissions as opposed to potential emissions since they are applied only to leaking emissions sources. However, it must be noted that

these leaker emissions factors assume that any emissions source found leaking has been leaking for the duration of an entire year.

143

### Appendix L: Development of Population emission factors

Natural Gas Emission Factors for Onshore Production

Population Emission Factors – All Components, Gas Service

Methodology

The well counts and emission factors were taken from GRI’s Methane Emissions from the Natural Gas Industry 55

. The emission factors for each source are calculated using gas production for the Eastern and Western United States. The average methane content of produced natural gas is assumed to be 78.8%.

Component EF, scf/hour/component = (EF All U.S., mscf/yr) / ( A ) * ( B ) / ( C )

EF All U.S. Valve, mscf/yr = ((Eastern U.S. Gas Production Count) * (Eastern U.S. Gas Production EF, mscf/yr) + (Western U.S. Gas Production Count) * (Western U.S. Gas Production EF, mscf/yr)) / (Tot al U.S. Gas Production Count)

Component

Name Component EF, scf/hr/comp Eastern U.S. Component

Count Eastern U.S. Component EF, Mcf/yr Western U.S. Component

Count Western U.S. Component EF, Mcf/yr U.S. Component

Count

Valve 0.08 4,200 0.184 6,059 0.835 10,259

Connector 0.01 18,639 0.024 32,513 0.114 51,152 Open-Ended

Line 0.04 260 0.42 1,051 0.215 1,311

Pressure Relief

Valve 0.17 92 0.279 448 1,332 540

Conversions:

A: 78.8% – production quality of natural gas (% methane) from: “Vented and Combustion Source Summary,” Methane Emissions from the Natural Gas Industry, U.S. EPA, Volume 6, Appendix A, page A-2. B: 1,000 scf/mscf C: 8,760 hours/year

“Low-Bleed Pneumatic Device Vents” Methodology Methane emissions per pneumatic devise are from EPA’s Inventory of U.S. Greenhouse Gas

Emissions and Sinks: 1990-2007 56 , The average methane content of natural gas is assumed

to be 78.8%.

2.75 scf/hour/component EF = ( 52 [scfd CH 4 /pneumatic devises, low bleed]) / ( A ) / ( D )

Conversions:

55 GRI. Methane Emissions from the Natural Gas Industry . Volume 8. Tables 4-3, 4-6 and 4-24. June 1996. <www.epa.gov/gasstar/documents/emissions_report/8_equipmentleaks.pdf>

56 EPA. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2007 . Annexes. Tables A-112 – A-125. U.S. EPA. April 2009. <epa.gov/climatechange/emissions/downloads09/Annexes.pdf>

144A: 78.8% – production quality of natural gas (% methane) from: “Vented and Combustion Source Summary,” Methane Emissions from the Natural Gas Industry, U.S. EPA, Volume 6, Appendix A, page A-2.

D: 24 hours/day

“Gathering Pipelines” Methodology Emissions and mileage of underground production pipelines are from GRI’s Methane Emissions from the Natural Gas Industry 54 . The average methane content of produced natural gas is assumed to be 78.8%.

2.81 scf/hour/mile EF = ( E ) / ( A ) / ( D )

Conversions:

A: 78.8% – production quality of natural gas (% methane) from: “Vented and Combustion Source Summary,” Methane Emissions from the Natural Gas Industry, U.S. EPA, Volume 6, Appendix A, page A-2.

D: 24 hours/day

E: 53.151651325 scfd/mile EF = ( 6.6 Bscf [Total Emissions Estimates from Underground Production Pipelines]) * ( 1,000,000,000 cf/bcf) / ( 365 days/year) / (( 268,082 miles [Protected Steel Gathering Pipelines]) + ( 41,400 miles [Unprotected Steel Gathering Pipelines]) + ( 29,862 miles [Plastic Gathering Pipelines]) + ( 856 miles [Cast Iron Gathering Pipelines]))

“CBM Well Water Production” Methodology Gg/gallon of water is from EPA’s Inventory of U.S. Greenhouse Gas Emissions and Sinks:

1990-2007 56 . To calculate Gg/gallon water, 542.9 mg /l is assumed as the concentration of methane in the water, at a well depth of 700ft.

0.11 scf methane/gallon EF = ( 51,922,341.5 [CH 4 density, scf/Gg]) * ( 2.05216E-09 Gg/gallon water)

2.05216E-09 Gg/gallon water EF = ( 542.9 mg/l) / ( 1,000 mg/g) * ( 3.78 l/gallon) * (gallons of water drainage/yr) / ( 1,000,000,000 g/Gg)

“Compressor Starter Gas Vent” Methodology Annual emission factors for comp ressor starts are from GRI’s Methane Emissions from the Natural Gas Industry 57 . The average methane content of natural gas is assumed to be

78.8%.

1.22 scf/hour/component EF = ( 8,443 [Annual Emission Factor for Compressor Starts]) / ( A ) / ( C )

Conversions:

A: 78.8% – production quality of natural gas (% methane) from, “Vented and

57 GRI. Methane Emissions from the Natural Gas Industry . Volume 6. Table 4-2 and Appendix A, page A-2. June 1996. <www.epa.gov/gasstar/documents/emissions_report/6_vented.pdf>

145Combustion Source Summary,” Methane Emissions from the Natural Gas Industry, Volume 6, Appendix A, page A-2. C: 8,760 hours/year

Flare Methodology Emissions and flaring efficiency are from GRI’s Methane Emissions from the Natural Gas Industry 58 . GRI assumed all gas is flared, that the dur ation is one day per completion, that the gas is 78.8% CH 4 , and the flare is 98% efficient. Re sults are adjusted to assume that no conventional gas well completions are flared.

Conventional Gas Well Completion: 46,510 scf/completion EF = ( 0.733 scf/completion) / ( 0.02 [% Methane not Burned]) * ( B ) / ( A )

Conventional Gas Well Workover: 3,114 scf/workover EF = ( 2.454 mscf methane/workover) * ( B ) / ( A )

Conversions:

A: 78.8% – production quality of natural gas (% methane) from: “Vented and Combustion Source Summary.” Methane Emissions from the Natural Gas Industry 57

.. B: 1,000 scf/mscf

Population Emission Factors – All Components, Light Crude Service

Methodology Average emissions factors by facility type were taken from API’s Emission Factors for Oil

and Gas Production Operations. 59 (A discussion on how this study was conducted is provided in Appendix P.) Hydrocarbon liqui ds greater than or equal to 20°API are considered “light crude.” The methane conten t of associated natural gas with onshore light crude is 61.3% from the same study.

Component EF, scf/hour/component = (Average Emissions Factors by Facility Type, lb/component-day) / ( D ) / ( F ) * ( G )

Component Name Component EF, scf/hr/comp Average EF by Facility Type, lb/component-day

Valve 0.04 7.00E-02

Connector 0.01 8.66E-03
Open-Ended Line 0.04 6.38E-02
Pump 0.01 1.68E-02

Other 0.24 3.97E-01

58 GRI. Methane Emissions from the Natural Gas Industry . Volume 7, page B-9. June 1996. <www.epa.gov/gasstar/documents/emissions_report/7_blowandpurge.pdf >

59 API. Emission Factors for Oil and Gas Production Operations . Table 9, page 10. API Publication Number 4615. January 1995.

146Conversions:

D: 24 hours/day

F: 0.04246 CH 4 density lb/scf

G: 0.613 – CH 4 content of onshore light crude associated natural gas

Population Emission Factors – All Components, Heavy Crude Service

Methodology Average emissions factors by facility type were taken from API’s Emission Factors for Oil and Gas Production Operations 59 . (A discussion on how th is study was conducted is provided in Appendix P.) Hydrocarbon liqui ds less than 20°API are considered “heavy

crude.” The methane content of associated na tural gas with onshore light crude is 94.2% from the same study.

Component EF, scf/hour/component = (Average Emi ssions Factors by Facility Type, lb/component-day) / ( D ) / ( F ) * ( H )

Component Name Component EF, scf/hr/comp Average EF by Facility Type, lb/component-day

Valve 0.001 6.86E-04

Flange 0.001 1.16E-03
Connector (Other) 0.0004 4.22E-04
Open-Ended Line 0.01 8.18E-03

Other 0.003 3.70E-03

Conversions:

D: 24 hours/day

F: 0.04246 CH 4 density lb/scf

H: 0.942 – CH 4 content of onshore heavy crude associated natural gas



### Methane Emission Factors For Processing

Population Emission Factors – Other Components, Gas Service

“Gathering Pipelines” Methodology Emissions and mileage of underground production pipelines from GRI’s Methane Emissions from the Natural Gas Industry 54 . The average methane content of produced natural gas is

assumed to be 78.8%.

2.81 scf/hour/mile EF = ( E ) / ( A ) / ( D )

Conversions:

A: 78.8% – production quality of natural gas (% methane) from: “Vented and Combustion Source Summary.” Methane Emissions from the Natural Gas Industry 57

. D: 24 hours/day

147E: 53.151651325 scfd/mile EF = ( 6.6 Bscf [Total Emissions Estimates from Underground Production Pipelines]) * ( 1,000,000,000 cf/bcf) / ( 365 days/year) / (( 268,082 miles [Protected Steel Gathering Pipelines]) + ( 41,400 miles [Unprotected Steel Gathering Pipelines]) + ( 29,862 miles [Plastic Gathering Pipelines]) + ( 856 miles [Cast Iron Gathering Pipelines]))



### Methane Emission Factors for Transmission

Population Emission Factors – All Components, Gas Service

Methodology Gas transmission facility emission factors were taken from the Handbook for Estimating Methane Emissions from C anadian Natural Gas Systems 51 . (A discussion on how this study was conducted is provided in Appendix P. ) “Connector” includes flanges, threaded connections, and mechanical couplings. “Block Valve” accounts for emissions from the stem packing and the valve body, and it applies to all types of block valves (e.g., butterfly, ball, globe, gate, needle, orbit, and plug valves). Le akage past the valve seat is accounted for the Open-Ended Line emission category. Leakag e from the end connections is accounted for by the connector category (i.e., one connector for each end). “Control Valve” accounts for leakage from the stem packing and the valve body. Emissions from the controller and actuator are accounted for by the Instrument Controller and Open-Ended Line categories respectively. This factor applies to all valv es with automatic actuators (including fuel gas injection valves on the drivers of reciprocat ing compressors). “Orifice Meter” accounts for emissions from the orifice changer. Emissions from sources on pressure tap lines etc. are not included in the factor (i.e., these emissions must be calculated separately). “Other Meter” accounts for emissions from other types of gas flow meters (e.g., diaphragm, ultrasonic, roots, turbine, and vortex meters).

Component EF, scf/hour/component = (Gas Transmission Facility Emissions, kg/h/src) * ( I ) / ( F )

Component Name Component EF, scf/hour/comp Gas Transmission Facility Avg. Emissions, kg/hr/src

Connector 0.01 2.732E-04

Block Valve 0.11 2.140E-03

Control Valve 1.02 1.969E-02

Pressure Relief Valve 14.51 2.795E-01

Orifice Meter 0.17 3.333E-03

Other Meter 0.0005 9.060E-06 Regulator 0.17 3.304E-03
Open-Ended Line 4.34 8.355E-02

Conversions:

F: 0.04246 CH 4 density lb/scf

I: 2.20462262 lb/kg

148Population Emission Factors – Other Components, Gas Service

“Low-Bleed Pneumatic Device Vents” Methodology Methane emissions per pneumatic device are from EPA’s Inventory of U.S. Greenhouse Gas

Emissions and Sinks: 1990-2007

. 56 The average methane content of produced natural gas is assumed to be 78.8%. Pipeline quality natural gas is assumed to be 93.4% methane.

2.57 scf/hour/component EF = ( 52 [scfd CH4/pneumatic devises, low bleed]) / ( A ) / ( D ) * ( J )

Conversions:

A: 78.8% – production quality of natural gas (% methane) from: “Vented and Combustion Source Summary.” 57

D: 24 hours/day

J: 93.4% – pipeline quality of natural gas (% methane) from: “Vented and Combustion Source Summary.” 57

“Gathering Pipelines” Methodology Emissions and mileage of undergr ound production pipelines from GRI’s Methane Emissions from the Natural Gas Industry 54 . The average methane content of produced natural gas is assumed to be 78.8%. Pipeline quality natural gas is assumed to be 93.4% methane.

2.62 scf/hour/mile EF = ( E ) / ( A ) / ( D ) * ( J )

Conversions:

A: 78.8% – production quality of natural gas (% methane) from: “Vented and Combustion Source Summary.” 57

D: 24 hours/day

E: 53.151651325 scfd/mile EF = ( 6.6 Bscf [Total Emissions Estimates from Underground Production Pipelines]) * ( 1,000,000,000 cf/bcf) / ( 365 days/year) / (( 268,082 miles [Protected Steel Gathering Pipelines]) + ( 41,400 miles [Unprotected Steel Gathering Pipelines]) + ( 29,862 miles [Plastic Gathering Pipelines]) + ( 856 miles [Cast Iron Gathering Pipelines]))

J: 93.4% – pipeline quality of natural gas (% methane) from: “Vented and Combustion Source Summary.” Methane Emissions from the Natural Gas Industry 57

.

149

### Methane Emission Factor s for Underground Storage

Population Emission Factors – St orage Station, Gas Service

Methodology See methodology for “Population Emission Fact ors – All Components, Gas Service” for

Transmission.

Population Emission Factors – Storage Wellheads, Gas Service

Methodology Emission factors for injection/withdrawal wellheads are from GRI’s Methane Emissions from the Natural Gas Industry 55

.

Component EF, scf/hour/component = (In jection/Withdrawal Wellhead) * ( B ) / ( C )

Component Name Component EF, scf/hr/comp Injections/Withdrawal Wellhead, Mcf/yr

Connector 0.01 0.125

Valve 0.10 0.918

Pressure Relief Valve 0.17 1.464
Open-Ended Line 0.03 0.237

Conversions:

B: 1,000 scf/mscf C: 8,760 hours/year

Population Emission Factors – Other Components, Gas Service

Methodology

See “Low-Bleed Pneumatic Device Vents” Methodology for Population Emission Factors – Other Components, Gas Service for Transmission.



### Methane Emission Factors for LNG Storage

Population Emission Factors – LNG Storage Components, LNG Service

Methodology Component emission factors are from GRI’s Methane Emissions from the Natural Gas Industry 55 . The emission factors were adjusted by an assumed average methane content of 93.4% by volume.

Component EF, scf/hour/component = (Component EF, Mscf/comp-yr) * ( I ) / ( F )

150Component Name Component EF, scf/hour/comp Component EF, Mscf/comp-yr

Valve 0.10 0.867

Open-ended Line 1.28 11.2

Connector 0.02 0.147

PRV 0.71 6.2
Conversions:

F: 0.04246 CH 4 density lb/scf

I: 2.20462262 lb/kg

Population Emission Factors – LNG Storage Compressor, Gas Service

“Vapor Recovery Compressor” Methodology The methane emissions per compressor are from the Inventory of U.S. Greenhouse Gas

Emissions and Sinks: 1990-2007 56 . The methane content of associated natural gas with onshore light crude is 61.3%. 60

6.81 scf/hour/component EF = ( 100 scfd CH 4 /compressor) / ( D ) / ( G )

Conversions:

D: 24 hours/day

G: 0.613 – CH 4 content of onshore light crude associated natural gas



### Methane Emission Factors for LNG Terminals

Population Emission Factors – LNG Terminals Components, LNG Service

Methodology See methodology for Population Emission Fa ctors – LNG Storage Components, LNG Service for LNG Storage.

Population Emission Factors – LNG Terminals Compressor, Gas Service

Methodology See “Vapor Recovery Compressor” Methodology for Population Emission Factors – LNG Storage Compressor, Gas Service for LNG Storage.

60 API. Emission Factors for Oil and Gas Production Operations . API Publication Number 4615. page ES-3, Table ES-4, January 1995.

151

### Methane Emission Factors for Distribution

Population Emission Factors – Above Grad e M&R Stations Components, Gas Service

Methodology Gas distribution meter/regulator station average emissions from: Gas transmission facility

emissions are from the Handbook for Estimating Methane Em issions from Canadian Natural Gas Systems 51 . (A discussion on how this study was conducted is provided in Appendix P.) “Connector” includes flanges, threaded connect ions, and mechanical couplings. “Block Valve” accounts for emissions from the stem pack ing and the valve body, and it applies to all types of block valves (e.g., butterfly, ball, gl obe, gate, needle, orbit, and plug valves). Leakage past the valve seat is accounted fo r the Open-Ended Line emission category. Leakage from the end connections is accounted for by the connector category (i.e., one connector for each end). “Control Valve” acco unts for leakage from the stem packing and the valve body. Emissions from the contro ller and actuator are accounted for by the Instrument Controller and Open-Ended Line cate gories respectively. This factor applies to all valves with automatic actuators (including fuel gas injection valves on the drivers of reciprocating compressors). “Orifice Mete r” accounts for emissions from the orifice changer. Emissions from sources on pressure tap lines etc. are not included in the factor (i.e.,

these emissions must be calcula ted separately). “Other Mete r” accounts for emissions from other types of gas flow meters (e .g., diaphragm, ultrasonic, roots, turbine, and vortex meters).

Component EF, scf/hour/component = (Gas Dist ribution Meter/Regulator Station Emissions, kg/h/src) * ( I ) / ( F )

Component Name Component EF, scf/hour/comp Gas Distribution Meter/Regulator Station Avg. Emissions, kg/h/src

Connector 5.70E-03 1.098E-04

Block Valve 5.76E-02 1.109E-03

Control Valve 1.02E+00 1.969E-02

Pressure Relief Valve 8.65E-01 1.665E-02

Orifice Meter 1.73E-01 3.333E-03

Other Meter 4.71E-04 9.060E-06
Regulator 9.94E-02 1.915E-03 Open-Ended Line 4.33E+00 8.355E-02

Conversions:

F: 0.04246 CH 4 density lb/scf

I: 2.20462262 lb/kg

Population Emission Factors – Below Grade M&R Stations Components, Gas Service

Methodology

152Average emission factors are from GRI’s Metering and Pressure Regulating Stations in

Natural Gas Transmission and Distribution 61

.

Below Grade M&R Station, In let Pressure > 300 psig: 1.30 scf/hour/station EF

Below Grade M&R Station, Inle t Pressure 100 to 300 psig: 0.20 scf/hour/station EF

Below Grade M&R Station, In let Pressure < 100 psig: 0.10 scf/hour/station EF

Population Emission Factors – Gathering Pipeline, Gas Service

Methodology See “Gathering Pipelines” Methodology fo r Population Emissions Factors – Other Components, Gas Service for Transmission.

Population Emission Factors – Distribut ion Mains and Services, Gas Service

Methodology Emission factors for pipeline leak s (mains and service) are from the Inventory of U.S.

Greenhouse Gas Emissions and Sinks: 1990-2007 56

.

Component EF, scf/hour/service = (P ipeline Leak ms cf/mile/year) * ( B ) / ( C )

Component Name Component EF (Mains),

scf/hr/service Pipeline Leak EF (Mains), Mscf/mile-yr Component EF (Services),

scf/hr/service Pipeline Leak EF (Services), Mscf/mile-yr
Unprotected Steel 12.58 110.19 0.19 1.70

Protected Steel 0.35 3.07 0.02 0.18

Plastic 1.13 9.91 0.001 0.01

Cast Iron 27.25 238.7

Copper 0.03 0.25

Conversions:

B: 1,000 scf/mscf C: 8,760 hours/year



### Nitrous Oxide Emission Factors for Gas Flaring

Population Emission Factors – Gas Flaring

Methodology

61 GRI. Methane Emissions from the Natural Gas Industry . Volume 10. Table 7-1. June 1996.

< www.epa.gov/gasstar/documents/emissions_report/10_metering.pdf >.

153Emission factors are from API’s Compendium of Greenhouse Ga s Emissions Methodologies for the Oil and Gas Industry 62

.

Gas Production: 5.90E-07 metric tons/MMcf gas production or receipts EF

Sweet Gas Processing: 7.10E-07 metric tons/MMcf gas production or receipts EF

Sour Gas Processing: 1.50E-06 metric tons/MMcf gas pr oduction or receipts EF

Conventional Oil Production: 1.00E-04 metric tons/barrel conventional oil production EF

Heavy Oil Production: 7.30E-05 metric tons/barrel heavy oil production EF

N ATURAL G AS E MISSION F ACTORS FOR O NSHORE P RODUCTION

Onshore production Emission Factor (scf/hour/component)

Population Emission Factors - All Components, Gas Service

Valve 0.08

Connector 0.01 Open-ended Line 0.04

Pressure Relief Valve 0.17

Low-Bleed Pneumatic Device Vents 2.75
Gathering Pipelines 1 2.81

CBM Well Water Production 2 0.11 Compressor Starter Gas Vent 1.22
Conventional Gas Well Completion 3 46,510

Conventional Gas Well Workover 4 3,114
Population Emission Factors - All Components, Light Crude Service 5

Valve 0.04

Connector 0.01 Open-ended Line 0.04 Pump 0.01

Other 0.24
Population Emission Factors - All Components, Heavy Crude Service 6

Valve 0.001 Flange 0.001 Connector (other) 0.000 Open-ended Line 0.01

Other 0.00

1 Emission Factor is in units of "scf/hour/mile"

2 Emission Factor is in units of "scf methane/gallon", in this case the operating factor is "gallons/year”. Therefore do not multiply by methane content

3 Emission Factor is in units of "scf/completion"

4 Emission Factor is in units of "scf/workover"

5 Hydrocarbon liquids greater than or equal to 20  ̊ API are considered "light crude"

62 API. Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry . American Petroleum Institute. Table 4-7, page 4-30. February 2004.

1546 Hydrocarbon liquids less than 20  ̊ API are considered "heavy crude"

155M ETHANE E MISSION F ACTORS FOR P ROCESSING

Processing Emission Factor (scf/hour/component)

Population Emission Factors - All Eq uipment Components, Gas Service

Valve NA

Connector NA Open-ended Line NA

Pressure Relief Valve NA

Meter NA Population Emission Factors - Centrifugal Compressor Components, Gas Service

Valve NA

Connector NA Open-ended Line NA Dry Seal NA
Population Emission Factors - Ot her Components, Gas Service

Valve NA

Connector NA Open-ended Line NA

Pressure Relief Valve NA

Meter NA
Population Emission Factors - Ot her Components, Gas Service

Gathering Pipelines 1 2.81

1 Emission Factor is in units of "scf/hour/mile"

M ETHANE E MISSION F ACTORS FOR T RANSMISSION

Transmission Emission Factor (scf/hour/component)

Population Emission Factors - All Components, Gas Service

Connector 1.42E-02

Block Valve 1.11E-01

Control Valve 1.02E+00 Compressor Blowdown Valve NA

Pressure Relief Valve 1.45E+01

Orifice Meter 1.73E-01

Other Meter 4.71E-04 Regulator 1.72E-01 Open-ended Line 4.34E+00
Population Emission Factors - Ot her Components, Gas Service

Low-Bleed Pneumatic Device Vents 2.57
Gathering Pipelines 1 2.62

1 Emission Factor is in units of "scf/hour/mile"

156M ETHANE E MISSION F ACTORS FOR U NDERGROUND S TORAGE

Underground Storage Emission Factor (scf/hour/component)

Population Emission Factors - St orage Station, Gas Service

Connector 1.42E-02

Block Valve 1.11E-01

Control Valve 1.02E+00 Compressor Blowdown Valve NA

Pressure Relief Valve 1.45E+01

Orifice Meter 1.73E-01

Other Meter 4.71E-04 Regulator 1.72E-01 Open-ended Line 4.34E+00 Population Emission Factors - Storage Wellheads, Gas Service

Connector 0.01

Valve 0.10

Pressure Relief Valve 0.17 Open-ended Line 0.03
Population Emission Factors - Ot her Components, Gas Service

Low-Bleed Pneumatic Device Vents 2.57

M ETHANE E MISSION F ACTORS FOR LNG S TORAGE

LNG Storage Emission Factor (scf/hour/component)

Population Emission Factors - LNG Storage Components, LNG Service

Valve 0.87 Open-ended Line 11.20

Connector 0.15

PRV 6.20
Population Emission Factors - LNG Storage Compressor, Gas Service Vapor Recovery Compressor 6.81

M ETHANE E MISSION F ACTORS FOR LNG T ERMINALS

LNG Terminals Emission Factor (scf/hour/component)

Population Emission Factors - LNG Te rminals Components, LNG Service

Valve 0.87 Open-ended Line 11.20

Connector 0.15

PRV 6.20 Population Emission Factors - LNG Terminals Compressor, Gas Service Vapor Recovery Compressor 6.81

157M ETHANE E MISSION F ACTORS FOR D ISTRIBUTION

Distribution Emission Factor (scf/hour/component)

Population Emission Factors - Above Grade M&R Stations Components, Gas Service

Connector 5.70E-03

Block Valve 5.76E-02

Control Valve 1.02E+00

Pressure Relief Valve 8.65E-01

Orifice Meter 8.65E-01

Other Meter 4.71E-04 Regulator 1.92E-03 Open-ended Line 4.33E+00

Population Emission Factors - Below Grade M&R Stations Components, Gas Service 1

Below Grade M&R Station, Inlet Pressure > 300 psig 1.30 Below Grade M&R Station, Inlet Pressure 100 to 300 psig 0.20 Below Grade M&R Station, Inlet Pressure < 100 psig 0.10
Population Emission Factors - Ga thering Pipelines, Gas Service
Gathering Pipelines 2 2.62

Population Emission Factors - Di stribution Mains, Gas Service 3

Unprotected Steel 12.58

Protected Steel 0.35

Plastic 1.13

Cast Iron 27.25

Population Emission Factors - Dist ribution Services, Gas Service 3

Unprotected Steel 0.19

Protected Steel 0.02

Plastic 0.001 Copper 0.03

1 Emission Factor is in units of "scf/hour/station"

2 Emission Factor is in units of "scf/hour/mile"

3 Emission Factor is in units of "scf/hour/service"

Summary This Appendix provides population emissions f actors for potential emi ssions sources. These population emissions factors can be used in conjunction with populat ion counts that make it more cost effective in estimating emissions. Howeve r, these population emissions factors estimate potential emissions as the percenta ge of emissions sources leaking may or may not be the same as the assumption made when developing the emissions factors. Also, the population emissions factors assume that a subset of leaking emission sour ces is leaking continuous ly throughout the year.

158159 

### Appendix M: Potential Solutions to Measure Greenhouse Gas Emissions in Various Modes of Equipment Operation

The purpose of this appendix is to analyze the issues involved w ith and potential solutions to estimating emissions in the different modes of operation for equipment at oil and natural gas facilities. The scope includes fugitive and vented methane and carbon dioxide emissions.

1. Evaluation Criteria and Approach

A. Assessment on permutations of operating modes: startup, running, pressurized, shut down and depressurized to in termediate pressure shut down and depressurized to atmospheric pressure, shut down for major maintenance: Equipment will have variable vented and fugitive emissions depending on their modes of operation. The three equipment types discussed are i. compressors, ii. tanks, and iii. other components. The text below discusses how emissions differ and potential approaches for measurem ent and developing an inventory.

i. Compressors – The table below shows each mode of operation in the rows and each emission type in the columns, forming a matrix of which emission types occur in each mode of operation. Diffe rent numbers denote when a different measurement is required, i.e. compressor seals will leak at different rates when pressurized and when depressurized, re quiring separate measurements. For example, under normal operations seals on compressor piston rods have been documented to leak at approximately 75 c ubic feet (scf)/hour. However, when a compressor is idle and fully pressurized (not blown down), this can increase to 300 scf/hour. On the other hand, blowi ng a compressor down emits on average approximately 1,500 scf through the open blowdown valve and the upstream unit valve can leak an additional 1,400 scf/hour. However, when the compressor is left idle pressurized, the 1,400 scf/hour is el iminated from the unit valve and instead approximately 450 scf/hour emissions can leak through the closed blowdown valve. This clearly demonstrates how leak rates from different components can change between different operating modes 63

.

63 EPA. Reducing Emissions when Taking Compressors Off-Line . EPA430-B-04-001. February 2004.Emission Type

Operating Modes Starter

OEL

open Starter

OEL

closed Blowdown OEL open Blowdown

OEL

closed Unit

Valves Seal or Rod Packing

Face OEL Engine

Crankcase (where applicable) Seal Oil Degassing OEL (where applicable) Engine or

Turbine

Exhaust (where applicable) Startup M1 M5 M8 M12 M14 M18 Running (normal operation) M2 M5 M8 M12 M14 M19

Shutdown (left pressurized) M3 M5 M9 M13 M15

Shutdown (blown

down to atmosphere) M3 M4 M7 M10 M13 M16

Shutdown (blown

down to

intermediate pressure) M3 M6 M11 M13 M17

Offline (major maintenance) Emergency/systems testing M4 M13 M16

Emergency venting/shutdown M4 M13 M16

In the chart above, the necessary components to monitor are displayed by the letter “M” and a number. The “M” stands for “monitor” to signify it is necessary, and the numbers differentiate measurements. For example, “M3” refers to starter OEL leaks in any of the shutdown operating modes. The leak rates should be the same for measurements sharing the sa me number; so no duplicate measurement would be necessary. While it is difficu lt to predict which components will have large leaks, cells highlighted in light bl ue signify which com ponents are expected to have potentially large leaks for the m odes. The table below displays a legend for all the necessary components under different condi tions to monitor as derived

from the matrix above.

M1 Starter OEL Vents in Startup Mode

M2 Starter OEL Leaks under Normal Operation

M3 Starter OEL Leaks for All Shutdown Modes

M4 OEL Blowdown Venting for All Modes

M5 OEL Blowdown Vent Leaks for All Pressurized Modes

M6 OEL Blowdown during Shutdown at Intermediate Pressure

M7 Unit Valve Leaks during Shut down Blowdowns to Atmosphere

M8 Wet Seal or Rod Packing Face OEL during Startup and Normal Operation

M9 Wet Seal or Rod Packing Face OEL during Pressurized Shutdown

M10 Wet Seal or Rod Packing Face OEL during Shutdown Blowdown

M11 Wet Seal or Rod Packing Face OEL dur ing Shutdown at Intermediate Pressure

M12 Engine Crankcase (where appl icable) during Normal Operations

M13 Engine Crankcase (where appl icable) during Al l Shutdown modes

M14 Wet Seal Oil Degassing OEL duri ng Startup and Normal Operation

M15 Wet Seal Oil Degassing OEL during a Pressurized Shutdown

Background Technical Support Document – Petroleum and Natural Gas Industry 160M16 Wet Seal Oil Degassing OEL during a Blowdown

M17 Wet Seal Oil Degassing OEL during S hutdown at Intermediate Pressure

M18 Engine or Turbine Exhaust during Startup

M19 Engine or Turbine Exhaust during Normal Operation

The 19 measurements, displayed above, are required to potentia lly cover all the possible compressor operating modes.

ii. Tanks and Vapor Recovery Units (VRUs) – Emissions from storage tanks can potentially be estimated using one of the several options; standard simulation software, one time direct measurement of one cycle of tank operations, or using engineering methods such as Vasquez Be ggs Equation. If no control device is present on the tank, then all tank vapors can be assumed to be vented. If control devices are present, then the “efficiency” of the control device will have to be evaluated by logging different operating mode s. These events are displayed in the table below, where the owner/operator ma y have to use its best judgment to determine the recovery “efficiency” (p ercent of vapors recovered during each mode). By logging these situ ations, the overall efficien cy for the reporting period can be determined. When a vapor rec overy unit is operating properly, tank emissions are nearly zero. However, when a tank is able to vent freely, it has been documented to vent as much as 96 million cubic feet per year of gas 64 . The following table summarizes the situations in which a control device may be recovering vapors and when venting may occur. In some cases, both may be going on simultaneously.

VRU Efficiency Considerations

Control

functions properly Valve or hatch pops

open Significant leak

in tank

structure Large “slug” of

fluids overloads

device Control device

malfunctions Control device

down for

maintenance Emitting gas × × × × × Capturing gas × × × ×

There may be an opportunity to utilize some of the provisions under 40 CFR part 60 regulating petroleum tanks with liquids at a certain vapor pressure, which may require a VRU.

40 CFR part 60, Subpart K

(3) A vapor recovery system which collects all VOC vapors and gases discharged from the storage vessel, and a vapor return or disposal system which is designed to process such VOC vapors and gases so as

to reduce their emission to the atmo sphere by at least 95 percent by weight.

64 EPA. Installing Vapor Recovery Units on Crude Oil Storage Tanks . EPA430-B-03-015. October 2003.

Background Technical Support Document – Petroleum and Natural Gas Industry 161iii. Other components – Most equipment have different operating modes that may affect its magnitude of emissions. Pneumatic actuation instruments will vary depending on whether the instrument is actuating or not. Chemical pumps will emit depending on the current throughput of chemical through the pump. Valves will emit at different rates depending on th eir configurations (e.g. closed, open, half-open). Wellheads may be produci ng to a production line or venting after completion or cleanup.

There may be an opportunity to utilize some of the provisions under 40 CFR part 60 regulating natural gas plan ts, however it may not lead to the “inventory” of emissions that the EPA is seeking.

40 CFR part 60, Subpart KKK Standards of Performance for Equipment Leaks of

VOC from Onshore Natura l Gas Processing Plants.

Equipment includedEquipment means each pump, pressure relief device, openended valve or line, valve, compressor, and flange or other connector that is in VOC service or in wet gas service, and any device or system required by this subpart.

B. Assessment of potential seasonal differences affecting emissions such as operating pressure or throughput: Seasonal changes typically occur in a changeover to winter operati ons but can occur based on an y periodic yearly cycle. During winter months, throughput to end use may increase while throughput to storage may decrease. Remote wells and their facilities may also be shut in during winter. The result of these changes is th at equipment may cycl e between very low and very high operating factors through the y ear and that key operating parameters such as line pressure may vary with each season. Seasonal differences can therefore be tracked with a detailed pr escription of operating modes.

C. Assessment on other operating parame ters that may vary such as gas composition, temperatures, and flow rates: Calculation of methane emissions depends greatly on gas composition (methane content). While downstream pipelines may require that strict composition specifi cations are met, upstream gas compositions can vary widely by well production rates and ages or the bringing of new wells/fields online or taking them offline.

D. Discussion on non-continuous or non- steady emissions and how they may vary depending on different equipment modes of operation: Tanks are an example of non-steady and non-continuous emissions. Th roughput rates and weather both affect

the rate of emissions as well and control acti vity can affect the continuity. However, all the vapor that evolves from the tank conten ts will either be vented or collected by the control device and the monitoring met hods for these have been discussed in

section A. Pneumatic actuation devices and gas-driven pumps may have noncontinuous emissions as actuations occur or fluid is pumped more or less heavily.

Background Technical Support Document – Petroleum and Natural Gas Industry 162E. Potential methods to account for vario us operational modes in emissions monitoring:

i. Compressors – Operators could log time spent in different operating modes. For compressors this may already be automated and recorded, though at remote sites operating hours may have to be determined by alternative means such as fuel consumption. Determining the resulting emissions can be done in several ways: 1) Require that measurements of all operating modes for each reporting period be measured. This may require multiple days of measurement collection for each period if e quipment modes are not cycled frequently. Alternatively, this may require scheduling cycling between all modes in a short time span to accommodate data

collection.

• Advantages: This will provide the most accurate and precise emissions inventory data for each reporting period.

• Disadvantages: This increases the burden on companies to force all modes of operation for a compressor for each reporting period for monitoring purposes. 2) One inspection and measurement survey can be performed per reporting period, but a different ope rating mode can be surveyed in each reporting period to complete collection of emissions from each operating mode.

• Advantages: This will decrease the burden of measurement and reporting on companies. For established and steady operations, the accuracy will likely not deteriorate, i.e. compressor blowdown volumes will remain constant.

• Disadvantages: Initially it may take several reporting periods before the companies have collected enough data to accurately report emissions for compressors when all operating modes are considered. Additionally, by the time emissions data for all modes of operation are collected, the originally measured mode may have changed substantially for facilities with changing process conditions. 3) Only normal operation and the most typical operating modes and parameters can be measured each reporting period, and previously

collected measurements for other operating modes can be collected with less frequency.

• Advantages: EPA receives reli able data for at the most common modes of operation.

• Disadvantages: Burden on companies still increases.

ii. Tanks – Operators may have to track and log time spent in each mode of operation. The logs of these operating times can be provided to a junior engineer, who can perform the appropria te calculation based on the available data. Determining these emissions can be done in several ways:

Background Technical Support Document – Petroleum and Natural Gas Industry 1631) Use simulation software and requi re quarterly co llection of key parameters such as: liquid hydrocarbon gravity and composition, tank vapor composition, tank conditions (temperature and pressure), hydrocarbon liquid condition im mediately upstream of tank (temperature and pressure), av erage liquid hydro carbon throughput.

Perform the emissions simulation fo r each quarter using the collected data and apply the appropriately determined control device operating efficiency (if a control device is present) using data logs.

• Advantages: The most reliable i nventory data ca n be received for every reporting period.

• Disadvantages: The labor and co st burden of performing this level of monitoring may increase for a company depending on its current internal monitoring practices. 2) Use simulation software and require collection of key parameter data (as described above) on ce per reporting period.

• Advantages: The burden of monitoring is diminished on the owner/operator for the reporting period.

• Disadvantages: Less reliable data will be reported and does not capture changes in the process that may occur within a reporting period due to seasona l or operational changes.

iii. Downstream (Transmission and Storag e) Reporting Considerations – As discussed earlier, the increased demand in cooler months affects gas systems such that downstream pipeline throu ghput increases and operating pressures are increased, and that gas is withdrawn from storage. Alternatively, during warm months the pipeline throughput and pressures decrease while gas is injected into storage. Options for accounting for downstream emissions

include: 1) Potentially define warm and cool seasons by fixed months or by average temperature for each month. Entities can then perform monitoring twice annually (once at peak demand, once at low demand for normal operations) to es timate emissions for the warm and cool seasons; then extrapolate the measured/monitored

emissions for the entire season a nd total for the reporting period.

• Advantages: The most accurate emissions data for the represented reporting pe riod can be obtained.

• Disadvantages: Economic and labor burden could be significant, as would be requir ed to monitor more than one time per year. Costs would be further impacted by the method required to monitor emissions. 2) Potentially define warm and cool seasons, as discussed in the previous bullet. Companies can then monitor emissions once per period (year), but alternate measurements for peak demand (cold season) every other reporting peri od, and low demand (warm season) in the remaining seasons. After year 1, it will use the most current

Background Technical Support Document – Petroleum and Natural Gas Industry 164monitoring data for each season to estimate emissions from the reporting period.

• Advantages: Data that represents both seasons can be received.

• Disadvantages: The first reporting will be inaccurate since it will be estimated as if peak demand is reached for the entire period. Subsequent reporting pe riods will continue to have some level of uncertainty because it requires using data from the previous year. 3) Potentially define an intermediate period between the peak demand

and low demand that can be assume d to be representative of the average over the course of the year.

• Advantages: This can be easier for the companies to track and plan for if the same monitoring time can be used each reporting period. It does not increase the burden of monitoring for reporting entities.

• Disadvantages: It will be difficult to determine where the representative operating conditions are achieved.

3. Data Sources for Research

• Clean Air Act

o EPA Method 21

o EPA Method 21 AWP

• Industry published standard operating procedures

o API Leak Detection Standards

o AGA Leak Detection Standards

Background Technical Support Document – Petroleum and Natural Gas Industry 165

### Appendix N: Identifying gas compos itions for emissions estimates

This appendix summarizes the research to identify gas composition sampling needed to quantify CH 4 and CO 2 emissions in estimates of natural gas emissions from direct measurements, engineering calculations, or the use of emissions factors.

Sources that could be affected by gas composition changes

1. The initial proposed rule provi ded leeway on how gas compos ition could be estimated. A facility could estimate gas composition from continuous monitoring equipment, or a couple of samples per year. This could lead to GHG under or over reporting if the regulated entity selects samples that are not representative of the emissions source.

2. The composition of produced gas varies wide ly from well to well, and over time the composition will change for the same well. Th e initial proposed rule language could be interpreted as a composite gas composition that represents all the wells. Again the issue of how the gas composition estimate is derive d is not defined. This will impact GHG reporting for Offshore E&P and for Onshore E&P.

3. The gas composition a processing plant receives will vary over the period of one year for example as wells are taken off-line for mainte nance activities; new well volumes are sent to a gas plant; and as the composition and volumes of exiting wells change over time. Gas processing plants are not always owned and operated by the gas producer. This will result in different feed gas compositions as the gas plant starts and ends contracts for taking gas from different producers.

4. For gas plants the initial proposed rule stat es that only two gas composition estimates are used for the “feed natural gas” upstream of the de-methanizer, and “residue gas”

downstream of the de-methanizer. This can be clarified as “dow nstream of the demethanizer overhead ”.

Summary

To minimize the cost burden and also achie ve a more representative gas composition and therefore more accurate emissions estimation, quarterly samples could be made. In addition the following stream compositions could be us ed for estimating GHG emissions from natural

gas; 1. Gas Processing Facilities: “feed natural gas” can be used for all emissions sources upstream of the de-methanizer

2. Gas Processing Facilities: “residue gas” to transmission pipeline systems can be used

for all related emissions sources downs tream of the de-methanizer overhead

3. Gas Processing Facilities: ga s i) entering and ii) exiti ng the acid gas removal unit

which can be used to calculate the AGR vent emissions and for all emissions of

related sources

4. Offshore and Onshore Petroleum and Natu ral Gas Production: produced natural gas

can be used to estimate GHG emissions from all emissions sources in the facility.

Background Technical Support Document – Petroleum and Natural Gas Industry 166

### Appendix O: Development of performance criteria and monitoring protocol for fugitive measurement techniques

The purpose of this appendix is to outline relevant sources of documentation on fugitive and vented emissions detection and quantification technologies, including av ailable standards of performance, use, and calibration.

1. Issue Identification and Clarification

A. Brief summary of the changes to LDAR under the newly passed AWP

The recently promulgated alternative work prac tice (AWP) allows owners or operators to detect VOC or HAP leaking equipment using an optical gas imaging instrument if it is capable of imaging compounds in the streams th at are regulated by th e applicable rule. The imaging instrument must provide the operator with an image of both the leak and the leak source. Before using the instrument, ow ners and operators are required to determine the mass flow rate that the imaging instrument will be required to image. The mass flow rate can be determined using the method provided in sections (i)(2)(i)(A) and (i)(2)(i)(B) of the AWP. They are required to conduct a da ily instrument check to confirm that the optical gas imaging instrument is able to de tect leaks at the emi ssion rate by using the instrument to view the mass flow rate requ ired to be met exiting a gas cylinder.

The AWP specifies that the imaging instrument is to be used as a direct replacement for other acceptable screening equipment; however, no measurement, record keeping, reporting, or other procedures can be replaced because of this. The company still must use the standard Method 21 screening equipment in one screening period per year. In addition to the record keeping practices alrea dy prescribed in the current work practice, companies must keep video records of the daily instrument check and leak survey results for at least 5 years. The company must document the equipment, process units, and facilities for which the optical gas imaging instrument will be/is used.

The instrument must be used following the ma nufacturer’s instructions, ensuring that all appropriate settings conform to the instructi ons and parameters. All leaks that can be viewed with the instrument are regulated by the rule, so that they have to be fixed.

“Optical gas imaging instrument” means an in strument that makes visible emissions that may otherwise be invisible to the naked eye. The AWP defines leaks as “any emissions imaged by the optical gas instrument; indica tions of liquids drip ping; indications by a sensor that a seal or barrier fluid system ha s failed; or screening re sults using 40 CFR part 60, Appendix A-7, Method 21 monitor that exc eed the leak definition in the applicable subpart to which the equipment is subject.”

B. Existing performance criteria and prot ocols for using fugitive emission detection

devices

Background Technical Support Document – Petroleum and Natural Gas Industry 167This section reviews existing performance criteria and protocols for using fugitive and

emission devices. A discussion of current standards of performance follows.

Method 21 Section 6 defines equipment specifications a nd performance criteria for VOC monitoring

instruments:

6.1 The VOC instrument detector shall respond to the compounds being processed. Detector types that may meet this requirement include, but are not limited to, catalytic oxidation, flame ionization, infrared absorption, and photoionization. 6.2 The instrument shall be capable of measuring the leak definition concentration specified in the regulation. 6.3 The scale of the instrument meter shall be readable to ±2.5 percent of the specified leak definition concentration. 6.4 The instrument shall be equipped with an electrically driven pump to ensure that a sample is provided to the detector at a constant flow rate. The nominal sample flow rate, as measured at the sample probe tip, shall be 0.10 to 3.0 l/min (0.004 to 0.1 ft 3 /min) when the probe is fitted with a glass wool plug or filt er that may be used to prevent plugging of the instrument. 6.5 The instrument shall be equippe d with a probe or probe extension or sampling not to exceed 6.4 mm (1 /4in) in outside diameter, with a single end opening for admission of sample. 6.6 The instrument shall be intrinsically safe for operation in explosive atmospheres as defined by the National Electrical Code by the National Fire Prevention Association or other applicable regulatory code for operation in an y explosive atmospheres that may
be encountered in its use. The instrument shall, at a minimum, be intrinsically safe for Class 1, Di vision 1 conditions, and/or Class 2, Division 1 conditions, as appropriate, as defined by the example code. The instrument shall not be operated with any safety device, such as an exhaust flame arrestor, removed.

Section 6.1 is a performance cr iterion that defines which type s of detection devices may be used (all of the devices proposed for use in the ini tial rule proposal ar e covered here) and specifies that the instrument must be responsive to the com pounds being processed. Section 6.2 indicates that the instrument shall be capable of accurately measuring the specified leak

definition and section 6.3 defines the lower limit of instrument detection range or the highest

concentration before there are no detectable emissions.

Sections 6.4 and 6.5 would not be applicable to portable monitoring de vices that do not have probe extensions for sampling leaks. These speci fications could still be applied specifically for portable VOC monitoring de vices under the initial rule proposal. Section 6.6 is a reasonable performance criterion to adopt as it specifies that the de tection device must conform to safe operating standards for use in explosive atmospheres.

Background Technical Support Document – Petroleum and Natural Gas Industry 168Section 7 of Method 21 covers leak detection device calibration and performance evaluation. It specifies the types of calibration gases that may be used as well as specifications for prepared gases and mixed compound gases that may be used for calibration.

Section 8 details specifications for performan ce of the leak detection devices. The device must meet requirements for the response factor , calibration precision, and response time. These performance requirements are needed to en sure that the device will respond to the gas of interest, provide reasonably accurate measurements of leak concentration, and take an appropriate leak sample. Secti on 8 also describes leak detec tion procedures for individual components. Leak detection procedures are de fined for the following sources within Method

21:

i. valves

ii. flanges and other connectors

iii. pumps and compressors

iv. pressure relief devices

v. process drains

vi. open-ended lines or valves

vii. seal system degassing vents and accumulator vents

viii. access door seals

Alternative Work Practice to Detect Leaks from Equipment Performance criteria for optical gas imaging instruments are disclosed in the AWP

document.

(1)Instrument Specifications. The op tical gas imaging instrument must comply with the requirements in (i)( 1)(i) and (i)(1)(ii) of this section. (i)Provide the operator with an imag e of the potential leak points for each piece of equipment at both th e detection sensitivity level and within the distance used in the daily instrument check described in paragraph (i)(2) of this section. The detection sensitivi ty level depends upon the frequency at which leak m onitoring is to be performed. (ii)Provide a date and time stamp for video records of every
monitoring event. (2)Daily Instrument Check. On a daily basis, and prior to beginning any leak monitoring wo rk, test the optical gas imaging instrument at the mass flow rate determin ed in paragraph (i)(2)(i) of this section in accordance with the procedure sp ecified in paragraphs (i)(2)(ii) through (i)(2)(iv) of this section fo r each camera configuration used during monitoring (for example, d ifferent lenses used), unless an

alternative method to demonstrate daily instrument checks has been approved in accordance with paragr aph (i)(2)(v) of this section. (i)Calculate the mass flow rate to be used in the daily instrument check by following the procedures in paragraphs (i)(2)(i )(A) and (i)(2)(i)(B) of this section.

Background Technical Support Document – Petroleum and Natural Gas Industry 169(ii) Start the optical gas imagi ng instrument according to the manufacturer’s instructions, ensuri ng that all appropriate settings conform to the manufacturer’s instructions. (iii) Use any gas chosen by the user that can be viewed by the optical gas imaging instrument and that has a purity of no less than 98

percent. (iv) Establish a mass flow rate by using the following procedures: (A) Provide a source of gas where it will be in the field of view of the optical gas imaging instrument. (B) Set up the optical gas imaging inst rument at a recorded distance from the outlet or leak orifice of the flow meter that will not be exceeded in the actual performance of the leak survey. Do not exceed the operating parameters of the flow meter. (C) Open the valve on the flow meter to set a flow rate that will create a mass emission rate equal to th e mass rate specified in paragraph (i)(2)(i) of this section while obser ving the gas flow through the optical gas imaging instrument viewfinde r. When an image of the gas emission is seen through the viewfinde r at the required emission rate, make a record of the reading on the flow meter. (v)Repeat the procedures specified in paragraphs (i)(2)(ii) through (i)(2)(iv) of this section for each configuration of the optical gas imaging instrument used during the leak survey. (vi)To use an alternative method to demonstrate daily instrument checks, apply to the Administrator for approval of the alternative under § 60.13(i). (3)Leak Survey Procedure. Operate the optical gas imaging instrument to image every regulated piece of equipment selected for this work practice in accordance wi th the instrument manufacturer’s operating parameters. All emissions imaged by the optical gas imaging instrument are considered to be leaks and are subject to repair. All emissions visible to the naked eye are also considered to be leaks and are subject to repair.

Additional Sources Investigated

Other sources of data were researched to find additional information on leak detection device performance criteria. The CDM AM 0023 methodology for leak detection and repair at natural gas transmission compresso r stations and distri bution gate stations outlines a procedure for systematic leak dete ction. This procedure does not provide any detailed performance criteria for the leak detection devices themselves. However AM0023 specifies that portable monitoring in struments such as the OVA and TVA may

be used for leak detection but not meas urement. For leak measurement, AM0023 specifies that one of five methods be us ed: rotameters, high volume sampler, flowthrough bagging, calibrated bagging and ultras onic. The American Petroleum Institute and American Gas Association publish leak detection standards that may contain additional performance criteria for leak detec tion devices that may be applicable to the initial rule proposal.

Background Technical Support Document – Petroleum and Natural Gas Industry 170C. What information is available on existi ng performance criteria and protocols for using fugitive measurement detection devices and how can it be collected and

modified for the EPA rule

Method 21 was developed in the 70’s and 80’ s to find and reduce emissions from leaks that were not easily detectable by other m eans. Although the method was not developed to quantify leak rates, EPA has published the “Protocol for Equipment Leak Emission

Estimates.” 65 This document covers quantificati on of leak rates through the use of SOCMI or petroleum industry correlati ons and Method 21 leak concentration

measurements. This document also de scribes flow-through and vacuum bagging techniques for mass emission sampling. These quantification methods are not included as part of the initial rule proposal however , pieces of the flow-through bagging procedure may be applicable to emissions measurements using calibrated bags. Section 4.3 covers source enclosure of specific leaking components such as valves, pumps and agitators, compressors, connectors, and relief valves.

Method 2C 66 in Appendix A of CFR Title 40 Part 60 defines a procedure for measuring the stack gas velocity and vol umetric flow rate. This method can be used for estimating fugitive and vented emissions from flare st acks and compressor wet seal degassing vents

as discussed in the initial proposed rule. This method re fers back to Method 2 for performance criteria of pitot tubes. This in formation could be adapted for use in the Fugitive GHG Reporting Rule.

D. Performance criteria and past precedent fo r existing relevant regulations under the

Clean Air Act.

Performance criteria for fugitive detection devices include the following general aspects:

i. The detection device should respond to th e compounds being processed. Detector types that may meet this requirement incl ude organic vapor analyzers, toxic vapor analyzers, infrared detection devi ces (imaging and pointing devices). (1) Both Method 21 and its AWP state this performance criterion first (as seen in Method 21 paragraph 6.1 and AWP instrume nt specifications (e)(1)(i)). This performance criterion ensures that leak detection surveys will be carried out using equipment that is able to det ect the presence of the fugitive methane emissions and pinpoint the leak location.

ii. The detection device shall be intrinsi cally safe for operation in explosive atmospheres. (1) Method 21 specifies this in paragraph 6.6. This performance criterion pertains to the safety of the operator performing the leak detection survey. Fugitive methane emissions have the potential to combine with air in a flammable

65 US EPA. “Protocol for Equipment Leak Emission Estimates”. EPA-453/R-95-017

66 http://ecfr.gpoaccess.gov/cgi/t/text/textidx?c=ecfr&sid=75ed3a088a2e23401559636e29116342&rgn= div9&view=text&node=40:7. 0.1.1.1.0.1.1.1&idno=40

Background Technical Support Document – Petroleum and Natural Gas Industry 171mixture. It is necessary that a leak de tection survey that is looking for methane releases into the atmosphere does no t introduce any possibl e ignition source. (2) The AWP, however, does not reference th e intrinsic safety issue of optical imaging devices. The onus of the safety of the device is on the reporter and

manufacturer of the device.

iii. Two gas mixtures are required for inst rument calibration. A zero gas and a methane reference gas should be used to de termine that the leak detection device is functioning correctly and will be able to pinpoint leak locations during a

survey. iv. Calibration precision test must be complete d prior to placing the detection device into service and at subseque nt 3 month intervals or at the next use, whichever is

later. (1) Method 21 and the infrared imaging AWP both prescribe methods for calibration of the instrument. These are potentially applicable to the monitoring rule.

Additional performance criteria should be de fined for the various types of detection devices. Performance Criteria specific to OVAs and TVAs has been well defined in Method 21. Information on performance criteri a may be derived for infrared imaging

devices from the recent AWP for Method 21.

Very little information ha s been found relating to perf ormance criteria for leak

measurement devices. As with leak detection devices it is difficult to define performance criteria that will be applicable to all devices named as appropriate measurement tools in the initial rule proposal. Met hod 2C provides equipment speci fications for pitot tubes.

2. Evaluation Criteria and Approach

A. Review of existing performance criteria in the CAA and if they are applicable to fugitive

GHG emissions

i. Method 21 provides performance criteria fo r portable VOC mon itoring devices to detect equipment fugitives. These can be adapted so that references to VOCs are converted to methane and the frequency of confirmation of performance/ calibration is better aligned with the frequency of monito ring associated with this

rule.

ii. The AWP provides performance criteria for optical VOC imaging cameras to detect equipment fugitives. These can be adapted so that references to VOCs are converted to methane and the frequency of confirmation of performance/ calibration is better aligned with the frequency of monito ring associated with this

rule.

B. CARB Mandatory Greenhouse Gas Emissions Reporting

(1) For reference, the CARB rule for fugitive methane emissions was reviewed. CARB relies on Method 21, screening va lues and correlations, and VOCs to

methane conversion factor.

Background Technical Support Document – Petroleum and Natural Gas Industry 172Equipment fugitive methane emissions methods are base d upon your local AQMD/APCD Leak Detection and Repair (LDAR) procedures. You will need to extend your LDAR monitoring to all gas service components. This includes all components carrying natural gas, refine ry fuel gas, and low Btu gases. All components should be identified as one [of] the following six classification types: valve, pump seal, connector, flange, ope n-ended pipe, and ot her. For guidance you should consult and use the Component Identification and Counting Methodology found in the follow ing CAPCOA (1999 ) document: California Implementation Guidelines for Estimating Mass Emissions of Fugitive Hydrocarbon Leaks at Petroleum Facilities, CAPCOA and CARB, 1999. www.arb.ca.gov/fugitive/fugitive.htm

All gas service components should be screened usi ng a monitoring instrument capable of detecting methane. Screenings should be conducted at the frequency interval required by your local air di strict. Specific screening procedures and instrument calibration requirements c an be found in EPA Reference Method 21 published in 40 CFR 60, Appendix A (EPA Method 21), www.epa.gov/ttn/emc/ promgate/m-21.pdf. First identify and screen your gas se rvice components. Component screening

values will be used to calculate me thane emissions. The CAPCOA document referenced above provides several met hods by which VOC emissions may be calculated using component screening values. You will use Method 3: the Correlation Equation Method with modifications as required by the procedures that your local AQMD/APCD has put in place. You will calculate VOC emissions for three categories of components based on the component screening value: 1. Zero components – where the screeni ng value, corrected for background is indistinguishable from zero. 2. Leaking components – components with screening values greater than zero but less than the screening value limit abo ve which the local AQMD/APCD does not allow the use of correlation equations for the calculation of VOC emissions. This upper bound screening value is either 9,999 ppmv or 99,999 ppmv. 3. Pegged components with SVs above the upper SV/correlation equation limit.

After you have calculated VOC emissions for all your zero components, leaking components and pegged components, sum th e three to obtain your fugitive equipment VOC emissions. The sum total of VOC emissions is then multiplied by CF, a VOC to CH4 conversion factor and a kg to metric tons conversion factor (0.001) to calculate total methane emissions.

In most cases you should be able to dete rmine a system specific VOC to methane conversion factor (CF) based on determi nations of gas composition and methane content from fuel analysis. In cases wher e fuel analysis data is available, use the mass CH4/mass fuel ratio to calculate a system specific CF. In cases where representative data is not available you should use a default CF value of 0.6.

Background Technical Support Document – Petroleum and Natural Gas Industry 173B. In general, all screening devices do not qua ntify the mass or volumetric magnitude of

leaks

i. Wind can distort the size of a leak as seen through the camera. Point source suction devices that are screening leak s within touching di stance (<1 cm from leak source) do not necessarily encompass an entire leak volume. Currently in the rule §98.234 (d)(4), weather is addressed such that monitoring using infrared imaging devices must be performed under favorable conditions (such as weather).

ii. Evaluate existing screening prot ocols such as LDAR/Method21.

Infrared Imaging Protocol, AWP to Method 21, Paragraph (g)(4)(i-vii) (3) Leak survey procedure. Operate the optical gas imaging instrument to image every regulated piece of equipment selected for this work practice in accordance with the instrument manufacturer’s operating parameters. All emissions imaged by the optical gas imagi ng instrument are considered to be leaks and are subject to re pair. All emissions visible to the naked eye are also

considered to be leaks a nd are subject to repair. (4) Recordkeeping. Keep the record s described in paragraphs (g)(4)(i) through (g)(4)(vii) of this section: (i) The equipment, processes, and facil ities for which the owner or operator chooses to use the alternative work practice. (ii) The detection sensitivity level sel ected from Table 3 to subpart A of this part for the optical gas imaging instrument. (iii) The analysis to determine the piece of equipment in contact with the lowest mass fraction of chemicals that are detectable, as specified in paragraph (g)(2)(i)(A) of this section. (iv) The technical basis for the mass fr action of detectable chemicals used in the equation in paragraph (g)(2)(i)(B) of this section. (v) The daily instrument check. Record the distance, per paragraph (g)(2)(iv)(B) of this section, and the flow meter reading, per paragraph (g)(2)(iv)(C) of this section, at which the leak was imaged. Keep a video record of the daily instrument check for each c onfiguration of the optical gas imaging instrument used during the leak survey (for example, the daily instrument check must be conducted for each lens used). The video record must include a time and date stamp for each daily instrument check. The video record must be kept for 5

years. (vi) Recordkeeping requirements in the applicable subpart. A video record must be used to document the leak survey results. The video record must include a time and date stamp for each monitoring ev ent. A video record can be used to meet the recordkeeping requirements of th e applicable subparts if each piece of regulated equipment selected for this work practice can be identified in the video record. The video record must be kept for 5 years. (vii) The results of the annual Method 21 screening required in paragraph (f)(7) of this section. Records must be kept for all regulated equipment specified in paragraph (f)(1) of this section. Records must identify the equipment screened, the screening value measured by Method 21, the time and date of the screening, and calibration information required in the existing applicable subparts.

Background Technical Support Document – Petroleum and Natural Gas Industry 174Method 21, Section 8.3 8.3 Individual Source Surveys. 8.3.1 Type I - Leak Definition Based on Concentration. Place the probe inlet at the surface of the component inte rface where leakage could occur. Move the probe along the interface periphery while observing the instrument readout. If an increased meter reading is observed, slowly sample the interface where leakage is indicated until the maximum meter reading is

obtained. Leave the probe inlet at this maximu m reading location for approximately two times the instrument response time. If the maximum observed meter reading is greater than the leak definition in th e applicable regulation, record and report the results as specified in the regulation reporting re quirements. Examples of the application of this general technique to specific equipment types are:

8.3.1.1 Valves. The most common source of leaks from valves is the seal between the stem and housing. Place the probe at the interf ace where the stem exits the packing gland and sample the st em circumference. Also, place the probe at the interface of the packing gland take-up flange seat and sample the periphery. In addition, survey valve hous ings of multipart assembly at the surface of all interfaces where a leak could occur. 8.3.1.2 Flanges and Other Connections. For welded flanges, place the probe at the outer edge of the flange gasket interface and sample the circumference of the flange. Sample other types of nonpermanent joints (such as threaded connections) with a similar traverse. 8.3.1.3 Pumps and Compressors. Conduct a circumferential traverse at the outer surface of the pump or compressor s haft and seal interf ace. If the source is a rotating shaft, positi on the probe inlet within 1 cm of the shaft-seal interface for the survey. If the housing configuration prevents a complete traverse of the shaft periphery, samp le all accessible portions. Sample all other joints on the pump or compressor housing where leakage could occur. 8.3.1.4 Pressure Relief Devices. The c onfiguration of most pressure relief devices prevents sampling at the seali ng seat interface. For those devices equipped with an enclosed extension, or horn, place the probe inlet at approximately the center of the ex haust area to the atmosphere. 8.3.1.5 Process Drains. For open drains, place the probe inlet at approximately the center of the area open to the atmosphere. For covered drains, place the probe at the surfa ce of the cover interface and conduct a peripheral traverse. 8.3.1.6 Open-ended Lines or Valves. Pl ace the probe inle t at approximately the center of the opening to the atmosphere. 8.3.1.7 Seal System Degassing Vents and Accumulator Vents. Place the probe inlet at approximately the center of the opening to the atmosphere. 8.3.1.8 Access door seals. Place the probe inlet at the surfac e of the door seal interface and conduct a peripheral traverse. 8.3.2 Type II - "No Detectable Emissi on". Determine the local ambient VOC concentration around the source by moving the probe randomly upwind and

Background Technical Support Document – Petroleum and Natural Gas Industry 175downwind at a distance of one to tw o meters from the source. If an interference exists with this determina tion due to a nearby emission or leak, the local ambient concentration may be determined at distances closer to the
source, but in no case shall the dist ance be less than 25 centimeters. Then move the probe inlet to the surface of the source and determine the

concentration as outlined in Section 8.3.1. The difference between these

concentrations determines whether th ere are no detectable emissions. Record and report the results as specified by the regulation. For those cases where the regulation requires a specific device in stallation, or that specified vents be ducted or piped to a control device, the existence of these conditions shall be visually confirmed. When the regula tion also requires that no detectable
emissions exist, visual observation s and sampling surveys are required. Examples of this technique are: 8.3.2.1 Pump or Compressor Seals. If applicable, determine the type of shaft seal. Perform a survey of the local area ambient VOC concentration and determine if detectable emissions exis t as described in Section 8.3.2. 8.3.2.2 Seal System Degassing Vents, Accumulator Vessel Vents, Pressure Relief Devices. If applicable, observe wh ether or not the app licable ducting or piping exists. Also, determine if any s ources exist in the ducting or piping where emissions could occur upstream of the control device. If the required ducting or piping exists and there are no sources where the emissions could be vented to the atmosphere upstream of the control device, then it is presumed that no detectable emissions are present. If there are sources in the ducting or piping where emi ssions could be vented or sources where leaks could occur, the sampling surveys describe d in Section 8.3.2 shall be used to determine if detectable emissions exist.

C. Leak measurement instruments to be review ed; review existing instrument protocol

documents

i. High volume sampler Bacharach provides a user manual for th e HiFlow® Sampler on its website. The manual has seven chapters, several of which are useful to this rule: Chapter 2: Technical Data This chapter provides specifications such as measurable leak rates from 0.05 to 8.00 cubic feet per minute (scf/min), sampli ng flow rate of 10.5 scf/min, accuracy of +/- 10%, as well as natural gas sensor specifications. Chapter 3: Operation This chapter discusses operation of the in strument; providing us eful protocol steps

such as: a) To ensure gas sensors are properly zeroe d, turn the instrument on in clean

air. b) Calibrate the instrument ever y 30 days to assure accuracy. c) Create a maintenance log to tr ack calibration dates, etc. d) Always purge the instrument with clean air after testing. e) Instructions on how to ground the instrument for safety.

Background Technical Support Document – Petroleum and Natural Gas Industry 176f) Instructions on how to equip attachments, use them, and when tips for when they are useful. g) Instructions on how to use vari ous menus programmed into the

instrument. h) Step-by-step instructions on how to measure leaks (section 3.18 pages 31 – 37), including what modes (e.g. automatic 2-stage mode) for

measurement. Chapter 4: Calibration This chapter provides step-by-step instruc tions on how to calibrate the instrument, and provides useful specifications such as using 2 calibration gases: 1) 2.5% CH4 in air, 2) 100% methane.

ii. Rotameters Rotameters are not complicated instruments. A few key considerations for use of

a rotameter are: a) Using the proper size. Rotameters have ranges of flow rates that they can measure. It is important to select th e appropriate size so as not to exceed or fall below this range. For best results, the leak size should fall toward the middle of the acceptable range. b) Rotameter use a “float bob” in the measurement, and the readings assume the force for gravity pulling down on the float bob. Thus, the rotameter must be upright during measurement. c) Rotameters require that all of the gas is directed into them , and a tight seal is formed around the edges of the inle t so that gas does not escape out the sides. This would require a flexible hose or tubing with suitable reducers to fit over different size vent pipes. d) Greenhouse gas emissions are calculat ed using the following equation:
hgAkw F
i

i ×××××= 3600

where,

F i = the leak flow rate of greenhouse gas “i”

w i = the concentration of gree nhouse gas “i” in the natural gas k = constant provided by the rotameter documentation

A = annular area between the float and the tube wall g = acceleration due to gravity h = the pressure drop across the float (as shown by height)

iii. Turbine meters Daniels (subsidiary of Emerson) provides a user manual for its turbine meters. This document provides equipment specifications for each of its models, detailed instructions for installation and use, as well as maintenance instructions. Amongst the key considerations for the use of this instrument are: a) The meter should be installed in th e horizontal position with the arrow pointing in the direction of the flow. b) To maintain accuracy, the meter should have an upstream meter tube with recommended minimum length of 10 pipe diameters of straight pipe, and a

Background Technical Support Document – Petroleum and Natural Gas Industry 177downstream meter tube with reco mmended minimum length of 5 pipe diameters of straight pipe. c) A straightening vane should be inst alled with a minimum of 5 pipe diameters upstream of the meter (measured from the downstream end of the vane). d) For accurate measurement, the meter mustbe installed in the pipe (metertube) without offsets at the flanges a nd without gaskets protruding into the

line bore. e) Wet gas may only require inspection of the internal assembly once per year, while dusty gas may requi re inspection every 30 days. f) Depending on the model selected, accura cy can be +/- 0.25% of better. Operational over a temperature range from 0 to 220°F. g) The majority of this 91-page documen t is dedicated to the use of the instrument, including the removal and reassembly of internal assembling of the meter for purposes of ca libration and measurement.

iv. Hot wire anemometers Do not have adequate info to elaborate on possible perf ormance criteria for this

measurement device.

v. Pitot tube Accuracy can be more than 1%. Method 2C provides details on performance cr iteria in paragraph 6.1, 6.2, and 6.7

of Method 2: 6.1 Standard Pitot Tube (instead of Type S). A standard pitot tube which meets the specifications of Secti on 6.7 of Method 2. Use a coefficient of O.99 unless it is calibrated against anothe r standard pitot tube with a NISTtraceable coefficient (see Section 10.2 of Method 2). 6.2 Alternative Pitot Tube. A modifie d hemispherical-nosed pitot tube (see Figure 2C-1), which features a shortened stem and enlarged impact and static pressure holes. Use a coefficien t of 0.99 unless it is calibrated as mentioned in Section 6.1 above. This pito t tube is useful in particulate liquid droplet-laden gas streams when a "back purge" is ineffective.”

“6.7 Calibration Pitot Tube. When ca libration of the Type S pitot tube is necessary (see Section 10.1), a standard pitot tube shall be used for a reference. The standard pitot tube shall, preferably, have a known coefficient, obtained either (1) directly from th e National Institute of Standards and Technology (NIST), Gaithersburg MD 20899, (301) 975- 2002, or (2) by calibration against another standard pitot tube w ith an NIST-traceable coefficient. Alternativel y, a standard pitot tube designed according to the criteria given in Sections 6.7.1 thro ugh 6.7.5 below and illustrated in Figure 2-5 (see also References 7, 8, and 17 in Section 17.0) may be used. Pitot tubes designed according to these specificati ons will have baseline coefficients of

0.99 ± 0.01. 6.7.1 Standard Pitot Design.

Background Technical Support Document – Petroleum and Natural Gas Industry 1786.7.1.1 Hemispherical (shown in Figure 2-5), ellipsoidal, or conical
tip. 6.7.1.2 A minimum of six diameter s straight run (based upon D, the external diameter of the tube) between th e tip and the static pressure holes. 6.7.1.3 A minimum of eight diamete rs straight run be tween the static pressure holes and the centerline of the external tube, following the 90E bend. 6.7.1.4 Static pressure holes of equal size (approximately 0.1 D), equally spaced in a piezometer ring configuration. 6.7.1.5 90E bend, with curved or mitered junction.

Method 2C provides detail on the protocol for use of a pitot tube for flow rate measurement. Below is an excerpt, section 8: 8.1 Follow the general procedures in Section 8.1 of Method 2, except

conduct the measurements at the trave rse points specified in Method 1A. The static and impact pressure holes of st andard pitot tubes ar e susceptible to plugging in particulate-laden gas streams. Therefore, adequate proof that the openings of the pitot tube have not plugge d during the traverse period must be furnished; this can be done by taking the velocity head ( Δ

p) heading at the final traverse point, clea ning out the impact and static holes of the standard pitot tube by "back-purging" with pr essurized air, and th en taking another ( Δ

p) reading. If the Δ p readings made before and after the air purge are the same (within ±5 percent) the traverse is acceptable. Otherwise, reject the run. Note that if the Δ p at the final traverse point is unsuitably low, another point may be selected. If "back purging" at regular intervals is part of the procedure, then take comparative Δ p readings, as above, for the last two back purges at which suitably high Δ p readings are observed.

vi. Calibrated bagging Calibrated bags are relatively simple inst ruments to measure flow rates. The key

concepts are: a) Calibrated bagging requires proximity to the leak, requiring user to be cautious of safety considerations (e.g . temperature of emissions and vent pipe). b) Ensure that the entire emi ssion is captured by the bag. c) Measure the time required to completely fill the bag. Repeat the process at least 3 times to improve accuracy. d) The bag must be made of a static material that will not build charge or create sparks under any operating conditions.

2. Data Sources for Research

• CAA – LDAR program, Method 21 guidance documents

• Manufacturers information (Heath, FLIR, etc)

• CDM leak detection methodologies (AM0023)

3. Summary

Background Technical Support Document – Petroleum and Natural Gas Industry 179It is likely that existing performance criteria and protocols may need se lective references and exclude selective provisions which do not appl y for mandatory reporting for the expressed purpose of finding and measuring methane l eaks for the reporting of GHG emissions. Information from Method 21 and the Alternative Work Practice may be adapted into performance criteria for OVAs, TVAs, and infrared imaging cameras. These documents do not contain any standards for performance criteria of leak measurement devices. Manufacturer data may serve as a starti ng point for developi ng measurement device performance criteria.

Background Technical Support Document – Petroleum and Natural Gas Industry 180

### Appendix P: Discussion on Methodo logies in Emission References

API’s Emission Factors for Oil and Gas Production Operations 48

Emissions factors were develope d using the following approach: 1. The contributions of screening values th at are less than 10 ppmv; screening values 10 to 9,999 ppmv; and emitters pegged at 10,000 pp mv were summed for each component type. Emissions from components with these screening values were calculated using the

methods below: a. Emission rates for screening values: < 10 ppmv 1) EPA default zero values for connectors and open ended lines; and 2) Emission rates for non-emitters (at 10 ppmv) were used for flanges, pumps, valves, and other components. b. Emission rates for compone nts with screening rates from 10 ppmv to 9,999 ppmv 1) Correlation equations from the Protoc ol for Equipment Leaks Emission Estimates (6/1993) were used to calculate emission rates. c. Emission rates for compone nts pegged at 10,000 ppmv 1) EPA 10,000 ppmv pegged emission factors were used to calculate emission rates. 2. The sum of emissions for each component (from step (1)) was then divided by the total number of components of that type to develop average emission factors. 3. The sum of emissions for each component fr om step (1a) and step (1b) were divided by

the total number of com ponents of that type to develop no-leak factors. 4. The sum of emissions for each component fr om step (1c) was divided by the total number of components of that type to develop leak factors. 5. The emission factors for each type of compon ent were then separated by facility type (i.e. light crude, gas production).

Identification and Evaluation of Opportuni ties to Reduce Methane Losses at Four Gas Processing Plants 49 . AND Cost-Effective Directed Inspection and Mainte nance Control Opportunities at Five Gas Processing Plants and Upstream Gather ing Compressor Stations and Well Sites 50

.

Emission factors were also developed using the following approach:

1. Equipment components were screened us ing bubble tests with soap solution, portable hydrocarbon gas detectors and ultr asonic leak detectors. a. The majority of the equipment was screen ed using the bubble test with soap solution

method.

b. Ultrasonic detectors were used to sc reen equipment in areas with low background noise levels in the ultrasonic range. c. Gas detectors were used to screen equi pment that could not be screened using the bubble test such as equipment in high-temperature service, certain flanged connections and open-ended lines.

Background Technical Support Document – Petroleum and Natural Gas Industry 181d. The five facilities surveyed in (Clearstone 2006) conducted supplementary leak surveys using a passive midwave infrared camera to qualitatively compare the method with the more traditional portable hydrocarbon analyzer method. e. Those components found emitting from the bubble test or ultrasonic detectors were rescreened with a portable hydrocarbon vapor analyzer to determine whether they met

the leaker definition. f. 10,000 ppmv or greater was used as the “leaker definition.”

2. A HiFlow® Sampler was used to measure components that exceeded 10,000 ppm. a. Equipment leaks that were greater th an the upper limit of the unit and most openended lines and vents were not measured using the HiFlow® Sampler. They were measured using bagging or other “direct measurement techniques.”

3. Equipment component counts were conducted.

4. The average emission factors for each type of component were calculated as follows: a. The measured emissions were aggregat ed by component type which also included “non-leaking” components emission rates. The non-leaking emission rates from the EPA’s Protocol for Equipment Leak Emi ssion Estimates were used for non-leaking components (screening values < 10,000 ppmv). b. The aggregate emissions were divided by the number of components to estimate average emissions factors.

Handbook for Estimating Methane Emission s from Canadian Natural Gas Systems 51

, AND

Measurement of Natural Gas Emissions from the Canadian Natural Gas Transmission and Distribution Industry 52

1. Component Screening Process Leak screening was conducted using ultrasoni c leak detectors, bubbl e tests with soap solution and portable hydrocarbon vapor analyzers calibrated to methane. A positive qualitative screening process was followed by a quantitative screening process in which the screening value, 10,000ppmv, was verified. Components that have a screening value equal to or greater than 10,000ppm were cat egorized as leaking. The leak detection survey was conduc ted in accordance with Method 21 67 developed by the EPA, and the measurements were conducted in accordance with the Fugitive

Emissions Measurement Protocol 68

.

2. Leak Rate Measurement Emission rates were measured using a vari ety of techniques that are outlined in Section 4 of the Fugitive Emissions Meas urement Protocol. The primary instrument

67 U.S. EPA (Environmental Protection Agency). 1997 . Method 21 – Determination of Volatile Organic Compound Leaks.

68 Clearstone Engineering Ltd. 2006. Canadian Energy Partnership for Environmental Innovation (CEPEI) – Fugitive Emissions Measurement Protocol.

Background Technical Support Document – Petroleum and Natural Gas Industry 182used to quantify the emission rate was the HiFlow TM Sampler. However, depending on the source type and emission rate, velo city probes (i.e. hot wire anemometer, thermal dispersion anemometer, vane anem ometer and micro-tip anemometer) and flow-through meters (i.e. rotary meter, diaphragm meter and rotameter) were also used. Data was collected and reported in accordance to Section 2 of the Fugitive

Emissions Measurement Protocol.

3. Component Count Clearstone Engineering conduc ted a thorough count of components in the surveyed facilities in accordance to the Fugitive Emissions Measurement Protocol. These numbers were compared to independen t counts provided by facility operators. Significant discrepancies were noticed during the comparison as follows:

 Facility operators used piping and instrumentation drawing that underestimated the number of components. The drawings did not have the detail required to make an accurate component count.

 Facility operators did not use a system atic approach as stipulated by the Fugitive Emissions Measurement Prot ocol leading to double counting or undercounting. When developing the average emission f actors, the Clearstone component counts

were used.

4. Emission Factors

a. Average Emission Factors Average emission factors include emissi ons rates from leaking and non-leaking components. Emission rates from leaking components were measured using the procedure described earlier. Non-leaking components were assigned emission rates

found in EPA’s Protocol for E quipment Leak Emission Estimates 69 . Prior to calculating average emission factors, com ponents were grouped into the following source categories: centrifugal compressor seal, reciprocating compressor seal, connector, control valve, controller, blowdown system , open-ended line, orifice meter, other flow meter, pressure regulato r, pressure relief valve and valve. Finally, average emission factors were calculated by summing the total organic emission in each source category and dividing by the corresponding component count.

A 95 percent confidence interval limit was cr eated for the average emission factors in each source category. Total organic emissions were calculated for the entire company using average emission factors ut ilizing the following equation; 

# ∑ ∑

⋅⋅ =

i j jiji XNEF ER

,

where

i denotes the source category,
j denotes the facility type (i.e . transmission or distribution),

ER is the total emission rate for the target source population (kg/h),

EF is the average emission factor (kg TOC/h/source),

69 US EPA. 1995. Protocol for Equipment Leak Emission Estimates. Publication No. EPA-453/R-95-017

Background Technical Support Document – Petroleum and Natural Gas Industry 183N is the number of source,

X

is the mass fraction of the target pollutant in the process fluid.

b. Screening Range Approach Leaking components were separated from non-leaking components. As described earlier, components found to have a screen ing value greater than or equal to 10,000ppmv were labeled as leaking. Subse quently, the components were categorized into the source groups. Leaker factors were calculated by summing the emission rates from leaking components in a particular source group and dividing by the number of corresponding component count. Non-leak ing components are assigned emission rates found in EPA’s Protocol for Equipment Leak Emission Estimates.

Total organic emissions for the entire co mpany was calculated using leaker and nonleaker emission factors us ing the following equation;



## ( ) ( ) 

# ∑ ∑ ⋅+⋅=

i j ji LL ji GG TOC NFNF E

, ,

where

i denotes the source category,
j denotes the facility type (i.e . transmission or distribution),

E TOC is emission rate for an equipment type (kg/hr),

F

G is applicable emission factor fo r sources with sc reening values ≥ 10,000 ppmv (kg/hr/source),

N

G

is equipment count (specific equi pment type) for sources with screening values ≥ 10,000 ppmv,

F

L is applicable emission factor fo r sources with sc reening values < 10,000 ppmv (kg/hr/source),

N

L is equipment count (specific equipment type) for sources with screening values < 10,000 ppmv.

Background Technical Support Document – Petroleum and Natural Gas Industry 184

### Appendix Q: Glossary

The following definitions are based on commo n industry terminology for the respective equipment, technologies

, and practices.

Absorbent circulation pump means a pump commonly powered by natural gas pressure that circulates the absorbent liquid between the absorbent regenerator and natural

gas contactor.

Acid Gas means hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) contaminants that are separated from sour natural gas by an acid gas removal.

Acid Gas Removal unit (AGR) means a process unit that separates hydrogen sulfide

and/or carbon dioxide from sour natural gas using liquid or solid absorbents or membrane

separators.

Acid gas removal vent stack emissions mean the acid gas separated from the acid gas absorbing medium (e.g., an amine solution) and released with methane and other light hydrocarbons to the atmo sphere or a flare.

Air injected flare means a flare in which air is blown into the base of a flare stack to induce complete combustion of low Btu natura l gas (i.e., high non-combustible component content).

Blowdown vent stack emissions mean natural gas released due to maintenance and/or blowdown operations including but not limited to compressor blowdown and emergency shut-down (ESD) system testing.

Calibrated bag means a flexible, non-elastic, anti -static bag of a calibrated volume that can be affixed to a emitting source such that the emissions inflate the bag to its calibrated

volume.

Centrifugal compressor means any equipment that increases the pressure of a process natural gas by centrifugal action, employing rotating movement of the driven shaft.

Centrifugal compressor dry seals mean a series of rings around the compressor shaft where it exits the compressor cas e that operates mechanically under the opposing forces to prevent natural gas from escaping to the atmosphere.

Centrifugal compressor dry seals emissions mean natural gas released from a dry seal vent pipe and/or the seal face around the rotati ng shaft where it exits one or both ends of the

compressor case.

Centrifugal compressor wet s eal degassing venting emissions means emissions that occur when the high-pressure oil barriers fo r centrifugal compressors are depressurized to

Background Technical Support Document – Petroleum and Natural Gas Industry 185release absorbed natural gas. Hi gh-pressure oil is used as a barrier against escaping gas in centrifugal compressor shafts. Very little gas escapes through the oil barrier, but under high pressure, considerably more gas is absorbed by th e oil. The seal oil is purged of the absorbed gas (using heaters, flash tanks, and degassing techniques) and r ecirculated. The separated gas is commonly vented to the atmosphere.

Coal Bed Methane (CBM) means natural gas which is extracted from underground coal deposits or “beds.”

Component

, for the purposes of subpart W only, means but is not limited to each metal to metal joint or seal of non-welded connection separated by a compression gasket, screwed thread (with or wit hout thread sealing compound), metal to metal compression, or fluid barrier through which natural gas or liquid can escape to the atmosphere.

Compressor means any machine for raising the pre ssure of a natural gas by drawing in low pressure natural gas and discharging significantly higher pressure natural gas.

Condensate means hydrocarbon and other liquid se parated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at storage conditions, includes both wate r and hydrocarbon liquids.

Conventional wells mean gas wells in producing fiel ds that do not employ hydraulic fracturing to produce commercially viable quantities of natural gas.

Dehydrator means a device in which a liquid absorbent (including but not limited to desiccant, ethylene glycol, diethylene glycol, or triethylene glycol ) directly contacts a natural gas stream to absorb water vapor.

Dehydrator vent stack emissions means natural gas released from a natural gas dehydrator system absorbent (typically glycol) reboiler or regenerator, including stripping natural gas and motive natural gas used in absorbent circulation pumps.

De-methanizer means the natural gas processing unit that separates methane rich residue gas from the heavier hydrocarbons (e.g., ethane, propane, butane, pentane-plus) in feed natural gas stream).

Desiccant means a material used in solid-bed dehydrators to remove water from raw natural gas by adsorption. Desiccants include ac tivated alumina, palletized calcium chloride, lithium chloride and granular silica gel material . Wet natural gas is passed through a bed of the granular or pelletized solid adsorbent in these dehydrators. As the wet gas contacts the surface of the particles of desiccant material , water is adsorbed on the surface of these desiccant particles. Passing through the entire desiccant bed, almost all of the water is adsorbed onto the desiccant material, l eaving the dry gas to exit the contactor.

E&P Tank means the most current version of an exploration and pr oduction field tank emissions equilibrium program that estimates flashing, working and standing losses of

Background Technical Support Document – Petroleum and Natural Gas Industry 186hydrocarbons, including methane, from produced crude oil and gas condensate. Equal or

successors to E&P Tank Version 2.0 for Windows Software. Copyright (C) 1996-1999 by

The American Petroleum Institute and The Gas Research Institute.

Engineering estimation means an estimate of emissions based on engineering principles applied to measured and/or approximated physical pa rameters such as dimensions of containment, actual pressures, actual temperatures, and compositions.

Enhanced Oil Recovery (EOR) means the use of certain methods such as water flooding or gas injection into existing wells to increase the recovery of crude oil from a reservoir. In the context of this rule, EOR applies to injection of critical phase carbon

dioxide into a crude oil reservoir to enhance the rec overy of oil.

Field means standardized field names and codes of all oil and gas fields identified in

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

Code Master List.

Flare combustion efficiency means the fraction of natural gas, on a volume or mole basis, that is combusted at the flare burner tip.

Flare combustion means unburned hydrocarbons including CH 4 , CO 2 , N 2 O emissions resulting from the incomplete combustion of gas in flares.

Fugitive emissions means those emissions which are unintentional and could not reasonably pass through a stack, chimney, vent , or other functionally-equivalent opening.

Fugitive emissions detection means the process of identifying emissions from equipment, components, and other point sources.

Gas conditions mean the actual temperature, volume, and pressure of a gas sample.

Gas gathering/booster stations mean centralized stations where produced natural gas from individual wells is co-mingled, comp ressed for transport to processing plants, transmission and distribution systems, and othe r gathering/booster sta tions which co-mingle gas from multiple production ga thering/booster stations. Such stations may include gas dehydration, gravity separation of liquids (both hydrocarbon and wa ter), pipeline pig launchers and receivers, and ga s powered pneumatic devices.

Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature and pressure that is produced from a volum e of oil when depressurized to standard temperature and pressure.

High-Bleed Pneumatic Devices are automated flow control devices powered by pressurized natural gas and used for maintain ing a process condition su ch as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream which is regulated by

Background Technical Support Document – Petroleum and Natural Gas Industry 187the process condition flows to a valve actuator controller where it ve nts (bleeds) to the atmosphere at a rate in excess of six standard cubic feet per hour.

Liquefied natural gas (LNG) means natural gas (primarily methane) that has been liquefied by reducing its temperature to -260 degrees Fahrenheit at atmospheric pressure.

LNG boiloff gas means natural gas in the gaseous phase that vents from LNG storage

tanks due to ambient heat leak age through the tank insulation a nd heat energy dissipated in the LNG by internal pumps.

Low-Bleed Pneumatic Devices mean automated flow control devices powered by pressurized natural gas and used for maintain ing a process condition su ch as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream which is regulated by the process condition flows to a valve actuator controller where it ve nts (bleeds) to the atmosphere at a rate equal to or less than six standard cubic feet per hour.

Natural gas driven pneumatic pump means a pump that uses pressurized natural gas to move a piston or diaphragm, which pumps liquids on the opposite side of the piston or diaphragm.

Offshore means tidal-affected borders of the U.S. lands, both state and Federal, adjacent to oceans, bays, lakes or other normally standing water.

Onshore petroleum and natural gas production owner or operator means the entity who is the permitee to operate petroleum and na tural gas wells on the state drilling permit or a state operating permit where no dri lling permit is issued by the state

, which operates an onshore petroleum and/or natural gas production facility (as described in §98.230(b)(2). Where more than one entity are permitees on th e state drilling permit, or operating permit where no drilling permit is issued by the state, th e permitted entities for the joint facility must designate one entity to report all emissions from the joint facility.

Operating pressure means the containment pressure th at characterizes the normal state of gas or liquid inside a particular process, pipeline, vessel or tank.

Pump means a device used to raise pressure, drive, or increase flow of liquid streams in closed or open conduits.

Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon dioxide containing light liquids from escaping the inside of a pump case to the atmosphere.

Pump seal emissions means hydrocarbon gas released fr om the seal face between the pump internal chamber and the atmosphere.

Reciprocating compressor means a piece of equipment that increases the pressure of a process natural gas by positive displacement, em ploying linear movement of a shaft driving a piston in a cylinder.

Background Technical Support Document – Petroleum and Natural Gas Industry 188Reciprocating comp ressor rod packing means a series of flexible rings in machined metal cups that fit around the re ciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas th at escapes to the atmosphere.

Re-condenser means heat exchangers that cool compressed boil-off gas to a temperature that will condense natural gas to a liquid.

Reservoir means a porous and permeable underg round natural formation containing significant quantities of hydrocarbon liquids and/o r gases. A re servoir is characterized by a single natural pressure system.

Sales oil means produced crude oil or condens ate measured at the production lease automatic custody transfer (LACT) mete r or custody transfer meter tank gauge.

Sour natural gas means natural gas that contains significant concentrations of hydrogen sulfide and/or carbon dioxide that exceed the con centrations specified for commercially saleable natural gas delivered from transmission and distribution pipelines.

Sweet Gas is natural gas with low con centrations of hydrogen sulfide (H 2 S) CO 2 ) that does not require (or has already had) acid gas treatment to meet pipeline corrosionprevention specifications for tr ansmission and distribution.

Transmission pipeline means high pressure cross c ountry pipeline transporting sellable quality natural gas from producti on or natural gas processing to natural gas distribution pressure let-down, me tering, regulating stations wher e the natural gas is typically odorized before delivery to customers.

Turbine meter means a flow meter in which a gas or liquid flow rate through the calibrated tube spins a turbine from which the sp in rate is detected and calibrated to measure

the fluid flow rate.

Unconventional wells means gas well in producing fields that employ hydraulic fracturing to enhance gas production volumes.

Vapor recovery system means any equipment located at the source of potential gas emissions to the atmosphere or to a flare, that is composed of piping, connections, and, if necessary, flow-inducing devices, and that is used for routing the gas back into the process as a product and/or fuel.

Vaporization unit means a process unit that performs controlled heat input to vaporize LNG to supply transmission and distribution pi pelines or consumers with natural gas.

Vented emissions means intentional or designed releases of CH 4 or CO 2 containing natural gas or hydrocarbon gas (not including stationary com bustion flue gas), including but not limited to process designed flow to the atmosphere through seals or vent pipes,

Background Technical Support Document – Petroleum and Natural Gas Industry 189equipment blowdown for maintenance, and direct venting of gas used to power equipment (such as pneumatic devices).

Well Completions means a process that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling an d reservoir fluids and test the reservoir flow characteristics. This process includes high-rate back-flow of injected water and sand used to fracture and prop-open fractures in low permeability gas reservoirs.

Well Workover means the performance of one or more of a variety of remedial operations on producing oil and ga s wells to try to increase pr oduction. This process also includes high-rate back-flow of injected wate r and sand used to re-fracture and prop-open new fractures in existing low permeability gas reservoirs.

Wellhead means the piping, casing, tubing and connected valves protruding above the Earth’s surface for an oil and/ or natural gas well. The wellhead ends where the flow line

connects to a wellhead valve.

Wet natural gas means natural gas in which water vapor exceeds the concentration specified for commercially saleable natural gas delivered from transmission and distribution pipelines. This input stream to a natural ga s dehydrator is referre d to as ‘‘wet gas’’.

Background Technical Support Document – Petroleum and Natural Gas Industry 190

### Appendix R: References

AGA (2008) Greenhouse Gas Emissions Estimation Methodologies, Procedures, and Guidelines for the Natural Gas Distribution Sector

.

API (2004) Compendium of Greenhouse Gas Emissi ons Estimation Methodologies for the Oil and Gas Industry

. <http://www.api.org/ehs/climate/new/upload/2004_COMPENDIUM.pdf>.

API. (2007) Summary of Carbon Dioxide Enhanced O il Recovery (CO2EOR) Injection Well Technology

. <http://www.api.org/aboutoilgas/sectors /explore/upload/API_CO2_Report_August2007.pdf>

Bacharach, Inc. (2005) HiFlow® Sampler Natural Gas Leak Rate Measurement: Instruction 55-9017, Operation & Maintenance . < http://www.bacharach-inc.com/PDF/Instructions/55- 9017.pdf>.

Bureau of Economic Analys is (2007) Table 1.1.9. Implicit Price Deflators for Gross

Domestic Product . <http://www.bea.gov/bea/dn/n ipaweb/TableView.asp#Mid>.

Bylin, Carey (EPA), et. al (2009) Methane’s Role in Promoting Sustainable Development in Oil and Natural Gas Industry . <presented at 24th World Gas Conference>

California Environmental Protection Agency (2007) Rulemaking to Consider Adoption of a Regulation for the Mandatory Re porting of Greenhouse Gas Emissions

. <http://www.arb.ca.gov/regact/2007/ghg2007/ghg2007.htm>.

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